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Home My WebLink About195-177XHVZE 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. / ~'¢"-/'~"~ File Number of Well History File PAGES TO DELETE 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: Bevedy Mildred Daretha Natha~~ [] TO RE-SCAN Notes: Re-Scanned by: Bevedy Mildred Daretha Nathan Lowell Date: /s/ Memorandum State of Alaska Oil and Gas Conservation Comzniss~ 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 ~e. 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 i 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 remair unchanged. The APl number and in some instances the well name reflect the number of preexistin( redriils and or multilaterals in a well. In order to prevent confusing a cancelled or expired permit witi-, an active well or multilateral these case sensitive well identifiers will be changed for expired and cancelled applications for permits to ddil. 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 AP! numbering methods descnbed in AOGCC staff memorandum "Multi-lateral (weiibore segment) Ddiling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. e McMains ' ~ Statistical Technician TONY KNOWLES, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 November 9, 1995 1: Tim Schofield, Senior Drilling Engineer BP Exploration (Alaska), Inc. P O Box 196612 Anchorage, AK 99519-6612 Re: Miine Point Unit MPJ-20 BP Exploration (Alaska), Inc. Permit No 95-177 ' Surf Loc 2207'NSL, 3288'WEL, Sec. 28, T13N, R10E, UM Btmhole Loc 4380'NSL, 2422'WEL, Sec. 20, T13N, R10E,UM Dear Mr. Schofield: 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 ddlling 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 ddiling 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 /encl c: Dept of Fish & Game, Habitat Section - w/o encl Dept of Environmental Conservation - w/o encl · STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 ila. Type of work Drill [] Redrill E]llb. Type of well. Exploratoryl-I Stratigraphic Test [] Development Oil [] Re-Entry [] DeepenI-II Service [] Development Gas [] Single Zone [] Multiple Zone [] 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool BP Exploration (Alaska) Inc. Plan RTE = 64.6 feet Milne Point / Kuparuk River 3. Address 6. Property Designation P. O. Box 196612, Anchorage, Alaska 99519-6612 ADL 025515 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 2o AAC 25.025) 2207' NSL, 3288' WEL, SEC 28, T13N, RIOE Milne Point Unit At top of productive interval 8. Well number Number 4169' NSL, 2298' WEL, SEC 20, T13N, RIOE MPJ-20 2S100302630-277 At total depth 9. Approximate spud date Amount 4380' NSL, 2422' WEL, SEC 20, T13N, RIOE 11/13/95 $200,000.00 12. Distance to nearest 13. Distance to nearest well 4. Number of acres in property15. Proposed depth (MD and TVD) property line ADL 315848 2422 feet MPJ-9i 65.7 feet 2544 12001' MD / 7414' TVD feet 16. To be completed for deviated wells 17. Anticipated pressure (see 20 ^AC 25.035 (e)(2)) Kickoff depth 500 feet Maximum hole angle 61 o Maximum surface 3160 psig At total depth (TVD) 7000'/3857 psig 18. Casing program Specifications Setting Depth s~ze Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 24" 20" 91.1# H-40 Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 3069' 31' 31' 3100' 2591' 617sxPF'E', 250sx'G', 150sxPF'E' 8-1/2" 7" 26# L-80 Btrc 11971' 30' 30' 12001' 7414' 462 sx Class 'G' 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structural Conductor Surface i" ,,,., ~ ~,i..? Intermediate Production !'i' r'i''; ' '~ ' "" ¢'':: t, ',~ .; ,~ ._, Liner Perforation depth: measured A!~.,~:~, {J~[ ~'~ I~:'~d~.-'; ~;,.'~%. true vertical " 20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program [] Drilling fluid program [] Time vs depth plot [] Refraction analysis[] Seabed report[] 20 AAC 25.050 requirementsFI 21.1 hereby certif, y..-that th_..e forepoing ~j~true and correct to the best of my knowledge /3/q Signed. '"~ -~' .¢_~~~6[ ' CommissionTitleSeni°rDfil/in~En~ineeruse Only Date [/ ~'. Permit Number lAP[ number _ IApproval~d¢,e, _~ See cover letter i o. ¢_ i //_/_?/%_ for other requirements Conditions of approval Samples required [] Yes 'IX! No Mud Icg required []Yes ,[~ No Hydrogen sulfide measures [] Yes ~ No Directional survey required '~ Yes [] No Required working pressur.e, for B.OP~E ~2~..; I-'I3M; l~5M; []10M; I-'115M; Other: Original btgneaDy by order of Approved by David W. Johnston Commissioner ~ne commission Date///~.../?._ Form 10-401 Rev. 12-1-85 Submit I Well Name: I MPJ-20 I Well Plan Summary IType °f Well (pr°ducer °rinjector)' IKuparukPr°ducer I Surface Location: 2207 NSL 3288 WEL Sec 28 T13N R10E UM., AK Target Location: 4169 NSL 2298 WEL Sec 20 T13N R10E UM., AK Bottom Hole 4380 NSL 2422 WEL Sec 20 T13N R10E UM., AK Location: I AFE Number: 13301 70 I Rig: I Nabors 22-E 13 Well Design (conventional, etc.): Formation Markers: slimhole, I Milne Point Ultra Slimhole 7"LS Formation Tops MD TVD (bkb) base permafrost 1962 1865 NA 5594 3795 Top of Schrader Bluff Sands (8.3 PPg) Seabee Shale 6088 4035 Base of Schrader Bluff Sands (8.3 PPg) HRZ 10982 6584 High Resistivity Zone Top Kuparuk 11255 6804 Kuparuk Cap Rock Target Sand 11574 7065 Target Sand (10.5 ppg) Total Depth 12001 7414 Casing/Tubing Program: Hole Csg/ Wt/Ft Grade Conn Length Top Btm Size Tbg O.D. MD/TVD MD/TVD 24" 20" 91.1# H-40 Weld 80 32/32 112/112 12 1/4" 9 5/8" 40# L-80 btrc 3069 31/31 3100/2591 8 1/2" 7" 26# L-80 btrc 11971 30/30 12001/7414 Internal yield pressure of the 9-5/8" 40# casing is 5750 psi. Worst case surface pressure would occur with a full column of gas to the reservoir at 7000 TVDSS. Maximum anticipated surface pressure in this case assuming a reservoir pressure of 3857 psi is 3160 psi, well below the internal yield pressure rating of the 9-5/8" casing. Logging Program: Open Hole Logs: Surface MWD Directional DSS Intermediate N/A Final Cased Hole Logs: 1. PDC Bit f/Prince Creek to TD w/MWD Dir and LWD GR/CDR/CDN). Mudloggers are NOT required for this well. Alaska 0il & 6as Coi',s. Corr~mission Anchorage Mud Program: Special design I None- SPUD MUD considerations I Surface Mud Properties: I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscos. ity Point gel gel Loss 8.6 1 00 1 5 8 1 0 9 8 , to to to to to to to , 9.0 50 35 1 5 30 1 0 1 5 Intermediate Mud Properties- N/A'I Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss Production Mud Properties: I None- LSND freshwater mud Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 9.0 40 1 0 3 7 8.5 6 - 8 to to to to to to to 11.0 50 15 10 20 9.5 4-6 Well Control: Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed and is capable of handling maximum potential surface pressures. Diverter, BOPE and drilling fluid system schematics on file with AOGCC. Directional' I KOP= 1500' Maximum Hole Angle: Close Approach Well: 61 o MPJ-9i. 65.7' @ 2253' MD/2087' TVD. MP J-9i is shut-in. A plug will be set at Packer depth to iSolate wellbore. Disposal' Cuttings Handling: Cuttings should be hauled to the ball mill at CC-2A. The Milne Point reserve pit can be opened in emergencies by notifying Karen Thomas (564-4305) with request. Request to AOGCC for Annular Pumping Approval for MPJ-20: 1. Approval is requested for Annular Pumping into the MPJ-20, 9-5/8" x 7" casing annulus. 2. Aquifers in the Milne Point Unit have been exempted from Class II injection activities by the AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. There are no domestic or industrial use water wells located within one mile of the project area. 3. The 9-5/8" casing shoe will be set at 3100' md (2582' tvd) which is a minimum of 500' tvd below the Permafrost and into the Prince Creek formation which has a long established history of annular pumping at Milne Point. 4. The burst rating (80%) for the 9-5/8" 40# L80 casing is 4600 psig while the collapse rating (80%) of the 7" 26# LB0 casing is 4325 psig. The break down pressure of the Prince Creek formation is 13.5 ppg equivalent mud weight. The Maximum Allowable Surface Pressure while annular pumping is calculated according to the following equation and is 3116 psi for'a 10.9 ppg fluid in this well (Assumes worst case in which 7" casing is filled with gas). MASP = 4325 psig - ((fluid density ppg - 1.9) X 0.052 X 9-5/8" Casing Shoe TVD A determination has been made that the pumping operation will not endanger the integrity of the well being drilled by the submission of data to AOGCC on 7/24/95 which demonstrates the confining layers, porosity, and permeability of the injection zone. The cement design for this well ensures that annular pumping into hydrocarbon zones will not occur. . . AREA WELL PREVVOL PERMITTED PERMITTED INJECTED VOL DATES (aBES) (aBES) Milne Point MPJ-13 81 10 0 1 995 ! Milne Point MPJ-20 0 0 :1 995 DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS. . . . , , , , , . 10. 11. 12. 13. 14. 15. 16. MPJ-20 Proposed Summary of Operations Drill and Set 20" Conductor. Weld a starting head and top job nipple on conductor. Prepare location for rig move. MIRU Nabors 22E drilling rig. NU and test 20" Diverter system. Build Spud Mud. Drill a 12-1/4" surface hole as per directional plan and run and cement 9-5/8" casing. Run only Dir MWD. ND 20" Diverter, NU and Test 13-5/8" BOPE. MU a PDC bit on a motor, with Directional MWD and LWD CDR/CDN (GR/RES/Dens/Neu). RIH, drill out FE and 10' of new formation -- Perform FIT to 12.5 PPg. Drill 8.5" hole to TD as per directional plan -- Run and Cement 7" Casing. RIH while PU 3-1/2" drill pipe and tandem 7" 26# scrapers and bit. Drill the ES Cementer and RIH to PBTD, perform a casing wash while displacing the hole with source water. Filter source water to 2 micron absolute. Freeze Protect Top 2000' of hole with diesel. Pressure test above the plug to 3500 psig. POOH LD remainder of 3-1/2" drill pipe. ND BOPE, NU Tree, tubing hanger with BPV. Test Tree, BPV. RDMO Nabors 22E drilling rig to drill next well. Perforate and Stimulate in absence of rig. Displace well with 10.5 ppg brine and set a wireline retrievable bridge plug. MIRU Nabors 4ES or Polar 1 Rig. NU & Test BOPE to 5000 psig. Perform Casing Wash. Change Rams and run Electric Submersible Pump on 2-7/8" threaded tubing. t 0 '",! '" '~ "''~ "" "--' Install Surface Lines and Wellhouse and put the well on production. · ' :~ ' ' I ~ . ,~ i - Drilling Hazards and Risks: The Kuparuk reservoir sands are pressured to 10.5 ppg in the MPJ- 09 injector which is located in the same fault bi;ack as the proposed MPJ-20 well. The MPJ-09 injector has been shut-in and is currently being bled back as production Facility process capability allows. By the time the Rig moves to the MPJ-20 location ,on or about 11/13/95, the anticipated reservoir pressure is expected to be below the 10.5 ppg EMW noted above. Pressure "bombs" will be run as often as necessary to monitor BHP to ensure the listed BHP is no greater than noted above. An IHR Gyro will be run in the first 1500' out of the 9-5/8" surface casing shoe to ensure the target is reached as per the directional plan. 2. The kick tolerance for the 10.5 ppg pore pressure case with 11.0ppg mud weight is lOObbls. This is calculated using a 0.39 psi/ft gas gradient for the Milne Point Kuparuk Crude with a 600 GOR. Discuss the MPJ-09 pressure status and this kick tolerance at the pre-reservoir meeting before drilling into the Kuparuk reservoir -- and perform a Flow Check after penetratin~l each of the Kuparuk A3, A2, and A1 sands. 3. Gas hydrates: From the 7 wells drilled by Nabors 22E in 1994, 1995 hydrates are not present on J Pad. However, in the event hydrates are encountered follow the guidelines outlined on the MPI Pad Data Sheet. 4. No other drilling hazzards or risks have been identified for this well. CASING SIZE: 9-5/8" MPJ-20 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON CIRC. TEMP 50 deg F at 2500' TVDSS. SPACER: 75 bbls fresh water. LEAD CEMENT TYPE: ADDITIVES: Retarder WEIGHT: 12.0 ppg APPROX #SACKS: 61 7 Type E Permafrost YIELD:2.17 ft3/sx MIX WATER: 11.63 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. TAIL CEMENT TYPE: ADDITIVES: 2.0% CaCI2 WEIGHT: 15.8 ppg APPROX #SACKS: 250 FLUID LOSS: 100-150 cc Premium G YIELD:l.15 ft3/sx MIX WATER: 5.0 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. FREE WATER: 0 TOP JOB CEMENT TYPE: Permafrost E ADDITIVES: Retarder WEIGHT: 12.0 ppg APPROX NO SACKS: 150 YIELD:2.17 ft3/sx MIX WATER: 11.63 gal/sk CENTRALIZER PLACEMENT: 1. I Bowspring centralizer per joint of 9-5/8" casing on bottom 15 joints of casing (15 required). 2. Place all centralizers in middle of joints using stop collars. OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacedmud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 12 bpm. Mix slurry on the fly--batch mixing is not necessary. CEMENT VOLUME: 1. The Tail Slurry volume is calculated to cover 618' md above the 9-5/8" Casing Shoe with 30% excess. 2. The Lead Slurry volume is calculated to cover from the top of the Tail Slurry to 1500' md with 30% excess and from 1500' md to surface with 100% excess. 3. 80'md 9-5/8", 40# capacity for float joints. 4. Top Job Cement Volume is 150 sacks, ~,., ',¢,'" ~.,i, MPJ-20 Well 7" PRODUCTION CASING CEMENT PROGRAM- HALLIBURTON STAGE I CEMENT JOB ACROSS THE KUPARUK INTERVAL: CIRC. TEMP: 140° F BHST SPACER: 20 bbls fresh water . 170 deg F at 7040' TVDSS. 70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0 ppg above current mud weight. CEMENT TYPE: Premium G ADDITIVES: 0.2% CFR-3, 0.1% HR-5, 0.4% Halad 344 WEIGHT: 15.8ppg YIELD: 1.15 cu ft/sk MIX WATER: 5.0 gal/sk APPROX # SACKS: 220 THICKENING TIME: 3 1/2 - 4 1/2 hrs @ 140° F FLUID LOSS: < 50cc/30 min @ 140° F angle. FREE WATER: 0cc @ STAGE II CEMENT JOB ACROSS THE SCHRADER BLUFF SANDS: 45 degree CIRC. TEMP: 60° F BHST 80° F at 3970' TVDSS. SPACER: 20bbls fresh water. 70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0 ppg above current mud weight. ~ ~ ~ LEAD CEMENT TYPE: ADDITIVES: Retarder Type E Permafrost YIELD:2.17 ft3/sx WEIGHT: 12.0 ppg MIX WAT E R ;' ')-i:'."6;¢3~.~lr/as~ APPROX #SACKS: NONE THICKENING TIME: Greater than 4 hrs at 50° F. TAIL CEMENT TYPE: Premium G ADDITIVES: 0.2% CFR-3, 0.2% Halad 344 WEIGHT: 15.8ppg YIELD: 1.15 cu ft/sk MIX WATER: 5.0 gal/sk APPROX # SACKS: 242 THICKENING TIME: 4 hours @ 50 FLUID LOSS: 100-150 cc FREE WATER: 0cc @ 45 degree angle. CENTRALIZER PLACEMENT: 1. 7" x 8-1/4" Straight Blade Rigid Centralizers-- two per joint on the bottom 18 joints of 7" Casing (36 total). This will cover 300' above the C1 Sand. 2. Run one 7" x 8-1/4"Straight Blade Rigid Centralizer above and below the 7" ES Cementer (2 Total). 3. 7" x 8-1/4"Straight Blade Rigid Centralizers-- two per joint from OB Base Sand to 200' above the NA Sand (44Total). 4. Run two 7" x 8-1/4"Straight Blade Rigid Centralizer inside the 9-5/8" casing shoe. 5. Total 7"x 8-1/4"Straight Blade Rigid Centralizers needed is 84. OTHER CONSIDERATIONS' Perform lab tests on mixed cement/spacer/mud program and ensure compatibility prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 8-10 bpm. Batch mixing is not necessary. CEMENT VOLUME: 1. Stage 1 cement volume is calculated to cover 1000' md above the Kuparuk Target Sand with 30% excess. 2. Stage 2 cement volume is calculated to cover from the OB Base to 500' above the NA Top with 30% excess. ~6 '95 02:1£PM SHARED SERVICES DRILLIMG TO .. SEA ~8~ ~,5/~oo ' t~o ~, ~6 ~ ' ' ~ ' ' ' , DROP ~/~O0 T~f ' ' TD tt~ i 744~ · 44~3 DRAWN ...... ; ~[/05/g5 , , ,. : ,~ , ~ ~ .. ~ ,--, _~ m _ ,,. . . ,, ' ~ ; A~A-DPC :' , : A~ ACR1LL' , ~ , ~ -, ~~- ,~, ,. , :' ' ~ % lOT ' .~ i ~ ~ 'APPI~OVi~D; F,}R ', ~i ' q~"- ' '~ "'""'qJ - I ' ' ~ ' ~ : I, . ~.' ...... _.__, : : ~,.,~ , . .. ~ I ' I I I ' ~ ' ' ' I ~ ' I i , : ' i ' . ' " ~ i ' ~ ' I -. ,, ', ~ : ', , ,_. .. , ~ ~ :" I , . ,, ,, . 7;0~ 6BOO ;OOO ~O0' m~ 4ao~ ~¢oo 3000 2a~, ~aoo ~2oo ~o ':: ¢' ' ~, , , ~ ~V ,";.~': .~.,.', , ' "'" i "' " ' ' ' ~995 ' , , , ,, : ' ' ''. '-" 0 A&~s~ 0;~ & Gas Cons. Commbsbn Anchorage .!:'-- _'--SHARED,.SER¥ICEs DR~LI~-.IN'G" - i~ i i iiii _ i~1 [) {flOP ~ ~ 5eO~ 7219 61.~ TVD Scale · I inch = I60Q feel ~ T~[ m~m ~5 ~L ~.~ Draun · ~S/06/~ Zl r' ~S(NSPO~T It~6. 7~ ~66 ~.~ ...... i . ~ · 8 a ' ~ ; F1 · '1 I/~'- El _----I -- -- iii I I - = ~m,~ i I III 2~11_, _~' '(P 31' " ,,.T~ ,,~ ~ ~,, ~.oo VERTICAL SECTION':VIE'~"" ·, ~ ' i ' .; ' BeD Scale,: ~. ~nch'-'EO0 fee~., , ;~' ~' '" ' I '~ DPawn ..... · ~/06/95~ ,~ _~ , , ,---~,,,~ ~ _ .' j ~ . ,: ' ~ ~ ~ i · '~ : ' ,;~00 ~ -~ - ~ ' ' "j - ' '~, r . , , ,. ~x ', . . . ~ ~ ' ~ i:. ~ ' " ......... ~ ,, '' ' .' & , . , ' '.2 . , ... ~.~~,, .... ~.~.,~ ......... . _.., '[ ~ ~ ~ '~, , ~aO~,,, , , , .... ' .... "'~' ~ ' :Z__: ' I - ~ , , , , ' ';'L , ,~.~ ................. ,....... ...... ~ ........... : ~ ............. ~ ...... ~.-. ;7t0C ..~,o~ ', ~ ~ ,~ , ' -- I i ~__ , ~ X~' , ..., . : ,~~'~ . Z~ ' ' ~ ~ I [ ~ I ~ . ,.,~ L ' =,- ,~ i ,' ~ ~ ~~ ,, , Alaska Ud & Ga Cons. domm~ss~)~ i ~ ~ I , , I' ~ , ~60~ , ~~ ~~ _ ' , ,, -__ 7600 7700 ~O_ ~gOO :8~0 8~00 8~00 a~o i~4gO ~O0 ~600 .87~ ~oo, ~ 8gOD ., ,...~, , se~t uep, e~:ure ,, ,~, , : WELL PERMIT CHECKLIST Poo , ,_ .C'.2__ ,5'./o.o . ADMINISTRATION ,PR lo 2. 3. 4. 5. 6. ~ 7. 8. 9. '[2. 13. Permit fee attached .................. ~ N Lease number appropriate.. ~ N Unique well name and number .............. ' N Well located in a defined pool.'.'.'.'.'.'.'.'.'.'.'... N Well located proper distance from drlg unit boundary...Y N Well located proper distance from other wells ..... N Sufficient acreage available in drilling unit ...... Y N If deviated, is wellbore plat included ........ N Operator onl~ affectsd party ............... Y N Operator has appropria~e bond in force ........ N Permit can be issued without conservation order .... N Permit can be issued without administrative approval. N Can permit be approved before 15-day wait ....... N ENGINEERING dev~ rsdrll [] serv [] ON/OFF SHORE d2~J GEOLOGY 14. Conductor string provided ............... ~ N 15. Surface casing protects all known USDWs'. ....... .~ N 16. CMT vol adequate to circulate on conductor & surf osg. ~ N 17. CM~ vol adequate to tie-in long string to surf csg . . 18. CM~wil! cover all known productive horizons ...... ~ N 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 22. Adequate wellbore separation proposed .......... ~ N 23. If diverter required, is it adequate .......... 24. Drilling fluid program schematic & equip list adequate .~ N 25. BOPEs adequate ............. ~ ....... %~ N 26. BOPE press rating adequate; test to 5~ psig.~ N 27. Choke manifold complies w/API RP-53 (May 84) ...... 28. Work will occur without operation shutdown ....... (~) N 29. Is presence of H2S gas probable ............ ~ N / 30. Permit can be issued w/o hydrogen sulfide measures .... Y N presented on potential overpressure zones ..... Y 31. 32.. Seismic analysis gf shallow gas zonesData .......... 33. Seabed condition survey (if off-shore) ....... J Y N 34. Contac'. name/phone for weekly progress repo~s . ./.. Y N [exploratory only] GEOLOGY: ENGINEERING: COMMISSION: Comm,_uts~Instructions: z o