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196-067
XHVZE Pages NOT Scanned in this Well History File This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. / d./,'~ -- ~ ~ File Number of Well History File PAGES TO DELETE Complete RESCAN [] Color items - Pages: [] Grayscale, halftones, pictures, graphs, charts - Pages: n Poor Quality Original- Pages: [] Other- Pages: DIGITAL DATA Diskettes, No. Other, No/Type 'OVERSIZED .Logs of various kinds Other COMMENTS: Scanned b~~dred-D~reU~ Nathan Low~ll TO RE-SCAN Notes: MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON :OR BEFORE JANUARY 03, 2 001 M p L A T T H E E W IA L U N D t: R ISM ARK ER C:LORBMFILM.DOC Memorandum State of Alaska Oil and Gas Conservation Commi~ion To: Well File: ~o _ ~.~ ~:~/'~ DATE Re: Cancelled or Expired Permit Action EXAMPLE: Point McIntyre P2-36AXX API# 029-22801-95 This memo will remain at the front of the subject well file. Our adopted conventions for assigning AP! numbers, permit numbers and well names did not specifically address expired or cancelled permits. This omission has caused some inconsistencies i the treatment of these kinds of applications for permit to ddil. Operators have asked us to adopt formal procedures for this class of permit application in order to prevent future database disparities. If a permit expires or is cancelled by an operator, the permit number of the subject permit will remair unchanged. The AP! number and in some instances the well name reflect the number of preexistin reddils and or muitilaterais in a well. In order to prevent confusing a cancelled or expired permit witi' an active well or multilateral these case sensitive well identifiers will be changed for expired and cancelled applications for permits to ddil. The AP! number for this cancelled or expired permit is modified so the eleven and twelfth digits is 9,~ The well name for a cancelled or expired permit is modified with an appended xx. These procedures are an addendum to the APl numbenng methods descnbed in AOGCC staff rnemorancium "Multi-lateral (welibore segment) Ddiling Permit Procedures. revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician ~KA OIL AND GAS CONSERVATION COMMISSION t TONY KNOWLE$, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 April 4, 1996 Tim Schofield, Senior Dflg Engineer BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Milne Point Unit MPK-09 BP Exploration (Alaska) Inc. Permit No: 96-67 Sur. Loc. 3704'NSL, 2123'WEL, Sec. 3, T12N, R11E, UM Btrnhole Loc. 3501'NSL, 1241'WEL, Sec. 32, T13N, RILE, UM Dear Mr. Schofield: Enclosed is the approved application for permit' to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. David W. Jo ston BY ORDER OF TIlE COMMISSION dlffEnclosures CC: Department offish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill [] Redrilll-Illb. Type of well. Exploratory I-! Stratigraphic Test [] Development Oil [] Re-Entry [] DeepenI-II Service [] Development Gas [] Single Zone [] Multiple Zone[] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska)/nc P/an RTE = 62.2 f e et Mi/ne Point / Kuparuk River 3, Address 6. Property Designation P. O. Box 196612. Anchorage, Alaska 99519-6~12 ADL 028231 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025) 3704' NSL, 2123' WEL, SEC. 3, T12N, R11E Milne Point Unit At top of productive interval 8. Well number Number 3382' NSL, 1150' WEL, SEC. 32, T13N, R11E MPK-09 2S100302630-277 At total depth 9. Approximate spud date Amount 3501' NSL, 1241' WEL, SEC. 32, T13N, R11E 04/24/96 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property15. Proposed depth (MD and TVD) property line ADL 028232, 1241 feet MPK-05, 36' @ 1746'TVD feet 2560 10412' MD / 7271' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth ~ooo feet Maximum hole anglesd.4~ o Maximum surface 3005 psig At total depth (TVD) 7529'/3758 psig 18. Casing program Setting Depth s~ze Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 30" 20" 91.1# NTdOLHE Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 4030' 31' 31' 4061' 3578' 65osx PF 'E', a30 sx 'G', 250 sx PF 'C' 8-1/2" 7" 26# L-80 Mod B 10382' 30' 30' 10412' 7271' 405 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structural ~.~..~i'" ! '~!,/ ~-~ i:'-., Conductor ~[;.i'? i:'~-; i~'i, ; i.. Surface ~;: '~ '~" Intermediate Production i':'":' ~ ;:! '~ f-~ 'i !_) ~" .. Liner Perforation depth: measured ,~ ..... ~.., rtl; ~. ~ .... ,:_t.7:-::;. !-?.:~'~7;;© true vertical /',:i::'. ~:::t':_:':.. 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program [] Drilling fluid program [] Time vs depth pict [] Refraction analysis ~' Seabed report• 20 AAC 25.050 requirements[] 21. I hereby ~ that t~he foj'egoing~ i/~ true and correct to the best of my knowledge,P~-'~,oJr¥,~on.~-,~¢+-{br- Signed ~'f.~ --..~'~ Title Senior D#lling Engineer C..k~-~ $~- e_ ~-5~¢'lDate num e Commission Use Only P ermiL,N, umbe.r r ' IApproval date See cover letter - ~ 150- 1~'~' ?-';;;L'~(~ (o ~ I .~z.....~_ ~, for other requirements Conditions of approval Samples required [] Yes .[~]'No Mud Icg require, d, [] Yes J~ No Hydrogen sulfide measures [] Yes I~No Directional survey required ,[~ Yes [] No Required working pressure for BOPE [] 2M' []3M; J~5M; []10M; 1-115M; Other: Original Signed'By by order of~/~/~'/~D Approved by David W. Johnston Commissioner me commission Date Form 10-401 Rev. 12-1-85 Submit ir )licate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 2O AAC 25.005 la. Typeofwork Drill Id] Redrilll-lllb. TypeofwelI. Exploratory[] Stratigraphic Test[~ DevelopmentOil[] Re-Entry [] DeepenI-II Service [] Development Gas [] Single Zone [] Multiple Zone [] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc Plan RTE = 62.2 feet Milne Point / Kuparuk River 3. Address 6. Property Designation P. O. Box 196612, Anchorage, Alaska 99519-6612 '~ADL 028231 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025) 3704' NSL, 2123' WEL, SEC. 3, T12N, R11E Milne Point Unit At top of productive interval 8. Well number Number 3382' NSL, 1150' WEL, SEC. 32, T13N, R11E JMPK-09 2S100302630-277 At total depth 9. Approximate spud date Amount 3501'NSL, 1241' WEL, SEC. 32, T13N, R11E 04/24/96 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property15. Proposed depth (MD and TVD) property line ADL 028232, 1241 feet MPK-05, 36'@ 1746'TVD feet 2560 10412'MD/7271' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth ~ooo feet Maximum hole angle~8.4~ o Maximum surface 3005 psig At total depth (TVD) 7529'/3758 psig 18. Casing program Setting Depth raze Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 30" 20" 91.1# NTdOLHE Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 4030' 31' 31' 4061' 3578' 65o sx PF 'E', 830 sx 'G', 250 sx PF'C' 8-1/2" 7" 26# L-80 Mod B 10382' 30' 30' 10412' 7271' 405 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structural Conductor ~; :,'-i'~ !¢..~..~u. ~. 'i/' Surface i':~,, '!,.,, "~ Intermediate Production 0..'~ .""' 3 ¢ Liner ,:.,~-~.~ ~ .... Perforation depth: measured true vertical Al.._"',:~..'_a 0}', ": ..... 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program[] Drilling fluid program [] Time vs depth plot [] Refraction analysis[] Seabed reportl-] 20 AAC 25.050 requirementsl-I 21. I hereby certj.tu that the fol'egoing~i~ true and correct to the best of my knowledgeP~-'~,o~-¥.¢ond-~c+ Signed -'"'//.~ -...~'~ Title SeniorDrillin~1En~1ineer--.- // Commission Use Only ' Permit Number. J~PI number _ JApproval date JSee cover letter ¢/f~ .. f~ ? J5 0- ~ ), C/ .. 2, ~ (, (~ c/ J ~- ~.__ ¢ (~ Jfor other requirements Conditions of approval Samples required [] Yes [~NO Mud log required E_lYes E;~No Hydrogen sulfide measures [] Yes ~ No Directional survey required ~ Yes [] No Required working pressure for BOPI~ [] 2M; 1-13M; J~5M; I-I10M' []15M; Other: ~,~ ,glna~ Signed' By by order ofI/I/! Approved by .)avid W. Johnston Commissioner me commission Date -- Form 10-401 Rev. 12-1-85 Submit in 'iplicate I Well Name: I MPK-9 I Well Plan Summary ]Type of Well (producer or injector): ] Kupamk Producer Surface Location: 3704' FSL 2123' FEL Sec 3 T12N R11E UM., AK. Target Location: 3382' FSL 1150' FEL Sec 32 T13N R11E UM., AK. Bottom Hole 3501' FSL 1241' FEL Sec 32 T13N Rile UM., AK. Location: Note: Target & BHL footages are based on assumed true and square sections and are not surveyed legal locations. I AFE Number: 1337030 ] I Rig: I Nabors 27E I Estimated Start Date: ]April 24, 1996 I Operating days to drill and case: IMD: I10412' I ITvD: 17271'BKB I I~C~: 16]'1 Well Design (conventional, slimhole, I Ultra Slimhole, 7" Longstring etc.): I Formation Markers: Formation Tops MD TVD Formation Pressure/EMW Base permafrost 1815 1811 n/a NA (Top Schrader) 5976 4581 1905 psi# / 8.0 ppg OA 4631 1955 psig/ 8.0 ppg Base Schrader Bluff 6387 4796 1995 psi# / 8.0 ppg Top HRZ 9324 6391 n/a Base HRZ 6601 n/a Kupark D Shale 9838 6781 n/a Kupamk C 10112 7011 3650 psi# / 10 ppg TKB8 7056 3669 psi# / 10 ppg Total Depth 10412 7271 n/a Casin TTubin:, Pro ,ram. Hole Csg/ Wt/Ft Grade Conn Length Top Btm Size Tbg MD/TVD MD/TVD O.D. 30" 20" 91.1# NT80LHE weld 80 32' 112/112 12 1/4" 9 5/8" 40# L-80 Nrc 4030 31' 4061/3578 8 1/2" 7" 26# L-80 Mod B 10382 30' 10412/7271 N/A (tbg) 2-7/8" 6.5# L-80 EUE 9809 29' 9838/6781 8rd Internal yield pressure of the 7" 26g casing is 7240 psi. Worst case surface pressure would occur with a full column of gas to the reservoir at 7529' TVDSS. Maximum anticipated surface pressure in this case assuming a reservoir pressure of 3758 psi is 3005 psi, well below the internal yield pressure rating of the 7" casing. The Modified Buttress 7" 26# will be run on bottom. Logging Prol I Open Hole Logs: ,ram. IMud Logs & Samples Surface MWD - CDR. Schrader Bluff Final CDR- CDN- MWD None required AP1 # 50-029-22XXX March 27, 1996 I Well Name: I MPK-9 I Well Plan Summary I Type of Well (producer or injector): I Kuparuk Producer Surface Location: 3704' FSL 2123' FEL Sec 3 T12N Ri 1E UM., AK. Target Location: 3382' FSL 1150' FEL Sec 32 T13N RllE UM., AK. Bottom