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Alaska Oil and Gas Conservation Commission
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.
VERIFICA TION OF APPLICATION FOR SPACING EXCEPTION
COOK INLET, ALASKA
ADL-384380
C-061590
C-061588
Happy Valley #7 well
I, KEVIN A. TABLER, Manager, Land and Government Affairs, Union Oil Company of
California, do hereby verify the following:
I am acquainted with the application submitted for the drilling of the
Happy Valley #7 well in the Deep Creek Unit.
I have reviewed the application submitted for the exception to 20 AAC
25.055 (a)(2) and all facts therein are true.
I have reviewed the plat attached to said application, and it correctly
portrays pertinent and required data.
DATED at Anchorage, Alaska this 16th day of April 2004.
~ "Jr!J.L-
In A. Tabler
Mgr., Land & Govt. Affairs
STATE OF ALASKA
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THIRD JUDICIAL DISTRICT
SUBSCRIBED TO AND SWORN before me this 16th day of April, 2004.
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NénÃRY PUBLIC IN AND FOR
THE STATE OF ALASKA
My Commission expires: :J --/i'.. ðG
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Unocal corporatio.
P.O. Box 196247
Anchorage, AK 99501
Telephone (907) 263-7660
UNOCAL.
RECEIVED
JUN 1 42004
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Am:'hnr~!1I'
Monday, June 14,2004 "'11';
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Alaska Oil and Gas Conservation Commission
333 West th Avenue
Anchorage, Alaska 99501
Attn: Commission Chair John Norman
Re: New Application for Permit to Drill (Form 10-401)
Happy Valley #7
Dear Commissioner Norman,
Please cancel the existing Permit to Drill (Form 10-401) for Happy Valley #7, API # 50-
231-20020, Permit # 204-068, dated April 2th, 2004. The well will be re-permitted as
Happy Valley #7 with a new surface location.
Attached for your approval is an application for permit to drill (Form 10-401) for the
Happy Valley #7 Well. The surface location has changed on the existing pad, and the
directional profile has changed slightly. The bottom hole location is within the 500'
radius of the previously permitted well. The casing program and TVD setting depths
remain the same.
Unocal respectfully requests a waiver of the requirement for a diverter on the 16" surface
hole as allowed under AOGCC Regulation 20 MC 25.035 (h) (2). Please refer to
attached supporting documentation.
The anticipated spud date is approximately June 16th. If you have any questions please
contact myself at 263-7637.
Sinc.er7]eIY. '~//./.'
/. ~-
A/.. ?--. A
Steven Lambe
Advising Drilling Engineer
SSLls
Enclosure
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AI/ASIiA OIL AND GAS
CONSERVATION COMMISSION
Phil Krueger
Drilling Manager
Union Oil of California (Unocal)
P.O. Box 196247
Anchorage, Alaska 99519
FRANKH. MURKOWSKI, GOVERNOR
333 W. 7'" AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
Re: Happy Valley #7
Union Oil of California (Unocal)
Permit No: 204-068
Surface Location: 1312' FSL, 1170' FEL, SEC. 22, T2S, R13W, S.M.
Bottomhole Location: 1415' FSL, 150' FEL, SEe. 15, T2S, R13W, S.M.
Dear Mr. Krueger:
Enclosed is the approved application for permit to drill the above referenced exploration well.
This permit to drill does not exempt you fi'om obtaining additional permits or approvals required
by law fi'om other governmental agencies, and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the Commission
reserves the right to withdraw the permit in the event it was erroneously issued. A weekly status
report is required from the time the well is spudded until it is suspended or plugged and
abandoned. The report should be a generalized synopsis of the week's activities and is
exclusively for the Commission's internal use.
All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample
intervals from below the permafi'ost or fi'om where samples are first caught and 10' sample
intervals through target zones.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the
Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure
to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska
Administrative Code, or a Commission order, or the terms and conditions of this permit may
result in the revocation or suspension of the permit. Please provide at least twenty-four (24)
hours notice for a representative of the Commission to witness any required test. Contact the
Commission's North Slope petroleum field inspector at -3607 (pager).
m'
J
Chair
BY ORDER Q1 THE COMMISSION
DATED thislJ. day of April, 2004
cc: Department ofFish & Game, Habitat Section w/o encl.
Department of Environmental Conservation w/o encl.
"
.
Unocal Alaska .
Union Oil Company of Cali
909 West 9th Avenue, P.O. . 196247
Anchorage, Alaska 99519-6247
Telephone (907) 276-7600
Fax (907) 263-7698
UNOCAL8
RECEIVED
APR 1 9 2004
Kevin A. Tabler, Manager
Land/Government Affairs
Alaska Oli &1..
Anr:/w; ·'e
..;¡;. ,~Ion
April 16, 2004
Mr. Bob Crandall
Alaska Oil and Gas Conservation
Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
APPLICATION FOR SPACING EXCEPTION
Happy Valley #7 well
Unocal Lease C-061588, C-061590
ADL # 384380
Dear Mr. Crandall:
Union Oil Company of California (Unocal) hereby submits this Application for Spacing
Exception to drill the referenced "Happy Valley #7" well in the Deep Creek Unit. Our
anticipated spud date is late April, early May, 2004. In accordance with 20 AAC 25.005
(a), a Permit to Drill and associated filing fees are filed herewith. '
The Happy Valley #7 well is situated in governmental Section 15, Township 2S - Range
13W S.M. requiring a spacing exception in accordance with 20 AAC 25.055 (a)(2), and if
the results of the Happy Valley #7 well are successful, may be within 1,500' of a property
line with a different landowner. This regulation provides in pertinent part, "a wellbore
may be open to test or regular production within 1,500 feet of a property line only if the
owner is the same and the landowner is the same on both sides of the line." This well
location is structurally high on the formation and is a crestal withdrawal based on
seismic, dip meter and subsurface data available to Unocal. Additionally, the correlative
rights of all affected owners, landowners and operators will be protected by exception
approval.
At the date of this mailing, in accordance with 20 AAC 25.055 (d)(l), notice of our intent
to drill has been sent by certified mail to all owners, landowners, and operators of all
.
.
outlying properties within 3,000 feet of the Happy Valley #7 well. A copy of this
application (landowner notice) along with a certified mailing receipt has been attached to
this application. Additionally, the owner and operator (Unocal) and the landowner (Cook
Inlet Region, Inc.) are within 3000' oflands owned by DNR.
Pursuant to 20 AAC 25.055 (d)(2), enclosed is a plat, identified as Exhibit "A", which
shows the location of the well for which the exception is sought and all adjoining
properties. Also enclosed, Exhibit "A-I" identifies the owners, landowners and operators
associated with each tract.
Pursuant to 20 AAC 25.055 (d)(3), an affidavit is enclosed stating the undersigned is
acquainted with the facts and verifying that all facts are true.
It is requested that the Commission approve an exception to the statewide spacing
regulation for the drilling of the proposed Happy Valley #7 well.
If you require additional information regarding the Happy Valley #7 drill site, please
contact Mr. Jerry Bowen, drilling engineer at 263-7640, or you may contact the
undersigned at 907-263-7600.
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Enclosures
cc: CIRI
DNR
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C-061590
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UNOCALfj
DEEP CREEK UNIT
HAPPY VALLEY 7
EXHIBIT A
N
A
0.5 0.25 0 0.5
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Miles
Alaska State Plane Zone 4, NAD27
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LEASE
ADL-384380
(Section. 22 portion)
T2S-R13W
C-061590
(Sections 22, 23)
T2S-R13W
C-061588
(Sections 14,15)
T2S-R13W
.
EXHIBIT "A-I"
LANDOWNER
OWNER
DNR Unocal
Division of Oil and Gas
550 West 7th Avenue, Suite 800
Anchorage, Alaska 99501-3560
Attn: Carol Lee
Cook Inlet Region, Inc.
2525 C Street, Suite 500
Anchorage, Ak 99509
Attn: Kirk McGee
Cook Inlet Region, Inc.
2525 C Street, Suite 500
Anchorage, Ak 99509
Attn: Kirk McGee
Unocal
Unocal
.
OPERATOR
Unoca1
Unocal
Unocal
Cheo/tYpe of mail or service:
~Certified 0 Recorded Delivery (Intematlonal)
o COD 0 f3e1 istered
o Delivery Confirmation [;Y'Retum Receipt for Merchandise
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reconstruction of nonnegotiabls do.cuments under Express Man document rsconstructlon insurance is $500 per piece subject to
additional Umilations for multiple plecss lost or damagss In a single catastrophic occurrence. The maximum indemnity payable
on Express Msil merchandise insurance Is $500, but optional Express Mail Service merchandise Insurance is available for up to
$5,000 to some, but not all countries. The maximum indemnity payable is $25,000 for registered mail. See Domestic Mail
Manual R900, S913, and S921 for Umitatlons of coverage on Insured and COD mail. See /n/erna/ional Mail Manualfor limitations
of coverage on International mail. Special handilngcharges apply only to Standard Mail (A) and Standard Mail (B) parcels.
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Unoca' corporatio.
P.O. Box 196247
Anchorage, AK 99501
Telephone (907) 263-7660
UNOCALe
Phil Krueger
Drilling Manager
Monday, April 19,2004
Alaska Oil and Gas Conservation Commission
333 West th Avenue
Anchorage, Alaska 99501
Attn: Commission Chair John Norman
Re: Application for Permit to Drill (Form 10-401)
Happy Valley #7
Dear Commissioner Norman,
Attached for your approval is an application for permit to drill (Form 10-401) for the
Happy Valley #7 Well.
Unocal respectfully requests a waiver of the requirement for a diverter on the 16" surface /'
hole as allowed under AOGCC Regulation 20 MC 25.035 (h) (2). Please refer to
attached supporting documentation.
The anticipated spud date is approximately May 1 st. If you have any questions please
contact myself at 263-7628 or Mr. Jerry Bowen at 263-7640.
Sincerely,
r;/~
----
Phil Krueger
Drilling Manager
LWB/s
Enclosure
RECEIVED
APR 1 9 2004
Alaska Oil & Gas Cons. Commission
Anchorage
ORIGINAL
W 41\- t 11..:!I , 2..b "£1-
. STATE OF ALASKA .
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
20. Attachments: Filing fee: X Property Plat: X BOP Sketch: X
Drilling fluid program: X Time vs. depth plot: X Refraction analysis:
21. I herby certify that the foregoing is true and correct to the best of my knowledge:
Signed: l ß/· . tv.) ~hil Krueger Title: Drilling Manager Date: 04/16/2004
7 I' Commission Use Only
Permit Number I API number -> I Approval date i' \ :l '1~ ) I See cover letter
:<011- ~ç' .s-C' - 23/- ,-.()ö.2.0 11'10'1 for other requirements
Conditions of approval sampl~uired: [] Yes MNo Mud lo~ r:quired: ] Ye ~ No .
Hydrogen sulfide measur [ ] Yes,);;No ¡;[¡rèctional survey required ;qYes [] No T~ st ßO PE to 4-S'oo t'S <.
RequireR wor . ess re or BOPE [] ~;.. [] 3M; [] ~M; [] 10M; [] 15M t.'· £.V,~..hl ~J. J
Other: r.¿ .. .D~S" (~1 2-) J L;v~t.tr (e1i(í~ W\-~:r¥,,~,otvC£CÚA.M. " s ~of~ve .
f.1' p, S". 0 c; 0 ( k a,..lrø'Ý VIA-t!.. IM-t ,.,0 N.. L It)' order of ~ / J 1
Approv bv \. -' Commissioner the Commission Date: )'é r lOT
"MOl 9 I HdV "'f1~{~
-'01R~-185 ORIGINAL '""""-
Redrill:
Deepen:
\1 b. Type of well
Service:
1 a. Type of work Drill: X
Re-Entry:
2. Name of Operator
Union Oil of California (Unocal)
3. Address
P.O. Box 196247 Anchorage, AK 99519
4. Location of well at surface
1312'FSL, 1170'FEL, Sec. 22, T2S, R13VV, S.M.
At top of productive interval
350'FSL,280'FVVL,Sec. 15, T2S, R13VV, S.M.
At total depth
1415' FSL, 150'FEL, Sec. 15, T2S, R13VV, S.M.
12. Distance to nearest 13. Distance to nearest well
property line
5524 feet
16. To be completed for deviated wells
Kickoff depth: 1500 feet 37° Maximum hole angle:
18. Casing program
size
Casing
18 5/8"
13 3/8"
121/4" 95/8"
8 1/2" 3 1/2"
3293
Hole
N/A
Specifications
Grade Coupling
K-55 (welded)
K-55 BTC
L-80 BTC - mod
L-80 IBTC-mod
16"
VVeight
96.79
68
40
9.2
19. To be completed for Redrill, Re-entry, and Deepen Operations.
Present well condition summary
Exploratory: X
Developement Gas:
5. Datum Elevation (DF or KB)
738.5' KB to MSL feet
6. Property Designation
C-061588
7. Unit or property Name
Deep Creek Unit
8. Well number
Happy Valley #7
9. Approximate spud date
05/01/04
14. Number of acres in property
Development Oil:
Multiple Zone: X
Stratigraphic Test:
Single Zone:
10. Field and Pool
Wildcat in Beluga
& Tyonek Gas Sands
11. Type Bond (see 20 AAC 25.025)
Number
U 62-9269
Amount
$200,000
15. Proposed depth (MO and TVO)
feet
2780.01 12,330' /10,590'
17. Anticipated pressuÏ'"{see 20 AAC 25.035 (e)(2»
Maximum surface 3717 psig At total depth (TVO)
Setting Depth
feet
4734 psig
Top Bottom Quantity of cement
Length MD TVD MD TVD (include stage data)
40-80' 0' 0' 40-80' 40-80' N/A - driven to refusal /
1037' 0' 0' 1032' 1032' 107.7 bbls (388 sx) /
4350' 0' 0' 4350' 4016' 228 bbls (725 sx)
13,800' 0' 0' 12,330' 10,590' 565 bbls (1283 sx)* /
'Contingent upon log analysis.
RECEIVED
APR 1 9 2004
Alaska Oil & Gas Cons. Commission
Anchorage
Diverter Sketch:
Seabed report: NIA
Drilling program: X
20 AAC 25.050 requirements:
.
.
List of Attachments
~
1. Permit to Drill (form 10-401)
2. Waiver Request
3. Surveyors Location Plat
4. Acreage Map wi Offset Wells & Trajectories
5. General Drilling Procedure
6. Predicted Days vs. Depth Curve
7. Proposed Wellbore Schematic
8. M.A.S.P. Calculation & Casing Design Factors
9. Proposed Well Trajectory
10. Kick Tolerance Output
11. Leak Off Test Procedure
12. Cement Program (D/S - includes volume calculations)
13. Cellar & BOP Stack Diagram
14. Choke Manifold Diagram
15. Cuttings Disposal Description
16. Offset Well Usable Quality Water Salinity Calculations &
Graph
17. Mud Program (Baroid)
.
.
WAIVER REQUEST
Unocal respectfully requests waivers to;
(1.) AOGCC regulations 20 AAC 25.035 (C)
(2.) AOGCC regulations 20 AAC 25.050 (C)(1)
WAIVER #1:
Unocal request permission to drill the 16" surface hole to a depth of +/-
1032' without a diverter. AOGCC regulation 20 AAC 25.035 (h) (2) /
stipulates:
(h) ¡¡Upon request f the operator, the commission will, in its
discretion, approve a variance ...... (2) from the diverter system
requirements in (C) of this section if the variance provides at least
equally effective means of diverting flow away from the drill rig or if
drilling experience in the near vicinity indicates that a diverter
system is not necessary. "
Based on our experience drilling 12 %" surface holes in Happy Valley #1,
#2, #3, #4, #5 & #6 it has been proven conclusively that no shallow gas /~
hazards exist beneath this pad to a depth of at least 1032' BRT. The 16"
surface hole for Happy Valley #7 will be drilled from the same pad as Happy
Valley Wells #1 through #6 (within +/-225'), and to the approximate same
depth as the previous Happy Valley surface holes.
