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Home My WebLink About194-117XHVZE 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. I(~' C/- I/ 7 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: Beved~ncent TO RE-SCAN Nathan Lowell - · Date:~ - 3 Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: Is~ W C..gOagl~]~M-DOC Memorandum State of Alaska Oil mgl Gas Conservation Co~ To' Well File: (~q _ (~) [[r-~ DATE Re: Cancelled or Expired Permit Action EXAMPLE: Point McIntyre P2-36AXX AP1 # 029-22801-95 This memo will remain at the front of the subject well fie. 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. unchangect. The APl number and in some instances the well name reflect the number of preexistin,~ reddils and or multilaterals 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 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 AP! numbering methods descnbed in AOGCC staff memorandum "Multi-lateral (wellbore segment) Ddlling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE I)RIVE ANCIlORAGE, ALASKA 99501-3192 PIIONE: (907)279-1433 TELECOPY: (907)276-7542 December 2, 1994 Terry Jordan Drilling Engineer Supervisor BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Unit R-37 (previously R-37i) BP Exploration (Alaska), Inc. Permit No: 94-117 Sur. Loc. 736'NSL, 1433'EWL, Sec. 32, T12N, R13E, UM Btmhole Loc. 1050'NSL, 1806'EWL, Sec. 32, T12N, R13E, UM Dear Mr. Jordan: Enclosed is the approved revised application for permit to drill the above referenced well previously submitted as R-37 injection. 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. Sincerely, Russell A Dougla~ Commissioner BY ORDER OF THE COMMISSION dlf/Enclosures cc: Department of Fish & 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 2O AAC 25.O05 la. Type of work Drill [] Redrill [-111b. Type of well. Exploratory[] Stratigraphic Test [] Development Oil [] Re-Entry [] Deepenl-II Service [] Development Gas [] Single Zone [] Multiple Zone[] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exp/oration KBE = 49.1 feet Prudhoe Bay Field/Prudhoe 3. Address 6. Property Designation Bay Pool P. O. Box 196612. Anchorac~e. Alaska 99519-6612 ADL 28279 4. Location of well at surface 7. Unit or property Name 11. Type Bond(me 20 ,,.Ac 25.025) 736' NSL, 1433' EWL, SEC. 32, T12N, R13E, UM Prudhoe Bay Unit At top of productive interval 8. Well number Number 929' NSL, 1553' EWL, SEC. 32, T12N, R13E, UM R-37 (23-32-12-13) 2S 100302630-277 At total depth 9. Approximate spud date Amount 1050' NSL, 1806' EWL, SEC. 32, T12N, R13E, UM 12/3/94 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property15. Proposed depth(uDand'rVD) property line ADL28279 - 736 feet R-08 - 30' @ 1200' MD fe et 2560 9299 MD/9237' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth 78oo feet Maximum hole angle ~9 0 Maximum surface 3330 psig At total depth (TVD) 8800'/4390 psig 18. Casing program Setting Depth s~ze Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length M D TVD MD TVD (include stage data) 30" 20" Cond. H-40 Weld 80' 30' 30' 110' 110' 260 sx Arcticset (Approx.) 13-1/2' 10-3/4" 45.5# ~-~OL,E Butt 3034' 29' 29' 3063' 3055' 975 sx CS 111/375 sx "G"/250 sx CS II 9-7/8" 7-5/8" 29. 7# NT95HS NSCC 9271' 28' 28' 9299' 9237' 730 sx Class "G" Conting ency 6-3/4" 5-1/2" 17# L-80 NSCC 652' 8647' 8620' 9299' 9237' 95 sx Class "G" 1'9. 