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Home My WebLink About195-203Pages 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. 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 Diann~athan Lowell Date :~~__~ Is/ [] TO RE-SCAN Notes: Re-Scanned by: Be~,edy Dianna Vincent Nathan Lowell Date: Is~ oN OR W C:LOP,~4~ILM'DOC Memorandum State of Alaska OH and Gas Conservauon Commission To: Well File: %% - (~ ~-~-.~ DATE Re: Cancelled or Expired Permit Action EXAMPLE: Point Mclntyre P2-36AXX AP1 # 029-22801-95 This memo will remain at the front of the subject well f'de. 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 the treatment of these kinds of applications for permit to ddll. 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 with an active well or multilateral these case sensitive well identifiers will be changed for expired and cancelled applications for permits to ddii. 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 memoranctum "Multi-lateral (weiibore segment) Drilling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician ~ALASKA~' rvices rilllng BP Exploration / Arco To: Alaska Oil & Gas Conservation Commission Date: March 6, 1996 From: Terrie Hubble Technical Assistant Permit #95-202, S-01B and Permit #95,203, S-01BL1 The regional structural high (targeted by the pilot hole) was confirmed. Due to the presence of 108 feet NLOC (net light oil column) versus the approximately 75 feet predicted, the decision was made to complete the pilot hole rather than risk costly plug backs and horizontal drilling. An Application for Sundry Approval was submitted and approved to complete the pilot hole (96-014). Consequently S-01BL1 was not drilled. TB/tlh / / t CONSERVATION CO SSION / TONY KNOWLE$, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 December 18, 1995 Dan Stoltz, Senior Drilling Engineer BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Well # Company Permit # Surf Loc Btmhole Loc Prudhoe Bay Unit S-01BL1 BP Exploration (Alaska), Inc. 95-203 1629'SNL, 756'EWL, Sec 35, T12N, R12E, UM 189'NSL, 915'EWL, Se¢27, T12N, R12E, UM Dear Mr. Stoltz: Enclosed is the approved application for permit to re-drill the above referenced well. The permit to re-drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting re-drilling operations until all other required permitting determinations are made. The permit is for a new wellbore segment originating from well S-01B, Permit No. 95-202, APl No. 50-029-20717-02. Production should continue to be reported to the originating well identifier, 50-029-20717-02. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to ddlling a new hole. Notice may be given by contacting the Commission's petroleum field inspector on the North Slope pager at 659-3607. David W Johnston \ _Chairman - ~',,, / BY ORDER OF THE SION dlf/encl c: Dept of Fish & Game, Habitat Section - w/o encl Dept of Environmental Conservation - w/o encl Joan Miller, AOGCC STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill [] Redrill FIIlb. Type of well. Exploratory l-I Stratigraphic Test [] Development Oil [] Re-Entry [] DeepenFII Service [] Development Gas [] Single Zone [] Multiple Zone [] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration Plan RTE = 70.9 fe et Prudhoe Bay Field/Prudhoe 3. Address 6. Property Designation Bay Pool P. O. Box 196612, Anchorage, Alaska 99519-6612 ADL 028258 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025) 