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Home My WebLink About194-008XHVZE 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. lC~ C~ .c00~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 vadous kinds [] Other COMMENTS: scanned by: Bevedy ~ncent Nathan Lowell Date: ' (~ ,..~-'~ [] TO RE-SCAN Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: ~si os W Memorandum State of Alaska Re: Oil and Gas Conservation Commission DATE /{'~{,,{.q ~t, tqqq 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 file. Our adopted conventions for assigning AP! numbers, permit numbers and well names did not specifically address expired or cancelled permits. This omission has caused some inconsistencies in 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 remain unchanged. The APl number and in some instances the well name reflect the number of preexisting 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 ddll. The APl number for this cancelled or expired permit is modified so the eleven and twelfth digits is 95. 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 memorandum "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 Sep. 26. 1995 !i:I?AM AR-L~a ALASKA INC ARCO Alaska, Inc. Post Office Box 100360 Anchorage. Alaska 99510-(]360 Telephone 907 276 1215 September 26,1995 No. 3533 P. 2/2 Steve McMains Alaska Oil and Gas Conservation Commission 3001 Forcupine Drive Anchora§e, AK 99501 Subject: Cancellation of Approved Permits to Drill for Undrilled Wells Dear Mr. McMains: Per our discussion last week, I am writing to request that you cancel several approved Permits to Drill for the Kupmmk River Unit. The wells wore permi~ for different expansion and infill projects duzing the last two years. Due to information gained from other new wells or to changes in the drilling schedule, the wells I'd like to cancel were dropped from the program. While we will reuse the well names, by the time the wells are actually ch-il]ed the information will be significantly different than is on the current approved permits. Since this change requires re-submission of a Form 401 anyway, I think it would be easier on both of us to cancel the current permits. _ rd like m cancel the Permits to Drill for the following we!ls: c~3- { ~ 8 KRU 2E-04 q~-- l']5 KRU2E-18 KRU ZA-18 (Permit ~93-166, issue date 11/9/93) I<RU ZA-22 (Pe~t g$3-163, issue date 10/27/93) KKU 3M-27 KRU 3H-24 KRU 3H-29 ' KRU 3H-30 00<3 2A-18 and 2A-22 inadvertently have two Permits to Drill, each; please cancel only the permit noted above. Thank you for calling our attention to this matter. If you have any questions on the above wells please call me, Sincerely, " _ ,. , , -"'" .... : ..... ........... R'-- ":'- ED Denise Petrash $ E? 2 B 1995 Drilling Engineer J, Hartz M, Zanghi $. Allsup-Drake (W1) Well File Alas~ 0il & Gas Cons. Commission AOGCC (Anchorage) Anchorage ATO-1286 ATO-1205 ATO-1205/ATO-370 (one copy f/each well listed abeve) AR38-8003-93 2a2-2503 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 February 17, 1994 A. W. McBride Area Drilling Engineer ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Unit 3H-24 ARCO Alaska, Inc. Permit No. 94-08 Sur Loc 1095'FNL, 282'FWL, Sec. 12, T12N, RSE, UM Btmhole Loc 1432'FNL, 1348'FEL, Sec. 3, T12N, R8E, UM Dear Mr. McBride: Enclosed is the approved revised application for permit to drill the above referenced well. The provisions of the original approved permit dated January 12, 1994 are in effect for this revision. Sincerely, BY ORDER OF THE COMMISSION dlf/Enelosures CC.' Department of Fish & Game, Habitat Section W/o eric1 Department of Environmental Conservation w/o encl STATE OF ALASKA AI_~oKA OIL AND GAS ~SERVAT1ON COMMIL .~ON PERMIT TO DRILL 2O AAC 25.OO5 la. Type of Work Drill X Redrill [~ lb Type of Well Exploratory D Stratigraphic D Development Oil X Test Re-Entry [~ Deepen r~ Service E] DevelopmenlGas ~] Single Zone X Multiple Zone ~-] 2.. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool ARCO Alaska, Inc. RKB 80', Pad 39' GL feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchorage, AK 99510-0360 ADL 25532, ALK 2658 4. Location of well at surface 7. Unit or property Name 11. Type Bond (see 20 AAC 25.025) 1095' FNL, 282' FWL, SEC. 12, T12N, R8E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 1548' FNL, 1186' FEL, Sec. 3, T12N, RSE, UM 3H-24 #U-630610 At total depth 9. Approximate spud date Amount 1432' FNL, 1348' FEL, Sec. 3, T12N, RSE, UM 2/21/94 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number o! acres in property 15. Proposed depth (MD and TV•) property line 3H-16 11025' MD 1348' @ TD feet 12.0' @ 200' MD feet 2560 6127' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035(e)(2)) Kickoff depth 400 feet Maximum hole angle 64.1 9° Maximum surface 1835 psig At total depth (TVD) 3280 psig "18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 24" 16' 62.5# H-40 Weld 80' 41' 41' 121' 121' _+200 CF 12.25" 9.625' 47.0# L-80 BTC 2499' 41' 41' 2540' 21 19' 570 Sx Arcticset III & HF-ERW 570 Sx Class G 12.25" 9.625" 36.0# J-55 BTC 2252' 2540' 2119' 4792' 3100' HF-ERW 8.5" 7' 26.0# L-80 BTCMOE 10984 41' 41' 11025' 6127' 150SxClassG HF-ERW Top 500' above Kuparuk 19. To be completed for Redrill, Re-entry, and Deepen Operations, Present well condition summary Total depth: measured fe et Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structural i~ r?