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10/6/2005 Orders File Cover Page.doc
•
Kenai Gas Field KU 24-7
1. September 16, 1996 Marathons Application for Disposal Injection Order
2. October 14, 1996 Addendum to Application for Underground
Injection Order
3. November 20, 1998 Ltr from Marathons regarding 24 month
4. October 26, 1996 Notice of Hearing
5. November 25, 1998 Ltr to Marathon re: 11/20/1998 ltr
6. January 11, 2002 Ltr Patton Boggs re: Marathon be allowed to
dispose of certain radioactive tracer returns
7, September 27, 2004 Proposals to amend underground injection orders to
incorporate consistent language addressing the
mechanical integrity of wells
8. November 21, 2004 Report from Marathon KU 24-7 Cuttings Disposal
Project Evaluation
9. February 7, 2006 Amend Disposal Injection Order ("DIO") 11, by
replacing well KU 24-07 (PTD 182-016) with
sidetrack well KU 24-7rd (PTD 205-099). (DIO
11.001)
10. 2007 Kenai Gas Field Grind & Inject (G&I) Operations
(Confidential)
11. March 8, 2010 Marathon's commercial disposal through G&I
facility
Disposal Injection Order 11
,
l
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Re: The REQUEST OF MARATHON
OIL COMPANY to dispose of
Class II oil field fluids by
underground injection in the
Kenai Unit 24-7 well
) Disposal Injection Order No. 11
)
) Kenai Unit Well No 24-7
) Kenai Unit
)
November 21, 1996
IT APP.EARING THAT:
1. Marathon Oil Company by correspondence dated September 16, 1996 made
application to the Alaska Oil and Gas Conservation Commission (AOGCC) for
authorization to inject Class II waste fluids into the Kenai Unit No 24-7 (KU 24-7)
well.
2. The AOGCC requested a modification to the original application on September 25,
1996. Marathon Oil COl11pany provided the requested information on October 17,
1996.
3. Notice of an opportunity for public hearing was published in the Anchorage Daily
News on October 26, 1996.
4. Marathon Oil Company provided revised operational parameters for the proposed
disposal project and additional information regarding potential fracture development
on November 6, 1996.
5. No protest or request for a public hearing was timely filed.
FINDINGS:
1. Cook Inlet Region Inc. and Salamantof Village are surface owners within a one-
quarter mile radius of the KU 24-7 and have been duly notified of the proposed
plans.
2. Marathon Oil Company is the operator of the Kenai Unit. There are no other
operators present within a one-quarter mile radius of the proposed KU 24-7 disposal
injection project.
3. The Kenai Unit No. 33-7 (KU 33-7) well penetrates the proposed injection zone
within a one-quarter mile radius of the KU 24-7 well.
)
Disposal Injection Order 1\ 0. 11
November 2 I, 1996
Page 2
)
¡
4. KU 33-7 has 13 3/8-inch surface casing set at 2025' measured depth and cemented
to surface. Production casing is 9 5/8-inch pipe set at 6529' measured depth and
cemented up to 3950' measured depth equivalent to 3515' TVD subsea.
5.KU 24-7 was drilled to a total measured depth of 5820', equivalent to 4796' true
vertical depth.
6. The Sterling Formation consists of Pliocene aged, massively bedded, predominately
coarse grained, fluvial deposits and is present within the KU 24-7 from above the
surface casing shoe at 2003' measured depth to total depth.
7. The proposed disposal injection zone consists of three highly porous and permeable,
and pressure depleted sandstones that are present from 4400' to 4710' measured
depth (approximately 3720' to 3960' true vertical depth) in KU 24-7.
8. The production and Class II disposal injection history of Kenai Unit Sterling
F ormation gas reservoirs similar to the 4400' to 4710' measured depth interval in
KU 24-7 indicates the sandstones are highly permeable.
9. 40 CFR 147. 1 02(b) (1) (c) exempts all underground sources of drinking water
(USDWs) at depths greater than 1300' below ground level and extending one
quarter-mile beyond the boundaries of the Kenai Unit,
10. Approximately 2400 true vertical feet of Sterling Formation sediments separate the
proposed disposal injection zone in KU 24-7 from the base of the non-exempt
USDWs in the Kenai Unit. This interval contains an aggregate thickness of more
than 450 true vertical feet of impermeable confining zone shale lithologies.
11. KU 24-7 has 13 3/8-inch surface casing string set at 2003' measured depth and
cemented to the surface.
12. The production string in KU 24-7 consists of9 5/8-inch casing set at 5801' measured
depth, cemented to at least 3250' measured depth.
13. KU 24-7 will meet the test requirements of20 AAC 25.030 and 20 AAC 25.412
prior to initiating disposal injection.
14. Two strings of three and 1/2-inch tubing are installed in KU 24-7 with a dual packer
set at 4313' and a single packer set at 4679' measured depth.
15. Cement evaluation tools run in KU 24-7 indicate good to excellent cement bond
from total depth to at least 3250' measured depth.
16. The operator will demonstrate mechanical integrity pressure testing KU 24-7 prior
to initiating disposal operations.
)
Disposal Injection Order 1\[0. 11
November 21, 1996
Page 3
)
17. Disposal fluids will consist of fluids associated with drilling, production, and
workover operations. Typical fluids will include, produced fluid, drilling and
completion fluids, equipment wash water, drilling mud, cuttings, and NORM scale.
18. Well KU 24-7 will be operated intermittently, as needed, on a weekly basis. The
operator expects to run the operation 5 days per week, approximately 12 hours per
day under normal conditions.
19. Maximum injection rates are expected to be as high as 7200 barrels per day.
Average injection rates are estimated to be 1000 barrels per day.
20. Estimated average surface injection pressure wi11 be 1600 psi. and maximum will be
less than 2400 psi, limited by pump working pressure and safety relief valve
pressure.
21. The estimated injection pressure parameters for KU 24-7 are based on previous
disposal well tests and their nominal performance during disposal operations.
22. A three-dimensional hydraulic fracture simulation with a 500,000 barrel disposal
volume using operational parameters and fluid types described in the application,
predicted the proposed KU 24-7 disposal project will induce a fracture up to 650'
high (approximately to 3200' TVD, 3850' MD) 1900' below the base of the
nonexempt aquifer in the Kenai Unit. Over 265' of confining above the fracture are
expected to prevent movement of disposal fluids into nonexempt aquifers.
23. The operator will monitor disposal performance using instantaneous shut in pressure
plots versus cumulative disposal, well head pressure trends, and disposal rates.
These data will be evaluated relative to modeling results to qualitatively track
fracture height and disposal placement.
24. The operator will monitor the casing-tubing annulus pressure on the disposal well
and report the results on the Monthly Injection Report. Production wells annuli are
monitored routinely to confirm integrity.
CONCLUSIONS:
1. The approval of disposal injection operations at KU 24-7 will not jeopardize
correlative rights.
2. Permeable strata which reasonably can be expected to accept injected fluids are
present in the interval from 4400' to 4710' measured depth in KU 24-7.
)
Disposal Injection Order No. 11
November 21, 1996
Page 4
l
3. The disposal interval, 4400' to 4710' measured depth, in KU 24-7 is approximately
2420 true vertical feet below the base of the deepest non-exempt USDW in the
Kenai Unit.
4. More than 450 vertical feet of impermeable confining zone lithologies are present in
KU 24-7 between the top of the proposed disposal injection zone and the base of the
deepest non-exempt USDW.
5. Disposal fluids injected at KU 24-7 will consist exclusively of Class II waste
generated from drilling, completion, and production operations.
6. KU 24-7 is constructed in conformance with the requirements of20 AAC 25.030
and complies with 20 AAC 25.412.
7. Well integrity will be demonstrated in KU 24-7 in accordance with 20 AAC 25.412.
8. Operational parameters will be monitored routinely at the KU 24-7 for indications of
abnormal pressure and rate conditions.
9. Disposal injection operations in the KU 24-7 will cause fracturing of some of the
low stress depleted sands and shales above the disposal interval. Over 350' of
confining shales and numerous sands will prevent movement of disposal fluids into
nonexempt aquifers.
10. Cement evaluation logs and well records demonstrate the KU 24-7 well and the
adjacent KU 33-7 well have adequate cement behind casing to properly contain
fluids within the disposal injection zone; neither well should serve as a conduit to the
surface.
11. The requirements of20 AAC 25.252 have been met.
NOW, THEREFORE, IT IS ORDERED THAT:
Rule 1 Authorized Injection Strata for Disposal.
Class II oil field fluids may be injected in conformance with Alaska Administrative Code
Title 20, Chapter 25, for the purpose of disposal into the Sterling Formation interval from
4400' to 4710' measured depth in KU 24-7.
Rule 2 Demonstration of Tubing/Casing Annulus Mechanical Integrity
The tubing/casing annulus must be tested prior to the start of injection and at least every
four years thereafter for mechanical integrity in accordance with 20 AAC 25.412. The
Commission must be notified at least 24 hours prior to these tests so they may witnessed.
Disposal Injection Order )0. 11
November 21, 1996
Page 5
Rule 3 Well Integrity Failure
Whenever disposal rates and/or operating pressure observations or pressure tests indicate
pressure communication or leakage of any casing, tubing or packer, the operator must
notify the Commission on the first working day following the observation, obtain
Commission approval of a plan for corrective action and obtain Commission approval to
continue injection.
Rule 4 Administrative Action
Upon request, the Commission may administratively revise and reissue this order upon
proper showing that any changes are based on sound engineering practices and will not
result in an increased risk of fluid movement into an underground source of drinking
water.
DO N.E at Anchorage, Alaska and dated November 21, 1996
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Alaska Oil & Gas Conservation Commission
AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a
person affected by it may file with the Commission an application for rehearing. A request for rehearing
must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a
holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or
in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day
period. An affected person has 30 days from the date the Commission refuses the application or mails
(or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to
appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the
Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is
deemed denied (i.e., 10th day after the application for rehearing was filed).
~u~uŒ [ûJ~ ~~~~ltriÆ
ALASKA. OIL AM) GAS
CONSERVATION COMMISSION
FRANK H. MURKOWSKI, GOVERNOR
333 W. pH AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
ADMINISTRATIVE APPROVAL NO. DIO 11.001
Mr. Ben Schoffmann
Operations Superintendent
Marathon Oil Company
P.O. Box 196168
Anchorage, AK 99519-6168
Re: Request to amend Disposal Injection Order ("DIO") 11, by replacing well KU 24-
07 (PTD 182-016) with sidetrack well KU 24-7rd (PTD 205-099).
Dear Mr. Schoffman:
The Alaska Oil and Gas Conservation Commission ("Commission") grants the request of
Marathon Oil Company ("MOC") to amend DIO 11 by replacing well KU 24-07 with
sidetrack well KU 24-7rd. By Application for Sundry Approvals (Form 10-403) dated
June 21, 2005 and application for Permit to Drill (Form 10-401) dated June 22, 2005,
MOC proposed to abandon well KU 24-07 (PTD 182-016) and replace it with sidetrack
well KU 24-7rd (PTD 205-099). During an attempted workover operation approved by
the Commission on February 17, 2005 (Sundry Approval No. 305-034), MOC deter-
mined that KU 24-07 was damaged beyond repair.
The Commission finds as follows:
1. KU 24-7rd was drilled to a bottom-hole location approximately 170 feet away
from KU 24-07's bottom-hole location;
2. during an attempted workover operation, MOC determined that KU 24-07 was
irreparably damaged;
3. KU 24-07 and KU 24-7rd penetrate common subsurface strata;
4. MOC proposes to utilize well KU 24-7rd as a replacement for the no\\!" abandoned
well KU 24-07, for injection in the Kenai Unit;
DIO 11.001
February 7,2006
Page 2 of2
5. KU 24-7rd's area of review ("AOR") encompasses no wells that are not already
within KU 24-07's AOR, and
6. Replacing well KU 24-07 with sidetrack well KU 24- 7rd is based upon sound
engineering practices and will not result in an increased risk of fluid movement
into an underground source of drilling water.
It is therefore ordered that DIO 11 is amended by replacing well KU 24-07 with sidetrack
well KU 24-7rd.
As provided in AS 31.05.080, within 20 days after written notice of this decision, or such
further time as the Commission grants for good cause shown, a person affected by it may
file with the Commission an application for rehearing. A request for rehearing is consid-
ered timely if it is received by 4:30 PM on the 23rd day following the date of this letter,
or the next working day if the 23rd day falls on a holiday or weekend. A person may not
appeal a Com . ssion decision to Superior Court unless rehearing has been requested.
"-
~ffi~¡i
Mary Jones
XTO Energy, Inc.
Cartography
810 Houston Street, Ste 2000
Ft. Worth, TX 76102-6298
David McCaleb
IHS Energy Group
GEPS
5333 Westheimer, Ste 100
Houston, TX 77056
Mona Dickens
Tesoro Refining and Marketing Co.
Supply & Distribution
300 Concord Plaza Drive
San Antonio, TX 78216
George Vaught, Jr.
PO Box 13557
Denver, CO 80201-3557
Jerry Hodgden
Hodgden Oil Company
408 18th Street
Golden, CO 80401-2433
Richard Neahring
NRG Associates
President
PO Box 1655
Colorado Springs, CO 80901
John Levorsen
200 North 3rd Street, #1202
Boise, 10 83702
Kay Munger
Munger Oil Information Service, Inc
PO Box 45738
Los Angeles, CA 90045-0738
Samuel Van Vactor
Economic Insight Inc.
3004 SW First Ave.
Portland, OR 97201
Michael Parks
Marple's Business Newsletter
117 West Mercer St, Ste 200
Seattle, WA 98119~3960
Mark Wedman
Halliburton
6900 Arctic Blvd.
Anchorage, AK 99502
Schlumberger
Drilling and Measurements
2525 Gambell Street #400
Anchorage, AK 99503
Ciri
Land Department
PO Box 93330
Anchorage, AK 99503
Baker Oil Tools
4730 Business Park Blvd., #44
Anchorage, AK 99503
Ivan Gillian
9649 Musket Bell Cr.#5
Anchorage, AK 99507
Jill Schneider
US Geological Survey
4200 University Dr.
Anchorage, AK 99508
Gordon Severson
3201 Westmar Cr.
Anchorage, AK 99508-4336
Jack Hakkila
PO Box 190083
Anchorage, AK 99519
Darwin Waldsmith
PO Box 39309
Ninilchick, AK 99639
James Gibbs
PO Box 1597
Soldotna, AK 99669
Kenai National Wildlife Refuge
Refuge Manager
PO Box 2139
Soldotna, AK 99669-2139
Penny Vadla
399 West Riverview Avenue
Soldotna, AK 99669-7714
Richard Wagner
PO Box 60868
Fairbanks, AK 99706
Cliff Burglin
PO Box 70131
Fairbanks, AK 99707
Bernie Karl
K&K Recycling Inc.
PO Box 58055
Fairbanks, AK 99711
North Slope Borough
PO Box 69
Barrow, AK 99723
Williams Thomas
Arctic Slope Regional Corporation
Land Department
PO Box 129
Barrow, AK 99723
\~\~~\O~
DIO 11.001 Kenai Gas Unit
Subject: DIO 11.001 Kenai Gas Unit
From: Jody Colombie <jody_colombie@admin.state.ak.us>
Date: Tue, 07 Feb 2006 15 :26:36 -0900
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1 of2
2/7 /2006 3 :26 PM
DIG 11.001 Kenai Gas Unit
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2/7/2006 3:26 PM
X11
Marathon & commercial dis~al through G&I facility • Page 1 of 2
Maunder, Thomas E (DOA)
From: Stebbins, Tiffany A. [tastebbins@marathonoil.com]
Sent: Tuesday, March 09, 2010 9:27 AM
To: Maunder, Thomas E (DOA)
Cc: Regg, James B (DOA)
Subject: RE: Marathon & commercial disposal through G&I facility
Tom,
~~~ t \
~s-~~.~
Thanks for responding to the subject. If we do begin third party disposal, `I will add a line item to capture the
volumes on our annual DIO reporting.
