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Home My WebLink About193-188Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. [ (;r~ -. [~ ~' File Number of Well History File PAGES TO DELETE Complete RESCAN [] Color items- Pages: ,[3 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: Beverly~ Vincent TO RE-SCAN Nathan Lowell Notes: Re-Scanned by; Bevedy Dianna Vincent Nathan Lowell Date: Is~ Il · 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 APl 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 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 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) Ddiling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician Sep. 26. I995 II' i?AM AR~k.4LASKA INC ARCO Alaska, Inc._ Post Office Box 100360 Anchorage. Alaska 99510-0360 Telephone 907 276 1215 No. 3533 P. 2/2 Steve McMains Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Subiect: 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 Kupamk 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 chaz~ge requires re-submission of a Form 401 anyway, I think it would be easier on both of us to cancel the current permits. _ I'd like to caz~cel the Permits to Drill for the following we!is: 2 -o4 1'75 KRU 2 -zS KRU ZA-18 (Permit $$93-166, issue date 11/9/93) KRU 2A-22 (Permit $$93-163, issue date I0/27/93) KRU 3M-Z7 KRU 3H-24 KRU 3H-29 ' KRU 3tt~0 qq q,.-ool'7 H -' 2A-18 and 2A-~ 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 arty questions on the above wells please call me. Sincerely, DenisePetrash SEP 2 6 1995 Drilling Engineer C~ M. Zanghi $. Allsup-Drake (wi) wen Odaska Oil & Gas Cons. COmmission AOGCC (Anchorage) Anchorage ATO-1286 ATO-1205 ATO-1205/ATO-370 (one copy f/each well listed above) AR38-6003-93 242-2503 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 January 10, 1994 Phyllis Billingsley ARCO Alaska Inc P O Box 100360 Anchorage, AK 99510-0360 Dear Ms Billingsley: The Commission is compiling statewide drilling statistics for 1993. Attached is a list of outstanding Permits to Drill issued to your engineering group (permits for which no form 10-407 has been received by this office). Please review this list to determine if any of the wells were drilled in 1993. If so, please note the well name, total measured depth, and class (development, service or exploratory). If any wells were drilling as of 12/31/93, estimate the depth at 12:00 midnight. We would appreciate your reply by the end of January if possible. Thank you for your cooperation with this project. If I may be of any assistance, please call me at 279-1433. Yours very truly, Robert P Crandali Sr Petr Geologist enci jo/A: RPC:~drlstats .1104/94 OPERATOR ARCO ALASKA INC ARCO ALASKA ARCO ALASKA ARCO ALASKA INC ARCO ALASKA ARCO ALASKA ARCO ALASKA INC ARCO ALASKA INC ARCO ALASKA ARCO ALASKA INC ARCO ALAS~CA ARCO ALASKA ARCO ALASKA ARCO ALASKA ARCO ALASKA ARCO ALASKA ARCO ALASKA ALASKA WELLS BY ARCO PERMIT 93-0166-0 93-0152-0 93-0151-0 93-01~3-0 93-0144-0 93-0188-0 93-0179-0 93-0169-0 93-0104-0 93-0189-0 93-0174-0 93-0175-0 93-0187-0 93-0195-0 93-0196-0 93-0193-0 92-0040-0 WELL NAME KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV ~-NIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT KUPARUK RIV UNIT 2A-18 2A-19 2A-20 2A-22 2A-24 2E-04 2E-05 2E-06 2E-07 2~-09 2E-17 2E-18 3M-23 3~-24 3M-25 3M-26 3R-16 ALASKA OIL AND GAS CONSERVATION CO~IMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 December 3, 1993 A. W. McBride Area Drilling Engineer ARCO Alaska, Inc. P O Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Unit 2E-04 ARCO Alaska, Inc. Permit No: 93-188 Sur. Loc. 580'FSL, 160'FWL, Sec. 36, TllN, R9E, UM Btmhole Loc. 839'FNL, 1250'FWL, Sec. 7, T10N, R10E, 