~m~it(~ira t e RECEIVED Production Liner -.' FEB - 8 1994 Perforation depth: measured true vertical A!~,~ka Oil & Gas Cons. Commission 20. Attachments Filing fee X Property plat ~1 BOP Sketch X "Diverter sketD~i~lCJ~l:)rage Drilling program X Drilling fluid program X Time vs depth plot D Refraction analysis [] Seabed report r-~ 20 AAC 25.050 requirements X 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed ~'~ ~ Title Area Drilling Engineer Date ~ Commission Use Only mb n~ ~b,~r ~/al._. d,~e~.~ Perm~j ~ ~j JAPI so- ' 3. o oo I^ppr J SeeotherCOVerrequirementsletterfor Conditions of approval Samples required [--] Yes ~ No Mud Icg required [] Yes [~ No Hydrogen sulfide ~ Yes [~ No Directional survey required J~ Yes r-~ No measures Required working pressure for DOPE r~ 2M ~;~ 3M ~ 5M r"] 1OM r-] 15M Other: Original Signed By by order of ._Approved by David W. Johnston Commissioner the commission Date Z /[ ,) /?~/ Form 10-401 Rev. 7-24-89 Submit i~ triplicate o . . . , . . , . 10. 11. 12. 13 14 15 16 17 18 GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD 3H-24 Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (4,792')according to directional plan. Run and cement 9-5/8" casing (cement to surface). No cement bond logs to be run in 9-5/8" casing. Install and test BOPE. Test casing to 2000 psi. Drill out cement and 10' of new hole. Perform leak off test to 12.5 ppg EMW. Drill 8-1/2" hole to total depth (11,025') according to directional plan. Run open hole evaluation logs or LWD tools as needed. Run and cement 7" casing. (If significant hydrocarbon zones are present above the Kuparuk, sufficient cement will be pumped for isolation in accordance with Rule 20 AAC 25.030. Alternatively, if significant hydrocarbon zones occur within 200' TVD of the surface casing shoe, cement will be down squeezed in the annular space' between the surface and production casing after the primary cement job is completed.) ND BOPE. NU tubinghead & full opening valve for cased hole logging. Secure well and release rig. Run cased hole cement evaluation. ND full opening valve & NU tree assembly. Move in and rig up Nordic #1. ' Install and test BOPE. Pressure test 7" casing to 3500 psi. Perforate and run completion assembly, set and test packer. ND BOPE and install production tree. Shut in and secure well. Clean location and release rig. REEEIVED FEB - 8 1994 Alaska Oil & (~a~ Cons. Commission Anchorage jCreoted by : jones For: S Bi~EDLEY iDote plotted : 7-Feb-g4 iPIot Reference is 24 Version #2. iCoordinotes ore in feet reference slot #24. !True Vertical Depths ore reference wellhead. Baker Hughes INTEO --- 7200 6800 6400 6000 56005200 I I I t I I I I I I I I I ARCO ALASKA, Inc. Structure : Pad 5H Well : 24. Field : Kuparuk River Unit Location : North Slope, Alaska <-- West 4,800 4400 4000 5600 5200 2800 2400 2000 1600 1200 800 I t I I I I I I I I I I I I I I I I I I I Scale 1 : 200.00 4DO 0 40O I I I I I I I v (~ TAR O E-f LOCATION: ID LOCATION: ~ SEC. 5, T12N, RSE J 1452' FNL, 1348' FEL 'a~~ TARGET ~ TVD=5890 ~ TMD=10715 SEC. 3, T12N, RBE DEP=8297 ~ NORTH 4827 8 aa 400_ 0,1 0 RKB ELE'VATtON: 80' .. _.e400 KOP WD=400 TMD=400 DEP=O 8 3.00 m 9.00 8O0 15.00 N 54.42 DEG W 8~97' (TO TARGET) 1200 400 0 400 Scale 1: 200.00 21.00 BUILD 5 DE(; / lOO' 27.00 33.00 39.00 B/ PERMAFROST TVD=1630 TMD=1736 DEP=449 45.O0 51.00 T/ UGNU SNDS TVD=1870 TMD=2078 BEP=691 57.00 63.00 EOC TVD=2119 TMD=2540 DEP=1078 T/ W SAK SNDS TVD=2570 TMD=3575 DEP=2010 3/ W SAt( SNDS TVD=5000 TMD=4562 DEP=2899 9 5/8" CS(; PT TVD=3100 TMD=4792 DEP=5106 MAXIMUM ANGLE 64.19 DEG TARGET ANGLE 40 DEG i i i i i i I i i i i i 800 1200 1600 2000 2400 2800 K-10 TVD=3200 TMD=5022 DEP=3313 ESTIMATED SURFACE LOCATION: 1095' FNL, 282' FWL SEC. 12, T12N, R8E _520o 8oo K-5 TVD=465fi TMD=8363 DEP=6321 BEGIN ANGLE DROPTVD=5152 'fMD=9506 DEP=7350 62.00 58.00 54.00 DROP 2 DEO / 100' 50.00 46.00 TARGET -T/ ZONE C (EOD) TVD=5890 TMD=I0715 DEP=8297 42.00 T/ ZONE A TYD=5926 TMD=10762 DEP=8327 B_/ KUP SNDS TVD=5974 TMD=10825 DEP=8367 TD / 7" CSG PT TVD=Olg7 TMD=IIO25 DEP=8496 Vertical Section on 305.58 azimuth with reference 0.00 N, 0.00 E from slot #24 i i i i i I i i i i i i i i i i i i i i i i / i J i i i 3200 3600 4000 4400 4800 5200 5600 6000 6400 6.800 7200 7660 800,0 84~30 450 400 350 I I I I I 300 I 250 We sf Scele 1 200 150 100 50 0 2100 ~ ~~tRC 0 g~ ~ ALASKA, Inc. ~ ~ tructure : Pad 5H . Well : 24 :=. ~ ~ : Kuparuk I;l~ver Uni~ Location : No~h S~ope, Al~aka / 1900 1700 · 50.00 50 1500 ,3OO 1100 27OO 900 1,3¸ 25C I 100110i 1700 °~>~ 500 150( ;00 ~00 400 _350 _300 _250 _200 l I _150 Z - _100 ..