Hole 3501' FSL 1241' FEL Sec 32 T13N R11E UM., AK. Location: Note: Target & BHL footages are based on assumed true and square sections and are not surveyed legal locations. I aFE Number: 1337030 I I Rig: l Nabors27E I IEstimated Start Date: I April 24, 1996 IOperating days to drill and case: 113 I IMD: I 10412' I I TVD: 17271' BKB I I KBE: I61' I Well Design (conventional, slimhole, I UltraSlimhole, 7" Longstring etc.): I Formation Markers: Formation Tops MD TVD Formation Pressure/EMW Base permafrost 1815 1811 n/a NA (Top Schrader) 5976 4581 1905 psig / 8.0 ppg OA 4631 1955 psig / 8.0 ppg Base Schrader Bluff 6387 4796 1995 psig / 8.0 ppg Top HRZ 9324 6391 n/a Base HRZ 6601 n/a Kupark D Shale 9838 6781 n/a Kuparuk C 10112 7011 3650 psig / 10 ppg TKB8 7056 3669 psig / 10 ppg Total Depth 10412 7271 n/a Casing/Tubing Program: Hole Csg/ Wt/Ft Grade Conn Length Top Btm Size Tbg MD/TVD MD/TVD O.D. 30" 20" 91.1# NT80LHE weld 80 32' 112/112 12 1/4" 9 5/8" 40# L-80 btrc 4030 31' 4061/3578 8 1/2" 7" 26# L-80 Mod B 10382 30' 10412/7271 N/A (tbg) 2-7/8" 6.5# L-80 EUE 9809 29' 9838/6781 8rd Internal yield pressure of the 7" 26# casing is 7240 psi. Worst case surface pressure would occur with a full column of gas to the reservoir at 7529' TVDSS. Maximum anticipated surface pressure in this case assuming a reservoir pressure of 3758 psi is 3005 psi, well below the internal yield pressure rating of the 7" casing. The Modified Buttress 7" 26# will be run on bottom. Logging Program: I Open Hole Logs: Surface Schrader Bluff Final IMud Logs & Samples MWD - CDR. ,~:~...~. ~.,.~: r'"' '-~'" CDR - CDN - MWD None required i',,,~' ), il '~',. AP1 # 50-029-22XXX March 27, 1996 Mud Program: Special design considerations Hydrates LSND freshwater mud. Special attention to gravel and coal in the surface hole, with appropriate viscosity and weight to control each. The use of frequent short trips as per the updated pad data sheet are encouraged. We will have hydrates on K Pad. We will have our mud weight to 11 PPG by 2000 feet. We will weight up in 0.5 ppg increments if necessary. We will use the coldest mix water available to minimize warm/ng in the interval. We will use only 8" directional motors to allow lower flow rates. We will control flow rates to 450 to 600 GPM when hydrates are present to keep mud temperatures to a minimum. We will control drilling rate and keep mud viscosity at 100 sec/qt to keep the hole clean. Surface Mud Properties: I Spud Mud Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.6 80 15 8 10 9 8 to to to to to to to 11.5 100 35 15 30 10 15 Production Mud Properties: ]LSND Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 9.0 40 15 3 7 8.5 6-10 to to to to to to to 10.5 50 20 10 20 9.5 4 - 6 Well' Control: Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Diverter, BOPE and drilling fluid system schematics on file with AOGCC. Directional: IKOP: 11000' Maximum Hole Angle: Maximum Dog Leg: Inclination in target: Closet Approach Well: 58.41 degrees _< 4 degrees 30 Degrees MPK-05 is 36 feet at 1746 TVD. The closet well for drilling MPK-9 is the current plan profile for MPK-05. This will be treated as a shut in well. This will allow MPK-9 wellpath to be drilled as per BP's close approach guidelines. The well path should be followed as close as possible to ensure we do not compromise the proximity tolerances. FREEZE PROTECTION: Pay close attention to annulii being used for disposal so to avoid freezing. Sometimes the annulii are kept open by ensuring that an adequate volume (+60 bbls) is injected every 6-12 hours. This practice is more economical than pumping 60 bbls of diesel freeze protection every time the pumps are shut down; however, if this practice is used, it is important that the injection frequency into the annulus be adequate to prevent freeze ups -- the drillers must communicate to each other the last time the annunlus was injected into to avoid freezing. AP1 # 50-029-22XXX March 27, 1996 Mud Program: Special design considerations Hydrates LSND freshwater mud. Special attention to gravel and coal in the surface hole, with appropriate viscosity and weight to control each. The use of frequent short trips as per the updated pad data sheet are encouraged. We will have hydrates on K Pad. We will have our mud weight to 11 PPG by 2000 feet. We will weight up in 0.5 ppg increments if necessary. We will use the coldest mix water available to minimize warming in the interval. We will use only 8" directional motors to allow lower flow rates. We will control flow rates to 450 to 600 GPM when hydrates are present to keep mud temperatures to a minimum. We will control drilling rate and keep mud viscosity at 100 sec/qt to keep the hole clean. Surface Mud Properties: I SpudMud Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.6 80 15 8 10 9 8 to to to to to to to 11.5 100 35 15 30 10 15 Production Mud Properties: I LSND Density Marsh Yield 10 sec 10 rain pH Fluid (PPG) Viscosity Point gel gel Loss 9.0 40 15 3 7 8.5 6-10 to to to to to to to 10.5 50 20 10 20 9.5 4 - 6 Well Control: Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Diverter, BOPE and drilling fluid system schematics on file with AOGCC. Directional: IKOP: I 1000' Maximum Hole Angle: 58.41 degrees Maximum Dog Leg: < 4 degrees Inclination in target: 30 Degrees Closet Approach Well: MPK-05 is 36 feet at 1746 TVD. The closet well for drilling MPK-9 is the current plan profile for MPK-05. This will be treated as a shut in well. This will allow MPK-9 wellpath to be drilled as per BP's close approach guidelines. The well path should be followed as close as possible to ensure we do not compromise the proximity tolerances. FREEZE PROTECTION: Pay close attention to annulii being used for disposal so to avoid freezing. Sometimes the annulii are kept open by ensuring that an adequate volume (+60 bbls) is injected every 6-12 hours. This practice is more economical than pumping 60 bbls of diesel freeze protection every time the pumps are shut down; however, if this practice is used, it is important that the injection frequency into the annulus be adequate to prevent freeze ups -- the drillers must communicate to each other the last time the annunlus was injected into to avoid freezing. AP1 # 50-029-22XXX March 27, 1996 Disposal: Cuttings Handling: Cuttings should be hauled to the ball mill at CC-2A. pit can be opened in emergencies by notifying Karen Thomas (564-4305) The Milne Point reserve with request. Fluid Handling: All drilling and completion fluids can be annular injected after allowing the cement on the 7" casing cement job to cure 6 hours following CIP. Request for AOGCC Approval Disposal of Drilling Wastes (20AAC25.254) 1. Approval is requested for Annular Pumping for K 9 well to be drilled, and any well on the pad/drillsite previously permitted for disposal activities by AGOCC. 2. The Base of the Permafrost for all wells located in the Milne Point Unit is 1750 feet. Aquifers in the Milne Point Unit have been exempted from Class II injection activities by the AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. 3. The receiving zone to which the fluids will migrate is identified as the Prince Creek geological formation at-2500 - 3300' TVD. The confining layer is the Sagavanirktok Shale defined by logs between 2500 'TVD. Additional data which demonstrates the confining layers, porosity, and permeability of the injection zone was submitted to the AOGCC on 7-24-95. 4. There are no wells on Milne Point K Pad. There may be additional unidentified wells within a quarter mile distance from the subject well. There are no domestic or industrial water use wells located within one mile of the project area. 5. The drilling wastes to be disposed of during this operations can be defined as drilling mud, cement contaminated drilling mud, and drill cuttings; rig wash fluid (inclusive of rig boiler blow down, and mud and cement rinse water of associated rig equipment, completion fluids (seawater and brine), formation fluids, reserve pit fluids, and drill rig domestic waste water. (Note: if you plan to dispose of fluids OTHER than those outlined above you must list them on the request) The maximum volume to be disposed of in the annulus is 35,000 bbls. Fluid densities will range from 8.3 to 13.0 ppg. Any deviation from this program must be detailed separately. 6. The 9.625 "surface casing shoe will set at 3500'md 3500 ('tvd) and cemented with 691 "E" and 250 "G" sacks cement. This depth is below the base of the permafrost (1750' TVD) and into the top of the Prince Creek formation which has a long established history of annular pumping at Milne Point. The break down pressure of the Prince Creek formation is 13 to13.5 ppg equivalent mud weight. 7. The burst rating (80%) for the 9.625" 40# 'surface casing is4600 psi. The collapse rating (80%) for the7" 26# 'intermediate/production casing is 4325 psi. 8. The Maximum Allowable Surface Pressure while annular pumping is the lesser of 2000 psi or the calculated pressure according to the following equation: MASP (psi) = (Max Breakdown ppg-8.3 ppg) X 0,052 X Surf Csg Shoe TVD MASP (psi) = 855 psi 9. The maximum pressure imposed at the surface casing shoe is calculated according to the following equation: Max Press @ Surf Csg Shoe (psi) = .052 x Max Breakdown ppg x Surf Csg Shoe TVD Max Prss at Surf Csg Shoe =2457 psi This pressure is less than the 80% burst and collapse casing pressures calculated in #7. 1 0. Additional data supplied as needed. DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS. AREA WELL PREV VOL PERMITTED PERMITTED DATI~"" INJECTED (BBL) VOL (ESL) Milne Point MPK-17 0 35,000 2/16/96 - 2/16/97 Milne Point MPK-25 0 35,000 2/15/96 - 2/15/97 Milne Point MPK-38 0 35,000 3/4/96 - 3/4/97 Milne Point MPK-18 0 35,000 3/7/96 - 3/7/97 Milne Point MPK-37 0 35,000 3/13/96 - 3/13/97 Milne Point MPK-10 0 35,000 3/13/96 - 3/13/97 Milne Point MPK-05 0 35,000 Requested Milne Point M P K- 9 0 35,000 Requested API # 50-029-22XXX March 27, 1996 Disposal: Cuttings Handling: Cuttings should be hauled to the ball mill at CC-2A. pit can be opened in emergencies by notifying Karen Thomas (564-4305) The Milne Point reserve with request. Fluid Handling: All drilling and completion fluids can be annular injected after allowing the cement on the 7" casing cement job to cure 6 hours following CIP. Request for AOGCC Approval Disposal of Drilling Wastes (20AAC25.254) 1. Approval is requested for Annular Pumping for K 9 well to be drilled, and any well on the pad/drillsite previously permitted for disposal activities by AGOCC. 