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Home My WebLink About203-071 e e Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. <10'3 - 071 Well History File Identifier Organizing (done) ~wo-sided 1111111111111111111 D Rescan Needed III 1111111111111111 RESCAN ~olor Items: D Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, NofType: D Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: Date (g/ :17 þ~ Date (g I:J. 7/0 to 3 D Other:: Mf ,~IIIIIIIIIIIIIIIIIVV1f BY: ~ 151 Project Proofing BY: ~ BY: + ~ = TOTAL PAGES 0/ <? (Count does not include cove~ 151 p Scanning Preparation Production Scanning Stage 1 Page Count from Scanned File: --!!J.-9- (Count does include cover sheet) Page Count Matches Number in Scanning pr¡."ration: -t.L- YES BY ~ Date 1ri(:J-7¡00 Stage 1 If NO in stage 1, page(s) discrepancies were found: YES 11I1111111111111111 NO rVìf 151 NO BY: Maria Date: 151 11111111111I1111111 Scanning is complete at this point unless rescanning is required. ReScanned 11111111111I111111I BY: Maria Date: 151 Comments about this file: Quality Checked 11111111111I111111I 10/6/2005 Well History File Cover Page. doc • • i 1 ~ ~ ~ 11 ~J o3io~~zoos DO NOT PLACE ~.... or ~Sa ~.~. iTt+'~_ .~~ l ANY NEW MATERIAL UNDER THIS PAGE F:1LaserFiche\CvrPgs_InsertsiMicro6lm Marker.doc 1a. Test: l:J Initial U Annual U Special 1b. Type Test: U Stabilized U Non Stabilized l:::J Multipoint o Constant Time o Isochronal o Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC July 16, 2004 203-071 3. Address: 6. Date TO Reached: 12. API Number: 1400 West Benson Blvd, Suite 410, Anchorage, AK 99503 July 6, 2004 50- 283-20104-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 1308' FNL,1706' FEL, S26, T11N, R12W, SM 213.6' Kaloa #2 Top of Productive H~NED MAY· 2 9 2007 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): Same 3,600' Kaloa Gas Field Total Depth: 9. Total Depth (MD + TVD): Same 3,720' 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 260774.49 y- 2566864.64 Zone- 4 NIA C-61393 TPI: x- Same y- Same Zone- 4 16. Type of Completion (Describe): Total Depth: x- Same y- Same Zone- 4 Sand Control Screens below packer across casing perforations. 17. Casing Size Weight per foot, lb. 1.0. in inches Set at ft. 19. Perforations: From To 5-1/2" 17 bl/ft 4.892" 3,715' 3-3/8"HC HMX 3,522-3552 18. Tubing Size Weight per foot, lb. 1.0. in inches Set at ft. 3,250-3,330, 3,200-3,220, 2-7/8' 6.5 Ib/ft 2.441 Screen @ 3,152' 3,158-3,178 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 3,079 NIA None 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): [] Tubing 0 Casing 89 FO 1,564 psia @ Datum 3,136' TVDSS Assume psi a 25. Length of Flow Channel (L): Vertical Depth (H): Gg: I % CO2: % N2: % H2S: Prover: I Meter Run: I Taps: 3,355' 3355' 0.11 0 0.84 0 NA 3.068" Flange 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice Size (in.) Size (in.) psig Hw FO psig FO psig FO Hr. 1. 3.068 X 1.75 1371 60 3 hrs. 2. 3.068 X 1.75 1357 45 2 hrs. 3. 3.068 X 1.75 1223 45 3 hrs. 4. 3.068 X 1.75 1302 40 3 hrs. 5. X Basic Coefficient -J Pressure Flow Temp. Gravity Factor Super Compo Rate of Flow No. (24-Hour) hwPm Pm Factor Fg Factor Q1 Mcfd Fb or Fp Ft Fpv 1. 110.65 Calculated using Daniel Sr. 5,431 2. 11 0.65 Orifice Meter Readings 6,087 3. 110.65 7,359 4. 110.65 8,100 5. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT . . Temperature for Separator for Flowing No. Pr Tr z Gas Fluid T Gg G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc 1,448 pc2 2,096,704 Pf 1,570 Pf2 2,464,900 No. Pt pf Pc2 _Pt2 Pw Pw2 PC2_PW2 Ps PS2 pr _PS2 1. 1,371 1,879,641 217,063 1,509 2,277.081 187,819 2. 1,357 1,841,449 255,255 1,503 2,259,009 205891 3. 1,323 1,750,329 346,375 1,483 2,199,289 265611 4. 1,302 1,695,204 401,500 1,471 2,163,841 301,059 5. 25. AOF (Mcfd) 44,251 Remarks: Calculated using Ryder Scott Software n 0.806896 I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ø~ Title ¡J1'1'. 6'''':;'''«-''7 J- f"'J~ Date '>1t.y'07 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ -J hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= -f1ïZ dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 . . "'............ .. .... .. "'.... . . . POINT NO. Test Data (Automatic) Q, Mcf/d SCPD BWPD FTP, Psi a WHT, of BHP, PSÎa COMMENT SHUT-IN 0 0 0 1,448 52 1,570 SIBHP 1 5,431 0 0 1,371 60 1,509 2 6,087 0 0 1,357 45 1,503 3 7,359 0 0 1,323 45 1,483 .- 4 8,100 0 0 1,302 40 1,470 These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. e e Page 1 of 1 2D3-Õ-7 ( Ed Jones From: Ed Jones Uejones@aurorapower.com] Sent: Wednesday, June 09,20041:19 PM To: Steve Davies Cc: Tom Maunder; 'Duane Vaagen'; Randy Jones Subject: Request to Cancel Permit to Drill #203-071 Because the location of the proposed Aurora Gas LLC-operated Kaloa #2 has been changed and a new Application for Permit to Drill has been filed for this new location, Aurora Gas hereby requests that the original approved Permit to Drill for this well, #203-071, be cancelled, to be replaced by the pending Permit for the new location. Please let me know if any further action iMuired by Aurora to cancel this approved Permit. Thanks, Ed Jones )' X I Ed Jones ~/~ Vice President l / Engineering & Operations / . i Aurora Gas, LLC í' F{ECEfVED JUN 09 Z004 Aiacka Oil 6/9/2004 -- e NOTE TO FILE Aurora Gas, LLC Diverter Waiver Request Kaloa #2 (203-071) Aurora Gas, LLC (Aurora) has applied for an exception to 20 AAC 25.035(c)(1)(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 size for the surface interval has been reduced. In the new plan, the maximum hole size possible is now 10-5/8", which gives a hole area 13% larger than the 10" diverter line cross-sectional area. It is Aurora's contention that the surface hole on the subject well can be safely drilled. This document considers Aurora's request and recommends approving it. Kaloa #2 is being drilled as a gas well with a planned TD of 3700'. The surface hole will TD at 620'. This well is located -120' from the Albert Kaloa #1 (AK#1) (167-031) which was drilled in 1968 and P&Aed in 1974. The AK#1 did produce gas from intervals near 3600', however sand production was experienced and it was not possible to keep the we II bore clean. According to the AK#1 mud log, surface casing in that well was set at 285' and cemented to surface. The surface hole section and the next hole interval were both "piloted" and sUbsequently opened after logging. The file records do not indicate any problems encountered drilling these intervals. Given the operations performed, the time necessary to drill, log, open and case the hole sections does not indicate many difficulties. Examination of the mud·log indicates that methane was first detected around 500' md which is slightly shallower than the planned surface casing depth. The minimum planned mud weight for this hole section is 9.5 with provisions to increase to 10 ppg if necessary. The rig is equipped with required mud pit monitoring equipment and since the rig will only recently have started up, an AOGCC Inspector will have witnessed the function testing of such equipment either on this well or one prior to it. The requirement to have a diverter line size greater than the initially drilled hole size is to prevent the diverter line from acting like a choke if a divert situation were to occur. With the hole and casing sizes originally proposed, Aurora rightly planned to drill a pilot hole. 12-1/4" hole would have given an area 50% larger than the diverter line. The Commission has previously approved drilling a 12-1/4" hole while using a 12" diverter line (hole area 4% larger than diverter line). For the new hole and casing sizes planned, the maximum difference in area is 13% with the likely difference being 5%. 20 AAC 25.035 (h) (2) allows the Commission to approve a variance from the diverter requirements if [...] the variance provides at least equally effective means of diverting flow away from the drill rig [... J. I recommend approval of Aurora's request based on the file review conducted. T~S appr.oval i.S SpeCifijl~Y for Kaloa #2. ~^v\~~~~L? Tom Maunder, PE Sr. Petroleum Engineer April 14, 2004 G:\common\tommaunder\ Well Information \By Subject\BOP- Diverter\ Waivers\040414- note Kaloa #2 diverter line. doc - - e (ffi~ ~~ e AI,ASIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 April 16, 2004 Mr. J. Edward Jones Executive Vice-President, Operations and Engineering Aurora Gas, LLC 1400 West Benson Blvd. Suite 410 Anchorage, AK 99503 Request for Waiver of Diverter Requirements at 20 AAC 25.035 (c)(l)(B) Kaloa #2 (PTD 203-071) Dear Mr. Jones: We have received your request for exception to the Diverter requirements at 20 AAC 25.035 (c) (l)(B) for the drilling of Kaloa #2. You have requested this exception due to decrease in the tubular and hole sizes planned for the well. 20 AAC 25.035 (c)(l)(B) requires that the drilled surface hole be equal to or less than the inside diameter of the diverter line. Providing a diverter line larger than the hole size prevents the diverter line from becoming a choke if a divert situation were to occur. As now planned, Aurora will set 11-7/8" conductor which will allow a maximum hole size of 10-5/8" to be drilled. It is planned to drill a 10-114" 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 [. . .]. e e Lone Creek #3 PTD 203-062 April 16, 2004 Page 2 of2 Your request to employ a 10" diverter line while drilling either 10-5/8" or 1 0-1/4" hole for Kaloa #2 is approved. This approval is specificaU Kaloa #2. cc: Duane Vagen Fairweather E&P e e ~(?Aurora Gas, L.L.C www.aurorapower.com April 12, 2004 RECEIVED APR 1 3 20D4 Alaska Oil & Gas Cons. Commission Anchorage Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Approval to Change Drilling Program Kaloa No.2 (pTD# 203-071) Dear Mr. Norman, Aurora Gas, LLC hereby submits an Application for Sundry Approval to change the well design covered by Permit to Drill #203-071. Aurora has modified its drilling program to reflect the following changes in wellbore geometry. Conductor: Original well design used 13-3/8" 54.5# K-55 welded. Will now use 11- 7/8" 71.8# USS limited service structural pipe with 0.582" wall thickness. The conductor will be driven as originally permitted. Surface Casing: Original well design used 9- 5/8" 36# K-55 LT&C. Will now use 8 5/8" 32# Wildcat 50, ST &C. Hole size will be 10-5/8" (possibly 1 O-W' if available) and original planned hole depth will be the same. Production Casings Original well design used 7" 23# J-55 LT&C. Will now use 5-W' 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 2) Casing analysis 3) Modified proposed wellbore schematic 10333 Richmond Avenue, Suite 710. Houston, Texas 77042. (713) 977-5799· Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503. (907) 277-1003. Fax (907) 277-1006 e e 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 enclosures cc: Duane Vaagen Andy Clifford T~ <-~~~ c:;, ~s ~ S~~~> c:\' ~\\,(¿ C\'\Q ~. -\~\--\\~N:I;, \.. L.cc'\¿\:i'-SG.~ \~'-.\ CDts\\"~ \CL~~\'.-œ .-+,,~ \\\ì./'Þ\\ca;J\...."'\C\'ö\ ú? P~Q\S '-\c \:)X- (). \)¿'~.y\. L -8"0 S'\Q;c¿j<èb~""ë>«~ ö "" b~,~\-. R(C c.o\\c.rC;Q.~\~Q \s \JQ'~( \"\~,, ~ t'<Q.\\f"'~~ %~ .. f\~" ~ ~ \o..\~ \e f'Q$¿XQ G"'-CéC¿ I ß -.).\ c~, \ \c."!< ~S.é .~è:.{\ C1 QQ~~'\ ~\\ G-C;\ ':> \'O.~ c~ c~\\-\ cc, \ \,,0 \X'c-\'J i-:S:\~ ~c., CbSh:~ ~~ \·,,-....:)<ëo,.\·~·r ·~o c,o~ç\.\,'-'( .\"-G: \')~'t~~:>..\-. ~ \~C( C> \=0, -'\-"'-<2 <i<;5/G '< ~ sì "'S .\ k ':J'<Ù~ \ ":> \, R-\ ~ ~ ~ leI'" 11: (J ff V-.~. 5:;... '\k- '-.)û..\ () Q:: s D~ ~ 0 \~-\ ~ Cc) \ \o~c:;c a. \Q:: \Nt\- \..- \ "'- 1..4 'û--t---,\ '" o'\'\ k", <C ') m!Je.. 'S. &.\~~c}. ~ -h~-A\(} Ñ1L \ \ '\ \--€. \,'(()í?"C:" sSJ ::-~-S\I'S> "'''- ~ (L \>'(Ö\,rL~\'\<ts. '>G~' C:, u;,,-\- -\-u <...... c...<,:~-\\~ \ \" ¡ "~tl \ \ c.a ",$ \ c\~va ,,"'-.s \.~ \-t \, ~ú '-.0 \:"'~\:> \<2- ~~Å"-t ~C~'ð ~? /J £~ 4kJ<-~v,J~c \' \::. ~ ( l '\ ~o Li 1. Type of Request: Abandon U Suspend 0 Operational shutdown 0 Perforate 0 Waiver 0 Annular Dispos. U Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 other 0 Change approved program 0 Put! Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Aurora Gas, LLC Development 0 Exploratory 0 203-071 3. Address: 1400 West Benson Blvd, Suite 410 Stratigraphic 0 Service 0 6. API Number: Anchorage, AK 99503 50-283-20104-00 7. KB Elevation (ft): 9. Wet! Name and Number: 220.5' Kaloa NO.2 8. Property Designation: 10. Field/Pools(s): C-61393 Kaloa 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): T~tal Depth iVD (ft): Effective Depth MD (ft): Effective Depth iVD (ft): Plugs (measured): Junk (measured): 0 0 0.0' P&A'd 0.0' P&A'd Surface NA Casing Length Size MD TVD Burst Collapse Structural Conductor 90' 117/8" 71.8# LSS 90 90 7270 psi 7190 psi Surface 620' 8 5/8" 32# WC-50 620' 620' 3600 psi 2440 psi Intermediate Production 3700' 5.5" 17# J-55 3700' 3700' 4910 psi 5320 psi liner Perforation Depth MD (ft): Perforation Depth TVD (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 I Suspended NIA NfA 12. Attachments: Description Summary of Proposal U 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 6/1/2004 on 0 Gas 0 Plugged 0 Abandoned 0 16. Verbal Approval: Date: WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact J. Edward Jones Printed Name G. r ~rd Jones Title Executive VP Operations 1 EngIneering Signature ·Z .J. V 1..-.. Phone 713-977-5799 Date q//2/¿()1/ // / ~// COMMISSION USE ONLY . (/ {/ Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .3 ¿JY- / ?d-~ Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 O\\~,-~ \ Ö- ?\>'\\J'\JC\\ S ~Q5- .dO S-CYì \ RECEIVED other: C\ \>? \'-1 APR 1 3 2004 Subsequent Form Re ~i\ <iÇJ,,~~ RIG I N A L Alaska Oil & Gas Cons. Commission Anchorage ~/~M '/ J / kttt./' COMMISSIONER BY ORDER OF Approv~d THE COMMISSION Date: ..f. . C/ ~ - .I " .. STATE OF ALASKA . A~ Oil AND GAS CONSERVATION COMM ION APPLICATION FOR SUNDRY APPROVAL 20 AAC 25 280 """- ,4-y Il L...\ ~ /~ (¡ f/\ aIJMS 8ft APR 2 e Well ID Kaloa No.2 11 7/S" Conductor Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 11 7/8 USS Ltd. 71.80 Welded 95.00 (ft)MD 620.00 (ft)MD COllapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness in 10.625 0.58 Fluid Properties: Material e 95.00 (ft)TVD 620.00 (ft)TVD 7190.00 7270.00 1129.00 1858.00 1,129,000.00 * Tensile Limits 1,858,000.00 * Tensile Limits Weight ppg Gradient psi/ft Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Point Gas Gradient (psi/ft) Mud Backup Gradient ppg 9.20 13.00 0.86 15.8 8.94 16 17 8.95 0.478 psi/ft 0.676 psi/ft 0.822 psi/ft 0.465 psi/ft 0.832 psi/ft 0.884 0.110 0.465 55 0.55 e e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 6,821.00 5,861.47 Maximum setting depth (ft) 15,724.23 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor (At proposed depth) Body Yield Safety Factor (At proposed depth) 165.52 In Air: = Jt Strength / (Wt ppf * set depth) 272.39 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 387. 