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196-038
Ot'4 oR BEF ORE c..~o~V~Doc · PERMIT 96-038 96-038 96-038 96-038 96-038 96-038 96-038 96-038 96-038 AOGCC Individual Well Geological Materials Inventory Page: 1 Date: 03/12/98 DATA T DATA PLUS RUN RECVD DIR SRVY DIR SRVY DGR/CNO/ROP-MD DGR/CNP-TVD L3~'SPERRY 0-15077 ~GYRODATA 0-9038 ,~- MWD 8500-15070. ~M-WD 5072-8220 ROP/DGR/EWR4 -MD ~/200-15070 . DGR/EWR4 -TVD 7988 MUD -MD MUD -TVD ~200-8220 201.5-15077 Q~ ~. Gi~//i//';/Y~//:q::~' '" SPERRY 112-15077 SPERRY 220-8265 05/24/97 05/24/97 06/05/97 06/05/97 FINAL 06/05/97 FINAL 06/05/97 06/10/97 07/02/97 07/02/97 10-407 ~ COMPLETION DATE 3/[~ / ~/ 3-/2 ~//~ / DAILY WELL OPS R ~/~7/~/ TO 3//{ /~6 / )~/~°?/F~/ Are dry ditch samples required? ~ no And received? ~~no Was the well cored? yes ~~Analysis & description received? Are well tests required?~ lyes Well is in compliance Initial COMMENTS At'n: BP EXPLORATION, Alaska Howard Okland Alaska Oil and Gas Conservation Commission (907) 279-1433 P ETROTECHNICAL ATA C ENTER Date: Trans# 07/02/97 ~ 87156 CONFIDENTIAL DATA MILNE POINT UNIT / NMILNE-02 Sw Name Rec Type Date Job I~'" Company Comments ' NMILNE-02 OH 03/02/96 AK-MM-960310 SPERRY COMBINATION MUDLOG (MD) NMILNE-02 OH 03/02/96 AK-MM-960310 SPERRY COMBINATION MUDLOG (TVD) ,, Enclosed are the materials listed below. If you have any questions please contact me in the Petrotechnical Data Center at (907) 564-5929. Please sign and return one copy of this transmittal. Th-~,nk-you, ,~ ........ -. ..' ', David W. Douglas Petrotechnical Data Center Received By: Petrotechnical Data Center, ~B3-3 000 fiast Benson Boulevard, ~.0. Box 10~12, ~nchora~e, ~laska 00510-~12 p ETROTECHNICAL BP EXPLORATION, Alaska ATA C ENTER Date: 06/05/97 Attn: Howard Okland Trans# 87156 Alaska Oil and Gas Conservation Commission (907) 279-1433 CONFIDENTIAL DATA MILNE POINT UNIT / NMILNE-02 ~ ~ '- ~ ~ (~ , , , , Sw Name Rec Type Date Job Id Company Comments NMILNE-02 OH I,~;' ~ '~ ' 'r~" :~ ' 03/13/96 AK'MM'960310 SPERRY MWD (MD) DUAL GAMMA RAY/COMPENSATED NEUTRON "' NMILNE'02 ' OH ~,.~'~: .... 03/13/96 AK'MM'960310 SPERRY MWD (TVD) DUAL GAMMA RAY/COMPENSATED NEUTRON NMILNE'02 OH' /~'~7 V 03/13/96 AK'MM'960310 SPERRY MWD (MD) DUAL GAMMA RAY/ELECTROMAGNETIC WAVE RESISTIVITY' EWR4 NMILNE'02 OH ~' 03/13/96 AK--MM'960310 SPERRY MWD (TVD) DUAL GAMMA RAY/ELECTROMAGNETIC WAVE RESISTIVITY' EWR4 NMILNE'02 DISK 03/14/96 SPERRY 1 EA' IBM FORMATTED 3'5" DISKETTE W/ BP LABEL: CONTAINS SELF EXTRACTING zIP FILE (NMILNE02'EXE) LAS FORMAT ' GR/RES/NEUT Enclosed are the materials listed below. If you have any questions please contact me in the Petrotechnical Data/~/~jar at (907) 564-5929_ i ,. // ~4e~se sign and ret_urn one copy of this transmittal. ,..,,, ~,~ ..., ~ Receive~ By: · JUN 05 199! David W, Douglas ,~a~x~ a.i ~ ~ r- ~. Petroteohni~al Data Oenter ~etrote~ic~l ~ta Center, ~B~-~ ~00 ~ast Be.so. Bo.levard, ~.O. Box 196~12, ~nchorage, ~laska ~1~-661~ PLUGGING LOCATION CLEAR qCE REPORT State of Alaska .ALASKA 0IL & GAS CONSERVATION COMMISSION Memcrandum To File: APi No. Well Name Operator -- Location Abnd Date Spud: $]LIgG , TD: 5/;319G , Completed ! Note casing size, wt, depth, cmt vol & procedure. Liner Perf intervals - tops Review the well file, and-comment on plugging, well head status, and location clearance - provide loc. clear, code. Plugs: '~zo ~ c~ 6 ~ I~0~S "~ ~/~ ~V ~ ~%~o'~ ~o 5~ 5~ %. ~o S~ - I Well head cut off: Marker 'post or plate: Location Clearance: Conclusions Code Signed Date STATE OF ALASKA ALASK~ OIL AND GAS CONSERVATION Ct..,MMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG !.' Status of Well Classification of Service Well [] Oil [] Gas [] Suspended [] Abandoned [] Service 2. Name of Operator 7. Permit Number BP Exploration (Alaska) Inc. 96-38 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612 50-029-22653 4. Location of well at surface 9. Unit or Lease Name 2045' NSL, 2700' WEL, SEC. 17, T14N, R10E ~,..;.~%~'~'~.q~;~sil Milne Point Unit At top of productive interval'~ '"' -'~~i ~----. ,~:~'""~' ! 10. Well Number 5068' NSL, 2124' WEL, SEC. 22, T14N, R10E ~_.,~.~"/~'~/i North Milne Point #2 At total depth !-, ~I ..... 5039' NSL, 2252' WEL, SEC. 22, T14N, R10E ~ ~ ~.. ~_.'. ....~ 11. Field and Pool Milne Point Unit / Kuparuk River Pool 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. KBE = 35'! ADL 355016 12. Date Spudded 113. Date T.D. Reached 114. Date Comp., Susp., or Aband.ll5. Water depth, if offshore . 16. No. of Completions 03/02/96 03/13/96 03/18/96 Natural Island MSLJ Zero 17. Total Depth (MD+'I'VD)118. Plug Back Depth (MD+TVD)I19. Directional Surveyl20. Depth where SSSV set~21. Thickness of Permafrost 15077 8265 F~ 70 70 F'r] ~Yes I-1No I N/A MD! 1700' (Approx.) 22. Type Electric or Other Logs Run All LWD logs. 12-1/4" hole GE/RES & 8-1/2" hole GR/RES/NEU/DEN 23. CASING, LINER AND CEMENTING RECORD CASING SETTING DEPTH HOLE SIZE VV'r'. PER FT. GRADE TOP BOTTOM SIZE CEMENTING RECORD AMOUNT PULLED 30" 234# X 34' 110' 30" Driven 11' 20" 94# H-40 31' 147' 24" 525 sx P F 'C' 13' 9-5/8" 40# L-80 29' 5339' 12-1/4" 1575 sx PF 'E', 250 sx 'G', 150 sx PF 'E' 31' 24. Perforations open to Production (MD+TVD of Top and Bottom 25. TUBING RECORD and interval, size and number) S~ZE DEPTH SET (MD) PACKER SET (MD) N/A (7" casing not run, well P & A) N/A N/A N/A MD TVD MD TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED N/A N/A 27. PRODUCTION TEST Date First Production IMethod of Operation (Flowing, gas lift, etc.) N/A I N/A Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SI'ZE I GAS-OIL RATIO N/A TEST PERIOD · N/A N/A N/A N/AI N/A Flow Tubing Casing Pressure CALCULATED . OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (CORE) Press. N/A N/A 24-Hour RATE N/A N/A N/A N/A 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. None ORIGINAL RECEIVED MAY ?_ 4 1996 ~!:~.I~ Oil & Gas Cons. Commission Form 10-407 Rev. 07-01-80 Anchorage Submit In Duplicate Geologic Markc 30. Formation Tests Measured True Vertical Include interval tested, pressure data, all fluids recovered Marker Name Depth Depth and gravity, GOR, and time of each phase. Kuparuk Sand Top 14868' 8104' N/A Miluveach Shale 14980' 8190' TD 15077' 8265' 31. List of Attachments Summary of Daily Drilling Reports, Surveys 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed~--~----'~'~~-~'~'~ _ Title ,,,,~, ~"~'~"lr"~c.. ~,C~,,,~. Date ~'/Z ~/c~.l~ Prepared'~ Name~mber Joe Polya, 564-5713 INSTRUCTIONS GENERAL: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. ITEM 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. ITEM 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. ITEM 16 AND 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. ITEM 21: lndicatewhether from groundteveF(GL) or other~levation (DF, KB, etc.). ITEM 23; Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 27.' Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, Other-explain. ITEM 28: If no cores taken, indicate 'none'. Form 10-407 Rev. 07-01-80 RECEIVED MAY 2 4 1996 Alaska 0il & 6as Cons. Commission Anchorage SUMMARY OF DALLY OPERATIONS SHARED SERVICES DRILLING -.BPX ! ARCO Well Name: N. Milne Rig Name: Nabors AFE: Point #2 22 E Accept Date: 02/27/96 Spud Date: 02/29/96 Release Date: 337005 03/18/96 02/27/96 MIRU. RIG ACCEPTED @ 1600 HRS., 12/27/95 02/28/96 FINISH MIRU. REPAIR ANCHOR PIN FOR WHEELS, BERM UNDER ALL COMPLEXES. PU TOP DRIVE, BOLT TO DERRICK, STAB IN MAIN SHAFT, LOCK IN LINK PIN ASSY. WORK ON COUNTER BALANCE SYSTEM. 02/29/96 RU TOP HALF OF TOP DRIVE, EQUALIZER RAMS. RU LOWER HALF OF TOP DRIVE, SERVICE LOOPS, WIRE ALL BOLTS. INSTALL SAFETY VALVE ACTUATOR, INSTALL PIPE HANDLER, INSTALL LOWER TIW VALVE & SAVER SUB, INSTALL MUD HOSE & BLOWER HOSE. FUNCTION TEST ALL TOP DRIVE ELECTRICAL CIRCUITS & ASSIGNMENTS. INSTALL ELEVATOR LINKS, 5" ELEVATORS, PU BHA TOOLS, ALIGN TOP DRIVE TO HOLE, INSTALL SKATE RAILS. CUT 156 OF DRLG LINE. INSTALL MOUSE HOLE, PU HWDP & PREPARE TO RIH W/26" BIT. 03/01/96 PU 26" BIT, PU HWDP, RIH TO 68'. UNABLE TO GET BELOW DUE TO EGG SHAPED DRIVE PIPE. POOH. PU 24" AUGER, ROTOTE TO GET PAST 70' TO 75'. CLEAN CUTTINGS OUT OF CELLAR & CUT OFF 30". AUGER F/110' T/112', HARD AUGERING, CU'I-I'ING 12-6" EACH TRIP, FULL AUGER. LD SUBS & 1 JT HWDP, LD AUGER. CLEAN CUTTINGS OUT OF CELLAR. RUN & WELD 20" CONDUCTOR. CUT EYES OF 20", LD ON BOTTOM. CEMENT CONDUCTOR W/CLASS C, HAD COMMUNICATION WITH INNER ANNULUS. RAN 1" WITHIN 10' OF BOTTOM TO CEMENT & DUMPED 5 SX DOWN ANNULUS & INSIDE. WELD ON BASE. PLATE & DIVERTER RING. 03/02/96 ASSIST WELDERS W/20" LANDING RING, RU STABBING BOARD, LADDER, STRING GEOLOGRAPH LINE. PU 30 STDS DP, MIX SPUD MUD, WELD OUT LANDING RING. LOAD PIPESHED W/G PIPE, PUT ANNULAR IN CELLAR. NU DIVERTER, 20" HYDRIL & LINES. TEST DIVERTER & GAS ALARMS. JOHN SPAULDING W/AOGCC PRESENT. PU 8 STDS HWDP & STD BACK. PU BHA & BIT. CIRC SYSTEM & CHECK FOR LEAKS. DRILL CEMENT F/34' T/90'. 03/03/96 DRILL CEMENT F/90' T/112', CIRC & SWITCH TO MUD. DRILL F/112' T/274'. POOH, PU BHA, ORIENT MOTOR TO MWD, RIH. DRILL F/274' T/354'. CHANGE OUT Page PULSATION DAMPER BLADDERS ON BOTH PUMPS, CLEAN OUT SUCTION DAMPERS ON BOTH PUMPS. COULDN'T GET SURVEYS. DRILL F/354' T/1558'. 03/04/96 DRILL T/1744'. DRILL F/1744' T/2200'. REPAIR DRAG CHAIN. DRILL F/2200' T/2500'. CIRC HI/LO VIS SWEEP AROUND. POOH T/266'. RIH, PU DP. OK. DRILL F/2500' T/2794'. DRILL F/2794' T/4211'. DRILL F/4211' T/4494'. 03/05/96 DRILL F/4494' T/4963'. CIRC HI/LO SWEEP~. POOH, CHANGE BIT, 2 STB SLEEVES, JET IN MWD, RIH PU DP. SERVICE CROWN & TOP DRIVE. RIH T/4963'. DRILL F/4963' T/6029'. DRILL F/6029' T/6219'. 03/06/96 DRILL F/6219' T/6500'. CIRC HI/LO SWEEP. POOH T/4900'. RIH, PU 45 JTS G PIPE. OK. DRILL F/6500 T/6986'. DRILL F/6986' T/7459'. DRILL F/7459' T/8525'. 03/07/96 CIRC SWEEPS AROUND. POOH T/HWDP. OK. SLIP & CUT DRILL LINE. CHANGE OUT SAVER SUB. TIH. PUMP HI/LO VIS SWEEPS. COND MUD TO RUN CASING. MONITOR WELL, PUMP DRY JOB & BLOW DOWN TOP DRIVE. POOH. DOWNLOAD LWD & LD BHA. PU CASING TOOLS. RU 10-3/4" ELEVATORS & CHECK TORQUE ON FMC MUD LINE HANGER. RD. RUN 9-5/8" 40# L-80 BTC CASING. 03/08/96 FINISH RUNNING & LAND 9-5/8" CASING WITH ML HANGER. RU & CIRC/COND MUD. FULL RETURNS. TEST LINES. PUMP 75 BBLS WATER, MIX & PUMP 1575 S× CLASS E, TAIL WITH 250 SX CLASS G, DISPLACE WITH RIG PUMPS. BUMP PLUG 3000 PSI. FLOATS HELD. CIP @ 1730 HRS. LD CEMENT HEAD, RD CASING EQUIP, RU TO PUMP TOP JOB. FLUSH ANNULUS WITH 40 BBLS WATER & PUMP 150 SX CLASS E TOP JOB CEMENT BACK. RD HOWCO. OPEN PORTS ON MUD LINE HANGER & FLUSH ANNULUS WITH TREATED WATER. CLOSE PORTS. TORQUE TO 4000# & TEST CASING. ND 20" DIVERTER & MAKE ROUGH CUT ON 10-3/4" CASING. REMOVE 20" DIVERTER FROM CELLAR. SET SLIPS ON 10-3/4" CASING. MAKE FINAL CUT ON 10-3/4" CASING. WELD ON ADAPTER BUSHING. 03/09/96 FINISH WELDING ON HEAD & TEST. MU STARTING HEAD & TUBING SPOOL TO ADAPTER. SET BOP STACK ON SPEED HEAD & TEST METAL TO METAL SEALS. OK. NU-B-OP STACK, INSTALL FLOWLINE & TURN BUCKLES. INSTALL TEST PLUG & TEST BOPE. TEST WITNESSED BY DOUG AMOS W/AOGCC. REPLACED DOOR SEAL ON TOP RAMS & REBUILD DART VALVE. PULL TEST PLUG & INSTALL LONG WR. BLOW DOWN CHOKE LINES. SERVICE TOP DRIVE. CHANGE OUT SWIVEL PACKING. PU BHA #4. ORIENT & TEST MWD. LOAD SOURCE IN LWD. TIH, PU E & G DP. 03/10/96 FINISH PU DP & TIH. TAG FC @ 8418'. RU HOWCO & TEST CASING. OK. DRILL FC, CEMENT, FS & 10' NEW FORMATION T/8535'. CBU. PERFORM LO'~I~(iDY~[~E~. I~EL.E! V EIJ Page 2 MAY 2 4 '1996 Naska 0il & Gas Cons. Commission Anchorage DRILL 8-1/2" HOLE F/8535' T/9871'. CIRC SWEEPS AROUND. BLOW DOWN LINES. SHORT TRIP TO SHOE BEFORE RUNNING GYRO. 03/11/96 RU ATLAS & RUN GYRO F/9100' TO SURFACE. RD. DRILL 8-1/2" HOLE F/9871' T/12057'. 03/12/96 DRILL 8-1/2" HOLE F/12057' T/12627'. CIRC LO/HI SWEEPS AROUND. MONITOR WELL. POOH 30 STDS TO 9813'. OK. SERVICE TOP DRIVE & CROWN. TIH. PU 30 JTS S DP. DRILL 8-1/2" HOLE F/12627' T/13757'. 03/13/96 DRILL 8-1/2" HOLE F/13757' T/14135'. CIRC LO/HI VIS SWEEPS AROUND. MONITOR WELL. PUMP PILL. POOH TO CASING SHOE. WORK THRU TIGHT SPOTS. BOP DRILL WHILE TRIPPING. SERVICE TOP DRIVE & CROWN. SLIP & CUT DRILL LINE & CHANGE OUT SAVER SUB. TIH. OK. PU 15 JTS S DP. DRILL 8-1/2" HOLE F/14135' T/14886'. 03/14/96 DRILL 8-1/2" HOLE F/14886' T/15077'. CIRC & COND MUD. PUMP SWEEPS AROUND. MONITOR WELL. POOH T/MWD. UNLOAD SOURCE & DOWNLOAD TOOLS. FINISH LD BHA. CLEAR RIG FLOOR, CHANGE OUT BAILS. MU MULE SHOE & TIH T/15075'. MU CIRC HEAD & CBU. MIX & PUMP 220 SX CLASS G. DISPLACE & SPOT BALANCE PILL WITH RIG PUMP F/15077' T/14200'. POOH 10 STDS. CBU. POOH LD DP. 03/15/96 POOH LD DP. MU 9-5/8" EZSV & TIH T/8420'. SET EZSV. MIX & PUMP 100 SX CLASS G, DISPLACE W/RIG PUMPS. PUMP 80 SX BELOW EZSV & SET 40 SX BALANCED PLUG ABOVE EZSV. PULL 3 STDS & CBU. TEST PLUG T/2000 PSI. WITNESSED BY LOU GRIMALDI W/AOGCC. POOH. LD 19 STDS DP. PU 9-5/8" DP. MU 9-5/8" EZSV & SET SAME @ 315'. MIX & SPOT 50 SX CLASS E ON TOP OF EZSV @ 315'. POOH TO 70' & CIRC HOLE CLEAN. CLEAR RIG FLOOR. PULL WR & ND BOPE. 03/16/96 MU 10-3/4" CASING SPEAR & STING INTO CASING. PULL CASING SLIPS & BACK OUT OF MUD LINE HANGER. LD SPEAR & CASING. NU 20" DIVERTER SPOOL ANNULAR& FLOWLINES. MU20"X30"CASING CUTTER. TIH TAGGED UP @ 37'. POOH AND CHANGE STAB F/18.5 T/17.5, TIH T/48' & CUT CASING. CHANGE BLADES FOUR TIMES. LD CASING CUTTER, BLOW DOWN TOP DRIVE & MUD LINES. DRAIN STACK. ND 20" HYDRIL & FLOWLINE. CLEAN OUT CELLAR & PREP TO PULL 20" & 30" CASING. 03/17/96 CUT LANDING RING & BASE PLATE OFF 20" CONDUCTOR. MU SPEAR AND STING INTO 20" CASING. PULL 20" AND LD SAME. REMOVE CEMENT FROM INSIDE CASING & MU 30" SPEAR. STING INTO 30" CASING. GRAPPLE WOULD NOT BITE. Page GRAPPLE SET TO CATCH 1" & 1-1/2" NOT 1/2" CASING. WELD 3/16 PLATE ON NOSE TO KICK GRAPPLE OUT. PULLED LOOSE AT 200,000. WELD ANOTHER 3/16 PLATE AROUND NOSE. STUNG INTO, WOULD NOT COME FREE. RU JACK HAMMER & REMOVE 2' OF CEMENT AROUND 30" INSIDE CELLAR. JAR ON 30" & PULL 475-500,000. WOULD NOT COME FREE. APPEARS NOT TO BE COMPLETELY CUT. RELEASE FROM SPEAR & LD SAME. MU 30" CUTTER & SPACE OUT TO RECUT @ 48'. PRESSURE UP TO OPEN KNOWVES & RECUT 30". 03/18/96 FINISH CUTTING 30" CASING. LD CU'I-rER,~& RIH WITH GRAPPLE. STING INTO 30" CASING. JAR & PULL. LD GRAPPLE & MU 30" STAB & REAM CEMENT INSIDE 30". MU NEW CUTTER WITH NEW BLADES. CUT 30" CASING. LD CUTTER & STAB. PU SPEAR & PULL 30" TO RIG FLOOR. CUT 30" OFF SPEAR & LD FISHING TOOLS. CLEAR CEMENT OFF FLOOR. JACK HAMMER CEMENT OUT OF CELLAR BOX, REMOVE CHICKEN WIRE & INSULATION. 03/19/96 PULL CELLAR BOX & BACKFIELD 30" HOLE & CELLAR BOX WITH GRAVEL. LEVEL LOCATION. RIG RELEASED @ 1400 HRS.,03/18/96. Page 4 ATMILNE02.tmp created Tue Jun 10 18:30:22 1997 by CLEANUP V1.0 ISL ISL Summary Listing - version 1.01 ISL ISL Date Processed - 10 JUN 97 ISL Input File Name - NMILNE02 ISL File 1 - File Header Information Reel Nbr - 1 Tape Nbr - 1 File Nbr - 1 LIS File Nbr - 001 Start - Stop Depth : Service Name - MINCOM Service Sub Name - MWD Origin of Data - File Type - LO Reel Comments - Tape Comments - 201.5 - 15077.0 (F) File 1 - Channel Listing Mnem NbrSamp NbrEntry ServID Stat InUnit OutUnit DEPT 1 1 MWD 01 ALLO F F FET 1 1 MWD 01 ALLO HR HR GR 1 1 MWD 01 ALLO API API NPHI 1 1 MWD 01 ALLO PCT PCT ROP 1 1 MWD 01 ALLO FTHR FTHR RPD 1 1 MWD 01 ALLO OHM/4 OHI~M RPM 1 1 MWD 01 ALLO OHMM OHMM RPS 1 1 MWD 01 ALLO OHM/~ OHMM RPX 1 1 MWD 01 ALLO OHMM OHI~I~ Start 201 500 -999 250 -999 250 -999 250 -999 250 3 779 3 200 2 409 1 749 Stop 15077 000 -999 250 -999 250 -999 250 100 263 -999 250 -999 250 -999 250 -999 250 File 1 - Comments Listing File does not contain any comments ID: ..~ Sp~RRY-SUN'DRILLING SERVICES COMBINED GYRO & MWD SURVEYS NORTHWEST M1LNE / NORTI{ MILNE PT #2 ~ ~~' . '%~.~., '.,' ; · .- 50~029-22653 ¢,9..~.:~' .,i~.,,~~ MEASURED ANGLE DIRECTION DEPTH DEG DEG IND.UU£ Page 19 MARCH, 1996 NORTI{ SLOPE 475.00 0.48 315.40 474.99 0.77 N 1.94 W 575.00 0.74- 328.39 574.99 1,62 N 2.57 W -2 675.00 0.72 334,17 674,98 2,73 N 3,18 W -3 ?75.00 1.05 335.39 774.9'! 4,13 N 3.84 W -4 875.00 1.26 346,10 '874,95 6,03 N 4.48 W -5 344.82 994,91 8,81 N 5,21 W 3,82 1074,89 10,65 N 5,42 W 36.77 1174.87 12.52 N 4.74 w 82.41 1274,83 13,60 N 2.17 W 90.55 1374.65 13.82 N 3.65 E 995.00 1.48 1075.00 1.21 1175.00 1,17 3275,00 2.26 1375.00 4.44 92,42 1474.20 13.55 N 13.09 E 97.47 1573.33 12.33 N 26.15 ~ 3.02.62 1671.71 9.10 N 43.72 E 305.06 1'768.93 3.44 N 66.44 E 2.05.25 1817.02 0.13 S 79.60 E 1475.00 6.40 1575.00 8.69 1675.00 11.91 1775.00 15.18 1825.00 16.48 104,86 1864.71 4.03 S 94.10 E ~.05.17 1912.02 8.21 S 109.71 E 105.67 1958.98 12.78 S 126.25 E 106.00 2005.57 17.74 S 143,72 E 106.50 2051,85 23,03 S 36~.88 E 1875.00 18.46 1925.00 19.26 1975,00 20.89 2025.00 21.71 2075.00 22,75 ~06.77 2097.77 28.70 S 180.84 E 106.88 2143,30 34.68 S 200.62 E %07,02 2188.42 40.96 S 221.23 ~ 106.93 2233.23 47.43 S 242.43 E 106.79 2277.68 54.07 S 264,34 E 2125.00 23.87 2~75,00. 24.96 2225.00 26.08 2275.00 26,56 2325.00 27,94 306,33 2321.62 60..87 S 287.22 E &06.30 2365.13. ( 67.-80 S 310.89 E ~06.07 2408.~4 74.90 S 335.34 E 105.37 2450.74 81.99 S 360,~ E 104.93 2492.82' 89.04 S 386.61 E 23';5.00 29.10 2425.00 30.01 2475.00 31.21 2525 . 00 31,95 2575.00 33.42 VERTICAL DOG SECTION ~EG .00 0.00 .11 0.28 .56 0.37 .10 0,19 ,52 0.07 .05 0,34 .85 0.29 ,67 0.08 ,60 0.33 ,62 0.30 -6.90 0.19 -7.49 0.65 -7.20 0,68 -4,91 1.67 0.75 2,23 10.04 ~.97 23.08 2.38 40.93 3.35 64,33 3.32 77.94 2.60 92,93 3.97 3.09,07 1.61 126.19 3.28 .1.44.31 1.66 163.17 2,11 ~82,88 2.25 203.47 2.18 224.93 2.24 247.01 0.96 269.81 2,76 293.60 2.36 318.19 1.82 343,57 2.41 369.69 1.65 396.65 2.98 2625.00 34.51 2675.00 36.07 2725.00 37.22 2775.00 38.30 282~.00 39.84 103,91 2534.29 96.00 S 413.66 E 103.08 2575.10 102,73 S 441,75 E 102.61 2615.21 109.37 S 470,85 E !02.23 2654.74 11~.95 S 500,75 E 102.15 2693.56 122,60 S 531.55 E 424.55 2.46 453.43 3,26 483.26 2.37 513.88 2,21 545.39 3.08 ID:907-659-4565 M~R 1~'96 4:16 NO.UU1P.13 SPERRY-SUN DRILLING SERVICES COMBINED GYRO & MWD SURVEYS Pase 20 10RTHWEST MILNE / NORTH MII~NE PT.92 30-029-22653 MARCH, 1996 NORTH SLOPE MEASURED ANGLE DIRECTION VERTICAL DEPTH DEG DEG DEPTH LATITUDE FEET DEPARTURE VERTICAL DOG FEET SECTION LEG 2875.00 40.68 ].01,96 273~.72 2925.00 42.43 ].01.94 2769.13 2975.00 43.24 101.73 2805.80 3025,00 44.59 101.82 2841.81 3075,00 45.39 101.~0 2_877.18 129 136 143 150 157 .35 S .22 S .]9 S .27 S .47 S 563.15 E 577.70 1.70 595.60 E 610,87 3.50 628.87 E 644,86 1.64 662.82 ~ 679.54 2.70 697.42 ~ 714.89 1.6] 3125.00 46.63 3375,00 48.20 3225.00 48.86 3275.00 .50.16 3325.00 51.11 3375.00 51.81 3425.00 52.64 3475,00 53.78 3525,00 55.12 3575.00 55.50 101.51 2911.90 164 101.39 2945.73 172 101.42 2978.85 179 10].40 5011.31 186 101.36 3'043.02 194 101.59 3074.18 202 101.79 3104.80 210 101,82 3134.75 218 101,72 3163.82 226 102.15 3192.27 235 .71 S .0] S .42 S ,94 S .57 S ,35 S .36 S .56 S .86 S .36 S 732.66 E 750 . 86 2 . 50 768.74 E 787 . 67 3 . 14 805,47 E 825.14 1,32 842.74 E 863.16 2.60 880.64 E 901,82 1.90 918.96 E 940.92 1.45 957.66 E 980.44 1.69 996,86 E 1020.49 2.28 1036.68 E 1061.16 2.69 1076,90 E 1102.28 1.04 3625.00 56.49 3696.00 57,74 3726.00 58,16 3776.00 60.~8 3826,00 60.61 102.30 3220.24 244 100.69 3247,93 252 100.67 3274.46 260 100,45- 3300.09 268 100,44 3324.79 276 .14 S .67 S .52 S .39 S ,27 9 1117,41 E 1159.38 E 1201,02 E ~ 243,23 E 1285.98 E 1143.72 2.00 1186.55 3.61 1228.92 0.84 1271.84 4.06 1315.30 0.86 3876,00 62.93 3926.00 63,21 3976.00 65.17 . 4026.00 65.51 4076.00 66.33 ~00,69 3348.44 284 100.87 3371,08 292 101.19 3392,85 301 101,72 3413.71 310 102.35 3434.11 319 ,35 S .68 S .30 S .32 S ,84 $ 1329.28 1373.07 1417,2~ 1461.79 1506.43 1359.34 4.66 1403.91 0.65 1448.92 3.96 1494.36 1.18' 1540,00 2.00'. 4126.00 66.65 4176.00 66.04 4226,00 66.28 4276.00 65.85 4326,00 67.15 102.55 3454.06 32R ]02.47 3474.12 339 ~02.35 3494.33 349 102,30 3514.61 359 302.40 3534.55 369 .72 .65 .47 ,23 .04 1551.20 1595'91 1640.58 1685.23 1730.02 1585,85 0.74 1631,65 1,23~ 1677,38 0.53 1723,08 0.86 1768,93 2.61 4376.00 67,89 4426,00 67.56 4476.00 67,99 4526.00 67.22 4576,00 67.52 102.54 3553,67 102.38 3572.62 102.34 3591.53 102.23 3610.58 3.01.53 3629'.82 379..01 388,'99 398.90 408,74 418.24 1775.13 E 1820.31 E 1865,52 E 1910,69 E 1955.85 E 18.1.5.12 1,50 1861,39 0.72 1907.67 0.86 19~3.90 1.55 2000,05 1.42 4626.00 67.34 4676.00 67.17 4726.00 66.89 4776.00 67.23 4826.00 69.69 '99.99 3649,01 99.58 3~68,34 99.68 3687.86 99 · 53 3707 . 34 99.48 3725.70 426 434 442 450 457 .86 S .70 S .40 S .08 S .76 S 2001.21 E 2046.21 2.87 2046.65 E 2092.29 0.83 2092.04 E 2138.29 0,59 2183.30 92 MAY ?. ~ 1996 Alaaka 011 & 9as Cons. Commission Anchorage ~:15 No.O01F.12 SPERRY-SUN DRILLING SERVICES COMBINED GYRO &MWD SURVEYS Pase 21 NORTHWEST MIi~NE / NORTH MILNE PT.#2 50-029-22653 MARCH, 1996 NORTH SLOPE MEASURED ANGLE DIRECTION VERTICAL DEPTH. DE~ DEG DEPTtt LATITUDE FEET DEPARTURE VERTICAL DOG FEET SECTION LEG 4876,00 69.50 99.40 3943 . 13 4926,00 70.24 99.24 3760.34 4976,00 69.80 99.12 3777.43 5026.00 69.84 99.20 3794 . 67 5076,00 69.31 99.29 3812_.12 465.44 473,05 480.54 488.02 495.5_4 2229.53 E 2277,60 0.41 2275.86 E 2324.50 1.51 2322.24 .E 2371,44 0.91 2368,58 E 2418.32 0.17 2414.82 E 2465.,13 1.07 5126,00 68.77 99,22 3830.01 5176.00 69,10' 99.32 3847,98 5226.00 68,94 99.30 3865.88 5276.00 69,65 99.18 3883,56 5326.00 69,06 99.31. 3901.19 5376.00 69,40 i00.27 3918,92 5426.00 69,62 101.44 3936.42 5476.00 69.43 i01.~9 3953.91 5526.00 69.77 101.50 3971.34 5576.00 69.25 101,59 3988.84 5O3. O5 S 510.57 S 518.12 S 525.63 S 533.15 S 541.10 S 549.92 S 559.22 S 568.55 S 577.93 S 2460.91 E 2511,77 1.09 2506,96 E 2558.38 0,69 2553,03 E 2605.03 0.32 2599,19 E 2651.75 1.44 2645.37 E 2698.49 1.20 2691,44 E 2745.21 1.92 2737,44 E 2792.04 2.24 2783.35 E 2838,88 0.38 2829.27 E 2885,74 0.68 2875.].6 E 2932.58 1.05 5626.00 69 . 76 101.62 4006.35 5676.00 69.21 101,63 4023 . 87 5726.00 69,19 101.43 4041.63 5776 . 00 68.85 I01,40 4059 . 53 b826 . 00 68 . 37 101 . 43 4077 . 76 587 596 606 615 624 .35 S .78 2 .13 S .39 S .58 S 2921.04 E 2979.42 1.02 2966.91 E 3026.24 1,10 3012.70 E 3072.98 0.38 3058.47 E 3119.67 0,68 3104.10 E 3]66.22 0,96 5876.00 68.47 101,47 4096.15 5926.00 67.66 101.53 4114.83 5976.00 67,79 101.92 4133.78 6026.00 67,03 102,04 4152.99 6076.00 67.05 101,96 4172.50 633 643 652 662 671 .81 S ,06 S .46 S ,04 S .61 $ 3149.67 E- 32]2.72 0,21 3195.12 E 3259.10 1,62 3240.42 E 3305,37 0,77 3285.58 E 3351.53 1,54 3330.61 E 3397.57 0.15 6126 , 00 67 . 70 102 . 05 4191,73 6176.00 69,04 102.01 4210.16 6226 . 00 69.64 102 , 21 4227.80 6276,00 69 . 26 102 . ].2 4245 , 35 6326.00 69.85 102 . 05 4262 . 82 681 690 700 710 720 .21 S .90 S .71 S .58 S ,39 S 3375,76 E 3443.72 1.31 3421.21 E 3490,20 2.68 3466.96 E 3536.98 1.26 3512,72 E 3583.80 0.78 3558.54 E 3630,65 1,19 6376.00 69.61 102,05 4280.14 6426.00 69.90 102.04 4297.44 6476.00 70.07 ~0'2.07 4314,56 6526.00 70.03 102,03 4331.62- 6576.00 70.72 102,08 4348.41 730 739 749 759 769 .18 S .97 S .78 S .59 S ,43 S 3604.41 E 3677.55 0.48 3650,28 E 3724.46 0.58 3696,23 E 3771.44 0.34 3742.19 E 3818.44 0.11 3788.25 E 3865.53 1,38 6626.00 70.1] 101,94 4365.17 6676,00 70.71 303.93 4381,93 6726.00 90.31 101.95 4398.62 6776,00 70.49 101,91 4415.39 6826.00 70.59 102.03 4432.05 779 788 798 808 818 .23 S .97 S .72 S .46 S .24 S 3834.32 E 3912.64 1.25 3880.41 E 3959.75 1.20 3926.53 E 4006.88 0.80 3972,61 E 40 . 0.37 o '. MAY P_ 4 1996 Alaska Oil & Gas Cons. commission Anchorage ~:15 NO,UU1 P.11 SPeRRY-SUN DRILLING SERVICES COMBINED GYRO & MWD SURVEYS NORTHWEST MILNE / NORTH MILNE PT.~2 50-02D-22653 Page 22 MARCH, 1996 NORTH SLOPE MF~AgURED ANGLE DIRECTION VERTICAL DEPTH DEG DEG DEPTH LATITUDE FEET DEPARTURE VERTICAL DOG FEET SECTION LEG 68?6,00 70.32 102.24 4448.77 6926.00 69.35 102.09 4466.01 6975.00' 68.29 102.08 4483.71 7025.00 68.59 102,41 4502.09 7075.00 68.42 3.02.39 4520,41 7125.00 68.60 102,45 '4538.72 7175.00 68,49 ' 102,78 4557.01 ?225.00 68.49 102.95 4575.35 7275.00 68.87 102,89 4593.52 7325.00 68.48 102.94 4~11,71 7375.00 68.76 103,01 4629.93 7425.00 68.46 103.09 4648.17 7475.00 68,43 103.21 4666.54 7525.00 68.20 103,39 4685,02 7575.00 67.94 103.24 4703.69 828.14 838,04 847.60 857.46 867.45 877.46 887.62 897.98 908.39 918,80 929.26 939.?? 950.35 961.04 971.72 4064.80 E 4148,25 0,67 4110.68 E 4395.38 ~.96 4155 , 36 E 4240 . 87 2 . 16 4200.80 E 4287,3'7 0,86 4246 . 24 E 4333 . 89 0 , 34 4291.67 E 4380,41 0,38 4337.08 E 4426,.94 0.65 4382,43 E 4473,45 0.32 4427.83 E 4520,02 0,77 4473.23 E 4566.59 0.79 S 45%8.60 E 4613,14 0,57 $ 4563.95 E 4659.68 0.62 S 4609.24 E 4706.17 0,23 S. 4654.45 E 4752.62 0.57 S 4699.59 E 4798.98 0.59 7625.00 67.77 3.03.33 4722,54 7675.00 67.36 %03.05 4741,62 7725.00 67.53. 102.96 4760,80 7775.00 67.22 %02.85 4780,05 7825.00 67.1D 103.02 4799,42 982,28 992.75 1003,14 1013,45 1023.77 4'744.68 E 4845.28 0.40 4789.69 E 4891.49 0.83 4834.68 E 4937.65 0.34 4879.66 E 4983.79 0.61 4924.59 E 5029.88 0.32 7875.00 67.09 102.91 483.8.84 7925,00 66 . 73 102.85 4838.45 7975.00 67.04 102.87 4858 , 08 8025 , 00 66 , 60 102 . 86 4877 . 76 8075.00 66.53 102.75 4897,65 1034,10 1044.36 1054.59 1064.82 1074,99 4969,49 E 5075,94 0.28 5014,33 E 5121,93 0.73 5059.16 E 5167.90 0.62 5103.97 E 5213.86 0.88 5148.70 E 5259.73 0.25 8125.00 66.07 102.60 4917.75 8175.00 65.59 102.57 4938.22 8225.00 65.86 102.46 4958.77 8275.00 65.37 102.39 4979.42 8325.00 66.01 102.33 5000.00 8375,00 65.47 102.16 5020.54 8425,00 66,03 102,17 5041.08 8475.00 66.86 102,07 5061,06 8525.00 65.90 102.04 5081.09 8575,00 66,25 102.24 5101.37' ~085,04 ~094.98 1104.85 3R14.65 ~24,41 1134.07 1143.68 1153.30 1162,87 1172.48 5193,37 E 5305,51 0,96 5237,89 E 5351,12 0,96 5282,39 E 5396.69 0.58 532~,8~ E 5442,23 0,99 5371,37 E 5487,79 1,28 5415,92 E 5533,38 1,12 5460.48 E 5578,96 1,12 5505.29 E 5624.80 ~.67 5550.09 E 5670.61 1.92 5594.77 E 5716,31 0,79 8625,00 65.48 101.71 5121.82 8675.00 65 . 56 101 , 31 5142 . 53 8725.00 65 . 03 100 . 86 5163 . 43 8775 . 00 67 . 62 100 . 74 5183 . 51 8825 . 00 67 . 95 100 . 57 5202 . 41 1183 .95 S 1191.03 S 11.99.77 S 1208.34 S 1216.90 S 5639,41 E 5761.94 1,82 5684.00 E 5807.44 0.75 5728.58 E 5852,86 1.34 5773.55 E 5898.64 5,18 5819.04 E 5944.92 0.73 '. RECEIVED MAY 2 4 199t~ fill A ~. Pnn~ P. nrnmi~_~inn ID:9Q_?-659-4568 MAR 1~'9~6 4:12 No.001 P.10 8P~.RRY-SUN DRILLING SERVICES COMBINED GYRO & MWD SURVEYS Page 23 NORTHWEST MILNE / NORTH MILNE PT.#2' 50-029-22653 MARCH, 1996 NORTH SLOPE MEASURED ANGLE DIRECTION VERTICAL DEPTH DEG DEG DEPTH LATITUDE FEET DEPARTURE VERTICAL DOG FEET SECTION LEG 8875.00 67.72 8925.00 68.42 8975.00 69.79 9038,00 69.39 9095.17 68.40 9190.10 68.53 9285.65 68,74 9381'.48 69.48 9476,99 69,13 9572.40 68.77 9667.90 68.24 9761.90 67.76 9859.48 67,43 9955.33 69,37 10051.06 69.33 100.20 5221.28 1225.25 100.05 5239.95 1233.40 99.91 5257.78 1241.50 99.78 5279.75 1251.59 98.29 5300.34 1259.97 96.28 5335,19 1271,17 97.54 5370.00 1281.87 99.18 5404,17 1294.89 101.55 5437.93 1310,96 100,?~ 5472.20 1328.20 100,50 5507.19 '1344.60 S 98.95 5542.40 1359.32 S 96,85 5579.60 1373.72 S 99,31 5614.89 1384.26 S 98.81 5648.65 1398.37 S 5864.59 E 5993.2~ 0.83 5910.25 E 6037.58 1,43 5956.25 E 6084.26 2.75 6014.43 E 6143.27 0.66 6067.10 E 6196.54 2.99 6154.68 E 6284.57 1,9.7 6243,02 E 6373.22 1.25 6331.59 E 6462,59 1,78 6419.47 E 6551.90 2.35 6506,83 E 6640.93 0.85 6594,16 E 6729.77 0.61 6680.06 E 6816,87 1,61 6769.41 E 6906.86 2.02 6857,63 E 6995.78 3.13 6946 , 09 E 7085,26 0,49 10146.92. 69.35 10242,60 69,14 10338.60 69.56 10433.32 69.17 10528.88 70,30 99.52 99.76 99.77 101.51 102.50 5682,47 5716.38 5750,23 5783.62 5816.71 1412.65 1427.63 1442.87 1459,24 1477.88 7034.64 E 7174.86 0.69 7122,85 E 7264.26 0.32 7211.38 E 7354.04 0.44 7298.50 E 7442.66 1.77 7386.18 E 7532,30 1,53 10624.69 70.11 10719.25 70.00 10813.54 69.42 10908.34 69.20 11003.53 68.57 I01 104 104 103 ]03 .97 .81 .25 .11 .38 5849.16 5881.42 5914.12 5947.63. 5981.91. 1496,99 S 1517.57 S 1539,76 S 1560.73 S 1581,08 S 7474.'28 E 7622.45 0.56 7560.74 E 7711.29 2.83 7646.35 E 7799.63 0.83 7732.52 E 7888.26 1.15 7818.95 E 7977.03 0.71 11098.39 68.1]. 11191.91 67.63 11285,70 66,94 11380.60 66.69 11476,00 68.42 ~05 101 102 103 106 .40 .63 .72 .86 .00 6016 6052 6088 6125 6162 .92 .16 .38 .74 .16 1602.98 1623,23 1641.47 1661.52 1684.25 7904.35 E 8065.10 2.04 7988.56 E 8151.67 3.77 8073,12 E 8238.18 1.30 8158.02 t~ 8325.39 1,14 8243,21 E 8413.42 2.76 11570.72 68.30 116.65,02 68.10 11759.72 67.98 11855,13 68,05 11949,31 67,36 12043,95 67.13 12138.33 66.69 12231.52 66.80 12326.55 67,01 12421.50 66.85 106 105 108 103 100 99 99 99 99 98 .52 .05 .67 .61 .36 .92 .59 .97 .78 .14 6197 6232 6267 6303 6339 6375 6412 6449 6486 6B23 ,08 .11 .53 .27 .00 .61 .62 ,42 .69 .90 1708,'90 S 1732,72 S 1758,19 S 1782.77 S .1.800.87 S ~816,23 S ].830.94 S 1845.49 S 1860.48 S 1874.08 S 8327.73 E 8501.20 0.53 8411,98 E 8588.55 1.46 8496.02 E 8676.02 3.55 8580,97 E 8764.20 4.92 8666,19 E 8851.32 3.28 8752.10 E 8938.56 0.49 8837,67 E 9025.32 0.57 8922.04 E 9110.89 0.39 9008,16 E 9198,25 0,29 9094.45 E 9285.50 1.60 ID:gQ=?-659-~568 M~R 1~'9_6 ~:11 No.O01 P.O9 .. SPERRY-SUN DRILLING SERVICES COMBINED GYRO & MWD SURVEYS Page 24 ~ORTHWEST MILNE / NORTH MILNE PT.#2 ~0-029-22653 MEASURED ANGLE DIRECTION VERTICAL LATITUDE DEPARTURE DEPTH PEG DEG DEPTH FEET FEET 12516,07 66,82 99,01 6561,11 1887.05 S 9180.42 E 12609.23 66,18 100.80 6598,26 1901,74 S 9264,58 E 12706.20 63.38 103.08 6639,57 1919.87 S 9350.39 E 12801.32 60.57~ 101.87 6684.26 3938.01 S 9432.36 E 12894-,43 58~46 102.46 6731,50 ~954.92 S 9510,80 E MARCH, 3.996 NORTH SLOPE VERTICAL DOG SECTION LEG 9372.30 0.85 9457.68 1,89 9545.39 3,59 9629.34 3,16 9709,57 2,33 12988,76 56.49 102,43 6782.21 1972.05 S 9588,46 13083,74 56.20 ' 100.76 6834,85 1987.95 S 9665,90 13177.22 55.96 101.16 6887.02 2002.69 S 9742.06 13272.34 53.87 103.11 6941.69 20]9,04 S 9818,15 13367.29 53.,44 105.49. 6999,29 2037,65 S 9891.29 13462.06 49,38 104.86 7059,68. 2056.78 S 9961,76 13558.35 47.83 102.16 7123.36 2073.67 S 10031,98 13649.14 46.14 102.84 7185.29 2088.03 S 10096.79 13743,77 44.55 102.26 7251.80 2102.66 S 10162.49 13837.57 42.90 102.28 7319,59 21-16.44 S 10225.84 9789.10 2.09 9868..16 1,50 9945,72 0.44 10023 . 54 2 . 76 10098 , 94 3 , 24 10~71,84 2,23 10244.03 2.65 10310.41 1.94 10377.73 1,74 10442.54 1.76 13932.28 41.19 101,67 7389,92 2129,60 S 10287.89 14028,49' 39,60 102,59 7463,19 2142.70 S 10348.84 14116.25 39,98 102.65 7530.62 2154.97 S 10403.65 14212,60 40.64 101.33 7604,10 2167,91 S 10464.62 14306,90 40.60 105.05 7675.68 2181.91 S 10524.37 10505.97 1,86 10568.31 1,76 10624.47 0,44 10686.80 1.12' 10748.15 2.57 14402,50 40,60 103.02 7748,27 2197,00 S 10584.72 14498.25 40.40 101.24 7821.09 2210.07 S 10645,51 14589.72 40.3~ 102.78 7890,79 2222.39 S 10703.44 14684.08 40.06 101,69 7962.88 2235.29 S 10762,94 14779.83. 39.87 100.86 8036.25 2247,32 S 10823,24 10810 , 31 1.38 10872,49 1.23 10931,71 1,09 10992 . 60 0.79 11054 , 08 0 . 59 14874,76 39.83 101.23 8109'15 2258.97 S 10882,96 149';0,43 39,59 102.39 8182.75 2271.48 S 10942,78 15077.00 39.59 302,39 8264.87 -2286.05 $ 11009.12 11114.92 0.25 11176.04 0.81 1~243,95 0.00 THE DOGLEG SEVERITY IS IN DEGREES PER 3.00.00 FEET THE VERTICAL SECTION WAS COMPUTED ALONG 10~,81~ (TRUE) BASED UPON MINIMUM CURVATURE TYPE CALCULATIONS. THE BOTTOM HOLE DISPLACEMENT IS i1243.96 FEET, IN THE DIRECTION OF 101.73~ (TRUE) SHORT COLLAR M~THOD USED AND THE FOLLOWING CORRECTION FACTORS APPLIED: TOTAL MAGNETIC FIELD STRENGTH ~ 57459 nT, DIP ANGLE = 80.70°. SURVEYS CORRECTED FROM MAGNETIC NORTH TO TRUE NORTH 28.100. SPERRY-SUN ENGINEERS: M, HANIK, B. ZIEMKE, M. WORDEN SURVEYS BELOW 9038'MD ARE MWD SURVEYS CORRECTED'BY -.1.23 DEGREES. A iS y r od at a Di'.,-e ct ;. o na ~ NORTH M!LNE POINT, WELL NO NM-2 NORTHWEST MiLNE, A~SKA Job Number: AKO396G330 ?un Pate: !O-Mar-% 0645 ~fve~,., TOM STODDARD Calculation Method: MIN!~dM CURVATURE Survey Lnk~tude:_. o70. =-=.~;3'~-~,~ deg. N Azimuth Correction: Gyro: Bearings are Relative to True North ...~.o~P~nnn~d Wei~. Dir~rtion:__ 101.810 deg Vertical Section Caicuiated from Well Head Location Ciosure Caicuiateo from Well Head Location Horizontal Coordinates Caicuiateo from Local Horizontal Reference B: P, E×PLORATiON NORTH k:ILNE POINT: Job NuBber-: ~K03968338 DEPTH DEPTH SEVERITY feet deg. deg. feet deg./ 100 ft. feet MST. AZIMUTH feet deg. 0.0 0.00 0.08 75.0 .21 243.39 175.0 .40 309.44 275.0 .27 285.49 375,0 .2I 277.42 0.0 0,88 75,0 .28 175.0 .37 275.0 .19 375.0 .07 ~.ON 0.0E .iS ,1W .IN .6W .AN i, iW .SN !,5W 0.0 0.0 . I 843.4 .b 278.2 i. 1 289.2 1.5 287.2 ~,~.B .48 315.40 ,~.0 ,74 328,39 675.0 .72 334. i7 775.0 t.05 875.0 i.26 346. i0 475.0 .34 .8 575.0 .29 !.6 ~/¢.0 .08 2.7 /¢~.0 .~¢ 4.1 874.9 .30 6.~ 1,9 2,6 3,2 3.8 4,5 2. i 291.7 3.(f: 302.2 4.2 310.6 5.6 317. I 7.5 323.3 995.0 ..' 48 344.82 1075.0 !.2i 3.82 !175.0 1.17 36.77 i275.0 ~.~ 82.41 i375.0 4.44 90.55 994.9 .i8 8.8 1074.9 .65 i0.6 ..... q .68 i2.5 i274,8 1.66 i3.6 i374.7 2.23 13.8 5.2: 5,4 4.7 - ,_ 3.6 10.2 il.9 13.4 13.8 14.3 329.4 333.~ 339.2 350.9 14.8 14/~.. ~ 6, 40 92.42 M70. ~ 8.69 97.47 1675.0 ii.9i i02.62 1775.0 i5. !8 i05. E~6 1825.0 i6.46 i05.25 i474.2 1.97 1573.3 2.39 i67i.7 3.35 i768.9 3.32 i8i7.0 2.59 i3.5 9. i 3.4 .i .,.'.. i E 26, i E 43, '? E 66,4 E 79,6 E !8,8 ;:'8, 9 e4,6 66, 5 --- . 44.~ 64,8 78, 3 87, (~ 90,: i875.0 18.46 104.86 i985.0 i9.26 105.17 i975.0 20.89 105.67 2025.0 21.7i !06.00 ~75,0 ~.'~' 75 106.~ i864.7 3,98 ,~o ~ 1.60 i959.0 3.28 2005.6 1.65 205i.8 2.13 4,0 8,2 12.8 t7.7 23.0 94. i 109.7 126.3 143.7 161.9 41 ~ i10.0 126.9 144.8 163.5 92. b 94, 3 95,8 97,0 98.1 2!25.0 23.87 i06.77 2175.0 24.96 i06.88 2225.0 co~"' 08 107.02 zc~¢.~ ~t,56 i~6.93 2325.0 27.94 i06.79 2097.8 2.24 28.7 S 2i43.3 2.18 34.7 S 2188.4 2.26 4!.0 S 2233.2 .96 47.4 S 2277.7 2.76 5~.i S 180, 8 242.4 264.3 183. 203. 247. 269. 99.0 99.8 100.5 101.* i01.6 2375.~ 29. i~ 106.~ 2485.0 3~.8i i06.30 2475.0 31.2t i06.07 ~¢~.~. 31.95 i05.37 257%0 33,42 184.93 8625.0 34.5! i03.9I 2675.0 36.07 103.08 2725.0 *" .... ' J~.d= 102.6! .2775,0 38.30 i02.23 2825.~ 39.R4 102.'= 23~i.6 ~.d~ 2408. i 2.42 2450.7 1.65 2492.8 2.97 2534.3 2.46 2575.! '3.27 26i5.2 8.35 265~,7 2,2i 2693.6 3. i0 60.9 S 67.8 S 74.9 S 82.0 S 89. I S 96.0 S 102.7 S 109.4 S 1i6.0 S i22.6 S 287.~ L 3i~.9 E 335,3 E 360,6 E 386,6 E 413,7 E 441.8 E 470.8 E 589.7 E 53i.5 E 293,6 102.0 o~.2 102.3 343. S 102.6 369.8 102,8 396·7 RECEIVED 424.'? 453.5 483.~ 5!4.~ 545, c 103.1 103.1 io,~lttska 0il & Gas Cons, Commission Anchorage 103.0 2875.0 40.68 i01,96 2731.7 i.70 2%5.0 42.% 18i.94 2769.1 3.50 !29, 4 S 1.%. 2 c ,_'.Od,, I ~. rTqc,. A g F"E~;kURFD i ~ C L AZIMUTH ,.:~T~ .... ~ ¥~_~,. bH~ DOGLEG DEPTH DEPTH SEVERITY feet deg. deg. feet oeg. / !8~ ft. HORI ........ zu,~, wc COORDINATES feet DiSL AZIMUTH feet deg. 2975,0 '43,24 101,73 3025,0 44,59 101,82 3075,0 45,39 10t,70 2805.8 i.64 2841.8 2.71 2877.2 1.60 14~.2 S 628.9 E 645.0 102.8 158.3 S 662.8 E 679.6 102.8 157,5 S 697,4 E 7i5,8 102.7 3!25,0 46.63 101,51 3i75,0 48.20 i0i,39 3225.0 48,86 101,42 3275,0 50, i6 i0i,40 ~.~ 51.1i !01,36 2911.9 2.49 2945.7 3.!6 2978.8 1.32 3011.3 2.59 3043.0 1.91 164.7 S 738,7 E 750,9 i72,0 S 768,7 £ ?~7. S 179,4 S ~q~o. 5 E 825.2 I87.0 S 842,7 E 663,2 194,6 S 880,6 E 901,9 102.7 102.6 l~d.6 102.5 102.5 3375. ~ ~..'x:, 8i i0i, ~o=~ 3074.2 ~,. 43 · 3425, k~ 52.64 i01,79. ~.,,~ml ._~ i,70 .~ ~-,. 0 uJ./~ 101,83 3i34, 7 ~8 3525,0 55, i2 t0i,72 3163.8 2.69 Ja~, 0 ~.~: 50 i~2, i5 R~_.92.3 I, 04 202.4 S 919,0 E 941.~ i02.4 210,4 S 957,7 E 980,5 i02.4 2!8,6 S 996.9 E i020,5 i02,~ 226,9 S 10~,7 E ![~i.2 102.3 235,4 S 1076,9 E 1102,3 i02.3 36~,0 ~.49 i02,30 3220,2 1,99 3676,0 57,74 i00,69 3247,9 3.62 372~,0 58. i6 i00.67 3274.5 .84 3776,0 60,18 100.45 3300. i 4,8~ 3826.0 60.6i 100.44 3324.8 ,87 244,2 S !117,4 E E52,7 S 1159,4 E 26~,5 S 120i.0 E 868,4 S 1243,2 E 276,3 S 1286.0 E 1t43.8 102.3 i186,~ i02.3 i229.~ 102,2 1271.9 i02,2 !315,3 3876,0 62,93 i00,69 3926.0 63.2i t00.87 3976.0 65. i7 i0i, i9 4026,0 65.5i 10i.72 4076.0 66.33 i02.35 3348.4 4,65 3371. i ,64 3392.8 3.96 3413.7 1,18 2~34,1 2,0i 284, 4 S 1389, 3 E 892, 7 S !373, 1 E 381,3 S 1417.3 E 310, 3 S !461,8 E 319,9 S 158~, 4 E i359.4 !403.9 1448.9 1494.4 i540.0 102.1 102.0 102.0 102.0 102,0 4i26.0 66.65 4176.0 66.04 102.47 4226.0 66.28 102.35 4276.0 65.85 i02.30 3454. i ,73 3474. i i, ~ 3494,3 .54 35i4.~ ,88 329.7 S 1551.2 E 339.7 S 1595.9 E 349.5 S I640.6 E 359.2 S 1685.2 E 369.0 S 17~.0 E 1-~, 9 1631,7 1677.4 1723.: 1768.9 102.0 102.0 102.0 102.0 102.0 4376.0 67,89 108,54 4426,0 67,56 1~2,38 4476.0 67.99 102.34 4526.0 67.~ i02.23 ~ ,-.- *o~6,0 67,~a i0i,53 ~J,r 1,5! 3572.6 ,~ 359i.5 .87 3Si0.6 i.55 3629.8 1.43 379.0 S 1775.1 E 389.0 S 1880, 3 E 398.9 S 1865.5 E 488.7 S 1910.7 E 4i8. 8 S 1955. 8 E 1815.1 102,1 i86!,4 102,1 1907.7 102. i i953.9 102. i 2000, i 102.1 4626.0 67.34 99.99 4676.0 67. i7 99.58 4726.0 66.89 99.68 4776.0 67.23 99.53 4826.0 69.69 99.48 4876.0 69.50 99.40 4926.0 70.24 99~4 4976.0 69.80 99.12 3649.0 2,87 3668.4 ,83 3687,9 ,59 3707.4 ,74 3725.7 4.92 3743~i .41 3760.3 ~.5i 3777. a .91 77q~ ? i~ 426.9 S 2801, 2 E 434,7 S E~46,6 E 442, 4 S 8892, 0 E 450. 1 S 2137, 4 E 457,8 S 2183, 3 E 465. 4 S 2229.5 E 477:.i S ~/o.'-' .... : 9 ' 480.5 S -:,'~--:,-:, ':, r 2~46,2 102.0 2092.3 102.0 2138,3 10i,9 2184.3 101.9 2230,8 101.8 2277,' iOl. A :2371.~ 101.7 D£PTH DEPTH SEVERitY feet deg. deg, feet deg,/ 100 ft. 5876.0 89.31 99,29 38i2. i 1.87 5126,0 68,77 99,22 5176,0 69,10 99,32 5~6.0 68,94 99.30 5276.0 69.65 99.18 5326,0 69,06 99,3i 5376,0 6%40 i00,27 5426,0 69,62 10i,44 5476.0 69,43 i01,47 5526,0 69.77 i~i.50 ~,0 69,25 !8i.o~ 562S.~ $9.76 i0i.62 5676.0 69.2i i0!,63 5786.0 69. i9 i0i.43 5776.0 A~,~O ~ -- ~,40 5826.0 68,37 101,43 5876,0 68,47 i01.47 5926,0 67,66 101.53 5975.0 67.79 !~!.92 6026,0 67.03 102, E~ 6076,0 87,05 i~i,96 6i26,0 67,70 i02, KS5 6176,0 69,~ I~,01 6226,0 69,64 102,2i 6276,0 6%26 1(~2.12 6326,0 69,85 !0° Os 6376.0 69,61 !02.05 6426.0 6%90 i02.04 6476,8 70.07 i08.07 6526.0 70,03 102.~ 6576.0 70,72 102.08 6626,0 70, ii i01,94 6676,0 70.7! i01,93 6726,0 70,31 101,95 8776.0 70,49 !0i,9i 6826,0 70,59 108,03 6876.0 70.32 I~2,24 6926,0 69.35 102.09 6975,0 68.29 i02.~8 7025.0 68.59 7075.0 ~8.42 i02. J9 3830,0 1.09 3848,0 ,69 3865,9 ,33 3883.6 1.43 390i,2 1,20 3918.9 1.92 3936, 4 2, 25 3953, 9 ,38 397i, 3 ,67 3988, 6 1, 06 4006.4 1,03 4023,9 1,09 4041,6 4059,5 ,69 4077,8 ,96 4096,2 ,21 4!14.8 1,61 4133.8 ,77 4i53.0 1 = 4172,5 ,16 4!9!.7 !.31 4210.2 2,67 4227.8 1.26 4245.4 .78 4262. d !.19 4280. i ,48 4297.4 .58 4314,6 ,35 433~.6 ~' 4348.4 1,39 4365,2 i,25 4381,9 1,20 4398,6 ,79 4415,4 ,35 4432,0 ~'~ 4448,8 ,67 4466.0 1,95 4483°7 2. i7 45~2. i ~,~ --.~ feet 49~, 5 S 2414, 8 E 503, i S 2460,9 E 510.6 S 2507,0 E 5!8,1 S 2553,0 E 525.6 S 2599.2 E 533,2 S ~645,4 E CLO~URE DIST, AZIMUTH feet deg, 2465. i 101.6 2511,8 101.6 ~8,4 i01.5 2605.1 101.5 2651.8 1~i.4 2698,6 101.4 541, i S 2691,4 E 8745,3 101.4 5 ~ ~ e9,~ ~ 2737,4 E 2792,1 101.4 ~.,=::q ~ R~ 2783,3 E 282:9.0 10i,4 ~b~.6 S -~-o~- ~ ~- _ -'~ ~,~ ~ 288s. 8 10i.4 577,9 S 2875,2 E 2932,7 10i,4 ~oz,4~c' 2q21,0. E 596,8 S 2966,9 E 606.1S 3012,7 E 6i5,4 S 3058,5 E 624,6 S 3104,1 E 633,8 S 3i49,7 E 643, i S 3195,! E o~=.~ S 3240,4 E 662,0 S 3285.6 E 67i,6 S 3330,6 E 2979.5 !0~.4 3026,3 101,4 3073,1 10!,4 3119.8 i01.4 3166.3 10i.4 3218.8 I0i.4 3259,2 101,4 3305,5 i0i.4 335i,6 101,4 3397.7 !01.4 68i,2 S 3375,8 E 3443,8 1~1,4 690,9 S 3421,2 E 3490,3 101,4 700.7 S 3467,0 E 3537,1 101,4 710,6 S 3512,7 E 3583,9 i01.4 720.4 S 3558,5 E 3630.7 101,4 730,2 S 3604,4 E 74~.0 S 2~,50,3 F 749,8 S 3696,2 E ~.6 S 3742.2 E 769,4 S 3788,2 E 779.2 S 3834,3 E 769.8 S 3880,4 E 798.7 S 3926,5 E 808.5 S 3972.6 E 8i8.2 S 4018,7 E 3724.5 101.5 3771,5 101.5 3818.5 10i.5 3865,6 10i.5 3912,7 101.5 3959,8 101,5 4006,9 101,5 4054.0 10i.5 4101,2 10i,5 828,1S 4064,8 E 4148,3 101.5 838.0 S 41!0.7 E 4195,2 10i.5 847.6 S 4i55,4 E $240.9 657,5 S 4280,8 E 4267.4 867.5 S 4246.2 E 4333.9 i~i.5 RECEIVED MAY 2 4 1996 011 & Ga~ Cons. Commisslorl Anchorage Pa~e feet deg. deg. feet SEVERITY deg./ i00 ft. feet CLOSUk~ DiST. AZIMUTH feet deg. 7125.0 68.60 102.45 7175.0 68.49 102.78 7225.0 68.49 102.95 72'i5.0 68.87 10'2.89 7325.0 68.48 i02.94 4538.7 ,37 4557.0 ,64 4575.3 .33 4593.5 ,75 46ii,7 .78 877~ 5 S 4291.7 E 887.6 S 43~7. 1 E 898.0 S 4382. 4 E 908.4 S 4427.8 E 918.8 S 4473. 2 E 4380.5 101.6 4427.0 101.6 4473.5 101.6 4520.1 101.6 4566.6 101.6 7375.0 68.76 7425.0 68.46 7475.0 68.43 ~.~ 68.20 7575.0 67.94 103.0! 1~3.09 103.2i 193.39 4629.9 .57 4648.2 .61 4666. r7 .=L°° 4685.0 .58 4703.7 .58 929.3 S 4518.6 E 939.8 S 4564.0 E 950.4 S 4609.2 E 96i.0 S 4654.5 E 97i.7 S 4699.6 E 4613.2 465%7 4706.2 4752.6 4799.0 I0i.6 101.6 101.7 101.7 i0!.7 7525,0 67.77 !QJ~.i3 4722.5 .41 7675.0 67.36 103.05 474i.6 .82 · 7725.0 67.5i i02.96 4760.8 .35 7775.0 67.22 102.85 4780.0 .62 7825.0 67.19 103.02 4799.4 .32 982.3 S 4744.7 E 992.8 S 4789.7 E i003.1S 4834.7 E i013.5 S 4879.7 E 1~23.8 S 4924.6 E 4845.3 4891.5 4937.7 4983.8 5029.9 10i.7 10i.7 t01.7 101.7 101.7 7875.0 67.09 i02. qi 4818.8 .28 7925.0 66.73 i02.85 48JB. o .74 7975,0 67,04 102,87 a~. 8025.0 66.60 !02.86 4877.8 .87 iOZ~. ~ S ~9.5 E 1044.4 S 5014. d ~ i054.6 S 5059.~ ~ 106_4.8 S 5104.0 E i075.0 S 5i48.7 E 50'?b. 9 ~i2i.9 5i67.9 52i3.9 5259.7 i01.8 i0i.8 !01.8 10i.8 101.8 8125.0 66.07 i02.60 4917.8 8i75.0 65.59 10E.57 49'38.2 .96 8225.0 65,86 102.46 4958.8 .57 8275.0 65.37 i02.39 4979.4 .97 8325.0 66.01 i~2.33 5000.0 l.=!' o- i085.0 S 5i93.4 £ i095.0 S 5237.9 E i104.8 S 5282.4 E 1114.6 S 53~.9 E ti24.4 S 5371.4 E 5305.5 535!.1 5396.7 5442.2 5487.8 101.8 101.8 101.8 101.8 101.8 8375.0 65.47 102.!~ 5020.6 ~.' ,L'° 8475,0 66,86 !8::2,87 586i.i !.67 8525.0 65,90 i02,[~4 5081. i 1.92 8575,0 66.25 i02.34 5i¢i,4 .79 ii34.! S 5415.9 E ii43./ 5 5460.5 E i!53.3 S 55~. d i 1i62.9 S 5550. i E ii72.5 S 5594.8 E 5533,4 5624.8 5670.6 57i6.3 i0i.8 101.8 101.8 i01.8 i0!.8 8625.0 65.48 10i, ~l,. 5~2~. .,~° i.82 8675.0 85.56 i8i.3i ~i,=. ..... ¢ . 75 8725.0 65.0~ 100.86 5163.4 1.34 8775.0 67.62 i08.7~ 5183.5 5.19 88¢~.0 6%95 I~0.57 5202.4 .~a i181.9 S 5639.4 E i19i.0 S 5684.0 E !!99,8 S 5728.6 E !208.3 S 5773.6 E i216,9 S 5819.0 E 576!.9 ~'G ¢~0,.4 5852.9 5898.6 5944.9 10i.8 10i.8 101.8 101.8 i01.8 8875.0 67.72 100.2~ ~i.3 .83 8925.0 68.42 100.05 ~239.9 i.42 8975.0 69.79 99,9! 5257.8 2.75 9038.0 69.3~ 99.78 3~79.8 .67 1~5,2 S 5864.6 E 1233.4 S 5910.3 E 1241.5 S 5956.3 E ~u~.~ S 6014.4 E 5991.2 6037.6 6084.3 6!43.3 101.8 101.8 101.8 101.8 Final Station Ciosu're: Lis~ance: 6i43.28 ft Az: 101.76 deg. DI=~I I_LI N 13 S I:= l=l~d ! !- I=:: S Contact No. NM2#8 To: State of Alaska (AOGCC) Attn: Larry Grant 3001 Porcupine Dr. Anchorage, AK 99501 From: Sperry-Sun Drilling Services Attn: Steve Carroll 5631 Silverado Way, #G Anchorage, AK 99518-1654 Contents: Washed & Dried From: BP Exploration (Alaska) Inc. North Milne Point #2 T9N; R24E; SEC 29 AP1 #50-029-22653-00 Shipment Includes: Process Depth Start I 12 t_ 2.00 Process Depth End '3 q oo'" ~ oao' Process Date Start Process Date End 5 /i 7/q 6 Total Number of Samples Included in this Shipment ;~40 1622 752 Shipment Number %. . Comments 5631 Silverado Way, Unit G, Anchorage AK 99518-1654 · (907)563-3256 · Fax (907)563-7252 A Dresser Industries, Inc. Company MEMORANDUM TO: David Jo~ Chairman THRU: Blair Wondzell, P. I. Supervisor State of Alaska Alaska Oil and Gas Conservation Commission DATE: March 14, 1996 FILE NO: O9©JCNDD.DOC -~r FROM: Lou Grimaidi, ~c,. SUBJECT: Casing shoe Cement plug BPX North Milne Point//2 Exploratory PTD #96-0038 Thursday, March '!4, '1996: I witnessed the placement of the cement plug at the surface casing shoe on BPX exploratory well North Miine Point #2. I arrived as the rig was tripping in the hole with a EZSV cement retainer. As the attached plugging report shows the retainer was set at 8420'. The running tool was unstung from the retainer then back down and re-engaged the EZSV. The driller stacked 30 K down with no apparent movement. 120 sacks of cement (1.15 yield) were then pumped, 80 sacks squeezed below then 40 laid above. The top of cement should be at 8312' approximately 192 feet above the shoe and 108' above the retainer. Enough cement was pumped to extend to approximately 8600'. SUMMARY: I witnessed the placement of the cement plug at the surface casing shoe on BPX exploratory well North Milne Point #2. Attachments: O9OJCNDD.XLS CC: STATE OF ALASKA ~LASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon. x Suspend __ Operation Shutdown __ Re-enter suspended well __ Alter casing __ Repair well __ Plugging X Time extension __ Stimulate __ Change approved program __ Pull tubing __ Variance __ Perforate Other__ 2. Name of Operator BP Exploration (Alaska) Inc 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 2045' NSL, 2700' WEL, SEC. 17, T14N, RIOE 5. Type of Well: Development __ Exploratory x Stratigraphic __ Service 6. Datum elevation (DF or KB) KBE = 35 ORIGINAL 7. Unit or Property name Milne Point Unit 8. Well number North Milne Point #2 .... At top of productive interval 9. 5103' NSL, 2678' WEL, SEC. 22, T14N, RIOE At effective depth To be determined At total depth 5050' NSL, 2426' WEL, SEC. 22, T14N, RIOE Permit number 96-38 10. APl number 50- 029-22653 11. Field/Pool Milne Point/Kuparuk River 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Structural Conductor 112' Surface 8173' Intermediate Production Liner Perforation depth: measured N/A 14632' feet Plugs (measured) 7899' feet To be determined feet Junk (measured) feet 14200' TD @ 14632' MD 15.8 ppg Class 'G' Premium cement Size Cemented Measured depth True vertical depth 20" 250 sx Arcticset l (Approx.) 144' 144' 9-5/8" ~¢75'sx P£ 'E'. 250 sx 'G; 150 sx PF 'E' 8204' 4985' true vertical Tubing (size, grade, and measured depth) N/A Packers and SSSV (type and measured depth) 9-5/8" EZSV @ 8129' MD w~ 73 sx below & 37 sx above of 15.8 ppg Class 'G' Premium cement. 9-5/8" EZSV @ 300' MD w/39 sx 12.0 ppg PF 'E' cement above. 13. Attachments Description summary of proposal × Detailed operations program __ BOP sketch X 14. Estimated date for commencing operation 03/12/96 16. If proposal was verbally approved Name of approver 1~' !,~--'7' ~4.,2'¢-/~.~-~ I i Date approved 15. Status of well classification as: Oil X Gas Suspended.__ Service 17. ! hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~~-~--- Title Senior Drilling Engineer Date FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity ,-~ BOP Test__ Location clearance ~ Mechanical Integrity Test__ Sul~sequent form required 10- Approved by order of the Commission ORIGINAL SIGNED BY J. David Norton, R E. I Approval No. ?6 '" ?7 Commissioner Date ,~//~/~ Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE feet .... .red e icos ri ll:iing TO: From' Date: Blair Wondzell, AOGCC Joe Polya, BPX March 6, 1996 SUBJECT: Revised Procedures and Diagrams for the North Milne Point #1 and #2 P&A As per our telephone conversations on 3/5 and 3/6 of 1996, I have revised the procedures and diagrams for the P&A (Non-Commercial Oil Case). The step which included displacing the top 2000' tvd of 9-5/8" casing with a non-freezable brine has been deleted. Instead we will leave the drilling fluid in the wellbore and allow it to freeze back which will provide a better seal. And the top of the surface cement plug has been extended to 70' rkb instead of the the originally proposed 100' rkb. Furthermore, we will fill the void between the TOC at 70' rkb to the 20" casing cut at 46' rkb with 56 sacks of sand. Once the rig is moved off the well, the original conductor the cellar will be removed and the hole will be filled with the original conductor dirt. Please find enclosed three sets of 4 pages which include a revised P&A procedure and diagram for both the North Milne #1 and #2 wells. Please shed the originals which these will replace. Respectfully, Joe Polya, Sr. Drilling Engineer, BPX Z.. Attachment No. 1 Non Commercial Hydrocarbons 9-5/8", 20" and any screw pipe will be cut off to 4' below mudline -- 46' rkb Surface Cement Plug Top 70'rkb 2/1 O/96 JD Polya Drawing Not to Scale 9-5/8" EZSV @ 300' md 20" 91# Casing Shoe @ 140' tvd/140' md 9.9 ppg NaCI/Br B (10°F LCTD) 9.9 ppg Drilling Mud Cement Interface 7600' md Schrader Bluff Sand Top 4935'tvd//8069'm~ 9-5/8" EZSV @ 8129' md Top of 37 sxs of 15.8 ppg Cement @ 8029' md -- Retainer@ 8129'md. Base of 73 sxs of 15.8 ppg Cement @ 8304' md. ;chrader Bluff Sand Base Top Seabee Shale 9-5/8"40# L80 Btrc @ 4985' tvd/8204' md 9.9 ppg Drilling Mud ~ TOC @ 14240' md [ TOC at 14200' md 7745' tvd/14431' md Top Kuparuk Formation ................ .~~ 192 sxs Class G 15.8 ppg Crn-t- ~ ~-'~'.~-~-~--~.~ Plug (from 14632' to14240') ~X,~ 7822' tvd/14532' md ~--~'~ ~ Top Miluveach Shale 7" 26# L80 Btrc @ 8052' tvd/14632' md 12.0 ppg Permafrost E Cement 15.8 ppg Class G Cement Attachment No. 2 North Milne Point #2 Proposed P&A Procedure Note: Note: (Non Commercial Hydrocarbon) Notify Kevin Hite with FMc (563-3990) to ensure he is present at the rig to aid in retrieval of the 10-3/4" SD-1 Casing Hanger· Notify AOGCC to Witness P&A Operations · · · , . . , RIH with mule shoe on 5" drill pipe to TD. Circulate and Condition mud and pump a 192 sx 15.8 ppg Class G Cement plug. Pull out of plug and circulate conventionally one bottoms up. POOH and pick up a 9-5/8" EZSV. RIH and set EZSV at 8129' (adjust this depth to be 75' above the 9-5/8" Casing Shoe). Mix and Pump 110 sx 15.8 ppg Class G cement -- Squeeze 73 sxs through the EZSV, unsting and lay a 100' balanced cement plug with the remaining 37 sxs of cement. Lay down 2 stands and circulate 1 bottoms up conventionally· Close in on the Pipe Rams and perform a 2000 psig pressure test on casing for 30 minutes. POOH and PU a second 9-5/8" EZSV, RIH and set at 300' md. Unsting from the EZSV and pump a 45 sx 12.0 ppg permafrost E balanced cement plug. POOH to 70' and circulate off the top of the plug to ensure access to the 10-3/4" tieback assembly. Circulate fresh water at high rate until clean fresh water returns. POOH and lay down the drill pipe and the EZSV stinger. ND BOPE, retrieve the 10-3/4" tie back to 60' md rkb, and MU Baker Casing Cutter Tool with appropriate knife and cut 20" casing and any screw pipe to a minimum depth of 45' md rkb (this correlates to 4'- below the mudline which is 2' deeper than the AOGCC regulations require. RIH open ended with 5" drill pipe to 46' and dump 112 50 lb sacks of sand (Colville has the 20/40 frac sand in 50 lb. bags -- 659-3197) down the drill pipe. Arrange to have drill pipe pups available to space out tool joint at working level above rotary table. Have a head pin rigged up to circulate as needed to keep drill pipe from plugging. After all sand is in place, PU 5' and circulate at high . . rate to clean sand from drill pipe. RDMO Nabors 22E Rig to North Milne Point #1 Well. NMP#2 Well Plan PAGE 24 JDP Classified: "SECRET" MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TRRU~\ ~lair Wondzell, ~,~. !. Supervisor Do ~u~g.~mos, FROM: Pet.~ebm lnspeclor DATE: March 8, 1996 FILE NO: awohchdd.doc SUBJECT: (~ONFNDL~ BOPE Test Nabors 22E BPX MPU NMP-2 Exploratory PTD No. 96-0038 T Friday, March 8, 1996T~ traveled to BPX MPU NMP-2 exploration well to witness the BOPE Test on Nabors Rig 22E. As the attached AOGCC BO!~Test Form indicates there were three failures. The Upper Pipe Rams door seal failed it's initial test, the Inside BOP valve failed and the H2S gas detection high alacm-c, ircuit failed. ,The Upper Pipe Rams door seal and the Inside BOP were repai~cl'~ -"and retested. The high alarm on the H2S gas detector was wired to the t~iarm until the new circuit board arrives on location. The H2S gas detection system is operational but the driller must check the alarm panel to obtain the parts -.l~illion concentration generating the alarm. / ~L\.~ Sunday, March 10~ 1996: i was contacted by Nabors Drilling representative Leverne Linder and informed that the H2S Gas D~'~tion System had been repaired and retested.~ SUMMARY: Witnessed the successful BOPE test at B~PU NMP-2 exploratory well on Nabors Rig 22E. 6 Test Hrs., 3 Failures, 23 Valves Tested. Attachment: AWOHCHDD,XLS T OPERATION: Drig: X Drlg Contractor: Opera~!'--~ Well Nan~e: ~ Casing Siz~ 9 5/8" Test: Initial X . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report ~'ONFI:DENT1A,~ .'31 Workover: DATE: NABORS Rig No. 22E PTD# g6-038 Rig Ph.# BP Exploration Rep.: Jimmy, Pyron MPU NMP-2 Rig Rep.: L. Linder Set @ 8,502 Location: Sec. 17 T. '/4 N R. '/0 E Meridian Umiat Weekly Other 3/8/96 65g-4446 Test MISC. INSPECTIONS: Location Gen.: OK Housekeeping: OK (Gen) PTD On Location Yes Standing Order Posted ' Yes ~11 Sign Yes ~rl. Rig OK ~ard Sec. Yes ,, , BOP STACK: Quan. Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. VaNes HCR Valves Kill Line Valves Check Valve 1 500/5,000 I 500/5, OO0 FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Ball Type Inside BOP Quan. Pressure 1 5OO/5,0OO 500/5 000 '/ 500/5,000 f 500/5,000 P/F P ,, P F Test Pre~. Test 30023,0~ Pressure P/F 500/5,000 P .p 5oo/5,ooo 500/5,000 2 500/5,000 t 500/5,000 N / A N/A CHOKE MANIFOLD: No. Valves '/7 No. Flanges '36 Manual Chokes '/ Hydraulic Chokes I 500/5,000 Functioned Functioned P P ACCUMULATOR SYSTEM: ~ System Pressure 3,0001P ....Pressure After Closure 1,400 . P MUD SYSTEM: Visual Alarm 200 psi Attained After Closure minutes 23 sec. Trip Tank OK OK System Pressure Attained 3 minutes 18 sec. Pit Level Indicators OK OK ~\ i~nd Switch Covers: Master: Yes Remote: Yes Flow Indicator . OK OK ~__ ~gn. Btl's: 8 ~ 2, '/00 Avg. Meth Gas Detector OK OK Psig. H2S Gas Detector See Remarks See Remarks Equipment will be made within I days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North $ ~l~pe Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. S~pervisor at 279-1433 REMARKS: The H2S Panel had a bad circuit and would not give a high alarm~. The ~r.cuit board will be replaced *' The high alarm was Wired 'tO tile Iow level alarm so 'lhat th® system could remain in service. ~'~ Dart valve failed it s in'~al " · . , , , ,t-~-~ ~=~ . , , , , ~ . test. ~The Uppec Pipe rams door ~eal leaked on the inilial te~t."Both the Dart Valve and, the ,~ppe~ Pipe Rams were repaired and retested dudng the course of this test.~The H2S system was repaired on 3/10796. *~ Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Riot File c -Inspector STATE WITNESS REQUIRISD? ' YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: ~ Witnessed By: F1-02t L (Rev. 12/94) AWOHCHDA.XLS MEMORANDUM TO: THRU: FROM: David Johr~'~ Chairman ~ Blair Wondzeli, P. !. Supervisor John Spaulding,'~<~vr Petroleum lnsp. State of Alaska Alaska Oil and Gas Conservation Commission DATE: March 1,1996 FILE NO: ewolcadd.doc Diverter Function Test BPX No. Miine Pt. 02 Miine Point Unit Exploration PTD 96-38 Friday March 1, !996: ! travelled to BPX's North Milne Point exploration well to witness the Diverter Function Test on Nabors 22E. The AOGCC test report is attached for reference. The pad area is an ice pad built up about 4' on a gravel islsnd. The diverter vent line is facing out over the edge of the pad and is approximately 60" from the rig sub-base. The bifurcated section is approximately 30' in length, both sections take good advantage of the wind direction. Three H2S detectors failed to issue an audible alarm when reaching high limits. These items will be re-calibrated prior to spudding the well.'"'- Summary: I witnessed the Diverter Function Test on Nabors 22E, 3 hour test time. Attachments: ewolcadd.xis STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Diverter Systems Inspection Report Operation: Development .... Ddg Contractor: Nabors Rig No. 22E PTD # 96-38 .. Operator: .... . . BPX ......... Opel Rep.: Well Name: North Miine Point #2 Rig Rep.: Location: Sec. 17 T. 14N R, 10E Merdian Umiat Date: 3/1196 Exploratory: Rig Ph. # Dave Mountjoy *. Laveme Linder X 659-4446 MISC. INSPECTIONS: ACCUMULATOR SYSTEM: Location Gen.' ok Well Sign:. Ok, , Systems Pressure: ,,3~000, , psig Housekeeping: ok (Gen.) Drlg. Rig: _- ok. _ Pressure After Closure: , _ . . 1,750 .... psig Reserve Pit: .. 'r ga .... Flare Pit: ~,a 200 psi Attained After Closure: min. 24 sec. Systems Pressure Attained: ' '2" ' min. 12 sec. DiVERTER SYSTEM INSPECTION: Nitrogen Bottles: Diverter Size: 20 in. _ psig , , Divert Valve(s) Full Opening: Valve(s) Auto & Simultaneous: Vent Line(s) Size: Vent Line(s) Length: 2~ 90 Line(s) Bifurcated: .. ]/e~,,, Line(s) Down Wind: , yes Une(s) Anchored: . yes Tums Targeted / Long Radius: N/A .... yes _ MUD SYSTEM INSPECTION: Light Alarm t0 in. Trip Tank: .... o,k . ok ff. Mud Pits: ok -" 6k" Flow Monitor: ok ok GAS DETECTORS: Light Alarm Methane ok ok Hydrogen Sulfide: 'ok ' o~* ' Edge Of Ice Island ~----~---~ 10" vent lines with ~I. _u ----- ~ North isolation valves . J :=~ ~ Full opening knife valve ' 0 " ' ! Wind .... Sub-Base Pipe .' _ ! !shed .~-___.~. Direction Motors ~ !_ .. . ' Non Comi~lia~;-e It~rns Remarks: Distribution orig. - Well File c - OperlRep c- Database c - Trip Rpt File c- Inspector ' ~1" ' ReP'~ir Items Within' .... 1 Day (s) And conta~ the ]~p~'ct0~ ~) 6'59-3607 The hi[iR level aud~bte alarm on the H2S alarms failed-visual alarms worked roperS, The alarms will be .,alibratc~l i i , i i i , , i i .i i i.i , ,11 . J . . i i ' [ i Jl ! Pi i . ,'i i i i ! ii ? AOGCC REP.: ..... John H. $jmu!,~n~ .... OPERATOR REP.: · , Dave Moun{/o, / Laveme Linder ..... EWOLCADD.XLS DV'I'RINSP.XLT (REV. 1/94) ALAS AND GAS CoNsERVATION COMMISSION TONY KIVOWLE$, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 27~1433 FAX: (907) 276-7542 February 23, 1996 Tim Schofieid, Senior Ddg Engr BP Exploration (Alaska)Inc P O Box 196612 Anchorage, AK 99519-6612 Re: North Milne Point No. 2 Company BP Exploration (Alaska), Inc. Permit # 96-038 Surf Loc 2045'NSL, 2700'WEL, Sec 17, T14N, R10E, UM Btmhole Loc 5050'NSL, 2426'WEL, Sec 22, T14N, R10E, UM Dear Mr. Schofield: Enclosed is the approved application for permit to ddll the above referenced well. A ddlling permit is not valid at a location where the applicant does not have a dght to ddll for, produce, and remove oil and gas. This approval is expressly conditioned upon conformance with the operating agreement in effect between BP Exploration (Alaska) inc. and the owners of ADL 355016, Maxus Exploration Company and Amerada Hess Corporation, and not on the proposed total depth of the well as represented on the enclosed form 10-401. Any penetration of strata in the North Milne Point No. 2 well, for which BP Exploration (Alaska) Inc. has not been designated operator, will be a violation of this approval. 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. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. 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 eld inspector on the North Slope pager at 659-3607. · David W J~ston \ Chairman ) BY ORDER OF THE COMMISSION /encl c: Dept of Fish & Game, Habitat Section -w/o end Dept of Environmental Conservation - w/o encl STATE OF ALASK/. ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 2O AAC 25.OO5 BP SECRET la. Type of work Drill [] Redrill Type of well. Exploratory[] Stratigraphic Test [] Development Oil [] Re-Entry [] DeepenCII 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. KBE = 35 feet Milne Point Unit / Kuparuk River 3. Address 6. Property Designation P. 0. Box 196612, Anchoraae. Alaska 99519-6612 ADL 355016 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025) 2045' NSL, 2700' WEL, SEC. 17, T14N, RIOE Milne Point Unit At top of productive interval 8. Well number Number 5103' NSL, 2678' WEL, SEC. 22, T14N, RIOE North Milne Point #2 2S100302630-277 At total depth 9. Approximate spud date Amount 5050' NSL, 2426' WEL, SEC. 22, T14N, RIOE 02/28/96 $200,000.00 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD andTVD) property line MPU borders unleased acreage f e e t No Close Approach f e e t 2560 14832' MD / 8052' TVD f e e t 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth ~000 feet Maximum hole angle 6B o Maximum surface 3101 psig At total depth (TVD) 7745'/3866 psig i18. Casing program Setting Depth s~ze Specifications 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' 140' 140' 250 sx Arcticset I (Approx.) 12-1/4" 9-5/8" 40# L-80 Btrc 8173' 31' 31' 8204' 4985' 1575 sx PF'E', 250 sx 'G', 150 sx PF'E' 8-1/2" 7" 26# L-80 Btrc 12822' 30' 30' 12852' 8052' 333 sx + 113 sx Class 'G' 8-1/2" 7" 26# L-80 Mod Btrc 2250' 12582' 6605' 14832' 8052' 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 i~-~-=~ ~ ~ Surface Intermediate FE@ 1 6 ]995 Production Liner Alaska 0it & G~s Cons. Comrnissio~ Perforation depth: measured A~chorag~. 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 requirementsl-I 21. I hereby ce~j~that.~t~th.e f~rego~in~ ~s true and correct to the best of my knowledge Signed ~/~..f/! ~'~C~~'.~CommissionTitleSeni°rDri//in~/En~/ineeruse Only Date ~/~/q~, Permit Number APl number Approval date See cover letter ~'-.~ 50- ~,2_~- 2--2~'~'._~ ?.~./'9.."~/~:~G for other roquiromonts Gonditions of a~proval Samplos roquirod ~ Yos ~ ~ Mud Io~ roqui~oO ~Yos ~ ~ HyOro~en sulfiOo measuros ~ Yes ~ ~ D~roctional su~ey roqu~roO ~ Yes ~ ~ ~equire~ workin~ pressure for BO~[ ~2M; ~M; ~M; ~IOM; ~I~M; Othor: Od~inal S~ned By ~y orOor of Approvod ~avid W. d0hnst0n Commissionor me commission Date Form 10-401 Rev. 12-1-85 Submit Proposed P&A/Suspension for North Milne Point #2 Well References: 20 AAC 25.105 Plugging, Abandonment & Suspension of Wells 20 AAC 25.110 Suspended Wells el) BP proposes two suspension plans for this well. In the event commercial hydrocarbons are not found, the well will be P&Aed as per North Milne Point #1 Dry Hole P&A Diagram and Proposed Summary of Operations-- see Attachment Nos. 1 and 2, respectively. The reason of abandonment in this circumstance is obvious. el) If the well finds commercial hydrocarbons, BP proposes to P&A/Suspend the well according to North Milne Point #1 P&A/Suspend Diagram and Proposed Summary of Operations -- see Attachment Nos. 3 and 4, respectively. The reason to P&A/Suspend this appraisal well in this circumstance is to prevent damage to the tree from ice encroachment onto Levitt Island while BP further evaluates the reservoir and facility design alternatives. The P&A/Suspend proposal suggests a design that would both meet suspension and P&A critieria through the use of an FMC mudline suspension system (SD-l). This is a win/win approach whereby the well is still accessable in future years should BP decide and receive approval to construct a facility in this location. In the event the decision is reached or approval is not granted to construct a facility at this location, then the well would already meet P&A status eliminating the need to spend future monies on access and further P&A operations. e2A) Porous and Abnormally GeoPressured Strata: The Schrader Bluff Sands which are expected to be wet and are normally perssured at 8.6 ppg will come in with the Na Top prognosed at 4200' sstvd and the OB Base at 4600'sstvd. The primary target is the Kuparuk Sands which are prognosed at 9.6 ppg (based on MPF-38 Kuparuk intercept in the same fault block). The top prognosed sand is the C Sand at 7684' sstvd and the base sand will be the A1 at 7795' sstvd. · There are no other porous or abnormally pressured sands expected. e2B) The kind, size, and location, by measured depth of proposed plugs is depicted on the P&A diagrams. e2C) There are no plans to perforate or perform well tests for this well. Call with any questions -- 564-5713. Respecfully, Joe Polya, Sr. Drilling Engineer, BPX REG .i'v D 0il & Gas Cons. r.5ommissi0n Anchorage BP SECRET Attachment No. I ~~lh )J~{]~® I~~ ~:~ ~J~.{]~ (Drawing Not To Scale) Non Commercial Hydrocarbons 9-5/8", 20" and any screw pipe will be cut off to 17' below mudline - 58' rkb Surface Cement Plug Top 100'rkb Base of Permafrost E Surface Plug @ 300' rkb (200' length Plug 20" 91# Casing Shoe @ 140' tvd/140' md 9.9 ppg Drilling Mud 4735'tvd/7~ Cement Interface 7600' md Schrader Bluff Sand Top Top of 37 sxs of 15.8 ppg Cement @ 8029' md -- Retainer@ 8129'md. Base of 73 sxs of 15.8 ppg Cement @ 8304' md. Bluff Sand Base Top Seabee Shale 9-5/8"40# L80 Btrc @ 4985' tvd/8204' md TOC @ 14240' md .OCat 7745' tvd/14431' md L~~'~ - - ~-"~Top Kuparuk Formation ~ ~.%."~ 136 sxs Class G 15.8 ppg Cmt ~,,.~ Plug (from 14632' to 14240') ~'~,~' 7822' tvd/14532' md ~--~%~ ~ Top Miluveac, Shale ~\\\ 7" 26# L80 Btrc @ 8052' tvd/14632' md 12.0 ppg Permafrost E cemi iECi't'vED 15.8 ppg Class G Cement FEB ~ 6 ~996 ~aska 0ii & Gas Cons. Commission Anchorage 2/10/96 JD Polya Drawing Not to Scale BP SECRET ATTACHMENT NO. 2 North Milne Point #2 Proposed P&A Procedure (Non Commercial Hydrocarbon) , . , , , , RIH with mule shoe on 5" drill pipe to TD. Circulate and Condition mud and pump a 136 sx 15.8 ppg Class G Cement plug. Pull out of plug and circulate conventionally one bottoms up. POOH and pick up a 9-5/8" EZSV. RIH and set EZSV at 8129' (75' above the 9- 5/8" Casing Shoe). Mix and Pump 110 sx 15.8 ppg Class G cement -- Squeeze 73 sxs thru the EZSV and unsting and lay a 100' balanced cement plug with the remaining 37 sxs of cement. Lay down 2 stands and circulate 1 bottoms up conventionally. Close in on the Pipe Rams and perform a 3000 psig pressure test on casing for 30 minutes. POOH to 375', Spot a 7.5 bbl hi-vis pill, POOH to 300' and lay a 39 sx 12.0 ppg permafrost E Cement plug. POOH to 100' and circulate of the top of the plug to ensure access to the 9-5/8" tieback assembly. Lay down the drill pipe and the EZSV stinger. ND BOPE, retrieve the 9-5/8" tie back to 84' md, and MU Baker Casing Cutter Tool with appropriate knife and cut 20" casing and any screwpipe to a minimum depth of 58' rkb (this correlates to 17' below the mudline which is 2' deeper than the AOGCC requires. POOH and RDMO Drilling Rig. Note: Proposed P&A/Suspend Procedure to follow in the event commercial ydrocarbons are found in this well. RECEIVED FEB 1 6 1~96 ~a~ 0il & Gas Co~s. Commission A~chorege BP SECRET 20" Stub at 17' below Mudline (58' md RKB) 20" Baker Tools Swab Cup with Fins Up 9-5/8" T&A Cap 84' md RKB 1/26/96 JD Polya Drawing Not to Scale 400' of Cement 7" T&A Cap · 7" EZSV @ 500' md 20" 91# Casing Shoe @ 140' tvd/140' md Top E Cement 400' md Top G Cement 2173' md Base G cement 2536' md Schrader Bluff Sand Top 4935'tvd/8069'm~ Bluff Sand Base Top Seabee Shale 9-5/8"40# Casing Shoe @ 8204' tvd/4985' md 7" Casing will not be perforated 7675' tvd/14340' md @ 14140' md TOC at 12600' md Top Kuparuk Formation 7822' tvd/14532' md 12.0 ppg Permafrost E Cement 15.8 ppg Class G Cement Top Miluveach Shale 7" 26# Casing Shoe @ 8052' tvd/14832' md 10.0 ppg NaCI Brine 10.0 ppg LSND Drilling Fluid BP SECRET , , , , . , . , . 10. 11. ATTACHMENT NO. -~ North Milne Point #2 Proposed P&A Procedure (Commercial Hydrocarbons) Excess cement (112 sxs -- 600' md) is planned to be pumped behind the top plug to effectively bring the cement top in the 7" casing 200' md above the top Kuparuk reservoir sand (C Sand). The 7" caisng will not be perforated nor will the cement be drilled out. This should effectively seal the Kuparuk sands with cement both in the 7" casing by 8.5" annulus and inside the 7" casing. Once the 7" cement plug is bumped, the casing will be tested to 3500 psig for 30 minutes. The floats will be checked. The production cement will be allowed to cure for 6 hours minimum. While the cement is curing, the 7" will be spaced out with a pup such that the top collar of the 7" will be just above the rotary. The elevators will be released since the 7" will be resting on the Mud Line Hanger. A false rotary stand will be installed to allow a 7" EZSV to be run in the hole to 500' md. A 400' (40 sx) balanced Permafrost E cement plug will be set on top the EZSV. After waiting the 6 hours for the production cement to set up, RU the cement unit and pump 50 sxs (10.2 bbls) 15.8 ppg Class G cement followed by 130 sxs (50.2 bbls) Permafrost E cement followed by 13 bbls of spacer flush mixed in 10.0 ppg brine (10°F LCTD). This spacer needs to be pumped at the maximum rate (10 bpm minimum) to effectively wash all scour and wash all cement away form the 7" mudline suspension hanger and tie back sleeve. Wait on Cement for 6 hours and perform 2000 psig pressure test for 30 minutes. RD the false rotary stand and back out the 7" drillng sleeve from the mud line suspension hanger. Install the 7" abandonment cap. Nipple down BOPE and retrieve the 9-5/8" tieback assembly with a 9-5/8" casing fishing spear. RIH with the 9-5/8" abandonment cap. RIH with 20" Guiberson Swap Cup Packer and release to leave it firmly on top the 9-5/8" P&A cap. Dump 52 cubic feet (52 sacks of sand) on top of the 20" swab cup. RIH with casing cutter and cut the 20" casing and any screw pipe installed to a minimum depth of 58' md rkb. This will put the all metal stubs 8' below the mudline (2' below AOGCC requirements). Ensure 10.0 ppg brine (IO°F LCTD) fluid is utilized as the completion fluid for all the above operations. RDMO Nabors 22E Rig to next well. FEB 6 ' 996 0il & Gas c,.,o~s. Gommissio~ /~ch0r;~ge BP SECRET B" P" EXP£ ORA T IoN '"Z NC ..... I', i i ~1__ii _ iii i ii i ii i ii i ii iii l~l i iii i i i ii ii i i ii i iiiii i i ii i i ii i_!! ii ii [ i i section at: lol.Bl TVD Scale · I inch = 2000 feet 'Oep Scale' I inch = 2000 feet Drawn .... '02/07/96 ~nadri 1 ] 5£hlumberger N~P-2 (P4) VERTICAL SECTION VIE~ ! I I . · i i '-- ~ ................... Narker loentit lCatlon NLI URU Al KB 0 0 0 0.0 'B} ~IL0 i/100 i000 1000 0 0.0 C) BUILD 1.5/100 t200 i200 3 2. '-- B= ' ' O] ~IL0 2/100 1500 1499 C '' E) ~ILD 2.5/t00 i900 t892 99 14.5 O,~~ ~ F) E~ ~.5/i00 BUILD 4051 3447 1469 68.~ ' ,,,,L, ,, , . ~-~r'l~ G} 9-5/8' CASING POINT 8204 4985 5327 68. H) ~ 2/100 i26i8 6618 9427 68.~ l) E~ 2/100 OROP. t4031 7438 105El 40.C d} I~ET 1443i 7745 10818 40.( .... K) 7" CASIN6 POINT 14832 8052 11076 40.C L) ID 14832 ~52 11076 40.{ . ~ : : APP[OVED .~ - ~ ..... ;~ ......... ~ ......... -~," ~ , ~ ruK PER~iT'FIN~ ~~~ O~ILY .... -~ ~~ ~ ~ ., , .... :; : ............... '::'::':""' . ,, i ( ~ .... ~ ,--,. 7000- gO{ t0000 0 1000 2000 3000 4000 5000 ~)00 7000 8000 9000 10000 il000 ia)iX) 13000 14000 15000 ]6000 17000 ______..R~-dH'nn ilenarture ...... ..~_.._ -- ~ .... _ -- r' --'"1' I i mm l i i ~or~]] (c)96 1~o2P4 2.50.04 I;46 ~1 PJ O N NMP-2 (P4) PLAN VIEW i ii I ' CLOSURE · 11076 feet at Azimuth lOI.8~ ,INATION.' +28.~07 (E) E. ' ~ inch: ~600 feet N. ' 02/07/96 , .~ ....... ~'~'~ ' r Identi~ica:ion ND N/S ,, - ,, · r~.~' ,' O 1/I~ t000 0 0 ,~¢,. ~r ~o ~.uloo lsoo ~o s~ " " 9 ~.5/~00 BOZLO 405~ 30~ ~438 u,' c~sm~ POmT ~0~ ~o~ , l 3 2/$00 ~DP S4031 2~6~ S0338 ' 3~T 1443~ 22~4 ~0589~.~.._~_ AKA -DPC CASING ~INT 14832 2267 14~2 PERMIT'rING --- ~-...... OFJLY . _ ~00 FI T~ R~I RADIUS , 800 0 BO0 t ~Ra 3a~n SCALE. DHA~N. Marker B) C}, D) FI END DROP 10 00 5600 6400 7200 8_Q00 ....8800 9600 10400 11200 12000 12GO0 13600 <- ICEST ' EAST -> ma~r~]l {c]~ ~4 2.~.04 1:50 ~ PI '1'1 o .1 J, Summary I Type of Well (producer or injector): I Kuparuk Producer I Surface Location: 2045 NSL 2700 WEL Sec 17 T14N R10E UM., AK Target Location: 5103 NSL 2678 WEL Sec 22 T14N R10E UM., AK Bottom Hole Location' 5050 NSL 2426 WEL Sec 22 T14N R10E UM., AK I AFE Number: 1337005 I I IEstimated Start 2/28/96 Date: IOperating days to 120 complete' I MD' 4832' I I TVD: 180S2' RKB I I KBE - MSL: 135' I IWell Design (conventional, slimhole, etc.)' IMilne Point Ultra Slimhole:9-5/8" SURFACE CASING X 7" LONGSTRING Formation Markers' Formation Tops MD TVD (rkb) base permafrost 1739 1 739 NA 7529 4735 Top of Schrader Bluff Sands (8.3 ppg) Seabee Shale 8204 4985 Base of Schrader Bluff Sands (8.3 ppg) HRZ 8359 7389 High Resistivity Zone Kuparuk Cap D Shale 1 4183 7555 Kuparuk Cap Rock Target Sand -Target 1 4431 7745 Target Sand (9.6 ppg) hbi:j 1 ]996 Total Depth 1 4832 8052 ~aska Oil & Cas Coi'~s. Casinq/Tubing Pro ]ram: Hole C~sg/ Wt/Ft Grade Conn Length Top Btm Size Tbg O.D. MD/TVD MD/TVD 24" 20" 91.1# H-40 Weld 80 32/32 140/140 12 1/4" 9-5/8" 40# L-80 btrc 8173 31/31 8204/4985 8 1/2" 7" 26# L-80 btrc 12822 30/30 12852/8052 & mod- 7" 26# L-80 btrc 2250 12582/6605 14832/8052 Internal yield pressure of the 7" 26# casing is 7240 psi. Worst case surface pressure would occur with a full column of gas to the reservoir at 7745' TVDRKB. Maximum anticipated surface pressure in this case assuming a reservoir pressure of 3866 psi is 3101 psi, well below the internal yield pressure rating of the 7" casing. Logging Program: IOpen H°leL°gs: I Surface Intermediate Final Cased Hole Logs: None Required MWD Directional and LWD GR/RES N/A MWD Directional and LWD (GR/CDR/CDN). None Required Mudloggers will be employed on this well with H2S monitoring equipment as outlined in 20 ACC 25.065. BP SECRET Mud Program: I Speciai design considerations I(No Special Design Considerations.) I Surface Mud Properties- I Spud Mud Density Marsh Yield 10 sec 10 min pH Fluid (PPG) Viscosity Point gel gel Loss 8.6 100 15 8 10 9 8 to to to to to to to 9.0 50 35 1 5 30 1 0 1 5 Production Mud Properties: I 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 9.9 to 10.2 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. Direct onal: KOP: Maximum Hole Angle: Close Approach Well: Waste Management: rl 000' 68° (No Shut Ins) 1996 Anchora~ge 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. An emergency cuttings storage area will be available on the ice pad for contingency in the event of bad weather. Request to AOGCC for Annular Pumping Approval for NMP#2: 1. Approval is requested for Annular Pumping into the NMP#2, 9-5/8" x 7" casing annulus. 2. The base of the Permafrost for all wells located in the Milne Point Unit is +_1,850' TVD. in the Milne Point Unit have been exempted from Class II injection activities by the~ Aquifers AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. There are no do,,mestic or industrial use water wells, located within one mile of the project area. 3. The 9-5/8 casing shoe will be set at 8204 md (4985' tvd) which is a minimum of 500 tvd below the Permafrost and into the Seabee/Colville formation which has an established history of annular pumping at Milne Point. 4. There are no domestic or industrial water use wells located within one mile of the project area. 5. The wastes to be disposed of during drilling operations can be defined as "DRILLING WASTES". 6. The burst rating (80%) for the 9-5/8" 40# L80 casing is 4600 psig while the collapse rating (80%) of the 7" 26# L80 casing is 4328 psig. The break down pressure of the Schrader Bluff formation is 12.5 ppg equivalent mud weight. The Maximum Allowable Surface Pressure while annular pumping regardless of fluid density is 2000 psi as per Shared Services Drilling "Recommended Cuttings Injection Procedure". 7. 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. 8. The cement design for this well ensures that annular pumping into hydrocarbon zones will not occur. BP SECRET DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS. MAXIMUM EXPECTED FLUID DENSITY IS 17.0 PPG BURST PRESSURE 9-5/8" 40# L-80 CASING: COLLAPSE 7", 26#, L-80 CASING: 9-5/8" SURFACE CASING SHOE DEPTH: 575O PSI 5410 PSI 8204' MD/4985' TVD HYDROSTATIC PRESSURE @ 4985' TVD WITH VARIOUS DENSITY FLUIDS: (0.052) X (4985) X (FLUID DENSITY) = HYDROSTATIC PRESSURE 80% OF 7" COLLAPSE PRESSURE = (5410 PSI) X (0.8) = 4328 PSI MAXIMUM ALLOWABLE INJECTION PRESSURE 2000 PSI AT ANY PPG SURFACE CASING SHOE DEPTH (TVD): 4 9 8 5 ' HYDROSTATIC MAXIMUM ALLOWABLE PRESSURE AT 7" COLLAPSE ANNULAR INJECTION 9-5/8" FLUID DENSITY CASING SHOE DEPTH PRESSURE (80%) SURFACE PRESSURE (PPG) (PSI) (PSI) (PSI) 8 2073 4328 2000 9 2334 4328 1994 1 0 2593 4328 1735 1 1 2851 4328 1477 1 2 311 0 4328 121 8 1 3 3370 4328 958 1 4 3629 4328 699 1 5 3889 4328 439 1 6 41 48 4328 1 80 1 7 4406 4328 78 MAX ALLOWABLE INJECTION PRESSURE = 4328 PSI - HYDROSTATIC PRESSURE or 2000 psi (whichever is less). 1996 ~chor~.g-~ BP SECRET North Milne Point #2 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. NOTE: NOTIFY AOGCC OF UPCOMING DIVERTER TEST 1996 NU and test 20" Diverter system. Build Spud Mud. A~aska Oi! & l'-;r~ Cons. NOTE: Hold pre-spud meeting with Co. Rep, Toolpusher, Rig Crew (~ci~;~: Mud Engineer, Directional Driller, MWD personnel and any other key service company personnel as outlined on PAGE17 of the drilling policy manual. Note on morning report that pre-spud meeting was held. REFER TO RECOMMENDED PRACTICES MANUAL FOR LONGSTRING SLIMHOLE FOR UPCOMING DRILLING AND CASING OPERATIONS . , . el . 10. Drill a 12-1/4" surface hole as per directional plan. Run DIR/GR/RES across Schrader Bluff in surface hole. An ESS is NOT necessary in the surface hole. Run and cement 9-5/8" casing. /,,,~c,y- ~',,-¢ 8 ~.o,-/ /t4p NOTE: Have and FMC Representative onsite to supervise the running of the mudline suspension components -- open ports and wash cement from above the mudline suspension hanger. NOTE: Notify AOGCC of upcoming BOPE test. ND 20" Diverter, Run the 9-5/8" Tie-Back Assembly, Cut & Weld on 9-5/8" Gen 5 Casing Spool, 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 Float Equipment and 10' of new formation. Perform FIT to 12.5 ppg. Drill 8.5" hole to TD as per directional plan. An ESS will NOT be necessary if the IHR Gyro is successful. NOTE: NOTE: NOTE: An IHR Gryo I_~S required for this well. Hold a "pre-reservoir" meeting approximately 24 hrs prior to penetrating the KUPARUK reservoir with Co. Rep, Toolpusher, Dir Driller and Mud Hand as per PAGE20 of the drilling policy manual. Note meeting on morning report. Pump Iow vis/high vis weighted sweeps in combination with short trips to remove/prevent cuttings bed development. Run and Cement 7" Casing -- Drop the top cement plug ahead of the last 23 bbls of cement to be pumped as part of P&A procedure. Displace cement with 10.2 ppg NaCI/Br Brine with a 10°F LCTD rating. NOTE: Have and FMC Representative onsite to supervise the running of the mudline suspension components. Test casing to 3500 psig. Prepare to perform Suspension or P&A of Well based on Geologists appraisal of the LWD logs. BP SECRET GENERAL DISCUSSION Obiective: The North Milne Point #2 well is planned as an exploration well to test the a fault block north of the MPF-38 fault block. The geological prognosis includes the Kuparuk C, B, A3, A2, and A1 Kuparuk sands. The primary target is the KUPARUK 'A' Sands with additional potential in overlying 'B' and 'C' sands. If the well encounters commercial hydrocarbons, the well will be suspended utilizing an FMC SD-1 mudline suspension system as per the attached 10-403 request. Otherwise, the 8.5" openhole section will be plugged and the wellbore abandoned as per 20 ACC 25.105. Drillinq Hazards and Risks: The Kuparuk reservoir sands are expected to be a maximum of 3849 psig or 9.6 ppg. The closest well is MPF-38 which was recently drilled by Nabors Rig# 27E. Obtain the MPF-38 workfile from Nabors Rig# 27E and review same. There will be no close approach wells associated with the drilling of the North Milne Point #2 well. An IN-HOLE REFERENCE GYRO will be required on this well in the 8.5" hole section at +9500'. Lost Circulation: The MPF-38 did experience losses due to what has been termed the breathing phenomena, The well takes fluid and then gives some of it back for instance when the pumps are shut down. The recent efforts by Nabors 27E to combat this problem has been to drill with a 9.9 ppg MW versus the standard 10,2 ppg through the Kaparuk Cap rock area, Lost returns while running and cementing the 7" production casing in this portion of the Milne Point Unit is quite common. A lost circulation zone has been verified to exist in what are called the Colville sands which are sometimes encountered at or near the base of the Colville Shale formation near the top of the HRZ. Have the LCM materials outlined in the Drilling Fluid Program on location and recommended pills ready to address the Lost Circulation Problem when drilling into the Kuparuk Sand. Stuck Pipe Potential- The F Pad Data Sheet prepared by Pete Van Dusen will be utilized to drill this well. There was one stuck pipe incident on MPF-53 in the surface hole when running gravels were encountered, The immediate reaction to combat running gravels is to immediately raise the Funnel Viscosity to 150 seconds/quart, There were three stuck pipe incidents on L Pad and one while drilling the No, Point #1 exploration well -- these incidents have been and can continue to be avoided by ensuring good hole cleaning and short tripping techniques, Gas hydrates: Hydrates were encountered on E, H, and I Pads located in the southern portion of the Milne Point Unit; however, no hydrates have been encountered while drilling the J, C, L, or F Pads which are located in the northern portion of the unit -- NO HYDRATES ARE EXPECTED WHILE DRILLING THIS WELL WHICH IS LOCATED IN THE UNIT'S NORTHERN PORTION. Furthermore, there is a neutron density crossover on the surface porosity logs which coincides with the hydrates on the southern pads. This crossover is absent on these northern pads. No other drilling hazards or risks have been identified for this well. BP SECRET Hyctrogen Sulfide -- H2S . (20 AA~. 25.065) There is no evidence of H2S being encountered in any of the offset wells. Specifically, The surface location for the proposed North Milne Point #2 well is located only 2.5 miles northeast along an azimuth of 40° from the surface of the Northwest Milne Point #1 Exploration well-- Mud logs from this well indicate no presence of H2S. The Jones Island #1 well drilled by Arco in the exploration season of 1993 intercepted the Kuparuk formation 5.1 miles due east of the proposed North Milne Point #2 Kuparuk target -- no record of H2S encountered on this well. Furthermore, in reference to Arco's permit to drill the Jones Island #1 Exploration well, research was conducted for the following exploration wells for which there was no evidence of H2S at any of these wells: Sand Piper #1 Well Long Island #1 Well Phlagm Beechey Point Well Seal Island Wells (four) Northstar Wells Since nearby offset well data indicates H2S is not present in any of the formations to be drilled in the North Milne Point #2 well, Shared Services Drilling asks for exemption from items c2B, 02C, and c3 in 20 ACC 25.065 while planning to comply with the following items: clA) clB) clC) c2A) c2D) The mud logging unit will be equipped with a combination visual and audible alarm system located where it can be seen or heard form all parts of the location; The automatic hydrogen sulfide monitor will have a minimum of two probes, one at the shale shaker and one at the bell nipple; and In addition to the automatic hydrogen sulfide monitor, at least three manual detectors will be available at the rig site -- if the manual detectors require tubes, an adequate supply of detector tubes will be available at the rig site. As stated, we do not expect to encounter H2S. In the unlikely event H2S were encountered, the effects would be minimal for the following reasons: · Since our seismic analysis does not indicate any abnormal pore pressure and our MW program is consistent with the offset wells, H2S would be encountered in an overbalance situation and effects would be minimized. · Upon detection, adequate supplies of Caustic Soda are maintained at the rig site to initiate treatments. · Furthermore, since this location is not remote, Baroid could provide adequate supplies of Zinc Carbonate from the mud plant inventory to treat the mud. Furthermore, the Nabors 22E Rig is equipped with six Scott Air-Packs available at the rig floor as standard equipment. All personnel on location are trained in H2S and the use of Self Contained Breathing Apparatus. BP SECRET NORTH MILNE POINT #2 WL ,. WELL SITE SURVEY and PRESSURE ANALYSIS (20 ACC 25.005c8 and 20 AAC 25.061a and c) Site-specific seismic data and offset well information have been utilized to perform a pressure analysis for the drilling of this well. The North Milne #2 Well will TD 300' md past the base of the Kuparuk reservoir into the Miluveach Shale formation -- planned total measured depth is 14832' (8017' sstvd). The seismic data indicates that no abnormally pressured zones should be encountered while drilling the North Milne Point #2 well-- see the Attached 2D Seismic Shallow Hazard Assessment prepared by BPX geophysicist Eric Dioxin complete with three ITT versus Depth Charts numbered 14, 15, and 16 and two plan view maps. Based on these results and the absence of shallow gas or abnormally pressured zones in nearby offset wells, we do not feel a shallow hazard survey is necessary. The closest offset well is the recently drilled Milne Point F-38. The North Milne Point #2 Kuparuk target is located 3.4 miles northeast along a 74° azimuth from the point the MPF-38 well penetrated the Kuparuk reservoir. See Attachment NO. 2 for the MPF-38 MW vs. TVD plot. There have been numerous F-Pad wells drilled north of F Pad that all show similar MW versus TVD plots as depicted in the MPF-38 well with no signs of abnormal pressures. North Milne Point #2 Appraisal well is in the same stratiagraphic structure as these wells. The Jones Island #1 well drilled by Arco in the exploration season of 1993 intercepted the Kuparuk formation 5.1 miles due east of the proposed North Milne Point #2 Kuparuk target. See Attachment NO. 4 for the Jones Island #1 MW vs. TVD plot -- no sign of abnormal pressure. The surface location for the proposed North Milne Point #2 well is located only 2.5 miles northeast along an azimuth of 40° from the surface of the Northwest Milne Point #1 Exploration well-- See Attachment No. 3 for a MW versus TVD plot. Again, the Northwest Milne Point well showed no signs of abnormal geopressure. Cons. BP SECRET A'ITACHMENT NO. _ NMP#2 Pore Pressure, MW, & Fracture Gradient Plot ppg (EMW) 8 9 10 11 12 13 14 15 1000 2000 30O0 A ~ 4000 ~m 5000 6OOO 7OOO 8OOO 9000 ,-, FRAC GRADIENT FEB 1 G 1996 ~Jaska Oil & Gas Cons. Commissiop~ Anchorage BP SECRET - A'I-FACHMENT NO. _ IOO0 2OOO 3OO0 ~4000 50OO 6OO0 70O0 8O0O 7 0 MPF-38 MW versus TVD Plot MW (ppg) 9 10 11 FEB 1 6 1996 Alaska Oi! & Gas Cons. Commission Anchorage BP SECRET A'FTACHMENT NO... Northwest Milne Point #1 MW vs TVD 1000 2OOO 3OO0 4000 5OOO 6000 7OOO 8OOO 7 0 MW (ppg) 8 9 10 11 '-- NWMP#1 BP SECRET A'I-I'ACHMENT NO.,. 1000 20OO 3O00 4000 5OOO 6000 7000 8O0O 9000 10000 Jones Island #1 MW (ppg) 9 Exploration Well 10 11 Jones Island #1 I BP SECRET BP EXPLOR~'ION Memorandum To: From: Subject: Tim Schofield Eric Dixon Milne Point Unit North Milne #1 & #2 2D Seismic Shallow Hazard Assessment Date: January 16, 1996 An analysis to detect shallow abnormally high geopressure has been conducted in the area surrounding the surface locations of North Milne #1 and #2. Results from the analysis predict that no abnormally high geopressures will be encountered while drilling the North Milne wells. This analysis utilized stacking velocities from two nearby 2D seismic lines to derive interval transit time vrs. depth curves. This method is not as accurate at predicting shallow over pressure zones as a high resolution shallow hazard survey, but it is a good gross indicator of abnormal geopressure conditions. No significant velocity inversions were observed in the data. The ITT curve trends are typical of seismic velocities observed in shallow water and near shore environments throughout the Milne Point unit. Chart 15 displays data from five shot points on line S82HB4; acquired in 1982. Chart 14 shows two shot points from a much older line AIG-25 shot in 1977. Chart 16 displays the two closest shot points to the North Milne surface locations. Based on nearby well control, the following shallow subsurface conditions are predicted: Depth ss ft. -2 to 6 Frozen ground composed of sand silts and gravel 6 to 70 Unfrozen sandy silts and clays grading into sand and gravel at about 28 ft. 70 to 1650 Permafrost 1650 to 3500 Unfrozen sands silts and mud stone of the Gubik and Sagavanirktok. Because no shallow gas or strongly over pressured zones have been encountered in nearby wells we do not feel that a shallow hazard survey is needed. Eric Dixon BP SECRET 000~ O0I. III 00000~ 0000~ 000[ O0 L OL 0oo~ OOL ].LI OL O0000L O000L O00L 001. Aiias~.s 0~t A Gas Cons. ~acI~o~'age 000~ 00~ .U.I O0000L 0000~ O00L O0 L I<uP~RuK. ~1 8iii- ~r Proposed lee I1~ ~ d ti'se ¢ s .:,./ · ./ / BP SECRET KuP~RqK STP. u cTU P. E VI Ew' o F I I I I I I I I I I I I I Pot~T t~Ro~EcT. I BP SECRET BP SECRET KILOME,rERS ~ t 1KILOME'rERS STATUTE MILE$O 1 2 S'[ATUTE MILES I I I BP EXPLORATION {ALNiKA) INC. NORTH MILNE/JONES ISLAND I~ L.J. V[NOL IN 12-FE8-9§ Proposed Casing Des.~n for North Milne Point #2 Well (20 ACC 25.030) All calculations utilized in the casing design for this well are based on parameters and guidelines set forth in the BP Casing Design Manual (1994). The Casing Design Summary, Calculations, and a sketch of the proposed casing strings and cement coverage are enclosed. The proposed casing design is in exception to b4) pertaining to wells drilled from a historically shifting natural island. BP makes a formal request that the commission grant the variance to approve the following casing design. BP is confident that shallow gas and abnormal geopressures will not be encountered for drilling this well based on review of seismic data and offset well data as presented in those specific sections of this permit package. Conductor Casing' 20" 91.1# H-40 Welded proposed to be set at +100' md below the mudline similar to the Northwest Milne Point #1 which Conoco drilled from the manmade gravel island. Surface Casing: 9-5/8" 40# L80 Btrc proposed to be set at the Base of the Schrader Bluff Sands into the Seabee Shale at 8204' md (4985' tvd). The Schrader Bluff formation is watered out in the Northern portion of the Milne Point Unit as is evident in the Northwest Milne Point well data and those wells drilling north of Milne Point Unit L and F pads. The 9-5/8" surface casing will provide an adequate shoe to drill through the Kuparuk formation and set 7" into the Miluveach Shale. This standard practice for drilling Kuparuk wells in both the BP operated Milne Point Unit and the Arco operated Kuparuk Unit. I. Burst Calculations were performed for: 1. Displace entire casing full of cement with 9.4 ppg Mud back side. 2. Bump Plug with 3000 psig with Cement to Surface on back side. 3. Casing tested to 3000 psig with 8.6 ppg EMW on back side. 4. Well Control for drilling into a 12.4 ppg EMW reservoir with 9.9 ppg MW calculated for gas influx at the Shoe and at the Surface. II. Collapse Calculations were performed for: 1. Total lost circulation while drilling with 9.4 ppg EMW on backside. , , A 8.34 ppg emw lost circulation zone at 7000' sstvd allows the fluid level to drop to 1276' while drilling with a 10.2 ppg MW. Cementing the casing with 15.8 ppg tail cement channeling to surface and fresh water used to bump the plug. Well Suspended -- Permafrost Freeze Back (see formulas). Total Evacuation was also considered for this string with 9.4 ppg mud on the back side. BP SECRET Iil. Tensile Ca,,.,ulations were performed for: 1. Running casing at 5 feet per second with two times the planned dogleg and 9.4 ppg MW. 2. Displacing Cement with 500 psig back pressure when in reality casing should be on vacuum. 3. Bumping the Cement Plug with 2000 psig and 9.4 ppg mud. IV. Triaxial Calculations were not performed since OD/t ratio > 15. IV. Buckling and Compression Calculations were not performed since this string is <10,000 feet in length. Production Casing: 7" 26# L80 Btrc proposed to be set through the Kuparuk Sands into the Miluveach Shale at 14832' md (8052' tvd). The 7" Iongstring is the standard casing design for Kuparuk wells in both the BP operated Milne Point Unit and the Arco operated Kuparuk Unit. . . Burst Calculations were performed for: 1. Displace Cement with 9.9 ppg EMW on the back side. 2. Bump Plug with 3000 psig and 9.9 ppg mud, Water Ahead, Spacer, and Tail Cement on back side. Casing tested to 3500 psig with back side pressures calculated with 9.6 ppg EMW to TOC and 8.6 ppg EMW above TOC. Calculation was performed for production casing with 12.4 ppg EMW gas influx at surface with gas gradient to formation in the event well is suspended for future completion. II. Collapse Calculations were performed for: 1. Lost Circulation while Drilling ahead in 7" production casing was not considered. 2. Cementing the casing with 15.8 ppg tail cement channeling to surface and fresh water used to bump the plug. 3. DST and total evacuation were not considered for the 7" production casing. III. Tensile Calculations were performed for: 1. Running casing at 5 feet per second with two times the planned dogleg and 9.9 ppg MW. 2. Displacing Cement with 500 psig back pressure when in reality casing should be on vacuum. 3. Bumping the Cement Plug with 3500 psig and 10.2 ppg NaCI/Br brine. IV. Triaxial Calculations were not performed since OD/t ratio > 15. IV. Buckling and Compression Calculations since this string -- although the string is > than 10,000 feet in length, it will not be drilled out. A.r~chor~ BP SECRET 4935'tvd//8069'm~ 7745' tvd/14431 md Cement Interface 7600' md TOC @ 14140' md 20" 91# Casing Shoe @ 140' tvd/140' md Schrader Bluff Sand Top rader Bluff Sand Base Top Seabee Shale 9-5/8"40# L80 Btrc @ 4985' tvd/8204' md t 7" Casing will not be perforated TOC at 12600' md Top Kuparuk Formation 7822' tvd/14532' md 12.0 PP9 Permafrost E Cement 15.8 ppg Class G Cement BP SECRET Top Miluveach Shale 7" 26# L80 Btrc @ 8052' tvd/14832' md 2/10/96 JD Polya Drawing Not to Scale NMP#2 9-5/8" SURFACE CASING CEMENT PROGRAM - HALLIBURTON CASING SIZE: 9-5/8" SPACER: 75 bbls fresh water. CIRC. TEMP 70 deg F at 4500' TVDSS. LEAD CEMENT TYPE: ADDITIVES' Retarder Type E Permafrost WEIGHT: 12.0 ppg APPROX #SACKS' 1575 YIELD:2.17 ft3/sx MIX WATER' 11.63 gal/sk THICKENING TIME: Greater than 4 hrs at 50° F. TAIL CEMENT TYPE: Premium G ADDITIVES: 2.0% CaCI2 WEIGHT: 15.8 ppg APPROX #SACKS: 250 YIELD:l.15 ft3/sx MIX WATER: 5.0 gal/sk THICKENING TIME: Greater than 4 hrs at 50© F. FLUID LOSS' 100-150 cc 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. 1 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/spacer/mud program and ensure compatibility, prior to pumping job. Ensure thickening times are adequate relative to pumping job requirement. Displace at 12 - 15 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. FE~ i ~ 199(~ NMP#2 Well 7" PRODUCTION CASING CEMENT PROGRAM- HALLIBURTON STAGE I CEMENT JOB ACROSS THE KUPARUK INTERVAL: CIRC. TEMP: 7O4O' TVDSS. 140°F BHST 170° F at S PACE R: 20 bbls fresh water 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: 333 THICKENING TIME: 3 1/2 -4 1/2 hrs @ 140° F plus 112 sacks left inside casing to cover Kuparuk formation. FLUID LOSS: < 50cc/30 min @ 140° F FREE WATER: 0cc @ 45 degree angle. CENTRALIZER PLACEMENT: , , . 7"x 8-1/4" Straight Blade Rigid Centralizers. Two per joint on the bottom 34 joints of 7" casing. This will cover 300' above the KUPARUK C1 Sand (68 total). Run two 7"x 8-1/4" Straight Blade Rigid Centralizers on the second full joint inside the 9-5/8" casing shoe. Total 7" x 8-1/4" Straight Blade Rigid Centralizers needed for job is 70. 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: . Stage 1 cement volume is calculated to cover to the start of the drop section at 12,618'-- 1813' md above the Kuparuk Target Sand with 30% excess. BP SECRET CASING DESIGN SUMMARY INorth Milne Point.#2 GENERAL INFORMATION: UNITS SURFACE PRODUCTION Casing Size inches 9.625 7 Weight I bs./ft 4 0 2 6 Grade n/a LB0 LB0 Connection n/a B'['RC BTRC DESIGN CRITERIA: Burst psig 5750 7240 Collapse psig 3090 5410 Tensile M LBS. 91 6 604 DESIGN FACTORS: 3.0 Burst Loads: 3A. Cement Displacement (Dfb > 1.1) 3B. Cementing -- Bump Plug (Dfb > 1.1) 3C. Pressure Test (Dfb > 1.1) 3D,E,F,&G. Well Control / DST (Dfb > 1.15) 7.72 25.50 4.63 4.30 1.68 1.77 2.16 1.44 4.0 Collapse Loads: 4B. Cementing (Dfb > 1.1) 4A,C,or D. Drilling, Loss Circ, Evacuation (Dfb > 1.1) 1.60 1.73 1.59 0.00 5.0 Tensile Loads: 5AorB. Running Casing (Dfb > 1.6) 5DorE. Cementing (Dfb > 1.1) 6.0 Triaxial Loads: (Disregard if OD/t > 15) 2.17 1.92 1.68 1.51 OD/t = 24.37 OD/t = 19.34 7.0 Buckling and Compression Loads: Note: 1) Consider for Casing Set >10,000 feet which will be drilled through, or 2) if MW will increase over 2 ppg when compared with MW used during cementing. Note: All Design Safety Factors based on BPX Casing Design Manual (1994) GENERAL CASING DATA HOLE SECTION HOLE SIZE CASING SIZE WEIGHT GRADE CONNECTION ID BURST COLLAPSE TENSILE (<) TENSILE BODY TENSILE CONN MD of Casing Shoe TVD of Casing Shoe Casing Capacity Annular Capacity SURFACE INTER 1 INTER 2 PROD UNER 916 604 0.0758 0.0383 0,0558 0,0226 3.0 CASING DESIGN WORKBOOK (BURST) Casing Surf SIZE 9.625 WEIGHT 4 0 GRADE L80 CONNECTION BTRC BURST (100% Design Rating) 5750 3A. Pb Displace Cement 2935 Calculated Design Factor 1.96 OK 3B. Pb Bump Cement Plug 1 242 Calculated Design Factor 4.63 OK 3C. Pb Pressure Test Casing 341 5 Calculated Design Factor 1.68 OK Pb WELL CONTROL ~ 3D. Influx at Casing Shoe 11 41 Calculated Safety Factor 5.04 OK 3E. Influx at Surface 2667 Surface Csg Burst Rating 5750 Calculated Safety Factor 2.16 OK BP Minimum Design Factor 1.1 9.625 40 L80 B'T'RC 5750 BHA Calc OD LENGTHinflux BPF BBLS BHA ~ .6.75 :~:':: 0.0259 7.0 DRILL PIPE '~ .~5 ::',' 2026 0.0459 93.0 In fl u x ~ 2296 ~i i i!i?. :.i!::i:. i :~i!:?.';:ii~ ;.~i~i!iiiiii!ii;!~:!;!i!::ii!?:! Hole Diameter 8,5. ID 8.835 MD Shoe 8204 I TVD Shoe 4985 Page B1 - Surface Burst Calculations 9,625 40 L80 BTRC 5750 8.835 0,0758 8204 4985 13A. Pb Displace Cement Calculations Values ISymbol lUnit IDecription & Explanation I 2 9 3 5IPb disp psig Pb disp = Pi - Pb (Burst Pressure applied while cementing) 3192 P/ psig Pi = Psp + Ptc + PIc + Pdf 8204 CheckMD 0 4985 Dshoe feet (tvd) Depth of Casing Shoe 4985 CheckTVD 0 8204 MDshoe feet (md) Measured Depth of Casing Shoe 622 Check Volume., 0 622 VOLcsg bbls Volume of the Casing 1.0 Check % Total 0 0 i INPUT: 1 if Applies Spacer Calulations 0 Psp psig Psp -- CWsp * 0.052 * Hsp · 11.0 CWsp ppg (emw) Equivalent MW of Spacer 0 Vsp bbls Volume of Spacer 0 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length 0 Lsp feet (md) Lsp --- Vsp/Ccap 0.00 I ~ .1 INPUT: 1 if Applies Lead Cement Calculations ,,,, , , 2855 PIc psig PIc = CWIc * 0.052 * HIc 12:O: CWlc ppg (emw) Equivalent MW of Lead Cement 571 V/c bbls Volume of Cement I Pumped 609 ,,,, ,,, 4575 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length 7529 LIc feet (tvd) LIc = Vlc/Ccap 0.92 1 INPUT: 1 if Applies Tail Cement Calculations 337 Ptc psig PIc = CWIc * 0.052 * HIc 15.8 CWtc ppg (emw) Equivalent MW of Tail Cement 51 ' Vtc bbls Volume of Cement I Pumped 51 410 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length 675 Ltc feet (tvd) Htc = Vtc/Ccap 0.08 i. 0 INPUT: 1 if Applies Heavier of Drilling Fluid or Displacement Fluid 0 Pdf psig Pdf = CWdf * 0.052 * Hdf 9;6 MWdf ppg (emw) Equivalent MW of Drlg or Disp Fluid 0 Vdf bbls Volume of Drlg or Disp Fluid 0 Hdf feet (tvd) Hdf=LdflMDshoe*Dshoe 1% TL I%ofTota, Length 0 Ldf feet (tvd) Hdf Vdf/Ccap 0.00 ' '- ~ '~' 2 5 7 Pe psig Pe = Pmud + Psp + PIc + Pdf 4985 Dshoe feet (tvd) Depth of Casing Shoe 8204 MDshoe feet (md) Measured Depth of Casing Shoe 12.25 Big ID inches Last Casing ID or Surface Hole Size whichever is the case~AJ~8~ 458 VOLann bbls Annular Capacity (annular between casing and last casing ID) 0.0558 ANNcap bpf Annular Capacity (annular between casing and last casing ID) · . 0 INPUT: 1 if Applies Drilling Fluid Calculations 677 CheckMD 7527 0 Pmud psig Pmud = MW * 0.052 * Hmud 411 CheckTVD -4574 · 9.4 MW ppg (emw) Density of Drilling Fluid 3 8 Check Volume., -420 0 Vmud bbls Volume of Drilling Fluid 0.1 Check % Total - 1 0 Hmud feet (tvd) Hmud--Lmud/MDshoe*Dshoe % TL I% of Total Length 0 Lmud feet (md) Lmud = Vmud/ANNcap 0.00 I .. 0 INPUT: 1 if Applies Water Ahead Calculations 0 Ph20 psig PIc = CWh20 * 0.052 * Hh20 ": 8i3 CWh2o ppg (emw) Equivalent MW of Water Ahead :~ "75 ' Vh20 bbls Volume of Water Ahead 0 Hh20 feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length 1345 LIc feet (tvd) LIc = VIc/ANNcap 0.00 : 0 INPUT: 1 if Applies Spacer Calculations ,,, 0 Psp psig Psp = CWsp * 0.052 * Hsp · . 8i3 CWsp ppg (emw) Equivalent MW of Spacer ~ 0: Vsp bbls Volume of Spacer ., 0 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length 0 Lsp feet (md) Lsp = Vsp/ANNcap 0.00 I · 1 ' INPUT: 1 if Applies Lead Cement Calculations 257 PIc psig PIc = CWIc * 0.052 * HIc Csg Size 9.625 BTRC 5750 8.835 0.0758 8204 4985 [3B. Pb Bump Plug Calculations Values ]Symbol 1 242 I Pb bump Unit I Decription & Explanation psig Pb bump = Pi - Pe (Pressure Applied when Bumping Plug) 4437 P/ psig Pi = Ptc + Pdf + Pfz + Pbump 8205 CheckMD -1 4985 Dshoe feet (tvd) Depth of Casing Shoe 4985 CheckTVD 0 8204 MDshoe feet (md) Measured Depth of Casing Shoe 622 Check Volurne., 0 622 VOLcsg bbls Volume of the Casing 1.0 Check % Total 0 ' :: 0 INPUT: 1 if Applies Tail Cement Calculations 0 Ptc psig PIc = CWIc * 0.052 * HIc 0.0 CWtc ppg (emw) Equivalent MW of Tail Cement 6,4 Vtc bbls Volume of Cement I Pumped 51 0 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length 84 Ltc feet (tvd) Htc = Vtc/Ccap 0.00 : 1:': INPUT: 1 if Applies Displacement Fluid Calc 2437 Psp psig Pdf = MWdf * 0.052 *Hdf '9;4 MWdf ppg (emw) EMW of Displacement Fluid 622 Vdf bbls Volume of Displacement Fluid 4985 Hdf feet (tvd) Hdf = Ldf/MDshoe*Dshoe % TL I% of Total Length 8204 Ldf feet (md) Ldf = Vdf/Ccap 1.00 I 0. INPUT: 1 if Applies Freeze Protection 0 Pfz psig Pfz = MWfz * 0.052 * Hfz L:7,1 ' CWfz ppg (emw) EMW of Freeze Portection Fluid 0 Vfz bbls Volume of Freeze Protection 0 Hfz feet (tvd) Hfz=Lfz/MDshoe*Dshoe % TL I% of Total Length 0 Lfz feet (tvd) Hfz = Vfz/Ccap 0.00 I 2000 ' Pbump psig Pressure when bump plug .; ,, 31 95 Pe psig Pe = Pdf + Ph20 +Psp +PIc +Ptc 4985 Oshoe feet (tvd) Depth of Casing Shoe 8204 MDshoe feet (md) Measured Depth of Casing Shoe 12.25 Big ID inches Last Casing ID or Surface Hole Size whichever is the case. 458 VOLann bbls Annular Capacity (annular between casing and last cas~ng.~,,-', 0.0558 ANNcap bpf Annular Capacity (annular between casing and last casing ID) :, 1:: · INPUT: 1 if Applies Drilling Fluid Calculations 8204 Check MD 0 Pmud psig Pmud = MW * 0.052 * Hmud 4985 CheckTVD · 8.6 · MW ppg (emw) Density of Drilling Fluid 458 Check Volume., 0 Vmud bbls Volume of Drilling Fluid 1.0 Check % Total 0 Hmud feet (tvd) Hmud--Lmud/MDshoe*Dshoe % TL I% of Total Length 0 Lmud feet (md) Lmud = Vmud/ANNcap 0.00 I :. 0 :: INPUT: 1 if Applies Water Ahead Calculations 0 Ph20 psig PIc = CWh20 * 0.052 * Hh20 8'i3 CWh2o ppg (emw) Equivalent MW of Water Ahead : 0 :. Vh20 bbls Volume of Water Ahead 0 Hh20 feet (tvd) HIc=LIc/MDshoe*Dshoe % TL I% of Total Length 0 LIc feet (tvd) LIc = VIc/ANNcap 0.00 I : 0 INPUT: 1 if Applies Spacer Calculations ,,,, ,, ,,, 0 Psp psig Psp = CWsp * 0.052 * Hsp :' 8~3 CWsp ppg (emw) Equivalent MW of Lead Cement :. 0 Vsp bbls Volume of Lead Cement , , 0 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length 0 Lsp feet (md) Lsp = Vsp/ANNcap 0.00 I 1. · INPUT: 1 if Applies Lead Cement Calculations 2846 PIc psig PIc = CWIc * 0.052 * HIc 12:0 CWIc ppg (emw) Equivalent MW of Lead Cement ~ 41.9: Vic bbls Volume of Cement I Pumped 609 4560 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length 7505 LIc feet (tvd) LIc = VIc/ANNcap 0.91 · 1iI: INPUT: 1 if Applies Tail Cement Calculations 9.625 3C. Pb for Testing Casing Values I Symbol I Unit 341 5 I Pbtestcsg psig 5644 i Pi psig 3000 Ptest psig 10.2 4985 2229 MWorBW ppg(emw) Dshoe feet (tvd) I Pe psig TOC PPfm TOF1 EMW TOF2 EMW TOF3 EMW feet (tvd) ppg (EMW) feet (tvd) ppg (EMW) feet (tvd) ppg (EMW) feet (tvd) ppg (EMW) BTRC 5750 8.835 0.0758 8204 I TVD Shoe 4985 I Description & Explanation Pbtestcsg = Pi- Pe Pi = Ptest + MW (or Brine Weight) * 0.052 * Dshoe Pressure for Test Pressure Test = 3000 psig for Surface Casing Pressure Test = 3500 psig for Producers and 4000 psig for Injectors Mud Weight or Brine Weight True Vertical Depth of Casing Shoe Pe -- (EMW * 0.052 * Dshoe) cumm for various fluid levels Cummulative gradient from TD to Surface (see notes below): TVD Height of TOC or TVD of Hole Section based on notes below Pore Pressure of Adjacent fm TVD Height of Fluid Level EMW of Fluid or Pore Pressure of Adjacent fm based on notes below TVD Height of Fluid Level EMW of Fluid or Pore Pressure of Adjacent fm based on notes below TVD Height of Fluid Level EMW of Fluid or Pore Pressure of Adjacent fm based on notes below EMWleast is a combination of the following: 1) For casings in contact with formation via cement EMW = Pore Pressure 2) For uncemented casing across from fm or csg ann, Pe is lower of: a) the lowest expected pore pressure in the uncemented section, or b) a full column of mud mix in the annulus with zero surface pressure. 3) For casing to casing annuli sealed by cement (i.e., top of cement above shoe of previous casing) Pe is pore pressure up to the previous casing shoe. In the annulus above the previous casing shoe Pe is defined as follows: a) If inclination exceeds 30 degrees, OR the time since casing installation at potential exposure to the burst loading exceeds 6 months Pe is as for casing exposed via and uncemetned section. b) If inclination less than 30 degrees AND the time since casing installation at potential exposure to the burst loading is less thant 6 months Pe can be taken as mud weight to the top of cement with zero surface pressure. This porvision which in some circumstances may result in less onerous burst requirements should only be used where there is high confidence in both an adequate cement job, and that mt properties will adequately inhibit settling for this period. 4) No external structural support form the cemnt sheath and formation is to be assumed during design, this requirement reflects uncertainty regarding the presence of voids and micro annuli. 5) The external pressure profile for burst differs from that assumed for collapse. This is because the more onerous requirement in collapse is to assume that mud does not settle out, while in burst it is more onerous to assume it does settle. 6) The time and inclination limits above can be modified if appropriate using specialist advice on mud properties. Page B4 - Surface Burst Calculations ~* ~ .... ~i '" ~ ' ~ ?' CL~' ~ · . Burst 5750 ID 8.835 I Ccap(bpf) 0.0758 MD Shoe 8204 I TVD Shoe 4985 3D. Pb Well Control for Influx at the Casing Shoe Values I Symbol IUnit I Description & Explanation Pbx@shoe psig Pbx@shoe = Pi - Pe 2229 3370 3370 i d2';5 0:5. 4985 ,4985 Pe psig Pe = pp * 0.052 * Dint pp ppg (emw) Pore Pressure on external casing. Pfs psig LOT ppg (emw) TM ppg Dshoe feet (tvd) Dxtop feet (tvd) Pi = Pxtop + ((Pfs-Pxtop)/Dshoe) x Dxtop Pfs = (LOT + TM) * Dshoe * 0.052 Fracture Pressure @ shoe for casing design Formation Fracture Gradient at the Casing Shoe Trip Margin (0.5 ppg for Exploration and 0.2 ppg for Development) Depth of Last Casing Shoe Depth of Point of Interest Psurf = [(S^2/4) + {(K * MW * 0.052)/Cbha}]^l/2 - SI2 where: S = Dr * MW * 0.052 + Px -Pf ir Values 2797 -792 499737 7745 ;9.9 100 218 ~:0;1 2179 0.0436 0.0459 8.5 5 4997 :1,08 4627 11.5 ~0;12 3866 9,6 ISymbol IUnit Iixt°p psig psig constant feet (tvd) PPg IVx bbls IPx psig gg psi/ft hgas feet (tvd) Cbha bpf Cdp bpf Dx inches Odp BHP psig design factor ID/:P psig DPP(emw) ppg COV factor Mean PP psig ,I EMWr ppg I Decription & Explanation Maximum Pressure at Top of Influx S = Dr* MW* 0.052 + Px- BHP K = BHP * Vx Depth of formation initiating influx Mud Weight = Expected Pore Pressure + Overbalance (Note: Overbalance for Kick Desing is not to exceed 0.5 ppg) Initial Influx Volume Development Well (70 bbls) Exploration Well (100 bbls) ~ .4 :i ~ i ~ ~ '~'~ Hydrostatic pressure of gas influx, psi (hgas x gg) gg is the gas gradient ~: F'J~ t O 1996 gg is 0.1 psi/ft for Exploration <10,000 feet. - , gg is 0.15 psi/ft for Exploration >10,000 feet. gg is calculated from actual case in production fleld~J~e,~8 Oil, ,~,c~¢';'~'~ * hgas is the tvd height of the gas Aiioh0~'8~ Annular Capacity including BHA Annular Capacity for Drill Pipe Only Diameter of hole at top of influx (Use Casing ID) Diameter of drill pipe Bottom Hole Pressure = DPP x design factor x 0.052 x Dr BHP = 1.05 X DPP (for Development Wells) BlIP = 1.08 x DPP (for Exploration Wells) Design Pore Pressure Design Pore Pressure (Equivalent Mud Weight) DPP= Meanpp*(1+1.64*COV) COV is the Coefficient of Variance COV is 0.06 for development wells COV is 0.12 for exploration wells with some relevent offset data COV is 0.20 for exploration wells with no relevent offset data Mean Pore Pressure Either the mean pore pressure calculated in nearby wells or the most likely geophysical estimate. EMW of Reservoir Page B5 - Surface Burst Calculations Csg Size 9.625 40 L80 BTRC 5750 8.835 Ccap(bpf) I 0.0758 MD Shoe 8204 3E. Pb Well Control for Influx at the Surface Values ISymb°l IUnit IDescripti°n & Explanation 2667 I Pbx@surf psig Pbx@surf = Pi - Pe 4.7 I Pe psig Pe = Atmospheric Pressure 2682 I Pi :~ 3370 Pfs psig 12.5 0.5 4985 2O LOT ppg (emw) TM ppg Dshoe feet (tvd) Dint feet (tvd) Pi = Psurf + ((Pfs-Psurf)/Dshoe) x Dint Pfs = (LOT + TM) * Dshoe * 0.052 Fracture Pressure @ shoe for casing design Formation Fracture Gradient at the Casing Shoe Trip Margin is 0.5 ppg ( Exploration and 0.2 ppg for Development) Depth of Last Casing Shoe Depth of Point of Interest Psurf = [(S^2/4) + {(K * MW * 0.052)/C}]^1/2 - S/2 where: S = Dr * MW * 0.052 + Px -Pf I TVD Shoe 4985 Values ISymbol IUnit 2679 lisurf -816 499737 [ 1 00 JVx 1 94 O. 1 gg psig psig constant feet (tvd) PPg bbls 1940 0.0515 8.835 5 4997 1.08 4627 11.5 I o. 2 I psig psi/ft hgas feet (tvd) C bbls/ft Dx inches Odp BHP psig design factor DPP psig DPP(emw) ppg COV factor 3866 I Mean PP psig 9.6 I EMWr ppg I Decription & Explanation Maximum Pressure at Top of Bubble S = Dr* MW * 0.052 + Px -Pr K = BHP * Vx Depth of formation initiating influx Mud Weight = Expected Pore Pressure + Overbalance (Note: Overbalance for Kick Desing is not to exceed 0.5 ppg) Initial Influx Volume Development Well (70 bbls) Exploration Well (100 bbls) Hydrostatic pressure of gas influx, psi (hgas x gg) gg is the gas gradient gg is 0.1 psi/ft for Exploration <10,000 feet. gg is 0.15 psi/ft for Exploration >10,000 feet. gg is calculated from actual case in production field hgas is the tvd height of the gas Annular Capacity below top of influx Diameter of hole at top of influx (Use Casing ID) Diameter of drill pipe Bottom Hole Pressure = DPP x design factor x 0.052 x Dr BHP = 1.05 X DPP (for Development Wells) BHP = 1.08 x DPP (for Exploration Wells) Design Pore Pressure Design Pore Pressure (Equivalent Mud Weight) DPP= Meanpp*(1+1.64*COV) COV is the Coefficient of Variance COV is 0.06 for development wells COV is 0.12 for exploration wells with some relevent offset data COV is 0.20 for exploration wells with no relevent offset data Mean Pore Pressure Either the mean pore pressure calculated in nearby wells or the most likely geophysical estimate. EMW of Reservoir Page B6 - Surface Burst Calculations FEB i8 199 4.0 CASING DESIGN PROGRAM (COLLAPSE) Casing Surf SIZE 9.625 WEIGHT 4 0 GRADE L80 CONNECTION BTRC Collapse (100% Design Rating) 3090 4A. LC While Drilling Ahead 624 Calculated Design Factor 4.95 OK.11 ~f Applies, Else 0: 4B. Cementing Tail Cmt to Surf 1 934 Calculated Design Factor 1.60 OK I1 if Applies, Else 0: !~ii:;*~!i~?~ii!~?i~ii~!!i~i~i~!:~:iiii~ii~!!i~i!ii!~i!i~i~:iii~ii 4C. Permafrost FZ Back 1377 Calculated Design Factor 2.24 OK I1 if Applies, Else 0: i?ii?i.ii?i;:i?i?i;.ii~;:i;iiiiliiiii?ii??ii~;?iii!:;!;~i; 4D. Total Evacuation of Csg 1938 Calculated Design Factor 1.59 OK I1 if Applies, Else 0: i:~;::!:i:ilili:i!i(i!~iii:!!::i:;ii!;~::!ii:;~.i!::!i.!ii?..~!i!~iiii:~ii:.:i. BP Minimum Design Factor 1.1 9,625 40 L80 BTRC 3090 8.835 0.0758 8204 4985 4A. Total Lost Circulation While Drilling Values I Symbol I Unit 62 4 PClc psig 9.4 I FDbc ppg (umw) 1276 Dtof feet (md) 7000 I D/cz feet (tvd) 5724 Heqmw feet (tvd) 10.2 J MW ppg (umw) 3036 Plcz psig ,18.34 I PPIcz ppg (emw) I Decription & Explanation PClc=MWbc*0.052*Dtof (Collapse Press--Lost Circ While Drlg) Density of Fluid behind casing (Most Likely MW ahead of Cement) Dtof=DIcz-Heqmw Depth of Lost Circulation Zone Heqmw=Plcz/(MW*0.052) Height of Equiv Balanced MW column Mud Weight of Drilling Fluid PIcz=PPIcz*0.052*DIcz Pore Pressure of Lost Circulation Zone 4B. Cementing (Assumes Tail Cement Channels to Surface Bump Plug w! Fresh Water) Values ISymbol IUnit 1 934 PCshoe psig 4096 Pe psig 15.8 J CWtc ppg (umw) 4985 Dshoe feet (tvd) 2162 Pi psig 8,34 J MWdf ppg (emw) I Decription & Explanation PCshoe=Pe-Pi (Collapse Press at Shoe--Lead Cement Channels to Surface) Pe=CWtc*0.052*Dshoe Weight of Tail Cement Depth of Casing Shoe Pi=MWdf*0.052*Dshoe Mud Weight of Displacement Fluid 4C. Well Suspended -- Permafrost Freeze Back Values I Symbol I Unit 1 377 PCpermfz psig 2074 Pe psig [ 2000 J Dpermfz feet (tvd) 1282 Pfz<800' psig 792 Pfz>800' psig 697 Pi psig I Decription & Explanation PCpermfz=Pe-Pi Pe=Pfs<800 + Pfz>800 Depth of the Permafrost Pfz<800=1.44'800+130 Pfz>800=0.66*(Dpermfz-800) Pi=FZPROTemw*0.052*Dpermfz [ 6.7 I MWfzprot ppg (emw) Mud Weight of Freeze Protecton Fluid (Worst Case is diesel) 4D. Total Evacution While Running Casing Values ISymb°l IUnit IDecripti°n & Explanation 1 938 PCevac psig 2437 Pe psig 4985 Dshoe feet (tvd) n~ I MW nnn (FMW) Pe:MW * 0.052 * Dshoe Depth of Casing Shoe MW in hole while running casina 5.0 CASING DESIGN PROGRAM (TENSILE) Casing Surface SIZE 9.625 WEIGHT 4 0 GRADE L80 CONNECTION BTRC Tensile (100% of Rated) 916 MLB. 5A. Ft(1) = Fwt-Fbuoy+Fbend 319.331 M LB. Calculated Design Factor 2.87 OK BP Minimum Design Factor 1.6 5B. Ft(2) = Fwt-Fbuoy+Fbend+Fshock 421.270 M LB. Calculated Design Factor 2.17 OK BP Minimum Design Factor 1.4 5C. Ft(3) = Fwt-Fbuoy+Fbend+Fop 334.955 M LB. Calculated Design Factor 1.4 OK BP Minimum Design Factor 1.4 5D. Ft(4) = Fwt-Fbuoy+Fbend+Fplug+Fshock 319.331 M LB. Calculated Design Factor 2.87 OK BP Minimum Design Factor 1.4 5E. Ft(5) = Fwt-Fbuoy+Fbend+Fplug+Fshock 543.882 M LB. Calculated Design Factor 1.68 OK BP Minimum Design Factor 1.4 9.625 40 L80 BTRC 5 Speed 916 8.835 0.0758 8204 I TVD Shoe 4985 ppg (emw) Mud Weight deg/100ft Dog Leg Severity (Add 3 to the plan to account for field results) fps Casing Running Speed (5' is recommended) Casing Design Minimum Requirements: Page 1T .- Surface Casing Tensile 9.625 40 L80 BTRC 91 6 8.835 ICcap(bpf) I MD Shoe TVD Shoe 0.0758 8204 4985 5A. Tensile Forces While Running Casing (Ft(1) = Fwt - Fbuoy + Fbend) I Values ISymbo~ lUnit IDecription & Explanation I 319.331 Ft(1) IMIbs. force Ft(1)=Fwt 199.400 IFwt M lbs. force 40 W ppf 4985 Dtvd feet (tvd) 2437 Pe psig 72.76 Ao sq.in. 2437 Pi psig 61.31 Ai sq.in. - Fbuoy + Fbend Air Weight of Casing Weight per unit length of casing True Vertical Depth below the point of interest to TD of casing Upward Buoyancy force Acting on the Bottom of the Casing at TD Fbuoy = Pe*Ao-Pi*Ai Pressure at the bottom of Casing (external) Area of casing OD Pressure at the bottom of Casing (internal) Area of casing ID Bending Component of the Tensile Load resuling from Hole Curvature Fbend = 64*DLS*OD*CSGppf 5B. Tensile Forces While Running Casing Ft(2) = Fwt - Fbuoy + Fbend + Fshock Values ISymbol lUnit IDecription & Explanation Ft(2) = Fwt - Fbuoy + Fbend + Fshock Fwt, Fbuoy, and Fbend (Same values Calculated Above Apply) 01.939 ~ Fshock MIbs. force Fshock=1780*v*As 5 v ft/sec v = 5 fi/sec as per BP Casing Design Manual 11.45 As sq.in. As = 0.7854 * (OD^2 - ID^2) 5C. Maximum Overpull While Running Casing Ft(3) = Fwt - Fbuoy + Fbend + Fop I Values ISymbo~ lUnit IDecription & Explanation Fop = (Tensile Rating/l.4)-Ft(1) (Calculate the Max Allowable Overpull) Ft(1) = Fwt, Fbuoy, and Fbend (Same values Calculated Above Apply) 654.286 TENcorr M lbs. force TENcorr = Tensile Rating/1.4 319.331 Ft(1) M lbs. force (Fwt - Fbuoy + Fbend) 5D. Tensile Force While Displacing Cement Ft(4) = Fwt - Fbuoy + Fbend + Fplug + Fshock Values ISymbol IUnit IDecription & Explanation L 498.192 Ft(4) 395.052 Fwt 177.292 Fbuoy M lbs. force 147.840 Fbend M lbs. force 30.653 Fplug M lbs. force Psurf psig JM lbs. force Ft(4) = Fwt - Fbuoy + Fbend + Fplug + Fshock M lbs. force Fwt = Fwt * Csg Ai * Hydrostatic Pressure (Mud + Cement + Spacer) 3046 Pmax psig 101.939 Fshock M lbs. force Fbuoy = Csg Ao * Hydrostatic Column of Mud in Annulus Fbend -- Same Value Calculated Above Applies Fplug = Psurf * Ai Psurf Surface Pressure While Displacing Cement (ROT 500) Note: The well will most likely be on suction while the cement is being pumped to the shoe; however, for conservative design use 500 psig for surface pressure. Pmax = ((TENrtg/1.4)-(Fwt-Fbuoy+Fbend+Fshock))/Ai Fshock (Same Value as Calculated above Applies) Page 2T-- Surface Casing Tensile ID 8.835 0.0758 8204 4985 5E. Tensile Force Exerted Bumping Cement Plug Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock Values ISymb°l lUnit IDecripti°n & Explanation I 543.882 Ft(5) 348.783 Fwt 177.292 Fbuoy 147.840 Fbend M lbs. force 122.612 Fplug M lbs. force Psurf psig 3801 Pmax psig 101.939 Fshock M lbs. force lbs. force Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock lbs. force Fwt = Fwt * Csg Ai * Hydrostatic Pressure (Displacement Fluid) lbs. force Fbuoy = Csg Ao * Hydrostatic Column of Mud, Spacer, and Cement in Annulu Hydrostatic Pressure (Mud+Cement+Spacer-- Calc Below 5E.1) Fbend -- Same Value Calculated Above Applies Fplug = Psurf * Ai Psurf is Pressure Required to Bump Plug. Use Casing Test Pressures from SSD Recommended Practices Surface 3000, Intermediate & Production 3500, Injector 4000 Pmax = ((TENrtg/l.4)-(Fwt-Fbuoy+Fbend+Fshock))/Ai Fshock (Same Value as Calculated above Applies) 5E.1 Tensile Force Exerted Bumping Cement Plug Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock 2437 Phydann psig Pe = Pdf + Ph20 +Psp +PIc +Ptc 4985 Dshoe feet (tvd) Depth of Casing Shoe 8204 MDshoe feet (md) Measured Depth of Casing Shoe 12.25 Big ID inches Last Casing ID or Surface Hole Size whichever is the case. 458 VOLann bbls Annular Capacity (annular between casing and last casing ID) 0.0558 ANNcap bpf Annular Capacity (annular between casing and last casing ID) 1 ' · INPUT: 1 if Applies Drillin9 Fluid Calculations 8204 Check MD 0 2437 Pmud psig Pmud = MW * 0.052 * Hmud 4985 CheckTVD 0 9.4 MW ppg (emw) Density of Drilling Fluid 458 Check Volurr 0 ,, ,,, 458 Vmud bbls Volume of Drilling Fluid 1.0 Check % To1 0 4985 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe %TL I% of Total Length 8204 Lmud feet (md) Lmud = Vmud/ANNcap 1.00 I 0 INPUT: 1 if Applies Water Ahead Calculations 0 Ph20 psig PIc = CWh20 * 0.052 * Hh20 8,3 CWh2o ppg (emw) Equivalent MW of Water Ahead O, Vh20 bbls Volume of Water Ahead ,,,,, 0 Hh20 feet (tvd) HIc=LIc/MDshoe*Dshoe % TL I% of Total Length 0 LIc feet (tvd) LIc = Vlc/ANNcap 0.00 I 0 INPUT: 1 if Applies Spacer Calculations 0 Psp psig Psp = CWsp * 0.052 * Hsp : 8~3 CWsp ppg (emw) Equivalent MW of Spacer 0 Vsp bbls Volume of Spacer 0 Hsp feet (tvd) Hsp--Lsp/MDshoe*Dshoe % TL I% of Total Length 0 Lsp feet (md) Lsp = Vsp/ANNcap 0.00 I 0 INPUT: 1 if Applies Lead Cement Calculations , 0 PIc psig PIc = CWIc * 0.052 * HIc :12,0 CWlc ppg (emw) Equivalent MW of Lead Cement '417 V/c bbls Volume of Cement I Pumped 609 0 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length 7484 LIc feet (tvd) LIc = VIc/ANNcap 0.00 0 INPUT: 1 if Applies Tail Cement Calculations 0 Ptc psig Plo = CWIc * 0.052 * HIc ~_1. 5~8 . CWtc ppg (emw) Equivalent MW of Tail Cement 40.1 Vtc bbls Volume of Cement I Pumped 51 0 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length 720 Ltc feet (tvd) Htc = Vtc/Ccap 0.00 Page 3T- Surface Casing Tensile 3.0 CASING DESIGN WORKBOOK (BURST) Casing WEIGHT GRADE CONNECTION BURST (100% Design Rating) 3A. Pb Displace Cement Calculated Design Factor 3B. 3C. Pb Bump Cement Plug Calculated Design Factor Pb Pressure Test Casing Calculated Design Factor Pb Well Control 3D. Influx at Casing Shoe Calculated Safety Factor 3E. Influx at Surface Surface Csg Burst Rating Calculated Safety Factor BP Minimum Design Factor Prod 7.000 26 L80 BTRC 724O 3F. Pb DST (HC to Surface) 5041 Calculated Design Factor 1.44 1 if Applies, Else 0: i.ili.liiii:i?~iiiii?i?:i?;~ii?iiii;.i;.i;.ii;.~iiiii;:ii;.i?i OK o. I Pb Tubing Leak (DST or Prod) I 0 Calculated Design Factor I N/A o. I 284 25.50 1682 4.30 4094 1.77 0 N/A 0 7240 N/A 1.1 o. I 7.000 2 6 LB0 BTRC 7240 6.276 BHA Calc OD LENGTHinflux BPF ~ BHA 4;75: ~: i ':::2~0 :i: ! .I 0.0131 3.5 , DRILL PIPE :::. 3;5..: ; 4182 0.0231 96.5 Influx ~ 4452 Hole Diameter [ 6 I ICcap(bpf) l MDShoe ITVDShoe 0.0383 14832 8052 Page B1 -. Production Burst Calculations Csg Size 7.000 Weight I Grade Conn 26 LB0 BTRC 13A. Pb Displace Cement Calculations I TVD Shoe 8052 Values ISymbol IUnit 28 4 I Pb disp psig I Decription & Explanation Pb disp = Pi - Pb (Burst Pressure applied while cementing) 4398 Pi psig Pi = Psp + Ptc + PIc + Pdf 1 4832 CheckMD 0 8052 Dshoe feet (tvd) Depth of Casing Shoe 8052 CheckTVD 0 14832 MDshoe feet (md) Measured Depth of Casing Shoe 568 Check Volume., 0 568 VOLcsg bbls Volume of the Casing 1.0 Check % Total 0 : 1 INPUT: 1 if Applies Spacer Calulations 568 Psp psig Psp = CWsp * 0.052 * Hsp 11.0 CWsp ppg (emw) Equivalent MW of Spacer 70 Vsp bbls Volume of Spacer 993 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length 1829 Lsp feet (md) Lsp = Vsp/Ccap 0.12 I 0 INPUT: 1 if Applies Lead Cement Calculations , ,,,,, 0 PIc psig PIc = CWIc * 0.052 * HIc 12.0 CWIc ppg (emw) Equivalent MW of Lead Cement 0 Vic bbls Volume of Cement I Pumped 0 0 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length 0 LIc feet (tvd) LIc = VIc/Ccap 0.00 I INPUT: 1 if Applies Tail Cement Calculations 525 Ptc psig Plo -- CWIc * 0.052 * HIc 15.8 CWtc ppg (emw) Equivalent MW of Tail Cement 45 Vtc bbls Volume of Cement I Pumped 68 638 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length 1176 Ltc feet (tvd) Htc = Vtc/Ccap 0.08 1 INPUT: 1 if Applies Heavier of Drilling Fluid or Displacement Fluid 3305 Pdf psig Pdf = CWdf * 0.052 * Hdf 9.9 MWdf ppg (emw) Equivalent MW of Drlg or Disp Fluid 453 Vdf bbls Volume of Drlg or Disp Fluid 6420 Hdf feet (tvd) Hdf=Ldf/MDshoe*Dshoe I % TL I% of Total Length 11827 Ldf feet (tvd) Hdf = Vdf/CcapI 0.80 I 411 4 Pe psig Pe = Pmud + Psp + PIc + Pdf 8052 Dshoe feet (tvd) Depth of Casing Shoe 1 4832 MDshoe feet (md) Measured Depth of Casing Shoe 8,835 Big ID inches Last Casing ID or Surface Hole Size whichever is the case. 41 9 VOLann bbls Annular Capacity (annular between casing and last casing ID) 0.0282 ANNcap bpf Annular Capacity (annular between casing and last casing ID) 1. INPUT: 1 if Applies Drilling Fluid Calculations 1 4832 CheckMD 0 3947 Pmud psig Pmud = MW * 0.052 * Hmud 8052 CheckTVD 0 9.9 /V/VV ppg (emw) Density of Drilling Fluid 419 CheckVolume.~ 0 399 t/mud bbls Volume of Drilling Fluid 1.0 Check % Total 0 7667 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length 14123 Lmud feet (md) Lmud = Vmud/ANNcap 0.95 I 1 IINPUT: 1 if Applies Water Ahead Calculations 1 67 Ph20 psig PIc = CWh20 * 0.052 * Hh20 8.3 CWh2o ppg (emw) Equivalent MW of Water Ahead 20 Vh20 bbls Volume of Water Ahead ,,, 385 Hh20 feet (tvd) HIc=LIc/MDshoe*Dshoe % TL I% of Total Length 709 LIc feet (tvd) LIc = VIc/ANNcap 0.05 I 0 INPUT: 1 if Applies Spacer Calculations , 0 Psp psig Psp = CWsp * 0.052 * Hsp : 8,3 CWsp ppg (emw) Equivalent MW of Spacer 0 Vsp bbls Volume of Spacer 0 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length 0 Lsp feet (md) Lsp = Vsp/ANNcap 0.00 I 0 INPUT: 1 if Applies Lead Cement Calculations ,,,, ,,, 0 PIc psi(~ PIc = CWIc * 0.052 * HIc Csg Size 7.000 2 6 L80 BTRC 7240 6.276 0.0383 14832 8052 13B, Pb Bump Plug Calculations Values ISymbol IUnit 1 682 IPb bump psig I Decription & Explanation Pb bump = Pi - Pe (Pressure Applied when Bumping Plug) 6277 P/ psig Pi = Ptc + Pdf + Pfz + Pbump 1 4833 Check MD - 1 8052 Dshoe feet (tvd) Depth of Casing Shoe 8052 CheckTVD 0 14832 MDshoe feet (md) Measured Depth of Casing Shoe 11 2 5 Check Volume., 0 I 1 2 5 VOLcsg bbls Volume of the Casing 1.0 Check % Total 0 · 1 INPUT: 1 if Applies Tail Cement Calculations ,, ,, I 9 Ptc psig PIc = CWIc * 0.052 * HIc ~115~8 CWtc ppg (emw) Equivalent MW of Tail Cement ~3;2 Vtc bbls Volume of Cement I Pumped 68.2 23 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length 42 Ltc feet (tvd) Htc = Vtc/Ccap 0.00 1' INPUT: 1 if Applies Displacement Fluid Calc 4259 Psp psig Pdf = MWdf * 0.052 * Hdf : 10;2 MWdf ppg (emw) EMW of Displacement Fluid 1121 Vdf bbls Volume o Displacement Fluid 8029 Hdf feet (tvd) Hdf = Ldf/MDshoe*Dshoe % TL I% of Total Length 14790 Ldf feet (md) Ldf -- Vdf/Ccap 1.00 I 0 INPUT: 1 if Applies Freeze Protection 0 Pfz psig Pfz = MWfz * 0.052 * Hfz ~7,1~ CWfz ppg (emw) EMW of Freeze Portection Fluid 0 Vfz bbls Volume of Freeze Protection 0 Hfz feet (tvd) Hfz=Lfz/MDshoe*Dshoe % TL I% of Total Length 0 Lfz feet (tvd) Hfz = Vfz/Ccap 0.00 I 2000 Pbump psig Pressure when bump plug 4 596 Pe psig Pe = Pdf + Ph20 +Psp +PIc +Ptc 8052 Dshoe feet (tvd) Depth of Casing Shoe 14832 MDshoe feet (md) Measured Depth of Casing Shoe 8.835 Big ID inches Last Casing ID or Surface Hole Size whichever is the case. 41 9 VOLann bbls Annular Capacity (annular between casing and last casing ID) 0.0282 ANNcap bpf Annular Capacity (annular between casing and last casing ID) 1 ~. INPUT: 1 if Applies Drilling Fluid Calculations 1 4832 CheckMD 0 2634 Pmud psig Pmud = MW * 0.052 * Hmud 8052 CheckTVD 0 9:'9 MW ppg (emw) Density of Drilling Fluid 41 9 Check Volume,, 0 266 Vmud bbls Volume of Drilling Fluid 1.0 Check % Total 0 5116 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length 9425 Lrnud feet (md) Lmud = Vmud/ANNcap 0.64 I 11' INPUT: 1 if Applies Water Ahead Calculations 1 67 Ph20 psig PIc = CWh20 * 0.052 * Hh20 '8.3 CWh2o ppg (emw) Equivalent MW of Water Ahead 20 Vh20 bbls Volume of Water Ahead 385 Hh20 feet (tvd) HIc=LIc/MDshoe*Dshoe % TL I% of Total Length 709 LIc feet (tvd) LIc = VIc/ANNcap 0.05 I ,1 INPUT: 1 if ApPlies Spacer Calculations ,,, ,,, 805 Psp psig Psp = CWsp * 0.052 * Hsp .....1,.,1:,5 CWsp ppg (emw) Equivalent MW of Lead Cement 70 Vsp bbls Volume of Spacer 1346 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length 2480 Lsp feet (md) Lsp = Vsp/ANNcap 0.17 I 0 INPUT: 1 if Applies Lead Cement Calculations 0 PIc psig PIc = CWIc * 0.052 * HIc .12,0 CWIc ppg (emw) Equivalent MW of Lead Cement i0 Vic bbls Volume of Cement I Pumped 0 0 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length 0 LIc feet (tvd) LIc = VIc/ANNcap 0.00 ' i i IINPUT: 1 if Applies Tail Cement Calculations 7.000 26 L80 B'I'RC 7240 6.276 I Ccap(bpf) I MD Shoe 0.0383 ,J 14832 I 'FVD Shoe 8052 3C. Pb for Testing Casing Values ISymbol ]Unit 4094 I Pbtestcsg psig 7771 I P/ psig /3500. [ Ptest psig i!0'2 I MWorBW ppg(emw) 8052 Dshoe feet (tvd) Description & Explanation Pbtestcsg = Pi - Pe Pi = Ptest + MW (or Brine Weight) * 0.052 * Dshoe Pressure for Test Pressure Test = 3000 psig for Surface Casing Pressure Test = 3500 psig for Producers and 4000 psig for Injectors Mud Weight or Brine Weight True Vertical Depth of Casing Shoe 3676 I Pe psig Pe = (EMW * 0.052 * Dshoe) cumm for various fluid levels : 6~Oo · , , . · ;0 0 TOC feet (tvd) PPfm ppg (EMW) TOF1 feet (tvd) /7¢/W ppg (EMW) TOF2 feet (tvd) Bt4W ppg (EMW) TOF3 feet (tvd) /gt4W ppg (EMW) Cummulative gradient from TD to Surface (see notes below): TVD Height of TOC or TVD of Hole Section based on notes below Pore Pressure of Adjacent fm TVD Height of Fluid Level EMW of Fluid or Pore Pressure of Adjacent fm based on notes below TVD Height of Fluid Level EMW of Fluid or Pore Pressure of Adjacent fm based on notes below TVD Height of Fluid Level EMW of Fluid or Pore Pressure of Adjacent fm based on notes below EMWleast is a combination of the following: 1) For casings in contact with formation via cement EMW = Pore Pressure 2) For uncemented casing across from fm or csg ann, Pe is lower of: a) the lowest expected pore pressure in the uncemented section, or b) a full column of mud mix in the annulus with zero sur[ace pressure. 3) For casing to casing annuli sealed by cement (i.e., top of cement above shoe of previous casing) Pe is pore pressure up to the previous casing shoe. In the annulus above the previous casing shoe Pe is defined as follows: a) If inclination exceeds 30 degrees, OR the time since casing installation at potential exposure to the burst loading exceeds 6 months Pe is as for casing expo via an uncemetned section. b) Il' inclination less than 30 degrees AND the time since casing installation at potential exposure to the burst loading is less thant 6 months Pe can be taken a,= mud weight to the top of cement with zero surface pressure. This porvision whic in some circumstances may result in less onerous burst requirements should only be used where there is high confidence in both an adequate cement job, and tha' properties will adequately inhibit settling for this period. 4) No external structural support form the cemnt sheath and formation is to be assumed during design, this requirement reflects uncertainty regarding the presence of voids and micro annuli. 5) The external pressure profile for burst differs from that assumed for collapse. This is because the more onerous requirement in collapse is to assume that mud does settle out, while in burst it is more onerous to assume it does settle. 6) The time and inclination limits above can be modified if appropriate using specialist advice on mud properties. Page B4 -- Production Burst Calculations 8052 I-'1~ I.J~ly , Io -- ~,LU II IVl) I.J~llU~, Fracture Pressure @ shoe for casing design LOT ppg (emw) Formation Fracture Gradient at the Casing Shoe TM ppg Trip Margin is 0.5 ppg ( Exploration and 0.2 ppg for Development) Dshoe feet (tvd) Depth of Last Casing Shoe Dxtop feet (tvd) Depth of Point of Interest Psurf = [(S"2/4) + {(K * MW * 0.052)/Cbha}]^l/2 - Si2 where: S = Dr * MW * 0.052 + Px -Pf Values I Symbol I Unit 3651 IPxtop -590 IS 501038 ~K psig psig constant feet (tvd) PPg bbls t.... .......... ! psig psi/ft 0.0225 0.0231 6 3.5 5010 4772 11.8 hgas feet (tvd) Cbha bpf Cdp bpf Dx inches Odp B/-f' psig design factor DPP psig DPP(emw) ppg [ 3987 J MeanPP psig I Decription & Explanation Maximum Pressure at Top of Influx S = Dr* MW* 0.052 + Px - BHP K = BHP * Vx Depth of formation initiating influx Mud Weight = Expected Pore Pressure + Overbalance (Note: Overbalance for Kick Desing is not to exceed 0.5 ppg) Initial Influx Volume Development Well (70 bbls) Exploration Well (100 bbls) Hydrostatic pressure of gas influx, psi (hgas x gg) gg is the gas gradient gg is 0.1 psi/ft for Exploration <10,000 feet. gg is 0.15 psi/ft for Exploration >10,000 feet. gg is calculated from actual case in production field hgas is the tvd height of the gas Annular Capacity including BHA Annular Capacity for Drill Pipe Only Diameter of hole at top of influx (Use Casing ID) Diameter of drill pipe Bottom Hole Pressure = DPP x design factor x 0.052 x Dr BHP = 1.05 X DPP (for Development Wells) BHP = 1.08 x DPP (for Exploration Wells) Design Pore Pressure Design Pore Pressure (Equivalent Mud Weight) DPP-- Meanpp*(1+1.64*COV) COV is the Coefficient of Variance COV is 0.06 for development wells COV is 0.12 for exploration wells with some relevent offset data COV is 0.20 for exploration wells with no relevent offset data Mean Pore Pressure Either the mean pore pressure calculated in nearby wells or the most likely geophysical estimate. EMW of Reservoir Page B$ -- Production Burst Calculations BP SECRET 15 0.5 8052 2O , labtul~ ~ I~,.~.Ul~, L~. ,~llU~.. IUI L;~III~I u ~1~11 LOT ppg (emw) Formation Fracture Gradient at the Casing Shoe TM ppg Trip Margin is 0.5 ppg ( Exploration and 0.2 ppg for Development) Dshoe feet (tvd) Depth of Last Casing Shoe Dint feet (tvd) Depth of Point of Interest Psurf = [(S^2/4) + {(K * MW * 0.052)/C}]^1/2 - S/2 where: S = Dr * MW * 0,052 + Px -Pf Values I Symbol I Unit I Decription & Explanation 3651 tPsurf psig -590 S psig 501 038 K constant 7745 Dr feet (tvd) 9.9 MW ppg I 100 JVx bbls 433 Px psig 0.1 gg psi/ft 4334 0.0231 6 3.5 5010 1.05 4772 11.8 hgas feet (tvd) C bbls/ft Dx inches Ddp BHP psig design factor DPP psig DPP(emw) ppg [ 0.12 ] COV factor [ 3987 ] Mean PP psig [ 9.9 ] EMWr ppg Maximum Pressure at Top of Bubble S = Dr * MW * 0.052 + Px -Pf K = BHP * Vx Depth of formation initiating influx Mud Weight = Expected Pore Pressure + Overbalance (Note: Overbalance for Kick Desing is not to exceed 0.5 ppg) Initial Influx Volume Development Well (70 bbls) Exploration Well (100 bbls) Hydrostatic pressure of gas influx, psi (hgas x gg) gg is the gas gradient gg is 0.1 psi/ft for Exploration <10,000 feet. gg is 0.15 psi/ft for Exploration >10,000 feet. gg is calculated from actual case in production field hgas is the tvd height of the gas Annular Capacity below top of influx Diameter of hole at top of influx (Use Casing ID) Diameter of drill pipe Bottom Hole Pressure -- DPP x design factor x 0.052 x Dr BHP = 1.05 X DPP (for Development Wells) BHP -- 1.08 x DPP (for Exploration Wells) Design Pore Pressure Design Pore Pressure (Equivalent Mud Weight) DPP= Meanpp*(1+1.64*COV) COV is the Coefficient of Variance COV is 0.06 for development wells COV is 0.12 for exploration wells with some relevent offset data COV is 0.20 for exploration wells with no relevent offset data Mean Pore Pressure Either the mean pore pressure calculated in nearby wells or the most likely geophysical estimate. EMW of Reservoir Page B6 - Production Burst Calculations Bottom Hole Pressure as calculated previous in spreadsheet. Depth of formation being tested 13G. PbTBGLK Tubing Lead Near Surface During DST or Production Values ~ IUnit ~ IPbTBGLK psig 8291 ~ Pi psig il;:ili!iiii::i~:::!!!iil;:~i;~i iiii::i::ii!~ Dpkr feet(tvd) ................... ~: :'"'1 Psuff psig gg psi/ft B/¢ psig Dr feet (tvd) JDescription & Explanation PbTBGLK = Pi at Surface Pi = Psurf + CF * 0.052 * Dpkr Completion Fluid Density Depth of packer above formation being tested Psurf = BHP - Dr* gg gg is the gas gradient gg is 0.1 psi/ft for Exploration <10,000 feet. gg is 0.15 psi/ft for Exploration >10,000 feet. gg is calculated from actual case in production field Bottom Hole Pressure as calculated previous in spreadsheet. Depth of the Perforations Page B7 - Production Burst Calculations _.. -, t ,-"' -'* ~, ,", '-*'~ '~ .... ~ ' ' BP SECREq Calculated Design Factor N/A OK I1 if Applies, Else 0: i:.:.i. ~O:~: . :i 4D. Total Evacuation of Csg 0 Calculated Design Factor N/A OK I1 if Applies, Else 0: i:!! 0 .~ BP Minimum Design Factor 1.1 7.000 5410 Weight Grade Conn ID MD Shoe 26 L80 BTRC 6.276 14832 8052 Ccap(bpf) 0,0383 ITVD Shoe 4A. Total Lost Circulation While Drilling Values I Symbol IUnit IDecripti°n & Explanation 1303 PClc psig 2667 Dtof feet (md) Dlcz feet (tvd) 5333 Heqmw feet (tvd) MW ppg (emw) 3578 Plcz psig PPlcz ppg (emw) PClc=MWbc*0.05*Dtof (Collapse Press--Lost Circ While Drlg) Density of Fluid behind casing (Most Likely MW ahead of Cement) Dtof=DIcz-Heqmw Depth of Lost Circulation Zone Heqmw=Picz/(MW*0.052) Height of Equiv Balanced MW column Mud Weight of Drilling Fluid PIcz=PPIcz*0.052*Dlcz Pore Pressure of Lost Circulation Zone 4B. Cementing (Assumes Tail Cement Channels to Surface Bump Plug w/Fresh Water) Values ISymbol IUnit 31 24 PCshoe psig 6616 Pe psig ~;!:iii;:iiiiii!i:.~i~i~i~?ii!~ii:.:;.ii?ili:;ili:::! CWtc ppg (emw) 8052 Dshoe feet (tvd) 3492 Pi psig MWdf ppg (emw) I Decription & Explanation PCshoe=Pe-Pi (Collapse Press at Shoe--Lead Cement Channels to Surface) Pe=CWtc*0.052*Dshoe Weight of Tail Cement Depth of Casing Shoe Pi=MWdf*0.052*Dshoe Mud Weight of Displacement Fluid 4C. PERFORATIONS plug off during DST (Full Gas Column inside tubing and casing below packer). IValues ISymbol lUnit IDecription & Explanation 44 43 PCdst psig PCdst=Pe-Pi 5221 Pe psig Pe=MW*0.052*Dbperf f':i;:?;ii!!::i?'?'~i~i~ili'~iiiii'~ili'~i~iiii~:~;i~i~ MW ppg (EMW) MW used to Balance Formation li!i:;;i:ii;ili:;:~-~:..~ii:::i!:.:!!;;i~;!i~:i!;!l Dbperf feet (tvd) Depth of the Bottom Perforations 778 Pi psig Pi=GG*0.052*Dbperf 4D. Total Evacution While Running Casing Values I Symbol lUnit IDecripti°n & Explanation 34 66 PCevac psig 4271 Pe psig 8052 Dshoe feet (tvd) Ii!!!:.!!!!;!i!i;~!';i!iiiiii:i~::.i~.~iii.,.i:.:..!i.~,iiii..! MIA/ ppg (EMW) 805,2 Pi psig Pe=MW * 0.052 * Dshoe Depth of Casing Shoe MW in hole while running casing Pi=Gas Gradient * Dshoe Page C1 -- Production Casing Collapse t,) ,/k,~ BP SECRET Calculated Design Factor 1,92 OK BP Minimum Design Factor 1.4 5C, Ft(3) = Fwt-Fbuoy+Fbend+Fop 183.481 M LB. Calculated Design Factor 1,4 OK BP Minimum Design Factor 1,4 5D. Ft(4) = Fwt-Fbuoy+Fbend+Fplug+Fshock 247.948 M LB. Calculated Design Factor 2.44 OK BP Minimum Design Factor 1.4 5E. Ft(5) = Fwt-Fbuoy+Fbend+Fplug+Fshock 400.671 M LB. Calculated Design Factor 1.51 OK BP Minimum Design Factor 1.4 ID I Ccap(bpf) MD Shoe 6.276I 0.0383 14832 ppg (emw) Mud Weight deg/100ft Dog Leg Severity (Add 3 to the plan to account for field results) fps Casing Running Speed (5' is recommended) Casing Design Minimum Requirements: Page 1T- Production Casing Tensile TVD Shoe 8O52 BP SECRET 4145 Pe psig 38.48 Ao sq.in. 4145 P/ psig 30.94 Ai sq.in. Fbuoy = Pe*Ao-Pi*Ai Pressure at the bottom of Casing (external) Area of casing OD Pressure at the bottom of Casing (internal) Area of casing ID Bending Component of the Tensile Load resuling from Hole Curvature Fbend = 64*DLS*OD*CSGppf 5B. Tensile Forces While Running Casing Ft(2) = Fwt - Fbuoy + Fbend + Fshock Values I Symbol IUnit IDecripti°n & Explanation Ft(2) = Fwt - Fbuoy + Fbend + Fshock Fwt, Fbuoy, and Fbend (Same values Calculated Above Apply) 67.187 I Fshock M lbs. force Fshock = 1780 * v * As 5 v ft/sec v = 5 fi/sec as per BP Casing Design Manual 7.55 As sq.in. As = 0.7854 * (OD^2 - ID^2) 5C. Maximum Overpull While Running Casing Ft(3) = Fwt - Fbuoy + Fbend + Fop Values I Symbol lUnit IDecripti°n & Explanation 183 481 Ft(3) 431.429 TENcorr 247.948 Et(l) M lbs. force Fop = (Tensile Rating/1.4)-Ft(1) (Calculate the Max Allowable Overpull) Ft(1) = Fwt, Fbuoy, and Fbend (Same values Calculated Above Apply) M lbs. force TENcorr -- Tensile Rating/1.4 M lbs. force (Fwt - Fbuoy + Fbend) 5D. Tensile Force While Displacing Cement Ft(4) = Fwt - Fbuoy + Fbend + Fplug + Fshock Values I Symbol lUnit IDecripti°n & Explanation 338.420 345.402 159.525 69.888 15.468 Ft(4) IM lbs. force Ft(4) = Fwt - Fbuoy + Fbend + Fplug + Fshock Fwt M lbs. force Fwt = Fwt * Csg Ai * Hydrostatic Pressure (Mud + Cement + Spacer) Fbuoy M lbs. force Fbuoy = Csg Ao * Hydrostatic Column of Mud in Annulus Fbend M lbs. force Fbend -- Same Value Calculated Above Applies Fplug M lbs. force Fplug = Psurf * Ai Psurf psig Psurf Surface Pressure While Displacing Cement (ROT 500) Note: The weft will most likely be on suction while the cement is being pumped to the shoe; however, for conservative design use 500 psig for surface pressure. Pmax psig Pmax = ((TENrtg/1.4)-(Fwt-Fbuoy+Fbend+Fshock))/Ai Fshock M lbs. force Fshock (Same Value as Calculated above Applies) 3507 67.187 Page 2T-- Production Casing Tensile BP SECRET 108.274 Fplug M lbs. force Psurf psig 4494 Pmax psig 67.187 Fshock M lbs. force hplug = Psurf" A~ Psurf is Pressure Required to Bump Plug. Use Casing Test Pressures from SSD Recommended Practices Surface 3000, Intermediate & Production 3500, Injector 4000 Pmax = ((TENrtg/1.4)-(Fwt-Fbuoy+Fbend+Fshock))/Ai Fshock (Same Value as Calculated above Applies) 5E.1 Tensile Force Exerted Bumping Cement Plug Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock 4736 Phydann psig Pe = Pdf + Ph20 +Psp +PIc +Ptc 8052 Dshoe feet (tvd) Depth of Casing Shoe 14832 MDshoe feet (md) Measured Depth of Casing Shoe iiiiii!iiii?:i?~ii~::~i~iii:ji:-iiiiiii!iiii Big ID inches Last Casing ID or Surface Hole Size whichever is the case. 335 VOLann bbls Annular Capacity (annular between casing and last casing ID) 0.0226 ANNcap bpf Annular Capacity (annular between casing and last casing ID) :iii::.i::;~:i::ii~'iii!?iiii~iiiii~!i!!~:iiiii!.:~iiii::.i~.!:~iiiiiiii:, INPUT: 1 if Applies Drilling Fluid Calculations 1 4832 Check MD 0 231 9 Pmud psig Pmud = MW * 0.052 * Hmud 8052 Check TVD 0 /t/M/ ppg (emw) Density of Drilling Fluid 335 Check Volurr 0 1 82 Vmud bbls Volume of Drilling Fluid 1.0 Check % Tol 0 4372 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length 8053 Lmud feet (md) Lmud = Vmud/ANNcap 0.54 I ::i::iii!!:~?i!!i:~i:~i!!~:.i!iijli~ii!i?iii:-i~i!ii!ili?i:-!i;i~.!? INPUT: 1 if Applies Water Ahead Calculations 20 8 Ph20 psig PIc = CWh20 * 0.052 * Hh20 i!i:.i::;i:iiiii:;,.ii'::~i!i;!.!~iii~!;;~iiiiii:iil;!:i:i:!:~.:! CWh2o ppg (emw) Equivalent MW of Water Ahead i;ii;iii;'::.i:.ii;':iil;,';;iiiii!~i~-;ii~.-iiii!ii:.i:.iiiii;:iiiiiiiii Vh20 bbls Volume of Water Ahead ::::::::::::::::::::: :~:':':"'"':" T :: =: :;:i',:~'ffiTF' 481 Hh20 feet (tvd) HIc=LIc/MDshoe*Dshoe % TL I% of Total Length 886 LIc feet (tvd) LIc = Vlc/ANNcap 0.06 I i!;.ii;ii:ilil;¢i;;il;ii;!iiiii~iiiiiiiii~ii:.i!iii?;i:iiiiiiii INPUT: 1 if Applies Spacer Calculations 962 Psp psig Psp = CWsp * 0.052 * Hsp CWsp ppg (emw) Equivalent MW of Spacer 1683 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length 3099 Lsp feet (md) Lsp = Vsp/ANNcap 0.21 I ,ili:??.ii:?:i!i!i:.~iiii':ii!!!iii??:~iliiiiii INPUT: 1 if Applies Lead Cement Calculations 0 Plc psig PIc = CWlc * 0.052 * HIc :,.i;;i!:.ii:,!,i;.i,ii, iii;ii~:....iii~:,i!iii;.iiiii.,.il,;ii,,i CWIc ppg (emw) Equivalent MW of Lead Cement ii::!i!i;ii?:!iiiiiiiii:~!ii::!ii;iiii~!ili!ili!i!!iiiii?:i::~,~ii!iii Vic bbls Volume of Cement I Pumped 0 0 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length 0 LIc feet (tvd) LIc = VIc/ANNcap 0.00 i;;;;;?;!?.!iii, i::!::~iii::;..ii::i!ii;:.ii;!;i?!;,;!,! INPUT: 1 if Applies Tail Cement Calculations 1 246 Ptc psig PIc = CWlc * 0.052 * HIc :;?.i, liiiii?;iiii~ii;i;.;i::i~;;~.?.Si':ii;iji:~':;iiii:; CWtc ppg (emw) Equivalent MW of Tail Cement 63.1 Vtc bbls Volume of Cement I Pumped 6 8 1517 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length 2794 Ltc feet (tvd) Htc = Vtc/Ccap 0.19 Page 3T- Production Casing Tensile BP SECRET FEB 16 '96 03: i~2P~SHRRED SERVICES DRILLIMG P. I h red ervices rilling TO: Bob Crandall, AOGCC From: Joe Polya, BPX Date: · 2/16/96 Subject:, North Milne Point #2 TD versus the 7426' tvd +100' Datum Established in the Northwest Milne Point #1 well. in respohse to your question requesting clarification on this datum and how it correlates in the North Milne Point #2 well, ! present the following information. In the Northwest Miine Point #1 well, the 7426' + 100' datum is better defined as follows; ' · The top of the Miluveach Shale in the NWMP#1 well was at 7285' tvd, Therefore, 7526' tvd - 7285' tvd equates to 241'tvd from Miluveach top. The proposed TD of the NMP#2 well is at 80,52' tvd and the top of the Miluveach is at 7822' tvd which is 230' tvd from the Miluveach top. We will be logging while drilling with GR/RES/DENS/NEU and will specify in the welt plan that the 230' tvd is an absolute hardline. I apologize for not being more clear on this in the permit. I will call you after faxing this to disouss. · Respectfully, i Joe Pole/a, Sr. Drilling Engineer, BPX LWD LOGGING WHILE DRILLING A M~rk of gcl Using the following logs: Phase & Amplitude Resistivity Density & Neutron Porosity Gamma RAy (l"& 2") Company; Well: Reid: CONOCO, INC. · WILDCAT County: NORTH SLOPE BOROUGH State: ALASKA Run' ONE Date Logged: ~ation: MARCH 9-19, 1992 Reference No: :2500 FSL, 500 FEL,9EC 25,T14N,RSE 50-029-2223 Elevations: KB: 42.7 DF: ,ti 7 GL: 7.7 Log Measured From: KELLY BUSHING Permanent Datum: MSL Depth Units: FEB 16 ~$ ~1 & G~s Cons, C0mmi~sJ0n I~G S ~OLL O08Z ~.. ~80 ~ O0~Z OO~OL O0~OL O00Z 00~ L 0069 ~3S G3 North Milne Point #2 Well Cover Letter This well is classified by BP as 'SECRET' and we request that all information be handled accordingly. Please find the attached request for Permit to Drill the North Milne Point #2 Well. Even though BP is handling this as an exploration well for permitting purposes, it is actually an appraisal well in regard to geology, geopressures, and engineering. It is being drilled from the Levitt Island to a BHL which lies in the same geologic structure from which the Milne Point F Pad wells are currently producing. The particular fault block we are targeting in this well lies immediately north of the MPF-38 fault block. This block is down dip of the MPF-38 fault block and is being drilled to determine if hydrocarbons were trapped by this fault. There are no plans to core or perform a flow test on this well. SUMMARY: Casing Design- This well is in the expanded Milne Point Unit and BP is confident that we have sufficient offset and seismic data to eliminate the chances of shallow gas and abnormal geopressures -- estimated Kuparuk reservioir pressure is 9.6 ppg. We are submitting a standard Milne Point casing design which is the Ultra Slimhole 9-5/8" surface casing and 7" Iongstring into the Kuparuk reservoir. We are proposing to set 20" conductor pipe _+100' below the mudline as was done by Conoco on the Northwest Milne Point #1 well. The 9-5/8" surface casing is proposed for a deep set below the Schrader Bluff Sands into the Seabee Shale. This is the standard practice in the both the BP operated Milne Point and Arco operated Kuparuk River Units. Furthermore, the Schrader Bluff sands are wet in the Northwest Milne Point well and in all the wells drille~Milne Po~ F and L Pads -- the northe~on of the Milne Point Unit lies within the water leg of the Schrader Bluff structure. The 7" casing will then be run as a long string across the Kuparuk reservoir and into the Miluveach Shale. A detailed casing design is included in the permit package. Spacing and Deviation Exceptions: There should not be any Spacing or Deviation Exceptions required for this well. The North Milne Point #2 well will drill to a bottom hole location of 5050 FSL and 2426 FEL Section 22 Township 14 North and Range 10 East. This BHL lies within the expanded Milne Point Unit boundary for which the operators are BPE&O 64.38, BPX 26.81, and OXY USA 8.81 down to 7526' sstvd. The 7526' sstvd boundary is a stratiagraphic reference to the rathole drilled into the Miluveach Sand below the Kuparuk reservoir in the Northwest Milne Point #1 well -- the proposed TD of this well is above that datum. The operators for strata below 7526' sstvd are Maxus 50.00 and Amerada Hess 50.00. Conoco negotiated a Farmout Agreement with both Maxus Exploration Company and Amerada Hess Corporation pertaining to the strata above 7526' sstvd in the State of Alaska Leases to include 355016, 355017, and 335018. Conoco earned designation as Operator as per that agreement by drilling the Northwest Milne Point #1 well. The farmors (Maxus and Amerada Hess) now have overriding royalty interests as per the Farmout Agreement. BP assumed Conoco role as farmee in that agreement. A P&A/Suspension proposal is included in the permit package. should you have any questions -- 564-5713. Respectfully, Joe Polya, Sr. Drilling Engineer, BPX Please call me BP SECRET We_11 ......... : ~MP-2 Fie~d ........ : North Milne Point Conkoutation-.: M~i~m ~ature Surfa~ ~t..: 70.56559282 ~ surface ~9.: ~9.61~85059 ~ surface ...... : 2045 FSL 2700 FEL TARGET ....... : 5103 FSL 2678 FBL BHL ........... : 5013 FSi. 2252 F~L ~ I~FICAT/ON D~ P/q~ ~ 0 O. O0 ~/~ 2.5/~oo ~ooo o. oo ~ 1100 2.50 ~ 1200 ~ 1300 7.50 ~ 1~00 ~ 1500 ~ .. 1600 1~00 Anadril3 Schlumberger Alaska District llll East BOth Awenue Anchorage, AK 9951B {907) 349-4511 Fax 34~-2160 DIRECtIOnAL ~ ~ for BP E_KPLORATXON INC. IX)CATIONS - AIASKA Zone: 4 X- Coord Y- Coord S17 TI4N RIOE ~ 5469&0.00 6056646.00 S22 ~14N RIOE ~ 55~542.00 6054499.00 S22 T14N ~0~ ~ 557969.46 6054412.44 PRDPOSEDWELL PROFILE DIRECTION VERT-DEPTHS EECT AZXMUT~ TVD S~B-S DIST O.O0 0 -33 0 0.00 1000 968 0 101.81 1100 1067 2 101.81 1200 1167 9 101.81 1299 1267 20 10.00 101.B1 . 1398 12.50 101.81 1496 15.00 .... 101.81 '1593 17.50 101.B1 1689 20.00 101.81 1784 ? ~ 9o0 22.50 L~ 2000 25. O0 (mmad~ill (c)96 I~i~,~ZP2 2.Sh.o,~ 10=5.~ J~ P) 101.81 1B77 101.81 ].969 Prepared ..... : 01/07/96 _ Ver~ sec~ az.: 101.B1 -* KB elevation.: 32.50 £~ Magnetic Dcln: +0.000 (E) Scale Factor.: .0.99990250 ANADRtLL AKA-DPC FEASIBILITY plAN NOT APPROV£D FOR EXECUTION PI. AN z COORD/NATES- PROM 0.00 N 0.00 0.00 N 0.00 O.&5 S 2.14 1.79 S 8.54 4.01 ~ 19.19 1365 35 7.13 S 1464 54 11.12 S 1561 78 15~9B S 1657 i06 21.71 S 1751 138 28~29 S 1845 174 35.71 1936: 215 43.95 STATE-PLANE Y 546940.00 6056646-00 546940-00 6056646.00 546942.14 6056645.57 546948.55 6056644.27 546959.21 6056642.11 FAC]I 100 O. 00 0.00 2.50 2 2.50 34.08 E 546974.12 6056639.09 ~S 53.1B · 5~6993.24 6056635.22 HS 76.44 E'54701'6~53 6056~30.50 'ItS 103.$3 E 547043.95 6056624.95 HS 135.29 E 547075.45 60566L8.57 1~ 2 ,,S0 2.51) . 2.50 '2.50 2.50 i70.76 E 547110-97 6056611.38 HS 2.50 210.'L8 E 547150.43 6056603.39 }IS 2.S0 0 well I i North Milne Point #2 Permit Package List of Enclosures Item No. · , . . 1 . , 1 · Description Cover Letter 10-401 Permit Form w/Directional Plan and Section Views Well Plan Summary Proposed Summary of Operations General Discussion Well Objectives and Drilling Hazzards Hydrogen Sulphide Variance Request Well Site Survey and Pressure Analysis Proposed Casing Design Verbage Proposed Wellbore Schematic 9-5/8" Cement Program 7" Cement Program Casing Design Summary Sheet Casing Design Calculations General Casing Data Casing Design Calculations 9-5/8" Burst 9-5/8" Collapse 9-5/8" Tensile 7" Burst 7" Collapse 7" Tensile 10-403 Permit Forms P&A-- Non-Commercial Hydrocarbons P&A/Suspend Commercial Hydrocarbons 3 FEB 1 2 3 2 Pages 11 BP SECRET _IST GEOL AREA PROGRAM: exp~ der [] redrll [] aery [] wellbore seg ~# //~ ~ o~/o~ SHO~ -- ~e attached .................. JY/ N ~ber appropriate ............... ~ N :11 name and number .............. ~ N ~ted in a defined pool ............. ~Y~ N ~ted proper distance from drlg unit boundary..~-~ N ~ted proper distance from other wells ...... N ~t acreage available in drilling unit ..... Y N ;ed, is wellbore plat included ........ ~ N only affected party ...... N has appropriate bond in force, i i ~ i i i i N ~n be issued without conservation order .... N ~n be issued without administrative approval. N 15-day wait. Lt be approved before ...... N r string provided ............... :asing protects all known USDWs ........ adequate to circulate on conductor & surf csg. ~dequate to tie-in long string to surf csg . . cover all known productive horizons ...... esigns adequate for C, T, B & permafrost .... tankage or reserve pit ............. ~rill, has a 10-403 for abndnmnt been approved. wellbore separation proposed. ter required, is it adequate. .'.'.'.'.'.'.'.'.' fluid program schematic & equip list adequate equate ..................... ss rating adequate; test to ~O~ psig.~ nifold complies w/API RP-53 (May 84) ...... 1 occur without operation shutdown ....... nce of H2S gas probable ............. ~an be issued w/o hydrogen sulfide measures....Y~_ N sented on potential overpressure zones .... .~ N analysis of shallow gas zones ......... ~~ ' N ~ondition survey (if off-shore) . . .~.~.L~.,.. N name/phone for weekly progress reports ..... Y N [exploratory only] ENGINEERING: COMMI SS I ON: BE~ DWJ~ ~/~7~//~/~ JDN ~.-,-~ ..~,: TAB Comments/Instructions:
