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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAboutAIO 021 BAREA INJECTION ORDER 21B
Meltwater Oil Pool
Kuparuk River Field
1. May 5, 2015 Notice of public hearing, affidavit of publication, email
distribution, mailings
2. April 14, 2015 CPAI’s request to amend AIO 21A
3. July 9, 2015 Transcript, exhibits, sign-in sheet
4. July 16, 2015 CPAI’s request to amend AIO 21A
5. October 21, 2015 KRU 2P-447 administrative approval (AIO 21B.001)
6. August 1, 2017 KRU 2P-429 administrative approval (AIO 21B.002)
7. September 26, 2017 CPAI’s injectivity test 8/22/17-9/5/17.
8. October 8, 2024 CPAI request cancellation of administrative approval of
AIO 21B.001 (AIO 21B.001 Cancellation)
ORDERS
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West 7th Avenue
Anchorage Alaska 99501
Re: THE APPLICATION OF
CONOCOPHILLIPS ALASKA,
INC. for an amendment to the order
authorizing underground injection of
fluids for enhanced oil recovery in the
Meltwater Oil Pool, in the Meltwater
Participating Area, Kuparuk River
Field, North Slope, Alaska
IT APPEARING THAT:
Area Injection Order No. 21B
Docket No. AIO-15-015
Kuparuk River Field
Kuparuk River Unit
Meltwater Oil Pool
October 8, 2015
1. Area Injection Order (AIO) 21 authorizing underground injection of fluids for
enhanced oil recovery was issued for the Kuparuk River Unit (KRU) Meltwater Oil
Pool (MOP) on August 1, 2001. Based upon additional information presented by
ConocoPhillips Alaska, Inc. (CPAI), AIO 21 was revoked and replaced by AIO 21 A
on May 16, 2013.
2. Recent geologic and production data analyses indicate AIO 21A does not accurately
describe the MOP and confinement of injected fluids.
3. By application received on April 14, 2015 CPAI, as operator of the KRU, requested
four amendments to existing rules of AIO 21A.
4. A notice of a public hearing was published on the State of Alaska Online Public
Notice web site and on the Alaska Oil and Gas Conservation Commission (AOGCC)
web site on May 4, 2015. On May 5, 2015, the notice was published in the Alaska
Dispatch News. The hearing was scheduled for July 9, 2015.
5. The AOGCC received no comments or requests for a public hearing.
6. On July 9, 2015, the public hearing convened.
7. At the conclusion of the July 9, 2015 hearing, the AOGCC requested additional
information from CPAI. The record was left open until July 16, 2015. CPAI
submitted the requested information on July 16, 2015.
FINDINGS:
1. The Environmental Protection Agency exempted all aquifers within the existing
KRU. 40 CFR 147.102.
2. CO 456A defines the MOP as strata equivalent to those between 6,785 and 6,974
feet measured depth (MD) in well Meltwater North #2A.
3. Regular production from the MOP commenced in November 2001. Miscible gas
Area Injection Order A B
October 8, 2015
0 Page 2
injection began in January 2002, and water injection commenced in May 2003.
Producing wells initially used miscible injectant (MI) for artificial lift.
4. The initial reservoir pressure for the MOP was approximately 2,400 psi. Injection
activity increased reservoir pressure near injection wells to over 4,000 psi; reservoir
pressure near shut-in producers reached nearly 3,000 psi.
5. CPAI encountered elevated gas pressures while drilling MOP well KRU 2P-441 in
March 2002.
6. Beginning in April 2002, CPAI noted elevated outer annulus pressures in MOP
development wells. Gas samples taken from outer annuli had chemical signatures
consistent with MI. CPAI initially suspected MI gas used for artificial lift was
migrating into the outer annuli, possibly through leaking, threaded casing
connections.
7. After identifying elevated outer annulus pressures in MOP wells, CPAI initiated an
annulus -monitoring program and attempted periodic annulus pressure bleeds. Since
2003, CPAI has provided periodic updates of monitoring and diagnostic efforts to
AOGCC.
8. Water injection into the MOP ceased in October 2009 due to water supply line
corrosion concerns. CPAI converted existing MOP water -injection wells to MI
injection or shut them in. CPAI no longer uses water injection, other than for short
term diagnostic purposes.
9. Using proprietary 4D seismic evaluation, CPAI identified a potential vertical
migration mechanism from the MOP that allowed injected fluids to escape from the
MOP and enter shallower strata.
10. During April 2012, CPAI reduced the injection -to -withdrawal ratio to ensure
confinement of injected fluids to the MOP. Outer annuli pressures subsequently
declined. In August 2012, CPAI restricted MI injection pressure to ensure that sand -
face injection pressure remains less than 3,400 psi.
11. On October 4, 2012, AOGCC issued Administrative Approval AIO 21.001 allowing
continued MI injection into the MOP subject to several conditions, including: daily
recording of well pressures, monthly reporting of all MOP wells, and pressure
restrictions on the outer annuli of all wells.
12. CPAI requests AOGCC revise AIO 21A to address numerous changes needed
because CPAI believes injected gas is now being confined to the MOP as required
by AOGCC regulations and AIO 21A.
13. Rule 2 of AIO 21A prohibits new wells and well conversions in the MOP. CPAI
requests Rule 2 be modified to allow new wells (grassroots wells), development well
sidetracks, and well conversions within the MOP. CPAI requests this change to
allow for producer to injector conversions and the ability to drill new development
wells and coil tubing sidetracks within the MOP. CPAI believes that by placing
injectors and producers within the same lobe deposit, injected fluids will be
contained within the MOP, the risk of further migration of injected fluids will be
reduced, and ultimate hydrocarbon recovery will be improved.
Area Injection Order AB
October 8, 2015
0 Page 3
14. CPAI requests modification of Rule 8 of AIO 21A, to allow injection of Beaufort
Sea water and KRU produced water for surveillance, logging near wellbore
formation displacements, and well maintenance.
15. CPAI requests modification of Rule 9 of AIO 21A, Performance Reporting, to read
"The Operator shall submit an annual synopsis of the surveillance, monitoring, and
development initiatives completed during the previous year that pertain to the
confinement of injected fluids within the Bermuda Interval together with the
Meltwater Annual Surveillance Report."
16. CPAI requests removing Rule 11 of AIO 21 A, Expiration Date, which was extended
on May 6, 2015 by AIO 21A.007 to November 16, 2015. CPAI states in its
application "...surveillance and monitoring data suggest that the implementation of
the new reservoir management strategy has prevented further migration of fluids out
of the MOP. The existing rules in AIO 21A, together with the aforementioned
proposed amendments, will ensure long term confinement of injected fluids and
optimal hydrocarbon recovery." CPAI submitted additional information on July 16,
2015 stating "ConocoPhillips believes that a period of 10 years between Area
Injection Order renewals is appropriate for AIO 21A. This recommended period of
10 years is predicated upon the cycle time to design and complete development
initiatives and to evaluate the field performance data."
CONCLUSIONS:
1. AIO 21A and associated administrative actions should be revoked and replaced with
a time -limited injection order tailored to the circumstances in the MOP.
2. Injection activities at the MOP resulted in loss of confinement. Injected fluids
migrated into shallower strata, entered uncemented portions of offset wells, and
elevated pressures in the outer annuli of numerous MOP wells. Injection well
reservoir pressures above 4,000 psi (Finding 4), exceeded the fracture initiation
pressure of the Bermuda and confining strata (Finding 18 AIO 21A) establishing
migration pathways.
3. CPAI estimates that 25-30 percent of the fluids injected into the MOP cannot be
accounted for in the reservoir material balance and are suspected to have escaped
reservoir containment. Annulus pressure bleeds cannot account for this full volume
of escaped fluid. The possibility that gas charged sands overlying the MOP may
exist is a significant drilling hazard. Grassroots wells should be treated like
exploratory wells including requiring mud logs, gamma ray logs, porosity and
resistivity logs, and a shallow hazards survey to identify potentially gas charged
shallow sands.
4. CPAI has implemented reservoir management practices including reducing the
injection -to -withdrawal ratio and restricting the MI injection pressure in response to
the migration of MI out of the MOP. Indications are that these changes may be
allowing migration pathways to close, however, continued measures are required to
confirm the effectiveness of these mitigating practices.
5. Water injection for the purpose of surveillance, logging, near wellbore formation
Area Injection Order N IB
October 8, 2015
• Page 4
displacements, and well maintenance is a valuable tool to properly develop and
manage the MOP. Since Beaufort Sea water was previously authorized by AIO
21 A.003 and AIO 21 A.005 for a limited time for video and fluid movement logging,
this fluid should be authorized.
6. With the dissipating amounts of MI recovered during the annulus bleed operations
and other information indicating migration pathways are closing, a monthly report is
no longer necessary. A detailed annual report will provide sufficient information for
the AOGCC to properly monitor this issue moving forward.
NOW, THEREFORE, IT IS ORDERED THAT AIO 21 and AIO 2 1 A and all
associated administrative approvals are hereby revoked and replaced by this order. All
information related to AIO 21 and AIO 2 1 A is hereby incorporated by reference into the
record for this order. The following rules, in addition to statewide requirements under 20
AAC 25 (to the extent not superseded by these rules), govern Class 11 enhanced oil
recovery injection operations in the affected area described below:
Umiat Meridian
Township
Range
Section
T8N
R7E
Sections 1 through 36: All State Lands
Rule 1 Authorized Injection Strata for Enhanced Recovery (Source: AIO 21)
Within the affected area, fluids appropriate for enhanced recovery may be injected for
purposes of pressure maintenance and enhanced recovery into strata that are common to,
and correlate with, the interval between 6,785' and 6,974' MD in well Meltwater North
#2A.
Rule 2 Meltwater Oil Pool Wells (Source: — Revised this Order)
For any new well drilling surface hole in the affected area:
a. A well site survey in accordance with 20 AAC 25.061(a) will be required; and
b. Mud logs, gamma ray logs, porosity and resistivity logs will be required from the
base of the conductor to total depth.
Rule 3 Monitoring the Tubing -Casing Annulus Pressure Variations (Source:
AIO 21, AIO 21.001)
The tubing -casing annulus pressure and injection rate of each injection well must be
checked at least weekly to confirm continued mechanical integrity. The operator shall
record wellhead pressures and injection rates daily. The operator shall limit the outer
annulus pressure to 1000 psi.
Area Injection Order 1001 B
October 8, 2015
• Page 5
Rule 4 Demonstration of Tubing -Casing Annulus Mechanical Integrity (Source:
Revised this Order)
The mechanical integrity of an injection well must be demonstrated before injection
begins, and before returning a well to service following a workover affecting mechanical
integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed
after injection is commenced for the first time in a well, to be scheduled when injection
conditions (temperature, pressure, and rate) have stabilized and every 2 years thereafter.
MIT's must be conducted in accordance with AOGCC Industry Guidance Bulletin No.
10-02A — "Mechanical Integrity Testing" and done to a test pressure equal to the
maximum anticipated surface injection pressure. The AOGCC must be notified,
following the procedures in AOGCC Industry Guidance Bulletin No. 10-OIA — "Test
Witness Notification", at least 48 hours in advance to enable a representative to witness a
MIT. The MIT report (AOGCC Form 10-426) must be provided to AOGCC no later than
the 5t" calendar day of the month following the testing. Test results must be readily
available for AOGCC inspection upon request.
Rule 5 Notification of Improper Class II Infection (Source: Revised this order)
Injection of fluids other than those listed in Rule 8 without prior authorization is improper
Class II injection. Upon discovery of such an event, the operator must immediately
notify the AOGCC, provide details of the operation, and propose actions to prevent
recurrence. Notification to AOGCC does not relieve the operator of the notification
requirements of any other State or Federal agency.
Rule 6 Well Integrity and Confinement (Source: AIO 21A)
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 AOGCC and obtain permission for
continued operation of the well. A corrective action plan shall be provided for AOGCC
review and approval prior to further action being taken. The operator will also consult
with the AOGCC about the need to shut in all wells in the MOP.
Rule 7 Authorized Infection Pressure (Source: AIO 21A.004)
Injection pressures must be maintained at or below 3,400 prig at the reservoir sand -face.
Rule 8 Authorized Fluids for Injection (Source: Revised this order)
Fluids authorized for injection are:
a. Miscible injectant;
b. Dry gas provided by the Kuparuk River Unit;
c. Tracer survey fluid to monitor reservoir performance;
d. Fluids injected for stimulation purposes per 20 AAC 25.280(a)(2);
e. Glycol from hydro -tests and freeze protection;
f. Diesel used for freeze protection;
Area Injection Order Noll B
October 8, 2015
• Page 6
g. Methanol used for freeze protection;
h. Standard oilfield chemicals (corrosion and scale inhibitors, defoamers, emulsion
breakers, etc.);
i. Beaufort Sea water used for surveillance, logging, near wellbore formation
displacements, and well maintenance; and
j. KRU produced water used for surveillance, logging, near wellbore formation
displacements, and well maintenance.
Any other fluids, or uses for the above fluids, shall be approved in advance by separate
action based upon proof of compatibility with the reservoir and formation fluids.
Rule 9 Performance Reporting (Source: Revised this order)
The operator shall submit to AOGCC an annual synopsis of the surveillance, monitoring,
and development initiatives completed during the previous year that pertain to the
confinement of the injected fluids within the MOP together with the Meltwater Annual
Surveillance Report. The annual surveillance report will be required by April I of each
year. The report shall include, but is not limited to, the following:
a. progress of the enhanced recovery project and reservoir management summary
including engineering and geological parameters;
b. reservoir voidage balance by month of produced and injected fluids;
c. analysis of reservoir pressure surveys within the pool;
d. results and, where appropriate, analysis of production and injection log surveys,
tracer surveys and observation well data or surveys;
e. assessment of fracture propagation into adjacent confining intervals;
f. summary of MIT results;
g. summary of results of inner and outer annulus monitoring for all production wells,
injection wells, and any wells that are not cemented across the Meltwater Oil Pool
and are located within a'/4-mile radius of a Meltwater injector;
h. results of any special monitoring;
i. reservoir surveillance plans for the next year; and
j. future development plans.
Rule 10 Administrative Action (Source: AIO 21A)
Upon proper application, or its own motion, and unless notice and public hearing are
otherwise required, the AOGCC may administratively waive the requirements of any rule
stated herein or administratively amend this order 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 an increased risk of fluid movement into freshwater.
Rule 11 Expiration Date (Source: Revised this order)
This order shall expire if CPAI ceases to be the Designated Operator for the KRU. If
CPAI continues as Designated Operator, this order shall expire five years after the
effective date shown below unless prior to the expiration date CPAI requests the order be
extended.
Area Injection Order N9 B • Page 7
October 8, 2015
Any such request shall include:
a. A review of the existing rules in the order and an analysis whether or not those
rules should be retained, amended, or repealed;
b. A review of, and discussion on, whether or not the affected area of the order
should be revised; and
c. A discussion of, and justification for, proposed new rules or revisions to existing
rules.
Done at Anchorage, Alaska and dated October 8, 2015.
Cathy V Foerster Daniel T. Seamount, Jr.
Chair, Commissioner Commissioner
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the
AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the
matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must
set out the respect in which the order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act
on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the
denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date
on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration,
UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for
reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be
filed within 33 days after the date on which @re AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision
on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the
AOGCC by the application for reconsideration."
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in
the period, the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00
p.m. on the next day that does not fall on a weekend or state holiday.
Singh. Angela K (DOA)
From: Colombie, Jody J (DOA)
Sent: Thursday, October 08, 2015 4:09 PM
To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D
(DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (DOA);
Cook, Guy D (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E
(DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA);
Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery
B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA
sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA);
Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L
(DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA);
AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay;
Andrew VanderJack, Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bob
Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff
Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David
Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone;
ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR
sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli;
Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Gregg Nady; gspfoff, Jacki
Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW);
Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe
Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy
Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty, Kazeem Adegbola; Keith Wiles;
Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler,
Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley
(mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR);
Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill;
mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR);
Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W.
Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L
(DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan
Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly,
Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Smart Energy
Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R;
Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted
Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor
Cutler, Tim Mayers; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin;
Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew
Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff 1
(DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith,
Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR);
Holly Pearen; Hyun, James 1 (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com;
Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J
(DNR); Laney Vazquez, Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson;
Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk
A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane
M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR);
Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J
(LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke;
jilt.a.mcleod@conocophillips.com
Subject: A• 1B (CPA) (KRU) •
Attachments: aio2lb.pdf
•
•
James Gibbs
P.O. Box 1597
Soldotna, AK 99669
Gordon Severson
3201 Westmar Cir.
Anchorage, AK 99508-4336
Richard Wagner
P.O. Box 60868
Fairbanks, AK 99706
Jack Hakkila
P.O. Box 190083
Anchorage, AK 99519
Penny Vadla
399 W. Riverview Ave.
Soldotna, AK 99669-7714
Bernie Karl
K&K Recycling Inc.
P.O. Box 58055
Fairbanks, AK 99711
George Vaught, Jr.
P.O. Box 13557
Denver, CO 80201-3557
Kazeem A. Adegbola
Manager, GKA Development
Darwin Waldsmith North Slope Operations and Development
P.O. Box 39309 ConocoPhillips Alaska, Inc.
Ninilchik, AK 99639 Office: ATO-1326
700 G St.
Anchorage, AK 99501
Angela K. Singh
•
THE STATE
'A.LASl\L`1
GOVERNOR BILL WALKER
•
Alaska Oil and Gas
Conservation Commission
ADMINISTRATIVE APPROVAL
AREA INJECTION ORDER NO.21B.001
Ms. Kelly Lyons
Problem Wells Supervisor
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Re: Docket Number: AIO-15-045
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Request for administrative approval allowing well 2P-447 (PTD 2031540) to
continue to operate with increased outer annulus (OA) pressure not to exceed
1,800 psi to establish stabilized OA pressure and recharge rates.
Kuparuk River Unit (KRU) 2P-447 (PTD 2031540)
Kuparuk River Field
Meltwater Oil Pool
Dear Ms. Lyons:
By letter dated October 10, 2015, ConocoPhillips Alaska, Inc. (CPAI) requested administrative
approval to continue the increased annular pressure limit in the subject well.
In accordance with Rule 10 of Area Injection Order (AIO) 021B.000, the Alaska Oil and Gas
Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative
approval to continue to operate the well with the increased outer annular pressure limit specified
in AIO 021B.000 Rule 3 from 1000 psi to a maximum of 1800 psi in the subject well.
CPAI is continuing a program to determine fluid movement around the production casing shoes
of the injection wells. CPAI is also pursuing a number of surveillance initiatives to aid in their
efforts in characterization and understanding of the Meltwater shallow gas issue. This
monitoring plan will further investigate reservoir and injection responses for the Meltwater oil
pool. A key component of this plan is to allow the OA pressure in well 2P-447 to increase to
equilibrium pressure without being restrained by the 1000 psi limit that is being maintained
through the existing bleed program.
The well exhibits at least two competent barriers to the release of well pressure. Accordingly,
the AOGCC believes that the well's condition does not compromise overall well integrity so as
to threaten human safety or the environment.
AIO 21B.001 .
October 21, 2015
Page 2 of 2
DONE at Anchorage, Alaska and dated October 21, 2015.
a?41
Cathy V Foerster Daniel T. Seamount, Jr.
Chair, Commissioner Commissioner
AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the
AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the
matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must
set out the respect in which the order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act
on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the
denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date
on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration,
UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for
reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be
filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision
on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in
the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00
p.m. on the next day that does not fall on a weekend or state holiday.
• 0
James Gibbs Jack Hakkila Bernie Karl
P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc.
Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055
Fairbanks, AK 99711
Gordon Severson
Penny Vadla
George Vaught, Jr.
3201 Westmar Cir.
399 W. Riverview Ave.
P.O. Box 13557
Anchorage, AK 99508-4336
Soldotna, AK 99669-7714
Denver, CO 80201-3557
Ms. Kelly Lyons
Richard Wagner
Darwin Waldsmith
Problem Wells Supervisor
P.O. Box 60868
P.O. Box 39309
ConocoPhillips Alaska, Inc.
Fairbanks, AK 99706
Ninilchik, AK 99639
P.O. Box 100360
Anchorage, AK 99510-0360
y-&a,�-e
Angela K. Singh
Colombie, Jody J (DOA)
From: Colombie, Jody J (DOA)
Sent: Wednesday, October 21, 2015 12:37 PM
To: 'AKDCWellIntegrityCoordinator'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay';
'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bob
Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Carrie Wong'; 'Cliff
Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens';
'David Duffy'; 'David House'; 'David McCaleb'; 'David Steingreaber'; 'David Tetta'; 'Davide
Simeone'; 'ddonkel@cfl.rr.com'; 'Dean Gallegos'; Delbridge, Rena E (LAS); DNROG Units
(DNR sponsored); 'Donna Ambruz'; 'Ed Jones'; 'Elowe, Kristin'; 'Evans, John R (LDZX)';
'Frank Molli'; 'Gary Oskolkosf'; 'George Pollock'; 'ghammons'; 'Gordon Pospisil'; 'Gregg
Nady'; 'gspfoff'; 'Jacki Rose'; 'Jdarlington oarlington@gmail.com)'; 'Jeanne McPherren';
'Jennifer Williams'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jessica Solnick'; 'Jim Watt'; 'Jim
White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Adams'; 'John Easton'; 'Jon Goltz'; 'Juanita
Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karl Moriarty'; 'Kazeem Adegbola'; 'Keith
Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith';
'Lisa Parker'; 'Louisiana Cutler'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley
(mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marquerite kremer
(meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Michael Calkins'; 'Michael Duncan';
'Michael Moora'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'MJ Loveland'; 'mkm7200';
Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick
W. Glover'; 'Nikki Martin'; 'NSK Problem Well Supv'; Patty Alfaro; 'Paul Craig'; Paul
Decker (paul.decker@alaska.gov); 'Paul Mazzolini'; Pike, Kevin W (DNR); Randall Kanady;
Randy L. Skillern; 'Renan Yanish'; 'Robert Brelsford'; 'Ryan Tunseth'; Sara Leverette; 'Scott
Griffith'; Shannon Donnelly; Sharmaine Copeland; 'Sharon Yarawsky'; Shellenbaum,
Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; 'Stephanie
Klemmer'; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); 'Suzanne
Gibson'; Tamera Sheffield; 'Tania Ramos'; 'Ted Kramer'; Temple Davidson; Terence
Dalton; Teresa Imm; Thor Cutler; 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki
Irwin; Vinnie Catalano; 'Aaron Gluzman'; 'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis;
Andrew Cater; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; 'Bruce Williams';
Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; 'Donna Vukich'; Eric Lidji; 'Gary Orr';
'Graham Smith'; 'Greg Mattson'; Hak Dickenson; Heusser, Heather A (DNR); Holly
Pearen; James Hyun; 'Jason Bergerson'; 'Jill McLeod'; 'Jim Magill'; Joe Longo; John
Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois
Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt
Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; 'Patricia Bettis'; Pete
Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan
Daniel'; 'Sandra Lemke'; Sarah Baker; Shaun Peterson; 'Susan Pollard'; Talib Syed; Tina
Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); 'Wayne
Wooster'; 'William Van Dyke'; 'Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov)';
'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; Bixby, Brian D (DOA); 'Brooks,
Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie,
Jody J (DOA) Oody.colombie@alaska.gov)'; Cook, Guy D (DOA); 'Crisp, John H (DOA)
Oohn.crisp@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton,
Loraine E (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; Trystacky,
Michal (michal.frystacky@alaska.gov)'; 'Grimaldi, Louis R (DOA)
(lou.grimaldi@alaska.gov)'; 'Guhl, Meredith (DOA sponsored)
(meredith.guhl@alaska.gov)'; Herrera, Matthew F (DOA); 'Hill, Johnnie W (DOA)'; 'Jones,
Jeffery B (DOA) (Jeff Jones@alaska.gov)'; Kair, Michael N (DOA); Loepp, Victoria T (DOA);
'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Noble, Robert C (DOA)
1
To: (bo*ble@alaska.gov)'; 'Paladijczuk, Tracie L (LO (tracie.palad ijczuk@alaska.gov)';
'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA)
Oim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Scheve, Charles
M (DOA) (chuck.scheve@alaska.gov)'; 'Schwartz, Guy L (DOA)
(guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)';
'Singh, Angela K (DOA) (angela.singh@alaska.gov)'; 'Wallace, Chris D (DOA)
(chris.waIlace@alaska.gov)'
Subject: aio2lb-001(KRU Meltwater)
Attachments: aio2lb-001.pdf
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
ADMINISTRATIVE APPROVAL
AREA INJECTION ORDER NO. 21B.001 CANCELATION
Ms. Jaime Bronga
Well Integrity Specialist
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Re: Docket Number: AIO-24-029
Request to cancel Area Injection Order (AIO) 21B.001
Kuparuk River Unit (KRU) 2P-447 (PTD 2031540), Meltwater Oil Pool
Dear Ms. Bronga:
By letter dated October 8, 2024, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of
administrative approval (AA) AIO 21B.001.
In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission
(AOGCC) hereby GRANTS CPAI’s request to cancel the AA.
CPAI, by letter dated October 10, 2015, had requested an increase in the outer annulus operating
pressure from 1,000 psi (AIO 21B.000) to 1,800 psi in continuing efforts to understand the
Meltwater shallow gas issues. On October 21, 2015, AOGCC issued AIO 21B.001. AOGCC
determined that water only injection could safely continue if CPAI complied with the restrictive
conditions set out in the AA.
CPAI has suspended the well under Sundry 323-609 and on August 9, 2024, completed a passing
state-witnessed cement plug verification and mechanical integrity test of the tubing. AA AIO
21B.001 is hereby CANCELED.
DONE at Anchorage, Alaska and dated October 9, 2024.
Jessie L. Chmielowski Gregory C. Wilson
Commissioner Commissioner
Gregory Wilson Digitally signed by Gregory
Wilson
Date: 2024.10.09 13:31:59 -08'00'
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.10.09 15:26:27 -08'00'
AIO 21B.001 Cancelation
October 9, 2024
Page 2 of 2
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time
as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration
of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for
reconsideration must set out the respect in which the order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure
to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or
decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within
33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision
denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the
date on which the application for reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or
decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That
appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise
distributes, the order or decision on reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not
included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the
period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday.
From:Coldiron, Samantha J (OGC)
To:AOGCC_Public_Notices
Subject:[AOGCC_Public_Notices] Area Injection Order 21B.001 cancel (CPAI)
Date:Thursday, October 10, 2024 7:45:43 AM
Attachments:aio21B.001 cancel.pdf
Docket Number: AIO-24-029
Request to cancel Area Injection Order (AIO) 21B.001
Kuparuk River Unit (KRU) 2P-447 (PTD 2031540), Meltwater Oil Pool
Samantha Coldiron
AOGCC Special Assistant
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, AK 99501
(907) 793-1223
__________________________________
List Name: AOGCC_Public_Notices@list.state.ak.us
You subscribed as: samantha.coldiron@alaska.gov
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v
THE STATE
°1AI.As�
GOVERNOR BILL WALKER
Ms. Vanessa Angel
Alaska Oil and Gas
Conservation Commission
ADMINISTRATIVE APPROVAL
AREA INJECTION ORDER NO.21B.002
Senior Petroleum Engineer
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510
Re: Docket Number: AIO 17-025
Administrative Approval to allow for a water injectivity test
Kuparuk River Unit 2P-429 well (PTD 201-102)
Kuparuk River Unit
Meltwater Oil Pool
Dear Ms. Angel:
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
On August 1, 2017, ConocoPhillips Alaska, Inc. (CPAI) submitted a sundry application (Sundry
Number 317-358) to conduct an approximately two -week water injectivity test on the Kuparuk
River Unit 2P-429 well (KRU 2P-429). On August 3, 2017, CPAI sent an email clarifying the
maximum surface injection pressure expected during the proposed test. Area Injection Order 21B
(AIO 21B) currently authorizes the injection of Beaufort Sea and Kuparuk River Unit (KRU)
Produced water in the Meltwater Oil Pool (MOP) for surveillance, logging, near wellbore
formation displacements, and well maintenance. The proposed injectivity test does not fall within
the types of activities where water injection is already authorized. An administrative approval is
necessary in order to carry out the proposed work.
I In accordance with Rule 10 of AIO 21B, CPAI's proposed water injectivity test in the KRU 2P-
429 well is HEREBY AUTHORIZED subject to the conditions below.
The MOP was originally developed with a water alternating gas (WAG) enhanced oil recovery
(EOR) project, but has been exclusively injecting gas since 2009. Over time this has caused the
gas oil ratio (GOR) for wells in the MOP to climb to the point where they are no longer consistently
competitive producers. CPAI believes that converting the field to water injection will help make
this pool more competitive and extend its economic life and thus increase ultimate recovery.
Previously, water injection into the MOP was done at high pressures and this contributed to a loss
of containment, which ultimately led to the issuance of AIO 21 A. AIO 21 A provides a specific
list of fluids authorized for FOR injection in the MOP (the list does not include water) and
establishes a maximum sand -face injection pressure limit of 3,400 psig for injection activities.
AIO 21 B.002
August 9, 2017
Page 2 of 3
CPAI wants to test the viability of lower injection pressure, below the sand -face injection pressure
limit, as an FOR process for the MOP to: determine whether to pursue this as a full field project.
To that end, CPAI has requested authorization to conduct a two -week water injectivity test,
utilizing produced water sourced from KRU Central Processing Facility 2, with a maximum
surface injection pressure of 958 psi. Limiting the surface injection pressure to 958 psi during the
water injectivity test will ensure that the sand -face injection pressure does not exceed the limit set
by AIO 21B and thus should ensure containment of injected fluids during the test.] Bottomhole
pressure will be monitored in offset wells before, during, and after the injectivity test. Nearby gas
injection wells will be shut-in during the test so that any pressure response shown in the offset
wells can be attributed to the water injectivity test instead of being related to the ongoing gas
injection FOR project. The results of the test will be used to determine whether to pursue a full
field low-pressure water injection project.
In accordance with Rule 10 of AIO 21 B the AOGCC grants CPAI permission to conduct a
produced water injectivity test subject to the following conditions:
1) This authorization is limited to the single well injectivity test described in sundry
application number 317-358 and the additional information provided on August 3, 2017.
Expansion of water injection beyond this single well project will require separate approval
from the AOGCC; and
2) Within 30 days of completion of the injectivity test CPAI shall provide the AOGCC with
a summary of the results of the injectivity test. This summary shall include information on
the rates at which water was able to be injected and the corresponding surface injection
pressure at that rate, any operational issues encountered during the injectivity test, and
information on any pressure response in the offset wells.
DONE at Anchorage, Alaska and dated August 9, 2017.
Daniel T. Sea ount, Jr. Cathy P Foerster
Commissioner Commissioner
' Surface injection pressure will exceed the 958 PSI limit for a short period of time after water injection begins due to the fact that the well's tubing
will be filled with injection gas and the pressure at the surface will be approximately 2,200 PSI. The initial water pumping pressure will need to
be in excess of 2,200 PSI in order to be able to inject water into the wellbore. As the gas in the tubing is displaced with water the surface injection
pressure will decrease due to the increased hydrostatic head of the water compared to the gas and by the time the gas is completely displaced with
water and the water reaches the sand -face, the surface injection pressure will be under the 958 PSI limit,
AIO 21 B.002
August 9, 2017
Page 3 of 3
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC
grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by
it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the
order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it
within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of
reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the
AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by
inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed
within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on
reconsideration.
In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period;
the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day
that does not fall on a weekend or state holiday.
T] I f: S'I :}1TF.
