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205-080
Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov 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 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 DSR-3/25/2020 -00 Moquawkie Und Gas Pool SFD 3/25/2020 xG MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg ��`� lzJ,,(d, DATE: 10/24/19 P. I. Supervisor FROM: Lou Laubenstein SUBJECT: Surface Abandonment Petroleum Inspector Moquawkie #3 Plugging Inlet LLC PTD 2050800; §undry 318-337 10/8/19: 1 arrived on location for the surface abandonment inspection on Moquawkie #3. 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. I departed location and communicated the deficiencies to AOGCC Inspection Supervisor Jim Regg. 10/24/19: 1 arrived on location for a second of the well. The casing had been cut to the satisfying the current regulation. Informatic installed. Attachments: Photos (3) inspection to check for proper cut-off depth equired 3 feet below natural grade i on the marker plate was verified and 2019-1024_Surface_Abandon_Moquawkie-3_11. docx Pagel of 3 20� -arc 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 (Guy.schwartz@alaska aov). 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 sllckline 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: 10 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 2057'. 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:guy.schwartz@alaska.gov Sent: Monday, March 04, 2019 1:30 PM To: Ed Jones <jejones@aurorapower com> 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 gov). STATE OF ALASKA RECEIVED ALOIkA OIL AD GAS CONSERVATION CO WION REPORT OF SUNDRY WELL. OPERATIONS _IAN 2 3 2018 1.Operations Abandon Li Ping perforations Li Fracture Stere Li Pull Tubing LIL I 1 Performed: Suspend [ Perforate 0 Other Simulate 0 Atter Casing 0 Change Approved;Program 0 Plug for Redrtti 0 Perforate New Pool 0 Repair Well 0 Re-enter Susp Well 0 Temporary Plug U 2.Operator Aurora Gas,LLC '4.Welt Class Before Work: 5.Permit to DrillNrunber Name: Development 0 wry 0 205-080 3.Address: 3705 Arctic Blvd.#2114 Anchorage,AK 99503 Stratigraphic 0 Service ra 6.API Number 283-20111-00 7.Property Designation(Lease Number): 8.Well Name and Number: C-061390 Moquawkie#3 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: TotatD3epth miasiired2560 feet Plugs measured 1318/1-25T2 feet true vertical 2560 feet Junk measured None feet Effective Depth measured 2512 feet Packer measured 1345-1709 feet true-vertical 2512 feet true vertical 1345-1709 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80 13 718 72#P140 80 80 -9430 psi 5300 psi Surface 657 85/8 32#i J55 657 657 3930 psi 2530 psi Intermediate Production 2560 51/217#J55 2650 2650 5320 psi 4910 psi Liner Perforation depth Measured depth 1402-2477 feet True.V$ttica€_depth 1402 X477 feet Tubing(size,grade,measured and true vertical depth) 2 7/8 6.5#J55 3058 3.058. Packers and SSSV(type,measured arid true vertical pth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): S ME 6 :Ll NA Treatment descriptions including volumes used and final pressure: NA 13. Representative Daily Average Production or Injection Data , OilrBblk s Gas-Mcf ; Water=ebiw sCasing Pressure Tubing-Pressure' Prior to well operation: 0 0 560 Subsequent to operation: 0 0 0 14.Attachments(required per zo AAC 25.070,25.071,&25283) 15.Well Class after work: Daily Report of Well Operations Q' Exploratory 0 Development 2 Service 0 Stratigraphic E Copies of Logs and Surveys Run 0 16,Web Status after work: Oil 0 Gas 0 WDSPL 0 Printed and Electronic Fracture Stimulation Data El GSTOR 0 WINJ E WAG 0 GIN 0 3USP 0 SPLUG C] 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Num or N/A if C.O.Exempt 317-274 Authorized Name: George Pollock Contact Name: Authorized Title: Ma r-Prod Ops&Eng Contact Email: opollock()a,aurorapower,c( „,...- ...--- Authorized 'Authorized Signature: a / Darr 1/23/2018 Contact Phone: 907.351.8286 �6 /'form 10-404 Revised 4/2017 RB D M V1,N ? 4 Z13U18 Submit Original Onlyl•Q1� • • Aurora Gas,LLC Operations Summary—Set Temporary Plug Moquawkie#3 Well july20,2017 1000 hours R/IJ WL,PT lubricator w/wellbore 1030 hours RIH w/2.33" gauge ring to 1318'KB, tag profile in WXA sleeve, POOH 1100 hours RIHw/2418"X-Line w/ PX Plug to 1318','WT, POOH,plug not-set 1145 hours RIH w/same,WT,set plug,POOH,,set 1230 hours RIH w/2" SB w/Prong to 1318',set Prong,POOH,set 1300 hours Bleed off well, fluid to surface, shut in well 1315 RIH w/2.-12"gauge_ring to-1318',tap down on eProng, POOH 1345 hours Bleed off well,monitor pressure, Fails test 1400 hours RIH w/2.12"gauge ring to 1318',tap down on Prong, POOH 1445 hours RIH w/2"JDC to 1318',WT, POOH, OOH w/Prong 1515 ehours eRIHw/2-7/8" GS to 1318',slingshot up hole,POOkl,wire kinked 1600 hours RIH w/2.4"brush to 1070',set down,WT,fall to 1318',brush profile,POOH 1630 hours RIH w/2-7/8"X-Line w/PX Plug to 1000', could not pass,POOH 1700 hours RIH w/2.4" brush to 1318',brush tubing, POOH 1730 hours RIB w/2.33"gtutge ring,to 1318',tag:profile„in WITA sleeve,-POOH 1800 hours RIH w/2-7/8"X-Line'w/PX Plug to 950',WI",fall to 1050',WT,fall to 1318', WT,set plug,POOH 1845 hours RIH w/2" SB w/ Prong to 1318',WT, set Prong, POOH 1900 hours Bleed offwell, monitor pressure overnight,Mob to camp • . Aurora Gas, LLC 2 7/8"6.5# 8 Rd.1-55 Tubing to 3058' Moquawkie No. 3 As-Built 117/8 7L8# LLS Conductor June 2005 driven to refusal at 80 ft Updated July 2017 d . Drill 10 5/8"}tole 2 7/8"X 5 Yz"annulus displaced 8 5/8"32# Surface Casing set at 657' w/'02 inhibited brine from Cement w/50 bbls 14.5 ppg cmt wt good surface to top of packer. ' returns at surface x 1 :`r, XA Sliding Sleeve installed I joint above �I' pa w/2.313"X-Profile for landing plug— "LOSED PX Plug @ 1318" --r \ 5V2 HRP hydraulic packer at 1345' Prod Perfs: 1402-1407' XA Sliding Sleeve w/231"X profile at 1412-1422' �„ 1452'(Closed) 1442-1447' it um 1459-1469' S'lz"Arrowset IXpacker at 1709'w!On-Off BELUGA(Tsuga 2-8.11 ---..� _� Coop and 2.313"landing profile '$"`te4. a 3-1/2"StrataPack Screens Prod Perfs: 17741789' at 2027-67',2416-2425', & 1804-1824' --+ "y 2443-2474' CARYA 2-1.2 =< . r... Punched holes in tbg at 1932-34' Prod Perfs: 2039-2069' and shot holes at 1919.5-21.5' CARYA 2-2.2 ..., Tag fill at 1900'--4/17/15 AW Prod Perfs: 2414-2419' 2445-2455' ►Mie 2467-2477' ' i CARYA 2-3.3 1 Drilled 7 5/8"Hole to TI)id 2560' 5 4"17#LTC 3-55 Casing to 2560' and cemented in place from TI)to •I surface w/21.1 bbls 13.5 ppg Gas- PBTD est.at—2520' . • block"G"lead and 76 bbls 15.8 . ppg"G"tail • • ti®g y 4, • ,, THE STATE Alaska Oil and Gas 4 ofLCommission AsKA 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 QF -41712*". Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager SCANNED SEP 1 1 m-7 i- Aurora Gas, LLC 1400 W Benson Blvd., Suite 410 Anchorage, AK 99510 Re: Moquawkie Field, Undefined Gas Pool, Moquawkie 3 Permit to Drill Number: 205-080 Sundry Number: 317-410 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, Cat P. Foerster Commissioner DATED this to day of September, 2017. RBDNIS u-- SEP - 7 2017 . III • RECEIVED STATE OF ALASKA AUG 2 7017 ALASKA OIL AND GAS CONSERVATION COMMISSION 0-34‘,,1 I 7 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.28C AOG, u 1 Type of Request: Abandon ', Plug Perforations .., Fracture Stimulate 7: Reua r he' '--- Cr.;eraticns st utdowr,— ! Suspend ' Perforate 77 Other Stimulate r----_ Puti-...,-:,.-.:i "Lna,ce:1/4,:.Q. -e,..::Program ___ Plug for Redrill Li erforate New Pool ::_, Re-enter Susp Well Atte(Cas ; ., D7e-7. -e-71;:rar..Prug 2.Operator Name 4 Current Wet aass. 15 Pe7,-z7.-.1::D l-iL.71-.:e7 Aurora Gas.LLC Exploratory Development - • . ... --- .- 3 Address: 1400 W.Benson Blvd Suite 410 7- 6 Z.,.P Numo.ei- ,Strabgraphtc ___ Service Anchorage.AK 99503 I I 'f....-2-1'57.7-2--7.-''-2( • 7 If perforating. 18 :.e,`..ame art' me What Regulation or Conservation Order governs well sparing'ii this ixol, /04- I Moawkie#3 • Wilt planned perforations require a spacing exception? Yes ' No Z ?pa 1 9. Property Designation(Lease Number): i 10 Fieid/Poolis): C-061390 - 1 Moquawkie Unoefined Gas " 11 PRESENT WELL CONDITION StAMMARY Total Depth MD(ft) Total Depth TVD(R): Effective Depth MD. lEffective Depth TVD: 1MPSP ipso: ---1Pr..gs. VD: Lunn,!v'D-. 2560' - 2560' \ . 2512' • , 2512' 590 psi 25'2 None Casing Length Size MD I TVD Burst Collapse Structural 1 5350 ps,E.,4 .i Conductor 80' ' 13 7/872*P110 80' 80' 3C;.7.5 1 , Surface 657 8 5/8"32*J55 657' 55T 3930 ps, 2530 Ds! intermediate Production 2560' 51/2'17*J55 256(Y 1 2560' 532::Ps- 4910 os: I -.1 Liner i I Perforation Depth MD(fty Perforation Depth TVD(ft).. !Tubing Size. !Tubing Grade_ -7-ut!ng MD ifti 1402 -2477' . 1402'-2477' I 2 7 fr 1 6 3 _55 : 3058' t / I Packers and SSSV Type: Packers and SSSV MD(ft)and TVC HRP and Arrowset IX packers HRP @ 73:15'and Arrowset 12.Attachments: Proposal Summary 7 Wellbore schematic 7 13 Well Class after proposed work- Detailed Operations Program 2, BOP Sketo-i i ; Exploratory Strabgrapr'c __ Deer-Jo-nen: ;.;. ' 5e,pce 14.Estimated Date for TBD 15 Well Status after proposed work Commencing Operations. OIL ---- WIN,: .`1 't.''''SPt :----. 5.:soenoec 16.Verbal Approval. Date 1GAS ----- WAG G.S 7 0 R '... , SP L'...G CommissIon Representative. I GIN,2 CO SnLIC - 7_—_, Apar:dor ec 7 _.. 17. I hereby certify that the foregoing is true and the procedure approved herein wit riot be deviated from without prior written approval, George Pollock Contact Name Gecrge PC1F;17-K:', Authorized Name Authorized Title: Manager-Prod (14. lirr'! Contact F 1)3" , ' -, - •- - Contact Po-re K7-35"-828€ Authorized Signature: .. Date, 24-Aug-',7 ..- COMMISSION USE ONLY Conditions of approval, Notify Commission so that a representative may wtness Sr:" N'...rroer 3 t 7 111 0 Plug Integrity X 30P-rev __ Mechanicat Integrity Test ! Location Clearance X Other; * p --0,- Doc_„:,,i.4eva-c. 0,....".,ct 0 C.- LOX 0 FF ..i.. N.J\A.R.'Leg- PLM Post Initiat injectlon MiT Req'd? Yes -1_ No 7 RBDIVIS L— SEP - 7 2017 Spacing Exception Required' Yes Li No rif Suosequent Form Required- \0_ 40-7 APPRCVED BY Approved by. COMMISSIONER THE COMMISSION Date f....6 ..../7 N3 C444AtAlTit 14,11 I 11 Form and Form 10-403 Revised 412017 id for 12 months from the date of approval. ° . 4— " v Submrt Acnrrents,n aix,hcate • • AURORA GAS, LLC WELL ABANDONMENT MOQUAWKIE #3 August 2017 Version 2.1 0/24117) CURRENT COM:ATO YS: ( A.b rc"i F"`"' Max SITP-460 psi. ✓ KB=14.5 feet CASING: 5-1/2", 17# J-55 set at 2560'MD/TVD. PBTD=2520' TUBING: 2-7/8", 6.5# J-55 8 rd EUE,w/ 10.2 ppg NaBr-KC1 brine as packer fluid in tbg-csg annulus above top packer and with: Sliding Sleeves at: XA at 1311' (closed—opens upward—closed with.PX pig set in profile); XA at 1452' (now open); and 2.31"X nipple at 1707' (w!plug). Packers: HRP at 1345' and with Arrowset IX at 1709'with,OnrOff tool at 1707' with PX plug set in profile (Feb. 2016) 3-1/2" Screens at: 2027-67', 2416-25', and 2443-2474' w/bull plug at 2475'. Tubing perforated below deepest packer at 1932-34' and 1919.5-21.5' Last known sand fill at 1900'. (See attached well bore and completion diagrams) CAPACITIES: 2-7/8"$.5# Tubing: 0:00579 bbl/ft; Tubing-Casing Annulus: 0.0152 BPF; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to Bull Plug below bottom packer=14.3 bbl,to PX plug at 1707'=9.9 bbl. Annular Volume to top Packer=20.4 bbl PERFS:Beluga(Tsuga 2-8.1): 1403-07, 1412-22', 1442-47', 1459-69' behind sleeve at 1452' U. Tyonek(Carya 2-L2)at 1774-S9' aid-1g04=24' U. Tyonek(Carya 2-2.2)at 2039-2069' U. Tyonek (Carya 2-3.3) at 2414-19', 2445-55', 2467-77' NOTES: 1) Well is a straight hole. SUMMARY Of.PLAN: RU slzckilne. RIFT and pull prong and plug at 1311'. Open sleeve at 1311' and dump 10.2 ppg NaBr-KCl brine into tubing to kill well add additional clean produced water(or 3%KCl)to tubing and annulus to fill if needed to kill(not likely). Run gauge ring on slick line and tag fluid level and bottom—expected to be PX plug at 1707'. Retrieve PX•prong and plug at 1707' and confirm well is dead. Fill tubing. Reset PX plug at 1707' Close both sliding sleeves. Fill tubing and casing with clean field produced water or 3%KC1 water. Test PX plug and tubing to 1500 psi. Run CIBP and set in tubing at 1390'. Run tubing perforating gun or Kinley punch, tag CIBP at 1390',pull weight up to 1380' and perforate tubing with 4 SPF. RIH and perforate tubing at 1340'. RU cementers on tree (thru wing valve). Establish circulation pressure with 5-10 bbl-KCl-water at 3 BPM. Pump 170 sx (195 cf 35 bbl)Class G cement(I5.8 ppg, 1.15 cf/sk yield) with pump time of 4 hr at 70 • • degrees-4% excess and displace to surface. When good cement is seen at return line, shut casing annulus valve and continueto pump cement until allis displaced or pressure reached 1500 psi, squeezing he Beluga perfs at 1402-1469'.This will squeeze the Beluga perfs and provide one balanced plug is,to meet the requirements of`L 1,)plug 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 bury marker. Remove surface equipment from location. Grade location. Take soil samples for confirmation of no contaminants. 1 PROCEDURE: 1) Pick and move wellhouse.Notify AOGCC inspector of plans for plugging operations 2) Move in cementer(pump truck/mixer), bulk cement(150 sx Class G),slickline/electric line unit, water tank with WO bbl fresh water for cementing,mud"pit"open tank with mixing capability with 140 bbl clean produced water or 3%KCI water, open "cuttings"tank for returns. RU cement pump to tree through wing valve. 3) RU slickline lubricator on tree. RIH and pull prong from PX plug at 1311' KB. Allow pressure to equalize (expect maximum of 420 psi). Check lubricator and tree for leaks. If none, pull PX plug body. 4) Kill well by opening sleeve at 1311' and dumping 10.2 ppg NaBr-KCI packer fluid from annulus into tubing. Allow tubing to stabilize,bleed off pressure. Add clean produced water or 3%KCl water to fill tubing and casing if needed to kill well. (Volin e to deepest open perfs is about l3bbl 5) Run 2.25" gauge ring(GR)to check for fluid level and tag bottom (expected to be PX plug at 1707'). If restrictions are found, run bailer, brushes, etc. to clean out to about 1460' to close sleeve at 1452'. 