Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
Loading...
HomeMy WebLinkAbout196-048XHVZE
Pages NOT Scanned in this Well HistOry File
This page identifies those items that were not scanned during the initial scanning project.
They are available in the original file and viewable by direct inspection.
I Cf~ K[) L~ (:~ File Number of Well History File
PAGES TO DELETE
Complete'
RESCAN
Color items - Pages:
Grayscale, halftones, pictures, graphs, charts-
Pages: ~/~ ~
Poor Quality Original- Pages'
[] Other- Pages:
DIGITAL DATA
[] Diskettes, No.
[] Other, No/Type
OVERSIZED
Logs of various kinds
Other
COMMENTS:
Scanned' by:
Beverly ~ Vincent Nathan Lowell
Date:
TO RE-SCAN
Notes'
Re-Scanned by' Bevedy Dianna Vincent Nathan Lowell Date: Is~
THE MATERIAL UNDER THIS COVER HAS BEEN
MICROFILMED
ON OR BEFORE
0
JANUARY 3 2001.:
Pt.
Memorandum
State of Alaska
Oil and Gas Conservation Commission
Re:
Cancelled or Expired Permit Action
EXAMPLE' Point McIntyre P2-36AXX API# 029-22801-95
This memo will remain at the front of the subject well file.
Our adopted conventions for assigning APl numbers, permit numbers and well names did not
specifically address expired or cancelled permits. This omission has caused some inconsistencies i:
the treatment of these kinds of applications for permit to ddll. Operators have asked us to adopt
formal procedures for this class of permit application in order to prevent future database disparities.
if a permit expires or is cancelled by an operator, the permit number of the subject permit will remair.
unchanged. The APl number and in some instances the well name reflect the number of preexistin!
reddlls and or multilaterats in a well. In order to prevent confusing a cancelled or expired permit with
an active well or multilateral these case sensitive well identifiers will be changed for expired and
cancelled applications for permits to ddll.
The AP! number for this cancelled or expired permit is modified so the eleven and twelfth digits is 9[
The well name for a cancelled or expired permit is modified with an appended xx.
These procedures are an addendum to the APl numbering methods descnbed in AOGCC staff
memorandum "Multi-lateral (wetibore segment) Ddiling Permit Procedures, revised December 29,
1995.
AOGCC database has been changed to reflect these changes to this permit.
Statistical Technician
ALASKA OIL AND GAS
CONSERVATION COMMISSION
TONY KNOWLE$, GOVERNOR
3001 PORCUPINE DRIVE
ANCHORAGE, ALASKA 99501-3192
PHONE: (907) 279-1433
FAX: (907) 276-7542
March 13, 1996
Tim Schofield, Sr. Drlg. Eng.
BP Exploration (Alaska), Inc.
P O Box 196612
Anchorage, AK 99519-6612
Re:
Milne Point Unit M1)K- 10
BP Exploration (Alaska), Inc.
Permit No: 96-48
Sur. Loc. 3745'NSL, 2020'WEL, Sec. 03, T12N, R11E, UM
Btmhole Loc.3046'NSL, 1175'WEL, Sec. 33, T13N, R11E, UM
Dear Mr. Schofield:
Enclosed is the approved application for permit to drill the above referenced well.
The permit to drill does not exempt you from obtaining additional permits required by law
from other governmental agencies, and does not authorize conducting drilling operations
until all other required permitting determinations are made. A request for an amendment
to Area Injection Order No. 10 must be received and approved before injection into the
subject well.
The blowout prevention equipment (BOPE) must be tested in accordance with
20 AAC 25.035; and the mechanical integrity (MI) of the injection wells must be
demonstrated under 20 AAC 25.412 and 20 25.030(g)(3). Sufficient notice
(approximately 24 hours) of the MI test before operation, and of the BOPE test performed
before drilling below the surface casing shoe, must be given so that a representative of the
Commission may witness the tests. Notice may be given by contacting the Commission
petroleum field inspector on the North Slope pager at 659-3607.
Sincerely~__~
J. David Norton, P.E.
Commissioner
BY ORDER OF THE COMMISSION
dlf/EnClosures
CC;
Department of Fish & Game, Habitat Section w/o encl.
Department of Environmental Conservation w/o encl.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
2O AAC 25.005
la. Type of work Drill [] Redrill [311b. Type of well. Exploratory[] Stratigraphic Test [] Development Oil []
Re-Entry [] DeepenI--11 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 -- 61 feet Mi/no Point Unit/Kuparuk River
3. Address 6. Property Designation
P. O. Box 196612. Anchoraqe, Alaska 9~519-6612 ADL 028232
4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025)
3745' NSL, 2020' WEL, SEC. 3, T12N, R11E Mi/ne Point Unit
At top of productive interval 8. Well number Number
2830' NSL, 1239' WEL, SEC. 33, T13N, R11E MPK-IO 2S100302630-277
At total depth 9. Approximate spud date Amount
3046' NSL, 1175' WEL, SEC. 33, T13N, R11E 04/25/96 $200,000.00
12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property15. Proposed depth (MD and TVD)
property line
ADL375133 3046 feet MPK-18,61'@2149'TVD feet 2560 9459'MD/7446'TVDfeet
16. To be completed for deviated wells 17. Anticipated pressure (see 2o ^AC 25.035 (e)(2))
Kickoff depth 2o7~ feet Maximum hole angle 5o o Maximum surface 3005 psig At total depth (TVD) 7~j29,/3758 psig
18. Casing program Setting Depth
s~ze Specifications Top Bottom Quantity of cement
Hole Casing Weight Grade Coupling Length M D 'l-VD M D TVD (include stage data)
30" 20" 91.1# NT8OLHE Weld 80' 32' 32' 112' 112' 250 sx Arctic, set I (Approx.)
12-1/4" 9-5/8" 40# L-80 Btrc 4240' 31' 31' 4271' 3955' 836 sx PF 'E', 250 sx 'G', 250 sx PF 'E'
8-1/2" 7" 26# L-80 Mod B 9429' 30' 30' 9459' 7446' 284 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 FEB 2 9 1996
Liner
Perforation depth: measured ,;~i'::;~[.'.,2,,. O!i & O~Is Con,'-;. C,.-'~mr~ii~sior:
true vertical Ar~chora~'~
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 requirements[]
21.1 hereby~ce~i'f¥ that t__he f~regoing jsltrue, and correct to the best of my knowledge 2.__zq/&///~
Signed ' 7u~ ~'C~ Title Senior. DriliingEn~ineer Date '
15/~.p0/I Commission Uie Onlr.~v,/~l
Permit Number number App dat~ ISee cover letter
~:>~"'- ~'~:~ - C:~ <~'-- -.~.-2._ ~' .~-~ /~/?~ Ifor other requirements
Conditions of approval Samples required [] Yes [] No Mud log required []Yes J~ No
Hydrogen sulfide measures [] Yes ~ No Directional survey requirecl [] Yes [] No
Required working pressure ,(~~[~SB~~3M; ~)SM; []1OM; []15M;
Other: J. David Nortoll, P.E. by order of _/ /
Approved by Commissioner tne cOmmission Date..~/.3
Form 10-401 Rev. 12-1-85
Submit in t'"r{plicate
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
la. Type of work Drill [] Redrill rqllb. Type of well. Exploratoryl-I Stratigraphic Test [] Development Oil []
Re-Entry [] DeepenFII 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 = 61 feet Milne Point Unit / Kuparuk River
3. Address 6. Property Designation
P. O. Box 196612, Anchorage, Alaska 99519-6612 ADL 028232
4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20 AAC 25.025)
3745' NSL, 2020' WEL, SEC. 3, T12N, R11E Milne Point Unit
At top of productive interval 8. Well number Number
2830' NSL, 1239' WEL, SEC. 33, T13N, R11E MPK-IO 2S100302630-277
At total depth 9. Approximate spud date Amount
3046' NSL, 1175' WEL, SEC. 33, T13N, R 11E 04/25/96 $200,000. O0
12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property15. Proposed depth(uDandTVD)
property line
ADL375133 3046 feet MPK-18,61'@2149'TVD feet 2560 9459'MD/7446'TVDfeet
16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2))
Kickoff depth 2oz~ feet Maximum hole angle 5o o Maximum surface 3005 psig At total depth (TVD) 7529'/3758 psig
18. Casing program Setting Depth
s~ze Specifications Top Bottom Quantity of cement
Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data)
30" 20" 91.1# NTSOLHE Weld 80' 32' 32' 112' 112' 250 sx Arcticset I (Approx.)
12-1/4" 9-5/8" 40# L-80 Btrc 4240' 31' 31' 4271' 3955' 836 sx PF 'E', 250 sx 'G: 250 sx PF 'E'
8-1/2" 7" 26# L-80 Mod B 9429' 30' 30' 9459' 7446' 284 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 FEB 29 1996
Liner
,,-: r-,-.,-..-, r ',i.-:.,~ior~
Perforation depth: measured A'!a¢;;~
true vertical
20. Attachments Filing fee [] Property plat [] BOP Sketch [] Diverter Sketch [] Drilling program I-RI
Drilling fluid program [] Time vs depth plot [] Refraction analysis [] Seabed report[] 20 AAC 25.050 requirements[]
21.1 hereby ce~f:y,,./, that th__e/ ~/: ~,f ~f~reg°ing Js~true and correct to the best of my knowledge
Signed ' /~¢'n C~" Title Senior,Drill/nDEn[tineer Date/ -- ·
//
Commission Use Only
Permit Number I,~PI number APDrgval ,date See cover letter
.~'.- ~z'~:~ 150.~.2_..~'_ ~ ~. ~ ,~ ~¢" 3~1~/~(¢ for other requirements
Conditions of approval Samples required [] Yes · [] No Mud Icg required []Yes :1~ No
Hydrogen sulfide measures [] Yes [] No Directional survey required [] Yes [] No
Required working pressure fo~Sl(~l~i~3M; 1~5M; I--IIOM; []15M;
Other: J. David Norton, P.E. by order of--~/~-/,.~L~
Approved by Commissioner zne commission Date
Form 10-401 Rev. 12-1-85
Submit in tr licate
Bottom Hole 3046' FSL 1175' FEL Sec 33 T13N R11E UM., AK.
Location:
Note: Target & BHL footages are based on assumed true and square sections and are not
surveyed legal locations.
]AFE Number: ] 337014
Estimated Start Date: IApril 25, 1996
Rig: [ Nabors 27E
IOperating days to drill
and case:
113 ]
IMD: 19459' I I TVD: 17446' BKB I
I Well Design (conventional, slimhole, I Ultra Slimhole, 7" Longstring
I
etc.):
I
Formation Markers:
IKBE: 161'1
Formation Tops MD TVD Formation Pressure/EMW
Base permafrost 1811 1811 n/a
NA (Top Schrader) 5213 4561 1905 psig / 8.0 ppg
OA 1955 psig / 8.0 ppg
Base Schrader Bluff 5695 4871 1995 psig / 8.0 ppg
Top HRZ 8236 6504 n/a
Base HRZ n/a
Kupark D Shale 8780 6894 n/a
Kupamk C 9065 7124 3650 psig / 10 ppg
TKB 3669 psig / 10 ppg
Total Depth 9459 7446 n/a
Casing/Tubing Pro ,ram.
r
Hole Csg/ Wt/Ft Grade Conn Length Top Btm
Size Tbg MD/TVD MD/TVD
O.D.
30" 20" 91.1# NT80LHE weld 80 32' 112/112
12 1/4" 9 5/8" 40# L-80 btrc 4240' 31' 4271/3955
8 1/2" 7" 26g L-80 Mod B 9429' 30' 9459/7446
N/A (tbg) 3-1/2" 6.5# L-80 EUE 8786' 29' 8815/6921
8rd
Internal yield pressure of the 7" 26g casing is 7240 psi. Worst case surface pressure would occur with a full
column of gas to the reservoir at 7529' TVDSS. Maximum anticipated surface pressure in this case assuming a
reservoir pressure of 3758 psi is 3005 psi, well below the internal yield pressure rating of the 7" casing. The
Modified Buttress 7" 26# will be run on bottom.
Logging Program:
I Open Hole Logs:
Surface
Schrader Bluff
Final
I Mud Logs:
MWD ONLY
LWD CDR/CDN to TD
Mud logs and samples are not required
/
/
AP1 # 50-029-22XXX February 29, 1996
Target Location: 2830' FSL 1239' FEL Sec 33 T13N Ri 1E UM., AK.
Bottom Hole 3046' FSL 1175' FEL Sec 33 T13N R11E UM., AK.
Location:
Note: Target & BHL footages are based on assumed true and square sections and are not
surveyed legal locations.
I AFE Number: 1337014 I [Rig: I Nabors 27E I
IEstimated Start Date:lApril 25, 1996 I
IOperating days to drill
and case:
113 I
IuD: 19459' I ITVD: 17446'BKB I IKBE: 16~'1
Well Design (conventional, slimhole, I UltraSlimhole, 7" Longstring
etc.):
I
Formation Markers:
Formation Tops MD TVD Formation Pressure/EMW
Base permafrost 1811 1811 n/a
NA (Top Schrader) 5213 4561 1905 psig / 8.0 ppg
OA 1955 psig / 8.0 ppg
Base Schrader Bluff 5695 4871 1995 psig / 8.0 ppg
Top HRZ 8236 6504 n/a
Base HRZ n/a
Kupark D Shale 8780 6894 n/a
Kuparuk C 9065 7124 3650 psig / 10 ppg
TKB 3669 psig / 10 ppg
Total Depth 9459 7446 n/a
Casing/Tubing Program:
Hole Csg/ -Wt/Ft Grade Conn Length Top Btm
Size Tbg MD/TVD MD/TVD
O.D.
30" 20" 91.1# NT80LHE weld 80 32' 112/112
12 1/4" 9 5/8" 40# L-80 btrc 4240' 3 1' 4271/3955
8 1/2" 7" 26# L-80 Mod B 9429' 30' 9459/7446
N/A (tbg) 3-1/2" 6.5# L-80 EUE 8786' 29' 8815/6921
8rd
Internal yield pressure of the 7" 26# casing is 7240 psi. Worst case surface pressure would occur with a full
column of gas to the reservoir at 7529' TVDSS. Maximum anticipated surface pressure in this case assuming a
reservoir pressure of 3758 psi is 3005 psi, well below the internal yield pressure rating of the 7" casing. The
Modified Buttress 7" 26# will be run on bottom.
Logging Program:
I Open Hole Logs:
Surface
Schrader Bluff
Final
I Mud Logs:
MWD ONLY
LWD CDR/CDN to TD
Mud logs and samples are not required
AP1 # 50-029-22XXX February 29, 1996
present to keep mucl temperatures to a rmmmum. I
Surface Mud Properties: I Spud Mud
Density Marsh Yield 10 sec 10 min pH Fluid
(PPG) Viscosity Point gel gel Loss
8.6 80 15 8 10 9 8
to to to to to to to
10.5 100 35 15 30 10 15
Production Mud Properties: ]LSND
Density Marsh Yield 10 sec 10 min pH Fluid
(PPG) Viscosity Point gel gel Loss
9.0 40 15 3 7 8.5 6-10
to to to to to to to
10.5 50 20 10 20 9.5 4 - 6
Well Control:
Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed
and is capable of handling maximum potential surface pressures.
Diverter, BOPE and drilling fluid system schematics on file with AOGCC.
Directional:
I KOP: 12071'
Maximum Hole Angle:
Maximum Dog Leg:
Inclination in target:
Close Approach Well:
50 degrees
_< 4 degrees
35 Degrees
MPK 18 Well Plan is 61 feet @ 2149 feet TVD
This wellplan will allow MPK-IOi wellpath to be drilled as per BP's close approach
guidelines. The well path should be followed as close as possible to ensure we do not
compromise the proximity tolerances.
Disposal:
Cuttings Handling: Cuttings should be hauled to the ball mill at CC-2A. The Milne Point reserve
pit can be opened in emergencies by notifying Karen Thomas (564-4305) with request.
Fluid Handling: All drilling and completion fluids can be annular injected after allowing the
cement on the 7" casing cement job to cure 6 hours following CIP.
API # 50-029-22XXX February 29, 1996
II..,,UilLIUI IIUW lc[Lbo tU UulU~ bud bi iV1 Wilt,,11 ll~Ul~tb,J
present to keep mud temperatures to a minimum.
Surface Mud Properties: I SpudMud
Density Marsh Yield 10 sec 10 min pH Fluid
(PPG) Viscosity Point gel gel Loss
8.6 80 15 8 10 9 8
to to to to to to to
10.5 100 35 15 30 10 15
Production Mud Properties: I LSND
Density Marsh Yield 10 sec 10 min pH Fluid
(PPG) Viscosity Point gel gel Loss
9.0 40 15 3 7 8.5 6-10
to to to to to to to
10.5 50 20 10 20 9.5 4 - 6
Well Control:
Well control equipment consisting of 5000 psi W.P. pipe rams, blind rams, and annular preventer will be installed
and is capable of handling maximum potential surface pressures.
Diverter, BOPE and drilling fluid system schematics on file with AOGCC.
Directional-.
I KOP: 1 07 , I
Maximum Hole Angle:
50 degrees
Maximum Dog Leg: < 4 degrees
Inclination in target: 35 Degrees
Close Approach Well: MPK 18 Well Plan is 61 feet @ 2149 feet TVD
This wellplan will allow MPK-IOi wellpath to be drilled as per BP's close approach
guidelines. The well path should be followed as close as possible to ensure we do not
compromise the proximity tolerances.
Disposal:
Cuttings Handling: Cuttings should be hauled to the ball mill at CC-2A.
pit can be opened in emergencies by notifying Karen Thomas (564-4305)
The Milne Point reserve
with request.
Fluid Handling: All drilling and completion fluids can be annular injected after allowing the
cement on the 7" casing cement job to cure 6 hours following CIP.
AP1 # 50-029-22XXX February 29, 1996
formation at 2500 - 3300' TVD. The confining layer is the Sagavanirktok Shale defined by logs between ~215"o -fo
2500 'TVD. Additional data which demonstrates the confining layers, porosity, and permeability of the
injection zone was submitted to the AOGCC on 7-24-95.
4. There are no wells on Milne Point K Pad. There may be additional unidentified wells within a
quarter mile distance from the subject well. There are no domestic or industrial water use wells located
within one mile of the project area.
5. The drilling wastes to be disposed of during this operations can be defined as drilling mud, cement
contaminated drilling mud, and drill cuttings; rig wash fluid (inclusive of rig boiler blow down, and mud
and cement rinse water of associated rig equipment, completion fluids (seawater and brine), formation
fluids, reserve pit fluids, and drill rig domestic waste water. (Note: if you plan to dispose of fluids
OTHER than those outlined above you must list them on the request) The maximum volume to be disposed
of in the annulus is 35,000 bbls. Fluid densities will range from 8.3 to 13.0 ppg. Any deviation from
this program must be detailed separately.
6. The 9.625 "surface casing shoe will set at 4271'md 3955 ('tvd) and cemented with 836 "E" and
250 "G" sacks cement. This depth is below the base of the permafrost (1750' TVD) and into the top of the
Prince Creek formation which has a long established history of annular pumping at Milne Point. The
break down pressure of the Prince Creek formation is 13 to13.5 ppg equivalent mud weight.
7. The burst rating (80%) for the 9.625" 40# 'surface casing is4600 psi. The collapse rating
(80%) for the7" 26# 'intermediate/production casing is 4325 psi.
8. The Maximum Allowable Surface Pressure while annular pumping is the lesser of 2000 psi or
the calculated pressure according to the following equation:
MASP (psi) = (Max Breakdown ppg-8.3 ppg) X 0.052 X Surf Csg Shoe TVD
MASP (psi) = 1069 psi
9. The maximum pressure imposed at the surface casing shoe is calculated according to the following
equation:
Max Press @ Surf Csg Shoe (psi) = .052 x Max Breakdown ppg x Surf Csg Shoe TVD
Max Prss at Surf Csg Shoe =2776 psi
This pressure is less than the 80% burst and collapse casing pressures calculated in #7
·
1 0. Additional data supplied as needed.
FEB 2 9 1996
DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS.
AREA WELL PREV VOL PERMITTED PERMITTED DAT~or~
INJECTED (BBL) VOL (aBE)
Milne Point M P K- 1 7 0 35,000 Requested
Milne Point M PK-25 0 35,000 Requested
Milne Point M P K- 3 8 0 3 5,0 0 0 Requested
Milne Point M P K- 1 8 0 3 5,0 0 0 Requested
Milne Point M P K- 1 0i 0 35,000 Requested
Milne Point M P K- 3 7 i 0 3 5,0 0 0 Requested
FREEZE PROTECTION:
Pay close attention to annulii being used for disposal so to avoid freezing. Sometimes the annulii are kept open by
ensuring that an adequate volume (+60 bbls) is injected every 6-12 hours. This practice is more economical than
pumping 60 bbls of diesel freeze protection every time the pumps are shut down; however, if this practice is used,
it is important that the injection frequency into the annulus be adequate to prevent freeze ups -- the drillers
must communicate to each other the last time the annunlus was injected into to avoid freezing.
AP1 # 50-029-22XXX February 29, 1996
,,4. I I1~ ~JUr~lVlll~] Z:Oll~ I.O Wlll(.;ll I. I1~ ~IUlu~ Will ~ly~c~l.~ I~ lU~lll, lll~u c~ I.~1~ . iIi1~.,~ L,d,.,~,lt y,.,ulU~Jlt,~l
formation at 2500 - 3300' TVD. The confining layer is the Sagavanirktok Shale defined by logs between
2500 'TVD. Additional data which demonstrates the confining layers, porosity, and permeability of the
injection zone was submitted to the AOGCC on 7-24-95.
4. There are no wells on Milne Point K Pad. There may be additional unidentified wells within a
quarter mile distance from the subject well. There are no domestic or industrial water use wells located
within one mile of the project area.
5. The drilling wastes to be disposed of during this operations can be defined as drilling mud, cement
contaminated drilling mud, and drill cuttings; rig wash fluid (inclusive of rig boiler blow down, and mud
and cement rinse water of associated rig equipment, completion fluids (seawater and brine), formation
fluids, reserve pit fluids, and drill rig domestic waste water. (Note: if you plan to dispose of fluids
OTHER than those outlined above you must list them on the request) The maximum volume to be disposed
of in the annulus is 35,000 bbls. Fluid densities will range from 8.3 to 13.0 ppg. Any deviation from
this program must be detailed separately.
6. The 9.625" surface casing shoe will set at 4271'md 3955 ('tvd) and cemented with 836 "E" and
250 "G" sacks cement. This depth is below the base of the permafrost (1750' TVD) and into the top of the
Prince Creek formation which has a long established history of annular pumping at Milne Point. The
break down pressure of the Prince Creek formation is 13 to13.5 ppg equivalent mud weight.
7. The burst rating (80%) for the 9.625" 40# 'surface casing is4600 psi. The collapse rating
(80%) for the7" 26# 'intermediate/production casing is 4325 psi.
8. The Maximum Allowable Surface Pressure while annular pumping is the lesser of 2000 psi or
the calculated pressure according to the following equation:
MASP (psi) - (Max Breakdown ppg-8.3 ppg) X 0.052 X Surf Csg Shoe TVD
MASP (psi) = 1069 psi
9. The maximum pressure imposed at the surface casing shoe is calculated according to the following
equation:
Max Press @ Surf Csg Shoe (psi) = .052 x Max Breakdown ppg x Surf Csg Shoe TVD
Max Prss at Surf Csg Shoe =2776 psi
This pressure is less than the 80% burst and collapse casing pressures calculated in #7.
1 0. Additional data supplied as needed.
DO NOT EXCEED 35,000 BBLS IN ANY ANNULUS.
AREA WELL PREVVOL PERMITTED PERMITTED DATES
INJECTED (BBL) VOL (BBL)
Milne Point M P K- 17 0 35,000 Requested
Milne Point M P K-25 0 35,000 Requested
Milne Point M PK-38 0 35,000 Requested
Milne Point M P K- 18 0 35,000 Requested
Milne Point M P K- 10 i 0 35,000 Requested
Milne Point M PK-37i 0 35,000 Requested
FREEZE PROTECTION:
Pay close attention to annulii being used for disposal so to avoid freezing. Sometimes the annulii are kept open by
ensuring that an adequate volume (+60 bbls) is injected every 6-12 hours. This practice is more economical than
pumping 60 bbls of diesel freeze protection every time the pumps are shut down; however, if this practice is used,
it is important that the injection frequency into the annulus be adequate to prevent freeze ups -- the drillers
must communicate to each other the last time the annunlus was injected into to avoid freezing.
AP1 # 50-029-22XXX February 29, 1996
t.,Ulltlul IIUW ldtub I.U U~IuW uiytY k.J~ 1¥1 WlI~II ll3/Uldt~b dl~ I
present to keep mud temperatures to a minimum.
I
The MPU PE group will be perforating, and cleaning out wells shortly after the rig drills and completes
them. This will make the near rig area congested and as a result potentially hazardous. Ensure personnel
use caution moving around adjacent production activities.
Lost Circulation: The Kuparuk sands and a number of shallower intervals typically are highly
fractured. Be prepared to treat these losses while drilling initially with LCM treatments. This will
become even more prevalent in the production hole when we shallow set surface casing. Weighting up
before entering the reservoir will be the most likely time we would lose circulation.
Stuck Pipe Potential: There has been several cases of stuck pipe occuring at the top of the Kuparuk,
with both the intervals above and below the Schrader Bluff open. We have made improvements to the mud
system and continue to monitor for stuck pipe conditions. The stuck pipe intervals and short trip
guidelines on the Pad Data Sheet should be followed to avoid stuck pipe incidents. Fill every joint to
minimize time with stopped casing. We have stuck casing when we tried to fill 5 joint at a time.
Shallow Set Casing: The wells at K Pad will use shallow set casing which can provide cost savings if the
wells are trouble free. There are increased risk for stuck pipe, lost circulation, especially while running
casing. The casing program will include running centralizers over both the Kuparuk and Schrader Bluff,
and cemented in a single stage.
Kick Tolerance: The surface casing setting depth for this well allows a kick tolerance of 60.7 bbl
influx (Gas) based on a 12.5 ppg LOT at the 9-5/8" casing shoe and a estimated reservoir pressure of
3704 psig (9.9 ppg equivalent MW). Trip Schedules are required for all trips. All trips will be
performed with a trip tank or one pit isolated for use as a trip tank.
Formation Pressure: The maximum expected pore pressure for this well is 9.9 ppg EMW (3704
psi @ 7124' ssTVD). There has been no injection in this region since then, therefore the reservoir
pressure should not exceed this estimate. We will continue to take the conservative approach to drilling
operations and circulate the well until stable before tripping or before running casing. When any flow
occurs, the drilling superintendent should always be quickly notified and kept
appraised.
WATER USAGE
Have the water truck drivers track the water usage on a daily log. Send a copy of this log to Dennise
Casey in the Anchorage Office on a monthly basis.
API# 50-029-22XXX February 29, 1996
control flow rates to below 600 GPM when hydrates are
I
present to keep mud temperatures to a minimum.
The MPU PE group will be perforating, and cleaning out wells shortly after the rig drills and completes
them. This will make the near rig area congested and as a result potentially hazardous. Ensure personnel
use caution moving around adjacent production activities.
Lost Circulation: The Kuparuk sands and a number of shallower intervals typically are highly
fractured. Be prepared to treat these losses while drilling initially with LCM treatments. This will
become even more prevalent in the production hole when we shallow set surface casing. Weighting up
before entering the reservoir will be the most likely time we would lose circulation.
Stuck Pipe Potential: There has been several cases of stuck pipe occuring at the top of the Kuparuk,
with both the intervals above and below the Schrader Bluff open. We have made improvements to the mud
system and continue to monitor for stuck pipe conditions. The stuck pipe intervals and short trip
guidelines on the Pad Data Sheet should be followed to avoid stuck pipe incidents. Fill every joint to
minimize time with stopped casing. We have stuck casing when we tried to fill 5 joint at a time.
Shallow Set Casing: The wells at K Pad will use shallow set casing which can provide cost savings if the
wells are trouble free. There are increased risk for stuck pipe, lost circulation, especially while running
casing. The casing program will include running centralizers over both the Kuparuk and Schrader Bluff,
and cemented in a single stage.
Kick Tolerance: The surface casing setting depth for this well allows a kick tolerance of 60.7 bbl
influx (Gas) based on a 12.5 ppg LOT at the 9-5/8" casing shoe and a estimated reservoir pressure of
3704 psig (9.9 ppg equivalent MW). Trip Schedules are required for all trips. All trips will be
performed with a trip tank or one pit isolated for use as a trip tank.
Formation Pressure: The maximum expected pore pressure for this well is 9.9 ppg EMW (3704
psi @ 7124' ssTVD). There has been no injection in this region since then, therefore the reservoir
pressure should not exceed this estimate. We will continue to take the conservative approach to drilling
operations and circulate the well until stable before tripping or before running casing. When any flow
occurs, the drilling superintendent should always be quickly notified and kept
appraised.
WATER USAGE
Have the water truck drivers track the water usage on a daily Icg. Send a copy of this Icg to Dennise
Casey in the Anchorage Office on a monthly basis.
AP1 # 50-029-22XXX February 29, 1996
.
NU and function test 20" Diverter system. Ensure the diverter is as per AOGCC specifications
and is approved by AOGCC supervisor. Build Spud Mud.
.
Drill 12-1/4" surface hole to 4271' md (3955 tvd). Use extreme care when drilling through the
known hydrate interval down to _+ 3100 feet TVD. Run and cement 9-5/8" casing.
8. ND 20" Diverter, NU and Test 13_~5/8" BOP_F,. Run Wear Bushing.
.
RIH w/PDC bit and Double Power Section PDM (motor). Test the 9-5/8" casing to 3000 psig and plot
pressure vs volume for LOT baseline. Drill out float equipment and 10 feet of new formation, Perform a
LOT to a maximum of 12.5 ppg as per Recommended Practices Manual. Record pressure vs. cumulative
volume for LOT test for well file. Follow Pad Data Sheet short trip guidelines.
10.
Drill 8-1/2" hole to TD at 9459' MD (7446' TVD). (Note: This hole section will be logged with LWD
Triple Combo (GR/Res/Neu/Dens).
11.
Pull Wear Bushing, and Change Pipe Rams to 7". Run and Cement 7" casing with 1 stage cement
program. Test casing to 3500 psi and freeze protect wellbore to 2000' TVD with diesel. Closely monitor
casing running loads for drag. Make sure there is a circulating head for the topdrive before starting to run
casing.
12. ND BOPE and NU dry hole tree. Release rig.
Note: This well will be perforated, and cleaned out with a completion rig and prior to running the ESP
. completion.
13. MIRU workover completion unit. ND dry hole tree. NU BOPs and test.
14. PU and RIH with 3.5" DP and 6" bit, clean out to PBTD. TOOH.
15. PU and R/H with perforating string (procedure to be distributed later with perforation intervals).
16. PU and RIH with 3-1/2" EUE 8rd tubing with injection packer completion.
17.
18.
Set 2 way check. ND BOPE and NU tree and test. Pull two way check, freeze protect, set BPV, close
valves. Test tree.
RDMO with workover/completion rig.
FEB 2 9 19,36
POST RIG WORK
C-,~,:, Corm. C,.':mr.,'fission
Anchorage
,
Complete the handover form and turn it and the well files over to production. Turn over the
well files along with the handover form.
.
A SBT/GR/CCL is required on this well and will only be run if there are problems on the
production cement job.
.
An adequate volume to cover 2000' of diesel needs to be injected down the 7" X 9-5/8" annulus
before moving the rig off the well. Please note type and volume of freeze protection pumped
down the outer annulus on the morning report.
.
The rig will not complete this well. PEs will perforate and clean out this well with a pulling
unit.
API # 50-029-22XXX February 29, 1996
.
NU and function test 20" Diverter system. Ensure the diverter is as per AOGCC specifications
and is approved by AOGCC supervisor. Build Spud Mud.
.
Drill 12-1/4" surface hole to 4271' md (3955 tvd). Use extreme care when drilling through the
known hydrate interval down to _+ 3100 feet TVD. Run and cement 9-5/8" casing.
8. ND 20" Diverter, NU and Test 13-5/8" BOPE. Run Wear Bushing.
.
RIH w/PDC bit and Double Power Section PDM (motor). Test the %5/8" casing to 3000 psig and plot
pressure vs volume for LOT baseline. Drill out float equipment and 10 feet of new formation, Perform a
LOT to a maximum of 12.5 ppg as per Recommended Practices Manual. Record pressure vs. cumulative
volume for LOT test for well fde. Follow Pad Data Sheet short trip guidelines.
10.
Drill 8-1/2" hole to TD at 9459' MD (7446' TVD). (Note: This hole section will be logged with LWD
Triple Combo (GR/Res/Neu/Dens).
11.
Pull Wear Bushing, and Change Pipe Rams to 7". Run and Cement 7" casing with 1 stage cement
program. Test casing to 3500 psi and freeze protect wellbore to 2000' TVD with diesel. Closely monitor
casing running loads for drag. Make sure there is a circulating head for the topdrive before starting to run
casing.
12. ND BOPE and NU dry hole tree. Release rig.
Note: This well will be perforated, and cleaned out with a completion rig and prior to running the ESP
completion.
13. MIRU workover completion unit. ND dry hole tree. NU BOPs and test.
14. PU and RIH with 3.5" DP and 6" bit, clean out to PBTD. TOOH.
15. PU and RIH with perforating string (procedure to be distributed later with perforation intervals).
16. PU and RIH with 3-1/2" EUE 8rd tubing with injection packer completion.
17.
18.
Set 2 way check. ND BOPE and NU tree and test. Pull two way check, freeze protect, set BPV, close
valves. Test tree.
RDMO with workover/completion rig.
FEB 29 1996
POST
.
RIG WORK '~-~"~ Oil & '~"~'
P~ch0rag~
Complete the handover form and turn it and the well files over to production. Turn over the
well files alon9 with the handover form.
.
A SBT/GR/CCL is required on this well and will only be run if there are problems on the
production cement job.
.
An adequate volume to cover 2000' of diesel needs to be injected down the 7" X 9-5/8" annulus
before moving the rig off the well. Please note type and volume of freeze protection pumped
down the outer annulus on the morning report.
.
The rig will not complete this well. PEs will perforate and clean out this well with a pulling
unit.
AP1 # 50-029-22XXX February 29, 1996
ADDITIVES: Retarder
WEIGHT: 12.0 ppg
YIELD: 2.17 ft3/sx
MIX WATER: 11.63 gal/sk
WEIGHT: 15.8 ppg
APPROX #SACKS: 250
FLUID LOSS: 100-150 cc
APPROX #SACKS: 836 THICKENING TIME: Greater than 4 hrs at 50° F.
TAIL CEMENT TYPE: Premium G
ADDITIVES: 0.2% CFR-3, 0.2% Halad-344, 2.0% CaC12
YIELD:I.15 ft3/sx MIX WATER: 5.0 gal/sk
THICKENING TIME: Greater than 4 hrs at 50° F.
FREE WATER: 0
TOP JOB CEMENT TYPE: Type E Permafrost
ADDITIVES: Retarder
WEIGHT: 12.0 ppg YIELD: 2.17 cu ft/sk. MIX WATER: 11.63 gal/sk
APPROX NO SACKS: 250
CENTRALIZER PLACEMENT:
1. 1 Bowspring centralizer per joint of 9-5/8" casing on the bottom 10 joints above the FS.
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 bpm. Do not overdisplace by more than 1/2 the shoe joint. Mix slurry
on the fly -- batch mixing is not necessary.
Make sure to fill the casing every joint to avoid having to shut down to fill the casing.
Casing has been stuck while we were shut down filling only 5 joints.
CEMENT VOLUME:
1. The Tail Slurry volume is a standard 250 sacks is calculated to cover 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.
4. 80'md 9-5/8", 40# capacity for float joints. ~ ~, ~ ~ ..... ?~
5. Top Job Cement Volume is 250 sacks. ~ ~.~,:~,',~ ~*'~' ~'
FEB 2 9 I996
Alaska Oil & Gas Cons. Commission
Anchoraae
API # 50-029-22XXX February 29, 1996
LEAD CEMENT TYPE: Type E Permafrost
ADDITIVES: Retarder
WEIGHT: 12.0 ppg YIELD: 2.17 ft3/sx MIX WATER: 11.63 gal/sk
APPROX #SACKS: 836 THICKENING TIME: Greater than 4 hrs at 50° F.
TAIL CEMENT TYPE: Premium G
ADDITIVES: 0.2% CFR-3, 0.2% Halad-344, 2.0% CaC12
WEIGHT: 15.8 ppg
APPROX #SACKS: 250
FLUID LOSS: 100-150 cc
YIELD:I.15 ft3/sx MIX WATER: 5.0 gal/sk
THICKENING TIME: Greater than 4 hrs at 50° F.
FREE WATER: 0
TOP JOB CEMENT TYPE: Type E Permafrost
ADDITIVES: Retarder
WEIGHT: 12.0 ppg YIELD: 2.17 cu ft/sk. MIX WATER: 11.63 gal/sk
APPROX NO SACKS: 250
CENTRALIZER PLACEMENT:
1. 1 Bowspring centralizer per joint of 9-5/8" casing on the bottom 10 joints above the FS.
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 bpm. Do not overdisplace by more than 1/2 the shoe joint. Mix slurry
on the fly -- batch mixing is not necessary.
Make sure to fill the casing every joint to avoid having to shut down to fill the casing.
Casing has been stuck while we were shut down filling only 5 joints.
CEMENT VOLUME:
1. The Tail Slurry volume is a standard 250 sacks is calculated to cover 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.
4. 80'md 9-5/8", 40# capacity for float joints.
5. Top Job Cement Volume is 250 sacks.
AP1 # 50-029-22XXX February 29, 1996
70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0
ppg above current mud weight.
CEMENT TYPE: Premium G
ADDITIVES: 0.3% CFR-3, 30#/SK Silicalite, 1.7% Halad 344
WEIGHT: 12.25 ppg YIELD: 2.81 cu ft/sk
APPROX # SACKS: 284
FLUID LOSS: < 45cc/30 min @ 140° F
MIX WATER: 16 gal/sk
THICKENING TIME: 4 1/2 hrs @ 140° F
FREE WATER: 0cc @ 45 degree angle.
CENTRALIZER PLACEMENT:
1. 7" x 8-1/4" Straight Blade Rigid Centralizers-- two per joint on the bottom 17 joints of 7"
Casing (34 total). This will cover 200' above the C Sand.
2. 7" x 8-1/4"Straight Blade Rigid Centralizers-- one per joint from 6900' - 6100' to cover
the Schrader Bluffs Sands (20Total).
3. Run one 7" x 8-1/4"Straight Blade Rigid Centralizer inside the 9-5/8" casing shoe.
4. Total 7" x 8-1/4" Straight Blade Rigid Centralizers needed is 55.
OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and
ensure compatibility prior to pumping job. Ensure thickening times are adequate relative
to pumping job requirement. Displace at 8-10 bpm. Batch mixing is not necessary.
CEMENT VOLUME:
1. Stage 1 cement volume is calculated to cover 500' md above the NA Top with 30% excess.
FEB 2 9 1996
AP1 # 50-029-22XXX February 29, 1996
~.1 /"l.L, 12~.l.t. JU t/I/lo llt.,oll Wo-tt, l .
70 bbls Alpha Spacer mixed as per Halliburton specifications weighted to 1.0
ppg above current mud weight.
CEMENT TYPE: Premium G
ADDITIVES: 0.3% CFR-3, 30#/SK Silicalite, 1.7% Halad 344
WEIGHT: 12.25 ppg YIELD: 2.81 cu ft/sk
APPROX # SACKS: 284
FLUID LOSS: < 45cc/30 min @ 140° F
MIX WATER: 16 gal/sk
THICKENING TIME: 4 1/2 hrs @ 140° F
FREE WATER: 0cc @ 45 degree angle.
CENTRALIZER PLACEMENT:
1. 7" x 8-1/4" Straight Blade Rigid Centralizers-- two per joint on the bottom 17 joints of 7"
Casing (34 total). This will cover 200' above the C Sand.
2. 7" x 8-1/4"Straight Blade Rigid Centralizers-- one per joint from 6900' - 6100' to cover
the Schrader Bluffs Sands (20Total).
3. Run one 7" x 8-1/4"Straight Blade Rigid Centralizer inside the 9-5/8" casing shoe.
4. Total 7" x 8-1/4" Straight Blade Rigid Centralizers needed is 55.
OTHER CONSIDERATIONS: Perform lab tests on mixed cement/spacer/mud program and
ensure compatibility prior to pumping job. Ensure thickening times are adequate relative
to pumping job requirement. Displace at 8-10 bpm. Batch mixing is not necessary.
CEMENT VOLUME:
1. Stage 1 cement volume is calculated to cover 500' md above the NA Top with 30% excess.
AP1 # 50-029-22XXX February 29, 1996
Depth BBLS Cu. Et. Sacks Top of Cemenl
Shoe Depth ~ Calculated
G Tail Volume 623 51.2 288 250 3648
E Lead Volum6 1500 167.3 940 433 2148
E Tail Volume 2148 155.7 874 403 0
Total E 8 36
!Total G 2 50
9-5/8" Bows I 0
Production 1-Stage Cement Job
Cement Yield
Hole Size 8.5 Silicalite Slurry 2.81
Casing Size 7
BPF 0.0226
BPF + 30% 0.0294
___ ._T_ _o_p___o_f__.._C_ e_.~ e_n_'
Stage._1_ .......... ~ . BBLS Cu. Ft. Sacks Calculated
NA Top~~~ ' 142 799 284 ............ 4-~':1 '~
Seabee Top
Kuparuk Top
TD
Centralizers 32 Across the Kuparuk
Centralizers 37 Across the Schrader Bluff
Total G ST1 284
Total ST Blade; 71
FEB 29
~1~,~1.~ . ....
.~,.,~,~,~. Oil & Ga?. Cons. Commission
AnchoraCe
Page 1
BPF + 100% 0.1 116
,
,
Depth i BBLS I Cu. Et. I Sacks Top of Cemen~
i
Shoe Depth iii!i:.i:~iii!:,,~:!i ~:~.i i~i! !ii~i....i..ii I Calculated
G Tail Volume 623 i 51 2
~ . ! 288 i 250 3648
,
~ 940 ! 433 2148
E Lead Volum 1500 i 167.3
E Tail Volume 2148 i 155.7 i 874 ~ 403 0
Total E I 8 3 6
Total G 2 5 0
9-5/8" Bows I 0
·
Production 1-Stage Cement Job ! ,
i Cement i Yield
Hole Size 8.51 ISilicalite Slurry 2.81
i
Casing Size I 71
~ 26
BPF I 0.02
BPF + 30% I 0.0294
Top of Cemenl
Stage 1 IVD ! BBLS Cu. Ft. Sacks Calculated
N A Top ~iiiii~iiiii~ii~;ii!i ~i 1 42 i 799 , 284 4713
Seabee Top ~iii~ii~
Kuparuk Top ~i~ii
Centralizers I 32 Across the Kuparuk
Centralizers I 37 Across the Schrader Bluff
Total G ST1 284
I
Total ST Bladei 71!
Page 1
TFRZ
TKUD
END [DF CLRVE
K-~ / TK[JC1
8237 49.59 16.64 6504 3842 N 1148 E
8781 38.70 16.64 6894 4204 N 1E~37 E
8966 3.00 16.64 7046? 4311 N 1~ E
~6 ~.~ 16.64 7124 4~ N 1~ E
CA§ING POINT DATA
OD MD Inc An TVD N/§ E/W
9 5/8 in 4271 50.00 16.64 S~)55 931N 278 E
7 in 0459 35.00 16.64 7446 45~ N 1370 E
500I
1811
4871
5003--
5500--
G894
7124
VERTICAL VIEW
SCALE 500 Ft, / DIVISION
TVD RED WELLHEAD
VERTICAL SECTION REF: WELLHEAD
0.00 ~ 0 MD TIE IN
PRE~DSED ~
TVD 7446.00
MD 9459.01
VS 47~?_.14
N/S 45~1.81N
E/W 1369.60 E
Tom.qet Nome TVD BE; EW Cvid X Cvid Y
K-NJ 7124 4366 N 1305 E 585790 601C~60
0.00 ~ 1811 MD B~se PevmoFvosl
4871 .
16.64
$/.~.~
b. 64
/6.64
16.64
500 1000 1500 2C00 2500 3(E)O 3c..00 4000 4500 5000
0.00 @ E~71 MD KEP / ST/NRT 0L- BUILD ~ 2.50/100 Fi:
2.5O @ 2171 MD
5.00 ~ 2271 MD
7.5Q @ 2371 MD
3710.00 @ 2471 MD
le,50 ~ e571 MD
15,00 ~ 2671 MD
17.50 @ 2771 MD
20.00 @ 2871 ND
22.50 @ E:'971 MD
27.50 @ 3171 MD
2.~0 @ 3771 MD - 1664
~ 50.CE50.00 @ 4071 ND END OF BUILD - 16A.~
819
~c) 5/8 ;n OD,~ 4271 MD, 3955 TVD - 16.~'~
. /.~.s~ 0
FLo 2 9 1996
.AnchoFaqo
~ ~~~ ~T; C~e2~/i~ rt~ .
~42.~ ~ ~16 MD
4~
~ ~.~ ~4~%M~, ~446 Tvo
47~
i15OQ
1BI1
~KUU
END I]F CLRVE
K-I'~ / TKUC!
8966 3~.00 16,64 7042 4311 N 1L:~3g E
c)066 35.00 16.64 7124 4366 N 1305 E
CASINK] POINT DATA
DD MD Inc A~ TVD N/S E/~
g 5/8 in 4271 .SO.O0 16.64 3955 931N 278
7 in 9459 35.00 16.64 7446 4582 N 1370
VERTICAL VIEW
SCALE 500 Fi:. / DIVISIE]N
TVD RE]F: WELLI-EAD
VERTICAL SECTII]',I REF: WELLHEAD
PRC~ED
TVD 7446.00
MD 9459.01
VS 4782,14
N/$ 4581.81 N
E/W 1369.60 E
0,00 @ 0 MD TIE IN
ToV.Clet Nome TVD NS £W C~id X C~id Y
K-N 7124 4366 N 1305 E 58~790 601CL°60
FEB 2 9 I99.5
)il & Gas Cons. Commission
0.00 ~ 1811 MD B~se Per, mof'r'os't
4,56! .
16.64
0.00 ~ 2071 MD KEP / START EF BUILD ~ 2.,~3/100 rt
2.50 ~ 2171 MD
5.OD ~ 2271 MD
7.50 ~ 2371 MD
10.00 ~ 247t MD
12.50 8 2571 MD
15.00 ~ 2671 MD
17.50 @ 2771 MD
16.64
'"
3~00w
4871
5000--
5500--
6000--
-50O 0 5OO 1030
20.00 e 2871 MD
L~.50 @ E971 MD /n QD
7 M ) ' 16' '
X~.~ ~ ~ I D .- 16.~
~37.~71 MD ' 16.~~
~2.~ ~ 3771 MD '16.64 J
~ ~.~ ~ 4071 MD END ~'~ILD T ' 16'64 J
819 ~9 5/8 in DD, ~ 4271 MD, ~5 VD -
16.64
~.~ ~ ~14'MD ~ Sands
1694 ~
~ ~ ¢4~%MD, 7446 TVD
47~
15(]0 2000 LC]lDO 3000 3500 4000 4500
Halliburton Energy Services - Drilling Systems PSL
Proposal Report
Survey Reference: WELLHEAD
Reference World Coordinates: Lat. 70.25.34 N - Long. 149.18.40 W
Reference GRID System: Alaska State Plane Zone: Alaska 4
Reference GRID Coordinates: (fl): 6005880.00 N 584535.00 E
North Aligned To: TRUE NORTH
Vertical Section Reference: WELLHEAD
Closure Reference: WELLHEAD
TVD Reference: WELLHEAD
Calculated using the Minimum Curvature Method
Computed using WIN-CADDS REV2. I.B
Vertical Section Plane: 16.64 deg.
BPX - Shared Services Drilling
Alaska State Plane: Zone4
Milne Pt: MPK
MPK-10 Est
MPK-10 Wpl
Measured lncl Drift Subsea TVD Course
Depth Dir. Depth Length
(fl) (deg.) (deg.) (fi) (fi) (fi)
TIE IN
0.00 0.00
Base Permafrost
1811.00 0.00
KOP / START OF
2071.00 0.00
2171.00 2.50
2271.00 5.00
2371.00 7.50
TOTAL
Rectangular Offsets
(ft) (t~)
0.00 -61.00 0.00 0.00 0.00N 0.00 E
0.00 1750.00 1811.00 1811.00
BUILD62.50 deg/100 ~
0.00 2010.00 2071.00 260.00
0.00N 0.00 E
0.00N 0.00 E
16.64 2109.97 2170.97 100.00 2.09N 0.62E
16.64 2209.75 2270.75 100.00 8.36N 2.50E
16.64 2309.14 2370.14 100.00 18.79N 5.62E
2471.00 10.00 16.64 2407.97 2468.97 100.00
2571.00 12.50 16.64 2506.04 2567.04 100.00
2671.00 15.00 16.64 2603.17 2664.17 100.00
2771.00 17.50 16.64 2699.17 2760.17 100.00
2871.00 20.00 16.64 2793.85 2854.85 100.00
2971.00 22.50 16.64 2887.05 2948.05 100.00
3071.00 25.00 16.64 2978.57 3039.57 100.00
3171.00 27.50 16.64 3068.25 3129.25 100.00
3271.00 30.00 16,64 3155.92 3216.92 100.00
33.36N 9.97 E
52.05N 15.56 E
74.82N 22.37 E
101.63N 30.38 E
132.42N 39.59 E
167.15N 49.96 E
205.73N 61.50 E
248.10N 74.17 E
294.18N 87.94 E
3371.00 32.50 16.64 3241.40 3302.40 100.00 343.88N 102.80E
3471.00 35.00 16.64 3324.54 3385.54 100.00 397.11N 118.71E
3571.00 37.50 16.64 3405.18 3466.18 100.00 453.76N 135.64E
3671.00 40.00 16.64 3483.16 3544.16 100.00 513.72N 153.57 E
3771.00 42.50 16.64 3558.34 3619.34 100.00 576.89N 172.45 E
3871.00 45.00 16.64 3630.57 3691.57 100.00 643.14N 192.25 E
GRID Coordinates
Nonhing Easting
(ft) (t~)
6005880.00 584535.00
6005880.00 584535.00
6005880.00 584535.00
6005882.10 584535.60
6005888.38 584537.40
6005898.85 584540.40
6005913.47 584544.59
6005932.22 584549.97
6005955.06 584556.51
6005981.96 584564.22
6006012.85 584573.08
6006047.69 584583.06
6006086.40 584594.16
6006128.91 584606.34
6006175.14 584619.59
6006225.00 584633.88
6006278.40 584649.19
6006335.23 584665.48
6006395.39 584682.72
6006458.76 584700.88
6006525.22 584719.93
Closure Vertical
Dist. Dir. Section
(fi) (deg.) (ft)
o.oo~ o.oo o.oo
o.o(~ o.oo o.oo
o.o{~ o.oo o.oo
Build Walk DLS Cum.
Rate Rate Dogleg
(d~100a) (dg/100~t) (d~100~t) (dcg)
Expected Total
Rectangular Coords
(ft) (ft)
Max Hor Minl
Error E
(ft)
0.00 0.00 0.00 0.0 0.00N 0.00 E 0.00
0.00 0.00 0.00 0.0 0.00N 0.00 E 5.00
0.00 0.00 0.00 0.0 0.00N 0.00 E 5.63
2.18~ 16.64 2.18 2.50 0.00 2.50 2.5 2.09N 0.63 E 5.88
8.726 16.64 8.72 2.50 0.00 2.50 5.0 8.35N 2.51 E 6.14
19.616 16.64 19.61 2.50 0.00 2.50 7.5 18.77N 5.66E 6.43
34.826 16.64 34.82 2.50 0.00 2.50
54.33~ 16.64 54.33 2.50 0.00 2.50
78.09~ 16.64 78.09 2.50 0.00 2.50
106.076 16.64 106.07
138.216 16.64 138.21
174.46~ 16.64 174.46
214.73~ 16.64 214.73
258.95~ 16.64 258.95
307.05~ 16.64 307.05
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
10.0 33.33N 10.07 E
12.5 52.00N 15.73 E
15.0 74.74N 22.65 E
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
17.5 101.50N 30.82 E
20.0 132.23N 40.22 E
22.5 166.88N 50.84 E
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
25.0 205.38N 62.68 E
27.5 247.65N 75.70 E
30.0 293.60N 89.89 E
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
32.5 343.16N 105.24 E
35.0 396.22N 121.70 E
37.5 452.68N 139.25 E
358.926 16.64 358.92
414.476 16.64 414.47
473.60~ 16.64 473.60
40.0 512.44N 157.87 E
42.5 575.38N 177.52 E
45.0 641.38N 198.16 E
536.19~ 16.64 536.19
602.126 16.64 602.12
671.26~ 16.64 671.26
6.79
7.24
7.80
8.51
9.38
10.42
11.63
13.03
14.60
16.34
18.24
20.30
22.52
24.88
27.38
s~amourton e~ncrgy ~erwces - Drilling Systems PSL
Proposal Report
Survey Reference: WELLHEAD
Reference World Coordinates: Lat. 70.25.34 N - Long. 149.18.40 W
Reference GRID System: Alaska State Plane Zone: Alaska 4
Reference GRID Coordinates: (fi): 6005880.00 N 584535.00 E
North Aligned To: TRUE NORTH
Vertical Section Reference: WELLHEAD
Closure Reference: WELLHEAD
TVD Reference: WELLHEAD
Calculated using the Minimum Curvature Method
Computed using WIN-C, qDDS RE I/2. I.B
Vertical Section Plane: 16.64 deg.
BPX - Shared Services Drilling
Alaska State Plane: Zone4
Miln¢ Pt: MPK
MPK-10 Est
MPK-10 Wpl
Mcasured Incl Drifi Subsea TVD Course
Depth Dir. Depth Length
(ft) (deg.) (deg.) (t~) (t~) (t~)
TIE IN
0.00 0.00 0.00
Base Permafrost
1811.00 0.00 0.00
KOP / START OF BUILD
2071.00 0.00 0.00
2171.00 2.50 16.64
2271.00 5.00 16.64
2371.00 7.50 16.64
-61.00 0.00 0.00
1750.00 1811.00 1811.00
~ 2.50 dog/100 ~
2010.00 2071.00 260.00
TOTAL
Rectangular Offsets
(fi) (~)
0.00N 0.00 E
0.00N 0.00 E
0.00N 0.00 E
2109.97 2170.97 100.00 2.09N 0.62E
2209.75 2270.75 100.00 8.36N 2.50E
2309.14 2370.14 100.00 18.79N 5.62E
2471.00 10.00 16.64 2407.97 2468.97 100.00
2571.00 12.50 16.64 2506.04 2567.04 100.00
2671.00 15.00 16.64 2603.17 2664.17 100.00
33.36N 9.97 E
52.05N 15.56E
74.82N 22.37 E
2771.00 17.50 16.64 2699.17 2760.17 100.00 101.63N 30.38E
2871.00 20.00 16.64 2793.85 2854.85 100.00 132.42N 39.59E
2971.00 22.50 16.64 2887.05 2948.05 100.00 167.15N 49.96E
3071.00 25.00 16.64 2978.57 3039.57 100.00
3171.00 27.50 16.64 3068.25 3129.25 100.00
3271.00 30.00 16.64 3155.92 3216.92 100.00
205.73N 61.50 E
248.10N 74.17 E
294.18N 87.94 E
3371.00 32.50 16.64
3471.00 35.00 16.64
3571.00 37.50 16.64
3671.00 40.00 16.64
3771.00 42.50 16.64
3871.00 45.00 16.64
3241.40 3302.40 100.00 343.88N 102.80 E
3324.54 3385.54 100.00 397.11N 118.71E
3405.18 3466.18 100.00 453,76N 135.64E
3483.16 3544.16 100.00 513.72N 153.57 E
3558.34 3619.34 100.00 576.89N 172.45 E
3630.57 3691.57 100.00 643.14N 192.25 E
GRID Coordinates
Northing Easting
(ft) (~)
6005880.00 584535.00
6005880.00 584535.00
6005880.00 584535.00
Closure Vertical
Dist. Dir. Section
(fi) (deg.) (ft)
o.oo~ o.oo o.oo
o.oa~ o.oo o.oo
o.oa~ o.oo o.oo
Build Walk DLS Cum.
Rate Rate Dogleg
(dg/100ft) (dg/100t~) (dgtl00t~) (deg)
0.00 0.00 0.00 0.0
0.00 0.00 0.00 0.0
0.00 0.00 0.00 0.0
6005882.10 584535.60 2.18(~ 16.64 2.18 2.50 0.00 2.50
6005888.38 584537.40 8.72~ 16.64 8.72 2.50 0.00 2.50
6005898.85 584540.40 19.61@ 16.64 19.61 2.50 0.00 2.50
6005913.47 584544.59 34.82~ 16.64 34.82 2.50 0.00 2.50
6005932.22 584549.97 54.33~ 16.64 54.33 2.50 0.00 2.50
6005955.06 584556.51 78.09~ 16.64 78.09 2.50 0.00 2.50
6005981.96 584564.22 106.07~ 16.64 106.07
6006012.85 584573.08 138.21~ 16.64 138.21
6006047.69 584583.06 174.46~ 16.64 174.46
6006086.40 584594.16 214.73~ 16.64 214.73
6006128.91 584606.34 258.95~ 16.64 258.95
6006175.14 584619.59 307.05~ 16.64 307.05
6006225.00 584633.88 358.92~ 16.64 358.92
6006278.40 584649.19 414.47~ 16.64 414.47
6006335.23 584665.48 473.66~ 16.64 473.60
6006395.39 584682.72 536.19~ 16.64 536.19
6006458.76 584700.88 602.12~ 16.64 602.12
6006525.22 584719.93 671.26~ 16.64 671.26
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
2.50 0.00 2.50
Expected Tot.al Max Hor
Rectangular Coords Error
(fi) (ft) 60
0.00N 0.00 E 0.00
0.00N 0.00 E 5.00
0.00N 0.00 E 5.63
2.5 2.09N 0.63 E 5.88
5.0 8.35N 2.51 E 6.14
7.5 18.77N 5.66 E 6.43
32.5 343.16N 105.24 E 16.34
35.0 396.22N 121.70 E 18.24
37.5 452.68N 139.25 E 20.30
40.0 512.44N 157.87 E 22.52
42.5 575.38N 177.52 E 24.88
45.0 641.38N 198.16 E 27.38
25.0 205.38N 62.68 E !1.63
27.5 247.65N 75.70 E 13.03
30.0 293.60N 89.89 E 14.60
17.5 101.50N 30.82 E 8.51
20.0 132~23N 40.22 E 9.38
22.5 166.88N 50.84 E 10.42
10.0 33.33N 10.07 E 6.79
12.5 52.00N 15.73 E 7.24
15.0 74.74N 22.65 E 7.80
Measured lncl Drifi Subsea TVD Course b,qo~- T O T A L
Depth Dir. Depth Length Rectangular Offsets
(fi) (deg.) (deg.) (fi) (fi) (fi) (fi) (fi)
Halliburton Energy Services - Drilling Systems PSL
Proposal Report
GRID Coordinates Closure Vertical Build~ Walk DLS Cum. Expected Total Max Hot Min
Northing Easting Dist. Dir. Section Rate Rate Dogleg Rectangular Coords Error 1~
(fi) (fi) (It) (deg.) (fi) (dg/100fi) (dg/100fi) (dgtl00fl[) (deg) (fi:) (fl[) (fl[)
3971.00 47.50 16.64 3699.72 3760.72 100.00 712.35N 212.94E 6006594.65 584739.83 743.49(~ 16.64 743.49 2.50 0.00 2.50 47.5 710.31N 219.76E 30.02
4071.00 50.00 16.64 3765.64 3826.64 100.00 784.38N 234.47E 6006666.91 584760.54 818.67~ 16.64 818.67 2.50 0.00 2.50 50.0 782.04N 242.27E 32.79
END OF BUILD
4071.18 50.00 16.64 3765.76 3826.76 0.18 784.50N 234.51E 6006667.04 584760.57 818.80~ 16.64 818.80 2.50 0.00 2.50 50.0 782.17N 242.31E 32.79
CASING POINT OD = 9 5/8 in, ID = 8.84 in, Weight = 40.00 lb/fi.
4271.00 50.00 16.64 3894.19 3955.19 199.82 931.18N 278.35 E 6006814.19 584802.74 971.89~ 16.64 971.89 0.00 0.00 0.00 50.0 931.18N 278.35 E 0.00
NA Sands
5213.56 50.00 16.64 4500.00 4561.00 942.56 1623.01N 485.16E 6007508.27 585001.65 1693.98~ 16.64 1693.98 0.00 0.00 0.00 50.0 1617.32N 504.21 E 65.09
Base Schrader
5695.88 50.00 16.64 4810.00 4871.00 482.32 1977.04N 590.99E 6007863.45 585103.42 2063.48~ 16.64 2063.48 0.00 0.00 0.00 50.0 1969.92N 614.78E 78.87
START OF CURVE ~ 2.00 dog/100 ft
8215.70 50.00 16.64 6429.56 6490.56 2519.82 3826.59N 1143.87E 6009719.03 585635.05 3993.90(~ 16.64 3993.90 0.00 0.00 0.00 50.0 3812.07N ! 192.45 E 151.13
THRZ
8236.51 49.59 16.64 6443.00 6504.00 20.81 3841.82N 1148.43 E 6009734.32 585639.43 4009.79~ 16.64 4009.79 -2.00 -0.00 2.00 50.4 3827.24N 1197.21 E 151.72
8315.70 48.00 16.64 6495.16 6556.16 79.19 3898.90N 1165.49E 6009791.58 585655.84 4069.37~ 16.64 4069.37 -2.00 -0.00 2.00 52.0 3884.10N 1215.00E 153.92
8415.70 46.00 16.64 6563.35 6624.35 100.00 3968.97N 1186.43E 6009861.89 585675.97 4142.51~ 16.64 4142.51 -2.00 -0.00 2.00 54.0 3953.91N 1236.82E 156.60
8515.70 44.00 16.64 6634.05 6695.05 100.00 4036.72N 1206.69E 6009929.86 585695.44 4213.22~ 16.64 4213.22 -2.00 -0.00 2.00 56.0 4021.42N 1257.88E 159.18
8615.70 42.00 16.64 6707.18 6768.18 100.00 4102.07N 1226.22E 6009995.42 585714.22 4281.42~ 16.64 4281.42 -2.00 -0.00 2.00 58.0 4086.54N 1278.16E 161.66
8715.70 40.00 16.64 6782.64 6843.64 100.00 4164.93N 1245.01E 6010058.48 585732.29 4347.03~ 16.64 4347.03 -2.00 -0.00 2.00 60.0 4149.19N 1297.64E 164.02
TKUD
8780.83 38.70 16.64 6833.00 6894.00 65.13 4204.49N 1256.83E 6010098.18 585743.65 4388.33~ 16.64 4388.33 -2.00 -0.00 2.00 61.3 4188.63N 1309.89E 165.52
8815.70 38.00 16.64 6860.35 6921.35 34.87 4225.23N 1263.03E 6010118.98 585749.61 4409.96~ 16.64 4409.96 -2.00 -0.00 2.00 62.0 4209.30N 1316.31E 166.31
8915.70 36.00 16.64 6940.20 7001.20 100.00 4282.89N 1280.26E 6010176.83 585766.18 4470.15~ 16.64 4470.15 -2.00 -0.00 2.00 64.0 4266.79N 1334.12E 168.46
ENDOF CURVE
8965.92 35.00 16.64 6981.09 7042.09 50.22 4310.83N 1288.62E 6010204.87 585774.21 4499.31~ 16.64 4499.31 -2.00 -0.00 2.00 65.0 4294.65N 1342.75 E 169.51
K-NJ/TKUCI
9065.92 35.00 16.64 7063.00 7124.00 100.00 4365.79N 1305.04E 6010260.00 585790.00 4556.67~ 16.64 4556.67 0.00 -0.00 0.00 65.0 4349.44N 1359.73 E 171.61
CASING POINT OD = 7in, ID = 6.28in, Weight= 26.001b/~.
9458.76 35.00 16.64 7384.80 7445.80 392.84 4581.68N 1369.56E 6010476.60 585852.03 4782.00~ 16.64 4782.00 0.00 0.00 0.00 65.0 4581.68N 1369.56E 0.00
9459.01 35.00 16.64 7385.00 7446.00 0.24 4581.81N 1369.60E 6010476.74 585852.07 4782.14~ 16.64 4782.14 0.00 0.00 0.00 65.0 4564.82N 1426.46E 179.85
Measured lncl Drift Subsea TVD Course t~?,~- T 0 T A L
Depth Dir. Depth Length Rectangular Offsets
(fi) (deg.) (deg.) (ft) (ft) (ft) (fi) (fi)
GRID Coordinates
Northing Easting
(ft) (n)
flauiburton Energy Services - Drilling Systems PSL
Proposal Report
Closure Vertical Build. Walk DLS Cum. Expected Total Max Hot
Dist. Dir. . Section Rate Rate Dogleg Rectangular Coords Error
(ft) (deg.) (fi) (dg/lOOR) (dg/lOOft) (dg/lOOft) (deg) (ft) (ft) (ft)
3971.00 47.50 16.64 3699.72 3760.72 100.00 712.35N 212.94 E 6006594.65 584739.83 743.49~ 16.64 743.49 2.50
4071.00 50.00 16.64 3765.64 3826.64 100.00 784.38N 234.47E 6006666.91 584760.54 818.67{~ 16.64 818.67 2.50
END OF BUILD
4071.18 50.00 16.64 3765.76 3826.76 0.18 784.50N 234.51 E 6006667.04 584760.57 818.80~ 16.64 818.80 2.50
0.00
0.00
2.50 47.5 710.31N 219.76E 30.02
2.50 50.0 782.04N 242.27 E 32.79
0.00 2.50 50.0 782.17N 242.31 E 32.79
CASING POINT OD = 9 518 in, ID = 8.84 in, Weight = 40.00 lb/ft.
4271.00 50.00 16.64 3894.19 3955.19 199.82 931.18N 278.35E 6006814.19 584802.74 971.8~ 16.64 971.89 0.00 0.00
NA Sands
5213.56 50.00 16.64 4500.00 4561.00 942.56 1623.01N 485.16E 6007508.27 585001.65 1693.98~ 16.64 1693.98 0.00 0.00
Base Schrader
5695.88 50.00 16.64 4810.00 4871.00 482.32 1977.04N 590.99 E 6007863.45 585103.42 2063.48(~ 16.64 2063.48 0.00 0.00
START OF CURVE {~ 2.00 deg/100 ft
8215.70 50.00 16.64 6429.56 6490.56 2519.82 3826.59N 1143.87 E 6009719.03 585635.05 3993.90~ 16.64 3993.90 0.00 0.00
THRZ
8236.51 49.59 16.64 6443.00 6504.00 20.81 3841.82N 1148.43 E 6009734.32 585639.43 4009.7~ 16.64 4009.79 -2.00 -0.00
8315.70 48.00 16.64 6495.16 6556.16 79.19 3898.90N 1165.49 E 6009791.58 585655.84 4069.37(~ 16.64 4069.37 -2.00 -0.00
8415.70 46.00 16.64 6563.35 6624.35 100.00 3968.97N 1186.43E 6009861.89 585675.97 4142.51~ 16.64 4142.51 -2.00 -0.00
8515.70 44.00 16.64 6634.05 6695.05 100.00 4036.72N 1206.69 E 6009929.86 585695.44 4213.22~ 16.64 4213.22 -2.00 -0.00
8615.70 42.00 16.64 6707.18 6768.18 100.00 4102.07N 1226.22E 6009995.42 585714.22 4281.4~ 16.64 4281.42 -2.00 -0.00
8715.70 40.00 16.64 6782.64 6843.64 100.00 4164.93N 1245.01E 6010058.48 585732.29 4347.03~ 16.64 4347.03 -2.00 -0.00
TKUD
8780.83 38.70 16.64 6833.00 6894.00 65.13 4204.49N 1256.83E 6010098.18 585743.65 4388.33~ 16.64 4388.33 -2.00 -0.00
8815.70 38.00 16.64 6860.35 6921.35 34.87 4225.23N 1263.03 E 6010118.98 585749.61 4409.96~ 16.64 4409.96 -2.00 -0.00
8915.70 36.00 16.64 6940.20 7001.20 100.00 4282.89N 1280.26E 6010176.83 585766.18 4470.15~ 16.64 4470.15 -2.00 -0.00
END OF CURVE
8965.92 35.00 16.64 6981.09 7042.09 50.22 4310.83N 1288.62E 6010204.87 585774.21 4499.31~ 16.64 4499.31 -2.00 -0.00
K-Ni/TKUCI
9065.92 35.00 16.64 7063.00 7124.00 100.00 4365.79N 1305.04E 6010260.00 585790.00 4556.67~ 16.64 4556.67 0.00 -0.00
CASING POINT OD = 7in, ID=6.28in, Weight=26.001b/R.
9458.76 35.00 16.64 7384.80 7445.80 392.84 4581.68N 1369.56E 6010476.60 585852.03 4782.0f~ 16.64 4782.00 0.00 0.00
9459.01 35.00 16.64 7385.00 7446.00 0.24 4581.81N 1369.60E 6010476.74 585852.07 4782.14~ 16.64 4782.14 0.00 0.00
0.00 50.0 931.18N 278.35 E 0.00
0.00 50.0 1617.32N 504.21E 65.09
0.00 50.0 1969.92N 614.78 E 78.87
0.00 50.0 3812.07N 1192.45 E 151.13
2.00 50.4 3827.24N 1197.21E 151.72
2.00 52.0 3884.10N 1215.00E 153.92
2.00 54.0 3953.91N 1236.82 E 156.60
2.00 56.0 4021.42N 1257.88 E 159.18
2.00 58.0 4086.54N 1278.16E 161.66
2.00 60.0 4149.19N 1297.64E 164.02
2.00 61.3 4188.63N 1309.89E 165.52
2.00 62.0 4209.30N 1316.31E 166.31
2.00 64.0 4266.79N 1334.12E 168.46
2.00 65.0 4294.65N 1342.75 E 169.51
0.00 65.0 4349.44N 1359.73 E 171.61
0.00 65.0 4581.68N 1369.56E 0.00
0.00 65.0 4564.82N 1426.46 E 179.85
FEB 2 9 lg?G
AJaska Oi} & Gas Cons. Commi:ssion
A~chora~e
240
~ELLS STATUS
210.~?
P75
BO0
175
150
1E~
100
180
CLOSEST POINTS
Slot ~stonce ~ectlon ReF MD ReF TVD
IVPl<-37 Est B37.04 185.g7 0.00 0.00
PE~-L:5 Est l~.g4 ~.75 0.~ 0.~
~-18 Est 60.17 159.~ 0.~ 0.~
~-17 As-Stoked 1~.~ ~lg.~ 0.~ 0.~
CASCA~-IA ~.~7 133.7~ 4~.~ 3845.~
C~CA~-O1 137~.~ 1~.93 ~.~ 34~.07
~-~ Est ~.87 l~.B4 0.~ 0.~
Se~.Fact~
37.00
l~.gO
60.30
17.80
44.40
E09.90
250
225
200
175
150
125
100
~70
240
STATUS
FLI]WING
FLI]WING
FLOWING
FL[DWING
FLOWING
FLOWING
FLYING
180
150
FEB 29 I8,96
.Alaska Oi! & Gas Cons. ~ ....... '~-:'?
Anchorage
CL[F-~EST POINTS
Slot D~s~once I~meclion ReC MD ReC TVD
I~K-37 Est ~7.~ l~,g7 0.~ 0.~
~-~ Est 1~.94 ~.~ 0,~ 0.~
~-18 Est ~.17 15g.~ 0,~ 0.~
~-17 As-Stok~ 1~.~ 219.~ 0.~ 0.~
~-IA I~.~7 I~.Z3 41~.~ ~45,~
C~CA~-O 1 137~,~ ~ ~,93 ~,~ 34~.07
~-~ E~ ~,87 1~.~4 0.~ 0.~
Sel~3.Foc tc~
7.00
16~.gO
60.L:~3
l~5,go
17.80
44,40
L::~O.O0
N/o m~u E/W me measured ri'om the WELLHEAD
TVD is measured from the WELLHEAD
Interval Step Depth 50.00 I~.(MD) From 0.00 To 9459.01 t~.(MD)
All Directions using BP Highside Method in Dee. Deg.
All Depths and Distance are in FEET All distances are between EXPECTED Positions
Close Approach Status
Offset Flowing Zone Flowing Shut-in Enter Enter Exit Exit
Well Safety Min. Safety Safety Shut-in Danger Danger Shut-in
Clear Spread MD TVD Dist Dist Zone Zone Zone Zone
MD MD MD MD
MPK-37 Wpl 196.1 221.1 2000 2000 30.0 5.0
MPKo25 Wpl 122.0 147.0 2000 2000 30.0 5.0
MPK-18 Wpl 17.9 43.6 2100 2100 31.0 5.2
MPK-17 Wp2 83.6 109.4 2100 2100 31.0 5.2
CASCADE-lA 976.3 1017.0 4100 3845 51.0 10.3
CASCADE-01 1295.0 1332.3 3650 3528 46.5 9.1
MPK-38 Wpl 167.6 193.3 2100 2100 31.0 5.2
Close
Approach
Stares
OK
OK
OK
OK
OK
OK
OK
'1 VI) is measured from the WELLHEAD
Interval Step Depth 50.00 ft.(MD) From 0.00 To 9459.01 IL(MD)
All Directions using BP Highside Method in Dee. Deg.
All Depths and Distance are in FEET All distances are between EXPECTED Positions
Close Approach Status
Offset Flowing Zone Flowing Shut-in Enter Enter Exit Exit
Well Safety Min. Safety Safety Shut-in Danger Danger Shut-in
Clear Spread MD TVD Dist Dist Zone Zone Zone Zone
MD MD MD MD
MPK-37 Wpl 196.1 221.1 2000 2000 30.0 5.0
MPK-25 Wpl 122.0 147.0 2000 2000 30.0 5.0
MPK-18 Wpl 17.9 43.6 2100 2100 31.0 5.2
MPK-17 Wp2 83.6 109.4 2100 2100 31.0 5.2
CASCADE-lA 976.3 1017.0 4100 3845 51.0 10.3
CASCADE-01 1295.0 1332.3 3650 3528 46.5 9.1
MPK-38 Wpl 167.6 193.3 2100 2100 31.0 5.2
Close
Approach
Status
OK
OK
OK
OK
OK
OK
OK
FEB 2 9 1996
()ii & (.?.as Cons.
P,~chorage
N/b and E/W are measured from the WELLHEAD
TVD is measured from the WELLHEAD
Interval Step Depth 50.00 ft.(MD) From 0.00 To 9459.01 ft.(MD)
All Directions using BP Highside Method in Dee. Deg.
All Depths and Distance are in FEET All distances are between EXPECTED Positions
Closest Points
Slot Wellpath Distance Direction RefMD
MPK-37 Est MPK-37 Wpl 237.04 185.97 0.00
243.96 185.90 2150.00
MPK-25 Est MPK-25 Wpl 162.94 200.75 0.00
165.41 200.70 2100.00
MPK-18 Est MPK-18 Wpl 60.17 159.20 0.00
61.28 159.98 2150.00
MPK-17 As-StakdVIPK-17 Wp2 125.89 219.52 0.00
129.42 218.90 2200.00
CASCADE-lA CASCADE-lA 1088.27 133.73 4100.00
1545.79 192.04 4450.00
CASCADE-01 CASCADE-01 1372.85 106.93 3600.00
1963.42 144.93 4150.00
MPK-38 Est MPK-38 Wpl 209.87 158.24 0.00
224.48 160.95 2350.00
RefTVD
0.00
2149.98
0.00
2100.00
0.00
2149.98
0.00
2199.93
3845.28
4070.24
3489.07
3877.42
0.00
2349.31
Sep Factor
237.0
20.9
162.9
14.5
60.2
5.2
125.9
10.8
17.8
13.4
44.4
30.6
209.9
17.6
TVD is measured from the WELLHEAD
Interval Step Depth 50.00 tl.(MD) From 0.00 To 9459.01 tl.(MD)
All Directions using BP Highside Method in Dec, Deg.
All Depths and Distance are in FEET All distances are between EXPECTED Positions
Closest Points
Slot Wellpath
MPK-37 Est MPK-37 Wpl
MPK-25 Est MPK-25 Wpl
MPK-18 Est MPK-18 Wpl
MPK-17 As-StakdVIPK-17 Wp2
CASCADE-IA CASCADE-lA
CASCADE-01 CASCADE-01
MPK-38 Est MPK-38 Wp I
Distance Direction RefMD RefTVD SepFactor
237.04 185.97 0.00 0.00 237.0
243.96 185.90 2150.00 2149.98 20.9
162.94 200.75 0.00 0.00 162.9
165.41 200.70 2100.00 2100.00 14.5
60.17 159.20 0.00 0.00 60.2
61.28 159.98 2150.00 2149.98 5.2
125.89 219.52 - 0.00 0.00 125.9
129.42 218.90 2200.00 2199.93 10.8
1088.27 133.73 4100.00 3845.28 17.8
1545.79 192.04 4450.00 4070.24 13.4
1372.85 106.93 3600.00 3489.07 44.4
1963.42 144.93 4150.00 3877.42 30.6
209.87 158.24 0.00 0.00 209.9
224.48 160.95 2350.00 2349.31 17.6
WELL PERMIT CHECKLIST
GEOL a=a ~7'Cr
PROGRAM:
[] dev [] redrll [] serv~
exp
UNIT# .~'~~, ON/OFF SHORE
ADMINISTRATION
APPR DATE
ENGINEERING
APPR , DATE
1. Permit fee attached .................. N
2. Lease number appropriate ............... N
3. Unique well name and number .............. N
4. Well located in a defined pool ............. N
5. Well located proper distance from drlg unit boundary.. N
6. Well located proper distance from other wells ..... N
7. Sufficient acreage available in drilling unit ..... N
8. If deviated, is wellbore plat included ........ N
9. Operator only affected party .............. N~
10. Operator has appropriate bond in force ......... N
11. Permit can be issued without conservation order .... (Y~ N
12. Permit can be issued without administrative approval..~y,Y N
13. Can permit be approved before 15-day wait ....... N
Conductor string provided ................ ~Y~ N
Surface casing protects all known USDWs ........ ~I N
CMT vol adequate to circulate on conductor & surf csg.. N
CMT vol adequate to tie-in long string to surf csg . . . N
14.
15.
16.
17.
18. CMT will cover all known productive horizons ....... Y N
permafrost. Y~
19. Casin9 designs adequate for C, T, B & · · .
20. Adequate tankage or reserve pit ............. N
21. If a re-drill, has a 10-403 for abndnmnt been approved
Adequate wellbore separation proposed ......... N
23. If diverter required, is it adequate ..........
24. Drilling fluid program schematic& equip list adequate .LY/N
o · o . o o o o o ·~v~ M N
25. BOPEs adequate ........... i~/ ~
26. BOPE press rating adequate; test to ,,~'(~)0'~ psi9
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 .............
REMARKS
GEOLOGY
30. Permit can be issued w/o hydrogen sulfide measures .... Y
Data presented on potential overpressure zones ..... Y
32.31. Seismic analysis of shallow gas zones ..........
33. Seabed condition survey (if off-shore) ....... / Y N
34. Contact name/phone for weekly progress reports . . ~.. Y N [exploratory only]
GEOLOGY: ENGINEERING:
COMMISSION:
DWJ
JDN
TAB ,
Comments/Instructions:
HOW/Ijb - A:~FORMS~.cheklist rev 11/95