A L A S K__A_
t.rttVFRN0 R BiLL \%"AlKFP
Ms. Vanessa Angel
Alaska Oil and Gas
Conservation Commission
ADMINISTRATIVE APPROVAL
AREA INJECTION ORDER NO.21B.002
Senior Petroleum Engineer
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510
Re: Docket Number: AIO 17-025
Administrative Approval to allow for a water injectivity test
Kuparuk River Unit 2P-429 well (PTD 201-102)
Kuparuk River Unit
Meltwater Oil Pool
Dear Ms. Angel:
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
aogcc.alaska.gov
On August 1, 2017, ConocoPhillips Alaska, Inc. (CPAI) submitted a sundry application (Sundry
Number 317-358) to conduct an approximately two -week water injectivity test on the Kuparuk
River Unit 2P-429 well (KRU 2P-429). On August 3, 2017, CPAI sent an email clarifying the
maximum surface injection pressure expected during the proposed test. Area Injection Order 21B
(AIO 21B) currently authorizes the injection of Beaufort Sea and Kuparuk River Unit (KRU)
Produced water in the Meltwater Oil Pool (MOP) for surveillance, logging, near wellbore
formation displacements, and well maintenance. The proposed injectivity test does not fall within
the types of activities where water injection is already authorized. An administrative approval is
necessary in order to carry out the proposed work.
I In accordance with Rule 10 of AIO 21B, CPAI's proposed water injectivity test in the KRU 2P-
429 well is HEREBY AUTHORIZED subject to the conditions below.
The MOP was originally developed with a water alternating gas (WAG) enhanced oil recovery
(EOR) project, but has been exclusively injecting gas since 2009. Over time this has caused the
gas oil ratio (GOR) for wells in the MOP to climb to the point where they are no longer consistently
competitive producers. CPAI believes that converting the field to water injection will help make
this pool more competitive and extend its economic life and thus increase ultimate recovery.
Previously, water injection into the MOP was done at high pressures and this contributed to a loss
of containment, which ultimately led to the issuance of AIO 21 A. AIO 21 A provides a specific
list of fluids authorized for FOR injection in the MOP (the list does not include water) and
establishes a maximum sand -face injection pressure limit of 3,400 psig for injection activities.
A10 21B.002
August 9, 2017
Page 2 of 3
CPAI wants to test the viability of lower injection pressure, below the sand -face injection pressure
limit, as an FOR process for the MOP to determine whether to pursue this as a full field project.
To that end, CPAI has requested authorization to conduct a two -week water injectivity test,
utilizing produced water sourced from KRU Central Processing Facility 2, with a maximum
surface injection pressure of 958 psi. Limiting the surface injection pressure to 958 psi during the
water injectivity test will ensure that the sand -face injection pressure does not exceed the limit set
by AIO 21B and thus should ensure containment of injected fluids during the test.' Bottomhole
pressure will be monitored in offset wells before, during, and after the injectivity test. Nearby gas
injection wells will be shut-in during the test so that any pressure response shown in the offset
wells can be attributed to the water injectivity test instead of being related to the ongoing gas
injection FOR project. The results of the test will be used to determine whether to pursue a full
field low-pressure water injection project.
In accordance with Rule 10 of AIO 21B the AOGCC grants CPAI permission to conduct a
produced water injectivity test subject to the following conditions:
1) This authorization is limited to the single well injectivity test described in sundry
application number 317-358 and the additional information provided on August 3, 2017.
Expansion of water injection beyond this single well project will require separate approval
from the AOGCC; and
2) Within 30 days of completion of the injectivity test CPAI shall provide the AOGCC with
a summary of the results of the injectivity test. This summary shall include information on
the rates at which water was able to be injected and the corresponding surface injection
pressure at that rate, any operational issues encountered during the injectivity test, and
information on any pressure response in the offset wells.
DONE at Anchorage, Alaska and dated August 9, 2017.
//signature on file//
Daniel T. Seamount, Jr.
Commissioner
//signature on file//
Cathy P. Foerster
Commissioner
Surface injection pressure will exceed the 958 PSI limit for a short period of time after water injection begins due to the fact that the well's tubing
will be filled with injection gas and the pressure at the surface will be approximately 2,200 PSI. The initial water pumping pressure will need to
be in excess of 2,200 PSI in order to be able to inject water into the wellbore. As the gas in the tubing is displaced with water the surface injection
pressure will decrease due to the increased hydrostatic head of the water compared to the gas and by the time the gas is completely displaced with
water and the water reaches the sand -face, the surface injection pressure will be under the 958 PSI limit,
A10 21B.002
August 9, 2017
Page 3 of 3
RECONSIDERATION AND APPEAL NOTICE
As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC
grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by
it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the
order or decision is believed to be erroneous.
The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it
within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of
reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the
AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by
inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed.
If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on
reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed
within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on
reconsideration.
hi computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period;
the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day
that does not fall on a weekend or state holiday.
Bernie Karl Gordon Severson Penny Vadla
K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave.
P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714
Fairbanks, AK 99711-0055
George Vaught, Jr. Darwin Waldsmith Richard Wagner
P.O. Box 13557 P.O. Box 39309 P.O. Box 60868
Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868
<C,\\-2C, \Z
o- .
a
Colombie, Jody J (DOA)
From: Colombie, Jody J (DOA)
Sent: Wednesday, August 09, 2017 3:32 PM
To: aogcc.inspectors@alaska.gov; Bender, Makana K (DOA) (makana.bender@alaska.gov); Bettis,
Patricia K (DOA) (patricia.bettis@alaska.gov); Brooks, Phoebe L (DOA)
(phoebe.brooks@alaska.gov); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA)
Oody.colombie@alaska.gov); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine
E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); French, Hollis (DOA);
Frystacky, Michal (michal.frystacky@alaska.gov); Guhl, Meredith (DOA sponsored)
(meredith.guhl@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA);
Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov); Paladijczuk, Tracie L (DOA)
(tracie. pa lad ijczu k@a laska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Quick,
Michael (DOA sponsored); Regg, James B (DOA) Oim.regg@alaska.gov); Roby, David S (DOA)
(dave.roby@alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov); Seamount, Dan T
(DOA) (dan.seamount@alaska.gov); Singh, Angela K (DOA); Wallace, Chris D (DOA)
(chris.waIlace@alaska.gov); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator,
Alan Bailey; Alex Demarban; Alexander Bridge; Alicia Showalter, Allen Huckabay; Andrew
VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; Becky Bohrer; Ben Boettger;
Bill Bredar; Bob; Brandon Viator; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English;
Cocklan-Vendl, Mary E; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale
Hoffman; Darci Horner; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb;
David McCraine; ddonkel@cfl.rr.com; DNROG Units; Donna Ambruz; Ed Jones; Elizabeth Harball;
Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Garrett Brown; George
Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hunter Cox;
Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington
oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe
Lastufka; Joe Nicks; John Burdick; John Easton; John Larsen; John Stuart; Jon Goltz; Josef
Chmielowski; Juanita Lovett; Judy Stanek, Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola;
Keith Torrance; Keith Wiles; Kelly Sperback; Kevin Frank; Kruse, Rebecca D (DNR); Kyla
Choquette; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Lori Nelson; Louisiana
Cutler; Luke Keller, Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark
Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; Mike
Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); nelson; Nichole
Saunders; Nick Ostrovsky; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Paul
Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan
Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Sara Leverette; Scott Griffith; Shahla
Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe;
Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Steve Moothart
(steve.moothart@alaska.gov); Steve Quinn; Suzanne Gibson; Tamera Sheffield; Ted Kramer;
Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; trmjrl; Tyler Senden; Umekwe,
Maduabuchi P (DNR); Vinnie Catalano; Well Integrity, Well Integrity; Weston Nash; Whitney
Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz,
Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Corey Munk; Don Shaw; Eppie
Hogan; Eric Lidji; Garrett Haag; Graham Smith; Heusser, Heather A (DNR); Holly Fair; Jamie M.
Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Jim Shine; Joe Longo; John Martineck; Josh
Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia
Hobson; Marie Steele; Matt Armstrong; Melonnie Amundson; Mike Franger; Morgan, Kirk A
(DNR); Pascal Umekwe; Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard
Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Susan Pollard; Talib
Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke
Subject: AIO 21B.002
Attachments: aio21B.002.pdf
Re: Docket Number: AIO 17-025
Administrative Approval to allow for a water injectivity test
Kuparuk River Unit 2P-429 well (PTD 201-102)
Kuparuk River Unit
Meltwater Oil Pool
Jody J. Colombie
.AOGCC Special -Assistant
.Alaska Oil and Gas Conservation Commission
333 West Tti .Avenue
.Anchorage, .Alaska 99501
Office: (907) 793-1221
Fax: (907) 276-7542
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation
Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.
The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at
907.793.1221 or jodv.colombie@alaska.aov.
INDEXES
8
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
October 8, 2024
Commissioner Jessie Chmielowski
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
Commissioner Chmielowski,
ConocoPhillips Alaska, Inc. requests the cancellation of Administrative Approval AIO 21B.001
for Kuparuk service well 2P-447 (PTD 203-154). AIO 21B.001 was approved December 15,
2015, allowing continued operation of the well with an increased OA pressure not to exceed of
1800 psi.
KRU 2P-447 was recently suspended (sundry 323-609) which included setting a CIBP and dump
bailing cement on top. The state witnessed tag of TOC and MIT-T to 1500 psi was completed on
8/9/2024. As such, AIO 21B.001 is no longer relevant and CPAI request that the AIO be
cancelled.
Please contact Jaime Bronga at 907-265-1053 if you have any questions.
Sincerely,
Jaime Bronga
Well Integrity Specialist
ConocoPhillips Alaska, Inc.
Digitally signed by Jaime Bronga
DN: OU=Conoco Phillips Alaska, CN=Jaime
Bronga, E=jaime.bronga@conocophillips.com
Reason: I am the author of this document
Location:
Date: 2024.10.08 14:16:05-08'00'
Foxit PDF Editor Version: 13.0.0
Jaime
Bronga
By Samantha Coldiron at 2:25 pm, Oct 08, 2024
7
ConocoPhillips
September 26, 2017
i-i'CEIVED
OCT 0 2 2017
AXfJSI G4
Dan Seamount, Commissioner
Cathy Foerster, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Ave. Suite 100
Anchorage, Alaska 99501-3539
Re: Docket Number AIO 17-025
Administrative Approval to allow for a water injectivity test
Kuparuk River Unit 2P-429 well (PTD 201-102)
Kuparuk River Unit
Meltwater Oil Pool
Dear Commissioner Seamount and Commissioner Foerster,
Marc Lemons
Manager, GKA Base Production
And Optimization
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1376
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 265-6112
From August 22nd through September 51h a water injection test was performed at Meltwater on injector 2P-
429. CPA] wanted to test the viability of water injection at pressure below the sandface injection pressure
limit. Area Injection Order 21B (AIO 21 B) currently authorizes the injection of Beaufort Sea and Kuparuk
River Unit (KRU) produced water in the Meltwater Oil Pool (MOP) for surveillance, logging, near wellbore
formation displacements, and well maintenance. The proposed injectivity test did not fall within the types
of activity where water was already authorized so an administrative approval was necessary to carry out
the work.
The injectivity test was authorized by the AOGCC in accordance with Rule 10 of the AIO 21B. The
following data was requested from the AOGCC within 30 days of the end of the test.
1. Injection rates and corresponding well head pressures
2. Any operational issues
3. Information on pressure responses in offset wells
ConocoPhillips
Marc Lemons
Manager, GKA Base Production
And Optimization
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1376
PO Box 100360
Anchorage AK 99510-0360
Phone(907)265-6112
1. Injection Rates and corresponding well head pressures
The water injection test ran from 8/22/2017 through 9/5/2017. On 9/5/2017 a step rate test was performed
from 7:30AM to 10:OOAM.
No excursions above wellhead pressure limit set for this test (958 psi) were experienced.
Overall data, colored by day
Sw nv Pms m, pal, Inj.a Rm, BN D vs. Dm
900
600
700
4efe[t Gnsuv Osi
i
I
600
600
• •
��
6>• •
C
• Q O O
6 00
( 0 O fl
•
C
•
O
300
200
ni.mo�nw. enaD
7,000
•
6,600
6,000
6,600
6,000
•
4,600
4,000
3,600
3,000
¢Qa®
C O
•
0
as
20
Soo
16"�Qa
O C O
• • 6D as
•
2.000...
{
• • �- • 0 •
• Q
1,600
Ogg • •
1,000
p
C
6/228011 6Q672017
6126/2017 6IW2017 913/!017
a.a p
Ino nrw exp
cme, h
Dµ eIN'tNlDnt,
�An
� Nm
• *w
e,
o�
ConocoPhillips
Step Rate test data on 9/5/2017
9urfx Pressure, psi, Opeotlon Rab, swan vs. sass
900
860
800
760
700
650
600
550
600
7,000
6,600
6,000
5,600
5,000
4,500
4,000
3,600
3,000
2,600
2,000
1,500
•
Hopm
7:30 AM 7:60 AM 8:10 AM
2. Any operational issues
Marc Lemons
Manager, GKA Base Production
And Optimization
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1376
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 265-6112
s,mcsn.ss,rs. ssl
ammonium
In�lC4an R., BWW
8:30 AM
8:60 AM
9:10AM
9:60AM
9:30 AM
Date
Trxra ey
mover M
(RcrxwnMl
D.,
oey arweexioxe)
4/ Tue
There were no operational issues related to being able to inject water into the Meltwater reservoir below
the maximum allowable surface pressure. Injection rate was varied at the beginning of the test while work
was performed to confirm the accuracy of the injection rate metering. Five days after the start of the test,
the pump unit was shut down for 17 hours to repair a mechanical failure.
ConocoPhillips Marc Lemons
Manager, GKA Base Production
And Optimization
Greater Kuparuk Area
ConocoPhillips Alaska, Inc.
ATO -1376
PO Box 100360
Anchorage AK 99510-0360
Phone (907) 265-6112
3. Information on pressure responses in offset wells
Pressure gauges were hung in the injecting well 2P-429, an offset producer 2P -422A, and an offset
injector 2P-434. The offset injector had been SI for two years prior to the gauge being set, the offset
producer was SI when the gauge was set. Both offset wells remained SI until the test was complete and
all gauges were pulled.
The variation in the BHP data for 2P-429 is because the pump was shut down every 12 hours to check the
oil on the pump driver. Data is collected in the gauges every 10 seconds.
w.9
2.000
t 900
1 800
1.698
1 597
1496
+..396
1 295
1 194
1093
993
892
&82017 8798017 812/2017 81152017 8118/2017 8212017 8242017 8272017 81302017 922017
D..
If you have any questions concerning this data, please contact me at 265-6112.
Marc Lemons
Manager, GKA Base Production and Optimization
Greater Kuparuk Area
W�,tN
3.090 ua.6mw.
3.000
M,L
�MV1
2.964 •res
2,9664 •mu.
2.927
2.927
2.891
2,891
2655
2.855
2.818
2.818
2,782
2.782
2.745
2 745
2.709
2 709
2.673
2.673
2636
2.636
2,600
2 600
Roby, David S (DOA)
From: Angel, Vanessa M <Vanessa.M.Angel@conocophillips.com>
Sent: Thursday, August 03, 2017 9:58 AM
To: Roby, David S (DOA)
Cc: Jolley, Liz C
Subject: Meltwater water injection
Hello Dave,
Per our conversation I just wanted to note that for the 2P-429 WI test, the sundry says we will not exceed 958psi
surface pressure with water.
1 just wanted to clarify that to take the well from gas injection to water injection we will need to pump 1 tubing volume
of water at a higher pressure.
2P-429 is currently injecting gas at 2200 psi, so we need our pump rate to start at 2200 psi to overcome that pressure
and get water into the well, then we can decrease over time. Once approximately 1 tubing volume is in place, we will
stay at our expected pressure of 930 psi, within the do not exceed pressure of 958 psi.
Thanks,
Vanessa
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
AUG 01 2017
G
oC
1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑
Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑
Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Water Inj Test
2. Operator Name:
4. Current Well Class:
5. Permit to Drill Number:
COnocoPhilll sAlaska Inc.
Exploratory ❑ Development C'
Stratigraphic El Service
201-102
3. Address:
6. API Number:
P. O. Box 100360, Anchorage, Alaska 99510
50-103-20378-00
7. If perforating:
8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool? N/A
KRU 2P-429
Will planned perforations require a spacing exception? Yes ❑ No El
9. Property Designation (Lease Number):
10. Field/Pool(s):
ADL 389058 ftl
Kuparuk River Field / Meltwater Oil Pool
11. PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft):
Total Depth TVD (ft):
Effective Depth MD:
Effective Depth TVD:
MPSP (psi):
Plugs (MD):
Junk (MD):
8,974'
6,002'
8505
5738
958
NONE
8900
Casing
Length
Size
MD
TVD
Burst
Collapse
Conductor
82'
16"
110,
110,
Surface
2,936'
9 5/8
2,965'
2,434'
Production
8,941'
7"
8,966'
5,997'
Liner
Perforation Depth MD (ft):
Perforation Depth TVD (ft):
Tubing Size:
Tubing Grade:
Tubing MD (ft):
8176 - 8505
5549 - 5738
4.500"
L-80
7,617'
Packers and SSSV Type:
Packers and SSSV MD (ft) and TVD (ft):
PACKER - NONE
N/A
SSSV: - A-1 INJECTION VALVE on 3.875" DB Lock w.80 BEAN
517.5 MD and 517.3 TVD
12. Attachments: Proposal Summary ❑ Wellbore schematic ❑
13. Well Class after proposed work:
Detailed Operations Program ❑ BOP Sketch ❑
Exploratory ❑ Stratigraphic ❑ Development Service bCI
14. Estimated Date for 8/15/2017
15. Well Status after proposed work:
Commencing Operations:
OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑
GAS ❑ WAG ElGSTOR ElSPLUG ElCommission
16. Verbal Approval: Date:
Representative:
GINJ El Op Shutdown ❑ Abandoned El
17. 1 hereby certify that the foregoing is true and the procedure approved herein will not
be deviated from without prior written approval.
Authorized Name: Vanessa Angel Contact Name: Vanessa Angel
Authorized Title: Senior Petroleum Engineer Contact Email: Vanessa.M.Angel@conocophillips.com
Contact Phone: (907) 265-1018
Authorized Signature: Date: 26
COMMISSION USE ONLY
Conditions of approval: Notify Commission so that a representative may witness Sundry Number:
Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑
Other:
Post Initial Injection MIT Req'd? Yes ❑ No ❑
Spacing Exception Required? Yes ❑ No d Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Submit Form and
Form 10-403 Revised 4/2017 n t i PiP_icpA
r a o F pp valid for 12 months from the date of approval. Attachments in Duplicate
t )
2P-429
Water Injection Test
DATE: 07/25/17
ObiectiveBackground
Meltwater (2P) area has been on gas injection only since 2009. A water injection test into 2P-429
will enable data to be gathered on the water injection capability at the low maximum surface injection
pressure of 958 psi. Meltwater online producers will also be monitored for changes in performance
which may occur during the injection test period. The results of the test will be used to analyze
whether long term water injection at —950 psi maximum surface pressure is economically feasible at
Meltwater.
Downhole pressure will be gathered utilizing memory gauges from two wells with bottom hole
locations near 2P-429, before, during, and after the injection testing. Memory gauges will be run
approximately two weeks before the start of the injection test into injectors 2P-429 and 2P-434 (LTSI
injector) and low rate producer 2P-422A. Producer 2P-422 (-50 BOPD) will be SI and a downhole
memory gauge will be run into the well at least two weeks prior to the start of the injection test.
Injectors 2P-427 and 2P-432 will also be shut in just prior to the beginning of the injection test and
remain shut in for the duration of the test.
The intended start date for beginning injection into 2P-429 is 08/15/17 and a 2-week duration is
planned. CPF2 produced water as the injection fluid during the test; the produced will trucked to 2P
and a pump truck will be used to inject the water.
A drawing showing the approximate location of all equipment is attached to this procedure.
Items to Note:
The absolute surface pressure limit of 958 psi is based on a maximum reservoir sandface
injection pressure of 3400 PSI at the top of the perfed sand in the 2P-429 well. Below that depth,
the higher hydrostatic gradient will increase above 3400 psi. This is the current interpretation of
the AIO injection pressure limit.
2P-429 MITIA to 3300 psi passed 8/20/2016.
Expected Well Test Duration:
• 2 weeks
Anticipated Initial Injection Rate and pressure:
• 4000 BWPD
• 930 psi maximum wellhead injection pressure
Annulus Monitoring:
• DSO to Monitor Annulus Pressures:
• 2400 psi on the IA
• 1000 psi on the OA. Be aware of the potential for increase in pressure due to thermal expansion.
• Well Integrity Status is NORMAL, no ANNCOMM issues.
115
aivzoi7
2P-429
Water Injection Test
Safety:
• Ensure that the on -tour pump operator can be reached by field radio at all times.
• Follow all contractor company SOPS and the ASH handbook.
• Keep non -intrinsically safe devices such as cell phones out of classified areas such as the
wellhouse and modules on the 2P pad.
• Ensure all equipment and tanks are electrically grounded.
• Report any Accidents, Spills, or Near -Misses to supervisor immediately.
• H2S should not be present but every worker must wear a H2S monitor within 9" of the mouth at
all times when on the job site.
• The pump operator will neither operate nor defeat wellhead safety systems except to shut in the
well in an emergency situation via wellhead safety system(s).
• A pre job safety walk through will be conducted after connection to the Kuparuk piping or live
process prior to pumping operation being initiated. This pre job walkdown should include the
DS Lead, DSO, CPA Safety Specialist, CPA Production Engineer, CPA DS Facility Engineer
and the pump operator.
• Any significant change in from this procedure during the execution of the job, including use of
different metering or a different pump, during the job set up will be reviewed and approved by
the 2P DSO (radio call number, 233) and the Production Engineer.
Injection Procedure:
1) Prior to starting injection CPF2 Instrument Techs will install a Panemetrics flow meter and pressure
gauge (with wireless transmitters) on the piping downstream of the pump discharge:
2) Prior to starting injection, the Production Engineer will verify that correct changes in IP21 to convert
the well from GI to WI service for 2P-429 in IP21 have been completed and that the wireless
transmitters for the Panemetrics flow meter and pressure gauge have been added to IP21.
3) Tanker trucks will take on water at the CPF2 PWI truck loading facility (or possibly a temporary
truck loading station set up at 2N) and haul the water to a 4-tank battery on site in front of 2P-429.
4) Initiate water injection into 2P-429 ramping up to 4000 bwpd at a well head injection pressure of no
more than 930 psi. DSO to verify the Panemetrics flow meter and pressure gauge and wireless
transmitters are functioning properly.
5) Immediately notify the CPF2 PE should any significant changes to injection pressure and/or rate
occur to the well during the injection test.
6) Objective is two weeks of continuous injection into 2P-429. Short term interruptions in injection
into the well due to problems with truck delivery of water or pump maintenance, for example, will
not cause the test to be ended prior to the planned two -week duration nor is it likely to be extended.
7) DSO and Production Engineer to obtain frequent well tests on producers most likely to interact
directly with 2P-429.
8) DSO to monitor IA and OA pressures on all Meltwater wells while paying close attention to those
most likely to interact with 2P-429.
2/5
sn/2017
*a.- 420
i9k$9Ca
2P-429
Water Injection Test
.
�i
f
f ,
QUA i
fIS�dBs.SYA %n W3
..:...,.max.......• -...a+:...
f ..+...
:.... �,...k.:...»»..+«.+:... �A .,�.......,..,....-. �i:
3/5
8/l/2017
2P-429
Water Injection Test
CAUTION
THIS DRILL SITE IS TO BE
CONSIDERED AN H25 AREA.
.:d
FEATURE LOCATIONS
LEGEND
�- OLEAN SHOP! DUMP AREA, ALL EQUIPMENT;
- ENMA0wCNTAL AREA -NO SHOW DUMP=l
I — POKALINE—RtAICH MEARANCEIt,
SLOWERS MAY NIT- LINES WITH OfSCRAINZ
— SNOTS DLOWNS AREA OF&Y.
NO Show DUNIPING AREA.
®
RESCUE EQUIPMENT
SODA LOCATIONS
I'-1-1
DESIGNATED SM AREA (PRIMARY}
LI
DESIGNATED SAFE AREA (SEOMDARY)
EYACUATYON ROUTES DEKNOINC ON INNO
ti
WINDSOCK
DARRICADE/ESCAPE ROUTE
FIRE EMINOUISNER
NOTE:
Nil SNOW IS TO BE PLACED IN
ANY RESERVE PIT OR LINED PIT.
Keep 5' clearance from all flowllnes due
to high voltage electrical lines. If you
need to get closer, contact R&P:7"6.
LEGEND
# DOSTRIG PRODUCER
. EMSTM INJECTOR
O NEW PRODUrm
n NEW INJECTOR
. Q OORYMIED FROM
PAODUCEN TO IMECTER
Ill EEISRNB ODDUGIOR
¢,! k7WNiD1?a!Y CNAume
• wvo�n vpJ
s®allosl�
unoE hiltips AREA:2P MODULEXXXX UNIT: D2
3 5 1 Add Thermosi hens Per )C10002iACS R JEC �� O52P FACILITY EXPANSION
I)aHatMA dlk—v I --A b P-+,I, Par I(ARNRQSAM .FC R �`� 02/20/02 LKS21GEt FEATURE LOCATION
4/5
8/1/2017
e • e." s sWIF
ConocoPhillips ;
KUP INJ
2P-429
Well Atir bates
Max Angle AM TD
Welihore APW WI Field
Name Welibore Status
ncl (°)
MD (ftKB) Act Btm (ftKB)
501032037800 MELTWATER
INJ
56.09
8,902.56 8,974.0
Comment H2S (ppm) Date
Annotation End Date
KB-Grd (ft) Rig Release Date
SSSV: NIPPLE
Last W0:
33.91 12/20/2001
Annotation Depth (ftKB) Entl Date Annotation
Last Mod By
Entl Date
Last Tag: SLM 7,849.0 2I9/2015 Rev
Reason: GLV C/O, Pull plug/catcher, Tag,
INJ VLV, Fish
hipshkf
5I7I2015
Set
96
Casing Description OD
(in)
ID 9n)
Top (ftKB)
Set Depth (ftKB)
Set Depth (TVD)...
WtlLen
(1... Grade
Top Thread
CONDUCTOR
16
15.062
28.0
110.0
110.0
WELDED
Casing Description OD
(in)
ID (in)
Top (ftKB)
Set Depth (ftKB)
Set Depth (TVD)...
Will...
(I... Grade
Top Thread
SURFACE
9 5/8Will...8,835
28.6
2,965.0
2.434.3
40.00
L-80
BTCM
Casing Description OD
(in)
ID (in)
Top (ftKB)
Set Depth (ftKB)
Set Depth (TVD)...
WtlLen
(I... Grade
Top Thread
PRODUCTION 7"x4.5"
7
6.276
25.5
8,966.4
5,997.3
26.00
L-80
BTCM
01638'
<
Tiub�Dg ��s
Tubing Description String
Ma...
ID (in) Top
(ftKB)
Set Depth (7f
Set Depth (TVD) (.-..
Wt (Ibtft)
G.de
Top Connection
TUBING 4112
3.958
23.2
7,617.0
5,219.2
12.60
L-80
IBTM
Corr000n `Details:;
Nominal ID
Top (ftKB)
Top (TVD) (ftKB)
Top Intl (°)
Item Des
Core
(in)
23.2
23.21
0.00
HANGER
FMC TUBING HANGER
4,500
517.5
517.31
4.40
NIPPLE
CAMCO DB LANDING NIPPLE
3.875
7,550.0
5,179.01
53.28
SLEEVE
BAKER CMU SLIDING SLEEVE w1OTIS'X' PROFILE
3.812
7,570.6
5,191.41
53.15
NIPPLE
CAMCO DB-6 NIPPLE
3,750
7,614.1
5,217.51
52.88
SEAL
BAKER G-22 LOCATOR 8 SEAL ASSY
3.875
--OUIeTlq,HDle:..
!£171 'ie reti'ie3ai>>e
Pa9ss
Ya
11ii1175,.1Sti+;etG.) '
Top (ftKB)
Top (TVD) Top
(ftKB) (°)
Intl
Des
Core
Run Date
to (in)
517.5
517.3 4.40
VALVE
4.5" A-1 INJECTION VALVE ON 3.875" DB LOCK
5/4/2015
0.800
1
w.80 BEAN (S/N: HRS-51)
8,900.0
5,960.31 56.09
FISH
17" x 1-11/16" ELINE SPINNER
4/27/2015
0.000
Shot"
Dens
Top(TVD) Btm(TVD)
(shots/
Top (ftKB)
Bt. (ftKB)
(ftKB)
(ftKB)
Zone
Date
to
Type
Corn
8,176.0
8,240.0
5,549.5
5,586.3 T-3,
2P-429
1/1412002
6.0
IPERF
2.5" HSC, 2506 Power
jet HMX Chgs, 60 deg
phase
8,300.0
8,325.0
5,620.8
5,635.2 T-3,
2P-429
1/14/2002
6.0
IPERF
2.5" HSC, 2506 Power
jet HMX Chgs, 60 deg
phase
8,325.0
8,350.0
5,635.2
5,649.5 T-3,
2P-429
1/1312002
6.0
IPERF
2.5" HSC, 2506 Power
.
jet HMX Chgs, 60 deg
phase
8,386.0
8,411.0
5,670.2
5,684.5 T-3,
2P429
1/1312002
6.0
IPERF
2.5" HSC, 2506 Power
jet HMX Chgs, 60 deg
phase
8,411.0
8,435.0
5,684.5
5,698.2 T-3,
2RA29
1/13/2002
6.0
IPERF
2.5" HSC, 2506 Power
jet HMX Chgs, 60 deg
phase
8,495.0
8,505.0
5,732.5
5,738.1 T-3,
2P-429
1113/2002
6.0
IPERF
2.5" HSC, 2506 Power
jet HMX Chgs, 60 deg
phase
Mandrel inserts
St
all
on
(TVD)
Valve
Latch Port
Size TRORun
Top (fDCB)
(ftKB)
Make Model
OD(in)
-am
Type
Type
(in)
(psi)
Run Date
Co.
1
7,50 .21
5,149.3 1
CAMCO KBG-2
1
GAS LIFT
DMY BTM
0.000
0.0 12t8r2015
Alotes;
Genera] 8.5a%iy
End Date
Annotation
7/28/2009
NOTE: OBSTRUCTION (78417) IS 100T HIGHER THAN 1/1812007 TAG (8859')
11/2272010
NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0
4/27/2015
NOTE: 17" x 1-11/16" ELINE SPINNER LEFT IN HOLE
0 0
•
Wallace, Chris D (DOA)
From: Wallace, Chris D (DOA)
Sent: Saturday, October 10, 2015 10:52 PM
To: NSK Problem Well Supv
Subject: RE: Request to allow Meltwater injector 2P-447 (PTD 203-154 AIO 21A.006) and
producer 2P-431 (PTD 202-053 AIO 21A.002 Amended) to remain online 10-10-15
Kelly,
AIO 21 B did cancel the old orders but it was not our intent to change the current operation of the wells. Please
get back with me within the mentioned 14 days with the criteria that you see in conflict and we will work this
out.