1629' SNL, 756' EWL, SEC. 35, T12N, R12E Prudhoe Bay Unit At top of productive interval 8. Well number Number 720' SNL, 1961' WEL, SEC. 34, T12N, R12E S-01BL1 2S100302630-277 At total depth 9. Approximate spud date Amount 189' NSL, 915' EWL, SEC. 27, T12N, R12E 12/30/95 $200,000.00 12. Distance to nearest 13. Distance to nearest well 4. Number of acres in property15. Proposed depth (MD and'rVD) property line ADL 028256 189 feet No Close Approach feet 2560 12738' MD/9001' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth 9z65 feet Maximum hole angle 9o o Maximum surface 3330 psig At total depth (TVD) 8800'/4390 psig 18. Casing program Setting Depth raze Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD M D TVD (include stage data) 8-1/2" 7" 29# L-80 NSCT 1450' 6450' 5708' 10336' 8917' 320 sx Class 'G' 6" 4-1/2" 12.6# L-80 NSCT 2918' 9775' 8767' 12714' 8800' Uncemented Slotted Liner 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 ~-~ Intermediate Production Liner · Perforation depth: measured true vertical 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program[] Drilling fluid ce~f~ t~ the foregoi~ is_~u~/~ correct to the best of my knowledge~ 25 requirements[] prografl~l~ Time vs depth plot WI~, Refraction analysis [] Seabed report[] 2p~t~AC .050 21. I hereby Signed ./~_ ~"~L"'~,¢~--~- ? ~~' ' ' -- Title SeniorDrillin~l Engineer~ Date ' ~' ~-~-"-" ~- -(~ Commission Use Only Permit Number APl number Approva, Jl date~ ~.,~iSee cover letter ~-.2.<:D~ 5o-,~.?--~ ~/7'-- ~c~ /~/,~~',.~ Ifor other requirements Conditions of approval Samples required [] Yes [] ~ MuO log required []Yes [] No Hydrogen sulfide measures ffi Yes [] No Directional survey requireO [] Yes [] No Required working pressu0fi~[la~Q~e~l~; 1-13M; 1-15M; I-I10M; i-115M; Other: ,order of Approved by David W~ dohnston Commissioner me commission Date/ Form 10-401 Rev. 12-1-85 Submit dicate I Type of Well (producer or injector): I Well x,~ame: I S-01B / S-01BL1 I Sidetrack Plan Summary [Producer Surface Location: 1,629' FNL, 756' FWL Sec 35 T12N R12E Sadlerochit - Zone 4 Lateral (S-01B) 1st Lateral Target Location: 636' FNL, 2,093' FEL Sec 34 T12N R12E (start of horz - 1st lateral) Bottom Hole Location: 196' FSL, 918' FWL Sec 27 T12N R12E (end of horz - 1st lateral) Sag River Lateral (S-01BL1) 2nd Lateral Target Location: 1 720' FNL, 1,961' FEL Sec 34 T12N R12E (start of horz - 2nd lateral) Bottom Hole Location:I 189' FSL, 915' FWL Sec 27 T12N R12E (end of horz - 2nd lateral) I AFE Number: 14P0746.0 ] I Estimated Start Date: [ 12-30-95 [MD: [ 12,738' I I Well Design (conventional,slimhole,etc.) [ Horizontal Sidetrack (Multi-lateral) I Rig: [Nabors 28-E I .... [ I Operating days to complete: 127 I IT VD: 1 9,001' I [ KBE-MSL 71.6' I Formation Markers: Formation Tops MD TVD (SS) CM-3 (K-10) 6,055' 5,371' KOP in K-10 @ _+6,600' MD HRZ '7,187' 6,440' LCU 7,372' 6,625' Kingak 8,272' 7,525' Sag River (pilot hole) 9,623' 8,759' Pilot hole only Shublik (pilot hole) 9,679' 8,802' Pilot hole only Sadlerochit (pilot hole) 9,803' 8,897' Pilot hole only ~'~' ~;' ~' i~ ~L.;, ~ ~.,~'~ TD (pilot hole) 10,115' 9,135' Pilot hole only Sag River 9,751' 8,759' Shublik 9,853' 8,802' ~?~C ~ 2 ~,c~9~ Sadlerochit 10,190' 8,897' ~¢~.0 0i! ,5 {~:-~.s Cons. Coma' Casing/Tubing Prog ram: Hole Size Csg/ Wt/Ft Grade Conn Length Top Btm Tbg O.D. MD/TVD MD / TVD 8-1/2" 7" 29# L-80 NSCT 1,450' _+6,450'/5,708' _+10,336'/8,917' 6" 4-1/2" 12.6# L-80 NSCT 2,400' 10,188'/8,900' _+12,738'/9,001' (lst Lateral) 6" 4-1/2" 12.6# L-80 NSCT 2,918' 9,775'/8,767' _+12,714'/8,800' (2nd Lateral) Tubing 4-1/2" 12.6g L-80 NSCT 9,717' 33'/33' _+9,750'/8,758' Cementing Program: Lead Cement Tail Cement Casing/Liner Sx / Wt / Yield Sx / Wt / Yield Comments Class G, FW=0, FL=<50 cc 7" None 320 / 15.7 / 1.17 Pump time=4+ hrs; TOC = 8,458' MD (1,048' TVD above Sag River) 4-1/2" None None Slotted liner (lst Lateral) 4-1/2" None None Slotted liner (2nd Lateral) Volume assumptions: Gauge hole + 50% excess; 80' shoe joint; TOC at liner top. Logging Program: I Open Hole Logs: 8-1/2" Hole 6" Hole I Cased Hole Logs: 9-5/8" Casing I GR/SFL, ILM, ILD/sonic/density; RFT's contingent upon hole conditions MWD: Resistivity/GR in both horizontal intervals ~2{~3 None Planned 9EC' 1 2 1995 Mudn .ro ram.. k,'aska 0il & Gas .~ns."~, ~mmiasi0r, Intermediate Mud Properties: I 8-1/2" hole section to horizontal: LSND Ar chora§e Depth Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 6,000' 9.6-9.7 40-50 12-15 4-8 8-12 9-10 <6 HTHP-15.0 8,100' 9.8+ 50-60 20-30 10-12 12-16 9-10 <6 _+ 150' above HTHP- 15.0 Kingak 10,336' 9.8+ 50-60 20-30 10-12 12-16 9-10 <6 Csg Point HTHP- 15.0 Hazards/Concerns Utilize alternating lo / hi vis sweeps to assist hole cleaning Treat with 2 ppb each of Boreplate, Barotrol, & Baranex while drilling Kingak. Monitor LSYP and increase if problems occur trying to clean the hole. Potential high torque could need lubricant use. Lost circulation is probable due to anticipated faulting in Kingak. Reduce AP1 fluid loss to <6 cc in Kingak Section. Production Mud Prol~erties: 16" hole sections' Xanvis KCL Depth I Density Marsh Yield 10 sec 10 rain Fluid (MD)I (PPG) Viscosity Point gel gel pH Loss Sadlerochit Zone 4 Lateral 10,336' 8.8-9.0 50-60 30-40 15-20 18-24 9.5-10.5 <6 12,738' 8.8-9.0 50-60 30-40 15-20 18-24 9.5-10.5 <6 Sag River Lateral 9,765' I 8.8-9.0 50-60 30-40 15-20 18-24 9.5-10.5 <6 12,714'I 8.8-9.0 50-60 30-40 15-20 18-24 9.5-10.5 <6 Hazards/Concerns Lost Circulation a possibility due to possible faulting in Sadlerochit in 1 st lateral; Faults may also be encountered in the Sag River in 2nd lateral. Differential sticking possible (overbalance) - both laterals. Perform/report daily checks on KC1 concentrations in Xanvis KC1 system. High torque may be experienced and should be treated with Lubtex additions. Directional: I KOP: [ +6,000' MD (lst lateral); +9,765' MD (2nd lateral) Maximum Hole Angle: _+90© Tangent Angle +65° across Sag River in 1st lateral Close Approach Well: None. The above listed wells will be secured during the close approach. Well Control: Well control equipment consisting of 5,000 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. Disposal: Cuttings Handling: Fluid Handling: Annular Injection' CC2A Annular injection. As the S-lB annulus is not available for injection (cemented off), approval is hereby requested for annular injection into the following nearby wells (previously approved for injection by ADEC in 1990 and 1992, respectively). Additionally, these wells were recently approved for annular injection on the S-5A Drilling Permit. Cumulative total limitations will remain in effect. PREV. VOLUME MAX. PERMITTED MAX. PERMITTED PERMITTED AREA WELL INJECTED VOLUME FLUID DENSITY DATES (BBLS) (aBES) (PPG) WOA S-24 7,701 35,000 17.0 11/21/95-11/21/96 