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 Surface RECEIVED Intermediate Production DEC - 2 1994 Liner Perforation depth: measured /k~ska 0il & Gas Cons. Commission true vertical Anch0ra~e 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program ITl [Drilling fluid program [] Time vs depth pict [] Refraction analysis[] Seabed reportl-'l 20 AAC 25.050 requirements[] 21. I hereby certify that tltqe foregoing is true and correct to the best of my knowledge 9,~ ~.ltl~'t --_ Signed ~ ~'(~d~ Title OrillingEn~lineerSupervisor Date/ Commission Use Only IApprova_l date See cover letter Permit ,' ~ ~,- ,- ~,z_.;z_ /,) '~Number I. _. ~_....5'o._,4' ._ I ,~'u~7~''-',~'~ for other requirements Conditions of approval Samples required [] Yes ]~ No Mud Icg required/ I-lYes ~ No Hydrogen sulfide measures [] Yes J~ No Directional survey required I~ Yes [] NO Required working pressure for BOPE CI2M; CI3M; ,I~5M; []10M; []15M; Other: RUSSELLORIGiI~IAL SIGNED BY by order of Approved by A. DOUGLASS Commissioner [ne comm,ssion Date/~'~2.7~/ Form 10-401 Rev. 12-1-85 Submit in triplicate R-37i Permit to Drill Revision The permit to drill for R-37i needs to be revised due to the following casing size and cement volume changes: Well' R-37i Permit No.' 94-117 APl No.' 50-029-22505 Surface Casing Setting Depth' Intermediate Casing Setting Depth: 3063' MD / 3055' TVD 3034' of 10-3/4", 45.5#, NT80LHE, BTC casing 975 sx CSlII/375 sx "G" / 250 sx CSII 9299' MD / 9237' TVD 9271' of 7-5/8", 29.7#, NT95HS, NSCC casing 730 sx "G" Liner Casing Setting Depth (Contingency): TD' Kickoff: Max Hole Angle: 9299' MD / 9237' TVD 7800' MD / 7800' TVD 19.02° 8647' MD / 88620' TVD (top) 9299' MD / 9237' TVD (shoe) 652' of 5-1/2", 17#, L-80, NSCC casing 115 sx "G" In addition, Well R-37i will be drilled and completed with Rig Nabors 18E (KB-GL = 29.5'). RECEIVED DEC -2 1994 Alaska Oil & Gas Cons. Commission ^nchora Well Plan Summary I Well Name: I R-37iPBU I Type of Well (producer or injector): I MI Injector ISurface Location: Target Location: Bottom Hole Location: 736' FSL 1433' FEL Sec 32 T12N R13E UM 929 FSL 1553' FEL Sec 32 T12N R13E UM 1050' FSL 1806' FEL Sec 32 T12N R13E UM I AFE Number: Estimated Start Date: I mD: ] 9299' I 14P0586 I I Rig: I Nabors 18-E I Dec 3, 1994 I I Operating days to complete: I ~s ITVD: 19237' I IRT'GL I29.5. I KBE: 49.1' I Well Design (conventional, slimhole, etc.)' I Slimhole producer I Formation Markers: Formation Tops MD TVD (BKB) Base Permafrost 1983' 1975' Ugnu Zone 4A 3963' 3955' Top Seabee (CM3) 5613' 5605' Kuparuk~ut River Absent Absent IKRU/LCU 7113' 7105' Top Sag River 8797' 8762' Top Shublik 8842' 8804' Top Sadlerochit 8926' 8884' m r r' r' ~ ~ t r r~ Target 8926' 8884' ~x, !~ k~ 12 I ¥ 12 L/ Total Depth 9299' 9237' DEC - ~ 199zi Casin /Tubing Program: Wt/Ft Hole Size Csg/ Wt/l~t Grade Conn Length Top Btm Tbg O.D. MD/TVD MD/TVD 30" 20" 91.5# H-40 Weld 80' 30'/30' 1107110' 13-1/2" 10-3/4" 45.5# NT80LHE Butt 3034' 29'/29' 3063'/3055' 9-7/8" 7-5/8" 29.7# NT95HS NSCC 9271' 28'/28' 9299'/9237' Contingency 6-3/4" 5 1/2" 17# L-80 NSCC 652' 8647'/8620' 9299'/9237' Tubing 4 1/2" 12.6 L-80 NSCT 8670' 27'/27' 8697'/88667' Well Plan Summary Logging Program: I Open Hole Logs: 13 1/2" Hole 9 7/8" Hole 6 3/4" Hole Cased Hole Logs: 7 5/8" Casing 5 1/2" Liner None GR/DIFL/BHCA/CNL/SP (if well is longstringed) GR/DIFL/BHCA/CNL/SP (if well is not lon([stringed) SBT (Gyro optional) if well is longstringed SBT (Gyro optional) if well is not longstringed Mud Program: [Special design considerations I None Surface Mud Properties: I SPUD Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.5 100 20 15 20 9 15 to to to to to to to 9.5 300 60 60 80 10 25 Intermediate Mud Properties: ILS ND Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 9.0 35 10 5 10 9.5 5 tO tO tO tO tO tO tO 10.0 50 15 10 20 10 10 Production Mud Properties: I LSND Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.8 30 8 3 7 8 6 tO tO tO tO tO tO tO 9.2 45 13 10 15 9 8 NOTE: Keep annular velocities around drill pipe at or above 220 ft/min wherever possible Directional: I mOP: 17800' Maximum Hole Angle: Close Approach Well: 19.02 degrees R-6 at 257' (34' away) and R-8 at 1200' (30' away) The above listed wells will be secured during the close approach. 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. RECEIVED Well Plan Summary C - 2. 