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Home My WebLink About196-049Pages NOT Scanned in this Well History File XHVZE 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. [ ~'~_. L{C~ File Number of Well History File PAGES TO DELETE Complete RESCAN [] Color items - Pages: Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original- Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED [] Logs of various kinds [] Other COMMENTS: Scanned by: Bevedy ~ncent Nathan Lowell [] TO RE-SCAN Notes: Re-Scanned by: Be~,edy Dianna Vincent Nathan Lowell Date: Isl THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON OR BEFORE JANUARY 03 2001 PL M ATE E IA L U W N D E R T H IS M ARK E R Memorandum State of Alaska Re: Oil ~nd Gas Conservaxion Commission t BI, 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 ~e. 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 ddii. 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 APl number and in some instances the well name reflect the number of preexistin! reddiis and or muitilaterals 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 ddll. 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 AP! numbering methods described in AOGCC staff memoranaum "Multi-lateral (weltbore segment) Drilling Permit Procedures, revised December 2g, lg95. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician F~× NO.: 2654966 0~-1~-97 09:51 P.81 ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 995100360 Telephone 907 276 1215 Scott L Kerr Manager Kuparuk Development ATO 1220 Phone 26;3-4348 Fax 265-6133 March 3, 1997 Post4t'" brand fax transmittal memo 7671 TO ........ Mr, Howard Mayson Asset Manager, Milne Point Unit BP Exploration {Alaska) Inc. 900 East Benson Boulevard P, O. Box 196612 Anchorage, AK 99519-6612 Dear Howard: Attached is the original copy of the Memorandum of Agreement (MOA) regarding .K~Well 30-20 (A) and MPU Wells ddlled near KRU/MPU Boundary. We have i-etained--a copy for our flies and assume you will retain the original in your MPU files. Sincerely, Scott Kerr SIK/cjf Attachment Frank Brown Dan Roctgers Dave Sutter FRX NO.: 2634966 03-13-97 09:51 p.02 Memorandum'¥~6f~ Agre~ent Regarding MPU Wells Dr,lle~ ~ear.~,,~~M)~'~ i~unclary ARCO Alaska, Inc. ("ARCO"), as Operator and on behalf of the Working Interest Owners of the Kuparuk Participating Area of the Kuparuk River Unit ("KRU"), proposed to drill Well 30-20(A) near the boundary of the KRU and the Mitne Point Unit ("MPU") to develop the Kuparuk Reservoir in the KRU. The preliminary target location of the well was to be within the KRU and 500 feet south of the KRU/MPU boundary line ("Boundary Line" as defined below), which is permitted by state statues and regulations. After consultation, BP Exploration (Alaska), Inc. ("BPXA'), as Operator and on behalf of the MPU Working Interest Owners, and ARCO determined that the best development practice for the Kuparuk Reservoir, which also exists in the Kuparuk Participating Area of the MPU, would be to drill wells near the Boundary Line as follows. ARCO will drill well 30-20(A) to a target location within the KRU and approximately 1200 feet south of the Boundary Line, BPXA will not drill a well to a target in the Kuparuk Reservoir closer than 1200 feet north of the Boundary Line. ARCO wii not drill a well to a target in the Kuparuk Reservoir closer than 1200 feet sou[h of the Boundar7 Line. (Attachment 1). For purposes of this agreement, the Kuparuk Reservoir is defined as that interval between 7586 MD (-6373 'I'VD ss) and 7915 MD (-6646 TVD ss) as found in KRU Well 30-14. Also for purposes of this agreement, the Boundary Line is defined as that common border between the following adjoining sections: From MPU the Boundary Line is the South Line of the SW quarter of section 23, Township 13N and Range 9E UM. From KRU the Boundary Line is the North Line of the NW quarter section of section 26, Township 13N and Range 9E UM. (Attachment 2), This agreement is limited to only these named quarter sections. ARCO Alaska, inc. Operator of the Kuparuk River Unit By: Its: Date; BP Exploration (Alaska), Inc. Operator of the Milne Point Unit Date: . 