S-33 4,904 35,000 17.0 11/21/95-11/21/96 I o , , . o Aquifers in the Prudhoe Bay Field Western Operating Area have been exempted from Class II injection activities by the AOGCC by Aquifer Exemption Order #1 as referenced in Area Injection Order #3. There are no domestic or industrial use water wells located within one mile of the project area. The following design criteria were utilized in determination of maximum annular injection pressures (the attached pressure nomograph provides injection pressure vs. fluid density data): S-24 13-5/8", 68#, L-80 set and cemented at 2,668' MD (2,668' TVD) Burst (80%) = 2,760 psi 9-5/8", 47#, L-80 set and cemented at 9,843' MD Collapse (80%) = 3,800 psi S-33 10-3/4", 45.5#, NT-80 set and cemented at 2,958' MD (2,958' TVD) Burst (80%) = 2,864 psi 7-5/8", 29.7#, NT-95HS set and cemented at 9,018' MD Collapse (80%) = 4,096 psi A determination has been made that the pumping operation will not endanger the integrity of the well being drilled by the submission of data to AOGCC on 10/30/95 which demonstrates the confining layerS, porosity and permeability of the injection zone. The cement design for these wells (and the subject S-5A well) ensures that annular pumping into hydrocarbon zones will not occur. Worse case scenario calculations assume 17.0 ppg maximum fluid density and gas-filled inner casing (see attached nomograph for ppg equivalent mud weights vs. injection pressure profiles). Breakdown pressure of the Ugnu is 13.5 ppg equivalent mud weight. DO NOT EXCEED 35,000 BBLS IN ANY GIVEN ANNULUS. Ann. Inj. Nomograph PPG vs PSI S'24 Well Hydrostatic Pressure 13-3/8" Casing Burst 9-5/8" Casing Collapse Maximum Allowable Fluid Density at 2,668' TVD at 80% at 80% Injection Pressure (ppg) (psi) (psi) (psi) (psi) 8.00 1110 2,760 3,800 1,650 9.00 1249 2,760 3,800 1,511 10.00 1387 2,760 3,800 1,373 11.00 1526 2,760 3,800 1,234 12.00 1665 2,760 3,800 1,095 13.00 1804 2,760 3,800 956 14.00 1942 2,760 3,800 81 8 15.00 2081 2,760 3,800 679 .... 16.00 2220 2,760 3,800 540 17.00 2359 2,760 3,800 401 S-33 Well ! Hydrostatic Pressure 10-3/4" Casing Burst 7-5/8" Casing Collapse Maximum Allowable Fluid Density at 2,958' TVD at 80% at 80% Injection Pressure (ppg) (psi) . (psi) (psi) (psi) 8.00 1231 2,864 4,096 1,633 9.00 1384 2,864 4,096 1,480 10.00 1538 2,864 4,096 1,326 11.00 1692 2,864 4,096 1,172 12.00 1846 2,864 4,096 1,018 13.00 2000 2,864 4,096 864 14.00 2153 2,864 4,096 711 15.00 2307 2,864 4,096 557 16.00 2461 2,864 4,096 403 17.00 2615 2,864 4,096 249 Hydrostatic Pressure = TVD (casing shoe) * 0.052 * Fluid Density (ppg) Maximum Allowable Injection Pressure = Lesser of (Outer Csg Burst or Inner Csg Collapse) - Hydrostatic Pressure ~onai., _---, ,-,,-, r ur z.o, ntal Surnrna,~ . , i . 8~ , 10. 12. P&A well. Test cement to 2,000 ps/. Tag cement minimum of 100' above top perforation @ 10,151' MD. Cut the 3-1/2" tubing @ _+6,400' MD. MIRU Nabors 28-E drilling fig. Pull 3-1/2" tubing. ~ Test 9-5/8" casing to 3,500 psi for 10 minutes. RIH and set EZSV at +6,250' MD (250' below proposed 9-5/8" section). PU section mill, TIH and spot 14.5 bbl (_+200') of 18.0 ppg milling fluid from EZSV (6,250' MD) to 5,995' MD. Space out and mill section from 5,995' MD to 6,045' MD. POOH. T1H with open-ended ddllpipe. Mix and spot a 17.0 ppg cement kick-off plug (per recommended practices) from 6,145' to 5,795' MD. POOH a minimum of 12 stands, Perform a