19 Collapse Res / (Depth TVD " % Fluid Drop "(Mud Soup Grad - Gas Grad)) Collapse SF while cementing 212.48 Collapse Res / Depth TVD " (Cmt Grad - Soup Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TD of next hole section (TVD) for MASP calculations 479.88 (Frac Grad - Gas Grad)" Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 15.15 Tube burst rating / ASP Bottom Burst Safety Factor 15.24 (In!. Yld + Depth TVD " Seawater Grad) / ASP Summary of: 11 7/8 Safety Factors Body Yield 272.39 in air "Tensile" OK Joint Strength 165.52 in air "Tensile" OK Collapse 387.19 OK Collapse 212.48 while cementing OK Top Burst 15.15 OK Bottom Burst 15.24 OK e Well ID Kaloa No.2 8 5/8" Suñace Casing Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1 .2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 85/8" WC-50 32.00 STC 9 5/8" 00 620.00 (ft)MD 3750.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in 7.796 0.352 Fluid Properties: Material e 620.00 (ft)TVD 3750.00 (ft)TVD 2440.00 3600.00 341.00 457.00 341,000.00 * Tensile Limits 457,000.00 * Tensile Limits Weight ppg Gradient psi/ft Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Point Gas Gradient (psi/ft) Mud Backup Gradient ppg 13.00 9.80 0.80 15.8 8.94 17 17 8.95 0.676 psilft 0.510 psi/ft 0.822 psilft 0.465 psi/ft 0.884 psi/ft 0.884 0.110 0.465 55 0.55 e tit Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 19,840.00 15,896.27 Maximum setting depth (ft) 10,656.25 In Air: = Jt Strength I Wt.ppf Joint Strength Safety Factor (At proposed depth) Body Yield Safety Factor (At proposed depth) 17.19 In Air: = Jt Strength I (Wt ppf * set depth) 23.03 In Air: = Body Yld I (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 20.13 Collapse Res/ (Depth TVD > % Fluid Drop >(Mud B-up Grad - Gas Grad)) Collapse SF while cementing 11.05 Collapse Res/ Depth TVD > (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient. .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TO of next hole section (TVO) for MASP ca/culations 2,902.50 (Frac Grad - Gas Grad» Next Casing Set Depth TVD MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 1.24 Tube burst rating / ASP Bottom Burst Safety Factor 1.34 (Int. Yld + Depth TVD > Seawater Grad) / ASP Summary of: 8 5/8" Safety Factors Body Yield 23.03 in air "Tensile" OK Joint Strength 17.19 in air "Tensile" OK Collapse 20.13 OK Collapse 11.05 while cementing OK Top Burst 1.24 OK Bottom Burst 1.34 OK e WelllD Kaloa No.2 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1 .2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 51/2" J-55 17.00 LTC 3750.00 (ft)MD 3750.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness in 4.767 0.304 Fluid Properties: Material Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Set Point Gas Gradient (psi/ft) Mud Backup Gradient ppg e 51/2" Production Csg 3750.00 (ft)TVD 3750.00 (ft)TVD 4910.00 5320.00 247.00 329.00 247,000.00 * Tensile Limits 329,000.00 * Tensile Limits Weight ppg Gradient psi/ft 9.80 0.510 psi/ft 9.80 0.510 psi/ft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 17 0.884 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 e e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 63,750.00 54,197.25 Maximum setting depth (ft) 14,529.41 In Air: = Jt Strength I Wt.ppf Joint Strength Safety Factor (At proposed depth) Body Yield Safety Factor (At proposed depth) 3.87 In Air: = Jt Strength I (Wt ppf * set depth) 5.16 In Air: = Body Yld I (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 6.70 Collapse Res/ (Depth TVD " % Fluid Drop "(Mud B-up Grad - Gas Grad» Collapse SF while cementing 3.68 Collapse Res/ Depth TVD " (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TO of next hole section (TVO) for ASP calculations 2,902.50 (Frac Grad - Gas Grad)* Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 1.83 Tube burst rating / ASP Bottom Burst Safety Factor 2.43 (In!. Yld + Depth TVD " Seawater Grad) / ASP Summary of: 5 1/2" Safety Factors Body Yield 5.16 in air "Tensile" OK Joint Strength 3.87 in air "Tensile" OK Collapse 6.70 OK Collapse 3.68 while cementing OK Top Burst 1.83 OK Bottom Burst 2.43 OK e 2 7/8" 6.5# 8 Rd J-55 Tubing to 3100' Kaloa No.2 Proposed Configuration Drill 1 0 5/8" Hoie 2 7/8" X 5 W' annulus to be displaced over to inhibited packer fluid wI diesei freeze protect at surface following completion. Top Beluga ~ 700' Top Tyonek - 2000' 2 7/8" 6.5# 8 Rd J-55 Tubing 3100' - 3200 Tyonek Peñorations from ~ 3200' - 3600'. Exact Intervals to be determined by Open hole logging. Drill 7 7/8" Hole PBTD at 3665' Aurora Gas, LLC Summer 2004 Well Program Rev.3.1 e 11 7/8" 71.8# Structural Conductor to be driven to 90' 8 5/8" 32# WC-50 STC Surface Casing set at 620' Cement wI 14.5 ppg Gas-Block enhanced cement (- 35 bbls cmt @ Sliding Sleeve 1 joint above packer @ 3070' wI 2.313" X-Profile for ianding plug 5 W' Retrievable type Seal-bore Production Packer 90' above upper peñoration -3100' 2.313" XN-Profile 1 Joint below packer at-3130' Sand Exclusion Screen across all peñorations. All Screen sized to 5 W' casing. - 8 Jts Total. 5 W' 17# LTC J-55 Casing to 3700' MD (TVD) Cmtd wI 48 bb113.5 ppg Lead at 20 % and 72 bbls 15.8 ppg Tail at 20%(Top of Tail to extend to 1500' MD) 4/5/2004 e e urora Gas, LLC www.aurorapower.com April 12, 2004 Mr. John Nonnan, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Request for waiver of requirement to drill a pilot hole due to diverter outlet size versus hole size difference as stipulated in 20 AAC 25.035(c)(1)(B) as required for drilling of Kaloa No.2 (PTD# 203-071). Dear Mr. Nonnan, Aurora Gas, LLC has submitted under separate cover, a Sundry Application reflecting proposed changes in the wellbore geometry ofKaloa No.2, PTD # 203-071. Based on the change in well design, Aurora at this time requests a waiver to the requirement that a pilot hole be drilled, a requirement indicated in 20 AAC 25.035 (c)(l)(A & B) which states that the diverter outlet and line must be at least 16 inches in diameter or as large or larger than the diameter of the hole being drilled. The basis for the request is indicated below. Aurora will now use 11-7/8",0.582" wall, 71.8# LSS with a drift 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 ill bit. The diverter that Aurora intends to use has a 10" gate valve and flow line. Aurora intends to use a lO-W' or 10-5/8" bit, depending upon availabilities, to drill the surface hole. (The largest possible surface hole size will be 10-5/8" in diameter, due to constraints induced by the ill of the 11-7/8" conductor). Aurora is confident it can safely drill using the diverter / hole size configuration requested for the following reasons: 1. Aurora feels that due to the minimal difference between wellbore diameter and diverter line size, the surface hole section can be safely drilled without benefit of drilling a pilot hole first as was specified in the original approved PTD. The actual cross sectional flow area difference between OR and diverter line size is ~10 in2 (13% larger) with a 10 5/8" bit and ~4 in2 (5 % larger) using the 10 Y4" bit proposed. 2. Goodpressure infonnation is available in well records from nearby offset wells Albert Kaloa No. 1 and Simpco Kaloa No. 1 to correlate pressure trends. 3. Good understanding by rig and crew of drilling conditions which might be encountered. 10333 Richmond Avenue, Suite 710· Houston, Texas 77042. (713) 977-5799. Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503. (907) 277-1003. Fax (907) 277-1006 e e Page 2 Kaloa No.2 Diverter Waiver Contd... In retrospect, the original well-bore design was permitted for a 12-114" surface hole which required the drilling of a pilot hole. The cross-sectional flow area difference between the 12-W' hole and 10" diverter line was ~39.3 in2 (50% larger). . If you have any questions or require additional information, please contact the undersigned at (713)977-5799 or Duane Vaagen at (907)258-3446. Sincerely, AURORA GAS, LLC cc: Duane Vaagen Andy Clifford · lT~lTŒ (ill~ !Æ~!Æg)æ!Æ A I,ASIiA OIL AND GAS CONSERVATION COMMISSION J. Edward Jones Vice President Aurora Gas, LLC 1029 West 3rd Ave. Ste. 220 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: Kaloa #2 Aurora Gas, LLC Pennit No: 203-071 Surface Location: 987' FNL, 1669' FEL, S26, T11N, R12W, SM Bottomhole Location: 987' FNL, 1669' FEL, S26, T11N, R12W, SM Dear Mr. Jones: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659.:3607 (pager). Sincerely, BY ORDER OF THE COMMISSION DATED this~ day of December, 2003 cc: Department ofFish & Game, Habitat Section wlo encl. Department of Environmental Conservation wlo encl. .' STATE OF ALASKA ALASKAaL AND GAS CONSERVATION COMWSION ... PERMIT TO DRILL 20 AAC 25.005 tny)) IX ] Development Gas I ] Single Zone I X] Multiple Zone (Stratigraphic Test I j Development Oil 5. Datum Elevation (DF or KB) 10. Field and Pool 36' AMSl (oF) Kaloa Gas Field 6. Property Designation C-61393 7. Unit or Property Name Kaloa 8. Well Number Kaloa No. 2 9. Approximate spud date 1-Ju1-03 14. Number of acres in property 15. Proposed depth (MD and TVD) 3435 3750 17. Anticipated pressure {see 20 AAC 25.035 (e)(2)} Maximum surface 1238 pslg. At total depth (TVD) Setting Depth Top Bottom MD TVD MD TVD o 0 90' 90' o 0 620' 620' o 03700' 3700' 1a. Type of work IX] Drill I] Redrill 1b. Type of well I ] Service [ ] Re-Entry [ . ¡Deepen ¡ j Exploratory 2. Name of Operator Aurora Gas llC. 3. Address 1029 West Third Ave. Suite 220 Anchorage, Alaska 99501 4. location of well at surface ASPY = 2567105, ASPX = 260805 ASPZ4 *As Staked 987' FNl, 1669' FEl S26, T11N, R12W SM At top of productive interval Same At total depth Same 12. Distance to nearest property line 1002' 16. To be completed for deviated wells Kick Off Depth 18. Casing Program Size CasillQ 13318" 95/8" 13. Distance to nearest well 120' from P&A'd PanAm Kaloa No.1 Maximum Hole Anale Hole Driven 121/4" 8112" Specifications Grade CouP/ina lenath K-55 Welded 90' K-55 LTC 620' JoS5 LTC 3700' 7" Weiaht 54.5 36 23# 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Plugs (measured) feet feet feet feet Junk (measured) Casing length Size Structural Conductor Surface Intermediate Production liner Perforation depth: measured true vertical 11. Type Bond (See 20 AAC 25.025) Letter of Credit NZS 429815 Number Amount $200,000.00 1650psig Quantity of Cement (include staae data) No cement, driven 40 bbls 15.8 ppg "G" w/15% OH Excess 42 bbls 12.5 ppg "G"lead w/15% OH Excess & 57 bbls 15.8 ppg "G" Tail wI 15% OH Excess Cemented TVD MD RECEIVED APR 0 9 2003 Alaska Oil & Gas Cons. Commission Anchorage I X] Filing Fee [ X] Property Plat I X] BOP Sketch I X] Diverter Sketch I X] Drilling Program [ X] Drilling Fluid PrOQram r 1 Time vs Depth Plot r 1 Refraction Analvsis r 1 Seabed Report r 1 20AAC25.050 ReQ. Contact Engineer Name/Number: /--, J. Edward Jones I 713-977-5799 Prepared By NamelNumber: Duane H. Vaagen 1258-3446 21. ~~~:~rtify(Mt ~e fOregOinges tru; and correct to the ~~t ~f my kn<>;!)_.dgeþ '~0//~ ?!"U'~Þa-:> Title 1/ / // _ rr--/, I d//; / . Date 'I /7 / ¿J.3 / / '/ / Commission Use Only PermitþQurylber .2D3'_07/1";pl)Qumber 5D- ?Ð3- ?/ìIO'/~rv--. ~p~rp~~~!e See cover letter l/ I V &-C> ~ f· ~ I .-1-11 )!C'j for other requirement'" Conditions of Approval: Samples Required: I ] Yes I><f~o 'Mud log Required .,M'Yes ~o bY Hydrogen Sulfide Measures: I ] Yes XNo Directional Survey Req'd . I ¡ Yes þ(1ÍIo~ Requi~ Working Pressure for BO~E: I] 2M, -I] 3M, I] 5M, I] 10M, I] 15Mr;- 1jv:.f I~A. .ft'c-t'\. ".....,.!.J Oth~r:. ~~~ p;) \ ~~ V ~~ ~ ~J(è1{7 §i.J~ð· "tJ> Onglnal Slgn~ By by order of . :. _I " Sarah Pall!" Commissioner the commission Date / jilt; Jo '> Submit I'n Tlllplicate 20. Attachments Approved By Form 10-401 Rev. 12-01-85 OP i , L.. Aurora Gas, LLe. e Kaloa.. 2 Drilling Program Drilling Program: Kaloa No.2 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. Drill 8 1/2" hole to ~620 ft, using 8 1/2" mill-tooth bit with 6 %" stabilized BRA. Watch for gas in shallow coals and sands. Increase mud weight as needed to 9.8 - 10 ppg. 7. POOR, LD 8 W' bit, PU 12 W' hole opener, open hole to 620 ft. Condition hole for running 9 5/8" surface casing, POOR, LD 12 W' BRA. 8. Run and cement (new) 9 5/8" 36 #/ft, K-55 LTC surface casing at 620 ft and cement to surface. Shoe joint connection at shoe and float collar must be Baker- Locked. Cementing will be single stage with float collar and shoe installed using 15.8 ppg cement slurry. 9. RU and test II" 3M BOP stack and 5M choke manifold (see attached diagram). Test stack and surface equipment to 3000 psi. Pressure test casing to 2000 psi. or as required on approved permit. 10. PU 8 W' mill-tooth bit, RIH with 6 %" DC's and 3 W' DP to float collar. Drill out float equipment and shoe. Drill ~20' OR. Pull back into shoe and perform FIT with MWE, record results. 11. Condition and circulate mud system, build mud weight to 9.8 ppg, and be prepared to weight up more if required. Do not exceed fracture gradient determined in step 10! 12. Proceed to drill ahead, 8 W' 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 3750 ft maximum, depending on lithology encountered. 14. Short trip and condition hole as needed for running wireline logs. 15. POOR, rack back drillstring and RU wire1ine BOP's and lubricator and logging tools. Log cased hole section wlgamma ray sensor, Log OR section with logging suite to be decided. 16. RD wire line, RIH with drilling BRA as before to TD. Circulate and condition hole for running casing. 17. INSURE all cementing equipment, casing accessories, and casing running equipment is on location and functional. POOR, LD BRA, rack back DP. 18. RU casing equipment I crew, make up shoe joint with shoe and float collar, baker- locking both to joint during make-up. Install 7" pipe rams for casing. 19. RIH with (new) 7" 23 #/ft J-55 casing, installing centralizers per attached program. Run casing to ~3700 ft, or as determined by OR 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. While pumping Aurora Gas LLe. Rev. 1.4 Page 1 of6 4-April-2003 Aurora Gas, LLC. e KaloA. 2 Drilling Program cement, reciprocate pipe a minimum of 20 ft until displacement is finished. Land casing and WOC. 21. RD cementers, check annulus and casing for pressure. Nipple down stack and cut casmg. 22. Install 11" X 7 1/16" casing head, 7 1/16" X II" 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 KCl. POOH LD DP and casing scraper. 23. RU lubricator for wire1ine work. Change out 3 yz" pipe rams with rams for 2 7/8" work string. Pressure test all. 24. PU wire1ine 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 I retrievable type packer wlsealbore assembly, millout extension, profile nipple, crossovers and sand exclusion screen assembly. Packer is to be 75 ft minimum above top most screen. RIH and hang off (depth to be determined by depth of perforations). POOH with workstring, RIH with production tubing, space out and stab into packer, hang off in tubing head and lock down. Install blanking plug in profile nipple, Pressure test tubing to 2000 psI. 29. Install BPV at surface, nipple down and remove BOP stack. Install wellhead tree. RD and remove all rig equipment. 30. Prepare site for well testing and surface production facilities. 31. File completion reports with proper agencies. Site Access: Ka10a No.2 will be accessible via existing gravel roads built in the 1960's for drilling the nearby Pan Am Ka10a No. 1 and the Simpco Ka10a No. 1 wells. All major equipment and supplies will be barged across the Cook Inlet from the OSK dock in Nikiski to Tyonek for staging as required. Equipment will be staged from either Tyonek Contractors yard or one of several existing well sites Aurora is currently re-deve10ping. Personnel can be flown into either the nearby Shirleyville airstrip, a three mile drive, or the Tyonek airstrip which is approximately 7.5 miles away. An alternate site for embarkation will be the airstrip at Beluga, approximately 10 miles away. Crews will be billeted at either Shirleyville or Beluga, pending room availability. All sites are interconnected with an extensive road system for transport via vehicle. Rig: Aurora Well Service, Rig No.1 (A WS 1) will be used to drill the Ka10a No.2 well. A WS 1 has been used previously for work on wells in the Nicolai Creek Field. The pits, BOP system and mud equipment configuration will be similar to that used for previous work. Aurora Gas LLC. Rev. 1.4 Page 2 of6 4-April-2003 Aurora Gas, LLC. e KaZoa.. 2 Drilling Program Pressure Considerations: Based on test pressure information from the nearby Pan Am Ka10a No. 1 well, the following were maximum pressures recorded prior to production for fuel gas on the Spark Platform and for the Village of Tyonek. A maximum SIP pressure at surface of 1450 psi and a shut in BHP of 1580 psi were recorded for the production zone from 3516' - 3583'. This equates to a pressure gradient of .44 psi/ft, or mud weight equivalent of 8.46 ppg. This will require well drilling and completion operations to use fluids weighted from 9.0 - 9.2 ppg to maintain well control at final depth. Final surface pressures recorded after production and prior to plugging and abandonment indicated pressures ranging from 1350 - 1400 psi. Survey Program: The Kaloa No.2 well will be drilled as a vertical well. Wellbore surveys will be obtained at 500' intervals in accordance with rules laid out in 20 MC 25.050 (a) (1) & (2). Drilling Fluids: The drilling fluids are being furnished by MI Drilling Fluids. MI has extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor mud rheology and make recommendations. Attached is a copy ofMI's mud program. Drillin!! Fluid Properties While Drillin!! Surface 12 ~"Hole Section to 620': Beluga Formation Base Fluid 5% KCL Density 9.8 - 10 ppg PV 22-30 yP 20 - 30 API Filtrate < 10 Total Solids 15 - 25 % Gel & Polymer mud system Drillin!! Fluid Properties While Drillin!! 8 ~"Hole Section to 3750': Beluga and Tyonek Formations Base Fluid 5% KCL Density 9.0 - 9.2 ppg , PV 22 - 30 yP 20-30 API Filtrate < 10 Total Solids 15 - 25 % Polymer mud system Drillin!! Fluid Handlin!! System: Shale Shaker, Desilter, Centrifuge, Ditch Magnets, PVT monitors Aurora Gas LLC. Rev. 1.4 Page 3 of6 4-April-2003 Aurora Gas, LLC. e Kalo.. 2 Drilling Program Casing / Cementing Program: All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. All casing strings with the exception ofthe 13 3/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment and wiper plugs and centralizers installed as needed. Kaloa No.2. 13 3/8" Conductor Analvsis and Cementine Proeram The conductor for the Kaloa No.2 will be driven to - 90' or refusal. Joints will be welded and a drive shoe will be welded to the bottom joint. No cementing is required. Please see aUached Conductor Analysis with specifications. Kaloa No.2. 9 5/8" Surface Casine Analysis and Cementine Proeram The 9 5/8" surface casing will be cemented in fully from the proposed set depth of 620' to surface with a 15.8 ppg "G" cement system. Cement System Primary Type Cement Weight (ppg) 15.8 Volume @ % Excess 40 bbls @ 15% "G" The cement system may utilize a Gas-Block type additive to minimize potential for gas entrainment and or channeling. Please see aUached 9518" surface casing analysis. Kaloa No.2. 7" Production Casine Cementine Proeram The 7" production casing will be cemented in fully from proposed set depth of3700' to surface. A 12.5 ppg lead "G" cement followed with a 15.8 ppg "G" tail cement system will be used. This program is designed to insure the intended perforating / production intervals up to 1500' are isolated with 15.8 ppg "G" cement. Cement System Lead Tail Type Cement Weigllt (pPg) 12.5 15.8 Volume (âJ, % Excess 42 bb1s @ 15% OR 57 bbls @ 15% OR "G" "G" Please see aUached 7" production casing analysis. Aurora Gas LLC. Rev. 1.4 Page 40f6 4-April-2003 Aurora Gas, LLe. e KaZode. 2 Drilling Program Drillim! Hazards: Drilling in the South Central Region of Alaska offers its own challenges. Common known hazards are as follows: Shallow gas: Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record ofH2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level, the shale shaker and in the cellar . Coal Seams: The Cook Inlet region is rich in coal seams, interbedded between the sands, gravels and shale's that make up the Beluga and Tyonek 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 Mud Engineer. Nearby Well's: There are (2) wells within ~ mile ofthe proposed Ka10a No.2. These wells are the Pan-Am Kaloa No.1 which is P&A'd, and the Simpco Ka10a No.1, which is suspended. Neither well presents a proximity problem for drilling operations. II i/:x.A I j4-. /Þ4 IF / ;;. tv';~ 7-D ~ fl Other: Sticky bentonitic clays, boulders, lost returns & differential sticking wI overbalanced muds (+ 12.5ppg) and gas influx while cementing Aurora Gas LLe. Rev. 1.4 Page 5 of6 4-April-2003 Aurora Gas, LLe. e Kaloa.. 2 Drilling Program Kaloa No.2 Summary of DrillinCl Hazards POST THIS NOTICE IN DOGHOUSE ..J There is potential for abnormal pressured shallow gas. ..J There is potential for stuck pipe in coals encountered while drilling from surface to TO. Be extra vigilant while performing hole opener - run. ..J There is no H2S risk anticipated for this well. ..J Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. CONSULT THE "KALOA No.2" WELL PROGRAM FOR ADDITIONAL INFORMATION. Aurora Gas LLe. Rev. 1.4 Page 60f6 4-April-2003 e e WelllD Kaloa No. 2 13 3/8" Conductor Min. Safety Factors To Be Used: Body Yield: 1 .5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 13 3/8" J-55 54.50 Welded 95.00 (ft)MD 620.00 (ft)MD 95.00 (ft)TVD 620.00 (ft)TVD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 1130.00 2730.00 514.00 853.00 514,000.00 * Tensile Limits 853,000.00 * Tensile Limits 12.459 0.38 Fluid Properties: Material .. Weight ppg Gradient psi/ft 9.20 0.478 psi/ft 10.00 0.520 psi/ft 0.86 15.8 0.822 psi/ft 8.94 0.465 psi/ft 16 0.832 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 , Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Point Gas Gradient (psi/ft) Mud Backup Gradient ppg % Fluid Drop for Collapse ~ . -' , e e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 5,177.50 4,449.17 Maximum setting depth (ft) 9,431.19 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 99.28 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 164.75 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 60.85 Collapse Res / (Depth TVD ' % Fluid Drop '(Mud S-up Grad - Gas Grad» Collapse SF while cementing 33.39 COllapse Res / Depth TVD ' (Cmt Grad - S-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TD of next hole section (TVD) for MASP calculations 479.88 (Frac Grad - Gas Grad)* Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 5.69 Tube burst rating / ASP Bottom Burst Safety Factor 5.78 (Int Yld + Depth TVD ' Seawater Grad) / ASP Summary of: 13 3/8" Safety Factors Body Yield 99.28 in air "Tensile" Joint Strength 164.75 in air "Tensile" Collapse 60.85 Collapse 33.39 while cementing Top Burst 5.69 Bottom Burst 5.78 OK OK OK OK OK OK e WelllD Kaloa No.2 Min. Safety Factors To Be Used: Body Yield: 1 .5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 9 5/8" J-55 36.00 LTC 620.00 (ft)MD 3700.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 8.765 0.352 Fluid Properties: Material Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Point Gas Gradient (psi/ft) Mud Backup Gradient ppg % FlUid prop for CollapseCal6ulation (Enfêr#).' e 9 5/8" Surface Casing . 620.00 (ft)TVD 3700.00 (ft)TVD 2020.00 3520.00 453.00 564.00 453,000.00 * Tensile Limits 564,000.00 * Tensile Limits Weight ppg Gradient psi/ft 10.00 0.520 psi/ft . 9.50 0.494 psi/ft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 17 0.884 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 e e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 22,320.00 18,907.16 Maximum setting depth (ft) 12,583.33 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 20.30 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 25.27 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 16.67 Collapse Res / (Depth TVD ' % Fluid Drop '(Mud B-up Grad - Gas Grad» Collapse SF while cementing 9. 15 Collapse Res / Depth TVD ' (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TO of next hole section (TVO) for MASP calculations 2,863.80 (Frac Grad - Gas Grad)' Next Casing Set Depth TVD MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 1.23 Tube burst rating / ASP Bottom Burst Safety Factor 1.33 (In!. Yld + Depth TVD ' Seawater Grad) / ASP Summary of: 9 5/8" Safety Factors Body Yield 20.30 in air "Tensile" Joint Strength 25.27 in air "Tensile" Collapse 16.67 Collapse 9.15 while cementing Top Burst 1.23 Bottom Burst 1 .33 OK OK OK OK OK OK e WelllD Kaloa No. 2 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1 .8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1 .2 Casing Properties: Size 00: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 7" J-55 23.00 LTC 3700.00 (ft)MD 3700.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 6.241 0.317 Fluid Properties: Material Mud Weight Anticipated Mud Wt Next Csg pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Set Point Gas Gradient (psi/ft) Mud Backup Gradient ppg % Frùid Drop r "- .. -. JÌ.,~.'," . ... ff/."7\,;':" . '. e 7" Production Casing 3700.00 (ft)TVD 3700.00 (ft)TVD 3270.00 4360.00 313.00 366.00 313,000.00 * Tensile Limits 366,000.00 * Tensile Limits Weight ppg Gradient psi/ft 9.80 0.510 psi/ft 9.80 0.510 psi/ft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 17 0.884 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) Maximum setting depth (ft) Joint Strength Safety Factor Body Yield Safety Factor Collapse Calculations: Collapse Safety Factor Collapse SF while cementing Burst Calculations: MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor Bottom Burst Safety Factor Summary of: Body Yield Joint Strength Collapse Collapse Top Burst Bottom Burst It 85,100.00 72,348.01 13,608.70 In Air: = Jt Strength / Wt.ppf 3.68 In Air: = Jt Strength / (Wt ppf * set depth) 4.30 In Air: = Body Yld / (Wt ppf * set depth 4.52 Collapse Res / (Depth TVD' % Fluid Drop '(Mud B-up Grad - Gas Grad)) 2.48 Collapse Res / Depth TVD ' (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Assume seawater backup gradient, .465 psi/ft for burst design purposes Assume worst case by using anticipated frac gradient for TO of next hole section (TVO) for ASP calculations 2,863.80 (Frac Grad - Gas Grad)' Next Casing Set Depth (TVD) 1.52 Tube burst rating / ASP 2. 12 (Int. Yld + Depth TVD ' Seawater Grad) / ASP 7" Safety Factors 3.68 in air "Tensile" 4.30 in air "Tensile" 4.52 2.48 while cementing 1.52 2.12 OK OK OK OK OK OK e It WelllD Kaloa No.2 13 3/8" Conductor Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size 00: 13 3/8" Grade: J-55 Weight ppf: 54.50 Coupling: Welded Set Depth ft 95.00 (ft)MD 95.00 (ft)TVD Next Casing Depth 620.00 (ft)MD 620.00 (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 Wall Thickness (in) 0.38 Fluid Properties: Material Weight ppg Gradient psi/ft Mud Weight 9.20 0.478 psi/ft Anticipated Mud Wt Next Csg pt. 10.00 0.520 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 % Fluid prop forÇpllapse Calculation.(Enter #); 55 0.55 e e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 5,177.50 4,449.17 Maximum setting depth (ft) 9,431.19 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 99.28 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 164.75 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 60.85 Collapse Res / (Depth TVD - % Fluid Drop -(Mud B-up Grad - Gas Grad)) Collapse SF while cementing 33.39 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) for MASP calculations 479.88 (Frac Grad - Gas Grad)- Next Casing Set Depth (TVD) MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 5.69 Tube burst rating / ASP Bottom Burst Safety Factor 5.78 (Int. Yld + Depth TVD - Seawater Grad) / ASP Summary of: 133/8" Safety Factors Body Yield 99.28 in air "Tensile" Joint Strength 164.75 in air "Tensile" COllapse 60.85 Collapse 33.39 while cementing Top Burst 5.69 Bottom Burst 5.78 OK OK OK OK OK OK e . WelllD Kaloa No.2 9 5/StI Suñace Casing Min. Safety factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size 00: 95/8" Grade: J-55 Weight ppf: 36.00 Coupling: LTC Set Depth ft 620.00 (ft)MD 620.00 (ft)TVD Next Casing Depth 3700.00 (ft)MD 3700.00 (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 Wall Thickness (in) 0.352 fluid Properties: Material Weight ppg Gradient psi/ft Mud Weight 10.00 0.520 psi/ft Anticipated Mud Wt Next Csg pt. 9.50 0.494 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 Point 17 0.884 Gas Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 eyQ Fluid Dr'~foY<~(i)llâps~.CâIC\,lt~tìôr'r¡;t~nt~~~ 55 0.55 e It Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) 22,320.00 18,907.16 Maximum setting depth (ft) 12,583.33 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 20.30 In Air: = Jt Strength / (Wt ppf * set depth) Body Yield Safety Factor 25.27 In Air: = Body Yld / (Wt ppf * set depth Collapse Calculations: Collapse Safety Factor 16.67 Collapse Res / (Depth TVD . % Fluid Drop '(Mud Soup Grad - Gas Grad» Collapse SF while cementing 9.15 Collapse Res / Depth TVD . (Cmt Grad - Soup Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TD of next hole section (TVD) for MASP calculations 2,863.80 (Frac Grad - Gas Grad)' Next Casing Set Depth TVD MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor 1.23 Tube burst rating / ASP Bottom Burst Safety Factor 1.33 (Int. Yld + Depth TVD' Seawater Grad) / ASP Summary of: 9 5/8" Safety Factors Body Yield 20.30 in air "Tensile" Joint Strength 25.27 in air "Tensile" Collapse 16.67 Collapse 9.15 while cementing Top Burst 1.23 Bottom Burst 1.33 OK OK OK OK OK OK e WelllD Kaloa No.2 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.2 Bottom Burst 1.2 Casing Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 7" J-55 23.00 LTC 3700.00 (ft)MD 3700.00 (ft)MD Collapse Resistance (psi) Internal Yield (psi) Joint Strength (psi) x 1000 Body Yield (psi) x 1000 API Drift Diameter (in) Wall Thickness (in) 6.241 0.317 Fluid Properties: Material Mud Weight Anticipated Mud Wt Next Csg Pt. Calculated Bouyancy Factor @ Mud Wt: Anticipated Cement Weight (ppg) Sea Water Gradient (ppg) Frac Gradient at Shoe(ppg) Frac Gradient at Next Casing Set Point Gas Gradient (psi/ft) Mud Backup Gradient ppg .% Fluid'Oròp for:Ç'ot1~ÞSe ~cðtation(E*r1ft. e 7" Production Casing 3700.00 (ft)TVD 3700.00 (ft)TVD 3270.00 4360.00 313.00 366.00 313,000.00 * Tensile Limits 366,000.00 * Tensile Limits Weight ppg Gradient psi/ft 9.80 0.510 psi/ft 9.80 0.510 psi/ft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 17 0.884 psi/ft 17 0.884 0.110 8.95 0.465 55 0.55 e Tensile Calculations: Weight in Air (Ibs) Bouyant Weight in Mud (Ibs) Maximum setting depth (ft) Joint Strength Safety Factor Body Yield Safety Factor Collapse Calculations: Collapse Safety Factor Collapse SF while cementing Burst Calculations: MASP (Maximum Anticipated Surface Pressure) Top Burst Safety Factor Bottom Burst Safety Factor Summary of: Body Yield Joint Strength Collapse Collapse Top Burst Bottom Burst e 85, 100.00 72,348.01 13,608.70 In Air: = Jt Strength / Wt.ppf 3.68 In Air: = Jt Strength / (Wt ppf * set depth) 4.30 In Air: = Body Yld / (Wt ppf * set depth 4.52 Collapse Res I (Depth TVD " % Fluid Drop "(Mud S-up Grad - Gas Grad)) 2.48 Collapse Res I Depth TVD " (Cmt Grad - S-up Mud Grad) No lost CircuiationlEvacuation occurs Assume seawater backup gradient, .465 psilft for burst design purposes Assume worst case by using anticipated frac gradient for TO of next hole section (TVO) for ASP calculations 2,863.80 (Frac Grad - Gas Grad)" Next Casing Set Depth (TVD) 1.52 Tube burst rating I ASP 2. 12 (Int. Yld + Depth TVD " Seawater Grad) I ASP 7" Safety Factors 3.68 in air "Tensile" 4.30 in air "Tensile" 4.52 2.48 while cementing 1.52 2.12 OK OK OK OK OK OK loa No.2 Albert Kaloa Gas Field 27/8" 6.5# J-55 Srd Modified Coupling Production Tubing 13 3/8" 54.5# K-55 Conductor Driven 80 - 90' 121/4" Hole Top Beluga - 700' 9 5/8" 36#J-55 620' MD (TVD) Packer Fluid: 02 Inhibited KCl Fluid above Pkr. Top Tyonek: -2000' 8 1/2" Hole Tyonek Production Perfs -3200 - 3600'. Exact Intervals to be determined when logging. 7" 23# J-55 l TC @ 3700' MD (TVD) Cemented to Surface Kaloa No.2 8 1/2" Hole toTD @ 3750' MD (3750' TVD) Fairweather E&P Services, Inc. Proposed Present Condition Will Drill 8 1/2" Pilot Hole to 620' MD and then run a 12 1/4" hole opener prior to running 9 5/8" casing. 2.31 ID X-Nipple 1 Jt above packer 7" Permanent I Retrievable Packer W I sealbore assembly 2.13 ID X-Nipple 1 Jt below packer 3" Tubing Spacer w/XO's between packer and Screens Sand Exclusion Screen across Perforations. Type and size to be determined. Rev. 03 DHV 05-Feb-2003 DRAWING NOT TO SCALE Aurora Well Service Rig No.1: Proposed 3M BOP Configuration e e Fill Up Line 3M Schaffer Annular Preventer Pipe Rams sized to work string. 11" 3M Double Gate wI 3/12" pipe rams installed. Fluid flow direction while reverse circulating Blind Rams 3" 5M Manual Valve (Choke Line) /' _____ 3" 5M Hydrauic Valve (Choke Line) 11-X 3M Braden Head 2" 3M Manual Valves On Wellhead 9 5/8" Casing ¡ 13 3/8" Conductor Aurora Well Service BOP Fairweather E&P Services, Inc. Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale Aurora Well Service Jlig No. 1 Proposed Choke I KilIl\Janifold Configuration All valves are 3" rat"t 5000 psi. . Inlet from Power Swivel (Reverse Circulation Mode) Output to Pits '--+ Hydraulic Remote Activated choke Inlet from BOP Choke Line 3" 5M Rated Valves 2" 5M Rated Valves ~ Manual Choke To Gas Buster "Atmospheric Degasser" Aurora Well Service Choke Manifold Fairweather E&P Services, Inc. Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale Aurora Well 'rvice Rig No.1: Proposed Surf! Diverter System Bell Nipple Flow Line to Pits Fill Line 13-5/8",5000 psi WP Annular Preventer Hydraulically Operated 1 A" Knife Gate Valve 13-5/8", 5M Drilling Spool 1 Mud Cross 1 A" Diverter Vent Line 13 3/8" Conductor Pipe with 13-5/8", 5000 psi WP Flange welded on top Aurora Well Service Diverter Fairweather E&P Services, Inc. Rev. 3 DHV 10-Feb-2003 Drawing Not to Scale ,""'\\\, e ...... (': OF Ai. " .:- ~~···"·····.:in " - .L~.. ...\JL I - ;_,..' ··~L ,. _ -J' .':"Y r'. .. * ....49D:l .... *~ .-............ ....". ..... ...... ... ...." "" , , , ,. .... ..... .......... ................-. , ~ "·.M. SCOTT McLANE::!: ... ~..... . - ',~~..... 4928-5 ...... .:' 'I, ~ ~;;;.:~~ .......- ..,\""" PROTRACTED SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN ALASKA WITHIN U.S. Surve~ No. 1865 e --l Z U-.. r- U-.. r <i) <P 166~ FT. FEL AS STAKED KALOA NO.2 GRID N:25b lIØ5.ØØØ (OPT. C ALT. A) GRID E:26Ø8Ø5.ØØØ LATITUDE: bIOØI'IØ.851" Surface Location LONGITUDE: -151°2Ø'54.332" (FORMERLY ALBERT ELEV. 2Ø45 KALOA) SCALE 1 inch = 500 ft. ~o 750 \ 1000 I Consulting c; roup Testing ENGINEERING!MAPPING /SURVEYlNG/TESTlNG P.O. BOX 468 SOlD01NA, AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmdoneOmdonecg.com PROJECT NO. DRAWN BY: DATE: 04/04/03 REVISED: 04/07/03 033008 MSM NOTES 1)6,ASIS OF CO~INATES: NG5 CO~ STATION liKEN I". 2) ELEvATION DATUM: NAVDas 3) SECTION LINE OFFSETS DE~IVED F~OM T...EORETICAL. PROTRACTED SECTION ~R VALUES 4) ALASKA STATE PLANE ZONE 4 NAD21 623/624 S26 S25 KALOA NO.2 (OPTION C ALTERNATIVE A) SURFACE LOCATION APPLICANT: .·~Aurø,.a Gas,I.I.C OFFSETS: LOCATION: 1669' FEL SECTION 26 TOWNSHIP 11 NORTH RANGE 12 WEST 987' FNL SEWARD MERIDIAN ALASKA Permit / Project 2030710 Date 10/28/2003 Start Time 9:00:48 AM End Time 9:30:31 AM Duration UIC Category Description Drill Permit App Subject Kaloa #2: Operator I Ownership Docs Copy of incomplete ownership and operatorship documents returned to Randy Jones of Aurora. Jody formats letter, I sign, she sends. CC's to Ed Jones, Andy Clifford. Notes Contact-Primary Contact-Secondary PrimaryFile Randy Jones Company Aurora Gas, LLC Company e Secondary File Hyperlink!.' to Related File!.' Hyperlinb to Image Files - Thursday, December 11,2003 Page 10 of 10 STATE OF ALASKA .. ALASKA O~ND GAS CONSERVATION COM.,SION DESIGNATION OF OPERATOR 20 MC 25.020 1. Name and Address of Owner: Aurora Gas, LLC 10333 Richmond Avenue Suite 710 Houston, Texas 77042 2. Notice is hereby given of a designation of operatorship for the oil and gas property described below: Legal description of property: -Si1ttpeO'"*·a±oa--No. 2 sections 13; 14; 15, E2E2E2; 22, E2E2E2; 24, Fractional; 25, Fractional; 26, Fractional; 27, E2E2E2; Comprising 3,435 Gross/net acres Township 11 North, Range 12 West Seward Meridian Lessor: Cook Inlet Region, Inc. ~'-~ 'l Lessee: C-61393 J1 Aurora Gas, LLC #1 Ö.,-¡-t-J AÇA-L-,..... () "Û 1'1* c. r ¡.-¿J J1> Property plat attachedD 3. Name and Address of Designated Operator: Aurora Gas, LLC 10333 Richmond Avenue, Suite 710 Houston, Texas 77042 4. Effective Date of Designation: December 31, 2002 property with all attendant responsibilities and obligations is hereby acknowledged: Signature Date 7-17-03 ----~.- --~---'--- Title Vice President Signature Date 7-17-03 Title Vice President 7. Approved: ___. ···········...........·_H.·_··...·.._........_···_______ _.__._...._.._....m..~ ...........__.._...__....m.._.__..__ ....__..........______m.._.__M............._._m......_ Commissioner Date Approved: __.___.m._____._____.____._.___....._m. Commissioner ... ........__.._...,_._................._..~. --........--_.........-... ...-..-,.......-..----.......-.,..-..---...-.......--....-..--.- ..·_._..._'·_M........_.._.··· Date Approved: __....~_.___.__ ....................,........._..._.._..~....__.__. __......._....._~__..._~......__ ...._......_.____._.__.~._._..._ ·..·w·___·....··____·_··..··~·_...··... Commissioner Date (Requires approval by two Commissioners) Form 10-411 Revised 2/2003 OR!G!r~A' Submit in duplicate ·. STATE OF ALASKA . ALASKA AND GAS CONSERVATION CO Iì..ÍI1ISSION NOTICE OF CHANGE OF OWNERSHIP 20 MC 25.022 1. Name of Operator: Aurora Gas, LLC 2. Address: 10333 Richmond Avenue Sui te 710 Houston, Texas 77042 3. Notice is hereby given that the owner[1landownerD, of record for the oil and gas property described below has assigned or transferred interest in the property indicated below: Property designation: C-61393 Legal description of property: -SimpcoK-aJ:oa"'No";-2- Field or Unit: Moquawkie Field Sections 13; 14; 15, E2E2E2; 22, E2E2E2; 23; 24, Fractional; 25, Fractional; 26, Fractional; 27, E2E2E2; Comprising 3,435 Gross/net acres Township 11 North, Range 12 West Seward Meridian Lessor: Cook Inlet Region, Inc. Lessee: Aurora Gas, LLC ~~ .4 7 /lÍ.1 úne.d ~.~ .ft At} a...AA Property plat attachedD 4. Effective date of assignment or transfer: 5. Percentage interest assigned or transferred: December 31, 2002 100. OO"tb 6. Assignee or Transferee: Address: Aurora Gas, LLC 10333 Richmond Avenue, Suite 710 Houston, Texas 77042 7. Assignor or Transferor: Address: Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, Texas 77380 Signature Date ?/?/C3 Printed Na e . Edward Jones Title Vice President Form 10-417 Revised 2/2003 nD ,,) ¡" \ 1..·... 1\1... A ,. ª i \: ~ . :1 ~ li,~ ~Aurora Gas, LLC 10333 Richmond Ave., Suite 710 Houston, Texas 77042 ~.: L r~~~, (0~~:~5i~:~~_,:::=~~~=_~::= . ~.¿ . _~l"'" .r., c' =. ,. ,..,:=E~-,_,-,_,_- "'~._ (~;~:' r;lJ: s 6(~iî~?::êr":: ~ --_··,C~; "E; iv1Ai~!:D FRð", L.iP~·",,~,~ . ,~ ~ D Wt8 ::::> .~ c..... [1~ <...) be:', w.J 0 _ té. ..- ~..; -;::: :~> f'~~ C';c ~;. <'- .- Alaska Oil and Gas Conservation Commission Steve Davies 333 W. Seventh Avenue Suite 100 Anchorage, Alaska 99501-3539 ~3?5D i +~=5:;:~ II I I I I I I' II tI I I "I' .11. ft. 11,11",1 ! ni!H!H!iut!!!!!i f!11l1f!!tH!; 11:;11111.5 I.!f...! . e UNITED STATES POSTAL SERVICE, <':: ,;.; '=-,.~, ,.] ;: ~,! . · Sender: Please print yournarpe, address, andZIP+4 in this box'·' First-Class Mail Postage & Feès Paid USPS ...... '. Permit Nö:U"10 ... ;~C ~(~.r (J/\.,.. f::ì.¡.~ State. of Alaska . :t6' 0 I ~ I ./! V Å' AK Oil & Gas Conservation CommissioJ <f f> .3 ;). <... ....) 333 West 7th Avenue CJQ'..r /) <"()/,-. Anchorage Alaska 99501 1/¡c: "O/ì u...r ~ÚI. ~ c: ~.(>e o~. ~/.r' .rl.o· '/¡ . Ii! j f; I II II f ¡ ¡ i!1 ¡! I ¡ I !! I ¡! ! ill!i ¡ i I!! i I,I! ill ¡ ¡ Ii,! f I i Ii, II i ¡,f?¿/¿? /~ //;;; c?<v3· O(p¿?/',-:;;t)3·{)70/aa3~ 07/ t SENDER: COMPLETE THIS SECTION . ... - - . . . . . . · Complete items' 1 ; 2, and 3. Also complete. item 4. if Restricted Deliverý is desired. · Print your name and address on the reverse so that we can return the card to you. · Attach this card to the back of the mail piece, or on the front if space permits. 1. Article Addressed to: A. Received by (Please.pnnt Clearly) , E' Agent . ./ 0 Addressee ifferent from item 1? 0 Yes . ery address below: '9'N0 Ed jc7/?éÞ? / /'" Û¿.r!c//';Z YC:i¿7:;>' /¿;J 29 d/ 3,vd /lvc r0'~é;:?' Cbê/'-/ /J;< C}9?ó / í 3. Service Type ;a::certified Mail o Registered o Insured Mail o Express Mail o Return Receipt for Merchandise o C.O.D. 4. Restricted Delivery? (Extra Fee) es 2. Article ~I. ........a........... tr'..........1I frn,..., C'Þ'lIi,...o I~høll 7002 3150 0005 3521 1188 PS Form 3811,-:JuiY 1999----~-· Domestic Return Receipt 102595-00·M·0952 · "IT lJŒ lID~ ~~~~[ß~ , AI/ASKA OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CERTIFIED RESTRICTED DELIVERY 7002 315000053521 1188 Mr. Ed Jones Vice President Aurora Gas, LLC 1029 West 3rd Avenue, Suite 220 Anchorage, AK 99501 In Re: Long Lake # 1 West Moquawkie #1 Kaloa #2 (203-068) (203-070) (203-071) ~ Dear Mr. Jones: On April 9, 2003 the Alaska Oil and Gas Conservation Commission ("Commission") received 5 Permit to Drill ("PTD") applications for planned well activities on Aurora properties on the West Side of Cook Inlet. When Commission staff began reviewing the permits for completeness and compliance with our regulations (20 AAC 25), a number of deficiencies were identified in each permit. Email messages were sent to Mr. Duane Vaagan on April 22 (for operations and engineering) and Mr. Randy Jones on April 18 and April 21 (for land and ownership) listing the deficiencies and requesting their action to complete the PTD applications and allow the Commission to process them in a timely manner. Mr. Vaagan responded on April 30, providing the requested operations and engineering information. The land and ownership information has been slow in arriving. Sufficient information was ultimately received in mid-June to allow Lone Creek #3 (PTD #203-062) to be approved on June 25th and Mobil Moquawkie # 1 (PTD #203-068) to be approved on July 31st. However, several land and ownership items are still outstanding on the remaining applications. Mr. Jones was again contacted by phone on June 24, and an updated listing of the PTD application deficiencies was sent to him by email. A copy of that deficiency list is attached. Mr. Ed Jones October 16, 2003 Page 20f2 . , Despite repeated written and telephone requests for the needed information and documents to complete the PTD applications for Long Lake #1, West Moquawkie #1, and Kaloa #2, these application remain incomplete. This is unacceptable. Be advised, that if the Commission does not receive the necessary information to complete the PTD application packages for the subject wells by November 3,2003, the applications will be cancelled. DATED at Anchorage, Alaska and dated October 16, 2003. ~ ~~ Randy ::idriCh Commissioner By Order of the Commission · , Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information / Needs Updated October 16, 2003 Long Lake #1: (Permit to Drill number 203-068) expected spud date was May 20,2003. a. Designation of Operator and Notice of Change of Ownership forms (Forms 10-411 and 10-417, respectively) must be submitted to AOGCC for this lease, which is Mental Health Trust Lease 9300023. These forms are located on AOGCC's website at: http://\vww.aogcc.alaska.gov/forms/formscat.htm. Pertinent regulations are attached to the end of this letter. b. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.aogcc.alaska.gov/Regulations/art199.htm. A spacing exception is not needed to drill a well. but approval to perforate. test. and produce that well is contingent upon the Commission's issuance of a conservation order approving the spacing exception. By drilling a well without a spacing exception. Aurora assumes the 1iabi1itv of any protest to the spacing exception that may occur. West Moquawkie #1: (Permit to Drill number 203-070) expected spud date was June 20,2003. a. Designation of Operator and Notice of Change of Ownership forms have not been filed for this lease, which is C-61389. b. SPACING EXCEPTION REQUIRED: Simpco Moquawkie 1, 1,400' to the Southeast, is classified as a shut-in gas well, and is completed in the same interval as proposed for the West Moquawkie #1 re-comp1etion. Simpco Moquawkie 1 also lies within the same section (Section 36). Alaska Oil and Gas Conservation Commission 1 · , Kaloa #2: Pennit to Drill number 203-071, expected spud date was July 1, 2003. v a. Original Designation of Operator and Notice of Change of Ownership fonns have not been submitted for this lease, which is C-61393. The Commission received faxed copies of the fonns on August 7, 2003. Original copies were requested from Mr. Andy Clifford on August 18, 2003, but they were never provided. ~ /1 .' \,. \). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Pax: (907) 276-7542 steve _ davies@admin.state.ak.us ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides ofthe line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. Alaska Oil and Gas Conservation Commission 2 · , 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (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 3 N,otice of Change of Ownership and Designation of Ope... e e Randy, I received fax copies of the Notice of Change of Ownership and Designation of Operator forms on 7/17/2003. Your inclusion of the well name "Simpco Kaloa No.2" in the legal description on these forms is confusing. Our records show an existing well, Albert Kaloa 1, drilled by Pan American (Amoco) in section 26, T11N, R12W during 1967 - 1968. Our records also show a second, existing well in this same section, Simpco Kaloa 1, that was drilled by Simasko Production Company in 1978. However, our records do not show a well named Simpco Kaloa No. 2. I know Aurora Gas, LLC has submitted a permit to drill application for a proposed well, Kaloa No.2, to be drilled within 20 feet or so of the Albert Kaloa 1. This proposed well is the likely the source of the erroneous Simpco Kaloa NO.2 name on the forms. In any event, it would be best to eliminate the well reference on these forms. Aurora appears to own and desires to operate all of lease C-61393, and I believe that is what you intend the Notice of Change of Ownership and Designation of Operator forms to convey, rather than just ownership and operatorship of a single well. I also note that section 23 is listed in the legal description on the Notice of Ownership but not on the Designation of Operator form. Also, in regard to section 27, Aurora appears to be owner and operator of the onshore (fractional) portion of section 27 only. The current description on your forms implies ownership and operatorship of all of the E1/2 E1/2 E1/2 of section 27, both onshore and offshore. The offshore portion of section 27 is part of state lease ADL 17586. Please check the descriptions on both forms carefully as these are legal documents. The State of Alaska and BLM have an excellent site on the Internet at h~~£://~~.dnr.state.ak.~§jlri~j~~~L~j/ that you can use to access land status plats for Alaska which are presented in Adobe Acrobat format. Leases such as C-61393 are not labeled on the DNR/BLM plats, but these plats can still be used to check legal descriptions. The Commission has also purchased an excellent set of land maps produced by Mapmakers Alaska that I use in conjunction with the DNR/BLM plats. Their website can be found at http://www:mapalaska.com/. The Commission's regulations can be found on the Internet at http://www.state.ak.us/local/akpages/ADMIN/ogc/Regulations/RegIndex.htm. Regulations 20 AAC 25.020 - DESIGNATION OF OPERATOR and 20 AAC 25.022 - NOTICE OF OWNERSHIP are pertinent here. If you have any questions, please call or email me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation commission Telephone: (907) 793 -1224 1 of2 12/11/20039:20 AM [Fwd: 2003 Proposed Cook Inlet Basin Projects: Permit ... e e Ray, FYI, I provided the following update of my "Additional Information / Needs" listing to Randy Jones on June 24, 2003. Let me know if there is anything further I can do. Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793 -1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us ...---..-----.....--..----.---....---....--.-....-..-..--.---------.. Randy, As follow-up to our conversation today, I would like to send my listing of needed additional information concerning the permit to drill applications submitted to the Commission as part of Aurora's 2003 proposed Cook Inlet Basin projects. This is the original listing I sent you via email on April 21, 2003, annotated with comments about concerns/questions that have been answered, and those items that are still outstanding. If you have any questions, please call me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793 -1224 Fax: (907) 276-7542 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications Content-Type: message/rfc822 Content-Encoding: 7bit Content-Type: application/msword Content-Encoding: base64 1 of 1 12/11/20039:23 AM 2003 Proposed Cook Inlet Basin Projects...ations - Additional Information / Needs . . 'w e e Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Tue, 24 Jun 2003 12:19:46 -0800 From: steve _ davies@admin.state.ak.us To: Randy Jones <rjones@aurorapower.com>, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Randy, As follow-up to our conversation today, I would like to send my listing of needed additional information concerning the permit to drill applications submitted to the Commission as part of Aurora's 2003 proposed Cook Inlet Basin projects. This is the original listing I sent you via email on April 21, 2003, annotated with comments about concerns/questions that have been answered, and those items that are still outstanding. If you have any questions, please call me. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us !m¥~"',_,""A~._A'Ammnmm~'mmmm____~_~~~m.~,m'~~___"m__.'_.¥_.__._¥~~_~m_,_nm_'_"."mm~rl.¥.'m mmm_~'__~~~_mmm m'm__~__^,mm.mm,~_._,_m.~__....__.~_",t Name: 1_030623_Aurora_ W _CI_Proj( ~ 1 030623 Aurora W CI Proiect Deficiencies List.doc Type: WINWORD File (app1ication/rr Encoding: base64 '. e e Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information 1 Needs Updated June 24, 2003 Lone Creek #3: Permit to Drill number 203-062, expected spud date is May 15,2003, AOGCC senior staff submitted the application for pennit to drill to Commissioners for approval on 6/24/03. a.Logging program is not specified in 'Nell permit application. Received 4/22/03. b.Nøod dotorn1ination ftom Glen Gray as to whether an ACMP Consistency Determination is needed. ACMP determination may be needed (Glenn Gray, 6/6/03 emai1 to Tom Maunder, AOGCC). ACMP determinations will no longer delay approval and issuance of a permit to drill from the Commission. However, a permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. Long Lake #1: Permit to Drill number 203-068, expected spud date is May 20, 2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces from a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/10cal!akpages/ADMIN/ogc/art199.htm. b. Designation of Operator and Notice of Change of Ownership forms must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. These forms can be obtained from AOGCC's web site at: http://www.state.ak.us/local!akpages/ADMIN/ogc/homeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end of this letter. Alaska Oil and Gas Conservation Commission 1 e e c. C-P1an exemption determination needed from AOGCC. I am awaiting a request letter from ADEC. Submitted recommendation to Lydia Miner, Alaska Dept of Environmental Consrvation on June 20, 2003. d.Logging program is not specified in well permit application. Received 4/22/03. d. ACMP not needed «Glenn Gray, 6/6103 email to Tom Maunder, AOGCC). Mobil Moquawkie #1: Permit to Drill number 203-069, expected spud date is June 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease (see write-up in item "b"under Long Lake #1, above). e. Logging program is not spocified in well pelmit application. Received 4/22/03. b. c. ACMP not needed «Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). c. Spacing exception not required as long as re-comp1etion 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-comp1etion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-comp1etion operations are restricted to 2900' MD and shallower. West Moquawkie #1: Permit to Drill number 203-070, expected spud date is June20, 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-comp1etion. Simpco Moquawkie 1 also lies within the same section (Section 36). b. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. (see write-up in item "b"under Long Lake #1, above) f. Logging program is not specified in \vell permit application. Received 4/22/03. c. ACMP not needed «Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). Kaloa #2: Permit to Drill number 203-071, expected spud date is July 1, 2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. (see write-up in item "b"under Long Lake #1, above) Alaska Oil and Gas Conservation Commission 2 e e b. Logging program is not specified in well permit application.Received 4/22/03. c. Need determination from Glen Gray as to whether an ACMP Consistency Determination is needed.ACMP determination may be needed (Glenn Gray, 6/6/03 email to Tom Maunder, AOGCC). ACMP determinations will no longer delay approval and issuance of a permit to drill from the Commission. However, a permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. d. Spacing exception is not required. Although nearby well Simpco Ka10a 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 Pax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission 3 e e Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17 , 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Ka10a No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S18, T12N, R11 W. Aug 2000: Notice of change of Ownership from COO to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator fonn from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator fonn for that lease. Apr 2001: Designation of Operator fonn from Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, T12N, R11 W. Jan 2003: Designation of Operator fonn designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides ofthe line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission 4 e e (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance of the designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission 5 Aurora Gas, LLC Permit to Drill Deficiencies Letter .. .. ...... e e Subject: Aurora Gas, LLC Permit to Drill Deficiencies Letter Date: Mon, 23 Jun 2003 11 :02:25 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: ray@fairweather.com Ray: As we discussed on Friday, attached is the email that I sent to Randy Jones in April which outlines needs or deficiencies for each of the permit to drill applications submitted by Aurora. Please call or email me if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793 -1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------ Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today) . Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies ----------------------------------------------------------------------- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Aurora Gas, LLC Permit to Drill Deficiencies Letter .. .. '. '"' e Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us e '---- 11030418 Aurora W CI Proiect Deficiencies Name: 030418_Aurora_ W _CCProject_ Emai1.doc Type: WINWORD File (app1icationlm Encoding: base64 .- Ci.? r\.1T r? II tð\\ ' lþ ¡ ¡ 'F". . ¡ I! l'U'\"! L...,; d. WL-.. l~.. e rmrr '--, u e ." /'71^\ n r¡;\ rrù rVl ./. \ ¡ !I,\ "~.'''!'( .W\.. {'-', \\ ¡,\ Ij,.-,. \ II I ¡. .\ r'u' í ¡ !\ '. L U L..:::.1L.J lJ ......_/ lJ\..l FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. ]TH AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 June 18, 2003 Ms. Lydia Miner Section Manager Exploration, Production and Refineries Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, AK 99501 RE: C-Plan Exemption for Planned Aurora Gas, LLC 2003 Activities on the West Side of Cook Inlet Dear Ms. Miner: The Alaska Oil and Gas Conservation Commission ("the Commission") received your request for a formal determination regarding an exemption from Oil Discharge Prevention and Contingency Plan requirements for wells and re- completions planned by Aurora Gas, LLC ("Aurora") on the west side of Cook Inlet during 2003. In order to evaluate Aurora's request for an exemption from the oil spill contingency plan requirements for this program, I have reviewed all of the information submitted by Aurora, and the Commission's well files, log files, production records, and records associated with Conservation Order No. 478 (spacing exception for the drilling and testing of Nicolai Creek Unit wells #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, ·- e e .- 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 ~-mile wide (see map, below). Long Lake Unit #1 is located on a separate structure approximately 4 miles to the west. ~.R12Wi I . I,i . ¡ --¡;-- I ' I I i i I I i Moq uawkie Field 36 I W. Moquawkie 1 ._ -1 I T 12 N. R 11 I . 31 I ~ , Simpco ~. ~oquawkie 1 Ii .~. I .- Simpco Moquawkie 1 6 1 i I Mobil Moq~awkie 1 .. ! _ . . Moquawkie Simpco Moquawkie. ... 2 2 . long lake Unit 1 T yonek Restrve 1 ! o 1 mile I I + I ! M~qUawkie 44-& ~~.T nek ReserveiB 1 Slmpco kaldachabun 1, ., 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 e e 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. LonQ 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 e e 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. I T12N,R11W 12 7 8 I 9 Lone Creek 3 (proposed) b 13 18 I 17 18 Lone Creek 1 ... 24 19 20 21 Lone Creek 2 25 ~ 30 I 29 28 Lone Creek Basemap No oil indicators are marked on the mud logs across Aurora's proposed shallow development interval in Lone Creek #1 and #2. Lone Creek #1 tested only gas from this interval. Lone Creek #2 was plugged and abandoned without testing. Based on records from these offset wells, Lone Creek #3 is not likely to produce oil or encounter oil-bearing formations. Nicolai Creek Unit #7 and #9 Wells and Nicolai Creek Unit #1, #2 and #9 Facility The Nicolai Creek area wells are all clustered near the western shoreline of Cook Inlet. Aurora plans two shallow gas wells in this area, Nicolai Creek Unit #7 and #9. Aurora is also planning a production facility with associated pipeline to collect and process gas from the existing Nicolai Creek Unit #1 Band #2 wells, and the proposed #9 well. 4 e e . 