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Home My WebLink About194-017. 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. I C~ ~ -' 0 I '~ File Number of Well History File PAGES TO DELETE RESCAN Complete 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: , Beve~ncent TO RE-SCAN Nathan Lowell Date: '(~' -~'~lsl Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: /si THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON OR BEFORE JANUARY 03,2001 M p I E W ATE IA L U N U I-- i~ TH IS M ARK ER C:LOR~,fFILM.DOC 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 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 APl number and in some instances the well name reflect the number of preexisting reddils and or multilaterais 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 drill. 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 (welibore segment) Drilling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician Sep. 26. !995 1 i' 1 ?~ ALCD~ALASKA INC ARCO Alaska, inc. Post Office Box 100360 Anchorage. Alaska 99510~0360 Telephone 907 276 1215 September 26,1995 No. 3533 P. 2/2 Steve Mc_Mains Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Subiec~. 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 pem~tted 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 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. _ ct3- rd like to cancel the Permits to Drill for the following we!1s: [ ~ S KRU ZE-O4 ! q 5 2E- 8 KRU ZA-18 (Permit ~3-166, issue date 11/9/93) KRU ZA-22 (Pennit ~93-163, issue date I0/27/93) KRU 3M-27 ICRU 3H-24 KRU 3H-29 · K1KU 3H-30 clq-Oo3l 2A-t8 and 2_A-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, Denise Petrash Drilling Engineer C~ J. Hartz M. Zanghi S. Allsup-Drake (W1) Well File AOGCC (Anchorage) ATO-1286 ATO-1205 E? 2 6 995 Gas Cons. Commission Anchorage ATO-1205/ATO-370 (one copy f/each well listed above) AR38-6003-93 242-2603 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 1, 1994 A. W. McBride Area Drilling Engineer. ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Unit 3M-27 ARCO Alaska, Inc. Permit No: 94-~/~ Sur. Loc. 893'FNL, 1574'FEL, Sec. 25, T13N, R8E, UM Btmhole Loc. 967'FSL, l153'FEL, Sec. 22, T13N, 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. bTATE OF ~ "-- OIL gND PERMIT TO DRILL 20 AAC 25.005 la. Type of Work Drill X Redrill [] lb Type of Well Exploratory [] Stratigraphic [] Development Oil X Test Re-Entry D Deepen [~ Service r~ Development Gas D single Zone X Multiple Zone [-1 2.. Name of Operator ' 5. Datum Elevation (DF or KB) 10. Field and Pool ARCO Alaska, Inc. RKB 68', Pad 27' GL feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, AnchoraEle, AK 99510-0360 ADL 355032, ALK 3576 4. Location of well at surlace 7. Unit or property Name 11. Type Bond (see 20 AAC 25.025) 893' FNL, 1574' FEL, SEC. 25, T13N, RSE, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 929' FSL, 947' FEL, Sec. 22, T13N, RSE, UM 3M-27 #U-630610 At total depth 9. Approximate spud date Amount 967' FSL, 1153' FEL, Sec. 22, T13N, RSE, UM 2/2/94 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TV•) property line 3M-16 12896' MD 967' @ TD feet 10.6' @ 750' MD feet 5108 6355' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035(e)(2)) Kickoff depth 650 feet Maximum hole angle 68.74° Maximum surface 2009 psig At total depth (TVD) 3475 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 24" 16" 62.5# H-40 Weld 80' 41' 41' 121' 121' +200 CF 12.25" 9.625" 47.0# L-80 BTC 2900' 41' 41' 2941' 2430' 710 Sx Arcticset III & HF-ERW 580 Sx Class G 12.25" 9.625" 36.0# J-55 BTC 2656' 2941' 2430' 5597' 3393' HF-ERW 8.5" 7" 26.0# L-80 BTCMOC 12855 41' 41' 12896' 6355' 150 SxClass G HF-ERW Top 500' above Kuparuk 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Structural Length Size Cemented Measured ~.e .RLh .` L C F ~T, ru~,E,,~. I/'~'~01 depth Conductor ~J Surface Intermediate Production ,j ,/-"~. i"'! ~ ,; I:.~ .~J -r Liner Perforation depth: measured .',=~'~?,~ i.)iJ ~ 0~$ (~0t']$. (~OlTl~i3Si0g !~ r .or true vertical AgO.,Oj;~ . 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 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 //~//~~~~Z Title Area Drillin~l Engineer Date ]..~.q--G~]' "' - Commission Use Only Perm,t ~~,t I APl number I Approval date ~P I See cover letter for 50-~ ~, ~ -- ~ Z.. ~.,.