Thanks
Chris
-------- Original message --------
From: NSK Problem Well Supv <n I 617@conocophillips.com>
Date: 10/10/2015 2:20 PM (GMT-09:00)
To: "Wallace, Chris D (DOA)" <chris.wallace(&alaska.gov>
Subject: Request to allow Meltwater injector 2P-447 (PTD 203-154 AIO 21A.006) and producer 2P-431 (PTD
202-053 AIO 21 A.002 Amended) to remain online 10-10-15
Chris,
The AA's of two Meltwater wells, injector 213-447 (PTD 203-154 NO 21A.006) and producer 213-431 (PTD 202-053 NO
21A.002 Amended), expired when the new Meltwater Area Injection Order AIO 21B was issued on 10/08/15. CPAI
requests that these wells be allowed to remain on line while new applications are assessed and submitted if deemed
appropriate. The wells will be operated as set out in their expired AA's for a period not to exceed 14 days.
Brent Rogers / Kelly Lyons
Problem Wells Supervisor
ConocoPhillips Alaska, Inc
Desk Phone (907) 659-7224
Pager (907) 659-7000 pgr 909
•
ONES
lh Conocoillips
Alaska
July 16th, �Pw X0 I,S C Dt—J
JUL 16 2015
I�
Commissioners Cathy Foerster and Daniel Seamount
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
RE: Request to Amend Area Injection Order No. 21A, Meltwater Oil Pool
Greater Kuparuk Area
North Slope, Alaska
Dear Commissioners:
Kazeem Adegbola
Manager, GKA Development
Greater Kuparuk Area
P. O. Box 100360
Anchorage, AK 99510-0360
Phone: 907-263-4027
On july 91h,.391-4fe Alaska Oil and Gas Conservation Commission ("Commission or AOGCC")
held a public hearing concerning ConocoPhillips Alaska, Inc.'s ("ConocoPhillips") Request to
Amend Area Injection Order No. 21A ("AIO 21A"). ConocoPhillips submits this letter to
supplement the record presented to the Commissioners and provides the following responses
to the Commissioners' questions asked during the public hearing.
Source of Gas Present in the Overburden
A Meltwater Field Outer Annulus Gas Analysis was performed in 2012 by the ConocoPhillips
Technology Group in Houston. It was determined that the shallow intervals above the Bermuda
reservoir at discovery contained dominantly dry biogenic gas (high C1 content and highly
negative carbon isotopes) while the gasses associated with the Bermuda reservoir were
dominantly thermogenic gas with a small volume of more negative biogenic gas (methane).
The Meltwater N2 (discovery well) and Meltwater N1 and N2A (delineation wells) mud logs
show that at discovery numerous gas shows were present in the overburden below the base of
the Permafrost. These shallow gasses tended to have biogenic dry methane or a mix of
biogenic methane and thermogenic gas.
Based upon the mud logs from the Meltwater N2 discovery well and the N1 and N2A
delineation wells, there was no presence of butanes (C4), pentanes (C5), hexanes (C6), or
heptanes (C7) in the overburden 200' above the Bermuda reservoir. Miscible injectant (MI)
contains measurable amounts of C4-C7. The MI contains gas from the Prudhoe Bay Field that is
isotopically more positive (more mature) and thus distinguishable from the Meltwater gas
• !
Commissioners Foerster and Seamount
July 16, 2015
Page 2
accumulations. Therefore, gas composition analyses have been used at Meltwater to
determine the presence of reservoir fluids in the outer annuli. Since 2012, no well has
exhibited an increasing similarity to MI.
No gas has been encountered from the surface to base Permafrost interval while drilling any
Meltwater exploration, delineation, or development well. The Permafrost appears to act as a
barrier to natural migration of gas from the overburden below.
Vertical Extent of the Linear Features
In response to the Commissions' questions regarding the vertical extent of the linear features,
please see slides and transcript from the confidential presentation presented by Eric Bressler to
the AOGCC on November 14t", 2012. See confidential transcript, line 22 on page 57 through
line 1 on page 58 when referring to slide 3 of the confidential presentation. See line 14 on page
59 through line 11 on page 60 of the confidential transcript when referring to slides 6-7 of the
confidential presentation.
Seismic Resolution
The resolution of the 1998 and 2008 seismic data sets varies with depth. This is primarily
because fold and frequency are different with depth. Fold is a measure of the redundancy of
common midpoint seismic data, equal to the number of offset receivers that record a given
data point or in a given bin and are added during stacking to produce a single trace. Generally,
higher fold produces better resolution and the Meltwater 3D fold varies from 3 fold around
1000 feet TVDSS to 57 fold around 6000 feet TVDSS.
The dominant frequency of the Meltwater 3D datasets range from 34 Hz shallow to 29 Hz
deeper. Tuning Thickness is the thinnest interval over which a correct measurement of the
distance between two closely spaced reflectors can be made. At the Bermuda reservoir depth,
tuning thickness is estimated to about 87 feet.
Surface Faults
ConocoPhillips Alaska is not aware of any surface or subsurface data that suggests the presence
of faults at the surface.
Commissioners Foerster and Seamount
July 16, 2015
Page 3
Determination of Presence of Shallow Gas with Seismic
Seismic evaluations are used to determine if shallow gas is present in a predictive manner and
can be useful to qualitatively assess the presence of shallow gas. Seismic data was analyzed as
part of the exploration drilling permit issued by AOGCC for well Meltwater N2. A review of that
analysis shows seismic data did not indicate the presence of shallow hazards. If a rotary well
was to be drilled at Meltwater in the future, ConocoPhillips would complete a shallow gas
hazard assessment as part of the AOGCC drilling permitting process, an area review, and the
ConocoPhillips Well Design and Delivery Process.
Area Injection Order Sunset Clause
ConocoPhillips believes that a period of 10 years between Area Injection Order renewals is
appropriate for NO 21A. This recommended period of 10 years is predicated upon the cycle
time to design and complete development initiatives and to evaluate the field performance
data.
Area Review as Part of the Drilling Permitting Process at Meltwater
ConocoPhillips does not object to completing an area review as part of its Well Design and
Delivery Process and ConocoPhillips would submit the results of such area review to the AOGCC
with its application for a permit to drill.
Meltwater Outer Annulus Pressure Review
The charts within Attachment 1 depict the outer annulus (OA) pressure for each Meltwater well
from January 15t, 2010 through July 13th, 2015. This range was chosen as it spans the time
period before and after the sand face injection pressure limit was set for Meltwater injectors.
As of July 13th, 2015, no well at Meltwater, shut-in or active, had an OA pressure above the
1,000 psig limit set forth in Rule 3 of AIO 21A. The trends of the individual wells over the time
span specified can be classified into four categories:
• Decrease in OA Pressure:
0 2P-406(p)
0 2P-417(p)
0 2P-420(i)
0 2P-431(p)
0 2P-432(p)
0 2P-438(p)
•
I—]
Commissioners Foerster and Seamount
July 16, 2015
Page 4
0 2P-441(p)
0 2P-448A(p)
0 2P-451(p)
• No Appreciable Change in OA Pressure
0 2P-415A(p)
0 2P-422A(p)
0 2P-427(i)
0 2P-443(p)
0 2P-449(p)
• Recent Increase in OA Pressure Attributable to Thermal Effects
0 2P-419(i)
0 2P-429(i)
0 2P-434(i)
0 2P-447(i)
• Increase in OA Pressure
o 2P-424A(p)
From the time at which the sand face injection pressure limit was set in 2012 until 2014 only
three injectors were active, 2P-420, 2P-427, and 2P-429. When the reservoir pressure
decreased below the sand face injection pressure limit at 2P-419 and 213-447 in 2014, the two
injectors were returned to service. Upon completion of well work and pressure transient
analysis in 2014 injector 213-434 was returned to service. When these three injectors (213-419,
2P-434, and 2P-447) were returned to service they realized an increase in their outer annulus
pressure that can be attributed to thermal effects from the increase in thermal energy input
from the injection gas. In addition, injector 213-429, after a period of intermittent injection, was
brought online at a higher rate as the reservoir pressure had decreased substantially. This
increased injection rate resulted in an increase in OA pressure that can be attributed to thermal
effects from the increase in injection rate. Charts for each of these four wells (213-419, 213-429,
2P-434, and 2P-447) with their associated injection rates are depicted in Attachment 2.
Well 2P-424A, although below the 1,000 psi OA pressure limit, has seen a gradual increase in outer
annulus pressure over the 2010-2015 time period. This increase in OA pressure cannot be attributed
to thermal effects, nor can it be attributed to annular communication. Please refer to Attachment 3
for a chart of well 2P-424A's outer annulus pressure and production rates.
Further investigation was done into well 213-424A to determine if there were signs of migration of
injected fluids out of zone. The findings from this investigation are summarized below:
• Biogenic gas is native to the Meltwater overburden. Miscible injectant, that has been
injected into the Bermuda interval, has a significantly different isotopic signature for
Commissioners Foerster and Seamount
July 16, 2015
Page 5
methane and ethane. The isotopic analyses of the gas collected from the 2P-424A outer
annulus in 2012 indicated it was entirely biogenic in nature.
• Outer annulus gas composition analyses were conducted to determine if NGLs, that are
combined with methane and ethane to create MI, were present. Biogenic gas in the
Meltwater overburden does not contain appreciable quantities of NGLs. The results of
these analyses do not indicate the presence of NGLs in the outer annulus gas. Please refer
to Attachment 3 for a chart showing these outer annulus gas composition analyses.
• The outer annulus pressure has been bled down to assess the recharge rate. It has been
determined that the recharge rate is approximately 15 psi/day and that the pressure
levels off and is currently stable at approximately 750 psig. This 750 psig pressure is well
below the outer annulus pressure limit of 1,000 psig.
From the further investigation summarized above, there is no evidence that well 2P-424A's outer
annulus is in communication with fluids that were injected into the Bermuda interval. Well 2P-
424A's outer annulus pressure, gas composition, recharge rate, and annular integrity will continue to
be monitored for signs of migration of injected fluids out of zone.
Potential Meltwater Field Incremental Recovery
By pursuing well conversions and Coiled Tubing Drilling sidetracks at Meltwater an estimated
incremental 2-7 MMSTB of gross resource may be produced.
Well Schematics
ConocoPhillips has not yet begun the well design process for future development wells at
Meltwater. ConocoPhillips would submit a schematic with any permit to drill application after
completion of an area review and the Well Design and Delivery Process.
Coiled Tubing Drilling (CTD) wells would be drilled and completed within the Bermuda reservoir.
An example of a typical CTD well for the Kuparuk reservoir is attached within Attachment 4.
Location of 2P Pad
The location of the 2P pad was based upon Phillips Alaska's understanding of the Meltwater
subsurface accumulation as well as surface topography, habitat value, and other factors. The
pad was oriented to minimize snow accumulation on the site.
Commissioners Foerster and Seamount
July 16, 2015
Page 6
Conclusions
ConocoPhillips is confident that the requested amendments are based on sound engineering
and geoscience principles, will further mitigate the risk of the migration of injected fluids out of
the Meltwater Oil Pool, will increase ultimate hydrocarbon recovery, will not promote waste or
jeopardize correlative rights, and will not result in an increased risk of fluid movement into
freshwater. We are confident that with these changes, ConocoPhillips can continue to operate
in a safe and efficient manner at Meltwater.
Sincerely,
Kazeem Adegbola
Manager, GKA Development
Attachments
0 t •
Commissioners Foerster and Seamount
July 16, 2015
Page 7
Attachment 1: Meltwater OA Pressures
2 P-4Q6
taco
zaoo
� zaoc
A uoo
a too
q EAo
o ado
zoo
—2o.40s
2P-415A
ISO
I"
B =
iaoc
Iv
aco
N
N
Vw
200
0 -
9 4 b P y
—2lxdiiA
Ol •
Commissioners Foerster and Seamount
July 16, 2015
Page 8
2 P-417
i®00
1400
3 1200
A 1000
a i00
Vi
M
d am
4W
200
Q
11
2P-4Y!
2P-419
1mi0
140D
g um
1000
■ am i
GM
400
200
0 -- -
�� ,titi 7� ,y'i .�A ♦y 1�
2P 419
Commissioners Foerster and Seamount
July 16, 2015
Page 9
2P-420
IWO
1400
i20p
A Iwo
I
o am
NM
5M
4W
200
2 P-42p
2 P-422A
Iwo
140p
�UM
low
;p
am
ew
40Ci
200 Lf
0
J,�ct ��r� y0tA �,,cr
e Il
�2P.422A
0 •
Commissioners Foerster and Seamount
July 16, 2015
Page 10
2P-424A
Iwo
troo
1200
g two
a mo
6M
,00
ton
1/ 0'� 1 �
140'
—2a-a2a
2P-427
teoo
taoo
.Wy tam
tM0
3a a0
n
Q am
U 4W
2m rTrrT
0, 1 1 1 1 1 1
o ti ti s � u
— 2;: 27
0 0
Commissioners Foerster and Seamount
July 16, 2015
Page 11
2P-429
law
1400
Iwo
g low
mam
h
4M
203
8
'14 i~ 1'i' 1^3 14' tih ,40
—2�t2D
2P-431
14W
1D0
i200
vlli MW
L00
j� GM
�+ 4W
2C0
0
,y0 4� 41 ,ti3 ,�A 'ti'7 "rho
-2P 491
0 •
Commissioners Foerster and Seamount
July 16, 2015
Page 12
2P-432
Iwo
1400
�MO
1000
am
GM
200
0
—2P-432
2P-434
I-Aw
14M
.W, 1100
vu' 1000
a �0
60D
400
200
0
—2?.4i4
Commissioners Foerster and Seamount
July 16, 2015
Page 13
2P-438
Iwo
I"
I200
� IODD
a a0
M
6w
a4o
200
0
NO N
,�l� J il il il
—2W4S8
2P-"I
law
1400
I200
Iwo
sow
ew
20D
0 hit?
—2PdA1
• •
Commissioners Foerster and Seamount
July 16, 2015
Page 14
2 P-"3
,two
14M
1200
g 1000
a a0
a
600
400
200
0
10 ti� �N Nq
—2P-A43
2P-"7
IWO
MW
1200
IWD
a �0
sao
4W
200
0
Jsc�' �cr o� ,1ci Jai s'c1 �ac�
2Ad47
• : *
Commissioners Foerster and Seamount
July 16, 2015
Page 15
2P-"SA
Iwo
1400
1000
mas
CL oo
o. s
4W
2.W
0
1d 'f4 S'1' 'tip 'tit 1� ti�O
,y(i ySY CY ,�Ck � CS gCY
2P-"9
ieoo
uoo
laoo
�nw.
m aw
M
aw
400
200
0
ti4 NN yi 43 titr tih kb
�3�z ace tiD� ,ace �aci �9tx ,gcK
�2P.449
•
•
Commissioners Foerster and Seamount
July 16, 2015
Page 16
2P-451
1600
1400
12W
g 1000
m a0
a
60D
4M
200
0
,�9 titi .ti'L .%
-2P-d31
• •
Commissioners Foerster and Seamount
July 16, 2015
Page 17
Attachment 2: Recent Increase in OA Pressure Due to Thermal Effects
2P-419
3ROo
30000
1400
9fl00
_
s=
3200
ii
70DO
3000
b004
aw
5000
{i
IL800
4dDO
p
4O0
F 3000
;
2000
C
200
30J0
0
0
---2P.t3!-InjaKtion Rats
2P-429
3600
25000
1400
# _
p 1200
{ 20000
i
.� i000
i
3S000
O
�
am
lam C�
Q�GM
SODO C
200
4d
�'b tib
411
144 q13 y��
--2P•429 ---lnjectias Rate
0 •
Commissioners Foerster and Seamount
July 16, 2015
Page 18
2P-434
Iwo ,
ls=
1400
13000 ....
1200
, 13000
1000
soon
a
.r
7W
a� 6W `
sago
40o
3000
G
200
100o
i
0
1000
—2P.434 —Injection RAC!
ZP-447
16001,
IS=
'
3400
13000 +�+
1200
} 13000
.a low
9000
am
7000 �1
670 !
S000
4�
V 400
! 3000
200
1000
0
_I 11
_ _.
-lox
���2PA47—Ing4ctionW_
Commissioners Foerster and Seamount
July 16, 2015
Page 19
Attachment 3: Review of Well with an Increase in OA Pressure
2P-424A
ICU
Ixr soya
j 4M
A
a SM 300
Q.
20D
400 N
Iao
200 3$so
—i;'-MA —Ca RM —W,1!R e
3
2
I -
0
2P-424A OA Gas Compositon
U C
. z••ctar� �,+stuzou
w 2*stcs. s?a�.'2033
z►.ss� sott�aoai
_• 2src3c6 at/2�nOae
� E'.�ye-.e 6ss Cd+epo sR:ad+
Commissioners Foerster and Seamount
July 16, 2015
Page 20
Attachment 4: Typical Kuparuk Coiled Tubing Drilling Well Schematic
Typical Kuparuk CTD Sidetrack In Blue
conductor
S�xface Gsir�
of A3ands
of A -sands
This is a typical Kuparuk A -sand CTD Completion.
Depending on the results of the Well Design and
Delivery Process, a potential Meltwater CTD well
schematic may be different
46 0
1 ALASKA OIL AND GAS CONSERVATION COMMISSION
2
3 Before Commissioners: Cathy Foerster, Chair
4 Daniel T. Seamount
5
6 In the matter of proposed modifications )
7 to Area Injection Order AIO 21A. )
8 )
9
10 ALASKA OIL and GAS CONSERVATION COMMISSION
11 Anchorage, Alaska
12
13 July 9, 2015
14 9:00 o'clock a.m.
15
16 PUBLIC HEARING
17
18 BEFORE: Cathy Foerster, Chair
19 Daniel T. Seamount, Commissioner
0
0
1
TABLE OF CONTENTS
2 Opening remarks
by Chair Foerster
03
3 Comments by
Mr.
Nenahlo
08
4 Comments by
Mr.
Wentz
24
5 Comments by
Mr.
Bressler
27
6 Comments by
Mr.
Kanady
65
7 Comments by
Mr.
Starck
82
Pj
1 P R O C E E D I N G S
2 (Anchorage, Alaska - July 9, 2015)
3 (On record - 9:01 a.m.)
4 CHAIR FOERSTER: I'll call this hearing to
5 order. Today is July 9th, 2015, it's 9:01 a.m. We're
6 in the offices of the Alaska Oil and Gas Conservation
7 Commission located at 333 West Seventh Avenue,
8 Anchorage, Alaska. To my left is Commissioner Dan
9 Seamount, I'm Cathy Foerster.
10 Today we're having a hearing regarding docket
11 number AIO 15-015, Kuparuk River field, Meltwater oil
12 pool amendment to area injection order 21A.
13 ConocoPhillips Alaska, Inc., has requested
14 modifications to the existing area injection order 21A
15 for the enhanced oil recovery operations in a letter
16 dated February -- I mean, April 14th, 2015. Also by
17 letter dated May 6, 2015 ConocoPhillips Alaska, Inc.,
18 requested administrative approval to extend the
19 expiration date contained in rule 11 of area injection
20 order AIO 21A, amended by six months. In accordance
21 with rule 10 of AIO 21A amended, the AOGCC granted
22 Conoco's request for administrative approval to extend
23 the expiration date contained in rule 11 of AIO 21A
24 amended by six months. AIO 21A amended was scheduled
25 to expire on May 16th, 2015 and in order not to
3
1 interrupt operations before the AOGCC could hold the
2 scheduled hearing today we issued an order on Conoco's
3 request extending the expiration date contained in rule
4 11 of AIO 21A amended. That administrative approval
5 was granted on May 6 of 2015.
6 Sorry for all that, but I felt like background
7 was necessary for the record.
8 AOGCC is now taking this opportunity to update
9 the order and rules to reflect current operating
10 practices as well as latest regulatory requirements and
11 conditions.
12 Computer Matrix will be recording today's
13 proceedings. Anyone interested can get a copy of the
14 transcript from Computer Matrix Reporting.
15 We'd like to remind those testifying to speak
16 into the microphone. We've updated our microphones so
17 you don't have to try to speak into two separate
18 microphones simultaneously, either one will suffice,
19 but speaking into either is necessary so that the court
20 reporter can capture your testimony and so that people
21 in the back of the room can hear what you're saying.
22 We'll also ask you as you speak to slides reference the
23 slides, in other words instead of saying as you can see
24 this is a map of blab, blah, blah, we need you to say
4
1 whatever. And the reason we need you to do that is
2 because we're creating a permanent record and in the
3 future, you know, 10 years from now the people who take
4 your jobs may be wanting to look back on this and they
5 need to be able to reference the attachment which will
6 be the slides. So in order for it to make sense to
7 people in the future, you know, we want to look as
8 unstupid as possible in the future.
9 All right. Let me see if there's -- who is
10 going to testify today. Is there anyone besides Conoco
11 planning to testify today. Well, it looks like only
12 people from Conoco have signed up to testify so we'll
13 have -- we'll start with Conoco, but at the end of the
14 hearing if there's anyone else in the audience who
15 becomes compelled to testify such as Frank Brown, we'll
16 pull them up or ask them up. And so the way we'll do
17 this is -- are all four of you planning to testify?
18 MR. NENAHLO: Yes.
19 CHAIR FOERSTER: So what I'll do is I'll swear
20 you all in together, but when I ask you the question
21 we'll get separate I dos from you. And then as you
22 testify I'd like you to introduce yourself, who you --
23 you know, who you represent, what your credentials are,
24 if you want to be recognized in an -- as an expert in a
25 particular area what that area is and what your
5
1 credentials for that are, then we will decide whether
2 to accept you as an expert or not.
3 So all four of you would you raise your right
4 hand.
5 (Oath administered)
6 MR. KANADY: I do.
7 MR. BRESSLER: I do.
8 MR. WENTZ: I do.
9 MR. NENAHLO: I do.
10 CHAIR FOERSTER: Great. All right. So whoever
11 wants to start, go for it. And in case -- it looked
12 like you were planning -- okay. Good. I was going to
13 ask, I'm peeking ahead, I'd really appreciate some
14 chronology to set a background for and we may have some
15 reporters in the room, we may have members of the
16 public who aren't as painfully familiar with Meltwater
17 as we are and I'd like to set a groundwork for
18 newcomers.
19 MR. NENAHLO: Absolutely. We have that
20 prepared on slide two.
21 CHAIR FOERSTER: Excellent. A plus.
22 MR. NENAHLO: Okay. All right. Slide one.
23 Good morning. My name is Thomas Nenahlo. I'm the
24 development engineer for the Meltwater field for
25 ConocoPhillips Alaska. I'm here today with my
G
1 colleagues to represent ConocoPhillips as the operator
2 of the Kuparuk River unit and the Meltwater oil pool.
3 Given the individuals who know the details of the
4 history of the Meltwater field and the initiatives that
5 have been undertaken are with me today to present the
6 information and address your questions. In addition to
7 myself we have Bob Wentz, our staff geologist for the
8 area and he is prepared to describe the Meltwater oil
9 pool geology; Eric Bressler is a staff geophysicist and
10 is prepared to speak to you on matters regarding the
11 geophysical description of the field, Randy Kanady, our
12 staff drilling engineer, is also with us this morning
13 to provide an overview of our well design and delivery
14 process. Also joining us this morning is Patrick
15 Wolfe, our North Slope development manager and Kazeem
16 Adeglola, our greater Kuparuk area development manager.
17 Before I begin I would like to provide the
18 Commission with my educational and professional
19 background and experience. I graduated with a
20 bachelor's of science in chemical engineering with a
21 minor in economics in June of 2008 from the Colorado
22 Schools of mines and am currently near completion of my
23 master's degree in petroleum engineering at the
24 University of Alaska at Fairbanks. I have worked for
25 ConocoPhillips Alaska for the past seven years.
K
1 Throughout this time I have worked in facilities,
2 production and reservoir engineering roles. I have
3 worked the Meltwater field from December, 2011 until
4 present. I would like to be recognized as an expert in
5 facilities production and reservoir engineering.
6 CHAIR FOERSTER: Commissioner Seamount, do you
7 have any questions?
8 COMMISSIONER SEAMOUNT: No questions and.....
9 CHAIR FOERSTER: Nor do I.
10 COMMISSIONER SEAMOUNT: .....no objections.
11 CHAIR FOERSTER: Nor I. And I have no
12 objections. We'll recognize you as an expert in.....
13 MR. NENAHLO: Facilities.....
14 CHAIR FOERSTER: .....facilities.....
15 MR. NENAHLO: .....production and reservoir
16 engineering.
17 CHAIR FOERSTER: Okay. Wow. A man for all
18 seasons.
19 MR. NENAHLO: Thank you.
20 THOMAS NENAHLO
21 previously sworn, called as a witness on behalf of
22 ConocoPhillips Alaska stated as follows on:
23 DIRECT EXAMINATION
24 MR. NENAHLO: For the chronologies slide two.
25 Today's hearing arises from ConocoPhillips' request
1 to.....
2 CHAIR FOERSTER: You want to switch to slide
3 two for the audience?
4 MR. NENAHLO: Right. Thank you.
5 CHAIR FOERSTER: Sorry. Multitasking.
6 MR. NENAHLO: Today's hearing arises from
7 ConocoPhillips' request to amend area injection order
8 21A. Prior to summarizing the amendment request I
9 would like to provide the Commission with a brief
10 summary of key events that have occurred to date with
11 respect to the Meltwater oil pool since the original
12 area injection order was issued in 2001. In August of
13 2001 the original area injection order 21 was issued,
14 five months later injection operations began. Shortly
15 thereafter an increase in the outer annulus pressures
16 of three wells was identified. Samples of the gas from
17 these outer annuli indicated the presence of miscible
18 injectant. An investigation was then initiated to
19 determine the source and migration mechanism for the
20 MI. Several hypotheses were proposed including a gas
21 lift casing thread leak, poor cement bonds on
22 injectors, tubing by inner annulus by outer annulus
23 leaks, producer fracture stimulation above the casing
24 cement job, poor cement job in the exploration,
25 delineation or plugged and abandoned wells, a pressure
E
1 induced fault or fissure opening close to an injector
2 or natural faulting. In January of 2003 organic
3 tracers were injected into injection wells, but as of
4 May, 2003 no tracer had been detected in our outer
5 annuli gas or producer gas streams. Mechanical
6 integrity tests were performed on the inner annuli of
7 all producers and they all passed. A full field model
8 history match completed in May of 2003 indicated no
9 significant out of zone injection.
10 ConocoPhillips reviewed the well completions
11 and found no significant well design issues. Case
12 (indiscernible) logging indicated competent cement
13 bonds on injectors. Neutron density logging indicated
14 no elevated gas saturations at shallow depths on
15 injectors. Pressure pulse testing suggests that no
16 communication between injectors and the outer annuli.
17 In addition pressure response was not identified in
18 surrounding outer annuli during annular disposal
19 operations. Static noise and temperature logging was
20 conducted on wells 2P-431 and 2P-451 that indicated
21 fluid movement behind the production casing to C37, C40
22 and C50 depths. Although movement was identified in
23 the C37 to C50 interval investigation was unable to
24 identify a vertical migration mechanism from the
25 Bermuda interval to the outer annuli of wells with an
10
1 MI signature.
2 From 2003 to 2011 ConocoPhillips managed the
3 elevated outer annulus pressures through a number of
4 initiatives. These included internal waivers that
5 allowed outer annulus operating pressures up to 1,800
6 psig for those wells that exceeded 1,000 psig, our
7 normal maximum allowable operating pressure. These
8 waivers were reviewed and renewed on a semi annual
9 basis and distributed to the AOGCC to inform the
10 Commission of the ongoing surveillance. Meltwater
11 wells were equipped with inner annulus and outer
12 annulus pressure transmitters to alert operations of
13 detectable abnormal conditions. Operator well
14 integrity awareness training was conducted, periodic
15 extended outer annulus bleeds were performed as
16 necessary and outer annulus bleeds were performed as
17 necessary and outer annulus fluid levels were taken
18 monthly as part of an ongoing effort to monitor the
19 pressure at the surface casing shoe. Periodic status
20 updates were also delivered to the ConocoPhillips
21 Alaska management and the AOGCC through the history of
22 the Meltwater field.
23 In 2012 the linear features that had been
24 previously identified within the Bermuda formation were
25 mapped vertically into the overburden. The 2012 40
11
1 seismic features up to the C37 interval identified a
2 potential pathway for injected MI to reach the outer
3 annuli. With this new information the AOGCC was
4 notified and containment initiatives were developed.
5 ConocoPhillips requested amendments to the area
6 injection order in October, 2012 and after hearing the
7 AOGCC issued the current area injection order, 21A. In
8 2014 and 2015 ConocoPhillips prepared and submitted
9 interim progress reports detailing the ongoing
10 containment initiatives.
11 On April 14th, 2015 ConocoPhillips as operator
12 and on behalf of the working interest owners submitted
13 a request to amend area injection order 21A. These
14 amendments arise from geologic, engineering and
15 production data analyses that indicate there has been
16 no further migration of injected fluids out of the
17 Meltwater oil pool and that well conversions and
18 sidetracks utilizing coiled tubing drilling technology
19 may further reduce the risk of potential migration of
20 injected fluids out of the Meltwater oil pool while
21 optimizing the ultimate hydrocarbon recovery from the
22 field.
23 Slide three. The requested amendments to area
24 injection order 21A are as follows. An amendment to
25 rule 2 to allow for new wells and for producer to
12
1 injector conversions in the Meltwater oil pool.
2 Modification to Rule 8 to allow for the use of produced
3 water and sea water for well and surveillance work
4 only. The modification of the monthly reporting
5 requirements set out in rule 9. ConocoPhillips
6 requests these become annual reporting requirements.
7 And finally ConocoPhillips has requested that the
8 expiration date set forth in the area injection order
9 in rule 11 be removed. After expert testimony is
10 provided I will provide -- I will review these proposed
11 modifications in more detail prior to completing our
12 presentation.
13 Slide four. The Meltwater team and I will
14 begin this presentation with an overview of the
15 Meltwater field. We will the move into a summary of
16 the containment initiatives that have been pursued at
17 the field over the previous three years. Following
18 this we will discuss our development objectives at
19 Meltwater and how they pertain to containment and the
20 optimization of ultimate hydrocarbon recovery. We will
21 then conclude today's presentation with a summary of
22 our requested amendments to AIO 21A in our closing
23 remarks.
24 We do have quite a bit of material to cover
25 this morning so unless you have any questions for me at
13
1 this time I'll go ahead and begin.
2 CHAIR FOERSTER: Commissioner Seamount, do you
3 have any questions?
4 COMMISSIONER SEAMOUNT: I'll have some later,
5 not right now.
6 CHAIR FOERSTER: We'll probably both hold our
7 questions until we -- until you guys finish and we'll
8 take a recess and.....
9 MR. NENAHLO: Okay. That sounds good.
10 CHAIR FOERSTER: .....but that doesn't mean
11 that something won't pop up that we need to interrupt
12 and ask just for clarity in the moment. So it's not a
13 promise not to ask questions.....
14 COMMISSIONER SEAMOUNT: Okay.
15 CHAIR FOERSTER: .....it's just a hope.
16 COMMISSIONER SEAMOUNT: Okay. I just made you
17 a liar, I do have one question.
18 CHAIR FOERSTER: Okay.
19 MR. NENAHLO: Sure.
20 COMMISSIONER SEAMOUNT: How much work is
21 involved in these reports, you know, you want to change
22 from monthly to annual, is it because it's a lot of
23 work?
24 MR. NENAHLO: It requires, you know, about a
25 half day of work to complete that report. What we --
14
1 when we provide the report we provide two month data
2 increments, the month that we're reporting for and then
3 the previous month to help establish trends for those
4 that are looking at the report. In annual report we
5 will be providing the same data, but we'll be looking
6 at 12 month trend. So the information will be the
7 same, just over a longer trend. And so in capturing
8 some of the activities on the field establishing a
9 longer trend we think would be beneficial to both us
10 and the Commission.
