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Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,081'See schematic Casing Collapse Structural Conductor 1,500psi Surface 3,090psi Intermediate Production 5,410psi Liner 7,500psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name:Ryan Rupert, Operations Engineer Contact Email:ryan.rupert@hilcorp.com Contact Phone: 907-777-8503 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 7,437' 7,840' 3,549' ~1192 See schematic 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Dan Marlowe, ASC Team Operations Manager, 907-283-1329 8,430psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: Baker ZXP; N/A 8,830' MD/4,251' TVD; N/A 7,525 - 7,546 3,396 - 3,404 11/5/2021 4-1/2" 7,437' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0389737 / FEE-PRIVATE 207-096 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-133-20571-00-00 Hilcorp Alaska LLC Ninilchik Field / Beluga-Tyonek Gas Pool N/A Ninilchik Unit G Oskolkoff 6 (GO-6) Other: Install Cap String Length Size 12.6# / L-80 TVD Burst 8,842' 7,240psi MD 3,060psi 5,750psi 98' 1,788' 98' 2,999' 4,433'7" 20" 9-5/8" 98' 2,999' 9,038' Perforation Depth MD (ft): 9,038' 4-1/2"12,069'3,227' ry Statu Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:18 pm, Oct 21, 2021 321-553 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.21 15:05:33 -08'00' Dan Marlowe (1267) DSR-10/21/21 10-404 BJM 10/22/21 SFD 10/21/2021 dts 10/22/2021 JLC 10/22/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.22 15:19:38 -08'00' RBDMS HEW 10/25/2021 Cap String Well: GO-06 Date: 10/18/2021 Well Name:GO-06 API Number:50-133-20571-00-00 Current Status:SI Gas Well Permit to Drill Number:207-096 Regulatory Contact:Donna Ambruz (907) 777-8305 (O) First Call Engineer:Ryan Rupert (907) 777-8503 (O) (907) 301-1736 (C) Second Call Engineer:Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP:~ 1532 psi @ 3,404’ TVD (Based on a 0.45 psi/ft gradient to deepest open perfs) Max. Potential Surface Pressure:~ 1192 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Brief Well Summary GO-06 had been a long term SI well, until perfs were plugged off and the BEL-120L was shot in August of 2021. The well came on at 900mcfd and 0-1 bwpd. The well declined until late Sept-2021 when the rate suddenly fell from ~300mcfd to <50mcfd. The well subsequently died and will no longer flow. A SL drift didn’t find any fill, but did find a FL at ~2950’ MD. The objective of this intervention is to install a cap string to keep the well unloaded and return it to production. Notes Regarding Wellbore Condition x Min ID = 3.833” (4-1/2” drift ID) x Inclination o Max = 72 degrees at 1856’ MD o Sail angle of ~69 degrees from 1650’ MD – 7400’ MD o Then rolls to 53 degrees by 8000’ MD x Recent History: o 10/10/21: SL tagged at 7840’ MD with a sample bailer. Came back with fluid only. FL identified at 2,950’ MD o 8/18/21: EL set most recent CIBP and shot 21’ of 3-3/8” guns in BEL 120L o 6/10/18: CT IA squeeze complete. Milled down to 8832’ ELMD Procedure: 1. RU Cap String Truck. 2. Stab 3/8” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 3. RIH with 3/8” capillary string to ±7800’ MD. a. Deviation may stop us shallow of target depth b. Set cap string as deep as practical 4. Install slips and connect tubing to chemical injection pump. 5. Set spool of remaining line near well 6. RD cap string Unit, and turn well over to production. Attachments: 1. Proposed Schematic Size Type Wt Grade Conn. ID Top Btm 20" Conductor 113 K-55 PE Surf 98' 9-5/8" Surf Csg 40 L-80 BTC 8.835" Surf 2,999' 7" Prod Csg 26 L-80 Mod Butt 6.276" Surf 9,038' 4-1/2" Liner 12.6 L-80 Hy 563 3.958" 8,842' 12,069' 4-1/2" Tubing 12.6 L-80 Hy 563 3.958" 0 8,842' Sands Top (MD) Btm (MD) Top (TVD)Btm (TVD) Length (ft) Date Status BEL 120L 7525 7546 3396 3404 21 8/18/21 Open BEL-135 7903 7923 3584 3596 20 7/2/18 Isolated 8035 8050 3662 3672 15 6/22/18 Isolated 8070 8090 3684 3697 20 6/22/18 Isolated T-8 8808 8818 4232 4241 10 6/18/18 Isolated T-9 8879 8899 4293 4310 20 4/3/18 Isolated T-10 9005 9025 4403 4417 17 3/21/18 Isolated 9457 9482 4825 4849 25 11/21/07 Isolated 9482 9511 4849 4877 29 11/20/07 Isolated T-19 10103 10127 5464 5488 24 11/15/07 Isolated T-90 11537 11568 6898 6929 61 10/19/07 Isolated TD 12,081' MD PBTD 7,840' MD Revised by CRR 10-18-21 Velocity String Fish Details: 1-3/4" HO-70 0.134" wall thickness. 9398 - 10100' MD (chem cut). BHA consisting of coil grapple .68' L X 2.625" OD, straight bar 9.57' L X 2.625" OD. 1.48" ID, 1.25"XN Landing Nipple .78' L X 2.48" OD 1.135 NO GO, Wireline Reentry guide .66' L X 2.50" OD. Attempted to fish with overshot on 1-3/4" CT 05/24/16. CEMENT DETAIL 7,437' TVD 3,549' TVD T-2 PERFORATION DETAIL 43bbls of 15.8ppg cement circ'd into IA via a cement retainer on 5/29/18. 6/10/18 CBL showed ToC at 6665’ MD. Patchy between 7700' - 8580' MD 4-1/2" Tubing T-13A CASING DETAIL 9-5/8"12-1/4" Hole: 305bbls 12ppg Type 1 cement. 41bbls back to surface 8-3/4" Hole: 126bbls 12.5ppg lead and 30bbls 15.8ppg tail pumped. No losses. 14bbls found inside 7" from 8680' to 9038' MD. Volumetric ToC at 4216' MD with 10% washout. 7" 4-1/2" Liner 6-1/8" Hole: 100bbls 10.5ppg cement pumped with no losses. 5bbls circulated back to surface 67º Sail Angle from 1,583'-7,354' MD GO - 6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1N, R13W, S.M. *ZXP Liner Packer with 15' Tieback Extension @ 8,830.24' MD (Top) *Flex-Lock Liner Hanger @ 8,862.31' MD (Top) *Marker Joint Top @ 9,925.5' MD (19' long) *Marker Joint Top @ 10,929.5' MD (19.5' long) Cast Iron Bridge Plug @ 11,470' Permit #: 207-096 API #: 50-133-20571-00-00 Prop. Des: ADL 389737 KB Elevation: 187' (21' AGL) TD: 09/07/2007 Baker Chemical Injection Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID; 8,430 psi burst / ,7500 psi collapse SCHEMATIC CIBP @ 9,390' - 03/20/18 T9 T10 CIBP @ 8,990' - 04/02/18 B135 T2 T8 TOC 6,665' MD (06/10/18 CBL) CIBP @ 8,010' w/10' cmt 07/01/18 CIBP @ 8,870' ToC (milled) = 8832' ELMD 6/1/18 Punch @ 8,815'-8,820' 05/26/18 CIBP @ 8,800' 06/22/18 T13A T19 T90 CIBP @ 7,910' set mid-perf (8/6/21) CIBP @ 7,840' (8/18/21) B-120L Size Type Wt Grade Conn. ID Top Btm 20" Conductor 113 K-55 PE Surf 98' 9-5/8" Surf Csg 40 L-80 BTC 8.835" Surf 2,999' 7" Prod Csg 26 L-80 Mod Butt 6.276" Surf 9,038' 4-1/2" Liner 12.6 L-80 Hy 563 3.958" 8,842' 12,069' 4-1/2" Tubing 12.6 L-80 Hy 563 3.958" 0 8,842' Cap String (3/8"): To be installed Top Bottom 0'±7,800'MD Sands Top (MD) Btm (MD) Top (TVD)Btm (TVD)Length (ft)Date Status BEL 120L 7525 7546 3396 3404 21 8/18/21 Open BEL-135 7903 7923 3584 3596 20 7/2/18 Isolated 8035 8050 3662 3672 15 6/22/18 Isolated 8070 8090 3684 3697 20 6/22/18 Isolated T-8 8808 8818 4232 4241 10 6/18/18 Isolated T-9 8879 8899 4293 4310 20 4/3/18 Isolated T-10 9005 9025 4403 4417 17 3/21/18 Isolated 9457 9482 4825 4849 25 11/21/07 Isolated 9482 9511 4849 4877 29 11/20/07 Isolated T-19 10103 10127 5464 5488 24 11/15/07 Isolated T-90 11537 11568 6898 6929 61 10/19/07 Isolated TD 12,081' MD PBTD 7,840' MD Revised by CRR 10-18-21 T-13A CASING DETAIL 9-5/8"12-1/4" Hole: 305bbls 12ppg Type 1 cement. 41bbls back to surface 8-3/4" Hole: 126bbls 12.5ppg lead and 30bbls 15.8ppg tail pumped. No losses. 14bbls found inside 7" from 8680' to 9038' MD. Volumetric ToC at 4216' MD with 10% washout. 7" 4-1/2" Liner 6-1/8" Hole: 100bbls 10.5ppg cement pumped with no losses. 5bbls circulated back to surface CEMENT DETAIL 7,437' TVD 3,549' TVD T-2 PERFORATION DETAIL 43bbls of 15.8ppg cement circ'd into IA via a cement retainer on 5/29/18. 6/10/18 CBL showed ToC at 6665’ MD. Patchy between 7700' - 8580' MD 4-1/2" Tubing Velocity String Fish Details: 1-3/4" HO-70 0.134" wall thickness. 9398 - 10100' MD (chem cut). BHA consisting of coil grapple .68' L X 2.625" OD, straight bar 9.57' L X 2.625" OD. 1.48" ID, 1.25"XN Landing Nipple .78' L X 2.48" OD 1.135 NO GO, Wireline Reentry guide .66' L X 2.50" OD. Attempted to fish with overshot on 1- 3/4" CT 05/24/16. 67º Sail Angle from 1,583'-7,354' MD GO - 6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1N, R13W, S.M. *ZXP Liner Packer with 15' Tieback Extension @ 8,830.24' MD (Top) *Flex-Lock Liner Hanger @ 8,862.31' MD (Top) *Marker Joint Top @ 9,925.5' MD (19' long) *Marker Joint Top @ 10,929.5' MD (19.5' long) Cast Iron Bridge Plug @ 11,470' Permit #: 207-096 API #: 50-133-20571-00-00 Prop. Des: ADL 389737 KB Elevation: 187' (21' AGL) TD: 09/07/2007 Baker Chemical Injection Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID; 8,430 psi burst / ,7500 psi collapse PROPOSED SCHEMATIC CIBP @ 9,390' - 03/20/18 T9 T10 CIBP @ 8,990' - 04/02/18 B135 T2 T8 TOC 6,665' MD (06/10/18 CBL) CIBP @ 8,010' w/10' cmt 07/01/18 CIBP @ 8,870' ToC (milled) = 8832' ELMD 6/1/18 Punch @ 8,815'-8,820' 05/26/18 CIBP @ 8,800' 06/22/18 T13A T19 T90 CIBP @ 7,910' set mid-perf (8/6/21) CIBP @ 7,840' (8/18/21) B-120L 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,081 feet See schematic feet true vertical 7,437 feet See schematic feet Effective Depth measured 7,840 feet 8,830 feet true vertical 3,549 feet 4,251 feet Perforation depth Measured depth 7,525 - 7,546 feet True Vertical depth 3,396 - 3,404 feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 8,842 (MD) 4,261 (TVD) 8,830 (MD) Packers and SSSV (type, measured and true vertical depth)Baker ZXP 4,251 (TVD) N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Contact Phone: 321-355 Sr Pet Eng: 7,500psi Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 106 8,430psi Ryan Rupert ryan.rupert@hilcorp.com (907) 777-8503Dan Marlowe - Operations Manager measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 0 2044 0 229 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 98' 2,999' N/A 67 Structural TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 207-096 50-133-20571-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0389737 / FEE -PRIVATE Ninilchik Field / Beluga-Tyonek Gas Pool 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Ninilchik Unit G Oskolkoff 6 (GO-6) Hilcorp Alaska, LLC Other: ______________________ measuredPlugs Junk measured N/A Length 98' 2,999' Size Conductor Surface Intermediate 20" 9-5/8" Production Liner 9,038' 3,227' Casing 98' 1,788' 4,433' 4-1/2" 9,038' 12,069' 7,437' 7"5,410psi 3,060psi 5,750psi 7,240psi Burst Collapse 1,500psi 3,090psi L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 3:04 pm, Oct 21, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.21 14:51:53 -08'00' Dan Marlowe (1267) SFD 10/21/2021 RBDMS HEW 10/21/2021 DSR-10/21/21BJM 10/22/21 Size Type Wt Grade Conn. ID Top Btm 20" Conductor 113 K-55 PE Surf 98' 9-5/8" Surf Csg 40 L-80 BTC 8.835" Surf 2,999' 7" Prod Csg 26 L-80 Mod Butt 6.276" Surf 9,038' 4-1/2" Liner 12.6 L-80 Hy 563 3.958" 8,842' 12,069' 4-1/2" Tubing 12.6 L-80 Hy 563 3.958" 0 8,842' Sands Top (MD) Btm (MD) Top (TVD)Btm (TVD) Length (ft) Date Status BEL 120L 7525 7546 3396 3404 21 8/18/21 Open BEL-135 7903 7923 3584 3596 20 7/2/18 Isolated 8035 8050 3662 3672 15 6/22/18 Isolated 8070 8090 3684 3697 20 6/22/18 Isolated T-8 8808 8818 4232 4241 10 6/18/18 Isolated T-9 8879 8899 4293 4310 20 4/3/18 Isolated T-10 9005 9025 4403 4417 17 3/21/18 Isolated 9457 9482 4825 4849 25 11/21/07 Isolated 9482 9511 4849 4877 29 11/20/07 Isolated T-19 10103 10127 5464 5488 24 11/15/07 Isolated T-90 11537 11568 6898 6929 61 10/19/07 Isolated TD 12,081' MD PBTD 7,840' MD Revised by CRR 10-18-21 Velocity String Fish Details: 1-3/4" HO-70 0.134" wall thickness. 9398 - 10100' MD (chem cut). BHA consisting of coil grapple .68' L X 2.625" OD, straight bar 9.57' L X 2.625" OD. 1.48" ID, 1.25"XN Landing Nipple .78' L X 2.48" OD 1.135 NO GO, Wireline Reentry guide .66' L X 2.50" OD. Attempted to fish with overshot on 1-3/4" CT 05/24/16. CEMENT DETAIL 7,437' TVD 3,549' TVD T-2 PERFORATION DETAIL 43bbls of 15.8ppg cement circ'd into IA via a cement retainer on 5/29/18. 6/10/18 CBL showed ToC at 6665’ MD. Patchy between 7700' - 8580' MD 4-1/2" Tubing T-13A CASING DETAIL 9-5/8"12-1/4" Hole: 305bbls 12ppg Type 1 cement. 41bbls back to surface 8-3/4" Hole: 126bbls 12.5ppg lead and 30bbls 15.8ppg tail pumped. No losses. 14bbls found inside 7" from 8680' to 9038' MD. Volumetric ToC at 4216' MD with 10% washout. 7" 4-1/2" Liner 6-1/8" Hole: 100bbls 10.5ppg cement pumped with no losses. 5bbls circulated back to surface 67º Sail Angle from 1,583'-7,354' MD GO - 6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1N, R13W, S.M. *ZXP Liner Packer with 15' Tieback Extension @ 8,830.24' MD (Top) *Flex-Lock Liner Hanger @ 8,862.31' MD (Top) *Marker Joint Top @ 9,925.5' MD (19' long) *Marker Joint Top @ 10,929.5' MD (19.5' long) Cast Iron Bridge Plug @ 11,470' Permit #: 207-096 API #: 50-133-20571-00-00 Prop. Des: ADL 389737 KB Elevation: 187' (21' AGL) TD: 09/07/2007 Baker Chemical Injection Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID; 8,430 psi burst / ,7500 psi collapse SCHEMATIC CIBP @ 9,390' - 03/20/18 T9 T10 CIBP @ 8,990' - 04/02/18 B135 T2 T8 TOC 6,665' MD (06/10/18 CBL) CIBP @ 8,010' w/10' cmt 07/01/18 CIBP @ 8,870' ToC (milled) = 8832' ELMD 6/1/18 Punch @ 8,815'-8,820' 05/26/18 CIBP @ 8,800' 06/22/18 T13A T19 T90 CIBP @ 7,910' set mid-perf (8/6/21) CIBP @ 7,840' (8/18/21) B-120L BEL 120L 7525 7546 3396 3404 21 8/18/21 Open Rig Start Date End Date E-Line 7/31/21 10/10/21 Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name NINU GO-06 50-133-20571-00-00 207-096 8/12/2021 Arrive @ GO, sign permits, talk w/ company rep. Re-head, check tool string, rig up on well. Rih w/ 4 1/2 swab mandrel w/ 2 v-cups, begin swabbing. Cant get cups passed 5145' kb, pooh. Rih w/ 3.65 G-ring to 7500' kb, do not set down, pooh. Stand by for different style swab mandrel.,Rih w/ 4 1/2 Roller, xo, 4 1/2 mandrel w/ 3 v-cups, 4 1/2 Roller . Continue Swabbing. Ooh w/ swab cups. Last Run tagged fluid @ 5420 w/ 280' of returns. FL swabbed down to 5700' MD Lay down equipment. 7/31/2021 8/11/2021 Arrive @ Go, talk w/ company rep, sign permits. TGSM. Rig up on well w/ .160 Bleed down well. Rih w/ 4 1/2 swab mandrel w/ 2 v-cups. See swab report. Finished swabbing, lay down lub for the night. (metal pieces have been coming back when changing cups) FL swabbed from 1950 - 4530' MD ON LOCATION - TGSM - JSA - PERMIT. RIG UP W/L - PT LUB - GOOD. RIH W/ 3.75" GAUGE RING TO 8,011'KB TAG PLUG - POOH. RIH W/ 3-3/8" X 20' DUMMY GUNS (SPENT PERF GUNS) FALL SLOW AT 1,500'KB CONTINUE IN HOLE. TO 8,011'KB TAG PLUG - POOH - FLUID APPEARS TO BE AT 2,000'KB. RIG DOWN W/L - MOB TO GO-1. 8/6/2021 JSA, Rig Up, PT 250 lo, 2500 high RIH with 4.5" CIBP (3.5" OD), CCL, and Roller Bogies to 7902' Tied into CI mandrel at 2382' MD. (21' RKB accounted for) Line stretch estimated to be <4' at this depth with this unit. Pick up weight Standby to set plug Set 4.5" CIBP, Lost weight, Tagged plug at 7,890' Pooh OOH Rig down Leave location Set 4.5" CIBP, Lost weight, Tagged plug at 7,890' P Rig Start Date End Date E-Line 7/31/21 10/10/21 Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name NINU GO-06 50-133-20571-00-00 207-096 8/13/2021 Arrive @ GO, talk w/ company rep, sign pemits. TGSM. Rig up on well. Rih w/ 4 1/2 Roller, 4 1/2 swab mandrel w/ 3 v-cups, 4 1/2 Roller. Begin Swabbing. Cant fall passed 4600' kb, pooh and check tool string. Weight pod diaphrame breaks while pooh. Still get 380' return. Stand by for weight pod. Continue Swabbing. Ooh w/ tools, lay down and re-head. End FL at 7270' MD 8/14/2021 Arrive @ GO, rig up on well. Rih w/ 4 1/2 Roller, 4 1/2 Swab Mandrel w/ 3 v-cups, 4 1/2 Roller. See Swab report. Rih w/ 4 1/2 Roller w/ 4 1/2 BLB to 7930' kb, tag plug, pooh to 4000' kb, brush between 4000-5300 several times, pooh. Ooh brush is covered in sand. Run back in hole w/ swab cups. Cannot get passed 4600' kb. Rig down off well. Move to SD-6, end ticket. FL swabbed down to 7270' MD 8/15/2021 Arrive @ SD, sign permits, TGSM. Finish rigging off SD-6 Depart for GO Rig up on GO-6 Rih w/ 4 1/2 Roller, 4 1/2 swab mandrel w/ 3 v-cups,4 1/2 roller, 4 1/2 BLB, have to beat our way into hole from 1700- 6950 (where we see fluid level), rih to 7180' kb, pooh, ooh w/ 170 of fluid. Rih w/ 4 1/2 Roller, 4 1/2 Roller, 4 1/2 Swab mandrel w/ 4 v-cups, see swab report. Ooh w/ tools, rig down FL swabbed down to 7700' MD 8/18/2021 Arrive Location, JSA, Safety Meeting . Spot trucks, Rig up. MU rope socket,Roller Boggie, Gun Gamma, 3 3/8"x 21' Geo gun, Roller Boggie Pressure Test, O'ring leak, Change out O'ring (found bad spot) Retest 250/3000 PSI, Good test. RIH to 7857' CCL bottom of roller boggie 7910' Log strip to 6790', Send log to town,Plug is 20' deep 7910' (Middle of perfs) discuss, POOH. Surface wait on Plug and setting tool from shop. MU rope socket, GPT, Roller boggie, 3 1/8" wgt bar, Roller boggie, Setting tool and 3.5" CIBP. RIH to 7890', Log Correlation pass Send to town, Found fluid level at 7050',Set Plug at 7840', Good set, POOH. Surface Tubing Pressure bled down to 75 PSI. RIH with 21'x 33/8" gun to CIBP at 7840' >ŽŐŽƌƌĞůĂƟŽŶWĂƐƐĂŶĚƐĞŶĚƚŽƚŽǁŶ͘^ƵďƚƌĂĐƚϭ͘Place gun on depth 7525'- 7546' in BEL-120L ( CCL at 7516.3' ) 8.7' CCL to Top Shot,Fire gun, Rapid increase in Pressure 233 psi from 66 psi when fired , 290 in 5 minutes, 520 in 10 minutes. 710 psi in 15 minutes.WKK,͘^ƵƌĨĂĐĞϴϳϬƉƐŝŽŶƚƵďŝŶŐ͘ZŝŐĚŽǁŶƐĞĐƵƌĞǁĞůůĂŶĚƚƵƌŶŽǀĞƌƚŽKƉĞƌĂƟŽŶƐ͘ Travel to shop. Place gun on depth 7525'- 7546' in BEL-120L ,Fire gun, Rapid increase in Pressure 233 psi from 66 psi when fired , ,Set Plug at 7840', Rig Start Date End Date E-Line 7/31/21 10/10/21 Daily Operations: Hilcorp Alaska, LLC Weekly Operations Summary API Number Well Permit NumberWell Name NINU GO-06 50-133-20571-00-00 207-096 10/10/2021 Rig up Slickline P/T LUB 2500 PSI RIH/w 3" x 10' DD Bailer to 7819' SLM (7840' RKB) w/t can not pass (appear to be at CIBP at 7840' RKB) POOH OOH/w Fluid Only obtain samples from btm and top of bailer (could not verify fluid level),RIH/w 3.79 " Blind Box to 2950' RKB verify fluid level 4 passes POOH OOH Rig down Stow Tools and Lub Prep to Travel Travel to PWL shop. 8/21/2021 MIT-IA of 4-1/2" x 7" annulus passed to 1500psi. T/I/O readings: Initial: 382/1635/0. 15min: 383/1624/0. 30 min: 381/1620/0. Pressure loss of 11 followed by 4 psi. AOGCC witnessed. AOGCC witnessed. MIT-IA of 4-1/2" x 7" annulus passed to 1500psi. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___Patch / N2___ 2.Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,081'see schematic Casing Collapse Structural Conductor Surface 3,090psi Intermediate 5,410psi Production Liner 7,500psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.rupert@hilcorp.com 7,437'8,000'3,641'~1,192psi see schematic Baker ZXP; N/A 8,842' MD/4,261'TVD; N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: 8,430psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL-389737; FEE-PRIVATE 207-096 50-133-20571-00-00 Grassin Oskolkoff #6 (GO-6) Ninilchik Beluga/Tyonek Gas Length Size C.O. 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# / L-80 TVD Burst 8,842' MD 7,240psi 5,750psi 98' 1,788' 4,433' 98' 2,999' 20" 9-5/8" 98' 7"9,038' 2,999' Perforation Depth MD (ft): 9,038' See Attached Schematic 4-1/2" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: July 30, 2021 12,069'3,227' 4-1/2" 7,437' m n P 66 t _ c Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 8:08 am, Jul 20, 2021 Grassim 321-355 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.19 21:22:03 -08'00' Taylor Wellman (2143) MITIA to 1500 psi required within 10 days of return to production after adding perforations. Notify AOGCC to witness. 10-404 BJM 7/26/21 X DSR-7/21/21 X DLB 07/20/2021 dts 7/28/2021 JLC 7/28/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.28 15:55:17 -08'00' RBDMS HEW 7/30/2021 Well: GO-06 Date: 7/19/2021 Well Name:GO-06 API Number:50-133-20571-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:207-096 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Max. Expected BHP:~ 1531 psi @ 3402’ TVD (Based on 0.45 psi/ft) Max. Potential Surface Pressure ~ 1192 psi (Based on 0.1 psi/ft to surface) Well Summary GO 6 is a Long-term SI well that was recompleted in 2018 to the Beluga-135 sand with no success. There may potentially be additional sands to perforate in the Beluga sands. The IA cement job completed in 2018 now enable access to more uphole Beluga sands. The goal of this project is to perforate uphole Beluga sands in an attempt to return the well to production. The Beluga-135 may be reperforated with additional underbalance, as well. Notes Regarding Wellbore Condition x Min ID = 3.833” (4-1/2” drift ID) x Inclination o Max = 72 degrees at 1856’ MD o Sail angle of ~69 degrees from 1650’ MD – 7400’ MD o Then rolls to 53 degrees by 8000’ MD x Recent history o 7/2/18: SITP at 1800psi (hadn’t changed since 12 hrs ago). Perf’d 20’ in BEL-135 with 2-7/8” guns as deep as 7923’ MD (gun dry). Tagged at 8000’ Bled down well to 900psi before shooting. No real pressure change afterwards o 7/1/18: N2 pushed fluid below 8060’ and then set CIBP at 8010’ MD. Put 10’ of cement on top of plug o 6/26/18: SL had issues getting to bottom with a 4’ x 2.5” DD bailer. 60 gal diesel pumped, and tools went to bottom. Bailer came back full of fill. 900psi static BHP at 8090’ MD. FL at ~4200’ MD. Only T-2 open at the time o 6/22/18: Set CIBP at 8800’ MD. T-2 perfs added as deep as 8090’ MD. 2-7/8” guns. 980psi was trapped on well after plug set. Jumped up to 1130psi after T-2 shot. (dry gun) o 6/18/18: Perf’d T-8 as deep as 8818’ MD with 10’ x 2-7/8” gun. o 6/10/18: CT IA squeeze complete. Milled down to 8832’ ELMD Nitrogen Risk x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting Nitrogen during this job) x Ensure all crews are aware of stop work authority perforate uphole Beluga sands Well: GO-06 Date: 7/19/2021 E-Line Perf 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2,000 psi High Pump diesel as needed to help toolstrings make it downhole 3. RIH with GPT to determine FL 4. Plug set: CONTINGENCY a) IF FL is found too high, a plug may be set to isolate water production b) RU Nitrogen Truck c) Pressure up wellbore pushing water back into BEL-135 perfs d) Once below area to perf, set 4-1/2” CIBP per OE. 5. Rig up perf gun (Likely 2-7/8” – 3-3/8” 4-6 spf) 6. RIH and perforate the sand listed in the table below, per Geo/RE. Sand Perforation Top (MD) Perforation Bottom (MD) Perforation Top (TVD) Perforation Bottom (TVD) Total Footage (MD) BEL_100 ±6,942’±6,971’±3,182’±3,192’29‘ BEL_120U ±7,404’±7,420’±3,347’±3,353’16‘ BEL_120L ±7,525’±7,546’±3,396’±3,404’21‘ BEL_135 ±7,899’±7,944’±3,581’±3,608’45‘ Consult with OE for what WHP’s to use. May be shot while flowing Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Matt Petrowsky (Geo): 814-421-6753 ii. Anthony McConkey (RE): 529-6199 7. RD E-Line Unit and turn well over to production. Contingency EL Plug or Patch 1. MIRU E-line, PT lubricator to 250 psi low / 2,000 psi high 2. RIH W/ GPT tool and find fluid level 3. RU Nitrogen Truck a. Push water back into formation b. Use GPT tool to confirm water level is below interval to perf c. Consult OE for pressure to leave on well for perforating 4. Once fluid level is below interval to isolate, MU 4-1/2” patch or plug 5. RIH and set plug or patch per OE. 6. RD E-Line Unit and turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations Size Type Wt Grade Conn. ID Top Btm 20" Conductor 113 K-55 PE Surf 98' 9-5/8" Surf Csg 40 L-80 BTC 8.835" Surf 2,999' 7" Prod Csg 26 L-80 Mod Butt 6.276" Surf 9,038' 4-1/2" Liner 12.6 L-80 Hy 563 3.958" 8,842' 12,069' 4-1/2" Tubing 12.6 L-80 Hy 563 3.958" 0 8,842' Sands Top (MD) Btm (MD) Top (TVD)Btm (TVD) Length (ft) Date Status BEL-135 7903 7923 3584 3596 20 7/2/18 Open 8035 8050 3662 3672 15 6/22/18 Isolated 8070 8090 3684 3697 20 6/22/18 Isolated T-8 8808 8818 4232 4241 10 6/18/18 Isolated T-9 8879 8899 4293 4310 20 4/3/18 Isolated T-10 9005 9025 4403 4417 17 3/21/18 Isolated 9457 9482 4825 4849 25 11/21/07 Isolated 9482 9511 4849 4877 29 11/20/07 Isolated T-19 10103 10127 5464 5488 24 11/15/07 Isolated T-90 11537 11568 6898 6929 61 10/19/07 Isolated TD 12,081' MD PBTD 8,000' MD Revised by CRR 7-14-21 Velocity String Fish Details: 1-3/4" HO-70 0.134" wall thickness. 9398 - 10100' MD (chem cut). BHA consisting of coil grapple .68' L X 2.625" OD, straight bar 9.57' L X 2.625" OD. 1.48" ID, 1.25"XN Landing Nipple .78' L X 2.48" OD 1.135 NO GO, Wireline Reentry guide .66' L X 2.50" OD. Attempted to fish with overshot on 1- 3/4" CT 05/24/16. CEMENT DETAIL 7,437' TVD 3,641' TVD T-2 PERFORATION DETAIL 43bbls of 15.8ppg cement circ'd into IA via a cement retainer on 5/29/18. 6/10/18 CBL showed ToC at 6665’ MD. Patchy between 7700' - 8580' MD 4-1/2" Tubing T-13A CASING DETAIL 9-5/8"12-1/4" Hole: 305bbls 12ppg Type 1 cement. 41bbls back to surface 8-3/4" Hole: 126bbls 12.5ppg lead and 30bbls 15.8ppg tail pumped. No losses. 14bbls found inside 7" from 8680' to 9038' MD. Volumetric ToC at 4216' MD with 10% washout. 7" 4-1/2" Liner 6-1/8" Hole: 100bbls 10.5ppg cement pumped with no losses. 5bbls circulated back to surface 67º Sail Angle from 1,583'-7,354' MD GO - 6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1N, R13W, S.M. *ZXP Liner Packer with 15' Tieback Extension @ 8,830.24' MD (Top) *Flex-Lock Liner Hanger @ 8,862.31' MD (Top) *Marker Joint Top @ 9,925.5' MD (19' long) *Marker Joint Top @ 10,929.5' MD (19.5' long) Cast Iron Bridge Plug @ 11,470' Permit #: 207-096 API #: 50-133-20571-00-00 Prop. Des: ADL 389737 KB Elevation: 187' (21' AGL) TD: 09/07/2007 Baker Chemical Injection Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID; 8,430 psi burst / ,7500 psi collapse SCHEMATIC CIBP @ 9,390' - 03/20/18 T9 T10 CIBP @ 8,990' - 04/02/18 B135 T2 T8 TOC 6,665' MD (06/10/18 CBL) CIBP @ 8,010' w/10' cmt 07/01/18 CIBP @ 8,870' ToC (milled) = 8832' ELMD 6/1/18 Punch @ 8,815'-8,820' 05/26/18 CIBP @ 8,800' 06/22/18 T13A T19 T90 Size Type Wt Grade Conn. ID Top Btm 20" Conductor 113 K-55 PE Surf 98' 9-5/8" Surf Csg 40 L-80 BTC 8.835" Surf 2,999' 7" Prod Csg 26 L-80 Mod Butt 6.276" Surf 9,038' 4-1/2" Liner 12.6 L-80 Hy 563 3.958" 8,842' 12,069' 4-1/2" Tubing 12.6 L-80 Hy 563 3.958" 0 8,842' Sands Top (MD) Btm (MD) Top (TVD)Btm (TVD)Length (ft)Date Status BEL_100 ±6,942’ ±6,971’ ±3,182’ ±3,192’ 29‘ TBD Proposed BEL_120U ±7,404’ ±7,420’ ±3,347’ ±3,353’ 16‘ TBD Proposed BEL_120L ±7,525’ ±7,546’ ±3,396’ ±3,404’ 21‘ TBD Proposed BEL_135 ±7,899’ ±7,944’ ±3,581’ ±3,608’ 45‘ TBD Proposed BEL-135 7903 7923 3584 3596 20 7/2/18 Open 8035 8050 3662 3672 15 6/22/18 Isolated 8070 8090 3684 3697 20 6/22/18 Isolated T-8 8808 8818 4232 4241 10 6/18/18 Isolated T-9 8879 8899 4293 4310 20 4/3/18 Isolated T-10 9005 9025 4403 4417 17 3/21/18 Isolated 9457 9482 4825 4849 25 11/21/07 Isolated 9482 9511 4849 4877 29 11/20/07 Isolated T-19 10103 10127 5464 5488 24 11/15/07 Isolated T-90 11537 11568 6898 6929 61 10/19/07 Isolated TD 12,081' MD PBTD 8,000' MD Revised by CRR 7-14-21 Velocity String Fish Details: 1-3/4" HO-70 0.134" wall thickness. 9398 - 10100' MD (chem cut). BHA consisting of coil grapple .68' L X 2.625" OD, straight bar 9.57' L X 2.625" OD. 1.48" ID, 1.25"XN Landing Nipple .78' L X 2.48" OD 1.135 NO GO, Wireline Reentry guide .66' L X 2.50" OD. Attempted to fish with overshot on 1- 3/4" CT 05/24/16. CEMENT DETAIL 7,437' TVD 3,641' TVD T-2 PERFORATION DETAIL 43bbls of 15.8ppg cement circ'd into IA via a cement retainer on 5/29/18. 6/10/18 CBL showed ToC at 6665’ MD. Patchy between 7700' - 8580' MD 4-1/2" Tubing T-13A CASING DETAIL 9-5/8"12-1/4" Hole: 305bbls 12ppg Type 1 cement. 41bbls back to surface 8-3/4" Hole: 126bbls 12.5ppg lead and 30bbls 15.8ppg tail pumped. No losses. 14bbls found inside 7" from 8680' to 9038' MD. Volumetric ToC at 4216' MD with 10% washout. 7" 4-1/2" Liner 6-1/8" Hole: 100bbls 10.5ppg cement pumped with no losses. 5bbls circulated back to surface 67º Sail Angle from 1,583'-7,354' MD GO - 6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1N, R13W, S.M. *ZXP Liner Packer with 15' Tieback Extension @ 8,830.24' MD (Top) *Flex-Lock Liner Hanger @ 8,862.31' MD (Top) *Marker Joint Top @ 9,925.5' MD (19' long) *Marker Joint Top @ 10,929.5' MD (19.5' long) Cast Iron Bridge Plug @ 11,470' Permit #: 207-096 API #: 50-133-20571-00-00 Prop. Des: ADL 389737 KB Elevation: 187' (21' AGL) TD: 09/07/2007 Baker Chemical Injection Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID; 8,430 psi burst / ,7500 psi collapse PROPOSED SCHEMATIC CIBP @ 9,390' - 03/20/18 T9 T10 CIBP @ 8,990' - 04/02/18 B135 T2 T8 TOC 6,665' MD (06/10/18 CBL) CIBP @ 8,010' w/10' cmt 07/01/18 CIBP @ 8,870' ToC (milled) = 8832' ELMD 6/1/18 Punch @ 8,815'-8,820' 05/26/18 CIBP @ 8,800' 06/22/18 T13A T19 T90 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. SOF T� • % �A THE STATE Alaska Oil and Gas ��►,��, ofALCommission l® 333 West Seventh Avenue ig GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ALAS + Fax 907.276.7542 www.aogcc.alaska.gov Chad Helgeson %CANN Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga-Tyonek Gas Pool,Ninilchik Unit G Oskolkoff(GO) 6 Permit to Drill Number: 207-096 Sundry Number: 318-198 Dear Mr. Helgeson: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this�day of May, 2018. RBDMS I ate I -7 2O1 RECEIVED • • STATE OF ALASKA MAY 1 4 2018 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations 2- Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend 0 Perforate Q ' Other Stimulate 0 Pull Tubing 0 Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing ❑ Other: ❑✓ • 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number: CMT Pcgje.e-tr Hilcorp Alaska,LLC Exploratory 0 Development ❑✓ • 207-096 . 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20571-00-00 - 7. If perforating: 8.Well Name and Number: -7v I tC What Regulation or Conservation Order governs well spacing in this pool? C.O. SfihY'- p /t T) Ninilchik Unit G Oskolkoff(GO)6 Will planned perforations require a spacing exception? Yes ❑ No 0 s� K"� 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL-389737; FEE-PRIVATE - Ninilchik/Beluga-Tyonek Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD):8,990; Junk(MD): 12,081' . 7,437' ' 8,990' 4,390' -1,663psi 9,390;11470 9,398'(fish) Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060psi 1,500psi Surface 2,978' 9-5/8" 2,999' 1,788' 5,750psi 3,090psi Intermediate 9,017' 7 9,038' 4,433' 7,240psi 5,410psi Production Liner 3,227' 4-1/2" 12,069' 7,437' 8,430psi 7,500psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 8,842' ' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker ZXP; N/A 8,842'MD/4,261'TVD; N/A 12.Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑., Exploratory ❑ Stratigraphic ❑ Development❑✓ Service 14.Estimated Date for 15.Well Status after proposed work: CommencingOperations: May 25,2018 OILWINJ WDSPL p El ❑ 0 Suspended ❑ 16.Verbal Approval: Date: GAS ❑✓ WAG ❑ GSTOR 0 SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown 0 Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer( hilcoro.com Contact Phone: 777-8420 Authorized Signature: (meq" ` 1/ / . Date: hyli? COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 517- 19'2. Plug Integrity ❑ BOP Test adMechanical Integrity Test 1:1Location Clearance ❑ Other: -3f y opo 1& G- (c-.-r-ka I RSDMS, .� AY 1 /y X011 #'r �L ~Gb �I Post Initial Injection MIT Req'd? Yes ❑ No 0 Spacing Exception Required? Yes o No Subsequent Form Required: /0 —41041 APPROVED BY 5 O! (p Ii ej Approved��.ppp��rby: COMMISSIONER THE COMMISSION /4 Date: s'-!L- ` 8 Submit Form and t_��orm 10-403 Revised 4/2017 Approved apGilloNikto a date of approval. /_..-Attachments in Duplicate 11 • 0 Well Prognosis Well: GO-6 Hilcury Alaska,LL. Date:05/14/2018 Well Name: GO-6 API Number: 50-133-20571-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: 05/25/18 Rig: Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-096 First Call Engineer: Ted Kramer (907)777-8420(0) (985)867-0665 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824 (M) AFE Number: Current Surface Pressure: 621 psi Current BHP: - 1,482 psi @ 5,150' TVD (SBHP survey of GO-6 on 4/7/16) Maximum Expected BHP: - 1,847 psi @ 8803' MD (4,228'TVD) (Based on 0.437 psi/ft Grad. Max. Potential Surface Pressure: - 1,663 psi (Assumed 0.10 psi/ft gas gradient) Brief Well Summary GO-6 was originally drilled as a grassroots well in July 2007 and completed in the Tyonek sands. After initial completion,the lowest intervals were isolated and the upper interval was frac'ed,which doubled production but also brought in water, so a capillary string was installed in July 2008 to help with loading issues. In July 2010,the - cap string was removed and the 1-3/4" velocity string was installed.The well stopped producing in 2014 due to loading. In May of 2016 an attempt was made to remove the coil velocity string. The Velocity string was stuck, cut and removed,with the bottom of the string (+/-9,400' down) not recovered and plugged back. In April of 2018 a CIBP was set over the top of the coil fish at 9,390' and the T-10 and T-9 intervals were perforated. Both of these intervals tested wet. The purpose of this work/sundry is to abandon the lower portion of the well by setting a CIBP above the 1-9 ' perforations at 8,870' and placing 25'of cement on top of the CIBP with a bailer. Hilcorp then plans to punch holes in the tubing, set a retainer, and pump cement up the back side of the tubing in order to create a cement sheath between the tubing and casing to perforate through. F rs f // � / Notes Regarding Wellbore Condition • Ensure all crews are aware of stop job authority. E-line Procedure 1. MIRU a-line and pressure control equipment. PT lubricator to 250 psi low/2,000 psi high 2. PU RIH W/CIBP to 8,870'.Set same. POOH. 3. PU Bailer. Fill with Cement and RIH to proper depth and deposit 25' of cemen on top of CIBP(TOC @ 8,845'). POOH. WOC. yr -/-.6b >� l c-oot.ol. C44.,a- 4. PU phased Tubing Punches. RIH and tag TOC(needed for step 7). PU and punch tubing from (+/-) 8,830'-8,835'. POOH. Lc-41...)fr1, a e,a 141..11 5. RDMO E-line. CIK 1 T - 1111 • • Well Prognosis Well: GO-6 IIi(curn Alaska,LL 00`ok,h Date:05/14/2018 Coil Tubing Procedure 404).° �" vG ‘1 114)11- 6. MIRU Coil Tubing Unit. Test BOP to 3 psi high, 250 psi low. 7. PU RIH with Cement Retainer and tag TOC for depth control. PU and set CMT Retainer @ 8,825'. 8. Circulate well down coil and up back side of tubing. Establish PIR. (Note: min Rate needed is 1.0 BPM)Sting out of Retainer. 9. RU Cementing Unit, Circulate cement to bottom of coil. Sting into retainer and pump cement (38+bbls)through retainer and holes circulating up the 4-1/2"X 7" annulus. TOC needs to be 6,800' or shallower to meet new revised regulation 20AAC 25.030(d)(5). 10. Un-sting from retainer, PU CIBU and clean up coil, POOH. (Maintain 1,000 psi on the tubing). 11. Shut in well.WOC. 12. RU slickline and RIH and tag cement or PU bit on downhole motor. RIH to tag cement with coil tubing. If cement is tagged high, Drill cement to 8825'. PU, circulate clean. /ale 13. Pressure up on tubing to 2,000 psi, shut in well and test on chart for 30min. 14. Pressure test IA casing annulus to 1,500 psi and chart for 30 min. ( qbc-,--1..,.f CA41- P I"S._ ) 15. Bleed down pressure, drop ball to open port, blow well dry with Nitrogen leaving 1,600 psi on the N" well. POOH W/coil. // 16. RDMO Coil Tubing. vK (v , Nore ; X64- n - E-line Procedure ,�� VI Gw 17. MIRU E-line unit. Pressure test lubricator to 3,000 psi. t�`• �� 18 PU Logging tools and run a CBL from PBTD to 6,000' looking for top of cement. Evaluate CBL to confirm cement behind pipe and isolation to surface. Send copy of CBL to AOGCC. 19. PU, RIH with 2-7/8" 6 SPF 60 deg phased perf guns (up to 12 SPF with 2 perf runs). Perforate the following intervals: (Note: well surface pressure may need to be adjusted to achieve desired underbalance.) Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Beluga B120 ±7,408' ±7,427' ±3,339' ±3,356' 19 Beluga B131 ±7,528' ±7,540' ±3,397' ±3,402' 12 Beluga B135 ±7,903' ±7,923' ±3,584' ±3,596' 20 Tyonek T2 ±8,006' ±8,018' ±3,644' ±3,652' 8 Tyonek T2 ±8,030' ±8,050' ±3,659' ±3,671' 12 Tyonek T3 ±8,235' ±8,250' ±3,792' ±3,802' 10 Tyonek T5A ±8,364 ±8,374' ±3,882' ±3,889' 10 Tyonek T6 ±8,482' ±8,501' ±3,970' ±3,984' 19 Tyonek T6A ±8,650' ±8,669' ±4,101' ±4,117' 19 Tyonek T7 ±8,748' ±8,767' ±4,182' ±4,198' 19 Tyonek T8 ±8,803' ±8,818' ±4,228' ±4,241' 15 a. Proposed perfs also shown on the proposed schematic in red font. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c. Use Gamma/CCL to correlate. s • Well Prognosis Well: GO-6 [Blown Alaska,LL Date:05/14/2018 d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. e. Rule 2 of Conservation Order 701C defines the Ninilchik Beluga/Tyonek Gas Pool as the intervals common to and correlating between the measured depths of j.,48fl"in the_Paxto>T a.#5,-WeII and 9r60triin the Paxterr 1 well. /Ss5 `!y 9C)// S 111-636 1�c_ /6r�c�7L E-line Procedure (Contingency): /4J:/ ' 1. If any zone produces sand and/or water or needs isolated, or needs to be individually tested for Reserves. 2. MIRU E-line, PT lubricator to 2,500 psi Hi 250 Low. 3. RIH and set 4-1/2" CIBP at depth above zone. Or 4. RIH and set 4-1/2" Casing Patch across the zone. Coil Procedure Contingency: The GO#6 Well is a highly deviated well (69.2 degrees @ 7006'). 1. The possibility exists that E-line will not be able to get down to set the CIBP. If that happens, the CIBP will be set with Coil Tubing. 2. The zones may also need to be blown dry before perforating and if that happens Coil will be used to jet dry the well with N2. 3. Nitrogen may also be used to push water away into the formation prior to setting a CIBP. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Wellhead Diagram 4. CT BOPE Schematic 5. CT Schematic(forward jetting) 6. Standard Well Procedure—Nitrogen Operations • • IIGO - 6 Ninilchik Unit SCHEMATIC 2,975'FSL, 2,988'FEL Sec.23, TIN, RI3W, S.M. Hilcorp Alaska,LLCConductor I J \ 20" K-55 133 ppf PE f ; Top Bottom Permit#: 207-096 t MD 0' 98' API#: 50-133-20571-00-00 ND 0' 98' Prop.Des: ADL 389737 KB Elevation: 187' '21AGL ( ) Surface Casing X: 229,025.05(NAD 27) • 9-5/8" L-80 40 ppf BTC Y: 225,4940.94(NAD 27) ; T0' Bottom Latitude: 60 09'48.512"N MD o' 2,999' TVD 0' 1,788' Longitude: 151 29'23.738"W Spud: 07/30/2007 12-1/4"hole with 690 sks(305 bbls)12 ppg TD: 09/07/2007 Type 1 cement with 41 bbls cement to surface. Rig Released: 09/21/2007 @ 10:00 hrs. • WBS#: DD.06.15534.CAP.CMP y µ Intermediate Casinq L gD - / 7" L-80 26 ppf Mod Butt I u L iv 7- �� Top' 9,0 m 8' MD 0' 9,038' ND 0' 4,433' ..v Baker Chemical Injection Nipple 0`� 8 046-3/4"hole with 289 sks(126 bbls)12.5 ppg @ 2,382'MD(Top) - } Lead &145 sks(30 bbls)15.8 ppg Tail,did 5.930"OD/3.858"ID;8,430 psi burst '•. j • ., not bump plug,100%returns,floats held. /,7500 psi collapse p00 I✓ o l; •.' iS • e�� Tie-backTubinq 4-1/2" L-80 12.6 ppf Hydril 563 KOP @ 196'MD/ND Top Bottom Build 5.0°/100'from 200'-1583'MDI DMD 0' 8,842' Hold 67°from 1,583'-7,354'MD ND 0' 4,261' Drop 2.5°/100'to 10,120'MD Hold 0°from 10,120'to TD at 10,090'MD Azimuth:290.931° Liner 4-1/2" L-80 12.6 ppf Hydril 563 Top Bottom i.' MD 8,842' 12,069' ND 4,261' 7,437' 7"hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks(100 bbls)10.5 ppg *ZXP Liner Packer with 15'Tieback Extension cement,Plug failed,100%Returns. 5-8 bbls @ 8,830.24'MD(Top) cement returns. *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) "Marker Joint Top @ 9,925.5'MD(19'long) *Marker Joint Top @ 10,929.5'MD(19.5'long) _-- MIME - i'045 *Landing Collar Top @ 11,983.91' (1.53'Long) *Float Collar Top @ 12,025.56' (1.55'Long) ,' Velocity String Fish Details *Float Shoe Top @ 12,066.95 (2.05'Long) 1-3/4" HO-70 0.134 wall thickness Top Bottom .y_ MD 9,398' 10,100' (Chemical Cut) 19 illIE.,411 BHA consisting of coil grapple.68'L X 2.625"OD,straight CIBP @ 8,990'-04/02/18 = = T10 bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" OD. CIBP @ 9,390'-03/20/18 s m Attempted to fish with overshot on 1-3/4"CT 05/24/16. Tyonek Perfs:I =ti^ MD ND Ft 8,879'-8,899' 4,293'-4,310' 20 ft 2-7/8" 6spf 60°phase(04/03/18) Cast Iron Bridge Plug @ 11,470' ''' 9,005'-9,020' 4,403'-4,417 17 ft 2-7/8" 6spf 60°phase(03/21/18) '�- 9,457'- 9,482' 4,825-4,849' 25 ft 3-3/8" 6spf 60°phase(11/21/07) Formation Tops: = se= 9,482'- 9,511' 4,849'-4,877' 29 ft 3-3/8"6spf 60°phase(11/20/07) Formation Depth s Beluga 10,105-10,127' 5,464-5,488' 24 ft 3-3/8"6spf 60°phase(11/15/07) Tyonek T1 7,133'MD 3,250'ND (Frac'd May 20,2008) Tyonek T2 8,554'MD 4,025'ND Tyonek T3 9,918'MD 5,280'ND 11,537'11,568' 6,898'6,929' 61 ft 3 3/8"6spf 60°phase(10/19/07) TD 12,081'MD 7,437'ND m PBTD 12,081'MD 8,990'MD 7,43T ND 4,390'ND Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska Countr USA Perforations(MD): 8,879'-10,127' Perf(TVD): 4,293'-5,488' Angle a KOP&Depth: 5°/100 ft ft 196' Angle a Perfs: 16° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) Rid 21'(AGL) Revised by: Donna Ambruz Revision Date: 04/26/18 • • GO - 6 PROPOSED Ninilchik Unit 2,975'FSL, 2,988'FEL SCHEMATIC Sec.23, TIN, RI3W, S.M. Conductor Hilcorp Alaska,1 LC 20" K-55 133 ppf PE "; Top Bottom I MD 0' 98' Permit#: 207-096 P I L TVD 0' 98' API#: 50-133-20571-00-00 Surface Casing Prop.Des: ADL 389737 9-5/8" L-80 40 ppf BTC KB Elevation: 187 (21'AGL) r T Bottom X: 229,025.05(NAD 27 MD 0' 2,999' * TVD 0' 1,788' Y: 225,4940.94(NAD 27) !i Latitude: 60 09'48.512"N 12-1/4"hole with 690 sks(305 bbls)12 ppg Longitude: 151 29'23.738"W Spud: 07/30/2007 TD: 09/07/2007 Intermediate Casing Rig Released: 09/21/2007 @ 10:00 hrs. 7" L-80 26 ppf Mod Butt TOp Bottom WBS#: DD.06.15534.CAP.CMP MD 0' 9,038' 1/‘. " TVD 0' 4,433' - _ PC. 8-3/4"hole with 289 sks(126 bbls)12.5 ppg TOC±6,800' Lead 8145 sks(30 bbls)15.8 ppg Tail,did Baker Chemical Infection Nipple / @ 2,382'MD(Top) R 3 Tie-backTubinq 5.930"OD/3.858"ID;8,430 psi burst 114":.. 4-1/2" L-80 12.6 ppf Hydril 563 /,7500 psi collapse ili - ,*1' �.r Top Bottom '/i MD 0' 8,842' ND 0' 4,261' -- B120 o�� KOP @ 196'MD/TVD B131 Liner Build 5.0°/100'from 200'-1583'MD 4-1/2" L-80 12.6 ppf Hydril 563 Hold 67°from 1,583'-7,354'MD - B135 Top Bottom Drop 2.5°/100'to 10,120'MD ^,per* ''"r� T2 MD 8,842' 12,069' Hold 0°from 10,120'to TD at 10,090'MD ' ND 4,261' 7,437' Azimuth:290.931° y";"' - - T2 7"hole with 20 bbl MCS-43 spacer with red a T3 dye followed by 195 sks(100 bbls)10.5 ppg �.w' "`_'" T5A cement,Plug failed,100%Returns. 5-8 bbls `ZXP Liner Packer with 15'Tieback Extension T6 @ 8,830.24'MD(Top) . `Flex-Lock Liner Hanger @ 8,862.31'MD(Top) /;,±"....: -.-....i., T6A * Velocity String Fish Details `Marker Joint Top @ 9,925.5'MD(19'long) k w: T7 1-3/4" HO-70 0.134 wall thickness `Marker Joint Top @ 10,929.5'MD(19.5'long) ' g- =.1ui Top Bottom `Landing Collar Top @11,983.91' (1.53'Long) " - - T8 MD 9,398' 10,100' (Chemical Cut) *Float Collar Top @ 12,025.56' (1.55'Long) i'I' "' `Float Shoe Top @ 12,066.95 (2.05'Long) :ti .. BHA consisting of coil grapple.68'L X 2.625"OD,straight s �' at,-,-. bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L �(q, S, X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" t. '3 lcnqti• OD. M CIBP @ 8,870'w/25'cement -------- V Attempted to fish with overshot on 1-3/4"CT 05/24/16. Fr gariesirm T9 MD TVD Ft CIBP @ 8,990'-04/02/18 a a T10 Beluga Perfs: a a== B120 17,408'-±7,427' 13,339'-13,356' 19 ft 2-7/8"6spf 60°phase(Proposed) 8131 17,528'-±7,540' 13,397'-13,402 12 ft 2-7/8"6spf 60°phase(Proposed) ' CIBP @ 9,390'-03/20/18 1 8135 ±7,903'-17,923' 13,584'-±3,596' 20 ft 2-7/8"6spf 60°phase(Proposed) I'- Tyonek Perfs: i , T2 ±8,006-±8,018' ±3,644'-±3,652' 8 ft 2-7/8"6spf 60°phase(Proposed) T2 ±8,030'-18,060' 13,659'-±3,671' 12 ft 2-7/8"6spf 60°phase(Proposed) =c) == T3 ±8,235'-±8,250' ±3,792'-±3,802' 10 ft 2-7/8"6spf 60°phase(Proposed) T5A ±8,364'-±8,374' 13,882'-±3,889' 10 ft 2-7/8"6spf 60°phase(Proposed) Cast Iron Bridge Plug @ 11,470' *.; , T6 ±8,482'-±8,501 ±3,970'-±3,984' 19 ft 2-7/8"6spf 60°phase(Proposed) T6A ±8,650'-18,669' ±4,101'-14,117' 19 ft 2-7/8"6spf 60°phase(Proposed) T7 18,748'-t8,767' 14,182'-14,198' 19 ft 2-7/8" 6spf 60°phase(Proposed) Formation Tops: =Isc s T8 ±8,803'-18818' ±4,228'-±4,241' 15 ft 2-7/8"6spf 60°phase(Proposed) Formation Depth TO 8,879' 8,800' 4,203'4,310' 20 ft 2 7/8" 6spf 60°phace(04/03118) Beluga ItiUT T10 9,005' 9,020' 4,403' 4,417' 17 ft 2 7/8" 6spf 60°phase(03/21/44 Tyonek T1 7,133'MD 3,250'TVD Tyonek T2 8,554'MD 4,025'ND _ _ Tyonek T3 9,918'MD 5,280'TVD Tp PBTD 9,182' 9,511' 4,819'1,877' 29 ft 3 3/8" 6spf 60°phaso(11/20/07) TD 12,081'MD 7,437'ND 12,081'MD 8,990'MD 10,103' 10,127' 5,464'5,188' 21 ft 33/8" 6spf 60°phase(11/15/07) 7,437'ND 4,390'ND (Frac'd May 20,2008) 11,5'°7'11,568' 6,898'6,929' 61 ft 3 3/8" 6spf 60°phaco(10/19/07) Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska Country:1 USA Perforations(MD): ±7,408'-10,127' Perf(TVD): ±3,339'-5,488' Angle @ KOP&Depth: 5°/100 ft @ 196' Angle @ Perfs: 16° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) I RKI 21'(AGL) Revised by: Donna Ambruz Revision Date: 5/10/18 • • Ninilchik Unit GO#6 Current HirtMaxim,tu: 01/19/2018 Ninllchlk Unit Tubing hanger,M8-235,11 X GO 86 4.909 MCA lift X 4 K IBT susp, 20 X95/8 X 7 X475 w/4"Type H BPV profile,2- '4 continuous control lines 6.5"Extended neck Tree cap,Otis,4 1/16 5M FE X 6'rf Otis Quick Union r"6'r Valve,Swab, 3' VG-M,41/165M FE,HWO, r,•, c �� ,¢Jj$c�'‘ �� DD trim —AI \,e• � F,' �, '6O IP Jatib$ Ja`,5ti� oQe oo '1oo,��P 1111ur JVD JV\SQO P.Fe \ — Tee,stdd,4 SM X ■ ,. 31/85M 5M / �7, Valve,upper master, ^� VG-M,4 1/16 5M FE,HWO, H _ 410 DD trim �:. 11.. mi ern Term 2 1/16 5M Wing section w/ . Pneumatic Sly • w u Valve,master, tN t 4 1/16 SM FE,,HWO, DD DD trim Adapter,Vetco,11 5M stdd X fI'tt r4 1/8 5M stdd top,prepped f/6.5"extended neck hanger Multibowl,Vetco MB-235, '..-r�•i1 �'� 11 3M stdd bottom X . �� Cr►.w.. 115M FE top,w/ 2-2 1/16 5M 550,1-control 11T� line exit ='r�rr �� jarlr • - Starting head, ,7t Vetco MB-235 �. 113M X95/8 VG-Loc ! 11111.161111 bottom,w/2-2"LPO u. , I I. 20" 9 5/8" r 4.5" • . II Ninilchick GO-06 01/19/2018 Il*kerp 4t444.1.1.1: is p. .,• iiirr 'im s iIlu 1i4 Coiled Tubing HR580 Injector Head&Gooseneck fl. iVI i1 Weight=12,850 lbs EilEE I -- I •\�4SVA•=I r' ,r ll , � f 4-1/16"10K Conventional Stripper Nail WI JUILEart 4 5K C062 Lubricator WH PSI 2 1502 x 2-1/16 1 OK re Flanged Valve 0 4 5K C062 x 4-1/16"10K Flange (Manual) 2-1/1610Kx2-1/16�tt - 4-1/16"10K Combi BOP 10K Ranged)alve .C.�.�. I , Top Set:Blind/Shear Manus Second Set:Pipe/Slip ,.C. . ■..,I 4-1/16"10K Flow Cross Manual 2x2 Valve 1:2 1502 x 2-1/16"10K Flange ilIO `CONIN11101§0110, / Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 2 2-1/16"10K x 2-1/16"10K Flange Manual 2x2 Valve 4:2 1502 x 2-1/16"10K Flange El 4-1/16"10K x Wellhead Adapter Flange 11100 ■ VW.. 4 Wellhead t�, • • gj CO • . 3 D _ o D 1 C G U ,I Q z m o E 1 7 F .3 (n o z , o, C U L, Z e-aa N ii NW J Eg �i V V o s SSI$ V g 11: pgpg (NI I i 7111"004 • z A A O Li o C U J O d H I I I I d]f:1 t IIII Ini 111 IIII milti3 II iii lit mi IIIIIII•"•I,I 166441 w , Ilii fl o n. z c 0 E- o_o_ 0 1- 1 E •Iv R A V • Y g F...„2, r a j € 1 (e s IIPrn c Ni C 12 a oc lt VNZ O ii wtl N 1E1 • STANDARD WELL PROCEDURE IiIioi ,AI .L=�.HA; NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 41111 S GO - 6 PROPOSED Ninilchik Unit 2,975'FSL, 2,988'FEL SCHEMATIC Sec.23, TIN, RI3W, S.M. Conductor Io flacon)Alaska,LLC r 20" 133 m PE ' I L d + �► Top Bottom MD 0' 98' TVD 0' 98' Permit#: 207-096 API#: 50-133-20571-00-00 Surface Casing Prop.Des: ADL 389737 1 9-5/8" L-80 40 ppf BTC KB Elevation: 187' (21'AGL) 70' Bottom MD 0' 2,999' X: 229,025.05(NAD 27) .s., TVD o' 1,788' Y: 225,4940.94(NAD 27) f, Latitude: 60 09'48.512"N 4\ 12-1/4"hole with 690 sks(305 bbls)12 ppg Longitude: 151 29'23.738"W Spud: 07/30/2007 TD: 09/07/20071 Intermediate Casing 7" L-80 26 ppf Mod Butt Rig Released: 09/21/2007 @ 10:00 hrs. r -13p Bottom WBS#: DD.06.15534.CAP.CMP 0' 9,038' ND/ 0' 4,433' • 8-3/4"hole with 289 sks(126 bbls)12.5 ppg Lead &145 sks(30 bbls)15.8 ppg Tail,did • Baker Chemical Infection Nipple @ 2,382'MD(Top) Tie-backTubinq 5.930"0D/3.858"ID;8,430 psi burst - 4-1/2" L-80 12.6 ppf Hydril 563 /,7500 psi collapse Tg Bottom MD 0' 8,842' " ' ND 0' 4,261' , •� s. B120 KOP @ 196'MD/ND •r' - - B131 Liner Build 5.0°/100'from 200'-1583'MD * =:,,`,.:...,- 4-1/2" L-80 12.6 ppf Hydril 563 Hold 67°from 1,583'-7,354'MD .". 2112511111= B135 TQQ Bottom Drop 2.5°/100'to 10,120'MD ¢ Yy`„ 72 MD 8,842' 12,069' Hold 0°from 10,120'to TD at 10,090'MD ND 4,261' 7,437' 'Azimuth:290.931° °n - T2 7"hole with 20 bbl MCS-43 spacer with red ..fps - -- 13 dye followed by 195 sks(100 bbls)10.5 ppg % - T5A cement,Plug failed,100%Returns. 5-8 bbls *ZXP Liner Packer with 15'Tieback Extension • - - T6 @ 8,830.24'MD(Top) !,'a `- - *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) --;� T6'4 Velocity String Fish Details *Marker Joint Top @ 9,925.5'MD(19'long) T7 1-3/4" HO-70 0.134 wall thickness *Marker Joint Top @ 10,929.5'MD(19.5'long) '' ''i-i Igp Bottom *Landing Collar Top ( Long) t Y,*>` - @ 11,983 91' 1.53' � 18 MD 9,398' 10,100' (Chemical Cut) *Float Collar Top @ 12,025.56' (1.55'Long) d *Float Shoe Top @ 12,066 95 (2.05'Long) BHA consisting of coil grapple.68'L X 2.625"OD,straight - bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L tt� X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" • , ', Attempted to fish with overshot on 1-3/4"CT 05/24/16. CIBP @ 8,870'w/25'cement a 19 MD TVD Ft CIBP @ 8,990'-04/02118 T10 Beluga Perfs: = == 8120 17,408'-17,427' 13,339'-±3,356' 19 ft 2-7/8"6spf 60°phase(Proposed) I _, i, 6131 ±7,528'-±7,540' ±3,397'-±3,402' 12 ft 2-7/8"6spf 60°phase(Proposed) CIBP @ 9,390'-03/20/18 B135 ±7,903'-17,923' ±3,584'-±3,596' 20 ft 2-7/8"6spf 60°phase(Proposed) ac Tvonek Perfs; 1. T2 18,006'-±8,018' 13,644'-13,652' 8 ft 2-7/8"6spf 60°phase(Proposed) 5 7 T2 ±8,030'-±8,060' 13,659'-±3,671' 12 ft 2-7/8"6spf 60°phase(Proposed) T3 ±8,235'-±8,250' ±3,792'-±3,802' 10 ft 2-7/8"6spf 60°phase(Proposed) T5A ±8,364'-±8,374' ±3,882'-±3,889' 10 ft 2-7/8"6spf 60°phase(Proposed) T6 ±8,482'-±8,501' ±3,970'-13,984' 19 ft 2-7/8"6spf 60°phase(Proposed) Cast Iron Bridge Plug @ 11,470' i T6A ±8,650'-±8,669' ±4,101'-±4,117' 19 ft 2-7/8"6spf 60°phase(Proposed) C.. T7 ±8,748'-±8,767' ±4,182'-±4,198' 19ft 2-7/8"6spf 60°phase(Proposed) Formation Tops: T8 ±8,803'-±8818' ±4,228'-±4,241' 15 ft 2-7/8"6spf 60°phase(Proposed) Formation Depth T9 8,879' 8,890' 4,293' 1,310' 20 ft 2 7/8" 6cpf 60°phase(01/03/18) Beluga i,- , T10 9,005' 9,020' 1,103' 1,417' 17 ft 2 7/8" 6spf 60°phase(03/21/18) Tyonek T1 7,133'MD 3,250'ND Tyonek T2 8,554'MD 4,025'ND 9,157' 9,182' 1,825'1,819' 25 ft 3 3/8"6spf 60°phase(11/21/07) Tyonek T3 9,918'MD 5,280'ND 7p PBTD 9,182' 9,511' 1,849'1,877' 29 ft 3 3/8" 6spf 60°phace(11/20/07) TD 12,081'MD 7,437'ND 12,081'MD 8,990'MD 10,103' 10,127' 5,161'5,488' 21 ft 3 3/8" 6spf 60°phase(11/15/07) 7,43T ND 4,390'ND (Frac'd May 20,2008) 11,537'11,568' 6,898'6,929' 61 ft 3 3/8" 6cpf 60°phase(10/19/07) Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska I Country:I USA Perforations(MD): ±7,405'-10,127' Perf(TVD): ±3,339'-5,488' Angle A KOP&Depth: 50/100 ft @ 196' Angle @ Perfs: 16° Date Completed: 11115/2007 Ground Level: 166' (AMSL) I RK 21'(AGL) Revised by: Donna Ambruz Revision Date: 5/10/18 • . GO - 6 PROPOSED Ninilchik Unit 2,975'FSL, 2,988'FEL SCHEMATIC Sec.23, T1 N, R13W, S.M. Conductor Hilcorp Alaska,LLC 20" T133ppf PE Toopp Bottom Permit#: 207-096 _I] i' L MD 0'T98' VD 0' 98' API#: 50-133-20571-00-00 Surtace Casing Prop.Des: ADL 389737 9-5/8" l 4o ppf BTC KB Elevation: 187 (21'AGL) MD TO' B2 999' X: 229,025.05(NAD 27) a ND o' 1,788' Y: 225,4940.94(NAD 27) ) Latitude: 60 09'48.512"N 1 12-1/4"hole with 690 sks(305 bbls)12 ppg Longitude: 151 29'23.738"W 1)4, Spud: 07/30/2007 TD: 09/07/2007 {( Intermediate Casing Riq Released: 09/21/2007 @ 10:00 hrs. 7" L-80 26 ppf Mod Butt Top Bottom WBS#: DD.06.15534.CAP.CMP MD 0' 9,038' ND 0' 4,433' -k _ 8-3/4"hole with 289 sks(126 bbls)12.5 ppg Lead &145 sks(30 bbls)15.8 ppg Tail,did Baker Chemical Injection Nipple ;, @ 2,382'MD(Top) ;." Tie-backTubinq 5.930"OD/3.858"ID;8,430 psi burst +, +„* 4-1/2" L-80 12.6 ppf Hydril 563 /,7500 psi collapse `1# MD TO' Bottom8,842' ND 0' 4,261' ---.-.. B120 KOP @ 196'MD/ND -�_�- Liner _ B131 Build 5.0°/100'from 200'-1583'MD - -,-_-_v_. =.- 4-1/2" L-80 12.6 ppf Hydril 563 Hold 67°from 1,583'-7,354'MD , - _,iB135 DR Bottom Drop 2.5°/100'to 10,120'MD ,,,1 ==.:"--,"7-: T2 MD 8,842' 12,069' Hold 0°from 10,120'to TD at 10,090'MD ND 4, ' 7,437' Azimuth:290.931° y I:A T2 7"hole with 20 bbl MCS-43 spacer with red __ _ T3 dye followed by 195 sks(100 bbls)10.5 ppg --mss { TSA cement,Plug failed261,100%Returns. 5-8 bbls 'ZXP Liner Packer with 15'Tieback Extension 11°�efi -- T6 @ 8,830.24'MD(Top) " . t - `Flex-Lock Liner Hanger @ 8,862.31'MD(Top) y;.M ,i., T6A Velocity String Fish Details 'Marker Joint Top @ 9,925.5'MD(19'long) a: - -:- -17 1-3/4" HO-70 0.134 wall thickness `Marker Joint Top @ 10,929.5'MD(19.5'long) ;..,.q ci_ Tog Bottom 'Landing Collar Top @ 11,983.91' (1.53'Long) _ 18 MD 9,398' 10,100' (Chemical Cut) "Float Collar Top @ 12,025.56' (1.55'Long) 1;,i. "Float Shoe Top @ 12,066.95 (2.05'Long) + =x°5 = - BHA consisting of coil grapple.68'L X 2.625"OD,straight bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L i+ . !r ,+ X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" d i OD. CIBP @ 8,870'w/25'cement y. *`t1 ' Attempted to fish with overshot on 1-3/4"CT 05/24/16. =m sac 19 MD ND Ft CIBP @ 8,990'-04/02/18 T10 Beluga Peas' -..., a B120±7,408'-±7,427' ±3,339'-±3,356' 19 ft 2-7/8"6spf 60°phase(Proposed) 6131 ±7,526'-±7,540' ±3,397'-±3,402' 12 ft 2-7/8"6spf 60°phase(Proposed) CIBP @ 9,390'-03/20/18 ' '"-1 6135 ±7,903'-±7,923' ±3,584'-±3,596' 20 ft 2-7/8"6spf 60°phase(Proposed) Tyonek Perfs: . ' I T2 ±8,006'-±8,018' ±3,644'-±3,652' 8 ft 2-7/8"6spf 60°phase(Proposed) r T2 ±8,030'-±8,060' ±3,659'-±3,671' 12 ft 2-7/8"6spf 60°phase(Proposed) T3 ±8,235'-±8,250 ±3,792'-±3,802' 10ft 2-7/8"6spf 60°phase(Proposed) T5A ±8,364'-±8,374' ±3882'-±3,889' 10 ft 2-7/8"6spf 60°phase(Proposed) Cast Iron Bridge Plug @ 11,470' T6 ±8,482'-±8,501' ±3,970'-±3,984' 19 ft 2-7/8"6spf 60°phase(Proposed) - T6A ±8,650'-±8,669' ±4,101'-±4,117' 19 ft 2-7/8"6spf 60°phase(Proposed) T7 ±8,748'-±8,767' ±4,182'-±4,198' 19 ft 2-7/8"6spf 60°phase(Proposed) Formation Tops: 18 ±8,803'-±8818' ±4,228'-±4,241' 15 ft 2-7/8"6spf 60°phase(Proposed) Formation Depth T9 8,879' 8,899' 4,293' 1,310' 20 ft 2 7/8" 6spf 60°phasc(04/03/18) Beluga' T10 9,005' 9,020' 1,103' 4,117' 17 ft 2 7/8" 6s f 60° Tyonek Ti 7,133'MD 3,250'ND ''A..' p phase(03/21/18) Tyonek T2 8,554'MD 4,025'ND 9,157' 9,482' 1,825'1,849' 25 ft 3 3/8" 6spf 60°phace(11/21/07) Tyonek T3 9,918'MD 5,280'ND TD PBTD 9,482' 9,511' 4,819'1,877' 29 ft 3 3/8"6spf 60°phaco(11/20/07) TD 12,081'MD 7,437'ND 12,081'MD 8,990'MD 10,103' 10,127 5,461'5,188' 21 ft 3 3/8"6cpf 60°phase(11/15/07) 7,437'ND 4,390'ND )Frac'd May 20,2008) 11,537'11,568' 6,898'6,929' 61 ft 3 3/8"6cpf 60°phase(10/19/07) Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska I Country:I USA Perforations(MD): ±7,408'-10,127' Perf(TVD): ±3,339'-5,488' Angle @ KOP&Depth:, 5°/100 ft @ 196' Angle @ Perfs: 16° Date Completed: 11/15/2007 Ground Level. 166' (AMSL) RK 21'(AGL) Revised by: Donna Ambruz Revision Date: 5/10/18 • • Davies, Stephen F (DOA) From: Cody Terrell <cterrell@hilcorp.com> Sent: Tuesday, May 15, 2018 10:58 AM To: Davies, Stephen F (DOA) Subject: RE: GO 6 (PTD#207-096; Sundry 318-198) - Proposed Perfs Steve- the proposed perf adds will be entirely within the boundaries of the GO PA and produce only from the GO PA. There are currently no uncommitted tracts within the GO PA, or within 1,500 feet of the proposed perfs. Regards, Cody T. Terrell Landman Hilcorp Alaska, LLC Direct: 907-777-8432 Cell: 713-870-4532 From: Davies,Stephen F(DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, May 14, 2018 5:08 PM To:Cody Terrell<cterrell@hilcorp.com> Subject:GO 6(PTD#207-096; Sundry 318-198)- Proposed Perfs Cody, I'm reviewing Hilcorp's sundry application to potentially add perfs to the GO 6 well that are up to 945' shallower than existing perfs in the well. Are there any uncommitted tracts within the Ninilchik Unit that lie within 1500'of these proposed perfs? (See CO 701C, Rule 3B). Thank you, Steve Davies AOGCC 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,us- 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 forwardi g it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 1 • 2L3--7 _ c)9 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, May 14, 2018 5:08 PM To: 'Cody Terrell' Subject: GO 6 (PTD#207-096; Sundry 318-198) - Proposed Peas Cody, I'm reviewing Hilcorp's sundry application to potentially add perfs to the GO 6 well that are up to 945' shallower than existing perfs in the well. Are there any uncommitted tracts within the Ninilchik Unit that lie within 1500' of these proposed perfs? (See CO 701C, Rule 3B). Thank you, Steve AOGCC Davies SGOT© MAY 2 3202 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 Steve Davies at 907-793-1224 or steve.davies(caalaska.gov. 1 STATE OF A RECEIVED AKA OIL AND GAS CON ERVAT ON COARSION REPORT OF SUNDRY WELL OPERATIONS APR 27 2018 1.Operations Abandon Li Plug Perforations U Fracture Stimulate Li Pull Tubing U ;!; . . wn Li Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Chang' p i felrf ram ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: CT N2 ❑., 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC lorato❑ment Develo D Exploratory p ry ❑ 207-096 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic Service ❑ 6.API Number: AK 99503 50-133-20571-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL-389737;FEE-PRIVATE Ninilchik Unit G Oskolkoff(GO)6 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Ninilchik/Beluga-Tyonek Gas 11.Present Well Condition Summary: 8,990'; Total Depth measured 12,081 feet Plugs measured 9,390'; 11,470 feet true vertical 7,437 feet Junk measured 9,398'(fish) feet Effective Depth measured 8,990 feet Packer measured 8,842 feet true vertical 4,390 feet true vertical 4,261 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060psi 1,500psi Surface 2,978' 9-5/8" 2,999' 1,788' 5,750psi 3,090psi Intermediate 9,017' 7" 9,038' 4,433' 7,240psi 5,410psi Production Liner 3,227' 4-1/2" 12,069' 7,437' 8,430psi 7,500psi Perforation depth Measured depth See Attached Schematic e� True Vertical depth See Attached Schematic r"` Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 8,842'MD 4,261'TVD Packers and SSSV(type,measured and true vertical depth) Baker ZXP;N/A 8,842'MD 4,261'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 20 0 Subsequent to operation: 0 0 0 0 184 14.Attachments(required per 20 PAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 2 Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 318-084 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer(a.hilcoro.com at/f- Authorized Signature: Date: /L7/('t Contact Phone: 777-8420 Form 10-404 Revised 4/2017 S ( /J" RBDMS CMAY 012018 Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 E-Line 50-133-20571-00 207-096 3/10/18 4/3/18 Daily Operations: 03/10/2018-Saturday Move Halliburton equipment from FC 4 to location. PTW and JSA. Spot and rig up equipment. PT 250 psi low and 2,000 psi high.TP- 625 psi. RIH w/3.75" OD fluted centralizer, roller stem and tag top of fish at 9,394'. Had to run in hole between 40 and 60 fpm from 1,600' to 7,400' due to angle. POOH. Ran correlation log and send to town. RIH w/PT tool and roller stem to 3,000' looking for fluid level. Found fluid level at 2,720'. Ran log from 2,000' to 3,000' and sent to town. POOH. RIH w/3" bailer and roller stem to 2,800' to get fluid sample. POOH with sample. Left sample at GO Pad until Monday. Rig down lubricator and wire line truck for Swanson River job in the morning. Halliburton is leaving crane here. We are planning to be back here Monday morning. 