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Home My WebLink About194-031. XHVZE 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. /~/"/° 03 / 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: _~Dianna Vincent Nathan Lowell Date: F"~-" ~./si ~ TO RE-SCAN Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: ~si C:LOi~I:~ILM-DOC Memorandum State of Alaska Oil and Gas Conservation Commknaion 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 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 with, 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 numbenng methods descnbed 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. e MCMa~ns ' [ Statistical Technician Sep. 26. 1995 ii i?AM A.,CC~ALASKA Post Office Box 100360 Anchorage. Alaska 99510-Q360 Telephone 907 276 1215 ~~~ ~, 1~5 No. 3533 Steve McMains Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subject: Cancellation of Approved Permi~ to Drill for UndrillecI Wells Dear Ma'. McM~s: 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 pem~tted for different expansion and inffll 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 chilled the information will be significantly differ~t 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 m cance~ the Permits to Drill for the following wells: q3- I ~ 8 x~u 2~-04 q3-- 1"/5 KRU2E-t8 KRU ZA-18 (Permit ~3-166, issue date 1I/9/93) KRU ZA-22 (Permit ~3-163, issue date I0/27/93) KRU 3M-27 ICRU 3H-24 KRU 3H-29 ' KRU 3H-30 qq,-I,-ooiZ H - ooo ~ clH-Oo31 ~q-O021 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. CCi. I, Hartz M, Zangki $. Allsup-Drake OW1) Well File At~s~ 0il & Gas Cons. Commission AOGCC (Anchorage) Anchorage ATO-1286 ATO-1205 ATO-1205/ATO-370 (one copy f/each well listed abeve) AR38-6003-93 242-2503 cONSERVATION COMMISSION March 1, 1994. A. W. McBride Are~ Drillin~i Engineer ARCO Alaska, .Inc. P O Box 100360 Anqhorage, AK 99510-0360 . Re:.' Kuparuk-River Unit 3H~9 ARCO Alaska, Inc. Permit'No: 94-31 ;' % 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 cc.' .,. . Ha~bita~.~;Section w/o encl. DePartment of Fish & ~'~e, Department of Environmental .C~nser.9. ation w/o 'encl. · .: .! ~ .. WALTER J. HICKEL, GOVERNOR Sur' L6c. lll9'FNL, 2~i'FWL, Sec.~'.12, T12N, 'R8E, UM Btmhole Loc. 885'FNL,~.1372'FWL, S~'c. 3, T12N', R8E, UM · Dear Mr. ~cBr~de: ?-. . . .: _, Enclosed is t.he approved app~ication for!i!permit to .drill the above referenced we~l. '. The permi~ to' drill does not/~exempt:you ~rom obtaining additional permits requ~.red by law fro~?~.other, goverh~ental agehcies, and does not authorize-.conducting drilling oper~ionS:iuntil all 'other required permittin~ d~terminations ar~' made.-. ':' .. · .-. Blowout prevention equipmen~'~(BOPE) must:.be tested..in accordance with 20 'AAC 25'%03~'. Sufficient n~tice (~ppro~imately 24 hours) of the BOPE test perfdrm~d before drilling below the.~.surface casing shoe must be given so that a representatiwe of the Co..mmission may witness the test. Notice may be given by con~ting the cofi~uission petroleum field · · .. STATE OF ALASKA ALA~I~,A OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of Work Drill ' X Redrill ~] -lb Type of Well Exploratory r-I Stratigraphic Test I"] Development Oil X Re-Entry D Deepen !