11 CHAIR FOERSTER: So I'm assuming that going
12 from monthly which is half a day to annual which would
13 be 12 months, you know, it's not going to require six
14 days of work?
15 MR. NENAHLO: Correct. It would require.....
16 CHAIR FOERSTER: Okay.
17 MR. NENAHLO: .....less.
18 CHAIR FOERSTER: Okay. All right. Any other
19 questions?
20 COMMISSIONER SEAMOUNT: No.
21 CHAIR FOERSTER: Okay. Proceed, please.
22 MR. NENAHLO: Slide five. So it has been some
23 time since we have discussed the particulars of the
24 Meltwater field and so we would like to begin with an
25 overview of the Meltwater field operations and surface
15
1 facilities.
2 Slide six. The operator of the Meltwater
3 development is ConocoPhillips Alaska, the surface owner
4 is the state of Alaska and the working interest owners
5 are ConocoPhillips Alaska, BP Exploration, Chevron USA
6 and ExxonMobil Alaska.
7 Slide seven. This slide shows the bottom hole
8 location and services of wells that have been drilled
9 within the Meltwater field. The blue outline indicates
10 the Meltwater participating area, the green circles
11 indicates wells in production service, the blue
12 triangles are those in injection service and the red
13 stars indicate wells that have been plugged and
14 abandoned. All wells are drilled from a single drill
15 site, 2P, the location of which is indicated by the
16 brown rectangle in the northwest corner of the
17 participating area.
18 CHAIR FOERSTER: What do the yellow circles
19 represent?
20 MR. NENAHLO: The yellow circles are the
21 exploration delineation wells. So the Meltwater North
22 2 well was the discovery well drilled in 2000, the
23 delineation wells, Meltwater North 2A and North 1 were
24 drilled later that year. So you have those three wells
25 I just mentioned there in the yellow circle.
1 CHAIR FOERSTER: And what's the status of those
2 three wells?
3 MR. NENAHLO: They are plugged and abandoned.
4 CHAIR FOERSTER: Okay. Thank you.
5 MR. NENAHLO: Development drilling began in
6 2011, currently there are 13 producers and 6 injectors.
7 Slide eight. Meltwater is a single gravel pad,
8 2P, that can be accessed by gravel road. Four bridges
9 were constructed to access the development.
10 Meltwater's wells, manifold system and testing
11 facilities are located on this gravel pad. Power is
12 supplied to Meltwater through an overhead powerline.
13 Meltwater's production flows into a 24 inch production
14 flowline and co -mingles with Tarn and Kuparuk
15 production before arriving at the central processing
16 facility, CPF 2 at which point the production is
17 processed into sales quality crude. Historically water
18 that was used for injection and artificial lift was
19 supplied to Meltwater in a 12 inch pipe line, however
20 in October of 2009 the Meltwater water injection line
21 was proactively removed from service due to internal
22 corrosion. At this point in time Meltwater's converted
23 to MI injection and MI lift only. By making this
24 conversion improved oil production rate and sweep
25 efficiency were realized. In July of 2014 the
17
1 importation of Prudhoe Bay NGLs into the Kuparuk River
2 unit were discontinued and the Meltwater field was then
3 converted to lean gas injection and lean gas lift only
4 service.
5 CHAIR FOERSTER: Before you leave this slide
6 just for orientation for the public, although it's kind
7 of a separate field, it's operated as just an extension
8 of the Kuparuk field, there are no living quarters,
9 there's no production facilities on site, it's just --
10 it's just three production pads, correct?
11 MR. NENAHLO: It's just a single production
12 pad, 2P.
13 CHAIR FOERSTER: Single production pad,
14 the.....
15 MR. NENAHLO: Yes.
16 CHAIR FOERSTER: Okay.
17 MR. NENAHLO: The rest of that is correct.
18 CHAIR FOERSTER: Okay. Thank you.
19 MR. NENAHLO: Uh-huh. Slide nine. Meltwater
20 drill site 2P facilities were constructed using a trunk
21 and lateral design in which the wells tie into a
22 manifold system that extends east west across the south
23 side of the pad. Twenty foot wellhead spacing was used
24 as well as a conventional separator for well testing.
25 Remote capabilities include well test actuation,
IV
1 control of well chokes and actuation of surface safety
2 valves. An emergency shutdown skid is part of the
3 safety and environmental protection at Meltwater. An
4 electrical control room is located on the east end of
5 the pad adjacent to the test facilities.
6 CHAIR FOERSTER: How often are people on this
7 pad?
8 MR. NENAHLO: Typically daily, however we do
9 encounter days' conditions especially during the
10 wintertime which may prevent people to get onto the
11 pad. And that's one of the reasons that we put in
12 place, you know, the remote well test actuation,
13 control of the well chokes and emergency shutdown skid.
14 CHAIR FOERSTER: Some of the questions I'm
15 asking may sound really stupid.....
16 MR. NENAHLO: Oh, no, it's.....
17 CHAIR FOERSTER: .....and some of them are
18 stupid, but some of them are more just to orient the
19 audience.
20 MR. NENAHLO: No, no problem. Ask away.
21 CHAIR FOERSTER: And I won't identify which is
22 which.
23 COMMISSIONER SEAMOUNT: We'll be able to figure
24 it out.
25 CHAIR FOERSTER: Okay.
19
•
•
1 MR. NENAHLO: All right. Slide 10. The
2 reservoir management strategy for the Meltwater field
3 was adopted in 2012 in an effort to ensure containment
4 while optimizing ultimate hydrocarbon recovery. To
5 achieve these objectives a sand based injection
6 pressure limit of 3,400 psig was set. This pressure
7 limit is predicated upon the formation integrity test
8 data from production casing that was set near the top
9 of the Bermuda interval. The chart depicts the
10 formation integrity and leak off test data for the
11 Meltwater field. The three bars in red on the left are
12 the production casing formation integrity tests that
13 the sand face injection pressure limit is predicated
14 upon. In all three cases after the casing was set the
15 wells were drilled out to perform the FITS and drilled
16 into the upper part of the Bermuda interval. The red
17 line that crosses through the production casing data on
18 the left represents the sand face injection pressure
19 limit at the depth of the Bermuda interval in relation
20 to the FIT data. The blue bar, fourth from the left,
21 is the intermediate casing set at 4,696 feet measured
22 depth in 2P-441. The leak off test for this casing
23 point is 16 pounds per gallon. The remaining bars on
24 the graph in green are surface LOT or FIT data for the
25 development and exploration wells in the Meltwater
20
1 area.
2 CHAIR FOERSTER: LOT is leak off test, FIT is
3 formation integrity test?
4 MR. NENAHLO: That's correct.
5 CHAIR FOERSTER: Just for the record.
6 MR. NENAHLO: Thanks. The range for the LOT
7 and FIT tests are 14.6 to 18.1 pound per gallon for the
8 surface casing indicating a good strength throughout
9 this section.
10 Unless there are any further questions from the
11 Commission pertaining to Meltwater surface facilities
12 operations I'll pass the presentation over to Mr. Wentz
13 who'll be providing an overview of the geology at
14 Meltwater.
15 CHAIR FOERSTER: Commissioner Seamount, do you
16 have any questions at this time?
17 COMMISSIONER SEAMOUNT: The only one I have is
18 -- the only one I have is a question as to why you
19 placed the pad where you did when you drilled
20 exploration wells all over the area, I mean, why didn't
21 you put it in the middle?
22 MR. NENAHLO: I do not know the answer to that
23 question. I can get back with you guys.
24 COMMISSIONER SEAMOUNT: I assume it had
25 something to do with environment or topography or
21
1 something.
2 MR. NENAHLO: That would be my assumption as
3 well, I'm not sure about lakes in the area, but.....
4 CHAIR FOERSTER: So it's highly likely that one
5 or both of us will ask random questions that you don't
6 know the answer to. Rather than feeling compelled to
7 come up with an answer right now, write down -- have
8 somebody in your group write down the questions that
9 you don't have an answer to and we'll leave the record
10 open for whatever we determine is an appropriate amount
11 of time for you to get us answers to those questions.
12 So take the pressure off.
13 MR. NENAHLO: Okay. Thank you.
14 CHAIR FOERSTER: Okay. Any other question?
15 COMMISSIONER SEAMOUNT: No.
16 CHAIR FOERSTER: All right. Thank you for your
17 testimony and thank you for the thorough overview and
18 thank you for identifying each slide before you talked
19 about it.
20 All right. Whoever's next.
21 MR. WENTZ: Slide 11.
22 CHAIR FOERSTER: Before you start we need your
23 name, who you represent, what your expertise is, do you
24 want to be recognized as an expert, what your
25 credentials are and then you can carry forward.
22
1 MR. WENTZ: My name is Robert Wentz
2 (indiscernible - away from microphone).....
3 CHAIR FOERSTER: Oh, wait. Turn the mic on.
4 The mic has to be on before -- okay. Thank you. Start
5 over again, please.
6 MR. WENTZ: Okay. My name is Robert Wentz, I
7 graduated with a bachelor's degree in geological
8 sciences in May of 1977 from Susquehanna University in
9 Pennsylvania. I've worked for ConocoPhillips primarily
10 as a development geologist for the past 35 years.
11 Throughout this time I've had numerous assignments both
12 domestically and internationally. Currently I'm the
13 staff geologist assigned to the Meltwater field, an
14 assignment which has been ongoing for the past two
15 years. I will be presented an overview of the
16 Meltwater field geology. I would like to be recognized
17 as an expert in geology.
18 CHAIR FOERSTER: Commissioner Seamount, do you
19 have any questions of this witness?
20 COMMISSIONER SEAMOUNT: No questions, no
21 objections.
22 CHAIR FOERSTER: All right. I have no
23 questions and I no objections either so please proceed,
24 Mr. Wentz.
25 MR. WENTZ: Thank you.
23
1 ROBERT WENTZ
2 previously sworn, called as a witness on behalf of
3 ConocoPhillips, stated as follows on:
4 DIRECT EXAMINATION
5 MR. WENTZ: Slide 12. The image on the left
6 side of this slide is a map showing the location of the
7 Meltwater field in relation to the nearby Kuparuk River
8 and Tarn fields. The Meltwater field is located
9 approximately eight miles to the southwest of the
10 Kuparuk field. The stratigraphic column at the right
11 of the slide which is representative of the central
12 North Slope depicts the Meltwater field which is
13 located within the Brookian sequence, Torok formation
14 locally known as the Bermuda sandstone. It is
15 interpreted that the Bermuda sandstones were deposited
16 as deep water, channelized, turbidite lobes.
17 Slide 13. This slide illustrates a structural
18 cross section which traverses the field from the
19 northwest to the southeast as depicted on the map to
20 the lower left by the cross section line A to A prime.
21 The cross section depicts the reservoir characteristics
22 of the gross Bermuda reservoir interval which is
23 highlighted in yellow shading. Four wells are
24 identified across the top, the 2P-434, 417, 422A and
25 422. The text boxes at the bottom of each of the first
24
1 three wells depict the key average reservoir properties
2 of each well. The 2P-422 well to the right is
3 interpreted to have possibly intersected the field
4 oil/water contact. Though the gross Bermuda reservoir
5 interval is generally continuous across the Meltwater
6 field the internal stratigraphy is quite complex as
7 individual sand units are difficult to correlate
8 between wells. This continuous nature is illustrated
9 by the changes in the gamma ray curve, the brown,
10 between each well as well as the green pay flags and
11 the permeability curves in pink calculated from
12 petrophysical analysis. The 2P-417 well exhibits the
13 best overall reservoir quality particularly in the
14 upper portion of the Bermuda as illustrated by the
15 permeability curve. The 422A well exhibits better
16 reservoir quality at the base of the gross interval.
17 Additional insight into the discontinuous or
18 compartmentalized nature of the Bermuda will be
19 discussed in the geophysics overview.
20 Unless there are any questions from the
21 Commission at this time I will hand over the
22 presentation to Eric Bressler who will be providing the
23 geophysical overview of the Meltwater field.
24 CHAIR FOERSTER: Commissioner Seamount, do you
25 have any questions at this time?
25
1 COMMISSIONER SEAMOUNT: No, I -- no, I don't.
2 CHAIR FOERSTER: Save them for the.....
3 COMMISSIONER SEAMOUNT: Save them up for the
4 geophysicist.
5 CHAIR FOERSTER: All right. Mr. Bressler,
6 please proceed and again start with who you are and all
7 that good stuff.
8 MR. BRESSLER: My name's Eric Bressler. I
9 graduated with a degree -- a bachelor's degree in
10 geology with minors in math and physics from Olivet
11 Nazarene University in 1998. I earned a master's
12 degree in geophysics from Wright State University in
13 2001. I've worked for ConocoPhillips or its
14 predecessors as a geophysicist for the last 15 years.
15 I joined our Alaska Business Unit three and a half
16 years ago and have worked Meltwater since that time. I
17 would like to be recognized as an expert in geophysics.
18 CHAIR FOERSTER: Thank you. Commissioner
19 Seamount, do you have any questions?
20 COMMISSIONER SEAMOUNT: No questions, no
21 objections.
22 CHAIR FOERSTER: I have no questions, I have no
23 objections. We recognize you as an expert so please
24 proceed.
25 ERIC BRESSLER
26
1 previously sworn, called as a witness on behalf of
2 ConocoPhillips, stated as follows on:
3 DIRECT EXAMINATION
4 MR. BRESSLER: So slide 14 up here. Much of
5 the material -- before I get going here much of the
6 material that I'm presenting here today was presented
7 in the non -confidential section of the hearing held in
8 November of 2012 and has been updated to reflect our
9 current understanding. We do not intend to present any
10 confidential information at today's hearing.
11 CHAIR FOERSTER: That's very good news.
12 MR. BRESSLER: So slide 15. This is a depth
13 structure map of the C35 surface which is just below or
14 is in some areas the base of the Bermuda sands in
15 Meltwater field. The depth range in this range is from
16 on west in the bright, hot colors about 4,300 feet
17 below sealevel. On the east side we reach down to
18 5,888 field below sealevel. All of the Meltwater wells
19 are shown on the map and green dashes on the wellbore
20 are the C35 penetrations in these wells. The solid
21 green outline is the participating area boundary. The
22 shelf edge is approximately where the green changes to
23 blue on the map, the arrows depict the location of
24 canyons interpreted on the shelf and upper slope where
25 erosion has occurred. Immediately down dip from these
27
1 erosional canyons we see the up dip extent of the
2 Bermuda sands which were fed from these channels. The
3 white dashed polygon outlines the Bermuda sands in the
4 field. Note that the area as a whole is lower, deeper
5 in the area of the Meltwater sands and this is where
6 the sands were deposited in a local depression on the
7 C35 surface. There are faults that have been mapped
8 west of the participating area through the C35 -- at
9 the C35 interval, but we do not image and interpret
10 faults within the Bermuda reservoir.
it Slide 16, Bermuda stratigraphic complexity.
12 This slide illustrates the interpreted stratigraphic
13 complexity within the gross Bermuda reservoir interval
14 in the Meltwater field. The map is an interpretation
15 of the isolated channel levy system compartments or
16 lobes within the reservoir. The pay sands are
17 contained within the lobes and are characterized by
18 poor connectivity between individual sand bodies. The
19 isolation is a result of the chaotic nature of deep
20 water turbidite deposits. The deviated well
21 trajectories are depicted as gray lines and overlie the
22 lobe bound -- overlie the lobes. The map was primarily
23 based upon 3D seismic data and production performance
24 data. An analysis of the 4D seismic data was completed
25 at the Bermuda interval. This analysis identified
%:
1 linear features at the reservoir level that align with
2 the asmath (ph) of the maximum principal stress. These
3 linear features are a time shift between the 1998 and
4 the 2008 seismic shoots and are indicative of a change
5 in gas saturation and/or pressure. The linear features
6 are depicted in this illustration as dashed black lines
7 trending north/northwest, south/southeast.
8 Slide 17, Meltwater field geoseismic section.
9 This slides depicts an interpreted geoseismic section
10 of the gross Bermuda interval. The traverse of the
11 cross section is shown by the red line from A to A
12 prime. These lobes have been interpreted from the 3D
13 seismic character and are consistent with the geologic
14 and production data for the field. The geoseismic
15 section illustrates the individual lobes within the
16 gross Bermuda reservoir interval. The gross Bermuda
17 reservoir interval is depicted as -- with the dashed
18 blue line. Production data from the field indicates
19 poor connectivity between the individual sand lobes
20 shown in yellow in that gross interval.
21 And unless there are any further questions -- any
22 questions from the Commission at this time I will hand
23 the presentation back to Tommy Nenahlo who'll be
24 providing a review of the containment initiatives that
25 were undertaken at Meltwater.
29
1 CHAIR FOERSTER: Commissioner Seamount, do you
2 have any questions at this time?
3 COMMISSIONER SEAMOUNT: How abruptly do these
4 sandstones pinch out, looks like they're -- looks like
5 it's pretty abrupt, right?
6 MR. WENTZ: Yes, seismically it's -- they're
7 fairly distinct boundaries.
8 COMMISSIONER SEAMOUNT: Okay. This is
9 outstanding displays I might add.
10 CHAIR FOERSTER: You just did. Any other
11 questions?
12 COMMISSIONER SEAMOUNT: No other questions.
13 CHAIR FOERSTER: I don't have any questions at
14 this time, but we will have questions later.
15 MR. NENAHLO: Slide 19. As discussed in the
16 introduction ConocoPhillips Alaska would like to
17 provide you with details on the Meltwater containment
18 initiatives that we have undertaken since 2012.
19 ConocoPhillips Alaska has implemented two primary
20 initiatives to ensure containment and is pursuing
21 (indiscernible). The first initiative undertaken to
22 mitigate the large pressure differential between
23 injectors and producers was to implement a sand face
24 injection pressure limit. To determine the
25 effectiveness of the strategy ConocoPhillips Alaska
30
1 developed a significant number of surveillance and
2 monitoring programs. These programs yielded valuable
3 data to which a large technical and professional
4 resource has been applied to evaluate the information.
5 Based upon evaluation of these data there's no
6 indication of further migration of injected fluids out
7 of the Bermuda interval. As average reservoir
8 pressures declined outer annulus pressures have
9 declined, the composition of the outer annuli gas has
10 become less similar to MI. Isotopic analyses have
11 indicated the outer annuli gas becoming more similar to
12 biogenic gas which is native to the Meltwater
13 overburden. And oxygen activation logging has
14 determined that injected fluids are not bypassing the
15 production casing cement of the injected wells at
16 Meltwater. All six injectors have been logged to date.
17 Surveillance and monitoring programs will continue to
18 ensure safe operations and containment of injected
19 fluids within the Bermuda interval.
20 The second initiative undertaken was a
21 reservoir containment assurance project designed to
22 ensure the containment of injected fluids within the
23 Meltwater oil pool. This initiative resulted in the
24 creation and evaluation of a subsurface containment
25 matrix that enabled the qualitative assessment of the
31
1 five key elements of containment. In addition
2 ConocoPhillips developed and implemented a wells fit
3 for service program called WellTrak to ensure
4 compliance of the wells within operating and
5 administrative guidelines.
6 The third initiative is in a planning stage and
7 would be designed to place injectors and producers
8 within the same reservoir body or lobe through the use
9 of coiled tubing drilling sidetracks and well
10 conversions. This will reduce the effect of the
11 aforementioned stratigraphic discontinuities between
12 individual lobes have on the differential pressure
13 between injectors and producers. This initiative is
14 designed to mitigate further migration of injected
15 fluids out of zone as well as provide for improved
16 reservoir connectivity and ultimate hydrocarbon
17 recovery.
18 The following slides will detail the specific
19 elements of the initiatives that have been implemented
20 thus far at Meltwater.
21 Slide 20. To ensure the safe operations and
22 the integrity of the wells at Meltwater ConocoPhillips
23 has completed the following. Continuous pressure
24 monitoring capabilities are available on the outer
25 annuli of each Meltwater well. In addition near
32
1 surface casing corrosion is a known problem across the
2 greater Kuparuk area. Mitigation of the process with
3 an annular dielectric sealant has shown effectiveness
4 by reduction in corrosion rates. All Meltwater wells
5 were treated with the sealant in 2006. An
6 investigation in 2013 to determine the extent of
7 surface casing corrosion at Meltwater determined that
8 the wells are effectively protected from corrosion by
9 sealant and the corrosion rate on the surface casing is
10 very low. Furthermore operator awareness training is a
11 large component of ensuring risks to personnel and
12 equipment are mitigated. The primary components of
13 this training are one, skills now computer based
14 training on a three year frequency and two, classroom
15 training with a well integrity engineer instructor on
16 an annual basis.
17 Slide 21. As previously discussed in August of
18 2012 the well had injection pressure limit of 3,400 psi
19 at the sand face was put in place at Meltwater. This
20 reservoir management strategy was designed to reduce
21 the pressure in the Bermuda formation to a pressure at
22 or below 3,400 psi to ensure confinement of injected
23 fluids. A number of management and monitoring
24 initiatives are ongoing. These include wellhead
25 injection pressure monitoring and alarm set points,
33
1 Bermuda formation pressure surveillance and injection
2 withdraw monitoring. The chart shown in this slide
3 shows the formation pressures over the life of the
4 Meltwater field with the date of the survey on the X
5 axis and pressure and psi on the Y axis. The green
6 circles are producers while the red triangles are
7 injectors. The black bar in 2012 illustrates the time
8 at which the sand face injection pressure limit was
9 set. As shown formation pressures continue to decline
10 with the current reservoir management strategy. After
11 converting to miscible injectant only in 2009 and
12 subsequently to lean gas injection only in 2014
13 injector and producer formation pressures are
14 converging with the exception being the western portion
15 of the field where producer formation pressures have
16 been falling. I'll provide more in depth analysis on
17 the western section later in the presentation.
18 The injectors that had historically supported
19 these producers were shut-in during the spring of 2012
20 due to formation pressures above the sand face pressure
21 limit. In the fall of 2014 these injectors were
22 successfully returned to service after the formation
23 pressures had decreased below the limit. As of
24 February, 2015 all injectors had been successfully
25 returned to service at Meltwater and are capable of
34
1 operating below the current sand face injection
2 pressure limit.
3 Slide 22. The surface casing by production
4 casing annuli commonly referred to as the outer annuli
5 are utilized extensively to monitor for potential
6 communication between the Bermuda formation and
7 shallower intervals. With the exception of wells 2P-
8 406 and 2P-447 which have cemented outer annuli the
9 outer annuli of all Meltwater wells have an open shoe
10 to the formation. This allows the monitoring of the
11 pressure and gas composition of the overburden between
12 the Bermuda and the C80 interval where the surface
13 casings are set. The diagram shown are the well
14 trajectories for Meltwater with the surface pad
15 location shown as the blue rectangle. A number of
16 ongoing surveillance initiatives are in place to
17 monitor the outer annuli and will be discussed in the
18 following slides.
19 Slide 23. Outer annulus surveillance
20 initiatives are designed to monitor the gas
21 composition, static pressure and pressure build up of
22 the formation at the C80 interval. The chart depicts
23 the average outer annulus pressure at Meltwater.
24 Pressures have exhibited an overall significant decline
25 since 2005. In 2012 following the setting of the sand
35
1 face injection pressure limit three of the six
2 injectors at Meltwater were shut-in as they were unable
3 to inject at a pressure below this limit. The
4 reservoir pressure has since decreased and these three
5 injectors were able to be returned to service in the
6 2013 to 2014 time frame. As noted on the chart the
7 recent increase in the average outer annulus pressure
8 can be attributed to thermal effects from these three
9 injectors being returned to service.
10 Slide 24. Prior to the conversion to lean gas
11 injection after NGL imports from Prudhoe Bay to the
12 Kuparuk River unit were discontinued samples of gas
13 from the outer annuli of Meltwater wells were taken on
14 a semi annual basis. The chart shows the analysis
15 technique for the samples collected for an example well
16 injector 2P-429. The blue bars on the left is the Mol
17 percentage for each component for miscible injectant.
18 The teal bars for each component that have a zero value
19 are the Mol percentages for each of the components over
20 the C4 to C7 range for biogenic gas. Essentially
21 biogenic gas does not have any Mol percent of C4 to C7.
22 The values in between are the individual samples that
23 have been taken specific to well 2P-429. As can be
24 seen the outer annulus gas samples have been taken
25 specifically to well 2P-429 -- I'm sorry. As can be
36
0
0
1 seen the outer annulus gas composition since 2012 has
2 never indicated a presence of miscible injectant.
3 These composition analyses demonstrate the
4 effectiveness of the sand face injection pressure limit
5 as it has shown no indication of further migration of
6 injected fluids out of the Bermuda interval. At this
7 time no Meltwater well with compositional analyses
8 completed has shown an increasing similarity to
9 miscible injectant since 2012 when these analyses
10 began. In an effort to confirm the results of the
11 compositional analyses of the outer annuli gas isotopic
12 analyzes were performed. Miscible injectant contains
13 Prudhoe Bay NGLs that are isotopically more positive
14 and thus distinguishable from other gases in the
15 Meltwater oil pool. In 2002 and 2005 isotopic analyses
16 were performed that indicated the outer annulus gas of
17 a number of wells was very similar to MI. In 2012 a
18 systematic analysis of outer annulus gasses showed less
19 miscible injectant and more biogenic gas than in 2002
20 and 2005. These isotopic analyses support the
21 conclusions from the compositional analyses. There's
22 no indication of further migration of injected fluids
23 out of the Bermuda interval.
24 Slide 25. Oxygen activation logging technology
25 is keeping of identifying fluid movement around the
37
0
1-1
1 production casing cement shoe by identifying the
2 presence of oxygen when injecting water. Sea water was
3 used to provide the oxygen in the injected fluid. The
4 schematic on the lower left shows the flow scenario for
5 the oxygen activation logging test tool. The tool
6 works by injecting water past the neutron generator
7 where the oxygen atom within the water molecules is
8 activated then the detection of water flow behind the
9 casing string is possible by measuring gamma rays
10 originating from the activated oxygen. As defined in
11 AIO 21A.004 and .005, to obtain the most information
12 from the logging campaign an attempt was made to step
13 up the sand face injection pressure in 250 psi
14 increments from 2,975 psi to 4,475 psi while performing
15 oxygen activation logging runs. These logging runs
16 were designed to one, confirm there's no fluid movement
17 around the production casing shoe when injecting within
18 the current sand face injection pressure limit and two,
19 to determine if the migration of miscible injectant was
20 possibly a result of historic sand face injection
21 pressures prior to the issuance of AIO 21A.
22 The chart in the lower right summarizes the
23 logging program. On the X axis is the injection rate
24 of water while the Y axis is the sand face injection
25 pressure psi. The red bar indicates the current sand
0
1 face injection pressure limit. The data points for
2 each well indicate the range of rate and pressure that
3 was able to be applied during the logging runs. All
4 injectors have been successfully logged, no leakage of
5 injected fluids above the Bermuda interval was
6 identified over the range of pressure supplies.
7 Slide 26. For AIO 21A.002 ConocoPhillips
8 Alaska completed construction of the facilities
9 necessary to perform an extended bleed on the outer
10 annulus of 2P-431. This effort was designed to
it determine if the source providing pressure to the outer
12 annulus is trapped and if it can be depressured. Outer
13 annulus gas -- I'm sorry. The outer annulus began
14 being bled back to production on March 7th, 2015. The
15 chart on this slide details the duration during which
16 2P-431 outer annulus has been bled back. The maroon
17 line represents the OA gas bleed rate and has shown a
18 steady decline in rate since the bleed began. The
19 green light represents the cumulative gas production.
20 As of July 6th, 2015 the cumulative 19.5 million
21 standard cubic feet of gas has been bled to production
22 at an average rate of 112 standard cubic feet per
23 minute. The red line is the outer annulus pressure.
24 On June 18th the central processing facility was
25 shutdown for planned maintenance work. After returning
39
0
1 the well to service and opening the bleed line the
2 outer annuluses only flowed intermittently potentially
3 indicating that the source that had historically
4 charged the outer annulus was being depressured. It is
5 anticipated that a period of six to eight months will
6 be required to substantially reduce the pressure of
7 this source as the flow rate is relatively small and
8 the source is unable to support sustained flow in the
9 current surface operating pressures.
10 This concludes our review of the containment
11 initiatives. As previously mentioned based upon
12 evaluation of the data that has been collected and
13 evaluated to date there is no indication that further
14 migration of injected fluids out of the Bermuda
15 interval.
16 Unless there are any questions from the
17 Commission at this point in time I'll hand over the
18 presentation to Mr. Wentz to discuss the Meltwater
19 overburden characterization study.
20 CHAIR FOERSTER: Commissioner Seamount, do you
21 have any questions at this time?
22 COMMISSIONER SEAMOUNT: I've got one stupid
23 question.....
24 CHAIR FOERSTER: Go for it.
25 COMMISSIONER SEAMOUNT: .....that you were
40
1 referring to in the beginning. You get these gas
2 samples for analysis off the bleeds?
3 MR. NENAHLO: There's a -- where is the exact
4 physical location.....
5 COMMISSIONER SEAMOUNT: Yeah.
6 MR. NENAHLO: .....is that the question? So
7 there's a port on the outer annulus where you can
8 acquire a gas sample.....
9 COMMISSIONER SEAMOUNT: Okay.
10 MR. NENAHLO: .....for each individual well.
it COMMISSIONER SEAMOUNT: And how much biogenic
12 gas is produced would you say, is -- do you have any
13 way to figure that out?
14 MR. NENAHLO: Well, that's -- it's on a well by
15 well basis and exactly quantifying how much of it is
16 biogenic versus how much of it is non-biogenic is
17 difficult to determine. When we evaluate the
18 composition of the gas what we're simply looking for is
19 the -- if there is presence of those NGL components
20 that we know are not native to the overburden.
21 COMMISSIONER SEAMOUNT: Do you have any idea
22 where the biogenic gas is coming from, is it the entire
23 section or a discrete interval or, I mean, what do the
24 mud logs say?
25 CHAIR FOERSTER: Is that going to be addressed
41
1 later in the presentation?
2 MR. NENAHLO: Yeah, I don't have the specific
3 answer to that at -- that question at this time, but we
4 can get that for you.
5 CHAIR FOERSTER: Okay. So that'll get written
6 down as the second question to be followed up with.
7 Okay. I don't have.....
8 COMMISSIONER SEAMOUNT: That's it.
9 CHAIR FOERSTER: .....I don't have any
10 questions at this time. I'm debating whether we should
11 take recess and ask questions or just solider on to the
12 end. I'm leaning towards soldiering on. What do you
13 think?
14 COMMISSIONER SEAMOUNT: I agree.
15 CHAIR FOERSTER: Okay. Please continue. And
16 identify yourself again before you start talking. You
17 don't need to give the whole speel, just your name.
18 MR. WENTZ: Slide 27. For the record this is
19 Robert Wentz and I'll be presenting the overburden
20 characterization study.
21 CHAIR FOERSTER: Thank you.
22 MR. WENTZ: Slide 28. An integrated overburden
23 characterization study was initiated by ConocoPhillips
24 Alaska in late 2012 and completed in January, 2015.
25 ConocoPhillips Alaska provided the AOGCC with an
42
1 interim report in 2014 and a final report in April,
2 2015. Primary goal of the study was to better
3 understand the containment system and explain the
4 process of fluid migration into the overburden which
5 occurred in the Meltwater field throughout an
6 integration of geological, petrophysical and
7 geomechanical descriptions and modeling of the
8 overburden. In addition a better understanding of the
9 observed north/northwest, south/southeast trending
10 linear features observed in the 4D seismic was desired.