6) RIH with shifting tool. Close sliding sleeve at 1452'. Fill tubing and casing—close sleeve at 1311' Pressure up on tubing to 1500 psi to confirm that an sleeves are closed. Release pressure. 7) RD slickline lubricator unless slickline is used to set CIBP and perforate. If not,RU electric line lubricator(see Notes below;:for possible alternative methods of acc omplish ng this same result). PU CIBP for 2-7/8" CIBP, RIH and set inside top packer at about 1390'. POOH. Pressure test CIBP to 1500 psi. Release pressure. PU 1-1/2" gun with 4 SPF for large holes, RIH, tag CIBP,pull up to 1380' and perforate 4 shot in 1'. POOH. PU second gun (or additional Kinley punch runs) and perforate the tubing at 1340'. POOH. 8) COMBINATION PLUG: RU cement pumper on wing valve of tree. Open casing varve(tubing- casing annulus)and pump 10 bbl into perfs with KCI water down tubing and establish circulation and pressure at 3 BPM—NOTE: annular fluid is I°O.2 ppg KC1-NaBr brine—catch and use subsequent wells. Mix and pump 170 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. Catch annular brine for use in subsequent wells, divert to open tank as soon as returns are cement colored. When good cement is seen in the returns, shut in casing annulus valve and continue pumping until all cement is displaced or until pump pressure reaches 1500.psi—this is squeezing cement into the Beluga perfs • at 1402-1469' (4% excess). This is to be a balanced,plug with a squeeze below—monitor for flow or fall back. 9) When cement top is stable,disconnect cemerrtcr. Wash out tubing, and tubing-casing armulus t- 4' below GL. WOC 8 hours. Pressure test both sides(tubing and annulus)to 1500 psi. Release 6 ;L 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. 10)Fabricate '/" steel marker-plate cap for 8-5/8" conductor casing,not to extend beyond casing OD, and bead-weld the following information onto marker plate; Aurora Gas,LLC - Qti4c-n) AL c_,Ak-. C<+.sq c -c- PTD # 205-080 Moquawkie No. 3 �"S`+�u�u rnn�a�x rL i k)t-A.LAO - ' a,rc2 API# 50-283-20111-00 `'" IL'-401 +-3r-►1 11)Following any necessary inspections, remove cellar and bury marker. Dispose of any waste. Haul KCl water,tanks, and any support equipment to next location. 12)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. NOTES: 1)Will check with slickline company about setting CIBP on slickline. If so,we will use slickline Kinley punch (or similar)to perforate tubing at 1310', eliminating the need for an electric line unit. 2)Also, looking at the possibility of cementing,through the ports:of the upper sliding sleeves, which are very close to proposed tubing perfs, instead of adding perforations to tubing. 3)Another possibility is to reset the PX.plug in the X profile in the uppermost sliding sleeve instead of using CIBP's. However, because the profiles are above the ports, if this is done, it rules out Note 2 above, so the tubing would be perforated just above the PX plug. 4) The feasibility and cost of these options will be reviewed. However, whatever method is used, the bottom of the plugs will be very close to the depths in the text above. Ed Jones(8/23/20i7) �e 1' h45 ©4 P' /'S /ITC' MW'MY/i f �/' ?I k (air 6 �7 / �,�j #, it Weil v�d�r- (aV ,*4 7D 4-:tt Ate/ dy a; 4 �j 6 f�0 w `, Q� r,�`f r,.'^C j f afl 1"1'AhC. b Wyk w art''C(It', P aft,*, r4,3 w • • Aurora Gas, LLC 2 7/8"6.5# 8 Rd J-55 Tubing to 3058' A Moquawk;e No. As-Built r ' -et' e, b', *.• 117/8 71.8# LLS Conductor ."..**17.4' `"* �.� ' driven to refusal at 80 ftJune $ s FebUpdated 2016 t is A. ,/rk4 tk't Irk , Z t 4 a _ ` s t ' a *t,sig"' -"°°:,i '''',471 , . pr 3^4r '' Drill 105/8"Dole ,*a" `,'; , ; r*"V tr: )' +r ,. '1.a *.w Y f. ,' i ' 2 7/8"X 5'/2"annulus displaced ," ,;, # 8 5/8"32# Surface Casing set at 657' w/02 inhibited brine'from r a," r=; Cement w/50 bids 143 ppg tmt w/good surface to top of packer. r;=, kr,> returns at surface y a '_'''M a s *l aj r r XA Sliding Sleeve installed 1 joint above A\ .' packer w/2313"X-Profile for landing plug- . CLOSED ',; • 5'h"IMP hydraulic packer at 1345' Prod Perfs: 1402-1407' XA Sliding Sleeve w/2.31"X profile at 1412-1422' iii . ` 1452'(Closed) 1442-1447' 1 ' 1459-1469' 5 W'Arrowset IX packer at 1709'w/On-Off BELUGA(Tsuga 2-8.1) Tool and 2.313"landing profile •: T' +: 3-1/2"StrataPack Screens Prod Perfs: 1774-1789' + ° at 20277'.2416-2425', 18044824' ( >.+ !�"- 2443-2474' CARYA 2-1.2 i+' moPanelledw-- unclaed ivies in tbg at 1932-34' Prod Perfs: 2f139`2069' ! and shot boles at 19193-213. CARYA 2-2.2 +;, Tag fill at 1900'-4/17/15 ,:t Prod Perfs: 24142419' 2445-2455' : INN` pipe. 2467-2477' 1111 2:::•;;;E- CARYA +. CARYA 2-3.3 +...? Dammed 75/8"Hole to TD @2560' *� 5%s"17#LTC J-55 Casing to 2560' ..-----P "�+ and cemented in place from TD to surface w/21.1 133 ppg Gas- P131 TJ eat at 2520' I block"G"'lead and 76 bbh 15.8 ppg"G"tail # S Aurora Gas, LLC 2 7/8"6.5# 8 Rd J-55 Tubing to 3058' Moquawkie No. 3 PROPOSED PLUG ° ' `' : �'' AND ,t A,! � ° �' � 11 7/8 71.81 LLS Conductor AND ABANDON driven to refusal at 80 ft PTD 205-080 API 50-283-20111-00 r f u August 2017 Drill 105/8"Hole s + 2 7/8"X 5'/x"annulus now filled 8 5/8"32# Surface Casing set at 657' w/10.2 ppg NaBr-KCI from Cementer/50 bbls 143 ppg cmt w/good surface to top of packer,which returns at surface will be dumped and left across penis and in tubing below plugs p i COMBINATION PLUG(Beluga Perfs, Surface Casing Shoe,and Surface i ( Plugs)from 1345'tosmface—pert tubing at 1341)'.Circe and squeeze 170 sx Class G Cement to surface and into Beings pert^s at 1402-1469'. XA Sliding Sleeve installed I joint above r e e r packer w/2.313"X-Profile for landing plug- at 1311'CLOSED 5'r4"HAP hydra is Backer at 1345' r XA Sliding Sleeve w/2.31"X profile at 1452' rEls! j Set C1RP at 1390'.Perforate Turiing at 1388: Prod Perfs: 1402-1407' for Beluga pert plug 1492-1422' -•�n� 1442-1447' 04r..- 1459-1469' '!ICPP''" S 'Arrowset IX packer at 1709'w/On-Off BELUGA(Tsuga 2-8.1) ' Tool and 2.313"landing profile with PX plug set at 1707' 3-1/2"StrataPack Screens Prod Perfs: 17741789' at 202747',2416-2425', & 1804-1824' 2443-2474' CARYA 2-1.2 �.. Punched bales is ttig at 1932-34' Prod Perfs: 2039-2069' and shot holes at 19193-21.5° CARYA 2-2.2Tag fill at 1900'--4117/15 Prod Perfs: 2414-2419' +i 2445-2455' pipe. 2467-2477' 1111 CARYA 2-3.3 1}r •. ' Drilled'7 5/86"Rule to TD 2560' f + 5'f'17#LTC.1-55 Casing to 2560'. 'a and cemented in place from TD to surface w/21.1 bbls 13.5 ppg Gas- PBTD est.at-2520' . block"G"lead and 76 bbls 15.8 ppg"G"tail S OF 77.", s THE STATE Alaska Oil and Gas �'►�!'QiiAC4 of�T ASKA Conservation COnln2issi®n 333 West Seventh Avenue `, wM GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 oe, Main: 907.279.1433 L AAS Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager t$W �1 UL 2 6 21.E 1 t`, Aurora Gas, LLC • 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Moquawkie Field, Undefined Gas Pool, Moquawkie 3 Permit to Drill Number: 205-080 Sundry Number:317-274 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, aarC Hollis S. French Chair DATED this 3 day of July, 2017. RBDMS L(-JUL 1 1 2017 • • RECEIVED • STATE OF ALASKA JUN ALASKA OIL AND GAS CONSERVATION COMMISSION :11 6 2017 APPLICATION FOR SUNDRY APPROVALS , 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull TubMg ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing ❑ Other Temporary Plug Q• 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Aurora Gas,LLC Exploratory ❑ Development ❑ • 205-080 3.Address: 1400 W.Benson Blvd.Suite 410 Stratigraphic ❑ Service ❑ 6.API Number Anchorage,AK 99503 50-283-20111-00 • 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? Moquawkie#3 - Will planned perforations require a spacing exception? Yes ❑ No ❑ 9.Property Designation(Lease Number): 10.Field/Pool(s): C-061390' Moquawkie Undefined Gas • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 2560' , 2560' • 2512' • 2512' • 500 psi 2512' None Casing Length Size MD TVD Burst Collapse Structural Conductor 80° 13 7/872#P110 80' 80' 9430 psi 5300 psi Surface 657' 8 5/8"32#J55 657' 657' 3930 psi 2530 psi Intermediate Production 2560' 5 1/2"17#J55 2560' 2560' 5320 psi 4910 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 1402'-2477' 1402'-2477' 2 7/8" 6.5*J55 3058' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ttf: HRP and Arrowset IX packers HRP @ 1345'and Arrowset( 1709' 12.Attachments: Proposal Summary ❑ Wellbore schematic El 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ ' WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 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 Geo a Pollock Contact Name: Authorized Title: Manager-Pi!S• -ng Contact Email: gpoiiockra''�.aurorapower.com Contact Phone: 907-277-1003 Authorized Signature: Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 31 ? - 2?I{ Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 1 PC4 ctb( CIA.N.6 pc-eS t...)c, M�'1:T 122a A.ICZO t% ;-1-s'C'S i z `.: LS.,F.S%Or-) Cg-- t. I p1/4 Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS i. JUL 1 1 2017 Spacing Exception Required? Yes ❑ No Subsequent Form Required: l 0 -- 404 APPROVED BY .. 13 II"q Approved by: COMMISSIONER THE COMMISSION Date: M hnSubmit Form and �A,4o n 10-403 Revised 4/2017 0 RieiNtAhizlid for 12 months from the date of approval. in Dude • • Aurora Gas, LLC June 16, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 �,VEla Anchorage, AK 99501 JUN 1 6 2017 Re: Application for Sundry Approval—Set Temporary Plug ACC)GoC Moquawkie#3 Well PTD #: 205-080 API #: 50-283-20111-00 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 shut-in, is capable of producing gas from multiple zones in the Beluga and upper Tyonek sands and is mechanically • sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new 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 1304' 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. Sincerel orGeorge 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 2 7/8"65# 8 Rd J-55 Tubing to 3058' — Moquawkie No. 3 As-Built `'' 11 7/8 71.8# LLS Conductor June 2005 '�'' driven to refusal at 80 ft Updated Feb 2016 Drill 10 5/8"Hole . . 66 2 7/8"X 5'A"annulus displaced A I., 8 5/8"32# Surface Casing set at 657' w/02 inhibited brine from Cement w/50 bbls 145 ppg cmt w/good surface to top of packer. returns at surface .I: XA Sliding Sleeve installed 1 joint above , packer w/2313"X-Profile for landing plug– CLOSED . 5""A"HRP hydraulic packer at 1345' Prod Perfs: 1402-1407' XA Sliding Sleeve w/2.31'X profile at 1412-1422' , 1452'(Closed) 1442-1447' 114 1459-1469' C- 5''A"Arrowset IX packer at 1709'w/On-Off BELUGA(Tsuga 2-8.1) Tool and 2.313"landing profile ++� ; 43-1/2"StrataPack Screens Prod Perfs: 1774.1789' ? ' at 2027-67',2416-2425', & 1804-1824' <.s. C� �L 2443-2474' CARYA 2-1.2 .^' Prod Perfs: 2039-2069'. Punched holes in tbg191 at 1932-34' 191 and shot holes at 93-215' CARYA 2-2.2 Tag fill at 1900'-4/17/15 t� Prod Perfs: 2414-2419' ° 2445-2455' ' III=iii Pipe- 2467-2477' CARYA 2-3.3 "Y' Drilled 7 5/8"Hole to TD @ 2560' S'A"17#LTC J-55 Casing to 2560' _____ �!"'�' and cemented in place from TD to • surface w/21.1 bbls 135 ppg Gas- PBTD est.at 2520' ,� block"G"lead and 76 bbls 15.8 ppg"C"tail • • AURORA GAS, LLC Slickline Temporary Plug Set - Generalized Procedure June 2017 SUMMARY: This procedure describes the steps taken to set a temporary plug in wells operated by Aurora Gas, LLC to secure the well for a short term shut in. RIH with drift for the appropriate sized tool for the tubing, in most cases 2 7/8"tubing with 2.312" or 3 %2"tubing with 2.812"X landing nipple profile. Set PXX plug in uppermost landing profile. If a profile is not available, RIH with tubing stop pack-off plug and set above uppermost packer. After plug is set, a negative pressure test will be performed to ensure the plug has isolated the productive intervals from the surface. Upon passing the negative pressure test, the wellhead will be secured. PROCEDURE: 1) AG Operators to shut-in well and monitor pressure while rigging up. 2) RU Pollard Wire Line and lubricator on tree after removal of tree cap. Open well to pressure test lubricator—have pressure gauge on lubricator. 3) RIH with appropriate drift for X profile and sliding sleeves in upper profile. Pass through sleeve approximately 10' to insure safe operation of setting tool. POOH. 4) RIH with PXX Plug body on X-Line running tool. Set Plug body in upper most Sliding sleeve X profile above upper most production packer in well. 5) RIH with RB retrieval tool as running tool with prong. Set Prong in Plug body and POOH. 6) Record pressure and Bleed well bore to zero PSI, Monitor for 30 minutes recording pressure readings at 15 minute intervals. 7) Test successful if no pressure increase observed. If test fails, RIH and reset plug. 8) RDMO Pollard Wire Line. 9) Secure the wellhead. 10)Move to next well. 11)After 24 hours, a pressure reading will be obtained to ensure the integrity of the plug. .4ee Saua9e(6/11/2017) · . Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~ DS - 0 ~ 0 Well History File Identifier Organizing (done) ~WO-Sided 11111111I1111111111 D Rescan Needed 1/1111111111111111I RESCAN ~olor Items: ~reYSCale Items: D Poor Quality Originals: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, NolType: D Other: OVERSIZED (Non-Scannable) D Logs of various kinds: NOTES: Date7/3ojo7 Date '1/3D/ Q 7 ~ 0 +~ = TOTAL PAGES &L (Count does not include cover sheet) 151 D Other:: BY: ~ 151 mP Project Proofing III 111111111111111I BY: ~ 151 mf Scanning Preparation BY: Date: Production Scanning 111111111111111111I BY: Page Count from Scanned File: (p ~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: /YES ~ Da,e7/30jD1 Stage 1 If NO in stage 1, page(s) discrepancies were found: NO 151 rY\ f NO Stage 1 YES BY: Maria Date: 151 11111111111I111111I Scanning is complete at this point unless rescanning is required. ReScanned III 1111111111111111 BY: Maria Date: 151 Comments about this file: Quality Checked 1111111111111/11111 10/6/2005 Well History File Cover Page. doc )~ J~~ DATA SUBMITTAL COMPLIANCE REPORT 7/2/2007 Permit to Drill 2050800 Well Name/No. MOQUAWKIE 3 Operator AURORA GAS LLC MD 2560 / TVD 2560.......... Completion Date 6/26/2005 Completion Status 1-GAS --,._-~-~._~ ~~ ~J_ ^O~- API No. 50-283-20111-00-00 Current Status 1-GAS REQUIRED INFORMATION Mud Log Yes Samples No ~~._-~ DATA INFORMATION Types Electric or Other Logs Run: Schlumberger platform express, array induction, Dipole sonic imager, I Well Log Information: Log/ Data Type- ,¥D I I Electr Digital Dataset Med/Frmt Number Name C Las 13247 Induction/Resistivity Run No Log Log Scale Media Induction/Resistivity Sonic 25 Blu 5 Col 5 Blu 3 5 Blu 5 Blu 2 Formation Tester Cement Evaluation Perforation Well Cores/Samples Information: r--- I I Name Cuttings Cuttings Interval Start Stop 90 2580 90 2580 Received Sent ADDITIONAL INFORMATION Well Cored? Y~ Chips Received? ~ Analysis ~ Received? Daily History Received? Formation Tops UIC N Directional surv~ (data taken from Logs Portion of Master Well Data Maint Interval Start Stop 654 2520 OH/ CH Open 654 2520 Open 654 2449 Open 1112 2475 Open - Received Comments 81412005 PEX-AIT & DSI, CBL, P,rt I Record, Directional Survey. MDT Pressure Record 8/4/2005 PEX Array Induction 8/4/2005 Dipole Sonic Imager, Monopole P & S, Upper Dipole Shear 8/4/2005 Modular Dynamics Tester, Pressure Samples 82 2496 Case 8/4/2005 Cement Bond Log wNariable Density Log, GR-CCL Correlation I 1402 2477 Case 8/4/2005 3.5" HSD Powerjet Guns, 61 SPF, 60 Degree Phasing - I Sample Set Number Comments 1157 ¿,-- 1157 @N GIN ] DATA SUBMITTAL COMPLIANCE REPORT 7/2/2007 Permit to Drill 2050800 Well Name/No. MOQUAWKIE 3 Operator AURORA GAS LLC MD 2560 TVD 2560 Completion Date 6/26/2005 Completion Status 1-GAS Current Status 1-GAS Comments: API No. 50-283-20111-00-00 UIC N Compliance Reviewed By: Date: e e __ STATE OF ALASKA .. ALASKA OIL AND GAS CONSERVATION COM~SION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1 a. Test ~ Initial U Annual U Special 1b. Type Test: U Stabilized U Non Stabilized ~ Multipoint o Constant Time o Isochronal o Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC June 26, 2005 205-080 3. Address: 6. Date TO Reached: 12. API Number: 1400 West Benson Blvd., Suite 410, Anchorage AK 99503 June 12, 2005 50- 283-20111-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 1742' FEL, 2169' FNL, Sec1, T11N, R12W, SM 353' AMSL Moquawkie NO.3 Top of Productive Horizon: 8. Plug Back Depth(MD+ TVD): 14. Field/Pool(s): Same 2,512' MD 2,512'/tvd Moquawkie Gas Field Total Depth: 9. Total Depth (MD + TVD): Same 2,560' MD 2,560' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 266421 y- 2586947.8 Zone- 4 N/A C-061390 TPI: x- Same y- Zone- 16. Type of Completion (Describe): Total Depth: x- Same y- Zone- Multi-packer Selective w/ screens below bottom packer across perfs 17. Casing Size Weight per foot, lb. 1.0. in inches Set at ft. 19. Perforations: From To 5-1/2" 17# 4.892 2,560' 1,774'-89', 1,804'-24',2,039'-69' 18. Tubing Size Weight per foot, lb. 1.0. in inches Set at ft. 2,414'-19',2,445'-55',2,467'-77' 2-7/8" 6.5# 2.441 2,474' 20. Packer set at ft: 21. GOR cflbbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 1,345' & 1,708' NA None 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): o Tubing 0 Casing 75 FO 1,109 psia @ Datum 2,060 TVDSS 14.65 pSia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: I % CO2: % N2: %H2S: Prover: I Meter Run: I Taps: 2,060 2,060 0 1 0 Daniel Sr. 4.016 Flange 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice Size (in.) Size (in.) psig Hw FO psig FO psig FO Hr. 1. 4 X 1-1/2" 835 50 2 hrs. 2. 4 X 1-1/2" 774 50 1.5 hrs. 3. 4 X 1-1/2" 724 50 1 hr. 4. 4 X 1-1/2" 687 50 hr 5. X Basic Coefficient -J Pressure Flow Temp. Gravity Factor Super Compo Rate of Flow No. (24-Hour) hwPm Pm Factor Fg Factor Q1 Mcfd Fb or Fp Ft Fpv 1. 68.69 Calculated using Daniel Sr. 1,652 2. 68.69 Orifice Meter Readings 2,404 3. 68.69 3,055 4. 68.69 3,656 5. Temperature for Separator for Flowing No. Pr Tr z Gas Fluid T Gg G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc 1,057 pc2 1,117,249 1,109 pf 1,229,881 No. pt pf PC2 -pf Pw ~ pc2 -p~ Ps PS2 pf _PS2 1. 835 697,223 420 878 770,884 458,997 2. 774 599076 518,173 817 667,489 562,392 3. 724 524,176 593,073 768 589,824 640,057 4. 687 471,969 645,280 735 540,225 689,656 5. 25. AOF (Mcfd) 6,511 Remarks: Calculated using Ryder Scott Software. n I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ø#~ Title ~(\ f?,tfJ"""",'''~r~r.J OfC Date .F/2~o7 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 Mcfdl -I 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 1/2004 Side 2 WELL NAME: FIELD: lOCATION: RESERVOIR: MOQUAWKIE NO.3 MOQUAWKIE UPPER TYONEK 1174-2411') 10,000 75 0.560 ~$:: x N ro æ 1,000 Well ~ Cì: 100 100 10,000 POiNT NO. (Automatic) SHUT-IN 1 2 3 4, These results were prepared using Reservoir Solutions Software. This is riot Ryder Scott work product. . . AURORA GAS, LLC WELL TEST REPORT MOQUAWKIE #3 DATE: 71912005 4-POINT TEST ALL PERFS BELOW PACKER AT 1709' (1774-89', 1804-24', 2039-69', 2414-19', 2446-55', 2467-77') DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM WATER TIME SPYDR, TEMP - 164" PRESS STATIC DIFF TEMP FACTOR Q VOL METER PSIA dea F psi blue red areen MCFID MCF (CUM) 7:45 SITP 1015.5 34.13 9:45 SITP 1016 11:00 SITP 1016.5 12 OPEN WELL 24 11:15 850 24 500 4.9 5.1 6.5 68.69 1717 11:20 close choke 21 68.69 0 11:30 862 21 500 4.9 4.8 6.4 68.69 1616 11:45 881 21 500 4.9 4.3 6.3 68.69 1447 12:00 902.5 21 500 4.8 3.6 6.2 68.69 1187 12:00 Ooen to 24164 24 4.9 4.8 6.25 68.69 1616 12:15 813.2 24 500 4.9 4.8 6.25 68.69 1616 12:30 824.2 24 500 4.9 4.8 6.4 68.69 1616 12:45 842 24 500 4.9 4.6 6.35 68.69 1548 13:00 830.7 24 500 4.9 4.6 6.3 68.69 1548 13:15 821 24 500 4.9 4.7 6.3 68.69 1582 13:30 822 24 500 4.9 4.7 6.9 68.69 1582 ooen to 27164 27 13:45 752.4 27 500 5 6.3 6.5 68.69 2164 14:00 757.2 27 500 5 6.9 6.5 68.69 2370 14:17 761 27 510 5 6.3 6.5 68.69 2164 14:30 760.8 27 510 5 6.5 6.5 68.69 2232 14:45 760 27 510 5 6.7 6.5 68.69 2301 ooen to 30164 700 30 510 5 8.2 6.6 68.69 2816 15:00 699.6 30 520 5.05 8 6.6 68.69 2775 15:15 711.8 30 520 5.1 8.3 6.6 68.69 2908 15:30 Catch ~as samole 708.5 30 520 5.1 8.35 6.6 68.69 2925 15:45 ooen to 32164 705 30 520 5.1 8.3 6.6 68.69 2908 16:00 662 32 530 5.1 4.1 6.7 68.69 1436 16:02 ooen to 33164 655 32 16:15 651.1 33 520 5.1 9 6.7 67.1 3080 16:30 654.8 33 540 5.15 8.9 6.7 67.1 3076 16:45 661.2 33 540 5.1 9.7 6.7 67.1 3319 17:00 651.4 33 540 5.1 9.5 6.7 67.1 3251 17:20 655.3 33 540 5.2 9.4 6.7 67.1 3280 17:30 654.1 33 540 5.2 9.4 6.7 67.1 3280 17:45 662.2 33 540 5.2 9 6.7 67.1 3140 18:00 648 33 540 5.2 9.1 6.7 67.1 3175 18:20 672.9 33 540 5.2 9.6 6.7 67.1 3350 18:30 673.7 33 540 5.2 9.8 6.7 67.1 3419 38.01 Shut in after readino (7.73 bbl) 18:31 887 7.5 hrs 18:32 931.5 18:33 952.3 18:34 971.5 18:35 977.6 18:40 996.2 18:45 1006.5 18:50 1009.5 18:55 1011.4 19:00 1012 8:00 711112005 FSIP 1043.4 Point #1 Point #2 Point #3 Point #4 CI-164,OOO Load KCI fl¡Aurora Gas, LL! www.aurorapower.com November 20, 2006 RECEIVED NÚV ~ 4 2006 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 AIII$kø Oil &. Û¡; CCi1~. Commission Anchor.p Re: Revised Completion Schematic: Moquawkie No.3 (PTD#: 205-080) Dear Mr. Norman, On January 26, 2006, Aurora Gas, LLC submitted data in conjunction with the completion of operations in June of2005. We have recently discovered that an incorrect Completion Schematic for the above referenced well was inadvertently submitted. Aurora Gas, LLC hereby submits the correct Completion Schematic, which covers the completion of Moquawkie No.3 on June 27,2005. Pertinent information included under cover of this letter includes the following: 1) Completion schematic If you have any questions or require additional information, please contact me at (907) 277-1003, or Ed Jones at (713) 977-5799. Sincerely, ~0rÞ(£, Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC cc: Keith Sanders, CIRI Bill Penrose, Fairweather 10333 Richmond Avenue, Suite 710. Houston, Texas 77042· (713) 977-5799· Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503· (907) 277-1003· Fax (907) 277-100Á /('10'c& 4-(~1s- ~ I¥'f/~ Aurora Gas, LLC Moquawkie No.3 As-Built June 2005 Drill 10 5/8" Hole 27/8" X 511," annulus displaced wi O2 inhibited brine from surface to top of packer. Prod Perfs: 1402-1407' 1412-1422' 1442-1447' 1459-1469' BELUGA (Tsuga 2-8.1) Prod Perfs: 1774-1789' 1804-1824' CARYA 2-1.2 Prod Perfs: 2039-2069' CARYA 2-2.2 Prod Perfs: 2414-2419' 2445-2455' 2467-2477' CARYA 2-3.3 PBTD est. at -2520' 27/8" 6.5# 8 Rd J-55 Tubing to 3058' 11 7/8 71.8# LLS Conductor driven to refusal at 80 ft 8 5/8" 32# Surface Casiug set at 657' Cemeut wi 50 bbls 14.5 ppg cmt wi good returns at surface Figure I Sliding Sleeve installed 1 joint above packer wi 2.313" X-Profile for landing plug- CLOSED 5 11," HRP hydraulic packer at 1345' Sliding Sleeve wi 2.31" X profile at 1452' CLOSED 5 11," Arrowset IX packer w IOn-Off Tool and 2.313" landing profile 3- 1/2" StrataPack Screens at 2027-67', 2416-2425', & 2443-2474' Bull plug installed in tail pipe. Drilled 7 5/8" Hole to TD @ 2560' 5 If," 17# LTC J-55 Casing to 2560' and cemented in place from TD to surface wi 21.1 bbls 13.5 ppg Gas- block "G" lead and 76 bbls 15.8 ppg "G" tail FEB 1 3 2006 . STATE OF ALASKA . Alaska 0" & ALASKA OIL AND GI ONSERVATION COMMISSION Revis¿d Gas Cons. COfTJrnjss;on WELL COMPLETION OR RECOMPLETION REPORT ANd'f.'ew 1a. Well Status: OilD Gas0 Plugged 0 Abandoned 0 Suspended 0 WAGD 1 b. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 ExploratoryD GINJD WINJD WDSPLD No. of Completions Other Service 0 Stratigraphic TestD 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: Aurora Gas, LLC Completed: 27-Jun-05 205-080 3. Address: 6. Date Spudded: 13. API Number: 1400 West Benson Blvd, Suite 410 Anchorage, AK. 99503 June 4, 2005 50-283-20111-00 4a. Location of Well (Governmental Section): 7. Date TO Reached: 14. Well Name and Number: Surface: 2159' FNL, 1728' FEL, S01, T11N, R11W, SM June 12, 2005 Moquawkie NO.3 Top of Productive Horizon: 8. Kß Elevation (ft): 15. Field/Pool(s): Same 352.5' AMSL GL @ 338' Total Depth: 9. Plug Back Depth(MD+ TVD): Moquawkie Gas Field Same 2512' MD, 2512' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 266434.935 y- 2586956.785 Zone- 4 2560' MD, 2560' TVD C-061390 TPI: x- 266458.02 y- 2586956.59 Zone- 4 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x- 266533.10 y- 2586950.81 Zone- 4 NIA 18. Directional Survey: Yes 0 No 0 19. Water Depth, if Offshore: 20. Thickness of Permafrost: Wireline Surveys wI extrapolated pt at TO. N/A feet MSL NIA 21. Logs Run: Schlumberger Platform Express, Array Induction, Dipole Sonic Imager, Inclinometer, MDT and SWC's 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT. GRADE TOP BOTTOM TOP BOTTOM PULLED 11 7/8 71.8# P-110 Surface 90 Surface 90 driven 85/8" 32# We-50 Surface 657' Surface 657' 105/8 50 bbls 14.5 ppg GasBlk "G" 51/2" 17# J-55 Surface 2560' Surface 2560' 77/8" 21.2 bbls 13.5 #/g Lead 76 bbls 15.8 #/g Tail (returns observed at surface) 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) Guns: 3 1/2" HSD PD PJ HMX @ 6 SPF& 60 Deg Phasing: 2 7/8" 6.5# 8rd EUE - 1345.7' 1345' & 1708', 2039' - 2049',1804' - 1824',1774' - 1789',1459' - 1469', 1442' - 1447', 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 1402' - 1407'. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED All Depths MD & TVD. Directional Tendency is minor, MD & TVD within .5 ft. 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): June 21, 2005 Date ofTest: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: I~as-Oil Ratio: 6/21/2005 " 1/211900 Test Period -+0 163 0 26/64 NA Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity - API (carr): Press. 820 24-Hour Rate ..... 0 1420 0 NA 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit care chips; if none, state "none". " best zone in Multi-zone well and test. See attached data for other tests. Form 10-407 Revised 12/2003 o RIG fMrti:t ON REVERSE G NAME 29. ORMATION TESTS TVD Include and briefly su e test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state 0.00 0.00 "None", "·"-14.·ŠÖ·n... --m"-1-4:ŠÖ·m... 2039' -2477 920 MCFD, 840 osia. 30/64": 2039' -2477, 3.6MMCFD. .m·11Öå~öönn ......nÕ8.ÖÕ..--.. 750osia.36/64": 2414-2477'.870 MCFD. 450psia. 28/64"; 2414- 2477. ..m1Z·Õ2-ÖÖ··-- .m·-12Õ2'ÖÕ..-m 1.6MMCFD. 680 psia. 28/64": 1402-1469.100 mcfd. 70 psia. ··..·.¡;fÕ2~ÖÕm. ...m14Õiöõ·m. 32164",1774· 2477',1420 mcfd, 820 psi. 26/64": Please See Attached Flow Test Information. 1746.00 1746.00- ..n-1773~Ö·Õm. nm-1773:ÕÕ·m.. ----·199Õ~Ö·Õ·m m..-199Ö.ÖÕ....· ··--2Ö64~Ö·Õ·m .m··ZÖ64".ÖÕ--...· ····-2n4~Ö·Õ···· ·--·-·Z·n4".ÖÕ....·· ·····24·f3~ÕÖ···· -····-2413.ÖÕ····· 28. KB ELEVATION SURFACE ELEVATION TSUGA 2-7.1 SAND TSUGA 2-7.2 SAND TSUGA 2-8.1 SAND CARY A2-·f(TÕ·P-fŸÕÑEK) CARYA2-1.1 SAND CARY A 2-2.1 SAND CARY A 2-2.2 SAND CARYA 2-2.3 SAND CARYA 2-3.3 SAND 30. Contact: 31. Title: Executive Vice President Engineering-Operations Phone: 71] -? 77-579 -- Date: 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. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is chanoed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for I njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool comoletelv seoreoated. Each seoreoated 0001 is a comoletion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately oroduced. showino the data oertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (exPlain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 1212003 · . ~AulUra Gas, LLC WWIN. aurorapower. com February 8,2006 Mr. John Nonnan, Chair Alaska Oil and Gas Conservation Commission 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 Re: Revised final well completion report fonns for: Lone Creek #3 (API # 50-283-20112-00) & Moquawkie #3 (API#50-283-20111-00) Dear Mr. Nonnan: Aurora Gas, LLC hereby submits Revised well completion Report fonns Moquawkie #3 and Lone Creek #3. As discussed, well test data and fonnation tops have been entered in the appropriate places. If you have any questions or require additional infonnation, please contact the undersigned at (713) 977-5799, or John Breitrneier at Fairweather E&P Services, Inc (907) 258-3446. ward Jones ice President Operation Aurora Gas, LLC cc: Keith Sanders, CIR! John Breitrneier, Fairweather 10333 Richmond Avenue, Suite 710· Houston, Texas 77042. (713) 977-5799. Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503. (907) 277-1003· Fax (907) 277-1006 . . DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 10333 RICHMOND, STE. 710 HOUSTON, TX 77042 AT1N: ANDY CLIFFORD State of Alaska Oil & Gas Conservation Commission 333 W. 7'11 Avenue, Suite 100 Anchorage, AK 99501 ATTENTION: Howard Okland Enclosed From Area CDs and Paper Prints Aurora Gas, LLC Moquawkie Area, Cook Inlet, Alaska Date: 3 August, 2005 CDs: 1. Lone Creek #3 well data: CBL, PEX-AIT & DSI LAS data, Directional Survey, plus CBL, Perforation Record, PEX-AIT Composite, DSI, FMI, MDT & Directional Survey PDS files. 2. Moquawkie #3 well data: CBL, PEX-AIT & DSI LAS data, Directional Survey, MDT Pressures Record, plus CBL, Perforation Record, PEX-AlT, DSI & MDT PDS files. Paper Prints: 1. Lone Creek #3 well data: Cement Bond Log 5"/1 00', Perforating Record 5"/100', Directional Survey, Platform Express 2"/100' plus 5"/100', Dipole Sonic Imager 5"/100', Fullbore Micro-Imager (Unprocessed) 5"/100', Modular Dynamics Tester, Horizon Mudlog 2"/1 00' in wide & narrow plots. 2. Moquawkie #3 well data: Cement Bond Log 5"/100', Perforating Record 5"/100', Platform Express 2"/100' plus 5"/100', Dipole Sonic Imager 5"/100', Modular Dynamics Tester. PLEASE ACKNOWLEDGE RECEIPT OF DATA BY SIGNING BELOW AND SENDING A COPY BACK TO AURORA GAS FOR OUR FILES. ,j ( . '\ f! j l . ! {/' 'L! Received by: ·lj4.~'- lJ t()vv'i . ..< (; ~ 1~Y() ç AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 Date: ¿2os-- ò3t ¡:::(z FW: Data for well completion reports . ;;11) ~öl/Ô Bob, Here are the formation tops for Moquawkie 3 and Lone Creek 3. I checked with Ed Jones and our file copies and I believe Aurora did send in the well Test data. John Content-Description: MOQ #3 FORMATION TOPS.xIs #3 FORMATION TOPS.xls Content-Type: applicationlvnd.ms-exceI Content-Encoding: base64 Content-Description: LC #3 FORMATION TOPS.xIs #3 FORMATION Content-Type: applicationlvnd.ms-exceI Content-Encoding: base64 1 of 1 2/7/2006 6:56 AM FORMATION TOP . liD c:.85žJ 58'D KB ELEVATION SURFACE ELEVATION TSUGA 2-7.1 SAND TSUGA 2-7.2 SAND TSUGA 2-8.1 SAND CARY A 2-1 (TOP TYONEK) CARYA2-1.1 SAND CARYA 2-2.1 SAND CARYA 2-2.2 SAND CARYA 2-2.3 SAND CARYA 2-3.3 SAND · . ~JAulOra Gas, LLC www.aurorapower.com January 26, 2006 Mr. John Norman, Chair Department of Natural Resources 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RECEIVED I ^ N CJ O· 'IOlit' ..J /-\ ,tJ ( '.. . ' Re: Final well completion report and operations summary: Moquawkie No.3 (PTD#: 205-080) Alaska Oil & Gas Cons. COITImission Anchorage Dear Mr. Norman, Aurora Gas, LLC hereby submits the final well report, which covers the completion of Moquawkie No.3. Operations were completed on June 27, 2005. Pertinent information included under cover of this letter includes the following: 1) Form 10-407 "Well Completion RepOrt and Log" - 2 copies. 2) Wellbore schematic 3) Completion schematic 4) Summary of daily well work and operations 5) As-Built plat. Copies of electrical well logs, mud-logging reports and well test results will be submitted under separate cover. If you have any questions or require additional information, please contact the undersigned at (907) 277-1003, or John BreitIneier at (907) 258-3446. Sincerely, Jt~ Jones Vice President OperatIOns and Engineering Aurora Gas, LLC cc: Keith Sanders, CIRI John Breitmeier, Fairweather 10333 Richmond Avenue, Suite 710. Houston, Texas 77042. (713) 977-5799. Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503. (907) 277-1003· Fax (907) 277-1006 . STATE OF ALASKA . ALAS L AND GAS CONSERVATION COMMIS... . N RECEIVED' 3 0 7006 WELL COMPLETION OR RECOMPLETION REPORT ID ~I,.QG, - . 1a. Well Status: OilO Gas~ Plugged U Abandoned 0 Suspended 0 WAGU 1 b. Well Class: ,_f" ',. \.H">..... VII,). 20AAC 25.105 20AAC 25.110 Development 0 ~(ti9Ð GINJD WINJO WDSPL 0 No. of Completions Other ~. Service 0 Stratigraphic Test 0 2. Operator Name: 5. Date Comp., ~p., or ~'ð 12. Permit to Drill Number: Aurora Gas, LLC Completed: ~Jun-o! b 205-080 3. Address: 6. Date Spudded: 13. API Number: 1400 West Benson Blvd, Suite 410 Anchorage, AK. 99503 June 4, 2005 , 50-283-20111-00 4a. Location of Well (Governmental Section): 7. Date TO Reached: 14. Well Name and Number: Surface: 2159' FNL, 1728' FEL, S01, T11N, R11W, SM /' / June 12, 2005 Moquawkie NO.3 Top of Productive Horizon: 8. KB Elevation (ft): 15. Field/Pool(s): Same 352.5' AMSL GL @ 338' Total Depth: 9. Plug Back Depth(MD+ TVD): Moquawkie Gas Field Same 2512' MD, 2512' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation: Surface: x- 266434.935 - y- 2586956.785 Zone- 4 ' 2560' MD, 2560' TVD ,- C-061390 TPI: x- 266458.02 y- 2586956.59 Zone- 4 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x- 266533.10 y- 2586950.81 Zone- 4 NIA 18. Directional Survey: Yes UNo L::.J 19. Water Depth, if Offshore: 20. Thickness of Permafrost: Wireline Surveys w/ extrapolated pt at TO. N/A feet MSL N/A 21. Logs Run: Schlumberger Platform Express, Array Induction, Dipole Sonic Imager, Inclinometer, MDT and SWC's 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 11 7/8 71.8# P-110 Surface 90 Surface 90 driven 85/8" 32# We-50 Surface 657' Surface 657' 105/8 50 bbls 14.5 ppg GasBlk "G" 5 1/2" 17# J-55 Surface 2560' Surface 2560' 77/8" 21.2 bbls 13.5 #/g Lead 76 bbls 15.8 #/g Tail (retums observed at surface) 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) Guns: 3 1/2" HSD PO PJ HMX @ 6 SPF& 60 Deg Phasing: 27/8" 6.5# 8rd EUE - 1345.7' 1345' & 1708', 2039' - 2049',1804' -1824',1774' -1789',1459' - 1469',1442' -1447', 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 1402' - 1407'. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED All Depths MD & TVD. Directional Tendency is minor, MD & TVD within .5 ft. 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: I Gas-Oil Ratio: Test Period ... Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity - API (corr): Press. 24-Hour Rate -. 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". J-"", <-"'-~.,,--<, . '\ ',11' ~ - , ~_ RBDMS 8Ft FEB !) ., 2Doa . .,1 ,,'._ ~ ~. I t.Du oót-- ---""'-~-- ~ ì VEP:C!r.:jJ ; ¡~¡ t.::-,z.. ..~,.....;~J Form 10-407 Revised 12/2003 CONTINUED ON REVERSE 28. GEOLOGIC MARKE 29. FORMATION TESTS NAME TVD Include and briefly su rize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None" . Please See Attached Flow Test Information. 30. List of Attachments: As-Built, Wellbore & Completion Schematic, Drilling and Operations report. 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Title: Executive Vice President Engineering-Operations Signature: Phone: ')?J 7 -2-7 '1-/0¿;J S Date: 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. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for / njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 . . WELL DRILLING AND COMPLETION REPORT urora Gas,I.I.C Moquawkie No.3 Tyonek, Alaska 01 - August - 2005 Aurora Gas, LLC Page 1 019 . . Background Information: The Moquawkie No.3 well was spudded on June 4,2005. The well was drilled in close proximity to the Mobil Moquawkie No. 1 to access gas reserves not producible from the Moquawkie No. 1 for mechanical reasons, i.e. behind (2) strings of casing. The well was drilled, tested and completed and is now being connected for production through the Moquawkie No. 1 production facility. The following well work summary details the drilling and completion work chronologically. Each date covers work completed over the course of a 24 hour period, i.e. midnight to midnight. Figure I is a schematic of the well as completed. Attachment II is a tally and diagram of the actual completion equipment in the well at this time and Attachment III is a diagram ofthe wellhead and production tree installed on the well. Work Summary and Daily Activities: May 26, 2005 - June 1,2005 June 2, 2005 June 3, 2005 June 4, 2005 June 5, 2005 June 6, 2005 Aurora Gas, LLC Move in rig and support equipment and rig-up. Spot all equipment, filter brine and prep well for re-entry work. RU flow lines, derrick lights and tank lines. RU pits and pumps, load 30 bbls water to check for leaks. RU pipe handling equipment on floor. Continue RU of floor, pipe handling equipment, flow lines and other. Build 14 ppg spud mud system. RU kelly hose and power swivel hydraulics. Repair #1 pump, MU 10 5/8" BHA, RIH, tag up at 84'. Calibrate depth recorder and flow sensor. Hold pre-spud meeting wI crew and support personnel. Spud well and drill to 132'. Drill using 14 ppg spud mud. Drill ahead to 493', flow check well on connections. Short trip and work through tight spots. Survey at 433' (1.5°lnc), drill to 650'. Original decision was to set surface at 650 ft but in coal seam, decide to drill ahead to get out of coal. Drill to 660', detennine in clay I sand bed. CBU and attempt to POOH. Tight, pump out of hole. Back-ream while pumping out of hole 386' - 166', LD 4 %" DC's. BHA balled up wI clay. Run back in hole washing to bottom. Hole clean and no fill. CBU and prep to run casing. POOH, LD stabilizers and 1 DC. Rill wI 15 jts of8 5/8" 32# STC WC-50 surface casing. Hole in good shape. Work pipe and circulate Page 2 019 June 7, 2005 June 8, 2005 June 9, 2005 June 10, 2005 Aurora Gas, LLC . . while rigging up cementers. Casing cemented into place wi 50 bbls 14.5 ppg "gas-block" modified "G" and displaced wi 38 bbls 14 ppg mud, bumped plug, checked floats, OK. Casing landed at 657 ' MD (TVD). Had cement returns at surface. WOC, drain diverter and wash out. LD casing tools, prepare to ND diverter and other. WOC, slack off on csg string. LD elevators and slip bowl. ND diverter, rough cut 8 5/8" csg, remove stub and diverter. Finish cut and remove starting head. Install and weld on wellhead. NU BOPE. NU flow line and trip tank lines. NU choke and kill hoses, MU test joint for BOP test. Install mouse-hole, fill stack and work on pumps. RU for BOP test, cavity test to 500 psi looking for initial leaks. NU gas buster flow lines. Test BOPE. Finish RU of mud loggers and calibrate depth system. Attempt to RIH wi BHA, would not go. Pull wear bushing, work bit through wellhead, install wear bushing. Wrong wear bushing installed. RIH wi 7 7/8" drilling assembly. PU swivel, hold kick drill wi crews and discuss duties and responsibilities for each crew member. Tag top plug at 612' (float collar top). Berm in storage tank for excess muds, transfer out sufficient 14 ppg mud to allow dilution back to 10 ppg. Pressure test casing to 1500 psi. OK. Drill out float equipment and shoe track, drill 20' of new hole. CBU, condition mud and perform FIT test to 16 ppg MWE (210 psig at surface). Drill ahead to 916', check and record slow pump rates for well kill operations. Drill to 1020', see 5% increase in flow, shut in well and check pressures, none, attempt to circulate wi returns through gas buster, determine valve at shaker cemented off. Circulate out well through choke, 2900 units of gas. Circulate out gas, check for flow, none. Run single shot to get drift angle. Survey at 1010' indicated 10 inclination. Finish repair of valve to gas buster, resume drilling operations. Drill to 1258', noted slight well flow wi no recordable pressure, increase mud weight to 10.1 ppg. Prepare for and pull short trip, pulled (2) stands and swabbed in well. Circulate out gas at surface and kill well. Circulate back to bottom, condition mud and raise weight to 10.2 ppg. Perform short trip by pumping out of the hole. Wash back to bottom, no fill, drill to 1477'. Pump nut-plug sweep to eliminate bit balling. Noted 1500 units of gas at 1460'. / ,/ ./ Page 3 of9 June 11,2005 June 12,2005 June 13, 2005 June 14, 2005 June 15,2005 Aurora Gas, LLC . . Drill ahead, CBU at 1539', stops pumps and flow check well, OK. Run single shot survey at 1505', show 2° inclination. Drill ahead to 1569', show 5% flow rate increase. Shut in well and check for pressure, none, circulate out gas through gas buster wi 5000 units recorded at surface. Check for flow, well static, weight up to 10.5 ppg. Drill ahead to 1802', shut down to repair rig generator and mud pump # 1 for 1 hr. Drill ahead to 1881', CBU and short trip, pumping out of hole and washing back to bottom. No fill while washing back. Drill to 2037' CBU, run single shot survey, inclination at 2006' 4°. Drill to 2409', backream every 2 jts to insure hole cleaning. Had 5000 units gas at 2471', checked for flow and circulate out gas cut mud. Drill to 2507', shut down for generator repair. Drill to TD at 2560' , and perfonn flow check on well. No flow, CBU and short trip out of hole to prepare for OH logs. Backream to 1550' Continue to backream and pump out of the hole to 632'. Monitor well, service rig, POOH to 196'. Notice gas percolating out of mud wlo fluid gain. PU DP single and head pin. Shut in well and check for pressure, none. Open up and check for flow, none. Mud appears to be gassed up. MU IBOP and RIH, break circulation while staging in hole, max gas observed at surface on breaking circulation 5000 units each time. RIH to bottom, w 10' fill on bottom. Wash to bottom, circulate, condition mud and hole for OH logs. Pump out of hole, stand back BHA, LD stabilizers, break bit, monitor well. RU Schlumberger for OH logs. Run Platfonn Express logging suite (Array Induction, Dipole Sonic Imager, Inclinometer). Load nuclear source, RIH wi logging tools to 2530' and log. Service rig while logging. POOH wi logging tools, retrieve nuclear source, LD tools. PU sidewall core tool and RIH. Retrieve core plugs, POOH wi tools, LD. PU MDT logging tools, RIH wi MDT and take pressures and various stations in wellbore. Detennine tool seal against fonnation inadequate, cancel remainder of stations. POOH, LD tools and RD Schlumberger. MU bit and RIH wi DC and DP to condition hole for running casing. RIH to 2530', PU power swivel and wash to TD at 2560', (15' fill). Circulate, reciprocate and rotate while conditioning mud. Pump dry job and POOH. POOH LD DP and DC's and BHA. Pull wear ring and clo rams for 5 Yz" casing. RU and prepare for running casing. Hold PJSM, RIH wi 5 Yz" casing (56 jts total 5 Yz" , 17# J-55 LTC). Page 40f9 June 16, 2005 June 17,2005 June 18,2005 June 19,2005 June 20, 2005 Aurora Gas, LLC . . Finish Rlli wi 5 )tí" casing, break circulation and tag bottom at 2560'. RU cementers, hold PJSM fI cmt job. Load plugs in cmt head, ptest lines, OK. Pump 24 bbls 11.5 ppg scavenger slurry, 21.2 bbls 13.5 ppg lead "gas-block" lead and 76 bbls 15.8 ppg "G" tail. Displace wi 58.5 bbls brine. Drain and flush stack, flow line, possum belly and clean up cementers. WOC, continue cleaning up and prep to set pack-off and slips. ND stack, set slips wi 39,000 lbs wt. Set packoff, test to 3000 psig 10 min, OK. NU stack and flowline, LD power swivel. Change out rams for 2 7/8" workstring and cavity test stack to 2501 3000 psig, OK. Clean pits. Finish cleaning pits, PU 2 7/8" handling equipment, PU bit, casing scraper and RIH wi 27/8" tbg. Tag bottom @ 2512'. Continue cleaning pits, test casing to 1500 psi fI 30 min, OK. Clean pits and trip tank. Flush all lines and valves, take on brine for testing and completion. Prepare 10.2 ppg KCL based NaBr brine. Filter to 10 micron and displace hole. POOH wi tbg and LD scraper and bit. RU Schlumberger for CBL/CCL correlation run, log well. ND flowline and pitcher nipple. NU shooting flange. RU lubricator, hold PJSM, PU guns, test lubricator to 1500 psig. Rlli, correlate depth wi gamma and CCL. Casing perforated over the following intervals using Schlumberger 3 )tí" HSD Deep Penetrating Power Jet HMX charges at 6 spf & 60ophasing. [3)tí" HSD DP PI HMX guns]. Run Depth Inteerval 1 2467' - 2477' 2 2445' - 2455' 3 2414' - 2419' (miss-fire, pulled guns) 4 2414' - 2419' 5 2049' - 2069' POOH, well flowing. SI well and bleed off pressure and prepare for well kill. Both rig pumps down. Order out BI Services for pumping. Weight up brine to lOA ppg. Lubricate in brine while alternately bleeding off gas. Continue pumping cycle until well dead, observed not flow. RD Schlumberger. ND shooting flange, NU bell nipple and flow line. Open choke and blind rams, RIH wi bit and casing scraper on 2 7/8" tubing to 2087'. CBU and monitor well for gas flow. Circulate filtered brine, POOH, LD scraper and bit. RD bell nipple and flow line, RU shooting flange. RU Schlumberger for perforating. Hold Page 5 of9 June 21, 2005 June 22, 2005 Aurora Gas, LLC . . PJSM, RU lubricator and test to 1000 psi. Casing perforated over the following intervals using Schlumberger 3 W' HSD Deep Penetrating Power Jet HMX charges at 6 spf & 60ophasing. [3 W' HSD DP PJ HMX guns]. Run 1 2 3 4 5 6 7 Depth Interval 2039' - 2049' 1804' - 1824' 1774' - 1789' 1459' - 1469' 1442' - 1447' 1402' - 1407' (miss-fired, pull guns) 1402' - 1407' .;' POOH, RD Schlumberger, NU shooting flange and RU wi bell nipple and flow line. PU casing scraper and bit, RIH to 2500', circulate out debris and reverse (2) hole volumes. Circulate and filter brine. RU test skid, lines and flare. Continue circulate and filter brine while RU test facility. POOH wi bit and scraper, perform scheduled BOPE test. PU Weatherford test packer and RIH to 2004'. Set packer at 2000'. RU swab head and test lines, hold PJSM. RIH to 500' and swab well for flow test #1. Pull 1.5 bbls to pit and check bleeder for flow, well flowing. Flow 2.9 bbls total brine to pits before diverting to test separator. Flow test well record .8 mmcfd on 29/64th choke wi FTP 831 psig at start. End flow recorded at .85 mmcfd on 30/64th choke wi FTP of 854 psig (test results attached). Well then shut in wi initial SITP at 858 psig. Pressure build to 923 in Iminute, to 954 psig at 10 minutes and 964 psig in one hr. Monitor pressure build up after flow test #1, final SITP recorded at 969 psig at 5 hrs. Start flow test #2, at 736 FTP and 32/64th choke record flow at 2.4 mmcfd. Well flowed 1 hr, orifice changed out to 2" and final flow of3.7 mmcfd recorded on 36/24th choke wi FTP 753 psig (test results attached). Well shut in wi initial SITP of753 psig. At 1 hr, pressure recorded at 1011 psig. Open unloader, kill well. Reverse circulate to insure stable, unseat packer and RIH, reset packer at 2370' for flow test #3. Swab in well in (3) runs, running to 500', 750' and 1200', unload 14 bbls brine total. Record initial flow rate of. 7 mmcfd on 28/64th choke wi FTP of 437 psig. Final flow rate recorded at .96 mmcfd on 28/64th choke wi FTP of 445 psig (test results attached). Well shut in and initial SITP recorded at 1080 psig. Final SITP recorded as 1150 psig at (2) hrs shut-in. Monitor pressure build at crew change, hold PJSM and begin flow test #4. Page 60f9 June 23, 2005 June 24, 2005 June 25, 2005 June 26, 2005 Aurora Gas, LLC . . Flow test #4: Initial flow recorded at 1.6 mmcfd on 28/64th choke wI FTP 673 psig. Final flow recorded at 1.64 mmcfd on 28/64th choke wI FTP 684 psig (results attached). Final SITP 1151 psig. Kill well, reverse circulate, monitor well. POOH, PU RBP and Rill, set RBP at 2004', pull double, pressure test to 1500 psig, POOH and set test packer at 1759'. Swab well, 4 runs and unload 7.8 bbls, well attempted to flow then died. SI and record pressure at 168 psig. Bleed off pressure to test skid, and continue swabbing wI total recovery of9.55 bbls by run #7. SI well and monitor pressure. Decision made to kill well. RIH and unseat RBP, start POOH. RBP appears problematic as appears to have something catching on top of it when pulling. Attempt to work free when noticed well flowing. SI well and monitor, appear to have swabbed in well when working RBP. Circulate and kill well through choke and gas-buster. POOH and set RBP at 1560' wI test packer set at 1490. P-test to 1500 psig, to verify integrity of packers. Release from RBP and pull up to 1365 and set test packer. RU to swab and wait on daylight for swabbing operations. Swab from 750', then 1000', then 1200'. Pull total of 4.6 bbls and monitor well for pressure build. Wait 30 min and RIH wI swab, find fluid level static at 1200 ft. Make total of 11 swab runs total with 10 bbls swabbed in. SI well and monitor for pressure build. Test well wI initial flow of .2 mmcfd on 14/64th choke wI FTP of 546 psig. Final flow rate of .08 mmcfd on 32/64th choke and FTP of 56 psig. Final SITP of 640 psig recorded. Finish flow test on perfs from 1402' - 1469'. RD test head, lubricator etc., RU to kill well. Hold PHSM, open unloader tool, fill hole wI brine (8 bbls). Reverse circulate 1 hole volume, Rill to RBP, release RBP and circulate out gas. POOH, LD RBP and test packer. PU bit and scraper, Rill to 2512', circulate out sand and filter brine. POOH, LD scraper and bit. Monitor hole, PU completion and sand screens. RIH wI 41 jts tbg, PU landingjt, land tbg. Attempt to set packer, packer not there. LD landingjt, RIH 54', latch onto packer, pull back up 54', PU landingjt set 5 W' Weatherford Arrowset IX Packer at 1715.9'. RU slickline and RIH to 1709', set plug in landing profile. RD slickline. RU lines to test pump, set Weatherford HRP hydraulic set packer at 1352'. Pressure up to 2350 psig and hold for 30 minutes to test tubing. Swap lines and pressure test tubing! casing annulus to 1000 psig. RU slickline, Rill and retrieve plug. Open sliding sleeve at 1310' and circulate corrosion inhibitor into tubing Page 70f9 June 27,2005 Aurora Gas, LLC . . I casing annulus. Close sliding sleeve and attempt to pressure test tubing, no test. RIH wI slickline and re-shift sliding sleeve to closed position. Pressure test tubing to 2000 psig, OK. RD lines, set BPV, ND BOPE. NU tree, test seals to 3000 psig 110 minutes. Pull BPV, set 2-way check, test tree to 3000 psig 10 minutes. Pull 2-way check. RU slickline, RIH and pull plug ITom profile at 1709'. Shift open sliding sleeve at 1452', close sliding sleeve at 1310' which opened when running through wI slickline and re-close sleeve at 1452', decision made to just open perforations below packer at 1708' to test. RU test lines and lubricator, swab head, gas buster to flow test. Swab in well wI one pull from 750'. 12.4 bbls brine recovered prior to lining up on separator. Flow test #7 (results attached) started wI .932 mmcfd on 26/64th choke wI FTP 932 psig. A final flow rate of 1.7 mmcfd was recorded on 26/64th choke wI FTP of 862 psig. ¡SIP at surface recorded at 849 psig. A final SITP of 1010 psig was recorded after shut in of30 minutes. Install BPV in wellhead; begin rig down and rig released at midnight. Page 8 019 Gas, 1.1.C Moquawkie No.3 Current Well Configuration 06/27/05 See attached completion As-Built for specific Information Displaced 2 7/8" x 5 1/2" annulus kill weight inhibited brine from packer to surface Open Perfs: 1402' -1407' 1442' -1447' 1459' - 1469' Open Perfs: 1774' -1789' 1804' - 1824' Open Perfs: 2039' - 2049' 2049' - 2069' Open Perfs: 2414' - 2419' 2445' - 2455' 2467' - 2477' Aurora Gas, LLC }-{ }-{ }---[ }-[ 11 7/8" 71.8 polIO conductor driven to 90 ft minimum. 27/8" 6.5#, 8rd EVE tubing. 10 5/8" STC WC-50 Casing to 657' MD (Cemented with 50 bbls 14.5 ppg Gas-Block "G" cement slurry system with good returus observed at surface. 2.31" WOT XA Sliding Sleeve 1310.5' 5 y," Weatherford HRP Hydraulic Set Packer 1345.24' Please see Attachment for completion detail 27/8" 2.313" id WXA Sliding Sleeve 1451.9' 5 Yz" Weatherford Arrowset IX Packer (LH set / RH release) w/ 2.313 X profile located in ou/off tool at 1707.81' Prease see Attachment for 77/8" Hole drilled to 2560', 5 Yz" 17# J-55 LTC set at 2560' MD (TVD) Cemeuted w/21.2 bbls 13.5 ppg lead and 76 bbls 15.8 ppg "G" tail. PBTD at 2512' (Top of Fe) FIGURE I Page 90f9 Lease: Field OCS-G Com an Man Jack McDade Jim Brown Phone I ~ XA Sliding sleeve 2.31X 3.625 2.310 3.12 1310.52 2 7/8 tubing joint 2.875 2.441 31.60 5 112 HRP Hydraulic packer 4.500 2.440 6.30 1345.24 I I ~ Ii R~ 1:1 8J Total Len h of B.H.A.:- 27/8 Tubing 3 jts & 4' pup 2.875 2.441 100.37 27/8 WXA Sliding Sleeve 3.625 2.310 3.12 1451.91 X Profile 2.31 27/8 tubing 8 jts 2.875 2.441 251.78 27/8 On Off tool 2.31 X 4.500 2.310 1.70 1706.81 5 112 Arrowset IX Packer 4.625 2.440 6.97 1708.51 (left hand set/right release) 27/8 Tubing 10 jts 2 7/8 EU- 3 1/2 NU Xover Screen 27/8 EU- 31/2 NU Xover 27/8 Tubing 11 joints 27/8 EU- 31/2 NU Xover Screen 2 7/8 EU- 3 1/2 NU Xover 27/8 Pup Joints, 6' & 10' 2 7/8 EU- 3 1/2 NU Xover Screen 2 7/8-3 1/2 NU X over Bull Plug 2.875 2.441 321.04 4.250 2.440 0.94 2037.46 4.060 2.990 29.66 4.250 2.440 0.50 2067.12 2.875 2.441 347.14 4.250 2.440 0.94 2415.70 4.060 2.990 9.70 2425.40 4.250 2.440 0.50 2.875 2.441 16.30 4.250 2.440 1.06 2443.26 4.060 2.990 30.11 4.250 2.440 0.94 2474.31 Fig u re II 754.13 Date :. 21""JH)5 ENGINEERING ¡M APPING ¡SURVEYING ¡TESTING P.O. BOX 468 SOLDOTNA, AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmclane©n1c1anecg.com PROJECT NO. DRAWN BY: DATE: July 7, 05 053037 MSM MOQUAWKIE NO.3 WELL AS-BUILT SURFACE LOCATION DIAGRAM APPLICANT: SEC. LINE OFFSETS: 2159' FNL 1728' FEL LOCATION: PROTRACTED SECTION 1 TOWNSHIP 11 NORTH, RANGE 12 WEST SEWARD MERIDIAN, ALASKA 2-7/8' ALL DIMENSIONS ARE APPROX. vetcogray" . . C4 A5 A6 -5/8" OD CS'G 5-1/2" aD CS'G SWE & FCE ENGINEERING 9-5/8 X 5-1/2 X 2-7/8 OD,5M MSP ASSY . J ...."".,. ....""...11 1="11 I=" II Bll ACAO II nPAWlN~ "'1'1 AURORA GAS, LLC WELL TEST REPORT Test #: 1 Well: Moquawkie #3 Date: 6/21/2005 T S P k t 2000' 0 rt: r t t d 2039' 2477' est ummary: ac er a ¡pen pe ora Ions es e - DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME PERFS SPYDR, TEMP - 164" PRESS STATIC DIFF TEMP FACTOR Q VOL 6/21/2005 PSIA deQ F psi blue red green MCF/D MCF 20:41 Swab 500' 21:15 715 25 140 1 1.9 7.3 21:20 Choke 29/64 21:30 831 29 180 3.2 3.6 7.1 71.75 826 21:45 825 29 180 3.2 3.4 6.7 790 22:00 820 30 190 3.25 4.2 6.5 979 15 842 30 190 3.3 4.2 6.3 994 30 844 30 190 3.3 4.2 6.2 1,018 45 845 30 190 3.3 4.2 6 23:00 850 30 195 3.3 4.3 5.95 15 852 30 200 3.3 4.2 5.8 30 853 30 200 3.3 4.2 5.8 45 854 30 200 3.3 4.2 5.7 850 23:59 858 30 24:00:00 Shut well in Separator Water vol @ start 5.61 Separator Water vol @ Shut in 11.93 Pit Volume gain 5.5 Total water back 11.82 BBls 1:00 SHUT-IN pressures 964 2:00 965 3:00 969 4:00 968 5:00 969 Pressure on SPYDR 1 min after SI = 923 psi; ten min after SI = 954 psi I I I . . AURORA GAS, LLC WELL TEST REPORT Test: #2 Well: Moquawkie #3 Date: 6/22/2005 T t S P k t 2000 ft 0 P rft 2039' 2477' es ummarv: ac er a . Jpen e 5 - DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME PERFS SPYDR, TEMP - /64" PRESS STATIC DIFF TEMP FACTOR Q VOL 6/22/2005 PSIA dea F psi blue red areen MMCF/D MCF 7:45 Move SPDR to Swab Head 7:45 972 8:03 Start Test 24 8:20 736 32 480 5 6.7 6.4 71.75 2.403 8:30 763 32 480 5 7.5 6.4 71.75 2.691 8:45 730 36 500 5 9.2 6.4 71.75 3.3 9:00 743 36 500 5.2 9.6 6.4 71.75 994 9:05 Changed Orfice to 2" 9:15 750 36 500 5.1 5.4 6.4 131.1 3.61 9:30 752 36 510 5.1 5.45 6.3 131.1 3.643 9:45 752 36 505 5.1 5.5 6.4 131.1 3.677 10:00 753 36 505 5.1 5.6 6.4 131.1 3.774 10:00:00 Shut well in Separator Water vol @ start 12 bbl Separator Water vol @ Shut in 15 bbl Pit Volume gain 3 bbl Total water back 6 bbl 10:00 SHUT-IN pressures 753 10:15 999 10:30 1006 10:45 1009 11:00 1011 . . AURORA GAS, LLC WELL TEST REPORT Test: #3 Well: Moquawkie #3 Date: 6/22/2005 T tS T tp k 2370 ft 0 rfi t d 2414 ft 2477 ft es ummarv: es ac er at Jpen pe orations tes e : - DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME PERFS SPYDR, TEMP - /64" PRESS STATIC DlFF TEMP FACTOR Q VOL 6/22/2005 PSIA deg F psi blue red areen MMCF/D MCF 15:10 Start test 416 28 15:15 Change orifice to 1.5" 28 15:30 437 28 410 4.6 2.3 71.75 0.759 15:45 465 28 410 4.6 2.7 71.75 0.891 16:00 445 28 395 4.5 3 71.75 0.968 16:15 Shut well in. 1080 28 16:30 1130 28 16:45 1141 28 17:00 1146 28 17:15 1148 28 17:30 1149 28 18:00 1150 