03/12/2018 - Monday PTW and JSA. Rig up equipment. PT 250 psi low and 2,000 psi high.TP - 612.8 psi (Crane was left spotted while taking E-Line truck to Swanson to perf yesterday). RIH w/roller stem, wt bar, CCL/GR and 2-7/8" x 10' spent dummy gun to 4,350'. 70 and 71 deg angle was approx. 1,800 to 2,200' which went thru with no problem at 30 to 38 fpm from 1,600' to 4,350'. Called town and decision made to call that good because we have to get GO-1 PLT done today and we wouldn't be out of hole until around 2 PM. POOH. Had no trouble running to 4,350'. From 1,700' to 7,400' is approx. 69 to 71 deg. Rig down and move to GO-1. 03/19/2018- Monday PTW,JSA and SIMOPS with SLB and HLB. Spot and rig up HLB lubricator and SLB N2 hard lines. PT both to 4500 psi. TP - 618 psi. Start pushing fluid away with N/2 and going in hole with GPT tool and roller stem. Got to 2600' and tools slowed down to 6 to 10 fpm. Saw fluid level at 2890'. I stopped N2 from pumping and had them shut down at 1130 hrs. N2 was pumping 2000 scf at 2420 psi when shut down. RIH and found fluid level at 4930'.After approx. 8000' tools started falling at normal rate. The angle is approx. 69 deg from 1600' to 7600'. At 8000', I had N2 start pumping again (2030 hrs) while running GPT tool to 9390'. Sat at 9390' waiting on fluid level to pass by. At 2200 hrs fluid level went by 9390'. Tubing pressure on gauge was 3100 psi. On scada TP was 2329.3 and building. SLB pumped 226,500 scf total and 2532 gals total. We have approx. 580 gals left. When N2 started back up the second time it was 2400 psi at 2000 scf rate and finished at 3340 psi at 2000 scf/m. Rig down HLB lubricator and SLB hard line from tree. Closed masters and swab. Will have HLB back in AM and will call SLB N2 and give them an update on whether we need them or not. 03/20/2018-Tuesday PTW and JSA. Rig up lubricator. Wait on different detonator for plug. Detonator arrived and MU 3" OD Magna Range plug for 4-1/2" tubing. PT to 250 psi low and 2000 psi high.TP- 2530 psi. RIH with plug at 150 fpm until we get to 1600' and line speed has slowed to 25 fpm (69 deg angle). Starting at 3450' line speed is between 15 to 20 fpm. Line speed slowed down to 10 to 13 fpm from 5150' to 7600'. From 7600' to 8100' line speed was22 fpm, from 8125' to 9000' line speed 44 fpm and down to 9414' we ran at 56 fpm.Tied in to yesterday's log and ran correlation log. From CCL/GR to top of plug is 12.7'. Logged up to stop depth at 9377.3' which put top of plug at 9390'. Set plug with 2394.6 psi tubing pressure. Lost 200 lbs of line tension when plug set. Picked up 30' and went back down and tagged plug. POOH. Everything looks good. Rig down lubricator and secure well. Will be back at 0800 hrs to perforate. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 E-Line 50-133-20571-00 207-096 3/10/18 4/3/18 Daily Operations: 03/21/2018-Wednesday PTW and JSA. Rig up lubricator and PT to 250 psi low and 2000 psi high.TP-2384.9 psi. Dump 15 gals diesel in well to cut e-line grease. RIH w/2-7/8"x20' HC, 6 spf, 60 deg phase and tie into plug log. Added 3-1/4" roller stem to tools and 2-1/8" roller stem. RIH averaging 65 fpm down to 9160'. Run correlation log and send to town. Blow down tubing pressure from 2388 psi to 1404 psi. Get ok to perf from 9005' to 9025'. CCL/GR to top shot is 9.8' making stop depth at 8995.2'. Spot and fire gun from 900.5'to 9025' with 1404 psi on tubing (1505 hrs). After, 5 min - 1410.3 psi, 10 min - 1411.3 psi and 15 min - 1411.7 psi. Good indication shots fired. POOH. All shots fired and gun was wet. SLB N2 came and got equipment. Rig down lubricator and turn well over to field. Finish up with rig down. 04/02/2018- Monday PTW,JSA and PJSM with SLB N2 crew. Spot equipment for HLB E-line and SLB N2. Rig up lubricator and hard lines. Pressure test both to 250 psi low and 4,500 psi high. TP 400 psi. RIH w/GPT tool and roller stem down to 8,840'.Tied into OHL and then started pushing fluid away with N2. Saw fluid go by and followed it to 9,001'. Pumped N2 for another 10 min and shut down N2. Waited 10 min and no fluid came back. Highest pressure reached was 2,700 psi at 2,000 scf/m. SLB used 1,670 gals of N2. POOH. Fluid pushed with no problem. POOH. Pumped 15 gals of diesel in • lubricator and open it up to well. Well had 2,400 psi on tubing. RIH w/3-1/2" OD GEO plug and tied into OHL. Ran correlation log and then went back down to 8,990'. Brought N2 back on line and pump at 2,000 scf/m at 2,700 psi for 15 min.Then pulled up to stop depth at 8,978.1' (CCL/GR to top of plug is 11.9'). Set plug at 8,990'. Lost 250 lb line tension when plug set. Picked up 30' and went back down and tagged plug.Tubing pressure was 2,600 psi when plug was set. We used 20K scf(1,800 gals) of N2. We have 1,200 gals left. I had SLB N2 rig line off well and leave equipment just in case something happens. I told them I would call in the morning. POOH. Rig down lubricator and secure well. Will be back in AM to perforate. Out of hole everything looks good. 2018-Tuesday y PTW and JSA. Rig up lubricator. Pressure test to 250 psi low and 3,000 psi high.TP - 2,425.2 psi. Pump 10 gals of diesel down hole. RIH w/2-7/8" x 20' HC, 6 spf, 60 deg phase and tie into plug log. Run correlation log and send to town. Get ok to perf from 8,879' to 8,899'. Blew tubing down to 1,360 psi. Spotted and fired gun. After 5 min pressure was 1,375 , psi, 10 min - 1,378.2 psi and 15 min - 1,381.6 psi. Got good indication gun went off POOH. Fired gun at 1134 hrs. All shots fired and gun was dry.TP- 1,398 psi. Rig down lubricator and equipment. SLB N2 came out earlier and got their equipment. TP- 1,406.2 psi. l0 • II GO - 6 Ninilchik Unit SCHEMATIC 2,975'FSL, 2,988'FEL Sec.23, TIN, RI3W, S.M. Hilcorp Alaska,LLC Conductor 'I t!' L 20" K-55 133 ppf PE Tom Bottom MD 98' Permit#: 207-096 7�" ND 0' 98' API#: 50-133-20571-00-00 Prop.Des: ADL 389737 it KB Elevation: 187' (21'AGL) N ',"1 Surface Casing X: 229,025.05(NAD 27) R it 9-5/8" L-80 40 ppf BTC 0' Bottom Y: 225,4940.94(NAD 27) MD T 0' 2,999' Latitude: 60 09'48.512"N 1, TVD 0' 1,788' Longitude: 151 29'23.738"W Spud: 07/30/2007 if g 12-1/4"hole with 690 sks(305 bbls)12 ppg TD: 09/07/2007 , Type 1 cement with 4lbbls cement to surface. Rig Released: 09/21/2007 @ 10:00 hrs. K WBS#: DD.06.15534.CAP.CMP Intermediate Casing 7" L-80 26 ppf Mod Butt Tom Bottom MD 0' 9,038' A TVD 0' 4,433' Baker Chemical Injection Nipple 8-3/4"hole with 289 sks(126 bbls)12.5 ppg @ 2,382'MD(Top) Lead &145 sks(30 bbls)15.8 ppg Tail,did 6.930"OD/3.858"ID;8,430 psi burst - not bump plug,100%returns,floats held. /,7500 psi collapse yy € fit+ z ( ti Tie-backTubinq 'Y 4-1/2" L-80 12.6 ppf Hydril 563 KOP @ 196'MD/ND 0 "Ipg Bottom Build 5.0°/100'from 200'-1583'MD . MD 0' 8,842' Hold 67°from 1,583'-7,354'MD '�, TVD 0' 4,261' Drop 2.5°/100'to 10,120'MD Hold 0°from 10,120'to TD at 10,090'MD Azimuth:290.931° Liner 4i-112" L-80 12.6 ppf Hydril 563 T� Bottom MD 8,842' 12,069' 4 TVD 4,261' 7,437' 7"hole with 20 bbl MCS-43 spacer with red f dye followed by 195 sks(100 bbls)10.5 ppg *ZXP Liner Packer with 15 Tieback Extension I cement,Plug failed,100%Returns. 5-8 bbls @ 8,830.24'MD(Top) ' A cement returns. *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) *Marker Joint Top @ 9,925.5'MD(19'long) f *Marker Joint Top @ 10,929.5'MD(19.5'long) N - "i *Landing Collar Top @ 11,983.91' (1.53'Long) il! *Float Collar Top �' Velocity String Fish Details @ 12,025.56' (1.55'Long) 4 *Float Shoe Top @ 12,066 95 (2.05'Long) " 1-3/4" HO-70 0.134 wall thickness r k` Log Bottom MD 9,398' 10,100' (Chemical Cut) T9 a BHA consisting of coil grapple.68'L X 2.625"OD,straight CIBP @ 8,990'-04/02/18 a === T10 bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" 1X--- a OD. CIBP @ 9,390'-03/20/18 2,== Attempted to fish with overshot on 1-3/4"CT 05/24/16. 7,'t s Tvonek Perfs: MD ND Ft s 8,879'-8,899' 4,293'-4,310' 20 ft 2-7/8" 6spf 60°phase(04/03/18) Cast Iron Bridge Plug @ 11,470' I j? 9,005'-9,020' 4,403'-4,417' 17 ft 2-7/8" 6spf 60°phase(03/21/18) .. 9,457-9,482 4,825-4,849' 25 ft 3-3/8"6spf 60°phase(11/21/07) Formation Tops: a === 9,482'-9,511' 4,849'-4,877' 29 ft 3-3/8" 6spf 60°phase(11/20/07) Formation Depth Beluga E. W 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8"6spf 60°phase(11/15/07) Tyonek T1 7,133'MD 3,250'ND +`+• (Frac'd May 20,2008) Tyonek T2 8,554'MD 4,025'ND _ Tyonek T3 9,918'MD 5,280'TVDTD -PBTD 11,537'11,568' 6,808'6,929' 61 ft 3 3/8"6spf 60°phase(10/19/07) TD 12,081'MD 7,437'ND 12,081'MD 8,990'MD 7,437'ND 4,390'ND Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality. Kenai Peninsula Borough State: Alaska I I County' USA Perforations(MD): 8,879'-10,127' Perf(TVD): 4,293'-5,488' Angle A KOP&Depth: 5°/100 ftp 196' Angle A Perfs: 16° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) RKE 21'(AGL) Revised by: Donna Ambruz Revision Date: 04/26/18 • • yw"\OF� Tit, • THE STATE Alaska Oil and Gas , f LASI�;A Conservation Commission Loath oA 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 (4' Q„ Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager scow °' Hilcorp Alaska LLC 3800 Centerpoint Drive, Suite 1400 Anchorage,AK 99503 Re: Ninilchik Field, Beluga-Tyonek Gas Pool,NU GO-6 Permit to Drill Number: 207-096 Sundry Number: 318-084 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Afff\-' Hollis S. French Chair DATED this G day of March,2018. PL's'"."S LL- N&P - 2018 1 • • RECEIVED STATE OF ALASKA FEB 2 ALASKA OIL AND GAS CONSERVATION COMMISSION s 3(e/7,-,,O APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280AOGC'�./ 1.Type of Request: Abandon ❑ Plug Perforations Q - Fracture Stimulate ❑ Repair Well ❑ Operations shutdown 0 Suspend 0 Perforate Q . Other Stimulate 0 Pull Tubing ❑ Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool D Re-enter Susp Well ❑ Alter Casing ❑ Other: CT N2 Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ID. 207-096 ` 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20571-00-00 ` 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.701A ' Will planned perforations require a spacing exception? Yes 0 No 0 Ninilchik Unit G Oskolkoff(GO)6 . 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL-389737 F,� .-r=`t v a,Le-. Ninilchik/Beluga-Tyonek Gas 11. � e)PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,081' " 7,437' - 11,470' . 6,831' • -1,360psi 11,470' 9,398'(fish) Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060psi 1,500psi Surface 2,978' 9-5/8" 2,999' 1,788' 5,750psi 3,090psi Intermediate 9,017' 7 9,038' 4,433' 7,240psi 5,410psi Production Liner 3,227' 4-1/2" 12,069' 7,437' 8,430psi 7,500psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 8,842' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker ZXP;N/A 8,842'MD/4,261'TVD;N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory 0 Stratigraphic ❑ Development 2 Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: March 13,2018 OIL o WINJ ❑ WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS Q WAG ❑ GSTOR 0 SPLUG 0 Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcorp.com // Contact Phone: 777-8420 Authorized Signature: ( Date: e/ar!/'°8 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number Plug Integrity ❑ BOP Test i+ Mechanical Integrity Test 0 Location Clearance ❑ Other: � � Ss� � ith (cr) Post Initial Injection MIT Req'd? Yes ❑ No 0 rr "" lrv 1 .A:f, 1° 7C18 Spacing �SS acin9 Exception Required? Yes 0 No � Subsequent Form Required: 170 - u®1 da.Q04*.NNAPPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 3 ILII 2/4 3 -1e , 5,2•x'Form 10-403 Revised 4/2017 A roved a li ti i the date of approval. Submit Form and PP PP 12N1A6 Attachments in Duplicate • • Well Prognosis Well: GO-6 Hilcorp Alaska,LI) Date:02/26/2018 Well Name: GO-6 API Number: 50-133-20571-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: 03/13/18 Rig: Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-096 First Call Engineer: Ted Kramer (907) 777-8420(0) (985)867-0665 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: Current Surface Pressure: 621 psi Current BHP: — 1,482 psi @ 5,150'TVD (SBHP survey of GO-6 on 4/7/16) Maximum Expected BHP: — 1,887 psi @ 5,274' TVD (Based on SBHP survey of GO-8 on 11/14/15 (T-18 only)) Max. Potential Surface Pressure: — 1,360 psi (Assumed 0.10 psi/ft gas gradient) Brief Well Summary GO-6 was originally drilled as a grassroots well in July 2007 and completed in the Tyonek sands. After initial completion,the lowest intervals were isolated and the upper interval was frac'ed,which doubled production but also brought in water, so a capillary string was installed in July 2008 to help with loading issues. In July 2010,the cap string was removed and the 1-3/4" velocity string was installed.The well stopped producing in 2014 due to loading. In May of 2016 an attempt was made to remove the coil velocity string. The Velocity string was stuck and the bottom of the string(+/-9,400' down)was not recovered. The purpose of this work/sundry is to set a CIBP on top of the current fish at 9,390'. Perforate the T-9 and T-10 • intervals. Hilcorp Requests a waiver from 20 AAC 25.112 (c)(1)(E) requiring that a CIBP in a cased hole be set within 50' of the top perforation. With the fish in the well,the CIBP will be set 67'above the top perforation. oe 1_S Notes Regarding Wellbore Condition ? • Fish at 9,398'. 1-3/4" coil velocity string BHA(see schematic). • Fluid Level to be determined prior to starting Sundry work. Echometer or Slickline PIT survey. Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast(venting Nitrogen during this job). • Ensure all crews are aware of stop job authority. E-line Procedure • • Well Prognosis Well: GO-6 Flilcorp Alaska,LU Date:02/26/2018 1. MIRU e-line and pressure control equipment. PT lubricator to 250 psi low/2,000 psi high 2. PU RIH W/CIBP to 9,390'.Set same. POOH. 3. Pressure up well to 1,500 psi with nitrogen. (Note:This may happen before step#2 if Fluid level is above 9,390'.) — in:.•-sl. =L"• .s `,�-,�-,. 4. PU, RIH with 2-7/8" 6 SPF 60 deg phased perf guns (up to 12 SPF with 2 perf runs). Perforate the following intervals: (Note : well surface pressure may need to be adjusted to achieve desired underbalance.) Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Tyonek T9 ±8,870' ±8,901' ±4,285' ±4,312' 31 Tyonek T10 ±9,001' ±9,025' ±4,400' ±4,421' 24 a. Proposed perfs also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. f. Rule 2 of Conservation Order 701A defines the Ninilchik Beluga/Tyonek Gas Pool as the v intervals common to and correlating between the measured depths of 1,480' in the Paxton #5 well and 9,600' in the Paxton#1 well. Contingency: The GO#6 Well is a high) deviated well. The possibility exists that E-line will not be able to get down to set the • CIBP. If that happens, the—CIBP will be with Coil Tubing. The following procedure will be used should coil be necessary: Coiled Tubing Procedure: 1. Submit 24 hr.witness notification to AOGCC via web base notification. 2. MIRU Coiled Tubing, PT BOPE to 250psi low 4.3,009-psi. ./OC}-, 3. PU CIBP and RIH to 9,398' and tag top of fish. PU to 9,390' and set CIBP. 4. Jet well dry and leave 1,600 psi of N2 on the well for perforating. 5. POOH with coiled tubing. NDMO CTU. Turn well back to E-line to perforate. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Wellhead Diagram 4. CT BOPE Schematic 5. CT Schematic(forward jetting) 6. Standard Well Procedure—Nitrogen Operations . * • • r 11 GO - 6 Ninilchik Unit SCHEMATIC 2,975'FSL, 2,988'FEL Sec.23, T1 N, R13W, S.M. Hilcorp Alaska. LLC - - - Conductor i t _ 20" K-55 133 ppf PE ^+ S:, L Top Bottom Permit#: 207-096 TVD o' 96' API#: 50-133-20571-00-00 Prop.Des: ADL 389737 KB Elevation: 187' (21'AGL) Surface Casing X: 229,025.05(NAD 27) ' 9-5/8" L-80 40 ppf BTC Tio Bottom Y: 225,4940.94(NAD 27) Latitude: 60 09'48.512"N j ND 0' 1,788' Longitude: 151 29'23.738"W ' Spud: 07/30/2007 12-1/4"hole with 690 sks(305 bbls)12 ppg TD: 09/07/2007 Type 1 cement with 4lbbls cement to surface. Rig Released: 09/21/2007 @ 10:00 hrs. WBS#: DD.06.15534.CAP.CMP ;° ti Intermediate Casing 7" L-80 26 ppf Mod Butt Tp Bottom M D 0' 9.038' ND 0' 4,433' Baker Chemical Injection Nipple ' 8-3/4"hole with 289 sks(126 bbls)12.5 ppg @ 2,382'MD(Top) Lead &145 sks(30 bbls)15.8 ppg Tail,did 5.930"OD/3.858"ID;8,430 psi burst not bump plug,100%returns,floats held. /,7500 psi collapse Tie-backTubinq KOP 4-1/2" L-80 12.6 ppf Hydril 563 e 196'MD/ND T� Bottom Build 5.0°/100'from 200'-1583'MD ,, MD 0' 8,842' Hold 67°from 1,583'-7,354'MD ND 0' 4,261' Drop 2.5°/100'to 10,120'MD Hold 0°from 10,120'to TD at 10,090'MD Azimuth:290.931° Liner 4-1/2" L-80 12.6 ppf Hydril 563 Tp Bottom MD 8,842' 12,069' ND 4,261' 7,437' 7"hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks(100 bbls)10.5 ppg s cement,Plug failed,100%Returns. 5-8 bbls *ZXP Liner Packer with 15'Tieback Extension cement returns. @ 8,830.24'MD(Top) *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) . *Marker Joint Top @ 9,925.5'MD(19'long) *Marker Joint Top @ 10,929.5 MD(19.5'long) 'Landing Collar Top @ 11,983.91' (1.53'Lung) *Float Collar Top @ 12,025.56' (1.55'Long) - Velocity String Fish Details *Float Shoe Top @ 12,066.95 (2.05'Long) - _ 1-3/4" HO-70 0.134 wall thickness -lop Bottom MD 9,398' 10,100' (Chemical Cut) BHA consisting of coil grapple.68'L X 2.625"OD,straight bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" Cast Iron Bridge Plug @ 11,470' OD. I ,....=-_ Attempted to fish with overshot on 1-3/4"CT 05/24/16. Tyonek Perfs: = i . MD ND Ft ( 9,457'- 9,482' 4,825'-4,849' 25 ft 3-3/8" 6spf 60°phase(11/21/07) • 9,482'-9,511' 4,849'-4,877' 29 ft 3-3/8" 6spf 60°phase(11/20/07) 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8" 6spf 60°phase(11/15/07) Formation Tops: (Frac'd May 20,2008) Formation Depth Beluga . "_� -�'� 11,537,-1-13668"--6,8681-6,1328' 61 ft 3 3/8" 6spf-60°-phase-)40149/07 Tyonek Ti 7,133'MD 3,250'ND Tyonek T2 8,554'MD 4,025'ND _ Tyonek T3 9,918'MD 5,280'ND TD PBTD TD 12,081'MD 7,437'ND 12,081'MD 11,470'MD 7,437'ND 6,831'ND Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska Countr‘,1 USA Perforations(MD): 9,457'-10,127' Perf(TVD): 4,825'-5,488' Angle @ KOP&Depth: 5°/100 ft @ 196' Angle @ Perfs: 16° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) I RKE 21'(AGL) Revised by: Donna Ambruz Revision Date: 02/27/18 . . • • • GO - 6 PROPOSED Ninilchik Unit 2,975'FSL, 2,988'FEL SCHEMATIC Sec.23, TIN, RI3W, S.M. Hilcorp Alaska,LLC [ LConductor y 20" K-55 133 ppf PE Top Bottom Permit#: 207-096 t MD 0' 98' API#: 50-133-20571-00-00 TVD o' 98' Prop.Des: ADL 389737 f! KB Elevation: 187' (21'AGL) r Surface Casing X: 229,025.05(NAD 27) s 9-5/8" L-80 40 ppf BTC Y: 225,4940.94(NAD 27) Top Bottom MD 0' 2,999' Latitude: 60 09'48.512"N t TVD 0' 1,788' Longitude: 151 29'23.738"W Spud: 07/30/2007 12-1/4"hole with 690 sks(305 bbls)12 ppg TD: 09/07/2007 Type 1 cement with 41 bbls cement to surface. Rig Released: 09/21/2007 @ 10:00 hrs. WBS#: DD.06.15534.CAP.CMP . Intermediate Casing 7" L-80 26 ppf Mod Butt ' "1-3p Bottom MD 0' 9,038' TVD 0' 4,433' Baker Chemical Injection Nipple 8-3/4"hole with 289 sks(126 bbls)12.5 ppg @ 2,382'MD(Top) Lead &145 sks(30 bbls)15.8 ppg Tail, 5.930"OD/3.858"ID;8,430 psi burst not bumpplug,100%returns,floats held.d p /,7500 psi collapse . Tie-backTubinq - 4-1/2" L-80 12.6 ppf Hydril 563 KOP @ 196'MD/TVD Toe Bottom Build 5.0°/100'from 200'-1583'MD MD 0' 8,842' Hold 67°from 1,583'-7,354'MD ND 0' 4,261' Drop 2.5°/100'to 10,120'MD Hold 0°from 10,120'to TD at 10,090'MD , Azimuth:290.931° Liner 4i-1/2" L-802' 12.6 ppf Hydril 563 Top Bottom MD 8,84 12,069' ND 4,261' 7,437' 7"hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks(100 bbls)10.5 ppg "ZXP Liner Packer with 15'Tieback Extension k,. cement,Plug failed,100%Returns. 5-8 bbls @ 8,830.24'MD(Top) cement returns. *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) *Marker Joint Top @ 9,925.5'MD(19'long) *Marker Joint Top @ 10,929.5 MD(19.5 long) *Landing Collar Top @ 11,983.91' (1.53'Long) *Float Collar Top @ 12,025.56' (1.55'Long) Velocity String Fish Details *Float Shoe Top @ 12,066.95 (2.05'Long) _ 1-3/4" HO-70 0.134 wall thickness Top Bottom MD 9,398' 10,100' (Chemical Cut) .L -r= BHA consisting of coil grapple.68'L X 2.625"OD,straight =,.. -10 bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L � X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" �,y OD. Cast Iron Bridge Plug @±9,390' '�h:,`✓ =:.c .=sic Attempted to fish with overshot on 1-3/4"CT 05/24/16. T. v' Tvonek Perfs: MD ND Ft a= ±8,879'-±8,899' ±4,293'-±4,310' 20 ft 2-7/8"6spf 60°phase(Proposed) ±9,005-±9,022' ±4,403'-±4,418' 17 ft 2-7/8"6spf 60°phase(Proposed) Cast Iron Bridge Plug @ 11,470' '.. 9,457'-9,482' 4,8254,849' 25 ft 3-3/8"6spf 60°phase(11/21/07) Formation Tops: =lc s 9,482'-9,511' 4,849'4,877' 29 ft 3-3/8"6spf 60°phase(11/20/07) Formation Depth :�'� Beluga ��°°� 14 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8"6spf 60°phase(11/15/07) Tyonek Ti 7,133'MD 3,250'ND �l6r' (Frac'd May 20,2008) Tyonek T2 8,554'MD 4,025'ND Tyonek T3 9,918'MD 5,280'NDTD PBTD 1 ' 61 ft 3 3/8"6spf 60°phobic(10/19/07) TD 12,081'MD 7,437'ND 12,081'MD 11,470'MD 7,43T ND 6,831'ND Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska I Countr' USA Perforations(MD): 9,457'-10,127' Perf(TVD): 4,825'-5,488' Angle @ KOP&Depth: 5°/100 ft @ 196' Angle @ Perfs: 16° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) I RKI4 21'(AGL) Revised by: Donna Ambruz Revision Date: 02/27/18 • • • II Ninilchik Gas Field GO #6 02/8/2018 11.1..q..04040.II U: r i'i`ss s R ii;i7:::I..F.( 4 1 WIC ll �I 1u 4 Coiled Tubing HR580 Injector Head&Gooseneck � ��-� Weight=12,850 lbs I'yam. ■il g r, 0 0 0 II � WI� t 4-1/16"10K Conventional Stripper WI - Kill Pn,, 4 5K C062 Lubricator WH PSI 2"1502 x 2-1/16 10K t" Flanged Valve / 5K C062 x 4-1/16"10K Flange (Manual) 2-1/16 1 OK x 2-1/16 = 4-1/16"10K Combi BOP 10K Ranged Valve I . .®.�.�I., , Top Set:Blind/Shear Manual Second Set:Pipe/Slip — 4-1/16"10K Flow Cross Manual 2x2 Valve 1:2"1502 x 2-1/16"10K Range `lialiir®il`.,110 14 0111 4 Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 3:2-1/16"10K x 2-1/16"10K Flange Manual 2x2 Valve 4:2"1502 x 2-1/16"10K Range U 41 4-1/16"10K x Wellhead Adapter Flange 11110p�I( 0II(blip NII AA `W, 4 Wellhead ` � . iii • • Ninilchik Unit GO #6 Current tiil.Ylrp.A14.ka. t. 01/19/2018 Ninilchik Unit Tubing hanger,MB-235,11X GO fl6 4.909 MCA lift X4 Y IBT susp, 20X95/8X7X4Y w/4"Type H BPV profile,2- Y.continuous control lines 6.5"Extended neck Tree cap,Otis,4 1/16 5M FE X 614 Otis Quick Union Valve,Swab, 4\O' s,\.e VG-M,4 1/16 5M FE,HWO, .4,` x` �c,'4`<,n.% DD trimOr 111 a\�,a�yNt` a\�zghQ�, e J3y\ 04 J ,7,.'Po �` '114' 41 JC4 roc e' Q} Alk Tee,stdd,4 1/16 5M X 1 t ■ G, e 1 ;,‘ .� 31/85M I c s Valve,upper master, VG-M,41/16 5M FE,HWO, III 1111 DD trim .�. l■ '' 2 1/16 5M Wing section w/ Pneumatic SSV a a MI ON e° f .L ! , I.NC MM. (.--(3)-03 ) . Valve,master,VG-M, l'i k 41/16 5M FE,HWO,DD trim - <,-1,01 .,' ->-- �- ..� Adapter,Vetco,11 5M stdd X _"I:fi_r"" 41/8 5M stdd top,prepped rr f/6.5"extended neck hanger i= Multibowl,Vetco MB-235, -•7` 1• I ` .'24 11 3M stdd bottom X \�' 115MFEtop,w/ 2-2 1/16 5M SSO,1-control line exit Vit'_ ' IA °� °' ' ° Starting head, i ®t�=alai Vetco MB-235, _ 11 3M X 9 5/8 VG-Loc bottom,w/2-2"LPO ru L 9 5/8" 4.5" g ` a cn -.z. • 111) a 4 Q Z w i U U N I 0 Z E8 o 1 D 1- 4 F e, u) 8- ,E- Z t OH 1 1110 'e, [V R +-' V Z e s ry N R .111111 • g A lin N j i Z Vi0041 s_ 0 C o C V V • V A O 0 H x ii I :f::' 16 . in iiiii i Io1 •.yam, . 1 --=- 11.011111 b 1_I{IIII c* iIIff'I..I7'a'lUl1 'II' IIm w It 1111 11111111 1111 1111 °i o gi X 7. \ �z s c 0 o_ 0 c • 0 s A ¢e V • 41) !1111 O a rnE110 I . it C U C H d 0 U N O Z '9 .o a a re • • STANDARD WELL PROCEDURE Hilcorp Alaska,LL( NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets(formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure),whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Seth Nolan Hilcorp Alaska, LLC D GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 Hilrrl 11:rwka.i.t.;i. Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 02/02/2018 To: Alaska Oil & Gas Conservation Commission RECEIVED Meredith Guhl Petroleum Geology Assistant 333 W 7th Ave Ste 100 Anchorage, AK MAR 0 2 20',3 99501 DATA TRANSMITTAL AOGCC G0 6 Digital Files: u Marathon GO#6 SCRIPT_3158-44 TVD,las 4/5/2017 10:52 AM LAS File 389103 L MD Marathon GO#6 SCRIPT_MD_6875-9055,las 4/5/2017 10:52 AM LAS File 653 KE Please include current contact information if different from above. SUMO MAR 2018 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: /2-&OMSS 3/s//CS. 04/(6744.b STATE OF ALASKA ' AIL OIL AND GAS CONSERVATION COM SION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon .Plug Perforations Fracture Stimulate Pull Tubing H Operations shutdown ❑ Performed: Suspend ❑ Perforate [ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 3rforate New Pool [ Repair Well ❑ Re-enter Susp Well❑ Other: V string pull,ort oquoc=e ❑., 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC �"' Development 0 Exploratory ❑ 207-096 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20571-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL-389737 Ninilchik Unit G Oskolkoff(GO)6 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Ninilchik/Beluga-Tyonek Gas 11.Present Well Condition Summary: RECEIVED IVSD Total Depth measured 12,081 feet Plugs measured 11,470 feet true vertical 7,437 feet Junk measured 9,398'(fish) feet JUL. 0 1 2016 Effective Depth measured 11,470 feet Packer measured 8,842 feetAOGGC true vertical 6,831 feet true vertical 4,261 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060psi 1,500psi Surface 2,978' 9-5/8" 2,999' 1,788' 5,750psi 3,090psi Intermediate 9,017' 7" 9,038' 4,433' 7,240psi 5,410psi Production Liner 3,227' 4-1/2" 12,069' 7,437' 8,430psi 7,500psi Perforation depth Measured depth See Attached Schematic EE c ,17 True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 8,842'MD 4,261'ND Packers and SSSV(type,measured and true vertical depth) Baker ZXP;N/A 8,842'MD 4,261'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 23 449 Subsequent to operation: 0 0 0 25 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑✓ Exploratory❑ Development El Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-243 Contact Taylor Nasse-777-8354 Email tnassea.hilcorD.com Printed Name Chad Helgeson Title Operations Manager Signature (y...///77‘, Phone 907-777-8405 Date 7/ 1/16 Form 10-404 Revised 5/2015 ��/72- II 7_,27-i4, " ' RBDMS ‘,..-/JUL 0 6 2016 Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 CTU 50-133-20571-00 207-096 5/12/16 5/24/16 Daily Operations: 05/12/2016-Thursday Obtain PTW. Hold safety meeting. Discuss SLB JSA. Review BOPE test procedure. RU SLB CTU 12 and auxiliary shipping spool with spooler. Stab pipe. Start BOPE test. Test all rams and valves to 250/4,500 psi. Good test. No failures. Pressure test V string cement plug for 30 minutes. Starting pressure 2,149 psi. Ending pressure 2,133 psi. 16 psi loss over 30 minutes. Good pressure test. Send graph to town engineer. SDFN. Wellsite secure. 05/13/2016- Friday Obtain PTW. Hold safety meeting and discuss SLB JSA and job steps and procedures. Make up CC, DFCV,4" GS spear. Pull test BHA to 10K retighten and re pull to 20K. Stab on well. Pressure test stack to 240/4,500 psi. Good PT. Bleed down. Open well. RIH. Stack 4K at 11.5' Pick up. Not latched into hanger. Pop off well. Paint GS profile. Stab on well. PT. RIH stack 4K down. Pick up clean not attached to hanger. Pop off. Measure ring around GS nose. Indicates 3.5" GS spear. Make up 3.5" GS spear with 4" baited sub. RIH, stack 4K down at 11.5'. Pick up. Looks latched. Pull test to 25K. Slack off. Back off top lock down screws. Pick up. Hanger pulled of hanger seat. WHP increase to 400 psi. Pulled stretch out of CT string to 2'. Attempt to work pipe to 30K. No movement. Back out lower lock down screws to try and slack off V string as much as possible. Slacked off and tagged casing back pressure profile. Picked up and weight indicated we had sheared 3/16" shear stock in GS profile. Pick up. Close well. Pop off. Replace shear stock. Stab on PT stack. Open well, RIH. Stack 3K down at 12'. Pick up, no over pull. Normal RIH weight-6K to -8K. RIH to stack down. Stacked to -10K or 4K down @ 11', one foot higher than previous stack. Continue to push to -10K. Weight broke back to-6K. Thought to be traveling through tree. Stacked -10K at 30'. Broke back continued to 40' stack-10K down. Noticed CT pressure and WHP of 230 psi communicating. Decided to POOH to surface to see why CT pressure and wellhead pressure are matching. Pulled 1' and noticed gas venting at injector head. Ran back in with CT. Pressure off CT annuli. Pressure indicated parted CT string. Stab CT string back in packoffs. Line up to pump down backside to kill CT tubing annuli. Pump pressure increased to 800 psi. Looks like hanger is set in BPV profile of casing. Pressure not bleeding down. Hold safety meeting. Discuss procedure for closing pipe and slip rams. Executed. Manually lock pipe/slip rams with correct amount of turns (16.5). Ensure no flow at return tank. Pop off well. Noticed three string of CT in lubricator above BOPE. Hold safety meeting and discuss plan forward. Pressure test. Closed rams to 250/3,200 psi. Holding great. Secure and remove damaged CT strings in lubricator. Left 1.75" CT 5' stub. Stab over stub with lubricator and night cap. Pressure test night cap and stack to 250/1,000 psi. Holding great. SDFN. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 CTU 50-133-20571-00 207-096 5/12/16 5/24/16 Daily Operations: 05/14/2016-Saturday Obtain PTW. Hold safety meeting. Discuss JSA and procedure for removing parted CT stub. Pop night cap. Pick injector head and stab 20' lubricator. Dress CT stub and install double cold roll connector. Make up coil connector on well. Strip down lubricator. Pressure test stack to 250/2,500 psi. Equalize pipe rams. No notice in pressure below rams. Open pipes and slips. PU OOH 15'. Close master swab. Remove parted CT and cut coil BOPE test rams that j}) were used. Close pipe rams and slip rams on 1.75" CT. Pressure test 250/4,500 psi. Good pressure test. MU coil I�•l'/ connector, DFCV, 4" GS spear, baited sub, x over and 3.5" SL GS pined with 1/4" steel rod. Pull test connector to �� t 25,000. Stab on well. Pressure test stack to 250/4,500 psi. Good PT. Bleed down. Open master swab and RIH to !ll�� latch hanger. Latched in at 16' . CT hanger sitting in BPV profile of casing hanger. Pick up 30K. Continue to PU to 44411 42K. No luck pulling string. Make 5 attempts to RIH and pull up. No luck. Line up and pump 165 bbls down back side at 4 bbls/min. Pressure increased to 1,700 psi. Offline with pump backside bleeds down to 1,500 psi and holds pressure. No luck at injecting fill, or creating bouyancy. Attempt to pull 3 more times to 80%CT limit of 42K. No luck removing V string. Bleed off 1,600 psi of WHP from injecting down backside. RIH to land hanger. Hanger landed. Bottom and top set of hanger bolts locked in. PU, close master swab. Pop off well. Set down Injector head and rig back. SDFN. 05/16/2016- Monday Pollard Arrive on location. Hold safety meeting. Discuss job procedures. MIRU E-line unit.Tubing pressure 0 psi. Annulus (coil x tubing) pressure 0 psi. Continue rigging up. Stab on well. Pressure test lubricator 250/2,500 psi. RIH with BHA Rope socket. 4" x 6 'x 1" weight bars, x over, 4' x 3/4" perf torch. Tag @ 9,900'. Pick up weight puts BHA at 9,896" Made 5 attempts to achieve depth. Pick up and RIH at 120 ft/min. No luck getting past 9,896'. Called town to discuss depth and plan forward. Pick up to 9,876' and fire torch. POOH. At surface. Upper master and swab closed 23.5 turns. Confirmed perf torch fired leaving a 3/4" hole in coil velocity string tubing at 9,896'. Rig back E-line unit. Move E-line crane for coil crane to move in. Well site secure. SDFN. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 CTU 50-133-20571-00 207-096 5/12/16 5/24/16 Daily Operations: 05/17/2016-Tuesday Fire equipment. Hold safety meeting. Discuss JSA and job procedures. Rig up Flange x 1502 on glow line x annulus valve and choke skid. Install high pressure filter in 1502 pump iron. Pressure test iron 250/4,500 psi. Good PT. Bleed down. Open pump line to velocity string. Open annulus valve to choke and Open top tank. Come online at 1.5 bbls/min down v string. Returns noticed at tank. Well could be completely fluid packed or fluid pumping through compromised V string hanger seal. Close annulus valve. Max rate down 1.75" CT is 1.6 bbls/min at 3,200-3,600 psi. Increase rate to 3 bbls/min. Pump pressure 3,200 psi. If fluid was only going down, coil pressure would have spiked to 4,500 pump trip pressure. Confirmed that fluid was bypassing hanger and injecting down coil x tubing annuli. Continue to pump down V-string at 3.5 bbls/min and 3,600 psi. Attempting to inject tubing punch 9,876'. While pumping down V-string. SLB rigged up injector head and made up 3.5" GS spear on 2-7/8" CC, DFCV, HYD DISCO. Shut down pump. Pressure test lubricator 250/4,500 psi. Open well and RIH. Tag fish at 10.9'. Latched up. PU to 39,000 lbs. No movement. Hold in tension. Come online with pump down back side at 5.5 bbls/min injection pressure 1,950 psi. Pumped 50 bbls down backside at high rate 5.5 bbls/min. Shut down pump. Pressure bleeds down to 1,500 psi and flat lines. Tubing holds column of fluid and 1,500 psi applied surface pressure. Slack off with coil and make 4 attempts to pull V-string. Picked to 40K or 80%coil limit. No luck. Pulling up to 2' . Getting 9' of stretch out of V- string. Set weight trips higher. PU to 45K one time. No movement. Shut master and swab. Rig back coiled tubing injector head. Move crane and triplex. SLB off location. Wait on Pollard E-line. E-line on location. Spot crane. Rig up. Make up BHA as follows: rope socket, 4" x 6' x 1" weight bars, CCL, x over 1" OD x 6" length, 4' 5/8" perforating torch assembly, 2" x 4' x 1" roller stem. Stab on well. Pressure test to 250/2,500 psi. Bleed down. Open well, RIH. Tag at 9,896'. Same as previous day. Log OOH saw tubing punch hole at 9,876'. Slack off. PU to 9,875.4'. Attempt to fire. No indication on AMP gauge or bolt meter that perf torch was fired. 3 attempt to RIH and pick up to 9,875' and fire. Last attempt pulled heavy. Normal logging weight 1,700 lbs. PU to 3,000 lbs. 1,300 lbs over pull, weight jumped. May have cut without seeing on meters. PU, OOH. At surface. Master swab closed. Pop off. Radial jetting torch did not ignite. Lost one 4'x 1" roller stem. Inspected BHA and found CCL shorted out by indication of burn marks inside. Re-head and install new CCL and roller stem. RIH, tag up 9,896'. Pick up to 9,875.4'. Shoot radial jet cutter. Good indication of shot via volt/amp meter. POOH. At surface. Master swab closed. Confirmed fired. Rig back unit. Well site secure. SDFN. ,}% • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 CTU 50-133-20571-00 207-096 5/12/16 5/24/16 Daily Operations: 05/18/2016-Wednesday Obtain PTW. Hold safety meeting. Discuss JSA and job procedure. PU, make up BHA 2.875" OD tools. CC, DFCV, HYD DISCO, 4" GS spear, baited GS profile x 3.5" slick line GS pinned with 1/4" steel. Stab on well. Pressure test 250/4,500 psi. Latch into hanger at 11'. PU and over pull to max CT limit 39.5K. No luck pulling string. Continue attempts. Make call to town. Decide to open lower lock down screws to pass CT hanger and tag at casing BPV profile. Continue to work V-string up and down while pumping down backside and CT V-string at 3.5 bbls/min. 22 cycles of down and up pulls to 80%. 2,300 psi injection pressure at 3.5 bbls/min. Pollard E-line on location. Coil stretched to 2'. Total of 9' of coil stretch. Estimated inputs from CoilCade free point finder say around 9,600'. User input in question with original CT string weight when V-string was ran in hole. Land coil in CT hanger. Close lock down screws. Stack out on shear stock, 8K PU. Close master swab 23.5 turns. RU pollard E-line. Make up BHA as follows: rope socket, 4" x 6' of 1" weight bar, 1', 1"OD CCL, x over, 1' of 3/4" perf torch. 4' of 3/4 roller bogeys. Stab on well. PT 250/2,500 psi. Open well 23.5 turns. RIH to 9,450'. Paint yellow flag. PU in tension to 9,400.5' fire torch. Good indication on volt/amp gauge. POOH to surface. Torch confirmed spent. Make up same BHA with jetting cutter. Stab on well. PT 250/2,500 psi. Open well and RIH to 9,450'. PU in tension to 9,400'. Flag 11.75" off. On depth. Fire cutter. Good indication from Volt/Amp meter cutter fired. At surface. Confirmed cutter fired. RDMO Pollard E-line. 356 bbls of produced water injected into formation since start of CT operations. Pollard E-line transporting equipment to HVB-17. 05/19/2016-Thursday Obtain PTW. Hold safety meeting. Discuss JSA and job procedure. Pick up 20' lubricator. Make up BHA. CC, DFCV, DISCO,4" GS, latched into 4" GS baited sub witih 3.5" GS pinned 1/4" steel rod. Stab on well. Pressure test stack 250/4,500 psi. Bleed down. Open well, RIH. Latch into hanger at 11'. Pull test to 15K. Latched in. Slack off and back off top hanger lock down screws. Pick up to 40K. No movement. CT at 2'. 9' of stretch. Open lower lock down screws. Continue to slack off and attempt to pull V-string. 26 attempts. No luck. Tag up at surface. Close master and swab. Pop off rig back. SDFN. Pollard ordering and locating chemical cut tools. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 CTU 50-133-20571-00 207-096 5/12/16 5/24/16 Daily Operations: 05/21/2016-Saturday Obtain PTW. Hold safety meeting. RU Pollard E-line (Ed Hawker supervisor). Stab on well with BHA as follows. 4" x 5' x 1" OD weight bars, CCL 1" OD, 9'x 1.25" chem cutter. Pressure test stack 250/2,500 psi. Open well. 0 psi. RIH taking displacement to OT. Previous tubing punch 9,400.5', previous RJT(torch) 9,400'. Tagged twice at 9,400'. Called town to discuss shooting above previous RJT shot. Made it past 9,400'. Picked up from 9,500'to 9,400' CCL. Puts „x chem cut at 9,411'. Fired shot. Lost 200 LBS. of weight. Attempt to RIH with no luck. Good sign cut was complete. �'"" POOH to surface. Tagged up at surface. Rig down pollard E-line. RU SLB CTU 12 with 1.75" CT. Start BOPE test. AOGCC 24hr test witness notification sent 5/20/16 @ 0837. Witness waived by Jim Regg on 5/20/16 @ 0948 hrs. Test all rams and valves to 250/4,500 psi. No failures . BOPE test complete. MU BHA. 3.2" CC, 3.2" HYD DISCO, GS spear 3.5". Stabbed on well. PT stack 250/4,500psi. RIH to latch. Pull test 20K. Slack off. Unscrew hanger lock , down screws. PU. Pipe free at 18,000 lbs. Pull inside lubricator. Close pipe rams and slip rams. Drop chain traction and strip off lubricator. Expose 5' of V-string. Make cut on V-string. Cut off hanger and fishing tools. Dress CT side and V-string side of CT. Make up double dimple spoolable CT connector. Strip back down and collar up lubricator. Pull test to 20K. Slack off to neutral weight. Open pipe rams and slips. Start pulling 9,400' of V-string, POOH. Tag up at surface. Master swab closed 23.5 turns. Pop off well and cut off 7' of coil to show previous cutting attempts. 0 bbls pumped and 0 bbls returned from well. SLB crew stacking back and securing V-string reel. SDFN. 05/22/2016-Sunday Obtain PTW. Hold safety meeting. Discuss JSA and job procedure. Secure V-string reel. Make up connector on 1.75" CT and work string. Stab pipe into work string reel. Stab on well and pump 35 bbls of produced fluid to ensure CT is free of rust/debris. Pop off. Cut of coil connector. Make up BHA. Slip coil connector, DFCV, Hyd Disco, Slinger, weight bar,jars, hydraulic release grapple overshot. All OD's 3.425". BHA length 28'. Pull test pressure test BHA. 25K pull 250/3,500 psi. Stab on well. Pressure test stack 250/4,500 psi. Open master swab 23.5 turns. RIH with closed choke to see when we catch fluid at surface. RIH. WHP increase with coil at 800'. Start opening choke. Bleed well to 0 psi at 6000' online with water down CT at 1.5 bbls/min. 2,100 psi circulation pressure. Wash and pump until we reach fish. Weight check at 9,300' 24K. Continue IH tag fish top at 9,398' CT depth. Shut down pump. Slack off 8K on fish. Pick up. No over pull. 5 more attempts at latching fish. No luck. Online to wash fishing profile. Circulate 10 bbls. Shut down pump. Attempt to latch fish. RIH weight 4K, slack off on fish to 8K. 12K down on fish. PU clean weight of 25K, no over pull or indication fish is latched. POOH to surface. Close master and swab. Pop off break down tool string. Stack back injector head for the night. Night cap installed on BOPE. Well site secure. Crews off location. SLB will bring extra 10' lubricator for next fishing attempt. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date GO-06 CTU 50-133-20571-00 207-096 5/12/16 5/24/16 Daily Operations: 05/23/2016- Monday Obtain PTW. Hold safety meeting discuss JSA. Pick injector head. Make up BHA 2.875" MHA, 2.875" disco with 7/8" ball (3,200psi), 2.875" circ sub 3/4" ball 2,920 psi, 3.125" slinger,x over 3.125", weight bar 2.875, 2.875" dual acting jars, 2.875" motor, x over 3.125", 3.625" series 150 overshot loaded with 1.75" grapples. Cut lip guide and burn teeth inside. Stab on well. PT 250/4,500 psi. Open master swab. RIH. Stack weight at 11.5'. Inspected previously pulled casing hanger. Sent pictures to wellhead tech. Wellhead tech indicated hanger was old style and there should be two collars and a snap ring when pulled. Both collars and snap ring still in hanger profile. Closed well and popped off. RIH with 1/4" stainless steel control line with bent 90 degree lip. Pulled snap ring to surface. Attempt to pull hanger collars. No luck. Continue to attempt to pull. Waiting on wellhead tech to arrive with Pollard internal grapple. Attempt to pull with Pollard internal grapple. Latched in but keep shearing 1/2" brass shear stock. Redress as needed. No luck pulling. Decided to rig down tree. Lower master secured and closed. Perform no flow test. Unflange tree connections. One pick injector head, BOPE, tree. RIH with stainless steel line. Retrieve top hanger collar. RIH with Pollard internal grapple connection. Latched in to lower hanger collar. No luck with hand spangs. Set lower flange half on master valve. Rig up come along to top of pulling tool and BOP body. Pull in tension and tap pulling tool with hammer. Lower hanger collar popped loose. All hanger items fished from hanger profile. Reinstall tree and new ring gaskets. PT tree stack to 250/4,500 psi. Good test. Bleed down. Pop off lubricator. Stack down injector head. SDFN. Will resume fishing operations in the AM. 05/24/2016-Tuesday Obtain PTW. Hold safety meeting and discuss JSA . Review job procedure with crews. Remove night cap. Pick injector head, stab 45' of lubricator. Make up BHA as follows: external slip 2.875", MHA DISCO 7/8" ball, circ sub, 3/4" ball, 3.125" slinger, 3.125" OD x over, 3.125" weight bar, 2.875" DAJ, 2.875" MOTOR, 2.625" series 150 overshot. Total BHA= 40.24' stab on well. PT 250/4,500 psi. Open well, RIH to fish CT string. 278 bbls in open top tank. No weight bobbles past chemical injection mandrel. Continue RIH, start pumping at 1.5 bbls/min at 7,000' to clean up hole. Perform weight check at 9,300', 25K clean. Increase in pressure and drop in weight. Tagged top of fish at 9,398'. Stack 8K down. Shut down pump. Picked up. Latched up to fish. Pick to 15K over string weight at 40K also 80%CT yield. Hit jars. Continue jar licks. No indication fish is moving. Pulling to 40K at 9,390'. Jars hit at 120,000 lbs of force. Slack down to reset jars. Continue with 50 max jar licks. No luck moving fish. 53 up jar licks performed. Did small down jar lick to see if we could RIH. No luck. Attempt to turn overshot off fish. 5 attempts at different pump rates and pressures. On 5th attempt pull off fish nicely at 1 ft/min and 1.6 bbls/min. Increase pulling speed. Circulate bottoms up while POOH from top of fish at 9,400'. Tag up. Break down tools. Inside overshot confirms fish was inside. Small marks on grapple teeth. Start rigging down SLB. Weaver Bros on location. Spot some equipment at Susan D. • GO - 6 ACTUAL Ninilchik Unit 2,975'FSL, 2,988'FEL SCHEMATIC Sec.23, TIN, RI3W, S.M. Hilcorp Alaska, LL( - - Conductor I L'I 20" K-55 33 Bottom Permit#: 207-096 MD o' 98' API#: 50-133-20571-00-00 TVD o' 98' Prop.Des: ADL 389737 KB Elevation: 187' (21'AGL) JSurface Casing X: 229,025.05(NAD 27) 9-5/8" L-80 40 ppf BTC Y: 225,4940.94(NAD 27) Tom Bottom MD 0' 2,999' Latitude: 60 09'48.512"N AI l TVD 0' 1,788' Longitude: 151 29'23.738"W Spud: 07/30/2007 12-1/4"hole with 690 sks(305 bbls)12 ppg TD: 09/07/2007 Type 1 cement with 41 bbls cement to surface. Rig Released: 09/21/2007 @ 10:00 hrs. WBS#: DD.06.15534.CAP.CMP 0 Intermediate Casing 7" L-80 26 ppf Mod Butt Tort Bottom MD 0' 9,038' TVD 0' 4,433' Baker Chemical Injection Nipple 8-3/4"hole with 289 sks(126 bbls)12.5 ppg @ 2,382'MD(Top) Lead &145 sks(30 bbls)15.8 ppg Tail,did 5.930"OD/3.858"ID;8,430 psi burst not bump plug,100%returns,floats held. /,7500 psi collapse Tie-backTubing 4-1/2" L-80 12.6 ppf Hydril 563 KOP @ 196'MD/TVD Tog Bottom Build 5.0°/100'from 200'-1583'MD MD 0' 8,842' Hold 67°from 1,583'-7,354'MD TVD 0' 4,261' Drop 2.5°/100'to 10,120'MD Hold 0°from 10,120'to TD at 10,090'MD Azimuth:290.931° *ZXP Liner Packer with 15'Tieback Extension @ 8,830.24'MD(Top) iner 4-1/2"D L-80 12.6 ppf Hydril 563 Tom Bottom MD 8,842' 12,069' TV4,261' 7,437' 7L"hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks(100 bbls)10.5 ppg cement,Plug failed,100%Returns. 5-8 bbls cement returns. *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) *Marker Joint Top @ 9,925.5'MD(19'long) *Marker Joint Top @ 10,929.5'MD(19.5'long) - << *Landing Collar Top @ 11,983.91' (1.53'Long) *Float Collar Top @ 12,025.56' (1.55'Long) It, I.IP Velocity String Fish Details *Float Shoe Top @ 12,066.95 (2.05'Long) . 1-3/4" HO-70 0.134 wall thickness TIa Bottom . MD 9,398' 10,100' (Chemical Cut) BHA consisting of coil grapple.68'L X 2.625"OD,straight i bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" Cast Iron Bridge Plug @ 11,470' i OD. �' i Attempted to fish with overshot on 1-3/4"CT 05/24/16. Expro Radial Bond Log-10/11/2007 a Tvonek Perfs: a 6 MD TVD Ft 111 9,457'- 9,482' 4,825'-4,849' 25 ft 3-3/8" 6spf 60°phase(11/21/07) ` =, 9,482'- 9,511' 4,849'-4,877' 29 ft 3-3/8" 6spf 60°phase(11/20/07) 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8" 6spf 60°phase(11/15/07) Formation Tops: (Frac'd May 20,2008) Formation Depth e Beluga IL__ 11-,537-1-1;56X----6,898'-6,929' 61 ft 3 3/8" Tyonek T1 7,133'MD 3,250'TVD Tyonek T2 8,554'MD 4,025'TVD Tyonek T3 9,918'MD 5,280'TVD TO PBTD TD 12,081'MD 7,437'ND 12,081'MD 11,470'MD 7,437'TVD 6,831'ND Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 9,457'-10,127' Perf(TVD): 4,825'-5,488' Angle @ KOP&Depth: 5°/100 ft A 196' Angle A Perfs: 16° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) RKB: 21'(AGL) Revised by: Taylor Nasse Revision Date: 07/01/2016 VOFT{� • • .-0.„iyyy..,, THE STATE Alaska Oil and Gas ` \T*. oAZ V K1 Conservation Commission jtritt �� t 333 West Seventh Avenue " GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 UP ALAS1‘P Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson4`� Operations Manager , togg Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool,Ninilchik Unit GO 6 Permit to Drill Number: 207-096 Sundry Number: 316-243 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, //°4-44-0(4- .. Cathy P Foerster Chair DATED this 2 day of April, 2016. RBDMS t,v APR 2 9 2016 • • RECEIVED STATE OF ALASKA APR 2 0 2016 • ALASKA OIL AND GAS CONSERVATION COMMISSION O)s 4 MO lc APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations Li - Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑., Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other:V stnng pull,cmt squeeze ❑., 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory ❑ Development ❑✓ - 207-096 - 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20571-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.701A Ninilchik Unit G Oskolkoff(GO)6 Will planned perforations require a spacing exception? Yes El No ❑., 9.Property Designation(Lease Number): 10. Field/Pool(s): ADL-389737 - Ninilchik/Beluga-Tyonek Gas " 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,081' 7,437' 11,470' 6,831' 1,360psi 11,470' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060psi 1,500psi Surface 2,978' 9-5/8" 2,999' 1,788' 5,750psi 3,090psi Intermediate 9,017' 7 9,038' 4,433' 7,240psi 5,410psi Production Liner 3,227' 4-1/2" 12,069' 7,437' 8,430psi 7,500psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: 4-1/2" Tubing Grade: 12.6#/L-80 Tubing MD(ft): 8,842' See Attached Schematic See Attached Schematic 1-3/4" H0-70 10,100' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker ZXP;N/A 8,842'MD/4,261'TVD;N/A 12.Attachments: Proposal Summary n Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15.Well Status after proposed work: May 4,2016 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS 0 " WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasse( hilcorD.com Printed Name Chad Helgeson Title Operations Manager Signature 7.Y..//rili - Phone 907-777-8405 Date `//ZC/ I cII COMMISSION USE ONLY / Conditions of approval: Notify Commission so that a representative may witness Sundry Number. / li 2 Plug Integrity ❑ BOP Test LJ Mechanical Integrity Test ❑ Location Clearance El Other: 4 LISoo r S' 8L ;-' . 1 e.5 f cl C t ) Post Initial Injection MIT Req'd? Yes ❑ No Li ,, A Spacing Exception Required? Yes Li No 0 `/Subsequent Form Required: / L — `YL ' RBDMS LL r pr? 2 q 2016 / APPROVED BY Approved by: /) Gi COMMAL ISSIONER THE COMMISSION Date: 4.—26_r' 4-22, 4 OR I At Submit Form and Form 10-403 t-vised 11/2015 A r pi l12 months from the date of approval. A achments in Duplicate /fisc --b /47 • Well Prognosis • Well: GO-6 Hil(orI,;11aska,LL Date:04/15/2016 Well Name: GO-6 API Number: 50-133-20571-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: 05/04/16 Rig: Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-096 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907)903-0341 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824 (M) AFE Number: Current Surface Pressure: 1,230 psi Current BHP: — 1,482 psi @ 5,150' TVD (SBHP survey of GO-6 on 4/7/16) Maximum Expected BHP: — 1,887 psi @ 5,274' TVD (Based on SBHP survey of GO-8 on 11/14/15 (T-18 only)) Max. Potential Surface Pressure: — 1,360 psi (Assumed 0.10 psi/ft gas gradient) Brief Well Summary GO-6 was originally drilled as a grassroots well in July 2007 and completed in the Tyonek sands. After initial completion, the lowest intervals were isolated and the upper interval was frac'ed, which doubled production but also brought in water, so a capillary string was installed in July 2008 to help with loading issues. In July 2010, the cap string was removed and the 1-3/4" velocity string was installed. The well stopped producing in 2014 due to loading. The purpose of this work/sundry is to remove the velocity string, push away water and plugback the lower interval, check for water influx to see if the upper interval requires isolation, and add perforations in the - Tyonek sands. If the upper interval requires isolation, a cement squeeze will be performed prior to perforating. Notes Regarding Wellbore Condition • Fluid level at 7,900' MD with 755 psig surface pressure on 4/7/16. -� s• • PX plug will be set in XN landing nipple of v-string prior to starting work. ' • Blow down v-string to production after setting PX plug to perform negative pressure test. • Lubricate and bleed 25 bbls of water down well. Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter • Consider tank placement based on wind direction and current weather forecast (venting methane and nitrogen during this job) • Ensure all crews are aware of stop job authority - Coiled Tubing Procedure: t �� 1. Submit 24 hr.witness notification to AOGCC via web base notification. CT r) 2. MIRU Coiled Tubing, PT BOPE to 250/4,500 psi. .' 5 3. Make up MHA with disconnect and GS spear. Stab on well PT lubricator to 250/4,500 psi. ? #• 4. RIH to latch hanger profile. Pick up to confirm latch. Slack off to neutral weight. Back off top lock down screws. Pull V string into lubricator. /' • • Well Prognosis • Well: GO-6 Hilcorp Ala ka..l.L Date:04/15/2016 5. Set CT in BOPE pipe/slip rams. Mechanically lock in rams. Ensure pressure is 0 psig. 6. Raise injector head and lubricator up enough to expose CT hanger and GS profile. 7. Cut off CT connectors from both V string and CT retrieval whip. MU double dimple cold roll connector with slick 1.75" OD. 8. Stab lubricator back onto BOPE. 9. Pull test connector. Slack to neutral weight. Unlock rams and open BOP. 10. POOH with 1.75" coiled tubing and BHA. 11. Rig back Coiled Tubing. 12. ND coiled tubing hanger. 13. RU nitrogen pumping unit and connecting hoses. PT equipment 250/3,000 psig. 14. Pressure up well with nitrogen to push water away. Injection pressure should be around 1,600 psig. Once injection pressure has stabilized, stop pumping and SI well. 15. RD nitrogen pumping unit. E-Line Procedure: 16. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. 17. RIH with Pressure/Temperature tool and check for fluid level. POOH. 18. MU 4-1/2" CIBP and setting tool. I 19. RIH and set CIBP at+/- 10,095'. POOH w/setting tool. 20. MU dump bailer and fill w/cement. 21. RIH and dump cement on top of CIBP (10' = 6 gallons). POOH w/dump bailer. 22. Wait 24 hrs. for cement to set. 23. Blow down well to vent. RIH with Pressure/Temperature tool and check for fluid level. (Verify wind 'au-ea-ion when venting gas) If significant water influx occurred: y7 t S6)z t E4'.(-5 24. MU 4-1/2" composite bridge plug (CBP) and setting tool. 25. RIH and set composite bridge plug at+/-9,515'. POOH w/setting tool. ti r 26. RD E-line. eta Coiled Tubing Procedure: 27. RU coiled tubing. PT to 250/4,500 psi. 28. MU ball drop nozzle. RU cement pump. RIH and tag composite bridge plug. Lay cement from top of CBP to 9,430' (=5 bbls estimated for cement squeeze). 29. Close choke and squeeze cement into perforations. 30. POOH to surface. Let cement set up for 24 hrs. 31. Pressure test cement squeeze to 3,500 psi for 30 minutes. 32. MU motor and mill BHA. RIH and tag TOC. Record tag depths. 33. PU 10 ft. and come online with 3 % KCL. Mill through cement from 9,430' and through CBP at 9,515'. RIH to=10,070' to circulate cuttings and plug debris to surface. 34. Drop circulation sub ball and begin pumping nitrogen to jet well dry. Once N2 has reached return tank start pinching in choke and leave 1,500 psi SITP. POOH. 35. RD coiled tubing unit. • , • Well Prognosis Well: GO-6 Hilcorp Alaska,LL Date:04/15/2016 E-Line Procedure: 36. MIRU e-line and pressure control equipment. PT lubricator to 250 psi low/2,000 psi high. Note that the well is pressurized with nitrogen. 37. If necessary, bleed nitrogen pressure down as requested by the RE to establish a drawdown on the formation. 38. Perforate the Tyonek sand with 2-7/8" 6 SPF 60 deg phased perf guns. All intervals are planned for 12 SPF so each zone may be shot twice. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Gross Proposed Perforated Intervals Sands Top (MD) Btm (MD) FT l" /v/5 Tyonek T-18 ±9,912 ±9,965 ±53 39. POOH. 40. Flow through test separator and record water and gas rates. 41. RD e-line. 42. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Wellhead Diagram (Current and Proposed) 4. CT BOPE Schematic 5. CT Schematic(forward and reverse jetting) S • 14GO - 6 ACTUAL Ninilchik Unit 2,975' FSL, 2,988' FEL SCHEMATIC Sec.23, TIN, RI3W, S.M. Hilcocp Alaska,LLC 1 - - L Conductor 20" K-55 133ppf PE Tom Bottom Permit#: 207-096 MD 0' 98' TVD 0' 98' API#: 50-133-20571-00-00 Prop.Des: ADL 389737 KB Elevation: 187' (21'AGL) ) Surface Casing X: 229,025.05(NAD 27 9-5/8" L-80 40 ppf BTC Y: 225,4940.94(NAD 27) 1 Tom Bottom MD 0' 2,999' Latitude: 60 09'48.512"N r TVD 0' 1,788' Longitude: 151 29'23.738"W Spud: 07/30/2007 12-1/4"hole with 690 sks(305 bbls)12 ppg TD: 09/07/2007 i Type 1 cement with 41 bbls cement to surface. Rig Released: 09/21/2007 @ 10:00 hrs. '; WBS#: DD.06.15534.CAP.CMP Intermediate Casing 7" L-80 26 ppf Mod Butt Top Bottom MD 0' 9,038' TVD 0' 4,433' Baker Chemical Iniection Nipple 8-3/4"hole with 289 sks(126 bbls)12.5 ppg @ 2,382'MD(Top) Lead &145 sks(30 bbls)15.8 ppg Tail,did 5.930"OD/3.858"ID;8,430 psi burst not bump plug,100%returns,floats held. /,7500 psi collapse Tie-backTubinq 4-1/2" L-80 12.6 ppf Hydril 563 KOP @ 196'MD/TVD Tom Bottom Build 5.0°/100'from 200'-1583'MD MD 0' 8,842' Hold 67°from 1,583'-7,354'MD TVD 0' 4,261' Drop 2.5°/100'to 10,120'MD Hold 0°from 10,120'to TD at 10,090'MD Azimuth:290.931° *ZXP Liner Packer with 15'Tieback Extension @ 8,830.24'MD(Top) ner 4-1/2" L-80 12.6 ppf Hydril 563 Tom Bottom MD 8,842' 12,069' TVD 4,261' 7,437' 7Li"hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks(100 bbls)10.5 ppg cement,Plug failed,100%Returns. 