~ _ 50 -- iD __ 0 --, _ cn 0 _500 DRILLING FLUID PROGRAM Well 3H-24 Spud to 9-5/8" surface casing Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids 9.0-10.5 15-25 15-35 50-80' 5-15 15-40 10-12 9.5-10 +10% Drill out to wei~lht up 8.4-9.6 5-15 5-8 30-40 2-4 4-8 8-10 9.5-10 4-7% Drilling Fluid System: Tandem Brandt Shale Shakers Triple Derrick Shale Shakers Solids Processing System to minimize drilling waste Mud Cleaner, Centrifuges, Degasser Pit Level Indicator (Visual and Audio Alarm) Trip Tank Fluid Flow Sensor Fluid Agitators Notes: Weight up to TD 10.9 10-18 8-12 35-50 2-4 4-8 4-5 thru Kuparuk 9.5-10 <12% Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 AAC 25.O33. Maximum anticipated surface pressure is calculated using a surface casing leak-off of 13.5 ppg EMW and a gas gradient of 0.11 psi/ft. This shows that formation breakdown would occur before a surface pressure of 1835 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 3H-24 is 3H-16. As designed, the minimum distance between the two wells would be 12.0' @ 200' MD. Incidental fluids developed from drilling operations will be hauled to the nearest permitted disposal well or will be pumped down the surface/production casing annulus of the last well drilled. That annulus will be left with a non-freezing fluid during any extended shut down (> 4hr) in pumping operations. The annulus will be sealed with 225 sx of cement followed by arctic pack upon completion of fluid pumping. *Spud mud should be adjusted to a FV between 50-80 sec/qt to drill gravel beds. RECEIVED Anchorage Casing Design/Cement Calculations 7-Feb-94 Well Number: Surface Csg MD: Surface Csg TVD: Production Csg MD: Production Csg TVD: Top of West Sak, TM D: Top of Target, TMD: Top of Target, TVD: Estimated Pressure: Surface Casing Choice: Production Csg Choice: Production Casing Frac. Pressure 3H-24 4,792 ft 3,100 ft 11,025 ft 6,127 ft 3,575 ft 10,715 ft 5,890 ft 3200 psi Page 3,500 psi Maximum anticipated surface pressure Estimated BH pressure at top of target zone TVD surface shoe {(13.5'0.052)-0.11 }*TVDshoe Estimated Pressure= Top of Target, TVD: Overbalance, psi= Anticipated Mud Weight =1 3,100 ft 1,835 psiJ 3,200.0 ppg 5,890 ft 150 psi 10.9 ppg] Surface lead: Top West Sak, TMD = 3,575 ft Design lead bottom 500 ft above the Top of West Sak: 3,075 ft Annular area = 0.3132 cf/If Lead length * Annulus area = 963 cf Excess factor = 15% Cement volume required = 1,108 cf Yield for Permafrost Cmt = 1.94 Cement volume required =1 570 sxI Surface tail' TMD shoe = 4,792 ft (surface TD - 500' above West Sak) * (Annulus area) = 538 cf Length of cmt inside csg = 80 ft Internal csg volume = 0.4110 cf/If Cmt required in casing = 33 cf Total cmt = 571 cf Excess factor = 15% Cement volume required = 656 cf Yield for Class G cmt = 1.15 Cement volume required =[ 570 sxJ Casing Design / Cement Calculations Production tail: 7-Feb-94 TMD = 11,025 ft Top of Target, TMD = 10,715 ft Want TOC 500' above top of target = 10,215 ft Annulus area (9" Hole) - 0.1745 (TD-TOO)*Annulus area -- 141 cf Length of cmt wanted in csg = 80 ft Internal csg volume = 0.2148 Cmt required in casing -- 17 cf Total cmt = 159 cf Excess factor - 15% Cement volume required - 182 cf Yield for Class G cmt -- 1.23 Cement volume required =[ 150 sxJ TENSION - Minimum Design Factors are: T(pb)=1.5 and T(js)=l.8 Surface (Pipe Body): Casing Rated For: Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy -- Weight of displaced mud Length = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy -- Tension (Pipe Body) -- Design Factor =1 10860oo lb 4,792 ft 47.00 Ib/ft 225224.0 lb 36952.0 lb 188272.0 lb Surface (Joint Strength): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy -- Weight of displaced mud Casing Rated For: Length = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Joint Strength) = Design Factor =[ 1161000 lb 4,792 ft 47.00 Ib/ft 225224.0 lb 36952.0 lb 188272.0 lb 6,21 Production (Pipe Body): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (WEft) Buoyancy = Weight of displaced mud Casing Rated For: Length = Casing Wt (Ib/ft) = -. Dead Wt in Air = Buoyancy = Tension (Pipe Body) = Design Factor =1 604000 lb 11,025 ft 26.00 Ib/ft 286650.0 lb 47286.8 lb 239363.2 lb 2.5J Production (Joint Strength): Tension (Pipe Body) = Dead Wt in Air- Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy -- Weight of displaced mud Casing Rated For: Length = Casing Wt (Ib/ft)= Dead Wt in Air = Buoyancy = Tension (Joint Strength) = Design Factor =[ 667000 lb 11,025 ft 26.00 Ib/ft 286650.0 lb 47286.8 lb 239363.2 lb 2.8J Casing Design / Cement Calculations BURST - Minimum Design Factor = 1.1 Surface Casing: Burst = Maximum surface pressure Casing Rated For: Max Shut-in Pres = Design Factor =[ Production Csg: 1. Design Case - Tubing leak while well is SI Inside pres=Csg Frac pres(3500 psi)+Mud Wt*.052*TVD Outside Pres=Backup Gradient (8.9ppg *0.052*TVD) Net Pressure = Pressure inside-Pressure outside Design Factor = Rating / Net Pressure Casing Rated For: Inside pressure Outside Pressure Net Pressure Design Factor COLLAPSE - Minimum Design Factor = 1.0 Surface Casing 1. Design Case - Lost circulation and Fluid level drops to 2000' 'I'VD with 9.0 # Mud 2. Ext. Pres=Mud Wt*0.052*TVD-(2000'TVD of 9# Mud) Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Design Factor =[ Production Csg 1. Worst Case - Full evacuation of casing 2. Mud weight on outside = Mud Wt * 0.052 * TVD Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Design Factor =[ 7-Feb-94 6870 psi 1835.2 psi 3.7J 7240 psi 6985 psi 2836 psi 4149 psi 1.71 4750 psi 0.569 Ib/ft 827 psi 5.7J 5410 psi O.569 Ib/ft 3485 psi 1.6i R-E ,EIVED FE~ - 8 199~l. /InChorage Casing Design / Cement Calculations 7-Feb-94 Surface Casing Choices OD ID I b/ft Grade I 9.625 8.681 47 L-80 2 9.625 8.835 40 L-80 3 9.625 8.921 36 J-55 4 10.750 9.950 45.5 J-55 Metal X-Section Jt Strength Body Strength Collapse 13.5724 sq. in. 1161000 lb 1086000 lb 4750 psi 11.4538 sq. in. 979000 lb 916000 lb 3090 psi 10.2545 sq. in. 639000 lb 564000 lb 2020 psi 13.0062 sq. in. 931000 lb 715000 lb 2090 psi Burst 6870 psi 5750 psi 3520 psi 3580 psi Production Casing Choices OD ID I b/ft Grade I 7.000 6.276 26 L-80 2 7.000 6.276 26 J-55 Metal X-Section Jt Strength Body Strength Collapse Burst 7.5491 sq. in. 667000 lb 604000 lb 5410 psi 7240 psi 7.5491 sq. in. 490000 lb 415000 lb 4320 psi 4980 psi RECEIVED FEB -8 199 At~sk~ Oil & Gas Cons. Commission Anchorage KI--- ARUK RIVER UNIT 20" DIVERTER SCHEMATIC 3 DO NOT SHUT IN DIVERTER AND VALVES AT SAME TIME UNDER ANY CIRCUMSTANCES. MAINTENANCE & OPERATION . UPON INITIAL INSTALLATION, CLOSE PREVENTER AND VERIFY THAT VALVE OPENS PROPERLY. CLOSE ANNULAR PREVENTER IN THE EVENT THAT AN INFLUX OF WELLBORE FLUIDS OR GAS IS DETECTED. OPEN APPROPRIATE VALVE TO ACHIEVE DOWNWIND DIVERSION. ARCO ALASKA, INC., REQUESTS APPROVAL OF THIS DIVERTER SYSTEM AS A VARIANCE FROM 20AAC25.035(b) 1. 16" CONDUCTOR 2. SLIP-ON WELD STARTING HE. AD 3. DIVERTER ASSEMBLY WITH ONE 2-1/16"- 2000 PSI BALL VALVE 4. 20"- 2000 PSI DRILLING SPOOL WITH TWO 10" OUTLETS. 5. 10" HCR BALL VALVES WITH 10" DIVERTER LINES, A SINGLE VALVE OPENS AUTOMATICALLY UPON CLOSURE OF ANNULAR PREVENTER. VALVES CAN BE REMOTELY CONTROLLED TO ACHIEVE DOWNWIND DIVERSION 6. 20" - 2000 PSI ANNULAR PREVENTER RECEIVED FEE~ - 8 1994 Gas Cons. Commission Anchorage EDF 3/10/92 < < 7 , 6 5 4 I > ,> .- _. 13 5/8" 5000 PS 3OP STACK ACCUMULATOR CAPACrrY TEST 1. CHECK AND FILL ACCUMULATOR RESERVOIR TO PROPER LEVEL WITH HYDRAULIC FLUID. · 2. ASSURE THAT ACCUMULATOR PRESSURE IS 3000 PSI WITH 1500 PSI DOWNSTREAM OF THE REGULATOR. 3. OBSERVE TIME, THEN CLOSE ALL UNITS SIMULTANEOUSLY AND RECORD THE TIME AND PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PSI REMAINING PRESSURE. BOP STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH WATER. 2. CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. PREDETERMINE DEPTH THAT TEST PLUG WILL SEAT AND SEAT IN WELLHEAD. RUN IN LOCK-DOWN SCREWS IN HEAD. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TEST ALL COMPONENTS TO 250 PSI AND HOLD FOR 10 MINUTES. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR 10 MINUTES. BLEED TO ZERO PSI. 5. OPEN ANNULAR PREVENTOR AND MANUAL KILL AND CHOKE LINE VALVES. 6. CLOSE TOP PIPE RAMS AND I-,ICR VALVES ON KILL AND CHOKE LINES. 7. TEST TO 250 PSI AND 3000 PSI AS IN STEP 4. CONTINUE TESTING ALL VALVES, UNES, AND CHOKES WITH A 250 PSI LOW AND 3000 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. 8. OPEN TOP PIPE RAMS AND CLOSE BOll'OM PIPE RAMS. TEST BOl-rOM RAMS TO 250 PSI AND 3000 PSi. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TEST TO 3000 PSI FOR 10 MINUTES. BLEED TO ZERO PSI. 10. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE MANIFOLD AND LINES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN THE DRILLING POSITION. 11. TEST STANDPIPE VALVES TO 3000 PSI. 12. TEST KELLY COCKS AND INSIDE BOP TO 3(X)0 PSI VV]TH KOOMEY PUMP. 13. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 14. PERFORM COMPLETE BOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE BOPE DAILY. 1. 16' - 2000 PSI STARTING HEAD 2. 11 · - 3000 PSI CASING HEAD 3. 11' - 3000 PSI X 13-5/8' - 5000 PSI SPACER SPOOL 4. 13-5/8' - 5000 PSI PIPE RAMS 5. 13-,5/8" - 5000 PSI DRLG SPOOL W/ CHOKE AND KILL LINES 6. 13-5/8' - 5000 PSI DOUBLE RAM W/ PIPE RAMS ON TOP, BLIND RAMS ON BTM 7. 