28 28 28 Separator Water vol @ start 16.97 Separator Water vol @ Shut in 16.97 Pit Volume gain 0 Total water back 0 SHUT-IN pressures 1150 . . AURORA GAS, LLC WELL TEST REPORT Test: #4 Well: Moquawkie #3 Date: 6/22/2005 T t S T t k t 2370ft 0 Ii r t t d 2414ft 2477ft es ummarv: es pac er a Jpen pe ora Ions es e : - DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME PERFS SPYDR, TEMP - /64" PRESS STATIC DIFF TEMP FACTOR Q VOL 6/22/2005 PSIA dea F psi blue red areen MMCF/D MCF 18:00 WellSI 1150 28 71.75 18:20 Open to separator 1150 18:30 556 28 510 5.1 2.5 7.3 71.75 18:40 605 28 520 5.1 3.1 7.2 71.75 18:50 580 28 520 5.1 3.1 7.2 71.75 19:00 587 28 520 5.1 3.2 7.1 71.75 19:15 588 28 520 5.15 3.3 7.05 71.75 19:30 593 28 520 5.15 3.4 71.75 19:45 599 28 520 5.15 3.5 71.75 20:00 606 28 520 5.15 3.6 71.75 20:15 608 28 520 5.15 3.6 71.75 20:30 623 28 520 5.15 3.7 6.95 71.75 20:45 628 28 520 5.15 3.8 71.75 21:00 630 28 525 5.2 3.9 71.75 21:15 636 28 525 5.2 4 71.75 21:30 641 28 525 5.2 4 6.8 71.75 21:45 648 28 525 5.2 4.1 71.75 22:00 657 28 535 5.2 4 71.75 22:15 669 28 530 5.2 4.1 71.75 22:30 667 28 530 5.2 4.1 6.65 71.75 22:45 673 28 540 5.2 4.3 71.75 1.604 23:00 678 28 535 5.2 4.35 71.75 23:15 678 28 535 5.2 4.2 6.6 71.75 23:30 688 28 530 5.2 4.35 71.75 23:45 676 28 530 5.2 4.5 71.75 1.678 0:00 CaNT. on Sheet2 680 28 530 5.2 4.4 6.6 71.75 1.641 . . AURORA GAS, LLC WELL TEST REPORT #5 Test: #5 Well: Moquawkie #3 Date: 6/23/2005 T t S R t' bl b'd t 2004 ft t t k t 1759 ft 0 Ii r t t d 1774 ft 1821 ft es ummary: e neva e n ]Qe PIU a , es pac er a ¡pen pe ora Ions es e : - . DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME PERFS SPYDR, TEMP - 164" PRESS STATIC DIFF TEMP FACTOR Q VOL 6/23/2005 PSIA deQ F psi blue red Qreen MCF/D MCF 11:00 4-swab runs; 7.8 bbl back 11 :10 Shut well in 11 :12 11 11 :15 14 11:30 47 11:45 101 12:00 168 Open to gasbuster 12:15 Swab # 5; .5 bbl 14:00 Swab #6; .25 bbl 14:40 Swab #7; 1 bbl 14:50 Swab # 8; .4 bbl 10.0 bbls back total 16:00 Well flowinQ to Qas- buster @ 40 psi; Shut well in. 16:15 213 16:30 390 16:45 581 17:00 746 17:15 803 17:30 835 17:45 840 18:00 841 18:15 Kill well . . AURORA GAS, LLC WELL TEST REPORT Test#: 6 Well: Moquawkie #3 Date: 6/24/2005 T S R t . bl b'd t 1560 ft t t k t 1365 ft P rf f t t t 1402 ft 1469 ft est ummary: e neva e n ]ge p u a , es pac er a e ora Ions open 0 es: - DATE ACTIVITY I T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME PERFS 1402/1469 SPYDR, TEMP - 164" PRESS STATIC DIFF TEMP FACTOR Q VOL 24-Jun PSIA deg F psi blue red green MCF/D MCF 15:05 Open to test skid 640 12 15:10 6?? 14 15:15 546 14 80 2 1.5 8.2 71.75 215 15:30 470 14 70 1.9 1.3 71.75 177 15:45 408 14 50 1.5 1 71.75 107 16:00 ChanQe orofice to 1.0 369 14 50 1.5 1.9 31.45 16:15 346 14 50 1.5 1.8 7.95 31 .45 16:30 334 14 50 1.5 1.8 31.45 16:45 326 14 50 1.5 1.7 31.45 17:00 320 14 50 1.5 1.6 31 .45 15 316 14 50 1.5 1.6 31.45 30 312 14 45 1.5 1.5 31.45 75 45 308 14 50 1.5 1.6 31 .45 18:00 307 14 50 1.5 1.6 31.45 15 305 14 50 1.5 1.5 31.45 30 300 14 50 1.5 1.5 31.45 45 298 14 50 1.5 1.5 7.7 31 .45 71 19:00 296 14 50 1.5 1.5 31.45 15 296 14 50 1.5 1.5 31.45 30 295 14 50 1.5 1.65 31.45 45 294 14 50 1.5 1.5 31 .45 20:00 293 14 50 1.7 1.5 31 .45 15 Open ck to 32/64 65 32 65 1.7 1.7 31.45 90 30 69 32 50 1.5 1.9 31.45 101 45 56 32 50 1.5 1.8 31.45 84 . . AURORA GAS, LLC WELL TEST REPORT Test: #7-Post Completion Well: Moquawkie #3 Date: 6/27/2005 Test Summary: Production packer at 1707.8 ft. Perforations open to testing: 1774 ft - 2477 ft. DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME PERFS SPYDR, TEMP - /64" PRESS STATIC DIFF TEMP FACTOR Q VOL 6/21/2005 PSIA dea F psi blue red areen MCF/D MCF 5:00 Swab 250' 5:07 To Flare-1.5 Orfice 26 500 5:15 738 26 550 5.2 2.5 7 71.75 932.75 5:30 722 26 530 5.15 2 6.7 71.75 739.025 5:45 812 26 520 5.2 1.5 6.7 71.75 559.65 6:00 803 26 540 5.25 4 6.5 71.75 1506.75 6:17 799 26 550 5.25 4.2 6.4 71.75 1582.088 6:30 810 26 550 5.25 4.3 6.3 71.75 1619.756 6:45 823 26 550 5.25 4.4 6.3 71.75 1657.425 7:00 838 26 550 5.25 4.7 6.3 71.75 1770.431 7:15 847 26 560 5.3 4.6 6.3 71.75 1749.265 7:30 851 26 560 5.3 4.7 6.25 71.75 1787.293 7:45 862 26 555 5.25 4.6 6.25 71.75 1732.763 8:00 Shut In Well 849 5.25 4.7 71.75 1770.431 8:05 987 8:10 999 8:15 1005 8:20 1009 8:25 1009 8:30 1010 Recovered 17 bbl Fluid Final Wt. 10.2 ppg . . ... ~~W1Frl.. .fÄ\.~.I.. LÇ~.'. \ !/!Jì" , ii'li ¡,ï\l!!L. \~ ~i1.J i60a ~ . (ñ'\TlIf? , lip 10u . ,~n 18\ I! iJ " ,~ '.."! '.. ¡ I. ¡ 'I uU~ (rù \~, \\ r¡' U J ~ FRANK H. MURKOWSKI, GOVERNOR A .,ASIiA. OIL Al'O) GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE. SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 J. Edward Jones Executive vice President of Operations and Engineering Aurora Gas, LLC Address1400 West Benson Blvd, Suite 410 Anchorage, Alaska 99503 Re: Moquawkie #3 Aurora Gas, LLC Permit No: 205-080 Surface Location: 1742 FEL, 2169' FNL, SEC 1, TIIN, RI2W, SM Bottomhole Location: 1742' FEL, 2169 FNL, SEC. 1, TIIN, RI2W, SM Dear Mr. Jones: Enclosed is the approved application for permit to drill the above referenced development well. Because of the potential for encountering shallow gas-bearing sands, gas detection, PVT, and mud logging equipment must be fully operational prior to drilling out of the surface conductor pipe. A complete, continuous directional survey will be required for Moquawkie #3 because this well will be less than 200' from Mobil Moquawkie #1. It is acceptable to survey at 500' intervals while drilling and obtain the continuous survey after reaching TD. A spacing exception will not be required to drill and operate Moquawkie #3 so long as the sands open to the well bore are not open to any other well bore within Section 1 of TIIN, RI2W, Seward Meridian or within 3000' ofMoquawkie #3. 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 petroleum field inspector at (907) 659-3607 (pager). " . / mAy DATED this 1~ay ofmont~, 2005 . cc: Department ofFish & Game, Habitat Section wlo encl. Department of Environmental Conservation wlo encl. ·. ~Aurora Gas, LLC ~aurorapower.com May 20, 2005 RECEIVED MAY 2 0 2005 41askB Oil & GlJS C'·.." '. . an::;. ClJmm¡~~$mn Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 9950 I Attn: Mr. Tom Maunder P.E. RE: Application for Permit to Drill: Moquawkie No.3 Dear Mr. Norman: Aurora Gas, LLC hereby applies for a Permit to Drill an onshoré exploration well in the Moquawkie Gas Field of Alaska. The well, Moquawkie No.3, will be located approximately 6 miles due west of Tyonek, Alaska. Aurora Gas, LLC proposes to spud the Moquawkie No.3 on May 26,2005. / No construction other than general leveling and grading of the site is necessary for the location as the well will be drilled adjacent to the Mobil Moquawkie No. I well using the same clearing on the Moquawkie airstrip. The well is being drilled to access known ./ shallow gas reserves in the region that are inaccessible from the Moquawkie No. I well for mechanical reasons. While there are (3) wells total in the vicinity, only Moquawkie / No. I is capable of commercial production. The Simpco Moquawkie No.(s) I and 2 are / both shut in and neither is capable of producing from the proposed production horizon at Moquawkie No.3. For this reason, no spacing exception is required at this time. Pertinent information in and attached to this application includes the following: I) Form 10-401 Application for Permit to Drill- 2 copies 2) Fee of $100.00 payable to the State of Alaska 3) Location As-Staked plat 4) Days vs. Depth drilling curve 5) Drilling Procedure 6) Wellbore Schematic 7) Pressure and casing design and property information. 8) Description of the BOP equipment to be used per 20 AAC 25.035 (a)(1) and (b) 9) Cement program description 10) Drilling fluid program description 10333 Richmond Avenue, Suite 710· Houston, Texas 77042. (713) 977-5799· Fax (713) 977-1347 1400 West Benson Blvd., Suite 410. Anchorage, .Alaska 99503. (907) 277-1003. Fax (907) 277-1006 . . Mr. Norman May 20, 2005 Page 2 11) A summary of potential well hazards. If you have any questions or require additional information, please contact the undersigned at 277-1003, or Duane Vaagen at (907)258-3446 (Fairweather E&P Services, Inc.). Upon approval of this application, please forward a copy of the approved packet to Fairweather's office as well for implementation. Sincerely, /1 s//'ì /~-- / '" / - . _l~.d -"..-? ,/ I G~~ /,/·:l'-~-LL€./r..-- - ./ ,/ '/ j' . ~ / / c·/ {/ Mr. J. Edward Jones Executive VP, Engineering and Operations Aurora Gas, LLC Attachments cc: Andy Clifford Duane Vaagen .. STATE OF ALASKA .. A~ OIL AND GAS CONSERVATION CO~SION PERMIT TO DRILL RECEIVED t~ MAY 2 0 2005 I)Ç 20 AAC 25.005 Alaska nil ft. t::." r'",,,. ~ 1 a. Type of Work: Drill [2] Redrill 0 1b. Current Well Class: Exploratory 0 Devetopment~ ~Y 0 Re-entry 0 Stratigraphic Test 0 Service 0 Development arg~~g~ingle Zone [2] 2. Operator Name: 5. Bond; Blanket [2] Single Well 0 11. Well Name and Number: Aurora Gas, LLC Bond No. NZS 429815 ;' Moquawk.ìe No.3. 3. Address: 6. Proposed Depth: , 12. FìeldlPool(s): 1400 West Benson Blvd, Suite 410. Anchorage, AI< 99503 MD: 2550 ' TVD; 2550 Moquawkie Gas Field 4a. Location of Well (Govemmental Section): 7. Property Designation; /' Surface: -,1742' FEL, 2169' FNL, Sec1, T11N, R12W, SM /' ~1390 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date; Same NIA 5/2512005 Total Depth: 9. Acres in Property: 14. Distance to Nearest Same 640 Property; 1742' section line 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Wen Surface:x- 266421 ~ 2586947.8 Zone- / 4 (Height above GL): 16 feet Within Pool; No Wells y- 16. Deviated wells: Kickoff depth; nIa feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) ft ._ Maximum Hole Angle: o degrees Downhole; /8ßS"" po;t.. Surface: /.$"155 ~i s;. z 3Ô$ 18. Casing Program: Specifications Setting Depth Quantity of Cement Size Top Bottom c.f.orsacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 11 7/8" 71.8 P-110 welded 80+ 0 0 80 80 nIadriven 10 518" 8 518" 32# WC-50 STC 614 0 0 630 630 264ft3 7 718" 5112" 17# J-55 LTC 2534 0 0 2550 2550 527 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft); Junk (measured): Casing Length Size Cement Volume MD TVD Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee 0 BOP Sketch 0 Drilling Program 0 Time v. Depth Plot 0 Shallow Hazard Analysis U Property Plat [2] Diverter Sketch [2] Seabed Report 0 Drilling Fluid Program [2] 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Mr. J. Edward Jo~ Title Executive Vice President of Operations and IËngineering ~. / ~h. __ _)"~~AJ fð 7-Z77- /003 ,~ Signature Phone 7/) - 977- 574'4' Date 5/k/ðS // // Commission Use Only Permit to D~ AF[:~ber: Permit Approval See cover letter for other Number: 26S' -ó£::é> / 5O-~- 2.D1 ((,.. 60 Date: Ç"hr~<:- requirements. ~~.d_ ~ . Samplrequi Yes 0 No j§;( Mud log required Yes :ø: No 0 ~¡iYd n su measures Yes 0 No.8 Directional survey required Yes ~ No 0 Other. ~~Ç><:' \'. ..\--. \..o<--'-o.~ I:....,'.&-~~\..:>~.-S;:O \";,\\v. \"m ~ ~ . ( 'F BY ORDER OF ð/:..rí.r Approved b~...J f;,( , ".lfI¡;,cqMMISSION Date: . . t.- , 0 FO~ 1m'OO~ -- 'i '¡ 1,1 \1 ;.\ t_ I SylSmit inDu,plicate :/ ENGINEERING/MAPPING /SURVEYING /TESTING P.O. BOX 468 SOLDOTNA. AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmclane@mclanecg.com PROJECT NO. 053037 DRAWN BY: MSM DATE: May 19,05 SEC. LINE OFFSETS: 2168' FNL 1742' FEL LOCATION: PROTRACTED SECTION ·1 TOWNSHIP 11 NORTH, RANGE 12 WEST SEWARD MERIDIAN, ALASKA . . Well Information for Permit MOQuawkie No.3 The Moquawkie No.3 will be a new grass-roots ~ell drilled in the Moquawkie Gas Field. The Moquawkie NO.3 will be drilled on the north end of the Moquawkie Airstrip and adjacent to the Moquawkie No.1 well. / Moquawkie NO.3 will be drilled to access shallow gas reserves that are not / accessible from the Mobil Moquawkie No. 1 well for mechanical reasons, i.e. behind (2) strings of casing. The proposed production horizon will be the Beluga " formation. The proposed depth for the Moquawkie NO.3 will be 2550 ft MD & TVD. This depth, while deeper than the shoe of the Moquawkie 1 surface casing shoe at 2455', is necessary to provide rat-hole for logging, perforating and completion operations. / Estimated Spud date is Thursday, the 26th of May, 2005. / Drilling Program: Moquawkie No.3 1. File and insure all necessary permits and applications are in place. 2. Install drive shoe and drive 11 7/8" 71.8 Iblft USS structural conductor to 80 feet or refusal. ,. 3. Cut conductor at elevation which will allow top of starter head to be at ground level when installed. Pusher and Company man to verify correct cut-off height prior to cut to insure sufficient clearance for diverter line after installation. Install 13 3/8" 5M starter head. 4. Install Cellar box, move in and RU rig. 5. Rig up diverter (see attached diagram) and mud loggers. Test and / calibrate all PVT and gas sensor equipment/' 6. Notify AOGCC and pertinent agencies when ready to start drilling operations. 7. Prepare spud mud system, weight up to -9.8 ppg. " 8. Drill 10 5/8" hole to -630 ft, using 10 5/8" mill-tooth bit with 6 ~" stabilized BHA). Watch for gas in shallow coals and sands. Incrementally increase v mud weight as needed to (10.5 ppg) and keep fluid loss < 5. Note: Increase mud weight as needed and determined by hole conditions. It is estimated that mud weights will be in the 9.8 - 10.5 ppg range by the time surface hole TD's at 630'. Maximum pressure gradient for this interval is estimated to be .49 psilft, which equates to 9.5 ppg mud. / 9. Perform wiper trip to surface and condition hole for running 8 5/8" surface casing, POOH, LD 105/8" stabilizers and rack back remaining BHA. 10. Run and cement (new) 8 5/8" 32 #/ft, WC-50 STC surface casing at 630 ft and cement to surface. Cementing will be single stage with float collar and shoe installed using 14.5 ppg gas-block type cement slurry. Centralizers will be run as follows: One centered on shoe joint, and one Moquawkie NO.3 MOO 3, rev2 052005 Page 1 of 10 . . centered on each joint of casing above for a total of (4). Cement volumes to be adjusted to include 100% excess. 11. RU and test 11" 3M BOP stack and 5M choke manifold. Test BOP rams to 3000 psi, annular to 1500 psi and choke equipment to 3000 psi. Pressure test casing to 1500 psi. or other as required on approved permit. 12. PU 77/8" mill-tooth bit, RIH with 6 %" stabilized BHA and 3 %" DP to float collar. Drill out float equipment and shoe. Drill -20' OH. Pull back into shoe and perform FIT with MWE to 16 ppg, record results. 13. Condition and circulate mud system, While drilling 7 7/8" hole, mud weight requirements may vary from 10.5 - 14.2 ppg. Optimal mud weight ,- required to be dictated by drilling characteristics. Do not exceed fracture gradient determined in step 10! 14. Proceed to drill ahead, 7 7/8" hole. Monitor well and volumes carefully. Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. 15. Drill to TO at 2550 ft maximum. 16. Short trip and condition hole as needed for running wireline logs. 17. POOH, rack back drillstring and RU wireline BOP's, lubricator and logging tools. Log cased hole section (surface) wlgamma ray sensor, log OH section with logging suite 18. RD wireline, RIH with drilling BHA as before to TO. Circulate and condition hole for running casing. 19. INSURE all cementing equipment, casing accessories, and casing running equipment is on location and functional. POOH, LD Stabs, jars and 6 %" drill collars, rack back DP and 4 %" drill collars to save time. 20. RU casing equipment I crew, make up shoe joint with shoe and float collar, baker-locking both to joint during make-up. Install 5 1/2" pipe rams for casing. 21. RIH with (new) 5 %" 17 #/ft J-55 L T&C casing, installing centralizers per attached program. Run casing to -2550 ft, or as determined by OH logs. Keep pipe moving when casing is at TO and while waiting for cementers to get hooked up. Do not run casing until all cementing equipment is on site. 22. RU cementers, cement per attached cementing program from TO back to surface. A -13.5 ppg Lead system, 14 ppg spacer and 15.8 ppg Tail cement system will be used as primary system with Tail volume to be sufficient to extend above the shallowest potential production zone at 630'. While pumping cement, reciprocate pipe a minimum of 20 ft until displacement is finished. Land casing and WOC. 23. RD cementers, check annulus and casing for pressure. Drain and nipple down stack and cut casing. 24. Install 11" X 7 1/16" casing head, 7 1/16" X 11" DSA, mud cross and reinstall BOP stack. Pressure test BOP and surface equipment to 3000 psi. Pressure test casing to 1500 psi. PU bit and casing scraper, RIH with DP to top of float collar. Circulate out mud and cement with high-vis sweeps as necessary. Swap mud system over to clean filtered KC!. POOH LD DP and casing scraper. Moquawkie No.3 MOQ 3, rev2 052005 Page 2 of 10 . . 25. RU lubricator for wireline work. Change out 3 ~" pipe rams with rams for 2 7/8" work string. Pressure test all. 26. RU and RIH wI CBL over intended production interval (TBD based on OH logs. POOH. 27. Perforate intervals determined to be pay based on logs obtained after drilling. Perforating to be performed using either TCP or WL conveyed guns. 28. RIH wI casing scraper over perforated interval. 29. RU and RIH with test packer on workstring. Connect to surface flow test equipment. Swab in well for flow test, record results. Kill well. 30. Repeat steps 27 - 29 until sufficient intervals have been penetrated for production. 31. POOH, RD wireline. Prepare completion assembly. 32. PU and RIH wI sand exclusion screen on bottom of retrievable packer, install sliding sleeve 1 jt above packer and set roughly 75 ft above upper most open perforation. Install blanking plug in profile nipple, Pressure test tubing to 2000 psi. Open sliding sleeve, circulate tubing I casing annulus with inhibited packer fluid and freeze protect surface with diesel. Close sliding sleeve. Re-pressure test tubing and pull profile plug. 33. Install BPV at surface, nipple down and remove BOP stack, install and NU wellhead tree. Swab in well, get flow rates, record pressures. 34. Install BPV, RD and release rig. 35. Prepare site for well testing and surface production facilities. 36. File completion reports with proper agencies. Site Access: Moquawkie NO.3 will be accessible via existing gravel roads currently in use to support production operations at the Moquawkie NO.1 site. Rig: Aurora Well Service, Rig NO.1 (AWS 1) will be used to drill the Moquawkie No.3 well. The Alaska Oil and Gas Conservation Commission has information on this equipment as it has been in use for the last (3) years on other ~ Aurora Gas operations. The pits, BOP system and mud equipment configuration will be similar to that used for previous work. Pressure I Temperature Considerations: Estimated reservoir temperature ranges from 85 - 95 degrees Fahrenheit. / Survey Program: The Moquawkie NO.3 well will be drilled as a vertical well. / Wellbore surveys will be obtained at 500' intervals in accordance with rules laid out in 20 MC 25.050 (a) (1) & (2). Logging Program: Aurora will have mud loggers on site for the duration of -' drilling activities. Schlumberger will provide wireline logging services and will run their Platform Express suite in open-hole and a CBL will be run in the 5 ~" cased hole prior to perforating and testing. A gamma ray log will be obtained to surface while logging out of the hole on one of the Platform express runs. Moquawkie No.3 MOQ 3, rev2 052005 Page 3 of 10 . . Drilling Fluids: The drilling fluids are being furnished by Baroid Drilling Fluids. . An experienced mud engineer will be on site at all times while drilling to monitor mud rheology and make recommendations. BOP Equipment: Aurora Gas, LLC will use the same BOP system they have been using for the last (3) years which will consist of the following: 10 5/8" surface hole: While drilling the 10 5/8" surface hole, a 13 5/8" 5M annular w/ 13 5/8" diverter spool and 10" diverter line will be used. Information on this system is already on file at the AOGCC. 7 7/8" Production Hole: An 11" (3M) BOP system will be used which is configured with an 11" 3M annular preventer, (1) 11" 3M double gate with a set of blind rams and one set of pipe rams sized to fit the pipe being run installed as well as an 11" 3M drilling spool., BOP tests will be performed to 3000 psi. The annular preventer will be tested to 1500 psi. Again, this is the same equipment Aurora has been using all along and information on the system is on file at the AOGCC. DrillinCl Fluid Properties While DrillinCl Surface 10 5/8" Hole Section to 630': Beluga Formation Base Fluid 5% KCL Density 9.8 - 10.5 ppg PV 22 - 30 YP 20 - 30 API Filtrate < 5 Total Solids 15 - 25 % or less Gel & Polymer mud system DrillinCl Fluid Properties While DrillinCl 7 7/8" Hole Section to 2550': Beluga and Tyonek Formations Base Fluid 5% KCL Density 10.5 - 14.0 ppg ". PV 22 - 30 YP 20 - 30 API Filtrate < 5 Total Solids 15 - 25 % Polymer mud system DrillinCl Fluid HandlinCl System: Shale Shaker, Desilter, PVT monitors " Moquawkie No.3 Moa 3, rev2 052005 Page 4 of 10 . . Casing / Cementing Program: All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. All casing strings with the exception of the driven 11 7/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment and wiper plugs and centralizers installed as needed. MOQuawkie No.3. 11 7/8" 71.8# LSS Conductor Analvsis and CementinQ ProQram The conductor for the Moquawkie No.3 will be driven to - 80' or refusal. Joints /' will be welded and a drive shoe will be welded to the bottom joint. No cementing is required. MOQuawkie No.3. 8 5/8" 32# WC-50 STC Surface CasinQ Analvsis and CementinQ ProQram The 8 5/8" surface casing will be cemented in fully from the proposed set depth of 630' to surface with a 14.5 ppg Gas-Block type cement system. The system will consist of a spacer followed by the cement. Cement System Gas-Block enhanced Weiqht (ppq) 14.5 /' Volume Required 49 bbls @ 100% Where: 105/8" OH Capacity = .1097 bbllft 85/8" 32# Csg x 105/8" OH capacity = .0374 bbllft 8518" 32# Csg capacity = .0609 bbllft » OH x Csg: 630 ft x .0374 bbl I ft x 100 % excess = 47 bbls » Shoe Jt: 35ft x .0609 bbllft = 2. 135 bbls Actual volumes to be re-calculated at time of running casing due to potential ,/ variation in actual depth from planned. The surface cement system to utilize a Gas-Block type additive to minimize potential for gas entrainment and or channeling. MOQuawkie No.3. 5 1/2" 17# J-55 LTC Production CasinQ CementinQ ProQram The 5 1/2" production casing will be cemented in fully from proposed set depth of 2550' to surface. Cementing will consist of pumping a spacer followed by 13.5 ppg lead "G" cement followed with a 15.8 ppg "G" tail cement system. This program is designed to insure the intended perforating I production intervals up to 630' are isolated with 15.8 ppg "G" cement. Moquawkie NO.3 MOQ 3, rev2052005 Page 5 of 10 . . Cement System Type Cement Weiqht (ppq) Volume @ % Excess Lead "G" 13.5 20 bbls @ 0.0% CH Tail "G" 15.8 74 bbls @ 25% OH Total Vol = 94 bbls Where: 5~" 17# csg capacity = .0232 bbllft 5 ~"17# csg X 7718" OH capacity = .0309 bbllft 5~" 17# csg X 8518"32# annular capacity = .0316 bbllft 5~" 17# csg displacement = .00614 bbllft Lead System: 8 5/B"CH x 5 ~"Csg: = 630ft 630ft x .0316 bblslft x 1 (0% excess)=20 bbls Tail System: 7 7/B"OH x 5 ~"Csg: 2550ft - 630ft = 1920ft 1920ft x .0309bbllft x 1.25(25% excess)= 74 bbls Shoe Joint = 35' x .0232 bbllft = .812 bbls Total Tail Cmt Volume = 74 bbls Actual volumes to be re-calculated at time of running casing due to potential variation in actual depth from planned. MOQuawkie No.3 Pressure Considerations The Moquawkie No.3 well is being drilled to access shallow gas zones that are inaccessible from the nearby Moquawkie NO.1 well for mechanical reasons.; The drilling records for the Moquawkie No.1, document problems encountered which must be considered for safely drilling the Moquawkie No.3 well. After drilling the Moquawkie NO.1 well to 1525 ft with 10+ ppg mud, the well was swabbed in while POOH for a trip. A blowout occurred at 1525' and the rig caught on fire. Drilling mud weighted to 18+ ppg was used to kill the well by pumping in at the surface. The well control issues were worsened by the fact that they were drilling with a 36" currogated conductor set at 29' and no diverter. After the well was killed, it was discovered the well had bridged off shallow, the well was cleaned out to 216' using 11.36 - 14.7 ppg mud and a 20" conductor was installed. The well was then safely drilled to 2455' using 14.2 ppg mud ...- before running the next string of casing. .é:-I '" The 14.2 ppg mud equates to a pressure gradient of .74 psi / ft. Assuming an overbalance condition of 1 ppg was maintained while drilling, it would appear that the pore pressure for the interval approaches a MWE of 13.2 ppg, or .686 psi/ft. Moquawkie No.3 Moa 3, rev2 052005 Page 6 of 10 . . Maximum Anticipated Surface Pressure The maximum anticipated surface pressure (MASP) for this well can be calculated by subtracting the gas gradient from the predicted pore pressure for the TVO depth at TO. Using a pore pressure gradient of .7 (conservative estimate) and a gas gradient of .11, the MASP can be calculated as follows: Gas Gradient - .11 . . '" /8SS- ' B~ glJ Pore Pressure Gradient -.7 / ¿SÇDf"~'- ~ o. 7JB' ~b /S.Z-3·6::: => Maximum anticipated Surface Pressure = Oepth(tvd) x (PPG - GG) => 2550 x (.7 - .11) = 1505 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 lubricator 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, caution needs to be exercised to control and monitor pressures should the PPG be higher. In the event pore pressures exceed 12.5 ppg MWE, Aurora Gas, may elect to use TCP guns instead of the wireline perforating assembly. DrillinQ Fluid HandlinQ System: AWS #1 Pit System, Shale Shaker, Oesilter, PVT monitors Moquawkie NO.3 MOQ 3, rev2052005 Page 7 of 10 . . Moquawkie No.3 Summary of Drilling Hazards THIS NOTICE TO BE POSTED IN DOGHOUSE -v There is potential for abnormal pressured shallow gas. / -v There is potential for stuck pipe in coals encountered while drilling from surface to TO. Be extra vigilant, keep pipe moving and maintain mud properties per direction of on-site mud engineer. ./ -v There is no H2S risk anticipated for this well. / -v Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. ./ CONSULT THE "MOQUAWKIE NO.3" WELL PROGRAM FOR ADDITIONAL INFORMATION. ¿-~Aurora Gas, '-'-C Moquawkie No.3 MOQ 3, rev2 052005 Page 8 of 10 Moquawkie No.3 As proposed Drill 105/8" Hole 2 7/8" X 5 Yz" annulus displaced wi O2 inhibited brine from surface to top of packer. spaced out to cover productive intervals. Drill 7 5/8" TD @ 2550' 5 Y2" 17# LTC J.55 Casing to 2550' and cemented in place from TD to surface wi 83 bbls total iIlcludiIlg 25% excess over OH interval. Moquawkie NO.3 MOQ 3, rev2 052005 27/8" 6.5# 8 Rd J-55 Tubing 11 7/8 driven 8 5/8" 32# Cement wi 14.5 excess, cement wi 2.313" X-Profile 5 Yz" Retrievable profile crossed over to BulJplug pipe. PBTD est. at ~241 0' . . ~Aurora Gas, LLC o 100 200 300 400 500 600 700 800 900 1000 1100 1200 - = 1300 - C 1400 :æ: 1500 s:. õ.. 1600 CI) C 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 Moquawkie No.3 Days vs. Depth Days From Spud \ I I I ! \ 105/8" Hole to 630', Set / cement 8 518· surface casing at I \ 630. NU BOPE, P-test, Drill out and FIT to 16 ppg MWE \ I 1 I I I I 1\ II \ \ I ! \ 1\ I í I I 1 TO @ 2550', Condition hole, run OH logs, -1 Run 5 1/2" casing and cement. Perforate, 1. \ test and comple well. 1\ I I \ i \ , \ 1\ I, I I I I 'p , ~ 3 :'I t> 5 , HS ~ ~ lJ ,(, :' ,(, I ¿;j ¿ Ii' Moquawkie No.3 MOQ 3, rev2 052005 Page 10 of 10 . WelllD Aurora Gas, LLC Moquawkie No.3 Min. Safety Factors To Be Used: Body Yield: Jt. Strength: Collapse Collapse While Cementing Top Burst Bottom Burst Casing Properties: Size aD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth FIT TEST OR TD Depth Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in> 8 5/8 WC-50 32.00 STC 630.00 (ft)MD 2550.00 (ft)MD 650.00 (ft)MD 7.796 0.352 Formation &Fluid Properties: Material Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Point Est. Pore Pressure Gradient @ Shoe Est. Pore Pressure Gradient @ Next Csg pt. Gas Gradient (psi/ft) Mud Backup Gradient ppg 1.5 1.8 1.5 1.5 1.1 1.1 . 8 5/8" Surface Casing 630.00 (ft)TVD 2550.00 (ft)TVD 650.00 (ft)TVD 2440.00 3600.00 341.00 457.00 341,000.00 * Tensile Limits 457,000.00 * Tensile Limits Weight ppg Gradient psi/ft 10.50 14.20 0.84 15.8 8.94 16 16 13.2 13.2 8.95 0.546 psi/ft 0.738 psi/ft 0.822 psi/ft 0.465 psi/ft 0.832 psi/ft 0.832 0.686 0.686 0.110 0.465 55 0.55 . . Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 20,160.00 16,923.30 Maximum setting depth (ft) 10,656.25 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor (At proposed depth) Body Yield Safety Factor (At proposed depth) 16.91 In Air: = Jt Strength / (Wt ppf * set depth) 22.67 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 19.81 Collapse Res / (Depth TVD' % Fluid Drop '(Mud S-up Grad - Gas Grad)) Cûllapse SF while cementing 10.87 Coiiapse Res I üepih Tv'ü '(Cmt Graá - B-up Muá Graá) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by uSing anticipated frac gradient and pore press gradients at shoe with TD(TVD) of next hole section for MASP calculations MASP (Maximum Anticipated Surface Pressure using Frac Grad) MASP (Maximum Anticipated Surface Pressure Using Known Area Pore P) Top Burst Safety Factor (Based on most realistic MASP above) Bottom Burst Safety Factor 1,841.10 (Frac Grad - Gas Grad)' Next Casing Set Depth TVD ./ 1,469.82 (Pore Press Grad - Gas Grad)' Next Casing Set Depth TVD ./ 2.45 Tube burst rating / ASP 2. 11 (Int. Yld + Depth TVD ' Seawater Grad) I ASP Summary of: 85/8 Safety Factors Body Yield 22.67 in air "Tensile" Joint Strength 16.91 in air "Tensile" Collapse 19.81 Collapse 10.87 while cementing Top Burst 2.45 Bottom Burst 2.11 OK OK OK OK OK OK WelllD . Aurora Gas, LLC Moquawkie No.3 Min. Safety Factors To Be Used: Body Yield: Jt. Strength: Collapse Collapse While Cementing Top Burst Bottom Burst Casing Properties: Size aD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth FIT TEST OR TD DEPTH NIA Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness in Formation & Fluid Properties: Material 11 7/8 P-110 71.80 Welded 80.00 (ft)MD 630.00 (ft)MD (ft)MD 10.625 0.58 Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Point Est. Pore Pressure Gradient @ Shoe Est. Pore Pressure Gradient @ Next Csg pt. Gas Gradient (psi/ft) Mud Backup Gradient ppg 1.5 1.8 1.5 1.5 1.1 1.1 . 11 7/S" Conductor 80.00 (ft)TVD 630.00 (ft)TVD NIA (ft)TVD 5290.00 9430.00 1988.00 2271.00 1,988,000.00 * Tensile Limits 2,271,000.00 * Tensile Limits Weight ppg Gradient psi/ft 9.30 10.50 0.86 14 8.94 13 16 8.4 20 8.95 0.484 psi/ft 0.546 psi/ft 0.728 psi/ft 0.465 psi/ft 0.676 psi/ft 0.832 0.437 1.040 0.110 0.465 55 0.55 . . Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 5,744.00 4,927.19 Maximum setting depth (ft) 27,688.02 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor (At proposed depth) Body Yield Safety Factor (At proposed depth) 346.10 In Air: = Jt Strength / (Wt ppf * set depth) 395.37 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 338.29 Collapse Res I (Depth TVD' % Fluid Drop '(Mud Soup Grad - Gas Grad)) Coiiapse SF whiie cementing 251.81 Collapse Res I Depth TVD' (Cmt Grad - Soup Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psi/f! for burst design purposes Assume worst case by using anticipated frac gradient for TD of next hole section (TVD) for MASP calculations 454.86 (Frac Grad - Gas Grad)' Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 20. 73 Tube burst rating I ASP Bottom Burst Safety Factor 20.81 (Inl. Yld + Depth TVD ' Seawater Grad) I ASP Summary of: 11 7/8 Safety Factors Body Yield 395.37 in air "Tensile" Joint Strength 346.10 in air "Tensile" Collapse 338.29 Collapse 251.81 while cementing Top Burst 20.73 Bottom Burst 20.81 OK OK OK OK OK OK . WelllD Aurora Gas, LLC Moquawkie No.3 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.1 Bottom Burst 1.1 Casing Properties: Size aD: Grade: \NAinht nnf· ........~........,..,. Coupling: Set Depth ft Next Casing Depth FIT Test Depth Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness in 5 1/2 J-55 17.00 LTC 2550.00 (ft)MD 2550.00 (ft)MD 2550.00 (ft)MD 4.767 0.304 Formation & Fluid Properties: Material Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Set Point Est. Pore Pressure Gradient @ Shoe Est. Pore Pressure Gradient @ Next Csg pt. Gas Gradient (psi/ft) Mud Backup Gradient ppg . 5 1/2" Production 2550.00 (ft)TVD 2550.00 (ft)TVD 2550.00 (ft)TVD 4910.00 5320.00 247.00 273.00 247,000.00 * Tensile Limits 273,000.00 * Tensile Limits Weight ppg Gradient psi/ft 14.20 14.20 0.78 15.8 8.94 16 20 13.2 18.5 0.738 psi/ft 0.738 psi/ft / 8.95 0.822 psi/ft 0.465 psi/ft 0.832 psi/ft 1.040 psi/ft 0.686 psi/ft 0.962 psi/ft 0.110 psi/ft 0.465 psi/ft 55 0.55 . . Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 43,350.00 33,937.61 Maximum setting depth (ft) 14,529.41 In Air; = Jt Strength I Wt.ppf Joint Strength Safety Factor (At proposed depth) Body Yield Safety Factor (At proposed depth) 5.70 In Air: = Jt Strength I (Wt ppf * set depth) 6.30 In Air: = Body Yld I (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 9.85 Collapse Res I (Depth TVD . % Fluid Drop ·(Mud B-up Grad - Gas Grad» Collapse SF whiie cementing 5.41 Collapse Res I Depth TVD . (Cmt Grad - B-up Mud Grad) No lost CirCulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psi/ft for burst design purposes Assume worst case by using anticipated frac gradient and pore press gradients at shoe with TO (TVD) of next hole section for ASP calculations 1,841. 10 (Frac Grad - Gas Grad)· Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure Using Frac Gradient @ TO) MASP (Maximum Anticipated Surface Pressure Using Known Area PP) Top Burst Safety Factor (Based on Most Realistic MASP above) Bottom Burst Safety Factor 1,469.82 (Pore Press Grad - Gas Grad)· Next Casing Set Depth (TVD) 3.62 Tube burst rating I ASP 3.34 Using PP 3.53 (Inl. Yld + Depth TVD . Seawater Gré 4.43 Using PP Summary of: 51/2 Safety Factors Body Yield 6.30 in air "Tensile" Joint Strength 5.70 in air "Tensile" Collapse 9.85 Collapse 5.41 while cementing Top Burst 3.62 Bottom Burst 3.53 OK OK OK OK OK OK Permit to DrilI Moquawkie NO.3 MEMO_ ---- ". 0 0 2 2 (; q". .: ¡ 25 2000 (;0.: 3020 3Bq 1'" . . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/P ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ¡t(~tuUù.b~ .3 PTD# 7-D5 - 0 '6'6 CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI The permit is for a new wellbore segment of LATERAL existing well_, Permit No, API No. . (If API number Production should continue to be reported as last two (2) digits a function of the original API number stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(1), all (PH) 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). SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE 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. Rev: 04/01105 C\jody\trans m ittal_ checklist 0.:J.,..- J Jd -f~ tL+to~ f(~. f. II ..~V~ L i- ~ -f -ró-tt/\J.- I ~ U ~.f lÞk~ ~~ ~,~ ~ -to 6!v-;{r- <Î~r~':D Unit Program EXP On/Off Shore On Field & Pool MOQUAWKIE, UNDEFINED GAS - 528500 Well Name: MOQUAWKIE 3 PTD#: 2050800 Company AURORA GAS LLC Initial ClassfType EXP / PEND GeoArea 820 1 P~rmitfee attach~_ . _ . _ . _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ . _ _ _ . . 2 .Leas~ .number .appropriate_ _ _ . _ _ _ . _ _ _ Y~s _ _ . _ _. CIRJ l~a~eC-Oa1390_. Aurprahas filed proper OWl1er~hip_& de_sigoatipo ofoperator fprms~ . 3 _UJlique weltnam~_aod o~mb_er _ _ _ . _ . _ . _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ . _ _ . _ . _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 4 WeJlJocat~d in.a_d_efil1e~Lpool . _ _ _ _ _ _ _ _ _ . . . No_ _ _ _ _ _ _ Moquaw~ie ul1defjned ga~ popt . 5 WeJlJocat~d pr_oper _distance_ from driJling ul1itb9Ul1d_ary _ . _ _ . _ . Yes _ _ _ _ _ _ Conforms to 29 _MC2_5,055(a)12): -:174Q' from lease (aod_ ~eçtioJl) bo_uodaJ)'. 6 WellJocat~d pr_oper _distance from otber welJs _ _ _ _ _ _ . . Y~s . _ . . Reservoir sands will be shallower thao, _atld separ_ateJrom, those_ opeD to_Mo_quawkje_#_1_&_ SimPGo. MOq_uawkje #2, 7Sufficiel1tacrea9-e_ayailable In_drilliog unit _ _ _ _ . Y~s _ _ _ _ _ _ . _ _ _ _ _ _ _ _ . . . _ _ _ . . . . . . _ . _ _ _ _ 8 Jfdeviated, is weJlbore plç¡til1cJu_ded _ _ _ _ _ _ _ _ _ _ . _ _ . NA _ _ PIç¡l1n_ed to_ be_a_ v~rtiçal welJ. . . _ . _ _ _ _ . . 9 Operator ol1l~ affected party _ . _ _ _ _ _ _ _ _ _ _ _ _ . Y~s _ _ _ _ _ _ _ _ . . . _ _ . _ . _ _ _ 10 _Operator bas_apprppriate.botld inJorce _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ . Y~L _ _ _ _ _ _ Le_tterof Cre_dLL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 11 P~rmit cao be iss~ed witbout conserva_tiOI1 order. _ _ _ _ _. _ _ _ _ _ _ _ . . . Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ Appr Date 12 P~rmitc.ao be issu_ed wjtbout ç¡qmil1istrative_apprpval . _ _ . _ . _ . _ . Yes _ _ _ _ _ _ _ _ . - - . - . - SFD 5/24/2005 13 Can permit be approved before 15-day wait Yes 14 WellJocated withil1 area al1d_strç¡taauthorizeq byJojectipo Ord~r # (putlO# in_c_omm~otsUFor_ NA _ _ _ _ _ . _ _ _ . 15 AJlwelJs-,,.titniJlJl4JTJile_area.ofreyiewid~otified(Fpr~eNjcewellOI1I~L _ _ _ _ _. _ _ _ _ _. _ _ NA _. _.. _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ 16 Pre-produ_ced iojector; _duratio_n_of pre-productiol1 I~s~ than 3 mOl1ths (For_service well onJy) _ _ NA _ . . . _ _ _ 17 ACMPF'il1djngofConsisteOGyhasbeeni~suedfortbispr_oleçt_ _ _ _ _ _ _. _ _ .. NA.. _... .Prpposedlie_swjtbiocoa.stalzone,.butACMfJreviewdoe_s.noUmpact<lpprovç¡Lofç¡permitto_drill. Administration Engineering Appr Date TEM 5/25/2005 ~~?)J\ Geology Appr SFD Date 5/24/2005 Geologic Commissioner: Drs Well bore seg Annular Disposal . 18 _C90du_ctor stril1gprovided . . Y~s _ . . _ _ _ _ _ _ _ _. _ _ _ . . . 19 _Sw:face_cç¡~il1g_protecJs_ alLkJlown USDWs _ . . . . . . . . . . . . . . . . . _ _ _ _ _ _ . . . _ . Yes _ _ _ Surface and_produGtipo casjngwiILprotechI1Y_F'W sands. Based 011 area drilling, gas couJd_bepresel1tat 20 _CMTvoladeQuatetocirc.ulate.o_n.cOl1d_uctor_&su_rf_csg _ _ _. _ _. . yes.... _ _ _ .or.near.the_swfac_e_cç¡sil19-s_hoeat-63Q'. _ _ _ _ _ _. . _ _ _ _ _. _ __ 21 _CMT v.ol adeQu.ateto tie-in Jong .striog to_surf Ç&g_ Yes _ _ _ Prpd~ction c.asiog is plaOl1edto Gemented to surface, . . . . . . . _ _ 22CMTwill Goyera]l koownpro_duGtiye borizon_s_ _ . _ . _ _ _ _ _ _ . . Yes _ . _ _ _ _ _ _ _ _ . . _ _ _ _ _ . . . _ . _ ,23 .C_asiog de_slgos ad_equaJe fpr C,T, B& permafr9st _ _ _ _ . . . . _ Yes _ _ . . _ _ _ _ _ _ _ . . . . . . . _ _ . . . . . . . _ _ _ . 124 Adequatetan_kç¡geor re_seIYe pit. _ . _ _ _ _ _ _ _ _ _. ..... Y~s . . Rig is_equippedwith $teeLpjts.Altho~gn relatiyely small, ,/\urora_hç¡~ ~ucce_ssfullydrilJedsimila( weJls . 25 Jfare-drilt has a to,403 for abandonmeJlt be~o approved. _ . . . . . . .NA . . . _ _ . . . . usjng Jhi~ ri9-. _Qrilliog waste likely han_dled yia_EJlvirotecb._ _ _ _ . . _ _ 26 _Adequatewellbore~eparatioJl_proposed_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ Y~s_ _ _ _ _ _ _MOquaw~ie#tweIL2PO'_d[stantatsyrtace.J30thwellspla0l1ed_asstrai9-hLSeyere_aogleoeeded_for_collisiol1_ __ 27 Jfdiverter required, does it meet reguJaJiOl1s_ _ _ _ _ _ _ _ _ . . . . . . _ _ . . . . . . . . Yes. . . _ _ . . PlalJ is for _1 0-5/_8'~ hoJe with.1P'~ line.. This ç¡rra_ngement bas_beel1 approyed_ previosly._ 28 DriUiogfJuidprogramschematic_&eCl-uipJistadequate_ _.. _... _ _ _ _ ...... Y~s.. _ _ .Mç¡ximumexpecteqfp(TT)aii0l1pre~sure_upto_t3,5_EMW. PlaOlJe_d_MW_upto_t4.0_ppg._ 29 _BOPEs,_d_o_they meetreguJatiolJ . . . _ _Y~s _ _ _ . . _ _ _ _ _ _ _ . _ _ _ _ . _ _ _ _ _ 30 BOPEpress raiiog approp(Îate;JesHoJpuJ psig in_commel1ts)_ . _ _ _ _ _ _ _ _ _ _ . . . Y~s _ _ M,/\SP calGuJatedat 15.05 psi. 30QOpsiBQp testproposed._ 31 _CMke_manjfold compJie~ w/APIRfJ-53 (May 84) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ _Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ _ . . 32 Wor~ will OGc_ur withoytoperç¡tioJl_sbutdown_ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 33 J~pre~ence.ofH2Sgas_probable_ _ _ _ _ _ _ _ . _ No_ _ _ _1::I2Shas_notbeelJreportedjn_ga$prodYcedwjtho_utoil. Ri9-isequipedwithse_nsorsal1d_aJarms'- _ _ __ 34 Mechanicç¡LCOlJditioo pf weJls withil1 ,/\OR verified (for service welJ onJy) _ _ _ _ _ _ . _ . . _NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . . . . . _ . - - - - - - - - - 35 Permit c_ao be iss~ed w!o hydrogen sulfide meaSJJres _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . . . Yes _ . _ _ _ _ _ l'Jon_e_noted in_offset welJ Moquawkie #1. Np recprd_of H2S in shallow sands intbis ç¡reç¡._ _ _ _ _ . 36D_atapreseoted on_ pote_ntial pverpre~sure _ZOl1e$ _ _ _ _ _ . . . _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ Offset well Moquawkje_#1_bJew_o_ut aU 525~ MD, GaughHire, damaged_ the (i9-, &il1jured 4. _PressJJre _ _ _ _ _ _ _ _ 37 _Sei'sJ)1ic_aJlalysjs_ of shaJlow gas_zpoes _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ co_nsideratiotls se_ction_s_uJ)1m_arizes thjs_ iocidetll _Summary_of DrilUn.9_Hazards disc_us~es mitigatioJl measures, _ _ 38 _SeabedcOl1ditipo survey -Of off-shpre) _ _ _ _ _ _ _ _ _ _ _ _ . . NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ . . _ 39 _ Conta_ct l1am_elpnol1eJorweekly progress_reports [explorç¡tory _otllYI- _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _ Date: Engineering Commissioner: ~S-2S..f}.5- SPACING EXCEPTION NOT REQUIRED: Well will access shallow gas sands not perforated in nearby Mobil Moquawkie No. 1 well (see attached map & log). MUDLOGGING AND GAS DETECTION EQUIPMENT REQUIRED: due to shallow gas zones that caused a blowout and tire on Moquawkie No. 1 (see Pressure Considerations section). DIRECTIONAL SURVEY REQUIRED: Well will be less than 200' from existing Mobil Moquawkie NO.1 well. Accordingly, a directional survey is reauired oer 20 Me 25.050(a)(3t SFD 5/24/2005 Date s/arir