11 The studies were largely performed by several Houston
12 technology groups and the Meltwater technical team. A
13 total of six different initiatives were pursued, one, a
14 static description of the overburden; two, critical
15 stress modeling; three, mechanistic overburden
16 modeling; four, a completions analysis; five,
17 geomechanical modeling; and six, seismic modeling. The
18 results and information that I will present are fully
19 represented in the Meltwater annual report submitted in
20 April. I will now provide the Commission with a
21 summary of the overall results in each of the
22 initiatives.
23 Slide 29. Numerous technologies were applied
24 and an exhaustive attempt was made to understand the
25 containment system and explain the processes of fluid
43
1 propagation into the overburden, however the overall
2 results of the overburden characterization study were
3 greatly hampered by data constraints on key parameters
4 necessary to accurately describe the overburden. As
5 the modeling inputs contained large uncertainties
6 interpretation of the results were unable to provide an
7 additional insight into the processes and actual
8 propagation mechanism. Although the results were
9 quantitatively inconclusive we were able to
10 qualitatively infer conclusions that aligned with our
it understanding of field operations. It is important to
12 note that overall the modeling supported the
13 interpretation that the initial migration of injected
14 fluids out of the Bermuda interval was a result of a
15 larger pressure differential between injectors and
16 producers. This pressure differential was exacerbated
17 by the stratigraphic discontinuities within the Bermuda
18 interval.
19 I will now address each of the key initiatives
20 of the study.
21 Slide 30. The first initiative was a static
22 description of the overburden. The Meltwater field is
23 located on the central North Slope which has exhibited
24 a complex tectonic history. Several tectonic events
25 have produced multiple generations of faults and
1 fractures as evidenced on the chart to the lower right.
2 This chart represents a generalized geologic column of
3 the central North Slope with tectonic sequences,
4 stratigraphic units and major fault fracture events,
5 the solid arrows indicating the direction of maximum
6 horizontal stress. Some of these predate the Meltwater
7 reservoir and overburden, but still influence younger
8 episodes. The younger events pertain most directly to
9 the Meltwater reservoir and overburden. Multiple fault
10 sets and different stratigraphic intervals can be
11 interpreted using 3D seismic data. Below the lower
12 Cretaceous unconformity represented by LCU, Jurassic-
13 Cretaceous west, northwest striking normal faults are
14 present below the Bermuda reservoir interval. Early
15 Tertiary north/northwest striking faults are
16 interpreted in the overburden, exhibiting similar
17 strike to the observed 4D seismic lineaments. In an
18 attempt to better understand the faulting at Meltwater
19 field an automatic fault extraction process was
20 performed on the 3D seismic data on a fault enhanced
21 volume, FEV, in an attempt to identify potential fault
22 characteristics in the overburden. The automated
23 extraction process is a new ConocoPhillips technology
24 which may provide automated seismic detection for
25 potential faults by identifying seismic signal
45
•
1 disruptions. This interpreted technology is based upon
2 user specified thresholds. Due to the relatively poor
3 data quality available within the overburden the effort
4 yielded results that were inconclusive.
5 Slide 31. The modeling of critical stress can
6 provide an indicator of the potential for the slip
7 reactivation on existing faults and fracture. Faults
8 at or near critical stress may be more likely to
9 contribute to fluid flow. The modeling can also aid in
10 the identification of individual faults or fault
11 segments as well as fault sets and trends most prone to
12 being critically stressed. Critical stress models can
13 also offer insights into how much pressure if any would
14 be required to reduce the effective principal stresses
15 and thus reach a critical stress state. Critical
16 stress as a function of excess fluid pressure was
17 evaluated and modeled for the Meltwater field.
18 Under current geological conditions precise
19 subsurface stress directions and magnitudes for the
20 Meltwater field area are under constrained. The
21 regional maximum horizontal stress, HS max, is
22 interpreted to generally trend northwest/southeast with
23 local variations ranging from west/northwest to
24 east/southeast to north/northwest, south/southeast.
25 The Meltwater Ni well contains the borehole breakout
.R
0
1 data with the image -- from an image log indicating a
2 northwest/southeast maximum horizontal stress which is
3 consistent with these regional trends. 4D seismic
4 lineaments appear to be aligned with the maximum
5 horizontal stress trending north/northwest to
6 south/southeast. This suggests the most likely
7 Meltwater field stress model with HS max oriented
8 north/northwest to south/southeast. However the
9 difficulty in knowing exact stress state and changes in
10 the stress state dynamically contributes to a large
11 uncertainty in critical stress analysis. Final
12 evaluation of the critical stress modeling is that the
13 uncertainty and stress magnitudes is large enough to
14 make interpretations of excess fluid pressure value
15 from this approach inconclusive.
16 Slide 32. Mechanistic overburden modeling was
17 performed with a focus on evaluating the overburden
18 material balance. The model was used to test whether
19 MI migration is possible through high perm fractures in
20 the overburden. These factors were intended to
21 correspond with the 4D seismic lineaments. Due to
22 limit data characterizing the overburden in full field
23 extended reservoir the modeling input was quite
24 subjective. The results of the modeling were
25 inconclusive.
47
1 A 3D planar fracture geometry model was used in
2 a completions analysis to simulate the estimated
3 surface pressure and injection profile for the
4 Meltwater field. The modeling indicating that
5 hydraulic fractures likely grew and penetrated the
6 overburden. This modeling was limited by the lack of
7 data characterizing both the overburden and a full
8 field reservoir.
9 It supports the interpretation that the initial
10 migration of injected fluids out of the Bermuda
11 interval was a result of a large pressure differential
12 between injectors and producers.
13 Slide 33. A geomechanical analysis was
14 performed to evaluate scenarios for hydraulic fractures
15 to be induced by field injection operations or through
16 reactivated regional faults or a combination of the two
17 in a geologically conditioned model. A discrete
18 fracture network model was constructed to test this
19 range of scenarios. The tool allows for 3 dimensional
20 propagation of a hydraulic fracture in a geocellular
21 model containing any population of layers, cell
22 properties or discrete planar faults or fractures.
23 Hydraulic fracture propagation was simulated in the
24 model which considered general fluid injection
25 conditions as well as rule based calculations that
N
1 govern geomechanical interactions. These modeling
2 results were hindered by the limited characterizing the
3 overburden and the full field extended reservoir and
4 the results of the modeling were inconclusive.
5 At this point I will hand over the presentation
6 to Eric Bressler to discuss the sixth initiative, the
7 seismic modeling portion of the Meltwater overburden
8 characterization.
9 CHAIR FOERSTER: Before you proceed, are you
10 going to talk about more than slide 34?
it MR. BRESSLER: No, ma'am. Just.....
12 CHAIR FOERSTER: Okay.
13 MR. BRESSLER: .....slide 34.
14 CHAIR FOERSTER: Okay. Well, go ahead and do
15 that and then there might be some questions.
16 MR. BRESSLER: For the record this is Eric
17 Bressler. Seismic modeling was performed to better
18 understand the cause of the observed 4D time shifts at
19 Meltwater. Also for assessing the ability of seismic
20 to detect a reduction in gas or a related mitigating
21 change in the overburden. Though the rock physics
22 model used for the modeling is sub -optimally
23 constrained several conclusions can be drawn with a
24 fair amount of certainty. One outcome of this study is
25 that gas alone does not account for the observed time
1 shifts. When fractures are included modeled time
2 shifts are consistent with the time shifts observed in
3 the 4D seismic. Another result of this study is the
4 confirmation that seismic would be poorly suited for
5 confirming a reduction in overburden gas. This is
6 because p-wave velocity is not sensitive to changes in
7 gas concentration once gas is present at or in excess
8 of about 3 to 5 percent.
9 And at this point I will hand the presentation
10 back to Tommy Nenahlo to discuss the development
11 initiatives at Meltwater if you have no questions.
12 CHAIR FOERSTER: Okay. Before we proceed,
13 Commissioner Seamount do you have any questions at this
14 point?
15 COMMISSIONER SEAMOUNT: Just one. Are any of
16 these lineaments or faults or fractures expressed at
17 the surface?
18 MR. BRESSLER: Not that -- this is Eric
19 Bressler. There's certainly no information on the
20 seismic that would suggest that or any other data that
21 I'm familiar with.
22 COMMISSIONER SEAMOUNT: There's no topographic
23 expressions that may be.....
24 CHAIR FOERSTER: Okay. Any other questions?
25 COMMISSIONER SEAMOUNT: Go ahead.
50
•
1 CHAIR FOERSTER: Okay. I've heard of lot of
2 quantitatively inconclusive and insufficient data and
3 subject to blah, blah, blah, I've heard of lot of
4 (indiscernible), so can you say that you know where the
5 gas has gone and how it got there? And identify
6 yourself, whoever chooses to take this one.
7 MR. NENAHLO: This is -- this is Thomas
8 Nenahlo. So we believe is that essentially there's a
9 -- due to the stratigraphic discontinuities and the
10 operations there's a large pressure differential
11 between injector and producer and along these linear
12 features it migrated vertically and likely charged up
13 shallower zones. We can't.....
14 CHAIR FOERSTER: How did the migration occur,
15 you didn't have a good seal, you created fractures, how
16 did the migration occur?
17 MR. WENTZ: I would say that the excess
18 ejection pressures may have forced the gas up through a
19 fracture network into shallower intervals at least then
20 into the little outer -- open outer annulus where there
21 it may have charged up shallower zones.
22 CHAIR FOERSTER: Okay. So correct me if I'm
23 wrong, but what I'm hearing is that existing fractures
24 that -- in the absence of the increased pressure were
25 sealing, became open due to the increased pressure and
51
1 then provided a conduit for upward movement, is that
2 accurate?
3 MR. NENAHLO: That is correct.
4 CHAIR FOERSTER: Okay. And that's what you
5 believe happened, but because of all those
6 inconclusives and not enough data I heard you said
7 you're still not for sure that that's your mechanism,
8 is that -- is that also accurate?
9 MR. NENAHLO: The modeling that was done
10 supports that interpretation.
11 CHAIR FOERSTER: But modeling can support a lot
12 of interpretation that later become -- are dismissed,
13 right, in my history of using models the only thing you
14 can say about a model is you're going to change it, is
15 that -- are you okay with what I just said?
16 MR. NENAHLO: (Inaudible response).....
17 CHAIR FOERSTER: Do you have any questions now
18 that I've.....
19 COMMISSIONER SEAMOUNT: Do you know how high
20 these fractures go or how high the open part of the
21 fracture goes?
22 MR. BRESSLER: This is Eric Bressler.
23 Seismically we don't see a signal beyond about 1,700
24 feet above the reservoir.
25 COMMISSIONER SEAMOUNT: Above the reservoir?
52
0
•
1 MR. BRESSLER: Above the reservoir.
2 CHAIR FOERSTER: What would that depth be
3 subsea?
4 MR. BRESSLER: Just below -- oh.....
5 CHAIR FOERSTER: You don't see anything above X
6 feet subsea?
7 MR. BRESSLER: Yeah, I would need to.....
8 CHAIR FOERSTER: Get a calculator and subtract?
9 MR. BRESSLER: Yeah. Yeah.
10 CHAIR FOERSTER: It's okay to do that.
11 COMMISSIONER SEAMOUNT: Sounds like it would be
12 around 4,000 feet in parts of the field.
13 MR. BRESSLER: I would add that the fractures
14 are not identifiable on the seismic. Usually with a
15 fracture there's no offset of formation, that they're
16 just cracks in the rock. So they're not able to be
17 identified on the seismic. We do not identify faulting
18 within the Bermuda reservoir interval on the seismic.
19 CHAIR FOERSTER: So this is a hypothesis?
20 MR. BRESSLER: So it's a hypothesis.
21 CHAIR FOERSTER: Okay. And do you have a depth
22 above which you don't see anything?
23 MR. BRESSLER: I'm just going to have to
24 roughly subtract.....
25 CHAIR FOERSTER: We can put that in the list of
53
1 questions that.....
2 MR. BRESSLER: Okay.
3 CHAIR FOERSTER: .....somebody writes down and
4 you get back to us on.
5 MR. BRESSLER: Okay.
6 CHAIR FOERSTER: Okay. All right. Any other
7 questions?
8 COMMISSIONER SEAMOUNT: No.
9 CHAIR FOERSTER: All right. Please proceed.
10 MR. NENAHLO: Slide 35. And for the record
11 this is Thomas Nenahlo and I'll be presenting
12 initiative three, development objectives.
13 So these development objectives are predicated
14 upon recent geologic, engineering and production data
15 analyses that indicate that well conversions and
16 sidetracks utilizing coiled tubing drilling technology
17 may further reduce the risk of potential migration of
18 injected fluids out of the Meltwater oil pool while
19 optimizing the ultimate hydrocarbon recovery from the
20 field.
21 Slide 36. By placing a producer and an
22 injector in the same turbidite lobe deposit significant
23 improvements in producer performance can be realized.
24 This map on the lower right depicts the individual
25 lobes from the Meltwater field as discussed and
54
0 0
1 illustrated in the Meltwater geology overview section.
2 The well trajectories and bottom hole locations are
3 shown in relation to the individual turbidite lobe
4 boundaries. These individual channelized lobes
5 demonstrate the reservoir compartmentalization. The
6 green circles indicates the bottom hole locations of
7 the producers while the blue triangles indicate the
8 bottom hole locations of the injectors. In addition
9 due to the depositional nature of the turbidite
10 deposits the sands within each lobe can have
11 significant vertical and lateral heterogeneities
12 especially near the periphery of the lobe. As can be
13 seen on the map there are a number of examples in which
14 injectors and producers are not in the optimum location
15 to account for the lobate nature of the reservoir. To
16 overcome the stratigraphic barriers between the lobes
17 ConocoPhillips would like to progress well conversions
18 and coiled tubing drilling sidetrack opportunities.
19 This initiative is designed to mitigate further
20 migration of injected fluids out of zone as well as
21 provide for improved reservoir connectivity and
22 ultimate hydrocarbon recovery.
23 Slide 37. Shown on this slide is a cross
24 section within an individual turbidite lobe from A to A
25 prime. The picture on the right is a depiction of the
55
0
•
1 reservoir interpretation from seismic and well
2 interaction data between the injector 2P-434, producer
3 2P-417, and injector 2P-420. These wells exhibit
4 superior inter -well communication that correlates with
5 the seismic interpretation. The interaction between
6 injector 2P-434 and producer 2P-417, will be discussed
7 further on the next slide.
8 Slide 38. This slide demonstrates the superior
9 hydrocarbon production performance when an injector and
10 a producer are located within the same turbidite
11 deposit. The interaction depicted here is between
12 injector 2P-434 and producer 2P-417. The orange line
13 on the chart shows the injection rate, 1,000 standard
14 cubic feet per day, within the date of injection on the
15 X axis. The green area indicates the oil production
16 rate from 2P-417. Prior to restoring 2P-434 to
17 injection service well 2P-417 was producing
18 approximately 150 barrels of oil per day. After
19 restoring injection capabilities producer 2P-417
20 reached a peak oil rate of over 1,200 barrels of oil
21 per day. As can be seen a significant improvement in
22 the oil rate from this well was achieved by taking
23 advantage of the lobate nature of the reservoir and
24 returning this injector to service. There are a number
25 of other opportunities to further improve the
56
1 hydrocarbon recovery at Meltwater by pursuing well
2 conversions and coiled tubing drilling sidetracks.
3 Slide 39. Shown on this slide is a cross
4 section that crosses through multiple lobe boundaries
5 from B in the south to B prime in the north. The
6 picture on the right is a depiction of the reservoir
7 interpretation from seismic data between producer 2P-
8 449, injector 2P-447, producer 2P-448A and producer 2P-
9 451. As can be seen there are numerous stratigraphic
10 boundaries that need to be overcome between the
11 injector 2P-447 and the adjacent producers. These
12 barriers appear to negatively impact the ability to
13 provide pressure support and reservoir sweep to the
14 producers.
15 Slide 40. This slide shows the injection and
16 production rates in the southwest portion of the field
17 where there are significant reservoir heterogeneities
18 along the turbidite lobe boundaries that can be
19 attributed to the deposition environment. Prior to
20 setting the sand face injection pressure limit the
21 injectors in this area were capable of injecting
22 approximately eight million standard cubic feet per
23 day. After the sand face injection pressure limit was
24 set the injectors were shut-in to allow the reservoir
25 pressure to decline. When the injectors were returned
57
1 to service in late 2014 they were unable to inject at
2 historic rates. Rather than using the higher injection
3 pressure to support the producers in the area
4 ConocoPhillips is evaluating opportunities to relocate
5 the bottom hole location of existing wells to better
6 sweep individual lobes by not requiring injection
7 across the turbidite lobe boundary.
8 Slide 41. This slide illustrates the effects
9 of reservoir compartmentalization on Meltwater's total
10 oil production. The chart at the left is the oil
11 production in the western and eastern sections in
12 barrels of oil per day. Within the chart the green
13 represents the western section of the reservoir while
14 the red represents the eastern section. The primary
15 difference between the two is that the well
16 interactions within the western section are more
17 hindered by compartmentalization. On setting of the
18 sand face injection pressure limit the injection rate
19 into the western section of Meltwater experienced a
20 significant decline resulting in a decline in the oil
21 production rate. The eastern section production
22 injection remained relatively stable. This
23 compartmentalization hinders the ability to establish
24 an optimal sweep of the reservoir with the current well
25 locations. This is the primary driver for
1 ConocoPhillips to pursue well conversions and coiled
2 tubing drilling sidetrack opportunities as the
3 evaluations completed to date indicate that an
4 improvement in the ultimate recovery of the field can
5 be achieved by converting and/or relocating bottom hole
6 locations of a number of wells.
7 CHAIR FOERSTER: Okay. Go back to that slide
8 just for a sec. So are those cumulative production
9 rates, combined production rates or are they separate?
10 MR. NENAHLO: Those are stacked production
11 rates.
12 CHAIR FOERSTER: Stacked. Okay. That's what I
13 was -- that's a good word.
14 MR. NENAHLO: Yeah, and barrels of oil per day.
15 CHAIR FOERSTER: And when the dip occurred
16 that's when you stopped injecting, when the initial dip
17 occurred.....
18 MR. NENAHLO: This dip?
19 CHAIR FOERSTER: No. No, the first dip.
20 MR. NENAHLO: So that dip is attributable to
21 the 2012 CPF 2 shutdown, we were doing.....
22 CHAIR FOERSTER: Okay.
23 MR. NENAHLO: .....planned maintenance so we
24 actually shut-in the field.
25 CHAIR FOERSTER: Okay. So that was a field
59
1 shut-in.
2 MR. NENAHLO: Field shut-in.
3 CHAIR FOERSTER: And then when you brought the
4 field back on.....
5 MR. NENAHLO: And at that time we had a sand
6 face injection pressure limit set.....
7 CHAIR FOERSTER: Okay.
8 MR. NENAHLO: .....and then we experienced a
9 decline. This recent increase here is that interaction
10 between 2P-434 and 417. And this increase here is we
11 had a producer shut-in for some time in the field due
12 to low reservoir pressure and so by returning the
13 injectors to service -- so this -- we coincided
14 returning injectors to service with that single
15 producer 2P-449.
16 CHAIR FOERSTER: And you're pointing now to
17 which slide?
18 MR. NENAHLO: Oh, I'm sorry. Slide 40.....
19 CHAIR FOERSTER: Okay.
20 MR. NENAHLO: .....looking at the lower right
21 of the chart.
22 CHAIR FOERSTER: Okay.
23 MR. NENAHLO: So we -- when we brought online
24 the injectors we also brought online that additional
25 producer.
I
1 CHAIR FOERSTER: Okay. Thank you. All right.
2 And now you're back on slide 41.
3 MR. NENAHLO: Back on slide.....
4 CHAIR FOERSTER: Thank you. That gave it more
5 of a complete context for me.
6 MR. NENAHLO: Yeah.
7 CHAIR FOERSTER: Thank you. Okay. Continue.
8 MR. NENAHLO: Okay.
9 CHAIR FOERSTER: Oh, unless.....
10 MR. NENAHLO: Unless there any further.....
11 CHAIR FOERSTER: Do you have any questions
12 right now?
13 COMMISSIONER SEAMOUNT: No.
14 CHAIR FOERSTER: Okay. Nor do I.
15 MR. NENAHLO: Slide 42, requested amendments to
16 AIO 21A.
17 Slide 43. ConocoPhillips Alaska requests that
18 the Oil and Gas Conservation Commission
19 administratively amend area injection order 21A, the
20 Meltwater oil pool in the Kuparuk River field.
21 ConocoPhillips Alaska submitted the request in its
22 capacity as operator of the Meltwater oil pool and as
23 unit operator for an on behalf of the working interest
24 owners of the Meltwater participating area in the
25 Kuparuk River unit. The requested amendments to AIO
61
1 21A are designed to one, further mitigate the potential
2 for the migration of injected fluids out of the
3 Meltwater oil pool while improving flood efficiency and
4 ultimate hydrocarbon recovery in a safe and
5 environmentally friendly manner; two, to enable
6 ConocoPhillips Alaska to safely and successfully
7 conduct surveillance initiatives to ensure confinement
8 of injected fluids within the MOP; three, to ensure
9 continued performance reporting by providing an annual
10 synopsis on ConocoPhillips Alaska's surveillance and
11 monitoring and development initiatives that are
12 designed to ensure the containment of injected fluids
13 within the Meltwater oil pool and; four, to remove the
14 expiration date associated with AIO 21A.
15 Slide 44. In light of the new information
16 gathered and analyzed over the past three years
17 ConocoPhillips Alaska seeks to administratively amend
18 four rules within AIO 21A. The rationale in support of
19 each proposed amendments follows. Rule 2, fluid
20 injection wells. In an effort to mitigate the effect
21 of stratigraphic discontinuities between injectors and
22 producers within the Meltwater oil pool ConocoPhillips
23 originally requested that AIO 21A rule 2 be revised to
24 read as follows. Development well sidetracks are
25 permissible when drilled within the MOP and well
62
1 conversions are permissible in the MOP. This proposed
2 amendment is designed to improve reservoir connectivity
3 between producers and injectors thus mitigating the
4 effects of compartmentalization and improving ultimate
5 hydrocarbon recovery. Further by placing injectors and
6 producers within the same lobe deposit the risk of
7 injected fluids migrating out of the MOP can be
8 reduced. An alternative option to the original request
9 would be to replace the existing language with the
10 original AIO 21 rule 2 language. The proposed language
11 for either alternative is reflected on the slide above.
12 ConocoPhillips' operating philosophy and core values
13 emphasize safety and environmental stewardship. We are
14 committed to ensuring that the wells at Meltwater are
15 drilled and operated safely. To ensure this in
16 addition to the existing regulations that require the
17 AOGCC's approval through the drilling permitting
18 process to drill any new well as well as the AOGCC's
19 approval for all well conversions through the sundry
20 process, ConocoPhillips has internally developed a
21 thorough well design and delivery process.
22 And, Randy Kanady, our staff drilling engineer
23 will now provide an overview of our well design
24 delivery process for the Commission.
25 MR. KANADY: Good morning. My name is Randall
63
1 Kanady and I'm a staff drilling engineer with
2 ConocoPhillips Alaska Drilling and Wells Group. And
3 I'd like to be recognized as an expert in drilling
4 engineering. I have over 25 years experience in Alaska
5 oil fields with ARCO, Phillips and ConocoPhillips. My
6 responsibilities over the years have included
7 production engineering, drilling engineering, HSC and
8 currently I manage ConocoPhillips' drilling and wells
9 compliance and regulatory activities. I have a
10 bachelor's in petroleum engineering and a master's in
11 environmental engineering. My bachelor's is from
12 Montana College of Mineral Science and Technology and a
13 master's in environmental engineering from the
14 University of Alaska. Finally I'm a registered
15 professional engineer in the state of Alaska.
16 CHAIR FOERSTER: Do you have any questions for
17 this witness?
18 COMMISSIONER SEAMOUNT: I have no questions, I
19 have no objections.
20 (Off record comments)
21 CHAIR FOERSTER: Mr. Kanady, I have no
22 questions, I have no objections.
23 (Off record comments)
24 CHAIR FOERSTER: You may proceed.
25 RANDALL KANADY
64
1 previously sworn, called as a witness on behalf of
2 ConocoPhillips stated as follows on:
3 DIRECT EXAMINATION
4 MR. KANADY: ConocoPhillips Alaska would like
5 the Commission to consider that rule number 2 of AIO
6 21A revert back to the original AIO rule 2 which is
7 restated in his slide 36. I'm sorry, we're on slide
8 35.
9 CHAIR FOERSTER: Forty-five.
10 MR. KANADY: Forty-five. And that rule is
11 restated on the top of slide 45. CPA would like to
12 rely on AOGCC permit to drill process 20 AAC 25.005 to
13 review future Meltwater drilling opportunities to
14 address potential drilling risk. Before CPAI would
15 submit a permit to drill a proposed well would go
16 through ConocoPhillips' well design and delivery
17 process. I would like to briefly review the well
18 design and delivery process for the Commission to give
19 you an appreciation of the detailed work that would be
20 required. The well design and delivery process or
21 WDDP, establishes a set of standards and guidelines for
22 the delivery and operation of all ConocoPhillips wells.
23 The WDDP is managed -- is intended to manage and
24 identify operational risk as a structured process which
25 leverages multi discipline teams and continuous
65
1 improvement in an organized way to deliver safe,
2 efficient planning of well work across ConocoPhillips.
3 Implementation of the WDDP encourages collaboration by
4 soliciting and capturing the key issues and inputs from
5 each discipline. It guides a multi discipline team
6 through the well planning process, it documents well
7 design and delivery decisions, encourages timely
8 decision making on well design and provides early
9 feedback to other disciplines on the feasibility and
10 cost of proposed development alternatives.
11 The WDDP is a front end loading process that is
12 structured in a stage gate process that ensures robust
13 planning and design early in the project's lifestyle at
14 a time when the ability to influence changes in design
15 is relatively high and the cost to make those changes
16 is relatively low. It encourages the appropriate level
17 of specialist and leadership to be involved at the
18 appropriate stage of the project planning process to
19 ensure critical criterion options are considered at the
20 right time. And it enables the development of
21 sufficient strategic information with which owners can
22 address risk and make decisions to commit resources in
23 order to maximize the potential for success.
24 So the six phases of the WDDP as you can see on
25 slide 45 is front end loading or FEL-1 is explore
I
1 phase, FEL-2 is the appraise phase, FEL -- FEL-1 is the
2 appraise phase, FEL-2 is the select phase and FEL-3 is
3 the define phase. And ConocoPhillips would not be
4 bringing a well to the Commission until it has passed
5 the FEL-3 stage gate. And then the remaining stages of
6 the WDDP is execute phase or the well construction
7 phase and then operate phase. For each FEL phase it
8 has multiple requirements that must be completed before
9 getting approval to progress to the next phase. These
10 phases are implemented differently depending on whether
11 the project is an individual well or a program and its
12 associated program wells.
13 The WDDP utilizes Max Book which is a web base
14 software tool designed to support the WDDP by providing
15 a chronological tool to implement and document the WDDP
16 by enabling a multi discipline team to move a project
17 through the process of designing and delivering a well.
18 So unless the Commission has any questions
19 regarding our well design and delivery process I will
20 hand the presentation back to Tommy Nenahlo.
21 CHAIR FOERSTER: Do you have any questions?
22 COMMISSIONER SEAMOUNT: I just have one. I
23 hear a lot of talk about sidetracking existing wells,
24 put them in better locations and stuff, are you also
25 saying that you want to drill grassroot wells too, I
67
1 mean, can you reach the entire field by sidetracking
2 existing wells and do what you want to do?
3 CHAIR FOERSTER: And whoever answers identify
4 yourself.
5 MR. NENAHLO: I'll answer that one. This is
6 Thomas Nenahlo. Currently we are pursuing well
7 conversions and coiled tubing drilling sidetracks.
8 There are opportunities that we believe are to the
9 south -- the southeast of the field primarily that
10 would be inaccessible to CTD sidetracks and well
it conversions in terms of optimizing the ultimate
12 recovery. In addition CTD opportunities may be
13 challenged in the future due to the vertical
14 perm/horizonal perm relationship. The channelized
15 nature of Meltwater field provides us benefits in a
16 number of areas in the Meltwater field because we have
17 a better KVKH than sand -- a similar field like Tarn
18 would have. Tarn is a much more laminated system
19 because we're higher up on the slope and we have a much
20 more channelized nature deposition environment which
21 you'd think would be conducive for CTD sidetracks.
22 But, yes, there are opportunities that we would not be
23 able to reach with CTD and we need to evaluate the
24 deliverability of the CTD well once a pilot is drilled
25 before we assess anything further on the lower east
is
1 side.
2 CHAIR FOERSTER: Any other question?
3 COMMISSIONER SEAMOUNT: Not at this time.
4 CHAIR FOERSTER: I have a couple questions
5 about the WDDP. Is the WDDP something that everybody
6 -- I mean, is it like an ASME code or, you know, is it
7 something that everybody that drills wells follows or
8 is it -- is this something ConocoPhillips does?
9 MR. NENAHLO: I know for a fact it's something
10 ConocoPhillips does, but I couldn't say for sure which
11 of the companies follows it, the VDDT curriculum.
12 CHAIR FOERSTER: So it's not something that you
13 learned in college that everybody automatically does
14 like the laws of physics?
15 MR. NENAHLO: No.
16 CHAIR FOERSTER: Okay. So has Conoco's WDDP
17 changed during the time that you've been with Conoco or
18 is it something that -- I mean, it's like a law of
19 physics, you let go of it, it always drops, is the WDDP
20 like that, nothing ever changes in it?
21 MR. NENAHLO: The -- this WDD -- the current
22 well design and delivery process was implemented last
23 year and but the pieces that we talked about were
24 primarily there I think for the last several years, but
25 it has been formalized into a manual of standards here
69
1 in 2014.
2 CHAIR FOERSTER: So if Conoco were to pull a BP
3 on us and sell Meltwater to Hilcorp or somebody would
4 Hilcorp have this same WDDP?
5 MR. NENAHLO: Yeah, I would have to check with
6 Hilcorp.
7 CHAIR FOERSTER: So there's no guarantee that a
8 new operator -- and it could be -- it could be Pioneer
9 or somebody else, there's -- so there's no guarantee
10 that should Conoco relinquish operatorship of Meltwater
11 to a different operator that that operator would still
12 -- would have this same WDDP?
13 MR. NENAHLO: There's no way, yeah, without
14 checking with the operator to find out if they.....
15 CHAIR FOERSTER: So there's no guarantee?
16 MR. NENAHLO: .....without checking with the
17 operator.
18 CHAIR FOERSTER: So not knowing who the
19 operator is could you check with that operator?
20 MR. NENAHLO: We.....
21 CHAIR FOERSTER: I think that's a no. So
22 there's no guarantee. Never mind, it's a rhetorical
23 question. All right. I don't have any questions at
24 this time.
25 MR. NENAHLO: And so for the record this is
70
1 Thomas Nenahlo. Slide 46. I just have a few more
2 slides and we'll be complete with the presentation.
