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Home My WebLink About203-069Alaska 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 December 13, 2021 Mr. J. Edward Jones Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Location Clearances Aspen 1 (PTD #2051110) Moquawkie 1 (PTD #2030690) Kaloa 2 (PTD #2040960) Moquawkie 3 (PTD #2050800) Lone Creek 1 (PTD #1980840) Moquawkie 4 (PTD #2070840) Lone Creek 3 (PTD #2050970) Simpco Moquawkie 1 (PTD #1780470) Lone Creek 4 (PTD #2070910) Simpco Moquawkie 2 (PTD #1780880) Dear Mr. Jones: On December 20, 2019, the Alaska Oil and Gas Conservation Commission (AOGCC) received the final Well Completion Reports for the plugging and abandonment of the following wells: Aspen 1, Kaloa 2, Lone Creek 1, Lone Creek 3, Lone Creek 4, Moquawkie 1, Moquawkie 3, Moquawkie 4, Simpco Moquawkie 1, and Simpco Moquawkie 2. On June 15, 2021, AOGCC waived witness of each location status and an environmental site assessment (ESA) was conducted by Environmental Management, Inc. on June 17, 2021. AOGCC received a copy of the ESA report along with accompanying photographs of each site on December 7, 2021. Each drill site was found to be in compliance with onshore location clearance requirements as stated in 20 AAC 25.170. The AOGCC requires no further work on the subject wells or locations at this time. However, Plugging Inlet, LLC remains liable if any problems were to occur with these wells in the future. Sincerely, Jessie L. Chmielowski Jeremy M. Price Commissioner Chair, Commissioner May 13, 2020 RECEIVED MAY 18 2020 Jeremy M. Price, Chair AOGCC Alaska Oil and Gas Conservation Commission 333 West 7"' Ave., Suite 100 Anchorage, Alaska 99501 RE: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Costs to Plug and Abandon Wells on CIRI Leases Dear Mr. Price: Regarding your letter to me of May 1, 2020, the following information is responding to your request for costs incurred to plug and abandon the following wells on mineral interests owned by Cook Inlet Regional, Inc. (CIRI): • ASPEN 1 – API 50-283-20114-00-00 • KALOA 2 – API 50-283-20107-00-00 • LONE CREEK 1– API 50-283-20096-00-00 • LONE CREEK 3 – API 50-283-20112-00-00 • LONE CREEK 4 – API 50-283-20121-00-00 • MOQUAWKIE 1 –API 50-283-10019-90-00 • MOQUAWKIE 4 – API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 –API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 – API 50-283-20062-00-00 Plugging Inlet, LLC, was the operator of these wells and conducted plugging and abandonment (P&A) operations between October 2018 and November 2019. Costs were tracked on the basis of vendors, not by well or activity. Thus, while some costs, totaling about $1,007,000, were paid to vendors who worked solely on the P&A of the wells (e.g., Schlumberger, Pollard Wireline, and Halliburton), most of the vendor;/contractors also worked on DR&R, cleanup, and waste disposal operations. Thus, the costs of these vendors/contractors for P&A operations were estimated on the basis of the Summary of Operations, based on the daily reports—these include camp costs, air and marine transportation, supervision, welder and roustabouts, trucking, and equipment rental. It is estimated that another $595,000 were paid to these other contractors and vendors for services supporting P&A work for a total estimated cost to P&A the 10 wells of $1,602,000, or $160,200 per well. However, one well, the Lone Creek 1, was particularly problematic to P&A due to its original construction, and the cost to P&A that well is estimated at about $244,000, leaving the average cost to P&A the other 9 wells at $151,000. For clarity, the reported $1.6 million is for actual well plugging and abandoning costs only; in addition, Inlet Plugging LLC incurred approximately $3.4 million for associated lease remediation activities, including required deconstruction & removal of surface production equipment and restoration of the sites, cleanup of contamination (mostly compressor oil leaks under buildings and some small spills), disposal of waste (including historic drill cuttings and mud solids, contaminated gravel and soil, and used oil and glycol), required Mr. Jeremy M. Price 5/13/20 Page 2 surface use payments, transportation of salvaged equipment and waste, and associated expenses. If you have any questions or require additional information, please contact me at 713-899- 8103 or by email at jejones@aurorapower.com. Sincerely, �ZG 9!Edward Jones Operations Consultant for PLUGGING INLET, LLC 6733 South Yale Avenue Tulsa, OK 74136 CC: Suzanne Settle and Colleen Miller, CIRI Thomas Redman, Jim Sullivan, Mark Can, Plugging Inlet, LLC THE STATE "ALASKA May 1, 2020 GOVERNOR MICKNE•L I. DUNLEAFY J. Edward Jones Operations Consultant Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Dear Mr. Jones: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov The Alaska Oil and Gas Conservation Commission (AOGCC) requests documentation of the actual costs incurred to plug and abandon the following wells: • ASPEN 1 —API 50-283-20114-00-00 • KALOA 2 — API 50-283-20107-00-00 • LONE CREEK 1 —API 50-283-20096-00-00 • LONE CREEK 3 —API 50-283-20112-00-00 • LONE CREEK 4—API 50-283-20121-00-00 • MOQUAWKIE 1 —API 50-283-10019-90-00 • MOQUAWKIE 4 — API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 —API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 —API 50-283-20062-00-00 The wells are located on mineral interests owned by Cook Inlet Regional, Inc (CIRI). In 2017, Plugging Inlet, LLC was designated operator of record for the wells. This request is made pursuant to 20 AAC 25.300. Should you have any questions about the information request, please contact Guy Schwartz at 907-793-1226. Sincerely, v Jeremy M. Price Chair, Commissioner cc: Suzanne Settle VP Energy, Land, Resources CIRI itCIRI January 14, 2020 James Regg, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 �T ons WrInVeColprwation RE: Onshore location clearance, Plugging Inlet Site located: T12 N R12W, T12N Ri1W, T11N R12W, T12N R11W SM Dear Mr. Regg: This letter is submitted to formally request that the Alaska Oil and Gas Conservation Commission (AOGCC) withhold the site clearance at the location formerly operated by Aurora Gas, LLC. Tyonek Native Corporation (TNC) and Cook Inlet Region, Inc. (CIRI) are the majority landowners within the area and did not have the opportunity to conduct an on-site inspection prior to the 2019 snowfall. CIRI and TNC will conduct an on-site inspection of the property in the spring to ensure the site is reclaimed to the satisfaction of both landowners. TNC and CIRI appreciate the AOGCC's continued cooperation during this process. If you have any questions, please contact Suzanne Settle at (907) 263-5150 or Connie Downing at (907) 272-0707. Sincerely, Tyonek Native Corporation 1 Connie J. Downing Chief Administrative Officer Cook Inlet Region, Inc. Suzanne Settle VP, Energy and Infrastructure Colombie, Jody J (CED) From: Regg, James B (CED) Sent: Monday, January 6, 2020 12:26 PM To: Colombie, Jody J (CED) Cc: Schwartz, Guy L (CED) Subject: FW: Site Clearance - Plugging Inlet See email from CIRI below. Looks like we received the 407s for these December 20 according to the 400 -Logs. Plugging Inlet dragged out the P&As so long this past fall that we were unable to get to locations for site clearance inspections before weather turned (actually had an Inspector and CIRI rep at the airport ready to fly over for site clearance inspections but flights were canceled for weather and there has been snow on the well sites since). Wells affected are: - Aspen #1 (PTD 2051110) - Kaloa #2 (PTD 2040960) - Lone Creek #1 (PTD 1980840) - Lone Creek #3 (PTD 2050970) - Lone Creek #4 (PTD 2070910) - Moquawkie #1 (PTD 2030690) - Moquawkie #3 (PTD 2050800) - Moquawkie #4 (PTD 2070840) - Simpco Moquawkie #1 (PTD 1780470) - Simpco Moquawkie #2 (PTD 1780880) Jim Regg Supervisor, Inspections AOGCC 333 W.7'^ 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.reggPalaska.eov. From: Colleen Miller <cmiller@ciri.com> Sent: Monday, January 6, 2020 11:09 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Connie Downing <cdowning@tyonek.com>; Suzanne Settle <SSettle@ciri.com>; David Kroto <dkroto@tyonek.com> Subject: Site Clearance - Plugging Inlet Good Morning Jim. I hope you had a great holiday! I'm writing to let you know that CIRI and Tyonek will be issuing a joint letter to request that the AOGCC withhold the site clearance on the Westside until CIRI and Tyonek have an opportunity to get boots on the ground in the spring. As always, please call me if you have any questions. Colleen 263-5117 The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. 2 SFD 3/25/2020 -00 DSR-3/25/2020 xG MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 2efej 1214orr j- DATE: 10/24/19 P. I. Supervisor FROM: Lou Laubenstein SUBJECT: Surface Abandonment Petroleum Inspector Moquawkie #1 Plugging Inlet LLC PTD 2030690; Sundry 318-338 10/8/19: 1 arrived on location for the surface abandonment inspection on Moquawkie #1. David Wallingford was the Company representative on location for the day's inspection. Solid cement was confirmed at surface in the cutoff well. The casing cutoff depth was only cut to 3-4 feet below the current pad grade and not the proper depth of 3 feet minimum below original ground level — this was discussed with Mr. Wallingford. The hole was filled with debris and trash that needs to be removed prior to backfill. Also, there is another piece of casing that was used during the drilling process that should be cut off to the proper depth. I departed location and communicated the deficiencies to AOGCC Inspection Supervisor Jim Regg. 10/24/19: 1 arrived on location for a second inspection to check for proper cut-off depth of the well. The casing had been cut to the required 3 feet below natural grade satisfying the current regulation. Information on the marker plate was verified and installed. Attachments: Photos (3) 2019-1024_Surface_Abandon_Moquawkie-1 11.doex Page 1 of 3 Zai-G�v�1 McPhee, Megan S (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, March 7, 2019 8:13 AM To: Mcphee, Megan S (DOA) Subject: FW: CIRI P & A well status Could you place this email letter in all of the well files listed below. There should be 8 wells listed. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 (Guv schwartz@aloska govt. From: Ed Jones <jejones@aurorapower.com> Sent: Wednesday, March 6, 2019 1:53 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: George Pollock <gpollock@aurorapower.com>; Tom Redman <TomR@kfoc.net>; Mark Carr <MarkC@kfoc.net>; David Wallingford (david996@yahoo.com) <david996@yahoo.com> Subject: RE: CIRI P & A well status Guy, Following is an update on the status of each of the CIRI wells, formerly operated by Aurora Gas: Aspen 1(WDSPL)—PTD 205-111: An MIT was performed on the well on 10/14/18, the temporary tubing plug was pulled, and the well was cleaned out with slickline bailer. Produced water disposal was commenced soon thereafter, and 473 bbl of produced water was injected into the well for disposal in 3 days October. Another 2486 bbl of produced water, returned packer fluid (while cementing or testing), and cement rinsate were injected in 13 days in November. The well and injection facility was then winterized and shut-in pending commencement of plugging operations in the spring of 2019. Kaloa 2—PTD-204-096: A CIBP was set in the tubing at 2331' on 10/26/18. The tubing and IA were pressure tested to 1775 and 1700 psi, respectively on 10/31/18 (witnessed). On 11/7 35 bbl of cement were pumped of planned 49 bbl— ran out of cement. Shut down and tested in AM—tubing to 1650 psi and IA to 1700 psi. Submitted request for remedial procedure, which was approved. Barge delivered additional cement. On 11/10/18, cement was tagged in tubing at 373', perforated tubing at 370-373', and cemented down tubing with 11.7 bbl of cement, with cement to surface after 8.5 bbl. On 11/15/18, pressure tested tubing to 2175 psi and IA to 2300 psi. No further activity was performed pending cutting off casing this spring. Simpco Moquawkie 1—PTD 178-047: the pretest of the tubing and IA in late October indicated a casing leak. A temperature survey was performed while pumping down the IA, and a casing leak was indicated at 2122-46' (old squeeze perfs). A revised cementing procedure was submitted to the AOGCC and approved. On 11/3/18, the well was cemented by pumping 1 bbl down heater string, 112 bbl of cement down the tubing until cement returns at surface, then IA was shut in and 1 bbl of cement was squeezed into old squeeze perfs resulting in a squeeze pressure of 1700 psi. On 11/8/18, the tubing and IA were tested to 1800 and 2550 psi, respectively. No further activity was performed pending cutting off casing this spring. Simpco Moquawkie 2—PTD 178-088: Tubing and casing were pressure tested (witnessed) to 1600 and 1550 psi, respectively on 10/24/18, and the tubing was perforated at 5209' on 11/5, as sliding sleeve could not be opened. On 11/6, the well was cemented: 30 bbl were pumped down OA, then 193.6 bbl of cement were pumped down IA and up tubing to surface. The tubing, IA, and OA were pressure tested on 11/8 with final pressures of 2900, 3050, and 3050 psi. respectively. No further activity was performed pending cutting off casing this spring. Mobil Moquawkie 1—PTD 203-069: Pressure tests of tubing and IA were performed and witnessed on 10/15/18. The sliding sleeve at 2513' was opened and on 11/2/18 the well was cemented with 195.5 bbl of cement slurry pumped down the tubing with cement to surface out the IA. On 11/9, the tubing and IA were tested to 2450 and 4060 psi, respectively. No further activity was performed pending cutting off casing this spring. Moquawkie 3—PTD 205-080: The well was cleaned out with slickline between 10/17 and 10/22, and a CIBP was set in tubing at 1410'. On 10/27, the tubing and IA were pressured tested (witnessed) to 2000 and 1650 psi, respectively, and the tubing was perforated at 1380'. On 11/1, the well was cemented with 36 bbl of cement pumped down the tubing, with the IA shut in after 30 bbl pumped and 6 bbl was squeezed into open Beluga perfs at 1402-69'. On 11/8, the tubing and casing were pressure tested to 2225 and 1500 psi, respectively. No further activity was performed pending cutting off casing this spring. Moquawkie 4—PTD 207-084: Pressure tests of the tubing and IA were performed and witnessed on 10/30/18—the tubing to 1725 psi and the IA to 1750 psi. On 11/4/18 the well was cemented with 37.3 bbl of cement down tubing and out IA. On 11/8/18 the tubing and IA were pressure tested to 1450 psi and 2000 psi, respectively. No further activity was performed pending cutting off casing this spring. Lone Creek 1—PTD-198-084: Closed sleeves on 11/3/18 and set CIBP in tubing at 1780'. On 11/16/18, pretested tubing an IA, and pumped 15 bbl down OA at 1 BPM. On 11/18/18, tested tubing to 1780 psi and IA to 1700 psi (witnessed). Opened sleeve at 1745'. Prepared to cement as per approved procedure in Sundry, except will likely use light -weight cement to fill IA instead of viscous spacer. Lone Creek 3—PTD 205-097: 11/2-11/5/18 closed all sliding sleeves in the well (PX plug in bottom packer at 2841' from previous operations, so tubing is closed to all perforations). On 11/17/18, tubing and IA were pressure tested (witnessed), tubing tested to 2080 psi and IA to 1500 but dropped to 1225 in 30 minutes—packer leak is suspected. Revised procedure was submitted to AOGCC to add a second plug below top packer on 11/26/18, which was approved on 12/11/18. Lone Creek 4—PTD-207-084: All sleeves are closed and there is a PX plug from earlier operations at 20571. On 11/17, the tubing and IA were tested (witnessed) to 2200 and 2100 psi, respectively. The tubing was perforated above and below the top packer at 1078-81' and 978-81' in preparation to cement as per procedure. The plan forward is to mobilize in late April or early May depending upon the Schlumberger cementers availability, barging access, and road conditions. At that time, the 3 Lone Creek wells will be submitted as per procedures (approved revised procedure of #3 and an additional 35 bbl of light -weight cement will be pumped in the Lone Creek 1 instead of viscous spacer), which should take 7-10 days, including West Side mobilization and set up. The Wach saw will be mobilized at about that time, the well heads removed and the casing cut off, any top -off of cement will be done, steel plates welded on, and the cellars backfilled. Please let me know if you need additional information. Thanks, Ed J. Edward Jones Petroleum Consultant 4645 Sweetwater Blvd., Suite 200 Sugar Land, TX 77479 713-899-8103(C) 281-495-9957, ext 201 (0) 832-999-4382 (F) From: Schwartz, Guy L (DOA) (_mailto:guv schwartz@alaska eov] Sent: Monday, March 04, 2019 1:30 PM To: Ed Jones <> Cc: George Pollock <gpollock@aurorapower com> Subject: CIRI P & A well status Ed/George, I never received a final update on the work that was done on these CIRI wells.. last update was in first week of November. I recall you requested a temporary shutdown of operations until spring to finish the wellhead cutoffs. don't have an email or any documentation that I can find for this request. You are requested to provide an update on each of the wells current status and detail your plan to return and finish the P & A wellwork. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 aovl. y Illk STATE OF ALASKA RECEWED AL A OIL AND GAS CONSERVATION COM . ION REPORT OF SUNDRY WELL OPERATIONS JAN 2 3 2018 1.Operations Abandon Li Plug Perforaticars L Fracture Stimulate Li Pull Tubing Ll A• - ;.wn Ll ' Performed: Suspend El Perforate 0 Other Sfirnraate Ili Alter Casing LI C -,,_ e,. Plug for Reda [i] Perforate New Pool ❑ Repair Well 0 Re-enter Susp Well D Temporary Plug 0 2.Operator Aurora Gas,LLC 4.Well Class Before Work: 5.Permit to Drift-Number: Name: Development Q Exploratory El 203-069 3.Address: 3705 Arctic Blvd.#2114 Anchorage,AK 99503 t Stratigraphic 2 Service 2 6.API fikenber 283-10019-00 7.Property Designation(Lease Number): 8.Well Name and Number: C-061390 Moquawkie#1 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): NA Moquawkie Undefined Gas 11.Present Well Condition Summary: otalltepth measured 11364 feet FRugs measuredT2bub: 95 feet true vertical 11364 feet Junk 'treasured None feet Effective Depth measured 2995 feet Packer measured 2555-2687 feet true vertical 2995 feet true vertical 2555-2687 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 213 2094*P440 213 213 520 psi: 1530 psi Surface 2455 13 3/8 61 V J55 2455, 2455 3090 psi 1540 psi Intermediate Production 10350 9 5/8 474 L80 10350 10350 6870 psi 4760 psi Liner Perforation depth Measured depth 2636-2864 feet 'rte Vertical depth 2636-12864 -feet Tubing(size,grade,measuredand true vertical depth) 2 7/8 6.5#J55 2810 2810 Packersand'SSSV+(type;measured and true vertical depth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): NA SCANNED ,fAi\ 3 _j (.) Treatment descriptions including volumes used and final pressure: NA 13. Representative,Daily Average Production or Injection Data. Oil«Bbir S Gas-fwfcf: s Water-Bbl. S Casing Pressure i' Tubing Pressure Prior to well operation: 0 0 440 Subsequent to operation: 0 0 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory Q Development 0 Service 0 Stratigraphic Q Copies of Logs and Surveys Run ❑ 16.Weil Status after work: Oil El Gas D WDSPL El Printed and Electronic Fracture Stimulation Data Li GSTOR '0 WIN." 0 WAG 2 GINI D 3USP;2 SPLUG 17. I hereby certify that the foregoing is true arid correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-273 Authorized Name: George'Pollock Contact Name: Authorized Tittle: anager-Prod Ops&Eng Contact Email: opollockaaurorapower.ci Authorized Signature: .-�"-- " -V- Data 1/23/2018 Contact Phone: 907.351.8286 / 24e ( R Q 0 M S L U'r Mi % 4 ? 18 Submit Original only Form 10-404 Revised 412017 /° 0y • • Aurora Gas, LEC Operations Summary—Set Temporary Plug Moquta.wlsie#1 Well juty 21, 2an 0600 hours Mobilize to location 0645 hours Move Rig from M3 to location, R/U WL, PT lubricator w/ wellbore 0715 hours RIH w/gauge ring-to 2505'_KB,_tag-profile, POO1-1,=00H wimud 0800 hours RIH w/2.4"brush to 2505',brush profile, POOH 0830 hours RIH w/2-7/8"X-Line w/PX Plug to 2505%WT, set plug,POOH 0930 hours RIH w/2" SB w/Prong to 2505',WT, POOH 1000 hours illeed-off well,_monitor Pre-s sure 30minutes,Pass 1030 hours RD WL 1100 hours Mob to M4 ... . . • • , Aurora Gas*LLC Mobil Moquawkie No. t Completion configuration — . ' rl 2.7/3"-k5At8rtrE1lY-MOD-14511/1Tto-stgeface Original R103 370' ,''...); ;' i ---V 4 'I'..., 4 :'.414' 36"Corregated Conductor „„--,.. • .',,:;"', :-;0•74 ';49 tate .---,a,t,,' ta, a 20'901140 Structural Drilled 26"Hole '1'1,„ :101'41, ri, ifi,, ttr.0„ gg., , Conductor Set at 213', fte,,,14 ,e,, i, ,q1i.t it, ..4.: Cmtd to surface w/1000 sx ,., t'l 4'' ''fi l• Of,4.4.7 'id o il 4':.a.' 11111 . , Stage collar @ 502' ::11.ttE-1,,,i. .::---0,7.-2 . .ri l's-q _./.3_3k,"-Csg-perfedu:2"- w/-5' _boles Drilled 17 1/2"hole ,ax ;„-- '' ' — el\. . r,,,,:,„,,, at 12504. Pivviously squeezed Iv/ ',.-4i.,, 44 14 350 rit ',. 133/B*61N Jrn Surface Csg at 24S4. Cmtd.w/1506 RI around 04 Sliding Sleeve 2513' 11',e.,'. shoe&510 sx through stage.k* alit. ce.;,., collar®502'. 1 •i';',,Iti 'rf' ,g4t,: Previously perfed w/5 spf,4-1/2" g wr:k''' 4181.411113 at 2352'and squeezed 1 Vi, 9-SZS-Bydro Patirer x ,'4 ,. na - -=4kittk Wilt-kis"G"icemen t I 342/au@ 2534.sr 1 i',0 04:24 =14..i" Drilled 32 114"Holt tt4 rill ;tt to; i N t -at k ,, Screen ail 2598.35'-2629.39' A . f.ihsto.4''' iidg • • Prod perfs®2636'-2656'& ._t _2662'-.2.678‘wt5scifela fa" 1' - 1 -IA* HSD,guns t4-1 ' 'ZAP nig 1 4..,..4 - 1 9 5/8 AM'Packer®26S7.43' 1:1'1, to i 4741 P.- 4 e014 at oi - „v tilij 1. k 1%,.44 t' Previously perfed w/5 spf,4-1/2" 11 EHSD guns at 2730'and squeezed .g.'t ' w/5.5 bbls cement 44.14 ,a. 0 Serronal 274.6.45'—2725.51" ,-49 ; 1 '2.' '0 1 ' '' = . -- -Prod pails ,,. 2742'-2762'& , ._.2 - — 2770 790'vet 5spf,4-3/2 ;...iiv 1 1 wi- %...:10 1-TSD guns H ! Tit Zri , 1 t !At 1 Screen(12t2790.43'-2810.46' -.. ;'''",,,-, lig j Ntt',ir ...7',, IPA Prod perfs @ 2823'-2843'& 4',... Bull Plug(;)2810.46' '• •' 2854'-2864'w/5spf,4-1/2" . " Ett HSDrSuns :0 ,11. Previously perfed and squeezed• ,v IP 2932' 1 "%TO , , ,;,.* ,r0A.,7....ge,. ..1,:t CIBP set @ 2995' 4,,t ,,-4*- ,-- -4142,4.•-!, i,-1,„, 1,,:,,t14 g. PBTD®2995' ".61' ,,,: 9 5/8"47#L-80 Production Csg®3030'. Cmtd w/205 Please see attached Weatherford i sx"G"neat lead at 15.8 Completion Diagram for addition ppg and 850 sx"G"WI gas ,statail gar-caw olletioriggimigtv. , bloc-kat 15.11-ppg. 1 -1 t 0 rigi nallydrilled to TDat 10,350'MD / (10,350'TVD). Please sec=original well ) / I file for detail below 2995'. I Fairweather E&P Services,inc. 1 Mobil Moquawkie#1 Rev.1.0 i 9115/2006 RLS 1 Drawing Not To Soak.. 1 8,OF 7•4 • • \� v7, THE STATE Alaska Oil and Gas "„iv �l ice 9 Of T 1sKA Conservation Commission = - 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 rti Main: 907.279.1433 ALA9*P' Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock NOV 0 6 2.017' Manager S`AN�E® Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Moquawkie Field, Undefined Gas Pool, Moquawkie 1 Permit to Drill Number: 203-069 Sundry Number: 317-435 Dear Mr. Pollock: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the 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�-q day of September, 2017. RBDMS ( , OSI - 3 2017 ECEIVED 11111 • SEP 14 2017 STATE OF ALASKA AOGCC ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon Q Plug Perforations 0 Fracture Stimulate ❑ Repair Well ,❑ Operations shutdown 0 Suspend ❑ Perforate ® Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redri l ❑ Perforate New Pool ❑ Re-enter Susp Well Q Alter Casing ❑ Other Temporary Plug ❑ 2.Operator Name: 4.Current Web Class: 5.Permit to Drill Number Aurora Gas,LLC - Exploratory ❑ Development 2 1 203-069 • 3.Address: 1400`W.Benson Blvd.Suite 410Strati<Jrapfnic ❑ �� ❑ 6.API Number: Anchorage,AK 99503 50-283-10019-90• 7.If perforating: 8_Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? j)f c- Moquawkie#1 - Will planned perforations require;a spacing exception? Yes ❑ No [il 11/41 9.Property Designation(Lease Number): 10.Field/Pool(s): C-Q61390! FEE.E. A43 Moquawkie Undefined Gas - . 11. PRESENT WELL copornatit MAMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: -MPSP-(psi): Plugs(MD): Junk(MD): 11364' 11364' ' 2995'. 2995' • • 650 psi 2513'&2995' None Casing Length. Size MD TVD Burst Collapse Structural 7 k Conductor 213' 20"9411140 213' 213' 520 psi 1530 psi Surface 2455' 13 3/8'61*J55 2455' 2455' 3090 psi 1540 psi Intermediate Production s 10350' 9 5/18"•4744.80 10350' 10350' 6870 psi 4760 psi / Liner Perforation Depth MD(ft): Perforation Depth IVO(t): Tubing Size: Tubing Grade: Tubing MD(ft): 2636'-2864' • 2636'-2864' 2 7/8" 6.5#J55 2810' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(R): Hydraulic and ASIX • urrc @ 2555'and ASIX @ 2687' 12.Attachments: Proposal Summary Q Wellbore schematic [3 13.Weil Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 2, Service ❑ 14.Estimated Date for TBD 15.Well Status after proposed work: Commenting Operations: OIL ❑ WwNJ ❑ WDSPL ❑ Suspended El , 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: rNJ ❑ Op Shutdown ❑ Abandoned ❑, 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval Authorized Name: George Pollock Contact Name: George Pollock Authorized Title: Manager- Ott ng Contact Email: gpoliockCc�aurorapower.cam Contact Phone: 907-351-8286 Authorized Signature: -. " ""�� Date: 14-Sep-17 Y Conditions of approval: Notify Commission so that a representative may witness Sundry Number. �,� � ( 317- 113. Plug Integrity Dt;I BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance X Other: A.(!.� ^ /1X1` r-wt) UD(.tAi.4 i r, A .C. tvv.T CFP E NAA 1t Pt-Al Post initial injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes El No ©- Subsequent Form Required: `O .