-I Service I~1 Development Gas [-] Single Zone X Multiple Zone [] 2.. Name of Operator 5. Datum Elevation (DF or KB) 1 0. Field and P°°l 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 1 1. Type Bond (see 2O AAC 25.025) 1119' FNL, 281' FWL, SEC. 12, T12N, R8E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET) 8. Well number Number 1000' FNL, 1570' FWL, Sec. 3, T12N, R8E, UM 3H-29 #U-630610 At total depth 9. Approximate spud date Amount 885' FNL, 1372' FWL, Sec. 3, T12N, R8E, UM 2/28/94 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 3H-16 13294' MD ,885' ~ TD feet 11.7' ~ 380' MD feet 2560 6115' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035(e)(2)) Kickoff depth 500 feet Maximum hole angle 70.02° Uaxirnurnsurface 1 782 psig At total depth (TVD) 3050 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casin~ Weight Grade Couplin~l Length MD TVD MD TVD linclude stacje dataI 24" 16" 62.5# H-40 Weld 80' 41' 41' 121' 121' _+200 CF 12.25" 9.625" 40.0# L-80 BTC 4886' 41' 41' 4927' 3010' 450 Sx Arcticset III & 820 Sx Class G 8.5" 7" 26.0# L-80 BTCMOC 13253'! 41' 41' 13294' 6115' 150Sx ClassG Top 500' above Kuparuk 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented StructuralR E C E t l cDthTrue Vertical depth Conductor Surface Intermediate F:EB ~_ 2 19 Production Liner 1~,[~$[(.~ U~l & Gas Cons. Commission Perforation depffl: measured Anchorage true vertical 20. Attachments Filing fee X Property plat [] BOPSketch X Diverter Sketch X Drilling program X Drilling fluid program X Time vs depth plot [] Refraction analysis [] Seabed report [] 20 AAC 25.050 requirements X 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed II~1%~ ~~-~- 'r~ Title Area Drilling Engineer Date ~7//¢~/~~ Commission Use Only Permit Number ~ ~" -,~'// IAPl number 5 O-/"~ ,.~'----' ,2.,(~:~ .2_ (:~ ~' I Appr°va' da~..~ _/._..._~:,/~- J See cover letter fOrother requirements Conditions of approval Samples required D Yes ~[~ No Mud log required D Yes '~ No Hydrogen sulfide measures r~ Yes '~ No Directional survey required ~ Yes E] No Required working pressure for BOPE r-~ 2M ~:~ 3M [] 5M D 1OM D 15M Other: Original Signed By David by order of .A~oroved by W. Johnston Commissioner the commission Date Form 10-401 Rev. 7-24-89 '~ 'nit in triolicate DRILLING FLUID PROGRAM Well 3H-29 Spud to 9-5/8" surface casing Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids 9.0-10.0 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% Drillino 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 35-50 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 25.033. 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 1782 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 3H-29 is 3H-16. As designed, the minimum distance between the two wells would be 11.7' @ 380' MD. The wells would diverge from that point. Incidental fluids developed from ddlling operations will be hauled to the nearest permitted · disposal well or will be pumped down the sudace/production casing annulus of the last well ddlled. 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. . . , . , , . . 10. 11. 12. 13. 14. 15. 16. 17. 18. GENERAL DRILUNG PROCEDURE KUPARUK RIVER FIELD ~ 3H-29 Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (4927')according to directional plan. Run and cement 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 (13294') 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.) Pressure test to 3500 psi. 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. 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. ARCO ALASKA, Inc.: Structure : Pad 3H Well ; 29 Field : Kuparuk River Unit Location : North Slope, Alaska Created by : jones For: lvi ELLIS iDote plotted : 1 6-Feb-94 Plot Reference is 29 Version #4. Coordinates ore in feet reference slot #29. 