2-tt%tq'7 -6698 30-1 30-13 FI:IX NO.: .26~4966 , 1 -6715 ~t~ -67Zj 0~-1~-97 89:52 P.O~ Future MPU Producer (ApProximate BHL) Future MPU Well (min. 1200' North of Unit Bounda HPU M-O ] MPU 30-1 · -2g 3K-08 KRU / MPU Development Plan Well DS 30-20 (Al Attachment #1 (note: BHL's are ~~~ ~ wells but could be drill&~as horizontal wells) ../ ~ ~ KRU < I' 3 ' 3 ,~ 30-20(A) Producer ~K (min. 1200' South of Unit Boundary -6722 · Ii -6659 3K-lq · -6736 [] FAX NO.: 2634966 OJ-1J-9? 09:52 P.04 I I i ~ ~o-~§ ~OL 2551 ~OL 25528 aO-18 t + I 3K-92 & i SIMPSON LRGOON 32-1~1:1 80-20(A) W'ell Pa[h ~ 2*3 + "Boundary Line" ~OL 255 FtOL 25'5 19 .,.,,,'" ~ 30-2--8 (FI) ~ E;a3Z + 26 ~- FEE'f' 0 200~,') <3 'T'~ T U ';'E .."'1 r L ARCO Alaska, Inc. KU?RRUK DEVELOPMENT PLRNNING ORILLSITES 30 RNO 3K PROPOSED 30-20 LOCRTION RNO TRRJECTORY RTTRCHMENT Z .. i MPU KRU BP EXPLORATION Memorandum Date April 19, 1996 t To: Alaska Oil & Gas Conservation Commission /~..'.~i'~ ......... From' Kathy Campoamor / ~- ...... · Shared Services Drilling ( ~'-T~` Technical Assistant ~ ~~ .~ ~~ ~~ Subject: Permit ~96-49 (Now ~96-76) ~ The AOGCC originally issued permit g96-49 to we? ~5-37.. W~. then submitted a revision to permit g96-49 changing the BHL and well type. Subsequently, a new permit number was issued. This memo is to advise the AOGCC that permit g96-76 replaces the original issued permit for MPK-37 and that we wish to cancel Permit To Dri1~6-49. ~ Regards, Kathy Campoamor 564-5122 RECEIVED /klc Alaska 0ii 8, Gas Oons. Commission Anchorage ALASKA OIL AND C~kS CONSERVATION COMMI~SION TONY KNOWLE$, GOVERNOF~ 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 March 13, 1996 Tim Schofield, Sr. Drlg. Eng. BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Milne Point Unit MPK-37 BP Exploration (Alaska), Inc. Permit No: 96-49 Sur. Loc. 3509'NSL, 2045'WEL, Sec. 03, T 12N, K11E, UM Btmhole Loc. 74'NSL, 2050'WEL, Sec. 03, T12N, K11E, '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. A request for an amendment to Area Injection Order No. 10 must be received and approved before injection into the subject well. The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035; and the mechanical integrity (MI) of the injection wells must be demonstrated under 20 AAC 25.412 and 20 25.030(g)(3). Sufficient notice (approximately 24 hours) of the MI test before operation, and 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 tests. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Commissioner BY ORDER OF THE COMMISSION dlf/Enclosures 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 [] Redrill I-lllb. Type of well. Exploratoryl-I Stratigraphic Test [] Development Oil [] Re-Entry [] Deepen []1 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. KBE = 61 feet Milne Point Unit / Kuparuk River 3. Address 6. Property Designation P. O. Box 196612, Anchorage, Alaska 99519-6612 ADL 375133 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025) 3509' NSL, 2045' WEL, SEC. 3, T12N, R11E Milne Point Unit At top of productive interval 8. Well number Number 272' NSL, 2050' WEL, SEC. 3, T12N, R11E MPK-37 2S100302630-277 At total depth 9. Approximate spud date Amount 74' NSL, 2050' WEL, SEC. 3, T12N, R11E 04/12/96 $200,000.00 12. Distance to nearest 13. Distance to nearest well 4. Number of acres in property15. Proposed depth (MD andTVD) property line ADL375132 2050 feet MPK-38,116'@2249'TVD feet 2560 8479'MD/7399'TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth 2000 feet Maximum hole angle36.48 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" 91.1t/ NT8OLHE Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 401/ L-80 Btrc 3628' 31' 31' 3659' 3523' 721 sx PF 'E', 250 sx 'G', 250 sx PF 'E' 8-1/2" 7" 261/ L-80 Mod B 8449' 30' 30' 8479' 7399' 235 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~'..