Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
Loading...
HomeMy WebLinkAboutO 081Image Project Order File Cover Page
XHVZE
This page identifies those items that were not scanned during the initial production scanning phase..
They are available in the original file, may be scanned during a special rescan activity or are viewable
by direct inspection of the file.
U CO:r ` Order File Identifier
Organizing (done)
RESCAN
❑ Color Items:
❑ Greyscale Items:
❑ Poor Quality Originals:
❑ Other:
9'Two.,,ae< IIIIIIIII!IIIIIIIII
DIGITAL DATA
❑ Diskettes, No.
❑ Other, No/Type:
ae=canNaeaea iiiuuiiAiuiui
OVERSIZED (Scannable)
❑ Maps:
❑ Other Items Scannable by
a Large Scanner
OVERSIZED (Non -Scannable)
❑ Logs of various kinds:
NOTES: 6�2 ❑ Other::
BY: Angela Date: �312�'��C /s/
Project "ect Proofing
BY: Angela Date: \3« /s/
Scanning Preparation x 30 = + = TOTAL PAGES kU—(
(Count does not include cover sheet)
BY: Angela '� Date: Qll3i2o�'t /s/ G%<—
Production Scanning
Stage 1 Page Count from Scanned File: \ft`� (Count does include cover sheet)
Page Count Matches Number in Scanning Preparation: ✓ YES NO
BY: Angela
Date: 2-#'*\3t2"\--(- /s/ G
Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO
BY: Angela Date: /s/
1111111111111111111
Scanning is complete at this point unless rescanning is required.
ReScanned III IIIIIIIIIII IIIII
BY: Angela Date: /s/
Comments about this file: Quality Checked III IIIIII III IIII III
INDEX OTHER ORDER NO. 81
Kuparuk River Unit 3Q-16
Failure to complete a Mechanical Integrity Test
Failure to report to AOGCC a pressure communication
1. November 13, 2012
Email from CPAI to AOGCC regarding KRU 3Q-16
notification (failure to complete a Mechanical Integrity
Test)
2. December 21, 2012
Letter from AOGCC to CPAI regarding Notice of Proposed
Enforcement Action — Failure to complete a MIT and to
report to AOGCC a pressure communication (3Q-16)
3. January 7, 2013
Email correspondence between CPAI and AOGCC
regarding CPAI's request for extension of deadline for
CPAI's response to AOGCC's proposed enforcement
action for 3 Q-16
4. January 14, 2013
Letter from CPAI to AOGCC regarding CPAI does not
concur with AOGCC's proposed enforcement action and
requests an informal review to be scheduled
5. January 16, 2013
Letter from AOGCC to CPAI regarding informal review
meeting scheduled for January 30, 2013
6. January 30, 2013
CPAI Informal Review 3Q-16 Sign -in Sheet and CPAI's
Agenda
7. May 9, 2013
CPAI's Application for Reconsideration of Order No. 81
(Kuparuk River Unit 3 Q-16)
8. June 4, 2013
Notice of Public Hearing; Affidavit of Publication, email
distribution, and mailing
9. August 13, 2013
Emails between CPAI and AOGCC regarding August 20
public hearing
10. August 20, 2013
Public hearing transcript, sign -in sheet, scheduling order
(continuing hearing until September 11, 2013), May 16,
2013 order upon reconsideration, email between CPAI and
AOGCC regarding schedule coordinating, April 16, 2013
proposed order including CPAI's certified return receipt
11. August 23, 2013
MIT Kuparuk River Unit 3Q-16
12. September 11, 2013
Public hearing transcript, sign -in sheet, CPAI's exhibit
13. October 17, 2013
CPAI's response with requested documents to Order No.
81 issued on October 3, 2013
14. October 18, 2013
Copy of CPAI's civil penalty payment check in the amount
of $45,000
E
•
INDEX OTHER ORDER NO. 81
Kuparuk River Unit 3Q-16
Failure to complete a Mechanical Integrity Test
Failure to report to AOGCC a pressure communication
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West Seventh Avenue, Suite 100
Anchorage Alaska 99501-3539
Re: Failure to complete a Mechanical Integrity Test (MIT)
Failure to report to AOGCC a pressure communication Other Order No. 81
Kuparuk River Unit 3Q-16 October 3, 2013
(KRU 3Q-16) (PTD 1861790)
FINAL DECISION AND ORDER
On December 21, 2012, the Alaska Oil and Gas Conservation Commission (AOGCC or
Commission) issued a Notice of Proposed Enforcement Action (Notice) to ConocoPhillips
Alaska, Inc. (CPAI) regarding the 3Q-16 well of the Kuparuk River Unit (KRU). The Notice
advised that CPAI failed to complete a Mechanical Integrity Test (MIT) and failed to report to
AOGCC a pressure communication in well KRU 3Q-16. The Notice proposed specific
corrective actions and a $45,000 civil penalty under AS 31.05.150(a).
CPAI requested an informal review. That review was held January 30, 2013. Order 81
was issued April 16, 2013. On May 9, 2013, CPAI submitted an application for reconsideration
which was granted by AOGCC on May 16, 2013. The reconsideration hearing was scheduled
and held August 20, 2013 at which time it was continued and held September 11, 2013.
A. Summary of Proposed Enforcement Action
The Notice identified violations by CPAI of Rule 6 of Area Injection Order 2B (AIO
213) ("Demonstration of Tubing/Casing Annulus Mechanical Integrity"), the provisions of
Rule 7 of AIO 2B ("Well Integrity Failure") and 20 AAC 25.402(f). A violation occurred
Other Order #81
Page 2 of 7
0 October 3, 2013
every day after September 25, 2012 that CPAI injected into KRU 3Q-16 without completing an
MIT. A violation also occurred when CPAI failed to report to AOGCC a pressure
communication indicating a potential loss of mechanical integrity on KRU 3Q-16 by the next
working day. The Notice proposed the following corrective actions be completed by CPAI:
(1) within 2 weeks from the effective date of the AOGCC's final decision, CPAI
shall provide a detailed description of its Underground Injection Control
(UIC) regulatory compliance program;
(2) within 2 weeks from the effective date of the AOGCC's final decision, CPAI
shall provide details of its tracking system for determining when MIT's
are required, including the details of contingencies for wells shut in at the
time an MIT is due and its procedures for notification to the AOGCC, as
well as its processes for determining the MIT due date and identification
of past due wells; and
(3) within 2 weeks from the effective date of the AOGCC's final decision, CPAI
shall complete and provide the results of a root cause analysis addressing
the violations.
The Notice proposed civil penalties of $45,000 ($10,000 for the initial violation — failure
to perform the required MIT of the injection well in compliance with the testing protocols
specified in Rule 6 of AIO 213, $500 for each day September 26, 2012 to November 1, 2012 (37
days) for injecting in a well out of compliance with MIT regulations, and $500 for each day from
October II through November 12, 2012 inclusive (33 days) for failing to notify AOGCC of
indications of pressure communication or leakage in KRU 3Q-16).
Other Order #81 October 3, 2013
Page 3 of 7
B. Demonstration of Tubing/Casing Annulus Mechanical Integrity
Rule 6 of AIO 2B states "A schedule must be developed and coordinated with the
Commission, which ensures that the tubing/casing annulus for each injection well is pressure
tested prior to initiating injection and at least once every four years thereafter. "
The last AOGCC-witnessed MIT occurred September 25, 2008. Therefore an MIT was required
on or before September 25, 2012. No MIT was timely performed. The well was out of
compliance, but continued injection for 37 days, from September 26, 2012 to November 1, 2012
inclusive.
CPAI failed to demonstrate the mechanical integrity of injection well KRU 3Q-16 within the
required four year cycle, a violation of State regulations and AIO 2B.
C. Well Integrity Failure
Under AOGCC regulations, "If an injection rate, operating pressure observation, or
pressure test indicates pressure communication or leakage in any casing, tubing, or packer, the
operator shall notify the commission by the next working day... "
Rule 7 of AIO 2B states "Whenever operating pressure observances or pressure tests indicate
pressure communication or leakage of any casing, tubing or packer, the operator must notify the
Commission on the first working day following the observation, obtain Commission approval of
a plan for corrective action, and when an USDW is not endangered, obtain Commission
approval to continue injection. "
Other Order #81
Page 4 of 7
0 October 3, 2013
The only notice of potential pressure communication is an email from CPAI sent
November 13, 2012. Review of the TIO plots (pressure data from May 28, 2012 to November
12, 2012) indicate significant pressure anomalies which were not communicated to the AOGCC.
Significant inner annulus (IA) pressure decreases occurred from September 8, 2012 to October 2,
2012. On October 3, 2012 the IA pressure increased 650 psi to 2300 psi from the October 2,
2012 reading of 1650 psi. Incremental increases and sustained IA pressure were exhibited from
October 10, 2012 until the well was shut in November 13, 2012. Potential pressure
communication after October 10, 2012 demonstrates ongoing non-compliance with reporting
requirements from October 11, 2012 to November 12, 2012 inclusive.
CPAI failed to report to AOGCC a pressure communication indicating a potential loss of
mechanical integrity on KRU 3Q-16 by the next working day, a violation of State regulations
and AIO 2B.
D. Violations.
An MIT on KRU 3Q-16 was required no later than September 25, 2012. As of
September 25, 2012 no MIT had been performed on KRU 3Q-16. By email dated November 13,
2012 CPAI notified the AOGCC that KRU 3Q-16 was returned to injection on August 22, 2012
and ceased taking injection November 1, 2012, and was shut in November 13, 2012. Although
CPAI indicated a root cause analysis was performed and outlined the changes made in order to
avoid similar violations in the future, CPAI did not provide the Commission with its root cause
analysis.
Other Order #81 •
Page 5 of 7
• October 3, 2013
CPAI's November 13, 2012 email notification also states "the TIO plots suggests TxIA2
communication based on the slowly building IA pressure". The November 13 email was the first
communication AOGCC received from CPAI regarding pressure anomalies. However, TIO
plots (pressure data from May 28, 2012 to November 12, 2012) indicate significant pressure
anomalies which were not communicated to the AOGCC. Although CPAI was aware of this
information, it determined that the anomalies did not indicate pressure communication.
E. Mitigating Circumstances
The commission considered the factors in AS 31.05.150(g) in determining the
appropriate penalty. The penalty was reduced due to CPAI's general history of satisfactory
compliance and practices, an aquifer exemption for the KRU, the lack of actual threat to public
health or the environment, CPAI's eventual notification to AOGCC, and CPAI's shut-in of the
KRU 3Q-16 once CPAI determined the well was out of compliance. However, as to the missed
MIT, the commission reviewed Order 36 from 2005 for CPAI's missed MIT on CD1-19A and a
Notice of Violation to CPAI for a missed MIT on 3H-12A in April 2012. As to the pressure
anomalies, CPAI's internal "determination" that those anomalies did not constitute
communication effectively prevented the Commission's review of the issue.
' TIO plot is a graphical representation of the well's tubing, inner annulus, and outer annulus pressures over a
specified time period.
2 TxIA = tubing by inner annulus
Other Order #81 •
Page 6 of 7
F. Findings and Conclusions
0 October 3, 2013
The Commission finds that CPAI violated the regulations and the Rules in AIO 2B
governing the Demonstration of Tubing/Casing Annulus Mechanical Integrity and Well Integrity
Failure. Mitigating circumstances outlined above were considered in the Commission's Notice
of Enforcement Action and its assessment as to the appropriate civil penalty, which was
decreased from the maximums provided by statute. CPAI presented nothing during the hearing
which would warrant a change in the proposed order.
NOW THEREFORE IT IS ORDERED THAT:
1. Within 30 days after this Decision and Order becomes final, CPAI shall pay the Commission a
civil penalty of $45,0003:
2. Within 2 weeks after this Decision and Order becomes final, CPAI shall:
(1) provide a detailed description of its Underground Injection Control (UIC) regulatory
compliance program;
(2) provide details of its tracking system for determining when MIT's are required,
including the details of contingencies for wells shut in at the time an MIT is due and its
procedures for notification to the AOGCC, as well as its processes for determining the
MIT due date and identification of past due wells;
3 AS 31.05.150(a) provides for not more than $100,000 for the initial violation and not more than $10,000 for each
day thereafter on which the violation continues.
Other Order #81
Page 7 of 7
• October 3, 2013
(3) provide CPAI's root cause analysis addressing the violations.
Done at Anchorage, Alaska and dated October 3, 2013
4
Cathy P. Fo rster, C air, Commissioner
Alaska Oil and Gas Conservation Commission
Daniel T. Seamount, Jr., Commissioner
Alaska Oil and.Gas Conservation Commission
a, Commissioner
Gas Conservation Commission
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
Commission grants for good cause shown, a person affected by it may file with the Commission 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 Commission 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 Commission 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 Commission mails, OR 30 days if the Commission 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 Commission 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 Commission, and it may be appealed to superior court. That
appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission 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 Commission 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:
Monday, October 07, 2013 2:12 PM
To:
Singh, Angela K (DOA); Ballantine, Tab A (LAW); Bettis, Patricia K (DOA); Brooks, Phoebe
L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA);
Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA);
Grimaldi, Louis R (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Jones, Jeffery
B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); Mumm, Joseph (DOA
sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA);
Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, lames B (DOA); Roby, David S
(DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA);
Wallace, Chris D (DOA); (michaelj.nelson@ conocophi Ili ps.com);
AKDCWellIntegrityCoordinator; Alexander Bridge; Andrew VanderJack, Anna Raff;
Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill
Walker, Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller; Crandall,
Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens;
David Duffy; David Goade; David House; David Scott; David Steingreaber; Davide
Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt;
Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Schultz, gary (DNR
sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady;
gspfoff; Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones,
Jeffery B (DOA); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Lastufka;
news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L
(GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith
Wiles; Kelly Sperback; Kiorpes, Steve T; Klippmann; 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 P. Worcester; Kremer,
Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy
Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover;
Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini;
Pike, Kevin W (DNR); Pioneer; Randall Kanady; Randy L. Skillern; Randy Redmond; Rena
Delbridge; Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Sandra
Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon
Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe;
Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR);
Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer;
Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Tina
Grovier (tmgrovier@stoel.com); Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter
Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Anne
Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; David Martin;
Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O
(PCO); Greg Mattson; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason
Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo;
King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Marc Kuck; Steele, Marie C (DNR);
Matt Armstrong; Matt Gill; Franger, James M (DNR); Bettis, Patricia K (DOA); Peter
Contreras; Pollet, Julie; Richard Garrard; Ryan Daniel; Sandra Lemke; Pexton, Scott R
(DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Wayne Wooster;
Woolf, Wendy C (DNR); William Hutto; William Van Dyke
Subject:
Other Order 80
Attachments:
other081.pdf
Jody). Colombie
Special Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Avenue
Anchorage, Alaska 99501
(907) 793-1221
(907) 276-7542
Easy Peel® Labels i ♦ Bend along line to I i 1 AVERY® 596OTM I
Use Avery® Template 5160® feed Paper �� expose Pop-up Edger""0 IJ 1
Jill A. McLeod
Legal Counsel
ConocoPhillips Alaska, Inc.
Post Office Box 100360
Anchorage, AK 99510-0360
ttiquettes fadles a peler i ♦ ftepliez a la hachure afin de ; www.averycom
Utilisez le gabarit AVERY® 51600 ; 'h;erve de%„• reveler le rebord Pop-upTm ; 1-800-GO-AVERY
Easy Peel® Labels
Use Avery® Template 5160e
Penny Vadla
399 W. Riverview Ave.
Soldotna, AK 99669-7714
Jerry Hodgden
Hodgden Oil Company
408 IS" St.
Golden, CO 80401-2433
Bernie Karl
K&K Recycling Inc.
Post Office Box 58055
Fairbanks, AK 99711
North Slope Borough
Planning Department
Post Office Box 69
Barrow, AK 99723
Jack Hakkila
Post Office Box 190083
Anchorage, AK 99519
A 1"M Send along line to
0 Feed Paper expose Pop-up Edger^
David McCaleb
IHS Energy Group
GEPS
5333 Westheimer, Ste. 100
Houston, TX 77056
Richard Neahring
NRG Associates
President
Post Office Box 1655
Colorado Springs, CO 80902
CIRI
Land Department
Post Office Box 93330
Anchorage, AK 99503
Richard Wagner
Post Office Box 60868
Fairbanks, AK 99706
Darwin Waldsmith
Post Office Box 39309
Ninilchik, AK 99639
A19E t7
George Vaught, Jr.
Post Office Box 13557
Denver, CO 80201-3557
Mark Wedman
Halliburton
6900 Arctic Blvd.
Anchorage, AK 99502
Baker Oil Tools
795 E. 94" Ct.
Anchorage, AK 99515-4295
Gordon Severson
3201 Westmar Cir.
Anchorage, AK 99508-4336
James Gibbs
Post Office Box 1597
Soldotna, AK 99669
ttiquettes'faciles a peter ; ® Repliez a la hachure afin de ; www.avery.com p
..._�.-_- I- wksonare Z!9cne i Sens de ie ,. 11—A a...,_,. -TM 11_Qnn_Cn_avciov t
#14
47
This check was issued by ConocoPhillips Alaska Inc
DATE INVOICE(DESCRIPT) CO DOCUMENT NO. GROSS DISCOUNT NET
10/17/13 OTHER ORD #81 YA 1200015245 USD 45,000.00 0.00 45,000.00
Other Order No 81 - Kuparuk River Unit 3Q-16 (KRU 3Q-16) (PTD 1861790)
PAYEE NUMBER CHECK DATE CHECK NO CHECK AMOUNT
71474 10/18/2013 00016688 45000.00
If you have questions about this check, call (918)661-5746
or logon to https://vis.conocophillips.com.
ConocoPhillips is currently adopting direct deposit (ACH) as our primary
tool for payment in place of checks. Please access the following
website http://vendors.conocophillips.com/EN/payment/Pages/index.aspx
for application instructions. Your prompt response is greatly appreciated.
REGEir.0
OCT 21 2013
1 OG%OC
THIS IS WATERMARKED PAPER. DO NOT ACCEPT WITHOUT NOTING WATERMARK -_HOLD TO LIGHT TO VERIFY WATERMARK
Deutsche Bank Trust
Company Delaware
71474
PAY TO THE ORDER OF
62-38/311
ConocoPhillips Alaska Inc Check No: 00016688
Anchorage, AK 99510
EXACTLY
STATE OF ALASKA AOGCC
333 W 7TH AVE STE 100
ANCHORAGE, AK 99501-3539
10/18/2013 00016688 $45,000.00*
****45000 US Dollars and 00 Cents****
Treasurer
115000 166881I' i:0 3 1 100 38011:
00538732110
#13
1-1
ConocoPhillips
Alaska, Inc.
October 17, 2013
Ms. Cathy Foerster
Mr. Daniel Seamount, Jr.
Mr. John Norman
Commissioners
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
Dear Commissioners,
Re: Order No. 81 (KRU 3Q-16) (PTD 1861790)
RECEIVED
0 C T 17 2013
AOGCC
Michael Wheatall
Manager
Drilling & Wells Alaska
700 G Street, ATO 1520
Anchorage, AK 99501
Phone 907 263 4585
Michael.wheatall@cop.com
In accordance with the Alaska Oil and Gas Conservation Commission's ("AOGCC'� Final Decision and Order No. 81
("Order's issued on October 3, 2013, ConocoPhillips Alaska, Inc. ("ConocoPhillips") provides the following documents in
compliance with the requirements set out in paragraph 2 of the Order. Please find enclosed:
1. Attachment A: Attachment A includes:
a. A detailed description of ConocoPhillips' Underground Injection Control (UIC) regulatory compliance
program (paragraph 2(1) of the Order).
b. This document also incorporates the details of ConocoPhillips' MIT tracking system for determining when
MITs are required, the detail of contingencies for shut-in wells, its procedures for notification to the
AOGCC as well the processes for determining the MIT due date and identification of past due wells
(paragraph 2(2) of the Order).
2. Attachment B: ConocoPhillips' root cause analysis for the missed MIT violation (paragraph 3 of the Order).
3. Attachment C: ConocoPhillips' root cause analysis for the failure to timely report violation (paragraph 3 of the
Order).
Please be advised that ConocoPhillips is processing the payment for the civil penalties in the amount of $45,000, which
payment is due on November 4 in accordance with paragraph 1 of the Order. We will submit this payment as soon as it
is available and before the payment deadline set out in the Order.
�Siincerely,
IVf� 01
Michael Wheatall
Manager
Drilling & Wells Alaska
MW:db
Attachments
Cc: N. G. Olds ATO 2120
C. Alvord ATO 1570
T. D. Green ATO 1020
Enclosures: Attachment A: ConocoPhillips Alaska, Inc.'s UIC Class II Injection Wells Compliance Management System
Attachment B: ConocoPhillips Alaska, Inc.'s Process Safety LCA: 3Q-16 MIT Delay Causing AOGCC NOV (Supplemented)
Attachment C: ConocoPhillips Alaska, Inc.'s Process Safety LCA: 3Q-16 Not Timely Reporting Causing AOGCC Violation
0 Attachment A
ConocoPhillips Alaska, Inc.
Well Integrity Group
UIC Class II Injection Wells Compliance Management System
The Environmental Protection Agency (EPA) Underground Injection Control (UIC) Program is
responsible for regulating the construction, operation, permitting and closure of injection wells.
The State of Alaska acquired primary enforcement responsibility, or primacy, for the control of
underground injection related to the recovery and production of oil and gas. The Alaska Oil and
Gas Conservation Commission (AOGCC) was granted authority by the EPA to oversee injection
activities for Class II injection wells in Alaska. Wells subject to UIC compliance are located in
every CPAI operating area in Alaska, including both the North Slope and Cook Inlet areas.
ConocoPhillips Alaska (CPAI) operates both Class II injection wells that place fluids
underground for Enhanced Oil Recovery (EOR) and Class I disposal wells for disposal of waste
from production operations. The EPA retained oversight of Class I disposal wells and Class I
wells will not be addressed in this review.
CPAI has a robust UIC Class II compliance management system that complies with all statutes
and regulations related to Class II injection wells, including the AOGCC Regulations, Area
Injection Orders and CPAI Policies and Guidelines. Specifically, injection well integrity, testing,
and monitoring are managed within the overarching Area Injection Orders (AIO) for each field
and in compliance with all state statutes and regulations. Additionally injection wells are
internally governed by the CPAI Well Operating Guidelines (WOGs). The WOGs outline normal
operating parameters for each well type and provide instructions for notification and actions
when a well falls outside normal operating parameters. These guidelines set out an operating
range to allow for thermal expansion under normal operations. Leaks and suspected
communication are not allowed under the CPAI WOGs. Any suspected or confirmed
communication must be reported to the Problem Well Supervisor (PWS) as soon as it is
observed. The PWS must in turn report suspected and/or confirmed communication to the
AOGCC within one working day of the initial observance, as required in the regulations and the
various AIOs.
In order to track the compliance of individual wells with the regulatory requirements (including
Area Injection Order requirements and WOG requirements, CPAI has implemented a
sophisticated UIC Compliance Management System (CMS). The CPAI UIC CMS uses the
AnnComm database (ACDB) to document and report the status and condition of each well. The
IP21 supervisory control and data acquisition (SCADA) computer system is used to
electronically monitor and control each well, and communicate the current status of all wells to
the field personnel. The CPAI UIC CMS is a portion of the overarching CPAI Well Integrity
Management System (WIMS), including tracking of MITs, which is managed using a
combination of the ACDB reports and an Excel spreadsheet (known as the Overdue MIT
Tracking Spreadsheet), which is a subset of the ACDB data. With the addition of the Industry
Guidance Bulletin 10-002 (prior to the adoption of 10-02A) the data management and tracking
systems have become increasingly more complex.