C'1ti~ ~ ~tefi~b~i.n.G~
Regulatory Compliance Representative
Marathon Oil Corporation
Phone 907-565-3043
Ce11907-529-0522
Fax 907-565-3076
From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov]
Sent: Monday, March 08, 2010 2:03 PM
To: Stebbins, Tiffany A.
Cc: Regg, James B (DOA)
Subject: RE: Marathon & commercial disposal through G&I facility
Tiffany,
Commission Disposal Injection Orders (DIOs) authorize the Operator to dispose of Class II waste. We have not
made any distinction regarding whether the injected waste is solely produced by the Operator or results from
some third party's well operations. If third party waste is accepted, it is incumbent on Marathon to be satisfied
that the waste is indeed Class II and meets the requirements of the DIO. In your annual report it may be
appropriate to have a third party line item where such volumes can be listed.
Call or message with any questions.
Tom Maunder, PE
AOGCC
From: Regg, James B (DOA)
Sent: Monday, March 08, 2010 11:45 AM
To: Maunder, Thomas E (DOA)
Subject: FW: Marathon & commercial disposal through G&I facility
Jim Regg
AOGCC
333 W.7th Avenue, Suite 100
Anchorage, AK 99501
3/9/2010
Marathon & commercial dis~sal through G&I facility ~ Page 2 of 2
907-793-1236
From: Stebbins, Tiffany A. [mailto:tastebbins@marathonoil.com]
Sent: Monday, March 08, 2010 11:00 AM
To: Regg, James B (DOA)
Subject: Marathon & commercial disposal through G&I facility
Hi Jim,
We are considering commercial disposal. Would we need to convert our current disposal permit to a commercial
disposal permit even if we intend to only dispose of approved Class II exempt wastes.
Thanks,
C'1ti~~ar-,~. ~ ~h~,i,rv~
Regulatory Compliance Representative
Marathon Oil Corporation
Phone 907-565-3043
Cell 907-529-0522
Fax 907-565-3076
3/9/2010
X10
_ L ~
~9
FW: KU 24-07 and KU 24-07RD offsets
Subject:.FW: K1124-07 and KU 2407RD offsets
From: "Schoffmann, A B (Ben)" <abschoffmann@marathonoit:com>
Date: Tue, 07 Feb 2006 13'01:09 -0900
To: Winton G Aubert <Winton_aubert@admin.state:ai<.us>
Winton,
We have confirmed the interference data for the two referenced wells for the administrative DIO change we discussed. As indicated, the maximum
departure is 169' (at TD), which is basically the 170' we discussed previously. The corrected completion sundry will be in the mail shortly.
Ben
Ben Schoffmann
Operations Superintendent
Marathon Oil Company
work: 907-565-3035
ce//: 907-748-3589
fax: 907-565-3076
From: Laughlin, Gary A.
Sent: Tuesday, February 07, 2006 11:11 AM
To: Sthoffmann, A B (Ben)
Cc: Laughlin, Gary A.
Sutriect: KU 2407 and KU 24-07RD offsets
Ben,
It looks like at the perf interval the separation between the original hole and new hole starts at 98' and ends up roughly 125' apart and the maximum
separation of 169' at TD.
Gary
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1 of 1
2/7/2006 1:05 PM
#8
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o
Marathon KU 24-7 Cuttings Disposal
Project Evaluation
R. D. Barree
Barree & Associates LLC
November 21, 2004
u-
In 1996 a model was constructed to forecast the fracture growth resulting from
injection of cuttings slurry in the KU 24-7 well. The injection project has
continued through this year. A look-back model evaluation using the actual
observed surface pressures from the injection project was requested by
Marathon Oil Company, Anchorage. This report documents the results of that
analysis. It provides an estimate of the fracture geometry resulting from the
cutting slurry injected up to this time, and the effect of continued injection up to
a total of 1.5 million barrels of slurry.
1
are
2
.
.
C1-)r~~í~" KU 24-7 Injection Project
ì <t> Pool 3 Sterling Sands Perfs
· AI0: 4410-4490' MD
· All: 4525-4560' MD
· Injection from 8/18/2001 - present
<t> Pool 4 Sa nds
· B2: 4696-4708' MD
· Injection from 4/27/2000 - 8/18/2001
<t> Average rate while pumping = 6.8 bpm
<t> Average solids loading = 11-140/0
<t> Solids pass through 50-mesh screen
Copyright B&A 2004
The cuttings disposal initially began in the lower B2 perfs. After injection of
about 180,000 barrels of slurry the injection was switched to the upper A-sand
perfs because of rising treating pressure. Injection continued through the
upper perfs to the present time. Cuttings injection was a batch process, rather
than continuous injection. While pumping, the average rate was 6.8 bpm. The
slurry was composed of 11-14% solids by volume and the solids were ground
to pass through a 50-mesh screen.
3
Iii
Q.
<i 2500
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12/1012002 ¡¡¡1!1nOO:;
Copytìght 13M 2004
4
200
400
600
800
'1000
1200
1400
1600
1800
2000
Cumulative Hours on Injection
Copyright 8M 2004
47$6
4920
5Ó54
5U6
6318
6450
6579
Copyright B&A 2004
6
'¡¡¡
0.
.~
,
~
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.
o
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if>
200.00
400.00
600.00
800.00
1000,00 1200.00 1400.00 1600.00 1800.00 2000.00
HQurs Contitmus Injection
'¡¡
'"
~ 2000-
~
e
'"
.
.
{!
~
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1000<00
1 0000,00
Hours on -ContjnQus Injection
CopyrIght B&A 1004
8
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Cumulative 8armJs
:!!
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~ 3000
~
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u.
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1,00.0
10,000
100,000
1,000,000
10,000,000
CumuJative Barrels Injected
Copyríght 8&A 2004
)
)
KU 24-7 Disposal Project
1M;r^, Conclusions
G I~\l.tl!l':c iX ~~...'i..\tl·U
~ The current "look-back" model gives similar results to the pre-
injection model study conducted in 1996
~ The fracture height is expected to be contained by a series of
substantial coal seams above and below the perforated interval
~ A current fracture height of 300-400 feet is expected, with a
length of 3000-3200 feet ,/'-)
~ Extension of the injection volume up to/~.8/million barrels
should not result in excessive growth in'fytcture length or
height '
~ The two tubing strings appear to be in communication, so
accurate localization of injection is not possible
~ Data used to constrain the model are incomplete and the results
presented here are based on general trends of the observed
Injection pressure and may not be accurate
Copyright BM 2004
The results of the model are as accurate as can be, based on the available
data. In-situ stresses and rock properties are based on digital log data, with
poorly defined estimates of original and current pore pressures in the disposal
zones and surrounding rocks. No direct measurements åf frac geometry or
growth have ever been made to help constrain the model. Within these
limitations, the current model predictions give results similar to the previous
model study. Fracture height is predicted to be dominated by bounding coals.
Continued injection of up to 1.8 million barrels of slurry is not predicted to
substantially alter the current fracture geometry.
11
#7
)
(~~":,,,,Q,U,l""- ?,..I ' II\" '~~,,' ',',!:J,',rr
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/lP
,LñJ
FRANK H. MURKOWSKI, GOVERNOR
A"ßA~1iA. OIL Ala) GAS
CONSERVATION COltDllSSION
333 W. TH AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276·7542
September 27, 2004
Proposals to Amend Underground Injection Orders to Incorporate
Consistent Language Addressing the Mechanical Integrity of Wells
The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion,
proposes to amend the rules addressing mechanical integrity of wells in all existing area injection
orders, storage injection orders, enhanced recovery injection orders, and disposal injection
orders. There are numerous different versions of wording used for each of the rules that create
confusion and inconsistent implementation of well integrity requirements for injection wells
when pressure communication or leakage is indicated. In several injection orders, there are no
rules addressing requirements for notification and well disposition when a well integrity failure
is identified. Wording used for the administrative approval rule in injection orders is similarly
inconsistent.
The Commission proposes these three rules as replacements in all injection orders:
Demonstration of Mechanical Integrity
The mechanical integrity of an injection well must be demonstrated before injection
begins, at least once every four years thereafter (except at least once every two years in
the case of a slurry injection well), and before returning a well to service following a
workover affecting mechanical integrity. Unless an alternate means is approved by the
Commission, mechanical integrity must be demonstrated by a tubing/casing annulus
pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical
depth of the packer, whichever is greater, that shows stabilizing pressure and does not
change more than 10 percent during a 30 minute period. The Commission must be
notified at least 24 hours in advance to enable a representative to witness mechanical
integrity tests.
Well Integrity Failure and Confinement
Whenever any pressure communication, leakage or lack of injection zone isolation is
indicated by injection rate, operating pressure observation, test, survey, log, or other
evidence, the operator shall immediately notify the Commission and submit a plan of
corrective action on a Form 10-403 for Commission approval. The operator shall
immediately shut in the well if continued operation would be unsafe or would threaten
contamination of freshwater, or if so directed by the Commission. A monthly report of
daily tubing and casing annuli pressures and injection rates must be provided to the
Commission for all injection wells indicating well integrity failure or lack of inj ection
zone isolation.
Administrative Actions
Unless notice and public hearing is otherwise required, the Commission may
administratively waive or amend any rule stated above as long as the change does not
promote waste or jeopardize correlative rights, is based on sound engineering and
geoscience principles, and will not result in fluid movement outside of the authorized
injection zone.
The following table identifies the specific rules affected by the rewrite.
Injection Order
"Demonstration of
Mechanical
Integrity"
Affected Rules
"Well Integrity
Failure and
Confinement"
"Administrative
Action"
Area Injection Orders
AIO 1 - Duck Island Unit
AIO 2B - Kuparuk River
Unit; Kuparuk River,
Tabasco, Ugnu, West Sak
Fields
AIO 3 - Prudhoe Bay Unit;
Western Operating Area
¡ AID 4C - Prudhoe Bay Unit;
Eastern Operating Area
AIO 5 - Trading Bay Unit;
McArthur River Field
AIO 6 - Granite Point Field;
Northern Portion
AIO 7 - Middle Ground
Shoal; Northern Portion
AIO 8 - Middle Ground
Shoal; Southern Portion
AIO 9 - Middle Ground
Shoal; Central Portion
AIO 1 DB - Milne Point Unit;
Schrader BlutI: Sag River,
Kuparuk River Pools
AIO 11 - Granite Point
Field; Southern Portion
AIO 12 - Trading Bay Field;
Southern Portion
AIO 13A - Swanson River
Unit
AIO 14A - Prudhoe Bay
Unit; Niakuk Oil Pool
AIO 15 - West McArthur
6
7
9
6
7
9
6 7 9
6 7 9
6 6 9
6 7 9
6 7 9
6 7 9
6 7 9
4 5 8
5 6 8
5 6 8
6 7 9
4 5 8
5 6 9
)
')
Affected Rules
"Demonstration of "Well Integrity "Administrative
Injection Order Mechanical Failure and Action"
Integrity" Confinement"
River Unit
AIO 16 - Kuparuk River 6 7 10
Unit; Tarn Oil Pool 6 8
AIO 1 7 - Badami Unit 5
AIO 18A - Colville River 6 7 11
Unit; Alpine Oil Pool
AIO 19 - Duck Island Unit; 5 6 9
Eider Oil Pool
AIO 20 - Prudhoe Bay Unit; 5 6 9
Midnight Sun Oil Pool
AIO 21 - Kuparuk River 4 No rule 6
U nit; Meltwater Oil Pool
AIO 22C - Prudhoe Bay 5 No rule 8
Unit; Aurora Oil Pool 6 9
AIO 23 - Northstar Unit 5
AIO 24 - Prudhoe Bay Unit; 5 No rule 9
Borealis Oil Pool
AIO 25 - Prudhoe Bay Unit; 6 8 13
Polaris Oil Pool
AIO 26 - Prudhoe Bay Unit; 6 No rule 13
Orion Oil Pool
Disposal Injection Orders
D 10 1 - Kenai Unit; KU No rule No rule No rule
WD-l
DIO 2 - Kenai Unit; KU 14- No rule No rule No rule
4
DIO 3 - Beluga River Gas No rule No rule No rule
Field; BR WD-l
DIO 4 - Beaver Creek Unit; No rule No rule No rule
BC-2
DIO 5 - Barrow Gas Field; No rule No rule No rule
South Barrow #5
DIO 6 - Lewis River Gas No rule No rule 3
Field; WD-l
DIO 7 - West McArthur 2 3 5
River Unit; Wl\1RU D-l
DIO 8 - Beaver Creek Unit; 2 3 5
BC-3
DIO 9 - Kenai Unit; KU 11- 2 3 4
17
DIO 10 - Granite Point 2 3 5
Field; GP 44-11
Injection Order
"Demonstration of
Mechanical
Integrity"
2
---
010 11 - Kenai Unit; KU
24-7
DIO 12 -- Badami Unit; WD-
1, WD-2
010 13- North Trading Bay
Unit; S-4
010 14 -. Houston Gas
Field; Well #3
oro 15 - North Trading Bay
Unit; S-5
OIO 16 - WestMcArthur
River Unit; WMRU 40
010 17 ,- North Cook Inlet
Unit; NCrU A-12
010 19 - Granite Point
Field; W. Granite Point State
17587 #3
01020 - Pioneer Unit; Well
1702-15DA WDW
DIO 21 - Flaxman Island;
Alaska State A - 2
010 22 - Redoubt Unit; RU
01
DIO 23 - Ivan River Unit;
IRU 14-31
DIO 24 - Nicolai Creek
Unit; NCU #5
DIO 25 - Sterling Unit; SU
43-9
010 26 - Kustatan Field;
KFl
Storage Injection Orders
SIO 1 - Prudhoe Bay Unit,
Point McIntyre Field #6
SIO 2A- Swanson River
Unit; KGSF #1
SIO 3 - Swanson River Unit;
KGSF #2
Enhanced Recovery Injection Orders
ErO 1 - Prudhoe Bay Unit;
Prudhoe Bay Field, Schrader
Bluff Formation Well V-I05
2
2
2
2
2
2
3
3
3
3
No rule
3
3
No rule
2
2
No rule
Affected Rules
'"Well Integrity "Administrative
Failure and Action"
Confìnement"
3 4
3 5
3 6
3 5
3 Rule not numbered
3 5
3 6
4 6
4 6
4 7
No rule 6
No rule 6
Order expired
4 7
4 7
No rule No rule
No rule 6
No rule 7
No rule
8
Injection Order
EIO 2 - Redoubt Unit; RU-6
)
"Demonstration of
Mechanical
Integrity"
5
')
Affected Rules
"Well Integrity
Failure and
Confinement"
8
" Administrative
Action"
9
I
02-902 (Rev. 3/94)
Publisher/Original Copies: Department Fiscal, Department, Receiving
;\O.FRM
STATE OF ALASKA
ADVERTISING
ORDER
~EE BOTTOM Ft)RINVQICEADORESS
NOTICE TO PUBLISHER ADVERTISING ORDER NO.
INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO, CERTIFIED AO-02514016
AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF
ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE
F
AOGCC
333 West th Avenue, Suite 100
Aunchorage,AJ( 99501
907-793-1221
AGENCY CONTACT DATE OF A.a.
R
o
M
Jody Colombie September ?7, )004
PHONE PCN
(907) 793 -] ?? 1
DATES ADVERTISEMENT REQt:IRED:
T
o
Journal of Commerce
301 Arctic Slope Ave #350
Anchorage, AK 99518
October 3,2004
THE MA TERJAL BETWEEN THE DOUBLE LINES MlJST BE PRINTED IN ITS
ENT(RETY ON THE DATES SHOWN.
SPECIAL INSTRUCTIONS:
United states of America
AFFIDAVIT OF PUBLICATION
REMINDER
State of
SS
INVOICE MUST BE IN TRIPLICATE AND MUST
REFERENCE THE ADVERTISING ORDER NUMBER.
A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION
MUST BE SUBMITTED WITH THE INVOICE.
ATTACH PROOF OF PUBLICATION HERE.
division.
Before me, the undersigned, a notary public this day personally appeared
who, being first duly sworn, according to law, says that
he/she is the
of
Published at
in said division
and
state of
and that the advertisement, of which the annexed
is a true copy, was published in said publication on the
day of
2004, and thereafter for _ consecutive days, the last
publication appearing on the _ day of
, 2004, and that
the rate charged thereon is not in excess of the rate charged private
individuals.
Subscribed and sworn to before me
This _ day of
2004,
Notary public for state of
My commission expires
Public Notices
)
ì)
lof2
9/29/2004 I: 10 PM
Public Notices
PJ.ea.se find the attached Notice an~.AttachmeJ:lffortheprop()sed amendrnent of
un¢lerground injection orders and the 1?ublic NoticeHappyVa~ley #10.
Jody Colombie
20f2
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9/29/2004 1: 10 PM
Public Notice
)
)
Subject: Public Notice
From: Jody Colombie <jody_colombie@admin.state.ak.us>
J?~te: 'Ye~, ~9 S,e,p2004 ~.2:55:26 -0800
Jº·':.".,I~g;~l@~l~s~åjqt.1Ó1.m·ç~fu ',"".'.
Please publish the attached Notice on October 3, 2004.
Thank you.
Jody Colombie
Content-Type: applicationlmsword
Mechanical Integrity of Wells Notice.doc
Content-Encoding: base64
Content-Type: applicationlmsword
Ad Order form.doc
Content-Encoding: base64
1 of 1
9/29/2004 1: 10 PM
Citgo Petroleum Corporation
PO Box 3758
Tulsa, OK 74136
Mary Jones
XTO Energy. Inc.
Cartography
810 Houston Street, Ste 2000
Ft. Worth, TX 76102-6298
/1al/¿:d lð¡íþ~
David McCaleb I
IHS Energy Group
GEPS
5333 Westheimer, Ste 100
Houston, TX 77056
Kelly Valadez
Tesoro Refining and Marketing Co.
Supply & Distribution
300 Concord Plaza Drive
San Antonio, TX 78216
Robert Gravely
7681 South Kit Carson Drive
Littleton, CO 80122
George Vaught, Jr.
PO Box 13557
Denver, CO 80201-3557
Jerry Hodgden
Hodgden Oil Company
408 18th Street
Golden, CO 80401-2433
Richard Neahring
NRG Associates
President
PO Box 1655
Colorado Springs, CO 80901
John Levorsen
200 North 3rd Street, #1202
Boise.ID 83702
Kay Munger
Munger Oil Information Service, Inc
PO Box 45738
Los Angeles, CA 90045-0738
Samuel Van Vactor
Economic Insight Inc.
3004 SW First Ave.
Portland, OR 97201
Michael Parks
Marple's Business Newsletter
117 West Mercer St, Ste 200
Seattle, WA 98119-3960
Mark Wedman
Halliburton
6900 Arctic Blvd.
Anchorage, AK 99502
Schlumberger
Drilling and Measurements
2525 Gambell Street #400
Anchorage, AK 99503
David Cusato
200 West 34th PMB 411
Anchorage. AK 99503
Baker Oil Tools
4730 Business Park Blvd., #44
Anchorage. AK 99503
Ciri
Land Department
PO Box 93330
Anchorage, AK 99503
Jill Schneider
US Geological Survey
4200 University Dr.
Anchorage, AK 99508
Gordon Severson
3201 Westmar Cr.
Anchorage, AK 99508-4336
Jack Hakkila
PO Box 190083
Anchorage, AK 99519
Darwin Waldsmith
PO Box 39309
Ninilchick, AK 99639
James Gibbs
PO Box 1597
Soldotna. AK 99669
Kenai National Wildlife Refuge
Refuge Manager
PO Box 2139
Soldotna, AK 99669-2139
Penny Vadla
399 West Riverview Avenue
Soldotna, AK 99669-7714
Richard Wagner
PO Box 60868
Fairbanks. AK 99706
Cliff Burglin
PO Box 70131
Fairbanks, AK 99707
Bernie Karl
K&K Recycling Inc.
PO Box 58055
Fairbanks. AK 99711
Williams Thomas
Arctic Slope Regional Corporation
Land Department
PO Box 129
Barrow, AK 99723
North Slope Borough
PO Box 69
Barrow. AK 99723
· [Fwd: Re: Consistent Wording for Injection Jers - Well Integrity ...
)
Subj.ect: ,[Fwd:,' Re':, ,'C·<?í1s.istent, ,Wof(iìl}~...,fº1"'. ~J.~~ti()ll. ,9rde;s","'~"..,vye.~l,,#1t¢g:ri~~.'.'(R~viseº)J
F~o~:, John Norrnan".<j0ht1--"nOrman(@aªmil1,state.~.µ~>
pate: Fri, 01ûct 200411:09:26~0800
To: Jody J Colombie <jody_colombie@admin.state.ak.us>
more
-------- Original Message --------
Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised)
Date:Wed, 25 Aug 2004 16:49:40 -0800
From:Rob Mintz <robert lTIintz@law.state.ak.us>
To:jim regg@admin.state.ak.us
CC:dan seamount@admin.state.ak.us, john norrnan@admin.state.ak.us
Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well
integrity and confinement rule:
"The operator shall shut in the well if so directed by the Commission."
My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by
going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict
requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the
authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of
integrity, etc.
»> James Regg <jim regg@admin.state.ak.us> 8/25/2004 3:15:06 PM »>
Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits;
also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...J to set
apart from your questions).
Jim Regg
Rob Mintz wrote:
Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based
on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown
as redlines on the second document attached.
»> James Regg <jim regg(C4admin.state.ak.us> 8/17/20044:33:52 PM »>
Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well
integrity that I have integrated into the proposed fix.
Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity:
- "Demonstration of Tubing/Casing Annulus Mechanical Integrity"
- "Well Integrity Failure"
- "Administrative Actions".
This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to
prepare the public notice.
Main points -
Demonstration of Tubing/Casing Annulus Mechanical Integrity
- standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate
methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing
lof2
10/2/2004 4:07 PM
[Fwd: Re: Consistent Wording for Injection G,u.ers - Well Integrity ...
- specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more
frequent MITs when communication demonstrated)
- establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current
practice (but not addressed in regulations)
Well Integrity Failure
- retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25
and 26)
- consistent language regardless of type of injection (disposal, EOR, storage);
- eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if
there is no threat to freshwater;
- eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify");
- removes language about notifying "other state and federal" agencies;
- requires submittal of corrective action plan via 10-403;
- requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we
currently impose when notified of leak or pressure communication;
- notice and action not restricted to leaks above casing shoe as stated in several DIOs
Administrative Actions
- adopts "Administrative Actions" title (earlier rules used "Administrative Relief');
- consistent language regardless of type of injection (disposal, EOR, storage);
- uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.;
- adds geoscience to "sound engineering principles";
- language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of
protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone"
Jim Regg
John K. Norman <John Norman(ãJadmin.state.us>
Commissioner
Alaska Oil & Gas Conservation Commission
20f2
10/2/2004 4:07 PM
.[Fwd: Re: Consistent Wording for Injection 1rs - Well Integrity...
)
Std>ject: [Fwd: ,Re: "ConsistentW ording for In.jéctionOrder$ '~'"Wèl1~tégrity ,,(R.evis~ci)]
~r()m: John Nonnan <john_norman@admì:n~state.ak.,µs>
Date: Fri, 01 Oct 2004 11:08:55 -0800
T9;';Jody J Colombie <jody_colombie@admin.state.ak.us>
please print all and put in file for me to review just prior to hearing on these amendments. thanx
-------- Original Message --------
Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised)
Date:Thu, 19 Aug 2004 15:46:31 -0800
From:Rob Mintz <robert mintz@law.state.ak.us>
To:dan seamount@admin.state.ak.us, jim regg@admin.state.ak.us,
john nOffi1an@admin.state.ak.us
Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based
on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as
redlines on the second document attached.
»> James Regg <jim regg@2admin.state.ak.us> 8/17/20044:33:52 PM »>
Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well
integrity that I have integrated into the proposed fix.
Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity:
- "Demonstration of Tubing/Casing Annulus Mechanical Integrity"
- "Well Integrity Failure"
- "Administrative Actions".
This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare
the public notice.
Main points -
Demonstration of Tubing/Casing Annulus Mechanical Integrity
- standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods
(e.g., temp survey, logging, pressure monitoring in lieu of pressure testing
- specific to Ala 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more
frequent MITs when communication demonstrated)
- establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice
(but not addressed in regulations)
'Veil Integrity Failure
- retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and
26)
- consistent language regardless of type of injection (disposal, EOR, storage);
- eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if
there is no threat to freshwater;
- eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify");
- removes language about notifying "other state and federal" agencies;
- requires submittal of corrective action plan via 10-403;
- requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we
currently impose when notified of leak or pressure communication;
- notice and action not restricted to leaks above casing shoe as stated in several DIOs
Administrative Actions
lof2
10/2/20044:07 PM
[Fwd: Re: Consistent Wording for Injection Glùers - Well Integrity...
- adopts "Administrative Actions" title (earlier rules used" Administrative Relief');
- consistent language regardless of type of injection (disposal, EOR, storage);
- uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.;
- adds geoscience to "sound engineering principles";
- language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of
protecting "freshwater", "aquifers", "USDWs"; "risk oftluid movement"; "fluid escape from disposal zone"
Jim Regg
John K. Norman <John Norman@admin.state.us>
Commissioner
Alaska Oil & Gas Cmservation Commission
, Content-Type: applicationlmsword
Injection Order language - questions.doc
Content-Encoding: base64
Content-Type: applicationlmsword
Injection Orders language edits. doc
Content-Encoding: base64
20f2
10/2/20044:07 PM
)
)
Standardized Language for Injection Orders
Date: August 17, 2004
Author: Jim Regg
Demonstration of Tubing/Casing Annulus Mechanical Integrity
The mechanical integrity of an injection well must be demonstrated before injection begins, after
a workover affecting mechanical integrity, and at least once every 4 years while actively
injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical
integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by
the vertical depth, whichever is greater, must show stabilizing pressure and may not change more
than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity
must be approved by the Commission. The Commission must be notified at least 24 hours in
advance to enable a representative to witness pressure tests.
Well Integrity Failure and Confinement
The tubing, casing and packer of an injection well must demonstrate integrity during operation.
The operator must immediately notify the Commission and submit a plan of corrective action on
F orrn 10-403 for Commission approval whenever any pressure communication, leakage or lack
of injection zone isolation is indicated by injection rate, operating pressure observation, test,
survey, or log. If there is no threat to freshwater, injection may continue until the Commission
requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli
pressures and injection rates must be provided to the Commission for all injection wells
indicating pressure communication or leakage.
Administrative Actions
Unless notice and public hearing is otherwise required, the Commission may administratively
waive or amend any rule stated above as long as the change does not promote waste or
jeopardize correlative rights, is based on sound engineering and geoscience principles, and will
not result in fluid movement outside of the authorized injection zone.
Standardized Language for Injection Orders
Date: August 17, 2004
Author: Jim Regg
Demonstration of Tubing/Casing Annulus Mechanical Integritv
The mechanical integrity of an injection well must be demonstrated before injection begins, at
least once every four years thereafter (except at least ünce every two years in the case of a slurry
injection well), and before returnin,g a \:vcll to service followin.Q: afk,~ a workover affecting
mechanical integrity, and at lea~;t once every 4 year~; \vhile actively injecting. For slurry
injection \yclls, the tubing/casing annulus inust be t~st~d f()t" mechanical integrity every 2 yeB-fS-:
Unless an altelllate t11cans is approved by the COlnnlission. Inechanical integrity 111ust be
dcrnonstrared by a tubin.Q: pressure test using a +-A:e MI+-surface pressure of must be 1500 psi or
0.25 psi/ft multiplied by the vertical depth, whichever is greater, that m-H-St-show~ stabilizing
pressure that doesand lnay not change more than 1 O~ percent during a 30 minute period. ---A:aÿ
altenlate illc::ms of dClnonstrating Inechanìcal integrity must be approved by the COlnnlission.
The Commission must be notified at least 24 hours in advance to enable a representative to
witness pressure tests.
Well Integrity Failure and Confinement
Except as othenvise provided in this rule, +lhe tubing, casing and packer of an injection well
must dèmml~;trQte Inaintain integrity during operation. \Vhenever any pressure conlffiunication,
teakage or lack of injection zone isolation is indicated by injection rate, operating pressure
observation, test, survey, log. or other evidence. t+he operator fftHS-t-shaIl immediately notify the
Commission and submit a plan of corrective action on a Fonn 10-403 for Commission approval.:.
whenever any pressure cOllununication, leakage or lack of injection zone isolation is indicated by
injection ratc. operating pressure observation, test, ~:;urvey, or log. The operator shall shut in the
well if so directed bv the Commission. The operator shall shut in the \-vell \vithout awaiting a
response tÌ"om thê Comlnission if contìnued operation would be unsafe or would threaten
contamination of fresh\vaterIf there is no threat to freslnvater, injection tTIay continue until the
COl11111ìssion requires the \,vell to be shut in or secured. Until corrective action is successfully
cOll1pletcd, Aª monthly report of daily tubing and casing annuli pressures and injection rates
must be provided to the Commission for all injection wells indicating pressure communication or
leakage.
Administrative Actions
Unless notice and public hearing is otherwise required, the Commission may administratively
waive or amend any rule stated above as long as the change does not promote waste or
jeopardize correlative rights, is based on sound engineering and geoscience principles, and will
not result in fluid movement outside of the authorized injection zone.
.[Fwd: Re: [Fwd: AOGCC Proposed WI Lan~ 1e for Injectors]]
)
$llbJect: [Fwd: Re: [Fwd: AOGCCProposed WI Language for Injectors]]
~rºm:',.Winton',Aubet1'<winto~aubert@adtnin.state.ak.,us>
~~'~~·~·.,.2ñ:ll!:~,~,..,,()st~9P1-·H~:4~:?f:~P§9q., :" ',' '. ,'.' ','... ',,',.' ",' '.'".",'".'..". ',... ""...',,".,','.".',
1;Ø~:JoqYJ'(391~1!l~~~~'§j,Ç)clý2Ç~~oinbj¢@a4rµirt.$~~t~~~~:t1~*;'i ,':' '
This is part of the record for the Nov. 4 hearing.
WGA
-------- Original Message --------
Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors]
Date: Thu, 28 Oct 2004 09:41:55 -0800
From: James Regg <jim regg@admin.state.ak.us>
Organization: State of Alaska
To: Winton Aubert <winton aubert@admin.state.ak.us>
References: <41812422.8080604@admin.state.ak.us>
These should be provided to Jody as part of public review record
Jim
Winton Aubert wrote:
FYI.
--------
Original Message --------
AOGCC Proposed WI Language for
Tue, 19 Oct 2004 13:49:33 -0800
Engel, Harry R <EngeIHR@BP.com>
winton aubert@admin.state.ak.us
Injectors
Subject:
Date:
From:
To:
Winton...
Here are the comments we discussed.
Harry
*Frorn: * NSU, ADW Well Integrity Engineer
*Sent: * Friday, October 15, 2004 10:43 PM
*To: * Rossberg, R Steven¡ Engel, Harry R¡ Cismoski, Doug Ai NSU, ADW Well
Operations Supervisor
*Cc: * Mielke, Robert L.¡ Reeves, Donald F¡ Dube, Anna T¡ NSU, ADW Well Integrity
Engineer
*Subject: * AOGCC Proposed WI Language for Injectors
Hi Guys.
John McMullen sent this to us, it's an order proposed by the AOGCC to replace the
well integrity related language in the current Area Injection Orders. Listed
below are comments, not sure who is coordinating getting these in front of
I Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few
, comments, but could live with the current proposed language. Note the proposed
public hearing date is November 4.
The following language does not reflect what the slope AOGCC inspectors are
currently requiring us to do:
"The mechanical integrity of an injection well must be demonstrated before
injection begins, at least once every four years thereafter (except at least once
every two years in the case of a slurry injection well), and * before* **
10f3
10/28/2004 11:09 AM
[Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors]]
returning a well to service following a workover affecting mechanical integrity."
After a workover, the slope AOGCC inspectors want the well warmed up and on
stable injection, then we conduct the AOGCC witnessed MITIA. This language
requires the AOGCC witnessed MITIA before starting injection, which we are doing
on the rig after the tubing is run. Just trying to keep language consistent with
the field practice. If "after" was substituted for "before", it would reflect
current AOGCC practices.
It would be helpful if the following language required reporting by the "next
working day" rather than "immediately", due to weekends, holidays, etc. We like
to confer with the APE and get a plan finalized, this may prevent us from doing
all the investigating we like to do before talking with the AOGCC.
"Whenever any pressure communication, leakage or lack of injection zone isolation
is indicated by injection rate, operating pressure observation, test, survey,
log, or other evidence, the operator shall * immediately* ** notify the
Commission"
This section could use some help/wordsmithing:
"A monthly report of daily tubing and casing annuli pressures and injection rates
must be provided to the Commission for all injection wells indicating well
integrity failure or lack of injection zone isolation."
Report content requirements are clear, but it's a little unclear what triggers a
well to be included on this monthly report. Is it wells that have been reported
to the AOGCC, are currently on-line and are going through the Administrative
Action process? A proposed re-write would be:
"All active injection wells with well integrity failure or lack of injection zone
isolation shall have the following information reported monthly to the
Commission: daily tubing and casing annuli pressures, daily injection rates."
Requirements for the period between when a well failure is reported and when an
administrative action is approved are unclear. This document states "the operator
shall immediately notify the Commission and submit a plan of corrective action on
a Form 10-403". If we don't plan to do any corrective action, but to pursue an
AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider
an AA as "corrective action".
Let me know if you have any questions.
Joe
-----Original Message-----
From: Kleppin, Daryl J
Sent: Wednesday, September 29, 2004 1:37 PM
To: Townsend, Monte A¡ Digert, Scott A¡ Denis, John R (ANC) ¡ Miller,
Mike E¡ McMullen, John C
Subject: FW: Public Notices
FYI
-----Original Message-----
From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us
Sent: Wednesday, September 29, 2004 1:01 PM
Subject: Public Notices
Please find the attached Notice and Attachment for the proposed amendment of
underground injection orders and the Public Notice Happy Valley #10.
Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of
Wells Notice.doc»
2 of3
10/28/2004 11:09 AM
#6
)
~~~~E : F !Æ~!Æ~~~~
)
ALASKA OIL AND GAS
CONSERVATION COMMISSION
TONY KNOWLES, GOVERNOR
333 W. pH AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
January 11, 2002
Mr. Kyle Parker
Patton Boggs LLP
1031 West Fourth Avenue, Suite 504
Anchorage, AK 99501
\) \0 \ \
Re: Class II Disposal of Tracer Returns
Dear Mr. Parker:
You have asked the Commission for confirmation that your client, Marathon Oil
Company ("Marathon"), is permitted to dispose of certain radioactive tracer returns in the
Kenai Unit 24-7 Class II disposal well.
Disposal Injection Order No. 11, issued by the Commission on November 21, 1996,
authorizes the operator of the Kenai Unit 24-7 well to inject "Class II oil field fluids" in a
specified interval of the well in conformance with 20 AAC 25. The Commission's
regulation on underground disposal, 20 AAC 25.252, refers to 40 C.F.R. 144.6(b) for the
classification of a Class II well. The latter provision, in turn, describes a Class II well, in
relevant part, as a well that injects fluids
that are brought to the surface in connection with . . . conventional oil or
natural gas production and may be commingled with waste waters from
gas plants which are an integral part of production operations, unless those
waters are classified as a hazardous waste at the time of injection.
40 C.F.R. 144.3 provides that the term "[h]azardous waste means a hazardous waste as
defined in 40 CFR 261.3." The latter regulation excludes the following from the
definition of hazardous waste: "Drilling fluids, produced waters, and other wastes
associated with the exploration, development, or production of crude oil, natural gas or
geothermal energy." See 40 C.F.R. 261.3(a)(I) and 40 C.F.R. 261.4(b)((5).
Marathon has employed the fmn ProTechnics to assist in evaluating well completions
using ProTechnics' radioactive tracers known as "Zero Wash." You have informed the
Commission that the tracers aid in detailing the completion placement and effectiveness
of Marathon's hydraulic fracturing and acidizing treatments. You have also informed the
Commission that the use and disposal of the radioactive tracers are regulated by the
Nuclear Regulatory Commission.
Mr. Kyle Parker
January 11, 2002
Page 2 of2
)
)
The Commission understands that sands returned to the surface may contain some Zero
Wash tracer beads and that it is such sands that Marathon wishes to dispose of in the
Kenai Unit 24-7 well. Since this material has been brought to the surface in cormection
with conventional oil or gas production operations, it appears to qualify as Class II waste.
The second criterion listed in 40 C.F.R. 144.3, concerning classification as hazardous
waste, may apply only to waste waters from gas plants. However, even if this criterion
applies to the Zero Wash tracer returns, they appear to qualify as non-hazardous wastes
under the exclusion for "wastes associated with the exploration, development, or
production of crude oil [ or] natural gas."
It should be noted that the disposal of unused tracer material is an entirely different
matter. Such material would not appear to qualify as a Class II waste. The Commission
understands that the only tracer material Marathon proposed to dispose of in the Kenai
Unit 24-7 well is material that has actually been used downhole for bona fide well
completion purposes.
Please note further that the Commission's authorization under Disposal Injection Order
No. 11 does not relieve the operator from the responsibility to obtain any additional
authorizations that may be required from federal, state, or local authorities.
S incerel y,
G1'vW1N(/JuÁyC ~~
Cammy (Q)echsli Taylor
Chair
COT\jjc
#5
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\ '\ ¡'
TONY KNOWLES, GOVERNOR
.-.
'''; 'I. "., ~
ALASIiA OIL AND GAS
CONSERVATION COMMISSION
3001 PORCUPINE DRIVE
ANCHORAGE, ALASKA 99501-3192
PHONE: (907) 279-1433
FAX: (907) 276-7542
November 25, 1998
Gary Eller
Production Engineer
Marathon Oil Company
P.O. Box 196168
J\nchorage, ÄJaska 99519-6168
Re: Kenai Gas Field Well 24-7, Request for extension to DIO #11
Dear Mr. Eller:
The Commission has reviewed your November 20, 1998, request to approve an extension
to Disposal Injection Order ("DIO") #11 which authorizes injection of Class II oilfield
waste into the Kenai Unit ("KU") 24-7 well. Under 20 AAC 25.2520), if disposal
operations are not begun within 24 months after the approval date, the approval will
expire unless the Commission authorizes an extension.
The Commission approved DIO #11 on November 20, 1996. Marathon has not yet used
the well for disposal injection, but anticipates doing so within the next 24 months. The
well has not been physically altered since the Commission granted DIO #11, and Marathon
continues to perform yearly mechanical integrity tests (liMiT") on the well.
The Commission hereby approves the requested extension to DIO # 11, effective
November 21, 1998. A MIT must be performed on KU 24-7 prior to initial disposal and
the results forwarded to the Commission. The Commission must also be notified at least
24 hours prior to the MIT to allow a representative to witness the test.
David W. Johnst'
Chairman
#4
Notice of Public Hearing
STATE OF ALASKA
Alaska Oil and Gas Conservation Commission
Re: The application of Marathon Oil Company for an order allowing the
underground dispoal of class II fluids by injection into Kenai Unit well
24-7 in the Kenai Gas Field.
Marathon Oil Company by letter dated September 16, 1996 has
requested the Ala\ska Oil And Gas Conservation Commission to issue an
order in conformance with 20 AAC 25.252. The order would authorize the
disposal of class II fluids by injection into the Sterling Formation in well KU
24-7 at the Kenai Gas Field on the Kenai Penn insula in Southcentral Alaska.
A person who may be harmed if the requested order is issued may file
a written protest prior to 4:00 PM November 11, 1 996 with the Alaska Oil
and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage,
Alaska 99501, and request a hearing on the matter. If the protest is timely
filed and raises a substantial and material issue crucial to the Commission's
determination, a hearing on the matter will be held at the above address at
9:00 am on November 29, 1.996 in conformance with 20 AAC 25.540. If a
hearing is to be held, interested parties may confirm this by calling the
Commission's office, (907) 279-1433 after November 11, 1996. If no
protest is filed, the Commission will consider the issuance of the order
without a hearing.
If you are a person with a disability who may need a special
modification in order to comment or to attend the public hearing, please
contact Diana FI~~_~,.a~. 27~-·~-~3 n"o la, t, r~n fv~be~, '6',1,996.
~ ~----~ =- --~::);)
~-_.,;:b ...~
David W. Jphnston, C irman
Alaska Oil a'rì~~s C~~ ervation Commission
Published October 26, 1 996
A002714015 ADN
#3
)
Alaska F )n
Domestic I (oduction
~) Marathon
I ,MARATHON Oil Company
P.O. Box 196168
Anchorage, AK 99519-6168
Telephone 907/561-5311
November 20, 1998
Ms. Wendy Mahan
Alaska Oil & Gas Conservation Commission
3001 Porcupine Drive
Anchorage, AK 99501-3192
Reference: Kenai Gas Field, Well KU 24-7
Dear Ms Mahan:
On November 21, 1996, the AOGCC approved Disposal Injection Order (010)
No. 11 which authorized the disposal of Class II oilfield waste in well KU 24-7
in the Kenai Gas Field. Since that time however, Marathon has not disposed
of any fluids into well KU 24-7. Instead, well KU 24-7 has served as a "backup"
disposal well to well KU 11-17, awaiting the day when we no longer can inject
into well KU 11-17.
Alaska Administrative Code 20 MC 25.252(j) states that injection approval will
expire 24 months after the approval date if disposal operations have not begun,
unless application for extension if approved by the commission. Approval for
well KU 24-7 is due to expire, and Marathon hereby requests a 24-month
extension of the injection permit for this well. Marathon considers it likely that
we will cease injection into well KU 11-17 and begin injection into KU 24-7
sometime in the next 24 months.
Physically, well KU 24-7 is in the same condition as it was when 010 No. 11
was approved in November 1996. A successful MIT test was performed on well
KU 24-7 in June 1998. Another MIT will be conducted on well KU 24-7
immediately prior to the start of disposal operations there.
Sin:s~
J. G ler
Prod t n Engineer
~~
_1ft" .
~~~
~~
OPS98\JGE11201
Enclosure
A subsidiary of USX Corporation
Environmentally aware for the long run.
OPERATOR:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
Marathon
FIELD I UNIT I PAD:
6/24/1998
DATE:
Kenai Gas Field
WD-1
81-0107
COMMENTS:
KU11-17
81-0176
COMMENTS:
KU 24-7
82 0016
COMMENTS:
COMMENTS:
COMMENTS:
PW
Packer
Fluid
2, 1 74
2,174
1500 min
4 112 544
P
7'~ 29#, N-80
L~"";>:
Drill {505 1500 min
Cuttings P SIW {505 9518,47#, N-80 3112 1126
Annulus pressure dropped to 1200 psi after test and observed with no change for thirly minutes.
0 0 0 0
1.600 1.600 1,600 1.600
480 480 480 480
1,650 1.650 1,650 1,650
P
1000
P
Drill 4313 1500 min
Cuttings P SIW 4313 9518, 47#, N-80 1078
Annulus pressure dropped to 1200 psi after test and observed with no change for thirly minutes.
930
1500 min
o
1500 min
o
..~
TBG. INJ. FLUID CODES
F = FRESH WATER INJ.
G = GAS INJ.
S = SALT WATER INJ.
N = NOT INJECTING
TEST TYPE:
M = ANNULUS MONITORING
P = STD ANNULUS PRESSURE TEST
R = INTERNAL RAD. TRACER SURVEY
A = TEMPERATURE ANOMALY TEST
D = DIFFERENTIAL TEMPERATURE TEST
ANNULAR FLUID: P.P.G.
DIESEL
GL YCOL
SALTWATER 8.8
DRILLING MUD
OTHER
WELL TEST:
Initial
4 - Year
Workover
Other Yearly
Distribution:
orig - Well File
c - Operator
c - Database
c - Trip Rpt File
c - Inspector
Grad.
0.00
0.00
0.46
0.00
0.00
OPERATOR REP SIGNATURE: Pete Iverson
I AOGCC REP SIGNATURE:
Lou Grimaldi
JQ9JFXFEXLS
(Rev 9/17196)
#2
October 14, 1996
Mr. Crandall,
Sorry for the delay in getting you this information.
I was out of town 9/29-10/13 due to an illness in the
family.
RtCt\\]tt)
()(,\ "1 '99G .
rl\\ßit'O{\
COm\"
&. Ga~ COOS.
~\a.~\(a 0\\ 1!\.nchoralJ0
Michael J. Stover
J
Alaska h. ..Jlon
Domestic Production
'M.) Marathon
I ,MARATHON Oil Company
P.O. Box 196168
Anchorage, AK 99519-6168
Telephone 907/561-5311
October 14, 1996
Alaska Oil & Gas Conservation Commission
Attention: Mr. Bob Crandall
3001 Porcupine Drive
Anchorage, AK 99501-3192
RE: Addendum to Application for Underground Injection
Kenai Gas Field, KU 24-7
Dear Mr. Crandall:
As per your verbal request of September 25, 1996 the following information is provided
in relation to the previously submitted application for disposal to Well KU 24-7.
Well KU 33-7, while more than 1/4 mile away from Well KU 24-7, will be included in the
Section 20 AAC 25.252(h) (Mechanical Integrity of Other Wells Within 1/4 mile Radius)
of the application for disposal to Well KU 24-7 as requested. Following is a description
of the production status, mechanical condition and cement bond of Well KU 33-7.
Production Status
KU 33-7 was dually completed in March, 1986 with the shortstring to Sterling Pool 6 and
the longstring to the Upper Beluga. The shortstring is presently active while the
longstring has been shut-in since 1986. Cumulative production from the shortstring is
5.64 BCF, while cumulative production from the longstring is only 0.053 BCF. The small
amount of production from the longstring is due to water productive intervals.
Mechanical Condition
There are no known mechanical problems with KU 33-7. The last bottom hole pressure
measurement occurred in 1994. This measurement indicated the short and long strings
to be isolated from one another. Attached is a copy of the wellbore diagram.
Cement BondinQ
Adequate cement bonding is present in the Sterling interval of KU 33-7 to protect fresh
water aquifers. The top of the Sterling interval (A8) is at 4018' md in KU 33-7. The
initial cement bond log dated 12/24/85 indicated good cement bonding from 4530' md
to total depth. Between 4018' md and 4530' md the cement bond was of poor quality.
Several remedial cement squeezes were performed between 1/17/86 and 1/26/86 with
squeeze perforations at depths of 4087-4089' md, 4343-4345' md and 4364-4366' md.
RECE\VEO
OCT 1 '7 '996
comm\ss\on
0" ~ Gas Cons.
'ê\as\(a i Ancl'\()fage
Environmentally aware for the long run.
A subsidiary of USX Corporation
)
Addendum to Application for Underground Injection
Kenai Gas Field, KU 24-7
October 14, 1996
Page 2
)
A second bond log run on 1/25/86 indicated adequate cement isolation across the
following intervals at or near the top of the Sterling horizon: 3995-4001' md,
4016-4020' md, 4034-4050' md and 4070-4080' md. A final cement squeeze of the
interval 4087-4089' md was peñormed following the cement bond log. Following this
cement squeeze all the cement squeeze peñorations were successfully tested to
1700 psi. Attached is a copy of the 1/25/86 cement bond log over the mentioned
intervals.
If additional information is required please contact me at 564-6428 or Michael Stover at
564-6403.
~inçe~. Iy YOf~, s,
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Jl Brock Riddle
Alaska Region Landman
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WELL KBU 33-7
CASING '& ABANDONMENT DETAIL
.
I. Elevation of Kelly Bushing at 0 ~ ;'
II. Cameron Dual 3-1/2- Tubing Hanger at-:25'
. Iii. 20·, 94+, H-40 Casing at 178'
IV. 13-3/8-, 61#,1<-55 Casing at 2025'
V. Otis Model "WD- Packer at 5,462'
VI. 5-, 18+, N-80 Scab Liner Between Packers
VII. Otis Model "WD- Packer at 5,5S6'
VIII. E. T.D. at 5,298' wI HOWCO Cmt. Retainer at 5,930'
IX. Top of Cmt. and 9-5/8- Float Collar at 6,443'
X. 9-5/8-, 47+, N-80 Casing at 6,529'
. TUBING DETAIL -.
LONG STRING: 2-3/8", 4.6#, N-80
... 1. 3-1/2- x 2-3/S- x-over at 26'
2. Otis "X A- Sliding Sleeve w/CLR a-t 4~06'
3. 2-3/8- x 3-1/2- x-over at 4917' ",-
4. Otis Model "RDH- Dual Packer at .~921~ (C/L)
. . - . - ...~ <Þ_
5. 3-1/2 x 2-3/8 x-over at4925'_
6. Otis "XA - Sliding Sleeve w/CLR at 4 ~ 6 5'
, , . .--..-
7. Blast Joints From 4984 to 5.1Q3· _
8. Otis "XA- Sliding Sleeve wiCLR at-_5166':
)d ~E D 9. 2-3/S- x 2-7/8- x-over at 5202' .
A 10. Straight Slot Locator ~ t 5202'
11. Otis Model "WD- Perm. Packer wi 4 - _~ore & Connection
at 5.203' (C/L of Packer at .5205'1-
12. Otis Seal Bore Extension at 5.20 ß'
. .
13. Two X-Overs From 4- to 2~71 8- to 2-3/8! at 5213'
14. Otis "X- Nipple at 5.225'
15. Otis WL Re-Entry Guide at 5239"
I
II
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REV. DATE
~_F_M___5/.~7/86
R.A.W.6/17/86
-~~~.
--
SHORT STRING: 2-3/89, 4.6_:/1:, N-BO
A. 3-112- x 2-3/8- x-over at 26' .
B. Otis "XA - Sliding Sleeve w/CLR at 4905'
, --
C. 2-3/8- x 3-1/2- x-over at 4917 N. ~ SHARMA
D. Otis Model "RDH- Dual Packer at 4 ~ 2 1 ' Ok...
E. 3-1/2- x 2-3/8- x-over at 4926'· -- JUN 1 7 1986 I
F. Otis "XN- Nipple at 4.937' ,
G. Bottom of Otis Mule Shoe at 4939'
PERFORATION RECORD
DA TE INTERVAL CONDITION
12/17/85 5,978'-5,990' Squeezed
12/17i85 5,940'-5,963' r Squeezed
12/22/85 5,847'-5,826' Upper Beluga Sd. Production
12/23/85 5,847'-5,826' Reperforate
12/24/85 5,798'-5,822' Upper Beluga Sd. Production
5,757'-5,772' Upper Beluga Sd. Production
5,696'-5,718' Upper Beluga Sd. Production
12/24/85 5,676'-5,683' Upper Beluga Sd. Production
5,543' -5,554' Squeezed
5,4&2'-5,501" Squeezed
5,3~8'-5,406' Upper Beluga Sd. Production
5,314'-5,324' Upper Beluga Sd~ Productlo~..
5,006'-5,095' Sterling Zone Production
(4,364'-4,366', 4,343'-4,345~ 4,087'-4,089') - Squeezed
WELL KBU 33-7
'WELL~- SCHEMATIC
DRAWN B.A. W. CKD.
APP'D.
SCALE NPNF
DATE 4/14/86
þ
UNION OIL COMPANY OF CALIFORNIA
ANCHORAGE I ALASKA
#1
)\
Alaska R )n
Domestic \', ,roduction
,M
MARATHON
, 4
Marathon
Oil Company
P.O. Box 196168
Anchorage, AK 99519-6168
Telephone 907/561-5311
September 16, 1996
CERTIFIED MAIL
Alaska Oil & Gas Conservation Commission
3001 Porcupine Drive
Anchorage, AK 99501-3192
RE: Application for Underground Injection
Kenai Gas Field, KU 24-7
Ladies and Gentlemen:
If you need additional
kz:\hp:\Jand\aogc916a.wpd
Enclosure
cc: Mr. Jim Segura - Salamatof Native Association, hic. - CERTIFIED MAIL
Mr. Gerald Booth - Cook Inlet Region, Inc. - CERTIFIED MAIL
RECEIVED
SEP 1 9 1996
A1aska Oil & Gas Cons. commission
AnchGr2.ge
A subsidiary of USX Corporation
Environmentally aware for the long run.
SECTION
Letter of Application for Injection (20 MC 25.252(a))
Location/Plat Maps (20 MC 25.252(c) (1))
Operator and Surface Owners (20 MC 25.252(c)(2))
Affidavit of Notice to Surface Owners and Operators
(20 MC 25.252(c)(3))
Geological/Reservoir Information Concerning Injection Zone
(20 MC 25.252(c)(4))
Well Log for KU 24-7 (20 MC 25.252(c)(5))
Well Casing Information (20 MC 25.252(c)(6))
Injection Fluid (20 MC 25.252(c)(7))
Average/Maximum Injection Pressures (20 MC 25.252(c)(8))
Fracture Information (20 MC 25.252(c)(9))
Formation Information (20 MC 25.252(c)(1 0))
Aquifer Exemption (20 MC 25.252(c)(11))
Mechanical Integrity (20 MC 25.252( d) through (g))
Mechanical Integrity of Other Wells within % Mile
Radius (20 MC 25.252(h))
Attachments
Attachment A
Attachment 8
Attachment C
Attachment D
Attachment E
Attachlllent F
Attachment G
)) \ ),
Alaska 011 and Gas Conservation Con. mission
Application for Underground Injection:
Kenai Gas Field, KU 24-7
Marathon Oil Company, Alaska Region
September 13, 1996
CONTENTS
PAGE
1
1
1
2
2
2
2
3
4
5
5
5
5
5
Location/Plat Maps
Affidavit of Notice to Surface Owners and Operators
Geological and Completion Information
Well Casing Diagram
Fracture Information
Formation Fluid
Aquifer Exemption
R£C£.\\J£\)
S (? ,9 '<j<jG
"" \5S\on
CQm",
&. Gas conS.
T:\\asK3. 0\\ p.ncrlûír.ge
) )
Alaska OÎI and Gas Conservation Commission
Application for Underground Injection:
Kenai Gas Field, KU 24-7
Letter of Application for Injection (20 AAC 25.252(a»
Marathon Oil Company is requesting an injection permit to authorize the conversion of Kenai Gas
Field KU 24-7, a watered out, shut-in gas well, from a producer to a Class II disposal well.
KU 24-7 was last completed in May 1982. The intended primary use of the converted well will be
for injection of produced fluids, ground and slurried drill muds and cuttings, and other workover
fluids from existing wells at Kenai Gas Field and Cannery Loop. Also, similar materials from
Marathon's exploration efforts on the Kenai Peninsula. These materials will be processed prior
to injection to limit, to the extent possible, plugging and fracturing in the injection zone. The
proposed grinding and injection system is shown in Figure 1.
The proposed injection will be into the Sterling A 10, A 11 and B2 intervals, at a true vertical depth
interval of 3726 to 3952 feet. These intervals produced 34 BCF of gas prior to being shut-in.
Geologic review indicates the zones to be water bearing at this time.
Location/Plat Maps (20 AAC 25.252(c)(1»
Location information is enclosed as Attachment A. Figure A-1 shows the regional location of the
Kenai Gas Field, which is located on the Kenai Peninsula. KU 24-7 is located on Production Pad
41-18.
The physical location of the subject well, KU 24-7, is indicated on Figure A-2. Figure A-3 shows
a graphic % mile radius from KU 24-7 at the A-8 horizon. As indicated on Figure A-3, no other
wells are within a % mile radius. The % mile radius is shown on the A8 structure map rather than
the A10, A11 or B2 since at the A8 horizon the KU 24-7 well bore is closest to any offset well.
This was done since it is expected any injection into the lower A 10, A 11 or B2 intervals will
eventually create fracture growth into the A8 interval.
A structure map of the Sterling A-8 is included as Figure A-4. Structure maps of the A 10, A 11 and
B2 are conformable to the A8. Attached as Figure A-5 is a copy of the well log for KU 24-7 with
the intended disposal intervals indicated.
Operator and Suñace Owners (20 AAC 25.252(c)(2»
The interested parties within the % mile radius surrounding KU 24-7 are as follows:
o Operator
Marathon Oil Company
3201 C Street, Suite 800
P.O. Box 196168
Anchorage, Alaska 99519-6168
1
t.(t\\jt.~
R £¡
t.? '\ 9 \Cjtj .
~ i.\SS\C~
~ C,Q~
C,C~"'·
.\ &. t)'3.S nf\e
\f'(}. G\\ 1\ \"Ir''ì\()~ \...'::)
}\\'3.st'- 1""\ ,,,,
)
Alaska Oil and Gas Conservation Commission
Application for Underground Injection:
Kenai Gas Field, KU 24-7
o Surface/Subsurface Owners:
Mr. Jim Segura, President
Salamatof Native Association, Inc.
P. O. Box 2682
Kenai, AK 99611
Mr. Gerald G. Booth
Cook Inlet Region, Inc. (CIRI)
2525 C Street, Suite 500
P. O. Box 93330
Anchorage, AK 99509-3330
Affidavit of Notice to Suñace Owners and Operators (20 AAC 25.252(c)(3»
An affidavit is enclosed as Attachment B.
Geological/Reservoir Information Concerning Injection Zone (20 AAC 25.252(c)(4»
A description of the geologic zone where the proposed injection will occur is enclosed as
Attachment C. Also, included in Attachment C is pertinent completion information for KU 24-7.
Well logs for KU 24-7 (20 AAC 25.252(c)(5»
Logs for KU 24-7 have previously been submitted to the Alaska Oil and Gas Conservation
Commission in accordance with [20 MC 25.071 (a) and (b). Refer to Attachment A, Figure
A-5 for a log section of the Sterling intervals in KU 24-7. The targeted injection interval is
noted on the log.
Well Casing Information (20 AAC 25.252(c)(6»
KU 24-7 is cased as shown in Attachment D. A wellbore schematic for the proposed injection
zone is shown. The casing is cemented in accordance with 20 MC 25.252(b) and will be
tested prior to injection in accordance with 20 MC 25.030(g). Integrity of the 3% inch tubing
will be tested by injecting fluid into the tubing at approximately 5000 psig, and monitoring the
annulus pressure for 30 minutes.
2
Alaska Oil and Gas conservate\l~ Commission
Application for Underground Injection:
Kenai Gas Field, KU 24-7
Injection Fluid (20 AAC 25.252(c)(7»
Information concerning the proposed materials for injection follows:
The wastes will come, directly or indirectly, from Cook Inlet offshore oil and gas platforms as
well as from onshore production facilities owned or operated by Marathon and/or other
companies. The waste will be wastes generated from E&P operations. Typical fluids will
include, but not exclusively limited to, produced fluid, drilling fluid and completion fluids, rig
wash, drilling mud and cuttings, and pipe scale.
The following list of anticipated wastes to be disposed of in the injection well is not all-
inclusive, Marathon may inject other wastes determined by U.S. EPA to be RCRA E&P Exempt
Wastes per 53 FR 25446 July 6, 1988 and "Crude Oil and Natural Gas Exploration and
Production Wastes: Exemption From RCRA Subtitle C Regulation", May 1995,
EPA 530-K-95-003.
o One is pipe scale. The pipe scale will likely come from the tubulars and pipes once
used in oil or gas production, and possibly exploration operations. That is, the tubulars
and pipes that had been located at the production or exploration sites prior to
transportation beginning. The pipe scale, some of. which may contain naturally
occurring radioactive materials ("NORM"), has been "brought to the surface" in
conjunction with conventional oil and gas production. As you know, NORM waste
occurs as scale or sediment in production tubing and fittings. The AOGCC has written
to oil companies that it considers NORM waste to be a Class II substance and eligible
for injection into a Class II disposal well.
o Given the space limitations on the offshore platforms, those piping and equipment
(including tubulars) will most likely be taken from production sites to locations onshore
outside of production area to have their pipe scale removed and temporarily stored in
drums prior to disposal in injection well. We anticipate the pipe scale coming from two
types of storage locations:
One source will be new pipe scale and sludges with NORM. The sources of the
sludges with NORM will consist primarily of treatment vessels for produced water
"brought to the surface" in which the NORM sludges settle out. These treatment
vessels will be located on the offshore production platforms and at the onshore
production facilities prior to tre LACT meter where ownership and change of
custody of the product occurs. .
A second source providing pipe scale that originally has been "brought to the
surface" are the service facilities (located off production sites) that store tubulars
and pipes, such as Arctic Pipe Inspections near Kenai. The tubulars and pipes are
stored on storage racks. The pipe scale (as well as old, non-hazardous, pipe dope
used to seal pipe joints) may fall out of the ends and fall to the soil and gravel; other
pipe scale from these locations result from pipe cleanings. This pipe scale and pipe
dope, some mixed with soil, would be put in drums and disposed in this injection
well.
3
)
Alaska Oil and Gas ConservatÎon Commission
Application for Underground Injection:
Kenai Gas Field, KU 24-7
o Of course, dry pipe scale (and other dry E&P Exempt Waste such as soil), in order to
be injected downhole, must have water added to the waste to create a slurry. The
sources of this water will include produced water, fresh water from local wells, and/or
rainwater found within containment dikes for E&P Exempt materials at production
facilities.
o Besides pipe scale, other wastes to be disposed in the injection well includes rinsate
from rinsing drums used to store E&P Exempt Wastes.
o Another E&P Exempt Waste would be gas separation wastes, including wastes which
may have come into contact with glycol-based dehydration compounds, arising from
operations necessary in the oil and gas production process. Dehydration vessels, such
as contactor towers, have a potential for glycol carryover.
o Equipment wash water which will be fresh wash water from local wells.
o Other wastes to be disposed in the injection well are mixtures of E&P Exempt Waste
and non-hazardous solid waste or media, such as soil and organic materials which
have been contaminated by spills of crude oil or natural gas liquids, produced fluids,
production waste, pipe scale with NORM or solvent (not listed @ 40 CFR 261
Subpart D) used to clean pipe dope from the threads, or contaminated rainwater from
secondary containment sites used for temporary storage of such E&P Exempt Wastes.
o Stormwater in contact with secondary containment areas for E&P Exempt Waste
storage areas and production equipment, onshore reserve pits, and production pads.
o Injection Rates: 2-5 BPM
Daily Average: 1000 barrels per day (drilling operations)
Daily Maximum: Instantaneous rate of 5 barrels per minute, or 7200 barrels per day
Average/Maximum Injection Pressures (20 AAC 25.252(c)(8))
The average injection pressure is expected to be 1600 psi surface during mud and cutting
injection. The maximum surface injection pressure will be limited to the working pressure of
¿:h c3sing h03d, which is 5000 psi. working,pressure"s during in,J.'ection operations is not
expected to approach maximum allowable.
;;> Nö"rI? ~ ;t-I a...,Ù ~ S <--UfL ìzj ~J ì""^- fV ess €A- iff! ~~ 1 r; "-'-< ~+.&J Þ"j
pu.~ lPoor{c..~ PV()5.suY~ '( 5&--&'1 ptf D-tr ~\\jt.\)
lìMØ-C;;Ú)j"df. PU&-\A.-f) l^bl.ANf~~ WDV[Cf$ Rt.Ct
ru -) IJ -- ~~~
() V Cl ~ 4 V'(! (5' 3 OC>D f s-i IJ-'"""; fL pc> pC'S (í) ì <;) . s\OO
V cQ~\\"'\S
f e') J þ ,[) ... C' I, cons.
S"'e f Ú/' Þ-fC5D PSt. rJ2~---;tAr t.e JiÞv€-Y- ~Q\\&~c~~r\Qí~.Qe
f( ( 6 ! <1 b ~\~S ~ t' v
4 :r: ff~fÇ;J (?.ç,
Alaska Oil and Gas conservatit,)commiSSion
Application for Underground Injection:
Kenai Gas Field, KU 24-7
)
Fracture Information (20 AAC 25.252(c)(9»
An evaluation of the proposed injection program and its potential for initiating or propagating
fractures is enclosed as Attachment E. Based on that evaluation, Marathon believes that no
freshwater strata is at risk of being affected by the proposed injection operations. The model
predicted fracture height growth of 11 Q9feet and frac;tureJengthºf1?§ºf~~t after injection
of 55,000 bbls. of fluid. This amount othªi9.otgrº~h,VV()lJldr(3$lJltinth(3Jraçture reaching
atrue vertical depth of3450 feet which is 21.50 feet þ(3IQwth(3exempt(3d depth. The fracture
simulation presented in Attachment E illustrates that freshwater confining strata will remain
intact.
Formation Information (20 AAC 25. 252(c)(10»
The injection fluid for disposal will be predominantly cuttings and drill muds from new and
existing Marathon operated wells during rig work operations. The source of the produced
formation water will be from the Sterling, Beluga and/or Tyonek Sands. Laboratory analysis
of water samples from the Sterling interval at KGF are attached (Attachment F).
Aquifer Exemption (20 AAC 25.252(c)(11»
The aquifer penetrated by KU 24-7 is exempted under 40 CFR 147(b)(1 )(iii) below a vertical
depth of 1300 feet from the surface. A copy of the citation is enclosed as Attachment G. The
exempt zone is described as extending one-quarter mile beyond the limits of the Kenai Gas
Field.
Mechanical Integrity (20 AAC 25.252( d) through (g»
A mechanical integrity test will be performed at KU 24-7 as specified in 20 AAC 25.412 prior
to injection. The casing/tubing annulus pressure will then be monitored on a daily basis as
a routine field operating procedure, and reported on Form 10-406.
Mechanical Integrity of Other Wells Within Y4 Mile Radius (20 AAC 25.252(h»
No other wells are within a 'X mile radius of KU 24-7.
5
)
')
Makeup Water
~
Mud and Cuttings
From Well Solids
.. Control
Equipment
Solids
Mud back to rig pumps
.
7'\
Grinding
Mill
Ä
Á
Solids> 50 mesh
returned to ball mill
Slurry
~ / Sizing shaker with 50 mesh screen
tf
,
Injection
Pump
('\
"- ~
Injection Well
...-- 1300' Exempt Zone
- ~
~
FIGURE 1 :
SCHEMATIC DRAWING OF
~J(t \\fE\)
St.? "\ 9 \99G
1"'\1'\~$\O\\
<: C\J\Í\\,·I~,"
. (;9(; Con.,·
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t\\ð: ,~"'" p,\ 1~: IIY l.;:,
CUTTINGS GRINDING AND INJECTION SYSTEM
HM4171
øøø
--3920
1. SQ0. 0Be
KENRI GRS FIELD
R8 STRUCTURE
KU 2q-7
DISPOSRL CONVERSION
"""2ØØØ.ØØ FT/IN I"""
!3-MRR-96
I I
)
ATTACHMENT A
\
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,-
ALASKA PENINSULA
~
~
COOK INLET
"()
'.
o
qtfþ
..FigureA-1
~
KENAI /
:Cannery Loop Unit
e~
KENAI PENINSULA
A
N
,
o 1 0 20 30 40
I I I I I
MILES
o 20 40 60
I I I I
KILOMETERS
MARATHON OPERATIONS
IN UPPER COOK INLET
#A
MARATHON
~ 4
X-27J,I77.9J .14
V-2.3S6.76O.25
\ \ \ 1
\lEu. "A"
X-274,P46.0
V-2,35~,941.7
TOP e" PIPE EI..-66.1S·
TOP 2" PIPE EI..-Ii6.02"
)
+
-
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K.U. 33-7
~5~~~1I \
V-2,356,0S7.11 \
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---------------
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K,U. 24-7
WEU. HOUSE
X-275,057,33
V-2.356.01J.e9
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.+
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McLANE
CONSULTING GROUP
SOU)()'ItjA, ALASKA we:jglll
(807) 2aJ-4218
~ΠSUIM'I': 11EI!:
3OQ( !4Q.: R~:i<t ~
"RO.£CT NO.: 8531:18
_Ie NO.: 85P04"8
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IFGF'ND
32 33 34
T5N KENAI
T4N
GAS FIELD
6
5 4
/
7 8 9
13
18 i
Location
41-18
16
17
SCAlL 1" - 1 Milo
VICINITY MAP
.¡. GLO!BLM monument found this survey.
o Replaced 1/2" rebar os noted
FIGURE A-2
AHTIaPA'IED DRAINAGE PArn:RN
~
1 ) /28/IIPtAR
I" DA'Tr 'flY APP
(M)
.
..rathon
011 Company
~ Found survey monument of record.
-<J Power Pole
* Ught Pole
o
Existing well c-.hrlstmas tree
MonItor Well
Ci1>
Þ<1 Valve
-0 Piping underground
Ð Electrical switch box
A Septic Vent
~ Areo of expected pooling
---) Expected drainage flow
ARRRFVlA T1ON~
O.H.E.
a.H. P /W
E.M.
OVERHEAD ELECTRIC
OVERHEAD PIPE WAY
ELECTRIC METER
1) Elevations at the top of pipe for monitoring wells were token
with cover off or open.
2) Reference datum Is mean sea level- 0.00' for elevations shown.
3) All bearing8 are grid unless noted otherwise.
4) Basis of Coordinates is U.S.C. & C.S. Trl Station AUDRY In
A.S.P. Zone 4. Average convergence of points shown: -01'04'58"
5) T.B.M. elav.a: 67.90' SW comer top well cellar KU 11-17
6) AUDRY location:
Lot.: 60·30'50.559"N
Long.: 151'16·37....4S·W
X-269,866.75
Y-2,382,045.42
SCAl.£ p'IIN....... DA'n' ,,.,......
ptIC".. - OATI'
1'-&0" ~... ~.TI'
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41-1e
~ "00 DISC S'I'ST
12-0' ~UHoJ~8
...8 )(-2:75,136.84
!". V-2.355.8J8.ð5
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KENAI GAS FIELD PAD AS-BUILT SURVEY
AIalka R8910n
KBNAI GAS FIELD PAD 41-18
S~o 00
o 00
DW; NO. ~T NO REI
0001 1 0
')
ATTACHMENT B
)
)
Affidavit of Notice to
Surface Owners and Operators
(20 AAC 25.252{c) (3))
State of Alaska
Third Judicial District
I, J. Brock Riddle (print), declare and affirm as follows:
1. I am employed by Marathon Oil Company, Alaska Region. I have personal knowledge
of the matters set forth in this affidavit.
2. On September 16 , 1996, the following surface owners and operators of the Cannery
Loop Field were provided with a copy of a permit application to the Alaska Oil and Gas
Conservation Commission, dated September 13 , 1996, for conversion of KU Well
24-7 to a Class II injection well:
o Operators
Marathon Oil Company
P. O. Box 196168
3201 C Street, Suite 800
Anchorage, Alaska 99519-0168
o Surface/Subsurface Owners
Mr. Jim Segura, President
Salamatof Native Association, Inc.
P. O. Box 2682
Kenai, AK 99611
Mr. Gerald G. Booth
Cook Inlet Region, Inc. (CIRI)
2525 C Street, Suite 500
P. O. Box 93330
Anchorage, AK 99509-3330
DATED at Anchorage, Alaska this 12t~~¡ber ,1996.
~Ck Riddle, Alaska Region Landman (signature)
Subscribed and affirmed before me at Anchorage, Alaska on \.. <)-ej1!-e/J¡6e,,- /0 ' 1996.
c/.<!~A i jp~
Ño~ry Public in and for
the State of Alaska
My commission expires:
Oc..~6er I?I /7'18'
Ii
ATTACHMENT C
GEOLOGIC INFORMATION
KU 24-7 Disposal Candidate, Kenai Gas Field
The Sterling A10, A11, and B2 sand packages between 4410 and 4708 feet MD (Figure A-5)
are the proposed injection intervals in the KU 24-7 well. The Sterling Formation currently
contains the shallowest producing intervals in the field including the injection intervals. The
Sterling consists of thick sandy meandering stream bar deposits alternating with well
preserved bog and floodplain coals and shales. As seen in the KU 24-7 well, a thick (>40')
shaley interval occurs immediately above the B2 sand, and a shale, silt, and coaly sequence
more than 100 feet thick occurs above the A 10 sand. Coal and shale intervals such as these
within the Sterling have historically been effective barriers to vertical communication in
analogous disposal wells.
The current perforations of the Sterling B2 sand will be utilized for the purpose of primary
injection, with an expected fracture growth into the A 11 and A 10 intervals. These intervals
have a total net sand thickness of 140 feet with effective porosities between 25-28%,
permeabilities between 90-1000 feet MD, and are depleted to 350 psi. The thick shales above
and below the B2 sand should control fracture growth within the expected limits as shown by
a fracture simulation study. Also the nearest well bore is over 1500 feet away at this horizon,
which is beyond the estimated induced fracture radius. Because of the significant depths and
safe history of Sterling injection in sands 4000+ feet below the Pleistocene aquifers of the
area, and the numerous coal and shaley intervals within the Sterling Formation, no problems
of disposal fluid containment or fracture growth into freshwater zones can be foreseen within
the expected injection volumes.
)
J
ATTACHMENT D
}
COMPLETION INFORMATION
KU 24-7 WEll, KENAI GAS FIELD, ALASKA
Criteria for choosing a disposal well included:
· Using a well bore which has no future potential for production,
· Determining that the well has sufficient disposal capacity into one or both of the
already permitted and approved Sterling sands.
· Checking strata maps to ensure substantial vertical confinement.
· looking at Cement Bond logs to ensure mechanical integrity, and
· Adequate tubing size.
Well KU 24-7 fits these criteria and is located on KGF Pad 41-18. This Kenai gas well has
no future potential as a producer. The short string died in June of 1993, and the long string
in July 1994. The long string injection zone in well KU 24-7 is 12 feet of the B2 sand (4696-
4708' MD). Short string injection potential includes 80 feet of the A1 0 sand (4410-4490' MD)
and 35 feet of A11 sand (4525-4560' MD). Shown on the log section (Figure A-5) are the
proposed injection intervals.
The aquifer exemption limit is 1300 feet for the Kenai Gas Field, so the proposed interval of
injection is well below the specified limits. There are numerous laterally continuous shale
layers above the sands and solid cement bond below 4050 feet MD in the casing annulus
directly above the zone. The dual 3%" strings are of adequate size, and the site is not easily
accessible to the public.
The surface location is within the Kenai Gas Field Unit, and the working interest is divided
among Marathon and Chevron. land ownership includes Cook Inlet Region, Inc. (CIRI) and
Salamatof, Inc. The Bureau of land Management (BlM) manages the federal lease. All
applicable agencies, working interest owners, and land owners will receive a copy of this
application.
4 XA
6,7 ¿¿i~xx)<
\8 ¿j
B-l t 9cy
Send
o Cut Thg.
II
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IN ¿
2~
Á-iO=
Send
A-1' =
Send _
v .
8-4 ~
Sene
So::) ci "'7
. I
V1 J
",'
. ...-'
"'-
WELL KU 24-7 WELL SCHEMATIC
CASING &. ABANDONMENT DETAIL
I. Rotary Table 0 0.0'
II. Cameron 3- 1/2" Dual Tbg Hanger 0 27.68'
III. 20" 94/1 H-40 Drive Pipe 0 178'
_ N. 13-3/6" 61 # K-55 Casing 0 2003'
V. E.T.D. C 487S' TOF 0 4848'(30' of Tbg.}
VI. 9-5/8" 43.5# & 471 N-80 Csg to 5801'
~
1XA
~ TUBING DETAIL
XA A LONG STRING: 3-1/2" 9.2# fJ-aD TUBING
, . otis "XA" Sliding Sleeve 0 4273.53'
2. Baker Model "A-51t Dual Packer 0 4312.79'
~ ~ 8 3. Blast Joints From 4385.29' to 4581.52'
_ 4. Otis "XA" Sliding steeve 0 4639.47'
~ C 5. Locator Sub 0 4677.12'
6. Top of 13.72' Seat Assembly 0 4678.00'
7. Model "5-2" Prod. Poeker 0 4679'
8. Otis "X" Nipple 0 4691.72'
9. 4694' Cut Tbg on 7 /26/88
SHORT STRING: 3-1/2" 9.2# N-80 TUBING
:5
A. Otis "XAn Sliding Sleeve 0 4267.57'
8. Baker Model "A-5" Dual Pecker 0 4314.93'
C. Otis "X" Nipple C 4325.84-'
DATE
5/27/82
5/28/82
5/29/82
-4 5/30/82
5/30/82
7/88
PERFORATION RECORD
INTERVAL C0tf..P070N
4890'-4905' 8-4 Sd. Sqz'd 7 /88
4905'-4925' 8-4 Sd. Sqz'd 7/BB
4410'-+4-90' A-10 Sd. Production
4525'-4560' A-11 Sd Proauction
4410'-4490' Reperforate A- 10 Sd.
4696-4708' 8-1. Sd. Production
::::.
Checked by: NKS Drawn: 1 0-' 9-88 SAW
)
ATTACHMENT E
) )
KU-24-{ Fracture Growth Simulation and M'onitoring
Kenai Gas Field
Simulation
Marathon's Petroleum Technology Center has constructed a three-dimensional grid oriented
hydraulic fracture model of the strata at Kenai Gas Field. The model was constructed using
lithology, stress variations, pore pressure, and rock elastic properties for the Kenai Gas Field.
The purpose of the model was to simulate fracture growth as a result of drill cuttings injection
above fracture pressure.
An average injection rate of 5 barrels per minute (BPM) was used in the simulation. A fluid
viscosity of 50 cps was used, assuming the mud and cuttings would be diluted with water.
Particle size of 50 micron, cutting size of 50 mesh and solids content of 20% were utilized in
the simulation. Figures F-1 and F-2 indicate the calculated surface and bottom hole
pressures, and the fracture geometry as a function of volume pumped.
The model was used to simulate disposal of up to 55,500 bbls. of fluids. Injection of this total
amount would cause fracture height growth of 1100 feet. This height growth would result in
reaching a true vertical depth of approximately 3450 feet which is 2150 feet below the
exempted depth of 1300 feet. Fracture length may reach 1250 feet as shown on Figure F-2.
Referring to Figure A-5 (Attachment A), fracture height growth is limited and does not
approach the protective fresh water confining beds. The induced fractures will be propped with
an impermeable drill cutting and mud slurry. Once the induced fracture is closed, it will be
non-conductive.
Monitoring
A continuous record of surface pressure, pump rate and fluid density will be recorded during
all injection activities to KU 24-7. This data will then be compared to model predicted data to
determine the status of fracture height growth and extension. This data comparison will
provide a means to prevent any contamination of the exempted aquifer zone above 1300 feet.
Temperature and tracer surveys will also be utilized to monitor fracture height growth and
extension; however, these surveys are limited to monitoring within a radius of only 2 feet of
the wellbore and provide a minimum value of fracture height.
A disposal project similar the one proposed at Well KU 24-7 was undertaken at Well KU 14-4
between August, 1992 and September, 1993. In this case actual measured data compared
very well to model predicted data via the GOPHER simulator. The basic premise of this
monitoring approach is the fracture propagation through sand zones should cause abrupt
pressure drops or declining injection pressure, whereas propagation though shales should
cause height growth restriction and increasing injection pressure. In the case of Well
KU 14-4 it was possible to correlate these abrupt pressure changes to various sands and
shales as the fracture height increased, thus, providing a method of fracture height monitoring.
4,000
3,500
3,000
2,500
ë;
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Q.
f 2,000
:J
en
en
CD
...
a..
1,500
1,000
KU 24-7 DISPOSAL CANDIDATE
(Psurf. and Pbtm. VS. Vol. Injected)
.
.
.
.
, . -
~ -1' -. ~~~-ç
o
o
o 0
~ B U
~~~
f - ß ' ~J'-
500
1 0,000
20,000
h:\excel\kenai\sterling\KU24750 Chart 3
7/22/96
.. .
.
. - ~ ;.
--.... n , m£ ~ .. --...