~.~ ~ ~? Surface Intermediate FEB 2 9 Production Liner Alaska 0i! & '"~ , ....... Perforation depth: measured true vertical 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program[] Drilling fluid program [] Time vs depth plot [] Refraction analysis[] Seabed report[] 20 AAC 25.050 requirements[] 21. I hereby ce~fy th~at the foreg~ling is true and correct to the best of my knowledge Signed ~¢~,,~ ~ c~,~.~j~ TitleSeniorDrillin~lEn~lineer Date 777//'~g~ //" Commission Use ' Only Permit N_umber r IAPI number ..... Appro.val date See cover letter ~>.~'_¢_~¢ 150-O.;Z.~'- 7---~--(~,5 ~' I ~;~,/'/-~/c~ for other requirements Conditions of ~pproval Samples required [] Yes []No Mud log required []Yes [] No Hydrogen sulfide measures [] Yes J~ No Directional survey required ~1 Yes [] No Required working pressure for BOPE [] 2M; ~[Z]v3M; 1~5M; []l OM' I-'115M; Other: ORIGINAL SI(~ED,.,, ' by order of _Approved by J. David Norton, P.E. Commissioner tne commission Date Form 10-401 Rev. 12-1-85 Submit in triplicate I Well Name: [ MPK-37i I Well Plan Summary ]Type of Well (producer or injector): I Kuparuk Injector I Surface Location: 3509' FSL 2045' FEL Sec 3 T12N R11E UM., AK. Target Location: 272' FSL 2050' FEL Sec 3 T12N R11E UM., AK. Bottom Hole 74' FSL 2050' FEL Sec 3 T12N 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: 1337015 IEstimated Start Date: IApril 12, 1996 Rig: I Nabors 27E Operating days to drill and case: 113 I IMD: 18479' I I TVD: 17399' BKB I I mug: I61' I ] Well Design (c°nventi°nal' slimh°le' I Ultra Slimh°le' 7" L°ngstringetc.): I Formation Markers: Formation Tops MD TVD Formation Pressure/EMW Base permafrost 1811 1811 n/a NA (Top Schrader) 5074 4661 1905 psig/ 8.0 ppg OA 1955 psig/ 8.0 ppg Base Schrader Bluff 5335 4871 1995 psig/ 8.0 ppg Top HRZ 7374 6511 n/a Base HRZ n/a Kupark D Shale 7859 6901 n/a Kuparuk C 8145 7131 3650 psig/ 10 ppg TKB 3669 psig/ 10 ppg Total Depth 8479 7399 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 3628' 31' 3659/3523 8 1/2" 7" 26# L-80 Mod B 8449' 30' 8479/7399 N/A (tbg) 3-1/2" 6.5# L-80 EUE 6771' 29' 6800/7021 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 MWD ONLY Schrader Bluff MWD / CDR- (CDN & MRIL Optional - M. Vandergon @ 564-5089) Final LWD GR/Resistivity/SFC CSG to TD CDN over Kupamk intervals ]Mud Logs: Mud logs and samples are not required AP1 # 50-029-22XXX 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 10 PPG by 2000 feet. We will weight up in 0.5 ppg increments as necessary. We will use the coldest mix water available to minimize warming if the interval. We will use only 8" directional motors to allow lower flow rates. We will control flow rates to below 600 GPM when hydrates are >resent to keep mud temperatures to a minimum. Surface Mud Properties: [ 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 10.5 100 35 15 30 10 15 Production Mud Properties: I 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: I KOP: 12000' Maximum Hole Angle: Maximum Dog Leg: Inclination in target: Close Approach Well: 36.48 degrees < 4 degrees 36.48 Degrees MPK 38 Well Plan is 116 feet @ 2249 feet This wellplan will allow MPK-37i 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. 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. AP1 # 50-029-22XXX February 29, 1996 Request for AOGCC Approval Disposal of Drilling Wastes (20AAC25.254) 1. Approval is requested for Annular Pumping for K Pad well MPK-37i 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 ± 2150 to ± 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 3659'md 3523 ('tvd) and cemented with 703 "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 is 4600 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-8.0 ppg) X 0.052 X Surf Csg Shoe TVD i ~ MASP (psi) -- 952 psi '~ 9. The maximum pressure imposed at the surface casing shoe is calculated according to the fei ~,~ving-~- ~nuntion: c> Max Press @ Surf Csg Shoe (psi) = .052 x Max Breakdown ppg x Surf Csg Shoe TVD :,~-' Max Prss at Surf Csg Shoe =2473 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. -.~.h~, WELL PREV VOL PI~RIVIiTTED PERMITTED DATES . INJECTED (BBL)__V. OL (BBL) Milne Point M P K- 1 7 0 .... 3..5., 000 Requested Milne Point M P K- 2 5 0 3 5,0 0 0 Requested Milne Point M P K- 1 8 0 3 5,0 0 0 Requested Miine Point M P K-3 7i 0 3 5,0 0 0 Requested Milne Point MPK-3$ 0 "' ;~-~','0 0 0 Requested Miine Point M P K- 1 0 i 0 3 5,0 0 0 Requested 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 irtjeeted every 6-12 hours. This practice is more economical than pumping 60 bbls of diesel freeze protection every t/me 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. API# 50.029-22XXX March 4, 1996 E/E'd HOIZ~$OqdX3 d8 N~0~:0~ 9fi, ~0 S~N 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 equipment mechanical problems with the surface equipment, rather than formation drilling problems. Hydrates We will have hydrates on K Pad. We will have our mud weight to 10 PPG by 2000 feet. We will weight up in 0.5 ppg increments as necessary. We will use the coldest mix water available to minimize warming if the interval. We will use only 8" directional motors to allow lower flow rates. We will control flow rates to below 600 GPM when hydrates are present to keep mud temperatures to a minimum. 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. Be prepared to treat these losses while drilling initially with LCM treatments. This will become even more prevalent in the production hole when we shallow set surface casing. Weighting up before entering the reservoir will be the most likely time we would lose circulation. Stuck Pipe Potential: There has been several cases of stuck pipe occuring at the top of the Kuparuk, with both the intervals above and below the Schrader Bluff open. We have made improvements to the mud system and continue to monitor for stuck pipe 'conditions. The stuck pipe intervals and short trip guidelines on the Pad Data Sheet should be followed to avoid stuck pipe incidents. Running casing should be as smooth and quickly as possible to avoid stopping casing and possibly getting stuck. Shallow Set Casing: The wells at K Pad will use shallow set casing which can provide cost savings if the wells are trouble free. There are increased risk for stuck pipe, lost circulation, especially while running casing. The casing program will include running centralizers over both the Kuparuk and Schrader Bluff, and cemented in a single stage. The rig team will need to be more careful on these wells to fully realize the cost benefits. Kick Tolerance: The surface casing setting depth for this well allows a kick tolerance of 38.4 bbl influx (Gas) based on a 12.5 ppg LOT at the 9-5/8" casing shoe and a estimated reservoir pressure of 3708 psig (9.9 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 9.9 ppg EMW (3708 psi @ 7131' 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. 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 February 29, 1996 MP K-37i Proposed Summary of Operations o . o o o o 10. 11. 12. 13. 14. 15. 16. 17. 18. 17. POST , , , . Drill and Set 20" Conductor. Weld an FMC landing ring for the FMC Gen 5A Wellhead on the conductor. Prepare location for fig move. MIRU Nabors 27E drilling rig. 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 3659' md (3523' tvd). Use extreme care when drilling through the known hydrate interval down to _+ 3100 feet TVD. 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. cumulative volume for LOT test for well file. Follow Pad Data Sheet short trip guidelines. Drill 8-1/2" hole to end of the build past the Base of Schrader Bluff at 5335' MD (4871' TVD). POOH to run MRIL wireline logs if required. Drill 8-1/2" hole to TD at 8479' MD (7399' TVD). (Note: This hole section will be logged with LWD Triple Combo (GR/Res/Neu/Dens). 