WIMS
As stated above, the CPAI UIC CMS is a portion of the overarching WIMS. This system
consists of a network of databases, the SCADA system, regulatory requirements, WOGs and
manpower. The WIMS has been developed to ensure that all wells are operated within well
design envelope operating ranges and regulations. The WIMS also provides a structured
0 •
process to identify and evaluate wells with suspected mechanical integrity issues in a timely and
consistent manner.
ACDB
The primary database in the WIMS is ACDB. It uses an Oracle database as storage repository
and a frontend computer program that allows the tracking, trending, and reporting of the various
types of Well Integrity data that are stored in the repository and/or in the IP21 SCADA computer
system. ACDB is used to keep all well events, operating pressures, well status, and compliance
testing easily accessible in one location. The majority of the information in ACDB can be
viewed from the CPAI intranet. Additionally, ACDB is available on laptops to enable well
intervention research by the Technicians out in the field. Well intervention events and barrier
testing results are manually entered by the Technicians as they occur or daily by the PWS if the
work was completed by another group. When ACDB is connected to the CPAI computer
network, pressure data, production time events and bleeds are automatically pulled on demand
from IP21 for trending into the ACDB. The ACDB program has a variety of canned and user
defined report building capabilities. These reports are manually initiated. One such report
documents the due dates of required MITs on injection wells.
ACDB is used to comply with Class II/UIC program by tracking and trending the status of each
injection well. Additionally ACDB is used to document and provide reporting of due dates for
MITs and other compliance testing.
SCADA
Most Kuparuk well and facility operations are controlled by a SCADA system known as IP21. It
is a computer controlled system that monitors and controls well and plant operations and
processes. A SCADA system gathers information, such as high injection pressure, transfers the
information back to a central control room, alerting operations when any problem occurs so they
can carry out necessary analysis and response. It also displays any information, alert set
points, pressure temperature trends, etc. in a logical and organized fashion. All pressure data
for every well is entered into the IP21 at least daily though one of three methods (manually,
automatic or a combination of both manual and automatic.
IP21 sends a daily computer automated report via email to the Production Engineer (PE),
Drillsite Lead Tech (DSLT), and the PWS of any well that is not with in normal WOGs pressure
ranges. Any well that shows up on this report is reviewed for anomalies every day. Operations
and Downhole Diagnostic Technicians (DHD) document all annulus bleed events in the IP21
system. Additionally the well integrity status of each well in the field is transmitted to Operations
from ACDB to IP21 for seamless communication.
The SCADA system, with email automated alerts, is used to notify the PE, DSLT and PWS of
any issues, including out of operating range anomalies. Since thermal changes create
significant impacts, each alert and subsequent pressure trend is reviewed for validity and
appropriate response.
MIT Tracking Process Description
As mentioned above, CPAI generates a variety of reports from the ACDB. Two of the most
frequently used ACDB reports are for tracking MIT due dates. As a direct result of the
implementation of the original Guidance Bulletin 10-002, CPAI supplemented the ACDB
generated MIT reports with an Excel spreadsheet known as the Overdue MIT Tracking
Spreadsheet to enhance the tracking of MIT due dates. A description of the MIT tracking lists
follows:
2
• 0
1. ACDB Normal Injection Wells List: This is an ACDB generated list for injection wells which
are on a 4-year test cycle. The list is sorted by the due date of the next required MIT. The
list is used to plan and schedule MITs by pad location and all the active wells are generally
tested on the same date. By AOGCC approval (March 23, 2006) these pad tests are
primarily scheduled to be performed in the summer months.
2. ACDB Waivered Well List: This is an ACDB generated list of wells which are operating
under a state -approved (and a CPAI approved) variance. The injection wells on this list
require specific AOGCC approval to keep the well in service. These wells typically are on a
2-year MIT cycle, which will occur throughout the year based on the date that the variance
was granted by the AOGCC.
3. Overdue MIT Tracking Spreadsheet: This Excel spreadsheet is used to simplify and
supplement the tracking of wells that were shut-in at the time they were due for testing but
must be tested when they are returned to service. These wells also show up on the "normal"
list described in (1) above but due to the large number of shut-in wells and past due dates
on the Normal Injection Wells List (due to the wells' shut-in status), the Excel spreadsheet is
used to filter out those wells that cannot be returned to service in the near future. Wells that
may return to service in the near future are monitored frequently for return to service so that
an MIT can be scheduled with the AOGCC's inspectors as per AOGCC requirements. This
list relies on the transfer of information from list (1) above, as well as accounting for every
shut-in well that was present when the pad was tested.
Industry Guidance Bulletin 10-02A issued in August 2013 states that it is AOGCC's preference
that operators do not perform MITs on wells when they are shut in unless specific approval has
been granted to allow a shut-in test. If a well is shut-in at the time that it is due for testing and is
not tested, that well is entered on the Overdue MIT Tracking Spreadsheet. When this occurs,
the PWS informs the Production Engineer (via email or phone call) that they must contact the
Well Integrity (WI) desk when the well is returned to injection so that a witnessed MIT test can
be scheduled with the AOGCC. Notes to that affect are also made in the ACDB in the "PWS
Planned Action" section, which can be viewed through the company intranet and are available
to the Engineering staff. Notes are also placed into the SETCIM SCADA system so that
Operators are aware of the requirement. Finally, all the wells on the Overdue MIT Tracking
Spreadsheet are checked once a week by WI staff to make sure the well has not been put on
injection without the WI Supervisor being informed.
Procedure for CPAI MIT Tracking System in the ACDB
There is a section in the ACDB to enter and track MIT data, including that submitted to the
AOGCC. The data includes:
a. Most recent test date;
b. Most recent test date witnessed by AOGCC;
c. Required test pressure;
d. Test frequency (months);
e. Next MIT due date;
f. Whether well passed or failed MIT.
2. PWS enters the MIT data into the ACDB as tests occur.
3
•
3. Once the initial MIT is performed, the ACDB calculates a due date for all subsequent
required MITs based on the AOGCC specified frequency of 1, 2 or 4 years as required in the
regulations.
4. Normal Injection Wells Report: ACDB generated list for injection wells which are on a 4-year
test cycle. The list is sorted by the due date of the next required MIT.
5. There is a section in the ACDB to enter and track waiver and variance data, including
Administrative Approvals (AA) from the AOGCC. The data includes:
a. The variance identification number;
b. Anniversary compliance date;
c. Most recent test date;
d. Test frequency (months);
e. Next compliance due date;
f. Text field for comments or details related to the compliance conditions required.
6. A Waivered Wells Report can be generated for the waiver compliance section for the test
due dates for wells with variances. The wells are listed by the next compliance due date.
7. Normal wells and variance (i.e., waivered) wells MIT reports are printed and reviewed at
least once per slope tour by the PWS.
8. After the reports are generated, all wells with MIT dates or compliance dates that are coming
due are added to the Downhole Diagnostic (DHD) Technician Work List along with the
required due date.
9. The DHD Work List is managed on a daily basis by the PWS to prioritize and organize the
work load. This work list is provided to the DHD Supervisor to coordinate the crews and
AOGCC witnessed tests. Compliance due dates, diagnostic tests and logistics are all
considered so obligations are met with the most efficient use of labor.
10. The DHD Supervisor provides the AOGCC inspector with a proposed MIT schedule via
email; a mutually agreeable time is determined for the tests.
11. If a MIT is not conducted on a well because it is shut- in, that well is entered on the Overdue
MIT Tracking Spreadsheet, which is reviewed at least once per week by WI staff. This
spreadsheet is used to supplement and simplify the tracking of wells that were shut-in at the
time they were due for testing, but must be tested when they are returned to service. These
wells also show up on the Normal Injection Wells List described above; however, due to the
large number of shut-in wells and expired due dates, Overdue MIT Tracking Spreadsheet is
used to filter out those wells that cannot be returned to service in the near future. The
remaining wells are monitored frequently for return to service so that an MIT can be
scheduled as per AOGCC requirements.
12. The PWS may add notes into the ACDB and SCADA to act as reminders for when the well
comes back online. The notes are to alert Production Engineering and/or Operations that
issues need to be addressed on the well. The notes are soft codes and do not raise an alert
or alarm.
13. The PWS and/or DHD Supervisor monitor the various MIT reports frequently to keep watch
for when the wells are brought back online that need testing, and also rely on the CPF
personnel (Production Engineer (PE) Drill Site Operator (DSO) or DSO Lead Tech) to notify
them when the well has been brought on injection.
4
0 0
Improvements to the UIC CMS
CPAI is making a number of significant improvements to its UIC CMS since receipt of the
AOGCC's Notice of Proposed Enforcement Action related to well 3Q-16 dated December 21,
2012. CPAI performed a Latent Cause Analysis (LCA) to determine the possible cause(s) of the
missed MIT and for its failure to timely report a pressure communication as decided in Order No.
81. A number of the improvements CPAI is currently implementing were corrective actions
recommended in the LCA for the missed MIT. Some of the corrective actions were immediately
implemented while others are still in progress because they are longer term projects that take time
to develop and implement. As these corrective actions are implemented they will change the
previously described processes in a positive way. A description of each corrective action and
improvement follows.
1. Review the WI AnnComm database with IT, Operations and Engineering to streamline
both the efficiency of data management systems and the effectiveness of
communications to/from IP.21. Suggested improvements could include, for example,
improving the AnnComm report generating function so that MIT data is entered in only
one location and multiple lists can be drawn from the existing data.
An analysis of the MIT tracking system, which is part of the AnnComm database, indicated
limitations on report generating capabilities. The MIT reports were largely "canned' in that a user
selects a report option for display or print and does not have the capability of focusing on specific
time periods or selection of wells. The limitation on report configuration resulted in CPAI personnel
having to handle data twice and use a supplementary Excel spreadsheet which required moving
data outside the tracking database. CPAI is currently in the process of improving the report
generating capabilities of the AnnComm database. The deliverable allows the user several
different report options. The result will be more focused reports that target specific situations
defined by the user, which will eliminate non -essential information and the need to export data
from the AnnComm database into a supplementary Excel spreadsheet. Delivery of this
functionality is expected by year end 2013/early 2014.
2. Review training for WI personnel to ensure the WI management systems are properly
managed.
CPAI has implemented additional training for WI personnel to ensure all personnel are competent
with the WI compliance management systems during periods when they are required to
temporarily stand in for another WI staff person, for example during a vacation or an office
vacancy. This training will emphasize the importance of accuracy, reporting and over-all data
management. When combined with the database tracking improvements detailed above, these
improvements will ensure that those acting in a temporary capacity will be familiar with the MIT
data management system requirements.
3. Review staffing in WI and consider whether it would be appropriate to shift data
management duties to other personnel.
CPAI has increased the number of WI field staff and has added an additional Anchorage -based
Senior Well Integrity Engineer position. This will decrease individual staff workloads, which will
ensure that field personnel have ample time to perform all the responsibilities of their position. The
senior engineer has been hired and will start by year-end 2013.
CPAI has also added a WI Technical Aide position on the Anchorage staff. This is a full time
position dedicated solely to regulatory compliance matters. This employee will be tasked with
managing the MIT tracking responsibilities. The Technical Aide will ensure proper entry into the
AnnComm database of MIT test data, prepare MIT reports for submittal to the AOGCC, determine
5
• 0
upcoming test details and notify field personnel of upcoming testing requirements and schedules.
The Technical Aide will also perform audits on the MIT data to ensure accuracy and will track wells
that are put into service to ensure that all wells have a current MIT. Duties will be expanded as
competency is demonstrated. The Technical Aide was hired and is undergoing training.
Finally, some of the administrative functions of the field office staff will be relocated to Anchorage
in an effort to further reduce the workload on field personnel. All administrative duties that are not
required to be performed in the field office may be subject to the move. Implementation of this
transfer of job duties to the Anchorage office has commenced and will be evaluated on an ongoing
basis.
4. Develop and implement a comprehensive solution to ensure that wells cannot be put
into service until all regulatory and company requirements have been met.
CPAI has commenced a Wells Fit for Service initiative to ensure all wells are in compliance with
regulations and internal polices and guidelines. A gap analysis is currently being performed to
ensure existing software tools and applications capture all applicable regulatory requirements. .
A gap analysis has been performed on the major regulatory processes (MIT, Safety Valve System
Testing, Sundry Notices, Administrative Approvals, Underground Injection Control, Well
Commissioning) and a Responsible, Accountable, Communicate and Inform (RACI) chart was
developed to clearly identify the required steps that need to be performed and what position is
responsible for those actions. A system analysis is being performed to develop a comprehensive
software solution to ensure that a well cannot be put into service until all regulatory and company
requirements have been met. Any gaps will be appropriately addressed during the implementation
process. The end product will ultimately be a comprehensive software solution to integrate multiple
compliance management processes and applications (SVS, MIT, Defeated Safety, etc.) into a
common platform to easily, develop and implement new alerts (do not operate, compliance tests
due, etc.) and this will allow CPAI to quickly determine compliance with all applicable regulatory
requirements. The final implementation is expected to be completed in 2014 and CPAI will provide
the AOGCC with periodic project updates.
CPAI is confident that these enhancements to our UIC CMS will result in significant improvements
to the CPAI UIC CMS, including the MIT tracking and reporting system. The company is committed
to the highest standards for regulatory compliance and to maintaining good relationships with the
regulating agencies. We aim to deliver best in class performance in all of our Alaska operations.
1.1
• � Attachment B
Principal Investigator(s): Pete Fox Cost of Failure($/bbl):
ConocoPhillips
Alaska Event Date: 9/25/2012 Event Time: Event Location: 3Q-16 well
Process Safety LCA LCA Title: 3Q-16 MIT Delay Causing AOGCC NOV (Supplemented) IIMPACT#:
Executive Summary:
On 11/13/12 during the preparation of a Well Integrity report to the AOGCC, the Well Integrity Team discovered that the
Mechanical Integrity Test (MIT) for the on-line injection well 3Q-16 was not conducted on or before its 9/25/2012
scheduled due date. On 11/13/12, the Problem Wells Supervisor (PWS) reviewed well data (a T/I/O report) and
suspected inner annulus communication. The PWS reported both the overdue MIT and the suspected inner annulus
communication to the AOGCC on 11/13/12. On 11/14/12, the Well Integrity Team conducted a Draw Down Test (DDT)
and Packoff Test. The well passed all tests indicating no integrity issues were present with the well. On 12/21/12, the
AOGCC sent a Notice of Proposed Enforcement to CPAI alleging that CPAI was in violation of AOGCC regulations and the
Area Injection Order for its failure to timely conduct a MIT on 3Q-16 within the four-year cycle and failure to timely
report a pressure communication to the AOGCC.
Sequence of Events:
• 6/1/12: 3Q-16 well was shut-in to allow repairs to be made to the production / injection common line.
• 8/8/12: All on-line wells on 3Q DS pad undergo MITs as per Well Integrity's (WI) testing schedule. 3Q-16 did
not have a MIT performed at that time pursuant to AOGCC's guidance adopted 2/9/10 , which CPAI interpreted
as prohibiting MIT testing on shut-in wells except with AOGCC approval.
• 8/22/2012: 3Q-16 was brought back on-line and returned to MI injection service.
• 9/25/12: 3Q-16 four year anniversary MIT due date. MIT was not performed on the well.
• 11/13/12: The WI Supervisor discovered that the MIT due date for 3Q-16 (September 25) had passed while
compiling a quarterly report for the AOGCC. The WI Supervisor suspected inner annulus communication after
looking at a T/I/O plot. CPAI shut-in the well immediately and contacted the AOGCC regarding both the overdue
MIT and the suspected communication.
• 11/14/12: A diagnostic DDT and Packoff Test (not witnessed by AOGCC Inspector) was performed on 3Q-16
with all tests passing. No indications of communication were present. The well remained shut-in while a
resolution worked with AOGCC.
• 12/21/13: WI received a Notice of Proposed Enforcement from AOGCC, which alleged CPAI failed to
demonstrate mechanical integrity and failed to report annular communication in a timely manner.
• 1/11/13: Additional (MITIA) integrity testing was performed on 3Q-16 again confirming no annular
communication.
Unusual findings:
• The 3Q-16 well data available on November 13, 2012 (T/I/O plot) prior to the MIT being performed
suggested possible communication between the well annulus and the tubing; however subsequent MIT data
and diagnostics confirmed no integrity issues were present. Further analysis of the T/I/O plot together with
temperature data indicated the annular pressure was changing with injection temperature.
Conclusions:
LCA Team members reviewed concluded the following:
Well Integrity Data Base Management:
1 of 2
0 0
ConocoPhillips Principal Investigator(s): Pete Fox Cost of Failure($/bbl):
Alaska Event Date: 9/25/2012 Event Time: Event Location: 3Q-16 well
Process Safety LCA LCA Title: 3Q-16 MIT Delay Causing AOGCC NOV (Supplemented) (IMPACT#:
MITs are managed using three separate lists; two are in AnnComm, one is an Excel spreadsheet used to simplify the
AnnComm data. Using these spreadsheets, well data is crosschecked with the central data depository / management
system called AnnComm. The data management systems are complex. The complexity of the system can be especially
complicated for temporary step-up personnel tasked with managing and documenting the continually changing well
data.
It was noted that the AOGCC has provided some MIT tracking and due date relief since this event with the adoption of
Guidance Bulletin No. 10-02A in 8/16/13. This guidance document allows 4 year MITs to be completed within the month
they are due.
Physical Cause(s): No physical failure occurred.
Human Cause(s): A temporary step-up for the Problem Wells Supervisor was unaware of the requirement to
update the data management systems (i.e., the Excel spreadsheet) when 3Q-16 was shut-in during the 8/8/12 3Q MIT
pad testing efforts. This oversight resulted in the MIT due date passing unnoticed until the regular WI Supervisor
discovered this oversight after the MIT due date had passed during a management system data review.
Triggering Situations: The WI data management systems are complex, which allows for human error to occur.
Systemic / Latency Cause(s):
• The well data management systems are complex. Multiple lists increase the complexity of managing well data.
• The first AOGCC Guidance Bulletin No.10-002 issued on 2/19/10 contradicted the AOGCC regulations and
AOGCC-approved testing schedules and practices performed by CPAI at Kuparuk.
LCA Team Recommendations List: To prevent recurrence
1. Review the WI AnnComm database with IT, Operations and Engineering to streamline both the efficiency of data
management systems and the effectiveness of communications to/from IP.21. Suggested improvements could
include, for example, improving the AnnComm report generating function so that MIT data is entered in only one
location and multiple lists can be drawn from the existing data.
2. Review training for WI temporary step-ups to ensure the WI management systems are properly managed when
step-ups take charge.
3. Review staffing in WI and consider whether it would be appropriate to shift data management duties to other
personnel.
4. Meet with AOGCC to discuss testing shut-in wells and performing MITs at dates prior to the MIT due date.
5. Modify the current MIT data audit process to include periodic reconciliation with the AOGCC MIT database.
Supplemented LCA on October 16, 2013
2 of 2
• 0 Attachment C
ConocoPhillips Principal Investigator(s): MJ Loveland, Jerry Dethlefs 7C-1t
Failure($/bbl):
Alaska Event Date: 11/13/2012 TEvent Time: Event Location: 3Q-16 well
Process Safety LCA LCATitle: 3Q-16 Not Timely Reporting Causing AOGCC NOV ,IMPACT#:
Executive Summary:
On 11/13/12 during the preparation of a Well Integrity quarterly report to the AOGCC, the Well Integrity Team
discovered that the Mechanical Integrity Test (MIT) for the on-line injection well 3Q-16 was not conducted on or before
its 9/25/2012 scheduled due date. While compiling this report to the AOGCC, the Problem Wells Supervisor (PWS)
reviewed certain well data (a T/I/O report) for the first time and suspected inner annulus communication. The PWS
reported both the overdue MIT and the suspected inner annulus communication to the AOGCC on 11/13/12. On
12/21/12, the AOGCC sent a Notice of Proposed Enforcement to CPAI alleging that CPAI was in violation of AOGCC
regulations and the Area Injection Order for its failure to timely conduct a MIT on 3Q-16 within the four-year cycle and
failure to timely report a pressure communication to the AOGCC.
Sequence of Events:
• 08/08/2004: Well passed State Witnessed MIT
• 09/25/2008: Well passed State Witnessed MIT
• 8/22/2012: 3Q-16 was brought back on-line and returned to MI injection service.
• 11/13/12: The WI Supervisor looked at the T/I/O plot for the well (that was also part of the quarterly
submission) and based on the pressure trend suspected inner annulus communication. This was the first time
that CPAI had observed or suspected potential communication on 3Q-16. CPAI immediately shut-in the well and
contacted the AOGCC regarding the suspected communication.
• 11/14/12: A diagnostic MIT (not witnessed by AOGCC Inspector) was performed on 3Q-16 with all tests
passing. No indications of communication were noted. The well remained shut-in while a resolution worked
with AOGCC.
• 12/21/13: AOGCC issued a Notice of Proposed Enforcement, which alleged CPAI failed to demonstrate
mechanical integrity and failed to report annular communication in a timely manner.
• 1/11/13: Additional integrity testing was performed on 3Q-16 and this testing again confirmed no annular
communication.
• Mid -January, 2013: CPAI again reviewed the T/I/O plot provided to the AOGCC on 11/13/12. CPAI also
reviewed additional well data including passing wellhead packoff test, temperature trends, IA drawdown test and
the passing MITIA data. The review of the data indicated that the well experienced what appeared to be
thermally induced annular pressure fluctuations on 8/22/2012 due to the direct correlation of injection
temperature and the annular pressure swings.
Unusual findings:
• The 3Q-16 well data available on November 13, 2012 (T/I/O plot without temperature) suggested possible
communication between the well annulus and the tubing; however subsequent MIT data and diagnostics
tests passed.
• Prior to placing this well in service, it was not noted by Operations or Well Integrity personnel that the well
may have a communication problem that should have been investigated and reported.
• No annular pressure bleeds were performed between May 14, 2012, and November 14, 2012.
• SCADA system alerts were not generated on this well from May 2012 to November 2012.
• At no point from May 2012 to November 2012 did the annular pressure reach the Maximum Allowable
Operating Pressure (MAOP) of 3000 psi.
1 of 3
ConocoPhillips Principal Investigator(s): MJ Loveland, Jerry Dethlefs 7C-St
Failure($/bbl):
Alaska Event Date: 11/13/2012 Event Time: Event Location: 3Q-16 well
Process Safety LCA LCATitle: 3Q-16 Not Timely Reporting Causing AOGCC NOV IIMPACT#:
• At no point from May 2012 to November 2012 did the differential between the injection tubing pressure (FTP)
and the IA annular pressure approach the 500 psi minimum requirement.
• At no time in the history of this well has a MIT failed, which is the AOGCC test criteria for well integrity.
• There were no observations of communication or leakage or other indicators prior to 11/13/12 that required
reporting. The operators did not observe any indications of communication or leakage during well checks.
The very slow, gradual increase in pressure was not detected or observed.
• The annular pressure fluctuations from October 11, 2012, to November 13, 2012, were within the allowable
Well Operating Guidelines (WOG) operating range and therefore were not detected.