2. The Base of the Permafrost for all wells located in the Milne Point Unit is 1750 feet. Aquifers in the Milne Point Unit have been exempted from Class II injection activities by the AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. 3. The receiving zone to which the fluids will migrate is identified as the Prince Creek geological formation at 2500 - 3300' TVD. The confining layer is the Sagavanirktok Shale defined by logs between 2500 'TVD. Additional data which demonstrates the confining layers, porosity, and permeability of the injection zone was submitted to the AOGCC on 7-24-95. 4. There are no wells on Milne Point K Pad. There may be additional unidentified wells within a quarter mile distance from the subject well. There are no domestic or industrial water use wells located within one mile of the project area. 5. The drilling wastes to be disposed of during this operations can be defined as drilling mud, cement contaminated drilling mud, and drill cuttings; rig wash fluid (inclusive of rig boiler blow down, and mud and cement rinse water of associated rig equipment, completion fluids (seawater and brine), formation fluids, reserve pit fluids, and drill rig domestic waste water. (Note: if you plan to dispose of fluids OTHER than those outlined above you must list them on the request) The maximum volume to be disposed of in the annulus is 35,000 bbls. Fluid densities will range from 8.3 to 13.0 ppg. Any deviation from this program must be detailed separately. 6. The 9.625 "surface casing shoe will set at 3500'md 3500 ('tvd) and cemented with 691 "E" and 250 "G" sacks cement. This depth is below the base of the permafrost (1750' TVD) and into the top of the Prince Creek formation which has a long established history of annular pumping at Milne Point. The break down pressure of the Prince Creek formation is 13 to13.5 ppg equivalent mud weight. 7. The burst rating (80%) for the 9.625" 40# 'surface casing is4600 psi. The collapse rating (80%) for the7" 26# 'intermediate/production casing is 4325 psi. 8. The Maximum Allowable Surface Pressure while annular pumping is the lesser of 2000 psi or the calculated pressure according to the following equation: MASP (psi) = (Max Breakdown ppg-8.3 ppg) X 0.052 X Surf Csg Shoe TVD MASP (psi) - 855 psi . equation: Max Press @ Surf Csg Shoe (psi) = .052 x Max Breakdown ppg x Surf Csg Shoe TVD Max Prss at Surf Csg Shoe =2457 psi This pressure is less than the 80% burst and collapse casing pressures calculated in #7. The maximum pressure imposed at the surface casing shoe is calculated according to the following 1 0. Additional data supplied as needed. DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS. AREA WELL PREV VOL PERMITTED INJECTED (BBL) VOL (BBL) Milne Point MPK-17 0 35,000 2/16/96 - 2/16/97 Milne Point MPK-25 0 35,000 2/15/96 - 2/15/97 Milne Point MPK-38 0 35,000 3/4/96 - 3/4/97 Milne Point MPK-18 0 35,000 3/7/96 - 3/7/97 Milne Point MPK-37 0 35,000 3/13/96 - 3/13/97 Milne Point MPK-10 0 35,000 3/13/96 - 3/13/97 Milne Point M P K-05 0 35,000 Requested Milne Point M P K-9 0 35,000 Requested AP1 # 50-029-22XXX March 27, 1996 DRILLING HAZARDS AND RISKS: See both the NEW Milne Point K-Pad Data Sheet prepared by Pete Van Dusen for information on the Cascade wells , and review recent wells drilled on E Pad. Most of the trouble time on recent wells has been due to formation drilling problems such as hydrates and stuck pipe associated with the coal and gravel intervals. Hydrates We will have hydrates on K Pad. We will have our mud weight to 11 PPG by 2000 feet. We will weight up in 0.5 ppg increments if necessary. We will use the coldest mix water available to minimize warming in the interval. We will use only 8" directional motors to allow lower flow rates. We will control flow rates to 450 to 600 GPM when hydrates are present to keep mud temperatures to a minimum. We will control drilling rate and keep mud viscosity at 100 sec/clt to keep the hole clean. The MPU PE group will be perforating, and cleaning out wells shortly after the rig drills and completes them. This will make the near rig area congested and as a result potentially hazardous. Ensure personnel use caution moving around adjacent production activities. Lost Circulation: The Kuparuk sands and a number of shallower intervals typically are highly fractured. We will be setting casing above the Schrader Bluff interval which might break down at the mud weights required to TD the well, so close attention to mud volumes is critical. Stuck Pipe Potential: We were stuck on MPK-17 on the trip out to run surface casing. It appears the well had washed out a coal bed, which then accumulated gravel from the deeper'drilling intervals. With higher mud viscosities we will reduce the chance for this to occur. With shallow set surface casing, we will have a higher risk of getting stuck both while drilling and running casing. Close attention to torque and drag with downhole weight and torque sub will minimize this risk while drilling. Of particular concern is the interval just above the Kuparuk, where we will be weighting up just prior to entering the reservoir. We also will have the shallow formations exposed which might become differentially stuck. Using the top drive packoff while running casing, and filling casing every joint while lowering will minimiZe this risk while running casing. Kick Tolerance: The surface casing setting depth for this well allows a kick tolerance of 54.2 bbl influx (Gas) based on a 12.5 ppg LOT at the 9-5/8" casing shoe and a estimated reservoir pressure of 3646 psig (10 ppg equivalent MW). Trip Schedules are required for all trips. All trips will be performed with a trip tank or one pit isolated for use as a trip tank. Formation Pressure: The maximum expected pore pressure for this well is 10 ppg EMW (3646 psi @ 7011' ssTVD). There has been no injection in this region since then, therefore the reservoir pressure should not exceed this estimate. We will continue to take the conservative approach to circulate the well until stable before tripping or before running casing. When this occurs, the drilling superintendent should always be quickly notified and kept appraised. WATER USAGE Have the water truck drivers track the water usage on a daily log. Send a copy of this log to Dennise Casey in the Anchorage Office on a monthly basis. API # 50-029-22XXX March 27, 1996 DRILLING HAZARDS AND RISKS: See both the NEW Milne Point K-Pad Data Sheet prepared by Pete Van Dusen for information on the Cascade wells , and review recent wells drilled on E Pad. Most of the trouble time on recent wells has been due to formation drilling problems such as hydrates and stuck pipe associated with the coal and gravel intervals. Hydrates We will have hydrates on K Pad. We will have our mud weight to 11 PPG by 2000 feet. We will weight up in 0.5 ppg increments if necessary. We will use the coldest mix water available to minimize warming in the interval. We will use only 8" directional motors to allow lower flow rates. We will control flow rates to 450 to 600 GPM when hydrates are present to keep mud temperatures to a minimum. We will control drilling rate and keep mud viscosity at 100 sec/qt to keep the hole clean. The MPU PE group will be perforating, and cleaning out wells shortly after the rig drills and completes them. This will make the near rig area congested and as a result potentially hazardous. Ensure personnel use caution moving around adjacent production activities. Lost Circulation' The Kuparuk sands and a number of shallower intervals typically are highly fractured. We will be setting casing above the Schrader Bluff interval which might break down at the mud weights required to TD the well, so close attention to mud volumes is critical. Stuck Pipe Potential: We were stuck on MPK-17 on the trip out to run surface casing. It appears the well had washed out a coal bed, which then accumulated gravel from the deeper drilling intervals. With higher mud viscosities we will reduce the chance for this to occur. With shallow set surface casing, we will have a higher risk of getting stuck both while drilling and running casing. Close attention to torque and drag with downhole weight and torque sub will minimize this risk while drilling. Of particular concern is the interval just above the Kuparuk, where we will be weighting up just prior to entering the reservoir. We also will have the shallow formations exposed which might become differentially stuck. Using the top drive packoff while running casing, and filling casing every joint while lowering will minimize this risk while running casing. Kick Tolerance: The surface casing setting depth for this well allows a kick tolerance of 54.2 bbl influx (Gas) based on a 12.5 ppg LOT at the 9-5/8" casing shoe and a estimated reservoir pressure of 3646 psig (10 ppg equivalent MW). Trip Schedules are required for all trips. All trips will be performed with a trip tank or one pit isolated for use as a trip tank. Formation Pressure: The maximum expected pore pressure for this well is 10 ppg EMW (3646 psi @ 7011' ssTVD). There has been no injection in this region since then, therefore the reservoir pressure should not exceed this estimate. We will continue to take the conservative approach to circulate the well until stable before tripping or before running casing. When this occurs, the drilling superintendent should always be quickly notified and kept appraised. WATER USAGE Have the water truck drivers track the water usage on a daily log. Send a copy of this log to Dennise Casey in the Anchorage Office on a monthly basis. AP1 # 50-029-22XXX March 27, 1996 MP K-9 Proposed Summary of Operations , , . 