-40-1 RBDMS Li OCT - 3 2017 APPROVED BY (7__i_K)=----\Approved by: COMMISSIONER THE COMMISSION Date: 912-4 (r7 -11$ 7////0- 4,7'idtri `is-LSI!: �� ,( c e O m 1 a6 ti Form 10-403 Revised 4/2017Subsi form and pirfVMd� n�varttl for 12'morassthe date of approval. ` - Atladuneeds�DupScate • • AURORA GAS, LLC WELL ABANDONMENT MOBIL MOQUAWKIE #1 August 2017 Version 1.0(9/1/17) CURRENT CONDITON'S: Max SITP-900 psi (Blows down quickly). KB=20.0 feet CASING: 9-5/8", 40 &43.5#N-80 & S-95 set at 10,350'MD. TUBING: 2-7/8", 6.5#J-55 Mod 8 rd EUE, w/ 8.5 ppg KCl inhibited brine as packer fluid in tbg-csg annulus above,top packer and with: Slid n,gSleees tat: WXA;at 2513' (closed—opens upward now closed) with PX plug set in profile above it. Other Hardware: 2.31"X nipple at 2596' (now open); and 2.31"XN nipple at 2703' (open); 4-1/2" Sand Exclusion Screens at 2568-2630', 2705-2726', and 2790-2810' with 3-1/2"tubing spacers and Bull Plug at 2810'. Packers: Hydraulic packer at 2554.5'and Mechanical Arrowset ASIX at 2687' (See attached well bore diagrams) CAPACITIES: 2-7/8"6.5#Tubing: 0.00579 bbl/ft; Tubing-Casing Amaulus: 0.4584 bbl/it 9-5/8", 43.5# Casing: 0.0744 bbl/ft. Tubing volume to top packer=14.76 bbl,Annular Volume to top Packer= 149.2 (if 43.5#, 152.5 if 40#); to all perfs (tubing and between packers)=48.0 bbl PERFS: Carya 2-4.1 at 2636-56'& 2662-78' Carya 2-4.2 at 2743-62', 2770-90', 2823-46',and 2854-64' NOTES: 1)Well is a"straight"hole. SUMMARY OF PLAN: RU slickline. RIH and pull prong and plug at 2513'. Open sleeve at 2513' and dump 8.5 ppg KC1 brine into tubing to kill well—add additional clean produced water(or 3%KC1)to tubing and annulus to fill if needed to kill (not likely). Fill tubing and casing with clean field produced water or 3%KC1 water. Close sleeve at 2513'. Run CIBP for 2-7/8"tubing and set in top of top packer at 2555'. Test CIBP to 1500 psi. Open sleeve at 2513'. RU cementers,on tree(thru wing valve). Establish circulation pressure with 5-10,bbl KC1 water at 3 B=PM. Pump 830 sx (955 cf=170 bbl)Class G cement(15.8 ppg, 1.15 cf/sk yield)with pump time of 4 hr at 70 degrees-4% excess and displace to surface—this one balanced plug is to meet the requirements of: 1)plug for perforated intervals, 2) surface casing shoe, and 3) surface plug. Monitor for flow or fall back. Wash out tubing casing annulus to 3-4' below GL. WOC 8 hrs,pressure test to 1500 psi. Bleed off pressure. MI crane. Remove tree. Cut off casing strings and tubing 3-4' below GL. Mix any cement needed to fill any casing.sting or tubing to cut-off. Weld on permanent marker cap. Call inspector. Upon approval,=remove cellar and burgs narks. Remove surface equipment nom location. 'Grade location. Take soil samples for confirmation of no contaminants. co;cv''• the weld /��fted (erwl�,�ly vet;l Jam/ Loo? a - wl�,'c� rime ;r s f�v� ve ?v /Ito% c��.�ril,' 9a,j /.tt andwar{� /ritr Pf//¢,y Ns) 14,¢tl - / 4,•r t kC d �' i'5 ervc1 en a74 • • PROCEDURE 1) Pick and move weilhouse. Notify AOGCC inspector of plans for plugging operations ✓ a 2) Move in cementer(pump truck/mixer), bulk cement( 900 sx Class G), slickline/electric line combo unit, water tank with 100 bbl fresh water for cementing, mud"pit"open tank with mixing capability with 100 bbl clean produced water or 3% KCl water, open"cuttings"tank for returns. RU cement pump to tree through wing valve. 3) RU sliekline lubricator on tree. RIH and, pool prong from PX plug at. 2513'KB✓Allow pressure to equalize(expect maximum of 900 psi). Check lubricator and tree for leaks. If none,pull PX plug body. 4) Kill well by RIH w/shifting tool and opening sleeve at 2513' and dumping 8.5 ppg KC1 packer fluid from annulus into tubing. Allow tubing to stabilize,bleed off pressure. Add clean produced water or 3%KC1 water to fill tubing and casing if needed to kill well. (Volume to deepest open perfs is 48 bbl). 5) Close sleeve at 2513'. 6) PU CIBP for 2-7/g"CIBP, RIB and set inside top packer at about 2555'. Pull up,then go back and tag CIBP. POOH. Pressure test CIBP to 1500 Asir. Release pressure. PU shifting tools, RIH, and open sleeve at 2513'. POOH. 7) COMBINATION PLUG: RU cement pumper on wing valve of tree. Open casing valve (tubing- casing annulus) and pump 10 bbl into perfs with KCl water down tubing and establish circulation and pressure at 3 BPM. Mix and pump 830 sx Class G cement(accelerated for 4 hours pump time at 70 degress,15.8 ppg, 1.15 cf/sk yield)down tubing,circulating cement to surface{2%excess). Catch annular brine for use in subsequent wells,divert to open tank as soon as returns are cement colored. This is to be a balanced plug—monitor'for flow or fall back. 8) When cement top is stable, disconnect cementer. Wash out tubing, and tubing-casing annulus to 3- 4' below GL. WOC 8 hours. Pressure test both sides (tubing and annulus) to 1500 psi. Release pressure. MI crane. Remove tree. Cut off conductor, surface, and production casing strings and tubing 3-4' below GL. Mix any cement needed to fill any casing sting or tubing to cut-off. Release cementers and slickline units to next location. Gc,tzc -res r- Fol 3e *A"-I 9) Fabricate 1/4" steel marker-plate cap for 36"conductor casing, nor to extend beyond casing OD, and bead-weld the following information onto marker plate; Aurora Gas, LLC %oma i%-9c, CAkv ©FF eL t,,,,t, PTD#203-069 Mobil Moquawkie#1 �� FLA-Te � t�� \O-401 t.4Jtit'i I 1-1 API# 50-2.83-.100.19-90 10)FollnwMg any anymecessary inspections,remove cellar and bury marker. Dispose of any waste. Haul KCl water,tanks,and any support equipmertt ito next location. 11)Remove tree and casing/tubing cut-offs, surface production equipment, trash, and any other materials from the location. Clean up, grade and level location. Take soil samples and send to lab to confirm no contamination. Ed Jones(9/1/17) • • Aurora Gas, LLC MOBIL MOQUAWKIE NO. I PROPOSED PLUGGING AND ABANDONMENT ,.-. " ,�_/ r, , Original RKB 370'(KB-20' 9-5/8"X 13-3/8"Annulus sqzd " '_ ' " ' w/100 sx G cement from ,' ::'".° . : • • Aurora Gas, LLC MOBIL MOQUAWKIE NO. 1 PROPOSED PLUGGING AND ABANDONMENT t} , x ,+". , ?,y Original RKB 370'(KB-201 9-5/8"X 13-3/8"Annulus sqzd '*' �` w/100 sx G cement from Z•" • 36"Corregated Conductor surface to 325' Drilled 26"Hole '''• ! }" {r .' 20"94#11-40 Structural Conductor Set at 213',Cmtd 2-7/8"6.5#ppf J-55 Mod tbg to ', s. '' ' w/1000 sx surface 2-7/8"X 9-5/8"annulus is =••,. •* 2-7/8" . .� Drilled 17 112"Hole filled with 8.5 ppg KC1 water, '• which will be dumped into the +.•, 13-3/8'Csg perf'd&sgzd at tubing thru sliding sleeve at ;1 .0,- . '. T� 1250'w/350 sx 2513'to all the open perfs to �;.' ' ' �'• ' fill wellbore below C1BP and - ..' COMBINATION PLUG: to kill well. U.Tyonek Perfs,Surface Casing Shoe, ' '{'' ' and Surface from 2555'to surface—set CBS(before ; E 1�'!. ° CIBP inside tubing in top of packer at squeezes `_ "..'f 2555',open sliding sleeve at 2513', 2552'and 2730')shows spotty ��' 4, circulate with 830 sx.G Cement from cement up to about 2400'in 9- .. ' *' 2555'to surface. 5/8"X 13-3/8"annulus. ,�• r. ., .r t A Drilled 12 1/4"Hole ` * 133/8"61/#J-S r Surface Csg at 2455'. Cmtd w/1500 sx"G"thru shoe+510 sx :, .. XA Shing Sleeve.*2513'(open) with 2 bbl G cement t 4.10p Hydraulic Packer at 2554.5' w X nipple at 2596' Sand exclusion screen at 2598-2629' Prod Perfs at 2636-2656' y 11 . 2662-267W Squeeze perfs at 2730'w/5.5 �', �,, ir AS1 X Packer( 2687' bbl cement tit Prod Perfs:2743-62' ...-- '1" 1111= XN Nipple 2703' 2770-90' ® , - • Well completed with sand Prod Perfs:2823-46' _ ilio; exclusion screens 2705- .-- 2854-64' 2725'and 2790-2810'w/ +4*., bull plug at 2810' Squeeze perfs at 2932'w/900 ' , •----" sx ',4 -°* 1.--::., m CIBP set at 2995' PBTDE-2995' ."» N -,` 50 sx Balanced Plug at 5105-5240' Old Prod Perfs(Mobil)5300-25' 5345-65' \ • 9 Perfs and Sgzs between 5280-10,269' Originally drilled to TD at 11,364' with 1115 sx cement and 6 Cmt Retainer ' 4• y or Soz Packers between 7400-10.283' MD). Please see original well file for -r well detail below Aurora Gas PBTD of 2995' 9 55/8"40&43.5#N-80& ,.. S-95 Production Csg @ ''+ 10,350'. Cmtd w/750 sx+ 50 sx below sqz pkr at 10,283'. • • vof THE STATE Alaska Oil and Gas tii O T A Conservation CO111I111SslOn €Sr = = 333 West Seventh Avenue " GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 o'er^ •� � Main: 907.279.1433 ALS AFax: 907.276.7542 www.aogcc.alaska.gov George Pollock somas) , UL 2 6 Zvi!, Manager Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Moquawkie Field, Undefined Gas Pool, Moquawkie 1 Permit to Drill Number: 203-069 Sundry Number: 317-273 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 4 l Chair DATED this day of July, 2017. RBDMS Cc JUL 1 1 2017 • S 41) 'AEC' E7 1 V E D • STATE OF ALASKA JUN 1 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS A0G CO 20 AAC 25.280 1.Type of Request: Abandon 2 Plug Perforations 0 Fracture Stimulate 0 Repair well 0 Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing Eil Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Atter Casing 2 Other.Temporary Plug 0• 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Aurora Gas,LLC Exploratory 0 Development E. 203-069 • 3.Address: 1400 W.Benson Blvd.Suite 410 Stratigraphic 2 Service D 6.API Number Anchorage,AK 99503 50-283-10019-90 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Moquawkie#1 • Will planned perforations require a spacing exception? Yes cj No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): C-061390 • Moquawkie Undefined Gas 11. PRESENT WELL CONDITION SUMMARY Total Depih MD(ft): Tqtal Dett5'0,,VD(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): Junk(MD): ii-- (-5 a / 636V; 2995' . 2995' • 650 psi 2995 None Length Casing led.;.-ii f1 'A f Size MD TVD Burst Collapse Structural Conductor 213' 20"94#H40 213' 213' 520 psi 1530 psi Surface 2455' 13 3/8"61#J55 2455' 2455' 3090 psi 1540 psi Intermediate Production 10350' 95/8"47#L80 10350' 10350' 6870 psi 4760 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(It): 2636'-2864' 2636'-2864' 27/8" 6.5#J55 2810' Packers and SSSV Type: Packers and SSSV MD(ft)andlVD(14 Hydraulic and ASIX Hydraulic(i2 2555'and ASIX(if 2687' 12.Attachments: Proposal Summary D Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program 2 BOP Sketch D Exploratory 2 Stratigraphic 0 Development 0 • Service 0 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL 0 WINJ 0 WDSPL 0 Suspended El 16.Verbal Approval: Date: GAS 2 • WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown EI Abandoned El 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. George Pollock George Pollock Authorized Name: Contact Name: Authorized Title: Manager-P-4 Ops ••.ng Contact Email: apollockaaurorapower cam oe-t..------ Contact Phone: 907-277-1003 Authorized Signature: . Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: *•• t CtArt..,z.kie_Ni Z.A.A.L., pr k.,IS tvc-ir ts•••1: -N- ctaso.42.C.-bAt:- .'N Ft>z, St..A.c.,Velzr.,toi-3 • Va. {) .. Pc Post Initial Injection MIT Req'd? Yes 0 No D Spacing Exception Required? Yes 0 No 2( Subsequent Form Required: \0—A 04. RBDMS t---- JUL 1 1 2017 Approved by: LU2C< COMMISSIONER APPROVED BY THE COMMISSION Date: "q 1 c4 0 ,1 0RIQ ) Na AL tAnk-thili Submit Form and Form 10-494kevised 4/2017 li ap i on is valid for 12 months from the date of approval. Attachments in Dupiicate 1.1't L #t ;17 • • Aurora Gas, LLC June 16,2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission RECEIVELi 333 West 7th Avenue, Suite 100 JUN l Anchorage, AK 99501 l0)1 Re: Application for Sundry Approval—Set Temporary Plug QGC Moquawkie#1 Well PTD #: 203-069 API#: 50-283-10019-90 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Moquawkie Undefined Gas Field on the west side of Cook Inlet, northeast of the Village of Tyonek. This well is currently not producing and is mechanically sound. v 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 2513' 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. A back pressure valve will be set and the master valve repaired and then will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information, please contact me at(907) 277-1003. Sincerely, eorge Pollock Manager—Production Operations&Engineering 4645 Sweetwater Boulevard, Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd,Suite 410 *Anchorage,AK 99503 * (907) 277-1003 . • Aurora Gas, LLC Mobil Moquawkie No. 1 Completion Configuration 2 7/8"6.5#8rd EUE MOD J-55 the to surface Original RKB 370' r i,4 fA., r ap ,,F' 4 ,> 9., 1 +°f rte r1 - :14; ;fin 36"Corregated Conductor i 01 SA. } 'V?/ � 20"94#1I-40 Structural ; Drilled 26"Hole c t -;0' ,r/ Ft,I r,; ;i p+ tt+,. +'V+ + rk Conductor Set at 213', AisTtgis, 1,fi3 1 C�a • fxTtlr Cmtd to surface w/11100 sx , . T. ' Stage collar @ Ri4 r. 4 • Fr. 502' 4:.�¢F .Ce a ly e � ,r( t t `41.1,;,;' _ ,,: 13 38"Csg perred w/5 1/2"holes Drilled 17 1/2"hole �� f' {' at 1250'. Previouslysqueezed w/ 0 7 t, t. 350 sx P; rr . iis1 ' ,4'. 13 3/8"61#J-55 Surface Csg at �'t- v t 1 Y�a; 2455'. Cmtd rv/1500 sx around Sliding Sleeve 2513' '; 0° ' ' shoe&510 sx through stage t i' ® ' 0 {,;, 's L1 collar 502. lil !il•< �' Previously perfect 1v15 spf,4-U2" w — _ gr 1•ISD guns at 2552'and squeezed 9 5/8 Hydro Packer x a ', , w/2 bbls"G"cement 3-12/2EU r 2554.57' , 1 '' 13 > f ar#?y� F I 'ry.L�Y g .. Drilled 12 1/4"Hole Screen 0 2598.35'-2629.39' 0 1 Oki {}�� t r - �, A.Wip -- Prod perfs®2636'-2656'& i - 2662'-2678'w/5spf,4-1/2" t ;` i ' HSD guns f t ' _' rr 9 58 ASIX Packer @ 2687.43' W l E. 1 �� _ .' Previously perfed iv/5 spf,.4-112." r _ HSD guns at 2730'and squeezed g " w/5.5 bbls cement 0 Screen Z,2705.45'-2725.51' 11', O'r i? r _ �'*'" Prod perfs @ 2742'-2762'& 1 2770'-2790'w/5spf,4-1/2" r . HSI]guns r 1 ,Screen a 2720A3'-2810.46' !tt 's �" s f4 Prod pods @ 2823'-2843'& Bull Plug a 2810.46' i'ISh 2854'-2864'w/5spf,4-1/2" ,` i HSD guns 1 ,a w { w,''` Previously perfect and squeezed @ r 2932' pt i ,' r 44: !,''',,‘.,,,;,. :'* ;•.,•.7e::4,1 CIBP set @ 2995, ;P „;e: i r F PBTD®2995' n:. . :1, 0/. E '<: 9 5/8"47#L-80 Production Csg @3030'. Cmtd w/205 Please see attached Weatherford sx"G"neat lead at 15.8 Completion Diagram for addition ppg and 850 sr"G"w/gas detail nn cmmnletion string. block at 15.8 ppg. f e Originally drilled to TD at 10,350'MD / (10,350'TVD), Please see original well ) ? 1 file for detail below 2995'. Fairweather-E&P Services,Inc. ( Mobil Moquawkie#1 Rev.1.0 19115/200e RLS 4 Drawing Not To Scale 1i • i AURORA GAS, LLC Slickline Temporary Plug Set - Generalized Procedure June 2017 SUMMARY: This procedure describes the steps taken to set a temporary plug in wells operated by Aurora Gas, LLC to secure the well for a short term shut in. RIH with drift for the appropriate sized tool for the tubing, in most cases 2 7/8"tubing with 2.312" or 3 1/4"tubing with 2.812"X landing nipple profile. Set PXX plug in uppermost landing profile. If a profile is not available, RIH with tubing stop pack-off plug and set above uppermost packer. After plug is set, a negative pressure test will be performed to ensure the plug has isolated the productive intervals from the surface. Upon passing the negative pressure test, the wellhead will be secured. PROCEDURE: 1) AG Operators to shut-in well and monitor pressure while rigging up. 2) RU Pollard Wire Line and lubricator on tree after removal of tree cap. Open well to pressure test lubricator—have pressure gauge on lubricator. 3) RIH with appropriate drift for X profile and sliding sleeves in upper profile. Pass through sleeve approximately 10' to insure safe operation of setting tool. POOH. 4) RIH with PXX Plug body on X-Line running tool. Set Plug body in upper most Sliding sleeve X profile above upper most production packer in well. 5) RIH with RB retrieval tool as running tool with prong. Set Prong in Plug body and POOH. 6) Record pressure and Bleed well bore to zero PSI, Monitor for 30 minutes recording pressure readings at 15 minute intervals. 7) Test successful if no pressure increase observed. If test fails, RIH and reset plug. 8) RDMO Pollard Wire Line. 9) Secure the wellhead. 10)Move to next well. 11)After 24 hours, a pressure reading will be obtained to ensure the integrity of the plug. 4k .$aua9e(6/11/2017) • • ~~-.: - „ MICROFILMED 03!01 /2008 DO NOT PLACE .:;~~ '.~ ,,... „w--` ' , ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs_Inserts\Microfilm Marker.doc . . PAurora Gas, LLC September 18, 2006 RE.CE.\\IE.O StY?, 5 ?GGß . " C mi'lmisS1on ,"" &. Gas l,Of\$· , Alaska t,\\ ne t'\ Ment}{a" Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Report of Sundry Well Operations Aurora Gas, LLC: Mobil Moquawkie #1 (PTD 203-069) Dear Commissioner Norman, Aurora Gas, LLC hereby submits its Report of Sundry Well Operations for the work performed in working over its Mobil Moquawkie #1 gas production well in the Moquawkie Gas Field on the west side of Cook Inlet. Please find enclosed the following information for your files: 1) Form 10-404 Report of Sundry Well Operations 2) Workover Operations Summary 3) Wellbore Diagram as completed If you have any questions or require additional infognation, please contact me at (713) 977-5799 or Ron Stadem at Fairweather at 258-3446. Sincerely, AURORA GAS, LLC S+~ ~~~ardJOneS / / Vice President, En~ering and Operations enclosures cc: Mr. Ron Stadem - Fairweather · STATE OF ALASKA . ALASKA~LAND GAS CONSERVATION COMMIS REPORT OF SUNDRY WELL OPERATIONS RECEIVED SEP 2 5 2006 1, Operations Abandon Performed: Alter Casing 0 Change Approved Program 0 2, Operator Name: Repair Well oJ ' Pull Tubing 0 ' Ope rat Shutdown 0 Plug Perforations Perforate New Pool 0 Perforate 0 4, Well Class Before Work: Development 0 Stratigraphic 0 Other WaiverD Time Extension 0 Re-enter Suspended Well 0 5, Permit to Drill Number: Exploratory 0 203-069 Service 0 6. API Number: 50-283-10019-90 mission Aurora Gas, LLC 3. Address: 1400 W, Benson Blvd, Ste 410 Anchorage, Alaska 99503 7, KB Elevation (ft): 370' 9, Well Name and Number: Mobil Moquawkie #1 I 8, Property Designation: 10, Field/Pool(s): C-061390 Moquawkie . Total Depth 11, Present Well Condition Summary: , th ofp 113(," /" q·ttf. measured *0 feet true vertical l' , feet 1/1 measured 2,995 feet true vertical 2,995 feet Plugs (measured) Junk (measured) 2,995' None Effective Depth Casing Length Size MD TVD Burst Collapse Structural Conductor 213' 20" 213' 213' N/A N/A Surface 2,455' 13-3/8" 2,455' 2,455' 3,090psi 1,540psi Intermediate Production 10,350' 9-5/8" 10,350' 10,350' 5,750psi 3,090psi Liner Perforation depth: Measured depth: 2,636' - 2,864' True Vertical depth: 2,636' - 2,864' Tubing: (size, grade, and measured depth) 2-7/8" J-55 2,547.44' Packers and SSSV (type and measured depth) Hydro 1 @ 2,554' ASIX @ 2,687' No SSSV 12, Stimulation or cement squeeze summary: Intervals treated (measured): 2,636' - 2'690 Treatment descriptions including volumes used and final pressure: See attached Daily Reports dated 2-Sept and 3-Sept 06 13. Oil-Bbl Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 780 si 10 si Prior to well operation: 0 SI Subsequent to operation: 0 SI t/ 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run None Exploratory 0 Development 0 ' Daily Report of Well Operations Attached 16. Well Status after work: OilD Gas 0 WAG 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Service 0 Contact Ron Stadem 907-343-0389 Printed Name J. Edward Jones Signature Title Vice President, Engineering & Operations Phone 719-977-5799 Date q/ZZ./Ob , IGINAL RBDMS BFl SEP 2 8 200~ r;{~ Submit Original Only A. .,.z,s-.O(. ~~p6/0/' . . OPERATIONS SUMMARY Aurora Gas, LLC Mobil Moquawkie #1 August 21, 2006 Move A WS # 1 Rig onto location. Begin rigging up. Circulate and condition brine to 9.7 MW, Set BPV, ND tree, NU 9" x 11" DSA, NU BOPE, Install catwalk and slide, function test BOP's, Test BOPE, RD test pump, BOP test wiaved by Jim Regg- AOGCC August 22, 2006 Continue rigging up. August 23, 2006 Continue rigging up and make repairs to derrick board. Fill pits wi 8.5ppg, 3% KCL brine mix. RIH wi Pollard wire line, open SSV @ 2544'. RD wireline and prepare to reverse circulate. August 24, 2006 Begin reverse circulation and circulate until MW is 8.5ppg. Set BPV. ND tree, NU BOPE. Test choke, BOPE and gas detectors. August 25, 2006 Change out Hydril, repair Koomey, MU flow line. RIH, pull test dart and BPV. RIH wi retrieving tool. Retrieving tool packed off, worked free and cleaned. RD landing joint and tubing swivel. POH wi existing tubing. Changed pipe rams to 3.5" and tested to 2000 psi. Pull test plug and set wear ring. Prepare rig for 3.5" tubing. August 26, 2006 Continue RU for 3.5" work string and PU fishing BHA. POH wi packer and screens. LD BHA, including screens and packer. August 27,2006 MU 8-112" bit and scraper and RIH. Wash sand over 2,700' - 2,734' interval. Work tight spot, POH and LD bit and scraper. MU 7-7/8" BHA. RIH, wash tight spot and tag sand @ 2,700. August 28, 2006 Wash 2,740 - 2,913 interval until clean and filter brine. POH, laying down BHA. MU tail pipe and packer, RIH and set packer @ 2,700'. POH. RU to swab. Raise flare. August 29,2006 . . RIH wi swab, tag fluid @ 600'. Swab tubing and tail pipe. Tail pipe set @ 2,800' Swab two runs per hour for six hours. Samples showing mud and sand @ 8.8ppg. POH. Monitored tubing wi Spyder gauge for one hour - no build-up. RIH wi swab, tagging fluid @ 2,200'. Pulled from no-go at 2,700'. Tried milking column recovering 2.5 bbls. Set Spyder gauge on tubing while RU to release packer - showing no build-up. Released packer. Took 20 bblloss while reversing. Back side taking one bph. Total swabbed: 60bbls Chlorides: 23,000 - 8.8 MW August 30, 2006 Build 50bbls volume - static loss 8bph. RIH additional 20' to check for sand under tail pipe. POH wi packer. Build 50bbls volume. RIH wi RBP, set at 2,705' and POH. PU packer and RIH. Swabbed hole wi following results: #1 tag 200' pull from 1700' 11 bbls #2 tag 900' pull from 2400' 6 bbls #3 tag 1300' pull from 2550' 6.5 bbls #4 tag 1200' pull from 2000' 2 bbls #5 tag 1200' pull from 2550 5.3 bbls (well flowing gas) Fluid in tubing wouldn't unload, dropped soap stick. Flow well through separator for 30 minutes, 8/64 ck. Pressure fell off. Shut well in and monitored wi Spyder gauge - no build up. August 31, 2006 Continue monitoring well for build-up. Swab tubing, tag fluid level @ 700', swab tubing volume. Shut in on Spyder gauge. Pressure built to 8 psi. Tag fluid @ 1000'. Swabbed tubing volume again pulling from no go @ 2550'. Shut-in well to monitor - well stopped flowing. Swabbed in approx. 42 bbls from 2500'. Ran flow to separator and flared. Shut-in on Spyder gauge - built up to 8 psi (100 bbls total fluid swabbed out - still showing mud in samples. September 1, 2006 Performed rig maintenance. RIH wi swab, pulled from no-go @ 2570' recovering 20 bbls. Noticed sand build-up on no-go. Shut in well on Spyder gauge while LD swab. Pressure built to 56.5 psi. Unseated packer and filled hole to balance. POH taking 14 bph over tubing displacement. Pulled wear ring, set test plug and filled backside while testing. Test BOPE. Repaired bell nipple and set wear ring. September 2,2006 RIH wi notch collar. Washed sand from 2,659' to 2,690'. Reverse circ'd sand until clean. POH. RIH wi packer. Set packer and checked wi 200 psi on back side. POH. RU BJ, and test lines to 3000. Pumped 9 bbls of acid blend (3% Ammonium Chloride, 10% Acetic Acid solution). Chased wi 27 bbls of 3% Ammonium Chloride, 25% Methenol solution. Shut in well to allow well to soak. September 3, 2006 Pumped 18 bbls of 10% Acetic acid, 1 % Hydrofluoric acid solution and 14 bbls of 3% Ammonium Chloride, 25% Methanol solution. Chased wi 27 bbls 8.6 ppg KCL brine. Injected at 300 psi. Fell to 0 psi. RU swab and lubricator and RIH. Pulled from 2500' . . recovering 1 bbl of 8.5ppg brine - 16000 chlorides. Milked from 2000' recovering 2.7 bbls. Fluid tagged at 1700'. Pulled from 2000' recovering 2 bbls in 4 runs. Continued pulling from 2000' for next 6 hours for a total of 18 runs and 12 bbls out. Last run showed no fluid in tubing. Shut in well and check two hours later - well dead. ./ September 4,2006 Commence swabbing again. Fluid level @ 2200'. One run per hour for 4 runs getting 2 bbls per run. pH dropped to 7 wi gas show. Continued swabbing at 1 run/hour wi following results: #1 3.3 bbls #2 1.6 bbls #3 1.6 bbls #4 1.6 bbls #5 1.6 bbls #6 6 bbls (gas/mud residue) POH and monitored well for remainder of day wi well open. September 5,2006 Continued monitoring well for first 7.5 hours. RIH wi swab having trouble finding fluid level. Swabbed 4 runs for returns of 15.5 bbls. Run #5 tagged fluid @ 1800' recovering 1.5 bbls of gas cut wi mud emulation. Runs 6 and 7 recovered 13 bbls pulling from 1800'. Runs 8 and 9 recovered 11 bbls. POH and shut in well. Pressure built to 100 psi. Flowed thru 14/64 choke @ 3 min/15 psi for 7 min. RIH wi swab. Run # 1 0 tagged fluid @ 1900' and pulled from 2500' recovering 4.5 bbls. Fluid level moved up 200' between runs. Swabbed at 2 runs/hour. Couldn't get past 1700'. Pulled cups off. POH. RIH wi sinker bars to no-go. Pulled from 1800' recovering 13 bbls over 8 runs, getting gas cut. POH and shut in well for build up. Total of 20 runs for 62 bbls. September 6, 2006 Continue monitoring well - pressures recorded hourly at: 0100 35 psi 0200 35 psi 0300 35 psi 0400 10 psi 0500 10 psi RIH wi lubricator and swab. Made eight swabs recovering 44 bbls @ 8.8 ppg and 24000 Chlorides. POH and RD swabbing tools. RIH and released packer. Circulated well. Well diverted to gas buster due to flow increase. Circulated gas out of well. POH and LD packer. Pulled wear bushing. Tested BOPE. September 7,2006 Continued wi BOPE test. Installed wear bushing. MU BP Retrieving tool and TIH to RBP @ 2,705'. Tagged sand @ 2,660'. Washed hole to 2,705. Reversed well clean wi filtered brine (5 micron). Latched and released BP. Monitored well. POH wi BP and LD retrieving tool. RIH wi serrated collar on tubing 2,705'. Washed from 2,705' to 2,908' and CBU. Reverse circulated and filtered brine. Note: Static loss rate of7-l2 bph. September 8, 2006 POH and LD 3-1/2" tubing. Changed rams to 2-7/8" and tested rams and door seals to 250 and 1500 psi, respectively. Pulled test plug and LD test joint. MU completion equipment and RIH. RIH wi completion assembly on 2-7/8" tubing. MU hanger and land completion - tested hanger seals to 1000 psi. RU slickline and set PX plug and prong in X-nipple @ 2,594'. Set packer wi 1500 psi, holding for 10 minutes. POB. RIH . . wi slickline and retrieve PX plug and prong. Open sliding sleeve @ 2,512' and POH. Reverse circulate corrosion inhibited brine to 2,512'. RIH wi slickline and close sleeve @ 2,512', verifying closed wi 500 psi. Set BPV. Begin RD of A WS # 1. ND BOPE and NU tree testing to 3,000 psi. Pull BPV and RU to swab well. Swabbed well for 18 runs '" recovering 78 bbls. Continue RD of A WS # 1. Rig released at Midnight. September 9,2006 Continued RD of rig. Move rig to NCU #9 Aurora Gas, LLC Mobil Moquawkie No.1 Completion Configuration Original RKB 370' 36" Corregated Conductor Drilled 26" Hole 20" 94# H-40 Structural Conductor Set at 213', Cmtd to surface w/1000 sx Stage collar @ 502' Drilled 17 1/2" Hole 13 3/8" Csg perfed w/5 1/2" holes at 1250'. Previously squeezed wI 350 sx Sliding Sleeve 2513' 13 3/8" 61# J-55 Surface Csg at 2455'. Cmtd wI 1500 sx around shoe & 510 sx through stage collar @502'. 