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. A time-structure map of the top of the Tyonek Formation in the Nicolai Creek Field is published in the Commission's 2002 Annual Report. This report can be accessed on the Internet at: http://www.state.ak.us/local/akpaaes/ADMIN/oqc/homeoqc.htm. Nicolai Creek State #1 and #1A: Nicolai Creek Unit #1B. #2. and #9 The proposed Nicolai Creek Unit #9 well, and the existing Nicolai Creek State #1, #1 A and Nicolai Creek Unit #1 Band #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 #1B, #2, and the proposed Nicolai Creek Unit #9 well. The Tyonek gas sands were perforated and tested in Nicolai Creek State #1 between 3420' and 3630' (-3305' to -3505' TVD subsea) and they produced dry, clean gas with no associated oil. 24 I Nicolai Ck U 3 I *' 20 , 21 ! Nicolai Ck U 5 i I J~~ 0 N'col,' AU"it 7 IPmPO"~1 Nicolai Creek Field 22 25 27 -- Nicolai Ck U 6 31 .- Nicolai Ck 32 U4 33 34 I 1 i Nicolai Creek Basemap Oil shows in Nicolai Creek State #1 are restricted to the Hemlock Formation below 6025' (-5777' TVD subsea). These sands were tested, but according to the well file, showed "no oil accumulations." 5 · · e e · · Nicolai Creek State #1A, the first sidetrack of the #1 well, was drilled up-structure from the original #1 well bore. Commission records for #1 A report the shallowest oil indicator as being "solid hydrocarbon" (tar?) encountered between 5535' to 5550' (-5281' to -5295' TVD subsea) and 5620' to 5640' (-5360' to -5379' TVD subsea), which is over 1,500' below Aurora's interval of interest. Shallow Tyonek gas sands were produced in #1A between 3420' and 3630' (-3305' to -3505' TVD subsea). Commission records indicate this interval produced gas for only three months (December 1968 through February 1969), with no associated oil. The second sidetrack of the #1 well, Nicolai Creek Unit #1 B, was drilled up- structure of the #1 and #1 A wells by Aurora in September of 2002. There are no oil indicators shown on the mud log or mentioned in lithologic descriptions contained in the final well report from the mud-logging contractor. Nicolai Creek Unit #9 is a proposed well intended to produce gas up-structure from the #1 B well in the same fault block. The final well in this fault block, Nicolai Creek Unit #2, was drilled by Texaco as an exploration well in 1966. No oil accumulations were encountered. Texaco tested a gas sand between 3270' and 3315' (-2733' to -2768 TVD subsea), with no mention of any associated oil or water. The well produced 52 million cubic feet of gas from September 1968 through October 1969, with no record of any associated oil production. It was re-entered and tested by Aurora during 2002, and flowed gas and water from shallow Tyonek Formation sands. No associated oil is noted in Aurora's test summary reports. In summary, Nicolai Creek State #1, #1 A, and Nicolai Creek Unit #2 tested the down-dip portions of the reservoir block. Nicolai Creek Unit #1 Band #9 will produce gas from the up-dip portions of this same block. Neither #1, #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 .' e e " 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 #1 A, Nicolai Creek Unit #1 B, #2, and #3 all indicate that the #1 B and the proposed #7 and #9 gas wells are not likely to encounter oil in, or produce oil from, the Beluga Formation or shallow portions of the Tyonek Formation. Production facilities associated with Nicolai Creek Unit #1 B, #2 and #9 also have little possibility of receiving oil from any of these wells. Kaloa #2 The proposed Kaloa #2 shallow gas well will be drilled approximately 20 feet from the existing Albert Kaloa #1 well, an oil exploration well drilled in 1967 by Pan American and completed in 1968. 16 15 14 13 Albert Kaloa Field 24 28 Albe Kaloa 1 'f).: Kaloa 2 (proposed) 27 pco Kaloa 1"'- T 11 N, R 12 W Kaloa Area Basemap 7 .' ) I· e e .t 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' TVO 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 J<o.jC;JCL Z- ..DN~ Oil and Gas Update e 3 __ June 16, 2003 Pipeline System near Valdez. This facility provides the source for the Valdez Marine Terminal (VMT) raw water, potable and firewater needs. OPMP initiated this 30-day review on April 15, 2003 and issued the final determination on May 2,2003 [17 calendar days in review]. Contact: Kaye Laughlin. Pre-Application Stage Kuparuk River Rehabilitation Plan: ConocoPhillips Alaska, Inc. proposes to restore the East and West Channels of the Kuparuk: River to their approximate condition prior the spine road development. Contact: Kaye Laughlin. Aurora Gas LLC Projects: Aurora Gas proposes to conduct exploration for gas on a number of sites and a development project at one site during the summer of2003. All ofthese projects are located onshore on the west of Cook Inlet. Exploration activities for five projects will be conducted from existing pads, and no permits are expected to trigger an ACMP consistency review (Long Lake No.1, Mobil Moquawkie No.1, Simpco Moquakie No.1, West Moquawkie No.1, and Simpco Moquawkie No.2). Three exploration projects would likely need an ACMP review (Nicolai Creek Unit No.7, Lone Creek No.3, and Ka10a No.2). A production facility including installation of a four-inch pipeline is proposed near the Shirleyville runway. OPMP sponsored a pre-application meeting on Apri117, 2003. Contact: Glenn Gray. Petro Star Valdez Pipelines: Petro Star, Inc. proposes to construct two parallel petroleum pipelines and a fuel transfer dock on the south shore of Port Valdez just east of the Solomon Gulch Hatchery. In 1992, Petro Star investigated seven different alternative locations for delivering product to a marine terminal. The proposed pipelines will start at the Petro Star Valdez Refinery and continue west, buried under a mile-long section of a new bike path along Dayville road. From Dayville Road, a trestle will extend about 1,000-feet northward to a fuel transfer dock. Petro Star plans construction ofthe buried pipeline to be concurrent with construction of the pedestrian path along Dayville Road Contact: Kaye Laughlin. Borealis Power Project: BPXA proposes to expand infrastructure to meet power demands of future satellite expansion in the western end of the Prudhoe Bay Unit and a possible tie-in with the Milne Point Unit power grid. The project would include a new 69 kV power line, a sub- station, and possible minor pad extensions. The power line would run from the Central Power Station to the L and V Pads in the end ofthe unit and possibly extended to Milne Point. Originally planed for the 2003-2004 winter season, BP notified OPMP that the project has been deferred for another year. OPMP held a pre-application meeting on 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 Re: [Fwd: RE: Aurora] e e Subject: Re: [Fwd: RE: Aurora] Date: Fri, 06 Jun 2003 11: 16:44 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Glenn Gray <Glenn _ Gray@dnr.state.ak.us> cc: Steve Davies <steve_davies@admin.state.ak.us>, Randy Ruedrich <randy Juedrich@admin.state.ak.us> Glenn, Thanks much. I am frankly surprised that Fairweather/Aurora had not sent any paperwork after the meeting. That's what I would have done. Got to keep the ball rolling or in play and not sit on it. I do know that some of the "rush" has changed due to Aurora "re-Iooking" at seismic information. Regardless, the need for "rush" has a way reappearing to bite someone when they least expect it, so again I am surprised that you didn't get any paperwork. Thanks for chasing this, I do appreciate your efforts on our behalf. Tom Maunder AOGCC Glenn Gray wrote: > -------- Original Message -------- > Subject: RE: Aurora > Date: Fri, 6 Jun 2003 10:45:45 -0800 > From: Bill Penrose <bill@fairweather.com> > To: 'Glenn Gray' <Glenn_Gray@dnr.state.ak.us> > CC: Ray Eastlack <ray@fairweather.com> > > Glenn, > > Ray Eastlack, our engineer handling the Aurora Gas facility & pipeline > installations and related permitting is preparing a comprehensive status > update as a response to your previous email to the AOGCC. The short > answer > is that you'll be getting paperwork next week. Ray will have the story > to > you very quickly. > > By the way, are you in Anchorage, now, or Juneau? > > Regards, > Bi 11 > > -----Original Message----- > From: Glenn Gray [mailto:Glenn Gray@dnr.state.ak.usJ > Sent: Friday, June 06, 2003 10:00 AM > To: Bill Penrose > Subject: Aurora > > Bill: > Did you submit > preapplication > Glenn any paperwork on any of the proposed wells after the meeting? (-~~-~~~ ~~'~~,~~~~__~__n_~~~~~~~~ Tom Maunder <tom maunder(cV,admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission Aurora Operations e 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 Juedrich@admin.state.ak:.us>, bill penrose <bill@fairweather.com> e Tom: At a preapplication meeting held on April 17, 2003, Fairweather discussed a number of proposals for gas exploration and development projects on the West side of Cook Inlet for Aurora Gas LLC. Although the Office of Project Management and Permitting has not received a Coastal Project Questionnaire for any of the projects, it appears that some of the projects will not need an ACMP review. Unless there is an permit trigger (e.g., a Corps 404 permit or a state permit included on the "C List"), the following projects will not need an ACMP review: Long Lake No. 1 Mobil Moquawkie No. 1 Simpco Moquawki No. 1 Simpco Moquawki No. 2 West Moquawkie No. 1 For several other wells, an ACMP may be required, and a final decision will be made after Fairweather provides more information to me about the permits needed for the projects: Nicolai Creek Unit No. 7 (ACMP review likely needed) Lone Creek No. 3 (may need a review) Kaloa No. 2 (may need a review) Shirleyville Production Facility (may need an ACMP review) As I recall, Fairweather was working with the Corps to complete wetlands determinations to see if 404 permits are needed and with the Office of Habitat Management and Permitting to see if fish habitat permits are needed. By copy of this email, I will check with Fairweather to see if they have any new information. Glenn termination will Well Permit Response e e Subject: Well Permit Response Date: Wed, 30 Apr 200313:57:16 -0800 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.ak.us> CC: 'Ed Jones' <jejones@aurorapower.com> Tom: Please find attached a response to AOGCC's request for information and clarification for each of the following (4) wells. West Moquawkie No.1 KaJoa No.2 Moquawkie No. 1 Long Lake No. 1 I hope that the attachments will clarify, appropriately address and correct concerns initially submitted to us. Please do not hesitate to call or email me should more clarification or information be required. Thank You Duane Vaagen Project Engineer Fairweather E&P Services, Inc. d uaneæÐ.fairweather. com Office: (907)258-3446 Cell: (907)240-1107 " Name: W. Moquawkie #1.doc OW. Moauawkie #1.doc Type: WINWORD File (application/msword) Encoding: base64 Name: Kaloa #2.doc o Kaloa #2.doc Type: WINWORD File (application/msword) Encoding: base64 Name: Long Lake #1.doc OLona Lake #1.doc Type: WINWORD File (application/msword) Encoding: base64 1of2 7/24/2003 11 :52 AM e e From: Tom Maunder [tom_maunder@admin.state.ak.us] Sent: Tuesday, April 22, 2003 11:48 AM To: duane vaagen Subject: Kaloa #2 Hi Duane, Here is the note regarding my questions on the Kaloa #2. 1. After setting the 9-5/8" surface casing, it is a FIT but no value is given. What do you expect?? plans, a EMW value was stated. specified to do In the other 2. I note this BOP drawing does not include the rotating head. 3. In the 7" casing running instruction, it appears to state that the 7" might not be run to TD. If it were determined to not run the casing to TD, we would need to be notified and provisions for isolating any open hole below the shoe would have to be determined. This is similar to questions on the other wells on how to avoid "flip-flop". 4. The XS cement volumes specified are only 15%. Will that be sufficient?? What XS factors did you employ last year?? You may not have surface hole values since I don't think Aurora drilled a grass roots well last year, but the other hole sections might apply. Thanks for you attention to these questions. Tom Maunder, PE AOGCC Response: Kaloa No. 2 1) Sorry about that, we will attempt to test to an EMW of 17 ppg. 2) Since this will be a grass-roots well, we will use a standard circulating system, i.e. pump down drill-pipe with returns up annulus. Because of the area, we don't want to risk plugging our bit or pipe with the coal, gravel and rocks we will be drilling through. 3) We will run the 7" casing to bottom (-3745 - 3750'). This will give us the rat-hole we need inside as well as take care of the cement swap problem indicated. e e 4) As you pointed out, the excess cement amounts for cementing the casing strings indicated in the permit application are insufficient. Further review of historical well records for offset wells Albert Kaloa No. 1 and the Simpco Kaloa No. 1 wells, and the cement volumes that were used when cementing these wells indicate a larger volume should be planned for. We will plan on pumping 100% excess for the 9 5/8" surface casing with the intent to cease displacement operations when good cement is observed at surface. On the Albert Kaloa No. 1 well, 18% excess was required to cement 20" casing inside a 26" hole to surface with returns to surface. When cementing the 13 3/8" casing at 2922', 77% excess cement was used with no mention of any cement being seen at surface. The wells mentioned were cemented using a 15.8 ppg ~G" slurry. In the permit application we initially indicated we intended to use a 15.8 ppg cement system at surface. We are now analyzing a lighter system to cement the surface casing string, the idea being to minimize the potential of losing circulation and maximizing the potential of seeing good returns at surface thereby insuring a good cement job on the surface casing. This is not only critical but a requirement. We will notify and update AOGCC when we have optimized this and describe our intended cement system. Tom: Thanks and please do not hesitate to call me at 258-3446 with any more questions or concerns. Duane Vaagen Fairweather E&P Services, Inc. Kaloa #2 Albert Kaloa Field Log Run Depths Hole/Casing Tools E-Mail Prints Film/Sepia Digital OH1 1050-3700' 8-1/2" PEX (AIT/SP/GR/CNL/TLD) PDS/LAS 8 1 CMR FMS-Dipmeter? RFT CH1 Surface-3700' 7" USIT/CCUGR PDS/LAS 8 1 DSI RST 1-DLlS/PDS VSP (CD) 7 -LAS/PDS (Disk) e e Aurora Gas, LLC Aurora Logging Program . it Ka-/()t3v 2- Subject: Aurora Logging Program Date: Tue, 22 Apr 2003 15:16:16 -0800 From: duane vaagen <duane@fairweather.com> To: "Steve Davies (steve_davies@admin.state.ak.us)" <steve_davies@admin.state.ak.us> Steve: Attached are files as promised. The 2003 Wireline spreadsheet contains the proposed logging suites for each well, which are tabbed as additional spreadsheets in the file. Please do not hesitate to call with any questions or concerns. ".; . Duane Vaagen . Project Engineer / Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 Name: 2003 Wireline Logging Program.x1s ~2003 Wire line Logging Program. xIs Type: Microsoft Excel Worksheet (app1ication/vnd.ms-exce1) Encoding: base64 . Name: 2003 Mud10gging Program.xls ~2003 Mlld10gging Program.xIs Type: Microsoft Excel Worksheet (application/vnd.ms-exceI) Encoding: base64 Kaloa #2 Albert Kaloa Field Proposed Logging Program Log Run Depths Hole/Casina Tools E-Mail Prints Film/Sepia Digital OH1 1050-3700' 8-1/2" PEX (AIT/SP/GR/CNL/TLD) PDS/LAS 8 1 CMR FMS-Dipmeter? RFT CH1 Surface-3700' 7" USIT/CCUGR PDS/LAS 8 1 DSI RST 1-DLlS/PDS VSP (CD) 7 -LAS/PDS (Disk) . '. Aurora Gas, LLC 4/23/2003 030423_Aurora_W_CI_2003 Wireline Logging Program. xis 2003 Program Mudlogging Requirements Proposed Logging Program Nicolai Ck 9 lonQ lake 1 lone Ck 3 West MOQuawkie 1 Kalo 2 Nicolai Ck 7 Interval 200-620' 620-2300' 3052-4653' 200-1000' 1000-2900' 2515-3550' 200-1050' 1050-3700' 200-750' 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 Not 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-UnwashedlWet, 3-Washed/Dry None 1-UnwashedlWet.3-Washed/Dry None 1-UnwashedlWet,3-Washed/Dry 1-UnwashedlWet, 3-Washed/Dry Show Report Generation As Needed? As Needed? None As Needed? As Needed? None As Needed? As Needed? As Needed? As Needed? Daily 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 by Aurora Provided by Aurora Provided by Aurora Provided by Aurora Provided by Aurora Provided by Aurora Equipment Transportation Provided by Aurora Provided by Aurora Provided by Aurora Provided by Aurora Provided by Aurora Provided by Aurora . Aurora Gas, LLC 4/23/2003 2003 Mudlogging Program.xls Kaloa #2 ~ Subject: Kaloa #2 Date: Tue, 22 Apr 2003 11 :48:14 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Duane Vaagen <duane@fairweather.com> Hi Duane, Here is the note regarding my questions on the Kaloa #2. 