5-8 bbls cement returns. *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) *Marker Joint Top @ 9,925.5'MD(19'long) *Marker Joint Top @ 10,929.5'MD(19.5'long) r < Velocity Tubing (installed on 7/22/10) *Landing Collar Top @ 11,983.91' (1.53'Long) Float Collar Top @ 12,025.56' (1.55'Long) 4, 1 1-314" HO-70 0.134 wall thickness *Float Shoe Top @ 12,066.95 (2.05'Long) '1::,p 0' 10 1711:1_1 D 0' 10,,1om 100' s TVMD 0' 5,461' BHA consisting of coil grapple.68'L X 2.625"OD,straight bar 9.57'L X 2.625"OD.1.48"ID,1.25"XN Landing Nipple.78'L X 2.48"OD 1.135 NO GO, Wireline Reentry guide.66'L X 2.50" ;'I OD w/Pump out plug.12'L X 2.18"OD. Cast Iron Bridge Plug @ 11,470' _ e Expro Radial Bond Log-10/11/2007 ==ii Tyonek Perfs: a 6 MD TVD Ft N 9,457'- 9,482' 4,825'-4,849' 25 ft 3-3/8" 6spf 60°phase(11/21/07) I 9,482'- 9,511' 4,849'-4,877' 29 ft 3-3/8" 6spf 60°phase(11/20/07) 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8" 6spf 60°phase(11/15/07) Formation Tops: a (Frac'd May 20,2008) Formation Depth CC Beluga Tyonek T1 7,133'MD 3,250'TVD Tyonek T2 8,554'MD 4,025'TVD Tyonek T3 9,918'MD 5,280'TVD TD 12,081'MD 7,437'ND - TD PBTD 12,081'MD 11,470'MD 7,437'TVD 6,831'ND Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska I Country: USA Perforations(MD): 9,457'-10,127' Peri(TVD): 4,825'-5,488' Angle A KOP&Depth: 5°/100 ft A 196' Angle a7.Perfs:_ 16° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) I RKB: 21'(AGL) Revised by: Kevin Skiba Revision Date: 8/16/2010 •. .. • • • GO - 6 PROPOSED Ninilchik Unit 2,975' FSL, 2,988'FEL SCHEMATIC Sec.23, TIN, RI3W, S.M. Ililcorp Alaska. LU LConductor 'I 20" K-55 133 Bottom Permit#: 207-096 MD 0' 98' API#: 50-133-20571-00-00 TVD o' 98' Prop.Des: ADL 389737 KB Elevation: 187' (21'AGL) Surface Casing X: 229,025.05(NAD 27) 9-5/e" L-80 40 ppf BTC Y: 225,4940.94(NAD 27) TOS Bottom MD 0' 2,999' Latitude: 60 09'48.512"N r I\ TVD 0' 1,788' Longitude: 151 29'23.738"W Spud: 07/30/2007 12-1/4"hole with 690 sks(305 bbls)12 ppg TD: 09/07/2007 Type 1 cement with 41 bbls cement to surface. Rig Released: 09/21/2007 @ 10:00 hrs. WBS#: DD.06.15534.CAP.CMP Intermediate Casing 7" L-80 26 ppf Mod Butt lag Bottom MD 0' 9,038' TVD 0' 4,433' Baker Chemical Injection Nipple 8-3/4"hole with 289 sks(126 bbls)12.5 ppg @ 2,382'MD(Top) Lead &145 sks(30 bbls)15.8 ppg Tail,did 5.930"OD/3.858"ID;8,430 psi burst not bump plug,100%returns,floats held. /,7500 psi collapse Tie-backTubinq 4-1/2" L-80 12.6 ppf Hydril 563 KOP @ 196'MD/TVD Top Bottom Build 5.00/100'from 200'-1583'MD MD 0' 8,842' Hold 67°from 1,583'-7,354'MD TVD 0' 4,261' Drop 2.5°/100'to 10,120'MD Hold 0°from 10,120'to TD at 10,090'MD Azimuth:290.931° •ZXP Liner Packer with 15'Tieback Extension @ 8,830.24'MD(Top) 4-1/2" L-80 12.6 ppf Hydril 563 Tom Bottom MD 8,842' Liner 12,069' TVD 4,261' 7,437' 7"hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks(100 bbls)10.5 ppg cement,Plug failed,100%Returns. 5-8 bbls cement returns. *Flex-Lock Liner Hanger @ 8,862.31'MD(Top) *Marker Joint Top @ 9,925.5'MD(19'long) ' 11 *Marker Joint Top @ 10,929.5'MD(19.5'long) , ,� "Landing Collar Top ©11,983.91' (1.53'Long) *Float Collar Top @ 12,025.56' (1.55'Long) 4: I ,}t *Float Shoe Top @ 12,066.95 (2.05'Long) = , s 1 p I o5s' . :.ast Iron Bridge Plug @ 10,095' - / 5 Capped w/10'cement 11 I Cast Iron Bridge Plug @ 11,470' Tvonek Perfs: MD TVD Ft Expro Radial Bond Log-10/11/2007 a cc 9,457'- 9,482' 4,825'-4,849' 25 ft 3-3/8" 6spf 60°phase(11/21/07) _ ::::i 9,511' 4,849'-4,877' 29ft 3- 6spf 60phase(11/20/07)I 9,965' 5,274'-5,326' 53 ft 2-718" 6spf 60°phase(Proposed) p Formation Tops: a 6 Formation Depth a MS 10,103'10,127' 5,464'5,488' 24 ft 3 3/8" 6spf 60°phase(11/15/07) Beluga a ': Tyonek T1 7,133'MD 3,250'TVD .4.A+ -tl"_+ *. Tyonek T2 8,554'MD 4,025'TVD 11,537'-11,568' 6,898'-6,92W'--64ft--3418"-6spf-60°phase{1011-9/07) Tyonek T3 9,918'MD 5,280'TVD TD 12,081'MD 7,437'TVD TD PBTD 12,081'MD 11,470'MD 7,437'TVD 6,831'TVD Well Name&Number: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska _ Country: USA Perforations(MD): 9,457'-10,127' Perf(TVD):_ 4,825'-5,488' Angle @ KOP&Depth: 5°/100 ft A 196' Angle A Perfs: 16° Date Completed: 11/15/2007 . Ground Level: 166' (AMSL) L RKB: 21'(AGL) , Revised by: Taylor Nasse Revision Date: 4/19/2016 • •• Ninilchik Unit . 11 GO #6 04/12/2016 if.1-9. %14•k...Y.lit Tubing hanger,MB-235,11 X Ninilchik Unit 4.909 MCA lift X4 Y.IBT susp, GO#6 w/4"Type H BPV profile,2- 20 X 9 5/8 X 4'x l' '/<continuous control lines Tree cap,Otis,4 1/16 5M FE 6.5"Extended neck X 6''/Otis Quick Union 1111 I..111M.,u1 IIIIIIIIIII Minlinin Valve,Swab, mow fNl -30' -t\es VG-M,4 1/16 5M FE,HWO, 1/4(''' 44' yj'c�.<,<(,,0i 4•i <a DD trim ° AI ... ,'„< �s ,a,,Syo ,,,, -7- 3 O p' ,Z,P U + 4' O tip 4 c Afl Mil islisl J� J 6' P. Tee,stdd,4 1/16 5M X • G 49:;:ii 3 1/8 5M a - • i � = mow am Valve,upper master, � VG-M,4 1/16 SM FE,HWO, 04 4 DD trim .) NI mem 10,,,„„...-,...' _ 2 1/16 5M Wing section w/ Coiled tubing hanger,VG- Pneumatic SSV CTM,4”nominal X 2 3/8 EUE .. susp X 3"GS Baker Fish Neck - A _ Lift,w/2"Type HBPV and � �� t grapple fort 3/4"coil it M 'el LN Mill /�. I.IMI UM nl O_O Valve,master,VG-M, IVO 14 4 1/8 5M FE,HWO,DD trim ....®� Adapter,Vetco,11 5M stdd X 11111111Wall Me 4 1/8 5M stdd top,prepped 11111 f/6.5"extended neck hanger Multibowl,Vetco MB-235, 'garl�'��WI —' ' 11 3M stdd bottom X I 16......., 11 5M FE top,w/ 2-2 1/16 5M SSO,1-control 1 i '` H s J line exit =■iii �.��` � ` Ii!i ' I Starting head, 7[13 _ Vetco MB-235, I 1. 11 3M X 9 5/8 VG-Loc NOM 'Will• bottom,w/2-2"LPO ii: .,., i' ME ,sf4 Mil 20" 9 5/8" 7,, 4.5" 11 1'/" I • • PROPOSED Ninilchik Unit . H GO #6 04/12/2016 tin.,„i. ti..t... 1 Ninilchik Unit GO#6 20 X 9 5/8 X 4''Ax1Y. Tree cap,Otis,4 1/16 5M FE X 6''A Otis Quick Union Ell lin OM.me VG-M,4 1/16 5M FFE,HWO, m wig- A"\\ «`('‘ ��'Z' �`c <<,'.,.F DD trim e 4 e �� , Or*, gill U�� ,%'b \O. . „vas' oQe OCs P.ye Tee,stdd,4 1/16 5M X -i n/ 3 1/8 5M /C'� IIV ® , Ian Valve,upper master, VG-M,4 1/16 5M FE,HWO, 01.0 A DD trim .• •. 'i riih—i rrr.; OO OO Valve,master,VG-M, OO 4 1/8 5M FE,HWO,DD trim 0 0 Q 0 0/ Adapter,Vetco,11 5M stdd X rrn-eff rrr 4 1/8 SM stdd top,prepped f/6.5”extended neck hanger Multibowl,Vetco MB-235, =.$f,'' �� —Am._ 1;166°- 11 3M stdd bottom X "`^ I 11 5M FE top,w/ 2-2 1/16 5M SSO,1-control ` J ,- y. ., litra4 ,' line exit (Acomoomul 11701 alm 11 Starting head, Vt ,• Vetco MB-235, ' f +6.0 . 11 3M X 9 5/8 VG-Loc Ell ��i bottom,w/2-2”LPO ig '-' ar e �L 'i - 20" J 9 5/8" 4.5" • • Ninilchik Gas Field • ll GO-6 04/19/2016 11,i.,,,i, v.,.1., I I GO-6 Coil Tubing BOP Lubricator to injection head o I in j 1.75" Tandem Stripper 1 [ _1 C: Blind/Shear 4 1/16 10/4 Blind/Shear : j -_ "5 _- - C: Blind/Shear Blind/Shear -L'-L'3 4 Slip =_ Slip iIuI•i _ - C / L = Pipe Pipe = i Mud Cross i - - C 1 ----\\ 4 1/16 10M X 4 1/16 10M Outlet w/ 2- 2 1/16 10M full 1. - . _ , 1111-1111 i a _ opening FMC valves 11101 IA 11 M IIII 0 _,Lio a I 11 II i 1St $15 Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M U TZ 2 1/16 10M 2 1/16 10M Crossover spool r['1ill 4 1/16 10M X 4 1/16 5M . • • < 4g1 cn U I C H Q w Y , 7 U U N � . 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They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. - O q~ Well History File Identifier Organizing (done) ^ Two-sided III II111111 III II III ^ Rescan Needed RESCAN DIGITAL DATA OVERSIZED (Scannable) ~olor Items: ^ Diskettes, No. ^ Maps: „[~Greyscale Items: ^ Other, No/Type: ^ Other Items Scannable by vv a Large Scanner ^ Poor Quality Originals: OVERSIZED (Non-Scannable) ^ Other: ^ Logs of various kinds: NOTES: ^ Other:: BY: ~ Maria Date: ~ ~,~ ~ / / ~ ~ /s/ P Pro "ect Proofin ! / II I II ~I II I I ~I I I III I g BY: Maria Date: ' iJ ~ /s/ Scanning Preparation ~ x 30 = SD + ~ =TOTAL PAGES~~ ~j (Count does not include cover sheet) BY: ~ Maria Date: ~ a. ~ , I I D U l sl Production Scanning Stage 1 Page Count from Scanned File: ~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: _~,~ YES NO BY: Maria Date: ~ ~' 1 D O /s/ ~~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II II II I II II I I III ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked III Ililll III IIII II 10/6/2005 Well hiistory File Cover Page.doc • Marathon JNARAiHON Alaska Production LLC August 17, 2010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 1 •-4~4 ReN~rt •f Sundry Well Operations Field: Ninilchik Unit Well: Grassim Oskolkoff #6 Dear Mr. Aubert: Mar'a~hon Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 j ~~~~~ * ,;., ~~nisst~t~ ~~ 6 -~~ ao~ Attached for your records is the10-404 Report of Sundry Well Operations for GO-6 well. This report covers the work performed to remove the capillary string and install velocity tubing to a setting depth of 10,100' MD. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~le,,,~..-~.s~ Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS STATE OF ALASKA ALASK~L AND GAS CONSERVATION COMMIS REPORT OF SUNDRY WELL OPERATIONS '~~~ ~~ 201C! 1. Operations Abandon Repair Well Plug Perforations Stimulate '~ ~ .° .x ~ q~Otlary Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension i6 ~~r,ng & installed Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well^ velocity tubing 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Alaska Production LLC Development ^~ Exploratory^ X207-096 3. Address: PO Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133 20571-00~®~ 7. Property Designation (Lease Number): ~ 8. Well Name and Number: ADL-389737 rass' Oskolkoff #6 Ninilchik Unit / Tyonek Pool ~ , ~~ , ~4 11. Present Well Condition Summary: Total Depth measured 12,081' feet Plugs (measured) 11,470' feet true vertical 7,4$7' feet Junk (measured) NA feet Effective Depth measured 11,470' feet Packer (measured) 8,842' MD feet true vertical 6,831' feet (true vertical) 4,261' TVD feet Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060 psi 1,500 psi Surface 2,g77' 9-5/8" 2,999' 1,788' 5,750 psi 3,090 psi Intermediate 9,017' 7" 9,038' 4,433' 7,240 psi 5,410 psi Production Liner 3,239' 4-1/2" 12,081' 7,437' 8,430 psi 7,500 psi Perforation depth: Measured depth: 9,457' - 10,127' True Vertical depth: 4,825' - 5,488' Tie-back 4-1/2" L-80 8,842' MD 4,261' TVD Tubing (size, grade, MD &TVD): Velocity String 1-3/4" HO-70 10,100' MD 5,461' ~/D SSSV: - - MD - TVD Packers and SSSV (type, MD &TVD): Packers: Baker ZXP 8,842' MD MD 4,261' TVD TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): The 3/8" capillary string was removed and a 1-3/4" velocity sting was installed to help lift water from the wellbore during the low demand Treatment descriptions including volumes used and final pressure : season. 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,400 1.5 0 - Subsequent to operation: 0 630 1 0 600 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ^~ Service ^ ~ Daily Report of Well Operations X 15. Well Status after work: Oil Gas ~ WDSPL GSTOR ^ WAG ^ GINJ^ WINJ ^ SPLUG ^ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 310-187 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signature ~,~~ ~ ~ Phone (907) 283-1371 Date August 17, 2010 Form 10-404 Revised 7/2009 v RBDMS AUG 1' 92010 ~~~ Submit Original Only .M ~r~thort rations Summary Report by Jol~ Nu-aarxor Oi1C:ompany well Name: GRASSIM OSKOLKOFF 6 ~® Qtr/Qtr, Block, Sec, Town, Range Field Name License No. State/Province Country NINILCHIK - GRASSIM OSKOLKOFF ALASKA USA Daily Operations Report Date: 7/10/2010 Job Cate o WORKOVER 24 Hr Summary MIRU DynaCoil to pull cap string. Remove capstring from well. - -- -- Ops "' 'Trouble Start Time End Time Dur{hrs) Ops Code Activity Code = ,Status Code Comment 07:30 08:30 1.00 SAFETY MTG Hold PJSM. Discuss emergency response, alarms-red flashing strobe for fire alarm, blue flashing strobe for gas alarm, muster area, wind direction, and specific job hazards. Obtain SW Permit. 08:30 09:15 0.75 RURD EQIP MIRU crane truck. Disconnect power to well house. PU well house and set aside. Remove LO/TO from tree. 09:15 11:00 1.75 RURD COIL Spot equipment. Lay liner down. RU Dynacoil unit. PU spool. Stab coil thru side of injector. Carry injector to WH while "walking" injector down coil. Set injector on WH. Install hydraulic line on packoff. Check pressure. Set pressure to 3000 psi. Back off Ratigun. Release mechanical slips. 11:00 13:00 2.00 RUNPUL COIL PU on cap string to 3200 lbs. Pulls free from 10,103'. POOH 100' to insure it's free. Unable to RIH. Tubing weight goes to 200 Ibs when trying to go down hole.. No tag. (Perfs 10.103' - 10,127'). POOH. 13:00 13:30 0.50 TEST TREE Install tree cap and gauge. PT cap to 200 psi. 13:30 15:30 2.00 PUMP TRET Displace cap string w/ MEOH. 15:30 16:30 1.00 RURD COIL RD unit. 16:30 17:00 0.50 SECURE WELL Secure well. Turn in permit. Sign out and leave loc. Close and lock gates. Call operator finished for the night. Report Date: 7113/2010 Job Cate o WO RKOVER _ 24 Hr Summary LOTO flowline valve and valve at heater. MIRU Vetco Gray and UOSS to install V-string hanger. PT tree to 5000 Psi. Test good. ______-- ~ Start Time End Time Dur (hrs) Ops Code Ops j ActivityC9de , Status Trouble ~ Code Comment 07:30 08:30 1.00 SAFETY MTG Hold PJSM. Discuss alarms, muster area, and emergency response. Discussed operations, safety hazards around the well head, overhead hazards, working with man-lift. Obtained Hot Work Permit. 08:30 08:45 0.25 SECURE WELL Operations has shut in well. LOTO and bled flow line 08:45 09:30 0.75 RURD EQIP RU Vetco Gray and crane truck. Install lubricator. PT . Install Type H BPCV. Close lower master vallve. 09:30 11:30 2.00 NUND TREE Dismantle well head above bottom master valve. Install V-String hanger w/ annular flow tree, wing valve, and SSV. Re-install upper master valve, flow tee w/ wing valve and SSV, and swab valve and tree cap. Index flow trees 1 bolt hole ccw above lower master. 11:30 12:00 0.50 TEST TREE PT new coil tubing hanger connections to 5K psi. Hold test for ten minutes. Test good. 12:00 12:45 0.75 RURD EQIP Retrieve BPCH. RD Vetco Gray. 12:45 13:00 0.25 SECURE WELL Install Otis tree cap. PT tree cap. Test good. Turn in permit. Sign out and leave loc. Report Date: 7/21/2010 Job Cate o WORKOVER 24 Hr Summary Moblize BJ coil unit, ASRC crane and vac truck, and Arctic Iron flowback equipment. RU BJ coil spread in preparation to run V-string. Set BOP's on WH. Test BOP's-250 psi low/ 4500 psi high. Test good. AOGCC notified for test Monday July 19. Witness waived by Mr. Jim Regg July 20,2010 as per Kevin Skiba. Pig coil by pumping 22 bbls fresh water thru coil. Displace coil w/ N2. - - _ - _ Ops Trouble -- - Start Time ~ End.Time Dur (hrs) Ops Cade Activity Code I Status Code Comment 07:30 08:15 0.75 SAFETY MTG Hold PJSM. Discuss emergency response, alarms-red flashing strobe for fire alarm, blue flashing strobe for gas alarm, muster area, wind direction, and specific job hazards. Obtain SW Permit. 08:15 11:00 2.75 RURD COIL Lay down liners and drip pans. Spot equipment. Spot choke manifold and flow back tank. RU gas buster. RU hard lines. Remove Otis tree cap. PU BOP's. Set on Flow cross and hammer up. MU hydraulic control) lines on BOP. MU 2" hard line to flow cross. Carry BOP's to WH. PT flow back iron to 4500 psi. 11:00 12:12 1.20 TEST ROPE Function test BOP's- blinds, cutters, slips,and pipe rams. PT blinds 250 psi low/4500 psi high. Test good. Insert test bar. PT pipes 250 psi low/ 4500 psi high. AOGCC notified for test Monday July 19. Witness waived by Mr. Jim Regg July 20,2010 as per Kevin Skiba. 12:12 13:12 1.00 RURD COIL PU tag end of coil w/ crane. Thread end into injector assembly. Run in hole. Prep end. www.peloton.com Page 1/2 Report Printed: 8/17/2010 ' ~~pn rations Summary Report by Jo~ ~~pj~(;p~ ell Name: GRASSIM OSKOLKOFF -~naarnor Casing Flange Elevation (ft) Ground Elevation (ft) KB-Casing Flange Distance (ft) KB-Ground Distance (ft) Spud Date Rig Release Date 0.00 166.00 187.00 21.00 7/31 /2007 _ - - - --- -- - - _ _- _ i Ops ~ Trouble Start Time End Time Dut(hrs) Ops Code Activity Code, Status Code Comment __ _ _ - 13:12 13:12 RURD COIL Shut down equipment. Close vavles on equipment for the night. 13:12 13:12 SECURE WELL Secure well for the night. Close swab and upper master valves. Wing and SSV are tagged out. Turn in permit. Sign out and leave loc. Daily Operations Report Date: 7/22/2010 Job Cate o WORKOVER 24 Hr Summary Run 1.75" Velocity string to 10,100 and hang off in coil hanger. Hand well over to production. --- -- -- --- --- - ! Ops Trouble - Stert Time End Time Dur (hrs) , Ops Code Activity Code Status Code Comment 07:30 08:15 0.75 SAFETY MTG Hold PJSM. Discuss emergency response, alarms-red flashing strobe for fire alarm, blue flashing strobe for gas alarm, muster area, wind direction, and specific job hazards. Obtain SW Permit. 08:15 10:00 1.75 RURD COIL Perform equipment inspections. Start up equipment. PU injector. Prep coil end. Install pig catcher. Carrry injector to WH. Load pig. Pump 3 bbls. Launch pig. Pump 26 bbls water behing to pig line. Break off injector. Remove pig catcher. 10:00 10:30 0.50 RURD COIL Install grapple. Pull test to 22K. PT coil to 3200 psi. Test good. Carry injector to the WH. Blow coil dry using 12,300 scf N2. PU lubricator. MU BHA consisting of coil grapple .68' L X 2.625" OD, straight bar 9.57' L X 2.625" OD. 1.48" ID, 1.25"XN Landing Nipple .78' L X 2.48" OD 1.135 NO GO, Wireline Reentry guide .66' L X 2.50" OD w/ Pump out plug .12' L X 2.18" OD. 10:30 11:00 0.50 TEST EOIP Carry injector to WH. PT shell to 1000 psi. Test good. 11:00 13:00 2.00 RUNPUL COIL Open swab valve and RIH past 10,100'. PUH to 10,100'. Measure span 15.9'. PUH. Set and lock slips. Set and lock pipe rams. Bleed pressure in lubricator. Back off Bowens. Walk Injector up pipe. Set plate and pipe clamp. Cut weep hole. 13:00 13:15 0.25 SAFETY MTG Hold toolbox talk w/ Vetco Gray and BJ Coil crew. Discuss hazards, muster and smoking areas. Discuss job going forward. Measurements and procedures. 13:15 14:45 1.50 RURD COIL Prep pipe ends. Install grapplle on coil. Pull test to 22K. Install Weatherford GS and centralizer. Install Vetco grapple on V-string. MU coil hanger. Latch GS into hanger and PU to tubing weight.(10K) Pull test to 22K. RD pipe clamp and plate. Walk injector down pipe and MU Bowen. Equilize pressure into lubricator. Release pipe rams and slips. 14:45 15:45 1.00 RUNPUL COIL RIH 15'. Set lower dogs in coil hanger. Set weight down on dogs. Run in upper dogs to compress packoff. Pressure test packoff to 5K psi and hold for 10 minutes. Test good. Pressure up on GS and release from hanger. 15:45 17:15 1.50 PUMP N2 Pump N2. Pressure V-string to shear off plug on end of V-string. Flow well to gas buster until gas is flowing at surface. Hand well over to production. 17:15 17:30 0.25 SECURE WELL RD for the night. Install night cap. Turn well over to operations. Well flowing to sales. Secure loc. Turn in permit and leave loc. Re ort Date: 7/23/2010 Job Cate o WO RKOVER 24 Hr Summary Rig down coil equipment today. Job complete no accidents or spills. _ _ - -- ~ Ops Trouble Start Time End Time Dur (hrs) Ops Code Activity Code Status Code Comment -- - - 07:30 08:15 0.75 SAFETY MTG _ --- Hold PJSM. Discuss emergency response, alarms-red flashing strobe for fire alarm, blue flashing strobe for gas alarm, muster area, wind direction, and specific job hazards. Obtain SW Permit. 08:15 12:15 4.00 RURD COIL RD coil unit, BOP's and flowback iron. RD N2 and pumpinng equipment. Reinstal 6" OTIS tree cap. PT w/ well pressure. Test good. Replace all gauges and plugs. PU liners and drip pans. Set gas buster on ground. Replace well house. 12:15 12:15 SECURE WELL Secure well. Turn in permit, sign out and leave loc. www.peloton.com Page 2/2 Report Printed: 8117/2010 nit #: 207-096 ~: 50-133-20571-00-00 ~. Des: ADL 389737 :levation: 187' (21' AGL) 229,025.05 (NAD 27) 225,4940.94 (NAD 27) ude: 60 09' 48.512"N itude: 151 29' 23.738" W d: 07/30/2007 09/07/2007 Released: 09/21/2007 @ 10:00 hrs. i #: DD.06.15534.CAP.CMP Baker Chemical Infection Niople @ 2,382' MD (Top) 5.930" ODI3.858" ID; 8,430 psi burst / ,7500 psi collapse GO-6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. M ~~~n~oM Conductor 20" K-55 133 ppf PE TOp Bottom MD 0' 98' ND 0' 98' Surface Casing 9-5/8" L•80 40 ppf BTC T~ Bottom MD 0' 2,999' TVD 0' 1,788' 12-114" hole with 690 sks (305 bbls) 12 ppg Type 1 cement with 4lbbls cement to surface. Intermediate Casing 7" L-80 26 ppf Mod Butt Tom Bottom MD 0' 9,038' ND 0' 4,433' 8-3/4" hole with 289 sks (126 bbls) 12.5 ppg Lead & 145 sks (30 bbls) 15.8 ppg Tail, did not bump plug, 100 % returns, floats held. Tie-backTubing 4-1/2" L-80 12.6 ppf Hydril 563 T~ Bottom MD 0' 8,842' ND 0' 4,261' Liner 4-1/2" L-80 12.6 ppf Hydril 563 Tom Bottom MD 8,842' 12,069' ND 4,261' 7,437' 7" hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks (100 bbls) 10.5 ppg cement, Plug failed, 100 % Returns. 5-8 bbls cement returns. ' ~ ~ f a ~ Cast Iron Bridge Plug @ 11,470 ~ ~ ~a oc Expro Radial Bond Log - 1 011 112 0 0 7 a Q a ~ Formation Tops : Formation Deoth Beluga Tyonek T1 7,133' MD 3,250' ND Tyonek T2 8,554' MD 4,025' ND Tyonek T3 9,918' MD 5,280' ND TD 12,081' MD 7,437' ND sa c ~ ~ TD PBTD 12,081' MD 11,470' MD 7,437' ND 6,831' ND Velocity Tubing (installed on 7122110) 1-314" HO-70 0.134 wall thickness Tom Bottom MD 0' 10,100' ND 0' 5,461' BHA consisting of coil grapple .68' L X 2.625" OD, straight bar 9.57' L X 2.625" OD. 1.48" ID, 1.25"XN Landing Nipple .78' L X 2.48" OD 1.135 NO GO, Wireline Reentry guide .66' L X 2.50" OD w/ Pump out plug .12' L X 2.18" OD. MD ND Ft 9,457'- 9,482' 4,825'-4,849' 25 ft 3-318" 6spf 60° phase (11121107) 9,482'- 9,511' 4,849'-4,877' 29 ft 3-318" 6spf 60° phase (11/20107) 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8" 6spf 60° phase (11115/07) (Frac'd May 20, 2008) 1 , Well Name & Number: Grassin Oskolkoff # 6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 9,457' - 10,127' Perf (TVD): 4,825' - 5,488' Angle @ KOP & Depth: 5° 1100 ft 196' Angle @ Perfs: 16 ° Date Completed: 11/15/2007 Ground Level: 166' (AMSL) RKB: 21' (AGL Revised by: Kevin Skiba Revision Date: 8/16/2010 ,- • s Kevin J. Skiba Regulatory Compliance Representative Marathon Alaska Production LLC O a7 ~ P.O. Box 1949 Kenai, AK 99611-1949 Re: Ninilchik Field, Tyonek Undefined Gas Pool, Grassim Oskolkoff #6 Sundry Number: 310-187 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. 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 ? day of June, 2010. Encl. • 1lflarathon MARATHON ®Alaska Production LLC June 15, 2010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Application for Sundry Approvals Field: Ninilchik Unit Well: Grassim Oskolkoff #6 Dear Mr. Aubert: Mara~n Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Submitted for your approval is the 10-403 Application for Sundry Approvals for GO-6 well. We propose to run a 1.75" velocity string, in GO-6, to a target setting depth of 10,100' MD. The Cook Inlet region experiences large swings in the seasonal gas production demands. Marathon proposes this well-work activity to help mitigate the negative affects experienced by the infiltrating water during the low demand season. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, al.~ ~. sk.~.~ Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10-403 Application for Sundry Approvals cc: AOGCC Current Well Schematic Houston Well File Proposed Well Schematic Kenai Well File Detailed Operations Program KJS STATE OF ALASKA U'~ U ~~~~'X~' ALASK~ AND GAS CONSERVATION COMMISSI~~.~j'C~ ~~~~ APPLICATION FOR SUNDRY APPROVALS ~ ,,`~Z~ too 20 AAC 25.280 1. Type of Request: Abandon ^ Plug for Redrill ^ Perforate New Pool ^ Repair well ^ Change approved program ^ Suspend ^ Plug Perforations ^ Perforate ^ Pull Tubing ^ Specify: Time Extension ^ Operational shutdown ^ Re-enter Susp. Well ^ Stimulate ^ Alter casing ^ Other: Install velocity string Q 2. Operator Name: Marathon Alaska Production LLC 4. Current Well Class: 5. Permit to Drill Number: Development ^ _ Exploratory ^ 207-096 3. Address: PO BOX 1949 Stratigraphic ^ Service ^ 6. API Number: ~~,-. Kenai Alaska, 99611-1949 50-133-20571-00-.SA1s 7: If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No ~ Gra ssim Oskolkoff #6- 9. Property Designation (Lease Number): 10. Field/Pool(s): C:O 'T"ypN,eK. ut~t.dt'F ~R S ADL-389737 - Ninilchik Unit /dy e 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,081' 7,437' 11,470' 6,831' 1 1,470' NA Casing Length Size MD / TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060 psi 1,500 psi Surface 2,977' 9-5/8" 2,999' 1,788' 5,750 psi 3,090 psi Intermediate 9,017' 7" 9,038' 4,433' 7,240 psi 5,410 psi Production Liner 3,239' 4-1/2" 12,081' 7,437' 8,430 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9,457 - 10,12T f 4,825' - 5,488' Tie-back 4-1/2" L-80 8,842' Packers and SSSV Type: SSSV: - Packers and SSSV MD (ft) and ND (ft): _ Packers: Baker ZXP ,842' D 4,261' TVD 12. Attachments: Description Summary of Proposal ^ 13. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ^ Exploratory ^ Development ^~ r Service ^ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: July 20, 2010 Oil ^ Gas ^~ , WDSPL ^ Plugged ^ 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 Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signature ~ ~ Phone (g07) 283-1371 Date June 15, 2010 COMMISSION USE ONLY nditi n f r v l: N C tif C i i th ti t t it S d N b ~ ~ < J V~ ~~ o o s o app o a o y omm on so a represen ve may w ss a a ness un ry um er: - / Plug Integrity ^ BOP Test Q Mechanical Integrity Test ^ Location Clearance ^ r ~{~~~V~® Other: T 'eS~ ~~~~ "~'O ~SOO ~t-`' . ~~_ls' 1 ~ 2010 ;~k18Slf~? ~~(~ ~8e ~~~ CGtTMnI$SIO Subsequent Form Required: l v ^ `~ O `~ . ~flch~r~ge APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ~ 2 ! (] v RBDi~IS JUN 2 9101 ' Form 10-403 Revised 12/2009 ' ~ ~ ~ ~ ~ ~ Submit in Duplicate ~' • M MARATHON MARATHON ALASKA PRODUCTION LLC ALASKA ASSET TEAM Grassim Oskolkoff #6 Ninilchik Unit Grassim Oskolkoff Pad Coiled Tubing Velocity String Hangoff Procedure WBS # PF.10.22078.CAP.001 APPROVALS: ~ame~ S~t~oot 3/16/10 Program Writer /1~icP~ec~ /V1;u~in G///2U~U Mickey Mullin L. C.16eCe, 6/14/lo Lyndon Ibele Latest Version Date: 6/7/10 Well Status: The well is producing 800 MSCFD at 250 psi with around 2 BWPD. Well has 3/8" capillary string installed @ 10,103' MD. ~ History: 06/30/08: Install 3/8" cap string to 10103' 06/20/08: Pull straddle packers and extension tubes 06/13/08: PT 05/21/08: Frac stim 05/14/08: Set straddle packer at 9512' 05/14/08: GR 3.75" tag 11453' 04/17/08: PLT 01 /23/08: PLT 11/21/07: Perf 9457'-9511' 11 /16/07: Perf 10103'-10127' 11/14/07: Set CIBP 11470' 11 /14/07: PT, fluid at 10584' 10/20/07: Perf 11537'-11568' 10/12/07: CBL to 11978', TOC 8337' 09/22/07: Drilled Well. Objectives: Install a 1.75" CT v-string at bottom perforation. This allows for +/- 0.6 BCF expected incremental recovery, reduced rates for summer curtailment (stable to ~500M w/ VS), and ability to flow well past 2010. Coiled Tubing Velocity String Hangoff Procedure 6/7/2010 -1- Resources: BJ Dynacoil to pull capillary string Coiled tubing set up with pump and N2 pump Approx 10300' of 1.75" CT Arctic Iron choke, gas buster, tank set up Manlift / 2 Light plants Vetco Crew for wellhead modifications/hangoff Procedure: A. Pull Capillary String Current capstring Set Depth: Max OD of BHA: Min ID of 3.5" tubing: • 10103' (5464' TVD) 2.25" FCV 3.858" (chemical injection nipple) Disconnect power to wellhouse (call electrician). MI manlift & lightplants. MI crane, Remove wellhouse. On truck: Empty spool. Paperwork: WBD, Work Permit, Well Ops transfer sheet. 1. Ensure pumps are off and pressure has been safely bled from the CICM side of the tubing prior to job. 2. Disconnect tubing at manifold. Catch any foamer to absorbent. 3. Bleed pressure from the Dyna-Coil using the needle valve. Catch any foamer to absorbent. 4. MIRU BJ Dyna-Coil unit. Place liner around wellhead/truck. Set outriggers & ground. Flag off location. Record well flowrate /pressure. 5. P/U spool and mount on truck. 6. Break injector head and insert 3/8"coil into injector chains. 7. P/U Dyna-Coil injector with crane. 8. Lower injector head carefully on to the pack-off (line up slot with the pack-offs '/" x 4" nipple). 9. Attach hydraulic hoses to hydraulic rams and check pressure (should be 3000 psi). 10. Pressure hydraulic rams (top seal, '/" nipple) on pack-off to 1500 psi. 11.Open Rattiguns all the way. Watch for pressure leaks. 12.Open slips. Monitor weight indicator to ensure injector is holding weight. 13. Insert snubbing guides. 14. Wrap wellhead and packoff with absorbents to catch drips. Clear wellhead. 15. Set depth counter to 10103'. POOH several hundred feet (call if pulling over 4000#) run back and attempt to tag bottom. Record tag depth 16. Pull capillary string out of well. Bleed pressure off capillary string making sure to use absorbents to capture any injection fluid that may leak out. Coiled Tubing Velocity String Hangoff Procedure 6/7/2010 -2- • 17. Shut swab valve below capillary string. 18. Lift injector head off and away from well. 19. Replace extension on wellhead with tree cap. Pressure test cap. 20. Rig down BJ Dynacoil unit. RDMO. Clean up site. Sign-out and turn in work permit. B. Install Coiled Tubing Head Talk to construction and make arrangements to complete instrumentation, electrical, logic, and FCO to minimize shut-in time. Shut in well. Vetco to set 4" Cameron Type-H BPV. Close bottom master. Bleed off pressure and check for flow. Remove top master and install new Vetco 4-1/16 5M CT Head with 2-1/16" 5M side outlet. Install 2-1/16" gate valve and SSV to side outlet on coil tubing head. Reinstall and test (with diesel) top master and swab valve. Make final measurements to install flowline to CT Head outlet. Pull BPV. C. F/owline modifications for coil tubing string Hand over well to construction to modify flowline and install v-string flowline and choke. Velocity string flowline does not need dedicated gas metering (IPR indicates no appreciable rate gain for flowing up annulus). After complete, return well to production. D. MIRU MOC flowback equipment This includes open-top flowback tank, choke skid, gas buster, and flowback iron. Spot flowback tank close enough to run CT into tank for pigging. MIRU closed- top 500 bbl fluid supply tank. Lay liner and berm area around tank. Load fluid supply tank with 6% KCI. E. Hang Off 1.75" CT MIRU BJ coiled tubing unit. Verify 24 hour notification has been made to AOGCC for BOP test. Rig up fluid and N2 pumps. RU pumping iron (BJ) and flow back iron (MOC). RU equalizing hose from BOP to top of lubricator. 2. Pig CT. Run end of CT with pig catcher made up into flowback tank. Pump 5 bbls water, cleaning pig, and coil displacement +10% behind pig. Coiled Tubing Velocity String Hangoff Procedure 6/7/2010 -3- • . 3. Nipple up BJ CT wellhead assembly (WHA). Current WHA is 4-1/16" 5M swab/cap. WHA to include 4-1/16" - 5M X 4-1/16" - 10M DSA, 4-1/16" - 10M X 5' Flanged Riser, 4-1/16" -10M flow cross and 4-1/16" - 10M Dual-Combi BOP (dressed for 1-3/4" CT). Function test BOP. Stab 1-3/4" CT into injector. Have BJ coil tubing connector welded on prior to job off location and pull test to 15,000 lbs. Nipple up injector to WHA. 4. Perform complete BOP test and complete AOGCC BOP test report (Correct form dated 01/25/2010). Pressure test pump iron (200 low/~04'high psi). Pump fluid to load CT. Pressure test CT, WHA and flow back~iron to choke manifold (200/4500 psi). Pressure test BOP rams (200/450Q-psi). Purge pressure test fluids w/ N2 to flowback tank and vent N2 `pressure to flowback tank. Note BOP test witness or waiver in WeIlView, including details. 5. MU CT BHA. Nipple injector off WHA. PU 10' of 4-1/16" CQ lubricator. MU velocity string BHA to end of CT. BHA to include: a. 2.50" OD X 1.50" ID CT grapple connector, b. 2.50" OD X 1.50" ID X 10' long box x box straight bar, c. 1.91" OD X 1.25" PXN (1.135" no-go) pin x pin, d. 2.50" OD x 2.50" OD (1.50" ID top box x 2.0" ID bottom) wireline re-entry guide with 2.0 OD" x 2.50" OD O-ring sealed aluminum pump-off plug. Strap and record velocity string BHA dimensions and lengths. Include record in WeIlView and on updated WBD. 6. Nipple up infector to WHA. Pressure test WHA using CT kill line (200/1500 psi). Bleed WHP to flow back tank. Prior to next Step, ensure that flowback line from WHA through choke manifold to gas buster is ready and available to keep TP at or below 1500 psi while RIH to eliminate possible CT collapse. This would serve as a backup if flow through the production flow line was unexpectedly curtailed or ceased. 7. RIH with coil tubing velocity string and BHA with well flowing to sales up annulus (running v-strings into shut in wells has been very unsuccessful). 8. Cut coil tubing. POH to span WHA for final landing depth, 10100' Set CT in BOP tubing/slip rams. Lock tubing/slip rams. Slack off injector chain traction and roll chains to verify slips are set. Release WHP above tubing rams to the flowback tank. Nipple injector off of WHA. Walk injector up CT. Install C plate above BOP and polish rod clamp on CT. Cut CT above BOP high enough to allow Vetco to install CT connector and hanger mandrel assembly. Coiled Tubing Velocity String Hangoff Procedure 6/7/2010 -4- • . 9. MU Vetco Coil Tubing Hanger and Weatherford Hydraulic Release GS Running Tool. (Only hand file outside of CT above BOP. NO HOT WORK PERMIT REQUIRED). GS running tool should be plugged to release on pressure, not rate. Swing Injector and lubricator away from WH. Vetco to connect VGCT Coil Tubing Hanger (4" Nom C/W 3" Weatherford Fishneck with 2-3/8" 8rd Box and 2" BPV) to hanging coil tubing with coil grapple. While Vetco is making up CT hanger, BJ CoilTech to connect Weatherford GS tool string assembly to coil on reel trailer. Dimple-on a 1-3/4" CT connector. Pull test CT connector (25,000 lbs.) using 1.125" 10SA box X 1- 1/2" MT pin crossover and 1-1/2" MT box pull plate. Tool string will consist of 1-3/4" slimline dimple-on, 1-3/4" DF check valve, 1.125' 10SA box X 1-1/2" MT pin X-over and a plugged 3" GS spear. PU or lay down 4" lubricator as needed to cover GS tool string and Vetco CT hanger. 10. Latch GS spear to Vetco mandrel after PU injector. Remove polish rod clamp and C-plate from top of BOP. Accurately measure from hanger assembly to CT lock down screws. Walk injector down CT and nipple injector/lubricator to top of BOP. Pull test CT mandrel connection/GS spear assembly to CT string weight plus 5,000 lbs. Slack off weight to CT string weight. Measure and mark the exact distance that the CT has to move down to align the hanger. Make all measurements on the gooseneck with all rollers locked. Equalize WHP across tubing rams. Unlock tubing/slip rams. Open BOP tubing/slip rams. 11. RIH and land Vetco CT hanger per Vetco procedures. (Stop hanger 1' high and run lower lockdown screws to their landing position. Lower hanger onto the lockdown screws and then lock upper screws. Verify string and hanger are landed and secured per Vetco procedures. Slack off string weight to neutral. Tighten lock screws. Pressure test hanger between O-rings to 5000 psig with hand pump pressure test unit (Vetco Supplied). 12. Release GS Running Tool. Start pumping 6% KCL water or N2 to pressure up CT to release GS spear. Set down weight and then pick GS off of hanger 13. RD and release CT. RD equipment, clean location, and turn in work permit. F. Pressure Up and Blow Pump-Off Plug Shut in sales and allow WHP pressure to build up to 1100 psi. Jumper gas from annulus to coil tubing until CT WHP is 1100 psi. While leaving CT shut in, open annulus to sales. The differential pressure between the coil tubing and annulus should blow off the pump out plug. If the situation dictates, pump off plug with N2. Coiled Tubing Velocity String Hangoff Procedure 6/7/2010 -5- • G. Flow Test Well to Sales No more than a 60%drawdown with methane gas in wellbore is permitted for the lowest open interval. Obtain stabilized flow within the 60%drawdown limit. The unloading rate up 4-1/2" casing and 1.75" coil tubing in a vertical well is 4.0 MMCFPD and 638 MCFPD, respectively, at 800 psig FCP. Flow well to sales observing recommended drawdown rates. H. Complete Well Ops Transfer Sheet and distribute. WBD LINK GO 06 PT 04-17-08 F.pdf Considerations, Instructions, and Planning: A pre-meeting with the construction group is required. Talk to construction and make arrangements to complete instrumentation, electrical, logic, and FCO to minimize shut-in time. V-string candidates don't normally like shut-ins, and having a "rush" job adds considerably to the cost of the tree work. A hot work permit is necessary for grinding the top of the CT above the BOP to allow installation of the dimple on connector when the v-string is pulled. This permit requires special approval and must be obtained before the job. When running the v-string, only allow hand filing of the outside of the CT above the tree to avoid the necessity of the hot work permit. Hand filing the outside is sufficient to install the external connector. Pigging the coil is a good practice generally and required if we are running used pipe from BJ. If you pig the CT stabbed onto the well you will fill the tree with rust and create problems. Make sure that everyone plans to pig directly into the tank to keep the debris away from the tree. The critical point in the job is spacing out to hang off the CT. If the space out and procedure is not correct the CT or hanger can easily be damaged causing significant extra time and money. Organize a job meeting before the injector is walked back down to the BOP to ensure everything is measured and correct. There are 2 kinds of CT hangers in the field. The new style hanger has seals that are energized by the lockdown screws. The old style hanger has o-rings and is a larger OD. If an old style hanger is pulled from the well it should be discarded and replaced with the new style. A third hanger is in final design as of Sept-09. This design has shear screws to stop from prematurely energizing the seal while running through the lubricator or tree. Coiled Tubing Velocity String Hangoff Procedure 6/7/2010 -6- • • It is necessary to use straight bars to align the hanger and GS. Use a 6' straight bar between the CT connector and the hanger and above the GS spear use 2 large centralizers separated with a 2' - 3' straight bar. If running a 4" hanger in 4-1/16" lubricator (or 3" in 3-1/8") it is necessary to install a pump in sub at the top of the lubricator and connect a hose from the top pump- in sub to the BOP to equalize around the hanger. Differential across the hanger can energize the seals and then they will be damaged running the hanger through the lubricator. Vetco is redesigning the 4" hanger to severely reduce this possibility (in final design stage in Sept09). It is safer to latch the hanger with the GS after the lubricator is reconnected to avoid walking the injector down the pipe. Either method works but with the straight bar below the hanger and the double centralizers above the GS it is easy to latch inside the lubricator. When running the 3" hanger latching the GS inside the lubricator is not an option unless you have 3-1/8" lubricator and an equalizing system. Coiled Tubing Velocity String Hangoff Procedure 6/7/2010 -7- s -oo-oo Grassim Oskolkoff #6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. M MARATHON Latit Lon_ I . S u TD: ~ Rig WB ~ ~ ,. KOP @ 196' MDIND Build 5.0 deg/100' from 200-1583' MD Hold 67 deg from 1583-7354' MD Drop 2.5 deg1100'to 10,120' MD Hold 0 deg from 10,120'to TD at 10,090' MD Azimuth: 290.931 deg. Tubing String - 4.5", 12.6#, L-80, Hydril 563 $ Casing String - 4.5", 12.6#, L-80, Hydril 563 Baker Chemical Injection Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID; 8,430 psi burst / ,7500 psi collapse ZXP Liner Packer with 15' Tieback Extension @ 8,830.24' MD (Top) Flex-Lock Liner Hanger @ 8,862.31' MD (Top) Marker Joint Top @ 9,925.5' MD (19' long) Marker Joint Top @ 10,929.5' MD (19.5' long) Landing Collar Top @ 11,983.91' (1.53' Long) Float Collar Top @ 12,025.56' (1.55' Long) Float Shoe Top @ 12,066.95 (2.05' Long) s Formation Tops: Formation Depth Beluga Tyonek T1 7,133' MD 3,250' ND Tyonek T2 8,554' MD 4,025' ND Tyonek T3 9,918' MD 5,280' ND TD 12,081' MD 7,437' ND 3/8" Capillary string @ 10,103' KB 06/30/08 ~L ~ c ~ ~ Castlron Bridge Plug @ 11,470' a ~ Expro Radial Bond Log - 10111/2007 ~ c a ~ Conductor 20" K-55 133 ppf PE TOp Bottom M D 0' 98' rvD o' 9a' Surface Casino 9-518" L-80 40 ppf BTC T~ Bottom MD 0' 2,999' TVD 0' 1,788' 12-114" hole with 690 sks (305 bbls) 12 ppg Type 1 cement with 41bbls cement to surface. Intermediate Casing 7" L-80 26 ppf Mod Buttress Tom Bottom MD 0' 9,038' ND 0' 4,433' 8-3/4" hole with 289 sks (126 bbls) 12.5 ppg Lead & 145 sks (30 bbls) 15.8 ppg Tail, did not bump plug, 100 % returns, floats held. Tie-backTubing 4-112" L-80 12.6 ppf Hydril 563 Tom Bottom MD 0' 8,842' TVD 0' 4,261' 12" L-80 12.6 ppf Hydril 563 Tog Bottom MD 8,842' 12,069' ND 4,261' 7,437' hole with 20 bbl MCS-43 spacer with red e followed by 195 sks (100 bbls) 10.5 ppg roent, Plug failed, 100 % Returns. 5-8 bbls ment returns. MD ND Ft 9,457'- 9,482' 4,825'-4,849' 25 ft 3-318" 6spf 60° phase (11/21107) 9,482'- 9,511' 4,849'-4,877' 29 ft 3-318" 6spf 60° phase (11120/07) 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/S" 6spf 60° phase (11115/07) Frac'd May 20, 2008 1 , TD PBTD 12,081' MD 11,470' MD 7,437' ND 6,831' ND Well Name: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 9,457' - 10,127' (ND): 4,825' - 5,488' Angle @ KOP and Depth: 5° 1100 ft @ 196' Angle @ Perfs: 16 ° Dated Completed: 11115/2007 Completion Fluid: 6 % KCL Revised by: Nancy Henry Last Revison Date: 7/1412009 ~. Des: ADL 389737 :levation: 187' (21' AGL) 229,025.05 (HAD 27) 225,4940.94 (HAD 27) ude: 60 09' 48.512"N gitude: 151 29' 23.738" W p d; 07/30/2007 09/07/2007 Released: 09/21/2007 @ 10:00 hrs. S #: DD.06.15534.CAP.CMP API#: 50-133-20571-00-00 Prop. Des: ADL 389737 KB Elevation: 187' (21' AGL) X: 229,025.05 (NAD 27) Y: 225,4940.94 (NAD 27) Latitude: 60 09' 48.512"N Lonaitude: 151 29' 23.738" W Spud: 07/30/2007 TD: 09/07/2007 Rip Released: 09/21/2007 @ 10:00 hrs WBS #: DD.06.15534.CAP.CMP KOP @ 196' MDITVD Build 5.0 deg1100' from 200-1583' MD Hold 67 deg from 1583-7354' MD Drop 2.5 deg/100' to 10,120' MD Hold 0 deg from 10,120' to TD at 10,090' 290.931 deg. PROPOSED Grassim Oskolkoff #6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. ~~ ~ ~~~ ~..n .......y ,. ~... ,, ,.. .,..., ing String - 4.5", 12.6#, L-80, Hydril 563 er Chemical Injection Nipple @ 2,382' MD (Top) 0" OD/3.858" ID; 8,430 psi burst / ,7500 psi collapse Liner Packer with 15' Tieback Extension @ 8,830.24' (Top) Lock Liner Hanger @ 8,862.31' MD (Top) ker Joint Top @ 9,925.5' MD (19' long) ker Joint Top @ 10,929.5' MD (19.5' long) ding Collar Top @ 11,983.91' (1.53' Long) it Collar Top @ 12,025.56' (1.55' Long) it Shoe Top @ 12,066.95 (2.05' Long) Formation Tops: Formation Depth Beluga Tyonek T1 7,133' MD 3,250' TVD Tyonek T2 8,554' MD 4,025' TVD Tyonek T3 9,918' MD 5,280' TVD TD 12,081' MD 7,437' TVD a s a s +JJJJ ~~~f ' (((~] Castlron Bridge Plug @ 11,470 a 9 6 Expro Radial Bond Log - 10111/2007 T ~ s a ~ '- TD PBTD 12,081' MD 11,470' MD 7,437' TVD 6,831' TVD M MARATHON Conductor 20" K-55 133 ppf PE TO~I Bottom M D 0' 98' TVD 0' 98' Surface Casino 9.5/8" L-80 40 ppf BTC Top Bottom MD 0' 2,999' TVD 0' 1,788' 12-1/4" hole with 690 sks (305 bbls) 12 ppg Type 1 cement with 41bb15 cement to surface. Intermediate Casing 7" L-80 26 ppf Mod Buttress Tom Bottom MD 0' 9,038' TVD 0' 4,433' 8-314" hole with 289 sks (126 bbls) 12.5 ppg Lead & 145 sks (30 bbls) 15.8 ppg Tail, did not bump plug, 100% returns,floats held. Tie-backTubing 4-112" L-80 12.6 ppf Hydril 563 Tom Bottom MD 0' 8,842' TVD 0' 4,261' 4-112" L-80 12.6 ppf Hydril 563 ' Tom Bottom MD 8,842' 12,069' TVD 4,261' 7,437' 7" hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks (100 bbls) 10.5 ppg cement, Plug failed, 100 % returns. 5-8 bbls cement returns. Velocity String (installed xxlxx/xx) 1.75" 0.125" wall 1.50" ID T~ Bottom MD 0' 10,100' TVD 0' 2.50" OD X 1.50" 10' long b i ~ go) pin x ~ 0" 1 bottom) r` i e~ie wide X1.50"IDX 25" PXN (1.135" no- ID top box x 2.0" ID MD TVD Ft 9,457'- 9,482' 4,825'-4,849' 25 ft 3-318" 6spf 60° phase (11/21107) 9,482'- 9,511' 4,849'-4,877' 29 ft 3-318" 6spf 60° phase (11/20107) 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8" 6spf 60° phase (11115/07) Frac'd May 20, 2008 1 , Well Name: Grassin Oskolkoff #6 Lease: Ninilchik Unit Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 9,457' - 10,127' (TVD): 4,825' - 5,488' Angle @ KOP and Depth: 5° 1100 ft @ 196' Angle @ Perfs: 16 ° Dated Completed: 11/1512007 Completion Fluid: 6% KCL Revised by: Last Revison Date: ~ i ~~ r ~ .;~~~ ~~ ~ '~ , ~~~ b ~`~` MICROFILMED 6/30/2010 DO NOT. PLACE ANY N EW MATERIAL UNDER TH iS PAG E C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc DATA SUBMITTAL COMPLIANCE REPORT 11 /19/2008 Permit to Drill 2070960 Well Name/No. NINILCHIK UNIT G OSKOLKOFF 6 Operator MARATHON OIL CO APt No. 50-133-20571-00-00 MD 12069 TVD 7429 Completion Date 11/22/2007 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional nrey Yes DATA INFORMATION Types Electric or Other Logs Run: Quad Combo, CBL (data taken from Logs Portio n of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Tye Med/Frmt Number Name Scale Media No Start Stop CH Received Comments QED C Las 15721 Mud Log 9030 12053 Open 11/28/2007 LAS File, Den, CLDC, GR CGXT -Mudlog D E C 15721 See Notes 0 0 Open 11/28/2007 Final Well Report, LAS, PDF Log Files, Morning ~~ Reports, DML Files - Mudlog Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y Chips Received? Y % N -' Analysis / ~"'T 11~ Received? Daily History Received? ~/ N Formation Tops r~ L__J Comments: Date: Compliance Reviewed By: ~~~ M Marathon MARATHON Oil Company July 25, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 err ~~~ Reference: 10-404 Report of Well Operations Field: Ninilchik Unit Well: Grassim OskolkofF #6 Dear Mr. Maunder: Attached for your records is the 10-404 Report of Well Operations for GO-6 well. This report covers the Capillary string installation work that Marathon completed under sundry #308-216. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, `~ ~~ Kevin J. Skiba Engineering Technician Enclosures: 10-404 Sundry Report Operations Summary Well Schematic cc: Houston Well File Kenai Well File KJS DMD ~~ -E72t ~ ,~ STATE OF ALASKA " • ~., f0-D~ AL~KA OIL AND GAS CONSERVATION COIISSION r r} n REPORT OF SUNDRY WELL"~OP~F~-~~NS ~I 1. Operations Abandon Repair Well Plug Perforations Stimulate ~ ° • Other ~ Install Capillary Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ ' '' Waiver^ Time Extension ^ String . Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2.Operator Marathon Oil Company N 4. Well Class Before Work: 5. Permit to Drill Number: ame: Development^ Exploratory^ 207-096' 3. Address: PO Box 1949 Stratigraphic ^ Service ^ 6. API Number: ~ Kenai Alaska, 99611-1949 50-133-20571-00-00 7. KB Elevation (ft): 9. Well Name and Number: 187' 21' AGL ~ Grassim Oskolkoff #6 8. Property Designation: 10. Field/Pool(s): ADL-389737 ~ Ninilchik Unit / Tyonek Pool 11. Present Well Condition Summary: Total Depth measured 12,069'- feet Plugs (measured) 11,470' true vertical 7,42g' T feet Junk (measured) NA Effective Depth measured 11,470' " feet true vertical 6,831' ~ feet Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060 psi 1,500 psi Surface 2,977' 9-5/8" 2,999' 1,788' 5,750 psi 3,090 psi Intermediate 9,017' 7" 9,038' 4,433' 7,240 psi 5,410 psi. Production Liner 3,239' 4-1/2" 12,081' 7,437' 8,430 psi 7,500 psi Perforation depth: Measured depth: 9,457'-10,127' (gross) open perF interval 4,825' - 5,488' (gross) True Vertical depth: open pert interval Tubing: (size, grade, and measured depth) 4-1/2" L-80 8,842` Packers and SSSV (type and measured depth) Baker ZXP Packer 8,836' MD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions inGuding 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: 0 650 2.3 0 343 Subsequent to operation: 0 650 2.3 0 343 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development^ Service ^ Daily Report of Well Operations 16. Well Status after work: Oil ^ Gas Q 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: 308-216 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician Signature . ~ Phone (907) 283-1371 Date July 25, 2008 Form 10-404 Revised 04/2006 ~ .~ Submit Original Only aY ~ ~ ~ ~ ~~ A I ~ l~u~ ~ zoos Operations Summary Repolr~ Well Name: GRASSIM OSKOLKOFF I I Re ort Date: 7/1/2008 Job Cate o R8M MAINTENANCE 24 Hr Summary MIRU BJ Dynacoil. Install 3/8" capillary string to 10,103' KB . . . Load tube w/ 26 gallons(75°~ of capacity) of foamer. Install power to Foamer skid. ,.~ ~; tart?lme ;., ~r,d Tfine> ur. B , : pops co _ d. ~; eurny:code ~ t„s ~ ~We erode' ~ ~ -._ - 08:00 09:00 1.00 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response. _ Discuss BJ JSA and specific job hazards. Obtain SWP. 09:00 10:30 1.50 RURD COIL AF Spot equipment. RU Dynacoil unit. Install "new" tree cap. 10:30 10:54 0.40 TEST EQIP AF PTest "new" tree cap to 2500 psi. Test good. 10:54 11:24 _ 0.50 RUNPUL COIL AF Stab tubing into injector. Cant' injector to WH. MU packoff. 11:24 13:36 2.20 RUNPUL COIL AF _ Run 3/8" coil to 10,103' KB. 13:36 14:06 0.50 RUNPUL COIL AF Land coil @ 10,103' KB. Install slips on tubing in packoff. Remove coil from injector assembly. 14:06 15:06 1.00 RURD COIL AF Begin pumping foamer to load cap string to 75% capacity (26 gallons). 15:06 16:06 1.00 RURD COIL AF Foamer pumped. Set down coil spool. Hook up electrical power. No __ _ instrument fitters available. Will make tubing connections in the morning. 16:06 16:21 0.25 SECURE WELL AF Secure well and location. Install signage and LOTO on both master valves and swab valve. Tum in permit. Sign out and leave loc. Continue flowing well. www.peloton.com _- - - - - - - -- - _ _ Report Printed: 7/25/2008 i • 50-1 3 3-20571-00-00 g,~ zo7-09s ry Dea: ADL 389737 DD.06.15534.CAP.CMP 229,025.05 (NAD27) 225,4940.94 (NAD27) 60 09' 48.512" N 151 29' 23.738" W 4:00 hrs 7/3012007 7:30 hrs 9/0712007 E•d Rich 10:00 hrs 912112007 KOP @ 196' MDITVD Build 5.0 deg/100' from 200-1583' MD Hold 67 deg from 1583-7354' MD Drop 2.5 deg/100' to 10,120' MD Hold 0 deg from 10,120' to TD at 10,090' MD Azimuth: 290.931 deg. Grassim Oskolkoff #6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. J~ ~r Chemical Injection Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID 8,430 psi burst / ,7500 psi collapse Liner Packer with 15' Tieback Extension @ 8830.24' MD (Top) Lock Liner Hanger @ 8862.31' MD (Top) er Joint Top @ 9925.5' MD (19' long) :er Joint Top @ 10,929.5' MD (19.5' long) Iing Collar Top @ 11,983.91' (1.53' Long) t Collar Top @ 12,025.56' (1.55' Long) t Shoe Top @ 12,066.95 (2.05' Long) 318" Capillary suing @ 10103' KB (06130108) ~ t~ Cast Iron Bridge Plug @ 11,470' a al Bond Log - 10/11/2007 t ~ Tops: Beluga Tyonek T1 Tyonek T2 Tyonek T3 TD ~ tc a t~ ~~~~~~~ Ii2~ 12,081' MD 7,437' TVD PBTD; 11,470' MD M M~ra-n~oM L Conductor 20" K-55 133 ppf PE Top Bottom MD 0' 98' TVD 0' 98' Surface Caeina 9-516" L-00 40 ppf BTC ott m MD 0' 2,999' rvD o• 1 aea• 12-114" hole whh 690 sks (305 bbls)12 pp0 Type 1 cement with 4l bble cement to surface. I mermedlab Casino 7" L-80 26 ppt Mod Buttress ~ Bottom MD 0' 9,036' TVD 0' 1,433' 8-3/4" hoN with 289 sks (126 bble) 12.5 ppg Lead 8:145 sks (30 bbla) 15.8 ppg Tall, did not bump plug, 100% returns, floats held. Tia-backTubinc 4-112" L-80 12.6 ppf Hydrll 563 ]yp o n MD 0' 8,842' TVD 0' 4,261' Liner 4-112" L-00 12.6 ppf Hydrll 563 IPp om MD 6,642' 12,069' TVD 4,261' 7,437' 7" hole with 20 bbl MCS~3 spacer with red dye followed by 195 sks (100 bbls) 10.5 ppg cement, Plug failed, 100% Returns. 5.8 bbls cement returns. MD TVD Ft 9,457'- 9,482' 4,825'-4,849' 25 ft 33/8" 6spf 60° phase (11121/07) 9,482'- 9,511' 4,849'-4,877' 29 ft 3318" 6spf 60° phase (11120/07) 10,103'-10,127' 5,464'-5,488' 24 ft 3318" 6spf 80° phase (11115/07) Frac'd May 20, 2008 11,b3T'-4'irli68'- 6,888~i,82&- S4# 2-318"- Well Name 8 Number: Grassim Oskolkoff # 6 Lease: Ninilchik Unit Count or Parish: Kenai Peninsula Borou h State/Prov: Alaska Count USA M le KOP and h: S° 1 100 k 186' M b/Perfs: KOP TVD : 196' Date Com leted: 1111512007 Ground Level above MSL : 166' RKB above GL : 21' Pre ared B : Kevin Skiba Last Revision Date: 07/25108 Last Revision Date: 6/24/2008 MBS M Marathon MARATHON Oil Company July 25, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7~' Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Ninilchik Unit Well: Grassim Oskolkoff #6 Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Attached for your records is the 10-404 Report of Sundry Well Operations for GO-6 well. This sundry covers the GO-6 fracture stimulation work that Marathon completed under sundry #308-165. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Engineering Technician Enclosures: 10-404 Sundry Report Operation Summary Well Schematic cc: Houston Well File Kenai Well File KJS KDW ~~~-U i~o STATE OF ALASKA ~ ~ r ti-- , AL KA OIL AND GAS CONSERVATION4CS51- REPORT OF SUNDRY WELL O16~~,.E-~~IS ~~ ,~ 0-08 1. Operations Abandon Repair Well Plug Perf 1ST ,_ imulate ~ ~ Other Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ~"'' '~iiit~nsion ^ Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re=enter Suspended Well ^ 2. Operator Marathon Oii Company N 4. Well Class Before Work: 5. Permit to Drill Number: ame; Development Q Exploratory^ 207-096 3. Address: PO Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20571-00-00' 7. KB Elevation (ft): 9. Well Name and Number: 187', Grassim Oskolkoff #6 8. Property Designation: 10. Field/Pool(s): ADL 389737 ~ Ninilchik Unit / T onek Pool 11. Present Well Condition Summary: Total Depth measured 12,069' - feet Plugs (measured) 11,470' true vertical 7,429' • feet Junk (measured) NA Effective Depth measured 11,470' • feet true vertical 6,831' - feet Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060 psi 1,500 psi Surface 2,977' 9-5/8" 2,999' 1,788' 5,750 psi 3,090 psi Intermediate 9,017' 7" 9,038' 4,433' 7,240 psi 5,410 psi Production Liner 3,239' 4-1/2" 12,081' 7,437' 8,430 psi 7,500 psi Perforation depth: Measured depth: 9,457'-10,127' (gross) open perF interval 4,825' - 5,488' (gross) True Vertical depth: open perF interval Tubing: (size, grade, and measured depth) 4-1/2" L-80 8,842' Packers and SSSV (type and measured depth) Baker ZXP Packer 8,836' MD 12. Stimulation or cement squeeze summary: Intervals treated (measured): Tyonek Zone 10,103' -10,127' Treatment descriptions including volumes used and final pressure: Fracture Stimulate with 36,280 Ibs of 20/40 sand 8 5,234 Ibs of Flex sand 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 650 4.2 0 349 Subsequent to operation: 0 1,910 2.3 0 343 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ^~ Service ^ Daily Report of Well Operations 16. Well Status after work: Oil^ Gas Q 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: 308-165 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba ~ Title Engineering Technician Signature - . Phone (907) 283-1371 Date July 25, 2008 ~ corm 10-404 FZeviseo 04/2006/ > `° I'~y ~ ~ ~ ~ /t ~ ~ ~~~ A~~ 4 ~j 1D~8 submit Original only Operations Summary Repoli Well Name: GRASSIM OSKOLKOFF Ops Trouble Start lime End Time Dur (hrs Ops Code Activity Code Status Code Comment -----_- -- ~~ Daily Operations -- - - -- Re ort Date: 5/14/2008 Job Cate o R8M MAINTENANCE 24 Hr Summary MIRU Pollard to run a tag and 3.75" GR. Expro to run Lower straddle packer and set at 9512' (CH). -_ T __ -- ~-r Opa '` Trou le Start Tlme End Time Dur (hrs) Ops Code Activity Code Status Code Comment 08:00 09:30 1.50 SAFETY MTG AF Hold PJSM. Obtain Safe Work Permit. Discuss ASRC and Pollard JSA. Discuss heavy traffic due to Frac RU. Multipule service companies involved. Operations installs LOTO on WH and Flow line. Hold Pre-lift meeting. Well on compression 800 mcf/d @ 400 psi. 09:30 10:30 1.00 RURD SLIK AF Spot crane, Wire line, and E line equipment. Rig up. MU tool string rope socket, knuckle joint, 2-1/4" roller stem, knuckle jt., hydraulic jars, roller spang jars, 3.68" roller boogie, 3.75" fluted centralizer, 3.68" roller boogie, 3.75" GR. 10:30 11:00 0.50 TEST EOIP AF PTest lubricator to 2000 psi. Test good. 11:00 13:00 2.00 RUNPUL SLIK AF RIH w/ 3.75" GR, 3.68" roller boogie, 3.75" fluted centralizer. Taa PBTD CrD11453' KB. POOH.Tools stuck ~ 10543'. Jar down, work tools. Drag something up hole with us to 10468'. Shake it loose and POOH. OOH. RD lubricator and tool string. No foreign material on tools. 13:00 13:30 0.50 RURD ELEC AF RU Expro lubricator and tool string. 13:30 14:00 0.50 SAFETY MTG AF Hold Explosives Safety Meeting. Shut down all cell phones, radios, and SKADA. Check stray voltage. Post signage and station guard at the gate to location. Arm Owen MSST setting tool and MU packer. 14:00 17:00 3.00 RUNPUL ELEC AF RIH. Run correlation pass at ZXP liner hanger. Set lower Weatherford ER Packer. Elements @ 9512' (ccl 9499' To of ac er Set down on packer to confirm set. POOH. OOH. RD. 17:00 18:00 1.00 SECURE WELL AF Tum in permit. Sign out. Leave loc. Re ort Date: 5/1 512 0 0 8 Job Cate o R8M MAINTENANCE 24 Hr Summary Pollard ran Lower straddle spacer pipe w/ snap latch and tie back receptacle. Expro set upper straddle spacer pipe and packer assembly. WHP 1000 psi. Ops Trouble ~:. -,r - Start 71me End Tl ~ Dur (hr9) J Ops Code ~ 1 Actvity Code Status ~ ode - ~ ~ Comrnen[ 08:00 08:45 0.75 SAFETY MTG AF Hold PJSM. Obtain Safe Work Permit. Discuss ASRC and Pollard JSA. Discuss heavy traffic due to Frac RU. Multipule service companies involved. 08:45 09:30 0.75 RURD SLIK AF PU lubricator. MU tool string rope socket, knuckle joint, 2-1/4" roller stem, knuckle jt., hydraulic jars, roller spang jars, 3.68" roller boogie, 4-1/2" GS, and lower straddle spacer pipe w/ snap latch and tie back recepticale. 09:30 09:40 0.17 TEST EOIP AF PTest lubricator to 1500 psi. Test good. 09:40 10:50 1.17 RUNPUL SLIK AF RIH w/ lower straddle assembly. Run thru 2:XP packer @ 8860'. Establish PU weight @ 9400'. 950 # Ta 9519'. PU to 1200#. Confirm latched into Lower Dacker. Shear own an o POOH. Hold Expro PJSM. Discuss JSA and job scope. 10:50 11:05 _ 0.25 RURD SLIK AF ---- --- OOH. RD lubricator and tool string. 11:05 -- 11:50 0.75 RURD ELEC ~ AF ___ _ - ------ RU Expro lubricator and tool string. __ 11:50 12:30 0.67 SAFETY MTG AF Hold Explosives Safety Meeting. Shut down all cell phones, radios, and SKADA. Check stray voltage. Post signage and station guard at the gate to location. www.peloton.com Report Printed: 7/2512008 Operations Summary Repo Well Name: GRASSIM OSKOLKOFF Ops Trouble Start Tlme End Tlme Dur (hra) Ops Code Actlvity Code Status Code Comment 12:30 15:15 2.75 RUNPUL ELEC AF PU lubricator. Arm Owen MSST setting tool and MU Weatherford ER packer. PTest Expro lubricator to 1500 psi. WHP 900 psi. RIH. Run correlation pass at ZXP liner hanger. PU weight 1310# Run tool string into tie-back latch. Overpull 800# (2100#). Confirm latch into SO snap-latch. PU to neutral point 1300# and set Weatherford ER acker 9450'. e own on pac er o con trm set. POOH. 15:15 15:30 0.25 RURD ELEC AF OOH. PU gamma ray/ ccl tools. Test OTS. RIH. 15:30 18:00 2.50 RUNPUL ELEC AF RIN w/ 1-11/16" gamma ray/ CCL tool string. Run thru straddle packers w/ 1-11/16" GR/CCL and log up. Bottom of packer 9512'. To acker 9446.5'. 18:00 18:45 0.75 RURD ELEC AF Rig down eline. 18:45 19:00 0.25 SECURE WELL AF Tum in permit. Sign out. Leave loc. Daily Operations Re ort Date: 5/17/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary MIRU pit liner crew. MIRU frac tanks and flowback tanks. ` ~ Ops Trouble ~ _~ Star[Time End Tlme Dur_ hra -,. ~-0ps Code Acdvi Code.: , Status Code;) , , : Comment 08:00 09:00 1.00 SAFETY . MTG ~ AF Hold PJSM. Obtain Safe Work Permit. ~~~ ~_ 09:00 17:00 8.00 PREP LOC AF Lay liner for fluid tanks, choke and flow back tanks, and for all frac equipment. Spot frac tanks. Spot flow back tanks. Vac truck hauling water to fill frac tanks. Spot sand cans and begin transferring sand. Unload KCL. 17:00 17:30 0.50 SECURE WELL AF Shut down all equipment. Secure location for the night. Re ort Date: 5/18/2008 Job Cate o R8M MAINTENANCE 24 Hr Summary Spot blender. RU suction hoses to frac tanks. KCL fluid in frac tanks. Spot HHP pumps. RU suction hoses to pumps. RU 4" hard lines to well head. Install gas buster on flow back tank. RU 2" hard lines to choke manifold, sand separator, gas buster, and flow back tank. StertTime ;. FsdTlme Durthrs) , ; OpsCode-. ~. ,ncnv~tyCode ~; Ops .'' Status Trouble Code n .. - , Cpmrnent ' 08:00 09:00 1.00 SAFETY MTG AF Hold PJSM. Discuss muster area and alarms. Discuss job specific JSA's and associated hazards. Obtain Safe Work Permit. 09:00 17:00 8.00 RURD STIM AF Spot blender. RU suction hoses to frac tanks. KCL fluid in frac tanks. Spot HHP pumps. RU suction hoses to pumps. RU 4" hard lines to well head. Install gas buster on flow back tank. RU 2" hard lines to choke manifold, sand separator, gas buster, and flow back tank. 17:00 17:30 0.50 SECURE WELL AF Shut down all equipment. Secure location for the night. Tum in permit and leave loc. Re ort Date: 5/21/2008 Job Cate o R8M MAINTENANCE 24 Hr Summary Fraced well with 36,280# sand + 5,234# of flex sand. N2 lifted well with Ct down to 5000' and recovered 175 Bbls water. SD for night. op5 fie _ ~ , • ~~ )~ ~ u ~` StartTlme FsdTlme Durhrs 0 sCode A Status Code tlvl C d ' mme ~ ~ p . , o e . c Co nt t ty - ks.. _ 07:30 09:00 1.50 SAFETY MTG AF Held PJSM. Discussed BJ JSA and job assignments. 09:00 10:30 1.50 RURD STIM AF Start equipment and prepare to test lines. 10:30 11:00 0.50 TEST EQIP AF Test lines to 8000 si. 11:00 11:15 0.25 PUMP WTR AF Load hole with 138 Bbls KCI water. 11:15 12:15 1.00 REPAIR EQIP TA MSSM Repair chem add system and Blender. Reset parameters in Chem add system. 12:15 12:30 0.25 PUMP FRAC AF Pump 58 Bbls pad + 36,280# 20/40 sand + 5,234# flex sand in 6 stages from 2 ppg to 12 ppg. Displace with 155 bbis KCI. Max injection pressure 2310 psi. 12:30 12:45 0.25 PUMP FRAC AF Observe fall off pressure. ISIP = 1700 psi. 5 min SIP = 1575. 10 min SIP = _ 1395. 15 min SIP = 1338. Total load fluid = 693 bbls. 12:45 16:15 _ __ 3.50 RURD _ OTHR AF SI well and RD tree saver. ___ 16:15 18:00 1.75 RURD COIL ~ AF RU CTU. Pull test connector. Function test BOP. Open well to gas buster at _ 5PM. RU pump lines. 18.00 19:45 1.75 TEST BOPE AF Test Expro iron 200 / 2000 psi. Test BOP 250 / 4500 psi. Good test. www.peloton.com Report Printed: 7125/2008 Operations Summary Report Well Name: GRASSIM OSKOLKOFF Start Time End Time Dur (hrs) Ops Code Activity Code Ops Status Troabie Code Comment 19:45 20:30 0.75 RURD COIL AF MU jet nozzle and stab on well. Shell test to 1000 psi. Cooi down N2. Well has made 25 bbis water and is making a small amont of water to tank. 20:30 21:30 _ _ 1.00 RUNPUL _ COIL AF__ RIH pumping n2 at 750 scf/min. Making water. Stop at 3000'to unload well. 21:30 22:00 0.50 PUMP N2 AF _ _ Lift well at 500 scf/min. Total returns = 95 bbis. 22:00 22:30 _ 0.50 RUNPUL ___ COIL ___ AF _ Increase rate to 750 scf/min and RIH to 5000'. Well has made 127 bbis. 22:30 23:45 1.25 PUMP N2 AF __ _ reduce rate to 500 scf/min and continue lifting well at 5000'. 23:45 00:15 0.50 RUNPUL COIL AF Out of N2. POH. Well has made 175 bbls water of 693 total load. 00:15 01:00 0.75 RURD COIL AF _ Well is dead. Leave well open to tank and rig back CTU for night. 01:00 01:15 0.25 SECURE WELL AF Secure well. Turn in permit and leave location. Daily Operations Re ort Date: 5122/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary Lifted well with nitrogen via coiled tubing. -- - - - _ _ Ops Trouble `Start Time End TIme~Dur (hrs) O s~Code A.~+~i~ Ccde Status Code ~_ Comment -- --- - 09:45 10:30 0.75 SAFETY MTG AF - - Held PJSM with Expro Well Testers, BJ CT and Frac Crew, ASRC crane, and MOC personnel. 10:30 11:00 0.50 RURD COIL AF RD BJ pop-off valve from casing annulus. 11:00 12:30 1.50 RURD COIL AF MU CT injector head and shell test to 250/4500 psi. 12:30 05:00 16.50 JAR N2 AF RIH with 'ettin nozzl on 1-3/4" CT jetting nitrogen at 350-750 scfm to 10,250' MD no to .Recovered 206.3 bbis of fluid with total rec v _ s o o tots c load . 05:00 06:00 1.00 RUNPUL COIL AF POOH with CT. Re ort Date: 5/23/2008 Job Cate o R8M MAINTENANCE 24 Hr Summary Finished POOH with CT. LD injector head. RDMO .;.StarCTime End Time. Dur hrs 0 sCode Acilrt Code -:. Ops ;Status Tmifbie Code - ..'. Comment 06:00 06:45 0.75 RUNPUL COIL AF Remove injector head and rig back. SDFN. 06:45 06:00 23.25 FLOW TEST AF RDMO BJ Frac Equipment-Flow test well through Well Tester Equipment. W I i .625 MM cfd at 410 si FTP, 56 deg F, and about 12 BW PD. Re ort Date: 5/24/2008 Job Cate o R8M MAINTENANCE 24 Hr Summa Flow test ry well .. `~ SiartTime End Time . Dur(FUS) -T ~ OpaCode ActlvttyCode_~ ~Ops Statue Trouble Code ~ , , '. Comment 06:00 13:15 7.25 FLOW TEST AF __ Flow test well through Well Tester Equipment. Well making about 1.70 MMscfd at 450 psi FTP, 47 deg F, and about 12 BWPD. Total fluid recovery is 406 bbls (58.6% of total load volume of 693 bbis.). End test through Expro Test equipment and put through MOC flowline to sales at 13:15 hrs. Final rate was 1.776 MMscfd at 410 psi FTP. Will drop out of sand separator loop in a couple of days. 13:15 18:00 4.75 RURD PIPE AF RD Expro Well Test lines. Prep for hauling off location. Re ort Date: 6/74/2008 Job Cate o R8M MAINTENANCE 24 Hr Summary Produce well to sales. Opa Tmub e` Start Tlf ~ End Tlme Dur (hrs) Ops Code - Activity Code Status ;-: Code ' Comment 06:00 07:00 1.00 SAFETY MTG AF _ __ __ __ __ MIRU electric line unit. Obtain work permit and held PJSM. 07:00 08:00 1.00 RURD ELEC AF MU 1 11/16" Logging tool. PT lubricator to 2000 psig. Good test. Open well. 08:00 __ 12:00 4.00 LOG OTHR RIH logging during down pass. Tagged fill at 10, 500' Fluid le~,ot of ~45a FBHP= 917 psig. POOH 12:00 14:00 2.00 RURD ELEC OOH rig down wire line unit. Cleaned up around well. Expro left lease. Re ort Date: 6/20/2008 Job Cate o R&M MAINTENANCE 24 Hr Summary --- --- Pull upper straddle packer and top extension tube. Will return Sunday to pull lower extension tube abd lower packer. Start Time End Tlme Dur (hrs), Ops Code Activity Cade Ops Status Trouble Code Comment. 08:00 09:30 --- 1.50 SAFETY MTG AF Hold PJSM. DFiscuss JSA, Assign tasks, and issue permit. Move to location. 09:30 11:30 2.00 KURD SLIK AF Spot and rig up unit. PU Weatherford spear baited on 4-1/2" GS. 11:30 12:00 0.50 _ _ TEST EQIP AF Pressure test lubricator to 3000 psi. www.peloton.com Report Printed: 7/25/2008 Operations Summary Repo Well Name: GRASSIM OSKOLKOFF 6 Ops Ttoiible i Start Time End Tlme Dur (hrs Ops Code ActlNty Code StsWs Code Comtrtent 12:00 15:15 3.25 RUNPUL SLIK AF RIH and latch upper straddle packer at 9167' WLMD. (counter is off). Hit up for 1 hour with oil jars and shear off. POH 15:15 - 16:30 - _ 1.25 - RURD SLIK - - AF Cut 100' of wire and rehead. Stab on and PT quick test sub. - 18:00 1.50 RUNPUL SLIK - AF - ---- RIH. Latch back into upper packer. Jar free in about 30 min and POH 18:00 _ T9:30 _ - _ 1.50 - RURD - SLIK - AF _ . -- LD u er straddle acker gand 30' extension tube. LD lubricator. 19:30 20:00 0.50 SECURE _ WELL ___ _ _ AF ___ Secure well. Close permit and leave location. --- Daily Operations ------ -- Re ort Date: 6124/2008 Job Category: R8M MAINTENANCE 24 Hr Summa ry - --- ----------- Pull lower straddle extension tube and lower packer. + - me rne Dur (hrs O s Code ActJv(ty Code ,Status.... .Code.. ,, Com[gent _ ©$ oo 08.48 0.80 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, emergency response. Discuss Pollard JSA, and job specific hazards. Obtain SWP. 08:48 09:48 1.00 RURD SLIK AF PU 3-112" and 4-1/2" lubricator. Must have enoagh to swallow tool string and fish. MU tools string- rs, kj, roller boggie, 5' X 2.30" roller stem, 5' X 2-1/8" roller stem, kj, roller boogie, oj, kj, tubular roller spangs, roller boogie, 4-1/2" GS. . 09:48 10:00 0.20 TEST EOIP AF PTest lubricator to 3000 psi. Test good. 10:00 11:30 1.50 RUNPUL SLIK AF RIH (1) w/ 4-1/2" GS to pull lower straddle extension tube. Set down @ 9472' KB. Unable to latch extension tube. POOH to check tool. OOH. Tool sheared. Clean up and re-pin w! brass. 11:30 14:30 3.00 RUNPUL SLIK AF RIH (2) w/ 4-1/2" GS. Run slower thru liner tie-back. Set down @ 9472'. PU and latch fish. Jar 11 licks 28-29K . Pull free. POOH. OOH. Stand bac lower stra a to e. - 14:30 16:30 2.00 RUNPUL SLIK AF RIH (3) w/ 4-1/2" GS baited w/ spear to pull lower pkr. Run slower thru liner tie-back. Set down @ 9506' KB. PU and latch fish.; Pull up. Slack back ' off. PU an~'ar ~ Ticlcs. u ee. at minor elements to relax. POOH. ecover p cr. t~s out of the hole. 16:30 17:12 0.70 RURD SLIK AF RD slick line unit. LD tool string. LD lubricator. LD straddle extension tube. Install tree cap. PTest. Test good. Call operations to place well back on production. 17:12 17:27 0.25 SECURE WELL AF Secure wellhead and location. Tum in permit. Sign. out and leave loc. - i i i - www.peloton.com Report Printed: 7/25/2008 • • 50.133.20571-00.00 2o7-oss tv Dea: ADL 389737 (~'. DD.06.15534.CAP.CMP 229,025.05 (NAD27) 225,4940.94 (NAD27) 60 09' 48.512" N 151 29' 23.738" W 4:00 hrs 7/30/2007 7:30 hrs 9/0712007 gel RIB 10:00 hrs 912112007 KOP @ 198' MD/TVD Build 5.0 deg1100' from 200-1583' MD Hold 87 deg from 1583.7354' MD Drop 2.5 deg1100' to 10,120' MD Hold 0 deg from 10,120'to TD at 10,090' MD Azimuth: 290.931 deg. Grassim Osk Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. J: L it Chemical InJectlon Nipple @ 2,382' MD (Top) 5.930' OD/3.858' ID 8,430 psi burst / ,7500 psi collapse Liner Packer with 15' Tieback Extension @8830.24' MD (Top) Lock Liner Hanger @ 8862.31' MD (Top) :er Joint Top @9925.5' MD (19' bng) ;er Jdnt Top @ 10,929.5' MD (19.5' bng) Iing Cellar Top @ 11,983.91' (1.53' Long) t Collar Top @ 12,025.56' (1.55' Long) t Shce Top @ 12,066.95 (2.05' Long) 318" Capillary string ~ 10103' KB (06130108) i Caat Iron Bridge Plug @ 11,470' i 6 M MARAT110N Conductor 20" K-55 133 ppf PE L¢ Bottom MD 0' 98' TVD 0' 98' Surfau Cosine 9.518" L-80 40 ppf BTC jsp om MD 0' 2,999' TVD 0' 1,788' 12-11d" hole with 690 eke (305 bble)12 ppg Type 1 cement with 41 bbls cement to surface. IMarmsdlate Casino 7" L-80 26 ppf Mod Buttnaa L4E Bosom MD 0' 9,038' TVD 0' 4,433' 8.314" hole whh 289 sks (126 bble) 12.5 ppg Lead 8 145 sks (30 bbla) 15.8 ppg Tall, did not bump plug, 100% returns, floats held. Tk~backTubina 4-112" L-80 12.6 ppf Hydril 563 I4P Bottom MD o• e,642• TVD 0' 4,261' LIDti 4112" L$0 12.6 ppf Hydril 563 I48 Bottom MD 8,842' 12,069' TVD 1,261' 7,437' 7" hde with 20 bbl MCS43 spacer with red dye followed by 195 sks (100 bbla) 10.5 ppg cement, Plug failed, 100% Rotuma. 5.8 bbls cement returns. MD TVD Ft 8,457'- 9,482' 4,825'4,849' 25 fl 3.3/6" 6apf 60° phase (11121/07) 9,482'- 9,511' 4,849'4,877' 29 fl 3-3/8" 6apf 60° phase (11120107) 10,103'-10,127' 5,464'-5,488' 24 R 3.3/8" 6spf 60° phase (11/15/07) Frac'd May 20, 2008 Fortnatlon Topa: Formatlon Beluga Deoth IMD1 Deod1 ITVDI Tyonek Tt 7,133' 3,250' Tyonek T2 8,554' 4,025' Tyonek T3 9,918' 5,280' TD 12,081' 7,437' 12,081' MD 7,437' TVD BTD; 11,470' MD 8,831' TVD 1ar837-ur888'- 8,898,828' 81-fE 3-218' Sspf 4A~'10118/0~) Well Name 8 Number: Graasim Oakolkofl # 8 Lease: Nlnllchik Unit Count or Parish: Kenai Peninsula Borou h State/Prov: Alaska Count USA le KOP and De h: S° / 100 fl 196' b/Perfa: KOP TVD : 196' Date Com /steel: 1 111 512 0 0 7 Ground Level above MSL : 166' RKB above GL : 21' Pre ared B : Kevin Skiba Last Revision Date: 07125108 Last Revision Date: 6124!2008 MBS ~~ ~~ r `+..A.::'s~r"F r~ dam` 6...1 ~...k ~ ~ ~ ~ ~ ~ ~ ~c ~ a P ~~~ ! t c 1 _, q 9 ~'_"1 t ~ S ~` ~~ t ~~ CO1~T5ER RATIO COl` II 5Ip Dennis Donovan Production Engineer Marathon Oil Company PO Box 1949 Kenai AK 996 1 1-1 949 • SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Ninilchik Unit, Tyonek Gas Pool, Grassim Oskolkoff #6 Sundry Number: 308-216 Dear Mr. Donovan: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum $eld inspector at (907) 659-3607 (pager). As provided in AS 31,05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Sea.-nount, Jr. Chair DATED thisZ6 day of June, 2008 Encl. ~O~ ~ ~} ~o • M Marathon MARATHON Oil Company June 17, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Sundry Notice Field: Ninilchik Unit, Grassim Oskolkoff Pad Well: Grassim OskolkofF #6 (PTD 207-096) Dear Mr. Maunder: C; Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~~ ~~~~~ -~ 9 2008 -. :nu : f`a '., i.1 F'~.. ~'lllggp •~ t~ ,., ~~.9$~~~ ~: We propose to run a 3/8" capillary string in GO #6 after the removal of the Weatherford ER Straddle @ 9446'-9512'MD set in May 15th 2008 for fracture operations. With the availability of a capillary injection unit on the Peninsula starting the week of June 23~' 2008; we are able to mitigate water loading by running a capillary string and pumping foamers. Setting depth of the capillary string should be around 10,103' MD. The past capillary string installation into KTU 24-6H (PTD 199-073) has yielded an approximate incremental gain of 475 MCFD over the past 3 months. We would like to continue to install capillary strings in other wells like GO #6 and be able to realize longer and more stable production. Please find attached a 10-403, current wellbore diagram, and detailed operations program. If you have any questions or need further information please call me at (907) 398-1362. SlrrtAraly Dennis Donovan Production Engineer Enclosures: 10-403 Sundry Notice Current Well Schematic Detailed Operations Program cc: AOGCC Houston Well File Kenai Well File DMD KJ S ,,y~" STATE OF ALASKA E'y ~~/~ ALA OIL AND GAS CONSERVATION COMMI N = :, ~ APPLICATION FOR SUNDRY APPR~L~S~ ~u~8 ~0 20 AAC 25.280 4laclca f"lii & G~3.c, I/OfIS. ~DITIi'^~~~SI9TY ~„~~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown Perforate ~Ct`iG; 8~C Waiver ^ Other Q Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Install Capillary Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ String , 2. Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number: Development ^, Exploratory ^ 207-096 - 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20571-00-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: ^ ~ Grassim Oskolkoff #6 Spacing Exception Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. FieldlPool(s): ADL 389737 ~ 187' . Ninilchik Unit / Tyonek Pool 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,069' ~ 7,429' - 11,470' ~ 6,831' ' 11,470' ~ NA Casing Length Size MD TVD Burst Collapse Structural Conductor 77~ 20" 98' 98' 3,060 psi 1,500 psi Surface 2,977' 9-5/8" 2,999' 1,788' 5,750 psi 3,090 psi Intermediate 9,017' 7" 9,038' 4,433' 7,240 psi 5,410 psi Production Liner 3,239' 4-1/2" 12,081' 7,437' 8,430 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9,457'-10,127' (gross) 4,825' - 5,488' (gross) 4-1/2" L-80 8,842' open perf interval open pert interval Packers and SSSV Type: Packers and SSSV MD (ft): Baker ZXP Packer 8,836' MD 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: Commencing Operations: June 27th, 2008 Oil ^ Gas^ 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 Dennis Donovan Jr Title Production Engineer Signature Phone (907) 283-1333 Date June 17th, 2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness .Sundry Number: .,, ~ I Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: t7 ~F~ ,)~~ ,`~ ~ ~Q~~ Subsequent Form Required: ~ " APPROVED BY / ~f Approved by: ~ ~ ~ COMMISSIONER THE COMMISSION Date: f/ Y Foofh 1b~df03rRe~Tsed Q8/2006 v ~ i ~ I ~~ ~ ~ Submit in Duplicate 2008 Capillary String Installation Page 1 2008 Capillary String Installation Program CLU, SU, BC, KGF .and NGF WBS#s SD#3 - W0.08.18049.CAP.001 KBU 11-8Y, 33-6X, 41-7 - W0.08.18053.CAP.001 BC 13 - W0.08.18054.CAP.001 CLU 6 - W0.08.18056.CAP.001 SU 32-9 - W0.08.18117.CAP.001 GO 6 - W0.08.18196.CAP.001 Objective - Install a 3/8" Capillary String into these wells to alleviate liquid loading. We intend to treat the producing fluid level in each of these 8 wellbores with foamer. Install and Complete CICM (injection skids) to utilize on wellheads. We have seen an incremental increase on KTU 24-6H capillary string installation of approximately 475MCFD. Procedure Companies Evolved: UOSS, BJDC, BJCS, BigG U Installation Order ell Maximum Setting De th Maximum String len th Minimum String Needed at Surface trin Size and T e lan a Connection Est'd Producing Fluid Level a De th Gauge Ring ID run Recommended Setting Depth From PT+Ta 1 CLU 6 8042' 8200' 45' 2205 3/8" X 0.049" WT 4-1/16 5M RX39 7880' 8058' 2.300" 8020' 2 SU 32-9 6200' 6250' 45' 2205 3/8" X 0.049" WT 3-1/8" 5M RX35 TBD TBD TBD TBD 3 BC 13 8590' 8750' 45' 2205 3/8" X 0.049" WT 3-1/16" 10M 6X154 7900' 10055' 2.300" 8580' 4 GO 6 10120' 10300' 45' 2205 3/8" X 0.049" WT 4-1/16 5M RX39 TBD TBD TBD TBD 5 SD 3 9290' 9450' 45' 2205 3/8" X 0.049" WT 4-1/16 5M RX39 TBD TBD TBD TBD 6 KBU 41-7 6910' 7050' 45' 2205 3/8" X 0.049" WT 3-1/8" 5M RX35 TBD TBD TBD TBD 7 KBU 11-8Y 8145' 8300' 45' 2205 3/8" X 0.049" WT 3-1/16" 10M BX154 TBD TBD TBD TBD 8 KBU 33-6X 8200' 8350' 45' 2205 3/8" X 0.049" WT 3-1/16" 10M BX154 TBD TBD TBD TBD 2008 Capillary. String Installation Page 2 Installation Procedure: 1.) BJCS: (Hold PJSM and JSA) a) Complete placement of 3 new CICM skids on wells CLU 6, SD 3, and KBU 41-7, all other wells have units placed. They will complete Installation of items that are pertinent to operation of CICM. b) Move NS#3 CICM to GO#6 well 2.) UOSS: (Hold PJSM and JSA) a) Removal of all well houses to setup for BJ Dynacoil Unit b) Replacement of CICM roof on (3) new skids, after tanks are set inside containment. 3.) Big G: (Hold PJSM and JSA) a) Complete explosion proof electrical end fittings for CICM b) Complete tubing for hookup of Dynacoil - if needed. - Placement of an open conduit under the well house wall for easy routing of 3/8" id tubing for skid hookup. This will prevent multiple tubing disconnects when well work is needed, thus reducing exposure to trapped pressure. 4.) BJDC: 1. Hold PJSM and Complete JSA/JHA 2. Move in rig up BJ Dynacoil unit. 3. Replace tree-cap flange with specified internally threaded flange listed above in the matrix. 4. MU BHA and secure to 3/8" string. 5. MU WHA to internally threaded flange 6. MU Trailer Haskell Pump to WHA with 1"male NPT tie back assembly 7. Pressure test flange assembly against a closed valve to 1.5 times SITP with Trailer Haskell Pump. 8. "SHUT IN WELL AT WING VALVE" -This will prevent BHA from traveling down flowline. BHA is small and capable of flowing into flow-Tee 9. RIH with capillary below "Est'd Producing Fluid Level". All strings must be set into the producing fluid level to prove the most effective. 10. Set Rattiguns and Leave 1.5 times SITP or greater as requested by BJDC on hydraulic pack off. 11. "OPEN WELL TO PRODUCTION" 12. Leave remaining spool of tubing outside of well for soap injection skid hookup. 13. Cap the tubing with a Swagelok cap, Swagelok valve, and pressure gauge. 14. Lockout/Tagout Swab, Upper Master and Lower Master. (Install BJ Dynacoil signs on all valves stating "Do Not Operate BJ Dynacoil in wellhead". Proceed to Lockout valves with production lock and cable.) 15. Hookup injection line to CICM, and set specified rate for each well. 16. RDMO, Cleanup site, Sign-out ~~ i 50-133.20571-00-00 2o7-0ss N Des: ADL 389737 #: DD.06.15534.CAP.CMP 229,025.05 (NAD27) 225,4940.94 (NAD27) 60 09' 48.512" N 151 29' 23.738" W 4:00 hrs 7/3012007 7:30 hrs 910712007 KOP @ 196' MD/TVD Build 5.0 deg1100' from 200.1583' MO Hold 67 deg from 1583.7354' MD Drop 2.5 deg1100' to 10,120' MD Hold 0 deg from 10,120'to TD at 10,090' MD Azimuth: 280.931 deg. Grassim Oskolkoff #6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. J~ r Chemical InJecOon Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID 8,430 psi burst / ,7500 psi collapse Liner Packer with 15' Tieback Extension @ 8830.24' MD (Top: Lock Liner Hanger @ 8862.31' MD (Top) er Joint Top @ 9925.5' MD (19' long) er Joint Top @ 10,929.5' MD (19.5' long) ling Collar Top @ 11,983.91' (1.53' Long) t Collar Top @ 12,025.56' (1.55' Long) t Shoe Top @ 12,066.95 (2.05' Long) Weatherford ER Straddle @ 9,446' - 9,512' 2.25" min ID. L = 65.31' 15-MAY-0B i Cast Iron Bridge Plug @ 11,470' i Radial Bond Log - Formaton Tops: Formation Deoth IMDI Deoth (TVDI Beluga Tyonek T1 7,133' 3,250' Tyonek T2 8,554' 4,025' Tyonek T3 9,918' 5,280' TD 12,081' 7,437' a TD: 12,081' MD 7,437' TVD PBTD: 11,470' MD 6,831' TVD • M ,MIARATNON L Conductor 20" K-55 133 ppf PE Typ Bottom MD 0' 98' rvD 0' 98' Surface Caalno 9-518" L-80 40 ppf BTC ottom MD 0' 2,999' rvD o• 1,76e• 12.114" hole with 690 aka (305 bbla) 12 ppg Type 1 cement with 1lbbls cemem to surface. In termediate Casino 7" L-80 26 ppf Mod Buttress Tom ottom MD 0' 9,038' TVD 0' 4,433' 8-314" hole with 269 aka (126 bbls) 12.5 ppg Lead & 145 sks (30 bbls)15.8 ppg Tail, did not bump plug, 100 % retuma, floats held. Tie-backTubino 4112" L-60 12.6 ppf Hydrll 563 ToJ? ~ 4S4i MD 0' 8,842' rvD 0' 4,261' ne 4.112" L-80 12.6 ppf Hydrll 563 0SL MD 8,842' 12,069' TVD 4,261' 7,437' 7" hole with 20 bbl MCS-43 spacer with red dye followed by 195 sks (100 bbla) 10.5 ppg cement, Plug failed, 100 % Retuma. 5-8 bbls cement returns. MD TVD Ft 9-,482'--8,619' 4;849'-4r87~ 29-fE b-3J8' bspf 80"-Phase-f~1F20167} 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8" 6spf 60° phase (11/15/07) Fret 20-MAY-0B ta-,637668' Sb98'-6-;928' S1-f6 3-218"--ispt-60°~W4T} Well Name & Number: Grassim Oskolkoff # 6 Lease: Ninilchik Unit Count or Parish: Kenai Peninsula Borou h State/Prov: Alaska Count USA An le KOP and De the 5° / 100 ft 196' An le/Pens: KOP TVD : 196' Date Com leted: 1 111 512 0 0 7 Ground Level above MSL : 166' RKB above GL : 21' Pre ared B : Kevin Skiba Last Revision Date: 01/16108 last Revision Date: 511912008 MAM GO-6 10-404 Sundry submittal ' eline Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, June 05, 2008 3:26 PM To: 'Skiba, Kevin J.' Cc: kdwatsh@marathonoil.com Subject: RE: GO-6 (207-096) 10-404 Sundry submittal timeline Page 1 of 1 Kevin and Ken, Send in the 404 when you have completed the work. If for some reason Marathon doesn't go after the patch, then that would be the time to submit the 404. Thanks for "checking" on the paperwork filing. Tom Maunder, PE AOGCC From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com] Sent: Thursday, June 05, 2008 3:23 PM To: Maunder, Thomas E (DOA) Cc: kdwatsh@marathonoil.com Subject: GO-6 10-404 Sundry submittal timeline Tom, Marathon has completed the fracture stimulation work on GO-6 welt, except for removing the isolation patch that was placed across a nonproductive interval. We are working through a busy frac schedule which is prohibit us from removing the isolation patch at this time. It will be approximately 6 weeks before we will be able to get back on GO-6 and remove the patch. Do you want me to submit a 10-404 Sundry for the work completed to date, or wait and submit a 10-404 that covers the work in its entirety. Kevin Slaba Engineering Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 6/5/2008 GO #6 Venting: PTD #207-O~and 10-403 Sundry #308-165 ~ Page 1 of 2 Maunder, Thomas E (DOA) From: Walsh, Ken [kdwalsh@marathonoil.com] Sent: Monday, May 12, 2008 4:06 PM To: Maunder, Thomas E (DOA) Cc: Cissell, Wayne E.; Donovan Jr, Dennis M.; Ibele, Lyndon; Mullin, Mickey; Rang, Craig L.; Skiba, Kevin J.; Sulley, Michael Subject: RE: GO #6 Venting: ,PTD #207-096 and 10-403 Sundry #308-165 Tom, Thanks. Reporting will be covered as requested. ~~ Ken D. Walsh Senior Production Engineer Marathon Oil Company-Alaska Asset Team 907-283-1311 (office) 907-394-3060 (cell) From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, May 12, 2008 4:02 PM To: Walsh, Ken Cc: Cissell, Wayne E.; Donovan Jr, Dennis M.; Ibele, Lyndon; Mullin, Mickey; Rang, Craig L.; Skiba, Kevin J.; Sulley, Michael Subject: RE: GO #6 Venting: PTD #207-096 and 10-403 Sundry #308-165 Ken, et al, Venting is understood to likely be a necessary part of the operation. As has been the practice, please report the volume on the facility disposition form. Regards, Tom Maunder, PE AOGCC From: Walsh, Ken [mailto:kdwalsh@MarathonOil.Com] Sent: Monday, May 12, 2008 3:55 PM To: Maunder, Thomas E (DOA) Cc: Cissell, Wayne E.; Donovan Jr, Dennis M.; Ibele, Lyndon; Mullin, Mickey; Rang, Craig L.; Skiba, Kevin J.; Sulley, Michael Subject: GO #6 Venting: PTD #207-096 and 10-403 Sundry #308-165 Tom, As per our telephone conversation this afternoon, Marathon is requesting permission to vent gas during the flowback of the frac on the GO #6 well. Marathon has received AOGCC 5/12/2008 GO #6 Venting: PTD #207-096 and 10-403 Sundry #308-165 ~ Page 2 of 2 approval to conduct the fracture stimulation but forgot to request approval on the sundry to vent gas. It is our intention to minimize any gas venting with preference to put the well to sales as quickly as possible. However, it would be prudent to request permission for up to five days of total venting with a maximum daily volume of up to 4 MMscfd. Please confirm your receipt of this email and concurrence with the venting request. Ken D. Walsh Senior Production Engineer Marathon Oil Company-Alaska Asset Team 907-283-1311 (office) 907-394-3060 (cell) 5/12/2008 ~ ra.._ ~-,._ .,w .. _, ~. ~ ,~ ALASSA OIL A1~D GABS COI~TSERQA'1`IO1~T CODII~II5SIOIQ Ken Walsh Senior Production Engineer Marathon Oil. Company PO Box 1949 Kenai, AK 996 1 1-1 949 SARAH PAtIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Ninilchik Unit,l~onek Gas Pool, Grassim Oskolkoff #6 Sundry Number: 308- 165 Dear Mr. Walsh: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Corrunission 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 ff 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, Cathy . Foerster Commissioner DATED this ~'_ day of May, 2008 Encl. ~~-0~~6 M Marathon MARATHON Oil Company May 2, 2008 Tom Maunder AOGCC 333 West 7t" Ave Suite 100 Anchorage, AK 99501 Alaska Business Unit P.O. Box 1949 Kenai, AK 99611-1949 Telephone 907/283-1311 Fax 907/283-6175 ©~~~ r`+ MA`s ~ ~ ~Z00$ Reference: 10-403 Sundry Submission Field: Ninilchik Unit Gas Cons• Gpmm~s pnchofa9e Well: Grassim Oskolkoff #6 ~ ~ Q~1 & Permit: PTD #207-096 Dear Mr. Maunder: Attached and submitted for your approval is the Form 10-403 to fracture stimulate a Tyonek interval in the Grassim Oskolkoff #6 well. A procedure and well schematic are also included. If you would like any other information, please contact me at 394-3060 or kdwalsht~marathonoil.com. Sincerely, ~~ ~.~ (~~ ~~ ~~ ~ Ken D. Walsh Senior Production Engineer Enclosures: 10-403 Sundry Procedure Well Schematic cc: AOGCC (2) Houston Well File Kenai Well File KDW KJS 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ^ Waive OC~e Other ^ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate^- Time Extension ^ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: Marathon OII Company 4. Current Well Class: 5. Permit to Drill Number: ' pevelopment ^ Exploratory ^ 207-096 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20571-00-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: - i i S ~ ^ Grassim Oskolkoff #6 pac ng Except on Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): _ ADL 389737 ~ 187' - Ninilchik Unit / Tyonek Pool 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 12,069' - 7,429' ' 11,470' 6,831' 11,470' NA Casing Length Size MD TVD Burst Collapse Structural Conductor 77' 20" 98' 98' 3,060 psi 1,500 psi Surface 2,977 9-5/8" 2,999' 1,788' 5,750 psi 3,090 psi Intermediate 9,017' 7" 9,038' 4,433' 7,240 psi 5,410 psi Production Liner 3,239' 4-1 /2" 12,081' 7,437' 8,430 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9,457'-10,127' (gross) 4,825' - 5,488' (gross) 4-1/2" L-80 8,842' open perf interval open perf interval Packers and SSSV Type: Packers and SSSV MD (ft): Baker ZXP Packer 8,836' MD 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program^ BOP Sketch ^ Exploratory ^ Development ^~ Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: May 19, 2008 Oil ^ Gas^ 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 Ken D. Walsh Title Senior Production Engineer Signature • / _ ~ ~~ ~ Phone (907) 283-1311 Date May 2, 2008 (~~~ w COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~ ~ -~ I ~5 Plug Integrity ^ BOP Test '~ Mechanical lntegrity Test ^ Location Clearance ^ (` c T Other: ~ ~~ ~. ~ b~S(~ ~ L'~O r"'rO C- C \ ~o~ }~5~ ( ~ ~v ~ QS ` 1 Subsequent Form Required: ~O'1.~ \ APPROVED BY Approved by COMMISSIONER THE COMMISSION Date: ~ ~ ~D~ sJ~. E~EIVE® • STATE OF ALASKA ~ ~ ALASKA OIL AND GAS CONSERVATION COMMISSION ~~~~ MAY ~ ~ 2008 APPLICATION FOR SUNDRY APPROVAL~~~a (~~~ & Gas Cons. Com ~ n 20 AAC 25.280 Form 10-403 evised 06/2006 Submit in Duplicate • M MARATHON MARATHON OIL COMPANY ALASKA REGION Ninilchik Field Grassim Oskolkoff #6 WBS # TBD Tyonek Frac Procedure Objective: To fracture stimulate perforation interval 10,103-10,127' MD to test the viability of significantly improving flow rate and quantify folds of increase potential for other candidates in the Ninilchik Field. 1. HOLD PRE-FRAC PAD MEETING: between BJ Services, Expro Well Testers, ASRC, and MOC representatives at least one week prior to frac date. Tentatively set for Monday, May 12, 2008. 2. RUN GAUGE RING: MIRU Pollard Wireline with wireline unit and crane truck. Hold Safety and environmental awareness meeting. MU pump-in tee and wireline valve to Otis tree cap connection. PU tool string consisting of roller stem, spang jars, oil jars, and 3.75" OD gauge ring into lubricator. Pressure test lubricator to 3000 psi with 6% KCL water. Bleed off pressure and RIH w/3.75" gauge ring to tag and record PBTD, estimated at 11,470' MD (top of cast iron bridge plug). POOH and RDMO Pollard Wireline. Note: Weatherford 4-1/2" ER straddle packer gauge OD is 3.74". 3. SET LOWER PACKER: MIRU Expro Wireline and ASRC 40-45 ton crane to set a Weatherford straddle packer assembly (customer property) across the upper set of open Tyonek perforations in this wellbore. Hold PJSM. MU pump-in tee and wireline valve to Otis tree cap connection. PU the Lower Weatherford 4-1/2" ER Straddle Packer Assembly (3.50" OVL, 2.98" center of element to top of packer, 2.375" ID), setting tool, Baker #10 slow-set tool, and CCL on wireline. Pull into lubricator and MU to wireline valve. Pressure test to 3500 psi with 6% KCL water. Bleed off pressure, open well, and RIH with packer below the perf interval, 9457-9511' MD. Correlate depth to Expro CBL run 11-Oct-2007 and Weatherford Array Induction openhole log run 08-Sept-2007 (history shows 1-2' correction necessary). Attempt to identify perforated interval. Set top of packer 2' below the bottom perforated interval at 9513' MD on the openhole log. Note: Casing collars are at 9500' and 9523' MD CBL. PUH 10-20' and then RIH to tag packer and confirm set depth. POOH with setting tool and CCL. 4. SET UPPER PACKER AND SEAL ASSEMBLY: PU the Upper Weatherford Snap-Latch seal assembly (1.1' long, 3.74" OD, and 2.25" ID), 52' of 2-7/8" tubing (2.441" ID) with EUE 10rd thread, 4-1/2" ER Straddle Packer Assembly (3.50" OVL, 2.98" center of element to top of packer, 2.375" ID), setting tool, Baker #10 slow-set tool, and CCL on wireline. Pull into lubricator and MU to wireline valve. Pressure test to 3500 psi with 6% KCL water. Bleed off pressure, open well, and RIH with packer and seal assembly. Sting into Lower Packer with snap-latch and verify latch by pulling up to 600 lbs. Set Upper straddle packer. PUH 10-20' and then RIH to tag packer and confirm set depth. POOH with setting tool and CCL. RDMO Expro Wireline and stand back ASRC crane. 5. HAUL IN FRAC TANKS AND FLUID: Haul in two Rain-for-Rent 500 bbl frac tanks and set on liner. Have ASRC berm tanks. Fill tanks with fresh water that has been tested previously to be suitable for gel hydration. Install BJ Services 4" fitting and butterfly valve with 602 connections to the tank manifold. • • Page 2 of 5 6. MIRU EXPRO WELL TESTERS: Haul an ASRC Volvo L-120 front-end loader to location. MIRU MOC sand buster. NU Expro Testing 3-1/18", 5K companion flange with 3", 1502 connection to end of flowline spool flange downstream of SSV. Haul in and stand up MOC vent stack. Lay flow lines to sand buster, separator and MOC vent stack. Plumb in methanol injection line to flow back line and air lines to SSV. Ensure that SSV has a lock open plug and a needle valve attached. Load separator with ± 20 bbls glycol water. Haul in and RU MOC flowback tank, gas buster, and rental 5K choke manifold. 7. MIRU BJ FRAC TRUCKS AND EQUIPMENT: Pressure test frac trucks and lines to 9500 psig. Pressure test all flowback lines to choke skid to 4500 psi with KCL water. APC to lay liner and berm around for Expro Well Test separator, flow lines, and vent stack. APC to lay liner and berm around Rain-for-Rent, MOC choke skid, and flowback tank. BJ Services to mix fresh water in Rain-for-Rent tanks with KCL in Super Sacks to yield 6% KCL mixture. Steam-on-Wheels to heat the frac water to have water at 70-72 deg F the morning of the frac. 8. MIRU BJ COILTECH COILED TUBING EQUIPMENT: MIRU coiled tubing unit with 1-3/4" coiled tubing, fluid pump, and nitrogen pump. Prep coiled tubing end for post-frac cleanout with KCL water and nitrogen. Spot CTU equipment and ASRC crane on proper containment. Have unit ready and able to RU to the top of the Stinger Wellhead Isolation frac head flange. 9. INSTALL WELLHEAD ISOLATION TOOL: Install Stinger wellhead isolation tool onto and through the Christmas tree per the attached supplemental procedure, STINGER WELLHEAD ISOLATION TOOL INSTALLATION PROCEDURE. 10. FRAC TYONEK INTERVAL: Fill well with 6% KCL and fracture stimulate the interval from 10,103-10,127' MD per pump schedule below (will be revised as required). Stage No. Prop Conc #/ al Clean Vol al Fluid Type Slurry Rate b m Dirty Vol al Stage Time min Cum Time min Cum Slurry al Cum Clean al Stage 16/30 Ottawa Stage Flex Sand Cum Prop Ibs 1 0 2520 Ltn 1800 25 2520 2.4 2.4 2520 2520 0 0 0 2 1 2016 Ltn 1800 25 2107 2.0 4.4 4627 4536 2016 0 2016 3 2 2016 Ltn 1800 25 2198 2.1 6.5 6825 6552 3528 504 6048 4 4 2520 Ltn 1800 25 2976 2.8 9.3 9801 9072 8820 1260 16128 5 6 2520 Ltn 1800 25 3204 3.1 12.4 13005 11592 13230 1890 31248 6 8 2100 Ltn 1800 25 2860 2.7 15.1 15865 13692 14700 2100 48048 7 10 2100 Ltn 1800 25 2875 2.7 17.8 18740 15792 18375 2625 48048 8 0 6332 Ltn 1800 25 6332 6.0 23.8 25072 22124 0 0 69048 60669 8379 69048 11. FLOW BACK FRAC TO TESTERS: Remove the Stinger Wellhead Isolation Tool once the surface pressure is below 5000 psi. Flow back frac through sand buster and Flow Testers for cleanup and rate. Have BJ Services blend the unused frac fluid to yield a 6% KCL water and consolidate it into one 500 bbl frac tank for a possible coiled tubing cleanout. Turn well to Production and sales when fluid and sand rates are manageable. If the well dies, continue to the next Step to tag fill before RIH with CT to cleanout fill and jet the well in. Otherwise, continue to Step # 17. 12. TAG FILL WITH SLICKLINE: MIRU Pollard Wireline with wireline unit and crane truck. Hold Safety and environmental awareness meeting. MU pump-in tee and wireline valve to Stinger wellhead connection. PU tool string consisting of roller stem, spang jars, oil jars, and 3.75" OD gauge ring into lubricator. Pressure test lubricator to 3000 psi with 6% KCL water. Bleed off pressure and RIH w/3.50" gauge ring to tag and record PBTD. Top of cast iron bridge plug at 11,470' MD. POOH and RDMO Pollard Wireline. NOTE: If the fill is below the bottom perf at 10,127' MD, make arrangements to iet the well in with nitrogen only. If fill is above the bottom perf, make arrangements to clean out the fill with KCL water and then iet the well in with nitrogen. GO #6 Tyonek Frac Procedure KDW- 5/2/2008 6:49:52 AM • Page 3 of 5 13. NU CT TO WELL: Nipple up wellhead assembly (WHA). WHA to include 4-1/16",10M Flow Cross, 4- 1/16",10M BOP (dressed for 1-3/4" CT). 14. MAKE UP CT BHA AND INJECTOR HEAD: BHA to include 1-3/4" CT connector, 1-3/4" DFCV, 3' of 1- 3/4" straight bar, 1-3/4" Tornado Tool, 2" nozzle. MU BHA and pull test to BJ Coil Supervisor specs. RU Injector to WHA. Pressure test WHA, BOP and flowback iron (200 psi/4500 psi) with KCL water. Pressure test BJ iron (200/4500 psi) with KCL water. 15. CIRCULATE WELL CLEAN: If fill needs to be removed across the open perfs, then RIH with coiled tubing circulating 6% KCL water with friction reducer to the cast iron bridge plug at 11,470' MD taking special care to work through the straddle packer assembly. Drop 7/16" ball to change the direction of the Tornado Tool jets upward and wash backup hole per BJ CoilTech CIRCA modeling recommendations. If fill does not need to be removed, proceed to the next Step. 16. JET WELL IN WITH NITROGEN: Pumping only nitrogen at BJ CoilTech recommended coiled tubing running rates and nitrogen rates, jet the frac fluid and any produced fluid from the wellbore to the gas buster and tank noting volumes recovered. POOH and RDMO BJ CoilTech. 17. FLOW WELL TO SALES: Release rental equipment and return to vendors. Release Expro Well Testers when the well is cleaned up sufficiently. Flow well to sales observing recommended drawdown rates. CONTACTS Lyndon Ibele: 907-565-3042 (w) Ken Walsh: 907-283-1311 (w) 907-748-2819 (c) 907-394-3060 (c) Dave Martens 713-296-3302 (w) Scott Szalkowski: 713-296-3390 (w) 832-472-6249 (c) 713-301-9834 (c) Clyde Scott:713-296-2336 (w) Ninilchik Operators: 907-260-7660 or 907-567-3248 (Susan Dionne Pad) KGF Operators: 907-283-1305 GO #6 Tyonek Frac Procedure KDW- 5/2/2008 6:49:52 AM • • Page 4 of 5 STINGER WELLHEAD ISOLATION TOOL INSTALLATION PROCEDURE 1. Take Wellhead pressure reading and check Wellhead rating. Last SITP taken was 2625 psig. 2. Make sure you do not have gas flowing back through pipelines or back to flow back tank. 3. Check all Wellhead valves to ensure they are in the right position. Ensure master valves are closed. Make sure that Wellhead pressure is bled off in order to install Isolation Tool. Remember to work off of highest blind ram or valve. 4. Before bleeding pressure, check all flow lines, manifolds and tanks for proper set-up. 5. Relieve pressure from Wellhead and record proper measurements. 6. Prior to lifting the Tool, close manual valve and make sure the needle valve on the polish rod is in the open position. 7. Lift boom and attach to Tool -make sure safety latch is in place. 8. Lift Tool and hang beside crane, then attach hydraulic hoses to Tool. 9. Stroke Tool down and check all connections to ensure they are tight. Take main mandrel measurements and record on Call Sheet. 10. Stroke Tool up and check packing nut for proper adjustment. Check to ensure that 2"x1" equalizing valves are in the open position both on the flow tee and on the bottom of the Tool. All bleed-off needle valves are in the closed position and the main valve is open. 11. At this time ensure that all required connections are clean and o-rings are replaced. 12. After installing all necessary extensions and cup tools, be sure to re-measure before installing tool 13. Ensure that ring groove is clean and in good shape. Flanges on Isolation Tool should be clean and .new ring gasket installed. 14. Bolt down the Isolation Tool to the Wellhead, having slacked off the winch line. Ensure that all flanges are hammered down straight and tight. Have bleed-off needle valve pointing away from equipment -point towards pit, if possible. 15. Recheck all valves, wing valves, flow tees, equalizing lines, etc. to ensure that everything is in the proper position. 16. When mandatory radius (30') around Wellhead is clear of all personnel, open Wellhead slowly and count the turns on the valve(s) to ensure they are open completely. 17. When Wellhead (with Tool installed) has been equalized, check all union and flange connections for leaks. Stroking the Tool into an equalized Well, will ensure that the pack-off cups will not try to set prematurely before the mandrel is stroked all the way down. 18. Begin stroking Tool into Well -watch the hydraulic gauge closely for pressure increase. If an unusual increase in hydraulic pressure is encountered, stop and remove Tool. Inspect cups and cup tool for unusual wear, ice, etc. Note: If Tool will not stroke down, it is probably due to the hydraulic fittings not being properly connected (even though they may appear to be). GO #6 Tyonek Frac Procedure KDW- 5/2/2008 6:49:52 AM • Page 5 of 5 19. When Tool is stroked in completely the hydraulic pressure will rise on the gauge, indicating the tool is all the way down. Screw down the lock-down nut on Isolation Tool and hammer lockdown union until tight. 20. Close the hydraulic valve on the Isolation Tool. 21. In order to check for cup seal and valve seal, open flow back line to the tank or pit after careful inspection of the flow back line. Once pressure is bled off, close the bleed-off valve (on flow line) to the tank or pit and open '/2° needle valve bleed- off, to check for proper seal. If proper seal is made, close 2" x 1" equalizing valve on the flow tee, then close the 2" x 1" equalizing valve on the bottom of the Tool. Check for trapped pressure by opening %" needle valve between the valves. If proper seal is not made, stop and remove Tool. Inspect the cups for unusual wear, connections for possible o-ring leak, etc. 22. If a proper seal is made, bleed and remove hydraulic hoses from main valve, open manual valve on top of Tool and install hydraulic hoses on setting tool for removal. 23. Upon applying downward hydraulic pressure, hammer top union loose and spin off. Clear Wellhead area of all personnel. Stroke up and clear top union. 24. Remove %" equalizing hose and install quick connect plugs in both equalizing caps on the flow tee and the bottom. 25. After applying tension to winch line, the stay rod keepers and pins can be removed. Lift the setting tool from the Wellhead area and set aside. 26. The Frac line can be properly attached to Isolation Tool valve or Frac Head with. proper line jack or swing installed. Use proper hammer techniques and Fall Protection. 27. Prior to pumping, attend pre-job safety meeting. Discuss 30' safety area around Wellhead. Have service company appoint one individual to tell us to open or close main valve. Request radio communication with the service company for these operations. Also, inform all involved if our cups are not set, what procedure we will take to set the cups during pumping. Note: If there is no pressure on the Well, have the service company notify you when the hole loads or catches pressure. 28. Before pumping, hook up the hydraulic hoses to the actuator on the main valve. Do Not open until told to do so by designated service company representative. 29. Have the service company provide at least 500 psi above Wellhead pressure, on top of main valve, before opening. 30. Before pumping, open valve to monitor proper cup seal using oil company flow back equipment. If not applicable, use Stinger 2" x 1"equalizing valve with %" needle valve bleed-off. 31. When instructed, open main valve on Isolation Tool and ensure the valve is fully open. Check valve periodically during pumping. Watch for leaks on Wellhead, Tool and seal. Be aware of "rough" pumping. GO #6 Tyonek Frac Procedure KDW- 5/2/2008 6:49:52 AM 50-133-20571-00-00 a : zo7-oss Des: ADL 389737 #: DD.06.15534.CAP.CMP 229,025.05 (NAD27) 225,4940.94 (NAD27) 60 09' 48.512" N 151 29' 23.738" W 4:00 hrs 7/30/2007 7:30 hrs 9107/2007 KOP @ 186' MD/TVD Build 5.0 deg/100' from 200.1583' MD Hold 67 deg from 1583-7354' MD Drop 2.5 deg1100' to 10,120' MD Hoid 0 deg from 10,120' to TD at 10,090' MD Azimuth: 290.931 deg. Grassim Oskolkoff #6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. >>i~~i~L ,y ,,.,,,,a -...~ , ~~. . r,y„n~ ~, r Chemical In)ecflon Nipple @ 2,382' MD (Top) 5.930" OD/3.858" ID 8,430 psi burst / ,7500 psi collapse Liner Packer with 15' Tieback Extension @ 8830.24' MD (TOpI Lock Liner Hanger @ 8862.31' MD (Top) er Joint Top @9925.5' MD (19' long) er Joint Top @ 10,929.5' MD (19.5' long) ling Collar Top @ 11,983.91' (1.53' Long) ;Collar Top @ 12,025.56' (1.55' Long) Shoe Top @ 12,066.95 (2.05' Long) ~ c ~ C ~ c Caat Iron Bridge Plug @ 11,470' ~' ~ ~J a. Expro Radial Bond Log -10/11/2007 ~ ~ c c Tops: ]~(~'~ TD: 12,081' MD 7,437' TVD PBTD: 11,470' MD M MARATHON onduclor 20" K-55 133 ppf PE Bottom MD 0' 98' TVD 0' 98' Surface Casino 9.518" L$0 40 ppf BTC Bottom MD 0' 2,999' TVD 0' 1,788' 12.111" hole with 690 sks (305 bbls) 12 ppg Type 1 cement with 416b1s cement to surface. Intermediate Casina 7" L-80 26 ppf Mod Buttress Tom Bottom MD 0' 9,038' TVD 0' 4,433' 8-314" hole whh 289 sks (126 bbls) 12.5 ppg Lead & 145 sks (30 bbls) 15.8 ppg Tall, did not bump plug, 100% retums, floats held. Tle-backTubinc 4-112" L-80 12.6 ppf Hydrll 563 L2 8ottom MD 0' 8,842' TVD 0' 4,261' Liner 4-112" L-80 12.6 ppf Hydrll 563 Bottom MD 8,842' 12,069' TVD 4,261' 7,437' 7" hde with 20 bbl MCS43 spacer with red dye followed by 195 sks (100 bbls) 10.5 ppg cement, Plug failed, 100% Rtums. 5-8 bbls cement retums. Tvonek Perfs: MD TVD Ft 9,457'- 8,482' 4,825'x,849' 25 ft 3-318" 6spf 80° phase (11121/07) 8,482'- 9,511' 4,849'-4,877' 29 ft 3-3/8" 6spf 60° phase (11120107) 10,103'-10,127' 5,464'-5,488' 24 ft 3-318" 6spf 80° phase (11115107) 11,637'-11.568'- 6,898'-6,929' Et-ft 3-318"- 6sPf 60°-phase-(x9118/07} Well Name 8 Number: Grassim Oskolkoff # 6 Lease: Ninilchik Unit Count or Parish: Kenai Peninsula Borou h State/Prov: Alaska Count USA An le KOP and De the 5° / 100 ft @ 198' An le/Perfs: KOP TVD : 198' Date Com leted: 1111512007 Ground Level above MSL : 186' RKB above GL : 21' Prepared B : Kevin Skiba Last Revision Date: 01116108 M Marathon MARATHON Oil Company January 21, 2008 Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Mr. Tom Maunder JAN ~ ~' 20Q8 Alaska Oil & Gas Conservation Commission 333 W 7th Ave pl8ska Oil & Gas Cons. Comm-~~~~~ Anchorage, Alaska 99501 Anchorage Reference: 10-421 Open Flow Potential Test Report Field: Ninilchik Unit Well: Grassim Oskolkoff #6 Dear Mr. Maunder: Enclosed is the Open Flow Potential Test Report 10-421 for well GO-6. This well was spud on July 7, 2007 and completed into the Tyonek formation. The information on this report was obtained from a one point test. We do not have the ability to vary the well's flow or pressure because it is producing at line pressure which is at the well's unloading rate. Maintaining production from this well is a sensitive balance which would be upset if well conditions were modified. Since the well is operating at line pressure the rate can not be increased and production could be lost if the rate is reduced. If you have any questions or require additional information, please call me at (907) 283- 1371. Sincerely, `` /' Kevin J. Skiba Production Technician Enclosures: 10-421 Open Flow Report cc: Houston Well File Kenai Well File KJS DMD STATE OF ALASKA /_~~ E~EI~E® ALAS OIL AND GAS CONSERVATION COMM ION AN 2 3 2008 GAS WELL OPEN FLOW POTENTIAL TEST REPOR~ 1a. Test: ~ Initial Annual Special 1b. Type Test: ~ Stabilized 8 -4 9V1 ~YIIIM$ ^ Constant Time ^ Isochronal ^ Other_ AtICh0~8g$ 2. Operator Name: 5. Date Completed; 11. Permit to Drill Number: Marathon Oil Company October 19, 2007 207-096 3. Address: 6. Date TD Reached: 12. API Number: PO Box 1949, Kenai Alaska, 99611-1949 ` September 7, 2007 50- 133-20571-00-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 2,975' FSL, 2,988' FEL, Sec. 23, T1 N, R13W, S.M. 187' ' Grassim Oskolkoff #6 Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): 303' FSL, 810' FWL, Sec. 15, T1 N, R13W, S.M. 11,470' MDR 6,831' TVD Total Depth: 9. Total Depth (MD + TVD): Ninilchik Unit / Tyonek Pool 392' FSL, 544' FWL, Sec. 15, T1 N, R13W, S.M. 12,081' MD 7,437' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 229,025 y- 2,254,940 Zone- 4 ADL 389737 TPI: x- 222,297 y- 2,257,687 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 222,039 y- 2,257,774 Zone- 4 Single 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 4-1/2" 12.6 3.958 12,069' MD 9,457' - 9,482', 9,482' - 9,511' ' 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 10,103' - 10,127', 11,537' - 11,568' 4-1/2" 12.6 3.958 8,842' MD 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 8,836' MD (top) - - 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): ^ Tubing Q Casing 125 F° 891 psia @ Datum 6,831' TVDSS 14.73 psis 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO2: % N2: % HZS: Prover: Meter Run: Taps: 9,436' 4,825' KB 0.56 0.246 0.123 0 Facility 26. FLOW DATA TUBING DATA CASING DATA No. Prover Choke Line X Orifice pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Size (in.) Size (in.) psig Hw F° psig F° psig F° Hr. 1 • 3.826 X 1.250 769 1.87 43 - - - - 4.00 2. X 3. X 4. )( 5. X N Basic Coefficient 24 H ~ Pressure Flow Temp. Gravity Factor Super Comp. Rate of Flow o. ( - our) h Pm Factor Fg Factor Qi Mcfd Fb or Fp Ft Fpv 1. 125.2 8.96716232 783.73 1.00 1.336 1.1010 1,123 2. 3. 4. 5. ~~~ Temperature for Separator for Flowing No. Pr T Tr z Gas Fluid Gg G 1 • 1.16 460 1.34 0.825 0.56 NA 2. 3• Critical Pressure 673.1 4• Critical Temperature 343.2 5. Form 10-421 Revised 1/20 CONTINUED ON REVERSE SIDE ~ (/ Submit in Duplicate $ ~~~ ~~~ ~ 4 200 ~ 4'1 Pc 2030 Pcz Pf No. Pt Ptz Pct-Ptz Pw Pv~ Pcz-Pv~ Ps Psz Pf -Psz 1 • 784 614232.71 2. 3. 4. 5. 25. AOF (Mcfd) 1,267 n 0.750 Remarks: I hereby certify that the foregoinCg,is true an~d~o~rrect to the best of my knowledge. ` \J 1~~~/'~ Production Technician D to 1/21/2008 Signed ~~,~%U7/t'f/ Title a DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin facface were reduced to zero psis Fb Basic orifice factor Mcfd/ hl wPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= /1 Z dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 Page 1 of 1 Maunder, Thomas E DOA) From: Skiba, Kevin J. (kskiba@marathonoil.com] Sent: Monday, January 14, 2008 9:16 AM To: Maunder, Thomas E (DOA) Subject: RE: GO #6 (207-096) Tom, Thanks for bringing this to my attention. The correct TVD for the 7" casing is 4,433'. I will make the corrections on my end. Thanks again, Kevin Slaba Production Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, January 11, 2008 12:49 PM To: Skiba, Kevin J. Subject: GO #6 (207-096) Kevin, I am reviewing the 407 for this well. What a nightmare fishingll On the 407, the same "TD" is listed for the and and tvd of the 7". t calculated that the tvd of the 7" shoe is about 4434. Would you or one of the engineers piease confirm? Thanks in advance. Tom Maunder, PE AOGCC 1/14/2008 M Marathon MARATHON Oil Company Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 January 2, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-407 Well Completion Report Field: Ninilchik Unit Well: Grassim Oskolkoff #6 _. ~~ ~;~,~.. Dear Mr. Maunder: Enclosed please find the 10-407 Well Completion Report and Log for Ninilchik Unit well GO-6. The well was completed into the Tyonek Pool. Gas production was initiated on November 24, 2007 with a present production rate of 865mcf at 498psi. Other attachments included for your records are: current wellbore diagram, operations summary, and directional survey. Please call me at (907) 283-1371 if you have any questions or require additional information. Sincerely, ~~ ~ ~~- Kevin J. Skiba Production Technician Enclosures: 10-407 Well Completion Report cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS Directional Survey KDW ~ Z ,~~ . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ft ,., ~~~~ WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Well Status: Oil ^ Gas ^ Plugged ^ Abandoned ^ Suspended ^ zonnczs.~os 2onnczs.>>o GINJ^ WINJ ^ WDSPL^ WAG ^ Other^ No. of Completions: If;ts~:.- '• B :~"' ` Development ~;~`~`_s:`'=~ Exploratory^ Service ^ Stratigraphic Test ^ 2. Operator Name: Marathon Oil Company 5. Date Comp., Stet ~ Aband.: 2007 12. Permit to Drill Number: 207-096 - 3. Address: p0 Box 1949, Kenai Alaska, 99611-1949 6. Date Spudded: 7/3 /2007 13. API Number: 50-133-20571-00-00 4a. Location of Well (Governmental Section): Surface: 2,975' FSL, 2,988' FEL, Sec. 23, T1 N, R13W, S.M. 7. Date TD ReaQChed: 9,~V2007 14. Well Name and Number: Grassim Oskolkoff #6 Top of Productive Horizon: 303' FSL, 810' FWL, Sec. 15, T1 N, R13W, S.M. 8. KB (ft above MSL): 1$7' Ground (ft MSL): 166' 15. Field/Pool(s): Total Depth: 392' FSL, 544' FWL, Sec. 15, T1 N, R13W, S.M. 9. Plug Back Depth(MD+TVD): 11.,470' MD 6,831' ND NInIIChlk Unit / Tyonek POOI 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 229,025 y- 2,254,940 Zone- 4 10. Total Depth (M~sD~+TVD): ~a?4~9i~/~ f'lp~~ .Property Designation: ADL 389737 TPI: x- 222,297 y- 2,257,687 Zone- 4 Total Depth: x- 222,039 y- 2,257,774 Zone- 4 11. SSSV Depth (MD +TVD): $,$36' MD 4 256' TVD 17. Land Use Permit: 18. Directional Survey: Yes ~ No (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: NA (ft MSL) 20. Thickness of Permafrost (TVD): NA 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): Quad Combo, CBL 22. CASING, L INER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 0 0 0 20" 133 K-55 0' 98' 0' 98' Driven NA NA 9-5/8" 40 L-80 0' 2,999' 0' 1,788' 12-1/4" 690 sks Type 1 92.75 sks 7" 26 L-80 0' 9,038' 0' 8-3/4" 434 sks Class G NA 0 0 0 ~ ~ l~ 4-1/2" 12.6 L-80 8,842' 12,069' 4,261' 7,437' 7" 195 sks -13 sks 23. Open to production or injection? Yes Q No ^ If Yes, list each 24. TUBING RECORD interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) MD TVD 4-1/2" 8,842' 8,836' 9,457'- 9,482' 4,825'-4,849' 25 ft 3-3/8" 6spf 60° phase 9,482'- 9,511' 4,849'-4,877' 29 ft 3-3/8" 6spf 60° phase 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 10,103'-10,127' 5,464'-5,488` 24 ft 3-3/8" 6spf 60° phase DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 26. PRODUCTION TEST Date First Production: 10/24/2007 Method of Operation (Flowing, gas lift, etc.): Flowing Date of Test: 12/10/2007 Hours Tested: 24 Production for Test Period Oil-Bbl: 0 Gas-MCF: 982.6 Water-Bbl: 0 Choke Size: 80/64 Gas-Oil Ratio: 100% Gas Flow Tubing Press. 580 Casing Press: 0 Calculated 24-Hour Rate ~ Oil-Bbl: 0 Gas-MCF: 982.6 Water-Bbl: 0 Oil Gravity -API (core): NA 27. CORE DATA Conventional Core(s) Acquired? Yes ^ No ^~ Sidewall Cores Acquired? Yes ^ No^ If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. z i {.J~1tiY "i.latlP ~' ~`~.> JAN ~ ~~0~ ~~ -~ ~~ ~~ ~~'~`~ Form 10-407 Revised 2/2007 CONTINUED ON REVERSE ~A 8. GEOLOGIC MARKERS (List all formations and m encountered): 29. FORMATION TESTS NAME MD ND Well tested? ~ Yes No H yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, 'rf needed, and submit detailed test information per 20 AAC 25.071. T2 Coal A 8,824' MD 4,245' ND 10/20/2007 Perforate 11,537'-11,588' MD: No change in surface pressure after T3 Coal A 10,182' MD 5,523' ND Perforating. TD 12,089' MD 7,429' ND 11/16/2007 Perforate 10,102'-10,126' MD: Pressure increased 385# in 3 hours. Well flowing 0.986 MMCFD at 774# FTP. 11/21/2007 Perforate 9,480'-9,509' MD: Perforations resulted in increased pressure and gas rate. Well flowing 1.073 MMCFD at 1100# FTP. 30. List of Attachments: Directional Surve ,Well Schematic, O erations Summa 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Kevin Skiba (907) 283-1371 Printed Name: Ken D. Walsh Title: Senior Production Engineer !!,w,~ .. ~ Signature: l~ ~ Phone: (907) 283-1311 Date: Janua 2, 2008 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 and Ground Level elevations in feet above mean sea level. 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: Report true vertical thickness of permafrost in Box 20. Provide MD and ND for the top and base of permafrost in Box 28. 