9 5/8 Hydro Packer x 3-1212EU @2554.57' Previously perfed w/5 spf, 4-1/2" HSD guns at 2552' and squeezed w/2 bbls "G" cement Drilled 12 1/4" Hole Screen (iìJ, 2598.35' - 2629.39' Prod perfs @ 2636' - 2656' & 2662' - 2678' wI 5spf, 4- 112" HSD guns 9518 ASIX Packer @ 2687.43' Screen (iìJ, 2705.45' - 2725.51' Previously perfed w/5 spf, 4-1/2" HSD guns at 2730' and squeezed wI 5.5 bbls cement Prod perfs @ 2742' - 2762' & 2770' - 2790' wI 5spf, 4- 112" HSD guns Screen (iìJ, 2790.43' - 2810.46' Bull Plug @ 2810.46' Prod perfs @ 2823' - 2843' & 2854' - 2864' wI 5spf, 4- 112" HSD guns Previously perfed and squeezed @ 2932' CIBP set @ 2995' PBTD @ 2995' Please see attached Weatherford Completion Diagram for addition detail on comnletion strinº" 9 5/8" 47# L-80 Production Csg @ 3030'. Cmtd wI 205 sx "G" neat lead at 15.8 ppg and 850 sx "G" wI gas block at 15.8 ppg. ) Originally drilled to TD ~' TVD). Please see file for detail below 2995'. z L Fairweather E&P Services, Inc. Mobil Moquawkie #1 Rev. 1.0 9/15/2006 RLS - . . FRANK H. MURKOWSKI, GOVERNOR ALASKA. OIL AlQ) GAS CONSERVATION COMMISSION 333 W. 7'H AVENUE. SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Edward Jones Vice President, Engineering and Operations Aurora Gas, LLC 1400 W. Benson Blvd, Ste 410 Anchorage, AK 99503 &03- o(Pq Re: Moquawkie Field, Moquawkie Undefined Gas Pool, Mobil Moquawkie # 1 Sundry Number: 306-275 hUG ~~ ~:¡ Dear Mr. Jones: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. 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. Sincerely, DATED this-'Þday of August, 2006 Encl. DC73" ?~ STATEOFALASKAql.}S·(. 4RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION . AUG 1 4 2006 APPLICATION FOR SUNDRY APPROV ALS\l,# .' 20 MC 25.280 Alnlt:a nil R. r.~t r"M' ,. 1. Type of Request: Abandon 0 Suspend 0 Operational shutdown 0 Perforate 0 Waiv.~orage Other 0 Alter casingD Repair well ~ ,II~Ð' Plug Perforations 0 . Stimulate 0 . Time Extension Change approved programD Pull Tubing 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 0 203-069 . 3. Address: Stratigraphic 0 Service 0 6. API Number: 1400 W. Benson Blvd, Suite 410, Anchorage, Alaska 99503 50-283-10019-90 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: N/A Spacing Exception Required? 0 No 0 Mobil Moquawkie #1 Yes 9. Property Designation: roo KB Elevation (ft): 11. FieldlPool( s): C-061390 370' KB Moquawkie 12. PRESENT WELL CONDmON SUMMARY Total Depth MD (ft): r0tal Depth TVD (ft): ¡Effective Depth MD (ft): Effective Depth TVD (ft): rlUgS (measured): runk (measured): 10,350' 10,350' 2,995' 2,995' 2,995' None Casing Length Size MD TVD Burst Collapse Structural Conductor 213' 20" 213' 213' NlA NlA Surface 2,455' 13-318" 2,455' 2,455' 3,090 psi 1,540 psi Intermediate Production 10,350' 9-518" 10,350' 10,350' 5,750 psi 3,090 psi Liner Perforation Depth MD (ft): rerfOration Depth TVD (ft): rUbing Size: Tubing Grade: Tubing MD (ft): 2,636' - 2,864' 2,636' - 2,864' 2-718" J-55 2,864' Packers and SSSV Type: Weatherford Arrowset 1-X pkr @ 2,589' Packers and SSSV MD (ft): Same 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: 8/1912006 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 Bill Penrose 250-3113 Pri_ Name C - J. ............. Title Vice President, Enaineerina and Operations Signature /"'. .h. .Á Phone Date 8// f /Ofo þ--- _. ·,,.-b,,, / /I 713-977-5799 // // COMMISSION USE ONLY I Conditions ~roval: Notify Commission ~at a representative may witness ISUndry Number: 2x:J.g. a 75 Plug Integrity 0 BOP Test ~ Mechanical Integrity Test 0 Location Clearance 0 Other: êXJeo p"::."\ ß'O\? ~~"'>\- 0-<;' ç\~.. 4a~ ~ RBDMS BFl AUG 1 7 20D6 Subsequent Form Required: ¥~b (7j ~~R APPROVED BY Approved by: THE COMMISSION Date: V...... 4/J f·,,{', ~ Form 10-403 Revised 0612006 ORIGINAL ;;il~~ . . Aurora Gas, LLC MOBIL MOQUAWKIE #1 2006 RIG WORKOVER / CLEANOUT PROCEDURE (VERSION 1.1) CAPACITIES: 2-7/8" Tubing: 0.00579 bbl/ft and 9-5/8" 40 & 43.5# Casing: 0.075 bbl/ft Casing Drift ID is 8.599" CIBP at 2995'. Tubing Volume to Packer is 15.0 bbl. Casing vol. below pkr to deepest perf: 21 bb1 RESTRICIONS IN TUBING: Tubing ID=2.441" (drift-2.347"), WF Sliding Sleeve at 2544' wI 2.321" X profile and On-Off Tool at 2586' wI 2.321" X profile. PACKER: Weatherford Arrowset I-X Retrievable Production Packer at 2589' wI 4-112" Stratapac Screens at 2639-2710',2734-96', and 2833-64' wI 3-112" tubing spacers. Bull plug at 2864'. PACKER FLUID: 3% KCl water wI 02 scavenger. HISTORY: The Mobil Moquawkie #1 well (MM 1) was re-entered and recompleted in 2003. It produced 1255 MMcf in about a year before starting to produce some water and sand. The well was SI in July 2005 when sand plugged up the surface facilities and damaged the compressor. The #3 well came on about the same time, using the same facility, so a sand filter was designed and added to the joint facility. Several attempts to put the #1 well on thru the sand filter have been unsuccessful as the well has loaded up and died. Long term SITP of 780 psi between attempts indicate that the well has significant remaining reserves (1450 MMcfwl a 75% RF based on P/Z vs. Cum Prod. Plot)/ Slick line sinker bars were run into the well in May and found fill at 2668' inside the sand-control screens--samples of the fill indicate that it is fine sand and drilling mud. Thus, it is believed that: 1) the water and sand are likely coming from the same perfs, and 2) the perfs giving up the water and\ sand are likely the deepest ones open in the well (at 2823-2864'). PROPOSED WORKOVER: 1 he proposed work is to: 1) pull the existing completion, which may involve washing over the screens beneath the packer-not a gravel pack, but free screens hanging from the packer; 2) clean out the well; 3) isolate and test the perfs to determine the source of sand and water; 4) plug back or isolate the water/sand bearing perfs; 5) stimulate,if necessary, the remaining perfs to clean up and restore production (well averaged 1500 mcfpd last month of production); and 6) re-install the packers and screens as appropriate to return the well to production. ..- 1) Prior to moving in rig, wI well SI (master, wing, and SSV), disconnect flow line downstream ofSSV. Disconnect electrical and put in safe place-use care to avoid damaging. (Need Work Permit from Operators to do so). Remove well house from #1 well and set aside out of the way. 2) Move in, rig up A WS #1 rig wI single workover pit for mud system (not AG mud system) and support equipment only as needed. 3) Starting with clean mud tank, mix 150 bbl (usable volume) 3% KCI water in field produced water brine (+1-8.5 ppg-max bhp expected is 830 psia at 2636'=0.31 psi/ft or 6.0 ppg). Expected volume to fill well is less than 38.4 bbl. . . 4) RU to pump down annulus thru casing valve on tree. Expect to have some pressure (200-300 psi}-bleed off. RU to take returns from flowline (2-9/16", 5000# API flanged connection}-have operators open and lock SSV open wI screw-on cap. Disconnect SSV controls and put aside in safe place. 5) RU Pollard with lubricator on tree cap. Run in hole with slick line and open sliding sleeve at 2544'. Reverse circulate volume (20-40 bbl) to kill well with 8.5 ppg brine. (May be several bbls of diesel freeze protection at the top of the annulus-when well is dead, circulate out into separate tank, store in containment-take to waste oil burner at Shirleyville when the capacity there is available). Monitor well--circulate/reverse circulate as needed to kill well- expected kill weight brine weight is only 6.0 ppg. May lose volume as open perfs are somewhat depleted. Monitor losses-may need to use LCM (salt or ground calcium carbonate) material to control. 6) When well is dead, set BPV in tubing hanger, ND tree, NU 3000-psi BOPE. Test to 2000 psi (or as required by AOGCC Sundry approval). 7) Latch onto tubing hanger and release packer, if possible. Reverse circulate tubing as needed to get any gas out of tubing Monitor well to be sure it is dead. Attempt to POH wI tubing, packer, and screens-suspect that screens may be sanded-in at 2668' or so where we found fill inside screens. If unable to pull, call out Schlumberger to run free-point. While waiting on Schlumberger, release On-Off tool, TOH wI 2-7/8" tubing, standing back. PU 3-1/2" L-80 EUE tubing as work string and run in hole with On-Off connection. Engage On-Off tool. Pull to release packer (limit to 60,000# overpull, or about 85,000# total on weight indicator). If it does not come free, go to Step 8. If it pulls free, go to Step 12. 8) RU Schlumberger and run free-point indicator. Run jet cutter and cut in 3-112" production tubing above free-point. Callout fishing hand, mill, overshot, bumper sub, jars, etc. POH wI workstring and packer, standing back workstring and lay down On-Off tool, packer, tail pipe and any screens. If top offish is deeper than 2800', go to Step 12. 9) Pick up mill, 4-3/4" drill collars, and run in hole on 3-112" tubing. Dress top of fish. TOH, standing back tbg and DC's. LD mill. 10) PU fishing string: overshot, bumper sub, and jars. TIH and engage fish. Attempt to fish for at least 24 hours or until jars fail. Make detennination as to whether or not to wash over-need to wash over max. OD of5.l2" (screens). 11) Continue fishing operations: either run wash pipe and wash over or free-point and cut deeper until hole is clean to 2800' or deeper wlo additional fishing (to 2900' at most). When hole is clean to this point, go to Step 12. 12) Run 8-112" bit and 9-5/8" 43.5# casing scraper on 3-112" tubing and clean out to 2810' or deeper. Circulate hole clean. Circulate and filter brine until it is as light as possible (for 3% KCl) and clean (thru 5 micron sock filters). POOH with tubing, laying down 3-112" tubing, bit, and scraper. However, if fish remains in the hole, set a CIBP just above fish (run on 3-112" tubing before laying down). 13) RU Aurora Gas Test Unit as follows: . . a) set test choke manifold close to rig choke skid and connect w/ 1502 hard line; install 24/64" positive choke in manifold (left side)-- use 2" 1502 target tees upstream of choke skid; b) run AG 2" 1502 hard line from choke manifold to test separator; c) set flare stack 100' or more from the rig and 100' or more away from trees and raise stack; d) lay AG 3" 1502 hard line from separator skid to flare stack, and connect propane bottle to flare stack, and e) RU sand monitor on test separator inlet line. 14) PU Treat/Test Packer (w/ unloader/circulating valve) and RBP and TIH to below deepest open perfs (either at +/- 2875' or at 2805'). Set RBP. Pull up and set pkr at above deepest perfs at either 2800' +/- or 2766'. Prepare to swab test deepest open perfs. (We want to isolate and test perfs at 2823-64',2770-90',2742-62' , and 2632-78' for water and sand). 15) Prepare for test: a) Take and record initial measurements of brine levels in all tanks to which swabbed/flowed back brine will go-know exact volume of brine is in all tanks; b) Record test separator water meter reading; c) install new chart on Barton recorder; d) install fresh nitrogen bottle onto skid for instrumentation; e) install new 2000 psi pressure gauge near test head, isolated with needle valve (upstream from valve that will shut in well for buildup-will want it to record and show SI pressures), and 1) confirm electric clock on chart recorder is on and set to 12 hrs and chart is appropriate for clock time. 16) Swab in deepest set of open perfs and flow test until clean and stable, as follows: a) swab in, unloading fluid to shaker/possum belly until well is gassing and/or kicks off to flow; b) when significant gas is at surface (whether swabbing or flowing) or the well is flowing, divert flow to test separator: i) shut down momentarily to light flare stack, then bring back on, adjusting choke size until well is flowing strongly to cleanup, but holding some back pressure on it (probably start at 14/64's and adjust accordingly, target flow at 400- 500 psi. ii) Flow until rate and pressure have stabilized for 15 minutes, increasing slightly is OK, but dropping is not-wait until fluctuations tend to be up, not down) and water has dried up (all of tubing volume + casing volume to bottom of top set of perfs has been recovered) or rate has stabilized. Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water production and cleanup. Watch for sand production in water. If producing any sand or much water, shut in and call. iii) Start w/ 1-1/2" orifice in test meter. Flow rate in mcf/day= static reading (blue) X differential reading (red) X 70, Ifred chart reading is below 3, change to 1.0" orifice; if it is above 8 change to 2.0" orifice. Meter factors change to 31 or 130, respectively. Orifices may be changed by experienced operator while flowing wi the Daniel Sr. orifree fitting- iv) Catch water samples thru out (downstream of test separator)--have tested by mud engineer for cWorides and weight-record both and time of sample. Produced water should have cWorides of less than 20,000 ppm and . . -' ""'. " weight is less than 8.4 ppg-if water is trending in that direction, continue to flow until these properties have stabilized. Keep last sample of produced water to send to lab in Anchorage-label thoroughly. v) Shut in well for buildup twice as long as flow period (should build up to about 780 psi). Report test results to me (Ed)-including email report of flow and buildup tests. 17) Open unloader and reverse out gas to kill well thru choke. When well is dead, release packer, CBU. Release pkr, retrieve RBP, and set RBP above these perfs (where packer was set). Get offRBP and test to 1000 psi. Reset pkr above next shallower perfs (at 2770-90' or 2742-62') and repeat Step 15 to test perfs. 18) Repeat Steps 16 and 17 until all open perfs are tested 19) If well does not come back at rate in excess of 1500 mcfpd, will consider small UCAlOCA acid clean up treatment (HF/Acetic Acid w/25% methanol)- procedure will be provided-flow back and retest. 20) At this time, well tests will be analyzed and the permanent completion design will be finalized. I expect will be setting a CIBP above the bottom perfs (at +1- 2810') and rerunning the completion very much like it is now, wi crossovers as needed, using old completion equipment from well when it is in good condition: a) 2-20' 4-112" Stratapack screens across the perfs at 2742-2790' wi 10' 3-112" tubing spacer between screen sections (or 2 - 30' screen sections as before if in good condition) and bull plug on the bottom b) 3-112 tubing spacer c) 4-112" screens across perfs at 2636-78' (either 2 - 30' sections as before or 2 20' sections) d) 3-112" tubing spacer to Arrowset mechanical packer to be set at 2575-2600'. e) OnlOffTool wi X profile f) 1 jt 2-7/8" tubing g) 2-7/8" WXA sliding sleeve wi X profile h) 2-7/8" 6.5# 8 rd EVE tubing to surface 21) Set packers, space out and land tubing. Set BPV. ND BOPE, NU and test tree. 22) Circ packer fluid wi scavenger/biocide and corrosion inhibitor-do not use diesel to freeze protect. (After setting packers, place by reversing thru top sliding sleeve, at +1-2544', unless packer serviceman recommends otherwise). 23) With all sliding sleeves shut, swab in and test thru test unit-get stable rate and buildup. 24) Set BPV in tree. Release rig, rig down and move. Pull BPV from tree after rig has moved. Put well on production thru existing facility. NOTE: None of the zones in this well after this work are producing in Moquawkie 3 nor any other well in the field. Ed Jones 8/8/06 . . c . "~AulOl'a Gas, LLC D Proposed m Current Mobil Moquawkie #1 Gas Prod. Granite Point, Alaska L 350' riginal KBE 370' 26" Hole 02 Inhibited 3% KCL Packer fluid above packer 17 1/2" Hole 27/8" Sliding Sleeve wI "X"landing profile @ 2544.3' T -2 OnlOff Tool wI "XA" Profile @ 2586 9 5/8" Weatheñord Arrowset 1-X Retrievable Production Packer @ 2589' 31/2" 9.2# L-80 8rd Tubing Spacer wI crossovers to 4 1/2" LTC 41/2" 12.6 #/ft Stratapac Screen 2639' - 2701' 12 1/4" Hole 3 1/2" 9.2# L-80 8rd Tubing Spacer wI crossovers to 4 1/2" LTC 41/2" 12.6 #Ift Stratapac Screen 2734'-2796" 3 1/2" 9.2# L-80 8rd Tubing Spacer wI crossovers to 4 1/2" LTC 41/2" 12.6 #Ift Strata pac Screen 2833' - 2864' 4 1/2" Bullplug@ 2864.21' Please see attached Weatherford diagram for completion detail Attachment I 2 7/8" 6.5# 8rd EUE MOD J-55 ProductionTubing I ! / Mobil Moquawkie #1 Fairweather E&P services, Inc. I 36" Currogated Conductor 20" 94# H-40@ 213" c......-. CMT'D to suñaceW/1000 SX Stage Collar at 502' 133/8" Csg peñed w 15 (1/2") holes at 1250' 350 SX cmt squeeze peñormed 133/8" 61# J-55 @ 2455' CMT'D WI 1500 SX around shoe & 510 SX through stage collar at 502' Squeezed 2 bbls "G" cement Squeeze Perfs shot at 2552' 5 SPF, 41/2" HSD guns Production Perfs 2636' - 2656' & 2662' - 2678' @ 5 SPF w/4 1/2" HSD guns Squeezed 5.5 bbls cement Squeeze peñorations shot at 2730' 5 SPF, 4 1/2" HSD guns. Production Perfs 2742' - 2762' & 2770' - 2790' @ 5 SPF w/4 1/2" HSD guns Production Perfs 2823' - 2843' & 2854' - 2864' @ 5 SPF w/4 1/2" HSD guns Original Squeezed Peñorations @ 2932' CIBP set at 2995' New PBTD @2995 See original well file for well detail below 2995' Rev. 05 DHV27-Dec-2003 Drawing Not to Scale . . www.aurorapower.com RECEIVED AUG 1 4 2006 Comnission Alaska Oil & Gas Cons. Anchorage August 14, 2006 Mr. John Norman, Chairman Alaska Oil and Gas Conservation COnunission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval: Workover of Mobil Moquawkie #1 (PTD No. 203-069) Dear Mr. Norman: Aurora Gas, Ltc hereby applies for approval of ils plans to work OVer !be Mobi] Moquawkie #1 gas well in the Moquawkie gas field on !be West side of Cook lnJet. The workover is expected to commence in the week of August 21. ' This workover will iovolve cleaning out the well, testing existing perforations and ~ possibly isolating some of the perforations. Enclosed p]ease find a Fonn 10-403, Application for SWldty Approval, for t/ús work. Also enclosed are a detailed work plan and current MM #] well bore diagram. The BOP system to be used for this workover is the same as that previously used 00 the A WS #] rig and is on file with the Commission. When returning !be approved SWldty, please also mail a COpy ro Bill Penrose at Fairweather. lf you have any questions or require additional infonnation, please contact me at (907) 277-1003 or Bill Penrose at 250-3113. Sincerely, AURORA GAS, LLC enclosures cc: Bill Penrose - Fairweather 10333 Richmond Avenue, SU/18 710. Houoton, Texoo 77042. (713) 977-5799. Fax (713) 977-1347 t400 West B8noon Blvd., SuIte 410. Anchorage, Ala_ 99503. (907) 277-1003. Fax (907) 277-1006 . . Sundry Application 306-275 Review Recommendation: I recommend approving the work proposed in this application, which may include plugging perforations. Discussion: Aurora Gas, LLC ("Aurora") submitted the subject Sundry Application for proposed work on the Mobil Moquawkie #1 ("MM1") well (PTD 203-069). The proposed activities are intended to return the well to regular production and include the possibility of an acid stimulation and/or plugging perforations to eliminate water and sand production. MMl was drilled, completed, and tested in 2003 and began regular gas production in July 2004. The well remained on continuous production until July 2005 when sand production from the well plugged surface facilities and damaged a compressor. After repairing the surface facilities Aurora has been unable to return the well to regular production. The well had a peak production rate of approximately 5,500 MCF/D in October 2004 and was still producing approximately 1,500 MCF/D prior to shutting the well in due to the surface equipment damage. Cumulative production from the well has been nearly 1.3 BCF. Aurora states that the shut-in tubing pressure for this well is 780 psi and that their P/z analysis shows that approximately 1.45 BCF remains recoverable. In May 2006 Aurora tagged fill in the tubing at a depth of 2,688 feet, which is near the bottom of the shallowest set of perforations in the wellbore, their analysis of the fill showed it to be fine grained sand and drilling mud. They propose to pull the existing completion string from the well and to attempt to clean the wellbore to expose all three sets of perforations. There are actually six distinct perforated intervals (2,636' to 2,656', 2,662' to 2,678', 2,742' to 2,762', 2,770' to 2,790', 2,823' to 2,843', and 2,854' to 2,864') but these intervals are paired into three sets (2,636' to 2,678',2,742' to 2,790', and 2,823' to 2,864'). They then plan to individual test each set of perforations, assuming they can clean the fill out of the wellbore to below the deepest perforations, and may acid stimulate the well and/or "plug" some of the perforations depending on the test results. Aurora anticipates that test results will show that the deepest set of perforations, 2,823' to 2,864', will produce large amounts of water and some sand and very little if any gas. If this assumption proves correct they intend to install a bridge plug above these perforations. The perforations will not be squeezed with cement in the traditional sense of plugging perforations but they would be isolated, which should allow the shallower perforations in the well to resume regular production. Aurora's proposed procedure indicates that they may acid stimulate the well if it does not corne back at a rate in excess of 1,500 MCF/D. . . I talked with Mr. Ed Jones of Aurora about their proposed program and specifically about what criteria would be used to determine whether or not to plug an of the perforations. He said they did not have a hard and fast rule, in terms of a maximum water cut or minimum gas production rate, that would be used to determine if they would plug a zone but would base the decision on the success of the well cleanup and well testing operations. I asked Mr. Jones if their assumption that the lowest perforations are the source of the problems with this well proved incorrect would they be able to isolate a shallower set of perforations and still keep the deepest set open. He stated that they are aware ofthis possibility and that their contractor is attempting to locate an additional packer, they intend to reuse their existing packer, that could be used in a completion string that would allow them to keep the deepest set of perforations open and still isolate a shallower set of perforations if needed. Conclusions: This well has an established history of significant sand production that resulted in damage to surface equipment and necessitated the well being shut in. Attempts to return the well to production have thus far been unsuccessful. Performing cleaning out the wellbore is the most likely means to restore production to the well. However, if Aurora does not curtail the sand production from this well it is likely that the well would be prematurely shut in again at some point in the future. Aurora's proposed activities to clean the wellbore and then test the individual sets of perforations to determine the source of the sand production, which the assume is associated with water production, are the prudent steps to take to troubleshoot the well. Isolating the problem interval through the use of a bridge plug and/or packers should alleviate the problem and allow the well to return to regular sustained production and ultimately the recovery of the remaining 1.45 BCF of reserves. D.S. Roby ~ Reservoir Engineer 8/16/06 /7 Æ1\ tI ,.(. ~(\ ç DATA SUBMITTAL COMPLIANCE REPORT 11/8/2005 S(l~ 7 6J-lJ)-¢~ API No. 50-283-10019-90-00 Permit to Drill 2030690 Well Name/No. MOQUAWKIE 1 Operator AURORA GAS LLC MD 3000 --- TVD 3000 ~ Completion Date 10/17/2003 Current Status 1-GAS UIC N Completion Status 1-GAS REQUIRED INFORMATION Mud Log No Samples No Directional Survey No DATA INFORMATION Types Electric or Other Logs Run: GRlCCUUSIT/RST Well Log Information: (data taken from Logs Portion of Master Well Data Maint Log/ Electr Data Digital Dataset Log Log Run Interval OH/ ;Z Med/Frmt Number Name Scale Media No Start Stop CH Received Comments og Reservoir Saturation 5 Blu 1 1940 2980 Case 11/6/2003 Reservoir Saturation Tool - I Sigma Mode -k( Completion ~<- Q~~) 5 Blu 2470 2915 Case 11/6/2003 Completion Record 4.5" HSD 4505 PJ, 5 SPF tOg Cement Evaluation 5 Blu 2000 2976 Case 11/6/2003 Ultrasonic Cement and (" Casing Imager I Log Casing collar locator 5 Blu 2000 2976 Case 11/6/2003 Ultrasonic Cement and I Casing Imager I Completion t8aJr~1. 5 Blu 2470 2840 Case 11/6/2003 Completion Record 4.5" ).-Log HSD 4505 PJ, 5 SPF ~og Perforation 5 Blu 2551 2553 Case 11/6/2003 Squeeze Perforating Record ./Log Perforation 5 Blu 2730 2732 Case 11/6/2003 Squeeze Perforating Record Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y It¡) Daily History Reœived? tIN If'1"N Chips Received? Y / N Formation Tops Analysis Y / N Received? Comments: . . DATA SUBMITTAL COMPLIANCE REPORT 11/8/2005 Permit to Drill 2030690 Well Name/No. MOQUAWKIE 1 Operator AURORA GAS LLC MD 3000 TVD 3000 Completion Date 10/17/2003 Completion Status 1-GAS Current Status 1-GAS UIC N Compliance Reviewed By: - J.o Date: API No. 50-283-10019-90-00 ;{D ~ r=- . . Re: Moquawkie Tie-in to Beluga Pipeline . . Subject: Re: Moquawkie Tie-in to Beluga Pipeline From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Tue, 28 Sep 2004 09:41:51 -0800 To: Chad Helgeson <chelgeson@emeraldalaska.com> CC: Ed Jones <jejones@aurorapower.com> Thanks much. My questions are answered. Tom Maunder Tom, Please see the response to the questions below. d-O~-()~~ µ~ '-.)C).,~ \L, "Ç\(~-,~ ~,\ c'" \7 <t ~~~II'-~ "'\- c:'~r-<t\~ \ Chad Helgeson wrote: Let me know if you need additional information. Thanks Chad Helgeson -----Original Message----- From: Thomas Maunder rmailto:tom maunder@admin.state.ak.usl Sent: Tuesday, September 28, 2004 7:33 AM To: Chad Helgeson Cc: Ed Jones Subject: Re: Moquawkie Tie-in to Beluga Pipeline Chad and Ed, Thanks for the information. Just a couple of questions/requests. 1. On the process flow diagram, the only meters I see are near the pipeline tie in. Is there a separate "test" meter for MM production?? On all of Aurora's wells there is a orifice meter downstream of the Production Separator, prior to any fuel gas takeoffs. This is usually a simplex type meter and is specifically for well allocation. There is also an orifice meter downstream of the gas dehydration system and downstream of the fuel gas system at each facility which is the sales allocation meter. 2. How is fuel gas metered?? Fuel gas is currently calculated based on each users fuel gas requirements, Le. when the compressor is running, it consumes approximately 200 mscf/d, but can also be measured by calculating the difference between the two orifice meters. 3. Is the fuel gas by-pass for start-up only?? The fuel gas bypass is for startup and in the event the compressor shuts down and when maintenance may be required on downstream equipment. 