3 Rule 8. So slide 46, rule 8, authorized fluids
4 for injection. AIO 21A, rule 8 specifies that the
5 authorized fluids for injection into the Meltwater oil
6 pool. Water is not currently listed. Water was
7 previously authorized and used as an underground
8 injection fluid in the Meltwater oil pool, but was not
9 identified in AIO 21A. This was because there are no
10 plans to revert to a waterflood or water alternating
11 gas flood at the MOP at this time due to the superior
12 performance of the field in utilizing a gas and/or
13 miscible injectant flooding agent. However Beaufort
14 Sea water in the Kuparuk River unit produced water is
15 necessary to conduct surveillance, logging, near
16 wellbore displacements and well maintenance.
17 Specifically the use of injected water allows for
18 displacement of gas in the wellbore prior to well
19 interventions to mitigate hazards to personnel and is
20 required for oxygen activation logging as a method to
21 ensure the integrity of the production casing cement
22 shoe on injectors. The Meltwater field fluid
23 sensitivity study was completed in March of 2001. This
24 study utilized core samples from the Meltwater North
25 number 1 and number 2 wells that included an
71
1 investigation into the sensitivity of preserved
2 reservoir samples to the proposed floodwaters. These
3 proposed floodwaters included a Kuparuk River unit
4 produced water blend and a 75 percent Kuparuk River
5 unit produced water, 25 percent Beaufort Sea water
6 blend. The investigation into the sensitivity of the
7 Meltwater North number 1 and number 2 core samples to
8 the proposed floodwaters concluded that there were no
9 adverse reactions to the produced water/sea water
10 blend.
11 As discussed in the application for permission
12 to inject produced water and sea water in the Meltwater
13 oil pool and which application resulted in AIO 21A.005,
14 although ConocoPhillips Alaska does not have fluid
15 sensitivity studies completed with 100 percent Beaufort
16 Sea water, the salinities of the KRU or Kuparuk River
17 unit produced water and the Beaufort Sea water are
18 similar and no appreciable compatibility problems for
19 either the Meltwater formation or its confining zones
20 are expected. If injectors do incur damage from sea
21 water injection the damage will be contained with a
22 small radius of the wellbore due to the small volume of
23 fluid required to complete the surveillance, logging,
24 displacements and well maintenance initiatives. Any
25 damage to the near wellbore formation that may arise
72
0
1 can be reversed by employing remedial treatments. The
2 AOGCC authorized the injection of Beaufort Sea water in
3 AIO 21A.005 on November 21, 2014 for a period of six
4 months to allow us to complete a number of surveillance
5 initiatives. Therefore ConocoPhillips requests that
6 AIO 21A rule 8 be modified to allow for the continued
7 injection of Beaufort Sea water and injection of KRU
8 produced water for surveillance, logging, near wellbore
9 formation displacements and well maintenance purposes.
10 Slide 47. Rule 9, performance reporting. Rule
11 9 of AIO 21A currently requires a monthly report
12 detailing the daily monitoring of all Meltwater oil
13 pool wells. ConocoPhillips Alaska respectfully
14 requests that the Commission modify AIO 21A, rule 9, to
15 read the operator shall submit an annual synopsis of
16 the surveillance, monitoring and development
17 initiatives completed during the previous year that
18 pertain to the confinement of injected fluids within
19 the Bermuda interval together with the Meltwater annual
20 surveillance report. This proposed modification to
21 rule 9 will ensure the Commission receives an annual
22 synopsis of surveillance, monitoring and development
23 initiatives as they pertain to the containment of
24 injected fluids at the same time ConocoPhillips Alaska
25 submits the Meltwater annual surveillance report that
73
1 is required by conservation order 456, rule 10. This
2 modification to AIO 21A, rule 9, will eliminate the
3 monthly reporting requirement yet ensure that the
4 Commission is regularly informed of the status and
5 results of containment and development initiatives.
6 Rule 11, expiration date. Currently AIO 21A
7 has an expiration date of November 16, 2015.
8 ConocoPhillips requests that the Commission remove the
9 expiration date as surveillance and monitoring data
10 suggest that the implementation of the new reservoir
11 management strategy has prevented further migration of
12 injected fluids out of the Meltwater oil pool. The
13 existing rules together with the aforementioned
14 requested amendments will ensure confinement of
15 injected fluids while optimizing ultimate hydrocarbon
16 recovery.
17 CHAIR FOERSTER: Mr. Nenahlo, before you go to
18 your next slide, are you aware that the AOGCC is
19 considering adding sunset clauses to all of its
20 conservation orders and AIOs?
21 MR. NENAHLO: That actually was discussed with
22 the AOGCC technical staff.
23 CHAIR FOERSTER: Okay. So the fact that we're
24 going to -- we are likely to put sunset clauses on all
25 of AIOs doesn't impact your desire to have us not do
74
1 one for this one?
2 MR. NENAHLO: What kind of time frame -- I'm
3 just out of curiosity what are the time frames for the
4 sunset clauses?
5 CHAIR FOERSTER: We haven't nailed it yet.
6 MR. NENAHLO: Okay. Yeah, we're -- essentially
7 we had a two year original AIO 21.
8 CHAIR FOERSTER: Do you have a recommendation
9 for -- you know, and one of the reasons we're
10 considering the sunset clause is just, you know,
11 mechanical conditions of wells change, operating
12 parameters change, knowledge of fields change,
13 operators change and the ability of different operators
14 to perform at the same level changes. So do you have a
15 suggestion on a sunset clause timing for this AIO given
16 that we're not likely to give you eternity?
17 MR. NENAHLO: I'd like to discuss that with the
18 technical team.
19 CHAIR FOERSTER: Okay. Well, maybe that's a
20 question you can answer and.....
21 MR. NENAHLO: Yeah, certainly. We'd be.....
22 CHAIR FOERSTER: .....we'll leave the record
23 open.
24 MR. NENAHLO: .....more than happy to.
25 CHAIR FOERSTER: Okay. Commissioner Seamount,
75
1 do you have any questions at this time?
2 COMMISSIONER SEAMOUNT: No, I don't. I might
3 after the break though.
4 CHAIR FOERSTER: Okay. Please proceed.
5 MR. NENAHLO: Thank you. Slide 48, closing
6 remarks. So in conclusion the requested amendments to
7 AIO 21A arise from geologic, engineering and production
8 data analyses that indicate there has been no further
9 migration of injected fluids out of the Meltwater oil
10 pool. Furthermore recent geologic and production data
11 analyses indicate that well conversions and sidetracks
12 utilizing coiled tubing drilling technology overcomes
13 stratigraphic barriers within the compartmentalized
14 reservoir may further reduce the risk of potential
15 migration of injected fluids out of the Meltwater oil
16 pool while optimizing ultimate hydrocarbon recovery.
17 ConocoPhillips believes the requested amendments are
18 based on sound engineering and geoscience principles
19 and they will further mitigate the risk of migration of
20 injected fluids, it will increase ultimate hydrocarbon
21 recovery, it will not promote waste or jeopardize
22 correlative rights and will not result in an increased
23 risk of fluid movement into freshwater. We are
24 confident that even with these changes ConocoPhillips
25 can continue to operate in a safe and efficient manner
76
1 at Meltwater therefore ConocoPhillips Alaska seeks
2 AOGCC approval of the amendments presented today.
3 And thank you for your attention during this
4 presentation.
5 CHAIR FOERSTER: Okay. Before we take a break
6 do you have any questions?
7 COMMISSIONER SEAMOUNT: No.
8 CHAIR FOERSTER: Neither do I. It is 10:40,
9 let's take a -- I'd say we'll need at least 20 minutes.
10 We'll tentatively plan on resuming at 11:00, but if
11 we're not back up here don't start without us. So
12 we're recessed at 10:40.
13 (Off record - 10:40 a.m.)
14 (On record - 11:04 a.m.)
15 CHAIR FOERSTER: All right. We have several
16 questions for Conoco and we'll start with Mr. Seamount.
17 (Off record comments)
18 COMMISSIONER SEAMOUNT: All right. I have a
19 few questions. Do these fractures or lineaments or
20 pathways, temporary pathways, do they propagate through
21 the C37?
22 MR. BRESSLER: They appear to die out about 200
23 feet below the C37.
24 COMMISSIONER SEAMOUNT: Okay.
25 MR. BRESSLER: And I can answer your earlier
77
1 question.....
2 COMMISSIONER SEAMOUNT: Okay.
3 MR. BRESSLER: .....like about the height.
4 Because the field itself has variable depth, right, and
5 these linear features have variable height, about 3,600
6 feet below sea level would be about the shallowest you
7 would expect that to reach.
8 COMMISSIONER SEAMOUNT: So 3,600 feet below sea
9 level?
10 MR. BRESSLER: Yeah.
11 COMMISSIONER SEAMOUNT: And it looks like there
12 are at least -- there's a C50, C40 and a C37 sand in
13 that interval, correct?
14 MR. BRESSLER: Correct.
15 COMMISSIONER SEAMOUNT: Do you see any shallow
16 gas, I think I may have asked this question, but do you
17 see any shallow gas above the C80?
18 MR. BRESSLER: No, sir. Of course the quality
19 of the seismic diminishes as you, you know, the amount
20 of fold, the amount of data you have in any seismic
21 survey's diminished up there, but we don't see
22 anything.
23 COMMISSIONER SEAMOUNT: So, is there a possible
24 way to get seismic that would work at those shallow
25 depths like these shallow hazard surveys that we do on
W.
1 exploration wells?
2 MR. BRESSLER: It's conceivable. I guess I
3 don't know enough about the limitations and issues with
4 acquisition up there on the Slope in terms of shallow
5 -- shallow seismic, but.....
6 CHAIR FOERSTER: Well, that would be a good
7 question to write down for your list and get back to us
8 on.
9 COMMISSIONER SEAMOUNT: And also I'd like to
10 know what the resolution of the seismic is. I assume
11 that these plumes have been mapped out with the aid of
12 seismic?
13 MR. BRESSLER: Yes.
14 COMMISSIONER SEAMOUNT: And are you able to get
15 a footage on them or just see them?
16 MR. BRESSLER: A footage for all dimensions,
17 height?
18 COMMISSIONER SEAMOUNT: Yeah, what.....
19 MR. BRESSLER: Yeah.
20 COMMISSIONER SEAMOUNT: .....what's the minimum
21 height that you can see?
22 MR. BRESSLER: Yeah, so the minimum depth is
23 3,600 below sea level. And they can be deeper than
24 that.
25 COMMISSIONER SEAMOUNT: Okay. But I'm talking
79
1 about the sand, the Bermuda sand, what thickness can
2 you identify off the seismic on the sand?
3 MR. BRESSLER: Oh, I see. Tuning thickness on
4 the newer data set is about 87 feet. That's
5 artificially precise, but that's the math, it's 87.5
6 feet when I use my, you know, rough interval velocity
7 and dominant frequency of about 30 hertz on the full
8 stack seismic.
9 CHAIR FOERSTER: And that's good to one
10 significant digit.
11 COMMISSIONER SEAMOUNT: Okay.
12 (Off record comments)
13 COMMISSIONER SEAMOUNT: So when you map out
14 these plumes your tuning thickness is 87 feet, but you
15 can see the edges of them anyway
16 correct, and that's how you -- how you map the aerial
17 extent?
18 MR. BRESSLER: Yeah, of the lobes.
19 COMMISSIONER SEAMOUNT: Okay. Has your seismic
20 analysis of the pathways changed since the last time we
21 looked at them.....
22 MR. BRESSLER: No.
23 COMMISSIONER SEAMOUNT: .....you came in and
24 gave a presentation?
25 MR. BRESSLER: No.
1 COMMISSIONER SEAMOUNT: Okay. What formation
2 is the C80 in, it's below the base of the West Sak?
3 MR. BRESSLER: I'll defer to my colleague here.
4 MR. WENTZ: This is Robert Wentz. We have it
5 within the Campainian (ph). The C80 is normally
6 markers and.....
7 COMMISSIONER SEAMOUNT: Okay.
8 MR. WENTZ: .....it's within the Campainian.
9 COMMISSIONER SEAMOUNT: Okay. Is that what the
10 C stands for?
11 MR. WENTZ: No, I don't believe so. It may be
12 the Cretaceous, but I'm not sure.
13 COMMISSIONER SEAMOUNT: Oh, okay. All right.
14 If you're going to sidetrack a well where would you set
15 the whipstock, do you have any idea?
16 CHAIR FOERSTER: Identify yourself please.
17 MR. NENAHLO: I'm sorry. For the record this
18 is Thomas Nenahlo. We have a CTD development engineer
19 with us today, maybe he would be able to answer that
20 question specifically.
21 CHAIR FOERSTER: Come on up and swear yourself
22 in if you're going to answer a question. Identify
23 yourself, who you're with, what you do and then let me
24 swear you in. And talk into one of the mics. Have a
25 seat.
1 MR. STARCK: Yes, my names Kai Starck, I've
2 worked for ConocoPhillips since 2005 in the
3 (indiscernible) drilling group and I -- since 2012 I've
4 been working as a (indiscernible) drilling engineer.
5 In that regard I guess I'd like to be considered an
6 expert witness on (indiscernible) drilling.
7 CHAIR FOERSTER: Okay. Do you have any
8 questions?
9 COMMISSIONER SEAMOUNT: Where did you qo to
10 school?
11 MR. STARCK: I do not have a degree.
12 COMMISSIONER SEAMOUNT: Oh. Okay. I've seen
13 those bumper stickers that say no college. Okay. I
14 have no questions other than that.
15 CHAIR FOERSTER: Nor do I. Please.....
16 COMMISSIONER SEAMOUNT: And no objections.
17 CHAIR FOERSTER: And no objections.
18 MR. STARCK: Thank you.
19 KAI STARCK
20 called as a witness on behalf of ConocoPhillips stated
21 as follows on:
22 DIRECT EXAMINATION
23 MR. STARCK: The placement of the whipstock
24 would be highly dependent on the original geometry of
25 the well. In general when we decide on placement of
E-IM
1 whipstock we want to have competent rock above us to
2 contain the wellbore to the actual formation we're
3 drilling. In general in Kuparuk area we don't do any
4 cementing of our liners, we use a slotted liner
5 completion so that requires having a good, competent
6 barrier above us. So we would place the whipstock
7 below whatever that competent barrier would be.
8 COMMISSIONER SEAMOUNT: Okay. So it's possible
9 that if you did have a problem lineament or temporary
10 fracture or whatever we call them that you would --
11 could set the whipstock above it, right, I mean, it --
12 I mean, you could drill through it?
13 MR. STARCK: Yes.
14 COMMISSIONER SEAMOUNT: Okay. That's all I
15 have. Thank you.
16 MR. STARCK: Thank you.
17 CHAIR FOERSTER: I have several questions and
18 they're in a variety of -- I wrote them down, kind of a
19 stream of consciousness approach and so they may be all
20 over the place. I'm going to try to make them as
21 logical as I can.
22 Can you account for all of the MI that was
23 injected?
24 MR. NENAHLO: This is Thomas Nenahlo. So on
25 reservoir material balance it would be approximately --
1 in terms of a material balance we have approximately 25
2 to 30 percent of MI that potentially leak off either
3 shallow or deep -- or deeper. CHAIR FOERSTER: And so
4 you can't account for 25 to 30 percent of the MI?
5 MR. NENAHLO: In the reservoir material
6 balance. And that's not necessarily MI, but accum
7 injected fluid including water.
8 CHAIR FOERSTER: Okay. Okay. You said that
9 you needed the rules lifted to allow you, you know, new
10 wells and conversions so that you can maximize recovery
it from the field. How will the field reserves and
12 recovery change if we lift this, are you going to --
13 are you going to add reserves, are you going to book
14 new reserves, are you just going to be able to get the
15 reserves you've already booked and after you answer
16 that question what's the quantity that you expect.
17 MR. NENAHLO: Okay. Well, currently we have --
18 we have two initiatives we're presenting, one would be
19 a pilot CTD well and one would be a well conversion and
20 that would be used to verify the work that we've done
21 so far in terms of linking up an injector and a
22 producer within a channel levy of turbidite lobe
23 complex. So making predictions on all of the
24 development opportunities would be difficult to say at
25 this time in terms of the actual additional reserves we
�1.
1 might get before the end of the field life, however we
2 do believe them to be substantial in terms of -- order
3 of magnitude would be thousands of barrels a day.
4 CHAIR FOERSTER: That's rate, not reserves?
5 MR. NENAHLO: Things of rates, yeah,
6 incremental rate. Now what the -- the end of field
7 life would then be extended if we -- if we did pursue
8 this opportunities because currently the wells or a
9 number of the producers are not receiving adequate
10 injection support and we believe that's attributable to
11 the stratigraphic discontinuities that we'd like to
12 overcome.
13 CHAIR FOERSTER: So put that down as a question
14 that we'd like an answer on is what do you -- do you
15 have a projection of incremental recovery, not rate,
16 but recovery, based on changing the rules.
17 MR. NENAHLO: Are you looking for a specific
18 estimate like a number?
19 CHAIR FOERSTER: Yeah, I'm looking for a
20 number.
21 MR. NENAHLO: Okay.
22 CHAIR FOERSTER: Yeah. And would that allow
23 you just to get what's already booked or would you be
24 booking additional reserves as part of that question
25 also.
E,
1 I'm trying to keep this in some sort of a
2 logical order, but -- okay, that's good. I'll go in a
3 different direction now. In earlier conversations with
4 Mr. Kanady there had been some concerns expressed about
5 increased potential for shallow gas hazards caused by
6 the earlier injection problems. What is your feeling
7 on the potential for increased shallow gas hazards at
8 this time?
9 MR. KANADY: This is Randy Kanady. At this
10 time we haven't done -- completed a detailed analysis
11 of those hazards and the -- that analysis would be
12 conducted in our well design and delivery process in
13 the FEL one in two phases.
14 CHAIR FOERSTER: Okay. And so when you do that
15 analysis would you include all of the inconclusive
16 results that you presented today?
17 MR. KANADY: Those risks would be taken into
18 account if we were to progress the project forward.
19 CHAIR FOERSTER: What's the worst thing that
20 could happen if you were to drill a new well and you
21 hadn't adequately planned for those -- you hadn't
22 adequately identified the shallow gas hazards?
23 MR. KANADY: Well, you know, the worst thing
24 that would happen is your mud weight would not be
25 adequate to control the pressure of that gas and you
M
1 would -- you would take a kick and have to shut-in the
2 BOPs and circulate in a higher mud weight.
3 CHAIR FOERSTER: Well, what would happen if you
4 didn't -- if you did that during the surface hole
5 drilling and you didn't have a BOP?
6 MR. KANADY: Again you would have to address
7 those risks in the well design and delivery process
8 before you.....
9 CHAIR FOERSTER: What if you didn't adequately
10 address them in the design process?
11 MR. KANADY: Well, I think, you know, the
12 Commission knows what the answer would be and.....
13 CHAIR FOERSTER: Well, the record doesn't.
14 MR. KANADY: The -- if you took an unpredicted
15 kick on your surface hole and couldn't control it with
16 mud weight you would have to take that kick through
17 your diverter and potentially lose the well.
18 CHAIR FOERSTER: So you'd have a well control
19 problem, you'd have loss of well control and what we
20 call a blowout?
21 MR. KANADY: Potentially, yeah.
22 CHAIR FOERSTER: Right. Okay. So I just want
23 the record to reflect that that risk is real and it
24 exists. Okay. Let's see. I'll go back to a question
25 that I think is for Mr. Nenahlo. And what is the
RE
1 economic limit on production rates for wells in Tarn?
2 MR. NENAHLO: The economic limit?
3 CHAIR FOERSTER: Yes.
4 MR. NENAHLO: The economic limit for Meltwater
5 wells in particular is usually constrained by gas to
6 oil ratio. And so the -- as we increase the gas/oil
7 ratio it becomes less competitive because we have
8 limited space in our facilities for handling that gas
9 and depending on the time of year, you know, in colder
10 months we have more compression capacity so.....
11 CHAIR FOERSTER: So a well that was producing
12 50 barrels a day but had a low GOR could still be
13 competitive?
14 MR. NENAHLO: Would very much be competitive,
15 yes.
16 CHAIR FOERSTER: Okay. So you don't have a --
17 so the fact that those wells weren't getting pressure
18 support and they were dropping down to 100 barrels a
19 day, that didn't by itself make them non-competitive?
20 MR. NENAHLO: That in itself.....
21 CHAIR FOERSTER: Okay.
22 MR. NENAHLO: .....however there is one point I
23 would like to make for the record is we do have a 24
24 inch PO line and so how we currently have been
25 operating is have seasonal producers. So we bring
1 online -- we shut it in in the summer to bring and
2 build our reservoir pressure on the producers such that
3 we can flush -- provide flush production to the 2P PO
4 line as it needs to cross it miles to reach Tarn
5 production. So those cold ambients, you know, can pose
6 freezing problems if we don't have sufficient rate.
7 And so there could theoretically be situations if we
8 aren't -- we do not pursue the developmental objectives
9 in which we need to shut-in the field during the winter
10 months due to that reason.
11 CHAIR FOERSTER: Okay.
12 MR. NENAHLO: So that would be another economic
13 limited source, but on a higher level.
14 CHAIR FOERSTER: Have you looked into the
15 possibility of gaining connectivity by hydraulically
16 fracturing your existing wells to interconnect the
17 different lenses or would that be just reopening
18 Pandora's Box on exceeding the pressure limits that
19 caused the earlier flows?
20 MR. NENAHLO: Our existing injector completions
21 were not fracture stimulated when they were originally
22 completed. And, you know, we have injectors -- we have
23 an injector, 2P-427 that is outside of the linear
24 feature and so we can model the rates in an unfractured
25 scenario. And we believe that that would be sufficient
:'
1 for providing the necessary support to the producers if
2 the stratigraphic barriers are overcome.
3 CHAIR FOERSTER: Okay. I probably didn't ask
4 my question properly.
5 MR. NENAHLO: Oh.
6 CHAIR FOERSTER: Rather than drill new wells to
7 gain communication among the different lobes that
8 aren't currently in communication could that
9 interconnectivity and that communication be gained
10 through hydraulic fractures?
11 MR. NENAHLO: In most cases the fractures would
12 need to be much larger than would be -- in terms of
13 laterally much larger than we'd be willing to pursue to
14 overcome distances that we need to cover to overcome
15 the.....
16 CHAIR FOERSTER: Okay.
17 MR. NENAHLO: .....stratigraphic
18 discontinuities.
19 CHAIR FOERSTER: Okay. So the answer is no?
20 MR. NENAHLO: Correct.
21 CHAIR FOERSTER: That's fine. You talk about
22 feeder channels. Can you map the feeder channels?
23 Identify yourself when you answer the question.
24 MR. BRESSLER: I believe you're speaking to me.
25 This is Eric Bressler. So you're talking about a dip
90
1 on the shelf where we were discussing the source for
2 the sediment?
3 CHAIR FOERSTER: And the channels that go down
4 and create the.....
5 MR. BRESSLER: Yes, those can be mapped in the
6 upper most portions -- up dip portions of the field and
7 then beyond up onto the shelf, outside of the reservoir
8 area.
9 CHAIR FOERSTER: So when you inject into the
10 lobes will the injection stay in the lobes or will it
11 -- does it have potential to move up into the feeder
12 channel and go other places?
13 MR. BRESSLER: Well, presumably, I mean,
14 outside the reservoir area the permeability would be
15 much less and I guess it's not my area of expertise to
16 answer that, but I.....
17 CHAIR FOERSTER: So you're thinking a
18 permeability decrease would be the barrier for.....
19 MR. BRESSLER: I believe so.
20 CHAIR FOERSTER: Are all the inconclusives that
21 you mentioned due to a lack of data or poor data or a
22 combination thereof? Identify yourself.
23 MR. WENTZ: This is Robert Wentz, I'll answer
24 that. And I'm assuming you're referring to the
25 overburden characterization studies?
91
1 CHAIR FOERSTER: I'm referring to every time
2 you said well, we looked at this, but we got
3 inconclusive data. So anybody who made that statement
4 might want to chime in with their own answer.
5 MR. WENTZ: The lack of data pertains primarily
6 to the overburden characterization. Traditionally in
7 the petroleum industry data acquisitions focus
8 primarily on the producing reservoirs or in the field
9 development. In he Meltwater development a full suite
10 of open hole logs covers the Bermuda section along with
11 conventional core which is actual rock data. The
12 portions of the borehole outside of the reservoir,
13 particularly the overburden above, normally contain
14 less than a full suite of a logs. There's -- there is
15 a full suite in some wells and in the case of the
16 Meltwater field there is no conventional core outside
17 of the reservoir. Currently well logging devices can
18 indirectly measure geomechanical properties of the
19 rock, but actual rock sample measurements are needed to
20 fully calibrate the data in order to fully understand
21 the geomechanical processes.
22 CHAIR FOERSTER: So given what you know now if
23 you had it to do again would you do it differently,
24 would you gather different data or more data? And this
25 is a question for our learning so that as we move into
92
1 development of fields we know what kinds of
2 requirements to make, put upon operators.
3 MR. WENTZ: I believe in the industry that is a
4 trend that the overburden sampling is done now to
5 forego problems like this based on what the industry
6 has learned.
7 CHAIR FOERSTER: So you would -- you would do
8 it differently now going with what you've learned.
9 Okay.
10 MR. WENTZ: That's hard to say for every field
11 case, but generally, yes.
12 CHAIR FOERSTER: Okay. Does anybody else want
13 to weigh in on this?
14 (No comments)
15 CHAIR FOERSTER: Okay. What's the source of
16 the biogenic gas that you -- to which you refer?
17 MR. WENTZ: Earlier you were asking where that
18 gas had come from. During the drilling of the well mud
19 logs were run and we saw indications of gas throughout
20 multiple levels of the overburden and varied from well
21 to well in differing amounts. I'm not sure exactly
22 where that gas has come from other than those multiple
23 layers throughout the overburden.
24 CHAIR FOERSTER: So these were in the initial
25 wells you identified, that's not in subsequent wells?
93
1 MR. WENTZ: The -- all the wells as they were
2 drilled.
3 CHAIR FOERSTER: Okay. Starting from the very
4 first -- those three that are now plugged and
5 abandoned, those three discovery wells?
6 MR. WENTZ: I believe so. I'd have to go back
7 and.....
8 CHAIR FOERSTER: Okay. That would be a
9 question I'd love to get the answer to so write that
10 one down. And as you move into lean gas injection how
11 will you identify the biogenic gas versus the injected
12 gas, I mean, since you won't have those heavy markers?
13 MR. NENAHLO: Correct. So working with.....
14 CHAIR FOERSTER: This is?
15 MR. NENAHLO: I'm sorry. This is Thomas
16 Nenahlo. Tracers, gas tracers are a viable option to
17 use for that scenario. And.....
18 CHAIR FOERSTER: Are you planning on putting
19 tracers into your injection?
20 MR. NENAHLO: We have not solidified plans at
21 this moment. I have worked with a contracting company
22 to ensure the feasibility of that and we do have -- it
23 is feasible to use gas tracers for the outer annulus
24 gas analysis as well as producer to injector
25 interactions.
I
1 CHAIR FOERSTER: Okay. Okay. You mentioned
2 that two wells still have increased pressure, which two
3 wells are those?
4 MR. NENAHLO: Those are well 2P-447 and 2P-431
5 as we're currently, you know, performing that extended
6 bleed as I had shown in the presentation and I can go
7 back to that slide if you like, we haven't.....
8 CHAIR FOERSTER: Go ahead.
9 MR. NENAHLO: .....let since -- would you like
10 me to go back to that slide?
11 CHAIR FOERSTER: No, no, no.
12 MR. NENAHLO: Okay. So I'll start with 2P-431.
13 We began bleeding it back March 7th of 2015 and we had
14 a short shut-in duration. During the CPF 2 shutdown it
15 rose to around eight to 900 psi, but then we returned
16 it to the -- to the bleed after we brought the facility
17 back online. So we don't know its true stabilized
18 pressure anymore. Historically it had been about 1,500
19 psi at surface. The gas composition we were monitoring
20 on a weekly basis and the gas composition is staying
21 steady and it's not showing influence from our lean gas
22 injection operations which indicates -- you know,
23 preliminarily indicates we're not being -- that source
24 that's charging the 2P-431 outer annulus is not being
25 supplied by the reservoir interval.....
95
1 CHAIR FOERSTER: The pressure increased
2 occurred.....
3 MR. NENAHLO: .....we're injecting in.
4 CHAIR FOERSTER: .....during the shut-in?
5 MR. NENAHLO: Right. Just due to the -- if you
6 wouldn't mind I can go to the.....
7 CHAIR FOERSTER: Oh, go back to the slide,
8 that's fine.
9 MR. NENAHLO: Okay. We're on slide 26 and the
10 maroon is the bleed rate and the red is the outer
11 annulus pressure. So you can see that we -- when we
12 shut-in the well it started to rise and we also, you
13 know, shut-in the bleeder cores as the facility was
14 shutdown and then when we restarted it it's been
15 producing intermittently since then indicating that the
16 source is starting to die out, but we still need more
17 time to evaluate this.
18 CHAIR FOERSTER: So what makes you think it's a
19 thermal effect?
20 MR. NENAHLO: 2P-431?
21 CHAIR FOERSTER: Yes. You said that you had
22 two wells that had higher pressure and you said that
23 the increase was just thermal. So what makes you think
24 that's thermal?
25 MR. NENAHLO: Oh, sorry. Not this well, this --
M
1 are you referring to the interim progress report or
2 you're referring.....
3 CHAIR FOERSTER: Earlier in your presentation
4 one of you said that there were two wells that had --
5 still had increased pressure, but it was simply
6 thermal. And so those are the two wells I wanted you
7 to identify and explain why you thought they were just
8 thermal.
9 MR. NENAHLO: On our injection wells we
10 believe.....
11 CHAIR FOERSTER: I don't recall which wells.
12 Well, you didn't identify them, you said that there
13 were two wells that had increased pressure that you
14 felt that the increase was thermal. So I'd like you'd
15 to tell me which two wells those are and why you think
16 it's thermal.
17 MR. NENAHLO: So 2P-429 and 2P-434 would be the
18 thermally affected wells.
19 CHAIR FOERSTER: Okay. So what were the
20 numbers of the wells again?
21 MR. NENAHLO: 2P-429, 2P-434.
22 CHAIR FOERSTER: And so you actually have four
23 wells that have increased pressure?
24 MR. NENAHLO: Well, I guess I need to make sure
25 of the question. So are you referring to above the
97
1 thousand psi limit or below the thousand psi limit?
2 CHAIR FOERSTER: I'm just referring to what you
3 said in your testimony.
4 MR. NENAHLO: Okay.
5 COMMISSIONER SEAMOUNT: It's slide 23.
6 MR. NENAHLO: Oh, okay. Those specific wells
7 and so the context of that.....
8 CHAIR FOERSTER: Which two wells are those?
9 MR. NENAHLO: So that is well 2P-424 and I have
10 to take a look at the -- I don't have that information
11 on the second well with me.
12 CHAIR FOERSTER: Oh, so now we've got five
13 wells or maybe six.
14 MR. NENAHLO: Sorry. Let me.....
15 CHAIR FOERSTER: You've got 2P-447, 431.....
16 MR. NENAHLO: .....let me refer to the.....
17 CHAIR FOERSTER: .....429, 434, 424 and
18 possibly a sixth well.
19 MR. NENAHLO: So I can -- let me work through
20 each well individually if you don't -- I can get
21 through the interim progress report.
22 CHAIR FOERSTER: Okay. I think so that I allow
23 you the time to do this with clarity and no pressure,
24 what I would like to hear form you is for the five
25 wells that you have named today and the potential sixth
0
1 well that this slide refers to I would like to know --
2 get a characterization of the pressure and if you still
3 have increased pressure an explanation of why you think
4 that is so and if you think it is thermal the
5 justification for why you think it is thermal. So
6 that's something that we'll get from you, but not right
7 now because I don't think you want to do that technical
8 analysis while everybody's staring at you. MR.
9 NENAHLO: Okay.
10 CHAIR FOERSTER: Is that fair?
11 MR. NENAHLO: Yes, that's fair.
12 CHAIR FOERSTER: Okay. We'll move on. Another
13 thing that we'd like to have submitted that we don't
14 need right now, but with the answers to all the other
15 questions please submit a well schematic for what a
16 typical completion would look like in a grassroots
17 well, in a coiled tubing sidetrack well and in a
18 conversion and in any other configuration that you
19 might deem possible.
20 When we do AIOs we often do -- okay, areas of
21 review. How would ConocoPhillips feel about a rule
22 requiring an area of review for any new wells in the
23 Meltwater pool. Now I'm asking for your feelings, but
24 to the degree that you feel comfortable answering that
25 questions I'd appreciate an answer.
• 01
1 MR. NENAHLO: I'm not familiar with an area
2 review. Like what would be the specifics of that?
3 CHAIR FOERSTER: It would be looking for
4 shallow gas hazards, it would be looking for mechanical
5 integrity of all wells within an affected area, that
6 sort of thing.
7 MR. NENAHLO: Yeah, I believe certainly that
8 would be included with our well design and delivery
9 process review.
10 CHAIR FOERSTER: So if we were to make that a
11 requirement that wouldn't be something that would be
12 unduly burdensome to ConocoPhillips?
13 MR. NENAHLO: No.
14 CHAIR FOERSTER: Okay. I think we're nearing
15 the end. Just -- I'd like to close out with one more
16 opportunity for ConocoPhillips to characterize in
17 laymen's terms an explanation of the mechanism that
18 caused the initial concerns, just something that the
19 Petroleum News reporter could understand because if he
20 understands it I have a reasonable amount of confidence
21 that I'll understand it too. So whoever wants to take
22 that one.
23 MR. NENAHLO: Okay. So this is Thomas Nenahlo,
24 I can take that question. So what we believe was the
25 ultimate reason for fluid migration out of zone was we
100
1 had injectors and producers and between them we had
2 stratigraphic barriers we were seeing in field
3 operations, you know, before my time. We had producers
4 out running injection support and we injected at a
5 pressure well above our current sand face injection
6 pressure limit. And likely this broke down the
7 reservoir or broke down the seal and we had leakage of
8 injected fluids vertically.
9 CHAIR FOERSTER: Thank you. Commissioner
10 Seamount, did I inspire any additional questions from
11 you?
12 COMMISSIONER SEAMOUNT: No, you certainly did
13 not.
14 CHAIR FOERSTER: Okay. Well, thank you for
15 your patience with all of our questions, thank you for
16 a thorough presentation, thank you for identifying
17 every one of your slides.
18 And at this point I'll ask if there is any
19 other person in the audience who would like to testify?
20 (No comments)
21 CHAIR FOERSTER: Okay. We've given you a
22 number of questions that we -- and we'll need an answer
23 from before we can proceed with your request. Will one
24 week of leaving the record open be sufficient, did you
25 need two weeks, how much time does ConocoPhillips need
101
1 -- think you'll need to answer the questions that
2 remain unanswered?
3 MR. NENAHLO: I think one week will be
4 sufficient.
5 CHAIR FOERSTER: Okay. Well, we will leave the
6 record open for seven calendar days from today and
7 expect answers to all of the questions that we've asked
8 by then. And should ConocoPhillips need additional
9 time we'll need a request in writing to keep the record
10 open longer and so that we can do that.
it All right. Then if there's nothing else for
12 the good of the order then at 11:38 this hearing's
13 adjourned.
14 (Recessed - 11:38 a.m.)
15 (END OF PROCEEDINGS)
102
•
•
1 TRANSCRIBER'S CERTIFICATE
2 I, Salena A. Hile, hereby certify that the
3 foregoing pages numbered 02 through 103 are a true,
4 accurate, and complete transcript of proceedings in re:
5 Area Injection Order AIO 21A public hearing,
6 transcribed under my direction from a copy of an
7 electronic sound recording to the best of our knowledge
8 and ability.
9
10 Date Salena A. Hile, Transcriber
11
103
Iv-.1"
ConocoPh*1111*PS •
Meltwater Area Injection Order 21A
Amendment Hearing
ConocoPhillips Alaska Meltwater Team 0
Thursday, July 9th, 2015
Meltwater A10 Chronology
w August 2001: Original A10 21 Issued
w January 2002: Injection Operations begin
w April 2002: Increase in OA pressures
w 2003: Completed investigation into the source of the increase in OA
pressures
w 2003 — 2011:
■ ConocoPhillips managed OA pressures through a number of initiatives
■ Provided periodic updates to the AOGCC
w Spring 2012: Identified likely migration of fluid out of zone with 4D seismic
w Summer 2012: Containment Initiatives Kicked Off
w October 2012: CPAI requested Amendment to A10 21
■► May 2013: Amended A10 21 Issued
w April 2014: Interim Progress Report Submitted
w April 2015: Interim Progress Report Submitted
w April 2015: NO 21A Request for Amendment Submitted
ConocoPhillips
Summary of Requested Amendments to A10 21A
10 CPAI requests the following amendments to A1021A
■ The allowance for Producer -to -Injector conversions (Rule 2)
■ The allowance to drill wells within the Meltwater Oil Pool (Rule 2)
■ The allowance to use PW and SW for well and surveillance work only (Rule 8) •
■ To change the monthly reporting requirement to annual reporting (Rule 9)
■ To eliminate the expiration date on the A10 (Rule 11)
0
3 w.wu•..uu..u.o.
ConocoPhillips
Presentation Outline
w Meltwater Field Overview
■ Facilities
■ Operations
■ Geoscience
w Meltwater Containment Initiatives
■ Operations
■ Well Integrity
■ Reservoir Management Strategy
■ Surveillance
■ Overburden Characterization
m Development Objectives •
w Requested Amendments to AIO 21A
w Closing Remarks
•
ConocoPhillips
0
Meltwater Operations
Operator and Surface Owners within One Quarter Mile of Injection Operations
ow Operator: ConocoPhillips Alaska, Inc.
m Surface Owner: State of Alaska
�► Working Interest Owners
■ ConocoPhillips Alaska, Inc.
■ BP Exploration (Alaska) Inc.
■ Chevron U.S.A. Inc.
■ ExxonMobil Alaska Production, Inc.
"'•"""' ConocoPhillips
•
Meltwater Field Wells
Meltwater 2P Pad Location
2P-451 •
2P-448
+ 2 P-448A
2P-434 0
2P-443
O MWN 2A
2P 417 2P-420
♦ 2P-406
•
OMWN 2 2P415A
2P-432 �
• + 2P-415
2P-422A
2P-447 0 2P-441 + 2P-422
2P-449 2P-438 ♦ 2P-429 2P-424
OMWN 1 2P-427
♦ 2P-41902P-431 ♦ : P-424A
LEGEND
2.4001.200 0 2.400 Feet • PRODUCER
♦ INJECTOR
N + PLUG & ABANDON
MELTWATER
PARTICIPATING AREA
Discovery Well:
■ Meltwater North 2 (2000)
Delineation Wells:
■ Meltwater North 2A
■ Meltwater North 1
Meltwater Field
■ 13 Producers
■ 6Injectors
■ 4 Abandoned Bore Holes
ConocoPhillips
•
Meltwater Operations
Meltwater Facilities
ow 8" Miscible Injectant/Lean Gas Injection Line
w 12" Water Injection Line (SI)
w 24" Production Flowline
w Gravel Road and Pad .,eo 24� Po
Ti •••► 24" PO
w 4 Bridges
_12" WI.10" Wi
w 1 Drill Site -•' �, _..--.. __..
m Overhead Powerline
•••• 2L
`4-Corners"
Intersection
O
CL
� I
Meltwater 12" WI line
proactively shut in
000000
. 4
•
• .
"Tam DS's"
• — .. — lam Pipelines
•
C4
r
. Meltwater Pipelines
a •
•
a • a • • ` "Meltwater"
CPF
ConocoPhillips
0
•
Meltwater Operations
Drill Site Facilities
m Trunk and Lateral Well Manifold
■ Production
■ Test
■ Water Injection (WI line to Meltwater currently shut-in)
• Miscible Injectant
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w Bermuda reservoir compartmentalized by turbidite lobe deposits
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.........
ConocoPhillips
Summary of Meltwater Containment Initiatives
w CPAI has implemented two primary initiatives and is pursuing a third
■ Initiative 1: Sand face injection pressure limit started in 2012
■ No indication of further MI migration, predicated upon:
■ Average reservoir pressure decline
■ Decline in Meltwater outer annulus pressures
■ The composition of the outer annuli gas becoming less similar to MI
■ Isotopic analyses indicating the outer annuli gas becoming more similar to biogenic gas
■ Surveillance logging verification of the integrity of the completion in all six injectors
■ Initiative 2: Reservoir Containment Assurance Project
■ Created and evaluated a Subsurface Containment Matrix that enabled the qualitative assessment
of the five key elements of containment
■ Wells
■ Reservoir and Overburden Characterization
■ Field Management/Surveillance
■ Operations
■ Action/Mitigation Planning
E
■ WellTrak Program
■ Initiative 3: Place injectors and producers within the same turbidite lobe deposit through is
Coiled Tubing Drilling sidetracks and well conversions
■ This will reduce the effect that stratigraphic discontinuities between individual lobes have on the
differential pressure between injectors and producers
■ Will require approval of WIOs and the AOGCC
... . ..... .
19 ConocoPhillips
:.............
Ensuring Safe Operations & Well Integrity
m Continuous Outer Annuli (OA) Pressure Monitoring
■ Advisory and critical alarms set to alert Operations of changing conditions
m Surface Casing (SC) Integrity Investigation in 2013
■ Objective:
■ To determine the extent of the SC corrosion at Meltwater
■ Conclusions:
■ The 2012 213-406 SC leak was attributable to a thread leak, not corrosion
■ Meltwater wells are effectively protected from corrosion by sealant
■ The corrosion rate on the SC is very low
■ The safety risks associated with excavation are greater than any potential benefits
■ Future inspections will be conducted to continue to monitor the corrosion rate
w In 2006 a corrosion inhibiting sealant was installed in all 2P conductor casings
w Operator Awareness Training
•
RG-2401 CorrosionInhibiting
..;;.........
..; 20 ....::::..
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Reservoir Management Strategy
Strategy:
■ Sand face injection pressure limit of 3,400 psig put in place in 2012
■ Based on FIT/LOT data from wells in which the production casing was set at the top of the Bermuda
interval
Monitoring Plan:
■ WHIP monitoring with advisory and critical alarms set to alert Operations of changing conditions
■ Injection -withdrawal monitoring
■ Cum I/W has decreased —6.5% from 2012 to 2015
■ Bermuda formation pressure surveillance
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Monitoring Program for Shallow Intervals
�► Un-cemented production casing annuli and open surface casing shoes
■ Allows for the monitoring of pressure and gas composition changes in shallow intervals
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�► Outer Annulus (OA) Monitoring Program
• Continuous monitoring of pressures
■ Quarterly fluid levels
■ Semi-annual pressure bleeds
■ Semi-annual gas composition analyses (through July 2014)
■ Isotopic gas analyses
w Outer Annulus Pressures
■ Decrease in OA Pressure: 11 of 19 wells
■ No Change in OA Pressure: 6 of 19 wells
■ Increase in OA Pressure: 2 of 19 wells
Injectors returned to service
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Meltwater Average Outer Annulus Pressures
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•
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Monitoring Program for Shallow Intervals
m CIA Gas Composition Analyses
■ No wells have shown an increasing similarity to MI
m CIA Gas Isotopic Analyses
■ Isotopic analyses performed in 2002, 2005, and 2012 •
■ Analyses in 2012 shows less MI and more biogenic gas than in 2002 and 2005
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24 ............�
Verification of Production Casing Cement Shoe Integrity
ft Utilized surveillance logging to verify the integrity of the production casing cement shoe
w Tested the shoe over a range of sand face injection pressures and rates
w No indication of fluid movement above the perforations detected
■ All injectors have been tested
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m 213-431 has historically had the highest outer annulus pressure (N1,500 psig)
w Began extended bleed on March 7t", 2015
CPF2 Shutdown Begins
w Bleed rate has shown a declining trend
•
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Overburden Characterization Study
m Initiated in late 2012, completed in January 2015
m Goal was to better understand the containment system and explain the
processes of fluid propagation into the overburden
m Additional goal of understanding the 4D seismic linear features •
m Studies largely performed by Houston Technology groups and Meltwater
technical team
w Specific Initiatives
■ Static Description of the Overburden
■ Critical Stress Modeling
■ Mechanistic Overburden Modeling
■ Completions Analysis
■ Geomechanical Analysis
■ Seismic modeling
Overburden Characterization Study — Results
w Numerous technologies applied
w Initiatives were highly data -constrained which provided quantitatively
inconclusive results
■ Model construction required key input parameters having large uncertainties •
■ Uncertainties resulted in inability to provide a conclusive determination as to the
mechanism that allowed propagation of fluids into the overburden
w Modeling supported interpretation of out -of -zone injection
■ Unable to provide additional insight into processes of fluid propagation into the
overburden
"""""" ConocoPhillips
0
Static Description of the Overburden
w Meltwater Field located on the Central
North Slope
w Complex tectonic history
w Multiple normal fault sets in stratigraphic column
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Critical Stress Modeling
w Critical Stress Modeling
■ Possible indicator of potential for slip reactivation on existing faults and fractures
■ Faults at or near critical stress may be more likely to contribute to fluid flow
■ Models can aid in the identification of faults most prone to be critically stressed
® Can offer insights into how much pressure would be required to reach a critical stress state •
w Results
■ Principal stress directions and magnitudes are under -constrained
■ Regional maximum horizontal stress (SHmax) ranges from WNW -ESE to NNW -SSE
■ 4D seismic lineaments appear aligned with SHmax trending NNW -SSE
■ Difficulty in knowing static stress state and changes in stress state dynamically contributes to a
large uncertainty in the critical stress analysis
■ Large uncertainty in stress magnitudes make interpretations of excess fluid pressure values
inconclusive 0
......::::::::
"" ConocoPhillips
Mechanistic Overburden Modeling & Completions Analysis
w Mechanistic Overburden Modeling
■ Focused on evaluating overburden material balance
■ Model tested whether MI migration was possible through high permeability fractures in
the overburden
■ Limited data characterizing the overburden and full -field extended reservoir made results S
inconclusive
m Completions Analysis
■ 3D planar fracture geometry model used to simulate estimated surface pressure and
injection profiles
■ Modeling indicated hydraulic fractures likely grew into overburden
■ Limited by lack of data characterizing the overburden and full -field extended reservoir
■ Supports interpretation that initial migration of injected fluids out of Bermuda interval was
a result of large pressure differential between injectors and producers
Geomechanical Analysis
w Geomechanical Analysis
■ Evaluated scenarios where hydraulic fractures could be induced by field injection
operations or through reactivated regional faults, or combination of both
■ Discrete fracture network model constructed
■ Tool allows for 3D propagation of hydraulic fracture in a geocellular model i
■ Simulation considered general fluid and injection conditions within framework of
geomechanical interactions
■ Limited data characterizing the overburden and full -field extended reservoir made results
inconclusive
•
................
ConocoPhillips
................
Seismic Modeling
w Seismic Modeling
■ Performed to better understand the cause of the observed 4D time -shifts at Meltwater
■ Also used to assess the ability of seismic to detect a reduction in gas or a related mitigating
change in the overburden
w Conclusions
■ Gas alone does not account for the observed time shifts
■ Fractures are required to match the modeled time shifts to the 4D seismic
■ Seismic would be poorly suited for confirming a reduction in overburden gas
■ P-wave velocity is not sensitive to gas concentrations when gas is present in excess of 3-5% of pore
volume
0
•
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Inter -well Communication
m Meltwater reservoir
compartmentalized by channelized
turbidite lobe deposits
To overcome stratigraphic barriers,
CPAI is considering/studying well
conversions and CTD sidetrack
opportunities
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Inter -well Communication
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Inter -well Communication
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Stratigraphic heterogeneities negatively
impact production rate
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Meltwater Production History
w Significant production decline in Western Meltwater attributed to
compartmentalization
■ May be possible to overcome with well conversions and CTD sidetracks
0
0
Meltwater Reservoir Boundary Map
•
•
ConocoPhillip
Requested Amendments to A10 21A
w CPAI requests the following amendments to A1021A
■ The allowance for Producer -to -Injector conversions
■ The allowance to drill wells within the Meltwater Oil Pool
■ The allowance to use PW and SW for well and surveillance work only •
■ To change the monthly reporting requirement to annual reporting
■ To eliminate the expiration date on the AlO
0
ConocoPhillips
:::........
Requested Amendments to A10 21A
w Existing Rule 2 - Fluid Injection Wells: New wells and production -to -
injection conversions are prohibited in the MOP.
■ Proposed Rule 2:
■ "Development well sidetracks are permissible when drilled within the MOP. Well conversions is
are permissible in the MOP."
■ Alternative Option: Modify Rule 2 to Original A10 21 Rule 2 Language
■ "The underground injection of fluids must be through a well permitted for drilling as a service
well for injection in conformance with 20 AAC 25.005, or through a well approved for
conversion to a service well for injection in conformance with 20 AAC 25.280. "
•
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Alternative to Proposed Modification of Rule 2
m Replace existing Rule 2 by reverting back to original A10 21 Rule 2:
■ The underground injection of fluids must be through a well permitted for drilling as a
service well for injection in conformance with 20 AAC 25.005, or through a well
approved for conversion to a service well for injection in conformance with 20 AAC
25.280.
Any proposed well at Meltwater would go through the CPA's Well Design
and Delivery Process
w The Well Design and Delivery Process (WDDP) establishes a set of standards
and guidelines for the delivery and operation of all ConocoPhillips wells. It
is a structured process which leverages multi -discipline expertise and
continuous improvement in an organized way to deliver safe, efficient
planning and delivery of well work across ConocoPhillips
w The six phases in the WDDP are:
■ FEL-0: Explore
■ FEL-1: Appraise •
■ FEL-2: Select
■ FEL-3: Define - Permit to Drill
■ Execute: Well Construction
■ Operate: Post Well Reviews
ow MaxBook is a Drilling and Wells project management tool used to track the
WDDP
'�• ,;;;;; ConocoPhillips
Requested Amendments to A1O 21A
w Existing Rule 8 — Authorized Fluids for Injection: Fluids authorized
for injection are:
■ Miscible injectant
■ Dry gas provided by the Kuparuk River Unit •
■ Tracer survey fluid to monitor reservoir performance
■ Fluids injected for stimulation purposes per 20 AAC 25.280 (a)(2)
■ Glycol from hydro -tests and freeze protection
■ Diesel used for freeze protection
■ Methanol used for freeze protection
■ Standard oilfield chemicals (corrosion and scale inhibitors, defoamers, emulsion breakers, etc.)
■ Proposed modification to Rule 8 is to add the following fluids to the list of authorized
fluids:
■ "Beaufort seawater for surveillance, logging, near-wellbore formation displacements, and well
maintenance; and 0
■ Kuparuk River Unit produced water for surveillance, logging, near-wellbore formation
displacements, and well maintenance."
Requested Amendments to A10 21A
w Existing Rule 9 — Performance Reporting: The Operator shall submit to the
AOGCC a monthly report detailing the daily monitoring of all Meltwater Oil
pool wells. Included in the monthly report, the Operator shall submit OA
fluid levels, well pressures, injection and/or production rates, and pressure
bleeds for all annuli. Trends shall be evaluated and detailed. In addition to
the conditions listed in the above rules the Operator shall provide by April
15t of each year an interim progress report that provides an update on the
status of the overburden characterization study, a synopsis of the
monitoring data collected during the previous year, and a detailed analysis
of the effects on ultimate recovery of switching from an MWAG project, as
authorized by AIO 21, to the current MI injection only project.
■ Proposed Rule 9:
■ "The Operator shall submit an annual synopsis of the surveillance, monitoring, and
development initiatives completed during the previous year that pertain to the confinement
of injected fluids within the Meltwater Oil Pool together with the Meltwater Annual
Surveillance Report:'
0
Existing Rule 11— Expiration Date: This order shall expire 24 months after
the effective date shown below (May 16, 2013)
■ CPAI requests that Rule 11 be removed and that A10 21A have no expiration date.
.....:.:
47 'ii"""""" ConocoPhillips
iii..i.i.....
Closing Remarks
Containment initiatives in conjunction with geologic and production
data analyses indicate there has been no further migration of
injected fluids out of the Meltwater Oil Pool.
0
■► Well conversions and sidetracks utilizing coiled tubing drilling may
further reduce the risk of migration of injected fluids while
optimizing hydrocarbon recovery.
The requested amendments are based on sound engineering
and geoscience principles, will further mitigate the risk of the
migration of injected fluids out of the MOP will increase
g J
ultimate hydrocarbon recovery, will not promote waste or
jeopardize correlative rights, and will not result in an increased
risk of fluid movement into freshwater.
•
•
.......::Hal
49 ............M.
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•
0
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
Public Hearing
Docket Number: AIO 15-015
Kuparuk River Field, Meltwater Oil Pool
Amendment to AIO 21 A
July 9, 2015 at 9:00 a.m.
NAME AFFILIATION
Testify (yes or no)
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Continuation Page
NAME AFFILIATION TESTIFY
(Please Print) (Yes or No)
G: S cAn CZ cc ho
9 0
•
ConocoP *I ips
Alaska
April 14, 2015
Cathy Foerster, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
i •
APR 14 2015
Kazeem A. Adegbola
Manager, GKA Development
North Slope Operations and Development
Office: ATO-1326
700 G. ST.
Anchorage, Alaska 99501
Telephone: 907-263-4027
E-mail: Kazeem.A.Adegbola@ConocoPhillips.com
RE: Meltwater Oil Pool Area Injection Order 21A Request for Amendment
Kuparuk River Field
North Slope, Alaska
Dear Commissioner Foerster:
ConocoPhillips Alaska, Inc. (CPA[) requests that the Alaska Oil and Gas Conservation Commission
administratively amend Area Injection Order 21A (AIO 21A) for the Meltwater Oil Pool (MOP)
within the Kuparuk River Field. CPAI submits this request in its capacity as operator of the MOP,
and as Unit Operator for and on behalf of the working interest owners of the Meltwater
Participating Area and the Kuparuk River Unit.
Please refer to the attached Request to Amend Meltwater Oil Pool Area Injection Order 21A for
the specific details of the proposed modifications to AIO 21A.
Please do not hesitate to contact me at (907) 263-4027 or Tommy Nenahlo at (907) 265-6934
should you have any questions about this request.
Kazeem A. Adegbola
Manager, GKA Development
Request to Amend Area Injectia'�fOrder No. 21A •
April 14, 2015
Request to Amend Meltwater Oil Pool Area Injection Order 21A
ConocoPhillips Alaska, Inc. (CPAI) requests that the Alaska Oil and Gas Conservation Commission
(Commission) administratively amend Area Injection Order 21A (AIO 21A) for the Meltwater Oil
Pool (MOP) within the Kuparuk River Field (see Attachment 1, Proposed AIO 21A Amendments).
The requested amendments to AIO 21A arise from geologic and production data analyses that
indicate there has been no further migration of injected fluids out of the MOP. Furthermore,
recent geologic and production data analyses indicate that well conversions and sidetracks
utilizing coiled tubing drilling technology may further reduce the risk of potential migration of
injected fluids out of the MOP.
The requested amendments to AIO 21A are designed to:
Further mitigate the potential for the migration of injected fluids out of the MOP, while
improving flood efficiency and ultimate hydrocarbon recovery in a safe and
environmentally friendly manner.
Enable CPAI to safely and successfully conduct surveillance initiatives to ensure
confinement of injected fluids within the MOP.
3. Ensure continued performance reporting by providing a synopsis of CPAI's surveillance,
monitoring, and development initiatives that are designed to ensure the containment of
injected fluids within the MOP.
4. Remove the expiration date associated with AIO 21A.
Technical Background
The MOP is defined as the Bermuda Interval that occurs between 6,785 ft. and 6,974 ft.
measured depth (MD) in the Meltwater North #2A well (see Attachment 2, Type Log). These
units are late Cretaceous -age (Cenomanian-Turonian) and are overlain by 2,600 ft. of marine
mudstone, siltstones, and shales. The top of the Cairn Interval to the C37 Interval represent
deep marine mudstones and siltstones and occasional sandstones, and are of late Cretaceous
age.
The Bermuda Interval itself is a complex shelf -slope turbidite deposit. The deposition
environment was of an intermittent nature, in which pulses of reservoir quality sand were
deposited in discrete intervals over a period of time. These deposition episodes were likely
triggered by storm and/or seismic events. Therefore, the reservoir is compartmentalized into
turbidite lobes, which are individual bodies of reservoir quality sandstone. Within the MOP,
these individual lobes are often separated by stratigraphic and/or structural discontinuities that
can cause significant baffling of flow.
Based upon the information gathered, and technical analyses completed to -date, it is likely the initial
migration of injected fluids out of the Bermuda interval was a result of a large pressure differential
between injectors and producers. (See the Meltwater Oil Pool Area Injection Oder 21A 2014 and 2015
Interim Progress Reports submitted to the Commission on April 1, 2014, and April 1, 2015,
respectively). This pressure differential was exacerbated by stratigraphic and/or structural
discontinuities within the Bermuda interval. To mitigate this issue and ensure the containment of
Page 1
Request to Amend Area Injection Order No. 21A 0
April 14, 2015
injected fluids within the Bermuda interval, CPAI has implemented two primary initiatives and is
pursuing a third.
The first initiative undertaken to mitigate the large pressure differential between injectors and
producers was to implement a sand face injection pressure limit. This sand face injection
pressure was incorporated into AIO 21A as Rule 7. To determine the effectiveness of this
strategy CPAI developed a significant number of surveillance and monitoring programs. These
programs yielded valuable data, to which a large technical and professional resource has been
applied to evaluate the information.
Based upon evaluation of these data, there is no indication of further migration of injected
fluids out of the Bermuda interval. This is predicated upon the following information:
o Average reservoir pressure has declined (see Attachment 3, Meltwater Reservoir
Pressures).
o The composition of the outer annuli gas has become less similar to MI (see
Attachment 4, Meltwater Outer Annulus Gas Compositions).
o Isotopic analyses have indicated the outer annuli gas becoming more similar to
biogenic gas (see Attachment 5, Meltwater Outer Annulus Gas Isotopic Analyses).
o Oxygen activation logging (Spectra -Flow®) has determined that injected fluids are not
bypassing the production casing cement in the wells tested to date (see Attachment 6,
Meltwater Oxygen -Activation Logging of Production Casing Cement Shoes).
Surveillance and monitoring programs will continue to ensure safe operations and
containment of injected fluids within the Bermuda interval. To safely and successfully
complete these programs, the injection of water for surveillance, logging, and near-wellbore
formation displacement will be required.
The second initiative undertaken was a Reservoir Containment Assurance Project designed to
ensure the containment of injected fluids within the MOP. This initiative resulted in the
creation and evaluation of a Subsurface Containment Matrix (SCM) that enabled the
qualitative assessment of the five key elements of containment:
1) Wells
2) Reservoir and Overburden Characterization
3) Field Management/Surveillance
4) Operations
5) Action/Mitigation Planning
In each category, the detailed elements of containment were assessed with a series of
statements related to details in the containment elements. The Meltwater SCM will continue
to be reviewed on a bi-annual basis.
The third initiative is in a planning stage and would be designed to place injectors and
producers within the same reservoir body, or lobe, through the use of coiled tubing drilling
(CTD) sidetracks and well conversions. This will reduce the effect that structural and/or
stratigraphic discontinuities between individual lobes have on the differential pressure
between injectors and producers. This initiative is designed to mitigate further migration of
Page 2
Request to Amend Area Injection• Order No. 21A is
April 14, 2015
injected fluids out of zone, as well as provide for improved reservoir connectivity and ultimate
hydrocarbon recovery.
It is CPAI's conclusion that the historic migration of injected fluids out of the Bermuda reservoir
was likely related to compartmentalization of the reservoir into turbidite lobes and the
bottomhole locations of the existing development wells. In the case in which an injector and
producer are located within the same lobe, reservoir connectivity is considered excellent. In the
case in which injectors and producers are located in different lobes, reservoir connectivity is
deemed poor, resulting in lower hydrocarbon production rates and recovery factors.
Discussion of Requested Amendments
In light of the new information gathered and analyzed over the past two years, CPAI seeks to
administratively amend four rules in AIO 21A. The rational in support of each proposed
amendment follows.
1. Fluid Injection Wells: New wells and production -to -injection conversions are prohibited in
the MOP. (AIO 21A Rule 2)
In an effort to mitigate the effect of structural and/or stratigraphic discontinuities between
injectors and producers within the MOP, CPAI requests that AIO 21A Rule 2 to be revised to read
as follows: "Development well sidetracks are permissible when drilled within the MOP. Well
conversions are permissible in the MOP."
This proposed amendment to Rule 2 would allow for producer -to -injector conversions and the
ability to drill development well sidetracks within the MOP using coiled tubing drilling
technology. This would improve reservoir connectivity between producers and injectors, thus
mitigating the effects of compartmentalization and improving ultimate hydrocarbon recovery.
Further, by placing injectors and producers within the same lobe deposit, the risk of injected
fluids migrating out of the MOP can be reduced.
CPAI believes that by placing injectors and producers within the same lobe deposit injected
fluids will be contained within the MOP and CPAI will reduce the risk of further migration of
injected fluids and improve the ultimate hydrocarbon recovery.
2. Authorized Fluids for Injection (A10 21A Rule 8)
AIO 21A Rule 8 specifies the authorized fluids for injection into the MOP. Water is not currently
listed. Water was previously authorized and used as an underground injection fluid in the MOP
(see Area Injection Order No. 21 dated August 1, 2001) but was not identified in AIO 21A as an
authorized fluid. This was because there are no plans to revert to a water flood or water -
alternating -gas flood at the MOP due to the superior performance of the field when utilizing a
gas and/or miscible injectant flooding agent. However, Beaufort Sea water and Kuparuk River
Unit (KRU) produced water is necessary to conduct surveillance, logging, near-wellbore
displacements, and well maintenance. Specifically, the use of injected water allows for
displacement of gas in the wellbore prior to well interventions to mitigate hazards to personnel
Page 3
Request to Amend Area Injectioder No. 21A •
April 14, 2015
and is required for oxygen -activation logging as a method to ensure the integrity of the
production casing cement shoe on injectors.
A Meltwater field fluid sensitivity study was completed in March of 2001. This study utilized
core samples from the Meltwater North #1 and Meltwater North #2 wells that included an
investigation into the sensitivity of preserved reservoir samples to the proposed flood waters.
These proposed flood waters included a KRU produced water blend and a 75% KRU produced
water/25% Beaufort Sea water blend.
The investigation into the sensitivity of the Meltwater North #1 and Meltwater North #2 core
samples to the proposed flood waters concluded that there were no adverse reactions to the
75% KRU produced water/25% Beaufort Sea water blend identified.
As discussed in AIO 21A.005, although CPAI does not have fluid sensitivity studies completed
with 100% Beaufort Sea water, the salinities of the KRU produced water and the Beaufort Sea
water are similar, and no appreciable compatibility problems for either the Meltwater formation
or its confining zones are expected. If injectors do incur damage from sea water injection, the
damage will be contained within a small radius of the wellbore due to the small volume of fluid
required to complete the surveillance, logging, near-wellbore formation displacements, and well
maintenance initiatives. Any damage to the near-wellbore formation that may arise can be
reversed by employing remedial treatments.
Therefore, CPAI requests that AIO 21A Rule 8 be modified to read as follows, to allow for the
injection of Beaufort Sea water and KRU produced water for surveillance, logging, near-wellbore
formation displacements, and well maintenance purposes.
Fluids Authorized for Injection are:
a. Miscible injectant;
b. Dry gas provided by the Kuparuk River Unit;
c. Tracer survey fluid to monitor reservoir performance;
d. Fluids injected for stimulation purposes per 20 AAC 25.280 (a)(2);
e. Glycol from hydro -tests and freeze protection;
f. Diesel used for freeze protection;
g. Methanol used for freeze protection;
h. Standard oilfield chemicals (corrosion and scale inhibitors, defoamers, emulsion
breakers, etc.);
i. Beaufort Sea water for surveillance, logging, near-wellbore formation displacements,
and well maintenance; and
j. Kuparuk River Unit produced water for surveillance, logging, near-wellbore
formation displacements, and well maintenance
All fluids injected must be compatible with the injection zone. Any other fluids shall be
approved in advance by separate administrative action based upon proof of compatibility
with the reservoir and formation fluids. Long-term injection of water provided by the
Kuparuk River Unit water injection system is currently not authorized and shall be approved
by a separate administrative action.
Page 4
Request to Amend Area Injecttorder No. 21A •
April 14, 2015
All of the proposed injection fluids have been authorized by the Commission for injection on the
North Slope. All of the injection fluids are non -hazardous, Class II approved fluids, E & P exempt,
or products being used for their intended purpose in the wells (and not waste), and therefore
have been approved by the Commission for injection in Class II wells.
3. Performance Reporting (AIO 21A Rule 9)
Rule 9 of AIO 21A currently states: "The Operator shall submit to the AOGCC a monthly report
detailing the daily monitoring of all Meltwater Oil Pool wells. Included in the monthly report,
the Operator shall submit OA fluid levels, well pressures, injection and/or production rates, and
pressure bleeds for all annuli. Trends shall be evaluated and detailed. In addition to the
conditions listed in the above rules the Operator shall provide by April 1" of each year an
interim progress report that provides an update on the status of the overburden
characterization study, a synopsis of the monitoring data collected during the previous year, and
a detailed analysis of the effects on ultimate recovery of switching from an MWAG project, as
authorized by AIO 21, to the current MI injection only project."
CPAI requests modifying AIO 21A Rule 9 to read: "The Operator shall submit an annual synopsis
of the surveillance, monitoring, and development initiatives completed during the previous year
that pertain to the confinement of injected fluids within the Bermuda Interval together with the
Meltwater Annual Surveillance Report."
This proposed modification to Rule 9 will ensure the Commission receives an annual synopsis of
surveillance, monitoring, and development initiatives as they pertain to the containment of
injected fluids at the same time CPAI submits the Meltwater Annual Surveillance Report that is
required by Conservation Order 456, Rule 10. This modification to AIO 21A Rule 9 would
eliminate the monthly reporting requirement, yet ensure that the Commission is regularly
informed of the status and results of containment and development initiatives being pursued at
Meltwater.
4. Expiration Date (AIO 21A Rule 11)
The current AIO 21A Rule 11 states: "This order shall expire 24 months after the effective date
shown below." The expiration date for AIO 21A is May 16, 2015.
CPAI requests that the Commission remove Rule 11 from AIO 21A as surveillance and monitoring data
suggest that the implementation of the new reservoir management strategy has prevented further
migration of injected fluids out of the MOP. The existing rules in AIO 21A, together with the
aforementioned proposed amendments, will ensure long term confinement of injected fluids and
optimal hydrocarbon recovery.
Page 5
0 0
Request to Amend Area Injection Order No. 21A
April 14, 2015
Conclusions
CPAI believes the requested amendment approvals are based on sound engineering and
geoscience principles, will further mitigate the risk of the migration of injected fluids out of the
MOP, will increase ultimate hydrocarbon recovery, will not promote waste or jeopardize
correlative rights, and will not result in an increased risk of fluid movement into freshwater.
Please do not hesitate to contact me at (907) 263-4027 or Tommy Nenahlo at (907) 265-6934
should you have any questions about this request.
Kazeem A. Adegbola
Manager, GKA Development
Page 6
Request to Amend Area InjectiaTf'order No. 21A
April 14, 2015
Attachment 1: Proposed AIO 21A Amendments
A10 21A Rule 2 (Fluid Injection Wells)
Current:
"New wells and production -to -injection conversions are prohibited in the MOP."
Requested:
"Development well sidetracks are permissible when drilled within the MOP. Well
conversions are permissible in the MOP."
A10 21A Rule 8 (Authorized Fluids for Injection)
Current:
"Fluids Authorized for Injection are:
a. Miscible injectant;
b. Dry gas provided by the Kuparuk River Unit;
c. Tracer survey fluid to monitor reservoir performance;
d. Fluids injected for stimulation purposes per 20 AAC 25.280 (a)(2);
e. Glycol from hydro -tests and freeze protection;
f. Diesel used for freeze protection;
g. Methanol used for freeze protection;
h. Standard oilfield chemicals (corrosion and scale inhibitors, defoamers, emulsion
breakers, etc.);
All fluids injected must be compatible with the injection zone. Any other fluids shall be
approved in advance by separate administrative action based upon proof of
compatibility with the reservoir and formation fluids. Water provided by the Kuparuk
River Unit water injection system is currently not available and not planned for injection.
The water is not authorized for injection and shall be approved by a separate
administrative action."
Requested:
"Fluids Authorized for Injection are:
a. Miscible injectant;
b. Dry gas provided by the Kuparuk River Unit;
c. Tracer survey fluid to monitor reservoir performance;
d. Fluids injected for stimulation purposes per 20 AAC 25.280 (a)(2);
e. Glycol from hydro -tests and freeze protection;
f. Diesel used for freeze protection;
g. Methanol used for freeze protection;
h. Standard oilfield chemicals (corrosion and scale inhibitors, defoamers, emulsion
breakers, etc.);
i. Beaufort Sea water for surveillance, logging, near-wellbore formation displacements,
and well maintenance; and
j. Kuparuk River Unit produced water for surveillance, logging, near-wellbore
formation displacements, and well maintenance
Page 7
Request to Amend Area Injection Order No. 21A
April 14, 2015
All fluids injected must be compatible with the injection zone. Any other fluids shall be
approved in advance by separate administrative action based upon proof of
compatibility with the reservoir and formation fluids. Long-term injection of water
provided by the Kuparuk River Unit water injection system is currently not authorized
and shall be approved by a separate administrative action."
A10 21A Rule 9 (Performance Reporting)
Current:
"The Operator shall submit to the AOGCC a monthly report detailing the daily monitoring of all
Meltwater Oil Pool wells. Included in the monthly report, the Operator shall submit OA fluid
levels, well pressures, injection and/or production rates, and pressure bleeds for all annuli.
Trends shall be evaluated and detailed. In addition to the conditions listed in the above rules
the Operator shall provide by April 15` of each year an interim progress report that provides an
update on the status of the overburden characterization study, a synopsis of the monitoring
data collected during the previous year, and a detailed analysis of the effects on ultimate
recovery of switching from an MWAG project, as authorized by AIO 21, to the current MI
injection only project.
Requested:
"The Operator shall submit an annual synopsis of the surveillance, monitoring, and development
initiatives completed during the previous year that pertain to the confinement of injected fluids
within the Meltwater Oil Pool together with the Meltwater Annual Surveillance Report."
A10 21A Rule 11 (Expiration Date)
Current:
"This order shall expire 24 months after the effective date shown below (May 16, 2013)."
Requested:
It is requested that Rule 11 be removed and that AIO 21A have no expiration date.
Page 8
Request to Amend Area Injection Order No. 21A •
April 14, 2015
Attachment 2: Current MOP Type Log — Meltwater North 2/2A Well
Meltwater Oil Pool
AET
�(.�
LZfnn MELTWATER TYPE LOG
oll�.
Ugnu C
-
Ugnu A
'- —
Top W. Bak
pwmwftt
YO
aaw
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IMY:
4�.
so" W. Sak
C
riiq
"n4
J.n
C -40
Ci-3
WVL
i
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uaz
w>,
awa
'f
+;x
wx
srao
T-7
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Cairn
.Benbuda
,.,, •
_..lf C-3
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z
L
P,
Page 9
•
Request to Amend Area Injection Order No. 21A
April 14, 2015
Attachment 3: Meltwater Reservoir Pressures
5000
'i 4500
CL
4000
7 3500
d3000
2500
E 2000
LL
• 1500
V
E 1000
m 500
0
e �4. V IN
♦!!♦
• ♦ 11%11 00
��` • • •
•• • f • • f
H
;E
s
P
'ti I1.le *,p tie tie tie ��O 1� a L0 Le:, Le L0 Le �0 �Q,yro
F eF '0 eF eF eF 6 'de
eF ec° eF e,P eF eF eF
Oec Oec Oec Oec Oec O� 'd Oes OeC Oec OeC 1j s5 Oe- Qec
• Producers ♦ Iryectars "Bermuda formation Pressure omit 0�
Page 10
Request to Amend Area Injeco. Order No. 21A Is
April 14, 2015
Attachment 4 (Page 1 of 2): Meltwater Outer Annulus Gas Compositions
2P-406 CIA Gas Compositon, 2P-415A CIA Gas Compositon
m2PA064!28/2012
92P4I3A4/30=12
M 2P.409 IV12023 a
aR
6041mloppoa
n2P.4062126/2M4 as NVN41SA411312014
k2P40641INM 24
BI.I.ft G. c-p-ti-
- --------- -----------
•
oe Polo L�L
104P
- ----------------- ----- - ------- - ------------
2P-417 OA Gas Compositon 2P-420 OA Gas Compositon
92P-4174IM2012
-.2P4I79/ICV20I2
12P<174113V2024
lop'
2P-424A OA Gas Compositon
•
2P-024A 4/30/2012
2Fi24A 3/30J2011
02P424A911712013
s
42� "/712021
'PA24A4/3D/2014
2Ps2aA 11/26/2014
I-e Ile
2P-429 OA Gas Compositon
. M I C—POO.n
.2P429$12%12013
UIF429 10/912011
0
,GIs
2P-427 OA Gas Compositon
•
. 2P-427 SA212023
0 2PA27 7PV2013
2P427 IW12MR
2PA27 61712014
eft cwp..i
LL- ---------------- - --
L
-
0--e me 0-le '10-11 Ile oe
: t-
0�
2P-431 OA Gas Compositon
Page 11
Request to Amend Area InjectionZ)rder No. 21A 0
April 14, 2015
Attachment 4 (Page 2 of 2): Meltwater Outer Annulus Gas Compositions
2P-432 OA Gas Compositon
s�
mpoiuon
.-.,
4/10/2012._........�.....�._.9/1f/2012
EW2P-4329/1IV2M2
S%24'20131a3/20132
S/2y2014ko:c.mP
tA0
ole ole a+
2P-441 OA Gas Composkon
S �
•IP4a29J19/2012
j
S y^.
.-----...__. .._.__.._. _._..._--
•2P�sl s/2N7013
''.
I
. iP..i ia�m3
02P.4415/142014
f
■91ppn4 NCkmpeakren
I .
1
2P-449A OA Gas Compositon
�T
. Mi cornpr�,wn
• 2F 44M 4/Pi2D12
.... ..------
_..._.....___.—.-_....—.._._.._.__._._,.'-
•1PJ4M9119/2012
•2h41M4/1412023
S
k IP• MS/1/2013
1
s 2P-44M 7/2S/2011
S �
4 IP44M 30h/2025
1 +'
e 2P.44MS/27/2014
• tbpnk BktCorryoWar
f i
0
41#1Ile
2P-451 OA Gas Compositon
���-^
�—����-� - _......
kMitcmpotticn
1
■ 2F4514/30,'2037
it
S
■ 2P•4515/1/2023
t
�
92F�517/2y2013
-
1
P 2P.51 20)9/2013
1
—
€2F4524/16/2034
_
-
2P-434 OA Gas Composkon
.111 Canpos6on
1
yam—
■7P•s3a 9/lq'7012
s
a 2P-t13 c/2a�xma
at
a1Pi3430,'9/101D
1
• tft-k Or C—m ,ki.n
1
!
. .
IL
2P-40 OA Gas Cmuposkon
` _
. Mi compunen
,. .•
..
.1P-4•174/3Q'2M2
■2P•4479/29J2M2
!,..
S t'
_..,
....
• 2PA47 S/27/2014
x IPM7IIW2M4
�S
■9igaN10r L6nN0411kM`
s �
i
.._
0
Ole
4r
Page 12
Request to Amend Area Inje,*Order No. 21A
April 14, 2015
Attachment 5: Meltwater Outer Annulus Gas Isotopic Analyses
•
-42
Tarn 2N-339 - MI Gas 2P-431, OA MI 2002
Misc Inj 2M-03 2P-432, OA
2P-431, C37-C80, OA 2P-434, CA
2P-438. C37-C80. OA 2P-438, OA
2P-451, C37-C80, OA 2P-441, OA
2PAA7, OA
2P-451, OA
"
-46
2P-451, A
22P-43P-43143 18 OA
L
y
-48
2P-432, OA 2P-441. OA
r
D2P-434, OA
a2P-427,
! ■�
OA% > 2P-449, OA
0
-50
�2Pf 448, OA
in
2P-447, OA
c
2P-429, OA
O
L
m
-52
C 2P 417, OA
U
_J
-54
Increasing
O
Biog
Gass
2P-424, OA
-56
.45 .40
-35 -30
-50
Carbon Isotopes Ethane 813Cz
■ MWN-1 ,-2A
* MWN mud gas
2P production
• 212-415 Cairn sst
MI
i T4 -T7 mud gas
\ C37-C80 mud gas
+ Outer Annulus 2002
X Outer Annulus 2005
D Outer Annulus 2012
Page 13
1 0
Request to Amend Area Injection Order No. 21A
April 14, 2015
•
Attachment 6: Meltwater Oxygen -Activation Logging of Production Casing Cement Shoes
4,500
ILV
LIQ
a 3,500
a�
N 3,000
%M
a)
a 2,500
0
is 2,000
y 1,500
500
0
M
k
E
2P-419 2P-434
2P-447
Sandface Pres::g]... - ............. -
1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000
Rate (STBD)
Page 14
Revised
Public Hearing
STATE OF ALASKA
Alaska Oil and Gas Conservation Commission
Re: Docket Number: AIO 15-015
Kuparuk River Field, Meltwater Oil Pool
Amendment to AIO 21 A
The Alaska Oil and Gas Conservation Commission (AOGCC) acting pursuant to AS
31.05.030(b), hereby gives notice of a Public Hearing concerning proposed modifications
to existing Area Injection Order (AIO) 21A.000 for the Enhanced Oil Recovery
Operations.
ConocoPhillips Alaska, Inc. (CPAI) sent to AOGCC on April 1, 2015 an Interim Progress
Report "Meltwater Oil Pool Area Injection Order 21A (AIO 21A)" and held a
presentation with AOGCC Senior Staff on April 30, 2015.
CPAI, by letter dated April 14, 2015 requests to amend AIO 21 A.
AOGCC will take this opportunity to update the order and rules to reflect current
operating practices and latest regulatory requirements and conditions.
CPA as operator of the Kuparuk River Field, Meltwater Oil Pool should be prepared to
offer evidence on these matters at this hearing.
Accordingly, the AOGCC hereby gives notice that it will hold a public hearing on this
inquiry on July 9, 2015 at 9:00 a.m. in the hearing room of the AOGCC, 333 West 71h
Avenue, Anchorage, Alaska 99501.
Written comments regarding this inquiry may also be submitted to the Alaska Oil and
Gas Conservation Commission, at 333 West 7`h Avenue, Suite 100, Anchorage, Alaska
99501. Written comments must be received no later than 5:00 p.m. Alaska time June 10,
2015.
If, because of a disability, special accommodations may be needed to comment or attend
the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no
later than June 20, 2015.
Cathy P. Foerster
Chair, Commissioner
0
STATE OF ALAS"
ADVERTISING
ORDER
ADVERTISEQG ORDER NUMBER
AO-15-020
FROM:
Alaska Oil and Gas Conservation Commission
AGENCY CONTACT:
Jody Colombie/Samantha Carlisle
DATE OF A.O.
05/04/15
AGENCY PHONE:
�(907) 793-1221
333 West 7th Avenue
Anchorage, Alaska 99501
DATES ADVERTISEMENT REQUIRED:
COMPANY CONTACT NAME:
PHONE NUMBER:
Publish 5/5/15
FAX NUMBER:
(907)276-7542
TO PUBLISHER:
Alaska Dispatch News
SPECIAL INSTRUCTIONS:
PO Box 149001
Anchorage, Alaska 99514
�1 ��ltlll9 tiE
�Ifl
DESCRIPTION
..
PRICE
AIO 15-015
Initials of who prepared AO: Alaska Non -Taxable 92-600185
SUBMIT INVOICE SHOWING ADVERTISING
ORDER NO., CERTIFIED AFFIDAVIT OF
PUBLICATION WITH ATTACHED COPY OF
ADVERTISMIENT To;
Department of Administration
Division of AOGCC
333 West 7th Avenue
Anchorage, Alaska 99501
Page 1 of 1
Total of
All Pa es $
REF
Type
Number
Amount
Date
Comments
I
PvN
ADN84501
2
Ao
AO-15-020
3
4
FIN
AMOUNT
SY
CC
PGM
LGR
ACCT
FY
I DIST
LIQ
I
15
02140100
73451
15
2
3
4
5
Purcha
ing N Title:
44
Purchasing Authority's Signature
Telephone Number
1)
TRIBUTION:
Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving
Form: 02-901
Revised: 5/4/2015
270227 RECEIVE®
0001364080 S
MAY 0 8 2015
$ 234.08
"
AFFIDAVIT OF PUBLICATION
STATE OF ALASKA
THIRD JUDICIAL DISTRICT
Leesa Little
being first duly sworn on oath deposes and
says that he/she is a representative of the
Alaska Dispatch News, a daily newspaper.
That said newspaper has been approved
by the Third Judicial Court, Anchorage,
Alaska, and it now and has been published
in the English language continually as a
daily newspaper in Anchorage, Alaska,
and it is now and during all said time was
printed in an office maintained at the
aforesaid place of publication of said
newspaper. That the annexed is a copy of
an advertisement as it was published in
regular issues (and not in supplemental
form) of said newspaper on
May 05, 2015
and that such newspaper was regularly
distributed to its subscribers during all of
said period. That the full amount of the fee
charged for the foregoing publication is not
in excess of the rate charged private
individuals.
Signed
Subscribed and sworn to before me
this 5th day of May, 2015
Notary Ieylblic in and for
The State of Alaska.
Third Division
Anchorage, Alaska
MY COMMISSION EXPIRES
Revised
Public Hearing
STATE OF ALASKA
Alaska oil and Gas Conservation Commission
Re: Docket Number: AID 15-015
Kuparuk River Field, Meltwater Oil Pool
Amendment to AIO 21A
The Alaska Oil and Gas Conservation Commission (AOGCC) acting
pursuant to AS 31.05.030(b), hereby gives notice of a Public Hearing
concerning proposed modifications to existing Area Injection Order
(AID) 21A.000 for the Enhanced Oil Recovery Operations.
ConocoPhillips Alaska, Inc. (CPAI) sent to AOGCC on April 1, 2015 an
Interim Progress Report "Meltwater Oil Pool Area Injection Order 21A
(AID 21A)" and held a presentation with AOGCC Senior Staff on April 30,
2015.
CPA[, by letter dated April 14, 2015 requests to amend AIO 21A.
AOGCC will take this opportunity to update the order and rules to
reflect current operating practices and latest regulatory requirements
and conditions.
CPA as operator of the Kuparuk River Field, Meltwater Oil Pool should
be prepared to offer evidence on these matters at this hearing.
Accordingly, the AOGCC hereby gives notice that it will hold a public
hearing on this inquiry on July 9, 2015 at 9:00 a.m. in the hearing room
of the AOGCC, 333 West 7th Avenue, Anchorage, Alaska 99501.
Written comments regarding this inquiry may also be submitted to the
Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue,
Suite 100, Anchorage, Alaska 99501. Written comments must be
received no later than 5:00 P.M. Alaska time June 10, 2015.
If, because of a disability, special accommodations may be needed to
comment or attend the hearing, contact the AOGCC's Special Assistant,
Jody Colombie, at 793-1221, no later than June 20, 2015.
AO-15-020
Published: April 16, 2015
Cathy P. Foerster
Chair, Commissioner
0
Singh, Angela K (DOA)
From:
Colombie, Jody J (DOA)
Sent:
Monday, May 04, 2015 3:09 PM
To:
Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle,
Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E
(DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA);
Hunt, Jennifer L (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph
(DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B
(DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh,
Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator; Alexander
Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch;
bbohrer@ap.org; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Carrie Wong;
Cliff Posey, Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens;
David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide
Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); Donna Ambruz;
Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George
Pollock, ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Hulme,
Rebecca E (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren;
Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW);
Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R
(DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari
Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR);
Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT
sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman;
Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan;
Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200;
Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com;
Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro;
Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady;
Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott
Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane
P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie
Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson;
Sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence
Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; Tony Hopfinger; trmjrl;
Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; Aaron Gluzman; Aaron
Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline
J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Donna Vukich; Eric Lidji; Erik
Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR);
Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson;
jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred;
Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W
(DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill;
Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Peter Contreras; Richard
Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Peterson,
Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Todd, Richard J (LAW); Tostevin, Breck
C (LAW); Wayne Wooster, William Hutto; William Van Dyke
Subject:
Revised Notice of Public Hearing, AIO-15-015
Attachments:
Revised Notice of Public Hearing, AIO-15-015.pdf
Amended Docket Number a added the time of the hearing.
0
James Gibbs Jack Hakkila
Bernie Karl
P.O. Box 1597 P.O. Box 190083
K&K Recycling Inc.
Soldotna, AK 99669 Anchorage, AK 99519
P.O. Box 58055
Fairbanks, AK 99711
Gordon Severson
Penny Vadla
George Vaught, Jr.
3201 Westmar Cir.
399 W. Riverview Ave.
P.O. Box 13557
Anchorage, AK 99508-4336
Soldotna, AK 99669-7714
Denver, CO 80201-3557
Kazeem A. Adegbola
Manager, GKA Development
Richard Wagner
Darwin Waldsmith
North Slope Operations and Development
P.O. Box 60868
P.O. Box 39309
ConocoPhillips Alaska, Inc.
Fairbanks, AK 99706
Ninilchik, AK 99639
Office: ATO-1326
700 G St.
Anchorage, AK 99501
vou-4 : Le
NIaY �{ � 20 t5
Angela K. Singh
Public Hearing
STATE OF ALASKA h
Alaska Oil and Gas Conservation Commission \
Re: Docket Number: AIO 15 005�
Kuparuk River Field, Meltwater Oil Pool ^ n
Amendment to AIO 21 A l'
The Alaska Oil and Gas Conservation Commission (AOGCC) acting p suAt to AS
31.05.030(b), hereby gives notice of a Public Hearing concerning propo d modifications
to existing Area Injection Order (AIO) 21 A.000 for the Enha ed Oil Recovery
Operations.
ConocoPhillips Alaska, Inc. (CPAI) sent to AOGCC on Apr , 2015 an Interim Progress
Report "Meltwater Oil Pool Area Inj/aend
A (AIO 21A)" and held a
presentation with AOGCC Senior Staff o
CPAI, by letter dated April 14, 2015 requAIO 21A.
AOGCC will take this opportunity to rder and rules to reflect current
operating practices and latest regulatory rnd conditions.
CPA as operator of the Kuparuk Riy6r Field, Meltwater Oil Pool should be prepared to
offer evidence on these matters at Ofis hearing.
Accordingly, the AOGCC he by gives notice that it will hold a public hearing on this
inquiry on July 9, 2015 at in the hearing room of the AOGCC, 333 West 7th Avenue,
Anchorage, Alaska 99
Written comments garding this inquiry may also be submitted to the Alaska Oil and
Gas Conservation ommission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska
99501. Writte omments must be received no later than 5:00 p.m. Alaska time June 10,
2015.
If, beca e of a disability, special accommodations may be needed to comment or attend
the ring, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no
lat,ef than June 20, 2015.
/—Zqe�
Cathy . Foerster
Chair, Commissioner
STATE OF ALASKA
ADVERTISING ORDER NUMBER
ADVERTISING
ORDER
AO-15-019
FROM:
AGENCY CONTACT:
Jody Colombie/Samantha Carlisle
Alaska Oil and Gas Conservation Commission
DATE OF A.O.
AGENCY PHONE:
333 West7th Avenue
04/30/15
1(907) 793-1221
Anchorage, Alaska 99501
DATES ADVERTISEMENT REQUIRED:
COMPANY CONTACT NAME:
PHONE NUMBER:
Publish 5/4/15
FAX NUMBER:
(907)276-7542
TO PUBLISHER:
SPECIAL INSTRUCTIONS:
Alaska Dispatch News
PO Box149001
Anchorage, Alaska 99514
qm "Pi
1�
DESCRIPTION
PRICE
AIO 15-005
Initials of who prepared AO:
Alaska Non -Taxable 92-600185
Department of Administration
SUBMIT INVOICE SHOWING ADVERTISING.
Division AOGCC
ORDER NO., CERTIFIED AFFIDAVIT OF
of
PUBLICATION WITH ATTACHED COPY OF
333 West 7th Avenue
Total of
ADVERTISMENT TO:
Anchorage, Alaska 99501
Page 1 of 1
All Pa es $
REF
Type
Number
Amount
Date
Comments
1
PvN
ADN84501
2
Ao
AO-15-019
3
4
FIN
AMOUNT
SY
CC
PGM
LGR ACCT
FY
DIST
LIQ
I
15
02140100
73451
15
2
3
4
Purc a ine: T le:
as' g thority's Signature Telephone Number
DISTRIBUTION:
Division Fiscal/Original AO
Copies:Publisher (faxed), Division Fiscal, Receiving
Form:02-901
Revised: 4/30/2015
270227 0001363950 RECEIVED
$ 229.10 MAY 0 8 2015
AFFIDAVIT OF PUBLICATIONAOGCC
STATE OF ALASKA
THIRD JUDICIAL DISTRICT
Leesa Little
being first duly sworn on oath deposes and
says that he/she is a representative of the
Alaska Dispatch News, a daily newspaper.
That said newspaper has been approved
by the Third Judicial Court, Anchorage,
Alaska, and it now and has been published
in the English language continually as a
daily newspaper in Anchorage, Alaska,
and it is now and during all said time was
printed in an office maintained at the
aforesaid place of publication of said
newspaper. That the annexed is a copy of
an advertisement as it was published in
regular issues (and not in supplemental
form) of said newspaper on
May 04, 2015
and that such newspaper was regularly
distributed to its subscribers during all of
said period. That the full amount of the fee
charged for the foregoing publication is not
in excess of the rate charged private
individuals.
Signed..�,��
Subscribed and sworn to before me
this 4th day of May, 2015
Notary Publ1d in and for
The State of Alaska.
Third Division
Anchorage, Alaska
MY COMMISSION EXPIRES
Public Hearing
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Re: Docket Number: CO-14-OAIO 15-005
Kuparuk River Field, Meltwater Oil Pool
Amendment to AID 21A
The Alaska Oil and Gas Conservation Commission (AOGCC) acting
purscconcerning nt to propos d modificationhereby
towexisting es A eace of aPublic injeccton Order
(AID) 21A.000 for the Enhanced Oil Recovery Operations.
ConocoPhillipS Alaska, Inc. (CPAI) sent to AOGCC on April 1, 2015 an
Interim Progress Report "Meltwater oil Pool Area Injection Order 21A
(AIO 21A)" and held a presentation with AOGCC Senior Staff on April 30,
2015.
CPAI, by letter dated April 14, 2015 requests to amend AID 21A.
AOGCC will take this opportunity to update the order and rules to
reflect current operating practices and latest regulatory requirements
and conditions.
CPA as operator of the Kuparuk River Field, Meltwater Oil Pool should
be prepared to offer evidence on these matters at this hearing.
Accordingly, the AOGCC hereby gives notice that it will hold a public
hearing on this inquiry on July 9, 2015 at a.m. in the hearing room of
the AOGCC, 333 West 7th Avenue, Anchorage, Alaska 99501.
Written comments regarding this inquiry may also be submitted to the
Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue,
Suite 100, Anchorage, Alaska 99501. Written comments must be
received no later than 5:00 P.M. Alaska time June 10, 2015.
If, because of a disability, special accommodations may be needed to
comment or attend the hearing, contact the AOGCC's Special Assistant,
Jody Colombie, at 793-1221, no later than June 20, 2015,
AO-15-019
Published: May 4, 2015
f-
Cathy P. Foerster
Chair, Commissioner
Singh, Angela K (DOA)
From:
Colombie, Jody J (DOA)
Sent:
Monday, May 04, 2015 1:03 PM
To:
Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle,
Samantha 1 (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E
(DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA);
Hunt, Jennifer L (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph
(DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqua[, Maria (DOA); Regg, James B
(DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh,
Angela K (DOA); Wallace, Chris D (DOA); AKDCWe[[IntegrityCoordinator; Alexander
Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch;
bbohrer@ap.org; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Carrie Wong;
Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens;
David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide
Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); Donna Ambruz;
Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf; George
Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Hulme,
Rebecca E (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren;
Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW);
Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R
(DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari
Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR);
Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT
sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt, Mark Wedman;
Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan;
Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200;
Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com;
Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Patty Alfaro;
Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady;
Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott
Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane
P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie
Klemmer; Sternicki, Oliver R, Moothart, Steve R (DNR); Suzanne Gibson;
Sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence
Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; Tony Hopfinger; trmjrl;
Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; Aaron Gluzman; Aaron
Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline
J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Donna Vukich; Eric Lidji; Erik
Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR);
Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson;
jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred;
Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez, Lois Epstein; Longan, Sara W
(DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill;
Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Peter Contreras; Richard
Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Peterson,
Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Todd, Richard J (LAW); Tostevin, Breck
C (LAW); Wayne Wooster; William Hutto; William Van Dyke
Subject:
Public Hearing Notice KRU, Meltwater Amendment AIO 21A
Attachments:
Notice of Public Hearing AIO-15-005.pdf
0
0
James Gibbs Jack Hakkila
Bernie Karl
P.O. Box 1597 P.O. Box 190083
K&K Recycling Inc.
Soldotna, AK 99669 Anchorage, AK 99519
P.O. Box 58055
Fairbanks, AK 99711
Gordon Severson
Penny Vadla
George Vaught, Jr.
3201 Westmar Cir.
399 W. Riverview Ave.
P.O. Box 13557
Anchorage, AK 99508-4336
Soldotna, AK 99669-7714
Denver, CO 80201-3557
Kazeem A. Adegbola
Manager, GKA Development
Richard Wagner
Darwin Waldsmith
North Slope Operations and Development
P.O. Box 60868
P.O. Box 39309
ConocoPhillips Alaska, Inc.
Fairbanks, AK 99706
Ninilchik, AK 99639
Office: ATO-1326
700 G St.
Anchorage, AK 99501
,-A-",�'eCL
IAl2,( A-1 t 2O 15
Angela K. Singh.
