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Home My WebLink About194-139Pages 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. Iq I~ --~"~ 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 ia~ Vincent Nathan Lowell [] TO RE-SCAN Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: Is~ n:~,ddgtkg f~43-6xrd~OG CC01 .xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend Operation Shutdown Alter Casing Repair Well Plugging Change Approved Program Pull Tubing Variance Re-enter Suspended Well Time Extension Stimulate X Perforate Other 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 233' FNL, 4160' FWL, Sec7, T4N, R11W, S.M. At top of Productive Interval At Effective Depth At Total Depth 2791' FSL, 3796' FWL, Sec. 6, T4N, R1 lW, S.M. 5. Type of Well: Development ~X Exploratory m Stratigraphic ~ Service 6. Datum Elevation (DF or KB) 114' KB above MSL feet 7. Unit or Property Name Kenai Tyonek Unit 8. Well Number KTU 43-6xrd 9. Permit Number 94-39 10. APl Number 50-133-20328-00 11. Field/Pool Kenai Gas Field/Tyonek 12. Present Well Condition Summary Total Depth: measured true vertical 9535 feet Plugs (measured) 8892 feet Effective Depth: measured true vertical 9461 feet Junk (measured) 8821 feet Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: Length Size Cemented 113 20" Driven 2508 13-3/8" 1093 sks 7446 9-5/8" 1792 sks 9534 7" 1690 sks measured 84-6 Sand: 9079' - 9099', D-1 Sand: 9405' - 9462' true vertical 84-6 Sand: 8453' - 8473', D-1 Sand: 8653' - 8708' Tubing (size, grade, and measured depth) 3-1/2", L-80, 7732' MD Packers and SSSV (type and measured depth) Baker SAm-3 packer @ 7651' Measured Depth /'-':';~i~ ~rtical Depth 113 113 2508 2427 7446 6880 9534 8890 13. Attachments Description Summary of Proposal X Detailed Operations Program BOP Sketch 14. 15. Status of Well Classification as: 16. Estimated Date for Commencing Operation 3/12/99 If Proposal was Verbally Approved Name of Approver Date Approved Oil Gas X Suspended Service 17. I hereby .~ify that the foregoing is true and correct to the best of my knowledge. Signed '.-,~,,__~1~"~,~ Gary Eller Title Production Engineer FOR COMMISSION USE ONLY IConditions of Approval: No, i-fy Commission so representative may witness Plug Integrity BOP Test ~ Location Clearance ./ Mechanical Integrity Test Subsequent Form Required 10-~-tL'O y Approved by Order of the Commission ORIGINAL SIGNED-By' Form 10-403 Rev. 0¢:~1~i¢8/ ~'' ~¢~l~Ob~r~N. (Jhdstenson ,,-,tO ' Date 2/18/99 Approval N_o. Commissioner Submit in Triplicate Kenai Gas Field Well KTU 43-6xrd, Pad 41-7 Marathon Oil Co., Alaska Region KB-THF: 31.1' KB-GL: 34.0' 233' S & 4160' E of NW Comer See. 7, T4N, R11W, S.M. Camco Injection Mandrel @ 1014' ID = 2.859" Squeeze Perfs(Sqzd 7/14/95) 5105'-5118' 5214'-5227' 5248'-5256' 5274'-5294' 5606'-5626' 5632'-5646' Tubing: 3-1/2", 9.3#, L-80, EUE 8rd Frae Stimulated Tyonek D-1 (9405' - 9462') w/53,000 lbs 20/40 Carbolite ~ 2 to 8 ppg plus 3,100 lbs Propnet (10/30/95) Existing Perfs - (2-1/8" strip guns, 6 spt; +45°, 14 gm EMIl) 84-6 9079'- 9099'CBL (1/30/97 & 12/16/96) D-1 9405'- 9462' CBL (9/I/95 & 9/26/95) Tagged fill ~ 9461' WLM (5/5/98) TD= 9534' 20", 94# Drive pipe ~ 113' · 13-3/8", 61 #, K-55, BTC Casing @ 2508' Cmt w/1093 sks of Class "G" 9-5/8", 47#, N-80, BTC Casing Set ~ 8370' Hole Milled in 9-5/8" ~ 7446' - 7510' (7/18/95) Orig. Cmt w/1792 sks of Class "G" Baker K-Anchor @ 7650' Baker SAB-3 Packer (9 7651' Camco X Nipple (9 7697' ID = 2.813" Camco XN Nipple (~ 7729' ID = 2.750" Baker SOS Wireline Re-entry guide @ 7732' EZSV (9 