~,.~" ~;~" / '" other requirements Conditions of approval Samples required [] Yes j~ No Mud log required [] Yes 'J~ No Hydrogen sulfide D Yes J~] No Directional survey required ~ Yes D No measures Required working pressure for BOPE [~] 2M ~ 3M D 5M ~] 10M ~] 15M Other: )rlgina} --' lgnea Bybyorder of Approved ~y .m id W. Johnston Commissioner the commission Date _~../.[,~.G .~. ,.. Form 10-401 Rev. 7-24-89 plicate GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD 3M-27 I · , . , , . , . , 10. 11. 12. 13. 14. 15. 16. 17. 18. Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (5597')according to directional plan. Run and cement 9-5/8" casing (cement to surface). No cement bond logs to be run in surface 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 (12,896') 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. .rFIVEE) iCreated by : jones For: S BPJLDLE~ IDate plotted : 19-Jan-94 Plot Reference is 27 Version #3. Coordinates are in feet. reference slot #27. True Vertical Depths are reference wellhead. Baker Hughes INTFQ --- ARCO ALASKA, Inc. Structure : Pad 3M Well : 27 Field : Kuparuk River Unit Location : North Slope, Alaska N 79.61 DEG W 0099' (tO tARGEt) < - - W e st ,: : o.oo 10,500 100009500 gO(X)8500 8000 7500 7000 6500 6000 5~qOO5000 4~00 4000 5500 5000 254102000 1500 tO00 500 0 500 II II [I It II II [I II tI II II II II II II II II II II II II I I I TD LOCATION: I ~~~ 967' FSI_, 1153' FEL "~"~........~.~ TARGET TVD=6146 TMD=12599 DEP=10099 NORTH 1822 WEST 9933 ESTIMATED SURFACE LOCATION: 895' FNL, 1574' FEL SEC. 25, TI3N, RSE 250o 1000_ 6,3 - 1500_ _ - 2500_ 30CO_ - - - [ 4500_ I V 5000_ 54.( R KEI ELEVATION; KOP TVD=650 TMD=650 DEP:O 6.00 1800 24 OO ;' :';',, i'~ ~.-... ,".., ! '? [~ :'-/' 000 .3'~ O0 B/ PERMAFROST TVD-1718 TMD=178..3 DEP=327 4200 ,. 48.00 ,i,',i': ": : ':" T/ UGNU SNDS TVD=2198 TMD=2455 DEP=791 ..... C TVD=2430 TMD=2941 DEP=1217 -'"--...~,..~/ W SAK SNDS TVD=2958 TMD=4342 DEP=2523 B/ W ~ SNDS 'PVD=5193 TMD=5046 DEP=,3178 K-lO T'v'D=5488 TMD=5859 DEP=;.'.3936 ~'"'-'"~?""--..,~..._5/8'' CSG PT TVD=3593 TMD=5597 DEP=3692 ~ MAXIMUM ANGLE 68.74 DEG K-5 TVD=4918 TMD=9802 DEP=7611 8bD~.00 6.00 45 DEG V ZONE A TVD=*18S m0=~2*28 eE~=101~* . TI) / 7" CSG Fl' TVI)=635§ 1~D=11~§90 1DE?=I030O I I I I I I I I I I I I I I I I 500 0 500 1000 1500 2000 2500 3000 5500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9.5001000010500 Scole 1 : 250.00 Vertical Section on 280.39 azimuth with reference 0.00 N, 0.00 E from slot #27 550 500 I I ,.,I 450 400 I I I ,.I 90O 1900 350 .300 250 200 150 1 O0 ARCO ALASKA, Inc. StTuature : Pad &M Well : 27 Field : Kuparuk River Unit location : North Slope, Alaeka 1700 1 O0 1500 1700 1300 1100 ~00 50 500 2900 1100 900 9OO 0 I 2700 9OO 21 O0 50 250 _ 200 _ 150 .i 100 5O 5O- -~, Gas Cons. Commission Anchora.o,,,~. 100 150 DRILLING FLUID PROGRAM Well 3M-27 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 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 11.1 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 2009 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 3M-27 is 3M-16. As designed, the minimum distance between the two wells would be 10.6' @ 750' 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 24-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 3M-27 5,597 ft 3,393 ft 12,896 ft 6,355 ft 4,342 ft 12,599 ft 6,146 ft 3400 psi ** See Page 4 For Casing Choices 3,500 psi Maximum anticipated surface pressure TVD surface shoe = 3,393 ft {(13.5'0.052)-0.11}*TVDshoe =1 2,009 psiJ Estimated BH pressure at top of target zone Estimated Pressure= Top of Target, TVD = Overbalance, psi= Anticipated Mud Weight =[ 3,400.0 ppg 6,146 ft 150 psi 11.1 ppgJ Surface lead: Surface tail: Top West Sak, TMD = 4,342 ft Design lead bottom 500 ft above the Top of West Sak = 3,842 ft Annular area = 0.3132 cf/If Lead length * Annulus area = 1,203 cf Excess factor = 15% Cement volume required = 1,384 cf Yield for Permafrost Cmt = 1.94 Cement volume required =1 710 sxJ TMD shoe = 5,597 ft (surface TD - 500' above West Sak) * (Annulus area) = 550 cf Length of cmt inside csg = 80 ft Internal csg volume = 0.4110 cf/If Cmt required in casing = 33 cf Total cmt = 583 cf Excess factor = 15% Cement volume required = 670 cf Yield for Class G cmt = 1.15 Cement volume required =1 580 sxJ RECEIVED Casing Design/Cement Calculations 24-Jan-94 Production tail: TM D = 12,896 ft Top of Target, TMD = 12,599 ft Want TOC 500' above top of target = 12,099 ft Annulus area (9" Hole) = 0.1745 (TD-TOC)*Annulus area = 139 cf Length of cmt wanted in csg = 80 ft Internal csg volume = 0.2148 Cmt required in casing = 17 cf Total cmt = 156 cf Excess factor = 15% Cement volume required = 180 cf Yield for Class G cmt = 1.23 Cement volume required =[ 150 sxJ TENSION - Minimum Desiqn Factors are: T(pb)=1.5 and T(js)=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 * (WEft) 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 * (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 Production (Joint Strength): 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 (Joint Strength) = Design Factor =[ 1086000 lb 5,597 ft 47.0O lb/ft 263059.0 lb 43831.1 lb 219227.9 lb 5.0J 1161000 lb 5,597 ft 47.0O Ib/ft 263059.0 lb 43831.1 lb 219227.9 lb 604000 lb 12,896 ft 26.00 Ib/ft 335296.0 lb 56172.3 lb 279123.7 lb 2.2] 667000 lb 12,896 ft 26.00 Ib/ft 335296.0 lb 56172.3 lb 279123.7 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--Osg 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 =[ 24-Jan-94 6870 psi 2008.7 psi 3.41 7240 psi 7171 psi 2941 psi 4230 psi 1.7J 4750 psi 0.578 Ib/ft 1024 psi 4.6J 5410 psi 0.578 Ib/ft 3671 psi 1.51 Casing Design / Cement Calculations 24-Jan-94 Surface Casing Choices OD ID Ib/ft Grade Metal X-Section Jt Strength Body Strength Collapse I 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 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,i 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 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 6. 20" - 2000 PSI ANNULAR PREVENTER !';'~'. ~'. ~, ~ [ :~J EDF 3/10/92 13 5/8" 5000 ,i $1 BOP STACK 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. 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 PSt 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 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 DALLY. 1. 16" - 2000 PSI STARTING HEAD 2. 11 ' - 3000 PSI CASING HEAD 3. 11' - 3000 PSI X 1;~5/8' - 5000 PSI SPACER SPOOL 4. 195/8' -5000 PSI PIPE RAMS 5. 13-5f8' - 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. 195/8' - 5000 PSI ANNULAR ITEM (1) Fee (2) Loc (3) Admin ['9 thru i3]}/ S5 i0. 12. (4) Casg < ~' 14. [1~ thru 22 15. (5) BOPE ** CHECK LIST FOR NEW WELL PERMITS ** APPROVE DATE. /~ ~__~ 1. Is permit fee attached ............................................... _,~, ,~ 2. Is well to be located in a defined pool .............................. .,-,. [2 thru'8] - 3. Is well located proper distance from property line ................... 4.. 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 ................... . 7' Is operator the only affected party .................................. "i" 8. Can permit be approved before 15-day wait ............................ . [23 thru 2 Company /F-~--, ~ .. Lease & Wel 1 ~ ,,.'~Z ,.~,~.S'-c:9'. ?,2. ,"' , '.x~.~,/', NO R'/EMARKS 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. Does operator have a bond in force ................................... ~_ _~_ Is a conservation order needed ....................................... Is administrative approval needed .................................... Is lease n~nber appropriate .......................................... Z Does well have a unique name & n~nber ................................ '~t~ . Is conductor string provided ....... '~- Will surface casing protect aii 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 existin9 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 8 BOPE attached .... Does BOPE have sufficient pressure rating -- test to ..~.. psig ..... Does choke manifold cc~nply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... (6) Other //(:~ .//--/~z~ 29 E29 thr~/~~'~'/ ' 30. 31. (7) Contact~y~_~ ~.~_~y 32. [32] (8) Addl 33. geology' DWJ RP.fi~. TAB enoineering: rev 6/93 jo/6.011 FOR EXPLORATORY & STRATIGRAPHIC 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 n~nber of contact to supply weekly progress data ...... Additional requirements ............................................. Additional INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~. SHORE remarks' MERIDIAN' UM-z~--- WELL TYPE:. Exp/~X Inj SM Redrill Rev 0 '"r' Z ~-~ m z