Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
CO 406 C
INDEX CONSERVATION ORDER NO. 406C Kuparuk River Field Kuparuk River Unit West Sak Oil Pool 1. January 30, 2014 ConocoPhillips Alaska, Inc.’s (CPAI) application to amend CO 406B, Exhibit 2 and Exhibits 5-7 held in secure storage 2. February 28, 2014 Notice of Public Hearing, Affidavit of Publication, email distribution, and mailings 3. March 17, 2014 and April 1, 2014 Public Hearing sign-in sheet, emails regarding calendaring Public Hearing for April 23, 2014 4. April 17, 2014 Emails regarding CPAI’s intention to convert current water injection wells into WAG service 5. April 22, 2014 CPAI’s supplemental request 6. April 23, 2014 Public Hearing transcript, sign-in sheet, CPAI’s West Sak Pool Rules and AIO Amendment exhibit 7. May 7, 2014 Additional information submitted by CPAI requested by AOGCC on Public Hearing held on April 23, 2014 8. March 14, 2016 CPA request to waive the monthly production allocation report (CO406C-002) 9. September 16, 2022 Eni request to modify well testing and production allocation conditions (CO406C.003) ORDERS • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF ConocoPhillips ) Docket Number: CO-14-003 Alaska, Inc. to modify the vertical and ) Conservation Order No. 406C areal limits of the West Sak Oil Pool, ) Kuparuk River Field, North Slope, Alaska ) Kuparuk River Field Kuparuk River Unit West Sak Oil Pool June 19, 2014 IT APPEARING THAT: 1. By application dated January 30, 2014, and received by the Alaska Oil and Gas Conservation Commission (AOGCC) on January 31, 2014, ConocoPhillips Alaska, Inc. (CPAI) requested the pool definition of the West Sak Oil Pool (WSOP) be expanded vertically to include the Schrader Bluff N Sands and that the northern and eastern extents of the pool be modified to coincide with the current unit boundaries. 2. Pursuant to 20 AAC 25.540, the AOGCC tentatively scheduled a public hearing for April 1, 2014. On February 28, 2014, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On March 1, 2014, the notice was published in the ANCHORAGE DAILY NEWS. The hearing was convened on April 1, 2014, and recessed until April 23, 2014. 3. The hearing was reconvened on April 23, 2014, and the AOGCC received testimony from CPAI. 4. The hearing record was held open until May 7, 2014, to allow CPAI an opportunity to respond to questions raised by AOGCC during the hearing. 5. By letter dated and received on May 7, 2014, CPAI responded to those questions. FINDINGS: 1. CPAI is the operator of the WSOP within the Kuparuk River Unit (KRU). 2. The WSOP is currently defined as only containing the West Sak Sands that correlate with the "O" Sands in the Schrader Bluff Oil Pools in the adjacent Milne Point Unit, Nikaitchuq Unit, and Prudhoe Bay Unit. Conservation Order 406C • June 19, 2014 Page 2 of 7 3. In the Prudhoe Bay, Milne Point, and Nikaitchuq Units, the Schrader Bluff N Sands and O Sands are being developed together as a single oil pool (collectively called Schrader Bluff Oil Pools or SBOPs). The affected areas for the SBOPs are adjacent to the affected area of the WSOP. 4. The unit boundaries have changed since the WSOP was originally defined in 1997 and now there are areas that are defined as both being part of the WSOP and as part of one of the SBOPs. Likewise there are areas that lie within the current KRU boundaries that should be a part of the WSOP affected area that aren't currently included in the pool description. CONCLUSIONS: 1. The existing vertical limits of the WSOP do not reflect the current understanding of how to effectively develop the Schrader Bluff Formation sands (N Sands and West Sak Sands/O Sands). 2. The existing areal extent of the WSOP creates areas where there are two sets of pool rules covering the same pool and areas where there are no pool rules where they should exist. NOW THEREFORE IT IS ORDERED: Conservation Order 406B is superseded and its record incorporated by reference into this order. The following rules apply to the WSOP within the following affected area: Conservation Order 406C • • June 19, 2014 Page 3 of 7 Umiat Meridian Township Range Sections T8N R7E Sections 1-18 T9N R1 IE Sections 5-8, 17-20, 29-32 T9N R10E All T9N R9E All T9N R8E All T9N R7E All T10N RI IE Sections 3-10, 15-22, 29-32 TION R10E All T10N R9E All T10N R8E All T10N R7E All T11N RI IE Sections 5-8, 16-22, 27-34 T11N RIOE All T11N R9E All T11N R8E All T11N R7E All T12N R11E Section 31 T12N R10E Sections 3-10, 14-23, 25-36 T12N R9E All T12N R8E All T12N R7E All T13N R9E SW1/4 Section 2, W1/2& SE1/4 Section 11, Sections 3- 10, 15-22, 25-36 T13N R8E Sections 1-3, 10-12, 13-15, 19-36 Rule 1 Field and Pool Name (Restated from CO 406B) The field is the Kuparuk River Field. Hydrocarbons underlying the affected area and within the herein defined interval of the Schrader Bluff Formation constitute a single oil and gas reservoir called the West Sak Oil Pool. Rule 2 Pool Definition (Revised this order) The West Sak Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 3,552 feet and 4,156 feet in the West Sak No. 1 well. Rule 3 Well Spacing (Restated from CO 406B)) There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to an external property line where ownership or landownership changes. Rule 4 Casing and Cementing Practices (Restated from CO 406M a. Conductor casing will be set at least 75 feet below ground level and cemented to surface. Conservation Order 406C • June 19, 2014 Page 4 of 7 b. Where required for annular disposal, surface casing will be set at least 500 feet measured depth below the permafrost and be cemented to surface. c. Combination surface -production casing will be set where applicable through the producing or injection intervals and be cemented to surface. Rule 5 Iniection Well Completion (Restated from CO 406B) Injection wells may be completed with tapered casing provided a seal bore, packer, or other isolation device is positioned not over 200 feet above the top of the producing or perforated interval. Rule 6 Automatic Shut-in Equipment (Revised by Other Order 66) a. Injection wells (excluding disposal injectors) must be equipped with; i. a double check valve arrangement; or ii. a single check valve and a SSV. A subsurface -controlled injection valve or SCSSV satisfies the requirements of a single check valve. b. The Low Pressure Pilot may be defeated on West Sak water injectors with surface injection pressure less than 500psi. Rule 7 Common Production Facilities and Surface Commingling (Restated from CO 406B.011 a. Production from the West Sak Oil Pool may be commingled with production from the Tarn, Tabasco, Meltwater, and Kuparuk River oil pools in surface facilities prior to custody transfer. b. The allocation factor for the West Sak Oil Pool produced fluids will be based on West Sak well tests. The allocation factor will be calculated on a monthly basis utilizing the Satellite Allocation Technique detailed on Exhibit 18 of the written testimony dated April 26, 2001 ("Testimony for Meltwater Oil Pool Rules — Revision 1") and will be capped at 1.02000. c. Each producing well must be tested at least once monthly. d. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. e. The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. f. The operator shall provide the AOGCC with a well test and allocation review report in conjunction with an annual reservoir surveillance report. Rule 8 Reservoir Pressure Monitoring (Restated from CO 406BI a. A bottom -hole pressure survey shall be taken on each well prior to initial sustained production or injection. b. The Operator shall obtain pressure surveys as needed to effectively manage hydrocarbon recovery processes subject to an annual plan outlined in paragraph (e) of this rule. c. The reservoir pressure datum will be 3500 feet subsea. d. Pressure surveys may consist of stabilized static pressure measurements at bottomhole or Conservation Order 406C • June 19, 2014 Page 5 of 7 extrapolated from surface under single-phase conditions, pressure fall -off, pressure buildup, multi -rate tests, drill stem tests, and open -hole formation tests. e. Data from the surveys required in this rule shall be filed with the AOGCC by April 1 of the subsequent year in which the surveys are conducted. Along with the survey submittal, the operator will provide a proposed survey plan for the upcoming year. The proposed plan shall be deemed accepted if the operator has not received written correspondence from the AOGCC within 45 days. f. Reservoir Pressure Report, Form 10-412 shall be utilized for all surveys with attachments for complete additional data. Data submitted shall include, but are not limited to rate, pressure, depth, fluid gradient, temperature, and other well conditions necessary for complete analysis of each survey being conducted. g. Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 9 Gas -Oil Ratio Exemption (Restated from CO 406B) Wells producing from the West Sak Pool are exempt from the gas -oil -ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply. Rule 10 Pressure Maintenance Project (Restated from CO 406B) A pressure maintenance waterflood must be initiated within six months after the start of regular production from the West Sak Pool. Rule 11 Reservoir Surveillance Report (Restated from CO 406B) The Unit Operator shall submit an Annual Reservoir Surveillance Report by April 1 of each year documenting operations for the previous calendar year. The report shall include but is not limited to the following: a. Reservoir management summary including a description of progress of enhanced recovery project implementation and results of reservoir simulation techniques; b. Voidage balance by month of produced fluids and injected fluids on a standard and reservoir volume basis with yearly and cumulative volumes; c. Summary and analysis of reservoir pressure surveys within the pool; d. Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring; e. Review of pool production allocation factors and issues over the prior year; and f. Updated future development plans including an estimated development schedule, progress report and basis of timeline for the complete pool development. Rule 12 Production Anomalies (Restated from CO 406B) In the event of oil production capacity proration at or from the Kuparuk facilities, all commingled reservoirs produced through the Kuparuk facilities will be prorated by an equivalent percentage of oil production, unless this will result in surface or subsurface equipment damage. Rule 13 Sustained Casing Pressure (Restated from CO 406B) Conservation Order 406C • June 19, 2014 Page 6 of 7 a. The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c. The operator shall notify the AOGCC within three working days after the operator identifies a well as having (1) sustained inner annulus pressure that exceeds 2000 psig or (2) sustained outer annulus pressure that exceeds 1000 psig. d. The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph c of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. f. Except as otherwise approved by the AOGCC under paragraph (d) or (e) of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 psig and (2) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph (c), but not paragraph (e), of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph (c), unless the AOGCC prescribes a different limit. g. For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; Conservation Order 406C 0 June 19, 2014 Page 7 of 7 "sustained pressure" means pressure that (1) is measurable at the casing head of an annulus, (2) is not caused solely by temperature fluctuations, and (3) is not pressure that has been applied intentionally. Rule 14 Administrative Actions (Restated from CO 406B) Unless notice and public hearing is otherwise required, upon proper application the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater_ DONE at Anchorage, Alaska and dated June 19, 2014. v Cathy P Foers er 4aniel T. mount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. E • Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, June 20, 201412:23 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator, Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; 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 McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Schultz (gary.schultz@alaska.gov); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry McCutcheon; Jim White; 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; 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, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; 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; Steve Kiorpes; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger, trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham 0 (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers, Jason Bergerson; Jennifer Starck; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Peter Contreras; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Woolf, Wendy C (DNR); To: 1Nlfr3m Hutto; William Van Dyke is Subject: Conservation Order 406C and Area Injection Order 2C Attachments: co406c.pdf, aio2c.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. • Penny Vadla George Vaught, Jr. Jerry Hodgden 399 W. Riverview Ave. Post Office Box 13557 Hodgden Oil Company Soldotna, AK 99669-7714 Denver, CO 80201-3557 40818 St. Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 James T. Rodgers Manager, GKA Development Darwin Waldsmith James Gibbs North Slope Operations and Development Post Office Box 39309 Post Office Box 1597 ConocoPhillips Alaska, Inc. Ninilchik, AK 99639 Soldotna, AK 99669 ATO-1326 700 G St. Anchorage, AK 99501 THE STATE "ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO.406C.002 CONSERVATION ORDER NO.430A.012 CONSERVATION ORDER NO. 435A.011 CONSERVATION ORDER NO.456A.011 Mr. Kazeem Adegbola Manager, Greater Kuparuk Area Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: CO-16-006 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to waive the monthly production allocation reporting requirement for the West Sak Oil Pool, Tarn Oil Pool, Tabasco Oil Pool, and Meltwater Oil Pools in the Kuparuk River Unit. Dear Mr. Adegbola: By letter dated March 14, 2016, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to waive the requirement for monthly reporting of daily allocation and test data contained in the following rules: - Rule 7(e) of Conservation Order No. (CO) 406C (Note: CPAI's request actually referred to CO 406B, but that order was superseded by CO 406C on June 19, 2014); - Rule 7(e) of CO 430A; - Rule 7(e) of CO 435A; and - Rule 6(e) of CO 456A; In accordance with Rule 14 of CO 406C, Rule 13 of CO 430A, Rule 13 of CO 435A, and Rule 12 of CO 456A, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to waive the requirement to submit monthly reports of daily allocation and test data. CPAI requested to waive the following rules in their entirety. Rule 7(e) of COs 406C, 430A, and 435A states: The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. CO 406C.002, CO 430A.012, CO 435A.011, CO 456A.011 May 10, 2016 Page 2 of 2 Rule 6(e) of CO 356A states: The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. Each of the affected pools is required to submit an annual reservoir surveillance report, providing a summary report on the production allocation and well test data in this annual report and retaining the ability to review the daily data if necessary allows the AOGCC to verify the performance of the well testing and allocation system without the need for monthly reports on the same data. Now therefore it is ordered that: Part (e) of Rule 7 CO 406C, CO 430A, and CO 435A, and part (e) of Rule 6 of CO 456Aare revised as follows: The operator shall submit a review of pool production allocation factors and issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. DONE at Anchorage, Alaska and dated May 10, 2016. Cathy . Foerster Chair, Commissioner Daniel T. S ount, Jr. Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, May 11, 2016 7:50 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Candi English; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty, Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; D. McCraine; Don Shaw; Eric Lidji; Furie Drilling; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; J. Stuart; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); T. Hord; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster; William Van Dyke Subject: co 406c-002, co430a-012, co435a-11, co456A-011 Attachments: co406c-002, co430a-012, co435a.1l,co456a-011.pdf Please see attached. Jot'Ay .1. Colomhte AOKjCC Spec1at_Assistant .Alaska Oit anct (ias Co11servation Con1n11ssioll 333 bVest 71'' ,A)1enue Anchorage, Alaska 9,950i Ofj t'e: (,9�)7) 7A3-1221 ,fah:: (�)07) 27 6-754 2 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. Bernie Karl James Gibbs Jack Hakkila K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Mr. Kazeem Adegbola Richard Wagner Darwin Waldsmith Manager, Greater Kuparuk Area Development P.O. Box 60868 P.O. Box 39309 ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 100360 Anchorage, AK 99510-0360 '.z; v-; & Angela K. Singh 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL CO 406C.003 ADMINISTRATIVE APPROVAL CO 430A.014 ADMINISTRATIVE APPROVAL CO 432E.001 ADMINISTRATIVE APPROVAL CO 435A.013 ADMINISTRATIVE APPROVAL CO 456A.013 ADMINISTRATIVE APPROVAL CO 596.010 ADMINISTRATIVE APPROVAL CO 597.010 Mr. Andrea Rimoldi Technical Services Director Eni US Operating Co Inc. 3700 Centerpoint Dr., Suite 500 Anchorage, AK 99503 Subject: Docket Number: CO-22-013 Multiphase Flow Meters (MPFM) Revised Conditional Agreement Oooguruk Unit Dear Mr. Rimoldi: By letter dated September 16, 2022, Eni US Operating Co Inc. (Eni) requested the Alaska Oil and Gas Conservation Commission (AOGCC) revise the conditions of approval for using multiphase metering for fiscal allocation of production from the Oooguruk Unit (OU) to be consistent with revised conditions that Eni and ConocoPhillips Alaska Inc. (CPAI) had developed and that were contained in a letter, which was included with Eni’s application, from CPAI to Eni dated August 25, 2022. The revised conditions are based on lessons learned over the more than a decade’s experience with the fiscal allocation meters in use at the OU and operating and maintenance practices. The AOGCC hereby approves Eni’s request to revise the conditions of approval for using multiphase metering for fiscal allocation purposes at OU. The revised conditions of approval are: 1. The Measurement Metering Operations and Maintenance Guidelines set forth as Appendix 4 to the April 14, 2008, joint application to the AOGCC shall be the basis for all current and future maintenance. Changes to the Guidelines must be mutually agreed upon between Eni and CPAI and remain under a revision control procedure. Administrative Approval CO 406C.003, CO 430A.014, CO 432E.001, CO 435A.013, CO 456A.013, CO 596.010, CO 597.010 February 1, 2023 Page 2 of 4 2. Eni must perform a Fluid Point Reference (FPR) at least every 31 days. If the fluid properties are known to have changed, Eni must perform a FPR using a representative combined fluid sample from the onshore separator within four days of the change. Events that may trigger a change in fluid properties include the introduction of a new well and shutting in, or bringing on, one or more producing wells. 3. When an extraordinary event occurs, Eni must perform calibration checks on MPFM secondary instrumentation and recalibrate them if necessary. Secondary instrumentation includes line temperature transmitter (TL), line pressure transmitter (PL), and differential pressure cell (DPV). CPAI continues to have sole but reasonable discretion to determine what constitutes an extraordinary event. Non-exclusive examples of what might reasonably be deemed an extraordinary events include spikes in differential pressure that put bias in the differential pressure cell, excessive slugging, and meter over range. 4. The MPFM data acquisition flow computer (DAFC) configuration, as agreed upon by Eni, CPAI and Schlumberger, will be checked every three months. No changes may be made to the DAFC configuration file inputs, except for the parameters associated with the updates of the Empty Pipe References and Fluid Point References, without prior agreement among all three parties. 5. Eni must record all activity related to the MPFM that measures the Oooguruk total field production in the electronic MPFM Compliance Log found in the Web-based Report Generator (WRG). The compliance log must be available for inspection and copying by CPAI. Examples of activity that must be recorded in the logbook include dates, times and notes pertaining to calibrations, data validations, changes to the DAFC, audits, nuclear source tests/replacements, and walk-around findings. 6. Eni is to log MPFM data (at the DAFC) at 1-second intervals. This data will be stored and retained to allow for post-processing analysis at CPAI's request. 7. As provided for under Section 9.7 of Attachment 4 to the Production Processing and Services Agreement (PPSA), an audit team that includes Eni, CPAI, and an Independent Party, recognized as an expert and agreed by other members of the team, shall audit the MPFM performance and accuracy on a 24-month frequency, or as otherwise agreed by CPAI. The Independent Party will Chair the audit team. 8. Eni operators who perform unsupervised maintenance on the Schlumberger Vx meters must be trained and evaluated on their use and maintenance. The Eni Measurement Operations Engineer, their designee, or qualified testing personnel may train and evaluate personnel on the use and maintenance of the Vx meters. These persons, as well as Eni Operators who have been trained and evaluated, may supervise personnel who have not completed training. Training records should be available upon request. Administrative Approval CO 406C.003, CO 430A.014, CO 432E.001, CO 435A.013, CO 456A.013, CO 596.010, CO 597.010 February 1, 2023 Page 3 of 4 Persons filling the role of the Eni Measurement Operations Engineer should be experienced in the operation and maintenance of Schlumberger Vx meters or multiphase flow meters using similar technology. 9. Eni must produce a monthly report relating the performance, sampling, and maintenance work carried out on the MPFM's. The report format is subject to CPAI's approval. 10. Eni must perform metering maintenance activities according to the following frequency schedule: OTP MPFM Fiscal Metering Maintenance Procedures Activity Frequency Gas, Oil and Water Allocation Metering Daily Checks Daily General Meter Walk Around and Inspection Daily Transmitter Calibration Checks: DPV, PL and TL 31 Days Fluid Point Reference (FPR) Update 31 Days Nuclear source Wipe Tests 6 Mo Ex and ExD Checks – Explosion-Proof DAFC Housing 1 Yr Thermowell Inspections 1 Yr Recalibrate Dedicated Test Equipment at NIST/Approved Lab 2 Yr MPFM Venturi Inspection* 3 Yr Nuclear Source Replacement** 5 Yr * CPAI, with AOGCC approval, reserves the right to change the frequency of MPFM Venturi Inspections back to the two-year interval specified in the June 25, 2009, letter to Pioneer that was subsequently incorporated in the AOGCC's approval. **CPAI, with AOGCC approval, reserves the right to grant up to five successive one-year extensions to the replacement interval for the OTP nuclear sources. Eni shall request each one- year extension, with CPAI approval based on an evaluation of nuclear source performance and MPFM uncertainty. The maximum length of time between replacement of the OTP nuclear sources shall not exceed 10 years. Custody Gas Meter Maintenance Procedures Activity Frequency General Meter Walk Around and Inspection Daily USM Temperature & Pressure Transmitter Calibration Checks 31 Days USM Meterlink Maintenance/Diagnostics Log 31 Days Coriolis Smart Meter Verification 31 Days Coriolis Molecular Weight/Compressibility Update 31 Days Recalibrate Dedicated Test Equipment at NIST/Approved Lab 2 Yr Gas Meter Inspection and Cleaning Planned Plan SD Administrative Approval CO 406C.003, CO 430A.014, CO 432E.001, CO 435A.013, CO 456A.013, CO 596.010, CO 597.010 February 1, 2023 Page 4 of 4 DONE at Anchorage, Alaska and dated February 1, 2023. Brett W. Huber, Sr. Jessie L. Chmielowski Chair, Commissioner Commissioner cc: Mr. Mike Timmcke Manager, GKA Operations ConocoPhillips Alaska P.O. Box 100360 Anchorage, AK 99510-0360 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.02.01 13:37:01 -09'00' Brett W. Huber. Sr. Digitally signed by Brett W. Huber. Sr. Date: 2023.02.01 14:27:53 -09'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] CO 406C.003, CO 430A.014, CO 432E.001, CO 435A.013, CO 456A.013, CO 596.010, CO 597.010 (Oooguruk) Date:Wednesday, February 1, 2023 3:02:52 PM Attachments:MPFM Conditions of approval.pdf Administrative Approval CO 406C.003, CO 430A.014, CO 432E.001, CO 435A.013, CO 456A.013, CO 596.010, CO 597.010. Docket Number: CO-22-013 Multiphase Flow Meters (MPFM) Revised Conditional Agreement Oooguruk Unit. Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 2/1/23 INDEXES 9 By Samantha Carlisle at 11:17 am, Sep 26, 2022 Page 1 of 3 August 25, 2022 Mr. David Hart Eni US Operating Company 3700 Centerpoint Dr., Suite 500 Anchorage, AK 95503 RE: Conditional Letter of Approval to Alaska Oil and Gas Conservation Commission Dear Mr. Hart: The Alaska Oil and Gas Conservation Commission (AOGCC) granted final approval for use of Schlumberger Vx Multiphase Flow Meters (MPFM) to measure Oooguruk Unit production for fiscal and production allocation purposes on July 30, 2009. Permanent approval by the AOGCC required the support of ConocoPhillips Alaska, Inc. (CPAI), as Operator of the Kuparuk River Unit. CPAI formally gave their support in a letter to Pioneer Natural Resources Alaska, Inc. (Pioneer) dated June 25, 2009, subject to 10 conditions outlined in the letter. Then on August 4, 2015, CPAI amended those 10 conditions based on the operating and maintenance practices of Caelus Natural Resources, LLC (Caelus); the Operator of the Oooguruk Unit at the time. CPAI is willing to amend the 10 previously approved conditions based on current operating and maintenance practices of Eni US Operating Co (Eni), Operator of the Oooguruk Unit and successor to Caelus as set forth below, and subject to approval by the AOGCC. The revised conditions are as follows: 1. The Measurement Metering Operations and Maintenance Guidelines set forth as Appendix 4 to the April 14, 2008 joint application to the AOGCC shall be the basis for all current and future maintenance. Changes to the Guidelines must be mutually agreed upon between Caelus and CPAI and remain under a revision control procedure. 2. Eni must perform a Fluid Point Reference (FPR) at least every 31 days. If the fluid properties are known to have changed, Eni must perform a FPR using a representative combined fluid sample from the onshore separator within four days of the change. Events that may trigger a change in fluid properties include the introduction of a new well and shutting in, or bringing on, one or more producing wells. 3. When an extraordinary event occurs, Eni must perform calibration checks on MPFM secondary instrumentation and recalibrate them if necessary. Secondary instrumentation includes line temperature transmitter (TL), line pressure transmitter (PL), and differential pressure cell (DPV). CPAI continues to have sole but reasonable discretion to determine what constitutes an extraordinary event. Non-exclusive examples of what might reasonably be deemed an extraordinary event include: spikes in differential pressure that put bias in the differential pressure cell, excessive slugging, and meter over range. Mike Timmcke Manager, GKA Operations P. O. Box 100360 Anchorage, AK 99510-0360 Phone 907-659-7219 Page 2 of 3 4. The MPFM data acquisition flow computer (DAFC) configuration, as agreed upon by Eni, CPAI and Schlumberger, will be checked every three months. No changes may be made to the DAFC configuration file inputs, except for the parameters associated with the updates of the Empty Pipe References and Fluid Point References, without prior agreement among all three parties. 