9499' 7", 29#, P-110, BTC Casing (~ 9534' Cmt w/1690 sks Last Rev: JGE, 2/18/99 Well KTU 43-6xrd Kenai Gas Field AFE 9203599 Purpose: Perform a fracture stimulation of the 84-6 Sand ofKTU 43-6xrd. Procedure: 1. MIRU 13/el'' coil tubing on KTU 43-6xrd. Test BOPE to 4000 psig. RIH with coil tubing to top of fill at 9461' ,MD. Lay a 20/40 sand plug from PBTD to 9200' MD (approximately 5800 lbs. of 20/40 sand, or 116 sacks). Place a 20' Maraseal plug on top of the sand plug, and displace with 3% KC1. - . Alter laying the sand plug and the Maraseal, PU to 8500' CTM. Shut in backside, and pressure up to 4000 psig to pack the sand plug. POOH, RDMO coil tubing. Allow Maraseal to set overnight before proceeding to the next step. o MIRU 31/2", 1 OM tree saver and fluid pump. Pressure test tree saver. Install SPIDR gauge on the tree saver. Perform mini-frac on the 84-6 Sand by pumping 3000 gal of 3% KC1 at maximum rate (anticipate 9 bpm). Following the mini-frac, shut in the tree saver but continue to record tubing pressure while rigging down the fluid pump. Anticipate recording pressure falloff data for 72 hours. 4. When adequate pressure data has been recorded, RD tree saver. Interpret fracture closure and pressure falloff data in the Anchorage office, and modify fracture design accordingly. , MIRU 31/2'', 10M tree saver and fracturing equipment. Also MIRU flowback equipment. Pressure test tree saver and frac lines. Frac stimulate the 84-6 Sand as per separate procedure. When complete, monitor for fracture closure, then RDMO fracture equipment. When surface pressure falls below 4500 psig, RDMO tree saver. . RU flowback lines and pressure test. Flow back fractured 84-6 Sand through temporary flowback equipment as per instructions of onsite engineer. When flow has cleaned up, switch to permanent facilities and test as per instructions of Production Foreman. 7. MIRU 13/,,,, coil tubing and nitrogen on KTU 43-6xrd. Test BOPE to 4000 psig. Wash out sand plug to 9499' MD, then jet well in as needed. POOH, RDMO coil tubing. 8. Produce well KTU 43-6xrd as per instructions of Production Foreman. JGE - February 18, 1999 Ol' ggFO W Memorandum State of Alaska Oil and Gas Conservation Commission Re: Cancelled or Expired Permit Action EXAMPLE: Point McIntyre P2-36AXX API# 029-22801-95 This memo will remain at the front of the subject well f'fle. Our adopted conventions for assigning APl numbers, permit numbers and well names did not specifically acldress expired or cancelled permits. This omission has caused some inconsistencies i 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 APl number and in some instances the well name reflect the number of preexistin', reddlls and or muitilaterais in a well. In order to prevent confusing a cancelled or expired permit ~ 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 APl numbering methods descnbed in AOGCC staff memorancium "Multi-lateral (welibore segment) Ddiling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician ALASKA OIL AND GAS CONSERVATION COMMISSION October 31, 1994 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Terry Jordan Drilling Engineer Supervisor BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Unit M-36 BP Exploration (Alaska), Inc. Permit No: 94-139 Sur. Loc. 2367'NSL, 605'WEL, Sec. 1, TllN, R12E, UM Btmhole Loc. 377'NSL, 384'WEL, Sec. 1, TllN, R12E, 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. 