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 2000' TVD with diesel. Closely monitor casing running loads for drag. Make sure there is a circulating head for the topdrive before starting to run casing. ND BOPE and NU dry hole tree. Release rig to MPK- 10i. Note: This well will be 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. 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. A SBT/GR/CCL is not required on this well and will only be run if there are problems on the production cement job. 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. AP1 # 50-029-22XXX February 29, 1996 MPK-37i WELL 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON CASING SIZE: 9-5/8" CIRC. TEMP 80 deg F at 4000' TVDSS. SPACER: 75 bbls fresh water. 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: 721 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: 250 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 E Permafrost ADDITIVES: Retarder WEIGHT: 12.0 ppg YIELD: 2.17 cu ft/sk. MIX WATER: 11.63 gal/sk APPROX NO SACKS: 250 CENTRALIZER PLACEMENT: 1. 1 Bowspring centralizer per joint of 9-5/8" casing on the bottom 10 joints above the FS. 2. Place all centralizers in middle of joints using stop collars. OTHER CONSIDERATIONS: P~erform 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 we were shut down filling only 5 joints. CEMENT VOLUME: 1. The Tail Slurry volume is a standard 250 sacks is calculated to cover the 9-5/8" Casing Shoe with 30% excess. 2. The Lead Slurry volume is calculated to cover from the top of the Tail Slurry to 1500' md with 30% excess and from 1500' md to surface with 100% excess. 4. 80'md 9-5/8", 40//capacity for float joints. 5. Top Job Cement Volume is 250 sacks. ~ ~ ~i ~ ~- i ~t~{ ~'Z ~i? Ar~chora9~:: API # 50-029-22XXX February 29, 1996 MPK-37i 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, 30#/SK Silicalite, 1.7% Halad 344 WEIGHT: 12.25 ppg YIELD: 2.81 cu ft/sk APPROX # SACKS: 235 FLUID LOSS: < 45cc/30 min @ 140° F MIX WATER: 16 gal/sk THICKENING TIME: 4 1/2 hrs @ 140° F FREE WATER: 0cc @ 45 degree angle. CENTRALIZER PLACEMENT: 1. 7" x 8-1/4" Straight Blade Rigid Centralizers-- two per joint on the bottom 17 joints of 7" Casing (34 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 (20Total). 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 8-10 bpm. Batch mixing is not necessary, CEMENT VOLUME: 1. Stage 1 cement volume is calculated to cover 500' md above the NA Top with 30% excess. FEB 29 lS,96 Oil & Gas Cons. Anchorage AP1 # 50-029-22XXX February 29, 1996 MPK-37i Cement Calculator Milne Point Cement and Centralizer Calculations Well I MPK-25 I ~ i _~ Surface (1 Stage) Cement Job i,i i I i cement Type E I G Hole Size 12.25 Yeild (cfs) 2.17 1.1 5 Casing Size 9.625 Weight (ppg) 1 2 1 5.8 BPF 0.0558 BPF + 30% 0.0725 BPF+100% [ 0.1116 -- Depth I BBLS Cu. Ft. i Sacks Top of Cemenl Shoe Depth iilii ii ii!ii!!iiiii!iii~iii!:ili~ii: !i~: iiiiii:::i, iii~ii i ~ Calculated -, G Tail Volume 623 i 51.2 i, 288 ! 250 3036i E Lead Volum~ 1500 " 167 3 I 940 I 433 1536 ETaiIVolume i 1536 i 111.4 i 625 i 288 0 ~ I I i Total E I 7 2 li I Total G I 2 5 0 I 9-5/8" Bows I O, ] i I Production 1-Stage Cement Job ~ l' i~ !i Cement ,I Yield J Hole Size 8.51 !Silicalite Slurry 2.81 Casing Size 7 , I - i BPF . 0.0226 BPF + 30% [ 0.02941 , _ I Top of Cemenl __ Stage 1 IVD BBLS Cu. Ft. ! Sacks Calculated ! 4574 NA Top iiiiiiiii!!ii!i!;iii~;i'.iii~:i!{ii';;~::ii~iiiii~i 118 I 661 ! 235 Seabee Top ii~!i~i~!~i i f I ! i I Centralizers . 30 Across the Kuparuk _[ ._ _ Centralizers II 27 Across the Schraderi Bluff . Total G ST1 235 i ' Total ST Bladei 5 7 ! I --' Page 1 .BIbX - Sho, r, ed Ato,~l-<o, Sto,-t:e Mitn e P-t: ' lvlpK MPK-37 F'~ MPK-37 Wp1 ~ Sex v, ces DmiLLin9 Plane: Zone4 HALLIBURTON O--' 10OO~ 1500~ 1811 L:~O0 ~0w 3363 3500-- 4000-- 4500-- 4(:~1 4871 5500-- 6901 7000-- 7131 7399 7500-- VERTICAL VIEW SCALE 500 Fi:. / DIVISION TVD REV: WELLHEAD VERTICAL SECTION REF: WELLHEAD I-ORIZONTAL VIEW (TRUE ~TH) SCALE 500 Ft. / DIVISION SURVEY REF: WELLHEAD 0.00 @ 0 MD TIE IN 0.00 @ 1811 MD Bose Pe~mof~ost O.OO @ Lq3OO MD K~ / START II BUILD @ ~.50/100 Ct 2.5O @ 21[X3 MD 5.00 ~ 22[X3 HD 03 ~ 10.