13-5/8' - 5000 PSI ANNULAR REC£1V£D Gas Cons. Commission Anchorage ALASKA OIL AND GAS CONSERYAT[ON COMMISSION WALTER J. HICKELo GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 January 12, 1994 A. W. McBride Area Drilling Engineer ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Unit 3H-24 ARCO Alaska, Inc. Permit No: 94-08 Sur. Loc. 1095'FNL, 282~FWL, Sec. 12, T12N, R8E, UM Btmhole Loc. 1447'FSL, 1222'FWL, Sec. 3, T12N, R8E, UM Dear Mr. McBride: 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 . cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA AL, _,KA OIL AND GAS CONSERVATION COMMI~,,~,ON PERMIT TO DRILL 20 AAC 25.005 la. Type of Work Drill X Redrill El lb Type of Well Exploratory [] Stratigraphic [] Development Oil X Test Re-Entry [--1 Deepen D Service El Development Gas El single Zone X Multiple Zone 2.. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool ARCO Alaska, Inc. RKB 80', Pad 39' GL feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchorage, AK 99510-0360 ADL 25532, ALK 2658 4. Location of well at surface 7. Unit or property Name 11. Type Bond (see 20 AAC 25.025) 1095' FNL, 282' FWL, SEC. 12, T12N, R8E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 1400' FSL, 1400' FWL, Sec. 3, T12N, R8E, UM 3H-24 #U-630610 At total depth 9. Approximate spud date Amount 1447' FSL, 1222' FWL, Sec. 3, T12N, R8E, UM 1/10/94 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 3H-16 12293' MD 3833' @ TD feet 12.0' @ 200' MD feet 2560 6127' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035(e)(2)) Kickoff depth 300 feet Maximum hole angle 67.92° Maximum sudace 1769 psig At total depth (TVD) 3177 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD /include stac~e data) 24" 16" 62.5# H-40 Weld 80' 41' 41' 121' 121' +200 CF 12.25" 9.625" 47.0# L-80 BTC 2523' 41' 41' 2564' 2070' 520 Sx Arcticset III & HF-ERW 730 Sx Class G 12.25" 9.625" 36.0# J-55 BTC 2443' 2564' 2070' 5007' 2988' HF-ERW 8.5" 7" 26.0# L-80 BTCMOC 12252 41' 41' 12293' 6127' 140SxClassG HF-ERW ToD 500' above Kuparuk 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 Surface Intermediate Production , Liner ..!' .. i'~! . . Perforation depth: measured .'.' ..:,,~ ¥ii 2,, l: true vertical .... l'~ ~'. ,-'.l'~t~, ~','~r ,- 20. Attachments Filing fee X Property plat El BOP Sketch X Diverter Sketch X Drilling program X Drilling fluid program X Time vs depth plot [] Refraction analysis ]--] Seabed report El 20 AAC 25.050 requirements X 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed //~.,~/~~ Title Area Drillin~l Engineer Date [ Commission Use Onl~/ Permi_4,/~- ~ ~ 50- /D~'~ ~ C~ ~ d~ ~ / ~/~ ~ other requirements Conditions of approval Samples required ~ Yes ~ No Mud Icg required ~ s ~ No Hydrogen sulfide ~ Yes ~ No Directional su~ey required ~ Yes ~ No measures Required working pressure for ROPE ~ 2M ~ 3M ~ 5M ~ 10M ~ 15M Other: Original Signed By David W. dohnston ordor ol Approved b~ Commissioner the commission Date [/t Form 10-401 Rev. 7-24-89 S"ubmit in triplicate , , , . , . , , 10. 11 12 13 14 15 16 17 18 GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD 3H-24 Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (5007')according to directional plan. Run and cement 9-5/8" casing (cement to surface). No cement bond logs to be run in 9-5/8" casing. Install and test BOPE. Test casing to 2000 psi. Drill out cement and 10' of new hole. Perform leak off test to 12.5 ppg EMW. Drill 8-1/2" hole to total depth (12293') according to directional plan. Run open hole evaluation logs or LWD tools as needed. Run and cement 7" casing. (If significant hydrocarbon zones are present above the Kuparuk, sufficient cement will be pumped for isolation in accordance with Rule 20 AAC 25.030. Alternatively, if significant hydrocarbon zones occur within 200' TVD of the surface casing shoe, cement will be down squeezed in the annular space between the surface and production casing after the primary cement job is completed.) ND BOPE. NU tubinghead & full opening valve for cased hole logging. Secure well and release rig. Run cased hole cement evaluation. ND full opening valve & NU tree assembly. Move in and rig up Nordic #1. Install and test BOPE. Pressure test 7" casing to 3500 psi. Perforate and run completion assembly, set and test packer. ND BOPE and install production tree. Shut in and secure well. Clean location and release rig. DRILLING FLUID PROGRAM Well 3H-24 Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids Spud to 9-5/8" surface casing 9.0-10.5 15-25 15-35 50-80* 5-15 15-40 10-12 9.5-10 +10% Drill out to weight up 8.4-9.6 5-15 5-8 30-40 2-4 4-8 8-10 9.5-10 4-7% Drilling Fluid System: Tandem Brandt Shale Shakers Triple Derrick Shale Shakers Solids Processing System to minimize drilling waste Mud Cleaner, Centrifuges, Degasser Pit Level Indicator (Visual and Audio Alarm) Trip Tank Fluid Flow Sensor Fluid Agitators Notes: Weight up to TD 10.4 10-18 8-12 35-5O 2-4 4-8 4-5 thru Kuparuk 9.5-10 <12% Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 AAC 25.O33. Maximum anticipated surface pressure is calculated using a surface casing leak-off of 13.5 ppg EMW and a gas gradient of 0.11 psi/ft. This shows that formation breakdown would occur before a surface pressure of 1769 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 