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204-096
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 May 13, 2020 RECEIVED MAY 18 2020 Jeremy M. Price, Chair AOGCC Alaska Oil and Gas Conservation Commission 333 West 7"' Ave., Suite 100 Anchorage, Alaska 99501 RE: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Costs to Plug and Abandon Wells on CIRI Leases Dear Mr. Price: Regarding your letter to me of May 1, 2020, the following information is responding to your request for costs incurred to plug and abandon the following wells on mineral interests owned by Cook Inlet Regional, Inc. (CIRI): • ASPEN 1 – API 50-283-20114-00-00 • KALOA 2 – API 50-283-20107-00-00 • LONE CREEK 1– API 50-283-20096-00-00 • LONE CREEK 3 – API 50-283-20112-00-00 • LONE CREEK 4 – API 50-283-20121-00-00 • MOQUAWKIE 1 –API 50-283-10019-90-00 • MOQUAWKIE 4 – API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 –API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 – API 50-283-20062-00-00 Plugging Inlet, LLC, was the operator of these wells and conducted plugging and abandonment (P&A) operations between October 2018 and November 2019. Costs were tracked on the basis of vendors, not by well or activity. Thus, while some costs, totaling about $1,007,000, were paid to vendors who worked solely on the P&A of the wells (e.g., Schlumberger, Pollard Wireline, and Halliburton), most of the vendor;/contractors also worked on DR&R, cleanup, and waste disposal operations. Thus, the costs of these vendors/contractors for P&A operations were estimated on the basis of the Summary of Operations, based on the daily reports—these include camp costs, air and marine transportation, supervision, welder and roustabouts, trucking, and equipment rental. It is estimated that another $595,000 were paid to these other contractors and vendors for services supporting P&A work for a total estimated cost to P&A the 10 wells of $1,602,000, or $160,200 per well. However, one well, the Lone Creek 1, was particularly problematic to P&A due to its original construction, and the cost to P&A that well is estimated at about $244,000, leaving the average cost to P&A the other 9 wells at $151,000. For clarity, the reported $1.6 million is for actual well plugging and abandoning costs only; in addition, Inlet Plugging LLC incurred approximately $3.4 million for associated lease remediation activities, including required deconstruction & removal of surface production equipment and restoration of the sites, cleanup of contamination (mostly compressor oil leaks under buildings and some small spills), disposal of waste (including historic drill cuttings and mud solids, contaminated gravel and soil, and used oil and glycol), required Mr. Jeremy M. Price 5/13/20 Page 2 surface use payments, transportation of salvaged equipment and waste, and associated expenses. If you have any questions or require additional information, please contact me at 713-899- 8103 or by email at jejones@aurorapower.com. Sincerely, �ZG 9!Edward Jones Operations Consultant for PLUGGING INLET, LLC 6733 South Yale Avenue Tulsa, OK 74136 CC: Suzanne Settle and Colleen Miller, CIRI Thomas Redman, Jim Sullivan, Mark Can, Plugging Inlet, LLC THE STATE "ALASKA May 1, 2020 GOVERNOR MICKNE•L I. DUNLEAFY J. Edward Jones Operations Consultant Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Dear Mr. Jones: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov The Alaska Oil and Gas Conservation Commission (AOGCC) requests documentation of the actual costs incurred to plug and abandon the following wells: • ASPEN 1 —API 50-283-20114-00-00 • KALOA 2 — API 50-283-20107-00-00 • LONE CREEK 1 —API 50-283-20096-00-00 • LONE CREEK 3 —API 50-283-20112-00-00 • LONE CREEK 4—API 50-283-20121-00-00 • MOQUAWKIE 1 —API 50-283-10019-90-00 • MOQUAWKIE 4 — API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 —API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 —API 50-283-20062-00-00 The wells are located on mineral interests owned by Cook Inlet Regional, Inc (CIRI). In 2017, Plugging Inlet, LLC was designated operator of record for the wells. This request is made pursuant to 20 AAC 25.300. Should you have any questions about the information request, please contact Guy Schwartz at 907-793-1226. Sincerely, v Jeremy M. Price Chair, Commissioner cc: Suzanne Settle VP Energy, Land, Resources CIRI itCIRI January 14, 2020 James Regg, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 �T ons WrInVeColprwation RE: Onshore location clearance, Plugging Inlet Site located: T12 N R12W, T12N Ri1W, T11N R12W, T12N R11W SM Dear Mr. Regg: This letter is submitted to formally request that the Alaska Oil and Gas Conservation Commission (AOGCC) withhold the site clearance at the location formerly operated by Aurora Gas, LLC. Tyonek Native Corporation (TNC) and Cook Inlet Region, Inc. (CIRI) are the majority landowners within the area and did not have the opportunity to conduct an on-site inspection prior to the 2019 snowfall. CIRI and TNC will conduct an on-site inspection of the property in the spring to ensure the site is reclaimed to the satisfaction of both landowners. TNC and CIRI appreciate the AOGCC's continued cooperation during this process. If you have any questions, please contact Suzanne Settle at (907) 263-5150 or Connie Downing at (907) 272-0707. Sincerely, Tyonek Native Corporation 1 Connie J. Downing Chief Administrative Officer Cook Inlet Region, Inc. Suzanne Settle VP, Energy and Infrastructure Colombie, Jody J (CED) From: Regg, James B (CED) Sent: Monday, January 6, 2020 12:26 PM To: Colombie, Jody J (CED) Cc: Schwartz, Guy L (CED) Subject: FW: Site Clearance - Plugging Inlet See email from CIRI below. Looks like we received the 407s for these December 20 according to the 400 -Logs. Plugging Inlet dragged out the P&As so long this past fall that we were unable to get to locations for site clearance inspections before weather turned (actually had an Inspector and CIRI rep at the airport ready to fly over for site clearance inspections but flights were canceled for weather and there has been snow on the well sites since). Wells affected are: - Aspen #1 (PTD 2051110) - Kaloa #2 (PTD 2040960) - Lone Creek #1 (PTD 1980840) - Lone Creek #3 (PTD 2050970) - Lone Creek #4 (PTD 2070910) - Moquawkie #1 (PTD 2030690) - Moquawkie #3 (PTD 2050800) - Moquawkie #4 (PTD 2070840) - Simpco Moquawkie #1 (PTD 1780470) - Simpco Moquawkie #2 (PTD 1780880) Jim Regg Supervisor, Inspections AOGCC 333 W.7'^ Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.reggPalaska.eov. From: Colleen Miller <cmiller@ciri.com> Sent: Monday, January 6, 2020 11:09 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Connie Downing <cdowning@tyonek.com>; Suzanne Settle <SSettle@ciri.com>; David Kroto <dkroto@tyonek.com> Subject: Site Clearance - Plugging Inlet Good Morning Jim. I hope you had a great holiday! I'm writing to let you know that CIRI and Tyonek will be issuing a joint letter to request that the AOGCC withhold the site clearance on the Westside until CIRI and Tyonek have an opportunity to get boots on the ground in the spring. As always, please call me if you have any questions. Colleen 263-5117 The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. 2 DSR-3/25/2020 -00 Albert Kaloa, Undef Gas Pool SFD 3/26/2020 xG MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 7) 6e DATE P. I. Supervisor Z� FROM: Lou Laubenstein SUBJECT Petroleum Inspector 10/24/19 Surface Abandonment Kaloa #2 Plugging Inlet LLC PTD 2040960;Sundry 318-342 10/8/19: 1 arrived on location for the surface abandonment inspection on Kaloa #2. David Wallingford was the Company representative on location for the day's inspection. Solid cement was confirmed at surface in the cutoff well. The casing cutoff depth was only cut to 3-4 feet below the current pad grade and not the proper depth of 3 feet minimum below original ground level — this was discussed with Mr. Wallingford. The hole was filled with debris and trash that needs to be removed prior to backfill. Also, there is another piece of casing that was used during the drilling process that should be cut off to the proper depth. I departed location and communicated the deficiencies to AOGCC Inspection Supervisor Jim Regg. 10/24/19: 1 arrived on location for a second inspection to check for proper cut-off depth of the well. The casing had been cut to the required 3 feet below natural grade satisfying the current regulation. Information on the marker plate was verified and installed. Attachments: Photos (3) 2019-1024_Surface_Abandon_Kaloa-2_I1. docx Page 1 of 3 4C $dor p'< Awl f ;r tet' � ��•,. r �'" Ilk} 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 CONFIDENTIAUTY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwadz@alaska go_v). From: Ed Jones <jejones@aurorapower.com> Sent: Wednesday, March 6, 2019 1:53 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: George Pollock <gpollock@aurorapower.com>; Tom Redman <TomR@kfoc.net>; Mark Carr <MarkC@kfoc.net>; David Wallingford (david996@yahoo.com) <david996@yahoo.com> Subject: RE: CIRI P & A well status Guy, Following is an update on the status of each of the CIRI wells, formerly operated by Aurora Gas: Aspen 1(WDSPL)—PTD 205-111: An MIT was performed on the well on 10/14/18, the temporary tubing plug was pulled, and the well was cleaned out with slickline bailer. Produced water disposal was commenced soon thereafter, and 473 bbl of produced water was injected into the well for disposal in 3 days October. Another 2486 bbl of produced water, returned packer fluid (while cementing or testing), and cement rinsate were injected in 13 days in November. The well and injection facility was then winterized and shut-in pending commencement of plugging operations in the spring of 2019. Kaloa 2—PTD-204-096: A CIBP was set in the tubing at 2331' on 10/26/18. The tubing and IA were pressure tested to 1775 and 1700 psi, respectively on 10/31/18 (witnessed). On 11/7 35 bbl of cement were pumped of planned 49 bbl— ran out of cement. Shut down and tested in AM—tubing to 1650 psi and IA to 1700 psi. Submitted request for remedial procedure, which was approved. Barge delivered additional cement. On 11/10/18, cement was tagged in tubing at 373', perforated tubing at 370-373', and cemented down tubing with 11.7 bbl of cement, with cement to surface after 8.5 bbl. On 11/15/18, pressure tested tubing to 2175 psi and IA to 2300 psi. No further activity was performed pending cutting off casing this spring. Simpco Moquawkie 1—PTD 178-047: the pretest of the tubing and IA in late October indicated a casing leak. A temperature survey was performed while pumping down the IA, and a casing leak was indicated at 2122-46' (old squeeze perfs). A revised cementing procedure was submitted to the AOGCC and approved. On 11/3/18, the well was cemented by pumping 1 bbl down heater string, 112 bbl of cement down the tubing until cement returns at surface, then IA was shut in and 1 bbl of cement was squeezed into old squeeze perfs resulting in a squeeze pressure of 1700 psi. On 11/8/18, the tubing and IA were tested to 1800 and 2550 psi, respectively. No further activity was performed pending cutting off casing this spring. Simpco Moquawkie 2—PTD 178-088: Tubing and casing were pressure tested (witnessed) to 1600 and 1550 psi, respectively on 10/24/18, and the tubing was perforated at 5209' on 11/5, as sliding sleeve could not be opened. On 11/6, the well was cemented: 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 SugarLand,TX 77479 713-899-8103(C) 281-495-9957, ext 201 (0) 832-999-4382 (F) From: Schwartz, Guy L (DOA) fmailto:guy.schwartz@alaska.gov Sent: Monday, March 04, 2019 1:30 PM To: Ed Jones <jejones@aurorapower.com> Cc: George Pollock <gpollockPaurorapower.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 (Guv.schwartz@alaska gov). , STATE OF ALASKA A..Oil GAS CONSERVATION Thi RECEIVED REPORT OF SUNDRY WELL OPERATIONS JAN 2 3 2018 1.Operations Abandon LI ,gL Fractrare - Phi Tubing L �i - ;. �; v Pe tfom ed: Suspend ❑ Perforations El Other - El Alter g ,:',�' Plug-for Reddil C1 Perforate New Pool El Repair Well 0 fee-enter Susp Well El Temporary Plug C 2.Operator Aurora Gas,LLC 4.Well Class Before Work: 5.Permit to Drill Number_ Name: Development 2 Expkvatory E 204-096 3.Address: 3705 Arctic Blvd.#2114 A ,AK 99503 r phic J Service X i 6.API hkenbet 283-20107-00 7.Property Designation(Lease Number): 8.Well Name and Number: C-061393 Kaloa#2 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): NA Albert Katoa undefined Gas 11.Present Well Condition Summary: 'ThItainenth measure. tzt1 feet plugs measured .1 `feet true vertical 3720 feet Junk measured None feet Effective Depth measured 3600 feet Packer measured 2315-3083 feet true vertical 3600 ,feet true vertical 2315-3083 feet Casing Length Size MD TVD Burst Collapse Structural Conductor t16 -123/4 65# 116 116 Surface 617 8 5/8 32#J55 617 617 3930 psi 2530 psi Intermediate Production 3714 511217#J55: 3714 3714 5320 psi 4910 psi Liner Perforation depth Measured depth 2442-3552 feet -True Vertical depth'2442-=3552 feet Tubing(size,grade,measured-and true vertical depth) 2.718 6:5#J55 3068 3068 Packers,and SSSV(type,measured and truearertical.depth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): y 'NA SCANNED ,:AN 3 1 '4).018- Treatment desccriptions including volumes used and final pressure: NA 13. Representative Daily Average Production or Injection Data S Oil-Bbl, t. Gas-Mcf s. Watec.Bbl. Casing Pressure . Tubin Pressure Prior to well operation: 0 0 845 Subsequent to operation: 0 0 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations Q' Eby © Development 2 Service 0 Stratigraphic Copies of Logs and Surveys Run ❑ ,16.Welt Status after work: OA 0 Gas E, WDSPL 0' Printed and Electronic Fracture Stimulation Data 0 GSTOR 2 vim ❑ WAG 0 GINJ 0 CUSP 0 SPLUG❑ 17. 1 t ereby certify that the foregoing is tie and correct to the best of my knowledge. Spy Number or WA itC.O.Exempt 317-269 Authorized Name: George.Pollock Contact Name: Authorized Title: Marler-R1ipd Ops&Eng Contact Via: gooliock{dsauroracower.c( Authorized Signature: /r ' Da6 1/2312018 Contact Phone: 907.351.8286 yP RBDMSv -/JAN 2 4 ZG18 21--- /-.�7/S Form 10-404 Revised 4/2017 ��� Submit Original Only • 410 Ausora-Gas, LLC Operations Summary Set Temporary Plug Kaloa#2 Well July-20,2017 0600 hours Mobilize to location 0645 hours R/U WL, PT lubricator w/wellbore 4715 hours -RIFI-w/2.33"-gauge-ting-to 2315'-106,-tag-profile-insleeve,-POOH 0745 hours RIH w/2-7/8'X-line w/ PX Plug to 2315',WT„set plug,POOH 0815 hours RIH SB w/Prong to 2315',WT,set Prong.POOH 0845 hours Bleed off well,monitor Pressure 30 minutes, Pass 0g15=hours -RD WI. • • 2 7/8 6.5#8rd EVE 3-55 Aurora Gas, LLC ;.RA , KALOA #2 , . ,r.. .W. ,,. Actual Configuration , *' Ilk 72-3(4"65.4#Structural July 2017 ` RKB—14.0ft Conductor driven to 116' Drill 10-5/8'Hole to 868' ,, 1' a' N... Tyoo ek Tops '.`' "'+ot, , 8-518"32#Surface Casing set at 617' Cary:2-3.2. 2994' ' Cement wl 14.5 ppg Gas-Black enhanced Carya 2-4.1-3154' Carya 2.4.2-3248' Carya 2-5.1-3402' Carya 2-5.2-3522' - . Es/ WXA Sliding Sleeve @ 2296' i)3'( - PRPlug*r 5'' PHRP Hydraulic-Set Packer @ 2344' New Perls: Carya 2-1.2 at iii�{ WXO Sliding Sleeve @ 2413' 2442-58' .r.� _"N PHRP Hydraulic Set Packer @ ' 2440' New Perk: ►;�di Carya 2-2 at --... WXO Shrouded Sliding Sleeve @ 2526-42'and 2 ' 2598-2618' _ _ PHRP Hydraulic Packer at 2675' a Carya 2-3.1 . 2748-2764' ' WXO Sliding Sleeve at 2746' 2774-2794' ply Hydraulic Packer at 2823' _ir New Perfs: Ii WXO Shrouded Sliding Sleeve @ 2866' Carya 2-3.1 at ''''''01841 „,,,,, 2886-2906' , ir t'I1RP Hydraulic Set Packer 2443'w/8' Carya 2-3.2 pup w/231 x profile @ 2959'w/RHCP 2995-3015' plug,8'pup and WL entry guide @ 2969' _ A Mechanical-set Packer @ 3083'w/On- Off Tool w/Top of cut-off tubing at Carya 2-4.1 3071',bottom of WLEG at 3099' 3158-78' ..UM aaSI" 3200-20' Tubing ca at 31W'w/OS&bait sub top at 3101' Carya 2-4.2 14ft of 2-718”tubing then crosses to 3- 3250-3330' 1/2" With 3-1/2"Stratapak screens @ Bailed Fill inside tubing f/ • 3152-3174' 3068-3127'on 9/25/14 3197321:6' (SANDED IN) r 3247-3329' lik , 3522-3552' Carya 2-5.2 3522-52' S`Fs"17#1-55 Caging to 3,714'MD(TVD) r 1 Cement w/48 hid 123 ppg+85 bbl 15.8 ppg PBTD @ 3,600' Class`G' Drill 7-7/8"Hole to 3,720' 1 • • • d OF Ttj� ,, THE STATE Alaska Oil and Gas of /0SKA Conservation Commission �. 333 West Seventh Avenue mak,' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 (4'ALAS Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock SEP 201(. Manager pNNE� `� Aurora Gas, LLC 1400 W Benson Blvd., Suite 410 Anchorage, AK 99510 Re: Albert Kaloa Field, Undefined Gas Pool, Kaloa 2 Permit to Drill Number: 204-096 Sundry Number: 317-408 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, Cath P. Foerster Commissioner 11L- DATED this day of September, 2017. RBDMS Lr - 7 2017 III • RECEIVED STATE OF ALASKA AUG 2 5 201 ALASKA OIL AND GAS CONSERVATION COMMISSION 01-SG) 1 4) ( t APPLICATION FOR SUNDRY APPROVALS AOGC(-$ 20 RAC 25.280 1.Type of Request- Abandon .7-. Plug Perforations r:-._ Fracture Stimulate {7 Repa'Vi'e" 7 Oceraticns shutdown T--, Suspend 111 Perforate Other StimulatePuri -i.. .-_, __. Plug for Redtill 72 Perforate New Pool 117 Re-enter Susp Well 71 Alter Ca sirig 1 (.;ther- Ternocrary Plug 2.Operator Name. Ti.Current Weft Class ,5 Perm-.'.tc -,''is.i...mcer Aurora Gas.LLC Exploratory Development J.--. , 204-096 . 3.Address- 1400 W Benson Blvd Suite 410 '° Stratigraphic Service Anchorage.AK 99503 7. If perforating. 18 A,eiil%elle and\umber What Regulation or Conservation Order governs well spacing in this poor? Mk' 1 Kaioa#2 • -- , Will planned perforations require a spacing exception? Yes No /: hill_l 9.Property Designation(Lease Number). 10 FieicUPoolisi- C-061393 . Albert Katoa Undefnei Gas • 11 PRESENT WELL COMMON SUMMARY Total Depth MD(ft}. 'Total Depth TVD(ft): Effective Depth MD Effective Depth TVD. MPSP(psi). P;..igs,VD: i-unk iMCi . 3720' - 3720' • 3600' . 360C I 920 osi X'...:- %one Casing Length Size MO WO Burst Collapse Structural , . Conductor 116' 12 14-65* 116' 116' Surface 617 8 518"32*J55 51T ei T .293'.:cs, 253C:s , 4. Intermediate , Production 3714' 5'!2"17*J55 3714' 3714' 532C cs; ,1S1C.,P Si - I • 1 ! i Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): :Tubing Size: Tubing Grade. ''utinc.--VD.ftl 2442 -3552 • 2442'-3552' 2 718. 6 ,..'5,5 Packers and SSSV Type: Packers and SSSV MD ifil and TVD.1"t Hydraulic retnevable and mechanical-set packers PHRP C 2344'.2490 2575'2866'&2943 a-c mec-!ariica. , 33,9.3' 12.Attachments Proposal Summary 7 Wellbore schematic , 13 Well Class after proposed work. Detailed Operations Program . BOP Sketch IL Exploratory 1 Stratigraor is 2iee*7-V '..e.7-7:11 • Se.i ce 1_- 14.Estimated Date for TBD 15.Well Status after proposed work Commencing Operations !OIL __. .._. 16 Verbal Approval: Date: 1GAS WAG __. i,,,STOR ,---. SP,,...G __ Commission Representative. GIN t .S'i.i.".boi•i- , ....... 17 I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval e Pollock Gr George P',;-_,. Authorized Name. ..Cordac Name Authorized Title Manager-Pr ng Contact Eire, , , ,, ,,,-.3 ,,, ., ..„, Coined F--o-e l ... iO4-- Authorized Signature: wDate 24-Aug-17 COMMISSION USE ONLY 1Conditions of approval Notify Commission so Mat a representative may witness TS-ric-i Plug Integrity X BOP Test Mechanical integrity Test Location Clearance X Other. 4 it' i)Ict.010 rYULLkt-Aelt,,Tr C-ACklr- C.- C_A.AT CRF '''- i\Aft1?-1420- rLACtc Post Initial Injection MIT Req`cP Yes No Spacing Exception Required? Yes :---. No / Subsequent Form Required \C).--A.(y--1 RBDIVIS LL--SEP - 7 2017 APPROVED lApproved by lOgekt4411es—. COMMISSIONERDate '?-t-/7 THE BY COMMISSION 3- 4/2017 401 '0007 Submit Form and Form 10-403 Revise R4,GolpNiAs Lid for 12 th:-fr-olt't-hteclate of approval. ci .4.1', Cr, ,r1 Duoive S • AURORA GAS, LLC WELL ABANDONMENT KALOA #2 August 2017 Version 1.0 (8/17/17). CURRENT CONDITON : Max SITP-850 psi (Blows down quickly).✓ KB=14.0 feet CASING: 5-1/2", 17# J-55 set at 3714'MD/TVD. TUBING: 2-7/8", 6.5# J-55 8 rd EUE,w/9.9 ppg KCI-NaCl brine as packer fluid in tbg-csg annulus above top packer and with: Sliding Sleeves at:WXA at 2296' (closed opens upward now closed); WXO at 2413'(now open);shrouded WXO at 2533'(now open); WXO at 2746' (now open); and shrouded WXO at 2866'; 2.31" X nipple at 2959'(now open);and 2.31" X nipple at 3078' with PX plug seta/ Packers: PHRP's at 2344', 2490', 2675', 2823', and 2943' and disconnected Arrowset IX at 3083' 3-1/2" Screens at: 3104' to 3552' w/bull plug (plugged with sand.at 3127' last run, 9/25/14), (See attached well bore and completion diagrams) CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing-Casing Annulus: 0.0152 BPF; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to Plug in bottom packer=18.4 bbl, Annular Volume to top Packer=41.1 bbl; to deepest packer=65.3 bbl (bottoms up); Casing Volume to Arrovvset Packer at 383'= 71:5 bbl. PERFS:Carya 2-1.2 at 2442-58'behind sleeve at 2413' Carya 2-2 at 2526-42'and 2598-2618'behind sileeve at 2533' Carya 2-3.lat 2748-64' and 2774-94' behind Sleeve at 2746' Carya 2-3.1 at 2886-2906' behind sleeve at 2866' Carya 2-3.2 at 2995-3015' Below deepest packer at 3083' (with PX plug set at 3083'): Carya 2-4.1 at 3158-78' and 3200-20', Carya 2-4.2 at 3250,3330',and Carya 2-5.2 at 3522-52'. NOTES: 1)Well is a straight hole. SUMMARY OF PLAN: RU slickline. RIH and pull prong and plug at 2296'. Open sleeve at 2296' and dump 9.9 ppg KCl-NaCl 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. Close all sliding sleeves.Fill tubing and casing with clean field produced water or 3%KCI water.Run CIBP for 2-7/8"tubing and set in top of top packer at 2344'. Test CIBP to 1500 psi. Run tubing-perforating gun and perforate tubing at 2350' with 4 SPF. RU cementers on tree • • (thru wing valve). Establish circulation pressure with 5-10 bill KCl water at 3 BPM. Pump 240 sx (276 cf=49.2 bbl)Class G cement(15.4 ppg, 1.15 disk yield)with pump time of 4 hr at 70 degrees- 4%excess and displace to surface—this one balanced plug is to meet the requirements of: 1)plug for perforated intervals:,2)surface casing shoe,and 3)surface.plug. Monitor for flow or fallback. 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. PROCEDURE: 1) Pick and move welihouse. Notify AOGCC inspector of plans for plugging operations 2) Move in cementer(pump truck/mixer),bulk cement(300 sx Class 6), slickline/electric line unit, water tank with 100 bbl fresh water for cementing, mud "pit"open tank with mixing capability with 100 bbl clean produced water or 3%KC1 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 2296' KB. Allow pressure to equalize (expect maximum of 850 psi). Check lubricator and tree for leaks. If none,pull PX plug body. 4) Kill well by opening sleeve at 2296' and dumping 9.9 ppg Kci-NaCI packer fluid from annulus into '/tubing. Allow tubing to stabilize,bleed off pressure. Add clean produced water or 3%KCI water to fill tubing and casing if needed to kill well (Volume to deepest open perfs is 18.5 bbl). 5) Run 2.25" gauge ring(GR)to check for fluid level and tag bottom (expected to be 3078', top of PX plug in pup joint below permanent packer). If restrictions are found, run bailer, brushes, etc. to cleanout to about 2900'. 6) RIH with shifting too. Close sliding sleeves at 2866', 2746',2533', and 2413'. Fill tubing and casing—close sleeve at 22966'. Pressure up on tubing to 1500 psi to confirm that all sleeves are closed. Release pressure. RD slickline lubricator. 7) RU electric line lubricator(see Note 1 below). PU.C1BF for 2-71&" Clii :?,Rifff and set inside top, packer at about 2344'. 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 2330', and perforate 4 shot in l' at 2330' . POOH. 8) COMBINATION PLUG:RU cement pumper op wing valve of tree. Open casing valve (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 9.9 ppg KCI-NaCl brine—catch and use subsequent wells. Mix and pump 250 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 (3% excess). Catch annular brine for use in subsequent wells, divert to open tank as soon as returns are cement colored. This is to be a balanced plug—monitor for flow or fall back. 9) When cement top is stable,disconnect cementer. Wash out tubing, and tubing-casing annulus to 3- 4' below GL. WOC 8.hours. Pressure test both.sides(tubing and annulus)to 1500 psi. Release pressure. MI crane. Remove tree. Cut off conductor, surface,and production casing strings and �7 akptizr Tes-c- Fixes 3D 1,4 it-1 a"-A-sca • • 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 1/4" steel marker-plate cap for 11-7/8" conductor casing,not to extend beyond casing OIC, and bead-weld the following information onto marker.prate, Aurora Gas, LLC PTD # 204-096 * µa►U Mt-LA SCr OATOC' E STPatei Kaloa No. 2 ( NR-t- - c L. - 0—401 API# 50-283-20107-00 M 9-st-n 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. ' coeGur. in 510'Fe of mob rkemiet j"o deco ArP/ere 71 .c We � /- iuS e" lb 6oen c.u4le of sfo1,�'01,c, f'o�. 6r rhe f45t 3 phis pegs* 4anc✓'onJP�` / e �-e1 ,S GfiOrof t s 41e. q 1` 41? t'1"7 e . • 0 2 7/8 638 Srd EL1E 3-55 Aurora Gas, LLC 1* i ai , ��7 #2 , I OA - s ..ice.. 4i .:* i ■a Actual Configuration • ' ' November r . o r " 12-314"65 4#Structural 215 ,.: "' � Conductor driven to 116' Drill 10-5/8"Hole to 868' '9, t ° ? Tyonek Tops �` Carya 2-3.2-2994' '"` ''``_ �` �`r 85/8'32#Surface Casing set at 6iT Carya 2-4.1-3154' in�� ;'° Cement w/14.5 ppg Gas-Block enhanced Carya 2-4.2-3248' S _ Carya 2-5.1 3402' Carya 2-5.2-3522' ', WXA Sliding Sleeve @ 2296' AL: E.- PHRP Hydraulic-Set Packer @ 2344' New Perfs: Carya 2-1.2 at 114 A WXO Shrouded Sliding Sleeve(? 2442-58' -""'* 2413' PHRP Hydraulic Set Packer @ 2490' New Perfs: Carya 2-2 at —... WXO Shrouded Sliding Sleeve @ 2526-42'and 2533' 2598-2618' PHRP Hydraulic Packer at 2675' Carya 2-3.1 , _ sr 411 . WXO Shrouded.Sliding Sleeve at 2748-2764' --' 2746' 2774-2794' ' , - ii, - . . PHRP Hydraulic Packer at 2823' to New Perfs: :'' {l p, WXO Sliding Sleeve @2866' Carya 2-3.1 a# w 2886-2906' Hydraulic-Set Packer @2943'tool and 8' Carya2-3.2ao.- ;lir ...,e pupw/2.31 x profile*2959'and WL - 2995-3015' entry guide*2%9' ` ..-_ JIL ''S+lecha -set Packer'i:3063/w/On- -A. a Off Toot w/PX plug. Top of cut-off Carya 2-4.1 tubing at 3071',bottom of WLEG at 3158-78' •-- 3099'. PX plug set in profile at 3078'. 3280-20 Tubing cut at 3104'w/OS&bait sub "'"" top at 3101' Carya 2-4.2 " ,.f, 14ft of 2-7/8"tubing then crosses to 3- 3250-3330' -3256 333fi' i 1/2" Bailed Fill inside tubing fi y - With 3-1/2"Stralapak screens 3152-3174' 3068-3127'on 9/25/14 3197-3216' (SANDED IN) ' " I 3247-3329' i .' 3522-3552' Carya 2-5.2 • 3522-52' 5'!"171E 3-55 Casing to 3,714'MD(TVD) Cement w/48 bbl 12.5 ppg+85 bbl 15.8 ppg PRIM @ 3,600' Class`G' Drill 7-7/8"Hole to 3,720' • 0 2 7/8 6.55 8rd EUE 3-55 , Aurora Gas, LLC i — ° ' !; p t KALOA#2 1 ' Proposed P&A Configuration ' ! ' 123/4"65.45 Structural August 2017 `, *' $a Conductor driven to 116' Drill 10-sir Hole to 868' . r i Tyonek Tops8-5/8"32#Surface Casing set at 617' YA Carya 2-3.2-2994' Cement w/14.5 ppg Gas-Block enhanced Carya 24.1-3154' Carya 2-4.2-3248' Carya 2-5.1 3402' Carya 2-5.2-3522' 1 COMBINATION PLUG(PEf FS, SURFACE SHOE,AND SURFACE)- ' t i r s ` 250 Sx Class G(15.8 ppg,1.15 cf/sk) From 2340'to surface f T a i I { E # S . WXA Sliding Sleeve*2296' t Perf tubing at 2330' Set C1BP i8 tubing at 2344' =1 is a PHRP Hydraulic-Set Packer*2344' WXO Sliding Sleeve @ 2413' Carya 2-1.2 at 2442- ►1 2490 ii "` WXO ShroudedSliding Sleeve @ 58. — ....ill _ •• ,'1 2533' PHRP Hydraulic Packer at 2675' Carya 2-2 at Z26-42' tFf WXO Sliding Sleeve at 2746' and 2598-2618' PHRP Hydraulic Packer at 2823' ar WXO Shrouded Sliding Sleeve!a 2866' Carya 2-3.1 - PHRP Hydraulic Set Packer r,3 2943' 2748-2764' ill w/8'pup w/2.31 a profile @ 2959'w/ 2774-2794' 1111 RHCP plug,rpu9 and W L entry Carya 2-3.1 at as....... gm --- Mechanical-set Packer @ 3083'w/On- 2886-2906' Off Tool wl Top of cut-off tubing at il -mss "� 3071',bottom of WLEG at 3099'.PX Carya 2-3.2plug set in profile at 3079'. 2995-3015' r'� Tubing cut at 3104'w/OS&bait sub Carya 2-4.1 -, top at 3101' 3158-78' 14ft of 2-718"tubing then crosses to 3- Imit. 1/2" Carya 2-4.2 .-- With 3-1/2"Stratapak screens 3250-3330' lillili No 3152-3174',3197-3216', 3247-3329', Carya 2-5.2Pr 1 3522-3552' SANDED PV 3522-52' PBTD*3,600' Drill 7-7/8"Hole to 3,720' 5`'A"175 J-55 Casing to 3,714'MD(TVD) Cement w148 bb1:12.5 ppg+85 bbl 15.8 ppg Class`G' • OF Tjf • • \ iyy,k THE • STATE Alaska Oil and Gas ��►�i�ti, o.f e T cKA Conservation Commission s __ k rth 333 West Seventh AvenueGOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 -ITh g gip• Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager111scow . , 2017 Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Albert Kaloa Field, Undefined Gas Pool, Kaloa 2 Permit to Drill Number: 204-096 Sundry Number: 317-269 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, dA/ Hollis S. French 4 Chair DATED this day of July, 2017. RBDMS , JUL 1 1 2017 I ! RECEIVED STATE OF ALASKA JUN 16 20 17 ALASKA OIL AND GAS CONSERVATION COMMISSION 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 Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other Temporary Plug ❑. 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Aurora Gas,LLC Exploratory ❑ Development ❑ , 204-096 • 3.Address: 1400 W.Benson Blvd.Suite 410 Stra ra hic ❑ 6.API Number ti9 ❑ Service P Anchorage,AK 99503 50-283-20107-00 - 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Kaloa#2 • Will planned perforations require a spacing exception? Yes ❑ No ❑ 9.Property Designation(Lease Number): 10.Field/Pool(s): C-061393' Albert Kaloa Undefined Gas ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 3720' • 3720' ' 3600' 3600' 920 psi 3600' None Casing Length Size MD TVD Burst Collapse Structural Conductor 116' 123/4"65# 116' 116' Surface 617' 8 5/8"32#J55 617' 617' 3930 psi 2530 psi Intermediate Production 3714' 5 1/2"17#J55 3714' 3714' 5320 psi 4910 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2442'-3552' 2442'-3552' 2 7/8" 6.5#J55 3068' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Hydraulic retrievable and mechanical-set packers PHRP C 2344',2490'2675'2866'&2943'and mechanical @ 3083' 12.Attachments: Proposal Summary 0 Wellbore schematic ❑ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development❑ Service ❑ 14.Estimated Date for TBD 15.Well Status after proposed work:. Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS Q • 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 Contact Name: George Pollock Authorized Title: Manageer- s.!'Eng Contact Email: aooljockc aurorapower.corn '' ---- Contact Phone: 907-277-1003 Authorized Signature: i i Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 317- 2Le9 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: '—� Cin i ,- A Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: `Ir1 -- 404 RBDMS z I"� � - 1 1 2017 Approved by: LQ_OCC COMMISSIONER APPROVED BY 1-4I 1 THE COMMISSION Date: -111, Submit Form and Fl 1102,Fteled 4/2017 0 RpliredlaftaiknEvalid for 12 months from the date of approval. Aftactimeris in Dupicate .x147 r 7 • • urora Gas, LLC June 16, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 PIECE! Anchorage, AK 99501 JUN 16 2017 Re: Application for Sundry Approval—Set Temporary Plug A Kaloa#2 Well PTD#: 204-096 API #: 50-283-20107-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Albert Kaloa Undefined Gas Field on the west side of Cook Inlet, southwest of the Village of Tyonek. This well is currently producing gas from multiple zones in the upper Tyonek sands and is mechanically sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new owners/investors notice of the impending action before on-site activity begins. The proposed work involves setting a plug via wireline in the profile at a depth of 2,296' above all open perforated intervals to mechanically isolate the reservoir. After the plug is set,tubing pressure will be monitored for 30 minu4es to ensure isolation. The master valve will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information, please contact me at(907) 277-1003. Sincerel Y v George Pollock Manager—Production Operations & Engineering 4645 Sweetwater Boulevard, Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 *Anchorage,AK 99503 * (907) 277-1003 • • 2 7/8 6.5#8rd EUE.1-55 Aurora Gas, LLC a ,i�- ,; SFr= KALOA #2 *`.* „." Actual Configuration November 2015 12-3/4"65.4#Structural RKB—14.0ft Conductor driven to 116' Drill 10-5/8"Hole to 868' • Tyonek Tops 8-5/8"32#Surface Casing set at 617' Carya 2-3.2 2994' Cement w(14.5 ppg Gas-Block enhanced Carya 2-4.1–3154' Carya 2-4.2-3248' Carya 2-5.1–3402' Carya 2-5.2-3522' WXA Sliding Sleeve @ 22%' PHRP Hydraulic-Set Packer @ 2344' New Perfs: Carya 2-1.2 at WXO Sliding Sleeve @2413' 2442-58' PHRP Hydraulic Set Packer @ 2490' New Perfs: Carya 2-2 at =IP !!�- WXO Shrouded Sliding Sleeve @ 2526-42'and 2533' 2598-2618' PHRP Hydraulic Packer at 2675' Carya 2-3.1 WXO Sliding Sleeve at 2746' 2748-2764' :=11 2774-2794' PHRP Hydraulic Packer at 2823' New Perfs: ; WXO Shrouded Sliding Sleeve @ 2866' Carya 2-3.1 at 2886-2906' PHRP Hydraulic Set Packer @ 2943'w/8' Carya 2-32 111Mo.-- pup w/2 31 x profile @ 2959'w/RHCP 2995-3015' 11.1"""-- plug,8'pup and WL entry guide*2969' Mechanical-set Packer @ 3083'w/On- Off Tool w/Top of cut-off tubing at Carya 2-4.1 — 3071',bottom of WLEG at 3099' 3158-78' -.RENO _____ 3200-20' Tubing cut at 3104'w/OS&bait sub top at 3101' Carya 2-4.2 14ft of 2-7/8"tubing then crosses to 3- 3250-3330' 1/2" With 3-1/2"Stratapak screens @ Bailed Fill inside tubing f/ 3152-3174' 3068-3127'on 9/25/14 3197-3216' (SANDED IN) 3247-3329' 3522-3552' Carya 2-5.2 3522-52' -- C5 V2"17#J-55 Casing to 3,714'MD(TVD) Cement w/48 bbl 12.5 ppg+85 bbl 15.8 ppg P1311) a'3,600' Class`G' Drill 7-7/8"Hole to 3,720' • . . 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. ,.Ll eie Saua ye(6/11/2017) • STATE OF ALASKA • RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION MAR 10 2016 REPORT OF SUNDRY WELL OPERATIONS /qy G�j��`�e 1 Operations Abandon L Plug Perforations Fracture Stimulate Li Pull Tubing';_] ' p rati6tts ht310own . Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redritl 0 arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well 0 Other ❑ 2.Operator AURORA GAS.LLC 4.Well Class Before Work: 5 Permit to Doli Number Name: Development Q Exploratory❑ 204-095 3.Address: 1400 WEST BENSON,STE 410, 1. Stratigraphic❑ Service❑ 6 API Number ANCHORAGE AK 99503 50-283-20107-00 7 Property Designation(Lease Number): 8.Well Name and Number: CIRI LEASE#C-061393 KALOA#2 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10 Field/Poops; Expro Perforating Record Albert Kalov, Undefined Gas Field 11.Present Well Condition Summary: Total Depth measured 3720 feet Plugs measured NA feet true vertical 3720 feet Junk measured NA feet Effective Depth measured 3600 feel Packer measured Multiple—see below feet true vertical 3600 feet true vertical (same) feet Casing Length Size MD TVD Burst Collapse Structural Conductor 116' 12-3/4" 116' 116' Surface 617' 8-5/8" 617' 617' 3830 psi 2530 psi Intermediate Production 3714' 5-1/2" 3714' 3714' 5320 psi 4910 psi Liner Perforation depth Measured depth 2442-58' feet 2526-42', 2598-2618', 2748-64', 2774-94',2886-2906', 2995-3015'(open) 3158-78,3200-20,3250-3330,3522-52'(below tubing plug) True Vertical depth same feet Tubing(size.grade,measured and true vertical depth) 2-7/8" J-55 2969' 2969' Packers and SSSV(type,measured and true vertical depth) PHRP-2344',PHRP-2490',PHRP-2675',PHRP-2823', PHRP-2943',Mech Pkr-3083' No SSV 12 Slimutation or cement squeeze summary: Intervals treated(measured): NONE " Treatment descriptions including volumes used and final pressure NA 13 Representative Daily Average Production or injection Data Oil-Bbl Gas—Md Water-6W Casing Pressure Tubing Pressure Prior to well operation: - 91i 6 0 100 Subsequent to operation: h 1 p o 101 14.Attachments(required per 20 AAC 25 070,25 071,&25 293) 15 Well Class after work: Daily Report of Well Operations Q Exploratory❑ Development E3 Service 0 Stratigraphic D Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil FitGasWOSPL ri Printed and Electronic Fracture Stimulation Data Li is OR ❑ WINJ ❑ WAG ❑ GINJ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge_ Sundry Number or N/A if C.O.Exempt: 315-553 Contact Ed Jones Email jetones @aurorapower com Printed Name _ J Edward Jones - Title President Signature / , ,, j Phone 281-495-9957 Date 3/10/2016 �f Form 10-404 Revised 5/2015 MAR 1 1 16 /t_/ RBDMS lr�/ mit nginat Only • • --;,;, _---,Atiirora Gas, LLC March 10, 2016 Ms. Cathy Foerster,Chair RECEIVED Alaska Oil and Gas Conservation Commission MAR 10 2016 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 AOGCC RE: Sundry#315-553 Kaloa#2 Well PTD#204-096 and API#50-283_20107-00 Perforate New Intervals and Reeomplete Dear Ms. Foerster: On 16 September 2015 Aurora Gas, LLC was granted approval to add new perforated intervals to this onshore gas development well in the Albert Kaloa Undefined Gas Field, on the west side of the Cook Inlet, southwest of the village of Tyonek. The well was previously completed in Upper Tyonek Sands, the Carya 2-3.1 thru the Carya 2-5.2, and new perforations were added in the shallower Upper Tyonek Sands, the Carya 2-1.2, 2- 2.1, and 2-2.2 and additional perfs in the 2-3.2, all expecting gas. The well work was done in October and November 2016,with testing continuing into January 2016. Please find attached information as required by 20 AAC 25.280 for your review. Pertinent information included with this report is as following: 1) Form 10-404 Sundry Report of Well Operations 2) Daily Report of Well Operations(Summary) 3) Schematic of the current wellbore and completion. 4) Expro Perforation Record Log If you have any questions or require additional information, please contact me at (281) 495-9957(Sugar Land office)or at 713-899-8103(cell). Sincerely, 11 ROR< GAS. ITC Y'dw l d ion&, President CC: CIRI 4645 Sweetwater Blvd.,Suite 200•Sugar Land,Texas 77479•(281)495-9957•Fax(832)999-4382 1400 West Benson Blvd.,Suite 410•Anchorage,Alaska 99503•{907)277-1003•Fax(907)277-1006 • S AURORA GAS, LLC DAILY SUMMARY KA LOA 2 RECOMPLETION WORKOVER ; 1 SUNDRY#315-553 ,u.) 'S OCTOBER-NOVEMBER 2015 1018-9/15—RU Pollard slickline. Run and set PX plug at 3083'. Set prong in plug with top at 3078' (WL measurements a bit deeper). Release Pollard. 10/26/15—Move in AWS#1 rig and support equipment. Remove wellhouse. Spot rig. 10/27/15—Rig up, raise derrick. Continue moving in support equipment. 10/28/15—Continue rig up. 10/29/15—Clean pits and fill with 3%KCI water from TMC 2 tank. Connect and test pump and lines. 10/30/15—Install choke and manifold,connect to well. Test lines to 1500 psi. Mix 150 bbl 9.9 ppg NaCI brine with 3% KCI. SITP-900 psi. SICP-0. Bullhead 20 bbl 9.9 brine down tubing at 1000 psi. SITP- 500 psi. SIFN. 10/31/15—SITP-900 psi,CP-0. Bullhead 20 bbl 9.9 ppg brine down tubing. RU Pollard. Test lubricator to 1500 psi. RIH with shifting tool and open WXA sleeve at 2688' (annulus with 9.9 ppg brine packer fluid). POOH. RD Pollard. SITP-0. CP-0. 11/01J1—SITP-0. Unable to circulate thru open sleeve. Set BPV. ND tree. Install blanking plug. NU X- 0 spool,BOP's including annular. Set floor. 11/02J15—Install windwalls and stairs on floor. Install HCR's on choke and kill lines. Hook up pump to kill manifold. Set beaver slide and operator's controls. 11/03/15—Berm around cellar. Install diverter line. Set BOP controls on floor and function test BOP's. RU floor equipment and landing joint. Test GOP's,witnessed by Chuck Sheve:test blind rams to ( (i 250/2500 psi, pull blanking plug and make up test joint in hanger,test pipe rams and choke manifold to 250/2500 psi. Test annular to 250/1500 psi. 11/04/15—Test floor and dart valves t 250/2500 psi. Test accumulator and gas detectors. Change valve on choke manifold and test to 250/2500 psi. Pull BPV. Pull tubing hanger—free at 42 t , Fill casing with 1 bbl 9.9 ppg brine. Install flow nipple. Blow down lines and secure well for night. 11/05/15—Finish installing flow nipple and flowlines with flow sensor. Install weight indicator, lights, and pump line. 11/06/15—Finish hooking up to circulate. PU to unseat hanger. Fill hole with 7 bbl brine. PU to shear packers—work up to 90,000#--unable to get free(top packers probably released). Circulate at 2 BPM at 100 psi with no losses. PU jars, bumper sub,jars and jar on tubing with 40,000#over string weight. Work up to 97,000#pull. LD jars,bumper sub,and jars. RU Expro slickline and RIH. Close sleeve at 2688'. POOH. SDFN. 11/07/15—Pump around packer at 2701'at 1.5 BPM with 80 psi. Unsuccessfully attempt to close sleeve at 2739'3X. RD slickline. RU electric wireline. PU and set 42,000#on tubing. RIH with jet cutter and cut tubing at 3020'. POOH with wireline. Pull up to 97,000#—move 1'. RIH with 2nd cutter and cut tubing at 2905'. POOH with wireline and RD. SIFN. 11/08/15—Circulate well. LD hanger_ Pull free with 90k. POH and standback 43 stands with 30K initial pull. LD 2 sleeves, packer,5'cut-off,and 4 sand-eroded joints. MU overshot,jars, bumper sub,4-3-1/2" • • DC's and RIH on 43 stands+single tubing. Tag sand at 2887'. RU rotating head and wash sand to 2898'. Circulate clean. Pull 3 stands with 30Kto get above perfs. SDFN. 11/09/15—Tag tubing cut at 2904'. MIII over cut. Set grapple. Jar on packer(jars trip at 55K). Jar 20' uphole,then came free. Circ out sand at 3 BPM at 540 psi. Pull 43 stands. Pull and lay down 2 joints, packer, pup, sleeve, 5' cut joint. Make up new overshot, bumper sub,oil jars,4 DC's and RIH on 43 stands of tubing to 2680'. SDFN. 11/10/15—RIH to 2980'—tag fill. Wash to 3020 at 3 BPM,440 psi. Mill over tubing stump. Latch on and jar at 55K. Pulled 80K and came free. Circ clean at 3 BPM at 450 psi. POH with 45 stands. LD cut off joint, packer, pups,overshot, bumper sub,jars, and DC's. MU mule shoe and RIH to 2686'. 11/11/15—RIH to 3047'and tag fill. Wash to 3070',circ clean at 3 BPM at 450 psi. Filter brine with 50, then 25,then 10 micron filters. Displace hole with clean brine. POH. Test BOP's, 0 11/12/15—ND flow nipple, NU shooting flange. Install and test lubricator to 1600 psi. Run gun#1—pert I41 2886-2906'---100 psi;Gun#2—misfired; Gun#3—pert 2598-2618'-0 psi;Gun#4—perf 2528-42'-30 psi; Gun#5—misfire;and Gun#6-2442-60'-0 psi. RD Expro wireline. 0 psi on well. SIFN. 11/13/15—ND shooting flange, NU flow nipple. PU casing scraper and run on tubing to 3070'. Circ hole clean at 3 BPM,450 psi. POH, LD 10 its tubing, stand back 43 stands, LD scraper,etc. Start PU and run completion. 11/14/15—Continue in hole with completion. Drop bar to set RHCP plug in profile at 2959'_ Pressure test tubing to 2500 psi for 15 minutes. Increase pressure to 3500 psi to set hydraulic packers—hold for (;,::" 30 minutes. Packers set at 2943',2823',2675', 2490',and 2344'. Sliding sleeves at: 2866',2746',2534', 2413', and 2296'. Test annulus to 1500 psi. Set BPV. ND flow nipple, annular, rams, and X-0 spool. NU tree. 11/15/15—Pull BPV. Set test plug—test tree to 2500 psi. Pull test plug. RU Expro slickline. Test lubricator to 1500 psi. Run shifting tool and open sleeve at 2861'. POOH. MU swab assembly on slickline and run-3 runs, rec 10 bbl brine. 11/16/15—Fish with slickline: Run#1—run spear and tag at 580',engage, pull 1500#, came off. POOH. ..ti Run #2—run 3-prong wire grab—unable to engage fish. Run#3—Add skirt and rerun—push wire to 1-) , 1180'. POOH, Run#4—Run spear w/2.40"guide to 1180'—unable to engage. POOH. Run#5—Run 1- '`? 3/4' blind box to 2922'and beat on rope socket to break wire. POOH. Run#6—Run 2-prong wire grab w/skirt to 1220',engage and pull 2400#. POOH with 3" wire. Run#7—Rerun to 1220'and pull 2600#, working up and down to wear out swab cup. Pull to 1024'and lost. POOH. SDFN. 11/17/15—Fishing with slickline: Run#1—run 2-prong wire grab w/skirt(2PWG)to 1251', catch wire and pull 2859#, work up to 1208'and came free—POOH, rec 10'wire. Run#2—run 2PWG to 1260', catch wire and POOH w/4'wire. Run#3—Run 2PWG,catch wire,sheared pin in tool. POOH. Run#4— run retrieving tool and retrieve 2PWG w/2' wire. Run#5—run 1-3/4" blind box to 2941' and beat on rope socket to break wire. POOH. Run#6—run 2PWG, catch wire and pull 2000#--still connected to swab assembly. Run#7—run 2" blind box to 1270', unable to go deeper. POOH. Run #8—run 2PWG, engage at 1270'and pull 3700#--unable to break free. 11/18/15—Pull 3700#and came free. POOH. Shear GU connection to fishing tool. RD Expro. RU sand line to fish. Run impression block to 1270', POOH. Run overshoot, engage,and pull 13K. POOH with G5 sub. Run spear grapple,engage, pull 5000#, and POOH with 2PWG. RU Pollard slickline. Run 2PWG, engage, pull 4000#and pull free—POOH, recovering 1650'slickline, cutting off 50' at a time. Recover swab assembly and 2 bbl brine. Some gas to surface. RD Pollard. SIFN. 11/19/15—RU to swab w/sand line on rig. Swab dry to 2594' in 6 runs, rec 5-1/2 bbl brine. SI for build up-0 psi in 1 hour. RU Pollard. RIH to confirm sleeve at 2866' is open—stop at 2290'. POOH. Run 2- 1/4" bailer and cleanout to 2301'. POOH. Run swab-2 runs to 2350', rec% bbl each run. 11/20/15—SITP-70 psi. Bled off, RIH and run 2-1/4; brush to 2954',then run 2.27" gauge ring to 2696', working down to 2954'. POOH—GR shows scrapes from piece of wire. Swab to 2954' in 4 runs—rec 2- • • 1/2 bbl brine. Run shifting tool and open sleeve at 2413'.SITP built to 450 psi in 1 hr. Open well to test unit for 1 hour. SI for build up for 1 hr-210 psi. Flow to test unit for 1 hour—SI for build up-225 psi in 1 hr.Check FL-2830'. RIH and close sleeve at 2413', open sleeve at 2533'. Close sleeve at 2866'. SIFN. 11/21/15—SITP-475 psi. Set up to test. SITP-525 psi. Flow test perfs at 2526-2618'for Ya hr. SI for 1 hr—SITP-370 psi. Flow test for 1 hr. SI for 1 hr,SITP-290 psi. Close sleeve at 2533'. Open sleeve at 2746'—SIP-90 psi, increased to 105 psi. FL at 2100'. Swab well,7 runs, rec 3-3/4 bbl, FL at 2770'. Close sleeve at 2746'. Open sleeve at 2866'. Swab 3 runs, rec 2-1/4 bbl. FL at 2910'. Close sleeve and open sleeves at 2423'and 2533', leave open with well SI overnight. 11/22/15—SITP-980 psi. Flow test to test unit for 2 hrs. SI for/ hr. SITP-180 psi. Close sleeves at 2413'and 2533'. Bled tubing to 0 psi. FL at 2790'. RD slickline. Release rig and start rig down. Total losses-40 bbl brine. Total recovery-27 bbl. 11/23/15—Rig down and start move out of rig and support equipment. 11/24/15—Finish rig down and continue move out of rig and support equipment. 11/25/15—Continue move out rig and support equipment. RU Pollard slickline. Open sleeve at 2413'- 550 psi. Open sleeve at 2533'-350 psi. RD Pollard. Final SITP for day-840 psi. 12/02/15—MI Pollard slickline. 12/03/15—RU Pollard and run 2.25" lead-impression block(LIB)to 2946'. POOH—wire marks on LIB. RIH with wire-finder and wire grab to 2694,work thru to 2752', work thru to 2968'. Shear off. 6 runs to fish—recover tool. Run wire brush to 2972'—POOH with 20" wire. Repeat—POOH clean. RIH and retrieve RHCP plug—rec 2"wire in it. RD. 12/04/15—RU Pollard and RIH with shifting tool. Open sleeve at 2866' (2881' Pollard). Slight pressure increase,440 to 450 psi. FL at 2700'. RD Pollard. 12/21/15—RU Pollard—Run 2.25" bailer to 3085' (no fill). FL-2700'. RD Pollard. 12/28115—SITP--900 psi. Open well to compression—sell small volume before going down on low suction. 12/29/15—SITP-940 psi. 1/21/16—SITP-820 psi. Open well to compression—sell gas for 5 days. Production about 60 mcfpd (+/-10 mcfpd to sales+50 mcfpd fuel gas). • • 27/865#Srdtl:EJ-55 Aurrara Gas, LLC B 1 ' .„ i KALOA#2 Actual Configuration f ` f ! ` f November 2015 1 t12-3/4"65.9#Structural RKB—14.Oft t R Conductor driven to 116' t Drill 10-5/8"Hole to 868' — t 4 � i t Tyonek Tops t , 8-5/8"32#Surface Casing set at 617' Carya 2-3.2 2994' Cement w:14.5 ppg Gas-Block enhanced Carya 2-41-3154' 14. Carya 2-4.2-3248' - Cary*2-5.1-3402' Carya 2-5.2-3522' el f 3 WXA Sliding Sleeve 22%' t... ...--+..ams-,.n --.. "" New Perls: ; PHRP Hydraulic-Set Packer @2344' Carya 2-1.2 at p WXO Sliding Sleeve®2413' 244258' �-- 1 II -'-...... .....".'-'- 1:7 PHRP Hydraulic Set Packer @a • 2490' New Perfs: Carya 2-2 at =;:S11 WXO Shrouded Sliding Sleeve 2526-42'and i 1 2533' 2598-2618' P1-IRP Hydraulic Packer at 2673' Cana 2-3.1 WXO Sliding Sleeve at 2796' 2748-2764' r , 2774-2794' i PHRP Hydraulic Packer at 2823' oliimmissumusiiiiim New Perfs: a- WXO Shrouded Sliding Sleeve @ 2866' Carya 2-3.1 at -y■ 2886-2906' ' +tel, " PURI'Hydraulic Set Packer a;2943'w/8' I f pup wt 2.31 x profile:a,2959'w/RHCP .t aisa 2-3._ plit- 2` +-3111{' - plug,8' WI,entry guide®2969' PI-u4 -- i` Mechanical-set Packer®3083'wl On- 1 Off Tool wi Top of cutoff tubing at Carya 2-4.1 . 3071',bottom of WLEG at 3099'.PX 3158--78' "' 7ll .' plug set in profile at 3(183'. 3200-20' :IP , Tubing cut at 3104'w/OS&bait sub Carya 24top at 3101' 3250-3330' t :o1/2" to 14ft of 2-7/8"tubing then crosses to 3- i With 3-1/2"Stratapak screens fid; Bailed Fill inside tubing to 3152-3174' 3127'on 9/25/14 3197-3216' (SANDED IN) / { 3247-3329' S I. I 3522-3552' Carya 2-5.2 3522-52' / ti- S'W'17#J-5S Casing to 3,'14'?41D(TVD) Cement w/48 bbl 12.5 ppg+85 bbl 15.8 ppg PBTD @ 3400' Class'G' Drill 7-7/8"Hole to 3.720' 1%®F Tke • 0 /�4'"I%%i's-----N\.\\THE STATE Alaska Oil andGas �"' —7A OConservationCommission PF.,�► J1 t f LAsKA .,_,.li_i___ =-=-41till,-7 5}fix _ _ 333 West Seventh Avenue Ai GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 llag Main: 907.279.1433 ALAS- Fax: 907.276.7542 www.aogcc.alaska.gov 15 J. Edward Jones SCONES � O President ---.--C C[ Aurora Gas, LLC - "'' 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Albert Kaloa Field, Undefined Gas Pool, Kaloa 2 Sundry Number: 315-553 Dear Mr. Jones: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. 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, i0)(51.e......,4(14 . Cathy P Foerster Chair DATED this t6 day of September, 2015 Encl. • • RECEIVED STATE OF ALASKA SEP 1 0 201 ALASKA OIL AND GAS CONSERVATION COMMISSION b75 11 k (5 APPLICATION FOR SUNDRY APPROVALS AOGC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug Perforations❑ Fracture Stimulate ❑ Pull Tubing CI Operations shutdown❑ Suspend❑ Perforate Li Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Test new sands CI 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number: AURORA GAS,LLC Exploratory 2 , Development ❑ 204-096 3.Address. Stratigraphic CI Service ❑ 6.API Number: 1400 West Benson Blvd.,Ste.410,Anchorage,AK 99503 50-283-20107-00 7.If perforating: r446 8.Well Name`and Number: What Regulation or Conservation Order governs well spacing in this pool? 20 AAC as.056- �l O2 2 - Will planned perforations require a spacing exception? Yes ❑ No 0 / 9.Property Designation(Lease Number): 10.Field/Pool(s): CIRI Lease#C-061393 Albert Kaloa, Undefined Gas Field 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 3720' 3720' - 3600' - 3600' 3600' 3101' Casing Length Size MD TVD Burst Collapse Structural Conductor 116' 12-3/4" 116' 116' Surface 617' 8-5/8" 617' 617' 3830 psi 2530 psi Intermediate Production 3714' 5-1/2" 3714' 3714' 5320 psi 4910 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2748-3552 gross--see attached 2748-3552 gross--see attached 2-7/8" 6.5#J-55 8 Rd EUE 3068 Packers and SSSV Type: Deepest pkr is mechanical.No SSV Packers and SSSV MD(ft)and TVD(ft): ' HRP'ss at 2701,2942,3052'.Mech at 3083'. Hydraulic retrieveabli pkrs(HRF No SSV 12.Attachments: Description Summary of Proposal El 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ' Stratigraphic❑ Development Service ❑ 14.Estimated Date for Sept. 21, 2015 15.Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL El Suspended ❑ 16.Verbal Approval: Date: GAS 2 . WAG Cl GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ed Jones,713-899-8103 Email Printed Name J. Edward Jones Title President Signature Phone 907-277-1003/713-899-8103 Date Sept. 4, 2015 COMMISSION USE ONLY Conditions o approval: Notify Comm' ion so that a representative may witness Sundry Number:3\6 -6s-2.6s-2. Plug Integrity CIBOP Test l/ Mechanical Integrity Test CILocation Clearance CI Other: )F 250D /05am & (C 1 y -i- C AlAsl f3s-7/,5c-) / `,, 1--,..,.,:e /elt rf-2) - kyr w.:-. c. l7.P ,.� r1C-rCw• C44- F-74-i._i'4%-j.. 4-00 -�...-d Q ..4,4--C— 4,4--C—Z J. 2 3 S.-Yd.)" ) Spacing Exception Required? Yes ❑ No li Subsequent Form Required: /0 ` 0---i APPROVED BY , Approved by: P___; COMMISSIONER THE COMMISSION Date: 5 —�6 —�S aY47 `? /5��" -/ //II/1S— / /N'IS— ORo1eEft4Akd°' o EP Form 10-403 Re ed2015 for 12 rom the date A c m Duplicate • • . Aura Gas, LLC RECEIVED SEP 102015 September 4, 2015 AOGCC Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval Kaloa#2 Well PTD #204-096 and API#50-283-20107-00 Perforate New Intervals and Recomplete Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to add new perforated intervals to this onshore gas development well in the Albert Kaloa Undefined Gas Field, on the west side of the Cook Inlet, southwest of the village of Tyonek. The well is now completed in Upper Tyonek Sands, the Carya 2-3.1 thru the Carya 2-5.2, and the planned perforations are in the shallower Upper Tyonek Sands, the Carya 2-1.2, 2-2.1, and 2-2.2 and additional perfs in the 2-3.2, all to test for gas. The AWS #1 rig will be used to recomplete this well. The rig's well control systems are on file with the Commission. The rig is expected to be ready for the work to start about September 21, 2013. Please find attached information as required by 20 AAC 25.280 for your review. Pertinent information attached to this application includes the following: 1) Form 10-403 Sundry Application 2) Proposed Summary and Detailed Workover Procedure 3) Schematics of the current and proposed wellbore and completion. 4) BOP Sketch If you have any questions or require additional information, please contact me at (907) 277-1003 (September 9-16) or at 713-899-8103 (cell, any time). Sincerely, AURORA GAS, LLC eysr-s . Edward Jones / President CC: CIRI 4645 Sweetwater Blvd., Suite 200•Sugar Land,Texas 77479•(281)495-9957•Fax(832)999-4382 1400 West Benson Blvd.,Suite 410•Anchorage,Alaska 99503•(907)277-1003•Fax(907)277-1006 • AURORA GAS, LLC RIG RECOMPLETION WORKOVER PROCEDURE KA LOA #2 Late September 2015 Version 1.2 (9/3/15) CURRENT CONDITONS: Max SITP-800 psi (Blows down quickly). KB=14.0 feet CASING: 5-1/2", 17#J-55 set at 3714'MD/TVD. TUBING: 2-7/8", 6.5#J-55 8 rd EUE,w/9.9 ppg KCl-NaCl brine as packer fluid in tbg-csg annulus above top packer and with: Sliding Sleeves at: WXA at 2688' (closed—opens upward—now closed); WXO at 2739' (now open); WXO at 2980' (now open); 2.31"X nipple at 3061' (now open); and 2.31"X nipple at 3077' (will be plugged at time of workover) to/ Px Packers: PHRP's at 2701', 2942', and 3052' and disconnected Arrowset IX at 3083' 3-1/2" Screens at: 3104' to 3552' w/bull plug (plugged with sand at 3127' last run, 9/25/14) (See attached well bore and completion diagrams) CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing-Casing Annulus: 0.0152 BPF; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to Plug in bottom packer---18.4 bbl, Annular Volume to top Packer=41.1bbl; to deepest packer= 65.3 bbl (bottoms up); Casing Volume to Arrowset Packer at 3083'= 71.5 bbl. PERFS: Carya 2-3.1at 2748-64' and 2774-94' behind Sleeve at 2739' (partially depleted) Carya 2-3.2 at 2995-3015' behind Sleeve at 2980' (partially depleted) Below deepest packer(which will stay in place): Carya 2-4.1 at 3158-78' and 3200-20', Carya 2-4.2 at 3250-3330', and Carya 2-5.2 at 3522-52'. NOTES: 1) Well is a straight hole. , �i3643w`� SUMMARY OF PLAN: Set PX plug in deepest packer(will not retrieve—not on tubing), kill well, release packers, circulate out, circulate well with 9.9 ppg brine (if necessary set packers to isolate any current perf intervals to avoid fluid losses), add perfs,run completion, swab in and test. PROCEDURE: 1) Pick and move wellhouse. 2) Prior to moving in rig,perform Slickline Procedure: RU Pollard. RU lubricator—test to 800 psi with tubing pressure. RIH w/2.25 bailer and clean out to 10' below X profile in On/Off tool at 3077'. Set PX plug in 2.310"profile at 3082'. RD Pollard(need to have them back on location after rig up). • • 3) Move in, rig up AWS #1 rig w/single workover pit for mud system (not AG mud system) and support equipment only as needed for workover(one gen set, 1 mud pump, etc.). Also, move in and spot Aurora Gas choke skid,test unit, and flare. 4) Starting with clean mud pit, mix 150 bbl (usable volume) 9.9 ppg 3%KC1-NaC1 saturated brine (3% KC1-11#/bbl+weight up with oilfield salt, 90#/bbl), using clean fresh water. Fluid weight may change pending outcome of slickline work—max expected kill weight of open any perfs is less than water gradient ppg, but may have to deal with losses into depleted intervals. Filter brine with _ 25 then 10 micron filters until clean. 4,11 ��-Sf- /. cop S 5) Set GE 2-way check in hanger. ND tree,NU 3000-psi BOPE. Test to 25l00 psi (or as required by AOGCC Sundry approval). Pull 2-way check—release GE. 6) RU Pollard w/pump-in sub on lubricator w/choke and HP hose back to mud pit. a) RIH and open WXA sleeve at 2688' (opens upward)-909 ppg brine will "U-tube"up tubing. b) Pump down casing to fill casing with new 9.9 ppg brine and equalize tubing and casing pressures. c) RD Pollard. d) Monitor losses—if not significant, go to Step 7. e) If losses are significant(more than 5 BPH), mix and circulate 20 bbl "Baraplug" LC pill(s) if needed (see Notes below)—let"soak"when displaced to upper perfs (+1-16 bbl),then if needed, displace second pill to lower perfs (+/-18 bbl). When losses are controlled, go to Step 7. If losses are not readily controlled, we will set packers before perforating—go to Step 7.c below,then Supplemental Procedure. 7) Screw into tubing hanger, and release hold downs. Then pull tubing and completion as follows: a. Pull to release the three hydraulic packers (approx 48,000# overpull) b. Reverse circulate out any gas seen in casing and equalize brine weight—should be about 9.9 ppg all the way around. Circulate filtered brine all the way around. Monitor loses (depleted perfs at 2748-94' and 2995-3015' now open). If losses are less than 5 BPH, go to Step 7.d below. c. If losses are serious, greater than 5 BPH, reduce brine weight in active pit to 8.9 ppg using 3% KC1 water. Monitor losses. Pump additional 20 bbl Baraplug pill(s) to control losses. d. When well is dead and losses are contained,then POH, standing back tubing and laying down packers and sliding sleeves. Strap out of hole and keep good records. Monitor hole and keep full. Expect some losses. e. NOTE: if losses are serious and the hole is filled with 8.9 ppg brine, go to Supplemental Procedure. If losses are not serious and hole is filled with 9.9 ppg brine,so to Step 8. 8) RU perforators w/lubricator. Run GR/CCL correlation log and correlate to Platform Express log of 7/6/04. r � .y ,�.. z a) PU 3-3/8"Millennium Deep-Penetrating perforating guns,test lubricator to 1600 psi, and RIH to perforate "2-3.2 Sand" at 2886-2906' (20') w/ 6 SPF w/ 60-deg phasing. Watch for gas, pressures, and fluid level in casing while shooting. b) Perforate the "2-2.2 Sand" at 2598-2618' (20') c) Perforate the"2-2.1 Sand" at 2528-42' (14') d) Perforate the"2-1.2 Sands" at 2442-60' (18') e) POOH, LD perf guns, RD wireline. (4 runs, 71' of perforations). • • NOTE: some of the zones may be slightly underbalanced, but I don't expect any significant gas due to permeability. If pressure builds, pump 10 bbl of clean 10.0 ppg brine into well and monitor; repeat as needed. 9) PU casing scraper and bit and run thru new perfs, to tag bottom at 3071'. Circulate wellbore clean. POH and LD bit. . 10) PU following completion BHA and RIH on 2-7/8"tubing, visually inspecting and replacing questionable collars or whole joints, as follows: NOTE:Rabbit all tubing before going in hole and watch torque DO NOT OVER TORQUE. a) Hydraulic-set Packer w/6-8' pup joint of 2-7/8"tubing, X nipple, 4-6' pup joint, and WLEG below. Run PX plug in X nipple below packer to set hydraulic packers,to set at+/-2950'. (Will run mechanical packer w/on-off tool only if we go with Supplementary Procedure due to brine loses in open perfs). b) 3 jts 2-7/8"tubing, c) 2-7/8" Shrouded Sliding Sleeve to be set at+1-2855' d) 1 jt 2-7/8"tubing, e) Hydraulic-set packer to be set about 2820', f) 3 jts 2-7/8"tubing, g) 2-7/8" Shrouded sliding sleeve at about 2730', h) 2 jts 2-7/8"tubing, i) Hydraulic Packer at about 2660' j) 4 jts 2-7/8"tubing, k) 2 2-7/8"pup joints for 16' 1) Shrouded Sliding Sleeve at 2520', m) 1 jt 2-7/8"tubing, n) Expansion Joint, o) Hydraulic-set Packer to 2480' p) 2 jts 2-7/8"tubing, q) Shrouded Sliding Sleeve at 2420', r) 2 jts 2-7/8"tubing, s) Hydraulic-set Packer at about 2355', t) 1 jt 2-7/8"tubing, u) XA sliding sleeve, v) 2-7/8"tubing to surface 11). Space out, land tubing, and lock down. Pressure test tubing to 2500 psi, then pressure up to set hydraulic packers (against existing plug in profile in on-off tool at 2960'). Bleed off pressure. {- r4 Install BPV. ND BOP. NU and test tree. Pull BPV. (Be rigging up AG test choke manifold, 1--.4 t4 separator, and flare stack, connected with hardline during this time). 12) RU Pollard slickline unit and lubricator,test lubricator to 1500 psi. RIH w/shifting tool and open .s_,s- sliding sleeve at 2855'. POOH. RD Pollard (but do not release to go to town, will have other work in field for them to do). 13)RU to swab and swab in Carya 2-3.2 perfs at 2886-2906' and test thru test separator. SEE SUPPLEMENTAL TEST PROCEDURE, II below. Allow to cleanup. SI for 1 hr buildup. Open to flow and allow to stabilize at about 80% (or more) of SITP. SI, and watch buildup for 1 hr. 14)RU Pollard. Test lubricator to tubing pressure and maintain pressure on tubing. RIH and close sleeve at 2855'. Open sleeve at 2520'. RD Pollard. Test 2-2 sand perfs at 2526-2618' as in Step 19 above. Tubing s/b essentially dry so no swabbing should be needed, unless perfs are making water. 15)RU Pollard. RIH and close sleeve at 2520' and open sleeve at 2420' to test 2-1 sand interval 2442- 58' as in Step 19 above. NOTE: AWS rig will be released when 2 zones are successfully tested at rates above 1 MMcfpd each w/o significant drawdown (FTP>75% SIP). 16)RU Pollard. RIH and close sleeve at 2420' and open sleeve at 2730' to test interval old perfs at 2748-94' as in Step 19 above. 17)Based on test results, determine initial configuration of well for production(probably deepest, driest interval) and RIH w/Pollard to pull plug and/or open sleeves to facilitate configuration. RD Pollard. RD AG test equipment. Turn well to operators to reconnect flowline and put to sales thru production facility. Ed Jones (6/26/15) Rev (7/28/15) NOTES: I. BARAPLUG RECIPE System Formulation: Saturated Salt Water- .888 bbl Salt- 109 ppb System Formulation: Sized Salt Bridging Pill Product Concentration Saturated Brine 0.83 bbl Baradefoam HP 0.1 ppb Citric acid 0.5 ppb BARAZAN D+ 2.0 ppb N-DRIL HT+ 4 ppb caustic .1 ppb(to a 9.0 pH) Baraplug 20 30 ppb Baraplug 50 27.5 ppb Baraplug 6/300 10 ppb Aldacide G 0.1 ppb Special Mixing Instructions: • Mix in order as listed • Please note that we will manipulate the pH to speed the additions of polymer • A can of X-Cide 207 must be added to any pills mixed. Adjust the pH of the brine for the pill to a 5.0 or less with citric acid. Then the BARAZAN D+ and N- DRIL HT+ can be added rapidly though the hopper. After all the polymer is added, adjust the pH back up to a 9-9.5 with caustic. The polymer will then yield. Check the YP after adding the caustic. The YP should then be adjusted to the 35-40 range with BARAZAN D+ if needed. The Aldacide G should be mixed in all fluid entering the wellbore. If possible, add it in the suction pit or below the mud line (inline chemical injection pump on the suction?). The Mud Man will make all additions of Aldacide G or supervise closely. Further additions of fluids will require the additions of Aldacide G. When pumping a kill pill, remove suction and DP screens. Pump pill at a fast rate as this will help maintain the integrity of the pill. When the pill gets to the perfs slow the pumps down to 1-1.5 bbl/min. Continue pumping until 200-400 extra psi is observed. Shut the pump down and watch for the pressure to bleed off. Repeat this procedure until it takes 10-15 minutes for the pressure to bleed off. Be careful not to over displace while squeezing and wash the pill away. If no squeeze pressure can be obtained, stop pumping and let the pill soak into the perfs. 3% KCI Saturated NaCI brine: 0.888 bbls Water+11 ppb KCI+98 ppb NaCI Saturation will be a 9.9+ ppg MW 9.3 ppg 3 % KCl NaC1 Brine: 11 ppb KC1 and 55 ppb NaCl II. TEST SUPPLEMENTATL PROCEDURE A. Prepare for test: 1) Take and record initial measurements of brine levels in all tanks to which swabbed/flowed back brine will go—know exact volume of brine is in all tanks; 2) Record test separator water meter reading; 3) install new chart on Barton recorder; 4) install fresh nitrogen bottle onto skid for instrumentation(or use separator pressure); 5) install Pollard SPIDR surface pressure recorder(or new 2000-psi pressure gauge)near test head, isolated with needle valve (upstream from valve that will shut in well for buildup—will want it to record and show SI pressures), and 6) confirm electric clock on chart recorder is on and set to 12 hrs. B. RU to swab. Swab in perfs and flow test until clean and stable, as follows: 1) swab in, unloading fluid to shaker/possum belly until well is gassing and/or kicks off to flow; 2) when significant gas is at surface (whether swabbing or flowing) or the well is flowing, divert flow to test separator: a) shut down momentarily to light flare stack,then bring back on, adjusting choke size until well is flowing strongly to cleanup,but holding significant back pressure on it(probably start at 24/64's and adjust accordingly,target flow at 75%of SITP (expect SITP to be 1200- 1500 psi, so target stabilized flowing tubing pressure above 900 psi). bi) Flow for an hour or more and until rate and pressure have stabilized for 15 minutes (i.e., pressure on SPYDR changes less than 2 or 3 psi in 15 minutes, increasing slightly is OK, but dropping is not—wait until fluctuations tend to be up, not down) and water has dried up (all of tubing volume+ casing volume to bottom of top set of perfs has been recovered, up to 15 bbl or rate has stabilized . Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water production and cleanup. c) Test meter has 1-1/2"orifice in it. Flow rate in mcf/day= static reading(blue)X differential reading(red)X 70, (if temperature reading (green) is 5.5-6.0, slightly higher for lower green reading and lower for higher green reading). If red chart reading is below 3, change to 1.0" orifice; if it is above 8 change to 2.0" orifice. Meter factors change to 31 or 130, respectively. Orifices may be changed by experienced operator while flowing w/the Daniel Sr. orifice fitting. d) Catch water samples thru out(downstream of test separator) -have tested by mud man for chlorides and weight—record both and time of sample. Produced water should have • • chlorides of less than 20,000 ppm and and weight is less than 8.5 ppg—if water is trending in that direction, continue to flow until these properties have stabilized, if the gas rate is above 1000 mcf/day. Keep last sample of produced water to send to lab in Anchorage—label thoroughly. 3) SI for pressure buildup (at least 2 times longer than flow period or until pressure is building at less than 1 psi/15 minutes on SPIDR). • • 2 7/8 6.5#8rd EUE J-55 Aurora Gas, LLC KALOA #2 Current Configuration 12-3/4"65.4#Structural August 2009 Conductor driven to 116' RKR—14.Oft • Drill 10-5/8"Hole to 868' 8-5/8"32#Surface Casing set at 617' Cement w/14.5 ppg Gas-Block enhanced Tyonek Tops Carya 2-3.2—2994' Carya 2-4.1—3154' Carya 2-4.2-3248' Carya 2-5.1—3402' WXA Sliding Sleeve @ 2688' Carva 2-5.2—3522' PHRP Hydraulic-Set Packer @ 2701' WXO Sliding Sleeve @ 2739'(open) Carya 2-3.1 Com` 2748-2764' 2774-2794' } PHRP Hydraulic Set Packer @ 2942' WXO Sliding Sleeve @ 2980'(open) Carya 2-3.2 2995-3015' PHRP Hydraulic Set Packer @ 3052' w/2.31 x profile(b)3061' w/WL entry guide @ 3068' Mechanical-set Packer @ 3083'w/On- — sr Off Tool.Top of cut-off tubing at 3071', • Carya 2-4.1 bottom of WLEG at 3099' 3158-78' 3200-20' Tubing cut at 3104'w/OS&bait sub top at 3101' Carya 24.2 14ft of 2-7/8"tubing then crosses to 3- 3250-3330' • 1/2" With 3-1/2"Stratapak screens @ 3152-3174' 3197-3216' (SANDED IN) 3247-3329' 3522-3552' Carya 2-5.2 3522-52' 5'/2"17#J-55 Casing to 3,714'MD(TVD) Cement w/48 bbl 12.5 ppg+85 bbl 15.8 ppg PBTD @ 3,600' Class'G' Drill 7-7/8"Hole to 3,720' • • 2 7/8 6.5#8rd EUE J-55 Aurora Gas, LLC • KALOA #2 Proposed Configuration August 2015 12-3/4"65.4#Structural RKB—14.Oft , Conductor driven to 116' 4 Drill 10-5/8"Hole to 868' Tyonek Tops ' Carya 2-3.2—2994' • 8-5/8"32#Surface Casing set at 617' Carya 2-4.1-3154' / `; Cement w/14.5 ppg Gas-Block enhanced Carya 2-4.2-3248' Carya 2-5.1—3402' ' Carya 2-5.2—3522' • ' dp WXA Sliding Sleeve @ 2315' • .•6.) ' e PHRP Hydraulic-Set Packer*2355'New Perfs: , ,, till Carya 2-1.2 at �M WXO Shrouded Sliding Sleeve @ 2442-58' 2420' ;' PHRP Hydraulic Set Packer @ 2480' 0 New Perfs: l,°', li Carya 2-2 at --- WXO Shrouded Sliding Sleeve @ 2526-42'and 2520' 2598-2618' r , PHRP Hydraulic Packer at 2660' Carya 2-3.1 �7y� WXO Shrouded Sliding Sleeve at 2748-2764' 1b 2730' 2774-2794' ` — — , a PHRP Hydraulic Packer at 2820' a) New Perfs: • `�' ., WXO Sliding Sleeve @ 2855' Carya 2-3.1 at =I 2886-2906' r= , Hydraulic-Set Packer @ 2950'tool and 8' c.✓/ O) r 7 Carya 2-3.2 pup w/231 x profile @ 2960'and WL ' 2995-3015' entry guide @ 2967' Mechanical-set Packer @ 3083'w/On- /^� < Off Tool w/PX plug. Top of cut-off i.Jf f /a ,-- Carya 2-4.1 t tubing at 3071',bottom of WLEG at 3158-78' ' 1113099' 3200-20' Tubing cut at 3104'w/OS&bait sub top at 3101' Carya 2-4.2 ...% !IT:. 14ft of 2-7/8"tubing then crosses to 3- 3250-3330' 1/2" Ia' With 3-1/2"Stratapak screens @ Bailed Fill inside tubing f/ ., 3152-3174' 3068 -3127'on 9/25/14 - 3197-3216' (SANDED IN) 3247-3329' ' 3522-3552' Carya 2-5.2 3522-52' , 5''A"17#J-55 Casing to 3,714'MD(TVD) Cement w/48 bbl 12.5 ppg+85 bbl 15.8 ppg PBTD @ 3,600' Class`G' Drill 7-7/8"Hole to 3,720' • • Aurora Well Sc vviice Rig No. I: Proposed 3M BOP Configuration /C ALoA '&2_ °`<,, Bell Nipple with flow line to pits Fill Up Line ' (i�`"` S te-;it.' .„.„---/ 1--...„., e 3M Schaffer Annular Preventer Pipe Rams sized to work string. f I 11"3M Double Gate wizyW'pipe rams installed. 1K 3M Mud Cross Blind Rams �3"5M Manual Valve (Choke Line) 3"5M Manual Valve(Kill Line) �� s--_ t 5M Hydraulic Valve .--3"5M Hydraulic Valve (Kill Line) ■ � •• FF , } 1.111441-:: Well rte` (Choke Line) Fluid stow direction �♦ while reverse circulating s. 4r,, r i t,/ 7_41b fen aero Cl �` _M_ ' l�lw B4 iiilri um 1�I IU. 7-1/16 3M 89 C2 Truth �� ; w' -B11 t Well fl 10 .,.. St;i /01-irir 4 j 4I 1 B12 Id Ael .� � B6 B5 mi l;- '"1 1111 B2 B 1 BIB B1 i 4 �: it,. ' M �� A 1� ';� B14 A5 `' B13 Irl l I„ 11M_. A6 coil ii...1" .4 �i:i i A2 1 .., � A3 A4 illi k Al � � � ` 1 $;/9 ' ClDCSG 2-7/8' OD TBG ------ -. 'r Na -5 .ai-C 5-1/2' EIB CSG ALL DIMENSIONS ARE ApPROX_ l • • - Aurora Well Servicejtig No. l Proposed Choke/ Kill Manifold Configuration All -valves are 3" rated at 5000 psi. op 7 / Output to Pits Inlet from Power Swivel (Reverse Circulation Mode) 2",M Rated Valves Hydraulic Remote Activated choke 1 • Inlet from BOP Choke Line I- t wirr 3"511.1 Rated II Valves m .raw ail II t I. ''-""""" (S Bleed Flare Line to ii 3"5M Rated Open Flare Fit II Valves 3"5M Rated Valves 0 , 1.„,—„i', • - .1t III - -H ';rIfit. -=E-, __ ' Manual Choke 2"SM Rated 0 Valves1.j To Gas Buster "Atmospheric Degasser" ��� Drawing Not to scats�_-. Aurora Well Service Choke Manifold . a I • 1 w I . a.. h oZ — * I-1 o — 1 d f �=aE.u oa L--_ ---J i x x x M s O _ Ill —1 0 Dig O gN ,------, age k@ @ m Imo .. ® ��i §- IS m _ '11 ! 1 0 'IlIlk 2 z I 1 c gr c 4 oil L L-- -- ------ il 1,0- 11, I1 ch cos Dm rY I I ig ,L.V. --cc.il v _,, a- - 1 1 9= .iii . u= iii s = n 9 , r a 1 i co I q I U t co I 6 • • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday, September 15, 2015 10:04 AM To: 'Ed Jones' Cc: Bettis, Patricia K (DOA); Regg,James B (DOA); George Pollock Subject: RE: Kaloa#2 (PTD 204-096) Ed, Thanks for the information below. AOGCC will grant a flaring variance as part of the sundry approval based on your response in question 5. You won't need to apply separately. Regards, Guy Schwartz Senior 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). From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Tuesday, September 15, 2015 9:36 AM To: Schwartz, Guy L(DOA) Cc: Bettis, Patricia K(DOA); Regg, James B (DOA); George Pollock Subject: RE: Kaloa #2 (PTD 204-096) Guy, In response to your questions about the Kaloa 2 10-403: 1) We use a shooting flange that we rent from Weatherford for perforating and slickline lubricator connection to the annular preventer on the BOP stack. 2) Expected pressures:from MDT data,which has proved optimistic in the past in these relatively tight sands (higher than actual, probably due to either supercharging during test or formation damage), the MASP is just Q less than 1500 psig from the new perfs at 2886-2906'. The MDT BHP was measured at 1605 psia. No other 4`S proposed perf intervals had MDT tests. However,one previously perforated interval had an MDT test: 1466 psia at 2791',the shallowest MDT pressure obtained,which calculates to give a 1357 psig SIP. This interval was perforated in 2009 and had a SIP of 1220 psi. 3) A casing-tubing annulus test to 1500 psi has been added to the Procedure in Step 11—see attached. (We do inadvertently routinely, it was left out of the procedure). 4) Testing Layout: See attached P&ID. The specs are: . The SDV is pneumatic-actuated but not pilot operated,as the test skid is always manned and pressures vary too much over the test to use pilot settings effectively. 5) Since these tests will all be relatively short(1 hour cleanup, 1 hour stable flow,with possibly 2-3 hours of flow prior to stabilization), and there will be as many as 5. If we have a maximum rate of 1500 mcfpd during the test 1 I v • (pretty optimistic for these sands),we would flow a total volume of less an 1600 mcf. How do we go about • requesting a variance (is this email acceptable,or do you need a more formal request)? 6) Yes,we are expecting that an inspection of the rig will be required. Please let me know if you need additional information. Regards, Ed J. Edward Jones President Aurora Gas, LLC 4645 Sweetwater Blvd.,Suite 200 Sugar Land,TX 77479 281-495-9957 (0) 713-899-8103 (C) 832-999-4382 (F) From:Schwartz,Guy L(DOA) [mailto:guy.schwartz(E alaska.gov] Sent: Monday,September 14,2015 2:21 PM To: Ed Jones<jejones@aurorapower.com> Cc: Bettis, Patricia K(DOA)<patricia.bettis@alaskao\:>; Regg,James B (DOA)<iim.regg@alaska.gov> Subject: Kaloa #2 (PTD 204-096) Ed, In reviewing the sundry application for Kaloa#2 I have a couple of questions: 1. How is slick line/Eline going to rig up with lubricator on the top of the BOP stack(step 6 and step 8) ? Shooting flange or?? 2. What pressures are you expecting with the new formations being perfed and what would that MASP calculate to ? 3. In step 11 after setting the packers an inner annulus test(MIT-IA) needs to be done before rigging down the BOP stack to verify that the packers are set and holding pressure. 4. Need a sketch of your testing layout: ,flare, piping, choke,separator, ESD system ,safety valves etc 5. Do you have an estimate of total volume you will likely flare for testing? You may request a variance under 20 AAC 25.235 (d)(6)for well testing. 6. AWS#1 rig will need an AOGCC inspection before starting up again. I believe it has been idle for a while. We will do that for the initial BOPE test most likely. Guy Schwartz Senior 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). 2 -- - Image Project Well History File Cover Page XHVlE 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. aO ~ - 0 ç¡ (p Well History File Identifier Organizing (done) vhWO-Sided 11111111I1111111111 R,CAN ¢' Color Items: D Greyscale Items: DIGITAL DATA D Diskettes, No. D Other, NolType: D Poor Quality Originals: D Other: NOTES: Date ~ IJ h/o/r; I BY: ~ Project Proofing Date Ii? II (pio to 5" x 30 = ,.s-D Date: ~ (p BY: .("1ii1aria ;;> - /5/ ty1p Production Scanning Stage 1 Page Count from Scanned File: ~. (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ YES BY: ~ Date: <ö II (p I 0 10 Scanning Preparation BY: Stage 1 If NO in stage 1, page(s) discrepancies were found: BY: Maria Date: Scanning is complete at this point unless rescanning is required. o Rescan Needed 1111111111111111111 OVERSIZED (Scannable) o Maps: o Other Items Scannable by a large Scanner OVERSIZED (Non-Scannable) ¢ logs of various kinds: o Other:: /5/ ~p 1111111111111111111 +L = TOTAL PAGES 15'~ ~Count does not include cover sheet) . 10 /5/ r 11111111111111 11111 YES NO /5/ VV\ f NO /5/ 11111111111I11 1111I ReScanned BY: Maria Date: /5/ Comments about this file: ì-\' .... ... , (~.P, ~ôP v è;T !f:¡\?J 11111111111111" III Quality Checked 111111111111111111I 1 0/6/2005 Well History File Cover Page.doc STATE OF ALASKA ALASK~L AND GAS CONSERVATION COMMIS•N GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: ~ Initial Annual Special 1b. Type Test: Stabilized Non Stabilized ~ Multipoint ^ Constant Time ^ Isochronal ^ Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC October 5, 2004 204-096 3. Address: 6. Date TD Reached: 12. API Number. 1400 West Benson Blvd, Suite 410, Anchorage, AK 99503 July 6, 2004 50- 283-20107-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 1308' FNL,1706' FEL, S26, T11N, R12W, SM ~ 213.6' Kaloa #2 Top of Productive Horizon: ~~ ~ ` 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): ~~° ~ ' Same a,~,~~`~~,~~'` ~ 3,600' MD &TVD Kaloa Gas Field " ~" D +TVD Total Depth: ~ ): 9. Total Depth (M Same 3,720' MD &TVD 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 260774.49 y- 2566864.64 Zone- 4 N/A C-61393 TPI: x- Same y- Same Zone- 4 16. Type of Completion (Describe): Total Depth: x- Same y- Same Zone- 4 Sand Control Screens below packer across casing perforations. 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 5-1/2" 17 Ib/ft 4.892" 3,715' 3,522-3552 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 3,250-3,330, 3,200-3,220, 2_7/8 6.5 Ib/ft 2.441 Screen @ 3,152' 3,158-3,178 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 3,079 N/A None 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): Q Tubing ^ Casing 89 F° 1,564 psis @ Datum 3,136' TVDSS 14.7 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO2: % N2: % HzS: Prover: Meter Run: Taps: 3,355' 3355' 0.56 0 0.84 0 Daniel Sr. 4.026 Flange 26. FLOW DATA TUBING DATA CASING DATA N Prover Choke )( Orifice Li Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow o. ne psig Hw F° psig F° psig F° Hr. Size (in.) Size (in.) 1• 4.026 X 2 993.9 33.64 57.66 1356 55 1hr 2• 4.026 X 2 1006.2375 42.25 57.66 1342 58 1hr 3• 4.026 X 2 1003.764 $2.41 57.66 1308 60 1hr 4• 4.026 X 2 993.9 74.8225 59.535 1287 62 45 min 5. X Basic Coefficient P Pressure Flow Temp.. F Gravity Factor Super Comp. F t Rate of Flow No. (24-Hour) hw m Pm actor F 9 or ac O~ Mcfd Fb or Fp Ft Fpv 1. 20.32 184.20 1008.6 1.003 1..333 1.001 5,009 2. 20.32 207.69 1020.9375 1.003 1.333 1.001 5,648 3. 20.32 252.12 1018.464 1.003 1.333 1.001 6,856 4. 20.32 274.71 1008.6 1.003 1.333 1.001 7,470 5. for Separator for Flowing No. Pr Temperature Tr z Gas Fluid T Gg G 1. 0.9981 0.562 0.562 2. 0.9981 0.562 0.562 3. 0.9981 Critical Pressure 0.562 0.562 4. 0.9981 Critical Temperature 0.562 0.562 5. Form 10-421 Revised 1/2004 CONTINUED ON REVER~~C~rA~ FEB 2 3 2010 it in Duplicate Pc 1,448 pct 2,096,704 • P 1,570 p{~ 2,464,900 No. Pt Ptz Pcz-Ptz Pw Pv~ Pct-Pv~ Ps PsZ Pf -Ps2 1. 1,371 1,879,641 217,063 138 19,044 2,077,660 1,509 2,277,081 187,819 2. 1,357 1,841,449 255,255 146 21,316 2,075,388 1,503 2,259,009 205,891 3. 1,323 1,750,329 346,375 160 25,600 2,071,104 1,483 2,199,289 265,611 4. 1,302 1,695,204 401,500 169 28,561 2,068,143 1,471 2,163,841 301,059 5. 25 AOF (Mcfd) 33,754 Remarks: AOF and n Calculated using Ryder Scott Software, see attached spreadsheet I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~~~~ Title Mgr. Production Ops & Eng n 0.75 Date 2/22/2010 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin face were reduced to zero psis. Fb Basic orifice factor Mcfd/ hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= /1 Z 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 i ~ ,--~, R~dcr ticott WELL NAME: AURORA GAS KALOA#2 __ _ ', Reser~~oir FIELD: KALOA GAS FIELD ~`~ Solutions LOCATION: T11N R12W, SM (West Side of Cook Inlet), ALASKA (Public) RESERVOIR: CARYA(U,PPER TYONEK) 3158-3552' ~'r;~tL u_~~7 , BOTTOM HOLE TEMP, °F: 89 SOUR GAS MOLE °a GAS GRAVITY: 0.560 Nz 0.84 HZO GRAVITY, y~;: 1.020 COZ 0.00 COND. GRAV., °API: H2S 0.00 TVD, FT: 3.355 MEAS. DEPTH, FT: 3.355 Options Cond. Correl. (Y/N): N ~ Check, If Injection Well Corrected` Tc, °R: 344 02 Corrected' Pc, Psia: 672.21 '~ Srnooth Pipe Roughness Pressure Base, Psia: 1#.650 TUBING ID, IN.: 2.441 * Wichert-Aziz correction for cont aminants, if any RESULTS AOF, Mcf/d: 33,754 C: 0.533915 n: 0.750472 ~~_ POINT NO. Test Data FLOWING (Automatic) Q, Mcfld BCPD BWPD FTP, Psia WHT, °F BHP, Psia COMMENT SHUT-IN 0 0 0 1,448 52 1,570 SIBHP 1 5,009 0 0 1,371 55 1,508 2 5,648 0 0 1,357 58 1,497 3 6,856 0 0 1,323 60 1,475 4 7,470 0 0 1,302 62 1,459 These results were prepared using Reservoir Solutions Software . This is not Ryder Scott work product. ._ ~ o00 otu~ i;~n oti% F.oer Rzte.. 'I~cf'd Aur~or~ Gas PLC ~~ www.aurorapower.com February 1, 2010 Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission 333 West 7~` Ave., Suite 100 Anchorage, Alaska 99501 Attn: Mr. Steve McMains Re: Report of Sundry Operations: Kaloa No. 2 (309-249) Dear Mr. Seamount: ~EC~ivEa FEB 0 1 ?010 Ahsks 0~ ~ 6a~ Cony. Commission An~harapn Aurora Gas, LLC hereby submits the Report of Sundry Operations at the above referenced natural gas production well (PTD # 204-096, API # 50-2$3-20107-00). Attached is AOGCC Form 10-404, a final wellbore diagram, Operations Summary, and the RST open hole log. If you have any questions or require additional information, please contact the undersigned at 277-1003, or Mr. Ed Jones at (713) 977-5799. Thank you for your time and consideration. Sincerely, Bruce D. Webb Manager, Land and Regulatory Affairs attachments cc: Kim Cunningham, CPA Director of Land and Resources Cook Inlet Region, Incorporated 2525 C' Street, Suite 500 Anchorage, AK 99503 1400 West Benson B/vd., Suite 410 • Anchorage, AK 99503 • (907) 277-1003 • Fax: (907) 277-1006 6051 North Course Drive, Suite 200 . Houston, TX 77072 • (713) 977-5799 • Fax: (713) 977-1347 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPER~4TIONS 1.Operations Abandon Repair Well ~ Plug Perforations Stimulate Other ~ Test WGA Pertormed: Alter Casing ^ Pull Tubing ~ Perforate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown ^ Perforate Q Re-e er Suspended Well ^ 2. Operator 4. Well Class Before Work: Permit to Drill Number: Name: Aurora Gas, LLC Development ~ Exploratory ^ 204-096 3. Address: 1400 W. Benson Blvd., Suite 410 Stratigraphic^ Service ^ 6. API Number: Anchorage, AK 99503 ` 50-283-20107-00 7. Property Designation (Lease Number): 8. Well Name and Number: CIRI Lease #C-061393 ~ Kaloa #2 9. Field/Pool(s): Albert Kaloa Undefined Gas Field 10. Present Well Condition Summary: Total Depth measured ~ 3,720' feet Plugs (measured) Alaskl 8t 6as Cons. Consni:s true vertical 3,720' feet Junk (measured) feet At~ehdts Effective Depth measured 3,800' feet Packer (measured) 2,701' - 3,083' feet see below true vertical 3,600' feet (true vertical} ~ 2,701' - 3,083' feet see below Casing Length Size MD TVD Burst Collapse Structural Conductor 118' 12-1/4" 116' 118' Surface 817' 8-518" 81 y' 617' 3,930 psi 2,530 psi Intermediate 3,714' S-1/2" 3,714' 3,714' 5,320 psi 4,910 psi Production Liner Perforation depth: Measured depth: 2,748'-2,764', 2,774'-2,794', 2,995'-3,015', 3,158'-3,178', 3,200'-3,220', 3,250'-3,330', 3,522'-3,552' True Vertical depth: 2,748'-2,764', 2,774'-2,794', 2,995'-3,015', 3,158'-3,178', 3,200'-3,220', 3,250'-3,330', 3,522'-3,552' Tubing (size, grade, measured and true vertical depth}: 2-7/8" 6.5#, 8 Rd EUE, J-55 3,088' 3,088' Packers and SSSV (type, measured and true vertical depth): 5-1/2" PHRP Hydraulic 2,701' 2,701' 5-1@" PHRP Hydraulic 2,942' 2,942' 5-1/2" PHRP Hydraulic 3,052' 3,052' 5-112" Mechanical 3,083' 3,083' 11. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 125 psi 15 psi Subsequent to operation: 0 800 8 15 psi 205 psi 13. Attachments: .Well Class after work: Copies of Logs and Surveys Run R5T Sigma Analysis Exploratory 0 WGA Development ^ Service ^ Daily Report of Well Operations Operations Summary .Well Status after work: Oil Gas ~ WDSPL GSTOR ^ WAG ^ GINJ ^ WINJ ^ SPLUG ^ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C_O. Exempt: 309-249 Contact Bruce D. Webb Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature `~ . ~~ Phone (9071277-1003 Date 02101/2010 ii~n I Form 10-404 Revised 7/2009 ~~~v ~ ~ ~ ~ `~~'~~ Submit Original Only AURORA GAS, LLG KALOA NO. 2 (AOGCC DRLG PERMIT No. 204-09fi) (API No. 50-283-20107-00) WORKOVER: CLEANOUT & RECOMPLETION OPERATIONS SUMMARY 7/30/09-RU Pollard w/ lubricator. Run 1.75" bailer to 3236'-tag fill, get sample and POH-mud & silt. Run and set PX plug in X profile at 3079'. Run and set prong in plug. Run shifting tool and open sleeve to annulus (packer fluid) at 3042'. POH. RD Pollard. 8/6-7/09-MI & RU AWS #1 rig. 8/8/09-Mix 145 bb18.9 ppg KCl-NaCI brine. Rev circ packer fluid. Set 2-way check in hanger. ND tree. NU BOP. Continue move in and rig up. 8/9/09-Function test BOP. Test BOP to 250/3000 psi---OK. Pull 2-way check. RU to release packer-would not release. Back off On-Off tool. PU to remove tbg hanger. Latch back onto On-Off tool. Work tubing to release packer. $/10/09-RU Pollard. Close sliding sleeve at 3042'. Pull PX prong and plug. RD Pollard. RU Schlumberger. Cut off tubing at 3101' (below packer). Work pipe-packer came free. Rev circulate tubing clean. POH w/ 2-7/8" tubing and packer. 8/11109---RU power swivel. PU 4.75" mill and X-O's. Set wear ring. RIH w/ mill on 2- 7/8" tubing. Casing tight at 2730'-could not circ and rotate thru. POH, LD 4.75" mill. PU 4.625" mill. RIH. Casing tight at 2770', but worked thru. 8/12/09--Continue in hole to 3101'. Mill on fish (2-7/8" tubing stub) to 3104'. CBU. POH, LD BHA. Receive, PU, and make up 3-1/8" DC's-stand back in derrick. WO tools. PU 4.75" tapered mill BHA and RIH to 2770'. 8113/09- Ream tight spot at 2770' to 4.75". CBU. RIH to 3081', ream to 3084'. CBU. Tag fish at 3104', and POH. LD tapered mill. PU overshot and WF jars and RIH. Engage fish at 3104'. Jar and work pipe. 8/14/09-Jar and work pipe. Release overshot. POH, LD overshot. PU 16 21' jts of 1- 7/8" FJ blast joints (2.15" OD), run in hole. PU bumper sub & jars, RIH on 12 3-18" DC's, then 2-7/8" tubing to 3150'. Rev circ-sand packed off annulus. Work pipe. 8/15/09-Wash down to 3245'-lost returns-hole taking 1 BPM. Fiil pits w/ 8.8 ppg brine. Mix and pump 7.5 bbl SO# Baraplug 50 pill w/ 3% KCl-saturated NaCI brine. Keep hole full by pumping down casing-hole still taking fluid. Mix and pump 2na Baraplug pill. Pull 4 jts. Pump 17 bbl Baraplug pill (#2), spot at 3085'. Mix 3% KCl brine, keeping hole full. Mix 30 bb130 ppb Baraplug /20 ppb Baracarb pill (#3). 8/16/09-Fin mix BaraplugBaracarb pill (#3). Pump 23 bbl pill. Losses 8 BPH. Pu112 stds. Losses 6 BPH. Mix 14 bb130#/20# Baraplug/Baracarb pill (#4) and pump. Monitor well-pull 1 std. Losses 6 BPH. POH for fishing BHA. LD bumper sub and 1- 7/8' blast joints. Start BOP test. 8/17/09---Test BOP to 250/3000psi. PU fishing BHA (Weatherford jars and spear). RIH to 3083'. Pump 13 bbl Baraplug 25/50 pill (#5). R1H to 3101' and engage fish (spear bait sub on top of OS). Jar on fish 2 hrs. Lost 13 bbl in 2 hr. POH for Bakke Hammer. LD fishing tools. PU and test Hammer. PU BHA & RIH. Engage fish at 3101'. Start Hammer-required pump pressure too high-~-chg out pump liners to 5-1/2". 8/18/09-Fin change pump liners to 5-1/2" (from 6"). Latch onto fish, pressure up and hammer on fish w/ upward pull for 6 hours-no movement. POH w/ SLM. LD Bakke Hammer. W.O. tools. PU 19 jts 1-7/8" blast joints w/ WF Tubing Sand Pump on bottom. RIH w/ jars and circ sub on 2-7/8" tubinig. 8/19/09-Fin RIH. Tight at 3123', work thru. Found top of sand at 3172'. Bailed sand w/ sand pump to 3425'. CBU thru circ sub. Bailed sand to 3471'. POH. LD BHA- recovered much sand. R1H w/ 1-7/8" blast joints on 2-7/8" tubing to 3471'. Wash down to 3498' (as deep as possible with amount of 1-7/8" available). CBU. Mix and pump high vis sweep, recovering lots of sand. 8/20/09-POH & LD 1-7/8" blast joints. PU overshot and BHA. R1H to 3101' and spear into bait sub. Jar w/ 45K pull. Jars failed after 1-1/2 hr. Release from fish. CBU. POH. RU SLB w/ lubricator. Run RST tool to 3495' and log out to 600'. Mix 9.9 ppg KCl- NaCI brine. RD SLB. R1H w/ mechanical packer w/ On-Off tool on 2-7/8" tubing w/ PX plug and prong set in O-O profile. $/21/09-RIH w/ packer. Set packer w/ top at 3081'. Release from On-Off tool. Hole took 22 bbl. Attempt to reengage O-O tool, could not. Circ sand and trash. POH= found plug and prong jammed into O-O skirt. Change out O-O skirt. RIH and engage O- Otool. Test casing to 2000 psi-OK. RU Pollard. Run 2.25" gauge ring to 3090'. Run and set PX plug and prong in profile in O-O tool on top of packer. Test tubing to 2000 psi-OK. RD Pollard. Release from On-Off tool. Displace hole with 9.9 ppg KCl-NaCI brine. Circ and filter brine. 8/22/09-Circ and filter brine, keeping weight at 9.9 ppg. ND bell nipple riser. NU shooting flange onto annular. RU SLB and lubricator. Perforate the Carya 2-3.2 sand at 2995-3015' and the Carya 2-3.2 sand at 2774-94' and 2995-3015' in 3 runs with 3-1/2" 2 HSD guns w/ 6 PowerJet Omega SPF. POH. RD SLB. RD shooting flange. Install riser and flowline. Start PU and run completion assembly. 8123/09-Fin RIH w/ completion assembly and tag sand at 3080'. Wash down and unintentionally latch into On-Off tool-wouldn't release. Work and attempt to release. RU SLB and lubricator-test to 2000 psi. Run jet cutter and CCL to cut 2-7/8" tubing (just above On-Off tool) at 3071'. 8/24109-Correlate and cut off tubing at 3071'. RD SLB. POH w/ 2-7/8" tubing and LD cut off joint. PU new completion and RIH. Land tubing w/ WL entry guide 2.5' above cut-off at 3068', PHRP hyd packer at 3052' (top), WXO sliding sleeve at 2980', PHRP packer at 2942', WXO sleeve at 2739', PHRP packer at 2701', WXA sliding sleeve at 2688' (annulus) and 2-7/8" tubing to surface. Spot 45 bbl inhibited 9.9 ppg brine into annulus. RU Pollard. Run PX plug and prong and set at 3061'. Test tubing to 3000 psi and set hydraulic packers. Test casing to 1000 psi. POH w/ slickline. Set BPV. ND BOP. 8/25/09-Fin ND BOP. NU tree-test to 3000 psi. Pull BPV. Swab 6 bbl from tubing (1000+ ft). Set BPV. RD & MO AWS #1 rig. 9/9/09-RU Pollard. Ran blind box and found FL at 1200'. Run selective shifting tool and open sliding sleeve at 2980' (2982' WLM). FL at 1160'. Ran swab-FL at 950'. Swab 200' fluid, wl cups catching on collars. RD Pollard. 9/10/09-SITP-1060 psi. Flow test well thru AG test unit for 5-1/2 hrs. Final (stable) rate: 668 mcfpd at 130 psig on 29/64" choke-rec 3.1 bbl 10.1-ppg water. SI. 45-minute SITP-1100 psi. RU Pollard. RIH w/ shifting tool and close sleeve at 2980'. Bled to 850 psi to test-good. Ran shifting tool and open sleeve at 2739' (2742' WLM). No change in SITP. POH. RD Pollard. 9/11/09-SITP 1220 psig. Open well and flow for 4 hours. Final (stable) rate: 174 mcfpd at 110 psi on 24/64' choke-no water. SI. 4-hr SITP-610 psi. 9/21/09-RU Pollard. Run shifting tool and open sleeve at 2980'. Pressure increased from 520 psi to 550 psi. RD Pollard. 10/8/09-Put well on stream to sales at rate of 585 mcfpd at 470 psi FTP. Ed Jones 01/29/10 Aurora Gas, LLC 11ALOA ~~ Proposed Configuration August 2009 RKR- ld.(Ift Drill 10-5/8" Hole to 868' Tyonek Tops Carya 2-3.2 ~ 2994' Carya 2-4.1 ~ 3154' Carya 2-4.2-3248' Carya 2-5.1 ~34D2' Larva 2-5.2 - 3522' Drill 7-7/8" Hole to 3,720' Carya 2-3, 2748-27 2774-279 Carya 2-3 2995-301 Carya 2-4 3158-7 3200-2 Carya 2 3250-333 Carya 2- 3522-5 PBTD @ 3,600' 2 7/8 6.5# 8rd EUE J-55 ,. s F° /P re < 'r f ,t.. ,w~ .-~ y.~ w ~" ~, ~, I,~` d"_; ?/'. s'~ ~;1. ~ ~•' ~f Yy y. ~- R t~ ~r~" ,.'~ ~~ ~~.+ ~. ~ ~~ a»;~ ~:, ~ , +.~ a r ,a ~~ ter "~ ,t.`" r~l ;~" ~ ~;„ ; ... `~~ ~ , ~' i" °tl' 1 64' :.. ;, 4' ,. •.F tr ~~41. ~~ ~ ~ iii; ~ ~. ,^ +r ry _,.. v'4 s4- 5' e :~. .d ', .; ~ ,.. , a ,. .1 8' 0' " ~, r_* 4 ,~R'. 0' ~~, ~ _. :r'. ,.F: .: ~> ~'*;t •ti «:., .;' SZ 2' k.% p 12-3/4" 65.4# Structural Conductor driven to 116' 8-5/8" 32# Surface Casing set at 61T Cement w/ 14.5 ppg Gas-Block enhanced WXA Sliding Sleeve @ 2688' PH12P Hydraulic-Set Packer @ 2701' WXO Sliding Sleeve @ 2739' (open) PHRP Hydraulic Set Packer @ 2942' WXO Sliding Sleeve @ 2980' (open) PHRP Hydraulic Set Packer @ 3052' w/2.31 x profile @ 3061' w/ WL entry guide @ 3068' Mechanical-set Packer @ 3083' w/ On- Off Tool wl P,X Plug set in X nipple. Top of cut-off tubing at 3071', bottom of WLEG at 3099' Tubing cut at 3104' w/ OS & bait sub top at 3101' 14ft of 2-7/8" tubing then crosses to 3- 1/2" With 3-1/2" Stratapak screens @ 3152-3174' 3197-3216' (SANDED IN) 3247-3329' 3522-3552' 5 Y:" 17# J-35 Casing to 3,714' MD (TVD) Cement wl48 bbl 12.5 ppg + 85 bbl 15.8 ppg Class `G' • . 1 ~ S - V F y ~4, "k r ,~S e~ ( ~ k ~~: f t ~: Il. ~ ~•- ~ i ~~. ~ t 4 ~' k1 .~ i. ~ ¢ ~4 ~~~, 4~ L ~ e ~ $ !l ~~ ~ ~ r ~ ~ ~ k ~ € 4 5 ~ ~ } ~ ~ " ~ ' ~S ~ ~ ~ [ ~~ ~ p E ` ~ ~ ~ ~ ~ t a_ U -. 1 x.., ~ ~. ~,.~ ~ ymm...,~ m. , . t;e . . _ w ~ ~ ~ssA ou ~D c~.~ CO1~T5ERQA7`IO1~T COMl-IISSIOI~T Bruce, D.Webb Manager, land and Regulatory Affairs Aurora Gas, LLC 1400 E. Benson Blvd., Suite 410 Anchorage, AK 99503 • ~F~ SARAH PALIN, GOVERNOR 333 W. 7thAVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 .. Q ~ ~d ~ Re: Albert Kaloa, Undefined Gas Field, Kaloa No. 2 Sundry Number: 309-249 `' `~.~i?~~~:.~' ~?,.i~, ~s -r: ~~~~ ~~~~. ~ Dear Mr. Web: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Searriount, Jr. ~ Chair DATED this~~day of July, 2009 Encl. • ~~ urora ~as LLC ~ ~1""~ www.aurorapower,com ~ ~~~~~~~~ July 21, 2009 Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Comrnission 333 West 7~' Ave., Suite 100 Anchorage, Alaska 99501 Attn: Mr. Winton Aubert Re: Application for Sundry Approval: Kaloa No. 2(204-096) Dear Mr. Seamount: .~11L 1 :~ Z~Q~ ~las~a ~J's6 $~ ~~w ~~n~. ~asnmi~~iar~ ~: ~rs~#~~r.r~~ ~ ~ ~~~ ~\ Aurora Gas, LLC hereby submits a Sundry Application for operations at the above referenced natural gas production well (API 50-283-20107-00). The Ka1oa No. 2 well has been shut-in since November 16, 2008 due to the accumulation of san and poor production volumes. Aurora plans to pull the tubing, clean-out the sand deposits and perforate_ rti9~al zones. Please refer to the attached 2009 Rig Workover / Recompletion Procedur . lso attached is a diagram of the current well configuration and the proposed configuration after workover ~ operations. The proposed spud date has also been revised to August 3, 20Q9. If you have any questions or require additional information, please contact the undersigned at 277-1003, or Mr. Ed Jones at (713) 977-5799. "T'hank you for your time and consideration. Sincerely, ~~'~~ C ~~ Bruce D. Webb Manager, Land and Regulatory Affairs attachments cc: Kim Cunningham, CPA Director of Land and Resources Cook Inlet Region, Incorporated 2525 C' Street, Suite 500 Anchorage, AI~ 99503 1400 West Benson Blvd,, Suite 410 ~ Anchorage, AK 99503 •(907) 277-1003 • Fax: (907) 277-1006 6051 North Cou~se Orive, Suite 200 • Houston, TX 77072 •(T13) 977-5799 • Fax: (713) 977-1347 - -7 ~ STATE OF ALASKA ALAS~IL AND GAS CONSERVATION COMMI~N APPLICATION FOR SUNDRY APPROVALS 20 AAC 25280 1 Tvnc nf De.,~ ~~.~. . 1"1 ~ ~~~~~~~~~ ~~-09 ,1 U ~. ~ ~ 2 (~ ~~ ~~4r -t~t;~zoc9 ~,~ask~ ~i~ & Gas Cons. Cammissi~n •' 7Y~ ~~ ~"MYO~~~ HAaflQOfl u SUSP211C~ u Operational shutdown U Perforate Q Waiver ~~'"'~- ~'~--°i Other ~ Atter casing ^ Repair well Q Plu Pertorations 9 ^ Stimulate ^ Time Extension ^ T't~'~- Change approved program ^ Pull Tubing Q Pertorate New Pool ^ Re-enter Sus~ndecl Weli ~ 2. Operator Name: 4. Current Well Class: ~ 5. Permit to Drill Number. AURORA GAS LLC Development ~.-- E~ Ioratory ~ 204 3. Address: -096 Stratigraphic ~ Service ~ 6. API Number: 1400 W. Benson Blvd., Suite 410, Anchorage, AK 99503 50-283-20107-00 7. If perfotating, dosest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No 0 Kaloa No 2 . 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): CIRI Lease # C-061393 213.6' AMSL (DF) Albert Kaloa, Undefined Gas Field 12~ PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total De th TVD ft Eff p ( ): ective Depth MD (ft): Effective Depth TVD (ft}: Plugs (measured): Junk (measured}: 3,720' 3,720' 3,600' 3,600' 3,600' none Casing Len th g Size MD ND Burst Collapse Structural Conductor ' " 116 12-1/4 116' 116' Surtace ~ ~~ g~l g~~g 617• 617~ 3,930 psi 2 530 si P Intermediate ' " , 3714 S-1/2 3714' 3714' 5,320 psi 4 910 si p Production , Liner Perforation Depth MD (ft): Pertoration Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 3,158'3,178', 3,200'3,220', 3,158'-3,178', 3,200'-3,220', 3,250'-3,330', 3,522'-3,552' 3,250'-3,330', 3,522'-3,552' 2'7~8~~ 6.5#, 8 Rd EUE, J-55 3,554' Packers and SSSV Type; 5-1/2" Retr7evable Packer Packers and SSSV MD (ft): 3,079' 13. Attachments: Description Summary of Proposa! Q 14. Well Class after proposed work: Detailed Operations Prvgram ~ BOP Sketch [] Exploratory ~ D~ lo~ent _--[~-" Service ^ 15. Estimated pate for 16. Weli Status after proposed work: Commenci~g Operaticns: A-ugust 3, 2009 ^ Oi! ^ Gas Q/ Plugged ^ Abandoned 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact ~. Edward Jones (713) 977-5799 Printed Name Brace D. Webb, Manager, Land and Regulatory Affairs Title Vice President, Engineering and Oper. Signature ~ ~~,_ ~ Date J I 21 2 y U y , 009 ~ ~~ , COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3o y aljL y' P~ug tntegrity ~ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ~ ane~: -re5.~ ap P~ '~0 3 o t~ o~~, Subsequent Form Required: ~ p._ ~ O 4• ~ ~ ~ ~ d ' ~ ~-`"" ~~ -~ ~` APPROVED BY Approved by: - ~ ~ ~ COMMISSIONER THE COMMISSION Date: ~ ~~ ~ ~ ~ // Form 10-403 Revised 06/2006 ~ ~ ~ ~ ~ ~ ~ ~ ~~~ ~~ ``~~ ~ 7 ~~Q~ Submit in Duplicate CJ ~ Aurora Gas, LLC Kaloa No. 2 Current ConfiguraUon Drill 10 5/8" Hole 2 718" X 5 Y:" annulus displaced w/ OZ in~ibited brine from surface to top of packer. Well Perforated @ 6 spf using SLB 3 3/8" HMX guns. Open Production Perforations: 3158' - 3178' 3200' - 3220' 3250' - 3330' 3522' - 3552' Dri117 5/8" Hole to TD @ 3720' 5'h" 17# LTC J-55 Casing to 3714' Cmtd w/ 48 bbls 12.5 ppg lead, 85 bbis 15.8 ppg Tail "G" cement systems. u 2 7/8" 6.5# 8 Rd J-55 Tubing to 3058' 12'/, 65.4# LLS Conductor driven to 116" 5/8" 32# Surface Casing set at 61T 'emeot w/ 14.5 ppg Gas-Block nhanced cement (- 53 bbls, 100% acess, cemeot back to surface) ling Sleeve 1 joint above packer @ 3042' :.313" X-Profiie for laading plug ° Retrievable~type packer w/ oo / off @ ~ 3099' Yv / 2.3131anding profile ised over to 2 7/S" EUE. 7/8" 6.5# 8 Rd J-55 Tubing 3055 - 3148' 3 jts) w/ xo 2 7/8 EUE 8rd B x 3'/: EUE rd P 3'/:" Screen 3152' -3172' (1) 20' jt (2) 10' z 3 Y:" spacer jts. (20' total) 3'/:" Screen 3197' -3217' (1) 20' jt (1) 30', x 3'/:" spacer jts (30' total) 3%:" Screen 3247' - 3328' (2) 30' jts and (l)10' jt (6) jts x 3%:" spaur jts (190' totai) 3%:" Screen 3522' - 3552' (1) 30' Bullplug at 3554' PBTD at 3600' 20~ ~93 Zoi 19~k Zo~jcb-7 • Aurora Gas, LLC KALOA #2 ~ 2009 R/G WORKOVER / RECOMPLETION PROCEDURE Version 1 A (DRAFT) Ct~PACITIES: 2-7/$" Tubing: 0.00579 bbUft and 5-1/2" 17# Casing: OA232 bbllft 5-112" Casing X 2-7/8" Annular Volume: OA152 bbl/ft. Casing Drift ID is 4.?67" . Tubing Volume ta Sliding Sleeve above Top Packer is 17,6 bbl. Annular volume to sliding sleeve is 46.2 bbl for total circulation volume of 63.9 bbl. Casing vol. to deepest perf: 82.4 bbl. 9.8 ppg brine left in tbg-csg annulus. KB=16' above GL (all depths from KB). PBTD=3600' MD/T'VD; TD=3720'MD/T`VD TUBING/COMPLETION: Tubing ID=2.441 ". Drift ID=2.347" Weatherford Sliding Sleeve at 3023'-2.313" X profile Weatherford T-2 On/Off Tool-at 3077' --23 i 0" ID Weatherford Arrowset IX Packer at 3079'-2.440" min ID X-O to 3-1 J2" Tubing at 3118' -3119' 3-1/2" Stata Pak Screens at 3152-3174', 3197-3216', 3247-3329', 3522-3554" Bottom of Tubing wBull Plug-3554'. EXISTING PERFS: 3128-3178' (30'); 3200-3220' (20'}; 3250-3330' (80'); 3522-3552' (30')~ 160' net / 424' gross interval. NOTE: Pollard Wireline work on 10/31/08 indicated hard sand fill in tubing at 3251'. 1) Prior to moving in rig, shut in well (all tree valves including SSV). Disconnect flow line downstream of SSV. Disconnect controls and put in safe place-use care to avoid damaging. (Need Work Permit from Operators to do so). Remove well houses from well and set aside out of the way. 2) Move in, rig up AWS #1 rig w/ single workover pit for mud system (not AG mud system) and support equipment only as needed (one gen set, 1 mud pump,etc.) 3) Starting with clean mud pit, mix 150 bbl (usable volume) 8.9 ppg b% KCl-NaCI ~ brine (6% KC1--21 #/bbl), using clean produced water from tanks on AG locations. ~4) RU to pump down annulus thru casing valve on tree. RU to take returns from flowline (2-1 /8" 5000# API flanged connection}-have operators open and lock SSV open. 5) RU Pollard with lubricator on tree cap. Run in hole with slick line, Set retrievable plug in ~ profile in On-Off Tool at 3 Q77' . Open sliding sleeve at 3042'. POH. Release Pollard. 6) Reverse circulate +/-~6 bbl of 9.8 ppg packer fluid out of annulus, displacing with +/-64 bbl of~~.9,,~ipg KCl-NaCI brine ~save 9.8 ppg brine i c an tank. Set BPV in tubing hai~ger, ND tree, NU 30Q0-psi BOPE. Test to Z OO~~si (or as ~ required by AOGCC Sundry approval). - F~,t,,, ~ ~ . ~; ~ /~~t /4 ~ ~ =?l Z ~o (~ ~ ~ .~. 2.00% ~:. ~'~~' `~'<'~, • • 7) Latch onto tubing hanger and release pacl~er (plug is still in On-Off tool and sleeve is open). Reverse circulate tubing volume as needed (thru sliding sleeve) to get any gas out of tubing. Monitor well to watch for losses and/or gas. POH standing back 2-7/8" tubing, laying down packer, 3-1/2" tubing spacer, and 3-1/2" screen assembly-strap out of hole ~nd keep good records-record and report depth to any holes in screens or sand fill in tubing. Monitor hole and keep full. 8) Run 5-1/2" 17# casing scraper on 2-7/8" tubing and ciean out to 3600' (PBTD), noting depths any fill is encountered. Catch samples af fill. Circulate hole clean w/ clean 8.9 ppg 6% KCUNaCI brine, and filter brine until it is 8.9 ppg and clean throughout (thru 5 or 10 micron sock filters). Monitor fluid level- determine rate of loss, if any. POOH with tubing. LD scraper. ALTERNATIVE: If hole will not stay full or if circulation cannot be established, PU Weatherford tubing Sand Pump and run on tubing to clean out fill. Then make bit and scraper run. If fluid losses into hole are egcessive, consider TCP for new deeper perfs (Carya 2-5.1) and order at this point. If circulation is possible but losses are high, consider adding rock salt, ground calcium carbonate, andlor cellophane flakes to brine for FL control-however, light acid treatment may be required to clean up, so avoid if possible. 9) Move in Schlumberger electrio-line unit, and lubricator. Pressure test to 1500 psi. Run GR/CCL/RST Log to PBTD (3600'), tie in to open-hole logs, and log up to surface casing (617'}. Evaluate logs and deternune plan forward-plug back (?), additional perfs, and/or setting depths of multiple packers. Especially evaluate water eneroachment in open perfs, potential of Carya 2-5.1 at 3402-1 &' and 3426-50' and Carya 2-3.2 at 2995-3015'. R.D SLB. WO orders. The next steps will be determined by: a) the depths of holes in screens, b} by tha depth of fill inside tubing and in the casing, and c) by the RST log. A. If the depth of the holes in the screens, the fill, and the RST log indicate that the sand and water are the perfs at 3522-52' and no other zone, proceed as follows. If not, go to B or C below, as applicable. 10) PU CIBP and test packer. RIH on tubing. Set CIBP at +/-3500'. Release from CIBP. Pull 1 stand and set packer. Test CIBP to 2000 psi fRelease packer and POH. 11)RU SLB w/ lubricator. PU Schlumberger 3-1/8" HSD guns with Pawerjet Omega charges (6 SPF w/ 60 deg phasing-OR EQUAL) and test lubricator to 2000 psi. RIH and perforate as foliows: a) 3426-3248' (22'~-MDT indicated 1584 psi (8.8 ppg gradient) b) 3402-3418' (16'1--MDT indicated 1562 psi (8.8 ppg gradient) c} 3330-3346' (16'}-likely partialty depleted by perfs above. RD & release SLB. 12) Run bit and scraper to PBTD. POH, lay down bit and scraper. • • 13) PU hydraulic-set packer w/ 10' pup wl 2.313" X nipple tubing spacer tubing and wire-lin~ enhy guide to set packer at +/-3375'. Run XD sliding sleeve (closed) w/ X profile nipple 1 joint above packer (sleeve at +/-3343'), then 3 stands tubing spacer to 3160', then second XD sliding sleeve, then 1 joint tubing, and mechanical-set packer at about 3125'. Mechanical-set packer to have On-Off Tool w/ 2.313" profile. Run in hole on 2-7/8" tubing, filling tubing as TIH. NOTE: Rabbit all tubing befare going in hole and watch torque DO NOT OVER TORQUE. 14) Set mechanical packer at +/-3125'. RU Pollard. PU 2.313" retrievable X plug , RIH, and set in X profile below hydraulic-set packer at 3375' POH, RD, & release Poilard. elease fram On-Off tool. (Hydraulic packer to be set later). Circulate hole w/ pg KCl-NaCI brine (build volume fram 9.8 ppg packer fluid). POH w/ tubing. 16) RU Schlumberger w/ lubricator. PU 3-1/8" HSD guns with Powerjet Omega charges (6 SPF w/ 60 deg phasing--OR EQUAL) aa~d test lubricator to 2000 psi. ~ RIH and perforate the Carya 2-3.2 as follows: a) 2995-3015' (20'}-MDT indicated 1531 psi (9.8 ppg). Monitor well for pressure and gas after perforating. POH. RD & release SLB. 17) Run bit and scraper? RIH w/ On-Off stinger, 3 joints tubing, XD sliding sleeve (at about 3025'), 3 joints of tubing, hydraulic-set packer (to be at about 2930'), 1 joint tubing, sliding sleeve (for annulus), then 2-7/8" tubing to surface. Add inhibitor to 45 bbl of 9.9 ppg brine and circulate into annuius as packer fluid. Sting o~ On-Off tool. Space out. Pressure up to +/- 3000 psi to set hydraulic packers (t~oth). Test annulus r to 1400 psi. Set BPV in hanger. ND BOP. NU tree. Pull BPV. Release rig. ? n ~~_ ~' `"" n~ t~ 18) RU Aurora Gas Test Unit as fb'~lows: a) set test choke manifold close to rig choke skid and connect to w/ 1~02 ,hard line; b) insta1124/b4" positive c~io~e in rnanifoid (left side)-- use 2" 1502 target tees ups#ream of choke skid; c) run AG 2" 1502 hard line from choke manifold to test separator; d) set flare stack 100' or more from the rig and from trees and raise stack; and e) lay AG 3" 1502 hard line from separator skid to flare stack, and connect propane bottle to flare stack. 19} Prepare for test: a) Take and recard initial measurements of brine levels in all tanks to which swabbedlflowed back brine will go--know exact volume of brine is in a11 tanks; b) Record test separator water meter reading; c) install new chart on Barton recorder; d) install fresh nitrogen bottle onto skid for instrumentation; e) install new 2000 psi pressure gauge near test head, isolated with needle valve (upstream from valve that vvill shut in well for buildup-will want it to record and show SI pressures), and ~ confirm electric clock on chart recorder is on and set to 12 hrs and chart is appropriate far clock time. • ~ ' ~~ 20) Pressure test tubin~ to 1500 psi. RU Pollard and open sliding sleeve below top packer at +/~.~QS~'. RD pollard. RU to flow back. 21) Flow test well as follows until clean and sta.ble, as follows: a) swab in as necessary, unloading fluid to shaker/possum belly until well is gassing andlor kicks off to flow; b) when significant gas is at surface (whether swabbing or flowing) or the well is flowing, divert flow to test separator: i) shut down momentarily to light flare stack, then bring back on, adjusting choke size until well is flowing strongly to cieanup, but holding some back pressure on it (probably start at 14/64's and adjust accordingly, target flow at 75% of SIP. ii) Flow until rate and pressure have stabilized for 15 minutes, increasing slightly is OK, but dropping is not--wait until fluctuations tend to be up, not down) and water has dried up (all of tubing volume + casing volume to 30Q0' has been recovered, 19 bbl at a minimum) or rate has stabilized . Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water productian and cleanup. Watch for sand production in water. If producing any sand or much water, shut in and call. iii) Start w/ 1" orifice in test meter. Flow rate in mcf/day= static reading (blue) X differential reading (red) X 31, If red chart reading is beiow 3, change to 0.75" orifice; if it is above 8 change to 1.5", then 2.0" orifice. Meter factors change to 17.4, 70, or 130, respectively. Orifices may be changed by e.xperienced operator while fZowing w/the Daniel Sr. oriface fitting. iv) Catch water samples thru out (downstream of test separator}-have tested with mud kit for weight-record with time of sample. Produced water should have weight is less than 8.4 ppg-if water is trending in that direction, continue to flow until these properties have stabilized. Keep last sample of produced water to send to lab in Anchorage-label thoroughly. v) Shut in well for bualdup twice as long as flow period (could build up to about 1204 psi, but will lii~ely be less-800 psi or so). Report test results to me (Ed~--including email report of flow and buildup tests. If well is making significant water, well will be killed, the packer pulled, a test packer run, and the water production will be isolated-a Supplementary Procedure wili be provided for this operation. 22} RU Pollard slick-line unit and RIH to close sliding sleeve below packer (at +/- 3080'). B1ow down tubing to test sleeve. When sleeve is holding, open sliding sleeves at 3345' and 3160'. RD Pollard. 23) Prep for test as in Step 19) above. Swab well in if necessary and test as in Step 21 } above. 23) When test is completed, RU slick-line and RIH to close sliding sleeves between second and third packers packer (at +l-3345' & 3160'). POH w/ tool. RIH and retrieve X plug below 3`d packer at +I-3385'. May have to bale perforating debris off of it-have hydrostatic baler available. RD Pollard. 24) Test bottom zone as per Steps 19 and 21 above. Evaluate tests. Leave highest pressure completion that is commercial open, and put well on production to compressor from that zone. ~ ~ B. If holes in screens, depths of fill, and RST log indicates that water and sand are coming from Carya 2-4.2 perfs at 3250-3330', proceed as follows, If not, go to C below. 1) Determine how best to isolate water/sand producing perfs: a) w/ CIBP if deeper zones appear to be producing water and do no# appear to be productive-in this case, set CIBP at depth to shut off water but preserve as much shallower production as possible, set mechanical packer w/ On-4ff tool as in Steps 13 and 14 above, except do not run Hydraulic packer beneath it----only 10' tubing pup with X profile and WL entry guide. Proceed as in Step 14 and following, except for only one deeper productive zone (assuming no new deeper perfs). OR b) with multiple packers if deeper zones appear productive; i.e., isalate water producing zone with packers (plan add an additional hydraulic packer to isoiate water producing zone in Steps 13 and 14), then proceed as in Step 11 and follows, perforating as appropriate to avoid water producing zones. G If holes in screens, depths of fill, and RST log indicate that the Carya 2-4.1 perfs at 3158-78' and/or 3200-3220', proceed as foilows. 1) Isolate the water producing perfs by adding an additional hydraulic-set packer in Steps 13 and 14. Then, proceed with the following Steps, adjusting as appropriate for additional packer. Ed Jones 7/1/09 n LJ ~:Aurora GeS, LLC KALOA #2 Proposed Contiguration Auuuct 2009 Dri1110-5/8" Hole to 868' Tyonek Tops Carya 2-3.2 - 2994' Carya 2-0.1 ~ 3154' Carya 2-4.2-3248' Carya 2-5.1 ~3402' ('arva 2-.5.2 - 3522' Carya 2-3 2995-301 Carya 2-4.1 3158-78' 3200-20' Carya 2-4 3250-333 3330-46' (ne~ Carya 2-5 3402-1 3426-4 (eil ne~ Carya 2-5 3522-5 PBTD @ 3,600' ~ ~ 2 7/8 6S# 8rd EUE J-55 12-3/4" 65.4# Structural Conductor driven to 116' 5/S" 32# Surface Casing set at 617' ement w/ 14.5 ppg Gas-Block eohanced Hydraulic Set Packer @ 2930' ~ lliding Sleeve @ 3025' iical-set Packer @_~:-" w/ On-Off ~liding Sleeve at 3160' >liding Sleeve @ 3343' ~aulic-Set Packer @ 3375' w/ 2.31 le X nipple w/WL entry guide BP set at 3500' 17# J-55 Casing to 3,714' MD (TVD) ~nt w/48 bbl 12S ppg + 85 b6115.8 ppg ~....od `G' Drill 7-7J8" Hole to 3,720' Aurora Well Service R~To. l: Proposed 3M BOP Conf ratioa ~,~ _.~ ~ Bel! Nippie with flow iine to pits 3M Schaffer Annular Preventer r 11" 3M Double Gat~ wf 3112" pipe ~ rams instailed. 11" 3M tu~d Cr~s 3" 5M Manuai Valve {ICiti Line) ~ 3" 5M Hydraulic Vaive tKitl Lirte) ~_ \ Flu~l ftow direction ~"'~~ while reverse circulating 5M Manual VaNe (Choke Line) ~-- 3" 5M Hydra~lic Valve (Choke Line) 2" 3M Manuai Vaives On Welihead Drawing lVot to SCale Nicolai Creek Na. 8 BOP System Fei,rweatt-erEB~PSenri~es. ~-r~ Rev. 02.01 / DHV 01-Aug-02 A~trora Well Service R~'°~No roposed Choke / Kill Ma old obfiguration Ail valves are 3" rateci _.t 5!~psi. ~~ Inlet from BOP Choke Line tniet from PoWner Swive.i (Reverse ~irculation Mode) Output to Pits B~ed Flare Line to Open F{are Pit To Gas Buster "Atmospheric Degass~r" Drawing Not to Scale Nicolal Creek No. 8 Choke/Kiil Manifoid FairneamerEB~F Senriaes, k,a Rev. 02.01 / DHV 01-Aug-02 DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 10333 RICHMOND, STE. 710 HOUSTON, TX 77042 ATTN: ANDY CLIFFORD State of Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchora e, AK 99501 ATTENTION: Howard Okland Enclosed One Set of Dr Well Cuttin s From Aurora Gas LLC Area Cook Inlet Alaska Date: 10 December, 2004 1. One set of dry cuttings in three box from Aurora Gas' Kaloa-2 well. SCAAtNED MAR 3 8 10D8 ~' PLEASE ACKNOWLEDGE RECEIPT OF DATA BY SIGNING BELOW AND SENDING A COPY BACK TO AURORA GAS FOR OUR FILES. REC~ev~~ ~} ~~ Received by: DEC 1 0.2004 Alaska Oil & Gas Cans. Commission Anchorage Date: J c4 -- ~v~ L~ AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 • • -~~-=,~, ~- MICROFILMED 03/01/2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE r ~~ ~, :` F:\LaserFiche\CvrPgs_InsertslMicrofilm Marker.doc . . DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 10333 RICHMOND, STE. 710 HOUSTON, TX 77042 ATTN: ANDY CLIFFORD State of Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 ATTENTION: Howard Okland Enclosed From Area CD Aurora Gas, LLC Moquawkie Area, Cook Inlet, Alaska Date: 16 August, 2006 CD: 1. Kaloa #2 well data: PDS, FMA and LAS files for Platform Express, Dipole Sonic Imager, Fullbore Micro-Imager, Caliper, Mudlog (LAS data only) and MDT data (PDS and Excel formats only). 1Þ r~1 () À I RECEIVED AUG 1 7 2006 Alaska Oil & Gas Clns. COI1IJ'Iiøion Anch.rage E 7 PLEASE ACKNOWLEDGE RECEIPT OF DATA BY SIGNING BELOW AND SENDING A COpy BACK TO AURORA GAS FOR OUR FIL Received by: "'\ ~. l7 -0(0 Date: AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 2 ~'1-- ocr k Kaloa #2 . . Andy, Sorry to bother you. I need some help with some Kaloa #2 data and the Fairweather contact person is no longer there. There is some OH data for Kaloa #2 (API 50-283-20107-00) that we did not receive. Reproduce abies: Dipole shear sonic imager Formation Micro Imager Array Induction/Litho-Density/Compensated Neutron/Gamma Ray logs Modular Formation Dynamic Tester ( Digital graphics files Le. pdf, pds formats are preferable over mylar/sepias). Digital logging data for the above mentioned OH logs (LIS, DLlS or LAS format). Please note: we do have blue line copies of these logs. TNX. Please contact me if you have any questions. TNX Howard howard okland@2admin.state.ak.us 907 793 1235 p.s. Has it cooled off in Houston? I spent the better part of July in Minnesota's 90 deg plus temps. Glad to be back in 50 and 60 deg temps. 1 of 1 8/16/20069:12 AM ) ~ ~""~ DATA SUBMITTAL COMPLIANCE REPORT 8/2/2006 Permit to Drill 2040960 Well Name/No. KALOA 2 Operator AURORA GAS LLC API No. 50-283-20107-00-00 MD 3720 TVD 3720 Completion Date 7/16/2004 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log Yes Samples No Directional Survey No \?\ ., 1.\ I \. - .Jfl'''I~'''-' ~ DATA INFORMATION Types Electric or Other Logs Run: CBUCCUGR Well Log Information: Log/ Data Type ~ (data taken from Logs Portion of Master Well Data Maint Name Sonic "~\~I {¡-.~S ~ 12757 ,.E!elferclfiÕn C ~ .wJ., Log Log Run Scale Media No 5 Col 1 Interval OH I Start Stop CH 614 3690 . Electr Digital Dataset Med/Frmt Number Received Comments DIPOLE SHEAR SONIC IMAGER Induction/Resistivity 3158 3552 2 Blu 116 3720 5 Blu 614 3690 5 Blu 2754 3545 5 Blu 614 3710 OIL & GAS MD MUDLOG ED C ~ ~ ~ ~ Mud Log Formation Micro Ima Formation Tester .~ ~. Cement Evaluation Perforation 5 Blu 50 3592 5 Blu 3158 3552 Sample Interval Set Start Stop Sent Received Number Comments MODULAR FORMATION DYNAMICS TESTER ARRAY INDUCTION/LlTHO- DENSITY/COMPENSATED NEUTRON/GAMMA RAY"PLATFORM EXPRESS" SLIM CEMENT MAP TOOL PERFORATING RECORD, 3-3/8" HSD POWERJETS . Well Cores/Samples Information: Name Permit to Drill 2040960 MD 3720 TVD 3720 ADDITIONAL INFORMATION Well Cored? Y ~ Chips Received? ~ Analysis 'L.LbI- Received? Comments: ¡v~ () ¡.t ~ Ìd: J;Y~~ Compliance Reviewed By: DATA SUBMITTAL COMPLIANCE REPORT 8/2/2006 Well Name/No. KALOA 2 Operator AURORA GAS LLC Completion Date 7/16/2004 Completion Status 1-GAS Daily History Received? Formation Tops V-a API No. 50-283-20107-00-00 Current Status 1-GAS UIC N GJN ~/N Date: 0( ~l ~~cb . . Re: [Fwd: Gas Well Potential Test, Kaloa #2 (203-071)] e e Subject: Re: [Fwd: Gas Well Potential Test, Kaloa #2 (203-071)] From: John Hartz <jack_hartz@admin.state.akus> Date: Tue, 28 Sep 2004 08:26:23 -0800 To: Ed Jones <jejones@aurorapower.com> CC: Thomas Maunder <tom_maunder@admin.state.akus>, Stephen F Davies <steve_davies@admin.state.akus>, Duane Vaagen' <duane@fairweather.com>, Chad Helgeson <chelgeson@emeraldalaska.com> Ed, Thanks for the note. The reason I asked about stability goes to the flow-after-flow section in Natural Gas Reservoir Engineering, C.D. Ikoku, where he stated that "The Texas Railroad Commission defines stabilized ... pressure readings over a period of 15 minutes agree within 0.1 psi." That criteria seemed too precise for field measurements, even with dead weight testers so thought I'd check with you. I have the IOGCC manual but did not look it up there. The textbook appears to be incorrect in the 0.1 psi standard it quotes and I would think the TRRC criteria are 0.1 % of pressure measured also. Anyway - thanks for the reality check Jack Hartz Ed Jones wrote: Jack and Tom, The "less than 1 psi in 15 minutes" stabilization criteria for a flow point comes from a rule of thumb from John Campbell in "Gas Production Operations" (I believe, the book is in my Anchorage office and I am in Houston for another week so I can't confirm that), which states the flow is stable when the pressure does not vary more than 0.1% of SIP in 15 minutes. This is similar to another rule of thumb from Campbell about shut in pressure stabilization, which is also on p. 8 of the "IOGCC Back-Pressure Testing of Gas Wells Manual," where it states that, "The well should be shut in until the rate of pressure buildup is less than 1/10 of 1 per cent of the previously recorded pressure, psig, in 30 minutes." I have added a minimum time for both flowing and shut in periods to be sure that this criteria is sufficient. The reservoirs that we are dealing with are quite permeable, so based on my experience, I think this is a good criteria. The biggest concern is that we are using surface pressures (common in 4-point tests), and if the well is making much water (which is not expected in this case), it can have a significant impact on surface pressures. Regarding the comparison of surface pressures and downhole pressures, we have not conducted any of our multi-rate flow tests with bottom-hole pressure recorders, so I don't have a comparison of flowing pressures. However, we have several comparisons of shut-in pressures measured by both surface and bottom-hole gauges, which are very close. Because most of these wells produce very little water, this can be expected. The software that is used to analyze the test data converts the surface pressures to bottom hole, of course, and related programs using similar conversions of static surface pressures to bottom-hole pressures seem quite accurate (although not quite that same, as a friction pressure loss must also be calculated in the flowing case) . Please let me know if you need other information or have other concerns. Thanks, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC -----Original Message----- From: John Hartz [mailto:jack hartz@admin.state.ak.us] Sent: Monday, September 27, 2004 7:26 PM To: Thomas Maunder; Ed Jones Cc: Stephen F Davies Subject: Re: [Fwd: Gas Well Potential Test, Kaloa #2 (203-071)] I had to dig out my Nat Gas Reservoir Eng book since I haven't done one 1of2 4/27/2005 1:55 PM Re: [Fwd: Gas Well Potential Test, Kaloa #2 (203-071)] e e of these for many years. The procedure looks like a fairly standard flow-after-flow procedure and should be appropriate to the conditions. - has the "less than 1 psi in 15 minutes" stabilization criteria been satisfactory in the past? - have you had opportunity to compare a downhole gauge test to surface tests? if so how do the two types generally compare? Looking forward to the results. Jack Hartz Thomas Maunder wrote: Jack, This testing information is plans to do is acceptable. Thanks, Tom more in your ball park. Do you agree?? I think what Ed -------- Original Message -------- Subject: Gas Well potential Test, Kaloa #2 (203-071) Date: Mon, 27 Sep 2004 16:52:03 -0500 From: Ed Jones <jejones@aurorapower.com> To: Tom Maunder <tom maunder@admin.state.ak.us> CC: 'Duane Vaagen' <duane@fairweather.com>, Chad Helgeson <chelgeson@emeraldalaska.com>, Randy Jones ~rjones@aurorapower.com> Tom, We recently completed the Aurora Kaloa #2 well (Permit No. 203-071) and are now finishing construction of the production facility and flow line, which will tie it in to the newly constructed Moquawkie gathering pipeline, just before it ties into the Beluga Pipeline. The combined sales gas will be metered by the ultrasonic sales meter that is now metering sales from the Mobil Moquawkie #1 re-entry, which came on stream in July. (The information about this sales meter that you requested in your email of 8/4/04 is being collected and will be sent to you by Chad Helgeson of Emerald Consulting). Sales will be allocated back to each well on the basis of Daniel Sr. orifice meters w/ Barton flow recorders at each well site, downstream from fuel gas take offs. The leasor (CIRI) and leasee (100% Aurora Gas) are identical for both wells. However, AOGCC 20 AAC 25.225 requires that all gas wells be tested by multi-point back-pressure method before regular production. For Kaloa #2, Aurora is planning to do the test at start-up of the production facility, expecting to flow all test gas to sales, since the well will likely flow at sufficient rates for a "4-point" backpressure test at pressures above the sales line pressure, w/o compression. Attached is the Test Procedure and a summary of the short-term well test results following the completion of the well. Please let me know if this is not acceptable. We plan to start the well test later this week (probably Thursday or Friday) . Thanks, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 2of2 4/27/2005 1:55 PM e e OPEN-FLOW POTENTIAL TEST PROCEDURE Aurora Gas, LLC KALOA #2 1) After finishing the Production Facility, including all hydrotests and x-rays, a) purge/pressure test facility piping with nitrogen. b) Repair any leaks. c) Install quartz crystal surface pressure recorder w/ readout ("SPYDR") on Kaloa #2 tubing (on swab cap). d) Initiate pressure recording-watch for an hour and confirm that shut-in pressure doesn't change more than 1 psi during that time. When pressure is stable (i.e., changes less than 1 psi in I hour), record surface Shut-in Tubing Pressure (SITP}-should be about 1400 psig. e) Confirm orifice sizes in orifice meters in heater- separator and dehy skids: should have 1-3/4" orifice in 3" run in heater- separator skid and 2.0" orifice in 4" run in dehy skid. f) Confirm and record ranges of static, differential, and temperature in Barton flow recorders: expecting 0-1500 psi static ranges in both, 0-200" differential in separator recorder and 0-100" in dehy recorder, and 150 deg temp in both. 2) Open well and pressure facility piping. Check for leaks using gas detector and soapy water at low pressure (100-200 psi). When all leaks are repaired, increase pressure to 1200 psi and recheck for leaks. When all leaks are repaired, light flames in heater and dehy reboiler. Allow both to get up to temperature-will take several hours. Start glycol pumps and confirm that dehy system is circulating and up to temperature (reboiler is stable at about 350 deg). 3) Fill pipeline (valve where Kaloa flowline ties into Moquawkie gathering pipeline should remain closed). Pressure to 1000 psi. Shut in well and allowto rebuild pressure. 4) Open valve to Moquawkie gathering pipeline (We will start test by flowing to sales-if lower pressures are needed, gas will be vented downstream of separator for lower flowing pressures-this is not expected to be necessary, and we will need to hold some back pressure on flow meter using 2" completions test choke if we do so). 5) Prepare to start flow test. Install 24-hr charts in Barton flow recorders in both heater-separator skid and dehy skid. Confirm that pens are zeroed (blue static pen on .86 and red differential pen on O-IISCO should have calibrated meters before testing). Open 5-valve manifold on orifice meter as per standard procedure. Confirm static pressure reading, which should be 8.2 at 1000 psig w/ 1500-psi spring: static reading= sq root of «(gauge pressure + 14.4) / spring range) X 100). Synchronize chart times with time on surface pressure recorder. e e 6) Measure flow at separator orifice meter, upstream from fuel gas take off. The approximate flow rate (in met/day) will be 127 X static reading X differential reading (assuming 3" run, 1.75" orifice, 1500-psi static spring, 200" differential range, and 60 deg flow temp-if any of these assumptions are not correct, let me know and I'll recalculate). Record flow parameters (red, blue, and green pen readings) every 15 minutes, and calculate flow rates. Also record flowing tubing pressures and well head temperature every 15 minutes. 7) Start "Flow-after-Flow" test by opening well on a choke that will cause the FTP to stabilize at 1250-1300 psig (start w/ 20/64" choke and adjust as needed}--allow flow to stabilize (so FTP changes less than 1 psi in 15 minutes). Catch sample of water early in test (if any}--mark well, time, and date. While not expected, the well may need to be "conditioned" (unloaded) before continuing with test-if it will not flow 2-3 MMcfpd at this pressure, unload it by flowing on a larger choke until water unloads and dries up-then reduce choke size to attain 1250-1300 psi and commence flow test. 8) After flow has stabilized for a minimum of 15 minutes AND well has flowed for at least an hour on the first choke size, open choke to drop FTP about 50-75 psig (1175-1225 psi)-allow flow to stabilize with less than 1 psi change in 15 minutes or more and flow for a minimum of an hour on this choke size. 9) Open choke again to allow FTP to drop another 50-75 psi (1100-1150 psi}--allow flow to stabilize for 15 minutes and flow for a minimum of an hour on this choke. 10) Open choke 4th time, allowing FTP to drop about 50-75 psi (1025-1075 psi}--allow to stabilize-then flow for 6 to 8 hours at this highest rate to watch for pressure declines. Catch samples of gas and water (if any). 11) Shut well in and monitor pressure buildup until pressure changes less than 1 psi in 1 hour, but for at least 12 hours. 12) Open well to sales w/o compression at +/- 5 MMcfpd. Continue recording pressures for at least 24 hours for a drawdown test (or until pressure drops less than 1 psi in 30 minutes). 13) Remove surface pressure recorder and return to Pollard for downloading. Send in 24-hr orifice meter charts to Ed Jones NOTES: a. Call Kenai Gas Field (907-283-1305) before starting flow to sales and before discontinuing flow to sales. Ed Jones (9.27.2004), Version 1.1 AURORA GAS, LLC July-04 KALOA #2 PRELIMINARY WELL TEST PERFORATIONS: 3158-78', 3200-3220', 3250-3330', AND 3522-52' UPPER TYONEK SHORT TESTS OF INDIVIDUAL ZONES AFTER PERFORATING (initially WIO sand control screens in place) EST FLOW/SI DATE PERF INTERVAL CHOKE FTP RATE TIME SITP WATER COMMENTS TOP I BTM 64" PSIG* MCFPD MIN PSIG BBL Swabbed in, unloaded well 7/12/2004 3522 3552 28 710 3542 30 22.9 load water, ended w/ dribble e SI 1 1100 SI 2 1250 SI 4 1350 SI 10 1375 SI 20 1400 final CI--130,OOO ppm (brine) SI 30 1400 Killed and moved packer & RBP Swabbed in, unloaded well 7/12/2004 3250 3330 29 875 4719 5 24 1050 3766 25 21.5 load not quite recovered SI 1 1325 trickle of water SI 2 1375 CI-135,000 ppm SI 10 1400 Based on MDT pressures, SIP SI 15 1400 sIb about 1450 psig (uncorrected gauge reading is 1440+ psig). Killed and moved packer & RBP (difficult to kill). e 7/13/2004 3158 3220 24 620 2224 30 Swabbed in, unloaded well 20 750 1918 20 22.2 load recovered then heavy mist SI 1 1150 CI-135,000 ppm SI 2 1230 SI 3 1260 SI 10 1330 SI 20 1330 SI 30 1350 Killed well, cleaned out (no solid fill). RAN COMPLETION ASSEMBLY INCL SCREENS AND TESTED ALL ZONES 7/15/2004 3158 3552 24 1100 3946 15 21.4 Load water 28 1000 4989 15 3 32 900 5945 15 2 20-30 bblload from kills were not SI SI SI SI SI 1 2 5 10 15 1300 1350 1400 1400 1400 recovered. Still heavy mist final. Rates estiimated using choke size and FTP, flowing thru 40-50' of 2" hardline, wi 390 ells to gas buster open to atmospere wI 8" vent --flow rates should be conservative. *Pressures measured wI 5000-psi gauge just upstream of choke--it zeros at about 50 psi, so 50 psi has been deducted from the readings. Pressures and rated on daily report are unadjusted (gauge pressure is used) so slightly higher. Ed Jones (7/16/04) e e ~-' - f"II- -... . 41 - ~ ... -- ~ -- --.... '''^'' - -, E & P SERVICES, INC. September 3,2004 Mr. John Nonnan, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Final well completion report and operations summary: Kaloa No.2 (PTD# 204-096) Dear Mr. Nonnan, On behalf of Aurora Gas, LLC, Fairweather E&P Services Inc. hereby submits the final well report which covers both the drilling and completion of Kaloa No.2 gas exploration well. Operations were completed on July 16th, 2004. Pertinent infonnation included under cover of this letter includes the following: 1) Fonn 10-407 "Well Completion Report and Log" - 2 copies. 2) Wellbore Schematic 3) Completion Schematic(s) 4) Summary of daily well work and operations. 5) As-Built Location Plat Wireline Log Infonnation is being submitted under separate cover. If you have any questions or require additional infonnation; please contact the undersigned at (907)258-3446, or Mr. J. Edward Jones, Executive Vice President of Engineering and Operations for Aurora Gas, LLC at (907)277-1003. Sincerely, 1d::11:í: me. Duane H. Vaagen Proj ect Engineer u¡ IGINAL RECEIVED SEP - 3 2004- Alaska Oil & Gas Cons. Commission Anchorage att: cc: J. Edward. Jones, Andy Clifford 2000 East 88th Avenue' Anchorage, Alaska 99507 . (907) 258-3446 . FAX (907) 279-5740 650 North Sam Houston Parkway East, Suite 505' Houston, Texas 77060' (281) 445-5711 . FAX (281) 445-3388 . STATE OF ALASKA . ALASKA,. AND GAS CONSERVATION COMMISS",", WELL COMPLETION OR RECOMPLETION REPORT AND LOG Oil 0 Gas 0 Plugged 0 Abandoned 0 20AAC 25.105 Same 4b. Location of Well (State Base Plane Coordinates): Surface: x- 260774.49" y- 2566864.64 .. TPI: x- 260774.49 y- 2566864.64 Total Depth: x- 260774.49 y- 2566864.64 18. Directional Survey: Yes 0 No 0 Single Shot Inc. Only Surveys Schlumberger Open Hole Logs: DSI, FMI and MDT - 7/7/04 CBUCCUGR -7/12/04 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE TOP BOTTOM TOP BOTTOM o 116' 0 116' 617' 3715' 1 a. Well Status: GINJ 0 WINJ 0 WDSPL 0 2. Operator Name: No. of Completions 1 Aurora Gas, LLC 1400 West Benson Blvd. Suite 410 Anchorage, AK 99503 4a. Location of Well (Governmental Section): tð ~ Surface: 1308' FNL, 1706' FEL, Sec 26, T11N, R12Jt. SM Top of Productive Horizon: Same 3. Address: Total Depth: Zone- 4 Zone- 4 Zone- 4 21. Logs Run: 22. CASING WT. PER FT. 65.4 32# 17# LLS WC-50 J-55 GRADE 123/4 8-5/8" 5-1/2" 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): 3522 - 3552 MD & TVD, 3 3/8" He, PH HMX 6 SPF 3250 - 3330 MD & TVD, 3 3/8" HC, PH HMX 6 SPF 3200 - 3220 MD & TVD, 3 3/8" HC, PH HMX 6 SPF 3158 - 3178 MD & TVD, 33/8" HC, PH HMX 6 SPF J 26. Date First Production: WAG 0 1 b. Well Class: Development 0 Exploratory 0 Service 0 Stratigraphic Test 0 12. Permit to Drill Number: 204-096 13. API Number: 50-283-20107-00 14. Well Name and Number: Kaloa NO.2 15. Field/Pool(s): Suspended 0 20AAC 25.110 Other 5. Date Comp., Susp., or I Aband.: July 16, 2004 6. Date Spudded: June 21, 2004 .. 7. Date TD Reached: July 6, 2004 8. KB Elevation (ft): 213.6 9. Plug Back Depth(MD+ TVD): " 3600' 10. Total Depth (MD + TVD): , 3720' 11. Depth Where SSSV Set: NIA 19. Water Depth, if Offshore: N/A feet MSL .. 10 5/8" 7 7/8" 24. SIZE 27/8" 8rd EUE Kaloa Gas Field 16. Property Designation: C-61393 17. Land Use Permit: 20. Thickness of Permafrost: N/A CEMENTING RECORD AMOUNT PULLED 53 bbls-gas block-to surface 168 bbls TUBING RECORD DEPTH SET (MD) PACKER SET (MD) 3079' 3079' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED PRODUCTION TEST 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 ~ SIP: 1450 psig 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". t.~IF, ~i~ JQ~rl SEPa 1 f" ëór;~p¡,=ET,ION , , DATE ~' ~:r:(~~;~T'L!f>f 'i, '" '" ." v'-'Ji,,''-' . t.. . -:IJ-'--------. .~ -, - ..~.::~_&__._.....,"'_.._.,.;(e._..""~_~ Form 1 0-407 Revised 12/2003 \ l) i LJ I i~AL CONTINUED ON REVERSE RECEIVED SEP - 3 2004 Alaska Oil & Gas Cons. Commissior Anchorage &, p NAME GEOLOGIC MARKERSA MD- TVD 29. ~RMATION TESTS Include and briefly sum.e test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". 28. June 26th, 2004 Formation Integraty Test (FIT) to 17 ppg - 240 psi surface pressure with 9.8 ppg mud, no leak off. Please See Attached Document For Flow Test Information. RECEIVED c" I) ,.., rt04 - :!J_Jt ,(U,<.:'-- Alaska Oii & Gas Cons. Commíssíon Anchorage 30. List of Attachments: Ops Summary, Wellbore Schematic, Completion Schematic, Wellhead Schematic, Flow Test Summary, As-Built Plat, Logs Submitted Separately 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Printed Name: A...."f' 1/ ¿ )'~., Title:ßj~"?' /"'J'M"~' h::,,wt!..If., E¡/Sc,..t.I.~e(. f"'c. Signature:! ()...<;;:;::.,--//â.-'-L.'") h.~. é.l :J"""'J. Phone: 9/)7~:ZJ¡f>-j~''I¿ Date: J ~Jt,,¡'~ð'l ~ ~ \. .A~r....... 1..-"-.1, LLC. ~ 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 I 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 Aurora Gas, LLC Kaloa tops . . Howard: Per your recent request, the following are the depths to the geologic tops encountered while drilling the Kaloa NO.2. KALOA-2 TOPS: BASE OF GLACIAL WASH: 680'; TOP OF BELUGA FM.: 680'; TOP OF TYONEK FM.: 2312'; Regards, Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 ;J 0 Cl-D ·ll1 AURORA GAS, LLC KALOA #2 PRELIMINARY WELL TEST July-04 PERFORATIONS: 3158-78', 3200-3220', 3250-3330', AND 3522-52' UPPER TYONEK SHORT TESTS OF INDIVIDUAL ZONES AFTER PERFORATING (initially W/O sand control screens in place) EST FLOW/SI DATE PERF INTERVAL CHOKE FTP RATE TIME SITP WATER COMMENTS TOP I BTM 64" PSIG* MCFPD MIN PSIG BBL e Swabbed in, unloaded well 7/12/2004 3522 3552 28 710 3542 30 22.9 load water, ended wI dribble SI (1-min-1100,2-min-1250) 20 1400 final CI--130,OOO ppm (brine) 4-min--1350, 10-min-1375 30 1400 Killed and moved packer & RBP Swabbed in, unloaded well 7/12/2004 3250 3330 29 875 4719 5 24 1050 3766 25 21.51oad not quite recovered SI 1 1325 trickle of water SI 2 1375 CI-135,OOO ppm 10 1400 Based on MDT pressures, SIP 15 1400 sIb about 1450 psig (uncorrected gauge reading is 1440+ psi g). Killed and moved packer & RBP (difficult to kill). e 7/13/2004 3158 3220 24 620 2224 30 Swabbed in, unloaded well 20 750 1918 20 22.2 load recovered then heavy mist 1 1150 CI-135,OOO ppm 2 1230 3 1260 10 1330 20 1330 30 1350 Killed well, cleaned out (no solid fill). Page 1 of2 - e 7/15/2004 RAN COMPLETION ASSEMBLY INCL SCREENS AND TESTED ALL ZONES 3158 3552 24 1100 3946 15 28 1000 4989 15 32 900 5945 15 1 2 5 10 15 1300 1350 1400 1400 1400 21.4 Load water 3 220-30 bblload from kills were not recovered. Still heavy mist final. Rates estilmated using choke size and FTP, flowing thru 40-50' of 2" hardline, w/3 90 ells to gas buster open to atmospere wI 8" vent --flow rates should be conservative. ·Pressures measured wI 5000-psi gauge just upstream of choke--it zeros at about 50 psi, so 50 psi has been deducted from the readings. Pressures and rated on daily report are unadjusted (gauge pressure is used) so slightly higher. Ed Jones (7/16/04) Page 2 of2 e e WELL DRILLING AND COMPLETION REPORT KALOA NO.2 Tyonek, Alaska -=~~Aurora Gas, LLC Aurora Gas, LLC 03 - September - 2004 Page 1 of8 e e Background Information: The Kaloa No.2 well was permitted to be drilled as a natural gas production well by Aurora Gas, LLC, with approval given on June 9, 2004, PTD # 204-096. The well was drilled on the reconstructed Albert Kaloa No. 1 drillsite using the rig Aurora Well Service No.1. The well was spudded on June 21 and reached TD on July 6,2004. Prior to rig mobilization and spud, an attempt was made to drive the conductor using a pile driver on site for other work. The conductor was driven to refusal at ~35 ft when it appeared to have encountered a boulder. It was hoped that moving approximately 20 ft would allow driving a conductor to the depth required. A new conductor was driven with refusal met at 37 ft. Operations were then suspended until A WS No.1 could be mobilized to the site. The conductor was finally installed using the drill and drive technique with final conductor set depth at 116' KB. After successfully installing the conductor, the remainder ofthe drilling rig was moved to the site and rigged up to drill the Kaloa No.2 well. The following well work summary details the drilling and completion work chronology. Dates indicated reflect date morning report( s) were received in office and reflect site activities over previous 24 hour period, i.e. 0700 hrs on day previous to 0700 hrs on date of report generation and submittal. Attachment I is a schematic of the well as completed and Attachment II is a tally and diagram of the actual completion equipment in the well at this time. Also attached is a diagram of the ABB Vetco production tree installed on the well. Work Summary and Daily Activities: June 11,2004 June 12, 2004 June 13, 2004 June 14,2004 June 15,2004 Aurora Gas, LLC Move in, rig up A WS #1 Continue RD. Assemble rig floor. Weld pitcher nipple on conductor. Hook up Kelly hose Continue RD. Pick up power swivel. Make up drill collar w/bit on power swivel. RIH, tag bottom. Break circulation, check for leaks. Drill out conductor wi 10-5/8" drilling assembly. Hard drilling. Stopped drilling: SD for night. Continue RD. Start up rig engines, break circulation. Drill 93' to 125'. Circ hole clean, ream ledges. Break out power swivel, LD drlg assembly. N/D pitcher nipple, tear down sub base, lower derrick in preparation to drive conductor wi MWD Pile Drivers to 116' KB. Continue RD. RD standby pumps, prepare around cellar, dig out cellar, weld on rig derrick board. Cut off conductor, weld on Page 2 018 June 16, 2004 June 17,2004 June 18, 2004 June 19,2004 June 20, 2004 June 21, 2004 June 22, 2004 June 23, 2004 June 24, 2004 June 25, 2004 June 26, 2004 June 27,2004 Aurora Gas, LLC e e 13- 5/8" x 5000 starting head. Rooked up pumps, water tank, flow back tank. RU to drill surface hole. Continue RD. RU diverter system and function test. Set catwalk, PU power swivel, RU kelly hose. Function test diverter. Took on 80 bbl KCl. Mix mud. Drill mouse hole. Fab mouse hole out of 7" csg. PU new BRA, Rill w/same. Rill, fill @ 71'. Clean/drill out conductor 73'. Drilling on metal. Repair swivel. Rack 8 5/8" csg, rabbit and remove thread protectors. Replace power swivel hydraulic pump. Drill metal to 74' KB. POR to check BRA - OK. Drill to 90'KB. Drill to 110' inside conductor. PU globe basket. Rill, core to 114'. POR. LD globe basket. PU flat mill and junk basket. Rill and mill to 115', fell free under shoe. Mill to 120' KB. POR, LD junk basket. PU 10-5/8" bit and stabilizers. Spud surface hole and drill to 259' KB. Drill 1 0-518" hole to 570' and circulate clean. Drill 10-5/8" hole to 620'. Short trip to 510'. Role in good shape. Survey 2°. POR, LD BRA. RU to run 8-5/8" casing. Run 8-5/8" casing to 617'. Cement wI 53 bbl Gas-Block cement - 100% excess. Cement to surface. WOC. ND diverter system. Finish ND diverter. Cut 8-5/8" csg and conductor. Weld on 8-5/8" head. NU BOPE. RU rig floor. Install flow nipple - Install choke lines- Rammer up bolts. Test BOPE. Repaired gas sensor on floor. Make up 7-7/8" BRA. Rill w/BRA. Circulate and condition mud. Test casing to 1500 psig. Drill out float collar, cement and shoe. Drill to 640'. FIT to 17 ppg - 240 psi surface press wI 9.8 ppg mud - no leak off. Drill to 1020'. Drilled 7-7/8" hole to 1100'. Ran survey@ 1100' - 4°. Ran lighter on bit. Noticed 200 psi drop in pump press. Checked pumps. Page 3 of8 June 28, 2004 June 29, 2004 June 30, 2004 July 1, 2004 July 2, 2004 July 3, 2004 July 4, 2004 July 5, 2004 July 6, 2004 July 7, 2004 Aurora Gas, LLC e e POOH looking for washout, none found, determine may have had plugged jet. Press test surface lines. RIH to 1250'. Circulate and condition hole. Drill to 1380'. Drill to 1592'. Run survey - 4°. Drill to 1882'. Notice pit gain- mud had foamed up. Drill to 2085' . Survey 2° @ 2100'. Drill to 2475'. Circulate and condition mud. Repair centrifuge. Drill to 2618' . Circulate and survey @ 2618' - 1°. Drill to 3022. Circulate bottoms up. Survey - 1 0. POOH to 2991', monitor well. POOH to 2840' - pulled tight. Work pipe, pumpe out of hole to 2632'. Pump out of hole to 8-5/8" shoe at 617'. Set back power swivel and attempt to pull stands. Could not pull due to swabbing. Repair power swivel and power pack engine. Circulate and condition mud. Pump out of hole to 617'. Circulate and condition mud at 8- 5/8" shoe. Circulate and condition mud. Set back power swivel. POOH. Rack back BHA, LD bottom collar, bit and stabilizers. Test BOPE. RIH wI drill pipe to 2834'. Swivel up, wash and ream to bottom. Wash to 3022'. Drill 7-7/8" hole to 3064'. Drill to 3172'. Check for flow - gas spiked to 1650 units. Drill 3237'. Mud extremely aired up. Standpipe washout. Pump out of hole, weld on standpipe. RD Kelly hose. Finish standpipe repair. Set back power swivel, RU Foster tongs. RIH wI 80 joints 3.5" DP off pipe rack. RU power swivel, wash nine joints to btm. Drill to 3395'. Work on Pump #1. Drill to 3685'. CBU for survey, 1100 units of gas, survey at 3486' - 5-112°. Circulation rate inconsistent using Pumps #2 and #3. Work on OPI mud pump - wear plate washed out. Drill to 3720' - pump Baralift sweep@ 3715'. W/L survey- 0.5°. Sweep hole and condition mud for logging and trip. POOH, tight at 3576'. Pump and rotate out to 3129'. LD singles. POOH to 471 ' standing back in derrick. Confirm pipe count - 105 jts. RIH wI DP to condition hole for logging. POOH and lay down stabilizers. RU Schlumberger and RIH wlOH logs. Run Platform Express suite. POOH and RIH w/DSI, FMI and MDT. Page 4 018 July 8, 2004 July 9, 2004 July 10, 2004 July 11, 2004 July 12, 2004 July 13, 2004 Aurora Gas, LLC e e Run MDT on W/L. POOH and RD Schlumberger. Rlli wl7-7/8" bit to 3702' and wash to 3720' . Circulate and condition mud for running production casing. POOH and LD DP. Clear rig floor to run casmg. Change pipe rams from 3.5" to 5.5". Cavity test BOP stack to1500 psi. Run 82 joints, 17# J-55, 5-112" csg to 3714'. RU BJ and cement csg w/35 bbls of 10.5 ppg spacer, 48 bbls of 12 ppg lead cement and 85 bbls of 15.8 ppg tail cement. Drain and wash stack, centralize casing w/annular and WOC. Clean flow lines and mud system in preparation for displacing mud. PU BOP, set slips on 5-1/2" csg and pull 50K to seat. Cut off stub and NU tbg spool. NU stack and pressure test BOPs, choke and valves to 3000 psi. Strap 2-7/8" tubing and RU to run tubing. Rlli wI 4-3/4" bit and casing scraper on 2-7/8" tbg. Tag cement @ 3562'. Drill cement to PBTD of3600'. Circulate bottoms up and pressure test 5-112" casing to 1500 psi. Displace mud wI 50 bbls brine. Filter and displace. POOH, rack tubing. ND flow line, rig shooting flange on BOP. RU Schlumberger for CBL/CCL/GR logging run. Run CBL. Run CBL, POOH, LD logging tools. RU to perforate. Perfwl Schlumberger from 3522-3652,3250-3330,3200-3220 & 3158- 3178 wI 3-3/8" HC gun wI PH HMX 6 shots per foot. RD Schlumberger, remove shooting flange, install flow nipple. Rlli wI bit and scraper on 2-7/8" tbg to clean out perf debris. POOH. LD BHA. MU Weatherford BHA, packer, sleeve and x-overs. Rlli to 3560'. Set bottom Weatherford packer wI plug @ 3570'. Set top packer @ 3509. Test perforations 3522-3552. RU to swab in well. Swabbed in well- unloaded 22.6 bbls brine. SIP 1440 psi stabilized. Initial press through 32/64 choke-55Opsi. Stabilized @625 psi. Flowed through 28/64 choke-stabilize pressure at 725 psi. Kill well by reverse circulating through unloader. Close unloader after kill weight fluid to surface. Release top packer and reverse one tubing volume through choke to confirm well dead. Move packers up for Test #2. RU to swab well in. Test. Shut in. Kill well reversing through unloader following pressure schedule- influx, reverse circulate kill well, fluid loss 49 bbls. Shut down pumps, check shut in press, check flow, monitor well. Unseat, run in approx 120' to retrieve plug @ 3368'. Pull 2 stands, set bridge plug, pull to 3102' to set packer. Unable to set packer, RU and circulate while building volume (50 bbls). Unsuccessful, attempt to Page 5 of8 July 14, 2004 July 15, 2004 July 16, 2004 Aurora Gas, LLC e e set packer. POOH slowly. LD, inspect and clean packer and bridge plug tools. Redress 5.5" bridge plug (bad seal in body). LD unloader, RllI wI bridge plug. Test @ 200' to 500 psi. RllI to 3235, set BP. POOH, PU packer, RllI to 3138', set packer. RU to swab off head. Flow test gas @ 20/64 choke @ 800 psi. RD lubricator while monitoring SIP of 1250 psi. Open unloader, equalize and kill well by reverse circulating. POOH wI packer, monitor hole for swabbing. LD packer, RllI to retrieve BP. Respond to and report fuel spill to ADEC. Unable to latch on to BP. RU to wash top ofBP. Latch on to BP, monitor flow and fluid levels. Circulate bottoms up twice - gas cut brine. RD circulating head and hose. POOH wI BP; monitor flow for swabbing. Finish trip out with BP - no plug. Inspect catcher, RllI to find plug. Circulate and latch into BP CBU and perforating debris. POOH wI BP. RllI wI x-over and bit to 3604' -114 jts. RU circulation. Reverse. Circulate reverse while filtering fluid. POOH wI 8 stands. Continue POOH (strap line measurement). Back off 4-3/4" bit, Prep to RIH wI completion assembly. RllI wI screens and packer. Space out hanger, prepare to spot packer fluid. RU pump to reverse. Mix packer fluid. Pump pill in backside. Set packer and land tubing wI 10K # compression. Test tubing annulus to 2000 psi. Step up 10 minute intervals, set BP valve. RD tongs, remove excess equipment from floor. ND stack and set out. Dress tubing head for tree, NU tree and wing valve. Test tree to 3000 psi - OK. RU to swab. Make two swab runs, swab in 80 bbls. Well came on. 28/64 choke, 1000 psi, most water returned. Remove lubricator, shut in well @ 1400 psi. 15 min flow @ 24/64 - 1100 psi, 21.4 bbls recovery tank, 3 bbl residue. 15 min flow@ 24/64 - 1150psi 28/64 - 2 min stabilize @ 1050 psi, 2 min 950 psi, 15 min 950 psi, est 2 bbls of fluid 32/64. Shut in. 60 min shut in total: 1 min - 1350 psi; 2 min - 1400 psi; 5 min - 1450 psi; 10 min - 1450 psi 10 min - 1450 psi; 10 min - 1450 psi: 13 min-1450psi Set BP valve, RD for next well. Release rig @ 2100 hrs. Page 60f8 July 17, 2004 Aurora Gas, LLC e e ND BOPE, NU tree, perform step test on well, release rig. RD sub base, move main generator, prepare to move rig, boat and matting boards to Nicolai Creek Unit #3. Page 70f8 Kaloa No.2 Final Configuration Drill 10 5/S" Hole 27/8" X 5 Yo" annulus displaced wI 02 inhibited brine from surface to top of packer. Figure I Please See FIgure /I for component details Well Perforated @ 6 spf using SLB 3 3/8" HMX guns. Open Production Perforations: 315S' - 317S' 3200' - 3220' 3250' - 3330' 3522' - 3552' Drill 7 5/8" Hole to TO @ 3720' 5 Yo" 17# LTC J-55 Casing to 3714' Cmtd w/4S bbls 12.5 ppg lead, S5 bbls 15.S ppg Tail "G" cement systems. Fairweather E&P Services, Inc. Aurora Gas, LLC e e 27/8" 6.5# S Rd J-55 Tubing to 305S' 12 % 65.4# LLS Conductor driven to 116" S 5/8" 32# Surface Casing set at 617' Cement wI 14.5 ppg Gas-Block enhanced cement (- 53 bbls, 100% excess, cement back to surface) Sliding Sleeve 1 joint above packer @ 3042' w/2.313" X-Profile for landing plug 5 Yo" Retrievable type packer w I on / off tool @ - 3079' w I 2.313 landing profile crossed over to 2 7/S" EVE. 27/8" 6.5# S Rd J-55 Tubing 3055 - 314S' (3 jts) w/ xo 2 7/8 EVE Srd B x 3 Yo EVE Srd P 3 Yo" Screen 3152' - 3172' (1) 20' jt (2) 10' x 3 W' spacer jts. (20' total) 3 W' Screen 3197' - 3217' (1) 20' jt (1) 30', x 3 W' spacer jts (30' total) 3 W' Screen 3247' - 332S' (2) 30' jts and (1) 10' jt (6) jts x 3 W' spacer jts (190' total) 3 W' Screen 3522' - 3552' (1) 30' Bullplug at 3554' PBTD at 3600' I Drawing Not to Scale Page 80f8 · Weath -<~:'; t\ e e -J 100 ~ LJ I ~ ¡; ~ == !\! Total Length of B.H.A. :- 27/8 EVE Tubing 3023.00 Sliding Sleeve w/2.313 X 3.670 2.313 3.57 2.375EUE 2 7/8 Tubing Jt 31.65 2 3/8 EVE T-2 On off Tool 2 7/8 4.500 2.310 1.68 3077 w 2.313 x profile 27/8 EVE 5 1/2 Arrowset IX packer 4.625 2.440 6.97 3079 Figure II 27/8 Tubing Joint 31.60 3086 2.440 27/8-3 1/2 Xover 3.750 2.440 1.10 3118 3 1/2 Tubing 4.500 2.992 32.40 3119 3 1/2 Strata Pak Screen & XO 4.110 2.992 22.15 3152 3 1/2 Tubing Pups 4.500 2.992 22.71 3174 3 1/2 Strata Pak Screen & XO 4.110 2.992 20.00 3197 3 1/2 Tubing 4.500 2.992 30.50 3216 3 1/2 Strata pak screen & XO 4.110 2.992 81.89 3247 3 1/2 Tubing 4.500 2.992 192.74 3329 3 1/2 Strata Pak Screen& XO 4.110 2.992 32.22 3522 3 1/2 BuB Plug 4.550 3.000 0.85 3554 1077.42 (Meters) I 3535.03 (Feet) Ple.El!;i:ll}()Ie thätall O/D's.émd,- JO,'s, are: äþproximate;. afuläte gi"'¢":â$,~.gUidelineoÖly: (B.Ii.A. #) (Run #) e e """"" ...... t". OF AI.. ., ~ ~~··......··Acro " _ ~~., *"~..L. I ;' "'.... '\~'Ý I ... * :' 49 IIi ". * ~ ...................................... , ", ~ ~ ~ ,................................... ifili' , ~ ". M. SCOTT McLANE.: ff ... I ~ . ..~ - I, ~·......4928-S......·~ .: " ~A .......... \,-# ... '. . 1?o¡>e-SSIONÞ,\. ,'" .,\\"", NORTHING: 2568137.490 EASTING: 262506.440 LAT: 61 °01 '21.360"N LONG: 151°20'20.242"W S23 S24 S26 S25 PROTRACTED SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN ALASKA AS BUILT KOLOA NO. 2 SURFACE LOCATION ¡-: NORTHING: 2566864.64 l.L EASTING: 260774.49 ~ LAT: 61 °01 '08.478"N 1") LONG: 151°20'54.851"W ..- / ELEV: 197.4 1706 FT. FEL ~ce -I Z l.L WITHIN U.S. SURVEY NO. 1865 AS BUILT KOLOA NO. 1 SURFACE LOCATION NORTHING: 2566877.080 EASTING: 260693.06 LA T: 61°01'08.584"N LONG: 151°20'56.508"W SCALE 1 inch = 500 ft. ~O 750 I 1000 I NOTES 1) BASIS OF COORDINATES: NGS CORS STATION "KEN 1". 2) ELEVATION DATUM: MLLW NOAA BM5869H 3) SECTION LINE OFFSETS DERIVED FROM THEORETICAL BLM PROTRACTED SECTION CORNER VALUES 4) ALASKA STATE PLANE ZONE 4 NAD27 ~ Consulting C;-roup ~Testing ENGINEERING /MAPPING /SURVEYlNG /TESTlNG P.O. BOX 468 SOLDOTNA, AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 EM AIL: msmclane@mclanecg.com KOLOA NO.2 SURFACE LOCATION APPLICANT: LC PROJECT NO. DRAWN BY: DATE: June 21. 2004 OFFSETS: 1706'FEL 1308' FNL LOCATION: PROTRACTED SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN ALASKA 033008 MSM 61.88' 24.00' 17.00' I ALL DIMENSIONS ARE APPROX. vetcogray'· , DRAWN BY: C. RICE ENG. APPR.: e - ] 2-7/8' DD TBG -----------= ~-S/8' 00 CSG 5-1/2' DD CSG KALDA, i2 SWE & FCE ENGINEERING ACAD 8-5/8 X 5-1/2 X 2-7/8 OD, 3M/5M MSP ASSY IDA 1£: 31 AUG 2004 I~IREFERENCE: DA 1£: XIV-G I SCALE: NA 85-252000 REV I) AURORA GAS, LLC PROJECT NO.: DRAWING NO. SP-5049-6 ~Aurora Gas, L8: www.aurorapower.com c::Jocf -é) ~ k August 18,2004 Alaska Oil and Gas Conservation Commission 333 W. ih Ave. Ste 100 Anchorage, Alaska 99501 R€.C€.N€.O ~\JÚ 't l) l~tïJà, .r-ì.~~i\\)\\ t" \:.Qf\\\1' RE: Aurora Gas, LLC Kaloa No.2, Permit #204-096 .~ ~ Gas t,Q\\S~ ~\a"~¡ ß\ Þ.\\r.\\Ot'ð~ Gentlemen: Attn: Steve Davies This letter in duplicate originals transmits the data to you identified below, pursuant to Aurora Gas, LLC's obligation to you. This data is relative to operations at the Kaloa Field, Cook Inlet, Alaska. Enclosed herewith are paper copies as indicated and a CD-ROM with electronic copies: SCHLUMBERGER Open-Hole LOGS 1- Platform Express: Array Induction/Litho-Density-Comp Neutron/GR 1- Modular Formation Dynamics Tester 1- Formation Micro Imager 1- Dipole Sonic Imager SCHLUMBERGER Cased-Hole LOGS 1- Slim Cement Map Tool 1- Perforating Record HORIZON WELL SERVICES 1- Mud Log Please signifY that you have received and accepted this data by signing in the space below and returning this letter to me at the Houston address below or by fax to me at 907-277-1006. If you have questions, please contact me at the Houston nwnber below. Sincerely,/'·' () I ! /1 í //1./ / .. ···_-[4t!u",/,!?-é¿// \I-..~Y"µ?~ ,p" ¡ v../ ,r ///i ¿-- / J " ,~ // J./Edward Jones . //./' C/A~xecutive .Vice PresideJåÍ:'Engineering and operation~s RECEIVED D ACCEPTED ABOVE DATA this c¡ ') 10 f Day of Au t'~2004. ") / . / ~~ .ij/~ LÃ~ ~tf,.u~ 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 e e subject: RE: weekly Drilling Reports--Aurora Gas Kaloa #2 From: Ed Jones <jejones@aurorapower.com> Date: Thu, 01 Jul 2004 18:26:36 -0500 To: Thomas Maunder <to~maunder@admin.state.ak.us> CC: 'Duane vaagen' <duane@fairweather.com> 2030710_Kaloa_#2_weekly Report_070104.eml.txt Tom, Yes, we have a strip chart on the well of that, using the mud logger's equipment, I believe. we'll get a copy for you. Ed J. Ed Jones vice president Engineering & operations Aurora Gas, LLC -----original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Thursday, July 01, 2004 6:03 PM To: Ed Jones Cc: 'Duane vaagen' subject: Re: weekly Drilling Reports--Aurora Gas Kaloa #2 Thanks Ed. Just needed to confirm that. DO you have any of the actual pumping/pressure information on that?? I am just curious to see how the "curve" is shaped. If you don't have that, OK. Maybe we can catch it on the next well. Tom Ed Jones wrote: »Tom, » I am sorry--I missed putting that down. On 6/25/04 (reported on report of »6/26/04), we drilled out to 640' KB w/ 9.8 ppg mud in the hole, pressured to »240 psi, which is a 17 pp~ EMW test, w/ no leak off. I have attached an »amended report showing thlS test. please let me know if you need any »additional info about this FIT. » Thanks, Ed J. » »Ed Jones »vice President »Engineering & operations »Aurora Gas, LLC » » »-----original Message----- »From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] »Sent: Thursday, July 01, 2004 5:23 PM »TO: Ed Jones; 'Duane vaagen' »subject: Re: weekly Drilling Reports--Aurora Gas Kaloa #2 » » Page 1 e e »Ed and Duane, »I was reviewing the report. After drillin9 out on June 26, there is no »comment regarding a leak-off or formation lntegrity test. »Was one accomplished?? could you please provide the pumping information. »Thank you. »Tom Maunder, PE »AOGCC » »Thomas Maunder wrote: » » » > »»Ed, »»This format will be fine. I appreciate your catching up on the activity. »»Based on where you are on the well, it is unlikely there will be »»another full BOP test. »»we really had wanted to witness one of the tests, however availability »»and travel schedules did not allow it. »»what will the next well be?? please plan to stay in touch with Jim »»Regg as that operation timing gets better defined »»Tom Maunder, PE »»AOGCC »» »»Ed Jones wrote: »» »» »» » »»»Tom, »»» Attached are weekly drilling reports as required by the drilling »»»permit approval eRE: letter from John Norman of June 9, 2004). My »»»apologies for my tardiness. please let me know if you need more »»»information or need it in a different format. Thanks, Ed J. »»» »»»Ed Jones »»»vice President »»»Engineering & operations »»»Aurora Gas, LLC »»» »»» »»» »»» »»» » »» »» »» 2030710_Kaloa_#2_weekly Report_070104.eml.txt page 2 Final Weekly Report--Kaloa #2 e e Subject: Final Weekly Report--Kaloa #2 From: Ed Jones <jejones@aurorapower.com> Date: Tue, 20 Jul2004 17:21 :57 -0500 To: Tom Maunder <tom_maunder@admin.state.ak.us> CC: 'Duane Vaagen' <duane@fairweather.com>, Scott Pfoff <gspfoff@aurorapower.com>, 'Andy Clifford' <acc1ifford@aurorapower.com>, 'Mike Flaherty' <mikef@kfoc.net> Tom, Attached is the final weekly report for the Kaloa #2 well. The well was briefly tested, the completion assembly run, and the rig was released on 7/15/04. We have rigged back onto Nicolai Creek #3 to finish the workover there (test the casing, test new perfs, and run completion assembly if successful). Please let me know if you have any questions or need more info. Regards, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC Content-Type: application/vnd.ms-excel Report K2 071604-6.xls Content-Encoding: base64 10fl 7/21/20043:14 PM e e Lease and Well No.: Contractor and Rig No.: Present Operations: 37' GL. Casing: 12-3/4" Conductor PTD: 52' RKB Well bore Fluid: water wi light gel Brief Description of Operations for past week: Clean/drill out conductor pipe to shoe. AURORA GAS,LLC WEEKLY DRILLING REPORT PERMIT # 204-096 KALOA #2 REPORT FOR WEEK OF: 6/13/2004 Aurora Well Service #1 Start Date: 6/10/2004 Spud Date: 6/20/2004 6/13/2004 Drill conductor hole wi rig after driving of conductor stopped at Tubing: Packer: Move in AWS #1. Rig up to drill out 12-3/4" conductor. IDATE* I OPERATIONS IN SEQUENCE 5/28/2004 Rig up MWD pile driver and drive 12-3/4" conductor to 37' GL--110 bpf. Stopped to avoid damage to 65.4# (0.50" wall) conductor pipe. Move pile driver. 6/11/2004 MIRU AWS #1 to clean out conductor and drill 1 0-5/8" pilot hole for conductor. 6/12/2004 Continue to move in and rig up. 6/13/2004 PU 10-5/8" bit and 6.25" DC's and clean out conductor and drill 1 0-5/8" pilot hole to 93' RKB. * Report for 24 hours ending at 7 AM this date. Plan for Next Week: Drill pilot hole to 120'. RD AWS #1. Drive conductor to 120'. RU AWS #1. Spud well. COMMENTS Reported By: Ed Jones (7/1/040 e e Lease and Well No.: Contractor and Rig No.: Present Operations: AURORA GAS,LLC WEEKLY DRILLING REPORT PERMIT # 204-096 KALOA #2 Aurora Well Service #1 (6/20/04) POH w/ junk basket. REPORT FOR WEEK OF: 6/20/2004 Start Date: 6/10/2004 Spud Date: 6/20/2004 Prep to spud surface hole at 120' RKB. Casing: 12-3/4" Conductor PTD: 120' Tubing: Well bore Fluid: 9.6 ppg polymer/KCI mud Packer: Brief Description of Operations for past week: Drive conductor to 116' RKB. Pick up BHA and clean out conductor (hard drilling: metal and rocks). IDATE* I OPERATIONS IN SEQUENCE 6/14/2004 Drill 10-5/8" pilot hole to 125'. LD drilling assembly. RD partially to drive conductor. RU MWD. Drive 12-3/4" conductor to 100' GL (116' RKB). 6/15/2004 Dig cellar. Cut off conductor, weld on starting head. RU to drill surface hole. 6/16/2004 RU diverter system and function test. Contintue to RU to drill. 6/17/2004 Drill mouse hole. PU 10-5/8" BHA, start in hole. 6/18/2004 RIH, tag fill at 71'. Clean / drill out conductor to 73'--drilling on metal. 6/19/2004 Replace power swivel hyraulic pump. Drill metal to 74'. POH to ck BHA--OK. Drill to 90' (inside conductor). 6/20/2004 Drill to 110' inside conductor. POH. PU globe basket. RIH. Drilllcore to 114'. POH. LD GB. PU flat mill and junk basket. RIH and mill to 115', fell free under shoe. * Report for 24 hours ending at 7 AM this date. Plan for Next Week: Spud 10-5/8" surface hole. Drill to 620' and run 8-5/8" surface casing. COMMENTS Reported By: Ed Jones (7/1/040 e e Lease and Well No.: Contractor and Rig No.: Present Operations: AURORA GAS,LLC WEEKLY DRILLING REPORT PERMIT # 204-096 KALOA #2 REPORT FOR WEEK OF: 6/27/2004 Aurora Well Service #1 Start Date: 6/10/2004 Spud Date: 6/20/2004 (6/27/04) Drilling 7-7/8" hole at 1380'. Casing: 8-5/8" Surface @ 617' PTD: 1380' Tubing: Wellbore Fluid: 9.6 ppg polymerlKCI mud Packer: Brief Description of Operations for past week: Drilled 8-5/8" surface hole to 620'. Ran 8-5/8" surface casing and cemented at 617'. PU 7-7/8" BHA, drilled out shoe, and drilled to 1380'. IDATE* I OPERATIONS IN SEQUENCE 6/21/2004 Milled to 120'. POH and LD junk basket and mill. PU 10-5/8" bit and stabilizers. Spud surface hole and drill to 259'. 6/22/2004 Drill 1 0-5/8" hole to 570'. 6/23/2004 Drill to 620'. ST. Svy--2 deg. POH, LD BHA. RU to run casing. Run 8-5/8" casing to 617'. Cement wI 53 bb114.5 ppg Gas-Block cement--100% excess. Cement to surface WOC. ND diverter system. 6/24/2004 Fin ND diverter. Cut 8-5/8" and conductor. Weld on 8-5/8' head. NU BOPE. 6/25/2004 Test BOPE. PU and run 7-718" BHA. 6/26/2004 C & C mud. Test casing to 1500 psi. Drill out float collar, cement, and shoe, then drilled to 640'. FIT to 17 ppg--240 psi wI 9.8 ppg mud--no leak off. Drilled to 1020'. 6/27/2004 Drill 7-7/8" hole to 1380'. * Report for 24 hours ending at 7 AM this date. Plan for Next Week: Drill to TD of 3700'. Log. Run 5-1/2" casing. Prep for completion. COMMENTS Reported By: Ed Jones (7/1/04 ) e e Lease and Well No.: Contractor and Rig No.: Present Operations: AURORA GAS,LLC WEEKLY DRILLING REPORT PERMIT # 204-096 KALOA #2 REPORT FOR WEEK ENDING: 7/5/2004 Aurora Well Service #1 Start Date: 6/10/2004 Spud Date: 6/20/2004 (7/5/04) Drilling 7-7/8" hole at 3685'. (TO of 3720' reached at 18:25 7/5/04). Casing: 8-5/8" Surface @ 617' PTD: 3685' Tubing: Wellbore Fluid: 9.85 ppg polymer-KCI mud Packer: Brief Description of Operations for past week: Drilled 7-7/8" hole from 1380' to 3685'. IDATE* I OPERATIONS IN SEQUENCE 6/28/2004 Drilled 7-7/8" hole from 1380' to 2085'. 6/29/2004 Svy-2 deg at 2100'. Drilled 7-7/8" hole to 2618'. C & C mud. 6/30/2004 Svys--1 deg at 2616' and 1 deg at 3022'. Drilled to 3022'. Ck for flow, circ btms up. Start ÞOH--tite hole. Pump out of hole to 2632'. 7/1/2004 Pump out of hole to shoe at 617'. Rig repairs (power swivel power pack engine). Mud vis high doe to drilled solids. 7/2/2004 C & C mud. Fin POH. BOP test. RIH to 2834'. Swivel up and wash & ream to btm. Wash to 3022'. Drill 7-7/8" hole to 3064'. 7/3/2004 Drill to 3237' w/ 1850 unit ML gas--checked for flow at 3172'. Standpipe wash out. Pump out of hole to casing. Rig repair. 7/4/2004 Fin repair stand pipe. RIH. Wash last 9 jts to btm. Drill to 3395' 7/5/2004 Drill to 3685' w/ svy at 3486'--5-1/2 deg. * Report for 24 hours ending at 7 AM this date. Plan for Next Week: Drill to TO of 3720'. Log. Run 5-1/2" casing. Start completion and testing. COMMENTS Reported By: Ed Jones (7/6/04 ) e e Lease and Well No.: Contractor and Rig No.: Present Operations: AURORA GAS,LLC WEEKLY DRILLING REPORT PERMIT # 204-096 KALOA #2 REPORT FOR WEEK ENDING: 7/12/2004 Aurora Well Service #1 Start Date: 6/10/2004 Spud Date 6/20/2004 (7/12/04 ) Testing perforated production zones. Casing: 51/2" @ 3714' PTD: 3600' Tubing: Well bore Fluid: 9.8 ppg KCI brine Packer: Brief Description of Operations for past week: TD'd well at 3720' and ran OH logs. Ran, cemented and landed 5 1/2" 17# LTC J-55 casing at 3714'. Swap out mud wI WO brine and run CH logs wI GR to surface. Perforated zones Of interest and proceeded with testing individual zones. IDATE* I OPERATIONS IN SEQUENCE 7/6/2004 Drilled hole to TD at 3720' MD (TVD). SS survey at 3715' 0.5 deg. Sweep hole and condition mud for logging and trip. TOH and strap pipe to confirm depth. 7/7/2004 TIH and condition hole for logging. TOH and LD Stabilizers. PU Schlumberger and RIH with OH logs. Run Platform Express. POOH and RIH with DSI, FMI and MDT. 7/8/2004 Run MDT on wireline. POOH and RD Schlumberger. RIH with 7 7/8" bit to 3702', wash to 3720'. Circulate and condition mud for running casing. POOH and LD DP. Clear rig floor for running casing, and do 3 1/2" pipe rams w/5 1/2 rams for casing. 7/9/2004 Finish c/o of rams, cavity test stack to 1500 psi. Run 51/2" casing to 3714', RU BJ, cement wI 35 bbls 10.5 ppg spacer, 48 bbls 12.5 ppg lead and 85 bbls 15.8 ppg tail. Drain and wash stack, centralize csg wI annular and WOC. Clean flow lines and clean mud system in preparation for displacing mud wI KCL. 7/10/2004 PU BOP, set slips on 5 1/2" csg and pull 50K to seat. Cut off stub and NU tbg spool. NU stack and pressure test. Strap 2 7/8" tbg and RIH w/4 3/4" bit and csg scraper. 7/11/2004 RIH wI bit and scraper, Tag cmt at 3562'. Drill cmt to PBTD of 3600'. CBU and p-test 51/2" csg to 1500 psi. Displace mud wI brine, filter and displace. POOH, rack pipe. RU shooting flange on BOP. RU Schlumberger for CBUCCUGR logging run. Run logs. 7/12/2004 Run CBL, POOH, LD logging tools and perforate from 3522' - 3652',3250' - 3330', 3200' - 3220' and 3158' - 3178' on muliple runs w/3 3/8" HC gun wI PH HMX 6 SPF. Monitor well at each shot. RIH wI scraper, POOH, LD and PU Packers for testing. * Report for 24 hours ending at 7 AM this date. Plan for Next Week: Finish well testing operations, run completion, NU wellhead and demob rig from site to next well. COMMENTS At time of this report submittal, we are in final steps of running completion and preparing to land tubing hanger. We will swab in well after running completion to clean up. After wellhead is installed, rig will be demo bed off of site to next well. dhv. Reported By: Duane Vaagen for Ed Jones (7/15/04) e e AURORA GAS,LLC WEEKLY DRILLING REPORT PERMIT # 204-096 Lease and Well No.: KALOA #2 REPORT FOR WEEK ENDING: 7/16/2004 Contractor and Rig No.: Aurora Well Service #1 Start Date: 6/10/2004 Spud Date: 6/20/2004 Present Operations: (7/19/04) Rig released and moved. Well shut in and secured. WO 4-point test and production facilities. Casing: 5 1/2" @ 3714' PTD: 3600' Tubing: 2-7/8" Well bore Fluid: 9.8 ppg KCI brine packer fluid Packer: 5-1/2" Arrowset IX set at 3080' Brief Description of Operations for past week: Isolated and tested perfs in 3 tests. Ran completion assembly. ND BOP, NU and tested Tree. Retested well for 45 min--est combined rate of about 6 MMcfpd at 900 psi. SITP--1400 psi. Set BPV. Release rig and rig down, move to next well. IDATE* I OPERATIONS IN SEQUENCE 7/13/2004 Run RBP (packer wi plug) and packer, set plug at 3570' (below perfs) and pkr at 3509'. Swab in perfs 3522-3552'. Flow for 30 min. Rec load. Final rate est at3.5 MMcfpd at 710 psi, 28/64". 30 min SITP-1400 psi. Open unloader and rev circ thru choke to kill well. Retrieve RBP and reset at 3368'. Reset pkr at 3233'. Swab well in and test perfs 3250-3330'. Rec load. Flow at 4.7 MMcfpd at 875 psi on 29/64" choke, then at 3.8 MMf at 1050 psi on 24/64" choke for 30 min. 10 min SITP--1400 psi. Open unloader to kill well by reversing thru choke. Took several circ to kill, lost 49 bbl. Retrieve RBP and pull up to reset. Unable to set pkr. POOH wi prk and RBP. 7/14/2004 Redress RBP and RIH and set at 3235'. POH and PU new pkr. RIH and set pkr at 3138'. Swab in perfs 3158-3178' and 3200-3220'. Rec load. Flow at 2.2 MMcfpd at 620 psi on 24/64" choke, then at 1.9 MMcfpd at 750 psi on 20/64" choke for 50 min. 30-min SITP-1350 psi (still building). Open unloader and rev circ thru choke to kill well. POOH wi pkr. Release RBP. POOH. 7/15/2004 Fin POOH--no RBP. RIH, latch onto RBP. POOH. RIH wi bit to 3600'. Circ and filter brine. POH wi bit. PU completion assembly wi sand control screens below pkr. RIH wi completion and space out--pkr at 3083' wi screens and tbg spacers 3151-3551'. 7/16/2004 Circ pkr fluid, space out, set pkr. Test tbg-csg annulus to 2000 pis for 10 min. ND BOP. NU & test tree to 3000 psi. Swab in well. Tested at est 5.9 MMcfpd at 900 psi on 32/64 10-min SITP-1400 psi. Set BPV in tree. Rei rig. RD and move to NCU #3. * Report for 24 hours ending at 7 AM this date. Plan for Next Week: Well completed. Move to finish workover at Nicolai Creek #3. COMMENTS Reported By: Ed Jones (7/20104 ) Aurora Gas, LLC Kaloa #2 e e Subject: Aurora Gas, LLC Kaloa #2 From: duane vaagen <duane@fairweather.com> Date: Fri, 25 Jun 2004 10:05:30 -0800 To: Thomas Maunder <tom_maunder@admin.state.ak.us>, James Regg <jim Jegg@admin.state.ak.us>, Robert Fleckenstein <bob _ fleckenstein@admin.state.ak.us> Tom: Please find attached the BOP test results for yesterday's test. We are currently preparing to drill out the shoe, will drill -20ft and perform the LOT and will then commence drilling operations on Kaloa #2. Regards, Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: 107 .. BOP Aurora Well Service Content-DescriptIOn: 06-24-04.xls BOP Aurora Well Service 06-24-04.xls Content-Type: Content-Encoding: applicationlvnd.ms-excel base64 10fl 7/21/20043:15 PM tIt e STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: Em reQQ(á¿admin.state.ak.us aogcc prudhoe bay@adm;f1.state.ak.us bob f;eckef1ste;f1~admín.state.ak.us Rig No.: 1 DATE: 6/24/2004 Rig Phone: 632-0083 Rig Fax: 240-4918 Op. Phone: 440-5500 Op. Fax: 440-5500 3/30/04 Contractor: Aurora Rig Rep.: Gary Goerlich Operator: Aurora Gas Rep.: Jack Keener Field/Unit & Well No.: Kaloa #2 Location: Section: Operation: Drlg: X Test: Initial: X Test Pressure: Rams: 3000 Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve 26 Well Sign Dr!. Rig Hazard Sec. Size 11" 31/2" N/A 11" 3" 3" MUD SYSTEM: Visual Test Trip Tank P Pit Level Indicators P Flow Indicator P Meth Gas Detector P H2S Gas Detector P Alarm Test P P P P P PTD # 204-096 Township: 11 N Workover: Weekly: Annular: 1500 TEST DATA Test Result P P P Test Result P P I P P P P NA Meridian: Range: Explor.: X Other: Valves: 3000 N/A R12W FLOOR SAFETY VALVES: Quantity Test Result Upper Kelly 1 P Lower Kelly NIA I Ball Type 1 P Inside BOP 1 P CHOKE MANIFOLD: Quantity Test Result No. Valves 12 P Manual Chokes 1 P Hydraulic Chokes 1 P ACCUMULATOR SYSTEM: TimelPressure Test Result System Pressure 3100 P Pressure After Closure 1800 P 200 psi Attained 20 P Full Pressure Attained 3 min 35 sec. P Blind Switch Covers: All stations P Nitgn. Bottles (avg): 1050 psi Test Results Number of Failures: 1 Test Time: § Hours Components tested 30 Repair or replacement of equipment will be made within 0 days. Notify the North Slope Inspector 659-3607, follow with written confirmation to Superviser at: Em reQQ(á¿admin.state.ak.us Remarks: Gas detector sensor failed on riq floor. Detector replaced and unit calibrated by Qualified technician called out to riq. MISC. INSPECTIONS: Test Result Location Gen.: P Housekeeping: P PTD On Location P Standing Order Posted P BOP STACK: Quantity 1 1 NIA 1 1 1 2 NA 24 HOUR NOTICE GIVEN YES x NO Waived By Tom Maunder Date 06/23/04 Time 14:00 Witness Jack Keener Test start 12:00 Finish 17:00 BOP Test (for rigs) BFL 3/8/04 BOP Aurora Well Service 06-24-04.xls RE: Aurora Gas Diverter Test Jim: Per our conversation concerning the diverter test, the following information is applicable to the BOPE being used: On the NCU #3 well, a work-over which Aurora Well Service just moved from, we were using a complete 13 5/8 5M stack, i.e., annular and double gate with a matching Koomey unit sized for the system. For the Kaloa project, we are using the 13 5/8" annular preventer and the rigs accumulator unit, which is sized for their 11" 3M stack. The slower recovery as noted below can be attributed to the larger volume requirements of the large annular preventer. As soon as we get done with the surface hole and diverter, we will rig up the 11" 3M stack which mates up with the rigs accumulator unit we are now using. The recovery time concern should then be a non-issue. In looking back at the reports from last year using the same diverter assembly, the recovery times are similar. Duane Vaagen Fairweather E&P Services, Inc. 258-3446 -----Original Message----- From: James Regg [mailto:jim regg@admin.state.ak.us] Sent: Thursday, June 17, 2004 5:59 PM To: duane vaagen Cc: Tom Maunder Subject: Re: Aurora Gas Diverter Test Duane - Thanks for the timely report. Test results indicate the accumulator pump took 4 minutes to attain full system pressure. This is right at our upper limit for approval (AOGCC Petroleum Inspection Manual - "After activating the BOP's, the accumulator must repressure the system in 4 minutes or less"). This should be investigated. Please advise. Jim Regg AOGCC 907-793-1236 duane vaagen wrote: Jim: Attached is digital copy of diverter test performed by Aurora Well Service Rig 1 on the Kaloa #2 well for Aurora Gas, LLC. Please call if any questions or concerns. Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com <mailto:duane@fairweather.com> Office: (907)258-3446 Cell: (907) 240-1107 ~ 6/18/2004 12:35 PM Re: Aurora Gas--Kaloa #2 (203-071) e e Subject: Re: Aurora Gas--Kaloa #2 (203-071) From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Fri, 28 May 2004 09:31 :39 -0800 To: duane vaagen <duane@fairweather.com> CC: Steve Davies <steve_davies@admin.state.ak.us> Duane, I checked with Steve Davies and a new permit is needed. Refer to 20 AAC 25.015 (a) (1) covering changing the surface location. Explain in the cover letter the reason for the new permit and request that the prior one be canceled. You can keep the same well name, however the permit # and API # will change. Tom Maunder, PE AOGCC Thomas Maunder wrote: Hi Duane, 1) No additional sundry is needed. Cover it in the 407. 2) What is the distance to the spot listed on the permit?? Tom duane vaagen wrote: Tom: We are in the process of driving the new conductor for the Kaloa #2 well. I do have a couple of questions? 1) Last week we received a verbal approval to go ahead and drive 12 3/8" pipe versus the 11 7/8" as indicated in the approved Sundry. IQuestion: Do you need another sundry to update this information or can I just indicate that change in the 10-407 when done?1 2) In the interest of minimizing surface disturbance and utilizing as much of the original Albert Kaloa #1 pad, it was in Aurora's best interest to re-stake the well center prior to driving the conductor (the original stake was placed in late winter when we had a lot of snow cover) . Also, we are in our second attempt to drive the conductor with a pile driver in the new location, the first being aborted when we struck a large rock at -28 I . IQuestion: What, if any paperwork do you need from us at this time? II After we get the conductor driven and surveyed, do you need a new PTD, or a Sundry to advise of the location change. II II II II I Regards, Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com <mailto:duane@fairweather.com> Office: (907)258-3446 Cell: (907) 240-1107 1 of 1 4/27/20052:27 PM . . fl . ! LS FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 J. Edwards Jones Executive Vice President Aurora Gas, LLC 1400 West Benson Blvd., Ste 410 Anchoragae, Alaska 99503 Re: Kaloa #2 (revised) Aurora Gas, LLC Pennit No: 204-096 Surface Location: 1172' +/- FNL, 1713' +/- FEL, S26, T11N, R12W, SM Bottomhole Location: 1172' +/- FNL, 1713' +/- FEL, S26, T11N, R12W, SM Dear Mr. Jones: Enclosed is the approved application for pennit to drill the above referenced exploration well. A revision of the original pennit was necessary due to moving the surface location. This pennit to . drill replàces the original pennit number 203-071, which has been cancelled at your request. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the pennafrost or from where samples are first caught and 10' sample intervals through target zones. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the commi.SSiont]to 1 ess any required test. Contact the Commission's petroleum field inspector at (907 659-3 7 ~er). Sµæere , /' If. C v .~L BY ORDER 0bTHE COMMISSION DATED this-7day of June, 2004 cc: Department ofFish & Game, Habitat Section w/o end Department of Environmental Conservation w/o encl. A STATE OF ALASKA '-:;KA OIL AND GAS CONSERVATION CelSSION PERMIT TO DRill 20 MC 25.005 I::~:~~~;::::Õ =: s~~weIlÆ~;~~¿;~~p Bond No. NZS 429815 KáfóìHitw.~n 6. Proposed Depth: 12. FieId/Pool(s): MD: 3700' TVD: 3700' Kaloa Gas Field 7. Property Designation: C-61393 8. Land Use Permit: 13. Approximate Spud Date: 10-Jun-04 14. Distance to Nearest A 36.3 .- , /..xJ 3435 Property: ~- "7.6'-/ 10. K.B Elevation 15. Distance to Nearest Well (Height above GL): 16 feet Within Pool: 82' to P&A'd well 17. Maximum Anticipated Pressures in psig (see 20 MC 25.035) Downhole: 1650 Surface: 1238 Setting Depth Quantity of Cement c.f. or sacks 1a. Type of Work: Drill l:d Redrill U Re-entry 0 2. Operator Name: Aurora Gas, LLC 3. Address: 1400 West Benson Blvd., Ste 410, Anchorage AK 99503 4a. Location of Well (Govemmental Section): Surface: 1172' +/- FNL, 1713' +/- FEL, 526, T11N, R12W, SM Top of Productive Horizon: Same Total Depth: Same 4b. Location of Well (State Base Plane Coordinates): Surface:x- 260758 y- 2566920.8 Zone- 16. Deviated wells: Kickoff depth: n/a Maximum Hole Angle: 9. Acres in Property: 4 feet nla degrees 18. Casing Program: Size Casing 12314" 85/8" 51/2" Specifications Top E.....'· . !Ii i Coupling welded ST&C LT&C Bottom MD TVD 90 90 NJA 620 620 46 bbls @ 100% Excess 3700 3700 120 bbls@20% OH Vol. Hole Driven Weight 65.4# 32# 17# Grade Structural WC-50 J-55 Length 90+ MD TVD o o o o o o 10 5/8" 77/8" 620 3700 (including stage data) 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) . Total Depth MD (fi): Total Depth TVD(fl): Plugs (measured): . Effect.DePUJ MP(fi): JOttect, [)epthIVD (fit Junk (rneasurecj): Casing Structural Conductor Surface Intermediate Production Liner Length Size Cement Volume Perforation Depth MD (fi): MD TVD 20. Attachments: Drilling Program U Seabed Report 0 Perforation Depth TVD (ft): Time v. Depth Plot U Shallow Hazard Analysis U Drilling Fluid Program 0 20 MC 25.050 requirements 0 Date Contact Filing Fee l:d BOP Sketch U Property Plat 0 Diverter Sketch 0 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing istrue and correct to the best of my knowledge. J, Edward Jones !.///l () ;- ~ X Signature \;1--- ~,.~ Phone 907-277-1003 /// / / Commission Use Only Permit to Drill/ / I / -..,¿:]/ IAPI N+r: Ipermit Approval Number: !/2Ó't-D/0 t>~0-2Bg'-20/07-é6 Date: Conditions of approval : Printed Name Title Exec. Vice President Other: ORIGINAL o No ~ o No Iß Yes Yes Mud log required Directional survey required ~ Approved by: FUll II I BY ORDER OF THE COMMISSION Date: Date 6/9/2004 ¡See cover letter for other requirements. Yes ~ No 0 # Yes D. No ø ~I.~ l'~ 41....<...- òi<!j ::~- v¿,:/ ' b/9k'~ ,~. ~.DíY 7 ~{;fv'~"V SENT BY: . 6- 9- 4 NOTES 1) BASIS OF COORDINATES: NGS CaRS STATION "KEN 1". 2) ELEVATION DATUM: NAVD88 3) SECTION LINE OFFSETS DERIVED FROM THEORETICAL PROTRACTED SECTION CORNER VALUES 4) ALASKA STATE PLANE ZONE 4 NAD27 5) Shoreline of Cook Inlet digitized from oeriol photography and distance to proposed well Is approximate. -- --- -- PROTRACTED SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN ALASKA WITHIN U.S. SURVEY NO. 1865 NORTHING: 2566920.8 EASTING: 260757.7 LAT: 61"01'09.028" LONG: 151°20'55.215" ELEV: 197.6 SCALE 1 inch ;= 1000 ~oo fl. 1500 I 2000 I ~ Cot15ulJi"g C;roup ~Te5ting ENGINEERING!MAPPING/SURVEYING/TESTlNG P.O. BOX 468 SOLDOTNA. AI<. 99aB9 VOICE: (907) 2S3-421B FAX: (901) 283-3255 EUAlL: msmclaneGmclonecg.cQffl PRO.IECT NO, DRAWN RV; DATE; REVISED: 06l0J..09/2004 033008 MSM 11 :36 . .... 9072771006;# 2/ 2 AS STAKED KALOA NO. 2 (OPT. C ALT. A) SURFACE LOCATION (FORMERLY ALBERT KALOA) I ~""\\'" .....'c Of A( " :': ~~·'·'.'--··"1~~tll I -¿'" 'I : * ..<49.Il:i ....., * ~ I ~... ......... ............... --...". ~ t' -- . --. . - .. . .... .. .. .. .. . ... . . . ... . . ~ I ~ '\ ....~. SCOTT MelANEï/ :: Î~ IJI~... 492S-S .,' - . ."''\:¡ ~ "'-' I II't~~~:;;~~""': " h\,"" I ! .....J :z LL - _ ....2231 S2.L s26Tš25 I I 1713 FT. FEI_. I I I I I ---- t-= LL ('J ,..... ..- COO K \1-11. E T KALOA NO.2 SURFACE LOCATION APPLICMlT; ulOra Gas, I.I.C .......... .' OFFSETS; 1713'FEL 1172' FNL LOCATION: SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN ALASKA Sent By: AURORA#POWER; . 7139771347; JU.04 11: 16AM; '.. ~ ) . Page 2 55 Q.3:j~:&9'.&c ~._. 1'1"k ~'f¡j~~~ .. ¡ ("'\. ,,-...... -. . ) ',. .,~. '.'.~i' + +' .' '-~~~,. + .~\ ....". ..... '.. r', ~/ :,.;.. . "'Il :~' .... ~ ... ~ '. . .... r- " + .- ~. 4- :+, :+ . ".., .~'.: . - + q¡:,.:·~'~;.~::t:::r~', .~ -- +., '" +" .-+ JUI\j O.~¡¡ /]U4 + . i*. ii.f.:,..;j~.,~. 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Ed Jones ---~_._~--,..._'"-..,......-~,._-~---.>~._----,------~~~~--~".~~-_._~'"--~~'--~->-' From: Ed Jones Uejones@aurorapower.com] Sent: Wednesday, June 09,20041:19 PM To: Steve Davies Cc: Tom Maunder; 'Duane Vaagen'; Randy Jones Subject: Request to Cancel Permit to Drill #203-071 Because the location of the proposed Aurora Gas LLC-operated Kaloa #2 has been changed and a new Application for Permit to Drill has been filed for this new location, Aurora Gas hereby requests that the original approved Permit to Drill for this well, #203-071, be cancelled, to be replaced by the pending Permit for the new location. Please let me know if any further action i~uired by Aurora to cancel this approved Permit. Thanks, Ed Jones (\ ~r! )t . ¡ I . . Ed Jones . / Vice President / r Engineering & Operations ,/ / ¡ / / I / Aurora Gas, LLC V ¿/ , ,) 6/9/2004 ! ¡ I 151 20 00 '\if 22 VI ¿;;'}I I<ALO!>. ! --{ALGA j Aurora LLC CIRILease C-61393 Feet ¡ o 2 U notal ADL 17581 260 ! STATE OF ALASKA .KA Oil AND GAS CONSERVATION C.ISSION NOTICE OF CHANGE OF OWNERSHIP 20 MC 25.022 I~erator Name: _ra Gas, LLC 2. Address: 10333 Richmond Avenue Suite 710 Houston, Texas 77042 -3. Notice is hereby given that the owner ~ ' landowner assigned or transferred interest in the property indicated below: u , of record for the oil and gas property described below has Property Designation: C-61393 Legal description of property: Sections 13; 14; 15, E2E2E2; 22, E2E2E2; 23; 24, Fractional; 25, Fractional; 26, Fractional; 27, Fractional, E2E2E2; Comprising 3,435 Gross/Net Acres Township 11 North, Range West Seward Meridian Field or Unit Moquawkie Field Lessor: Cook Inlet regions, Inc. RECEIVED APR 1 5 2004 Lessee: Aurora Gas, LLC . Alaska Oil & Gas Cons. Commission Anchorage Property plat attached 0 4. Effective date of assignment or transfer: December 31,2002 5. Percentage interest assigned or transferred: 100.00% 6. Assignee or Transferee: Aurora Gas, LLC Address: 10333 Richmond Avenue, Suite 710 Houston, Texas 77042 7. Assignor or Transferor: Anadarko Petroleum Corporation Address: 1201 Lake Robbins Drive The Woodlands, Texas 77380 8. I hereby certify that the foregoing is true and correct to the best of my knowledge. , ,/). A /\ /)Þ?ÆÆ~ 5;900,"re y JJ.A;4</ ~ )(--;-_::/tJ V" ¡ Date: April 13, 2004 tinted Name: Andrew C. Clifford Title: Executive Vice President Form 10-417 Rev.10/2003 A_ STATE OF ALASKA ~KA Oil AND GAS CONSERVATION C.ISSION DESIGNATION OF OPERATOR 20 MC 25.020 ¡. Name and Address of Owner: rora Gas, LLC 33 Richmond Avenue, Suite 710 Houston, Texas 77042 2. Notice is hereby given of a designation of operatorship for the oil and gas property described below: Legal description of property: f Sections 13; 14; 15, E2E2E2;22, E2E2E2; 23; 24 Fractional; 25, ractional; 26, Fractional; 27, Fractional, E2E2E2; Comprising 3,435 GrosslNet acres A Township 11 North, Range 12 West Seward Meridian )b {IÇ·6~ Lessor: Cook Inlet Region, Inc. RECEIVED APR 1 5 2004 Lessee: Aurora Gas, LLC C-61393 Alaska Oil & Gas Cons. Commission Anchorage Property Plat Attached: o 3. Name and Address of Designated Operator: Aurora Gas,LLC 10333 Richmond Avenue, Suite 710 Houston, Texas 77042 . Effective Date of Designation: 31-Dec-02 5. Acceptance of operatorship for the above described prope~ within all attendant responsibilities and obligations is hereby acknowledged: Signature r?dæw ª. e Date April 13, 2004 Printed Name Andrew C. Clifford 6. The Owner hereby certifies that the foregoing is true and correct: " Title Executive Vice President Signature ~ ~ e Date April 13, 2004 Printed Name Andrew C. Clifford 7. Title Executive Vice President Approved: Appr Commissioner 4/;_7Dat'r f6 ~i .qUireS Form 10-411 Rev.10/2003 Submit in duplicate Request to Cancel Permit to Drill #203-071 . . Because the location of the proposed Aurora Gas LLC-operated Kaloa #2 has been changed and a new Application for Permit to Drill has been filed for this new location, Aurora Gas hereby requests that the original approved Permit to Drill for this well, #203-071, be cancelled, to be replaced by the pending Permit for the new location. Please let me know if any further action is required by Aurora to cancel this approved Permit. Thanks, Ed Jones Ed Jones Vice President Engineering & Operations Aurora Gas, LLC r~,~1 \ lJ ,/ /' t J .~i!/ ~ /I V .'~ '-- (1 ~ / cY~~ . 0 / ( l/ ·v + l' .~. . . ¡ .// '. l /( \( r~) '~ /? ¿/{ /J.V .'\ 0 L/ C, \.) \~, í -z; ß P.·~.. '}..~ LX~ -'- ('\. C , l¿/l / . V í I lofl 6/9/2004 12:45 PM 2 I 1512000W -<AlO". 1 Feet t o 2 --,- ttc www.aurorapower.com 1400 West Benson, Suite 410, Anchorage, Alaska 99503 It~ June 3, 2001 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Re-application for Permit to Drill: Kaloa No.2 Dear Mr. Norman: Per a recent correspondence with Mr. Tom Maunder on May 28, 2004, Aurora Gas, LLC hereby submits a ne~Permit To Drill application for the Kaloa No.2 prospect. This application is being submitted for the following reasons: 1. The original Kaloa No.2 site was staked in late winter 2003. While clearing the site-access road this spring and beginning the site prep work, Aurora made a decision to move the well stake. This decision was made to minimize impact to nearby vegetation, re-use as much ofthe original Albert Kaloa No. 1 well pad as possible and avoid proximity issues with nearby wetlands as determined in a survey made last summer. We have picked the site indicated in the attached plat which offers the optimal spot to place the rig. It should also be noted we are on our second attempt at driving the 12 o/,¡" conductor. Hard driving conditions were encountered on both the initial and current attempt, we are preparing to complete the conductor installation using the drill and drive method. Aurora Gas will complete and submit an As-Built survey of the site upon completion of well drilling and testing activities at the site. 2. Subsequent to receiving approval for the original application for Permit to Drill, Aurora modified the proposed well geometry. This was noted in a recently approved Sundry Application. The well geometry modifications are noted in this new Application for Permit to Drill. All other details of the well program will remain the same and there are no other foreseeable changes at this time. Aurora plans to begin drilling operations on June 7, 2004. Pertinent information in and attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill- 2 copies. 2) Fee of $100.00 payable to the State of Alaska. ORIGINAL 10333 Richmond Avenue, Suite 710 · Houston, Texas 77042 · (713) 977-5799 · Fax (713) 977-1347 1C'''P W"d ir" Avenue, ~uitG 22C · Anchorage, A/aska 99501 · (907) 277-1003 · Fax (907) 277-1006 . . 3) Plat maps detailing the new surface and proposed bottom-hole location 20 AAC 25.050 (c)(2). If you have any questions or require additional information, please contact Duane Vaagen at (907) 258-3446, or the undersigned at (907) 277-1003. Sincerely, AURORA GAS, LLC / / / / i / . Edward Jones t/ Executive Vice President, Operations and Engineering Enclosures cc: Duane Vaagen Andy Clifford ~ STATE OF ALASKA .. A~ OIL AND GAS CONSERVATION CO~SION PERMIT TO DRILL 20 AAC 25.005 AirL1í:í 1~~;a~~~:~:i;;:s~laÒ ~:~~~:tOry â ~:::~::::~~~s r'~3j~j~::~~~:e ~ 5. Bond: Blanket [] Single Well 0 11. WeU Name and Number: Bond No. NZS 429815 Kaloa NO.2 6. Proposed Depth: 12. Field/Pool(s): ~ MD: 3700' TVD: 3700' Kaloa Gas Field 7. Property Designation: C-61393 ./ 8. LandLse Permit: 1a. Type of Work: Drill [] Redrill 0 Re-entry 0 2. Operator Name: Aurora Gas, LLC 3. Address: 1400 West Benson Blvd., Ste 410, Anchorage AK 99503 4a. Location of Well (Governmental Section): Surface: 1172' +/- FNL, 1713' +1- FEL, S26, T11 N, R 12W, SM ./ Top of Productive Horizon: Same Total Depth: Same 4b. Location of Well (State Base Plane Coordinates): Surface:x- 260758' y- 2566920.8' Zone- 16. Deviated wells: Kickoff depth: n/a Maximum Hole Angle: 4 feet n/a degrees 18. Casing Program: Size Casing 123/4" 8 5/8" 5 1/2" Specifications Grade Structural WC-50 J-55 Coupling welded ST&C LT&C Length 90+ Hole Weight 65.4# 32# 17# Driven 10 5/8" 77/8" 19. Total Depth MD (ft): PRESENT WELL CONDITION SUMM R Total Depth rvD (ft): Casing Structural Conductor Surface Intermediate Production Liner Length u o P'oled Name Cì -l. 6 Signature ~ 2.a Permit to Drï //-".... ' I Number: / 2D ....,- "'" Conditions of approval : /'/\ 13. ~ximate Spud Date: 7-Jun-04 14. Distance to Nearest 435 Property: 1 002' 15. Distance to Nearest Well ./ feet Within Pool: 82' to P&A'd well res in psig (see 20 AAC 25.035) Surface: 1238 Quantity of Cement c.f. or sacks 9. Acres in Property: 10. KB Elevation (Height above GL): 17. Maximum Anticipated Pres Downhole: 165D SeWn 1;op M~~~\ 3~~~ C\ .Vo ~/~ Bottom MD o o o 90 620 3700 A.h JUN 042004· (including stage data) TVD 90 N/A 620 46 bbls @ 100% Excess 3700 120 bbls @ 20% OH Vol. completed for Redrill and Re-Entry Operations) Effect. Depth MD (ft): Effect. Depth TVD (ft): Cement Volume Perforation Depth TVD (ft): Junk (measured): MD TVD ~ r¡,,¡{ Perforation Depth MD (ft): U 20. AUaohments, Fmog Fee JjV.,!{, Property Plat B 21. Verbal Approval: Commission Repre ntative: 22. I hereby certify that the foregoing is ue and correct to the best of my knowledge. Drilling Program U Seabed Report 0 Time v. Depth Plot U Shallow Hazard Analysis U Drilling Fluid Program 0 20 AAC 25.050 requirements 0 Date Contact Title EX ~C. lIí ~C" 907~277-1¿J¿)3 Phone Commission Use Only ber: IPermit Approval 50-2..83 - 2ð/07~c::::cJ Date: Yes Yes o No ~ o No ~ Mud log required Directional survey required BY ORDER OF THE COMMISSION ORIGINAL Approved Form 10-401 Revised 12/2003 ¡?Yt'.5/ ¿¿';n T Date & / -00 ¡See ~over letter for other requirements. Yes R1 No 0... Yes 0 No ~ ..i}> * I¡."clt'1\-t-h-"",- rni;¡ !.v...rIl.¿I·· t,7'Þ,;¡ ~t;œm Date: / '''-.-'''. ~ ÞS"sIA1<E!)loÓi~ON \ _ _ - ,- - - - -' - -"--- .oÁ-N.Q~.GAL ' 6i"\ /~.. __ -.- - - -- - ~ ~ \ ~~ /- \ \ ~,.,.., ,-'- ~ .. ,/..... "",.. '\ \ 'vj~......- ---- ~ 'r''''- "-, \ \,~ -"...... ,........, \ \. " h¿). __ ~ " ~~ \ /I. "- /' , ,/W .f ~.... ) --., .- __ \""/A/-"-%(.~ / ."'\.N<œ X.'¿ ~"")// -- - . (I»~~~ /ŽX ~{/' \ :ø ~'fF-;.~ /: :,,¿3 ~/' \ \'.. ?1r ?::' ----¿;;f ,/// ~ß#" \ 1 J 1// /. \ / U/ \ V/yfl ~' ' '-I \ If' , \ / 1/ V·/' s£~o\\// (ø l1' /' '\¡ / / jI , aR"''''' f. 1/ ilf. ( / .~ / ¡^, / /' I' / , i I /II I- tÍ(('¡ / ' , '1/ / 'I I 11 ì . I / ' / il/¡ '-<I ~! Ji1 / / II ¡, {\,.. -- l. I ~ 0\.0 GROWTH / ' It/¡ fOl\EST : / EXI$T'NGWEU. / 1 J / I /" ~ / N..6ERTYJ>J.QAOO.1Pþø/ll / / í i/l ~ / 1'///1 / 4[. jL 'r ,/ (,7 ¡ I / I t \ [~__ Illf / ~ New ~taked Kaloa #2 Well ~ --ì) //¡----.__-::::;---/ W} ___~/ ~-g- LocatIon: \ 0/ jI " /Lt /% -82' ENE from P&A'd Albert , ',\~~__J/{,/I______ I I~ .~~ Kaloa #1 and -190' SW of /\ \ ~ 'i} / / '\ \ j~' ~ ./if¡ lí~-" ~-;, Information will be updated _ " / / ~:';~\ / : ~~ i FL//'-Y ,/4.;);/,;~</~~:" when drilled and new As-Built , '~'""'-"" I; j'j " 'y'//.. /, rf d / ,', ~_ II jí~/7 ,y~." /> " /' '::>' ,--survey pe orme / , " -, / I t- ¡ 0/ ',' " f" '¡.' ..r . " ,W¡¡"AHœ ",c,(ì ~ I! ,'! .", . yo' . .' ' . "" I /{ r 'T/ ",'. , . . \ I! J' d j/ , " 11./;/ "I j/ , ,l }I {:51 .1/. ", ( I b, ,J, ' \~ I· 'I .// "\~ ! I) f; ]J / '\~ II! J :/j/ ,)'- \ " /¡1 .J.~?/ ).J, ~1~ .,. . '0 'iff:/. ",' , . . ',~\. ii/iff" / '.... 'b-. " /!!lI,J ,., ¡,. AI .1.. '<'f...::o.', ~ ¡ ..., J .~) ,~ \Jr 't -J¡ lvr / \ ~! If I: ,Y / \1í!i./",/ ,(,.' f'" ! ... J' ,I / / ~¡ / J)// I C1.D GRO',fffli '_S1 SCALE '" t 'f:%.' ,~ I ..' .~ '~ '~- -, --- ~ i ~ i' ~ ~ ~ £ L7 t ij: £ v ~ ,~~ _ ~ n~~ 3 ìJ' ~<:¡~ ~ ~ $~~t ~,,! f2~l 0:~ ~,*t' '.1 u;;~ ~Qg3 !~ ': ¡¡ J ¡)/IAw8Y;Ø\\& ~,CI([()8Y;iotS&.l lt1tl.~t·...Ut '«U. SCAiÆ, t;1J. 3'£tJo C1 ~ ~ U .... ..... I I~ :I ~ 1;~ ~I "~ f . i , . :~~9f~~~.\tttJf - ",. . ~ -'l~,!!I*' " r ~<~:¡:~~,~~:g ?~~.w~¿Zi #ft,~,..."'''' . ¿ '" % ~ 9 !. ¡ ~ ~ ~ . ( § .' o %' ~;, ß . "'-"\.\.\\\" .....' OF Al .f _- '\~""'''''.~.-1 ('\ " - ^,~.., *"~"'- I - &) ..' ':.'-y I :*....49TH ....*~ ".. ................ ............. .... " " ,; ~ " ,;.... ...............................". ,; ~ ··.M. SCOTT MCLANE;!: .. ~ ~~ .' - I~ '" ". 4928-S ..' - ~I ~<') .... .....:- , () I>b-........... \.~ .... I. 'VFtss I ~,,\. ......... ,.,\\\."\.", PROTRACTED SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN ALASKA WITHIN U.S. SURVEY NO. 1865 NORTHING: 2566920.8 EASTING: 260757.7 LAT: 61°01'09.028" LONG: 151°20'55.215" ELEV: 197.6 / SCALE 1 inch =: 500 ft. o 500 ~..~ 750 1 1000 ! ~ Consulting <::;'roup ~Testing ENGINEERING /M APPING /SURVEYlNG /TESTlN G P.O. BOX 468 SOLDOTNA, AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmclaneCmclanecg.com PROJECT NO. DRAWN BY: DATE: 04/04/03 REVISED: nt=:./n':t/nl1 033008 MSM . ...J Z U- I- U- N I"- ....- ....- / 1713 FT. FEL (@ AS STAKED KALOA NO.2 (OPT. C AL 1. A) SURFACE LOCATION (FORMERLY ALBERT KALOA) NOTES 1) BASIS OF COORDINATES: NGS CORS STATION "KEN 1". 2) ELEVATION DATUM: NA VD88 3) SECTION LINE OFFSETS DERIVED FROM THEORETICAL PROTRACTED SECTION CORNER VALUES 4) ALASKA STATE PLANE ZONE 4 NAD27 - KALOA NO.2 SURFACE LOCATION APPLICANT: S23 S24 S26 S25 /-'" ""~Aurora Gas, LLC OFFSETS: LOCATION: 1713' FEL SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST 117?' 1=1\11 C::¡::'^,ARn U¡::RlnlAfo.l AI AC::I<'/!. · - ,~Aurora Power 10333 RICHMOND AVE., SUITE 710 HOUSTON, TX 77042 PH: (713) 977-5799 PAY TO THE ¡\OGCC ORDER OF One Hundred dnd 00/ :;()GC~ ApD r\..a¡()a~¿.:.oo~ l- Kalod SW1lb:yNotioo A?.D MEMO FIRST NATIONAL BANK ALASKA ANCHORAGE. AK 99520 89-611252 2170 6/3/200·1 I $ ** 100.00 DOLLARS {Ð 9 ~··"'~··'L& ..... ()~} CL -p<~\ /) .. ..~,_' ...,',:_.,..........".,... ,."..~,.."_"".,.w,"'.~,.,.,.....".,,.,,' ."','_"""_."'.,__',.__>, ,<".__", ,~,.,\' "._...,...:~",..,.~",..,,~ .... "'_,.,."','_' ~,...¥,._...",.,,,,"~'.'> 11100 2 ¡. 70111 I: ¡. 25 2000 (;01: :10 20 :18 ~ ?III -- -- NOTE TO FILE Aurora Gas, LLC Diverter Waiver Request Kaloa #2 (203-071) Aurora Gas, LLC (Aurora) has applied for an exception to 20 AAC 25.035(c)(1 )(8) that requires the diverter line size to be equal to or greater than the drilled hole size. The reason for Aurora's request is that the planned casing/hole size for the surface interval has been reduced. In the new plan, the maximum hole size possible is now 10-5/8", which gives a hole area 13% larger than the 10" diverter line cross-sectional area. It is Aurora's contention that the surface hole on the subject well can be safely drilled. This document considers Aurora's request and recommends approving it. Kaloa #2 is being drilled as a gas well with a planned TD of 3700'. The surface hole will TD at 620'. This well is located -120' from the Albert Kaloa #1 (AK#1) (167-031) which was drilled in 1968 and P&Aed in 1974. The AK#1 did produce gas from intervals near 3600', however sand production was experienced and it was not possible to keep the wellbore clean. According to the AK#1 mud log, surface casing in that well was set at 285' and cemented to surface. The surface hole section and the next hole interval were both "piloted" and subsequently opened after logging. The file records do not indicate any problems encountered drilling these intervals. Given the operations performed, the time necessary to drill, log, open and case the hole sections does not indicate many difficulties. Examination of the mud log indicates that methane was first detected around 500' md which is slightly shallower than the planned surface casing depth. The minimum planned mud weight for this hole section is 9.5 with provisions to increase to 10 ppg if necessary. The rig is equipped with required mud pit monitoring equipment and since the rig will only recently have started up, an AOGCC Inspector will have witnessed the function testing of such equipment either on this well or one prior to it. The requirement to have a diverter line size greater than the initially drilled hole size is to prevent the diverter line from acting like a choke if a divert situation were to occur. With the hole and casing sizes originally proposed, Aurora rightly planned to drill a pilot hole. 12-1/4" hole would have given an area 50% larger than the diverter line. The Commission has previously approved drilling a 12-1/4" hole while using a 12" diverter line (hole area 4% larger than diverter line). For the new hole and casing sizes planned, the maximum difference in area is 13% with the likely difference being 5%. 20 AAC 25.035 (h) (2) allows the Commission to approve a variance from the diverter requirements if ['00] the variance provides at least equally effective means of diverting flow away from the drill rig [H']' I recommend approval of Aurora's request based on the file review conducted. T~s approval is specifically for Kaloa #2. ~'^'~~ Tom Maunder, PE .. Sr. Petroleum Engineer April 14, 2004 G:\common\tommaunder\Well Information\By Subject\BOP-Diverter\Waivers\040414- note Kaloa #2 diverter line.doc - - -- .- 9r\~r,.::¡ I' ;;II! ¡ l ¡ \. ,'" \ ,¡ , '~, î fL.1\~l~r LJ lJù 'J 6 p\ r-[~ IIIII~ lliJu r-. r-' ~ ~ r- '7 1[,\ ·1 1"\ ¡qJ í! \" 'I' 1 r '\\ 'I" I"~ ,! íf\'¡,', '{ lA"" \ ¡ I /",) \ "\, '\ ¡ i, \ 'I' t~~Jr'1" \\ ù~,-l \ ~)Lu FRANK H. MURKOWSKI, GOVERNOR AI,ASIi& OIL Alft) GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 April 16, 2004 Mr. J. Edward Jones Executive Vice-President, Operations and Engineering Aurora Gas, LLC 1400 West Benson Blvd. Suite 410 Anchorage, AK 99503 Request for Waiver of Diverter Requirements at 20 AAC 25.035 (c)(l)(B) Kaloa #2 (pill 203-'071) Dear Mr. Jones: We have received your request for exception to the Diverter requirements at 20 AAC 25.035 (c) (l)(B) for the drilling of Kaloa #2. You have requested this exception due to decrease in the tubular and hole sizes planned for the well. 20 AAC 25.035 (c)(l)(B) requires that the drilled surface hole be equal to or less than the inside diameter of the diverter line. Providing a diverter line larger than the hole size prevents the diverter line from becoming a choke if a divert situation were to occur. As now planned, Aurora will set 11-7/8" conductor which will allow a maximum hole size of 10-5/8" to be drilled. It is planned to drill a 10-1/4" hole if such bits can be obtained. If the maximum hole size were drilled, the hole area would be 13% larger than the diverter line area. If 10-114" hole is drilled, the area difference is 4%. Aurora will be employing the same rig used during the last 2 seasons. The rig is equipped with the required pit monitoring equipment. Since the rig will have recently started up, an AOGCC Inspector will have witnessed the function testing of such equipment either on this well or one prior to it. Aurora's plans a minimum mud weight of 9.5 ppg with provisions to increase to 10 ppg depending on hole conditions. 20 AAC 25.035(h)(2) allows the Commission to approve a variance from the diverter requirements if [...] the variance provides at least equally effective means of diverting flow away from the drill rig [.. .]. -- -- Lone Creek #3 PTD 203-062 April 16, 2004 Page 2 of2 Your request to employ a 10" diverter line while drilling either 10-5/8" or 10-114" hole for Kaloa #2 is approved. This approval is specificall Kaloa #2. cc: Duane Vagen Fairweather E&P ee __ ~:Aurora Gas, LLC WWKI. aurorapower. com April 12, 2004 RECEIVED APR 1 8 2004 Alaska Oil & Gas Cons. Commission Anchorage Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Approval to Change Drilling Program Kaloa No.2 (pTD# 203-071) Dear Mr. Norman, Aurora Gas, LLC hereby submits an Application for Sundry Approval to change the well design covered by Permit to Drill #203-071. Aurora has modified its drilling program to reflect the following changes in wellbore geometry. Conductor: Original well design used 13-3/8" 54.5# K-55 welded. Will now use 11- 7/8" 71.8# USS limited service structural pipe with 0.582" wall thickness. The conductor will be drìven as orìginally permitted. Surface Casing: Original well design used 9- 5/8" 36# K-55 LT&C. Will now use 8 5/8" 32# Wildcat 50, ST &C. Hole size will be 10-5/8" (possibly 1O-~" if available) and original planned hole depth will be the same. Production Casing: Original well design used 7" 23# J-55 LT&C. Will now use 5-~" 17# J-55 LT&C. Hole size will be 7-7/8" and original permitted hole depth will be the same. All other aspects of the original approved program will remain the same. Based on the above information, Aurora is submitting a waiver request under separate cover to forgo drilling a pilot hole at surface as required in the orìginal approved PID. Pertinent information attached to this application includes the following: 1) Form 10-403 Sundry Application- Original and 1 copy 2) Casing analysis 3) Modified proposed wellbore schematic 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 , -- Page 2 Application for Sundry Approval Contd... If you have any questions or require additional information, please contact the undersigned at (713)977-5799 or Duane Vaagen at (907)258-3446. Sincerely, AURORA GAS, LLC . Edward Jones Executive Vice Presiden, Operations and Engineering enclosures cc: Duane Vaagen Andy Clifford \L . / L _ , ~.. '. ~ ~. \' _ \. ..'I. ~. \'- '\ \~. '-',,^~'Qc) <::>\&.c:. 7' S~u!(.'> ~ ~\'YR Q~ ~". \WC~\\\'C:!~ .. ~~\:I'SC.~ ~~'\ <:o.s\\"~ \Q:~~,,-œ. -\-~<: \\\ìIÞ'\:.a~'-~-\tJ\ ú.ppY-~\S '-\0 \~~ G-\J~'-_:/~- L-8ù S\Q;SJ<èb~~\¿~ ö"" b~",\. R<i: CD \ \ c- ~<L ~ \ ~Q \ So \J Q __-I" \ ~ '" s;. "'<:ò'\ \ ".!j-\"<é "'-' ~ _ '\ \" \, \'G- ~o.\~ \ (¿ 1'CC ~(rQ ~ci:c¿ ¡ ~ 0·-\ c:c, \ \0 ~se --\'0'\ G QQ~~~ ~\\ ì)-c.;\ "-:> .\'O.~ 0 C~\\--\cc, \ \)\-0 f(Cr:~ì' .~ \'ð¡~0 Gsb~ ~~ \n~<ëÜ.-\- ~'\ ..\-0 co~ç\,,'--i .\.-"G: \')~\~">+ ~ \'-.JQ ~ \=oc --I·~CL ßSjç;" a:J---<, \ ~ .I, \--<¿ ~\ c~ \ <'" \, R\ ~ E: ~ \0--\ - I-t (J ~ \L-sç ~ '\~·.<)û\~CCS a~ 'D()'Ç~~~ CÐ\\o~~Ç¿ ú. DC """\ ~ \--\ ''--- \-'Në IC>-t----,_:?- 0 \--\ ~":> <C ~ lú, ~e'S, þ. \\ \."c~':;~ ~~ -\ \-~~\~ ~. :'Ú.. .. \ \ -.\;\~. D'\'a þ'(:) c.~.'-~. .. ) cG-S\. \~' ~ . \. \ \ (. \. (~. ~)~ \--..c---- ~ <£ \' '(D ?'Lx -1·<'\0.s. s ",.(.Q, c~ cs,,-\- --\-û (_'" Œ ~t~ ::<\,E \ \ 'h \'1 \~CL \ \ (D ~~ \ ~VD '''' S. \~ \-\ \"", \(( Ú '->0 \~G \) \(ê' ~~'\'--( ç~c~ù \ ~ f\ 41 '1 ,. . ~___ í.-; )v ' /~ fc'\.)..>J·¡,.;;:J.:.>c "' -t... \ ( \ '''-\ ~. a L-f 1. Type of Request: ~ STATE OF ALASKA .. ~ Oil AND GAS CONSERVATION CO~ON APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 Operational shutdown U Plug Perforations 0 Perforate New Pool 0 4. Current Well Class: Suspend U Repair well 0 Pull Tubing 0 Perforate U Waiver U Stimulate 0 Time Extension 0 Re-enter Suspended Well 0 5. Permit to Drill Number: ~~/¡....\ {) /~ (¡ II X£. Annular Dispos. U ./ ^' other 0 Abandon U Alter casing 0 Change approved program 0 2. Operator Name: Aurora Gas, LLC 3. Address: 1400 West Benson Blvd, Suite 410 Anchorage, AK 99503 Development Stratigraphic o o Exploratory 0 Service 0 203-071 6. API Number: 50-283-20104-00 7. KB Elevation (ft): 9. Well Name and Number: 220.5' Kaloa NO.2 8. Property Designation: 10. Field/Pools(s): C-61393 Kaloa 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): rotal Depth :m (ft): r=.ffective Depth MD (ft): IEffective Depth TVD (ft): rlUgS (measured): IJUnk (measured): 0 0.0' P&A'd 0.0' P&A'd Surface NA Casing Length Size MD TVD Burst Collapse Structural Conductor 90' 117/8" 71.8# LSS 90 90 7270 psi 7190 psi Surface 620' 8 5/8" 32# We-50 620' 620' 3600 psi 2440 psi Intermediate Production 3700' 5.5" 17# J-55 3700' 3700' 4910 psi 5320 psi Liner Perforation Depth MD (ft): None Packers and SSSV Type: NIA 12. Attachments: Description Summary of Proposal U Detailed Operations Program 0 BOP Sketch 0 14. Estimated Date for perfOration Depth TVD (ft): None Tubing Size: NIA ITubing Grade: N/A Packers and SSSV MD (ft): NIA 13. Well Class after proposed work: Exploratory 0 Development 0 15. Well Status after proposed work: Oil 0 Gas 0 Plugged 0 WAG 0 GINJ 0 WINJ 0 ITubing MD (ft): NIA Well P&A'd: No I Suspended Service 0 Commencing Operations: 16. Verbal Approval: Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name n (' ~rd Jones Title Signature >J---/ ø$'Z'.d;~ Phone 713-977-5799 ¿/ V COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness 6/1/2004 Abandoned 0 WDSPL 0 Date: Contact J. Edward Jones Executive VP Operations I Engineering Date 4//2,/0( SUndry Number: 3 ¿JY- /;?- ~~ Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 other: 0,\ <S' ,,---~ \ Q ?\>\'CJ'-JC\\ S ~Q-'- .dO s-a '\ \ c\ \>\' \'[ RECEIVED APR 1 3 2004 ~ Alaska Oil & Gas Cons. Commission AnChora~e BY ORDER OF /L ~~ COMMISSIONER THE COMMISSION Yi INSTRUCTIONS ON REVERSE Date: Subm' in ~ lie! APR 2 1 'ìfHn¿ ~BFL ö\ "QJ1:>R' GINA L -- Well ID -- Kaloa No.2 11 7/S" Conductor Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1 .2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 11 7/8 USS Ltd. 71.80 Welded 95.00 (ft)MD 620.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 10.625 0.58 Fluid Properties: 95.00 (ft)TVD 620.00 (ft)TVD 7190.00 7270.00 1129.00 1858.00 1,129,000.00 * Tensile Limits 1,858,000.00 * Tensile Limits Material Weight ppg Gradient psi/ft 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg 9.20 13.00 0.86 15.8 8.94 16 17 8.95 0.478 psi/ft 0.676 psi/ft 0.822 psi/ft 0.465 psi/ft 0.832 psi/ft 0.884 0.110 0.465 55 0.55 -- -- Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 6,821.00 5,861.47 Maximum setting depth (ft) 15,724.23 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor (At proposed depth) Body Yield Safety Factor (At proposed depth) 165.52 In Air: = Jt Strength / (Wt ppf * set depth) 272.39 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 387. 19 Collapse Res / (Depth TVD . % Fluid Drop '(Mud Soup Grad - Gas Grad)) Collapse SF while cementing 212.48 Collapse Res / Depth TVD . (Cmt Grad - Soup Mud Grad) 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 for TO of next hole section (TVO) for MASP calculations 479.88 (Frac Grad - Gas Grad)' Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 15. 15 Tube burst rating / ASP Bottom Burst Safety Factor 15.24 (Int. Yld + Depth TVD . Seawater Grad) / ASP Summary of: 11 7/8 Safety Factors Body Yield 272.39 in air "Tensile" OK Joint Strength 165.52 in air "Tensile" OK Collapse 387.19 OK Collapse 212.48 while cementing OK Top Burst 15.15 OK Bottom Burst 15.24 OK -- WelllD Kaloa No.2 8 5/8" Suñace Casing Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 8 5/8" WC-50 32.00 STC 9 5/8" OD 620.00 (ft)MD 3750.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 7.796 0.352 Fluid Properties: Material -- 620.00 (ft)TVD 3750.00 (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 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg 13.00 9.80 0.80 15.8 8.94 17 17 8.95 0.676 psi/ft 0.510 psilft 0.822 psilft 0.465 psi/ft 0.884 psi/ft 0.884 0.110 0.465 55 0.55 - - Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 19,840.00 15,896.27 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) 17. 19 In Air: = Jt Strength / (Wt ppf * set depth) 23.03 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 20.13 Collapse Res / (Depth ìVD ' % Fluid Drop '(Mud Soup Grad - Gas Grad» Collapse SF while cementing 11.05 Collapse Res / Depth ìVD ' (Cmt Grad - Soup Mud Grad) 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 for TD of next hole section (TVD) for MASP calculations 2,902.50 (Frac Grad - Gas Grad)' Next Casing Set Depth ìVD MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 1.24 Tube burst rating / ASP Bottom Burst Safety Factor 1.34 (In!. Yld + Depth ìVD ' Seawater Grad) / ASP Summary of: 8 5/8" Safety Factors Body Yield 23.03 in air "Tensile" Joint Strength 17.19 in air "Tensile" Collapse 20.13 Collapse 11.05 while cementing Top Burst 1.24 Bottom Burst 1 .34 OK OK OK OK OK OK -- WelllD Kaloa No.2 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1 .5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1 .2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 51/2" J-55 17.00 LTC 3750.00 (ft)MD 3750.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 4.767 0.304 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg -- 51/2" Production Csg 3750.00 (ft)TVD 3750.00 (ft)TVD 4910.00 5320.00 247.00 329.00 247,000.00 * Tensile Limits 329,000.00 * Tensile Limits Weight ppg Gradient psi/ft 9.80 0.510 psi/ft 9.80 0.510 psi/ft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 17 0.884 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 - -- Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 63,750.00 54,197.25 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) 3.87 In Air: = Jt Strength I (Wt ppf * set depth) 5.16 In Air: = Body Yld 1 (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 6.70 Collapse Res I (Depth TVD " % Fluid Drop "(Mud Soup Grad - Gas Grad» Collapse SF while cementing 3.68 Collapse Res! Depth TVD " (Cmt Grad - Soup Mud Grad) No lost CirculationlEvacuation occurs Burst Calculations: Assume seawater backup gradient. .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TD of next hole section (TVD) for ASP calculations 2,902.50 (Frac Grad - Gas Grad)" Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 1.83 Tube burst rating! ASP Bottom Burst Safety Factor 2.43 (Int. Yld + Depth TVD " Seawater Grad) I ASP Summary of: 5 1/2" Safety Factors Body Yield 5.16 in air "Tensile" OK Joint Strength 3.87 in air "Tensile" OK Collapse 6.70 OK Collapse 3.68 while cementing OK Top Burst 1.83 OK Bottom Burst 2.43 OK - 27/8" 6.5# 8 Rd J·55 Tubing to 3100' Kaloa No.2 Proposed Configuration Drill 10 5/8" Hole 2 7/8" X 5 W' annulus to be displaced over to inhibited packer fluid wI diesel freeze protect at surface following completion. Top Beluga - 700' Top Tyonek - 2000' 27/8" 6.5# 8 Rd J-55 Tubing 3100' - 3200 Tyonek Peñorations from - 3200' - 3600'. Exact Intervals to be determined by Open hole logging. Drill 7 7/8" Hole PBTD at 3665' Aurora Gas, LLC Summer 2004 Well Program Rev. 3.1 ~ ~r ~, :~ q ë .~ I ~¡' :-;-;' ~ t ¡,: f1 I w, - 11 7/8" 71.8# Structural Conductor to be driven to 90' 8 5/8" 32# WC-50 STC Suñace Casing set at 620' Cement wI 14.5 ppg Gas-Block enhanced cement (- 35 bbls cmt @ Sliding Sleeve 1 joint above packer @ 3070' wI 2.313" X-Profile for landing plug 5 %" Retrievable type Seal-bore Production Packer 90' above upper perforation -3100' 2.313" XN-ProfiIe 1 Joint below packer at - 3130' Sand Exclusion Screen across all peñorations. All Screen sized to 5 W' casing. - 8 Jts Total. 5 W' 17# LTC J·55 Casing to 3700' MD (TVD) Cmtd wI 48 bb113.5 ppg Lead at 20 % and 72 bbls 15.8 ppg Tail at 20%(Top of Tail to extend to 1500' MD) 4/5/2004 .e ._ 'Aurora Gas, LLC WMv.aurorapower.com April 12, 2004 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7fu Ave., Suite 100 Anchorage, Alaska 99501 Re: Request for waiver of requirement to drill a pilot hole due to diverter outlet size versus hole size difference as stipulated in 20 AAC 25.035(c)(I)(B) as required for drilling ofKaloa No.2 (PTD# 203-071). Dear Mr. Norman, Aurora Gas, LLC has submitted under separate cover, a Sundry Application reflecting proposed changes in the wellbore geometry of Kaloa No.2, PTD # 203-071. Based on the change in well design, Aurora at this time requests a waiver to the requirement that a pilot hole be drilled, a requirement indicated in 20 AAC 25.035 (c)(1)(A & B) which states that the diverter outlet and line must be at least 16 inches in diameter or as large or larger than the diameter of the hole being drilled. The basis for the request is indicated below. Aurora will now use 11-7/8",0.582" wall, 71.8# LSS with a drift ill of 10.625" for a conductor. The original PTD was approved using a 13-3/8" conductor. The drilling program now calls for drilling out with a 10-5/8" or smaller ill bit. The diverter that Aurora intends to use has a 10" gate valve and flow line. Aurora intends to use a 1 O-~" or 10-5/8" bit, depending upon availabilities, to drill the surface hole. (The largest possible surface hole size will be 1 0-5/8" in diameter, due to constraints induced by the ill of the 11-7/8" conductor). Aurora is confident it can safely drill using the diverter / hole size configuration requested for the following reasons: 1. Aurora feels that due to the minimal difference between wellbore diameter and diverter line size, the surface hole section can be safely drilled without benefit of drilling a pilot hole first as was specified in the original approved PTD. The actual cross sectional flow area difference between OR and diverter line size is ~10 in2 (13% larger) with a 10 5/8" bit and ~4 in2 (5 % larger) using the 10 W' bit proposed. 2. Good pressure information is available in wen records from nearby offset wens Albert Kaloa No. 1 and Simpco Kaloa No. I to correlate pressure trends. 3. Good understanding by rig and crew of drilling conditions which might be encountered. 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 ee .e Page 2 Kaloa NO.2 Diverter Waiver Contd... In retrospect, the original well-bore design was permitted for a 12-1/4" surface hole which required the drilling of a pilot hole. The cross-sectional flow area difference between the 12-W' hole and 10" diverter line was -39.3 in2 (50% larger). . If you have any questions or require additional information, please contact the undersigned at (713)977-5799 or Duane Vaagen at (907)258-3446. Sincerely, AURORA GAS, LLC J:~ Executive Vice President, Operations and Engineering cc: Duane Vaagen Andy Clifford .. ~I " ~ ~ 6 f(ììn s @ ~ 1:\ Cc2 -:1/~ æJ L uti b- ~ UlJ J U=;J ~ iJáu æ) _'0. J'u AJ,A.SIiA OIL AND GAS CONSERVATION COMMISSION / J. Edward Jones Vice President Aurora Gas, LLC 1029 West 3rd Ave. Ste. 220 Anchorage, AK 99501 .. / I ,I / í I I / f FRANK H. MURKOWSKI, GOVERNOR 333 W. ]T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kaloa #2 Aurora Gas, LLC Pennit No: 203-071 Surface Location: 987' FNL, 1669' FEL, S26, T11N, R12W, SM Bottomhole Location: 987' FNL, 1669' FEL, S26, T11N, R12W, SM Dear Mr. Jones: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill does not exempt you tram obtaining additional pennits or approvals required by law trom other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). BY ORDER OJ" THE COMMISSION DATED this~ day of December, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. .' Hole Driven 121/4" 8112" Weight 54.5 36 23# STATE OF ALASKA AI AAAlL AND GAS CONSERVATION .rMSION -.r-. PERMIT TO DRILL . 20 AAC 25.005 [ ] Redrill 1b. Type of well [ ] Service [X] Development Gas [ ] Single Zone [ ] Deepen [ J Exploratory [ ] Stratigraphic Test [ ] Development Oil Aurora Gas LLC. 5. Datum Elevation (OF or KB) 10. Field and Pool 36' AMSL (OF) Kaloa Gas Field 6. Property Designation C-61393 7. Unit or Property Name Kaloa 8. Well Number Kaloa No.2 -9. Approximate spud date 1-Jul-03 14. Number of acres in property 15. Proposed depth (MD and TVD) 3435 3750 117. Anticipated pressure {see 20 MC 25.035 (e) (2)} Maximum surface 1238 pslg, At total depth (TVD) Setting Depth Top Bottom MD TVD MD TVD o 0 90' 90' o 0 620' 620' o 0 3700' 3700' ~(;)) 1a. Type of work [X] Drill [ ] Re-Entry 2. Name of Operator [ X] Multiple Zone 1029 West Third Ave. Suite 220 Anchorage, Alaska 99501 4. Location of well at surface ASPY = 2567105, ASPX = 260805 ASPZ4 "As Staked 987' FNL, 1669' FEL S26, T11N, R12W SM At top of productive interval Same 3. Address 11. Type Bond (See 20 Me 25.025) letter of Credit NZS 429815 Number At total depth Same Amount $200,000.00 12. Distance to nearest property line 1002' 16. To be completed for deviated wells Kick Off Depth 18. Casing Program Size Casing 13 318" 9 5/8" /13. Distance to nearest well 120' from P&A'd PanAm Kaloa NO.1 Maximum Hole Angle 1650pslg 7" Specifications Grade Coupling K-55 Welded K-55 LTC J-5S LTC Length 90' 620' 3700' Quantity of Cement (include stage data) No cement. driven 40 bbls 15.8 ppg "G" w/15% OH Excess 42 bbls 12.5 ppg "G" Lead w/15% OH Excess & 57 bbls 15.8 ppg "G" Tail w/15% OH Excess 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical feet feet feet feet Plugs (measured) Junk (measured) Casing Length SiZe Cemented MD TVD Structural Conductor Surface Intermediate Production Liner RECEIVED APR 0 9 2003 Alaska Oil & Gas Cons. Commission Anchorage Perforation depth: measured true vertical [ X] Filing Fee [X] Property Plat [ X] BOP Sketch [ X] Diverter Sketch [ X] Drilling Program [ X] Drilling Fluid Program [ ] Time vs Depth Plot [ ] Refraction Analysis [ ] Seabed Report [ ] 20AAC25.050 Req. Contact Engineer Name/Number: J. Edward Jones 1713-977-5799 Prepared By Name/Number: Duane H. Vaagen /258-3446 21. ~~~~eb rti~~t the forego in is tru and correct to the ~t of my kn?)edge C/Æ ?£?? Title 1/ /~_ r'rr:rl d//ír Date '1/7 /¿J.3 Commission Use Only Permit u er 2Ds-ort I umber sv- ?t:.?""2_ ?/ìIO//~~ I ~pprov~~~e 1 Seecoverlett~r ?-D.::;:J ~ f· ~ ¡ ,11,", ~ ') for other reqUirement",. Conditions of Approval: Samples Required: [ ] Yes Þá~o .T /Mu Log Required p(Yes ~0~9 Hydrogen Sulfide Measures: [ ] Yes :Þ{No Directional Survey Req'd . [ ] Yes Wo~ Required Working Pressure for BOPE: [] 2M, -[] 3M, [] 5M, [J 10M, [] 15M '* 1ftc.( '~A. .f¡'c-I'\. ~!J other: ~'ë::f::)a)2 ~ \ \$'ù,\7 -\-~ ~ ~J0f7 :;/.)~. .JÞ Original Signed BY by order of ~. Sarah Palin Commissioner the commission Date / JIIS)() '7 Submit fn'T plicate 20. Attachments Approved By Form 10-401 Rev. 12-01-85 OP . Aurora Gas, LLC. e . Kaloa.. 2 Drilling Program Drilling Program: Kaloa No.2 10. File and insure all necessary pennits and applications are in place. Install drive shoe and drive (new) 13 3/8" 54.5 #/ft, K-55 conductor to ~ +90 feet. Weld on 13 5/8" starter head. Notify AOGCC and pertinent agencies when ready to start drilling operations. Rig up diverter (see attached diagram) and mud loggers. Test and calibrate all PVT and gas sensor equipment. ., Prepare mud system, weight up to ~9.5 ppg. Drill 8 1/2" hole to ~620 ft, using 8 1/2" mill-tooth bit with 6 %" stabilized BHA. Watch for gas in shallow coals and sands. Increase mud weight as needed to 9.8 - 10 ppg. POOH, LD 8 Yz" bit, PU 12 W' hole opener, open hole to 620 ft. Condition hole for running 95/8" surface casing, POOH, LD 12 W' BHA. Run and cement (new) 9 5/8" 36 #/ft, K-55 LTC surface casing at 620 ft and cement to surface. Shoe joint connection at shoe and float collar must be Baker- Locked. Cementing will be single stage with float collar and shoe installed using 15.8 ppg cement slurry. RU and test II" 3M BOP stack and 5M choke manifold (see attached diagram). Test stack and surface equipment to 3000 psi. Pressure test casing to 2000 psi. or as required on approved pennit. PU 8 12" mill-tooth bit, RIH with 6 %" DC's and 3 Yz" DP to float collar. Drill out float equipment and shoe. Drill ~20' OH. Pull back into shoe and perfonn FIT with MWE, record results. Condition and circulate mud system, build mud weight to 9.8 ppg, and be prepared to weight up more if required. Do not exceed fracture gradient detennined in step 1O! Proceed to drill ahead, 8 Yz" 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. Drill to TD at 3750 ft maximum, depending on lithology encountered. Short trip and condition hole as needed for running wireline logs. POOH, rack back drillstring and RU wireline BOP's and lubricator and logging tools. Log cased hole section w/gamma ray sensor, Log OH section with logging suite to be decided. RD wireline, RIH with drilling BHA as before to TD. Circulate and condition hole for running casing. INSURE all cementing equipment, casing accessories, and casing running equipment is on location and functional. POOH, LD BHA, rack back DP. RU casing equipment I crew, make up shoe joint with shoe and float collar, baker- locking both to joint during make-up. Install 7" pipe rams for casing. RIH with (new) 7" 23 #/ft J-55 casing, installing centralizers per attached program. Run casing to ~3700 ft, or as detennined by OH logs. Keep pipe moving when casing is at TD and while waiting for cementers to get hooked up. /' RU cementers, cement per attached cementing program from TD back to surface. A 12.5 ppg lead and 15.8 ppg tail cement system will be used. While pumping 1. 2. 3. 4. 5. 6. 7. 8. 9. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. Aurora Gas LLC. Rev. 1.4 Page 10/6 4-April-2003 Aurora Gas, LLC. .. !.. 2 Drilling Program cement, reciprocate pipe a minimum of 20 ft until displacement is finished. Land casing and WOC. 21. RD cementers, check annulus and casing for pressure. Nipple down stack and cut casmg. 22. 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 casing scraper and RIB 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 KCl. POOH LD DP and casing scraper. 23. RU lubricator for wireline work. Change out 3 W' pipe rams with rams for 27/8" work string. Pressure test all. 24. PU wire1ine BOP's, lubricator and perforating guns, RIB to depth as determined from OH logs and perforate. Watch for pressures in casing after shooting. POOH, LD perf gun. 25. RU and RIB with test packer on workstring. Connect to surface flow test equipment. Swab in well for flow test, record results. Kill well. 26. Repeat steps 21 and 22 until sufficient intervals have been penetrated for production. 27. POOH, RD wireline. Prepare completion assembly. 28. Pick up and assemble permanent 1 retrievable type packer wlsealbore assembly, millout extension, profile nipple, crossovers and sand exclusion screen assembly. Packer is to be 75ft minimum above top most screen. RIB and hang off (depth to be determined by depth of perforations). POOH with workstring, RIB with production tubing, space out and stab into packer, hang off in tubing head and lock down. Install blanking plug in profile nipple, Pressure test tubing to 2000 psI. 29. Install BPV at surface, nipple down and remove BOP stack. Install wellhead tree. RD and remove all rig equipment. 30. Prepare site for well testing and surface production facilities. 31. File completion reports with proper agencies. Site Access: Ka10a No.2 will be accessible via existing gravel roads built in the 1960's for drilling the nearby Pan Am Kaloa No. 1 and the Simpco Kaloa No. 1 wells. All major equipment and supplies will be barged across the Cook Inlet from the OSK dock in Nikiski to Tyonek for staging as required. Equipment will be staged from either Tyonek Contractors yard or one of several existing well sites Aurora is currently re-developing. Personnel can be flown into either the nearby Shirleyville airstrip, a three mile drive, or the Tyonek airstrip which is approximately 7.5 miles away. An alternate site for embarkation will be the airstrip at Beluga, approximately 10 miles away. Crews will be billeted at either Shirleyville or Beluga, pending room availability. All sites are interconnected with an extensive road system for transport via vehicle. Rig: Aurora Well Service, Rig No. 1 (A WS 1) will be used to drill the Kaloa No.2 well. A WS 1 has been used previously for work on wells in the Nicolai Creek Field. The pits, BOP system and mud equipment configuration will be similar to that used for previous work. Aurora Gas LLC. Rev. 1.4 Page 2 016 4-April-2003 Aurora Gas, LLC. · . !a.. 2 Drilling Program Pressure Considerations: Based on test pressure information from the nearby Pan Am Kaloa No. 1 well, the following were maximum pressures recorded prior to production for fuel gas on the Spark Platform and for the Village of Tyonek. A maximum SIP pressure at surface of 1450 psi and a shut in BHP of 1580 psi were recorded for the production zone from 3516' - 3583'. This equates to a pressure gradient of .44 psi/ft, or mud weight equivalent of 8.46 ppg. This will require well drilling and completion operations to use fluids weighted from 9.0 - 9.2 ppg to maintain well control at final depth. Final surface pressures recorded after production and prior to plugging and abandonment indicated pressures ranging from 1350 - 1400 psi. Survey Program: The Kaloa No.2 well will be drilled as a vertical well. Wellbore surveys will be obtained at 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). Drilling Fluids: The drilling fluids are being furnished by MI Drilling Fluids. MI has extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor mud rheology and make recommendations. Attached is a copy ofMI's mud program. Drillin2 Fluid Properties While Drilling Surface 12 ¥,¡" Hole Section to 620': Beluga Formation Base Fluid 5% KCL Density 9.8 - 10 ppg PV 22-30 yP 20-30 API Filtrate < 10 Total Solids 15 - 25 % Gel & Polymer mud system Drillin2: Fluid Properties While Drillin2: 8 ~"Hole Section to 3750': Beluga and Tyonek Formations Base Fluid 5% KCL Density 9.0 - 9.2 ppg , PV 22 - 30 yP 20-30 API Filtrate < 10 Total Solids 15 - 25 % Polymer mud system Drillin2: Fluid Handlin2 System: Shale Shaker, Desilter, Centrifuge, Ditch Magnets, PVT monitors Aurora Gas LLC. Rev. 1.4 Page 3 016 4-April-2003 Aurora Gas, LLC· . -. Kaloa o. 2 Drilling Program 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 13 3/8" 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. Kaloa No.2. 133/8" Conductor Analvsis and Cementin!! Pro!!ram The conductor for the Kaloa No.2 will be driven to - 90' or refusal. Joints will be welded and a drive shoe will be welded to the bottom joint. No cementing is required. Please see attached Conductor Analysis with specifications. Kaloa No.2. 95/8" Surface Casin!! Analvsis and Cementin!! Provram The 9 5/8" surface casing will be cemented in fully from the proposed set depth of620' to surface with a 15.8 ppg "G" cement system. Cement System Primary Type Cement "G" Weight (ppg) 15.8 Volume (â¿ % Excess 40 bbls @ 15% The cement system may utilize a Gas-Block type additive to minimize potential for gas entrainment and or channeling. Please see attached 9518" surface casing analysis. Kaloa No.2. 7" Production Casin!! Cementine Proeram The 7" production casing will be cemented in fully from proposed set depth of3700' to surface. A 12.5 ppg lead "G" cement followed with a 15.8 ppg "G" tail cement system will be used. This program is designed to insure the intended perforating / production intervals up to 1500' are isolated with 15.8 ppg "G" cement. Cement System Lead Tail Type Cement "G" "G" Weight (ppg) 12.5 15.8 Volume @ % Excess 42 bbls @ 15% OR 57 bbls @ 15% OR Please see attached 7" production casing analysis. Aurora Gas LLC. Rev. 1.4 Page 4 016 4-April-2003 Aurora Gas, Uc. .. . KaZoa.. 2 Drilling Program Drillim! Hazards: Drilling in the South Central Region of Alaska offers its own challenges. Common known hazards are as follows: Shallow gas: Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record ofH2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level, the shale shaker and in the cellar . Coal Seams: The Cook Inlet region is rich in coal seams, interbedded between the sands, gravels and shale's that make up the Beluga and Tyonek fonnations. Drilling into a coal seam will appear to be a drilling break when drilled with a tri- cone bit. The major hazard of drilling into a coal seam without observing the proper response, is the risk of stuck pipe. The proper course of action for preventing stuck pipe is two-fold. First, prior to drilling, insure the drilling fluid system is up to par, per recommendations from the on-site mud engineer. The second step to successfully drilling through coals in the Cook Inlet area is to not get greedy when coals are encountered. When a coal has been encountered, pull back above coal after drilling into it, and circulate, allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason it is critical to maintaìn the proper weight and viscosity of your drilling fluid to properly remove the coals drilled up, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the Mud Engineer. Nearby Well's: There are (2) wells within Yí mile of the proposed Kaloa No.2. These wells are the Pan-Am Kaloa No.1 which is P&A'd, and the Simpco Kaloa No.1, which is suspended. Neither well presents a proximity problem for drilling operations. 1l1/:x.A I ß !t?&;, :If I ;;. t¡J-/i-L ;2.D ~ /1> Other: Sticky bentonitic clays, boulders, lost returns & differential sticking wi overbalanced muds (+ 12.5ppg) and gas influx while cementing Aurora Gas LLe. Rev. 1.4 Page 5 016 4-April-2003 Aurora Gas, LLC. · . !a.. 2 Drilling Program Kaloa No. 2 Summary of Drillina Hazards POST THIS NOTICE IN DOGHOUSE ..¡ There is potential for abnormal pressured shallow gas. ..¡ There is potential for stuck pipe in coals encountered while drilling from surface to TO. Be extra vigilant while performing hole opener - run. ..¡ There is no H2S risk anticipated for this well. ..¡ 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 "KALOA No.2" WELL PROGRAM FOR ADDITIONAL INFORMATION. Aurora Gas LLC Rev. 1.4 Page 6016 4-April-2003 ·e WelllD -- Kaloa No. 2 13 3/8" Conductor 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 .2 Bottom Burst 1 .2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 13 3/8" J-55 54.50 Welded 95.00 (ft)MD 620.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 12.459 0.38 Fluid Properties: Material 95.00 (ft)TVD 620.00 (ft)TVD 1130.00 2730.00 514.00 853.00 514,000.00 * Tensile Limits 853,000.00 * Tensile Limits Weight ppg Gradient psi/ft 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg % Fluid Drop for Collapse Calculation (Enter #). 9.20 10.00 0.86 15.8 8.94 16 17 8.95 0.478 psi/ft 0.520 psi/ft 0.822 psi/ft 0.465 psi/ft 0.832 psi/ft 0.884 0.110 0.465 55 0.55 '·e -- Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 5,177.50 4,449.17 Maximum setting depth (ft) 9,431.19 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 99.28 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 164.75 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 60.85 Collapse Res / (Depth TVD ' % Fluid Drop '(Mud Soup Grad· Gas Grad» Collapse SF while cementing 33.39 Collapse Res / Depth TVD ' (Cmt Grad - Soup Mud Grad) 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 for TD of next hole section (TVD) for MASP calculations 479.88 (Frac Grad - Gas Grad)' Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 5.69 Tube burst rating / ASP Bottom Burst Safety Factor 5. 78 (Int. Yld + Depth TVD ' Seawater Grad) / ASP Summary of: 13 3/8" Safety Factors Body Yield 99.28 in air "Tensile" Joint Strength 164.75 in air "Tensile" Collapse 60.85 Collapse 33.39 while cementing Top Burst 5.69 Bottom Burst 5.78 OK OK OK OK OK OK ·e ee WelllD Kaloa No. 2 9 5/8" Surface Casing Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1 .5 Collapse While Cementing 1 .5 T~~~ 12 Bottom Burst 1 .2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 9 5/8" J-55 36.00 LTC 620.00 (ft)MD 3700.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 8.765 0.352 Fluid Properties: Material 620.00 (ft)TVD 3700.00 (ft)TVD 2020.00 3520.00 453.00 564.00 453,000.00 * Tensile Limits 564,000.00 * Tensile Limits Weight ppg Gradient psi/ft 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg % Fluid Drop for Collapse Calculation (Enter #). 10.00 9.50 0.85 15.8 8.94 17 17 8.95 0.520 psi/ft 0.494 psi/ft 0.822 psi/ft 0.465 psi/ft 0.884 psi/ft 0.884 0.110 0.465 55 0.55 -e ee Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 22,320.00 18,907.16 Maximum setting depth (ft) 12,583.33 In Air: = Jt Strength / Wt.ppf . Joint Strength Safety Factor 20.30 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 25.27 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 16.67 Collapse Res I (Depth TVD ' % Fluid Drop '(Mud Soup Grad - Gas Grad» Collapse SF while cementing 9. 15 Collapse Res I Depth TVD ' (Cmt Grad - Soup Mud Grad) 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 for TD of next hole section (TVD) for MASP calculations 2,863.80 (Frac Grad - Gas Grad)' Next Casing Set Depth TVD MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 1.23 Tube burst rating I ASP Bottom Burst Safety Factor 1.33 (Int. Yld + Depth TVD ' Seawater Grad) I ASP Summary of: 9 5/8" Safety Factors Body Yield 20.30 in air "Tensile" Joint Strength 25.27 in air "Tensile" Collapse 16.67 Collapse 9.15 while cementing Top Burst 1.23 Bottom Burst 1 .33 OK OK OK OK OK OK ·e WelllD Kaloa No. 2 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1 .5 Collapse While Cementing 1.5 Top Burst 1.2 . Bottom Burst 1 .2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 7" J-55 23.00 LTC 3700.00 (ft)MD 3700.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 6.241 0.317 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg % Fluid Drop for.Collapse Calculation(Enter#). .- 7" Production Casing 3700.00 (ft)TVD 3700.00 (ft)TVD 3270.00 4360.00 313.00 366.00 313,000.00 * Tensile Limits 366,000.00 * Tensile Limits Weight ppg Gradient psilft 9.80 0.510 psi/ft 9.80 0.510 psi/ft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 17 0.884 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 ee Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) Maximum setting depth (ft) Joint Strength Safety Factor Body Yield Safety Factor Collapse Calculations: Collapse Safety Factor Collapse SF while cementing Burst Calculations: MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor Bottom Burst Safety Factor Summary of: Body Yield Joint Strength Collapse Collapse Top Burst Bottom Burst 85,100.00 72,348.01 e. 13,608.70 In Air: = Jt Strength / Wt.ppf 3.68 In Air: = Jt Strength / (Wt ppf * set depth) 4.30 In Air: = Body Yld / (Wt ppf * set depth 4.52 Collapse Res / (Depth TVD ' % Fluid Drop '(Mud B-up Grad - Gas Grad» 2.48 Collapse Res / Depth TVD ' (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Assume seawater backup gradient, .465 psilf/ for burst design purposes Assume worst case by using anticipated frac gradient for TO of next hole section (TVO) for ASP calculations 2,863.80 (Frac Grad - Gas Grad)' Next Casing Set Depth (TVD) 1.52 Tube burst rating / ASP 2. 12 (Int. Yld + Depth TVD ' Seawater Grad) / ASP 7" Safety Factors 3.68 in air "Tensile" 4.30 in air "Tensile" 4.52 2.48 while cementing 1.52 2.12 OK OK OK OK OK OK -e Well ID -. Kaloa No.2 13 3/8" Conductor Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 13 3/8" J-55 54.50 Welded 95.00 (ft)MD 620.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 12.459 0.38 Fluid Properties: Material 95.00 (ft)TVD 620.00 (ft)TVD 1130.00 2730.00 514.00 853.00 514,000.00 * Tensile Limits 853,000.00 * Tensile Limits Weight ppg Gradient psi/ft 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg % Fluid Drop .forCollap$e Calculation ti:;nter#). 9.20 10.00 0.86 15.8 8.94 16 17 8.95 0.4 78 psi/ft 0.520 psi/ft 0.822 psi/ft 0.465 psi/ft 0.832 psi/ft 0.884 0.110 0.465 55 0.55 -- -. Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 5,177.50 4,449.17 Maximum setting depth (ft) 9,431.19 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 99.28 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 164.75 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 60.85 Collapse Res / (Depth TVD" % Fluid Drop "(Mud Soup Grad - Gas Grad)) Collapse SF while cementing 33.39 Collapse Res / Depth TVD" (Cmt Grad - Soup Mud Grad) 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 for TD of next hole section (TVD) for MASP calculations 479.88 (Frac Grad - Gas Grad)" Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 5.69 Tube burst rating / ASP Bottom Burst Safety Factor 5.78 (Inl. Yld + Depth TVD " Seawater Grad) / ASP Summary of: 133/8" Safety Factors Body Yield 99.28 in air "Tensile" Joint Strength 164.75 in air "Tensile" Collapse 60.85 Collapse 33.39 while cementing Top Burst 5.69 Bottom Burst 5.78 OK OK OK OK OK OK -e -. Well ID Kaloa No.2 9 5/8" Surface Casing Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1 .5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 95/8" J-55 36.00 LTC 620.00 (ft)MD 3700.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 8.765 0.352 Fluid Properties: Material 620.00 (ft)TVD 3700.00 (ft)TVD 2020.00 3520.00 453.00 564.00 453,000.00 * Tensile Limits 564,000.00 * Tensile Limits Weight ppg Gradient psi/ft 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg % Fluid Drop for Collapse Calculation (Enter #). 10.00 9.50 0.85 15.8 8.94 17 17 8.95 0.520 psi/ft 0.494 psi/ft 0.822 psi/ft 0.465 psi/ft 0.884 psi/ft 0.884 0.110 0.465 55 0.55 e. e. Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 22,320.00 18,907.16 Maximum setting depth (ft) 12,583.33 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 20.30 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 25.27 In Air: = Body Yld I (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 16.67 Collapse Res I (Depth TVD " % Fluid Drop "(Mud B-up Grad - Gas Grad» Collapse SF while cementing 9. 15 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 for TO of next hole section (TVD) for MASP calculations 2,863.80 (Frac Grad - Gas Grad)" Next Casing Set Depth TVD MASP (Maximum Anticipated SUfface Pressure) Top Burst Safety Factor 1.23 Tube burst rating I ASP Bottom Burst Safety Factor 1.33 (Int. Yld + Depth TVD " Seawater Grad) I ASP Summary of: 9 5/811 Safety Factors Body Yield 20.30 in air "Tensile" Joint Strength 25.27 in air "Tensile" Collapse 16.67 Collapse 9.15 while cementing Top Burst 1.23 Bottom Burst 1.33 OK OK OK OK OK OK .0111 ·e WelllD Kaloa No.2 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 COllapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 7" J-55 23.00 LTC 3700.00 (ft)MD 3700.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 6.241 0.317 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 Gas Gradient (psi/ft) Mud Backup Gradient ppg % Fluid Dropforyollapse CalcLJlation (Enter #). -e 7" Production Casing 3700.00 (ft)TVD 3700.00 (ft)TVD 3270.00 4360.00 313.00 366.00 313,000.00 * Tensile Limits 366,000.00 * Tensile Limits Weight ppg Gradient psi/ft 9.80 0.510 psi/ft 9.80 0.510 psi/ft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 17 0.884 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 ·e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) Maximum setting depth (ft) Joint Strength Safety Factor Body Yield Safety Factor Collapse Calculations: Collapse Safety Factor Collapse SF while cementing Burst Calculations: MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor Bottom Burst Safety Factor Summary of: Body Yield Joint Strength Collapse Collapse Top Burst Bottom Burst 85,100.00 72,348.01 -. 13,608.70 In Air: = Jt Strength / Wt.ppf 3.68 In Air: = Jt Strength / (Wt ppf * set depth) 4.30 In Air: = Body Yld / (Wt ppf * set depth 4.52 Collapse Res / (Depth TVD " % Fluid Drop "(Mud B-up Grad - Gas Grad)) 2.48 Collapse Res / Depth TVD " (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TO of next hole section (TVO) for ASP calculations 2,863.80 (Frac Grad - Gas Grad)" Next Casing Set Depth (TVD) 1.52 Tube burst rating / ASP 2.12 (In!. Yld + Depth TVD " Seawater Grad) I ASP 7" Safety Factors 3.68 in air "Tensile" 4.30 in air "Tensile" 4.52 2.48 while cementing 1.52 2.12 OK OK OK OK OK OK e_ -'aloa No.2 Albert Kaloa Gas Field 27/8" 6.5# J-55 8rd Modified Coupling '" Production Tubing 133/8" 54.5# K-55 Conductor Driven 80 - 90' 121/4" Hole Top Beluga - 700' 9 5/8" 36#J-55 620' MD (TVD) Packer Fluid: 02 Inhibited KCL Fluid above Pkr. Top Tyonek -2000' 8 1/2" Hole Tyonek Production Perfs -3200 - 3600'. Exact Intervals to be determined when logging. H J î 1-.J k~ .;;;1 "'* :r'<;~ '''.'/iiIi ì,.~ o Proposed D Present Condition Will Drill 8 1/2" Pilot Hole to 620' MD and then run a 12 1/4" hole opener prior to running 9 5/8" casing. 2.31 ID X-Nipple 1 Jt above packer 7" Permanent I Retrievable Packer W I sealbore assembly 2.13 ID X-Nipple 1 Jt below packer 3" Tubing Spacer w/XO's between packer and Screens Sand Exclusion Screen across Perforations. Type and size to be determined. ~ l¡:i ~\:j'".~ ~ r>,0y- i 7" 23# J-55 LTC l' @ 3700' MD (TVD) Cemented to Surface 8 1/2" Hole toTD @ 3750' MD (3750' TVD) Kaloa No.2 Fairweather E&P Services, Inc. I Rev. 03 DHV 05-Feb-2003 DRAWING NOT TO SCALE Aurora Well~ce Rig No.1: Proposed 3M ep Configuration e e Fill Up line r:=:::; =====s flow line to pits / ~ 3M Schaffer Annular Preventer c Pipe Rams sized "I to work string. ---1 11" 3M Double Gate wI 3/12" pipe ~ rams installed. Blind Rams . . /3" 5M Manual Valve (Choke Lme) ~.. .----- 3" 5M Hydraulic Valve ~ (Choke line) I ~ 2" 3M Manual Valves On Wellhead 11" 3M Mud Cross C 3" SM Manual Valve (Kill line) ~ 3" 5M Hydraulic Valve ~.~ ~ (Kill Line) ñ~ Fluid flow direction while reverse circulating 11-X3M ~ Braden Head 95/8" Casing ~ £ . 13 3/8" Conductor Aurora Well Service BOP Fairweather E&P Services, Inc. Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale J Aurora Well Se. Jüg No.1 Proposed Choke / . ~nifold Configuration All valves are 3" rat~t 5000 psi. . Inlet from BOP Choke Line ~'.~'~ Inlet from Power Swivel (Reverse Circulation Mode) ~ 2" 5M Rated Valves Hydraulic Remote Activated choke -~.:--.::' , -':" :ßO& . --~,'" 'c" n_ .-' ~.- 3" 5M Rated Valves Manual Choke 3" 5M Rated Valves .. ~ "'~~"-:~:-:. ,." ....... -, .- '-, ..,~- fl·.æ.·ll, - .- ~.~ ~ 2'" 5M Rated Valves I Aurora Well Service Choke Manifold I Fairweather E&P Services, Inc. Output to Pits J -'" '" '::,;):1 ID +~d Flare Line to Open Fjaf~'Pft =ID :....,,:~.---::...- .J To Gas Buster "Atmospheric Degasser" Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale · Aurora well'rvice Rig No.1: Fill Line Bell Nipple f I Hydraulically Operated 10" Knife Gate Valve \.. 10" Diverter Vent Line l Aurora Well Service Diverter e-- I:: E ...!§ E Fairweather E&P Services, Inc. I -. Proposed Surface Diverter System Flow Line to Pits ~ 1 I 13-518", 5000 psi WP Annular Preventer ~ 13-518", 5M Drilling Spool I Mud Cross 13 3/8" Conductor Pipe with 13-518", 5000 psi WP Flange welded on top Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale · """'~'\'" e .;... ~ OF AI.. " .: ~~··"·"·····1~ " -,.~.., .)f: ,; _ -J' ·or fill * ....4911:l .... * ~ fill. ... . .. . .. . .. . . .. .. .. .. . . .. . .. . .. . . , fill , " -- ,................................... fill , ~ ··oM. SCOTT McLANE::!: fill ~ ....' . - I, \I). ...... 4928-5 ...... .: , ~ .... ....~.£>- .~ ~...... ,,"'-'" t . ~ .....1:55 I ~ ........ a.""",.... PROTRACTED SECTION 26 TOWNSHIP II NORTH RANGE 12 WEST SEWARD MERIDIAN ALASKA e. 523 524 S26 525 -1 Z LL- l- LL- r ~ (}1 WITHIN U.S. Surve~ No. 1865 / 166~ FTo FEL AS STAKED KALOA NO.2 GRID N:2561JØ5.ØØØ (OFT C ALT A) GRID E:26Ø8Ø5.ØØØ . . LATITUDE: bIOØI'IØ.851" Surface Location LONGITUDE: -15IG2Ø'54.332" (FORMERLY ALBERT ELEv. 2Ø4o~ KALOA) SCALE 1 inch = 500 ft. ~o 750 I 1000 I ~ Consulting c;roup ~Testing ENGINEERING/MAPPING /SURVEYlNG /TESTlNG P.O. BOX 468 SOLOOTNA. AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmcloneOmclonecg.com PROJECT NO. DRAWN BY: DATE: 04/04/03 REVISED: 04107103 033008 MSM NOTES J) BASIS OF COORDINATES: NG5 COR5 STATION "KEN I". 2) EL.EvATION DATUM: NAYDaa 3) SECTION LINE OFFSETS DE~lvED F~OM Tf.4EORETICAL ffiOTAACTED SECTION CORNE~ VALUES 4) AL.ASKA ðT ATE FLANE ZONE 4 NAD21 KALOA NO.2 (OPTION C ALTERNATIVE A) SURFACE LOCATION APPLICANT: )~iAurora Gss,I.LC OFFSETS: LOCATION: 1669' FEL SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST 987' FNL SEWARD MERIDIAN ALASKA N,otice of Change of Ownership anl..lion of Ope... ·e Randy, I received fax copies of the Notice of Change of Ownership and Designation of Operator forms on 7/17/2003. Your inclusion of the well name "Simpco Kaloa No.2" in the legal description on these forms is confusing. Our records show an existing well, Albert Kaloa I, drilled by Pan American (Amoco) in section 26, TIIN, R12W during 1967 - 1968. Our records also show a second, existing well in this same section, Simpco Kaloa I, that was drilled by Simasko Production Company in 1978. However, our records do not show a well named Simpco Kaloa No. 2. I know Aurora Gas, LLC has submitted a permit to drill application for a proposed well, Kaloa No.2, to be drilled within 20 feet or so of the Albert Kaloa 1. This proposed well is the likely the source of the erroneous Simpco Kaloa No.2 name on the forms. In any event, it would be best to eliminate the well reference on these forms. Aurora appears to own and desires to operate all of lease C-61393, and I believe that is what you intend the Notice of Change of Ownership and Designation of Operator forms to convey, rather than just ownership and operatorship of a single well. I also note that section 23 is listed in the legal description on the Notice of Ownership but not on the Designation of Operator form. Also, in regard to section 27, Aurora appears to be owner and operator of the onshore (fractional) portion of section 27 only. The current description on your forms implies ownership and operatorship of all of the El/2 El/2 El/2 of section 27, both onshore and offshore. The offshore portion of section 27 is part of state lease ADL 17586. Please check the descriptions on both forms carefully as these are legal documents. The State of Alaska and BLM have an excellent site on the Internet at http://www.dnr.state.ak.us/lris/gis/qmi/ that you can use to access land status plats for Alaska which are presented in Adobe Acrobat format. Leases such as C-61393 are not labeled on the DNR/BLM plats, but these plats can still be used to check legal descriptions. The Commission has also purchased an excellent set of land maps produced by Mapmakers Alaska that I use in conjunction with the DNR/BLM plats. Their website can be found at http://www.mapalaska.com/. The Commission's regulations can be found on the Internet at http://www.state.ak.us/local/akpages/ADMIN/ogc/Regulations/RegIndex.htm. Regulations 20 AAC 25.020 - DESIGNATION OF OPERATOR and 20 AAC 25.022 - NOTICE OF OWNERSHIP are pertinent here. If you have any questions, please call or email me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 1 of2 12/1112003 9:20 AM [Fwd: 2003 Proposed Cook Inlet B.n.jects: Pennit ... .. Ray, FYI, I provided the following update of my "Additional Information / Needs" listing to Randy Jones on June 24, 2003. Let me know if there is anything further I can do. Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793 -1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us Randy, As follow-up to our conversation today, I would like to send my listing of needed additional information concerning the permit to drill applications submitted to the Commission as part of Aurora's 2003 proposed Cook Inlet Basin projects. This is the original listing I sent you via email on April 21, 2003, annotated with comments about concerns/questions that have been answered, and those items that are still outstanding. If you have any questions, please call me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us Proposed Cook Inlet Basin Projects: Permit to Drill Applications Content-Type: message/rfc822 Content-Encoding: 7bit Content-Type: application/msword Content-Encoding: base64 1 of 1 12/11/20039:23 AM 2003 Proposed Cook Inlet Basin Projects...ations - Additional Information I Needs " '. ee e_ Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Tue, 24 Jun 2003 12:19:46 -0800 From: steve _ davies@admin.state.ak.us To: Randy Jones <rjones@aurorapower.com>, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Randy, As follow-up to our conversation today, I would like to send my listing of needed additional information concerning the permit to drill applications submitted to the Commission as part of Aurora's 2003 proposed Cook Inlet Basin projects. This is the original listing I sent you via email on April 21, 2003, annotated with comments about concerns/questions that have been answered, and those items that are still outstanding. If you have any questions, please call me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793 -1224 Fax: (907) 276-7542 steve_davies@admin.state.ak.us L-______________~ ~--~----~-^_.¥__.__.~._-~-,--------.~ ---.-.--.-.< . _~ ".- _.~_.... _~~~~_w_~_"_,, ; Name: 1 030623 Aurora W CI Proj( ! ~ 1 030623 Aurora W CI Project Deficiencies Li st. doc : Type: WINwORD File (-;pplication/rr , Encoding: base64 ee ee Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information / Needs Updated June 24, 2003 Lone Creek #3: Pennit to Drill number 203-062, expected spud date is May 15, 2003. AOGCC senior staff submitted the application for pennit to drill to Commissioners for approval on 6/24/03. a.Logging program is not specified in well pennit application. Received 4/22/03. b.Noed determination ITom Glen Gray as to whether an ACMP Consistency Dotonnination is needed. ACMP detennination may be needed (Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). ACMP detenninations will no longer delay approval and issuance of a pennit to drill ITom the Commission. However, a pennit to drill does not exempt you ITom obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. Long Lake #1: Pennit to Drill number 203-068, expected spud date is May 20, 2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. .for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces ITom a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/local!akpages/ADMIN/ogc/artI99.htm. b. Designation of Operator and Notice of Change of Ownership fonns must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership fonns are not on file for this lease. These fonns can be obtained from AOGCC's website at: http://www.state.ak.us/local!akpages/ADMIN/ogc/homeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end ofthis letter. Alaska Oil and Gas Conservation Commission 1 -. ee c. C-Plan exemption determination needed from AOGCC. I am awaItmg a request letter from ADEC. Submitted recommendation to Lydia Miner, Alaska Dept of Environmental Consrvation on June 20, 2003. d.Logging program is not specified in well permit application. Received 4/22/03. d. ACMP not needed ((Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). Mobil Moquawkie #1: Permit to Drill number 203-069, expected spud date is June 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease (see write-up in item "b"under Long Lake #1, above). e. Logging program is not specified in well permit application. Received 4/22/03. b. c. ACMP not needed ((Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). c. Spacing exception not required as long as re-completion operations in Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie #1 is 1704' from the nearest lease line, which exceeds the required 1500' setback distance from property lines for a gas well. Moquawkie #1 is 2500' away from, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. from 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-completion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-completion operations are restricted to 2900' MD and shallower. West Moquawkie #1: Permit to Drill number 203-070, expected spud date is June 20, 2003. a. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie #1 re-completion. Simpco Moquawkie 1 also lies within the same section (Section 36). b. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. (see write-up in item "b"under Long Lake #1, above) f. Logging program is not specified in well permit application. Received 4/22/03. c. ACMP not needed ((Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). Kaloa #2: Permit to Drill number 203-071, expected spud date is July 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. (see write-up in item "b"under Long Lake #1, above) Alaska Oil and Gas Conservation Commission 2 ee ee b.Logging program is not specified in well permit application.Received 4/22/03. c. Need determination from Glen Gray as to whether an ACMP Consistency Dctcrmination is nceded.ACMP detennination may be needed (Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). ACMP detenninations will no longer delay approval and issuance of a pennit to drill from the Commission. However, a permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. d. Spacing exception is not required. Although nearby well Simpco Kaloa 1 is perforated in the same interval and is classified as shut-in, it is not capable of producing in its current condition (bridge plug set at 3552' MD, cement on top of the bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission 3 . . . ee ee Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17 , 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Kaloa No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S18, T12N, RIIW. Aug 2000: Notice of change of Ownership from COO to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator form from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator form for that lease. Apr 2001: Designation of Operator form from Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, TI2N, Rll W. Jan 2003: Designation of Operator form designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission 4 ee ee (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance of the designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission 5 Aurora qas, LLC Pennit to Drill Deficiencies Letter ·o~. ... e _ ee Subject: Aurora Gas, LLC Permit to Drill Deficiencies Letter Date: Man, 23 Jun 2003 11 :02:25 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: ray@fairweather.com Ray: As we discussed on Friday, attached is the email that I sent to Randy Jones in April which outlines needs or deficiencies for each of the permit to drill applications submitted by Aurora. Please call or email me if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------ Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today) . Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies ----------------------------------------------------------------------- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Aurora G~, LLC Pennit to Drill Deficiencies Letter ..' '- - e e Telephone: (907) 793 -1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us ! , 1030418 i L_____ _ ... Aurora W CI Project Deficiencies ee 1'laDle:030418_Aurora_W_CI_Projec~ Emai1.doC[ Type: WINWORD File (applicationlm .. L:En~()~!~~: b~~~64_ __ __.. Á" / ¿:> -t.--./V ^-..... Oil and Gas Update .' . 3 ee /( A-1c:£L 2- June 16, 2003 Pipeline System near Valdez. This facility provides the source for the Valdez Marine Terminal (VMT) raw water, potable and firewater needs. OPMP initiated this 30-day review on April 15, 2003 and issued the final determination on May 2,2003 [17 calendar days in review]. Contact: Kaye Laughlin. Pre-Application Stage Kuparuk River Rehabilitation Plan: ConocoPhillips Alaska, Inc. proposes to restore the East and West Channels of the Kuparuk River to their approximate condition prior the spine road development. Contact: Kaye Laughlin. Aurora Gas LLC Projects: Aurora Gas proposes to conduct exploration for gas on a number of sites and a development project at one site during the summer of2003. All of these projects are located onshore on the west of Cook Inlet. Exploration activities for five projects will be conducted from existing pads, and no permits are expected to trigger an ACMP consistency review (Long Lake No.1, Mobil Moquawkie No.1, Simpco Moquakie No.1, West Moquawkie No.1, and Simpco Moquawkie No.2). Three exploration projects would likely need an ACMP review (Nicolai Creek Unit No.7, Lone Creek No.3, and Kaloa No.2). A production facility including installation of a four-inch pipeline is proposed near the Shirleyville runway. OPMP sponsored a pre-application meeting on April 17, 2003. Contact: Glenn Gray. Petro Star Valdez Pipelines: Petro Star, Inc. proposes to construct two parallel petroleum pipelines and a fuel transfer dock on the south shore of Port Valdez just east of the Solomon Gulch Hatchery. In 1992, Petro Star investigated seven different alternative locations for delivering product to a marine terminal. The proposed pipelines will start at the Petro Star Valdez Refinery and continue west, buried under a mile-long section of a new bike path along Dayville road. From Dayville Road, a trestle will extend about I,OOO-feet northward to a fuel transfer dock. Petro Star plans construction of the buried pipeline to be concurrent with construction of the pedestrian path along Dayville Road Contact: Kaye Laughlin. Borealis Power Project: BPXA proposes to expand infrastructure to meet power demands of future satellite expansion in the western end of the Prudhoe Bay Unit and a possible tie-in with the Milne Point Unit power grid. The project would include a new 69 kV power line, a sub- station, and possible minor pad extensions. The power line would run from the Central Power Station to the L and V Pads in the end ofthe unit and possibly extended to Milne Point. Originally planed for the 2003-2004 winter season, BP notified OPMP that the project has been deferred for another year. OPMP held a pre-application meeting on April 9. Contact: Kaye Laughlin. DEC Inactive Reserve Pit Closure Program: OPMP is working with state resource agencies and the U. S. Army Corps of Engineers on reserve pit closures required by the DEC solid waste program. Companies are required to complete environmental assessments for all abandoned drilling waste reserve pits and must conduct corrective actions to clean up or prevent release of contaminants at these sites. Assessments have been completed on over 600 sites in the state, and Re: [Fwd: RE: Aurora] -- -- Subject: Re: [Fwd: RE: Aurora] Date: Fri, 06 lun 2003 11: 16:44 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Glenn Gray <Glenn _ Gray@dnr.state.ak.us> CC: Steve Davies <steve_davies@admin.state.ak.us>, Randy Ruedrich <randy Juedrich@admin.state.ak.us> Glenn, Thanks much. I am frankly surprised that Fairweather/Aurora had not sent any paperwork after the meeting. That's what I would have done. Got to keep the ball rolling or in play and not sit on it. I do know that some of the "rush" has changed due to Aurora "re-Iooking" at seismic information. Regardless, the need for "rush" has a way reappearing to bite someone when they least expect it, so again I am surprised that you didn't get any paperwork. Thanks for chasing this, I do appreciate your efforts on our behalf. Tom Maunder AOGCC Glenn Gray wrote: > -------- Original Message -------- > Subject: RE: Aurora > Date: Fri, 6 Jun 2003 10:45:45 -0800 > From: Bill Penrose <bill@fairweather.com> > To: 'Glenn Gray' <Glenn_Gray@dnr.state.ak.us> > CC: Ray Eastlack <ray@fairweather.com> > > Glenn, > > Ray Eastlack, our engineer handling the Aurora Gas facility & pipeline > installations and related permitting is preparing a comprehensive status > update as a response to your previous email to the AOGCC. The short > answer > is that you'll be getting paperwork next week. Ray will have the story > to > you very quickly. > > By the way, are you in Anchorage, now, or Juneau? > > Regards, > Bill > > -----Original Message----- > From: Glenn Gray [mailto:Glenn Gray@dnr.state.ak.us] > Sent: Friday, June 06, 2003 10:00 AM > To: Bill Penrose > Subject: Aurora > > Bill: > Did you submit any paperwork on any of the proposed wells after the > preapplication meeting? > Glenn t~,~"_·.,........~~~~.~.-_~.~~_~,.__~~·."""",,,~,~_=~,_,~,~~___,~,,~~~~.____""""'~~V~~,__," ..~~ --.-- w~_ _w_·____.___~__ 'W'w__._,~,,_.~.__w_.___~_____~.__ -----ì Tom Maunder <tom maunder@admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission Aurora Operations e_ Subject: Aurora Operations Date: Fri, 06 lun 2003 09:58:31 -0800 From: Glenn Gray <Glenn _ Gray@dnr.state.ak.us> Organization: Alaska Department of Natural Resources To: Tom Maunder <tom_maunder@admìn.state.ak.us> CC: Steve Davìes <steve_davìes@admìn.state.ak.us>, Randy Ruedrich <randy _ ruedrich@admìn.state.ak.us>, bìll penrose <bìll@faìrweather.com> -- Tom: At a preapplication meeting held on April 17, 2003, Fairweather discussed a number of proposals for gas exploration and development projects on the West side of Cook Inlet for Aurora Gas LLC. Although the Office of project Management and Permitting has not received a Coastal project Questionnaire for any of the projects, it appears that some of the projects will not need an ACMP review. Unless there is an permit trigger (e.g., a Corps 404 permit or a state permit included on the "C List"), the following projects will not need an ACMP review: Long Lake No. 1 Mobil Moquawkie No. 1 Simpco Moquawki No. 1 Simpco Moquawki No. 2 West Moquawkie No. 1 For several other wells, an ACMP may be required, and a final decision will be made after Fairweather provides more information to me about the permits needed for the projects: Nicolai Creek Unit No. 7 (ACMP review likely needed) Lone Creek No. 3 (may need a review) Kaloa No. 2 (may need a review) Shirleyville Production Facility (may need an ACMP review) As I recall, Fairweather was working with the Corps to complete wetlands determinations to see if 404 permits are needed and with the Office of Habitat Management and Permitting to see if fish habitat permits are needed. By copy of this email, I will check with Fairweather to see if they have any new information. Glenn termination will Well Permit Response -- -- Subject: Well Permit Response Date: Wed, 30 Apr 200313:57:16 -0800 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.ak.us> CC: 'Ed Jones' <jejones@aurorapower.com> Tom: Please find attached a response to AOGCC's request for information and clarification for each of the following (4) wells. West Moquawkie No. 1 Kaloa NO.2 Moquawkie No. 1 Long Lake No. 1 I hope that the attachments will clarify, appropriately address and correct concerns initially submitted to us. Please do not hesitate to call or email me should more clarification or information be required. Thank You Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 Name: W. Moquawkie #1.doc Ow. MOQuawkie #1.doc Type: WINWORD File (application/msword) ,Encoding: base64 Name: Kaloa #2.doc o Kaloa #2.doct Type: WINWORD File (application/msword) Encoding: base64 Name: Long Lake #1.doc DLOnQ Lake #1.doc Type: WINWORD File (application/msword) Encoding: base64 1of2 7/24/2003 11 :52 AM -- cae From: Tom Maunder [tom_maunder@admin.state.ak.us] Sent: Tuesday, April 22, 2003 11:48 AM To: duane vaagen Subject: Kaloa #2 Hi Duane, Here is the note regarding my questions on the Kaloa #2. 1. After setting the 9-5/8" surface casing, it is a FIT but no value is given. What do you expect?? plansl a EMW value was stated. specified to do In the other 2. I note this BOP drawing does not include the rotating head. 3. In the 7" casing running instruction, it appears to state that the 7" might not be run to TD. If it were determined to not run the casing to TD, we would need to be notified and provisions for isolating any open hole below the shoe would have to be determined. This is similar to questions on the other wells on how to avoid "flip-flop". 4. The XS cement volumes specified are only 15%. Will that be sufficient?? What XS factors did you employ last year?? You may not have surface hole values since I don't think Aurora drilled a grass roots well last year, but the other hole sections might apply. Thanks for you attention to these questions. Tom Maunder, PE AOGCC Response: Kaloa No. 2 1) Sorry about that, we will attempt to test to an EMW of 17 ppg. 2) Since this will be a grass-roots well, we will use a standard circulating system, i.e. pump down drill-pipe with returns up annulus. Because of the area, we donlt want to risk plugging our bit or pipe with the coal, gravel and rocks we will be drilling through. 3) We will run the 7" casing to bottom (-3745 - 3750/). This will give us the rat-hole we need inside as well as take care of the cement swap problem indicated. ~ ~ 4) As you pointed out, the excess cement amounts for cementing the casing strings indicated in the permit application are insufficient. Further review of historical well records for offset wells Albert Kaloa No. 1 and the Simpco Kaloa No. 1 wells, and the cement volumes that were used when cementing these wells indicate a larger volume should be planned for. We will plan on pumping 100% excess for the 9 5/8" surface casing with the intent to cease displacement operations when good cement is observed at surface. On the Albert Kaloa No. 1 well, 18% excess was required to cement 20" casing inside a 26" hole to surface with returns to surface. When cementing the 13 3/8" casing at 2922', 77% excess cement was used with no mention of any cement being seen at surface. The wells mentioned were cemented using a 15.8 ppg "G" slurry. In the permit application we initially indicated we intended to use a 15.8 ppg cement system at surface. We are now analyzing a lighter system to cement the surface casing string, the idea being to minimize the potential of losing circulation and maximizing the potential of seeing good returns at surface thereby insuring a good cement job on the surface casing. This is not only critical but a requirement. We will notify and update AOGCC when we have optimized this and describe our intended cement system. Tom: Thanks and please do not hesitate to call me at 258-3446 with any more questions or concerns. Duane Vaagen Fairweather E&P Services, Inc. Kaloa #2 Albert Kaloa Field Log Run Depths Hole/Casing Tools E-Mail Prints Film/Sepia Digital OH1 1050-3700' 8-1/2" PEX (AIT/SP/GR/CNLlTLD) PDS/LAS 8 1 CMR .. FMS-Dipmeter? RFT CH1 Surface-3700' 7" USIT/CCL/GR PDS/LAS 8 1 DSI RST 1-DLlS/PDS VSP (CD) 7-LAS/PDS (Disk) , Aurora Gas, LLC 2003 Proposed Cook Inlet Basin pr1liÞ Pennit to DriL "- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us Content-Type: application/msword !1_030418_Aurora_ W _CI_Proj, ect_Deficiencies_Email.doc Content-Encoding: base64 _ ___m._..........__.·__m_.._m..... 1 of 1 12/11/2003 9:03 AM -- -- Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information / Needs Lone Creek #3: Pennit to Drill number 203-062, expected spud date is May 15,2003. a. Logging program is not specified in well pennit application. b. Need detennination fÌ'om Glen Gray as to whether an ACMP Consistency Detennination is needed. Long Lake #1: Pennit to Drill number 203-068, expected spud date is May 20,2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce fÌ'om a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/locallakpages/ ADM IN/ ogcl art 199 .hun. b. Designation of Operator and Notice of Change of Ownership fonns must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership fonns are not on file for this lease. These fonns can be obtained from AOGCC's website at: http://www.state.ak.us/loca]!akpages/ADMIN/ogclhomeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end of this letter. c. C-Plan exemption detennination needed fÌ'om AOGCC. I am awaiting a request letter fÌ'om ADEC. d. Logging program is not specified in well pennit application. Moquawkie #1: Pennit to Drill number 203-069, expected spud date is June 1,2003. a. Designation of Operator and Notice of Change of Ownership fonns are not on file for this lease. b. Logging program is not specified in well pennit application. Alaska Oil and Gas Conservation Commission April 18, 2003 1 -- -- c. Spacing exception not required as long as re-completion operations III Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie # 1 is 1704' from the nearest lease line, which exceeds the required 1500' setback distance from property lines for a gas well. Moquawkie #1 is 2500' away from, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. from 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-completion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-completion operations are restricted to 2900' MD and shallower. West Moquawkie #1: Pennit to Drill number 203-070, expected spud date is June 20, 2003. a. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie #1 re-completion. Simpco Moquawkie 1 also lies within the same section (Section 36). b. Designation of Operator and Notice of Change of Ownership fonns are not on file for this lease. c. Logging program is not specified in well pennit application. Kaloa #2: Pennit to Drill number 203-071, expected spud date is July 1,2003. a. Designation of Operator and Notice of Change of Ownership fonns are not on file for this lease. b. Logging program is not specified in well pennit application. c. Need detennination from Glen Gray as to whether an ACMP Consistency Detennination is needed. d. Spacing exception is not required. Although nearby well Simpco Kaloa 1 is perforated in the same interval and is classified as shut-in, it is not capable of producing in its current condition (bridge plug set at 3552' MD, cement on top of the bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission April 18, 2003 2 ee .. Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17, 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Kaloa No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S18, TI2N, Rll W. Aug 2000: Notice of change of Ownership from CIRI to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator form from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator form for that lease. Apr 2001 : Designation of Operator form from Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, TI2N, Rll W. Jan 2003: Designation of Operator form designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides ofthe line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides ofthe line; Alaska Oil and Gas Conservation Commission April 18, 2003 3 -- .. (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance ofthe designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission April 18, 2003 4 Kaloa #2 -- . Subject: Kaloa #2 From: Tom Maunder <tom _ maunder@admin.state.ak.us> Date: Tue, 22 Apr 2003 11:48:14 -0800 To: Duane Vaagen <duane@fairweather.com> Hi Duane, Here is the note regarding my questions on the Kaloa #2. 1. After setting the 9-5/8" surface casing, it is specified to do a FIT but no value is given. What do you expect?? In the other plans, a EMW value was stated. 2. I note this BOP drawing does not include the rotating head. 3. In the 7" casing running instruction, it appears to state that the 7" might not be run to TD. If it were determined to not run the casing to TD, we would need to be notified and provisions for isolating any open hole below the shoe would have to be determined. This is similar to questions on the other wells on how to avoid "flip-flop". 4. The XS cement volumes specified are only 15%. Will that be sufficient?? What XS factors did you employ last year?? You may not have surface hole values since I don't think Aurora drilled a grass roots well last year, but the other hole sections might apply. Thanks for you attention to these questions. Tom Maunder, PE AOGCC 1 of 1 4/27/20052:26 PM Aurora Logging Program ^ a-IDc...·· L Subject: Aurora Logging Program Date: Tue, 22 Apr 2003 15:16:16 -0800 From: duane vaagen <duane@fairweather.com> To: "Steve Davies (steve_davies@admin.state.ak.us)" <steve_davies@admin.state.ak.us> Steve: Attached are files as promised. The 2003 Wireline spreadsheet contains the proposed logging suites for each well, which are tabbed as additional spreadsheets in the file. Please do not hesitate to call with any questions or concerns. .. ". . Duane Vaagen Project Engineer ./ Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 '_"~~~Y"'m~~YY~" ~ ~~~_. .~~.,...v. ~~Y_""""VV~_V~~'_~Y~~~VVV~yyVu~m_y" V~uy..,,·,v~~",/, Name: 2003 Wireline Logging Program.xIs ~2003 Wireline Logging Program.xIs Type: Microsoft Excel Worksheet (applicationlvnd.ms-exceI)¡ Encod~g:~~~~.~~ ,_<·vv__u~~·y··,·,y"..~_~u,...v...,~·v_,,·_,w~._,...._,_u~· _ '..__,.·,~____·v·,...~··,·_,__,v,_· u....v.uu~~.u> . ,_~ .y'u' _".._'m.__,,_ _'''yV,_u~_.~uuu.__,~~m "Y~"U'U"H" ... ..~__"". ..._."U~'" , Name: 2003 Mudlogging Program.xIs ~2003 Mudlogging program.xlsf Type: Microsoft Excel Worksheet (applicationlvnd.ms-exceI)¡ ..w'w.,"......~,....t~~~~.?~.i~g: b~~e6~ .... _....~..w.. .....1 r I· Kaloa #2 Albert Kaloa Field Proposed Logging Program Log Run Depths Hole/Casing Tools E-Mail Prints Film/Sepia Digital OH1 1050-3700' 8-1/2" PEX (AIT/SP/GR/CNLITLD) PDS/LAS 8 1 CMR P FMS-Dipmeter? RFT CH1 Surface-3700' 7" USIT/CCLlGR PDS/LAS 8 1 DSI RST 1-DLlS/PDS VSP (CD) 7 -LAS/PDS (Disk) ,. Aurora Gas, LLC 4/23/2003 030423_Aurora_W_CL2003 Wireline Logging Program.xls Interval Mudloggers Sample Catchers Sample Frequency FID Gas Detection Lithology Description PVT Monitoring Flow Monitoring Rig Function Monitoring Cuttings Show Report Generation Daily Log & Report Final Log & Report Sepia or Film Digital Camp Accommodations Equipment Transportation Nicolai Ck 9 200-620' 620-2300' 2 2 As Needed As Needed 30' 10' Yes Yes Yes Yes Yes Yes Yes Yes ? ? 1-UnwashedlWet; 3-Washed/Dry As Needed? ¡ As Needed? E-mail, fax or FTP 8 8 1 1 8 (CD) Provided by Aurora Provided by Aurora 2003 Program Mudlogging Requirements Proposed Logging Program Long Lake 1 3052-4653' 1 Not Needed None Yes No Yes Yes ? None None E-mail, fax or FTP 8 1 8 (CD) Provided by Aurora Provided by Aurora Lone Ck 3 200-1000' 1000-2900' 2 2 As Needed As Needed 30' 10' Yes Yes Yes Yes Yes Yes Yes Yes ? ? 1-UnwashedlWet, 3-Washed/Dry As Needed? ¡ As Needed? E-mail, fax or FTP 8 8 1 1 8 (CD) Provided by Aurora Provided by Aurora Aurora Gas, LLC West Moquawkie 1 2515-3550' 2 Not Needed None Yes No Yes Yes ? None None E-mail, fax or FTP 8 1 8 (CD) Provided by Aurora Provided by Aurora Kaloa 2 200-1050' 1050-3700' 2 2 As Needed As Needed 30' 10' Yes Yes Yes Yes Yes Yes Yes Yes ? ? 1-UnwashedlWet; 3-Washed/Dry As Needed? ¡ As Needed? E-mail, fax or FTP 8 8 1 1 8 (CD) Provided by Aurora Provided by Aurora Nicolai Ck 7 ~ 200-750' 750-2750' 2 2 As Needed As Nee 30' 10' Yes Yes Yes Yes Yes Yes Yes Yes ? ? 1-UnwashedlWet; 3-WashedlDry As Needed? ¡ As Needed? E-mail, fax or FTP 8 8 1 1 8 (CD) Provided by Aurora Provided by Aurora I· 4/23/2003 2003 Mudlogging Program.xls Kaloa #2 . Subject: Kaloa #2 Date: Tue, 22 Apr 2003 11 :48: 14 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Duane Vaagen <duane@fairweather.com> Hi Duane, Here is the note regarding my questions on the Kaloa #2. 1. After setting the 9-5/8" surface casing, it is specified to do a FIT but no value is given. What do you expect?? In the other plans, a EMW value was stated. 2. I note this BOP drawing does not include the rotating head. 3. In the 7" casing running instruction, it appears to state that the 7" might not be run to TD. If it were determined to not run the casing to TD, we would need to be notified and provisions for isolating any open hole below the shoe would have to be determined. This is similar to questions on the other wells on how to avoid "flip-flop". 4. The XS cement volumes specified are only 15%. Will that be sufficient?? What XS factors did you employ last year?? You may not have surface hole values since I don't think Aurora drilled a grass roots well last year, but the other hole sections might apply. Thanks for you attention to these questions. Tom Maunder, PE AOGCC Tom Maunder <tom maunder@admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 1 . 4/22/2003 11 :48 AM 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information I Needs Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today) . ee Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies ----------------------------------------------------------------------- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. ,. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Telephone: (907) 793-1224 Fax: (907) 276-7542 steve_davies@admin.state.ak.us commission ,..,...... .....,.«.,......"'.,~.._-''"~,,,~.. ..m..".AA'~..Mn......~""_~~..... "..U·M__~m~."..v."..~.~~~~~._·n...'..@~"..,.~..._~~~""~mw.""~__,~...,~.._~.~.~·~__·*~...,_~._.~.·.,,_,,.w~~_.~n~",'.·.m_.."~~",,,...,,"..~~.M.'·....~.~.........__."_"...m....'_~_.....,...._",..~..~"..,-. .~.......-<'y"'~~""'~_~.v. '''~ '_"""V'___ ~. ~.~ .... .~. _. ..__m. ~___~_. .. ~xy,,~·~·~>_···..~~ ~030418 Aurora W Name: 030418_Aurora_ W _CI_Project_Deficiencies_Emai1.doci CI Project Deficiencies Email.doc Type: WINWORD File (application/msword) ¡ Encoding: base64 ! ~ ~~"~vwP>~ ,~_ , "_·...w~.._...~~'_"o/'__._.. ~,,_, h~~' ,,~.~"'~""" ......~"...,,~....."'~~ , It Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information / Needs Lone Creek #3: Permit to Drill number 203-062, expected spud date is May 15,2003. a. Logging program is not specified in well permit application. b. Need determination from Glen Gray as to whether an ACMP Consistency Determination is needed. Long Lake #1: Permit to Drill number 203-068, expected spud date is May 20,2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 MC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/local/akpages/ADMIN/ogc/art199.htm. b. Designation of Operator and Notice of Change of Ownership forms must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. These forms can be obtained from AOGCC's web site at: http://www.state.ak.us/local/akpages/ADMIN/ogc/homeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end ofthis letter. c. C-Plan exemption determination needed from AOGCC. I am awaiting a request letter from ADEC. d. Logging program is not specified in well permit application. Moquawkie #1: Permit to Drill number 203-069, expected spud date is June 1,2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. b. Logging program is not specified in well permit application. Alaska Oil and Gas Conservation Commission I - . , c. Spacing exception not required as long as re-completion operations III Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie #1 is 1704' from the nearest lease line, which exceeds the required 1500' setback distance from property lines for a gas well. Moquawkie #1 is 2500' away from, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. from 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-completion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-completion operations are restricted to 2900' MD and shallower. West Moquawkie #1: Permit to Drill number 203-070, expected spud date is June 20, 2003. a. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie #1 re-completion. Simpco Moquawkie 1 also lies within the same section (Section 36). b. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. c. Logging program is not specified in well permit application. Kaloa #2: Permit to Drill number 203-071, expected spud date is July 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. b. Logging program is not specified in well permit application. c. Need determination from Glen Gray as to whether an ACMP Consistency Determination is needed. d. Spacing exception is not required. Although nearby well Simpco Kaloa 1 is perforated in the same interval and is classified as shut-in, it is not capable of producing in its current condition (bridge plug set at 3552' MD, cement on top of the bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission 2 , ~ ~ . Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17, 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Kaloa No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S18, T12N, Rll W. Aug 2000: Notice of change of Ownership from COO to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator fonn from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator fonn for that lease. Apr 2001: Designation of Operator fonn from Anadarko naming ARCO Alaska as operator of COO lease C-06l500, which is S18, Tl2N, Rll W. Jan 2003: Designation of Operator fonn designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission 3 - . , (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing ITom the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing ITom the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance ofthe designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission 4 RE: Lone Creek #3 ~ I II ~ ~ it Subject: RE: Lone Creek #3 Date: Wed, 16 Apr 200312:08:19 -0800 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.ak.us> Tom: Per your request, the following applies. I'll respond in the order of the questions below. 1. Yes, we have a formal meeting tomorrow afternoon with DGC, ADF&G, COE, DNR and TLO to discuss this and other wells in Aurora's program. In regards to Lone Creek No.3, we are hoping they give the green light to proceed as the only disturbance will be pad construction. No wetlands are being crossed and access will be via road constructed to drill the Chuit State wells years ago. Based on the meeting tomorrow, we will obtain all permits necessary. One thing we do know we need is a survey for a wetlands determination, site suitability and for archaeological or cultural resources. Another permit application submitted is for the Kaloa No.2. I am not so sure we will even get to this as we need a bridge. By the time we get thr Corp of Engineers and ADt-&G, tho cxIrl~ Are it will no~appen. Waste will be handled as last year, and the fonowing is applicable for the entire multi-well program this summer. Brines and muds will be recycled and used to the fullest extent possible. Drilling and workover wastes not recyclable will be transported offsite for treatment and disposal by Enviro-Tech. My apologies for not including this information in the permit application. I realized after I submitted the paper work that I omitted this information on all the wells. I will be submitting a Sundry application for testing and workover of the Simpco Moquawkie No.2 well soon. Base on log analysis and review of historical test results, I will be putting together a permit application for conversion of the SM NO.2 wen to disposal. This is one of the back-burner \ens~ut I think we will find that we real~sal well. ./ . he proposed Lead Slurry design cans for a yield ~ ) ) / 4. Attached is tentative outline of work progression. This may have been pushed back now as we are not moving the rig across Inlet until the 2nd of May. We are working on a Gantt chart and will forward a copy as soon as we have it ready. Thank you please can if you need more information or clarification. Duane Vaagen Fairweather E&P Services, Inc. -----Original Message----- From: Tom Maunder [mailto:tom maunder@admin.state.ak.usl Sent: Wednesday, April 16, 200310:52 AM To: duane vaagen Cc: Steve Davies Subject: Lone Creek #3 Duane, I left a message for you, but wanted to send this email as well. I am reviewing the Lone Creek #3 application and have a couple of questions. 1of2 4/16/20033:48 PM RE: Lone Creek #3 -. .. 1--ls this well being reviewed in the "Coastal Zone" process?? I am not sure what other permitting requirements are out there or how they are now handled, but could you elaborate on what other permits are being sought. 2--How will the drilling waste be handled?? I am aware that Aurora has submitted a request to enter one of the Moquawkie wells with the potential to complete it as a class II well and Aurora has a disposal injection order for Nicolai Crk #5. Are there any plans to do the work on Nicolai Crk #5?? The AOGCC only has authority for annular disposal and class II injection. If other methods are being planned, permits for DEC and/or DNR and maybe others will be necessary. 