The Geologist, Dave Buthman, has reviewed the shallow geology and has
prepared the following summary of the shallow lithology:
From surface to 1037' VD beneath the Happy Valley surface pad, we
anticipate the following lithologies:
0-300': interbedded med to coarse grained sand and coarse gravels
300-1037': interbedded light gray silty claystones, argillaceous
siltstones, gray silty claystones, light gray fine to medium grained
sandstones, with a few thin brown lignitic coals.
We do not anticipate any significant faulting, nor do we expect any
oil or gas to be trapped, as no suitable seals exist within this shallow
section.
For the purpose of basic risk mitigation, Unocal will utilize a gel/native
spud mud which is expected to weigh approximately 9.2 ppg when drilling
at the planned surface hole TD of 1032', to eliminate the risk of a shallow
water flow.
.
.
WAIVER #2:
Unocal requests permission to drill the 16" surface hole to +/-1032' without
surveying until after the 9 5/8" casing is cemented. AOGCC regulation 20 /'
AAC 25.050 (h) stipulates:
(h) "Upon application, the commission will, in its discretion, waive all
or part of the directional survey requirements of this section or
approve alternate means for determining the location of a wellbore if
the variance at least equally ensures accurate surveying of the
wellbore to prevent well intersection, to comply with spacing
requirements, and to ensure protection of correlative rights. II
Due to plans to drill the 16" surface hole vertically to 1032', there is no
cost-effective means to survey once each 500' as required in regulation
25.050 (C)(1). Unocal will obtain the required surveys at the first
opportunity after cementing the 13 3/8" casing, before drilling the 12 %"
hole, to eliminate the risk of a well-to-well collision and ensure accuracy of
the final BHL.
AS STAKED
HAPPY VALLEY NO. 7
GRID N: 2,189,852.69
GRID E: 228,097.43
LATITUDE: 59°59'09.545"N
LONGITUDE: 151°29'05.208"W
ELEV. 716'
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HAPPY VALLEY
NO.7 WELL
SURFACE LOCATION/·
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lL.
N
r;}
~
.
--
OILWELL RD.
SCALE
1 inch = 300 ft.
~o
450
I
600
I
NOTES
1) BASIS OF COORDINATES: NGS CORS
STATION "KEN 1" NAD27 ALASKA STATE PLANE
ZONE 4.
2) BASIS OF ELEVATION: NGS BM W75 NAVD88.
3) SECTION LINE OFFSETS DERIVED FROM
TIES TO BLM MONUMENTS AT SW CORNER
SECTION 10 AND SE CORNER SECTION 12 T2S
R13W SM FOUND THIS SURVEY
1170' FEL HV#7
~
N
SECTION 22
TOWNSHIP 2 SOUTH
RANGE 13 WEST
SEWARD MERIDIAN
ALASKA
Grid
SEC 22 SEC 23
SEC 27 SEC 26
APPLICANT:
UNDCAL
909 W. 9th A~nue .
Anchorage, AI( 99519-7685
HAPPY VALLEY NO.7 WELL
SURFACE LOCATION NINILCHIK, AK
P.O. 8cx 468 SCLCCTNA, AK 99669
~ ConsuLiing "'roup
~ Testing
Project: 043021
Revisions:
Dwg: 043021
I Date: 4/12/04
FIGURE: 1
8
9
17
3
24
26
25
DEEP CREEK UNIT
HAPPY VALLEY 7
EXHIBIT A
N
Alaska State Plane Zone 4, NAD27
Genera! Procedure.xls
Page 1 of 1
4/19/2004
HAPPY VALLEY #7
PLAN DAYS VERSUS DEPTH
o
10
15
Time (Days)
Valley #4
Happy Valley #3
Happy Valley #1
Valley #2
I I 'If ~I I # 'OJ _ \ V _, _I_I' I! .""'-,_
Valley #5
Happy Valley #7 AFE I
II ._1__.......... 'f v~_ . 1 11-0'111
Location: X==228,097.43 E, Y==2,189,852.69 N
Lat: 59" 59' 09.545" N, Long: 151029' 05.208" W
1312' FSL, 1170' FEL, Sec22, T2S, R13W, S.M.
RKB == 22.5' AGL
GL == 716' AMSL
RKB elevation == 738.5' AMSL
18 5/8" 96.79 DDf butt: welded. drilled/driven to +/·30-50' BGl
16" hole (drilled w/out diveter, AOGCC waiver requested AO 4/16/04, confirm approval)
8.8 ppg KCL- WBM spud mud
Cement to surface req'd wI 350' 15.8 ppg G tail & 682' 12.8 ppg extended G lead
Planned TD 12,330' MD /10,590' VD
Static BHT == 36.8°F + (0.0136 J( TVD)
Job Template #1
REVISED: 04/16/04
DRAWN BY: JFB
.
.
UNDCAL8
Maximum Anticipated Surface Pressure Calculation
Happy Valley Well #7
Kenai Peninsula, Alaska
Assumptions:
/
1. Based on offset drilling & well test data, the pore pressure gradient is predicted to be a 0.447 psilft gradient from
surface to planned total depth at 10,590' VD BRT. Unocal has drilled two wells on this structure to 10,590' VD or
deeper (HV #3 & #4) from this pad, and has reviewed data from three other wells drilled to at least this same depth
within a +/-3 mile radius (NNA #1, HV #31-22 & Deep Creek Unit #1).
2. The MAS.P. during drilling operations will be governed by the 9 5/8" shoe frac gradient, and is calculated based on
a full column of gas between the 9 5/8" shoe and the surface. The shoes for HV #7 will be at the same depth as the
shoes in HV wells #1, #3, #4 & #5 thus the nearby LOT data from approximately 4016' VD is useful for relatively
accurate kick tolerance & MASP calculations.
3. The M.A.S.P. during production operations will be the estimated SIBHP minus the gas hydrostatic pressure between
TD & the surface. The 9 5/8" intermediate casing must be designed to handle a potential burst load case based on a
shallow leak in the 3 1/2" pipe early in the life of a 10,590' VD gas completion (Le. before reservoir pressure declines).
M.A.S.P. During Production Life:
Max. pore pressure at T.D.
=
10,590' VD x
0.447
= 4734 psi
M.A.S.P. (tbg leak at surface)
=
4734 psi - (0.096 psilft * 10,590 ft) =
= 3717
/"
psi
MAS.P. While Drilling 8 1/2" hole at 12,330' MD:
Max. Est. Frac pressure at 9 5/8" shoe =
4016 ft. x
0.904 psi/ft* =
= 3630 psi
M.A.S.P. during drilling =
3630 psi - (.08 psilft x 4016 ft.) =
= 3309 psi
* highest observed FG at +1-4016' VD in Happy Valley area to date
M.A.S.P. While Drilling 12 1/4" hole at 4,350' MD:
Max. Est. F rac pressure at 13 3/8" shoe =
1032 ft. x
1.15 psi/ft** =
= 1187 psi
MAS.P. during drilling =
1187 psi -(.08psi/ftx4016ft.)=
= 866
psi
** highest observed FG at +/-1032' VD in Happy Valley area to date
Calculation & Casing Design Factors
.
" +
UNOCALfj)
Happy Valley Well #7
Kenai Peninsula, Alaska
WELL: Happy Valley #7 FIELD: South Kenai Gas DATE: 19-Apr-04 DESIGN BY: Jerry Bowen
Sect 1 16" hole MUD WT. 9.1 PPG MASP= 763 psi--
Sect 2 121/4" hole MUD WT. 9.1 PPG MASP= 3,838 psi
Sect 3 8 1/2" hole MUD WT. 9.3 PPG MASP= 3,838 psi
TENSION MINIMUM COLLAPSE COLLAPSE ."....- --
/ WEIGHT TOP OF STRENGTH ,/ PRESS @ RESIST. MINIMUM
DESCRIPTION W/OBF SECTION TENSION WORST CASE BOTTOM wlo TENSION WORST CASE MASP YIELD WORST CASE
SECTION CASING BOTTOM TOP LENGTH WT. GRADE THREAD LBS LBS 1000 LBS SF TENSION PSI- PSI SF COLL. PSI" PSI SF BURST
1 133/8" 1,032 0 1032 68 K-55 BTC 70,176 70,176 1300 18.52 454 1,950 4.29 866 3,450 3.98
TVD 1,032 0
2 95/8" 4,350 0 4350 40 L-80 BTC-mod 174,000 174,000 979 5.63 1,767 3,090 1.75 3,717 5,750 1.55
TVD 4,016 0
3 31/2" 12,330 0 12330 9.2 L-80 IBT -mod 113,436 113,436 207 1.82 4,660 10,530 2.26 3,717 10,160 2.73
TVD 10,590 0
- Collapse pressure is calculated; Normal Pressure Fluid Gradient for external stress (.44 psi/lt) and the casing evacuated for the internal stress (0 psi/It)
--
-- See attached sheet for calculation of MASP
Note: All wellhead components are rated to 5000 psi working pressure, with the exception of the X-mas tree and tree adapter spool, which are rated to 6500 psi working pressure.
.
.
UNOCAL
N..
.......
--
INTW~
Kenai Peninsula. Alaska
South Kenai Gas Field
Happy Valley
Location:
Field:
Installation:
WELL PROFILE DA T A
Slot: HV #7
Well: HV #7
Wellbore: HV #7
Point MD Ine A1J 1VD North East deg/100ft v. Sect
Tie on 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
End of Hold 1500.00 0.00 0.00 1500.00 0.00 0.00 0.00 0.00
End of BuildITum 3380.50 37.61 355.38 3248.33 593.42 -47.93 2.00 574.45
End of Hold 4329.35 37.61 355.38 4000.00 1170.61 -94.56 0.00 1133.19
End oITum 5286.40 37.61 27.00 4765.29 1727.09 15.54 2.00 1700.42
End of Hold 6213.85 37.61 'Z7.00 5500.00 2231.40 272.50 0.00 2243.43
End oITum 1??oo.86 37.61 8.06 8510.16 4412.55 961.47 0.30 4514.13
End of DroplTum 10292.02 34.70 6.60 8745.23 4582.88 983.46 1.04 4685.60
End of DroplTum 10583.18 31.79 5.15 8988.73 4741.61 999.88 1.04 4844.65
End of DroplTum 10874.35 28.88 3.69 9240.01 4888.18 1011.29 1.03 4990.81
End of DroplTum 11165.51 25.96 2.24 9498.44 5022.05 1018.31 1.03 5123.69
End of DroplTum 11456.67 23.05 0.78 9763.34 5142.77 1021.57 1.02 5242.94
End of DroplTum 11747.83 20.14 359.32 10034.04 5249.91 1021.76 1.02 5348.28
End of DroplTum 12039.00 17.23 357.87 10309.83 5343.15 1019.57 1.01 5439.52
ToO. & End of DroplTum 12330.16 14.32 356.41 10590.00 5422.18 1015.71 1.01 5516.50
Scale 1 em = 200 II
-800
<1=
0
0 -800
"<t
"
E
() 0
Q)
ro
()
U) 800
1600
2400
- 3200
-
CI)
.!
- 4000
.c
-
Q.
CI)
C 4800
C'O
U
:e 5600
CI)
>
CI) 6400
~
L.
~
.
V 7200
8000
8800
9600
10400
11200
ill
UNOCAL8
./
Created by: PIamer
Date plotted: 16-Apr-2004
Plot reference is HV #7.
Refwellpath is HV #7 Vers#3.
Coordinates are in feet reference HV #7.
True Vertical Depths are reference Rig Datum.
Measured Depths are reference Rig Datum.
Rig Datum: Kuukpik #5
Rig Datum to mean sea level: 738.50 II.
Plot North is aligned to TRUE North.
East (feet) ->
-400
1200
1600
-0
400
800
6400
6000
5600
TO - 7" Casing Pt.
HV#5 TD Tgt Rvsd 23Mar04
..
.J .l13 5/8" Casing Pt.
. KOP
6.00
12.00
OLS: 2.00 deg/100ft
24.00
32.00
EOC
..
Begin OropfTum
T arge·
HV#5 Tgt Rvsd 22-Mar-04,4:30pm
-..
5200
4800
4400
4000
3600
^
3200 .
Z
0
;:¡
2800 ::T
-
¡-
CD
-
2400 -
2000
1600
1200
800
400
C/)
(")
Q)
ã)
0
(")
3
"
-400 N
0
0
;:I!
9 5/8" Casing Pt.
OLS: 0.30 deg/100ft
37.24
37.23
37.26
37.32
37.41
37.53
HV#5 Tgt Rvsd 22-Mar-04,4:30pm Target Begin OropfTum
33.62
29.62
22.62
19.62
16.62
HV#5 TD Tgt Rvsd 23Mar04
TO - 7" Casing Pt.
-800 -0 800 1600 2400 3200 4000 4800 5600 6400
Scale 1 em = 40011 Vertical Section (feet)->
Azimuth 11.15 with reference 0.00 N, 0.00 E from HV #7
Begin Walk to left
, - r 9 5/8" Casing Pt.
EOC
13 5/8" Casing Pt.
, - r KOP
Tie-In
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
.
.
S. Kenai Gas project Happy Valley #7
9-5/8" SHOE DESIGN
SUMMARY & SKETCH
UNOCALe (/
-
13·3/8" shoe
1,010 ft BML....
(1,032 ft TVD) \
/
\
I
\
I
\
12-1/4" Hole /
\
I
\
/
\
I
\
I
\
/
-
mdb/01decOO
METHOD 2:
..
y
"
.6 WD = 0 ft with 0.447 PSI/FT Gradient
RT - MSL = 22.5 ft
DESIGN DOWN:
MW = 9.1 PPG
Pform = 9.1 PPG EMW
KT = 10 BBLS at 0 PPG
FG = 0.6 PSI/FT
Gas Gradient = 0.02 PSI/FT
Drill Pipe = 4.5 INCH
..
The deepest 12-1/4 in hole
that can be drilled =
4,228 ft BML or 4,250 ft TVD
13-3/8" shoe ....
The shallowest
9-5/8" shoe depth =
4,003 ft BML or 4,026 ft TVD
~
8·1/2" Hole
TD = 10,568 ft BML or 10,590 ft TVD
-
METHOD 1:
....
\
/
\
I
\
/
\
/
\
I
\
I
\
I
\
I
\
I
\
/
· DESIGN UP:
MW = 9.3 PPG
Pform = 9.8 PPG EMW
KT = 10 BBLS at 0.5 PPG
FG = 0.603 PSI/FT
Gas Gradient = 0.05 PSI/FT
Drill Pipe = 4.5 INCH
UNOCALi>
.
LEAK OFF TEST ("LOT") PROCEDURE
/'
1. Clean out the rathole below the shoe, and drill 20' of new hole. Circulate and condition mud.
3. RIU and test cement lines.
2. Pull the drill string into the shoe. RIU to monitor both drill pipe and drill pipe x annulus pressures.
4. Close the pipe rams and pump down the drillpipe at a slow rate (1/4 BPM).
5. Measure the volume pumped and plot annulus pressure-vs-cumulative volume pumped.
6. Upon initial leak off (Point B), continue to pump 1 bbl at injection pressure (Point C) taking pressure readings
every % bbl pumped.
7. Stop pumping and record shut-in pressure 10 seconds after initial shut-in (Point D).
Note: The point "D" shown in the attached graph (10-second shut-in) is the value used to calculate
LOT. The LOT (expressed in equivilent mud weight "EMW") is calculated as follows:
LOT = Mud weight in hole, ppg + 10-Second Shut-In Pressure. psi
(0.052) X (shoe depth TVD, ft)
C
"---~
SURFACE
PRESS. 10 sec.
(psi)
VOLUME PUMPED
(DDLS)
~ .
SHUT ·IN· TIME
(MIN)
Point "An will have some variance until the system begins to pressure up.
Point "B" is the fracture iniatation pressure.
Point "C" is known the injection pressure.
Point "D" is fracture closure pressure measured I 0 seconds after shutting down the pumps.
NOTES:
.
.
ScbllmbllPOIIP
*
CemCADE well cementing recommendation for 133/8" Surface Casing
Operator
Country
State
UNOCAL
USA
: AK
Well
Field
Happy Valley #7
Happy Valley
Prepared for : Jerry Bowen Location Ninilchik
Proposal No. : #1 Service Point Kenai
Date Prepared : 04-16-2004 Business Phone (907) 776-8156
FAX No. (907) 776-8158
Prepared by
Phone
E-Mail Address
Chinedu F. Akwukwaegbu
(907) 273-1739
CAkwukwaegbu@slb.com
~GN
( <:J<V~'
t
\'~,
~lIATE
Disclaimer Notice:
This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to
be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on
the well, reservoir and treatment The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the
model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for
comparison purposes rather than absolute values. The quality of input data. and hence results, may be improved through the use of certain tests and procedures which
Schlumberger can assist in selecting.
The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring
well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly.
Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time. equipment, and material ultimately
required to perform these services.
Freedom from infringement of patents of Schlumberger or others is not to be inferred.
. Mark of Schlumberger
.
Client
Well
String
District
Country
loadcase
UNOCAl
Happy Valley #7
Surface Casing
Kenai
USA
Surface Casing
Section 1: well description
Configuration
Stage
Rig Type
Mud Line
Total MD
BHST
Bit Size
: Casing
: Single
: Land
: 0.0 ft
: 1032.0 ft
: 80 degF
: 16 in
MD
(ft)
50.0
Previous String
OD Weight
(in) (lb/ft)
18 5/8 96.5
ID
(in)
17.655
Landing Collar MD : 952.0 ft
Casing/liner Shoe MD : 1032.0 ft
MD
(ft)
1032.0
Casing/Liner
ID Grade
(in)
12.415 K-55
OD
(in)
133/8
Joint
(ft)
40.0
Weight
(lb/ft)
68.0
Mean OH Diameter : 16.000 in
Mean Annular Excess : 20.0 %
Mean OH Equivalent Diameter: 16.475 in
Total OH Volume : 258.9 bbl (including excess)
The Well is considered VERTICAL
MD
(ft)
2500.0
Formation Data
Pore Name
(Ib/gal)
8.33
Frac.
(Ib/gal)
15.00
MD
(ft)
Geothermal Temperature Profile
TVD Temperature Gradient
(ft) (degF) (degF/100ft)
0.0 80 0.0
1032.0 80 0.0
2~0~ 00 ~O
0.0
1032.0
2500.0
; 04-16-2004; LaadCase Surtace Casing; Version wcs-oem44C51
.
Collapse
(psi)
1950
Lithology
Sandstone
Sil..rger
Burst
(psi)
3450
Thread
BTC
Page 2
.
Client
Well
String
District
Country
loadcase
UNOCAl
Happy Valley #7
Surface Casing
Kenai
USA
Surface Casing
Section 2: fluid description
Fluid No: 1
Rhea. Model
At temp.
: BINGHAM
: 80 degF
Fluid No: 3
Rhea. Model
At temp.
: BINGHAM
: 80 degF
Fluid No: 4
Rhea. Model
At temp.
: BINGHAM
: 81 degF
DESIGN
BLEND
Name : G
Dry Density : 199.77 Ib/ft3
Sack Weight : 94 Ib
BASE FLUID
Type : Fresh water
Additives
Code
0079
S002
0046
Cone.
1.500 %BWOC
1.000 %BWOC
0.200 %BWOC
Thickening Time
Compressive Strength
Mud DESIGN
Density
Pv
Ty
Job volume
MUDPUSH " DESIGN
Density
Pv
Ty
Gel Strength
.
SilllllPlep
: 8.80 Ib/gal
: 12.000 cP
: 12.00 Ibf/100ft2
: 142.5 bbl
: 9.50 Ib/gal
: 16.000 cP
: 16.00 Ibf/100ft2
: (lbf/100ft2)
Job volume : 20.0 bbl
Lead Slurry DESIGN
SLURRY
Mix Fluid
Yield
Porosity
Density
Schedule ( )
Schedule ()
Density
Pv
Ty
Gel Strength
~. 1 Hj6-'gal/sk
. .9 ._.3/sk
. . %
: 8.32 Ib/gal
Function
EXTENDER
Accelerator
ANTI FOAM
100 Be
571 psi
; 04-16-2004; loadCasa Surface Casing; Varsion wcs-cem441_51
: 12.80 Ib/gal /
: 11 .936 cP
: 16.99 Ibf/100ft2
: (lbf/100ft2)
Job volume :~. b I
Quantity : 80 sk
Solid Fractio - : 24.9 %
Base Fluid : 11.064 gal/sk
at
at
03:05 hr:mn
37:00 hr:mn
Page 3
Section 3: fluid sequence
Original fluid Mud
pv : 12.000 cp
142.5 bbl
274.2 bbl
O.Oft
.
Client
Well
String
Distri ct
Country
Loadcase
UNDCAL
Happy Valley #7
Surface Casing
Kenai
USA
Surface Casing
Fluid No: 5
Rhea. Model
At temp.
: BINGHAM
: 80 degF
DESIGN
BLEND
Name : G
Dry Density : 199.77 Iblft3
Sack Weight : 94 Ib
BASE FLUID
Type : Fresh water
Code
D065
S002
D046
Cone.
0.300 %BWOC
1.500 %BWOC
0.200 %BWOC
Thickening Time
Compressive Strength
Displacement Volume
Total Volume
TOC
.
lillllrger
Tail Slurry DESIGN
Density
Pv
Ty
Gel Strength
: 15.80 Ib/gal
: 25.749 cp
: 24.73 Ibf/100ft2
: (lbf/100ft2)
SLURRY
Mix Fluid
Yield
Porosity
~. 5 al/sk
1,.11 3/sk
. .2%
Job volume :~~ b I
Quantity : 08 sk
Solid Fractio : 41.8 %
Density
: 8.32 Ib/gal
Base Fluid : 5.098 gallsk
Additives
Function
DISPERSANT
Accelerator
ANTI FOAM
Schedule ()
Schedule ()
100 Be
2573 psi
at
at
03:04 hr:mn
24:00 hr:mn
8.80 Ib/gal
Ty: 12.00 Ibf/100ft2
Fluid Sequence
Name Volume Ann. Len Top Density Rheology
(bbl) (ft) (ft) (lb/gal)
Fresh Water 5.0 0.0 8.32 viscosity:5.000 cP
MUDPUSH II 20.0 0.0 9.50 pv:16.000 cp Ty:16.00 Ibf/100ft2
Lead Slurry 63.3 682.0 0.0 12.80 pv:11.936 cp Ty:16.99Ibf/100ft2
Tail Slurry 43.4 350.0 682.0 15.80 pv:25.749 cp Ty:24.73Ibf/100ft2
Mud 142.5 0.0 8.80 pv:12.000 cp Ty:12.00 Ibf/100ft2
Static Security Checks:
Frac
Pore
Collapse
Burst
CsgPump out
6 psi
12 psi
1679 psi
3450 psi
13 ton
at 50.0 ft
at 50.0 ft
at 952.0 ft
at 0.0 ft
Page 4
; 04-16-2004; loadCase Surface Casing; Version wcs-œm441_51
.
.
Client
Well
String
District
Country
Loadcase
UNOCAL
Happy Valley #7
Surface Casing
Kenai
USA
Surface Casing
Silllllrger
Section 4: pumping schedule
Pumping Schedule
Name Flow Rate Volume Stage Time Cum.Vol Inj. Comments
(bbl/min) (bbl) (min) (bbl). Temp.
(degF)
Fresh Water 5.0 5.0 1.0 5.0 80 Fluid pack lines
Pause 0.0 0.0 5.0 0.0 80 3-Pressure Test Lines
MUDPUSH II 5.0 20.0 4.0 20.0 80 7 -Start Pumping Spacer
Pause 0.0 0.0 5.0 0.0 80 4-Drop Bottom Plug
Lead Slurry 5.0 63.3 12.7 63.3 80 13-Start Mixing Lead Slurry
Tail Slurry 5.0 43.4 8.7 43.4 80 16-Start Mixing Tail Slurry
Pause 0.0 0.0 5.0 0.0 80 18-Drop Top Plug
Mud 5.0 140.0 28.0 140.0 80 19-5tart Displacement
Mud 1.0 2.5 2.5 142.5 80 21-Bump Top Plug
Total 01:11 274.2 bbl
hr:mn
Dynamic Security Checks:
Frac 5 psi
Pore 0 psi
Collapse 1679 psi
Burst 3183 psi
at 50.0 ft
at 63.5 ft
at 952.0 ft
at 0.0 ft
BHCT
Simulated BHCT
CT at TOC
80 degF
80 degF
79 degF
Temperature Results
I Simulated Max HCT
Max HCT Depth
Max HCT Time
80 degF
1032.0 ft
01 :11 :52 hr:mn:sc
WELLHEAD PRESSURE
o
eo
N
o
"<T
N
o
~
o
~ (0-
'û) --
.e,
£L
~~
0_
eo
~-
o
o
,
10
20
30
40
Time (min)
50
60
70
80
Page 5
; 04-16-2004; LoadCase Surface Casing; Version wcs-cem44C51
. .
Client UNOCAL lillllralr
Well Happy Valley #7
String Surface Casing
D istri ct Kenai
Country USA
Loadcase Surface Casing
ECD
D e p th = 1032ft
CD
.- -Frac
-Pore
- Hydrostatic
~_' __ nY,H1fYlÎc
-.t_
.-
1è~
.Q>
:§.
Q)
5 1'1_
v¡
v¡
Q)
ê:
¿ .--
~ .-
0
.-
(1)-
ro I , ,
0 10 20 30 40 50 60 70 80
Time (min)
FLOWRATE COMPARISON
1'1 Fluids at 1 032 ft
.-
0_
.-
ro-
ê
]
:is
.0
'Qi'CD
¡;¡
a::
¡;;
o
ü:
-.t
o
o
10
20
30
40
Time (min)
50
60
70
80
Page 6
; 04-16-2004; LoadCase Surtace Casing; Version wcs-cem44C51
.
.
SC~llDIbIPUIP
*
CemCADE well cementing recommendation for 95/8" Intermediate Casing
Operator
Country
State
UNOCAL
USA
: AK
Well
Field
Happy Valley #7
Happy Valley
Prepared for : Jerry Bowen Location Ninilchik
Proposal No. : #1 Service Point Kenai
Date Prepared : 04-16-2004 Business Phone (907) 776-8156
FAX No. (907) 776-8158
Prepared by
Phone
E-Mail Address
Chinedu F. Akwukwaegbu
(907) 273-1739
CAkwukwaegbu@slb.com
~GN
(,,«.,-c:,'
t
\ (\~.
~lIATE
Disclaimer Notice:
This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to
be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on
the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the
model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for
comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which
Schlumberger can assist in selecting.
The Operator has superior knowledge of the well. the reservoir. the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring
well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly.
Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time. equipment. and material ultimately
required to perform these services.
Freedom from infringement of patents of Schlumberger or others is not to be inferred.
* Mark of Schlumberger
.
Client
Well
String
Distri ct
Country
Loadcase
UNOCAL
Happy Valley #7
Intermediate Casing
Kenai
USA
Intermediate Casing (a)
Section 1: well description
Configuration
Stage
Rig Type
Mud Line
Total MD
BHST
Bit Size
: Casing
: Single
: Land
: 0.0 ft
: 4350.0 ft
: 92 degF
: 12 1/4 in
MD
(ft)
1032.0
Previous String
OD Weight
(in) (Ib/ft)
13 3/8 68.0
ID
(in)
12.415
Landing Collar MD : 4270.0 ft
Casing/liner Shoe MD : 4350.0 ft
MD
(ft)
4350.0
Casing/Liner
ID Grade
(in)
8.835 L-80
OD
(in)
9 5/8
Joint
(ft)
40.0
Weight
(Ib/ft)
40.0
Mean OH Diameter : 12.250 in
Mean Annular Excess : 20.0 %
Mean OH Equivalent Diameter: 12.710 in
Total OH Volume : 520.7 bbl (including excess)
Max. Deviation Angle : 38 deg
Max. DLS : 6.861 deg/100ft
MD
(ft)
4350.0
Formation Data
Pore Name
(psi/ft)
0.433
Frac.
(psi/ft)
0.700
MD
(ft)
Geothermal Temperature Profile
TVD Temperature Gradient
(ft) (degF) (degF/100ft)
0.0 80 0.0
1032.0 80 0.0
4016.4 92 0.3
4056.3 93 0.3
0.0
1032.0
4350.0
4400.0
; 04·16·2004; loadCase Intermediate Casing (a); Version w<:s-cem441_51
.
Collapse
(psi)
3090
Lithology
Sandstone
Sil..rler
Burst
(psi)
5750
Thread
Brc
Page 2
Client
Well
String
D istri ct
Country
Loadcase
.
UNOCAL
Happy Valley #7
Intermediate Casing
Kenai
USA
Intermediate Casing lal
.
Slilltllrgør
Section 2: fluid description
Mud DESIGN
Fluid No: 1 Density : 9.20 Ib/gal
Rhea. Model : BINGHAM Pv : 12.000 cP
At temp. : 80 degF Ty : 12.00 Ibf/100ft2
Gel Strength : (lbf/100ft2)
MUD
Mud Type :WBM Job volume : 323.8 bbl
Water Type : Fresh
Fluid No: 3
Rhea. Model
At temp.
Fluid No: 4
Rhea. Model
At temp.
: BINGHAM
: 80 degF
: BINGHAM
: 80 degF
DESIGN
BLEND
Name : G
Dry Density : 199.77 Ib/ft3
Sack Weight : 94 Ib
BASE FLUID
Type : Fresh water
Code
D046
D079
D167
S002
Additives
Cone.
0.200 %BWOC
2.000 %BWOC
0.800 %BWOC
0.750 %BWOC
Thickening Time
Compressive Strength
MUDPUSH " DESIGN
Density
Pv
Ty
Gel Strength
: 10.50 Ib/gal
: 16.000 cP
: 16.00 Ibf/100ft2
: (lbf/100ft2)
Job volume : 20.0 bbl
Lead Slurry DESIGN
Density
Pv
Ty
Gel Strength
: 12.80 Ib/gal
: 31.504 cP
: 33.84 Ibf/100ft2
: (Ibf/100ft2)
SLURRY __
Mix Fluid ~. . .06 gal/sk
Yield . 1.9 ft3/sk
Porosity . . . %
Job vOlume~. .6 bl
Quantity : 534 sk
Solid Fraction f : 25.3 %
Density : 8.32 Ib/gal
Base Fluid : 11.067 gal/sk
Function
ANTI FOAM
EXTENDER
FLUID LOSS
Accelerator
Schedule 9.4-,1
Schedule ( )
03:30 hr:mn
24:00 hr:mn
70 Be
922 psi
at
at
Page 3
; 04-16-2004; LoadCase Intermediate Casing (aJ; Version wcs-cem441_51
Section 3: fluid sequence
Original fluid Mud
pv : 12.000 cp
323.8 bbl
576.9 bbl
1032.0 ft
.
Client
Well
String
District
Country
Loadcase
UNDCAL
Happy Valley #7
Intermediate Casing
Kenai
USA
Intermediate Casing (al
Fluid No: 5
Rhea. Model
At temp.
: BINGHAM
: 80 degF
DESIGN
BLEND
Name : G
Dry Density : 199.77 Ib/ft3
Sack Weight : 94 Ib
BASE FLUID
Type : Fresh water
Additives
Code
D167
D065
D046
Cone.
0.400 %BWOC
0.300 %BWOC
0.200 %BWOC
Thickening Time
Compressive Strength
Displacement Volume
Total Volume
TOC
Name
Volume
(bbl)
5.0
20.0
188.6
39.5
323.8
Fresh Water
MUDPUSH II
Lead Slurry
Tail Slurry
Mud
.
Sillllrlep
Tail Slurry DESIGN
Density
Pv
Ty
Gel Strength
: 15.80 Ib/gal
: 72.013 cp
: 10.82 Ibf/100ft2
: (lbf/100ft2)
SLURRY
Mix Fluid
Yield
Porosity
Job volume ~. . I
Quantity : 91 sk
Solid Fractio : 41.4 %
Density : 8.32 Ib/gal
Base Fluid : 5.091 gal/sk
Function
FLUID LOSS
DISPERSANT
ANTI FOAM
Schedule 9.18-
4
Schedule ()
100 Be
at
04:38 hr:mn
2351 psi
at
18:30 hr:mn
9.20 Ib/gal
Ty: 12.00 Ibf/100ft2
Ann. Len
(ft)
83.7
334.8
2818.0
500.0
Fluid Sequence
Top Density
(ft) (Ib/gal)
613.5 8.32
697.2 10.50
1032.0 12.80
3850.0 15.80
0.0 9.20
Ty:16.00 Ibf/100ft2
T y:33.84 Ibf/100ft2
Ty:10.82Ibf/100ft2
Ty:12.00 Ibf/100ft2
Rheology
viscosity:5.000 cp
pv:16.000 cP
pv:31.504 cp
pv:72.013 cp
pv:12.000 cp
Static Security Checks:
Frac
Pore
Collapse
Burst
Csg.Pump out
210 psi
65 psi
2318 psi
5746 psi
47 ton
at 1032.0 ft
at 1032.0 ft
at 4270.0 ft
at 697.2 ft
Page 4
; 04-16-2004; loadCase Intermediate Casing (a) ; Version wcs-cem441_51
.
.
Client
Well
String
District
Country
Loadcase
UNDCAL
Happy Valley #7
Intermediate Casing
Kenai
USA
Intermediate Casing (a)
Sillllllrler
Section 4: pumping schedule
Pumping Schedule
Name Flow Rate Volume Stage Time Cum.Vol Inj. Comments
(bbl/min) (bbl) (min) (bbl). Temp.
(degF)
Fresh Water 5.0 5.0 1.0 5.0 80
Pause 0.0 0.0 5.0 0.0 80
MUDPUSH II 5.0 20.0 4.0 20.0 80
Pause 0.0 0.0 5.0 0.0 80
Lead Slurry 5.0 188.6 37.7 188.6 80
Tail Slurry 5.0 39.5 7.9 39.5 80
Pause 0.0 0.0 5.0 0.0 80
Mud 5.0 315.0 63.0 315.0 80
Mud 1.0 8.8 8.8 323.8 80
Total 02:17 576.9 bbl
hr:mn
Dynamic Security Checks:
Frac 111 psi
Pore 44 psi
Collapse 2318 psi
Burst 4970 psi
at 4350.0 ft
at 1032.0 ft
at 4270.0 ft
at 0.0 ft
BHCT
Simulated BHCT
CT at TOC
86 degF
80 degF
80 degF
Temperature Results
I Simulated Max HCT
Max HCT Depth
Max HCT Time
81 degF
3373.5 ft
00:06:00 hr:mn:sc
WELLHEAD PRESSURE
o
o
co
o
75
Tim e (m in)
125
150
ëii
Sg
Q.'<t
~
8
(")
o
o
~
o
Page 5
; 04-16-2004; LoadCase Intermediate Casing (a) ; Version wcs·cem441_51
.
.
Client
Well
String
District
Country
Loadcase
UNOCAL
Happy Valley #7
Intermediate Casing
Kenai
USA
Intermediate Casing (a)
Silllllrger
ECO
"L
~
o e p th = 4 3 50ft
..,.
or- -Frac
-Pore
Ilydrostatit:.
-- Dynamic
(YL
~
¡¡¡
.Q>
g
~
:Y~_
en ~
~
ct
¿
.ã: 0_
0>-
00
o
25
50
75
Tim e (m in)
100
125
150
FLOWRATE COMPARISON
0>
Fluids at 4350 ft
"2
·ê
]SLO
S-
a>
õí
C::..,.
~
ü:
o
25
50
75
Tim e (m in)
100
125
,
150
Page 6
; 04·16-2004; loadCase Intermediate Casing 1'1; Version wcs·cem441_51
.
.
ScblulJlbepger
*
Cern CAD E well cementing recommendation for 3.5" Production Casing
Operator
Country
State
: UNOCAL
: USA
: AK
Well
Field
Happy Valley #7
Happy Valley
Prepared for : Jerry Bowen Location Ninilchik
Proposal No. : #1 Service Point Kenai
Date Prepared : 04-16-2004 Business Phone (9071776-8156
FAX No. (907) 776-8158
Prepared by
Phone
E-Mail Address
Chinedu F. Akwukwaegbu
(907) 273-1739
CAkwukwaegbu@slb.com
~GN"
( <:J1y"':)
~
.,~
~
,
\~"4
'~lJATE .
Disclaimer Notice;
This Information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability tor advice or recommendations made conceming results to
be obtained from the use of allY product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on
the well. reservoir and treatment The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the
model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for
comparison purposes rather than absolute values. The quality of input data, and hence results, may he improved through the use of cel1ain tests and procedures which
5chlumberger can assist in selecting.
The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is awme of any conditions whereby a neighboring
well or wells might be affected by the treatment proposed herein it IS the Operator's responsibility to notify the owner or owners of the IVeil or wells accordlllgly.
Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment. and material ultimately
required to perform these services.
Fmedoll1 from infringement of patents of 5c"'umberger 01" others is not to be infened.
· Mark of Schlumberger
Client
Well
String
District
Country
loadcase
.
UNOCAl
Happy Valley #7
3.5
Kenai
USA
Production Casing (8)
Section 1: well description
Configuration
Stage
Rig Type
Mud Line
Total MD
BHST
Bit Size
MO
(ft)
4350.0
: Casing
: Single
: land
: 0.0 ft
: 12330.0 ft
: 181 degF
: 8 1/2 in
Previous String
00 Weight
(in) (lblft)
9 518 40.0
10
(in)
8.835
landing Collar MD : 12250.0 ft
Casinglliner Shoe MD : 12330.0 ft
MD
(ft)
12330.0
00
(in)
3 1/2
Casing/liner
ID Grade
(in)
2.992 L-80
Joint
(ft)
40.0
Weight
(Ib/ft)
9.2
Mean OH Diameter : 8.500 in
Mean Annular Excess : 20.0 %
Mean OH Equivalent Diameter: 9.179 in
Total OH Volume : 653.1 bbl (including excess)
Max. Deviation Angle : 38 deg
Max. DlS : 2.005 deg/100ft
MO
(ft)
7500.0
12340.0
MD
(ft)
0.0
1032.0
4400.0
12330.0
12340.0
Frac.
(psilft)
0.725
0.710
Formation Data
Pore Name
(psi/ft)
0.433
0.433
Geothermal Temperature Profile
TVD Temperature Gradient
(ft) (degF) (degF/100ft)
0.0 80 0.0
1032.0 80 0.0
4056.1 93 O~
10589.7 181 1.0
10599.4 181 1.0
.
Collapse
(psi)
10530
Lithology
Sandstone
Sandstone
HVj7 _RP./_#1.cfo.v; 04·16~2004; loa~Case Production CasiJ1tJ (a); V€Jf5ior. wcs-cC?m441_51
Scilllllrler
Su rst
(psi)
10160
Thread
MTC
Page 2
.
Clíent
Well
String
District
Country
loadcase
UNOCAl
Happy Valley #7
3.5
Kenai
USA
Production Casing (a)
Section 2: fluid description
cw 100 DESIGN
Fluid No: 2
Rhea. Model
At temp.
: NEWTONIAN
: 80 degF
Density
Viscosity
Job volume
MUDPUSH II DESIGN
Fluid No: 3
Rhea. Model
At temp.
: SINGHAM
: 80 degF
Density
Pv
Ty
Gel Strength
Job volume
LiteCRETE DESIGN
Fluid No: 4
Rhea. Model
At temp.
: BINGHAM
: 80 degF
Density
Pv
Ty
Gel Strength
DESIGN
BLEND
Name : 12# LiteCRET
Dry Density : 112.13 Ib!ft3
Sack Weight: 1511b
BASE FLUID
Type : Fresh water
SLURRY
Mix Fluid
Yield
Porosity
~.1.5.···· al/sk
. .4. t3/sk
: . %
Density
: 8.32 Ib/gal
Additives
Code Cone. Function
D047 0.161 gaVsk blend ANTI FOAM
D600G 2.415 gal/sk blend GASBLOK
D065 0.750 %BWOC DISPERSANT
D800 0.200 %BWOC RETARDER /
C359 0.025 %BWOC Viscosifier
Thickening Time Schedule 9.20- 100 Bc
2
Compressive Strength Schedule () 2863 psi
#4 Base Oil DESIGN
Fluid No: 5
Rhea. Model
At temp.
.
ScillllllPI8P
: 8.26 Ib/gal
: 5.000 cP
: 20.0 bbl
: 10.50 Ib/gal
: 16.000 cP
: 16.00 Ibf/100ft2
: (lbf/100ft2)
: 55.0 bbl
: 12.00 Ib/gal
: 92.092 cP
: 12.39 Ibf/100ft2
: (lbf/100ft2)
Job volume: ~6 .2 ~bl
Quantity :. 83 8 sk
Solid Fraction· . 55.0 %
Base Fluid : 5.739 gallsk
at 03:51 hr:mn
at 44:00 hr:mn
: NEWTONIAN
: 80 degF
Density : 7.40 Ib/gal
Viscosity : 4.000 cP
Job volume : 106.5 bbl
HV_#7 _REV_f.1.cf~v; 04~16·2004; loadCasc Pmduttion Casing (a); Vt)(SiOfi wcs-wm441_51
Page 3
.
.
Client
Well
String
District
Country
loadcase
UNOCAl
Happy Valley #7
3.5
Kenai
USA
Production Casing (a)
ScillllPgØP
Displacement Volume
Total Volume
TOC
Section 3: fluid sequence
Original fluid Mud
pv: 12.000 cP
106.5 bbl
746.8 bbl
4250.0 ft
9.501b/gal
Ty: 12.00 Ibf/100ft2
CW 100
MUDPUSH II
LiteCRETE
#4 Base Oil
Volume
(bbl)
20.0
55.0
565.2
106.5
Ann. Len
(ft)
312.9
860.4
8080.0
Fluid Sequence
Top Density
(ft) (lb/gal)
3076.8 8.26
3389.6 10.50
4250.0 12.00
0.0 7.40
Rheology
Name
viscosity:5.000 cP
pv:16.000 cP
pv:92.092 cP
viscosity:4.000 cP
Ty:16.00 Ibf/100ft2
Ty:12.39Ibf/100ft2
Static Security Checks:
Frac
Pore
Collapse
Burst
Csg.Pump out
901 psi
273 psi
7924 psi
10160 psi
34 ton
at 4350.0 ft
at 4350.0 ft
at 12250.0 ft
at 0.0 ft
Section 4: pumping schedule
Pumping Schedule
Name Flow Rate Volume Stage Time Cum.Vol (nj. Comments
(bbl/min) (bbl) (min) (bbl). Temp.
(degF)
CW 100 5.0 5.0 1.0 5.0 80 Fluid pack Jines
Pause 0.0 0.0 5.0 0.0 80 3-Pressure Test Lines
CW 100 5.0 15.0 3.0 20.0 80 5-Start Pumping Wash
MUDPUSH " 5.0 55.0 11.0 55.0 80 7-Start Pumping Spacer
Pause 0.0 0.0 1.0 0.0 80
LiteCRETE 5.0 565.2 113.0 565.2 80 9-Start Cement Slurry
Pause 0.0 0.0 5.0 0.0 80 36-Drop Dart
#4 Base Oil 5.0 60.0 12.0 60.0 80 19-5tart Displacement
#4 Base Oil 3.0 35.0 11.7 95.0 80 Slow down rate
#4 Base Oil 1.0 11.5 11.5 1 06.5 80 37-Bump Dart
Shut-In 0.0 0.0 20.0 0.0 80 38-Set Packer
Total 02:54 746.8 bbl
hr:mn
Dynamic Security Checks:
Frac 865 psi
Pore 230 psi
Collapse 7912 psi
Burst 7994 psi
at 4350.0 ft
at 4350.0 ft
at 12250.0 ft
at 0.0 ft
8HCT
Simulated 8HCT
CT at TOC
141 degF
144 degF
111 degF
Temperature Results
I Simulated Max HCT
Max HCT Depth
Max HCT Time
146 degF
11826.7 ft
02:54:14 hr:mn:sc
Page 4
HV_#7 _AEVj'1.cfw; 04·16~2004; loadCasc Pmduttiao Casing (a); Version wcs-<em441_51
.
.
Clíent
Well
String
Distri ct
Country
Loadcase
UNOCAL
Happy Valley #7
3.5
Kenai
USA
Production Casing (a)
Silll.rlor
WELLHEAD PRESSURE
ID
N
§
....
.ð.
~
~
100
Tim e (m in)
DIFFERENTIAL PRESSURE @ ZXP PACKER DEPTH:;; 4250'
N
..... - Collapse
eUrit
- Pseudo Hydrostatic
C>- - Dynamic
50 ft Fluì sat 251 ft
ô
8
.....
o
~
Æ:
Page 5
HVj·7_RHI_#1.dw; 04-16-2004: lOMCa50 Produc.tioo C'JlSIIlQ (a) ;VcrSIOJi wcs<~m44I_51
.
.
Client
Well
String
District
Country
Loadcase
UNOCAL
Happy Valley #7
3.5
Kenai
USA
Production Casing (a)
Scilmnnrgør
ECD
r(¡rr. +
~ Hydrostatie
..........-.... Dynamic \
~
Depth = 12330 ft
;!
--Frac
~
¡¡;
0>
ê
<I>
~ ~
UJ ~
:ß
ct
c::
<:
« ~~
(1)-..:.
o
20
i
40
60
.,.
80 100 120
Tim e (m in)
i
140
160
180
. ,
200
a)
FLOWRATE COMPARISON
CD -
Fluids at 12330 ft
Lt>
. .
II
~ ~
'it
:?
~ 1
ê. !
OJ <')
rn
a::
~
¡¡:
N
r
11 .0:
q /}
:~
........
..
....
nO__ ____0__
. .
. ".. . ~ ,
. ......................~...
. " "....'
.' . ......
····:·.····:·····:·.·.f·:···
. , ......
¡:/jl.
. ...
o
,.
100
Tim e (m in)
,
160
~L___;_j_··
180
U.._ I
200
o
Page 6
Hv_n_REV~*Lcf..\I, 04-16-2004. loadCa5C Produwoo Casmg ((I); VcrSIOJì wcs-cem44 _51
.
Client
Well
String
District
Country
loadcase
UNOCAl
Happy Valley #7
3.5
Kenai
USA
Production Casing (a)
.
Scilumlrgør
Section 5: centralizer placement
Top of centralization :4300.0 ft
Bottom Cent. MD :12310.0 ft
Casing Shoe :12330.0 ft
NB of Cent. Used :47
NB of Floating Cent. :47
Centralizer Placement
Bottom MD Nbr. Cent. I Cent. Name Code
(ft) Joint
12010.0 39 1/5 NW-PO-3 1/2-4-POT 9 W223
12330.0 8 1/1 NW-PO-3 1/2-4-POT 9 W223
Min. STO
(%)
@ Depth
(ft)
11980.4
12330.0
0.0
60.7
Centralizer Description
Cent. Name Code Casing Max. Min. OD Rigid
OD OD (in)
(in) (in)
NW-PO-3 1/2-4-POT W223 3 1/2 8.335 8.335 Yes
9
Centralizer Tests
Hole Size Running Restoring
(in) Force Force
(Ibf) (Ibf)
N.A. N.A. N.A.
Origin
Hannover
(1) - Centralizer performance data is based on tests by WEATHERFORD as per the current API 10D specifications
Running Force Calculations:
Travelling Block Weight
Friction Factor Centralizer/Formation
Total Drag Force
Hook load Down Stroke
Hook load Up Stroke
o
o
0-
1,0
:100 ton
:0.3
:10 ton
:132 ton
:152 ton
ft
%
0-
o
o
0-
o
o
0_
o
1,0
Pipe Standoff
Page 7
HV_'7_REVj:1.cfw; 04·16·2004; loadCasc Produc.tiao Casing la) ;Versiofo wcs<em441_51
.
Client
Well
String
Oistri ct
Country
Loadcase
UNOCAL
Happy Valley #7
3.5
Kenai
USA
Production Casing (a)
Section 6: WELLCLEAN II Simulator
fI
%
0-
o
o
0-
\0
o·
o
0-
o
o
o
0-
\0
Cement Coverage
Fluids Concentrations
Risk Mud on the Wall
it
Õ
2
it it õ it
2
I
:,QoCO 500D. :,QoCO
GI)OO 60000 GI)OO
7000 7001} 7000
,. ,.
110000 .! BOOD 110000 .!
01: 01:
>- 91)00 ;; 90000 ;;
. 9000 .
; ;
, >- 1 0000 10000 10000
'-11(100 11(100
.' 1~OOQ ~ 1 ~OOQ
.. ..
'e 'e
;i ;i
BOOD
90000
500D
~¡
60000
7001}
10000
11 ()OO
12000
..
'e
;i
J
"
"
z
_ #4 Base Oil
II ~~5~51~ II
_ CW100
_ High
_ Medium
_ Low
I;;;~W;;;~ None
.
HV37_RE\Cf1.cfw; 04~16-2004; loadCasc Prodoction Casing (a) ;Vt1r5iof' wcs<em44-'_51
s
IPI8P
Page 8
22'6"
or
270"
..
..
Ground Level
w/
Drilling spool to be
replaced by tubinghead 8.
DSA after 9 51S" casing
cemented
Iwi:.
13 3/8" SOW
Bradenhead
(starter) wellhead
F
I4;J
133/6" outlet
18 5/8" non-structural
conductor pipe, to be cut
above cellar floor after ~
cementing 9 5/8"
2" thick base alate ~
I·
11
9'0"
2' Skid Base
(' Mol· ~
"""
"
8'
or
96"
'"
12·
Choke
5,000 I Choke IVBnifold
Kuukpik Hing 5
.
.
Happy Valley Cuttings Disposal Description for Permit to Drill /
The drilling muds and cuttings from the Happy Valley #7 Well will be ground and
injected into the NNA #1 annulus, into the perforations in the tubing in accordance with
an AOGCC approved test plan for the perforations in the tubing, or into the tubing and
perforations of the NNA #1 Well should that well achieve permitted Class II injection
status during the Happy Valley drilling operations. Permission for the annular disposal
has already been secured from the Alaska Oil and Gas Conservation Commission
(AOGCC) and is being currently sought for the tubing-related disposal options.
The cuttings will be transported to the NNA #1 pad with the grinding to occur at the
NNA #1 pad.
Unocal Alaska does not intend at this time to request authorization under 20 AAC 25.080
for an annular disposal operation in the Happy Valley #7 well. In the event that a
problem develops such that Unocal is unable to inject drilling waste into the NNA #1
well the possibility exists that Unocal may then request authorization for annular disposal
into one or more of the other Happy Valley Wells.
DeepCreek Salinity Calculations
Calculations Method #1 - SP
Ü$.è:R~Q;fi*fitffi:;: .:;:;:;:;:;:::;:;:;;::::;: F~;:;:;~;t;::::;:;:;:::::;:;:;::; ;;;::;:;:::::::::::~li::::¡:::;:::;~¡:;:;:;¡ ;1::::);:;:;:;:;:1 ::::;:::¡:::;:¡;)::::::::;:::r~:;.::::::::::::::::::::::;::Q1ät"t::;:;':::;:::;:;:;:::;:;:;:
LOG HEADER: 80.00 5.00
15-2S-13W Deep Ck 1 Sterling 123 22 175 270 0.0066 75.86 62.447 4.84
15-2S-13W Deep Ck 1 Sterling 580 18 80 110 0.0066 78.86 62.797 4.67
15-2S-13W Deep Ck 1 Sterling 600 15 70 80 0.0066 78.99 62.812 4.67
15-2S-13W Deep Ck 1 Sterling 825 22 44 42 0.0066 80.46 62.984 4.59
15-2S-13W Deep Ck 1 Sterling 1120 22 28 36 0.0066 82.40 63.21 4.49
15-2S-13W Deep Ck 1 Sterling 1480 30 18 19 0.0066 84.76 63.485 4.37
15-2S-13W Deep Ck 1 Sterling 1700 30 17 15 0.0066 86.20 63.654 4.30
15-2S-13W Deep Ck 1 Sterling 2220 30 12 12 0.0066 89.61 64.052 4.15
15-2S-13W Deep Ck 1 Beluga 2550 52 22 17 0.0066 91.78 64.304 4.06
15-2S-13W Deep Ck 1 Beluga 2810 45 29 19 0.0066 93.48 64.503 3.99
15-2S-13W Deep Ck 1 TD 12953 0.0066 160.00 72.263 2.40
2.97
2.95
2.95
2.95
2.94
2.92
2.92
2.90
2.89
2.88
2.6
1 .456
1.654
1.822
1.453
1.452
1.125
1.125
1.125
0.563
0.703
4000
3000
2800
3800
3900
4600
4600
4300
8000
6500
.
Deep Creek Salinity Calculations
Method #2 Rwa
Use Rmf=0.61 Rm Form. Depth Porosity Geo. F Hdr Rwa Method #2
Location Well Top MD SP Elan Rt Grad t K Rm Rmf Method #2 Salinity ppm Chi
LOG HEADER: ' ...;Qt). S..
15-2S-13W Deep Ck 1 Sterling 123 22 0.32 270 0.0066 75.86 7.7755 62.45 1.12 2.97 34.72 freshwater
15-2S-13W Deep Ck 1 Sterling 580 18 0.32 110 0.0066 78.86 7.7755 62.80 1.12 2.95 14.15 freshwater
15-2S-13W Deep Ck 1 Sterling 600 15 0.3 80 0.0066 78.99 8.7334 62.81 1.05 2.95 9.16 800
15-2S-13W Deep Ck 1 Sterling 825 22 0.28 42 0.0066 80.46 9.8882 62.98 0.98 2.95 4.25 1200 e
15-2S-13W Deep Ck 1 Sterling 1120 22 0.15 36 0.0066 82.40 30.411 63.21 0.44 2.94 1.18 5000
15-2S-13W Deep Ck 1 Sterling 1480 30 0.18 19 0.0066 84.76 21.903 63.49 0.57 2.92 0.87 5800
15-2S-13W Deep Ck 1 Sterling 1700 30 0.2 15 0.0066 86.20 18.119 63.65 0.65 2.92 0.83 6000
15-2S-13W Deep Ck 1 Beluga 2220 30 0.22 12 0.0066 89.61 15.263 64.05 0.74 2.90 0.79 6100
15-2S-13W Deep Ck 1 Beluga 2550 52 0.15 17 0.0066 91.78 30.411 64.30 0.44 2.89 0.56 8000
15-2S-13W Deep Ck 1 Beluga 2810 45 0.13 19 0.0066 93.48 39.346 64.50 0.35 2.88 0.48 9500
TD 12953 0.0066 ·100.01 72.26 2.40 2.6
- - ----------------------------:=J
Deep Unit #1 Calculations
10000
9000
8000
7000
6000
5000
4000 -
3000
2000
1000
0
0 500 1000 1500 2000 2500 3000
Depth
·
e
I Halliburton BAROID
UNOCAL
Mud Program
UNOCAL
Happy Valley #7
Kenai Peninsula, Alaska
Baroid Mud Program
Halliburton
Baroid
Name (Printed)
Signature
Date
Originator
Dave Higbie
Reviewed by
Don Shaw / John Rose
Customer Approval
Jerry Bowen
Version No:
Date:
1.0
April16,2004
HV #7 v1.0
04/16//04
.
.
I Halliburton BAROID
UNOCAL
Mud Program
Happy Valley Producer
Introduction:
The following mud program was prepared for a deviated well accessing the Tyonek gas sands as part of
the Happy Valley development program on the Kenai Peninsula, Alaska. This well will be spudded with a
6% KCI drilling fluid and drilled vertically to the 1,032' MD range. It will be drilled with in a 16" hole size
and cemented. The surface casing will be drilled out with the existing mud system. The 12 ~" interval will
then be drilled building to 36° to 37° angle by section TD of 4350' MD. 9 5/8" casing will be run and
cemented at this depth. The well will then be displaced to an INVERMUL system, the 9 5/8" will be drilled
out and a leak off performed. An 8 %" hole will be directionally drilled (max hole angle of 38°) dropping to
14° by TD at 12,330' MD (-10,590' TVD). A 3 %" production liner will then be run and cemented in place.
Spud the well with a 6% KCI/PHPA mud - 8.6 ppg. The mud weight will then be held in the 8.6 - 8.9 ppg
mud weight range to the surface hole TD unless hole conditions dictate otherwise. Our primary focus for
surface hole drilling operations will be adequate mud weight for well control and sufficient mud viscosity
for efficient hole cleaning. This spud mud is formulated with two mechanisms to provide waste
minimization and effective wellbore stabilization, ionic inhibition (KCI), and polymer encapsulation (PHPA).
This same 6% KCI/PHPA mud will be maintained through the intermediate interval. This mud offers good
LCM responses if losses are encountered. Special emphasis should be placed on maintaining low ECD's
and surge/swab pressures to minimize the potential for lost circulation.
The production interval will begin with an 80/20 OWR (if available) used oil base fluid. The ratio will then
slowly be raised to 90/10 by 10,000' to reduce rheological parameters. CaCllevels will be maintained in
the 29-32% (290,000 - 320,000 ppm WPS) range. The mud weight will be held in the 9.2 -9.6 ppg range
or as required for hole stability.
Primary DrillinQ Obiectives:
· Zero fluid related HSE incidents
· Achieve well bore stability
· Achieve good hole cleaning considering hole angle, geometry and anticipated Rap rates
· Lost circulation mitigation/control
· Achieve good Zonal Isolation as per plan
· Achieve minimal formation damage in Tyonek sands
· Minimize fluids related NPT
· Minimize drilling wastes
Critical Fluid Issues:
· Eliminating/controlling losses in the 1,700' and 4,100' areas.
· Maintaining a low ECD in the production zone to reduce risk of lost returns.
· Maintaining a stable wellbore through coal seams.
· Reducing drilling wastes with the inhibited drilling fluid system.
HV #7 v1.0
'1
""
04/16/104
.
.
I Halliburton BAROID
UNOCAL
Mud Program
Well Specifics:
Casing Program
HV#3
16" hole (13 3/8" casing)
12 W' hole ( 9 5/8" casing)
8 %" Hole (3 %" liner)
MD TVD Foota~e
1032' 1032" 1032'
4350' 4016' 3318'
12,330' 10,590' 7980'
Surface Hole Recommendations
Mud Type: 6%KCI, EZ Mud
Properties:
0-1032'
Densitv Viscosity
8.6 - 8.9 60 - 85
Plastic Viscosity
6 - 16
Yield Point
35 - 45
API FL
N/C
I!.!:!
8.5-9.0
System Formulation: 6%KCI, EZ Mud
Product Concentration
Water 0.905 bbl
KCI 20 ppb (30K chlorides)
KOH 0.2 ppb (9 pH)
Barazan D 1.5 -2 ppb (as required 35-45 YP)
EZ Mud DP 0.75 ppb
Aldacide G 0.1 ppb
Baracor 700 1 ppb
Barascav D 0.5 ppb (add as the well spuds)
Special Mixing Instructions:
. Mix in order as listed
. Add polymers slowly to minimize fisheyes.
Concerns and Continaencies
Surface Interval - ( 0 - 1,032' MD )
Mud Type:
1. Mud weight:
2. Rheology:
3. Filtrate control:
6 % KCI/PHPA
Maintain the 8.6 - 8.9 ppg density or as directed.
Maintain a YP between 35 - 45 or as needed to achieve adequate hole cleaning..
No filtrate control is required prior to reaching 1032' MD. Additions BOF-263 may be required
to control screen blinding/bit balling. Seepage losses in this interval can be controlled with
additions of 3-5 ppb BAROFIBRE or by dedicated LCM pills but are unlikely to occur.
Operations Summary:
This section will drill a 16" hole. Build the 6% KCI fluid in the proper order of addition. Always maintain a
reduced pit volume during spud as losses are not expected in this section. Be prepared for sloughing
gravels in the upper interval; increasing the system rheology with BARAZAN-D/N-Vis will assist in bringing
this material out of the well, as will pumping dedicated high-viscosity sweeps. It is recommended that the
pump rate be increased to the maximum practical rate while the hole is unloading gravel.
Sweep Formulation: 30 barrels mud (500' annular coverage), add ca. 1.0 ppb BARAZAN 0 to achieve a tauO > 25.
HV #7 v1.0
3
04/16//04
.
.
I Halliburton BAROID UNOCAL
When penetrating high-clay content sections additions of BDF-263 ester
incidence of bit balling and shaker blinding.
Mud Program
are recommended to reduce the
This well is a larger borehole than the other Happy Valley wells to date. Modeling shows that it will be
more difficult to clean. Maintain a minimum 35 YP at all times. Be prepared to increase the YP if hole
cleaning becomes an issue. Run DFG (Drilling Fluid Graphics) to confirm hole cleaning efficiency based
on current rheology, flow rates and cuttings size.
At TD, a Wallnut "flag" (20 bbl pill with 15 ppb of Wallnut M) should be pumped to gauge hole washout
and to calculate the required cement volume. The cement will then be pumped and drilling mud will be
used to bump the plug. Pretreat this chase mud with 1 ppb Bicarb and 0.5 ppb citric acid.
Hazards I Concerns - Surface Interval:
· Preventing lost circulation through ECO management.
· Optimize solids control equipment to maintain density, sand content, and reduce the waste stream.
· Maintain YP between 35 - 45 to optimize hole cleaning and to control ECO.
· Pump high viscosity sweeps to enhance hole-cleaning efforts. Monitor sweep effectiveness.
· Successfully cement casing.
Maximum Acceptable ROP in fph at Specified GPM and RPM
GPM~ 550 600 650
80 rpm 110 120 170
100 rpm 110 120 170
Baroid's recommended flowrate for this interval is 650 gpm to maximize hole cleaning at these penetration
rates. RPM's have no effect on hole cleaning in this vertical section. Hole cleaning is made more difficult
in this increased hole size. Of interest: a step-change benifit is realized when increasing the flow rate
from 600 to 650 gpm.
.Intermediate Hole Recommendations
Mud Type: 6%KCI, EZ Mud
Properties:
1,032 - 1500'
1500 - 4350'
Densitv
8.7 -8.9
8.8-9.2
Viscosity
40-53
40-50
Plastic Viscosity
6 - 15
6 - 15
Yield Point
15 - 25
15 - 25
API FL
N/C
8-10
R!:1
8.5-9.0
8.5-9.0
System Formulation:
Product
Water
KCI
KOH
Barazan D
Dextrid
EZ Mud DP
Aldacide G
6%KCI, EZ Mud
Concentration
0.905 bbl
19.8 ppb (30K chlorides)
0.2 ppb (9 pH)
1.25 ppb (as required 35 YP)
1-2 ppb
0.75 ppb
0.1 ppb
HV #7 v1.0
4
04/16//04
.
.
I Halliburton BAROID
I Baracor 700
Barascav D
UNOCAL
11 ppb
0.5 ppb (maintain per dilution rate)
Mud Program
I
Special Mixing Instructions:
. Mix in order as listed
. Add polymers slowly to minimize fisheyes.
Concerns and ContinQencies
Intermediate Interval- (1032 - 4350' MD)
Mud Type: 6 % KCI/PHPA
1. Mud weight:
2. Rheology:
3. Filtrate control:
Maintain the 8.8 - 8.9 ppg density or as directed.
Maintain a YP between 13-20 or as needed to achieve adequate hole cleaning.
No filtrate control is required prior to reaching 1500' MD. At this point add Dextrid and/or Pac
L to reduce filtrate to the 8-10 cc/30 min range. Additions of BDF-263 may be required to
control screen blinding/BHA balling. Losses in this interval can be controlled with additions of
1-2 ppb BAROFIBRE and 1-2 ppb of Baracarb 50 or by dedicated LCM pills; see appendix
for LCM decision tree.
Operations Summary:
Drill out the cement/casing with the existing mud system. Bicarb or soda ash and citric acid should be
used to pretreat for any negative effects of the cement. BARAZAN-D/N-Vis should be used to maintain
rheological parameters. The rheology will need run towards the high side of the specified range in this
large diameter well bore. Maintain the mud as clean as possible while drilling. Should sweeps be required
a BAROLlFT sweep is recommended (check with the G&I plant to ensure compatability). This sweep will
help clean the hole with no neqative impacts on system mud weiqht or rheoloqy. Daily additions of X-Cide
207 should be made to control bacterial action.
Sweep Formulation:
pumping.
25 bbl of mud with 0.25 ppb of Barolift added. Shear thouroughly prior to
Dextrid and/or PAC L should be used for filtrate control past 1,500'. While drilling, monitor the torque and
drag to determine if liquid lubricant is required. When penetrating high-clay content sections additions of
BDF-263 ester are recommended to reduce the incidence of bit balling and shaker blinding. Maintain the
pH in the 8.5 - 9.0 range with caustic soda.
By -1500' TVD the system rheology may be relaxed as hole conditions allow. This will also lower the
ECD for the loss zone found -1,700' TVD. However, be prepared to increase the YP if hole cleaning
becomes an issue. Run DFG (Drilling Fluid Graphics) to confirm hole cleaning efficiency based on current
rheology, flow rates, angle and cuttings size.
At 1,650' begin stringing in 1-2 ppb of BAROFIBRE and 1-2 ppb of Baracarb 50 (10-15 sx/hr each). This
material will help seal any mini fractures or small vugs as they are drilled. Premixing -60 sx of Baracarb
50 and Barofibre in the "coil" tank and then stringing this mixture in has worked well on HV 3, 4 and 5.
This treatment should be maintained until -1,850'. Also, ensure that the mud weight is maintained as low
as possible through this area. Stress slow pipe movement to the drillers to reduce surge/swab on this
fragile zone. Stage pumps on slowly after connections and begin rotation prior to pumping (this will break
the gels and reduce the pressure required to break the gels). Should all these efforts fail and losses
occur, please refer to the LCM decision tree appendix. If the losses are still high (above 30 bbl/hr static)
after attempting an LCM pill, STOP running the fluid as a KCI/EZ Mud system. All additions of these
products should be halted and allow the system to slowly break back to an LSND system. Run the fluid
HV #7 v1.0 :' 04/16//04
.
.
I Halliburton BAROID UNOCAL Mud Program I
loss and rheology as with the inhibited system. When running the LSND, stop addtions of Baracor and
Barascav D when the chlorides drop below 6,000 ppm's. If any trips are required, consider spotting a 20
bbl, 20 ppb pill across the 1,700' zone. The pill should consist of base mud with 10 ppb Baracarb 50 and
10 ppb STEELSEAL added. This pill would reduce the effects of tripping back in and allow time for the
LCM to "soak" into the zone. STEELSEAL and Baracarb will not dehydrate the mud which will allow for
lower ECD's on the first bottoms up after TIH. Losses were incurred at - 4,100' TVD on HV #5. All pit
monitoring devices should be watched closely as this zone is cut.
Maximum Acceptable ROP in fph at Specified GPM and RPM
GPM- WO WO
100 rpm 100 110
120 rpm 115 140
Baroid recommends a flowrate in the 550-600 gpm range to maximize hole cleaning efficiencies at these
high penetration rates. There is a large drop in efficiency if the rpm drops from 120 to 100. However if
losses occur, the flow rate can be reduced in conjunction with a slower penetration rate which would
reduce the ECD/losses.
Reduce system YP with Therma Thin as required for running casing as allowed (do not jeopardize hole
conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology
once the casing is landed to a YP < 20 ( check with the cementers to see what yp value they have
targeted). Consider spotting the above Steelseal LCM pill prior to running the 7" casing if losses have
been seen in this interval. The plug will again be bumped with mud on the well. If operations allow, the
plug can be bumped with OBM.
Hazards I Concerns - Intermediate Interval:
· Preventing lost circulation in the 1,700' and 4,100' TVD ranges.
· Optimize solids control equipment to maintain density and sand content.
· Maintain YP between 15-25 to optimize hole cleaning and to control ECD.
· Pump high viscosity or Barolift sweeps to enhance hole-cleaning efforts. Monitor sweep effectiveness.
. Successfully land and cement casing.
Production Hole Recommendations
System Formulation
Product
Base Oil
EZ MUL NT
INVERMUL
GEL TONE V
Lime
DURATONE
RM63
Water
CaCI2
AK-70
BAROID
HV #7 v1.0
Concentration
0.696 bbl
4 ppb
4 ppb
4 ppb
5 ppb
4 ppb
0.5 ppb
0.178 bbl
24.6 ppb
4 ppb
to a 9.2 ppg
6
04/16//04
.
.
I Halliburton BAROID
UNOCAL
Mud Program
Mud Type: Invermul System
Mud Properties
Density Viscosity PV YP ES HTHP FL WPS O/W
4350 -10,000 8.9 - 9.2* 55-80 18 - 29 9-18 1 000- <8 290 to 320K 80/20
1100
10,000- TD 9.2 * 55 - 80 18 -29 9 - 18 1000- <5 290 to 320K 90/10
1100
. Additional mud weight may be required for effective coal or shale stabilization.
System Formulation
Product
Base Oil
EZ MUL NT
INVERMUL
GEL TONE V
Lime
DURATONE
RM63
Water
CaCI2
AK-70
BAROID
Concentration
0.696 bbl
4 ppb
4 ppb
4 ppb
5 ppb
4 ppb
1 ppb
0.178 bbl
24.6 ppb
4 ppb
to a 9.2 ppg
Concerns and ContinQencies
Production Interval (8 %" hole. 3.5" casinQ ): 0 to 12,330' MD
Mud Type:
1. Mud weight:
9.2 ppg INVERMUL System.
2. Rheology:
Maintain the density at 9.2 ppg or as directed; use solids control and whole mud dilution.
Increase density as required for hole stability/coal sloughing. Maximize solids control usage.
Maintain a YP between 9 and 18. Pump high viscosity or Barolift sweeps throughout the
interval as needed, particularly prior to POH for casing. Optimized mud rheology and flow
rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore.
Maximize pipe rotation (ideally ~ 100 RPM).
3. Other issues:
The use of good drilling practices to minimize excessive swab and surge pressure should be
employed to minimize the chances for losses and differential sticking. By 10,000 feet reduce
the HTHP to < 5 cc 30 min with DURA TONE HT/AK-70 treatments. Please see the Coal
Drilling recommendations attachment.
Operations Summary:
The water base mud system will be used to drill out the shoe and ca. 20 feet of new hole (unless
operations can be worked out to bump the plug with the Invermul). Approximately 600 bbls of oil mud will
be required for displacement. Used mud is available so it will be reconditioned at the rig and displaced
into the well bore. Prepare the pit system for the INVERMUL as follows:
· Clean pits, solids control equipment, all lines and pumps.
· Flush all lines with a small volume of oil and discard.
· Disconnect all water lines to the pit area and rig floor.
· Check all steam fittings in pit room for leaks and repair as needed.
HV #7 v1.0
7
04/16//04
.
.
I Halliburton BAROID UNOCAL Mud Program
Once the shoe has been drilled, displace the well to the ENVIROMUL system designated for this interval
of the well. Pump a 25 bbl spacer ahead of the oil mud as follows:
Spacer Formulation:
· 20 barrels of the OBM treated with GEL TONE to a YP > 30 (app. 4-6 sx). Weight this pill
to 2 ppg over the OBM weight.
· Follow with INVERMUL mud system.
Displacement procedure:
· Monitor pump strokes to obtain correct displacement.
· Maintain maximum pump rates.
· Have the bit on bottom as the oil mud exits the bit.
· Reciprocate the drill string by one joint every 15 minutes
· Rotate the pipe as rapidly as allowed during the actual displacement.
· Do not shut down during the displacement.
· Use an E.S. meter at the flow line to determine when the fluid is water free enough to start
taking the returns back into the system. An ES of 300-500 should be sufficient to indicate
when displacement is complete. A retort should also be run at this time to confirm fluid
quality.
· Clean possum belly and any troughs which were used.
Maintenance:
1. Additions of Geltone V and RM-63 will maintain/modify the system rheology to a YP between 9 and 18
to provide effective hole cleaning while controlling ECD and surge/swab pressures. Run the rheology
checks at flowline temp until-6800' then at 120°F to TD. This will give a more accurate reflection as
to the rheology the hole is experiencing.
2. OMC 2 and OMC 42 will be available to condition (thin) the mud as required; however, caution should
be used when using these oil mud thinners (particularly the OMC-2) to avoid over-thinning the system.
3. Drill this interval with a tight DURA TONE HT / AK-70 filtration mechanism « 8 cc/30 min @ 2000 F to
10,000' then <See/3D min @ 2000 to TD). Barablok and Barotrol will also be available to improve the
filtration control mechanism.
4. For formation bridging/LCM, graded calcium carbonate (Baracarb(s)), cellulose fiber material
(Barofibre) and SteelSeal are available.
5. The electrical stability of the mud should be run in the 1000-1100 volt range with INVERMUL and EZ
MUL as the primary and secondary emulsifiers. DRIL TREAT will be available as an effective wetting
agent, if needed.
6. Maintain the water phase salinity between 290,000 - 320,000 mg/I range with sack calcium chloride.
This level of salinity will provide an effective mechanism for good wellbore stabilization.
7. The excess lime content will be maintained in the 3 ppb range to provide an effective reserve alkalinity
source and to improve the emulsion stability of the mud system.
8. The initial oil:water ratio will be 80:20. However if the O/w ratio is higher in the used mud do not adjust
it down. From there, the system will be maintained with base oil allowing the ratio to drift to the 90: 1 0
range by 10,000'. This will help reduce the cost of the original fluid and then help control rheology/ECD's
with the 90: 10 ratio in the lower depths of the well.
Suggested Drilling Parameters
HV #7 v1.0
8
04/16//04
.
.
I Halliburton BAROID UNOCAL Mud Program I
Pump rate and drill string rotation should be optimized through the real-time use of the DFG software for
the actual Rap while drilling. The table below highlights the maximum Rap recommendations above
which hole cleaning will become an issue.
Maximum Acceptable ROP in fph at Specified GPM and RPM
GPM~ 450 500 590
80 rpm 120 140 150
100 rpm 160 175 200
Rap rates above these levels or with no (sliding) or low rpm will require an increased frequency of the
following remedial hole cleaning practices:
· wiper trips
· back reaming
· extended periods of circulation (with maximum pipe rpm, targeting ~ 100 rpm)
· hole cleaning sweeps (change flow regime of base mud by using fibers, density or rheology
for carrying capacity)
· connection practices - employing extended gpm, rpm and back reaming during the connection
Sweeps
Two types of hole cleaning sweeps can be used:
. Increase the sweep density with SWEEPWATE to 2 ppg over system density. The SWEEPWATE
will increase the sweep carrying capacity yet will be removed at the shakers; this will result in no
density increase from running weighted sweeps.
. To reduce the density/viscosity build up in the system, sweeps can be built by adding 0.25 ppb
BAROLlFT in place of the clay. The fibrous BAROLlFT will be removed at the shakers.
Note: Properly size all sweeps for 300 - 400 ft of annular coverage
Supplement the hole cleaning of the drilling fluid as dictated by hole cleaning indications. Monitor all
sweeps pumped and report on their effectiveness. Maximize drill pipe rotation at high rates on a frequent
basis (particularly during connections) to assist in disturbing any potential cuttings accumulations down-
hole. The objective of the sweep is to change the flow characteristics / carrying capacity that is inherent
with the mud system. Select sweep type accordingly.
Coal Drilling
The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The hole
stability risks when drilling coal seams are often high, and the fluid design and drilling operations have
been optimized to combine reduced risk with reduced costs. The need for good planning and drilling
practices is also emphasized as a key component for success.
· Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections.
· Use asphalt-type additives to further stabilize coal seams.
· Increase fluid density as required to control the running coal.
· Emphasize good hole cleaning through hydraulics, Rap and system rheology.
In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the
coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not
to exceed the total annular pressure loss ( based on ECD values using the DFG software). System
density increases can also be employed in increments of 0.5 ppg.
Solids Control Equipment
Maximize the use of all solids control equipment to ensure that the solids content of the system is kept to
a minimum during this interval.
HV #7 v1.0 9 04/16/104
.
.
I Halliburton BAROID UNOCAL Mud Program
1. Run the shale shakers with as fine a screen size as possible.
. Size shakers screens with coarse mesh initially
. Adjust screen size as solids loading, mud rheology and flowrates allow
· Inspect the shakers frequently, taking time to repair / replace damaged screens
2. Maximize the use of the centrifuge, keeping the fluid as clean as possible.
Running Casing I Cementing Preparation
Monitor hole fill/returns closely while running the liner to insure losses haven't occurred. Refer to Baroid's
DFG+ program if calculated surge/swab values are needed. Condition the mud prior to the cement job.
Displace the cement with base diesel oil - ensure availability.
Production Hole - Hazards I Concerns:
· Optimize solids control equipment to minimize colloidal solids build up and dilution requirements.
· Maintain flow profile based on PV, YP and tauo flow parameters.
· Pump sweeps as required to enhance hole-cleaning efforts. Monitor the effectiveness of any sweeps
pumped. No sweeps have been needed in this hole section to date.
· Follow the hole cleaning guidelines to assist in drilling parameter selection. Use connections for high
RPM and pump rate support when these parameters are limited during drilling operations.
· Follow the coal drilling guidelines.
Estimated Fluid Costs :
16" Surface 24,000
12 y,¡" Intermediate 28,000
8 Yz" Production (Oil) 46,000
Total $98,000
**The P-50 estimate assumes 800 bbls of reconditioned oil mud to be used.
37,000
61,000
66,000**
$164,000
54,000
89,000
175,000
$318,000
HV#7 v1.0
04/16//04
10
.
I Halliburton BAR OlD
Losses UNOCAL Lost Circulation Decision Tree f/lnhibited Mud Systems
~ + + +
Seepage Partial Severe Total
15·60 bbllhr
5·10 bbllhr Static Static 60·200 bbllhr Static > 200 bbllhr Static
+ + . . ~
I Treat Active System I I Treat Active System I 160-150 bbl/hr Static I 1150-200 bbl/hr Static I Drill Across Fault
with 5 sxlhr Barofibre with 10 sxlhr Barofibre
t t t
I Drill Across Fault I I Drill Across Fault I Pump Gunk Squeeze
+ pill to allow POH
Yes 100 ppb LCM/Mud Pill: (Volume to be
~ Yes 20 ppb Baroseal F . determined based
~ 20 ppb Baroseal M upon losses
30 ppb Barofibre I Contact Drilling Engineer I +
I Drill Ahead I I Drill Ahead 20 ppb Wallnut M or Engineer on call
No 10 ppb Wallnut F Contact Drilling
II'~ lfM,<II111> I No ~ Engineer or Engineer
. on call
5 sxlhr Barofibre 70 ppb LCMlMud Pill: I Contact Drilling Engineer or I ., +
5 ixlhr Sf2carb 50 Engineer "On Call"
20 ppb Baroseal F Pump Gunk POH, PU dumb iron I
20 ppb Baroseal M Squeeze pill BHA
20 ppb Barofibre (Volume to be ~
10 ppb Wall nut M determined based
Yes
~ upon losses)
Consider cement I
I Drill Ahead I
No plug back contingency
y
40 ppb LCMlMud Pill: .
Yes
10 ppb Baroseal F t Pump Gunk
10 ppb Baroseal M Drill Ahead I Squeeze pill
10 ppb Barofibre No
10 ppb Wallnut M .
Contact Drilling ( '\
Engineer or Engineer Notes:
on call to determine if
additional LCM 1) Drill across fault or loss zone 1.5 - 2.0 times the length of the
Yes throw before spotting Gunk Squeeze.
~ treatments are to be 2) PBl sub should be run in BHA to spot pills if 'Partial Loss' cases or
made or to proceed to above are anticipated prior to drilling to allow the spotting of lCM
I Drill Ahead I Gunk Squeeze pill pills.
3) lCM ~II volume = 300'-600' column based upon actual hole
No diameter
, 4)PRIOR TO ANY lCM Pill, APPROPRIATE DISCUSSIONS AT
Proceed to 'Partial THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR
Losses' Pill PLUGGING THE DRill STRING.
\ /
HV #7 v1.0
04/16/104
.
UNOCAL
Mud Program
11
I Halliburton BAROID
Losses
+
Seepage
5-20 bbUhr Static
,
Treat Active System
with 5 sxlhr Baracarb
50/150
Yes
¡
I Drill Ahead I
No
,
Increase Treatment to
10 sxlhr Baracarb 501
150
,
No
,
Yes
~
I Drill Ahead
20 ppb LCM/Mud Pill:
20 bbls base mud
10 ppb Baracarb 50
10 ppb Baracarb 150
Yes
+
I Drill Ahead I
No
,
Proceed to 'Partial
Losses' Pill
HV #7 v1.0
04/16//04
.
UNOCAL
.
Mud Program
UNOCAL Lost Circulation Decision Tree fl Payzone Mud Systems
+
Partial
20-60 bbl/hr
Static
,
Treat Active System
with 10 sxlhr Baracarb
150
Yes
+
I Drill Ahead I
No
,
50 ppb LCM/Mud Pill:
20 bbls Base mud
10 ppb Baracarb 25
20 ppb Baracarb 50
20 ppb Baracarb 150
Yes
t
I Drill Ahead I
No
,
Contact the Engineer
on call to determine if
additional LCM
treatments are to be
made or to proceed to
reverse gunk squeeze
pill
Severe
60-200 bbl/hr Static
+
. .
160-150 bbl/hr Static I 1150-200 bbl/hr Static I
t t
1 Drill Across Fault I I Drill Across Fault I
+ +
100 ppb LCMlMud Pill:
20 ppb Baroseal f
20 ppb Baracarb 50
30 ppb Barofibre
20 ppb SteelSeal
10 ppb Baracarb 150
+
I Contact Drilling Engineer or I
Engineer "On Call"
.
Pump reverse
gunk squeeze pill
(Volume to be
determined based
upon losses
Pump reverse
gunk squeeze pill
to allow POH
(Volume to be
determined based
upon losses)
¡
I Contact Drilling Engineer I
or Engineer on call
(
+
Total
> 200 bbl/hr Static
+
Drill Across Fault
.
Pump reverse gunk
squeeze pill to allow
POH (Volume to be
determined based
upon losses
,
Contact Drilling
Engineer or Engineer
on call
l
.
Plan to pump a second
50-80 bbl reverse gunk
squeeze pill if massive
losses continue.
Consider cement I
plugback contingency
'\
1 )UNOCAL must approve any steps past PARTIAL losses.
2) Drill across fault or loss zone 1.5 - 2.0 times the length of the
throw before spotting reverse gunk squeeze pills.
3) PBL sub should be run in BHA to spot pills if 'Partial Loss' cases or
above are anticipated prior to drilling to allow the spotting of LCM
pills.
4) LCM pill volume = 300'-600' column based upon actual hole
diameter.
5)PRIOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT
THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR
PLUGGING THE DRILL STRING.
\
.J
12
.
.
I Halliburton BAROID
UNOCAL
Mud Program
Gunks (WBM)
Description
The basic system forms a fairly soft plug. The addition of cement produces a firmer set which can
withstand differential pressure and has a longer lifetime - this is known as DOB2C. Essentially the gunk
treatment involves mixing bentonite, bentonite/polymer, or bentonite/cement powder blends into an oil
such as diesel. This mixture is pumped down the drill pipe whilst water based mud is pumped down the
annulus. When the two streams meet, a thick gunk (gel) is formed as the bentonite or other additives
hydrate. This is then squeezed into the formation. The hardness of the gunk depends on the relative
pump rates and the concentration of the pill (as well as the pill type). Typically the mud and pill would be
pumped at similar rates and the pill would contain around 200-400ppb bentonite. In some situations
environmental regulations may preclude the use of diesel oil. Low toxicity oils such as synthetic oils may
be used in place of diesel but should be tested in the laboratory first.
A cement unit is used for displacing the gunk squeeze. The pumping unit displaces the mixture down the
drill string and the mud pump pumps fluid down the annulus. The slurry reacts with water so that
precautions to keep water from prematurely contacting the slurry are needed. An oil spacer is pumped in
front of and behind the pill.
Benefits:
· Temperature is not very important
· Soft set avoids sidetracking problems (easy to wash/drill out)
· Slurry will pass through most BHAs
· Procedures are well established
· Suited to large fractures/voids
Limitations:
· Placement - need to generate gunk in the right place
· Flow rate and mix is important to achieve suitable consistency
· Suitable experience required
· Avoid premature mud contamination
· Possible environmental restrictions dealing with oily returns
· Effect can be short-lived due to softness of the plug (simple gunk)
· May not work with high salt muds (>50,000 mg/I chlorides)
HV #7 v1.0
04/16//04
13
.
I Halliburton BAROID
.
UNOCAL
Gel Gunk Squeeze Procedure
Mud Program
Formulation - 1 barrel
. 0.7 bbl Diesel
· 400 Ibs bentonite (density is approx. 10 Ib/gal)
Mixing Procedure
Mix in a cementing batch tank, not in the pits
o Ensure the cement unit, batch tank and all associated pipework is completely drained and then
flushed through with diesel
o Add the bentonite to the diesel. Preferably add the bentonite through a mixing jet (not directly into
the tank) to avoid lumps.
o If the mixture becomes too thick to add the required quantity of bentonite, stop mixing and use the
slurry as it is.
o Test the gunk by mixing a sample of it 50/50 with the mud. Check the quality - it should be a
consistency similar to chewing gum within 30 seconds. NOTE: If a highly inhibitive Mud does
not allow the Gunk Squeeze to hydrate, then Freshwater, not the Mud, should be used to pump
down the annulus AND to displace the Diesel Spacer - Gunk Squeeze-Diesel Spacer
combination in the drill pipe. See below procedure.
Suggested Procedure
1. Place the bit about 50-60' above the loss zone.
2. Line up mud pumps to pump simultaneously down the drillpipe and annulus.
3. Line up cement unit to pump down the drillpipe.
4. With the cement unit pump 10 bbls diesel followed by 40+/- bbls gunk and a further 10 bbls diesel,
down the drillpipe.
5. Displace with the mud pump until diesel at the bit. Close annular.
6. Pump at 5 bpm down the drillpipe and 10 bpm down the annulus (use freshwater, if mud is too
inhibitive) simultaneously until half of the gunk is out of the bit.
7. Pump at 5 bpm simultaneously down both the drillpipe and annulus until the gunk has been over
displaced from the drillpipe by 5 bbls.
8. Squeeze gunk into the loss zone. Leave at least 5 bbls gunk inside the wellbore to prevent over-
displacement. Try to establish a shut-in pressure at the end.
9. If successful, leave the gunk to firm up for 30 minutes prior to washing out.
Comments
The gunk pill is inert until it is mixed with water or water based mud. IT MUST ONLY CONTACT
WATER BASED FLUIDS AS IT EXITS THE BIT.
The purpose of initially pumping down the annulus at twice the rate down the pipe is to initially produce
a slower reacting product that can penetrate the formation more easily. The last part of the gunk is
mixed 50/50 and plugs the loss zone quickly.
These flow rates are designed to get the gunk to the loss zone quickly after the gunk has been mixed
with the mud (or fresh water). The progress of the job should be determined and monitored by the
volume of displacement mud pumped down the drillpipe.
HV #7 v1.0
04/16/104
14
.
.
I Halliburton BAROID
UNOCAL
Mud Program
DOB2C (DIESEL OIL BENTONITE 2 CEMENT)
PRODUCT INFORMATION AND APPLICATION
DOB2C is a gel cement slurry that is mixed in diesel oil. It is typically used to cure severe loss circulation
situations. DOB2C when contacted by water or a water base mud, will react, releasing the diesel and
hydrating the cement. This reaction begins - 1 min after mixing. The degree and rate of reaction depends
on how much water mixes with the DOB2C.
SAFETY PRECAUTIONS
Diesel Oil Slurries should be mixed wI adequate ventilation. The equipment used to mix the slurry must
meet requirements to handle combustible materials. Review the MSDS for the slurry components and
wear the proper PPE.
Variations on this system which use alternative oils to diesel are possible but would require pilot testing.
MIXING PROCEDURE
1. Mixing on location in a cement batch mixer.
2. Blend the required Cement and Bentonite at the bulk plant, if possible. Load this blend into a cement
bulk truck.
3. To assure fluid integrity and avoid potential incompatibility situations all mixing and pumping
equipment must be free of water. Circulate the batch mixer with warm diesel and isolate that material
for use ahead and behind the DOB2C.
4. Measure the required volume of diesel fuel into the mixer.
5. Begin weighting up the diesel with the Bentonite cement blend.
6. One barrel of DOB2C is made up as follows:
· 0.7 bbls Diesel Fuel (Arctic Diesel, #4 Diesel Oil (Mapco) or Mineral Oil)
· 150 - 200 Ibs of Bentonite
· 150 - 200 Ibs of Class G cement
7. Confirm the final density with a pressurized mud balance.
8. Allow the slurry to mix for 15 minutes prior to pumping.
DOB2C (DIESEL OIL BENTONITE 2 CEMENT) PUMPING PROCEDURE
It is important to the success of this operation to have a clear understanding of the loss rate. Both
dynamic and static rates should be reviewed just prior to doing this job and incorporated into the final
design. Various mixtures of drilling mud and DOB2C result in various degrees of a set product. Annular
and drill string injection rates will be based on what the loss rate is at the time of the job. Treatment
volume will be based a review of all available wellborelloss data with a typical minimum recommended
volume to be 40 bbls, however, depending upon tubular and annular clearances alternative volumes may
be utilized.
1. Go in hole with BHA suitable for pumping Loss Circulation material(s). When a bit is needed, remove
the jets. If necessary, a PBL circulating sub in the drilling BHA is suitable for placement. RIH to - 60'
above the loss zone. A minimum of 2 bbls hole volume above the loss zone.
2. Establish injection down the drill string. Monitor and record losses. The cement van will pump down
the drill pipe. The rig will do any pumping down the backside.
3. Batch mix the DOB2C slurry. Additional warm diesel should be made available on location for
equipment cleanup. The system will be effective when mixed with arctic diesel, #4 Mapco or mineral
oil, as the base fluid.
4. All surface equipment used to mix and pump the slurry will be free of water. Any diesel required to
accomplish this will be isolated and used in the spacer behind the DOB2C.
HV #7 v1.0 15
04/16//04
. .
I Halliburton BAROID UNOCAL Mud Program
5. "Typical" Pumping Procedure. Pump the treatment via dp at the maximum rate allowed as follows
(The hydril is open):
· Pump 10-15 bbls diesel oil pre-flush spacer
· Pump DOB2C slurry
· Pump 10-15 bbls diesel oil post-flush spacer
· For maximum hydration ability, displace the squeeze to the bit with freshwater (40-50 bbls). Follow
this with mud as needed.
6. When the diesel oil preflush is at the end of the bha, close hydrill and begin pumping down
annulus with rig pumps. Match injection rates if possible to effectively mix the DOB2C with the
annulus fluids. Too much dilution will soften the set product while too little water contact wIthe
DOB2C will not release the diesel. The best reactions occur at a mixture of 1:2 and 1:3 water based
mud:DOB2C.
Reverse Gunks (OBM)
Description
This is the reverse procedure compared with ordinary Gunks. Typically, organophilic clay is mixed into an
aqueous suspension and pumped down the drill pipe. The oil mud is pumped simultaneously down the
annulus and gelation occurs when the two fluids meet. The gunk is squeezed into the formation: Note that
it is not possible to add cement to strengthen the pill (unlike DOB2C used for WBM applications).
Benefits:
· Temperature is not very important
· Soft set avoids sidetracking problems (easy to wash/drill out)
· Slurry will pass through most BHAs
· Procedures are well established
· Suitable for large fractures/voids
Limitations:
· Placement - need to generate gunk in the right place
· Suitable experience required
· Avoid premature mud contamination
· Mixing time/placement often greater than 6hrs
· Effect can be short-lived due to soft plug formed
· The type of clay used to make the treatment can be quite critical
Procedures: Formulations (per 1 bbl)
Formulation for "LmH'ightcd Rc\crse" Gunk Pill
Water
0.66 bbl
Caustic Soda
1.5 Ib
Dispersant (Desco CF)
3.5 Ib
Organophilic clay (Geltone)
2501b
This formulation is provided as a guide only. The yield obtained will vary greatly dependant on the
particular clay used. Pilot testing of the pill formulation is strongly recommended. The formulation given
HV #7 v1.0
04/161104
16
.
.
I Halliburton BAROID UNOCAL Mud Program
above will have a density of approximately 11.0 ppg. The slurry density can be increased to that of the
active mud weight by viscosifying the water/clay slurry with XC polymer and adding barite.
Formulation for "Weighted 13.0 ppg ReHrse" Gunk Pill
Water O.63bbl
Caustic Soda I.Slb
Dispersant (Desco CF) 4.Olb
Organophilic clay (Geltone) 150lb
Barite 1751b
Mixing I Displacement Procedure
The pill should preferably be prepared in the cement batch tank. Ensure that the batch tank and all
associated lines are clean by flushing thoroughly with a water based rig wash followed by large volumes
of water.
Add the ingredients in the order shown utilising as much shear as possible to disperse the organophilic
clay (Geltone). A pill of approximately 30bbl is recommended.
The resultant slurry is preferably pumped through open ended pipe but may be pumped through the bit if
it is not practicable to POOH. The following displacement procedure should be strictly followed to prevent
gelation within the drill pipe. Before the displacement the string should be pulled back to a height sufficient
to leave the pill volume of open hole.
1. Pump 10bbl diesel base fluid
2. Pump 10bbl water
3. Pump the slurry (30bbl)
4. Pump 10bbl water
5. Pump 10bbl diesel base fluid
6. Displace the pill to the bottom of the drill string
7. If the hole is full, close the annular and squeeze at 300 - 500 psi into the formation
8. If the hole is full, close the annular and pump the pill at 1 bbl/min down the drill pipe and mud at
1 bbl/min down the annulus.
9. Allow at least 4 hours for the plug to set.
Note: Ensure that the entire pill is pumped out of the string. Do not attempt to reverse circulate.
HV #7 v1.0
04/16//04
17
.
.
I Halliburton BAROID
UNOCAL
Mud Program
DrillinQ Fluids ProQram Synopsis
General Discussion
A KCI drilling fluid will be used to drill the surface and intermediate hole sections of these wells. This fluid
offers hole stability, waste reduction and many options to address/prevent lost circulation. This fluid will
yield a more gauge hole which reduces the waste (both while drilling and for cement jobs). This gauge
hole, however, can also lead to challenges with swabbing on trips. The production hole will be drilled with
an INVERMUL system. This oil based fluid will offer added hole stability and lubricity for this section with
the added benefit of lowering waste stream costs. Please refer to the mud program for details.
SUQQested Fluids Properties
Surface Hole Properties:
0-1032'
Density Viscosity
8.6 - 8.9 60 - 85
Plastic Viscosity
6 -16
Yield Point
25 - 40
API FL
N/C
Iili
8.5-9.0
Comments: This interval will be drilled with a 6% KCI, EZ Mud fluid. Primary focus for this intervel will be adequate
hole cleaning for the large diameter (12 ~") hole and maintaining the drill solids / mud weight.
Intermediate Hole Properties:
1 ,032 - 1500'
1500 - 4350'
Density
8.7 -8.9
8.8-9.2
Viscosity
40-53
40-50
Plastic Viscosity
6 - 15
6 - 15
Yield Point
13 - 20
13 - 20
API FL
N/C
<8
Iili
8.5-9.0
8.5-9.0
Comments: The mud system from spud will be conditioned and used to drill this section. Maintaining low ECO's is of
primary importance. The zones -1,700' and 4,100 have had losses on previous wells. Treat with Barofibre while
drilling and emphasize to drillers ECO management. An LCM decision tree & Gunk Squeeze procedures are
attached should losses develop.
Production Hole Properties:
Density Viscosity PV YP ES HTHP FL WPS O/W
4350 - 10,000' 9.9 - 9.6* 45 - 60 18 - 29 11 - 20 1 000- <8 280 to 310K 80/20
fj 1100
10,000- TD 45 - 60 18 -29 11 - 20 1000- <5 280 to 310K 90/10
1100
* - Additional mud weight may be required for effective coal or shale stabilization.
Comments: The well will be displaced to an INVERMUL system prior to drilling out the 7" casing if rig ops didn't allow
bumping the plug with cement. This will be used mud from previous wells. Maintaining a clean, low solids content
and raising the OWR to 90/10 prior to 10,000 feet will keep the rheological profile low and reduce chances of lost
circulation, excessive pump pressures, and lay down a thinner, more durable wallcake. Maintain the mud weight as
low as possible but be prepared to weight up if hole conditions warrant. Reduce the 2000 HTHP fluid loss to <5 by
10,000' and maintain to TO.
Happy Valley #7 - Suñace
HV #7 v1.0
04/16//04
18
BAROID
UNOCAL
6%KCI
45 ~ 3.326 ~
5. d. x
B. K X
5 10 15 20 25 0 50 1000 3B
~ hr flIT nmP
The hole cleaning model indicates that 590 gpm and an ROP no more than 1 ft/hr will be needed to
achieve good hole cleaning in this large welibore. If flowrates cannot maintained, remedial
action such as high viscosity sweeps and circulating on connections may be required.
BAROID
UNOCAL
Intermediate
modeling
1000
r- ~
t~
2000 ~~
4.5 x 3J326 x 4092.0 Itl
3000
12.35 in
4000
5. x 3. x 150.0 Itl
6.75 x 2.813 x 100.0 It!
Rotation must be optimized in this size hole and this angle. Rotation less than 100 rpm's indicates
that there will be cuttings accumulation. At flowrates of 590 gpm (a the Kuukpik rig can achieve)
an average of 110 ftlhr can be achieved. For an increase in rotational speed from 100
rpm to 120 rpm is recommended - a gain of 30 ft/hr is had with a gpm flow rate. A hole
cleaning sweep strategy will required for ROPs 1 ftlhr.
BAROID
UNOCAL
Production hole modeling
4.5 x 3.826 x 12074.0ft!
5 10 15 20 25 0 50 1000 315 B30 30 so 90 9.30 9.80
1 q h, flIT timp
,0 x 3 x
f 7.25 x 2.813 x 107.0 it
The recommended flowrate is 500-550 gpm, although 450 gpm will give adequate hole cleaning at 1
ftlhr. With 4.5" dp, hole cleaning at 150 ftlhr, within the pump pressure limitation (3600 psi), should be
more than adequate with 80 rpm and gpm.
H.) 9.3 PPG OHM using
This line represents 3 % cuttings
the max ROP for effective hole cleaning would
At 100 ft/hr ROP, good hole cleaning
Discussion: Effective hole cleaning takes place if below the
loading in the annulus. model indicates that with
be The corresponding pressure loss would be about
can be achieved with as low as 350 gal/min, augmented with sweeps.
AlìflUlar Section 13 -10900.0 ft
Iblga! stepping Rotary ROf! . 1 s ¡ Hole Clean @ 100 rpm· 2min f Connection time . 5mkì
3OOf!1hr
10:40
10.35
10.30
125
500
Total
psi
·5000
Happy \Isley #7
KuuIqi 5
4500
4000
vwaf/nuI
3500 fJ¡~=
ppm = 300000
3000 800 = 59 100 = 14
300 = 34 6
3
2500 0=.928
k = .092561bJ1 orm2 sO
2000
1500
1000
500
galfmJn
.
.
CITIBANK DELAWARE
A Subsidiary of Citicorp
ONE PENN'S WAY
NEW CASTLE, DE 19720
62-20
31T
Union Oil Company of California
Accounts Payable Field Disbursing
2007778
UNOCALI76
Pay
One Hundred Dollars And 00 Cents**************************************************************
To the
order
of
19-APR-04
Check Amount
********100.00
Date
STATE OF ALASKA
ALASKA OIL & GAS CONSERVATION COMMISSION
333 WEST 7TH AVENUE SUITE 100
ANCHORAGE, AK 99501
United States
or ,;, moo~ f'~:1L
III 200 ? ? ? B III I: 0 :I . .00 2 0 g I:
:I g . . B . :I ? III
RECEIVED
APR 1 9 2DD4
Alaska Oil & G
as Cons C .
Anchorage' Dl11n1lssion
.
.
TRANSMITAL LETTER CHECK LIST
CIRCLE APPROPRIATE LETTER/P ARAGRAPHS TO
BE INCLUDED IN TRANSMITTAL LETTER
WELL NAME
PTD#
Development
Service
CHECK WBA T
APPLIES
ADD-ONS
(OPTIONS)
MULTI
LATERAL
(If API Dum ber
last two (2) digits
are between 60-69)
Exploration
Stratigraphic
·'CLUEn
Tbe permit is for a new well bore segment of
existing well
Permit No, API No.
Production. sbould continue to be reported as
a function· of the original API number. stated
above.
BOLE In accordance with 20 AAC 25.005(t), an
records, data and logs acquired for the pilot
bole must be dearly differentiated In botb
name (name on permit plus PH)
and API Dum ber (50
70/80) from records, data and logs acquired
for well (name on permit).
PlLOT
(PH)
SPACING
EXCEPTION
DRY DITCH
SAMPLE
Tbe permit is approved subject ·to fuD
compliance witb 20 AAC 25.05S~ Approval to
perforate and produce is contingent upon
issuance of;¡ conservation order approving a
spacing e:JCeption.
(Companv Name) assumes tbe liability of any
protest to the spacingeJception tbat may
occur.
An dry ditch sample sets submitted to tbe
Commission must be in no greater ·tban 30'
sample intervals from below tbe permafrost
or from wbere samples are first caught and
10' sample intervals through target zones.
.
.
D
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Well bore seg
Annular Disposal
Field & Pool HAPPY VALLEY, UNDEFINED GAS - 290500 Well Name: HAPPY VALLEY 7 Program DEV
PTD#: 2040680 Company UNION OIL CO OF CALIFORNIA Initial ClassfType DEV 11-GAS GeoArea Unit On/Off Shore On
Administration 1 Permittee <!ttache_d _ - - - - - - - - - - - - - - - - - - - - - - _ _ _ _ _ Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
2 _Le<!senumberappropriate _ - - - - - - -- - - - - - _ _ _ _ _ Yes - - - - - - - - - - - - - - - - - - - -
3 _U_nlque well_n_arne_afld ou.mb_er _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y_es - - - - - - - - - - - - - - - - - - - - - - - - - . . -. - - - - - - - - - - - - -
4 WeJUQcated in_a_ ciefil1edpool - - - - - - - - - - - - - - - _ _ _ _ _ No_ - - - - - - - - - - -
5 WelUQcated pcoper _dlstance3rom driJling ul1itb_oul1d_ary_ _ _ _ _ _ _ _ _ _ No _ _ _ _ _ A SPACING EX_C_EPTtQN IS REQUIRED fOR PROXIMITY TO A SECTIONLJNE._
6 WelUQC<lted proper _dlstaflce_ from otber welJs_ _ _ _ _ Yes _ _ _ _ HEARING NOJ"ICE I-IAS BEN DRAJ=1ED_
7 _S_u{ficieI1Lacre<!ge_ay<!iIable In_drilliog u.njL _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes - - - - - - - - - - - - - - - - - - - -
8 Jtdeviated, js_ weJlbQre platil1cJu_ded _ _ _ - - - - - - Yes - - - - - - - - - - - - - - - - - - -
9 _OJ)erator Ol1ly <!ffected party _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - No - - - - - - - - - - - - - - - --
10 .0J)ecator bas_appr.oprlateJ~ond inJorce _ . . . _ _ _ _ _ _ _ _ . . _ . . _ _ . _ _ _ _ _ _ _ Yes - - - - - - - - - - - - - - - - - - - - - - - -
11 Permit c_afl be issu.ed wjtbQut co_nserva_tiOI1 order _ _ _ _ _ - - - - -- - - - - - No - - -- - - - - - - - - - - - - - - - - - -
Appr Date 12 Permit ~afl be lssu.ed witbQut acimil'Jistratil¡e_appr.oval _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - - - -
RPC 4/22/2004 13 Can permit be approved before 15-day wait No
14 WellJQC<lted withil1 <!rea alld_strataauthorized by_lojectioo Order # (put 10# in_ c.ommeots) (For _ NA - - - - - - - - - - - - - - - - - - -
15 _AJI welJs_witJ1[nJl4.mile_area_of reyiew ideot[fied (F.or seNjc.ewell Ol1ly). _ . . . . _ _ _ _ _ _ _ _ . _NA - - - - - - - - - - - - - - - - - - - - - - --
16 Pre-produced injector; øuration_of prß-:ProduGtic:>I1 less t\1<!n_ 3 mOl1tbs (For_serYtce well onJy) . _ _NA - - - - - - - - - - - - - - - - - -
17 ACMP. F:il1djng of Consi,Steflcy_h_as been issued_ for_ tbis project NA - - - - - - - - - - - - - - - -
Engineering 18 Coodu.ctor strin.gprovided _ _ _ _ _ _ _ _ - - - - - - - - - - - - Yes - - -- - - - - - - - - - - - - - - - - - -
19 S_ur:f<!ce_casil1gprote~ts all_knowll USDWs _ _ _ _ _ Yes - - - - - - - -
20 _CMTvoladßQuateJo circ_ulateoncol1d_uçtor.& SUJtcsg _ _ _ _ .Yes · . _ _ _ AdeJ: uate excess, _ _ _ _ _
21 _CMT vol adßQuate to tie-in Jong _string to_surf CS9- - - - - - - Yes - - - - - - - - - - - - - - - - - - - -
22 CMTwill coyer_all kl'Jow_npro_ductiYe bori;!:on_s_ _ _ _ _ _ _ _ Yes - - - - - - - - - - - -
23 C_asiflg de_sigflS <!cieQua.te f.or C,_T" B_&Rermafrost _ Yes - - - - - - - - - -
24 Adequate tankage_or reserye pit _ _ _ _ _ _ _ - - - - -- Yes _ _ _ Ku.ukpils Rig_5, _ _ _ .
25 JtaJe-drilt \1asa to:40;3 for abandOnment beeo approved _ _ _ _ _ NA · . _ _ _ New welt . _ _ _ _ _ _ _ _ .
26 .Mequatewellbore. separatjo_nJ)roposed. _ _ _ . _ _ _ . . _ _ _ _ _ _ _ _ _ . . . _ _Yes - - - - - - - - - - - - - - - - - - - - - - - ~
27 Jtdivecter Jequire.d, does ¡tmeet reguJatiol1s_ _ _ _ _ - - - - - - - - _ _NA · _ . _ _ Oiverter waiver re,queste_d,
Appr Date 28 _DriUiog fluid_ program s~hematic& equip Jistadequate _ _ _ _ _ _ . _ _ Yes · . _ _ _ MaxMW9~6.ppg, _ _ _ _ .
WGA 4/23/2004 29 BOPEs,d_o_they me!'!treguJatiol1 _ _ _ _ . - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - -
30 _BOPE_press ra!iog approp(iate;test to_(pu_t psig in_comm~mts). . .Yes · _ _ _ _ Test t.o 4500_ psi. _MSF> 3717 psi
31 _C_hokemanjfold compJies w/APLRF>-53 (May 84). . _ _ _ . - - - - - - Yes
32 Work will occ_ur withoytoperatio_n _sbu.tdown _ _ _ _ _ _ _ _ - - - - - - Yes
33 .Is. pres.eflce_ of H2S g<!s prOQable _ _ _ - - - - - - -- - - - - - - No
34 Me.cba_nicaLcoodJt[Ofl .of wells withil1 AOR Yerified (for.s_ervic!'! wel] ollly) _NA - - - -
Geology 35 Permit can be issu.ed wfo hydcogen sulfide measures _ _ Yes - - - -
36 _D_atapres!'!l'Jted on_ pote_ntial oveJpres_suœ _zOl1eJ> _ _ _ _ _ _ . . . _ .Yes
Appr Date 37 _Setsrnicanalysjs_ of J>baJlow gasz_ooes_ _ _ _ NA
- - - - - - - - --
RPC 4/22/2004 38 _SeabedcOl1ditioo su.rvey _(if off-shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA
39 . Conta_ct l1amelpJ1on.eJor_weelsly progress_reports [explorato() _ _ _ NA
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Geologic Date: Engineering Dare { Date
Commissioner: Commissioner tift- /or
#0 0/21 / cJ--