4. On the meter spec excel sheet, the differential for the orifice meter is stated as 0 - 10000 psi. This seems a little large, what is the correct differential range?? The correct differential range of the chart recorder on the orifice meter is 0-100" of water column. 5. Is there a calibration report for the sonic meter?? If so, it should be provided or a statement provided why there is none. There is a calibration report for the meter and I will provide this in a latter email, after we receive it electronically. It was calibrated by the Southwest research institute in San Antonio, TX. Also, is there a "general" diagram that shows all the Aurora lines and tie-ins?? If there is, I 10f3 9/28/2004 9:42 AM Re: Moquawkie Tie-in to Beluga Pipeline . . would appreciate a copy. There is not a general diagram showing all the Aurora lines at this time. There are currently only three lines that tie-into existing pipelines: Lone Creek ties into the Beluga Pipeline at MV#2 Moquawkie ties into the Beluga Pipeline at the Beluga to Granite Point Transition Nicolai Creek Facilities tie-into the CIGGS line near the Granite Point Tank Farm I look forward to your reply. Tom Maunder, PE AOGCC Chad Helgeson wrote: Tom, Please find attached some documents concerning the metering at the Moquawkie Pipeline Tie-in to the Beluga Pipeline. I have attached the following documents for your review: 1. Process Flow Diagram showing a general overview of the main process equipment from the wellhead to the Pipeline Tie-in. 2. Piping and Instrument Diagram for the Tie-in piping to the Beluga Pipeline. 3. The Specifications of the Ultrasonic Flow meter (Sales) 4. The Specifications of the Daniel Senior Orifice Meter (Backup Sales Meter) Please let me know if you have any questions, or need more information. Thanks Chad Helgeson Project Engineer EMERALD Chad, Please provide Tom with this info. Thanks, Ed ----- ------- Original Message ------- ----- From: Thomas Maunder <tom maunder(a~admin.state.ak.us> To: Ed Jones <jejones(ii?aurorapower.com> Sent: Wed, 04 Aug 200416:18:20 Ed, Congratulations on getting the new wells on line. A while back I think you sent in information concerning the meters at Lone Creek. Could you send in similar information on any of the new installations you have operating or under construction. If you have a drawing of what your gas system looks like I would 200 9/28/2004 9:42 AM Re: Moquawkie Tie-in to Beluga Pipeline . . appreciate that as well. Thanks in advance. Please call with any questions. Tom Maunder, PE AOGCC ----- ------- End Forwarded Message ------- ----- 30f3 9/28/2004 9:42 AM . . ",,\ I / / ',,", ~. EMERALD / II \"" Aurora Gas LLC FLOW METER (GAS) Revision: o Checked By: CAH Approved By: CAH Date: 8/1512004 Data Sheet Number: project: Mobil Moquawkíe No. 1 Service 1 Tag Number FE-100-92 FE-110-92 2 Description/Service Sales Gas Sales Gas 3 Line No. 4"-GD-0207-C 4"-GD-0207-C 4 P&IDDWG PI-MM-0007-OO1 PI-MM-0007-OO1 5 Fluid Natural Gas Natural Gas 6 Fluid State Gas Gas 7 Mach. Design Presure Maximum 1415 psig 1415 psig 8 Mach. Design Temp Maximum 150 deg F 150 deg F 9 Pressure. Normal (For Calc) 1000 PSIG 1000PSIG 10 Process Temp. Normal (For Calc) 60 deg F 40 deg F 11 Flowrate.Maximum (For Calc) 54.7 rnmscfd 12 Base Temperature I Pressure 13 Flowrate. Maximum 20 nvnscfd 14 Flowrate. Normal 6-8 mmscfd 6-8 mmscfd 15 Mol. Weight I CplCv 16 Specific Gravity at Base 0.57 0.57 17 Operating Specific Gravity 0.57 18 Compressibility (Z) 19 Operating Viscosity 20 Meter 21 Type of Meter Differential Pressure Recorder Ultrasonic Meter 22 Manufacturer & Model Number ~I Senior, Instromet Q-Sonic 23 Differential Range 0-10.000 PSi.) V-\OÕllWC 24 Sela SP. Gr. @ 60 deg. F ~ f __ (!' 't-AO.ì \. 25 Static Pressure Range 1500 psi 26 Chart or Scale Range 27 Chart Multiplier Plate 28 Type Orifice Plate 29 Manufacturer & Model Number Daniel 30 Design Basis N/A 31 SOre 2" 32 Material 316SS 33 Manufacturer & Model Number Daniel 34 Ring Material & Type Rubber 35 Orifice SOre Diameter 2" 36 Plate Thickness 118" 37 Vent or Drain Hole NIA Fitting 38 Type Flange Flange 39 Manufacturer & Model Number Daniel Instromet 40 Flange Specification ANSI 600# ANSI 600# 41 Material A235B-WPB A235B-WPB Meter Run 42 Line Size & Sched. liD 4" Sched 40 4" Schad 40 43 Pipe Material A106 A106 44 "U" (Upstr. Length) & Connection 44" Long. Flange 30" Long, Flange 45 "D" (Dnstr. Length) & Connection 45" Long, Flange 24" Long, Flange 46 Straightening Vanes 304 SS RF Profiler CPA 50E Type A Flow Conditiner Notes: 1) 2) 3) Sheet: 1 of 1 Remarks: . met, Inc. Ins . Q.Sonic 3 Path Ultrasonic Gas Meter Using the Absolute Digital Time Travel method (ADTT), the flow meter measures fluid flow by comparing the time taken by an ultrasonic pulse to travel from td and tu. The larger the difference in time taken, the greater the velo- city or flow ofthe fluid. Cross Sectional View ...-'" I II. , ~ .,"',..',"',..,.,;;""."....".....",,;"...,,;,.;, FEATURES .... No pressure drop .... Wide rangeability/turn down ratio 50:1 .... Bi-directional flow .... No moving parts .... Very low cost ownership (maintenance) .... Insensitive to contamination .... Interfaces with major flow computer mfg. .... Transducer exchange without recalibration The Instromet a.Sonic 3 Path Ultrasonic Flow Meter is a one-of-a-kind flow meter. The combination of sophisticated trans- ducers, digital electronics and the unique patented path configuration results in a meter unsurpassed in gas measurement accuracy. The proven accuracy (better than ± 0.5%) and its swirl analysis capa- bility makes the a.Sonic 3 Path the ideal meter for natural gas custody transfer measurement. Theory of Operation ,~ " ,,"".'¥ ," .'> & :¡j¡!'~ '" , , , , ~~i.:;",'~", / 11 ~" /'(f) II~V /' L/2 D y L/2 Travel Time Equations L L tu= c-v- COS (f) tD= c+ v- COS{f) . Velocity Equation ^ V= L 2 - COS{f) (&-&) APPLICATIONS .... Custody transfer measurement .... Underground (natural) gas storage .... Gas compressor control .... Gas processing plants ..... Measurement and regulation stations ..... In-plant metering ..... Power plants ..... Check meter for conventional custody transfer meter Instromet, Inc.' 3731 Briarpark. Suite 100· Houston, TX 77042· Tel: 713.977.3591' Fax: 713.977.0810 Toll Free: 800.795.7512· E-mail: sales@instrometinc.com·www.instrometinc.com . . Instromet, Inc. 611 Q.Sonic Ultrasonic Flow Meter 6" 100 200 300 400 500 600 700 800 900 1000 mmscfd PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG Qmin 0.3 0.5 0.8 1.0 1.3 1.6 1.9 2.2 2.5 2.8 Qmax 13.7 26.1 38.8 52.0 65.6 79.7 94.1 109.1 124.4 140.2 6" FLOW RANGE '~~i - ~:~~:t==:::~_~~~I~~~~ ::: :::: - ~";""'¡:~~"~~:'::~:::±;:::=I~~- 400 PSIG ", Ll N:4! 'I ~ë i H' :~, 1f1l!l 200 PSIG I ¡ 100 PSIG - 300PSIG ~~~~I ¡j r 11111 0.0 I 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0 110.0 120.0 130.0 140.0 150.0 MMSCFD ; 8" Q.Sonic Ultrasonic Flow Meter 8" 100 200 300 400 500 600 700 800 900 1000 mmscfd PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG Qmin 0.5 0.9 1.3 1.8 2.3 2.8 3.3 3.8 4.3 4.9 Qmax 23.7 45.2 67.3 90.1 113.6 137.9 163.8 188.8 215.4 242.8 r FLOW RANGE 1000 PSIG 900 PSIG 800 PSIG 700 PSIG 600 PSIG 500 PSIG 400 PSIG I I L , ] _:,.]2 I ¡ _1JJ.J. 'IiIL.," . ... 'oJE-piô.· T ~ ~..- ] 1 . ¡[- "i ¡ -~i~¡i;<.'¿~;';w: J~Z!!2~~Jt'~1('~W,P.-<'¡,,~~i% D ~ 300 PSIG 11II111101"....1"'1..,·"'·- 200 PSIG ~~' ::~~r 100 PSIG .......... ,'" 0.0 20.0 40.0 60.0 80.0 100.0 120.0 140.0 160.0 180.0 200.0 220.0 240.0 260.0 MMSCFD . . :.10IlQ.SonicUltråsonicFløw.Meter 10" 100 200 300 400 500 600 700 800 900 1000 mmscfd PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG Qmin 0.7 1.4 2.1 2.8 3.6 4.3 5.1 6.0 6.8 7.7 Qmax 37.4 71.2 106.0 142.0 179.1 217.4 256.9 297.7 339.6 382.6 10" FLOW RANGE 1000 PSIG 900 PSIG 800 PSIG 700 PSIG 600 PSIG 500 PSIG 400 PSIG 300 PSIG ~I: t~-- ~- ml-~L-- _~m ~.A~lI I IL-.. '!It j - 4. -,- ,-,_.~,_.._±~ ~ . l ..,.. ---- .. _',., :::tr~ I '-""'"j -11 /.... ¡ 11. ~)u~~ I Jill I IL ~~ l t~l;-~ '-'1 C I 1 -- __L--L. ,~....J. ~ 100 PSIG 200 PSIG )irŒJWi~~¡¡¡ JUhJtn: !iJ,øa 0.0 20.0 40.0 60.0 80.0 100.0 120.0 140.0 160.0 180.0 200.0 220.0 240.0 260.0 280.0 300.0 320.0 340.0 360.0 380.0 400.0 420.0 MMSCFO 12" Q.Sonic Ultrasonic Flow Meter 12" 100 200 300 400 500 600 700 800 900 1000 mmscfd PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG PSIG Qmin 1.1 2.0 3.0 4.0 5.1 6.2 7.3 8.5 9.6 10.9 Qmax 53.1 101.0 150.5 201.5 254.2 308.6 364.7 422.5 482.0 543.1 12" FLOW RANGE 1000 PSIG 900 PSIG 800 PSIG 700 PSIG 600 PSIG 500 PSIG 400 PSIG 300 PSIG 200 PSIG 100 PSIG L I J I I I I ] ~"''''''''''- .1(;: . ~t::. þr'::;~- I r . - [ .. "'" , I I ~ o ~~~~1001~1~1~1"mm~mmm~~~~~ø~_~~m~~~ MMSCFD . . Instromet, Inc. STANDARD METER SPECIFICATIONS: * * OUTPUTS: Four pulse outs: 0 to 10,000 Hz; Modbus or ASCII RS 2321485 PERFORMANCE: Rangeability of 2' to 100'/sec, .6m to 30m per sec. Accuracy within 0.5%, Repeatability equal or <0.2%, Bi-directional flow. Velocity Range: -100' to 100' per second, -30m to 30m per second. Extended Range of l' to 120'/sec.; 0.3m to 36m/sec. RESPONSE TIME: 1 update per second. APPROVALS: FM Class, Div 1, Group C,D. POWER: 12/24 VDC, 7 Watts consumption Included with each meter: · Frequency Splitter Card and Telebyte Converter· · Uniform software program for monitoring and configuring flow meter with a laptop computer · All documentation as per AGA Report #9 STANDARD SPOOL PIECE SPECIFICATIONS: · Body design code: CFR 49 Part 192** · Flange design code: ANSI B16.5 or MSS SP 44 · Design temperature: -20°F to 200° F, -2SoC to 93°C (meter body only) · Design factor: 0.5 · Design pressure: 1480 PSIG, 100 Bar for 600 ANSI** · Testing pressure: Standard; 1.5 x Design Pressure for 8 hours. · Transducer ratings: Standard: 220 to 2250 PSIG**, -20°F to 176°F; 15 to 172 Bar, -28°C to SO°C · Sandblasting: To near white metal · Internal coating: Rust preventative Solvent · External coat Standard; Ameron Amercoat 385, Light Gray, OFT 4 -6 mils. - Additional design codes, ANSI or pressures and transducers ratings available, please contactfactory for specffications. The above Ultrasonic flowmeter is in full compliance with the requirements of AGA Report #9 and approved for custody transfer by Nmi. Measurement Canada. PTS. DTI. Gost and etc. METER MATERIAL AND DIMENSIONAL SPECIFICATION SIZE ID Length Weight ANSI 600 Inches/mm Inches/mm Ibs/Kg 4781bs /217 Kg ASTM A 106 Gr. C 5951bs /270 Kg API 5L X42 767 Ibs / 348 Kg 876 Ibs I 398 Kg Body Materials Flange Materials 6" Q3 6.065" /154.05 mm 30" /1762 mm 8" Q3 7.981" /202.72 mm 40" /1016 mm 10" Q3 10.020" /254.51 mm 40" /1016 mm 12" Q3 11.938" / 303.23 mm 40" /1016 mm API 5L X52 API 5L X52 ASTM A105 ASTM A694 F42 ASTM A694 F52 ASTM A694 F52 "" ~c~ø ~ Q ""~ ~O ~_.-_..... ..------.--.-.......------.. _/ ~ ø/ Q / ~ ê @ cœ- @ ê "..n__._._ .______ _n.._._________._._. ~ I @ / "" ~ ""- ~ .~ & U 3Q.0124.01 Instromet, Inc.' 3731 Briarpark· Suite 100· Houston, TX 77042· Tel: 713.977.3591 · Fax: 713.977.0810 Toll Free: S00.795.7512· E-mail: sales@instrometinc.com·www.instrometinc.com . . 8 7 6 5 .. 4 .I!::1BII::12 ~ ~ KC-111/112-?? AC-I5Q/I60->? :\l:l2a::J2 .£::1Ji!b12 ~ ~ .I:f:Wb12 UNE HEATER INlET $EP_TOR 1WO STAGE ~ COOlDIS GLYCOl. CONTACTOR ~~ GLYCOl. I'UNP ~ GLYCOL SIJC110II SCRU88ER REGENERATOR I::J!1l:::§2 I::J!I2::22 ~ OILY WASTE GLYCOl. COLLECI1ON PRODUCED T_ TANK WATER TANK D ¡---n---l , I , I ! 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I 1 f . u,MÆ~ I ~.e.. => < ..., , '"~ ',', I, , "" 2 EE::l.QQ:.Q.2 BACKUP FLOW II£TER ORIFICE II£TER RUN VENT TO ATW. .=,'. ····ö:oo ~ 1'tIIIÆ<T....... 04ECG-461 ~ SALIS FLOW II£TER Ul'lRASONlC II£TER RUN I::J!2J:::a2 COULC11ON TANK D SAIl'<; GAS TO Bl'lIIGA PIPEliNE 11E-IN POINT ~ !:OJ ,--------, , FUEl. GAS FOR I I lIE-IN EQUP. I I I , I '\!.: I I ç 1"'::.~2 C' MElERING BUIlDING AT lIE-IN:J!JTO 1 - EI£LUC, PIP£LI<£. IIODULE 92 PECO -------- COALESaNG ALTER c 1--- ---;;;I I "I. I : ()n r)A'IM' : I I:.m I : OOliCTlON TANK : L_!!~AI!Y_CONT~~_.J +- B I. NOlES: ALl. EQUlPIotENT ac INSTRUMENT TAGS ",,1/£ BEEN GII/£H A 2-DIGIT SUFf1J( TO DEStGNAT£ WHICIi ='rW~~1r~E~~:~ NUMBERS UNIQUE FOR DRAWING PlJRPOS£S ONLY. '!HE TAGS IN THE REI.D DO NOT CARRY THE SAME 2-DIGIT SUFfIX. "Alo· STANDS FOR .1ðI:1>IE OROUND·. AND "ufo· STANDS FOR "UNDER GR()UNO". 2. 5 .... .~ ~. II "" '" , " 8 ),".'. ..,:,',.. ,',jl " I ..:i , I !A "' . .~, " I . .,,\,,', " ~I'I' rr " .,f., " . '. " .-= J In. '. ' 2 1.00'1'- ···Õ:ÖÕ·" ··Ö:ö'i¡···· ,,··,,·Õ:Ö¡¡,,· ·······Ö:OO"· NJiIIIAGAS.llt MOBIL MOQUAIIKIE PR[JDUCTION F ACILlTlES SIMPLIFIED PFD PF 1.4:--; 01 I; II$C. I ro:. I uaEJU 1Cl11EV... IF DO: 1 I -, ~ . . CIGGS PFEUNE BEl.UGA PIPELINE ~ ~ I I J I : ~ : I P I I 12' 'T' 900f 12' I ~----~-7~--~~ NOTE 4 ~ ~ 172-\J291 6"ff-- ~6"-CO-OZ07-C 1/2" -i>I<Þ ,--------------------------, , INSTRUMENT GAS : I I I ~J SETO SETO , 2',a" SET 0 I ~ r"' 1400 PSG II we 11 we I ~ ~~SETO I \U9lþ-- VENT I 150 PSG , I"; 1/2" ; TO AIIT i ~TOf I ~ I SETO I , I 80 PSG ~ : Lu___¡ , , U/TG A/G 1 : : I LG A' '" N N ~ '1 ~ ~ FRaW (REMOYÞ8.E I I ~ I 11 I SET 0 ~ 1 I MOeIl MOQUAWKlE '1 3/4" 6" PIG RECENER 1,1 1,1 I,: I,: èll00P i!s:1~r--~-'s~:§:-Õll ~. 1 " I PI-MII-0006) .f~205-C I FUEl GAS c _ ' SHT.2 6" 6- t FP ¡---IQf-{ : I I : : 1 13 PSG : N N:JN NOTE 6·" / . 4' 1 6' _-':[~--'::.¿ I -" I 1 3 4 . ::¡:. I 6' <r_".,~. I ~ ~ ~-------t 1/2" ---=-1 U/G ::~FROII 2" "-'r76"-ro-0206-C II- ~---"1 -c:----i pi ~¡ - - ¡ I 4"xS" N; I A/G I "~--> y.~..: ~ { 3 I '.-,~ '>Ç~ © '4 I' qifi'''' SHT.1 =~~ I/G~_--' ____'! ml IT ~ ~ "" , ¡ " 1/2" 1 . @) " -' I 1 C 1 1 !: mm: 1~/4' 1/~'~; ~ _~~T- ¡ ___________~:t~~_~~~~______¡__.I 1. ~~sr::s.;~~~".NID"U/G· 1/4" I" 1 1 ¡ ¡ ¡------- ---1(-1 ~ L_+-{;}--__________@______________~j : ~;~- ! (' n r \ \ NOTE 7 So ::.NO. c001-D+99-R-ot-5003-o1-E. I LG ~ I 6. FUlURE TIE-IllS. : CCUEC'I1(J' TANK : 7. REIIaIE PlPEUHE SIfJI-IN IWW SWITCH. I \J I 8. ALL INS1RIJII£NT TAGGING IS ASSUMED TO CONTAIN A I I SI<ID DEHIF1ER SUFRX. FOR EX.\MPlE PHZO IN , , MOOUL£ ZO WOULD SH<1/ ¡.s ·PHZO-ZO". L__ SEC(J'IlJ.~~!~N~__~ 8 7 . 6 ;) ~ CDUECI10N TANK 38".60' 300 GH.I.(J' tI::2D!I::II2 IIEŒR SKI) CATALYIlC H£A'ŒR 24.000 BIU/HR. 120 'IN:. EE::1.IXI=S2 IW:I<UP flOW IIEŒR !WIEL SR. ORIFICE IIEŒR RUN 4" ~ B\RTON 1140 El£CIRONIC R.OW COIIPIII£R ~ !W£S R.OW MEIER INSIROIIEI 1I.1RASON1C IIEŒR RIlN 4' E:1œ::82 PECO CO!LESCING Al'ŒR DESIGN PRESSURE: 1400 PSG 0 15O'F ZO' D.O. X 104" S/S DESIGN flOW RAlE: 30 IIIISCFD IIODEL 77V-5-338-20-14OO D c ~r-' I I , , , I I I , I I I .... B A IIEFÐIÐCE IIOAVIIIGO fCL DATE REVl$DJI I ./2SIØo4IU\EDF'DR~ 1 .6IISI04i RDSSUED F1JR a:JrCS1"FtUCT1 2 II/C5J'O.4 AS-IUlLT I't' Cft<1IPI'II NO. DATE ... .. .... ... .. .... ... .. .... 0EVtSIIIN DO'" 25N'RII4 25N'RII4 AURORA GAS U.c I'( ""..... 1IfPROVAI. -- DRII\rIN IYJ LSA ÍIESuiNt:D..,. IfJ) ...... 0£DC[]0 CAlI """"'VEDI'(. ............1'(. \llllKPKGo EMERALD 3 I 8 7 6 5 ... """"'.- I 4 D FUEL GAS TO> LOCAl GENERATOR S6' c -+ A/G U/G o NOTE 3 t- B A ~ _ GAS, LLC MOBIL f41QUA\(KlE DEVELOPMENT PRODUCTION r ACILITIES COAlESCING rIL TER/METERING BLDG, & PIPELINE TIE-IN P&ID 0=-".:" 192, PI 1./:,\lJHGO';;; 021;; I - DIS<. ,... SEIII.ENŒ 1Cl11I£Y... 1F1 ê 1 www.aurorapower.com January 2, 2004 Mr. Tom Maunder PE Senior Drilling Engineer Alaska Oil and Gas Conservation Commission 333 W. 7th Ave. Ste 100 Anchorage, Alaska 99501 RECEIVED JAN 092004 Alaska Oil & G as Cons C . Anchorage' ommlssion End of well reporting and documentation: Mobil Moquawkie No.1 Re-Entry (203-069) U: Dear Mr. Maunder, Aurora Gas, LLC hereby submits the final well report, which covers the re-entry and recompletion of Mobil Moquawkie No. 1. Operations were completed on October 28th, 2003. Pertinent information included under cover of this letter includes the following: 1) Form 10-407 "Well Completion Report and Log" - 3 copies. 2) Summary of well operations. 3) Wellbore schematic depicting final well completion configuration. Copies of electrical well logs, mud-logging reports, and well testing results have been submitted under separate cover. 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, Aur a Gas, LLC . äward. Jones xecutive Vice Presi Att: cc: Duane Vaagen Andy Clifford ., ! [t I A L " "'-) II \! I 10333 Richmond Avenue, Suite 710· Houston, Texas 77042· (713) 977-5799· Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220· Anchorage, Alaska 99501 . (907) 277-1003· Fax (907) 277-1006 STATE OF ALASKA ALASKA O.NO GAS CONSERVATION .MISSION . WELL COMPLETION OR RECOMPLETION if'EPORT AND LOG 1. Status of Well Classification of Service Well OIL: GAS: X 2. Name of Operator Aurora Gas, LLC 3. Address 1400 W. Benson, Suite 41 ° ,Anchorage, Alaska 99503 4. Location of well at surface SUSPENDED: ABANDONED: SERVICE: 2366' FNL, 1704' FEL, S1, T11 N, R12W SM (ASPX 266,454.6, ASPY=2,586, 779.1) At Top Producing Interval 2636' Same At Total Depth Same 5. Elevation in feet (indicate KB, OF, etc.) 16. Lease Designation and Serial No. 369.8' KB (original) C-061390 12. Date Spudded 13. Date T.D. Reached 114. Dat¡.£omp., Susp. or Aband. 115. Water Depth, if offshore /16. No. of1COmPletiOnS 1017/2003 ' 10/9/2003 ' 10~003 completed.tb~ NA feet MSL 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) . 119. Directional Survey 120. Depth where SSSV set 121. Thickness of Permafrost 3000' MD & TVD 2995' MD & TVD Yes: No: NA feet MD NA 22. Type Electric or Other Logs Run GR/CCLlUSIT/RST 23. At PBTD 2995' MD & TVD 7. Permit Number 203-069 8. API Number 50- 283-10019-90 9. Unit or Lease Name Moquawkie 10. Well Number Mobil Moquawkie NO.1 11. Field and Pool Moquawkie CASING SIZE 20" 133/8" 9 5/8" WT. PER FT. 94# 61# 40 & 40.3# GRADE H-40 J-55 N-80 & S-95 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM o 213' o 2455' o 10350' HOLE SIZE 26" 17 1/2" 12 1/4" CEMENTING RECORD 1000 sx 2010 sx 750 sx AMOUNT PULLED o o o o SIZE 27/8" TUBING RECORD DEPTH SET (MD) 2586' PACKER SET (MD) 2589' 24. Perforations open to Production (MD+ TVD of Top and Bottom and interval, size and number) 25. 2636' - 2656' MD & TVD @5 SPF w/4 1/2" HSD guns 2662' - 2678' MD & TVD @5 SPF w/4 1/2" HSD guns 2742' - 2762' MD & TVD @5 SPF w/4 1/2" HSD guns 2770' - 2790' MD & TVD @5 SPF w/4 1/2" HSD guns 2823' - 2843' MD & TVD @5 SPF w/4 1/2" HSD guns 2854' - 2864' MD & TVD @5 SPF w/4 1/2" HSD guns 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 2552' 2730' Squeeze 2 bbls "G" cement Squeeze 5.5 bbls "G" cement 27. Date First Production PRODUCTION TEST I Method of Operation (Flowing, gas lift, etc.) 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 description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Hours Tested WATER-BBL o WATER-BBL o CHOKE SIZE I GAS-OIL RATIO NA OIL GRAVITY-API (carr) NA Shut In Date of Test Submit core chips. None RECEIVED JAN 0 9 2004 Alaska Oil & Gas Cons Comm' . . ISSlOn Anchorage ORIGiNAL Rl~S ~f'~ ...-' G \- J~N 2 100~ Submit in duplicate Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE GEOLOGIC MARKERS " 30. 29. FOí" AION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Flow Test #1 (Perforations from 2823' - 2864') Estimated flow of 1900 mcfd at FTP of 120 psig on 48/64" chok!:1: Flow 90 minutes. SITP = 1075 psig at 20 min. Flow Test #2 (Perforations fro1]12742' - 2790' & 2823' - 2864') Estimated flow of 4900 mcfd at FTP of 305 psig on 48/64" choke. Flow 20 minutes. Estimated flow of 3200 mcfd at FTP of 475 psig on 32/64" choke. Flow 15 minutes. SITP = 1110 psig at 30 min. Flow Test #3 (Perforations from 2636' - 2678') Estimated flow of 5100 mcfd at FTP of 750 psig on 32/64" choke. Flow 15 minutes. Estimated flow of 3600 mcfd at FTP of 990 psig on 24/64" choke. Flow 15 minutes. SITP = 1120 psig at 5 minutes. Flow Test #4 (all open perforations from 2636' - 2864' w/ completion installed) Estimated flow of 9941 mcfd at FTP of 650 psig on 48/64" choke. Flow - 5 minutes. Estimated flow of 4690 mcfd at FTP of 710 psig on 32/64" choke. Flow -5 minutes. SITP = 1120 psig at 5 minutes. (Test #4 was for clean up only prior to releasing rig). 31. LIST OF ATTACHMENÎS Wellbore schematic, Completion tally, Wellhead Schematic, Summary of Well Re-entry Operations 32. I hereby certify that the foregoing is true correct to the best of my knowledge S;g"oo¿¡~ Title _Vice President of Operations and Engineering_ Date 1/:z-/oY INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (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". Form 10-407 . . WELL RE-ENTRY AND COMPLETION REPORT MOBIL MOQUA WKIE NO.1 ," . :.::: ~:~':.: " b .".0. ""'''~f:::.." Aurora Gas, LLC Shirleyville, Alaska 28- December- 2003 Page 1 of8 . . Background Information: The Mobil Moquawkie No.1 was originally drilled in 1965 by Mobil Oil Corporation. The well supplied gas for a power plant that served the local village of Tyonek until 1970. A combination of production problems coupled with poor regional operating economics led Mobil dïl Corporation to plug and abandon the well. Cement plugs were placed across the open production perforations. A cement plug was placed at surface and the wellhead was reportedly cut off and replaced with a P&A marker post. Aurora Gas, LLC finalized their purchase of the leases and the right to development of the minerals in the area in 2002. Based on a significantly improved economic environment, new seismic information and reprocessing of the original electric line logs obtained in 1965, it was determined that commercial potential still existed in the area and a decision was made to re-enter and test the original Mobil Moquawkie No.1 well. Permits were applied for and obtained in early 2003 to begin operations on the well. The rig, Aurora Well Service Rig No. I was mobilized from the Nicolai Creek Unit No.9 well-site where drilling and completion operations were finished. The following well work summary details the re-entry and completion work chronology. Attachment I is a schematic of the well as completed and Attachment II is a tally and diagram of the actual completion equipment in the well at this time. Also attached is a diagram of the ABB VETCO production tree installed on the well. Work Summary and Daily Activities: 24-Sept-2003 Excavate and remove old cellar. Found original 13 3/8" starting head to be intact with P&A marker welded to the top of the flange. Cut and remove marker from well and prepare to remove old wellhead and install new starting head and valves. Initial inspection revealed ID of 9 5/8" casing full of cement to surface. Remove 2" bull plug from annular valve on starting head and noted to be full of cement. The 2 inch annular valve was inoperable so remove valve and nipple, examine id of starting head and noted substantial cement. Attempt to install new nipple, valve and pressure gauge but threads need to be redressed. Decision made to salvage and re-use original starting head. Redress surface and API ring groove for installation of new tubing head. Design and order stub extension for tubing head installation. 30-Sept-03 Return to site to finish redress of starting head flange. Clean up bore and install new stub extension with seals. Install 11 inch 3M tubing head, pressure test void space to 1200 psi, OK. Repair threads on side of starting head and install new nipple, valve and gauge to monitor pressure on 9 5/8 x 13 3/8 inch annulus. 