'True Vertical Depths ore reference wellhead. Baker Hughes INTEQ TD LOCATION: 885' FNL, 1372' FWL SEC. 3, T12N, ESE 600 _ ~ - ~ 0 _ .. '5 ~oo _ 1200 _ _ 2400_ ,_ >. _ g ~" 4200 I v < - - W e s t co,e ,: oo.oo 10200 9600 gO00 8400 7800 7200 6600 6000 5400 4800 4200 5600 3000 2400 1800 1200 600 0 600 I t f 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 I I I I I N 59.79 DEG W t07zg' (T0 T^RCET) RKB ELEVATION: 8,0' 9.00 BUILD 3 DEG / 100' 21.00 35.00 B/ PER~ROST WD=1615 TMD=t69~ DEP=359 500 T/ UGNU SNDS WD=1780 TMD=1905 DEP=492 ' 57.00 9.00 EOC ~=2295 TMD=28~4 DEP= 125~ ~ T/ W SAK GNDG ~=2~20 ~D=290~ DEP=1526 ~ B/ W SAK SND5 ~vD=2935 TMD=4705 DEP=3018 = : "_¢: - .v~,=_¢~!O T 0= _27 = K--lO ~=5110 TMD 5220 DEP=3500~5/8 ccc' p~ ~ % ~ 4a DEP 5224 TARGET LOCATION: I 1000' FNL. 1570' SEC. 3, T12N. RBE TARGET TVD=Sg22 TMD: 12995 0EP=10729 NORTH .5399 ISURFACE LOCATION: I 1119' FNL, 281' FWL SEC. 12, T12N, R8E TARGET ANGLE 50 DEG MAXIMUM ANGLE 70.02 DEC K--5 TVD= 4 570 TMD~ TARG - - - DE - -. - T/ 20HE A TVD=6959 TMD=]~052 DFP=~07?5 ~ 8/ kUP SNDS TVD=5986 TMD=13094 DEP=10805 TI) / 7" CSG PT TVD:CII5 TMD:13294 DEP=10958 i I : I I I t i r i I ~ ! I i i ~ } : i I I I I i I I I I I } I I I 60O 0 600 1200 1800 2400 ~v~OO } ~.4:,0 4200 4800 540.3 6000 6600 72OO 780O 84O0 9000 96O0 102001080011400 Scole 1- ..500.00 Vertical Section on 300.21 azimuth wilh reference 0.00 N, 0.00 E from slot #29 600 ~ 220 200 180 160 140 120 I I I I I I I I I I I 200 1700 <-- West Scale 1' 1 O0 80 60 4-0 20 0 20 500 1000 O0 ARCO ALASKA, 1600 1000 ~ ~°° ~oo ~'- 1500" ~ ',,.~4o~ ~oo ~oo Sfrucfure : Pad 5H field : Kuparuk River Unit Well- 29 Location : North Slope, Alaska · % '% 20.00 40 ,,,160 140 120 100 _80 /~ ,, 6O 40 ~ 2O _d -- 0 0 _40 o Casing Design/Cement Calculations 22-Feb-94 Well Number: 3H-29 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 Fmc. Pressure 4,927 ft 3,010 ft 13,294 ft 6,115 ft 2,907 ft 12,995 ft 5,922 ft 3050 psi 3,500 psi Maximum anticipated surface pressure TVD surface shoe {(13.5'0.052)-0.11}*TVDshoe 3,010 ft 1,782 psiJ Estimated BH pressure at top of target zone Estimated Pressure= Top of Target, TVD = Overbalance, psi= Anticipated Mud Weight = 3,050 psi 5,922 ft 150 psi 10.4 ppg J '~'~J'~'~"~'"'J'~'~i"i ............................................................................................................................ 'F'0p' w'es~ S~ak, TMD = 2,907 ft Design lead bottom 500 ft above the Top of West Sak = 2,407 ft Annular area = 0.3132 cf/If Lead length * Annulus area = 754 cf Excess factor = 15% Cement volume required = 867 cf Yield for Permafrost Cmt = 1.94 Cement volume required =1 450 sxJ Surface tail: TMD shoe = 4,927 ft (surface TD - 500' above West Sak) * (Annulus area) = 789 cf Length of cmt inside csg = 80 ft Internal csg volume = 0.4257 cf/If Cmt required in casing = 34 cf Total cmt = 823 cf Excess factor = 15% Cement volume required = 947 cf Yield for Class G cmt = 1.15 Cement volume required =1 820 sxJ Casing Design / Cement Calculations Production tail: 22-Feb-94 TM D = 13,294 ft Top of Target, TMD'= 12,995 ft Want TOC 500' above top of target = 12,495 ft Annulus area (9" Hole) = 0.1745 (TD-TOC)*Annulus area = 139 cf Length of cmt wanted in csg = 80 It Internal csg volume = 0.2148 Cmt required in casing = 17 cf Total cmt = 157 cf Excess factor = 15% Cement volume required = 180 cf Yield for Class G cmt = 1.23 Cement volume required =1 150 sxJ TEN~;ION - Minimljm Desi_an Factors are' T(_ob)=1.5 and T{_is)=1.8 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 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 =[ 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 =[ 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 916000 lb 4,927 ft 40.00 Ib/ft 197080.0 lb 30461.3 lb 166618.7 lb 5.51 979000 lb 4,927 ft 40.00 Ib/ft 197080.0 lb 30461.3 lb 166618.7 lb 604000 lb 13,294 ft 26.00 Ib/ft 345644.0 lb 54171.2 lb 291472.8 lb 667000 lb 13,294 ft 26.00 Ib/ft 345644.0 lb 54171.2 lb 291472.8 lb 2.3J Casing Design / Cement Calculations BURST. Minimum Desian Factor = 1.1 -- Surface Casing: Burst = Maximum surface pressure Casing Rated Fo~: 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 Desian 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 