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203-188
• 07o3- ) sS / o Seth Nolan Hilcorp Alaska, LLC ¢� GeoTech 3800 Centerpoint Drive, Suite 100 90`'1 ' 0840 Anchorage, AK 99503 �, l Tele: 907 777-8308 Ffilrurp ALtrku.i i i Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 05/19/2016 To: Alaska Oil & Gas Conservation Commission RECEIVED Meredith Guhl Petroleum Geology Assistant MAY 2 0 2016 333 W 7th Ave Ste 100 Anchorage, AK 99501n OG C DATA TRANSMITTA BCU 12 & 14 Electric log data CD: 1 DIGITAL LOG DATA SCANNED MAY 2 5 2016 d BCU 14 }:IN T'VD.tif • BCU 14 AIS-VEC MD.tif • BCU 14 AIS-'V'"EC-2 MD,tif • BCU 14 COMP-SONIC MD.tif BCU 14 PNS MD,tif • BCU 12 AIS TVD,tif BCU 12 COMP-PHOTO-DEN-COMP-NEUT TVD,tif is BCU 12 SONIC TVD.tif BCU 12 VECTAR T'V'D,tif e BCU-12 CSS-R.TP MD,tif BCU-12 Drd-REPL.A.'t MD,tif • BCU-12REG-IND-REPLAY MD.tif s.- BCU-12 'VECTAR MD.tif 14i FINAL_Data_Marathon_BCU 14_complete,dpk ffr FINAL_Data_Marathan_BCU 14_plotted.dpk fffr T14138_Reev es_m d.d p k T14138_Reeves_ty d.d p k Please include current contact information if different from above. , Please acknowledge receipt by sign'gg and returning one copy of this transmittal or FAX to 907 777.8337 Received By: 1 Date: < l2-0 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. ~ 03 -. 1 g g Well History File Identifier Organizing (done) D Two-sided 111111111111111111I D Rescan Needed 1111111111111111111 R~CAN ¢' Color Items: D Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, NolType: D Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: Date OJ .'.'7/ Db D Other:: BY: ~ 151 YYlf Project Proofing 1111111111111111111 BY: ~ Date q /15/00 \~ x 30 = c¡ 0 + d3 = TOTAL PAGES 1/3 Date: / IS / 0 ~ (Count does not i~~~ude cover sheet) 9 11111111I1111111111 151 M(J Scanning Preparation BY: ~ mr Production Scanning Stage 1 Page Count from Scanned File: I J Lf- (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES ~ Date:ql/S(ofo If NO in stage 1, page(s) discrepancies were found: 151 NO 1V\P BY: Stage 1 YES NO BY: Maria Date: 151 1/1111/111111111111 Scanning is complete at this point unless rescanning is required. ReScanned 1111111111111111111 BY: Maria Date: 151 Comments about this file: Quality Checked 11I1111111111111111 10/6/2005 Well History File Cover Page.doc Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, June 03, 2014 2:19 PM To: 'Stan Porhola' Subject: RE: Change request for BCU-12 (PTD 203-188) procedure (Sundry 314-286) Stan, Additional cement placed with coil is approved. I will place the updated procedure in the well file as record of the change. Guy Schwartz Senior Petroleum Engineer SCANNED AUG 1 4 20i4 AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Stan Porhola [mailto:sporhola'='hilcorp.com] Sent: Tuesday, June 03, 2014 12:54 PM To: Schwartz, Guy L (DOA) - Subject: Change request for BCU-12 (PTD 203-188) procedure (Sundry 314-286) Guy, Can we get approval for the following changes to the procedure for the plugback of Beaver Creek#12 (PTD 203-188) in the approved sundry(314-286)? The attached procedure has the changed/added steps listed in red.The main change is to use coiled tubing to spot cement across the open perforations. Also attached is the proposed schematic. Would plan to start rigging up coil on Thursday,June 5th.The Moncla 401 rig will move in as soon as the coil work is done. Regards, Stan Porhola Operations Engineer North Kenai Asset Team Hilcorp Alaska,LLC sporhola@hilcorp.com Office: (907) 777-8412 Mobile: (907) 331-8228 t Well Prognosis Well: BCU-12 Hilcora Alaska,Ll: Date:6/03/2014 Well Name: BCU-12 API Number: 50-133-20530-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: June 5th, 2014 Rig: Coiled Tubing Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 203-188 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: Current Bottom Hole Pressure: — 1,245 psi @ 7,701' TVD (Static survey June 2005 below bottom zone 7,884' MD) Maximum Expected BHP: — 1,245 psi @ 7,701' TVD (Static survey June 2005 below bottom zone 7,884' MD) Max. Allowable Surface Pressure: — 475 psi (Based on actual reservoir conditions and gas gradient to surface(0.10psi/ft) Brief Well Summary Beaver Creek Unit#12 was drilled as a Grass roots EXCAPE monobore completion in 2004 to target gas sands in the lower Beluga formation. All 12 EXCAPE modules were perforated and fracture stimulated.A capillary string was installed to deliver foamer to alleviate liquid loading in 2009. The capillary string was pulled in Sep 2010 but a fish was left in the well.The capillary string was re-ran to a shallower depth in Oct 2010. The capillary string was pulled in Feb 2014 and soap sticks have been dropped in place of the foamer. The purpose of this work/sundry is to abandon the current perforated interval (using coiled tubing in combination with slicifime)and prepare the wellbore for re-drilling operations. Notes Regarding Wellbore Condition • Last tag at 8,287'SLM on 2/18/14 w/a 2.50"Overshot. Coiled Tubing Procedure: 1. MIRU Coiled Tubing, PT BOPE to 3,000 psi Hi 250 Low. 2. RU 1.75"coil cleanout BHA 3. RIH and washdown from 7,228'to top of fish at 8,287' MD using 8.5 ppg lease water. 4. Mix and pump 10 bbl of 15.8 ppg cement from 8,287' MD. a. BHT= 135°F @ 8,287' MD/8,104'TVD. 5. POOH with 1.75"coiled tubing to above top of proposed top of cement at 7,200' MD. 6. Reverse circulate well clean with 8.5 ppg lease water. 7. POOH to surface. ND Injector. 8. RD Coiled Tubing. 9. Wait on cement min 12 hours. 10. MIRU Slickline, PT Lubricator to 3,000 psi Hi 250 Low. 11. RU 2.70"gauge ring, RIH and tag top of cement at+/- 7,200'. 12. RU tubing stop/plug for 3-1/2"tubing, RIH and set at+/-7,150'. Bleed off tubing pressure. 13. Dump bail 10' of cement on tubing plug (4 gallons of cement). 14. RD Slickline. 15. Turn well over to production. Well Prognosis Well: BCU-12 Ilileorp Alaska,LL Date:6/03/2014 WO Rig Procedure: 16. MIRU Moncla#401 WO Rig. 17. Set BPV. ND Tree. 18. NU BOPE.Set BPV.Test to 250 psi Low/3,000 psi High,annular to 250 psi Low/ 1,500 psi High (hold each valve and test for 10-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Notify BLM 48 hrs in advance of BOP test. 19. Bleed any pressure off tubing. Pull BPV. 20. MU landing joint and pull 10-15k tension over string weight on tubing hanger. 21. MIRU E-line. c. MU pump-in sub on 3-1/2" 8RD landing joint. 22. RU 1-11/16" 6'tubing punch. 23. RIH and punch tubing at+/-5,510'-5,516' MD. POOH. 24. RU to reverse circulate out the drilling mud in the 3-1/2"x9-5/8"annulus with lease water. d. Mud weight is 9.4 ppg. Spacer is 10.0 ppg (50 bbl). e. Estimated volume is 327 bbl. 25. RU 3.5"Tubing Jet Cutter. 26. RIH and jet cut tubing at+/-5,500' MD. f. Have backup cutters on location if tubing does not part. g. Plan 2nd jet cut if control lines do not part. h. Make cut above Cement top at 6,400'. 27. RD Eline. 28. SOOH and rack back 3-1/2"tubing. i. Tubing has rigid centralizers, 1 per joint. Utilize open-faced tubing tongs. j. Rigid centralizers secured with hex-screws. Do not drop on top of annular. k. No plans to re-use the 3 recovered control lines.Secured to tubing with bands. I. Expect to find a 1/2" braided line cable on the outside of the tubing. 29. MU flat-bottom BHA w/casing scraper and RIH on 3-1/2"tubing out of derrick. 30. Tag cut tubing at+/-5,500' MD. 31. Circulate well clean w/Produced Lease Water. 32. POOH. LD 3-1/2"tubing,casing scraper and flat-bottom BHA. 33. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. 34. RU 9-5/8"CIBP and GR/CCL tools. 35. RIH and set CIBP at+/-4,800' MD in the 9-5/8"40#casing(set 3-5 ft above a casing collar). 36. RD E-line. 37. Test casing to 2,000 psi for 30 min and chart. 38. Set BPV. ND BOPE. NU dry hole tree. Pull BPV. 39. RD Moncla#401 WO Rig. 40. Turn well over to production in preparation of moving in the Saxon#169 Drilling Rig. 41. Replace IA x OA pressure gauge if removed (9-5/8"x 13-3/8"). Drilling Rig Procedure: 42. MIRU Saxon#169 Drilling Rig. 43. NU BOPE. Set BPV.Test to 250 psi Low/4,500 psi High,annular to 250 psi Low/2,500 psi High (hold each valve and test for 10-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Notify BLM 48 hrs in advance of BOP test. Well Prognosis Well: BCU-12 Ililcorp Alaska,LL Date:6/03/2014 44. MU 4-1/2" DP and 7-7/8" string mill. 45. TIH to CIBP at+/-4,800' MD. 46. POOH standing back DP. 47. Run and set whipstock, displace to 9.0 ppg drilling mud. 48. Mill window and 20' of new formation. 49. Conduct FIT to 11.0 ppg. 50. REMAINING PROCEDURE TO BE SUBMITTED WITH PTD/APD. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic BC 12 Pad 4 SCHEMATIC 2,023' FNL, 482' FEL, PROPOSED liilrorp Alaska.LLC Sec. 33, T7N, R10W, S.M. Permit#: 203-188 Conductor API#: 50-133-20530-00-00 -- zo Top BottK-55 133omf Property Des: A-028083 I MD 0' 107' ' KB: 21'AGL (171' KB Elevation) TVD 0' 107' Lat: 60° 39' 22.118" N Long: 151° 01' 45.593" W Surface Casing 13-3/8" K-55 68 ppf BTC Spud: 5/27/2004 � m TD Reached: 6/10/2004 MD 0' 2,091' Rig Released: 00:00 hrs 06/15/04 TVD 0' 2,091'16"hole Cmt wl 600 sks(271 bbl)of 12.0 ppg, Type 1 cmt, 18 sks(8 bbls)to surface S ,r 'f' Intermediate Casing Tree cxn=6-112'Otis f 0 1 9-518" L-80 40 ppf BTC iiligi Dm Bottom MD 0' 7,160' Bridge Plug @ 4,800' , . TVD 0' 6,978' ",�[ 12-114"hole Lead Cmt w/833 sks(341 bbls)of Jet Cut Tubing @ 5,500' 12.5 ppg,Class G, Tail Cmt w/327 sks(106 bbls) of 13.5 ppg,Class G, 12 sks(5 bbls)to surface Tubing Punch @ 5,510' ' %'K Production Casinq Top of Cement3-1/2" L-80 9.3 ppf EUE @ 6,400'MD 10 C -Ip�^'!y Y" i Tp Bottom 8rd ---=,---- r` r`p't MD 0' 8,773' TVD 0' 8,590' Tubing Plug @ 7,150' ' 8-1/2"hole Cmt wl786sks(1891bbls)of Capped w/10'Cement e l e. ', 15.8 ppg,Class G es-1t. Spot cement(10 bbl)wl `� .,,,i Capillary Tubing C~Pulled 2114/14'"'•) Coiled Tubing '_0 0 ;A 3/8"OD 2205 0.049" 1 Stainless Steel Wall Thickness Excape System Details 'E - ° BHP monitoring Grp line volume tank located from 7,149'-7,185'RKB " Tro '' LI Excape System Details Excape System Details t,f -12 Excape module system -11 Conventional flappers i control line fires modules 5-12 1/4) -Mod 1 -no flapper ' �, - control line fires modules 2-4 Ceramic flapper valves below * - control line fires module 1 each module as follows: -Ceramic flapper valves below each module 'fii (excluding module 1) Flappers MD(RKB): f Module 12-7,247 ` Perfs(Open Hole Log): Module 11 -7,297' *;'; ,, ' MD TVD Date Module 10-7,499' i Module 12- 7,228'4,238' 7,046'-7,056' (8/12/04) Module 9-7,562' _. / � Module 11- 7,279'-7,289' 7,096'-7,107' (8/12/04) Module 8 7,603' Module 10- 7,480'-7,490' 7,297'-7,307' (8/12/04) Module 7-7,675' ' ' Module 9- 7,543'-7,553' 7,360'-7,370' (8/11/04) Module 6-7,750' i. Module 5-7,799' II Module 8- 7,584'-7,594' 7,401'-7,411' (8/11/04) Module 4-7,867' Module 7- 7,656'-7,666' 7,473'-7,483' (8/11/04) Module 3-7,908' t. C-1 Module 6- 7,731'-7,741' 7,548'-7,558' (8/11/04) t s Module 5- 7,780'-7,790' 7,597'-7,607' (8/11/04) Module 2-8,439' - Module 1- NA r Module 4- 7,848'-7,858' 7,665'-7,675' (8/11/04) .-.9t,. Module 3- 7,889'-7,899' 7,707'-7,716' (8/11/04) li Module 2- 8,420'-8,430' 8,237-8,247' (8/11/04) Tag fish @ 8,28T (2/18/14) Module 1 - 8,471'-8,481' 8,288'-8,299' (8/11/04) w/2.50"overshot TD PBTD Fish: @ 8,287'(Lost 8/30/10) 8,839'MD 8,736 MD 3/4"OD X 18"cap string BHA 8,656'TVD 8,553'TVD Possibly 3-4'of 3/8"cap string Well Name&Number: Beaver Creek Unit#12 Lease: A-028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country:I USA KOP and Max Dogleg: KOP @ 2,500'/3.98° 3,439' I Angle/Perfs:1 1.0°42.0° Maximum Deviation: 20°@ 4,196' Date Completed: 08/11/04 Ground Level(above MSL): 150' RKB(above GL): 21' Revised By: Stan Porhola Downhole Revision Date: Proposed Schematic Revision Date: 6/3/2014 ���'��\�I`//%,e, THE S AAT E 1 i tt 1_c ) -- — 333 West Sevenln Avenue P ( t, : FR\OR Sr DAR\1=,LtPp VIMII1P , i, Ancnorage Alaska 99501 3572 Mom 907.219 S MAY 1 6 Z014 Stan Porhola Operations Engineer '8 'Hilcorp Alaska, LLC � O3 ✓ 3800 Centerpoint Drive, Suite 1400 O'er Anchorage, AK 99503 Re: Beaver Creek Field, Beluga Gas Pool, Beaver Creek Unit#12 Sundry Number: 314-286 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. scerely, V l Daniel T. Seamount, Jr. Commissioner DATED thi day of May, 2014. Encl. G • Sill 144 RECEIVED , STATE OF ALASKA 4 ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 0 2 2014 APPLICATION FOR SUNDRY APPROVALS ����� 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrii 0, Perforate New Pod ❑ Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing Q - Time Extension❑ Operations Shutdowt❑ Re-enter Susp.Wel ❑ Stimulate❑ After Casing❑ Other.❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development [ ' 203-188 • 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service ❑ 6.API Number Anchorage,Alaska 99503 50-133-20530-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 237.002 BWill planned perforations require a spacing exception? Yes ❑ No 2 er Creek Unit(BCU)#12 . 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028083 Beaver Creek/Beluga Gas Pod • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 8,839 - 8,656 • 8,736 8,553 N/A 8,287 Casing Length Size MD TVD Burst Collapse Structural Conductor 107' 20" 107' 107' Surface 2,091' 13-3/8" 2,091' 2,091' 3,450 psi 1,950 psi Intermediate 7,160' 9-5/8" 7,160' 6,978' 5,750 psi 3,090 psi Production 8,773' 3-1/2" 8,773' 8,590' 10,160 psi 10,540 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#,L-80 8,773' Packers and SSSV Type: N/A;N/A Packers and SSSV MD(t)and ND(ft): N/A;N/A 12.Attachments: Description Summary of Proposal ❑✓ 13.Well Class after proposed work: Detailed Operations Program r] BOP Sketch n Exploratory ❑ Stratigraphic f Development n Service n 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 05/15/14 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑✓ • 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhda Phone: 907-777-8412 Email sDorholaOhilcorD.com Printed Name Stan Porhola Title Operations Engineer Signature Phone 907-777-8412 Date S o4/�� COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3\Lt-Z1319 Plug Integrity ❑ BOP Test [ Mechanical Integrity Test ❑ Location Clearance ❑ Other: '413060 ..-----. L Ec�P,��ve.Q 'or7t /-1.� c Z-c-1/1(L) Spacing Exception Required? Yes ❑ No [il Subsequent Form Required: /0 •- /10 7 lz:V..-- APPROVED BY 5-0/..-- Approved by: COMMISSIONER THE COMMISSION Date: © � t A I � l ( Submit Form and Rtrag(R 2 1 1 Appr d c nA11J-7Yicf r Lmont���fffs from the date- of approval. X Attachments in Duplicate Well Prognosis Well: BCU-12 Hilcorp Alaska,LL Date:5/01/2014 Well Name: BCU-12 API Number: 50-133-20530-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: May 15th, 2014 Rig: Moncla 405 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 203-188 First Call Engineer: Stan Porhola (907)777-8412 (0) (907)331-8228(M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: - 1,245 psi @ 7,701'ND (Static survey June 2005 below bottom zone 7,884' MD) Maximum Expected BHP: - 1,245 psi @ 7,701'ND (Static survey June 2005 below bottom zone 7,884' MD) Max. Allowable Surface Pressure: -475 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Beaver Creek Unit#12 was drilled as a Grass roots EXCAPE monobore completion in 2004 to target gas sands in the lower Beluga formation.All 12 EXCAPE modules were perforated and fracture stimulated.A capillary string was installed to deliver foamer to alleviate liquid loading in 2009.The capillary string was pulled in Sep 2010 but a fish was left in the well.The capillary string was re-ran to a shallower depth in Oct 2010.The capillary string was pulled in Feb 2014 and soap sticks have been dropped in place of the foamer. The purpose of this work/sundry is to abandon the current perforated interval and prepare the wellbore for re- • drilling operations.A drilling permit application will be submitted separately for the sidetrack. Con 'C. Y10 so-ell 40 jet,/ /'4 S ,1o()__. Notes Regarding Wellbore Condition dell,. 101. i#'S Pr:re 'tett/Jr- 10 les Met_ Q44' f Sk twp1 /�a,/{,C.q► .foa,a kt-atv W;f • Last tag at 8,287'SLM on 2/18/14 w/a 2.50" Overshot. T4'r redo e'd e_.j riaw. C.4 q f,ecffir rite ►vel .f no f Slickline Procedure: lk pP ,/4/®coli p GA lex n24.led. 1. MIRU Slickline, PT Lubricator to 3,000 psi Hi 250 Low. eve,, t r fe 'ft f4,19, 2. RU 2.70"gauge ring, RIH and tag fill/obstruction at+/-8,287'. 4110 lo, /*fro K1 'cowry 3. RU tubing stop/plug for 3-1/2" tubing, RIH and set at+/-7,210'. Bleed off tubing pressure. 44 r4ei 4. Dump bail 35'of cement on tubing plug(13 gallons of cement). 5. Wait on cement for 12 hours. 6. RU 2.50" bailer and tag top of cement. "G 5� 314 7. RD Slickline. Fr • - 6 fes;, WO Rig Procedure: 8. MIRU Moncla#405 WO Rig. 9. Set BPV. ND Tree. 10. NU BOPE.Set BPV.Test to 250 psi Low/3,000 psi High, annular to 250 psi Low/1,500 psi High (hold each valve and test for 10-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Notify BLM 48 hrs in advance of BOP test. V / ‘ ll Well Prognosis Well: BCU-12 Hilcorp Alaska,LL Date:5/01/2014 11. Bleed any pressure off tubing. Pull BPV. 12. MU landing joint and pull 10-15k tension over string weight on tubing hanger. 13. MIRU E-line. a. MU pump-in sub on 3-1/2"8RD landing joint. 14. RU 1-11/16" 6' tubing punch. 15. RIH and punch tubing at+/-5,510'-5,516' MD. POOH. 16. RU to reverse circulate out the drilling mud in the 3-1/2"x9-5/8"annulus with lease water. a. Mud weight is 9.4 ppg.Spacer is 10.0 ppg(50 bbl). b. Estimated volume is 327 bbl. 17. RU 3.5"Tubing Jet Cutter. 18. RIH and jet cut tubing at+/-5,500' MD. a. Have backup cutters on location if tubing does not part. b. Plan 2nd jet cut if control lines do not part. c. Make cut above Cement top at 6,400'. 19. RD Eline. 20. SOOH and rack back 3-1/2"tubing. a. Tubing has rigid centralizers, 1 per joint. Utilize open-faced tubing tongs. b. Rigid centralizers secured with hex-screws. Do not drop on top of annular. c. No plans to re-use the 3 recovered control lines.Secured to tubing with bands. d. Expect to find a 1/2" braided line cable on the outside of the tubing. 21. MU flat-bottom BHA w/casing scraper and RIH on 3-1/2"tubing out of derrick. 22. Tag cut tubing at+/-5,500' MD. 23. Circulate well clean w/Produced Lease Water. 24. POOH. LD 3-1/2"tubing, casing scraper and flat-bottom BHA. 25. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. 26. RU 9 5 8" P and GR/CCL tools. 27. RIH and set CIBP at+/-4,800' MD in the 9-5/8"40#casing(set 3-5 ft above a casing collar). 28. RD E-line. 29. Test casing to 2,000 psi for 30 min and chart. 30. Set BPV. ND BOPE. NU dry hole tree. Pull BPV. 31. RD Moncla#405 WO Rig. 32. Turn well over to production in preparation of moving in the Saxon#169 Drilling Rig. 33. Replace IA x OA pressure gauge if removed (9-5/8"x 13-3/8"). Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic .. fit BC-12 ACTUAL Pad4 SCHEMATIC Hilcorp Alaska.LLC 2,023' FNL, 482' FEL, Sec. 33, T7N, MOW, S.M. conductor Permit#: 203-188 20" K-55 133 ppf API#: 50-133-20530-00-00Top Bottom Property Des: A-028083I MD 0' 107' KB: 21'AGL (171'KB Elevation) .; ND 0' 107' Lat: 60° 39' 22.118" N ` er Lonq:, 151° 01' 45.593" W Surface Casing Spud: 5/27/2004 •* 13-3/8" K-55 68 ppf BTC T] Bottom TD Reached: 6/10/2004 4A Sym` ND 0' 2,091'1 Rio Released: 00:00 hrs 06/15/04 f'?,„,.."-- 16"hole Cmt w/600 sks(271 bbl)of 12.0 ppg, ti y! P Type 1 cmt, 18 sks(8 bbls)to surface hillir t. of Intermediate Casing ;.# • 4 9-5/8" L-80 40 ppf BTC -13p Bottom MD 0' 7,160' !Wee cxn=6-1/2"OtisND 0' 6,978' 12-1/4"hole Lead Cmt w/833 sks(341 bbls)of r 12.5 ppg,Class G, Tail Cmt w/327 sks(106 bbls) Top of Cement T4 of 13.5 ppg,Class G, 12 sks(5 bbls)to surface @ 6,400'MD ' 4-, Excape System Details Production casing - 3-1/2" L-80 9.3 ppf EUE -BHP monitoring Green line volume Top Bottom 8rd tank located from 7,149'-7,185'RKB MD 0' 8,773' - ND 0' 8,590' 8-1/2"hole Cmt w/786sks(1891bbls)of .1 15.8 ppg,Class G Excape System Details 11 Conventional flappers Capillary Tubing (***Pulled 2/14/14***) -Mod 1 -no flapperi I • 3/8"OD 2205 0.049" -Ceramic flapper valves below II Stainless Steel Wall Thickness each module as follows: II Flappers MD(RKB): y 1 Module 12-7,247 h7 r Module 11 -7,297' ` I t,, Excape S stem Details Module 19-7,499' I ' 12 ymodule Module 9 7,562' - Excapesystem Module 8-7,603' F ll • '• -Red control line fires modules 5-12 Module 7-7,675' - control line fires modules 2-4 Module 6-7,750' -Green control line fires module 1 Module 5-7,799' '. -Ceramic flapper valves below each module Module 4-7,867' t„ it (excluding module 1) Module 2-7,908' q Module 2-8,439' � Perls(Open Hole Log): j 9 Module 1 - NA MD TVD Date i,.'+, ( Module 12- 7,228'-7,238' 7,046'-7,056' (8/12/04) Module 11 - 7,279'-7,289' 7,096'-7,107' (8/12/04) Module 10- 7,480'-7,490' 7,297'-7,307' (8/12/04) " Module 9- 7,543'-7,553' 7,360'-7,370' (8/11/04) 1 Module 8- 7,584'-7,594' 7,401'-7,411' (8/11/04) Tag fish @ 8,287' (2/18/14) Module 7- 7,656'-7,666' 7,473'-7,483' (8/11/04) w/2.50"overshot x �In Module 6 7,731'-7,741' 7,548'-7,558' (8/11/04) elModule 5- 7,780'-7,790' 7,597'-7,607' (8/11/04) Module 4- 7,848'-7,858' 7,665'-7,675' (8/11/04) Module 3- 7,889'-7,899' 7,707'-7,716' (8/11/04) Fish: @ 8,287'(Lost 8/30/10) Module 2- 8,420'-8,430' 8,237'-8,247' (8/11/04) 3/4"OD X 18"cap string BHA Module 1 - 8,471'-8,481' 8,288'-8,299' (8/11/04) Possibly 3-4'of 3/8"cap string TD PBTD 8,839' MD 8,736 MD 8,656'TVD 8,553'TVD Well Name&Number:. Beaver Creek Unit#12 Lease: A-028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA KOP and Max Dogleg: KOP @ 2,500'/3.98° 3,439' Angle/Perfs: 1.0°42.0° Maximum Deviation: 20°@ 4,196' Date Completed: 08/11/04 Ground Level(above MSL): 150' RKB(above GL): 21' Revised By: Stan Porhola Downhole Revision Date: 2/18/2014 Schematic Revision Date: 2/20/2014 _._ BC-12 PROPOSED Pad4 SCHEMATIC 2,023' FNL,482' FEL, Hilcorp Alaska,LLC Sec. 33, T7N, MOW, S.M. Permit#: 203-188 conductor 20" K-55 133 ppf API#: 50-133-20530-00-00 Top Bottom Property Des: A-028083 MD 0' 107' KB: 21'AGL (171' KB Elevation) ND 0' 107' Lat: 60° 39' 22.118" N Long: 151° 01' 45.593" W Surface Casing Spud: 5/27/2004 , 13-3/8" K-55 68 ppf BTC -1:ip Bottom TD Reached: 6/10/2004 'y MD 0' 2,091' iRiq Released: 00:00 hrs 06/15/04 TVD 0' 2,091' 1 16"hole Cmt w/600 sks(271 bbl)of 12.0 ppg, ''' • Type 1 cmt, 18 sks(8 bbls)to surface 111 Intermediate Casing Tree cxn=6-1/2"Otis °� ,1 9-5/8" L-80 40 ppf BTC kik TOp Bottom r MD 0' 7,160' Bridge Plug @ 4,800' ,•' ,'! TVD 0' 6,978' 12-1/4"hole Lead Cmt w/833 sks(341 bbls)of Jet Cut Tubing @ 5,500' �.' 12.5 ppg,Class G, Tail Cmt w/327 sks(106 bbls) ,..,EA of 13.5 ppg,Class G, 12 sks(5 bbls)to surface Tubing Punch @ 5,510' ,i 1.. Production Casing Top of Cement ! 3-1/2" L-80 9.3 ppf EUE i if @ 6,400'MD Top Bottom 8rd `;1 MD 0' 8,773' TVD 0' 8,590' Tubing Plug @ 7,210' ', - ° 8-1/2"hole Cmt w/786sks(1891bbls)of Capped w/35'Cement L 4 ?•4 15.8 ppg,Class G y0," /.r, 1, 1 Z 5 y� Capillary Tubing (***Pulled 2/14/14***) ,, 3/8"OD 2205 0.049" i I I Stainless Steel Wall Thickness Excape System Details ►r, -BHP monitoring Green line volume ° Il tank located from 7,149'-7,185'RKB I Excape System Details Excape System Detailso I I3 _122 Excape module system ' -Red control line fires modules 5-12 -11 Conventional flappers ;iii I '!,.. - -Ceramic flapper valves below 11 1.* control line fires modules 2-4 -Mod 1 -no flapper -Green control line fires module 1 each module as follows: -Ceramic flapper valves below each module it (excluding module 1) Flappers MD(RKB): Module 12-7,247 I • Perfs(Open Hole Log): Module 11 -7,297' - MD TVD Date Module 10-7,499' -1(i Module 12- 7,228'-7,238' 7,046'-7,056' (8/12/04) Module 9-7,562' Module 11 - 7,279'-7,289' 7,096'-7,107' (8/12/04) Module 8-7,603' II C Module 10- 7,480'-7,490' 7,297'-7,307' (8/12/04) Module 7-7,675' T Module 9- 7,543'-7,553' 7,360'-7,370' (8/11/04) Module 6-7,750' Module 8- 7,584'-7,594' 7,401'-7,411 (8/11/04) Module 4-7,867' •Module 4-7,867' lir Module 7- 7,656'-7,666' 7,473'-7,483' (8/11/04) Module 3 7,908' ii Inlam Module 6- 7,731'-7,741' 7,548'-7,558' (8/11/04) Module 2-8,439' IjyllModule 5- 7,780'-7,790' 7,597'-7,607' (8/11/04) Module 1 - NA Module 4- 7,848'-7,858' 7,665'-7,675' (8/11/04) t4 Module 3- 7,889'-7,899' 7,707'-7,716' (8/11/04) It Module 2- 8,420'-8,430' 8,237'-8,247' (8/11/04) Tag fish @ 8,287' (2/18/14) Module 1 - 8,471'-8,481' 8,288'-8,299' (8/11/04) w/2.50"overshot TD PBTD Fish:@ 8,287'(Lost 8/30/10) 8,839' MD 8,736 MD 3/4"OD X 18"cap string BHA 8,656'TVD 8,553'TVD Possibly 3-4'of 3/8"cap string Well Name&Number: Beaver Creek Unit#12 Lease: A-028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA KOP and Max Dogleg: KOP @ 2,500'/3.98° 3,439' Angle/Perfs: 1.0°42.0° Maximum Deviation: 20° 4,196' Date Completed: 08/11/04 Ground Level(above MSL): 150' RKB(above GL): 21' Revised By: Stan Porhola Downhole Revision Date: Proposed Schematic Revision Date: 5/2/2014 4 Beaver Creek BC # 12 BOP Moncla 05/01/2014 1liknrp 'l**L.. AIM Hydril WEI 4.54'' GI< 13 5/8-10,000 1%I i! 1111111114111 DSA 1.00' 13 5/8 5M X 13 5/8 10M Spacer spool 2.00' 135/85MX 13 5/8 5M ,Ifs' ft Oft rn • Shaffer L)a 1=Ci 2 7/8-5 Variables 2.83 13 5/8 5M Blind 01), 2 1/16 5M Kill Valves 2 1/16 5M Choke Valves Manual and 1ICR � 1 ! i1 1jl 1#I Manual and HCR�''h Mud Cross ; 3.00' +� �� .1 13 5/8 5M FE! " I. X11' wl4 1116 5M i 'e t1i3 ? s it tarjr EFO rftrit Grade Level ■Ii?"a _ 'Mr7i WEIN— I' = I• II • ~ IUlarathon MQRATHON Alaska Production LLC ~ November 11, 2009 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Beaver Creek Field Well: Beaver Creek Unit #12 M~hon Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~~~~~~~~ ~Q~ ~ ~ 2.~1~9 Co~,ssion ~Iesks0il &~es Cons• p~n~h~~~~+~ ~:~~~~~G~ ~0 ;f ~~ ~ 200~ Dear Mr. Aubert: Attached for your records is the10-404 Report of Sundry Well Operations for BC-12 well. This report covers the work performed to install a capillary string, in BC-12, to a setting depth of 7,892' MD. The installation was perFormed on November 5, 2009. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, . ~~i~ .,~,tJ~,~v , ~ Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS STATE OF ALASKA ALAS~IL AND GAS CONSERVATION COMMI~N REPORT OF SUNDRY WELL OPERATIONS ~'`v. ., ~~... 4 ,,~, , .~l 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Install Cpillary Performed: Alter Casing ~ Pull Tubin~ Perforate New Pool ~ Waiver[] Time Extension ^ String Change Approved Program ^ Operat. Shutdowr0 Perforate ^ Re-enter Suspended Well ~ 2. Operator Marathon Oil Company N 4. Well Class Before Work: ~ Permit to Drill Number: ame: Development ^~ Exploratory^ 203-188 3.Address: PO BOx 1949 Stratigraphic^ Service^ ('~API Number: Kenai Alaska, 99611-1949 50-133-20530-00-00 7. KB Elevation (ft): Well Name and Number: '"~ 171' 21' AGL Beaver Creek #12 8. Property Designation: 10. Field/Pool(s): ``~ A- 028083 ~ Beaver Creek Field / Beluga Pool 11. Present Well Condition Summary: ' Total Depth measured `~. $,g3g' feet ~~~~~~~~~gs (measured) NA true vertical 8,656' feet Junk (measured) NA ~ov ~ ,~a~ Effective Depth measured 8,736' feet . true vertical 8,553' fe~r~~~ ~I~ ~c ~a~` .vUMI$. ~eQ(hrpjggpp~ ~;s~~~~r~ge Casing Length Size MD TVD Burst Collapse Structural Conductor $6' 20" 107' 107' 3,060 psi 1,500 psi Surface 2,068' 13-3/8" 2,091' 2,091' 3,450 psi 1,950 psi Intermediate 7,139' 9-5/8" 7,160' 6,978' 5,750 psi 3,090 psi Production g,752' 3-1/2" 8,773' 8,590' 10,160 psi 10,540 psi Liner Perforation depth: Measured depth: 7,22$' -$,4$1' True Vertical depth: 7,046' - 8,299' Excape Tubing 3-1/2" L-80 8,773' Tubing: (size, grade, and MD) Capillary String 3/8" 2205 Stainless Steel 7,892' Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): A 3/8' capillary string was installed to a setting depth of 7,892' MD to create a path for foamed insertion to aid in wellbore fluid removal. Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,165 23 - 334 Subsequent to operation: 0 1,205 - - 331 14. Attachments: `4~,5. Well Class afterwork: Copies of Logs and Surveys Run Exploratory ^ Development ^~ Service ~ Daily Report of Well Operations X . Well Status after work: Oil ^ Gas ~ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 309-359 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba ' Title Regulatory Compliance Technician ~ Signature ;`4-.~ ~ Phone (907) 283-1371 Date November 11, 2009 ~ A ~.~..p~~ c~ ( ~~~~ Form 10-404 Revised 04/2006 Submit Original Only '` Marathon ~ Operations Summary Report ,,,~~ ~~~ ~~ Well Name: BEAVER CREEK 12 Daily Operations Re ort Date: 11/62009 Job Cate o: R&M MAINTENANCE 24 Hr Summary Remov~ wellhouse, rig up BJ DynaCoil, install cap string set at 7892' MD, re-set wellhouse Ops Troubla Start Time End Time Dur hrs 0 s Code Activi Code Status Code Comment 07:30 08:30 1.00 SAFETY MTG AF Arrive location, sign in and get work permit. Hold PJSM - topics discussed - reviewed JSA's. assigned jobs, simultaneous operations, active gas production pad, blue lights for gas emission, red lights for fre, sirens, muster point is pad offce, emergency phone numhers, vehicles, cordone offwork area using caution tape, buddy rule and three second rule. 08:30 09:30 1.00 PULL EQIP AF spot crane, rig up and move offwellhouse. 09:30 11:30 2.00 RURD COIL AF Rig up BJ DynaCoil unit to run 3P8" capillary string to 7894' MD. Set Fluid Control Valve to 3460#. Perform pull test to 5d0#- test successful. Set injector head onto wellhead extension and packoff. 11:30 12:00 0 50 TEST BOPE AF Pressure test wellhead, extension and packoff to 1500#- test successful 12:00 14:D0 2.00 RUNPUL COIL AF Run 3!8" capillary string into wellbore. Tag bottom at 7894' MD, pull up to 7892' MD. Verify setting depth with production engineer. Set capillary string at 7892' MD. 14:00 15:00 1.00 RURD COIL AF Set packoff, rig down CTU injector head, rig down coil unit. 15:00 16:00 1.00 PULD EQIP AF Re-set wellhouse. Re-connect flowline to sand huster 16:00 16:30 0.50 SECURE WELL AF Secure well to turn back over to operations www.peloton.com Report Printed: 11P9/2009 50-133-20530-00-00 ~s: A-028083 D D.03.09540. CAP. C ML.01 ~n~ 171' (~1' AC;I 1 BC-12 Pad 4 2,023' FNL, 482' FEL, Sec. 33, T7N, R10W, S.M. ~ M MArurNON Conductor 20" K-55 133 ppf Top Bottom MD 0' 107' ND 0' 107' Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 2,091' ND 0' 2,091' 16" hole Cmt w/ 600 sks (271 bbl) of 12.0 ppg, Type 1 cmt, 18 sks (8 bbls) to surface 9-5/8" L-80 40 ppf Butt Top Bottom MD 0' 7,160' TVD 0' 6,978' 12-114" hole Lead Cmt w/ 833 sks (341 bbls) of 12.5 ppg, Class G, Tail Cmt wl 327 sks (106 bbls) of 13.5 ppg, Class G, 12 sks (5 bbis) to surface Production Casinq 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,773' ND 0' 8,590' 8-1/2" hole Cmt w/ 786sks (1891 bbls) of 15.8 ppg, Class G =xcape Svstem Details - 12 Excape module system - Red control line fires modul es 5-12 - control line fires modules 2-4 - Gre~r control line fires module 1 - Ceramic flapper valves below each module (excluding module 1) ~erfs (Open Hole Loq): MD TVD Date Module 12 - 7,228'-7,238' 7,046'-7,056' (8/12/04) Module 11 - 7,279'-7,289' 7,096'-7,107' (8/12/04) Module 10 - 7,480'-7,490' 7,297'-7,307' (8/12/04) Module 9 - 7,543'-7,553' 7,360'-7,370' (8/11/04) Module 8 - 7,584'-7,594' 7,401'-7,411' (8/11/04) Module 7 - 7,656'-7,666' 7,473'-7,483' (S/11/04) Module 6 - 7,731'-7,741' 7,548'-7,558' (8/11/04) Module 5 - 7,780'-7,790' 7,597'-7,607' (8/11/04) Module 4 - 7,848'-7,858' 7,665'-7,675' (8/11/04) Module 3 - 7,889'-7,899' 7,707'-7,716' (8/11/04) Module 2 - 8,420'-8,430' 8,237'-8,247' (8/11/04) Module 1 - 8,471'-8,481' 8,288'-8,299' (8/11l04) Well Name & Number: Beaver Creek Unit #12 Lease: Beaver Creek Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 7,228' - 8,481' Perf (TVD): 7,046' - 8,299' Angle @ KOP & Depth: 24.4° @ 2,500' Angle @ Perfs: 7° Date Completed: 8/11/2004 Ground Level: 150' (AMSL) RKB: 21' (AGL) Revised by: Kevin Skiba Revision Date: 11/11/2009 • ~ ~ ~~ ~ R a ~a ~ ~ ~A p', r ~` ( pM ~ Y ~y'" 2 ~ ~ 4 1 ~ ~ P G ` ~- @ ~. " ~~ ~ ~ ~ ~ "d`°"' 4 ~~ttj n ~r y~ P a ~ ~~ # ~':. ~ ~ ~~ ~ i ~~ tl ~r1 ~j 9 ~ & b' ~ ~ ~ ~ ' \ ~ ~~ ~ ~ ~ ~ ,~~ ~ ~ tt ~ ~ ~ ~ ~ . l ! . ~ ~ ~"" ~~~,,~~ ~ ~ ~~`~ ~~ ~ ~~~ ~ ~ ~ ~ SEAN PARNELL, GOVERNOR ~ ~ ~ ~-7~A ~~L .~~~ Vra47 ~ 333 W. 7th AVENUE, SUITE 100 NORA( 9501-3539 ~ PHC CO1~S~RQATIOI~T COMAIIS51OI~T 14 ~ ~ 07)279- 33 ~ FAX (907) 276-7542 Mr. Kevin J. Skiba Regulatory Compli.ance Technician Marathon Alaska Production LLC ~ P.O. Box 1949 ~~ 3 ~ ~S Kena.i, Alaska 99611-1949 Re: Beaver Creek Field, Beluga 8s 1~ronek Pools, Beaver Creek # 12 Sundry Number: 309-359 Dear Mr. Skiba: ~~~~~~~ ~~~~`~~ ~ {~~ ~~~~ Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representa.tive of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. ~ Chair DATED this ? 7 day of October, 2009 Encl. • ~ Marathon INi1RAiHON Alaska Production LLC ~ October 22, 2009 Ma~on Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~~~G~ V G~ ~c~~ ~ ~ zno9 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Application for Sundry Approvals Field: Beaver Creek Field Well: Beaver Creek #12 "° Dear Mr. Aubert: ~las~Ca Oil ~ Gas Cons. Comanission Anchorage Attached is the10-403 Application for Sundry Approvals requesting approval to install a 3/8" capillary string in BC-12 well. We are currently utilizing one of the Excape control lines as a flow path for the foamer. Installation of a capillary string would allow us to insert the foamer into the wellbore at the more strategic location, facilitating a more effective means to remove the wellbore fluids. The target setting depth for this capillary string is 7,890' MD. ~ Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, + ~ ~ ~ .~~ Z~~ ` Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-403 Application for Sundry Approvals cc: AOGCC Cap-String Installation Procedure Houston Well File Current Well Schematic Kenai Well File KJS y~~ STATE OF ALASKA "°1 ,~ ~ ~~ r ~~~~~~~~ ~ti~~ ALAS~L AND GAS CONSERVATION COMMIS~ ~ e.. ~;~ -~ ~ A~~ ~ ~} l~ , ~ a.., ~ 1° APPLlCATION FOR SUNDRY APPROVALS ~~~['~,p! 20 AAC 25.280 > ~' . . ' (~1'ASS1011 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perforate ^ Waiver ^~~ChQ~aQether ~ Alter casing ^ Repair well ~ Plug Perforations ^ Stimulate ^ Time E~ension ~ Install Capillary Change approved program ~ Pull Tubing ~ Perforate New Pool ~ Re-ent+~r Suspended Well ~ String 2. Operator Name: Marathon Alaska Production LLC 4. Current Well Class: '° 5. Permit to Drill Number: ~ Development ~ Exploratory ~ 203-188 ' 3. Address: p0 Box 1949 Stratigraphic ~ Service ~ . API Number: Kenai Alaska, 99611-1949 50-133-20530-00-00- 7. If perforating, closest approach in pool(s) opened by this operation to nearest . Well Name and Number: property line where ownership or landownership changes: ^ ~ Beaver Creek #12 - Spacing Exception Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): A- 028083 171' (21' AGL) Beaver Creek Field / Beluga & Tyonek Pools 12• PRESENT WELL CONDITION SUMMARY To I Depth MD (ft): tal Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8,839' - 8,656' - 8,736' - 8,553', NA NA Casing Length Size MD ~'` ND Burst Collapse Structural Conductor g6' 20" 107' 107' 3,060 psi 7,500 psi Surface 2,068' 73-3/8" 2,089' 2,089' 3,450 psi 9,950 psi Intermediate 7,139' 9-5/8" 7,160' 6,978' 5,750 psi 3,090 psi Production g,752' 3-1/2" 8,773' 8,590' 10,160 psi 10,540 psi Liner Perforation Depth MD (ft); Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 7,228' - 8,481' / 7,046' - 8,299' Excape 3-1/2" L-80 8,773' Capillary Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ~ 14. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ~ Exploratory ^ Development ^~ ' Service ^ 15. Estimated Date for 16. Well Status after proposed work: Novemb r 6 009 Commencing Operationx Oil ^ Gas Q- Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Titie Regulatory Compliance Technician Signature ` hone (907) 283-1371 Date October 22, 2009 ~ COMMISSION USE ONtY N vD l ~~" S b um er: Conditions of approval: Notify Commission so that a representative may witness undry Plug Integrity ~ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: ~ 0 _ Q, 0 4 APPROVED BY / n ~ DC~~ Approved by: COMMISSIONER THE COMMISSION Date: ~ 7 v Form 10-403 Revised 06/200 ~~ ~ ~ Submit in Duplicate ~ . M MARATHON MARATHON ALASKA PRODUCTION LLC ALASKA ASSET TEAM BC 12 Pad 4 Cap-string Installation Procedure WBS: To Be Submitted APPROVALS: ~'£~e .Mvcanda ~9-Uct-U9 Kyle Miranda Author: Kyle Miranda Latest Version Date: 10/19/09 Well Status: 10/19/09: 1.1 MM @ 370 psi FWHP, soapsticks, foamer 2gpd through red CL. Historv: • 10/20/09: Flowing PLT planned • 10/15/09: Foam at 2gpd on red line, soap sticks 1-4/day • 05/31/09: Foamer injection start down CL red • 04/26/09: PT tag 7895 (mod 3), 2.285 GR, fluid-phase level 4780. Had to jar down after stuck in at 7730 in mod 6. • 04/20/09: Tested control lines. Red (top) clear, Yellow (Mid) plugged, Green (bot) semi-plugged • --------------------------------- • 6/24/05: 1.75 dummy string, Tag at 7903 (mod 3). Ran PT Obiective: Install capillary string (3/8" 2205 0.049" WT) for delivering foamer to alleviate liquid loading. Capstring Installation Procedure JKM Page 1 10/19/2009 ~ . Procedure: Capstring Set Depth: 7,890' (7,515' TVD) - mod 3- depth may change based upon upcoming PLT. Coil length: 9,000' - may take from BC 19 (length now ~8300) Max OD of BHA: 2.250" centralizer Min ID of 3.5" tubing: 2.992" Disconnect power to wellhouse (call electrician). MI manlift. MI crane, arrange for crane operator. Move wellhouse. On truck: Coil, Well Head Adapter - Long w/ o-ring (WHA). Paperwork: WBD, Sundry, Work Permit, Well Ops transfer sheet. 1. MIRU BJ Dyna-Coil unit. Place liner around wellhead/truck. Set outriggers & ground. Flag off location. 2. Shut swab valve, pull tree-cap flange, replace blanking plug w/ WHA (o-ring). MU flange. Add snap ring. 3. Set Fluid Control Valve pressure to head pressure (so CICM surface line pressure equals BHP) _ (Setting TVD 7707')(0.433 psi/ft H20)(1.036 foamer SG) = 3460 psi. ~ 4. Install valve on the surface end of tubing. 5. P/LT Dyna-Coil injector with crane. Run 3/8" coil into injector chains. Adjust tubing straightener. 6. Run coil all the way through injector. Cut off non-straight tubing end (typically 5-15 ft). 7. Run the coil through BJ pack-off (hold pack-off with support pin). 8. Attach BHA. "Pull test" BHA to SOO lbs to verify ferrule is secure. Pull support pin. Gage BHA. 9. Lift injector. Thread pack-off into 2-7/8" female WHA (use teflon & lube). Hold WHA w/ tong/wrench. 10. Lower injector head carefully on to the pack-off (line up slot with the pack-off's %" x 4" nipple). 11. Attach hydraulic hoses to hydraulic rams. Attach MeOH hose to inlet valve. Insert snubbing guides. 12. Wrap wellhead and packoff with absorbents to catch drips. ------------------- revisit JSA ---------------------- 13. Pressure hydraulic rams (top seal, %" nipple) on pack-off to 3000 psi. 14. Pressure test well head adapter using MeOH at 1.5x SIWHP. Watch for leaks carefully. Release pressure. 15. Open swab valve. Watch for leaks at pack-off. 16. Adjust hydraulic rams (top seal) pressure to minimum level (100-500 psi). Ensure Rattiguns are open. 17. Set depth counter. RIH 100 fpm (lube/guide coil as needed), tag bottom, pull up to set depth of 7890'. ~ ------------------- revisit JSA ---------------------- 18. Set slips. Set Rattiguns. Release pressure on upper hydraulic seal (to protect operator). Watch for leaks. 19. Lift injector head off and away from well. 20. Pressure hydraulic rams (top seal) on pack-off to 2500 psi. Close needle valve and insert hydraulic plug. 21. Pull tubing excess through injector, or split injector head to remove tubing if over 500' of excess coil. 22. Connect tubing to Swagelok injection manifold (valve, gauge, filter, gauge, valve) to CICM line. 23. Lockout Swab, Upper Master, and Lower Master as per Capstring Lockout Procedure. 24. Pump foamer into capstring until fluid packed (if not already full). 25. Hookup injection line to CICM. Start foamer at 1 gpd. -~'" 26. Replace well house. Be careful of the tubing "bend" as it goes back inside if it extends through the roof. 27. RDMO. Cleanup site. Sign-out. Fill out Well Ops Transfer Sheet. Considerations Instructions and Planninq: ~/B~: ..\..\..Wlaska Wellbore Diaprams\BC 12 WBD 05-29-09.x1s PICtUP2S: \\kqfrs600.kqf.moc.com\kqfshrWlaska Wells Group\Procedures\Dvna-Coil\Capstrinq Installation Pictures.doc Capstring Installation Procedure JKM Page 2 10/19/2009 50-133-20530-00-00 Des: A-028083 DD.03.09540. CAP. CML.01 ~tion: 17T (21' AGL) te: 05/27/2004 ~ed: 06/10/2004 60°39'22.118" -151 °01'45.593" ased: 06/15/2004 @ hrs. TOC (est.) - ???' Tree cxn = 4-3\4" Otis Excaae Svstem Details - BHP monitoring green line volume tank located from 7,149' - 7,185' RKB - Ceramic flapper vaives below each module as follows: ule 12 - 7,239' ule 11 - 7,290' ule 10 - 7,495' ule 9 - 7,559' ule 8 - 7,601' ule 7 - 7,674' ule 6 - 7,743' ule 5 - 7,792' ule 4 - 7,862' ule 3 - 7,903' ule 2 - 8,433' ule 1 - NA Tag @ 7,895' w/ 2.285" GR on 4/27/09 Pad 4 2,023' FNL, 482' FEL, Sec. 33, T7N, R10W, S.M. •rt ~~ ~_ TD 8,839' MD 8,656' TVD BC 12 ~ ~ Surface Casinq: 13-3/8", 68 ppf, K-55, BTC @ 2089' Cmt w/ 600 sks of type 1 at 12 ppg Int. Casinq: 9-5/8", 40 ppf, L-80, BTC @ 7160' Cmt w/ 833 sks of class G Lead siurry at 12.5 ppg, tail with 327 sks G slurry at 13.5 - PP9 Prod. Tubinq: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 8773' Cmt w/ 786 sks of class G at 15.8 ppg M MARATMOM Drive Piqe: 20", 133 ppf, K-55 to 107' ~n control line fires module 1 control line fires modules 2-4 control line fires modules 5-12 mic flapper valves below each module ~ing module 1) le 12 - 7,228-7,238' (7,046-7,056' TVD) le 11 - 7,279-7,289' (7,096-7,107' TVD) le 10 - 7,480-7,490 ' (7,297-7,307' TVD) le 9 - 7,543-7,553' (7,360-7,370' TVD) le 8 - 7,584-7,594' (7,401-7,411' TVD) le 7 - 7,656-7,666' (7,473-7,483' TVD) le 6 - 7,731-7,741' (7,548-7,558' TVD) le 5 - 7,780-7,790' (7,597-7,607' TVD) le 4 - 7,848-7,858' (7,665-7,675' TVD) le 3 - 7,889-7,899' (7,707-7,716' TVD) le 2 - 8,420-8,430' (8,237-8,247' TVD) le 1 - 8,471-8,481' (8,288-8,299' TVD) PBTD 8,736 MD 8,553' TVD Well Name & Number: BC 12 Lease: Beaver Creek Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD:) 7,228' - 8,481' (TVD): 7,046' - 8,299' Angle @ KOP and Depth: 24.4° @ 2,500' Angle/Perfs: Dated Completed: 8/12/2004 Completion Fluid: 6% KCL Revised By: Nancy Henry Last Revision Date: 5/29/2009 • • ~_ -,. ~. „;~,. ~.. MICROFILMED 03/01 /2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs_Inserts\Microfilm_Marker.doc . Marathon Oil Company , Alaska Asset Team United States Production Organization September 21,2006 P.O. Box 3128 C\\/E 0 Houston, TX 77253 0 EC {:... , '-' Telephone 651-459-3040 i" Fax 713-499-8504 SO' "t 5 (uV) . . , Í/Jff\Il\\SSIO\'\ 0" &. Gas LullS. I\\as\(a' \\'\chN alJ~ Alaska Oil & Gas Conservation Commission Artn: Howard Okland 333 W. 7th Avenue, Suite 100 Jlnchorage,AJ( 99501 CERTIFIED MAIL RE: Marathon Oil Company Beaver Creek Unit No. 12 (BCU 12) Well Data CONFIDENTIAL The attached CD contains CONFIDENTIAL digital data for BCU 12. The CD includes: Daily Reports Precision Wire line Data EPOCH Mudlog Data Directional Survey CD Directory: "!::BC 12_Daily _Reports.pdf "LBC12_DD_mudlog.pdf "LBC12_MudLog.pdf "LBC12_MudLog_lVD.pdf ~ BCU 12_AOGCC_DIR_SUR.dat L:J BC 12_ CORR_If\[).Ias liI BC 12_DSC_MAIN_HIß.ES.las L:J BC 12_HI_RES_DEN_NEU.las L:J BCU 12_MAINPASS.las 'l2J BCU 12_mudlog.las L:JGamma_Ray.1as f!fBOND REPLAY _BCU12_complete.dpk f!fBOND REPLAY _BCU12-P1otted.dpk f!fReeves_BCU 12_md.dpk f!fReeves_BCU 12_tv'd.dpk It)~ \ ;~ ~ r.' '}nníè b') 0). P ¡"Y'J0 ~'. ' .~:. ~-:r> P."" \< r: . ""1"'.... '.1. ~ '",-' 'Ow" ~. Please sign and return to me by faxing to 713-499-8504 confirming your receipt of this data. Enclosure Received by: 11-101£J Date: J63 - t<3ír Beaver Creeek Unit BCU-12 (50-133-20530-00) . . Kaynell, Greetings. We are missing all of the open hole logging data for BCU-12 ( 50-133-20530-00) as well as a CBL cement log. Please send Blue lines, reproduce ables, and the logging digital data. Also, please send the directional survey in digital form ( MD, Inclination, Azimuth in ascii text) . TNX Howard P .S. Have the leaves been turning yet? lofl 9/12/200610:41 AM t;l ~ DATA SUBMITTAL COMPLIANCE REPORT 9/11/2006 Permit to Drill 2031880 Well Name/No. BEAVER CK UNIT BC-12 Operator MARATHON OIL CO 5,.... ¿ ~111..., ~ 'f API No. 50-133-2053tf-OO-OO MD 8839 / TVD 8656 ~ Completion Date 8/12/2004 Completion Status 1-GAS Current Status 1-GAS UIC N ------~ REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes ------ DATA INFORMATION Types Electric or Other Logs Run: SP / GR=IEL DENSITY / NEUTRON SONIC SINGLE ARM CALlPER& Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments . Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION Well Cored? Y G) Chips Received? Y'1-N-- Formation Tops ~ &/N Daily History Received? Analysis Received? ~ ------,-----~ . Comments: " Compliance Reviewed By: ~ , . Date: ))- s:)-~tp---- . . . Marathon Oil Company . Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 October 4, 2004 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 Reference: Completion Report 10-407 for permit 203-188 Field: Beaver Creek / Beluga Well: BC-12 RECEI\/ED OCT 12 2001- Dear Mr. Aubert, Enclosed please find the Well Completion Report with associated attachments for Beaver Creek Well No. 12. This well has been completed cased hole with a 3.5" monobore Excape production string to surface. I apologize for the delay in getting this completion notice to you. Should you require further information, I can be reached at 907-529-0524/713-296- 2730, or bye-mail atJRThompson@MarathonOil.com. Sincerely, r¡¿~ James R. Thompson Sr. Completions Engineer Enclosures: Completion Report Directional Survey Operations Summary Wellbore Diagram ORlGi(~AL STATE OF ALASKA ALAS. AND GAS CONSERVATION COMMIS. WELL COMPLETIOW' OR RECOMPLETION R~RT AND LOG OilU Gas~ Plugged U AbandonedU SuspendedU WAGU 1b. Well Class: 20AAC25.105 20AAC25.110 Development 0 ExploratoryD No. of Completions 1 Other Service D Stratigraphic TestD 5. Date Comp., Susp., or 12. Permit to Drill Number: Aband.: 8/12/2004 203-188 6. Date Spudded: 13. APt Number: 5/27/2004 50-133-20530-00-00 7. Date TD Reached: 14. Well Name and Number: 6/10/2004 Beaver Creek No. 12 8. KB Elevation (ft): 15. Field/Pool(s): 171' (21' above GL) Beaver Creek I Beluga 9. Plug Back Depth(MD+TVD): 8736' MD / 8553' TVD 10. Total Depth (MD + TVD): 8839' MD / 8656' TVD 11. Depth Where SSSV Set: NA 19. Water Depth, if Offshore: NA feet MSL SP/GR=IEL-Density/Neutron-Sonic-Single Arm Caliper & CBL 1a. Well Status: GINJD WINJD WDSPLD 2. Operator Name: Marathon Oil Company 3. Address: P.O. Box 196168, Anchorage, AK. 99519-6168 4a. Location of Well (Govemmental Section): Surlace: 2023'FNL, 482'FEL, Sec. 33, T7N,R10W,S.M. Top of Productive Horizon: 1285'FNL, 495'FWL, Sec. 34, T7N,R10W,S.M. 1295' FNL, 524' FWL, Sec. 34, T7N, R10W, S.M. Total Depth: 4b. Location of Well (State Base Plane Coordinates): Surlace: x- 315319.955 y- 2433200.639 TPI: x- 316308.6 y- 2433904.12 Total Depth: x- 316337.22 y- 2433913.13 18. Directional Survey: Yes ~ No U Zone- 4 Zone- 4 Zone- 4 21. Logs Run: 16. Property Designation: A-028083 17. Land Use Permit: NA 20. Thickness of Permafrost: NA 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 133 K-55 0 107 0 107 Driven NA NA 13.375" 68 K-55 0 2089 0 2089 16" 600 sx @ 12 ppg NA 9.625" 40 L-80 0 7160 0 6978 12.25" 833 sx 12.5/327 sx Tail 13.5 NA 3.5" 9.3 L-80 0 8773 0 8590 8.5" 786 sx @ 15.8 ppg 85,000 23. Perlorations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): MD: 7228-7238, 7279-7289, 7480-7490, 7543-7553, 7584-7594, 7656-7666, 7731-7741,7780-7790,7848-7858,7889-7899,8420-8430,8471-8481 TVD: 7046-7056, 7097-7107, 7297-7307, 7360-7370, 7401-7411, 7473- 7483,7548-7558,7597-7607,7665-7675,7706-7716, 8237-8247, 8288- 8298 24. SIZE 3.5" TUBING RECORD DEPTH SET (MD) PACKER SET (MD) 8773' NA 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED See No. 23 17,000 to 31,000 Ibs. 20/40 Ottawa 26. Date First Production: 8/14/2004 PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: 8/15/2004 1/24/1900 Flow Tubing Casing Press: Press. 800 psi 0 psi Production for Test Period Calculated 24-Hour Rate Oil-Bbl: ..... NA Oil-Bbl: ..... NA Gas-MCF: 3,000 Gas-MCF: 3,000 Water-Bbl: 318 Water-Bbl: 318 Flowing Choke Size: \GaS-Oil Ratio: 44I64th NA Oil Gravity - API (corr): Na 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water {attach separate ~eEt~/f: D Submit core chips; if none, state "none". None OCT 1 2 2004 -"ê'Õ:~Æ7'~1:~:f~¡DÌ'~-~'---'~ . 9i~t"r: ¡ 9'/J." '- <s./f "r-R' /¡n, ¡ VL:. it' .:L' ! ,#/.... i ~'---:l.·.1_ . ORIGiNAL Form 10-407 Revised 12/2003 CONTINUED ON REVERSE .Alaska Oil & Gas Con~. Anchorage «JJ)115 ~ .28. NAME GEOLOGIC MARKE~ TVD 29. FORMATION TESTS Include and briefly su.· ze test results. List intervals tested, and attach detailed supporting da . necessary. If no tests were conducted, state !lNone", None ~~-r p~~ 101:k110'f ~fiO, Ot6iLJ è2.2Qo.~ ".% / Uuð MI'ØRiPí¡,.&/G~~C?ns. ê~'~mission AUEnprage J ~~ ~''<.;y ¡J~);'I Ù-ij;{~;; 30. List of Attachments: Directional Survey. Event Operation Summary, Wellbore Diagram 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Printed Name: James R. Thompson S;gnat",e ~ ¡¿~ Title: Sr. Completion Engineer Phone: 907-529-0524/713-296-2730 Date: 10/4/2004 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". ORIGINAL Form 10-407 Revised 12/2003 28. 10-20-04; 1 :10PM;MARATHON OIL GEOLOGIC MARe NAME MD TVD ;7132963396 # 2/ 2 29. .ORMATlON TESTS Include and briefly summari:te test results. List intervals tested, and attach detailed supporting data as neCBssary. If no tests were conducted, state "None". None Top of L.ower Beluga 7154' 6821' SS Top of Tyonek 8791' 8458' 5S 30. List of Aüäëhments; Directional Survey, Event Operation Summary, Well bore Diagram 31. I hereby certify that the· foregoIng Is true and oorrect to the bast 0; my knowledge. -.-......-...-.. .". -.- - .... ---- --... - Contact Printed Name: James R Thompson ~m~~ Titie: Sr. Completion Engineer Phone: S07·e29·0624/71$-296-2730 Date: 10/412004 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska, Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design Is changed. Item 1 a: Classification of SelVlce wells: Ga$ Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for /njectlon, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. ~ch segregated pool is a completion. Item 4b: TPI (Top of ProducÎng Interval). Item S: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. It ern 13: The API number reported to AOGCC must be 14 digits (ax: 50.029.20123.00.(0). Item 20; True vertical thic mes$. Item 22: Attached supplemental records for this well should show the details of aoy multiple stage cementing and the location of the cementing tool. Item 23: If this well is Gompleted for separate production from more than one interval (multiple completion), so state !n item 1. and in item 23 show the produoing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertInent to such interval). Item 26: Method of Operation: Flowing, GaS L.ift, Roel Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut·in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test Information. If none, state "None". Form 10-407 Revised 12/2003 M MARATHON ~ ~ Wellbore Name BC-12 Well Name BC-12 Slot Name Slot #12 Installation Name Pad #4 Field Name Beaver Creek Unit Created By Comments MARATHON Oil.panY,Slot#12 Pad #4, Beaver Creek Unit,Kenai Peninsula, Alaska SURVEY .ING Page 1 Well bore: BC-12 Wellpath: MWD<O-8839'> Date Printed: 4-Aug-2004 I Created 21-Jun-2004 I Last Revised 28-Jul-2004 I Govemment ID I Last Revised 21-Jun-2004 I Grid NorthinQ 2433200.6390 I Grid Eastino 315319.9550 I Latitude N60 39 22.1201 I Lonoitude W151 1 45.5954 North 3258.04N I EastinQ I Northino I Coord System Name 321035.295~ 2429855.724~ AK-4 on NORTH AMERICAN DATUM 1927 I Eastino I Northino 321035.295~ I Coord System Name 2429855.724~ AK-4 on NORTH AMERICAN DATUM 1927 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #2 O.OOft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 54.10 degrees Bottom hole distance is 1242.04 Feet on azimuth 54.10 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ,&¡. BAKIR HUGHES INTEQ East 5765.80W North Alionment True North Alionment True .!f! ) MARATHON Oil cIpany,slot #12 Pad #4, Beaver Creek Unit,Kenai Peninsula, Alaska SURVEY "ING Page 2 Wellbore: BC-12 Wellpath: MWD<O-8839'> Date Printed: 4-Aug-2004 ,ei. BAKER HUGHES INTEQ Wéllþath (Grid) Report MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing ----"~.,_._-------,--"- rdeQL100ft] Section[ft] ~ - 0.00 0.00 0.00 0.00 O.OON O.OOE 0.00 0.00 315319.9E 2433200.6l 169.00 0.10 113.00 169.00 0.06S 0.14E 0.06 0.08 315320.0E 2433200.5f 225.00 0.20 341.30 225.00 0.02N ______.Q, 15E 0.49 0.13 315320.1C 2433200.6~ 285.00 0.60 306.90 285.00 0.30N 0.14W 0.75 0.07 315319.8. 2433200.9l 346.00 0.40 319.40 346.00 0.66N 0.53W 0.37 -0.04 315319.4< 2433201.3( 406.00 Jl30 314.20 406.00 0.93N 0.78W 0.17 -0.09 315319.H 2433201.51 466.00 0.40 266.40 465.99 1.02N 1.10W 0.50 -0.29 315318.8i 2433201.61 527.00 0.70 311.10 526.99 1.25N 1.59W 0.82 -0.56 315318.3f 2433201.9: 587.00 0.60 272.60 586.99 1.51N 2.18W 0.73 -0.88 315317.8C 2433202.11 647.00 0.90 280.70 646.98 1.61N 2.96W 0.53 -1.45 315317.0. 2433202.3( 738.00 1.30 291.30 737.97 2.12N 4.62W 0.49 -2.50 315315.3E 2433202.8~ 803.00 0.70 273.80 802.96 2.41N 5.71W 1.03 -3.21 315314.2E 2433203.1l 866.00 1.20 292.60 865.95 2.69N 6.70W 0.93 -3.85 315313.3C 2433203.4~ 929.00 0.8º-_ 276.60 928.94 3.00N 7.75W 0.77 -4.52 315312.2E 2433203.7E 993.00 0.40 286.40 992.93 3.11N 8.40W 0.64 -4.98 315311.6C 2433203.81 1056.0C 0.50 280.50 1055.92 _~.22N 8.89W 0.17 -5.31 315311.1. 2433204.0( 1119.0(, -----ºJ.Q--- 158.20 1118.9~ 3.22N 9.14W 0.89 -5.51 315310.8i 2433204.0( 1180.0(, 0.50 66.10 1179.9~ 3.28N 8.87W 0.84 -5.26 315311.1< 2433204.0E 1244.0C 0.20 140.8Q 1243.9~ 3.31N 8.55W 0.76 -4.98 315311.4E 2433204.Of 1306.0C 0.20 131.10 1305.92 3.15N 8.40W 0.05 -4.95 315311.6· 2433203.9: 1369.0C 0.20 127.40 1368.92 3.01N 8.23W 0.02 -4.90 315311.n 2433203.n 1432.00 0.30 141.20 1431.92 2.82N 8.04W 0.18 -4.86 315311.9E 2433203.51 1495.0C 0.50 51.80 1494.92 2.86N 7.72W 0.92 -4.57 315312.2E 2433203.6: 1558.0C 0.30 25.80 1557.9~ 3.18N 7.43W 0.42 -4.15 315312.5E 2433203.9: 1621.0C 0.20 349.30 1620.92 3.43N 7.38W 0.29 -3.96 315312.6~ 2433204.1! 1685.0C 0.30 134.30 1684.92 3.43N.____ 7.28W 0.75 -3.89 ~5312.7~ 2433204.11 1748.0(, 0.60 103.90 1747.92 3.23N 6.84W 0.59 -3.65 315313.1i 2433203.91 1810.0C 0.20 29.30 1809.92 3.25N 6.47W 0.94 -3.34 315313.5< 2433203.9E 1871.0C Q.70 81.90 1870.92 3.39N 6.05W 0.98 -2.91 315313.9E 2433204.1 ~ 1936.0C 0.50 _~___ 64.70 1935.92 3.57N 5.40W 0.41 -2.28 315314.6' 2433204.2! 1999.0C 0.20 12.50 199ß.91 3.79N 5.13W 0.65 -1,93 315314.8E 2433204.5' 2047.0C 0.30 56.00 2046.91 3.95N 5.01W 0.43 -1.74 315315.0' 2433204.6E 2178.0C 0.30 65.60 2177.91 4.28N 4.41W 0.04 -1.06 315315.6· 2433204.9! 2242.0C 0.30 105.00 2241.91 4.31N 4.0!1.W 0.32 -0.79 315315.9~ 2433205.0' 2305.00 0.10 99.00 2304.91 4.25N 3.88W 0.32 -0.65 315316.1l 2433204.9~ 2371.00 0.40 110.60 2370.91 4.17N 3.61W 0.46 -0.48 315316.4' 2433204.8E 2434.0C 0.30 84.20 2433.91 4.10N 3.24W 0.30 -0.22 315316.7E 2433204.7! 2494.0C 0.90 37.00 2493.91 4.50N 2.80W 1.22 0.37 315317.2~ 2433205.11 2557.0(, 3.00 43.80 2556.87 6.08N 1.36W 3.35 2.46 315318.6E 2433206.7l 2620.0C 4.80 49.30 2619.72 8.99N 1.78E 2.91 6.71 315321.8i 2433209.6( 2694.00 6.20 53.30 2693.3E 13.40N 7.33E 1.96 13.79 315327.4E 2433213.9: 2747.0C 6.70 54.30 2746.04 16.91 N 12.14E 0.97 19.75 315332.3~ 2433217.3E 2810.0C 7.20 55.70 2808.5a 21.28N 18.38E 0.84 27.37 315338.6i 2433221.6: ~I3.0(, 8.60 55.80 2870.9E 26.16N 25.54E 2.22 36.03 315345.9C 2433226.3! 2936.0JL 9.80 55.20 2933.17 31.86N 33.84E 1.91 46.09 315354.2E 2433231.91 3000.0C 10.60 55.00 2996.15 38.35N 43.13E 1.25 57.43 315363.6E 2433238.3( 3062.0(, 11.10 55.40 3057.05 45.01 N 52.72E 0.82 69.09 315373.3i 2433244.8' 3125.0(, 12.30 55.20 3118.74 52.28N 63.22E 1.91 81.87 315383.9E 2433251~ 3189.00 13.20 54.60 3181.16 60.~1N J4.77E 1.42 95.99 315395.6E 2433259.8E 3251.0C 14.50 54.20 3241.35 69.05N 86.84E 2.10 110.83 315407.8E 2433268.3· 3314.0C 15.30 53.00 3302.2~ 78.66N 99.88E --.- 1.36 127.Q3 315421.0< 2433277.7: All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #2 O.OOft above mean sea level) Vertical Section is from O.GON O.OOE on azimuth 54.10 degrees Bottom hole distance is 1242.04 Feet on azimuth 54.10 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated M MARATHON 4 MARATHON Oil !panY,Slot#12 Pad #4, Beaver Creek Unit,Kenai Peninsula, Alaska SURVEY ~ING Page 3 Well bore: BC-12 Wellpath: MWD<O-8839'> Date Printed: 4-Aug-2004 rei. BAKER HUGHIS INTEQ WellpathCGrid) Report MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing rdeQ/10OO1 Sectionfft1 3376.0C 15.90 53.20 3361.95 88.67N 113.21E 0.97 143.70 315434.5~ 2433287.5, 3439.00 18.40 53.90 3422.14 99.70N 128.16E 3.98 162.27 315449.6~ 2433298.3, 3502.00 19.10 54.30 3481.8C 111.58N 144.56E __J.13 182.52 315466.2~ 2433309.9: 3566.00 18.90 53.90 3542.31 123.79N 161.44E 0.37 203.36 315483.3C 2433321.81 3629.01; 19.00 54.00 3601.9C 135.83N 177.98E 0.17 223.82 315500.0~ 2433333.61 3691.01; 19.20 54.00 3660.42 147.76N 194.39E 0.32 244.11 315516.6. 2433345.3, 3755.01; 19.70 53.90 3720.83 160.30N 211.62E 0.78 265.42 315534.0~ 2433357.5! 3818.01; 19.70 54.00 3780.15 172.80N 228.79E 0.05 286.65 315551.4' 2433369.8, 3881.0C 19.70 53.80 3839.46 185.31N 245.95E 0.11 307.89 315568.71 2433382.01 3944.0C 19.40 54.20 3898.82 197.70N 263.01 E 0.52 328.97 315586.0· 2433394.11 4007.00 19.20 54.40 3958.22 209.85N 279.92E 0.33 349.79 315603.1C 2433406.0/ 4070.0C 18.90 54.20 4017.84 221.85N 296.61E 0.49 370.36 315619.9~ 2433417 .8( 4133.0C 19.40 54.1!L_ 4077.35 233.96N 313.37E 0.80 391.02 315636.9~ 2433429.6< 4196.0C 19.80 53.80 4136.70 246.39N 330.45E 0.65 _412.16 315654.2C 2433441.8 ' 4259.01; 19.60 53.90 4196.01 258.92N 347.60E 0.32 433.39 315671.5< 2433454.01 4321.01; 19.10 53.90 4254.51 271.02N .__3Q~,20E;__ 0.81 453.94 315688.32 2433465.9' 4384.01; 18.80 54.10 4314.09 283ß5N 380.75E 0.49 474.40 315705.0i 2433477.6/ 4447.00 19.40 53.00 4373.63 295.30N 397.33E 1.11 495.01 315721.8~ 2433489.61 4510.00 19.80 51.70 H32.9f.___.~~2J N 414.06E 0.94 516.13 315738.7€ 2433502.3· 4573.0C 19.70 51.70 4492.27 321.40N 430.77E 0.16 537.40 315755.6i 2433515.2< 4636.0C 19.80 .__~1.50 .. 4551.56 334.63N 447.45E 0.19 558.67 315772.5€ 2433528.2( 4700.0C 19.60 51.60 4611.82 348.04N 464.35E 0.32 580.22 315789.6€ 2433541.31 4762.0C 19.20 51.70 4670.3C 360.82N 480.50E 0.65 600.80 315806.0· 2433553.8/ 4826.00 18.70 51.90 4730.82 373.67N 496.83E 0.79 621.56 315822.5< 2433566.41 4889.00 18.70 52.30 4790.5C 386.08N 512.77E 0.20 641.75 315838.6i 2433578.6, 4952.0C 19.50 ~3.80 4850.02 398.47N 529.24E 1.49 662.36 315855.3< 2433590.7< 5015.0C 19.40 54.50 4909.44 410.75N 546.25E 0.40 683.34 315872.5~ 2433602.71 5078.0C 19.40 54.20 4968.86 422.95N 563.25E 0.16 704.26 315889.7. 2433614.6! 5141.0C ~__.N,90 54.10 5028.36 435.08N 580.04E___.___ 0.64 724.98 315906.7C 2433626.51 5205.0C 18.90 54.30 5088.89 447.24N 596.90E 0.19 745.77 315923.n 2433638.41 5268.0C 18.40 54.60 5148.58 458.95N 613.29E 0.81 765.91 315940.3. 2433649.9· 5330.0C 19.10 54.70 5207.2g 470.49N 629.55E 1.13 785.84 315956.7~ 2433661.1j 5393.0C 19.40 55.00 5266.77 482.44N 646.53E 0.50 806.61 315973.9. 2433672J!j 5457.0C 19.40 55.10 5327.12 494.62N 663.95E 0.05 827.86 315991.5~ 2433684.7/ 5521.0C 19.20 55.30 5387.54 506.69N 681.32E 0.33 849.01 316009.m 2433696.5/ 5584.0C 19.00 55.80 5447.07 518.36N ._._.ß98.32E 0.41 869.62 316026.2i 2433707.91 5645.0C 18.80 55.50 5504.7€ 529.50N 714.64E 0.36 889.37 316042.n 2433718.81 5708.0C 19.00 55.30 5564.3€ 541.09N 731.43E 0.33 909.77 316059.n 2433730.11 5771.0C 18.70 55.60 5624.01 552.64N 748.20E 0.50 930.12 316076.6i 2433741.41 5834.0C 18.50 55.60 5683.71 563.99N 764.78E 0.32 950.21 316093.4. 2433752.51 5896.0C 18.60 55.40 5742.42 575.16N 781.03E 0.19 969.93 316109.8~ 2433763.41 5960.0C 17.90 55.40 5803.27 586.54N 797.53E 1.09 989.97 316126.5. 2433774.51 6022.0C 17.50 55.60 5862.34 597.22N 813.07E 0.65 1008.81 316142.2. 2433785.0· 6085.0C 17.30 55.10 5922.46 607.93N 828.56E 0.40 1027.6< 316157.8€ 2433795.41 6148.0C 16.80 54.00 5982.62 618.64N 843.61E 0.94 1046.12 316173.1C 2433805.91 6211.0C 15.90 52.90 6043.14 629.20N 857.86E 1.51 1063.85 316187.5· 2433816.2! 6275.0C 15.30 52.70 6104.7€ 639.60N 871.57E 0.94 1081.05 316201.3€ 2433826.4] 6338.0C 14.70 52.80 6165.6~ 649.47N 884.55E 0.95 1097.36 316214.5· 2433836.1 < 6401.0C 14.1Q 52.60 6226.65 658.97N 897.01E 0.96 1113.02 316227.1. 2433845.4< 6463.0C 12.60 52.40 6286.9€ 667.68N 908.37E 2.42 1127.33 316238.6' 2433853.9/ 6526.01; 11.90 52.10 6348.54 675.86N 918.94E 1.12 1140.62 316249.3· 2433861.9! All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #2 O.OOft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 54.10 degrees Bottom hole distance is 1242.04 Feet on azimuth 54.10 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ,N!~ . MARATHON Oil Company,Slot #12 Pad #4, Beaver Creek Unit,Kenai Peninsula, Alaska SURVEY liNG Page 4 Wellbore: Bc-12 Wellpath: MWD<O-8839'> Date Printed: 4-Aug-2004 rei. IAKER HUGHI5 INTEQ Wêlløâth(Grid) · ReÞOR MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing fdeQ/10OO1 Sectionfftl 6589.0C 11.40 52.80 6410.24 683.62N 929.02E 0.82 1153.4C 316259.5· 2433869.5f 6652.0Ç 10.20 54.00 6472.12, 690.66N 938.50E 1.94 1165.21 316269.0~ 2433876.4f 6715.0C 8.30 54.30 6534.31 696.59N 946.70E 3.02 1175.33 316277.3~ 2433882.2f 6779.0C 7.20 52.30 6597.72 701.74N 953.63E 1.77 1183.96 316284.4C 2433887.3. 6842.0C 6.00 49.20 6660.3C 706.31N 959.25E 1.99 1191.1£ 316290.0f 2433891.7¡ 6906.0C 5.10 55.70 6724.0C 710.10N 964.13E 1.71 1197.37 316295.0. 2433895.5· 6968.0C 4.30 52.80 6785.7£ 713.05N 968.26E 1.35 1202.44 316299.2C 2433898.4( 7031.0C 3.20 52.40 6848.66 715.56N 971.53E 1.75 1206.56 316302.5· 2433900.8! 7120.0C 1.90 61.50 6937.57 717.77N 974.79E 1.53 1210.51 316305.8· 2433903.0. 7219.0C 1.60 74.60 7036.52 718.92N 977.57E 0.50 1213.43, 316308.6C 2433904.1. 7282.0C 1.60 77.80 7099.5C 719.35N 979.28E 0.14 1215.06 316310.3' 2433904.5. 7344.0C 1.30 57.00 7161.4f, 719.91N 980.71 E 0.97 1216.56 316311.7E 2433905.0E 7406.00 1.50 57.80 7223.46 720.73N 981.99E 0.32 1218.07 316313.0! 2433905.8! 7468.0C 1.30 55.60 7285.44 721.56N 983.26E 0.33 1219.5S 316314.3~ 2433906.6E 7531.0C 1.40 56.00 7348.42 722.39N 984.49E 0.16 1221.06 316315.57 2433907.4f 7592.0C 1.30 82.00 7409.41____ 722.90N 985.79E 1.01 1222.42 316316.8f 2433907.9; 7655.0C 0.90 64.80 7472.3~ 723.21 N ___.9Jl.6.94E 0.82 1223.5l 316318.0< 2433908.2E 7718.00 1.10 94.00 7535.3£ 723.38N 987.99E 0.86 1224.4£ 316319.0~ 2433908.4. 7781.00 1.20 68.30 7598.37 723.58N 989.21 E 0.83 1225.5£ 316320.3· 2433908.6( 7844.00 1.10 97.80 7661.36 723.75N 990.42E 0.94 1226.67 316321.5~ 2433908.7< 7905.0C 1.10 94.00 7722.35 723.63N 991.59E 0.12 1227.5l 316322.6~ 2433908.6( 7968.0C 0.90 64.40 7785.34 723.80N 992.64E 0.87 1228.4£ 316323.7< 2433908.7E 8031.00 0.60 69.70 7848.34 724.13N 993.39E 0.49 1229.3C 316324.5C 2433909.0; 8093.00 0.70 63.40 7910.32, 724.41 N 994.03E 0.20 1229.9B, 316325.1~ 2433909.3! 8156.00 0.90 97.10 7973.32 724.52N 994.87E 0.80 1230.72 316325.9~ 2433909.4< 8219.0C 1.00 96.80 8036.32 724.39N 995.91E 0.16 1231.4£ 316327.0. 2433909.3( 8280.0C 1.10 90.10 8097.31 724.33N 997.02E 0.26 1232.3e 316328.1~ 2433909.2. 8342.0C 0.80 59.90 8159.3C 724.54N 997.99E 0.92 1233.27 316329.1' 2433909.4. 8405.0C 1.20 60.20 8222.2S 725.09N 998.94E 0.63 1234.36 316330.07 2433909.9! 8468.0C 1.10 59.50 8285.27 725.73!'!.___.10.Q1J.04E 0.16 1235.62 316331.17 2433910.~i 8531.0Ç 0.80 81.70 8348.27 726.10N 1000.99E 0.75 1236.61 316332.1~ 243391 0.9~ 8594.0C. 0.80 91.50 8411.26 726.15N 1001.87E 0.22 1237.35 316333.0· 2433910.9; 8657.0C 1.10 58.50 8474.25 726.45N 1002.82E 0.97 1238.3C 316333.97 2433911.2! 8720.00 1.20 60.20 8537.24 727.10N 1003.91 E 0.17 1239.56 316335.07 2433911.8f 8783.00 1.20 58.50 8600.22, 727.77N 1005.05E 0.06 1240.87 316336.2' 2433912.5< __--ªª.3.9JlQ. 1.20 58.50 8656.21 728~38N__ 1006.05E 0.00 12.42.0l 316337.2. 2433913.1: All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #2 O.OOft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 54.10 degrees Bottom hole distance is 1242.04 Feet on azimuth 54.10 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . Marathon Oil Company Final Weill Event Summary Legal Well Name: BEAVER CREEK 12 Common Well Name: BEAVER CREEK 12 Event Name: ORIGINAL DRILLING 5/25/2004 37 (ft) 5/26/2004 37 (ft) 5/27/2004 75 (ft) 5/28/2004 1,548 (ft) 5/29/2004 2,100 (ft) 5/30/2004 2,100 (ft) 5/31/2004 2,100 (ft) 6/1/2004 3,135 (ft) 6/212004 4,570 (ft) 6/3/2004 6,145 (ft) 6/4/2004 6,408 (ft) 6/5/2004 6,995 (ft) 6/6/2004 7,183 (ft) 6fi /2004 7,183 (ft) 6/8/2004 7,183 (ft) 6/9/2004 7,955 (ft) 6/1 0/2004 8,643 (ft) Start Date: 5/24/2004 End Date: 6/11/2004 Load out, MI/ RU on Be 12 Cont rig up, take on water for spud. Rig Up , Spud Meeting, Rig Diverter & Function Test Annular & Knife, Pick up 5" & Rack in Derrick, Repair Gas Alarms, MU BHA, Tag @ 37' RKB, UD MWD, Run Bit, Mtr, 2-Jts. HWDP, C/O Conductor To 75' RKB. Spud @ 0430 Hrs. 5-27-2004 Cln-out 20",Drlg,CBU,Trip for BHA,Drlg,CBU,Wiper Trip, Drlg, Drlg.,CBU,Wiper Trip,CBU,POOH,Run Csg. Cmt. 13-3/8", WOC,ND Diverter,lnstall Well Head/Set BOP's NU BOPS,TEST BOP's, Csg.Test,MU Bha,PU 5" DP Trip/Drlg Float Equip & shoe TractlDrlg/Displace Wellbore/LOT/Drlg. Drlg, Wiper Trip & Slip Drlg. Line,Service Rig, Drlg.,CBU,Wiper Trip Wiper Trip, Drill F/4570' To 6145' Drill F/6145' to 6347'. Circ. Drill F/6347' to 6408'. Circ. clean. POOH.Bit Evaluation,MU Bha,TIH To Shoe Service Rig, Cut & Slip Drilling line. Slip & cut drilling line,test mwd, rih W&R 6366' to 6408', Dir drill 6408' to 6995' Drill F/6995' to 7183'. Circ. clean. Wiper trip.,CBU, Pooh, POOH. UD BHA. Installed 9-5/8" CSG rams. Tested BOPE,R/U to run CSG. Ran 9-5/8" CSG. Run and cement 95/8" CSG. set 95/8" packoff and test to 3000psi.,Chg Rams, Test BOP's,MU BHA,RiH to 845', RIH. Rig repair, Cont. RIH. Test CSG. Drill shoe tract and shoe. Cleanout old hole. Drill Ffi183' to 7203'. Circ. clean. Perform LOT. Drill F/7203' to 7955' Drill F/7995' to 8143'. Cire. clean. Wiper trip to shoe. Circ. clean. Service rig. TIH. Drill F/8143' to 8643'. ._~~'~-~'-"-"---'-'-----'~- Printed: 1 0/412004 2:03: 17 PM legal Well Name: Common Well Name: Event Name: DATE 6/11/2004 6/12/2004 . . Marathon Oil Company Final Weill Event Summary BEAVER CREEK 12 BEAVER CREEK 12 ORIGINAL DRilLING TMD 8,839 (ft) 8,839 (ft) Start Date: 5/24/2004 24 HOUR SUMMARY End Date: 6/11/2004 Drill F/8643' to 8839'. Circ clean, Wiper trip to shoe,Chg washpipe and packing,Rih, Circ clean,POOH, UD BHA. Run Logs. Printed: 10/4/2004 2:03: 17 PM Legal Well Name: Common Well Name: Event Name: DATE 6/12/2004 6/13/2004 6/14/2004 6/15/2004 . SEAVER CREEK 12 SEAVER CREEK 12 ORIGINAL COMPLETION TMiD 8,839 (ft) 8,839 (ft) 8,839 (ft) 8,839 (ft) . End Date: 6/15/2004 Start Date: 6/11/2004 RIH. Circ. and cond mud. Wiper trip. Rig service. LID DP. LID DP and BHA. Run 3.5" Excape completion. Run and cement 3.5" Excape completion. woe. Monitor well and empty and clean pits. Rasie stack and cut and run control lines through outlet on wellhead. Rig released to maintenance OO:OOhrs 06/15/04. Set slips on 3 1/2" CSG. Set Packoff and test. N/U tree and test. Clean pits. RID rig. ~---.,_._~--' -----~--"- Printed: 10/4/2004 2:03:35 PM . Legal Well Name: BEAVER CREEK 12 Common Well Name: BEAVER CREEK 12 Event Name: MAINTENANCE/REPAIR 8/3/2004 (ft) 8/4/2004 (ft) ----~-_."._--- . Start Date: 8/3/2004 Pollard WL RU to make GR pass RU RIH with 2.7" swedge to clear tight spot End Date: Printed: 10/412004 2:04:10 PM Legal Well Name: Common Well Name: Event Name: 8/12/2004 8/13/2004 8/14/2004 8/15/2004 8/16/2004 . . BEAVER CREEK 12 BEAVER CREEK 12 ORIGINAL COMPLETION 'J"MD (ft) (ft) (ft) (ft) (ft) Start Date: 6/16/2004 24 HOUR SUMMARY End Date: Fracture stimulated 8 of 12 Excape modules. Screened out module 9 treatment. RIH w/ coil tubing. Cleaned out well to 7590. POOH with coil and secured well. Fracture stimulated excape modules 9, 10, 11, and 12. Cleaned out well with coil tubing. Broke 8 of 11 flappers. Lifted well in with N2. POOH with CT and began monitoring well flowing conditions. Well slugging 350 to 800 BFPD with a WHP of 200 psig. Unloaded and cleaned up well. Put well to test separator and then to sales. Well currently on a 40/64th choke producing 3.2 mmcfd, 3-500 BWPD with an 815 psig FTP. Continued to flow well to LP system. Well making 3 mmcfd and 318 bwpd riding system pressure, with a 800 psig FTP. Flowed well to LP system. Put well to vent to lower WHP. Continued to flow well at 2.9 mmcfd and 348 bwpd on a 32/64th choke with a 710 psig FTP. Printed: 10/412004 2:03:51 PM API: 50-133-20530-00-00 RT-GL: 21' RT-THF: 21 ' 2023' FNL, 482' FEL, Sec. 33, T7N, R10W, S.M. Tree cxn '" 4-3/4" Otis ITOC (est.) - ???' Excape System Details - BHP monitoring green line volume tank located from 7149' - 7185' RKB Excape System Details - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 1 - NA Module 2 - 8433' Module 3 - 7903' Module 4 - 7862' Module 5 - 7792' Module 6 - 7743' Module 7 - 7674' Module 8 - 7601' Module 9 - 7559' Module 10 - 7495' Module 11 - 7290' Module 12 - 7239' Well Name &: Number: County or Parish: Perforations (MD) I BHP: Dated Completed: Prepared By: BC..12 TO - 8839' PSTD - 8736' Kenai BHT: I 8/12/2004 J. R. Thompson Lease: Completion Fluid; Last 20", Surface Casino: 13-318" , 68 @ 2089' Cmt w/ 600 sks of type 1 at 12 ppg Int. Casing: 9-518", 40 ppf, L-aO, Cmt wI 833 sksof classG Lead ppg, tail with 327 sks G slurry at Prod. Tubino: 3-1/2", 9.3 ppf, L-8Q,EUE8rd with 6.25" OD control line protectors to 8773' Cmt w/ 786 sks of class G at 15.8 PPQ Excape System Details - 12 Excape modules placed - Green control line fires module 1 - Yellow control line fires modules 2-4 - Red control line fires modules 5-12 - Ceramic flapper valves below eç¡chmodule (excluding module 1) Perfs MD (OH Lao): Module 1 - 8471c8481' Module 2 - 8420-8430' Module 3 - 7889-7899' Module 4 - 7848"7858' Module 5 - 7780-7790' Module 6 -7731-7741' Module 7 - 7656-7666' Module 8 - 7584-7594' Module 9 - 7543'1553' Module 10 -7480-7490' Module 11 - 7279-7289' Module 12 - 7228-7238' Beaver Creek Gas Field Alaska ¡Country: (TVD) tJtt-;·t~ ¡ Gentlemen, As per our phone conversations yesterday, Marathon is requesting a change in the intermediate casing setting depth for the Beaver Creek #12 well. This change is requested due to the fact that the directional plan was modified for a new target (noted in an e-mail from David Castillo 2/9/2004). Further analysis indicated that sòme of the Lower Beluga zones that would be possible pay would be covered under two casing strings. The 9 5/8" casing would be pulled back up to a depth of 7,158' MD. This reflects a change of approximately 333 feet MD and TVD. I have attached a revised Marathon drilling program, reflecting those changes. If you have any questions please feel free to contact me. As indicated in our conversations, we anticipate a spud either Wednesday (May 26) or Thursday (May 27). Thank you, Willard J. Tank Advanced Senior Drilling Engineer Marathon Oil Company Anchorage, AK 99519 907-564-6310 «BC #12 Drilling Prog Final Revision.lIP» Be #12 Drilling Prog Final Revision.ZIP Content-Description: BC ~1.2 Drilling Prog Final Revlslon.ZIP Content-Type: application/x-zip-compressed Content-Encoding: base64 e e ARATHON MARATHON Oil COMPANY DRilliNG PROGRAM BEAVER CREEK 12 REVISION 3 May 23, 2004 Originator: David R. Castillo (revised by W. J. Tank) Drilling Supervisors: Gene Anderson, Roland Lawson Drilling Superintendent: Peter Berga e e Table of Contents General Well Data................................................................................................................................ ................................... 1 Geologic Program Summary........................................................................................................................... ........................ 1 Summary of Potential Drilling Hazards. ... ... ..... ................ ...... ... ..... ... ..... .... ........ .......... ...... ......... .... ........ .......... ....... .......... ..... 2 Formation Evaluation Summary........................................................................... ...................... .............................................2 Drilling Program Summary ........... ..... .............. ....... ......... ......... ..... ......... ................... ... ......... .... ...... ........ ............ ...... ... ..... ......3 Casing Program........................................................................................................................... ........... .................................4 Casing Design......................................................................................................................... ................................................4 Maximum Anticipated Surface Pressure.......................................................................................................................... .......4 BOPE Program .. ..... ..... .... ........... ...... ........ ....... ...... ........... .......... ......... ............... ... ......... .............. ........ ........ ... ............ ....... ....6 Wellhead Equipment Summary............................................................................................................................ ...................7 Directional Program Summary......................................................................................................................... ....................... 7 Directional Surveying Summary .................. ......... ....... ...... .......... ...... ..... ... ...... ...... ...... .... ... ...... .......... ...... ... ........... ..... ........ .... 7 Bit Summary........................................................................................................................... ................................................. 8 Drilling Fluid Program Summary ..... ................ .......... ......... ..... ............ ...... .... .... .............. ......... ......... .......... ........... ...... ........ ...8 Drilling Fluid Specifications. ..... ...... ............. ... ...... .................. ............. ........ ...... ... ....... ................ ......... ........ ... ... ........... ..........8 Solids Control Equipment.... ......... ...... ...... ......... ......... ...... ........... .......... ........ .... ...... ......... ....... ... .......... ....... ........... ........ .........9 Cement Program Summary. ..... ................ ........ ......... ....... ............... ...... ..... .... ... ............... ... ..... ....... ... ........ ............ ...... ..... ..... 9 Regulatory Waivers and Special Procedures ................,......................................................................................................10 Hydraulics Summary............................................................................................................................ .................... .............. 10 Formation Integrity Test Procedure ..... ... ... ......... .............. .... ......... ......... ........ ....... ... ...... ........... ............ ........ ....... ...... .......... 11 e e General Well Data 8843 8656 NA DD.03.09540. CAP. DRL May 22, 2004 NA Beaver Creek 12 Y: 2433200.44 X: 315320.07 Pad 4 21 ft 150.1 ft RKB NA NA NA Beaver Creek Kenai Borough Alaska Development Inlet Drilling Glacier 1 Comments: Geologic Program Summary Sterling B3 5305.95 5181 1176 4.4 Sandstone Gas I Water Sterling B4 5475.81 5341 2161 8.0 tJ.l¢ Sandstone Gas I Water Upper Beluga B2 6293.37 6116 2485 to 3479 ~8.~ Sandstone Gas Lower Beluga B16 7356.42 7169 2522 to 3531 6.7 to 9.3 Sandstone Gas Lower Beluga B17 7464.42 7277 2553 to 3574 6.7 to 9.4 Sandstone Gas Lower Beluga B18 7550.42 7363 2204 to 3599 6.7 to 9.4 Sandstone Gas Lower Beluga B19 7602.42 7415 2225 to 3634 5.7 to 9.4 Sandstone Gas Lower Beluga B20 7673.42 7486 2257 to 3686 5.7 to 9.4 Sandstone Gas Lower Beluga B21 7779.42 . 7592 2288 to 3737 5.7 to 9.4 Sandstone Gas Lower Beluga B23 7883.42 7696 2635 to 3797 5.7 to 9.4 Sandstone Gas Lower Beluga B24 8006.42 7819 2782 to 3895 6.5 to 9.4 Sandstone Gas Lower Beluga B26 8206.42 8019 2810 to 3934 6.7 to 9.4 Sandstone Gas Lower Beluga B27 8286.42 8099 2872 to 4021 6.7 to 9.4 Sandstone Gas Lower Beluga B29 8464.42 8277 2917 to 4083 6.7 to 9.4 Sandstone Gas Lower Beluga B30 8590.42 8403 2485 to 3479 6.7 to 9.4 Sandstone Gas Comments: Township 7-N, Range 10-W 60039' 22.120' N 151001' 45.595" W 2433200.44 315320.07 NAD27 ASP ZONE 4 page 1 e e Top/L.Beluga LB-19 7603 7415 1297 ft FNL, 492 ft FWL, Section 34, T7N, R10W 726.27N 974.20E Circular - 100 Top/L.Beluga LB-23 7884 7696 1297 ft FNL, 492 ft FWL, Section 34, TIN, R10W 726.27N 974.20E Circular - 100 Top/L.Beluga LB-30 8591 8403 1297 ft FNL, 492 ft FWL, Section 34, TIN, R10W 726.27N 974.20E Circular - 100 Total Depth 8843 8656 1297 ft FNL, 492 ft FWL, Section 34, TIN, R10W 726.27N 974.20E Circular - 100 Comments: Summary of Potential Drilling Hazards Lost Circulation The Sterling B-3 sands are approximately 1147 psig and 400 md perm. The Lower Beluga intervals have SBHP's that range from a 0.31-.46 psilft. Control losses by using sufficiently sized LCM. See comment above about the Sterling B-3 and the Lower Beluga intervals. Keep the drill pipe moving and avoid if possible excess overbalance. Maintain low fluid loss and thin impermeable filter cake. Circulate hole clean before tripping. Do not POOH or RIH faster than 30 seclstand Differential Sticking SurgelSwabbing Comments: Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands will be encountered from +1- 5,306 ft MD RKB (5,181 ft TVD RKB) to total depth of the well. These sands will run from normal pressured to severely depleted and lost circulation and differential sticking are potential hazards. The FloPro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. No well interference hazards exist. Formation Evaluation Summary Surface Oft - 2,100 ft MD Intermediate 2,100 ft - 7,158 ft MD Production 7,158ft -8,843 ft MD None None None None None Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Basic with GCA, shale density, temperature in and out, sample collection (10' samples). None Triple combo (PEX), Digital Sonic (DSI), CMR Plus*, MDP Completion N/A GR, eeL N/A * Log run if borehole conditions allow Coring Requirements: None Comments: page 2 e e Drilling Program Summary CONDUCTOR: 1. Drive 20" conductor to +1-100 ft. RKB. 2. Move in and rig up Glacier #1 rotary drilling rig. 3. Install starting head 20" SOW x 21 1/4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. 5. Function test diverter and diverter valve. SURFACE: 1. Drill a 16" hole to 2,100 ft MD (2,100' TVD) with Spud Mud. 2. RIH with 13 3/8" casing and hang off in the slips. Make up stab-in sub and centralizer on 4" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 318" casing. Sting out and circulate drill pipe clean. TOOH with inner string. 3. PU 133/8" casing, set casing slips in 20", cut off 13 3/8", ND diverter. 4. Install 13 3/8" slip lock connection X 13 %" 5M flanged multibowl wellhead. 5. NU 13 %" 5M BOP'S. Test BOP'S and choke manifold to 250/3,500 psi. 6. Set wear bushing. 7. Test surface casing to 2,000 psi. INTERMEDIATE: 1. PU PDC bit and BHA. TIH to insert float. Drill out float equipment and make 20' of new hole. 2. Displace spud mud with FloPro. Circulate mud until mud weight in equals mud weight out. 3. Test shoe to leak-off. Estimated EMW is 14.6 ppg. 4. Drill 12 1/4" directional hole to approximately 6,600 ft MD (6,415 ft TVD) as per directional plan. This represents the approximate top ofthe conglomerate. 5. Trip out of hole and dull grade PDC bit. TIH with PDC bit and continue drilling to target depth of 7,158 ft MD (6,971 ft TVD) as per directional plan. (If the PDC bit cannot finish the conglomerate section, an insert bit will replace it) 6. Make wiper trip. 7. Change out variable pipe rams with 9 %" casing rams. Run test plug and test BOP casing rams to 250/3,500 psi. 8. Run and cement 9 %" casing. Land hanger in multibowl wellhead. 9. Back out landing joint. Change out 9 %" BOP casing rams with variable pipe rams. Run test plug and test BOP pipe rams to 250/3,500 psi. 10. Set wear bushing. Test casing to 2,000 psi. PRODUCTION: 1. Drill float equipment and 20' of new formation w/8 W' bit. Circulate mud until mud weight in equals mud weight out.. 2. Test shoe to leak-off. Estimated EMW 15.8 ppg. 3. Drill an 8 %" hole to 8843 ft MD RKB (8656 ft TVD) per the directional program. 4. TOOH. RU logging company. Run open hole logs as per plan. RD logging company. 5. TIH to TD for wiper trip. TOOH and lay-down BHA and drill pipe. Pull the wear bushing. 6. Run 3 %" EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD logging company. 7. Cement 3 %" casing while reciprocating. Bump plug with 500 psi over displacement pressure. WOC. 8. PU 3 %" casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 3 %" casing. 9. LD BOP. Set 3 %" packoff. NU 13 %" 5M X 3 Ys" 5M tubing head adapter and 3 Ys" 5M tree. Test tree to 5,000 psi. 10. Rig down and move out drilling rig. Note: Perforating guns will be run on the outside of the 3 %" production casing with a flapper valve just below each perforating gun. Guns to be activated by control line to surface. COMPLETION: Completion will be done without a rig. page 3 e e Casina Proaram 20 Surface 100 130.1 K-55 18.873 18.543 Driven 3056 1496 2125 13% Surface 2100 68 K-55 12.415 12.259 BTC 14.375 Diamond 16 3454 1949 1069 9% Surface 7158 40 L-80 8.835 8.75 BTC 10.625 Diamond 12 Y. 5745 3087 916 3% Surface 8843 9.3 L-80 2.992 2.867 8rd 4.5 3,200 8.5 10,160 10,530 207 Comments: Casina Desian 20 130.1 K-55 100 N/A 12.97 8.40 89 37.44 21.63 16.63 13% 68 K-55 2100 9.4 14.59 8.40 1437 2.14 1.49 4.05 9% 40 L-80 7158 9.6 15.56 9.19 2338 1.17 1.19 2.71 3% 9.3 L-80 8843 9.6 15.80 9.43 3373 1.14 2.12 1.62 Comments: Maximum Anticipated Surface Pressure 13 % 2100 2676 9 % 6971 4371 3 % 8656 5000 * MAWP = Maximum Allowable Working Pressure. MASP = Maximum anticipated surface pressure 1437 2339 3375 0/100 70/30 0/100 page 4 e Comments: MASP calculated as the lesser of MASPfrac and MASPbhp 13318 inch Surface Casing SF := O.S·ppg TVDShoe:= 2100·ft psi Pgas:= O.l·ft TVDOH := 7304· ft FG :== 14.6·ppg MASP frac:= (FG + SF)·TVDShoe- (Pgas·TVDShJ MASP frac == 1437 psi psi BHP := 0.49·-· TVDOH ft Pmud :== 9.6·ppg MASPbhp:= BHP - (Fmud·TVDoH·Pmud) -[(1- Fmud)·TVDOH·PgaJ MASPbhp == 1975psi 9 5/8" Intermediate Casing SF := O· 5ppg TVDShoe:== 7304·ft TVDOH := 8656·ft . FG := 15.64·ppg psi P gas :== O.l·ft F mud := 30% MASP frac:== (FG + SF)·TVDShoe- (Pgas' TVDShoe) MASP frac == 5204 psi BRP:= 9.43·ppg·TVDOH BHP '" 4240psi MASPbhp:== BHP - (Fmud' TVDOR Pmud) - (1- Fmud)·TVDOR P gas MASPbhp = 2339psi page 5 e F mud := 300/, Pmud := 9.60·ppg e 3 1/2" Production Casinq TVDShoe:= 8656·ft BHP:= 9.43.ppg.TVDShoe psi P gas:= O.l·it MASPbhp := BHP - TVDOH·Pgas MASPbhp = 3375 psi BOPE PrOgram e Surface 13% 1,437 2,000 2676 Intermediate 9% 4371 2,339 2,000 Production 2,000 3)12 5000 3,375 Comments: Blowout Preventers 9.0 (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 135/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-518" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-518" 5M drilling spool with 3-118" 5M outlets 250/3,500 250/3,500 250/3500 The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-118" x 5000 psi outlets. 9.6 9.6 The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. page 6 e e Wellhead Equipment Summary Casing Head 13-%" 3M X 13-3/8" Slip Loc W/2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL 1, PR1 13 %" x 9 %" Fluted Mandrel 13 %" x 3 y," Manual Slip Tubing Head 13-%" 3M Studded Bottom X 13-%" 5M Fig Top, WI 2, 2-1/16" 5M Studded Outlets, U,AA,PSL 1,PR1 Adapter Flange 13-%" 5M X 3-Ya" 5M WI Seal Pocket and 3" H BPV Threads Comments: Directional Pro~ram Summary KOP 2500.00 2500.00 0 0 0 53.3 0 0 0 End of Build 3480.78 3461.73 2.0 0 2.0 19.62 53.3 99.37 N 133.29 E 166.25 End of Hold 5944.84 5782.79 0 0 0 19.62 53.3 593.78 N 796.48 E 993.46 End of Drop 7252.54 7065.10 -1.5 0 -1.5 0 53.3 726.27 N 974.20 E 1215.13 TD 8843.44 8656.00 0 0 0 0 53.3 726.27 N 974.20 E 1215.13 Comments: Directional Survevin~ Summary Oft-2,100ft 2,100ft-7,158ft 7,158 ft - 8,843 ft X X X Comments: page 7 e e Bit Summary 0 2,100 16 Christensen MX-1 115 1 - 4 80 - 350 2,100 7,158 121/4 Christensen HCM-406 M333 Up to 50 Motor 7,158 8,843 81/2 Christensen HCM-605 M323 Up to 25 Motor Comments: The 12 y." HCM-406 will be pulled for a dull grade near 6,600' MD (top of the main conglomerate). This bit will then be re-run in an attempt to drill the conglomerate section. No damage charge will be assessed for this test of the PDC's ability to drill conglomerate. If a second bit is necessary for the 12 y." hole an MX-C09D (IADC 437) should be used to finish this section. Back up bit for the 8 y," hole section will consist of an MX-RS18DD (IADC 447). See bit prognosis for additional information. Drillina Fluid Proaram Summary 0 2,100 8.6 - 9.4 2,100 5,000 9.0 - 9.4 5,000 7,158 9.4 - 9.6 7,158 8,843 9.2 - 9.4 Comments: Gel I Gelex Spud Mud Gel, Gelex, Soda Ash, Caustic, Barite, Polypac Supreme UL Flo-Vis, PoluPac UL, KCI, SafeCarb F, Ventrol 401, Barite, Caustic, Conqor 404, SafeScav NA Flo-Pro wI 6% KCL + Safecarb Flo-Pro wI 6% + Safecarb Flo-Vis, DualFlo, KCI, Greencide 25G, SafeCarb F&M, Barite, Caustic, Conqor 404, SafeScav NA Drillina Fluid Specifications 0 2,100 8.6-9.4 60-100 25-35 NC-12 ± 9.5 2,100 5,000 9.0-9.4 8-12 40,000 7-9 ± 9.5 ±5% 5,000 7,158 9.4-9.6 10-14 40,000 7-9 ± 9.5 ±8% 7,158 8,843 9.2-9.6 10-14 40,000 <6 ± 9.5 ±5% Comments: page 8 e e Solids Control Equipment O-TO x x x x Closed Loop System, Full Containment 1 - Derrick Model 0522 2 - Ml/Swaco units Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. Cement ProQram Summary 13% 9% 3% 2,100 7,158 8,843 2,100 6,971 8,656 12 Y. 16 o 1,800 6,658 o 1,800 6,473 930 1,685 731 1,411 2,511 928 8 8 NA 50 50 35 8% 12 832 1,913 1,800 10.59 Fresh 183 0 1,257 9% Class "G" 13.5 327 1.83 598 5,958 9.26 Fresh 5 0 877 3% Class "G" 15.8 790 1.17 928 6,658 4.96 Fresh 24 0 500+ Comments: page 9 e e Requlatory Waivers and Special Procedures Requirement for 2 pipe rams, one blind ram, and one annular for a API 5K or above BOP stack. Comments: Marathon is requesting a waiver from the above regulation for BC 12. Marathon requests that the BOP stack be configured with one pipe ram instead of two, due to rig height restrictions in the running ofthe 3 1/2" production casing. The height restriction involves having rig crew members routing control line and electrical line through one of the tubing head outlets after the 3 1/2" casing is cemented and the BOP stack is picked up. This is before setting the casing on slips and cutting the casing sticking up. These lines control firing of the perforating guns and the monitoring of downhole pressure and temperature in our EXCAPE completion system. A similar waiver was requested for an offset well on this pad BC 11 on 1/15/2003 and was granted. No problems were encountered while doing this operation on the above well this year. Hvdraulics Summary Rig mud pumps available are shown below. 3 National Oil Well A600PT 5 5 5 8 8 8 2,597 2,597 2,597 2.04 2.04 2.04 175/357 175/357 175/357 Surface Intermediate Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. 1 -12 0-2,100 17.5 600 2215 48 9.2 1 -14 Wellplan 2000 Hydraulics 2 -16's 2,100 -7,158 12.25 2,400 3 - 22's Wellplan 2000 Hydraulics 600 60 9.6 1 -15 7,158-8,843 8.5 436 2,000 226 3 - 20's Actual Data from Be #11 Comments: page 10 e . Formation Intearity Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test the BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close the ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. page 11 BC12 - bottom hole location change . Winton, Stan, The targeted bottom hole location for the BC12 has been changed by 449.7 ft. Proposed Bottom Hole Locations Old UTM: 2433594N 316623E Section offset: 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W New UTM: 2433912N 316305E Section Offset: 1297 ft FNL, 492 ft FWL, Section 34, T7N, R10W Attached is the revised directional plan. As per our telephone conversation, I am not sending a Sundry Notice. Best regards David R. Castillo Sr. Drilling Engineer 713-296-2350 «BC12 V5 Grid Rpt.pdf» «BC12 V5 Min Dis Clear Rpt.pdf» «BC12 V5 pp.pdf» «BC12 V5 sp.pdf» «BC12 V5 Std Rpt.pdf» «BC12 V5 tc.pdf» 1 of 1 2/9/2004 12:47 PM . . MARATHON Oil Company Pad #4 BC-12 slot #12 Beaver Creek Unit Kenai Peninsula, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License BC-12 Ver prop5607 Date printed Date created Last revised 5-Feb-2004 2-Feb-2004 2-Feb-2004 Field is centred on n60 38 50.050,wI50 59 49.92 Structure is centred on n60 38 50.050,wI50 59 49.92 Slot location is n60 39 22.120,wI51 1 45.595 Slot Grid coordinates are N 2433200.639, E 315319.955 Slot local coordinates are 3258.04 N 5765.79 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North . MARATHON Oil Company Pad #4,BC-12 Beaver Creek Unit/Kenai Peninsula, Alaska Measured Inclin Depth Degrees 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2600.00 2700.00 2800.00 2900.00 3000.00 3100.00 3200.00 3300.00 3400.00 10.00 12.00 14.00 16.00 18.00 3480.78 3500.00 4000.00 4500.00 5000.00 19.62 19.62 19.62 19.62 19.62 5305.97 5500.00 5944.84 5952.54 6052.54 19.62 19.62 19.62 19.50 18.00 6152.54 6252.54 6352.54 6452.54 6552.54 16.50 15.00 13.50 12.00 10.50 6652.54 6752.54 6852.54 6952.54 7052.54 7152.54 7252.54 7500.00 7602.44 7602.54 7700.00 7800.00 7883.44 7883.54 8000.00 8500.00 8590.44 8590.54 8843.44 Azimuth Degrees 0.00 0.00 0.00 0.00 0.00 53.30 53.30 53.30 53.30 53.30 True Vert Depth 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2599.98 2699.84 2799.45 2898.70 2997.47 3095.62 3193.06 3289.64 3385.27 3461. 73 3479.84 3950.82 4421.80 4892.79 5181.00 5363.77 5782.79 5790.05 5884.74 5980.24 6076.48 6173.40 6270.94 6369.01 6467.56 6566.53 6665.83 6765.41 6865.19 6965.11 7065.10 7312.56 7415.00 7415.10 7512.56 7612.56 7696.00 7696.10 7812.56 8312.56 8403.00 8403.10 8656.00 R E C TAN G U L A R COO R DIN ATE S O.OON O.OON O.OON O.OON O.OON O.OON 1.04N 4.17N 9.38N 16.66N 26.01N 37.42N 50.86N 66.33N 83.80N 99.37N 103.23N 203.55N 303.87N 404.20N 465.59N 504.52N 593.78N 595.32N 614.53N 632.25N 648.48N 663.19N 676.38N 688.04N 698.16N 706.74N 713.76N 719.23N 723.14N 725.49N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N 726.27N O.OOE O.OOE O.OOE O.OOE O.OOE O.OOE 1.40E 5.59E 12.58E 22.35E 34.89E 50.19E 68.22E 88.97E 112.41E 133.29E 138.46E 273.04E 407.61E 542.18E 624.53E 676.76E 796.48E 798.55E 824.32E 848.09E 869.85E 889.59E 907.28E 922.92E 936.50E 948.00E 957.43E 964.76E 970.01E 973.15E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E 974.20E Dogleg Deg/100ft . PROPOSAL LISTING Page 1 Your ref BC-12 Ver 5 Last revised 2-Feb-2004 0.00 0.00 0.00 0.00 0.00 0.00 2.00 2.00 2.00 2.00 0.00 1. 75 6.98 15.69 27.88 Vert Sect G RID Easting COORDS Northing 2433200.64 2433200.64 2433200.64 2433200.64 2433200.64 2433200.64 2433201.66 2433204.72 2433209.83 2433216.96 2433226.12 2433237.29 2433250.46 2433265.61 2433282.72 2433297.97 2433301.75 2433400.01 2433498.28 2433596.54 2433656.67 2433694.80 2433782.23 2433783.74 2433802.56 2433819.92 2433835.81 2433850.22 2433863.13 2433874.56 2433884.47 2433892.87 2433899.75 2433905.11 2433908.94 2433911.23 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 2433912.00 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #12 and TVD from Est RKB (Glacier 1) (171.10 Ft above mean sea level Bottom hole distance is 1215.13 on azimuth 53.30 degrees from wellhead. Total Dogleg for wellpath is 39.23 degrees. Vertical section is from N 0.00 E 0.00 on azimuth 53.29 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ 0.00 2.00 4.00 6.00 8.00 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 9.00 7.50 6.00 4.50 3.00 53.30 53.30 53.30 53.30 53.30 1. 50 0.00 0.00 0.00 0.00 53.30 53.30 53.30 53.30 53.30 0.00 0.00 0.00 0.00 0.00 270.00 270.00 270.00 270.00 270.00 0.00 0.00 0.00 0.00 270.00 270.00 27 0 . 00 270.00 2.00 2.00 2.00 2.00 2.00 43.52 62.60 85.10 110.98 140.21 2.00 0.00 0.00 0.00 0.00 166.25 172.71 340.56 508.41 676.27 0.00 0.00 0.00 1. 50 1. 50 77 8.98 844.12 993.46 996.03 1028.18 1. 50 1. 50 1. 50 1. 50 1. 50 1057.83 1084.97 1109.59 1131.66 1151.17 1. 50 1. 50 1.50 1. 50 1. 50 1168.10 1182.45 1194.20 1203.35 1209.89 1. 50 1. 50 0.00 0.00 0.00 1213.82 1215.13 1215.13 1215.13 1215.13 0.00 0.00 0.00 0.00 0.00 1215.13 1215.13 1215.13 1215.13 1215.13 0.00 0.00 0.00 0.00 1215.13 1215.13 1215.13 1215.13 0.00 0.00 0.00 0.00 0.00 315319.95 315319.95 315319.95 315319.95 315319.95 315319.95 315321.37 315325.61 315332.68 315342.56 315355.24 315370.70 315388.94 315409.92 315433.62 315454.73 315459.96 315596.03 315732.10 315868.17 315951. 44 316004.24 316125.30 316127.39 316153.45 316177.49 316199.49 316219.44 316237.33 316253.15 316266.88 316278.51 316288.04 316295.45 316300.76 316303.94 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 316305.00 . MARATHON Oil Company Pad #4,BC-12 Beaver Creek Unit/Kenai Peninsula, Alaska Comments in wellpath -------------------- -------------------- MD TVD Rectangular Coords. Comment ----------------------------------------------------------------------------------------------------~------ . PROPOSAL LISTING Page 2 Your ref BC-12 Ver 5 Last revised: 2-Feb-2004 2500.00 2500.00 O.OON O.OOE KOP 3480.78 3461. 73 99.37N 133.29E End of Curve 5305.97 5181. 00 465.59N 624.53E Sterling B-3 5944.84 5782.79 593.78N 796.48E End of Hold 7252.54 7065.10 726.27N 974.20E End of Drop 7602.44 7415.00 726.27N 974.20E Lower Beluga B-19 7602.54 7415.10 726.27N 974.20E BC12 - LB-19R - 2/2/04 7883.44 7696.00 726.27N 974.20E Lower Beluga B-23 7883.54 7696.10 726.27N 974.20E BC12 - LB-23R - 2/2/04 8590.44 8403.00 726.27N 974.20E Lower Beluga B-30 8590.54 8403.10 726.27N 974.20E BC12 - LB-30R - 2/2/04 8843.44 8656.00 726.27N 974.20E TD Casing positions in string 'A' ------------------------------ ------------------------------ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing ----------------------------------------------------------------------------------------------------------- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 O.OON O.OON O.OON O.OON O.OOE O.OOE O.OOE O.OOE 100.00 2100.00 7491.44 8843.44 100.00 2100.00 7304.00 8656.00 O.OON O.OON 726.27N 726.27N O.OOE O.OOE 974.20E 974.20E 20 Conductor 13 3/8 Casing 9 5/8 Casing 3 1/2 Liner Target name T.V.D. Targets associated with this wellpath Revised ~------~~-~----------~------~~~------ -------~~~-------~----------~-------- Geographic Location Rectangular Coordinates ----------------------------------------------------------------------------------------------------------- BC12 - LB-19R - 2/2/ 316305.000,2433912.000,0.0000 BC12 - LB-23R - 2/2/ 316305.000,2433912.000,0.0000 BC12 - LB-30R - 2/2/ 316305.000,2433912.000,0.0000 7415.10 7696.10 8403.10 726.27N 726.27N 726.27N 974.20E 974.20E 974.20E 2-Feb-2004 2-Feb-2004 2-Feb-2004 Coordinates ore in feet referençe slot #12. Vertical Depths ore reference Esl f"K8 (Gtoçier R¡MII BAKER HUG"S INTEQ 500 - 1000 - 1500 - . . Created by bmichoel ¡ I IMARATHON Oil Company I I i ,- Dote plotted 2~Feb-2D04 Plot Reference is 8C-12 Ver 5. Sfructure : Pod #4 Well: BC-12 Field Beaver Creek Unit Location Kenai Peninsula. Alaska ~ East (feet) -> 100 100 200 700 800 900 1000 1100 o JOO 400 500 600 o ! 20 Conductor o KOP 02.00 Lower Beluga B-19 - 800 Lower Beluga 8-23 Lower Beluga B-30 9 5/8 Casing - 700 - 600 <0 CY o/, - 500 ^ 'ÝO I 0: ~ ">-/-. - 400 Z 'l;> 0 9<9 ..., - ::r '0' - JOO ~ -h CD CD - - 200 '--" - 100 0 100 2000- Ll 13 3/8 Casing 2500 - ~ -- Q) Q) 4- '--" JOOO - .s:: -- 0.. ( ) o JSOO - 4000 - o o 4500 - -- L Q) > Q) :¡ L l- I V 5000 - 5500 - 6000 - 6500 - 7000 - 7500 - DLS: 2.00 deg per 100 ft af Curve <0 CY o/, C'v /-1- (0 "'G /0' 0,0 0' --& C'o -5'. <) .9 ~ 9 5/8 19.50 16.50 13.50 10.50 7.50 4.50 1.50 0 o End of Drop Casing Ll Lower Beluga Lower Beluga B-19 B-23 TRUE DLS: 1.50 deg per 100 ft ---- WELL PROFILE DATA ---- Point ~~--- "0 Oir NO V. Seçt Tie on 53.30 0.00 0_00 0.00 KOP 2500.00 0.00 2500.00 QOO 0,00 0.00 End of Build 3480.78 19.62 53.30 3461.73 ~9.37 133.29 1615.25 End 01 HOld 19_62 53.30 5782.79 59338 796.48 [EO' of O"p 7252.54 0.00 53.30 1065_10 726..27 974.20 1215.13 Torget BC12 - LB-19R - 760Z.~4 0.00 53.30 7415.10 725.27 97420 1215.13 I Torr;¡et BC12 - L8~23R - 7883.54 0_00 270_00 7696.10 726.27 97420 1215.13 Torget Be12 ~ LB-30R - 8590.54 0.00 270.00 8403.10 725_27 974.20 1215.13 8000 - Lower Belu9a 8-30 8500 - 1/2 Liner jol 3 TO 9000 0 500 1O00 1500 Vertical Section (feet) -> Azimuth 53.29 with reference 0.00 N, 0.00 E from slot #12 Crealed by bmichoel Date plotted 2-Feb-2D04 Pial Reference is 8C:-12 Ver 5, Coon:linotes are in feet relerence slot #12. . . MARATHON Oil Company Sfructure : Pad #4 Well BC-12 True Ver1ìcal Depths ore reference Est RKB (Glacier 1). Riœ1l! Bt~s INTEQ 1280 1200 - 1120 - 1040 - 960 - 880 - 800 - 720 - ^ I 640 - 160 80 I i ____---.-1 Field Beaver Creek Unit Location Kenai Peninsula. Alaska --~- East (feet) -> o 320 560 640 720 800 80 160 240 400 480 77 -'00 7~ 000 7", V'°o 8C12 - LB-19R BC12 - LB-23R 8C12 L8-30R - 2/2/04 - 2/2/04 - 2/2/04 ~ 6'°0 .m '--0._ 7", 7V' _~~O~_:~O_. 7V'V'00 70'0'00 7V'-,0 -." "--'--0. -..-. ----..-o._.._~ V 7J; :900 _9 .-.-..' / '~-/7··-----·- .-- 77 700 77 "'00 000 /6' /' 6'0 700 /.s: 00 ß 0' 0'0 ¿ ~O 0 /' 0'.> 0 ß /' 0'6' °0 ¿ ð'.s: °0 /' 0' 00 /' ð'J; 7°0 ¿ ß 0',," 00 /' 0'7 00 ß /' 0'00 00 ¿ 70' 0 /' 7 00 /' 7.> Ó'00 ¿ ß 76' 00 /' 7.s: 00 /' 7 00 ß 70 ¿ 7J; ° ./ 'if 00 /'" '200 ß 70 ¿ "0 ° /' V'''' 00 / V'<£ 00 " ß V'.> 00 /' V'6' 00 /' V'0: °0 ß ß V'7 °0 /' V'J; 00 ß 00 ¿ V'7 €if "'", 00 70 °0 00 ,.-.... ;- Q) Q) '+- "-'" 560 - ø ,// 70." /' 7 Vo " 06' 0 ø'/"'/ / OX': °0 // 70,," 00 - ~ 700 00 0/ Do .c ;- L o Z 480 400 320 - 240 - 240 160 f7 160 - 80 - o - 80 - 160 - 80 80 800 240 480 720 o 160 320 400 560 640 East (feet) -> 880 880 MARATHON , .. 960 1040 1120 1280 - 1200 - 1120 - 1040 - 960 - 880 - 800 - 720 640 ^ I - 560 Z 0 , -+ :J - 480 ,.-.... -... <D <D -+ - 400 "-'" - 320 - 240 - 160 - 80 - 80 - 160 960 1040 240 1120 . . MARATHON Oil Company Pad #4 BC-12 slot #12 Beaver Creek Unit Kenai Peninsula, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License BC-12 Ver 5 prop5607 Date printed Date created Last revised 2-Feb-2004 2-Feb-2004 2-Feb-2004 Field is centred on n60 38 50.050,w150 59 49.92 Structure is centred on n60 38 50.050,w150 59 49.92 Slot location is n60 39 22.120,w151 1 45.595 Slot Grid coordinates are N 2433200.639, E 315319.955 Slot local coordinates are 3258.04 N 5765.79 W Projection type: alaska - Zone 4/ Spheroid: Clarke - 1866 Reference North is True North . MARATHON oil Company Pad #4,BC-12 Beaver Creek Unit, Kenai Peninsula, Alaska Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2600.00 2700.00 2800.00 2900.00 3000.00 3100.00 3200.00 3300.00 3400.00 10.00 12.00 14.00 16.00 18.00 3480.78 3500.00 4000.00 4500.00 5000.00 19.62 19.62 19.62 19.62 19.62 5305.97 5500.00 5944.84 5952.54 6052.54 19.62 19.62 19.62 19.50 18.00 6152.54 6252.54 6352.54 6452.54 6552.54 16.50 15.00 13.50 12.00 10.50 6652.54 6752.54 6852.54 6952.54 7052.54 7152.54 7252.54 7500.00 7602.44 7602.54 7700.00 7800.00 7883.44 7883.54 8000.00 8500.00 8590.44 8590.54 8843.44 0.00 0.00 0.00 0.00 0.00 53.30 53.30 53.30 53.30 53.30 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2599.98 2699.84 2799.45 2898.70 2997.47 3095.62 3193.06 3289.64 3385.27 3461.73 3479.84 3950.82 4421.80 4892.79 5181.00 5363.77 5782.79 5790.05 5884.74 5980.24 6076.48 6173.40 6270.94 6369.01 6467.56 6566.53 6665.83 6765.41 6865.19 6965.11 7065.10 7312.56 7415.00 7415.10 7512.56 7612.56 7696.00 7696.10 7812.56 8312.56 8403.00 8403.10 8656.00 R E C TAN G U L A R COO R DIN ATE S 0.00 N 0.00 N 0.00 N 0.00 N 0.00 N 0.00 N 1.04 N 4.17 N 9.38 N 16.66 N 26.01 N 37.42 N 50.86 N 66.33 N 83.80 N 99.37 N 103.23 N 203.55 N 303.87 N 404.20 N 465.59 N 504.52 N 593.78 N 595.32 N 614.53 N 632.25 N 648.48 N 663.19 N 676.38 N 688.04 N 698.16 N 706.74 N 713.76 N 719.23 N 723.14 N 725.49 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 726.27 N 0.00 E 0.00 E 0.00 E 0.00 E 0.00 E 0.00 E 1.40 E 5.59 E 12.58 E 22.35 E 34.89 E 50.19 E 68.22 E 88.97 E 112.41 E 133.29 E 138.46 E 273.04 E 407.61 E 542.18 E 624.53 E 676.76 E 796.48 E 798.55 E 824.32 E 848.09 E 869.85 E 889.59 E 907.28 E 922.92 E 936.50 E 948.00 E 957.43 E 964.76 E 970.01 E 973.15 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E 974.20 E Dogleg Deg/100ft . PROPOSAL LISTING Page 1 Your ref BC-12 Ver 5 Last revised 2-Feb-2004 Vert Sect 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.00 4.00 6.00 8.00 53.30 53.30 53.30 53.30 53.30 0.00 2.00 2.00 2.00 2.00 0.00 KOP 1. 75 6.98 15.69 27.88 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 53.30 9.00 7.50 6.00 4.50 3.00 53.30 53.30 53.30 53.30 53.30 2.00 2.00 2.00 2.00 2.00 43.52 62.60 85.10 110.98 140.21 1. 50 0.00 0.00 0.00 0.00 53.30 53.30 53.30 53.30 53.30 2.00 0.00 0.00 0.00 0.00 166.25 End of Curve 172.71 340.56 508.41 676.27 0.00 0.00 0.00 0.00 0.00 270.00 270.00 270.00 27 0.00 270.00 0.00 0.00 0.00 1. 50 1. 50 778.98 Sterling B-3 844.12 993.46 End of Hold 996.03 1028.18 0.00 0.00 0.00 0.00 270.00 27 0.00 270.00 270.00 1. 50 1. 50 1. 50 1. 50 1. 50 1057.83 1084.97 1109.59 1131.66 1151.17 1. 50 1. 50 1. 50 1. 50 1. 50 1168.10 1182.45 1194.20 1203.35 1209.89 1. 50 1. 50 0.00 0.00 0.00 1213.82 1215.13 End of Drop 1215.13 1215.13 Lower Beluga B-19 1215.13 BC12 - LB-19R - 2/2/04 0.00 0.00 0.00 0.00 0.00 1215.13 1215.13 1215.13 Lower Beluga B-23 1215.13 BC12 - LB-23R - 2/2/04 1215.13 0.00 0.00 0.00 0.00 1215.13 1215.13 Lower Beluga B-30 1215.13 BC12 - LB-30R - 2/2/04 1215.13 TD All data is in feet unless otherwise stated. Coordinates from slot #12 and TVD from Est RKB (Glacier 1) (171.10 Ft above mean sea level). Bottom hole distance is 1215.13 on azimuth 53.30 degrees from wellhead. Total Dogleg for wellpath is 39.23 degrees. Vertical section is from N 0.00 E 0.00 on azimuth 53.29 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ . MARATHON Oil Company Pad #4,BC-12 Beaver Creek Unit, Kenai Peninsula, Alaska Comments in wellpath --~-~--------------- -------------------- MD Rectangular Coords. Comment ----------~------------------------------------------------------------------------------------------------ TVD . PROPOSAL LISTING Page 2 Your ref BC-12 Ver 5 Last revised: 2-Feb-2004 2500.00 2500.00 0.00 N 0.00 E KOP 3480.78 3461.73 99.37 N 133.29 E End of Curve 5305.97 5181.00 465.59 N 624.53 E Sterling B-3 5944.84 5782.79 593.78 N 796.48 E End of Hold 7252.54 7065.10 726.27 N 974.20 E End of Drop 7602.44 7415.00 726.27 N 974.20 E Lower Beluga B-19 7602.54 7415.10 726.27 N 974.20 E BC12 - LB-19R - 2/2/04 7883.44 7696.00 726.27 N 974.20 E Lower Beluga B-23 7883.54 7696.10 726.27 N 974.20 E BC12 - LB-23R - 2/2/04 8590.44 8403.00 726.27 N 974.20 E Lower Beluga B-30 8590.54 8403.10 726.27 N 974.20 E BC12 - LB-30R - 2/2/04 8843.44 8656.00 726.27 N 974.20 E TD Casing positions in string 'A' ------------------------------ -----------------------------~ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing ----------------------------------------------------------------------------------------------------------- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 O.OON O.OON O.OON O.OON O.OOE O.OOE O.OOE O.OOE 100.00 2100.00 7491.44 8843.44 100.00 2100.00 7304.00 8656.00 O.OON O.OON 726.27N 726.27N O.OOE O.OOE 974.20E 974.20E 20 Conductor 13 3/8 Casing 9 5/8 Casing 3 1/ 2 Liner Target name Geographic Location T.V.D. Targets associated with this wellpath Revised --------~-----~------------------~--- ------------------------------------- Rectangular Coordinates BC12 - LB-19R - 2/2/ 316305.000,2433912.000,0.0000 BC12 - LB-23R - 2/2/ 316305.000,2433912.000,0.0000 BC12 - LB-30R - 2/2/ 316305.000,2433912.000,0.0000 7415.10 7696.10 8403.10 ----------------------------------------------------------------------------------------------------------- 974.20E 974.20E 974.20E 726.27N 726.27N 726.27N 2-Feb-2004 2-Feb-2004 2-Feb-2004 . . I -~-----~------~-- Crected by bm;.çhoel I MARATHON Oil Company! Date ploUed: 5-Feb-2004 Plot Reference is 8Ç-12 Ver 5, !mm CDordinotes ore in feet reference slot 612. I Vertical Depths Clfe reference Esl RK8 (Glacier Siructure : Pad #4 Well: BC-12 Bi!lll BAKER HUGHES Field: Beaver Creek Unit Location: Kenai Peninsula, Alaska _._----_._----<-~-----_._._---- TRUE NORTH cØ <:> = /.p 0'0 350 0 10 /' /ef' 0'.1 00 .. /'0'", 00 340 20 14/ 00 // 'ÚOo 330 30 / ø v' 280 æf "00 .'" 0'0'0 320 40 0 310 50 300 60 290 70 280 80 40 270 4C~) 90 40 260 100 250 1 1 0 240 120 230 130 220 140 210 150 200 160 190 180 170 ~ormal Plane Travelling Cylinder - Feet All depths shown ore Measured depths on Reference Well . 'M..") Marathon . ~MARATHON Oil Company . Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 November 17, 2003 Sarah Palin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ¡th Ave, Suite 100 Anchorage, AK 99501 Reference: Replacement Permit to Drill Field: Beaver Creek Field Well: Beaver Creek Unit BC-12 Dear Ms. Palin, Enclosed please find the revised well plan for the Beaver Creek Unit BC-12. 1) The cement volumes for the 3.50 EXCAPE production string have been corrected to 639 sacks. 2) All of the BOP test pressures have been changed to 3500 psi. 3) Incorrect 9-% inch casing depths have been corrected to 7544 ft MD. Additionally, I am attaching a corrected Permit to Drill application with the 639 sacks of cement. If you require further information, please contact me. Sincerely, 8'~__~. ~ David R. Castillo Senior Drilling Engineer Telephone: 907-564-6465 Email: DRCastillo@MarathonOil.com ()¡~\G\NAL . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 MC 25.005 1a. Type of Work: DrillŒ] Re-entryD RedrillD 1 b. Current Well Class: Stratigraphic TestD EXPloratoryD serviceD Development Oil D Development Gas Œ] Multiple zoneŒ] Single ZoneD 2. Operator Name: Marathon Oil Company 5. Bond: Œ]Blanket D SingleWellD 11. Well Name and Number: Bond No. 5194234 BC-12 3. Address: P.O. Box 196168. Anchorage. AK 99519-6168 4a. Location of Well (Governmental Section): Surface: 2023' FNL, 482' FEL, Sec 33 T7N R10W, S.M. 6. Proposed Depth: MD: 8,896 ft TVD: 8686 ft 7. Property Designation: A-028083 8. Land Use Permit: 12. Field/Pool(s): Beaver Creek I Beluga Total Depth: 1610' FNL, 815' FWL, See 34. T7N. R10W, S.M., AK 4b. Location of Well (State Base Plane Coordinates): 1560 1 O. KB elevation 13. Approximate Spud Date: 5/2212004 14. Distance to Nearest Property: 350011 15. Distance to Nearest Well within Pool: 1,332' (BC-9 Beluga cut point) Top of Productive Horizon: 1610' FNL. 815' FWL. See 34. T7N. R10W. S.M.. AK NIA 9. Acres in Property: Surface: x- 315319.955' y- ,2433,200.639' Zone- 4 16. Deviated Wells: (Height Above GL): 171 (21' above GL) feet 17. Anticipated Pressure (see 20 AAC 25.035) Kickoff Depth: 2,500 ft. 18. Casing Program: Size Casing 20" 133/8" 9 5/8" 3 1/2" Maximum Hole Angle: 24.4 0 Max. Downhole Pressure: 4083 Setting Depth psig. Max. Surface Pressure: 3,373 Quantity of Cement c.f. or sacks. (Including Stage Data) psig. Specifications Top Bottom Hole Weight 131.45# 68# 40# 9.3# Grade Coupling Length MD TVD MD TVD K-55 PE +1- 100' 0' 0' 100' 100' K-55 BTC 2,100' 0' 0' 2.100' 2.100' L-80 BTC 7,544' 0' 0' 7,544' 7304' L-80 EUE 8,896' 0' 0' 8,896' 8656' PRESENT WELL CONDITION SUMMARY (to be completed for Redrill and Re-Entry Operations) Total Depth TVD (ft.) Plugs (measured) Effective depth MD (ft) Effective Depth TVD(ft): +1-556sks + /-1.512 sks + 1- 639 sks. Driven 16" 121/4" 8112" 19. Total Depth MD (ft): Junk (measured) Casing Length Size Cement Volume MD TVD Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing FeeŒ] BOP Sketch Œ] Drilling Program Œ] Time v. Depth PlotD Shallow Hazard AnalysisD Property PlatŒ] Diverter Sketch Œ] Seabed ReportD Drilling Fluid ProgramŒ] 20 AAC 25.050 RequirementsD Date: 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name David R. Castillo ~R~ Title Senior Drilling Engineer Signature Phone 907-564-6465 Date 11/17/2003 Permit to Drill Number: IAPI Number: 50- Commission Use Only I Permit Approval Date: Hydrogen sulfide measures Dves DNo Dves DNo Mud log required Dves DVes I See cover letter for other requirements. DNo DNO Conditions of approval: Samples required Directional survey required Other: Approved by: COMMISSIONER BV ORDER OF THE COMMISSION Date: Form 10-401 Revised 3/2003 Submit in duplicate ¡~L . . MARATHON MARATHON Oil COMPANY DRilliNG PROGRAM BEAVER CREEK 12 PERMIT REVISION 1 November 14,2003 Originator: David R. Castillo Drilling Supervisors: Gene Anderson, Roland Lawson Drilling Superintendent: Peter Berga . . Table of Contents General Well Data............................................................................................................................ .......................................1 Geologic Program Summary........................................................................................................................... ........................1 Summary of Potential Drilling Hazards.................................. ..................................................................................................2 Formation Evaluation Summary ..................................................................................................................................... .........2 Drilling Program Summary............................................................................................................................... .......................3 Casing Program............................................................................ ......................................................................................... ..4 Casing Design .............................................................................................................................. ...........................................4 Maximum Anticipated Surface Pressure........................................................................................................................... ......4 BOPE Program....................................................................................................................... .................................................6 Wellhead Equipment Summary................................................................................................................................. ..............7 Directional Program Summary.............................................. .................................................................................................. 7 Directional Surveying Summary.................................................................................... .......................................................... 7 Drilling Fluid Program Summary............................................................................................................................. ................7 Drill ing Flu id Specifications................................................................................................................. .....................................8 Solids Control Equipment............................................................................................................................ ............................8 Cement Program Summary............................................................................................................................. ........................9 Regulatory Waivers and Special Procedures........................ .................................................................................................. 9 Hydraulics Summary.............................................................................................................................. ...............................10 Formation Integrity Test Procedure................................................................................................ .......................................10 . General Well Data Beaver Creek 1 Y: 2433200.639 X: 315319.955 Pad 4 21 ft 150.1ft RKB NA NA Ground Level Elev. to MSL Perm. Datum Water Depth State I Country Total MD TotalTVD NA Comments: GeoloQic PrOQram Summary . Lease/Ucense NA WBS Code DD.03.09540.CAP.DRL Beaver Creek Spud Date May 22, 2004 Kenai Borough API No. NA Alaska Well Class Development 8896 Rig Contractor Inlet Drilling 8656 Rig Name Glacier 1 Sterling B3 5346.70 5181 1176 4.4 Sandstone Gas I Water Sterling B4 5520.54 5341 2161 8.0 Sandstone Gas I Water Upper Beluga B2 6346.37 6116 2485 to 3479 9.9 Sandstone Gas Lower Beluga B 16 7409.42 7169 2522 to 3531 6.7 to 9.3 Sandstone Gas Lower Beluga B 17 7517.42 7277 2553 to 3574 6.7 to 9.4 Sandstone Gas Lower Beluga B 18 7603.42 7363 2204 to 3599 6.7to 9.4 Sandstone Gas Lower Beluga B19 7655.42 7415 2225 to 3634 5.7 to 9.4 Sandstone Gas Lower Beluga B20 7726.42 7486 2257 to 3686 5.7 to 9.4 Sandstone Gas Lower Beluga B21 7832.42 7592 2288 to 3737 5.7 to 9.4 Sandstone Gas Lower Beluga B23 7936.42 7696 2635 to 3797 5.7 to 9.4 Sandstone Gas Lower Beluga B24 8059.42 7819 2782 to 3895 6.5 to 9.4 Sandstone Gas Lower Beluga B26 8259.42 8019 2810 to 3934 6.7 to 9.4 Sandstone Gas Lower Beluga B27 8339.42 8099 2872 to 4021 6.7 to 9.4 Sandstone Gas Lower Beluga B29 8517.42 8277 2917 to 4083 6.7 to 9.4 Sandstone Gas Lower Beluga B30 8643.42 8403 2485 to 3479 6.7 to 9.4 Sandstone Gas Comments: Surface Location Coordinates From Lease/Block Unes 482 ft FEL 2023 ft FNL of Section 33 Township 7-N, Range 10-W 600 39' 22.120" N Longitude 151001' 45.595" W 2433200.639 315319.955 Coordinate System NAD27 ASP ZONE 4 Tolerance page 1 . . Top/L.Beluga LB-19 7655 7415 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 Top/L.Beluga LB-23 7957 7696 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 Top/L.Beluga LB-30 8664 8403 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 Total Depth 8896 8656 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 Comments: Summary of Potential Drillina Hazards Lost Circulation The Sterling B-3 sands are approximately 1147 psig and 400 md perm. The Lower Beluga intervals have SBHP's that range from a 0.31-.46 psi/ft. Control losses by using sufficiently sized LCM. See comment above about the Sterling B-3 and the Lower Beluga intervals. Keep the drill pipe moving and avoid if possible excess overbalance. Maintain low fluid loss and thin impermeable filter cake. Circulate hole clean before tripping. Do not POOH or RIH faster than 30 see/stand Differential Sticking Surge/Swabbing Comments: Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands will be encountered from +1- 5,347 ft MD RKB (5,181 ft TVD RKB) to total depth of the well. These sands will run from normal pressured to severely depleted and lost circulation and differential sticking are potential hazards. The FloPro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. No well interference hazards exist. Formation Evaluation Summary Surface None o ft - 2,100 ft MD Intermediate None 2,100 ft - 7,544 ft MD Production None 7,544 ft - 8,896 ft MD Completion NIA None None None Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Triple combo (PEX), Digital Sonic (DSI), CMR Plus', MDT' GR, CCL NIA * Log run if borehole conditions allow Coring Requirements: None Comments: page 2 . . Drillin~ Pro~ram Summary CONDUCTOR: 1. Drive 20" conductor to +1-100 ft. RKB. 2. Move in and rig up Glacier #1 rotary drilling rig. 3. Install starting head 20" SOW x 21 1/4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. 5. Function test diverter and diverter valve. SURFACE: 1. Drill a 16" hole to 2,100 ft MD (2,100' TVD) with Spud Mud. 2. RIH with 13 3/8" casing and hang off in the slips. Make up stab-in sub and centralizer on 4" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 3/8" casing. Sting out and circulate drill pipe clean. TOOH with inner string. 3. PU 133/8" casing, set casing slips in 20", cut off 13 3/8", ND diverter. 4. Install 13 318" slip lock connection X 13 %" 5M flanged multibowl wellhead. 5. NU 13 %" 5M BOP'S. Test BOP'S and choke manifold to 250/3,500 psi. 6. Set wear bushing. 7. Test surface casing to 2,000 psi. INTERMEDIATE: 1. Drill out float equipment and make 20' of new hole. 2. Displace spud mud with FloPro. Circulate mud until mud weight in equals mud weight out. 3. Test shoe to leak-off. Estimated EMW is 14.6 ppg. 4. Drill 12 1/4" directional hole to 7,544 ft MD (7,304 ft TVD) as per directional plan. 5. Make wiper trip. 6. Change out variable pipe rams with 9 %" casing rams. Run test plug and test BOP casing rams to 250/3,500 psi. 7. Run and cement 9 %" casing. Land hanger in multibowl wellhead. 8. . Back out landing joint. Change out 9 %" BOP casing rams with variable pipe rams. Run test plug and test BOP pipe rams to 250/3,500 psi. 9. Set wear bushing. Test casing to 2,000 psi. PRODUCTION: 1. Drill float equipment and 20' of new formation w/8 W' bit. Circulate mud until mud weight in equals mud weight out.. 2. Test shoe to leak-off. Estimated EMW 15.8 ppg. 3. Drill an 8 W' hole to 8896 ft MD RKB (8656 ft TVD) per the directional program. 4. TOOH. RU logging company. Run open hole logs as per plan. RD logging company. 5. TIH to TD for wiper trip. TOOH and lay-down BHA and drill pipe. Pull the wear bushing. 6. Run 3 W' EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD logging company. 7. Cement 3 Y2" casing while reciprocating. Bump plug with 500 psi over displacement pressure. WOC. 8. PU 3 Y2" casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 3 Y2" casing. 9. LD BOP. Set 3 Y2" packoff. NU 13 %" 5M X 3 Yo" 5M tubing head adapter and 3 Yo" 5M tree. Test tree to 5,000 psi. 10. Rig down and move out drilling rig. Note: Perforating guns will be run on the outside of the 3 Y2" production casing with a flapper valve just below each perforating gun. Guns to be activated by control line to surface. COMPLETION: Completion will be done without a rig. page 3 . . Casinç¡ Proç¡ram 20 Surface 100 130.1 K-55 18.873 18.543 Driven 3056 1496 2125 13 % Surface 2100 68 K-55 12.415 12.259 BTC 14.375 Diamond 16 3454 1949 1069 9% Surface 7544 40 L-80 8.835 8.75 BTC 10.625 Diamond 12 Y. 5745 3087 916 3'12 Surface 8896 9.3 L-80 2.992 2.867 8rd 4.5 3,200 8.5 10,160 10,530 207 Comments: Casinç¡ Desiç¡n 20 130.1 K-55 100 NIA 12.97 8.40 89 37.44 21.63 16.63 13% 68 K-55 2100 9.0 14.59 8.40 1437 2.20 1.49 4.14 9% 40 L-80 7544 9.6 15.64 9.40 2338 1.32 1.12 2.58 3'12 9.3 L-80 8896 9.6 15.80 9.43 3373 1.14 2.11 1.62 Comments: Maximum Anticipated Surface Pressure 13% 9% 2100 7304 2676 4371 1437 2339 3375 0/100 70/30 0/100 3 '12 8650 5000 * MAWP = Maximum Allowable Working Pressure. ** MASP = Maximum anticipated surface pressure page 4 . Comments: MASP calculated as the lesser of MASPfrac and MASPbhp 13 3/8 inch Surface Casinq SF := 0.5·ppg FG := 14.6· ppg TVD Shoe:= 2100· ft psi Pgas:= O.l·ft TVDOH := 7304·ft MASP frac := (FG + SF)· TVDShoe - (p gas' TVDShoe) MASP frac = 1437psi pSI BHP := 0.49·-· TVDOH P . 9 6 ppg ft mud·= . . MASPbhp:= BHP - (Fmud·TVDORPmud) - [( 1 - Fmud)·TVDOH·PgaJ MASPbhp = 1975psi 95/8" Intermediate Casinq SF := O· 5ppg TVDShoe:= 7304· ft TVDOH := 8656·ft FG := 15.64·ppg psi Pgas:= O.l·ft F mud := 30% MASP frac:= (FG + SF)· TVDShoe- (Pgas·TVDShoe) MASP frac = 5204psi BHP := 9.43·ppg· TVDOH BHP = 4240psi MASPbhp:= BHP - (Fmud·TVDOH·Pmud) - (1 - Fmud)· TVDOR Pgas MASPbhp = 2339psi page 5 . F mud := 300/, Pmud := 9.60·ppg . 3 1/2" Production Casinq TVDShoe:= 8656· ft pSI BHP := 9.43.ppg·TVDShoe Pgas:= O.l·ft MASPbhp:= BHP - TVDOH'Pgas MASPbhp = 3375psi BOPE Proaram . Surface 13 % 2,000 9.0 2676 1,437 Intermediate 9% 2,339 2,000 9.6 4371 Production 3% 2,000 9.6 5000 3,375 Comments: Blowout Preventers (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13518" 5M blind ram (1) 13-518" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 135/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-518" 5M annular (1) 13-5/8" 5M pipe ram (1) 135/8" 5M blind ram (1) 13-518" 5M drilling spool with 3-118" 5M outlets 250/3,500 250/3,500 250/3500 The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-118" x 5000 psi outlets. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. page 6 . . Wellhead Equipment Summary Casing Head 13-%" 3M X 13-3/8" Slip Loc W/2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL 1, PR1 13 %" x 9 %" Fluted Mandrel 13 %" x 3 y." Manual Slip Tubing Head 13-%" 3M Studded Bottom X 13-%" 5M Fig Top, W/2, 2-1/16" 5M Studded Outlets, U,AA,PSL 1,PR1 Adapter Flange 13-%" 5M X 3-%" 5M WI Seal Pocket and 3" H BPV Threads Comments: Directional Pro~ram Summary Tie On 0 0 0 0 0 0 0 0 0 0 KOP 2,500.00 2,500.00 0 0 0 0 72.33 0 0 0 End of Build 3,650.89 3,620.18 2.0 0 2.0 23.02 72.33 69.22 N 217.33 E 228.09 End of Hold 5,771.03 5571.52 0 0 0 23.02 72.33 320.81 N 1007.24 E 1057.10 End of Drop 7305.55 7065.10 -1.5 0 -1.5 0 72.33 413.11 N 1297.01 E 1361.21 TO 8896.55 8656.10 0 0 0 0 72.33 413.11 N 1297.01 E 1361.21 Comments: Directional Survevin~ Summary o ft - 2,100 ft 2,100 ft - 7,676 7,676 ft - 8,656 ft X X X Comments: Drillin~ Fluid Pro~ram Summary 0 2,100 8.6 - 9.4 Gell Gelex Spud Mud Gel, Gelex, Soda Ash, Caustic, Barite, Polypac Supreme UL 2,100 5000 9.0 - 9.4 Flo-Pro wI 6% KCL + Safecarb Flo-Vis, PoluPac UL, KCI, SafeCarb F, Ventrol 401, Barite, Caustic, Conqor 404, SafeScav NA 5000 7544 9.4 - 9.6 7544 8896 9.2 - 9.4 Flo-Pro wI 6% + Safecarb Flo-Vis, DualFlo, KCI, Greencide 25G, SafeCarb F&M, Barite, Caustic, Conqor 404, SafeScav NA Comments: page 7 . . DrillinQ Fluid Specifications 0 2100 8.6-9.4 60-100 25-35 NC-12 ± 9.5 2100 5000 9.0-9.4 8-12 40,000 7-9 ± 9.5 ±5% 5000 7544 9.4-9.6 10-14 40,000 7-9 ±9.5 ±8% 7544 8896 9.2-9.6 10-14 40,000 <6 ±9.5 ±5% Comments: Solids Control Equipment O-TD x x x x Closed Loop System, Full Containment NIA 1 - Derrick Model 0522 NIA 2 - Ml/Swaco units NIA Marathon G&I Facility NIA Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. page 8 . . Cement Program Summary 13% 16 o 1600 7000 o 1600 6739 953 2432 461 1389 3632 616 8 8 NA 50 50 35 9% 3% 2100 7544 8896 2100 7304 8656 12 Y. 8% Class "G" 12 275 2.53 1,443 1,800 10.63 Fresh 9% Class "G" 13.5 1236 1.83 1,101 5,000 9.25 Fresh 10 0 60 820 3% Class "G" 15.7 639 1.19 1,526 7,100 4.03 Fresh 24 0 500+ 2,431 Comments: Regulatory Waivers and Special Procedures AOGCC Regulation 20 ACC 25.035 (e) (1) (b) Requirement for 2 pipe rams, one blind ram, and one annular for a API 5K or above BOP stack. Comments: Marathon is requesting a waiver from the above regulation for BC 12. Marathon requests that the BOP stack be configured with one pipe ram instead of two, due to rig height restrictions in the running of the 3 1/2" production casing. The height restriction involves having rig crew members routing control line and electrical line through one of the tubing head outlets after the 3 1/2" casing is cemented and the BOP stack is picked up. This is before setting the casing on slips and cutting the casing sticking up. These lines control firing of the perforating guns and the monitoring of downhole pressure and temperature in our EXCAPE completion system. A similar waiver was requested for an offset well on this pad BC 11 on 1/15/2003 and was granted. No problems were encountered while doing this operation on the above well this year. page 9 . . Hydraulics Summary Rig mud pumps available are shown below. 3 National Oil Well A600PT 5 5 5 8 8 8 2,597 2,597 2,597 2.04 2.04 2.04 175/357 175 I 357 175/357 Surface Intermediate Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. 1 -12 0-2,100 17.5 600 2215 48 9.2 1 - 14 Well plan 2000 Hydraulics 2 - 16's 2,100 -7,544 12.25 600 2,400 3 - 22's Well plan 2000 Hydraulics 60 9.6 1 - 15 7,544 - 8,896 8.5 436 2,000 226 3 - 20's Actual Data from Be #11 Comments: Formation Integrity Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test the BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close the ram pre venter, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. page 10 . . FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA ORAND GAS CONSERVATION COMMISSION David Castillo Senior Drilling Engineer Marathon Oil Company PO Box 196168 Anchorage, AK 99519 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Beaver Creek BC-12 Marathon Oil Company Pennit No: 203-188 Surface Location: 2023' FNL, 482' FEL, Sec. 33, T7N, R10W, SM Bottomhole Location: 1610' FNL, 815' FWL, Sec. 34, T7N, R10W, SM Dear Mr. Castillo: 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 <;>;r THE COMMISSION DATED thisll- day of November, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section e e Alaska Region Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 November 3, 2003 Sarah Palin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 Reference: Replacement Drilling Permit Application Field: Beaver Creek Field Well: Beaver Creek Unit BC-12 Dear Ms. Palin J Enclosed please find a PERMIT TO DRILL application, along with the associated attachments for the Beaver Creek Unit BC-12. Please note that Marathon is requesting a waiver for 20 ACC 25.035 (e) (1) (b) requiring a two pipe ram stack. The requests are specified on page 11 of the attached drilling prognosis. , If you require further information, please contact me. Sincerely, ~R.~ David R. Castillo Senior Drilling Engineer Telephone: 907-564-6465 Email: DRCastìllo@MarathonOil.com OR\GiNAl e \~GA- U/171l.P03 . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 MC 25.005 1a. Type of Work: Drill@ Re-entryD RedrillD 1b. Current Well Class: Stratigraphic TestD ExPloratoryD ServiceD Development Oil D Development Gas@ Multiple zone@ / Single zoneD 2. Operator Name: Marathon Oil Company 3. Address: P.O. Box 196168, Anchorage, AK 99519-6168 4a. Location of Well (Governmental Section): Surface: 2023' FNL, 482' FEL, See 33 T7N R10W, S.M. Top of Productive Horizon: 1610' FNL, 815' FWL. See 34, T7N, R10W. S.M., AK Total Depth: 1610' FNL. 815' FWL. Sec 34, T7N, R10W. S.M., AK 4b. Location of Well (State Base Plane Coordinates): Surface: x- 315319.955' y- ,2433,200.639' Zone- 16. Deviated Wells: Kickoff Depth: 2,500 ft. 18. Casing Program: Size Casing 20" 133/8" 9 5/8" 31/2" 24.4 0 Maximum Hole Angle: Specifications 5. Bond: @Blanket D SingleWellD 11. Well Name and Number: Bond No. 5194234 BC-12 ../ 6. Proposed Depth: MD: 8,896 ft TVD: 8686 ft 7. Property Designation: A-028083 8. Land Use Permit: 12. Field/Pool(s): Beaver Creek I Beluga NIA 9. Acres in Property: 13. Approximate Spud Date: 5/2212004 / 14. Distance to Nearest Property: 3500ft 15. Distance to Nearest Well within Pool: 1,332' (BC-9 Beluga cut point) /" 1560 10. KB elevation 4 (Height Above GL): 171 (21' above GL) 17. Anticipated Pressure (see 20 MC 25.035) feet Max. Downhole Pressure: 4083 Setting Depth Max. Surface Pressure: 3,373 Quantity of Cement cJ. or sacks. (Including Stage Data) psig. psig. Top Bottom Hole Driven Weight 131.45# 68# 40# 9.3# Grade Coupling Length MD TVD MD TVD K-55 PE +1- 100' 0' 0' 100' 100' K-55 BTC 2.100' 0' 0' 2,toO'-- 2,100' L-80 BTC 7,544' 0' 0' /f.544/ 7304' L-80 EUE 8,896' 0' 0' ~6' 8656' PRESENT WELL CONDITION SUMMARY (to be completed for Redrill and Re-Entry Operations) Total Depth TVD (ft.) Plugs (measured) Effective depth MD (ft) Effective Depth TVD(ft): +1-556sks + I - 1,51Z~ks + lðßl<s. ~ 16" 121/4" 8112" 19. Total Depth MD (ft): Casing Length Perforation Depth MD (ft): 20. Attachments: Filing Fee@ BOP Sketch@ Property Plat@ Diverter Sketch@ 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Title Senior Drilling Engineer Printed Name David R. Castillo Signature &~l~ '-3'1 Junk (measured) Size Cement Volume TVD MD Perforation Depth TVD (ft): Drilling Program@ Time v. Depth PlotD Shallow Hazard AnalYSisD Seabed ReportD Drilling Fluid program@ 20 MC 25.050 RequirementsD Date: Contact Phone 907-564-6465 11/3/2003 Date Commission Use Only 1:~1/33: - .:z ò 5 3 ð I~::it Approval 1\' \ 'b o/f¡ Samples required DYes L:8JNO Mud log required DYes Hydrogen sulfide measures DYes ~NO Directional survey required ~Yes "gaPE to tl-t.t~Llh". "'5$00 P(/. Permit to Drill Number: Zo3 - / ~ F Conditions of approval: Other: T -e s t Approved by: I See cover letter for other requirements. ~NO DNo COMMISSIONER BY ORDER OF THE COMMISSION 0" II \ I ( U:mä;" "pi""" ORtGtNAL e e MARATHON MARATHON Oil COMPANY DRilliNG PROGRAM BEAVER CREEK 12 ORIGINAL November 4, 2003 Originator: David R. Castillo Drilling Supervisors: Gene Anderson, Roland Lawson Drilling Superintendent: Peter Berga e e Table of Contents General Well Data..................................................................................... ......................................... ................. ....................1 Geologic Program Summary ................................................ .................... ..................... .......................................................... 1 Summary of Potential Drilling Hazards................................................................................................................................ .. ..2 Formation Evaluation Summary ....................................................................... ..................................................... ..................2 Drilling Program Summary .................................................................................. ... .................................................... .............3 Casing Program....................................................................................................................... ................................................4 Casing Design........................................................................................................................ .................................................4 Maximum Anticipated Surface Pressure........... ................... ............................ .................................. .................. ................. ..4 BOPE Program....................................................................................................................... .................................................6 Wellhead Equipment Summary......................... ............... ......................... ..................... .......... .......... ... ... .............. .................7 Directional Program Summary ......................... ........ ........... ............. .......... ...... ................................. ...... ................ ................7 Directional Surveying Summary... ....................................................................... .................... ......................... ........ ......... ......7 Drilling Fluid Program Summary.............................................................. .......... ....................................................... .... ..........7 Drill ing Fluid Specifications................................................................................................................ ......................................8 Solids Control Equipment....................................................... .................................................................................................8 Cement Program Summary........................................................................................................................ .............................9 Regulatory Waivers and Special Procedures.......................................................................................................................... 9 Hydraulics Summary................................ ........................................................................................ .....................................10 Formation Integrity Test Procedure.............. ........................................................ .......... .................... .......................... .........10 e e General Well Data Beaver Creek 1 Lease/License WBS Code Spud Date API No. Y: 2433200.639 X: 315319.955 Beaver Creek Pad 4 21 ft Ground Level Elev. to MSL 150.1 ft Perm. Datum RKB Field County/Province State I Country Total MD Kenai Borough Alaska 8896 8656 Water Depth NA NA NA Comments: Geologic Program Summary NA DD.03.09540.CAP.DRL May 22, 2004 NA Development Inlet Drilling Glacier 1 Sterling B3 5346.70 5181 1176 4.4 Sandstone Sterling B4 5520.54 5341 2161 8.0 Sandstone Upper Beluga B2 6346.37 6116 2485 to 3479 9.9 Sandstone Lower Beluga B16 7409.42 7169 2522 to 3531 6.7 to 9.3 Sandstone Lower Beluga B 17 7517.42 7277 2553 to 3574 6.7 to 9.4 Sandstone Lower Beluga B18 7603.42 7363 2204 to 3599 6.7 to 9.4 Sandstone Lower Beluga B 19 7655.42 7415 2225 to 3634 5.7 to 9.4 Sandstone Lower Beluga B20 7726.42 7486 2257 to 3686 5.7 to 9.4 Sandstone Lower Beluga B21 7832.42 7592 2288 to 3737 5.7 to 9.4 Sandstone Lower Beluga B23 7936.42 7696 2635 to 3797 5.7 to 9.4 Sandstone Lower Beluga B24 8059.42 7819 2782 to 3895 6.5 to 9.4 Sandstone Lower Beluga B26 8259.42 8019 2810 to 3934 6.7 to 9.4 Sandstone Lower Beluga B27 8339.42 8099 2872 to 4021 6.7 to 9.4 Sandstone Lower Beluga B29 8517.42 8277 2917 to 4083 6.7 to 9.4 Sandstone Lower Beluga B30 8643.42 8403 2485 to 3479 6.7 to 9.4 Sandstone Comments: Surface Location Coordinates From Lease/Block Lines 482 ft FEL 2023 ft FNL of Section 33 Township/Range Township 7-N, Range 10-W Latitude 60· 39' 22.120" N Longitude 151·01'45.595"W UTIyI North (Y) 2433200.639 UTM East(.¡<) 315319.955 Coordinate System NAD27 ASP ZONE 4 'Tole~ance' page 1 Gas I Water Gas I Water Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas q,~ ~ e e Top/L.Beluga LB-19 7655 7304 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 Top/L.Beluga LB-23 7957 7696 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 / Top/L.Beluga LB-30 8664 8403 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 Total Depth 8896 8656 1610 ft FNL, 815 ft FWL, Section 34, T7N, R10W 495.95N 1322.74E Circular - 100 Comments: Summary of Potential Drillina Hazards Hazard Event Discussion The Sterling B-3 sands are approximately 1147 psig and 400 md perm. The Lower Beluga intervals have SBHP's that range from a 0.31-.46 psilft. Control losses by using sufficiently sized LCM. See comment above about the Sterling B-3 and the Lower Beluga intervals. Keep the drill pipe moving and avoid if possible excess overbalance. Maintain low fluid loss and thin impermeable filter cake. Circulate hole clean Lost Circulation / Differential Sticking ./ Swabbing Comments: Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands will be encountered from +1- 5,288 ft MD RKB (5,111 ft TVD RKB) to total depth of the well. These sands will run from normal pressured to severely depleted and lost circulation and differential sticking are potential hazards. The FloPro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. No well interference hazards exist. Formation Evaluation Summary Interval LWD Surface None o ft - 2,100 ft MD Intermediate None 2,100 ft-7,544 ft MD Production None 7,544 ft - 8,896 ft MD Completion NIA Electric Logs Mud Logs None None None Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Triple combo (PEX), Digital Sonic (DSI), CMR Plus', MDT' GR, CCL NIA * Log run if borehole conditions allow Coring Requirements: None Comments: page 2 e e Drilling Proqram Summary CONDUCTOR: 1. Drive 20" conductor to +/-100 ft. RKB. 2. Move in and rig up Glacier #1 rotary drilling rig. 3. Install starting head 20" SOW x 21 1/4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. 5. Function test diverter and diverter valve. / SURFACE: 1. Drill a 16" hole to 2,100 ft MD (2,300' TVD) with Spud Mud. 2. RIH with 133/8" casing and hang off in the slips. Make up stab-in sub and centralizer on 4" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 3/8" casing. Sting out and circulate drill pipe clean. TOOH with inner string. 3. PU 133/8" casing, set casing slips in 20", cut off 13 3/8", ND diverter. .,/ 4. Install 13 3/8" slip lock connection X 13 %" 5M flanged multi bowl wellhead. 5. NU 13 %" 5M BOP'S. Test BOP'S and choke manifold to 25012,OOtrpsi. 6. Set wear bushing. 3 soo 7. Test surface casing to 2,000 psi. 8. INTERMEDIATE: 1. Drill out float equipment and make 20' of new hole. 2. Displace spud mud with FloPro. Circulate mud until mud weight in equals mud weight out. / 9. Test shoe to leak-off. Estimated EMW is 14.6 ppg. 10. Drill 12 1/4" directional hole to 7,544 ft MD (7,304 ft TVD) as per directional plan. 11. Make wiper trip. / 3. Change out variable pipe rams with 9 %" casing rams. Run test plug and test casing rams to..3,.Q86'psi. 4. Run and cement 9 %" casing. Land hanger in multibowl wellhead. 1~OO/ /' 5. Back out landing joint. Change out 9 %" casing rams with variable pipe rams. Run test plug and test pipe rams to 250L3,.OOO- psi. 3~oo 6. Set wear bushing. Test casing to 3,000 psi. vJ6A- PRODUCTION: 1. Drill float equipment and 20' of new formation w/ 8 Y:.," bit. Circulate mud until mud weight in equals mud weight out.. 2. Test shoe to leak off. Estimated EMW 15.8 ppg. 3. Drill a 8 Y:.," hole to 8896 ft MD RKB (8656 ft TVD) per the directional program. /' 4. TOOH. RU logging company. Run open hole logs as per plan. RD logging company. 5. TIH to TD for wiper trip. TOOH and lay-down BHA and drill pipe. Pull the wear bushing. 6. Run 3 Y:.," EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD logging company. 7. Cement 3 )12" casing while reciprocating. Bump plug with 500 psi over displacement pressure. wac. 8. PU 3 Y:.," casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 3 Y:.," casing. 9. LD BOP. Set 3 Y:.," packoff. NU 13 %" 5M X 3 Ya" 5M tubing head adapter and 3 Ya" 5M tree. Test tree to 5,000 psi. 10. Rig down and move out drilling rig. / Note: Perforating guns will be run on the outside of the 3 Y:.," production casing with a flapper valve just below each perforating gun. Guns to be activated by control line to surface. COMPLETION: Completion will be done without a rig. page 3 e e Casina Proaram 20 Surface 100 130.1 K-55 18.873 18.543 Driven 3056 1496 2125 13 % Surface 2100 68 K-55 12.415 12.259 BTC 14.375 Diamond 16 3454 1949 1069 9% Surface 7544 40 L-80 8.835 8.75 BTC 10.625 Diamond 12 y. 5745 3087 916 3% Surface 8896 9.3 L-80 2.992 2.867 8rd 4.5 3,200 8.5 10,160 10,530 207 Comments: Casina Desian 20 130.1 K-55 100 NIA 12.97 8.40 89 37.44 21.63 16.63 13% 68 K-55 2100 9.0 14.59 8.40 1437 2.20 1.49 4.14 /' 9% 40 L-80 7544 9.6 15.64 9.40 2338 1.32 1.12 2.58 3% 9.3 L-80 8896 9.6 15.80 9.43 3373 1.14 2.11 1.62 Comments: Maximum Anticipated Suñace Pressure 13% 9% 2100 7304 2676 4371 1437 2339 3375 / 0/100 70/30 0/100 3 % 8650 5000 * MAWP = Maximum Allowable Working Pressure. ** MASP = Maximum anticipated surface pressure page 4 e Comments: MASP calculated as the lesser of MASPfrac and MASPbhp 13 3/8 inch Surface Casinq SF := O.s.ppg TVDShoe:= 2100·ft psi P gas := 0.1.[; TVDOH := 7304·ft FG := 14.6·ppg MASP frac:= (FG + SF).TVDShoe- (Pgas·TVDShoe) MASP frac = 1437psi pSI BHP := 0.49·-· TVDOH P . 9 6 ppg ft mud·= . . MASPbhp:= BHP - (Fmud·TVDOH·Pmud) - [( 1- Fmud)·TVDOH"PgaJ MASPbhp = 1975psi 9 5/8" Intermediate Casinq SF := O· 5ppg TVDShoe:= 7304·ft TVDOH := 8656· ft FG := 15.64·ppg pSI P gas := 0.1.[; F mud := 30% MASP frac := (FG + SF)· TVDShoe - (p gas· TVDShoe) MASP frac = 5204psi BHP := 9.43·ppg·TVDOH BHP = 4240psi MASPbhp := BHP - (Fmud·TVDOH·Pmud) - (1- Fmud)·TVDOH·Pgas MASPbhp = 2339psi page 5 e F mud := 30% Pmud := 9.60·ppg e 3 1/2" Production Casinq TVDShoe:= 8656· ft pSI BRP:= 9.43·ppg·TVDShoe Pgas:= O.l·ft MASPbhp:= BRP - TVDOKPgas MASPbhp = 3375psi BOPE Proaram ./ e Surface 2,000 13% 2676 1,437 Intermediate 9% 4371 2,339 2,000 Production 2,000 3% 5000 3,375 Comments: Blowout Preventers 9.0 (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets 25G 35",,0 . ,.r::-::! 250~{ ~ÇÐO ~6Æ- 250/3500 7 9.6 9.6 /' The blowo~preventer stack will consi~f a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-118" x 5000 psi outlets. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. page 6 N<J t»ø4VfH" YI.U.e<'Ç.CLrl j d~ ~~ P t-L?<;. ycJ:1,¡ <é SoOO I"~ e e Wellhead Equipment Summary Component Description Casing Hanger Type 13 %" x 9 %" Fluted Mandrel 13 %" x 3 Y2" Manual Slip Casing Head 13-%" 3M X 13-3/8" Slip Loc WI 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL 1, PR1 Tubing Head 13-%" 3M Studded Bottom X 13-%" 5M Fig Top, WI 2, 2-1/16" 5M Studded Outlets, U,AA,PSL 1,PR1 Adapter Flange 13-%" 5M X 3- Yo" 5M WI Seal Pocket and 3" H BPV Threads Comments: Directional ProQram Summary KOP 2,500.00 2,500.00 0 0 0 0 0 0 0 3 End of Build 3,650.89 3,620.18 2.0 0 /~.o 23.02 69.22 N 217.33 E 228.09 4- End of Hold 5,771.03 5571.52 0 0 0 23.02 72.33 320.81 N 1007.24 E 1057.10 End of Drop 7305.55 7065.10 -1.5 0 -1.5 0 72.33 413.11 N 1297.01 E 1361.21 TO 8896.55 8656.10 0 0 0 0 72.33 413.11 N 1297.01 E 1361.21 Comments: Directional SurvevinQ Summary Interval MD o ft - 2,100 ft 2,100 ft - 7,676 7,676 ft - 8,656 ft MWD Survey X X X Magnetic Multishot Gyro Multishot Comments Comments: DrillinQ Fluid ProQram Summary 0 2,100 8.6 - 9.2 2,100 5000 9.0 - 9.4 5000 7655 9.& 7655 8896 9.2 - 9.4 Comments: Gel I Gelex Spud Mud Gel, Gelex, Soda Ash, Caustic, Barite, Polypac Supreme UL Flo-Vis, PoluPac UL, KCI, SafeCarb F, Ventrol 401, Barite, Caustic, Conqor 404, SafeScav NA Flo-Pro wI 6% KCL + Safecarb Flo-Pro wI 6% + Safecarb Flo-Vis, DualFlo, KCI, Greencide 25G, SafeCarb F&M, Barite, Caustic, Conqor 404, SafeScav NA page 7 e e Drilling Fluid Specifications 0 2100 8.6-9.4 60-100 25-35 NC-12 ±9.5 2100 5000 9.0-9.4 8-12 40,000 7-9 ± 9.5 ±5% 5000 7655 9.4-9.6 10-14 40,000 7-9 ±9.5 ±8% 7655 8896 9.2-9.6 ./ 10-14 40,000 <6 ±9.5 ±5% Comments: Solids Control Equipment O-TD x x x x Closed Loop System, Full Containment 1 - Derrick Model 0522 / NIA 2 - MIISwaco units / NIA Marathon G&I Facility NIA Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. page 8 e e Cement ProQram Summary 13% ~ de 9 % 'lS l . 12 Y. 1600 2432 3632 8 50 3 Y:z 896 8Y:z 6739 ,461 616 NA 35 1100 W6k' (,,'lo 838 3Y:z Class "G" 12 275 2.53 1 ,443 !? 10.63 Fresh 135 æ 183 1,101 ,000 9.25 Fresh 10 0 60 820 15.7 1.19 1,526 .2,.Q96'" 4.03 Fresh 24 0 500+ 2,431 704 ~ ~ VJú/t" 1100 1 L- ~ '" L-l ç ~/ . (5 I I 9% Class "G" Comments: ReQulatorv Waivers and Special Procedures AOGCC Regulation 20 ACC 25.035 (e) (1) (b) Requirement for 2 pipe rams, one blind ram, and one annular for a API 5K or above BOP stack. Comments: Marathon is requesting a waiver from the above regulation for BC 12. Marathon requests that the BOP stack be configured with one pipe ram instead of two, due to rig height restrictions in the running of the 3 1/2" production casing. The height restriction involves having rig crew members routing control line and electrical line through one of the tubing ,...-- head outlets after the 31/2" casing is cemented and the BOP stack is picked up. This is before setting the casing on slips and cutting the casing sticking up. These lines control firing of the perforating guns and the monitoring of downhole pressure and temperature in our EXCAPE completion system. ~ A similar waiver was requested for an offset well on this pad BC 11 on 1/15/2003 and was granted. No problems were encountered while doing this operation on the above well this year. NO w~'ljw ~,"I...f(.f\ - ~ p,' page 9 e e Hvdraulics Summary Rig mud pumps available are shown below. 3 National Oil Well A600PT 5 5 5 8 8 8 2,597 2,597 2,597 2.04 2.04 2.04 175/357 175/357 175/357 Surface Intermediate Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. 1 -12 0-2,100 17.5 550 1,900 48 1 - 14 Actual Data from Be #11 2 - 16'5 2,300 -7,544 12.25 545 2,000 3 - 22's Actual Data from Be #11 107 1 - 15 7,544 - 8,896 8.5 436 2,000 226 3 - 20's Actual Data from Be #11 Comments: Formation Intearitv Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test the BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close the ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. page 10 e 121 1/4" 2M Diverter 1-. 1 Diverter Spool "> I I" . Marathon Oil Well BC-12 Diverter Flow line ~ I I ,/ '" e ....- 116" Automatic Knife Valve BI,- ,/ I I..... \- " I I í \ '--~ 116" Diverter Line e I Flow Nipple I 1135/8" 5M Annular I Pre venter .. ") I I > 13 5/8" 5M Double Ram Preventer Ie ------. I 21/16"5M Ie Check Valve I 21/16" 5M Manually I \ opera~e~s : > [[[][]]I@I!III@1IJ] I:E!L~ ~i, 113 5/8" 5M Cross I '\ ~ Marathon Oil Well BC-12 BOP Stack / I J < IPipe Ram I I Blind Ram I < I I e I Flow Line I I / 31/8" 5M Manually Operated Valve ~ /' / ~ I 3 1/8" 5M Manually Operated Valve I I í t 3 1/8" 5M Hydraulically Operated Valve e Marathon Oil Well BC-12 Choke Manifold e ITO Gas Buster IT 0 Blooey Line I I Bleed off Line to Shakers ~ ~ ~ ç::=::;1 ç::=::;1 ç::=::;1 ~J [ ~J [~ 000 t==J t==J t==J C ~ ~ ~ ~ ~ ~ r;::==:J '-----' rn@aII@[~[I@[I] , J ~ /3" 5M Valves i t 2 9/16" 10M Swaco 0 131/8" 5M Manually Hydraulically Operated Adjustable Choke Choke From BOP Stack e e Surface Use Plan for Beaver Creek #12 Surface location: Anticipated at 2023 ft FNL, 482 ft FEL, Sec. 33, T7N, R10W, S.M. 1) Existing Roads Existing roads, which will be used for access to Beaver Creek #12, are shown on the attached map. Kenai, Alaska is the nearest town to the site and is shown on the map. 2) Access Roads to be Constructed or Reconstructed No new roads will be required to access Beaver Creek #12. 3) Location of existing wells Well BC-12 will be drilled on pad BC 4. A pad drawing is enclosed that shows existing wells and the proposed location of BC-12. 4) Location of existing and/or proposed facilities The locations of existing production facilities are shown on the enclosed pad drawing. These facilities will be upgraded to handle the additional gas production. 5) Location of Water Supply A water supply well exists on the Beaver Creek Pad 3. Water will be pipe from the water well on pad 3 to the Beaver Creek #12 location. 6) Construction Materials No construction is planned on the pad. If the pad requires minor leveling, the sand and gravel will be obtained from the approved gravel pit in the SW/4, NE/4, Sec. 5 T6N, R10W, S.M. Other materials will be obtained from various vendors and suppliers in Alaska. 7) Methods of handling waste disposal; a) Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to / Pad 41-18 of the Kenai Gas Field for disposal into Well KU 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Clear fluids will be injected into approved disposal wells Beaver Creek # 2 (Alaska Oil and Gas Conservation Commission Disposal Injection Order No.4) or hauled to Pad 34- 31 of the Kenai Gas field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). e e d) Chemicals Unused chemicals will be returned to the vendors that provided them. Efforts will be made to minimize the use of all chemicals. e) Sewage Sewage will be hauled to the Kenai sanitation facility. 8) Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. Sand R will collect and transport sanitary wastes to their ADEC approved disposal facility. 9) Plans for reclamation of the surface Beaver Creek #12 will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of Beaver Creek #12 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from the U.S. Fish and Wildlife Service before any reclamation work beginning. 10) Surface ownership The surface owner of the land in the Beaver Creek Unit is the U.S. Fish and Wildlife Service. The minerals are under the jurisdiction of the U.S. Bureau of Land Management. 11) Operator's Representative and Certification 1 hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that I am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: "/3I2(J~ f ~ Name and Title: David R. Castillo, Senior Drilling Engineer Marathon Oil Company P.O. Box 196168 Anchorage, Alaska 99519-6168 (907) 564-6319 II ABBREVlA TlONS: \\.. O,H.E. = OVERHEAD ELECTRIC ~ OH. P/W = OVERHEAD PIPEWAY ¿; :::E IS S; '" ! ~ ¡¡¡ :::E :>: '" S ~ :r <> § . . ~ ~ ~ z ~ .., ~ - õ i 2+' N:Æ:SS RO. i- .i ~ê~ ~~ ~:a... ;'f\\li II~ r L' ~~ Y 2,432,800.00 8 § .; ;;¡ ... ~ ~. .¡~ =¡.a 4 ;~g~f I ~m· "~?i . ui ~ o~, Q ~. ~~~:a r~ .~ J J y 2.4.J2.iOO.oo e , Y 2_00 8 I ;;¡ ... . SECTION 33 T7N R10W SM AI< ~! " ;;! ~~~ . j I BCU NO. + ~/2.~Ja.s:f ~XJfG,17ua w~ ~ 'ª ~ :-s a£V.148' % S$4' ro. ..tH 1ð4O"F'I'fL ~~ ¡;i ~~h;1 i;;§jV _8 ~ 00'" ! 18 11OH} ~ ~ ¡ .. rN' Y 2,+33,4OQ.00 8 ! ¡;; ... op{ ~ lID. . . c; 0 21 c¡¡ &-~ Z1 _ #7~ ) Yi~ 33 3+ '.ltt PAD NO. 1 ~ ~ ~PAD NO. 2~' 'Pf~7 ~~ 0::) 20 . .~ 10 11 ~ ¡¡¡ IIICINITY MAP l' - 2 M1LES SCALE: 1" = 100' if LEGEND ~ tIt GlO/SlM MONUMENT FOUND THIS SURVEY 0 FOUND r REBAR wi ALCAP . SET r REBAR WI ALCAP 0 FOUND SURVEY MONUMENT OF RECORD -ct POWER POLE 1) LIGHT POLE @ EXISTING WELL CHRISTMAS TREE ~ MONITOR WELL 1><1 VALVE -0 PIPING CONTINUES UNDERGROUND QJ ELECTRICAL JUNCTION BOX ~ !1 SEPTIC VENT ¿; if NOTES ~ 1. ELEVATIONS AT THE TOP OF PIPES FOR MONITORING WELLS TAKEN WITH COVER OFF OR OPEN. 2. REFERENCE DATUM IS NAVD 88 FOR ELEVATIONS SHOWN BASED ON NGS MONUMENT D 81. 3. ALL BEARINGS ARE GRID UNLESS NOTED OTHERWISE. 4. BASIS OF COORDINATES IS CONTINUOUSLY OPERATING REFERENCE STATION KEN 1, IN A.S.P. ZONE 4. (NAD 27) 5. KEN 1 LOCATION: LAT: 60'40'32.315"N LONG: 151'20'52.519"W X = 258,310.40 Y = 2,441,360.73 ( > >D >D ( > [J\ " « « z l- t! t! oJ C [1} III >D V X C lD o 11 C>... :J <::. S- \..I"" 'V\ .!:: ~ -+> .- \I) ~ ~ ~ I- ~ <::. \J ~ IJ1 >D N '" '" <D N t- o [J\ x 11 tD N V '" <D N " o [J\ oJ '" f- > ~ I Z Q 2 <C<C ~ D. D. >- ~ :e W- en > o <C DC: ;¡ U 'ft :) .!. V U) 0 ::!~t-g OW = S Z W :) ~ a= CO ¡¡: o C.) fñ- % c ...a= QS ~ W C ~ > D. 5 <C à <C W ~ :em ~ (i.· : ~ ~ ~ Q !! -< o ~ or > '" ~ Q. S ~ i !!! ~ S w or ..... 15 i3 ... ~ ~ -(!jBCU10 IICU 11 acu g o 8CU 8 BCU Ii BCU 3 e VICINITY MAP o . BOOO SCALE IN FEET N PRODUCTION PAD - BCU .. 0 SEC. 33 Marathon 011 Company Road -. \ ~c'" ~~~ SEC. .. ¿cu, PAD 7 PURPOSE: ORtLL & COMPLETE BCU 12 ADJACENT PROPERTY OWNERS PLAN VIEW o . 1000 SCALE IN FEET 2000 I KENA'I NATIONAL WILDLIFE REFUGE MARATHON OIL COMPANY P.O. BOX 190188 ANCHORAGE. AK. 9951·9 e SEC 34 T7N R 10W SM Drlllalt. , ~. PAD 3 SEC. 34 BEAVER LAKE PAD 2 SEC. 3 PROPOSED LOCATION FOR BCU 12 ON: PAD 4 AT: 8EAVER CREEK PRODUCTION FACILITY IN: PAD 4 KENAI PENINSULA 80UROUGH. AK. APPLlCA TION BY: MARATHON OIL COMPANY f¡;-'- . -~oò y. :t'~~;,\l~~:' 60~30' . I' FEET ' S' I .OLDDTNA 'M 151·07'30" 300000 HOMER 7. M( ).) Mapped; edited, and published by the Geological Survey Control by USCE Topography by photoflrammetrlc methods from aerial photo¡¡raphs . taken 1950, Cuture revised in part from aerial photographs . Field annotated 1980, Map not field checked Projection and lOOO-meter grid ticks: Universal Transverse Mercator, zone 4 1O,OOO-foot grid ticks based on Alaska coordinate system, zone 5; ·1927 North American datum G;ay land lines represerit unsurveyed and unmarked locations . p·redetermined by the Bureau of Land Management Folio s- 16, Seward Meridian. ,swamps,· as portrayed. indicate only the wetter areas, usually of low relief, as interpreted from aerial photographs To place on the predicted North American Datum 1983 move the projection lines 67 meters north and 121 meters east There may be private inholdlngs within the boundaries of the. National or State reservations shown on this map ., u~, I \l~ . \(" :;" .!t\;"¡ . i / ~ ,': ,..li.- ", .' ":<::~::""\\. .. 3:£.,<., .,. .._.....;..~;;.,J.. T. 7 N. .......:~. .:."...."... T. 6 N. "1 6 13 "H'~"""'''''~''''-: ~.. )~)::·7-"·· . ...:\:. .... ..,.·ff~" . .... ". ~~i Y4· )¡.~ .,:" ;.. . "::è ..... ...;;... -'f ..¡;;¡ ..... .... .".;1:'9. .,'.. . . (::,::~'i ~.;.:'..~ ::H:<{~". 4 ~ T. 5 N. * -! o SCALE ·1:63~60 _.~. . ·';;.c~~ _. _ " , ndin¡ Slrlp . . .': fl.. í 5- . e· f~;i-" :4' - .21 NILS Z MILS 3000 3000 sooo 1000 4 MILES ·12000 ISOOQ 18000 21000 FEET .1 --....... - -_.- 5 ~ILOMETERS urN GRID AND 1110 MAGNETIC HORTH OECLINATlON AT'eENTER 0' SHUT CONTOUR INTERVAL SO FEET DOTTED UNES REPRES£HT 25·FOOT coÑToURS NATIOHAI. GECIOETIC VERTICAl.' DATUM OF 1828 . ~AlASKA . . . . '¡'J.., . "'1' ........ . FOR SAlE BY U. S. GEOLOGICAL SURVEY FAIRBANKS; AlASKA 99701, DENVER, COLORADO 80225, OR RESTON, VIRGINIA 22092 A ~ DESCRIBING TOPOGRAPHIC' MAPS AND SYMBOLS IS AVAILABLE ON REQUEST QUADRANGLE LOCATION BEAVER CREEK UNIT \ 32 ~ ;; I I 5 ? I :Q3 40 59 20 W Proved Productive Area 2003 Well I I Unproved Productive Area 1:12000 ALASKA BUSINESS UNIT LOWER BELUGA TOP '" r-<r 14....... I I t I L________ I I I I I I I I I I t .....--......, 1/¡'CDlJ(]\'" ¡IIEGASSER) ,\ / I . I ....-- . ~-----i ~-----l~ r ~__.J u : 1 I I I I , I , 1 I I I I I I I- r-----' I I I I I:ENTR1FUiE) I UNIT I I 4' X 10' I , I I , I I I , DlI4P I t t-' I t '-~ I I I 1.._____.1 1 KCOKY 3' X 12' /1\11'/11 , t I : ,.--, " I r I II I I II I I . I II I ill I II t t I II I I II I 'I 11 I :IS I·: ~ u ¡ a I I I!i II L__=_.J '-_____.J r---,. ---,.-' I I -\" -\' I I , ~ ... , I ]519 6 X '5 11· c ~~¿ 2 ... .. ... ..... .. - . re \... . .~ ... 11IUH ]519 6 X '5 U' GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT \.. f'....... 7S HP 6 X :5 U' t ;'; _,i .. , r .. . . rTiiI ~ . ~.... 7519 6 (, 11' --" ~. ..t I ., .. -. ), !L . o ... .. 5\1 9L IHáOO PT .. IU. Min1II1R --, :¡\o' 9L A-6OO PT - -ill . . T ~..," . . __PLL m >< ...... t- c£ .... :x: ~~ :::1:' 14·... , I I I I I , I I I I I I I , I I I e II mA 3¡,S- . .rrA_~ 13'-iI" ~ ., Qr::..1 e ~~..~ e e MARATHON Oil Company Pad #4 BC-12 slot #12 Beaver Creek Unit Kenai Peninsula, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License BC-12 Ver prop5537 Date printed Date created Last revised 30-0ct-2003 3-0ct-2003 30-0ct-2003 Field is centred on n60 38 50.050,w150 59 49.92 Structure is centred on n60 38 50.050,w150 59 49.92 Slot location is n60 39 22.120,w151 1 45.595 Slot Grid coordinates are N 2433200.639, E 315319.955 Slot local coordinates are 3258.04 N 5765.79 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North e MARATHON Oil Company Pad #4,BC-12 Beaver Creek Unit, Kenai Peninsula, Alaska Measured Inclin Depth Degrees 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2600.00 2700.00 2800.00 2900.00 3000.00 3100.00 3200.00 3300.00 3400.00 10.00 12.00 14.00 16.00 18.00 3500.00 3600.00 3650.89 4000.00 4280.87 20.00 22.00 23.02 23.02 23.02 4500.00 5000.00 5271. 54 5500.00 5771.03 23.02 23.02 23.02 23.02 23.02 5805.55 5905.55 6005.55 6105.55 6138.16 22.50 21.00 19.50 18.00 17.51 6205.55 6305.55 6405.55 6505.55 6605.55 16.50 15.00 13 .50 12.00 10.50 6705.55 6805.55 6905.55 7005.55 7105.55 7205.55 7305.55 7400.45 7500.00 7507.25 7655.55 7700.00 7800.00 7900.00 7936.55 Azimuth Degrees 0.00 0.00 0.00 0.00 0.00 72 .33 72 .33 72 .33 72 .33 72 .33 True Vert Depth 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2599.98 2699.84 2799.45 2898.70 2997.47 3095.62 3193.06 3289.64 3385.27 3479.82 3573.17 3620.18 3941. 50 4200.00 4401.69 4861.88 5111. 80 5322.07 5571. 52 5603.36 5696.24 5790.05 5884.74 5915.80 5980.24 6076.48 6173.40 6270.94 6369.01 6467.56 6566.53 6665.83 6765.41 6865.19 6965.11 7065.10 7160.00 7259.55 7266.80 7415.10 7459.55 7559.55 7659.55 7696.10 e PROPOSAL LISTING Page 1 Your ref BC-12 Ver 4 Last revised 30-0ct-2003 R E C TAN G U L A R COO R DIN ATE S Dogleg Vert Deg/lOOft Sect O.OON O.OON O.OON O.OON O.OON O.OON 0.53N 2.12N 4.76N 8.46N 13.21N 19.00N 25.83N 33.68N 42.55N 52.43N 63.31N 69.22N 110.65N 143.98N 169.98N 229.32N 261. 54N 288.65N 320.81N 324.87N 336.11N 346.62N 356.37N 359.39N 365.37N 373.61N 381. 08N 387.78N 393.70N 398.84N 403.19N 406.76N 409.54N 411. 52N 412.71N 413.11N 413.11N 413.11N 413.11N 413.11N 413.11N 413.11N 413.11N 413.11N O.OOE O.OOE O.OOE O.OOE O.OOE O.OOE 1. 66E 6.65E 14.95E 26.56E 41. 47E 59.65E 81. 08E 105.74E 133.60E 164.62E 198.76E 217.33E 347.40E 452.04E 533.69E 719.97E 821.14E 906.26E 1007.24E 1019.97E 1055.27E 1088.25E 1118.88E 1128.35E 1147.13E 1173.00E 1196.45E 1217.48E 1236.07E 1252.20E 1265.87E 1277.07E 1285.79E 1292.02E 1295.76E 1297.01E 1297.01E 1297.01E 1297.01E 1297.01E 1297.01E 1297.01E 1297.01E 1297.01E 0.00 0.00 0.00 0.00 0.00 0.00 2.00 2.00 2.00 2.00 0.00 1. 75 6.98 15.69 27.88 G RID Easting 0.00 0.00 0.00 0.00 0.00 315319.95 315319.95 315319.95 315319.95 315319.95 COORDS Northing 2433200.64 2433200.64 2433200.64 2433200.64 2433200.64 2433200.64 2433201.14 2433202.66 2433205.17 2433208.70 2433213.22 2433218.73 2433225.23 2433232.71 2433241.16 2433250.57 2433260.92 2433266.55 2433306.00 2433337.74 2433362.50 2433418.99 2433449.68 2433475.49 2433506.12 2433509.98 2433520.68 2433530.69 2433539.98 2433542.85 2433548.54 2433556.39 2433563.50 2433569.88 2433575.52 2433580.41 2433584.56 2433587.95 2433590.60 2433592.49 2433593.62 2433594.00 2433594.00 2433594.00 2433594.00 2433594.00 2433594.00 2433594.00 2433594.00 2433594.00 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #12 and TVD from Est RKB (Glacier 1) (171.10 Ft above mean sea level). Bottom hole distance is 1361.21 on azimuth 72.33 degrees from wellhead. Total Dogleg for wellpath is 46.04 degrees. Vertical section is from N 0.00 E 0.00 on azimuth 72.33 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ 0.00 2.00 4.00 6.00 8.00 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72.33 72 .33 72 .33 72.33 72 .33 72 .33 72 .33 72 .33 72.33 72.33 72.33 72.33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 9.00 7.50 6.00 4.50 3.00 72 .33 72 .33 72 .33 72 .33 72 .33 1.50 0.00 0.00 0.00 0.00 72 .33 72 .33 72 .33 72 .33 72 .33 0.00 0.00 0.00 0.00 0.00 72.33 270.00 270.00 270.00 270.00 2.00 2.00 2.00 2.00 2.00 43.52 62.60 85.10 110.98 140.21 2.00 2.00 2.00 0.00 0.00 172.77 208.60 228.09 364.59 474.42 0.00 0.00 0.00 0.00 0.00 560.10 755.61 861.79 951.12 1057.10 1.50 1.50 1.50 1.50 1.50 1070.45 1107.51 1142.12 1174.26 1184.21 1.50 1.50 1.50 1.50 1.50 1203.91 1231. 06 1255.67 1277.74 1297.25 1. 50 1.50 1. 50 1. 50 1. 50 1314.18 1328.53 1340.29 1349.44 1355.98 1.50 1. 50 0.00 0.00 0.00 1359.90 1361. 21 1361. 21 1361. 21 1361. 21 0.00 0.00 0.00 0.00 0.00 1361. 21 1361. 21 1361. 21 1361. 21 1361. 21 315319.95 315321.63 315326.63 315334.98 315346.64 315361.62 315379.88 315401.41 315426.19 315454.18 315485.34 315519.64 315538.29 315668.97 315774.10 315856.12 316043.28 316144.92 316230.43 316331.88 316344.67 316380.14 316413.27 316444.04 316453.56 316472.42 316498.41 316521.97 316543.10 316561.77 316577.98 316591.72 316602.97 316611.73 316617.99 316621. 75 316623.00 316623.00 316623.00 316623.00 316623.00 316623.00 316623.00 316623.00 316623.00 e e MARATHON Oil Company PROPOSAL LISTING Page 2 Pad #4,BC-12 Your ref BC-12 Ver 4 Beaver Creek Unit, Kenai Peninsula, Alaska Last revised 30-0ct-2003 Measured Inclin Azimuth True Vert R E C T A N G U L A R Dogleg Vert G RID C o 0 R D S Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/100ft Sect Easting Northing 8000.00 0.00 270.00 7759.55 413.11N 1297.01E 0.00 1361. 21 316623.00 2433594.00 8500.00 0.00 270.00 8259.55 413.11N 1297.01E 0.00 1361. 21 316623.00 2433594.00 8643.55 0.00 270.00 8403.10 413.11N 1297.01E 0.00 1361. 21 316623.00 2433594.00 8896.55 0.00 270.00 8656.10 413.11N 1297.01E 0.00 1361. 21 316623.00 2433594.00 All data in feet unless otherwise stated. Calculation uses ffilTIlffiUm curvature method. Coordinates from slot #12 and TVD from Est RKB (Glacier 1) (171.10 Ft above mean sea level Bottom hole distance is 1361.21 on azimuth 72.33 degrees from wellhead. Total Dogleg for wellpath is 46.04 degrees. Vertical section is from N 0.00 E 0.00 on azimuth 72.33 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad H,BC-12 Beaver Creek Unit, Kenai Peninsula, Alaska Comments in wellpath ---~~~-~------------ -------------------- MD TVD Rectangular Coords. Comment ----------------------------------------------------------------------------------------------------------- e PROPOSAL LISTING Page 3 Your ref BC-12 Ver 4 Last revised : 30-0ct-2003 2500.00 2500.00 O.OON O.OOE KOP 3650.89 3620.18 69.22N 217.33E EOC 4280.87 4200.00 143.98N 452.04E T/ Coal Beds 5271.54 5111. 80 261. 54N 821.14E Sterling B-3 5771.03 5571. 52 320.81N 1007.24E End of Hold 6138.16 5915.80 359.39N 1128.35E Top Beluga 7305.55 7065.10 413.11N 1297.01E End of Drop 7400.45 7160.00 413.11N 1297.01E B/Cnglmrt T/Tyonek 7507.25 7266.80 413.11N 1297.01E B/Mid Beluga 7655.55 7415.10 413.11N 1297.01E BC12-T/L Beluga19-Rvsd290ct03 7936.55 7696.10 413.11N 1297.01E BC12-T/L Be1uga23-Rvsd290ct03 8643.55 8403.10 413.11N 1297.01E BC12-T/L Be1uga19-Rvsd290ct03 8896.55 8656.10 413.11N 1297.01E TD Casing positions in string 'A' ---------------~~------------- ------------------------------ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing ----------------------------------------------------------------------------------------------------------- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 O.OON O.OON O.OON O.OON O.OOE O.OOE O.OOE O.OOE 100.00 2100.00 7544.45 8896.45 100.00 2100.00 7304.00 8656.00 O.OON O.OON 413.11N 413.11N O.OOE O.OOE 1297.01E 1297.01E 20 Conductor 13 3/8 Casing 9 5/8 Casing 3 1/2 Liner Target name T.V.D. Targets associated with this wellpath Revised --------------------~~------------~-- ------------------------------------- Geographic Location Rectangular Coordinates ----------------------------------------------------------------------------------------------------------- BC12-T/L Beluga19-Rv 316623.000,2433594.000,0.0000 BC12-T/L Beluga23-Rv 316623.000,2433594.000,0.0000 BC12-T/L Beluga19-Rv 316623.000,2433594.000,0.0000 7415.10 7696.10 8403.10 413.11N 413.11N 413.11N 1297.01E 1297.01E 1297. DIE 3-0ct-2003 3-0ct-2003 3-0ct-2003 e e MARATHON Oil Company Pad #4 BC-12 slot #12 Beaver Creek Unit Kenai Peninsula, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License BC-12 Ver prop5537 Date printed Date created Last revised 30-0ct-2003 3-0ct-2003 30-0ct-2003 Field is centred on n60 38 50.050,w150 59 49.92 Structure is centred on n60 38 50.050,w150 59 49.92 Slot location is n60 39 22.120,w151 1 45.595 Slot Grid coordinates are N 2433200.639, E 315319.955 Slot local coordinates are 3258.04 N 5765.79 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North e MARATHON Oil Company Pad #4,BC-12 Beaver Creek unit,Kenai Peninsula, Alaska Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2600.00 2700.00 2800.00 2900.00 3000.00 3100.00 3200.00 3300.00 3400.00 10.00 12.00 14.00 16.00 18.00 3500.00 3600.00 3650.89 4000.00 4280.87 20.00 22.00 23.02 23.02 23.02 4500.00 5000.00 5271. 54 5500.00 5771.03 23.02 23.02 23.02 23.02 23.02 5805.55 5905.55 6005.55 6105.55 6138.16 22.50 21. 00 19.50 18.00 17 .51 6205.55 6305.55 6405.55 6505.55 6605.55 16.50 15.00 13 .50 12.00 10.50 6705.55 6805.55 6905.55 7005.55 7105.55 7205.55 7305.55 7400.45 7500.00 7507.25 7655.55 7700.00 7800.00 7900.00 7936.55 0.00 0.00 0.00 0.00 0.00 72 .33 72 .33 72 .33 72 .33 72 .33 0.00 500.00 1000.00 1500.00 2000.00 2500.00 2599.98 2699.84 2799.45 2898.70 2997.47 3095.62 3193.06 3289.64 3385.27 3479.82 3573.17 3620.18 3941.50 4200.00 4401.69 4861.88 5111.80 5322.07 5571. 52 5603.36 5696.24 5790.05 5884.74 5915.80 5980.24 6076.48 6173.40 6270.94 6369.01 6467.56 6566.53 6665.83 6765.41 6865.19 6965.11 7065.10 7160.00 7259.55 7266.80 7415.10 7459.55 7559.55 7659.55 7696.10 e PROPOSAL LISTING Page 1 Your ref BC-12 Ver 4 Last revised : 30-0ct-2003 R E C TAN G U L A R COO R DIN ATE S Dogleg Vert Deg/100ft Sect 0.00 N 0.00 N 0.00 N 0.00 N 0.00 N 0.00 N 0.53 N 2.12 N 4.76 N 8.46 N 13.21 N 19.00 N 25.83 N 33.68 N 42.55 N 52.43 N 63.31 N 69.22 N 110.65 N 143.98 N 169.98 N 229.32 N 261.54 N 288.65 N 320.81 N 324.87 N 336.11 N 346.62 N 356.37 N 359.39 N 365.37 N 373.61 N 381.08 N 387.78 N 393.70 N 398.84 N 403.19 N 406.76 N 409.54 N 411. 52 N 412.71 N 413.11 N 413.11 N 413.11 N 413.11 N 413.11 N 413.11 N 413.11 N 413.11 N 413.11 N 0.00 E 0.00 E 0.00 E 0.00 E 0.00 E 0.00 E 1.66 E 6.65 E 14.95 E 26.56 E 41.47 E 59.65 E 81. 08 E 105.74 E 133.60 E 164.62 E 198.76 E 217.33 E 347.40 E 452.04 E 533.69 E 719.97 E 821.14 E 906.26 E 1007.24 E 1019.97 E 1055.27 E 1088.25 E 1118.88 E 1128.35 E 1147.13 E 1173.00 E 1196.45 E 1217.48 E 1236.07 E 1252.20 E 1265.87 E 1277.07 E 1285.79 E 1292.02 E 1295.76 E 1297.01 E 1297.01 E 1297.01 E 1297.01 E 1297.01 E 1297.01 E 1297.01 E 1297.01 E 1297.01 E 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.00 4.00 6.00 8.00 72 .33 72 .33 72 .33 72.33 72 .33 0.00 2.00 2.00 2.00 2.00 0.00 KOP 1. 75 6.98 15.69 27 .88 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 72.33 72 .33 72.33 72.33 72 .33 72 .33 72 .33 72 .33 72 .33 72 .33 9.00 7.50 6.00 4.50 3.00 72 .33 72 .33 72 .33 72.33 72.33 2.00 2.00 2.00 2.00 2.00 43.52 62.60 85.10 110.98 140.21 1. 50 0.00 0.00 0.00 0.00 72.33 72 .33 72 .33 72 .33 72 .33 2.00 2.00 2.00 0.00 0.00 172.77 208.60 228.09 EOC 364.59 474.42 TI Coal Beds 0.00 0.00 0.00 0.00 0.00 72 .33 270.00 270.00 270.00 270.00 0.00 0.00 0.00 0.00 0.00 560.10 755.61 861.79 Sterling B-3 951.12 1057.10 End of Hold 1. 50 1. 50 1. 50 1. 50 1. 50 1070.45 1107.51 1142.12 1174.26 1184.21 Top Beluga 1. 50 1. 50 1. 50 1. 50 1. 50 1203.91 1231.06 1255.67 1277.74 1297.25 1.50 1.50 1.50 1.50 1. 50 1314.18 1328.53 1340.29 1349.44 1355.98 1. 50 1. 50 0.00 0.00 0.00 1359.90 1361.21 End of Drop 1361.21 B/Cnglmrt T/Tyonek 1361. 21 1361.21 B/Mid Beluga 0.00 0.00 0.00 0.00 0.00 1361.21 BC12-T/L Beluga19-Rvsd290ct03 1361. 21 1361. 21 1361. 21 1361.21 BC12-T/L Beluga23-Rvsd290ct03 All data is in feet unless otherwise stated. Coordinates from slot #12 and TVD from Est RKB (Glacier 1) (171.10 Ft above mean sea level). Bottom hole distance is 1361.21 on azimuth 72.33 degrees from wellhead. Total Dogleg for we11path is 46.04 degrees. Vertical section is from N 0.00 E 0.00 on azimuth 72.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company Pad #4,BC-12 Beaver Creek Unit, Kenai Peninsula, Alaska Measured Inclin. Azimuth True Vert R E C T A N G U L A R Depth Degrees Degrees Depth C 0 0 R D I N A T E S 8000.00 0.00 270.00 7759.55 413.11 N 1297.01 E 8500.00 0.00 270.00 8259.55 413.11 N 1297.01 E 8643.55 0.00 270.00 8403.10 413.11 N 1297.01 E 8896.55 0.00 270.00 8656.10 413.11 N 1297.01 E PROPOSAL LISTING Page 2 Your ref BC-12 Ver 4 Last revised : 30-0ct-2003 Dogleg Deg/lOOft Vert Sect 0.00 1361.21 0.00 1361.21 0.00 1361.21 BC12-T/L Beluga19-Rvsd290ct03 0.00 1361.21 TD All data is in feet unless otherwise stated. Coordinates from slot #12 and TVD from Est RKB (Glacier 1) (171.10 Ft above mean sea level). Bottom hole distance is 1361.21 on azimuth 72.33 degrees from wellhead. Total Dogleg for wellpath is 46.04 degrees. Vertical section is from N 0.00 E 0.00 on azimuth 72.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad #4,BC-12 Beaver Creek Unit, Kenai Peninsula, Alaska Comments in wellpath -------------~------ -------------------- MD Rectangular Coords. Comment ----------------------------------------------------------------------------------------------------------- TVD e PROPOSAL LISTING Page 3 Your ref BC-12 Ver 4 Last revised : 30-0ct-2003 2500.00 2500.00 0.00 N 0.00 E KOP 3650.89 3620.18 69.22 N 21 7.33 E EOC 4280.87 4200.00 143.98 N 452.04 E T/ Coal Beds 5271. 54 5111. 80 261. 54 N 821.14 E Sterling B-3 5771. 03 5571. 52 320.81 N 1007.24 E End of Hold 6138.16 5915.80 359.39 N 1128.35 E Top Beluga 7305.55 7065.10 413.11 N 1297.01 E End of Drop 7400.45 7160.00 413.11 N 1297.01 E B/Cng1mrt T/Tyonek 7507.25 7266.80 413.11 N 1297.01 E B/Mid Beluga 7655.55 7415.10 413.11 N 1297.01 E BC12-T/L Be1uga19-Rvsd290ct03 7936.55 7696.10 413.11 N 1297.01 E BC12-T/L Be1uga23-Rvsd290ct03 8643.55 8403.10 413.11 N 1297.01 E BC12-T/L Be1uga19-Rvsd290ct03 8896.55 8656.10 413.11 N 1297.01 E TO Casing positions in string 'A' -~---------------------------- ------------------------------ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing ----------------------------------------------------------------------------------------------------------- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 O.OON O.OON O.OON O.OON O.OOE O.OOE O.OOE O.OOE 100.00 2100.00 7544.45 8896.45 100.00 2100.00 7304.00 8656.00 O.OON O.OON 413.11N 413.11N 20 Conductor 13 3/8 Casing 9 5/8 Casing 3 1/2 Liner O.OOE O.OOE 1297.01E 1297.01E Target name Geographic Location T.V.D. Targets associated with this wellpath Revised ----~~--------~~~~-----------~--~~~-- ------------------------------------- Rectangular Coordinates ----------------------------------------------------------------------------------------------------------- BC12-T/L Be1uga19-Rv 316623.000,2433594.000,0.0000 BC12-T/L Be1uga23-Rv 316623.000,2433594.000,0.0000 BC12-T/L Be1uga19-Rv 316623.000,2433594.000,0.0000 7415.10 7696.10 8403.10 413.11N 413.11N 413.11N 1297.01E 1297.01E 1297.01E 3-0ct-2003 3-0ct-2003 3-0ct-2003 e MARATHON Oil Company Pad #4 BC-12 slot #12 Beaver Creek Unit Kenai Peninsula, Alaska e 3-D M I N I MUM D I S TAN C E C LEA RAN C ERE P 0 R T by Baker Hughes INTEQ Your ref Our ref License Date printed Date created Last revised BC-12 Ver 4 prop5537 30-0ct-2003 3 -Oct-2003 30 -Oct-2003 Field is centred on n60 38 50.050,w150 59 49.92 Structure is centred on n60 38 50.0S0,w150 59 49.92 Slot location is n60 39 22.120,w151 1 45.595 Slot Grid coordinates are N 2433200.639, E 315319.955 Slot local coordinates are 3258.04 N 5765.79 W Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North Report is limited to clearances less than 200 feet Obj ect wellpath DECREASING CLEARANCES of less than 1000 feet are indicated by an asterisk, e.g. 487.4* BC-IIA version #l"BC-12,BC Pad 7 TOTCO <0 - 15746>"BC-7,BC Pad 7 MWD <6433-10005>, ,BC-3Rd,Pad #3 PMSS <0 - 8854>,.BC-I0,Pad #3 GMS <8000-16247'>"BC-5,Pad #3 GMS <0-15844'>"BC-6,Pad #3 Schlumberger <5943-8858'>"BC-9,Pad #3 MSS <0-6387>"BC-3,Pad #3 MWD <0-8931>"BC-ll,Pad #3 BC-13 Verso #3"BC-13,Pad #3 MMS<3185-15940'>"BC-4,Pad #4 GMS <0-2800'>"BC-4,Pad #4 Minimum Distance method M.D. Diverging from M.D. 4200.0 4200.0 2537.5 8896.6 600.0 600.0 0.0 8800.0 8460.0 8460.0 7291.3 7600.0 8700.0 8700.0 600.0 600.0 5480.0 5480.0 5480.0 8896.6 620.0 2480.0 620.0 2480.0 Closest approach with 3-D Last revised Distance 3-0ct-2003 13-Feb-2002 2-Jun-2003 9-Apr-2001 5-Sep-1992 5-Sep-1992 14-Dec-1994 25-Feb-2003 17-Apr-2003 13-Aug-2003 19-5ep-2003 3-0ct-2003 3949.1 5241.1 2132.4 2224.7 790.6 792 .4 1263.3 2132.4 1541. 3 1784 . 0 412.1 412.1 Coordìnctes ore in Feet reference slot #12. VertIcal Depths ore reference Est RKB (Glacier 1). f&i. BAKER HUGHES TNTEQ 0 A 20 Conductor 500 - 1000 - 1500 - 2000 - ,U 13 3/8 Casing Created by bmicMoel 2500 - ----- - 3000 - (]) (]) ...... '-" 3500 - .J:: - 0.. Q) o 4000 - o ü 4500 - - L (]) > Q) :::; L f- I V e e Far: D Castilla MARATHON Oil Company M MARATHON Dote ploUed ; .3D-Od-200.3 Plol Reference Îs BC-12 Ver 4. Sirudure : Pad #4 Well BC-12 Field Beaver Creek Unit Location Kenai Peninsula. Alaska East (feet) -> 200 600 1200 1600 1400 800 1000 o 200 400 800 þ..'L '(1- .?J?J Target - 600 ^ 3 1/2 Liner I g 5/8 Casing - 400 Z 0 ~ :::r - 200 ,......, -;, (]) ~ '-" 0 - 200 ~ TRUE 13 3/8 Casing 20 Conductor KOP 2.00 6.00 10.00 OLS: 2.00 deg per 100 it 14.00 18.00 22.00 EOC T/ Cool Beds TANGENT ANGLE 23.02 DEG 5000 - Sterling B-3 5500 - 22.50 1 9.50 WELL PROFILE DATA Beluga ---- --_.- 6000 - 16.50 13.50 DL$; 150 deg per 100 It 10.50 6500 - ----- Poinl ----- "D Djr TVD North Eost V. Sect Oe9/1OO 7.50 4.50 Tìeon 0.00 0.00 72.33 0.00 D.oo 0.00 0.00 0.00 7000 - 1.50 End1f DrO~ B/Cnglmrt T ;[¡;one KOP 2500.00 o.oD 72.3.3 2500_00 0.00 0.00 0.00 0.00 B/Mi eluga j~L g 5/8 Casing LB-19 Tgt 0.00 ~ End of Bujld 3650.89 23.02 72.33 3620.18 69.22 217.33 228.09 2.00 7500 - 0 LB-23 Tgt End of Hold 5771.03 2.3.02 72..33 5571.52 320.81 1007.24 1057.10 0.00 8000 - TARGET AN G LE 0.00 DEG End of Droþ 7.30:;.:;5 0.00 72.33 7065.10 413.11 1297,01 1361.21 1.50 LB-30 Tgt Target BC12-TjL Beluga 7655.55 0.00 72.33 7415.10 413.11 1297.01 1361.21 0.00 i 8500 - jol 3 1/2 Liner TO I Torget 8C12-T/L Beluga 7936.55 0.00 270.00 7696.10 413.11 1297,01 1361,21 0.00 i 9000 I 0 500 1000 1500 Target BC12-TjL Beiugo 8643.~5 0,00 270.00 8403.10 413.11 1297.01 136121 0.00 ! Vertical Section (feet) -> I T.O. & End of Hold 8696.55 0.00 270.00 8656.10 413.11 1297.01 136121 0.00 I Azimuth 72.33 with reference 0.00 N, 0.00 E from slot # 12 e e Dote plotted; 30-0d-2003 MARATHON Oil Company Cn~ct~d by bmichoel For: D Castillo True Vertlcol Depths ore reference Es\ RK8 (Glacier 1). Structure : Pad #4 Well: BC-12 M MARATHON j Plot Reference is BC-12 Ver 4. Coordinates ore În feet reference slot '12. r~ií. BAKER HUGIES TNTEQ Field: Beaver Creek Unit Location: Kenai Peninsula. Alaska TRUE NORTH ßc-A / ~ 3200 ßc-A 3300 c:=:J 350 0 10 340 20 330 280 30 320 40 310 50 300 60 290 70 280 80 40 270 4(!Jc 90 40 260 100 250 110 240 120 230 130 220 140 210 150 200 160 190 180 170 Normal Plane Travelling Cylinder ~ Feet All depths shown are Measured depths on Reference Well bmiçhael For: D il om D<J!.e piotted JO-Od-2003 VN 4- Co()rd¡rI()l~S 0('1 in feet (QJ.;'renç0 Slot #"2. R<8 1) Structure : Pad #4 Well : 8C-12 Field Beaver Creek Unit Location : Kenai Peninsula, Alaska East ( -> 100 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1400 1200 1200 11 00 ~ 1100 1 000 ~ ~ 1000 900 ~ ~ 900 300 800 12300 12700 13000 13300 13600 700 13900 ~ 700 14200 14500 14800 15100 600 600 0300 00 500 500 ;\ 400 400 ^ .~ I .fl ~ -+- 300 - ~ ~ 300 Q) ~ --"$ Q) / <y (; 0'00 4- I 100 '--' --" I: 200 ~ ~ 200 -+- --" L -- liT <0'-0 0 --"~ "7 0 Z )00 ~ 00 100 ~ 0 100 ~ ~ 100 200 ~ ~ 200 300 300 400 ~ 400 500 - 500 600 - 600 ~ i 700 I 700 100 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 ast ( -> Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Prepared MA THO ILCOMPANY Well Beaver Creek # 12 Kenai Peninsula, Alaska Prepared by: Tony Tykalsky Reviewed by: Lee Dewees Presented to: David Castillo Revised October 31 st, 2003 IFE e e Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 A TTN: David Castillo David: Enclosed is the revised recommended drilling fluid program for the Beaver Creek # 12 Well to be drilled next year. The following is a brief synopsis of the program. Overview: Beaver Creek # 12 is a development well targeting the Beluga formation at the Beaver Creek field. F10-Pro fluid will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with 3-112" liner cemented in place. Surface Interval: The surface interval will be drilled with the standard Ge1/Ge1ex spud mud. No problems were noted in this interval while drilling Beaver Creek # 11. Intermediate Interval: This interval will be drilled with a F10-Pro fluid. After drilling out the surface cement, the well will be displaced to a standard F10-Pro KC1 fluid. Safecarb bridging material will be maintained according to the mud program to minimize losses to the formation. Fluid loss should be maintained @ 7 - 9 cc' s API. Production Interval: This interval will be drilled with the modified Flo-Pro fluid. After drilling out the intermediate cement and 20- 25 feet of new hole, the well will be displaced to a modified F10-Pro KC1 fluid. Fluid loss should be maintained @ < 6 cc' s API for this interval. Completion: This program assumes the well will be completed with 6% KC1 brine. Tony Tyka1sky Project Engineer M - I Drilling Fluids Reference Wells: Beaver Creek # 9, #10, #11 NOTE: This proe:ram is provided as a 2uide only. Well conditions will always dictate fluid properties required. ~IFE ~ n ~ e e Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. EXECUTIVE SUMMARY Our overall goal is no spills and no incidents while providing fluids and solids control services to our customer. Our goal for Beaver Creek '# 12 is to remove drill solids from the mud system at a cost of less than $0.23 per pound. This has been the average for the last three years of centrifuge van operations With the revised fluid formulation (increasing the fluid agent concentration and maintaining a lower fluid loss), we expect to minimize formation damage and hole enlargement as demonstrated on Beaver Creek #3 RD. Use of the MI Swaco centrifuge van for the last three years has provided an estimated savings in dilution and disposal costs to Marathon Oil of over $500,000. With continued usage of our equipment, we expect to provide more savings to you during future operations. r:zRiIÆ œœ e e - .. ·'IFE --- Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling Intervals Depth Interval (ft) Benchmark Benchmark 2 Benchmark 3. Benchmark 4 Fluid cost per foot Volume Usage Solids Removal 0-2100' > $5.43 ft > 2230 bbls 2100 - > $28.70 ft > 3916 bbls 7544' 7544 - 8996' > $45.01 ft > 1265 bbls Total Project Targets for Drilling Interval Avg. < $25.90 Max. < 7411 bbls < $0.23 Ib No Spills from Centrifuge Van Operation r:zJItlFE mœ e e Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Proj ect Summary Casing Hole Casing Depth TVD Mud Mud Sum Size Size Program System Weight Days (in) (in) (ft) (ft) Solids Control (ppg) 13 3/8" 16" 2100' 2100 ' GellGelex Spud Mud 8.6 - 9.4 5 Screens 150/180 mesh Desilter Centrifuge Van 95/8" 12-1/4" 7544' 7304' Flo- Pro w/SafeCarb 9.0-9.6 10 Screens 180 - 210 mesh Desilter Centrifuge Van Interval Mud Cost $14,534 $162,498 3-1/2" 8-1/2" 8996' 8656' Flo-Pro w/SafeCarb 9.0 - 9.6 7 $69,727 Screens 230 - 210 mesh Desilter Centrifuge Van 3 1/2" 8-112" Completion 8996' 8656' 6% KCl 8.55 2 $7,290 ).- Utilize all solids control equipment to minimize the build up of drill solids in the system (if possible, centrifuge the surface mud during trips to reduce drill solids). ).- Condition the mud prior to running casing for all intervals. ).- Cost does not include the use of any lubricants. ~IFE mœ e e Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Product Usage Summary M-I Bar 0 196 126 0 322 1.6 M-I Gel 446 0 0 0 446 2.4 Ge1ex 28 0 0 0 28 .015 Soda Ash 16 10 6 0 32 0.2 Caustic Soda 22 39 13 0 74 0.8 Conqor 404 0 9 4 0 13 6.2 SafeScav NA 3 9 3 0 15 2.4 Bicarb 22 20 13 0 55 0.4 Conqor 303 0 0 0 5 5 1.0 FloVis 0 313 101 10 424 34.7 Desco CF 22 0 0 0 22 0.4 DualFlo 0 0 126 0 126 4.3 Polypac UL 13 157 0 0 170 11.1 Greencide 25G 0 0 3 0 3 2 Bioban BP Plus 0 0 96 0 96 .9 KCI 0 1645 531 210 2386 12.5 Safecarb 0 1567 506 0 2073 17.5 SafeKleen 0 1 1 1 3 .55 Asphasol 0 0 51 0 51 1.35 Supreme Defoam X 0 45 7 0 52 1.9 Engineer Service 5 10 7 2 24 ~IFE ~ e e - Marathon Oil Company _IFE Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments BC#9 12.25 559 9.1 23 51 14 1865 9.5 12 13 14 LOT 12.0 EMW 8.5 2332 9.6 14 12 10.4 Drlg ahead 3158 9.8 15 12 10.8 4151 9.4 15 13 8.8 4929 9.4 18 16 6.8 5965 9.4 23 18 5.8 Hole tight on trip - lower fluid loss 6 6330 9.6 21 25 5.2 LOT 14.0 EMW 6346 9.7 19 30 4.5 Coring 7068 9.9 20 23 4.6 Gas, increase mud weight 7584 9.9 20 18 4.6 Drill ahead 8082 10 23 20 5 Coring 8540 10 23 22 6.6 Drlg ahead 8881 9.9 26 19 4.2 Trip ok @ T.D. Be #10 8.5 215 8.65 12 37 20 Spud in 2385 8.9 16 13 10.6 Condition mud for cagin run wlDesco CF 6.125 3198 8.85 5 19 7.2 Drlg out, LOT 16.42 EMW, FloPro fluid 4516 9 6 21 7.6 Drlg 1318' in one day 5260 9 7 24 7.5 Drlg ahead 6440 9.25 8 29 7.1 Short trip - backreaming required 6906 9.3 9 27 7 Trip for bit - backream 7480 9.4 10 25 6.4 Trip in - OK 7788 9.5 10 25 6.3 Bit trip - backream through new hole section 8418 9.35 9 21 5.8 Trip in - OK drlg ahead 8587 9.4 9 19 6 Drlg ahead, trip for bit, backream new hole section 8854 9.55 9 20 6 @ T.D. POH for logs 8854 Spot 16 PPG pill on bottom prior to running casing Be #11 17.5 400 8.75 15 25 14 Spud in 1520 8.95 17 36 12.2 Drlg ahead 2202 9.4 15 25 9.4 TD of surface interval 12.25 2242 9.2 7 19 14.8 Drill out 3697 9.35 10 18 18.6 Drill ahead 4656 9.35 8 20 19.6 Drill ahead 5714 9.35 9 22 18.4 Short trip ok 5910 9.5 9 20 18.4 Adding SafeCarb to combat losses to formation 6620 9.4 10 20 15.4 Drlg ahead 6825 9.5 11 28 17.8 Drlg ahead, add Lubetex 7120 9.5 11 29 7 Drlg ahead control fluid loss with Pac 7260 9.6 12 31 7 Condition mud, run & cement casing 8.5 8036 9.35 10 26 6.8 Dril out drlg ahead 8652 9.4 10 24 7.4 Drlg ahead getting 1000 unit of gas 8931 9.55 9 22 8 At td - run logs ~IÆ mœ e e Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Plans & Procedures => COMMUNICATION - The Field Mud Engineer will communicate daily with the In-Town Project Engineer. The Project Engineer will then communicate daily with the rig Drilling Engineer. Communications should be about, but not limited to, fluid properties, hole difficulties, possible changes to the mud program, and proposals to use products not included in the mud program. => Whole Mud Losses to the Sterln9 B3 & B4 Sands - Refer to fluid formulas and the Optibridge charts for maintaining proper bridging material concentration in the mud system while drilling the intermediate and production intervals. => FLUID LOSS CONTROL - In the intermediate interval the API fluid loss will be maintained in the 7 - 9 cc's range. In the production interval the API fluid will be maintained at less than 6 cc's at all times. In addition to sufficient fluid loss agent additions, this may require adequate dilution of the mud system in order to keep reactive drill solids to a minimum. It is particularly important to maintain a low hardness «200 ppm Ca) for effective use of DualFlo, therefore cement contamination should be completely treated as rapidly as possible prior to adding DualFlo to control or reduce fluid loss. NOTE: If additions of DualFlo do not appear to be lowering the fluid loss adequately, then switch to additions of Polypac Supreme SL after consultation with town. => LSRV - When drilling with a FloPro fluid, the low shear rate rheology should be maintained around 40,000 cps. In addition to adequate additions of FloVis Plus, this will also require keeping reactive drill solids to a minimum in order to reduce or eliminate false and unwanted high LSRV. => DRILL SOLIDS - MBT - The MBT should be kept at less than 5 ppb in the production interval through aggressive use of solids equipment and dilution as needed. => MIXING CONDITIONS - Whenever possible all treatments to the mud system should be made as pre-mix additions. Polymers and KCI should first be mixed in fresh water in that order and then blended into the active system over one or two circulations as needed. => CORROSION - Conqor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a Conqor 404 concentration of +/- 2000 PPM. => CORRISION - SafeScav NA additions should be made daily as needed with any fluid in the hole. Maintain a DO reading of less than 3 ppm => GREENCIDE 25G ADDITIONS - Greencide 25G additions should be made daily when drilling in the production interval, in the range of 5 gallons per day. => SOLIDS VAN USAGE - The Solids Van should be used whenever drill solids become un- acceptably high and reduction of drill solids in the mud can be more economically done with centrifuging and dilution then just with dumping and diluting. The weight of the drilling fluid alone should not be the determining condition for when to use the Solids Van. => WEIGHTING UP - All increases in mud weight should be accomplished with barite additions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. ~IÆ æœ e - - ·'}IFE ----- Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Interval Summary -16" hole Drilling Fluid System Gel/Ge1ex Spud Mud Key Products MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / PolyPac Supreme UL Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 150 - 180 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions IntervaIDriUipgFluid:pfope.rties Depth Mud Funnel Yield API Interval Weight Viscosity Point Fluid Loss (ft) (ppg) (sec./qt) (lb./l00ft2) (ml/30min) 0-2100' 8.6 - 9.4 60 - 100 25 - 35 NC - 12 pH Drill Solids (%) +/- 9.5 <7% ~ Treat drill water with Soda Ash to reduce hardness. ~ Build spud mud with 20 - 25 PPB M-I Gel to +/- 100 sec.qt funnel viscosity. ~ Lower funnel viscosity to +/- 75 after gravel zone has been drilled. ~ Add Gelex as needed to maintain sufficient viscosity for hole cleaning. ~ Increase funnel viscosity if fill on connections begins to occur. ~ Reduce fluid loss with additions ofPolypac Supreme UL prior to running surface casing. ~ Add 2 - 5 PPB of M - I Seal Fine to mud system if seepage losses becomes a problem.. ~ Condition mud prior to cementing casing to reduce yield point and gel strengths. ~ Estimated volume usage for interval- 2230 barrels. ~ Estimated haul off volume - 4180 barrels. ~IFE ~ e e - ~IFE Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Interval Summary - 12-1/4" hole 2100 - 7544' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / PoluPac UL / KC1/ SafeCarb F, Ventrol401 / MI Bar / Caustic Soda / Conqor 404 / SafeScav NA Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 210 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions IntervaIDrillingiFluidl'~øper~ie$ Depth Mud Plastic LSRV Interval Weight Viscosity 1 min (ft) (ppg) (cp.) (cps) 2100 - 5000' 9.0-.?:ì 8 - 12 40,000 5000 - 7544' 9.4 -(~ 10 - 14 40,000 API Drill Fluid Loss pH Solids (mI/30min) (%) 7-9 +/- 9.5 +/- 5% 7-9 +/- 9.5 +/- 8% ~ Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed fluid formula. ~ After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test ~ Ifrunning coals become a problem, treat with a 2 PPB addition of Asphasol D. ~ Estimated volume usage for interval- 3916 barrels. ~ Estimated haul off volume - 6348 barrels. ~ Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. J:UaIÆ ~ e e - . ·-)IFE .--.. Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Output - 1 bbl COncentratiOn fiêk:l,Ib Water 298.70 298.70 0.853 Soda Ash 0.25 0.25 0.000 Flovis 2.00 2.00 0.004 Poly pac Supreme UL 2.00 2.00 0.004 Caustic Soda 0.50 0.50 0.001 Potassium Chloride 19.07 19.07 0.023 SafeCarb F 10.00 10.00 0.010 SafeCarb M 10.00 10.00 0.010 Asphasol Supreme 2.00 2.00 0.006 If bit balling becomes a problem, add the following: D-D CWT I 1.00 I 1.00 I 0.003 I 1.00 Reduce BHA Balling If torque becomes a problem, or sliding is difficult, add up to 5% of the following: Lubetex 14.00 14.00 0.041 14.43 Fluid Formula 12-1/4" Interval 12-1/4" Interval from 2100 -7544' De$Cription Mud Weight Weight Material Code Weight Material SG Input Beaver Creek Well #12 9.1 - 9.2 PrehydratedGeI MI Bar PrøhydratecfGeI 4.2 KCIWt% 6 No Order of Addition 1 2 3 4 5 6 7A 7B 8 Products 298.70 0.10 1.33 1.25 0.23 7.98 3.60 3.60 2.08 9 10 Total Calculated Mud Weight Total Chloride 399 9.500 29600 1.000 350 Estimated Volume Usaae 399 ~IÆ mœ Reduce Hardness Viscosity Fluid Loss Control pH Control Inhibition Bridging Agent Bridging Agent Wellbore Stability Lubricity 3916 Barrels Marathon on Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. - Marathon 011 Max Permeability: Sand Control Device: 400 mDarcy © 1999-2001 M-I 1...1._<: . All Rights Reserved 0.9 010 Target! Blend: O.S 050 Target I Blend: 20.!) 090 Target I Blend: 64.8 1.5 0.8-- ¡:: o "§ O_7-~ .Q or:: - II> ã (þ N ü) d;. ü t2 «I C!.. Q) > ;:; «I "S E ::¡ u Brand Name B=Safe-Carb 10 (F) D=Safe-carb 40 (M) E=Safe-Carb 250 (C) 0.1 B 49.3% 10x10-2 Calcium Carbonate added: Avg Error 0 -100 % CPS Ftill"lge : Max Error 0 -100 % CPS Range: 20 Iblbbl 3.43 % 17.0S % Particle Size (microns) ;;.. Zone of interest - Sterling B-4 sands y Pore Pressure 4.3 - Maximum Porosity - 400 mD y Measured Depth - y Build additional volume as needed usin2 the blend listed above. IFE e e - . <1IFE - Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole 7544 - 8996' Drilling Fluid System Flo-Pro Fluid Key Products Flo- Vis / DualFlo / KCI / Greencide 25G / SafeCarb F / SafeCarb M / MI Bar / Caustic Soda / Conqor 404 / SafeScav NA Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions Int~rval Drilling Fluid Prøperties Depth Mud Plastic LSRV Interval Weight Viscosity 1 min (ft) (p~ (cp.) (cps) 7544 - 8996' 9.2t.::J/ 10 -14 40,000 API Fluid Loss (mI/30min) <6 pH Drill Solids (%) +/- 5% +/- 9.5 ? Use one rig pit for drilling out intennediate casing. In other rig pits, build new Flo-Pro fluid using the enclosed fonnula. ? Ifrunning coals become a problem, treat with a 2 PPB addition of Asphasol D. ? Periodic additions of Greencide 25G will be needed to control bacteria build-up. ? Estimated volume usage for interval- 1265 barrels. ? Estimated haul off volume - 1746 barrels. ? Condition mud prior to running 3-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~~IÆ ~ e e Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Fluid Formula - 8-1/2" Interval 8-/12" Interval from 7544 - 8996' Input Description Mud Weight Weight Material Code Weight Material SG Weight Material Price Sea Water Sea Salt M-IGel M-I Gel Price Order of Addition 1 2 3 4 5B 5B 6 7 8 9 10 11 12 13 Beaver Creek #12 9.05 Prehydrated Gel SafeCarb Prehydrated Gel Conc. 2.8 KCI 0.35 KCI Wt% No KCI No NaCI 6 0.2516 No NaCI Price Output - 1 bbl Products Lal:5,gm Water 325.19 325.19 Soda Ash 0.25 0.25 FloVis Plus 1.75 1.75 DualFlo 5.00 5.00 SafeCarb Fine 14.00 14.00 SafeCarb Medium 6.00 6.00 Potassium Chloride 20.76 20.76 Greencide 25G 0.25 0.25 CONQOR 404 2.00 2.00 Caustic Soda 0.50 0.50 SafeScav NA 0.25 0.25 If Bit balling becomes a rroblem, add the following D-D 4.00 I 4.00 I 0.011 I 4.00 If sliding or high torque becomes a problem add 1 - 3% of the following Lubetex I 7.00 I 7.00 I 0.021 I 7.00 If sloughing coals become a problem add 2 - 4 ppb of the followin~ Asphasol Supreme I 2.00 I 2.00 I 0.004 I 1.33 Mix fluid in the order listed above. Wait for 1 - 2 circulations before adding SafeScav NA to the system. Alternate additions of Greencide 25G and SafeScav NA as needed. Maintain 5 - 6 ppb concentration of DualFlo to maintain as Iowa API fluid loss as possible. Plan on daily additions of DualFlo to achieve> 6.0 cc's API Fluid Loss Reduce concentration of FloVis as needed to maintain rheology. 0.929 0.000 0.004 0.009 0.015 0.006 0.025 0.001 0.004 0.001 0.001 325.19 0.10 1.18 3.32 5.30 2.30 8.68 0.30 1.43 0.23 0.25 Total I Calculated Mud Weight Total Chloride Estimated Volume Usage I 380.1 380.1 9.050 29600 r:zJ8IÆ œœ Reduce Hardness Viscosity Fluid Loss Control Bridging Agent Bridging Agent Inhibition Biocide Corrosion Control pH Control Oxygen Scavenger Reduce BHA Balling Lubricity Wellbore Stability 1265 Barrels e e - .. ·'IFE ----.. Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. HSE Issues HANDLING OF DRilLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. ~IFE ~ Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Product M-I BAR M-I GELEX FLOVIS DUAL-FLO POLYPAC XCD HEC Safe-Carb F,M,C LO WATE Nut Plug M-I Seal F, M, C Mix II F,M,C DESCO CF SPERSENE CF TANNATHIN VENTROL 401 SALT (Solar) BROMIDE (NaBr) & Brine Solution POTASSIUM CHLORIDE - Function Weighting Agent Viscosity control Bentonite Extender Viscosifier Modified Starch Fluid Loss Reducer Viscosifyer Loss Circulation Material Bridging and weighting agent Weighting agent Loss Circulation Material Loss circulation Material Loss circulation Material Dispersant Dispersant Dispersant Surfactant Densifier Densifier Shale Inhibitor Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Product CAUSTIC SODA CAUSTIC POTASH BORAX SAPP SODA ASH SODIUM BICARBONATE CITRIC ACID BIOBAN BP-PLUS GREEN CIDE 25G - DEFOAM X - G-SEAL KLA-GARD LUBE TEX D-D CWT Concor404 SAFEKLEEN AsphasolD Soltex SafeScav NA Function Alkalinity control pH Modifier Inorganic Borate Sodium Pyrophosphate Alkalinity control Alkalinity control pH Adjuster Biocide Biocide Defoamer Sized graphite LCM Shale Control agent Lubricant Detergent Corrosion ·Inhibitor Drilling fluid additive Shale Inhibitor Shale Inhibitor Oxygen Scavenger IFE e e Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 - Severe hazard 3 - Serious hazard 2 - Moderate hazard 1 - Slight hazard o - Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A - Safety Glasses B - Safety Glasses, Gloves C - Safety Glasses, Gloves, Synthetic Apron D - Face Shield, Gloves, Synthetic Apron E - Safety Glasses, Gloves, Dust Respirator F - Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G - Safety Glasses, Gloves, Vapor Respirator H - Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I - Safety Glasses, Gloves, Dust and Vapor Respirator J - Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K - Air Line Hood or Mask, Gloves, Full Suit, Boots X - Consult your supervisor for special handling directions ~IFE œœ Marathon Oil Company Well Name: Beaver Creek # 12 Location: Kenai, Alaska. .. MI Project Engineer and Tech Service Engineer will coordinate between the Marathon· office, rig, warehouse, and the M-I field engineers. . Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. Proj ect Team Title Home Cellular Craig Bieber District Manager 907 345-1239 907 229-1196 Deen Bryan Tech Service 907 373-2713 907223-1634 Tony Tykalsky Project Engineer 907 376-4613 907 Gus Wik Warehouse Manager 907 776-8722 907 776..8680 Bob Williams Senior Engineer 907 248-5857 907 590-3636 Floyd Faulkner Senior Engineer 907349-8147 907 590...3636 IFE 1101129 Check Date Bank Bank No Vendor NA 11/04/2003 NCBAS 7780 5001123 T iiii@MÞ~WÞÄ@i@~fiW 11/01/2003 1900031145 TOTAL: Marathon Oil Company P. O. Box 3128 Houston, TX 77253 AL ~ ~WiuIN¥~ir~~Y~BLE DEPARTMENT Accts Payable - Customer Serv Phone: 713-296-4336 @Ä@p~yAfu@ri!) . 100.00 100.00 Hndlg Check No AL100.00 100.00 100.00 NO! 0 6 Alaska Oil & 3as Cons. Commission 1< ., HficHorag-s (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) '1'. ~ [1:'« .,~ ~i: I' J ~ I ~ ~ i-"I¡'/~'.! ~ II ~ r (I :l~' ~I'. ~, ~ .._: I =-.,: 1:( ~ ~~ :,~ t ~ ~(e' ;{ '1' J ~ I'.~' :1::111 ~ "Jr.] ~::¡.. _: I =- ~ I ~ I =-: =! I{ 'll¡I.Ii.] ~V~'I~¡'''~lr~:{II] :¡~Úi'l~tï··· SVOS/OO 11'000 ~ ~o ~ ~ 2 '111' 1:0 I.. ~ 20 ~B '151: 0 ~B ~ L.B 1..11' e e TRANSMIT AL LETTER CHECKLIST CIRCLE APPROPRIATE LETTERlPARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME L~C -)2- PTD# 2-0:] - J()f CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) PILOT (PH) "CLUE" The permit is for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function· of the original API number stated above. HOLE In accordance with 20 AAC 25.005(1), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API Dumber (50 70/80) from records, data and logs acquired for well (name on permit). SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to peñorate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) assumes the liability of any protest to the spacing . exception that may occur. An dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. _ Company MARATHON OIL CO PTD#:2031880 Field & Pool BEAVER CREEK. BELUGA GAS - 80500 Initial ClasslType Administration 1 P~rmitfee attaçhep . . . . . . . . . . . . . . . . . . . Yes. 2 .Leas~.number .appropriate. . . . . .. Yes. . . . . . . . . 3 .U.nlque well.n.a!11~.aod oumb.er . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Yes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 WellJQcated in a defined pool Yes. 5 WeJIJQcated pr.operdistance from driJling unitbpund.ary. . . . . . . . . . . . . . . . . . . . . . . . Yes. 6 WelUQcated proper distance from Qtber wells . Yes 7 .Sutfiçien"açreaQ.e.ayailable in.driUioQ.unj" . . . . . . . . . . . . . . . . y~s . 8 Jf.d~viated, js weJlbQre plaUncJuded . . . . . . . . . . . . . . Yes. 9 Qperator onl}' affeçted party. . . . . . . . . . Yes 10 .Qper.ator bas.appropriate. Qond inJorce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . y~s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 P~rmit cao be issued wjtbQut conservation order. . . . . . . . . . . . . . . . . . . . . . y~s . 12 P~rmit cao be issued wjtbQut ad.ministrati\,le.appr.oval. .................. . Yes. 1117/2003 13 Can permit be approved before 15-day wait Yes _ 14 WeJIJQcat~d within area and strata authorized by.lojectioo Order # {puUO# in.c.o!11!11.eots).{for. NA . . . . . . .. .......... 15 .A]I wells.within.1l4.mile.area.of reyiew jd~otified (F.or servjc.eweU onl}'). . . . . . . . . . . . . . . NA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Pre-produced iojector; puratiQnof pre-propuc:;tion I~ss. than 3. montbs. (for service well QnJy). NA. 17 ACMP Fïnding of CQnsisteoc:;yh.as been Jssued. fortbis projeçt . . . . . . . . . . .. . NA Appr Appr 18 19 20 21 22 23 24 25 26 27 Date 28 11/17/2003 29 30 31 32 33 34 Engineering 1Þ Geology Appr Date RPC 11/7/2003 Geologic Commissioner: Dr( Date Cpoductor stringprQvided . . . . . . . . . . . . . . . y~s .Sw:faœ casing pJQtects alLknown USDWs . . . . y~s . .CMTv.otadequ.ateto çirc.utate.o.n.cond.uctor.& surf.csg . . . . . . . . . . . . . . . . . . . . . . Y~s. . . . . . J\deJ: uate excess, . .CMT.v.ot adequateto tie-inJQngstring tosur:f csg. . . . . . . . . . . . . . . . . . . . . . . . . y~s CMTwill c:;oyeraJl knownWQduc:;tiye bQrizon.s. . . . . . . . . . . . . .. .. Yes ........................ ............ C.asiog desigos adec uate f.or C,T, B&.permafr.ost . Yes. Apequatetankage.or reserve pit. . . . . . . . . . . . . . . . . . . . . . . . .. . . . . Yes. Jf.aJe-prilt has.a. tOAO;3 fQr abandonment be~o apPJQved . . . NA .Apequatewe!lbore separatio.n.proposed. . . _ . . . . . . . . . . . . . . . . . . . . . . . .Y~s . Jf.diverter req.uired, dQes j"m.e~t reguJations. . . y~s . DriUiog fJujd.prQgram schematic.&eq.uipJistadequate. . . . . Y~s. BOPEs,.d.othey meetreguJation . . y~s . . BOPEpress rajiog appropriate; test to.{put psig tn.comments). . . . . Y~s. Test to.3500.psi. .MS~ 33.73 psi.. . . . . C.hokemanjfold cQmpJies w/API R~-53. (May 84). . . . . . . . . . . . . . . . . Y~s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . WQrk will occur withoytoperation .sbutdo.wn. . . . . . . . . . . . . . . . Y~s . . . . . . . .. ............................... .Is presence Qf H2S gas probable. No. . . . . . . . Meçba.nicaLC9odJtion .of wells within J\Oß yerified (for.s.erviœ w~1I only). . NA . . . . . . 35 P~rmit can be issued w/o hydrogen s.ulfide meas.ures. . Yes. 36 .D.ata.presented on. potential .overpressure zones . . . . . . . . . . . . . . .NA 37 .S~ismic.analysjs. Qf shaJlow gas.z.ooes. . . . NA 38 .S~abed .conditi.oo survey (if off-shore) . . . . . . . . . . . . . . . . . . . . . . . . NA 39 . CQntact narn.elphoneforweekly progress reports [exploratpryonly] . . . . . . . . NA Engineering Public . ~ Date: Commissioner: Date CommissioneW Date flj/7lJ ,\"é\ Well Name: BEAVER CK UNIT DEV 11-GAS GeoArea BC-12 Program DEV __ On/Off Shore ~ Well bore seg Annular Disposal o Unit - .. .. .. .. - - .. .. .. .. .. .. .. .. .. - .. - .. - - - - - - - .. - - - .. - - - - .. - - - - - .. .. .. - .. - .. .. .. .. .. - .. .. - .. - - - - - - .. .. .. .. .. - - .. .. .. .. .. - .. - - - - - - .. - - .. - - - - - .. .. - - .. .. - .. - - - - - - - - - - - - - - - - .. .. - - - .. .. .. .. - - .. .. .. .. .. .. .. .. .. .. .. .. - - - .. - .. .. - - .. - .. - - - - .. .. .. .. .. .. - - .. .. .. .. - - - - - .. - - .. - - - - .. .. - - - - .. .. .. .. .. - - .. .. .. .. - .. .. .. .. .. .. .. .... .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. - .. .. .. .. .. .. - - - - - - - - - - - - - - - - - - - - . Glacier.Rig #1.. . . . . - - - - - - - - - . - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ - - - - - - -- - - - - - - . . Max MW.9Ji ppg. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