3-0ct-2003 Install felt and Herculite ground cover in preparation for rig installation Aurora Gas, LLC Page 2 of8 4-0ct-2003 5-0ct-2003 6-0ct-2003 7-0ct-2003 8-0ct-2003 9-0ct-20Ð3 10-0ct-2003 1l··Oct-2003 12-0ct-2003 Aurora Gas, LLC . . Mobilize in rig. Spot mud boat and rig. Raise mast and set anchors and connect guy lines. Spot mud pit, generator, and pumps. Install 11 inch spacer spool, drilling spool and BOPE. Install drillers console and substructure. RU continue.. Working on containment, wind walls and general rig up. Noted new gauge on 9 5/8 x 13 3/8 inch annulus indicated 150 psi. Rigging up PVT system and mud lines. RU continue.. Complete RU ofBOPE. Test BOPE to 250 13000 psi, test and calibrate PVT and gas detection systems, all OK. AOGCC witness of BOPE test waived by Jim Regg. Circulate pits and prepare to drill out cement. Rig accepted for drilling at 1200 hrs. Begin drilling out cement plug at surface. Drilling cement. Encounter some gas, drill to 127 ft and circulate while moving pipe racks and pipe. Monitor well for gas, units rising while pumps shut down. Treat mud with barite and flo-vis. Continue hole clean-out to 717 ft. CBU and gas units to 8500. Circulate out gas and RIH to 1800 ft where heavy, high vis mud encountered in hole. Wash to 2115 ft and encounter tight spot. Work through, appears to be sand bridge off in casing. Returns indicate formation sand. Tag cement plug at 2969 ft and circulate out what appears to be thick mud and green cement. Pressure test casing to 2000 psi for 10 minutes, OK. Continue drilling cement plug, until through at 2775 ft. Wash to 3000 ft, condition mud, check for flow and POOH. PU casing scraper, RIH with no restrictions, circulate and condition mud. Again, pressure test casing, bleeds off at 500 psi due to perforations. POOH, LD BHA and PU CIBP wi setting tool. RIH and set CIBP at 2995 ft. Drop ball and shear out at 1800 psi. POOH and LD setting tool, PU test packer and RIH to 2900 ft, set packer. Test to 2000 psi, for 15 minutes, OK. POOH wi packer, LD and RIH open ended to 2995 ft to swap out mud wi brine. Clean Pits and displace out mud. Prepare 9.5 ppg KCL brine kill fluid. Finish swapping out mud wi brine and POOH laying down 3 Y2 inch DP. RU Schlumberger and run CBL. Run R§T, POOH and lay down logging tools. RU lubricator and perforating guns. Based on analysis of CBL and RST, decision made to perform cement squeeze to isolate pay from apparent water bearing zone behind casing. RIH and perforate wl5 shots over 1 ft interval at 2730 ft. POOH wi gun, Page 30/8 13-0ct-2003 14-0ct-2003 15-0ct-2003 16-0ct-2003 Aurora Gas, LLC . . LD lubricator, pick up 3 Y2 inch DP for further treatments due to mechanical limitations imposed by 2 7/8 inch work string. PU bit and scraper and RIH to 2768 ft. CBU, TOH and LD bit wI scraper. PU and RIH wI retrievable bridge plug, set at 2785 ft, un-sting from BP. RU cementers for squeeze, establish rate of 1 bpm at 680 psi. Mix and pump 5 sks of sand down on top of bridge plug, POOH and LD running tool. TIH open-ended and tag sand at 2878 ft. Set DP at 2768 ft. RU BJ to squeeze. Displace 11 bbls 13.5 ppg slurry above bridge plug. POOH wI 3 stands. Hesitate squeeze 5.5 bbls. Final pressure 800 psi. Bleed back 1.5 bbls fluid. TOH and pick up 8 Y2 inch bit. TIH to 2600 ft and work on winterizing rig while WOC. Wash and ream ratty cement to 2778 ft, CBU and p-test to 500 psi. Bled 75 psi in 10 minutes. Pump dry job, TOH with 8 Y2 inch bit, LD and RIH with Baker Retrieval tool. Rig up to reverse circulate. Reverse circulate sand off bridge plug, release and POOH. Attempt to re- set at 2575 ft, unable, attempt again, RIH for second isolation squeeze and set at 2590 ft, OK. Dump 2 sacks of sand on top of retrievable bridge plug. POOH with setting tool. Driller dropped 1 joint of pipe and setting tool from surface. RIH and attempt to screw into fish. Unable, order out fishing tools, POOH. Modify pin on scrap drillpipe and RIH in attempt to screw into fish while wait on fishing tools. Drum clutch control valve malfunctioned, secure well and shut down for repairs. Repair valve and air system, POOH wI fish, LD and prepare for BOP test. Test BOPE. Testing BOPE. Crew tested to wrong test pressure, initiate re-test to 250 I 3000 psi. OK. AOGCC witness ofBOPE test waived by Chuck Scheve. ND flow nipple and NU lubricator flange. RU Schlumberger with 5 inch 5spf perforating gun, test lubricator to 250 psi, RIH and perforate at 2552 ft. TOH wI gun and RD Schlumberger. ND lubricator, NU flow nipple and RIH open-ended to 2595 ft. Tag sand, POOH to 2546 ft and RU cementers for squeeze. Establish injection rate of .25 bpm at 1000 psi. Displace 2 bbls cement over perforations, POOH 3 stands. Perform hesitation squeeze with maximum pressure of 1100 psi. Hold pressure for 30 minutes. Release pressure and 1 bbl fluid returned. RD cementers, POOH. Make up new bit and RIH, tag TOe at 2464 ft. Hard cement encountered. Drill cement. Drill out cement to 2580 ft. Reverse circulate sand from top of retrievable bridge plug. Pressure test casing to 1500 psi. OK. POOH and LD bit, PU plug retrieval tool. RIH and reverse out remaining sand, latch onto plug, unseat and POOH. LD plug and PU bit and casing scraper. RIH to 2896 ft while reverse circulating. Reverse circulate 2 hole volumes, POOH while laying down drillpipe, LD bit and scraper. RU Schlumberger for perforating. Hold safety meeting to discuss safety and well test Page 4 of8 17-0ct-2003 18-0ct-2003 19-0ct-2003 20-0ct-2003 Aurora Gas, LLC . . operations. RIH and perforate 2854 - 2864 ft at 5 spfwl 4 W' HSD guns. POOH to pick up new gun. RU and RIH and perforate from 2823 - 2843 ft shooting 5 spfwl 4 W' HSD guns. POOH and RD Schlumberger. Install test plug and 'change out 3 Yz inch pipe rams for 2 718 inch rams. Test to 3000 psi, OK. PU and RIH with test packer and 86 joints of tubing. Set packer at 2789 ft. Move in test tank, RU test lines and test pit. RU lubricator for swabbing é:-'-'- operations. Standby until daylight for swabbing and testing operations. Wait on daylight for swabbing ops. Hold PJSM, start swabbing. Swab 40 bbls fluid to 2780 ft; discover annulus taking same fluid amount as that swabbed indicating packer is not holding. Release and reset test packer at 2700 ft, swab. Packer still not sealing. Release and reset at 2590 ft. Swab, packer still not sealing. Release packer, unloader malfunctioned, stab in safety valve on floor, hook up and circulate around to balance hole. POOH with packer and inspect. Test unloader, breakout unloader, RIH with packer and no unloader. Set packer at 2685 ft, pressure test annulus to 350 psi, OK. Release, Rill to 2780 ft, set packer and pressure test to 270 psi, packer leaking. POOH and reset packer 2685 ft, set packer, pressure backside. Rig on standby until daylight for swabbing operations. Standby until daylight. Hold PJSM and begin swabbing operations. Swab fluid to 1000 ft, monitor well. Swab again, and parted sand line when driller missed flag. Secure well, inspect and repair pack-off on lubricator, replace rope socket and inspect swabbing tools for damage. RU lubricator to continue swabbing and discover pressure at surface. Open well to flow on 48/64 inch choke to tank wi 29 bbls brine recovered. Flow 90 minutes .- until flow stream cleans up. Appears to be old drilling mud and cement in flow stream. FTP = 120 psi at 1900 mcfd on 48/64 inch choke. Final SITP = 1075 psi. Kill well using bullhead squeeze method with 9.4 ppg brine. Reverse circulate hole volume twice to balance and equalize. Notice high gas concentration, so circulate around long way once and monitor. No gas and well dead. Release and POOH with test packer. RU and RIH with Schlumberger to perforate. Perforate from 2770 - 2790 ft and 2742 - 2762 ft in two runs at 5 spfwl 4 W' HSD guns. POOH and LD Schlumberger. PU test packer and rebuilt unloader assembly. RIH to 2685 ft. Reverse circulate and monitor well for flow, OK. Set packer at 2685 ft, pressure annulus to 200 psi, OK. RU swabbing equipment and standby until daylight. Standby until daylight. Swab in well with two runs. Flow well on 48/64 inch choke to test tank, recovered 2.8 bbls brine, again with some old mud and cement. Flow well on 48/64 inch choke until stream cleared up to heavy mist. Calculated flow rate of 4900 mcfd at 305 psi on 48/64 inch choke and 3200 mcfd at 475 psi on 32/64 inch choke. Final SITP = 1110 Page 5 of8 21-0ct-2003 22-0ct-2003 23-0ct-2003 24-0ct-2003 Aurora Gas, LLC . . psi. Shut in and kill well using bullhead squeeze method with 15 bbls 9.5 ppg brine. Release and POOH with test packer. RU Schlumberger for perforating. Test lubricator to 250 psi, OK. RIH and perforate 2662 - 2678 ft and 2636 - 2656 ft in two runs at 5 spfw/ 4 W' HSD guns. POOH and RD Schlumberger. PU and RIH with retrievable bridge plug to 2718 ft. Set plug and pump 5 sacks sand on top of plug. POOH, lay down packer tool and PU test packer assembly. RIH to 2588 ft, circulate bottoms up to clear up gas. Set packer and pressure annulus to 150 psi. RU swabbing lubricator and equipment and standby until daylight for testing operations. Standby until daylight to continue swabbing and testing operations. Swab in well. Unload well through 48/64 inch choke. Flow test through choke with calculated flow rate of 5100 mcfd at 750 psi FTP on 32/64 inch choke and 3600 mcfd at 990 psi FTP on 24/64 inch choke. Final SITP = 1120 psi. Kill well using bullhead squeeze method with 23 bbls 9.5 ppg brine to kill. Circulate long way to kill well completely. POOH and discover packer left in hole. PU centralizer and pup joint and RIH in attempt to screw back into fish. TIH and tag fish at 720 ft, screw into packer and POOH. LD packer, RIH w/ bridge plug retrieval tool, tag sand and reverse circulate out sand from top of bridge plug. POOH and LD bridge plug. Install test plug and perform BOPE test, OK. Test BOPE to 250/3000 psi, AOGCC witness waived by John Crisp. PU casing scraper and bit and RIH. RIH with bit and scraper to 2760 ft and tag restriction, cannot circulate through. POOH, LD scraper and 8 12 inch bit. PU 6 y.¡ inch bit and RIH. Went through tight spot at 2760 ft and tagged up on fill at 2880 ft. RU to circulate and wash down 4 joints to tag CIBP at 2994 ft. Circulate and condition hole. POOH and lay down 3 joints pipe. Pick up drill collars and prepare for swaging operations. Set test plug and c/o 2 7/8 inch pipe rams with 3 12 inch pipe rams. Finish c/o of rams and test BOP to 3000 psi, OK. Pick up 7 12 inch casing swage, jars and 4 % inch drill collars. PU 3 12" DP while running in hole to 2760 ft and find no obstruction. Continue in hole to 2960 ft and still nothing, circulate bottoms up and POOH. LD 7 Y2 inch casing swage and PU 8 1/8 inch swage. RIH and tag obstruction at 2736 ft. Set 10 k-lbs on swage and work through tight spot. Continue into hole to 2760 ft and didn't find obstruction at original spot. CBU and POOH while LD drillpipe. Work swage through tight spot and perforated areas prior to POOH and LD BHA. POOH while LD DP and BHA. Install test plug and c/o rams from 3 12 inch to 2 7/8 inch. Test stack to 3000 psi, OK. RIH and POH with 2 7/8 inch production tubing while installing seal rings on way in and out. RU Page 60f8 25-0ct-2003 26-0ct-2003 27-0ct-2003 28-0ct-2003 29-0ct-2003 T T r' . . to run completion and find vendor had incorrect cross-overs for making up their equipment. Standby while waiting on fabrication at machine.. shop in Kenai. XO's into Tyonek at 5:30 am via Rediske. Finish make-up of completion and RIH with same. RIH with completion. RU to circulate packer fluid around. Mix and circulate packer fluid down backside prior to setting packer. Space out, set packer and land tubing hanger. Pressure test of annulus failed when able to circulate around. Unlock and unseat packer. POOH and inspect packer. Pressure test sliding sleeve and all components at surface, OK. RIH and attempt to re-set packer in different location using different space-out. Again packer seated but seal elements not holding. POOH and inspect packer, OK. RIH and attempt set at 500 ft and again fail pressure test. POOH and LD packer. Install one joint 2 7/8 inch tubing on top of screen, RIH, close rams and secure well for night while waiting on equipment. Freeze protect stack and equipment. Rig on standby. Rig on standby. Measurement and inspection of packer elements revealed that wrong packer elements were installed. Standby while vendor hot- shots re-dress kit out of Vernal, Utah. Kit arrived in Anchorage at 2200 hrs but weather bad and cannot fly to Tyonek. Rig on standby. Redress kit on location at 0800 hrs. Tool hands redress packer on catwalk. PU packer and RIH with completion. RIH, set packer at 2592 ft, land tubing hanger and pressure test backside. Pressure test to 2000 psi with bleed off. Fluid is no longer bypassing packer elements but appears to be bleeding offthrough squeeze perforations above packer. Pressure up to 1500 psi with very slow bleed off. Order out slickline tools to set profile plug in tubing for tubing pressure test. RU lubricator, RIH and set plug in "X" profile in top of sliding sleeve. Pressure test tubing to 2000 psi, OK. RIH and retrieve plug, set BPV in wellhead and standby until morning for daylight operations. RD rig floor and RD BOPE. Nipple up ABB Vetco production tree. Test bonnet to 3000 psi, and tree body and valves to 5000 psi. Pull BPV and RU lubricator to swab in well. Swab in well, flowing well to test tank through 48/64 inch choke. Unload and flow well to clean up. Calculated flow of 9941 mcfd at 650 psi FTP on 48/64 inch choke and 4690 mcfd at 710 psi FTP on 32/64 inch choke. Finish flow test and clean up. RD lubricator, pump in sub and rig equipment over well. Install BPV in wellhead and freeze protect wellhead with methanol. Finish rigging down, release rig for demob and barge back to Nikiski for winter. RD sub-base and floor. RD all lines, drain and winterize pumps and equipment. Move all equipment to barge landing for load-out. Page 70[8 30-0ct-2003 31-0ct-2003 Aurora Gas, LLC . . De-mob equipment from site to Tyonek barge landing for shipping. De-mob, clean up site and ship equipment from Tyonek barge landing to Nikiski. Page 80f8 .j" _Weatherlon !tem C¡l' to Surface '-J 000 --, Ql ~ ~i, . =1 - fl . Client: Auwra Cas . ...--.. ..-., -- ,.-.------ Address: -- "_0"____- _.~.__._._..__._.__. . : Lease: IHeld --. OCS-G MOQUAWKlE 1'1'!tf~.~~:__... __._._ ""__"__'_ ______" _".~_çl!!!!P~!!!Y}~1"n.._~~.I.~ll1c _\('!.<:B.I,!~.__ _.__.""._______._ . We.!I~.~Ù!!!'e'~.___. __.__ ,Mobile !\loqu,H"kie 111 ¡Phon.,=~_._.._.~Q?-'i4~-550(~____._____.___,,___.__. Type of Opcr,ltion: Sand SCI'Clm / Production Slring _ Tool ~e.~cripti~)n Tool % Tool I/O I Length Depth Connection Asset No. MinlD I 4 1/2 Screen 4112 Bull Plu\! 5.120 5.000 3.958" X 27/8" 6.5# EVE 8rd J-55 Tbg 2718 WXA Sliding Sleeve 3.625" 2.312" (wi 2.321 " "X" landing profile: 2718 Tubing joint 2718 Pup Joint 2718 Pup Joint 27/81'-2 On/OffTool wI 2.321" X Profile 2.875" 2.875" 2 875" 4.500" 2.441 " 2.441 " 2.441 " 2.312" 2.63 2 7/8 EVE Cross Over Cross Over 4.500" 5.600" 2.500" 2.500" 32.45 2.23 4.10 1.50 2 7/8 EVE 2 7/8 EVE 2 7/8 EVE 9 5/8 X 4 1/2 Arrowset 1)( Packer 8.250" 4.00" 0.87 0.92 2718 EVE X 41/2 LTC 4 1/2 LTC X 4 1/2 EVE Cross Over Cross Over 3 1/2 Tubing 3 1/2 Pup Joint Cross Over 7.96 4 1/2 LTC 5.020" 2.920" 0.92 41/2 EVE X 41/2 LTC 5.000" 2.920" 0.87 41/2 LTC X 3 1/2 EVE 3.500" 2.992" 30.74 3 1/2 EVE 3.500" 2.992" 8.11 4.500" 3.000" 0.96 3 1/2 EUE X 41/2 LTC 4 1/2 Screen 5.120 3.958" 31.ü4 4 1/2 LTC 4 1/2 Screen 5.120 3.958" 31.02 Cross Over 5.000" 2.920" 0.87 4112 LTC X 3 1/2 EUE 3 1/2 tubing joint 3.500" 2.992" 30.75 [:=1 Cross Over 4.500" 3.000" 0.96 3 1/2 EUE X 4 1/2 LTC ~~I I~I ~~i 4 1/2 Screen 5.120 3.958" 31.05 4 1/2 LTC ~,JI ~ Attachment II ~~I ~~ ~III ~ I 4 1/2 Screen 5.120 3.958" 31.01 4 1/2 LTC m Cross Over 5.000" 2.920" 0.87 4112 LTC X 3 1/2 EVE 3 1/2 Pup Joint 3.500" 2.992 4 fH 3 1/2 Tubing joint 3.500" 2.992 31.15 Cross Over 4.500" 3.000" 0.96 3 1/2 EUE X 41/2 LTC 31.00 0.60 4 1/2 LTC . . D Proposed o Current Mobil Moquawkie #1 Gas Prod. Granite Point, Alaska ,~i4u,..ora Gas, LI..C IGL Original KBE 350' 370' 26" Hole 02 Inhibited 3% KCL Packer fluid above packer 17 1/2" Hole 2 7/8" Sliding Sleeve wI "X"landing profile @ 2544.3' T-2 OnlOff Tool wI "XA" Profile @ 2586 95/8" Weatherford Arrowset 1-X Retrievable Production Packer @ 2589' 3 1/2" 9.2# L-80 8rd Tubing Spacer wI crossover.s to 4 1/2" LTC 41/2" 12.6 #/ft Stratapac Screen 2639' - 2701' 121/4" Hole 3 1/2" 9.2# L-80 8rd Tubing Spacer wI crossovers to 4 1/2" LTC 41/2" 12.6 #/ft Stratapac Screen 2734'-2796" 3 1/2" 9.2# L-80 8rd Tubing Spacer wI crossovers to 4 1/2" LTC 41/2" 12.6 #/ftStratapac Screen 2833' - 2864' 41/2" Bullplug@ 2864.21' Please see attached Weatherford diagram for completion detail Attachment I 27/8" 6.5# 8rd EUE MOD J-55 ProductionTubing 36" Currogated Conductor . 20" 94# H-40@ 213" __ CMT'D to surfaceW/1000 SX , Stage Collar at 502' 133/8" Csg perfed w 15 (1/2") holes at 1250' 350 SX cmt squeeze performed 133/8" 61# J-55 @ 2455' CMT'D WI 1500 SX around shoe & 510 SX through stage collar at 502' Squeezed 2 bbls "G" cement Squeeze Perfs shot at 2552' 5 SPF, 4 1/2" HSD guns ·,i".' ···r .~ï ,~. ,!' (;'¡I i 'f·:r . . ';', I." . 4:: ~ . ., ., ~ Production Perfs 2636' - 2656' & 2662' - 2678' ;~,,;i' @ 5 SPF wI 4 1/2" HSD guns - ¡ . I . ~ i - - ¡ ';' ;.~" ¡ ¡'i ~\ ';f - ! I ~ ~ ~ ~ . I": i ,¡ :. "." . 'II ;' ~.': Squeezed 5.5 bbls cement Squeeze perforations shot at 2730' 5 SPF, 4 1/2" HSD guns. - I ~ ~ 1:~ ':\;¡'~" I" .1 'i.' ~i ./' . ~ i'i~ ! '.fl, , ~i ;:¡ ,!. Production Perfs 2742' - 2762' & 2770' - 2790' .:: @ 5 SPF wI 4 1/2" HSD guns i,'if,: - í i:" h~ -7,'~ ~ .1,,1. ·:}I, .::.:11 .1 ¡ ~ , , :; ~, :" :" ì '';\ U·. .i:',.....'... Production Perfs 2823' - 2843' & 2854' - 2864' ""'"7""j'T" . .. '7 @ 5 SPF w/4 1/2" HSD guns . :'. \ . " ~ ¡ " . \; 1!!Iet ~ I ;~;;;~~:;~;:d Perlorations @ 2932' I See original well file for well detail below 2995' Mobil Moquawkie #1 Fairweather E&P Services, Inc. Drawing Not to Scale Rev. 05 DHV27-Dec-2003 . . Aurora Gas, LLC's Mobil Moquawkie NO.1 Completion Tally Component Description ?:?!8"~~# EUE 8rd Mod tubing t~ Surface 27/8" WXA SlidingSleev~~:X" Profile 1_~1~ 7/8" 6.5# ElJE---ª.r.9__~()~~ubing 1 Pup Jt 27/8" 6.5# EUE 8rd Mod tubing JPuP Jt 27/8" 6.5#- EUE__8~~~od tubing 27/8" T-2 On/Off Tool w/2.321 "XA" Profile -..-....--- ~--- ~-- 27/8" EUE X 4 1/2" LTC XO ~- - ~~._--- 4 1/2" LTC X 41/2 EUE XO ----- ._~ 9 5/8" X 4 1/2" Arrowset 1 X Ret. Packer --.-- ~--- 41/2" EUE X 4 1/2" LTC XO 4 1/2" LTC X 3 1/2" EUE XO 1 Jt 3 1/2" 9.2#_~ª"0 8rd tubing 1 Pup Jt. 3 1/2" 9.2# L-80 8rd tubing 31/2" EUE X 4 1/2" LTC XO 1 Jt 4 1/2" 11 ~§# Stratapac Screen 1 Jt 4 1/2" 11.6# Stratapac Screen 4 1/2" LTC X 3 1/2" EUE 8rd XO 1 Jt 3 1/2" EUE 8rd 9.2# L-80 tubing 31/2" EUE X 4 1/2" LTC XO 1 Jt 4 1/2" 11.6# ~tratapac Screen _1 ~~1{2" 11.6it Stréltap~c~~~en 4 1/2" LTC X 3 1/2" EUE XO --.....-.-- , .-.---..-- 1 Pup Jt 3 1/2" 9.2# L-80 8rd tbg lJt 3 1/2" 9.2# L-80 8rd tbg 31/2" EUE X 4 1/2" LTC XO _1 J~~!~:_11.6# Stratapac Scre~_ ~1/2':_Bull Plug Total Tubing Length Installed Total Completion Length Center of Packer Element Depth Tool 00 (in) Tool 10 (in) 2.875 3.625 2.875 2.875 2.875 4.5 4.5 5.6 8.25 5.02 5 3.5 3.5 4.5 5.12 5.12 5 3.5 4.5 5.12 5.12 5 3.5 3.5 4.5 5.12 5 N/A 2544.3 319.91 2591.8 Length (ft) Depth (ft) 2.441 2.312 2.441 2.441 2.441 2.312 2.5 2.5 4 2.92 2.92 2.992 2.992 3 3.958 3.958 2.92 2.992 3 3.958 3.958 2.92 2.992 2.992 3 3.958 2544.3 3 32.45 2.23 4.1 1.5 0.87 0.92 7.96 0.92 0.87 30.74 8.11 0.96 31.04 31.02 0.87 30.75 0.96 31.05 31.01 0.87 4 31.15 0.96 31 0.6 2544.30 2547.30 2579.75 2581.98 2586.08 2587.58 2588.45 2589.37 2597.33 2598.25 2599.12 2629.86 2637.97 2638.93 2669.97 2700.99 2701.86 2732.61 2733.57 2764.62 2795.63 2796.50 2800.50 2831.65 2832.61 2863.61 2864.21 . . t" f ~ '!"11"-+-......... {~~~~/7':;~;, ~ P"'~'-<>. [I' r! ·~,>ö'~-;··· .'\¡ n' '! ; oil T··_·~ì'.-k4 "}1 ~ "-1', }ij ¡ ! ;i-...:.:i:l...1 ¡Ii t1-.--."--,.-~.._---,,J ;¡ _ .~..., i .. _ ~ .~ t ^ " ..J "' ~~~'Q.¡o,,' .., , 1 . , , r1 .~_. , , f1L1 - -.. ", ! ,_.._.)1:.,:\ \.-¡;it; \~'1;~;Þf.1 v, A' -J--" ,. --~ ~._," 'II'I-~ '!~~¥]' it }..~~~~&L~-' I .. 1'-; . ...~,,-....- -k-r1 ,-'~-";'.-'~ .....~.J L· I ."... u'" ~-I ,,:.,.,;~ jft ....L¿.._- ¡¡,:¡ ¡....i"j ~' .f~ '-i't.::' UH_ . ·r-- .., I .~.,-. . ~,... ! i ; .-:-\.- [~i:]l ¡'~l t~ ~j ,. . ., I -- . I i i \ ; I "'-, ............ '-....... ....",. ',- - I ./ rS[i ~JD " u - , -... "- ,- ..~"". ,/ ._---- .- i ~~~..~.. ~ tù,¡" K ~ :.. ri ---.........--.--- -------.-----------. ~;l. <'-! ~ ~~ ~ :. ti " .- ... --." ----. _. ~-- . .~L___.._.._~...._~v._._.._.. H._'_ _..__~ S'!·'c. &. ~·CE Er-J~_:ii'.JEEr~¡t\:c :'-:.::..;:.;:::..:....:. ;.::.:.,:.:;:::.--=:.:-"" _. .-...:.:~"':::~.:::.-:-;-~-=-. '. ....,. ... ;..~.-( -- \ -. !" ~ . ~~~} -.- .... -~~.. ~=l~~~Ç~f{~f~ _ S~.._.~~~~ ASSY -----.- ---- .-------. ,C ! jv':: ~J-5ía OD~ __. _ ___~_.6. ~ .____~_.__~_____.... _....-_._~____~.___ ._- l1!~C~1;!_Ú~~~~È~·~- ~;~,~;~.,~~;.,;;~u Z~;.· oi.'''' ~=.,J~çi.:!~t__,.::~~..._Jt~SbL~;,L!«?.:.. rjr 3~~1 d 2-7/ x ;.~ " J ~_._.I I -.... , : ...- _...:~.-:...:.!...- .... : ~ F ---,-,------._-~ ., 'tl .-..-..--.- IU'.'I' NiUt.~~UII c::;::;::~~;;:',;;:::::·_·__·_--:~··- '" . STATE OF ALASKA .. RECEIVED ALASKA AND GAS CONSERVATION CO~SION GAS WELL OPEN FLOW POTENTIAL TEST REP6Rt 1 2003 Initial (] Annual 0 Special 0 1b. Type Test: Stabilized U Non Stabillkillsl:a Oil &~n!;.JColT"11ission Constant Time 0 ISOChronal 0 Other Anr.1 . wrage 5. Date Completed: 11. Permit to Drill Number: 10/27/2003 203-069 1a. Test: 2. Operator Name: Aurora Gas, LLC 3. Address: 6. Date TD Reached: 10333 Richmond, Ste 710, Houston, TX 77042 10/20/1965 4a. Location of Well (Governmental Section): 12. API Number: 50-283-10019-90 Top of Productive Horizon: Surface: 2366' FNL, 1704' FEL, SEe 01, T11N R12W, SM 8. Plug Back Depth (MD + TVD): 2995' MD (2992' TVD) 2295' FNL, 1630' FEl, SEC 01, T11N, R12W SM' 9. Total Depth (MD + TVD): 11,364' MD 7. KB Elevation (ft): 370 13. Well Name and Number: MOBIL MOQUAWKIE #1 14. FieIdlPool(s): Total Depth: 4b. Location of Well (State Base Plane Coordinates): Surface: x- 266,459 y- 2,586,703 Zone- TPI: x- 266,522 y- 2,586,857 (MID) Zone- TotalDepth: x- 267,060 y- 2,586,842 Zone- 17. Casing Size Weight per foot, lb. I.D. in inches 9-5/8" 40 8.835 MOQUAWKIE GAS FIELD 10. Land Use Permit: 15. Property Designation: C-061390 16. Type of Completion (Describe): Cased and perforated, wI sand control screens I.D. in inches 2.441 Set at ft. 10,350 Set at ft. 2592 19. Perforations: From To 18. Tubing Size 2-7/8" 20. Packer set at ft: 2592 Weight per foot, lb. 6.5 21. GOR cflbbl: NA 2636-56',2662-78',2742-62', 277()"90', 2823-43', 2854-64' 22. API Liquid Hydrocarbons: NONE 23. Specific Gravity Flowing Fluid (G): 0.56 24a. Producing through: 24b. Reservoir Temp: Tubing (] Casing 0 85 FO 25. Length of Flow Channel (L)1 Vertical Depth (H): 2750' 2747' 24c. Reservoir Pressure: 1233 psia @ Datum 2750' I Gg: I % CO2: I % N2: 0.562 0 1.36 TVDSS I%H~: 24d. Barometric Pressure (Pa): 15 psia I Prover: I Meter Run: I Taps: 5.761" Flange 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Ditt. Temp. Pressure Temp. Pressure Temp. Duration of Flow Line X Orifice psig hw OF psig OF psig OF Hr. No. Size (in.) Size (in.) 1. 5.761 X 2.0 504 17 1013 80 2.5 2. 5,761 X 2.0 460 21 987 80 1.75 3. 5.761 X 2.0 524 28 896 80 1.25 4. 5.761 X 2.0 495 30 862 80 1.0 5. 5.761 x 2.0 486 27 960 80 4.5 Basic Coefficient -ÝhwPm Pressure Flow Temp. Gravity Factor Super Comp. Rate of Flow (24-Hour) Pm Factor Factor Q, Mcfd No. Fb or Fp Ft Fg Fpv 1. 4740 2. NOT AVAlLABLE- CALCULATED ELECTRONICAllY BY ASRC WELL TEST UNIT 5490 3. 6910 .4. 7560 5 5990 Temperature for Separator for Flowing Pr T Tr z Gas Fluid No. Gg G 1. 0.56 2. NOT CALCULATED -USED RYDER SCOTT SPREADSHEET 3. SEE A IT ACHED Critical Pressure 671.28 4. Critical Temperature 343.36 5. Form 10-421 Revised 212003 CONTINUED ON REVERSE SIDE Submit in Duplicate OR\G\NAL of Pc2 1,327,104 . ... Pf ~3. Pc 1152 Pf2 1,520,289 No. Pt Pt2 Pc2-PF Pw Pw2 Pc2-Pw2 Ps PS2 Pf2_Ps2 1. 1028 1,056,784 270,320 1129 1,274,641 245,648 2. 1002 1,004,004 323,100 1112 1,236,544 283,745 3. 911 829,921 497,183 1044 1,089,936 430,353 4. 877 769,129 557,975 1025 1.050,625 469,664 5. 975 950,625 376,479 1092 1.192,464 327,825 25. AOF (Mcfd) 16,437 n 0.6684 Remarks: true and correct to the best of my knowledge. Title Exec. Vice President Date 12/30/03 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/-y'hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= ~dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 2/2003 Side 2 .. BOTTOMHOLE TEMP, "F: GAS GRAVITY: HzO GRAVITY, 'Yw: CONDo GRAV., "API: TVD, FT: MEAS. DEPTH, FT: Cond.Corr8I. (Y/N): Corrected" Tc, oR: Corrected* Pc, Psia: Pressure Base, Psia: 85 0.562 1.070 2,747 2,750 N 343.36 67128 14.730 . WELL NAME: FIELD: LOCATION: RESERVOIR: SOUR GAS _~1__ - ----~<?~ H~ . MOBIL MOQUAWKIE NO.1 MOQUAWKlE SEC. 1 T11N R12W SM, KENAI BOROUGH, WEST SIDE INLET, ALASKA UPPER TYONEK, 2636-2864' MOLE % 1.36 0.00 0.00 Options o Check, If Injection Well o Smooth Pipe Roughness TUBING ID, IN.: 2.441 RESULTS AOF, Mcf/d: C: n: 16,437 1.212934 0.668384 ,,~ =i:=tt=-~~~m; ~ . . . . _ .. _ ..I. _ _ . .. ~ . ~ _ Ll ... II' f- ! I .! ! I ~,.. ==1t~=-~~~-I -- ¡ ~____~_ ¡II ____ .:__ ---L~ I ~_ I If' I ---t-T_-:-:_~Li+~-=~l I ! ¡ I!I, : II III 1.000 10,000 100,000 Flow Rate, McfId 100 100 POINT NO. Test Data FLOWING (Automatic) Q, Mcf/d BCPD BWPD FTP,Psia WHT, of BHP, Psia COMMENT SHUT-IN 0 0 0 1,152 20 1,233 SIBHP 1 4,740 0 0 1,028 17 1,129 28/64 CHK 2 5,490 0 0 1,002 21 1,112 32/64 3 6,910 0 0 911 28 1,044 36/64 4 7,560 0 0 877 30 1,025 40/64 5 5,990 0 0 975 27 1,092 321-extended These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. '* Job Log Entry Time I 11/23/03 17:00 11/23/03 17:45 11/23/03 17:55 11/23/0323:30 11/24/03 4:40 11/24/03 5 :00 11/24/03 5:05 11/24/03 7:32 11/24/03 7:36 11/24/03 7:40 11/24/03 7:57 11/24/03 7:58 11/24/03 8: 1 0 11/24/03 9:07 11/24/03 10:33 11/24/03 10:37 11/24/03 10:44 11/24/0311:40 11/24/03 11 :42 11/24/03 12:11 11/24/03 12:16 11/24/03 12:24 11/24/03 13:34 11/24/03 13:37 11/24/03 14:45 11/24/03 15:00 11/24/03 16:00 11/24/03 17:00 11/24/03 18:00 11/24/03 18:30 11/24/03 18:32 11/24/03 18:40 11/24/03 19:00 11/24/03 22:30 11/25/03 4:00 . Job Log . Comment Arrived on Location With Separator. Flare Arrived on Location. Started Rigging Up Flare. Flare Completed, Started Running Pipe. All Piping Completed. PT Inlet With Well Gas. Installed 2" Orifice Plate in Daniels Meter. PT complete. Opened Well On 12/64 Adjustable Choke. Increased to 16/64 Adjustable Choke. Increased to 18/64 Adjustable Choke. Dropped Orifice Plate, Reset Totalizers. Increased to 24/64 Adjustable Choke. Increased to 28/64 Adjustable Choke. Divert to 28/64 Positive Choke. Gas Gravity .569. Divert To 32/64 Adjustable Choke. Divert To 32/64 Positive Choke. Lost Prime on Methanol Injection Pump Reprimed Methanol Pump. Diverted to 32/64 Adjustable Choke. Increased to 36/64 Adjustable Choke. Diverted to 36/64 positive choke Diverted to 36/64 Adjustable choke Diverted to 40/64 Positive Choke. Diverted to 32/64 Positive Choke. Last Test Phase, 4 Hour Test @ 32/64 Positive Choke Continue 4 Hour Test. Continue 4 Hour Test. Continue 4 Hour Test. Attach Pollard Electronic Guage. Blow Fluid From Bottom Of Separator. Blow Fluid From Bottom Of Separator. Blow Fluid From Bottom Of Separator. S/I Well at manifold, Monitor S/I Pressure. Start rig down SI @ wing and SSV, pollard recorder in place Rig down complete Page 1 location Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No.1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie NO.1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie NO.1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 Mobil Moquawkie No. 1 . 15 Min Reads . Well Head Skid BS&W Vessel Gas I ...~, I ICa~ v""wl I I VAI~AI I Choke Cut Solid. I GIs I L~u~ Size Rate Increment Total Reading Time Location (Psig) (Psig) (Psig) (DegF) Setting % % (Psig) (DegF) (DegF) (in) (mmsol/d) (msol/d) (mscfld) 11/24/03 4:45 Mobil Moquawkie No. 1 0 0 4 0 0 0.00% 0.00% 0.00% 0 45 46 1 0.00 0.00 0.00 11/24/03 5 :00 Mobil Moquawkie No. 1 0 0 4 0 0 0.00% 0.00% 0.00% 0 46 46 1 0.02 0.01 0.53 11/24/035:15 MobU Moquawkie NO.1 0 0 1137 0 0 0.00% 0.00% 0.00% 1 46 46 1 0.02 0.01 0.70 11/24/03 5 :30 Mobil Moquawkie No. 1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 46 46 1 0.02 0.01 0.87 11/24/03 5:45 Mobil Moquawkie No. 1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 46 46 1 0.02 0.01 1.04 11/24/036:00 Mobil Moquawkie No. 1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 46 46 1 0.02 0.01 1.21 11/24/036:15 Mobil Moquawkie No. 1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 47 47 1 0.02 0.01 1.38 11/24/03 6:30 Mobil Moquawkie No. 1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 47 47 1 0.02 0.01 1.55 11/24/03 6:45 Mobil Moquawkic No. 1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 47 47 1 0.02 0.01 1.72 11/24/03 7 :00 Mobil Moquawkie No.1 0 0 1137 0 0 0.00010 0.00% 0.00% 0 47 47 1 0.02 0.01 1.88 11/24/037:15 Mobil Moquawkie No. 1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 47 48 1 0.02 0.01 2.05 11/24/03 7:30 Mobil Moquawkie No.1 0 0 1137 0 0 0.00% 0.00% 0.00% 0 47 48 2 1.51 0.31 2.56 11/24/037:45 Mobil Moquawkie No. 1 0 0 1126 0 12 0.00% 0.00% 0.00% 136 44 48 2 0.04 0.03 0.10 11/24/03 8:00 Mobil Moquawkie No. 1 0 0 1107 0 24 0.00% 0.00% 0.00% 495 29 48 2 2.38 1.66 5.42 11/24/03 8:15 Mobil Moquawkill No. 1 0 0 1032 0 28 0.00% 0.00% 0.00% 499 21 48 2 4.61 3.20 37.89 11/24/03 8:30 Mobil Moquawkie No. 1 0 0 1050 0 28 0.00% 0.00% 0.00% 487 17 46 2 4.03 2.82 84.33 11124/03 8:45 Mobil Moquawkie No.1 0 0 1047 0 28 0.00010 0.00% 0.00% 494 15 48 2 4.10 2.85 126.61 11124/03 9:00 Mobil Moquawkie No. 1 0 0 1032 0 28 0.00% 0.00% 0.00% 515 16 47 2 4.26 2.96 170.72 11/24/039:15 Mobil Moquawkie No. 1 0 0 1001 0 28 0.00% 0.00% 0.00% 514 18 44 2 4.78 3.30 216.91 11124/03 9:30 Mobil Moquawkie No. 1 0 0 1013 0 28 0.00% 0.00% 0.00% 499 17 43 2 4.74 3.29 265.67 11/24/03 9:45 Mobil Moquawkie No. 1 0 0 1013 0 28 0.00% 0.00% 0.00% 499 17 42 2 4.72 3.28 314.77 11/24/03 10:00 Mobil Moquawkie No. 1 0 0 1013 0 28 0.00% 0.00% 0.00% 501 17 42 2 4.73 3.28 363.96 11/24/03 10:15 Mobil Moquawkie No.1 0 0 1013 0 28 0.00% 0.00% 0.00% 499 17 41 2 4.74 3.29 413.25 11/24/03 10:30 Mobil Moquawkie No. 1 0 0 1013 0 28 0.00% 0.00% 0.00% 504 17 40 2 4.74 3.29 462.68 11/24/03 10:45 Mobil Moquawkie No. 1 0 0 945 0 32 0.00% 0.000/. 