hesitation squeeze. Do not exceed a final squeeze pressure of 2,000 PSI and do not displace cement any closer than 100' above section top. , NOTE"- Final cement volume should insure slurry ptacement 100' below milled section, 50' across milled section and 200' inside casing above mi~led section. PU directional BHA and TIH. Tag TOC, MINIMUM WOC TIME IS 12 HOURS. Dress off cement plug to 6,000' MD (5' below top of section), kick-off and directionally drill pilot hole to_+10,115' MD (9,135' TVD). Final inclination is planned for 40.25° along an azimuth of 316°. POOH. RU and run. open hole logs. RFT's may be run pending hole conditions, TIH with open-ended driilpipe and pump cement to plug back pilot hole to +_9,000' MD (+_300' MD above proposed kick-off point). NOTE: Final kick-off point and target depths may adjusted slightly pending evaluation of open hole log data. PU directional BHA and TIH. Tag TOC, MINIMUM WOO TIME IS 12 HOURS. Dress o~f cement plug to +_9,200' MD, kick-off and directionaliy drill an 8-1/2" hole to +_10,336' MD (+_86°). POOH, RU and run 7" liner from 10,336' MD and tie back into 9-5/8" casing at +_5,850' MD. POOH and LD liner running tools. S-01B Sidetrack Operations Summary Page 2/3 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. PU directional BHA and drill 6" horizontal hole to 12,738' MD (at +86°) along an azimuth of 290°. Maximum lateral interval is +_2,400'. POOH. NOTE: Inclination, azimuth and overall lateral length may be shortened by onsite geologist. A wiper trip may be made prior to running production liner. Run and set a 4-1/2", L-80 slotted liner @ Total Depth. Top of liner will be at +_10,188' MD. Set 7"x 3-1/2" permanent production packer (with 3-1/2" tubing tail) at _+9,870' MD (end of 65° tangent). A wireline plug shall be set in the tubing tail. Set oriented, retrievable whipstock above permanent packer to promote kick- off at 9,765' MD (8,765' TVD; 5' TVD below the top of the Sag River). Mill window off whipstock at +_9,765' MD and drill -+25' new hole. POOH. PU directional BHA, kick-off and directionally drill a 6" hole to -+10,398' MD (-+86°). POOH. PU directional BHA and drill a 6" horizontal hole to 12,714' MD along a planned azimuth of 290°. Maximum lateral interval is -+2,783'. POOH. NOTE: Inclination, azimuth and overall lateral length may be shortened by onsite geologist. A wiper trip may be made prior to running production liner. Run and set a 4-1/2", L-80 slotted liner @ Total Depth. · +9,775' MD (_+10' from window). RIH and pull retrievable whipstock. RU and run 4-1/2", L-80 production tubing. Set two way check and test to 1,000 psi. ND BOPE. NU tree and test to 5,000 psi. Freeze protect well and release rig. Top of liner will be at S-01B Sidetrack Operations Summary Page 3/3 Drilling Hazards Sadlerochit interval has a pore pressure of +8.0 ppg EMW. Lost circulation may occur due to overbalance conditions. Small faults are expected in the lower portion of the build interval with larger (50-100' throw) faults anticipated in the horizontal section for the Sadlerochit lateral. Similar faulting can be expected in the horizontal section of the Sag River lateral. There are no known drilling close approaches. No other known drilling hazards are expected. · ;tI . Alaska ()ii & G,% ~0~s. C0mri'ii.~sion BPX-Shared Services Dril Alaska State Plane: Zone4 PBU : WOA: S-Pad S-O1B S-O1B WplO Sag River NCW HORIZONTAL V~E~' (THUe ~OHTI() ~C~ 200 It./ VERTICAL YI]~ff [ $CAL~ IO0 ~t. / tn. YERTtCAL M~CT~ON RKY: !Ir]LLLtflr-.AD HALLIBURTON S-01BL1 SAG RIVER LATERAL ~o CASING PDINT DATA Azl TVD N/S 51~E/~3V 8~481818 N 4 1/8 In IE714 90.00' 290,00' OEO 1 $199'5 Alaska Oi~ ,,,,,m. Commission ~Jchorage ~RTICAL SKCT[0N PL~N~: 289,~4' SCALE lo0 IL / b~. TVD RgF: ~ VERTICAL SECTION ~ IlELLEEAD 84(R] 8846~ ~7 ~7 9100 ] ~R~C~ Sg~0N P~: 28g.~* CRITICAL POINT DATA -, WELL PLAN PROFILE SUMMARY 6TART MDI~MD F~AG~ 9765 9790 Drill with 6' asse~ly oFF oF w~psto~ 9790 9940 S~ar% oF b~Ld ~ E0'/I~ t0 95' IncUn~tlon a~ ~zl~ oF 316% 9940 10396 10398 11098H~nt=ln ~ %=ngen% oF 86' Iht[In=flora 11098 11165S~t OF c~ve ~t 6'/100' to 90' Inclination ~t ~90' ~zl~ 11~65 I~714H~ln~eln 4 VI h ~, I ~r7~4 I~, 1141 TYI N/S E/V 23 S 243 818 N 1620 859 N E066 259 N 2066 259 N 2066 259 N 8066 259 N 2066 263 N 2O69 367 N 2t69 454 E~54 2437 658 N 2451 N 2467 ~8498 ~ 3605 N 3667 HD Inc Azl. TVD UG4A 371426,71'875.08° 3671 CH3 605548146'820,93' 5371 HRZ 71870.00' 316.00' 6440 LCU 73720.00' 3t6.00° 66~5 ~ Klng~k 83090.00' 316,00' 7562 64840,00' 316,00' 7737 TJE 87860,00' 316,00' 7979 TJD 88786.49' 316.00' 8[31 TJC 926837,69'316,00' 8488 TJB 944151.55'316,00' 8611 ~r~ ~g/~ver 974465,00'316,00' 8756 976565.00'316.00' 8765 INTERPOLATED POINT KOP / START 979065,00'316.00' 8775 675 DF ~UIL9 J 20. 00'/100 F~ Shubtlk 9838 74.55'316.00' 8792 707 START ur 994095.00'316.00' 8801 780 CURVE ~ 6.00'/I00 f~ END OF CURVE10398 86.00'890.00' 8797 10~7 START OF 11098 86.00'890,00' 8846 1266 CURVE R 6,00'/100 F~ END DF CURVE11165 90.00'~90.00' 8848 1280 Turge~ N~me ~D NS ~ ~ld X ~d Y S~d gTarg 8997 909 N 3350 V S~d ET~rg 900l IBE6 H ~IE~ V Poty p~L 8897 1617 N ~lBt V Poty pt~ 9897 607 N 2591V Poly p~3 8897 10~6 N ~OG V Poty pt4 gB97 1899 N 5109 V Po~y ' 8697 1617 N ~18[ V APPROVED WELL n ~,q """N 615555 5980710 613770 5981600 613714 5981390 616319 5900420 616395 ~980870 613782 5961673 613714 5981390 pLOT INFORMATION DRAWING NAME / FILE NAME rm,-r~ / r4r~ SURFACE LOCATION pg0~O3En Dtl~ ~ 18714.70 ~el~eJ ~ ~ ~ ~a.gT ~ ~/~ 1818.~ N ~R:~O ~ ~~/w Bl~3.~ W ~ By : WELL PERMIT CHECKLIST ADMINISTRATION 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. REMARKS 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 ....... ENGINEERING 15. Surface casing protects all known USDWs ......... Y .~.. 16. CMT vol adequate to circulate on conductor & surf csg.. Y 17. CMT vol adequate to tie-in long string to surf csg . . Y 18. CMT will cover all known productive horizons ....... Y 19. Casing designs adequate for C, T, B & permafrost .... ~ N 20. Adequate tankage or reserve pit ............. 21. If a re-drill, has a 10-403 for abndnmnt been approved. 22. Adequate wellbore separation proposed .......... ~ N 23. If diverter required, is it adequate .......... 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) ...... ~Y--~~ 28. Work will occur without operation shutdown ....... ~ N 29. Is presence of E2S gas probable ............ ~ N GEOLOGY / 30. Permit can be issued w/o hydrogen sulfide measures .... Y N/._ 31. Seismic analysis of shallow gas zones .......... Data presented on potential overpressure zones ..... Y 32. 33. Seabed condition survey (if off-shore) ....... 34. Contact name/phone for weekly progress reports . . .//.. Y N [exploratory only] GEOLOGY~ ENGINEERING: JDE ~ HOW/lib - A:\FORMS~cheklist rev 11195 , COMMI SS ION: Comments/inst~ctions: CD