1. After setting the 9-5/8" surface casing, it is specified to do a FIT but no value is given. What do you expect?? In the other plans, a EMW value was stated. 2. I note this BOP drawing does not include the rotating head. 3. In the 7" casing running instruction, it appears to state that the 7" might not be run to TO. If it were determined to not run the casing to TO, we would need to be notified and provisions for isolating any open hole below the shoe would have to be determined. This is similar to questions on the other wells on how to avoid "flip-flop". 4. The XS cement volumes specified are only 15%. Will that be sufficient?? What XS factors did you employ last year?? You may not have surface hole values since I don't think Aurora drilled a grass roots well last year, but the other hole sections might apply. Thanks for you attention to these questions. Tom Maunder, PE AOGCC . Tom Maunder <tom maunder@admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 1 4/22/2003 11 :48 AM 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Subject: 2003 Proposed Cook Inlet Basin Projects: Permit to Drill Applications - Additional Information / Needs Date: Mon, 21 Apr 2003 08:52:49 -0800 From: Steve Davies <steve_davies@admin.state.ak.us> To: rjones@aurorapower.com, duane vaagen <duane@fairweather.com> CC: Tom Maunder <tom_maunder@admin.state.ak.us> Gentlemen: This is a re-transmission of an email sent on Friday. I received a transmission error notice on the copy sent to Randy Jones. I phoned Aurora Power to confrim the email address, and it appears to be correct. So, I'll try again and follow-up with a phone call tomorrow morning to ensure receipt (I understand Randy is out of the office today) . . Also, the C-Plan exemption determination needed from AOGCC applies to each of these proposed projects, not just Long Lake #1. I am awaiting a request letter before I undertake a review. Thanks, Steve Davies ----------------------------------------------------------------------- Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. . Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us Commission L~.""" ~030418 Aurora W CI Project Deficiencies Name: 030418_Aurora_ W _CI_Project_Deficiencies_Emai1.doc Emai1.doc Type: WINWORD File (applicationlmsword) Encoding: base64 . . Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information I Needs Lone Creek #3: Permit to Drill number 203-062, expected spud date is May 15, 2003. a. Logging program is not specified in well permit application. b. Need determination from Glen Gray as to whether an ACMP Consistency Determination is needed. Long Lake #1: Permit to Drill number 203-068, expected spud date is May 20, 2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce from a pool and to appropriate the oil and gas the person produces ITom a pool for that person and others." The spacing exception process takes about 6 weeks. Spacing exception application requirements are published in AOGCC's regulation 20 AAC 25.055 (d), which can be found on the Internet at: http://www.state.ak.us/local/akpages/ADMIN/ogc/art199.htm. b. Designation of Operator and Notice of Change of Ownership forms must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. These forms can be obtained from AOGCC's website at: http://www.state.ak.us/local/akpages/ADMIN/ogc/homeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end ofthis letter. c. C-Plan exemption determination needed ITom AOGCC. I am awaiting a request letter from ADEC. d. Logging program is not specified in well permit application. Moquawkie #1: Permit to Drill number 203-069, expected spud date is June 1,2003. a. Designation of Operator and Notice of Change of Ownership forms are not on file for this lease. b. Logging program is not specified in well permit application. Alaska Oil and Gas Conservation Commission 1 . . c. Spacing exception not required as long as re-completion operations III Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie #1 is 1704' from the nearest lease line, which exceeds the required 1500' setback distance from property lines for a gas well. Moquawkie #1 is 2500' away from, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. from 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-comp1etion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-comp1etion 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 ofthe bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission 2 . . Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17, 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Kaloa No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S18, 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 fonn from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator fonn for that lease. Apr 2001: Designation of Operator fonn from Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, T12N, R11 W. Jan 2003: Designation of Operator fonn designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only ifthe owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission 3 . . (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designatl:::d operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance ofthe designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission 4 2003 Proposed Cook Inlet Basin Projects: Permit to Dril... e e Gentlemen: The attached notes are my comments and needs for your permit to drill applications for Aurora's 2003 Cook Inlet Basin program. Please call or email if you have any questions. Sincerely, Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve davies@admin.state.ak.us ...._.......___.......__...__........____..............__...........__.....m.. .m_mm_.....m............__ ................... . --------~-- _ _ _ m_mmm_ ..........mm._ ..................................... i 1_030418_Áurora_ W _ CI_Project_Deficiencies_Email.doc Content-Type: application/msword II ! Content-Encoding: base64 ............... ..... 0_- _..__..__........m................. .~.._.__________.____.._..__. onm....................... _. _.._m_ 1 of 1 12/11/2003 9:03 AM e e Aurora Gas LLC 2003 Proposed Cook Inlet Basin Projects Permit to Drill Applications - Additional Information / Needs Lone Creek #3: Pennit to Drill number 203-062, expected spud date is May 15,2003. a. Logging program is not specified in well pennit application. b. Need detennination fÌom Glen Gray as to whether an ACMP Consistency Detennination is needed. Long Lake #1: Pennit to Drill number 203-068, expected spud date is May 20,2003. a. SPACING EXCEPTION REQUIRED: due to close proximity (less than 500') to property line with an Escopeta lease to the south and apparently unleased Mental Health Trust land to the east. Our regulation states: ".. . for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line;" (see attached regulations, below). Landowner means "the owner of the subsurface estate of the tract affected," and owner means "the person who has the right to drill into and produce fÌom a pool and to appropriate the oil and gas the person produces fÌom 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: hap:/lwww.state.ak.us/local/akpages/ADMIN/ogc/artI99.htm. b. Designation of Operator and Notice of Change of Ownership fonns must be submitted to AOGCC. I thoroughly searched AOGCC's files, and Designation of Operator and Notice of Change of Ownership fonns are not on file for this lease. These fonns can be obtained fÌom AOGCC's website at: http://www.state.ak.us/local/akpages/ADMIN/ogc/homeogc.htm. Pertinent regulations are attached to the end of this letter. My notes concerning ownership and operatorship records for the Moquawkie area that are on file at AOGCC are also attached to the end ofthis letter. c. C-P1an exemption detennination needed fÌom AOGCC. I am awaiting a request letter fÌom ADEC. d. Logging program is not specified in well pennit application. Moquawkie #1: Pennit to Drill number 203-069, expected spud date is June 1,2003. a. Designation of Operator and Notice of Change of Ownership fonns are not on file for this lease. b. Logging program is not specified in well pennit application. Alaska Oil and Gas Conservation Commission April 18, 2003 1 e e c. Spacing exception not required as long as re-comp1etion operations III Moquawkie #1 are restricted to intervals above 2900' MD. Moquawkie #1 is 1704' from the nearest lease line, which exceeds the required 1500' setback distance from property lines for a gas well. Moquawkie #1 is 2500' away from, and in same section as, Simpco Moquawkie 2 (178-088), a shut-in gas well capable of production. Perforations in Simpco Moquawkie 2 are open in Tyonek Fm. from 5666' - 5708' MD and 5880' - 5945' MD. Perforations in shallower intervals have all reportedly been squeezed. Since the Moquawkie #1 re-comp1etion will be in the Moquawkie SS member between 2735' - 2874' MD (an interval about 2800'shallower) a spacing exception is not required as long as re-comp1etion 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-comp1etion. 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 ofthe bridge plug, plus two plugs in casing at 2705' MD and 900' MD). Steve Davies Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 steve _ davies@admin.state.ak.us Alaska Oil and Gas Conservation Commission April 18, 2003 2 e e Moquawkie Field Area Ownership and Operatorship Records in AOGCC Files April 17, 2003 Nov 1990: Notice of Change of Ownership from Simasko assigning ownership of Simpco Moquawkie No 1, Simpco Moquawkie No 2, and Simpco Ka10a No 1 to COO. Jun 1998: Mobil and COO designate Anadarko as operator for S 18, T12N, R11 W. Aug 2000: Notice of change of Ownership from CIRI to Anadarko (50%) and Phillips (50%) for C- 061388 and C-061389. Designation of operator form from Phillips designating Anadarko as operator of COO Lease C-061388. Anadarko also provided an Assignment of Oil and Gas Lease document for C-061389, immediately to west, but there is no designation of operator form for that lease. Apr 2001: Designation of Operator form from Anadarko naming ARCO Alaska as operator of COO lease C-061500, which is S18, T12N, R11 W. Jan 2003: Designation of Operator form designating Aurora as Operator of Moquawkie "Unit" area only. ------------------------------------------------------------------------------------------------------------ Pertinent AOGCC Regulations 20 AAC 25.055 DRILLING UNITS AND WELL SPACING. (a) The commission will, in its discretion, establish drilling units to govern well spacing and prescribe a spacing pattern by pool rules adopted in accordance with 20 AAC 25.520. In the absence of an order by the commission establishing drilling units or prescribing a spacing pattern for a pool, the following statewide spacing requirements apply: (1) for a well drilling for oil, a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; (2) for a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line; Alaska Oil and Gas Conservation Commission April 18, 2003 3 . . (3) if oil has been discovered, the drilling unit for the pool is a governmental quarter section; not more than one well may be drilled to and completed in that pool on any governmental quarter section; a well may not be drilled or completed closer than 1,000 feet to any well drilling to or capable of producing from the same pool; (4) if gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. 20 AAC 25.020 DESIGNATION OF OPERATOR If an owner of a property wishes to designate a new operator for the property, the owner shall submit to the commission for approval a Designation of Operator (Form 10-411). The commission will not approve the designation of a new operator without the signature of the newly designated operator on the same Designation of Operator form. By signing the Designation of Operator form, the newly designated operator agrees to accept the obligations of an operator. The newly designated operator shall furnish a bond and, if required, security as provided for in 20 AAC 25.025. The commission's acceptance ofthe designated operator's bond constitutes the release of the former operator's bonding obligation for the property indicated on the Designation of Operator form. 20 AAC 25.022 NOTICE OF OWNERSHIP Within 15 days after a person becomes an owner of a property on which operations subject to this chapter are proposed to the commission or are being conducted, the person shall file a Notice of Ownership (Form 10-417). Alaska Oil and Gas Conservation Commission April 18, 2003 4 w I 20 00 51 I 22 00 W 5 2 N RE: Lone Creek #3 . Subject: RE: Lone Creek #3 Date: Wed, 16 Apr 200312:08:19 -0800 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.ak.us> Tom: Per your request, the following applies. I'll respond in the order of the questions below. 