3H-24 is 3H-16. As designed, the minimum distance between the two wells would be 12.0' @ 200' MD. Incidental fluids developed from drilling operations will be hauled to the nearest permitted disposal well or will be pumped down the surface/production casing annulus of the last well drilled. That annulus will be left with a non-freezing fluid during any extended shut down (> 4hr) in pumping operations. The annulus will be sealed with 225 sx of cement followed by arctic pack upon completion of fluid pumping. *Spud mud should be adjusted to a FV between 50-80 sec/qt to drill gravel beds. ARC0 ALASKA, Inc. Structure : Pad SH Well : 24 Field : Kuparuk River Unit Location : North Slope, Alaska __ _ ;Creoted by : jones For: S BRADUg¥ iDote plotted : 5-don-94 iPIot Reference is 24 Version #2. iCoordinotes ore in feet reference slot #24. ',True Verticol Depths (]re reference wellhe(]d. Baker Hughes INTEQ < - - W e s t Sco,e, : 10000 9500 go00 8500 8000 7500 7000 6500 6000 5500 5000 4500 4000 3500 3(X)O2500 2000 1500 1000 500 0 5,00 I I i ! I I I f I I I I I I I I t I I I I I I I I I I t t I I I I I I I I I I I [ I T~ LOC*,'nON: J 1447' FSL, 1222' FWL SEC. 3, T12N. RSE ITARGET LOCATION: 1400' FSL. 1400' FWL SEC. 3, 712N. RSE TARGET, TVD:5908 TMD=12007 BEP=9766 NORTH 2495 WEST 9442 N 75.2 DEG W 9766' (TO TARGET) 25OO .--~ 500 ~ 0 ., g soo g o q ~ 0 i ! ESTII]ATED RKB ELEVATION: 80' c4 . ~ KOP TVD=300 TMD=300 DEP=O .soo 6.00 ,~ 12.00 "~ 18.00 BUILD 3 DEO / 100' co t 24.00 -J , 30.00 (- ~5oo.~. \ 36.00 (D 2o00, -- ._ - %- 3000_ > - 3500_ ESTIMATED SURFACE LOCATION: 1095' FNL. 282' FWL SEC. 12, T12N, RSE 42.00 B,' PERMAFROST '1%/D=1610 TMD=1744 DEP=520 48.00 ~/ UGNU SANDS TVD=1740 TMD=1951DEP=655 '% 54~%~ 0 EOC 'fVD=2070 TMD=2564 DEP=1192 W SAK SNDS ~7D=2340 7MD=3285 DEP=1858 '"'"'"'""'---..~..~B/ W SAK SNDS TVD=2920 TMD=4826 DEP=3288 K-lO TVD=3055 TMD=5185 DEP=3620 ---~'"~...~9 5/8" CSG PT %.D=2988 TMD=5007 DEP=5455 MAXIMUM ANGLE 67.92 DEG TARGET ANGLE t 40 DEG -. .6.oo TARGET - T/ ZONE C (EOD) TVD=5908 TMD=lg00? DEP=9766 ~_~__.42.00 60OO T/ ZONE A TVD=5939 7MD=12047 DEP,:,9792 "~:x--' B/ KUP SNDS TVD=5974 TMD=12093 DEP=9821 '~'"? j TD /7" CSG PT TVD=6127 TMD=I2293 DEP=g9§o 6500 I I I I I I ! I I I i I I t I I I I i ; I i i i i i I i i I I I i I I i i I i I i i 0 ,500 1000 1,500 20c¢_3 2500 5000 3500 400~ 4500 500.0 55c~) 6030 6500 700.0 7500 8000 8500 9000 9500 10000 Scole ~ - 250.00 Vedicol Section on 284.80 ozimuth with reference 0.00 N, 0.00 E from slot #24 ARCO ALASKA, Inc. Structure : Pad 5H Well : 24. ~-- West 350 300 250 Field : Kuparuk River Unit Location : North Slope, Alaska 200 150 1 O0 50 0 I I I I I I I I I I 1900 1300 P 250C 1100 1700 gOO 11 700 500 900 2100 10, 5O 250 2OO 150 100 I I 50 c 50 [ 100 o° Casing Design / Cement Calculations 6-Jan-94 Well Number: Surface Csg MD: Surface Csg TVD: Production Csg MD: Production Csg TVD: Top of West Sak, TMD: Top of Target, TMD: Top of Target, TVD: Estimated Pressure: Surface Casing Choice · Production Csg Choice · Production Casing Frac. Pressure 3H-24 5,O07 ft 2,988 ft 12,293 ft 6,127 ft 3,283 ft 12,007 ft 5,908 ft 3100 psi For Casing Choices 3,500 psi Maximum anticipated surface pressure TVD surface shoe = 2,988 ft {(13.5*0.052)-0.11}*TVDshoe =1 1,769 psiJ Estimated BH pressure at top of target zone Estimated Pressure= Top of Target, TVD = Overbalance, psi= Anticipated Mud Weight =1 3,100.0 ppg 5,908 ft 100 psi 10.4 ppgJ Surface lead: Top West Sak, TMD = Design lead bottom 500 ft above the Top of West Sak = 3,283 ft 2,783 ft Annular area = 0.3132 cf/If Lead length * Annulus area - 872 cf Excess factor - 15% Cement volume required - 1,002 cf Yield for Permafrost Cmt - 1.94 Cement volume required =1 520 sx] Surface tail: TMD shoe = 5,007 ft (surface TD - 500' above West Sak) * (Annulus area) = 697 cf Length of cmt inside csg -- 80 ft Internal csg volume - 0.4110 cf/If Cmt required in casing = 33 cf Total cmt - 729 cf Excess factor - 15% Cement volume required - 839 cf Yield for Class G cmt - 1.15 Cement volume required =L 730 sxJ Casing Design / Cement Calculations 6-Jan-94 Production tail: TMD = 12,293 ft Top of Target, TMD = 12,007 ft Want TOC 500' above top of target = 11,507 ft Annulus area (9" Hole) = 0.1745 (TD-TOC)*Annulus area = 137 cf Length of cmt wanted in csg = 80 ft Internal csg volume = 0.2148 Cmt required in casing = 17 cf Total cmt = 154 cf Excess factor = 15% Cement volume required = 177 cf Yield for Class G cmt = 1.23 Cement volume required =[ 140 sx TENSION - Minimum Desicjn Factors are: T(pb)=l.5 and T(js)=l.8 Surface (Pipe Body): Casing Rated For: Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air - Length * (Wt/ft) Buoyancy = Weight of displaced mud Length Casing Wt (lb/fi) Dead Wt in Air Buoyancy = Tension (Pipe Body) Design Factor 1086000 lb 5,007 ft 47.00 Ib/ft 235329.0 lb 36768.7 lb 19856O.3 lb Surface (Joint Strength): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy = Weight of displaced mud Casing Rated For: Length = Casing Wt (lb/fi) = Dead Wt in Air = Buoyancy = Tension (Joint Strength) = Design Factor =1 1161000 lb 5,007 fi 47.00 lb/fi 235329.0 lb 36768.7 lb 198560.3 lb Production (Pipe Body): Tension (Pipe Body) = Dead Wt in Air- Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy = Weight of displaced mud Casing Rated For: Length = Casing Wt (lb/fi) - Dead Wt in Air = Buoyancy = Tension (Pipe Body) = Design Factor =1 604000 lb 12,293 ft 26.00 lb/fi 319618.0 lb 50211.0 lb 269407.0 lb Production (Joint Strength): Tension (Pipe Body) = Dead Wt in Air - Buoyant Force Dead Wt in Air = Length * (Wt/ft) Buoyancy = Weight of displaced mud Casing Rated For: Length = Casing Wt (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Joint Strength) = Design Factor,~l~.~. ,~-. ~ ~ ,,~rv ~) 667000 lb 12,293 ft 26.00 lb/fi 319618.0 lb 50211.0 lb 269407.0 lb Casing Design/Cement Calculations BURST - Minimum Design Factor = 1.1 Surface Casing- Burst = Maximum surface pressure' Casing Rated For: Max Shut-in Pres = Design Factor =[ Production Csg: 1. Design Case - Tubing leak while well is SI Inside pres=Csg Frac pres(3500 psi)+Mud Wt*.052*TVD Outside Pres=Backup Gradient (8.9ppg *0.052*TVD) Net Pressure = Pressure inside-Pressure outside Design Factor = Rating / Net Pressure Casing Rated For: Inside pressure Outside Pressure Net Pressure Design Factor COLLAPSE - Minimum Design Factor = 1.0 Surface Casing 1. Design Case - Lost circulation and Fluid level drops to 2000' TVD with 9.0 # Mud 2. Ext. Pres=Mud Wt*0.052*TVD-(2000'TVD of 9# Mud) Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Design Factor =[ Production Csg 1. Worst Case - Full evacuation of casing 2, Mud weight on outside = Mud Wt * 0.052 * TVD Casing Rated For: Mud Gradient = Ext. Pres. @ Bottom = Design Factor =[ 6-Jan-94 6870 psi 1768.9 psi 3.91 7240 psi 6819 psi 2836 psi 3983 psi 1.8J 4750 psi 0.542 Ib/ft 682 psi 7.01 5410 psi 0.542 Ib/ft 3319 psi 1 .si Casing Design / Cement Calculations 6-Jan-94 Surface Casing Choices OD ID I b/ft Grade Metal X-Section Jt Strength Body Strength Collapse 1 9.625 8.681 47 L-80 13.5724 sq. in. 1161000 lb 1086000 lb 4750 psi 2 9.625 8.835 40 L-80 11.4538 sq. in. 979000 lb 916000 lb 3090 psi 3 9.625 8.921 36 J-55 10.2545 sq. in. 639000 lb 564000 lb 2020 psi 4 10.750 9.950 45.5 J-55 13.0062 sq. in. 931000 lb 715000 lb 2090 psi Burst 6870 psi 5750 psi 3520 psi 3580 psi Production Casing Choices OD ID I b/ft Grade Metal X-Section Jt Strength Body Strength Collapse 1 7.000 6.276 26 L-80 7.5491 sq. in. 667000 lb 604000 lb 5410 psi 2 7.000 6.276 26 J-55 7.5491 sq. in. 490000 lb 415000 lb 4320 psi Burst 7240 psi 4980 psi .: -.. 20" DIYERTER SCHEMATIC 5 6 4 , 3 DO NOT SHUT IN DIVERTER AND VALVES AT SAME TIME UNDER ANY CIRCUMSTANCES. MAINTENANCE & OPERATION 1. UPON INITIAL INSTALLATION, CLOSE PREVENTER AND VERIFY THAT VALVE OPENS PROPERLY. 2. CLOSE ANNULAR PREVENTER IN THE EVENT THAT AN INFLUX OF WELLBORE FLUIDS OR GAS IS DETECTED. OPEN APPROPRIATE VALVE TO ACHIEVE DOWNWIND DIVERSION. ARCO ALASKA, INC., REQUESTS APPROVAL OF THIS DIVERTER SYSTEM AS A VARIANCE FROM 20AAC25.035(b) 1. 16" CONDUCTOR 2. SLIP-ON WELD STARTING HEAD 3. DIVERTER ASSEMBLY WITH ONE 2-1/16"-2000 PSI BALL VALVE 4. 20"- 2000 PSI DRILLING SPOOL WITH TWO 10" OUTLETS. 5. 10" HCR BALL VALVES WITH 10" DIVERTER LINES, A SINGLE VALVE OPENS AUTOMATICALLY UPON CLOSURE OF ANNULAR PREVENTER. VALVES CAN BE REMOTELY CONTROLLED TO ACHIEVE DOWNWIND DIVERSION EDF 3/10/92 13 5/8" 5000BOP STACK 7 1 6 5 4 I3 F ACCUMULATOR CAPACITY TEST 1. CHECK AND FILL ACCUMULATOR RESERVOIR TO PROPER LEVEL WITH HYDRAULIC FLUID. 2_ ASSURE THAT ACCUMULATOR PRESSURE IS 3000 PSI WITH 1500 PSI DOWNSTREAM OF THE REGULATOR. ~ OBSERVE TIME, THEN CLOSE ALL UNITS SIMULTANEOUSLY AND RECORD THE TIME AND PRESSURE REMAINING AFTER ALL UNITS ARE CLOSED WITH CHARGING PUMP OFF. 4. RECORD ON THE IADC REPORT. THE ACCEPTABLE LOWER LIMIT IS 45 SECONDS CLOSING TIME AND 1200 PSI REMAINING PRESSURE. BOP STACK TEST 1. FILL BOP STACK AND MANIFOLD WITH WATER. 2_ CHECK THAT ALL HOLD-DOWN SCREWS ARE FULLY RETRACTED. PREDETERMINE DEPTH THAT TEST PLUG W1LL SEAT AND SEAT IN WELLHEAD. RUN IN LOCK-DOWN SCREWS IN HEAD. 3. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TEST ALL COMPONENTS TO 250 PSI AND HOLD FOR 10 MINUTES. INCREASE PRESSURE TO 3000 PSI AND HOLD FOR 10 MINUTES. BLEED TO ZERO PSI. 5. OPEN ANNULAR PREVENTOR AND MANUAL KILL AND CHOKE LINE VALVES. 6. CLOSE TOP PIPE RAMS AND HCR VALVES ON KILL AND CHOKE LINES. 7. TEST TO 250 PSI AND 3000 PSI AS IN STEP 4. CONTINUE TESTING ALL VALVES, LINES, AND CHOKES WITH A 250 PSI LOW AND 3000 PSI HIGH. TEST AS IN STEP 4. DO NOT PRESSURE TEST ANY CHOKE THAT IS NOT A FULL CLOSING POSITIVE SEAL CHOKE. 