3--What is the yield on the lead slurry for the 7" cement job?? 4--Could you or Aurora please provide a schedule of the coming planned work with approximate operation dates?? This will help us start to get our Inlet summer schedule set up. Thanks. Tom Maunder, PE AOGCC Name: Aurora Gas POD Well Schedule.doc [JAurora Gas POD Well Schedule. doc Type: WINWORD File (application/msword): Encoding: base64 ; 2 of 2 4/16/2003 3:48 PM I \ 20 00 W 151 ,\~~Lo.A. 2 *-ASI<AL~ 22 00 W 5 1 \ \ ~É~~ ,J.. 2 .cccc.cc:·.....~/ ______ -Q;SIMPGO I<.hLOA ~-------) , 41000 , 31000 Feet 21000 ,000 1 o 260,000 I N ~ Q -- -- . k1? r¡"\ ï:ï? r-"[-' ¡' ¡.; '! ! ! ¡ L\ \ ¡, ! ~ Uit~~u lC: P"n \ r? , ¡ I , ! I ¡ I ¡ L, ¡ ¡ III I r ~...~ u ,....... n n'· n:Jr.n F"~ 1,,<1 ! d fr, ¡I,../ u\ . \ , . (\\ ¡ \ I ,F, I ¡¡ \ I \ \. i' i ,,, \., ': ;," Î.µ·u\ i L / g'.\.\ ~J') 1 !\\ ;,g\ LJ \ L___~...,.1 L", ~..._... l..... ....... L.~ t.."'-" FRANK H. MURKOWSKJ, GOVERNOR AI~A.SIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)27~7542 June 18, 2003 Ms. Lydia Miner Section Manager Exploration, Production and Refineries Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, AK 99501 RE: C-Plan Exemption for Planned Aurora Gas, LLC 2003 Activities on the West Side of Cook Inlet Dear Ms. Miner: The Alaska Oil and Gas Conservation Commission ("the Commission") received your request for a formal determination regarding an exemption from Oil Discharge Prevention and Contingency Plan requirements for wells and re- completions planned by Aurora Gas, LLC ("Aurora") on the west side of Cook Inlet during 2003. In order to evaluate Aurora's request for an exemption from the oil spill contingency plan requirements for this program, I have reviewed all of the information submitted by Aurora, and the Commission's well files, log files, production records, and records associated with Conservation Order No. 478 (spacing exception for the drilling and testing of Nicolai Creek Unit wells #18, #2 and #9). Recommendation Based on a detailed examination of Commission records, it is unlikely that any of Aurora's proposed re-completions or new wells will encounter oil or oil-bearing formations in their interval of interest, which includes the Beluga Formation and shallow portions of the Tyonek Formation. I recommend approval of the requested exemption from Oil Discharge Prevention and Contingency Plan requirements for Aurora's planned 2003 activities on the west side of Cook Inlet, " -- -- ," including the Mobil Moquawkie #1, Simpco Moquawkie #1, West Moquawkie #1, Simpco Moquawkie #2, Texaco Long Lake Unit #1, Nicolai Creek Unit #7, Nicolai Creek Unit #9, Lone Creek #3, and Kaloa #2 wells, and their associated gas production facility and pipeline. A detailed discussion for each of Aurora's planned activities is presented below. All depths presented are measured depths, unless otherwise noted, Moquawkie Area Wells Exemptions are being sought for re-entry, testing, and production of five existing wells in the Moquawkie area: Mobil Moquawkie #1, Simpco Moquawkie #1, West Moquawkie #1, Simpco Moquawkie #2, and Long Lake Unit #1 to evaluate the economics of gas production. All of these are exploratory wells drilled between 1965 and 1978 in search of oil. The four Moquawkie wells mentioned above are clustered on the same structure within a narrow, north-south trending band that is about 1 mile long and X-mile wide (see map, below). Long Lake Unit #1 is located on a separate structure approximately 4 miles to the west. T 12 N. R 12 W ._-----!-~. T12N,R11W I I I ¡ Moquawkie Field 36 ! I . Long Lake Unit 1 W. Moquawkie 1 .. ¡ 6 .. Simpco Moquawkie 1 ! I. Mobil M. .oqul,aWkie 1 ,. . Moquawkie I Simpco Moquawkie. '.' 2 I 2 I 311 Simpco E. ~oquawkie 1 .:: i T yonek Reserve 1 o t mile - ! ~) M~uawkie 44.s! -:~Tyonek ReservelB 1 I I .'¡ Slmpco ~aldac~bun~ 1 Scale !.-. Moquawkie Basemap MOQuawkie Wells Commission records do not show any indications of oil in Simpco Moquawkie #1 and Simpco Moquawkie #2, which are, respectively, the shallowest and the deepest wells on this portion of the Moquawkie structure, Oil indicators were recorded on mud logs from the other two wells, Mobil Moquawkie #1 and West 2 -- -- Moquawkie #1. All of these wells are vertical through the interval of interest, which includes the Beluga Formation and the upper Tyonek Formation. In Mobil Moquawkie #1, three very poor oil shows are noted on the mud log between 2700' and 2810' (-2330' and -2440' TVD subsea), which is the lowest portion of Aurora's interval of interest in this well. Descriptions associated with these very poor shows indicate the oil is residual, and is not live, producible oil ("very few pieces gave dull fluorescence, faint dull gold cut, residual oil in argillaceous sand"). A drill stem test conducted across the interval containing two of these very poor shows yielded very little water and no oil. Mobil Moquawkie #1 was subsequently completed in this interval and produced 985 million cubic feet of gas with associated water from May of 1967 until February 1970, when the well was shut-in. No evidence of oil production has been found in Commission records for this well. The mud log from West Moquawkie #1 notes three "slight trace" oil shows between 2320' and 2580' (-1821' and -2081' TVD subsea). Mud log descriptions mention some dark brown oil stain or "tar stain" associated with a trace to 40% pale to light yellow sample fluorescence and weak to light yellow cut fluorescence, but there is no mention of white-light hydrocarbon cut or live oil. Sixty-six sidewall cores were recovered from the well, including 42 between 795' and 2520'. Detailed lithologic descriptions or laboratory analytical results are not present in the Commission's well file, but summary records for these sidewall cores clearly state "no shows." The well was not tested (the Completion Report lists the well as "dry"), and it was immediately plugged and abandoned. Long lake Unit #1 This exploratory well was drilled, plugged, and abandoned by Texaco in 1973. Commission records do not show any indication of oil in the Beluga or Tyonek Formations within Long Lake Unit #1. The only indications of oil in the well are very poor shows marked on the mudlog in the Hemlock Formation from 5280' to 5290' (-4721' to -4731' TVD subsea), and in the West Foreland below 6655' (-6088' TVD subsea). The shallowest of these very poor shows occurs approximately 1700' below Aurora's interval of interest. Texaco plugged and abandoned Long Lake Unit #1 without testing. Summary for the MOQuawkie Area Wells The absence of oil in well tests or in regular production, the lack of oil shows in sidewall cores, and the very poor quality of all oil shows noted on mud logs indicate that Mobil Moquawkie #1, Simpco Moquawkie #1, West Moquawkie #1, Simpco Moquawkie #2, and Long Lake Unit #1 are not likely to produce oil from the Beluga or shallow Tyonek Formations. 3 -- -- Lone Creek #3 Well Lone Creek #3 is a proposed vertical, shallow gas well located to the northeast of, and on the same structure as, the Lone Creek #1 and #2 exploratory wells (see map, below). Lone Creek #1 is located high on the structure, while Lone Creek #2 is structurally lower, on the side of the structure. Both wells are vertical through Aurora's interval of interest. T12N,R11W 12 ! 9 Lone Creek 3 (proposed) 1=' 13 18 I 17 16 Lone Creek 1 .. 2. 19 20 21 25 Lone Creek 2 f 30 I 29 28 Lone Creek Basemap No oil indicators are marked on the mud logs across Aurora's proposed shallow development interval in Lone Creek #1 and #2. Lone Creek #1 tested only gas from this interval. Lone Creek #2 was plugged and abandoned without testing. Based on records from these offset wells, Lone Creek #3 is not likely to produce oil or encounter oil-bearing formations. Nicolai Creek Unit #7 and #9 Wells and Nicolai Creek Unit #1, #2 and #9 Facility The Nicolai Creek area wells are all clustered near the western shoreline of Cook Inlet. Aurora plans two shallow gas wells in this area, Nicolai Creek Unit #7 and #9. Aurora is also planning a production facility with associated pipeline to collect and process gas from the existing Nicolai Creek Unit #1 Band #2 wells, and the proposed #9 well. 4 .. -- ee : Several exploratory and development wells are located in the vicinity of this project area. Records and logs from Nicolai Creek State #1, #1A, and Nicolai Creek Unit #18, #2, and #3 (see map, below) were examined. A time-structure map of the top of the Tyonek Formation in the Nicolai Creek Field is published in the Commission's 2002 Annual Report. This report can be accessed on the Internet at: http://www.state.ak.us/local/akpaqes/ADMIN/oqc/homeoqc.htm. Nicolai Creek State #1 and #1A; Nicolai Creek Unit #1B. #2. and #9 The proposed Nicolai Creek Unit #9 well, and the existing Nicolai Creek State #1, #1 A and Nicolai Creek Unit #18 and #2 wells all penetrate the Beluga and shallow Tyonek Formations within the same reservoir block. Nicolai Creek State #1 is a 1965 exploratory well drilled, then subsequently plugged and abandoned, by Texaco. This well penetrates the Beluga and Tyonek Formations in one of the deepest portions of the fault block that also contains Nicolai Creek State #1A, Nicolai Creek Unit #18, #2, and the proposed Nicolai Creek Unit #9 well. The Tyonek gas sands were perforated and tested in Nicolai Creek State #1 between 3420' and 3630' (-3305' to -3505' TVD subsea) and they produced dry, clean gas with no associated oil. ------ 24 Nicolai Ck U 3 *' 20 21 Nicolai Ck U 5 i 1 .. .. _____l.._c N_iCO~i_ _~~_~nit 7 (proposec) 22 Nicolai Creek Field 27 25 1 cNicölãrC"kUni19 (proposed) ~trif1B;¡;. /- ~Iai Ck St 1V NI~a~ r Nicolai Ck St 1. .- ~ . NicolaiCk Nicolai Ck U 6 U 4 .' 36 31 32 -- ---- 33 34_ Nicolai Creek Basemap Oil shows in Nicolai Creek State #1 are restricted to the Hemlock Formation below 6025' (-5777' TVD subsea). These sands were tested, but according to the well file, showed "no oil accumulations." 5 . . ee e. Nicolai Creek State #1A, the first sidetrack of the #1 well, was drilled up-structure from the original #1 well bore. Commission records for #1 A report the shallowest oil indicator as being "solid hydrocarbon" (tar?) encountered between 5535' to 5550' (-5281' to -5295' TVD subsea) and 5620' to 5640' (-5360' to -5379' TVD subsea), which is over 1,500' below Aurora's interval of interest. Shallow Tyonek gas sands were produced in #1A between 3420' and 3630' (-3305' to -3505' TVD subsea). Commission records indicate this interval produced gas for only three months (December 1968 through February 1969), with no associated oil. The second sidetrack of the #1 well, Nicolai Creek Unit #1 B, was drilled up- structure of the #1 and #1 A wells by Aurora in September of 2002. There are no oil indicators shown on the mud log or mentioned in lithologic descriptions contained in the final well report from the mud-logging contractor. Nicolai Creek Unit #9 is a proposed well intended to produce gas up-structure from the #1 B well in the same fault block. The final well in this fault block, Nicolai Creek Unit #2, was drilled by Texaco as an exploration well in 1966. No oil accumulations were encountered. Texaco tested a gas sand between 3270' and 3315' (-2733' to -2768 TVD subsea), with no mention of any associated oil or water. The well produced 52 million cubic feet of gas from September 1968 through October 1969, with no record of any associated oil production. It was re-entered and tested by Aurora during 2002, and flowed gas and water from shallow Tyonek Formation sands. No associated oil is noted in Aurora's test summary reports. In summary, Nicolai Creek State #1, #1A, and Nicolai Creek Unit #2 tested the down-dip portions of the reservoir block. Nicolai Creek Unit #1 Band #9 will produce gas from the up-dip portions of this same block. Neither #1, #1 A, nor #2 have shown any indications of the presence of oil in the Beluga Formation or in the shallow portion of the Tyonek Formation. All of these wells tested or produced dry gas from shallow Tyonek sands with no indications of associated oil production. Therefore, it is highly unlikely that Nicolai Creek Unit #1 B or the proposed #9 well will produce oil or encounter oil....bearing formations. Nicolai Creek Unit #3 and Proposed Nicolai Creek Unit #7 The existing Nicolai Creek Unit #3 well and the proposed Nicolai Creek Unit #7 well will both penetrate the Beluga and shallow Tyonek Formations within the same reservoir block. Texaco drilled Nicolai Creek Unit #3 in 1967 as a Hemlock oil exploration well. The mud log for this vertical well shows only scattered, very poor oil indicators in the Hemlock Formation between 6600' and 7220' (-6400' and -7020' TVD subsea). Texaco did not test this Hemlock interval. The well was plugged back to 2522', and sands between 2000' and 2380' (-1800' and -2180' TVD subsea) were tested for gas. Reports from the test indicate production was dry gas, with 6 " ee ee .. no associated oil. Texaco produced 893 million cubic feet of gas from the well between March 1967 and September 1977. Commission records indicate only gas was produced; they do not report any associated oil production. In 2001, Aurora tested Nicolai Creek Unit #3 in five intervals between 1900' and 2380' (-1700' and -2180' TVD subsea). The well produced only gas, with no oil or water. The proposed #7 gas well is situated up-structure of #3 within the same fault block. Because the #3 well has shown no indications of the presence of oil in the Beluga Formation or the shallow Tyonek Formation, the proposed #7 well is not likely to produce oil or encounter oil-bearing formations. Summary for the Proposed Nicolai Creek Activities The absence of oil in test or regular production and the lack of significant oil shows in the shallow geologic section in Nicolai Creek State #1 and #1A, Nicolai Creek Unit #1 B, #2, and #3 all indicate that the #1 B and the proposed #7 and #9 gas wells are not likely to encounter oil in, or produce oil from, the Beluga Formation or shallow portions of the Tyonek Formation. Production facilities associated with Nicolai Creek Unit #1 B, #2 and #9 also have little possibility of receiving oil from any of these wells. Kaloa #2 The proposed Kaloa #2 shallow gas well will be drilled approximately 20 feet from the existing Albert Kaloa #1 well, an oil exploration well drilled in 1967 by Pan American and completed in 1968. 16 15 14 13 Albert Kaloa Field 24/ 28 Albert Kaloa 1 'Ø." Kaloa 2 (proposed) Z7 Sinpco Kal~a1~ T 11 N, R 12 W Kaloa Area Basemap 7 .' , ¡ .- .- ·e In 1970, Pan American perforated Albert Kaloa #1 between 3213' and 3403' (-2982' to -3172' TVD subsea) and flow-tested the well for a total of 29 hours. This test produced 13.4 million cubic feet of gas with "no significant liquid production during test." Gas samples from this test were dominantly methane, with only trace amounts of ethane, propane, and butane. According to Commission records, Albert Kaloa #1 produced 118 million cubic feet of gas from this interval during December 1970 and January 1971, with no recorded oil production. The well bore became plugged with "mud and sand," and was subsequently plugged and abandoned in 1974. The mud log from Albert Kaloa #1 reports 20% dull fluorescence with a slight solvent cut and residue at 3425' (-3194' TVD subsea), but the occurrence was not classified by the mud logging geologist as an oil show. The associated lithologic description does not mention any oil staining or the presence of live oil. Gas associated with this dull fluorescence consists only of methane. The next oil indicator noted on the mud log is a very poor show at 5875' (-5644' TVD subsea). The absence of oil in test or regular production and the lack of significant oil shows in the shallow geologic of the adjacent Albert Kaloa #1 well indicate that the proposed Kaloa #2 gas well is not likely to produce oil or encounter oil- bearing formations. Summary None of the well or production records examined suggest the possibility that oil will be encountered in, or produced from, any of the intervals that Aurora will drill, test, or produce in their proposed 2003 activities. An exemption from oil spill contingency plan requirements is appropriate for Aurora's proposed 2003 activities on the west side of Cook Inlet. Please contact me if you need additional information. Sincerely, Steve Davies Petroleum Geologist· Alaska Oil and Gas Conservation Commission cc: Daniel Seamount, Jr., AOGCC Ray Eastlack, Fairweather Kaye Laughlin, ACMP 8 f. ø .. . . __,,_&!:!:.?Lp:>:~,g¿_4-dd~u'zs;_________. U 'k: -+" . . J V .vL->'. . .. . ..p'. l"·''''' ~~ ~'*¿.;¡. _..............:...............m...............................'.' ~~'"·,·,,··"_~.·.."·.~",.·'ë"~"=··>. .. .. "'.""_~ .~.<.=!:,"'"..,."",. _ _.....~..."'~~.. .. ,~,_"=,'.= ..""".._~~ ~ // """,.._.~~"'=-""-'". <- ------~-, ~ - _..._~--....-., "'.~~.=~"'=-_"~.=--=.,_=,~~~__=----"'=_====~=_,~="="'-==--.,-~-""""""""""'=""______~..~<_..__.~_~.,~,~.,~~_~r.=,~._'",.-""'~~, "'-...==_~_,~=<c~.'.-_7~_"'~___..~~..-._~~.____~~~~~·_·,'~_·.~_·__~-~""""'-_·_·:>~_=.~._~_,.».""".__._'__"_.'''·r,.~_.~~~~,,~___"~~7.,.._'_'__~__'"'__.__'~~_.~.~__"'--,._~_.~'_,..>·_,', ~'__W_"'. ~...'.~».__~..".'_~.~"~'~_,_.____~_' Permit / Project 2030710 Date Start Time 9:00:48 AM End Time 9:30:31 AM Duration UIC 1 0/28/2003 Category Subject Drill Permit App Kaloa #2: Operator I Ownership Docs De.'icription Copy of incomplete ownership and operatorship documents returned to Randy Jones of Aurora. Jody formats letter, I sign, she sends. CC's to Ed Jones, Andy Clifford. Notes Contact-Primary Randy Jones Contact-Secondary Company Aurora Gas, LLC Company Primary File Secondary File Hyperlink~' to Related Files Hyperlink~' to Image Files """-'^'~"""'~-"--" «~- Thur.\·day, December II, 2003 Page 10 of I 0 .. , . e . e · STATE OF ALASKA . . ALASK~.ND GAS CONSERVATION COM SION DESIGNATION OF OPERATOR 20 MC 25.020 1. Name and Address of Owner: Aurora Gas, LLC 10333 Richmond Avenue Suite 710 Houston, Texas 77042 2. Notice is hereby given of a designation of operatorship for the oil and gas property described below: Legal description of property: Simpco Kaloa No. 2 Sections 13; 14; 15, E2E2E2; 22, E2E2E2; 24, Fractional; 25, Fractional; 26, Fractional¡ 27, E2E2E2¡ Comprising 3,435 Gross/net acres Township 11 North, Range 12 West Seward Meridian Lessor: Cook Inlet Region, Inc. Lessee: E~EJYE~61393 OCrT7200J Aurora Gas, LLC JUL 2 1 2003 Alaska Oil & Gas Cons. Commission Anchorage # I {hK-<-' ";544... ¿-Sf ¡'II:-I ¿.: r ¡.-.tel ßi> Property plat attachedD 3. Name and Address of Designated Operator: Aurora Gas, LLC 10333 Richmond Avenue, Suite 710 Houston, Texas 77042 4. Effective Date of Designation: December 31, 2002 5. Acceptance r,erato~ for the above d~ibe Signature Y ¿:~.. / "-- > /. ~ / / Printed Na~ J. Edward Jones 6. The Owner MbY ce .. Signature ~ P,'oled Nt5. 7. property with all attendant responsibilities and obligations is hereby acknowledged: Date 7 -17 -03 .. ----"--- Title Vice President Date 7-17-03 Title Vice President Approved: ..........-.-..--.-...-..-. Commissioner Date Approved: Commissioner Date Approved: .......-....--..-.--...-.. Commissioner Date (Requires approval by two Commissioners) Form 10-411 Revised 2/2003 O¡p G f\IAt /1\ ,.+ ,\\ . Submit in duplicate _.. STATE OF ALASKA .. ALASKA AND GAS CONSERVATION CO.'SSION NOTICE OF CHANGE OF OWNERSHIP 20 MC 25.022 1. Name of Operator: Aurora Gas, LLC 2. Address: 10333 Richmond Avenue . Sui te 710 Houston, Texas 77042 3. Notice is hereby given that the owner[1landownerO, of record for the oil and gas property described below has assigned or transferred interest in the property indicated below: Property designation: C-61393 Legal description of property: .g-±mpeo~"1\-a::l:oa-No-;--2- Field or Unit: Moquawkie Field Sections 13; 14; 15, E2E2E2; 22, E2E2E2; 23; 24, Fractional; 25, Fractional; 26, Fractional; 27, E2E2E2; Comprising 3,435 Gross/net acres Township 11 North, Range 12 West Seward Meridian Lessor: Cook Inlet Region, Inc. Lessee: Aurora Gas, LLC ECEIVEO ocri7 .6b RECE JUL 2 1 2003 Alaska Oil & Gas Cons. Commission í.~nchorage /V · i û-rreLI '¿5~ ,.8'1> Maska Oil & A* 6'~~A Property plat attachedO 4. Effective date of assignment or transfer: 5. Percentage interest assigned or transferred: December 31, 2002 100.00% 6. Assignee or Transferee: Address: Aurora Gas, LLC 10333 Richmond Avenue, Suite 710 Houston, Texas 77042 7. Assignor or Transferor: Address: Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, Texas 77380 Signature /ß7/C-5 Printed Na e . Edward Title Vice President Form 10-417 Revised 2/2003 IA.I ~~urora Gas, LLC 10333 Richmond Ave., Suite 710 ,;;::: Houston, Texas 77042 .~ ø "i c:> w t'''''\ \.-I "-1..\ ';> - UJ <.) UJ ex: r- ~ U c:;J ...; ~~ c::: (Q o .... '-'ß. ø t.,) co c::: ød:. cXj g co ~ en co :ã. ~ /. --- ~ ./"" ... ./' l~':<'<-··'~\_-·' I...·) ..' \.1 '.' ·.'Co,,_. l":;,l . ]' ¡~ P 1',* -¡'; * ~" ~--- - ......~ 3 ü '2:!? .. D - ~ . ~;'~':;"t~t~·~1.ê ':"- ../ -'. .......'..; .-.' -..I.,", n i '''·~~''·f.. ~.'.' '. '.. ·.'··"".....~·"c"·-.u·..-j.... - -"'" C!í!~·T-~'-<'....: \...YiE~-::_ .u,,-.t _ "--= ..,.. ...._ ...::..··:')·4 7 g MAlLEDFRoM"ZlP'COOE?-?'"tr 4 z "'- . ...,.. . * Alaska Oil and Gas Conservation Commission Steve Davies 333 W. Seventh Avenue Suite 100 Anchorage, Alaska 99501-3539 . 33:5Di+~~:;:J III I I I I I' II 1/ I II! II I' It 'I . - 1 !!H i:fnH It!!!!! HIUH!H!i!!! H!11h!: Iff Hd - F'ÆlfWl!Ãit'HE1iI !XPEeR'A1mN 8rPRODU"SERVICES INC. I GENERAL ACCOUNT -. 10868 VENDOR J.D. I NAME I PAYMENT NUMBER I CHECK DATE . .I.Uq~ I;;TA'!'¡'; Ur' ALAI>KA AOOCc.: 00008867 4/9/2003 OUR \oGUCHER NUMBER YOUR VOUCHER NUMBER DATE AMOUNT AMOUNT PAID DISCOUNT WRITE-OFF UUUJ.JJ45 1049030409*K#2 4/9/2003 $100.00 $100,00 $0.00 $0.00 $100.00 $0.00 $100,00 $0.00 COMMENT FAIRWEATHER EXPLORATION & PRODUCTION SERVICES INC. GENERAL ACCOUNT P.O. BOX 103296 ANCHORAGE, AK 99510-32% PH. (907) 258·3446 FIRST NATIONAL BANK OF ANCHORAGE ANCHORAGE, AI< 99501 89-611252 - 1 DATE 4/9/2003 PAY One Hundred Dollars And 00 Cents TO THE ORDER OF STATE OF ALASKA AOOCC 333 WEST 7TH AVE SUITE 100 ANCHORAGE AI< 99501 __di AUTHORIZED SIGNATURE 1110 ~08 b8111 I: ~2 5 2000 bOI: 0 ~ ~ 2 8 2 ~ Dill :;; ~ .. \1 6 ! '" z o ï= :> Õ '" '" '" w z ¡¡; :> ED '" Z Š II. !i' w 0: C> t o '" o 0: o ¡¡ ~ o "' \;; z È5 FÀiRWÊAmE~ ~xpeOWÅ'iTÖN ~PRODUCTION SERVICES INC. I GENERAL ACCOUNT VENDOR I,D. I NAME I PAYMENT NUMBER I.CHECK DATE I 1049 STATE OF ALASKA AOGCC 00008867 r/9/2003 OUR \oGUCHER NUMBER YOUR VOUCHER NUMBER DATE AMOUNT AMOUNT PAID 00013345 1049030409*K#2 4/9/2003 $100.00 $100.00 DISCOUNT WRITE-OFF $0.00 $0.00 10868 RECEIVED APR 0 9 2003 Alaska Oil &. Gas Cons. Commission Anchorage $100.00 $0.00 $0.00 $100.00 COMMENT ... 10868 NET $100.00 $100.00 10868 AMOUNT $100.00 +...._._.~ '__"'._·__·_U~·.... .........._~ ____.___n__.__._.__ 10868 NET $100.00 $100.00 . ·e .. TRANSMIT AL LETTER CHECKLIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME /<f~ 4f 2-- PTD# )L) 3 '-. 0·7 I CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (H API number last two (2) digits are between 60-69) "CLUE" The permit is for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function of the original API number stated above. HOLE In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). PILOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to peñorate and produce 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. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below tbe permafrost or from where samples are first caught and 10' sample intervals through target zones. o o Well bore seg Annular Disposal On Program DEV On/Off Shore Unit Well Name: KALOA 2 DEV / PEND ._GeoArea 820 PQo) ha.s not. y.et be.eo defi.ned ,.500' $) i~ listed. as.shut:in, Þutith.a~ 3 downhole plugs &. is.n.ot capabl~ of producting. CI SimpÇQ I<aloa #1 .e V~rtic<ll weJ letter_oJ Credit Initial ClassfType Yes Yes Yes NA. Yes Yes Yes NA Yes Yes Yes Yes Yes NA. NA NA NA. 40500 ALBERT KALOA, UNDEFINED GAS Field & Pool Permit.fe~ attached Lease .numb~r aPRropriç¡te !J!1iqu~ well_n.ame _aod I)u.mber WeJIJocated in .a.defined pool WeJI lo.cated prop~r distaoce. WeJI Jo.cated prop~r distaoce. from. driJIing unit boundary _ from. Qther wens. in. comme ots) -<F or Qnly) S].Jffjcient acreage.aYailable in.drillirJgun¡t jf .deviated, is. weJlbor~ plaUncluded has.apprppriate.b_o(1d in JQrGe. o be iJ>sued wjtho.ut cons~rvation ord~r cao be iJ>su.ed witho_ut administr:ativ:e.approval be approved before 15-day wait ø within area an.d.strata authorized by.lojectiol) Order # (puUO# _are_a_of review ideotlfied (for: s.ervice well only) _ . . dlJrç¡tio.n.of pre-prodlJdiol) less.than.3. months.(for.seryiçe well bee.n js.su~d. fortl)is proieçt. be deterrnin.ed þy Gleo Gray, Wi r~view .requirement 4/17103.: ACMP be ceme.nted .tQ su.rfç¡çe. Sl!rf.ac~ ca~ing (set. at 62Q' MD) and.prQd].Jctioo casing.(set ç¡t3700' MD) wi casing JQ su_rfç¡çe. Pial) i~ to. cemeotprQd].Jçtioo , for disRo~al Close¡;t weJI js_ t20'_djstant atsurfa.ce._ ~Q pro~il)lity. Rrobl~m .mtiçipatect 10:' diyerter Ijn.e, plan to. driJl 8:1l2" pilot hQI~ an.d.open to .12-.1W.. . Expected. BH~ 6.6 EMW. .~ote.ntial for highe.r EMW sh.allQW. PlanJo sRud with 9.5 ppg mud. 60P to. 3.000 psi ,ð.uror¡¡ norm.ally. tests their MAS¡:> estimated at 1.450 psi Yes Yes Yes Yes Yes Yes Yes NA _Yes Yes Yes Yes Yes Yes Yes No. NA 14 15 16 17 18 19 20 4 N_ ~ \ 5 <s~ t" 6 ~~\4t \~ \) "\ I ~ 9 ~ \Y I t 11 , 11 ¡ 12 Appr ~ 13 D 12/11/2003 SF 2 3 ~ ~ Èngineering .GMTvola.dequ.ateJo CI .CMT vol adequ.ateJo .GMT-will coyer .all T, 6.&.p.ermaJrost .Gasiog deJ>igos ad.equate. for. No. reseNe .pit plaone.d, Any- drilling waste to .E.nyiro: T eel) Rig is. equip Red wjth steel pits. beeo apprQved Adequç¡te Jankage.or Jf.a.re-ddll, has.a. to:, Açlequ¡¡te .wellbore_ s_epgratjO!1prOP Jf .diverter re.quire.d. do_es it DrilJiog fluid. program schemgtic.&. e.q].Ji .BOPEs, .do .they m.eet regula.tion . . .BOPE.pre.s$ ratiog gpprop(iate;t~st to .Ghoke.ma.nifQld complies. w/API RF'-53. Work will OCCUr without .o~ration ¡;huJdow!1 Is. Rres.eoçe. oJ H2S ggs. prQb.able ~ . . _ . . Mechanical coodilion ot weJls withJn J1.0R verified. 21 22 23 24 25 26 27 Date 28 4/22/2003 29 30 31 32 33 34 Appr TEM ~Q 1:125 kn.owo tn.regiQn, Offset welLcootr:ol :""':^~', Surfa.ce hole wiJl.be çlrjlled wìth.9.8 -.1.O.Ppg rr o.ductioo inteNal with.9,2. ppg muçl.. . . . . . . Wel! will b~ drilled 5"0' Qf ~)(isting Albert I:<aloa #1. exp1or.atory. weJllP&A'~d) I, ,,,,,,,,y.;es.nplJ1)aJ press.ure. gradje.nt. Yes Yes NA NA. NA Qnly) Per:rnitcao be iJ>su.eçl wlo. hyçlr.ogen.s.uIJid~ measur.e" .Data.pr~sel)tect Qn. pote.ntial overpres.sure zone:; Sei~mi.c.anglysjs.oJ shaJIQW gas.zooe.s. 35 36 Date 37 4/17/2003 38 39 Geology Appr SFD (if Qft-shor.e) Co.ntaçt nam.e(PhoneJQr.w.eelsly- progress.reports [e)(RIQrªtory .only] .Seabeçl.conditìoo survey Samples not required as this well will be drilled within 50 feet of the Albert Kaloa #1 exploratory well, which has samples from 36' to 13,600' MD. Methane, H2S, and PVT sensors will be in place and operational. No H2S has been found in this area. SFD Public ~ ~ / Comml",o"" /2//7'5' Date Engineering Commissioner Date: </(51.3 Geologic Commissioner Gì:5 ~rm~t æ)LLr~~~ ., (ffi} !Æ~!Æ~~~!Æ ., I . ~I/.4.SKA ORAND GAS CONSERVATION COMMISSION í / I / ¡ I j ¡ 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501·3539 PHONE (907) 279-1433 FAX (907) 276-7542 FRANK H. MURKOWSK' GOVERNOR CERTIFIED RESTRICTED DELIVERY 7002315000053521 1188 Mr. Ed Jones Vice President Aurora Gas, LLC 1029 West 3rd Avenue, Suite 220 Anchorage, AK 99501 In Re: Long Lake # 1 West Moquawkie # 1 Kaloa #2 (203-068) (203-070) (203-071) ~ Dear Mr. Jones: On April 9, 2003 the Alaska Oil and Gas Conservation Commission ("Commission") received 5 Permit to Drill ("PTD") applications for planned well activities on Aurora properties on the West Side of Cook Inlet. When Commission staff began reviewing the permits for completeness and compliance with our regulations (20 AAC 25), a number of deficiencies were identified in each permit. Em ail messages were sent to Mr. Duane Vaagan on April 22 (for operations and engineering) and Mr. Randy Jones on April 18 and April 21 (for land and ownership) listing the deficiencies and requesting their action to complete the PTD applications and allow the Commission to process them in a timely manner. Mr. Vaagan responded on April 30, providing the requested operations and engineering information. The land and ownership information has been slow in arriving. Sufficien t information was ultimately received in mid-June to allow Lone Creek #3 (PTD #203-062) to be approved on June 25th and Mobil Moquawkie # 1 (PTD #203-068) to be approved on July 31st. However, several land and ownership items are still outstanding on the remaining applications. Mr. Jones was again contacted by phone on June 24, and an updated listing of the PTD application deficiencies was sent to him byemail. A copy of that deficiency list is attached. Mr. Ed Jones October 16, 2003 Page 20f2 -. ., Despite repeated written and telephone requests for the needed information and documents to complete the PTD applications for Long Lake # 1, West Moquawkie # 1, and Kaloa #2, these application remain incomplete. This is unacceptable. Be advised, that if the Commission does not receive the necessary information to complete the PTD application packages for the subject wells by November 3, 2003, the applications will be cancelled. DATED at Anchorage, Alaska and dated October 16, 2003. ~.~~ Randy ~driCh Commissioner By Order of the Commission ., ., Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information / Needs Updated October 16, 2003 Long Lake #1: (Pennit to Drill number 203-068) expected spud date was May 20,2003. a. Designation of Operator and Notice of Change of Ownership fonns (Fonns 10-411 and 10-417, respectively) must be submitted to AOGCC for this lease, which is Mental Health Trust Lease 9300023. These fonns are located on AOGCC's website at: http://www.aogcc.alaska.gov/fonns/fonnscat.htm. Pertinent regulations are attached to the end of this letter. b. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.aogcc.alaska.gov/Regulations/art199.htm. A spacing exception is not needed to drill a well, but approval to perforate, test, and produce that well is contingent upon the Commission's issuance of a conservation order approving the spacing exception. By drilling a well without a spacing exception, Aurora assumes the liability of any protest to the spacing exception that may occur. West Moquawkie #1: (Pennit to Drill number 203-070) expected spud date was June 20,2003. a. Designation of Operator and Notice of Change of Ownership fonns have not been filed for this lease, which is C-61389. b. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie #1 re-completion. Simpco Moquawkie 1 also lies within the same section (Section 36). Alaska Oil and Gas Conservation Commission 1 ·. -, Kaloa #2: Pennit to Drill number 203-071, expected spud date was July 1, 2003. If a. Original Designation of Operator and Notice of Change of Ownership fonns have not been submitted for this lease, which is C-61393. The Commission received faxed copies of the fonns on August 7, 2003. Original copies were requested rrom Mr. Andy Clifford on August 18, 2003, but they were never provided. il 07 1\. . \ \~ Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any govemmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing ITom the same pool. Alaska Oil and Gas Conservation Conunission 2 ., ., 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Fonn 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator fonn, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance of the designated operator's bond constitutes the release of the fanner operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). ------------------------------------------------------------------------------------------------------------ Alaska Oil and Gas Conservation Commission 3 April 4, 2003 . .. ~Aurora Gas, LLC www.aurorapower.com Oil and Gas Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 RE: Application for Pennit to Drill: Kaloa No.2 Dear Commissioner( s), Aurora Gas, LLC hereby applies for a Pennit to Drill, a prerequisite for drilling the grass- roots well, Kaloa No.2. The well will be located onshore the Granite Point bluff area approximately -7 ~ miles southwest of Tyonek and -2 miles due east of Shirleyville. ~ \"'\"\-c),-\,\ <..~-C 'Ob~-~~) ~\Cø'tt -cr~\ Access will be via th~;.?_~d system originally installed to drill the Pan Am Albert Kaloa r ~ ~ ~/';. _"\'-" No. 1 and the Simpco Kaloa No. 1 wells. A drill site will be constructed directly adjacent \... to and using part of the original Pan Am Kaloa No.1 well-site. Upon receipt of all necessary pennits and approvals, contractors will clear the original access roads of overgrowth and extend / rebuild the original Pan Am Kaloa drill site. The 13-3/8" conductor will be driven and the rig, Aurora Well Service No.1, will be rigged up over the well to commence drilling operations. Aurora plans to begin drilling operations on July 1,2003. Pertinent infonnation in and attached to this application includes the following: 1) 2) 3) 4) 5) 6) Fonn 10-401 Application for Pennit to Drill- 3 copies. Fee of$lOO.OO payable to the State of Alaska. A plat map and infonnation detailing the surface location and proposed bottomhole location 20 AAC 25.050 (c)(2). Diagrams and description of the BOP equipment to be used as required by 20 AAC 25.035 (a)(l) and (b). The drilling fluid program, in addition to the requirements of20 AAC 25.033 are attached. A copy of the proposed drilling and completion program, procedures and operational considerations. RECEIVED APR 0 9 Z003 OR!rl \!D! r L Alaska Oil & Gas Cons. Commission Anchorage 10333 Richmond Avenue, Suite 710 · Houston, Texas 77042· (713) 977-5799· Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220· Anchorage, A'aska 99501· (907) 277-1003. Fax (907) 277-1006 ·e .. Commissioner( s) Page 2 7) Aurora Gas LLC. does not anticipate the presence ofH2S in the formation to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during sidetracking, drilling and completion operations. 8) A Summary of Potential Well Hazards. 9) Pressure Information 10) The following are Aurora Gas LLC's designated contacts for reporting responsibilities to the Commission. 1) Completion Report (20 AAC 25.070) Duane Vaagen, Project Engineer (907) 258-3446 2) Geologic Data and Information (20 AAC 25.071) Andy Clifford, Vice President (713) 977-5799 3) Well Records, Testing and Production Reporting (20 AAC 25.070) Ed Jones, Vice President (713) 977-5799 If you have any questions or require additional information, please contact the undersigned at (713) 977-5799, or Duane Vaagen at (907) 258-3446. Sincerely, AURORA GAS, LLC . Edward Jones Vice President, Operations and Engineering Enclosures cc: Duane Vaagen Andy Clifford RECEIVED APR 0 9 2003 Alaska Oil & Gas Cons. Commission Anchorage o ! i . L- VI ¡ o ! ! 1 N , I ~ . e . TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/P ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ~/D(!"- #2- PTD# lflC¡~ {)cl~ Development Service CHECK WBA T APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API Dum ber last two (2) digits are betweeD 60-69) v/ Exploration Stratigraphic ~'CLUEn Tbe permit is for a new weUboresegment of existing well . Permit No, API No. Production sbould continue to be reported as a function' of tbe original API number. stated above. BOLE In accordance witb 20 AAC 25.005(t), all records, data and logs acquired for tbe pilot bole must be dearly differentiated In botb Dame (name on permit plus PH) and API Dum ber (SO 70/80) from records, data and logs acquired for well (name on permit). PILOT (PH) SPACING EXCEPTION DRY DITCH SAMPLE The permit is approved subject ·to fuD compJiance with 20 AAC 25.0SS~ Approval to perforate and produce is contingent upon issuance of ~ conservation order approving a spacing e:JCeption. (Company Name) assumes tbe liability of any protest to tbe spacinge:Jception that may occur. An dry ditcb sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Initial ClassfType Yes Y~s Y~s No~ Yes Y~s Y~s ~NA Y~s Y~es Yes Y~s Yes NA ~NA NA NA o o Well bore seg On Annular Disposal _Program EXP On/Off Shore Unit Well Name: KALOA 2 EXP I PEND GeoArea ß20 Field & Pool Company AURORA GAS LLC P~rrT)it fee attached ~ ~ ~ ~ ~ ~Leas~number ~appropri<ite ~ ~ ~U~nique welt l1am~ ~aod OUrT)b~er W~I) IpcaJiOI) ch~aogeMr.omJlJa~t orjgil1a!!y- prORo~ed~ forJbis well io PTO ~O~0]1 Q, w/1içlJ lJé!.s~bßel) ça~n~lIed. PQo) bé!.s npl y-et be~eo defined. Well -'QC<lt~d in a_ defil)e~dpool WeJIJQcat~d prpper Distaoce_ from dri)Ii[lg unitb_oul)d~l)'_ Well JQC<lt~d prpper Dislance~ from QtlJer wells ~(1.5QO' $)i~ Ijste~da~ ~bu_t-)n. buth<ls ~ dQwnhQle plugs_& i~ [lotcOlpableof producing $impco Ké!.IQaß1 Vertical wel ~SJJtfiçiel)t ~creage~aYail~ble in~dJiUiog unit Itd~viated, js weJlbQre pl<lUl)c)u_ded 2 3 4 5 ,6 7 8 9 PTD#: 2040960 Administration . Le~tte( Qf Çre~dit NZS 429.8j5 (For QnJy) in_c~o01m_eots) Ope(ator only- affected Party ~Oper~ator bas~approprlate~ b.ond inJQrce ca[l be issued witbQut c_ao be issued wjtbQut o 11 12 13 14 15 16 17 Date 6/7/2004 Appr SFD 8CMP çqnsi$teoçy_dßtermioatioo OQ looger (eç ui(ed to~ issue PTO. SFD~ - ~ $urta~ an_d_productipo casingwillbe~cemel)ted to surface. PI<ln is tQ cementpJQd~ucUon Ç< sil19JQ surf<ice~. . diSpo~al Spud wjth 9.5 ppg. 8uror<lMrma!!y- te~t~ lo~300Q psi M8SP est <It 12~8 p~i Y~s Yes y~s Y~s Y~s Yes Y~s NA~ Y~s y~s Y~s Y~$ Y~s Yes Yes No_ NA !ol¡¡;;;¡;- ,_, ,_1\.1'1 "v .WO~.I~I... ,",-U "'!oIU ~""'!.;:, NQ re$eJ\lepitpla[loed, All w<lste to_Enyiro~-Te~cb for Close$t weJUs_ P&Aed _82'_distant at ~urface. I-IQle size wilJ be maximum ot to-518"> 1Q" Me. Exception prevjQusly <lPPJQv~d. No change_s _have_ b.e~1) propQsed fJQm origin_at app(oval. Exp~çted BI-IF' 8.6 ~EMW. _(puJ p$ig incommel)t$) _CMkemanjfold çQmpJies w/APt RF'-53 (May 84) Work wi!! OÇCJJ( withoutoperationsbutdown 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 Engineering Rig ise~quippe_d_witb st~elp¡t$. be~o <lPPJQved Jtdiverter JeqJJired, does it meet reguJé!.tiol)s~ DJiUiog fJuid_ prQgram schematic_& eCLuip Ji$tadequate BPPJ:s,_d_o they meet reguJatiol) _ _BPPJ:_press ratiog appropriate; _test to P~(1)it cOMervatiOI) order P~unit adrT)il)i$trati\le~apprpval Can permit be approved before 15-day wait Well JQcat~d within area and_strata authorized by_lnjeçtion Ord~r # (put 10# A)I wel!s_ wit/1in J l4~ mite _are.a_ of reyißW id~ntified (Fpr $eNj~ we!! only) _ ~ _ PJe-produ_cecl injector; duratiQn~of pre-produc;tioo I~ss than 3 montbs (FoLservlce wel ACMPFindingof CQn_sistençy_h_a$ been Jssued_ for~ tbi$ project _C_ondu_ctor string~PJQvid~d __ _SJJrfa~casil)gpJQtects all_koown_ USDWs _ _ ~ _CMT v_ot é!.deQ u_ate_ to circulate_ on _cooductor & SUJt csg _C_MT v_ol é!.deQuate_ to >'0 'n ,~~" ~'r'n" '^ ~"..z ^~" CMTwilLçoyeLall koc _C_asing, de_signs adeç 1 ,t _Adequate jank<lge OJ JtaJe-dri/L has_a to-¿ Adequ<lte_wellbore. se Appr Date TEM 6/7/2004 tft~ - ~Q 1-12S known in_ regiQn, E'e'orig oaJ wel L prQposal h F>TD 2.0307J, Qffset we]1 çontroLs~uggests pres$uJe gradien_t of 8A6_ppg J:MW. ' i" be drilled with 9_.8 - to,O_ppg mud,a_nd pWduction ho)e~ with_9,0_ -9,2 ppg. OffseJ welLs_ . i 1 & SimpcQ KalQa ftthave significant ditch gas belQw 70_0' MD._ShalJoy,-gas di~çussedjn Drjlling ¡ r QCapplicatioll._ CQnté!.ct is J:d JQnes,9.D7-~277-1Q03. - i Surface 1J0lq wi'J Yes Y~$ No_ NA Yes Is presence Qf H2S gas prob.able Mecl)an¡ca'-coodjtion p{ well$ within AOR verified (For_service w~1J only) P~rrT)it can be ¡s$~ed wfo hydrogen sulfide measures _D_atapJeseotecl QI1 pote_ntial oveJpressure _zOl)es _ _ _S~ismicanalysis Qf slJaJlow gasz_ones_ _S~<lbedcondjtioo survey (if Qff-shpre) _ _ ~ _ ~ Conta_ct namelp/"loneJorweekly progress_reports [explor<ltoiyonlYl 35 36 37 38 139 Date 6/7/2004 Geology Appr SFD This well was originally permitted as PTD 2030710. A new permit was required per 20 AAC 25.015 (a)(1) because the surface location was moved about 190' to the south. The casing program has been changed, but all other aspects of the original well program remain as in PTD 2030710 (which has been cancelled). Samples not required as this well will be drilled within 200 feet of the Albert Kaloa #1 exploratory well, which has samples from 36' to 13,600' MD. Methane, H2S and PVT sensors will be in o/ace and ooerational. No H2S has been found in this area, SFD ~/of Date Engineering Commissioner Date: f/1- ~ Geologic Commissioner f)N'