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. Chairman . BY ORDER OF THE COMMISSION dlf/Enclosures co: 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 25.005 la. Type of work Drill [] Redrill CIIlb. Type of well. Exploratoryr-I Stratigraphic Test [] Development Oil [] Re-Entry [] DeepenCII Service [] Development Gas [] Single Zone [] Multiple Zone[] 2. Name of Operator 5. Datum Elevation (DF or KB) i10. Field and Pool BP Exploration KBE = 55.8 feet Prudhoe Bay Field/Prudhoe 3. Address 6. Property Designation Bay Pool P. O. Box 196612. Anchoraae. Alaska 99519-6612 ADL 28260 4. Location of well at surface 7. Unit or property Name 11. Type Bond(~ee 20 AAC 25.025) 2367' NSL, 605' WE/_, SEC. 1, T11N, R12E Prudhoe Bay Unit At top of productive interval 8. Well number Number 479' NSL, 390' WEL, SEC. 1, T11N, R12E M-36 (44-1-11-12) 25100302630-277 At total depth 9. Approximate spud date Amount 377' NSL, 384' WEL, SEC. 1, T11N, R12E 11/6/94 $200,000.00 12. Distance to nearest 13. Distance to nearest well 4. Number of acres in property15. Proposed depth(UDandTVO) property line ADL 28282-384' feet M-2-51' @ 2892' MD feet 2560 9501' MD/9214' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (s~e 20 AAC 25.035 (e)(2)) Kickoff depth 2~oo feet Maximum hole angle~8.~5 o Maximum suHace 3330 psig At total depth (TVD) 8800'/4~90 psi~ 18. Casing program Specifications Setting Depth s~ze Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length M D TVD MD TVD (include stage data) 30" 20" 91.5# H-40 Weld 80' 30' 30' 110' 110' 1260 sx Arcticset (Approx.) 13-1/2" 10-3/4" 45.5# NT8OLHE Butt 3047' 29' 29' 30 76' 3056' 980 sx CS 111/375 sx "G"/250 sx CS II 9-7/8" 7-5/8" 29.7# NT95HS NSCC 8573' 28' 28' 8601' 8327' 9-7/8" 7-5/8" 29.7# 13CR80 NSCC 900' 8601' 8327' 9501' 9214' 805 sx Class "G" Contin.cl ency 6-3/4" 5-1/2" 17# 13CR80 NSCC 850' 8651' 8376' 9501' 9214' 130 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 RECEIVED Conductor Surface Intermediate 0CT 2 4 1994 Production Liner Alaska 0il & ~as Cons. C0mmJssi0n Perforation depth: measured Anch0ra~.~ true vertical 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program[] Drilling fluid program [] Time vs depth pict [] Refraction analysis I--! Seabed report[] 20 AAC 25.050 requirements[] 21. I hereby certify that the foregoing is true,a~nd correct to the best of my knowledge ~ ~ol¢~J,~' _/ /' Signed ~)~{/¢~"'~,~..¥ Title Drilling En~ineer Supervisor DatoI0/7-'[/r~L{ /~ ~ (// Commission Use Only Permit Number IAPI number ~ IApproval date ISee cover letter jother requirements Conditions (~f approval Samples required [] Yes ~ No Mud log required [] Yes ~ No Hydrogen sulfide measures [] Yes ~ No Directional survey requ~rea [] Yes [] NO Required working pressure for BOPE [] 2M; 1-13M; ,,]~J5M; I-I10M; 1-115M; by order of Other: Original Signed By Commissioner [ne commission Date Approved by David W' ........... Form 10-401 Rev. 12-1-85 Submit in Well Plan Summary [Well Name: M-36 PBU Type of Well (producer or injector): I Producer Surface Location: Target Location: Bottom Hole Location' 2367' FSL 605' FEL Sec 01 T11N R12E UM 479' FSL 390' FEL Sec 01 T11N R12E UM 377' FSL 384' FEL Sec 01 TllN R12E UM [AFENumber: [4P0581 I Estimated Start Date: I Nov. 6, 1994 [ l MD: 19501' I iTVD: Well Design (conventional, slimhole, etc.)' [Rig: [Nabors 18-E Operating days to complete: I 15 9214' I IRT'GL 129'5' IKBE:I 55.8' [ Slimhole producer I I Formation Markers: Formation Tops MD TVD (BKB) Base Permafrost 1861' 1856' Ugnu Zone 4A 3707' 3656' Top Seabee (CM3) 5496' 5356' Kuparuk/Put River Absent Absent IKRU/LCU 7022' 6806' Top Sag River 8792' 8515' Top Shublik 8827' 8550' Top Sadlerochit 8915' 8636' Target 8915' 8636' Total Depth 9501' 9214' Casing/Tubin Program: Wt/Ft Hole Size' Csg/ - Wt/F-t Grade Conn Length Top Btm Tbg O.D. MD/TVD MD/TVD 30" 20" 91.5// H-40 Weld 80' 30'/30' 110'/110' 13-1/2" 10-3/4" 45.5// NT80LHE Butt 3047' 29'/29' 3076'/3056' 9-7/8" 7-5/8" 29.74/ NT95HS NSCC 8573' 28'/28' 8601'/8327' 9-7/8" 7-5/8" 29.74/ 13Cr-80 NSCC 900' 8601'/8327' 9501'/9214' Contingency 6-3/4" 5 1/2" 174/ 13Cr-80 NSCC 850' 8651'/8376' 9501'/9214' Tubing ~ m ' 5' 4 1/2" 12.6 13Cr-80 NSCT 8674' 27'/27'. 4. _8~)], ~ - - RE( Well Plan Summary OCT 2 4 1994 Alaska Oil & Gas Cons. Commission Anchor~. :~ Logging Pro 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 'ram: None GR/DIFL/BHCA/CNL/SP and RFT (if well is longstringed) GR/DIFL/BHCA/CNL/SP and RFT (if well is not longstringed) None Optional SBT and Gyro 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: [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: 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 KOP: 1 2300' [ Maximum Hole Angle: I 18.15 degrees Close Approach Well: M-02 at 2892' (51, 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 OCT 2 4 1994 Alaska Oil & Gas Cons. Commission Anchor;... PROPOSED DRILLING AND COMPLETION PROGRAM WELL M-36 [ 44-01-11-12 ] PBU 1. MIRU. NU diverter and function test same. o Drill 13-1/2" hole. Run and cement 10-3/4", 45.5#, 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 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. . 6a. Longstring Option: Directionally drill 9-7/8" hole to TD. Run a 7-5/8", 29.7#, NT-95 NSCC by 7-5/8", 29.7#, 13Cr-80 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. 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#, 13 Cr-80 NSCC liner from TD to 150' inside 7-5/8" casing shoe and cement using Class G cement. 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", 12.6g, 13 Cr-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. 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 wells M-33, M-34 or M-36. Tubing Size: 4-1/2", 12.6 # NT 13CR-80 tubing with 5 GLM's. Well Plan Summary RECEIVED 0C7 2. 4 199t1· /~:!~ska Oil & Gas Cons. Commission Anchort.. ~ 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' 980 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: 1.15ft3/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 APPROX. # SACKS' 250 YIELD: 0.96 ft3/sx 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 OC I 2.. 4 199q oil & Gas Cons, Commission Anchort. ; 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: 375 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: 430 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) from 3407' to 5796'. 3. Run 1 solid body 7-3/4" x 9-1/4" centralizer or turbolator on fh'st 2 joints inside 10-3/4" 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 300' MD above top of Ugnu (top of Ugnu at 3725' 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~i~e~~~) Well Plan Summary OCT 2 4 1994 Oil & Gas Cons. Commission Anchort.., 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 YIELD: 1.17 ft3/sx MIX WATER: 3.58 gps APPROX. # SACKS' 130 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 oCT 2. 4 i994 0il & Gas Cons. C0mmi~si0n Angh0rt ~ PRUDHOE BAY DRi_LZNG~RoU~ - M-36 (P~3) VERTICAL SECTION VIEW I L i i Ji ..... i Section at: J76.23 ;TVD Sca)e,' I ~nch -- J200 feet . ~Dep Sce]e.' ~ ~nch = ~200 feet 600--- B .TT .... : .... ~. ~, ............... i I ~ ~nadr ~ ] ] Sc~ ]umberge~ JaO0-- ~ j .,, ; ... N~r~e~ ~dentificat~on ND BKB SECTN ~NCLN I I ~) KB 0 0 0 0,00 ~ i , B) BUILD 1,5/JO0 500 500 -0 0,00 I I C) END 3.5/~00 BU]LD 9DO B~9 ~3 .... 01' - .......I ; ----,.~ D) DRDP ~.5/~00 16OO ~595 58 B,O0 ~,~,~sr'~ E) END ~.5/~00 DROP . , E - ~ ~ ~000 ~995 7t 0 O0 / . F) KOP/BUILO ~,5/100 ~300 2295 71' 0,00. 840D--- - F ~' . ...... G) END 2,5/~00 BUILD 30~6 3009 lB5 ~ ~ H) 10-3/4" 6~SING PO]NI 3076 3056 80~ IB.I5 I} DROP ~.5/JO0 7757 7504 J559 tB.~5 300D~-.. . ~ J) END J,5/~O0 DROP B300 8030 $79t ~ ....... . ....... K) 7-5/8" CASING POINT BBOJ. 85~4 ~BTB JO,OD L] ....... TARGET ....... B9S5 8536 ~89B ; M) TD 950f 92~4 2000 ~0~ ........ ~ ............ ~ ........ i ......... ' ..... 4BO0~ ~ ,,, - I · .... , ._ , ~000 ..... - ~ , . ....... . ~oo ...... ~ X.. -; . ~ ........ ~~,~-?~ .......... FT--. ~' _ ...'-" , .... ~c~ 2 ~..~ .... , ~ Sect ion Departure PRUBHOL' B/~Y DRILLTNG ~ROUP...__~__ ] cl ~,o ,.o/~oo ~,=o ~oo ,~ ~ PLAN VIEW O) DROP ~.5/~00 1600 53 78~ ......... E] END ~.5/]00 DROP 8000 65 95 CLOSURE ' 2002 feet at Az~mut~ ~73 F) KOP/~UILD 2.5/~00 2300 65 95 ' G) END ~.5/~00 BUILD 3026 }79 102 DECLINATION ' 29.3~0 E J0-3/4" CASING POINT 3076 J94 103 SCALE · ~ 1nch : 400 feet H DROP 1.5/100 7757 d) END 1.5/100 DROP 8300 t78~ 208 DRAWN ' ~0/18/94 K) 7-5/8" CASING POINT 880J ~86B 2~ L) ....... TARGET ....... B9~5 ~SBB 2~5 N) TD g50~ ~989 222 " " ='" Anadr~ ]1 Sch]umberger .~. 200 ........... ~00 .... ; ............ ~ ..... :fi ._. ' ....... ~oo~ - . , ........ ~ '' [00 .......................... 8oo ~ ... J ' ' " I -' ...... I / m......... ~ m. i ..... ~ ................. , ...... lO00 m / i, -.~ . ..... ~ .......... , ...... . ..... I , ~50 ~T lARGE! RADIUS' ~eoo-- i I ......... , 2000 · [ ~ I , ~ R :CEiVED ~oo ....... ] ..~ i~ l' 0 ;T 2 4 1994 , 2~00~., I I ..... I I ~400 l~O0 1000 800 BO0 400 200 0 ~o0 ~00 ~oo 800 ~00o 1200 1400 WELL PERMIT CHECKLIST UNIT# PROGRAM: exp [] dev~ redrll [] aery [] ADMINISTRATION l, 2. 3. 4. 5. 6. ' 7. 8. 9. 10. 11. 12. 13. Permit fee attached .................. N Lease number appropriate ............... N Unique well name and number .............. N Well located in a defined pool ............. N Well located proper distance from drlg unit boundary.. N Well located proper distance from other wells ..... N Sufficient acreage available in drilling unit ..... N If deviated, is wellbore plat included ........ N Operator only affected party .............. N Operator has appropriate bond in force ......... N Permit can be issued without conservation order .... N Permit can be issued without administrative approval.. N Can permit be approved before 15-day wait ....... N ENGINEERING 14. Conductor string provided ............... ~ N 15. Surface casing protects all known USDWs ........ ~ N 16. CMT vol adequate to circulate on conductor & surf csg. ~ N ~ 17. CMT vol adequate to tie-in long string to surf csg . . ~ N ~ . '~-~ 18. CMT will cover all known productive horizons ...... ~ N 19. Casing designs adequate for C, T, B & permafrost .... ~ N 20. Adequate tankage or reserve pit ............. Y~ N _~,,. 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 .......... ~ N 24. Drilling fluid program schematic& equip list adequate .~ N ~ l~~ 25. ~Sp ~ate tee; ;~ ~d~O psig.~ ~ ~- - 27. Choke manifold complie w/ I RP- ( y ) ...... ~/~ 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 31. Data presented on potential overpressure zones ..... 32. Seismic analysis 9f shallow gas zones .......... 33. Seabed condition survey (if off-shore) ........ 34. Contact name/phone for weekly progress reports . . [exploratory only] GEOLOGY: ENGINEERING: COMMISSION: Comments/Instructions: TAB HOW/jo - A:~CORMS~cheklist rev 03/94