~
00 0
- ~ --. -L.røm ]
L --- ......- -
30,000
Volume Inj, (bbls)
I. BHP 0 THP I
o
~
~
40,000
FIGURE F-1
11 ___ ~ ItJ
-/
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____ - I
50,000
60,000
-
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~
u.
1 0,000
1 ,000
100
10
10
h:\excel\kenai\sterling\KU24760 Chart 2
7/19/96
KU 24-7 DISPOSAL CANDIDATE
(Frac Length/Height vs. Vol. Injected)
o
100
I I I " "I" IIlIlITuU
I
1 ,000
1 0,000
Volume Inj. (bbls)
1- Frac Length -0- Frac Height I
FIGURE F-2
-
~/
100,000
)
ATTACHMENT F
\
(Na nlu4 In aboft rnph. iDcludOl N.. E. ILI1d U)
NOTE:: UB/l =WilliiTlmI Pft lit~ l.hv'1 = UüU¡Tam Þ: uin.1.ntl p.u litw
Iodhu:a dùonlM ~ur.ùoat=by DuD1ap.. HawUorM eak\Jlatioft frOal «>-"'~DWtI
i j '!' m1+!1+t:.t:P~it:!Ji-¡m,~+i..~~'
. - it t ;L;-·+a3~'"'11'rt:::::.1..-H-H-t""1" ·~·"1~~:r
~, , 'I f 1-1i~·i-~.¡·~m·'~-t",,~,"""...............,-··1 ,
. ...~.CJ- '·i::tt-!+U1-·· ii''':i. ..,..~_... .+
I It". . '_ j. T"~I I, 11.t:~:!-t~.cttj+
~f.a. _J........ _~"I-:"· -,...+- ' .-, + ":"""+-I::::r::;.:._.:....!-.:-
, . ',.....,Tti·:±g;f,· :-~........-,WT,.~q.,..........." '",,-:..'-,-!--~ Cl
-- -, ,..¡U, ~~-r--1Th ·]tlf-J:.~:~:':''-4~
~ ... _........XL. +.¡_..~~.J-+_~'"
~ ..~-EF.Eiti:t~~.~;·~ -................;....;.;..¡..,.........-1+
" " tI::!:::.r:t:t~~;...~, -·i-t.......i--¡T,..-ï+~J:--'-'~·~
:, IMt¡+t~T-Ftf-r(..!:~~.i-U~ ~iiT-;~~~:Af8T;$~
...J.. ,-lWJJ.L-¡.LlW-.l...W-,. ,........,...¡_....t..... " .. :.JJ::e-......._;..4-;-;
,.J...i:r.r·-:-~·'-r-(-''-'--_:+'-'"~----:·M-''''''·'·''' -:- ...._~1"'":--,... 1i C 0 3
-TILb.... ~ttt-;--....... ~"+t±..........- -'-'-._....+..---.."._-~
~.~:7J11j W¿i17b±~~~-q:~W
- =+'~l r'~, ª*.' ........_.~-'...,.:.~"1'"'~, .....-..-,T, C1,...~-._,~....~
. ~~1TIT.!lL: -i:rtt~~~::~~~~t:¢~::~
1,,' ¡t.·L'~ I ¡",...~--t-.--............ ~-:~-_-..:....
...¡..;....... -_ -...~_.....-,_.......~..{ -;--, ¡....--:-...-r.:--:-~.. ......-.-r, '....: S 0
-t-"'t"r.t+;-- I . t ' , : ' , '::-ti'- .....·~-!->-"--'-:ï·--~- ~
=t+1-tt+\++-\~.±f=?E;'::.:s:~·~.. ~':t1Ïì~:~=""
.-i-i-I--+"........-t:.......... . . I , ~----.-,......._....,-........¡.~
, ·1 , t . I t I .--....~t-_~. ... ~---......---.-
- ~ I I , I_t---....-~~~~~~I_·....~r~
\- .; i ~ ~ : ; ~ ¡ ~ ';: ..:.-{ . - . _~-+-.~..t:..r--=~:
~~ir-, ~-"'H" L!.""rl.¡~_.k..!-.........,... CO,
-h",. ~........:-·...~¡i.:t¡:w:;::1:t~,~þ:-:-:-.-:-.~
~~~". .......;::::;:~. I I . ..~.L..L._.-..-:~.......~~"'__~
-tftt1-,: ¡ ; ~ ! : !~=-~~~~~..:::=:~
~ í I t .¡,,,',, ·1" ' .. .. I ; ~ "",' I (' . ! " . ---~'-
t' ~ ' : t ¡ : ; ~ i Z~ ~ t : : I 1 ~ ~ ~ : ~ ¡ ~ : : I ; ~"7 (.., :
,1T1l ¡ I ! t t III Ill: II ~ ! : tr ! . : I : ~ ; t 1 : ¡ ; . . : ! ~ ; . . :
Fe
Mg
Ca
Na
**' - t,;r II EM, ; í,t1t-lli, ¡.., ¡'1-4+f+t~t..:...~µ 'æ', T ++-L
- H-.- r +- k ~....+.~' ", ,:t-::: 0-++
- ,'. .. hi- .- '.....~!-n+t¡~ f++--t-++ -r-;T
.. H'~ +. -+..... I , ¡ I ' I-r.-'¡"'¡',
I:: B$~~7-Frnm, ....., 'l:I1ÿ;¡rr¡-;-;, I,' i " I , :~,:,~U, L~ t±
+~ ct "~-t"t~:':"~,-~,,",~~ I ~ ~-+~ -~ +--
Na ~~_'"L''' -,..,...,-~-- ..,;'1.'.. fl" f¡,......~ Cl
.. . . I" ¡ 'M'--+~' ....-o-r. ~.~._..............i=t! '..........
.. ~ "H --:;:. ~-..:.r=+P. T.:p·,,;,,::¡;,.. .7'-+
+;_#11 ~--:ttl .~¡-+-... ..,....--:....- __k -............. -....-..:::::::t:
:n .1: i:J:tcr .....~.. -.;..~ .+ "i-rr~~T..J·:tËf
_~r . '-" . ::¡-...~::=::::±_ ':¡.L;.; ,. t!:.¡':-.::.::~-:~...:..-
.ff.;'r ..,"th·..""1.....,..-,_I-"-......._, ,~c -;-.......~.._~_....-....... HCO
~ :t:tt . . :¡¡:;'''''''''--4-Mo- ~ -r-þo.........~_oa ~~~--......... 3
Ca ·1~ ·1...¡'1H1"'t W ....:::¡:;:::......,; .......,...,....,.-..,( I t"t.... :::r::::;................. 1
0t t ~~t::--+t-~::- ;=:::t:~··.,.f.. ::+::r..._+-+-,-~~
"r1'- '}r:'~"" I' ¡ -_..··f"t:::t.';7.'-M::t:_·....·.......ï"""'"tT"
:: ¡..~t :t¡:::':¡:f~7~~:-' .::::::::::;t'~;-~:-: ': :"
E' ¡ rp-l . ¡ LLt_W I ! I , ~II-":,/.: I t f " . I I I' I I '1~
~ ~. r¡i~·.¡..tt:t::.: ~___ __,.~ .;;_~:+::.::-~::::::~
M ~ ~r· '[" ~-;l.J.............-¡.-j:--J._~.........L-l. " -f- . . ., . , , ,............... SO.4
b -r~~; 1'!_~~-;~' .-.......;.:_:::: ~ r:::::::;:::;+'::':::;::'-=:·~+--r-
....J..¡-, \..., ,...........~t...........~.......... \ \'.' I '" ¡ --~......_~
.:tt· Lt··t1 ++-+-'-1·1-1 ~ '-1-:-~:tq.:"~. - ...4-........--~-
:iiJ"f r~.~Œ~'::.l¡:,::-~=1 S~-+-:-~¡ ;:-~.:.~'~.:..
-t4=d.-I.¡"~f.J ----....¡:-'".....--...-....\ -;-..;-r......... . fir',' o-+~ ~~
Fe :+~~~\:~tç~~:~~~~Ë~,·:.·.;~;,·s=;~~~~~ CO 3
!T:"r'+~ ~+"""$~~~, ~..~.,................., ' I~"'-~""" . .........,...¡.., +.............,
m,.....,-~ "1'"1"-:-;-'" ~"""'~--r1---~----' .............-..-....'.............,
- :t'" ·t*+--t-r.;.t, -t..~.:~~.:-~;-;--:--;:-~:-::.:..:..:-~
. ..~~-;.-~~...~j..+.¡.-.~I I \ II. I L~'~
....¡:t. rt-~........ rr;-7T..-....,-~-.:=:::+-~.;..:f:*
:t-Ht (II t ¡ l ~ l ¡ ¡ t t l ! II, j 1 ;Ti1Ti ! ( ~ ~ 1 ! t t ¡ ! 1 :"
1
1
10
WATER ANALYSIS PATTERN
Scale
MEQ per Unit
o1&m-~~
-~~
2.40
Specific rc:¡~~till.1CO @ 68 op.:
Obaervød ....
Caku1.tú~ ....
47.9~
Total A.niora
. . . .
10.00
AnJ~
Su1.b1te
Chloride
CMbonate
Bicarbonate
Hydroxide
E:Æl
0.47-
~7 & 51
.ær.L!
?o
1~=10
o
610
Sample ~bovc ùcscribed
2,40
Total w:=oJved eolidc, mVl
N.Cl equiv~oot, q/l - -
O*"C'd pH .....
2759
. . . . .
47.93
. . . .
Totnl CaticulI
m~
45.05
1.23
O.~5
1.15
Calcium . . · ·
Ua(l11e2ium
Iron
. . . -
mrr/l
1036
50
9
14
CnttoM
Sodium
PotMJÌ1.1m
. . . . . .
.
REMARII::3 ¡. CONCLUSIONS! Cloudy brown water, clear filtrate.
WHtS fI-c:.. (rO~u. 3 ~ I.(). 2.1- c. (T"orou 5."l. t r:.) ,4:0 3:{ - J I (rbOt.. c.. C I S.Jl,",~) !"~~~..t=; I"-I'M:I 01J, ,"t".f\JI'.,.r.;r;:it. ¡a.J.,I~ 'nt15
. .s;<I.,.,....,...!-'~·~·'CI1UL."!) 'r.Ë A l-" ""<Tt5~:E r~dr Ii ,~ 7'::.!~J(·:)1 'r:¡ I'! ~:~Ti"'.~ f;:""....... ,,"\~ "C'tS:"o.,)Q '~J ·i.,)'f."l·(. '1'~f-.1'. 'fT"
.s~\OUt.O FIif.. t~t)I~ C-I'\~D.
LAD NO, 0169-?
DATR March 9, '97?
LOCATION
FORMA'fION
INTERVAT.
SAUPLE FROf!
Alaska
OPERATO}'?
WELL UO-
FIELD
COUNTY
STATR
UNION OIL CQ'¡iPANY OF CALIr.
34-31 C, $"\")'D
Kenai Gas
WATER ANALYSIS REPORT
¿~ I
ALAS:(A, I~~C.
2603 ARCTIC BLVO
Cr~Eh/jjCAL & JEOLOGiCAL LABOFtA·rOR~...,B
TELEPHONE (907) 279-4014 P..O. BOX 4 ·1276
ANCHORAGE, ALASKA 99509
Æ(~\~~
/\Íl~~
V"~..~~~..
OF
ATTACHMENT G
§ 147.2
administered program is promulgated
in those'instances where the state has
fa Bed to submit a program for approv-
al or where the submitted program
does not meet the minimum statutory
and regulatory requirements.
(c) In the case of State programs ap-
proved by EPA pursuant to section
1422 of the SDW A, each State subpart
describes the major elements of such
rrograms, including Si;ate statutes and
regulations, statement of Legal Au-
thority, Memorandum of Agreement,
n.nd Program Description. State stat-
utes and regulations that contain
st::.ndards, requirements, and proce-
dures applicable to owners or opera-
tors have been incorporated by refer-
ence pursuant to regulations of the
0' - ~ of the Federal Register. Materi-
al ,orporated by reference is avail-
able for inspection in the appropriate
EP A Regional Office, in EP A Head-
quarters, and at the Office of the Fed-
eral Register Information Center,
Room 8301, 1100 L Street, NW, Wash-
ington, DC 20408. Other State statutes
and regulations containing standards
and procedures that constitute ele-
ments of the State program but do not
apply directly to owners or operators
have been listed but have not been in-
corporated by reference.
(d) In the case of State programs
promulgated under section 1422 that
are to be administered by EP A, the
State sUbpart makes applicable the
provisions of Parts 124, 144, and 146,
and provides additional requirements
pertinent to the specific State pro-
gram.
( 'R egulatory provisions incorporat-
C{ I reference (in the case of ap-
pr0ve'd State programs) or promulgat-
ed by EP A (in the case of EP A-admin-
istered programs), and all permit con-
ditions or permit denials issued pursu-
ant to such regulations, are enforcea-
ble by the Administrator pursuant to
section 1423 of the SDWA.
(f) The information requirements lo-
cated in the following sections have
been cleared by the Office of Nlanage-
ment and Budget: Sections 147.104,
147.304, 147.754, 147.904, 147.1154,
147.1354, 147.1454, 147.1654, 147.1954,
and 147.2154.
The OMB clearance number is No.
2040-0042.
40 CFR Ch. I (7-1-90 Edition)
§ 147.2 Severability of provisions.
The provisions in this part and the
various applications thereof are dis-
tinct and severable. If any provision of
this part or the application thereof to
any person or circumstances is held in-
valid, such invalidity shall not affect
other provisions or application of such
provision to other persons or circum-
stances which can be given effect with-
out the invalid provision or applica-
tion.
Subpart B-Alabama
§ 147.50 State·administered program-
Class II wells.
The UIC program for Class II wells
in the State of Alabama, except those
on Indian lands, is the program admin-
istered by the State Oil and Gas Board
of Alabama, approved by EP A pursu-
ant to section 1425 of the SDW A.
Notice of this approval was published
in the FEDERAL REGISTER on August 2,
1982 (47 FR 33268); the effective date
of this program is August 2, 1982. This
program consists of the fOllowing ele-
ments, as submitted to EPA in the
State's program application:
(a) Incorporation by reference. The
requirements set forth in the State
statutes and regulations cited in this
paragraph are hereby incorporated by
reference Rnd made a part of the ap-
plicable UIC program under the
SDWA for the State of Alabama. This
incorporation by reference was ap-
proved by the Director of the Federal
Register on June 25, 1984.
(1) Code of Alabama 1975, sections
9-17-1 through 9-17-110 (1980 and
Supp.1983);
(2) State Oil and Gas Board of Ala-
bama, on and Gas Report 1 (supple-
mented) 0981>, General Order Pre-
scribing Rules and Regulations Gov-
erning the Conservation of Oil and
Gas in Alabama (Order No. 76-100) as
amended by Board Order No. 82-96
(May 14, 1982) amending Rule E-4).
(b) The Memorandum of Agreement
between EPA Region IV and the Ala-
bama on and Gas Board, signed by
the EP A Regional Administrator on
June 15, 1982.
(c) Statement of legal authority.
"State Oil and Gas Board has Author-
780
il
Environmental Protection Agency
i~Y to Carry Out Underground Injec-
tIOn Control Program Relating to
Class II Wens as Described in Federal
Safe Drinking Water Act-Opinion by
Assistant Attorney General " May 28
1982. "
(d) The Program Description and
any other materials submitted as part
of the application or as supplements
thereto.
(49 FR 20197, May 11, 1984, as amended at
53 FR 43086, Oct. 25, 1988J
§ 147.51 State-administered program-
Class I, III, IV, and V wells.
The UIC program for Class I, III, IV
and V wells in the State of Alabama
except those on Indian lands, is th~
program administered by the Alabama
Department of Environmental Man-
agement, approved by EPA pursuant
to section 1422 of the SDWA. Notice
of this approvaJ was PUblished in the
FEDERAL REGISTER on August 25, 1983
(48 FR 38640); the effective date of
this program Is August 25, 1983. This
program consists of the fOllowing ele-
ments, as submitted to EPA in the
State's program application:
(a) Incorporation by reference. The
requirements set forth in the State
statutes and regulations cited in this
paragraph are hereby incorporated by
reference and made a part of the ap-
plicable UIC program under the
~DW A for the State of Alabama. This
Incorporation by reference was ap-
proved by the Director of the Federal
Register on Jl.ne 25, 1984.