22-Feb-94 5750 psi 1781.9 psi 3.21 7240 psi 6804 psi 2830 psi 3974 psi 1.81 3090 psi 0.540 Ib/ft 690 psi 4.5J 5410 psi O.54O Ib/ft 3304 psi 1.61 Casing Design / Cement Calculations 22-Feb-94 Surface Casing Choices OD ID Ib/ft Grade Metal X-Section Jt Strength Body Strength Collapse Burst 1 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 Burst 1 7.000 6.276 26 L-80 7.5491 sq. in. 667000 lb 604000 lb 5410 psi 7240 psi 20" '~JPARUK-RIVER UI~':' ~- ..... '- DIVERTER SCHEMATIC 5 I I s ·\ / DO NOT SHUT IN DIVERTER AND VALVES AT SAME TIME UNDER ANY CIRCUMSTANCES. MAINTENANCE & OPERATION 3 UPON INmAL 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 ALASK~ INC., REQUESTS APPROVAL OF THIS DIVERTER SYSTEM AS A VARIANCE FROM 20AAC25.035(b) 1. 16" CONDUC3OR 2. SLIP-ON WELD STARTING HEAD 3. DIVERTER ASSEMBLY WITH ONE 2-1/16'- ZOO0 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" - 20(X) PSI ANNULAR PREVENTER EDF 3/10/92 7 I 4 ! I 13 5/8' 5000 '. 1BOPSTACK ACCUMULATOR CAPAC~ TEST , ' . 1. CHECK AND FILL ACCUMULATOR RESERVC~ TO PROPER LEVEL WITH HYDRAULIC FLUID. 2. ASSURE THAT ACGUMULATOR PRESSURE IS 3(X)0 PSI WITH 1500 PSI DOWNSTREAM OF THE REGULATOI:L 3~ OBSERVE TIME, THEN CLOSE ALL UNITS SII~JLTANEOUSLY AND REGORD 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 TE~I' 1. FILL BOP STACK AND MANIFOLD WITH WATER. ?- CHECK THAT ALL HOLD-DOWN SCREWS N::IE FULLY RETRACTED. PREDETERMINE DEPTH THAT TEST PLUG WiLL SEAT AND SEAT IN WELLHEAD. RUN IN LOCK-DOWN SCREWS IN HEAD. CLOSE ANNULAR PREVENTER AND CHOKES AND BYPASS VALVES ON THE MANIFOLD. ALL OTHERS OPEN. 4. TEST ALL COMPONENTS TO 250 PSI AND NDLD 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. CLOSE TOP PIPE RAMS AND HCR VALVES ON KILL AND CHOKE LINES. 7. TEST TO 250 PSI AND 3(X)0 PSI AS IN STEP 4~ CONTINUE TESTING ALL VALVES, LINES, ~ CHOKES WITH A 250 PSI LOW AND 3000 PSI HIGH. TEST AS IN STEP4. 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 3(X)O PSI. 9. OPEN PIPE RAMS. BACKOFF RUNNING JTAND 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. 17_ 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 SUPERVlSOt:[ 14. PERFORM COMPLETE BOPE TEST ONCE AWEEK 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 SPCX:)L W/ CHOKE AND KILL UNES ~ 13-5/8' - 5000 PSI DOUBLE RAM W/ PIPE RAMS ON TOP, BLIND RAMS ON BTM 7. 13-5/8' - 5(X)0 PSI ANNULAR WELL PERMIT CHECKLIST COMPANY INIT CLASS ~ ~--~, '/ UNIT# PROGRAM: exp [] der ~ redrll [] serv [] II/~ ON~OF~ s~oRE ~,3 ADMINISTRATION APPR DATE 1. Permit fee attached .................. .[Y~ 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 drlllin9 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 REMARKS 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 ...... ~_ 19. Casing designs adequate for C, T, B & permafrost .... .~ N 20. Adequate tankage or reserve pit ............ N 21. If a re-drill, has a 10-403 for abndnmnt been approved..Y 22. Adequate wellbore separation proposed .......... ~ 23. If diverter required, is it adequate .......... ~ 24. Drilling fluid program schematic & equip, list adequate .~ 25. BOPEs adequate ..................... 26. BOPE press ratin9 adequate; test to ~~ psig. 27. Choke manifold complies w/API RP-53 (May 84) ....... Y 28. Work will occur without operation shutdown ....... (~ N 29. Is presence of H2S gas probable ............. Y ~ N N N N N N.-~A' GEOLOGY / 30. Permit can be issued w/o hydrogen sulfide measures .... Y 31. Data presented on potential overpressure zones ..... Y 32. Seismic analysis of shallow gas zones .......... Y/N-- '~ ' ' ' 33. Seabed condition survey (if off-shore) ......... / N 34. Contact name/phone for weekly progress reports .... ~ Y N [exploratory only] GEOLOGY: ENGINEERING: COMMISSION: Con~nents/Instructions: