Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout196-055 AOGCC Individual Well
Geological Materials Inventory
PERMIT DATA T DATA PLUS
Page: 1
Date: 03/12/98
RUN RECVD
:
96-055 DGRIEWR4/ROP-MD ~230-9100
FINAL 02/05/97
FINAL 02/05/97
FINAL 02/05/97
FINAL 02/05/97
06/11/97
FINAL 06/11/97
96-055
DGR/EWR4-TVD ~'~230-7925
FINAL 06/11/97
96-055
DGR/CNP/SLD-MD ~5300-9040
FINAL 06/11/97
96-055
DGR/CNP/SLD-TVD UL/5200-7925
FINAL 06/11/97
10-407 ~COMPLETION DATE 2/3 O/c~ / 37~c//y6/
DAILY WELL OPS L~R ~//q/~O / TO 3/3[/~6/ I-~
Are dry ditch samples required? yes ~.~And received? ~,~.~.~...~-~
Was the well cored? yes ~._Analysis & description received?
Are well tests required?llyes ~eceived?
Well is in compliance
Inmtial
COMMENTS
BP. EXPLORATION, Alaska
p ETROTECHNICAL
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-01
Well ' Ret'Type Date Job Id , , company Comments '
NMILNE-01 DISK 03/27/96 SPERRY 1 EA. IBM FORMATTED 3.5" DISK?~TTE: (LIS FORMAT) - DGR/EWR4/SN'0/SLD
/"~l$-IVIIVl-~./I./q.a' I....w ~.,- II..~ll II..iV I lUl 'II/--~1,-- ~,~j~ '~,,,) ,
NMILNE-01 OH 03/28/96 AK-MM-960315 SPERRY MWD (TVD) DUAL GAMMA RAY/ELECTROMAGNETIC WAVE RESISTIVITY- EWR4 .
NMILNE-01 OH ... 03/28/96 AK-MM-960315 SPERRY MWD (MD) DUAL GAMMA RAY/ELECTROMAGNETIC WAVE RESISTIVITY- EWR4
NMILNE-01 OH 03/28/96 AK-MM-960315 SPERRY MWD (MD) DUAL GAMMA RAY/COMPENSATED NEUTRON/LITHO DENSITY
NMILNE-01 OH 03/28/96 AK-MM-960315 SPERRY MWD (TVD) DUAL GAMMA RAY/COMPENSATED NEUTRON/LITHO DENSITY
,Enclosed are the materials listed above. If you have any questions please contact me at (907) 564-5929.
~P~le~s.e sign/.a.qd~urn one copy of this transmittal.
ql -you
David W. Douglas
Petrotechnical Data Center
Received By:
Petrotechnical Data Center, MB3-3
900 East Benson Boulevard, P.O. Box 196612, Anchorage, Alaska 99519-6612
PLUGGING & LOCATION CLEAR.CE R~PORT
State of Alaska
.ALASKA 0IL & GAS CONSERVATION COHMISSION
Lease ~'~h"' 3550
0oerator ~
.
Note cas~g size, w~ dep~, ~t vol~ & ~rocedure.
Perf inte~als - tops:
Review the well file, and-comment on plugging, well-head
status, and location clearance - provide loc. clear, code.
.
Well head cut off: ~ --
~arker ~ose or plate: ~ 0
Location Clearance:
Conclusions
Code
..... STATE OF ALASKA ....
ALASKA oiL AND GAS CONSERVATION COb, MISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
1. Status of Well Classification of Service Well
[] Oil [] Gas [] Suspended [] Abandoned [] Service
2. Name of Operator 7. Permit
BP Exploration (Alaska) Inc. ~
3. Address 8. APl Number
P.O. Box 196612, Anchorage, Alaska 99519-6612 m .......... 50-029-2L~e59
4. Location of well at surface ..~ , :,., .._,.,,, 9. Unit or Lease Name
2014' NSL, 2700' WEL, SEC. 17, T14N, R10E ~ :;#~.-~_~:; ¢ Milne Point Unit
At top of productive interval ,~:;~-~ ~¢/)~ 10. Well Number
2013' NSL, 794' WEL, SEC. 18, T14N, R10E~.:.~.,~,.~.~_ ¢,~'. * "~'~ North Milne Point #1
At total depth ~;:-;;~~ 11. Field and Pool
2008' NSL, 1000' WEL, SEC. 18, T14N, R10E
Milne Point Unit/Kuparuk River
5. Elevation in feet (indicate KB, DF, etc.) J6. Lease Designation and Serial No.
35' RKBI ADL 355016
12. Date Spudded i13. Date T.D. Reached I 14. Date Comp., Susp., or Aband.115. Water depth, if offshore , 16. No. of Completions
03/20/96 03/27/96 03/30/96 Natural Island MSLI Zero
17. Total Depth (MD+'I'VD)118. Plug Back Depth (MD+TVD)119. Directional Surveyl20. Depth where SSSV set~l. Thickness of Permafrost
9101 7976 FI] 70 . 70 F1 []Yes []No i N/A MD! 1700'(Approx.)
22. Type Electric or Other Logs Run
All logs were LWD, GR/RES in 12-1/4" hole & GR/RES/NEU/DEN in 8-1/2" hole
23. CASING, LINER AND CEMENTING RECORD
CASING SE-I-rING DEPTH HOLE
SIZE VVT. PER FT. GRADE TOP Boq-rOM SIZE CEMENTING RECORD AMOUNT PULLED
30" 234# X 34' 110' 30" None 11'
20" 94# H-40 31' 147' 24" 525 sx PF'C' 25'
9-5/8" 40# L-80 29' 5339' 12-1/4" 1001 sx PF 'E', 250 sx Class 'G' 29'
!24. Perforations open to Production (MD+TVD of Top and Bottom 25. TUBING RECORD
and interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD)
N/A (7" not run, well P & A) N/A
MD TVD MD TVD
26. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED
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 SIZE 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
ORIGINALI ECEIVED
MAY 2 4 1996
Alaska 0tl & Gas Cons. Commission
An~hnr~nq
Form 10-407 Rev. 07-01-80 Submit In Duplicate
.9. Geologic Marker. 30. .ormation Tests
Measured True Vertical Include interval tested, pressure data, all fluids recovered
Marker Name
Depth Depth and gravity, GOR, and time of each phase.
N/A
Kuparuk Sand Top 8766' 7713'
Miluveach 8970' 7954'
TD 9099' 7974'
31. List of Attachments
Summary of Daily Drilling Reports, Surveys
32. ! hereby certify that the foregoing is true and correct to the best of my knowledge
Signed ~_____~.,~,~_~ .... Title ~ ¥~y,. ~,~,~ ~~.. Date ~'/Z ~./c~
~ v Prepared B~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: Indicate whether from-ground level (GL) or other elevation (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 011 & (~a~ Cons. Commission
Anchorage
SUMMARY OF DALLY OPERATIONS
SHARED SERVICES DRILLING - BPX / ARCO
Well Name: N. Milne Rig Name: Nabors AFE: 3301 68
Point #1 22 E
Accept Date: 03/1 9/96 Spud Date: 03/20/96 Release Date: 03/30/96
03/19/96
MIRU. RIG ACCEPTED @ 1000 HRS.
03/20/96
BUILD BERM AROUND RIG. NU DIVERTER. LOAD PIPE SHED W/BHA. RU
DIVERTER LINES, HOOK UP HYDRAULIC LINES & INSTALL MOUSEHOLE.
FUNCTION TEST DIVERTER. BOBBY FOSTER W/AOGCC WITNESSED TEST. MU
BHA #1. DRILL CEMENT F/32' T/112'. SPUD 2 112' AND DRILL T/300'. POOH. MU
BHA #2. ORIENT & TEST SAME.
03/21/96
DRILL F/300' T/1560'. DRILL F/1560' T/1774'. CIRC & COND MUD, WAIT ON
GUZZLERS. DRILL F/1560' T/2408'. LOST PUMP PRESSURE @ 2317'. PUMP HIGH
VIS SWEEP & DRY JOB. POOH TO BIT. CHANGE OUT BIT, CENTER NO?TLE
HOLDER WASHED OUT OF BIT. RIH T/2317'. BREAK CIRC & SURVEY 2317' T/2409'.
O3/22/96
DRILLED F/2408' T/3269'. WAIT ON RIG MOVE ON SPINE ROAD, DUE TO
CUTTINGS TANK FULL. DRILL F/3269' T/3460'. DRILLED F/3460' T/5234'.
03/23/96
CIRC HIGH/LOW VIS SWEEPS, CHECK FOR FLOW, PUMP PILL. POOH T/3429',
SWABBED IN 5 BBLS, HOLE TIGHT MU TD, CIRC DOWN 2 STDS, RIH TO BO'i-i'OM
W/NO FLOW. DRILL F/5234' T/5360, SOME GAS WITH BO'I-I'OMS UP. CIRC
HIGH/LOW VIS SWEEPS, CHECK FOR FLOW, PUMP PILL, BD TD. POOH T/550',
TRIED TO SWAB 3394' T/2540', MAX DRAG 25K. TIH, WASH 20' SOFT FILL, NO
PROBLEMS, RIH. PUMP HIGH VIS SWEEP, LEVEL RIG, CHECK FOR FLOW, PUMP
PILL. POOH, LD BHA, DOWNLOAD LWD, NO PROBLEM, POOH. CLEAR FLOOR OF
BHA, RU CASING EQUIP.
03/24/96
RU CASING EQUIP. RUN 130 JTS, 9-5/8" 40# L-80 BTRC CASING, SHOE @ 5339',
FC @ 5254'. RU CEMENT HEAD, CIRC 450 BBLS MUD @ 10 BPM. PUMP 75 BBLS
WATER, TEST LINES, PUMP 1000 SX CLASS E, DROP BOTTOM PLUG, PUMP 250
SX G, DROP TOP PLUG, DISPLACE WITH 399 BBLS WATER, CALC STKS 389,
ACTUAL 3910, BUMP PLUG T/2000 PSI, CHECK FLOATS. OK. RD CEMENTING
HEAD, LD LANDING JT, LD MOUSEHOLE, REMOVE DIVERTER. ND FLOWLINE,
RISER, HYDRIL & DIVERTER SPOOL. PERFORM TO JOB W/80 SX OF CLASS E
CEMENT. REMOVE ALL DIVERTER EQUIP F/CELLAR, BRING IN WELLHEAD. LD
ALL 9-5/8" CASING EQUIP OFF RIG FLOOR, CHANGE BAILS, INST~ ~ [IV E ~
Page !
MAY ~ 4 1996
Aluka 011 & Ga; Con;. 0ommission
Anchorage
SPEEDHEAD, TEST METAL TO METAL SEAL T/1000 PSI. OK. NU BOP, RISER &
FLOWLINE. INSTALL MOUSEHOLE, PU TEST JT, TEST BOPE, CHOKE MANIFOLD
& LINES T/250/5000 PSI. TEST ANNULAR T/250/3500 PSI. STILL TESTING.
03/25/96
TEST UPPER & LOWER IBOP VALVES, BLIND RAMS, ACCUM, REMOVE TEST
PLUG. REMOVE CASING STABBING BOARD. CUT & SLIP NEW LINE ON. SERVICE
TOP DRIVE & BLOCKS. INSTALL FLOWLINE & RISER. PU BHA, LOAD LWD & MWD,
TEST ANDERGAUGE & MOTOR, PU REST OF BHA. TIGHTEN BOLTS ON TOP
DRIVE. RIH, PU 30 JTS G PIPE, TAG FC @ 5254', RU TO TEST CASING T/3000 PSI
FOR 30 MIN. OK. DRILL FLOAT EQUIP, CEMENT & 10' NEW HOLE F/5360' T/5370'.
CBU. RU & RUN LOT, FORMATION BROKE @ 2060' W/8.5 PPG. DRILL F/5370'
T/5817'. WAIT ON GUZZLER. DRILL F/5817' T/5975'.
03/26/96
DRILL F/5965' T/6917'. DRILL F/6917' T/7106'. MOTOR FAILED. POOH TO BHA.
SERVICE TOP DRIVE. POOH W/BHA, REMOVE SOURCES, DOWNLOAD TOOLS,
LD MOTOR, CHANGE NO77LES IN BIT, LOST 4 CENTER CUTTERS IN BIT, PU NEW
MOTOR, ORIENT MWD TO MOTOR. RIH W/REST OF BHA & DP.
03/27/96
DRILL F/7106' T/7297'. DRILL F/7297' T/8441'. CHECK FOR FLOW, POOH 15 STDS,
RIH. OK. DRILL F/8441' T/9101'. CIRC SWEEPS AROUND, CHECK FOR FLOW,
PUMP PILL. POOH TO 9-5/8" SHOE. OK. RIH, HIT BRIDGE @ 7202', WORKED THRU
3 TIMES, DIDN'T SEE AGAIN, RIH TO TD. WILL CIRC UNTIL GET OUT OUT PHASE
III WEATHER.
O3/28/96
RIH, WASH & REAM LAST 90'. PUMP SWEEPS & CIRC WHILE WAITING ON
WEATHER. DROP ESS, PUMP PILL, BLOWDOWN TOP DRIVE. POOH. BOP DRILL W/
TRIPPING. LD BHA. DOWNLOAD MWD, LWD, LD BHA, CLEAR FLOOR. RIH T/5300'
W/MULESHOE. CHANGE BAILS. RIH T/9098', PU 17 JTS DP. CBU. PUMP 13 BBLS
WATER, 240 SX CLASS G, 5 BBLS WAER, DISPLACE W/137.9 BBLS MUD, POOH 8
STDS. CBU. POOH LD DP.
03/29/96
LD DP & STD 55 STDS IN DERRICK, LD MULESHOE, PU 9-5/8" RETAINER. RIH
T/5265'. SET RETAINER @ 5265', UNSTING, CBU. PUMP 15 BBLS, 110 SX G
CEMENT, 5 BBLS WATER, DISPLACE UNTIL 13 BBLS WATER BEHIND DP (USING
CHOKE)-STUNGINTO-RETAINER, SQUEEZED 2 BBLS WATER & 15 BBLS CEMENT
BELOW RETAINER. POOH RETAINER, SPOTTED 7.5 BBLS CEMENT ON TOP OF
RETAINER, POOH 5 STDS. CBU, TEST PLUG T/2000 PSI FOR 30 MIN,
WITNESSED BY LOU G W/AOGCC. POOH LD DP. LD DP. RIH W/EZSV SET @ 300'.
POOH LD SETTING TOOL, RIH OPEN ENDED. PUMP 10 BBLS WATER, 110 SX PFC
AND 2 BBLS WATER. POOH T/60' CIRC HOLE CLEAN. PULL WEAR BUSHING. PU
TRISTATE TOOLS, RIH, CUT 9-5/8" CASING @ 58', COLLAR @ 60', POOH. ND
BOP'S & WELLHEAD. PU TRISTATE TOOLS, SPEAR 9-5/8" CASING @ 58', POOH
WITH CASING, LD CASING & TOOLS. PU 16" BIT, RIH & CLEAN OUT TO 58', POOH
& LD SAME. PU TOOL TO CUT 20 & 30".
Page 2
03/30/96
CUT OFF 20 LANDING RING, MU 20" CUTTING TOOLS, RIH. CUT ON 20" & 30" W/
33" MAX REACH CUTTERS. CHANGEOUT CUTTING BLADES & CUT ON 30" W/41"
MAX REACH. POOH LD CUTTING TOOL, PU 20" SPEAR, STAB 20". PU 20" HAD TO
PULL 450K TO FREE, PU TO TOP OF CELLAR, CUT OFF CELLAR PLATE, CUT OFF
7' OF 20", SPLIT DOWN FROST GROOVE, RESPEAR 20" SPLIT AGAIN, WELD
STRAPS ONTO 20" & SPEAR, POOH, CUT SPEAR & 20", LD. CHIP CEMENT OUT OF
INSIDE OF 30'. SPEAR 30", WOULDN'T MOVE W/500K, RD SPEAR. MU 16" BIT &
28-3/4 STB, WASH & REAM 30" TO TOP OF' 9-5/8" STUMP. LD BIT, RIH CUT 30" @
45', 30" CAME UP HOLE 5' ON CUTTERS, LD CUTTING TOOLS.
03/31/96
LD 30" CUTTING TOOLS, PULL 30" CASING & LD, CLEAR FLOOR OF TOOLS. RIG
RELEASED @ 0900 HRS, 03/30/96.
Page 3
RECEIVED
MAY ;~ z~ 1996
Alaska 011 & Gas Cons, Commission
Anchorage
d
.{Y-SUN DRILLING SERVICES
ANCHORAGE ALASKA
tBP EXPLORATION (ALASKA),INC.
NORTHWEST MILNE/N MILNE POINT #1
500292266300
iNORTH SLOPE BOROUGH
COMPUTATION DATE: 4/12/96
TRUE SUB-SEA
I MEASD VERTICAL VERTICAL
DEPTH DEPTH DEPTH
!
!
PAGE 1
MWD SURVEY -'
JOB NUMBER: AK-MM-960315
KELLY BUSHING ELEV. = 34.55 FT.
OPERATOR: BP EXPLORATION
COURS
INCLN
DG MN
COURSE DLS TOTAL
DIRECTION RECTANGULAR COORDINATES VERT.
DEGREES DG/100 NORTH/SOUTH EAST/WEST SECT.
.00 .00 -34.55
112.00 112.00 77.45
177.27 177.27 142.72
263.35 263.35 228.80
354.34 354.34 319.79
0
0
22
14
18
N .00 E .00 .0ON .00E
N .00 E .00 .0ON .00E
S 11.49 W .57 .21S .04W
S 2.73 E .17 .66S .09W
S 1.28 E .08 1.10S .07W
.00
.00
.04
.09
.08
445.80 445.80 411.25
536.56 536.55 502.00
628.00' 627.99 593.44
719.57 719.55 685.00
809.67 809.64 775.09
25
35
39
41
53
S 9.80 W .15 1.68S .13W
S 3.17 E .22 2.48S .16W
S 4.49 E .07 3.47S .09W
S 13.70 E .13 4.52S .08E
S 5.72 E .25 5.75S .28E
13
16
10
07
27
901.04 901.00 866.45
990.96 990.90 956.35
1085.94 1085.87 1051.32
1179.54 1179.46 1144.91
1275.36 1275.28 1240.73
2
7
56
4
23
S 5.63 E. .16 7.28S .43E
S 4.12 E .11 8.97S .57E
S 8.33 E .22 10.68S .75E
S 8.08 E .92 11.50S .87E
N 16.97 E .48 11.26S .98E
42
56
74
86
96
1369.86 1369.78 1335.23
1465.36 1465.27 1430.72
1559.91 1559.82 1525.27
1654.19 1654.09 1619.54
1748.84 1748.73 1714.18
22
29
42
52
50
N 12.98 E .03 10.65S 1.14E -1.
N 16.86 E .12 9.95S 1.33E -1.
N 23.23 E .24 9.02S 1.68E -1.
N 33.98 E .23 7.89S 2.31E -2.
N 37.44 E .06 6.74S 3.13E -3.
13
32
67
30
13
1844.'31 1844.19 1809.64
1937.82 1937.69 1903.14
2033.15 2033.01 1998.46
2127.74 2127.59 2093.04
2223.88 2223.72 2189.17
46
49
48
45
49
N 33.26 E .09 5.64S 3.92E -3.
N 28.33 E ,08 4.52S 4.58E -4.
N 23.95 E .07 3.32S 5.18E -5.
N 30.75 E .11 2.18S 5.76E -5.
N 29.12 E .08 1.03S 6.42E -6.
91
58
17
76
42
2317.86 2317.69 2283.14
2413.61 2413.43 2378.8'8
2509.69 2509.42 2474.87
2603.62 2602.84 2568.29
2697.10 2695.15 2660.60
0
0
4
7
10
46
54
3
40
26
N 30.94 E .06 .liN 7.08E
N 36.64 W .98 1.28N 6.97E
N 76.87-W 3.55 2.65N 3.21E
N 78.18 W 3.86 4.69N 6.16W
N 80.52 W 2.99 7.36N 20.62W
-7.
6.
20.
08
97
22
15
61
2793.42 2789.35 2754.80
2889.21 2882.07 2847.52
2984.74 2973.76 2939.21
3080.47 3064.65 3030.10
3175.78 3154.10 3119.55
13
15
17
19
20
34 N 78.57 W 3.28 ll.04N 40.31W
25 N 81.96 W 2.13 15.05N 63.94W
7 N 86.16 W 2.16 17.77N 90.56W
25 N 86.98 W 2.41 19.55N 120.52W
55 N 87.66 W 1.60 21.08N 153.35W
40.
63.
90.
120.
153.
29
92
54
5O
33
RECEIVED
SPi Y-SUN DRILLING SERVICES
ANCHOt~AGE ALASKA
PAGE
BP EXPLORATION (ALASKA),INC.
NORTHWEST MILNE/N MILNE POINT #1
500292266300
NORTH SLOPE BOROUGH
COMPUTATION DATE: 4/12/96
TRUE SUB-SEA COURS
MEASD VERTICAL VERTICAL INCLN
DEPTH DEPTH DEPTH DGMN
3270.75 3242.11 3207.56 23 9
3366.48 3329.28 3294.73 25 37
3460.59 3413.21 3378.66 28 6
3557.11 3497.14 3462.59 31 3
3652.80 3577.56 3543.01 34 32
DATE OF SURVEY: 032796
MWD SURVEY
JOB NUMBER: AK-MM-960315
KELLY BUSHING ELEV. = 34.55 FT.
OPERATOR: BP EXPLORATION
COURSE DLS TOTAL
DIRECTION RECTANGULAR COORDINATES
DEGREES DG/100 NORTH/SOUTH EAST/WEST
VERT
SECT
N 89.07 W 2.41 22.08N 188.97W
S 89.93~ W 2.61 22.36N 228.49W
S 89.67 W 2.65 22.21N 271.01W
S 89.92 W 3.06 22.04N 318.66W
N 89.79 W 3.65 22.10N 370.49W
188 .
228.
270.
318.
370.
3748.56 3655.57 3621.02 36 19
3844.14 3732.27 3697.72 36 56
3940.07 3809.00 3774.45 36 49
4034.21 3884.37 3849.82 36 48
4129.83 3960.82 3926.27 37 1
N 89.80 W 1.85 22.30N 426.01W
N 89.89 W .65 22.46N 483.03W
S 89.52 W .39 22.27N 540.60W
S 89.12 W .25 21.60N 597.01W
N 89.76 W .74 21.28N 654.44W
425 .
483 .
540.
596.
654.
4225.23 4036.98 4002.43 37 2
4319.14 4112.08 4077.53 36 44
4415.40 4189.69 4155.15 35 46
4508.98 4266.26 4231.71 34 24
4604.79 4345.23 4310.68 34 34
S 89.73 W .32 21.27N 711.90W
S 88.44 W .89 20.37N 768.27W
S 87.23 W 1.24 18.23N 825.15W
S 89.19 W 1.90 16.53N 878.91W
S 88.84 W .28 15.60N 933.16W
711 .
768.
825.
878.
933.
4698.71 4422.43 4387.88
4795.08 4501.39 4466.84
4890.50 4579.56 4545.01
4986.42 4658.35 4623.80
5079.35 4734.67 4700.12
34 50 S 87.92 W .63 14.08N 986.62W
35 6 S 88.17 W .31 12.20N 1041.84W
34 52 S 87.76 W .34 10.26N 1096.52W
34 40 S 88.33 W .40 8.39N 1151.20W
34 54 S 88.35 W .25 6.85N 1204.19W
986.
1041.
1096.
1151.
1204.
5174.88 4813.05 4778.50
5263.51 4885.60 4851.05
5378.49 4979.42 4944.87
5471.63 5055.56 5021.01
5568.57 5135.14 5100.59
34 49 S 88.48 W .11 5.34N 1258.78W
35 17 S 89.02 W .64 4.23N 1309.69W
35 19 S 88.12 W .45 2.57N 1376.13W
35 0 S 87.24 W .65 .41N 1429.73W
34 38 S 86.73 W .48 2.51S 1485.00W
1258.
1309.
1376.
1429.
1485.
5663.39 5213.37 5178.82
5758.85 5292.00 5257.45
5854.28 5370.55 5336.00
5950.63 5450.35 5415.80
6043.38 5527.42 5492.87
34 11 S 85.63 W .81 6.07S 1538.47W
34 53 S 88.38 W 1.79 8.89S 1592.51W
34 18 S 88.33 W .61 10.44S 1646.67W
33 51 S 86.45 W 1.19 12.90S 1700.61W
33 44 S 89.73 W 1_.97 L4.62S 1752.15W
1538.
1592.
1646.
1700.
1752.
6138.94 5607.34 5572.79
6234.74 5687.45 5652.90
6329.91 5766.98 5732.43
6426.16 5847.03 5812.48
6521.11 5924.15 5889.60.
32 45 N 88.69 W 1.38 14.15S 1804.53W
33 45 N 86.09 W 1.82 11.75S 1856.99W
32 52 N 86.63 W .98 8.42S 1909.14W
34 34 N 87.32 W 1.82 5.61S 1962.50W
36 45 N 87.30 W 2.30 3.01S 2017.80W
1804.
1857.
1909.
1962.
2017.
95
47
98
63
47
98
00
58
98
41
87
24
13
89
14
60
82
51
19
18
77
68
13
73
01
48
52
68
62
17
55
00
15
51
80
SP
.Y-SUN DRILLING SERVICES
ANCHORAGE ALASKA
PAGE
BP EXPLORATION (ALASKA),INC.
NORTHWEST MILNE/N MILNE POINT #1
500292266300
NORTH SLOPE BOROUGH
COMPUTATION DATE: 4/12/96
DATE OF SURVEY: 032796
MWD SURVEY
JOB NUMBER: AK-MM-960315
KELLY BUSHING ELEV. = 34.55 FT.
OPERATOR: BP EXPLORATION
TRUE SUB-SEA
I MEASD VERTICAL VERTICAL
DEPTH DEPTH DEPTH
COURS COURSE DLS
INCLN DIRECTION
DG MN DEGREES DG/10
TOTAL
RECTANGULAR COORDINATES
0 NORTH/SOUTH EAST/WEST
VERT.
SECT.
6616.16 6000.27 5965.72 36 49 N 87.75 W .
6711.76 6077.13 6042.58 36 9 N 88.09~ W .
6806.50 6153.31 6118.76 36 47 N 88.52 W .
6901.64 6229.53 6194.98 36 43 N 88.78 W .
6996.59 6306.15 6271.60 35 39 N 88.20 W 1.
29 .56S 2074.67W 2074.67
73 1.51N 2131.47W 2131.47
74 3.17N 2187.77W 2187.76
18 4.51N 2244.70W 2244.69
18 5.99N 2300.75W 2300.74
7092.46 6384.57 6350.02 34 33 S 89.46 W 1.
7187.87 6461.91 6427.36 37 5 S 89.61 W 2.
7282.84 6537.11 6502.56 38 11 N 89.49 W 1.
7378.15 6612.05 6577.50 38 7 N 89.87 W .
7473.73 6687.19 6652.64 38 13 N 89.69 W .
81 6.61N 2355.87W 2355.86
65 6.16N 2411.70W 2411.69
29 6.23N 2469.69W 2469.68
25 6.55N 2528.58W 2528.57
16 6.78N 2587.66W 2587.65
7568.85 6762.06 6727.51 37 55 S 89.89 W
7664.87 6837.82 6803.27 37 54 N 89.88 W
7760.48 6913.31 6878.76 37 47 S 89.43 W
7855.80 6988.61 6954.06 37 49 S 89.39 W
7951.31 7064.25 7029.70 37 27 S 89.20 W
42 6.88N 2646.32W 2646.31
15 6.89N 2705.32W 2705.31
46 6.66N 2763.99W 2763.98
03 6.06N 2822.42W 2822.41
40 5.34N 2880.75W 2880.74
8047.07 7140.50 7105.96 36 58 S 88.98 W
8142.81 7216.87 7182.32 37 13 S 88.88 W
8235.82 7290.90 7256.35 37 17 S 89.41 W
8332.83 7368.17 7333'.62 37 5 S 89.20 W
8426.71 7442.90 7408.35 37 24 S 89.30 W
53 4.42N 2938.66W 2938.65
27 3.34N 2996.39W 2996.38
36 2.50N 3052.69W 3052.69
25 1.79N 3111.33W 3111.33
35 1.05N 3168.15W 3168.15
8521.80 7518.29 7483.74 37 41 N 89.95 W .
8617.54 7594.15 7559.60 37 30 S 89.57 W .
8710.42 7667.97 7633.42 37 12 S 88.82 W .
8803.19 7741.78 7707.23 37 21 S 88.74 W .
8897.25 7816.17 7781.62 38 5 S 88.75 W .
56 .72N 3226.11W 3226.10
36 .53N 3284.52W 3284.52.
59 .26S 3340.87W 3340.87
17 1.46S 3397.06W 3397.06
79 2.72S 3454.60W 3454.60
8993.13 7891.44 7856.89 38 27 S 88.38 W .45
9099.00 7974.34 7939.79 38 27 S 88.38 W .00
4.21S 3513.98W 3513.99
6.07S 3579.80W 3579.81
THE CALCULATION PROCEDURES ARE BASED ON THE USE OF
THRE~-DIMENS-ION MINIMUM CURVATURE METHOD.
HORIZONTAL DISPLACEMENT = 3579.81 FEET
AT SOUTH 89 DEG. 54 MIN. WEST AT MD = 9099
VERTICAL SECTION RELATIVE TO WELL HEAD
VERTICAL SECTION COMPUTED ALONG 269.93 DEG.
SURFACE TO 9099'
RECEIVED
MAY ? ~ 199~
Alaska 011 & I~ Con.~ Commi~tliior~
Anchorage
SP ".Y-SUN DRILLING SERVICES
ANCHORAGE ALASKA
PAGE
BP EXPLORATION (ALASKA),INC.
NORTHWEST MILNE/N MILNE POINT #1
500292266300
NORTH SLOPE BOROUGH
COMPUTATION DATE: 4/12/96
DATE OF SURVEY: 032796
JOB NUMBER: AK-MM-960315
KELLY BUSHING ELEV. = 34.55 FT.
OPERATOR: BP EXPLORATION
INTERPOLATED VALUES FOR EVEN 1000 FEET OF MEASURED DEPTH
TRUE SUB-SEA
MEASD VERTICAL VERTICAL
DEPTH DEPTH DEPTH
TOTAL
RECTANGULAR COORDINATES
NORTH/SOUTH EAST/WEST
.00 .00 -34.55 .00 N .00 E
1000.00 999.94 965.39 9.15 S .59 E
2000.00 1999.86 1965.31 3.74 S 4.99 E
3000.00 2988.35 2953.80 18.07 N 95.05 W
4000.00 3856.98 3822.43 21.92 N 576.52 W
MD-TVD VERTICAL
DIFFERENCE CORRECTION
.00
.06 .06
.14 .08
11.65 11.52
143.02 131.37
5000.00 4669.52 4634.97 8.16 N 1158.92 W
6000.00 5491.35 5456.80 14.50 S 1728.06 W
7000.00 6308.92 6274.37 6.05 N 2302.73 W
8000.00 7102.90 7068.35 4.93 N 2910.35 W
9000.00 7896.81 7862.27 4.33 S 3518.25 W
330.48 187.46
508.65 178.17
691.08 '182.43
897.10 206.02
1103.19 206.08
9099.00 7974.34 7939.79 6.07 S 3579.80 W 1124.66
21.48
THE CALCULATION PROCEDURES ARE BASED ON THE USE OF
THREE-DIMENSION MINIMUM CURVATURE METHOD.
RECEIVED
SI .~Y-SUN DRILLING SERVICES
ANCHORAGE ALASKA
BP EXPLORATION (ALASKA),INC.
NORTHWEST MILNE/N MILNE POINT #1
500292266300
NORTH SLOPE BOROUGH
COMPUTATION DATE: 4/12/96
DATE OF SURVEY: 032796
PAGE
JOB NUMBER: AK-MM-960315
KELLY BUSHING ELEV. = 34.55 FT.
OPERATOR: BP EXPLORATION
INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH
TRUE SUB-SEA
MEASD VERTICAL VERTICAL
DEPTH DEPTH DEPTH
.00 .00 -34.55
34.55 34.55 .00
134.55 134.55 100.00
234.55 234.55 200.00
334.55 334.55 300.00
434.55 434.55 400.00
534.56 534.55 500.00
634.56 634.55 600.00
734.57 734.55 700.00
834.58 834.55 800.00
TOTAL
RECTANGULAR COORDINATES
NORTH/SOUTH EAST/WEST
MD-TVD VERTICAL
DIFFERENCE CORRECTION
.00 N .00 E .00
.00 N .00 E .00 .00
.00 N .00 E .00 .00
.54 S .09 W .00 .00
.99 S .08 W .00 .00
1.60 S .11 W .00 .00
2.46 S .16 W .01 .00
3.54 S .09 W .:01 .01
4.70 S .12 E .02 .01
6.13 S .32 E .03 .01
934.60 934.55 900.00
1034.62 1034.55 1000.00
1134.63 1134.55 1100.00
1234.63 1234.55 1200.00
1334.63 1334.55 1300.00
7.88 S .49 E .05 .02
9.83 S .64 E .07 .02
11.39 S .86 E .08 .01
11.51 S .90 E .08 .00
10.87 S 1.09 E .08 .00
1434.64 1434.55 1400.00
1534.64 1534.55 1500.00
1634.65 1634.55 1600.00
1734.66 1734.55 1700.00
1834.67 1834.55 1800.00
10.20 S 1.26
9.31 S 1.56
8.14 S 2.14
6.91 S 3.01
5.75 S 3.84
E .08 .00
E .09 .00
E .10 .01
E .11 .01
E .12 .01
1934.68 1934.55 1900.00
2034.69 2034.55 2000.00
2134.70 2134.55 2100.00
2234.71 2234.55 2200.00
2334.72 2334.55 2300.00
4.56 S 4.56
3.30 S 5.18
2.10 S 5.81
.89 S 6.50
.31 N 7.20
E .13 .01
E .14 .01
E .15 .01
E .16 .01
E .17 .01
2434.73 2434.55 2400.00
2534.91 2534.55 2500.00
2635.66 2634.55 2600.00
2737.26 2734.55 2700.00
2839.92 2834.55 2800.00
1.55 N 6.61
3.10 N 1.24
5.58 N 10.62
8.71 N 28.24
13.20 N 51.00
E .18' .01
E .36 .17
W 1.11 .75
W 2.71 1.60
W 5.37 2.66
2943.71 2934.55 2900.00
3048.56 3034.55 3000.00
3154.85 3134.55 3100.00
3262.53 3234.55 3200.00
3372.33 3334.55 3300.00
16.96 N 78.50
18.99 N 109.92
20.78 N 145.88
22.03 N 185.74
22.36 N 231.02
W 9.16 3.79
W 14.01 4.85
W 20.30 6.29
W 27.98 7.68
W 37.78 9.80
.~Y-SUN DRILLING SERVICES
ANCHORAGE ALASKA
PAGE
BP EXPLORATION (ALASKA),INC.
NORTHWEST MILNE/N MILNE POINT
500292266300
NORTH SLOPE BOROUGH
COMPUTATION DATE: 4/12/96
DATE OF SURVEY: 032796
JOB NUMBER: AK-MM-960315
KELLY BUSHING ELEV. = 34.55 FT.
OPERATOR: BP EXPLORATION
INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH
TRUE SUB-SEA
MEASD VERTICAL VERTICAL
DEPTH DEPTH DEPTH
3484.88 3434.55 3400.00
3601.16 3534.55 3500.00
3722.47 3634.55 3600.00
3846.99 3734.55 3700.00
3971.98 3834.55 3800.00
TOTAL
RECTANGULAR COORDINATES
NORTH/SOUTH EAST/WEST
22.15 N 282.61
22.04 N 341.92
22.25 N 410.56
22.46 N 484.75
22.11 N 559.73
MD-TVD VERTICAL
DIFFERENCE CORRECTION
W 50.33 12.55
W 66.61 16.29
W 87.92 21.31
W 112.44 24.52
W 137.43 24.99
4096.93 3934.55 3900.00
4222.19 4034.55 4000.00
4347.18 4134.55 4100.00
4470.53 4234.55 4200.00
4591.82 4334.55 4300.00
21.20 N 634.63
21.28 N 710.07
19.91 N 785.03
16.86 N 857.17
15.75 N 925.80
W 162.3'8 24.95
W 187.64 25.26
W 212.63 24.99
W 235.98 23.35
W 257.27 21.29
4713.48 4434.55 4400.00
4835.61 4534.55 4500.00
4957.48 4634.55 4600.00
5079.20 4734.55 4700.00
5201.07 4834.55 4800.00
13.78 N 995.05
11.45 N 1065.14
8.87 N 1134.75
6.86 N 1204.11
4.95 N 1273.73
W 278.93 21.66
W 301.06 22.14
W 322.93 21.87
W 344.65 21.72
W 366.52 21.87
5323.49 4934.55 4900.00
5445.98 5034.55 5000.00
5567.85 5134.55 5100.00
5689.00 5234.55 5200.00
5810.68 5334.55 5300.00
3.61 N 1344.34
1.11 N 1415.03
2.48 S 1484.59
7.17 S 1552.82
9.73 S 1622.08
W 388.94 22.42
W 411.43 22.49
W 433.30 21.87
W 454.45 21.15
W 476.13 21.68
5931.61 5434.55 5400.00
6051.95 5534.55 5500.00
6171.30 5634.55 5600.00
6291.29 5734.55 5700.00
6411.01 5834.55 5800.00
12.24 S 1690.03
14.64 S 1756.92
13.75 S 1822.03
9.66 S 1888.21
6.01 S 1953.91
W 497.06 20.93
W 517.40 20.35
W 536.75 19.34
W 556.74 19.99
W 576.46 19.72
6534.09 5934.55 5900.00
6658.99 6034.55 6000.00
6783.07 6134.55 6100.00
6907.91 6234.55 6200.00
7031.55 6334.55 6300.00
7153.57 6434.55 6400.00
7279.58 6534.55 6500.00
7406.75 6634.55 6600.00
7533.97 6734.55 6700.00
7660.73 6834.55 6800.00
2.65 S 2025.56
.45 N 2100.31
2.81 N 2173.74
4.59 N 2248.44
6.63 N 2321.11
6.30 N 2391.01
6.21 N 2467.68
6.59 N 2546.24
6.92 N 2624.88
6.88 N 2702.78
W 599.54' 23.09
W 624.44 24.89
W 648.52 24.09
W 673.36 24.84
W 697.00 23.64
W 719.02 22.02
W 745.03 26.01
W 772.20 27.17
W 799.42 27.22
W 826.18 26.76
RECEIVED
I
I
I
m
m
i
m
m
kY-SUN DRILLING SERVICES
ANCHORAGE ALASKA
PAGE
BP EXPLORATION (ALASKA),INC.
NORTHWEST MILNE/N MILNE POINT #1
500292266300
NORTH SLOPE BOROUGH
COMPUTATION DATE: 4/12/96
DATE OF SURVEY: 032796
JOB NIIMBER: AK-MM-960315
KELLY BUSHING ELEV. = 34.55 FT.
OPERATOR: BP EXPLORATION
INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH
TRUE SUB-SEA
MEASD VERTICAL VERTICAL
DEPTH DEPTH DEPTH
TOTAL
RECTANGULAR COORDINATES
NORTH/SOUTH EAST/WEST
MD-TVD VERTICAL
DIFFERENCE CORRECTION
7787.36 6934.55 6900.00 6.50 N 2780.47 W 852.81 26.64
7913.90 7034.55 7000.00 5.66 N 2857.99 W 879.34 26.53
8039.62 7134.55 7100.00 4.50 N 2934.17 W 905.07 25.72
8165.01 7234.55 7200.00 3.08 N 3009.82 W 930.46 25.39
8290.67 7334.55 .7300.00 2.14 N 3085.91 W 956.12 25.66
8416.20 7434.55 7400.00 1.13 N 3161.77 W 981.65 25.52
8542.35 7534.55 7500.00 .73 N 3238.67 W 1007.80 26.15
8668.45 7634.55 7600.00 .24 N 3315.49 W 1033.90 26.10
8794.09 7734.55 7700.00 1.34 S 3391.54 W 1059.54 25.64
8920.60 7834.55 7800.00 3.04 S 3469.01 W 1086.05 26.51
9048.19 7934.55 7900.00 5.18 S 3548.21 W 1113.64 27.58
9080.00 7959.46 7924.91 5.74 S 3567.99 W 1120.54 6.90
THE CALCULATION PROCEDURES USE A LINEAR INTERPOLATION BETWEEN
THE NEAREST 20 FOOT MD (FROM MINIMUM CURVATURE) POINTS
I
I
I
RECEIVED
N~AY ~ 4 1996
Alaska Oil & Gms Cons. Commission
Anchorage
m
i
NMILNE01.tmp created Tue Jun 10 18:29:43 1997
by CLEANUP V1.0
ISL
ISL Summary Listing - version 1.01
ISL
ISL Date Processed - 10 JUN 97
ISL Input File Name - NI~ILNE01
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 -
229.0 - 9099.0 (F)
File 1 - Channel Listing
Mnem NbrSamp NbrEntry ServID Stat InUnit OutUnit
DEPT 1 1 MWD 01 ALLO F F
DRHO 1 1 MWD 01 ALLO GCC GCC
FET 1 1 MWD 01 ALLO HR HR
GR 1 1 MWD 01 ALLO API API
NPHI 1 1 MWD 01 ALLO PCT PCT
PEF 1 1 MWD 01 ALLO BARN BARN
RHOB 1 1 MWD 01 ALLO GCC GCC
ROP 1 1 MWD 01 ALLO FTHR FTHR
RPD 1 1 MWD 01 ALLO OHM~ OHMM
RPM 1 1 MWD 01 ALLO OHMM OHMM
RPS 1 1 MWD 01 ALLO OHMM OHMM
RPX 1 1 MWD 01 ALLO OHMM OH/~/~
Start
229.000
-999.250
-999.250
-999.250
-999 250
-999 250
-999 250
-999 250
2 226
1 855
1 454
1 207
Stop
9099 000
-999 250
-999 250
-999 250
-999 250
-999 250
-999 250
75 000
-999 250
-999 250
-999 250
-999 250
File 1 - Comments Listing
File does not contain any comments
MEMORANDUM
State of Alaska
Alaska Oil and Gas Conservation Commission
?
TO: David Johnst_~ DATE:
Chairman~...~"'
March 19, 1996
THRU: Blair Wondzeil, ~~ FILE NO:
P. 1. Supervis~~~
FROM: Bobby Fos{er~ \ SUBJECT:
Petroleum Inspector
EWOICSDD.doc
Diverter Inspection
BPX - MPU - N.MP #1
PTD # 96-0055
Exploration
Tuesday, March 19, 1996: i traveled this date to BPX's exploration well North MP
#t being drilled by Nabors rig 22E and witnessed'the function test and inspected
the system for correct installation.
As the attached AOGCC Diverter Systems Inspection Report shows the system
function tested and was installed properly. I requested that an additional 20' of line
be added to the vent line to get the end farther away for the rig. This was being
done as I departed the location.
Summary: i witnessed the diverter test and inspected the system for correct
installation. The system was installed properly, with the exception of line length
which was corrected, and tested OK.
Attachment: EWOICSDD.XLS
'~-'" STATE OF ALASKA
ALASKA O.. AND GAS CONSERVATION COMMISSION
Diverter Systems Inspection Report
Operation:
Ddg Contractor: . . Nabors Rig No.
Operator. BPX Oper. Rep.:
Well Name: North Miine Point #1 Rig Rep.:
Location: Sec. 17 T. 14N R. 10E
Development
22E PTD #
Date: 3/19196
Exploratory: X
, , ,,
96-0055 Rig Ph. # 659.4446
J.C. Pyron
Leonard Schiller
Merdian Umiat
MISC. INSPECTIONS:
Location Gen.' ok Well Sign: ok
Housekeeping: ok (Gen.) Drig. Rig: ok
Reserve Pit: n/a Flare Pit: nla
DIVERTER SYSTEM INSPECTION:
Diverter Size: 20 in.
Divert Valve(s) Full Opening: yes
Valve(s) Auto & Simultaneous:
Vent Line(s) Size:
Vent Line(s) Length:
Line(s) Bifurcated: ye.s,.
Line(s) Down Wind: yes
Line(s) Anchored: ...... yes .
Tums Targeted / Long Radius: N/A
ACCUMULATOR SYSTEM:
Systems Pressure: 3,000 .L- psig
Pressure After Closure: . '1,,750 psig
200 psi Attained After Closure: min. ' 3'4 sec.
Systems Pressure Attained: 2 min. 31 sec.
Nitrogen Bottles: . 8 ~ 2000 avg. , , ,
psig
yes
in.
75' x12' ft.
MUD SYSTEM INSPECTION: Light Alarm
Trip Tank: ok ok
Mud Pits: ok ok
Flow Monitor: ok ok
GAS DETECTORS: Light Alarm
Methane ok ok
Hydrogen Sulfide: ok ok
,,
10" vent lines with ~
isolation valves
Pits (~
Sub.Base
Motors
i~pe
Shed
knife va~e
No~h
IWind
Direction
Non Compliance Items I Repair Items Wrthi~ 0 Day (s) And contact the Inspector ~ 659-3607
Remarks: Requested 20' of vent line be added .to, move end of line farther away from rig and equipment..T, his
ws being done when i departed the location.
Distfi~
orig. - Well File AOGCC REP.: _ _ ., Bobbby D. Foster
c - Oper/Rep
c-Database OPERATOR REP.: ,,.d. .C. Pyron ~Leonard,, Sch, iller ........
c - Trip Rpt File
c - Inspector EWOICSDD~XLS DWrRINSP.XLT (REV. 1194)
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Diverter Systems Inspection Report
Date: 0 3/1 9/9 6 Operation: Development Exploratory:
Drlg Contractor: NABORS Rig No. 22E PTD # 96-55 Rig Ph. #
Operator: SSD Oper. Rep.: JC PYRON
Well Name: NMP #1 Rig Rep.: LEONARD SCHILLER
Location: Sec. 1 7 T. 14N R. 10E Merdian UM
X
659-4446
MISC. INSPECTIONS: ACCUMULATOR SYSTEM:
Location Gen.: X Well Sign: X Systems Pressure: 3000 psig
Housekeeping: × (Gen.) Drlg. Rig: X Pressure After Closure: 1800 psig
Reserve Pit: NA Flare Pit: NA 200 psi Attained After Closure: min. 34 sec.
Systems Pressure Attained: 2 min. 31 sec.
Nitrogen Bottles:
8 @ 2000 average
DIVERTER SYSTEM INSPECTION:
Diverter Size: 2 0
Divert Valve(s) Full Opening: 3
Valve(s) Auto & Simultaneous: 1
Vent Line(s) Size: 1 0
Vent Line(s) Length: 75
Line(s) Bifurcated: 1
Line(s) Down Wind: 1
Line(s) Anchored: 2
Turns Targeted / Long Radius: NA
in. psig
MUD SYSTEM INSPECTION: Visual Alarm
in. Trip Tank: X na
ft. Mud Pits: × X
Flow Monitor: X X
GAS DETECTORS: Visual Alarm
Methane X X
Hydrogen Sulfide: X X
PITS
PIPE
SHED
NEW WELL
Distribution
orig. - Well File
c - Oper/Rep
c- Database
c - Trip Rpt File
c - Inspector
AC)GCC REP.:
OPERATOR/RIG REP.:
BOBBY FOSTER
JC PYRON / LEONARD SCHILLER
FI-022 DIVERTER TEST copy
/
A kSI A OIL /
C O~SERYATIO~ COMMISSIO~
/
TONY KNOWLE$, GOVERNOR
3001 PORCUPINE DRIVE
ANCHORAGE, ALASKA 99501-3192
PHONE: (907) 279-1433
FAX: (907) 276-7542
March 13, 1996
J. D. Polya, Sr. Drlg Eng
BP Exploration (Alaska), Inc.
P 0 Box 196612
Anchorage, AK 99519-6612
Re:
North Milne Point No. 1
BP Exploration (Alaska), Inc.
Permit No: 96-55
Sur. Loc. 2014'NSL, 2700'WEL, Sec. 17, T14N, R10E, UM
Btmhole Loc. 2009'NSL, 1017'WEL, Sec. 18, T14N, R10E, UM
Dear Mr. Polya:
Enclosed is the approved application for permit to drill the above referenced well. A drilling
permit is not valid at a location where the applicant does not have a fight to drill 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 10-40 I. Any penetration of strata in the North Milne
Point No. 1 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 drilling operations until all other
required permitting determinations are made.
Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035.
Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the
surface casing shoe must be given so that a representative of the Commission may wimess the test.
Notice may be given by contacting the Commission petroleum field inspector on the North Slope
pager at 659-3607.
Commissioner
BY ORDER OF THE COMMISSION
rill/Enclosures
CC:
Department ofFish & Game, Habitat Sect/on w/o encl.
Department of Environmental Conservation w/o encl.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION ~-'~r'4.. ! ~,/¢ ,'-~ ~
PERMIT TO DFllLL
20 AAC 25.005
ila. Type of work Drill [] Redrill 1-111b. Type of well. Exploratoryl-I Stratigraphic Test [] Development Oil []
Re-Entry [] Deepen []1 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 f e et Milne Point Unit / Kuparuk River
3. Address 6. Property Designation
P. O. Box 196612, Anchorage, Alaska 99519-6612 ADL 355016
4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025)
2014' NSL, 2700' WEL, SEC. 17, T14N, RIOE Milne Point Unit
At top of productive interval 8. Well number Number
2009' NSL, 780' WEL, SEC. 18, T14N, RIOE North Milne Point #1 2S100302630-277
At total depth 9. Approximate spud date Amount
2009' NSL, 1017' WEL, SEC. 18, T14N, RIOE 03/15/96 $200,000.00
12. Distance to nearest 13. Distance to nearest well 4. Number of acres in property15. Proposed depth (MD and TVD)
property line
UnleasedAcreage 3271 feet No Close Approach feet 5071 9189' MD / 8060'TVD feet
16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2))
Kickoff depth 2~0o feet Maximum hole angle 36 o Maximum surface 3097 psig At total depth (TVD) 7735'/3861 psig
18. Casing program Specifications Setting Depth
s~ze Top Bottom Quantity of cement
Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data)
24" 20" 91.1# H-40 Wold 112' 32' 32' 144' 144' 250 sx Arcticset I (Approx.)
12-1/4" 9-5/8" 40# L-80 Btm 4971' 31' 31' 5102' 4756' 993 sx PF 'E', 250 sx 'G', 150 sx PF 'E'
8-1/2" 7" 29# L-80 Mod-Btm 9169' 30' 30' 9189' 8060' 317 sx Class 'G'
19. To be completed for Redrill, Re-entry, and Deepen Operations.
Present well condition summary
Total depth: measured feet Plugs (measured)
true vertical feet
Effective depth: measured feet Junk (measured)
true vertical feet
Casing Length Size Cemented Measured depth True Vertical depth
Structural
Conductor
Surface
Intermediate
Production
Liner
Perforation depth: measured
true vertical
20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program[]
Drilling fluid program [] Time vs depth plot [] Refraction analysis [] Seabed report[] 20 AAC 25.050 requirementsFI
21. I hereby certify that the foregoing is true and correct to the best of my knowledge
Signed ~~.-T- Title Senior Drilling En~lineer Date
Commission Use Only
Permit Number APl number Approval date See cover letter
?.~. _.-.~"',_¥ 5 O- 43 ~_- ~ - 2_ 2. ,~ ~ ~' ,,~ / [ '~/9 0 for other requirements
Conditions of approval Samples required [] Yes J~ No Mud Icg required []Yes ~ No
Hydrogen sulfide measures [] Yes [~ No Directional survey required [] Yes [] No
Required working pressure for BOPE []2M; i-13M; [~SM; 1-110M; []15M;
Other: 0~Ji~INAL 81GNED BY by order of
Approved by ,J, Dlilvid NOI'k~, P.E. Commissioner tne commission Date.~'/,.%/~ ....
Form 10-401 Rev. 12-1-85
Submit in i
BP SECRET
Attachment No. 2
North Milne Point #1
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
,
1
1
,
,
,
,
RIH with mule shoe on 5" drill pipe to TD. Circulate and Condition mud and
pump a 237 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~.~i.r.c.,.~!ate...a..t.~igh,:,
rate to clean sand from drill pipe. ~"~.~:~:-~'%.-'~'~?:::::~ ~-
RDMO Nabors 22E Rig to Milne Point F Pad.
"..!~xr( '! '1 ?396
NMP#2 Well Plan PAGE 24 JDP Classified: "SECRET"
STATE OF ALASKA
ALASKA 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. 0. Box 196612, Anchorage, Alaska 99519-6612
4. Location of well at surface
2014' NSL, 2700' WEL, SEC. 17, T14N, RIOE
5. Type of Well:
Development __
Exploratory x
Stratigraphic __
Service
At top of productive interval 9.
Datum elevation (DF or KB)
KBE = 35 feet
Unit or Property name
Milne Point Unit
Well number
North Milne Point #1
Permit number
2009'NSL, 780' WEL, SEC. 18, T14N, RIOE
At effective depth
To be determined
At total depth
2009' NSL, 1017' WEL, SEC. 18, T14N, RIOE
ORIGINAL
10. APl number ~' '
50- ~.~? .-~.~, ~' ~/_~ -~
11, Field/Pool
Milne Point Unit/Kuparuk River
12. Present well condition summary
Total depth: measured
true vertical
9100' feet
7988' feet
Plugs (measured) 8568;9100' MD, 15.8 ppg Class 'G' Premium
cement
Effective depth: measured
true vertical
To be determined feet
feet
Junk (measured)
Casing Length
Structural
Conductor 112'
Surface 4971'
Intermediate
Production
Liner
Perforation depth: measured N/A
Size
20"
9-5/8"
true vertical
Tubing (size, grade, and measured depth) N/A
Cemented Measured depth True vertical depth
250 sx Arcticset I (Approx.) 144' 144'
993 sx PF'E',250sx'G°, 150 sx PF'E' 5 1 02' 4756'
Packers and SSSV (type and measured depth) 9-5/8" EZSV set @ 5027' MD w~ 73 sx below & 37 sx above of 15.8 ppg Class 'G' Premium cement. 9-5/8"
EZSV set @ 300' MD w/39 sx, 12.0 ppg PF 'E' cement above.
13. Attachments
Description summary of proposal X Detailed operations program __
BOP sketch ×
14. Estimated date for commencing operation
O3/27/96
16. If proposal was verbally approved
Name of approver
Date approved
15. Status of well classification as:
Oil X Gas
Suspended.__
Service
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Signed ~ o,- 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__ Subsequent form required 10-
,:Jdginal Signed By
Approved by order of the Commission 0avid W. Johnston
Form 10-403 Rev 06/15/88
Approval No. D
.~. ;.~pproved Co!y ¢(,,, -
/'lr~ -- ' R~etur. ned
---~omm,ss,oner--~ Date ~..~/~Q~~
SUBMIT IN TRIPLICATE
Proposed P&A/Suspension
for
North Milne Point #1 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
designs alternatives. The P&A/Suspend proposal suggests a design that would both
meet suspension and P&A criteria through the use of an FMC mudline suspension
system (SD-l). This is a win/win approach whereby the well is still accessible 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 moneys 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
prelssured at 8.6 Ppg will come in with the Na Top prognosed at 4200' sstvd and
thelOB 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 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.
Respectfully,
Joe Polya, Sr. Drilling Engineer, BPX
Attachment No. I ~j.~)~l~ I~i~l]~ I~)i~ ~1 ~1]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//22/96
JD Polya
Drawing Not to Scale
9-5/8" EZSV
@ 300' md
20" 91# Casing Shoe
@ 142' tvd/141' md
9.9 ppg Drilling Mud
4235'tvd/445t
Cement
Interface 4500' md
Schrader Bluff Sand Top
9-5/8" EZSV
@ 5027' md
Top of 37 sxs of 15.8 ppg Cement
@ 4927' md-- Retainer@ 5027'md.
Base of 73 sxs of 15.8 ppg Cement
@ 5202' md.
Bluff Sand Base
Top Seabee Shale
9-5/8"40# L80 Btrc
@ 4756' tvd/5102' md
7719 tvd/8768' md .~~ - - ~Top Kuparuk Formation
~ ~,.'~'~ 237 sxs Class G 15.8 ppg Cmt ~,\\~
~'~~-'-~'~~~ Plug (from 8568' to 9100' md) ~,,~'
7830' tvd/8905' md ~--~~ ~ Top Miluveach Shale
7" 26# L80 Btrc
@ 7988' tvd/9100' md
12.0 ppg Permafrost E Cement
15.8 ppg Class G Cement
Item No.
.
,
.
.
,
,
.
.
,
North Milne Point #1 Well
Permit Package
List of Enclosures
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&NSuspend Commercial Hydrocarbons
Pages
11
2
3
2
North Milne Point #1 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 #1 Well. Similar to NMP#2 well, 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 stratagraphic structure from which the Milne
Point F Pad wells are currently producing from. In fact, the North Milne Point #1
well will intercept the Kuparuk reservoir down dip in the same fault block the MPF-
38 well recently drilled into. The intent of this well is to determine if there is an
oil/water contact associated with this fault block. There are no plans to core or
perform a flow test on this well.
SUMMARY:
Casing Design- Variance is requested to 20AAC25.030 Section
(1) structural casing must be set by driving, jetting, or drilling to
minimum depth of 100 feet below the mud line.
(2) conductor casing must be set at least 300 feet, but not more than
1000 feet, below the mud line; the casing must cemented with a
quantity of cement sufficient to fill the annular space up to the mud
line or to the top of the casing when the blowout prevention stack is
placed in an excavation or glory hole. Cement fill must be verified by
observation or-other means approved by the commission. Upon
approval of the commission, cement may be washed out to a depth not
exceeding the depth of the structural casing shoe, to facilitate casing
removal upon well abandonment.
BP submits proposal to eliminate the structural casing and set a conductor casing
100' below the mudline. Since this well is in the expanded Milne Point Unit and BP
is confident that we have sufficient offset data and seismic data to eliminate the
chances of shallow gas and abnormal geopressures, 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 and the NMP#2 currently being drilled. 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 Milne Point and Kuparuk Units.
Furthermore, the Schrader Bluff sands are wet in the Northwest Milne Point well
and in all the wells drilled north of the Milne Point F and L Pads -- the northern
portion 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 into the rathole in 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. As stated, the North Milne Point #1 well
will drill to a bottom hole location of 2009 FSL and 1017 FEL Section 18 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' md boundary is a stratagraphic reference to
the rathole drilled into the Miluveach Sand below the Kuparuk reservoir in the
Northwest Milne Point #1 well-- the 7526' md equates to a tvd depth 241'tvd
below the top of the Miluveach Shale. The proposed TD in the NMP#1 well is 230'
tvd below the top of the Miluveach Shale and Logging While Drilling tools will be
used to ensure we do not drill beyond this datum (which has an 11' tvd safety factor
included). Also, the geological prognosis shows no faults present at TD.
The operators for strata below 7526' are Maxus 50.00 and Amerada Hess 50.00.
Conoco negotiated a Farmout Agreement between Maxus Exploration Company
and Amerada Hess Corporation pertaining to 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 assumes all rights as Farmee in this agreement.
A P&A/Suspension proposal is included in the permit package. Please call me
should you have any questions -- 564-5713.
(:~es~ctfully,
Joe Polya, Sr. Drilling Engineer, BPX
· r-01-g6 12:14 Ana~ ill DPC
344 2160
P.04
.BP'EXPLORATION 'INC'.
Harker Identification MD BK8 SECTN INCLN .
A) KB 0 0 0 0.00
B). KOP/BUILD 3/100. 2500 2500 -0 0.00
C) END 3/100 BUILD -3702 3624 366 36.06
D) 9-5/8' CASING POINT 5~02' 4756 ItgO -36.06
E) TARGET 8787 7735 3360- 36.06
F) 7-". CASING. POINT -9189 8060 3596 · 36.06
II
NMP-J. (P7)
VERTICAL SECTION VIEW
I
.
Section at: 269.93
'TVD Scale.:- I inch = 1200 feet
TO 9189 8060 3596 36.06 'Dep Scale · $ inch = J200 feet
600 1200 JS0O 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800
Semi:inn D~napf~mp
Marker Identif icat~on
A) KB
B) KOP/BUILD 3/t00
C) END 3/100 BUILD
D), 9-5/8' CASING POINT
'E) TARGET'
F) 7' CASING PDINT
G) TD
mi
Ull
· ii
ND
0
2500
3702,,.,
5~02
B787
,9189
9189 .
'EXPLORATION' 'INC.
i iii
i iIiim i
iii i
E/W
OE
OE
356 w
t 190 'W
3360 W
3596 W
3596 N
N~
ON
'ON
OS
IS'
'4S
4S
4S
Jnadr Y ] ]Sch]umberger
II III
... NMP1 (P7)
PLAN VIEW.
CLOSURE.". · 3596 feet "at Azimuth 269.93
DECLINATION' *0.000 (E}
;SCALE." · 1 inch = '500 feet,
'DRAWN. ,03/0i/96
..
i '
i ii
__
mllll i i mi Ii il
aOnlll (c)96 NMPIP7 3,Ob,O! ti):. 19 AM P)
4250 4000 3750 3500 3250 3000 2750 2500 , 2250 2000 1750 1500 t250 1000 750 500 250, 0 250
<- WEST' EAST ->
· mmlml i i n m ·
Ii
0
Well 'Plan I Well Name: I North Milne Point #1 Appraisal
Summary
I
I
I Type of Well (producer or injector)'
I Kuparuk Producer
Well
Surface Location: 2014 NSL 2700 WEL Sec 17 T14N R10E UM., AK
Tar~let Location: 2009 NSL 0780 WEL Sec 18 T14N R10E UM., AK
Bottom Hole Location: 2009 NSL 1017 WEL Sec 18 T14N R10E UM., AK
IAFE Number: 1330168 I
Rig: I Nabors 22-E
Date: complete:
IuD- 1918e' I ITVD- 180S0' RKB I IKBE - USE= 135'
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 1 735 1 700
NA 4457 4235 Top of Schrader Bluff Sands (8.3 ppg)
SeabeeShale 4952 4985 Base of Schrader Bluff Sands (8.3 ppg)
HRZ 8359 4635 High Resistivity Zone
Kuparuk Cap D Shale 8 60 0 75 8 4 Kuparuk Cap Rock
Target Sand -Target 8787 7735 Target Sand (9.6 ppg)
Total Depth 91 8 9 8 0 6 0
Casinq/'i'ubing Pro! ram'
'W
Hol~, (~sg/ t/Ft Grade Conn Length Top Btm
Size Tbg O.D. MD/TVD MD/TVD
24" 20" 91.1# H-40 Weld 112 32/32 144/144
12 1/4" 9-5/8" 40# L-80 btrc 4971 31/31 5102/4756
8 1/2" 7" 29# L-80 mod- 9169 30/30 9189/8060
btrc
Internal yield pressure of the 7" 29# casing is 8160 psi. Worst case surface pressure would
occur with a full column of gas to the reservoir at 7735' TVDRKB. Maximum anticipated surface
pressure in this case assuming a reservoir pressure of 3861 psi is 3097 psi, well' below the
internal yield pressure rating of the 7" casing.
Logging Program:
IOpen Hole Logs:
Surface
Intermediate
Final
Cased Hole Logs:
INone 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. (Note: No H2S has been experienced on offset nor is it expected on this well.)
Mud Program:
I Special design considerations I(No Special Design Considerations.)
Surface Mud Properties: I SpudMud
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 I 0 I 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.
Directional:
KOP:
Maximum Hole Angle:
r2500
36°
(No Shut Ins)
Close Approach Well:
Waste Management:
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.
North Milne Point #1
Proposed
Summary of Operations
I ·
,
·
4,
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
NU and test 20" Diverter system. Build Spud Mud.
NOTE: Hold pre-spud meeting with Co. Rep, Toolpusher, Rig Crew on tour, 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
.
.
.
.
.
10.
Drill a 12-1/4" surface hole as per directional plan. Run DIR/GR/RES across Schrader Bluff in
surface hole. Drop ESS before POOH. Run and cement 9-5/8" casing.
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, Cut & Weld on 10-3/4" Emergency Bell Nipple -- test, attach the Gen 5
Casing Spool via mechanical lock down, NU and Test 13-5/8" BOPE.
MU a Hycalog PDC bit on 'an Anadrill extended motOr, with Directional MWD and LWD
CDR/CDN (GR/RES/Dens/Neu). RIH, Drill out Float Equipment and 10' of new formation.
Perform LOT as per the LOT Procedures contained in Section 3 of the Dossier.
Drill 8.5" hole to TD as per directional plan. Drop ESS before POOH to run casing.
NOTE: An IHR Gryo is NOT required for this well.
NOTE: 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.
Run and Cement 7" Casing -- the Float Collar should be spaced approximately 200' above
the top Kuparuk oil bearing sand which would be +_8568'-- depth should be adjusted based
on logs. 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.
Request to AOGCC for Annular Pumping Approval for NMP#1:
1. Approval is requested for Annular Pumping into the NMP#1, 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.
Aquifers in the Milne Point Unit have been exempted from Class II injection activities by the
AOGCC by Aquifer Exemption Order #2 as referenced in Area Injection Order #10. There
are no domestic or industrial use water wells located within one mile of the project area.
3. The 9-5/8" casing shoe will be set at 5102' md (4756' 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 p$ig while the collapse
rating (80%) of the 7" 29# L80 casing is 5616 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.
BURST PRESSURE 9-5/8" 40# L-80 CASING:
COLLAPSE 7", 26#, L-80 CASING:
9-5/8" SURFACE CASING SHOE DEPTH:
5750 PSI
7O2O PSI
5102' MD/4756' TVD
HYDROSTATIC 'PRESSURE @ 4756' TVD WITH VARIOUS DENSITY FLUIDS:
(0.052) X (4756) X (FLUID DENSITY) = HYDROSTATIC PRESSURE
80% OF 9-5/8" COLLAPSE PRESSURE = (5750 PSI) X (0.8) = 4600 PSI
MAXIMUM ALLOWABLE INJECTION PRESSURE 2000 PSI AT ANY PPG
SURFACE CASING SHOE DEPTH ('I-VD): 4 7 5 6'
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 1978 4600 2622
9 2226 4600 2374
·
I 0 2473 4600 2127
1 I 2720 4600 1880
I 2 29'68 4600 1632
1 3 3215 4600 1385
1 4 3462 4600 1138
I 5 3710 4600 890
I 6 3957 4600 643
1 7 4204 4600 396
MAX ALLOWABLE INJECTION PRESSURE = 4600 PSI- HYDROSTATIC PRESSURE
or 2000 psi (whichever is less).
GENERAL DISCUSSION -- North Milne Point #1
Objective:
The North Milne Point #1 well is planned as an appraisal well into 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.
it is hoped a full oil column will be found; however, an Oil/Water contact could be
encountered. 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" open hole section will be plugged and the wellbore abandoned as per 20
ACC 25.105.
Drilling Hazards and Risks:
The Kuparuk reservoir sands are expected to be a maximum of 3853 psig or 9.6 ppg. The
closest well is MPF-38 which was recently drilled by Nabors Rig# 27E. Obtain the MPF-38
work file from Nabors Rig# 27E and review same.
This well is expected to drill very much like the development wells currently drilled in the
Milne Point Unit; however, this well is located on the north most edge of the Milne
Point Unit boundary and the unexpected may happen -- BE 'ALERT!!!!!!!!!!!!!!!!!
There will be no close approach wells associated with the drilling of the North Milne Point #1
well. An IN-HOLE REFERENCE GYRO will NOT be required for this well.
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 have been to drill to TD with
a 9.9 ppg MW versus the standard 10.2 ppg previously used in Kuparuk wells -- the MW is
increased as required to drill the Kuparuk interval.
Lost returns while running and cementing the 7" production casing in this portion of the Milhe
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
Coiville 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:
Although hydrates were encountered on E, H, and I Pads located in the southern portion of
the Milne Point Unit, 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.
Neither the Northwest Milne Point #1 and Arno Jones Island #1 wells experienced hydrates.
No other drilling hazards or risks have been identified for this well.
Hydrogen Sulfide-- H2S (20 AAC 25.065)
There is no evidence of H2S being encountered in any of the offset wells.
Specifically, The Proposed North Milne Point #1 Kuparuk target is located 1.5
miles northeast along a 23° azimuth from where the recently drilled MPF-38 well
penetrated the Kuparuk reservoir -- these Kuparuk targets are in the same fault
block and the MPF-38 well did not experience any signs of H2S.
The surface location for the proposed North Milne Point #1 well is located only 2.5
miles northeast along an azimuth of 40° from the surface location of the Northwest
Milne Point #1 Exploration well -- Mud logs from this well indicate no presence of
H2S.
The nearby Arco Jones Island #1 Exploration well was drilled with no sign of H2S.
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 #1 well, Shared Services Drilling asks for
exemption from items c2B, c2C, and c3 in 20 ACC 25.065 and plans to comply with
the following items:
clA)
clB)
clC)
c2A)
c2D)
The mudlogging unit will be equipped with a combination visual and audible
alarm system located where it can be seen or head 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.
NORTH MILNE POINT #1 WELL
WELL SITE SURVEY and PRESSURE ANALYSIS
(20 ACC 25.005c8 and 20AAC 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 #1 Well will TD 300' md
past the base of the Kuparuk reservoir into the Miluveach Shale formation -- planned
total measured depth is 9204' (8038' sstvd).
The seismic data indicates that no abnormally pressured zones should be
encountered while drilling the North Milne Point Cf1 well-- see the Attached 2D
Seismic Shallow Hazard Assessment prepared by BPX geophysicist Eric Dixon
complete with three ITT vs Depth Charts numbered 14, 15, and 16. 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 proposed North Milne Point #1 Kuparuk target is located 1.5 miles northeast
along a 23° azimuth from where the recently drilled MPF-38 well penetrated the
Kuparuk reservoir-- these Kuparuk targets are in the same fault block and the
MPF-38 well did not experience any signs of H2S.
The surface location for the proposed North Milne Point cf1 well is located only 2.5
miles northeast along an azimuth of 40° from the surface location for the Northwest
Milne Point cf1 Exploration well-- See Attachment No. 3 for a MW vs TVD plot.
Again, all these wells showed no signs of abnormal geopressure.
BP EXPLORATION
Memorandum
To:
From:
Subjeot:
Tim $chofield
Eric Dixon
Milne Point Unit North Milne #1 & #2
2D Seismic Shallow Hazard Assessment
Date: January 16, 1996
An analysis to detect shallow abnormally high geopressure has been conducted in the area
surrounding the surface locations of North Milne #1 and #2. Results from the analysis predict that no
abnormally high geopressures will be encountered while drilling the North Milne wells.
This analysis utilized stacking velocities from two nearby 2D seismic lines to derive interval transit time
yrs. depth curves. This method is not as accurate at predicting shallow over pressure zones as a high
resolution shallow hazard survey, but it is a good gross indicator of abnormal geopressure conditions.
No significant velocity inversions were observed in the data. The I'1-1' curve trends are typical of seismic
velocities observed in shallow water and near shore environments throughout the Milne Point unit.
Chart 15 displays data from five shot points on line S82HB4; acquired in 1982. Chart 14 shows two shot
points from a much older line AIG-25 shot in 1977. Chart 18 displays the two closest shot points to the
North Milne surface locations.
Based on nearby well control, the following shallow subsurface conditions are predicted:
Depth ss
-2 to 6
6 to 70
Frozen ground composed of sand silts and gravel
Unfrozen sandy silts and clays grading into sand and gravel at about 28 ft.._-
70 to 1650
1650 to 3500
Permafrost
UnfroZen sands silts and mud stone of the Gubik and Sagavanirktok.
Because no shallow gas or strongly over pressured zones have been encountered in nearby wells we
do not feel that a shallow hazard survey is needed.
Eric Dixon
-P. uc..Tta R E'
BP SECRET
1:{B000
KILOMETER$~ ...... ~ , ~"ILOMETEES ,,.
STRTUTE HILES ~ ~, qSTRTUTE MILES,
~ I[}{FI,Olt~lON ~ INO.
NORTH MILNE/JONES ISLRND
BP SECRET,
O00L OOL OL
.LLI
00000 I.
0000 !.
O00L
00~
000 L
OOL
.ILl
00000 I.
0000 I.
000 L
OOL
OL
000 L O0 L 0 L
.ILl
O0000L
O000L
000~
OOL
ATrACHMENT NO. I
NMP#1 Pore Pressure, MW
& Fracture Gradient Plot
IOO0
2OOO
3OOO
4ooo
5000
6OOO
70O0
8OOO
9OO0
10
plplg (EM~N~ 13 14
15
MW
FRAC GRADIENT
ATTACHMENT NO. 2
MPF-38 MW versus TVD Plot
MW (ppg)
9 10
11-
1000
2OOO
30OO
,,.- 4000
5OOO
6O0O
-- MPF-38:
.
700O
8O0O
A'I-r'ACHMENT NO. 3
Northwest Milne Point #1 MW vs TVD
1000
2OOO
3000
4000
50O0
60OO
7000
8000
7
0
MW (ppg)
8 9 10
11
I~ NWMP#1 I
A'rTACHMENT NO. 4
1000
2O00
3000
4OOO
5000
6O0O
7O00
80O0
9000
10000
Jones Island #1
MW (ppg)
9
Exploration Well
10
11
I'-~--Jones Island #1 I
Proposed Casing Design
for
North Milne Point #1 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 5102' md (4756' 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.
Burst Calculations were performed for:
1. Displace Cement with 8.6 ppg EMW on the back side.
2. Bump Plug with 3000 psig with 8.6 ppg EMW on back side.
3. Casing tested to 3000 psig with 8.34 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.
I1.
Collapse Calculations were performed for:
1. Total lost circulation while drilling with 9.6 ppg MW above Cement of
backside. A 8.34 ppg emw lost circulation zone at 7000' sstvd allows the
fluid level to drop to 1387'.
2. Cementing the casing with 15.8 ppg tail cement channeling to surface and
fresh water used to bump the plug.
3. Well Suspended -- Permafrost Freeze Back (see calculation).
4. Total Evacuation was also considered for this string with 9.6 ppg mud on the
back side.
III. Tensile Calculations were performed for: 1. Running casing with two times the planned dogleg and 9.6 ppg MW.
2. Displacing Cement with 500 psig back pressure.
3. Bumping the Cement Plug with 3000 psig and 9.0 ppg mud.
Production Casing: 7" 28# L80 Btrc proposed to be set through the Kuparuk
Sands into the Miluveach Shale at 9204' md (8072' 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.
·
2.
3.
4.
Burst Calculations were performed for:
Displace Cement with 8.6 ppg EMW on the back side.
Bump Plug with 3000 psig with 8.6 ppg EMW on back side.
Casing tested to 3000 psig with 8.34 ppg EMW on back side.
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.
Note: All of the above calculations are overly conservative, yet the Casing
Design exceeds all safety factors.
II. Collapse Calculations were performed for:
1. Total lost circulation while drilling with 9.6 ppg MW above Cement of
backside. A 8.34 ppg emw lost circulation zone at 7000' sstvd allows the
fluid level to drop to 1387'.
2. Cementing the casing with 15.8 ppg tail cement channeling to surface and
fresh water used to bump the plug.
3. Well Suspended -- Permafrost Freeze Back (see calculation).
Note: All of the above calculations are overly conservative, yet the Casing
Design exceeds all safety factors.
III. Tensile Calculations were performed for:
1. Running casing with two times the planned dogleg and 9.6 ppg MW.
2. Displacing Cement with 500 psig back pressure.
3. Bumping the Cement Plug with 3000 psig and 9.0 ppg mud.
20" 91# Casing Shoe
@ 142' tvd/142' md
Schrader Bluff Sand Top
Cement
Interface 5500' md
.~r Bluff Sand Base
Top Seabee Shale
9-5/8"40# L80 Btrc
@ 4756' tvd/5102' md
7" Casing will not
be perforated
7719' tvd/8768' md
TOC @ 8568' md
TOC at 7768' md
Top Kuparuk Formation
7830' tvd/8905' md -
12.0 ppg Permafrost E Cement
15.8 ppg Class G Cement
Top Miluveach Shale
7" 26# L80 Btrc
@ 8060' tvd/9189' md
2/22/96
JD Polya
Drawing Not to Scale
NMP#1
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 YIELD:2.17 ft3/sx MIX WATER: 11.63 gal/sk
APPROX #SACKS: 993 THICKENING TIME: Greater than 4 hrs at 50° F.
TAIL CEMENT TYPE' Premium G
ADDITIVES:
0.2% CFR-3 + 0,2% Halad 344
WEIGHT: 15.8 ppg YIELD'1.15 ft3/sx MIX WATER: 5.0 gal/sk-
APPROX #SACKS' 250 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.
11
CEMENT
NMP#1 Well
PRODUCTION CASING
PROGRAM- HALLIBURTON
STAGE I CEMENT JOB ACROSS THE KUPARUK INTERVAL'
CIRC. TEMP:
7040' TVDSS.
140° F BHST 170° F at
S PACE R' 20 bbls fresh water
70 bbls Alpha Spacer mixed as per Halliburton specifications weight~d~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: 15.8 ppg YIELD: 1.15 cu ft/sk
MIX WATER: 5.0 gal/sk
APPROX # SACKS: 317 THICKENING TIME: 3 1/2-4 1/2 hrs @ 140°F
219 plus 98 sacks left inside casing to cover Kuparuk
formation.
FLUID LOSS' < 50cc/30 min @ 140° F
FREE WATER: 0cc @ 45° 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 I cement volume is calculated to cover 1000' md above the Kuparuk
Target Sand with 30% excess.
The 7" Float Collar should be spaced out 200' md above the Kuparuk C
Sand to meet the P&A requirements -- shoe joint volume 23 bbls.
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
.
~' .,...~ ., ~. ~..i '' ~ ~
916 676
~T..--'.~ ~ .~-.. ...... ..;' . - ...
0.0758 0.0371
0.0558 0.0226
CASING DESIGN SUMMARY
GENERAL INFORMATION: UNITS SURFACE PRODUCTION
Casing Size inches 9.625 7
Weight Ibs./ft 4 0 2 9
Grade n/a LB0 LB0
Connection n / a BTRC B'rRC
DESIGN CRITERIA:
Burst psig 5750 8160
Collapse psig 3090 7020
Tensile M LBS. 91 6 676
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)
4.0 Collapse Loads:
4B. Cementing (Dfb > 1.1)
4A,C,or D, Drilling, Loss Circ, Evacuation (Dfb > 1.1)
5.0 Tensile Loads:
5AorB. Running Casing (Dfb > 1.6)
5DorE. Cementing (Dfb > 1.1)
6.0 Triaxial Loads: (Disregard if OD/t > 15)
7.0 Buckling and Compression Loads:
7.90 17.33
4.68 5.00
1.69 1.99
2.16 1.62
OD/t =
I .67 2.25
1.67 0.00
2.22 1.92 ..," AI~S~{~'~ OiJ & L~,;,.~S
1.7,1 1.56 Arc, ch
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)
3.0 CASING DESIGN WORKBOOK (BURST)
.,Casing Surf
iS[ZE 9.625
WEIGHT 4 0
'GRADE L80
CONNECTION BTRC
BURST (100% Design Rating) 5750
3A. Pb D!splace Cement 728
Calculated Design Factor 7.90 OK
3B. Pb Bump Cement Plug 1228
Calculated Design Factor 4.68 OK
3C. Pb Pressure Test Casing 3396
Calculated Design Factor~1. 6 9 OK
Pb WELL CONTROL
3D. Influx at Casing Shoe 1688
Calculated Safety Factor 5.28 OK
3E. Influx at Surface 2667
Surface Csg Burst Rating 5750
Calculated Safety Factor 2.16 OK
BP Minimum Design Factor 1.1
Csg Size
9.625
BHA Calc OD LENGTHinflux B{~= BBI. S
BHA 0.0259 7.0
DRILL PfPE 2026 0.0459 93.0
Hole Diameter
Page B1 - Surface Burst Calculations
I CsgSize I WeightI Ora I I Burst I ,O ICcap(bPf) l MOShoe ! VOShoe !
I 9'625 I 40 I L80 I ~rRC I 5750 I 8-835 10'0758 I 5102 I 4756 I
13A. pb Di,p ace Cement Ca cu ation I
IValues ISymbol lUnit IOecriptio. & Explanation I
728 IPb disp psig Pb disp = Pi - Pb (Burst Pressure applied while cementing)
3092 P~ psig Pi [] Psp + Ptc + PIc + Pdf 5102 Check MD 0
4756 Dshoe feet (tvd) Depth of Casing Shoe 4756 CheckTVD 0
5102 MDshoe feet (md) Measured Depth of Casing Shoe 387 CheckVolume~ 0
387 VOLcsg bbls Volume of the Casing 1.0 Check % Total 0
~ INPUT: 1 if Applies Spacer Calulations
0 Psp psig Psp = CWsp * 0.052 * Hsp
~,.~ CWsp ppg (emw) Equivalent MW of Spacer
~ 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
~~ INPUT: I if Applies Lead Cement Calculations
2577 P/c psig PIc = CWIc * 0.052 * HIc
~~ CYvlc ppg (emw) Equivalent MW of Lead Cement
~~ Vic bbls Volume of Cement I Pumped 384
4129 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length
4429 LIc feet (tvd) LIc = VIc/Ccap 0.87
~~ INPUT: 1 if Applies Tail cement Calculations
51 5 Ptc psig PIc = CWIc * 0.052 * HIc
~ CWtc ppg (emw) Equivalent MW of Tail Cement
~~ Vtc bbls Volume of Cement I Pumped 51
627 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length
673 Ltc feet (tvd) Htc = Vtc/Ccap 0.13
~~ INPUT: 1 if Applies Heavier of Drilling Fluid or Displacement Fluid
0 Pdf psig Pdf = CWdf * 0.052 * Half
MWdf ppg (emw) Equivalent MW of Drlg or Disp Fluid
0 Vdf bbls Volume of Drlg or Disp Fluid
0 Hdf feet (tvd) Hdf=Ldf/MDshoe*Dshoe %TL I% of Total Length
0 Ldf feet (tvd) Hdf = Vdf/Ccap 0.00
I
2364 Pe psig Pe = Proud + Psp + Plc + Pdf
4756 Dshoe feet (tvd) Depth of Casing Shoe
5102 MDshoe feet (md) Measured Depth of Casing Shoe
12.25 Big ID inches Last Casing ID or Surface Hole Size whichever is the case.
285 VOLann bbls Annular Capacity (annular between casing and last casing ID)
0.0558 ANNcap bpf Annular Capacity (annular between casing and last casing ID)
~i INPUT: I if Applies Drilling Fluid Calculations 5102 Check MD 0
1321 Pmud psig Proud = MW * 0.052 * Hmud 4756 CheckTVD 0
~~i MW ppg (emw) Density of Drilling Fluid 285 CheckVolurne~ 0
162 Vmud bbls Volume of Drilling Fluid 1.0 Check%Total 0
2703 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length
2900 Lmud feet (md) Lmud = Vmud/ANNcap 0.57
I
~~:, INPUT: I if Applies Water Ahead Calculations
544 Ph20 psig PIc = CWh20 * 0.052 * Hh20
CWh2o ppg (emw) Equivalent MW of Water Ahead
;~;~ Vh20 bbls Volume of Water Ahead
1253 Hh20 feet (tvd) Hl~LIc/MDshoe*Dshoe % TL I% of Total Length
1345 LIc feet (tvd) LIc = VIc/ANNcap 0.26
I
i~'~:.,,,.i~::~r,~ INPUT: I if Applies Spacer Calculations
0 Psp psig Psp = CWsp * 0.052 *.Hsp
~! ! CWsp ppg (emw) Equivalent MW of Spacer
!~!!~i~!~,! 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
~:~i~i~i~:~i~! INPUT: I if Applies Lead Cement Calculations
499 P/c psig PIc = CWIc * 0.052 * HIc
:.i~iiii:~;i~: CW/c ppg (emw) Equivalent MW of Lead Cement
i:i~!~i~~,i Vic bbls Volume of Cement I Pumped 384
800 H/c feet (b/d) HIc=-LIc/MDshoe*Dshoe % TL % of Total Length
858 LIc feet (tvd) LIc = VIc/ANNcap 0.17
Page B2 - Surface Burst Calculations
9.625 I 40 I L80 I mm I 5750 I 8.635 I 0.0756I 5102 I 4756 I
13B. Pb Bump Plug Galculations I I
Values ISymbol lUnit IDecription & Explanation . I
1 228 IPb bump psig Pb bump = Pi - Pe (Pressure Applied when Bumping Plug)
4325 P/ psig Pi = Ptc + Pdf + Pfz + Pbump 5103 Check MD - 1
4756 Dshoe feet (tvd) Depth of Casing Shoe 4756 Check'l'VD 0
5102 MDshoe feet (md) Measured Depth of Casing Shoe 387 CheckVolume~ 0
387 VOLcsg bbls Volume of the Casing 1.0 Check % Total 0
~ INPUT: 1 if Applies Tail Cement Calculations
0 Ptc psig PIc = CWIc * 0.052 * HIc
~~ CWtc ppg (emw) Equivalent MW of Tail Cement
...... ~ .............
Vtc bbls Volume of Cement I Pumped 51
0 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length
84 Ltc feet (h/d) Htc = Vtc/Ccap 0.00
~$"""* ~
INPUT: 1 if Applies Displacement Fluid Calc
2325 Psp psig Pdf = MWdf * 0.052 * Hdf
MWdf ppg (emw) EMW of Displacement Fluid
387 Vdf bbls Volume of Displacement Fluid
4756 Hdf feet (tvd) Hdf = Ldf/MDshoe*Dshoe % TL I% of Total Length
5102 Ldf feet (md) Ldf = Vdf/Ccap 1.00
I
ii INPUT: 1 if Applies Freeze Protection
0 Pfz psig Pfz = MWfz * 0.052 * Hfz
CWfz ppg (emw) EMW of Freeze Portection Fluid
Vfz bbls Volume of Freeze Protection
0 Hfz feet (h/d) Hfz=Lfz/MDshoe*Dshoe % TL I% of Total Length
0 Lfz feet (tvd) Hfz -- Vfz/Ccap 0.00
I
i Pbump psig Pressure when bump plug
3097 Pe psig Pe = Pdf + Ph20 +Psp +PIc +Ptc
4756 Dshoe feet (h/d) Depth of Casing Shoe
5102 MDshoe feet (md) Measured Depth of Casing Shoe
Big ID inches Last Casing ID or Surface Hole Size whichever is the case.
285 VOLann bbls Annular Capacity (annular between casing and last casing ID)
0.0558 ANNcap bpf Annular Capacity (annular between casing and last casing ID)
INPUT: I if Applies Drilling Fluid Calculations . 5102 Check MD 0
0 Pmud psig Pmud = MW * 0.052 * Hmud 4756 CheckTVD 0
::.;~::::::~::~:~.:.~:~
MVI/ ppg (emw) Density of Drilling Fluid 285 Check Volume., 0
0 Vmud bbls Volume of Drilling Fluid 1.0 Check % Total 0
0 Hmud feet (h/d) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length
0 Lmud feet (md) Lmud = Vmud/ANNcap 0.00
I
INPUT: I if Applies Water Ahead Calculations
0 Ph20 psig PIc = CWh20 * 0.052 * Hh20
CWh2o ppg (emw) Equivalent MW of Water Ahead
Vh20 bbls Volume of Water Ahead
0 Hh20 feet (h/d) Hl~LIc/MDshoe*Dshoe % TL I% of Total Length
0 LIc feet (h/d) LIc = VIc/ANNCap 0.00
I
INPUT: 1 if Applies Spacer Calculations
0 Psp psig Psp = CWsp * 0.052 * Hsp
CWsp ppg (emw) Equivalent MW of Lead Cement
Vsp bbls Volume of Lead Cement
0 Hsp feet (h/d) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length
0 Lsp feet (md) Lsp = Vsp/ANNcap 0.00
I
INPUT: I if Applies Lead Cement Calculations
2561 P/c psig PIc = CWIc * 0,052 * HIc
CW/c ppg (emw) Equivalent MW of Lead Cement
!il Vic bbls Volume of Cement I Pumped 384
4104 /-/Jc feet (h/d) Hl~LIc/MDshoe*Dshoe % TL % of Total Length
4403 LIc feet (tvd) LIc = VIc/ANNcap 0.86
~iii!~ INPUT: I if Applies Tail Cement Calculations
535 Ptc psig PIc = CWIc * 0.052 * HIc
CWtc ppg (emw) Equivalent MW of Tail Cement
~ Vtc bbls Volume of Cement I Pumped 51
652 Htc feet (h/d) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length
699 Ltc feet (h/d) Htc = Vtc/Ccap 0.14
Page B3 - Surface Burst Calculations
ICseS,-e I Weieht I Grade I Co.n I Bur. I = I C""(b""l , DSho. I VOSho.
9.625 I 4O I Leo I En'RC I 575O I S.835 I 0.0766 I 5102 I 4756
3C. Pb for Testing Casing
Values ISymbol lUnit IDescription & Explanation
3396 I Pbtestcsg pslg Pbtestcsg = Pi - Pe
5523I R pstg
~~1 Ptest psig
~ MWorBW ppg(emw)
4756 I Oshoe feet (tvd)
I 2127 I Pe psig
Pi = Ptest + MW (or Brine Weight) * 0.052 * Dshoe
Pressure for Test
Pmasure 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
~ TOC
TOF1
~v
TOF2
TOF3
feet (tvd)
ppg (EMW)
feet (tvd)
ppg (EMW)
feet (tvd)
ppg (EMW)
feet (tvd)
ppg (EMW)
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
'I'VD 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 sudace 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 expose(
via and uncemetned section.
b) If inclinat~on 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 porvialon 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 mL
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
9,625 40 L80 I BT"C ! 5750 I 6'835 I 0'0768 I 5102 I 4756 I
3D. Pb Well Control for Influx at the Casing Shoe
I V.,ues ISYmUo lUnit IDeecriptio. & Explanation I
1088 I Pbx@shoe
1 .27 I
3215 I Pfs
LOT
Dshoe
Dxtop
psig Pbx@shoe = Pi - Pe
psig Pe = pp * 0.052 * Dint
ppg (emw) Pore Pressure on external casing.
psig
ppg (emw)
PPg
feet (tvd)
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}]^1/2 - S/2
where: S = Dr * MW * 0.052 + Px -Pf
I Values ISymbol IUnit IDecription & Explanation
2797 IPxtop psig
-792 Is psig
499737 iK constant
Dr feet (tvd)
~'-~;
........................................... il PPg
I:.~i~~ Vx bbls
I218 JPx psig
gg psi/ft
0.0436
0.0459
8.5
5
4997
hgas feet (tvd)
Cbha bpf
Cdp bpf
Dx inches
Ddp
B~P psig
design factor
4627 I DPP - psig
11,5 DPP(emw) ppg
COV factor
[ 3866 j Mean PP psig
F_MWr ppg
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/ff 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 = Mean pp * (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
ICs~Size I Weight I Grade
9.625 ~ 40 LB0
co.. I
Burst I "~ I Ccap(bPf) l "°sh°~ I ~vo sho~ I
m~c I s750 I 8'835 1°.°758 I s102 I 4756
I
3E. Pb Well Control for Influx et the Surface
Values 1Symbol
2667 I Pbx@surf
14.7 I Pe
IUnit IDescription & Explanation
psig Pbx@surf = Pi - Pe
psig Pe = Atmospheric Pressure
2681
3215 ~ Pfs psig
I 102~5 I. LOT ppg (emw)TM ppg
4756 I Oshoe feet (tvd)
20 I Oint 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 Values ISymbo~ lUn"IDecription & Explanation
I 2679 IPsurf psig
i-816 Is psig
I 499737 IK constant
I 7745 IDr feet (tvd)
9.9 IMW ppg
1100 IVx bbls
194 Px
gg
psig
psi/ft
hgas feet (tvd)
C bbls/ft
Dx inches
Ddp
B~P psig
design factor
DPP psig
DPP(emw) ppg
0.12 I COY factor
3866 I MeanPP psig
9.6 I 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/ff 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 = Mean pp * (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
3.0 CASING DESIGN WORKBOOK (BURST)
Casing
~ZE
WEK~HT
GRADE
CONNECTION
BURST (100% Design Rating)
3A. Pb Displace Cement
Calculated Design Factor
3B. Pb Bump Cement Plug
Calculated Design Factor
3C. 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
i Csg SizeI WeightI Grade
7.000 29 L80
Prod
7.000
29
8160
471
17.33
1631
5.00
4095
1.99
3F. Pb DST (HC to Surface) 5042
CalcUlated Design Factor 1.62
I if Applies, Else O:
3A. Pb Tubing Leak (DST or Prod) I 0 I
Calculated Design Factor ........ J N/A I
1 if Applies, Else 0: ~4 OK ~
OK I
I if Applie
°1
8160 ~
~
Co~n I Burst J ID I Ccap(bpf) I MDShoe J TVD Shoe
~c I 8~60 I 6.~84 I 0.0371I 9489 I so60
BHA Cdc OD LENGTHinflux BPF BBJ.S
BHA .... ,, ~ .......... ! ~:~:~;1 0.0131 3.5
DRILL P~PE 4182 0.0231 96.5
Influx 4452
Hole Diameter
Page B1 - Production Burst Calculations
_csg s=e I Weight I Grade I Corm I Burst I ID I Ccap(bpf) I MD Shoe I TVD Shoe
7.000 I 2g I ,80 I I 8160 I 6.184 10.0371 I g18gr I 8O60
Pb Displace Cement Calculation~ I
I Values ISymbol IUnit IDecription & Explanation
471 ~Pb disp ' psig Pb disp = Pi - Pb (Burst Pressure applied while cementing}
4570 P/ psig Pi = Psp + Ptc + PIc + Pdf 9189 Check MD 0
8060 Dshoe feet (tvd) Depth of Casing Shoe 8060 CheckTVD 0
9189 MDshoe feet (md) Measured Depth of Casing Shoe 341 CheckVolume~ 0
341 VOLcsg bbls Volume of the Casing 1.0 Check%Total 0
~ INPUT: I if Applies Spacer Calulations
945 Psp psig Psp = CWsp * 0.052 * Hsp
~~t CWsp ppg (emw) Equivalent MW of Spacer
~ Vsp bbls Volume of Spacer
1653 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL ~% of Total Length
1884 Lsp feet (md) Lsp = Vsp/Ccap 0.21
I
~~ INPUT: I if Applies Lead Cement Calculations
0 P/c psig PIc = CWlc * 0.052 * HIc
:~:,:~.~i CWIc ppg (emw) Equivalent MW of Lead Cement
:~~ 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 = Vlc/Ccap 0.00
~:~,:~:~,.~,~,i;~!~:.~~ INPUT: I if Applies Tail Cement Calculations
873 Ptc psig PIc = CWlc * 0.052 * HIc
::~:~.:~ "~"~'~:~'""~;~.~ CWtc ppg (emw) Equivalent MW of Tail Cement
Vtc bbls Volume of Cement I Pumpadl 45
1062 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length
1211 Ltc feet (tvd) Htc = Vtc/Ccap 0,13
~~,INPUT: I if Applies Heavier of Drilling Fluid or Displacement Fluid
2751 Pdf psig Pdf = CWdf * 0,052 * Hdf
i~9~ MWdf ppg (emw) Equivalent MW of Drlg or Disp Fluid
226 Vdf bbls Volume of Drlg or Disp Fluid
5345 Hdffeet(tvd) Hdf=LdflMDshoe*Dshoe [ % TL I% of Total Length
6093 Ldf feet (b/d) Hdf = Vdf/Ccap 0.66
4099 Pe psig Pe = Pmud + Psp + PIc + Pdf
8060 Dshoe feet (tvd) Depth of Casing Shoe
9189 MDshoe feet (md) Measured Depth of Casing Shoe
~~,~ BiglD inches Last Casing ID or Surface Hole Size whichever is the case.
.... -~ ~:~.~ :~ .~... ~ .~,~.~.~'
259 VOLann bbls Annular Capacity (annular between casing and last casing ID)
0.0282 ANNcap bpf Annular Capacity (annular between casing and last casing ID)
~... ,.,::::~, ..~. ~-.~
:~~~ INPUT: I if Applies Drilling Fluid Calculations 9189 Check MD 0
3829 Pmud psig Pmud = MW * 0.052 * Hmud 8060 CheckTVD 0
MW ppg (emw) Density of Drilling Fluid 259 CheckVolum~ 0
239 Vmud bbls Volume of Drilling Fluid 1.0 Check % Total 0
7439 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length
8480 Lmud feet (md) Lmud = Vmud/ANNcap 0.92
I
:~. ...... ~
~. ,~,~:~,~:~ INPUT: I if Applies Water Ahead Calculations
270 Ph20 psig PIc = CWh20 * 0.052 * Hh20
~~j/j~: CWh2o ppg (emw) Equivalent MW of Water Ahead
i!.~i~21~.i!:.~ Vh20 bbls Volume of Water Ahead
621 Hh20 feet (tvd) Hl~LIc/MDshoe*Dshoe % TL I% of Total Length
709 LIc feet (tvd) LIc = VlcJANNcap 0.08
I
:. ~i~;~D!~i~, INPUT: 1 if Applies Spacer Calculations
0 Psp psig Psp = CWsp * 0.052 * Hsp
i::~3.~;~;ii:::ii!~ CWsp ppg (emw) Equivalent MW of Spacer
,
;:i!~i~:i~!!~i!i~!~i; 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
r.
~:i!i:.~!0~ INPUT: I if Applies Lead Cement Calculations
0 P/c psig PIc = CWIc * 0,052 * HIc
.
~i!?ii~i~i~i;i CWlc ppg (emw) Equivalent MW of Lead Cement
i~!~!~, VIc bbls Volume of Cement I Pumped 0
0 HIc feet (tvd) Hl~LIc/MDshoe*Dshoe % TL % of Total Length
0 LIc feet (tvd) LIc = VIc/ANNcap 0.00
Page B2 - Production Burst Calculations
Cs9Size J Weight I Grade
7.000 ~ 29 L80
13B. Pb Bump Plug Calculations
8160 I §'184 I 0'0371 I 9189 I 6080 I
V.~ues IS~m~o~ lUn" IDecription &Explanation I
1631 IPb bump psig Pb bump = Pi - Pe (Pressure Applied when Bumping Plug)
6286 P/ psig Pi = Ptc + Pdf + Pfz + Pbump 9190 Check MD -1
8060 Dshoe feet (tvd) Depth of Casing Shoe 8060 Check'rVO 0
9189 MDshoe feet (md) Measured Depth of Casing Shoe 697 CheckVolurne~ 0
697 VOLcsg bbls Volume of the Casing 1.0 Check % Total 0
~~ INPUT: I if Applies Tail Cement Calculations
3 0 Ptc psig PIc = CWIc * 0.052 * HIc
CWtc ppg (emw) Equivalent MW of Tail Cement
~~i Vtc bbls Volume of Cement I Pumped, 44.8
36 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length
41 Ltc feet (tvd) Htc = Vtc/Ccap 0.00
~ INPUT: I if Applies Displacement Fluid Calc
4256 Psp psig Pdf = MWdf * 0.052 * Hdf
MWdf ppg (emw) EMW of Displacement Fluid
694 Vdf bbls Volume o Displacement Fluid
,
8024 Hdf feet (tvd) Hdf= Ldf/MDshoe*Dshoe % TL I% of Total Length
9148 Ldf feet (md) Ldf = Vdf/Ccap 1.00
I
INPUT: I if Applies Freeze Protection
0 Pfz psig Pfz = MWfz * 0.052 * Hfz
CWfz ppg (emw) EMW of Freeze Portection Fluid
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
Pbump psig Pressure when bump plug
4655 Pe psig Pe -- Pdf + Ph20 +Psp +PIc +Ptc
8060 Dshoe feet (tvd) 'Depth of Casing Shoe
9189 MDshoe feet (md) Measured Depth of Casing Shoe
8.835 BiglD inches Last Casing ID or Surface Hole Size whichever is the case.
259 VOLann bbls Annular Capacity (annular between casing and last casing ID)
0.0282 ANNcap bpf Annular Capacity (annular between casing and last casing ID)
INPUT: I if Applies Drilling Fluid Calculations 9189 Check MD 0
2080 Proud psig Proud = MW * 0.052 * Hmud 8060 CheckTVD 0
MW (emw) Density of Drilling Fluid 259 CheckVolurne~ 0
............. '~?~?r" ...........
130 Vmud bbls Volume of Drilling Fluid 1.0 Check % Total 0
4041 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length
4606 Lmud feet (md) Lmud = Vmud/ANNcap 0.50
I
i INPUT: I if Applies Water Ahead Calculations
270 Ph20 psig PIc = CWh20 * 0.052 * Hh20
CWh2o ppg (emw) Equivalent MW of Water Ahead
Vh20 bbls Volume of Water Ahead
621 Hh20 feet (tvd) Hl~LIc/MDshoe*Dshoe % TL I% of Total Length
709 LIc feet (tvd) LIc = VIc/ANNcap 0.08
I
INPUT: I if Applies Spacer Calculations
1301 Psp psig Psp = CWsp * 0.052 * Hsp
:i CWsp ppg (emw) Equivalent MW of Lead Cement
Vsp bbls Volume of Spacer
2175 Hsp feet (b/d) Hsp=Lsp/MDshoe*Dshoe % TL ~% of Total Length
2480 LSp feet (md) Lsp = Vsp/ANNcap 0,27
I
INPUT: I if Applies Lead Cement Calculations
0 P/c psig PIc = CWIc * 0.052 * HI~
~ii CW/c ppg (emw) Equivalent MW of Lead Cement
i Vic bbls Volume of Cement I Pumped 0
0 H/c feet (b/d) Hl~LIc/MDshoe*Dshoe % TL % of Total Length
0 LIc feet (b/d) LIc = VIc/ANNcap 0,00
INPUT: I if Applies Tail Cement Calculations
1 005 Ptc psig PIc = CWIc * 0.052 * HIc
CWtc ppg (emw) Equivalent MW of Tail Cement
Vtc bbls Volume of Cement I
Pumped
44.8
1223 Htc feet (tvd) Htc=Ltc/MDshoe*Dshoe %TL % of Total Length
'1394 Ltc feet (b/d) Htc = Vtc/Ccap 0.15
Page B3 - Production Burst Calculations
3C. Pb for Testing Casing
Values ISymbol IUnit IDescription & Explanation
4095 I Pbtestcsg psig Pbtestcsg = Pi - Pe
P/ psig
Ptest psig
!~~! MW or BW ppg(emw)
8060 I Dshoe feet (Nd)
3680 I Pe psig
TOC
PPfm
TOF1
TOF2
TOF3
E~/IW
feet (tvd)
ppg (EMW)
feet (tvd)
ppg (EMW)
feet (tvd)
ppg (EMW)
feet (tvd)
ppg (EMW)
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 exp~
via an uncemetned section.
b) If inclination less than 30 degrees AND the time since casing installation at
potential exposure to the burst loading is less thent 6 months Pe can be taken a~
mud weight to the top of cement with zero surface pressure. This porvision whh
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 extemal 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
set'de 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
7.000 I 29 I L80 I ~rm I 8160 I 6-184 I °-°371 I 9189 I 8060 I
3D. Pb Well Control for Influx at the Casing Shoe
I Val.ea Is~.~o~ lunit IDescription & Explanation
2347 I Pbx@shoe psig Pbx@shoe = Pi - Pe
Pe psig Pe= pp * 0.052 * Dint
pp ppg (emw) Pore Pressure on external casing.
6496I 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 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)/Cbha}]^ll2 - S/2
where: S = Dr * MW * 0.052 + Px -Pf
Values ISymbol IUnr~ IDecription & Explanation
3651 IPxtop psig
-590 IS psig
I.......~ 0~!..~.~.~v,..J K constant
Dr feet (tvd)
MW ppg
:~'::~'~:~ Vx bbls
433 JPx psig
! gg psi/ft
0.0225
0.0~231
hgas feet (tvd)
Cbha bpf
Cdp bpf
Dx inches
Ddp
EH~ psig
design factor
DPP psig
DPP(emw) ppg
COV factor
~ 3987 ~ MeanPP psig
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 bbis)
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 = Mean pp * (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 - Production Burst Calculations
I csgS=e I WeightI GradeI C, orln
I Burst
17.0001 29 I ,80 I ~c I 616° I
13E. Pb Well Control for Influx at the Surface
Values ISymbol IUnit IDescription & Explanation
3644 I Pbx@surf
~4.? I "~
6496 I Pfs
15 LOT
0.5 TM
8060 Dshoe
20 Dint
psig
psig
psig
PPg
PPg
feet
feet
(emw)
(tvd)
(tvd)
Pbx@surf = Pi - Pe
Pe = Atmospheric Pressure
"~ I coap(bpf) J MO Sho~ I TVO Sho~ !
6.18410.0371I 9189 I 80601
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
Values JSymbol JUnit JDecription & Explanation
3651 IPsurf psig
-590 IS psig
501038 IK constant
7745 IOr feet (b/d)
9.9 IMW ppg
lOO IVx bbls
Px psig
gg psi/ft
4334
0.0231
6
3.5
5010
1.05
4772
11.8
0.12
hgas feet (tvd)
C bbls/ft
Dx. inches
Ddp
EFF' psig
design factor
DPP psig
DPP(emw) ppg
COY factor
3987 J MeanPP psig
9.9 .J F___MWr 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/ff 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 = Mean pp * (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
I cs; S,-e I
Weight I Grade I Corm I Burst I = I Ccap(bpf) l aD Shoe I WP Shoe I
I 7.000 I 2g I LB0 I E~C I 8160 I 6.184 10.037~ I 9169 I 8060 I
13F. PbDST (HC to Surface)
Values
5042
5O42
4236
iill
8060
5010
'Symbol IUnit IDescripti°n & Explanation
PbDST psig
P/ psig
Psurf psig
gg psi/ft
Dshoe feet(tvd)
B-J= psig
Dr. feet(tvd)
PbDST = Pi at Surface
Pi = Psurf + gg * Dshoe
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
Depth of the Production Casing Shoe
Bottom Hole Pressure as calculated previous in spreadsheet.
Depth of formation being tested
13G. PbTBGLK Tubing Lead Near Surface During DST or ProdUction
5010
PbTBGLK psig
Pi psig
C~ ppg
Dpkr feet(tvd)
Psurf psig
gg psi/ft
B-P psig
Dr feet (tvd)
Description & 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/ff 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
4.0 CASING DESIGN PROGRAM (COLLAPSE)
Casing Surf
SIZE 9.625
.WEIGHT 4 0
GRADE L80
CONNECTION BTRC
Collapse (100% Design Rating) 3 09 0
4A. LC While Drilling Ahead 6 2 4
I Calculated Design Factor 4.95 OK I1 if Applies, Else 0: ~
4B. Cementing Tail Cmt to Surf 1 845
Calculated Design Factor 1.67 OK I1 if Applies, Else 0: ~
4C. Permafrost FZ Back 1 3 77
Calculated Design Factor 2.24 OK I1 if Applies, Else 0: ~
4D. Total Evacuation of Csg 1 849
Calculated Design Factor 1.67 OK I1 if Applies, Else 0: ~
BP Minimum Design Factor 1.1
Csg SizeI WeightI Grade
9.625 40 L80
Conn Collapse
BTRC . 3090
ID ICcap(bpf) l MDShoe
8.835 0.0758 5102
I TVD Shoe
4756
4A. Total Lost Circulation While Drilling
Values I Symbol l Unit I Decription & Explanation
6 2 4 PCIc psig
~ FDbc ppg (emw)
1 276 Dtof feet (md)
~ D/cz feet (tvd)
5724 Heqmw feet (tvd)
~ MW ppg (emw)
3036 P/cz psig
PPIcz ppg (emw)
PClc=MWbc*0.052*Dtof (Collapse Press-Lost Circ While Drlg)
Density of Fluid behind casing (Most Likely MW ahead of Cement)
Dtof=Dlcz-Heqmw
Depth of Lost Circulation Zone
Heqmw=PIcz/(MW*0.052) Height of Equiv Balanced MW column
Mud Weight of Drilling Fluid
Plcz=PPIcz*0.052*Dlcz
Pore Pressure of Lost Circulation Zone
4B. Cementing (Assumes Tail Cement ChannelS to Surface Bump Plug w! Fresh Water)
J Values JSymbol JUnit IDecription & Explanation
1 84 5 PCshoe psig
3908 Pe psig
~ CWtc ppg (emw)
4756 Dshoe feet (tvd)
2063 Pi psig
MWdf ppg (emw)
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
Page Cl -- Surface Casing Collapse
4.0 CASING DESIGN PROGRAM (COLLAPSE)
Casing Surf
SIZE 9.625
WEIGHT 4 0.
GRADE L80
CONNECTION BTRC
Collapse (100% Design Rating) 3 090
4A. LC While Drilling Ahead 62 4
.I Calculated Design Factor 4.95 OK I1 if Applies, Else 0:
4B. Cementing Tail Cmt to Surf 1 845
Calculated Design Factor 1.67 OK I1 if Applies, Else 0: ~
4C. Permafrost FZ Back 1 377
Calculated Design Factor 2.24 OK I1 if Applies, Else 0: ~
4D. Total Evacuation of Csg 1 849
Calculated Design Factor 1.67 OK I1 if Applies, Else 0: ~
BP Minimum Design Factor 1.1
9.625 40 L80 BTRC 3090 8.835 0.0758 5102
I TVD Shoe
4756
4C.
Well Suspended - Permafrost Freeze Back
Values ISymbol IUnit
1377 PCpermfz psig
2074 Pe psig
Dpermfz feet
1282 Pfz<800' psig
792 Pfz>800' psig
697 Pi psig
~~'"~'~" ....... ':'~":'~ MWfzprot ppg
(tvd)
(emw)
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
Mud Weight of Freeze Protecton Fluid (Worst Case is diesel)
4D.
Total Evacution While Running Casing
I Values I Symbo~ l Unit I Decription & Explanation
1 849 PCevac psig
2325 Pe psig
4756 Dshoe feet (tvd)
~ MW ppg (EMW)
475.6 Pi psig
~ GRADgas psi/ft
Pe=MW * 0.052 * Dshoe Depth of Casing Shoe
MW in hole while running casing
Pi=Gas Gradient * Dshoe
Page C2 -- Surface Casing Collapse
4.0 CASING DESIGN PROGRAM (COLLAPSE)
Casing Prod
SIZE 7.000
WEIGHT 2 9
GRADE L80
CONNECTION BTRC
Collapse (100% Design Rating) 7020
4A. LC While Drilling Ahead 0
Calculated Design Factor N/A OK I1 if Applies, Else 0: ~
4B. Cementing Tail Cmt to Surf 3127
Calculated Design Factor _. 2.25 OK I1 if Applies, Else 0: ~
4C. DST Perforations Plug 0
Calculated Design Factor NIA OK I1 if Applies, Else 0: ~
4D. Total Evacuation of Csg 0
Calculated Design Factor N/A OK I1 if Applies, Else 0: ~
BP Minimum Design Factor 1.1
I CsgSize17.000 Weight129
Grade Conn
L80
BTRC
7020 6.184 0.0371
MD Shoe TVDShoe
9189 8060
4A.
Total Lost Circulation While Drilling
Values I Symbol lUnit IDecripti°n & Explanation
1 3 0 3 PClc psig
--- ~::,-~:~'-~;~ ~.:~.:.~
FDbc ppg (emw)
2667 Dtof feet (md)
Dlcz feet (tvd)
5333 Heqmw feet (tvd)
MW ppg (emw)
3578 Plcz psig
PP/cz 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=Dlcz-Heqmw
Depth of Lost Circulation Zone
Heqmw=Plcz/(MW*0.052) Height of Equiv Balanced MW column
Mud Weight of Drilling Fluid
Plcz=PPIcz*0.052*Dlcz
Pore Pressure of Lost Circulation Zone
4B.
Cementing (Assumes Tail Cement Channels to Surface Bump Plug w/Fresh Water)
Values I Symbol lUnit IDecripti°n & Explanation
31 2 7 PCshoe psig
6622 Pe psig
CWtc ppg (emw)
8060 Dshoe feet (tYd)
3495 Pi psig
MWdf ppg (emw)
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
Page Cl - Production Casing Collapse
4.0 CASING DESIGN PROGRAM (COLLAPSE)
Casing Prod
~ 7.000
:WEIGHT 2 9
~ GRADE L80
CONNECTION BTRC
Collapse (100% Design Rating) 7 02 0
4A. LC While Drilling Ahead 0
Calculated Design Factor N/A OK I1 if Applies, Else 0: ~
4B. Cementing Tail Cmt to Surf 31 27
Calculated Design Factor 2.25 OK I1 if Applies, Else 0: ~
4C. DST Perforations Plug 0
Calculated Design Factor N/A OK I1 if Applies, Else 0: ~
4D. Total Evacuation of Csg 0
Calculated Design Factor N/A OK I1 if Applies, Else 0: ~
BP Minimum Design Factor 1.1
7.000 29 L80 BTRC 7020 . 6.184 0.0371 I 9189
4C.
Values ISymbol lUnit
444 3 PCdst psig
5221 Pe psig
Mw ppg (EMW)
~Bi.:3'~:i!!:. Dbperf feet (tvd)
778 Pi psig
i:~.[~1~:~;~! (:~ ppg (emw)
PERFORATIONS plug off during DST (Full Gas Column inside tubing and casing below packer).
I Decription & Explanation
PCdst=Pe-Pi
Pe=MW*0.052*Dbperf
MW used to Balance Formation
Depth of the Bottom Perforations
Pi=GG*0.052*Dbperf
Gas Gradient
I TVD Shoe
8O6O
4D.
Values ISymbol [Unit
3 46 9 PCevac psig
4275 Pe psig
8060 Dshoe feet (tvd)
· ~.~;'~2ii~;~,i~MW ppg (EMW)
8 0 6 Pi psig
l~}~i~{ii~iiii~!i~! GRADgas psi/ft
Total Evacution While Running Casing
JDecription & Explanation
Pe=MW * 0.052 * Dshoe Depth of Casing Shoe
MW in hole while running casing
Pi=Gas Gradient * Dshoe
Page C2 - Production Casing Collapse
5.0 CASING DESIGN PROGRAM (TENSILE)
Casing Surface
SIZE 9.625
WEIGHT 4 0
GRADE L80
CONNEC'rlON BTRC
Tensile (100% of Rated) 916 M LB.
SA. R(1) = Fwt-Fbuoy+Fbend 311.453 M LB.
Calculated Design Factor 2.94 OK
BP Minimum Design Factor 1.6
5B. Ft(2) = Fwt-Fbuoy+Fbend+Fshock 413.392 M LB.
Calculated Design Factor 2.22 OK I
BP Minimum Design Factor 1.4
5C. R(3) --- Fwt-Fbuoy+Fbend+Fop 342.833 M LB.
Calculated Design Factor 1.4 OK I
BP Minimum Design Factor 1.4
5D. Ft(4) = Fwt-Fbuoy+Fbend+Fplug+Fshock 311.453 M LB.
Calculated Design Factor 2.94 OK I
BP Minimum Design Factor 1.4
5E. Ft(5) = Fwt-Fbuoy+Fbend+Fplug+Fshock 536.004 M LB.
Calculated Design Factor ._ 1.71 OK I
BP Minimum Design Factor 1.4
9.625 40 L80 ~ 916 8.835 0.0758 5102
Speed
TVD Shoe
4756
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)
5A. Tensile Forces While Running Casing (Ft(1) = Fwt - Fbuoy + Fbend)
Values ISymbol IUnit IDecription & Explanation
311.453 Ft(1) IM lbs. force Ft(1) = Fwt - Fbuoy + Fbend
90.240 IFwt M lbs. force
40 W ppf
4756 Dtvd feet (tvd)
2325 Pe psig
72.76 Ao sq.in.
2325 P/ psig
61.31 Ai sq.in.
147.840 Fbend M lbs. force
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 = co4*DLS*OD*CSGppf
Page 1T- Surface Casing Tensile
9.625 40 L80
Conn I Tensile I ID
BTRC 916 8.835
ICcap(bpf) I MDShoe
0.0758 5102
I TVD Shoe
4756
5B. Tensile Forces While Running Casing Ft(2) -- Fwt - Fbuoy + Fbend + Fshock
Values ISymbol Iunit IDecription & Explanation
Ft(2) = Fwt- Fbuoy + Fbend + Fshock
Fwt, Fbuoy, and Fbend (Same values Calculated Above Apply)
101.939 ~Fshock M lbs. 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 - IDA2)
5C. Maximum Overpull While Running Casing Ft(3) = Fwt - Fbuoy + Fbend + Fop
Values ISymbol
342.833 Ft(3)
654.286 TENcorr
311.453 Et(l)
Unit I Decription & Explanation
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)
SD. Tensile Force While Displacing Cement Ft(4) = Fwt - Fbuoy + Fbend + Fplug + Fshock
I Values ISymbol Iunit IDecription & Explanation
I
491.061 Ft(4) IM lbs. force Ft(4) = Fwt - Fbuoy + Fbend + Fplug + Fshock
379.776 Fwt M lbs. force
169.147 Fbuoy M lbs. force
147.840 Fbend M lbs. force
30.653 Fplug M lbs. force
Psurf psig
31 62 Pmax psig
101.939 Fshock M lbs. force
Fwt = Fwt * Csg Ai * Hydrostatic Pressure (Mud + Cement + Spacer)
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)
5E. Tensile Force Exerted Bumping Cement Plug Ft(5) -- Fwt - Fbuoy + Fbend + Fplug + Fshock
Values ISymbol
536.004 Ft(5)
IUnit IDecripti°n & Explanation
M lbs. force Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock
332.760
169.147
147.840
122.612
3929
101.939
Fwt M lbs. force
Fbuoy M lbs. force
Fbend M lbs. force
Fplug M lbs. force
Psurf psig
Pmax psig
Fshock M lbs. force
Fwt = Fwt * Csg Ai * Hydrostatic Pressure (Displacement Fluid)
Fbuoy = Csg Ao * Hydrostatic Column of Mud, Spacer, and Cement in
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)
Page 2T- Surface Casing Tensile
9,625 40 L80 BTF~ 916 8.835 0.0758 5102 4756
5E.1 Tensile Force Exerted Bumping Cement Plug Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock
2325 Phydann psig Pe = Pdf + Ph20 +Psp +PIc +Ptc
4756 Dshoe feet (tvd) Depth of Casing Shoe
51 02 MDshoe feet (md) Measured Depth of Casing Shoe
12.25 Big ID inches Last Casing ID or Surface Hole Size whichever is the case.
2 85 VOLann bbls Annular Capacity (annular between casing and last casing ID)
0.0558 ANNcap bpf Annular Capacity (annular between casing and last casing ID)
i~ INPUT: I if Applies Drilling Fluid Calculations 51 0 2 Check MD 0
2 325 Pmud psig Pmud = MW * 0.052 * Hmud 4 75 6 Check TVD 0
~i MW ppg (emw) Density of Drilling Fluid 2 8 5 Check Volurr 0
285 Vmud bbls Volume of Drilling Fluid 1.0 Check % To1 0
4756 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length
5102 Lmud feet (md) Lmud = Vmud/ANNcap 1.00
I
INPUT: 1 if Applies Water Ahead Calculations
0 Ph20 psig PIc = CWh20 * 0.052 * Hh20
~ CWh2o ppg (emw) Equivalent MW of Water Ahead
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
INPUT: 1 if Applies Spacer Calculations
0 Psp psig Psp = CWsp * 0.052 * Hsp
~:~;~ CWsp ppg (emw) Equivalent MW of Spacer
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
INPUT: 1 if Applies Lead Cement Calculations
0 P/c psig PIc = CWlc * 0.052 * HIc
CW/c ppg (emw) Equivalent MW of Lead Cement
,
, Vic bbls Volume of Cement I
Pumped l
3
8
4
0 HIc feet (tvd) HIc=LIc/MDshoe*Dshoe % TL % of Total Length
4382 LIc feet (tvd) LIc = VIc/ANNcap 0.00
INPUT: 1 if APplies Tail Cement Calculations
0 Ptc psig PIc = CWIc * 0.052 * HIc
CWtc ppg (emw) Equivalent MW of Tail Cement
40,1 Vtc bbls Volume of Cement I Pumped 51
0 I--Itc feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length
720 Ltc feet (tvd) Htc = Vtc/Ccap 0.00
Page 3T- Surface Casing Tensile
5.0 CASING DESIGN PROGRAM (TENSILE)
Casing Prod
SIZE 7
WEIGHT 2 9
C..d=Lad:)E L80
CONNECTION BTRC
Tensile (100% of Rated) 676 M LB.
5A. R(1) = Fwt-Fbuoy+Fbend 276.633 M LB.
Calculated Design Factor 2.44 OK I
BP Minimum Design Factor 1.6
5B. Ft(2) = Fwt-Fbuoy+Fbend+Fshock 351.833 M LB.
Calculated Design Factor 1.92 OK I
BP Minimum Design Factor 1.4
5C. Ft(3) = Fwt-Fbuoy+Fbend+Fop 206.224 M LB.
Calculated Design Factor 1.4 OK I
BP Minimum Design Factor 1.4
5D. Ft(4) = Fwt-Fbuoy+Fbend+Fplug+Fshock 276.633 M LB.
Calculated Design Factor 2.44 OK
BP Minimum Design Factor 1.4
5E. Ft(5) -- Fwt-Fbuoy+Fbend+Fplug+Fshock 433.323 M LB.
Calculated Design Factor 1.56 OK
BP Minimum Design Factor 1.4
7.000 29 L80 BTRC 676 6.184 0.0371 9189
I TVD Shoe
8060
tuvv
| Speed
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)
5A. Tensile Forces While Running Casing (Ft(1) = Fwt - Fbuoy + Fbend)
Values ISymbol
Unit I Decription & Explanation
276.633 Ft(1) IM lbs. force Ft(1) = Fwt - Fbuoy + Fbend
233.740 IFwt M lbs. force
29 W ppf
8060 Dtvd feet (tvd)
4149 Pe psig
38.48 Ao sq.in.
4149 P/ psig
30.04 Ai sq.in.
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
Page 1T- Production Casing Tensile ~,~
7.000 29 L80 B]3:~ 676 6.184 0.0371 9189
I TVD Shoe
8060
58. Tensile Forces While Running Casing R(2) = Fwt - Fbuoy + Fbend + Fshock
Values ISymbol IUnit IDecription & Explanation
351.833 ~Ft(2) = Fwt - Fbuoy + Fbend + Fshock
l~ Fwt, Fbuoy, and Fbend (Same values Calculated Above Apply)
75.200 Fshock M lbs. force Fshock = 1780 * v * As
5 v ft/sec v = 5 ft/sec as per BP Casing Design Manual
8.45 As sq.in. As = 0.7854 * (OD^2 - ID^2)
5C. Maximum Overpull While Running Casing Ft(3) = Fwt - Fbuoy + Fbend + Fop
Values ISymbol
206.224 Ft )
482.857 TENcorr
276.633 Ft(1)
Unit IDecripti°n & Explanation
M lbs. force Fop = (Tensile Rating/l.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 ISymbol
379.481 Ft(4)
IUnit I Decription & Explanation
M lbs. force Ft(4) = Fwt - Fbuoy + Fbend + FI)lug + Fshock
370.995 Fwt M lbs. force
159.684 Fbuoy M lbs. force
77.952 Fbend M lbs. force
15.018 Fplug M lbs. force
Psurf psig
3942 Pmax psig
75.200 Fshock M lbs. force
Fwt = Fwt * Csg Ai * Hydrostatic Pressure (Mud + Cement + Spacer)
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/l.4)-(Fwt-Fbuoy+Fbend+Fshock))/Ai
Fshock (Same Value as Calculated above Applies)
5E. Tensile Force Exerted Bumping Cement Plug Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock
Values ISymbol
433.323 Ft(5)
nit I Decription & Explanation
lbs. force Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock
358.365 Fwt M lbs. force
183.317 Fbuoy M lbs. force
77.952 Fbend M lbs. force
105.123 Fplug M lbs. force
Fwt = Fwt * Csg Ai * Hydrostatic Pressure (Displacement Fluid)
Fbuoy = Csg Ao * Hydrostatic Column of Mud, Spacer, and Cement in Ann
Hydrostatic Pressure (Mud+Cement+Spacer-- Calc Below 5E.1)
Fbend -- Same Value Calculated Above Applies
Fplug = Psurf * Ai
Psurf psig
5149 Pmax psig
75.200 Fshock M lbs. force
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)
Page 2T -- Production Casing Tensile
7.000 29 L80 B'TRC 676 6.184
Ccap(bpf)I MDShoe I TVD Shoe
0.0371 9189 8060
5E.1 Tensile Force Exerted Bumping Cement Plug Ft(5) = Fwt - Fbuoy + Fbend + Fplug + Fshock
4 763 Phydann psig Pe = Pdf + Ph20 +Psp +PIc +Ptc
8 060 Dshoe feet (tvd) Depth of Casing Shoe
91 89 MDshoe feet (md) Measured Depth of Casing Shoe
~~~ Big ID inches Last Casing ID or Surface Hole Size whichever is the case.
2 0 8 VOLann bbls Annular Capacity (annular between casing and last casing ID)
0.0226 ANNcap bpf Annular Capacity (annular between casing and last casing ID)
~ INPUT: 1 if Applies Drilling Fluid Calculations 91 89 Check MD 0
1 601 Pmud psig Pmud = MW * 0.052 * Hmud 8060 CheckTVD 0
~ ~ ppg (emw) Density of Drilling Fluid 208 Check Volur~ 0
7 8 Vrnud bbls Volume of Drilling Fluid 1.0 Check % To1 0
3018 Hmud feet (tvd) Hmud=Lmud/MDshoe*Dshoe % TL I% of Total Length
3441 Lmud feet (md) Lmud = Vmud/ANNcap 0.37
I
~ INPUT: 1 if Applies Water Ahead Calculations
337 Ph20 psig PIc = CWh20 * 0.052 * Hh20
~ CWh2o ppg (emw) Equivalent MW of Water Ahead
~~ Vh20 bbls Volume of Water Ahead
777 Hh20 feet (tvd) HIc=LIc/MDshoe*Dshoe % TL I% of Total Length
886 LIc feet (tvd) LIc = VIc/ANNcap 0.10
I
~ INPUT: I if Applies Spacer Calculations
1 555 Psp psig Psp = CWsp * 0.052 * Hsp
~ CWsp ppg (emw) Equivalent MW of Spacer
~~ Vsp bbls Volume of Spacer
2718 Hsp feet (tvd) Hsp=Lsp/MDshoe*Dshoe % TL I% of Total Length
3099 Lsp feet (md) Lsp = Vsp/ANNcap 0.34
I
~~ INPUT: I if Applies Lead Cement Calculations
0 P/c psig PIc = CWIc * 0.052 * HIc
~~~~~ CWlc ppg (emw) Equivalent MW of Lead Cement
~~, 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
~=INPUT: I if Applies Tail Cement Calculations
1 271 Ptc psig PIc = CWIc * 0.052 * HIc
~~ CWtc ppg (emw) Equivalent MW of Tail Cement
39.8 Vtc bbls Volume of Cement I Pumped 45
1547 Htc .feet (tvd) Htc=Ltc/MDshoe*Dshoe % TL % of Total Length
1763 Ltc feet (tvd) Htc = Vtc/Ccap 0.19
Page 3T-- Production Casing Tensile
WELL PERMIT CHECKLIST
FIELD & POOL
WE LLNAME /df/".d' /~///A ~5/~' ~ :i~'LPROGRAM: exp []
dev~ redrll [] serv [] wellbore seg []
/
ON/OFF SHORE ~
ADMINISTRATION
1. Permit fee attached ...................
2. Lease number appropriate ................
3. Unique well name and n~mber ...............
4. Well located in a defined pool .............
5. Well located proper distance from drlg unit boundary..
6. Well located proper distance from other wells .....
7. Sufficient acreage available in drilling unit .....
8. If deviated, is wellbore plat included ........
9. Operator only affected party ..............
10. Operator has appropriate bond in force .........
Il. Permit can be issued without conservation order ....
12. Permit can be issued without administrative approval..
13. Can permit be approved before 15-day wait .......
ENGINEERING
14. Conductor string provided ............... ..~ N
15. Surface casing protects all known USDWs ....... '-'~1 N
16. CMT vol adequate to circulate on conductor & surf csg. N
17. CMT vol adequate to tie-in long string to surf csg . . . Y
18. CMT will cover all known productive horizons ...... ~Y~ N
19. Casing designs adequate for C, T, B & permafrost .... ~,p N
20. Adequate tankage or reserve pit ............. N
21. If a re-drill, has a 10-403 for abndnmnt been approved. '~.~
22. Adequate wellbore separation proposed .......... (Y~ N
23. If diverter required, is it adequate .......... ~Y% N
24. Drilling fluid program schematic & equip list adequate ~_yjZ-, N
25. BOPEs adequate ..................... ~ N
26. BOPE press rating adequate; test to ~-d3d30 psig. Y N
27. Choke manifold complies w/API RP-53 (May 84) ...... ~ N
28. Work will occur without operation shutdown .......
29. Is presence of H2S gas probable ............. Y
REMARKS
GEOLOGY
30. Permit can be issued w/o hydrogen sulfide measures .... Y
31. Data presented on potential overpressure zones .....
32. Seismic analysis of shallow gas zones .......... Y/N /~ ~/t
33. Seabed condition survey (if off-shore) ......... /~ N
34. Contact name/phone for weekly progress reports .... / Y N
[exploratory only]
GEOLOGY:
RPC.,~
ENGINEERING: COMMISSION:
JDH ~ JDN