(1) Alabama Water Pollution Con-
t~ol Act, Code ot Alabama 1975, sec-
tions 22-22-1 through 22-22-14 (1980
and SuPp. 1983); .
(2) Regulations, Policies and Proce-
dures of the Alabama Water Improve-
ment Commission, Title I (Regula-
tions) (Rev. December 1980), as
amended May 17, 1982, to add Chapt.er
9, Underground Injection Control Reg-
ulations <effective June 10, 1982), as
amended April 6, 1983 <effective May
11, 1983).
(b) The Memorandum of Agreement
between EPA Region IV and the Ala-
bama Department of Environment
Management, signed by the EPA Re-
gional Administrator on May 24, 1983.
(c) Statement of legal authority (1)
"Water Pollution-Public HeaÍth-
§ 147.100
State has Authority to Carry Out Un-
derground Injection Control Program
Described in Federal Safe Drinking
Water Act-Opinion by Legal Counsel
for the Water Improvement Commis-
sion," June 25, 1982;
(2) Letter from Attorney, Alabama
Wat.er Improvement Commission to
ReglOnal Administrator, EPA Region
IV, "Re: A WIC Response to Phillip
Tate's (U.S. EPA, Washington) Com-
ments on A WIC's Final Application
for Class I, III, IV, and V UIC Pro-
gram," September 21, 1982;
. (3) Letter from Alabama Chief As-
sIstant Attorney General to Regional
Counsel, EP A Region IV, "Re: Status
of Independent Legal Counsel in Ala-
b.am,a Water Improvement Comr
Slon s Underground Injection Cont"-,, ,
Program," September 14, 1982.
(d) The Program Description and
any other materials submitted as part
of the application or as supplements
thereto.
[49 FR 20197, May 11, 1984, as amended at
53 FR 43086, Oct. 25, 1988]
§ 147.60 EPA-administered
Indian lands.
(a) Contents. TheUIC program for
aU classes of wells on Indian lands in
Alabama is a~inistered by EP A. This
prog~am COnsISts of the UIC program
reqUIrements of 40 CPR Parts 124,
144, 146 and any additional require-
m~nts set forth in the remainder of
thIS sUbpart. Injection wen owners and
operators ~nd EP A shall comply with
these reqUIrements.
(b) Effective date. The effective dE.
of the UIC program for Indian Jandš"
in Alabama is November 25, 1988.
(53 FR 43086, Oct. 25, 1988J
program_
Subpart C-A'aska
§ 147.100 State-administered program_
Class II wells.
The UIC program for Class II wells
in the State of Alaska, other than
thos~ on Indian lands, is the program
admmistered by the Alaska Oil and
Gas Conservation Commission ap-
proved by EP A pursuant to Section
1425 of the SDWA. Notice of this ap-
proval was PUblished in the FEDERAL
781
§ 147.101
REGISTER (May 6, 1986]; the effective
date of this program is June 19, 1986.
This program consists of the following
elements, as submitted to EPA in the
State's program application.
(a) Incorporation by reference. The
requirements set forth in the State
statutes and regulations cited in this
paragraph are hereby incorporated by
reference and made a part of the ap-
plicable UIC program under the
SDW A for the State of Alaska. This
incorporation by reference was ap-
proved by the Director of the FEDERAL
REGISTER effective June 19, 1986.
(1) Alaska Statutes, Alaska Oil and
Gas Conservation Act, Title 31,
§§ 31.05.005 through 31.30.010 <1979
and Cum. Supp. 1984);
(2) Alaska Statutes, Administrative
Procedures Act, Title 44, § § 44,132.010
through 44.62.650 (1984);
(3) Alaska Administrative Code,
Alaska Oil and Gas Conservation Com-
mission, 20 AAC 25.005 through 20
AAC 25.570 (SUpp. 1986).
<b) The Memorandum of Agreement
between EPA Region 10, and the
Alaska Oil and Gas Conservation Com-
mission, signed by the EP A Regional
Administrator on January 29, 1986.
(c) statement of Legal Authority.
Statement from the Attorney General
of the State of Alaska, signed by the
Assistant Attorney General on Decem-
ber 10, 1985.
(d) The Program Description and
any other materials submitted as part
of the original application or as sup-
plements thereto.
[51 FR 16684, May 6, 1986]
§ 147.101 EPA-administered program.
(a) Contents. The UIC program in
the State of Alaska for Classes I, III,
IV and V wells, and for all classes of
wells on Indian lands, is administered
by EP A. This program consists of the
UIC program requirements of 40 CFR
Parts 124, 144, and 146, and additional
requirements set forth in the remain-
der of this subpart. Injection wells
owners and operators and EP A shall
complY with these requirements.
(b) Effective dates. The effective
date of the VIe program for all non-
Class II wells in Alaska and for all
wells on Indian lands, is June 25, 1984.
40 CFR Ch. I (1-1-90 Edition)
[52 FR 1 'l68O, May 11, 1987]
§ 147.162 Aquifer exemptions.
(a) This section identifies any
aquifers or their portions exempted in
accordance with §§ 144.7(b) and 146.4
of this chapter at the time of program
promulgation. EP A may in the future
exempt other aquifers or portions, ac-
cording to applicable procedures, with-
out codifying such exemptions in this
section. An updated list of exemptions
will be maintained in the Regional
office.
(b) The following aquifers are ex-
empted in accordance with the provi-
sions of §§ 144.7(b) and 146.4 of this
chapter for Class II injection activities
only:
(1) The portions of aquifers in the
Kenai Peninsula, greater than the in-
dicated depths below the ground sur-
face, and described by a % mile area
beyond and lying directly below the
following oil and gas producing fields:
(i) Swanson River Field-1700 feet.
(ii) Beaver Creek Field-1650 feet.
(liD Kenai Gas Field-1300 feet.
(2) The portion of aquifers beneath
Cook Inlet described by a If4 mile area
beyond and lying directly below the
fonowing oil and gas producing fields:
(I) Granite Point.
(U) McArthur River Field.
(iii) Middle Ground Shoal Field.
(iv) Trading Bay Field.
(3) The portions of aquifers on the
North Slope described by a 14 mile
area beyond and lying directly below
the Kuparuk River Unit oil and gas
producing field.
§ 147.103 Existing Class I, II (except en·
hanced recovery and hydrocarbon stor·
age) and III wells authorized by rule.
Maximum injection pressure. The
owner or operator shall limit injection
pressure to the lesser 01:
(a) A value which wiU not exceed the
operating requirements of
§ 144.28(f)(3) (1) or <ii> as applicable; or
(b) A value for well head pressure
calculated by using the following for-
mula:
Pm=(o.'133-0.433 Sg)d
where
Pm=injection pressure at the well head in
pounds per square inch
782
Environmental Protection Age~cy
Sg=specJfJc gravity of inject fluId <unftless)
d=injection depth in feet.
'.i _
.~
If 147.104 Existing Class II enhanced re-
covery and hydrocarbon storage wells
authorized by rule.
(a) Maximum injection pressure. (1)
To meet the operating requirements of
§ 144.28(f}(3)(ii) (A) and (B) of this
chapter, the owner or operator:
(D Shall use an injection pressure no
greater than the pressure established
by the Regional Administrator for the
field or formation in which the wen is
located. The Regional Administrator
shall establish maximum injection
pressures after notice, opportunity for
comment, and opportunity for a public
hearing, according to the provisions of
Part 124, Subpart A of this chapter
and will inform ownus and operator~
in writing of the applicable maximum
pressure; or
(ii) May inject at pressures greater
than those specified in paragraph
(a)(1)(i) of this section for the field or
formation in which he is operating
provided he submits a request in writ-
ing to the Regional Administrator, and
demonstrates to the satisfaction of the
Regional Administrator that such in-
jection pressure will not violate the re-
quirement of § 144.28(f)(3)0i) (A) and
(B). The Regional Administrator may
grant such a request after notice op-
portunity for comment, and opp¿rtu-
nity for a public hearing, according to
the provisions of Part 124, Subpart A
of this chapter.
(2) Prior to such time as the Region-
al Administrator establishes rules for
maximum injection pressure based on
data provided pursuant to paragraph
(a)(2)(ii) of this section the owner or
operator shall:
. (1) Limit injection pressure to a
value which will not exceed the oper-
ating requirements of § 144.28(f)(3)(ii)·
and '
(li) Submit data acceptable to the
Regional Administrator which defines
the fracture pressure of the formation
h:t which Injection is taking place. A
smgle test may be submitted on behalf
of two or more operators conducting
operations in the same formation, if
the Regional Administrator approves
such submissIon. The data shall be
submItted to the Regional Administra-
§147.151
tor within 1 year of the effective date
of this program.
(b) Cas.ing and cementing. Where
t~e RegIOnal Administrator deter-
mmes. tJ:1at the owner or operator of
an eXlstmg enhanced recovery or hy-
droca~bon storage well may not be in
comphance with the requirements of
§§ 144.28(e) and 146.22, the owner or
operator shall comply with paragraphs
(b) (1) th.rough (4) of this section,
when reqUIred by the Regional Admin-
istrator:
(1) Protect USDWs by:
. (i) Ce~enting surface casing by re-
clrculatmg the cement to the surface
from a point 50 feet below the lower-
most USDW; or .
(iO Isolating all USDWs by ph~
cement between the outermost cas=ng
and the well bore; and
(2) Isolate any injection zones by
placing sufficient cement to fill the
calculated space between the casing
and the well bore to a point 250 feet
above the injection zone; and
(3) Use cement:
(i) Of sufficient quantity and quality
to withstand the maximwn operating
pressure;
. (iD Which is resistant to deteriora-
tIOn from formation and injection
fluids; and
(Hi) In a quànUty no less than 1200/.
of the calculated volume necessary t~
cement off a zone.
(4) The Regional Administrator may
specify other requirements in addition
to or .in lieu of the requirements ~At
forth ill paragraphs (b) (1) througt
as needed to protect USDWs.
"--'.
Subpart D-Arizona
§ 147.150 State-administered
[Reserved]
program.
§ 147.151 EPA-administered program.
<a). Contents. The UIC program that
applIes to all injection activities in Ari-
zona. including those on Indian lands
is administered by EPA. The UIC pro~
gram for Navajo lands consists of the
requirements contained in Subpart
HHH of this Part. The program for all
injection activity except that on
Navajo Indian land consists of the UIe
program requirements of 40 CFR
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0'1 & Ga~ Cons. Comrmss1on
KENAI GAS FIELD DISPOSAL PROJECTSA\aska I Å~~hCWga
The following is a discussion concerning the modeling and actual performance of the
mud/cutting disposal projects conducted in KU 14-4, 11-17, and the proposed disposal
project at KU 24-7.
Numerical model studies of the past injection in KU 14-4 were conducted throughout the
life of the project. The model studies were not well defined because of lack of accurate
rock property and stress data in the large interval affected by the injection. A post-mortem
analysis of the project was conducted after the injected slurry established communication
with the casing annulus above the cement top. This analysis revealed that a diagnostic
plot of ISIP (instantaneous shut-in pressure) versus cumulative injected volume could be
used to detect major instances of height growth. In principal, major breaks, or drops in ISIP
correspond to growth of a vertical fracture through bounding shales. This analysis is
subjective and can be difficult to substantiate without other direct observation of fracture
height. In the KU 14-4 project the arrival of fluid at the cement top provided this additional
data. While the analysis is subjective it has provided consistent results in both the KU 14-
4 and 11-17 projects, thus, improving the degree of confidence in the results.
The attached plot of pressure versus cumulative volume injected can be associated with
well logs from the disposal well to correlate major pressure events with substantial shales.
The upper line represents the calculated bottomhole net pressure from ISIP data in the KU
14-4 project. This project accomplished the disposal of about 460,000 bbls of slurry into
a 40-50' perforated interval in the 81-82 sands at a SSTVD (sub-sea true vertical depth)
of 4100'. The first pressure break (labeled 1 on the plot) may correspond to the parting of
the 50' thick shale immediately overlying the B 1 sand at a SSTVD of 4040' (top of shale).
Pressure break (2) corresponds to the shale top at 3940' TVD. Similarly, breaks 3-7
correspond to the sequence of shale tops at 3880' 3770', 3680' 3580', and 3490'. After
parting through the top shale, the fracture grows rapidly through the lower stress sand until
it communicates with the wellbore at the casing cement top at about 3450' TVD.
A similar analysis has been performed using the KU11-17 ISIP data, which is plotted as
the lower curve in the plot. There are only four major interpreted events indicated on this
plot. They are labeled A-D to differentiate them from the numbers used for the KU 14-4
data. The first break (A) corresponds to the shale top overlying the injection perfs at a
SSTVD of 3940'. Event (B) corresponds to the small sand break in the shale at 3810' TVD.
The next major break is interpreted to correspond to the shale top at 3540' TVD. The last
major break may be related to the small sand at 3340' TVD. Based on this analysis an
additional volume of 20,000-50,000 barrels could be injected into KU 11-17 before parting
the shale top at 3180' TVD (the next major break).
The two wells for which data are available indicate a similar rate of height growth with
cumulative volume injected. Both yield about 650 feet of upward height growth for
approximately 500,000 barrels of total injection. Because of lithostatic stress gradients and
gravity segregation of injected solids, significant downward fracture growth is not
J
,
anticipated. Overall rate of height growth is related to several factors including degree of
pressure depletion in the Sterling sands, thickness of overlying shales, and overall
sand/shale ratio in the overlying sediments. It appears that wells intersecting a more shale-
rich sequence will allow for more injection capacity. This is consistent with North Sea
operations, where massive shale intervals are typically selected for disposal. Sand, or
reservoir quality, does not substantially affect slurry placement, other than to somewhat
increase overall fluid loss.
Modeling of the KU 11-17 disposal treatment was only carried out to a relatively small
fraction of the total injected volume. The modeling predicted a total fracture height of 600'
after 200,000 barrels of injection. This is somewhat more height growth than indicated from
the actual treatment data.
A model prediction has been run for the proposed KU 24-7 injection to a total volume of
more than 500,000 barrels. The results of this prediction are attached. The study shows
that the final fracture top should be in the shale body at a SSTVD of 3200-3300' at the end
of injection. This height growth rate is similar to that observed in the previous jobs.
Past experience has shown that injected tracers do not adequately indicate the position
of the fracture top! for these large scale injection treatments. If the fracture deviates from
the axis of the well bore by more than a few degrees it will leave the detection range of a
wellbore tracer tool within 50-100 feet of the injection perforations. This shortcoming
applies to both temperature and radio-active tracers.
None of the pressure behavior observed in any disposal project in the Kenai area to date
has indicated horizontal fracture development. To propagate a horizontal fracture the fluid
injection pressure must equal or exceed the total overburden pressure (roughly 1.0 psi/ft).
All of the observed injection (IS I) pressures are well below the overburden pressure, and
are consistent with vertical fracture propagation.
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KGF DISPOSAL PROJECTS
K U 14-4 KU 11-17
Total Injection Vol. (bbls) 452,400 520,000
Est. Frac Length (ft.) 3,000 3,000
Est. Frac Height (ft.) 650 650
Temp. Surveys Yes No
Tracer Surveys Yes No
Injection Interval Sterling Sterling
B 1 & B2 83, 84,C1
Injection Depth (ft. md) 4194-4250 4468-5152
Injection Dates 8/92 - 10/92 8/95 - 11/96
5/93 - 9/93
* The volume, length and height reported for KU 11-17 are as of 11/96.
It is estimate an additional 20,000 - 50,000 bbls. of waste will be disposed
of in this well.
RECEIVED
NOV 0 G 1996
Alaska Oil & Gas Cons. Commission
AnchorëQ9
h: lex cellkenailsterli ng 10 I SP~ SE.X l S
11/6/96
~
6000
5000
4000
Õ 3000
1/6/96
10000
1000 ~
1
I
100
o
500000
600000
100000
300000
400000
200000
14-4 KtJ 11-17
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