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Home My WebLink About194-021Memorandum State of Alaska Oil and Gas Conservation Commission To: Well File: %L~ - ~'~o.1 DATE 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 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 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 remain unchanged. The AP! 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 (weilbore segment) Ddiling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. e McMains ' ~ Statistical Technician . ~95 11' !?AM .LRC~.ALASKA I~¢C ARCO Alaska, 1'~ Post Office Box 100360 Anchorage. Alaska 9951 Telephone 907 276 1215 3533 ?. 2/2 Steve McM~ Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, 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 Kuparuk River Unit. The wells were permi~ for different expansion and infill projects during 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 drilled the information will be significantly different than i~ 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 nke to canceA the Permiu to Drm for the following wells: { 3 <rtu 2 -04 Iq5 KRU 2E-!S KRU 2A-18 (Permit ~93-I66, issue date 1I/9/93) KRU ZA-22 (Permit #93-163, issue date 10/27/93) KRU 3M-27 KRU 3H-24 KRU 3H-29 ' KRU 3H-30 q - ooo ¥ 2A-18 and 2A-22 inadvertently have two Permits to Drill, each; please cancel only the permit noted above. Thank you for calling our affention to this matter. If you have any questions on the above wells please call me, Sincerely, ' erdse eh"ash S EP 2 S 1995 Dril 'Iing Engineer CC J, Hartz M. Zanghi S. Allsup-Drake (W1) Well File Alaska Oil & Gas Cons. Commission AOGCC (Anchorage) Anchorage ATO-1286 ATO-t205 ATO-1205/ATO-370 (one copy f/each well listed above) AR38-6003-93 2~2-2503 ALASKA OIL AND GAS CONSERVATION CO~MISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 February 10, 1994 A W McBride, Area Drlg Engr ARCO Alaska Inc P O Box 100360 Anchorage, AK 99510-0360 Re: Well # Company Permit # Surf Loc Btmhole Loc Kuparuk River Unit 3H-30 ARCO Alaska Inc 94-21 995'FNL, 282'FWL, Sec 12, T12N, R8E, UM 940'FSL, 2090'FEL, Sec 34, T13N, RSE, 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 Nodh Slope pager at 659-3607. BY ORDER OF THE COMMISSION jo/encl c: Dept of Fish & Game, Habitat Section - w/o encl Dept of Environmental Conservation - w/o encl STATE OF ~ ALASKA Oil_ AND GAS CONSERVATION COMMI~oION PERMIT TO DRILL 20 AAC 25.005 la. Type o! Work Drill X Redrill [--] lb Type of Well Exploratory E] Stratigraphic [] Development Oil X Test Re-Entry D Deepen D Service D Development Gas [~ 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, Anchorac, le, AK 99510-0360 ADL 25524, ALK 2655 4. Location of well at sudace 7. Unit or property Name 11. Type Bond (see 20 AAC 25.025) 995' FNL, 282' FWL, SEC. 12, T12N, R8E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 764' FSL, 2006' FEL, Sec. 34, T13N, R8E, UM 3H-30 #U-630610 At total depth 9. Approximate spud date Amount 940' FSL, 2090' FEL, Sec. 34, T13N, RSE, UM 2/1 4/94 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and 1-VD) property line 3H-20 10549' MD 940' @ TD feet 11.9' @ 260' MD feet 1 920 6194' 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 60.99° Maximum surface 1871 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 IV~ TVD IVE) 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 2292' 41' 41' 2333' 1970' 580 Sx Arcticset III & HF-ERW 550 Sx Class G 12.25" 9.625" 36.0# J-55 BTC 2454' 2333' 1970' 4787' 3160' HF-ERVV 8.5" 7" 26.0# L-80 BTCMOE 10508 41' 41' 10549' 6194' 150 SxClass G HF-ERW Top 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 _Me. asur~[[ depth True Vertical depth Structural Conductor REC£1 Surface Intermediate Production LinerrE{3 - 8 1994 'Perforation depth: measured true vertical ~oSK~ uu & Gas Cons. Commission Anchorage 20. Attachments Filing fee X Property plat [-] BOP Sketch X Diverter Sketch X Drilling program X Drilling fluid program X Time vs depth plot [] Refraction analysis D Seabed repeal E] 20 AAC 25.050 requirements X 21. I hereby certily that the foregoing is true and correct to the best of my knowledge Signed ,/,/~,/~/F~~_L_~ ~' -~'~?~'~ Title Area Drillincj En,ilqeer Date ~. ' Commission Use Only q -'~...