Conclusions:
Reasons that the slowly building annular pressure and pressure anomalies that began on or about October 11, 2012
were not observed and reported at that time:
1. CPAI established indicators and trigger points are: approaching or hitting the MAOP of 3000 psi; the inability to
maintain 500 psi differential between tubing and IA; or performing maintenance bleeds to control annular
pressure. None of these triggers were met.
2. The gauge pressure increase was so small and slow that the Drill Site Operators (DSO) did not recognize the slow
increase, and therefore did not report the situation as possible communication to Well Integrity group.
3. There are not any other conditions or computer aided scans besides the above mentioned trigger points that
would have alerted personnel to a slow increase in annular pressure before a trigger point was met.
4. Without a report from a DSO, or an alert from SCADA, there were no indicators, observations or reasons for CPAI
to investigate this well based on current operating practices.
5. There is no established routine to periodically review annular pressure trends for communication on every well
without cause.
Physical Cause(s): No physical failure has been identified.
Human Cause(s): None
Triggering Situations: No triggers were indicated with the current allowable operating pressure ranges for
injection wells.
Systemic / Latency Cause(s):
• The standard for reporting of pressure fluctuations to the AOGCC, as per the findings and decisions in AOGCC
Order No. 81, is more stringent than previously established history.
• Current allowable operating parameters and trigger points used to identify small, slow annular pressure
fluctuations are not consistent with the findings and decisions in AOGCC Order No. 81.
• AIO 213, Rule 5, Reporting of tubing/casing pressure variations states that: "Tubing/casing annulus pressure
variations between consecutive observations need not be reported to the commission."
2 of 3
0 •
ConocoPhillips Principal Investigator(s): MJ Loveland, Jerry Dethlefs Cost of Failure($/bbl):
Alaska Event Date: 11/13/2012 EvenTim t e: Event Location: 3Q-16 well
Process Safety LCA LCA Title: 7 3Q-16 Not Timely Reporting Causing AOGCC NOV (IMPACT#:
LCA Team Recommendations List: To prevent recurrence
1. Evaluate changes to allowable operating pressure ranges for injection wells.
2. Evaluate a computer -assisted algorithm to identify increasing annular pressure while an injection well is shut-in.
3. Evaluate the addition of a computer -assisted algorithm that would identify changing annular pressures that are
not thermally induced for an injection well in service.
4. Provide enhanced refresher training for Operations on the Well Operating Guidelines based on the outcome of
the 3Q-16 events.
5. Investigate Best Practices for the detection and reporting of indications of annular communication with other
North Slope Alaska Operators.
LCA completed on October 11, 2013.
3of3
#12
• •
1 ALASKA OIL AND GAS CONSERVATION COMMISSION
2 Before Commissioners: Cathy Foerster, Chair
3 Daniel T. Seamount
4 John K. Norman
5
6 In the Matter of ConocoPhillips )
7 Alaska's Request for )
8 Reconsideration of Other Order )
9 No. 81, Kuparuk River Unit 3Q-16. )
10 )
11 ALASKA OIL and GAS CONSERVATION COMMISSION
12 Anchorage, Alaska
13 September 11, 2013
14 9:00 o'clock a.m.
15
VOLUME II
16 PUBLIC HEARING
17 BEFORE: Cathy Foerster, Chair
18 Daniel T. Seamount, Commissioner
19 John K. Norman, Commissioner
1 TABLE OF CONTENTS
2 Remarks by Chair Foerster
3 Remarks by Mr. Detleth
4 Remarks by Mr. Robinson
12
50
11
1 P R O C E E D I N G S
2 (On record - 9:00 a.m.)
3 CHAIR FOERSTER: All right. We'll call this
4 hearing to order. Today is September llth, 2013, it's
5 about 9:00 a.m. And we're at the offices of the Alaska
6 Oil & Gas Conservation Commission, 333 West Seventh
7 Avenue, Anchorage, Alaska.
8 On my right is Commissioner John Norman, on my
9 left is Commissioner Dan Seamount and I'm Cathy
10 Foerster.
11 Computer Matrix will be recording the
12 proceedings from today's hearing, you can get a
13 transcript from Computer Matrix Reporting.
14 Just a quick reminder to people testifying.
15 Make sure both of your mics are on and speak into --
16 try to speak into both of them so that people in the
17 back of the room can hear you and so that the court
18 reporter can get a clear recording of what you say.
19 This hearing is in reference to docket number
20 Other Order No. 81. Let me give a little history. On
21 11/13 of 2012 ConocoPhillips notified the AOGCC that
22 KRU 3Q-16 was not tested for its MIT on schedule. The
23 AOGCC did some investigative work and sent
24 ConocoPhillips a notice of violation for failure to
25 complete the MIT on schedule and failure to report a
g
1 pressure communication in the well KRU 3Q-16.
2 ConocoPhillips responded to the NOV and requested a
3 informal review on -- they responded on January 14th of
4 2013. On January 16th the AOGCC set schedule for a
5 conference for an informal review and to be held on
6 January 30th, 2013. On January 30th the parties met
7 and conducted the informal review. On April 16th of
8 2013 AOGCC issued proposed order and fined
9 ConocoPhillips $45,000 and requested additional
10 information be filed. On May 9th of 2013
11 ConocoPhillips filed an application for reconsideration
12 and on May 16th the AOGCC sent an order to
13 ConocoPhillips setting a hearing. The notice of
14 hearing was published in the Anchorage Daily News and
15 the state of Alaska online as well as the AOGCC website
16 on June 7th, 2013.
17 Let's see, it looks like we have two people
18 from ConocoPhillips wanting to testify; is that
19 correct?
20 (No audible response)
21 CHAIR FOERSTER: Okay. Will you be giving
22 sworn testimony?
23 (No audible response)
24 CHAIR FOERSTER: Okay. Let's swear you both in
25 then. Raise your right hand.
9
1 (Oath administered)
2 (No audible response)
3 CHAIR FOERSTER: Okay. Thank you. All right.
4 You can begin. When you start, give your name, who you
5 represent and then if you'd like to be recognized as an
6 expert witness what the subject of your expertise is
7 and your qualifications and then we'll weigh it -- in
8 on that.
9 MR. DETLETH: I'm Jerry Detleth (ph), I'm a --
10 the -- Jerry Detleth the ConocoPhillips Alaska well
11 integrity director. I've got 33 years of oilfield
12 experience and the last 15 has been with well integrity
13 and I currently head up the well integrity group for
14 Alaska. I've got a bachelor's of science in
15 engineering and two master's degrees. I would like to
16 be known as an expert witness today for the testimony
17 on mechanical integrity.
18 CHAIR FOERSTER: Do you have any questions of
19 the witness?
20 COMMISSIONER SEAMOUNT: No, I don't.
21 CHAIR FOERSTER: Commissioner Norman.
22 COMMISSIONER NORMAN: A little more of your
23 background on mechanical integrity.
24 MR. DETLETH: Sure. I started here in Alaska
25 right out of college in 1979, worked first three years
10
1 running drilling fluid and then I started working for
2 ARCO and have put in 25 of the last 30 years working
3 for ARCO in production, engineering, operations, I was
4 a production operator on the slope. Then I went into
5 well supervisor and in 1998 I started with well
6 integrity in Prudhoe Bay and started up the well
7 integrity program in Kuparuk and in 2007 I assisted
8 starting up the Conoco worldwide program out of
9 Houston. I've been back for two years and head up the
10 well integrity program here in Alaska.
11 CHAIR FOERSTER: Okay. Thank you.
12 COMMISSIONER NORMAN: Thank you.
13 CHAIR FOERSTER: Do you have any concerns or do
14 you.....
15 COMMISSIONER SEAMOUNT: Will your testimony
16 concern anything other than well integrity?
17 MR. DETLETH: Only -- it'll be directly
18 associated with the enforcement letter and allegations
19 here.
20 COMMISSIONER SEAMOUNT: I just wondered if it
21 would be more appropriate to be an expert as a
22 production engineer.
23 MR. DETLETH: The only way I can answer that is
24 by mechanical integrity testing as it's performed and
25 associated with this hearing is done out of my group.
11
1 COMMISSIONER SEAMOUNT: Then I think I'll
2 withdraw my suggestion. I have no objections.
3 CHAIR FOERSTER: All right. We recognize you
4 as an expert in mechanical integrity.
5 MR. DETLETH: Okay.
6 CHAIR FOERSTER: You may proceed.
7 JERRY DETLETH
8 previously sworn, stated as follows on:
9 DIRECT EXAMINATION
10 MR. DETLETH: Good morning, Commissioners
11 Foerster, Seamount and Norman. Since mechanical
12 integrity testing is part of my organization I'm
13 representing ConocoPhillips in this today.
14 On slide two my testimony will cover these
15 topics, the context and purpose of why we're here at
16 this hearing, ConocoPhillips' position on these
17 allegations and penalties and the timeline of events
18 that transpired regarding Kuparuk Well 3, Quebec 16.
19 The two issues from Order No. 81 ConocoPhillips is
20 requesting for reconsideration will be discussed and
21 then some closing comments.
22 CHAIR FOERSTER: Thank you, Mr. Detleth, and
23 thank you for remembering that as you refer to each
24 slide to refer to its number because that'll make the
25 record good. Thank you for reminding me to say that to
12
1 you.
2 MR. DETLETH: I was reminded in previous
3 hearings so.....
4 CHAIR FOERSTER: Okay. Good memory. Thank
5 you.
6 MR. DETLETH: Thank you. So on slide four in a
7 letter dated December 21, 2012 the AOGCC proposed to
8 fine ConocoPhillips $45,000 in civil penalties for two
9 regulatory infractions regarding injection well 3
10 Quebec 16. The first penalty is for injecting into
11 well 3Q-16 without having a current mechanical
12 integrity test as per Rule 6 of Area Injection Order
13 2B. Second penalty is for failure to report a
14 suspected pressure communication observations by the
15 next working day as per Rule 7 of Area Injection Order
16 2B. Each penalty incurs daily fines from the alleged
17 point of infraction until the day ConocoPhillips self
18 reported the issues to the AOGCC. CPA or
19 ConocoPhillips submitted a written response on January
20 14th, 2013 disputing a portion of the allegations and
21 requesting an informal hearing. That informal meeting
22 was held on April 16th, 2013 after which AOGCC issued
23 Order No. 81 which affirmed the original penalties.
24 The purpose of this hearing is to request
25 reconsideration of the decisions and penalties of Order
13
1 No. 81, specifically to reduce the penalty for the
2 missed MIT and withdraw the decision and penalty for
3 failure to timely report suspected communication on
4 well 3 Quebec 16.
5 Slide number 5. ConocoPhillips' position on
6 the allegations and penalties are as follows.
7 ConocoPhillips self disclosed the missed MIT to the
8 AOGCC on November 13, 2012. ConocoPhillips has also
9 taken significant corrective actions to prevent a
10 recurrence of missing or required test which I will
11 provide some details later in my testimony.
12 ConocoPhillips requests that AOGCC reduce the imposed
13 penalties for this non-compliance event.
14 Issue two is in regards to the allegation of
15 not timely reporting suspected annular communication
16 observed on 3Q-16. There were no prior events that
17 suggested the well had a communication problem. A
18 trend plot was generated during preparation of a
19 quarterly report to AOGCC on November 13th, 2012 and
20 the trend plot was very simple and without detail, but
21 it indicated the potential that communication may be
22 present and CPAI or ConocoPhillips is required to
23 report operating pressure observances that indicate
24 communication the first working day following the
25 observation. On 11/13 of 112 ConocoPhillips did timely
14
1 report the suspected communication. In that case we
2 think that the enforcement penalties and -- the
3 enforcement and the penalties are not warranted.
4 On slide six is a discussion of the timeline of
5 events. Well 3 Quebec 16 is permitted for water or MI
6 injection. On 9/25/08 an MIT passed and it was a
7 witnessed MIT, state witness, and the next text was not
8 due until September 25th of 2012. On June 1 the well
9 was shut-in for repairs on surface piping. And on
10 August 8th MITs on all the active injectors on 3Q pad
11 were performed, but 3Q was not tested because of the
12 AOGCC preference that a well is on active injection
13 when it has its witnessed MIT. At -- a step-up
14 supervisor was temporarily covering this position's
15 duties and at that point a clerical mistake was made on
16 the date about the well not being tested. On August
17 22nd the well was returned to service on MI injection.
18 The water header had been fixed -- had not yet been
19 fixed, but the MI header was operational and the well
20 was put on MI. On November -- well, on September 25th
21 was the anniversary of the due date and it came and
22 went without the well being tested.
23 On November 13th while compiling a quarterly
24 report for the AOGCC ConocoPhillips discovered that the
25 MIT due date had passed and the MIT had not been
15
•
•
1 performed after the well went back into service.
2 Although the injection well status is reviewed weekly
3 the outstanding MIT requirement was missed because it
4 had not been noted in our compliance management system
5 by the temporary step-up supervisor. When that --
6 during the preparation of that report there are trend
7 plots that are generated associated with that report,
8 they're very simple, but the indication of that trend
9 plot was that there may be tubing by communication or
10 tubing by annulus communication. It was unconfirmed,
11 but we're obligated to report even suspected
12 communication and so after conferring with me as the
13 director on the situation we decided to immediately
14 report it and get the well shut-in. And so the well
15 was reported that day as having missed the MIT and
16 suspected communication as per the requirements in the
17 regulations. And the well has been shut-in and will
18 remain shut-in until it's approved to return to
19 service. On November 14th which was the day after the
20 report, diagnostics were performed by ConocoPhillips'
21 contractors who identified potential leak paths and
22 test back offs and a draw down test was performed with
23 up to a 2,700 pound differential across the packer
24 which found no indication of any communication on the
25 well. Further analysis of -- looking at a different
16
1 trend plot with temperature curves indicated that
2 pressure fluctuations had taken place due to
3 temperature, but there were still no indications of
4 communication.
5 On December 21 we received a letter from the
6 AOGCC with the notice of enforcement -- proposed
7 enforcement for allegedly failing to demonstrate
8 mechanical integrity and for failing to timely report
9 annual communication by the first day -- one business
10 day after observance. On January lath ConocoPhillips
11 -- well, on January 11 there was an MIT performed for
12 diagnostic reasons that also passed and on January 14th
13 ConocoPhillips responded to the AOGCC and requested an
14 informal review meeting as per an option in the
15 enforcement letter. And then on April 16th after that
16 informal meeting the AOGCC issued Order 81 which
17 affirmed the original decision and penalties from the
18 notice of proposed enforcement letter.
19 Onto slide seven. This would be issue one for
20 reconsideration for penalties for the missed MIT.
21 And slide eight, ConocoPhillips believes that
22 the penalty calculation does not take into
23 consideration all the mitigating circumstances that due
24 to self disclosure and the implementing of significant
25 corrective actions to prevent recurrence that -- which
17
1 I'll detail on the next slide that reconsideration is
2 warranted.
3 Slide eight [sic], corrective actions that are
4 currently taking place include.....
5 CHAIR FOERSTER: Slide nine.
6 MR. DETLETH: Pardon me?
7 MR. ROBINSON: Nine, slide nine.
8 CHAIR FOERSTER: Isn't it slide.....
9 MR. DETLETH: Oh, I'm sorry. Yeah, I don't see
10 a.....
11 CHAIR FOERSTER: It's nine.
12 MR. DETLETH: Corrective actions that are
13 currently taking place include improvements to the MIT
14 and compliance data management systems by consolidating
15 recordkeeping to a new and dedicated full-time position
16 which we have filled and are in the process of getting
17 that person up to speed. Enhancing reporting
18 capabilities in our MIT data management system, the
19 data base system, to enable tracking compliance tests
20 more effectively. And also enhancing training
21 requirements for personnel that fill in during office
22 vacancies which was part of the contributing factor to
23 this situation.
24 In addition ConocoPhillips is developing a
25 comprehensive process to ensure compliance on wells to
18
1 make sure they're fit for service through a variety of
2 other compliance data bases that we have. This will be
3 multiple compliance management processes linked
4 together to a universal alert system and that will tie
5 into the SCADA system which is the supervisory control
6 and data acquisition system and it will provide alerts
7 to warn operators of do not operate type situations,
8 compliance tests due and similar notices that would
9 either alert a person not to bring a well -- put a well
10 in service without compliance being up-to-date or it
11 would alert you when compliance is coming due on a well
12 and get those tests done.
13 The development schedule has begun and there is
14 a simple interim solution already implemented, but the
15 -- a larger project is considerable and it will be
16 worked and hopeful delivery during next year. And the
17 progress on that project is going to be reported to the
18 AOGCC. I believe you already received a little bit of
19 a notice on the initiation of that project and we'll
20 continue those updates.
21 Slide 10. ConocoPhillips requests that the
22 AOGCC consider these mitigating circumstances and the
23 corrective actions and reduce the penalty for the
24 missed MIT. And the penalty reduction of 28,500 is a
25 portion of the penalty that was allocated to the missed
19
•
•
1 MIT.
2 Slide 11. Issue two is for reconsideration for
3 failure to timely report suspected annular
4 communication in a timely manner. And this includes
5 withdrawal of the enforcement decision and removal of
6 the penalty.
7 Slide 12 is quotes from the regulations that we
8 need to adhere to. Rule 7 of Area Injection Order 2B
9 states whenever operating pressure observances or
10 pressure tests indicate pressure communication or
11 leakage of any casing, tubing or packer the operator
12 must notify the Commission on the first working day
13 following the observation and obtain Commission
14 approval for a plan of corrective action and when a
15 USDW is not endangered obtain Commission approval to
16 continue injection.
17 And in the regulations 20 AAC 25.402(f)
18 requires that if an injection rate, operating pressure
19 observation or pressure test indicates pressure
20 communication or leakage in any casing, tubing or
21 packer, the operator shall notify the Commission by the
22 next working day and shall implement corrective actions
23 or increased surveillance as the Commission requires to
24 ensure protection of freshwater.
25 Slide 13. On December -- on November 13th of
20
1 1012 ConocoPhillips first observed on pressure trend
2 plot the suspected communication. The pressure trend
3 plot was a simple plot and without a temperature curve
4 it indicated potential communication. ConocoPhillips
5 timely reported the suspected communication on the same
6 day as the observance. And ConocoPhillips met the
7 regulatory requirement by reporting the first working
8 day following the observation as per the requirements
9 in the previously read recommend -- regulations.
10 ConocoPhillips requests that AOGCC withdraw its
11 decision that ConocoPhillips failed to timely report
12 and eliminate the penalties that are associated with
13 this decision.
14 Slide number 14. There were no observances of
15 communication or leakage prior to November 13 that
16 required reporting. The operators did not observe any
17 indications of communication or leakage during their
18 daily well checks. The maximum allowable pressure on
19 the annulus of this well is 3,000 pounds and at no time
20 did the annulus pressure approach this limit. We do
21 have triggers that had it approached that limit we
22 would have got an alert. The differential between the
23 tubing and annulus remained greater than 500 psi.
24 That's also a best practice that is generally
25 encouraged by the AOGCC and we use it as well that if
21
1 an annulus pressure gets less than 500 pounds between
2 it and the tubing that there is a alert or an alarm and
3 so that somebody will look into it and see what's going
4 on and at no time in this time interval did this well
5 get less than 500 pounds differential. Pressure
6 bleeding is also another indication of potential
7 leakage and this well was not bled at all from the --
8 during the time period of the enforcement letter from
9 May until November of 2012. The SCADA.....
10 COMMISSIONER NORMAN: I'm sorry, could you
11 repeat that bleeding and there was no bleeding between
12 May and November 12th, was that.....
13 MR. DETLETH: That's correct. And there's a
14 bleed log kept and there's no entries for that period.
15 And on the trend plot you can generally see when a
16 bleed is made and there were no bleeds done.
17 COMMISSIONER NORMAN: Okay.
18 MR. DETLETH: The SCADA reports that are
19 automatically generated that look for these items did
20 not have any reports during that period that showed
21 there may be potential communication.
22 Slide 15 is just a transition to closing.
23 Slide 16. ConocoPhillips respectfully requests
24 that the AOGCC reduce the penalties associated with the
25 missed MIT and do a reduction in the penalty amount of
22
1 the 28,500 that was allocated to the MIT. We also
2 request that we -- you withdraw your decisions,
3 findings and conclusions that ConocoPhillips failed to
4 timely notify the AOGCC of a potential pressure
5 communication situation and eliminate the penalties
6 associated with that decision that ConocoPhillips
7 failed to timely report.
8 And slide 17 is the end of presentation.
9 CHAIR FOERSTER: Thank you, Mr. Detleth.
10 Commissioner Norman, do you have any questions for Mr.
11 Detleth?
12 COMMISSIONER NORMAN: Yes, I have a few.
13 CHAIR FOERSTER: Okay.
14 COMMISSIONER NORMAN: Mr. Detleth, thank you
15 for your testimony. I'll talk first about the first
16 item, the mechanical integrity test, the request for
17 penalty reduction. Normally that's based upon -- a
18 penalty reduction would be based upon a finding of
19 mitigating factors, would you agree with that or not?
20 In other words there is -- there are penalties that we
21 would set and then we find reasons that -- to come
22 down, there are maximum penalties, but then we find
23 mitigating factors to adjust those penalties.....
24 MR. DETLETH: I understand that.....
25 COMMISSIONER NORMAN: .....in general
23
1 principal.
2 MR. DETLETH: .....I don't believe that I'm
3 qualified to determine.....
4 COMMISSIONER NORMAN: Well, in general
5 principle.
6 MR. DETLETH: .....how you reduce penalties,
7 but I understand.
8 COMMISSIONER NORMAN: Oh, okay.
9 MR. DETLETH: Yes.
10 COMMISSIONER NORMAN: In general principle.
11 That's not a trick question.
12 MR. DETLETH: Okay.
13 COMMISSIONER NORMAN: I just wanted to point
14 out that the penalty there if I'm looking at it right,
15 already the initial penalty has already been decreased
16 by 90 percent of what it could have been and the daily
17 penalty has been decreased by 95 percent of what it
18 could have been which is a significant reduction. Said
19 differently the initial penalty is at 10 percent of
20 what the maximum might have been and the other penalty
21 is set at 5 percent of what it could have been. So
22 turning to the mitigating circumstance in the AOGCC
23 order I'm looking at page 5 of Order Number 81. And I
24 can take time to just look at this if you don't have
25 that readily available.
24
1 MR. DETLETH: I don't have it.
2 COMMISSIONER NORMAN: That's okay because I
3 don't have a detailed question on this, but one of the
4 things noted was ConocoPhillips' general history of
5 satisfactory compliance and practices in the state of
6 Alaska. The Commission is aware of that and I think
7 it's important to make that clear.
8 The next point is you mentioned the voluntary
9 reporting and a mitigating circumstance was
10 ConocoPhillips' notification to AOGCC which said
11 differently is voluntary reporting I think, is it not?
12 MR. DETLETH: That's correct.
13 COMMISSIONER NORMAN: So that appears to be
14 taken into consideration and the Commission did note
15 the fact that was reported. In other words it was
16 ConocoPhillips that reported this and that is noted
17 among the mitigating factors. My question to you is
18 had ConocoPhillips not notified AOGCC of this is it
19 your belief that this incident might have escaped
20 detection by the AOGCC and there would have been no
21 penalty?
22 MR. DETLETH: I don't know that I'm qualified
23 to answer that as well because what systems you use
24 within -- within your data management system may very
25 well have caught it at some future point. And I'm not
25
1 qualified to know what those auditing protocols may be
2 that you have within your system. I know in the past
3 we have been notified by the -- by our contacts here in
4 AOGCC of a late or a date that we didn't have the same
5 date and that kind of thing so I know there's a process
6 here for looking at due dates, but I'm not sure what
7 that is. So.....
8 COMMISSIONER NORMAN: Certainly. Would you
9 agree that there are certain events that are calendared
10 if you will or scheduled or that are tracked both by
11 the operator and by the agency and are expected to be
12 followed both by the operator and the agency that may
13 be picked up.....
14 MR. DETLETH: That's correct.
15 COMMISSIONER NORMAN: .....and there are
16 certain other unplanned events and unplanned events
17 might not come to the attention of the agency if
18 they're not voluntarily reported.
19 MR. DETLETH: Right.
20 COMMISSIONER NORMAN: But a planned, scheduled
21 event that the agency would expect to be reported.....
22 MR. DETLETH: Well.....
23 COMMISSIONER NORMAN: .....might likely come to
24 the attention of the agency if it's not reported, there
25 might be a lag time, but it.....
26
1 MR. DETLETH: .....the single item that I can
2 identify that complicated our system was with the
3 guidance bulletin on the MIT document that -- or the
4 MIT guidance document bulletin two or whatever the
5 number was on it, where we previously had been doing
6 MITs on all wells whether they were shut-in or not and
7 at any given time we have a lot of wells shut-in and
8 what happened after that was put in place and we quit
9 testing wells that were shut-in was we built up a very
10 large backlog in our data system about past due wells
11 that we had to track for when they came back in
12 service. And that's a level of complication our system
13 was not designed to handle. We had -- at one point we
14 had 100 wells that were on the backlog that we had to
15 be tracking those on a -- literally a daily basis. And
16 that was a large part of what led into this clerical
17 error that -- that caused us to miss that date. And
18 those are the refinements we're making in our system
19 now to give us a much better ability of sorting through
20 our data to see -- be able to determine what's shut-in
21 and what's not and what we need to test very quickly
22 before a well's put in service. So it -- it's
23 partially complying with your regulations that got us
24 into this mess. So we're trying to straighten that
25 out.
27
1 COMMISSIONER NORMAN: Okay. I think my final
2 question is given the fact that our penalty's already
3 been reduced by more than 90 percent and you're asking
4 for a further reduction based upon mitigating factors,
5 what mitigating factor do you think justifies us going
6 beyond what we've already done?
7 MR. DETLETH: The larger project that we're
8 doing that's tying in a number of diverse systems
9 includes safety valve testing and defeated safeties and
10 for any other reason, upcoming compliance tests, that's
11 a much larger effort than what we had originally
12 committed to just getting our mechanical integrity data
13 base up to speed. And it should improve the
14 performance, the reliance on compliance for -- all the
15 way across all of our operations in the field. So it's
16 much more significant than we may have undertaken just
17 for this enforcement action.
18 COMMISSIONER NORMAN: Sure. And I began by
19 noting the fact that the Commission observes the fact
20 that the history -- the long history of ConocoPhillips
21 in this state is a history of satisfactory compliance
22 and practices. So we understand that and that's what
23 we would expect of you anyway. Thank you. Thank you
24 for that. I may have further questions on other
25 issues, but thank you for your response on those.
28
0
1 MR. DETLETH: All right.
2 CHAIR FOERSTER: Commissioner Seamount, do you
3 have any questions.
4 COMMISSIONER SEAMOUNT: I have no questions.
5 Thank you, Mr. Detleth.
6 CHAIR FOERSTER: I have a few. On slide five
7 you say that ConocoPhillips has taken significant
8 corrective actions to prevent from recurrence. Have
9 there been any other similar non -compliant events since
10 11/13, have you found other wells that you.....
11 MR. DETLETH: No, not to my knowledge have we
12 had any other compliance issues.
13 CHAIR FOERSTER: How about 2F04 and CD121?
14 MR. DETLETH: 2F04 was actually, but we found
15 that and reported that to you as part of this. After
16 -- we audited our system after this notice of
17 enforcement and we found that and brought that to your
18 attention.
19 CHAIR FOERSTER: So you have a non-compliance
20 event since 11/13?
21 MR. DETLETH: We have.
22 CHAIR FOERSTER: Okay. And CD121?
23 MR. DETLETH: And that was a safety valve
24 testing event I believe.
25 CHAIR FOERSTER: But it's still compliance,
FIE
1 right?
2 MR. DETLETH: Yes.
3 CHAIR FOERSTER: Okay.
4 MR. DETLETH: That's correct.
5 CHAIR FOERSTER: Okay. So the corrective
6 actions happened after -- after these two events.....
7 MR. DETLETH: The.....
8 CHAIR FOERSTER: .....the significant.....
9 MR. DETLETH: .....the discussion started clear
10 back in there as -- as a we need to do something to
11 make the systems we have more foolproof. And so it was
12 actually starting back at that time as a result of
13 those and it has been in progress ever since.
14 CHAIR FOERSTER: Okay.
15 MR. DETLETH: Those all happened at a fairly
16 close time period.
17 CHAIR FOERSTER: Okay. You stated that the 3Q-
18 16 has not been approved to return to service, why is
19 that?
20 MR. DETLETH: For a number of reasons. We have
21 decided it -- it's -- the only injection that was
22 available is MI and there are certain things we can and
23 can't do for diagnostic testing on MI. And we -- so by
24 putting it back in water service it allows us to do a
25 lot of things. So that's been one thing we've been
30
1 waiting for. But recently there was some testing done
2 on the well and the results have been less than
3 definitive and the -- and in our correspondence with
4 Mr. Regg we have decided just to keep the well shut-in
5 until this -- the results of this hearing are
6 completed. So as of right today we don't know what the
7 current -- the integrity status of that well is.
8 CHAIR FOERSTER: So it may have a leak?
9 MR. DETLETH: It may.
10 CHAIR FOERSTER: As a long -- long way of
11 saying we don't know if the well has.....
12 MR. DETLETH: It.....
13 CHAIR FOERSTER: .....integrity or not?
14 MR. DETLETH: .....may, but.....
15 CHAIR FOERSTER: Okay. That's why it's shut-in
16 because you don't know whether it has integrity or not?
17 MR. DETLETH: And that.....
18 CHAIR FOERSTER: Okay.
19 MR. DETLETH: .....that's correct.
20 CHAIR FOERSTER: Okay.
21 MR. DETLETH: Yes.
22 CHAIR FOERSTER: All right. I'm a man of few
23 words. You know, if you can say it in three don't say
24 it in 15.
25 MR. DETLETH: Right.
31
1 CHAIR FOERSTER: Okay. On November 13th you
2 looked at a trend plot of several days of pressure.
3 What was the first day that the pressure plot indicated
4 that there might be an issue?
5 MR. DETLETH: It's just a general trend, we
6 have.....
7 CHAIR FOERSTER: But it's a time plot, isn't
8 it, it's pressure versus time?
9 MR. DETLETH: We -- we have the trend plot here
10 that we originally submitted, but.....
11 (Whispered conversation)
12 MR. DETLETH: Sorry. We're.....
13 CHAIR FOERSTER: Pulling it out, right. So let
14 me ask my question more clearly.
15 MR. DETLETH: Okay. This trend plot started on
16 about -- it -- May 15th or May 28th I believe was the
17 exact date.
18 CHAIR FOERSTER: Okay. So you have data points
19 for several days that go.....
20 MR. DETLETH: Months.
21 CHAIR FOERSTER: .....and that goes from May
22 through November, through part -- through -- to
23 November 13th.
24 MR. DETLETH: Right.
25 CHAIR FOERSTER: So as you're looking at that
32
1 trend there's a date at which things start to suggest
2 there's possible pressure communication. What date was
3 that?
4 MR. DETLETH: Right from the beginning.
5 However this is looking at one piece of data that
6 doesn't tell the story. Okay. If you look at it with
7 the data that we submitted during our informal meeting
8 it doesn't look like there's any pressure associated,
9 any communication until about 10 days before the
10 enforcement -- before our notification. So looking at
11 the proper data is the most important thing to do.
12 CHAIR FOERSTER: So takes a -- look at all the
13 data that -- the pressure communication wasn't since
14 May, it was since 1st of November?
15 MR. DETLETH: About -- about approximately the
16 last -- about 25th of October or so.
17 CHAIR FOERSTER: Okay.
18 MR. DETLETH: Would have been more towards the
19 beginning of October.
20 CHAIR FOERSTER: Okay.
21 MR. DETLETH: But -- but I will go -- also I
22 want to mention that the entire pressure increase over
23 that interval was 150 pounds.
24 CHAIR FOERSTER: Okay.
25 MR. DETLETH: That is almost like a needle in a
33
1 haystack.
2 CHAIR FOERSTER: Okay. Thank you. I have a
3 few more questions, just gathering my thoughts here.
4 You talk about having your internal trigger being the
5 MAOP and where do you get that, what's the basis for
6 that?
7 MR. DETLETH: History, the -- the available
8 pressure limits of the tubulars that -- so that we
9 don't exceed -- we don't get up into a risky area of
10 reaching the limits of the pressure ratings of our
11 tubulars. And the 3,000 psi dates back to probably
12 around field start-up which was before my time up here
13 and it only applies to gas injectors. We don't have
14 any other wells in the field that are allowed to have
15 that high of pressure. But the gas injectors typically
16 are operated at 3,600 pounds or so injection pressure.
17 CHAIR FOERSTER: Do you guys deal with your
18 production wells differently than your injection wells,
19 do you have different pressure thresholds or.....
20 MR. DETLETH: Sure. We have well operating
21 guidelines that define the operating parameters for
22 each type of well we have.
23 CHAIR FOERSTER: Okay. So when you were
24 talking to Commissioner Norman you were saying that we
25 should consider additional mitigation because you've
34
1 got this elaborate system that's going to allow you to
2 ensure reg -- adequate regulatory compliance and that
3 should be our basis for considering further
4 reductions.....
5 MR. DETLETH: Yes.
6 CHAIR FOERSTER: .....of the fine? But isn't
7 adequate regulatory compliance a baseline expectation?
8 MR. DETLETH: Yes, it is.
9 CHAIR FOERSTER: Okay. All right. I don't
10 have any other questions unless I've inspired either of
11 you to have other questions? Go ahead, Commissioner
12 Norman.
13 COMMISSIONER NORMAN: I have one more -- one or
14 two more. I understand that injection into the well
15 ceased on or about November 1st; is that right?
16 MR. DETLETH: It -- we shut the well in or the
17 day we reported it so it was November 13th.
18 COMMISSIONER NORMAN: Okay. You shut it in,
19 but when did injection stop? That's -- that -- it's
20 reported in our decision I believe that it was November
21 1st. Let me find that for you. I believe I saw that
22 in the fact -- recitation of facts.
23 MR. DETLETH: well, the well was in service at
24 the.....
25 COMMISSIONER NORMAN: So on.....
W,
1 MR. DETLETH: .....at the date on Nov -- on
2 November 13th. And when we discovered the missed MIT
3 and we shut the well in on that date.
4 COMMISSIONER NORMAN: Okay. So I'm reading now
5 at page 4 under violations at about line one, two,
6 three, four. The well was returned to injection on
7 August 22nd and ceased taking injection November 1st,
8 2012. Is that date a misprint, should it be 2013?
9 MR. DETLETH: Yes, that's a misprint.
10 COMMISSIONER NORMAN: All right. To your --
11 attached to your letter of May 9th there was a plot.
12 Do you have that available to you where you could.....
13 MR. DETLETH: Yes.
14 COMMISSIONER NORMAN: .....could look at it?
15 As I'm understanding this your basic point is that
16 there is a triggering point at which reporting occurs,
17 something triggers reporting and until this triggering
18 point occurs you don't know to report. That -- that's
19 what I'm gleaning from the argument here. And this was
20 attached and this has on it a plot of both temperature
21 and inner annulus pressure?
22 MR. DETLETH: That's correct.
23 COMMISSIONER NORMAN: In looking at this we see
24 fluctuations in the pressure of the inner annulus and
25 I'm wondering at what point along here would someone
36
1 looking at this see a trigger point or would -- well,
2 first of all if you looked at this would you see a
3 trigger point that said we'd better report pressure?
4 MR. DETLETH: No.
5 COMMISSIONER NORMAN: Okay.
6 MR. DETLETH: Nowhere on this plot.
7 COMMISSIONER NORMAN: Nowhere on this plot.
8 Then why was this plot attached to this letter, I spent
9 a lot of time.....
10 MR. DETLETH: Because the.....
11 COMMISSIONER NORMAN: .....trying to read it
12 and under.....
13 MR. DETLETH: .....plot that was submitted with
14 the original report did not have this temperature curve
15 on there and if you only look at the annulus pressure
16 without the temperature on there it would make you
17 suspect there's something going on. And but it's a
18 cause and effect item, if we -- you put the temperature
19 on there then all the communication issues dropout.
20 There's a direct relationship here with the exception
21 of when you get to about halfway through October then
22 -- then that is a -- and I believe that's what we're
23 being fined on here, is it doesn't look like that last
24 little bit of the curve has a direct connection to the
25 temperature curve, but it only builds 150 psi, that's
37
1 five psi per day over that time period. And it still
2 does not reach any of our trigger points.
3 COMMISSIONER NORMAN: Yeah, that doesn't even
4 look like a curve to me, it looks odd, it -- it
5 flatlines.
6 MR. DETLETH: Right.
7 COMMISSIONER NORMAN: So is that.....
8 MR. DETLETH: And I believe that's what we're
9 being.....
10 COMMISSIONER NORMAN: .....is that a true.....
11 MR. DETLETH: .....that's.....
12 COMMISSIONER NORMAN: .....true plot -- is that
13 a true plot or is that just someone's.....
14 MR. DETLETH: No.
15 COMMISSIONER NORMAN: .....projection?
16 MR. DETLETH: No, that's right off -- that's
17 right out of the computer the way that -- out of our
18 data base.
19 COMMISSIONER NORMAN: Okay.
20 MR. DETLETH: So up -- up until the time we
21 reported this well there's no indication whatsoever of
22 any kind of -- of -- not a -- a communication issue or
23 -- or with the successful MITs prior to this -- this
24 time period that there was any reason to suspect that
25 the well had a problem.
t:
1 COMMISSIONER NORMAN: And finally what plot did
2 the engineer that made the decision to report look at
3 that caused him or her to determine that we'd better
4 report this, where's that document?
5 MR. DETLETH: We have a copy here that you can
6 -- that you can see.
7 COMMISSIONER NORMAN: Is -- has that been
8 submitted to us in our file, do we have that?
9 MR. DETLETH: Well, yes, because the reason it
10 was being put together was for the -- the quarterly
11 report that -- that we submit to the AOGCC.
12 COMMISSIONER NORMAN: Okay. Then I may have
13 seen it in the.....
14 MR. DETLETH: Yeah.
15 COMMISSIONER NORMAN: .....in the stuff -- in
16 the things. In fact.....
17 MR. DETLETH: And at.....
18 COMMISSIONER NORMAN: .....I think I did, it's
19 the document that shows.....
20 MR. DETLETH: .....in the informal hearing I
21 provided a copy.....
22 COMMISSIONER NORMAN: Yeah.
23 MR. DETLETH: .....back then. If you have.....
24 COMMISSIONER NORMAN: I do recall seeing it,
25 it's a series of dots that trend upward?
39
1 MR. DETLETH: Yeah.
2 COMMISSIONER NORMAN: Okay.
3 MR. DETLETH: Right. Yeah. Now I do believe
4 that a lot of where we are today is the fact that what
5 we originally submitted was not a very good trend plot
6 and I don't -- we're not going to keep doing that.
7 These -- anytime we need to report something we need to
8 report the best data we have and that would have been
9 this other plot and we -- so that is definitely an
10 improvement that we're implementing.
11 COMMISSIONER NORMAN: Okay. I have no further
12 questions.
13 CHAIR FOERSTER: I have a couple more. I'm
14 looking at my notes and I was told that our inspectors
15 went out for some MIT attempts this year on August 23rd
16 and 25th and there were some anomalous conditions
17 observed. That's all I've got in my notes. Do you --
18 are you familiar with what that means and can you
19 explain that to me?
20 MR. DETLETH: In relation to this well?
21 CHAIR FOERSTER: No.
22 MR. DETLETH: No, I don't. This well.....
23 CHAIR FOERSTER: Okay. Well, this well should
24 be shut-in or -- if what you're telling me.....
25 MR. DETLETH: .....this well was shut-in when
1 the pad was tested in August. Are you talking about
2 this August.....
3 CHAIR FOERSTER: Yes.
4 MR. DETLETH: .....or a year ago?
5 CHAIR FOERSTER: Oh. No, this August. Yeah,
6 is it -- it's confusing. But no, I had some notes that
7 the inspectors were out for some MIT testing on a -- on
8 a ConocoPhillips site on -- on those two dates and had
9 some discomfort.
10 MR. DETLETH: I am aware that there were some
11 comments or notes made by the field inspectors and
12 there's still a -- let's just say a differing opinion
13 on the status of the well. So it will remain shut-in
14 until we're ready to bring it up again.
15 CHAIR FOERSTER: Could you explain what the
16 difference of opinion is?
17 MR. DETLETH: We did not want to -- I'm trying
18 to be careful with my wording as well. There were some
19 comments made by the field inspectors about gas smell
20 or something like that that's unrelated to -- to a
21 passing or failing MIT. And Mr. Regg voided one of our
22 tests that was done that day, but we were in the
23 process of leading up to this hearing and so we just
24 made a decision to not proceed any further down the
25 road on whether those wells were -- tests were
41
1 successful or not until this hearing had -- had wound-
2 up and we move forward on what we're going to do with
3 the well.
4 CHAIR FOERSTER: I'm not sure I understand what
5 you're saying. I mean, I understand what you're
6 saying, but I'm not sure that it provides me
7 information.
8 MR. DETLETH: Okay.
9 CHAIR FOERSTER: I think you're being too
10 careful, you're being so careful that you're not
11 answering my question.
12 MR. DETLETH: I don't know exactly what those
13 inspectors said, I do know that there's -- by the
14 pressures that we saw on those tests they should have
15 been good and they have been changed to a fail. So
16 we'll have to resolve what that is.
17 CHAIR FOERSTER: So have they been retested?
18 MR. DETLETH: We will.....
19 CHAIR FOERSTER: And so if.....
20 MR. DETLETH: .....soon.
21 CHAIR FOERSTER: .....so if they failed the MIT
22 then what's the.....
23 MR. DETLETH: They did not fail the MIT in our --
24 by the -- by MIT criteria.
25 CHAIR FOERSTER: Then why are they classified
42
1 as a fail?
2 MR. DETLETH: I think we need to ask Mr. Regg.
3 CHAIR FOERSTER: Okay. So Conoco has its set
4 of rules and it passed.....
5 MR. DETLETH: Your.....
6 CHAIR FOERSTER: .....your set of rules, but we
7 have the state's set of rules and it didn't pass those?
8 MR. DETLETH: No, it passed those.
9 CHAIR FOERSTER: Then why is it classified as a
10 fail, I'm still not understanding?
11 MR. DETLETH: I can't answer for Mr. Regg so
12 we'll have to deal with that in another forum.
13 CHAIR FOERSTER: Wow. Okay. I may have more
14 questions for you on that later. You said that you
15 have different requirements for reporting and for
16 evaluating for different kind of wells. Can you
17 describe to me what your criteria are for production
18 wells versus injection wells, what your thresholds are
19 or identifying a problem and when notification is
20 required?
21 MR. DETLETH: On a injection well, I've
22 mentioned most of those here, that we have annular
23 pressure limits and typically on a water injector -- on
24 an annulus it's 2,000 psi and that's on an inner
25 annulus and an outer annulus is 1,000. In general that
43
1 holds true for -- for production wells also, but the --
2 on the addition with the injector is maintaining that
3 500 pound differential between the annulus and the
4 tubing because if you can't maintain that differential
5 that's a clear sign that you've got communication going
6 on. And our computer systems are designed to monitor
7 all the wells, all the injectors, for that on a
8 continuing basis. So if any one of those wells
9 develops communication and it -- it gets within -- less
10 than 500 pound dp it flags it, sends an alert. There's
11 also however how many bleeds, if we start having to
12 bleed an annulus we -- we track all that and when you
13 start having to bleed an annulus more than just
14 occasionally then that generates a visit to the well
15 for diagnostics and if we find or suspect communication
16 that's another reason to report. So there -- there's a
17 number of trigger points and we use the computer system
18 to our advantage to be able to look at all of these
19 wells. Now on a producing well when we're talking
20 about gaslift and things like that we -- the 500 pound
21 differential is meaningless so that's not an item for
22 that. But on a producer we don't allow tubing by
23 annulus communication because is that another
24 regulatory no no and so we have very strict rules about
25 dealing with those and getting those repaired so that
1 we don't have any of those out of compliance.
2 CHAIR FOERSTER: So what was the maximum
3 annular pressure that you noticed in the 3Q-16?
4 MR. DETLETH: I've got it right here, it's --
5 went to about 2,650.
6 CHAIR FOERSTER: So -- okay. Now.....
7 MR. DETLETH: But the tubing injection pressure
8 was like 3,600. It was like 1,000 pounds higher.
9 CHAIR FOERSTER: Okay. So -- but I thought I
10 remembered you saying that there was a IA maximum of
11 2,000 and an OA of 1,000?
12 MR. DETLETH: On a -- on a gas injector it's
13 3,000, okay, we never reached that so that trigger was
14 never -- never met. It was almost -- it was 900 psi
15 plus differential between the annulus and the tubing so
16 it never reached that 500 pound differential.....
17 CHAIR FOERSTER: Okay.
18 MR. DETLETH: .....and there was no bleeding
19 and all the previous MITs, state witnessed and -- and
20 diagnostic MITs, had all passed. No reason to suspect
21 this well had a problem.
22 CHAIR FOERSTER: Okay. All right. So I know
23 you're trying to be really, really careful and I
24 understand that and I understand that you've got a
25 lawyer sitting right behind you who's going to stab you
1 if you're not really careful. So but I'm trying to
2 understand so be patient with me as I'm being patient
3 with you. You've got the well shut-in now and you're
4 not sure if it has integrity or not. So I'm struggling
5 a little bit with feeling comfortable that your systems
6 for detecting a problem are adequate. So make me feel
7 a little bit better about that.
8 MR. DETLETH: Well, we're using your test to
9 determine mechanical integrity.
10 CHAIR FOERSTER: And.....
11 MR. DETLETH: The MIT is what we use to
12 determine if a well has mechanical integrity. And
13 if.....
14 CHAIR FOERSTER: Okay.
15 MR. DETLETH: .....if we.....
16 CHAIR FOERSTER: And I thought you said you
17 didn't know -- a minute ago you said you didn't know
18 whether this well had integrity or not?
19 MR. DETLETH: The well has recently been tested
20 and apparently your staff in town may disagree with the
21 results of that test.
22 CHAIR FOERSTER: Okay. The -- and I thought we
23 liked to test the wells after they'd been on production
24 for a while?
25 MR. DETLETH: We -- we do diagnostic tests
If
1 anytime we -- we feel we need to, but we do state
2 witnessed, the official regulatory test is typically
3 done when the well's in service.
4 CHAIR FOERSTER: So why do we require that it
5 be done after the well has been on production for a
6 while?
7 MR. DETLETH: I don't know, but I disagree with
8 that completely.