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. ~2:~m~~n ' 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 AIJ~, ~ OIL AND GAS CONSERVATION COMMIS~ _ .Al PERMIT TO DRILL 2O AAC 25.005 la. Type of Work Drill X Redrill r~ lb Type of Well Exploratory [--I Stratigraphic [~ Development 'Oil X Test Re-Entry Z] Deepen F=~ Service D Development Gas E] Single Zone X Multiple Zone 2.. Name of operator 5. Datum Elevation (DF or KB) 10. Field and Pool ARCO Alaska, Inc. RKB 147', Pad 106' GL feet Kuparuk River Field 3. Address 6. Property Designation Kuparuk River Oil Pool P. O. Box 100360, Anchoracje, AK 99510-0360 ADL 25664, ALK 473 4. Location of well at surface 7. Unit or property Name 11. Type Bond (see 20 AAC 25.025) 580' FSL, 160' FWL, SEC. 36, T11N, R9E, UM Kuparuk River Unit Statewide At top of productive interval (@ TARGET ) 8. Well number Number 650' FNL, 1100' FWL, Sec. 7, T10N, R10E, UM 2E-04 #U-630610 At total depth 9. Approximate spud date Amount 839' FNL, 1250' FWL, Sec. 7, T10N, R10E, UM 12/8/93 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property i5. Proposed depth (MD and TVD) property line 2E-05 11965' MD 1280' @ TD feet 23.6' @ 460' MD feet 2501 6403' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.~35(e)(2)) Kickoff depth 600 feet Maximum hole angle 66.52° Maximum surface 2052 psig At total depth (TVD) 3050 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include sta~]e data) 24" 16" 62.5# H-40 Weld 80' 41' 41' 121' 121' +200 CF , 12.25" 9.625" 36.0# J-55 BTC 5576' 41' 41' 5617' 3487' 520 Sx Arcticset III & HF-ERW 800 Sx Class G 8.5" 7" 26.0# L-80 BTCMOI~ 11654 41' 41' 11965' 6403' 160SxClass 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 Measured depth True Vertical depth Structural Conductor ¥~; t~ ~. ~.~r ~ ~ Surface ~-' ~ ~ Intermediate ~ %*. ~ ~ 'J ~ Production ,. · Liner i' :'i'."~",' 'i ('; ', Perforation depth: measured 20. Attachments Filing fee X Property plat r-I BOP Sketch X Divert"~Y,-;[~k~t~ X Drilling program X Drilling fluid program X Time vs depth plot r~ 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 J,,~J~ ~~,~ Title Area Drillin~l Encjineer Date /////~.~/~.~, Commission Use Only Permit Number IAPI number {Ap I dat I cover ?...~ _/<~,~7 50- 4:~ 2.. '~ ~ -~- ~.2. ~ ~a._... ~-rT~ ~"~-~ See letter for -- other requiremenls Conditions of approval Samples required D Yes [~ No Mud log required E] Yes J~ No Hydrogen sulfide [--~ Yes [~ No Directional survey required [~ Yes r-] No measures Required working pressure for BOPE [~] 2M [~ 3M [~] 5M ~] 10M D 15M Other: Original Signed By David W. Johnston by order of Approved by Commissioner the commission Date ,,/ ~ ~/,~ Form 10-401 Rev. 7-24-89 Submit in triplicate , , o 10. 11 12 13 14 15 16 17 18 GENERAL DRILLING PROCEDURE KUPARUK RIVER FIELD 2E-04 Move in and rig up Parker #245. Install diverter system. Drill 12-1/4" hole to 9-5/8" surface casing point (5617')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 (11965') 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 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 2E-04 Density PV YP Viscosity Initial Gel 10 Minute Gel APl Filtrate pH % Solids Spud to 9-5/8" surface casin~t 9.0-10.8 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 10.1 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 2052 psi could be reached. Therefore, ARCO Alaska, Inc. will test the BOP equipment to 3000 psi. The nearest well to 2E-04 is 2E-05 (proposed). As designed, the minimum distance between the two wells would be 23.6' @ 460' MD. The wells would diverge from that point. 