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: ff 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: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 • 50-133-20571-00-00 n :: 2o7-0ss lv Des: ADL 389737 #: DD.06.15534.CAP.CMP 229,025.05 (NAD27) 225,4940.94 (NAD27) 60 09' 48.512" N 151 29' 23.738" W 4:00 hrs 7/30/2007 7:30 hrs 9/07/2007 KOP @ 196' MD/TVD Build 5.0 deg/100' from 200.1583' MD Hold 67 deg from 1583-7354' MD Drop 2.5 deg/100' to 10,120' MD Hold 0 deg from 10,120' to TD at 10,090' MD Azimuth: 290.931 deg. Grassim Oskolkoff #6 Ninilchik Unit 2,975' FSL, 2,988' FEL Sec. 23, T1 N, R13W, S.M. >>i~~i~~ ~r Chemical Injection Nipple @ 2,395' MD (Top) 5.930" OD/3.858" ID 8430 psi bursU7500 psi collapse Liner Packer with 15' Tieback Extension @ 8835.63' MD (Topi Lock Liner Hanger @ 885T MD (Top) er Joint Top @ 9925.5' MD (19' long) Joint Top @ 10,929.5' MD (19.5' long) ~ c J C ~ ~ c c r L Cast Iron Bridge Plug @ 11,470' ~' ~ ~7 ft= Expro Radial Bond Log • 10/11/2007 .... ,_.. .. _. _ N ~ ~ c C Tops: • ~~ TD: 12,081' MD 7,437' TVD PBTD: 11,470' MD C 9'11• T/r~ M MARATHON onductor 20" K-55 133 ppf PE Top Bottom MD 0' 98' TVD 0' 98' Surface Cuino 9.5/6" L$0 40 ppf BTC Two Bottom MD 0' 2,999' TVD 0' 1,788' 12-114" hob with 690 ske (305 bbls)12 ppg Type 1 Bement whh 41661s cement to surface. IMermedlale Caslna 7" L$0 26 ppf Mod Buttress Bottom MD 0' 9,038' TVD 0' 4,433' 8-314" hole with 289 eke (126 bble) 12.5 ppg Lead & 145 aka (30 bbls) 15.8 ppg Tail, did not bump plug, 100% returns, floats held. Tie-WckTubino 4112" L$0 12.6 ppf Nydril 563 Tip Bottom MD 0' 8,842' TVD 0' d,261' ie 4-1/2" L$0 12.6 ppf Fiydril 563 jop Bottom MD 8,842' 12,069' TVD 4,261' 7,437' 7" hole with 20 bbl MCS-43 spacer with red dye followed by 195 aks (100 bbls) 10.5 ppg cement, Plug failed, 100% Returns. 5-8 bbls cement returns. Tvonek Perfa: MD TVD Ft 9,457'• 9,482' 4,825'-4,849' 25 ft 3.318" 6spf 60° phase (11121/07) 9,482'- 9,511' 4,849'-4,877' 29 ft 3-318" 6spf 60° phase (11120/07) 10,103'-10,127' 5,464'-5,488' 24 ft 3-3/8" 6spf 60° phase (11/15/07) ) 11,537'•11,568' 6,898'-6,929' 61 ft 3-3/8" 6spf 60° phase (10/19/07) Well Name & Number: Grassim Oskolkoff # 6 Lease: Ninilchik Unit Count or Parish: Kenai Peninsula Borou h StatelProv: Alaska Counl USA An le KOP and De the 5° 1100 ft 196' An le/Perfs: KOP TVD : 196' Date Com leted: 1111512007 Ground Level above MSL: 166' RKB above GL: 21' Pre ared B : Kevin Skiba Last Revision Date: 12/27107 ACTUAL WELLPATH REPORT (CSVversion) Software System: WellArchitectT""1.2 REFERENCE WELLPATH IDENTIFICATION Operator MARATHON Oil Company Area Cook Inlet, Alaska (Kenai Penninsula) Field Ninilchik Field Facility MGO Slot MGO #6 Well MGO #6 Wellbore MGO #6 Wellpath NaviTrak<124-2931'>ATK G3<3031-9006'>NaviTrak<9078-12069'> Sidetrack (none) REPORT SETUP INFORMATION Projection : TM Alaska State Plane, Zone 4 (5004), US feet North Reference TRUE Scale 0.999984 Wellbore Last Revised 9/9/2007 Software System WellArchitectT"' Report Generated 10/23/07 at 12:42:20 DataBase/Source file WA Anchorage/ev56.xm1 Local Local WELLPATH LOCATION North East [ft] [ft] Slot Location 2986.28 -2990.52 Facility Reference Pt Field Reference Pt WELLPATH DATUM Calculation method Minimum curvature Horizontal Reference Point Slot Vertical Reference Point Glacier #1 (RKB) MD Reference Point Glacier #1 (RKB) Field Vertical Reference Mean Sea Level Glacier #1 (RKB) to Facility Vertical Datum 187.00 feet Latitude [°] 60 09 48.512N 60 09 19.105N 60 09 19.105N Longitude [°] 151 29 23.738W 151 28 24.639W 151 28 24.639W Glacier #1 (RKB) to Mean Sea Level 187.00 feet Facility Vertical Datum to Mud Line (Facility) 0.00 feet Section Origin X 0.00 feet Section Origin Y 0.00 feet Section Azimuth 290.93° WELLPATH DATA Wellbore: MGO #6 Wellpath: NaviTrak<124-2931'>ATK G3<3031-9006'>NaviTrak<9078-12069'> MD Inclination Azimuth TVD Vert Sect North East DLS feet deg deg feet feet feet feet deg/100ft 0 0 0 0 0 0 0 0 124 0.11 254.53 124 0.1 -0.03 -0.11 0.09 183 0.55 284.32 183 0.42 0.02 -0.44 0.78 242 3.4 278.31 241.96 2.41 0.35 -2.45 4.84 302 8.12 279.82 301.64 8.31 1.33 -8.39 7.87 363 13.16 282.59 361.57 19.41 3.58 -19.42 8.3 423 17.58 285.39 419.41 35.2 7.47 -34.83 7.47 483 19.25 287.15 476.34 54.09 12.79 -53.02 2.93 543 19.72 288.01 532.9 74.07 18.84 -72.09 0.92 601 20.37 289.24 587.39 93.93 25.19 -90.93 1.34 662 23.4 290.27 643.98 116.66 32.89 -112.32 5.01 722 26.21 291.91 698.44 141.83 41.96 -135.8 4.82 782 29.22 292.91 751.55 169.72 52.61 -161.59 5.08 847 31.92 292.87 807.52 202.75 65.47 -192.04 4.15 910 34.56 292.01 860.2 237.27 78.64 -223.96 4.26 972 36.88 291.42 910.54 273.46 92.03 -257.58 3.78 1036 39.97 290.53 960.67 313.23 106.25 -294.72 4.9 1099 45.01 289.27 1007.11 355.76 120.71 -334.73 8.11 1162 46.94 288.91 1050.89 401.04 135.52 -377.53 3.09 1225 48.56 288.75 1093.25 447.64 150.57 -421.67 2.58 1288 51.96 289.31 1133.52 496.05 166.37 -467.46 5.44 1352 55.31 290.64 1171.46 547.57 183.99 -515.88 5.5 1415 59.26 292.41 1205.51 600.56 203.45 -565.17 6.7 1478 62.97 292.39 1235.93 655.69 224.46 -616.16 5.89 1541 62.98 291.78 1264.56 711.8 245.56 -668.17 0.86 1605 63.29 292.03 1293.48 768.88 266.86 -721.14 0.6 t =interpolated/extrapolated station Tgt# 1667 67.38 292.04 1319.35 825.21 288 -773.35 6.6 1730 68.31 291.59 1343.11 883.55 309.68 -827.52 1.62 1794 69.91 291.23 1365.93 943.34 331.5 -883.19 2.55 1856 71.15 291.82 1386.59 1001.79 352.95 -937.56 2.19 1920 71.07 291.87 1407.31 1062.33 375.48 -993.77 0.15 1983 70.92 291.65 1427.83 1121.89 397.57 -1049.09 0.41 2046 70.59 292.09 1448.59 1181.36 419.72 -1104.29 0.84 2110 70.49 292.06 1469.92 1241.69 442.4 -1160.21 0.16 2173 70.58 292.17 1490.91 1301.08 464.76 -1215.24 0.22 2235 69.81 292.37 1511.92 1359.4 486.87 -1269.22 1.28 2298 69.18 292.03 1533.98 1418.39 509.16 -1323.85 1.12 2362 69.09 292.09 1556.78 1478.18 531.62 -1379.28 0.17 2425 69.02 291.73 1579.3 1537.01 553.58 -1433.87 0.55 2489 68.78 291.78 1602.34 1596.71 575.71 -1489.32 0.38 2552 68.7 291.63 1625.18 1655.42 597.42 -1543.87 0.26 2616 68.66 292.09 1648.45 1715.03 619.62 -1599.21 0.67 2679 68.65 291.89 1671.38 1773.7 641.59 -1653.61 0.3 2742 68.69 291.77 1694.3 1832.38 663.42 -1708.09 0.19 2806 68.8 292.08 1717.5 1892.01 685.69 -1763.42 0.48 2869 68.75 292.16 1740.31 1950.73 707.8 -1817.83 0.14 2931 68.75 291.96 1762.78 2008.5 729.5 -1871.38 0.3 3031 67.21 291.84 1800.27 2101.19 764.08 -1957.39 1.54 3094 68.88 291.68 1823.82 2159.61 785.74 -2011.66 2.66 3157 69.16 292.65 1846.38 2218.42 807.93 -2066.14 1.5 3220 69.14 292.02 1868.81 2277.28 830.31 -2120.59 0.94 3283 69.27 29.1.61 1891.17 2336.17 852.19 -2175.27 0.64 3345 69.39 291.05 1913.06 2394.18 873.29 -2229.31 0.87 3408 69.43 290.24 1935.21 2453.15 894.09 -2284.49 1.21 3471 69.32 288.62 1957.41 2512.09 913.7 -2340.1 2.41 3534 69.39 289.77 1979.62 2571.02 933.08 -2395.77 1.71 3597 69.28 289.07 2001.85 2629.94 952.68 -2451.36 1.05 3661 69.38 289.32 2024.44 2689.79 972.37 -2507.91 0.4 3724 69.35 288.69 2046.65 2748.72 991.57 -2563.66 0.94 3787 69.34 288.27 2068.87 2807.61 1010.26 -2619.57 0.62 3850 69.37 288.5 2091.08 2866.51 1028.85 -2675.51 0.34 3913 69.35 288.83 2113.29 2925.42 1047.72 -2731.37 0.49 3976 69.38 287.85 2135.49 2984.32 1066.27 -2787.33 1.46 4039 69.4 288.5 2157.67 3043.22 1084.66 -2843.36 0.97 4103 69.36 290.08 2180.21 3103.09 1104.45 -2899.89 2.31 4166 69.37 290.09 2202.41 3162.04 1124.7 -2955.27 0.02 4230 69.39 291.11 2224.95 3221.94 1145.77 -3011.33 1.49 4291 69.4 290.28 2246.42 3279.04 1165.95 -3064.75 1.27 4355 69.39 290.48 2268.94 3338.94 1186.81 -3120.9 0.29 4418 69.39 290.38 2291.12 3397.9 1207.39 -3176.16 0.15 4482 69.37 290.64 2313.65 3457.8 1228.38 -3232.26 0.38 4545 69.41 290.89 2335.83 3516.77 1249.29 -3287.4 0.38 4608 69.35 289.97 2358.02 3575.73 1269.87 -3342.66 1.37 4672 69.42 291.45 2380.55 3635.63 1291.05 -3398.69 2.17 4735 69.38 291.82 2402.72 3694.6 1312.79 -3453.5 0.55 4799 69.35 291.91 2425.27 3754.48 1335.1 -3509.09 0.14 4862 69.37 291.88 2447.48 3813.43 1357.09 -3563.79 0.05 4925 69.35 291.06 2469.69 3872.39 1378.66 -3618.66 1.22 4988 69.39 292.29 2491.89 3931.34 1400.44 -3673.45 1.83 5051 69.38 292.31 2514.07 3990.29 1422.82 -3728 0.03 5114 69.34 291.68 2536.27 4049.23 1444.9 -3782.67 0.94 5177 69.36 291.23 2558.49 4108.18 1466.46 -3837.53 0.67 5240 69.38 292.04 2580.69 4167.14 1488.2 -3892.34 1.2 5304 69.42 291.52 2603.21 4227.04 1510.43 -3947.97 0.76 5367 69.42 291.16 2625.35 4286.02 1531.89 -4002.91 0.53 5429 69.38 290.96 2647.17 4344.05 1552.74 -4057.07 0.31 5493 69.38 290.46 2669.71 4403.95 1573.93 -4113.1 0.73 5556 69.43 290.49 2691.87 4462.92 1594.55 -4168.34 0.09 5619 69.38 290.74 2714.03 4521.9 1615.32 -4223.54 0.38 5682 69.34 290.03 2736.23 4580.85 1635.85 -4278.8 1.06 5745 69.34 290.2 2758.46 4639.79 1656.13 -4334.16 0.25 5809 69.41 290.71 2781.01 4699.69 1677.06 -4390.28 0.75 5872 69.37 289.93 2803.18 4758.65 1697.54 -4445.58 1.16 5935 69.36 290.37 2825.39 4817.6 1717.85 -4500.93 0.65 5998 69.4 289.77 2847.57 4876.56 1738.08 -4556.31 0.89 6061 69.39 289.37 2869.74 4935.51 1757.83 -4611..87 0.59 6124 69.34 289.56 2891.95 4994.45 1777.48 -4667.46 0.29 6187 69.43 290.36 2914.13 5053.41 1797.61 -4722.88 1.2 6250 69.28 289.92 2936.34 5112.36 1817.91 -4778.23 0.7 6313 69.18 289.92 2958.68 5171.26 1837.98 -4833.61 0.16 6375 69.18 289.92 2980.72 5229.2 1857.72 -4888.1 0 6438 69.25 290.4 3003.07 5288.09 1878.02 -4943.39 0.72 6501 69.19 290.57 3025.43 5346.99 1898.63 -4998.57 0.27 6564 69.22 290.29 3047.79 5405.89 1919.19 -5053.76 0.42 6627 69.22 289.36 3070.14 5464.78 1939.17 -5109.17 1.38 6690 69.22 290.69 3092.5 5523.67 1959.34 -5164.51 1.97 6753 69.23 291.38 3114.84 5582.57 1980.48 -5219.49 1.02 6816 69.23 292.01 3137.18 5641.47 2002.26 -5274.22 0.94 6880 69.18 292.64 3159.9 5701.28 2024.98 -5329.56 0.92 6942 69.18 292.38 3181.94 5759.21 2047.17 -5383.1 0.39 7006 69.22 292.19 3204.67 5819.03 2069.86 -5438.46 0.28 7069 69.11 292.83 3227.08 5877.88 2092.4 -5492.85 0.97 7132 69.23 293.56 3249.48 5936.72 2115.59 -5546.98 1.1 7195 69.29 293.71 3271.79 5995.57 2139.21 -5600.95 0.24 7257 69.2 292.45 3293.76 6053.51 2161.94 -5654.29 1.91 7321 69.15 292.63 3316.51 6113.3 2184.87 -5709.54 0.27 7384 68.3 291.79 3339.37 6171.99 2207.06 -5763.88 1.83 7446 66.83 291.84 3363.03 6229.29 2228.36 -5817.09 2.37 7510 65.13 291.45 3389.08 6287.74 2249.92 -5871.42 2.71 7573 63.68 290.31 3416.3 6344.56 2270.17 -5924.5 2.82 7637 62.03 289.48 3445.5 6401.5 2289.55 -5978.05 2.82 7701 60.39 290.48 3476.32 6457.57 2308.71 -6030.76 2.91 7764 58.77 289.84 3508.22 6511.89 2327.44 -6081.76 2.72 7827 57.2 289.56 3541.62 6565.3 2345.45 -6132.05 2.52 7890 55.57 289.83 3576.49 6617.75 2363.13 -6181.44 2.61 7954 53.87 290.38 3613.46 6669.99 2381.08 -6230.5 2.75 8017 52.3 289.91 3651.3 6720.35 2398.43 -6277.79 2.56 8080 50.98 289.85 3690.39 6769.74 2415.23 -6324.24 2.1 8143 49.68 289.96 3730.61 6818.23 2431.74 -6369.84 2.07 8206 48.14 290.72 3772.02 6865.7 2448.24 -6414.36 2.61 8269 46.17 290.59 3814.85 6911.89 2464.53 -6457.58 3.13 8333 44.68 291.31 3859.77 6957.48 2480.83 -6500.16 2.46 8396 42.82 290.96 3905.28 7001.04 2496.54 -6540.79 2.98 8459 41.07 291.89 3952.1.4 7043.15 2511.91 -6579.99 2.95 8523 39.33 291.81 4001.02 7084.45 2527.29 -6618.33 2.72 8585 37.86 291.5 4049.47 7123.12 2541.56 -6654.27 2.39 8648 36.36 291.57 4099.71 7161.13 2555.51 -6689.63 2.38 8712 34.69 291.69 4151.8 7198.31 2569.22 -6724.2 2.61 8775 32.69 291.86 4204.21 7233.25 2582.18 -6756.65 3.18 8838 31.15 291.26 4257.69 7266.56 2594.43 -6787.63 2.5 8901 29.59 291.29 4312.04 7298.41 2605.98 -6817.31 2.48 8964 28.05 291.19 4367.24 7328.78 2616.98 -6845.61 2.45 9006 41 ~ 26.69 290.75 4404.53 7348.09 2623.9 -6863.64 3.27 5 9078 25.5 292.73 4469.19 7379.75 2635.61 -6893.06 2.05 ~~ ~ 9141 22.4 290.65 4526.76 7405.31 2645.09 -6916.8 5.1 ~~~ 9204 21.81 294.83 4585.14 7429 2654.24 -6938.66 2.67 9267 20.64 295.5 4643.86 7451.74 2663.93 -6959.3 1.9 9330 18.34 290.16 4703.25 7472.72 2672.13 -6978.63 4.61 9393 15.77 285.8 4763.48 7491.17 2677.88 -6996.18 4.55 9456 15.51 291.9 4824.15 7508.12 2683.35 -7012.23 2.64 9519 13.98 294.54 4885.07 7524.13 2689.66 -7026.97 2.65 9582 11.67 295.26 4946.5 7538.08 2695.54 -7039.66 3.68 9645 9.85 294.45 5008.39 7549.82 2700.49 -7050.33 2.9 9709 8.32 290.08 5071.58 7559.91 2704.34 -7059.66 2.62 9771 6.72 280.55 5133.05 7567.97 2706.55 -7067.44 3.26 9834 5.1 281.87 5195.72 7574.36 2707.8 -7073.81 2.58 9897 3.52 286.85 5258.54 7579.05 2708.93 -7078.4 2.57 9960 0.9 336.46 5321.49 7581.33 2709.95 -7080.45 4.79 10086 0.93 44.35 5447.47 7581.61 2711.59 -7080.13 0.81 10212 0.78 51.67 5573.46 7580.77 2712.85 -7078.74 0.15 10338 0.76 104.28 5699.45 7579.5 2713.18 -7077.26 0.54 10464 1.05 100.58 5825.43 7577.54 2712.76 -7075.31 0.23 10590 1.18 115.74 5951.41 7575.11 2711.98 -7073.01 0.25 10716 1.5 114.39 6077.38 7572.17 2710.74 -7070..34 0.26 10842 1.34 115.2 6203.34 7569.05 2709.43 -7067.5 0.13 10968 2.22 125.76 6329.28 7565.22 2707.38 -7064.19 0.74 11094 0.7 151.71 6455.23 7562.28 2705.27 -7061.84 1.29 11221 0.79 183.73 6582.22 7561.44 2703.71 -7061.53 0.33 11347 0.9 151.35 6708.21 7560.43 2701.98 -7061.12 0.38 11473 1.28 161.07 6834.19 7558.77 2699.78 -7060.18 0.33 11600 1.77 166.03 6961.14 7556.74 2696.53 -7059.25 0.4 11728 2.52 155.15 7089.05 7553.59 2692.06 -7057.59. 0.66 11855 3.13 151.3 7215.9 7548.95 2686.49 -7054.75 0.5 11982 3.73 145.04 7342.67 7542.89 2680.06 -7050.72 0.56 12016 3.69 142.91 7376.6 7541.04 2678.28 -7049.43 0.42 12069 3.69 142.91 7429.49 7538.15 2675.56 -7047.37 0 HOLE AND CASING SECTIONS Ref Wellbore: MGO #6 Ref Wellpath: N aviTrak<124-2931'>ATK G3<3031-9006'>NaviTrak<9078-12069'> String/Diameter Start MD End MD Interval Start TVD End TVD Start N/S End N/S Start E/W End E/W feet feet feet feet feet 20in Conductor 0 98 98 0 98 0 0 -0.02 -0.07 9.625in Casing Surface 0 2999 2999 0 1788 0 0 753.08 -1929.96 Tin Casing Intermediate 0 9038 9038 0 4433.19 0 0 2629.04 -6876.92 TARGETS Name MD TVD North East Grid East Grid North Latitude Longitude Shape US US survey ft survey ft DegMinSec DegMinSec 1362002 2257579 60 10 15.255N 151 31 44.181 W circle 1362002 2257579 60 10 15.255N 151 31 44.181 W circle 1362002 2257579 60 10 15.255N 151 31 44.181 W circle feet feet feet feet MGO #6 Tyonek T2 Coal -Rvsd: 12-Jun-07 3837 2717.52 -7105.09 MGO #6 Tyonek T3 Coal -Rvsd: 12-Jun-07 5467 2717.52 -7105.09 MGO #6 TD -Rvsd: 12-Jun-07 7437 2717.51 -7105.09 WELLPATH COMPOSITION Log Name/Comment NaviTrak MWD<0-3010'> ATK G3 MWD <3031 - 9058'> NaviTrak<9078 - 9141'> NaviTrak <9204 - 12069'> Ref Wellbore: MGO #6 Ref Wellpath: NaviTrak<124-2931'>ATK G3<3031-9006'>NaviTrak<9078-12069'> Start MD End MD Pos Unc Model feet feet 0 2931 NaviTrak (Magcorr1) 2931 9006 AutoTrak G3 (SAG, MagCorr) 9006 9141 NaviTrak (SAG, Magcorr1) 9141 12069 NaviTrak (SAG, Magcorr1) i Marathon Oil Company Page ~ of 20 Operations Summary Report Legal Well Name: Common Well Name Event Name: Contractor Name: Rig Name: GRASSIM OSKOLKOFF 6 GRASSIM OSKOLKOFF 6 ORIGINAL DRILLING GLACIER DRILLING GLACIER DRILLING Spud Date: 7/30/2007 Start: 7/27/2007 End: Rig Release: Group: Rig Number: 1 Date From - To Hours Code Code Phase 7/28/2007 06:00 - 15:00 9.00 RURD_ RIG_ ~ MIRU 15:00 - 01:00 ~ 10.00 ~ RURD_ RIG_ ~ MIRU 01:00 - 06:00 ~ 5.00 ~ RURD_ RIG_ ~ MIRU 7/29/2007 06:00 - 12:00 6.00 RURD_ RIG_ MIRU 12:00 - 06:00 18.00 RURD RIG MIRU 17/30/2007 106:00 - 16:00 ~ 10.00 ~ RURD_ RIG_ ~ MIRU 16:00 - 06:00 I 14.001 NUND I BOPE I SURDRL 7/31/2007 06:00 - 07:30 1.50 NUND BOPE SURDRL 07:30 - 12:00 4.50 PULD_ DP_ SURDRL 12:00 - 14:30 2.50 NUND BOPE SURDRL 14:30 - 16:00 1.50 TEST_ EQIP SURDRL 16:00 - 18:00 2.00 SURDRL 18:00 - 18:30 0.50 TEST BOPE SURDRL 18:30 - 02:30 I 8.001 PULD I DP I SURDRL 02:30 - 03:30 1.00 PULD_ BHA_ SURDRL 03:30 - 04:00 0.50 WASH FILL SURDRL 04:00 - 05:30 1.50 DRILL_ ROT_ SURDRL 05:30 - 06:00 0.50 CIRC_ MUD_ SURDRL 8/1/2007 06:00 - 07:00 1.00 TRIP_ DP_ SURDRL 07:00 - 07:30 0.50 REPAIR RIG_ SURDRL 07:30 - 10:30 3.00 TRIP_ BHA_ SURDRL 10:30 - 11:30 1.00 DRILL_ SLID SURDRL 11:30 - 12:30 1.00 PULD BHA SURDRL 12:30 - 06:00 ~ 17.50 ~ DRILL_ ~ ROT_ ~ SURDRL ~ 8/2/2007 ~ 06:00 - 09:30 ~ 3.50 ~ DRILL_ ~ SLID ~ SURDRL 09:30 - 10:00 ~ 0.50 ~ CIRC_ ~ MUD_ ~ SURDRL Description of Operations Spot sub over well. Set generator,boiler houses. Set water tank. set in mud boat move carrier on mud boat and level. Set pumps and pits. Begin running service lines. Set camp units and run power and water lines. Set break room. Start Generator for camp. All permit loads on location at 1500hrs. Hold PJSM review procedures for working with crane,Set fuel tank,lnstall turnbuckles,Spot mechanics shop,Monkey board,carrier landing,and stairs,grey iron dog house,wind walls,flowline,pull wires,and power up generator Pull dog house wires,Put up rig floor Iights,Prep,and scope up derrick,Hook up and tighten derrick guy wires,Set cuttings tank,and hanson tank.Rig up mud pits. Rig up GD-1. PJSM;Set trip tank, HP mud lines Rig up mud lines in pits. Set # 3 mud pump and R/U. Continue installing service lines to sub and rig floor. Set catwalk and beaver slide. Set stairs to conex. C/O pump liners to 5" PJSM;WeId base plate on 20" conductor. Dress out 20" conductor and set starting head.lnstall torque tube and top drive.Test starting head seals to 300 psi for 10 min. PJSM;Change #3 pump liners to 5",Rig up service lines across pit roof to choke house and gas buster.Weld in trip tank signal to show full tank.Start changing out washed out hyd. line on #2 Jennison pump. Continue working on torgue tube and top drive. Set top drive on rig floor, install service lines and rotary hose. Hang pipe spinners and tongs rig up floor.and stand pipe manfold. Begin to mix spud mud (500bb1s ) Nipple up diverter system. Remove riser and move flow line outlet 6" up. Remove riser from diverter stack to move outlet nipple above flow line PJSM: P/U drift and stand back 5" drilfpipe while repairing riser. Install riser and nipple up same Function test mud pumps, plc controls. conduct rig inspection Continue P/U drift and stand back 5" drillpipe Peform function test of diverter svstem. Test aas alarms LEL. H2S flow and pvt system. Witness waved by Chuck Sheave AOGCC Continue P/U drift and stand back 97 stds. 5" drillpipe and 10 stds. 5" HWDP Pick up ,measure and make u Clean out assy. Clean out conductor f/83' to 98~ Drill from 98' to165' Circulate hole clean POOH for Directional BHA POH f 165' for directional bha. Repair top drive service loop. PJSM; Make up 12 1/4 directional bha # 2 RIH Directionaly drill f 165'- 196' ART=.6 AST=O PJSM; P/U 8" monel, shock sub and jars. Change in bha as per directional driller Drill rotate slide f-196'- 1343' Pump hi visc. sweep at 509' 200% more cuttings and 1015' 300% more cuttings Up Wt.=62K Dn. Wt.=55K Rt. Wt.= 60K Tq.=3-5K ART= 2.5 hrs AST 7.9 hrs No gain loss Directionaly drill f- 1343'- 1533' Up Wt. 62kDn. Wt.55k Rt Wt. 60kTq 3-5k Art=.4hrs Ast=1.8hrs Rop rotate 67.5fph Rop slide 92.2fph No gain/loss Circulate pump low vis sweep followed by hi vis sweep. Pump 310spm Printed: 12/21/2007 12:56:26 PM ~ M Marathon Oil Company Page 2 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 8/2/2007 09:30 - 10:00 0.50 CIRC_ MUD_ SURDRL 650gpm 1450psi. Sweeps returned 300% increase in cuttings. 10:00 - 11:30 1.50 TRIP_ WIPR SURDRL POH wiper trip f-1533'- 300' Hole slick no overpulls. correct hole fill. no gain/loss. 11:30 - 12:15 0.75 SERVIC RIG_ SURDRL Service rig. Top drive, blocks,crown and carrier. Lube Drive lines. Inspect Jennison hyd pumps. 12:15 - 13:00 0.75 TRIP_ WIPR SURDRL TIH f-300'-1533' Hole slick no tight spots. Precautionary Wash f-1471'-1533' tag 3' of fill. 13:00 - 15:30 2.50 DRILL_ SLID SURDRL Directionaly drill f-1533' - 1662' ART= 0.4 AST= 1.1 15:30 - 16:00 0.50 REPAIR RIG_ SURDRL Replace swivel packing cartridge 16:00 - 00:00 8.00 DRILL_ SLID SURDRL Directionaly drill f/ 1662'- 2100' Pump hi-vis sweep at 2030' 200% returns. Up wt 65k dwn wt 45k Rt wt 55k Trq 4-6k ART= 3.8 AST= 1.3 00:00 - 06:00 6.00 DRILL_ ROT_ SURDRL Directionally drill f/ 2100' to 2410' Up wt 62k dwn wt 45k Rt wt 55k Trq 4-6k WOB 10-20k RPM 70 ART= 4.3 AST= 0.2 8/3/2007 06:00 - 12:00 6.00 DRILL_ ROT_ SURDRL Continue directionally drilling ahead f/ 2410'. Pumped hi-vis sweep at 2520'. very little increase in cuttings. Up. Wt. 71k Dn. Wt. 47k Rt.Wt. 56k Tq 6-7k Pump at 650gpm 336stks 1750psi. Art 4hrs Ast. 0. No gain loss 12:00 - 16:45 4.75 DRILL_ ROT_ SURDRL Drill ahead f 2735'- 3010' TD surface section. Up. Wt 74k Dn.Wt 46k Rt. Wt. 59k Tq 3-5k Pump at 650gpm 336stks 1750psi Art 3.7 Ast 0 No gain/loss. 16:45 - 17:45 1.00 CIRC_ MUD_ SURDRL Pump low and hi vis sweeps. Increase rotary rpm to 120, Saw increase in cuttings over shakers due to higher rotary speeds. Sweeps returned with slight increase in cuttings. 17:45 - 22:00 4.25 TRIP_ WIPR SURDRL UD 1 jt. Wiper trip. Pulled good to 2550'. Backreamed f/ 2550' to 1550' mostly in areas where slide drilling was done. 22:00 - 22:20 0.33 CIRC_ MUD_ SURDRL CBU at 640 gpm and 110 rpm's. Large amount of cuttings to surface. 22:20 - 22:50 0.50 TRIP_ WIPR SURDRL Continue wiper trip f/ 1550' to 1200'. No overpulls. 22:50 - 00:30 1.67 TRIP_ WIPR SURDRL TIH. Wash last std down. No fill. 00:30 - 01:10 0.67 CIRC_ MUD_ SURDRL CBU. Pumped 30 bbl low vis followed by 50 bbl hi-vis pill at 640gpm with 110 rpm's. Slight increase in cuttings. Hole appears clean. 01:10 - 04:30 3.33 TRIP_ DP_ SURDRL PJSM. TOH to BHA. 04:30 - 06:00 1.50 TRIP_ BHA_ SURDRL PJSM. LD BHA 8/4/2007 06:00 - 06:30 0.50 CLEAN_ RIG_ SURCSG Clean clear rig floor 06:30 - 08:30 2.00 RURD_ CSG_ SURCSG RU to run casing C/O bails and elevators. R/U Weatherford casing tools. 08:30 - 08:50 0.33 SAFETY MTG_ SURCSG Hold PJSM review procedures for running casing 08:50 - 13:45 4.92 RUN_ CSG_ SURCSG Make up shoe track ck floats, Run 75jts 40#9 5/8 L-80 BTC casing. 13:45 - 14:45 1.00 CIRC_ MUD_ SURCSG R/U BJ cement head and lines, Circulate and condition mud at 3000' 14:45 - 15:00 0.25 SAFETY DRIL SURCSG PJSM review Plan Forward. 15:00 - 18:10 3.17 PUMP_ CMT_ SURCSG Pump 5 bbls H2O. Test lines to 3000psi. Drop btm plug. Pump 305 bbls (690 sks) of 12.Oppg Type 1 cement w/ 22% LW-6, 20% MPA-1, 2% CaCL2, 1% SMS, 0.3% CD-32, 1gps FP-6L .Drop top plug and pump 5 bbls water. Switch to rig pumps and displace cement with 220 bbls 9.8ppg mud. Plug bumped on time. Total returns during cementing and displacment. Circulated 41 bbls cement to surface. Casing became differentually stuck shortly after landing. Unable to reciprocate d_uring_ cement'ob. CIP @ 1810hrs. F/C at 2955 Shoe at 2998' 18:10 - 20:00 1.83 RURD_ OTHR SURCSG Clean rig floor. Cleanout cellar. Wash-up all rig cementing and flow lines. Pumpout and clean mud pits. 20:00 - 00:00 4.00 NUND BOPE SURCSG .. Nipple down 16" diverter line. Flow lines. Continue cleaning pits. Printed: 12/21/2007 12:56:26 PM • ~ Marathon Oil Company Page 3 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Phase ~ Description of Operations Hours Code , Code 8/4/2007 20:00 - 00:00 4.00 NUND BOPE SURCSG Called AOGCC and gave 24 hrs notice for BOPE testing.. 00:00 - 00:15 0.25 SAFETY DRIL SURCSG PJSM reviewing plan forward. 00:15 - 04:00 3.75 NUND BOPE SURCSG Continue ND diverter. Make intial rough cut on 9-5/8" csg. LD cut jt and pitcher nipple. Set out 20" diverter. 04:00 - 05:00 1.00 NUND WLHD SURCSG Remove and set out 20" starting head. 05:00 - 06:00 1.00 NUND WLHD SURCSG Make final cut on 20" conductor and 9-5/8" casing. 8/5/2007 06:00 - 07:30 1.50 NUND WLHD SURCSG Continue with making final cut on 20" conductor and 9-5/8" casing. Install Vetco Gray multi bowl system, would not go down all the way. Remove and redress stub, still would not go down. 07:30 - 16:30 9.00 NUND BOPE SURCSG PJSM; Nipple up DSA, spacer spool, and BOP stack. multi bowl went down and seated.Test void to 2400 psi hold 30 min. OK, hammer up flanges, nipple up choke line, clean cement out of flowline. Weld nipple in flowline for Autotrac. Fill pits with heated water and mix mud. 16:30 - 17:30 1.00 RURD_ RIG_ SURCSG Change out links and MU elevators. 17:30 - 22:30 5.00 TEST_ BOPE SURCSG PU and set test plug. Open lower annulus valve. Fill stack w/ water. Start testin BOPE 250 si low and 2500 si hi h for 5 min each. First test found leak on one of choke line's Greylok clamps. Replace seal ring continue testing. Lower pipe rams failed. 22:30 - 00:30 2.00 TEST_ BOPE SURCSG Open lower pipe ram doors. Inspect carrier seals. No apparent dings. Flip over carriers button up doors. Retest failed. 00:30 - 01:00 0.50 TEST_ BOPE SURCSG Continue with testing blind rams and accumulator drawdown test. 01:00 - 05:00 4.00 TEST_ BOPE SURCSG Open lower rams. Remove carriers and replace with another set with new seals. Retest. Will not hold over 2000psi. Confirm there's no surface leaks. Check that manifold pressure is 1500psi. Open doors remove carriers and inspect seals. Nothing to indicate a problem. Flip carriers and retest with same results. Increased manifold pressure to 2000psi still not holding. Clearly leaking at the rams, no surface leaks. Pull and inspect test jt, not egged. Called WF discussed problem. Similiar problem on 43-9X. Possible problem with elastomer style. WF calling for different manufacture 05:00 - 06:00 1.00 RURD_ OTHR SURCSG RU Auto-Trac bypass valve. Prep to slip/cut drilling line. 8/6/2007 06:00 - 07:30 1.50 SLPCUT DLIN SURCSG PJSM;SIip and cuff drilling Iine.Cut 146' and slip113'.Adjust brakes. 07:30 - 09:00 1.50 TEST_ BOPE SURCSG PJSM;Change 5" pipe rams with new rubber.Test 250 psi low f/ 10 min. good 2500 psi hi f/ 10 min. good.Rig down testing equip. Install wear bushin . 09:00 - '1'0:00 1.00 TEST_ CSG_ SURCSG PJSM; Test casing to 2000 psi .Not holding, starts leaking off at 800 psi shut down test pump and bleeds off to 550 psi in 5 minutes.Check for leaks in surface equipment did not find any. 10:00 - 14:00 4.00 PULD_ DP_ SURCSG PJS; Measure, drift and pick up 66 joints 5" drill pipe stand back in derrick. 14:00 - 16:30 2.50 TRIP_ DP_ SURCSG POOH with 5" drill pipe. 16:30 - 18:40 2.17 PULD. BHA_ SURCSG PJSM; Measure and pick up Haliburton RTTS tool to test casing and shoe.RlH 18:40 - 19:40 1.00 TEST_ CSG_ SURCSG With RTTS set @ 2920' test casing to 2000psi f/ 30 min. Good test lost 40 psi. Line up pump down DP to 800psi. Neld for 5 min bleed down to 770psi. Pull and release RTTS. 19:40 - 22:30 2.83 TRIP_ DP_ SURCSG TOH. UD RTTS. 22:30 - 02:00 3.50 PULD_ BHA_ SURCSG PJSM. PU Auto-Trak tools. Test tools -good. PU remaining BHA. 02:00 - 04:00 2.00 TRIP_ DP_ SURCSG TIH and tag float collar at 2954 04:00 - 06:00 2.00 DRILL_ CMT_ SURCSG Drill float collar and shoe track. 400gpm 950psi with 250psi motorwork. 10-12k wob 45 rpm's Up wt 55k, dwn wt 45k 8/7/2007 06:00 - 07:00 1.00 DRILL_ CMT_ SURCSG Continue drilling shoe track to -3010' 07:00 - 07:30 0.50 DRILL ROT SURCSG Directional Drill with AutotraK f/ 3010' to 3030' Printed: 12/21/2007 12:56:26 PM ~ • Marathon Oil Company Page 4 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 8/7/2007 07:30 - 08:00 0.50 CIRC_ MUD_ SURCSG Circ. bottoms up, Displace hole with 9.Oppg Flo Pro mud. 08:00 - 08:30 0.50 TEST_ LOT_ SURCSG Perform FIT test EMW=13.9# 08:30 - 18:30 10.00 DRILL_ ROT_ IN1 DRL Directional Drill with AutoTrak f/ 3030' - 3523' 500gpm 1100psi wob= 10-12K 50 rpm's ART= 4.6hrs Up wt= 86k, Dwn wt= 35k, rot wt= 56k 18:30 - 19:00 0.50 CIRC_ CFLD IN1 DRL CBU f/ wiper trip. (Planned wiper trip. Also topdrive's hydraulic motor seals are leaking. Good time to check) 19:00 - 20:00 1.00 TRIP_ WIPR IN1 DRL Wiper trip into surface csg. Normal overpulls 20-25k. No problem through shoe. 20;00 - 20:20 0.33 SAFETY DRIL IN1 DRL Decided to replace TD hyd drive motor. Make JSA. Review LOTO precedures and PPE requirements. 20:20 - 00:00 3.67 REPAIR RIG_ IN1DRL Confirm LOTO. Remove hyd motor. MU hyd lines to new motor. Prep to install. 00:00 - 00:15 0.25 SAFETY DRIL IN1 DRL PJSM with new crews. Review LOTO, pinch points, overhead loads, fall protection. 00:15 - 02:15 2.00 REPAIR RIG_ IN1 DRL Install new hyd motor. Check operation. Closeout LOTO. 02:15 - 03:05 0.83 TRIP_ WIPR IN1DRL TIH wash last std to bottom. 03:05 - 06:00 2.92 DRILL_ ROT_ IN1 DRL Directionally drill with Auto Trak f/ 3523' to 3650'. 500gpm 1150psi wob= 10-12K 50rpm's. ART= 1.80hrs 8/8/2007 06:00 - 18:00 12.00 DRILL_ ROT_ IN1 DRL Continue directionally drill ahead with Autotrak f/ 3650' to 4430'. 50-55 rpm's, 500 gpm, 1250 psi, 12k wob, 5-7k trq, upwt= 95k, dwn wt= 44k, rt wt= 50k ART= 9.2hrs 18:00 - 00:00 6.00 DRILL_ ROT_ IN1 DRL Directionally drill f/ 4430' to 4850'. 50-55 rpm's, 500 gpm, 1350 psi, 10-12k wob, 5-7k trq, upwt= 99k, dwn wt= 46k rtwt= 55k ART= 4.8hrs 00:00 - 06:00 6.00 DRILL_ ROT_ IN1DRL Directionally drill f/ 4850'. Added another 1/2% Lubetex total now 1%. Drilled to 5300'. 50-55 prm's, 500 gpm, 1400psi, 10-12k wob, wt wt= 100k dwn wt 50k, rtwt 65k ART= 4.5hrs 8/9/2007 06:00 - 06:30 0.50 CIRC_ MUD_ IN1 DRL Circ. bottoms up at 5292' for wiper trip. 06:30 - 11:00 4.50 TRIP_ WIPR IN1 DRL POOH for wiper trip f/ 5292' to shoe at 2998' Up Wt.=160K Dn. Wt.=50K Rt. Wt,=65K Max. Wt. pulled 45K over string wt. coming out of hole. Hole dragged from 15-45K Had to work pipe, most of the way out. No back reaming or circ. 11:00 - 11:40 0.67 SERVIC RIG_ iN1DRL Serv. rig and top drive. 11:40 - 13:30 1.83 TRIP_ DP_ IN1 DRL RIH f- 2998' - 5292' Precationary wash f- 5232'-5292' No fill. 13:30 - 18:00 4.50 DRILL_ ROT_ IN1DRL Continue directionally ahead f/ 5292' to 5556'. 500gpm, 1450psi, 50-55rpm's, trq= 7.2k Up wt 102k, dwn wt= 55k, rt wt= 70k ART= 3.5 hrs 18:00 - 00:00 6.00 DRILL_ ROT_ IN1 DRL Continue directional drilling ahead f/ 5556' to 5850' 500gpm, 1490psi, ECD= 11.35ppg, 50-55rpm's trq= 7k Upwt= 106, dwn wnt= 50k, rotwt= 60k spr= 60 @ 260psi w/ 9.5ppg mud wob= 10-12k ART= 4.7 hrs 00:00 - 06:00 6.00 DRILL_ ROT_ IN1 DRL Continue directional dril-ing f/ 5850' to 6238'. 500 gpm 1490psi 52 rpm's, trq 7.2k. Hyd hose on elevators blew while making a connection. ART= 4.3 hrs 8/10/2007 06:00 - 11:00 5.00 DRILL_ ROT_ IN1DRL Continue directional drilling ahead f/ 6238' to 6552' Up Wt 105k Dn. Wt. 50k Rt. Wt.70k Tq 6-8k Art= 4.2hrs 11:00 - 12:15 1.25 CIRC_ MUD_ IN1 DRL Circ. B/U condition hole for wiper trip. add 1% more lubetex. Pump at 255spm 500gpm1550psi. 12:15 - 14:45 2.50 TRIP_ WIPR IN1 DRL Monitor well POH (wiper trip) f-6552'-5292' work various tight spots 15-45k drag. No back reaming or circulating. Printed: 12/21/2007 12:56:26 PM Marathon Oil Company Page 5 of 20 ~ Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours ~ Code Code.:' Phase Spud Date: 7/30/2007 Start: 7/27/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations 8/10/2007 14:45 - 15:30 0.75 SERVIC RIG_ IN1DRL Lube Carrier drivelines ,top drive blocks and crown. 15:30 - 16:15 0.75 TRIP_ DP_ IN1DRL RIH f-5292'-6552' No fill /hole slick. 5-10k drag down 16:15 - 18:00 1.75 DRILL_ ROT_ IN1DRL Directional drill w/ auto track f 6552'- 6615' 500 gpm, 1600psi Upwt= 108k dnwt= 50k, rotwt= 74k, trq= 7k WOB= 10-12k 50-55rpm's ART= 1.5 hrs 18:00 - 00:00 6.00 DRILL_ ROT_ IN1 DRL Directional drill f/ 6615' to 6868'. 500gpm 1650psi ECD= 11.5ppg, Up wt= 110k, dwwt= 50k, rtwt= 75k, trq= 7-8k WOB= 10-12k 50-55 rot rpm's ART= 4.8 hrs 00:00 - 06:00 6.00 DRILL_ ROT_ IN1 DRL Continue directional drilling f/ 6868' to 7183' 500gpm 1650 psi ECD= 11.6ppg upwt= 110k dwn wt= 50k rtwt 75k trq= 7.5k ART= 4.8 hrs 8/11/2007 06:00 - 12:00 6.00 DRILL_ ROT_ IN1 DRL Continue directional drilling f/ 7183' to 7464' Up. Wt. 120k Dn. Wt. 55k Rt Wt.76k Tq 6-9k 282spm 550gpm 1750psi. Art=5.2hrs ECD 11.7 12:00 - 15:30 3.50 DRILL_ ROT_ INIDRL Directionally Drill f/7464'-7625' Up Wt. 117k Dn.Wt. 55k Rt wt. 75k Tq=6-9k Art=3.Ohrs 15:30 - 16:30 1.00 CIRC_ MUD_ IN1DRL Circulate 2x bu at 7625' 550gpm 1850psi 282spm increase rpm's to 70. Hvy cuttings over shaker circulate until shakers cleaned up 16:30 - 20:00 3.50 TRIP_ WIPR IN1 DRL Monitor well POH ,wiper trip f 7625'- 6451'. Moderatly tight in places f/ 7300' to 6700'. 20:00 - 20:30 0.50 SERVIC RIG_ IN1DRL Circulate and work pipe at 6451' while servicing rig. 20:30 - 21:30 1.00 TRIP_ WIPR IN1DRL TIH wash last stand to bottom, no fill. 21:30 - 22:00 0.50 DRILL_ ROT_ IN1DRL Circulate and 'down-link' Auto-Trak info. 22:00 - 00:00 2.00 DRILL_ ROT_ IN1 DRL Continue directional drilling f/ 7625' to 7730' 550gpm 1960psi ,ECD= 11.7ppg, 50-55 rpms, trq= 8k ART= 1.8 hrs 00:00 - 06:00 6.00 DRILL_ ROT_ IN1 DRL Continue directional drilling f/ 7730' to 8030' w/ 550 gpm 2000psi ECD=11.8ppg 50-55 rpm's trq= 9.5k wob= 10-14k Noise coming from #2 pump gear end. LOTO pump. Remove inspection hatch. Drilling ahead w/ 440gpm 1480 psi. Nothing found on pump #2. Retum to 550gpm. Drill to 8030'. ART= 5.0 hrs 8/12/2007 06:00 - 12:00 6.00 DRILL_ ROT_ IN1DRL Continue directional drilling f/ 8030'- 8384' Up Wt. 140k Dn. Wt.60k Rt. Wt. 85k Tq 9-11 k ECD 11.8 Art 4.6hrs Pump rate 550gpm 2050psi 12:00 - 13:15 1.25 CIRC_ MUD_ IN1 DRL Circulate 2x B/U at 8348' Circ at 550gpm 2050psi. Increase rotary rpm to 75. Circ unit) shakers cleaned up 13:15 - 16:45 3.50 TRIP_ WIPR IN1DRL Monitor well, POH wiper trip 8384-7500' 10-25k drag up, RIH f-7500' to 8384' no fill hole slick normal down drag, no gain/ loss 16:45 - 18:00 1.25 DRILL_ ROT_ IN1DRL Directionally drill (/8384' to 8447'. Up wt= 145k, dwnwt= 65k. rotwt= 89k, trq= 9-11 k 550gpm 2150psi ART= 1.Ohrs Wiper trip btms up gas 76 units 18:00 - 00:00 6.00 DRILL_ ROT_ IN1DRL Continue directional drilling f/ 8447' to 8627'. #1 pump developed hydraulic leak on high pressure hyd supply line to Hagglin motor. Continue drilling ahead with 2 pumps 435gpm, 1630psi. Make repairs to #1 pump. Back on line at 8572' 550gpm 2200psi, ECD= 11.7ppg W06= 10-12k w/ 52rpm's ART= 4.90 hrs 00:00 - 06:00 6.00 DRILL_ ROT_ IN1DRL Directional drill f/ 8627' 550 gpm 2250psi, WOB 12-14k trq= 11-12k. Change out 2 valves on pump #2. At 8700' reduce to 500gpm, 1900psi, ECD 11.55gpm Drill to 8982'. Upwt= 160k, Dwnwt= 65k, rotwt=100k ART= 4.5 hrs 8/13/2007 06:00 - 07:45 1.75 DRILL_ ROT_ IN1DRL Continue directional drilling f/ 8982'-9058' (T/D 8 3/4hole section.) Up Wt. 165 Dn.Wt. 70k Rt. Wt. 105k ECD-11.5. ART= 1.8hrs Printed: 12/21/2007 12:56:26 PM Marathon Oil Company Page 6 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Sub I Phase Description of Operations Code 8/13/2007 07:45 - 09:10 1.42 CIRC_ MUD_ IN1 DRL Circulate and wndition mud for wiper trip. Increase rotatry to 75rpm. Pump 282sts 550gpm 2250psi. Circ. until shakers cleaned up. 2x B/U 09:10 - 10:45 1.58 TRIP_ WIPR IN1 DRL Monitor well Poh wiper trip 9058'-8321' Normal drag up 10-25k hole stable. no gain loss. RIH 8321'-9058, normal drag no fill 10:45 - 12:00 1.25 CIRC_ MUD_ IN1DRL Circulate 285spm 550gpm 2150psi. Pump Hi vis sweep at 9058'. Continue circulating until shakers clean up. Sweep returned with 2X increase in cuttings 12:00 - 00:00 12.00 TRIP_ DP_ IN1 DRL Monitor well, POH slm for BHA change f/ 9058' Work through various tight spots. Wash and clean up coal at 6230'-6225' continue poh. No correction slm 00:00 - 01:00 1.00 TRIP_ DP_ IN1DRL PJSM Standback HWDP. Drain motor. 01:00 - 02:00 1.00 PULD_ BHA_ IN1DRL Download Auto-Trak memory. 02:00 - 03:30 1.50 PULD_ BHA_ IN1DRL LD Auto-Trak tools. 03:30 - 04:30 1.00 SERVIC RIG_ IN1DRL Service rig. 04:30 - 05:00 0.50 PULD_ BHA_ IN1 DRL PU cleanout BHA #4 05:00 - 06:00 1.00 TRIP_ DP_ IN1 DRL TIH 8/14/2007 06:00 - 06:30 0.50 TRIP_ DP_ IN1 DRL Continue TIH with cleanout BHA #4 to 2950' 06:30 - 07:30 1.00 CUT_ WIRE IN1DRL PJSM; Slip Drilling line 07:30 - 12:00 4.50 TRIP_ DP_ IN1DRL Cont. TIH f 2950'. Fill pipe at 2950' 4850' 5680' 8976'. Wash f- 8976-9058' no fill correct displacement No gain/loss. Max gas on b/u 129u 12:00 - 14:45 2.75 CIRC_ MUD_ IN1 DRL Circulate B/U, 277spm 550gpm 1750psi Hvy clay sand returing over shakers. Mud wt out 10.Oppg continue circulating and pump sweep, condition mud for casing run. Add 4bbls lubetex. Sweep returned with 2x cutttings over shakers Mud wt 9.9ppg in and out .Pump KCL dry job 14:45 - 01:00 10.25 PULD_ DP_ IN1 DRL PJSM; Monitor well POH lay down 5" drillpipe f 9058' to HWDP 01:00 - 02:00 1.00 PULD_ BHA_ IN1 DRL PJSM. LD HWDP and cleanout BHA tools. 02:00 - 02:30 0.50 CLEAN_ RIG_ IN1 DRL Clean rig floor and tools. Observe well. 02:30 - 04:00 1.50 NUND BOPE IN1CSG PJSM: Drain stack. Close blind rams. Changeout upper VBR rams to ~' 7-5/8" csg rams. Same time off-load remaining 7-5/8" csg. 04:00 - 05:30 1.50 RURD_ CSG_ IN1CSG Pull wear bushing. PU 7-5/8" test jt and test plug. Test csg rams 250psi / 2500psi 5 min ea. Pull test plug . 05:30 - 06:00 0.50 RURD_ CSG_ IN1CSG PU Vetco 7-5/8" hanger and make dummy run. RKB 24.21 8/15/2007 06:00 - 10:30 4.50 RURD_ CSG_ INICSG RU to run 7-5/8" casing. Remove bails Install internal fill up tool to top drive. P/U long bails and 7 5/8 csg. elevators and spiders. Move torque tube. Hold PJSM; Hazards and procedures running casing 10:30 - 13:30 3.00 RUN_ CSG_ IN1CSG Make up and baker lock shoe track 80' Ck. floats Run 7 5/8 29.7# L-80 Hydril 513 Casing. Install 2 centralizers on shoe joint. attempt to RIH, work joint, unable to pass throurgh 9 5/8 csg ID 8.835. Centz bow springs 10 5/16 od x 20" remove one centz. force jt down. P/U jt 2 add 1 centz and force into hole. Unable to move pipe down after adding Jt # 3 with 1 centz. _ decision to run cs ,without centz. 13:30 - 18:30 5.00 RUN_ CSG_ IN1CSG Continue running 7 5/8 csg. f- 120' 2913' W/O centralizers. 18:30 - 18:45 0.25 CIRC_ MUD_ IN1CSG Break circulation at 2900'. 18:45 - 21:30 2.75 RUN_ CSG_ IN1 CSG Continue running csg jt #'s 95,96,97 progressively taking weight but going in hole fine. Make connection with jt# 98 then unable to ao down or u .End of cs at 3928'. (surface csg shoe at 2999') This zone is a volcanic ash. 21:30 - 00:00 2.50 RUN_ CSG_ IN1CSG PJSM. Stab in and circulate csg while working up to 260k. Mix and spot high concentration Lubetex pill. Make pill pit only active pit and bring Printed: 12/21/2007 12:56:26 PM a Marathon OiI Company Page 7 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To ~ Hours Code Code Phase Description of Operations 8/15/2007 21:30 - 00:00 2.50 RUN_ CSG_ INICSG Lubetex concentration up to 8%. Circulate at max rate of 360gpm / 980psi while working pipe. Stopped pumping and let hole relax for 20 min. Pull again without movement. 00:00 - 06:00 6.00 RUN_ CSG_ IN1CSG PJSM with new crews. Continue working pipe to max 300k. Mix 50 bbl pill with 10#/bbl SAP and 5% drilling detergent. Spot 25 bbls outside casing. Wait 30 min. Work pipe to 325k. Wait another 30 min. (meantime having machine shop make XO 7-5/8" BTp x 4-1/2"IFb to make-up to our XO circulating pup jt then back to topdrive. Also hotshoting additonal mud products..Pipe-Lax and Black Magic) Pump another 5bbls pill outside csg. Wait 30min. Work pipe to 325k. Pump 5 bbls wait 30 min. Working pipe. (Options discussed: Mixing new mud at a lower ppg. Spotting Pipe-Lax pill. Working in torque) 8/16/2007 06:00 - 12:30 6.50 WORK PIPE INICSG Continue working pipe. Pull 310k Wait on 7 5/8 buttress x 4 1/2if crossover. 12:30 - 14:00 1.50 MIX_ PILL INICSG Mix up 100bb1s 8.7 Kcl with 2% lubetex and spot in 7 5/8 X 8.750 annulus from 3000'-3993' let soak for 1 hr. recipocate pipe and pull up to 310k without success. Continue working pipe up to 310k, attempt to freeup. 14:00 - 16:00 2.00 WORK PIPE INICSG PJSM;Release torque on pipe and continue to work pipe.Max. pull 310K. 16:00 - 23:00 7.00 WORK PIPE IN1CSG PJSM;Circ. pill 10 bbls.Cont. to work stuck pipe,275K. 23:00 - 01:00 2.00 CIRC_ MUD_ IN1CSG Circulate brine from annulus and add to mud system. 01:00 - 03:00 2.00 RURD_ CSG_ IN1CSG PJSM;Lay down 350 ton elevators and bails,break out cross ovens to 533 hydril X buttress 25K torque to break out. 03:00 - 06:00 3.00 SERVIC RIG_ INICSG Move torque tube to pick up drill pipe ,rig up elevators, change out saver sub on top drive to 4" HT-38, change dies on grabber. 8/17/2007 06:00 - 06:30 0.50 JAR_ BHA_ IN1 CSG Make up baker M/S 5.5od cutter and string mill/ stablizer 06:30 - 07:30 1.00 JAR_ FISH IN1 CSG Rih 45' and make cut on 7 5/8 csg. pump 90spm 177gpm rotate at 40rpm. Cut casing. Cut was made at 45 ' to move too of 7 5/8 below rota table and bo s. La down cut'oint 07:30 - 08:30 1.00 PULD_ DP_ INICSG Load pipe rack with 100jts HT-38 drillpipe and tally. Set 10jts in v-door 08:30 - 09:15 0.75 REPAIR RIG_ INICSG Repair drive line on carrier 09:15 - 09:30 0.25 JAR_ BHA_ IN1CSG TIH With 5.5 M/S cutter assy. 09:30 - 13:15 3.75 TRIP_ DP_ IN1CSG P/U drift RIH W/ Ht-38 4" drillpipe to 2900' 13:15 - 13:45 0.50 CUT_ CSG_ IN1 CSG Set depth of Cutters at 2900' rotate at 45rpm, pump at 90spm 560psi increase circ rate to 135 spm 1050psi saw 10bb1 fluid loss .Reduce rate to 90 and 560ps no losses, torque 2.5k.increase rotary to 60rpm. tq increased to 2.74k Cut 7 5/8 csg. Note increase in tq to 7.5k confirm csg. cut./ P/U 10' to release cutters. Cut 7 5/8 csg in 13 min. 13:45 - 15:30 1.75 TRIP_ DP_ IN1CSG Monitor well, POH with 5.5 M/S cutter assy. And lay down 15:30 - 16:30 1.00 TRIP_ BHA_ INICSG Make up Bowen Spear and extension, grapple 16:30 - 17:30 1.00 TRIP_ TOOL INICSG Run spear /Grapple into 7 5/8 casing at 45'. P/U weight increased to 70k confirm Latch up of 7 5/8 casing. pull casing and set slips. Remove spear and grapple from csg. and lay down. 17:30 - 19:30 2.00 RURD_ CSG_ IN1CSG Clear rig floor Rig up 7 5/8 csg. tong and elevators. 19:30 - 03:30 8.00 TRIP_ EQIP INICSG PJSM; POOH and lay down 7 5/8 csg. Lay down cut offjt. 18', Pipe over torqued and hard to break out, some joints mashed. 03:30 - 04:30 1.00 RURD_ CSG_ IN1CSG Rig down csg. equip. and rig up to run drill pipe. 04:30 - 05:00 0.50 JAR_ BHA_ IN1CSG Measure and caliper fishing tools and drill collars. 05:00 - 06:00 1.00 JAR_ BHA_ INICSG Pick up Fishing BHA for 7 5/8 csg. 8/18/2007 06:00 - 07:30 1.50 JAR_ BHA_ IN1CSG P/U 6 1/4 drill collars RIH, 07:30 - 09:15 1.75 TRIP_ DP_ IN1CSG RIH with 4 "drillpipe to 2900'~~~ Printed: 12/21/2007 12:56:26 PM Marathon Oil Company Page 8 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code Code Phase a - -- 18/18/2007 109:15 - 10:30 1.251 JAR_ I FISH IN1CSG 10:30 - 12:30 2.00 TRIP_ DP_ IN1CSG 12:30 - 13:30 1.00 JAR_ BHA_ IN1CSG 13:30 - 14:30 1.00 REPAIR EOIP IN1CSG 14:30 - 15:15 0.75 JAR_ BHA_ IN1CSG 15:15 - 17:15 2.00 TRIP_ DP_ IN1CSG 17:15 - 18:00 0.75 JAR FISH IN1CSG 18:00 - 19:30 1.50 TRIP_ DP_ IN1CSG 19:30 - 22:00 2.50 TRIP_ DP_ IN1CSG 22:00 - 02:00 4.00 TRIP DP IN1CSG 02:00 - 03:00 1.00 LAYDW CSG_ IN1CSG 03:00 - 03:30 0.50 JAR_ BHA ~ IN1CSG 03:30 - 06:00 2.50 TRIP_ OP IN1CSG 8/19/2007 06:00 - 07:15 1.25 JAR FISH IN1 CSG 07:15 - 22:00 ~ 14.75 ~ JAR_ ~ FISH ~ IN1CSG Spud Date: 7/30/2007 Start: 7/27/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations Tag to of fish at 2902 work spear and grapple into top of 7 5/8 csg at 9 with 9 spm 350psi.l saw 50psi increase as spear entered top of 7 5/8 csg. Maintained full returns while entering top of fish.With 20k down Set grapple. P/U to 110k confirm latch up of fish. Comence jarring operations. Pull up to 250k no movement increase pull to 300k, 310k'325k work and jar 30 times with movement of fish. set down to 40k and rotate to right and release grapple. Note Circulated complete B/U from 3978' Inspect. Mast torque tube and guy wires. POOH Stand back drill collars Lay down jars bumper sub Spear and grapple Replace swivel packing cartage P/U M/U 5.5 M/S BOT cutter assy RIH To 3050' Note entered 7 5/8 csg. at 2900' Set M/S 5.5 cutters at 3050' Rotate at 46rpm and circ 90spm 650psi./152 GPM PJSM; Check flow,pump dry job,POOH,Laydown cutter assy. PJSM; Pick up 7 5/8 Bowen Itco spear.RlH Latch fish gained 5K over string weight. POOH with fish.Retrieved 151' Lay down spear. Lay down 151' of 7 5/8 csg. PJSM;rig up and pick up Itco spear assy. RIH with spear assy. Circulate and Work Spear and grapple into 7 5/8 fish at 3050' Set down into fish p/u weight increased to 120k, confirm latch up. Circulate B/U. Attempt to jar down with no pipe movement. Comence Jaring on fish. P/U to 250k, jar 275k jar, 300k jar 325k jar. No pipe movement. Continue to work pipe and jar. 15x up and 15x down no pipe movement. Continue Circulating and Mix pipe lax pill and spot F- 3930'-3050' 7 5/8 x 8 3/4 annulus. Stop Circulating .Continue to work pipe With 100k Up And 50K down during soak time for pipe lax. Note mixing time for pipelax 2hrs. Jar on pipe to 275k 350k every 2hr.3x times. Note Static fluid losses to hole 1bbl every 4hrs. Cut 233' and slip 206' drilling line waiting on pipelax soak. Jar on Fish.275-350k no movement of stuck 22:00-22:301 0.501 FLOW ICHEK IIN1CSG 22:30 - 23:30 1.00 SERVIC RIG_ IN1 CSG 23:30 - 02:30 3.00 TRIP_ DP_ IN1CSG 02:30 - 05:00 2.50 JAR_ BHA_ IN1CSG 05:00 - 06:00 1.00 CUT CSG IN1CSG 8/20/2007 06:00 - 08:15 2.25 TRIP_ DP_ IN1CSG 08:15 - 09:00 0.75 JAR_ BHA_ IN1CSG 09:00 - 10:30 1.50 TRIP_ DP_ IN1CSG 10:30 - 11:30 1.00 JAR FISH IN1CSG 11:30 - 16:00 ~ 4.50 ~ TRIP_ ~ DP_ ~ IN1CSG PJSM; Check for flow, pump dry job. PJSM; Adjust brakes. PJSM; POOH with spear assy. and lay down M/U 5.5 M/S cutter assy RIH to 3710' Make Cut at 3710' Circ at 158spm 590psi Rotate at 45rpm Tq -2.6k Saw pressure loss of 202psi. tq decreased to 2k. Pull up to 3490' and make cut #2. Pump 585 psi finish 425 psi rotate 45 rpm Tq.-2.3 - 2.7K set down 5K on cut. Note no fluid loss at 590psi. Continue POH f- 3400' Lay down 5.5MS cutter assy. P/U spear and grapple assy RIH Continue RIH W/ 4" drillpipe to 3040'. Up wt -52k Dn. wt. 42k Work spear/Grapple into top of fish at 3050' Comence faring operations. P/U to 250k Jar, 275k Jar, 300k. Pulled 310k as jars fired,lost 254k of weight. with drillstring and top drive jumping causing drilling line to back lash on draworks. Shut down and inspect guy wires,crown blocks, draworks and top drive. Up weight increased to 55/56k. 3k over string weight POH Saw slight weight increase as spear assy, entered 9 5/8 shoe at Printed: 12/21/2007 12:56:26 PM a Marathon Oil Company Page 9 of 20 ..Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date 8/20/2007 8/21 /2007 From - To Hours Code 'Cod Phase `' Description of Operations 11:30 - 16:00 I 4.501 TRIP DP IN1CSG 16:00 - 18:30 2.50 TRIP_ DP_ INICSG 18:30 - 21:00 2.50 TRIP_ DP_ INICSG 21:00 - 22:30 1.50 SETREL PKR_ IN1CSG 22:30 - 23:30 1.00 NUND BOPE IN1CSG 23:30 - 04:30 5.00 TEST BOPE IN1CSG 04:30 - 05:30 1.00 TRIP_ DP_ INICSG 05:30 - 06:00 0.50 TRIP_ BHA_ IN1CSG 06:00 - 06:30 0.50 RUNPU WBSH IN1CSG 06:30 - 07:45 1.25 PULD_ BHA_ INICSG 07:45 - 08:35 0.83 TRIP_ DP_ IN1CSG 08:35 - 09:35 1.00 REPAIR RIG_ IN1CSG 09:35 - 09:45 0.17 TRIP_ DP_ IN1CSG 09:45 - 10:20 0.58 MILL FISH IN1CSG 2998'. Continue Poh. Stand back Collars. Spear and grapple damaged,no recovery of fish. Pick up 7 5/8 csg. cutter. RIH to 3050' could not enter top of fish. PJSM; Check for flow, POOH, Break down cutter PJSM; Pick up and run RTTS storm packer set at 85' PJSM; Change out top rams to 5 1/2 " X 2 7/8' Variables. and change bottom rams to 4" Test Bop 250 / 2500psi.All components passed Perform Accumulator draw down test..Witness waved by Jim Regg AOGCC PJSM; RIH and Retrieve RTTS and lay down. PJSM;POOH W/ 6 1/4 drill collars Set wear bushing P/U 6 5/8 taper mill and string mill. Bumper Sub Jars Crossovers TIH W/ 4" drillpipe to 2640' Repair replace link tilt Hyd. hose RIH to 3440' 7 5/8 casino at 3050' Mill Inside 7 work mill and clean up top of 7 5/8csg. Continue working mill to 3235' pipe clear. 10:20 - 12:20 2.00 TRIP_ DP_ INICSG Monitor well POH to Fishing BHA 12:20 - 13:30 1.17 TRIP_ BHA_ IN1CSG Stand 6 1/4 collars back. lay down mill) assy. 13:30 - 14:00 0.50 PULD_ BHA_ INICSG Make up 5.5MS cutter assy RIH 14:00 - 15:30 1.50 TRIP_ DP_ IN1CSG RIH W/ 4" drillpipe to 3050 enter top of 7 5/8 csg.no drag rih to 3200' 15:30 - 17:00 1.50 CUT_ CSG_ INICSG Make cut at 3200' 45rpm 150stks 587psi Tq 2.5k -2.9k Pressure slack off cutter took weight,confirm cut made. Pull up to 3150 make cut with 45rpm 160stks 600psi Tq 2.6-2.8k pressure dropped to 285psi slack off ,cutter took 2k weight confirm cut made. Pull up to 3100' make cut with 45/60r m 165spm 688psi tq 2.2k-2.6k pressure dropped to 285psi slack off 3k. cutters took weight confirm cut made. 17:00 - 19:00 2.00 TRIP_ DP_ IN1CSG Pull up to 3040' monitor well pump dryjob. POH 19:00 - 19:30 0.50 RUNPU WBSH IN1CSG PJSM;PuII Wear Bushing 19:30 - 21:30 2.00 JAR_ BHA_ IN1CSG PJSM;Pick up and measure spear assy. 21:30 - 23:00 1.50 TRIP_ DP_ IN1CSG PJSM; RIH with spear assy.to 3050'. 23:00 - 23:30 0.50 LAYDW CSG_ INICSG Latch into fish at 3050' circ bottoms up. No fluid losses 23:30 - 03:00 3.50 TRIP_ DP_ IN1CSG PJSM;POOH with 7 5/8" csg. fish retreive 50' No overpull 03:00 - 03:30 0.50 JAR_ BHA_ IN1CSG PJSM;Lay down spear assy. and 50.30' 7 5/8 fish 03:30 - 04:00 0.50 JAR_ BHA_ IN1CSG PJSM;Pick up Spear assy. redress 04:00 - 05:30 1.50 TRIP_ DP_ IN1CSG PJSM; RIH with spear assy. 05:30 - 06:00 0.50 JAR_ FISH IN1 CSG Enter top of fish at 3100' with left hand rotation to 3112' pick up and confirm spear engaged 65K then pull to 100K set jars off. Pull to 150K fish came free.Up wt.53K do wt.=40K.Up wt. after engaging fish 54K Circ. bottoms POOH 8/22/2007 06:00 - 09:00 3.00 TRIP_ DP_ INICSG Monitor well POH with Fish F-3100' Stand back 6 1/4 DC Remove spear from fish recovered 50' 7 5/8 CSQ. 09:00 - 09:30 0.50 JAR_ BHA_ IN1CSG Dress out spear and grapple RIH W/ 6 1/4 drill collars 09:30 - 11:15 1.75 TRIP_ DP_ INICSG RIH W/ 4" drillpipe to 3150' Top of fish Break circulation and enter top of 7 5/8 csg. Up. Wt. 55k 40 Dn. Wt. 11:15 - 12:00 0.75 JAR_ FISH IN1CSG Set 5K down and rotate spear to left 2x turns. Circulate at 200spm 285psi. P/U to 100k set Jars off/ P/U to 150k Fish nulled free smooth . Up Wt. 56/57k Circulate B/U. No Fluid losses Note:Continued circulating while pulling fish free. Printed: 12/21/2007 12:56:26 PM r Marathon Oil Company Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Page 10 of 20 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date ~ From - To I Hours Code Code Phase Description of Operations 8/22/2007 12:00 - 14:15 2.25 TRIP_ DP_ IN1CSG POH f- 3200' 2850', Pump dryjob POH Note: Dry job was KCL (10 bbls) 14:15 - 16:00 1.75 TRIP_ BHA_ IN1CSG Stand Back Drill collars. Release spear/grapple from fish. Recovered 50' of 7 5/8 cs .Had problem Removing Spear grapple from inside Fish 16:00 - 16:30 0.50 PULD_ BHA_ IN1CSG P/U 5.5M/S cutter assy. and Dress blades 16:30 - 18:30 2.00 REPAIR RIG_ IN1CSG Replace oil pump on cotta box and C/O rig floor tongs. Repair handle on spinners. Replace Damaged guard on top drive. 18:30 - 20:00 1.50 TRIP_ DP_ IN1 CSG RIH, ~o thru top of fish at 3200' did not see anything going thru. 20:00 - 22:00 2.00 CUT_ CSG_ IN1 CSG On depth at 3356' up wt.=47K do wt.=36K Start rt. at 45 rpm slowly start pumps to 150 stks.=629 psi, 187 gpm, Tq.=3150K 10 min. for cut. Pull 50' to 3300' Cut #2 at 3300' Up wt.=47K Dn.wt.=36K, 50 rpm tq.=3048K Pump 150 stks=603 psi 187 gpm tq.=3600K cut took 10 min. Cut #3 at 3250' Up wt.=47K dn. wt.=36K 54 rpm tq.=3600K Cut slow bring pump up to 163 stks. 650 psi cut went thru, press. drop to 372 psi took 30 min. for cut. 22:00 - 22:30 0.50 REPAIR RIG_ IN1 CSG Take light from derrick for repair. 22:30 - 00:00 1.50 TRIP_ DP_ IN1CSG Check for flow, pump dry job POOH 00:00 - 01:00 1.00 JAR_ BHA_ INICSG Pick up Fishing assy. lay down 4' ext. make up run spear, 6 1/4 drill collars, acc. 01:00 - 02:30 1.50 TRIP_ DP_ IN1CSG RIH tot h 02:30 - 03:00 0.50 JAR FISH INICSG Up Wt.=55K Dn. wt.=40K Engage fish start pump at 50 stk. =72 psi rotate left hand turns and slack off to engage, set down 45K. Pick up to 100K let jars hit. Increase pump to 86 stks.=114 psi. Pull 125K let jars hit did not move.let jars hit at 150K, 175K, Straight pull max. to 250K. Fish let o when pulling to 180K and jars hit.POOH 5-10K over string wt. 03:00 - 03:30 0.50 CIRC_ MUD_ INICSG Circ. bottoms up at 204 stks. press.=290 psi 03:30 - 06:00 2.50 TRIP_ DP_ IN1CSG PJSM; POOH to shoe and pump dry job POOH 8/23/2007 06:00 - 07:00 1.00 JAR_ BHA_ IN1 CSG Stand back drillcollars, Remove spear assy. Recovered 50.20' of 7 5/8 casin .Lay joint down 07:00 - 09:30 2.50 TRIP_ DP_ IN1 CSG Dress out Spear and grapple. RIH with Spear assy and drillcollars to TOF 3250'. Up 55 Dn 40. Engage fish. Circ. 75GPM 80psi. 09:30 - 10:00 0.50 JAR_ FISH IN1CSG Jar and circ. stuck CSG Max Jar 175K Max pull 275K. CSG came free when ullin 275K and increasing pumps to 125GPM. 10:00 - 11:00 1.00 CIRC_ MUD_ INICSG Circ. B/U and inspect derrick. PJSM for POOH and handling BHA. 11:00 - 11:30 0.50 TRIP_ DP_ INICSG POOH to CSG shoe. 11:30 - 14:30 3.00 CIRC_ MUD_ INICSG Pump dryjob POOH. 14:30 - 15:00 0.50 TRIP_ BHA_ IN1CSG PJSM. Handle BHA. L/D 49.73' of 7 5/8" CSG. 15:00 - 15:30 0.50 TRIP_ BHA_ INICSG Dress spear. PJSM. 15:30 - 18:00 2.50 TRIP_ DP_ IN1CSG RIH Tag TOF(a)_3300' UP 58K DN 40K. Pump 50GPM 60psi, 18:00 - 18:30 0.50 JAR_ FISH INICSG PJSM; RIH Tag TOF@3300' UP 58K DN 40K. Pump 50GPM 60psi, Go into fish 6' and set 5K down on fish.Pick up and set jars off at 100K, bring pumps up to 100 stks= 116 psi 120 gpm, pull up 200K and fish 18:30 - 19:00 0.50 CIRC_ MUD_ INICSG Circ. bottoms up at 100 stks.=116 psi =120gpm 19:00 - 20:00 1.00 CIRC_ MUD_ IN1 CSG PJSM;POOH to 9 5/8 shoe @ 2917' Check for flow pump dry job. 20:00 - 22:30 2.50 TRIP_ DP_ IN1CSG PJSM;POOH with fish Lav down 49.60' 7 5/8 cca. 22:30 - 23:00 0.50 JAR_ BHA_ INICSG PJSM; Make up 5 1/2 Multi string Cutter 23:00 - 01:00 2.00 TRIP_ DP_ IN1CSG PJSM; RIH with 5 1/2 Multi string Cutter 01:00 - 01:30 0.50 CUT_ CSG_ IN1CSG Put cutter on de th at 3450', Up wt.=48K Dn. wt.=38K Start rotation at 47 rpm, Start pump at 153 stks.=732 psi, 191.8 gpm, Free tq.=5700K Max. tq.=6400K Cut made in 15 min. Stop rt. slack off 5K to verfy cut pressure loss to 275 psi. Pull 50' to make next cut.At 3400' Printed: 12/21/2007 12:56:26 PM • • Marathon Oil Company Page 11 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date Iii From - To Hours Code Coe Phase Description of Operations 8/23/2007 01:30 - 02:00 0.50 REPAIR RIG_ INICSG 02:00 - 02:30 0.50 CUT CSG IN1CSG 02:30 - 04:00 1.50 TRIP_ DP_ INICSG 04:30 - 05:30 1.00 REPAIR RIG_ INICSG 05:30 - 06:00 0.50 SERVIC RIG_ IN1CSG 8/24/2007 06:00 - 07:00 1.00 TRIP_ BHA_ IN1CSG 07:00 - 09:30 2.50 JAR FISH IN1CSG 09:30 - 10:30 I 1.001 CIRC I MUD I IN1CSG 10:30 - 12:30 2.00 TRIP_ DP_ IN1CSG 12:30 - 14:00 1.50 TRIP_ BHA_ IN1CSG 14:00 - 15:00 1.00 TRIP_ BHA_ INICSG 15:00 - 16:30 1.50 TRIP DP IN1CSG Work on Rig hyd. system. Put cutter on depth at 3400', Up wt.=48K Dn. wt.=38K Start rotation at 50 rpm, Start pump at 155 stks.=564 psi., 194.3 gpm, Free tq.=5760K Max. tq.=6300K Cut made in 15 min., Stop rt. set down 5K to verify cut pressure drop to 275 psi. POOH with cutter and lay down tool. Work on Top Drive Hyd. system. Service rig. M/U 7 5/8" Spear BHA. RIH w/spear assy. P/U 60K S/O 40K. Pump @ 75GPM 72psi Engage fish @ 3350'. PJSM. Jar and work stuck CSG Max Jar 200K Max Pull 275KQarred 19 total times). Vary pumps F/0 to 250GPM. Pig pe came free while working between 75K and 275K straight pull pumping with 250gpm. CBU 250GPM 380psi. Inspect derrick. PJSM. Flow check and pump dry job. POOH. Handle BHA. UD fish 59.03' cut CSG. TOF now 3409'. PJSM. Dress spear and RH w/BHA. RIH w/DP. P/U 60K DN 40K. Pump 40spm 50GPM 73psi.. Engage fish w/spear @ 3409'. 16:30 - 17:00 I 0.501 JAR I FISH I IN1CSG 17:00 - 17:30 0.50 CIRC_ MUD_ INICSG 17:30 - 20:30 3.00 TRIP DP INICSG 20:30 - 23:00 2.50 TRIP_ DP_ IN1CSG 23:00 - 23:30 0.50 JAR_ FISH IN1CSG 23:30 - 00:00 0.50 CIRC_ MUD_ IN1CSG 00:00 - 03:30 3.50 TRIP_ DP_ INICSG 03:30 - 05:30 2.00 TRIP_ DP_ INICSG 05:30 - 06:00 0.50 CUT_ CSG_ INICSG 8/25/2007 06:00 - 06:30 0.50 CUT CSG IN1CSG 06:30 - 07:00 0.50 TRIP DP INICSG 07:00 - 08:00 1.00 WORK PIPE IN1CSG 08:00 - 09:30 1.50 INSPCT RIG_ INICSG 09:30 - 12:30 3.00 SLPCUT DLIN INICSG 12:30 - 16:00 I 3.501 SLPCUTI DLIN I IN1CSG max pull 200k max pump 125GPM. Jared 2 times Circ. bottoms up.Check for flow, pump dry job PJSM; POOH With spear assy. Lay down 41.10', 7 5/8 fish TOF @ 3450' PJSM; RIH with spear assy. to 3450' top of fish. PJSM; Spear on depth, Up wt.=59K Dn. wt.=38K Pump=40 stks.=73psi=47.6gpm, Engage fish at 3450', set 10K wt. down to verify top of fish, increase pump rate to150 stks.=226psi=47.6gpm, Jar and work pipe F/150K to 250K straight pull max, Jarred on fiish 6 times,F/150K to 200K, fish came loose after jarring 2 times at 200K. Circ. bottoms up. Check for flow, pump dry job. PJSM; POOH With spear assy. Lay down 62.32' of 7 5/8 TOF @ 3514' PJSM; RIH with 5 1/2 Multi cutter to make cuts at 3564', 3614', 3664'. Put cutter on depth, at 3664' Up wt.=50K Dn wt.=37K RPM=50 Free tq.=3450K Start pump at 151 stks.=706 psi Tq. went to 3740K Made cut in 5 min. finish dress off cut with pump press. at 293 psi and tq. at 3578K 65 RPM. Position cutter and cut 7 5/8" CSG ~ 3614' UP 50K DN 37K. Good indication of cut. Cut took 15min. Pull up with cutter and tool stuck after moving up 6'. Attempt to free pipe with 100K over pull and S/O with 22K. Work torque into pipe and attempt to work free. Work stuck pipe. Pulled free with 225K. Circ. and inspect rig. Found drilling line had jumped around load cell at dead man. This caused a kink in the drilling line. PJSM;SIi and cut drilling line to get bad spot out. Did not have enough line on spare drum to complete slipping line. ut me off of drawworks drum. Cont. to circ 72gpm 140psi. PJSM;Load new line on spare drilling line spool. Quadco repaired the following while spool drilling Iine:Repair load cell on wt. indicator, and caliper iWt. indicator.Calibrate superchoke. Printed: 12/21/2007 12:56:26 PM ~ ~ Marathon Oil Company Page 12 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To j Hours Code Code Phase Description of Operations 8/25/2007 16:00 - 22:00 22:00 - 23:30 23:30 - 02:00 02:00 - 02:30 02:30 - 04:00 04:00 - 04:30 6.00 SLPCUT DLIN IN1CSG 1.50 WORK. PIPE IN1CSG 2.50 TRIP_ DP_ IN1CSG 0.50 INSPCT BHA IN1CSG PJSM;Restring blocks with new drilling line, Put drilling line onto drum to reach floor. PJSM; work stuck pipe. Something along side of BHA. Up Wt.=60K Dn. wt.=40K Cont. to work pipe out fof hole pull max. of 75K. Try to rt.object by BHA Tq.=3000K to 7900K. Work pipe from 3608' to 3514' top of fish.Then came free PJSM;POOH to check csg. cutter. PJSM;Check BHA and test cutter. String mill had a 2" cut down one side. PJSM;RIH with 5 1/2 multi string cutter, to make cut at 3564'. Put cutter on depth and cut 7 5/8 csg.@3564', Up wt.=53K Dn. wt.=40K free rt. tq.=3454K Pump /155 stks.=748 psi 193 gpm Cutting tq.=3700K cut took 15 min. press. dropped to 270 psi. Rt. tq. jumped from 3470KK to 6900K stop rt. and set down 5K on blades. Shut pump off. POOH W/ 5 1/2 multi cutter. POOH w/BHA. PJSM. UD Cutter assy. Dress spear. RIH w/BHA. RIH w/DP. UP 60K DN 40K. Engage fish @ 3514'. Confirm spear is latched. Work stuck CSG. Max Jar 140K Max Pull 225K Max pump 250gpm 350psi. Jarred 3 times. CSG came free. CBU 260GPM 325psi inspect rig. Flow check and pump dry job. POOH w/DP. Handle BHA. U_D fish(49.74'). TOF is now 3564'. Dress spear and RIH w/BHA. RIH W/DP. UP 60K DN 40K. Engage fish@3564'. PJSM. Work stuck CSG. Max jar 125K Max pull 175K Max pump 250gpm 350psi. Jarred 1 time. CSG came free. CBU 160gpm 170psi and inspect rig.Pump dry job. POOH W/ Spear assy. Fish dragged 20k to 45K over string wt. in 9 5/8 csg. PJSM; Release spear from fish. Retrieved 50' 7 5/8" csg. and (3) Cent. (4) stop collars.TOF now at 3614'. Redress spear. PJSM; RIH With spear assy. On depth, Up wt.=61K Dn. wt.= 40K, engage spear, Pump 200 stks.=345psi-250gpm ,Pull to 75K have JSA, Safety Meeting, Pull to 125K set off jars, pull to 165K, Pulled free. CBU Pump 200 stks.=352 psi -249 gpm POOH W/ Spear assy. and drill pipe.Pump dry job at shoe. Handle BHA UD Fish (49.29') TOF is now 3664' Redress spear. PJSM; RIH With spear assy. RIH w/DP. UP62K DN 40K. Engage fish @3664'. Confirm latch. PJSM. Pull fish free. Max Jar 125K, Max pull 165K, Max pump 226gpm.Jar (1) Time CBU 160gpm 175psi. Flow check pump dry job. POOH w/DP. POOH w/BHA. UD fish(70.99'). TOF now is 3735'. P/U CSG cutter and RIH. UP 53K DN37K. Tag Float collar @ 3886'. Cut CSG @ 3876'. Cut took one hour. Indication of cut was not 100% conclusive. ,Move cutter up to 3806'.Up Wt.=53K Dn. Wt.=37K Pump 153stks=695 1.50 TRIP_ DP_ IN1CSG 0.50 CUT CSG IN1CSG 04:30 - 06:00 1.50 TRIP_ DP_ IN1CSG 8/26/2007 06:00 - 06:30 0.50 TRIP_ BHA_ IN1CSG 06:30 - 07:00 0.50 TRIP_ BHA_ IN1CSG 07:00 - 07:30 0.50 TRIP_ BHA_ IN1CSG 07:30 - 10:00 2.50 TRIP BHA INICSG 10:00 -10:30 I 0.501 JAR I FISH I IN1CSG 10:30-11:00 0.50 CIRC MUD_ IN1CSG 11:00 - 14:00 3.00 TRIP_ DP_ IN1CSG 14:00 - 14:30 0.50 TRIP_ BHA_ IN1CSG 14:30 - 15:00 0.50 TRIP_ BHA_ IN1CSG 15:00 - 17:00 2.00 TRIP DP IN1CSG 17:00 - 18:00 1.00 CIRC_ MUD_ IN1CSG 18:00 - 21:00 3.00 TRIP DP_ IN1CSG 21:00 - 21:30 0.50 JAR_ BHA_ IN1CSG 21:30 - 00:00 2.50 TRIP_ DP_ IN1CSG 00:00 - 00:30 0.50 JAR BHA IN1CSG 00:30 - 01:00 0.50 CIRC_ MUD_ IN1CSG 01:00 - 04:00 3.00 TRIP_ DP_ IN1CSG 04:00 - 04:30 0.50 JAR_ BHA_ IN1CSG 04:30 - 06:00 1.50 TRIP_ DP_ IN1CSG 8/27/2007 06:00 - 08:30 2.50 ENGAG FISH IN1CSG 08:30 - 09:00 0.50 JAR_ FISH IN1CSG 09:00 - 10:00 1.00 CIRC_ MUD_ IN1CSG 10:00 - 12:00 2.00 TRIP_ DP_ IN1CSG 12:00 - 14:00 2.00 TRIP_ BHA_ IN1CSG 14:00 - 17:00 3.00 TRIP_ BHA_ IN1CSG 17:00 - 18:00 1.00 CUT CSG IN1CSG 18:00 - 19:00 ~ 1.00 ~ CUT_ ~ CSG_ ~ IN1CSG Printed: 12/21/2007 12:56:26 PM ~ » Marathon'Oil Company Page 13 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase 8/27/2007 18:00 - 19:00 1.00 CUT CSG IN1CSG 19:00 - 21:30 2.50 TRIP_ DP_ IN1CSG 21:30 - 22:00 0.50 JAR_ BHA_ INICSG 22:00 - 00:00 2.00 TRIP_ DP_ IN1CSG 00:00 - 01:00 1.00 SERVIC RIG_ IN1CSG 01:00 - 02:00 1.00 TRIP_ DP_ IN1CSG 02:00 - 02:30 0.50 JAR FISH IN1CSG 02:30 - 03:00 0.50 CIRC_ MUD_ IN1CSG 03:00 - 03:30 0.50 TRIP_ DP_ IN1CSG 03:30 - 04:00 0.50 CIRC_ MUD_ IN1CSG 04:00 - 06:00 2.00 TRIP_ DP_ IN1CSG 8/28/2007 06:00 - 07:00 1.00 TRIP BHA_ IN1CSG 07:00 - 08:00 1.00 TRIP_ BHA_ IN1CSG 08:00 - 09:00 1.00 REPAIR RIG_ IN1CSG 09:00 - 11:00 2.00 TRIP DP_ IN1CSG 11:00 - 11:30 0.50 _ JAR_ FISH IN1CSG 11:30 - 12:00 0.50 CIRC_ MUD_ IN1CSG 12:00 - 15:30 3.50 TRIP DP_ IN1CSG 15:30 - 16:30 1.00 TRIP_ BHA_ IN1CSG 16:30-19:00 2.50 TRIP_ BHA_ IN1CSG 19:00 - 20:00 1.00 JAR_ FISH IN1 CSG 20:00 - 21:00 1.00 TRIP_ DP_ IN1CSG 21:00 - 21:30 0.50 CIRC_ MUD_ IN1CSG 21:30 - 00:00 2.50 TRIP_ DP_ IN1CSG 00:00 - 02:00 2.00 JAR BHA IN1CSG 02:00 - 03:30 1.50 PULD_ BHA_ IN1CSG 03:30 - 06:00 2.50 PULD_ DP_ IN1CSG 8/29/2007 06:00 - 14:00 8.00 PULD_ DP_ IN1CSG 14:00 - 15:30 1.50 REPAIR RIG IN1CSG 15:30 - 18:00 2.50 PULD_ BHA_ IN1CSG 18:00-19:30 1.50 TRIP_ DP_ IN1CSG 19:30 - 00:00 4.50 REAM OH IN1CSG 00:00 - 01:30 ~ 1.50 ~ CIRC_ ~ MUD_ ~ IN1CSG 01:30 - 05:30 ~ 4.00 ~ REAM_~ OH_ ~ IN1 CSG 05:30 - 06:00 0.50 CIRC_ MUD_ IN1CSG 8/30/2007 06:00 - 09:00 3.00 CIRC MUD IN1CSG 09:00 - 14:00 5.00 TRIP_ DP_ IN1CSG Description of Operations psi - 191.8gpm, 47 RPM=3578 free tq., Max. tq=3900 Stop rt. set down 3K no indication of cut. Bring pump up to 200 stks.=1100psi rt.50 rpm. Pump press. dropped to 270 psi indicating pipe cut. Shut down rt. set down 5K.Turn pump off POOH. POOH with 5 1/2 Multi cutter Lay down 5 1/2 multi cutter. Pick up spear assy. RIH with spear assy. to 1700' PJSM; Service Rig and Equipment RIH with spear assy. from 1700' PJSM;On depth W/ spear at 3735' Up wt.=62K Dn. wt.=41 K Pump 40 stks.=96psi 51.4gpm, Set 20K on fish ull to 75K to confirm latched, increase pump rate to 200 stks.=324psi, 249.4gpm, Hit jars (6 times F/125K to 175K max., straight pull F/175K, to max.=250K came free. Circ. bottoms up 200 stks.=324psi, 249.4gpm. PJSM;POOH w/ fish to Csg.shoe @2993' Check for flow and pump dry job. PJSM;POOH w/ fish from Csg.shoe @2993' POOH w/BHA. UD fish(71.64'). TOF now 3806'. PJSM. Dress spear and RIH w/BHA. Inspect and adjust drawworks breaks. RIH Engage fish @ 3806'. UP 63K DN 35K 55GPM 100psi. PJSM. Max Jar 150K Max Pull 250K 250GPM. Jar 1 time. CBU 250GPM. POOH. POOH w/BHA. UD fish (70.48'). TOF @ 3876'. Dress spear an RIH. On depth at 3876' Up wt.=65K Dn. wt.=40K Start pump at 40 stks.=100 psi 52.6 gpm, Slack spear into top of fish, set down 10K down. Pull up to 75K to confirm latch in. Jar wt. from 150K to 175k jarred (2) times. Max. straight pull 250K,,fish came loose with up weight of 175K. PJSM; POOH w/fish to shoe Circ. pump dry job. PJSM; POOH w/fish to surface PJSM;Break down spear assy. and lav down fish 94', 7 5/8 csg with float collar and float shoe. ~~ ~~ ~ L~ A ~ PJSM;Lay down 6 1/4" drill collars from derrick. Pick up 4" drill pipe and stand back in derrick. P/U 4" DP. Troubleshoot top drive(link tilt float does not allow bales and elevators to hang straight down). PJSM. Prep to P/U BHA. P/U BHA./Install wearbushing. RIH W/ 4" drill pipe to 3993' Wash and ream F/3993' to 7000' Pump=200 stks.=700 psi - 250gpm tagging tight spots goinging hole. Circ. bottoms up and condition mud @7000'.pump 200 stks.=700 psi 250 gpm Wash and ream F/7000' to 9058' Pump 200 stks.=Tagging tight spots going in hole. Hole not taking fluid.Up wt.=140K Dn. wt.=51 K rt. wt.=84K Tq.-5-6K Circ. and condition mud at 9058' Cont. to Circ. and condition mud. Stage pumps up to 416GPM 1780psi. CBUX3. Flow check pump dry job and POOH to CSG shoe @ 2999'. ~ Printed: 12/21/2007 12:56:26 PM ~ ~ Marathon Oil Company Operations Sumrnary Report Page 14 of 20 Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From'- To Hours Code ode Phase Description of Operations 8/30/2007 14:00 - 15:00 1.00 SERVIC RIG_ IN1CSG 15:00 - 18:00 3.00 TRIP_ DP_ INICSG 18:00-19:45 1.75 CIRC MUD IN1CSG 19:45 - 21:45 2.00 CIRC_ MUD_ IN1CSG 21:45 - 04:00 6.25 TRIP_ DP_ IN1CSG 04:00 - 04:45 0.75 TRIP_ BHA_ INICSG 04:45 - 04:55 0.17 SAFETY MTG IN1CSG 04:55 - 05:30 0.58 RUNPU WBSH INICSG 05:30 - 06:00 0.50 RURD_ CSG_ INICSG 8/31/2007 06:00 - 07:00 1.00 RURD_ CSG_ IN1CSG 07:00 - 08:30 1.50 RURD CSG_ IN1CSG 08:30 - 09:00 0.50 _ RURD_ CSG_ IN1CSG 09:00 - 12:00 3.00 RURD CSG INICSG 12:00 - 14:00 2.00 RURD_ CSG_ INICSG 14:00 - 15:30 1.50 RUN_ CSG_ IN1CSG 15:30 - 21:30 6.00 RUN CSG INICSG 21:30 - 05:15 7.75 RUN_ CSG_ IN1CSG 05:15 - 06:00 0.75 CIRC_ MUD_ IN1CSG 9/1/2007 06:00 - 08:30 2.50 CIRC_ MUD_ IN1CSG 08:30 - 09:45 1.25 PUMP_ CMT_ INICSG 09:45 - 11:30 1.75 CIRC_ MUD_ INICSG 11:30 - 12:30 1.00 RURD_ CMT_ IN1CSG 12:30 - 15:00 2.50 NUND WLHD INICSG 15:00 - 1.7:00 2.00 NUND WLHD IN1CSG 17:00 - 18:00 1.00 NUND WLHD INICSG Service rig. RIH to 9058'(tagged @ 9020', turned pumps on and rotated to 9058). Circ. clean (415GPM, 1750psi, 70RPM) fines and clays circulated to surface. Pump Safe-Garb sweep/gauge, came back on time indicating fairly gauge hole. Increased Lube-tex 1%. Pump KCL dry job. PJSM. TOH. One tight spot at 3755' worked area several times. Remainder of trip good. SLM..no corcection. LD BHA. Observe well...static. PJSM. Review Plan Forward and JSA's for pulling wear bushing and changing out VBR's to 7" casing rams. Drain BOP stack and pull wear bushing. Close blind rams. Change out VBR pipe rams for 7" casing rams. Continue changing out VBR pipe rams for 7" casing rams. Test rams. Rams leaking. Tum ram blocks over and retest 250!2500 osi OK. Test run 7" hanger assy. and UD. PJSM. Remove elevators and C/O.to long bales. Install fill up tool. C/O snubbing post. Cont. R/U CSG tools. PJSM. M/U and Bakerlok shoe track and check floats. Cont run 7" 26PPF L-80 Mod-Butt CSG. Check wt's at surface csg shoe (up 87k, dwn 30k) and break circulation. Continue running csg without problems to 3970'. (end of trouble time) Continue running csg breaking circulation every 500' to 6800' then every 1000' to 9000'. MU landing jt and landout hanger. 7" shoe is at 9038.38' No problems, no fill. Ran total of 220 jts Circulate and condition mud while rigging down Weatherford equipment. Cont. CBU prior to cementing(250gpm, 790psi). Shut down circ. R/U BJ cement head. Cont. circ. CSG 250GPM 790psi(circ total 1.5XCSG vol). PJSM prior to cementing. Transfer fluid to Hanson tank to make room in pits for volume increase from cement job. Pump 5bbls water ahead. Test cement lines to 3000psi. Drop bottom plug. Mix and pump 30bbls 10ppg spacer. Mix and pump 289sxs "G" cement w/20%MPA, 2%SMS, .3%FL-52, .4%R-3, .2%CD-32, .05%Static free, 1gphs FP-6L to yield 126bb1s 12.5ppg slurry. Tail in with 145sxs "G" cement w/.6%FL-63, .5%EC-1, .1%ASA-301,.3%CD-32, .1%R-3, .05%Static free, and 1gphs FP-6L to yield 30bbls 15.8ppg slurry. Drop top plug and kick out with 10bbls from BJ. Displace with rig pumps 334bb1s(96%eff) 9.8ppg mud. Displace @4BPM after catching cement. Did not bump plug. Engage pumps and displace another 2bbls and did not bump plug. Max pressure @2BPM 850psi. Bleed off pressure and checked floats OK. CIP@11:30hrs. Full returns during entire cement job. R/D Cement head. Release and L/D hanger running tool . Empty pits. Install 11" X 7 5/8" hanger packoff. Empty and clean pits. Organize rig floor. R/D CSG elevators. Test packoff to 5000psi. Seal ruptured during test. Retrieve packoff and redress. Install packoff. R/D circ. tool and long bales. R/U short bales. Cont. to inject packing into void of packoff. Test Printed: 12/21/2007 12:56:26 PM Marathon Oil Company Page ~5 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date 'From - To ~ Hours Code .Code Phase Description of Operations 9/1/2007 17:00 - 18:00 1.00 NUND WLHD IN1 CSG packoff and failed. Pull inspect found 2 of 4 o-rings nicked. Also LDS were run in on upper o-ring groove damaging it. 18:00 - 21:00 3.00 TEST_ WLHD IN1CSG Redress seal assembly same time pickup wash tool. RIH and pump 6bpm washing face of wellhead bowl and BOP stack. Install packoff. Tested to 5000psi for 15 min. 21:00 - 21:30 0.50 RURD_ OTHR IN1CSG Readjust torque tube from running casing. 21:30 - 22:00 0.50 TEST_ BOPE IN1CSG Remove 7" casing rams and install 2-7/8" x 5" VBR's. 22:00 - 00:00 2.00 TEST_ BOPE IN1CSG PJSM Test BOPE to 250psi/2500psi 5 min each. VBR's failed to test. AOGCC wavied witnessing test. 00:00 - 01:00 1.00 TEST_ BOPE IN1 CSG Crew change. PJSM continue testing BOPE 01:00 - 02:00 1.00 TEST_ BOPE IN1 CSG Inspect VBR rams found one carrier installed upside down. Retest 250psi/2500psi. Good test. 02:00 - 02:40 0.67 RUNPU WBSH IN1CSG Set wear bushing. RILDS. LD testjt. 02:40 - 03:30 0.83 TEST_ CSG_ IN1CSG Test 7" casing to 2000psi for 30 min. Good test no leak-off. 03:30 - 05:30 2.00 SERVIC RIG_ IN1CSG Cut /slip drilling line. Adjust brake. Service rig and topdrive. 05:30 - 06:00 0.50 PULD_ BHA_ IN1CSG PJSM Start PU 6-1/8" drill out BHA. 9/2/2007 06:00 - 07:30 1.50 PULD_ BHA_ IN1CSG Cont. to PU 6-1/8" bit drill out BHA. 07:30 - 10:00 2.50 PULD_ DP_ IN1CSG P/U 74 joints coated 4" DP. 10:00 - 13:30 3.50 TRIP_ DP_ IN1CSG Cont. RIH Tag cement stringer at 8620'. 13:30 - 16:30 3.00 DRILL_ CMT_ IN1CSG Drill cement stringers F/8620' to 8680'. Drill wiper plug and firm cement F/8680'. Drill Float collar @ 8954'. Drill shoe track and shoe @ 9038'. Clean 8 3/4" hole to 9058'. 16:30 - 17:00 0.50 DRILL_ ROT_ IN1 CSG Drill F/9058' to 9078'. ART= 0.5hrs 17:00 - 19:30 2.50 CIRC_ MUD_ INICSG Circ. clean. Pump 34 bbl lead hi-vis sweep followed by new 9.4ppg Flo-Pro mud. 19:30 - 20:00 0.50 TEST_ LOT_ IN1CSG Perform FIT with 9.4 mud. Take to 12.4 EMW no leak-off seen. Hold BOP drill. 20:00 - 01:00 5.00 TRIP_ DP_ PR1DRL PJSM. TOH 01:00 - 03:15 2.25 PULD_ BHA_ PR1 DRL PU BHA #35 including 7" RWD bit. test MWD tool. Placed Agitator tool and shock sub 2000' above bit. Test Agitator 03:15 - 06:00 2.75 TRIP_ DP_ PR1DRL TIH 9/3/2007 06:00 - 06:30 0.50 TRIP_ DP_ PR1DRL Cont. TIH with 7" RWD drilling assembly to CSG shoe. 06:30 - 07:00 0.50 SERVIC RIG_ PR1 DRL Service rig. 07:00 - 07:30 0.50 TRIP_ DP_ PR1 DRL Cont. RIH wash last 60' down to 9078'. 07:30 - 12:00 4.50 DRILL_ ROT_ PR1 DRL Dir drill and survey F/9078' to 9130'(ART=1.3hrs AST=2.Ohrs). 12:00 - 14:30 2.50 DRILL_ ROT_ PR1 DRL Dir drill and survey F/9130' to 9152'. (ART=O hrs AST=2.Ohrs MWD tool quit pulsing while slide drilling). 14:30 - 15:00 0.50 CIRC_ MUD_ PR1DRL Troubleshoot MWD pulsar failure(cycle pumps and rotate drill string). 15:00 - 16:00 1.00 DRILL_ ROT_ PR1 DRL Drill F/9152' to 9193' (ART=.Shrs AST=Ohrs rotating and giving pulsar a chance to start working, pulsar did not start working). 16:00 - 17:00 1.00 CIRC_ MUD_ PR1DRL Circ. clean CBUX1(275GPM, 2000psi). (Cycle pumps several times to give pulsar a chance to start working, pulsar did not start working). 17:00 - 17:30 0.50 TRIP_ DP_ PR1DRL POOH to 9060'. Circ. and try to get MWD pulsar to pulse. Pulsar would not pulse. Flow check and pump dry job. 17:30 - 22:00 4.50 TRIP_ DP_ PR1 DRL TOH. Visually inspect MWD's pulsar sub but nothing found to indicate problems. Inspect motor, RWD and pilot bit -looks new. 22:00 - 02:30 4.50 TRIP_ BHA_ PR1 DRL Pick-up new MWD TIH test MWD. TIH to 2000' PU Agitator and shock sub and test same continue TIH to 9000'. 02:30 - 03:15 0.75 SERVIC RIG_ PR1 DRL Service rig. 03:15 - 03:30 0.25 TRIP_ DP_ PRIDRL TIH to 9193' no fill. Survey 03:30 - 06:00 2.50 DRILL_ ROT_ PR1 DRL Directionally drill f/ 9193' to 9233. 270gpm 1950psi 100-150psi motor work with 4-6k wob. Slide drilling with 180 TF ART= 0.5hrs AST= 1.4hrs Printed: 12/21/2007 12:56:26 PM ~ r Marathon Oil Company Operations Summary Report Page 16 of 20 Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING I Rig Number: 1 Date From - To Hours Code Cod 1 Phase Description of Operations 9/4/2007 06:00 - 12:00 6.00 DRILL_ ROT_ PR1DRL 12:00 - 18:00 6.00 DRILL_ ROT_ PR1DRL 18:00 - 00:00 6.00 DRILL ROT PR1 DRL 00:00 - 06:00 6.00 DRILL_ ROT_ PR1DRL 9/5/2007 06:00 - 12:00 6.00 DRILL_ ROT_ PR1DRL 12:00 - 17:30 5.50 DRILL ROT PR1DRL 17:30 - 18:45 1.25 CIRC_ MUD_ PR1DRL 18:45 - 20:30 1.75 TRIP WIPR PR1DRL 20:30-21:10 0.67 TRIP_ WIPR PR1DRL 21:10 - 00:00 2.83 DRILL ROT PR1 DRL 00:00 - 06:00 6.00 DRILL ROT PR1DRL 9/6/2007 06:00 - 09:30 3.50 DRILL ROT PR1DRL 09:30 - 10:30 1.00 MIX LCM PR1DRL 10:30 - 11:30 1.00 TRIP WIPR PR1DRL 11:30 - 18:00 ~ 6.50 ~ DRILL_ ~ ROT_ ~ PR1 DRL 18:00 - 00:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 00:00 - 06:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 9/7/2007 ~ 06:00 - 12:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL Dir drill and survey F/ 9233' to 9354'(ART=1.4hrs AST=2.4hrs) Dir drill and survey F/9354' to 9508'(ART=2.2hrs AST=2.3hrs). Directional drill ahead f/ 9508' to 9650'. 300gpm 2500psi 2-300psi dill W06= 4-10k ART= 1.8 hrs AST= 3.1 hrs Directional drill ahead f/ 9650' to 9780' 305gpm 2650psi 200psi motor work 5-10k wob up wt= 155k dwn wt= 55k, rot wt= 90k trq 8.5k ART= 1.5 hrs AST= 3.1 hrs Dir drill and survey F/9780' to 9948'(ART=2.5hrs AST=2.3hrs). Dir drill and survey F/9948' to 10,146(ART=3.1hrs AST=.7hrs). Lost#1generator while drilling @10,146. Circ. shakers clean TOH to 9-5/8" shoe. Up wt 155k. Hole in good condition. Same time diagnose problem with generator #1 (rotating diode went out. replaced it with one from stand-by generator.) TIH Continue directional drilling f/ 10147' to 10264' 300gpm 2730psi 5-10k wob ART= 2.6hrs AST= Ohrs Directional drill f/ 10264' to 10574' 300gpm 2750psi, 5-8k wob, mud wts= 9.5/9.5+ ART= 4.7 hrs Directional drill f/ 10574' -10672' Starting loosing returns at 10662' Decrease pump rate to 210gpm 1575psi. Start adding safe Garb 10/20/40 to active system Continue drilling ahead to 10672' Total fluid loss 149bb1s. Shut pumps down Welt static no fluid loss. ART= 2.3 hrs Mix and pump 56bbls 100# per bbl safe Garb pill and spot at 10672,-10662' Ck flow ,well breathing,aull 3 stands while Icm pill is soaking. Saw 26bb1 gain from well breathing. Drill ahead f/ 10672'- Fluid loss continues at 40bbls per hour. Build 50bb1 batches of mud and add to active system. Begin increasing pump rate f-210gpm to 250gpm 2100psi fluid losses remain at 40bbls per hour. No change in fluid loss with increase in pump rate. Continue to drill ahead, fluid loss Decreasing to 30bbls per hr at 10755' Well breathing, on connection 17bb1 gain. Fluid loss decreased to 20bbls per hr. at 10830. Well flowed back 20bbls on connection at 10830'. Drilled to 10950' ART= 4.9hrs Directional drill ahead f/ 10950' to 11094'. Heavier losses at 11000' 20-30bbls/hr. hit hard streak at 11085' and losses tapered to <5bbls/hr 240-245gpm 1800psi 400-500psi dill wob= 8-11 k rop= 50-90'/hr while rotating trq= 11-12k adding Lubetex to system. Well breathing back +/- 10-20 bbls on connections. Total losses since loss occured up to midnight is 550 bbls. ART= 4.0 hrs AST= 0.9 hrs Directional drill ahead f/ 11094' to 11285' 245gpm 2100psi with 10k wob silding 8-17'/hr losses 5bbls/hr. Start rotating at 11113' rop= 50'-80'/hr losses maintaining +/- 5bbls/hr (48 units connection gas from 11148') Losses increasing to 15-25 bbls/hr shortly after rotating. Continue having 20bb1 gain while making connections. ART= 3.7hrs AST= 1.4hrs Continue directional drilling f/ 11,285'-11,500'. Up Wt. 180k Dn. Wt. 70k Rt. Wt. 112 Tq 9-11k. Pump 245gpm 2150psi. Fluid loss 19.5bbls per hr. Well continues to flow back on connection 20-30bbls. Reduced pump rate on connections to 205gpm 1625psi with no losses. Art=4.4 Ast= Printed: 12/21/2007 12:56:26 PM ~ ~ Marathon Oil Company Page 17 of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 D Fr T I~ t om - ate o ion of Operations , Hours Code Code Phase Descrip 9/7/2007 12:00 - 18:00 6.00 DRILL_ ROT_ PRIDRL Directional drill f/11,500'- 11,700' max gs 200units Up Wt 175k Dn Wt 75k Rt Wt. 117K Tq 9-10k Reduce Pump rate to 225gpm drilling. Fluid losses decreased to 10.3bbls per hr. Well flowing back 20bbls on connections. Add 1 % E/P tube. Art= 5.0 hrs Ast=O 18:00 - 00:00 6.00 DRILL_ ROT_ PR1 DRL Directional drill F-11,700'- Make connection at 11716' then shortly after ROP dropped to <5'/hr. Gradual increase in ROP to 8'/hr avg to 11749' then punched through hard streak with ROP increasing to 50'/hr. Reset stroke counter watching BU gas. max 81 units. Drilled to 11824'. Connections flowing back 15-20bbls. ART= 5.2hrs 00:00 - 06:00 6.00 DRILL_ ROT_ PR1 DRL Directional drill ahead f/ 11824' 226gpm 1800psi off bottom 300-400psi dill. wob= 5-11k rop 20-60'/hr trq= 10k Up wt= 180k, Dwn wt= 72k, rt wt= 119k varied losses to hole 5-15 bbls/hr. Connections flowing back 15-20 bbls. Fluid lost to hole last 24 hrs= 355 bbls ART= 4.9 9/8/2007 06:00 - 07:30 1.50 DRILL_ ROT_ PR1DRL Continue drilling f/ 12045' -12069' T/D Up Wt.= 182k Dn. Wt. 71kRt. Wt.120k Tq 9.5-10.5k. Fluid losses 20bbls. Art= 1.3hrs Ast=O 07:30 - 10:00 2.50 CIRC_ MUD_ PR1DRL Circulate B/U for samples to confirm T/D. 169spm 1725psi 210gpm. Reduce circ rate to 175gpm/1460psi. no losses , 10bb1 gain from well breathing. Reduce Circulating rate to 75gpm 850psi. had 15bb1 gain well breathing) Shut pumps down. Well breathing, 6 bbl gain. Flow from well decreased from 30% flow to 5% flow .Total of 37bbls returned from well breathing 10:00 - 13:30 3.50 TRIP_ WIPR PR1 DRL Monitor well. 4% flow (breathing) pull 10 stands Monitor well no increase in flow Continue wiper trip to10560'. No flow from well, continue poh to 10149' Hole slick no over pulls. RIH to 12069' at reduced rate. Clean up ledge at 11620' Tag bottom no fill 13:30 - 15:30 2.00 CIRC_ CFLD PR1 DRL Circulate B/U at 12069' 180gpm 1565psi. No fluid losses during circulation Heavy returns of cuttings over shakers. Continue circulating until shakers cleaned up. Max gas on B/U 400units. 15:30 - 18:15 2.75 TRIP_ DP_ PR1 DRL Monitor well for 10 min. no flow. Pull 5 stands monitor well. Pump dry job for trip margin. Drop 1.990" drift Pull 10stands Ck Flow. Continue POH and SLM into 7" csg. 18:15 - 19:15 1.00 SERVIC RIG_ PR1DRL Monitor well while servicing rig and cut/slip drilling line. Well stable no gain/loss. 19:15 - 01:00 5.75 TRIP_ DP_ PR1DRL Continue TOH SLM no correction. All DP/HWDP/Jars drifted fine. 01:00 - 02:30 1.50 PULD_ BHA_ PR1 DRL LD BHi tools. Clean rig floor. 02:30 - 02:45 0.25 SAFETY DRIL PR1 EVL PJSM/JSA review procedures for MU of logging tools and BHA. 02:45 - 05:40 2.92 PULD_ BHA_ PR1 EVL PU logging lower 3-1 /2" DP BHA ("garage" drift with 2.35") PU and load logging tools. Check flow pressures at 2, 4, 6 bbls 05:40 - 06:00 0.33 TRIP_ DP_ PR1EVL TIH with Weatherford Quad-Combo logging tools. 9/9/2007 06:00 - 12:30 6.50 TRIP_ BHA_ PR1EVL TIH with Weatherford Quad-Combo logging tools. Ck flow pressures at 3000', 6000' & 9000' Tag Bottom at 12069' no fill Pull up to 12056' No gain /loss 12:30 - 13:30 1.00 CIRC_ MUD_ PR1 EVL Circ B/U at 12056' 154stks 195gpm 1450psi No gain or losses. max gas on B/U 290uniits. Up Wt 175k Dn Wt 85 Rt Wt 115k 13:30 - 21:40 8.17 LOG_ OH_ PR1 EVL Pull up to 11954 and drop messenger dart. Pump dart down at 133stks 166gpm 1086psi at 3000stks reduce rate to 67stks 590psi 84gpm. at 3850stks pressure increased to/1275psi then dropped to 275psi confirmed logging tools deployed Pump dry job .Run quad/ combo tools on drillpipe shuttle from 12054' Printed: 12/21/2007 12:56:26 PM ~ ~ Marathon Oil Company Page ~ s of 20 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Phase Description of Operations Date Fram - To I' Hours Code Cod e 9/9/2007 13:30 - 21:40 8.17 LOG_ OH_ PR1 EVL (depth with tools deployed) to 6873'. 21;40 - 00:30 2.83 TRIP_ DP_ PR1 EVL TOH 00:30 - 01:45 1.25 PULD_ LOG_ PR1 EVL PJSM. LD logging tools. Confirmed data was recorded. 01:45 - 02:45 1.00 SERVIC RIG_ PR1 EVL Service rig. Re-adjust actuator on hydraulic elevators. Hole static. 02:45 - 03:00 0.25 PULD_ BHA_ PR1 EVL MU 6-1/8" bit w/o jets, bit sub and XO 03:00 - 06:00 3.00 TRIP_ DP_ PR1 EVL TIH break circulation at 3800', Fill drillpipe 9/10/2007 06:00 - 09:30 3.50 TRIP_ DP_ PR1EVL Continue TIH w/ 6-1/8" bit. (open jets) Fill pipe at 6800', 9000'. Wash from 11960' to 12069' Tag 8' fill. No gain/Loss . 09:30 - 12:00 2.50 CIRC_ MUD_ PR1EVL Circulate and condition mud at 12069' stage circulate 136stks 135gpm 850psi No fluid loss to hole. Run Centerfuge van. Mud weight out 9.7. Increase circ rate to 170spm 215gpm 945psi at 9.5 mud weight. With no fluid losses to hole. Increase rate to 200spm 250gpm 1067psi. 9.3+Mud weight In and out. 12:00 - 13:00 1.00 TRIP_ DP_ PR1 EVL Poh f-12069' to 11642' 13:00 - 14:30 1.50 MIX_ LCM_ PRIEVL Mix 100bb1 9.8ppg 25ppb G-seal / 25ppb Safe-Garb LCM pill and pump 3350stks to place in drillpipe 14:30 - 15:30 1.00 PUMP_ LCM_ PR1EVL Pump G- seal LCM pill at 10,672- 10,642'. Pump at 300spm 376gpm 1810psi.11.1 ECD Saw 20 bbl loss to hole. After 20 bbls hole stablized with no loss. Increase pump rate to 345spm 433gpm 1902psi 11.4 ECD. Lost 9 more bbls then hole stablized with no Iosses.Total of 29bbls lost. Shut down pumps had 6bbls returned and flow stopped. Putl 8 stands, monitor well no flow. Pump dry job . 15:30 - 19:00 3.50 TRIP_ DP_ PR1 EVL POH f- 10320' Stop at 9000' Monitor well. No gain /Loss. Continue POH to 3757'. 19:00 - 22:30 3.50 PULD_ DP_ PR1 EVL PJSM. LD 3000' of 4" drillpipe. 22:30 - 23:30 1.00 TRIP_ BHA_ PR1 EVL TOH w/ BHA 23:30 - 00:00 0.50 RURD_ CMT_ PR1 EVL RD dp elevators. 00:00 - 00:20 0.33 SAFETY DRIL PR1 EVL PJSM. New crews. Review past 2 weeks of work. Review Plan Forward. 00:20 - 02:15 1.92 RURD_ CSG_ PR1 EVL RD bales. RU long bales. RU Weatherford equipment to run RFT through 4 1/2" Hydrill 563 casing. 02:15 - 02:30 0.25 SAFETY DRIL PR1 EVL Hold PJSM/JSA with all crews for PU running 4-1/2" tbg 02:30 - 06:00 3.50 RUNPU TBG_ PR1 EVL Run 4-1/2" 12.6# L-80 Hyd 563 tbg make-up torque 40001bs 9/11/2007 06:00 - 06:30 0.50 REPAIR EOIP PR1EVL Repair O-ring on Weatherfords hyd power pack 06:30 - 14:00 7.50 RUNPU TBG_ PR1EVL Continue running 4-1/2" 12.6# L-80 Hydril 563 tbg. Hold 20min safety meeting with new crew. Continue running 4 1/2 tubing. to 10508' 262jts 14:00 - 15:15 1.25 CIRC_ MUD_ PR1EVL R/U and Circ.B/U at 10508'. Pump 219spm 274gpm 800psi No gain/Loss Max gas on B/U 46 units. 15:15 - 17:30 2.25 RURD_ ELEC PR1 EVL R/U E-line guide on top drive and hang wire line sheave's R/U.Weatherford wire line tools. 17:30 - 18:15 0.75 WAITON EOIP PR1 EVL Wait for cross over for pack off Weatherford wire line 18:15 - 20:00 1.75 PULD_ LOG_ PR1 EVL PU logging tools and MU pcak-off with pump-in sub. 20:00 - 06:00 10.00 RUNPU ELEC PR1EVL RIH with RFT tools without pumping. Stopped at 1350'. Start pumping gradually increasing flowrate tools moving starUstop with increased flowrate stopped at 1860' with 5.2bpm 700psi. Pack--off not holding good. POH with tools to 200'. Pull pack-off assembly from tubing. Slit 4.5" drillpipe "nerf' wiper ball and install on top of logging tools. MU pack-off. RIH with just charge pump at 26 psi. Log tools stop at 1200' slowly increase flowrate to 3.6bpm 550psi and logging tools going downhole nicely at 100'/min then stopped at 3500'. May have pumped nerf ball past logging tools. TOH ball is gone. Install a 6" ball with some support under it (3.5" OD Printed: 12/21/2007 12:56:26 PM Marathon Oil Company Operatiolns Summary Report Legal Well Name: Common Well Name Event Name: Contractor Name: Rig Name: Date From - To GRASSIM OSKOLKOFF 6 GRASSIM OSKOLKOFF 6 ORIGINAL DRILLING GLACIER DRILLING GLACIER DRILLING Hours Code Code Phase 9/11/2007 120:00 - 06:00 10.00 I RUNPUL ELEC PR1 EVL 9/12/2007 106:00 - 12:45 6.751 RUNPUL ELEC PR1 EVL 12:45 - 14:30 1.75 RURD ELEC I PR1 EVL 14:30 - 15:15 0.75 RUN_ CSG_ PR1 EVL 15:15 - 15:45 0.50 CIRC MUD PR1EVL 15:45 - 02:00 10.25 RUNPU TBG_ PR1EVL 02:00 - 02:30 0.50 RURD_ CSG_ PR1 EVL 02:30 - 03:00 0.50 SERVIC RIG_ PR1EVL 03:00 - 04:30 1.50 REPAIR RIG PR1 EVL 04:30 - 04:50 0.33 PULD_ BHA_ PR1 EVL 04:50 - 06:00 1.17 PULD_ DP_ PR1EVL 9/13/2007 06:00 - 06:30 0.50 REPAIR RIG_ PR1 EVL 06:30 - 10:00 3.50 PULD_ DP PR1EVL 10:00 - 15:30 5.50 TRIP_ _ DP_ PR1EVL 15:30 - 16:00 0.50 REAM OH PR1EVL 16:00 - 18:00 2.00 CIRC MUD PR1EVL 18:00 - 01:00 7.00 TRIP DP PR1 EVL 01:00 - 01:30 0.50 SERVIC RIG_ PR1 EVL 01:30 - 06:00 4.50 LOG OH PR1 EVL 9/14/2007 06:00 - 11:30 5.50 TRIP DP PRIEVL 11:30 - 13:00 1.50 RURD ELEC PR1EVL 13:00 - 19:30 ~ 6.50 ~ TRIP_ ~ TOOL ~ PR1 EVL 19:30 - 20:00 0.50 CIRC_ MUD_ PR1 EVL 20:00 - 21:00 1.00 LOG OH PR1 EVL 21:00 - 23:00 2.00 TRIP TOOL PR1 EVL 23:00 - 23:30 0.50 CIRC_ MUD_ PR1 EVL 23:30 - 03:00 3.50 TRIP_ TOOL PR1 EVL 03:00 - 04:00 1.00 TRIP TOOL PR1 EVL Page 19 of 20 ~ Spud Date: 7/30/2007 Start: 7/27/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations rubber from a Lovejoy coupling). But unable to go further than 1820' pumping at max 5.6bpm.TOH ball pumped away, inspect logging tools. No problems. Support rubber still on top of tools. Place 2 split 1/4" x 4" OD rubber gaskets on top of support then some mesh cloth then another 6" ball. Pumped ok to 2100' but slowing to <10/min at 3.6bpm 480psi. Increase to 4.5bpm and running speed increased to +/-40'/min. Depth 3900' at 0600hrs. Continue RIH with RFT tools. Pump down tools 545psi 154spm. at 7500' tool running speed increased to 150fpm. At 8400' reduce pump rate to 77spm 250psi. Tool running speed increased to 250fpm. Shut pump down at 8600' tool running speed increased to 300fpm with out pumps. at 0830hrs. Continue rih W/ E-line to 10608 wlm /Hit bridge Attempt to work tools through 8:45-10:40 . No progress POH with E-line at low rate due to swabbing Rig down e- line RFT tools and sheaves. R/D top drive wireline guide. install drillpipe guide on top drive. Run /wash 4 1/2 tubing F-10508- 10620' Unable to pass Circulate and wash F-10597-10620' Unable to wash through bridge Pump at 200spm 585psi 250gpm POH W/ 4 1/2 tubing f 10620' and lay down. No damage to any joints. RD Weatherford tools. Service rig. Found loose bolt on driveline. Change out driveline hub on #1 Dennison hydraulic pump. Layout and strap 4" DP. PJSM MU BHA # 39 Start to PU 3000' of 4" DP. Repair elevator Hyd. Latch assy. Continue P/U 4" drillpipe total of 96 jts P/U TIH W/drillpipe F- 3811' Fill pipe at 6700' 9000' and 10500' Wash and ream F- 10,620'- 10'625' C tight Hole. Precautionary Wash and ream F-11970-12069' Circulate and condition Mud .Circ B/U at 197stks 250gpm 698psi Hvy sand and sitlt and coal returned over shakers. PJSM; Monitor Well. pump dry job. Drop 2.125" rabbit w/wire. POOH Up wt=210K Dn wt.=95K rt wt.=125K Tq.=5-6K Serv. rig and equip. PJSM; W/ wireline crew. P/U wireline formation image log, RIH hole. RIH with 4" D.P. Circ. every 2000'. Continue TIH W/ FMI logging tool on drillpipe .Circulate 20min at 6000' and 9000' R/U schlumberger E- line sheaves, and make up crossovers & wire line side entry sub. Adjust sheaves Rih and pump down W/ E-line inside drillpipe to 8970', and latch up to wet connect Latch confirmed Continue rih with e- line and drillpipe f-8970' Circulate every 5 stands. Taking weight at 11945'. Circ, mix and pump dry job. Log 7" production section F- 11940' to 11240' Up wt.=200K Dn wt.=100K RIH w/ logging tools, E-line falling behind drill pipe, when logging out of hole, could not get to pull equal. Circ, mix and pump dry job. Work on line tension, POOH Log from 11941'-9038' RIH from 9038'- 9500' to relog as per MOCGO dept. Printed: 12/21/2007 12:56:26 PM Marathon Ql Company Page 20 of 20 Operations Summary Report. Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL DRILLING Start: 7/27/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 I Phase li Description of Operations Date From - To Hours Code' C x c fe 9/14/2007 04:00 - 05:00 1.00 TRIP_ TOOL PR1 EVL POOH Log from 9500' to 9038' 05:00 - 06:00 1.00 TRIP_ TOOL PR1 EVL POOH to side entry sub and rig down Schlum.Unlatch from wet connect.Pull E-line out of drill pipe. 9/15/2007 06:00 - 07:30 .1.50 RURD_ ELEC PR1 EVL Rig Down Schlumberger wire line side entry sub and sheaves. 07:30 - 09:00 1.50 CIRC_ MUD_ PRIEVL Circ 2x B/U at 8811' 211spm 900psi 265gpm 09:00 - 13:30 4.50 TRIP_ DP_ PR1 EVL Monitor well POH W/ 4" drillpipe 13:30 - 14:00 0.50 RURD_ ELEC PR1EVL Lay down Schlumberger FMI logging tools. Move to completion phase 1400hrs 9-14-2007 Note ;One 2 1/2" x 3" pad missing from caliper arm on Schlumberger FMI tool Printed: 12/21/2007 12:56:26 PM Marathon Oil Company Page ~ of 3 Operations Summary Report Legal Well Common W Event Name Contractor Rig Name: Date I Name: G ell Name: G : O Name: G G From - To RASSI RASSI RIGINA LACIE LACIE Hours ~ M OSKO M OSKO L COM R DRILL R DRILL Code LKOF LKOF PLETI ING ING Code F 6 F 6 ON .Phase 9/15/2007 14:00 - 14:15 0.25 RUNPU WBSH PRICSG 14:15 - 18:00 3.75 TEST BOPE PR1 CSG 18:00 - 18:30 0.50 TEST_ BOPE PR1CSG 18:30 - 23:00 4.50 TRIP_ DP_ PR1CSG 23:00 - 00:00 1.00 SLPCUT DLIN PR1CSG 00:00 - 02:30 2.50 TRIP_ DP_ PR1 CSG 02:30 - 05:00 2.50 CIRC MUD_ PRICSG 05:00 - 05:30 0.50 CIRC i MUD_ PR1CSG 05:30 - 06:00 0.50 TRIP_ DP_ PRICSG 9/16/2007 06:00-13:30 7.50 TRIP DP PRICSG 13:30 - 15:30 2.00 RURD_ CSG_ PR1CSG 15:30 - 20:30 5.00 RUN CSG_ PR1CSG 20:30 - 22:00 1.50 RURD_ CSG_ PR1 CSG 22:00 - 22:30 0.50 CIRC_ MUD_ PR1CSG 22:30 - 04:30 6.00 RUN CSG PR1CSG 04:30 - 05:00 0.50 CIRC_ MUD_ PRICSG 05:00 - 05:30 0.50 RURD_ CSG_ PRICSG 05:30 - 06:00 0.50 RUN CSG PR1 CSG 9/17/2007 06:00 - 10:00 4.00 RUN CSG_ PR1CSG 10:00 - 10:30 0.50 RURD_ CMT_ PR1 CSG 10:30 - 10:45 0.25 SAFETY DRIL PR1CSG 10:45 - 12:20 1.58 CIRC MUD_ PR1CSG 12:20 - 14:25 2.08 PUMP CMT_ PR1CSG Spud Date: 7/30/2007 Start: 8/24/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations Pull wear bushing PJSM; M/U test joint, Set test plug. Test BOPE 250/2500 5min all components passed. Peform accumlator drawdown test. Test Gas, PVT and flow alarms Witness wavied by Jim Regg Aogcc Rig down BOP test tools, pull test plug, set wear ring. PJSM; Make up clean out assy., RIH w/ drill pipe to 9000' PJSM; Hang blocks, slip 33' drilling line, set and test crown-o-matic. PJSM; RIH w/drill pipe f/ 9000' to 12069' Tight spots at 10421' and 11915'. Up wt.=170K Dn. wt.=83K Rt. wt.=120K Tq.=8K Circ. Hole 1 1/2 times hole volume. Mud aired up, cut mud wt. back to 9.4# No fluid losses PJSM; Check flow, slow pump rate, pump dryjob. No fluid losses. PJSM; Trip out of hole from 12069'. Continue POH W 4" drillpipe and clean out assy to 3850' Lay down 96joints from 3850-850'. Continue poh stand back HWDP /jars. PJSM;C/O bails and elevators, Rig up Weatherford casing tongs and Fill up line. Make up shoe and baker lock shoe track. Ck floats. Run 77jts 4 1/2 12.60# L-80 563 hydril casing. to 3217' PJSM;C/O Bails and elavators, Rig down Weatherford, Pick-up liner hanger assy. Circ. liner volume 52 bbls. PJSM; Continue rih 4 1/2 Hydril 563 liner on Drillpipe F 3217'. Stop at 9038, (7" Csg. shoe) circ. liner volume. Circ. at shoe 9038' 200 stks. =500psi PJSM; Pick up and make up cement head and lay down. PJSM; Continue RIH with 4 1/2 Hydril 563 liner on drillpipe. Up wt.=112K Dn. wt.=42K Rt. wt.=85K Tq.=5K 19 RPM Continue Running 4 1/2 L-80 12.6# 563 Hydril Liner to 10275' Circulate 3000stks at 2bbls min 339psi 3bblsmin 384psi and 3.5bbls min 437psi. No Gain loss. Contiune Rih 10275'- 11970' Wash from 11981-12069. at 2bbl min 375psi. Tag bottom no fill. No gains or losses. Ran 4 1/2 liner on drillpipe at 2.5min per stand. Correct hole displacement. No gain or losses. Liner depths later adjusted: liner shoe at12081' liner landing collar at 11995', Top of liner at 8842', Chem. injection nipple at 2395' Rig up Baker Cement Head and lines Hold PJSM, With BJ Baker and crew to review hazards with hi pressure and cementing. Discuss cement procedures Circulate and condition mud at 12069' Pump at 3.2bbls min 485psi. BJ batch mix 107bb1s 10.5ppg Cement Reciprocate pipe while circulating. Up Wt 175k Dn. Wt 68K. No gain/ loss Pump 5bbl H2o Test cement lines to 4500psi. Mix and pump 20 bbls. MCS-43 spacer with red dye Followed by 195.2sx/ 100bb1s pre mixed 10.5ppg cement. Pump from 0-65 bbls at 4bbls per min. 775psi 41 flow ,pump from 65-80bbls at 3bpm 450psi. pump from 80-95bbls 39%.at 2bb1s325psi per min, flow rate decreased to 4% increase pump rate to 2bbls per min f-97-128bb1s. flow rate increased to 15% Pump at 1bbl per min from 128-138bb1s 350/ 400psi Bump plug pressure increased to 675 then bleed down to 400psi. Plug failed. Reciprocate and rotate pipe until last 10bbls. Cement in place at 14:25hrs. 100 Printed: 12/21/2007 12:57:59 PM ' f ' • Marathon Oil Company Page 2 of 3 Operations. Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL COMPLETION Start: 8/24/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Phase Description of Operations Date From - To Hours Code Code 9/17/2007 12:20 - 14:25 2.08 PUMP_ CMT_ PR1CSG returns. 14:25 - 15:00 0.58 RURD_ OTHR PR1CSG Rig down Top drive cement head and lay down. 15:00 - 15:15 0.25 SETREL LNR_ PR1 CSG Liner hanger not released with hydraulics, used left hand safety to release hanger. 15:15 - 16:15 1.00 CIRC_ MUD_ PR1CSG Circ. bottoms up got 20 bbl. spacer back and 5-8 bbls. cement. 16:15 - 21:00 4.75 TRIP DP_ PR1CSG PJSM;Trip out of hole with liner running tool.Up wt.=105K Dn wt.=55K Rt wt.=79K 21:00 - 22:00 1.00 SERVIC RIG_ PR1 CSG Service Rig and Top Drive 22:00 - 01:30 3.50 TRIP_ DP_ PR1TIE PJSM; Make up Polish mill assy. RIH 01:30 - 02:30 1.00 TAG_ PKR_ PR1TIE Tag and polish top of liner hanger @8857' Note change in liner depth to 12074' Note Circulated B/U. Liner depths later adjusted: liner shoe at12081' liner landing collar at 11995', Top of liner at 8842', Chem. injection nipple at 2395' 02:30 - 03:30 1.00 SLPCUT DLIN PR1TIE PJSM;Cut and slip drilling line, cut 146' slip 120' and test C.O.M. 03:30 - 06:00 2.50 TRIP_ DP_ PR1TIE PJSM;POOH with polish mill. to 4300' @ 0600hrs 9/18/2007 06:00 - 08:00 2.00 TRIP_ DP_ PR1TIE Continue Poh w/ Polish mill assy on drillpipe f-4300' Stand back HWDP and lay down polish mill 08:00 - 08:50 0.83 PULD_ PKR_ PR1TIE P/U baker 5" ZXP packer dress out and ck shear pins. Set 1 7/16 ball in top of packer 08:50 - 15:00 6.17 TRIP_ DP_ PR1TIE RIH with ZXP packer on 4" drillpipe. Reduce running speed due to flow back from drillpipe 15:00 - 15:30 0.50 SETREL PKR_ PR1TIE PJSM; Test seals and liner lap to 500 psi f/ 5 min. Test seals and lap to 1500 psi for 30 min. 15:30 - 17:30 2.00 SETREL PKR_ PR1TIE Set liner tie back packer, Top of packer at 8835.63, Set packer with 4,100 psi did not shear ball seat. Release from liner packer tie back.Pick up. Test liner and casing to 1500 psi for 30 min. Good test.Cleaning mud pits and hauling mud to G & I. 17:30 - 20:30 3.00 CIRC_ MUD_ PR1TIE PJSM; Cleaning rig floor prep to lay down drill pipe.Circ. and pump dry job .Setting ball went on seat after pumping 30 bbls.Try to blow ball seat with 4700 psi, 15% over shear pressure twice would not shear.POOH with wet string 20:30 - 06:00 9.50 TRIP_ DP_ PR1TIE POOH F/8835' to 2000' Laying down drillpipe (wet) 9/19/2007 06:00 - 09:40 3.67 PULD_ DP_ PR1TIE Continue POH and lay down drillpipe f-2000' (wet) and lay down zxp packer running tool Note: Complete pit cleaning. Begin Mixing 6 % kcl 09:40 - 11:00 1.33 REPAIR RIG_ PR1TIE Repair Hyd pump 11:00 - 11:30 0.50 RUNPU WBSH PR1TIE Pull wear bushing 11:30 - 14:15 2.75 RURD_ CSG_ PR1TIE R/D Floor C/O bails and elevators. Rig up Weatherford tubing elevators and tongs 14:15 - 02:30 12.25 RUNPU TBG_ PR1TIE PJSM: Make up baker 4 1/2 seal assy. run 158jts 1/2 12.60# Hydril563 L-80 Tubing to 2397' Rig up sheave and install baker chemical injection mandrel and control line continue rih f- 2397'. 02:30 - 04:40 2.17 RUNPU TBG_ PR1TIE Rig up to pump down tubing.Pump 2 BPM Slacked off and verified seals going in seal bore 250 psi. 81eed off press. and slackoff seals in seal bore.Space out and install hanger and landing joint. top of liner packer at 8842.31 04:40 - 06:00 1.33 CIRC_ CFLD PR1TIE Pump 35 bbl H2O and 35bb1 flow vis/ safe clean spacer Displace 4 1/2 X 7" annulas with 6% KCL W/ Conquor 404. 9/20/2007 06:00 - 08:00 2.00 NUND ROPE PR1TIE P/U and M/U tubing hanger and landing joint, Land hanger.Adjust liner depth, deeper.liner shoe at12081' liner landing collar at 11995', Top of liner at 8842', Chem. injection nipple at 2395' 08:00 - 09:00 1.00 RURD_ CSG_ PR1TIE PJSM; R/D Weatherford tongs, elavators, R/D Pollard sheave and control line. Printed: 12/21/2007 12:57:59 PM • Marathon Oil: Company Page 3 of 3 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours. Code Code Phase 9/20/2007 1 09:00- 10:00 1.00 TEST TREE l XMBO 10:00 - 12:00 I 2.001 NUND (TREE IXMBO 12:00 - 16:00 4.00 NUND BOPE XMBO 16:00 - 17:30 1.50 NUND BOPE XMBO 17:30 - 21:00 3.50 NUND TREE XMBO 21:00 - 21:30 0.50 NUND TREE XMBO 21:30 - 06:00 8.50 RURD_ RIG_ RDMO 9/21/2007 ~ 06:00 - 00:00 ~ 18.00 ~ RURD_~ RIG_ ~ RDMO 00:00 - 06:00 ~ 6.00 ~ REPAIR ~ RIG_ ~ RDMO 19/22/2007 ~ 06:00 - 10:00 ~ 4.00 ~ RURD_~ RIG_ ~ MIRU Spud Date: 7/30/2007 Start: 8/24/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations PJSM;Test tubing hanger seals to 5000 psi for 10 min.test annulus to 500 psi for 15 min.lnstall back pressure valve. PJSM; L/D mousehole and put grading over open hole. Slowdown top drive, 2" line, choke manifold, back to pits. PJSM; Nipple down BOP and remove spool, DSA, Pickle #3 pump, PJSM; Load trailers, mud products, clean pits,hanson tank,pickle #1 & 2 pumps. PJSM; Nipple tree, test bonnet, and tree to 5000 psi for 15 min. each. PJSM; Pull two way check and install back pressue valve. PJSM;R/D Top drive, take down torque tube, Get derrick ready to scope down, De-mob service loops, rig down stairs to floor, disconnect choke line to gas buster and flowline. R/D Beaver slide, R/D auto driller ,roll back tarp on carrier, move console in dog house, take down guy wires, pump down water tank, pull pwerfrom both dog house, remove dog house lights, PJSM; Crane work, remove windwalls from rig floor and floor plates, suck out carrier sumps,crane down dog house and choke house, stairs, .PJSM; Scope down derrick and lay mast over, cont. to crane grey iron. Load out pump ,pits, generator house, boiler, pull wires, lower carrier off jack stds. remove trip tank, rig down water lines to camp, load trailers, prep carrier to move off mud boat, load up grey iron, ready light plants, move bridge cranes back into sub base Power steering coupling broke on carrier cannot move off of mud boat.Tie up wings on sub base, Prep camp for move. Finish moving off GO-6 Release rig @10:00 hrs. to BC-16 Printed: 12/21/2007 12:57:59 PM W .. , • Marathon Oil Company Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date from - To Hours Code Sub ~ Phase Codel 10/12/2007 ~ 09:00 - 10:45 ~ 1.75 ~ SAFETY ~ MTG_ ~ PR1 EVL 10:45 - 11:40 0.92 RURD_ ELEC PR1EVL 11:40 - 13:50 2.17 RUNPU ELEC PR1EVL 13:50 - 15:45 1.92 LOG_ CSG_ PR1 EVL 15:45 - 16:40 0.92 RUNPU ELEC PR1EVL 16:40 - 17:30 0,83 RURD_ ELEC PR1 EVL 10/14/2007 08:00 - 08:01 0.02 08:01 - 09:00 0.98 SAFETY MTG PR1 EVL 09:00 - 15:00 I 6.001 RURD I COIL I PR1 EVL 15:00 - 16:00 ~ 1.00 ~ TEST_ ~ BOPE ~ PR1 EVL 16:00 - 17:00 1.00 RURD_ COIL PR1 EVL 10/15/2007 07:00 - 08:00 1.00 SAFETY MTG PR1 EVL Page 1 of 4 ~ Spud Date: 7/30/2007 Start: 9/1/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations Hold safety meeting and issue safe work permit. Discuss Expro JSA and job. Spot and RU eline. RIH CBL tool. Log CBL from PBTD at 11,978' back to 8700'. TOC is at 8,337'. POH. RD eline unit and release unit. BOP test witness waived by Jim Regg 3PM 120ct2007. Hold safety meeting and issue safe work permit. Discuss BJ JSA and safety checklist. Spot and RU coiled tubing unit, N2 unit, tanks, gas buster, choke, and associated equipment Test lines, valves, blind rams, and piupe rams 250 psi low and 4500 psi high. Good test. Secure well and shut down for night Hold safety meeting and issue safe work permit. Discuss BJ JSA and safety checklist. Start all equipment. RU reverse nozzle and stab on well. Shell test to 1500 psi. RIH CT. Cool down N2 and start pumping at min rate in reverse circulation at 1300 CTD. Stop CT at 3620 and reverse out water. N2 rate at 600, P = 1500 psi RIH reversing out water at 10' to 25' per min. N2 rate from 500 to 800 SCF/min, p at 1500 to 1750 psi. Depth = 10,800'. RIH to 11,250' and pump N2 at 1000 scf/min. Water reached surface at p = 2300 psi. RIH to 11,950' and pump N2 at 1000 scf/min. Reached pressure limit of 2600 psi. POH 100' and unload water. RIH to 11,950' and pump N2 at 1000 scf/min. pressure stabilized as N2 entered CT. Reduce N2 to min rate and POH. POH. SD N2 while POH. Close in choke with 1650 psi on well. Bleed CT to 0 psi. 08:00 - 09:30 1.50 RURD_ COIL PR1 EVL 09:30 - 09:35 0.08 TEST_ EOIP PR1 EVL 09:35 - 10:00 0.42 RUNPU COIL PR1EVL 10:00 - 11:40 1.67 JET_ N2_ PR1EVL 11:40 - 19:00 7.33 JET N2 PR1EVL 19:00 - 19:40 0.67 JET_ N2_ PR1 EVL 19:40 - 20:20 0.67 JET_ N2_ PR1 EVL 20:20 - 20:40 0.33 JET N2 PR1 EVL 20:40 - 23:50 3.17 RUNPU COIL PR1EVL 23:50 - 00:15 0.42 RURD COIL PR1EVL 00:15 - 01:00 0.75 RURD_ COIL PR1 EVL Secure well and shut down for night 10/20/2007 08:00 - 09:00 1.00 SAFETY MTG_ CMPPRF Hold safety meeting and issue safe work permit. Discussed job scope and personnel duties. 09:00 - 11:00 2.00 RURD_ ELEC CMPPRF MIRU electric line unit, MU 3.375" perforating gun, 6 SPF, 60 deg phased. WHP= 1450 psig. PU gun and PT lubricator to 3000 psig. good test. 11:00 - 13:00 2.00 PERF_ TBG_ CMPPRF Open well, RIH with gun. Correlate depth to Weatherford Array Induction log dated 09-08-2007 with Expro CBL dated 10-11-07. On depth Perforate from 11,537 - 11568' DIL. No change in surface ~ pressure. Lost 600 Ibs after perforating. POOH with gun. 13:00 - 15:30 2.50 WORK ELEC CMPPRF OOH with gun. All shots fired. note:Perforated Gun did not have water was dry. 15:30 - 17:00 1.50 RURD_ ELEC CMPPRF RD Eline unit. Leave well shut in to monitor WHP and make SIBHP survey on Monday. 10/23/2007 08:00 - 09:00 1.00 SAFETY MTG_ PR1 EVL Sign in. Hold PJSM-discuss Pollard JSA. Obtain Safe Work Permit. Discuss job scope. 09:00 - 10:00 1.00 RURD_ SLIK PR1EVL MIRU equipment. PU lubricator. MU tool string. 1560 psi on tree. 10:00 - 10:30 0.50 TEST_ EOIP PRIEVL PTest lubricator to 2500 psi. Good test. Printed: 12/21/2007 12:58:23 PM J N A Marathon Oil Company Operations Summary Report Page 2 of,4 Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL COMPLETION Start: 9/1/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To I Hours ~ Code S ~b Phase i Description of Operations 10/23/2007 10:30 - 14:55 4.42 RUNPU SLIK PR1 EVL RIH with PT gauges. 14:55 - 15:05 0.17 RUNPU SLIK PR1 EVL Hold station @ 11,552' for 10 min. 15:05 - 17:08 2.05 RUNPU SLIK PR1 EVL POOH @ 120 fpm with 3 minute stations @ 11,200', 10,700', 10,200', 9,300', 8,800', 7,800', 6,800', 5,000', 0'. 17:08 - 17:30 0.37 RURD_ SLIK PR1 EVL OOH. Bleed down lubricator. Verify data on both gauges. 17:30 - 18:00 0.50 RURD_ SLIK PR1EVL Rig down. 18:00 - 18:.15 0.25 RURD_ SLIK PR1 EVL Secure well. Turn well over to production with instructions to flow well. Minimum FTP 1000 psi. Turn in Permit. Sign out and leave location. Lock gate. 11/9/2007 13:30 - 13:45 0.25 SAFETY MTG_ WBPREP Hold PJSM-discuss BJ JSA. Obtain HOT Work Permit. Discuss job scope. 13:45 - 14:30 0.75 RURD_ OTHR WBPREP MIRU equipment. PT hardline. Open well. 1400 psi on tree. 14:30 - 16:00 1.50 PUMP_ N2_ WBPREP Start pumping N2 at 1000 scfm, slowly ramping upto 1,500 scfm. 16:00 - 16:50 0.83 RURD_ OTHR WBPREP WHP= 2,800psi, shut down N2 unit. Close and flag all valves on tree. 16:50 - 17:00 0.17 SECUR WELL WBPREP N2 unit rigged down, well secured. Note: WAM calculations based on the static log indicate 100% N2 from the fluid level to surface. 11/14/2007 08:00 - 09:00 1.00 SAFETY MTG_ PR1EVL Call for a sand truck. Hold PJSM-discuss EXpro JSA. Obtain Safe Work Permit. Discuss job scope. 09:00 - 10:00 1.00 SAFETY MTG_ PR1 EVL Sand location prior to rig up. 10:00 - 11:25 1.42 RURD_ ELEC PR1 EVL MIRU equipment. PU lubricator. MU PT gauge string. 1940 psi on WH. 11:25 - 11:35 0.17 TEST_ EOIP PR1 EVL PTest Lubrcator to 3500 psi. Test good. 11:35 - 14:35 3.00 RUNPU ELEC PR1EVL RIH w/ PT gauges tp determine fluid level. Log to 11,000'. Establish fluid level @ 10,584'. Capacitance probe and pressure gradient in good agreement. 14:35 - 15:40 1.08 RUNPU WELL PR1EVL POOH. 15:40 - 16:15 0.58 RURD_ ELEC PR1 EVL OOH. Lay down small lubrcator and pick up the 5". 16:15 - 16:25 0.17 SAFETY MTG_ PR1 EVL Hold Explosives Safety meeting. Shut down all cell phones and two way radioes on location. Shut down SCADA. Post placards and guard at front entrance to location. Arm setting tool for CIBP. 16:25 - 16:35 0.17 TEST_ EOIP PR1 EVL PTest lubrcator to 3000 psi. Test good. 16:35 - 19:05 2.50 RUNPU ELEC PR1EVL RIH w/ 4-1/2" CIBP. 19:05 - 19:10 0.08 RUNPU ELEC PR1 EVL Run collar locator log. Pull up into position. 19:10 - 19:15 0.08 RUNPU ELEC PR1EVL Set CIBP 11,470' KB. PU and set back down on plug to verify that plug is set. Plug takes weight. Test good. 19:15 - 20:10 0.92 RUNPU ELEC PR1 EVL POOH. 20:10 - 21:00 0.83 RURD_ ELEC PR1EVL OOH. Rig down. 21:00 - 21:30 0.50 RURD_ ELEC PR1 EVL Secure well for the night. Verify PT on tree cap connection. Turn in permit. Sign out and leave locaton. Close and lock gate. 11/16/2007 08:00 - 08:30 0.50 SAFETY MTG_ CMPPRF Arrive on location, obtain work permit and sign in 08:30 - 09:00 0.50 SAFETY MTG_ CMPPRF Hold PJSM with Expro JSA. Sand Truck arrived onsite and sanded whole pad 09:00 - 10:10 1.17 RURD_ ELEC CMPPRF RU E-line unit 10:10 - 10:35 0.42 SAFETY MTG_ CMPPRF Hold explosive safety meeting and inform all pad workers of explosive operations, cellphone and welders are turned off. 10:35 - 10:50 0.25 RUNPU ELEC CMPPRF Arm and PU 24' - 3-3/8" - HSC 6spf -pert gun. 10:50 - 11:05 0.25 TEST. EOIP CMPPRF Pressure test Lubricator to 2500 psig, Test good 11:05 - 12:40 1.58 RUNPU ELEC CMPPRF RIH with 1542 psi on well 12:40 - 12:50 0.17 RUNPU ELEC CMPPRF Pull into position and bleed well down to 1515 psi (SCADA) 1500 psi on Gauges on Wellhead (42 psi bled) 12:50 - 14:00 1.17 PERF_ CSG_ CMPPRF Shoot gun ~ 10102'-10126' (CH) -- 10103'-10127' (OH) (1 foot off depth from coorelation), POOH. Lost a little ammount of weight on the Printed: 12/21/2007 12:58:23 PM .~ • Marathon Oil Company Operations Summary Report Page3of4~ Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL COMPLETION Start: 9/1/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date. From - To Hours i Code C de Phase Description of Operations 11/16/2007 12:50 - 14:00 1.17 PERF_ CSG_ CMPPRF tool string when we perforated. Time: Pressure: 1250 1516psi (read) 1300 1518psi (read) 1315 1590psi (read) 1330 1622psi (estimated) 1345 1655psi (estd) 1400 1688psi (estd) 1415 1721 psi (estd) 1430 1754psi (read) 1450 1784psi (read) 1500 1795psi (read) 1515 1834psi (read) 1545 1874psi (read) 1555 1880psi (read) 14:00 - 16:00 2.00 RURD_ ELEC CMPPRF OOH, Lay down tools, Inside of the Gun body was dry. Shot in dry pipe. Move over to GO#5 16:00 - 16:30 0.50 RURD_ ELEC CMPPRF Sign out and Leave Location 11/21/2007 08:00 - 08:30 0.50 SAFETY MTG_ CMPPRF Arrive on location, obtain work permit and sign in. Hold PJSM with Expro JSA. 08:30 - 09:45 1.25 SAFETY MTG_ CMPPRF MIRU Expro. PU lubricator. MU tool string. PU 29' of 3-3/8" HSC 6 spf, 60 degree phased pert guns. 09:45 - 09:55 0.17 SAFETY MTG_ CMPPRF Hold explosive safety meeting and inform all pad workers of explosive operations, cellphone and welders are turned off. 09:55 - 10:05 0.17 RUNPU ELEC CMPPRF Arm and PU 29' - 3-3/8" -HSC 6spf - perF gun. 10:05 - 10:25 0.33 TEST_ EQIP CMPPRF Pressure test Lubricator to 2500 psig. Test good. 10:25 - 10:55 0.50 RUNPU ELEC CMPPRF RIH withwell flowing @ 770 psi. 10:55 - 11:35 0.67 CMPPRF Shut in well. 11:35 - 11:40 0.08 RUNPU ELEC CMPPRF Pull into position. Holding 1100 psi on WH. 11:40 - 11:45 0.08 PERF_ CSG_ CMPPRF Shoot un 9480'-9509' CH -- 9482'-9511' OH (2 foot off depth from coorelation), Lost a little ammount of weight on the tool string when we perforated. POOH. 11:45 - 12:15 0.50 PERF_ CSG_ CMPPRF Well flowing 960 mscf/d @ 1100 psi. 12:15 - 12:35 0.33 PERF_ CSG_ CMPPRF Well flowing 1073 mscf/d @ 1100 psi. 12:35 - 12:45 0.17 RURD_ ELEC CMPPRF OOH, Lay down tools, Inside of the Gun body was dry. Shot in dry pipe. 12:45 - 13:30 0.75 RURD ELEC CMPPRF 13:30 - 13:45 0.25 RURD_ ELEC 11/22/2007 08:00 - 08:30 0.50 SAFETY MTG 08:30 - 08:40 08:40 - 08:55 08:55 - 09:05 09:05 - 09:20 09:20 - 10:10 10:10 - 10:25 10:25 - 10:28 0.17 SAFETY MTG 0.25 SAFETY MTG 0.17 RUNPU ELEC 0.25 TEST_ EQIP 0.83 RUNPU ELEC 0.25 RUNPU ELEC 0.05 RUNPU ELEC Stand back lubricator and tools. Will load another 25' of guns to shoot in the morning. CMPPRF Sign out and Leave Location CMPPRF Arrive on location, obtain work permit and sign in. Hold PJSM with Expro JSA. CMPPRF MIRU Expro. PU lubricator. MU tool string. PU 25' of 3-3/8" HSC 6 spf, 60 degree phased pert guns. CMPPRF Hold explosive safety meeting and inform all pad workers of explosive operations, cellphone and welders are turned off. CMPPRF Arm and PU 25' - 3-3/8" -HSC 6spf - perf gun. CMPPRF PU and install (lubricator. Pressure test Lubricator to 2500 psig. Test good. CMPPRF RIH with well flowing @ 1000 psi. CMPPRF Shut well in to let it build to 1100 psi. CMPPRF Run correlation strip across ZXP Packer Printed: 12/21/2007 12:58:23 PM ... ~ • Marathon Oil Company Page 4 of 4 Operations Summary Report Legal Well Name: GRASSIM OSKOLKOFF 6 Common Well Name: GRASSIM OSKOLKOFF 6 Spud Date: 7/30/2007 Event Name: ORIGINAL COMPLETION Start: 9/1/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 i Date 'From - To Hours Code Phase Description of Operations .Code 11/22/2007 10:28 - 10:29 0.02 RUNPU ELEC CMPPRF Pull into position @ 9450.5'(CCL depth). Holding 1100 psi on WH. 10:29 - 10:45 0.27 PERF_ CSG_ CMPPRF Perforate (a)_ 9455'-9480' (CH) -- 9457-9482' (OH) (2 foot off depth from correlation), Lost weight on the tool string when we perforated. Sticky pulling off depth. POOH. 10:45 - 11:15 0.50 PERF_ CSG_ CMPPRF Well flowing 870 mscf/d @ 1100 psi. 11:15 - 12:00 0.75 RURD_ ELEC CMPPRF OOH, Lay down tools, Inside of the Gun body was wet. 12:00 - 12:15 0.25 RURD ELEC CMPPRF Sign out and Leave Location. Move to NS-3. Printed: 12/21/2007 12:58:23 PM Maunder, Thomas E (DOA) From: Ibele, Lyndon [Icibele@marathonoil.com] Sent: Monday, December 17, 2007 11:37 AM To: Maunder, Thomas E (DOA) Subject: Sundry status • Page 1 of 1 Tom-- FYI, just wanted to let you know that we have had an on-going, company-wide IT problem that may affect our ability to file sundry notices timely for a few wells. The data-base system that is used to generate all of our downhole activity reports crashed on December 8th, and all the king's horses and all the king's men haven't been able to put Humpty-Dumpty back together yet and we have been given no timeline for completion. We know we are close to the 30 day deadlines for submitting Form 404 for recent work performed on Wells G03 and G05, and the_ 407 for GQ6. However, should the afore-mentioned database not be functional in the next few days, we will be unable to retrieve operations summaries that are required with the sundries, and it is likely these sundry reports could be tardy. I will keep you posted if that looks likely to occur. ---~ a-O~ -O`~ RE Forms 10-421, there are several pending. However, we have not yet achieved stable production rates and have been unable to perform multi-point tests on Sterling Unit wells 41-15rd and 43-9x. Those tests will be performed and submitted as soon as possible. For Wells NS-3 and GO-6, we have single-point tests only to report, because the wells are producing at maximum capacity but at very low rate. The only means to achieve multiple flow points would require that the wells be choked-back, but doing so would cause them to be produced below the unloading rate. This would not only be meaningless from amulti-point test perspective, but would also jeopardize killing the wells. We will submit a cover letter with this explanation when we submit the form 10-421 for these two wells. ~~ ~~~~® ~~ 4/9/2009 ?'~ ~ 11'~#1'1011 MARATHON ~ ~ ~~~ 1' 0111p111 November 27, 2007 Alaska Asset Team United States Production Organization P.O. Box 3128 Houston, TX 77253 Telephone 713-296-3398 Fax 713-499-6720 Alaska Oil & Gas Conservation Commission FedEx Attn: Howard Okland 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon Grassim OskolkoffNo. 6 (GO-6); API# 50-133-20571-00 CONFIDENTIAL Dear Mr. Okland: The following confidential digital well data are enclosed for the above referenced well. GO-6 As-Built Plat .................................................................................................................. digital Operations Report ..........................................................................................................digital Directional Survey ......................................................................................................... digital EPOCH Mud Log Data .................................................................................................. digital Weatherford Well Log Data ...........................................................................................digital One CD containing digital well logs and above data (see attached CD contents)..........digital Please indicate your receipt of this data by signing below and returning one copy to my attention at the above address or fax to 713-499-6720. Thank you, Deborah A. Svatek-Logue r - Advanced Administrative Assistant ~_-' (,~~ ~ ~ p ~- -s~a' Received by: __ ~ '~ ~ a Date: : 1, j .~a~%89nB~J9s.3 d~'. Enclosures • GO-6 API 50-133-20571-00 CD CONTENTS Confidential GO-6 CD Director Mudlogs Wireline Daka "AGO #6As•Bu~t Plat NAD 27 API# 50-133-20571-00.OO.pdf '",~ GO 6AOGCC Rig Operakions API# 50.133-20571.OD-DO.... t~ J GO6 dir_survey_API# 50-133-20571-00-OO.dat Mudlo s: DML DATA ;~ FIMAL KNELL REPORT LAS FILE SLOG PDF FILES ~MORNIIVG REPORTS i~ REMARKS FILE Wireline Data I DP LAS I~ PLO T S ®SEELOG.exe File Folder 11127!2007 9:52 AM File Folder 11127!2007 9:54 AM 248 KB Adobe Acrobat 7.0 ... 6!1120071:46 PM 97 KB Adobe Acrobat 7.0 ... 1 1 11 312007 9:46 AM 4 KB DAT File 101112ao71 a:27 AM File Folder 111271200710:06 AM File Folder 1112r 1200710:06 AM File Folder 111271200710:07 AM File Folder 111271200710:07 AM File Folder 111271200710:1 ~ AM File Folder 11 !271200710:14 AM File Folder 11 l27~200710:14 AM File Folder 11 X271200710:15 AM File Folder 111271200710:16 AM 909 KB Applicakion 1015120x6 4: SO AM GO 6 possible sidetrack Page 1 of ~~ Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, August 27, 2007 10:55 AM To: 'Bergs, Pe#e' Cc: 'Stephen F Davies'; 'Arthur C Saltmarsh' Subject: RE: GO 6 (207-096) possible sidetrack Thanks for the information. Don't you just hate those "incidental issues"? Course reel problems are not unusual, especially with recreational fishing. What are the thoughts on what grabbed the casing? It appears that "something" has a good hold on you. Best regards for continued success. Tom From: Bergs, Pete [mailto:pkberga@marathonoil.com] Sent: Monday, August 27, 2007 10:33 AM To: Maunder, Thomas E (DOA) Subject: RE: GO 6 (207-096) possible sidetrack We have recovered pipe to 3806'. Lost the better part of a day when we put a kink in our drill (ine and had to replace. Still looking good to get it all. From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sant: Monday, August 27, 2007 10:00 AM To: Maunder, Thomas E {DOA); Bergs, Pete Cc: Stephen F Davies; Arthur C Saltmarsh Subject: RE: GO 6 (207-096) possible sidetrack Hi Pete, I presume since I did not hear from you over the weekend that you fishing operations were successful or continuing. Could you please provide an update? Thanks in advance, Tom Maunder, PE AOGCC Fro sunder, Thomas E {DOA) Sant: Fri ugust 24, 2007 9:57 AM To: 'Bergs, Pete Cc: 'Stephen F Davies' Subject: RE: GO 6 (207-096) le sidetrack Good news on continued recovery. So long a covery continues will understand that plugging may be necessary. We hdi oncern r application and note that mud logging was planned for rmediatE of that interval sent to us for examination? I u and there w b~ fish to plug below. If Marathon can pr what information is availab due diligence for an possible ing. Thanks in advance, Tom Maun su-et~mpt to get all the fish? I ~e long OH interval. I looked at the permit interval. Is it possible to have the mud log challenges if you had to drill through the !