9 CHAIR FOERSTER: You do?
10 MR. DETLETH: I do.
11 CHAIR FOERSTER: Okay. So it sounds like we
12 have some real technical issues that are outside of the
13 realm of this enforcement action, but could impact
14 future regulatory compliance that we need to come to
15 some understanding on, that -- what I'm saying is, you
16 know, I don't want to be having a discussion with you
17 guys every six months because you made a decision and
18 it disagrees with our decision and you think we're
19 wrong and we think you're wrong. I -- you know what
20 I'm saying, I think -- I think that there's a systemic
21 issue here that goes beyond an enforcement action. And
22 I am looking back at your boss' boss, and saying that
23 you and I need to talk.
24 Okay. I don't have any other questions at this
25 point. So if the next witness wants to speak then
47
1 let's go there. And you'll remain under the oath for
2 the duration of the hearing and you're already under
3 oath. Now, Mr. Robinson, are you going to testify?
4 MR. ROBINSON: Can we confer with out.....
5 CHAIR FOERSTER: You can confer.
6 MR. ROBINSON: Can we have a few minutes to
7 confer?
8 CHAIR FOERSTER: Sure. We'll recess.
9 (Off record)
10 (On record)
11 CHAIR FOERSTER: We're back on the record. So
12 Mr. Robinson, are you going to testify?
13 MR. ROBINSON: I am.
14 CHAIR FOERSTER: All right. So you're still
15 under oath. So what I need for you to do for the
16 record is your name, who you represent, if you want to
17 be recognized as an expert what that area is and what
18 are your qualifications.
19 MR. ROBINSON: Okay. So my name is Sean
20 Robinson, I'm the wells manager for ConocoPhillips
21 Alaska. So that includes basically any of the wells
22 that need to be repaired or -- with regard to well
23 integrity fall under my stewardship. I've got -- I'm
24 in my eighteenth year of working in the oil and gas
25 industry, significant experience in designing and
0
1 constructing quality wellbores, drilling, completions
2 operations, fracture, those type of operations and then
3 I've been working with the well integrity on wells that
4 have problems.
5 CHAIR FOERSTER: And do you want to be.....
6 MR. ROBINSON: So.....
7 CHAIR FOERSTER: .....recognized as an expert?
8 MR. ROBINSON: An expert witness, please. I do
9 have an engineering degree as well as a master's
10 degree.
11 CHAIR FOERSTER: Okay. Do you have any
12 questions?
13 COMMISSIONER SEAMOUNT: Which discipline do you
14 want to be considered an expert in?
15 MR. ROBINSON: That's a good question. Well
16 integrity for -- for this instance.
17 COMMISSIONER SEAMOUNT: I have no questions, no
18 objections.
19 COMMISSIONER NORMAN: Your master's degree is
20 in engineering?
21 MR. ROBINSON: No, it's in business.
22 COMMISSIONER NORMAN: Business.
23 MR. ROBINSON: Yes.
24 COMMISSIONER NORMAN: No further questions.
25 CHAIR FOERSTER: What's your bachelor's degree
1 in?
2 MR. ROBINSON: It's in mechanical engineering.
3 CHAIR FOERSTER: Mechanical engineering. Okay.
4 Where'd you get it?
5 MR. ROBINSON: Brigham Young University.
6 CHAIR FOERSTER: Okay. No problems recognizing
7 Mr. Robinson as an expert witness? Okay.
8 COMMISSIONER NORMAN: No problem.
9 CHAIR FOERSTER: You may proceed.
10 SEAN ROBINSON
11 previously sworn, testified as follows on:
12 DIRECT EXAMINATION
13 MR. ROBINSON: Okay. Three points. The first
14 is relatively simple with relation to the additional
15 corrective actions and the request with regard to the
16 missed MIT on reduced penalties. We recognize that the
17 Commission has already reduced the fine significantly.
18 In the document that was sent to us it outlined a few
19 of the mitigating factors the Commission --
20 Commissioner Norman referred to. The one that wasn't
21 specifically mentioned in there was this fit for
22 service charter that ConocoPhillips is working on. We
23 recognize that the base case is complete compliance
24 with regulation so that -- that's clearly understood.
25 We recognize that is our base case. The -- this fit
50
1 for service charter we feel is a -- we probably haven't
2 impressed the significance and the effort that's going
3 into this as well as possibly we should have. We have
4 multiple different systems from the MIT, the mechanical
5 integrity testing systems, the safety system lockout
6 type systems, all of these pressure type systems, we're
7 integrating all of those efforts into one integrated IT
8 solution. That's why it's taking so long, but it is a
9 significant effort and has a lot of backing by upper
10 management. So again we recognize the Commission has
11 reduced that fine significantly, but again we just
12 wanted -- because it wasn't specifically enumerated in
13 the letter we wanted to impress upon the Commissioners
14 the effort that is going into it is not insignificant.
15 So that's the first point.
16 The second point is -- is simply with regard to
17 the mechanical integrity tests that have occurred on
18 the 3 Quebec 16 well. We referenced two tests that
19 occurred immediately following the recognition of the
20 missed MIT so in the November time frame did two
21 integrity tests. Those were not witnessed by the
22 state, but as part of our -- ConocoPhillips' diagnostic
23 testing as soon as we recognized the potential issue
24 and that oversight, we wanted to understand the
25 integrity of that well. It passed in our opinion in
51
1 both cases according to state criteria, however we also
2 recognize the state witness was not -- did not witness
3 those tests. Further in August of this year we
4 conducted two mechanical integrity tests on the same
5 well so just last month, both of those according to
6 state criteria also passed. And we have no -- so both
7 of them passed however according to this -- that's
8 according to the state inspector onsite, when it came
9 to town one of those inspections was reverted to a
10 fail. However -- so that's the issue that we'll need
11 to handle later on, but we're comfortable operating
12 that well.
13 CHAIR FOERSTER: So the inspector passed
14 it.....
15 MR. ROBINSON: The onsite.....
16 CHAIR FOERSTER: .....onsite?
17 MR. ROBINSON: .....inspector, correct.
18 CHAIR FOERSTER: Okay. I'm looking at a piece
19 of paper that says something different. So maybe --
20 just proceed, you are under oath.
21 MR. ROBINSON: Okay. Then the final -- the
22 final point is just with regard to the second issue
23 which is the timely reporting of the -- the missed MIT.
24 Sorry, not the missed MIT, of the communication issue.
25 As soon as we noticed it, we reported it. I think
52
1 that's the -- the key of the argument. As soon as we
2 recognized there was an issue we reported it right
3 away.
4 CHAIR FOERSTER: Okay.
5 MR. ROBINSON: I think that.....
6 CHAIR FOERSTER: Great.
7 MR. ROBINSON: .....ends my testimony.
8 CHAIR FOERSTER: Do you have any questions for
9 this witness, Commissioner Norman?
10 COMMISSIONER NORMAN: Yes, I'll give the
11 witness a moment.
12 CHAIR FOERSTER: Okay.
13 COMMISSIONER NORMAN: Mr. Robinson, generally
14 speaking in an administrative proceeding like a court
15 of law generally we're looking backwards at what
16 happened and fashioning a penalty or remedy and then
17 sometimes what the offender, if you will, promises to
18 do could be taken into consideration in reduction of a
19 sentence or penalty going forward if it is done and
20 evidence of that is brought in. I mean, occasionally
21 that -- once in a while you see that, but generally the
22 focus is on what occurred and I think generally that's
23 where our focus stays. But with what you said in mind
24 about what is being done, that is noted, it's
25 appreciated, and it is what we would expect of an
53
1 operator like ConocoPhillips.
2 I'm looking at page 6 of Order No. 81, the
3 proposed order, if you have it. And I wanted you to
4 comment on the two items or the three items there and
5 then indicate what you are doing beyond those three
6 items. Your characterization of it I think went beyond
7 that was slightly more expansive. So I wonder if you
8 could enlarge on what you're doing beyond what the
9 Commission is ordering right here?
10 MR. ROBINSON: So the -- so just for clarity --
11 is that the end of your question? Sorry, did I -- I
12 didn't want to interrupt.
13 COMMISSIONER NORMAN: I'm sorry, did you want
14 my question again?
15 MR. ROBINSON: No, is -- I just wanted to make
16 sure that was the end of your question and then I'm
17 going to try and clarify.
18 COMMISSIONER NORMAN: Yes, that finishes my
19 question.
20 MR. ROBINSON: So on page 6, item number 2, you
21 want clarity on items one, two and three; is that
22 correct?
23 COMMISSIONER NORMAN: That is correct. And by
24 way of background, you asked us to take into
25 consideration the steps and procedures that you're
54
1 working on now and that you will -- I understood you to
2 say you will complete.....
3 MR. ROBINSON: Correct.
4 COMMISSIONER NORMAN: .....meaning in the
5 future you will complete?
6 MR. ROBINSON: Definitely future.
7 COMMISSIONER NORMAN: Yes. And so what I'm
8 trying to do is understand what you're working on and
9 what you will complete in terms of the three items
10 listed here. Are any of these the same or are they
11 expansions on these three items, do they overlap?
12 MR. ROBINSON: Okay. I think I understand so
13 let me give it a shot. So item number 1 is provide a
14 detailed description of our UIC regulatory compliance
15 program. So, I mean, there's the past and the future.
16 We -- the past or what we do today is easily done, no
17 issues. The future we may with this enhanced system
18 we're going to give six monthly updates, I think that's
19 actually requested, maybe not in this letter, but we
20 plan to give six monthly updates on the progress on
21 what we call the fit for service work. So that may
22 change over time and obviously for the better, not for
23 the worse.
24 The second item, details of the tracking system
25 for determining when MITs are required. Because I
55
9
1 think that's very, very similar. Again we can provide
2 what we do today plus we have the interim solution
3 which isn't the long term solution, but the -- the six
4 monthly updates I think will give you insights into
5 what -- the level of effort that's going in. And then
6 the RCA, we're happy to provide the -- the analysis.
7 That's completed as Mr. Detleth mentioned, some of
8 those items are completed including hiring of an
9 additional individual to assist in this effort.....
10 COMMISSIONER NORMAN: And then.....
11 MR. ROBINSON: .....as well as the training,
12 sorry, for relief, when people are not in position.
13 COMMISSIONER NORMAN: I'm sorry, I didn't mean
14 to interrupt. So go ahead and finish what -- your.....
15 MR. ROBINSON: No, that's -- that was -- that's
16 it.
17 COMMISSIONER NORMAN: Okay. And then could you
18 now take what you are doing now beyond these three
19 items and explain to us what ConocoPhillips is involved
20 in going forward for the future in addition to these
21 that will expand on and enhance these three items?
22 MR. ROBINSON: Okay. We probably could refer
23 to slide -- if I can find it. We tried to put quite a
24 bit of detail on this particular slide because it was --
25 there is quite a few -- there are quite a few things
56
0
1 we're trying to link together and tie together. Let me
2 find the slide. Sounds like slide nine. Are you able
3 to find that? Okay.
4 COMMISSIONER NORMAN: I have.
5 MR. ROBINSON: So in -- as examples we have
6 defeated safety logs under the second bullet there --
7 or maybe I should go through in it -- just in -- I'll
8 go through all of it again really quickly, is that.....
9 COMMISSIONER NORMAN: I can read it, if you
10 could just summarize it in your own words though.
11 MR. ROBINSON: Okay. The -- the big level
12 summary is we have a lot of different systems that
13 currently aren't integrated as adequately as we -- they
14 should be. And we had built -- we had essentially work
15 arounds or different things that weren't linked
16 together as well as they should. The charter is to
17 bring all that together and make one whole system which
18 is extremely complex because of the -- all of the
19 different regulatory and -- and operating procedures
20 that we need to comply with for our own internal
21 satisfaction as well as the AOGCC's. Does that
22 summarize it?
23 COMMISSIONER NORMAN: Yes.
24 MR. ROBINSON: Okay.
25 COMMISSIONER NORMAN: Thank you. And my final
57
1 question -- my last question for you, I'm looking at
2 your May 9th letter, you don't need to have it in front
3 of you and I'll read it and give you time to look at it
4 if you need it, but Commissioner Foerster touched on
5 this and it's been on my mind also. I'll read the
6 sentence or at least the opening phrase slowly.
7 ConocoPhillips currently has approximately 60 injection
8 wells with suspected or confirmed communication issues
9 that resulted in administrative approvals to keep the
10 wells in service. For each of these wells as soon as
11 can, et cetera, et cetera. What I am wondering is how
12 do we reconcile the Commission's regulatory
13 responsibilities that we have expressed in our order
14 here, our enforcement order, with apparently what is
15 ConocoPhillips' interpretation of good oilfield
16 practice as result -- as related to all of the wells
17 that you have to avoid some repetitive incidents and
18 possibly future hearings like this?
19 MR. ROBINSON: So I'm not completely sure I
20 understand.....
21 COMMISSIONER NORMAN: Well, maybe.....
22 MR. ROBINSON: .....the question.
23 COMMISSIONER NORMAN: Yeah, let me try to
24 restate it again. If what happened on this particular
25 well is reflective of acceptable practice which I
58
1 understand it is within ConocoPhillips, that seems to
2 be the testimony that it is, then do you have any
3 suggestions for bringing that practice in line with
4 what the Commission considers as acceptable practice as
5 expressed in our enforcement order and regulations and
6 conservation orders?
7 MR. ROBINSON: I think I understand. Can I
8 clarify? So in the enforcement letter there are two --
9 in my mind two distinct, missing of the MIT as well as
10 the non -reporting. Are you referring to one or the
11 other or both?
12 COMMISSIONER NORMAN: No, I'm not referring to
13 the missing MIT, I understand that incident and that's
14 distinct. I'm more referring to the second incident.
15 MR. ROBINSON: Okay. All right. So now again
16 just to be crystal clear, so the question is the
17 AOGCC's opinion, not opinion, regulations and how
18 ConocoPhillips complies with that; is that.....
19 COMMISSIONER NORMAN: Yes, I mean, for example,
20 you indicated that you manage gas injection wells
21 different than oil wells, for example?
22 MR. ROBINSON: Correct.
23 COMMISSIONER NORMAN: That you have certain --
24 your opinion and Mr. Detleth's opinion is that you
25 followed proper procedures, it's the opinion of the
59
1 Commission that proper procedures were not followed.
2 Those positions needs to be reconciled and if that --
3 when you walk out of this room you continue to believe
4 you're following proper procedures then that's
5 problematic for the future. That -- that's where I'm
6 headed. If you don't have a ready answer for that now
7 that's fair enough because it's also something the
8 Commission has to grapple with, but.....
9 MR. ROBINSON: Right.
10 COMMISSIONER NORMAN: .....while you were there
11 I'd like to ask that broader question and just see if
12 you have an opinion on it.
13 MR. ROBINSON: I do. I -- I think -- I don't
14 think that I can answer now. I think -- I think the
15 correct way to do it is in -- is meet and discuss and
16 agree. And I think the regulations are clear and to
17 comply with the regulations we need to make sure that
18 we're -- as well as our own operating practices, to
19 make sure we have wells with good integrity. we need
20 to agree so as Commissioner Foerster mentioned we don't
21 want to be here next week, next month doing -- arguing
22 about this same issue. I -- anyway so I don't know
23 that I have an answer, but very interested in working
24 with the Commission to make it crystal clear so that
25 we're all working to the same end which I believe we
1 are which is having wells with integrity.
2 COMMISSIONER NORMAN: Good. Thank you for that
3 answer.
4 CHAIR FOERSTER: Commissioner Seamount, do you
5 have any questions of Mr......
6 COMMISSIONER SEAMOUNT: I have none.
7 CHAIR FOERSTER: Where to begin. Mr. Robinson,
8 you mentioned a minute ago that the -- this August 3Q-
9 16 met the state's requirements for passing an MIT. I
10 want you to have -- this is yours, you can keep it.
11 I'm going to read it out loud for the record and I will
12 get a copy for you for the record, Nathan.
13 In the note section of the August 27th MIT, it
14 says MIT for AA request. Large amounts of gas with a
15 rich smell in the inner annulus, bled twice to fluid
16 with gas appearing again both times. I consider this a
17 no test. That's not a pass. I consider this is a no
18 test as there was too much gas in the annulus to
19 perform valid test. ConocoPhillips rep tested well
20 with this understanding. Above readings were after
21 pumping nine barrels of diesel to bring to pressure
22 noted, afterward it was bled to production so return
23 volume was not obtained. Suggest leaving IA open to
24 atmosphere bleed system to allow MI to cook off. This
25 does not sound to me like something I'm happy about if
61
1 I'm the inspector out there, it sounds to me like
2 something that wasn't a passed test and when you
3 testify under oath you need to be sure that you know
4 the facts. Do you have anything to say about this to
5 make me feel better?
6 MR. ROBINSON: Well, I'd agree that this test
7 shows -- has a -- has a no test.
8 CHAIR FOERSTER: Thank you. I really only have
9 one thing more to say before I feel okay about
10 adjourning this hearing and that is since right now
11 we're not fully aligned on what's the right way to do
12 things, until we get fully aligned I suggest that you
13 follow the state's regulations. And if you need help
14 doing that there are a lot of other operators in the
15 state who we're not having these conversations with who
16 can tell you how to do it.
17 Does anyone else have anything they'd like to
18 say?
19 COMMISSIONER SEAMOUNT: No.
20 COMMISSIONER NORMAN: Nothing further.
21 CHAIR FOERSTER: All right. Is there anyone
22 else who'd like to testify or do you guys have anything
23 else?
24 (No audible response)
25 CHAIR FOERSTER: All right. Adjourned.
62
•
•
(Adjourned - 10:40 a.m.)
(END OF PROCEEDINGS)
63
0
1 TRANSCRIBER'S CERTIFICATE
2 I, Salena A. Hile, hereby certify that the
3 foregoing pages numbered 06 through 64 are a true,
4 accurate, and complete transcript of proceedings in re:
5 Order No. 81, Kuparuk River Unit 3Q-16 public hearing,
6 Volume II transcribed under my direction from a copy of
7 an electronic sound recording to the best of our
8 knowledge and ability.
9
10
11 Date Salena A. Hile, Transcriber
12
64
0
•
i
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
Public Hearing on
Request for Reconsideration
KRU 3Q-16
September 11, 2013 at 9:00 a.m.
SIGN IN SHEET
NAME AFFILIATION TESTIFYING
YES OR NO
UM jqe- (-eDA C PA( NO
mm n - un ky ►/ At 61 Cf-.,
51
I ��
a
LU c_h
> VR
N
WV
W
CC
•
b-0
L..
Ct3
V
CL
0
s.:
•
4.�
Iri ok
•
•
O
-i--a
U
0
c
c
O
.Z7;
c
O
U
Q)
re
L
0
cn
a�
LO
m
O
N
101
Ln
a--+
L
G �
_0 aA
Q
un a--+
.E Q
L-
O
+j
O
E U
f� C-
f0 �
E
U
ri [V
(A U0
■ ■
i
0
0
•
s
t uo
E
Q)
U
0
W
Ln
O
0-
0
O
r
■
m
_O
a
Z3
■
0
ro
.E
E
E
O
U
Ln
Ln
L
Q
Q)
Q)
E
:4-j
O
a--j
N
■
0
r"I
00
U
U
CD
O
a
C
O
U
U
0
O
a
CAA
O
N
c6
E
L
0
N
U
O
z
O
0
L-
Q.
Ln
•
r-1
O
N
m
0
U
U
CD
0
Q
a-J
0
c�
G
CA
G�
t�
w
LVEL
U
0
U
c
O
Q
E
U
3
.e,
u
a--j
O
-j
+-j
Q
U
Ln
.0
.E
a-'
4-J
E
�--+
NO
c
—
N
O
�
-a
O
+�
L-
+,
c6
Q
tiA
O
E
E
O
bn
u
\
4 -'
-a
m
-0
(1)
�
U
0-
-0
0
.�
Q
Ln
C6
U �
au o
o
04-
" ro
-3-0
V) aA
aA
O
N ro V)
Q
O -c-
+,
O
Q O
C6
0. U
+-
-0E
.� E
0-O O
� U
n >
Q
U . O
1
(
D-
Q
om
Lq44l
N — N
Ln C6
N � � E Q)
s-
o _ ' cn o
C:
N i -0 O W
ca Q L .0 V N Ln • �
o •Ln � v �
i 0 p O U-0
a� CU O. o -0 Q W
o� v cr' H' O chi) `� — O E
n :U1:3) .� •� s
4 .O — n p N :� 00
x O • � .� N -� +- z ,� aA 00
� O N C
U
O ca O L.ro
U un M U
� o o L7 °- O
E
�- •- - O o Q
Lu ; a a Q
2 .. u _ m
`o N .. .. N •-
Q r.
cc .. .. N N r-I ri m m 0
�\ \ \ rl ri N � \ ri ri \ \ � E r�l N rl O l0
_ N \ \ N
• N rl 00 N N \ E \ \ ri (� ri
i=
L
(A
O
4)
�
4�
•
C-7
V)
to
i�
Ow
O
a
O
U
a
>
O
un
O
cn
N
U
\
-
4-'
�
0
Ul
O
U
i
U
�
m
�
�
�
�
�Q
N
O
Ln
�-.
:
O
ca
Ln
E
Ln
N
O
U
O
m
>
a
o
OU
E
O
-
U
_0
�
M
U
aQ.
ate.
CD
O
U
U
E
Q
■
■
O
Ln
.O
U
m
cn
X
Q)
c
E
0
E
O
~�
Ln
Q)
u
(U..
Ln
a--+
C
O
u , U_
--
L
O
Q)
Q
>
L
Ln
S—
4-'
Un
(1)
—
—
(1)
Q)
>
Q)
v)
Urn
Un
G
p
�'
U
.C:
O
O
a--�
4-
U
4—
J
c
U
ate-+-+
>
U
E
Q�
CAA
�
�
cn
t1A
C~
0
v
O
ca
ca
+-'
Ln
4A
(B
•—
`�
U
•�
CA
O
•�
(/)
.2
U
m
L
U
U
N
0
L-
Q
4-J
o
'ca
dJ
Q�
t�0
0-
+
C
—
�
aU
m
E
w
cn
O
Q_
U
O
.�
Q
U4-J
i
O
c
}'
O
N
tw
IQU)
O
'—
V
Q
U
w
Q
>
U,
0
a
V
a
U
a--+
N
N
Un
4-J
N
ate-+
U
C6
Q
E
0
ate-+
f�
L
0-
0
O
N
L
C6
Ln
U
Ln
v
mi
■
L
L
O
a--+
X
_=3
O
L)
' Un
N
a--+
Q-
i
E
N
-0
O
U
E
O
U
ate-+
v
O
Urn
N
O
�-
=3
U
Un
ca
N
O
Lun
E
_�
a-
E
•—
-0
m
Q)
c:
O
o
-o
N
U
dJ
Q
O
C6
+•�
E
0-
E
c6
-0
a
a--+
U
O
Q
ate--+
U
O
Q
O
E
t
0
a;
i.i
�>
O
U
Q
o
•�
Ln
c-
C
-0
p
0
O
Q)
E
U
O
Q)
a--+
Ln
Ln
E
•I--�
C6
C6
>`
>
-
'
U
a--j
Q
N
Q
C6
.�
U
C
4-�
.i
Q
O
U
�
o
.