1. Yes, we have a formal meeting tomorrow afternoon with DGC, ADF&G, COE, DNR and TLO to discuss this and other wells in Aurora's program. In regards to Lone Creek No.3, we are hoping they give the green light to proceed as the only disturbance will be pad construction. No wetlands are being crossed and access will be via road constructed to drill the Chuit State wells years ago. Based on the meeting tomorrow, we will obtain all permits necessary. One thing we do know we need is a survey for a wetlands determination, site suitability and for archaeological or cultural resources. Another permit application submitted is for the Kaloa No.2. I am not so sure we w· this as we need a bridge. By the time we get thr Corp of Engineers and A . will not happen. ._--~ . Waste will be handled as last year, and the following is apPlicablC\ for the entire multi-well program this summer. Brines and muds will be recycled and used to the fullest extent possible. Drilling and workover wastes not recyclable will be transported offsite for treatment and disposal by Enviro-Tech. My apologies for not including this information in the permit application. I realized after I submitted the paper work that I omitted this information on all the wells. I will be submitting a Sundry application for testing and workover of the Simpco Moquawkie No.2 well soon. Base on log analysis and review of historical test results, I will be putting together a permit application for conversion of the SM No.2 well to disposal. This is one of the back-burner wells, but I think we will find that we really need a disposal well. .--._-,","'~----""~'_.--"---- '. ' ..' ,. he própõsefuad Slurry design calls for ~'ÿ¡ë¡d'éi2~1Ciì~"'" 4. Attached is tentative outline of work progression. This may have been pushed back now as we are not moving the rig across Inlet until the 2nd of May. We are working on a Gantt chart and will forward a copy as soon as we have it ready. Thank you please call if you need more information or clarification. Duane Vaagen Fairweather E&P Services, Inc. -----Original Message----- From: Tom Maunder [mailto:tom maunder@admin.state.ak.usl Sent: Wednesday, April 16, 200310:52 AM To: duane vaagen Cc: Steve Davies Subject: Lone Creek #3 Duane, I left a message for you, but wanted to send this email as well. I am reviewing the Lone Creek #3 application and have a couple of questions. 1of2 . 4/16/20033:48 PM RE: Lone Creek #3 . . 1--ls this well being reviewed in the "Coastal Zone" process?? I am not sure what other permitting requirements are out there or how they are now handled, but could you elaborate on what other permits are being sought. 2--How will the drilling waste be handled?? I am aware that Aurora has submitted a request to enter one of the Moquawkie wells with the potential to complete it as a class II well and Aurora has a disposal injection order for Nicolai Crk #5. Are there any plans to do the work on Nicolai Crk #5?? The AOGCC only has authority for annular disposal and class II injection. If other methods are being planned, permits for DEC and/or DNR and maybe others will be necessary. 3--What is the yield on the lead slurry for the 7" cement job?? 4--Could you or Aurora please provide a schedule of the coming planned work with approximate operation dates?? This will help us start to get our Inlet summer schedule set up. Thanks. Tom Maunder, PE AOGCC L.. Name: Aurora Gas POD Well Schedule.doc [JAurora Gas POD Well Schedule. doc Type: WINWORD File (application/msword) Encoding: base64 2of2 4/16/20033:48 PM · e ~AulOra Gas, I..I..C www.aurorapower.com April 4, 2003 Oil and Gas Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: Kaloa No.2 Dear Commissioner( s), Aurora Gas, LLC hereby applies for a Permit to Drill, a prerequisite for drilling the grass- roots well, Kaloa No.2. The well will be located onshore the Granite Point bluff area approximately ~ 7 ~ miles southwest of Tyonek and ~ 2 miles due east of Shirleyville. ~ \~""\-a'-\~ <"~1: 'ObÇ,.-~~') ¡--+-\fø"L -CYS\ Access will be via th~~.?~d system originally installed to drill the Pan Am Albert Kaloa r ~ t\.. C:;/~ _~~\. No. 1 and the Simpco Kaloa No. 1 wells. A drill site will be constructed directly adjacent " \ \ to and using part of the original Pan Am Kaloa No. 1 well-site. Upon receipt of all necessary permits and approvals, contractors will clear the original access roads of overgrowth and extend / rebuild the original Pan Am Kaloa drill site. The 13-3/8" conductor will be driven and the rig, Aurora Well Service No.1, will be rigged up over the well to commence drilling operations. Aurora plans to begin drilling operations on July 1,2003. Pertinent 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 MC 25.050 (c)(2). 4) Diagrams and description of the BOP equipment to be used as required by 20 AAC 25.035 (a)(l) and (b). 5) The drilling fluid program, in addition to the requirements of20 MC 25.033 are attached. 6) A copy of the proposed drilling and completion program, procedures and operational considerations. R E C E IVE D APR 0 9 Z003 Op10! r\ t ',J ¡ , II f ~ ,\ "\ L- Alaska Oil & Gas Cons. Commission Anchorage 10333 Richmond Avenue, Suite 710· Houston, Texas 77042· (713) 977-5799· Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220· Anchorage, Alaska 99501· (907) 277-1003· Fax (907) 277-1006 . e Commissioner( s) Page 2 7) Aurora Gas LLC. does not anticipate the presence ofH2S in the formation to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during sidetracking, drilling and completion operations. 8) A Summary of Potential Well Hazards. 9) Pressure Information 10) The following are Aurora Gas LLC's designated contacts for reporting responsibilities to the Commission. 1) Completion Report (20 AAC 25.070) Duane Vaagen, Project Engineer (907) 258-3446 2) Geologic Data and Information (20 AAC 25.071) Andy Clifford, Vice President (713) 977-5799 3) Well Records, Testing and Production Reporting (20 AAC 25.070) Ed Jones, Vice President (713) 977-5799 If you have any questions or require additional information, please contact the undersigned at (713) 977-5799, or Duane Vaagen at (907) 258-3446. Sincerely, AURORA GAS, LLC . Edward Jones Vice President, Operations and Engineering Enclosures cc: Duane Vaagen Andy Clifford RECEIVED APR 0 9 2003 Alaska Oil & Gas Cons. Commission Anchorage o ! L F'~WI!ÃtrHEÌ éxJP~AmN BPPRODUCTION SERVICES ING.I GENERAL ACCOUNT 10868 10868 VENOOR 1.0. NAME PAYMENT NUMBER DISCOUNT WRITE-OFF $0.00 $0.00 NET $100.00 OUR \¡QUQiER NUMBER YOUR VOUCHER NUMBER DATE 4 9 2003 AMOUNT 100.00 $100.00 $100.00 $0.00 $0.00 $100.00 COMMENT FAIRWEATHER EXPLORATION & PRODUCTION SERVICES INC. GENERAL ACCOUNT P.O. BOX 103296 ANCHORAGE, AK 99510-32% PH. (907) 258·3446 FIRST NATIONAL BANK OF ANCHORAGE ANCHORAGE, AK 99501 89-611252 - 1 DATE 4/9/2003 10868 AMOUNT $100.00 PAY One Hundred Dollars And 00 Cents TO THE ORDER OF STATE OF ALASKA AOGCC 333 WEST 7TH AVE SUITE 100 ANCHORAGE AI< 99501 -~---- .. ..___. .__/!If AUTHORIZED SIGNATURE ilia ¡'08 b8111 _: ¡. 25 2000 bO-: 0 ¡.¡. 2 8 2 ~ Dill ---------- ------ fÀiRwÊÃmE~ ÉiPEðWÄ'ìiöN ~PRODUCTION SERVICES INC. I GENERAL ACCOUNT 10868 10868 ;¡¡ ¡ ~ ~ (/) z o ;: 3 o (/) (/) (/) IU Z ¡¡¡ ¡¡¡ (/) z 3 Q. !< IU a: '" Ii: o (/) o a: o ~ '" ¡¡¡ .... " z ~ VENDOR 1.0. I NAME I PAYMENT NUMBER I CHECK DATE I I 1049 I STATE OF ALASKA AOGCC 100008867 14/9/2003 1 I OUR \¡QUQiER NUMBER YOUR VOUCHER NUMBER DATE AMOUNT AMOUNT PAID DISCOUNT WRITE-OFF NET 00013345 1049030409*K#2 4/9/2003 $100.00 $100.00 $0.00 $0.00 $100.00 RECEIVED APR 0 9 2003 A'as\(a Oil & Gas Cons. Commission Anchorage $100.00 $100.00 $0.00 $0.00 $100.00 1 COMMENT . 51N321 t . e TRANSMJT AL LETTER CHECKLIST CIRCLE APPROPRIATE LETTERlPARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME k~ # 2-- PTD# ::203'-- 0 ~7 / CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI The permit is for a new well bore segment of LATERAL existing well ~ Permit No, API No. . (H 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(t), 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 exception. (Companv Name) assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' sample intervals from below tbe permafrost or from where samples are first caught and 10' sample intervals through target zones. Rev: 07110/02 C\jody\templates Field & Pool ALBERT KALOA, UNDEFINED GAS - 40500 Well Name: KALOA 2 Program DEV Well bore seg D PTD#: 2030710 Company AURORA GAS LLC Initial ClasslType DEV I PEND GeoArea 820 Unit On/Off Shore On Annular Disposal D Administration 1 P~emitfe~ attached _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 2 Leas~ _numb~r <1PRropJiat~ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 3 _U_niqu~ w~ltn_am~ _a!:ld Iwmb~r _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . . . _ _ _ _ _ _ _ _ _ . . . Y~s _ _ _ _ _ _ _ _ . . . _ . _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ . _ . . _ . . _ _ _ _ _ _ _ _ _ _ _ _ . . . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ 4 WeJIJocat~dinad~tinedpool_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _l='ooJha_s_noty_etbee!:ldefined _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ 5 WeJI Jo_cat~d prop~r dista!:lceJrom driJli!:lg unitboundary _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 6 WeJI Jocat~d prop~r dista!:lce f(Om_ QtheJ w~lIs_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ 5impço Kaloa tit (:1,_500' 5) i$ listed aSßhut:in, butit ha$ 3 downhol~ plugs 8< is not capabl~ of producting._ 7 Sufficient <1crea9-e_available in_drilJin9- unJL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 8 Jtd~viated, isweJlboJ~ plaUncJuded _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ V~rticatweJI_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 9 0per_ator only aff~cted party _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 10 _Operator has .appropriate_ b9!:1d in Jorce. . _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ _ . . . . _ _ _ _ _ Y ~L . . _ . _ _ Letter_ oJ Cred iL . _ . _ _ _ _ _ _ _ _ . . . . _ _ _ _ _ _ _ _ _ _ . . _ . . . . . _ _ _ _ _ _ _ _ _ . . . . . . . _ _ _ _ _ _ _ . . 11 P~emitcao b~ i$su_ed witho_ut conservation Qrd~r _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Appr Date 12 P~emitc_ao be i$su_ed without administrativ.e_approvaJ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ SFD 12/11/2003 13 Can permit be approved before 15-day wait Yes 14 WeJlJocat~d within area and_strata authQrized byJojection Ord~r # (puUO# in_comm~ots>-<for _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 15 A!lw~lIs_withinJKmil~_are_a_ofeeYiewid~otified(Foeservic~.w~IJonlYL _ _ _..... _ _ _ _ _ _ _NA..... _ _ _ _ _ _ _ _..... _ _ _ _ _ _ _ _.... _. _ _ _ _ _ _ _ _ _ _...... _ _ _ _ _ _ _ _ _ _..... _ _ _ _ _ _ _ _ _. _. 16 Pre-Rroduçed_i!:ljector~ duration_ofpr~-productionl~ss_than_3.months_(for_seryiçeweIt Qnly) _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ 17 ACMPFindingofCQn$i$te!:lcy_hasb~enJssu~dJorJbisproiec! _ _ _ _ _ _ _ _ _ NA _ _ _ A/17J03;ACMPJ~view_requirem~ntwillbed~termin_edbYGI~oGray._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ Engineering Appr Date TEM 4/22/2003 Geology Appr SFD Date 4/17/2003 Geologic Commissioner: o~ e 18 Çpoductor steingprQvided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 19 _SurfacecasJngpJQtects_ alLk!:lown_ USDWs _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ Surtace ca$ing (s~t at 620' MD) andproducHo!:l casing (se! at3700' MD) will be cementedtQ sUJface. _ _ 20 _CMTvotad~qu_ateJo circulate_onconductor_& surfC$g _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 21 ÇMT-votadequateJo ti~-inIQng $tring to_surf CS-9_ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ ,l='lan i$ to cem~!:ItprQductioo casingJQ su_rface. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 22 _CMTwill GOver_ail kno.wnproductiv~ bQri'zQn$_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 23 _Casiog desig!:lS ad_equa!e_ foe C, T, B&p_ermaJros! _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 24 Adequat~JanJ<age_oJfe$ery~ pit _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ Rig is_equippe_d.wnb $t~elpits. _NoJeseJ\l.epitpta!:lned, A!:IY driJIing waste to Enyiro:1eçb for disRosal. _ _ _ _ _ _ 25 Jta_re-deilt bas_a_ to:4_03 fOJ aba_ndonment be~o aRprQved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 26 Adequat~ -,,'(ellbore_ separation proposed _ _ _ _ _ _ _ _ _ . . . _ _ _ _ _ _ _ _ _ . . . . . _ . _ _ _ _ _ _Y~L . _ _ _ _ _ Closest weJI Js. t20'_dis!a_nt at.surfa_ce._ ~o pro~imi!y_ Rrobl~m anticipated. _ _ _ . _ . . . . _ _ _ _ _ _ _ _ _ _ _ . . _ _ _ 27 Jtdivert~rr~quire_d.do_e$itme~treguJa_tions_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _10~'diverterlin_e, Pla!:lto_driJI8-1l2"pilotbQI~and_opentoJ2-V4~._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ 28 _DrilJio9- fluidpJQgram schematic & ~quip Jis!adequat~ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ Expected BH~ 8.6 EMW.~otential fOJ higb~r EMW shallQW. PJanJo SRud .with 9.5 ppg mud. _ _ _ _ _ _ _ 29 BOPEs,_do!hey meetreguJa!ion _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 30 _BOPEpress ra!iog approp(iate;t~stto _(put psig in_commentsL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ YeL _ MASf' estimated at t450 psi. Aurora _normally tests their BOI=' to_ 3.000 psL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 31ChokemaMold compJies w/APtR~-53_ (May 84L _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 32 WOJk will occue withouLoperatlon_sbutdo.wn_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 33 Js RreS_e!:lce_ oJ H2S gas_ pJQb_able _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ N_o _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 34 Mechanical_condJtioo of wells wi!hJn AOR y~rified_ (for_se(\/ice w~1J only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - ~ - - - - -e 35 P~rmitcao be i$su_ed wlo_hYdrog~n_s_uIJid~ meaSure$ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s 36 Dala_pre_sented on_ Rote_ntial ovefRres_sur~ zone$ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y~s _ 37 S~ismicanalysis_of shaJlow gas_zoo~s_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA 38 _S~abedconditioo survey (if off-shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA 39 _Contact namelphone}orweekly progress_reRorts [e1<RloratoryonIYL _ _ _ _ _ _ _ NA _ _ _ _ No 1:i2S kn_owo inJegiQn, _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Offs_et w~lIcontrol indicaJ~s_normaJ press_ure_Qradient. Surface hole wiJl be drJlled _ _ _ _ _ _ _ _ _ _ _ _ _ _ with_9Ji -_ to_ppg mud;productioo inteNal with 9,2 RP9 mud._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Well will b~ drilled within 50' Qf existing Albert Kaloa tit ~xplor_atory_ weJlll='&A'~d>-- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - Date: Engineering Comm issioner: > ~-/ /2//;/5 Samples not required as this well will be drilled within 50 feet of the Albert Kaloa #1 exploratory well, which has samples from 36' to 13,600' MD. Methane, H2S, and PVT sensors will be in place and operational. No H2S has been found in this area. SFD Public Commissioner Date (<J IS D