4, . . 10. 11. 12. 13. 14. 15. 16. 17. 18. Drill and Set 20" Conductor. Weld an FMC landing ring for the FMC Gen 5A Wellhead on the conductor. Prepare location for rig move. MIRU Nabors 27E drilling rig. Prior to spud, discuss hydrates drilling as part of our PJSM. NU and function test 20" Diverter system. Ensure the diverter is as per AOGCC specifications and is approved by AOGCC supervisor. Build Spud Mud. Drill 12-1/4" surface hole to 4061' md (3578' tvd). Use extreme caution while drilling through the known hydrate interval down to 3100 feet. Run open hole logs. Check cement volumes with OH log caliper. Run and cement 9-5/8" casing. ND 20" Diverter, NU and Test 13-5/8" BOPE. Run Wear Bushing. RIH w/PDC bit and Double Power Section PDM (motor). Test the 9-5/8" casing to 3000 psig and plot pressure vs volume for LOT baseline. Drill out float equipment and 10 feet of new formation, Perform a LOT to a maximum of 12.5 ppg as per Recommended Practices Manual. Record pressure vs. cumulatrive volume for LOT test for well f'fle. Follow Pad Data Sheet short trip guidelines. Drill 8-1/2" hole to TD at 10412' MD (7271' TVD). (Note: This hole section will be logged with LWD Triple Combo (GR/Res/Neu/Dens). Use due caution while drilling with shallow set surface casing for both stuck pipe and well control issues. Pull Wear Bushing, and Change Pipe Rams to 7". Run and Cement 7" casing with 1 stage cement program. Test casing to 3500 psi and freeze protect wellbore to 100' TVD by displacing with air. Closely monitor casing running loads for drag. ND BOPE and NU dry hole tree. Release rig. Note: This well will be ROPE perforated, and cleaned out with a completion rig and prior to running the ESP completion. MIRU workover completion unit. ND dry hole tree. NU BOPs and test. PU and RIH with 3.5" DP and 6" bit, clean out to PBTD. TOOH. PU and RIH with perforating string (procedure to be distributed later with perforation intervals). PU and RIH with 2-7/8" EUE 8rd tubing with Electric Submersible Pump (ESP) completion. Set 2 way check. ND BOPE and NU tree and test. Pull two way check, freeze protect, set BPV, close valves. Test tree. RDMO with workover/completion rig. POST RIG WORK , Complete the handover form and turn it and the well files over to production. Turn over the well files along with the handover form. 2. A SBT/GR/CCL is not required on this well. o An adequate volume to cOver 2000' of diesel needs to be injected down the 7" X 9-5/8" annulus before moving the rig off the well. Please note type and volume of freeze protection pumped down the outer annulus on the morning report. . The rig will not complete this well. PEs will perforate and clean out this well with a pulling unit. API # 50-029-22XXX ~I .... ~,,~ (ii'; ~.': ??.:; ('' "';' 1,1¢',4) '~'- "' March 27, 1996 MP K-9 Proposed Summary of Operations o , , o 10. 11. 12. 13. 14. 15. 16. 17. 18. Drill and Set 20" Conductor. Weld an FMC landing ring for the FMC Gen 5A Wellhead on the conductor. Prepare location for rig move. MIRU Nabors 27E drilling rig. Prior to spud, discuss hydrates drilling as part of our PJSM. NU and function test 20" Diverter system. Ensure the diverter is as per AOGCC specifications and is approved by AOGCC supervisor. Build Spud Mud. Drill 12-1/4" surface hole to 4061' md (3578' tvd). Use extreme caution while drilling through the known hydrate interval down to 3100 feet. Run open hole logs. Check cement volumes with OH log ~ caliper. Run and cement 9-5/8" casing. ND 20" Diverter, NU and Test 13-5/8" BOPE. Run Wear Bushing. RIH w/PDC bit and Double Power Section PDM (motor). Test the 9-5/8" casing to 3000 psig and plot pressure vs volume for LOT baseline. Drill out float equipment and 10 feet of new formation, Perform a LOT to a maximum of 12.5 ppg as per Recommended Practices Manual. Record pressure vs. cumulatrive volume for LOT test for well file. Follow Pad Data Sheet short trip guidelines. Drill 8-1/2" hole to TD at 10412' MD (7271' TVD). (Note: This hole section will be logged with LWD Triple Combo (GR/Res/Neu/Dens). Use due caution while drilling with shallow set surface casing for both stuck pipe and well control issues. Pull Wear Bushing, and Change Pipe Rams to 7". Run and Cement 7" casing with 1 stage cement program. Test casing to 3500 psi and freeze protect wellbore to 100' TVD by displacing with air. Closely monitor casing running loads for drag. ND BOPE and NU dry hole tree. Release rig. Note: This well will be ROPE perforated, and cleaned out with a completion rig and prior to running the ESP completion. MIRU workover completion unit. ND dry hole tree. NU BOPs and test. PU and RIH with 3.5" DP and 6" bit, clean out to PBTD. TOOH. PU and RIH with perforating string (procedure to be distributed later with perforation intervals). PU and RIH with 2-7/8" EUE 8rd tubing with Electric Submersible Pump (ESP) completion. Set 2 way check. ND BOPE and NU tree and test. Pull two way check, freeze protect, set BPV, close valves. Test tree. RDMO with workover/completion rig. POST RIG WORK , Complete the handover form and turn it and the well files over to production. Turn over the well files along with the handover form. 2. A SBT/GR/CCL is not required on this well. . An adequate volume to cover 2000' of diesel needs to be injected down the 7" X 9-5/8" annulus before moving the rig off the well. Please note type and volume of freeze protection pumped down the outer annulus on the morning report. . The rig will not complete this well. PEs will perforate and clean out this well with a pulling unit. API # 50-029-22XXX MPK-9 WELL 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON CASING SIZE: 9-5/8" CIRC. TEMP 80 deg F at 4000' TVDSS. SPACER: 70 bbls NSCI Spacer weighted to 12 ppg LEAD CEMENT TYPE: Type E Permafrost ADDITIVES: Retarder WEIGHT: 12.0 ppg YIELD: 2.17 ft3/sx MIX WATER: 11.63 gal/sk APPROX #SACKS: 650 THICKENING TIME: Greater than 4 hrs at 50° F. TAIL CEMENT TYPE: Premium G ADDITIVES: 0.2% CFR-3, 0.2% Halad-344, 2.0% CaC12 WEIGHT: 15.8 ppg APPROX #SACKS: 830 FLUID LOSS: 100-150 cc YIELD:I.15 ft3/sx MIX WATER: 5.0 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. FREE WATER: 0 TOP JOB CEMENT TYPE: Type C Permafrost ADDITWES: Retarder WEIGHT: 15.6 ppg YIELD: 0.95 cu ft/sk. MIX WATER: 3.75 gal/sk APPROX NO SACKS: 250 CENTRALIZER PLACEMENT: 1. 1 TURBULATOR centralizer per joint of 9-5/8" casing on the bottom 10 joints above the FS. 2. 1 TURBULATOR centralizer per joint of 9-5/8" casing from 2000 to 2500 feet. OTHER CONSIDERATIONS: This well is being drilled after MPK-25 was suspended following problems with the surface casing job. We cannot overstress the importance of getting a sucessful cement job on the well. There are changes to the spacer, cement volumes and centralizer program on this well. Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 12 bpm. Do not overdisplace by more than 1/2 the shoe joint. Mix slurry on the fly -- batch mixing is not necessary. Make sure to fill the casing every joint to avoid having to shut down to fill the casing. Casing has been stuck while the rig was shut down filling only 5 joints. CEMENT VOLUME: 1. The Tail Slurry volume is increased to 830 sacks is calculated to cover the 9-5/8" to 1800 feet with 30% excess. 2. The Lead Slurry volume is calculated to cover from the top of the Tail Slurry surface with 150% excess. 3. 80'md 9-5/8", 40# capacity for float joints is 6 BBL. 4. Top Job PF "C" Cement Volume is 250 sacks. AP1 # 50-029-22XXX March 27, 1996 MPK-9 WELL 9-5/8" SURFACE CASING CEMENT PROGRAM- HALLIBURTON CASING SIZE: 9-5/8" CIRC. TEMP 80 deg F at 4000' TVDSS. SPACER: 70 bbls NSCI Spacer weighted to 12 pp.~ LEAD CEMENT TYPE: Type E Permafrost ADDITIVES: Retarder WEIGHT: 12.0 ppg YIELD: 2.17 ft3/sx MIX WATER: 11.63 gal/sk APPROX #SACKS: 650 THICKENING TIME: Greater than 4 hrs at 50° F. TAIL CEMENT TYPE: Premium G ADDITIVES: 0.2% CFR-3, 0.2% Halad-344, 2.0% CaC12 WEIGHT: 15.8 ppg APPROX #SACKS: 830 FLUID LOSS: 100-150 cc YIELD:I.15 ft3/sx MIX WATER: 5.0 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. FREE WATER: 0 TOP JOB CEMENT TYPE: Type C Permafrost ADDITIVES: Retarder WEIGHT: 15.6 ppg YIELD: 0.95 cu ft/sk. MIX WATER: 3.75 gal/sk APPROX NO SACKS: 250 CENTRALIZER PLACEMENT: 1. 1 TURBULATOR centralizer per joint of 9-5/8" casing on the bottom 10 joints above the FS. 2. 1 TURBULATOR centralizer per joint of 9-5/8" casing from 2000 to 2500 feet. OTHER CONSIDERATIONS: This well is being drilled after MPK-25 was suspended following problems with the surface casing job. We cannot overstress the importance of getting a sucessful cement job on the well. There are changes to the spacer, cement volumes and centralizer program on this well. Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 12 bpm. Do not overdisplace by more than 1/2 the shoe joint. Mix slurry on the fly -- batch mixing is not necessary. Make sure to fill the casing every joint to avoid having to shut down to fill the casing. Casing has been stuck while the rig was shut down filling only 5 joints. CEMENT VOLUME: 1. The Tail Slurry volume is increased to 830 sacks is calculated to cover the 9-5/8" to 1800 feet with 30% ex_.cas~ ~ " 2. ~ad Slurry volume is calculated to cover from the top of the Tail Slurry surface with 150% excess. 3. 80'md 9-5/8", 40# capacity for float joints is 6 BBL. 4. Top Job PF "C" Cement Volume is 250 sacks. _ .- AP1 # 50-029-22XXX March 27, 1996 MPK.9 7" PRODUCTION CASING CEMENT PROGRAM- HALLIBURTON STAGE I CEMENT JOB ACROSS THE KUPARUK and SCHRADER BLUFF: CIRC. TEMP: 115° F BHST 120 deg F at 7040' TVDSS. SPACER: 50 bbls fresh water . 70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0 ppg above current mud weight. CEMENT TYPE: Premium G ADDITIVES: 0.3% CFR-3; 15#/SK Silicalite, 0.8% Halad 344 WEIGHT: 13.1 ppg YIELD: 2.05 cu ft/sk APPROX # SACKS: 405 FLUID LOSS: < 40cc/30 min @ 114° F MIX WATER: 11.0 gal/sk THICKENING TIME: 4:14 hrs @ 114° F FREE WATER: 0cc @ 45 degree angle. Be sure to displace cement with kill weight brine. CENTRALIZER PLACEMENT: 1. 