0.00% 506 19 40 2 6.41 3.81 514.81 11124/03 11 :00 Mobil Moquawkie No. 1 0 0 952 0 32 0.00% 0.00% 0.00% 505 21 38 2 5.89 4.05 574.92 11/24/03 11:15 Mobil Moquawkie No. 1 0 0 957 0 32 0.00% 0.00% 0.00% 504 21 37 2 5.92 4.10 636.19 11/24/03 11 :30 Mobil Moquawkie No. 1 0 0 957 0 32 0.00% 0.00% 0.00% 502 21 37 2 5.92 4.12 697.83 11/24/03 11 :45 Mobil Moquawkie No. 1 0 0 960 0 32 0.00% 0.00% 0.00% 499 21 36 2 5.97 4.15 759.53 11/24/03 12:00 Mobil Moquawkie No.1 0 0 960 0 32 0.00% 0.00% 0.00% 496 22 36 2 5.96 4.14 821.61 11/24/03 12:15 Mobil Moquawkie No.1 0 0 987 0 32 0.00% 0.00% 0.00% 460 21 36 2 5.49 3.81 882.38 11/24/03 12:30 Mobil Moquawkie No. 1 0 0 896 0 36 0.00% 0.00% 0.00% 519 26 36 2 6.86 4.75 951.31 11/24/03 12:45 Mobil Moquawkie No. 1 0 0 896 0 36 0.00% 0.00% 0.00% 521 27 36 2 6.88 4.78 1022.87 11/24/03 13 :00 Mobil Moquawkie No. 1 0 0 896 0 36 0.00% 0.00% 0.00% 524 27 36 2 6.89 4.78 1094.58 11/24/03 13:15 Mobil Moquawkie No. 1 0 0 896 0 36 0.00% 0.00% 0.00% 519 28 37 2 6.91 4.80 1166.46 11/24/03 13 :30 Mobil Moquawkie No. 1 0 0 896 0 36 0.00% 0.00% 0.00% 524 28 38 2 6.91 4.80 1238.40 11/24/03 13:45 Mobil Moquawkie No. 1 0 0 851 0 40 0.00% 0.00% 0.00% 500 30 38 2 739 5.12 1312.16 11/24/03 14:00 Mobil Moquawkie No. 1 0 0 855 0 40 0.00% 0.00% 0.00% 496 30 38 2 7.51 5:21 1390.05 11/24/03 14:15 Mobil Moquawkie No. 1 0 0 859 0 40 0.00% 0.00% 0.00% 494 30 39 2 7.52 5.22 1468.20 11/24/03 14:30 Mobil Moquawkie No. 1 0 0 862 0 40 0.00% 0.00% 0.00% 495 30 39 2 7.56 5.24 1546.71 11/24/03 14:45 Mobil Moquawkie No. 1 0 0 952 0 40 0.00% 0.00% 0.00% 422 30 40 2 6.40 5.08 1625.34 11 /24/03 15:00 Mobil Moquawkie No. 1 0 0 983 0 32 0.00% 0.00% 0.00% 506 25 40 2 6.09 4.23 1686.99 11/24/03 15: 15 Mobil Moquawkie No. 1 0 0 987 0 32 0.00% 0.00% 0.00% 504 25 40 2 6.20 4.31 1751.18 11/24/03 15 :30 Mobil Moquawkie No. 1 0 0 983 0 32 0.00% 0.00% 0.00% 499 24 40 2 6.19 4.31 1815.88 11/24/03 15:45 Mobil Moquawkie NO.1 0 0 964 0 32 0.00% 0.00% 0.00% 489 25 39 2 6.05 4.21 1879.58 11/24/03 16:00 Mobil Moquawkic No. 1 0 0 972 0 32 0.00% 0.00% 0.00% 503 25 39 2 5.95 4.13 1942.06 11/24/03 16:15 Mobil Moquawkie No. 1 0 0 968 0 32 0.00% 0.00% 0.00% 486 25 40 2 6.00 4.17 2004.61 11/24/03 16:30 Mobil Moquawkie No. 1 0 0 968 0 32 0.00% 0.00% 0.00% 508 26 40 2 5.95 4.13 2066.89 11124/03 16:45 Mobil Moquawkie No. 1 0 0 968 0 32 0.00% 0.00% 0.00% 530 27 40 2 5.93 4.11 2128.83 11/24/03 17:00 Mobil Moquawkie No. 1 0 0 968 0 32 0.00% 0.00% 0.00% 538 28 40 2 5.94 4.12 2190.71 11/24/0317:15 Mobil Moquawkie No.1 0 0 964 0 32 0.00% 0.00% 0.00% 481 27 40 2 6.13 4.26 2252.89 11/24/03 17:30 Mobil Moquawkill No. 1 0 0 968 0 32 0.000/. 0.00% 0.00% 481 26 40 2 6.01 4.17 2315.24 11/24/03 17:45 Mobil Moquawkie No. 1 0 0 968 0 32 0.00% 0.00% 0.00% 481 25 40 2 5.51 4.14 2377.71 11/24/03 18:00 Mobil Moquawkie No. 1 0 0 964 0 32 0.00% 0.00% 0.00% 490 26 40 2 6.00 4.16 2440.09 11124/03 18:15 Mobil Moquawkie No. 1 0 0 964 0 32 0.00% 0.00% 0.00% 486 26 40 2 6.00 4.16 2502.50 11/24/03 18:30 Mobil Moquawkie No. 1 0 0 964 0 32 0.00% 0.00% 0.00% 478 26 40 2 5.87 4.13 2564.75 11/24/03 18:45 Mobil Moquawkie No. 1 0 0 964 0 32 0.00010 0.00% 0.00% 486 26 39 2 5.98 4.16 2626.33 11 /24/03 19:00 Mobil Moquawkie No. 1 0 0 960 0 32 0.00% 0.00% 0.00% 486 27 39 2 5.99 4.16 2688.72 11/24/0319:15 Mobil Moquawkie No. 1 0 0 1122 0 32 0.00% 0.00% 0.00% 1 16 24 2 0.00 0.00 2689.73 11/24/03 19:30 Mobil Moquawkie No. 1 0 0 1126 0 32 0.00% 0.00% 0.00% 0 22 28 2 0.00 0.00 2689.73 11/24/03 19:45 Mobil Moquawkie No. 1 0 0 1126 0 32 0.00% 0.00% 0.00% 0 25 30 2 0.00 0.00 2689.73 11/24/03 20:00 Mobil Moquawkie No. 1 0 0 1126 0 32 0.000/. 0.000/. 0.00% 0 26 32 2 0.00 0.00 2689.73 11/24/03 20: 15 Mobil Moquawkie No. 1 0 0 1126 0 32 0.00% 0.00% 0.00% 1 27 33 2 0.00 0.00 2689.73 11/24/03 20:30 Mobil Moquawkie No.1 0 0 1129 0 32 0.00% 0.00% 0.00% 0 28 34 2 0.00 0.00 2689.73 11/24/03 20:45 Mobil Moquawkie No. 1 0 0 1129 0 32 0.00% 0.00% 0.00% 0 29 35 2 0.00 0.00 2689.73 Page 1 . 15 Min Reads . 11/24/03 21:00 Mobil Moquawkie No. 1 0 0 1133 0 32 0.00% 0.00% 0.00% 0 29 35 2 0.00 0.00 2689.73 11/24/03 21 : 15 Mobil Moquawkie No. 1 0 0 1129 0 32 0.00% 0.00% 0.00"1.. 0 30 36 2 0.00 0.00 2689.73 11/24/03 21 :30 Mobil Moquawkie No.1 0 0 1133 0 32 0.00% 0.00% 0.00% 0 30 37 2 0.00 0.00 2689.73 11/24/03 21 :45 Mobil Moquawkie No. 1 0 0 1129 0 32 0.00% 0.00"/. 0.00% 0 30 37 2 0.00 0.00 2689.73 11/24/0322:00 Mobil Moquawkie No. 1 0 0 1129 0 32 0.00% 0.00% 0.00% 1 31 38 2 0.00 0.00 2689.73 11/24/0322:15 Mobil Moquawkie No. 1 0 0 1133 0 32 0.00% 0.00% 0.00% 0 31 38 2 0.00 0.00 2689.73 11/24/03 22:30 Mobil Moquawkie No.1 0 0 1129 0 32 0.00% 0.00"1.. 0.00% 0 32 39 2 0.00 0.00 2689.73 11/24/03 22:45 Mobil Moquawkie No.1 0 0 1129 0 32 0.00% 0.00% 0.00% 0 32 39 2 0.00 0.00 2689.73 11/24/03 23 :00 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 0 33 40 2 0.00 0.00 2689.73 11/24/0323:15 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00"/. 0.00% 0 33 40 2 0.00 0.00 2689.73 11/24/03 23 :30 Mobil Moquawkie No. 1 0 0 9 0 32 0.00% 0.00% 0.00% 1 34 41 2 0.00 0.00 2689.73 11/24/0323:45 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00"1.. 1 34 41 2 0.00 0.00 2689.73 11/25/03 0:00 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 34 42 2 0.00 0.00 2689.73 11/25/03 0:15 Mobil Moquawkie No. 1 0 0 9 0 32 0.00% 0.00% 0.00% 1 35 42 2 0.00 0.00 2689.73 11/25/03 0:30 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 35 42 2 0.00 0.00 2689.73 11/25/03 0:45 Mobil Moquawkie No.1 0 0 9 0 32 0.00% 0.00"/. 0.00% 1 35 43 2 0.00 0.00 2689.73 11/25/03 1:00 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 0 35 43 2 0.00 0.00 2689.73 11/25/03 1:15 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 36 43 2 0.00 0.00 2689.73 11/25/03 1 :30 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 36 44 2 0.00 0.00 2689.73 11/25/03 1 :45 Mobil Moquawkie No. 1 0 0 9 0 32 0.00% 0.00% 0.00% 1 36 44 2 0.00 0.00 2689.73 11/25/03 2:00 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 36 44 2 0.00 0.00 2689.73 11/25/03 2: 15 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 0 36 44 2 0.00 0.00 2689.73 11/25/03 2:30 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 36 45 2 0.00 0.00 2689.73 11/25/03 2:45 Mobil Moquawkie No. 1 0 0 9 0 32 0.00% 0.00% 0.00"1.. 0 37 45 2 0.00 0.00 2689.73 11/25/03 3 :00 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 37 4S 2 0.00 0.00 2689.73 11/251033:15 Mobil Moquawkie No. 1 0 0 4 0 32 0.00% 0.00% 0.00% 1 37 45 2 0.00 0.00 2689.73 11/25103 3 :30 Mobil Moquawkie No. 1 0 0 9 0 32 0.00% 0.00% 0.00% 1 37 45 2 0.00 0.00 2689.73 11/25/033:45 Mobil Moquawkie No.1 0 0 9 0 32 0.00% 0.00% 0.00% 1 37 46 2 0.00 0.00 2689.73 11/25/034:00 Mobil Moquawkie No. 1 0 0 4 0 32 0.00"1.. 0.00% 0.00% 0 37 46 2 0.00 0.00 2689.73 Page 2 · . 1100 (I ¡ 1150 1200 1250 ¡ 1300 1350 1400 Pressure P-Grad T -Grad 500 21.7 1145.25 27.44 500.6 1159.28 44.51 0.0293 3.56 1000.2 1173.77 54.90 0.0290 2.08 1500.6 1187.74 63.90 0.0279 1.80 2000.9 1201 .28 72.62 0.0271 1.74 1000 2501 .0 1214.62 79.90 0.0267 1.46 2636.3 1218.2'1 82.50 0.0266 1 2619.0 1219.30 83.14 0,0255 1.49 2741 .4 1238.72 84.48 0.3114 2.15 2191.1 1262.86 85.58 0.4856 2.22 2822.6 1278.35 85.86 0.4925 0.88 1500 2864 ,3 1298.95 86.36 0.4934 '1.21 2000 2500 3000 o I 90 10 20 30 40 50 70 80 100 60 Perfs Report date: 11119/2003 www.aurorapower.com November 4, 2003 State of Alaska Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, AK 99501 Attn: Mr. Steve Davies RE: Mobil Moquawkie No.1, PTD #203-069 Gentlemen: This letter in duplicate originals transmits the data to you identified below, pursuant to Aurora Gas, LLC's obligation to you. This data is relative to operations at the Moquawkie Field, Cook Inlet, Alaska. Enclosed herewith: SCHLUMBERGER CASED-HOLE LOGS 1- Ultrasonic Cement and Casing- Imager (USIT) w/ Gamma Ray and Casing-Collar Locator 1- Reservoir Saturation Tool-Sigma Mode 2- Squeeze Perforating Records, dated 10/11/03 and 10/14/03 2 - Completion Records, dated 10/16/03 and 10118/03 Please signify that you have received and accepted this data by signing in the space below and returning this letter to me at the Houston address below or by fax to me at 713-977-1347. If you have questions, please contact Andy Clifford or me at the Houston number below. ~il\cerely, /-'\ I/,,", ,.! .~ Z.,á1'7£-~~/-;h/~'-;» ; / > , ,.J. Edward Jones /,/,// L . Executive Vice Pn'~Úient, Engineering and Operations RECENED AND ACCEPTED ABOVE DATA this lO Day of November, 2003. BY~·~\.~ N'''-. ~'-~k::L~Y\ TITLE: 6 ,",-~~\) ~y\~ 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 Sent By: AURORAUPOWER; . --~"....." To: stcVt.. ~V\'5 "~ax: q01 ~ l1('- 1~~2. Phone. Re= ----,.........".. 7139771347; Jul-10-03 11: HAM; . Page 1 . . j~.···""·8; Gi··S, LLC 1'm. .' lë~"". v. . . . A' 10333 Richmond, Suite 710 Houston, Texas 77042 ~one;713~977~5799 Fax: 713..977..1347 Fax Transmittal Form : From: ~. Srð-t\-':P-Á,f.ç.. Datet 1 ...10 p..... 5 eel ............--- ".....,..-.-...- ............,.......-----...........,'. [] Urgent 0 For Ravlew ;0....... Cc;.""II.B.d [J"".. bpl)f [J Please Reeyele M..sage: NOTE: The Information contðioed in this fðX I~ conflde",tlal and/or privileged. This fax Is intended for the sole use on the individ- ual named above. If the reader of this tran.' page is not ttle intended recipient or a representative of the intended reåpient, yOI,I are hereby notified that any review, d~inéltion, distrIbution, or copying of this f~x or the Information contained herein is prohIbited, If you have received this fð)( In errë>r, please Immediately notify the sender by telephone and rm.rn this fax to the sender at the address above." . Sent By: AURORA#POWERj . 7139771347j JUl-1~ 11 :17AMj Page 2 , . ; STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION DESIGNATION OF OPERATOR 20 MC 25.020 .... ~ ... \ \". .... ""... 1. Name and Address olOwnør; Aurora Ga~, LLC 10333 RiChmond Avenue Suite 710 ; Hcn~~s:.~on, ~!¡I 77042 2. Nouc:e is høreby gIVen of a deslgnatlon of openltoijship Jor Ihe oU ilnd gill& property descrIbed betoW: L@glll d@5ClÌþlJon of property: Mobil MQquawkie No. 1 Section~ l¡ 2;3, E2E2E2; 10, E2E2E2;11.12 comprising 2,720 gross/net acres TownshiP' 11 North, Range 12 West Seward Meridian Lessor;: Cook Inlet Region, Inc. Lessee: ,: Aurora Gas t LLC Lease Date February 1, 1995 C-61390' Property plat attached 0 '" ! 3. NëlliI(I 0111(1 AI,Idrøl;s 01 DesJgnalt'ld Opel alar: Aurora Gas, LLC 10333 Richmond Avenue $uite 710 ~ouston, Texas 77042 ...... .............".. 4_ Eflective Dale of 08s191'1811on: ... ..... .. ~ . Decembet 31, 2002 5. Acceptance of ope~Sh~ the~,d I.d propeny with all aUendant respoO$lbllidea and.: obligations hi hereby acknOWledged; Signalure h..~"~ .... Datil...... _ 7~rt::Þ.-:=.~"? ..... . . . Printed Name G. Scott Pfaff 6. The awn. er hereby ?;:S that the foregoi Sign.iltul'O ...... ... . . ~,...,~ . TIt1è President - Dale ?--{f¿.~a? Printed Name 7. G. Scott Pfoff ( .. ....... .... ...... .... .... ......~ ............. ........ ...... ........... Tille President ........·...V\·..·"'.\'."'··\/lA_........". Approved: ____... . ........,~.".__".a._.. Commlsslonei' Dala Approved: ....., .. Commlaliion~ Dais Approved: ~....._~... . . .. ..... CömmissioneÍ' Dall!! (RB~!uira.$ ~~prc;1v¡¡lby Iw.Q C~_IT\Il1~~~o.~'!'r.~) ..... Form 10-41 11 Rev¡s~ 2/2003 .-----~ .,"........,'..1..... . . .',. Submit In dupllcale.. : ,:)~~"A.J.. ')ý/b,·~,.~;t~! tt (...~'-. i"· ¿'.... .,r<S,ö "7 II.- ù:'3 Sent By: AURORA#POWER; . 7139771347; J ul-1 0 - 03 11: 18AM; . Page 4/5 ., STATE OF ALASKA . AlASKA OIL AND GAS CONSERVATION CQMMISSION NOTICE OF CHANGE OF OWNERSHIP , . , '. . 20 MC 25.022 . .."."....1',.... 'Y" 1, N"me of Opfilr¡¡lQr: Aurora Gas, Ltc 2. Address: 10333 Richmond Avenue Suite 710 , Houston, Texa~ 77042 ...-.. ....... ........,. ,- .....', 3. Nollce Is hêreby given that the ownerß. IandQwnerD. of record for the 011 and ·gas property d~bed below has asslgnfild or transferred intere~1 in the property indicated below: . . , Property designation: C-61390 legal descrlpllon of properly: MObil! MoquawJde No. 1 Field or Unit: Moquawkie Field SectiOns Ii 2; 3, E2E2E2; 10, E~E2E2; 11; 12; comprising 2,720!gross /net acres Township 11 North, Range 12 West seward Meridian Lesso~: Lessæ: Cook Inlet Region, Inc. Aurora Gas, LLC Properly pial attachedO 4. Effective date of &$$lgnm$nl or IranGfét~ 5. Percentage Inleresl ~sslgned or transferred: December 31, 20J2 100.00% 6. Ae$ignee or Trl!lr't!irét&e~ .. ... ~~ . Aurnra Gas,'; t,Le ... ...." ......, ......,.. .......... ........... Address: 10333 Richmþnd Avenue, Süite 710 Houston, Teþcas 77042 ......./.. .\.'1"·/"·"..·,....·: ..-.....- Anadarko petroleum corporation 1201 Lake Rþbbi~ Dr! ve The Woodl~s, Texas 77380 ./\.\,..."........."...... co+ 10 the bel!ll o( my knowledge: Date 7 -(0 -()3 7. Assignor or Transferor: AddI'$S': :;Q~:::~cert,~z;:~I"g :~. . PtlnlG(j Namé ,G. Scott Pfoff Tille _ Pr~~~dery~ '....n..." "............"'.....__...." ."'............. ............... Fonn10-417 Ftevlsed 212003 .s'lf1rd: ....c,. h'.."I...'.:A-_'?~ ,.-.~...... U'- ...) <~(... pv ... j.1¿ ò ~ 2003 Proposed Cook Inlet Basin Projects...ations - Additional Infonnation / Needs . , . . Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information I Needs Date: Tue, 24 Jun 2003 12:19:46 -0800 From: steve_davies@admin.state.ak.us To: Randy Jones <tjones@aurorapower.com>, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Randy, As follow-up to our conversation today, I would like to send my listing of needed additional information concerning the permit to drill applications submitted to the Commission as part of Aurora's 2003 proposed Cook Inlet Basin projects. This is the original listing I sent you via email on April 21, 2003, annotated with comments about concerns/questions that have been answered, and those items that are still outstanding. If you have any questions, please call me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us "",,,,,,,,,,~~,~~___~·~_.·mm_'mmmm"n~m"nmmmm~~mm"¥.¥.W.,_~~_m"'mmm"__m__mm~_'~~_"_^_W_W_'A___, nmn~~____""··"'''''''·''''''''''m.''''._.·''m_~~.mnmn_____,_~_,^"._"''''mm.~_.'m_~' ~___~___.·_v_ 'y., ~ 1 030623 "~____'~_.~___._." ww_~,~,,_~~_~~~__ ~_~__._._ Name: 1_030623_Aurora_ W _CI_Proj{ Aurora W CI Project Deficiencies List.doc! Type: WINWORD File (application/rr __" .. _~__"__~_.... ..~_~._. I E~~.~~ing:..~~~~64 ._.__..~ . . Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information I Needs Updated June 24, 2003 Lone Creek #3: Permit to Drill number 203-062, expected spud date is May 15, 2003. AOGCC senior staff submitted the application for pennit to drill to Commissioners for approval on 6/24/03. a.Logging program is not spccifit'<i in well permit application. Received 4/22/03. b.Need determination from Glen Gray as to whether an ACMP Consistency Detelmination is needed. ACMP determination may be needed (Glenn Gray, 6/6103 email to Tom Maunder, AOGCC). ACMP determinations will no longer delay approval and issuance of a permit to drill from the Commission. However, a permit to drill 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. Long Lake #1: Permit to Drill number 203-068, expected spud date is May 20,2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/locallakpages/ADMIN/ogc/art199.htm. b. Designation of Operator and Notice of Change of Ownership forms must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. These forms can be obtained from AOGCC's web site at: http://www.state.ak.us/local/akpages/ADMIN/ogc/homeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end ofthis letter. Alaska Oil and Gas Conservation Commission 1 . . c. C-P1an exemption determination needed from AOGCC. I am awaiting a request letter from ADEC. Submitted recommendation to Lydia Miner, Alaska Dept of Environmental Consrvation on June 20,2003. d.Logging program is not specified in well permit application.Received 4/22/03. d. ACMP not needed ((Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). Mobil Moquawkie #1: Permit to Drill number 203-069, expected spud date is June 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease (see write-up in item "b"under Long Lake #1, above}. e. Logging program is not specified in well pelmit application.Received 4/22/03. b. c. ACMP not needed ((Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). c. Spacing exception not required as long as re-completion operations in Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie #1 is 1704' from the nearest lease line, which exceeds the required 1500' setback distance from property lines for a gas well. Moquawkie #1 is 2500' away from, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. from 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-completion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-completion operations are restricted to 2900' MD and shallower. West Moquawkie #1: Permit to Drill number 203-070, expected spud date is June 20, 2003. a. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie #1 re-completion. Simpco Moquawkie 1 also lies within the same section (Section 36). b. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. (see write-up in item "b"under Long Lake # 1, above) f. Logging program is not Gpecified in well permit application. Received 4/22/03. c. ACMP not needed ((Glenn Gray, 6/6103 email to Tom Maunder, AOGCC). Kaloa #2: Permit to Drill number 203-071, expected spud date is July 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. (see write-up in item "b"under Long Lake #1, above) Alaska Oil and Gas Conservation Commission 2 . . b. Logging program is not specified in well permit application. Received 4/22/03. c. Need detem1ination from Glen Gray aG to whether an ACMP Consistency Determination is needed.ACMP determination may be needed (Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). ACMP determinations will no longer delay approval and issuance of a permit to drill from the Commission. However, a permit to drill 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. d. Spacing exception is not required. Although nearby well Simpco Kaloa 1 is perforated in the same interval and is classified as shut-in, it is not capable of producing in its current condition (bridge plug set at 3552' MD, cement on top ofthe bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission 3 . . Moquawkie Field Area Ownership and Operators hip Records in AOGCC Files April 17, 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Kaloa No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S 18, T12N, R11 W. Aug 2000: Notice of change of Ownership from COO to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator form from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator form for that lease. Apr 2001: Designation of Operator form from Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, T12N, R11 W. Jan 2003: Designation of Operator form designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission 4 . . (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance ofthe designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission 5 .¡~.c...<¡ Gas, LLC Permit to Drill Deficiencies Letter . . Subject: Aurora Gas, LLC Permit to Drill Deficiencies Letter Date: Mon, 23 Jun 2003 11 :02:25 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: ray@fairweather.com Ray: As we discussed on Friday, attached is the email that I sent to Randy Jones in April which outlines needs or deficiencies for each of the permit to drill applications submitted by Aurora. Please call or email me if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------ Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today) . Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies ----------------------------------------------------------------------- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska oil and Gas Conservation Commission ~/..¡¡rC[a Gas, LLC Permit to Drill Deficiencies Letter . Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us . _~'WV"'~V ~__~.......~,.........,.~_~ __~~_____vw" ____"'_y_,,___ v_~~~__ _wwvw___·~···~__w_,__, v_v~=_ ¡ Name: 030418 Aurora W CI Project ~030418 Aurora W CI Project Deficiencies Email.doc: Type: WINWORD Fil~ (appl~ationl~ I Encoding: base64 ____._______.J_____._____.......___. __ ____mm...____.____....__.. :.--__m_'~__~~ '~,_v..,....~,_,..~~__v..____~ Aurora Operations . . Subject: Aurora Operations Date: Fri, 06 Jun 2003 09:58:31 -0800 From: Glenn Gray <Glenn _ Gray@dnr.state.ak.us> Organization: Alaska Department of Natural Resources To: Tom Maunder <tom_maunder@admin.state.ak.us> CC: Steve Davies <steve_davies@admin.state.ak.us>, Randy Ruedrich <randy _ ruedrich@admin.state.ak.us>, bill penrose <bill@fairweather.com> Tom: At a preapplication meeting held on April 17, 2003, Fairweather discussed a number of proposals for gas exploration and development projects on the West side of Cook Inlet for Aurora Gas LLC. Although the Office of Project Management and Permitting has not received a Coastal Project Questionnaire for any of the projects, it appears that some of the projects will not need an ACMP review. Unless there is an permit trigger (e.g., a Corps 404 permit or a state permit included on the "C List"), the following projects will not need an ACMP review: Long Lake No. 1 Mobil Moquawkie No. 1 Simpco Moquawki No. 1 Simpco Moquawki No. 2 West Moquawkie No. 1 For several other wells, an ACMP may be required, and a final decision will be made after Fairweather provides more information to me about the permits needed for the projects: Nicolai Creek Unit No. 7 (ACMP review likely needed) Lone Creek No. 3 (may need a review) Kaloa No. 2 (may need a review) Shirleyville Production Facility (may need an ACMP review) As I recall, Fairweather was working with the Corps to complete wetlands determinations to see if 404 permits are needed and with the Office of Habitat Management and Permitting to see if fish habitat permits are needed. By copy of this email, I will check with Fairweather to see if they have any new information. Glenn termination will ':PAi/£:.. Oil and Gas Update . 3 . June 16, 2003 Pipeline System near Valdez. This facility provides the source for the Valdez Marine Terminal (VMT) raw water, potable and firewater needs. OPMP initiated this 30-day review on April 15, 2003 and issued the final determination on May 2, 2003 [17 calendar days in review]. Contact: Kaye Laughlin. Pre-Application Stage Kuparuk River Rehabilitation Plan: ConocoPhillips Alaska, Inc. proposes to restore the East and West Channels of the Kuparuk River to their approximate condition prior the spine road development. Contact: Kaye Laughlin. Aurora Gas LLC Projects: Aurora Gas proposes to conduct exploration for gas on a number of sites and a development project at one site during the summer of2003. All ofthese projects are located onshore on the west of Cook Inlet. Exploration activities for five projects will be conducted from existing pads, and no permits are expected to trigger an ACMP consistency . review (Long Lake No.1, Mobil Moquawkie No.1, Simpco Moquakie No.1, West Moquawkie No.1, and Simpco Moquawkie No.2). Three exploration projects would likely need an ACMP review (Nicolai Creek Unit No.7, Lone Creek No.3, and Kaloa No.2). A production facility including installation of a four-inch pipeline is proposed near the Shirleyville runway. OPMP sponsored a pre-application meeting on April 17, 2003. Contact: Glenn Gray. Petro Star Valdez Pipelines: Petro Star, Inc. proposes to construct two parallel petroleum pipelines and a fuel transfer dock on the south shore of Port Valdez just east of the Solomon Gulch Hatchery. In 1992, Petro Star investigated seven different alternative locations for delivering product to a marine terminal. The proposed pipelines will start at the Petro Star Valdez Refinery and continue west, buried under a mile-long section of a new bike path along Dayville road. From Dayville Road, a trestle will extend about 1,000-feet northward to a fuel transfer dock. Petro Star plans construction of the buried pipeline to be concurrent with construction of the pedestrian path along Dayville Road Contact: Kaye Laughlin. Borealis Power Project: BPXA proposes to expand infrastructure to meet power demands of future satellite expansion in the western end of the Prudhoe Bay Unit and a possible tie-in with the Milne Point Unit power grid. The project would include a new 69 kV power line, a sub- station, and possible minor pad extensions. The power line would run from the Central Power Station to the L and V Pads in the end of the unit and possibly extended to Milne Point. Originally planed for the 2003-2004 winter season, BP notified OPMP that the project has been deferred for another year. OPMP held a pre-application meeting on April 9. Contact: Kaye Laughlin. DEC Inactive Reserve Pit Closure Program: OPMP is working with state resource agencies and the U. S. Army Corps of Engineers on reserve pit closures required by the DEC solid waste program. Companies are required to complete environmental assessments for all abandoned drilling waste reserve pits and must conduct corrective actions to clean up or prevent release of contaminants at these sites. Assessments have been completed on over 600 sites in the state, and Well Permit Response . . Subject: Well Permit Response Date: Wed, 30 Apr 200313:57:16 -0800 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.ak.us> CC: 'Ed Jones' <jejones@aurorapower.com> Tom: Please find attached a response to AOGCC's request for information and clarification for each of the following (4) wells. West Moquawkie No.1 Kaloa NO.2 Moquawkie No. 1 Long Lake No. 1 I hope that the attachments will clarify, appropriately address and correct concerns initially submitted to us. Please do not hesitate to call or email me should more clarification or information be required. Thank You Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 .. ............................................... .................. "" .."."".".."".".....",............... ................................. . ..""".."''''.".......""............. ......... ........"..... i . Name: W. Moquawkie #1.doc 1 ~W. ~~~uawki~~1.dOC Enc()~;;~;~~~ORD File (application/msword) , Name: Kaloa #2.doc . DKaloa #2.docjl,. Type: WINWORD File (application/msword) Encoding: base64 v_vw·",·' ....>' ".···.