[ 50- /O'~' '~.O'"~:~ ~ ~('~..' ~ ~/~' other requirements Conditions of approval Samples required [] Yes ~ No Mud log required [] Yes [~ No Hydrogen sulfide D Yes [~q No Directional survey required ~ Yes [-1 No measures Required working pressure for BOPE [] 2M [] 3M ~] 5M D 10M [] 15M Other: Original Signed By by order of Approved by David W .lr~hno+,-,,., Commissioner the commission Date Z~/~/C:/r'~"? Form 10-401 Rev. 7-24-89 Subm triplicate , , , . . o . o . 10 11 12 13 14 15 16 17 18 GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD 3H -30 Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (4,787')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 (10,549') 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. FEB - 8 1994 Oil & Gas Cons. Comrnis¢o~ Anchorage ARCO ALASKA, Structure : Pad 3H Well : $0 Field : Kuparuk River UnH Location : North Slope, Alaska iCreated by : jones For: S BP.~L1)LEY ?ate plotted : 7-Feb-94 iPIot Reference is 30 Version #3. !iCoordinetes ore in feet reference slot #50. iTrue Verticel Depths ore reference wellhead,i Baker Hughes INTEQ N 25.38 DEG W ?~g~' (to T~C~t) 4O0 0 400 800 12O0 - 1 r-:~)O_ _ 2000_ _ 24~_ - 28~ _ - 32~_ _ 3~_ - 44~_ _ 4~_ _ 52~_ - - - JTD LOCATION: J 940' FSL, 2090' FEL SEC. 34, T13N, RSE <--Wesf 5600 5200 2800 2400 2000 1600 1200 800 I I I I I I I I I I I 1 I I I I JTARGET LOCATION: 784' FSL, 2006' FEL SEC. 34, T1,3N, RSE TARGET TVD=Sg62 TMD=10246 DEP=7791 NORTH 7039 WEST 3340 400 I I Scale 1 : 200.O0 0 400 I I I 7600 7200 .6800 .6400 6000 - _5600 _ _5200 _ _4800 . .4400 _ _4000 _ _5600 /X I I KOP TVD=300 TMD=300 DEP=O .-~ 6.00 - ---I-- 12.00 _28oo ~- 1 8.00 BUILD 3 DE(; / ~00' - 24,00 _2400 30.00 - 36.00 _2ooo 42.00 B/ PERMAFROST TVD=1645 TMD=1792 0EP=554- - 48,00 ~600 x~854.00 T/ UONU SNDS TVD=t920 TMD=2234 DEP=898 - ~.oo Eoc ~o=~97o TM0=23~ °EP=9*~ [,200 ~T/ W SAN SNDS TVD=2600 TMD=3632 DEP=2120 _80O W SAK SNDS 1¥D=3030 TMD=4519 DEP=2895 _ 4o0~- 9 ESTIIvlATED ~ K~85 TMD--5044 DEP=3555 v --..~ SURFACE LOCATION' - -- ' _ 0 ~ 995' FNL. 282' FWL ~ ....... '-'" .... _ 400 O MAXIMUM ANGLE ~ .. ..... RECEIVED K-5 TVD:4705 TMD:7973 DEP:5916~.~ FE~ - 8 1994 BEGIN ANGLE DROP TV0=5298 TMD=9196 OEP:6~--....~Alaskall 0~t & Ga~ ~8 oo ",-,O/Ts" o,o~ ~ ~o / ,o '54.o~AoonChora 'u°mm188IO_rl 46.00 TARGET - T/ ZONE C (EOD) TVI)=596~ TMD=10846 DEP=??91 ~2.00 TARGET ANGLE T/ ZONe- A W~=Sg~ TM~=~0263 OEP=~02'~ B/ KUP SNOS TVD=6041 TMD=10349 DEP=7858 kx,,,"= 40 DEC- .m / ?" cs~ m' ~-v~=~9~ ~'~=~os~ ~--?~ - I I I I I I I I I 16100 I I I I I I I I I I J 40100 I I I I I t f00/ I I I I I 68100 I I I I I I I I 400 0 40(3 800 1200 2000 2400 2800 3200 3600 4400 4800 5200 56 6000 6400 7200 7600 8000 8400 Scale 1 : 200.00 Vertical Section on .334.62 azimuth with reference 0.00 N, 0.00 E from slot 350 300 I I I 250 200 150 100 50 0 50 · 50.00 lO0 1500~ 1700 1500 1500 1900 300 ARCO ALASKA, Inc. Str'u~-,tum : Pad 3H Well : 30 1700 1500 1300 1300 1100 1500 1100 270( 9OO 1100 25( 1700 900 10017Cl 3 900 700 / ¢ 550 _500 _450 _400 _350 _~oo _250 - _200 O0 _150 _100 50 -- ~ 0 _ _50 DRILLING FLUID PROGRAM Well 3H-30 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 5O-8O* 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 10.8 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 1871 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 3H-30 is 3H-20. As designed, the minimum distance between the two wells would be 11.9' @ 260' 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. Casing Design / Cement Calculations 8-Feb-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-30 4,787 ft 3,160 ft 10,549 ft 6,194 ft 3,632 ft 10,246 ft 5,962 ft 3200 psi ** See Page 4 ~ For Casing Choices 3,500 psi Maximum anticipated surface pressure TVD surface shoe = 3,160 ft {(13.5*0.052)-0.11}*TVDshoe =1 1,871 psiJ Estimated BH pressure at top of target zone Estimated Pressure= Top of Target, TVD = Overbalance, psi= Anticipated Mud Weight =[ 3,200.0 ppg 5,962 ft 150 psi 10.8 ppgJ Surface lead: Surface tail: Top West Sak, TMD = 3,632 ft Design lead bottom 500 ft above the Top of West Sak = 3,132 ft Annular area = 0.3132 cf/If Lead length * Annulus area = 981 cf Excess factor = 15% Cement volume required = 1,128 cf Yield for Permafrost Cmt = 1.94 Cement volume required =1 580 sxJ TMD shoe = 4,787 ft (surface TD - 500' above West Sak) * (Annulus area) = 518 cf Length of cmt inside csg = 80 ft Internal csg volume = 0.4110 cf/If Cmt required in casing = 33 cf Total cmt = 551 cf Excess factor = 15% Cement volume required = 634 cf Yield for Class G cmt = 1.15 Cement volume required =1 550 sxJ Casing Design / Cement Calculations 8-Feb-94 Production tail: TM D = 10,549 ft Top of Target, TM D = 10,246 ft Want TOC 500' above top of target -- 9,746 ft Annulus area (9" Hole) = 0.1745 (TD-TOC)*Annulus area -- 140 cf Length of cmt wanted in csg -- 80 ft Internal csg volume - 0.2148 Cmt required in casing = 17 cf Total cmt - 157 cf Excess factor = 15% Cement volume required = 181 cf Yield for Class G cmt - 1.23 Cement volume required =J 150 sxJ TENSION - Minimum Desiqn 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 (Ib/ft) Dead Wt in Air Buoyancy Tension (Pipe Body) Design Factor 1086oo0 lb 4,787 ft 47.OO Ib/ft 224989.0 lb 36467.6 lb 188521.4 lb 5.8J 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 =l 1161000 lb 4,787 ft 47.00 Ib/ft 224989.0 lb 36467.6 lb 188521.4 lb 6.:2! 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 (Ib/ft) = Dead Wt in Air = Buoyancy = Tension (Pipe Body) = Design Factor =1 604000 lb 10,549 ft 26.OO Ib/ft 274274.0 lb 44698.8 lb 229575.2 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 Strengt_.h),.= 667000 lb 10,549 ft 26.00 Ib/ft 274274.0 lb 44698.8 lb 229575.2 lb 2.91 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 =1 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 =1 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 =1 8-Feb-94 6870 psi 1870.7 psi 3.7j 7240 psi 6980 psi 2867 psi 4114 psi 1.81 4750 psi 0.562 Ib/ft 840 psi 5.71 5410 psi 0.562 Ib/ft 3480 psi 1.61 Casing Design/Cement Calculations 8-Feb-94 Surface Casing Choices OD ID Ib/ft Grade Metal X-Section Jt Strength Body Strength Collapse Burst I 9.625 8.681 47 L-80 13.5724 sq. in. 1161000 lb 1086000 lb 4750 psi 6870 psi 2 9.625 8.835 40 L-80 11.4538 sq. in. 979000 lb 916000 lb 3090 psi 5750 psi 3 9.625 8.921 36 J-55 10.2545 sq. in. 639000 lb 564000 lb 2020 psi 3520 psi 4 10.750 9.950 45.5 J-55 13.0062 sq. in. 931000 lb 715000 lb 2090 psi 3580 psi Production Casing Choices OD ID Ib/ft Grade Metal X-Section Jt Strength Body Strength Collapse I 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 ' UPARUK RIVER UNI .... 20" DIVERTER SCHEMATIC 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) RECEIVED FEB - 8 1994 ~.~ska O~l & Gas Cons. Corrlmission Anchorage 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 VALVESWITH 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 EDF 3/10/92 I I [__ I , 13 5/8" 5000 BOP STACK ACCUMULATOR GAPAGITY 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. ~)P STAGK 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 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 BOTTOM PIPE RAMS. TEST BOTTOM 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. 1;3-5/8" - 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 , , , ADMINISTRATION APPR DATE 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 ......... Y 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 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 .... 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 ............. Y~ N 21. If a re-drill, has a 10-403 for abndnmnt been approved..Y N ~ 22. Adequate wellbore separation proposed .......... ~ N 23. If diverter required, is it adequate .......... ~ N 24. Drilling fluid program schematic & equip list adequate .~ N 25. BOPEs adequate ............ ~ ........ ~_~ N 26. BOPE press rating adequate; test to 5~M~ 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 30. Permit can be issued w/o hydrogen sulfide measures .... Y N 31. Data presented on potential overpressure zones ..... Y N/w/ 32. Seismic analysis of shallow gas zones .......... yN 33. Seabed condition survey (if off-shore) ........ ///Y N 34. Contact name/phone for weekly progress reports . . ./~ . Y N [exploratory only] GEOLOGY: ENGINEERING ~ .... COMMISSION: HOW/jo - A:\FORMS%cheklist rev 01/94 WELL NAME GEOL AREA gU - exp [] dev~]'-redrll [] serv [] Co~m~nts/Instructions: Z