+-+
bO
U
•�
U
�
V
+�
._
O
•
Q
U
O
(1)
4-J
cu
>
O
N
0
V
4-+
-j
—
O
Ln
00
Zi
w
._
C
�
L
. —
O
v
4-j
U
u)
ca
cn
Q)
r-�
a)
-
Lr)
>
}'
O_'
cr
O
(1)
O
m
U
m
Ln
w
a
Q
N
O
"
Q
00
I—
°-
U
._
E
L.
a-
U
N
•tn-
L
0
N
L�
•
v
�
v
�
O
�
�
�
a
�
�
O
O
E
E
O
V
��
a
un
O.
=
v
O
.�
i
i
O
QO
cc
LM
O
nJ
�
•-
4-0
Qj
.�
U
_S4
cr
'
'i '
i
>
i
Q.
O
LM
Q
O
:�
O
m
t4--
a
7
W
O
L •
Q
(j)
�
v
a
0
o
�
�
•-
U
o
v
O
c:
v
a
a
�O
cii
a
•-
O
O
a
v
—
4-j
a
O
V
.0
.�
4-1
u
o
.�
a
�
°
v
�
a
4-1
,o
4-1
O
v
v
•`�
4�
i
o
Ln
�
o
a
N
v
O
V
v
U
4-1
�
O
O
a
v
0
0
`4F L__.j
0
4-J
0
4-J
•
4-j
u
0
C:
Q.
Z3
(1)
N
C:
E
E
.0
0cn
u
4-J
E
u
CL)
0
(1)
D
U
CL)
U
(A
ro
U
0
Lf)
<
I-j
o
o
0
m
0
L-
0
+-j
ro
4-J
-0
4-j
Q)
4-J
E
Q)
S-
.E
4-j
m
E
Ln
<
Ln
<
u
u
LF-
u
1
L
O
f�
Q)
� O
c C:
M O
i
O
y_ U
N •E
.O E
E
O
i U
N O
0 O
�Oi >
a
a�
O
z O
co O
O
z i
O
0
Q
4-
O
U
2
Ln
(�
O
Qul
U
+J
O
O
�
=
U
C:
O
m
U
.�
0
U
.�
•v
Q
O
0
_0
�_
(1)
E
�
O
-j
•�
C6
cn
O
U
ate.,
•
N
Ln
Q
Q
U
can
O
JCZ-
}'
�
m
ca
o
O
.�
rl
O
O
�
O
QQ�
�O
V
o
N
Ln
Ln
0
.o
.o
447—
+-j
M
0-E
Q
o
�
Q
�-
un
cn
.V
N
Q
v1
Q
s
O
■
CAA
a-
�-
Q
U
V)
•
_0
Q)
N
E
Q)
Q)
+j
.10
U
O
(n
W
a-J
C6
Q)
Q
a--j
V
Q)
w
O
\V
V
E
E
O
V
L
cn
Q)
i
Q
U
U
O
Q
a--)
C- O
Cu
Cl) a�
co E
V •
O 4-'
V / CU
� T
� Q
C- ro
+ --J C-
CU a-j
a-J C:
c6 O
• — cn
E •V
w -�
1
#11
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE: Tuesday, August 27, 2013
TO: Jim Regg
P.I. Supervisor SUBJECT: Mechanical Integrity Tests
CONOCOPHILLIPS ALASKA INC
3Q-16
FROM: Lou Grimaldi KUPARUK RIV UNIT 3Q-16
Petroleum Inspector
Src: Inspector
Reviewed By:
P.I. Supry _
NON -CONFIDENTIAL Comm
Well Name KUPARUK RIV UNIT 3Q-16 API Well Number 50-029-21667-00-00 Inspector Name: Lou Grimaldi
Permit Number: 186-179-0 Inspection Date: 812312013
Insp Num: mitLG130825173505
Rel Insp Num:
Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min
Well
I 3Q-16
Type Inj
W
TVD
6azz
IA
1508
3390
3249
3205
3180
PTD
1861790
Type Test
SPT
Test psi
1606
OA
479
817
772
741
717
—
Interval
OTHERP/F
1
Tubing
2678
2630
2599
2595
2594
Notes: MIT for AA request. Large amounts of gas (rich smell) in IA. Bled twice to fluid with gas appearing again both times. I consider this a "No
Test" as there was too much gas in the annulus to perform valid test. CPAI rep tested well with this understanding. Above readings were after
pumping 9 bbl's of diesel to bring to pressure noted. Afterwards IA was bled to production so return volume was not obtained. Suggest
leaving IA open to atmospheric bleed system to allow MI to "cook off'.
#10
dp
•
1 ALASKA OIL AND GAS CONSERVATION COMMISSION
2 Before Commissioners: Cathy Foerster, Chair
3 Daniel T. Seamount
4 John K. Norman
5
6 In the Matter of ConocoPhillips )
7 Alaska's Request for )
8 Reconsideration of Other Order )
9 No. 81, Kuparuk River Unit 3Q-16. )
10 )
11 ALASKA OIL and GAS CONSERVATION COMMISSION
12 Anchorage, Alaska
13 August 20, 2013
14 9:00 o'clock a.m.
15 VOLUME I
16 PUBLIC HEARING
17 BEFORE: Daniel T. Seamount, Commissioner
•
TABLE OF CONTENTS
2 Remarks by Commissioner Seamount 03
1 P R O C E E D I N G S
2 (On record - 9:01 a.m.)
3 CHAIR FOERSTER: On the record. I'd like to
4 call this hearing to order. Today is August 20th,
5 2013, the time is 9:01 a.m. We're located at 333 West
6 Seventh Avenue, Anchorage, Alaska, these are the
7 offices of the Alaska Oil & Gas Conservation
8 Commission.
9 My name is Dan Seamount, I'm the Geology
10 Commissioner.
11 Computer Matrix is recording the proceedings,
12 you can get a transcript from Computer Matrix.
13 This is a hearing regarding ConocoPhillips
14 Alaska, Incorporated's application for reconsidering of
15 Other Order No. 81, Kuparuk River Unit, Well 3Q-16 of
16 AOGCC's final decision in this matter.
17 Notice of the hearing was published in the
18 Anchorage Daily News June 7th, 2013, the state of
19 Alaska online notices as well as the AOGCC website.
20 The AOGCC has not received any comments, protests or
21 requests from the public at this time.
22 Since I'm the only Commissioner out of three
23 Commissioners at the bench we do not have a quorum for
24 making any decisions. Both Commissioner Foerster and
25 John Norman are -- unexpectedly could not attend. At
3
7ij
•
1 the agreement of the participants this hearing is being
2 continued until September 11, 2013 at 9:00 a.m. so that
3 all three Commissioners can be in attendance.
4 At this time -- as I said we're continuing this
5 hearing, we're going to adjourn until then and the time
6 is 9:03 a.m. Off the record.
7 (Adjourned - 9:03 a.m.)
8 (END OF PROCEEDINGS)
•
1 TRANSCRIBER'S CERTIFICATE
2 I, Salena A. Hile, hereby certify that the
3 foregoing pages numbered 02 through 05 are a true,
4 accurate, and complete transcript of proceedings in re:
5 Order No. 81, Kuparuk River Unit 3Q-16 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
11 Date Salena A. Hile, Transcriber
12
J
•
40
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
Public Hearing on
Request for Reconsideration
KRU 3Q-16
August 20, 2013 at 9:00 a.m.
SIGN IN SHEET
NAME AFFILIATION TESTIFYING
YES OR NO
•
0
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West Seventh Avenue, Suite 100
Anchorage Alaska 99501
Re: Failure to complete a Mechanical Integrity Test (MIT) )
Failure to report to AOGCC a pressure communication ) AOGCC Order No. 81
Kuparuk River Unit 3Q-16 August 16, 2013
(KRU 3Q-16) (PTD 1861790)
SCHEDULING ORDER
The hearing currently scheduled for August 20, 2013 at 9:00 a.m. is hereby continued
until September 11, 2013 at 9:00 a.m.
Done at Anchorage, Alaska and dated August I
-A
Cat y P. oerster
Chair, Commissioner
ke •
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West Seventh Avenue, Suite 100
Anchorage Alaska 99501
Re: Failure to complete a Mechanical Integrity Test (MIT) )
Failure to report to AOGCC a pressure communication ) AOGCC Order No. 81
Kuparuk River Unit 3Q-16 ) May 16, 2013
(KRU 3Q-16) (PTD 1861790)
ORDER
UPON RECONSIDERATION
Acting under 20 AAC 25.535(b), the Alaska Oil and Gas Conservation Commission
(AOGCC) notified Conoco Phillips Alaska, Inc. (CPAI) of the AOGCC's intention to take
enforcement action with regard to violations which occurred at the Kuparuk River Unit 3Q-16
well. CPAI requested informal review pursuant to 20 AAC 25.535(c). After informal review,
the AOGCC issued a proposed decision. CPAI filed an "Application For Reconsideration of
Order No. 81." Because the only authorized avenue to object to a proposed order entered under
20 AAC 25.535(d) is to request a hearing, the AOGCC construes CPAI's request for
reconsideration to be a request for hearing and will notice a public hearing as required by
Regulation.
Done at Anchorage, Alaska and dated May 16, 2
Cathy . Foerster
Chair, Commissioner
Colombie, Jody J (DOA)
From: Colombie, Jody J (DOA)
Sent: Friday, May 17, 2013 10:14 AM
To: 'McLeod, Jill A (LDZX)'
Subject: AOGCC Order No 81 - Order Upon Reconsideration
Attachments: S45C-213051709410.pdf
Please call me in the next few days so that we can coordinate schedules.
JodyJ. Colombie
Special Assistant
Alaska Oil and Gas Conservation Commission
333 W. Th Avenue
Anchorage, Alaska 99501
(907) 793-1221
(907) 276-7542
•
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
333 West Seventh Avenue, Suite 100
Anchorage Alaska 99501-3539
Re: Failure to complete a Mechanical Integrity Test (MIT) )
Failure to report to AOGCC a pressure communication ) AOGCC Order No. 81
Kuparuk River Unit 3 Q-16 ) April 16, 2013
(KRU 3Q-16) (PTD 1861790)
PROPOSED ORDER
On December 21, 2012, the Alaska Oil and Gas Conservation Commission (AOGCC)
issued a Notice of Proposed Enforcement Action (Notice) to ConocoPhillips Alaska, Inc. (CPAI)
regarding the 3Q-16 well of the Kuparuk River Unit (KRU). The Notice advised that CPAI
failed to complete a Mechanical Integrity Test (MIT) and failed to report to AOGCC a pressure
communication in well KRU 3Q-16. The Notice proposed specific corrective actions and a
$45,000 civil penalty under AS 31.05.150(a).
CPAI requested informal review. That review was held January 30, 2013.
A. Summary of Proposed Enforcement Action
The Notice identified violations by CPAI of Rule 6 of Area Injection Order 2B (AIO
213) ("Demonstration of Tubing/Casing Annulus Mechanical Integrity"), the provisions of
Rule 7 of AIO 2B ("Well Integrity Failure") and 20 AAC 25.402(f). A violation occurred
every day after September 25, 2012 that CPAI injected into KRU 3Q-16 without completing an
MIT. A violation also occurred when CPAI failed to report to AOGCC a pressure
communication indicating a potential loss of mechanical integrity on KRU 3Q-16 by the next
working day. The Notice proposed the following corrective actions be completed by CPAI:
AOGCC Order #81 46
Page 2 of 7
46 April 16, 2013
(1) within 2 weeks from the effective date of the AOGCC's final decision, CPAI
shall provide a detailed description of its Underground Injection Control
(UIC) regulatory compliance program;
(2) within 2 weeks from the effective date of the AOGCC's final decision, CPAI
shall provide details of its tracking system for determining when MIT's
are required, including the details of contingencies for wells shut in at the
time an MIT is due and its procedures for notification to the AOGCC, as
well as its processes for determining the MIT due date and identification
of past due wells; and
(3) within 2 weeks from the effective date of the AOGCC's final decision, CPAI
shall complete and provide the results of a root cause analysis addressing
the violations.
The Notice proposed civil penalties of $45,000 ($10,000 for the initial violation — failure
to perform the required MIT of the injection well in compliance with the testing protocols
specified in Rule 6 of AIO 213, $500 for each day September 26, 2012 to November 1, 2012 (37
days) for injecting in a well out of compliance with MIT regulations, and $500 for each day from
October I I through November 12, 2012 inclusive (33 days) for failing to notify AOGCC of
indications of pressure communication or leakage in KRU 3Q-16).
AOGCC Order #81 46 4OApril 16, 2013
Page 3 of 7
B. Demonstration of Tubing/Casing Annulus Mechanical Integrity
Rule 6 of AIO 2B states "A schedule must be developed and coordinated with the
Commission, which ensures that the tubing/casing annulus for each injection well is pressure
tested prior to initiating injection and at least once every four years thereafter. "
The last AOGCC-witnessed MIT occurred September 25, 2008. Therefore an MIT was
required on or before September 25, 2012. No MIT was timely performed. The well was out of
compliance, but continued injection for 37 days, from September 26, 2012 to November 1, 2012
inclusive.
CPAI failed to demonstrate the mechanical integrity of injection well KRU 3Q-16 within
the required four year cycle, a violation of State regulations and AIO 2B.
C. Well Integrity Failure
Under AOGCC regulations, "If an injection rate, operating pressure observation, or
pressure test indicates pressure communication or leakage in any casing, tubing, or packer, the
operator shall notify the commission by the next working day... "
Rule 7 of AIO 2B states "Whenever operating pressure observances or pressure tests
indicate pressure communication or leakage of any casing, tubing or packer, the operator must
notify the Commission on the first working day following the observation, obtain Commission
approval of a plan for corrective action, and when an USDW is not endangered, obtain
Commission approval to continue injection. "
The only notice of potential pressure communication is an email from CPAI sent
November 13, 2012. Review of the TIO plots (pressure data from May 28, 2012 to November
12, 2012) indicate significant pressure anomalies which were not communicated to the AOGCC.
Significant inner annulus (IA) pressure decreases occurred from September 8, 2012 to October 2,
AOGCC Order #81 46
Page 4 of 7
46 April 16, 2013
2012. On October 3, 2012 the IA pressure increased 650 psi to 2300 psi from the October 2,
2012 reading of 1650 psi. Incremental increases and sustained IA pressure were exhibited from
October 10, 2012 until the well was shut in November 13, 2012. Potential pressure
communication after October 10, 2012 demonstrates ongoing non-compliance with reporting
requirements from October 11, 2012 to November 12, 2012 inclusive.
CPAI failed to report to AOGCC a pressure communication indicating a potential loss of
mechanical integrity on KRU 3Q-16 by the next working day, a violation of State regulations
and AIO 2B.
E. Violations.
An MIT on KRU 3Q-16 was required no later than September 25, 2012. As of
September 25, 2012 no MIT had been performed on KRU 3Q-16. By email dated November 13,
2012 CPAI notified the AOGCC that KRU 3Q-16 was returned to injection on August 22, 2012
and ceased taking injection November 1, 2012, and was shut in November 13, 2012. Every day
of injection from September 26 through November 12 was a violation. At the informal
conference, CPAI indicated it had performed a root cause analysis and outlined the changes it
had made in order to avoid similar violations in the future. However, CPAI did not provide the
AOGCC with its root cause analysis.
CPAI's November 13, 2012 email notification also states "the TIO plots suggests TxIA2
communication based on the slowly building IA pressure". The November 13 email was the first
communication AOGCC received from CPAI regarding pressure anomalies. As specified
above, TIO plots (pressure data from May 28, 2012 to November 12, 2012) indicate significant
' TIO plot is a graphical representation of the well's tubing, inner annulus, and outer annulus pressures over a
specified time period.
2 TxIA = tubing by inner annulus
AOGCC Order #81 40
Page 5 of 7
do April 16, 2013
pressure anomalies which were not communicated to the AOGCC. At the informal conference,
CPAI indicated its awareness of this information, but stated it determined that the anomalies did
not indicate pressure communication.
F. Mitigating Circumstances
The commission considered the factors in AS 31.05.150(g) in determining the
appropriate penalty. The penalty was reduced due to CPAI's general history of satisfactory
compliance and practices, an aquifer exemption for the KRU, the lack of actual threat to public
health or the environment, CPAI's notification to AOGCC, and CPAI's shut-in of the KRU 3Q-
16 once CPAI determined the well was out of compliance. However, as to the missed MIT, the
commission reviewed Order 36 from 2005 for CPAI's missed MIT on CD1-19A and a Notice of
Violation to CPAI for a missed MIT on 3H-12A in April 2012. As to the pressure anomalies,
CPAI's internal "determination" that those anomalies did not constitute communication
effectively prevented the Commission's review of the issue.
G. Findings and Conclusions
The Commission finds that CPAI violated the regulations and the Rules in AIO 2B
governing the Demonstration of Tubing/Casing Annulus Mechanical Integrity and Well Integrity
Failure. Mitigating circumstances outlined above were considered in the Commission's Notice
of Enforcement Action and its assessment as to the appropriate civil penalty, which was
decreased from the maximums provided by statute. CPAI presented nothing during the informal
review which would warrant a change in the proposed order.
AOGCC Order #81 40 40 April 16, 2013
Page 6 of 7
NOW THEREFORE IT IS ORDERED THAT:
1. Within 30 days after this Decision and Order becomes final, CPAI shall pay the Commission a
civil penalty of $45'0003:
2. Within 2 weeks after this Decision and Order becomes final, CPAI shall:
(1) provide a detailed description of its Underground Injection Control (UIC)
regulatory compliance program;
(2) provide details of its tracking system for determining when MIT's are
required, including the details of contingencies for wells shut in at the time an
MIT is due and its procedures for notification to the AOGCC, as well as its
processes for determining the MIT due date and identification of past due
wells;
(3) provide CPAI's root cause analysis addressing the violations.
Done at Anchorage, Alaska this 16th day of April, 2013.
Cathy P oerster, Chair, Commissioner
Alaska Oil and Gas Conservation Commission
Daniel T. Se aunt, Jr., Commissioner
�Oil�d Oas Conservation Commission
Jblrli K\JLsrtnan, Con'iT 4slloner
Alaska Oil and Gas Conservation Commission
'AS 31.05.150(a) provides for not more than $100,000 for the initial violation and not more than $10,000 for each
day thereafter on which the violation continues.
AOGCC Order #81 46
Page 7 of 7
RECONSIDERATION AND APPEAL NOTICE
4bApril 16, 2013
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
Commission grants for good cause shown, a person affected by it may file with the Commission 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 Commission 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 Commission 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 Commission mails, OR 30 days if the Commission 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 Commission 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 Commission, and it may be appealed to superior court. That
appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission 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 Commission 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 aweekend or state holiday.
%.ot.cow
afto Wove w+asi Wlel A=80 ID a"
c,Matfiawing at du* I I C,�
/-e-
U.S. Postal Service,,,
_ CERTIFIED MAIL,. RECEir f
(Domestic Mail Only; No Insurance Coverage Provided)
For delivery information visit our website at www.usps.com,
ri
ni`t
Cr
Postage
$
m
Certified Fee
ED
lZ3
Return Receipt Fee
(Endorsement Required)
O
Restricted Delivery Fee
(Endorsement Required)
u1
rl-J
Total Postage r -
n.
ru
Q ` tA� .
~ POstrhark
C;
O Jre
S_ i
$6.31 04/17/2013
Sent To
O Mr. Jerry Dethlefs
O 171- or
, Apt-1VDirector
r PPOO Box No.. Well Integrity
City siaie, ziP+ ConocoPhillips Alaska, Inc.
Post Office Box 100360
Anchorage, AK 99510-0360
■ Complete items 1, 2, and 3. Also complete
item 4 if Restricted Delivery is desired.
■ Print your name and address on the reverse
so that we can return the card to you.
■ Attach this card to the back of the mailpiece,
or on the front if space permits.
1. Article Addressed to:
•
A. Signature/
❑ Agent
XR ed by (PrintedfL2
Delivery
D. Is del�very address different from Rem 17 ❑ Yes
If YES, enter delivery address below: ❑ No
3. Service Type
Mr. Jerry Dethlefs
0 Certified Mail
❑ Express Mail
Well Integrity Director
❑ Registered
❑ Return Receipt for Merchandise
ConocoPhillips Alaska, Inc.
❑ Insured Mail
❑ C.O.D.
Post Office Box 100360
4. Restricted Delivery? (Extra Fee) ❑Yes
Anchorage. AK 99510-0360
2. Article Number
7009 2250 0004
3911 5068
(Transfer from service label)
—
PS Form 3811, February 2004
Doi. ME RrYxn Reodpt
102595-02-M-1540
#9
•
•
Colombie, Jody J (DOA)
From: Colombie, Jody J (DOA)
Sent: Tuesday, August 13, 2013 2:14 PM
To: jill.a.mcleod@conocophillips.com
Subject: RE: [EXTERNAL]Re: CPAI Public Hearing August 20th
There have been no other inquiries into this matter.
JodyJ. Colombie
Special Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7tn Avenue
Anchorage, Alaska 99501
(907) 793-1221
(907) 276-7542
From: McLeod, Jill A (LDZX) [mailto:Jill.A.McLeod@conocophillips.com]
Sent: Tuesday, August 13, 2013 10:39 AM
To: Colombie, Jody J (DOA)
Subject: Re: [EXTERNAL]Re: CPAI Public Hearing August 20th
Thank you very much.
From: Colombie, Jody J (DOA) [maiIto: jody.colombie(aalaska.aov]
Sent: Tuesday, August 13, 2013 01:35 PM
To: McLeod, Jill A (LDZX)
Subject: [EXTERNAL]Re: CPAI Public Hearing August 20th
Jill see below answers.
Sent from my Whone
On Aug 13, 2013, at 10:28 AM, "McLeod, Jill A (LDZX)" <Jill. A. McLeod@conocophillips.com> wrote:
Good morning, Jody,
In preparation for the CPAI public hearing on Tuesday, August 20th, I wanted to let you know that we still
anticipate that the hearing will run no more than 2 hours. Ok
CPAI will make a PowerPoint presentation. Ok.
1
Please confirm that we should bring a thumb drive loaded with our presentation and thatwe will use the AOGCC equipment in the
hearing room. Yes
We will bring paper copies of the presentation to the hearing. Ok
Please let me know how many copies we should bring. 6 copies
Please also confirm that the hearing will start a 9 a.m. Yes
Has the AOGCC had any additional enquiries from reporters about this matter? I don't believe so, but I am in hearing all day and will
confirm during a break.
Thanks,
Jill
Jill McLeod
Counsel
ConocoPhillips
ATO 2084
700 G Street
Anchorage, Alaska 99501
Tel: ( 907) 265-6844
Fax: (918) 662-8388
Email: jill.a.mcleod@conocophillips.com
The information contained in this email may be confidential, privileged, or both. If you are not the intended recipient of this
email, you may not read, retain, copy, or distribute this email. If you have received this email in error, please contact me.
Thank you.
2
M3
A
�-1
STATE OF ALASKA
ADVERTISING
ORDER
1W NOTICE TO PUBLISHER mw
INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED
AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF
ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE
ADVERTISING ORDER NO.
/� O_O�_3_14-043
/`1
jEE BOTTOM FOR INVOICE ADDRESS
F
R
°
M
AOGCC_'
333 W 7th Ave, Ste 100
Anchorage, AK 99501
AGENCY CONTACT
Jody Colombie
DATE OF A.O.
