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Home My WebLink About203-062Image Pro,ect VU'ell History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. p~V ~ - ~ U~, Well History File Identifier Organizing (done) ~ Two-sided III IIIIII II III II III ^ Rescan Needed III IIIII II II III III R CAN DIGITAL DATA Color Items: ^ Diskettes, No. ^ Greyscale Items: ^ Other, No/Type: ^ Poor Quality Originals: ^ Other: OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: NOTES: ^ Other:: BY: c Maria Date: ~ I I ~'~ U lsl Project Proofing BY Date: ~O /s/ ~- __ / l Scanning Preparation ~_ x 30 = ~~ + ~ =TOTAL PAGES__~~ (Count does not include cover sheet) BY: Maria Date: /s/ Production Scanning IIIIIIIIIIIIII IIIII Stage 1 Page Count from Scanned File: (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ES NO BY: Maria Date: ~/' 3l0 V /s/ ~~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III I) II I) III II IIIII ReScanned III IIIIII IIIII II III BY: Maria Date: /s/ Comments about this file: Quality Checked II I II I) II III (I'I III P 10/6!2005 Well History File Cover Page.doc • • ~;~ ~~ r~ ~ r,~_. ,_ _. -.. MICROFILMED 03/01 /2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:~LaserFiche\C~rPgs_Inserts~lVticrofilm Marker.doc ~Aur~ora Gas, LLC www.aurorapower.com June 10, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave. Suite 100 Anchorage, Alaska 99501 Re: Request for Cancellation of Permit to Drill for Lone Creek #3 (PTD 203-062). Dear Mr. Norman: Aurora Gas, LLC hereby requests that the AOGCC cancel Permit to Drill No. 203-062. Aurora has moved the location of the proposed well approximately 2200 feet to the south. We will soon resubmit a 10-401 Permit to Drill form with the new location and pertinent information. All other aspects of the original approved program will remain basically the same. If you require additional information or have any questions, please contact the undersigned at (713) 977-5799 or Richard Tisch at (907) 258-3446. AURORA GAS, LLC t ward Jones / xecutive Vice Presid t Operations and Engineering Cc: Duane Vaagen Andy Clifford .a P.R ~ .. J' 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 Sub"ect: Re: Some Well ue• ns J Q From: Thomas Maunder <tom maunder@admin.state.ak.us> Date: Mon, 03 Jan 2005 08:44:29 -0900 To: duane vaagen <duane@fairweather.com> Hi Duane, Thanks for the response. For Long Lake, I think that given the we are now in January, the plugs are in place and it will be some 5 months at best until further work can be done that it is appropriate to file a 407 with the well listed as suspended. That will help "clear" the well from the "outstanding well" list that I have consulted. For Simpco Moquawkie No. 1, it is appropriate to submit a 404 reporting the work that was accomplished. Since no activity has been done on the other wells, I will just put a copy of this note in the well file. I appreciate your helping me "clear" these wells from the list. It saves me getting questions from our statistical people when they pull the report and find outstanding wells. Call or message with any questions. Tom Maunder, PE AOGCC duane vaagen wrote: Tom: Regarding the wells in question, the following applies: Long Lake No. 1: This well was Plugged with all plugs to surface as indicated in our P&A program. The only thing remaining to be done is cut off the starter head and weld on the marker. Aurora elected to ': leave the head on at this time and leave the pad intact as they were considering some possible future utility for_the well, perhaps a sidetrack out at shallow depth. .When Aurora made the decision to leave : the head on, I consulted with Winton Aubert about this and he indicated that would be OK for the short term while Aurora re-evaluated their geology based on the test results of the Long Lake No. 1. Aurora is planning on drilling in the region again in 2005 and may want to see what they find before fully pulling the plug on the LL #1 site. Lone Creek No. 3: The well was never drilled, nor was a site was ever built to drill a well: Aurora is still working on some seismic issues for the region, the results of which 2 have not heard yet. West Moquawkie No. l: The well was never re-entered. Aurora is re-evaluating their seismic in the region based on the Moquawkie No. 1 production results and the results obtained on the testing of the Simpco Moquawkie No. 1 performed this fall. There should be more news on the plan ahead this winter concerning this prospect. While I'm updating, the Simpco MoquaWn~c 1~~. 1 was tested this fall the results of which indicate we may have to perform a work-over at some future date to try and make commercially productive. No well work-over activity took place. We just opened it up to see what it would do. The well is currently shut in. I hope this answers your questions on the wells in question. Please call if there is anything else you need in the way of information or if you find we are lacking in our reporting. Regards and have a Happy New Year! Duane 1 of 2 1/3/2005 10:44 AM ', -----Original Message - From: Thomas Maunder [mailto:tom maunderGadmin.state.ak~] Sent: Thursday, December 30, 2004 1:08 PM ', To: duane vaagen Subject: Some Well Questions Duane, In the new year, could you look into the status of reports on these wells. Long Lake #1--203-068--Last correspondence I show was with regard to not having an inspector to witness the cut off. I don't see a 407 in the file. Lone Creek #3--203-062--Was this well drilled?? W. Moquawkie #1--203-070--Likewise, were there any activities on this well?? Hope you have a happy new year. Tom 2 of 2 1/3/2005 10:44 AM • ~Aurrora Gas, LLC www.aurorapower.com April 16, 2004 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7~` Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Approval to Change Drilling Program Lone Creek No. 3 (PTD# ~~3-Q62) Dear Mr. Norman: Aurora Gas, LLC hereby submits an Application for Sundry Approval to change the well design covered by Permit to Drill #203-062. 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-SS welded. Will now use 11- 7/8" 71.8# USS limited service structural pipe with 0.582" wall thickness. The conductor will be driven as originally permitted. Surface Casing: Original well design used 9-7/8" 36# K-55 LT&C. Will now use 8- 5/8" 32# Wildcat S0, ST&C. Hole size will be 10-5/8" (possibly 10-1/d") and original planned hole depth will be the same. production Casing: Original well design used 7" 23# 3-55 LT&C. Will now use 5-'/z°' 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 original approved PTD. Pertinent information attached to this application includes the following: 1) Form 10-403 Sundry Application -Original and 1 copy R ~ ~` ~' ~ V E 2) Casing analysis 3) Modified proposed wellbore schematic APR ~ 4 Z~Q4 Alaska Oil & Gas Cons. Commission n , ~ ~ Anchorage 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 ~~ I f / ~ ~ ~dward Jones Executive Vice President, Operations and Engineering enclosures cc: Duane Vaagen Andy Clifford • 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 S cc ~c,~.,c~~~ ~~-; 4,~~ 5 ~~ .~ ~ cam-, ~ «~ ~ ~~-~~ ~~-_~~~ , ~~~ ~c~ ~s~_~:~ . ` ~ ~ ~ l ~~ ~~~ cL '~~%~C~•~tiCS s ~-~ ~ ~~ c~~~ ~`~? ExCCLCiJ -t-\~C ~ ~ ~~ y ~~,~ ~ \ c~ ~~ ~ ~- ~~ ~~ ti~ y~`~ ~cc~ SC t~c~~~lC~- ~~~~-~ ,c-~%~ ~ STATE OF ALASKA AL~ OIL AND GAS CONSERVATION COM ION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 °~--~ ~ ~- t ~s 1. Type of Request: Abandon Suspend Operational shutdown Perforate Waiver AnnularD'ssp Alter casing ^ Repair well ^ Plug Pertorations ^ Stimulate ^ Time Extension ^ Other ^ Change approved program 0 Pu0 Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Aurora Gas, LLC Development ^ Exploratory ~ 203-062 3. Address: 1400 West Benson Blvd, Suite 410 Stratigraphic ^ Service ^ 6. API Number: Anchorage, AK 99503 50-283-20103-00 7. KB Elevation (ft): 9. Well Name and Number: 399' Lone Creek No. 3 8. Property Designation: 10. Field/Pools(s): C-61395 Lone Creek (formerly Moquawkie) 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): 0 0 0.0' P&A'd 0.0' P&A'd Surface NA Casing Length Size MD ND Burst Collapse Structural Conductor 90' 11 7/8" 71.8# LSS 90 90 7270 psi 7190 psi Surface 700' 8 5/8" 32# WC-50 700' 700' 3600 psi 2440 psi Intermediate Production 3200' S.5" 17# J-55 3200' 3200' 4910 psi 5320 psi Liner Pertoration Depth MD (ft): Pertoration Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): None None N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft): Well P&A'd: No /Suspended N/A N/A 12. Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^ Service ^ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 6/1/2004 Oil ^ Gas ~ Plugged ^ Abandoned ^ 16. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Gommission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Nam J dward Jones Title Executive VP Operations J Engineering Signature Phone 713-977-5799 Date COMMISSION USE ONLY CondRions of approval: Notify Commission so that a representative may witness Sundry Number: ~'j c`? -`~ ~~~-~.. ~ Plug Integrity ^ BOP Test ^ Mechanical Integrity fiest ^ Location Clearance ^ Other: Ej~'tC ~. \, G ~~?t'G.~ Ci~~tj ~ ~}~ '.'Q(~ ~ ~ ` ~ ~ ~.. ~ r..~.,,' V C ~./ y ~~j~~ ~ goo ~ a~ ~ Subsequent Form 'red: .~.~~ ~~C~ Alaska Oii ~ iaas Cons. Commission Anch e BY ORDER OF _ ` / Approv d b : OMMIS ONER THE COMMISSION Date: ~, • 3 '/:" 9.2# 8rd EUE Mod L-80 Tubing Lone Creek No. 3 Proposed Configuration 'r Drill 10 5/8" Hole 31/2" X 5'/" annulus to be displaced over to inhibited packer fluid w/ diesel freeze protect at surface following completion. Top Beluga ~ 500' Top Tyonek ~ 1500' 3 '/:" 9.2# EUE 8rd Mod Tubing to Top of Screen Tyonek Perforations from 2400' - 2800'. Exact Intervals to be determined by Open hole logging. 11 7/8" 71.8# Structural Conductor to be driven to 90' 8 5/8" 32# WC-50 STC Surface Casing set at 700' Cement w/ 14.5 ppg Gas-Block enhanced cement (~ 39 bbls cmt @ Sliding Sleeve 1 joint above packer @ 2280' w/ 2.813" X-Profile for landing plug 5'/z" Retrievable type Seal-bore Production Packer 90' above upper perforation 2310' 2.813" XN-Profile 1 Joint below packer at _ 2340' Sand Exclusion Screen across all perforations. All Screen sized to 5'/:" casing. _ 8 Jts Total. Dri117 7/8" Hole PBTD at 3165' I Aurora Gas, LLC Summer 2004 Well Program Rev. 3.1 5'/:" 17# J-55 LTC Casing to 3200' MD (TVD) Cmtd w/ 48 bbl 13.5 ppg Lead at 20 % and 56 bbls 15.8 ppg Tail at 20%(Top of Tail to extend to 1500' MD) 4/5/2004 • Well ID Lone Creek No. 3 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1,8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 11 7/8" Conductor Casing Properties: Size OD: 11 7/8 Grade: USS Ltd. Weight ppf: 71.80 Coupling: Welded Set Depth ft 95.00 (ft)MD 95.00 (ft)TVD Next Casing Depth 700.00 (ft)MD 700.00 (ft)TVD Collapse Resistance (psi) 7190.00 Internal Yield (psi) 7270.00 Joint Strength (psi) x 1000 1129.00 1,129,000.00 * Tensile Limits Body Yield (psi) x 1000 1858.00 1,858,000.00 * Tensile Limits API Drift Diameter (in) 10.625 Wall Thickness (in) 0.58 Fluid Properties: Material Wei ht g ppg Gradient psi/ft Mud Weight 9.20 0.478 psi/ft Anticipated Mud Wt Next Csg Pt. 13.00 0.676 psi/ft Calculated Bouyancy Factor @ Mud Wt: 0.86 Anticipated Cement Weight (ppg) 15.8 0.822 psi/ft Sea Water Gradient (ppg) 8.94 0.465 psi/ft Frac Gradient at Shoe(ppg) 16 0.832 psi/ft Frac Gradient at Next Casing Point 17 0.884 Gas -Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 °Io Fluid Drop for Collapse Calculation (Enter #). 55 0.55 e ~ Tensile Calculations: Weight in Air (Ibs) 6 821.00 Bouyant Weight in Mud (Ibs) 5,861.47 Maximum setting depth (ft) 15,724.23 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 165.52 In Air: = Jt Strength / (Wt ppf * set depth) (At proposed depth) Body Yield Safety Factor 272.39 In Air: =Body Yld / (Wt ppf * set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 387.19 Collapse Res / (Depth TVD * % Fluid Drop *(Mud B-up Grad -Gas Grad)) Collapse SF while cementing 212.48 Collapse Res /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 TD of next hole section (ND) for MASP calculations MASP (Maximum Anticipated Surface 541.80 (Frac Grad -Gas Grad)* Next Casing Set Depth (ND) Pressure) Top Burst Safety Factor 13.42 Tube burst rating /ASP Bottom Burst Safety Factor 13.50 (Int. Yld + Depth ND * 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 13.42 OK Bottom Burst 13.50 OK • II ID Lone Creek No. 3 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1 2 Bottom Burst 1.2 king Properties: OD: ght ppf: ~pling: Depth ft t Casing Depth 8 5/8" WC-50 32.00 STC 9 5/8" OD 700.00 (ft)MD 3200.00 (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) ~~Fluid Properties: 7.796 0.352 8 5/8" Surface Casing 700.00 (ft)TVD 3200.00 (ft)TVD 2440.00 3600.00 341.00 341,000.00 ''Tensile Limits 457.00 457,000.00 * Tensile Limits rv~a~Ciiai Weight ppg Gradient psi/ft Mud Weight 13.00 0.676 psi/ft Anticipated Mud Wt Next Csg Pt. 9.80 0.510 psi/ft Calculated Bouyancy Factor @ Mud Wt: 0.80 Anticipated Cement Weight (ppg) 15.8 0.822 psi/ft Sea Water Gradient (ppg) 8.94 0.465 psi/ft Frac Gradient at Shoe(ppg) 17 0.884 psi/ft Frac Gradient at Next Casing Point 17 0.884 Gas Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 'I% Fluid Drop for Collapse Calculation (Enter #). 55 0.55 Tensile Calculations: Weight in Air (Ibs) 22,400.00 Bouyant Weight in Mud (Ibs) 17,947.40 Maximum setting depth (ft) 10,656.25 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 15.22 In Air: = Jt Strength / (Wt ppf * set depth) (At proposed depth) Body Yield Safety Factor 20.40 In Air: =Body Yld / (Wt ppf * set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 17.83 Collapse Res / (Depth ND * % Fluid Drop *(Mud B-up Grad -Gas Grad)) Collapse SF while cementing 9.79 Collapse Res /Depth ND * (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 TD of next hole section (TVD) for MASP calculations MASP (Maximum Anticipated Surface 2,476.80 (Frac Grad -Gas Grad)* Next Casing Set Depth ND Pressure) Top Burst Safety Factor 1.45 Tube burst rating /ASP Bottom Burst Safety Factor 1.58 (Int. Yld + Depth ND * Seawater Grad) /ASP Summary of: 8 5/8" Safety Factors Body Yield 20.40 in air "Tensile" OK Joint Strength 15.22 in air "Tensile" OK Collapse 17.83 OK Collapse 9.79 while cementing OK Top Burst 1.45 OK Bottom Burst 1.58 OK • i II ID Lone Creek No. 3 Min. Safety Factors To Be Used: Body Yield: Jt. Strength: Collapse Collapse While Cementing Top Burst Bottom Burst Casing Properties: Size OD: 5 1/2" Grade: J-55 Weight ppf: 17.00 Coupling: LTC Set Depth ft 3200.00 (ft)MD Next Casing Depth 3200.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) 4.767 Wall Thickness (in) 0.304 ~~Fluid Properties: 5 1/2" Production Csg 1.5 1.8 1.5 1.5 1.2 1.2 3200.00 (ft)TVD 3200.00 (ft)TVD 4910.00 5320.00 247.00 247,000.00 * Tensile Limits 329.00 329,000.00 * Tensile Limits nnateria~ Weight ppg Gradient psi/ft Mud Weight 9.80 0.510 psi/ft Anticipated Mud Wt Next Csg Pt. 9.80 0.510 psi/ft Calculated Bouyancy Factor @ Mud Wt: 0.85 Anticipated Cement Weight (ppg) 15.8 0.822 psi/ft Sea Water Gradient (ppg) 8.94 0.465 psi/ft Frac Gradient at Shoe(ppg) 17 0.884 psi/ft Frac Gradient at Next Casing Set Point 17 0.884 Gas Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 Fluid Drop for Collapse Calculation (Enter #) 55 0.55 Tensile Calculations: Weight in Air (Ibs) 54,400.00 Bouyant Weight in Mud (Ibs) 46,248.32 Maximum setting depth (ft) 14,529.41 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 4.54 In Air: = Jt Strength / (Wt ppf * set depth) (At proposed depth) Body Yield Safety Factor 6.05 In Air: =Body Yld / (Wt ppf * set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 7.85 Collapse Res / (Depth TVD * % Fluid Drop *(Mud B-up Grad -Gas Grad)) Collapse SF while cementing 4.31 Collapse Res /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 TD of next hole section (TVD) forASPcalculations MASP (Maximum Anticipated Surface 2, 476.80 (Frac Grad -Gas Grad)* Next Casing Set Depth (TVD) Pressure) Top Burst Safety Factor 2.15 Tube burst rating /ASP Bottom Burst Safety Factor 2.75 (Int. Yld + Depth TVD * Seawater Grad) /ASP Summary of: 5 1/2" Safety Factors Body Yield 6.05 in air "Tensile" OK Joint Strength 4.54 in air "Tensile" OK Collapse 7.85 OK Collapse 4.31 while cementing OK Top Burst 2.15 OK Bottom Burst 2.75 OK NOTE TO FILE Aurora Gas, LLC Diverter Waiver Request Lone Creek #3 (203-062) Aurora Gas, LLC (Aurora) has applied for an exception to 20 AAC 25.035(c)(1)(B) 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 sizes for the surface interval in this well 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. Lone Creek #3 is being drilled as a gas well with a planned TD of 3150'. The surface hole will TD at 700'. This well is located ~1 mile NE of Lone Creek #1 drilled in 1998. Lone Creek #1 was completed and Gas was encountered in the surface hole intervals of Lone Creek #1. the surface hole on the #1 well was drilled to about 1000'. Care had to be used to avoid swabbing the well which is a prudent practice drilling any surface hole section. Lessons learned on the #1 well were employed on the #2 well. It is interesting to note that the diverter regulations changed between the drilling of the 2 wells. The #1 well employed a 10" diverter line while drilling a 12-1/4" hole, a practice that has not been allowed under the new regulations. This request is similar to that for the Kaloa #2. 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 [...] the variance provides at least equally effective means of diverting flow away from the drill rig [...]. I recommend approval of Aurora's request based on the file review conducted. Thi approval is specifically for Lone Creek #3. Tom Maunder, E Sr. Petroleum Engineer April 15, 2004 G:\common\tommaunder\Well Information\By Subject\BOP-Diverter\Waivers\040415- note Lone Creek #3 diverter line.doc ~ f t ~~ ~ } ~ ti~ ,~ ..~ d•.-:. r ~~ , FRANK H. MURKOWSKI, GOVERNOR ALASSA OIL A1~TD GAS COI~TSERQATIOAT CODII-IISSIOI~T 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 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Request for Waiver of Diverter Requirements at 20 AAC 25.035 (c)(1)(B) Lone Creek #3 (PTD 203-062) Dear Mr. Jones: We have received your request for exception to the Diverter requirements at 20 AAC 25.035 (c) (1)(B) for the drilling of Lone Creek #3. You have requested this exception due to decrease in the tubular and hole sizes planned for the well. 20 AAC 25.035 (c)(1)(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 10-1/4" 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 [...]. Your request to employ a 10" diverter line while drilling either 10-5/8" or 10-1/4" hole for Lone Creek #3 is approved. This approval is specifically for Lone Creek #3. • Lone Creek #3 (PTD 203-062) April 16, 2004 Page 2 of 2 Si el , J Orman hai cc: Duane Vagan Fairweather E&P • • ti Aurora Gas, LLC www.aurorapower.com April 16, 2004 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7~ 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 ZO AAC 25.035(c}(1)(B) as required for drilling of Lone Creek Na. 3 (PTD# 203-062). Dear Mr. Norman: Aurora Gas, LLC has submitted under separate cover, a Sundry Application reflecting proposed changes in the wellbore geometry of Lone Creek No. 3, PTD # 203-062. Based on the change in well design, Aurora at this time requests a waiver on 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 he 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" .582" wa1171.8# LSS with a drift ID 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 ID bit. The diverter that Aurora intends to use has a 10" gate valve and flow line. Aurora intends to use a 10-'/4" bit or 10-5/8" bit to drill the surface hole. The largest possible surface hole size will be 10-5/8" in diameter which is due to constraints induced by the ID of the 11- 7/8" conductor. Aurora. is confident they 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 OH and diverter line size is ~10 in2 with a 10-5/$" bit (13% larger) and ---4 in2 using the 10-1/a" bit (5% larger). 2. Good recent well records are available from the drilling of offset wells Lone Creek No. 1 and Lone Creek No. 2 to correlate pressure trends. 3. Goad 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 Page 2 Lone Creek No. 3 Diverter Waiver Contd... In retrospect, the original well-bore design was permitted fora 12-1/4" surface hole, which required the drilling of a pilot hole. The cross-sectional flow area difference between the 12-'/a" 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, AU~OIZA ~rAS, LLC °ti :'~~ r ~~Edward Jones f Executive Vice President, Operations and En~ineerin~ cc: Duane Vaagen Andy Clifford • r FRANK H. MURKOWSKI, GOVERNOR Re: Lone Creek No. 3 Aurora Gas LLC Permit No: 203-062 Surface Location: 565' FSL, 276' FWL, S8, T12N, R11W, SM Bottomhole Location: 565' FSL, 276' FWL, S8, T12N, R11W, SM Dear Mr. Jones: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Unocal assumes the liability of any protest to the spacing exception that may occur. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the. Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, ~~ Randy uedrich Commissioner BY ORDER Q)F,THE COMMISSION DATED this- day of June, 2003 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section STATE OF ALASKA ALAS~IL AND GAS CONSERVATION CO~SSION PERMIT TO DRILL 20 AAC 25.005 i~, 1 a. Type of work [X ~] Drili [ ] Redrill 1 b. Type of wel [ ]Service [X ]Development Gay [ ]Single Zone [ X] Multiple Zone Re-Ent Dee en Ex lorato Strati ra hic Test Develo ment Oi 2. Name of Operator Aurora Gas LLC. 5. Datum Elevation (DF or KB 10. Field and Poo 290' AMSL DF Moquawkie Gas Field 3. Address 1029 West Third Ave. Suite 22C 6. Property Designatior ~ Anchors e, Alaska. 99501 -~6~SBt1~(,'- 4. Location of well at surface ASPY = 2610642, ASPX = 273849. i 7. Unit or Property Name 11. Type Bond (See 20 AAC 25.025) ' As-Staked 565' FSL, 276' FWL, S8, T12N, R11 W SM Lone Creek Letter of Credit At top of productive interva Same 8. Well Number Number NZS 429815 3 Lone Creek No. At total depth Same 9. Approximate spud date .Amount $200,000 15-Ma -03 12. Distance to nearest property lint 13. Distance to nearest wel 14. Number of acres in property 15. Proposed depth (MD and TVD 276' > 1 mile to Lone Creek No. 1 603. 3200' MD TVD 18. To be completed for deviated wells 17. Anticipated pressure {see 20 AAC a5.03b (e) (z)} Kick Off De th Maximum Hole An le Maximum surface 1120 At total depth ND 1472 psi 18. Casing Program Setting Depth Size S cifications To Bottom C2uanti of Cement Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD include sta a data Driven 13 318" 54.5 K-55 Welded 90' 0 0 90' 90' No cement, driven 121!4" 9 5l8" 38 K-55 LTC 700' 0 0 700' 700' 45 Bbls 15% excess 8 1/2" 7" 23# J-55 LTC 3150' 0 0 3150' 3150' 43 Bbls 12.5 "G" Lead w/ 20% OH Excess 8~ 44 Bbls 15.8 "G" Tail wl15% OH Excess 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented MD TVD Structural Conductor Surface Intermediate Production `' ((''""~~ Liner R~Cj~i V ~L.~ APR Q 9 2003 Alaska Oil & Gas Cons. Commission Anchorage Perforation depth: measured tNe V@rtical 20. Attachments [ X] Filing Fee (X] Property Plat [ X] BOP Sketch [ X] Diverter Sketch [ X] Drilling Program Driliin Fluid Pro ram Time vs De th Plot Refraction Anal sis Seabed Re rt 20AAG25.050 Re . Contact Engineer NamelNumber.• J. Edward Jones / 713-977-5799 Prepared By NameMumber.• Duane H. Vaagen 1258-3446 21. I hereby rfY tt~the foregoin s t e and correct to the best of my knowledge 9 Si ned ~ ~ Title (/ / G~ /" ~" ! i' ~ ~r/n~ Date ~ ~~ Commission Use Only Permit ber Number Approval Date See cover letter 2173 "' Z,. -Z. ZD /O3 "' DD forother re uirements Gonditions of Approval: Samples Required: [ ]Yes o Mud Log Required [ ]Yes No Hydrogen Sulfide Measures: [ ] Yss No Directional Survey Req'd [ ] Yss ~(J o / Required Workin Pressure for ROPE: [ ] 2M, [ ] 3M, [ ] 5M, [ ] 10M, [ ] 15M T}., et!rs~q~ O~y ~ other: 30~ Qs~ ~d~ E~cs~ S u rr>~ . by order of /Q ~~ roved B f 1~' °~- Commissioner the commission Date Form 10-401 Rev. 12-01-85 ~__.~ f ~~ , ~ 6 0' IGINAL Submit In~'friplibate Aurora Gas, LLC. Drilling Program: Lone Creek No. 3 Lone Creek No. 3 Drilling Program 1. File and insure all necessary permits and applications are in place. 2. 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. 3. Notify AOGCC and pertinent agencies when ready to start drilling operations. 4. Rig up diverter (see attached diagram) and mud loggers. Test and calibrate all PVT and gas sensor equipment. 5. Prepare mud system, weight up to ~9.5 ppg. 6. Dri118 1/2" hole to 700 ft, using 8 1/2" mill-tooth bit with 6 3/a" stabilized BHA. Watch for gas in shallow coals and sands. Increase mud weight as needed to 9.8 - 10 ppg. 7. POOH, LD 8 '/2" bit, PU 12 '/4" hole opener, open hole to 700 ft. Condition hole for running 9 5/8" surface casing, POOH, LD 12 '/4" BHA. 8. Run and cement (new) 9 5/8" 36 #/ft, K-55 LTC surface casing at 700' 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 tail cement slurry. 9. RU and test 11" 3M BOP stack and SM choke manifold (see attached diagram). Test stack and surface equipment to 3000 psi. Pressure test casing to 2000 psi. or as required on approved permit. 10. PU 8 %2" mill-tooth bit, RIH with 6 3/a" DC's and 3 '/2" DP to float collar. Drill out float equipment and shoe. Drill ~20' OH. Pull back into shoe and perform FIT with MWE to 17.5 ppg, record results. 11. Condition and circulate mud system, build mud weight to 9.5 ppg., and be prepared to weight up more if required. Do not exceed fracture gradient determined in step 10! 12. Proceed to drill ahead, 8 %z" 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. 13. Drill to TD at 3200 ft maximum, depending on lithology encountered. 14. Short trip and condition hole as needed for running wireline logs. 15. 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 loggin suite to be decided. Gm~ ~~~~- .~-~~~ ~- ~v rres~~ °~ ~--=~ 16. RD wireline, RIH with dnlhng BHA as before to TD. Circulate and condition `~' z.z • ° 3 ~~-~~~:~~~J hole for running casing. 17. INSURE all cementing equipment, casing accessories, and casing running equipment is on location and functional. POOH, LD BHA, rack back DP. 18. RU casing equipment /crew, make up shoe joint with shoe and float collar, baker- lockingboth to joint during make-up. Install 7" pipe rams for casing. 19. RIH with (new) 7" 23 #/ft J-55 casing, installing centralizers per attached program. Run casing to 3150', or as determined by OH logs. Keep pipe moving when casing is at TD and while waiting for cementers to get hooked up. 20. 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. Tail slurry to be of Aurora Gas LLC. Page 1 of 6 Rev. 1.4 04-April-2003 Aurora Gas, LLC. ~ Lone Creek No. 3 Drilling Program sufficient volume to cover desired perforating intervals. While pumping cement, reciprocate pipe a minimum of 20 feet until displacement is finished. Land casing in tension and WOC. 21. RD cementers, check annulus and casing for pressure. Nipple down stack and cut casing. 22. Install 11" X 7 1/16" tubing spool, 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 RIH with DP to top of float collar. Circulate out mud and cement with high-vis sweeps as necessary. Swap mud system over to clean filtered KCI. POOH LD DP and casing scraper. 23. RU lubricator for wireline work. Change out 3 %2"pipe rams with rams for 2 7/8" work string. Pressure test all. 24. PU wireline BOP's, lubricator and perforating guns, RIH to depth as determined from OH logs and perforate. Watch for pressures in casing after shooting. POOH, LD perf gun. 25. RU and RIH 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 /retrievable type packer w/sealbore assembly, millout extension, profile nipple, crossovers and sand exclusion screen assembly. Packer is to be 75 ft minimum above upper-most screen. RIH and hang off (depth to be determined by depth of perforations). POOH with workstring, RIH with 3%2" 9.2# 8rd Mod 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: Lone Creek No. 3 will be accessible via gravel road from Lone Creek No. 1 site. The road was originally built by the Superior Oil Company when the nearby Chuit State exploration wells were drilled. 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 either be staged from Tyonek Contractors yard or one of several existing well sites Aurora is currently re-developing. Personnel can be flown into either the Tyonek or Beluga airstrips, both of which are 11 to 12 miles away, or an alternate airstrip at Shirleyville, which is approximately 8 '/2 miles distant. All sites are interconnected by an extensive gravel road system in the region. Crews will be housed at either Shirleyville or Beluga, pending room availability. Transportation to and from the work site will be via motor vehicle. Rig: Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Lone Creek No. 3 well. AWS 1 has been used previously for work on wells in the Nicolai Creek Field. Aurora Gas LLC. Page 2 of 6 Rev. 1.4 04-April-2003 Aurora Gas, LLC. ~ Lone Creek No. 3 Drilling Program The pits, BOP system and mud equipment configuration will be similar to that used for previous work. Pressure Considerations: From offset wells in the immediate area and actual pressure data from the nearby offset well Lone Creek No. 1, maximum anticipated bottom-hole pressures should not exceed 1550 psi at 3150 ft. Pressures measured at the Lone Creek No. 1 well indicated a gradient of ~.46 psi/ft with abottom-hole pressure of 1100 psi recorded at 2400 ft. For this reason, permission is requested to limit casing test pressures to 2000 psi. Maximum anticipated surface pressures "HASP" can be calculated by subtracting the gas gradient of .11 psi/ft from pore pressure gradient of .46 psi / ft and multiplying by the total TVD depth. =>MASP = (.46 - .11) * 3200 = 1120 psi 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 rheologies and make recommendations. Drilling Fluid Properties While Drilling Surface 12'/4" Hole Section to 700': 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 Drilling Fluid Properties While Drilling 8 %2" Hole Section to 3200': Beluga and Tyonek Formations Base Fluid 5%KCL Density 9.3 - 9.5 ppg PV 22 - 30 YP 20-30 API Filtrate < 10 Total Solids 15 - 25 Polymer mud system Drilling Fluid Handling System: Shale Shaker, Desilter, Centrifuge, Ditch Magnets, PVT monitors Aurora Gas LLC. Page 3 of 6 Rev. 1.4 04-April-2003 Aurora Gas, LLC. ~ Lone Cre• o. 3 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. Lone Creek No. 3, 13 3/8" Conductor Analysis and Cementing Program The conductor for Lone Creek No. 3 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. Lone Creek No. 3, 9 5/8" Surface Casing Analysis and Cementing Program The 9 5/8" surface casing will be cemented in fully from the proposed set depth of 700' to surface with a 15.8 ppg "G" tail cement system. Cement S.. s~ Tyne Cement Weigh ppg) Volume e % Excess Primary "G" 15.8 45 bbls @ 15% Lead cement system may utilize alias-Block type additive to minimize potential for gas entrainment and or channeling. Please see attached 9 S/8"surface casing analysis and specifications. Lone Creek No. 3, 7" Production Casing Cementing Program The 7" production casing will be cemented in fully from the proposed set depth of 3150' 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 are isolated with 15.8 ppg "G"cement. Cement System Type Cement Weight (ppg) Volume (a~ % Excess Lead "G" 12.5 43 bbls @ 20% OH Tail "G" 15.8 44 bbls @ 15% OH Please see attached 7"production casing analysis and specifications. Aurora Gas LLC. Page 4 of 6 Rev. 1.4 04-April-2003 Aurora Gas, LLC. • Lone Creek No. 3 Drilling Program Drilling 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 of H2S 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, inter-bedded between the sands, gravels and shale's that make up the Beluga and Tyonek formations. Drilling into a coal seam will appear to be a drilling break 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 maintain the proper weight and viscosity of your drilling fluid to properly remove the coals drilled up, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Nearby Well's: There are no known active wells in close roximity to Lone Creek No. 3. The nearest known well is Lone Creek No. ,.which is ~ 1 mile to the~a~t^ The Chuit State No. 1 and No. 2 well's, both o which are P&A'd are withi %2 mile. j ~ Other: Sticky bentonitic clays, boulders, lost returns & differential sticking w/ overbalanced muds (+12.Sppg) and gas influx while cementing. Aurora Gas LLC. Page 5 of 6 Rev. 1.4 04-April-2003 Aurora Gas, LLC. Lone Creek No. 3 Drilling Program Lone Creek No. 3 Summary of Drilling 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 TD. 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 LONE CREEK No. 1 WELL PLAN FOR ADDITIONAL INFORMATION. Aurora Gas LLC. Page 6 of 6 Rev. 1.4 04-April-2003 Lone Creek Unit #3 Lone Creek Field Proposed Logging Program Lo Run Depths Hole/Casin Tools E-Mail Prints Film/Se is Di ital OH1 1000-2900' 8-1/2" PEX {AIT/SP/GR/CNL/TLD) PDS/LAS 8 1 CMR RFT CH1 Surface-2900' 7" USIT/CCL/GR PDS/LAS 8 1 DSI RST?? 1-DLIS/PDS (CD) 7-LAS/PDS (Disk) • C 4/23/2003 Aurora Gas, LLC 030423 Aurora_W CI 2003 Wireiine Logging Program.xls II ID Lone Creek No. 3 13 3/8" Conductor Min. Safety Factors To Be Used: II Body Yield: 1,5 I Jt. Strength: 1.8 Collapse 1.2 Collapse While Cementing 1.2 ,Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size OD: 13 3/8" Grade: J-55 eight ppf: 54.50 Coupling: Welded Set Depth ft 95.00 (ft)MD 95.00 (ft)TVD Next Casing Depth 700.00 (ft)MD 700.00 (ft)TVD Collapse Resistance (psi) 1130.00 Internal Yield (psi) 2730.00 Joint Strength (psi) x 1000 514.00 514,000.00 * Tensile Limits Body Yield (psi) x 1000 853.00 853,000.00 * Tensile Limits API Drift Diameter (in) 12.459 all Thickness (in) 0.38 Properties: aterial Weight ppg Gradient psi/ft ud Weight 9.20 0.478 psi/ft ~ticipated Mud Wt Next Csg Pt. 10.00 0.520 psi/ft alculated Bouyancy Factor @ Mud Wt: 0.86 ~ticipated Cement Weight (ppg) 15.8 0.822 psi/ft ~a Water Gradient (ppg) 8.94 0.465 psi/ft ~ac Gradient at Shoe ppg) 16.5 0.858 psi/ft 'ac Gradient at Next Casing Point 16.5 0.858 as Gradient (psi/ft) 0.110 ud Backup Gradient ppg 8.95 0.465 Fluid Drop for Collapse Calculation (Enter #). 55 0.55 Tensile Calculations: eight in Air (Ibs) 5,177.50 Bouyant Weight in Mud (Ibs) 4,449.17 Maximum setting depth (ft) 9,431.19 In Air: = Jt Strength / Wt.ppf oint 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 ND' % Fluid Drop'(Mud B-up Grad -Gas Grad)) Collapse SF while cementing 33.39 Collapse Res !Depth Np ` {Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation oaxus Burst Calculations: Assumeseawaterbackupgradient„465ps/Rforburstdesignpurposes Assume worst case by using anticipated frac gradient for 7D of next hole section (TVD) for MASP calculations MASP (Maximum Anticipated Sufface 523.60 {Frac Grad -Gas Grad)' Next Casing Set Depth (TVD) Pressure) Top Burst Safety Factor 5.21 Tube burst rating /ASP Bottom Burst Safety Factor 5.30 (Int. vld + Depth ND 'Seawater Grad) /ASP Summary OF 13 3/8" Safety Factors Body Yield 99.28 in air "Tensile" OK Joint Strength 164.75 in air "Tensile" OK Collapse 60.85 OK Collapse 33.39 while cementing OK Top Burst 5.21 OK Bottom Burst 5.30 OK II ID Lone Creek No. 3 9 5/8" Surface Casing in. Safety Factors To Be Used: -dy Yield: 1.5 Strength: 1.8 -Ilapse 1.2 -Ilapse While Cementing 1.2 ~p Burst 1.2 -ttom Burst 1.2 Casing Properties: Size OD: 9 518" Grade: J-55 Weight ppf: 36.00 Coupling: LTC Set Depth ft 700.00 {ft)MD 700.00 (ft)TVD Next Casing Depth 3150.00 (ft)MD 3150.00 (ft)TVD Collapse Resistance (psi) 2020.00 Internal Yield (psi) 3520.00 Joint Strength (psi) x 1000 453.00 453,000.00 * Tensile Limits Body Yield (psi) x 1000 564.00 564,000.00 * Tensile Limits API Drift Diameter (in) 8.765 all Thickness (in) 0.352 Properties: -terial Weight ppg Gradient psi/ft -d Weight 10.00 0.520 psi/ft ticipated Mud Wt Next Csg Pt. 9.50 0.494 psi/ft ~Iculated Bouyancy Factor @ Mud Wt: 0.85 ticipated Cement Weight (ppg) 15.8 0.822 psi/ft a Water Gradient (ppg) 8.94 0.465 psi/ft ac Gradient at Shoe ppg) 16.5 0.858 psi/ft ac Gradient at Next Casing Point 17.5 0.910 -s Gradient (psi/ft) 0.110 -d Backup Gradient ppg 8.95 0.465 Fluid Drop for Collapse Calculation (Enter #). 55 0.55 ~ ! Tensile Calculations: Weight in Air (ibs) 25,200.00 Bouyant Weight in Mud (Ibs) 21,346.79 Maximum setting depth (ft) 12,583.33 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 17.98 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 22.38 In Air: =Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 14.76 Collapse Res / (Depth ND ` % Fluid Drop *(Mud B-up Grad -Gas Grad)) Collapse SF whine cementing 8.10 Collapse Res /Depth ND * (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calcula#ions: Assume seawater backup gradient .465psifftforburstdesignpurposes Assume worst case by using anticipated frac gradient for TD of next hole section (TVD) for MASP calculations MASP (Maximum Anticipated Surface 2, 520.00 (Prat Grad -Gas Grad)* Next Casing Set Depth ND Pressure) Top Burst Safety factor 1.40 Tube burst rating /ASP Bottom Burst Safety Factor 1.53 (Int. vld + Depth ND * Seawater Gred) t ASP Summary OF 9 5/8" Safety Factors Body Yield 17.98 in air "Tensile" OK Joint Strength 22.38 in air "Tensile" OK Collapse 14.76 bK Collapse 8.10 While cementing OK Top Burst 1.40 OK Bottom Burst 1.53 OK 1 ID Lone Creek No. 3 7" Production Casing in. Safety Factors To Se Used: ~dy Yield: 1.5 Strength: 1.8 >Ilapse 1.2 ~Ilapse While Cementing 1,2 ~p Burst 1.2 rttom Burst 1.2 Casing Properties: Size OD: 7" Grade: J-55 Weight ppf: 23.00 Coupling: LTC Set Depth ft 3150.00 (ft)MD 3150.00 (ft)TVD Next Casing Depth 3150.00 (ft)MD 3150.00 (ft)TVD Collapse Resistance (psi) 3270.00 Internal Yield (psi) 4360.00 Joint Strength (psi) x 1000 313.00 313,000.00 'Tensile Limits Body Yield (psi) x 1000 366.00 366,000.00 '` Tensile Limits PI Drift Diameter (in) 6.241 all Thickness (in) 0.317 JFluid Properties: iterial Weight ppg Gradient psi/ft id Weight 9.80 0..510 psi/ft ticipated Mud Wt Next Csg Pt. 9.80 0.51A psi/ft Iculated Bouyancy Factor @ Mud Wt: 0.85 ticipated Cement Weight (ppg) 15.8 0.822 psi/ft a Water Gradient (ppg) 8.94 0.465 psi/ft ~c Gradient at Shoe ppg) 17.5 0.910 psi/ft 3c Gradient at Next Casing Set Point 17 0.884 ~s Gradient (psi/ft) 0.110 id Backup Gradient ppg 8.95 0.465 Fluid Drop for Collapse Calculation (Enter #). 55 0.55 • Tensile Calculations: eight in Air (Ibs) 72,450.00 Bouyant Weight in Mud (Ibs) 61,593.58 Maximum setting depth (ft) 13,608.70 In Air: = Jt Strength / Wt.ppf oint Strength Safety Factor 4.32 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 5.05 In Air: =Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 5.31 Collapse Res / (Depth ND ; % Fluid Drop `{Mud B-up Grad -Gas Grad)) Collapse SF while cementing 2.91 Collapse Res /Depth ND * (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465psi/ftrorburstdesignpurposes Assume worst case by using anticipated frac gradient for TD of next hole section (TVD) forASPcaiculations MASP (Maximum Anticipated Surface 2, 520.00 (Frac Gred -Gas Grad)' Next Casing Set Depth (TVD) Pressure) Top Burst Safety Factor 1.73 Tube burst rating /ASP Bottom Burst Safety Factor 2.31 (Int. Yld + Depth ND "Seawater Grad) /ASP Summary OF 7" Safety Factors Body Yield 4.32 in air "Tensile" OK Joint Strength 5.05 in air "Tensile" OK Collapse 5.31 OK Collapse 2.91 while cementing OK Top Burst 1.73 OK Bottom Burst 2.31 OK Lone Creek No. 3 ~oquawkie Gas Field 3 1/2" 9.2# L-80 8rd Modified Coupling Production Tubing 13 3/8" 54.5# I Conductor Driven 80 - 90' :-~ Aurora Gas, LLC ~x Proposed Present Condition Will drill 8 1/2" hole to 700' MD and then run a 12 1/4" hole opener prior to running 9 5/8" casing. 12 1/4" Hole 700' MD (700) Packer Fluid: 02 Inhibited KCL Fluid above Pkr. 8 1/2" Hole Tyonek Production Perfs 2400 - 2800'. Exact intervals to be determined by logging 7" 23# J-55 LTC @ 3150' MD (TVD) Cemented to Surface . ,'., ~~. ~ •, ,r ~~~~~~i ~~. . 2.66" ID X-Nipple 1 Jt above packer 7" Permanent Packer W/seal assembly 3 1/2" Tubing Spacer w/XO's between packer and Screens Sand Exclusion Screens installed across Perforations. Size and type to be determined. 8 1/2" Hole toTD @ 3200' MD (3200' TVD) Lone Creek No. 3 Fairweather E8P Services Inc. Rev. 03 DHV 04-April-2003 DRAWING NOT TO SCALE Aurora WeU Service Rig No. 1: Proposed 3M BO~Configuration Bell Nipple with flow line to pits 3M Schaffer Annular Preventer 11" 3M Double Gate w/ 3/12" pipe rams installed. 3" SM Manual Valve (Kill Line) ~ 3'° 5M Hydraulic Valve (Kill Line) \_ ~ Fluid flow direction ~~ while reverse circulating SM Manual Valve (Choke Line) 3" 5M Hydraulic Valve ~' (Choke Line) 2" 3M Manual Valves On Wellhead Aurora Well Service BOP Fairweather E&P Services, Inc. Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale Aurora Well Service Rig No. 1 Proposed Choke / Kill~nifold Configuration All valves are 3" ra>~ at 5000 psi. Inlet from BOP Choke Line Inlet from Power Swivel (Reverse Circulation Mode) Output to Pits Bleed Flare Line to Open Flare#'~tt To Gas Buster '°Atmospheric Degasser" Aurora Well Service Choke Manifold Fairweather E8P Services, Inc. Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale Aurora Well Service Ri No. l; Pro osed Surface Diverter S stem g P Y Bell Nipple Flow Line to Pits Fill Line 13-5/8", 5000 psi WP Annular Preventer Hydraulically Operated 10" Knife Gate Valve 13-5/8", 5M Drilling Spool /Mud Cross 10°° Diverter Vent Line 13 3/8" Conductor Pipe with 13-5/8", 5000 psi WP Flange welded on top Aurora V1fe11 Service Diverter Fairweather E&P Services, Inc. Rev. 3 DHV 10-Feb-2003 Drawing Not to Scate ~~OFAjq iii P .. s ~..•'' '~" ~I ~ '~ •,M. SCOTT McLANE~ .. ~~, ~`~r~'•.• 4928-S ~~~~ ~~~o~~~ ~; -~~~ AS STAKED LONE GREEK NO. 3 COPT. A ALT. A) Surface Location 2 ~f ~ FT. FWL i S~( SS S18 Sl~f I ~ f~ SCALE 1 inch = 500 ft. o soo Aso Iaao PROTRACTED sEcTiON s TOWNSHIP 12 NORTH RANGE 11 WEST SEWARD MERIp1AN ALASKA RID N:2ro1O642.OOO RID E:2~3849.~OO ATITUDE: Col°08'22.010" ONCsITUDE: -151°iCa'46.948" LI=v. 384.8 FT. NOTI=S i) BASIS ~ COORDINATES: NCsB COBS STATION "KEN I" NAD2~ 2) BASIS OF ELEVATION: NAVD8o8 3) SECTION LINE OFFSETS DERIVED FROM TI-1EORETICAL PROTRACTED SECTION CORNER VALUES 4) ALASKA STATE PLANE ZONE 4 NAD2~ LONE CREEK NO. 3 (OPTION A ALTERNATIVE A) Consulting Group SURFACE LOCATION IV~cLane Testing APPLICANT: ENGINEERING/MAPPING/SURVEYING/7ES11NG P.O. BOX 468 SOLDOTNA, AK. 99669 -^4.,,,.. VOICE: (907) 283-4218 FAX: (907) 283-3265 <~~~ EMAIL: msmciane®mclanecg.com PROJECT NO. DRAWN BY: DATE: OFFSETS: LOCATION: 033008 MSM 04/04/03 276' FWL SEC. $ TOWNSHIP 12 NORTH RANGE 11 WEST 565' FSL SEWARD MERIDIAN, ALASKA • .=~F. )f € ice. ~ ~~! t ~~ lls; t~ ~ ~--, r°~ AIa~SBA OITi A1~D t][~~7 CONSERQATI011T CODII-IISSIOI~T June 18, 2003 Ms. Lydia Miner Section Manager Exploration, Production and Refineries Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, AK 99501 • FRANK H. MURKOWSKI, GOVERNOR 333 W. 7"' AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 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 #1 B, #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 '/4-mile wide (see map, below). Long Lake Unit #1 is located on a separate structure approximately 4 miles to the west. T12N.R12W T12N,R11 I _~_ _ i I ___ I I Moquawkie Field 3E 3, ~ I ~ Simpco E. = i ~vloquawkie t i + Long Lake Unit 1 W. Moquawkie 1 ~_ +- Simpco M oquawkie 1 i 6 I Mobil Moquawkie 1 i I_ I . Moquawkie _ Tyonek Res~ rve 1 Simpco Moquawkie R 2 I 2 M ~quawkie 44-& 0 t mile ~~ ~-T ~ nek Reserve; B 1 Scale i , Simpco ~Caldachabun t 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. 1 W 12 7 Lone T12N,R g Creek 3 (propo 1 I g sed) 13 19 Lone Creek 17 1 18 24 19 20 21 25 Lone Creek 2 30 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 B and #2 wells, and the proposed #9 well. 4 • • 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 #1 B, #2, and #3 (see map, below) were examined. Atime-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/akpaaes/ADMIN/c~c/homeogc.htm. Nicolai Creek State #1 and #1 A; Nicolai Creek Unit #1 B, #2, and #9 The proposed Nicolai Creek Unit #9 well, and the existing Nicolai Creek State #1, #1A and Nicolai Creek Unit #1B 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 #1 B, #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' ND subsea) and they produced dry, clean gas with no associated oil. i Nicolai Ck U 3 24 I ~ 20 ,. 21 ~ 22 Nicolai Ck U 5 ! ~, Nicolai CI~ Unit 7 (proposed ) Nicolai Creek Field 27 25 __ ,-.Nicolai Ck Dri (pro osed k U~if`1 B ~-_ Nicolai Ck N' lai Ck St 1A U2 Nicolai Ck St 1 r Nicolai Ck U 6 Nicolai Ck 32 (~ 4 33 34_ I Nicolai Creek Basemap Oil shows in Nicolai Creek State #1 are below 6025' (-5777' TVD subsea). These the well file, showed "no oil accumulations." restricted to the Hemlock Formation sands were tested, but according to 5 • • 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 #1A 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 B and #9 will produce gas from the up-dip portions of this same block. Neither #1, #1A, 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 • • 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 2a Albe 27 Si Kaloa 1 ~, Kaloa Z (proposed) pco Kaloa 1~~ z5 T11N,R12W Kaloa Area Basemap 7 V • • 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' ND 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 Oil and Gas Update ~ 3 '~ June 16, 2003 Pipeline System near Valdez. This facility provides the source for the Valdez Marine Terminal (VMT) raw water, potable and firewater needs. OPMP initiated this 30-day review on April 15, 2003 and issued the final determination on May 2, 2003 [17 calendar days in review]. Contact: Kaye Laughlin. Pre-Application Stage Kuparuk River Rehabilitation Plan: ConocoPhillips Alaska, Inc. proposes to restore the East and West Channels of the Kuparuk River to their approximate condition prior the spine road development. Contact: Kaye Laughlin. Aurora Gas LLC Projects: Aurora Gas proposes to conduct exploration for gas on a number of sites and a development project at one site during the summer of 2003. 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 apre-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 smile-long section of a new bike path along Dayville road. From Dayville Road, a trestle will extend about 1,000-feet northward to a fuel transfer dock. Petro Star plans construction of the buried pipeline to be concurrent with construction of the pedestrian path along Dayville Road Contact: Kaye Laughlin. Borealis Power Project: BPXA proposes to expand infrastructure to meet power demands of future satellite expansion in the western end of the Prudhoe Bay Unit and a possible tie-in with the Milne Point Unit power grid. The project would include a new 69 kV power line, a sub- station, and possible minor pad extensions. The power line would run from the Central Power Station to the L and V Pads in the end of the unit and possibly extended to Milne Point. Originally planed for the 2003-2004 winter season, BP notified OPMP that the project has been deferred for another year. OPMP held apre-application meeting on Apri19. 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 Aurora Operations Subject: Aurora Operations Date: Fri, 06 Jun 2003 09:58:31 -0800 From: Glenn Gray <Glenn_Gray@dnr.state.ak.us> Organization: Alaska Department of Natural Resources To: Tom Maunder <tom maunder@admin.state.ak.us> CC: Steve Davies <Steve_davies@admin.state.ak.us>, Randy Ruedrich <randy_ruedrich@admin.state.ak.us>, bill penrose <bill@fairweather.com> Tom: At a preapplication meeting held on April 17, 2003, Fairweather discussed a number of proposals for gas exploration and development projects on the West side of Cook Inlet for Aurora Gas LLC. Although the Office of Project Management and Permitting has not received a Coastal Project Questionnaire for any of the projects, it appears that some of the projects will not need an RCMP 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. l 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 Aurora Logging Progam ~~ ~~„~~ 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(a?_fairweather.com Office: (907)258-3446 Cell: (907)240-1107 Name: 2003 Wireline Logging Program.xls 2003 Wireline Lodging Pro rag m.xls Type: Microsoft Excel Worksheet (application/vnd.ms-excel); Encoding: base64 Name: 2003 Mudlogging Program.xls 2003 Mudlo ing Pro rag m.xls Type: Microsoft Excel Worksheet (application/vnd.ms-excel) Encoding: base64 • Lone Creek Unit #3 Lone Creek Field Proposed Logging Program Lo Run Depths Hole/Casin Tools E-Mail Prints Film/Se is Di ital OH1 1000-2900' 8-1/2" PEX (AIT/SP/GR/CNL/TLD) PDS/LAS 8 1 CMR RFT CH1 Surface-2900' 7" USIT/CCL/GR PDS/LAS 8 1 DSI RST?? 1-DLIS/PDS (CD) 7-LAS/PDS (Disk) 4/23/2003 Aurora Gas, LLC 030423_Aurora_W_CI_2003 Wireline Logging Program.xls 2003 Program Mudlogging Requirements Proposed Logging Program Nicolai Ck 9 Lon Lake 1 Lone Ck 3 West Mo uawkie 1 Kaloa 2 Nicolai Ck 7 Interval 200-620' 620-2300' 3052~t653' 200-1000' 1000-2900' 2515-3550' 200-1050' i 1050-3700' 200-750' i 750-2750' Mudloggers 2 2 1 2 2 2 2 2 2 2 Sample Catchers As Needed As Needed Not Needed As Needed ~ As Needed Nat Needed As Needed As Needed As Needed As Nee Sample Frequency 30' 10' None 30' 10' None 30' 10' 30' 10' FID Gas Detection Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Lithology Description Yes Yes No Yes Yes No Yes Yes Yes Yes PVT Monitoring Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Flow Monitoring Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Rig Function Monitoring ? ? ? ? ? ? ? ? ? ? Cuttings 1-UnwashedNVet; 3-WashedlD None 1-UnwashedNVet; 3-WashedlD None 1-UnwashedlWet; 3-WashedlD 1-UnwashedNUet; 3-WashedlD Show Report Generation As Needed? As Needed? None As Needed? As Needed? None As Neetletl? As Neetletl? As Needed? As Needed? Dairy Log & Report E-mail, fax or FTP E-mail, fax or FTP E-mail, fax or FTP E-mail, fax or FTP E-mail, fax or FTP E-mail, fax or FTP Final Log & Report 8 8 8 8 8 8 8 8 8 8 Sepia or Film 1 1 1 1 1 1 1 1 1 1 Digital 8 (CD) 8 (CD) 8 CD) 8 CD 8 CD 8 CD Camp Accommodations Provided b Aurora Provided b Aurora Provided b Aurora Provided b Aurora Provided b Aurora Provided b Aurora Equi ment Trans ortation Provided b Aurora Provided b Aurora Provided b Aurora Provided b Aurora Provided b Aurora Provided b Aurora • Aurora Gas, LLC 4123!2003 2003 Mudlogging Program.xls 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information /Needs Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications -Additional Information /Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today) . Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. • Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 Steve davies~admin.state.ak.us Name: 030418 Aurora W CI Project_Deficiencies_Email.doc 03041$ Aurora W CI Protect Deficiencies Email.doc Type: WINWOIZD File (application/msword) Encoding: base64 • • 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 AAC 25.055 (d), which can be found on the Internet at: http://www.state. ak. us/IocaUakpa~es/ADMIN/o gc/art 199.htm. b. Designation of Operator and Notice of Change of Ownership forms must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. These forms can be obtained from AOGCC's website at: http://www.state.ak.us/locaUak~a~es/ADMIN/o~c/homeo~. 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 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 • • 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) aspacing 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 Apri117, 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 CIRI. Jun 1998: Mobil and CIRI designate Anadarko as operator for 518, T12N, R11W. 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 CIRI 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 CIRI lease C-061500, which is 518, T12N, R11W. 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 maybe 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 maybe 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) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well maybe 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 maybe 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 4 2003 Proposed Cook Inlet Basin Proj...ns - itional Information /Needs Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications -Additional Information / Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned: Aurora Power to confrim the email address, and it appears to be correct. So, 1'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, no# just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve_davies@admin.state.ak. us Name: 030418 Aurora_W_CI_Project_Deficienci 030418 Aurora W CI Project Deficiencies Email.doc Type: WINWORD File (application/msword) Encoding: base64 1 of 1 4/21/2003 8:59 AM RE: Lone Creek #3 • Subject: RE: Lone Creek #3 Date: Wed, 16 Apr 2003 12:08:19 -0800 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.ak.us> Tom: Per your request, the following applies. I'll respond in the order of the questions below. 1. Yes, we have a formal meeting tomorrow afternoon with DGC, ADF&G, COE, DNR and TLO to discuss this and other wells in Aurora's program. In regards to Lone Creek No. 3, we are hoping they give the green light to proceed as the only disturbance will be pad construction. No wetlands are being crossed and access will be via road constructed to drill the Chuit State wells years ago. Based on the meeting tomorrow, we will obtain all permits necessary. One thing we do know we need is a survey for a wetlands determination, site suitability and for archaeological or cultural resources. Another permit application submitted is for the Kaloa No. 2. I am not so sure we will even get to this as we need a bridge. By the time we get through Corp of Engineers and ADF&G, the odds are it will not happen. 2. Wast® will be handled as last year, and the following is applicable for the entire multi-well program this summer. Brines and muds wiB 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. 1 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 well to disposal. This is one of the back-burner wells, but I think we will find that we really need a disposal well. The proposed Lead Slurry design calls for a yield of 2.1 cf/sack. 4. Attached is tentative outline of work progression. This may have been pushed back now as we are not moving the rig across Inlet until the 2nd of May. We are working on a Gantt chart and will forward a copy as soon as we have it ready. Thank you please call if you need more information or clarification. Duane Vaagen Fairweather E&P Services, Inc. -----Original Message----- From: Tom Maunder [mailto:tom maunder[a~admin.state.ak.usi Sent: Wednesday, April 16, 2003 10:52 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. 1 of 2 4/16/2003 3:48 PM RE: Lone Creek #3 ~~ ~~ 1--Is 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?? 1 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 Aurora Gas POD Well Schedule.doc Type: WINWORD File (application/msword) Encoding: base64 2 of 2 4/16/2003 3:48 PM ~~Aurrora Gas, L C www.aurorapower.com April 7, 2003 Oil and Gas Commissioners Alaska Oil and Gas Conservation Commission 333 West 7~' Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: Lone Creek No. 3 Dear Commissioner(s), RECEIVED APR 0 9 20D3 Alaska ail & bas Cons. Carnrnission Anchorage Aurora Gas LLC hereby applies for a Permit to Drill, a prerequisite for drilling the grass- roots well, Lone Creek No. 3. The well will be located onshore ~ 8 miles northeast of Granite Point and ~ 6 miles northwest of the Village of Tyonek. Access will be via the road system originally installed to drill the Chuit State No. 1 and the Chuit State No. 2, wells drilled by Superior Oil in the 1960's. A drill site will be constructed directly adjacent to the original road and approximately 1 mile north of the Lone Creek No. 1 well. Upon receipt of all necessary permits and approvals, contractors will clear the location of overgrowth and build a gravel pad for the drill site. The 13-3/8" conductor will be driven and the rig, Aurora WeII Service No. 1, will be rigged up over the well to commence drilling operations. Aurora plans to begin drilling operations on May 15th, 2003. Pertinent information in and attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill - 3 copies. 2) Fee of $100.00 payable to the State of Alaska. 3) A plat map and information detailing the surface location and proposed bottomhole location 20 AAC 25.050 (c)(2). 4) Diagrams and description of the BOP equipment to be used as required by 20 AAC 25.035 (a}(1) and (b). 5) The drilling fluid program, in addition to the requirements of 20 AAC 25.033 are attached. 6) A copy of the proposed drilling and completion program, procedures and operational considerations. OPIGINAL 10333 Richmond Avenue, Suite 710 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220 • Anchorage, Alaska 99501 • (907) 277-1003 • Fax (907) 277-1006 Commissioner(s) Page 2 7) Aurora Gas LLC. does not anticipate the presence of H2S in the formation to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during sidetracking, drilling and completion operations. 8) A Summary of Potential Well Hazards. 9) Pressure Information 10} The following are Aurora Gas LLC's designated contacts for reporting responsibilities to the Commission. 1) Completion Report Duane Vaagen, Project Engineer (20 AAC 25.070) (907) 258-3446 2) Geologic Data and Information Andy Clifford, Vice President (20 AAC 25.071) (713) 977-5799 3) Well Records, Testing and Production Reporting (20 AAC 25.070} _ Ed Jones, Vice President (713) 977-5799 If you have any questions or require additional information, please contact the undersigned at (713) 977-5799, or Duane Vaagen at (907) 258-3446. Sincerely, AURORA GAS, LLC J. Edward Jones Vice President, Operations and Engineering Enclosures cc: Duane Vaagen Andy Clifford OP161NAL ~$l'I~~IL~RsE~P~.