5. Eni must record all activity related to the MPFM that measures the Oooguruk total field production in the electronic MPFM Compliance Log found in the Web-based Report Generator (WRG). The compliance log must be available for inspection and copying by CPAI. Examples of activity that must be recorded in the logbook include dates, times and notes pertaining to calibrations, data validations, changes to the DAFC, audits, nuclear source tests/replacements, and walk-around findings. 6. Eni is to log MPFM data (at the DAFC) at 1-second intervals. This data will be stored and retained to allow for post-processing analysis at CPAI's request. 7. As provided for under Section 9.7 of Attachment 4 to the Production Processing and Services Agreement (PPSA), an audit team that includes Eni, CPAI, and an Independent Party, recognized as an expert and agreed by other members of the team, shall audit the MPFM performance and accuracy on a 24-month frequency, or as otherwise agreed by CPAI. The Independent Party will Chair the audit team. 8. Eni operators who perform unsupervised maintenance on the Schlumberger Vx meters must be trained and evaluated on their use and maintenance. The Eni Measurement Operations Engineer, their designee, or qualified testing personnel may train and evaluate personnel on the use and maintenance of the Vx meters. These persons, as well as Eni Operators who have been trained and evaluated, may supervise personnel who have not completed training. Training records should be available upon request. Persons filling the role of the Eni Measurement Operations Engineer should be experienced in the operation and maintenance of Schlumberger Vx meters or multiphase flow meters using similar technology. 9. Eni must produce a monthly report relating the performance, sampling, and maintenance work carried out on the MPFM's. The report format is subject to CPAI's approval. 10. Eni must perform metering maintenance activities according to the following frequency schedule: OTP MPFM Fiscal Metering Maintenance Procedures Activity Frequency Gas, Oil and Water Allocation Metering Daily Checks Daily General Meter Walk Around and Inspection Daily Transmitter Calibration Checks: DPV, PL and TL 31 Days Fluid Point Reference (FPR) Update 31 Days Nuclear Source Wipe Tests 6 Mo Ex and ExD Checks – Explosion-Proof DAFC Housing 1 Yr Thermowell Inspections 1 Yr Recalibrate Dedicated Test Equipment at NIST/Approved Lab 2 Yr MPFM Venturi Inspection * 3 Yr Nuclear Source Replacement** 5 Yr Page 3 of 3 * CPAI, with AOGCC approval, reserves the right to change the frequency of MPFM Venturi Inspections back to the two-year interval specified in the June 25, 2009 letter to Pioneer that was subsequently incorporated in the AOGCC's approval. **CPAI, with AOGCC approval, reserves the right to grant up to five successive one-year extensions to the replacement interval for the OTP nuclear sources. Eni shall request each one-year extension, with CPAI approval based on an evaluation of nuclear source performance and MPFM uncertainty. The maximum length of time between replacement of the OTP nuclear sources shall not exceed 10 years. Custody Gas Meter Maintenance Procedures Activity Frequency General Meter Walk Around and Inspection Daily USM Temperature & Pressure Transmitter Calibration Checks 31 Days USM Meterlink Maintenance/Diagnostics Log 31 Days Coriolis Smart Meter Verification 31 Days Coriolis Molecular Weight/Compressibility Update 31 Days Recalibrate Dedicated Test Equipment at NIST/Approved Lab 2 Yr Gas Meter Inspection and Cleaning Planned Plant SD Subject to these conditions, and AOGCC's approval, CPAI supports continued use of the MPFMs in their current application at the Oooguruk Unit. If these conditions are not satisfied or the measurement appears not to work as reasonably expected, CPAI may petition the AOGCC or take other action to ensure accurate fiscal metering and otherwise protect the interests of the Kuparuk River Unit Working Interest Owners. Nothing in this letter is intended to waive or modify any aspect of the Production Processing and Services Agreement. We look forward to continuing to work constructively with Eni for continued success of both the Kuparuk River and the Oooguruk Units. Sincerely, Mike Timmcke Manager, GKA Operations IV," ConocoPhillips Alaska, Inc. March 14, 2016 Commissioner Cathy Foerster Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Foerster, Kazeem Adegbola Manager, GKA Development North Slope Operations & Development ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, Alaska 99510-0360 Phone: (907) 263-4027 MAR 15 2016 A OGCC ConocoPhillips Alaska, Inc. (COPA), as Operator of the Kuparuk River Unit, respectfully requests an administrative action by the Commission to waive the requirement for monthly production allocation reports and well test data for the Meltwater, Tabasco, Tarn, and West Sak oil pools under the following Rules: 1. Rule 7(e) of CO 406B (West Sak Oil Pool) 2. Rule 7(e) of CO 430A (Tarn Oil Pool) 3. Rule 7(e) of CO 435A (Tabasco Oil Pool) 4. Rule 6(e) of CO 456A (Meltwater Oil Pool) The rule is stated similarly in each CO and generally reads: "The operator shall submit a monthly report and electronic file(s) containing daily allocation data and daily test data for agency surveillance and evaluation." (The word "electronic" was omitted in CO 456A.) COPA collects and retains this daily data and intends to continue to do so. The requested waiver is limited to the requirement for monthly reporting of this data. We will continue to provide the data in summary form to the Commission in the Annual Surveillance Reports for the Kuparuk River Unit. We could send the daily data to the Commissioner at any time, if asked to do so. We simply seek relief from the cost and burden of preparing the reports on a monthly basis. The Commission recently waived the monthly reporting requirements for the Colville River Unit. We are seeking the same treatment for the Kuparuk River Unit. Eliminating these monthly reports will allow the operator to appropriately allocate limited resources without compromising the data available to the Commission. We are concurrently submitting a similar request to the Alaska Department of Natural Resources. Please feel free to contact Gary Targac at 265-6586 regarding this request. Sincerely, Kazeem Adegbola Manager, reater Kuparuk Area Development Cc: Rob Kinnear, BP Exploration Inc. G. C. Fredrick, Chevron USA Inc. Gilbert Wong, ExxonMobil Alaska Production Inc. Cord Feige, AK DNR Division of Oil & Gas sConocoPhillip Alaska, Inc. March 14, 2016 Director Cord Feige State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 71h Ave., Suite 800 Anchorage, AK 99501-3560 Dear Director Feige, Kazeem Adegbola Manager, GKA Development North Slope Operations & Development ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, Alaska 99510-0360 Phone: (907) 263-4027 MAR 15 2016 ConocoPhillips Alaska, Inc. (COPA), as Operator of the Kuparuk River Unit, respectfully requests an administrative approval to waive the requirement for monthly production allocation reports and well test data under the Meltwater, Tabasco, Tarn, West Sak, and NEWS Participating Area Decisions of the Alaska Department of Natural Resources. The specific provisions of each Decision for which a waiver is requested are: 1. Meltwater Participating Area (MWPA) — Section IV Rules 11 & 14 2. Tabasco Participating Area (TABPA) — Section IV Rules 6 & 9 3. Tarn Participating Area (TPA) — Section IV Rules 13 & 16 4. West Sak Participating Area (WSPA) — Section IV Rules 8 & 13 With respect to the NEWS PA, we do not find specific language in the Decision approving the PA that requires monthly submittals. Nonetheless, it has been our practice to submit the data monthly for the NEWS PA as well as the other Kuparuk River Unit PAS. Therefore, we request a waiver for the NEWS PA in addition to the other Kuparuk River Unit PAS to make clear that monthly reports will no longer be expected for the NEWS PA. The rules are stated similarly in each Decision and generally read as follows: COPA, as KRU Operator, shall provide the Division with the monthly production allocation reports and well test data for the PA wells by the 20th of the month following production. The Division reserves the right to request any information it deems pertinent to the review of those reports. Moreover, the approval of the allocation methodology is conditioned upon the operator's agreement to promptly and fully reply to any such requests. The monthly allocation report shall include a summary of monthly allocation by well, and specific well test data for all tests that have been conducted. To account for the gas produced from each PA within the KRU and the gas volume disposition and gas reserves debited from or credited to each PA using the shared KRU facilities, COPA shall submit a monthly gas disposition and reserves debit report. The report shall be submitted with the monthly production allocation reports. Cc: Rob Kinnear, BP Exploration Inc. G. C. Fredrick, Chevron USA Inc. Gilbert Wong, ExxonMobil Alaska Production Inc. Cathy Foerster, Alaska Oil & Gas Conservation Commission #7 • C01--locoxophillips May 7, 2014 MAY 0 7 2014 A,OGW Commissioners Cathy Foerster and Daniel Seamount Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 James T. Rodgers Manager, GKA Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263 4027 RE: Request to Amend Conservation Order No. 406B and Area Injection Order No. 213: Request to Expand the West Sak Oil Pool Request to Expand VRWAG Project in West Sak Oil Pool Kuparuk River Field North Slope, Alaska Dear Commissioners: On April 23, 2014 the Alaska Oil and Gas Conservation Commission ("Commission or AOGCC") held a public hearing concerning ConocoPhillips Alaska, Inc.'s ("ConocoPhillips") Request to Amend Conservation Order 406E ("CO 4066") and Area Injection Order 213 ("AIO 2B") for the West Sak Oil Pool ("WSOP") within the Kuparuk River Unit ("KRU"). Cumulative Gas injection Volumes if VRWAG is approved as Injectant for West Sak The Commission requested additional information regarding gas injection volumes relating to cumulative injection and net injection following gas recovery. The estimated values are listed below for the ten expansion candidates within the West Sak Core Area as submitted in the application: Estimated injection volumes: o Cumulative gas injection volume = 102.5 BSCF o Cumulative net gas injection volume = 20.5 BSCF Estimated production volumes: o Cumulative returned injection volume = 82 BSCF o Cumulative produced West Sak solution gas volume = 82.6 BSCF o Cumulative produced gas volume = 164.6 BSCF Areal Extent of the West Sak Oil Pool Boundary The Commission requested ConocoPhillips provide any insights into the difference between the areal extent of the WSOP and the estimated hydrocarbon bearing zone. The areal extent of the proposed pool rules substantially conforms to the original WSOP boundaries established in October 1997 through Conservation Order 406. The original pool boundary was proposed to include the Greater West Sak alignment area at the southern boundary of the pool. At the public hearing for the original pool rules held on July 30, 1997, Mr. Keith Lynch of ARCO Alaska, Inc. testified that within this area, "The working interest owners have amended the Kuparuk River Unit Operating Agreement to specify requirements for cooperative development of this greater West Sak area, and the working interest owners recognize the need for a consistent development strategy across the entire West 0 0 CPAI Supplement to Request for Amendments CO 406B & AIO 2B May 7, 2014 Page 2 of 6 Sak pool, and we see having consistent pool rules across this area as a means of satisfying that need. So that's ...the main reason that the area is as large as it is." See pages 9 and 10 of the transcript of the proceedings (attached). Since that time, ConocoPhillips has not changed the geologic interpretation of the extent of West Sak hydrocarbons. ConocoPhillips has no additional geologic evidence beyond what was presented in the original hearing with respect to the areal extent of the WSOP. The modifications proposed by ConocoPhillips to the northern and western boundaries of the WSOP only arise from geographic changes in the extent of the KRU and the West Sak Participating Area since the time the original pool rules were issued. ConocoPhillips proposed these housekeeping changes to conform the boundaries listed in the WSOP Rules to the boundaries defined in the pool rules of the adjacent Schrader Bluff units. This eliminates the potential for conflict between the newly established pool rules for these adjacent units and the WSOP Rules. There would no longer be two sets of pool rules covering the same geographic area. Clarification of H2S Levels for West Salk The Commission asked ConocoPhillips regarding H2S levels in West Sak. In response, ConocoPhillips provided testimony which was correct for highest on -pad H2S levels. However, the highest on -pad H2S levels are not a reflection of those specific to West Sak since both Kuparuk and West Sak wells are drilled from the same pad location. A review of the most recent H2S samples from all West Sak production wells yields a range of H2S levels from 0 ppm to 275 ppm. Other Matters: AOGCC Staff Request for information Finally, the Commission also queried when it might expect to receive ConocoPhillips' response to an AOGCC staff request for an explanation of the impacts on Kuparuk River Unit recovery due to the conversion of the Oliktok Pipeline from importation of NGLs to fuel gas. Alan Campbell, Manager, GKA Reservoir Engineering and Planning, will provide a response directly to Dave Roby on or by May 31, 2014. Please do not hesitate to contact me at (907) 263-4027 should you have any additional questions or require clarification of the information provided in this letter or our request. Sincerely, James T. Rodgers Manager, GKA Development North Slope Operations and Development cc: Wolfe, Patrick Campbell, Alan Seitz, Brian • CPAI Supplement to Request for Amendments CO 406B & NO 2B May 7, 2014 Page 3 of 6 ATTACHMENT 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 91 MR. LYNCH: .....this is not it. CHAIRMAN JOHNSTON: .....what you'd -- you would describe this today as just basically the highlights of the more detailed plan that..... MR. LYNCH: That's a good description. CHAIRMAN JOHNSTON: .....you would be submitting to us, and that more detailed plan would do the three points that are on top of this slide: Prevent waste, protect correlative rights and ensure a greater ultimate recovery. MR. LYNCH: Yes. CHAIRMAN JOHNSTON: Thank you. MR. LYNCH: Well, here again these are the bases for the rules, and we will discuss the rules in a little bit more detail. This is Exhibit 2 from the written portion of our testimony, but I wanted to put this up to make sure that everybody is aware of the area that we're actually talking about today, and here for locator purposes you can see the outline of the Milne Point Unit, the Kuukpik Unit and then the Kuparuk River Unit all delineated with dash lines, and then the single heavy line inside the highlighted -- or that bounds the highlighted area is the area that the working interest owners refer to as the greater West Sak area, and that is the area that we'd like these pool rules to apply to. The working interest owners have amended the Kuparuk ELITE COURT REPORTING 4051 East 20th Avenue #65 • Anchorage Alaska 99508 907.333-0364 1 2 3 4 5 6 7 8 9 13 1 14 15 16 17 I". 19 20 21 22 23 25 10 River Unit Operating Agreement to specify requirements for cooperative development of this greater West Sak area, and the working interest owners recognize the need for a consistent development strategy across the entire West Sak pool, and we see having consistent pool rules across this area as a means of satisfying that need. So that's why the --- one of the main reasons that the area is as large as it is. That's kind of the meat of our introduction, and if the commission is ready to proceed, I'd like to turn the mic over to Mike Werner to give you some details about. Rules 1 and 2 that basically define the pool. CHAIRMAN JOHNSTON: I assume you wish to be sworn this morning? MR. WERNER: Yes, I do. CHAIRMAN JOHNSTON: Please raise your right hand. (Oath administered) MR. WERNER: Yes, I do. CHAIRMAN JOHNSTON: Please state your name for the record. MR. WERNER: My name, Mr. Chairman and Mr. Commissioner, is Michael Werner; W-e-r--n-e-r. CHAIRMAN JOHNSTON: And do you wish to be considered an expert witness in this matter: MR. WERNER: Yes, I do. CHAIRMAN JOHNSTON: If you'd state your qualifications. ELITE COURT REPORTING 4051 East 20th Avenue #65 Anchorage Alaska 99508 907.333.0364 #6 • 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 Before Commissioners: Cathy Foerster, Chair 4 Daniel T. Seamount 5 6 In the Matter of ConocoPhillips Alaska's ) 7 Request for Amendment of CO 406B and ) 8 AIO 2B to Expand the West Sak Oil Pool ) 9 and Authorize Expansion of the Viscosity ) 10 Reducing Water Alternating Gas Project ) 11 to Full Field Development. ) 12 ) 13 Docket No.: CO 14-03 14 15 ALASKA OIL and GAS CONSERVATION COMMISSION 16 Anchorage, Alaska 17 18 April 23, 2014 19 9:00 o'clock a.m. 20 21 VOLUME I 22 PUBLIC HEARING 23 24 BEFORE: Cathy Foerster, Chair 25 Daniel T. Seamount, Commissioner 0 • 1 TABLE OF CONTENTS 2 Remarks by Chair Foerster 3 Remarks by Mr. Rogers 4 Remarks by Mr. Jensen 5 Remarks by Mr. Warner 6 Remarks by Mr. Sendent 7 Remarks by Mr. Redman 03 05 11 19 46 52 2 • • 1 P R O C E E D I N G S 2 (On record - 9:00 a.m.) 3 CHF_IR FOERSTER: All right. I'll. call this 4 hearing to order. Today is April 23rd, 2014, the- time 5 is 9:00 a.ni. ;,e're located at the offices of the 6 Alaska Oil & Gas Conservation Commission, 333 West 7 Seventh Avenue, Anchorage, Alaska. To my left is 8 Daniel Seamount, Commissioner, and I'm Cathy Foerster, 9 the Chair. 10 We're meeting today regarding docket number CO 11 14-03, West Sak Oil Pool, Kuparuk River field, proposed 12 amendment of pool rules and area injection order. 13 A brief summary although everyone in the room 14 knows why we're here for the record. ConocoPhillips 15 Alaska by application dated January 30th, 2014, has 16 requested that conservation order number 406B and area 17 injection order number 2B, which established rules 18 governing development of the West Sak oil pool, Kuparuk 19 River field, be amended to expand the pool and 20 authorize expansion of the viscosity reducing water 21 alternating gas project from a pilot to full field 22 development. 23 Computer Matrix will be recording today's 24 proceedings and you can get a transcript from them. 25 I see people who have lots of experience 3 1 testifying before us and I want to remind you that when 2 you speak make sure both of the microphones are turned 3 on and speak -- try to speak into both of them or, you 4 ?rnc; .__nd of get bet-,,,een them, that both the court reperter and the people in the bac]r of the room can 6 hear what you're saying. 7 All right. It looks like Conoco is teed up and 8 ready to testify. So what we'll do first is we'll 9 swear all of you in at one time if that's okay with you 10 guys, it's just for simplicity. So if you'll just 11 raise your right hand. 12 (Oath administered) 13 CHAIR FOERSTER: One at a time introduce 14 yourself and say yes. 15 UNIDENTIFIED VOICES: (Indiscernible - away 16 from microphone)..... 17 CHAIR FOERSTER: Thank you. All right. So 18 again for the sake of the record I want to remind you 19 when you start to speak introduce yourself and if 20 someone else feels the need to chime in and give 21 assistance before you start introduce yourself. And as 22 best you can as you're referencing overhead pictures 23 refer to them by something that will identify them. I 24 hope they're numbered and if they're not some other 25 identifier. 4 1 Okay. All right. That's all the housekeeping 2 I had so you guys go ahead. 3 JAMES ROGERS previously .:'orn, called as a.-,,itness on hehalf of 5 ConocoPhillips Alaska, stated as follows on: 6 DIRECT EXAMINATION 7 MR. ROGERS: Okay. Good morning, 8 Commissioners. My name is James Rogers, I'm the 9 greater Kuparuk area development manager for 10 ConocoPhillips stationed here in Anchorage. I'm here 11 primarily to introduce the presentations that will 12 follow. For the record I may want to weigh in as an 13 expert witness. 14 CHAIR FOERSTER: All right. Then let's get 15 your credentials then we'll determine whether you can 16 be an expert. 17 MR. ROGERS: I'd like to weigh in as a 18 reservoir and production engineering expert. So my 19 qualifications are I have a bachelor's degree in 20 petroleum engineering and a master's in business 21 administration. I have over 33 years with 22 ConocoPhillips in areas of reservoir, production, 23 operations, facilities and completions. I've worked in 24 Alaska since 1999 so I have nearly 15 years working 25 Prudhoe Bay, Kuparuk and their respective satellite 5 1 fields associated with those main bodies. I've worked 2 both in town and up on the slope and I've been in my 3 current role for five and a half years. 4 CHF.IR FOERSTER: T here did yc i get degrees? 6 MR. ROGERS: At Louisiana Tech University in 7 Ruston, Louisiana. 8 CHAIR FOERSTER: Not an Aggie, that's good. 9 Just kidding. Commissioner Seamount, do you have any 10 questions or concerns? 11 COMMISSIONER SEAMOUNT: And your expert 12 discipline would be reservoir production..... 13 CHAIR FOERSTER: Engineering. 14 MR. ROGERS: Yes, sir. 15 COMMISSIONER SEAMOUNT: .....engineering? 16 MR. ROGERS: Yes, sir. 17 COMMISSIONER SEAMOUNT: Okay. I don't have any 18 objections. 19 CHAIR FOERSTER: Nor do I. We'll recognize you 20 as an expert. 21 MR. ROGERS: Okay. Thank you. Okay. We'll 22 begin the presentation. So slide two, the hearing 23 today arises from our request to amend West Sak's 24 conservation and area injection orders. On January 25 31st, 2014 ConocoPhillips Submitted documents to amend 31 1 conservation order 406B as in baker which establishes 2 the pool rules for West Sak and area injection order 2B 3 as in baler which governs injection into the West Sak 4 oil pool. The proposed amendments and supporting 5 material will be detailed in our following slides. 6 The first part of our application focuses on 7 the redefinition of the West Sak oil pool, but aerial 8 and vertical changes are recommended. The second part 9 seeks approval to inject enriched hydrocarbon gas into 10 the West Sak oil pool. The following presenters will 11 provide supporting evidence for these requests. 12 Presenters will provide details in support of the 13 application for the modification of the area injection 14 order including injection containment, wellbore 15 integrity of candidate and offset wells and benefits of 16 that enhanced oil recovery. 17 Slide three. The presentation begins with an 18 overview of West Sak's history and progression to 19 current day, followed by formation geology, the 20 Schrader Bluff N sands will be the focus of that 21 geologic discussion. The next section will review 22 current and proposed injection operations within the 23 West Sak oil pool, followed by a review of well 24 integrity, status and proposed rules. The results of 25 the recently completed viscosity reducing water 7 1 alternating gas pilot will then be presented. This 2 section provides the basis for discussing the benefit 3 of this process and the overall de-,,7elopment of the West Sa7�_ oil pooi. The p,-esentation ,:ill then f-, is'_7 :°its; 5 summary of the proposed amendments and suggested res. 6 The confidential materials submitted with the 7 application will not be shown here, unless there are 8 questions specifically regarding those materials the 9 presentation will cover only nonconfidential material. 10 So..... 11 CHAIR FOERSTER: It's probably appropriate at 12 this time for me to disclose the potential, I don't 13 know whether it's conflict of interest, but maybe you 14 want to weigh in on that, Commissioner Seamount, but 15 years ago I was part of some West Sak studies that were 16 kind of during the bear skins and stone knives era and 17 so some of West Sak's history involves me during our 18 less intelligent time. So it -- I may not be able to 19 bring myself up to the modern technology. No, I'm just 20 kidding. But I do have some West Sak history and some 21 of the people in the room have worked for me. So if no 22 one sees that as a conflict then I think we're good. 23 But, Dan, what do you think? 24 COMMISSIONER SEAMOUNT: I don't see any way 25 around it because it takes two to make a quorum. 1 CHAIR FOERSTER: Okay. COMMISSIONER SEAMOONT: So even if I 3 objected..... i'OERSTEK : But COIflMISSIONER. SE!--MIOUNT: . .. . .I couldzi't kick 6 you out of here. 7 CHAIR FOERSTER: Oh. All right. Then 8 whatever. Please proceed. 9 MR. ROGERS: Okay. Thank you. So unless there 10 are further questions we'll continue with the 11 presentation of Mark Jensen who'll provide the Vilest Sak 12 historical overview. 13 CHAIR FOERSTER: Mr. Jensen, are you going to 14 want to be recognized as an expert in any particular 15 area? 16 MR. JENSEN: Yes, production engineering. 17 18 CHAIR FOERSTER: Okay. Then give us your 19 credentials. 20 MR. JENSEN: All right. Again thank you, 21 Commissioners, for taking the time today to visit with 22 us. I graduated with a bachelor's of science in 23 chemical engineering from Bringham Young University in 24 April of 2010. I joined ConocoPhillips shortly after 25 my graduation and spent my first year rotating through 1 various development roles, including reservoir, 2 production and surface facilities engineering. I then 3 spent the better of a year supporting -capital project 4 execution as a process engineer before joining the 11,1est Salc team. I �aorhed as a drill site petroleum engineer 6 supporting the West Sak assets for the last two and a 7 half years. 8 CHAIR FOERSTER: Any questions? 9 COMMISSIONER SEAMOUNT: So you want to be 10 considered an expert witness in production engineering 11 or drilling engineering? 12 MR. JENSEN: Production. 13 COMMISSIONER SEAMOUNT: Okay. I don't have any 14 objection to that. 15 CHAIR FOERSTER: Okay. You said production or 16 did you say reservoir and production? 17 MR. JENSEN: I mentioned just production. 18 CHAIR FOERSTER: Oh, okay. I'm sorry, I 19 thought I heard both because I was listening and didn't 20 hear any reservoir in your resume. All right. I have 21 no objections to that either. Please proceed. 22 MR. JENSEN: Thank you. 23 MARK JENSEN 24 previously sworn, called as a witness on behalf of 25 ConocoPhillips Alaska, stated as follows on: 10 1 DIRECT EXAMINATION 2 So this is slide four and this section will provide the 3 historical context and a snapshot of our current operations. It provides the foundation to introduce 5 the proposed amendments that affect operations and 6 recovery in the West Sac. 7 This is slide five. The plot on the left was 8 provided as exhibit Bl in the submitted application. 9 This represents the West Sak core area or main 10 development within the West Sak oil pool. Development 11 in this area began in 1983 with a pilot operation at 1J 12 pad targeted at demonstrating the producibility of the 13 West Sak reservoir. And the pilot area is represented 14 as the darker red box with a label 1J. Nine vertical 15 producers and seven vertical injectors were drilled in 16 a inverted nine spot pattern, five -- on five acre 17 spacing. The results of this pilot demonstrated the 18 viability of waterflood recovery for West Sak oil, for 19 viscous oil. 20 Approximately one decade later the first phase 21 of the commercial development began at 1D pad. It's 22 highlighted at purple at the center of the plot at the 23 left of the slide. Again vertical injectors and 24 producers were drilled using sand exclusion completion 25 technologies. 11 1 The second phase of commercial development 2 occurred on 1B as in baker and 1C as in charlie pads 3 shown on the upper right of the plot in -Yellow. The 4 second phase of development incorporated horizontal 5 drilling technologies, dual lateral horizontal 6 producers were drilled and completed with large mesh, 7 stand alone screens and slotted liners with offset 8 vertical injectors. 