7"x 8-1/4" Straight Blade Rigid Centralizers-- two per joint on the bottom 17 joints of 7" Casing (57 total). This will cover 200' above the C Sand. 2. 7" x 8-1/4"Straight Blade Rigid Centralizers-- one per joint from 6900' - 6100' to cover the Schrader Bluffs Sands (25Total). 3. Run one 7" x 8-1/4"Straight Blade Rigid Centralizer inside the 9-5/8" casing shoe. 4. Total 7" x 8-1/4" Straight Blade Rigid Centralizers needed is 55. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 10 bpm. Batch mixing is not necessary. We will have displaced cement to above the Schrader Bluff top with this single stage. CEMENT VOLUME: 1. Stage 1 cement volume is calculated to cover 500' md above the NA Top with 30% excess. AP1 # 50-029-22XXX March 27, 1996 MPK-9 7" PRODUCTION CASING CEMENT PROGRAM- HALLIBURTON STAGE I CEMENT JOB ACROSS THE KUPARUK and SCHRADER BLUFF: CIRC. TEMP: 115° F BHST 120 deg F at 7040' TVDSS. SPACER: 50 bbls fresh water . 70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0 ppg above current mud weight. CEMENT TYPE: Premium G ADDITIVES: 0.3% CFR-3; 15#/SK Silicalite, 0.8% Halad 344 WEIGHT: 13.1 ppg YIELD: 2.05 cu ft/sk APPROX 4/ SACKS: 405 FLUID LOSS' < 40cc/30 min @ 114° F MIX WATER: 11.0 gal/sk THICKENING TIME: 4:14 hrs @ 114° F FREE WATER: 0cc @ 45 degree angle. Be sure to displace cement with kill weight brine. CENTRALIZER PLACEMENT: 1. 7" x 8-1/4" Straight Blade Rigid Centralizers-- two per joint on the bottom 17 joints of 7" Casing (57 total). This will cover 200' above the C Sand. 2. 7" x 8-1/4"Straight Blade Rigid Centralizers-- one per joint from 6900' - 6100' to cover the Schrader Bluffs Sands (25Total). 3. Run one 7" x 8-1/4"Straight Blade Rigid Centralizer inside the 9-5/8" casing shoe. 4. Total 7" x 8-1/4" Straight Blade Rigid Centralizers needed is 55. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 10 bpm. Batch mixing is not necessary. We will have displaced cement to above the Schrader Bluff top with this single stage. CEMENT VOLUME: 1. Stage 1 cement volume is calculated to cover 500' md above the NA Top with 30% excess. API # 50-029-22XXX March 27, 1996 MPK-9 Cement Calculator Milne Point Cement and Centralizer Calculations Well MPK-9 Surface (1 Stage) Cement Job cement Type E G Hole Size 12.25 Yeild (cfs) 2.17 1.15 Casing Size 9.625 Weight (ppg) 1 2 15.8 BPF 0.0558 BPF + 30% 0.0725 BPF + 150% 0.1395 Depth BBLS Cu. Ft. Sacks Top of Cemenl Shoe Depth ~ Calculated G Tail Volume 2261 170.0 954 830 1800 E Lead Volume 1800 251.0 1409 650 Surface Total E 6 5 0 Total G 8 3 0 9-5/8" Bows 1 0 Production 1-Stage Cement Job Cement Yield Hole Size 8.5 Silicalite Slurry 2.05 Casing Size 7 BPF 0.0226 BPF + 30% 0.0294 Top of Cemenl Stage I IVE) BBLS Cu. Ft. Sacks Calculated INA Top~,i'~ ....... 'TDKuparukSeabee TOPTop~l~!ll ~,~,~" '~ 148 831 405 5476 Centralizers 27 Across the Kuparuk Centralizers 34 Across the Schrader Bluff Total G ST1 405 Total ST Blade~ 6 2 Page 1 MPK-9 Cement Calculator Milne Point Cement and Centralizer Calculations ' I Well MPK-9 Surface (1 Stage) Cement Job ~1 cement Type l E G Hole Size 12.25i i Yeild (cfs) 2.17 1.15 -- Casing Size 9.6251 I Weight (ppg) 1 2 1 5 8 I · 0.05581 , BPF + 30% 0.0725] BPF + 150% 0.1395 I Depth BBLS I Cu. Ft. Sacks Top of Cemenl G Tail Volume 2261 170.0 I 954 830 1 800 E Lead Volum~ 1800 I 251.0 1409 650 Surface i 0 Total E 6 5 Total G 83 0 9-5/8" Bows I 0 I Production 1-Stage Cement Job i Cement Yield I Hole Size 8.5 Silicalite Slurry 2.05 Casing Size7 BPF 0.0226~ BPF + 30% t 0 0294. , ! I Top of Cemen' Stage 1 ...~ ......................................................... BBLS I Cu. Ft. Sacks Calculated NA Top i!iii~iiiii~:iii~i~iii!i~ii~i !~ii 1 48 831 405 5476 Seabee Top ~iii~ii~i~ii~ Top ! , I I Centralizers 2 7 Across the Kuparuk Centralizers i 341Across the Schrader Bluff I I I , TotalGST1i 405,, Total ST Blade~ 6 21 Page 1 A~c~sl<~ S~c~:e P[c~ne~ 'one4 Mitne Pt ' MPK MPK-g MPK-Og (g6F) WpP Pmetimincmy 3/L::~3/c)6 1 ~41 pm CRITICAL POINT DATA MD Inc Azi. 1FVD TIE IN 0 0.00 3E~3.63 0 KEP / STPC;~T I000 0.~ ~,~ ~ BUILD ~ ST~T ~ ~LD 1~ 3.~ ~.63 ST~T ~ ~ILD 1~ 7.~ ~,~ 15~ END ~ ~ILD 17~ 10.~ ~.63 B~se 1815 10.~ ~.63 1811 Pem~F~o~ ST~T ~ I~ 10.~ ~,63 lglg CI~V[- P END ~ C~ 3861 ~.41 ~.63 3473 NA S~ds 5976 ~.41 ~,~ 4~1 B:se S~ 6~Z ~.41 ~,~ 47~ C~VE ~ 2,~/1~ F~ T~ ~Z g~4 45.76 ~,~ Top ~D ~ ~,47 ~,~ 6781 F~'S E/W ON OE ON OE 6N 5W 43N 3~3W 56N 42W 71N .m/1W 910 2342 ~620 4180 4576 4842 4959 VERTICAL VIEW SCALE 500 ?t, / DIVISION TVD REP WELLHEAD VERTICAL SECTION REP WELLHEAD N 6~ W N 178gW N 2:q301 W N 31g~ W N :3494 W N :~sg7 W N 3787 W HORIZONTAL VIEW (TRUE NORTJ~) SCALE 500 Ct. / DIVISION ~)r~oo SURVEY REP WELLHEAD 0/ 0 T 0,00 8 0 MD TIE IN 500 / [ 4500 4000 3500 3000 8500 8000 1500 1000 500 0 500 lOOOm i 000 @ 1000 MD KIP / START OF BUILD ~ 100/100 1300 I J 3,00 e 1300 MD START I~ BUILD @ 1,50/100 Pt [Tc~get 7011 495g N 3787 W 5~ 6010755 .1,~,~! 0 ~ to,oo e 1985 MD START EF C_J~V£ e e,50/tO0 $'¢ ~ ~~s-~-I ~, iu,~J : ,-,cu i-~u [ 7 in 10412 30.00 3~.63 7871 5078 N 3878 W J · ~d' EqD.OO ~ P3L:5 MD 8500 ~ ~ 2.5,00 8 ~ MD x,,~ 30.00 @ 8785 MD \ 35.~ ~ ~ MD · ~000- X.,o,~ e 3~85 MD I~ '~]~:~ I ~. 45,~ e ~ MD I N~/S ~78,46 N I ~0 = ! !46 ~~6~]1J~41~ ~ [~-D,~ TVD 4O0O -- 5000 3897 ~MD ~se Scl~ade~ ' 65OO-- 5758 '~.4~.4! @ 9491 MD ~, 38,41 ~ 969! MI) 6781 . ~ ~x 35,47 I~ 9838 MD Top KUD 70~)~ ~ ~]~.~ . X~ 30,00@ 10118 MD Tonoet / Top KUC 7500 -- 6390 0 eooo I I I I I I I I I I I I I ~1 I -~o0 o 500 !~ ~ ~ ~ ~ ~ 4ooo ~Do ~oo ~oo 6000 ~ 7o0o VERTICAL SECTION PLANE: 3~,63 CRITICAL POINT MD In c Azl. TIE IN 0 0.03 3~.63 0 KCP / START !~ O,OO 322.63 1000 Br BUILD ~ 1.CO/iOO Ft START OF ~JILD 13~ 3,C0 ~.63 8 1.50/1~ Ft ST~T E~ ~LD 16~ 7,59 ~.63 ~ ~.00/1~ Ft END ~ BUILD 1725 10,00 ~.63 1722 Base 1815 10.~ ~.63 1811 Pe~msFpost START OF 19~5 10.00 ~.63 1919 CUa~E ~ ~.50/~00 Ft END ~- CUR~ 3851 58.41 ~.63 3473 NA S~ds 5976 58.41 ~,63 B~se Schpc~ 6387 5~.41 ~.63 47~ START B~ 8591 58.41 ~,63 CURVE a 2,OO/1OO ~ Top ~Z ~3a4 45,76 ~.63 Top ~dD 98~ 35.47 ~,63 6781 TQ~e~ / T~ 1Olla 30,~ ~.~ 701i KUC[ N/S ON OE ON OE 6N 5W ~N 43N 33W 56N 4~ 71N 54~ P620 4180 4576 484P 4959 VERTICAL ViEW SCALE 500 £t / DIVISION TVD REF: WELLHEAD VERTICAL SECTION REF: WELLHEAD N 695 W N 1783W N 2301 W N 3192 W N 3494 W N 3697 W N 3787 W HORIZONTAL VIEW (TRUE NORTH) SCALE 500 Ft, / DIVISION ~,.~v -'~o..o SURVEY REF: WELLHEAD fl%qx VERTICAL SECTION PLANE: 322,63 0 0 I O,OO @ 0 MD TIE IN / 500 -- / i / 4~0 4000 3500 3000 2500 2000 1500 l ooo 500 0 500 1000 ! ~ 0,00 @ !OOO MD KOP / START [2~ BUILD e 1,00/100 ?~ , o / T~.~ 1300 I ~ 3,00 @ !300 MD START []F BUILD @ 1.50/100 ?~ T~~et 7011 4~-Jg N 3787 W 580592 6010755 4 8 !1599-~,, ?_ I 7,50 @ !600MD START OF BUILD@ P,O0/lO0 ~t500__ 3000--~ '~ 40,00 @ 31a5 MD I Vg '~:~O',SY I ! X 45,00 e SSa5 ~) I N/S _50_~6~6 N I I x?.oo 4ooo~ --~. 4o~i 58.4! ~ 5976 MD NA Scuads 4 " I 2947 ~ ....... , ~,. '790 ] ~ 58,41 @ 6387 MD Bo. se Schmo, de~ ',',,: ~', - ') }{ '~ !:::- 6391; x~ 45,76 @ 9324 MD Top HRZ @ 2.0Ct 678!/ ~3%'~,~7%~?~D Top KUD / 609~ 7O~--q ~30.00 e 10112 MD Targe~c / Top KUC / 6240 \ 6390 7500 8000 -500 0 500 ~ 000 ! 500 2000 2500 3000 3500 4000 4500 5000 5500 6000 ~500 7000 Halliburton Energy Services - Drilling Systems PSL Proposal Report Page Date: 3/20/~ Time: 1.:59 pi Wellpath ID: MPK-09 (96F) WI: Last Revision: 3/20/5 Survey Reference: WELLHEAD Reference World Coordinates: Lat. 70.25.33 N - Long. 149.18.43 W Reference GRID System: Alaska State Plane Zone: Alaska 4 Reference GRID Coordinates: (ft): 6005838.40 N 584433.40 E North Aligned To: TRUE NORTH Vertical Section Reference: WELLHEAD Closure Reference: WELLHEAD TVD Reference: WELLHEAD Calculated using the Minimum Curvature Method Computed using WIN-CADDS REV2.2.1 Vertical Section Plane: 322.63 deg. BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-9 Est MPK-09 (96F) Wp2 Preliminary Measured Incl Drift Subsea TVD Course T 0 T A L Depth Dir. Depth Length Rectangular Offsets (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) GRID Coordinates Northing Easfing (ft) fit) TIE IN 0.00 0.00 0.00 -61.00 0,00 0.00 0.00N KOP / START OF BUILD @ 1.00 degtl00 ft 1000.00 0.00 0.00 939.00 1000.00 1000.00 0.00N 1100.00 1.00 322.63 1038.99 1099.99 100.00 0.69N 0.00 E 6005838.40 584433.40 0.00 E 6005838.40 584433.40 0.5TN 6005839.09 584432.86 Closure Vertical Build Walk DLS Cum. Expected Total Max Hor Min Hor Dir. Vert Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (ft) (dg/lOOft) (dg/lOOft) (dg/lOOft) (deg) (ft) (ft) (ft) (ft) (deg.) (ft) Survey Tool 0.0C@ 0.00 0.00 0.00 0.00 0.00 0.0 0.00N 0.00 E 0.00 0.00 0.00 0.00 MWD 0.0C@ 0.00 0.00 0.00 0.00 0.87@322.63 0.87 1.00 0.00 0.00 0.0 0.00N 1.00 1.0 0.69N 0.00E 3.17 3.17 0.00 1.41 BPHM-PBD 0.53W 3.38 3.38 52.63 1.56 BPHM-PBD 1200.00 2.00 322.63 1138.96 1199.96 100.00 2.77N START OF BUILD @ 1.50 degtl00 ft 1300.00 3.00 322.63 1238.86 1299.86 I00.00 6.24N 1400.00 4.50 322.63 1338.65 1399.65 100.00 11.44N 2.12W 6005841.15 584431.25 3.4~@322.63 3.49 4.77W 6005844.59 584428.56 7.85@322.63 7.85 8.74W 6005849.74 584424.54 14.3~@322.63 14.39 1500.00 6.00 322.63 1438.22 1499.22 100.00 18.71N 14.25'W 6005856.95 584418.90 23.54@322.63 23.54 START OF BUILD @ 2.00 deg/100 ft 1600.00 7.50 322.63 1537.53 1598.53 100.00 28.05N 21.42W 6005866.21 584411.66 35.3C@322.63 35.30 1700.00 9.50 322.63 1636.42 1697.42 100.00 39.80N 30.35'W 6005877.85 584402.56 50.08@322.63 50.08 1.00 0.00 1.00 0.00 1.50 0.00 1.50 0.00 1.50 0.00 2.00 0.00 1.00 2.0 2.77 N 2.12rvV 3.60 3.59 52.63 1.71 BPHM-PBD 1.00 3.0 6.23 N 4.78W 3.83 3.81 52.63 1.87 BPHM-PBD 1.50 4.5 11.41 N 8.77W 4.09 4.03 52.63 2.03 BPHM-PBD 1.50 6.0 18.66N 14.35W 4.38 4.26 52.63 2.19 BPHM-PBD 1.50 7.5 27.96N 21.54W 4.73 4.49 52.63 2.37 BPHM-PBD 2.00 9.5 39.65 N 30.55'W 5.16 4.72 52.63 2.55 BPHM-PBD END OF BUILD 1725.00 10.00 322.63 1661.06 1722.06 25.00 43.16N 32.9fiW 6005881.19 584399.95 54.31@322.63 54.31 2.00 0.00 Base Permafrost 1815.31 10.00 322.63 1750.00 1811.00 90.31 55.62N 42.4ghr 6005893.54 584390.30 69.9~@322.63 69.99 0.00 0.00 START OF CURVE @ 2.50 deg/100 ft 1925.00 10.00 322.63 1858.02 1919.02 109.69 70.76N 54.04W 6005908.54 584378.56 89.04@322.63 89.04 0.00 0.00 2.00 10.0 43.00N 33.18W 5.28 4.78 52.63 2.60 BPHM-PBD 0.00 10.0 55.40N 42.78W 5.72 5.01 52.63 2.74 BPHM-PBD 0.00 10.0 70.46N 54.44W 6.29 5.30 52.63 2.92 BPHM-PBD 2025.00 12.50 322.63 1956.10 2017.10 100.00 86.27N 65.88W 6005923.91 584366.55 108.55@322.63 108.55 2.50 0.00 2125.00 15.00 322.63 2053.22 2114.22 100.00 105.15N 80.31W 6005942.63 584351.91 132.31@322.63 132.31 2.50 0.00 2225.00 17.50 322.63 2149.22 2210.22 I00.00 127.39N 97.25'W 6005964.68 584334.68 160.2~@322.63 160.29 2.50 0.00 2.50 12.5 85.86N 66.41W 6.94 5.54 52.63 3.14 BPHM-PBD 2.50 15.0 104.60N 81.04W 7.72 5.79 52.63 3.39 BPHM-PBD 2.50 17.5 126.63N 98.25'W 8.66 6.04 52.63 3.66 BPHM-PBD 2325.00 20.00 322.63 2243.90 2304.90 100.00 152.94N I16.8CW 6005990.00 584314.89 192.44@322.63 192.44 2.50 0.00 2425.00 22.50 322.63 2337.10 2398.10 100.00 181.74N 138.75W 6006018.55 584292.57 228.68@322.63 228.68 2.50 0.00 2525.00 25.00 322.63 2428.62 2489.62 100.00 213.74N 163.24W 6006050.27 584267.77 268.95@322.63 268.95 2.50 0.00 2.50 20.0 151.91N 118.14W 9.76 6.30 52.63 3.95 BPHM-PBD 2.50 22.5 180.39N 140.57W 11.04 6.56 52.63 4.27 BPHM-PBD 2.50 25.0 211.99N 165.53W 12.50 6.84 52.63 4.62 BPHM-PBD 2625.00 27.50 322.63 2518.30 2579.30 100.00 248.89N 190.08W 6006085.11 584240.54 313.17@322.63 313.17 2.50 0.00 2.50 27.5 246.66N 193.0CW 14.15 7.13 52.63 4.99 BPHM-PBD Survey Reference: WELLHEAD Reference World Coordinates: Lat. 70.25.33 N - Long. 149.18.43 W Reference GRID System: Alaska State Plane Zone: Alaska 4 Reference GRID Coordinates: (ft): 6005838.40 N 584433.40 E North Aligned To: TRUE NORTH Vertical Section Reference: WELLHEAD Closure Reference: WELLHEAD TVD Reference: WELLHEAD Halliburton Energy Services - Drilling Systems PSL Proposal Report Calculated using the Minimum Curvature Method Computed using WIN-CADDS REV2.2.1 Vertical Section Plane: 322.63 deg. Page 1 Date: 3/20/96 Time: 1:59 pm Wellpath ID: MPK-09 (96F) Wp2 Last Revision: 3/20/96 BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-9 Est MPK-09 (96F) Wp2 Preliminary Measured Incl Drift Subsea TVD Course T O T A L Depth Dir. Depth Length Rectangular Offsets (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) GRID Coordinates Northing Easting (ft) (ft) TIE IN 0.00 0.00 0.00 -61.00 0.00 0.00 0.00N KOP / START OF BUILD @ 1.00 deg/100 ft 1000.00 0.00 0.00 939.00 1000.00 1000.00 0.00N 1100.00 1.00 322.63 1038.99 1099.99 100.00 0.69N 0.00E 6005838.40 584433.40 0.00E 6005838.40 584433.40 0.53W 6005839.09 584432.86 Closure Vertical Build Walk DLS Cum. Expected Total Max Hor Min Hor Dir. Vert Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (ft) (dg/100ft) (dg/100ft) (dg/100ft) (deg) (ft) (ft) (ft) (ft) (deg.) (ft) 1200.00 2.00 322.63 1138.96 1199.96 100.00 2.77N START OF BUILD @ 1.50 deg/100 ~ 1300.00 3.00 322.63 1238.86 1299.86 100.00 6.24N 1400.00 4.50 322.63 1338.65 1399.65 100.00 11.44N 0.0¢@ 0.00 0.00 0.0¢@ 0.00 0.00 0.87@322.63 0.87 2.12W 6005841.15 584431.25 3.45@322.63 3.49 4.77W 6005844.59 584428.56 7.85@322.63 7.85 8.74W 6005849.74 584424.54 14.35@322.63 14.39 Survey Tool 0.00 0.00 0.00 0.00 1.00 0.00 1.00 0.00 1.00 0.00 1.50 0.00 0.00 0.0 0.00N 0.00 0.0 0.00N 1.00 1.0 0.69N 1.00 2.0 2.77 N 1.00 3.0 6.23 N 1.50 4.5 11.41 N 0.00 E 0.00 0.00 0.00 0.00 MWD 0.00E 3.17 3.17 0.00 1.41 BPHM-PBD 0.53W 3.38 3.38 52.63 1.56 BPHM-PBD 2.12W 3.60 3.59 52.63 1.71 BPHM-PBD 4.78W 3.83 3.81 52.63 1.87 BPHM-PBD 8.7T~ 4.09 4.03 52.63 2.03 BPHM-PBD 1500.00 6.00 322.63 1438.22 1499.22 100.00 18.71N 14.2~V 6005856.95 584418.90 23.54@322.63 23.54 START OF BUILD @ 2.00deg/100R 1600.00 7.50 322.63 1537.53 1598.53 100.00 28.05N 21.42W 6005866.21 584411.66 35.3¢@322.63 35.30 1700.00 9.50 322.63 1636.42 1697.42 100.00 39.80N 30.39N 6005877.85 584402.56 50.08@322.63 50.08 1.50 1.50 2.00 0.00 0.00 0.00 1.50 6.0 18.66N 14.35W 4.38 4.26 52.63 2.19 BPHM-PBD 1.50 7.5 27.96N 21.54W 4.73 4.49 52.63 2.37 BPHM-PBD 2.00 9.5 39.65N 30.5~r 5.16 4.72 52.63 2.55 BPHM-PBD END OF BUILD 1725.00 10.00 322.63 1661.06 1722.06 25.00 43.16N 32.9fiW 6005881.19 584399.95 54.31@322.63 54.31 Base Permafrost 1815.31 10.00 322.63 1750.00 1811.00 90.31 55.62N 42.48W 6005893.54 584390.30 69.95@322.63 69.99 START OF CURVE @ 2.50 deg/100 ft 1925.00 10.00 322.63 1858.02 1919.02 109.69 70.76N 54.04W 6005908.54 584378.56 89.04@322.63 89.04 2025.00 12.50 322.63 1956.10 2017.10 100.00 86.27N 65.8ghr 6005923.91 584366.55 108.55@322.63 108.55 2125.00 15.00 322.63 2053.22 2114.22 100.00 105.15N 80.31W 6005942.63 584351.91 132.31@322.63 132.31 2225.00 17.50 322.63 2149.22 2210.22 100.00 127.39N 97.2~W 6005964.68 584334.68 160.25@322.63 160.29 2325.00 20.00 322.63 2243.90 2304.90 100.00 152.94N 116.8CW 6005990.00 584314.89 192.4~@322.63 192.44 2425.00 22.50 322.63 2337.10 2398.10 100.00 181.74N 138.7W~r 6006018.55 584292.57 228.68@322.63 228.68 2525.00 25.00 322.63 2428.62 2489.62 100.00 213.74N 163.24W 6006050.27 584267.77 268.95@322.63 268.95 2625.00 27.50 322.63 2518.30 2579.30 100.00 248.89N 190.08W 6006085.11 584240.54 313.17@322.63 313.17 2.00 0.00 0.00 2.50 2.50 2.50 2.50 2.50 2.50 2.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.00 10.0 43.00N 33.18W 5.28 4.78 52.63 2.60 BPHM-PBD 0.00 10.0 55.40N 42.78W 5.72 5.01 52.63 2.74 BPHM-PBD 0.00 10.0 70.46N 54.44W 6.29 5.30 52.63 2.92 BPHM-PBD 2.50 12.5 85.86N 66.41W 6.94 5.54 52.63 3.14 BPHM-PBD 2.50 15.0 104.60N 81.04W 7.72 5.79 52.63 3.39 BPHM-PBD 2.50 17.5 126.63N 98.2¢W 8.66 6.04 52.63 3.66 BPHM-PBD 2.50 20.0 151.91N 118.1~VV 9.76 6.30 52.63 3.95 BPHM-PBD 2.50 22.5 180.39N 140.57W 11.04 6.56 52.63 4.27 BPHM-PBD 2.50 25.0 211.99N 165.53W 12.50 6.84 52.63 4.62 BPHM-PBD 2.50 27.5 246.66 N 193.0CW 14.15 7.13 52.63 4.99 BPHM-PBD Halliburton Energy Services - Drilling Systems PSL Proposal Report Page Date: 3/20/9~ Wellpath ID: MPK-09 (96F) Wp: Measured Incl Drift Subsea TVD Course T O T A L Depth Dir. Depth Length Rectangular Offsets (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) GRID Coordinates Northing Easting (ft) (ft) Closure Vertical Build Walk DLS Cum. Expected Total Max Hor Min Hor Dir. Vert Dist. Dir. Section Rate ' Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (ft) (dg/100ft) (dg/100ft) (dgtl00ft) (deg). (ft) (ft) (ft) (ft) (deg.) (ft) 2725.00 30.00 322.63 2605.97 2666.97 100.00 287.12N 219.27W 6006123.00 584210.92 361.27@322.63 361.27 2.50 0.00 2825.00 32.50 322.63 2691.45 2752.45 100.00 328.34N 250.75W 6006163.86 584178.98 413.14@322.63 413'.14 2.50 0.00 2925.00 35.00 322.63 2774.59 2835.59 100.00 372.49N 284.47W 6006207.63 584144.77 468.6~@322.63 468.69 2.50 0.00 3025.00 37.50 322.63 2855.23 2916.23 100.00 419.49N 320.35W 6006254.21 584108.36 527.82@322.63 527.82 2.50 0.00 3125.00 40.00 322.63 2933.21 2994.21 100.00 469.23N 358.34W 6006303.51 584069.82 590.41@322.63 590.41 2.50 0.00 3225.00 42.50 322.63 3008.39 3069.39 100.00 521.63N 398.35W 6006355.45 584029.22 656.34@322.63 656.34 2.50 0.00 3325.00 45.00 322.63 3080.62 3141.62 100.00 576.58N 440.32W 6006409.93 583986.64 725.48@322.63 725.48 2.50 0.00 3425.00 47.50 322.63 3149.77 3210.77 100.00 633.99N 484.1e'W 6006466.83 583942.17 797.71@322.63 797.71 2.50 0.00 3525.00 50.00 322.63 3215.70 3276.70 100.00 693.74N 529.78W 6006526.06 583895.87 872.89@ 322.63 872.89 2.50 0.00 3625.00 52.50 322.63 3278.28 3339.28 100.00 755.71N 577.11W 6006587.49 583847.86 950.87@322.63 950.87 2.50 0.00 3725.00 55.00 322.63 3337.41 3398.41 100.00 819.80N 626.05W 6006651.02 583798.20 1031.51@322.63 1031.51 2.50 0.00 3825.00 57.50 322.63 3392.96 3453.96 100.00 885.88N 676.51W 6006716.52 583747.01 1114.65@322.63 1114.65 2.50 0.00 END OF CURVE 3861.48 58.41 322.63 3412.32 3473.32 36.48 910.45N 695.28W 6006740.88 583727.97 1145.57@322.63 1145.57 2.50 0.00 CASING POINT OD = 9 5/8 in, ID = 8.84 in, Weight = 40.00 lb/ft. 4061.00 58.41 322.63 3516.83 3577.83 199.52 I045.53N 798.4TN 6006874.78 583623.32 1315.53@322.63 1315.53 0.00 0.00 NA Sands 5976.15 58.41 322.63 4520.00 4581.00 1915.15 2342.10N 1788.55W 6008160.12 582618.91 2946.92@322.63 2946.92 0.00 0.00 Survey Tool 2.50 30.0 284.32N 222.9TN 15.98 7.42 52.63 5.39 BPHM-PBD 2.50 32.5 324.90N 255.2CQV 18.00 7.73 52.63 5.82 BPHM-PBD 2.50 35.0 368.31 N 289.95W 20.22 8.05 52.63 6.28 BPHM-PBD 2.50 37.5 414.47N 326.93W 22.62 8.38 52.63 6.78 BPHM-PBD 2.50 40.0 463.28 N 366.13W 25.22 8.71 52.63 7.31 BPHM-PBD 2.50 42.5 514.65N 407.49W 28.01 9.05 52.63 7.88 BPHM-PBD 2.50 45.0 568.48N 450.9TN 30.98 9.40 52.63 8.48 BPHM-PBD 2.50 47.5 624.66N 496.37W 34.14 9.74 52.63 ' 9.12 BPHM-PBD 2.50 50.0 683.09N 543.72W 37.48 10.08 52.63 9.79 BPHM-PBD 2.50 52.5 743.65N 592.91W 40.99 10.41 52.63 10.50 BPHM-PBD 2.50 55.0 806.23N 643.83W 44.68 10.73 52.63 11.24 BPHM-PBD 2.50 57.5 870.71N 696.38W 48.53 11.05 52.63 12.02 BPHM-PBD 2.50 58.4 894.68N 715.93W 49.96 11.16 52.63 12.31 BPHM-PBD 0.00 58.4 1045.53 N 798.43W 0.00 0.00 0.00 0.00 BPHM-PBD 0.00 58.4 2291.81 N 1854.41W 134.15 21.57 52.63 27.70 BPHM-PBD Base Schrader 6386.60 58.41 322.63 4735.00 4796.00 410.46 2619.99N 2000.75W 6008435.62 582403.67 3296.5~@322.63 3296.56 0.00 0.00 START OF CURVE @ 2.00 deg/100 ft 8691.00 58.41 322.63 5942.07 6003.07 2304.40 4180.09N 3192.11W 6009982.42 581195.38 5259.53@322.63 5259.53 0.00 0.00 8791.00 56.41 322.63 5995.92 6056.92 100.00 4247.05N 3243.24W 6010048.81 581143.53 5343.78@322.63 5343.78 -2.00 -0.00 0.00 58.4 2562.99N 2075.3~ 150.59 23.62 52.63 30.86 BPHM-PBD 0.00 58.4 4085.46N 3316.0TN 243.03 35.15 52.63 48.87 BPHM-PBD 2.00 60.4 4150.86N 3369.2CVV 246.92 35.89 52.63 49.46 BPHM-PBD 8891.00 54.41 322.63 6052.69 6113.69 I00.00 4312.47N 3293.21W 6010113.68 581092.86 5426.11@322.63 5426.11 -2.00 -0.00 8991.00 52.41 322.63 6112.29 6173.29 100.00 4376.28N 3341.9TW 6010176.95 581043.45 5506.4£@322.63 5506.40 -2.00 -0.00 9091.00 50.41 322.63 6174.66 6235.66 100.00 4438.40N 3389.37W 6010238.55 580995.34 5584.5~@322.63 5584.56 -2.00 -0.00 2.00 62.4 4214.80N 3421.11W 250.68 36.66 52.63 50.02 BPHM-PBD 2.00 64.4 4277.20N 3471.6~N 254.31 37.44 52.63 50.53 BPHM-PBD 2.00 66.4 4337.98N 3520.8TN 257.79 38.24 52.63 51.00 BPHM-PBD 9191.00 48.41 322.63 6239.72 6300.72 100.00 4498.75N 3435.46W 6010298.39 580948.60 5660.4~@322.63 5660.49 -2.00 -0.00 9291.00 46.41 322.63 6307.39 6368.39 100.00 4557.26N 3480.14W 6010356.41 580903.29 5734.11@322.63 5734.11 -2.00 -0.00 Top HRZ 9323.61 45.76 322.63 6330.00 6391.00 32.60 4575.93N 3494.4CW 6010374.92 580888.84 5757.6¢@322.63 5757.60 -2.00 -0.00 2.00 68.4 4397.08N 3568.61W 261.13 39.05 52.63 51.44 BPHM~PBD 2.00 70.4 4454.41N 3614.84W 264.33 39.86 52.63 51.84 BPHM-PBD 2.00 71.1 4472.70N 3629.5~N 265.36 40.13 52.63 51.96 BPHM-PBD 9391.00 44.41 322.63 6377.58 6438.58 67.40 4613.86N 3523.3Ohr 6010412.53 580859.47 5805.33@322.63 5805.33 -2.00 -0.00 9491.00 42.41 322.63 6450.22 6511.22 I00.00 4668.48N 3565.07W 6010466.68 580817.17 5874.05@322.63 5874.05 -2.00 -0.00 9591.00 40.41 322.63 6525.22 6586.22 100.130 4721.05N 3605.2TN 6010518.81 580776.46 5940.1~@322.63 5940.19 -2.00 -0.00 2.00 72.4 4509.88N 3659.53W 267.41 40.68 52.63 52.20 BPHM-PBD 2.00 74.4 4563.48N 3702.57W 270.31 41.49 52.63 52.52 BPHM-PBD 2.00 76.4 4615.10N 3743.9e'W 273.06 42.30 52.63 52.80 BPHM-PBD 9691.00 38.41 322.63 6602.47 6663.47 100.00 4771.50N 3643.75W 6010568.84 580737.39 6003.68@322.63 6003.68 -2.00 -0.00 9791.00 36.41 322.63 6681.90 6742.90 100.00 4819.78N 3680.62rvV 6010616.71 580700.00 6064.43@322.63 6064.43 -2.00 -0.00 Top KUD 9838.06 35.47 322.63 6720.00 6781.00 47.06 4841.74N 3697.3SW 6010638.48 580683.00 6092.05@322.63 6092.05 -2.00 -0.00 2.00 78.4 4664.68N 3783.63W 275.65 43.11 52.63 53.05 BPHM-PBD 2.00 80.4 4712.17N 3821.54W 278.10 43.90 52.63 53.26 BPHM-PBD 2.00 81.4 4733.77N 3838.77W 279.21 44.27 52.63 53.35 BPHM-PBD 9891.00 34.41 322.63 6763.39 6824.39 52.94 4865.83N 3715.7gW 6010662.37 580664.34 6122.37@322.63 6122.37 -2.00 -0.00 9991.00 32.41 322.63 6846.86 6907.86 100.00 4909.59N 3749.21W 6010705.77 580630.45 6177.43@322.63 6177.43 -2.00 -0.00 10091.00 30.41 322.63 6932.20 6993.20 100.00 4951.01N 3780.84W 6010746.84 580598.38 6229.55@322.63 6229.55 -2.00 -0.00 2.00 82.4 4757.48N 3857.6TN 280.42 44.68 52.63 53.45 BPHM-PBD 2.00 84.4 4800.60N 3891.94W 282.56 45.45 52.63 53.59 BPHM-PBD 2.00 86.4 4841.44N 3924.32W 284.54 46.19 52.63 53.71 BPHM-PBD Target / Top KUC 1 10111.60 30.00 322.63 6950.00 7011.00 20.60 4959.25N 3787.13W 6010755.00 580592.00 6239.91@322.63 6239.91 -2.00 -0.00 2.00 86.8 4849.56N 3930.7TvV 284.94 46.34 52.63 53.73 BPHM-PBD Halliburton Energy Services - Drilling Systems PSL Proposal Report Page 2 Date: 3/20/96 Wellpath ID: MPK-09 (96F) Wp2 Measured Incl Drift Subsea TVD Course T O T A L Depth Dir. Depth Length Rectangular Offsets (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) GRID Coordinates Northing Easting (ft) (ft) Closure Vertical Build Walk DLS Cum. Expected Total Max Hor Min Hor Dir. Vert Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (ft) (dg/100ft) (dg/100ft) (dg/100ft) (deg). (ft) (ft) (ft) (ft) (deg.) (ft) 2725.00 30.00 322.63 2605.97 2666.97 100.00 287.12N 219.27W 6006123.00 584210.92 361.27@322.63 361.27 2.50 0.00 2825.00 32.50 322.63 2691.45 2752.45 100.00 328.34N 250.75W 6006163.86 584178.98 413.14@322.63 413~14 2.50 0.00 2925.00 35.00 322.63 2774.59 2835.59 100.00 372.49N 284.47W 6006207.63 584144.77 468.6¢@322.63 468.69 2.50 0.00 3025.00 37.50 322.63 2855.23 2916.23 100.00 419.49N 320.35W 6006254.21 584108.36 527.82@322.63 527.82 2.50 0.00 3125.00 40.00 322.63 2933.21 2994.21 100.00 469.23N 358.34W 6006303.51 584069.82 590.41@322.63 590.41 2.50 0.00 3225.00 42.50 322.63 3008.39 3069.39 100.00 521.63N 398.35W 6006355.45 584029.22 656.34@322.63 656.34 2.50 0.00 3325.00 45.00 322.63 3080.62 3141.62 100.00 576.58N 440.32W 6006409.93 583986.64 725.48@322.63 725.48 2.50 0.00 3425.00 47.50 322.63 3149.77 3210.77 100.00 633.99N 484AfiW 6006466.83 583942.17 797.71@322.63 797.71 2.50 0.00 3525.00 50.00 322.63 3215.70 3276.70 100.00 693.74N 529.78W 6006526.06 583895.87 872.8¢@322.63 872.89 2.50 0.00 3625.00 52.50 322.63 3278.28 3339.28 100.00 755.71N 577.11W 6006587.49 583847.86 950.87@322.63 950.87 2.50 0.00 3725.00 55.00 322.63 3337.41 3398.41 100.00 819.80N 626.05W 6006651.02 583798.20 1031.51@322.63 1031.51 2.50 0.00 3825.00 57.50 322.63 3392.96 3453.96 100.00 885.88N 676.51W 6006716.52 583747.01 1114.65@322.63 1114.65 2.50 0.00 END OF CURVE 3861.48 58.41 322.63 3412.32 3473.32 36.48 910.45N 695.28W 6006740.88 583727.97 1145.57@322.63 1145.57 2.50 0.00 CASING POINT OD = 9 5/8 in, ID = 8.84 in, Weight = 40.00 lb/ft. 4061.00 58.41 322.63 3516.83 3577.83 199.52 1045.53N 798.43W 6006874.78 583623.32 1315.53@322.63 1315.53 0.00 0.00 NA Sands 5976.15 58.41 322.63 4520.00 4581.00 1915.15 2342.10N 1788.55W 6008160.12 582618.91 2946.92@322.63 2946.92 0.00 0.00 Base Schrader 6386.60 58.41 322.63 4735.00 4796.00 410.46 2619.99N 2000.75W 6008435.62 582403.67 3296.5~@322.63 3296.56 0.00 0.00 START OF CURVE @ 2.00 deg/100 ft 8691.00 58.41 322.63 5942.07 6003.07 2304.40 4180.09N 3192.11W 6009982.42 581195.38 5259.53@322.63 5259.53 0.00 0.00 8791.00 56.41 322.63 5995.92 6056.92 100.00 4247.05N 3243.24W 6010048.81 581143.53 5343.78@322.63 5343.78 -2.00 -0.00 8891.00 54.41 322.63 6052.69 6113.69 100.00 4312.47N 3293.21W 6010113.68 581092.86 5426.11@322.63 5426.11 -2.00 -0.00 8991.00 52.41 322.63 6112.29 6173.29 100.00 4376.28N 3341.93W 6010176.95 581043.45 5506.4£@322.63 5506.40 -2.00 -0.00 9091.00 50.41 322.63 6174.66 6235.66 100.00 4438.40N 3389.37W 6010238.55 580995.34 5584.5~@322.63 5584.56 -2.00 -0.00 9191.00 48.41 322.63 6239.72 6300.72 100.00 4498.75N 3435.403/ 6010298.39 580948.60 5660.4¢@322.63 5660.49 -2.00 -0.00 9291.00 46.41 322.63 6307.39 6368.39 100.00 4557.26N 3480.14W 6010356.41 580903.29 5734.11@322.63 5734.11 -2.00 -0.00 Top HRZ 9323.61 45.76 322.63 6330.00 6391.00 32.60 4575.93N 3494.4CW 6010374.92 580888.84 5757.6£@322.63 5757.60 -2.00 -0.00 9391.00 44.41 322.63 6377.58 6438.58 67.40 4613.86N 3523.3C%V 6010412.53 580859.47 5805.33@322.63 5805.33 -2.00 -0.00 9491.00 42.41 322.63 6450.22 6511.22 100.00 4668.48N 3565.07W 6010466.68 580817.17 5874.05@322.63 5874.05 -2.00 -0.00 9591.00 40.41 322.63 6525.22 6586.22 100.00 4721.05N 3605.22W 6010518.81 580776.46 5940.1¢@322.63 5940.19 -2.00 -0.00 9691.00 38.41 322.63 6602.47 6663.47 100.00 4771.50N 3643.75W 6010568.84 580737.39 6003.68@322.63 6003.68 -2.00 -0.00 9791.00 36.41 322.63 6681.90 6742.90 100.00 4819.78N 3680.62W 6010616.71 580700.00 6064.43@322.63 6064.43 -2.00 -0.00 Top KUD 9838.06 35.47 322.63 6720.00 6781.00 47.06 4841.74N 3697.35W 6010638.48 580683.00 6092.05@322.63 6092.05 -2.00 -0.00 9891.00 34.41 322.63 6763.39 6824.39 52.94 4865.83N 3715.7gW 6010662.37 580664.34 6122.37@322.63 6122.37 -2.00 -0.00 9991.00 32.41 322.63 6846.86 6907.86 I00.00 4909.59N 3749.21W 6010705.77 580630.45 6177.43@322.63 6177.43 -2.00 -0.00 10091.00 30.41 322.63 6932.20 6993.20 100.00 4951.01N 3780.84W 6010746.84 580598.38 6229.55@322.63 6229.55 -2.00 -0.00 Target/Top KUC1 10111.60 30.00 322.63 6950.00 7011.00 20.60 4959.25N 3787.13W 6010755.00 580592.00 6239.91@322.63 6239.91 -2.00 -0.00 Survey Tool 2.50 30.0 284.32N 222.93W 15.98 7.42 52.63 5.39 BPHM-PBD 2.50 32.5 324.90N 255.2fiW 18.00 7.73 52.63 5.82 BPHM-PBD 2.50 35.0 368.31N 289.95W 20.22 8.05 52.63 6.28 BPHM-PBD 2.50 37.5 414.47N 326.93W 22.62 8.38 52.63 6.78 BPHM-PBD 2.50 40.0 463.28 N 366.13W 25.22 8.71 52.63 7.31 BPHM-PBD 2.50 42.5 514.65N 407.4¢W 28.01 9.05 52.63 7.88 BPHM-PBD 2.50 45.0 568.48N 450.93W 30.98 9.40 52.63 8.48 BPHM-PBD 2.50 47.5 624.66N 496.3TvV 34.14 9.74 52.63 ' 9.12 BPHM-PBD 2.50 50.0 683.09N 543.72W 37.48 10.08 52.63 9.79 BPHM-PBD 2.50 52.5 743.65N 592.91W 40.99 10.41 52.63 10.50 BPHM-PBD 2.50 55.0 806.23N 643.83W 44.68 10.73 52.63 11.24 BPHM-PBD 2.50 57.5 870.71 N 696.38W 48.53 11.05 52.63 12.02 BPHM-PBD 2.50 58.4 894.68N 715.9TN 49.96 11.16 52.63 12.31 BPHM-PBD 0.00 58.4 1045.53N 798.43W 0.00 0.00 0.00 0.00 BPHM-PBD 0.00 58.4 2291.81N 1854.41W 134.15 21.57 52.63 27.70 BPHM-PBD 0.00 58.4 2562.99N 2075.3gW 150.59 23.62 52.63 30.86 BPHM-PBD 0.00 58.4 4085.46N 3316.02W 243.03 35.15 52.63 48.87 BPHM-PBD 2.00 60.4 4150.86N 3369.2CW 246.92 35.89 52.63 49.46 BPHM-PBD 2.00 62.4 4214.80N 3421.11W 250.68 36.66 52.63 50.02 BPHM-PBD 2.00 64.4 4277.20N 3471.65wq 254.31 37.44 52.63 50.53 BPHM-PBD 2.00 66.4 4337.98N 3520.87W 257.79 38.24 52.63 51.00 BPHM-PBD 2.00 68.4 4397.08N 3568.61W 261.13 39.05 52.63 51.44 BPHM-PBD 2.00 70.4 4454.41N 3614.84W 264.33 39.86 52.63 51.84 BPHM-PBD 2.00 71.1 4472.70N 3629.5¢W 265.36 40.13 52.63 51.96 BPHM-PBD 2.00 72.4 4509.88N 3659.53W 267.41 40.68 52.63 52.20 BPHM-PBD 2.00 74.4 4563.48N 3702.5TW 270.31 41.49 52.63 52.52 BPHM-PBD 2.00 76.4 4615.10N 3743.9CCW 273.06 42.30 52.63 52.80 BPHM-PBD 2.00 78.4 4664.68N 3783.63W 275.65 43.11 52.63 53.05 BPHM-PBD 2.00 80.4 4712.17N 3821.54W 278.10 43.90 52.63 53.26 BPHM-PBD 2.00 81.4 4733.77N 3838.77W 279.21 44.27 52.63 53.35 BPHM-PBD 2.00 82.4 4757.48N 3857.67W 280.42 44.68 52.63 53.45 BPHM-PBD 2.00 84.4 4800.60N 3891.94W 282.56 45.45 52.63 53.59 BPHM-PBD 2.00 86.4 4841.44N 3924.32W 284.54 46.19 52.63 53.71 BPHM-PBD 2.00 86.8 4849.56N 3930.77W 284.94 46.34 52.63 53.73 BPHM-PBD Halliburton Energy Services - Drilling Systems PSL Proposal Report Page Date: 3/20/9( Wellpath ID: MPK-09 (96F) Wp'~ Measured Incl Drift Subsea TVD Course T O T A L Depth Dir. Depth Length Rectangular Offsets (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) GRID Coordinates Northing Fasting (fO (ft) Closure Vertical Build Walk DLS Cum, Expected Total Max Hor Min Hor Dir. Vert Dist. Dir. Section Rate ' Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (ft) (dgtlOOft) (dg/lOOft) (dgtlOOft) (deg) (ft) (ft) (ft) (ft) (deg.) (ft) Survey Tool CASING POINT OD = 7 in, ID = 6.28 in, Weight = 26.00 lb/ft. 10411,50 30.00 322.63 7209.73 7270.73 299.90 5078.42N 3878.15W 6010873.17 580499.71 6389.8~@322.63 6389.86 10411.60 30.00 322.63 7209.81 7270.81 0.10 5078.46N 3878.18W 6010873.21 580499.68 6389.91@322.63 6389.91 0.00 0.00 0.00 0.00 0.00 86.8 5078.42N 3878.15W 0.00 0.00 0.00 0.00 BPHM-PBD 0,00 86.8 4967.08N 4024.0TN 290.80 47.87 52.63 54.65 BPHM-PBD Halliburton Energy Services - Drilling Systems PSL Proposal Report Page 3 Date: 3/20/96 Wellpath ID: MPK-09 (96F) Wp2 Measured Incl Drift Subsea TVD Course T 0 T A L Depth Dir. Depth Length Rectangular Offsets (ft) (deg.) (deg.) (ft) (ft) (ft) (ft) (ft) GRID Coordinates Northing Easting (ft) (ft) Closure Vertical Build Walk DLS Cum. Expected Total Max Hor Min Hor Dir. Vert Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (ft) (dg/lOOft) (dg/lOOft) (dg/lOOft) (deg) (ft) (ft) (ft) (ft) (deg.) (ft) Survey Tool CASING POINT OD = 7in, ID = 6.28in, Weight= 26.001b/ff. 10411.50 30.00 322.63 7209.73 7270.73 299.90 5078.42N 3878.15W 6010873.17 580499.71 6389.8fi@322.63 6389.86 10411.60 30.00 322.63 7209.81 7270.81 0.10 5078.46N 3878.18W 6010873.21 580499.68 6389.91@322.63 6389.91 0.00 0.00 0.00 0.00 0.00 86.8 5078.42N 3878.15W 0.00 0.00 0.00 0.00 BPHM-PBD 0,00 86.8 4967.08N 4024.02W 290.80 47.87 52.63 54.65 BPHM-PBD TravelUng CyUnde~ - No, mat PLane ReFerence ~/ell - MPK-O9 (96F) WpB MD: 0 - ~04~B Pt. ~nteewb 50 ~. ALL Directions using BP Hi.side Method Lines ~me the EXACTED ~s~ance Cindes ~ne the B.P. FLOWI~/S~T-IN condtion 33O 300 240 210 WELLS STATUS MPK-17 MWD FLDW-.SNG v:~K- --fi.~ FWD ~PK-25 Win2 FLOWING MPK-5 (DSK) Wp~ FLOWING ~PK--18 Wol FLOWING MPK-37 Wb~ FLOWING v~i--'3g Wb~ :...ZWiW3 V-'F'":O W~ i'.._~Wj',G 180 _W~L~:F~ ~ot NPK-17 MWD 450 40O 3.5O \ ',.. \ /; i . CLDSEST PDINTS Bstance 58,11 i 13.75 ! 19.49 30,26 124,45 210,08 237 10 ~pec~on ~q7 ~ 336.45 97Zg t58,38 t30,65 68,38 3O Ref' MD 1000,00 O.L'O 0,00 [),CO 0,00 0 O0 3120/96 1:42 pm 6O // 120 ReP TVD 1000,00 0.0'3 0,00 0,(%) 0,00 J ',']0 Sep,Fo. ctof 9.10 30,30 124.40 210.10 ~ C9.83 i Date Plotted C~eated By Checked By Approved By Date 3/20/96 8PX- Shaped Sepvic~ D~ ~ln9 /' ................ '-,, Akaskc S~ccte Pkcne~ Zone4 / " ii HPK-9 Es~ TmaveL[in9 Cx[indem -Nommo[ P[one RePenence ~e[[~ MPK-O9 (96F) W~2 MD', 0 ~ 04 ~ ~ ~ ~, ~n ~emwb 50 ~, Ail Dimections using BP Highside Method Lines ape ~he EXPECTED aistonce Omc[es eme ~he B,P. FLOWING/SHUT-IN condition 3120/96 1:42 pm 0 330 30 45O 400 3OO 350 300 250 200 150 // 6O 240 WELLS STATUS MPK-17 MWD FLOWING "::>k S:5 FWD ::'...?L',G MP~-5 (96K) ~p~ F-LOWiNG ~--18 W~i ?_OWiN8 vrir'"iO WNi :....i~r-s ~ 180 CLBSEST PBINTS :2' -" '¥' i, · .. :~-~ We[lpelh S/at MPK-17 MWD MPK-17 HPK--5 (g6K) Wp1HPK-5 Esi ~PH--~8 Wn~ HPK-'~8 HPH-~7 Wb~ HPK-37 ~i::~N---38 Whl HPi<----38 Rst Dls~conce 58,1 ' {% 7'.": 30,86 ~ {t4.45 2~0,08 ,i'- 37 _'..' ;. O:?-'80 Di r, ectl on 150.11 -:.? 97 ..'.-? 9 ~58,38 t 6,?:38 ReF MD 1030,00 :.'.<";" F? 0.00 O.CO 0 Od',.' 0 ReF TVD 1000.00 ?'T'""i{Y'~ 0,00 0,00 3 CO Sep.Factor, 9.~0 /.:':"! 4'i 30.30 ?74.~!3 rl~O.~O :.:.:.2 ;'. i 12 C:,.{73 120 Date P(otted C~eated By Checked By Appeared By Date 3120/96 Halliburton Travelling Cylinder Report Computed using WIN-CADDS REV2.2.1 Pa~e 1 Date: 3/20/96 Time: 1:41 pm Normal Plane Method All distances are between EXPECTED Positions REFERENCE WELL: BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-9 Est MPK-09 (96F) Wp2 Preliminary N/S and E/W are measured from the WELLHEAD TVD is measured from the WELLHEAD Interval Step Depth 50.00 ft.(MD) From 0.00 To 10411.60 ft.(MD) All Directions using BP Highside Method in Dee. Deg. All Depths and Distance are in FEET All distances are between EXPECTED Positions Close Approach Status Offset Flowing Zone Flowing Shut-in Enter Well Safety Min. Safety Safety Shut-in Clear Spread MD TVD Dist Dist Zone MD MPK-17 MWD 35.9 49.0 1050 1050 15.8 2.6 MPK-25 MWD 94.6 105.8 900 900 13.5 2.2 MPK-25 Wp2 97.8 110.9 1050 1050 15.8 2.6 MPK-5 (96K 1.0 19.1 1450 1449 21.8 3.6 MPK-18 Wpl 102.8 115.9 1050 1050 15.8 2.6 MPK-37 Wpl 188.4 201.6 1050 1050 15.8 2.6 MPK-38 Wpl 215.5 228.7 1050 1050 15.8 2.6 MPF-10 Wpl 87.7 100.8 1050 1050 15.8 2.6 1550 Enter Exit Exit Danger Danger Shut-in Zone Zone Zone MD MD MD 1800 Close Approach Status OK OK OK SHUT-IN OK OK OK OK Halliburton Travelling Cylinder Report Computed using WIN-CADDS REV2.2.1 Page 1 Date: 3/20/96 Time: 1:41 pm Normal Plane Method All distances are between EXPECTED Positions REFERENCE WELL: BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-9 Est MPK-09 (96F) Wp2 Preliminary N/S and E/W are measured from the WELLHEAD TVD is measured from the WELLHEAD Interval Step Depth 50.00 ft.(MD) From 0.00 To 10411.60 ft.(MD) All Directions using BP Highside Method in Dec. Deg. All Depths and Distance are in FEET All distances are between EXPECTED Positions Offset Flowing Zone Flowing Shut-in Enter Enter Well Safety Min. Safety Safety Shut-in Danger Clear Spread MD TVD Dist Dist Zone Zone MD MD MPK-17 MWD 35.9 49.0 1050 1050 15.8 2.6 MPK-25 MWD 94.6 105.8 900 900 13.5 2.2 MPK-25 Wp2 97.8 110.9 1050 1050 15.8 2.6 MPK-5 (96K 1.0 19.1 1450 1449 21.8 3.6 MPK-18 Wpl 102.8 115.9 1050 1050 15.8 2.6 MPK-37 Wpl 188.4 201.6 1050 1050 15.8 2.6 MPK-38 Wpl 215.5 228.7 1050 1050 15.8 2.6 MPF-10 Wp1 87.7 100.8 1050 1050 15.8 2.6 Close Approach Status Exit Exit Close Danger Shut-in Approach Zone Zone Status MD MD 1550 1800 OK OK OK SHUT-IN OK OK OK OK Halliburton Travelling Cylinder Report Computed using WIN-CADDS REV2.2.1 Page 1 Date: 3/20/96 Time: 1:41 pm Normal Plane Method All distances are between EXPECTED Positions REFERENCE WELL: BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-9 Est MPK-09 (96F) Wp2 Preliminary N/S and E/W are measured from the WELLHEAD TVD is measured from the WELLHEAD Interval Step Depth 50.00 ft.(MD) From 0.00 To 10411.60 ft.(MD) All Directions using BP Highside Method in Dec. Deg. All Depths and Distance are in FEET All distances are between EXPECTED Positions Slot Wellpath Distance MPK- 17 As-Built MPK- 17 MWD 58.11 62.37 MPK-25 As-Built MPK-25 MWD 113.75 130.09 MPK-25 As-Built MPK-25 Wp2 119.49 138.10 MPK-5 Est MPK-5 (96K) Wpl 30.26 36.95 MPK- 18 Est MPK- 18 Wp 1 124.45 152.30 MPK-37 Est MPK-37 Wpl 210.08 343.40 MPK-38 Est MPK-38 Wpl 237.10 423.78 MPK- 10 Est MPF- 10 Wp 1 109.80 4148.07 Closest Points Direction Ref MD Ref TVD Sep Factor 150.11 1000.00 1000.00 9.1 147.51 1250.00 1249.92 8.4 158.92 850.00 850.00 20.4 162.11 1250.00 1249.92 17.4 157.84 0.00 0.00 43096.6 155.73 1450.00 1449.46 16.7 336.45 0.00 0.00 30.3 8.32 1750.00 1746.68 3.4 97.29 0.00 0.00 124.4 107.03 1600.00 1598.53 16.9 158.38 0.00 0.00 210.1 152.05 2100.00 2090.04 25.6 130.65 0.00 0.00 237.1 135.78 2250.00 2234.02 28.0 68.38 0.00 0.00 109.8 81.87 6600.00 4907.78 13.1 Halliburton Travelling Cylinder Report Computed u~ing WIN-CADD$ RE1/2.2.1 P~ge 1 Date: 3/20/96 Time: 1:41 pm Normal Plane Method All distances are between EXPECTED Positions REFERENCE WELL: BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-9 ]Est MPK-09 (96F) Wp2 Preliminary N/S and E/W are measured from the WELLHEAD TVD is measured from the WELLHEAD Interval Step Depth 50.00 ft.(MD) From 0.00 To 10411.60 ft.(MD) All Directions using BP Highside Method in Dec. Deg. All Depths and Distance are in FEET All distances are between EXPECTED Positions Closest Points Slot Wellpath Distance Direction MPK-17 As-Built MPK-17 MWD 58.11 150.11 62.37 147.51 MPK-25 As-Built MPK-25 MWD 113.75 158.92 130.09 162.11 MPK-25 As-Built MPK-25 Wp2 119.49 157.84 138.10 155.73 MPK-5 Est MPK-5 (96K) Wpl 30.26 336.45 36.95 8.32 MPK- 18 Est MPK- 18 Wp 1 124.45 97.29 152.30 107.03 MPK-37 Est MPK-37 Wpl 210.08 158.38 343.40 152.05 MPK-38 Est MPK-38 Wpl 237.10 130.65 423.78 135.78 MPK-10 Est MPF-10 Wpl 109.80 68.38 4148.07 81.87 Ref MD Ref TVD Sep Factor 1000.00 1000.00 9.1 1250.00 1249.92 8.4 850.00 850.00 20.4 1250.00 1249.92 17.4 0.00 0.00 43096.6 1450.00 1449.46 16.7 0.00 0.00 30.3 1750.00 1746.68 3.4 0.00 0.00 124.4 1600.00 1598.53 16.9 0.00 0.00 210.1 2100.00 2090.04 25.6 0.00 0.00 237.1 2250.00 2234.02 28.0 0.00 0.00 109.8 6600.00 4907.78 13.1 WELL PERMIT CHECKLIST F .LD . POOL 5-- 2 5--10 0 GEOL AREA PROGRAM: exp [] dev ~ redrll [] serv [] wellbore se9 [] ADMINISTRATION l. Permit fee attached ................... 2. Lease number appropriate ............... 3. Unique well name and number .............. 4. Well located in a defined pool ............. 5 Well located proper distance from drlg unit boundary. 6. Well located proper distance from other wells ...... 7. Sufficient acreage available in drilling unit ..... 8. If deviated, is wellbore plat included ........ 9. Operator only affected party .............. 10. Operator has appropriate bond in force ......... 11. Permit can be issued without conservation order ..... 12. Per, it can be issued without administrative approval. 13. Can permit be approved before 15-day wait ........ ENGINEERING 14. Conductor string provided ............... ~ N 15. Surface casing protects all known USDWs ........ N 16. CMT vol adequate to circulate on conductor & surf csg.~ N 17. CMT vol adequate to tie-in long string to surf csg .~--~ N 18. CMT will cover all known productive horizons ...... ~ N 19. Casing designs adequate for C, T, B & permafrost .... ~ N 20. Adequate tankage or reserve pit ............. ~ N 21. If a re-drill, has a 10-403 for abndumnt been approved. ~ 22. Adequate wellbore separation proposed .......... ~ N 23. If diverter required, is it adequate .......... ~ N 24. Drilling fluid program schematic & equip list adequate .~ N 25. BOPEs adequate ...................... [~! N 26. BOPE press rating adequate; test to ~ psig.~ N 27. Choke manifold complies w/API RP-53 (May 84) ....... ~· N~ 28. Work will occur without operation shutdown ....... ~ N 29 Is presence of H2S gas probable ............. Y ~ GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures .... Y N 31. Data presented on potential overpressure 32. Seismic analysis of shallow~ ....... Y N 33. Seabed condit~off-shore) ........ Y N 34. Cont one for weekly progress reports ..... Y N [exploratory only] REMARKS GEOLOGY: ENGINEERING: COMMISSION: TAB Comments/Instructions: m HOWlljb- A:~FORMS\cheklist rev 11195