June 4, 2013
PHONE
9 79 —1221
PCN
DATES ADVERTISEMENT REQUIRED:
June 7, 2013
THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS
ENTIRETY ON THE DATES SHOWN.
o
Anchorage Daily News
PO Box 149001
Anchorage, AK 99514
g
SPECIAL INSTRUCTIONS:
Type of Advertisement Legal® ❑ Display Classified
❑Other (Specify)
SEE ATTACHED
SEND INVOICE IN TRIPLICATE
TO
AOGCC, 333 W. 7th Ave., Suite 100
Anchorage, AK 99501
PAGE 1 OF
2 PAGES
TOTAL OF
ALL PAGES $
REF
ITYPE
I NUMBER
AMOUNT
I DATE
I COMMENTS
1
VEN
2
ARD
1 02910
FIN
AMOUNT
SY
CC
PGM
LC
ACCT
FY
NMR
DIST
10
1
13
02140100
73451
2
REQUISITIONE Y:
0
DIVISION APPROVAL:
02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving
AO.FRM
Notice of Public Hearing
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
ConocoPhillips Alaska, Inc. has requested Reconsideration of Proposed Order No 81, the
decision of the Alaska Oil and Gas Conservation Commission to impose civil penalties in the
amount of $45,000 based on the circumstances surrounding a missed mechanical integrity test
and the failure to report pressure communication in Kuparuk River Unit 3Q-16 by the next
working day.
The AOGCC has scheduled a public hearing in this matter for August 20, 2013 at 9:00 a.m. at
333 W. 71h Ave., Ste 100, Anchorage, Alaska 99501.
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 July
30, 2013.
Cathy . Foerster
Chair, Commissioner
0 0 RECEIVED
STOF0330
#212058
$99.60
AFFIDAVIT OF PUBLICATION
STATE OF ALASKA
THIRD JUDICIAL DISTRICT
Joleesa Stepetin
being first duly sworn on oath
deposes and says that he is
a representative of the
Anchorage Daily 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
June 07, 2013
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 ch ged private in ividuals,
T!
Signed
Subscribed and sworn to before
me this -7 day of
20 13
Notary Public in and for
The State of Alaska.
Third Division
Anchorage, Alaska
MY COMMISSION EXPIRES
Notice of Public Hearing
STATE OF ALISKA
AIASKAOIIp& IONSERVATION
Re: ConocoPhilli s Alaskaer , Inc. has requested
the Ala ka Oilland Gas Conservati91 on Commission
decision to imposeCivil penalties in the amount of
$45,000 for failure to report pressure
communication in Kuparuk River Unit 3Q-16 by the
next working day.
The AOGCC has scheduled a public hearing in this
matterforAu
Ste 100SAncho Anchorage, 99501.
t 333 W.
If, because of a disability, special accommodations
may be needed to comment or attend,stantthe hearing,
contact the ACCC's AE
Colombia, at 793--1221, no ljo
aterlal than July30, 2013. y
AO-02-3-14-043
Published: June 7, 2013
Cathy P. Foerster,
Chair, Commissioner
JUN 1 1 2013
AOGCC
0 •
STATE OF ALASKA NOTICE TO PUBLISHER
ADVERTISING ORDER NO.
ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED w - O-023-1 A_043
ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF F1 �7 �#
ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE
stt I�v� I Una UK IN��I :r �►�ur��� k �.
!
! Yiyi ��i1W'i�
.J
u
......... k .� ,'.. t .. ..
' AOGCC
R 333 West 7`I' Avenue. Suite 100
° Anchorage. AK 99501
M
o Anchorage Daily News
PO Box 149001
Anchorage, AK 99514
AFFIDAVIT OF PUBL
United states of America
State of ss
division.
Before me, the undersigned, a notary public this day personally appeared
who, being first duly sworn, according to law, says that he/she is the
of
Published at in said division and
state of and that the advertisement, of which the annexed
is a true copy, was published in said publication on the day of
2013, and thereafter for consecutive days, the last publication appearing
on the day of , 2013, and that the rate charged thereon
is not in excess of the rate charged private individuals.
Subscribed and sworn to before me
This _ day of 2013,
tary public for state of
My commission expires _
AGENCY CONTACT
DATE OF
PHONE PCN
9 7 9 -1221
DATES ADVERTISEMENT REQUIRED:
June 7, 2013
THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS
ENTIRETY ON THE DATES SHOWN.
SPECIAL INSTRUCTIONS:
Account 9 STOF0330
]CATION
REMINDER
INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE
THE ADVERTISING ORDER NUMBER.
A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION
MUST BE SUBMITTED WITH THE INVOICE.
ATTACH PROOF OF PUBLICATION HERE.
•
•
Singh, Angela K (DOA)
From:
Colombie, Jody J (DOA)
Sent:
Tuesday, June 04, 2013 9:02 AM
To:
jill.a.mcleod@conocophillips.com; Singh, Angela K (DOA); Ballantine, Tab A (LAW);
Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H
(DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA);
Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Hunt, Jennifer L (DOA); Johnson,
Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA);
McIver, Bren (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman,
John K (DOA); Okland, Howard D (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); Wallace, Chris D (DOA);
(michaelj.nelson@conocophillips.com); AKDCWellIntegrityCoordinator;
alaska@petrocalc.com; Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F
Fullmer; bbritch; bbohrer@ap.org; Bill Penrose; Bill Walker; Bowen Roberts; Brian
Havelock; Burdick, John D (DNR); caunderwood@marathonoil.com; Cliff Posey; Crandall,
Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens;
David Duffy; David House; David Scott; David Steingreaber; Davide Simeone;
ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Elowe, Kristin;
Evans, John R (LDZX); Francis S. Sommer; Gary Laughlin; schultz, gary (DNR sponsored);
ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory
Geddes; gspfoff; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B
(DOA); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Lastufka;
news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L
(GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell
Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana
Cutler; Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley
(mark.hanley@anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael
Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson;
mkm7200; knelson@petroleumnews.com; Nick W. Glover; Nikki Martin; NSK Problem
Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR);
Pioneer; Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan
Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Sandra Haggard; Sara
Leverette; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland;
Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smith, Kyle S
(DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR);
Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer;
Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier
(tmgrovier@stoel.com); Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter
Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J
(DNR); Casey Sullivan; David Lenig; David Martin; Donna Vukich; Eric Lidji; Erik Opstad;
Franger, James M (DNR); Gary Orr; Smith, Graham O (PCO); Greg Mattson; Heusser,
Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; Jim
Magill; Joe Longo; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Marc Kuck;
Steele, Marie C (DNR); Matt Gill; Ostrovsky, Larry (DNR sponsored); Bettis, Patricia K
(DOA); Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DNR); Pollard, Susan R
(LAW); Pollet, Jolie; Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Wayne
Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke
Subject:
Public Notice KRU 3Q-16
Attachments:
CPA Mtn For Reconsideration KRU 3Q-16.pdf
•
JodyJ. Colombie
Special Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7tn Avenue
Anchorage, Alaska 99501
(907) 793-1221
(907) 276-7542
Easy Peel® Labels
Use Avery® Template 51600
i ♦ Bend along line to
Feed Paper ®
AVERY@ 596OTM �
expose Pop up EdgeT9
David McCaleb
Penny Vadla
IHS Energy Group
George Vaught, Jr.
399 W. Riverview Ave.
GEPS
Post Office Box 13557
Soldotna, AK 99669-7714
5333 Westheimer, Ste. 100
Denver, CO 80201-3557
Houston, TX 77056
Jerry Hodgden
Richard Neahring
Mark Wedman
Hodgden Oil Company
NRG Associates
Halliburton
m
408 18 St.
President
6900 Arctic Blvd.
Golden, CO 80401-2433
Post Office Box 1655
Anchorage, AK 99502
Colorado Springs, CO 80901
Bernie Karl CIRI Baker Oil Tools
K&K Recycling Inc. Land Department ,n
Post Office Box 58055 Post Office Box 93330 795 E. 94 Ct.
Fairbanks, AK 99711 Anchorage, AK 99503 Anchorage, AK 99515-4295
North Slope Borough
Planning Department Richard Wagner Gordon Severson
Post Office Box 60868 3201 Westmar Cir.
Post Office Box 69 Fairbanks, AK 99706 Anchorage, AK 99508-4336
Barrow, AK 99723
Jack Hakkila Darwin Waldsmith James Gibbs
Post Office Box 190083 Post Office Box 39309 Post Office Box 1597
Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669
tiquettes faciles a peter ; A ftepliez a la hachure afin de ; wrww.avery.com ;
Utilisez le nabarit AVERY& 5160� 'MSen—s dew+ reveler le rebord Pon-unTm ! 1-900-GO-AVFRY !
Easy Peel® Labels ip
® Bend along line to I AVER ® 5960TM"
Use AveryU Template 51600 Feed Paper ® expose Pop-up Edge TM S
Jill A. McLeod
Legal Counsel
ConocoPhillips Alaska, Inc.
ATO-2084
Post Office Box 100360
Anchorage, AK 99510-0360
Etiquettes faciles a peter I ® Repliez a la hachure afin de ; www.averyxom
-_._,_ ,,.,.- CR) , nR I Sens de __Mc I i_Rnn_rn_evFRv
#7
ConocoPhillips
Alaska, Inc.
May 9, 2013
•
(RECEIVED
MAY 0 9 2013
AOGCC
Cathy Foerster, Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
RE: Application for Reconsideration of Order No. 81
Kuparuk River Unit 3Q-16
(KRU 3Q-16) (PTD 1861790)
Jill A. McLeod
Legal Counsel
ATO-2084
P. O. Box 100360
Anchorage, AK 99510-0360
Phone 907.265.6844
Fax 918.662.8388
jill.a.mcleod@conocophillips.com
Hand Delivery
Pursuant to AS 31.05.080(a), ConocoPhillips Alaska, Inc. ("ConocoPhillips") respectfully
requests that the Alaska Oil and Gas Conservation Commission ("AOGCC") reconsider the
decision to propose civil penalties in the amount of $45,000, and the decision that
ConocoPhillips failed to report to the AOGCC the pressure communication by the next working
day as set forth in Order No. 81 dated April 16, 2013 ("Order 81 ").' The grounds for
ConocoPhillips' application for reconsideration are identified and explained below.
I. CONTEXT
On December 21, 2013, the AOGCC issued a Notice of Proposed Enforcement Action ("Notice")
to ConocoPhillips regarding the 3Q-16 well. The Notice advised ConocoPhillips that it failed to
complete a Mechanical Integrity Test ("MIT") and failed to timely report a pressure communica-
tion in well KRU 3Q-16. The Notice proposed specific corrective actions and a $45,000 civil
penalty under AS. 31.05.150(a). At ConocoPhillips request, the AOGCC held an informal review
with ConocoPhillips on January 30, 2013. On April 16, 2013, the AOGCC issued Order 81 and
proposed to fine ConocoPhillips $45,000 in civil penalties for its failure to complete an MIT pur-
suant to Rule 6 of Area Injection Order ("AIO") 213 and for its failure to report pressure commu-
nication by the next workincl day following an observance as per Rule 7 of AIO 2B. Each viola-
tion incurs daily fines from the alleged point of infraction until the day ConocoPhillips self -
reported the issues to the AOGCC. In addition, Order 81 proposes specific corrective actions.
On the grounds stated below, ConocoPhillips timely requests that the AOGCC reconsider (1)
the penalties calculated for the failure to complete an MIT; and (2) its conclusion set forth in
paragraph C and E, Well Integrity Failure and Violations, its decision that ConocoPhillips failed
to report a pressure communication by the next working day in violation of State regulations and
AIO 2B, and the penalties associated with the alleged violation.
ConocoPhillips received Order 81 by mail and the deadline for filing this application for reconsideration
is May 9, 2013.
Cathy Foerster, Commissior•, AOGCC •
Re: Application for Reconsideration of Order 81
May 9, 2013
Page - 2-
II. RECONSIDERATION OF PENALTY FOR MISSED MIT
The AOGCC has proposed a penalty in the amount of $10,000 for its failure to complete a MIT
plus $18,500 (calculated at $500 per day calculated from the MIT due date until the date of the
self -disclosure). Although the AOGCC reduced the penalty from the maximum allowable pen-
alty due to certain mitigating factors including our prompt disclosure of the problem, our action
to immediately shut in the well and the lack of actual threat to public health or the environment,
ConocoPhillips requests that the penalty be reduced even further to take into account additional
mitigating circumstances. The proposed penalty does not take into account that the failure to
complete the MIT was systematically discovered through the implementation of our compliance
management process. Further, the proposed penalty does not take into account the corrective
actions that ConocoPhillips has taken and is taking to prevent this problem from recurring. At
the informal hearing on January 30, 2013 ConocoPhillips advised that it is committed to making
improvements in reporting and tracking processes for MITs that should prevent this kind of vio-
lation once those measures are implemented. The improvements include consolidating the
recordkeeping functions within a dedicated position, improving report generation capabilities for
MIT tests and an improved IT solution for tracking regulatory compliance. ConocoPhillips has
committed to review its progress on these corrective actions with the AOGCC every six months.
Accordingly, ConocoPhillips requests that the AOGCC reduce the civil penalty associated with
the missed MIT to a much smaller penalty.
III. RECONSIDERATION OF PENALTY FOR THE FAILURE TO TIMELY REPORT
ConocoPhillips disputes the allegations and the proposed penalties for failing to comply with
Rule 7 of AIO 2B. Rule 7 of AIO 2B states:
"Whenever operating pressure observances or pressure tests indicate pressure
communication or leakage of any casing, tubing or packer, the operator must
notify the Commission on the first working clay following the observation, obtain
Commission approval of a plan for corrective action, and when an USDW is not
endangered, obtain Commission approval to continue injection."
ConocoPhillips did notify the AOGCC of suspected annular communication in a timely manner.
ConocoPhillips notified the AOGCC on November 13, 2013, the same day as the pressure
observance. ConocoPhillips did not suspect annular communication on 3Q-16 until reported on
November 13. The very first observance of suspected pressure communication only took place
on November 13 and therefore ConocoPhillips did comply with Rule 7 of AIO 2B for timely
reporting by immediately notifying the AOGCC on the very same day.
The AOGCC has erroneously interpreted the meaniing of a "pressure observance" pursuant to
Rule 7. In Order 81, the AOGCC states that from May 28, 2012, to November 13, 2012, there
were "significant pressure anomalies which were not communicated to the AOGCC". There
were, in fact, pressure fluctuations but none of these fluctuations were considered communica-
tion issues. The Inner Annulus (IA) pressure trend plot closely follows the injection temperature
plot and does not show any direct relationship to either the injection tubing pressure or Outer
Annulus (OA) pressure trend. For reference, see the attached T/I/O Plot-3Q-16 for the period
August 1, 2012-December 31, 2012.
0,
Cathy Foerster, Commissioner AOGCC •
Re: Application for Reconsideration of Order 81
May 9, 2013
Page - 3-
There are a number of trigger points that would lead ConocoPhillips to evaluate a well for the
presence of annular communication and result in a report to the AOGCC. These include a well
that has reached the Maximum Allowable Operating Pressure (MAOP) that is prescribed for
each annulus, the inability to maintain at least 500 psi differential between the tubing and IA
pressures and annular pressure bleeds that are performed to keep annular pressure within
MAOP limits.
The MAOP of the IA for 3Q-16 is 3000 psi. At no time did the IA pressure approach this limit. In
addition, at no point during this time period was pressure bled from the annulus in an effort to
control pressure buildup. A differential pressure of at least 500 psi between the tubing and IA is
a Best Practice used by ConocoPhillips on all injection wells that do not have an Administrative
Approval (AA) from the AOGCC. 3Q-16 had well over 500 psi differential at all times through
the noted time period.
When tubular leaks in a well are extremely small they may not be noticed on a day to day basis;
it may take some time for the buildup to be noticed since in the short term they may be masked
by the annular pressure changes that result from thermal changes in the well. In most cases,
minor leaks are usually first identified after a trigger event and looking at pressure trend plots
over time, and not by simply looking at the pressure gauge on the wellhead. When this slow
leaking is identified (or "observed") it is immediately reported to the AOGCC as required in Rule
7 of AIO 2B.
The original notice to the AOGCC on November 13, 2012, reported "suspected" annular com-
munication "based on the slowly building IA pressure". Since none of the previously described
triggers for annular communication had taken place, there was no reason to have suspected
this well had a problem prior to this observance. This was the first observance of the slowly
increasing pressure and was properly reported to the AOGCC.
ConocoPhillips currently has approximately 60 injection wells with suspected or confirmed
communication issues that resulted in Administrative Approvals to keep the wells in service. For
each of those wells, as soon as communication was suspected a report was required to the
AOGCC as per regulatory requirements. In some cases the communication issues were at the
outset more significant with the leak found and reported to the agency on the same day. For
other wells the communication issues were not immediately evident and were discovered by
observing trends over time. In each case, ConocoPhillips notified the AOGCC of the potential
communication at the first observance. The AOGCC did not levy penalties in these other self -
disclosed, similar circumstances. In short, there is nothing in the pressure trend history of this
well that would have generated a report to the AOGCC prior to the observance that took place
on November 13, 2012. Respectfully, a non -penalty action would have been the appropriate
response to this situation and ConocoPhillips believes a penalty is not warranted under the cir-
cumstances.
The AOGCC has proposed civil penalties calculated at $500 per day from October 11 through
November 12, 2012 (33 days) for failing to report indications of pressure communication in KRU
3Q-16 ($16,500 total penalty). ConocoPhillips requests that the AOGCC reconsider its deci-
sions, findings and conclusions and eliminate the penalty associated with this violation because
the larger pressure fluctuations in the trend plot were not caused by annular communication, but
rather temperature effects; and the pressure data that indicated possible annular communica-
0
Cathy Foerster, Commissioner, AOGCC •
Re: Application for Reconsideration of Order 81
May 9, 2013
Page - 4-
tion built very slowly and gradually over time and was reported immediately after it was first
observed pursuant to Rule 7 of AIO 2B.
IV. REMEDY ON RECONSIDERATION
For the foregoing reasons, ConocoPhillips requests that the AOGCC issue an amended Order
81 reducing the civil penalties associated with the missed MIT and withdrawing it decisions,
findings, and conclusions that ConocoPhillips failed to timely notify the AOGCC of a potential
pressure communication, and eliminate the penalties associated with this alleged violation.
V. CONCLUSION
For the reasons set forth above, ConocoPhillips respectfully (i) applies for reconsideration of
Order 81 and (ii) seeks the relief identified in Sections ll, III and IV above. The AOGCC's review
of our application for reconsideration is appreciated. Please do not hesitate to contact me at
(907) 265-6844 if you have any questions regarding this matter.
Sincerely,
Jill . McLeod
Legal Counsel
Attachment
W]
1 0
�
Cf
�
13
0
\
44
. . . .
~ - - -
- - - -
�
^ ' -
~ '
r--'--' -
1
1
0
7
0
IL
EL
I
W
1,1
• dkma uosio :D i
0 Ln
rN
Y a .
• .
.471
CL
��X��•
V
1
a
La 3
N
i
1
rN
a
ct
c
r
i�4y �°L�y
CN CN r
II 'Sd
#6
NAME
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
CPA Informal Review 3Q-16
January 30, 2013 at 9:00 a.m.
AFFILIATION
eo
PHONE #
ass -IW4 y
TESTIFY (Yes or No)
C17,4o,,A iLl,-Ps 2,65 3ac>6 �<s
WEAK - •
n
irn
r�
ConocoPhillips Alaska, Inc
Well Integrity Group
AGENDA
• Timeline of events
Failure to timely report annular communication
• Failure to perform MIT
Description of UIC program
Description of MIT tracking process, including missed wells
• Recommendations for improvements
ConocoPhillips Alaska, Inc
Well Integrity Group
3Q-16 Class II Injection Well
Timeline of Events
• 3Q-16 (PTD 1861790) is an MWAG Class II injector; it can be used for either water or
miscible gas injection. The well was drilled and completed in November, 1986.
• On September 25, 2008, the well passed a State witnessed MIT, which set the anniversary
for the next MIT to be conducted not later than September 25, 2012.
• On June 1, 2012, the well was shut-in due to repairs required on the water injection header
system.
• On August 8, 2012, MITs were performed on all the active injectors on 3Q pad. 3Q-16 was
not tested since it was shut-in, and the AOGCC's preference is to witness a MIT while a well
is actively injecting (per the Guidance Bulletin). The Problem Well Supervisor (PWS) was
not working and a step-up supervisor was temporarily covering this position's duties. While
completing paperwork for the MITs performed that day, the step-up did not add 3Q-16 to the
Shut -In Well Excel spreadsheet (explanation of spreadsheet is in description of CPAI MIT
compliance management system program).
• On August 22, 2012, the well was returned to service on MI injection. The water header had
not yet been fixed but the MI system was operational.
• On November 13, while the PWS was compiling the MIT Quarterly Report, the PWS
discovered that the MIT due date for 3Q-16 (September 25) had passed by and a MIT had
not been performed after the well went back into service and before September 26, 2012.
Although the PWS reviewed the Shut -In Injector Excel spreadsheet weekly, the outstanding
MIT requirement was missed because it had not been noted in the compliance management
system by the temporary step-up. The PWS also suspected T x IA communication after
looking at a TWO plot, which was reviewed for the first time on this same day. The PWS
consulted with the Well Integrity Director and immediate steps were taken to shut-in the well
while the possible integrity issue was investigated further. The PWS immediately reported
the missed MIT and the suspected communication to the AOGCC. The well was shut-in and
will remain shut-in until the AOGCC approves return to service.
• On November 14, diagnostics were performed on 3Q-16 to identify potential leak paths;
packoff testing passed and a drawdown test passed (1900 psi differential). CPAI found no
indications of communication. Further analysis of the T/I/O plot with an added temperature
curve indicated the annular pressure was changing with injection temperature.
• On December 21, the AOGCC served CPAI with a Notice of Proposed Enforcement (Notice)
allegedly for failing to demonstrate mechanical integrity on 3Q-16 on or before the four year
anniversary date, and for failing to report annular communication within one business day of
observance.
January 14, 2013, CPAI responded to AOGCC and requested an informal review meeting of
the alleged violations. An informal review was scheduled for today, January 30, 2013.
ConocoPhillips Alaska, Inc
Well Integrity Group
Root Cause Analysis Corrective Actions
LCA Team Recommendations List:
1. Review the WI AnnComm database with IT, Operations and Engineering to streamline both the
efficiency of data management systems and the effectiveness of communications to/from IP.21
(SCADA). Suggested improvements could include, for example, improving the AnnComm
report generating function so that MIT data is entered in only one location and multiple lists can
be drawn from the existing data.
2. Review training for WI temporary step-ups to ensure the WI management systems are properly
managed when step-ups take charge.
3. Review staffing in WI and consider whether it would be appropriate to shift data management
duties to other personnel.
4. Meet with AOGCC to discuss testing shut-in wells and performing MITs at dates prior to the
MIT due date.
ConocoPhillips Alaska, Inc
Well Integrity Group
3Q-16 Class II Injection Well
Failure to Timely Report
In the Notice dated December 12, 2012, the AOGCC alleges that CPAI failed to timely report a
pressure communication issue on Class II injection well 3Q-16. The AOGCC correctly quotes
from Rule 7 of AIO 213,
"Whenever operating pressure observances or pressure tests indicate pressure communication
or leakage of any casing, tubing or packer, the operator must notify the Commission on the first
working day following the observation, obtain Commission approval of a plan for corrective
action, and when an USDW is not endangered, obtain Commission approval to continue
injection. "
In CPAI's opinion, CPAI did notify the AOGCC in a timely manner having sent a report to the
AOGCC on the same day as the pressure observance, November 13, 2012. The report to the
AOGCC included a trend plot of tubing and annular pressures (without an injection fluid
temperature curve) for a period of approximately 168 days, originating prior to the well being
placed in service. This report was first generated on November 13, 2012. Prior to that day,
there were no operational signs or trends that would indicate any well integrity issues or that
would trigger the review of a T/I/O plot. The behavior of 3Q-16 was not considered suspected
annular communication until reported on November 13. Accordingly, the first "observance" of
suspected pressure communication did not take place until November 13, and therefore CPAI
did comply with Rule 7 of AIO 2B for timely reporting.
Furthermore, once the report to the AOGCC had been made, CPAI took immediate steps to
shut-in 3Q-16 and initiate diagnostic integrity tests to verify whether annular communication
existed. The first piece of evidence is a T/I/O plot with the addition of the injection fluid
temperature curve. It can be readily observed that the characteristics of the IA pressure trend
correlate with the injection temperature curve; i.e., most, if not all, of the "anomalies" are
thermally induced.
On November 14, 2012, diagnostics at the wellsite were performed. Tubing packoff tests
passed and an IA Drawdown Test passed, holding 1900 psi differential from the tubing to the IA
for 60 minutes (tubing 3420 psi, IA 720 psi). The AOGCC was not notified since the normal
procedure is to perform all the diagnostics necessary to prepare for submittal of an AA. On
January 11, 2013, a diagnostic MITIA passed at 2500 psi, but the AOGCC had already sent the
Notice to CPAI on December 21, 2012.
CPAI concludes that barrier testing was successful and no leaks are present within the
threshold of the test procedures. The AOGCC alleges that CPAI failed to report annular
communication that barrier testing has demonstrated does not exist.
CPAI contends that not only did it comply with the requirements for timely reporting; the well
itself did not have measureable annular communication. CPAI complied with all rules and
regulations and therefore enforcement and penalties are not warranted as proposed in the
Notice.
Annular Communication History •
3Q-16
•
Date
Type
Comment
1/11/13
MIT
MITIA (Passed) @ 2500 psi.
FL -IA
Initial T/I/O = 3350/1880/0, IA FL @ 56'.
Stung into T PO with 0+ psi, stung into IC PO with 0+ psi for monitoring purposes.
Pressured IA up to 2500 PSI with 2 bbls diesel, T PO 0 psi, IC PO 0 psi.
T/I/O = 3350/2500/20.
15 Min reading: T/I/O = 3350/2460/20, T PO 0 psi, IC PO 0 psi.
30 Min reading: T/I/O = 3350/2460/20, T PO 0 psi, IC PO 0 psi.
Bled IA down to 1650 psi.
Final T/I/O = 3350/1650/0.
12/21/12
AOGCC
Received notice of Proposed Enforcement Action for Failure to Complete MIT and Failure
to report pressure communication (reviewed T/I/O plot and IA appears to follow temp
trend)
11/14/12
BLEED -IA
(AC EVAL) : POT-T Passed, PPPOT-T Passed, IA DDT Passed. T/1/0 = 3420/2620/30.
DID TEST -IA
IA FL @ 504'. Stung into T PO w/ 2800 psi, bled to 0 psi (hydraulic fluid/gas) & monitor for
POT-T
15 min. T PO @ 0 psi. Pressured T PO to 5000 psi. 15 min 5000 psi. 30 min 5000 psi.
PPPOT-T
Passed.
IA DDT, bled IA from 2620 psi to 1000 psi (FTS) in 5 min, SI & let gas swap out for 15
min. IA @ 1150 psi
Re bled IA from 1150 psi to 1050 psi (FTS) in 30 sec. SI & let gas swap out for 15 min.
IA @ 1100 psi.
Re bled IA from 1100 psi to 700 psi (gas/fluid) in 30 min. (Note : had charged fluid initially
but swapped to regular fluid after 2 min of bleeding).
Initial T/I/O = 3420/700/30.
15 min T/I/O = 3420/705/30.
30 min T/I/O = 3420/720/30.
45 min T/I/O = 3420/720/30.
60 min T/I/O = 3420/720/30. IA FL @ 50'.
Final T/I/O = 3420/720/30.
11/13/12
AOGCC
Jim, Chris
While compiling the 4 yr MIT quarterly report, I discovered that 3Q-16 (PTD 186-179) was
not tested on schedule. Its last 4 yr test was completed on 9/25/08 and therefore was due
this past September. During this summer's pad testing on 3Q on 8/8/12, the well was shut
in and therefore not included in the testing per Guidance Bulletin 10.002. It was returned
to injection on 8/22/12 and was missed and not tested.
The TIO plot suggests TxIA communication based on the slowly building IA pressure.
The well is open to the MI injection header but is not injecting due to tight reservoir sands.
Under normal circumstances we would WAG this well to water and monitor for
communication. The water injection line is derated and cannot be used. The well will be
shut in, diagnostics initiated, and when there is something more to report we will contact
the AOGCC with suggested repair plans for your approval. The well will remain shut in
until AOGCC approves return of service and will be added to the monthly report.
8/22/2012
BOL
Open well, return to MI service
8/8/2012
MISC
Pad test for MITs (this well was not tested since shut in 6/1/2012)
6/1/2012
SI
Downhole scale inhibition treatment (production injection commonline repair)
9/25/08
MIT -IA
State witnessed ( Bob Noble ) MIT -IA ( passed ), T/1/0= 3440/1800/20. Pressured up IA
with 1.2 bbls diesel, T/1/0= 3440/2540/20. 15 min T/1/0= 3440/2520/20. 30 min T/1/0=
3440/2520/20. Bled IA, final T/1/0= 3440/1225/20.
ConocoPhillips Alaska, Inc
Well Integrity Group
Missed MIT Violation
The second alleged violation in the letter regarding the Notice is failure to complete a
Mechanical Integrity Test on Class II injection well 3Q-16. CPA[ self -disclosed this violation in
the report to the AOGCC on November 13, and voluntarily self -disclosed to the AOGCC that the
required test was not performed by the required due date.
Application of the EPA Audit Policy:
We hold to the view that no penalty is warranted in this situation because we voluntarily self -
disclosed the violation. The facts of the matter and the language of the policy support
application of the EPA Audit Policy to this situation. The issue was systematically discovered;
voluntarily and promptly disclosed; promptly corrected; is not likely to recur; did not result in
serious actual harm or present and imminent and substantial endangerment; did not violate the
specific terms of an administrative or judicial order or consent agreement; and was not a repeat
violation. We therefore believe that that a penalty and enforcement are not warranted under the
circumstances and that the AOGCC has discretion to not seek any penalty. We believe that
CPAI meets the criteria in the Audit Policy and is eligible for the incentives set forth in the policy.
We are prepared to discuss each item in more detail at a time convenient for you.
#5
•
THE STATE
�11 a � A, W1,
4545 00-- MILM M'
GOVERNOR SEAN PARNELL
Jerry Dethlefs
Well Integrity Director
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Alaska Oil and Gas
Conservation Commissi®n
January 16, 2013
Re: Notice of Proposed Enforcement Action
Failure to complete a Mechanical Integrity Test (MIT)
Failure to report to AOGCC a pressure communication
Kuparuk River Unit 3Q-16 (KRU 3Q-16) (PTD 1861790)
Request for Informal Review
Dear Mr. Dethlefs:
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
On December 21, 2012 the Alaska Oil and Gas Conservation Commission (AOGCC) notified
ConocoPhillips Alaska, Inc. (CPAI) of a Notice of Proposed Enforcement Action. CPAI
responded on January 14, 2013 requesting an informal review under 20 AAC 25.535 (c).
The informal review meeting is scheduled for January 30, 2013 at 9:00 a.m. in the AOGCC's
Anchorage office at 333 West 7`h Avenue.
As part of the informal review process, the AOGCC is providing CPAI an opportunity to submit
documentary material and make written and oral statements regarding failure to complete a
Mechanical Integrity Test (MIT) and failure to report to AOGCC a pressure communication for
KRU 3Q-16.
Copies of all written submissions and a summary of any oral statements planned by CPAI should
be provided to the AOGCC no later than January 24, 2013 so we can make best use of the
informal review.
Sincerely,
(�� ��4��
Cathy P. oerster
Chair, Commissioner
#4
•
•
ConocoPhillips
January 14, 2013
Mr. Daniel Seamount, Jr.
Commissioner
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
Subject: Notice of Proposed Enforcement Action
Failure to complete a Mechanical Integrity Test (MIT)
Failure to report to AOGCC a pressure communication
Kuparuk River Unit 3Q-16 (PTD 1861790)
Request for Informal Review
Dear Commissioner Seamount:
Jerry Dethlefs
Well Integrity Director
ConocoPhillips Alaska, Inc
700 G Street
Anchorage, AK
Phone 907-265-1464
RECEIVED
JAN 14 2013
ConocoPhillips Alaska, Inc. (CPAI) received a Notice of Proposed Enforcement Action (Notice)
from the Alaska Oil & Gas Conservation Commission (AOGCC) dated December 21, 2012
alleging that CPAI failed to demonstrate the mechanical integrity of Kuparuk injection well 3Q-
16, and did not timely report a pressure communication on the well. The letter requested that
CPAI respond within 15 days after receipt of the Notice. CPAI requested, and was approved, an
extension of the period of time to respond until close of business on Monday, January 14, 2013.
CPAI does not concur with the proposed enforcement action described in the Notice and requests
an informal review with the AOGCC to be scheduled as soon as reasonably practicable to present
written and oral information that we believe is important for fair consideration of the matters
alleged in the Notice.
The AOGCC also states in the letter certain actions to be performed by CPAI "within 2 weeks of
the AOGCC's final decision" including:
(1) provide a detailed description of its Underground Injection Control (UIC) regulatory
compliance program;
(2) provide details of its tracking system for when MITs are required;
(3) complete and provide the results of a root cause analysis addressing the violations.
The final decision has not yet been made by the AOGCC but CPAI will be prepared to provide
details on these items at the informal review.
We recognize the importance of mechanical integrity testing and the need for regulatory
compliance and timely communication with the AOGCC. After CPAI discovered through its
compliance management system that KRU 3Q-16 was returned to injection without a mechanical
integrity test, CPAI promptly and voluntarily disclosed this compliance gap. CPAI disputes the
allegation that CPAI did not timely report pressure communication on the well and will present
information in support of this position at the informal hearing. CPAI has extensive compliance
management systems in place that reflect CPAI's due diligence in preventing, detecting and
correcting compliance issues and we currently have efforts underway to make further
•
•
improvements to our procedures. We believe we can demonstrate that the AOGCC's proposed
penalty is not warranted. We are committed to operating in full compliance with all regulations
and we will be prepared to inform and discuss the details surrounding this Notice during the
informal review.
We look forward to the informal review with the AOGCC and CPAI proposes that the meeting be
held during the week of January 28, 2013. Please contact me at your earliest convenience to set
up a date and time for the informal review.
Sincerely,
�C'eO C— O��
Jerry Dethlefs
Well Integrity Director
#3
•
•
Wallace, Chris D (DOA)
From: Regg, James B (DOA)
Sent: Monday, January 07, 2013 2:07 PM
To: Dethlefs, Jerry C
Cc: Robinson, Shon D; jill.a.mcleod@conocophillips.com; Seamount, Dan T (DOA); Foerster,
Catherine P (DOA); Norman, John K (DOA); Fisher, Samantha J (DOA); Wallace, Chris D
(DOA)
Subject: RE: ConocoPhillips 3Q-16 Proposed Enforcement Action
As discussed by phone earlier this afternoon, I have been asked to follow up on your request for additional time to
respond to the AOGCC.
Your request to provide a written response no later than the close of business on Monday, January 14, 2013 is
approved.
Jim Regg
AOGCC
333 W. 7th Ave, Suite 100
Anchorage, AK 99501
907-793-1236
From: Dethlefs, Jerry C[mailto:Jerry.C.Dethlefs@conocophillips.com]
Sent: Monday, January 07, 2013 8:26 AM
To: Seamount, Dan T (DOA)
Cc: Robinson, Shon D; jill.a.mcleod@conocophillips.com; Regg, James B (DOA); Dethlefs, Jerry C
Subject: ConocoPhillips 3Q-16 Proposed Enforcement Action
Commissioner Seamount: A few minutes ago I opened a letter from you regarding a proposed enforcement action for
Kuparuk well 3Q-16. I have been out of the office since December 14 and did not know the letter was delivered. In
addition, it appears there were not copies sent to anyone else at ConocoPhillips, so this morning is the first that CPAI has
been aware of the proposed action.
The letter states that within 15 days of receipt CPAI must respond to the issues contained within; that time has already
come and gone. I request an extension of this deadline for one week from today so there is adequate time to make a
proper response. I propose that CPA[ needs to make a response no later than the close of business on Monday, January
14. Please respond and indicate whether that date is acceptable or not. Thanks for your understanding of the position
CPAI is in regarding the requirements stated in the letter.
My regards,
Jerry Dethlefs
Well Integrity Director
ConocoPhillips Alaska
Office: 907-265-1464
Cell: 907-268-9188
#2
V OF TFJ� •
THE STATE Alaska Oil and Gas
Conservation Commission
GOVERNOR SEAN PARNELL
December 21, 2012
Certified Mail
Return Receipt Requested
7009 2250 0004 3911 5792
Mr. Jerry Dethlefs
Well Integrity Director
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Re: Notice of Proposed Enforcement Action
Failure to complete a Mechanical Integrity Test (MIT)
Failure to report to AOGCC a pressure communication
Kuparuk River Unit 3Q-16 (KRU 3Q-16) (PTD 1861790)
Dear Mr. Dethlefs:
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
The Alaska Oil and Gas Conservation Commission (AOGCC) hereby notifies ConocoPhillips
Alaska, Inc. (CPAI) of a proposed enforcement action.
Nature of the Apparent Violation or Noncompliance (20 AAC 25.535(b)(1)).
The AOGCC believes CPAI violated the provisions of Rule 6 of Area Injection Order 2B (AIO
213) ("Demonstration of Tubing/Casing Annulus Mechanical Integrity"), the provisions of Rule 7
of AIO 2B ("Well Integrity Failure") and 20 AAC 25.402(f) in its operation of the KRU 3Q-16
well.
Basis for Finding the Violation or Noncompliance (20 AAC 25.535(b)(2)).
By email dated November 13, 2012 CPAI notified the AOGCC that KRU 3Q-16 was returned to
injection on August 22, 2012 without the required MIT. CPAI also states "the TIO plot]
suggests TxIA2 communication based on the slowly building IA pressure". KRU 3Q-16 ceased
injection on November 1, 2012 and was shut in by CPAI.
' TIO plot is a graphical representation of the well's tubing, inner annulus, and outer annulus pressures over a
specified time period.
2 TxIA = tubing by inner annulus
I-]
0
SENDER: COMPLETE THIS SE
TION
■ Complete items 1, 2, and 3. Also complete
item 4 if Restricted Delivery is desired.
■ Print your name and address on the reverse
so that we can return the card to you.
A.
❑■
■ Attach this card to the back of the mailpiece, 1, H6c Y Printed !}lame) C. Date of Delivery
or on the front if space permits. J tJG eY Z c
1. Article Addressed to: D. Is delivery address different from item 1? ❑ Yes
If YES, enter delivery address below: ❑ No
J. s e Type
rtiffed Mail ❑ Express Mail
❑ Registered %);Wtum Receipt for Merchandise
❑ Insured Mail ❑ C.O.D.
4 Racfrlrtdl rleL'......n m._._ .-
- ---- ....,,r, r� r,a�w� U Yes
c. Article Number
(Transfer from service label) 7009 2250 0004 3 911 5792
PS Form 3811, February2004
Domestic Return Receipt
102595-02-M•1540
Postal
CERTIFIED MAIL,.
RECEIPT
ru I
(Domestic Mail Only; No Insurance
Coverage
Provided)
Er
r-
,n
rigNUMMUMM
AL
U
r"i
Q Postage
$
m
Certified Fee
-I
Postmark
O Return Receipt Fee
Here
O (Endorsement Required)
Restricted Delivery Fee
(Endorsement Required)
Ln
rU Total Postage & Fees
r $;
rU
Sent To --
/
�..-----
t.r
0 , Street, ApNo.;
-- -
- -
� oPO Box No.
----------
-----
..
r City State, Z%P+.1
PS Form 8030
Notice of Proposed Enforcement on 3Q-16 •
December 21, 2012
Page 2 of 4
Rule 6 of AIO 2B states "A schedule must be developed and coordinated with the Commission,
which ensures that the tubing/casing annulus for each injection well is pressure tested prior to
initiating injection and at least once every four years thereafter. "
The last AOGCC-witnessed MIT occurred September 25, 2008. Therefore an MIT was required
on or before September 25, 2012. No MIT was performed before September 26, 2012. The well
was out of compliance, but continued injection for 37 days, from September 26, 2012 to
November 1, 2012.
Under AOGCC regulations, "If an injection rate, operating pressure observation, or pressure
test indicates pressure communication or leakage in any casing, tubing, or packer, the operator
shall notify the commission by the next working day... "
Rule 7 of AIO 2B states "Whenever operating pressure observances or pressure tests indicate
pressure communication or leakage of any casing, tubing or packer, the operator must notify the
Commission on the first working day following the observation, obtain Commission approval of
a plan for corrective action, and when an USDW is not endangered, obtain Commission
approval to continue injection. "
AOGCC records demonstrate the only notice of potential pressure communication is the email
sent on November 13, 2012. AOGCC review of the TIO plots (pressure data from May 28, 2012
to November 12, 2012) indicate significant pressure anomalies which were not communicated to
the AOGCC. Significant inner annulus (IA) pressure decreases occur from September 8, 2012 to
October 2, 2012. On October 3, 2012 the IA pressure increased 650 psi to 2300 psi from the
October 2, 2012 reading of 1650 psi. Incremental increases and sustained IA pressure are
exhibited from October 10, 2012 through to well shut in November 2, 2012. Potential pressure
communication occurring after October 10, 2012 demonstrates non-compliance with reporting
guidelines from October 11, 2012 to November 12, 2012.
CPAI has failed to demonstrate the mechanical integrity of injection well KRU 3Q-16 within the
required four year cycle, and to report to AOGCC a pressure communication indicating a
potential loss of mechanical integrity on KRU 3Q-16 by the next working day, which would be
violations of State regulations.
Proposed Action (20 AAC 25.535(b)(3).
Within 2 weeks of the date of the AOGCC's final decision, CPAI shall:
(1) provide a detailed description of its Underground Injection Control (UIC) regulatory
compliance program;
(2) provide details of its tracking system for determining when MIT's are required,
including the details of contingencies for wells shut in at the time an MIT is due and its
procedures for notification to the AOGCC, as well as its processes for determining the
MIT due date and identification of past due wells;
(3) complete and provide the results of a root cause analysis addressing the violations.
Notice of Proposed Enforcement loon 3Q-16 •
December 21, 2012
Page 3 of 4
For these violations the AOGCC intends to impose civil penalties on CPAI as follows 3:
$10,000 for the initial violation — failure to perform the required MIT of the injection
well in compliance with testing protocols specified in Rule 6 of AIO 213;
$500 for each day September 26, 2012 to November 1, 2012 (37 days) for injecting in
a well out of compliance with MIT regulations.
$500 for each day October 11 through November 12, 2012 inclusive (33 days) for
failing to notify AOGCC of indication of pressure communication or leakage in KRU
3Q-16.
The total proposed civil penalty is $45,000. CPAI's failure to comply with the fundamental
wellbore mechanical integrity testing requirements raises the potential for similar behavior with
more serious consequences. Violations relating to Underground Injection Control Class II well
integrity and notification practices warrant the imposition of civil penalties. Mitigating
circumstances considered in issuing the proposed civil penalty include the operator's history of
satisfactory compliance and practices, the existing aquifer exemption of the KRU, the lack of
actual or potential threat to public health or the environment, CPAI's initiative in notifying
AOGCC, and CPAI's initiative to shut in the KRU 3Q-16 once CPAI determined the well was
out of compliance.
Rights and Liabilities (20 AAC 25.535(b)(4)).
Within 15 days after receipt of this notification — unless the AOGCC, in its discretion, grants an
extension for good cause shown — CPAI may file with the AOGCC a written response that
concurs in whole or in part with the proposed action described herein, requests informal review,
or requests a hearing under 20 AAC 25.540. If a timely response is not filed, the proposed action
will be deemed accepted by default. If informal review is requested, the AOGCC will provide
CPAI an opportunity to submit documentary material and make a written or oral statement. If
CPAI disagrees with the AOGCC's proposed decision or order after that review, it may file a
written request for a hearing within 10 days after the proposed decision or order is issued. If
such a request is not filed within that 10-day period, the proposed decision or order will become
final on the 1 Ith day after it was issued. If such a request is timely filed, the AOGCC will hold
its decision in abeyance and schedule a hearing.
If CPAI does not concur in the proposed action described herein, and the AOGCC finds that
CPAI has violated a provision of AS 31.05, 20 AAC 25, or an AOGCC order, permit or other
approval, then the AOGCC may take any action authorized by the applicable law including
ordering one or more of the following: (i) corrective action or remedial work; (ii) suspension or
revocation of a permit or other approval; (iii) payment under the bond required by 20 AAC
25.025; and (iv) imposition of penalties under AS 31.05.150. In taking action after an informal
review or hearing, the AOGCC is not limited to ordering the proposed action described herein, as
long as CPAI received reasonable notice and opportunity to be heard with respect to the
3 AS 31.05.150(a) provides for not more than $100,000 for the initial violation and not more than $10,000 for each
day thereafter on which the violation continues.
Notice of Proposed Enforcement Son 3Q-16 •
December 21, 2012
Page 4 of 4
AOGCC's action. Any action described herein or taken after an informal review or hearing does
not limit the action the AOGCC may take under AS 31.05.160.
Sincerely,
Daniel T. Seamount, Jr.
Commissioner
#1
Wallace, Chris D (DOA)
From: NSK Problem Well Supv [n1617@conocophillips.com]
Sent: Tuesday, November 13, 2012 10:43 AM
To: Regg, James B (DOA); Wallace, Chris D (DOA)
Subject: 3Q-16 (PTD 186-179) report of TAA communication and out of date 4 yr MIT 11-13-12
Attachments: 3Q-16.xis; 3Q-16 schematic.pdf
Follow Up Flag: Follow up
Flag Status: Flagged
Jim, Chris
While compiling the 4 yr MIT quarterly report, I discovered that 3Q-16 (PTD 186-179) was not tested on schedule. Its last
4 yr test was completed on 9/25/08 and therefore was due this past September. During this summer's pad testing on 3Q
on 8/8/12, the well was shut in and therefore not included in the testing per Guidance Bulletin 10.002. It was returned to
injection on 8/22/12 and was missed and not tested.
The TIO plot suggests TxIA communication based on the slowly building IA pressure. The well is open to the MI injection
header but is not injecting due to tight reservoir sands. Under normal circumstances we would WAG this well to water
and monitor for communication. The water injection line is derated and cannot be used. The well will be shut in,
diagnostics initiated, and when there is something more to report we will contact the AOGCC with suggested repair plans
for your approval. The well will remain shut in until AOGCC approves return of service and will be added to the monthly
report.
Please call or email with any questions you may have.
Brent Rogers / Kelly Lyons
Problem Wells Supervisor
ConocoPhillips Alaska, Inc
Desk Phone (907) 659-7224
Pager (907) 659-7000 pgr 909
1� I4 PO 1 T- Poi ►A N T ass eon (�IY)InC4 S - -�
GPA h atvw� -jegs �")