9 The current development design uses dual and 10 trilateral producers offset by dual and trilateral 11 injectors. These wells types are shown here at lE or 1 12 echo pad and 1J, 1 julliette pad and also at 3K pad 13 which is not shown here. These developments are shown 14 both in green and red there. The producers were 15 completed with slotted liner where any sand production 16 is managed at the surface rather than excluded 17 downhole. 18 This is slide six. The objective of this slide 19 is to provide the audience with a history of enhanced 20 oil recovery projects at West Sak. The base plot on 21 the right is the same at that on the previous slide 22 where the red boxes represent the patterns involved in 23 a small scale, enhanced oil recovery project. Most of 24 those are in the northeastern corner of the plot shown. 25 The green boxes represent the patterns involved 12 1 in the drill site lE and drillsite 1,7 of your WAG pilot 2 project. The small scale enhanced oil recovery project 3 was sanctioned in 2003. The objectives were to establish ,cell integrity in the injectors, perform an 5 injectivity test and observe gas breakthrough between 6 injectors and offset catcher producer. The AOGCC 7 approved this project in July of 2003 and the project 8 achieved the first two objectives, but the third or gas 9 breakthrough test, was inconclusive. 10 Following the small scale FOR project lab work 11 in the form of multi contact experiments were conducted 12 to tune and validate the equation estate for West Sak 13 oil. In 2006 BP Exploration Alaska filed an amendment 14 application seeking approval to inject enriched 15 hydrocarbon gas into the Orion oil pool for enhanced 16 recovery purposes. The Commission did approve their 17 request later that same year. 18 Prior to field wide implementation 19 ConocoPhillips Alaska determined a large scale pilot 20 was needed to demonstrate operability and ultimately 21 quantify the benefit associated with the VRWAG process. 22 The West Sak drill site lE and drill site 1J, VRWAG 23 pilot project received AOGCC approval in 2009 and 24 operations began shortly thereafter. They continue 25 through the end of 2013 following two approved requests 13 I for extension. The pilot did achieve all objectives and precipitated this application. Additional details 3 regarding the „ilct �,1ill be ccveied in one of the late, ri`hTell. I�7e 1-1_ t. on the iic,ht 6 shows oil rate on the Y axis and date on the X axis. 7 You can see the increased rate -- increase in rate due 8 to the drill site lE and drill site 1J developments as 9 well as the recent dip in production from the single 10 casing workover program. West Sak production rates are 11 currently around 15,000 barrels of oil per day, 10,000 12 barrels of water per day and 8 million standard cubic 13 feet of gas per day. In terms of active wells in 14 service there are 54 producers and 55 injectors drilled 15 from six pad locations. All patterns are currently 16 under waterflood with a current water injection rate of 17 approximately 20,000 barrels of water per day. And 18 that water comes from the Kuparuk central processing 19 facilities and the seawater treatment plant. The 20 developed portions of the West Sak reservoir are 21 estimated to contain approximately 1.1 billion barrels 22 of oil in place with an ultimate recovery factor under 23 waterflood estimated at 15 percent of the original oil 24 in place. 25 Unless there are further questions I'd like to 14 • • 1 turn the presentation over to Mike Warner to discuss 2 geology. 3 CHAIR FOEPSTER: Okay. Thank_ you. Sure. Do )'ou havE any questions. 5 COMMISSIONER SEAMOUNT: Yeah. Could �,e go hack 6 to the first slide. 1983 to 1986 you have vertical 7 producers and vertical injectors. What were the rates 8 on these original producers? 9 MR. JENSEN: So the original -- so the -- 10 during the pilot the production ranged from anywhere 11 from 50 barrels a day to 200 barrels a day. 12 COMMISSIONER SEAMOUNT: And I believe the price 13 of oil was around $15 a barrel at that time. 14 MR. JENSEN: I wasn't alive then. 15 (Laughter) 16 COMMISSIONER SEAMOUNT: Okay. When did you 17 start doing the horizontal attempts then? 18 MR. JENSEN: The horizontal attempts came in 19 that second commercial phase so the 1B, 1 baker pad and 20 1 charlie pad. 21 COMMISSIONER SEAMOUNT: And what years were 22 those? 23 MR. JENSEN: That would be in the yellow and 24 highlighted on the third bullet point, the 2000 to 2004 25 time frame. 15 1 COMMISSIONER SEAMOUNT: And what was the 2 enhanced recovery methods at that time? 3 MR. JENSEN: So the small scale -- I'm going to 4 flip to the nest slide, slide six.. The small scale EOP, 5 project began in 2003 and so those were again 6 concentrated on the 1 baker and 1 charlie wells 7 highlighted there in the red boxes. 8 COMMISSIONER SEAMOUNT: And what were the rates 9 then? 10 MR. JENSEN: So they were a bit higher because 11 they were horizontal wells and I don't -- I don't know 12 the numbers exactly on those horizontal wells. I can 13 hazard a guess. Our horizontal wells typically land -- 14 I mean, when they -- when they come off of flush 15 production after initial, they range anywhere from 500 16 to 200 barrels a day. And these were shorter laterals 17 than those that were drilled at 1 echo and 1J pad, 18 about half of them. 19 COMMISSIONER SEAMOUNT: And presently what are 20 the rates on the horizontal wells? 21 MR. JENSEN: Presently on the 1 echo and 1J 22 drill sites, the longer horizonal wells, they range 23 from -- anywhere from 250 barrels a day all the way up 24 to 1,500 barrels a day. 25 CHAIR FOERSTER: And now you are -- wasn't 16 i paying much attention, you did -- you're doing water 2 alternating gas? 3 CHATR FOERSTER: Yeah, a few -spots. IP. JENSEN: Yeah. So on the -- on the four 5 patterns, and ,,,7e,ll cover this a little bit in the -- 6 in later slides we'll actually cover the results of the 7 pilot and reference the final report that we submitted 8 to the Commission. 9 COMMISSIONER SEAMOUNT: Okay. I'll be patient 10 then and wait. 11 MR. JENSEN: Okay. 12 COMMISSIONER SEAMOUNT: Thank you. 13 CHAIR FOERSTER: I have no questions for you at 14 this time, but I want to remind all of you that we may 15 call one or another back up for questions later and as 16 long as the hearing is in process then you are under 17 oath. If we take a recess you can go out back and lie 18 to each other all you want, but during the hearing 19 process you're under oath. 20 All right. Proceed. 21 MR. WARNER: Okay. Commissioners, I'm Michael 22 Warner, I'd like to be considered an expert witness or 23 geologist today. I'd like to give you a brief summary 24 of my background. I attended California State 25 University at Northridge where I received a bachelor's 17 1 of science in geology in 1976 and a master of science 2 degree in geology in 1979. I have 35 years of 3 petroleum industry experience. The first two years I 4 wor;:ed heavy oil pi-ojects for the Getty Oil Company in 5 Ba)_ersfield, California. Since 1981 I've been emplo-,ed 6 by ARCO Alaska and its successor, ConocoPhillips, 7 working a variety of Alaska development and exploration 8 projects. These include the start up of the Kuparuk, 9 Lizburne and West Sak oil fields and exploratory 10 drilling projects from the Brooks Range foothills to 11 the Beaufort Sea. Most relevant to my testimony is 12 that for 26 years of my time in Alaska I've been 13 directly involved in the West Sak and other viscous oil 14 projects including the West Sak pilot in 1983, West Sak 15 delineation in the mid 1980s and planning and drilling 16 of most of the West Sak development wells since 1997. 17 I provided the geologic testimony for the original West 18 Sak pool application in 1997 and was directly involved 19 in writing the original Kuparuk area injection order. 20 Based on these qualifications I would like to 21 be considered an expert witness in geology for this 22 hearing. 23 CHAIR FOERSTER: Any questions, Commissioner 24 Seamount. 25 COMMISSIONER SEAMOUNT: Yes. Mr. Warner, who In 1 did you work for in Bakersfield? 2 MR. WARNER: Getty, Getty Oil Company. 3 COMMISSIONER SEP.MOUNT: And. vahat year was that? 4 MR. i^IARNEP.: I started there in ' 79, I worked 5 '79 and '80 there. 6 COMMISSIONER SEAMOUNT: Oh, my goodness, I 7 worked for Chevron there in the seventies. So but by 8 definition you are an expert witness. We might have 9 been neighbors. 10 MR. WARNER: Yeah, I find that. 11 COMMISSIONER SEAMOUNT: Okay. I have no 12 objections. 13 CHAIR FOERSTER: Well, Mr. Warner, weren't you 14 also the co-author on an SBE paper about..... 15 MR. WARNER: Yes. 16 CHAIR FOERSTER: .....West Sak development? 17 MR. WARNER: Yes. 18 CHAIR FOERSTER: Back in the bear skins and 19 stone knives days. Right. I'm very familiar with your 20 work. We recognize you as an expert witness. 21 MR. WARNER: Thank you. 22 MICHAEL WARNER 23 previously sworn, called as a witness on behalf of 24 ConocoPhillips Alaska, stated as follows on: 25 DIRECT EXAMINATION III 1 MR. WARNER: All right. Slide nine is an 2 agenda for the geologic justification for the expansion 3 of the I%Iest Sak pool stratigraphy inter-jal in the 4 Kuparul_ Ri-jer unit. First I will describe our proposed 5 change to the iciest Sa}c pool stratigraphic interval, 6 then I will briefly review the West Sak reservoir 7 interval geology which is discussed in detail in the 8 original pool application. Finally I will describe in 9 detail the nature of the N sand interval in the Kuparuk_ 10 River unit and the bases for our proposal to now 11 include it in the West Sak pool. 12 As James Rogers had mentioned, confidential 13 material which were submitted with the application will 14 not be shown here. 15 Slide 10 corresponds with exhibit 1 in our 16 written application and shows the ARCO West Sak 1 type 17 log showing the current and proposed West Sak pool 18 stratigraphic limits. Here and on all subsequent log 19 displays each will have a gamma ray curve and a deep 20 resistivity curve. The gamma ray is shaded to show 21 relative amounts of clay volume computed from the logs. 22 Yellow represents sands and have computed V clays (ph) 23 generally less than 10 percent. The orange intervals 24 represent silty sands and siltstones and have computed 25 V clay from 10 to 19 percent and the gray intervals 20 1 represent non -reservoir mudstones and generally have V 2 clays of 20 percent or more. The iciest Sak pool �qas originally defined by rule two of conservation order rnmiber 406 at the strata 5 that are common to and correlate with the accumulation 6 found in Atlantic Richfield Company West Sak River 7 number 1 between the depths of 3,742 and 4,156. As 8 part of this application ConocoPhillips requests the 9 Commission to expand the West Sak pool definition to 10 include the overlying Schrader Bluff N sands. The 11 revised West Sak pool interval as shown would correlate 12 with interval found in the West Sak River State 1 13 between depths of 3,552 and 4,156, measured depth. 14 We will show that the expanded definition is 15 consistent with the Schrader Bluff pool rules of the 16 adjoining Milne Point, Prudhoe Bay and Nikaitchuq units 17 with the West Sak equivalent Schrader Bluff O sands and 18 the Schrader Bluff N sand intervals are both included 19 in each of these pools. This requested revision to the 20 original definition of the West Sak pool interval has 21 resulted in N sand development activity in these 22 adjoining units in conjunction with the results from 23 additional appraisal drilling in the eastern Kuparuk 24 River unit. These activities demonstrate the potential 25 to co -develop the N sands with the underlying West Sak. 21 1 And this proposed vertical expansion would facilitate 2 including the N sands in future West Sal_ developments 3 ,,here appropriate. 4 Slide 11 is the base map of the Kuparuk River 5 unit and the Pest Sal_ pool area. The map shop,,, the 6 Kuparuk River unit in red and adjoining units including 7 Prudhoe Bay, Milne Point and Nikaitchuq unit. The 8 current West Sak and Northeast West Sak participating 9 areas are outlined in yellow here. The proposed Incest 10 Sak pool limits are in green. Modifications to the 11 original pool boundary are minor and will be discussed 12 later. Current shallow well coverage used in mapping 13 are shown in blue. Mapping incorporates all wells with 14 shallow, open hole logs in the Kuparuk River unit and 15 representative wells from adjoining areas. Finally the 16 map highlights key wells in red in two representative 17 cross sections to be shown. The West Sak pool type 18 log, West Sak number 1, is shown at the intersection of 19 the two cross sections. In subsequent maps we'll focus 20 on the area outlined in the black dashed outline which 21 encompass the hydrocarbon bearing portions of the West 22 Sak and the Schrader N sand intervals in the Kuparuk 23 River unit. 24 Slide 12 is an overview of the west Sak 25 reservoir geology. The map here is the total West Sak 22 0 1 interval isochore, the interval map is shown on the 2 type log here highlighted in yellow. The extent of the 3 [,,est Sa}_ accumulation within the KRU is shown by the pul"pie cutline here and is truncated at the Southern 5 Kuparuk boundary. The Sa): name was named by 6 Jameson in 1980 and is correlated to the Schrader Bluff 7 formations in the Colville group. It's stratigraphic 8 equivalence is the Schrader Bluff O sands are 9 correlated across the Kuparuk River, Prudhoe, Milne and 10 the Nikaitchuq units and are late cretaceous in age. 11 Average gross reservoir interval thickness of the West 12 Sak sands in the Kuparuk area is 450 feet and range 13 from 350 feet in the northern -- northeast KRU to over 14 700 feet in the southeast. The West Sak is a 15 shallowing upward sequence of interbedded lower 16 shoreface sandstone and mudstone. The West Sak sands 17 are divisible into the upper most thicker D and B beds 18 and four lower intervals and thinner, interbedded sands 19 and mudstones, the A4, A3, A2 and Al. All reservoir 20 units have excellent continuity at current interval 21 spacing. Oil sands or oil bearing aggregate net pay 22 can reach 80 to 90 feet thick. The best quality 23 reservoir sands are fine grained, moderately well 24 sorted and consolidated. Cross views range from 25 to 25 35 percent and unstressed air permeabilities range from 23 1 200 to over 1,000 millidarcies. Lower quality 2 reservoir intervals are matrix supported silty sandstones. Porosity is still high, on the order of 20 to 30 percent, ho•��ever permeability is moderate to 1cr? 5 in the range of to to no millidarcies. Pegional 6 structure on the West Sak dips to the northeast between 7 one and two degrees and ranges from 1,300 feet in the 8 southwestern KRU to 420 feet -- 4,200 feet in the 9 eastern KRU. The West Sak is cut by both north/south 10 trending and east/west trending, normal faults. Both 11 fault sets are of similar age and postdate deposition 12 of the West Sak interval. Those typically are 20 to 30 13 feet, the maximum throw is 150 feet. Due to thin 14 interbedding and shale gouge faulted vertical 15 displacement as low as 20 feet can trap oil and segment 16 the reservoir into blocks of different oil/water 17 contact and different oil quality. West Sak oil is 18 characterized by varying degrees of biodegregation with 19 API gravity varying from 16 to 22 in the current 20 development areas in the deeper eastern Kuparuk River 21 area. Within these areas oil gravities vary vertically 22 and generally improve the height above oil/water 23 contact. Regionally oil gravity as low as 10 to 12 API 24 characterize the shallower western parts of the West 25 Sak in the Kuparuk River area. 24 1 Slide 13 begins our discussion of N sand 2 geology. This slide shows representative Schrader 3 Bluff interval well logs from KRU and adjoining units, 4 milne Point unit, Prudhoe Ba-Y and llikaitchuq unit. The 5 N sands are assigned to the Schrader Bluff formation of 6 the Colville group and based upon Conoco in-house 7 biostratigraphic data the Schrader N sands like the 8 West Sak are interpreted to be late cretaceous in age. 9 As shown the N sands in the Kuparuk area correlate to 10 stratigraphic equivalence in the Milne Point, Prudhoe 11 Bay and Nikaitchuq units for both the West Sak 12 equivalent Schrader O sands here and the N sand 13 interval are included in the Schrader Bluff pool 14 description. The N sand interval in the Kuparuk River 15 unit comprises a shallowing upward deltaic (ph) 16 sequence transitional from the underlying West Sak 17 marine facies to the overlying fluvial dominated (ph) 18 interval. Typical gross N sand normal thickness along 19 the eastern KRU in the Kuparuk River unit where the 20 interval is hydrocarbon bearing is approximately 180 21 feet. In the Kuparuk River area the N sand interval is 22 divided into four stratigraphic intervals from oldest 23 to youngest, these are the NF, the NC, the NB and the 24 NA. The basal NF and NC intervals are distal shoreface 25 or prodelta facies and are predominantly mudstone which 25 1 (indiscernible) upward into interbedded silt and fine 2 sand. These intervals range from 80 to 100 feet in 3 thickness and constitute the confining upper layer with 4 the underlying 1,2est Sak reservoir as described in the 5 original pool rules. The NB interval near the middle 6 of the N sand interval is dominated by sands deposited 7 in prograding, distributory channels and delta front 8 sheet sand environments. It is the predominant 9 hydrocarbon bearing portion of the Schrader Bluff N 10 sands in the eastern Kuparuk area where it typically 11 contains five to 30 feet of net sand. The upper most 12 NA interval is comprised of interdistributory mudstones 13 with some localized channel and overbank sands. In the 14 eastern Kuparuk area the NA interval is comprised 15 predominantly of 30 to 40 feet of mudstone and 16 siltstones and constitutes the confining layer for the 17 underlying NB reservoir. Additional confinement is 18 provided by the immediately overlying floodplain and 19 mudstones of the basal of NA interval (ph). 20 Slide 14 is a total N interval isopach map and 21 corresponds to exhibit 2 in our written application. 22 The mapped interval is highlighted in yellow on the 23 West Sak 1 type logs, this interval here. As shown the 24 Schrader Bluff N sand interval can be mapped across the 25 Kuparuk River unit area and thickens regionally to over 26 1 300 feet in the southwest KRU. However known 2 hydrocarbons are restricted to the eastern side of the 3 K.uparu). area as outlined with the purple here, where 4 gross I� sand inter-.7a1 thickness is about 1-80 feet. i!,e 5 will no%"' lool_ at the following correlation sections, A 6 to A prime and B to B prime, which will illustrate 7 Schrader Bluff N sand depositional strike along A to A 8 prime and N sand depositional dip along B to B prime. 9 Slide 15 is stratigraphic section A to A prime 10 and corresponds to a portion of exhibit 3 from our 11 written application. Trending from northwest to 12 southeast this section is a long interpreted N sand 13 depositional strike and characterized by fair to good 14 lateral sand continuity. The section illustrates the 15 persistence of net sand development in the NB along 16 depositional strike in the eastern KRU. As seen here 17 NB net sand ranges from five to 30 feet. This section 18 also shows a good lateral extent of the NCNF and the NA 19 confining mudstones for the West Sak and NB sands 20 respectively. There are limited N sand corrugate in 21 the Kuparuk River unit. Wells with corners shown with 22 red dots in either the Ugnu Swept number 1 and in the 23 West Sak pilot area of the West Sak pilot 24 (indiscernible). Corrugated from the NV shows the 25 interval consists of unconsolidated, massive bedded, 27 1 very fine to medium grain, moderately to well sorted 2 sand. Processes range from 30 to 37 percent with 3 permeabilities ranging up to several darcies. Permeabilit.ies of the bounding mudstones are typically 5 only several millidarcies. wells with interpreted 6 hydrocarbons in the N sands along this section are 7 shown with green starts. Despite the good continuity 8 of sand prone facies along this trend hydrocarbon 9 distribution is complex and has both structural and 10 stratigraphic controls. 11 Slide 16 is stratigraphic section B to B prime 12 from southwest to northeast and corresponds to a 13 portion of exhibit 4 from our written application. 14 This section is parallel to depositional dip and 15 characterized by a greater amount of change in the 16 depositional facies for more fluvial dominated motif 17 (ph) in the southwest KRU to more deltaic and shallow 18 marine character. This section illustrates a general 19 increase in total net sand thickness to about 70 feet 20 in the NB and NA intervals in the western KRU where the 21 facies are interpreted to be more fluvial dominated. 22 However in the east where the NB is hydrocarbon 23 bearing, NB sand and net pay ranges to only 30 feet and 24 the NA is predominantly mudstone. Wells with 25 hydrocarbon occurrence in the N sand are again flagged MM 0 9 1 with the green star here, they're limited to the 2 eastern end of the cross section. NB oil quality in 3 the eastern KRU ranges from 10.8 to 13.2 API. This is 9 generally lover than the P7est Sal=_ in the eastern KRU, 5 but is generally better than the Ugnu in the same 6 areas. 7 Slide 17 is my final slide and shows two wells 8 in the eastern Kuparuk River area and one from the 9 adjoining Prudhoe Bay area. To further illustrate the 10 geologic similarities to the reservoirs and confining 11 intervals in these adjacent pools. In the previous 12 slide we discussed the nature and continuity of the 13 Schrader N sand reservoir and confining layers. Both 14 the West Sak and the Schrader Bluff NB are immediately 15 overlaid by sequences of prodelta or lower delta plain 16 mudstones which in aggregate provide a regional seal 17 and an effective confining zone above the hydrocarbon 18 bearing portions of the reservoir. In the following 19 section on West Sak operations we'll discuss rocks main 20 characterization of the shallow interval from both 21 sonic log calculations and operational experience from 22 formation integrity tests. These data show these 23 mudstones will act as vertical confining layers at our 24 proposed waterflood and VRWAG injection gradient. The 25 Schrader Bluff N sands are cut by the same fault sets 29 I which provide lateral seals in underlying West Sak 2 accumulation. It is observed these faults contribute 3 significantly to observed variation in the lateral distribution of hydrocarbon content and oil =.;later ccntact in the N sand interval. In our Plest Sal- 6 experience there is no evidence of transmissive faults 7 in the West Sak, there have been no instances in West 8 Sak development drilling of fluid lost when crossing 9 faults or evidence of injected fluids moving along 10 faults or fault zones. As a result it's felt that 11 faults do not represent a major containment risk in the 12 N sands. 13 At this point I'll conclude the geologic 14 justification for extending the West Sak pool 15 stratigraphic interval to include the Schrader Bluff N 16 sands. I hope I've demonstrated that the N sand 17 reservoir and confining intervals are comparable to 18 those in the adjacent pools where the N sands are 19 included with the underlying West Sak equivalent 0 20 sands in the pool interval descriptions. In these 21 adjacent pools there's ongoing co -development of the N 22 and O sand and we see the same opportunity to pursue N 23 sand development with the West Sak in the eastern 24 Kuparuk River unit. 25 This concludes my testimony and unless there 30 1 are any questions I'll now turn it back over to Mark 2 Jensen who will discuss West Sak operations. 3 CHF,IR FOER.STER: Commissioner Seamount, do you 4 have any questions? 5 C01,111ISSIOIQER SE1-I,90U1,ZT: Yes, I ha e a lot. of 6 questions, but I'm wondering -- they probably include a 7 lot of reservoir engineering questions and I assume 8 they'll be a lot of reservoir engineering testimony 9 coming up later. One question, I guess sort of a 10 leading question coming up would be what's the 11 temperature -- what's the reservoir temperature of this 12 zone? 13 MR. WARNER: In the eastern KRU it's around 70 14 degrees. 15 COMMISSIONER SEAMOUNT: Seventy degrees. 16 MR. WARNER: Yes, uh-huh. 17 COMMISSIONER SEAMOUNT: And, you know, I'm sure 18 you're -- coming from Bakersfield, you know, the API 19 gravity of a lot of the oil out there can be below zero 20 and the API gravity here you talked about is around 12, 21 some of this stuff and probably it flows about the same 22 as the -- as the zero API gravity of the Bakersfield 23 oil, is that correct? 24 MR. WARNER: Viscosities here -- the measured 25 viscosities are around 2,300 centipoise where we do 31 1 have one sample. And we have not flow tested the N 2 sand in Kuparuk unit, but we believe it will be amenable to waterflood or something like VRV2F,G. 3 COMMISSIONEF. SE210,40UNT : 01:ay. . I ' m going to - - 5 I'll probably asl_ some ignorant questions later on 6 regarding the steam..... 7 MR. WARNER: Yeah. 8 COMMISSIONER SEAMOUNT: .....but the other 9 thing is you've shown a lot of maps and you've talked a 10 lot about faults and I haven't seen any faults on any 11 of the maps. 12 MR. WARNER: Uh-huh. 13 COMMISSIONER SEAMOUNT: And I'm just wondering 14 how the faults affect the production out here and I'm 15 wondering, you know, when you have these long laterals 16 what do the faults do to the production, what do the 17 faults do to the drilling out there, do you have 18 problems, you know, finding the reservoir once you 19 cross a fault? 20 MR. WARNER: I would say no. We cross quite a 21 few faults in the West Sak development. Some of the 22 West Sak pattern maps you'll see will have the fault 23 patterns on them so you'll be able to see where the 24 wells have cross faults. And we've successfully 25 crossed 90 foot faults in the 3K area and reacquired 32 1 the sand while drilling without a problem. No drilling 2 problems crossing the faults and no real geosteering 3 (ph) problems reacquiring the sands on the other side. 4 �Lr,d no e,ridence of -- as 1 mentioned here no evidence 5 of fluid loss associated %%ith the faults ,ahile drilling 6 and to date no apparent problems with the fluid loss or 7 injectivity along the fault. So they do 8 compartmentalize the faults, but the wells themselves 9 do not see the faults in their performance. 10 COMMISSIONER SEAMOUNT: So you consider this 11 one continuous pool and not hundreds of pools that are 12 defined by hundreds of fault blocks? 13 MR. WARNER: There are different oil/water 14 contacts within the pool and in the accumulation and 15 each sand is vertically isolated so there is changes in 16 gravities and fluid contacts, but it's -- it represents 17 one charge event geologically and in that regard it's 18 treated as a single accumulation. 19 COMMISSIONER SEAMOUNT: Okay. That's all I 20 have for now. Thank you. 21 MR. WARNER: Uh-huh. 22 CHAIR FOERSTER: Mr. Warner, because I know 23 your history so well I'm not going to constrain myself 24 to geology questions, but you're welcome to call a 25 friend or use a lifeline if you choose to or tell me 33 1 that the question will be answered later and that'll be 2 fine too. But my first one Commissioner Seamount kind 3 of teed up for me, if everything that you're looking at is ene charge event then �,,,-hat's the difference bets -seen 5 i4est Sad- and Schrader Bluff and Ni]taitchuq and Orion or 6 why are they all different pools, are they not one 7 charge event? 8 MR. WARNER: I want to think about the answer 9 to that question. 10 CHAIR FOERSTER: Okay. I certainly can respect 11 that. And I suspect that ownership boundaries had a 12 large..... 13 MR. WARNER: Uh-huh. 14 CHAIR FOERSTER: .....geologic contribution to 15 those separate pools which would lead to my second 16 question. You know, I would like an answer from you on 17 that if -- you know, if you feel like you've got one. 18 But my second question would be and maybe I should ask 19 my own staff this, but to the extent that you know, are 20 there differences in the pool rules among those 21 different variations of the same flavor and to the 22 extent that you know do you know why, are the West Sak 23 pool rules different from the Milne Point, Schrader 24 Bluff pool rules and et cetera? And I..... 25 MR. WARNER: We'd have to regroup on that one 34 1 too. 2 CHAIR FOERSTER.: Okay. But they're little 3 ones. And that's something I can ask my ov,7n staff to chec]-_ into, but I thought if you i_neW that it •,.:ou3ci t)e 5 interesting for the sale of this discussion. 6 The -- you know, very simplistically when you 7 look at your slide there's a lot more yellow in the N 8 than there is in the A, B, C, D. Why has ARCO/Conoco 9 not pursued the N before? 10 MR. WARNER: We've really become more 11 interested in it as we've seen some success with other 12 offset operators and then in our appraisal in the 13 eastern news area that series of wells encountered 14 better sand development and better quality oil than we 15 had seen to date and kind of represents our most near 16 term target probably for pursuing the N sand. 17 CHAIR FOERSTER: Okay. 18 MR. WARNER: So they're learning. 19 CHAIR FOERSTER: And then can we go back to 20 slide either 11 or 12, whichever one might answer the 21 question, does either one of these slides show the -- 22 where you hope to extend the aerial extent of the West 23 Sak reservoir? 24 MR. WARNER: Most of the -- I think you'll see 25 that the changes in boundary are along the kind of 35 1 political boundaries of the -- to be changed along the 2 northern boundary of the Nikaitchuq, but their pool 3 covers part of it and there's another minor change 4 along I thin]c it's either Prudhoe or Milne portion of 5 Prudhoe so. 6 CHAIR FOERSTER: So you're..... 7 MR. WARNER: Those will be shown later, yes. 8 CHAIR FOERSTER: So there would be expansions 9 of the West Sak pool in..... 10 MR. WARNER: They are really contractions, I 11 think. 12 CHAIR FOERSTER: Oh, they're contract -- you're 13 not -- I thought you were expanding the aerial extent a 14 little bit? 15 MR. JENSEN: So there's both and we'll cover it 16 kind of at the end..... 17 CHAIR FOERSTER: You will. 18 MR. JENSEN: .....we're contracting in the 19 Nikaitchuq portion and then there's a portion on the 20 eastern extent I can point out here where the KRU 21 boundary shifted one block and so it's capturing that 22 into the area injection order so we now marry up the 23 boundaries. 24 CHAIR FOERSTER: What do you mean marry up? 25 MR. JENSEN: Can we hold the question until I 36 L� I get to it..... I CHAIR FOEP.STER: Sure. Okay. That's..... rf �; U?AIDE?'dTIF'I_D C`I�.F : ..... � t' � .1 1-De rnuCh cl ea_ er =r, I ct�c c y. CHIP FOERS T ER . _ ha f c- . ! i a.t 6 perfectly acceptable answer to me. All right. Those 7 were my questions for right now, but as I said before 8 we may want -- we go a geologist in the room and he may 9 have questions for you later. 10 Okay. And we're back to you..... 11 MR. JENSEN: Yes. 12 CHAIR FOERSTER: .....Mr. Jensen? 13 MR. JENSEN: All right. This is slide 18 and 14 again thank you, Mike, for the geology portion. 15 This section will cover the proposed injection 16 operations as outlined in the application and then 17 following this section we'll tie it in and we'll 18 discuss the well integrity portion. So this focuses 19 more on the operational aspects. 20 This is slide 19, current injection operations 21 at West Sak focus on mitigating injection risks. Each 22 injector has a well specific maximum surface injection 23 pressure value per -- visible and alarmed in the 24 surface control and data acquisition system. Pad 25 operators are trained to manage injection, to conform 37 1 to the maximum wellhead injection pressure. Also real 2 time monitoring is in place or outer annulus pressure 3 on all i<uparuj<_ wellbores that traverse vaithin one - of anr_1 _ ( .UCi11iC. E_'l ES1_a.nce c nd �laintenanc Gf each ::'ell c'2 6 specified in the ConocoPhillips well operating 7 guidelines ensures compliance with all state regulator 8 requirements and ConocoPhillips' best practices. These 9 steps mitigate the risk_ of injecting out of the 10 intended zone and are an important part of minimizing 11 matrix bypass of information. No abnormal pressures 12 were observed during the pilot West Sak injection 13 operations. The management practices outlined will be 14 maintained in all future operations. 15 All right. Slide -- this is slide 20. It's a 16 little busy, but it provides some context and it's 17 important for the discussion on the next slide. What 18 you see here is log derived stresses plotted on the X 19 axis versus true vertical depth in feet on the Y axis. 20 The solid colored lines, so the blue, the red and the 21 green reflect the log derived minimum horizontal stress 22 values calculated for three West Sak wells. The 23 triangles represent well leak off tests within this 24 zone. The dashed lines represent the trend lines of 25 the calculated stress or fracture gradients which are a 0 1 function of clay volume. The lowest gradient at 0.579 2 psi per foot is for clean sands and shaley sands ha:re a C]"a d1E Ti i_ of 0 . 63 ::finds T11CCe a,-e highl_lght ed O'_7 the lc: d .-__ic:,i a it `,i 1i 1111'u1 tre I6 cf CJ . 8. psi per foct.. I';i1 CI ad Filn thG^.c 6 are highlighted on the slide in the blue dash lines. 7 The brackets highlight the proposed West Sak intervals. 8 The left most bracket highlights the interval for the 9 1V wells which are shown in blue and red and the other 10 highlights the interval for the 1H north well shown in 11 green. You can see those brackets. The key take away 12 from this slide is the shale or overburden fracture 13 gradient trends highlighted by the dashed lines. They 14 provide evidence for a maximum injection gradient limit 15 to maintain injection into the zone of interest. 16 So this is slide 21. And so with that context 17 then from the previous slide we can discuss the 18 proposed injection operations in the West Sak oil pool. 19 The table on the top left of this slide contains the 20 estimates for the expected bottom hole and wellhead 21 pressures on water and gas injection service. The 22 average values in the left columns are based on current 23 operational practices at a true vertical depth of 3,500 24 feet. The expect maximum injection gradient of 0.8 psi 25 per foot defines the maximum pressures and is below the M, 0 1 overburden gradient trend illustrated on the previous slide. The maximum and minimum bounds of the ranges 3 in th_os(- rwo columns are calculated using the 4-h � '`le ai-d L:__ r' icn acz_;ss the Ea!; C"11 pool. 6 injection consists of produced water and sea water and 7 the amendment application proposed the addition of 8 enriched gas as a normal injection fluid. The enriched 9 gas will consist of a blend of. Kuparuk lean gas and 10 indigenous and/or imported NGLs. From the previous 11. modeling -- from the modeling results that will be 12 shown in a later section we anticipate a peak gas 13 injection rate between 15 and 25 million standard cubic 14 feet per day for the developed or the core area. 15 Future wells converted to VRWAG service will require an 16 additional two to 6 million standard cubic feet per day 17 per well. Operational data to dates suggests there are 18 no fluid compatibility problems and ultimately this 19 part of the application proposes the operational 20 practices going forward which govern injection into the 21 West Sak oil pool. 22 Slide 22 lists all surface owners and operators 23 within one -quarter mile of the proposed injection 24 operations within the West Sak oil pool. Copies of the 25 nonconfidential portion of the application were .O 1 provided to these entities. 2 This is slide 23 and this will be my final 3 slide for this section. It outlines two of the other required portions of the application; related to 5 injection operation. Produced .,rater and sea vaater 6 analyses were submitted with previous application 7 packages and an analysis of West Sak konig water (ph) 8 was provided with this application as exhibit Ll. Also 9 all aquifers or portions of aquifers lying below and 10 within one -quarter mile of the Kuparuk River unit are 11 exempted aquifers. 12 And that concludes my section so unless there's 13 questions I'll turn it over to Ti. 14 CHAIR FOERSTER: Commissioner Seamount, do you 15 have questions for Mr. Jensen? 16 COMMISSIONER SEAMOUNT: I think I do, Chair 17 Foerster, but I think this is your expertise and I 18 would request that you go first. 19 CHAIR FOERSTER: Well, I think you're very 20 generous thinking I have any expertise, but I will go 21 first. 22 COMMISSIONER SEAMOUNT: Because what 1 tninK i 23 heard is very intriguing. 24 CHAIR FOERSTER: Okay. My questions are pretty 25 simple. On slide 22 you listed several operators and 41 0 1 you -- and the slide says that copies were provided to 2 all of them. Did you get any inquiry or interest or 3 pushhac}; from any of the operators that..... 4 I,1F. JEIISEN: None that I've seen so far. 5 CHE_IF FOERSTER: Okay. vnd :,could your 6 proposals have any impact on any of these other 7 operators to the best of your knowledge? 8 MR. JENSEN: No, not to my knowledge. 9 CHAIR FOERSTER: Okay. In other exchanges 10 between Conoco and the AOGCC a Conoco employee has 11 stated that Conoco's best practices are impeded by 12 state regulations and that if it weren't for our 13 regulations that Conoco would be doing just fine. And 14 I'm wondering if in any way -- yeah, I took that very 15 unfavorably, but I'm wondering if there's anything like 16 that that is a concern to you guys right now and if 17 there is have you address -- attempted to address it in 18 recommended changes to your pool rules? 19 MR. JENSEN: I guess I can't speak to other 20 ConocoPhillips' employees, but as we have -- as we have 21 completed the work and reviewed West Sak and what 22 pertains to this injection order, we have not -- no 23 AOGCC regulation has impeded in the formation of the 24 plans going forward. 25 CHAIR FOERSTER: Okay. Because I do want you M 0 1 to recognize that the pool rules is the place to 2 address differences between our regulations and 3 improved operating practices and to come in before us during a time of enforcement action and _ it' got 5 our fault that ee did something it's just that 6 your regulations aren't good is not acceptable. And so 7 this is your chance. 8 MR. JENSEN: So I guess maybe a broader 9 response. Let me regroup with my colleagues and then 10 we can address. 11 CHAIR FOERSTER: Okay. Well, yeah, if you feel 12 that there's another response that's warranted later 13 I'd be happy to take that at anytime. But I did want 14 to just let you know if you need to do something 15 differently then you need to get it approved in the 16 pool rules, not just decide to do it and then use us -- 17 you know, use the we're better than you are as an 18 excuse for not following regulations. Okay. 19 MR. JENSEN: Thank you for that, yes, and we'll 20 make sure to address that. 21 CHAIR FOERSTER: Okay. That was it for me. So 22 it wasn't very -- there was nothing insightful or 23 expert about my questions so I'm going to defer back to 24 you, Commissioner Seamount. 25 COMMISSIONER SEAMOUNT: On slide 21 you have 43 1 estimated gas injection rates. 2 MR. JENSEN: So these are estimated -- yes, so 3 the gas injection rates for both the core area so the 4 developed portions which are existing wells and then 5 additional ;-!ells that may be added later. 6 COMMISSIONER SEPIAOUNT: Fifteen to 25 million 7 cubic feet per day peak for the core area and that's 8 for all the wells? 9 MR. JENSEN: This will be better detailed in 10 the reservoir portion where we cover the modeling 11 results, but..... 12 COMMISSIONER SEAMOUNT: Okay. 13 MR. JENSEN: .....as part of the application 14 we're asking that 10 wells initially be considered for 15 long term service and so that peak rate is for those 10 16 wells that were included in the application. 17 COMMISSIONER SEAMOUNT: Okay. So then I will 18 wait until we get to that section then. That's all I 19 have then. 20 CHAIR FOERSTER: Okay. Thank you. 21 COMMISSIONER SEAMOUNT: Thank you. 22 CHAIR FOERSTER: All right. Thank you, Mr. 23 Jensen. 24 MR. SENDENT: Thank you, Mark, and good 25 morning, Commissioners. For the purpose of this 1 hearing I would like to be considered an expert witness 2 in integrity. CHTP 7CEPS7FR: end f ci t l c the su, 6 CHAIR FOERSTER: .....proceed. 7 MR. SENDENT: My name is Ti Sendent, I'm the 8 well integrity director for ConocoPhillips Alaska. 9 CHAIR FOERSTER: Okay. 10 MR. SENDENT: I'm a 1995 graduate with a BS in 11 civil engineering from the University of Alaska 12 Fairbanks. I have 18 years of engineering experience 13 mostly on the North Slope oil fields including the past 14 10 years working in a drilling and wells organization. 15 At this time I would like to be considered an expert 16 witness in well integrity. 17 CHAIR FOERSTER: Commissioner Seamount, do you 18 have any questions for Mr. Sendent. 19 COMMISSIONER SEAMOUNT: Where was your 20 schooling, Mr. Sendent? 21 MR. SENDENT: University of Alaska Fairbanks. 22 COMMISSIONER SEAMOUNT: Okay. And your expert 23 witness -- your expert designation would be in civil 24 engineering? 25 MR. SENDENT: That was my degree. I would like 45 0 1 to be considered an expert in well integrity. 2 COMMISSIONER SEAMOUNT: Okay. That would be 3 fine with me. CHAIR FOERSTER: I have no questions for you, 5 Mn:. Sendent. i,de'11 recognize you as an expert and you 6 may proceed. 7 MR. SENDENT: Thank you. 8 TI SENDENT 9 previously sworn, called as a witness on behalf of 10 ConocoPhillips Alaska, stated as follows on: 11 DIRECT EXAMINATION 12 MR. SENDENT: One critical aspect of the VRWAG 13 project..... 14 CHAIR FOERSTER: Mr. Sendent, introduce each 15 slide as you start to talk about it. 16 MR. SENDENT: I'm sorry. Slide 25. 17 CHAIR FOERSTER: Don't want to interrupt you 18 again. 19 MR. SENDENT: Slide 25. One critical aspect of 20 the VRWAG project is wellbore confinement. Detailed 21 evaluation was conducted for all wells within one- 22 quarter mile radius of each VRWAG injection well. A 23 confinement evaluation included the following. The 24 review included all wells within a quarter mile radius 25 and those were West Sak Wells, Kuparuk wells and all 46 1 exploration wells. The confinement evaluation included 2 a review of initial cement placement based on visual 3 ri.g operations, cement top estimation )c s- d c,_. r c ash.ot_t -Toll:Iles, -e:= to,,- the ertyL 6 that had bond logs and any mechanical evaluation of the 7 wells confirming tubing, casing and packer integrity. 