1994- Gas Cons. G0mmJs~10a Anchora: ~ PROPOSED DRILLING AND COMPLETION PROGRAM WELL R-37i [ 23-32-12-13 1PBI. J 1. MIRU. NU diverter and function test same. 2. Drill 13-1/2" hole. Run and cement 10-3/4", 45.5#, NT-80 Buttress casing to surface. o Install blowout prevention equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer. Maximum possible bottomhole pressure is 4390 psi at 8800' TVDss based on original reservoir pressure. Maximum possible surface pressure is 3330 psi based on a gas column to surface from 8600' TVDss and an oil column to 8800' TVDss. Function test BOPE to 5000/250 psi. . Test 10-3/4" casing to 3000 psi for 30 minutes. A formation leak-off test will be performed 10' below the 10-3/4" shoe. o Longstring Option: Directionally drill 9-7/8" hole to TD. Run a 7-5/8", 29.7#, NT-95 NSCC casing string and cement with Class G cement around the 7-5/8" shoe. The annulus will be freeze protected with dry crude. Bump the plug with filtered seawater. Test casing to 3500 psi. Sa. Non-longstring Option: Directionally drill 9-7/8" hole to the 7-5/8" casing point above the top of Sag River. Run a 7-5/8", 29.7#, NT-95 NSCC casing string to within 10' of 9- 7/8" TD and cement with Class G cement around the 7-5/8" shoe. The annulus will be freeze protected with dry crude. 6b. Drill out of 7-5/8" casing with a mud weight of at least 0.5 ppg over the highest anticipated mud weight to used while drilling 6-3/4" hole for formation integrity test. Directionally drill the 6-3/4" hole to TD. Run 5-1/2", 17#, L-80 NSCC liner from TD to 150' inside 7-5/8" casing shoe and cement using Class G cement. 6C. Clean out to 5-1/2" float equipment. Change over to filtered seawater completion fluid. Test casing and lap to 3500 psi. . Run 7-5/8" production packer on the 4-1/2", 12.6#, L-80 NSCT tubing. A subsurface safety valve with dual control lines will be placed 100' below base of permafrost. Install and test Xmas tree. Freeze protect the tubing and annulus with diesel from surface to 2100' TVDBKB. Set and test packer. 8. The well will be perforated after the rig has been released. Fluids incidental to the drilling of a well will be injected down CC-2A or the annuli of R-36 or R-37i. Tubing Size: 4-1/2", 12.6 # NT L-80 tubing with No GLM's. Well Plan Summary RECEIVED DE(; - 2 1994 ~!~sk~. Oil & Gas Cons. Commission Anchors. 10-3/4" SURFACE CASING CEMENT PROGRAM- BJ SERVICES CASING SIZE: 10-3/4" CIRC. TEMP: 38°F PREFLUSH: 75 bbls fresh water ahead of lead slurry. LEAD CEMENT TYPE: COLD SET III ADDITIVES: retarder WEIGHT: 12.2 ppg APPROX. # SACKS: 975 YIELD: 1.92 ft3/sx MIX WATER: 10.53 gps THICKENING TIME: Greater than 4 hrs. @ 50°F TAIL CEMENT TYPE: CLASS G ADDITIVES: 2% A-7 +1 ghs FP-6L WEIGHT: 15.8ppg YIELD: 1.15 ft3/sx APPROX. # SACKS: 375 MIX WATER: 4.95 gps THICKENING TIME: Greater than 3-1/2 hrs @ 50°F TOP JOB CEMENT TYPE: COLD SET II ADDITIVES: WEIGHT: 14.5 ppg YIELD: 0.96 ft3/sx APPROX. # SACKS: 250 MIX WATER: 3.89 gps THICKENING TIME: Greater than 2 hrs @ 50°F CENTRALIZER PLACEMENT: 1. Run 1 bow type centralizer per joint for the first 15 joints. 2. Place the centralizers in the middle of each joint with a stop collar. CEMENT VOLUME: 1. Lead slurry from TD to surface w/100% excess (less the tail slurry volume). 2. Tail slurry volume 375 sx (to cover 500' of casing shoe w/100% excess). 3. Top job volume 250 sx. Well Plan Summary RECEIVED DEC - 2 1994 Oil & Gas Cons. Commission Anchora. 7-5/8" LONGSTRING CASING CEMENT PROGRAM - BJ SERVICES CASING SIZE: 7-5/8" CIRC. TEMP: 140°F PREFLUSH: 20 bbls fresh water SPACER: 70 bbls BJ MCS-4 Spacer weighted 1.0 ppg above mud weight. LEAD CEMENT TYPE: CLASS G ADDITIVES: 3% A-2 + 0.4% FL-52 + 0.5% CD-32 + 1 ghs FP-6L WEIGHT: 11.0 ppg APPROX. # SACKS: 350 YIELD: 3.31 ft3/sx MIX WATER: 20.92 gps THICKENING TIME: 5 hrs FLUID LOSS: 150-250 cc/30 minutes FREE WATER: 0 cc TAIL CEMENT TYPE: CLASS G ADDITIVES: 150 ghs BA-86L + 0.6% CD-32 + 0.2% FL-33 + 0.2% A-2 + 0.5% gel + 2 ghs FP-10L + S-400 WEIGHT: 15.7 ppg APPROX. # SACKS: 380 FLUID LOSS: < 50 cc/30 minutes YIELD: 1.17 ft3/sx MIX WATER: 4.85 gps THICKENING TIME: 2-1/2 to 3 hrs FREE WATER: 0 cc CENTRALIZER PLACEMENT: 1. Run 2 Turbulator per joint to 300' MD above top of Sadlerochit. 