········,······.,·_______.,,."."'w.v.........v . ............ ""..",...".............. , Name: Long Lake #1.doc DLong Lake #1.doc Type: WINWORD File (application/msword) Encoding: base64 1 of 2 6/24/2003 8:25 AM Well Permit Response . . ! Name: Moquawkie No. 1.doci I D.......'.·...M.....o...q......u......a.....w........k.....I.·.e...N.....O......1. .doc ,I Type: WINWO.....R.......D..........F....ile....<a.p. Plic.atio..n.I..m......s.....w......o.....rjd. )... : ¡ Encoding: base64 . >'".,,»-:.'...,"'..................-----------------..................,:.....'''.,......--.-----.--......'.'. 2 of 2 6/24/2003 8:25 AM . . Original Message: From: Tom Maunder [tom_maunder@admin.state.ak.us] Sent: Monday, April 21, 2003 2:53 PM To: Duane vaagen Subject: Moquawkie No.1 Hi Duane, I was looking at the Moquawkie #1 and had a couple of questions. Some are the same as for Long Lake. 1. I note that you are planning to have the rotating head installed. Is there a plan to reverse circulate while cleaning out?? I think that is what was done last year. 2. It would appear that you are just going to install a wellhead beginning on the 9-5/8" casing?? Is that correct?? 3. You plan to drill out the plug through the old production perforations and clean out to immediately above the shallowest squeeze perforations to about 2900'. You will test the casing before drilling that cement plug, but there is no plan to test once the plug is cleared out. I realize that it may prove difficult to get a casing test at that point. Has it been considered to set a retainer at about 2900' to give a solid bottom?? This would help answer the questions with regard to preventing cement fall as asked in the Long Lake memo. 4. In the cased hole logs, is any CBL planned?? I realize that there is only 550' or so of 9-5/8" casing below the 13-3/8" shoe, but knowing what the cement looks like around your potential target sands would seem to be important, especially given that it appears that all cement placed in that portion of the well was by squeeze. Also, the mentioned sand production in the well history might give some evidence of suspect cementing although the nature of the sands might be more of the cause. 5. Are there any plans to test intervals above the 13-3/8" shoe?? 6. If the 9-5/8" does not test, is there a plan to run a full string of 7" to get competent pipe in the hole?? 7. Your hazard analysis has documented a lot regarding the uncertainty on potential formation pressures. Your caution statements are appropriate. Provided the 9-5/8" tests, that "blowout interval II will likely not be a source of problems. Given that there could still be uncertainty for potential production . . zone pressures, have you considered making some of the perf and test runs with tubing conveyed guns or perforating through drill pipe. This would have you all set up to handle pressure with the kill string already in the hole. Thanks for you attention to these questions. Also, has the letter regarding the gas determination been sent to DEC?? Tom Maunder, PE AOGCC Response: Mobil Moquawkie No. 1 Tom: Thank you for your prompt review, please find below Aurora's response to the above concerns and questions in the order originally posed. 1) Yes, for re-entry and clean out procedures our plan is to use a rotating head and reverse circulate. I apologize for not clarifying that on the well procedure submitted with the permit application. 2) No, we will install a 13 5/8" casing head with slips and seal for the 9 5/8" first, followed by a 13 5/8" x 11" tubing spool. This was not clarified in the application submitted and I apologize. 3) We will set a bridge plug or retainer at 3000'. This will give us - 100+' of rathole below our completion and as indicated, insure a solid bottom. This will require that we clean out the casing to -3010' prior to setting the plug. 4) In looking at the original cement bond logs, I'm not totally sure that is necessary. There appears to be pretty good cement in place from 2480' - 2620', which will cover the interval above the shallowest intended perforations. There also appears to be pretty good isolation from 2900' - 3210', which is directly below the deepest intended perforations. Unless some other discovery is made on re-entry, we are not at this time proposing to run a CEL. 5) There are no plans at this time to test above the 13 3/8" casing shoe located at 2455'. . . 6) Again, running a 7" casing string is always an option. We will leave that as a last resort though and try repairing with cement squeeze procedures or even a casing patch if required. 7) Yes, we have given some thought to using tubing conveyed perforating guns, but in reviewing the history of the well coupled with the fact that the well produced almost 1 bcf prior to being plugged, we feel cautiously optimistic that the overpressure problem originally encountered has been mitigated. Also, the Simp co Moquawkie No. 1 and No. 2 offset wells have been drilled in the interim since the Mobil Moquawkie was originally drilled, produced and plugged. There is significant pressure and test data from both to lend credibility to our theory that pressures have been reduced in the proposed production intervals. We will nonetheless approach the re-entry of this well with caution as indicated in the proposal submitted. There may be some economic advantage though to using the tubing conveyed guns and we are investigating that possibility at this time, so there is a possibility. Thanks and please do not hesitate to call me at 258-3446 with any more questions or concerns. Duane Vaagen Fairweather E&P Services, Inc. 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today) . . Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies ----------------------------------------------------------------------- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. . Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us Commission ......_A"'."""'.."'''''''''''.''''''''...W..A. ..."."".".... ..A ........."'.."."."................. .__..,.""""",,,,,,.,, _..".''''... ~030418_Aurora_ W CI Project Deficiencies Name: 0304] 8_^urora_ W _ CI_Projcct_Dclicicllcics_Email.doc, Email.doc Type: WINWORD Pile (applicationlmsword) I Encoding: base64 I ,~,.,-" ,¥~.... ~ . . Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Informatiou I Needs Lone Creek #3: Permit to Drill number 203-062, expected spud date is May 15, 2003. a. Logging program is not specified in well permit application. b. Need determination from Glen Gray as to whether an ACMP Consistency Determination is needed. Long Lake #1: Permit to Drill number 203-068, expected spud date is May 20, 2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ". . . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/locallakpages/ADMIN/ogc/art199.htm. b. Designation of Operator and Notice of Change of Ownership forms must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. These forms can be obtained from AOGCC's website at: http://www.state.ak.us/locallakpages/ADMIN/ogclhomeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end ofthis letter. c. C-Plan exemption determination needed from AOGCC. I am awaiting a request letter from ADEC. d. Logging program is not specified in well permit application. Moquawkie #1: Permit to Drill number 203-069, expected spud date is June 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. b. Logging program is not specified in well permit application. Alaska Oil and Gas Conservation Commission 1 . . c. Spacing exception not required as long as re-completion operations III Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie #1 is 1704' from the nearest lease line, which exceeds the required 1500' setback distance from property lines for a gas well. Moquawkie #1 is 2500' away from, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. from 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-completion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-completion operations are restricted to 2900' MD and shallower. West Moquawkie #1: Permit to Drill number 203-070, expected spud date is June 20, 2003. a. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie #1 re-completion. Simpco Moquawkie 1 also lies within the same section (Section 36). b. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. c. Logging program is not specified in well permit application. Kaloa #2: Permit to Drill number 203-071, expected spud date is July 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. b. Logging program is not specified in well permit application. c. Need determination from Glen Gray as to whether an ACMP Consistency Determination is needed. d. Spacing exception is not required. Although nearby well Simpco Kaloa 1 is perforated in the same interval and is classified as shut-in, it is not capable of producing in its current condition (bridge plug set at 3552' MD, cement on top of the bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission 2 . . Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17, 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Kaloa No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S18, T12N, RllW. Aug 2000: Notice of change of Ownership from CIRI to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator form from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator form for that lease. Apr 2001: Designation of Operator form rrom Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, T12N, R11 W. Jan 2003: Designation of Operator form designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission 3 . . (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance ofthe designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission 4 Aurora Logging Program Subject: Aurora Logging Program Date: Tue, 22 Apr 2003 15:16:16 -0800 From: duane vaagen <duane@fairweather.com> To: "Steve Davies (steve_davies@admin.state.ak.us)" <steve_davies@admin.state.ak.us> Steve: Attached are files as promised. The 2003 Wireline spreadsheet contains the proposed logging suites for each well, which are tabbed as additional spreadsheets in the file. Please do not hesitate to call with any questions or concerns. Duane Vaagen . Project Engineer Fairweather E&P Services, Inc. d uane(â)fa irweather. com Office: (907)258-3446 Cell: (907)240-1107 . .................... ·r.._w.Y..·~·''''·" ···········v~yy·.·,_.·,v_,,~· ...... "W'_"¥~""""""'~H'''~Y~' r~'m._w.wy.y..~=~Y~"¥~V~~w~""V"""""~"V~"~~~ww~~.""""'~", ~~_~y~_,,_~~~w~w·____y······,v·,·,_' _y.w······y·····yyy~~_¥~~~·.w "ww·····oo : I Name: 2003 Wireline Logging Program.xls : ~2003 Wireline Logging Program.xls~ Type: Microsoft Excel Worksheet (applicationlvnd.ms-excel)i . ......~.J E~~.~.~ï.~~E. base64 . ~·..,,~~,~v~~ ..·~_"ww~w~w ~_'M~_"~·Y·······YY··~W~·_~_W~W~V'W ."""". """""""M'".",,,,,",, """"".""." '''''''''''''.,"""""""", ".."''''....'_'''''¥.M...''.''"""""""".""."......... A..'""""..".."..."... ....... ""......~...~. .... -- l'iame: 2003 Mudlogging Program.xls . ~2003 Mudlogging Program.xls Type: Microsoft Excel Worksheet (applicationlvnd.ms-excel)i .~mm.~. \.~_._._~ .L~nc.?di~~~.~ase64. . __....._~ _~ d" fi6./i,':''fì c~ AI(;)pv4JÁ¡~ J (j 'fJ hb Moquawkie #1 (Re-Entry) Moquawkie Field Proposed Logging Program Log Run Depths Hole/Casing Tools E-Mail Prints Film/Sepia Digital CH1 Surface-51 00' 9-5/8" USIT/CCLlGR CHFR? RST VSP? PDS/LAS 8 1 . 1-DLlS/PDS (CD) 7 -LAS/PDS (Disk) . Aurora Gas, LLC 4/23/2003 030423_Aurora_W_CL2003 Wireline Logging Program.xls Moquawkie 1 Moquawkie NO.1 . Subject: Moquawkie No.1 Date: Mon, 21 Apr 200314:53:23 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Duane Vaagen <duane@fairweather.com> Hi Duane, I was looking at the Moquawkie #1 and had a couple of questions. Some are the same as for Long Lake. 1. I note that you are planning to have the rotating head installed. Is there a plan to reverse circulate while cleaning out?? I think that is what was done last year. 2. It would appear that you are just going to install a wellhead beginning on the 9-5/8" casing?? Is that correct?? 3. You plan to drill out the plug through the old production perforations and clean out to immediately above the shallowest squeeze perforations to about 2900'. You will test the casing before drilling that cement plug, but there is no plan to test once the plug is cleared out. I realize that it may prove difficult to get a casing test at that point. Has it been considered to set a retainer at about 2900' to give a solid bottom?? This would help answer the questions with regard to preventing cement fall as asked in the Long Lake memo. 4. In the cased hole logs, is any CBL planned?? I realize that there is only 550' or so of 9-5/8" casing below the 13-3/8" shoe, but knowing what the cement looks like around your potential target sands would seem to be important, especially given that it appears that all cement placed in that portion of the well was by squeeze. Also, the mentioned sand production in the well history might give some evidence of suspect cementing although the nature of the sands might be more of the cause. 5. Are there any plans to test intervals above the 13-3/8" shoe?? 4. If the 9-5/8" does not test, is there a plan to run a full string of 7" to get competent pipe in the hole?? 5. Your hazard analysis has documented a lot regarding the uncertainty on potential formation pressures. Your caution statements are appropriate. Provided the 9-5/8" tests, that "blowout interval" will likely not be a source of problems. Given that there could still be uncertainty for potential production zone pressures, have you considered making some of the perf and test runs with tubing conveyed guns or perforating through drill pipe. This would have you all set up to handle pressure with the kill string already in the hole. Thanks for you attention to these questions. Also, has the letter regarding the gas determination been sent to DEC?? Tom Maunder, PE AOGCC . Iq..I)'l"Mª.\:!..o.q.?r <tom maunder@admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 2 4/21/20032:55 PM 2003 Proposed Cook Inlet Basin Proj...ns -lionallnformation / Needs . Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information I Needs Date: Mon, 21 Apr 200308:52:49 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today). Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a revieW. Thanks, Steve Davies ------------------------------------------------ ----------- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us ..__...__..___.._·,_·.·_M__..Mh_ Name: 030418_Aurora_W_CI_Project_Deficienci 0030418 Aurora W CI Project Deficiencies Email.doc Type: WINWORD File (application/msword) Encoding: base64 1 of 1 4/21/20038:59AM . . Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information I Needs Lone Creek #3: Permit to Drill number 203-062, expected spud date is May 15,2003. a. Logging program is not specified in well permit application. b. Need determination from Glen Gray as to whether an ACMP Consistency Determination is needed. Long Lake #1: Permit to Drill number 203-068, expected spud date is May 20, 2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: "...for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/locallakpages/ADMIN/ogc/art199.htm. b. Designation of Operator and Notice of Change of Ownership forms must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. These forms can be obtained from AOGCC's website at: http://www.state.ak.us/local/akpages/ADMIN/ogclhomeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end of this letter. c. CoPlan exemption determination needed from AOGCC. I am awaiting a request letter from ADEC. d. Logging program is not specified in well permit application. Moquawkie #1: Permit to Drill number 203-069, expected spud date is June 1,2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. b. Logging program is not specified in well permit application. Alaska Oil and Gas Conservation Commission 1 . . c. Spacing exception not required as long as re-completion operations III Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie #1 is 1704' rrom the nearest lease line, which exceeds the required 1500' setback distance rrom property lines for a gas well. Moquawkie #1 is 2500' away rrom, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. rrom 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-completion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-completion operations are restricted to 2900' MD and shallower. West Moquawkie #1: Permit to Drill number 203-070, expected spud date is June 20, 2003. a. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie # 1 re-completion. Simpco Moquawkie 1 also lies within the same section (Section 36). b. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. c. Logging program is not specified in well permit application. Kaloa #2: Permit to Drill number 203-071, expected spud date is July 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. b. Logging program is not specified in well permit application. c. Need determination rrom Glen Gray as to whether an ACMP Consistency Determination is needed. d. Spacing exception is not required. Although nearby well Simpco Kaloa 1 is perforated in the same interval and is classified as shut-in, it is not capable of producing in its current condition (bridge plug set at 3552' MD, cement on top ofthe bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission 2 . . Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17, 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Kaloa No 1 to COO. Jun 1998: Mobil and CIRI designate Anadarko as operator for S18, T12N, R11 W. Aug 2000: Notice of change of Ownership from COO to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator form from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator form for that lease. Apr 2001: Designation of Operator form from Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, T12N, RllW. Jan 2003: Designation of Operator form designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only ifthe owner is the same and the landowner is the same on both sides ofthe line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission 3 . . (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance ofthe designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Ahulkll ()iI IIfl<l Gas Conservation Commission 4 RE: Lone Creek #3 . . Subject: RE: Lone Creek #3 Date: Wed, 16 Apr 200312:08:19 -0800 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.ak.us> Tom: Per your request, the following applies. I'll respond in the order of the questions below. 1. Yes, we have a formal meeting tomorrow afternoon with DGC, ADF&G, COE, DNR and TLO to discuss this and other wells in Aurora's program. In regards to Lone Creek No.3, we are hoping they give the green light to proceed as the only disturbance will be pad construction. No wetlands are being crossed and access will be via road constructed to drill the Chuit State wells years ago. Based on the meeting tomorrow, we will obtain all permits necessary. One thing we do know we need is a survey for a wetlands determination, site suitability and for archaeological or cultural resources. Another permit application submitted is for the Kaloa No.2. I am not so sure we will even get to this as we need a bridge. By the time we get through Corp of Engineers and ADF&G, the odds are it will not happen. 2. Waste will be handled as last year, and the following is applicable for the entire multi-well program this summer. Brines and muds will be recycled and used to the fullest extent possible. Drilling and workover wastes not recyclable will be transported offsite for treatment and disposal by Enviro-Tech. My apologies for not including this information in the permit application. I realized after I submitted the paper work that I omitted this information on all the welts. I will be submitting a Sundry application for testing and workover of the Simpco Moquawkie NO.2 well soon. Base on log analysis and review of historical test results, I will be putting together a permit application for conversion of the SM NO.2 well to disposal. This is one of the back-burner wells, but I think we will find that we really need a disposal well. 3. The proposed Lead Slurry design calls for a yield of 2.1 cf/sack. 4. Attached is tentative outline of work progression. This may have been pushed back now as we are not moving the rig across Inlet until the 2nd of May. We are working on a Gantt chart and will forward a copy as soon as we have it ready. Thank you please call if you need more information or clarification. Duane Vaagen Fairweather E&P Services, Inc. -----Original Message----- From: Tom Maunder [mailto:tom maunder@admin.state.ak.usl Sent: Wednesday, April 16, 200310:52 AM To: duane vaagen Cc: Steve Davies Subject: Lone Creek #3 Duane, I left a message for you, but wanted to send this email as well. I am reviewing the Lone Creek #3 application and have a couple of questions. 1of2 4/16/2003 3:48 PM RE: Lone Creek #3 . . 1--ls this well being reviewed in the "Coastal Zone" process?? I am not sure what other permitting requirements are out there or how they are now handled, but could you elaborate on what other permits are being sought. 2--How will the drilling waste be handled?? I am aware that Aurora has submitted a request to enter one of the Moquawkie wells with the potential to complete it as a class II well and Aurora has a disposal injection order for Nicolai Crk #5. Are there any plans to do the work on Nicolai Crk #5?? The AOGCC only has authority for annular disposal and class II injection. If other methods are being planned, permits for DEC and/or DNR and maybe others will be necessary. 3--What is the yield on the lead slurry for the 7" cement job?? 4--Could you or Aurora please provide a schedule of the coming planned work with approximate operation dates?? This will help us start to get our Inlet summer schedule set up. Thanks. Tom Maunder, PE AOGCC Name: Aurora Gas POD Well Schedule.doc [JAurora Gas POD Well Schedule.doc. Type: WINWORD File (application/msword) c Encoding: base64 2of2 4/16/20033:48 PM . !Æ~ . ~ cQ) FRANK H. MURKOWSKI, GOVERNOR ~'iA.SIiA OIL AND GAS CONSERVATION COMMISSION J. Edward Jones Vice President Aurora Gas, LLC 1029 West 3rd Ave. Ste. 220 Anchorage, AK 99501 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)27&7542 Re: Moquawkie, Mobil Moquawkie #1 Aurora Gas, LLC Permit No: 203-069 Surface Location: 2366'NFL, 1704' FEL, SI, TI1N, RI2W, SM Bottomhole Location: 2188' FNL, 1630' FEL, SI, RI2W, SM Dear Mr. Jones: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill 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. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). G~.. / '~'l ,DJL al 1\ Chair V BY ORDER OF THE COMMISSION DATED this.3L day of July, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section At total depth STATE OF ALASKA ALASI<a>IL AND GAS CONSERVATION CO'-ISSION ., PERMIT TO DRILL ., 20 AAC 25.005 [ ] Redrill 11 b. Type of well [ ] Service [X] Development Gas [ ] Single Zone [ ] Deepen [ ] Exploratory [ ] Stratigraphic Test [ ] Development Oil Aurora Gas LLC. 5. Datum Elevation (DF or KB) 10. Field and Pool 369.8' KB, 350' GL Moquawkie 6. Property Designation C-061390 7. Unit or Property Name Moquawkie 8. Well Number Mobil Moquawkie No.1 9. Approximate spud date 1-Jun-03 14. Number of acres in property 15. Proposed depth (MD and TVD) 2720 3000' MD & 2995' TVD 17. Anticipated pressure {see 20 MC 25.035 (e) (2)} Maximum wñaœ 968 psig, M total depth (\'VO) Setting Depth Specifications Top Bottom Grade Coupling Length MD TVD MD TVD h{ ..-r5"Z I lJ;, / 1 a. Type of work [] Drill [ X] Re-Entry 2. Name of Operator [ X] Multiple Zone 1029 W. Third Ave. Ste 220 Anchorage, Alaska 99501 4. Location of well at surface ~ ~L, 1704' FEL, S1, T11N, R12W, SM ~cr~ At top of productive interval @ 2735' MD, 2732' TVD 2295' FNL, 1630' FEL, S1, T11N, R12W, SM @ Original TO 10,900 2188' FNL, 1630' FEL, S1, T11N, R12W, SM 12. Distance to nearest property line 113. Distance to nearest well 1704' 1/2 mile 16. To be completed for deviated wells Kick Off Depth 18. Casing Program Size Casing Weight 3. Address 11. Type Bond (See 20 MC 25.025) Letter of Credit Number NZS 429815 Amount $200,000 Maximum Hole Angle 1283 psig Hole Quantity of Cement (include stage data) 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Plugged back to surface. Total depth: measured true vertical Effective depth: measured true vertical o feet o feet o feet o feet Plugs (measured) Cement: 0 - 60', 2660 - 2792',5105 - 5240' BP's: 7400', 7618', 776S', 8968', 9700',10283' Junk (measured) Casing Length Size Cemented MD TVD Structural Conductor Surface Intermediate Production Liner 26' 213' 2455' 10,350' 36" 20" 133/8" 9 S/8" Currogated Pipe 1000 sx 2002 sx 750 sx 213' 245S' 10,350' 213' 2453' RECEIVED APR 0 9 2003 Perforation depth: measured See attached diagram w/ well program true vertical Alaska Oil & Gas Cons. Commission Anchorage 20. Attachments [ X] Filing Fee [ X] Property Plat [ X] BOP Sketch [ ] Diverter Sketch [ X] Drilling Program [X] Drilling Fluid Program [ ] Time vs Depth Plot [ ] Refraction Analysis ( ] Seabed Report [ ] 20AAC2S.050 Req. Contact Engineer NameINumber: J. Edward Jones I (713)977 -S799 Prepared By NameINumber: Duane H. Vaagen/258-3446 21. I herelY ce' tha.t~oregOing is true d orrect to the best of my knowledge Signed 1/· // 411 ¡ k ~~-A Title V/Ú'rÞrTì df"/l! Date '/ Ô2/'03 Commission Use Only PermitNu be203-06? IAPI er 5'D-2.&3- /DD/9-96 Conditions of Approval: Samples Required: [ ] Yes 1XfN0 Hydrogen Sulfide Measures: { 1 Yes WNo Required Working Pressure for BOPE: [ ] 2M, [] 3M, [] SM, Other: ~CJc:.:~ ~s \ \3>~\? -\-CS-"r OrIginal Signed By Sarah Palin Apfrovj D~ I See cover letter /II ð J O? for other requirements Mud Log Required [ ] Yes D(No Directional Survey Req'd { 1 Yes ~o [ ] 10M, [] 15M Approved By Form 10-401 Rev. 12-01-85 Commissioner by order of the commission Date 7/31 Þ7 Submit In Triplicate Ot<ÎGlr~AL · e ¡ Mobil Moquawkie No.1 Re-Entry and Re-completion Back2round Information and Present Condition All depths herein are referenced to original RKB at 369.8' AMSL. Mobil Moquawkie NO.1 was spudded May 2, 1965 by Mobil Oil Corporation. A 36" currogated conductor was set at 29'. A 26" hole was then drilled and 213' of20", 94#, H-40 surface casing was run and cemented into place with 1000 sacks of cement. The intermediate hole section consisted of drilling a 17 W' hole and setting 13 3/8",61#, J-55 casing at 2455' and cementing into place with 2002 sacks of cement. A 12 114" hole was then drilled to TD at 11,364'. The BHA was lost, the fish was cemented over and a 95/8" 40 & 43.5#, N-80 and S-95 casing string was set at 10,350' and cemented into place with 750 sacks of cement. While drilling at 1525', the well blew out, the rig caught on fire, was extensively damaged and four personnel suffered bum injuries. The well was killed by bullheading heavy mud in at surface, the rig was repaired and the well was drilled to TD. With no market in the area, the gas was piped to the village of Tyonek for fuel to run the village generators. The well was produced in this manner until 1970, when production problems combined with little economic incentive to invest money into re-working the well provoked Mobil Oil Corporation to plug and abandon the well. Cement plugs were placed across the open production perforations, a cement plug was placed at surface and the wellhead was cut QfT, replaced with a P&A marker post. The Mobil Moquawkie No. 1 has minor directional tendencies. Due to the minor incremental change in hole attitude along the course length being considered for redevelopment, the well will be treated as a vertical hole for purposes of calculation. Site Access Access will be via the existing road system. The original access road and well site will be cleared of brush and utilized. Other then general maintenance, no new construction or disturbance is anticipated for the well work. Ril! Used for Proiect Aurora Well Service, Rig NO.1 (AWS #1) will be used. This is the same rig used last year for the Nicolai Creek well work. Configuration of pits, and solids equipment will be similar to last year. Working floor elevation ~ 14' AGL. .Mobil MÔQuawkie No.1 Re-entrv. Re-Completion Procedure In order to effectively re-enter and re-complete the Mobil Moquawkie No. 1 as a gas production well in accordance with AOGCC regulations, the following tasks must be completed: 1. Install cellar and new 3000 psi wellhead assembly. e 2. MI I RU AWS Rig No.1, install and test II" 3M BOPE. Test gas detection and PVT systems to ensure proper function. Prepare recycled 10 ppg mud system. 3. PU 8 1/2" bit, drill out cement plug at surface and clean wellbore to top of the cement plug at 2660'. Pressure test casing to 2000 psi. Remediate with squeeze procedures as required. 4. Drill out cement plug from 2660 - 2792' in the 95/8" casing with 8 1/2" mills or bits as required. Clean wellbore to 2900'. Perform flow check on well. 5. POOH, LD bit, PU 95/8" casing scraper, Rllf and clean casing to 2900'. Circulate out mud and replace with clean, filtered 9.5 ppg brine or other as dictated by conditions encountered.. 6. POOH, LD casing scraper, RU wireline BOP and lubricator, run cased hole logs (type to be determined). Analyze logs and prepare to perforate. 7. Perforate and test well as determined by wireline logs to ~ 2900'. 8. Run sand exclusion screen assembly spaced as needed across perforations. Hang assembly off permanent I retrievable gravel pack type packer. 9. Pull workstring, Run, space out and land 2 7/8" 6.5# J-55 production tubing. PU and circulate, displace tubing annulus with O2 inhibited brine, land tubing and lock in place. Install blanking plug in profile nipple, test tubing to 2000 psi. 10. ND BOP, NU production tree valve assembly, install BPV, pressure test tree to 3000 psi. Pull BPV, pull blanking plug. Attachment II illustrates proposed completion. 11. Swab in well, release rig. MOQuawkie No.1 Pressure Considerations The area has had considerable exploration activity for oil, however; information on the properties of the shallow gas sands is incomplete. Historic well records indicate the Mobil Moquawkie NO.1 was drilled with mud weights to 14.2 ppg at 2300' and 11 ppg mud at 2800'. A blowout occurred at 1525' and drilling mud weighted to 18+ ppg was used to kill the well by pumping in at the surface. After performing rig repairs, drilling resumed with 11.4 ppg, at which time gas broke out at surface again. A mud weight of 14.2 ppg was required to successfully drill the hole to 2465' before 13 3/8" casing could be run and cemented in place. The 14.2 ppg mud equates to a pressure gradient of .74 psi / ft, which is excessive. ~ .;.. e e J Prior to the plugging and abandonment of the Mobil Moquawkie No. 1 well, records indicate the well produced about 1 bcf of gas from the zones of interest. A DST in the offset well Simpco Moquawkie No.1, which was drilled in 1978 revealed a static BHP of 1283 psi at 2877'. This equates to a pore pressure gradient of .45 psi / ft which is equivalent to 8.65 ppg mud. Based on this information, it is believed that a kill weight brine of9.2 ppg should be sufficient for perforating and well kill fluid. Re-entry and work-over procedures on the Mobil Moquawkie NO.1 will require constant vigilance and monitoring of well conditions to maintain a safe work environment. Maximum Anticipated Surface Pressure The maximum anticipated surface pressure (MASP) for zones of interest behind the 9 5/8" casing, can be calculated by subtracting the gas gradient from the predicted pore pressure for the TVD depth at TD. Using a pore pressure gradient of.45 and a gas gradient of .11, the MASP can be calculated as follows: Gas Gradient ~ .11 Pore Pressure Gradient ~ .45 (conservative estimate) => Maximum anticipated Surface Pressure = Depth( tvd) x (pPG - GG) => 2900 x (.45 - .11) = 986 psi. For perforating, a filtered KCL brine weighted to 9.2+ ppg will be used. Prior to perforating procedures, wireline BOP's will be installed, tested and closed on the wireline and the lubricatQr will be pressurized Gauges will be tested to insure proper function. Perforating and testing will reveal actual pressures prevalent to the area and zones of interest, kill weight brine density will be adjusted accordingly. When perforating the 9 5/8" casing, caution needs to be exercised to control and monitor pressures should the PPG be higher. An 11" (3M) BOP system will be used, BOP tests will be performed to 3000 psi. Please see attached diagram of BOP system Drillin2 Fluid Properties: Recycled drilling muds will be used while drilling cement plugs inside 9 5/8" casing. These fluids will be augmented with gel and polymer as needed for high vis sweeps required to maintain hole cleaning capabilities. Muds will be weighted to 10 ppg to ensure that should trapped pressures be encountered, potential well control problems are minimized. Prior to perforating, the well will be swapped over to filtered brine, weighted to 9.2 ppg or other, as dictated by discoveries made during well re-entry. Drillim~ Fluid System: Shale Shaker, Desilter, Centrifuge, Ditch Magnets, PVT monitors p e Drillim! / Well Re-Entry Hazards: Abandoned well re-entries offer a number of challenges, among them the potential for junk in the hole, mechanical degradation of casing strings, and trapped pressures below plugs. Drilling in the South Central Region of Alaska offers challenges as well, the most notable being shallow gas hazard and stuck pipe in the numerous coal beds present. Work on the Mobil Moquawkie No. 1 will entail cased hole operations only so the stuck pipe hazard due to coals should hopefully be eliminated. The common known hazards are as follows: Shallow gas: Shallow gas is a known hazard which exists throughout the region. The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. The Mobil Moquawkie well was drilled in an area with an abnormally pressured shallow gas zone. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record ofH2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level, the shale shaker and in the cellar. When the Mobil Moquawkie No. 1 well was originally tested, a pore pressure gradient in excess of .58 psilft was discovered at the depth now being considered for re-completion. There is a potential that gas may be present in a pressurized state below the cement plugs placed in the wellbore during P&A procedures. It is anticipated that pressures which may be encountered in the Mobil Moquawkie No.1 will closely match those found in the Simpco Moquawkie No.1 well drilled in 1978. When the Mobil Moquawkie No. 1 was drilled, abnormally pressured shallow gas blew out the well causing extensive damage to the rig and injury to 4 crew members. DEW ARE! Junk in hole: It is not improbable that one could find discarded steel and other assorted junk which was thrown "down the hole" at abandonment time. Drillers need to be aware ofthis when drilling. If sudden torque and ROP changes occur, this may be the reason and the company man needs to be notified immediately. Collapsed I burst casing: Re-entering an old well is always an unknown. While not likely, the potential exists that casing damage has occurred, either through some type of corrosive action, some time of mechanical deficiency or possibly even because of seismic activity. At the least, this could cause a minor inconvenience and require cement squeeze procedures. At the worst, safety could be compromised should high pressure gas broach the surface through a leak. Here again, well conditions need to be monitored very carefully. e e ì 1 Mobil MOQuawkie No. 1 Summary of DrillinQ Hazards POST THIS NOTICE IN DOGHOUSE ~ There is potential for pressure below surface plug. ~ Possibility of junk in hole from original P&A procedure. ~ There is potential for pressure below cement plug from 2660' to 2792'. ~ Potential for unsound casing, either from corrosion, mechanical failure or seismically induced weakness. ~ There is a chance that higher than normal pore pressure gradient (>.45 psi I ft) may be encountered while perforating. Have sufficient kill fluid materials ready and standing by for well kill operations. ~ There is no H2S risk anticipated for this well. PLEASE SEE: MOBIL MOQUAWKIE No.1 WELL PLAN FOR ADDITIONAL INFORMATION I ;, J .' GI.. KBE 318" aiuiI.Ilws. 36'" Conductor 213" "101}0 SX 310' I I = ., at 602' 13 3/8" 360 SX hol~s at "1250' 60St 2660 - 2792' Perfs 2932' plug "13 3/8" 6"1# J~66 2456' CI\IITDW/"IiOO around shoe &610 SX through stage coliar ~t 602' Perforations 2736 - 2766' SX - Squeeze Perfs @ 2932' Hole Perfs 6260' Production Perforations 5300 - 5326' & 6346 . P~rfs @ 5428 Squee:.œd wf 200 SX= = Squee:.œ Perfs @ 5428' "100 squee:.œd wf'lOOn SX Perfs Perfs Perfs Perfs 7618' 100 Sk squee:.œd cmt Sql.le~:.œ packer @ 8968' Test Perfs 9080 - 9125' seal phJ:J 60 Halliburton DC Squee:.œ packer @ 10283 50 '" 9 Cmtd _. iii. Fish 10919 -11335' MD í. ç , ,I Mobil E&PSeNices. Rev DHV Draw Í!1g No! 26" Hole - GL 360' KBE 36~UI' He! M1' ISIP'" 1268, fHP 162& 5366 ¡SIP'" 2424, I"HP 3099 Hole 2.31" lei Profile Nipple 1 Jt !ilbove packer Production Perforations -2136 !ili'l1:! œ determined by logging. Sand Screen across perforations. Exact size and type be determined. 12 Perfs @ i428 Squeezed 200 SX = Perfs Perfs Perfs Pelfs Sit squeez:ed em'!: plug 100 sk squeezed SO sk em'!: squeeze fish 10919 -11336' TI) @ 11 ,364' Mobìl + ¡ + + + ¡ f + ¡ t + 1 +1 ¡ T SX SX I I- ~ ) 11S" J"'¡S - 1000 SX '1 Collar at 602' 13318" perfed i (112") holes at 1260' 350 SX squeeze pel'furmed Inhibited KCL Packer fll.lid above packer 13 61# J"'¡S 2455' CMT'D WI 1600 around shoe & 61 I) SX throl.lgh stage collar at 602' 2.13" id Profile ipple 1 Jt below packer Squeeze Perfs @ 2932' Sq~eeze Pelfs @ 6260' &0 "G" Balai'u::ed plug 5106·6240' = Sql.leeze Perfs 6428' @ 1400' 1S1S' - TestPerfs Hamb~i'ton OM Squeeze packer @ 8968' Test Perfs 90lG - 9125' DC Squeeze packer seal plug Halliburton DC Squeeze packer @ 10283 9 H-IO & S-!' @ 10360' Cmtd W 150 SX 27 -F&b-2003 Natto e e Aurora Well Service Rig No.1: Proposed 3M BOP Configuration for well re-entry, work-over and Drilling I"", ~ ) ~ System designed to work in reverse circulation mode, where returns taken up workstring and through power swivel to pits, during re-entry procedures. Grant rotating head to be replaced with standard flow nipple when OH drilling commences. ./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 c Pipe Rams sized ---, to work string. --.J 11" 3M Mud Cross C 3" 5M Manual Valve (Kill Line) ~ 3" 5M Hydraulic Valve ~.~ ~ (Kill Line) .....~ Fluid flow direction while reverse circulating ~ II 13 5/5' 3M dlIh Braden Head I Aurora Well Service #1 BOP System I Fairweather E&P Services, Inc. 11" 3M Döuble Gate w/ 3/12" pipe ~ rams installed. Blind Rams . /3" 5M Manual Valve (Choke Line) ~. ..----- 3" 5M Hydraulic Valve ~ (Choke Line) I 135/8" X 11" 3M Casing Spool 2" 3M Manual Valves On Wellhead ,; 133/8" Surface Casing Rev. 03 DHV 25-Feb-2003 Drawing Not to Scale e e Aurora Well Service Rig No. 1 Proposed Choke / Kill Manifold Configuration All valves are 3" rated at 5000 psi. Inlet from Power Swivel (Reverse Circulation Mode) ~ Output to Pits Hydraulic Remote Activated choke 2" 5M Rated Valves Inlet from BOP Choke Une 3" 5M Rated Valves Manual Choke - ß:O:IJ.. . ...1J:O:IJ:3:OtJ ---------+ .. .-- +.~ : .. Bleed Flare Line to Open Flare Pit 3" 5M Rated Valves - fIÃfI -~.." .1D I.tYtJ - ... m 2" 5M Rated Valves To Gas Buster "Atmospheric Degasser" r Aurora Well Service #1 Choke Manifold Fairweather E&P Services, Inc. Rev. 03 DHV 25-Feb-2003 Drawing Not to Scale . . I R 12, W I R I W r- --- - - - ï---- ---- I I '~?'i:\;,f:::\;:~:t::-:":.;'/f,;:-,~,'.' r,'~i..;' .'. ¡ 34 ! 35 J~li1~(*f~II'Î T I 2 N I ()pe·^J·'f/iif¡t:.;;.:"iJ.iÎ~Îi;;""'é.: - T-I ;- ~ - - r- - - -.¥L!,l?;k7£~.,~;~;·;.."n' ..,.. ".,';'\' I "".b, I . ..::; :,.' . I ~J¡D~t;~~N."'... ~1704.0"'. I 3 2 ...... 6 . I 'MOQU'AWKIE 1..0. I . ." I (P~OP.08JO' LOCATION)'M~~;' I I t!J,>e N ;,.~~¡ia1~':f~;~~: ~ :~.'\~~I¡j'¡"'O,vlI·C :- - - - - - - - "1' - - - - - - - - I"AT".','610.04' 25.68""..,. .' I I ,"óNG .I"~ ì 9."'()7.75 ':t:,t, "..' '.:. '~." : .10 i II ':,::,~{¡f~J¡; ~:J:,i',j¡1 a I I ·.·M,,'" h::;-...:·,,··· ~:l~.'.~·k:;)-.:~ I I (....j .' '. '1/.,,<:.; :,;:.'......¡.:.; .rtr~>·)..~.·;··,g '.;~¡ ¡¡'.".",Jø/c. D I {J,,,- ¡v I 11'¡ID'N-" c . ~,:~. ~; '/ell''2'e; ..~ '.:;.';', <: L-______ _1-_______ 11III ' -------- (ï; I I I I I I 0 I I Z I » Q I 15 14 I 13 18 17 Z : : I . ô~ Ilt~m L-_____ _~_~êe~___~_~~~~__~__~~e~__ --,"'r-:C~ ~~.: J of- --- "Z R 12 W I R I ~.Ý ~ fE: SEW A ROM E R 101 AN, A LA S K A u> SCALE I" = I MILE "- 32 )lq..,¡'/~ N T 12 N --- T II N " 5 , II " iii We. ')~ -0 ;;:0 ;.tJ rï1 (1 ï1î T>') ('~,~.. --- ()l < n' CJ c(.:; (}~¡ (",;~}Ftt·l·~~"'~[ c;. 4 ~'i;.~'~' (::1":' ;';/[l./'·j >~,".,' ?OIl .T hereby 'è:e.r-::,',,;I Lh~l.t J '},'i¡ .',~o;~el'l.LI ¡·('![J'Î.3t<2l'ecl C'.!1c1 ~iCCllD'.:'_.' tr'" G¿i~,,; ì'UL' ::Zft't1:.'Ui.'1[' 'in the: (·tc:tè of id.cu;j¡,~ ;.:n··;"t thi..~ ..,I.~lt !'Opl"é'¿:cn.t:: .'] ~()c.'1ii.on ¿~tlrvt?'J n~{l(!e /)!./ rc':C or f.-,J~.~:~~~(· /,:1./ DU}:);":l"oi.::iort, C~l1cl tb.:,-~t all c!imcnDion:. ',r:..1 o;hc;:lctaU;; a.rC'! COI'rect. /1¡:'/'kt!t /jJp[ ¿--1f:otfP7 !~Ut?~J'~'YO.:?,-; i¡O~!r;': / ?. r-~:;J~~'~ ,~t(l t e ¡lene CoorJin~tes ~ .....,"') lei t.. :. r~ Z·~.ì F: ~: LOCATION SURVEY OF MOBIL OIL MOQUAWKIE NO. I SURVEYED FOR MOBIL OIL COMPANY BO X 1734 ANCHORAGE, ALASKA SURVEYED BY F.M. LINDSEY a ASSOC. SUR V E YO R S. a C I V I LEN GIN EE R S 1415 W. NORTHERN LIGHTS BLVD. ANCHORAGE, ALASKA T'hc locc:tioll. of Ao..'UC.;::L .¡,c/. _ :x::; cc()mtli,:;hcrl using U.3. D.L.I.. HOJ;Lu.\ nt: DC C:~.3, :J.!1c' the 1!tOJ"!.tlJi1(?n t C OJ,ï.r.: on t () U . .:~'. ,'~'/tü~'~t,) (~U ..~ "~' é 5 .t~:...1 ,:. " 1 boun-:l:u'U ~inc COT."..mon to TÜ("l1:Jhi,:J:' '~.: Ne:-::\ ~:r:é: 12 !lOt'th. ) ) :·,;;,::,~"·,:·;,:·",·,,·,··,,.II'u'~"a Gas I.I.C ~1I1 ...,.. , www.aurorapower.com March 31, 2003 Oil and Gas Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: Mobil Moquawkie No.1 RECEIVED APR 0 9 2003 Alaska Oil & Gas Cons. Commi$Sion Anchorage Dear Commissioner( s), Aurora Gas, LLC hereby applies for a Permit to Drill, a prerequisite for re-entering and recompleting the abandoned well, Mobil Moquawkie No.1. It is Aurora's intent to re- enter, log, test and re-complete Mobil Moquawkie No. 1 as a natural gas production well. Mobil Moquawkie No. 1 was drilled by Mobil Oil Corporation in 1965 in se'arch of oil. While no commercial quantities of oil were found, natural gas in producible quantities was discovered. The well was completed as a gas producer with production allocated to the power generation facility for the village of Tyonek. Due to production problems encountered at the time, economics and an alternate source for gas, the well was abandoned in 1970. Mobil Moquawkie No.1 is in an area known as the Moquawkie Gas Field. The well is located onshore approximately 5 miles northwest of the village of Tyonek. Aurora plans to begin well re-entry and re-completion operations on June 1, 2003. The site is readily accessible via road so no new roads are required. Upon receipt of all necessary permits and approvals, contractors will clear the location of overgrowth and repair the surface. A new wellhead will be installed and the rig, Aurora Well Service No. 1, will be rigged up over the well to commence well operations. Pertinent information in and attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill- 3 copies 2) Fee of$100.00 payable to the State of Alaska 3) A plat map and information detailing the surface location and proposed bottomhole location 20 AAC 25.050 (c)(2) 4) Diagrams and description of the BOP equipment to be used as required by 20 AAC 25.035 (a)(1) and (b) 5) The drilling fluid program, in addition to the requirements of 20 AAC 25.033 is attached 6) A copy of the well history, proposed re-entry, re-completion procedure and operational considerations is attached 10333 Richmond Avenue, Suite 710 · Houston, Texas 77042 · (713) 977-5799 · Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220· Anc't1~ f/~t ~At.~907) 277-1003· Fax (907) 277-1006 ) Commissioner( s) Page 2 7) 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. 8) A Summary of Potential Well Hazards. 9) Pressure Information 10) The following are Aurora Gas, LLC's designated contacts for reporting responsibilities to the Commission. · Completion Report (20 AAC 25.070) Duane Vaagen, Project Engineer (907) 258-3446 · Geologic Data and Information (20 AAC 25.071) Andy Clifford, President (713) 977-5799 · 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, r-~ . Edward Jones Vice President, Operations and Engineering AURORA GAS, LLC cc: Duane Vaagen Andy Clifford RECEIVED APR 0 9 2003 Attachments Alaska Oil & Gas Cons. Commission Anchorage U ¡.-< I G t j i~ t-\ L 10865 FÅtRWê1MJi~ ~XÞ[tm'A"ðN 1(1 PRODUCTION SERVICES INC. I GENERAL ACCOUNT COMMENT PAY TO THE ORDER OF COMMENT . VENDOR I.D. .I.Uq::¡ ') PAYMENT NUMBER UUUUtHb4 CHECK DATE 4/':J/,¿UU:' ) NAME ::f!'A'n¡ Vi" ALA::;M AVl:i\",;\",; OUR VOUCHER NUMBER UUUU.H2 YOUR VOUCHER NUMBER DATE 104~0~0409*MM#1 4/9/2003 AMOUNT :;>100.00 AMOUNT PAID :;>100.00 DISCOUNT WRITE-OFF :;>0.00 :;>0.00 $100.00 $100.00 $0.00 $0.00 FAIRWEA THER EXPLORATION & PRODUCTION SERVICES INC. GENERAL ACCOUNT P.O. BOX 103296 ANCHORAGE, AK 99510-3296 PH. (907) 258..3446 FIRST NATIONAL BANK OF ANCHORAGE ANCHORAGE, AK 99501 89-6/1252 - 1 DATE 4/9/2003 One Hundred Dollars And 00 Cents STATE OF ALASKA AOGCC 333 WEST 7TH AVE SUITE 100 p ANCHORAGE AI< 99501 """.,-,,.,.," ""."-.._""._",..".,~.,,.,..,,..'." "'.."".,...."".....",,...,~ AUTHORIZED SIGNATURE 1110 ~oa b Sill I: ~ 2 5 2000 b 0 I: 0 ~ ~ 2 8 2:1 0 III F',tMWËÂmEFi ~xpfóWÅíTðN lrPRODUCTION SERVICES INC. I GENERAL ACCOUNT 10865 VENDOR I.D. 1049 PAYMENT NUMBER 00008864 CHECK DATE 4/9/2003 NAME STATE OF ALASKA AOGCC OUR VOUCHER NUMBER 00013342 YOUR VOUCHER NUMBER DATE 1049030409*MM#1 4/9/2003 AMOUNT $100.00 AMOUNT PAID DISCOUNT WRITE-OFF $100.00 $0.00 $0.00 RECEIVED APR 0 9 Z003 Alaska Oil & Gas Cons. Commission Anchorage $100.00 $100.00 $0.00 $0.00 10865 NET ~100.00 $100.00 . .. . - "" - -" -" ,." - - - - - - - ~ ~ -. - -- 10865 AMOUNT $100.00 ."....-...~ 10865 NET $100.00 $100.00 51N321 ' 4 ) TRANSMITAL LETTER CHECKLIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMtTTAL LETTER WELL NAME PTD# CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) "CLUE" The permit is for a new well bore segment of existing well Permit No, API No. Production should continue to· be reported as a function· of the original API number stated above. HOLE In accordance with 20 AAC 25.005(t), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). paOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a . conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. WELL PERMIT CHECKLIST Company AURQ8A GAS LLC Well Name: MOQUAWKIE 1 . Program QEY Well bore seg PTD#: 2030690 Field & Pool..M.O_Q.!JÆ\\.I\I.KtE,.UNQEEINEO..:52.85.QO_.... Initial ClassfType ._..PE\lLt:ß8.S._.. GeoArea 82.0 Unit On/Off Shore .0..0_ Annular Dìsposal i' Administration :1 Permit fee attached Yes :2 Lease number .appropriate yes 3 .U.ntq!J~ w~lI. n.arn~ _and OLl.mb.er . . . . . . _ . _ _ _ _ . _ _ . . . . . . . . . . . . _ . . _ . . . . . . . .Y~$ . . . . . . . R~-el1try .of ~xjstiog, wellc . - . . . . . . . . - . - - - . - - - . . . . . . - . - - - - . . . . . . . . . . . . - . . - . . . . . . A Welllocat~d ìn.a. define.d -pool No Undefined poo!.gas. . . :5 Well .!ocat~d proper dtstance from drìlling unit b.oundary Yes Moquawkìe 1 is.250o.' awayfrom, and. in same section .as,. SimpcoMoquawkie2, a shut-ìngas well capable of 16 Wellloc~t~d prpper .di.stance. from. other wells Yes. . produ.ction. Moquawki~1 rec.ompl~tionwill be2800' shallower th.a[1 perfs. ilJ Simpco Moquawkìe 1.. A spa.cing :7 .S.ufficìentacreag,e.ayailable i.n.drilJiOg unit Yes. ex.ceptiolJ is .notrequjred as.longa. re-.completiolJ oprations are restricted to. < 30.00' MD and.TVD. '8 Ifdeviated,is well bore plat ìnclu.ded NA . Existing well; app~ars to. be v~r:tical through re:comptetìon ilJterval (weJlis. ilJclìned2.75d.eg at 7675' MD). ,9 o..perator only affected party Yes. . . 110 .Qper.ator b&s.apprppriate_b.ond i.n.forçe. . . . . . _ _ _ . _ . . _ . . . _ . _ . . _ . . _ . . . . _ . . . Y~$ _ _ . _ _ . .I,.e.tter_of .cre.dì.t. - - - - . . . . - - . . - . . . . - . . . . . . . . . . - . - . . - - - . - . . . . . . - - . . - . . . . . . . . . 111 Pe(mit c.an be tssLl.ed without conserva.tion order. . . Yes Appr Date '12 p~(rllìtcalJ be i.ssLl.ed without administ(ati\,le.apprpvaJ . . . Y~s . SFD 7/16/2003 13 Can permit be approved before 15-day wait Yes 14 WelUocated wi.thìn area and.strata authorized by.llJjectìOIJ Order # (putlO# in comments) (For. NA. . . . . . . . . . ( 15 AJlweJs-'Nithin.1l4_l1Jite_are.a.of(eyiewjd~otified(Fp(servjc.ewellol1l~).. _.... _. _... _. NA. - - - - _. _... -.. - - - - - - -. -... -. -. - -. -. -. - -. -. -.. -..... - -. -.. - -. - -. - - - - - - -...... 16 Pre.-produ.ced injector: .dur.ationof pr~:pro.ductiolJ I~ss. than 3 mOl1ths. (For.servì.ce well onJy) NA. . . . . 17 A.GMP Finding.of CQn.sIstency. h.as been .issued. for. tbìs project. . NA.. 6/06/03. e.majl from .Glenn .Grayto Tom Maul1d~c .an .ACMP. re\,liew is not.need.eçl for thjs. we.!!.. . . . Engineering Appr Date TEM 4/21/2003 ~._.~.,.,- .--. --.-- -- . Geology Appr SFD Date 4/17/2003 Geologic Commissìoner: I}\r ,--- ----.. --~-,..-,._- ,-._,-----,~_...._-,.._----------_.-,.---~ ----------.----- ---".-.-----.-.---------------.---,-,-,-.-.-.-----------.-- --~---~----.----'" .---,---.-,.---- -_._..__.~.--,---_..._._--------,----_.._._._----'"-- 18 Conqu.ctor strìng.providßd . . Y~s ..... Set when Qrigi.nal.weJl d(ì!led.. 19 .S.ur:fac~.casing.pJQtec.ts all.known USOWs .. eYes. . . . . . .20." @ 2t3~ and.13-.318~' @ 24.55'.. . . 20 .CMT. v.ol. adequ.ate. to çirc.u tate. on .cçmd.uçtor & surf.csg . Y~s . 21 CMT. v.ol. ad~qu.ate.to tie-in Jong .string to.surf csg. . . No. . . . . . . . . 22 .CMT wiU çoyer.a!1 KIJO,wn.pro.duçtiye borì:zon.s.. . . .Yes. . . . . . . . . . . . . . . . . . . . . 23 C.asing designs adequate f.or C, I, ß.&. p.erroafr.ost. . Y~s . . . . . . . . . . . . . 24 A.dequat~.tan.kage.or reserye pit. . . . . . . . . . Y~$ . . Rig .has steeJ pits.. Npresßrve pit planned.. Any.driJìlJg waste.to Erwiro-Tßch. for.d.isposaJ.. . 25 .If.a. re-drill, bé!s. a. 10::-403 forab&ndonment beelJ approvßd . . . . . . . . . . . NA . - . . . 26 _A.dequate.w.eUbore. separç¡tjo.n .proposep _ . _ " _ _ _ _ _ _ . . _ . . _ . . . _ . _ . . " _ . . _ _ . . . .Y~$ _ _ _ _ . _ " _ " . . . . _ " _ _ _ _ . " _ _ _ " . . _ _ . _ _ . _ _ _ _ . . " . - - " . - . . - - . - " - " . - - . . - - - . - . - - . . - . " . c 27 .Itdiv~r:terreq.uìre.d, does itJY1e~t reguJatiOl1s" . . NA . . .. . . " . . - " . . - - - - . - . . . . . . . . 28 DrHliOg f.lujd" prQgram $c.hematic.& eq.uìp Jistadequat~. . . . Yes ... ..... Max.imuro formatioo press.ure. e.stimated at8.65 ppg. Plan .to cleanout witb 1 Q.O ppg, 29BQPEs,.do .they me~1. regula.tiol1 y~s 30BQPEpre.s$ ra.tiog approp(ié!te; .test t.o .(put psìg incol11rnelJts). . " yes 31 C"hoke. manifold cQmpJies. w/APL R~-53 (May 84). .. . . . . . . . . . . Y~$ - . . 32 Work wi!1 occ"u( withoutopera1.ion .shutdown. Yes 33 Is presence. of H2S gas prQP.able . .. No. . . . - 34 Mecba.nical.cOlJd.ition .of. weJI$ withìl1 AOß, YeriJied (For. ser\,ice welJ On.ly,) .. NA . - " . . . . . - - - - - - . ~ - - - - - - - - ~ - - ( . MA$P estim.ated .at 94.6.psi. On.pre.vì.ous we.lIs,.AuroJé! tested 1.0.3000. psi.. . . . . - - - - - - - - - . .. w _ ~ _ ~ _ _ . - ~ - - - .. .~, ,.__., ,__.. ~_."___...__.._".._._..__"..~....___.m_______._._____._...._.___._. _....._,____..._..m_..__ n__ .._...~..__.. ..._"",_,._ .~ -.-----..-,,----.-"'-.--.--. - -, -,_.-,-,-,--_."". ..--..--------,---..-,..--.--,----..----.-----,.-,-,---..._-"-----~,-,._-----~.._-~_..-._.,,---_.- _.,-~- -----,..-.,-.-.,-..-...,.-.--.-.-.-,.,-----,-...-----.-.._-~--_._.._-,.,_._--_..,_.-._.._.--- ._-_.--~._'.._---- ._ __".._ __ ._...__..._ ...__...____.__,__.___ _._ ___,..._ _._,_____~..h._.._.___ 35 peon it.. c.alJ be issLl.eçl w/o. hyç:(ogen. s.ulfide rneaSJj(es . 36 D"ata.preselJted Qn. potentié!lovemressure .zones. . 37 S~i.smicanalys.is of .shallow gas.zooes 38 .SeªbedcOl1d,itipo survey {if off-shore) 39 . Gonta.cl namelphQne.for"weßk.ly progress. reports [exploratory .only] . . . . Yes .. No (eçQrd ofH2.S.ilJ (egipo.. . . y~s ...... Caution: pay zone pr~ss,U(e.gr&d¡ent r:naY.b.e.up.tQ 0.5a psj/ft."W~II..b.l~wout at.1!525' MD.&.ca!Jgh.t fir~.(beJo..w). NA . . . . . . . Suromé!ry of.QrillìlJg Haz:a(d.s .alJd re:e.ntry plan addreS$ PQten.tialhazard.s.and mitigati.on m~a$ures, NA.. . " . . . . . . . .. . " . . . NA. .. - - - - - -~ - - - Date: Engineering Commìssioner: Public Þ-- Commissìoner~ Date ~~ /::9 Caution: potential shallow gas hazard. This well blew out at 1525' MD, caught fire, heavily damaged the rig, and injured 4. The potential shallow gas hazard, expected pressure gradient, and mìtigation measures are discussed on pages 2 to 4 of re- entry program. A Summary of Drilling Hazards to be posted on the rig is presented on page 5. Administrative approval of this permit was delayed by lack of Ownershìp and Operator designatìon forms. Operator notified of deficiency on 4/21/03. ProDer forms were received bv Commission on 7/11103. Date 7/) 7 /0