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. ARCO ALASKA, ][nc. $1ructure : Pad 2E Well : 4 Field : Kuparuk River Unit Location : North Slope, Alaska ~Created by ' jones For: S BRM)LEY iDate plotted : 29-Nov-95 iPIot Reference is 4 Version #2. iCoordinates ore in feet reference slot #4. !True Ver[ical Depths ore reference wellhead.! Baker Hughes INTEQ ,co, o.oo E a st - - > ~0 0 5C~3 '4(>(20 150<) 20{3'<> 2~0 30C~3 350<) 40<)0 4~ ~00 [ I i I I I I I I I I I I I I I I I I I I I I I 5500 6000 I II 155o 2250_ _ 2700_ 5150i 4050_~ 4950_ 6750 4~ ISURFACE LOCATION: 580' FSL, 160' FWL SEC. .:36, T11N, R9E RKB ELEVATION: 147' KOP TVD=600 TMD=600 DEP=O 6.00 12.00 BUILD _% OEG / 100' 18.00 ~,~ 24.00 ,30.00 B/ PERMAFROST TVD=1502 TM0=1559 DEP=226 36.00 ,% 42.00 -- ~'"~'%.48~u4U. O0 T/ UGNU SNDS TVD=2122 TMD=2361 DEP=756 oc ~=2352 T~D:28~7 DEP=~,49 ~.~$AK SND$ TVD=2687 TMD=3650 DEP:I§2'i MAXIMUM ANGLE 66.52 DEG TAR O E-f LOCATION: 650' FNL, 1100' SEC. 7, T10N, Ri0E S 43.7 DEG E 9004' (TO TARGET) TARGET TVD=6092 TMD= 11559 DEP=9004 SOUTH 6510 EAST 6220 TARGET ANGLE 40 DEG ~ B/' vl SA~< SNDS TVD=5267 TMD=5115 DEP=5256 ~,~'"'~5/A" CSC- PT TVD=3467 TMD=5617 DEP=3717 ~ K-lO TVD=5797 TMD=6445 DEP=4477 6500 5oo _5000 _ _5500 _ _6500 - _700~ TD LOCATION: I 850' FNL 1280' FWL SEC. '7. TION, RIOE 7'.: ~.7 !,;,~, "-,, '" ¢ i TM ~ ;r, '".: i:" ,.. !,. Scale I : 225.00 Vertical Section on 156.30 azimuth with reference 0.00 N, 0.00 E from slot #4 J I I I I I { { I I [ i [ ! i i : i i J ~ I i i i i i i i f f i J f i i i i i i ! i i 0 450 900 13.50 1800 2250 2700 ,3150 3600 4050 4500 4,950 5400 5850 6500 6750 7200 7650 8100 8550 §000 9450 K-5 TVD=5147 TMD=9854 BEGIN ANGLE DROP TVD=5,306 '1'MD=1023,3 DEP=7951 "'"'---.,. 66(1(~0062' '~' 58.00 DROP 2 DEO / tOO' '~. 54.00 50.00 %%-. 46,00 · TARGET - T/ ZONE C (EOD) TVD=6092 TMD=11559 DEP=9004 ",,. 42.00 T/ ZONE A TVD=6156 TMD=11642 DEP=9058 ',, "'x. ",. B/ KUP SNDS 'P40=6250 TMD=~1765 DEP=9136 :.', TD / 7" CSG PT TVD=6403 TMD=II965 DEP=9265 Scale ~00 · 50.00 0 5O 8OO 200, 40£ 8OO 16O( 50 100 ,200 400 400 200 400 250 300 35O lO0 At{CO Structure : pad 21~ FleJC~ : KuparUk River Unit ALASKA, Inc. ~o Well : ~' Location : t4orth Slope, Alaska 0 600 160 1800 50 100 150 fin O CD O 200 1600 2000 250 0 300 Casing Design / Cement Calculations 30-Nov-93 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 2E - 04 5,617 ft 3,467 ft 11,965 ft 6,403 ft 3,659 ft 11,559 ft 6,092 ft 3050 psi : : :: :: :: :: :: :: :: :: :: :: :: : :: :: :: :: : :: :: :: ?: :: :: :: :: : :: :: :: :: : :: :: :: :: :: :: :: :: ?: ?: :: :: ?: :: : : ?: ?: ?: ?: ?: ?: ** See Page 4 3,500 psi Maximum anticipated surface pressure TVD surface shoe = 3,467 ft {(13.5'0.052)-0.11}*TVDshoe =l 2,052 psiI Estimated BH pressure at top of target zone Estimated Pressure= Top of Target, TVD = Overbalance, psi= Anticipated Mud Weight =1 3,050.0 ppg 6,092 ft 150 psi 10.1 ppgJ Surface lead: Top West Sak, TMD = 3,659 ft Design lead bottom 500 ft above the Top of West Sak = 3,159 ft Annular area = 0.3132 cf/If Lead length * Annulus area = 989 cf Excess factor = 15% Cement volume required = 1,138 cf Yield for Permafrost Cmt = 2.17 Cement volume required =I 520 sxJ Surface tail: TMD shoe = 5,617 ft (surface TD- 500' above West Sak) * (Annulus area) = 770 cf Length of cmt inside csg = 80 ft Internal csg volume = 0.4340 cf/If Cmt required in casing = 35 cf Total cmt = 805 cf Excess factor = 15% Cement volume required = 925 cf Yield for Class G cmt = 1.15 Cement volume required =1 800 sxJ Casing Design / Cement Calculations 30-Nov-93 Production tail: TMD = 11,965 ft Top of Target, TMD = 11,559 ft Want TOC 500' above top of target: 11,059 ft Annulus area (9" Hole) = 0.1745 (TD-TOC)*Annulus area = 158 cf Length of cmt wanted in csg = 80 ft Internal csg volume = 0.2148 Cmt required in casing = 17 cf Total cmt = 175 cf Excess factor = 15% Cement volume required = 202 cf Yield for Class G cmt = 1.23 Cement volume required =1 160 sxJ TENSION - Minimum Design Factors are: T(Db)=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 * (WEft) Buoyancy - Weight of displaced mud Length = Casing Wt (Ib/ft): Dead Wt in Air = Buoyancy = Tension (Pipe Body) = Design Factor =[ 564000 lb 5,617 ft 36.00 Ib/ft 202212.0 lb 3O223.4 lb 171988.6 lb 3.3J 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 =1 639000 lb 5,617 ft 36.00 Ib/ft 202212.0 lb 30223.4 lb 171988.6 lb 3.71 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 11,965 ft 26.00 Ib/ft 311090.0 lb 47395.2 lb 263694.8 lb 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 =1 667000 lb 11,965 ft 26.00 Ib/ft 311090.0 lb 47395.2 lb 263694.8 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 =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 =[ 30-Nov-93 3520 psi 2052.5 psi 1.7J 7240 psi 6863 psi 2963 psi 3900 psi 1.91 2020 psi 0.525 Ib/ft 885 psi 2.3J 5410 psi 0.525 Ib/ft 3363 psi 1 .Si Casing Design / Cement Calculations 30-Nov-93 Surface Casing Choices OD ID I b/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 20" ,.JPARUK RIVER UNI' DIVERTER SCHEMATIC I HCR I I HCR / 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 , 2. 3. 4. 5. . 16" CONDUCTOR SLIP-ON WELD STARTING HEAD DIVERTER ASSEMBLY WITH ONE 2-1/16"- 2000 PSI BALL VALVE 20"-2000 PSI DRILLING SPOOL WITH TWO 10" OUTLETS. 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 20"-2000 PSI ANNULAR PREVENTER ~" ~: ":'~-' ?.!~' ~ ~ ~'~ 'l EDF3/10192 ,?, ;,'__ I I 7 5 4 13 5/8" 5000 F,.,I 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 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 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 BOTFOM 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 195/8"-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 ** CHECK LIST FOR NEW WELL PERMITS ** ITEM APPROVE DATE [ 2 ~hru 8] (3) Admi n [~/~<_~ (4) Casg (5) BOPE [~J' thru 13] [ 10 & 13] [14 thru 22 [23 thru . 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. Company Lease & Well ~ /;2~ NO · , , YES 1. Is permit fee attached ............................................... ~ 2. Is well to be located in a defined pool .............................. ~ 3. Is well located proper distance from property line ................... 4. Is well located proper distance from other wells ..................... /~ 5. Is sufficient undedicated acreage available in this pool ............. ~ 6. Is well to be deviated & is wellbore plat included ................... L 7. Is operator the only affected party .................................. /~ 8. Can permit be approved before 15-day wait ............................ ~ Does operator have a bond in force ................................... Is a conservation order needed ....................................... Is administrative approval needed .................................... , Is lease nLrnber appropriate .......................................... ~__ Does well have a unique name & nL~nber ................................ . Is conductor st r i ng provided ......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. t/- 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 & BOPE 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 ...................................... REMARKS [29 thru'31] E32] (8) Addl 29. 30. 31. 32. 33. geology' engineering' .__ TAB_~ i~/~/~ 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 nLrnber of contact to supply weekly progress data ...... Additional requirements eee$leleee®eeleeeeeeeeeleeee®eleeeeee®eeel.l. Additional INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA ~ SHORE MERIDIAN' ///.~ remarks' UM SM WELL TYPE' Exp/Dev Redrill Inj Rev 0 --4 -r'Z ,--.~ 0 m z