~0 ~ 240O ~D ~ 12.50 ~ 25~0 HD 15.00 ~ 2600 HD % ~u.uu e ~uu mu Bose 1811 0.00 179.99 1811 0 N 0 E ~38.50 @ 33001MD PeDm~F~ost ~ ................. KEP / START c~]O0 0.00 179.99 EK)O0 0 N 0 E 449~ ~&, 9 5/8 ',n FID ¥~' ' ' E~D EF BUILD 3459 36.48 17g.gg 3363 449 S 0 E ~ NA S~ncts 5074 36.48 179.99 4661 1409 S 0 E ~ Bose Scl~odeD 5335 36.48 179.99 4871 1564 S 0 E ~ TI-RZ 7375 36.48 179.99 6511 2777 S 0 E ~ TKUD 7860 36.48 17g.gg 6901 3065 S 0 E x~ K-J / TKUC1 8146 36.48 179.99 7131 3836 S 0 E ~ I F1D MD Inc gzi IYD N/§ F/W ~ I 9 ~/8 ~n 3659 ~:,.48 179.99 3~3 ~ g 0 F ~ 7 m 8479 B6.48 179.99 7399 3434 § 0 F '~ B&48 @ 5074 MD Ix~ Sands 5335 MD Bose Sch~ode~ ~ ITo~tNo~e TVD NS EW C~iOX C~idYI K-J 7131 ~ S 0 E ~4~0 Gooe40gI FEB 29 1996 Anch°ra~e3065 ~xx,36,48 8 7860 MD TKUD N~.48 e 8146 MD K-J / TKUCI N , 7, M 399 TVD 3434 -500 0 500 1000 1500 L:~O0 2500 3000 3500 40CKD VERTICAL SECTION FLAKE: ! 79.99 Halliburton Energy Services - Drilling Systems PSL Proposal Report Page I Date: 2/9/96 Time: 4:09 pm · Wellpath ID: MPK-37 Wpl Last Revision: 2/9/96 Survey Refercnec: WELLHEAD Reference World Coordinatcs: Lat. 70.25.31 N - Long. 149.18.41 W Reference GRID System: Alaska State Plane Zone: Alaska 4 Refercncc GRID Coordinates: (it): 6005644.00 N 584513.00 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-C,4DDS REY2. I.B Vertical Section Plane: 179.99 deg. BPX -Shared Services Drilling Alaska State Plme: Zone4 Milne Pt: MPK MPK-37 Est MPK-37 Wpl ~,,d/'E/ Measured Incl Drift Subsea TVD Course Depth Dir. Depth Lcngth (fl) (deg.) (deg.) (it) (fl) (it) TOTAL Rectangular Offsets (it) (it) TIE IN 0.00 0.00 0.00 -61.00 0.00 0.00 Base Permafrost 1811.00 0.00 0.00 1750.00 1811.00 1811.00 KOP / START OF BUILD ~ 2.50 deg/100 it 2000.00 0.00 0.00 1939.00 2000.00 189.00 O.OON 0.00 E O.OON 0.00 E O.OON 0.00 E 2100.00 2.50 179.99 2038.97 2099.97 100.00 2200.00 5.00 179.99 2138.75 2199.75 100.00 2300.00 7.50 179.99 2238.14 2299.14 100.00 2.18 S 0.00E 8.72 S 0.00 E 19.61 S 0.00 E 2400.00 10.00 179.99 2336.97 2397.97 100.00 34.82 S 0.00E 2500.00 12.50 179.99 2435.04 2496.04 100.00 54.33 S 0.01 E 2600.00 15.00 179.99 2532.17 2593.17 100.00 78.095 0.01E 2700.00 17.50 179.99 2628.17 2689.17 100.00 106.07 S 0.01E 2800.00 20.00 179.99 2722.85 2783.85 I00.00 138.215 0.02E 2900.00 22.50 179.99 2816.05 2877.05 100.00 174.465 0.02E 3000.00 25.00 179.99 2907.57 2968.57 100.00 214.735 0.02E 3100.00 27.50 179.99 2997.25 3058.25 100.00 258.95 S 0.03E 3200.00 30.00 179.99 3084.92 3145.92 100.00 307.05 S 0.03 E 3300.00 32.50 179.99 3170.40 3231.40 I00.00 358.92S 0.04E 3400.00 35.00 179.99 3253.54 3314.54 100.00 414.47S 0.05E END OF BUILD 3459.21 36.48 179.99 3301.60 3362.60 59.21 449.06 S 0.05 E CASING POINT OD = 9 5/8 in, ID = 8.84 in, Weight = 40.00 lb/it. 3659.00 36.48 179.99 3462.24 3523.24 199.79 567.84 S NA Sands 0.06 E GRID (~ordinates Northing Easting (it) (it) 6005644.00 584513.00 6005644.00 584513.00 6005644.00 584513.00 6005641.82 584513.03 6005635.28 584513.10 6005624.40 584513.22 6005609.19 584513.40 6005589.69 584513.62 6005565.92 584513.89 6005537.95 584514.21 6005505.81 584514.58 6005469.58 584515.00 6005429.31 584515.46 6005385.09 584515.96 6005337.01 584516.51 6005285.14 584517.11 6005229.60 584517.74 6005195.02 584518.14 6005076.25 584519.49 Closure Vcrtical Dist. Dir. Section (it) (deg.) (it) 0.00~ 0.00 0.00 o.oo~ o.oo o.oo 0.00~ 0.00 0.00 Build Walk DLS Cum. Rate Rate Dogleg (dg/iOOR) (dg/lOOit) (dg/lOOit) (deg) Expected Total Rectangular Coords (it) (ft) 0.00 0.00 0.00 0.0 0.00N 0.00 E 0.00 0.00 0.00 0.0 0.00N 0.00 E 0.00 0.00 0.00 0.0 O.00N 0.00 E 2.18(~ 179.99 2.18 2.50 0.00 2.50 8.72~179.99 8.72 2.50 0.00 2.50 19.61@179.99 19.61 2.50 0.00 2.50 34.82~179.99 34.82 54.33~179.99 54.33 78.09~179.99 78.09 106.07~179.99 106.07 138.21~!79.99 138.21 174.46(~179.99 174.46 214.73~179.99 214.73 258.95~!79.99 258.95 307.05~179.99 307.05 358.92~179.99 358.92 414.47@179.99 414.47 449.06~179.99 449.06 2.50 0.00 2.50 2.50 0.00 2.50 2.50 0.00 2.50 2.5 2.185 0.00E 5.0 8.725 0.00E 7.5 19.615 0.00E 2.50 0.00 2.50 2.50 0.00 2.50 2.50 0.00 2.50 10.0 34.825 0.00E 12.5 54.335 0.01E 15.0 78.095 0.01E 17.5 106.075 0.01E 20.0 138.215 0.02E 22.5 174.465 0.02E 2.50 0.00 2.50 25.0 2.50 0.00 2.50 27.5 2.50 0.00 2.50 30.0 2.50 0.00 2.50 32.5 2.50 0.00 2.50 35.0 2.50 0.00 2.50 36.5 567.84~ 179.99 567.84 0.00 0.00 0.00 36.5 214.73 S 0.02 E 258.95 S 0.03 E 307.05 S 0.03 E 358.92 S 0.04 E 414.47 S 0.05 E 449.06 S 0.05 E 567.84 S 0.06 E Max Hor Min Hor Dir. Vert Error Error Max Err Error (it) (it) (deg.) (it) 0.00 0.00 0.00 0.00 MWD 5.00 5.00 0.00 2.62 BPHM-PBD 5.46 5.46 0.00 2.91 BPHM-PBD 5.70 5.70 89.99 3.07 BPHM-PBD 5.96 5.93 89.99 3.24 BPHM-PBD 6.26 6.15 89.99 3.44 BPHM-PBD 6.62 6.37 89.99 3.66 BPHM-PBD 7.07 6.58 89.99 3.91 BPHM-PBD 7.63 6.79 89.99 4.17 BPHM-PBD 8.34 7.00 89.99 4.46 BPHM-PBD 9.21 7.21 89.99 4.78 BPHM-PBD 10.24 7.42 89.99 5.12 BPHM-PBD ! 1.44 7.63 89.99 5.48 ·BPHM-PBD 12.81 7.85 89.99 5.88 BPHM-PBD 14.35 8.08 89.99 6.30 BPHM-PBD 16.04 8.32 89.99 6.75 BPIlM-PBD 17.88 8.56 89.99 7.23 BPHM-PBD 19.02 8.71 89.99 7.53 BPHM-PBD 0.00 0.00 0.00 0.00 BPHM-PBD Survey Tool s~assauus tou .,~ucrgy ocrvaces - IJrllllng :Systems PSL Proposal Report Measured lncl Drift Subsca TVD Course T O T A L 1,4OE:~ GRID Coordinates Closure Vertical Build Walk DLS Cum. Expected Total Max Hot Mia Hor Dir. Vcrt Depth Dir. Depth Length Rcclangular Offsets Northing Easting Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error Error Max Err Error (ft) (deg.) (deg.) (ft) (ft) (ft) (fi) (ft) (ft) (ii) (ft) (deg.) (ft) (dgtl00ft) (dg/100ft) (dg/100ft) (deg) (t~) (ft) (ft) (ft) (deg.) (ft) Page 2 Date: 2/9/96 Wcllpath ID: MPK-37 Wpl Survey Tool 5074.01 36.48 179.99 4600.00 4661.00 1415.01 1409.13 S Base Schrader 5335.19 36.48 179.99 4810.00 4871.00 261.17 1564.41S THRZ 7374.83 36.48 179.99 6450.00 6511.00 2039.64 2777.07S 0.16E 6004235.10 584529.11 1409.13~179.99 1409.13 0.00 0.00 0.17E 6004079.84 584530.89 1564.41~179.99 1564.41 0.00 0.00 0.31 E 6002867.37 584544.76 2777.07~179.99 2777.07 0.00 0.00 0.00 36.5 1409.13 S 0.00 36.5 1564.41 S 0.00 36.5 2777.07 S 0.15E 51.93 16.68 89.99 13.17 BPHM-PBD 0.17E 57.35 18.04 89.99 14.17 BPHM-PBD 0.30 E 99.83 28.97 89.99 22.31 BPHM-PBD TKUD 7859.86 36.48 179.99 6840.00 6901.00 485.04 3065.44S K-J / TKUC 1 8145.91 36.48 179.99 7070.00 7131.00 286.05 3235.51 S CASING POINT OD = 7 in, ID = 6.28 in, Weight = 26.00 lb/fi. 8478.97 36.48 179.99 7337.80 7398.80 333.06 3433.53S TD 8479.22 36.48 179.99 7338.00 7399.00 0.25 3433.68S 0.34 E 6002579.04 584548.06 3065.44~179.99 3065.44 0.00 0.00 0.36 E 6002409.00 584550.00 3235.51@179.99 3235.51 0.00 0.00 0.38 E 6002211.02 584552.26 3433.53(~179.99 3433.53 0.00 0.00 0.38E 6002210.87 584552.27 3433.68~179.99 3433.68 0.00 0.00 0.00 36.5 3065.44 S 0.00 36.5 3235.51S 0.00 36.5 3433.53 $ 0.00 36.5 3433.68 S 0.33 E 109.96 31.60 89.99 24.29 BPHM-PBD 0.35E 115.93 33.15 89.99 25.46 BPHM-PBD 0.38 E 0.00 0.00 0.00 0.00 BPHM-PBD 0.37 E 122.89 34.96 89.99 26.83 BPHM-PBD BPX - Sba. mad Alo.~l<o. Sto,%e Milne P~ ' F'IPK IvlpK-37 Es-i:: MPK-37 Wpl ut'~ Sap',;- ~,__es }r~iLLing PLane: Zone4 Troveilin9 Cyilnder - Normal Plane ReFerence Well - NPK-37 Wpll MD: 0 - 8479 Ft. Interval, 50 Ft. All Directions using BP Hi,qhside Method Circles are the B.P. FLFIWIlXlG?SI-LIT-IN condi~on --'" t-IALLI BURTI3N 533 pm 27O lO0 180 STATUS ~PK-85 Wpl FLI]WIN(] IriS- 18 Wp 1 FLOWING I4:~K- 17 w~ FL~I~ ~-~ Wp1 FL~I~ C~CA~- lA FL~I~ CASCA~-O 1 FL~I~ ~K- 10 Wp i FL~I~ 180 F i!' © /-:] CLOSEST POINTS Slot Bstance Bnection Re£ MD ReF TVD Sep. Factc~ h~K-t:x5 Est 89.70 338.37 0.00 0.00 89.70 Nlq<-18 Est l~.~ 14.~ 0.~ 0.~ 1~.~ ~-17 As-Staked 149.~ 3~.21 0.~ 0.~ 149.~ g-~ Est 110.~ ~.27 0.~ 0.~ 110.~ CA,CA,-lA ~518.65 76.16 ~.~ ~.~ 4~19.~ CAZCA~-01 1518.65 ~6.16 ~.~ ~.~ 4~19.~ ~-10 Est ~7.04 5.97 0.~ 0.~ ~3~.~ Halliburton Travelling Cylinder Report Computed using WIN-CADDS REV2. I.B Page 1 Date: 2/9/96 Time: 5:33 pm Normal Plane Method REFERENCE WELL: BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-37 Est MPK-37 Wpl 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 8479.22 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 MPK-25 Wpl 47.2 73.3 2150 2150 31.5 5.4 MPK-I 8 Wpl 144.4 169.4 2000 2000 30.0 5.0 MPK-17 Wp2 108.4 133.4 2000 2000 30.0 5.0 MPK-38 Wp 1 68.8 94.2 2050 2050 30.5 5.1 CASCADE-lA 1455.3 1495.3 4000 3797 50.0 10.0 CASCADE-01 1491.2 1513.1 1750 1750 26.3 4.4 MPK-10 Wpl 196.1 221.1 2000 2000 30.0 5.0 Enter Exit Exit Danger Danger Shut-in Zone Zone Zone MD MD MD Close Approach Status OK OK OK OK OK OK OK Halliburton Travelling Cylinder Report Computed using WIN-CADDS REV2. I.B Page 1 Date: 2/9/96 Time: 5:33 pm Normal Plane Method REFERENCE WELL: BPX - Shared Services Drilling Alaska State Plane: Zone4 Milne Pt: MPK MPK-37 Est MPK-37 Wp 1 N/S and F_JW are measured from the WELLHEAD TVD is measured from the WELLHEAD Interval Step Depth 50.00 ft.(MD) From 0.00 To 8479.22 ft.(MD) All Directions using BP Highside Method in Dee. Deg. All Depths and Distance are in FEET All distances are between EXPECTED Positions Closest Points Slot Wellpath MPK-25 Est MPK-25 Wpl MPK-18 Est MPK-18 Wpl MPK-17 As. StakdVIPK-17 Wp2 MPK-38 Est MPK-38 Wp I CASCADE-lA CASCADE-IA CASCADE-01 CASCADE-01 MPK-10 Est MPK-IO Wpl Distance Direction RefMD RefTVD Sep Factor 89.70 338.37 0.00 0.00 89.7 1037.01 275.54 8300.00 7254.90 4.2 185.32 14.38 0.00 0.00 185.3 194.47 13.74 2200.00 2199.75 16.2 149.32 338.21 0.00 0.00 149.3 154.18 338.88 2150.00 2149.89 13.2 110.32 68.27 0.00 0.00 110.3 116.20 62.01 2250.00 2249.50 9.5 1518.65 76.16 50.00 50.00 4219.2 2429.55 331.63 5200.00 4762.30 12.8 1518.65 76.16 50.00 50.00 4219.2 1983.41 37.94 5650.00 5124.13 19.6 237.04 5.97 0.00 0.00 237.0 244.37 5.94 2150.00 2149.89 20.9 WELL PERMIT CHECKLIST PROGRAM: exp [] dev [] redrll [] serv~ wellbore seg [] UNIT# /4~/4/~~ ., ON/OFF SHORE ~/~3 ADMINISTRATION Permit fee attached ................... Lease number appropriate ................ Unique well name and number ............... Well located in a defined pool ............. Well located proper distance from drlg unit boundary. Well located proper distance from other wells ...... Sufficient acreage available in drilling unit ..... If deviated, is wellbore plat included ......... Operator only affected party ........... ./~'. Operator has appropriate bond in force ...... >' Permit can be issued without conservation order. { .... Permit can be issued without administrative approval. Can permit be approved before 15-day wait .... N D~TE/ 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. N N ENGINEERING Conductor string provided ............... ~ N ....................... 1.../' ,~. ~. ' .. /' .. ............... " Surface casing protects all known USDWs ........ ~ N .................... ------ .......................................... :"' '""-" ~ ..... ~:.i:4,-.':~L--Z:"~ ~:"--~....- CMT vol adequate to circulate on conductor & surf csg..~ N ---:- ~- ~' -~ .... / -~ 14. 15. 16. 17. CMT vol adequate to tie-in long string to surf csg . . . ~L-. 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 abndnmnt been approved. ~ N 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 ..................... Y~ N 26. BOPE press rating adequate; test to ~-'OO ~ psig. Y N 27. Choke manifold complies w/API RP-53 (May 84) ...... ~ N 28. Work will occur without operation shutdown ....... ~ N Is presence of H2S gas probable ............. Y ~ 29. GEOLOGY 30. Permit can be issued w/o hydrogen sulfide measures .... Y/N~;YYN/~ 31. Data presented on potential overpressure zones ..... Y -- 32. Seismic analysis of shallow gas zones .......... ~ 33. Seabed condition survey (if off-shore) ........ ./ 34. Contact name/phone for weekly progress reports . . ./. Y N [exploratory only] y GEOLOGY: ENGINEERING: COMMISSION: JDH //~ JDN ..... ---2 . Comments/Instructions: HOWIIjb - A:%FORMS\cheklist rev 11195