~Nl~ PRODU N SERVICES INC. /GENERAL ACCOUNT 10867 ~ O VENDOR I.D. NAME PAYMENT NUMBER CHECK DATE OUR WUCHER NUMBEFI YOUR VOUCHER NUMBER DATE AMOUNT AMOUNT PAID DISCOUNT WRITE•OFF NET S1oo.oo Sloo.oo So.oo So.oo S1oo.o0 COMMENT FIRST NATIONAL BANK Z O H G T FAIRWEATHER EXPLORATION of arleHORAGE & PRODUCTION SERVICES INC. ANCHORAGE, AK 99501 GENERAL ACCOUNT 89-6/1252 -1 P.O. BOX 103296 .DATE AMOUNT ANCFIORAGE, AK 99510-3296 4 / 9/2003 S1oo . o 0 PH. (907) 25&3446 One Hundred Dollars And OO Cents PAY TOTHE STATE OF ALASKA AOGCC ORDER 333 WEST 7TH AVE SUITE 100 OF ANCHORAGE AK 99501 _ _ _ __ Nr ~~ ~~~-~~ ~ ~~ ~~~ ~~ AUTHORIZED SIGNATURE ~~ ~~ II'0 L086 7~I' ~: L 2 5 20D060~ 0 L 1 2 8 2 3 011' ~~~~` I~~Fi ~~PG1~'A~N~ PRODUCTION SERVICES INC. /GENERAL ACCOUNT 10867 -y O Q 6 7 51N321;. , •. ~~ TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ~ PTD# ~~ ~D~p ~~ CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS MULTI The permit is for a new wellbore segment of LATERAL ezisting well , Permit. No, API No. (If API number Production should continue to be reported as last two (2) digits a function of the original API number stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(f), all (PH) records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 - 70/80) from. records, data and logs acquired for well (name on permit). SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing ezception. iCompany Name) assumes .the liability of any protest to the spacing ezception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Rev: 07/10/02 C\jody\templates WELL PERMIT CHECKLIST Company AURORA GAS LLC Well Name: LONE CREEK 3 Program DEV Well bore seg ^ PTD#:2030620 Field & Pool MOQUAWKIE. UNDEFINED - 528500 Initial ClasslType DEV! 1-GAS GeoArea 820 Unit ONOff Shore 9n_ Annular Disposal ^ Administration 1 Permit-fee attached____________________ __Yes__ ____-_- 2 Lease number appropriate___--__--__________________________ ____No__- _____Properlease number isC-61395, Changed on 10-401,__________-__--_--__- ----------- 3 Unique well-name and number ------ - - - - - - - - - - - -- - - - - -- - - - - - - - - - - - - -Yee - _ _ _ _ - _ Previous Lone Creek 3 permit (2Q¢144) was withd[awn on 10111!2000.. - - _ - . _ - ------------------ 4 Well located inadefnedpool______________________________-_-_ ----No___ ___-_POOlnotyet defined.________--_ 5 Well located properdistance_f[omdrillingunit.boundary...----------__ __--Yes-- ----------------------------------------------------------------, - 6 Welt located proper distanee_f[om-other wells_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Offset Chun State 1 and 2_explocatory wells were drilled and-P&A'ed-in 1962._ _ - _ _ - _ _ _ _ 7 Sufficient acreageayailableindrillingunit________________________--_ _--_Yes__ -__--_--__-____________-_--__-__ ----------------------------------------- 8 If deviated, iswellboreplatincluded_______________________________ ____ NA__ _____Vertical_well__-____--_____-___________----_________-__--____ ------------ 9 Operator only affected party- - _ - _ _ _ - _ _ - _ Yes - - - - _ - -Aurora Gas LLC is operator; Con_ocoPhillipslAnadarko a[eW1O's_in this_lease and-all offset leases, - _ _ _ - - - - 10 Operato[hasappropriate_bondinfarce----------------------------- ----Y~-- ------------------------------------- ------------------------------ --- 11 Pe[m-it-eanbe issued without conservation order___________----------- ----Yes-- ----------------------------------------_------------------------_-- - Appr Date 12 Pe[mitcanbeissuedwithoutadminist[ativ_eapprgval___-__-______________ ___Yes-- _____-________________- -------------------------------------------------- SFD 6/2312003 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strataauthgrkzedby_InjectionOrder#(pat_10#incomments)- (FQr_NA___ ________________________-_-__-___--__--____________--_------__---_____ 15 All wells within1l4_mileareaofreviewidentified(forservicewellonly)____________ ___IJA--- --------__-______________.---------- ------------------------------------- 16 Pre-produced- injector; duration of pre-p[oductign less_than_3 months_(For service well_onl y) _ _ NA_ _ _ _ _ - ---------------------------------------------------------------------- 17 ACM_P_F_inding of Consistency_has been issued_for_this project_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ tJA_ _ _ _ _ _ 6-20.2003:_ per Rob Mintz, ACMP consis#encydetermination not needed prior to approval of permit to drill. _ _ - - _ Engineering 18 Condu_cto[string_provided_______--____________________________ ___Yes__ __________________-__--_--______________-__---_ ------------------------- 19 Surface casing-protects all known_USDWS - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ 9-5!$"Surface Casing at 709'-MD1TVp and7" prodpction ca-sing at315Q' MDl1'VD wiU becemented to_surfaee, - _ 20 CMT_voladequatetocirculateonconductor_&surf_csg-__--_--___.____-___ _-_Yes__ ___________________________________________________________-_--_---____ 21 CMTvoI_adequate_t4tie-inlongstringtosurfcsg_________________________ ___Yes__ ___--Aurora intends to cementp[oductionst[ingtosurface._-__--____________--_________-_--- 22 CMT will coyer all knownp[oductiyehorizons_-_______________________ __Yes_- --_--_--__--__-___--_ --------------------------------------------------- 23 Casing designsadegnateforC,T,B&_pe[mafrost---------------------- ---Yes-- ----------------------------------------------------------------------- 24 Adequate tankage or reserve pit _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes Rig is equipped with Skeels pits, Noreserve pit planned.- Per email, bnnelmud_disposalvio Env_iro-Tech, _ _ - _ - - 25 1fa_re-drill,has-a-10-403 forabandQn_mentbeenapproved__________________ ___NA___ ___-______________--__-__-__ -------------------------------------------- 26 Adequakewellboreseparationp[oposed______________________________ ___Yes-- _-___Nearestwellsa[e 112 mile-distant.------_.-____-________-----------_- ------------- 27 Ifdiverterrequired,doesitmeet_rQgulations___________________________ ---Yes__ --__-Plan toempl_oy10"diverterline_andd[i118-112"_pilothole,_________--_-----------_-___--_- Appr Date 28 Drilling fluid_prQgram sehematic_& egs~iplist adequate. - - Yes - _ - - _ - -Formation pressures estimated-f[om Lone Creek #1(1 mile away).. BHP est @ $.8 EMW, plans fo[ 8.3 to_ 10,0. _ - TEM 4121/2003 29 BOPEs,dotheymeet_regulation_____________________________--_ _-_Yes__ -___MASPCaleulated at 1120psi._-____ -------------------------------------------- 30 BOPEpress rating Appr-opiate; test to_(puf prig in comments) _ Yes - - _ - - - - Plan to test to 3000 psi, well in excess of_MASP, - _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 31 Choke manifold complies-wIAPI_I2P-53(May$4)_____-_________-__-_--- __-Yes__ ___________________________ ---------------------------------------------- 32 Work will occu[withoutoperationshutdown____________________________ ___Yes-_ __-__-_______________.__--_________-__________--_--------_ ------------- 33 Is presence-of H2S gas.probable - - - - - NO- - - - - - - - - - - - - - - - - - - - 34 Mechanical condition of wells within AOR verified (For service well only) _ _ NA_ _ - ------------------------------------------------------------------------- Geology 35 Permit_can be issued w!o-hyd[ogen_sulfide measures - - - - - - - - - - - - - - - - - - - - - - - -Yes No [ecord of_H2S in region; however, detectors will be installed on rig.. - _ -------------------- 36 Data_presented on-potential gverpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes - _ _ - _ Nearby Lone Creek 1_ (located t mile SW_onsame structure) gradient is 0.46 psili# (8,8 ppg EMW), Appr Date 37 Seismic analysis-of shallow gas zones- - - - - - - - - - - - - - - - - - - - NA_ _ _ _ _ _ _ _ _ - _ well will be drilled with-9.3 to 9,5_ppg m_ud. SFD 4115/2003 8 eabed condition survey -(if off shore) - - - - - - NA _ _ _ _ _ _ _ _ - -- ---- ----------------------- - - - - - - - - - - - - - - - - - - - 39 .Contact namelphone for weekly progress reports [exploratory onlyj_ - NA_ _ _ _ Geologic C(o~m(missioner: Engineering Public Date: Date Commissioner: Commissioner Date Vertical well: inclination onl surve re wired. D cuttin s sam les not re wred as cuttin s have been collected in three Y Y q ry 9 P q~ 9 wells that lie whin 1 mile of this proposed well. ~~ ~ ~~ / ~ G t Eil W