2. Run 1 straight blade rigid centralizer every joint 300' above and below the Cretaceous interval. (only where lead cement is being pumped to the Cretaceous) frgm 3663' to 5913'. 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 12 bpm. Mix lead slurry on the fly, batch mix the tail slurry. CEMENT VOLUME: 1. Lead slurry to 300' MD above top of Ugnu (top of Ugnu at 3963' MD) 2. Tail slurry to 1000' MD above top of Sag River with 30% excess. 3. 80' MD 7-5/8", 29.7# capacity for float joints. Note: Hydrocarbon bearing zones are identified in the Ugnu and Sag River intervals. RECEIVED Well Plan Summary DEC - 2 i99~ ~i~ska Oil & Gas Cons. Commission Anchor~ 5-1/2" PRODUCTION LINER (CONTINGENCY) CEMENT PROGRAM- BJ SERVICES CIRC. TEMP: 140° F BHST: 220° F at 8800' TVDSS. PREFLUSH: 20 bbls fresh water SPACER: 70 bbls BJ MCS-4 Spacer weighted 1.0 ppg above mud weight. CEMENT TYPE: CLASS G ADDITIVES: 150 ghs BA-86L + 0.6% CD-32 + 0.2% FL-33 + 0.2% A-2 + 0.5% gel + 2 ghs FP-10L WEIGHT: 15.7 ppg APPROX. # SACKS: 115 YIELD: 1.17 ft3/sx MIX WATER: 3.58 gps THICKENING TIME: 45 min. @ Surface + 3-4 hrs @ 140°F FLUID LOSS: less than 50 cc/30 minutes @ 140°F FREE WATER: 0 cc at 45° angle. NOTE: Ensure that a thickening time test is performed that simulates the shut down time incurred while rotating off of the liner. Note gellation tendencies ( if any ) of slurry when consistometer is re-started after shutdown period - additional retarder may be required - consult w/cementer. CENTRALIZER PLACEMENT: 1. Run 2 right hand turbolators per joint in open hole, 2. Run 1 right hand turbulator per joint in lap, and none opposite intermediate casing shoe.. OTHER CONSIDERATIONS: Batch mix the cement slurry. Perform fluid loss test on the batch mixed slurry. Fluid loss should be 50 cc/30 min. or less. Report actual fluid loss on morning report. Displace @ 6-8 bpm. LINER CEMENT VOLUME: 1. Open hole (6-3/4" X 5-1/2") + 30% excess (adjust if a caliper log is run and it indicates severe washouts). 2. 5-1/2", 17# casing capacity below landing collar (80'). 3. 150' liner lap (6.875" x 5-1/2") 4. 200' of cement on top of the liner in the 7-5/8" casing. Well Plan Summary RECEIYED DEC - ?. 199q- Oft & Gas Cons. Commission Anchor; Pr',~dhoe Bo.~' Un i±..~ ._... R-37i ' R-37 Wp5 103 ¢~ / I I I I RECEIVED RE 0 0 N 8 [ 2CO 0 N 4g S vs 23"..56 :EIVED - 2 1994 ~as Cons. Commission nchon. · BP EXPLORATION To: Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Date: December 1, 1994 Attention' David Johnston Subject: R-37 Revised Permit (#94-117) Enclosed is a new permit for well R-37. The casing sizes and cement volumes have been changed. Also, please correct the well name to R-37 (deleting the 'i") Yours Sincerely, Drilling Engineer Supervisor MS RECEIVED DEC - 2 1994 Oil & Gas Cons, Commission Anchorage., .. ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 September 8, 1994 Terry Jordan Drilling Engineer Supervisor BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Unit R-37i BP Exploration (Alaska), Inc. Permit No. 94-117 Sur. Loc 736'NSL, 1433'EWL, Sec. 32, T12N, R13E, UM Btmhole Loc. 1050'NSL, 1806'EWL, Sec. 32, T12N, R13E, UM Dear Mr. Jordan: 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. 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. _. Chairman BY ORDER OF THE COMMISSION dlf/Enclosure cc: Department of Fish & 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 25.0O5 la. Type of work Drill [] Redrilll-Illb. Type of well, Exploratoryl-] Stratigraphic Test[-] Development Oill'-] 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 £xp/oration KBE = 74.4 feet Prudhoe Bay Field/Prudhoe 3. Address 6. Property Designation Bay Poo/ P. O. Box 196612. Anchoraae. A/aska 99519-6612 ADL 28279 4. Location of well at surf-ace 7. Unit or property Name 11. Type Bond(see 20 AAC 25,025) 736' NSL, 143,3' EWL, SEC. 32, T12N, R13E, UM Prudhoe Bay Unit At top of productive interval 8. Well number Number 929' NSL, 1553'EWL, SEC. 32, T12N, R13E, UM R-37i (23-32-12-13) 2S100302630-277 At total depth 9. Approximate spud date Amount 1050' NSL, 1806' EWL, SEC. 32, T12N, R13E, UM 9/9/94 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD andTVD) property line ADL28279 - 736 feet R-08 - 30'@ 1200'MD feet 2560 9299 MD/9237' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth 7~oo feet Maximum hole angle ~9 0 Maximum surface 3330 psig At total depth (TVD) 8800'/4390 psig 18. Casing program Setting Depth s ~ze S pecificat ions Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 30" 20" Cond. H-40 Weld 80' 35' 35' 110' 110' 260 sx Arcticset (Approx,) 12-1/4" 9-5/8" 40# NT-80 Butt 3028' 34' 34' 3063' 3055' 795 sx CS 111/375 sx "G"/250 sx CS II 8-1/2" 7" 26~ L-80 L TC 5565' 33' 33' 5600' 5592' 8-1/2" 7" 26~ NT-aOS NSCC 3614' 5600' 5592' 9299' 9237' 365 sx Class "G" 6" 5" 14.87# 13CR80 STL 432' 8797' 8762' 9299' 9237' 90 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 ConductorRECEIVED Surface Intermediate SE? - 6 1994 Production Liner ~,i~ska 0il & 6~s Cons. Commission Perforation depth: measured.~nol;r",,,..;, '~.~. true vertical 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program[] iDrilling fluid program [] Time vs depth plot [] Refraction analysis [] Seabed reportl'-I 20 AAC 25.050 requirements[] 21. I..hereby certify t~at the,~pr~g~oin9 i,s true and correct to the best of my knowledge · ~/~"/~i~ned 7¢/LJ21,/ f ~~A~,---- T itleDri//ing En~ineerSupervisor D at - ] / (,) u' ~' Commission Use Only Permit Number APl'number IApproval date JSee cover letter so-o I Iforother requirements Conditions of approval Samples required [] Yes [] No Mud log required []Yes ~ No Hydrogen sulfide measures [] Yes ~ No Directional survey required ~ Yes [] No Required working pressure for BOPE [] 2M; 1-13M' ~5M; 1-'110M' I-I15M; Other: Original Signed By by order of Approved by David W. Johnston Commissioner me commission Date ~///'?/"~;'~ Form 10-401 Rev. 12-1-85 Submit in tr ~licate ]WellName: ]R-37iPBU Well Plan Summary Type of Well (producer or injector): I Injector Surface Location: 736' FSL 1433' FWL Sec 32 T12N R13E UM Target Location: 929' FSL 1553' FWL Sec 32 T12N R13E UM Bottom Hole Location: 1050' FSL 1539' FWL Sec 32 T12N R13E UM [ AFE Number: I Estimated Start Date: IMD: 19299' I Well Design (conventional, slimhole, etc.): 14P0586 I I Rig: I Nabors 28-E I I Sept. 9, 1994 I I Operating days to complete: I 12 ITVD: 19237' I IRT-GL [35.2' I I KBE: 74.4' IUltraslimh°le I Formation Markers: Formation Tops MD TVD (BKB) Base Permafrost 1983' 1975' Ugnu Zone 4A 3963' 3955' Top Seabee (CM3) 5613' 5605' Kuparuk/Put River Absent Absent IKRU/LCU 7113' 7105' Top Sag River 8797' 8762' Top Shublik 8842' 8804' Top Sadlerochit 8926' 8884' Target 8926' 8884' Total Depth 9299' 9237' SEF' - 6 '~99~. .,!-',,l?;S'ka [.)it L~ ~a.3 t_,uL~,',. O,J~,V,,,,.~ ..... Casing/Tubin 'Program: Wt/Ft Hole Size Csg/ Wt/Ft Grade Conn Length Top Btm Tbg O.D. MD/TVD MD/TVD 30" 20" 91.5# H-40 Weld 80' 35'/35' 110'/110' 12-1/4" 9-5/8" 40~ NT80 BTC 3028' 34'/34' 3063'/3055' 8-1/2" 7" 264~ L-80 LTCM 5565 33'/33' 5600'/5592' 8-1/2" 7" 26~ NT-80S NSCC 3614' 5600'/5592' 9299'/9237' Contingency 6" 5" 14.87# 13Cr-80 STL 432' 8797'/8762' 9299'/9237' . Tubing 3 1/2" 6.737# L-80 N/A 5765' 32'/32' 5800'/5792' Well Plan Summary Logging Prog I Open Hole Logs: 12-1/4" Hole 8-1/2" Hole I Cased Hole Logs: 7" Casing None DIFL/BHCA/CN/GR/SP SBT Mud Program-. I Special design considerations I None Surface Mud Properties: I SPUD Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.5 100 20 15 20 9 15 tO tO tO tO tO tO tO 9.5 300 60 60 80 10 25 Intermediate Mud Properties: I LSND Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 9.0 35 10 5 10 9.5 5 tO tO tO tO tO tO tO 10.0 50 15 10 20 10 10 Production Mud Properties: ]LSND Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.8 30 8 3 7 8 6 tO tO tO tO tO tO tO 9.2 45 13 10 15 9 8 Directional' IKOP: 17800' I I Maximum Hole Angle: I 19 degrees Close Approach Well: None The above listed wells will be secured during the close approach. Well Control: Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular oreventer_ will be installed and is capable of handling maximum potential surface pressures::i; '~ t5 [. IV ED Diverter, BOPE and drilling fluid system schematics on file with AOGCC. Well Plan Summary /',,t'l¢.:ftt ;; Ub;~ . . o Sa. 6b. SC. . . PROPOSED DRILLING AND COMPLETION PROGRAM WELL R-37i [ 23-32-12-13 ] PBU MIRU. NU diverter and function test same. Drill 12-1/4" hole. Run and cement 9-5/8", 40g, NT-80 Buttress casing to surface. Install blowout prevention equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer. Maximum possible bottomhole pressure is 4390 psi at 8800' TVDss based on original reservoir pressure. Maximum possible surface pressure is 3330 psi based on a gas column to surface from 8600' TVDss and an oil column to 8800' TVDss. Function test BOPE to 5000/250 psi. Test 9-5/8" casing to 3000 psi for 30 minutes. A formation leak-off test will be performed 10' below the 9-5/8" shoe. Longstring Option: Directionally drill 8-1/2" hole to TD. Run a 7", 20g, L-80, LTC by 7", 26g, NT-80 NSCC casing string and cement with Class G cement around the 7" shoe. The annulus will be freeze protected with dry crude. Bump the plug with filtered seawater. Test casing to 3500 psi. Non-longstring Option: Directionally drill 8-1/2" hole to the 7" casing point above the top of Sag River. Run a ", 26#, L-80, LTC by 7", 20g, NT-80 NSCC casing string to within 10' of 8-1/2" TD and cement with Class G cement around the 7" shoe. The annulus will be freeze protected with dry crude. Directionally drill the 6" hole to TD. Run 5", 15.87#, 13 Cr-80 STL liner from TD to 150' inside 7" casing shoe and cement using Class G cement. Clean out to 5" float equipment. Change over to filtered seawater completion fluid. Test casing and lap to 3500 psi. The well will be perforated after the rig has been released and prior to running coil tubing. Run 3-1/2" L-80 coil tubing w/3-3/4" sealbore stung into profile nipple @ 5800' MD. Tubing and annulus will be freeze protected with diesel from surface to 2100' TVDBKB. Well Plan Summary CASING SIZE: 9-5/8" 9-5/8" SURFACE CASING CEMENT PROGRAM - BJ SERVICES CIRC. TEMP: 40°F PREFLUSH: 75 bbls fresh water ahead of lead slurry. LEAD CEMENT TYPE: COLD SET III ADDITIVES' retarder WEIGHT: 12.2ppg YIELD: 1.92ft3/sx APPROX. # SACKS' 795 MIX WATER: 10.53 gps THICKENING TIME: > 4 hrs TAIL CEMENT TYPE: CLASS G ADDITIVES' 2% A-7 + 0.5 ghs FP-12L WEIGHT: 15.8ppg YIELD: 1.15 ft3/sx APPROX. # SACKS: 375 MIX WATER: 4.95 gps THICKENING TIME: > 3-1/2 hrs TOP JOB CEMENT TYPE: COLD SET II ADDITIVES: WEIGHT: 14.95 ppg YIELD: 0.96 ft3/sx MIX WATER: 3.89 gps APPROX. # SACKS' 250 THICKENING TIME: Greater than 2 hrs @ 50°F CENTRALIZER PLACEMENT: 1. Run 1 bow type centralizer per joint for the first 15 joints. 2. Place the centralizers in the middle of each joint with a stop collar. CEMENT VOLUME: 1. Lead slurry from TD to surface w/100% excess (less the tail slurry volume). 2. Tail slurry volume 375 sx (to cover 500' of casing shoe w/100% excess). 3. Top job volume 250 sx. Well Plan Summary 7" LONGSTRING CASING CEMENT PROGRAM - BJ SERVICES CASING SIZE: 7" CIRC. TEMP: 140°F PREFLUSH: 20 bbls fresh water SPACER: 70 bbls BJ MCS-4 Spacer weighted 1.0 ppg above mud weight. LEAD CEMENT TYPE: CLASS G ADDITIVES: 3% A-2 + 0.4% FL-52 + 0.5% CD-32 + 1 ghs FP-6L WEIGHT: 11.0 ppg YIELD: 3.31 ft3/sx MIX WATER: 20.92 gps APPROX. # SACKS: 140 THICKENING TIME: 5 hrs FLUID LOSS: 150-250 cc/30 minutes FREE WATER: 0 cc TAIL CEMENT TYPE: CLASS G ADDITIVES: 150 ghs BA-86L + 0.2% FL-33 + 0.6% CD-32 + 0.2% A-2 + 0.5% gel + 0.5 ghs FP-12L WEIGHT: 15.7 ppg APPROX. # SACKS: 225 FLUID LOSS: < 50 cc/30 minutes YIELD: 1.17 ft3/sx MIX WATER: 5.08 gps THICKENING TIME: 3-1/2 to 4-1/2 hrs FREE WATER: 0 cc CENTRALIZER PLACEMENT: 1. Run 2 Turbulator per joint to 300' MD above top of Sadlerochit. 2. Run 1 straight blade rigid centralizer every joint 300' above and below the Cretaceous interval. (only where lead cement is being pumped to the Cretaceous) 3. Run 1 solid body 7" x 8-1/2" centralizer or turbolator on first 2 joints inside 9-5/8" surface casing shoe. 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 12 bpm. Mix lead slurry on the fly, batch mix the tail slurry. CEMENT VOLUME: 1. Lead slurry to 5000' MD 2. Tail slurry to 7787' MD (1000' above TSAD) 3. 80' MD 7", 26g capacity for float joints. Oar:. (;one;..6sr,,lmission Well Plan Summary 5" PRODUCTION LINER CEMENT PROGRAM - BJ SERVICES CIRC. TEMP: 140° F BHST: 220° F at 8800' TVDSS. PREFLUSH' 20 bbls fresh water SPACER: 70 bbls BJ MCS-4 Spacer weighted 1.0 ppg above mud weight. CEMENT TYPE: CLASS G ADDITIVES' 150 ghs BA-86L + 0.6% CD-32 + 0.2% FL-33 + 0.2% A-2 + 0.5% gel + 2 ghs FP-10L WEIGHT: 15.7 ppg APPROX. # SACKS: 90 YIELD: 1.17 ft3/sx MIX WATER: 3.58 gps THICKENING TIME: 45 min. @ Surface + 3-4 hrs @ 140°F FLUD LOSS' less than 50 cc/30 minutes @ 140°F FREE WATER: 0 cc at 45© angle. NOTE' Ensure that a thickening time test is performed that simulates the shut down time incurred while rotating off of the liner. Note gellation tendencies ( if any ) of slurry when consistometer is re-started after shutdown period - additional retarder may be required - consult w/cementer. CENTRALIZER PLACEMENT: 1. Run 2 right hand turbolators per joint in open hole, 2. Run 1 right hand turbulator per joint in lap, and none opposite intermediate casing shoe.. OTHER CONSIDERATIONS' Batch mix the cement slurry. Perform fluid loss test on the batch mixed slurry. Fluid loss should be 50 cc/30 min. or less. Report actual fluid loss on morning report. Displace @ 6-8 bpm. LINER CEMENT VOLUME: 1. Open hole (6" X 5") + 30% excess (adjust if a caliper log is run and it indicates severe washouts). -- 2. 5", 15# casing capacity below landing collar (80'). 3. 150' liner lap (6.151" x 5") 4. 200' of cement on top of the liner in the 7" casing. Well Plan Summary Pr, udhoe Bciy Un i'L.. R-37i R-37 g/p5 ~ / :S1-AKrT [ir ~ E ]ZID"/iO0 ?t S'TA~T ID- ~ e IZ)O"/ICI] ?t L 9 5/B in rrr,- 8 3~:~3 HI1:305~ TVD g/I/g4 1~I P'~ HALLIBLRT[N FC}2JZi~T~- VIL-9,,' (T~,JE h.[D2TI-D S~'uN_E 103 ?:. / DD,ISEIq ~REF: ~ · O/ID" e D963 {t3) To~ O~ID~ ~5~13 MI) Tc~ ~e OJI~ 8 7BCO K~ START O:' Ii.D._D 8 P___~O"/lEi3 Fi; P_~ E 7900 I."~ LO. OD" 8 BL:~GD MD 1~.~ 8 B4OO HI) tg,13E~ 8 B~6t I,~ V~"~T'~'~ SECII]EN DLA"~: 18.59° o ON 0E ~ O N FI~ S 149 ~1 4g SI~D E I~ N ~ ~45N ~ 114 ~ ~ 245 114 9114 ~2 111 9 ~ in DDg3 007 OJEL~ ~(Z~5 [ BP EXPLORATION BP TELEOOPY ARCO Alaska, Inc. TO: SATELLITE UNIT Company: ., Location: ..... · ,v v ~ I I,;/,7~1· .............. Fax ~aska Anchorage. Department: PAGES'TO FOLLOW _ 7.- .......... (Do not include covert/' ester) ~~ ..__ ram III 1 SECURITY CLASSIFICATION PRIVATE SECRET Ifil ] IIII Iii I ..... I I'1 Ii ..... - ..... .... i,.~, SATELLITE FAX MACHINE i4-51,'1.93 CONFIRM# CONFIDENTIAL PAX# 907~ 907 564- R-37i Proposed Well Schematic Proposed Coil Tubing Completion RT Elev = 54.6' Xr~: T-~/8" NfSC~ pin X 7" NSGK~ pin, -J' XOL 10-3/4'' BTC- pin X 9-5/~" I:t'rU pm--/ 7" 'FI' NIPPLE ~;~ + 2,200' ID .-, ~.g63" -- WELLHEAD,. FMC UNIVERSAL SLIMHOLE CAMERON 4" ~M CARBON KOP; 7,800' MAX, ANGLE; ~. 19 DEG. DEPARTURE- planP~a Tel5 af C~.ment C~ ?~SO0' md 7'.' 'R' NIPPLE I[3 = 5.963" Sag River Ports @ _. 