8. OPEN TOP PIPE RAMS AND CLOSE BOq-rOM PiPE RAMS. TEST BOq-rOM RAMS TO 250 PSI AND 3000 PSI. 9. OPEN PIPE RAMS. BACKOFF RUNNING JT AND PULL OUT OF HOLE. CLOSE BLIND RAMS AND TEST TO 3000 PSI FOR 10 MINUTES. BLEED TO ZERO PSI. 10. OPEN BLIND RAMS AND RECOVER TEST PLUG. MAKE SURE MANIFOLD AND LINES ARE FULL OF ARCTIC DIESEL AND ALL VALVES ARE SET IN THE DRILLING POSITION. 11. TEST STANDPIPE VALVES TO 3000 PSI. 12. TEST KELLY COCKS AND INSIDE BOP TO 3000 PSI WITH KOOMEY PUMP. 13. RECORD TEST INFORMATION ON BLOWOUT PREVENTER TEST FORM. SIGN AND SEND TO DRILLING SUPERVISOR. 14. PERFORM COMPLETE BOPE TEST ONCE A WEEK AND FUNCTIONALLY OPERATE BOPE DAILY. 1. 16' - 2000 PSI STARTING HEAD 2_ 11' - 3000 PSI CASING HEAD 3. 11' - 3000 PSI X 13-5/8' - 5000 PSI SPACER SPOOL 4. 13-5/8' - 5000 PSI PIPE RAMS 5. 13-5/8' - 5000 PSI DRLG SPOOL W/ CHOKE AND KILL LINES 6. 13-5/8' - 5000 PSI DOUBLE RAM W/ PIPE RAMS ON TOP, BLIND RAMS ON BTM 7. 13-5/8' - 5000 PSI ANNULAR WELL PERMIT CHECKLIST ' ELD POOL '4 01 (I 0 AD'MINTSTR~TION ......... DATE 1. Permit fee attached ................... Y ~ 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 .............. ~.~ N 10. Operator has appropriate bond in force ......... ~ N 11. Permit can be issued without conservation order ..... ~ N 12. Permit can be issued without administrative approval.. ~ N 13. Can permit be approved before 15-day wait ........ ~ N ENGINEERING WELL NAME GEOL AREA 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 surf csg to next string...~~ 18. CMT will cover all known productive horizons ...... ~~ 19. Casing designs adequate for C, T, B & permafrost .... 20. Adequate tankage or reserve pit ............. 21. If a re-drill, has a 10-403 for abndnmnt been approved..Y N ~ 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 ..................... ~ N 26. BOPE press rating adequate; test to ~>C~ psig.~ N 27. Choke manifold complies w/API RP-53 (May 84) ....... Y N ~ 28. Work will occur without operation shutdown ....... ~ N 29. Is presence of H2S gas probable ............. Y ~ GEOLOGY APPR DATE 33. 34. Permi~be issued w/o hydrogen sulfide measures .... Y N Data pres~otential o~ ..... Y N Seismic analysis o~s zones. ......... Y N Seabed conditi~9~ey (i~ore). ........ Y N Conta_gs~e/phoneo~rog/~reports ..... Y N ~ [exploratory o UNIT# REMARKS PROGRAM: exp [] dev ~ redrll [] serv ~ ,//l GEOLOGY: ENGINEERING: COMMISSION: Comments/Instructions: HOW/jo - A:%FORMS%cheklist rev 01/94 ** CHECK LIST FOR NEW WELL PERMITS ITEM APPROVE D~TE, (1) Fee (2) Loc ..- E2 ~h~u (3) Admi (4) Casg (5) BOPE '[9 thru '13] [ 10 & 13] [14 thru 22] '" [23 thru le 5. 6. 7. 8. e 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22 23 24 25 26 27 28. Company YES Is permit fee attached .............................................. Is well to be located in a defined pool .............................. ~ ...... Is well located proper distance from property line ........... '?'~ Is well located proper distance from other wells ..................... Is sufficient undedicated acreage available in this pool .............. ~ .. Is well to be deviated & is wellbore plat included ................... Is operator the only affected party .................................. Can permit be approved before 15-day wait ............................ ~. Does operator have a bond in force ................................... Is a conservation order needed eeeaeeeeeeeeeeeeeeteeeeeeeeeeeee.el*ee~ .... , Is administrative approval needed .................................... Is lease nL~nber appropriate eleeeeeeeeeeeleeeleeel.eeeeeeeeeeeeeeeeeee Does well have a unique name & ntmber ................................. Is conductor string provided ......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. Is enough cement used to circulate on conductor & surface ............ ~ ' Will cement tie in surface & intermediate or production strings ...... Will cement cover all known productive horizons ..................... -~ .. Will all casing give adequate safety in collapse, tension, and burst. Is well to be kicked off from an existing wellbore ................... ---~ Is old wellbore abandonment procedure included on 10-403 ............. Is adequate wellbore separation proposed ............................. Is a diverter system required ........................................ Is drilling fluid program schematic & list of equipment adequate ..... Are necessary diagrams & descriptions of diverter & BO_PE attached .... Does BOPE have sufficient pressure rating -- test to ~ psig ..... Does choke manifold comply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... Lease & Well NO RI~'MARKS (6) Other [29 thru 31] (7) Contact [32] "' (8) Add1 29. 30. 31. 32. 33. geology' encjineerinq' rev 6~93 jo/6.011 FOR EXPLORATORY $ STP~kTIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Name and phone nL~nber of contact to supply weekly progress data ...... Additional requirements ............................................. Additional remarks' INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~. SHORE UM /X MERIDIAN: SM WELL TYPE' Redri 11 Inj Rev