~r.Q,m the penetration, then we can do our 8/27/2007 GO 6 possible sidetrack . • Page 1 of 2 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, August 24, 2007 9:57 AM To: 'Berga, Pete' Cc: 'Stephen F Davies' Subject: RE: GO 6 (207-096) possible sidetrack Good news on continued recovery. So long as recovery continues will you attempt to get all the fish? I understand that plugging may be necessary. We have concerns over the long OH interval. I looked at the permit application and note that mud logging was planned for the intermediate interval. Is it possible to have the mud log of that interval sent to us for examination? t understand there would be challenges if you had to drill through the fish to plug below. If Marathon can provide what information is available from the penetration, then we can do our due diligence for an possible plugging. Thanks in advance, Tom Maunder, PE AOGCC From: Berga, Pete [maiito:pkberga@marathonoil.com] Sent: Friday, August 24, 2007 9:40 AM To: Maunder, Thomas E (DOA) Subject: RE: GO 6 (207-096) possible sidetrack We have recovered pipe to 3512' and made some more cuts. Still have 400' to get out. I am leaving the office at 10:30 to go home. I'm getting my water well pulled today. How are things looking if we have to pump cmt this weekend? From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, August 24, 2007 9:28 AM To: Berga, Pete Subjects RE: GO 6 (207-096) possible sidetrack How goes the fishing? From: Bergs, Pete [mailto:pkberga@marathonoil.com] Sent: Thursday, August 23, 2007 12:25 PM To: Maunder, Thomas E (DOA) Subject: RE: GO 6 (207-096) possible sidetrack We did not log this interval. From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, August 23, 2007 11:26 AM To: Bergs, Pete Subject: RE: GO 6 (207-096) possible sidetrack What do you think you chances are of getting it all? That is a pretty long OH section to loose. Do you have OH logs that could be examined to confirm no pay in the interval? 8/24/2007 GO 6 possible sidetrack ~ ~ Page 2 of 2 From: Bergs, Pete [mailto:pkberga@marathonoil.com] Sent: Thursday, August 23, 2007 10:36 AM To: Maunder, Thomas E (DOA) Subject: RE: GO 6 (207-096) possible sidetrack We drilled to 9058' md/4449' tvd. The 9 518" shoe is at 2998' md. Top of fish(today) is 3400' and and the bottom of fish is at 3928' md. We have been pulling 50' at a time. Our pay is in the next section.. The production interval will be from 9058' to 12090' md. If we have to sidetrack my intention would be to spot a 15.8 ppg or heavier plug from the top of the fish back up into the 9 5/8" casing. Give it 24 hrs. Dress it off and see how hard it is and then low side it(we are at 69 deg. at the shoe) and turn left or right depending on what our geologist says. We would only get far enough away from the original hole so that we don't have any interference from it. From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, August 23, 2007 9:40 AM To: Bergs, Pete Subject: RE: GO 6 (207-096) possible sidetrack Bummer, not quite the fishing I think you'd like to be doing. Can you lay out a plan that I can share with the Commissioners? Some questions/considerations ... How deep is the hole and the shoe? Have you opened any pay zones? Do you plan to or will you need to drill out the shoe to spot cement in the open hole below? Look forward to your reply. Tom Maunder, PE AOGCC From: Bergs, Pete [mailto:pkberga@marathonoil.com] Sent: Thursday, August 23, 2007 9:29 AM To: Maunder, Thomas E (DOA) Subject: GO 6 possible sidetrack Tom-We are presently fishing stuck intermediate casing. Things are going okay. As you know things can tum bad quickly on a fishing job. !f we have to sidetrack it would be just around the fish and back to the original depth and within 100-200 feet of the old wellbore. Far enough to get away from magnetic interference. With the weekend approaching 1 just wanted to know if a verbal(email) to/from the AOGCC is acceptable with follow up paperwork on the next work day. Let me know. Thanks. 8/24/2007 • t ~ 0 ~ ~ ~ SARAH PALIN, GOVERNOR ~T`~1 ~a7~ Q~ ~D ~~ 333 W. 7th AVENUE, SUITE 100 CO1~T5ER~~/~~i` C~~~IIS+SIO~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Willard Tank Advanced Senior Drilling Engineer Marathon Oil Company 3201 C. Street, Suite 800 Anchorage, AK 99503 Re: Ninilchik Unit, Tyonek Gas Pool, Ninilchik Unit -Grassim Oskolkoff #6 Marathon Oil Company Permit No: 207-096 Surface Location: 2975' FSL, 2,988' FEL, SEC. 23, T1N, R13W, S.M. Bottomhole Location: 413' FSL, 4,813' FEL, SEC. 15, T1N, R13W, S.M. Dear Mr. Tank: Enclosed is the approved application for permit to drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Marathon Oil Company assumes the liability of any protest to the spacing exception that may occur. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). DATED this day of July, 2007 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. • M Marathon MARATHON Oil Company July 12, 2007 P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 ~~~~~~~~ John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Ninilchik Well: Ninilchik Unit - Grassim Oskolkoff #6 Dear Mr. Norman Jl.l~ 1 ~ 2~~J? Alaska Oi! ~ has [a~n~, ~~r~missoli Anch~rag~ Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a Tyonek development well. Please note that the surface coordinates for this well and the directional plan are now utilizing North American Datum 1983 (NAD 83) as required in the latest BLM 43 CFR Part 3160, Onshore Order No. 1, dated March 7, 2007. Getting well and surface equipment coordinates on this GPS based standard (NAD 83) has been an effort that Marathon has been working on and will continue to progress. The state plane coordinates for the surface location on the PERMIT TO DRILL have been converted back to NAD 27 for your database usage. If you require further information, I can be reached at 713-296-3273 or by a-mail at wjtank@marathonoil.com. Sincerelly, ~ Willard J. Tank Advanced Senior Drilling Engineer Worldwide Drilling North America Enclosures STATE OF ALASKA ~_~~ ALA OIL AND GAS CONSERVATION COMION ,Y~ PERMIT TO DRILL ''~ `~~~ ~n aar ~5 nn~ 1 a. Type of Work: Drill Q Redrill ^ Re-entry ^ 1 b. Current Well Class: Exploratory ^ Stratigraphic Test ^ Service ^ Multiple Zone ^ Development Oil ^ Development Gas Q Single Zone ~ 1 c. Specify if well is p d Coalbed Methane ^ C~$$a1~ ^ Shale Gas ^ 2. Operator Name: Marathon Oil Company 5. Bond: Blanket ~ Single Well ^ Bond No. 5194234 11. Well Name and Number: Ninilchik Unit - Grassim Oskoikoff #6 3. Address: 3201 C. Street, Suite 800, Anchorage, AK 99503 6. Proposed Depth: MD: 12,090 TVD: 7,437 12. Field/Pool(s): Ninilchik Unit 4a. Location of Well (Governmental Section): Surface: 2,975' FSL, 2,988' FEL, Sec. 23, T1 N, R13W, S.M. 7. Property Designation: ADL 389737 Tyonek Pool Top of Productive Horizon: 169' FSL, 4,177' FEL, Sec. 15, T1 N, R13W, S.M. 8. Land Use Permit: 13. Approximate Spud Date: Jul 27, 2007 Total Depth: 413' FSL, 4,813' FEL, Sec. 15, T1 N, R13W, S.M. 9. Acres in Property: 3,095.55 14. Distance to Nearest Property: 177 ft (ADL 384305) 4b. Location of Well (State Base Plane Coordinates): NAD 27 Surface: x - 229,026.517 y - 2,254,940.730 Zone - 4 10. KB Elevation (Height above GL): (21' AGL) 187 feet 15. Distance to Nearest Well Within Pool: 2,276 ft to GO #2 16. Deviated wells: Kickoff depth: 200 feet Maximum Hole Angle: 69.146 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 3,481 Surface: 1,846 18. Casing Program: Specifications To p -Setting Depth -Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 K-55 PE 77' 0' 0' 77' 77' 12 1/4" 9 5/8" 40 L-80 BTC 2,979' 0' 0' 3,000' 1,775' 698 sacks 8 3/4" 7 5!8" 29.7 L-80 Hydril 513 9,031' 0' 0' 9,052' 4,437' 289 sacks lead, 126 sacks tail 6 314" 4 1/2" 12.6 L-80 Hydril 563 3,240' 8,850' 4,261' 12,090' 7,437' 192 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry O perations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ^~ BOP Sketch Q Drilling Program Q Time v. Depth Plot ^ Shallow Hazard Analysis ^ Property Plat Q Diverter Sketch Q Seabed Report ^ Drilling Fluid Program ~ 20 AAC 25.050 requirements ^ 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct. Printed Name Willard J. Tank Signature Date Contact Title Advanced Senior Drilling Engineer Phone 713-296-3273 Date July 12, 2007 Commission Use Only Permit to Drill Number: 0 0~Q API Number: 50-,•~-aQS'~~-O1J.QQ Permit Approval Date: r See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce Coalbed methane, ga hydrates, or gas contained in shales: [~ Other: Samples req'd: Yes^ No~ Mud log req'd: Yes^ No~ *~Sp-~O~S` ~,`r\,~v~ ~o'°~ ~~~ HZS measures: Yes^ NoQ~ Directional svy req'd: Yes No^ ~/~ /' ~ APPROVED BY THE COMMISSION DATE: 6 0 ,COMMISSIONER ~"~:~~~~ .IUL 1 3 2007 .~ Form 10-401 Revised 12/2005 ` ~ ~ ~ ~ ~ ~~ ~ v `~ ubmit in Duplicate V ~ ~~J Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit MARATHON MARATHON OIL COMPANY DRILLING PROGRAM Grassim Os ko I koff #6 Originator: Will Tank ivV Reviewed by: _Pete Berga July 12, 2007 Date Date Brian Roy Date 7/12/2007 CONFIDENTIAL MATERIAL Page 1 of 18 Grassim Oskolkoff #6 ~ Drilling Program ~ Marathon Oil Company Northern Business Unit TABLE OF CONTENTS 1. Emergency Response Information ...................................................... ............................................................ 4 1.1 Directions to Location .......................................................................... ............................................................ 4 1.2 Rig Contact Numbers .......................................................................... ............................................................ 4 1.3 Marathon Emergency Response Contacts ......................................... ............................................................ 4 1.4 Outside Emergency Response ........................................................... ............................................................ 4 1.5 Marathon Contact List ......................................................................... ............................................................ 5 2. Regulatory Agency Contacts .............................................................. ............................................................ 5 2.1.1. Internal Regulatory Contact ................................................................ ............................................................ 5 2.1.2. External Regulatory Contact ............................................................... ............................................................ 5 3. Regulatory Compliance ....................................................................... ............................................................ 5 4. Drilling Program Summary .................................................................. ............................................................ 6 4.1 General Well Data ............................................................................... ............................................................ 6 4.2 Working Interest Owners Information ................................................. ............................................................ 6 4.3 Geologic Program Summary ............................................................... ............................................................ 6 4.4 Summary of Potential Drilling Hazards ............................................... ............................................................ 7 4.5 Formation Evaluation Summary .......................................................... ............................................................ 7 4.6 Drilling Program Summary .................................................................. ............................................................ 8 4.7 Casing Program Summary .................................................................. .......................................................... 10 4.8 Casing Design ..................................................................................... .......................................................... 10 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) . .......................................................... 10 4.10 Casing Test Pressure Calculations ..................................................... .......................................................... 12 4.11 Blowout Prevention Equipment, Testing and General Procedures ..... .......................................................... 12 4.11.1. Function Testing .................................................................................. .......................................................... 12 4.11.2. Pressure Testing ................................................................................. .......................................................... 13 4.12 Wellhead Equipment Summary ......................................................... .......................................................... 13 4.13 Directional Program Summary ............................................................ .......................................................... 13 4.14 Directional Surveying Summary .......................................................... .......................................................... 14 4.15 Drilling Fluid Program Summary ......................................................... .......................................................... 15 4.16 Drilling Fluid Specifications ................................................................. .......................................................... 15 4.17 Solids Control Equipment .................................................................... .......................................................... 16 4.18 Cement Program Summary ................................................................ .......................................................... 17 4.19 Bit Summary ........................................................................................ .......................................................... 17 4.20 Hydraulics Summary ........................................................................... .......................................................... 18 4.21 Formation Integrity Test Procedure .................................................... .......................................................... 18 7/12/2007 CONFIDENTIAL MATERIAL Page 2 of 78 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit Attachments Grou Attachment Attached Commercial Information AFE Da s/Cost vs. De th Curves X Pro'ect Ob'ectives and Scorecard RSO Codin Information X Re uisitions Vendor List Bonus Pro ram Drillin Contract Re ulato / HES Information Emer enc Evacuation Plan X H2S Conlin enc Plan n/a Re ulato Permits X Re ulato Rules and Re ulations Risk Anal sis Miscellaneous Pro rams Vendors Bit Pro osal X Cement Pro osal X Directional Plan X Fluids Pro ram X Wellhead E ui ment - Descri lion/Drawin s Drill Strin and BHA Summa Ri Mobilization/Moorin Procedure n/a Geolo ical Information Location Ma w/ offsets X Offset Data Pro osed Formation Pore Pressure, Mud Wt & Fracture Gradient X Tem erature Curves Geolo is Structure Ma s Geolo is Cross Section Bath met Ma n/a Anal sis Riser Anal sis n/a Station Kee in Anal sis -Moorin /DP n/a Stress Check Casin Desi n File X Maximum Allowable Over ull Miscellaneous Information Wellbore Dia ram n/a Ri Elevations X Well Location Dia ram X BOP Schematic X BOP Well Control Brid in Document Detailed Casin S ecifications X Detailed Drill Pi e S ecifications 7/12/2007 CONFIDENTIAL MATERIAL Page 3 of 18 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit 1. Emergencv Response Information 1.1 Directions to Location Method Directions Air Latitude - 60°09'48.512"N Longitude - 151 °29'23.738"W (NAD 83) From the Kenai airport, go 0.5 mile South on Willow Street. Turn East on Main Street Loop, go 0.3 miles. Continue East on Ground Bridge Access Road 3.2 miles. Turn West on Kalifornsky Beach Road. Go West and then South, go 16.9 miles. Turn South on Sterling Highway, go 14.4 miles. Turn West onto road to the pad (Sterling Highway milepost 124.1). 1.2 Rig Contact Numbers Contact Office Cell Glacier Drilling Rig 1 Inlet Drilling Tool Pusher 907-283-1314 907-394-1321 Marathon Supervisor 907-283-1312 907-394-1317 1.3 Marathon Emergencv Response Contacts Individual Postion Main Phone Alternative Kenai Gas Field Emergency Number 907-283-6465 CERT 24 hrs Notification 1-800-MOC-CERT CERT Crisis Center Houston 713-296-4230 713-296-4237 1.4 Outside Emergencv Response Location Contact Phone Fire Kenai /Soldotna, Alaska 907-262-4792 Ambulance Hospital Kenai /Soldotna, Alaska Central Peninsula Hospital 907-262-4404 Police Kenai /Soldotna, Alaska Kenai Police Soldotna Police State Police 907-283-7879 907-262-4455 907-262-4453 Coast Guard 800-478-5555 Spill and Contamination Alaska Alaska State Spill Reporting National Response Center Oil /Toxic Chemical Spills 800-424-8802 Best Practices: 1 Policy: Post emergency notification information on rig floor, company man's and tool pushers' office Comments: 7/12/2007 CONFIDENTIAL MATERIAL Page 4 of 18 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit 1.5 Marathon Contact List Contact Title Office Mobile Facsimile Home WiIlTank Drilling Engineer 713-296-3273 713-203-8398 713-499-6737 832-934-2617 Pete Berga Drilling Superintendent 907-565-3032 907-529-0551 907-565-3076 907-346-3763 Bryan Roy Drilling Manager 713-296-3256 832-444-4772 713-499-6707 281-246-4686 Scott Szalkowski Geologist 713-296-3390 713-301-9834 Clyde Scott Reservoir Engineer 713-296-2336 Completion Engineer Ken Walsh Production Engineer 907-283-1311 907-394-3060 907-283-3050 John Nicholson Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Dan Byrd Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Mike Feketi Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Rowland Lawson Drilling Supervisor 907-283-1312 907-394-0953 907-283-1313 2. Regulatory Agency Contacts 2.1.1. Internal Reaulatorv Contact Contact Title Office Phone Cell Phone Home Phone Facsimile Chick Underwood Re ulato Com liance 713-296-3254 979-830-7927 979-836-9390 713-499-6748 2.1.2. External Reaulatorv Contact Contact Title Office Phone Facsimile 24 hr Emer enc Pa er AOGCC 907-793-1236 3. Repulatory Compliance Regulation Requirement 20 AAC 25.035 a 10 A BOP testing interval requirement is now 14 days. 20 AAC 25.035 a 10 F Requirement fora 24 hour notice to AOGCC prior to BOP test. Comments 7/12/2007 CONFIDENTIAL MATERIAL Page 5 of 18 Grassim Oskolkoff #6 Drilling Program Marathon Oil Company Northern Business Unit 4. Drilling Program Summary 4.1 General Well Data Well Name Grassim Oskolkoff #6 Lease /License Surface Location 2,975' FSL, 2,988' FEL, Sec. 23, T1 N, R13W, S.M. WBS Code DD.07.15534.CAP.DRL Slot/Pad Grassim Oskolkoff Pad Field Ninilchik Unit Spud Date 07/27/07 (est.) KB (above MSL) 187' County/Province Kenai Peninsula API No. GL (above MSL) 166' State /Country Alaska Permit No. Perm. Datum KB Total MD 12,090' Well Class Development Water Depth N/A Total TVD 7,437 Rig Contractor Glacier Drilling Water Protection Depth Rig Name Glacier Rig 1 Best Practices: Comments: 4.2 Working Interest Owners Information Com an Workin Interest Address Phone Facsimile Marathon 60% P.O.Box196168 907-561-5311 907-565-3076 Anchors e, AK 99519-6168 Chevron -Texaco 40% 4.3 Geologic Program Summary Surface Location Coordinates - NAD 83 From LeaselBlock Lines 2,975' FSL, 2,988' FEL, Sec. 23, T1 N, R13W, S.M. Latitude 60° 09' 48.512"N Longitude 151 ° 29' 23.738" W UTM North (~ 2,254,701.994' UTM East (x) 1,369,044.337' Tolerance Pore Pore MD -RKB TVD -RKB Pressure Pressure Possible Formation (ft) (ft) (psi) (ppg) Lithology Fluid Content Tyonek (Primary Target) 7,626 3,437 3.80 - 9.00 Sandstone Gas 7/12/2007 CONFIDENTIAL MATERIAL Page 6 of 18 Grassim Oskotkoff #6 Drilling Program • Marathon Oil Company Northern Business Unit Depth (KB) Horizontal Displacement (ft) Target MD (ft) TVD (ft) Location +N/-S (Y) +E/-W (X) Tolerance (ft) Tyonek T-2 Coal 8,307 3,837 169' FSL, 4,177' FEL, Sec. 15, T1 N, R13W, S.M. 2,474 -6,469 Circle 500' radius Tyonek T-3 Coal 10,120 5,467 413' FSL, 4,813' FEL, Sec. 15, T1 N, R13W, S.M. 2,718 -7,105 Circle 250' radius TD 12,090 7,437 413' FSL, 4,813' FEL, Sec. 15, T1 N, R13W, S.M. 2,718 -7,105 Circle 250' radius 4.4 Summary of Potential Drilling Hazards Depth KB Hazard Event Discussion Precautions (ND) Bit or BHA balling Surface Hole Maintain high pump rates to keep bit and BHA clean. Use extra circulation time if necessary. Excessive Torque Intermediate & Production Use good hole cleaning techniques with high pump Excessive pumping on bottom could Hole rates. Add lubricant where necessary. result in hole washout. 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 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 +/- 8,307' MD (3,837' TVD) to total depth of the well. These sands will run from slightly depleted to slightly above normal pressure. The Flo-Pro mud system that will be properly weighted to hydraulically control all sands and lost circulation materials will be available on location, if required. Best Practices: 1 Comments: 4.5 Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surface None None None 0' - 3,000' MD Intermediate None None Basic with GCA, shale density, temperature in and 3,000' - 9,052' MD out, sample collection (10' samples). Production None Reeves Quad Combo on drill pipe shuttle, ' ' Basic with GCA, shale density, temperature in and 9,052 - 12,090 MD MFT through 4 1/2" csg. Pull GR-Neutron out, sample collection (10' samples). to tie into Intermediate run. Completion N/A GR, CCL, CBL N/A Comments: 7/12/2007 CONFIDENTIAL MATERIAL Page 7 of 18 Grassim Oskotkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit 4.6 Drilling Program Summary Drive Pipe: N/A Conductor: 20" set to approximately 100', prior to drilling rig move. MIRU drilling rig. NU diverter. 1. RU conductor rig. Drill/Drive 20" conductor to +/-100 ft. RKB. RD conductor rig. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SLC 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. Best Practices: 1 Comments: Surface: Drill 12-1/4" hole to +/- 3,000' set 9-5/8" casing. 1. Drill a 12 1/4" hole to 3,000' MD (1,775' TVD) per the directional plan. 2. Run and cement 9 5/8" casing. 3. Cut off 9 5/8" casing. ND diverter. ~~©~ 4. Install 9 5/8" slip lock connection X 11" 5M flanged multibowl wellhead. 5. NU 11" 5M X 13 5/8" adapter spool. NU 13 5/8" 5M BOP'S. Test BOP's and choke manifold to 250/2~psi. [ 6. Set wear bushing. Test surface casing to 2,000 psi. '1~~ Best Practices: 1 During cementing operations, take returns in the cellar, instead of into the pits. Eliminates the clean up of pits from cement that circulated to surface. Vac trucks will pull from cellar. Comments: Intermediate: Drill 8-3/4" hole to +/- 9,052' set 7 5/8" casing. 1. PU 8 3/4" PDC bit and directional BHA. Drill out float equipment and 20' of new formation. CBU. 2. Test shoe to leak off. Estimated EMW is 18.5 ppg. 3. Drill 8 3/4" directional hole to 9,052' MD (4,437' TVD) as per directional program, short tripping as required. 4. At TD circulate hole clean. Make wiper trip. TOOH. Pull wear bushing. ~$O~ 5. Change out pipe rams with 7 5/8" casing rams in single ram. Run test plug and test casing rams to psi. 6. Run and cement 7 5/8" casing. Land hanger in multibowl wellhead. ~~ 7. Back out landing joint. Change out 7 5/8" casing rams with pipe rams. Run test plug and test BOP's to 250/~psi. 8. Set wear bushing. Test intermediate casing to 2,000 psi. Best Practices: 1 Pre-heat mud mix water to help in early shaker screen blinding issues with the mud. Comments: Production Liner: Drill 6 3/4" hole to +/- 12,090' set 4-1/2" liner. Tie back to surface with 4-1/2" tubing. 1. PU 6 3/4" bit and directional BHA. Drill float equipment and 20' of new formation. CBU. 2. Test shoe to leak off. Estimated EMW 16.5 ppg. 3. Drill a 6 3/4" hole to an anticipated TD of 12,090' MD (7,437' TVD) as per the directional program, short tripping as required. 4. At TD circulate hole clean. Make wiper trip. TOOH. 7/12/2007 CONFIDENTIAL MATERIAL Page 8 of 18 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit 5. RU logging company for shuttle system. Run quad combo open hole logs as per plan on drill pipe shuttle. TOOH and lay down shuttle equipment and 3 1/2" drill pipe. 6. PU and TIH with 4 1/2" Hydril 563 casing to the first setting depth for the MFT log. RU and run MFT pressure points through 4 1/2" Hydril 563 casing. After completing the MFT log run, POOH with logging tool. TOOH with 4 1/2" Hydril 563 casing, laying it down. RD logging company. 7. TIH w/ 6 3/4" tri-cone bit to TD for wiper trip. TOOH and laydown BHA and drill pipe. Pull wear bushing. 8. RU and run 4 1/2" Hydril 563 casing liner with hanger on drill pipe. Run liner to TD with top of liner at approximately 8,850' MD. On bottom reciprocate and rotate liner while circulating the hole. 9. RU cementing company. Cement 4 1/2" while reciprocating and rotating pipe. Drop wiper plug and bump plug to pressure up and set the liner hanger. Release hanger running tool, pick up and clear seal area of any cement. Pick up out of liner. 10. Circulate hole clean. If cement circulates, TOOH. If cement doesn't circulate, WOC, then prepare and pump liner top job. 11. Once cement is either circulated or the liner top is squeezed, PU mill for 4 1/2" along with string mill for 7 5/8" casing. Make cleanout trip to top of 4 1/2" liner with mill combo on drill pipe. Polish 4 1/2" liner seal bore. 12. Run 4 1/2" liner hanger packer with hydraulic pusher tool. Stab into polish bore receptacle and set packer. TOOH laying down drill pipe. 13. Run 4 1/2" Hydril 563 casing with seal unit. Displace hole with 6 %KCL. Space out tubing and land hanger. ND BOP, NU tree and test to 5,000 psi. 14. Rig down and move out drilling rig. Best Practices: 1 Make up torque shown for the Hydril 563 is 80% of yield. The final make up torque for the liner should exceed any potential torque that would be used to release the running tool from the hanger. Comments: Completion: Completion will be done without a rig. The completion will encompass work to run a cement bond log, displace the KCL water in the wellbore with nitrogen, perforate several Tyonek intervals, and test the well for rate and pressure. No stimulation of the perforating intervals is anticipated. Best Practices: 1 Comments: 7/12/2007 CONFIDENTIAL MATERIAL Page 9 of 18 Grassim Oskolkoff #6 Drilling Program 4.7 Casing Program Summary • • Marathon Oil Company Northern Business Unit MD (tt) Connection A PI Ratings Casing Makeup Hole ~ .•. n = o y Size Weight ID Drift O. D. Torque Size m' a U °. ~ ~' (in) Top Bottom (Ibs/ft) (in) (in) Grade Type (in) (tt-Ibs) (in) 9 5/8 0 3,000 40 8.835 8.679 L-80 BTC 10.625 N/A * 12 1/4 5,750 3,090 979 7 5/8 0 9,052 29.7 6.872 6.750 L-80 Hydril 513 7.625 10,800 8 3/4 6,890 4,790 487 4 1/2 8,850 12,090 12.6 3.958 3.833 L-80 Hydril 563 5.200 10,080 6 3/4 8,430 7,500 288 Best Practices: 1 Have float equipment made up at Tubescope's yard prior to bringing casing to location. Buck on all equipment to the pin end and not make up to box below, due to rig height restrictions. 2 Make up torque shown for the Hydril 563 is 80% of yield. The final make up torque for the liner should exceed any potential torque that would be used to release the running tool from the hanger. * -Make up buttress connection to proper mark, not to a torque value. Comments: Make up torque for 7 5/8" Hydril 513 casing is the target torque from Hydril. 4.8 Casing Design Casing Shoe Safety Factors Setting Maximum Casing Depth Mud Wt Frac. Form Surface a o Size Weight TVD When Set Grad Press Pressure ~ ~ c (in) (Ib/ff) Grade (tt) (Ib/gal) (Ib/gal) (Ib/gal) (psi) m' U H 95/8 40 L-80 1,775 9.4 18.5 8.5 1,032 2.21 3.56 3.35 75/8 29.7 L-80 4,437 9.6 16.5 8.7 1,846 2.05 2.17 1.75 41/2 12.6 L-80 7,437 9.6 16.5 9.0 1,846 1.10 2.02 2.12 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) Setting Casing Depth Size TVD MAWP * MASP ** Mud/Gas (in) (ft) (psi) (psi) Percentage 9 5/8 1,775 3,923 1,032 30/70 7 5/8 4,437 4,777 1,846 30/70 4 1/2 7,437 4,777 1,846 30/70 * MAWP =Maximum allowable working pressure ** MASP =Maximum anticipated surface pressure The calculation method for MASPaHP has been modified from the standard AOGCC use of a Bottom Hole Pressure - 0.1 psi/ft gas gradient to what Marathon considers a more accurate Bottom Hole Pressure - 30% Mud Column - 70% Gas Column. This method follows the MMS standard for any well with a TVD of 12,000' or less. Marathon believes that constant gas monitoring and proper rig supervisor well control training will prevent the possibility of a wellbore being completely evacuated with only a gas gradient remaining. 7/12/2007 CONFIDENTIAL. MATERIAL Page 10 of 18 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit Surface casing 9 5/8" (3.000' MD. 1.775' TVD) MASPrrac _ ((Fracture gradient at shoe) x .052 x TVDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPrrac = (18.5 ppg x .052 x 1,775') - (0.1 psi/ft x 1,775') MASPrrac = 1,708 psl - 178 psi MASPrrac = 1,530 psi. MASPbnp = BHPopen Hole rd -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnp = (8.7 ppg x .052 x 4,437')) - (0.3 x 9.6 ppg x .052 x 4,437') - (0.7 x 0.1 psi/ft x 4,437') MASPbnp = 2,007 psi - 664 psi - 311 psi MASPbnp = 1,032 psi MASP =MASPbnp = 1,032 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x ND MAWP = (0.7 x 5,750) - (9.4 - 8.3) x .052 x 1,775' MAWP = 4,025 psi -102 psi = 3,923 psi Intermediate casing: 7 5/8" (9,052' MD. 4.437' TVD) MASPrrao =((Fracture gradient at shoe) x .052 x TVDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPrrac = (16.5 ppg x .052 x 4,437') - (0.1 psi/ft x 4,437') MASPrrac = 3,807 psl - 444 psl MASPrrac = 3,363 psi. MASPbnp = BHPopen Hole rd -Hydrostatic pressure of a gas column MASPbnp = (9.0 ppg x .052 x 7,437') - (0.3 x 9.6 ppg x .052 x 7,437') - (0.7 x 0.1 psi/ft x 7,437') MASPbnp = 3,481 psi -1,114 psi - 521 psi MASPbnp = 1,846 psi MASP =MASPbnp = 1,846 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 6,890) - (9.6 - 9.4) x .052 x 4,437' MAWP = 4,823 psi - 46 psi = 4,777 psi Production liner: 4 1/2" (Top - 8.850' MD. 4.261' TVD) (Bottom - 12.090' MD. 7.437' TVD) MASP = MASP sie° = 1,846 psi MAWP = MAWP sis° = 4,777 psi Best Practices: 1 Comments: 7!12/2007 CONFIDENTIAL MATERIAL Page 11 of 18 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit 4.10 Casing Test Pressure Calculations Casing test pressures calculations are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. Best Practices: a ~~~ ~~©Q~. Comments: ~ ~ ©~ ~~~ ~~~~~ 4.11 Blowout Prevention E ui ment Testin and General Procedures ~ ~~ N N BOP PROGR AM Casing Test Test Casing Test Fluid Pressure Size MAWP MASP Press Density BOPS Low/High Casing (in) (psi) (psi) (psi) (Ib/gal) Size & Rating (psi) (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Surface 9 5/8 3,923 1,032 2,000 9.4 (1) 13 5/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M pipe ram (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Intermediate 7 5/8 4,777 1,846 2,000 9.6 (1) 13 5/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M pipe ram (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Production 4 1/2 4,777 1,846 2,000 9.6 (1) 13 5/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M pipe ram Blowout Preventers 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, a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets, and a 13-5/8" x 5000 psi single pipe ram. 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 avacuum-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. 4.11.1. Function Testino Function Regularly. 7/12/2007 CONFIDENTIAL MATERIAL Page 12 of 18 Grassim Oskolkoff #6 • • Marathon Oil Company Drilling Program Northern Business Unit 4.11.2. Pressure Testing The Marathon Drilling Supervisor will verify all pressure tests of BOP's, surface lines, seals, casings and FIT or LOT tests. All tests are to be recorded on the IADC and daily drilling reports. Best Practices: 1 Comments: 4.12 Wellhead Eauipment Summary Component Description Casing Hanger Type Casing Head 11" 3M X 9-5/8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, PR1 10 314" x 7 5/8" Fluted Mandrel Tubing Head 11" 3M Studded Bottom X 11" 5M Flg Top, W/ 2, 2-1/16" 5M Studded Outlets, U,AA,PSL1,PR1 11" x 4 1/2" Manual Slip Adapter Flange 11" 5M X 4-1/16" 5M W/Seal Pocket and 3" H BPV Threads Best Practices: 1 Comments: Use a drilling spacer spool on the 9-5/8" casing head to allow for a B-Section contingency. 4.13 Directional Program Summary Build Turn Coordinates Sec. No. Description MD (ft) TVD (ft) Rate (°1100') Rate (°/100') Dogleg (°/100') Inclination (deg) Azimuth (deg) +N/-S (ff) +E/-W (ft) VS (ft) 1 Tie On 0 0 0 0 0 0 290.931 0 0 0 2 KOP 200.00 200.00 0 0 0 0 290.931 0 0 0 3 Build up Section 5.00 0 5.00 290.931 4 End of Build 1,582.92 1,270.85 5.00 0 5.00 69.146 290.931 263.63 -689.29 737.98 5 Hold Section 0 0 0 69.146 290.931 6 End of Hold 7,354.08 3,325.30 0 0 0 69.146 290.931 2,190.24 -5,726.52 6,131.08 7 Drop Section -2.50 0 2.50 290.931 8 End of Drop 10,119.92 5,467.00 -2.50 0 2.50 0.00 290.931 2,717.51 -7,105.09 7,607.05 9 TD 12,089.92 7,437.00 0 0 0 0.00 290.931 2,717.51 -7,105.09 7,607.05 7/12/2007 CONFIDENTIAL MATERIAL Page 13 of 18 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit Comments: Vertical section calculated from a reference azimuth of 290.93° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (ft) Depth (MDR Grassim Oskolkoff #1 405.71 Surface Grassim Oskolkoff #2 412.74 763 Grassim Oskolkoff #3 125.38 1,155 Grassim Oskolkoff #4 219.36 Surface Grassim Oskolkoff #5 108.41 Surface SoCal Falls Creek 1388.84 1,330 Texaco Ninilchik #1 506.24 Surface No serious interference exists. See attached directional plan and anticollision analysis for more details. Best Practices: 1 Comments: 4.14 Directional Surveving Summary Interval MD (ft) MWD Survey Magnetic Multishot Gyro Multishot Other Survey Tool Remarks Surface 0 - 3,000' X Intermediate 3,000' - 9,052' X Production 9,052' - 12,090' X 7/12/2007 CONFIDENTIAL MATERIAL Page 14 of 18 Grassim Oskolkoff #6 Drilling Program Best Practices: 1 Comments: • • 4.15 Drillino Fluid Program Summary Marathon Oil Company Northern Business Unit Interval - TVD Minimum Inventory From To Density Gel (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite Gel, Gelex, Soda Ash, Caustic, Barite, Polypac 0 1,775 8.8 - 9.4 Gel / Gelex Spud Mud Supreme UL, Sodium Meta Bisulfate Flo-Vis, Polypac UL, KCI, SafeCarb 10 8~ 40, 1,775 4,437 9.2 - 9.7 6% Flo-Pro w/ Safecarb Asphasol Supreme, Lubetex, Caustic, Conqor 404, Sodium Meta Bisulfate, Klagard Flo-Vis, DualFlo, KCI, Greencide 25G, SafeCarb 4,437 7,437 9.4 -10.3 6% Flo-Pro w/ Safecarb 10, Asphasol Supreme, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate, Lubetex Best Practices: 1 Comments: 4.16 Drilling Fluid Saecifications Interval - TVD LSRV Drill From (ft) To (ft) Density (Ib/gal) Vis (sec/gt) 1 min (Ib./100ft2) PV (cP) YP (Ib/100 ft2) Fluid Loss (cc) pH Solids (%) 0 1,775 8.8-9.4 50-75 N/A 25-35 NC-10/12 +/-9.5 <7 1,775 4,437 9.2 - 9.7 20 - 30,000 8 - 12 7 - 9 +(- 9.5 +/- 7.5 4,437 7,437 9.4 - 10.3 20 - 30,000 10 - 14 5 - 7 +/- 9.5 +/- 5 Best Practices: 1 As a standard practice for tie-back string completions, displace the drilling mud above top of liner with brine treated with corrosion inhibitor (Conqor 303A) at a concentration of 1 drum per 100 barrels of fluid. Comments: See mud prognosis for details. Sized CaCOa (SafeCarb) will be used to control leakoff. 7/12/2007 CONFIDENTIAL MATERIAL Page 15 of 18 Grassim Oskolkoff #6 • Drilling Program 4.17 Solids Control Eauipment Marathon Oil Company Northern Business Unit c o ~ d z ~ ;?' v ` m ~ o m - ~ y Y ~ y U .~ ~~ rn c a> c p .mac aNi ayi ~ N > > `N InteNal U U 0 ~ U U U N Comments 0 - 12,090' MD X X X X Closed Loop System, Full Containment, Run shakers with finest screens possible Item Equipment Specifications (quantity, design type, brand, model, flow capacity, etc) Shaker 2 - Swaco Mongoose PT Desander N/A Desilter 1 -Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MI/Swaco units Cuttings Dryer N/A Cuttings Injection Marathon G&I Facility Zero Discharge N/A Best Practices: 1 Have vacuum trucks pull fluids from trough above slop pit to more efficiently pull fluids for disposal. This minimizes water added to the solids to suspend for pickup by the trucks, thus minimizing total volume to be disposed of. Comments: 7/12/2007 CONFIDENTIAL MATERIAL Page 16 of 18 Grassim Oskolkoff #6 Drilling Program 4.18 Cement Program Summary Marathon Oil Company Northern Business Unit De pth Gauge Top of Cement Gauge Ann Vol Slurry Casing Size (in) MD (ff) TVD (ff) Hole Size (in) MD (ff) TVD (ff) Ann Vol To TOC (ff3) With OH Excess (ff3) Density Lead/Tail (PPg) Open Hole Excess (%) Thickening Time (hrs) 20 77 77 Driven N/A 95/8 3,000 1,775 121/4 0 0 1,024 1,710 12.0 75 8 7 5/8 9,052 4,437 8 3/4 2,900 1,740 618 861 12.5 / 15.8 40 8 4 1/2 12,090 7,437 6 3/4 8,850 4,261 449 575 10.5 30 N/A Mix Water Compressive Casing Size Density Qty Yield Slurry Vol TOC MD Qty WL FW Strength (psi) (in) Slurry Cement Description (Iblgaq (sx) (ft3/sx) (ft3) (ft) (gal/sx) Type (cc) (%) 8 hr 24 hr 9 5/8 Tail Type I Cement 12.0 698 2.45 1,710 0 10.20 Fresh 547 0 183 675 Lead Class"G" 12.5 289 2.47 713 2,900 13.78 Fresh 559 0 92 645 7 5/8 Tail Class "G" 15.8 126 1.17 148 8,000 4.99 Fresh 40 0 428 3,437 4 1/2 Tail Class "G" 10.5 192 2.99 575 8,850 12.36 Fresh 20 0 50 1,755 Best Practices: 1 Pump several fluid calipers at TD to help with the hole volume determination from the open hole caliper log. Comments: See cement prognosis for details and spacer specifications. 4.19 Bit Summary Interval - MD Type Recommended Estimated From (ft) To (ff) Size (in) Manufacturer Model No. IADC WOB (kips) RPM Rotating Hours Expected Minimum ROP (ft/hr) 0 3,000 12 1/4 Christensen MXL-1 117 20 - 50 80 - 300 3,000 9,052 8 3/4 Christensen HCM605 M323 Up to 25 Motor 9,052 12,090 6 3/4 Christensen HCM505Z M233 Up to 17 Motor Best Practices: 1 Comments: See bit prognosis for additional information. Back up bits for the 8 3/4" hole section will consist of PDC and mill tooth bits. Back up bits for the 6 3/4" hole section will consist of 6 3/4" mill tooth and TCI tricone bits. 7/12/2007 CONFIDENTIAL MATERIAL Page 17 of 18 Grassim Oskolkoff #6 Drilling Program • • Marathon Oil Company Northern Business Unit 4.20 Hydraulics Summary Qty Make Model Liner ID (in) Stroke (in) Max Press @ 90% WP (psi) Displacement @ 95% Vol. eff (gal/stroke) Max Rate @ 95% Vol. eff (spm/gpm) Hole Sections Used On 5 8 2,597 2.04 125 / 255 Surface 3 National Oil Well A600PT 5 8 2,597 2.04 125 / 255 Intermediate 5 8 2,597 2.04 125 / 255 Production Est. Hole Pump Standpipe Openhole Nozzle OP at Depth-MD Size Rate Pressure Min AV MW ECD Size bit (ft) (in) (gpm) (psi) (fpm). (ppg) (ppg) (32"s) si Remarks (Drill string configuration) 0 - 3,000 12 1/4 625 2,334 122 9.2 3 - 18's MI Virtual Hydraulics @ 3,000' MD 1-16 3,000 - 9,052 8 3/4 547 2,300 260 9.4 5 - 15's Actual Data from NS #3 (@ 7,243' MD) 9,052 - 12,090 6 3/4 269 1,904 223 9.4 6 - 11's MI Virtual Hydraulics @ 12,090' MD Best Practices: 1 Comments: See mud program (Virtual Hydraulics) for additional information. 4.21 Formation Integrity Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test 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 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. Best Practices: 1 Comments: 7/12/2007 CONFIDENTIAL MATERIAL Page 18 of 18 Marathon Oil Well Grassim Oskolkoff #6 Diverter 21 1/4" 2M Diverter ~ Knife Valve Diverter Spool Marathon Oil Well Grassim Oskolkoff #6 BOP Stack 13 5/8" 5M Cross 11" 5M x 13 5/8" 5M DSA • Marathon Oil Well Grassim Oskolkoff #6 Choke Manifold To Gas Buster x 1 2 9/16" 10M Swaco Hydraulically Operated Choke ~ ~~~ ~ x ~~~~ ~ ~ 3" 5M Valves To Blooey Line x °°~ 00 • Bleed off Line to Shakers x ~ ooog ~ x ~ x x ~~~ ~~ x J I I I~X~ x I 3 1/8" 5M Manually Adjustable Choke Gauge Block Choke Hose to HCR (BOP Stack) • • Surface Use Plan for Ninilchik Unit -Grassim Oskolkoff #6 Surface location: 2,975' FSL, 2,988' FEL, Sec. 23, T1 N, R13W, S.M. 1) Existing Roads The Sterling Highway will be used for access to the Grassim Oskolkoff #6 well and is shown on the attached map. Ninilchik, Alaska is the nearest town to the site. 2) Access Roads to be Constructed or Reconstructed No new roads will be required to access Grassim Oskolkoff #6. 3) Location of existing wells Well Grassim Oskolkoff #6 will be drilled on Grassim Oskolkoff pad. A pad drawing is enclosed that shows existing wells and the proposed location of Grassim Oskolkoff #6. 4) Location of existing and/or proposed facilities The locations of existing production facilities on the Grassim Oskolkoff pad are shown on the enclosed pad drawing. A flowline will be installed from the Grassim Oskolkoff #6 wellhead to an existing heater and separator. 5) Location of Water Supply A water supply well exists on the pad that Grassim Oskolkoff #6 will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. 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 hauled to Pad 34-31 of the Kenai Gas field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). 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. Town & Country will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface Grassim Oskolkoff #6 will be drilled from an existing pad. Reclamation of the pad, if required by the landowner, will occur after the abandonment of Grassim Oskolkoff #6 and the other existing wells on the pad. 10) Surface ownership Marion Oskolkoff is the surface owner of the land at the Grassim Oskolkoff pad. Operator Certification Field: Ninilchik Well: Ninilchik Unit - Grassim Oskolkoff #6 Surface Location: 2,975' FSL, 2,988' FEL, Sec. 23, T1 N, R13W, S.M. I hereby certify that I, or someone under my direct supervision, have inspected the drill site and access route proposed herein; that I am familiar with the conditions which currently exist; that I have full knowledge of state and Federal laws applicable to this operation; that the statements made in this APD package are, to the best of my knowledge, true and correct; and that the work associated with the operations proposed herein will be performed inconformity with this APD package and the terms and conditions under which it is approved. I also certify that I, or the company I represent, am responsible for the operations conducted under this application. These statements are subject to the provisions of 18 U.S.C. 1001 for the filing of false statements. Executed this 12'h day of July , 20 07 ~~ Name Willard J. Tank Position Title Advanced Senior Drilling Engineer Address P.O. Box 3128. Houston. TX 77253-3128 Telephone 713-296-3273 Field Representative Pete Berga (Drilling Superintendent) (if not above signature) Address 3201 C Street. Suite 800, Anchorage. Alaska 99503 (if different from above) Telephone 907-565-3032 (if different from above) E-mail wjtank _marathonoil.com (optional) ~.. ~~ 0 ~~ }~ ~~ ~e NORTH ~ j SCALE 0 100 200 FEET ~j V~ / RM1 PAT 19]9 ELEV.=162.00 ~ ~~ GO NO. 1 WELL ~G ELEV. = 165.28' FB'~a ~ N 2255066.3516 48~ o E 1369222.7745 PQ (`P a ~~ O RM2 PAT 19]9 ELEV. =18282' W! ~~~ ~/ ,A` o~ V GO NO. 6 WELL AS-BUILT LOCATION ASP ZONE 4 NAD83 GRID N:2254701.994 GRID E:1369044.337 LATITUDE: 60°09'48.512"N LONGITUDE: 151 °29'23.738"W FEL = 2988' FSL = 2975' ELEV= 166.12' (NGVD29) SECTION 23 I TOWNSHIP 1 N RANGE 13W, SM AK 1. BASIS OF ELEVATIONS IS NGS MONUMENTS 82 PID TT0583 AT MILE POST 124.2 OF THE STERLING HIGHWAY. THE ELEVATION OF S82 IS 237.12 FEET (NGVD 29). BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2003 DETERMINED BY AN NGS OPUS SOLUTION FROM CORS BASE STATIONS "TLKA PID AH2494", "ZAN1 PID DE9153"AND "GNAA PID AH2492" OBSERVED JUNE 5, 2007 ON MCI S82 ECC 2"ALUM. CAP SET AJACENT TO BM S82 N: 2252517.780 E: 1368533.525 ELEV. 240.08 . 2) SOUTHEAST CORNER COORDINATES DETERMINED FROM RECORD TIES (HM HM79E8 & HM75-14) TO EXISTING BLM SECTION CORNER OF RECORD NOT PROTRACTED SECTION CORNER VALUES. 0 GO NO. 2 WELL GO NO. 3 WELL ELEV. = 165.5' ELEV. = 166.1' N 2255043.82 6 N 2254946.8888 E 136929,1.110 G~~ E 1369122.8005 / ~2 ® ~ER WELI® B.S s 8.5 WELLHWSE ~+ EXPLORATION PAO ~~/ PRODUCTION GO N0.4 WELL Q BUILDING ELEV. = 166.5' N 2254891.1690 °~a E 1369155.3660 PRODUCTION PAD w/ EXISTING STRUCTURES eg , ® GO N0.5 WELL ~ °' , I POND ELEV. = 166.40' APB ® E N 2254810.3810 ° N DGNTROL ENNA BUILDING / E 1369046.3200 /~'"j~\ 1mREeAR ELEV. =150.51' /~ ~ '~ i ~ I / / 2988' FEL WASTE EXfAVATION F / STORAGE BERM Z w z J Z o __~ ~ ~ ~_ roE of BERM _ MARION OSKOLKOFF T1 N R13W S23 HM PORTION SE1/4 NW1/4 E1/2 SW1/4 NW1/4 n SW1/4 NW1/4 SE1/4 NORTH OF N STERLING HWY. m N I EXISTING FENCE N 2251649.8081 ' ` - ~ • ~O~ PROJECT M AIL COMPANY GO WELL N0.6 ARATNON ~ ~~ AS-BUILT SURFACE LOCATION DIAGRAM ENGINEERING /MAPPING /SURVEYING /TESTING CmisuLHn9 RC P.O. BOX 488 SOLOOTNA AK. 99669 LOCATION VOICE: (907)2834218 FAX: (907)2833285 S23 T1N R13W SEWARD MERIDIAN, ALASKA EMAIL: SAMCLANE~MCLANECG.COM 430 \ zs zs REVISION: -2 DATE: 6-8-07 DRAWN BY: MSM SCALE: ,"=100' PROJECT NO. 073045 BOOK NO. 06-21 SHEET OF 1 Marathon Oil Company Project: Grassim Oskolkoff #6 Project Location SE 1/4, NW 1/4, Sec 23, TIN, R13W ! A _~„'-..~ ~~ . t s ~~. ~ n~.s¢ ~t~ . ,~ .t'~, 1 ~ ~ .+ 'r / L'1~ by~ca f' : ; _r' i f ~ y~ ~ _ ~ -.. ' ~ ~.Jd L,_ ., .a t~ n ~ ~ .. :. JJ}} w ~ ~ 4. 1 ~ - ~ - - y;__. . t. 1 '~ :7 ~ ,- R~,. ~ __ -s, ;a .- era, 'r _ , _ f =~ - a_~ .- '_.- ~ :_ - ., ~ 6rwF n ~ - -- i .' , -~ } i ~- - _,b. ~ / - -vim _ - ~ '-K( ~^i'_~_ _. __ .. ~L /~ `+ Y~.r - -Vii-'+~ ` `-~l . _y°L'. ~' ~ c13C2 1 - i 37, "- ~~~z~`32 -- :33^ ~ /-" ,l ~~._ ~--- -T- t ~~;,,`~ . ~~, ~•--, aUSfrS • • • • GO#6 TD 12,090'MD 1 ~ (7437' TVD) Got cos ~' ~ ~ `- 3L G04 .,, ,,,. ,~ . G02 1~~~ 1 2 ~ ~- 2 ~--- ~~- NS3 ~ ~ NS1 ~-_ f_ Ns2 -~~ 3 3 ~ ~ ~°'~ ~ {' Ninilchik Unit ~, , r~' ~~ '.~ ~ ~ . ~- .~ GO#6 Location ~ ~,~~ ~~r~w.r~ June 2007 GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT MARATHON x m • • MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: MGO #6 Field: Ninilchik Field (NAD83) Well: MGO #6 Facilily: MGO Wellbore: MGO #6 r BAKlR ~~~~~~ INTEQ Plot reference wellpath is MGO #6 Version #4 True vertical depths are referenced to Glacier #1 (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4 (5004), US feet Measured depths are referenced to Glacier #1 (RKB) North Reference: True north Glacier #1 (RKB) to Mean Sea Level: 187 feet Scale: True distance Mean Sea Level to Mud line (Facility - MGO): 0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by: michwilg on 7/9/2007 Targets Name MD (ft) TVD (R) Local N (ft) Local E (ft) Grid East (LISR) Grid North (USR) Lalilude Longdutle MGO x6 Tyonek T2 COal-mad: 12-Jun-O7 3837.00 271752 -7105.09 1362002.48 2257579.03 60°1a 15255"N 751°37'44.787"YV MGO #6 Tyonek T3 COal-Rvsd: 12JUn-07 5467.00 2717.52 -7705.09 7362002.48 2257579.03 80°'10'18255"N 751°31'44.181'w MGO #6 TD-Rrsd: l2JUn-07 7437.00 2717.51 -7705.09 7362002.48 2257579.03 60°10'15.255"N 751°31'44.181'w Well Profile Data Design Comment MD (R) Inc (°) Az (°) TVD (R) Local N (ft) Local E (R) DLS (°/1008) VS (ft) Surtace RKB: 187' 0.00 0.000 290.931 0.00 0.00 0.00 0.00 0.00 KOP 200.00 0.000 290.931 200.00 0.00 0.00 0.00 0.00 End Angie Build 1582.92 69.146 290.931 1270.85 263.63 -689.29 5.00 737.98 Begin Angie Drop 7354.08 69.146 290.931 3325.30 2190.24 -5726.52 0.00 6131.08 End Angie Drop 10119.92 0.000 178.708 5467.00 2717.51 -7105.09 2.50 7607.05 TD 12089.92 0.000 178.708 7437.00 2717.51 -7105.09 0.00 7607.05 Surtace RKB: 187' :0.00° Inc, O.OOR MD, O.OOR TVD, O.OOR VS KOP :0.00° Inc, 200.008 MD, 200.008 TVD, O.OOR VS OOft Angle Build :69.15° Inc, 1582.92ft MD, 1270.SSft TVD, 737.98ft VS 9000 L O. m 0 3750 2' IU N ` 4500 H 9.625in Casing Surtace :69.15° Inc, 3000.OOft MD, 1775.31ft TVD, 2062.23ft VS Begin Angle Drop :69.15° Inc, 7354.OBft MD, 3325.308 TVD, 6131.Oeft VS MGO #6 Tyonek T2 Coal -Rvsd: 12-Jun-07 7.625in Casing Intermediate :26.71 ° Inc, 9051.668 MD, 4437.OOft TVD, 7362.568 End Angle Drop :0.00° Inc, 10119.92ft MD, 5467.008 TVD, 7607.058 VS MGO #6 Tyonek T3 Coal -Rvsd: 12-Jun-07 7500 8250 4.5in Casing Production :0.00° Inc, 12089.92ft MD, 7437.OOft TVD, 7607.058 VS TD :0.00° Inc, 12089.928 MD, 7437.008 TVD, 7607.OSft VS MGO #6 TD -Rvsd: 12-Jun-07 ;7 OOft Vertical Section (tt) Azimuth 290.93° with reference 0.00 N, 0.00 E from wellhead '~ MARATHON c ~~op R m G~ ~yQ o'° ~..C ti MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: MGO #6 Field: Ninilchik Field (NAD83) Well: MGO #6 Facili MGO Wellbore: MGO #6 Plot reference wellpath is MGO #6 Version #4 True vertical depths are referenced to Glacier #1 (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4 (5004), US Teet Measured depths are referenced to Glacier #1 (RKB) North Reference: True north Glacier #1 (RKB) to Mean Sea Level: 187 feet Scale: True distance Mean Sea Level to Mutl tine (Facility - MGO): O feet Depths are in feet Coortlinates are in feet referenced to Slot Created by: michwilg on 7/9/2007 Fasting (ft) -4800 -4400 -4000 -3600 3200 sa R ~ NY6MlS INTEQ -2000 -1600 -~00 -800 -400 0 Well Profile Data Design Comment MD (ft) Inc (°) Az (°) ND (ft) Local N (ft) Local E (ft) DLS (°/100ft) VS (ft) Surtace RKB: 187' 0.00 0.000 290.931 0.00 0.00 0.00 0.00 0.00 KOP 200.00 0.000 290.937 200.00 0.00 0.00 0.00 0.00 Entl Angle Build 1582.92 69.146 290.937 1270.85 263.63 -689.29 5.00 737.98 ssoo ~0 2600 2400 j Z 2000 O S 7 16~ 1200 Y 400 ~0 MGO #6 • • Planned Well ath Re ort ~~~ p p BAKER MGO #6 Version #4 MYQrMEs MARATHON Page 1 of 5 INTEQ .. ~ ~ Operator MARATHON Oil Company ',Slot ~GO #6 __. Area Cook Inlet, Alaska (Kenai Penninsula) _ Well iMGO #6 Field iNinilchik Field AD83 ~ Wellbore ~MGO #6 ?_~_~__ Facility .MGO _ __ _ ___ s _~.~. __ _ _ _ _ ____,_~_____._.__~ Projection System INAD83 / TM Alaska State Plane, Zone 4 (5004), US feet Software System ~We1lArchitectT"' 1.2 North Reference True ;User ~Michwilg Scale .0.999984 Report Generated '07/09/07 at 13:57:05 Wellbore last revisedj06/12/07 {Database/Source tile;WA Anchorage/MGO #6.xml '~ 1 ~ ~ ~ Local coordinates ~ ~ Grid coordinates ~ Geographic coordinates _ North ~feet~ i East [feet] ~ ___ Easting [US feet Northing SUS feet Latitude [°] ~ Longitude [°] Slot Location 2986.28 ~ -2990 52 1369044.34 2254701.99 60 09 48.512N 151 29 23.738W Facility Reference Pt ~ 1371967.44 2251649.81 r 60 09 19.1O5N 151 28 24.639W - -- _._ Field Reference Pt ____. _. _._____ r .-__-- t ~ € __ _ -_______ __ ____-. 1371967.44 2251649.81 __ _ ~__ __ _ _ _ ._-- - 60 09 19.1O5N 151 28 24.639 W Calculation method jMinimum curvature Glacier #1 (RKB) to Facility Vertical Datum 187.00 feet Horizontal Reference Pt Slot Glacier #1 (RKB) to Mean Sea Level 87.00 feet Vertical Reference Pt !Glacier #1 (RKB) Facility Vertical Datum to Mud Line (Facility ) X0.00 feet MD Reference Pt ____ ---.__ GGlacier #1 (RKB) _ ___ __ _._.- Section Origin __ _ _..___._ __ _._,m_ .. _._ ____. ~N 0.00,E 0.00 ft ._-- ._-~ -------_._______ Field Vertical Reference ;Mean Sea Level SSection Azimuth 1290.93° • • M MARAi110N Planned Wellpath Report MGO #6 Version #4 Page 2 of 5 ~~. BAKER NudNEs INTEQ ELLPATH DATA 125 statio~ v ~ ~_~_.______ ~ ( ns) ~' interpolated/extrapolated'statlon s ___....~_..-.~ .~ --° MD Inclination w Azimuth ~ TVD ~ f t ° ° ( f _ Vert Sect ! ~ North ~ East Grid East I Grid North I DLS Build Rate 'turn Rate,Design f f 1 f t00f 1 f ° ~ ~ ° ° [ ee ] ~ ] ~ ~ [ eet] [feet [ eet) [ eet] [us survey feet] [as survey feet~~[ 00 t~ [ / / 00 t] I / t1 Comments 0.00 0.000 290 931 0 00 ! 0.00 0.00. 0.00 ; 13 69044.34 ~ 2254701.99 ~ 0 00 ~ 0.00 __._ O.OO Surface RKB 18T 00~', 100 0.000E 0.000 100.00 ; 0.00 _ 0.00 0.00' 1369044.34 1 2254701.99 0.00 ~ 0.00 0.00 200 ~ _ .00 0.000390.931. 200.00 0.00 0.00. 0.00. 1369044.34 2254701.99 0.00 0.00 0.00 KOP ; ~ ~ . __ 29 4.36 1.56 4.07 1369040.30 2254703.64 5.00 ' 5.00 - _ 0.00: 400.00 j',_ 2 10.000 90931' 398.99 + 17.41 ' _ 6.22 -16.26 ' 1369028.22 2254708.57 5.00 -_ 5.00 0.00! SOO.OOt 15.0001.290.931 496.58 39.05 -- 13.95 -36.47 13 69008.19 2254716.76 ~ 5.00 ' 5.00 - ~ 0.00. 600.00 i 20.000', 290.93 L 591.93 69. L L _ _ _-- _ --. ____._ 24.69 a -64.55 1368980.37 ~ 2254728.13. _ _ 5.00 { -_ _ S.OOi ____w. ..---_-- _-- 0.00. 0.00'i z 70 25.000 290.931 684.28 107.36 38.35 ~ 100 28 1368944.95 2254742 60 _ ._ ___ , _ __, . _._ _ ____ -. __ ~ _ _. ~__ 5.00 1 5 001 0.00 __ _.._ ___ ... _._ _ _~__ _ .. p f 800.00 i 30.000 290.931 772.96 153.52 54.84 ~ -143.39 1368902.22 2254760.05 5.00 5.00 0.00 900.00 j' 3 S.000i 290.931 857.27 ' 207.24 ' 74.03 r -~ 1 -193.56 , 136$852.50 ; 2254780.37 ' 5.00 ~ 5.00 __- _ __ 0.001 1000.00 i 40.000' 290.931 936.58 268.09 95.77 ' -250.40 li68796.17 2254803.38 5.00 5.00 0.00 1100 00 i ~, 45.000290.931 1010.28 335.63 119.90 -313.48 1368733 65 ~ 2254828.93 5.00 ~ 5 00 _ 0.00 ~1 ~ 1200 OOf 50.000 290.931 1077.82 409.34 146.23 -382.32 1368665.42 2254856.80 5.00 5.00 0.00 s 1300.00i' 55.000 290.93 l 1138.68 488.65 174.56 -456.40 1368592.00 2254886.80. 5.00 5.00 0.00: 1400.00' 60.000 290.931 1192.39 572.96 ! 204.68 -535.15 1368513.95 ~ 2254918.69 ' 5.00 ' 5.00 0.00'. '. 1500.OOi' 65.000.290.931 1238.55 66L63 236.36' -617.97 1368431.87 2254952.22 5.00 5.00 0.00 _ 1582.92 69.146290.931 1270.85 737.98 689.29 1368361.19 2254981.10 263 63 ~ 5.00 5.00 _. _ __ 0.00 End Angle Build 1600.00' 69.146'.290.931' 1276.93 753.94 - 269 34 704.19 1368346.41 2254987.14 0.00. 0.00 0.00 ~~ 11700.00' 69.146290.931 1312.53 847.39 302.72 -791.48 1368259.91 2255022.48 0.00 0.00 0.00 1800.OOj'; 69.146j290.931 1348.12 ; 940.84 336.10 -878.76 1368173.40 2255057.82 0.00 0.00 0.00'; 1900.00' 69.146'290.931 ~ 1383.72 1034.29 369.49 -966.04 1368086.89 2255093.17 0.00 0.00 0.00 ;2000.00'1' 69.146'.290.931 1419.32 '. 1127.74 402.87 ;-1053.33 1368000.3 9 2255128.51 0.00 0.00 0.00; ~2100.OOt 69.146~~290.931 I-15492 1221.19 _ 436.25 -1140.61 1367913.88 , 2255163.85 ~ 0.00 0.00 0.00 2200.00'i 69.146 290 931 1 490.52 1314.64 _v _____ _ ___ 469.64 -1227.89 1367827.38 2255199.20 0.00 0.00 0.00 i 2300.00 ~ _ . i -- 69.146 290931'.1526.12'.. 408.09 ', _ __ _- - ~__ __-_ - 503.02 ,-1315.17 1367740.87 2255234.54' 0.00 , 0.00 _ _ _ _ 0.00 I 2400.OOi 69.146 290.91 1561.72 1501.54 536.40 -1402.46 1367654.36 2255269.88 0.00 0.00 0.00 j2500.00i' -- 69.146j290.931 1597.32' 1594.99 ~ -- 569.79'-1489.74. 1367567.86 2255305.22 0.00 _ 0.00 0.00 :600.00 i 69.146290.931 1632.91 1688.44: -- - 603.17 -1577.02 1367481.35 + 2255340.57 0.00 ___ 0.00 0.00 .2700.001 69.146290.931 1668.51 1781.88: . 636.55 ~-1664.31 1367394.85 ~ 2255375.91 0.00' 0.00 0.00 28a' - - O.OOj' - - _ 69.146 290.931 1704.11 , _ ~--r 1875.33 ---_ __ _- -- - _ 669.94 1751.59 1367308:34 , 2255411.25 '. - 0.00 -~___ 0.00 0.00 E '` 2900.00 ~ - 69.146 290.931 1739.71 . _ 1968.78 ~ - 703.32 1838.87 1367221.83 ~ 2255446 60 ' - 0.00 0.00 0.00 __._~ __ __ __ _ 3000.OOj', 69.146 290.93 11775.31 2062 23 ` 736 70 1 1926.15 ' 1367135.33E 2255481 94 f 0.00 0.00 0.00 `' 03100 001'' 69.146 290.93 11810.91 2155 68 ' 770 09 ; 2013.44 ; 1367048 82 ! 225551 7 28 = 0.00 ' 0.00 0.00 03200.00'1'' 69.146290.931 1846.5 L 2249.13 = _ 803.47 ~-2100.72 ~ 1366962.32 1 2255552.631 0.00 0.00 0.00 ;3340:00'; 69.1461290.931 1882.11 ; 2342.58 . 836.83 -218$.00 13668'75.81 ~ 2255587.97 OAO 0.00, O.OOi 3400.OOt ~ 69.146 90.931 f 1917.70. ' 2436.03 ~ __ 22 870.24 -2275.28 ! 1366789.30 1 2 3.31 556 001 0 0.00 O.OO _ 3500.OOt~ 69.146 290.931 ( ~~~~~(1953.30 ; _ 2529.48 ; . _ _ __ _ _ 903.62 ~-2362.57 11366702.80 2255658.65 ~ , 0.001 0 OOi 0.00, ~ 3600 OOi 69.146 29 0 931 1988 90 2 26 2 93 r ~. ~ 937 00 2449.85 1 1366616.29 2255694.00 0 00 ~ _._ 0 00 0.00 ~ . 0 93112024 50 , 2716 38 ~ 970 39 2537.13 ~ 1 366529.79 ~ 2255729.34 I 0.00 ~ 0.00 0.00 _ 3800.OO~i _ _ 69.146;290.93I12060.102809.82 X . 1003.?7?-262~k.42 : 1366443--~ ~ -~ .28 ! 2255764.68 0.00 ! -_ 0.00 __ _.__ __ _._ 0.00! C7 M MARATHON • Planned Wellpath Report MGO #6 Version #4 Page 3 of 5 WELLPATH BATA (125 stations) ~' =interpolated/extrapolated station E~. BAKER ~IY1t~NE INTEQ ___ ___-__~___.__.._ MD iInctination s Azimuth j TVD ~ Vert Sect ______ ~___ North East r__-_ -__-_ Grid East ~ ~--__-~.__~.._._._ Grid North ~ ___~__ _ _ DLS Build Rate ~'Purn Rate Design [feet] [°l I°l [feet] ` Meet] lfcetl lfeet] [us survey feet] [us survey feet] [ °/100ft] I°/100ft] 1°/100i't] 'Comments 3900.00 j', 69.146 290.93 L 2095.70 ~, 2903.27 1037. L 5 -2711.70 ' 1366356.77 2255800.03 ~ 0.04 ~ 0.00 0.00. 4000.00 fi; 69.146:290.931 2131.30 ' 2996.72 1070.54 -2798.98 1366270.27 2255835.37 0.00 0.00 0.00 ~4100.00~; 69.146.290.931 2166.89 .3090.17 1103.92 -2886.26 1366183.76 2255870.71 0.00: 0.00 0.00 4200.00 69.146 290.93 l 2202.49 ' 3183.62 1137.30 -2973.55 1366097.26 2255906.06 0.00 0.00 0.00 4300.00 j' 69.146:290.931' 2238.09', 3277.07 1170.69 -3060.83 i 1366410.75 ' 2255941.40 0.00 ; _ - 0.00 0.00 4400.00'- 69.146 290.931 2273.69'3370.52 1204.07 -3148.1 l 1365924.24 2255976.74 , 0.00 0.00 0.00: 4500.OOi' 69.146290.931 2309.29 ~~3463.97 1237.45 -3235.40 1365837.74 2256012.09 0.00 0.00 _ 0.00 4600.00'1' 69.146'..290931 2344.89 3557.42 .1270.84 -3322.68 L365751.23 2256047.43 0.00 ~ 0.00 0.00- ~ 4700.00 i 69.146~~ 290.931 2380.49 ' 3650.87 1304.22 -3409.96 1365664.73 2256082.77 0.00. 0.00 0.00 t 4800.00' 69.146 290.931 2416.09 ', 3744,32 .1337.60 -3497.24 _ 1365578.22 ' 2256118.11 0.00 ; 0.00, _ 0.00 4900.00'1 69.146.290.9312451.68 3837.76 1370.99 -3584.53 1365491.71 2256153.46 0.00' 0.00 0.00 _. _ 5000.00 i 69.146'. 290.93 12487.28 3931.21 1404.37 -3671.81 1365405.21 .2256188.80 0.00 ' 0.00 0.00' 5100.001 __ 69.146.290.931 2522.88 4024.66 1437.75 -3759.09 1365318.70 2256224.14 0.00 0.00 _ 0.00 _ 5200.00''1 69.146.290.931 2558.48 4l 18.11 1471.14 -3846.37 1365232.20 2256259.49 0.00 ' 0.00 0.00 5300.OOt 69.146' 290.931 2594.08 4211.56 1504.52 ! -3933.66 1365145.69 2256294.83 0.00 0.00' O.OOI ', 5400.00 t 69.146.290.931 2629.68 4305.01 L537.90 -4020.94 1365059.18 2256330.17 O.OU 0.00 0.00 j 5500.001 69.146, 290.93 12665.28 .4398.46 1571.29 -4108.22 1364972.68 2256365.52 0.00 0.00 _ 0.00 s j 5600.001- 69.146~'~ 290.931 2700.88 4491.91 1604.67 -4195.51 1364886.17 2256400.86 0.00 0.00 0.00. `5700.OOi~ 69.146 290.931 273647 4585.36 .1638.05 -4282.79 1364799.67 2256436.20 0.00 0.00 0.00 ? 5800.00', 69.146, 290.931 2772.07 14678.81 1671.44 I -4370.07 . 1364713.16 2256471.54 0.00 0.00 0.00' 5900.001 69.146.290.931 2807.67 4772.26 1704.82 -4457.35 1364626.66 2256506.89 0.00 ! 0.00 0.00 16000.001' 69.146 290931 2843.27 ' 4865.70 ' 1738 20 ~ 4544.64 1364540.15 2256542.23 0.00 ' 0.00 0.00' 6100.001' 69.146.290.93 12878.87:4959.15 , -~ 17?1.59 4631.92 1364453.64 2256577.57 , 0.00 ' 0.00 0.00. _, ._ s 6200.001 f 69.146 290.931 2914.47 5052.60 __, 1804.97 4719.20 _ ___ ._ 1364367.14 _-_._ - _- ~ 2256612.92 _._ 0.00 0.00 . 0.00, _- 16300.OOfi~' - 69.146!290.931'2950.07 ;5146.05 ___ 1838.36 ,-4$x6.49 ~.__ _ _ ~ 1364280.63 _ _ _ ~, 2256648.26 ~ 0.00 ~'; 0.00 0.00;' 6400.OOt 69.146290.931 2985.66 5239.50 1871.74 -4893.77 1364194.13 2256683.60 0.00 ' 0.00 _ 0.00 s j6500.001' . 69.146.290931 3021.26 5332.95 1905.12 ~-4981.05 __ 1364107.62 - ___ - -- 2256718.95E 0.00'. 0.00 _- 0.00 6 7 1 9. 0 6 54 ; 9 068. 8. , - 3640211 56754 29 _ 00 0 6 00.00 ~' g ; 69.146 290.931 3092.4 6 55 7 89 5 62 155 i i 363934.6 22 56789.63 0. 00 0.00 0.00' - _ - 6800.00 69.146.290.931 3128.06 ',5613.30 2005.27 -5242.90 1363848.10 2256824.98 0.00 0.00 __ _ _ 0.00' ~_ 6900.00 69.146290.93L 3163.66 .5706.75 2038.66 -5330.18 1363761.60 ! 22568 60.32. 0.00 0.00. O.OOi ,, 7000.00' 69.146' 290.93 13199.26 5800.20 _ 2072.04 -5417.4 6 1363675.09 _ ', 2256895.66 0.00 ' 0.00. _ _ O OOU~ - 7100.00' 69.146 290.93 I =3234. 86 ~ 5893.64 _ 2105.42 -5504.75 ~ 1363588.58 , 2256931.00 0.00 ' 0.00. _ 0.00 7200.00~~' _ 69.146 290.931 3270 45 ~ 5987.09 2138.81 -5592.03 ~ 1363502.08 _ 2 256966.35 0.00 ' 0.00' 0.00! 7300.00' 69.146 290.93 l 3306 O5 ; 6080.54 2172.19 ' -5679.31 ; 1363415.57 _ ', 2257001.69 0 00 _ _ 0.00 0.00, 7354.08 69.146 290.931:3325.30 j 6131.08 2190.24 -5726 52 ! 13 63368.79 j 2257020.80 + 0.001 0.00 O.OO~Begin Angle D rop 7400;00' 67.998 290 931; 3 342 08 1, 6173 .83 ~ 2205.51 ~ -5766 44 _ 1363329.22 _ ~ 2257036 97 ~ 2.50 ~ -2.50' _ _ 0.00) 7500.00~1~ _ _ _ 65.498' 290.931 ~3381.55 j 6265.70 22 8 3 (-5852.25 r 1363244.17 , 2257071.72 ~ 2.50 .50. -2 ~ 0.00 ~~ 7600.00' G2~998 290.931 ~ 3425 00 6355.76 , 2270.51.5936 37 1363160.81 ~ 2257105 78 ~ 2.50 _ _ ` _ ! 7700.00';, ;6443.84 2341..97 ~~-6018.64 60.498; 290.931 3472.33 ' '~~ 1363079.27 ~ 2257139.09 2.50 , -2.50 _ _ O.Ob ---- ----_- ', Planned Wellpath Report MGO #6 Version #4 MARATHON Page 4 of 5 ;rator MARATHON Oil Company __ _ Slot 1MG0 #6 a~ jCook Inlet, Alaska (Kenai Penninsula) ~~ ____ Well 1MG0 #6 td 'Ninilchik Field (NAD83) :Wellbore ~MGO #6 ilitY_,_MGO _ ___ __ _~~___ __._ _ _____ ' ~^ BAKER NYt~NEs INTEQ ~VELLPATH DATA (125 stations) ~' mterpolatedlegtrapolated station _ ~ 1VSD Inclination i Azimuth TVTVD~ Vert Sect NorthEast ? ~ ~ Grid East _ G d-r North Q _ DLS ~BUlld Rate ~ ~ Turn Rate Design [feet] [°] [°] ~` [feet] ; [feet] [feet] ; [feet] e [us survey feet] ~ [us survey feet] [[ E /1 [°/100ftJ ~ Comments ~°/100tt 4 ~ 7800.00~~ _„p _ _ 57.998 290 931; 3523.46 ;65 29.77 2332.67 ~ 6098 90 ~~ . 1362999.72 2257171.59 i 2.50 , ._ -2.50. ._ ... . .~__. _ _~ _..d. ~_ ., 0.00 7900.00~'j _ 55.498 290.931 j 3578.29 6613.39 ~'~ 2362.54 j -6177.00 i 1362922.31 j 2257203.22 ~ 2.50 I -2.50 __ 0.00 _a_ 8000.00'1' 52.998 290.931 3636.71 6694.54 2391.53 -6252.79 1362847 19 2257233.91 2.50 -2.50. ~ - -- 0.00 8100.009' 50.498 290.931 3698.62 .6773.06 ' 2419.58 -6326.14 1362774.51 2257263.61 2.50 -2.50 0.00 8200.00 j•, 47.998 290.931 3763.89 ~ 6848.81 2446.64 -6396.89 1362704.38 2257292.25 2.50 -2.50 0.00 j 8300.001 45.498 290.931 3832.41 6921.64 2472.66 -6464.91 1362636.97 2257319.80 2.50 -2.50 0.00 ~° 8400.00 i 42.998 290.931 3904.03 ~ 6991.41 ' 2497.58 ~-653 0.0$ ' 1362572.38 2257346.19 2.50 ~ ___ -2.50 __ 0.00 ~~~~~~ 8500.001~ _ 40.498 290.931, 3978 63 705799 2521.37 ? 6592.26 ~ 1362510.75 2257371.37 2.50 -2.50 _ 0 OO -- ` 1 8600.00'1 37.998 290.931 4056.07 7121.25 2543.97 -6651.35 1362452.18 257395.29 2.50 2.50 0.00' 8700.00• 35.498 290.931', 4136.19 ' 7181.08 2565_.34'. -6707.23 1362396.80 ' 2257417.92 2.50 -2.50 0.001 ~ 8800.009' _ 32.998 290.931 4218.84 7237.35 2585.44 -6759.79 1362344.71 2257439.20 2.50 -2.50 0.00 8900.OOf 30.498 290.931 4303.87 7289.97 2604.24 -6808.93 1362296.01 2257459.10 2.50 2.50' 0.00' 9000.OOt 27.998 290.931 4391.12 7338.82 2621.69 6854 56 _ 1362250.78 2257477 58 _ 2.50 2.50 0.00'. s 9100.OOt 25.498 290.931 4480.41 7383.82 2637.77 -6896.60 1362209.12 2257494.60 _ 2.50 = 2.50 , ~ 0.00' 9200.00' 22998.290.931 4571.58 7424.89; 2652.44 -6934.95 ' 1362171.11 2257510.13 2.50 ' -2.50 0.001 ' 9300.OOt 20.498 290.931 4664.46 7461.94 2665.67 -6969.56 1362136.81 2257524.14 2.50 -2.50 0.00 9400.001' 17.998 290.931 4758.86 .7494.90 ?2677.45 -7000.35 ---- -_ 1362106.30 2257536.61 ~ 2.50 -2.50 0.00'. R 9500.00~'~ 15.498 290.931 4854.61 7523.72 2687.74 -7027.26 1362079.62 2257547.51 2.50 -2.50 0.00 9600.OOj• 12.998 290.931 4951.53 7548.33 ' 2696.53 -7050.24 1362056.84 2257556.82 2.50 -2.50 0.00 9 9700.00j' 10.498 290.931, 5049.42 7568.69 2703.81 -7069.26 1362037.99 2257564.52 2.50 ' -2.50. 0.00'1 9800.009' 7.998 290.931 5148.12 7584.76 ~ 2709.55 -7084.27 ~ 136202 3.12 22575 70.59 2.50 -2.50. 0.00 __ _ ~~ j 9900.OOt _ 5.498 290.931 5247.42 ;7596.51 2713.75 -7095.24 _ 1362012.24 _ . 2257575.04 2.50 _ -2.50= _ 0.00 I,10000.00t 2 998 290.931 5347.13 7603.91 i 2716 .39 r 7102 16 ~ 1362005.39 2257577.84. 2.50 -2.50 0.00 I O100.00t _ _- ~~~_ ___ __ __ _ ~ ___. -. 0.498 290.93 15447.08 ~ 7606.96 i 2717.48 j -7105 O1 ~ _--- _-_--_ 1362002.56 _. _ 2257578.99 2.50 ~ _ -2.50 _ ._~_ _ __ . e. _.. _ _ 0.003 ,10119.92 _ _ -- -~__-_.r_ _._. _ __ , 0.000 178.708':5461.OOZ~7607.05 2117 51~ -7 105 09 __ _ _ 41362002.48 2257579.02 _ 2.50 -2.50 _ _ _ _. _ _ O.OOEnd Angle Drop 10200.OOt _ _ ____ _. 0.000 178.747 5547.08'7607.05 '2717.51 ~-7105.09 ~ 1362002.48 2257579.02 0.00 0.00 0.00 10300.00'1 0.000 178.707. 5647.08 17607.05 .2717.51 -7105.09 1362002.48 2257579.02 0.00 0.00 -0.04 f 10400.001• r .~____.__ _ _. _ __._.___~. 0.000 178.657 5747.08 X7607.05 2717.51 -7105.09. 1362002.48 __-- 2257579.02 _ 0.00 0.00 _ ~ _____ ~ _ -0.05. 10500.00 i . _ -. 0.000 178.702 5847.08 7607.05 2717.5 l -7105.09 1362002.48 _ 2257579.02 0.00 0.00 _ 0.04 , ? 10600,00' _ __ _ _ 0.000178.761 5947.08 7607.05 , 2717.51 -7105.09 13620Q2.48 2257579.02 0.00 0.00: 0.06'; 10700.OOt 0.000 178.657 6047.08 7607.05 ' 2717.51 -7105.09 1362002.48 2257579.02 0.00 0.00 -0.10 ~ 10800.00~~ s 0.000 178.670 6147.08 7607.05 ~ 2717.51 -7105.09 1362002.48 , 2257579.02 0.00 0.00 _ 0 01~ ~, ~ 10900.00 ~ _ _ --_-_-- __- i. _ ---- 0.000 178.702= 6247 08 > 7607.05 .2717.51 -7105.09 - -~. _._ ~ 1362002.48 . __ ; 2257579.02 0.00 0.00 _. _ .._ ___ ___ .., , ~ 1 0.03 j 11000.001` ~._____ _ _ _.. _. __~.. __ _____ __._ __...-__-___ 0.000 178.716 6347.08 !7607.05 j2717.51 -7105.09 _________._ . 1362002.48 _ r _.._ ' 2257579.02 0.00 ~ 0.00. _ _ _ ___ _ ~__ .__. _ 0.01" . j 11200 00 j•~ 0.000 178.76 647.08 7607.05 j 2717.51 -7105.09 1362002.48 2257579.02 0.00 O.OOi 0.01 $ 11300.00•; 0.000 178.709 6647.08 7607.0 5 ~ 2717.51 - 7105.09 j 1362002.48 2257579.02 ; 0.00 ; 0.00 ~ 0.00 11400.OOt _ _ _ _ 00 178.698 6747.08 X7607.05 717.51 0 0 -7105.09 ! 1362002.48 ~ 2257579.02 0.00 ` O.OOi _ -_._ -0.01 11500.001-: j _ _ -7105.09 0.000 178.720 6847.08 7607.05 2717.51 1362002.48 2257579.02 OAO 0.00, _ 0.021 11640.00'f', 0.000 178.721' 6947.48 7607.05 , 2717.51 -7105.09 ' 1362002.48 ' 2257579.02 0.00 0.00' _ - 0.001 M MARATHON i,WELLPATH DATA 125 s MD ; Inclination i -_--- Azimuth [feet] [°] ; [°] 11700.00 j' ( 0.000 ~ 178.701 i 11800.003'3 0.000 178.704 11900.OOt~ 0.000 178 706 12000.OOt 0.000. [78.699 1208992 0.000 178.708 Planned Wellpath Report MGO #6 Version #4 Page 5 of 5 ~~ BAKER NY6ME3 INTEQ ions) ~' = mter_p_olate_d/extrapolated_statl_on _ ^_TN _ _ __ _ TVD Vert Sect ~ North r- East Grid East ~ ~ Grid North DLS ~ Bnild Rate j Turn Rate CDesign 7047.08 ~ 7607.05 i 2717.51 7147.08 7607.05 2717.51 7247.08 7607 OS X2717.51 7347.08 ~ 7607.05.2717.51 7437.OOa 7607.05. 2717.51 7105.09 1362002.48 j 2257579.02 ( 0.00 ~ 0.003 -0 02'; -- r 7105.09 --- - - - 1362002.48 ~ - ~- 2257579.02 ° 0.00 ~ - - 0.00 0 00~ 7105.09 13 62002 48 ~ 2257579 02 0.00 __ 0.00 _ 0 00 -7105.09 ; _ 1362002.48 s 2257579.02_. 0.00 0.00 -0.01 _~_ -7105.09~~ 1362002.48 . 2257579.02 ' 0.00 0,00' 0.01 Tll HOLE & CASING SECTIONS Ref Wellbore: MGO #6 jString/Diameter 'Start MD End MD Interval [feet] ~ [feet] [feet] V2.25in Open Hole 0.00 3000.00= 3000.C 19 625m Casing Surface 0.00 3000.00 ~ 3000.C ~8 75in Open Hole ~~~ ~~ ~~~~ ' ~~3000.00 9051.66; 6051.6 ~7.625in Casing Intermediate 0.00 9051.66; 51.6 90 '6.75in Open Hole ~ _ 0.00 _ 12089.92 ~ _ 12089.5 4.Sin Casing Production ~OAO 12089.92, 12089.5 ARGETS MGO #6 Tyonek T2 Coal - Rvsd: 12-Jun-07 1) MGO #6 Tyonek T3 Coal - Rvsd: 12-Jun-07 2) MGO #6 TD - Rvsd: 12-Jun- =07 __ __._ ,.e_ __..__-_.__-_~___.__ __._ _ .. _-_. ,____.. ____ _------_~v__________-_________.~.._ _._,~___, __ -- ~SUR_VEY PROGRAM R_ef Wellborec MGO #b Re_f W_ellpath: M_GO #__b Versitrn #4 Start MD~ ~ End MD Positional Uncertainty Model Log Name/Comment ~ Wellbore ~ [feet] [feet] 0.00 3000.00 NaviTrak Standard MGO #6 ~ _~_~____~_ _ _.__ _____ _ _ __ ~ -~___~ __ __ s 3000.00 9051.66 AutoTrak G3 SAG ~ GO #6 9051.66;. 12089.92 AutoTrak G3 (MagCorr) GO #6 j O #6 Version # 4 Re f Wellpath: MG _ '~Start TVD _ _ _ End TVD Start N/S _ Start E/R' F.nd N/S E d /W (feet] [feet] [feet] ~ [feet] [feet] ~ [feet] 0.00 1775.31 0.00 ~ 0.00 ~ 736.70! -1926.15 0.00 ~ 1775.31 0.00 0.00 736 70 ~~ -192 6.15 v ___. 17753] : 4437.00! 736.70 -1926.15 2630.17 _ -6876.73 0.00 4437.00 0.00> 0.00 2630.17, -6876.73 ~- _,_-_. 0.00 .___._. ~ . 7437.00 ~ . ___-- -n_ 0.00E __. ~ 0 00 _.__ _ 2717 51 ~ 7105.09 ______e__ 0.00 ,--y 7437.00; --- ~-- 0.00 ~ ----.- 0.00 ~ 2717.51;. -7105.09 MD TVD i North East ~ Grid East Grid North Latitude ~ Longitude ,Shape [feet] ~ [feet] [feet] ~ [feet] ~ [us survey feet] [us survey feet] ~ [°} ~ [°] __ _ __ _ c _.~ „ _...~ ' 3837.00 ~ 2717 52 ( 7105.09 ~ 1362002.481 _2257579 03 ! _60 10 15.255N ~ 151 31 44.181 W i ctrcle ~~ 15467.00 2717.52 7105.09? 1362002.482257579.03 601015.255N 151 3144.181W ctrcle 7437.00 ~ 2717.51 { -7105.09 2257579 03 b010 15.255N 151 3144.181W circle M MARATHON • Wellpath Design Summary Report Wellpath: MGO #6 Version #4 Page 1 of 2 rator jMARATHON Oil Company _ _;Slot ~ Cook Inlet, Alaska (Kenai Penninsula) ~ ~ ~ !Well 3 Ninilchik Field (NAD83) Wellbore lity MGO ~~. ~ ~. ~ ection System ~NAD83 / TM Alaska State Plane, Zone 4 (5004), US feet th Reference True _ e~.__ ~__ __ 0.999984____. - ~ ______ __ _ _~_-- -- _ lbore last revised 96/12/07 Calculation method Horizontal Reference Pt Vertical Reference Pt _ _.__________ w___. MD Reference Pt Field Vertical Reference Minimum curvature #6 #6 ~~~ BAKER MY+l~MES INTEQ #6 Software System User ~ ~ ~. Report Generated Database/Source file e1lArchitectTM 1.2 at 13:50:34 #6.xm1 Glacier #1 (RKB) to Facility Vertical Datum Glacier #1 (RKB) to Mean Sea Level _.___ _.___._ _ .__.. ____ .mA__..._ __ _ ._._-___.____.._~___®.__ _-.... .. __w_ r #1 (RKB) Facility Vertical Datum to Mud Line (Facilit r #1 (RKB) Sea Level W ELLPATH DATA (6 stations) ;187.00 feet 187_.00 feet 0.00 feet _ - ~ NID Incliuat~on ~ - Azimuth ~ - - TVD ~ Vert Sect North East DLS EDesign feet ° ~ ° feet feet feet feet ~ °/IOOft Comments ~ _ - 0.00 ' 0.000 ,_. 290.931 ~ 0.00 ° 0.00 0.00 ; 0.00 ~ 0.00 Surface RKB: 18T 200.00 0.000 290.931 ° 200.00 0.00 0.00 I 0.00 0.00 ~KOP 1582.92 69.146 290.93 I 1270.85 737.98 263.63 i -689.29 5.00 End Angle Butld _ 7354.08 69.146 290.931> _ 3325.30 ~ 6131.08 2190 24 ! -5726.52 ; 0.00 .Begin Angle Drop _ t0119.92 0.000, 178.708', 5467.OOI 7607.05: 2717.51 -7105.09 2.50 End Angle Drop 12089.92 0.000= 178.708 ?437.00~~' 7607.05 2717.51 -7105.09; 0.00 ~TD Ref Wellpath:. HOLE & CASING SECTIONS `Ref Wellbore. MGO #6 MGO #6 Version #4 LL IString/Diameter {Start MD . End MD lInterval j Start TVD End TVD Start N/S =Start E/W End N/S End E/W ~ ~ ~ [feet] [feet] ~ [feet] ; [feet] [feet] [feet] ~ [feet] ~ [feet] [feet] O ~ ~ 0.00 3000 00;~ 0 00~ 0.00 736 70~ 1926.15 1775.31 ~ 0 00~ __.___ v.______ ____,~__-.._._____ 9 625in C asm Surface ~ g ~ M_ _m 0.00+ ~ _ i.. ~._~ 00.001 3000.00; ~30 t.__ __._..__.._._ 0.00 i ~ ~~ __._ ~_ ...._____r_._. ~ 1775.31 I 0.00 ~ 0.00. 736.70! -1926.15 ~8.75in Open Hole ~ ~ 3000.00 __ ._. -_r-----__ -r--- 9051.66 ~ 6051.66 ~ -- -_ -__.~_~_ 1775.31 ~ _ ® f_ ~ _ 2630.17 -6876.73 4437.00 736 70 j 1926.15 ___ .625in Casing Intermediate ~ 0.00 ~ 9051.66 9051 66 ( 0.00 ~ 4 7.00 0 OO j 0.00, 2630.17 -6876.73 ~6.75in Open Hole 0 ~ 12089.92 ~ 12089 92 0.00; 7437.00~~ 0.00 0 2717.51 ~-7105.09 __ ~4.Sin Casing Production ~ _ j ~ O.UO _ _ 12089.92 i 21 089.92E ~ ~ 0.00 f 7437.00 ~ 0.00 ~ 0.00 2717.51 ~ -7105.09 Well ath Desi n Summa Re ort ~~r p Wellpath: MGO #6 Version 4 p V~N~,~ MARATHON Page 2 of 2 INTEQ Operator jMARATHON Oil Company _ ?Slot __ 'MGO #_6_ _ _ Area 'Cook Inlet, Alaska (Kenai Penninsula) w ~~ ~ -ell w ,MGO #6 ____._~_____ ~ u ~~ -- ~Field #Ninilchik Field (NAD831 ?Wellbore !MGO #6 TARGETS Name MD ' TVD I North East € Grid East Grid North Latitude ~ Longitude ,Shape [feet] ~ [feet] j [feet] [feet] ; [us survey feet] ((us survey feet] [°j ~ [°] > ~ _ _ __ _~__~_,__ ___-- MGO #6 Tyonek T2 Coal - -.- _ -, _ _m ,--.. ~ 3837 00' 2717 52 ~ 7105 09 ,_ 1362002.48; ______ _ _._~ .__ .__ _ v _ __ __W.__ 2257579.03 60 10 15.255N~ 151 31 44 181 W ~ circle Rvsd: 12-Jun-07 1) MGO #6 Tyonek T3 Coal - ~_ ~ 5467.002717.52 ~ -7105 09 ~ ~_ 1362002 48, rt .____s___~m__ _2257579 03 ~f0 10 15.255N 151 31 44.181Wcircle Rvsd: 12-Jun-07 ~MGO #6 TD -Rvsd: 12-Jun ~7437.00~ 2717.51 7105 09! ~ 1362002 48~ 2257579.03', 60 10 15.255N,~ 151 31 44.181W circle ~~ Y SURVEY PROGRAM Ref Wellbore: MGO #6 Ref Wellpath: MGO #6 Version #4 Start MD End MD ~ Positional Uncertainty Model Log Name/Comment W ellbore [feet] [feet] ~ _ _ _ _ 0.00. 3000.OON_aviTrak (Stan_dard)_ ~VIGO~#6 ~~ 3000.00 9051.66 AutoTrak G3 (SAG) M~ ~ v ~ ~ ~~_ _ _~ _~ _ _ _ __._ __ _ ____.__ _._ _ _~_~_ `AGO #6 9051.66 12089.92AutoTrak G3 (MagCorr) ~~GO #6 M MARATHON MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: MGO #6 Field: Ninilchik Field (NAD83) Well: MGO #6 Facilit MGO Wellbore: MGO #6 r~.~ BAKER 1~1~16~IES INTEQ Plot reference wellpath is MGO #6 Version #4 True vertical depths are referenced to Glacier #1 (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4 (5004), US feet Measured depths are referenced to Glacier #1 (RKB) North Reference: True north Glacier #1 (RKB) to Mean Sea Level: 187 feet Scale: True distance Mean Sea Level to Mud line (Facility - MGO): 0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by: michwilg on 7/9/2007 -leoo -teao -noo -tsoo -tsoo -taoo -t3oo ->zoo -tloo -loco -eoo -Boo aoo -Boo -Soo -aoo moo -200 -100 o too '~c~ ~'~o ~~ \~o eoo ~°' y ti°° ~ ~,~~° Um ~N 1~ BOO ~. ~ 'Neo ~'s ~P ^S ~ 8p0 700 s'`$ a0~ ~0 ^ 800 ~^~ ~~ °~~ h ,y~ oy ,ACS' 500 a 8 16~ 00 ~ ~ > 0 ~ 0 1 ~ MGO #2 N S g °o c ~ ~ o a ~ ~p ~ _ $ g g g ~ ,o X400 300 1~ o °~ 0 0 ° 0 o o ~° ~ 'op o g w $ ~° $° 'n ° o ~ X100 M 100 ~00 200 o 0o °j Op $ MGO #5 ~ a~ g n $ o `~ y~~~ 0 0 MG #6 0 0o MGOi ~ M MARATHON MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: MGO #6 Field: Ninilchik Field (NAD83) Well: MGO #6 Facilit MGO Wellbore: MGO #6 Plot reference wellpath is MGO #6 Version #4 True vertical depths are referenced to Glacier #1 (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4 (5004), US feet Measured depths are referenced to Glacier #1 (RKB) North Reference: True north Glacier #1 (RKB) to Mean Sea Level: ~ 87 feet Scale: True distance Mean Sea Level to Mud line (Facility - MGO): 0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by: michwilg on 7/9/2007 ~~~ BAKER Mt~GMES INTEQ • z 0 s ~• sG,~„~~~=6001 Easting (ft) M MARATHON M ATHON Oil Co pany Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: MGO #6 Field: Ninilchik Field (NAD83) Well: MGO #6 Facilit : M 0 Wellbore: r~.r BAKER N~16NE5 INTEQ Plot reference wellpath is MGO #6 Version #4 True vertical depths are referenced to Glacier #1 (RKB) Gnd System: NAD83 / TM Alaska State Plane, Zone 4 (5004), US feet Measured depths are referenced to Glacier #1 (RKB) North Reference: True north Glacier #1 (RKB) to Mean Sea Level: 187 feet Scale: True distance Mean Sea Level to Mud line (Facility - MGO): O feet Depths are in feet Coordinates are in feet referenced to Slot Created by: michwilg on 7/9/2007 Traveling Cylinder: Map North ,. 600 ' 200 MGO 4 790' 9 ' Ie0/1 0 Ipar 200 0 '°°~ M G 0 5 °°. 000 ep1f 0 V~Ie .ar age• Doff ear zro' fzo' fm,f 1 0 0 fees zf0' f60' ipt ib' G • M MARATHON Slot Location Facility Reference Pt Field Reference Pt ~~ Clearance Report Closest Approach MGO #6 Version #4 Page 1 of 29 Local coordinates_ North [feet] ': East [feet 2986.28 ". -2990.52 alculation method Mini_m_um Curvature _~._ __ ontal Reference Pt oriz ,__~.~ .~ Slot _ ertical Reference Pt _ Glacier #1 (RK_B) _~ ~ Reference_Pt ?Glacier #1 (RKB) _ field Vertical Reference Mean Sea Level Geographic coordinates Latitude [°] _L_ongitude [°] 60 09 48.512N 151 29 23.738W _.~___ __, __ _v ________~____ 60 09 19.105N 151 28 24.639W 60 09 19.105N 151 28 24.639W Glacier #1 (RKB) to Facility Vertical Datum X187.00 feet ;Glacier #1 (RKB) to Mean Sea_Level_ ~~ 187.00 feet _ 'Facility Vertical Datum to Mud Line (Facility) X0.00 feet ~~ POSITIONAL UNCERTAINTY CALCULATION SETTINGS ~llipse Confidence Limit 3.00 Std Dev Ellipse Start Depth _ __..... ~_ _.. ~ ..~.._.a... ~._____e__.~ ___.. _ _._ _ ~ ._ _..- Declination x18.94° East of TN jDip Angle ANTI-COLLISION RULE Surface Position Uncertainty included Magnetic Field Strength ~ 55275 nT ~ ule Based On ~ Ell p Separation Rule Name ~ mm ; E type Closest Approach w/Hole&Csg Limit:0 StdDev:3.00 w/Surface Uncert Plane of Rule (Closest Approach ~___ , __ Subtract Casing & Hole Size eyes • Est BAKER Nu~NEs INTEQ __ Grid coordinates sting [US feet] Northing [US feet] 1369044.34 701.9_9_ 2254 __ _ 13_71967.44 _ _ 2251649.81 _~_._ ~~ 1371967.44 2251649.81 O.OO feet 173.11° Threshold Value ~0 00 feet - - - --.._._ _ _ ____._r_._ ___._ Apply Cone of Safety ~ no M MARATHON Clearance Report Closest Approach MGO #6 Version #4 Page 2 of 29 ~~ BAKER - Nu~NEs INTEQ Operator MARATHON Oil-Company _ _ Slot ';1VIG0 #6 _ _ Area ;Cook Inlet, Alaska (Kenai Penninsula) ~ Well MGO #6 ~ ____ ____ Field Ninilchik Field (NAD83) ~ Wellbore MGO #6 ;Facility jMGO ~ HOLE & EASING SEC_T_IONS Ref Wellbore: MGO #6 Ref Wellp~ String/Diameter ~~ ~ _ ~; St ra t MD End MD Interval ~ Start TVD Y-- [feet] ~ [feet] ~ [feet] ~12.25in Open Hole ! 0.00 ~ 3000.00; 3000.00 9 625m Casing Surface 0.00 3000.00, 3000.00 8 75in Open Hole 7.625in Casing Intermediate 6N75in Open Hole_ 4 ___ 4.Sin Casing Production 3000.009051.66 ~ 6051.66 0.00 9051.66 i 9051 66 0.00. 12089.92 j 12089.92 0.00! 12089.92': 12089.92 the MGO #6 Version:#4 F.nd `I'VD Start N/S Start E/W [feet] [feet] [feet] 0.00. 1775.31; 0.00 ~~ 0.00 _ 0.00 1775.31 ~ 0.00 r ~ 0.001 1775.31 ~ .._ 36.7 4437.00 7 _ 0-1926,15 0 00' 4437.00 0.00 O.OOI 0 00. 7437.00 0.00 0.00 0.00 i 7437.00 ~ 0.00 . 0.00 SURVEY_PROGRAM Ref Wellbore: MGO #6 Ref Wellpath: MGO #6 Version #4 Start MD End MD E Positional Uncertainty Model Log Name/Comment [feet]____ . _..._ _ [feet] __ _~ ___~_____ ~ _ -._- 0.00! 3000 OOjNaviTrak (Standard) ~ 3000.00 _ 9051.66AutoTrak G3 SAG ~ a ( ~_.___ .___ __. ---__ . ___~ _____.._. ___.__.... __ 9051.66 12089.92iAutoTrak G3 (MagCorr) I End N/S ~ End E/W (feet] j [feet] 736.70 ~-1926.15 _736.70 -1926.15 ..~..n._; _____.__._ 2630.17 ~ -687_6.73 2630.17 ~-6876.73 27_17.51; -7105.09 2717.51 j -7105.09 ~ Wellbore #6 #6 #6 CALCULATION RANGE & CUTOFF From: 0 00 MD ~To: 12089 92 MD ~C C Cutoff 5280.00 feet OFFSET WELL CLEARANCE SUMMARY (7 Offset Wellpaths selected) Offset Offset Offset Offset Offset Ref Min C-C Diverging Ref MD of Min C-C Min C-C ACR Facility Slot Well Wellbore Wellpath MD Clear Dist from MD Min C-C EII Sep Ell Sep Status [feet] (feet] [feet] Ell Sep [feet] Dvrg from [feet] [feet] __..__ .__~ _.~._.~ ~.~,_.. __ ...-_ ._ ___~.__._e _.__,____.__ _________.__ w _.__ __..__ __r._._ __.__ _~~ ___,_. MGO ~MGO #1 MGO #1 MGO #1 CMWD<0-11600'> 0.00. 405 71' 12089 92 ~ 0 00! 392 80' 12089.92 PASS i ~PGMS<0- ---- - -- ---- MGO MGO #2 i MGO #2 , MGO #2 12500'>MWD<2523- 762.50 412.74 ~ 12089.92 ~ 786.73 395.07 12089.92 =,PASS ' 12026'> ~ ~ _ ~MGO ~MGO #3 MGO #3 MGO #3 MWD <0-13771> 1154.53 125.38 ~ 1154.53: 1154.53 ~ 100.88 1154.53 .PASS { MGO MGO #4 MGO#4 MGO#4 MWD <0-8175> 0.00 219.36 0.00 , 0.00 206.29 0.00 PASS _ NaviTrak MVt+D <0_ ~ _. _._ -- _- -_ _ _ --- -_ _ ---- - - , MGO MGO #5 ,MGO #5 MGO#5 0.00' 108.41 0.00 ~ 0.00 95.07 0.00 PASS SoCal Falls SoCal Falls SoCal Falls ' E ~MGO ~ MSS<0-8256'> 1329.G3 1388.84! 11000.00' 1517.24'; 1351.20. L0900.00{PASS Creek !Creek 'Creek E I ~~ ,__. ..______ . _ __ ~ _ _. -_._-- _ _.-- _ ..-- 3..__ ____ _ ~ __.. _..____ ~MGO Texaco ;Texaco Cexaco •MSS <0-12903'> ~ 0.00 506 24 ~ 12089.92 ~ 392.26 ~ 493.05 12089.92 PASS !Ninilchik #1 ~Ninilchik #1 ~Ninilchik #1 ~ ! ~ t • _~ -"'~ • Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PROJECT PLAN ~. =1FE Prepared For: MARATHON OIL COMPANY Well Grassim Oskoloff #6 Prepared by: Jim Dwyer Reviewed by: Hal Martens Presented to: Will Tank July 11, 2007 ~~ Kenai Peninsula, Alaska • • ~'~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 _ Location: Kenai, Alaska. Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: Enclosed is the revised recommended drilling fluid program for the Grassim Oskoloff #6 Well to be drilled in August 2007. The following is a brief synopsis of the program. Overview: GO #6 is a development well targeting the Tyonek formation at the Grassim Oskoloff field. A Gel/Gelex spud mud is recommended for the surface interval. Two Flo-Pro fluids will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with 4-1/2" liner cemented in place. Surface Interval: A standard fresh water Gel/Gelex spud mud will be used. Initial funnel viscosity should be in the 50 - 75 sec/qt range. Lower funnel viscosity to 45 - 60 sec/qt after gravel has been drilled. Lower fluid loss to 10 - 12 cc's API prior to running surface casing. Intermediate Interval: This interval will be drilled with the same type of Flo-Pro fluid used on the GO #5 well. After drilling out the surface cement, the well will be displaced to the new fluid. SafeCarb bridging material will be maintained according to the mud program to minimize losses to the formation. Lubricants should be added on a as-needed basis. Production Interval: This interval will be drilled with the standard non-damaging Flo-Pro fluid used on non-excape wells. After drilling out the intermediate cement and 20 - 25 feet of new hole, the well will be displaced to the new fluid. Fluid loss should be maintained @ 5 - 7 cc's API for this interval. Completion: The completion will consist of a 4-1/2" liner cemented in place. This will be tied back to the surface with a 4- 1/2" completion string. Corrosion control will be added to the 6% KCl brine that will remain in the 4-1/2" x 7" annulus prior to tie-back. Jim Dwyer Project Engineer M-I Drilling Fluids Reference Well: GO #1, GO #2, GO #3 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties reauired. ~~ • • Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. EXECUTIVE SUMMARY Our overall goal is no M-USwaco HSE incidents while providing fluids and solids control services to our customer. Our goal for GO #6 is to remove drill solids from the mud system at a cost of less ~ ~ than X0.29 per pound. This has been the average for the last five years of centrifuge van operations Our goal for GO #6 is to drill the well at a fluid cost of less than $23.94 per foot with a total volume of fluid used less than 4104 barrels. Use of the MI-SWACO centrifuge van for the last five years has provided an estimated savings in dilution. and disposal costs to Marathon Oil of over $1.,250,000.. '? I~ With continued usage of our equipment we expect to provide more savings to you ~_ F during future operations. In addition, the installation of Mongoose shakers has allowed the utilization of finer mesh screens on intermediate and production intervals. Running finer mesh screens has reduced the need for the centrifuge van. IFE • • ~'~ Marathon Oil Company ~~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Benchmarks .and Targets Drilling Intervals Depth Benchmark 1 Benchmark 2 Benchmark 3 Benchmark 4 Interval eft) Fluid cost per foo Volume Usage Solids Removal 0 - 3000' < $5.72 ft < 2149bb1s 3000 - 9052' < $25.91 ft < 2200 bbls 9052 -12090' < $40.69 ft < 1543 bbls Total Project Avg. Max. Targets for < $24.62 < 6092 bbls < $0.29 lb o Spills from Centrifuge Drilling Van Operation Interval IFE _~ '1~ • Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth ND Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) (in) (ft) (ft) Solids Control (ppg) 9-5/8" 12-1/4" 3000' 1775' Gel/telex Spud 8.6 - 9.4 7 $24,171 Mud Screens 150!180 mesh Desilter Centrifuge Van 7 5/8" 8-3/4" 9052' 4337' FloPro 9.4 - 9.7 7 $163,837 w/SafeCarb Screens 180 - 210 mesh Desilter Centrifuge Van 4-1/2" 6 3/4" 12090' 7437' FloPro 9.4 - 10.3 9 $132,613 w/SafeCarb Depending Screens 230 - 210 On gas mesh readings Desilter Centrifuge Van 4-1/2" 7 5/8" Completion 12090' 7437' 6% KC1 8.55 6 $15,596 - 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 any considerations for whole mud losses. Cost includes daily mud engineering rate - Cost includes 3% Lubetex concentration for intermediate and production interval. IFE • • ~'~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 ~° Location: Kenai, Alaska. Product Usage Summary PRODUCT Surface 12-1/4" Intermediate 8-3/4" Production 6 3/4" Completion 4-1/2" Total Usage % of .Total Cost M-I Bar 0 330 1234 0 1564 4.33 M-I Gel 645 0 0 0 645 2.28 Gelex 27 0 0 0 27 0.15 Soda Ash 11 11 15 0 37 0.24 Caustic Soda 11 22 15 0 48 0.71 Con or 404 0 5 5 0 10 4.50 Sodium Meta Bisulfate 21 21 15 1 58 1.39 Bicarb 11 11 15 0 38 0.24 Con or 303A 0 0 0 1 1 0.17 F1oVis 0 154 108 0 264 18.77 Desco CF 28 0 0 0 28 0.47 DualFlo 0 0 93 0 93 2.78 Polypac UL 43 77 0 0 120 6.50 Greencide 25G 0 0 2 0 2 1.02 KCl 0 924 648 84 1656 10.61 Kla and 0 23 21 0 44 10.87 Safecarb 0 440 617 0 1038 7.39 Lubetex 0 40 37 0 77 20.03 Defoam X 0 12 9 0 21 0.67 Asphasol Su reme 0 169 62 0 231 6.91 En ineer Service 7 7 9 6 29 IFE • • ~'~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments GO #1 12.25" 945 8.6 14 26 9.9 Spud in, drlg ahead 1479 8.8 20 32 7.4 Short trip, OK 1897 8.9 20 35 7.3 Trip for bit & motor 2468 9.6 22 32 7.6 Drlg ahead w/short trip 2500 9.4 18 26 9 Drlg to T.D., run casing 8.5" 3488 9.45 8 22 9.8 Drig out, displace mud, drlg ahead 4138 9.55 9 27 9.8 Run solids van, add lubetex for sliding 4762 9.7 9 24 10.8 Added DD for clays, running solids van 5248 10.1 13 29 8.8 Running centrifuge van for dry jobs 5617 9.75 10 23 8.1 Drlg ahead, dill stuck, work free, short trip 6290 9.75 10 24 6.9 Condition mud, drlg ahed 6567 9.8 10 21 7.2 Drlg ahead POH for BOPs & BHA 6976 9.55 9 23 8.5 RIH drlg ahed 7358 9.8 8 18 7.3 Drlg ahead, short trip, weight up for running shale 7578 10 9 17 7.5 Ream to bottom, drlg ahead 8086 9.6 14 30 6.2 Drlg to casing point, condition hole for logs, add lubetex 8086 10 9 27 6.3 Finish logging, run and cement casing 6.125" 8765 10 9 23 7.3 Drlg out, blend old/new mud drlg ahead 9393 9.9 9 22 6.4 Drlg ahead, POH, lost cone 9393 10.1 10 21 6.4 Fish for bit cone 9404 10.1 10 20 6.5 RIH w/mill, work to td, RIH w/drlg assembly 9718 10 9 28 6.4 Drill ahead 10010 10 9 28 5 CBU, POH 10443 10 12 31 5.6 5' fill on bottom, increased connection gas 11016 10 12 29 5.8 Drlg ahead, run van for drill solids 11305 10.05 12 28 6.4 Drlg ahead 11600 10 11 27 6.2 POH for logs, 11600 10 11 27 6.2 Run & cement 4-1/2" liner IFE • ~'~ • Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Offset Well Information GO #2 12.25" 866 9 15 33 10 Spud in, drlg to 866, trip for BHA 1163 9.65 21 42 7.2 Drlg ahead, hard to slide 1495 9.6 16 44 6.2 Drlg ahead, added Lubetex to help slide 1695 9.45 13 40 6.9 Drlg ahead, trip fo new BHA, drtg ahead 2240 9.8 13 37 8 Drlg ahead, run centrifuge and desilter for solids 2500 9.75 14 38 8 Drlg to csg point, cond hole run casing 8.5" 2935 10.1 8 28 7.8 Drlg out, disp to new mud, drlg ahead 3639 10.05 10 29 7 Solids building up, start centrifuge van, 4355 10.1 11 30 8.4 Drlg ahead, run centrifuge van 4702 10.1 13 31 8.2 Drlg ahead, run centrifuge van 5344 10.15 14 31 8 MBT increasing, dump and dilute 5727 10.2 13 26 8.2 MBT increasing, dump and dilute 6247 10.25 14 24 7.5 Rig repair, circulate &cond mud 6507 10.1 14 31 8.9 POH test BOPE 6667 10.35 17 33 8 RIH, mad pass log well, 7030 10.2 16 28 7.3 Drlg ahead 7345 10.2 17 23 7 Short trip, backream as needed 7788 10.3 16 28 7.5 Stuck @ 7113', coal, backream, add lubetex to 2% 8118 10.35 18 29 9 Increase lubetex concentration to 3% 8422 10.35 18 28 8.8 Centrifuge mud for fines (MBT) 8530 10.3 18 30 8.6 Sweep hole, POH for logs 7" 8644 9.5 7 20 5.5 Drlg out, disp to new mud, drlg ahead 9402 9.6 8 23 4.5 Drlg ahead 10018 9.95 10 26 5.2 Increase mud weight to 9.9 PPG 10835 9.95 12 28 5.8 Dump & dilute to reduce drill solids 11338 10.15 11 23 5.8 Inc mud weight for high trip tgas 11995 10.25 10 27 6.6 Losing mud to hole after weight up 12026 10.4 11 26 6.4 Swabbing, increase mud weight, pump OOH 12026 10.4 8 24 6.5 Logs hit bridge at 8640' 12026 10.45 8 24 6 Difficulty logging, engr released 11/4 IFE Marathon Oil Company ~~'~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Offset Well Information GO #3 12.25" 1078 8.8 12 27 15 Spud in 2396 9.3 14 20 11.8 Drill ahead, short trip, OK 2508 9.65 15 22 8.2 Drlg to casing point 2508 9.6 15 21 8.8 Run and cement surface casing. OK 8.5" 2528 9.4 17 34 4.8 Drlg casing shoe, displace to new mud, drlg ahead 3858 9.55 15 29 5.6 Drill ahead with autotrack 4891 9.7 14 23 6.2 Drlg to 4891, short trip, tight in spots, drlg ahead 6414 9.5 22 27 4.6 Drlg ahead, pump sweeps every 300' 7332 9.6 19 32 5 Drlg to casing poiint, conditon mud, POH 7332 9.65 17 23 4.1 Log interval, run 8 cement casing, all OK 7'~ 8190 9.6 10 24 4 Drlg out, displace to new mud, drlg ahead 9598 9.6 10 21 4.2 Drlg ahead 9794 9.75 10 26 5.2 Drlg to core point, short trip, OK, POH 9814 9.8 10 25 5.6 RIH, Core 50 9814' 9842 9.75 12 24 4.8 Recover core, RIH continue coring 9875 9.75 11 22 5.4 Finish coring, log cored section 10662 9.8 11 24 4.4 repair top drive, drill ahead 11529 9.8 12 23 5.2 Drlg ahead 12212 10.3 13 26 5.8 Dril to core point, treat lost circulation, weight up to 10.3 PPG 12212 10.75 12 19 6.2 Hole appears to be breathing 12250 10.7 13 22 6.4 Core well 12331 10.7 12 23 5 Finish coring, RIH ream core run, drlg ahead 12967 10.7 13 19 4.2 Drlg ahead 13233 10.7 12 19 4.6 Drlg ahead, POH for MWD 13358 10.5 10 21 4.8 RIH, ream tight spots, cirs out 1800 units gas, drlg ahead\ 13436 10.2 11 20 4.8 Drlg ahead, lost returns, pump ICM pills, lower mud weight 13771 10 10 20 5 Drlg ahead, lost 510 bbls, slow pumps, reduce tossed 13771 10.1 11 19 5.2 POH, RIH w/log tools on DP, 13771 10.25 11 20 5.4 Circ out gas, log well 13371 10.2 9 13 4.2 Run liner, cement with lost returns, 13371 9.8 9 11 5.2 Squeeze liner top, displace well to KCL, run completion strring IFE • • Marathon Oil Company ~~'~ Well Name: Grassim Oskoloff #6 Ver 1.0 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 formation - 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 in the 5 - 7 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 UL after consultation with town. ~ LSRV - When drilling with a F1oPro fluid, the low shear rate rheology should be maintained around 30,000 cps. In addition to adequate additions of F1oVis 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 KCl 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 - Congor 404 additions should be made daily when drilling with F1oPro fluid in order to maintain a Congor 404 concentration of +/- 2000 PPM. ~ CORRISION - Sodium Meta Bisulfate 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 too 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. IFE C] ~~ r~ u Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary -12-1/4" hole 0 - 3000' Drilling Fluid System GeUGelex Spud Mud Key Products MI Gel / Gelex /Soda Ash /Caustic Soda / MI Bar / PolyPac Supreme UL /Sodium Meta Bisulfate 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 nterval Drilling Fluid Properties Depth Mud Funnel Yield API Drill Interval Weight Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec./qt) (Ib./100ft2) (mU30min) (%) 0 - 3000' 8.8 - 9.4 50 - 75 25 - 35 NC -10/12 +/- 9.5 < 7% - Treat drill water with Soda Ash to reduce hardness. - Build spud mud with 20 - 25 PPB M-I Gel to +/- 75 sec.gt funnel viscosity. - Lower funnel viscosity to +/- 60 after any gravel 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 of Polypac 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 - 2149 barrels. - Estimated haul off volume - 3498 barrels. ~~ C /I/~ • ~;'~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary -12-1/4" hole Virtual Hydraulics Snapshot ~~ T.D. IV~'SWAC:,.~. ~13=}_:.~ ~.~ L ~ ~. 'tmN wpn. 3000 ft Operator: Marathon Oil Company 'iAariof 41~ L.L.c. ~ tvo:1775 ft WeII Name: G0 i16 YIRTUAI HYDRAULICS' SnapShott ~s~="12.25 in Location: Kermi Peninsula DAe: 7f11110~7 Countrv~ USA De th Geometry An le D~ {f~) MDITVD CsgOD110 {'~ (II P, 0 60 00 10 I i :_ I Annil~ i L Dulling Fluid Water•Based Mud Mud Weight 9.2 Iblgal Test Temp 120 °F System Data Flow Rate 625 gal!min rnetratlan Rlrte100 ftlhr ~tarySpeed SO rpm eight on Bit 15 1000 Ib t Nozzles 1.1 in' Pressure Losses Modffied Power Law filling String 363 psi WD 250 psi dor 200 psi t 1333 psi t OnfOff 120 psi mulus 23 psi trface Equip ?5 psi Tube Effect 18 psi ESD ECD +Cut Shoe 9,28 9.40 9.61 PLAN Vwdai;t.l VO 6 11.1f1AD6 - Hole cleaning deteriorates as angle build to +/- 70 degrees. Recommend a high viscosity sweep at interval T.D. prior to POH for casing run. IFE Ej.'~' ffl1 in) • Marathon Oil Company - ~'~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary -12-1/4" hole Virtual Hydraulics Hole Cleaning Index Mi "''' :~: I ~I ~_ ~ ~:: MD. 3000 ft Operator: M arathon 0 it Company -"~-~"::--:'""kormai,.c TYD;1820 ft ellflame:GO06 VIRTUAL HYDRAULICS' Snapshot' I 'Bit Size,1Z.25 in Location: Kenai Peninsula lH th Geometry -, - --- Date:7J'11f200T Courttr~ Hole Z`fean - l~i MD/TVD Csg ODIID Index 91[0+~ enn~".3 D5=1A; Drifliny Fluid Water-Based Mud Mud Weight 9.2 Ibfgal Test Temp 120 °f System Data Flaw Rate 625 galirnin snetratlon Rate100 ftlhr Mary Speed 80 rpm eight on Bit 15 1000 Ib t Nozzles 18-18-18-16- 0-0-0-0- Pressure Losses Mod'rfied Power• Law •ill String 375 psi WD 250 psi otor 200 psi t 376 psi t OnfOtf 12fi psi mulus 26 psi arface Equip 24 psi •Tube Effect 20 psi >tal System 1392 psi ESD ECD +Cut Sq Shoe 25.3225.4525.fi8 4aslua A 1 Faun 35 0 6 1]-7SJ,g6 - Avoid hole cleaning issues by maintaining high flow rate (+/- 625 GPM), and ROP < 125 ft/hr IFE E~i~~ • • ~'~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary - 8-3/4" hole 3000 - 9052' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / PolyPac UL / KCl / SafeCarb 10 & 40, Asphasol Supreme Lubetex / Caustic Soda / Congor 404 /Sodium Meta Bisulfate / Kla and Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 200 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss pH Solids (ft) (ppg) (cp.) (cps) (mU30min) (%) 3000 - 9052' 9.2 - 9.7 8 - 12 20 - 30,000 6 - 8 +/- 9.5 +/- 7.5 - Use one rig pit to drill out surface casing. In other rig pits, build new F1oPro fluid using the enclosed formula. - After drilling out surface casing, displace hole to F1oPro fluid prior to running leak off test. - Maintain DO reading of less than 3 ppm with additions of Sodium Meta Bisulfate. - Maintain Congor 404 concentration of 2000+ ppm. - If running coals become a problem, increase Asphasol Supreme additions. - Estimated volume usage for interval - 2200 barrels. - Estimated haul off volume - 3600 barrels. - Condition mud prior to running 7 5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~~ ~ ~ • • Marathon Oil Company '~ Well Name: Grassim Oskoloff #6 Ver 1.0 ~.° Location: Kenai, Alaska. Fluid Formula - 8-3/4" hole MI `~wA~.__---''' MUDCALC 4.5 -Water-Based Mud Calculation 8-3/4" Interval from 3000- 9052' In ut Out ut -1 bbl Order of Products Concentrati on Volume Product Addition Field Ib Lab m Field, bbl - Lab ml Usa e 1 Water 317.07 317.07 0.906 317.07 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 Flovis 2.00 2.00 0.004 1.33 Viscosit 4 Pol ac Su reme UL 2.00 2.00 0.004 1.25 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 H Control 6 KlaGard 6.00 6.00 0.016 5.45 Inhibition 7 As hasol Su reme 4.00 4.00 0.010 3.33 Wellbore Stabilit 8 Potassium Chloride 20.24 20.24 0.024 8.47 Inhibition 9 Con or 404 2.00 2.00 0.004 1.43 Corrosion Control 10 SafeCarb 10 10.00 10.00 0.010 3.57 Brid in A ent 11 MI Bar 30.24 30.24 0.021 7.20 Mud Wei ht 12 Sodium Meta Bisulfate 0.50 0.50 0.002 0.56 O en Scaven er If for ue becomes a roblem add u to 5% of the followin 13 Lubetex 14.00 14.00 0.041 14.43 Lubricit Total 394.8 394.8 Estimated Volume Usa a 2200 bbls Calculated Mud Wei ht Total Ch{pride 9.400 29600 Descr tion GO #6 Intermed iate Interval Mud Wei ht 9.4 Preh drated Gel ' No Wei ht Material Code MI Bar Preh drated Gel Conc. Wei ht Material SG 4.2 KCI Chloride Wei. ht Material Price KCI Wt% 6 • • ~~ Marathon Oil Company ~_~ ~'~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary - 8-3/4" hole Virtual Hydraulics Snapshot ~~ T.D. ___ y ~, ~ ~ ~ I .I ~ ~ ~~ Tatal Dapth:9052 ft Operator: Marathon Oil Company -- ~ _-~"dko1"^a~~'= ', TVD:4437 ft WeIlName: G0 #6 YIRTUAI HYDRAULICS' Snapshot" Blto'~e$„;,moo, '" Lco~rm~ use i Peninsula ~~} Pret:au ~ ~tri6ution ~/o 41I=T Ann=11 D5=?i.t Dullingg Fluid FLOPRO NT Mud Weight 9.4 Iblgal Test Temp 120 °F System Data Flaw Rate 507 ctalimi rtratlen rte 100 ftlhr nary Speed 70 rpm fight on Bit 15 1000 Ib Nozzles 0.396in' Pressure Losses Modrfied Power Law ling String 456 psi iD 402 psi for 321 psi 898 psi OnlOff 120 psi lulus 221 psi fiace Equip 18 pal 'ube Effect 29 psi al System 2465 psi ESD ECD +Cut a Shoe 9.49 10?310.36 IAM ~ Vndm.i.1 GU 6 i.15.hD8 - Hole cleaning should not be an issue while rotating drillstring. If extended periods of sliding is required, then added circulation and high viscosity sweeps may be needed. IFE ~i' :' P, LSYP'{Ib/100ft • ~_ ='~ • Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary - 8-3/4" hole Virtual Hydraulics Hole Cleaning Index M1 SWAG l::j_~ 1n L}I L I_'~. ~ - - __ 'M art o'N~L.L.C. YIRTUAL HYDRAULICS` ~il~~lshot`'~~ De th Geometry {f~) MDffVD Csg OD11D MD:9052 ft Operator: Marathon Oil Company TVD:4494 ft ell Marne: GO II6 Bit Size:8.75 in Location: Kenai Peninsula Date:711112007 Cou_ ntrv: USA ---- Prsssu t ~} button ~ an•~.3 Ann•Ye,a us•at .,~ f. Drillingg Fluid FLOPRO NT Mud Weight 9.4 Iblgal TestT_emp_ __120 °F System Data Flow Rate 400 gallmin Penahaaan R~te100 ftlht Rotary Speed TO rpm Weigle on Bit 15 1000 Ib Bit Nozzles 12-12-12-12- 12-0-0.0- _ _ _ ___ __ Pressure Losses ModHied Power Law Drill String 352 psi M WD 250 psi Motor 200 psi Bit 318 psi Bit On10ff 120 psi Annulus 205 psi Surface Equip 12 psi U•Tube Effect 38 psi Total System 1495 psi _ ESD ECD Cut Csg Shoe 9.49 10.1810.34 TD 9.50 10.3810.54 _- - - VRDH - W~sia~ 7.1 Frn SS Fia - VV 6 B.IS.IAB - Maintain flow rates above 400 GPM along with ROP < 100 ft/1tr. IFE Fes' v~ v F • • Marathon Oil Company ~~'~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary - 6 3/4" hole 9052 - 12090' Drilling Fluid System Flo-Pro Key Products Flo-Vis / DualFlo / KCl / Greencide 25G / SafeCarb 10/ MI Bar / Caustic Soda / Conqor 404 /Sodium Meta Bisulfate / la and / Lubetex / As hasol Su reme Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 230 - 275 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions, stuck pipe. nterval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss pH Solids (ft) (ppg) (cp.) (cps) (mV30min) (%) 9052 - 12090' 9.4 - 10.3 10 - 14 20 - 30,000 5 - 7 +/- 9.5 +/- 5% - Use one rig pit for drilling out intermediate casing. In other rig pits, build new Flo-Pro fluid using the enclosed formula. - NOTE: Initial formula does not call for Lubricant. However lubricant additions should be monitored for there effectiveness with the enclosed data sheet. - If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. - If connection gas increases and background gas remains high, mud weight should be increased accordingly - Periodic additions of Greencide 25G will be needed to control bacteria build-up. - Estimated volume usage for interval - 1543 barrels. - Estimated haul off volume - 2006 barrels. - Condition mud prior to running 4-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. IFE E~i'L' • ~ Marathon Oil Company ~'~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Fluid Formula - 6 3/4" hole M~ ~~+.,_,,,.~-~ MUDCALC 4.5 -Water-Based Mud Calculation M-I L.L.C. 6.75" Interval from 9052 -12090' Input Descri tion - GO #6 Production Interval Mud Wet ht 9.4 reh drated Gel No Wei ht Material Code MI Bar drated Gel Conc. Wei ht Material SG 4.2 KCl Chloride Wei ht Material Price KCI Wt% 6 vu~ u~ - ~ ur~~ Order of Products Concentration. Volume Product Addition Field {b Lab m Field, bbl Lab, ml Usa e 1 Water 317.07 317.07 0.906 317.07 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 Flovis 1.50 1.50 0.040 1.00 Viscosit 4 DualFlo 5.00 5.00 0.010 3.33 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 H Control 6 KlaGard 6.00 6.00 0.016 5.45 Inhibition 7 As hasol Su reme 4.00 4.00 0.010 3.33 Wellbore Stabilit 8 Potassium Chloride 20.24 20.24 0.024 8.47 Inhibition 9 Con or 404 2.00 2.00 0.004 1.43 Corrosion Control 10 SafeCarb 10 10.00 10.00 0.010 3.57 Brid in A ent 11 MI Bar 51.42 51.42 0.035 12.24 Mud Wei ht 12 Sodium Meta Bisulfate 0.50 0.50 0.002 0.56 O en Scaven er If for ue becomes a roblem add u to 5% of the followin 13 Lubetex 14.00 14.00 0.041 14.43 Lubricit Mud wei ht increases are ossible with increased connection and back round as readin For every .5 ppg increase in mud weight, 3000 Ibs of Barite per 100 bbls mud are required Total 411.6 411.6 .Estimated Volume Usa a 1543 barrels Calculated Mud Wei ht 9.800 Total Chloride 29600 ~~ ~~ C~ - -" 1~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary - 6 3/4" hole Virtual Hydraulics Snapshot ~~ T.D. YlRTUAL NYDRAULICS' SnapSAot' De team err -- ,~~t~O ~ I~ GtD,T~; D cs~~DDnD ~~F { Q IlI E4 'il P. T tel Depth: 12052 ft TVD=7472 R Btt S+ze.6J6 In 40h F Operaror; Merattton Dil Campeny Walt Name; t34 !6 Locadon; Beret Penlneula A- MOI.~eMOh Praew~Qgr~utlon ~ Dtiillrnfgg Fktid I FLOPRt} wr Mud'JWighr 4.1 Iblgal Teat Tamp _t20 "F System Data Flow f+a1~ 264 gallmin ar~fonRaee98.? hAu ry Sped 70 rpm Ifat on Bit 15 f000 b Ia;rlss 01:t1n' Pressure Losses todifiad pao-+ar Low ng S1+Ing 987 psi ! 1Bil psi N 707 ps+ ~2 pm~ fn~Oft 100 psi dua 331 pai tea Equp 7 pa bs Effect 50 pm ESD ECD +Cut Csg Shoe 9_.19 10A6f0.59 YHVLAM Vw.~ 1,1 FM. GO a s,JS ? N18 - Tangent section of 7 5/8" casing may develop cuttings beds. Consider low/high viscosity sweeps while bit is inside 7 5/8" casing only (not in open hole). IFE ~:~ • • _~~ Marathon Oil Company ~'~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary - 6 3/4" hole Virtual Hydraulics Hole Cleaning Index - - 'M art o!MJ LL.C. YIRTUAI HYDRAULICS` Snapshot' Geometry iORVD CsAODiID Hole Clean Index MD: 12090 Ft Operator: Marathon Oil Company TVD: 7510 Ft ell Name: G 0 A6 Bit Size:6.75 in Location: Kenai Peninsula Date:7(11R007 Country USA______.___ Preswro DistribuBon (°/al Dulling Fluid FLOPRO NT Mud Weight 9A Ibfgal Test Tem 120 °F System Data Flow Rate ?60 gallmin Penetration rtate80 ftlhr Rotary Speed 70 rpm Weight on Bit 15 1000 Ib Bit Nozzles 11-11-11-11- 0-0-0-0- Pressure Losses Modrfied Powsr Law Drill String 884 psi M WD 150 psi Motor 100 psi Bit 274 psi Bit OnlOff 100 psi Mnulus 328 psi Surface Equip 6 psi U-Tube Effect 47 psi Total System 1890 psi ESD ECD +Cut Csg 5hoe9.49 10.4510.57 TD 9.50 10.3410.46 _-- __ - VHUM VwcMm 3.1 FMn SS Fia ~i0 6 6.r52.L0a - Flow rates of 250 - 275 GPM are adequate to clean this interval. NOTE: Higher flow rates may increase ECD's to a level to high for the formation. IFE~"'~ vc c F • • ~~;'~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Interval Summary -Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well Grassim Oskoloff#6 Volumes: Tubing Volume 3-112" Tubing 187.24 barrels Annular Volume Casing x Tubing 299.01 barrels 3.992 x 12090 ft Packer ~ 8972 ft MD 6.8 @ 9052 ft MD 4.00 @ 12090 ft MD Total Annular Volume 299.01 Tubing Volume 187.2a Total Hole Volume ass.2a Treatment Procedures. 1. After the 3-1/2" tubing is run and the drilling fluid is conditioned, build at least 400 barrels of 6% KCL brine. 2. Displace mud out of well with the 6% KCL brine. Add 1 drum of Conqor 303A and 1 sack of Sodium Meta Bisulfate for 100 barrels of brine pumped. 3. Displace treated fluid with brine prior to setting the tubing hanger so treated fluid is in 7" annulus 4. Verifv pump strokes for placi x 7 5/8" annulus. IFE Eli :;~ • • '~ Marathon Oil Company ~ Well Name: Grassim Oskoloff #6 Ver 1.0 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: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammabilit Reactivit PPE M-I BAR Weighting Agent *1 0 0 E M-I GEL Viscosity control *1 1 0 E GELEX Bentonite Extender 1 1 0 E FLOVIS Viscosifier 1 1 0 E DUAL-FLO Modified Starch 1 1 0 E POLYPAC Fluid Loss Reducer *1 1 0 E HEC Loss Circulation Material 1 1 0 E Safe-Garb 10,40,250 Bridging and weighting agent *1 0 0 E Nut Plug Loss Circulation Material *1 1 0 E M-I Seal F, M, C Loss circulation Material *1 1 0 E Mix II F,M,C Loss circulation Material *1 1 0 E DESCO CF Dispersant 1 1 0 E SALT (Solar) Densifier 1 0 0 E POTASSIUM CHLORIDE Shale Inhibitor 1 0 0 E CAUSTIC SODA Alkalinity control 3 0 1 X BORAX Inorganic Borate 1 0 0 E SAPP Sodium Pyrophosphate *1 0 0 E SODA ASH Alkalinity control 1 1 0 E SODIUM BICARBONATE Alkalinity control 1 0 0 E CITRIC ACID pH Adjuster 1 0 0 E BIOBAN BP-PLUS Biocide *2 0 0 J GREEN CIDE 25G - Biocide 3 0 0 J DEFOAM X- Defoamer 1 1 0 J G-SEAL Sized graphite LCM 1 1 0 E SteelLube Lubricant 1 1 0 J LOBE TEX Lubricant 1 1 0 J D-D CWT Detergent 2 1 0 J Concor 404 Corrosion Inhibitor 1 1 0 J SAFEKLEEN Drilling fluid additive 1 1 0 J Asphasol Supreme Shale Inhibitor 1 1 0 J Sodium Meta Bisulfate Oxygen Scavenger 1 1 0 J IFE • • '~ Marathon Oil Company Well Name: Grassim Oskoloff #6 Ver 1.0 ~° Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS o m m ~ ~ HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 -Severe hazard 3 -Serious hazard 2 -Moderate hazard 1 -Slight hazard 4 -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 ~~ • • Marathon Oil Company ~~ t~ Well Name: Grassim Oskoloff #6 Ver 1.0 Location: Kenai, Alaska. Contacts Contact Title a-mail Work Cellular Pete Berga Drilling pkberga@marathonoil.com 907 565- 907 231-0663 Marathon Superintendent 3032 Will Tank Drilling Engineer wjtank@marathonoil.com 713 296- 713 203-8398 Marathon 3273 Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274- 907 227-2412 MI SWACO 5011 Bob Myles Warehouse Manager rmyles@miswaco.com 907 776- 907 252-4218 MI SWACO 8680 Oliver Amend Field Engineer Miswacogdrl@hotmail.com 907 260- 907 590-3636 MI SWACO 4666 (home) Locke Rooney Field Engineer rooneyl@alaska.net 907 235- 907 590-3636 MI SWACO 0598 (home) John Nicholson / Drilling Foremen alaska_drilling@marathonoil.com 907 283- Roland Lawson 1312 Marathon Responsibilities - MI Project Engineer and will coordinate daily 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. - Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. - Field Engineers will communicate with office personnel (Marathon & MI SWACO) for approval of any changes in the mud program (including introduction of new products). - Field Engineers will produce a recap at the end of the well based on daily activities. Recap should include any lessons learned that may be used to provide better service on future wells. Lessons learned can include changes in procedures, product additions, equipment usage, and/or utilization of any third party service. IFE Page 1 of 1 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, Juty 24, 2007 3:11 PM To: Wilt Tank; Pete Berga Subject: G.O. #6 Will and Pete, i am finishing review of the permit for this well and have a few questions. 1. For drilling, Marathon calculates MASP using a combination of 30%° mud and 70°r6 gas. This gives a value of 1846 psi. Does Marathon calculate a different and higher value for the production condition when reservoir fluid (gas} would be at surface? 2. What is the actual Sl surtace pressure at G.O.? 3. What is the pressure test value for the tubing? Thanks, Tom Maunder, PE AOGCC 7/26/2007 Page 1 of Maunder, Thomas E (DOA) From: Walsh, Ken [kdwalsh@marathonoil.com] Sent: Tuesday, July 24, 2007 11:37 AM To: Maunder, Thomas E (DOA) Cc: Meese, Craig A.; Skiba, Kevin J. Subject: RE: New Well 10-403 Application-GO #6 Tom, I expect that the work will begin within 2-3 weeks (+/- one week) from rig release depending on the availability of equipment and personnel. Ken Ken D. Walsh Senior Production Engineer Marathon Oil Company-Alaska Asset Team 907-283-1311 (office) 907-394-3060 (cell) From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, July 24, 2007 11:33 AM To: Walsh, Ken Cc: Meese, Craig A.; Skiba, Kevin ). Subject: RE: New Well 10-403 Application-GO #6 Ken, et al, That should be fine. What sort of time interval do you anticipate between drilling rig release and commencement of the completion work? Tom Maunder, PE AOGCC From: Walsh, Ken [mailto:kdwalsh@marathonoil.com] Sent: Tuesday, July 24, 2007 11:19 AM To: Maunder, Thomas E (DOA) Cc: Meese, Craig A.; Skiba, Kevin J. Subject: RE: New Well 10-403 Application-GO #6 Tom, For the GO #6 new drill well planned soon for the Ninilchik area, will Marathon still be ok with the short completion write-up in the drilling prognosis included with the drilling permit application rather than filing a Form 10-403 for the completion? We are still looking at running a CBL, jetting the well dry, and perforating the Tyonek interval. No stimulation is anticipated. Ken Ken D. Walsh 7/24/2007 • Senior Production Engineer Marathon Oil Company-Alaska Asset Team 907-283-1311 (office) 907-394-3060 (cell) • Page 2 of ~. From: Thomas Maunder [mailtoaom_maunder@adminstate.ak.us] Sent: Friday, March 09, 2007 11:24 AM To: Walsh, Ken Subject: Re: New Well 10-403 Application-GO #5 (207-001) Ken, Including the plans for after rig work in the drilling permit application will be fine. You mentioned that any drillout work will be with coil and that BOP tests are performed as required. With regard to send in those reports, I would expect that your Foreman would be in contact with the Inspectors regarding an opportunity to witness a BOP test. I don't know how often an Inspector might be able to witness a test, but I do know that they do witness an occasional coil test. I would think that your contractor as well as Marathon would maintain files with the test records. Good luck with the well operations. Call or message with any questions. Tom Maunder, PE AOGCC Walsh, Ken wrote, On 3/9/2007 10:49 AM: Tom, A couple of weeks back during one of our telephone conversations, the topic of filing a Form 10-403 application for new completions in the Ninilchik wells came up. I told you that Winton Aubert was not requiring Marathon to file the 10-403 in this case if it was a similar completion style to those in the past. He wanted a small description of the intended completion inserted in the drilling prognosis filed with the 10-401 for the well. This description would be something like what was placed in the Grassim Oskolkoff #5 and the Ninilchik State #3 drilling applications. The description for the NS #3 is as follows: The completion will encompass work to run a cement bond log, displace the KCL water in the wellbore with nitrogen, perforate several Tyonek intervals, and test the well for rate and pressure. No stimulation of the perforating intervals is anticipated. Therefore, Marathon has not been submitting a 10-403 for new well completions for our Ninilchik area wells but we do submit the 10-407 following the work. My question is how do you wish me to handle this in the future? We are currently setting up to drill out the DV tool and log the CBL on the GO #5 over this weekend. We do not intend to perforate for a week or two. Regards, 7/24/2007 Alaska Department of Natural Resources Land Administration System Page 1 of 3 _ .-~ ~- ,, ar;i ' ~~or .. ~ ~ ;. ~~~ :?s ~ . ~~,~r!te~'s Search State Cabins ~~tu~ ~4lC[~S Alaska DNR Case Summary File Type: ADL File Number: 389737 ~ Printable Case File_Summary. See Township, Range, Section and Acreage? * Yes fi No New Search 1_AS Menu I Case Abstract I Case Detail I Land Abstract ..»', Pile: _~DL 389737 ``'~~'_` Search for Status Plat Updates ids c,l 07.'1 ~%'00 L'zrslumer: 00015964? .ti~L~1I:1~~THON (AIL COMPANY' ATTN: CONTRACT DEPARTMENT P.O. BOX 68 HOUSTON TX 770010068 Case Type: r OIL & GAS LEASE COMP DNR Uiait: 780 OIL AND GAS File Location: DOG DN-OIL AND GAS Case Staters: 35 ISS/APPRV/ACTV RUTH Status Date: 11/21/?002 TotalAcres : 3095.550 Date Initiated: 10/31/2001 Office of Pr imary Resp orzsiliility : DOG DIV OIL AND GAS Lae[ 1 rcrosactio n Date: l 0/07/2005 Casc- Srrbtjpe: CI COOK INLET La.~~ ~Iransactiw ~: CCN CUSTOMER CH ANGED NAI~1L I~e~rfcli~~n.~ S Tue+~r~sltzp: OOIN Rart,~re: 01?~'<~ ~S'c<criurl.~ U(i Sec~rrurz ~lcr~~~~: 31 Plats :~~1C'17[~ILI71: ~ fOri'll.tijllj): ~~~~~ i~ R(ln~L': ~~~ ~'~~~ ,S('CIlOil: ~~7 ~S~BC/IU/1 ."~CYCS_ ~) ~1e'T1[ilclll: ~ T i11PnS~l/j): OO ~ ~ RCIn~>L': U~ j ~~' JeCt~O/1. ~) ~ ~S~'C'/IUI! '~C'YC,1" ~O0 Plats ilc~r~iciicrr~: S 7~~itnshij~: OOIN Run~c~: 01 ;~~' ,'~ectr<~rr: 02 Scrliun;lcr~s: 3~0 LlL'17[~lUil: ~ IOil'!l,1~{7lj~: O~_)~N [vCr)/mot: ~)1>~' ~~L'CllUll: ~)~ ,S('C/1071i~C'Y~',S: al~~rrclicrn: ~ l ~n~~rr.chi~: 01")1 N Run,~rc: 013 ~V Sc c~t~nrr: ] 0 .S~~c/i~~n .~~~~r~.~: 160 alerrcli~or: S Inirrislrii~: OOIN Rang: 013~t' S'ectirxl: II Sectiun.l~rc~~: 6~U ~1C'FlC~1Cln: ~ T(IbFi1,5{I7~); O~~N ~~a71~TC': Q~ i~' ~`1~c:C~1O/l: ~~ iS('C'tlUil:~(7'B~S: i0~ 1~~c°r•rc~~ur~: S 7~~tir~t,~~hii~: OOIN h~r~~5~~: O1>~~~ Scc~lron: 13 :5"cctinrl_-l~rc~s: Cleric/iajt: S Imr~r.c{lij~: OOiN R~rn~;c~: OliW' ~`~c~c~tion: 1~1 S'~~%tln/1.~c•rPS: >5~ ;blcridi<m: 5 7<nrrtsfiiR: OOIN Rans~Jc: Ol3~V Scc~li~in: 15 ,S`e~Iinn.~~rES: 6.10 Legal Description 10-31-?001 *'~ * CASE CREATED BY SEUREGATION FROMADL ~ 90 * * * * ~` UNITIZED AND LEASE LEGAL DESCRIPTION* Search Search http://www.dnr.state.ak.us/las/Case_Summary.cfm?FileType=ADL&FileNumber=3 89737... 7/17/2007 Alaska Department of Natural Resources Land Administration System Page 2 of 3 • • NINILCHIK UNIT UNIT TRACT 3 T. 1 N R. 13 W. SM SEC. 1: NI/2N1/2, SI/2NW1/=l, SWI/~1NEU~1, NI/2SW1/~, SW1/4SW1/4 SEC. 2: EI/2 SEC. 10: SEI/4 SEC'. 11: ALL SEC. 12: FRACT., NWI/~NWI/~, SI/2NW1/d, SI/2NE1/~, SI/2, EXCEPT THAT PORTION LYING ABOVE THE LINE OF MEAN HIGH TIDE. SEC. 13: FRACT., ALL, EXCEPT THAT PORTION LYING AI30VE THE LINE OF MEAN HIGH TIDE. SEC. 14: FRACT., ALL, EXCEPT THAT PORTION LYING ABOVE THE LINE OF MEAN HIGH TIDE. SEC. I5: FRACT., ALL T. 1 N, R. 12W, SM SEC. 6: FRACT., EI/2, EXCEPT THAT PORTIONLYING _ABOVE THE LINE OF MEAN HIGH TIDE. SEC. 7: FRACT., ALL, EXCEPT THAT PORTION LYING ABOVE THE LINE OF MEAN HIGH TIDE. CONTAINING 3095. S.5 ACRES, MORE OF LESS. 07/01/2003 * * * * * PARTICIPATING AREA ESTABLISHED * * * * * * * ~` * * * * ~` LEASE INCORPORATED IN PART INTO GRASSIM OSKOLKOFF PA NINILCHIK UNIT TRACT 3(PARTIAL) GRASSIM OSKOLKOFF PARTICIPATING (GOPA) T. IN, R. 13W, SM http://www.dnr. state.ak.us/las/Case_Summary.cfm?FileType=ADL&FileNumber=3 8973 7... 7/ 17/2007 Alaska Department of Natural Resources Land Administration System Page 3 of 3 • .SEC. 14: UNSURVEYED, S/2NW/d, NW/4SW/~, 120 ACRES; SEC. 1 ~: PROTRACTED, ALL EXCLUDING THE W/2NW/4, ~ 60 ACRES; CONTAINING 680.00 ACRES, MORE OR LESS. 07/01/?003 *~`***PARTICIPATINGAREAESTABLISHED *~~*********** LEASE INCORPORATED IN PART INTO FALLS CREEK PA NINILCHIK UNIT TRACT 3 (PARTIAL) FALLS CREEK PARTICIPATING AREA T. 1 N, R. 13 W, SM SEC. 1: PROTRACTED, NE/4SW/4, SW/4SW/~, CONTAINING 80 ACRES; SEC. 11: PROTRACTED, E/ONE/4, CONTAINING 80 ACRES; SEC. 12: UNSURVEYED, W/2NW/4, CONTAINING 80 ACRES; T. 1 N, R. 12W, SM SEC'. 6: UNSURVEYED, FRACTIONAL, THAT PART OF THE W/2NE/4 LYING BELOW THE LINE OF MEAN HIGH TIDE, 31.85 ACRES. CONTAINING 271.85 ACRES, MORE OR LESS. End ~` Case Summary Last updated on 07/17/2007. Not sure who to contact? Have a question about DNR? Visit the u.. blic I_nforrr~atort Center. Report technical problems with this page to the Webaster. Site optimized for Netscape 7, IE 6 or above. This site also requires that all CC3®~CIE. must be accepted. State of Alaska Natural Resources LAS Home Copyright Privacy System_Status http://www.dnr.state.ak.us/las/Case_Summary.cfm?FileType=ADL&FileNumber=3 89737... 7/17/2007 • • TRANSMITTAL LETTER CHECKLIST WELL NAME ~.e~tss/~1 C/-sir°l~e'D~~ '~~ PTD# 0.?o~4~O /_ Development Service Exploratory Stratigraphic Test Non-Conventional Well :Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and AP[ number (50- - -_) from records, data and logs acquired for well SPACING The permit iS approved subject to full. compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce /inject is contingent upon issuance of a conservation order approving a spacing exception.. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Non-Conventional production or production testing of coal bed methane is not allowed Well for (,name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing ro ram. Rev: 7/13/2007 • • ^^ ~ W ~ ~ ~ ~ ~ i ~ , N Q ~ ~ ~ N W ~ , ~ ~ O ~ , Y' , ~ a. , w d a : ~ w N 3 ~ °i m ° o . ° , ; , N n . ~''~ •y, o m. 4 E O ~' U y, O ~, O, u~ , f~6 Q1 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ O ~ V, p OL ~ N, ~ N: ~ ~ , a ~ ~ ~ ~ ~ °'' N, ~, ~' ~ N' 1°' ~ ~, ; ~ , , 3, m ; ~' ~ ~'' , V' f6' N' c f~ U: ~ C. a ~ N. O c a ~ ?~ r°~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ -6, ~ c: ~~ ~~~ 3 3~ ~~ , ~ ~ ~ ~~ ~ ~~ ~ Y : ~' c ' ~ ~ Z °o: N• ~ ~ ~ ~ ~ ~ ~ ~ ifT ~ ~ ~ ~ ° Z. m. h. N. 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