8,800' -_- Sadlemchit Peris ~ ~ 8,925' VHH 8131ig4 , -. 20" 95 ppf H40 WELD CoMuetor 3-1J2" L-So coli Tubing -- 7" ~6 P~f L'80 LTC MOD {7~ ~ ~r ~ ~,~O') Heducin~ 5lccvc ~ ~ 2,~OU' md with 2.75" 'X' Nipple XO; 7" LTC MOD p~ X 7" I~S ~ 7" 26 ppf L-E0 IJ4S Recluaing $1ae¥o @ *_ 8,700' with 2.75" 'X' Nipple wl[h 2.75" 'X' Nipple 7" ehOe 9,~00' md 8-1/2" HOIO TD Alaska 011 ~ L~as bo~]$, buJ,mJs$1u~ Anchorage R-37i Proposed Well Schematic Standard Coil Tubing Completion RT Elev · $4,8' 20" 9.5 ppf i-~0 WELD X~: 7-.e,t~." NSC;C: I~1~ X 7" NSGG pin, XOt 10-3/4" BTO pin X s-~l~' BTC~ WELLHEAO: 'FM~ ~NTvERS.aL SLIMHOLE TREE: CAMERON 4" SM CARBON · . XO: 7" LTG MOD 10in X/" l,J,~Ei box · ;t.5!fl" 40 ppf L.an RTe @ 3,0G3' md ?" 26 ppf L-80 IJ43 ~3.1/2" L-80 0oll Tublr~g 2.75" 'X' Nipi~le Beker FB-1 Packer @ = 8,000' n~d wt:h 2,75" 'X' NIpple 8ag River Parts i~ + 8,ElO0' Gadlerochit Peris VHH &/31,~1 Baker FB-1 Isolation Racker @ = 8,BB0' with 2.?~" 'X' Nllaple ~-'f ~" Hole TD WELL PERMIT CHECKLIST INIT CLASS WELL NaME GEOL AREA UNIT# PROGRAM: exp [] dev~ redrll [] serv [] f/~('~ ON/OFF SltORE ADMINISTRATION 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 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 ....... Permit fee attached ................... Y 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 ..... ENGINEERING N N N N N N N N N N N N DAT~i / . 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 .... %_Yw' N 20. Adequate tankage or reserve pit ............. ~ N 21. If a re-drill, has a 10-403 for abndnmnt been approved. ,T ~:,~" 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 ~o ~ psig. ~%~,/ N 27. Choke manifold complies w/API RP-53 (May 84) ...... 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/ 7 32. Seismic analysis of shallow gas zones .......... / N 33. Seabed condition survey (if off-shore) ........ / Y N 34. Contact name/phone for weekly progress reports . . . / · Y N [exploratory only] ~ GEOLOGY: ENGINEERING: COMMISSION: Comments/Instructions: Z HOW/jo - A:%FORMS%cheklist rev 03/94 WELL PERMIT CHECKLIST WELL NAME GEOL AREA UNIT# PROGRAM: exp ~1 der [] redrll [] serv ~ ADMINISTRATION 1. Permit fee attached .................. ~ N 2. Lease number appropriate ............... ~ N 3. Unique well name and number ............... ~ N 4. Well located in a defined pool ............. ~ N 5. Well located proper distance from drlg unit boundary.. ~ N 6. Well located proper distance from other wells ...... ~ N ' 7. Sufficient acreage available in drilling unit ...... ~ N 8. If deviated, is wellbore plat included ......... (~ N 9. Operator only affected party .............. O N 10. Operator has appropriate bond in force ......... ~ N 11. Permit can be issued without conservation order ..... 6~ N 12. Permit can be issued without administrative approval..~ N 13. Can permit be approved before 15-day wait ....... ~ N ENGINEERING APPR 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 . . Y ~ 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. ~ 22. Adequate wellbore separation proposed...................~y~ N 23. If diverter required, is it adequate. N 24. Drilling fluid program schematic & equip list adequate . Y~ N 25. BOPEs adequate .................... 'Y~ N 26. BOPE press rating adequate; test to ~~ psig. Y~ N 27. Choke manifold complies w/API RP-53 (May 84) ....... ~ 28. Work will occur without operation shutdown ....... ~ N 29. Is presence of H2S gas probable ............. Y ~ GEOLOGY DATE 30. Permit can be issued w/o hydrogen sulfide measures .... Y / 31. Data presented on potential overpressure zones ..... Y/N 32. Seismic analysis 9f shallow gas zones .......... 7 N 33. Seabed condition survey (if off-shore) ........ ~ N 34. Contact name/phone for weekly progress reports .... & Y N [exploratory only] GEOLOGY: ENGINEERING: COMMISSION: Comments/Instructions: HOW/jo - A:~ORMS~cheklist rev 03/94 Z ©