8 All strings of casing and production tubing will be 9 pressure tested as required and there will be no 10 packerless ESP producers or single casing injectors 11 completed within one -quarter mile radius. Additionally 12 all Kuparuk wells within the one -quarter mile radius 13 will have automated pressure monitoring gauges 14 installed on the outer annular as Mark mentioned 15 before. This same confinement evaluation was completed 16 on the pilot project wells prior to the VR injection on 17 those wells. The pilot VRWAG injection was completed 18 without any containment or well integrity issues on any 19 of the injection wells or offset wells. 20 Slide 26. Per regulation 20 AAC 25.412 all VR 21 injection wells have been constructed with competent 22 tubing, casing and packer integrity that isolates 23 pressure and fluid to the injected interval. Each VR 24 injector has surface casing string, any single casing 25 injector wells will not be permitted without first 47 0 1 requiring a remedial workover. And each injector has 2 production casinos cemented through the production zone in accordance -,<ith regulations 20 AF,C 25.412 and 20 PAC edlllee l_ o _ rl"1aU .l '11- J-%e Je v' L� JJF 6 monitored at least weekly per area injection order 2B. 7 All of the proposed injection wells have met the 8 minimum requirements for injection, i.e., bond logs, 9 waterflow logs, to demonstrate isolation from the 10 injected fluids and all the proposed wells have been on 11 water service. The wells have all passed initial four 12 year MIT IAs, inner annulus, per area injection order 13 2B. We propose that for existing injection wells that 14 may be recompleted for the new N sand that we will 15 submit a 10403 application prior to the recompletion 16 followed up by a 10404 after the work has been 17 completed. For all existing injection wells, 18 production wells converted to injection or newly 19 drilled wells the permitting will be handled in 20 accordance with rule three of the existing area 21 injection order and will follow all AOGCC permit 22 process. This keeps the process consistent with AOGCC 23 requirements and all existing WAG injection wells. 24 Slide 27. Production wells within a VRWAG 25 pattern have also all been reviewed to confirm that all 48 1 have competent packers, casings have all been cemented 2 per regulation and all annuli will be in a condition to 3 facilitate pressure monitoring. All future injection ,4 cells and offset producers 7.iill undergo the same 5 evaluation as pre-.7iously mentioned and may require 6 offset producer workovers prior to VR injection. And 7 all Kuparuk and West Sak producers located with in the 8 quarter -mile radius of the VRWAG injector will again be 9 automated with the real time pressure monitoring on the 10 OA. 11 Slide 28. The plot on the right is the West 12 Sak core area. The West Sak participating area extents 13 are marked in light blue. The long, hashed ovals 14 represent a quarter -mile radius around the blue 15 injection wells and green lines indicate the production 16 wells. The very short purple wells or purple lines 17 indicate portions of Kuparuk wells that are located 18 within the West Sak oil pool. Currently there are 10 19 wells proposed for long term VRWAG injection. The 20 three pilot wells are the blue dots. There are seven 21 wells ready for VRWAG service at this time and those 22 are shown as the green dots. And all of these wells 23 and their details were listed in the application in 24 exhibits 0-1 and also all 10 of these wells were used 25 in the simulation and estimation of the incremental 1 rate. There are additional VRWAG injection well 2 candidates located in the West Sak core area for 3 consideration after offset producers have rig workovers 4 to ii,stall production packers or second casing strings. 5 And those are shown by the yelloV. circles. Injectors 6 chosen for VRWAG injection are existing West Sak_ 7 injectors at this time it is not anticipated that there 8 will be any conversions from producers to VRWAG 9 injection and any new injection wells will be permitted 10 and designed as potential VRWAG injectors. 11 Unless there are any questions I will turn the 12 presentation over to Scott Redman. 13 CHAIR FOERSTER: Commissioner Seamount, do you 14 have any questions? 15 COMMISSIONER SEAMOUNT: I do not. 16 CHAIR FOERSTER: Okay. I do. Let's go back to 17 slide 26. And you said that injection wells 18 recompleted in the N sand will require 403, but all 19 other wells will not. Okay. So which wells are you 20 going to complete -- recomplete into the N sand, do you 21 know at this time? 22 MR. SENDENT: We've not identified any. 23 CHAIR FOERSTER: Okay. And so for the other 24 wells that -- if there's no recompletion, but just a 25 conversion from waterflood to WAG then we'll -- you'll 50 • 1 use rule three, is that what you said? 2 MR. SENDENT: 404. 3 CHAIR FOERSTER: Vdhat? 4 MR. SENDENT: If there's an existing injector 5 permitting fcr ,ater injection just_ use the 404 6 process. 7 CHAIR FOERSTER: Right. 8 MR. SENDENT: Yes. 9 CHAIR FOERSTER: Okay. That's -- I just wanted 10 to make sure I understood you properly. Okay. Thank 11 you. I have no further questions for you at this time. 12 Introduce yourself for the record and then I'm 13 sure you want to be a reservoir engineer expert so let 14 us have your qualifications. 15 MR. REDMAN: Okay. My name is Scott Redman, 16 I'm a greater Kuparuk reservoir engineer for 17 ConocoPhillips stationed in Anchorage. I graduated 18 with a bachelor's degree in civil engineering from 19 Oregon State University in 1983. I have 30 years of 20 engineering experience working on North Slope oil 21 fields and 10 years working on the West Sak oil field. 22 I'd like to be considered an expert witness in 23 reservoir engineering for this hearing. 24 CHAIR FOERSTER: Commissioner Seamount, do you 25 have any questions for Mr. Redman? 51 • • 1 COMMISSIONER SEAMOUNT: I have no questions and 2 no objections. 3 CHAIR FOERSTER : Nor do 1, �,:e ' re real-],," o.._, ar� j-cu _ picce'ed. 6 MR. REDI✓LAN : Okay. Thank_ you. 7 CHAIR FOERSTER: And remember to identify your 8 slides. 9 MR. REDMAN: Okay. 10 SCOTT REDMAN 11 previously sworn, called as a witness on behalf of 12 ConocoPhillips Alaska, stated as follows on: 13 DIRECT EXAMINATION 14 MR. REDMAN: Slide 29. The next several slides 15 will review the viscosity reducing water alternating 16 gas mechanism, initial lab studies and the conclusion 17 of the final report submitted to the Commission at the 18 end of the VRWAG pilot project. After the VRWAG pilot 19 slides I will cover the hydrocarbon recovery for the N 20 sand which is the proposed vertical expansion of the 21 West Sak oil pool. 22 Slide 30 compares miscible gas and viscosity 23 reducing gas recovery processes. Plot A shows the 24 distribution of hydrocarbon components in a low 25 viscosity oil, plot B shows a slim tube lab experiment 52 1 that determines the minimum miscibility pressure and 2 plot C shows a one dimensional displacement �,,ith 3 miscible qas. Plots A, B and C depict the mechanism c t_.-c�aeGt P1lld1a0 Bay- Pi-Ct J sh tJiE. <z1 S� 11;ll -On 6 of hydrocarbon components in a medium viscosity oil, 7 plot E shows a slim tube experiment with the minimum 8 miscibility pressure much higher than the reservoir 9 pressure and plot F shows a one dimensional 10 displacement of oil with viscosity reducing gas 11 injection. Plots D, E and F depict the mechanisms 12 involved in the viscosity reducing mechanism. The low 13 viscosity oil in plot A has more intermediate 14 hydrocarbon components that can interact with the gas 15 to achieve miscibility at reservoir pressure than the 16 medium viscosity oil in plot B. The miscible 17 displacement process can drive oil saturations down to 18 very low residual oil saturations. The medium 19 viscosity oil on the right has less intermediate 20 hydrocarbon components available to interact with gas 21 injection. The pressure required to achieve 22 miscibility is significantly above the reservoir 23 pressure. The viscosity reducing process condenses 24 enriched gas hydrocarbons into the oil to improve its 25 oil properties, the oil viscosity's reduced and the oil 53 1 volume is swelled. The viscosity reducing process 2 enhances the •,,I-aterflood by mal=ing it easier to move the 01i 2,._T)6 _ i lec'.'ES less E fable oil behind In the 1 and lF'b used 6 to justify the piloting of the process. These 7 plots were submitted as exhibits L1 and L2 in the 8 original pilot application. The plots on -- the plot 9 on slide 31 shows oil viscosity results of a multi 10 contact experiment conducted in the lab. The oil 11 viscosity is plotted versus a number of gas contacts. 12 The blue squares, purple triangles and red diamonds are 13 actual data. This includes two experiments run on West 14 Sak solution gas and one experiment run on viscosity 15 reductant injectant which is a mixture of Kuparuk blend 16 gas and 50 barrels per million standard (ph) cubic feet 17 of indigenous NGLs. The anomalous behavior on the 18 first contact of the West Sak solution gas experiments 19 is suspected to be precipitation of asphaltenes that 20 then went back into solution on the second gas contact. 21 As shown even the West Sak solution gas can improve oil 22 viscosities. The greater the enrichment of the 23 viscosity reducing injectant has a greater -- 24 progressively greater impact on viscosity reduction. 25 The lines of the plot are calculated using the West Sak 54 0 • 1 equation of state. There are six gas injection 2 compositions that are shown including methane shov,-n in 3 the green Line, iwest sal- so]utzon gas shown, i_n the pink r n the :-._t;"i L1a.i";CI_eS, ,_S(_U..it-..r �eUUC'1l9 -JeCt oil 6 barrels per million standard cubic feet of indigenous 7 NGLs shown in the red line, viscosity reducing 8 injection with 100 barrels per million of indigenous 9 NGLs shown in the blue line and Kuparuk MI blend with 10 150 barrels per million of Prudhoe and indigenous NGLs 11 shown in the blue line with diamonds. Injecting 12 methane actually slightly increased the viscosity while 13 the remaining compositions decreased the oil viscosity. 14 Slide 32 shows the oil density versus number of 15 gas contacts. The empirical data again is depicted by 16 individual points and corresponds to the corresponding 17 models as lines. This plot demonstrates the reduction 18 in oil density or oil swelling with the VRWAG process. 19 Methane injectant slightly increases the oil density 20 and the remaining injectant compositions decrease the 21 density. Decreasing the oil density reduces the amount 22 of sellable oil in the remaining oil in the reservoir 23 after the VRWAG process. 24 Slide 33 shows the four patterns that were 25 originally chosen for the VRWAG pilot. The four 55 1 patterns are shown in hashed ovals on the map of the West Sak core area. The completed sands in the four 3 patterns are shown in colored circles, D sand only in -f green, D and r wand i,n blue mind D, � and h and in i 5 The 'JR I--C—' injection began on 23rd, 2009 6 officially starting the three year clock for the 7 approved pilot. Shortly after gas injection in pattern 8 1E102, a matrix bypass event occurred requiring the 9 removal of the pattern from the pilot. The three 10 remaining patterns remained on VRWAG service until the 11 end of the three year pilot with no containment or well 12 integrity concerns. 13 Slide 34 shows the oil recovery factor versus 14 time for a D sand type pattern model. This plot was 15 provided as exhibit L4 in the original pilot 16 application. Type pattern recoveries were multiplied 17 by .67 to account for reservoir conformance, matrix 18 bypass and throughpoint uncertainties. One waterflood 19 and four WAG injection cases are shown including 20 waterflood in the blue line, Kuparuk blend gas in the 21 orange line, viscosity reducing injection with 50 22 barrels per million indigenous NGLs in the green line, 23 viscosity reducing injection with 100 barrels per 24 million indigenous NGLs in the pink line and Kuparuk MI 25 blend with 150 barrels per MCF of Prudhoe and 56 1 indigenous NGLs shown in the red line. Type header 2 (ph) model forecasts were developed for waterflood and 3 XAG cases to develop the pilot rate forecasts that are sho-,an on the ne.•.t slide- Some of the type header 5 models could not be run with the full Y.RU MI enrichment 6 so all of the forecasts were made using the gas 7 injection with 100 barrels per million of NGL 8 enrichment. 9 Slide 35 is a rate forecast of the original 10 VRWAG from the original VRWAG pilot application. This 11 plot was provided as exhibit L6 in the original 12 application. Plot A shows VRWAG and waterflood oil 13 rate forecasts versus time. As shown there's a 14 projected 1,000 barrels per day benefit for VRWAG over 15 waterflood. Plot B shows the predicts oil recovery 16 factor of VRWAG and waterflood versus time. As shown 17 there's an incremental recovery benefit of about 4 18 percent of original oil in place. Plot B shows water 19 injection in dark blue and water production in light 20 blue for the VRWAG case. Plot C shows gas injection in 21 pink, gas production in green and gas/oil ratio in red 22 for the VRWAG case. Gas rates are plotted on the left 23 axis and the gas/oil ratio is plotted on the right 24 axis. 25 Slide 36 illustrates the forecast versus actual 57 I performance of the VRWAG pilot. These plots were 2 submitted in the final VRWAG pilot report as figures 3 4.2 to 4.5. Plots A and C show the actual injection 4 rates in red -EiE less than the e-pected injection 5 rates in green. The reduced injection car; he 6 attributed to the wellhead pressure constraints imposed 7 on the West Sak injectors to mitigate major (ph) bypass 8 events. Plot B shows the production rates prior to the 9 pilot in green. A forecast of the expected waterflood 10 only behavior of the pilot wells remaining on water 11 injection in blue and the red line is the date of 12 actual production rates during the pilot and highlights 13 the benefit of VRWAG above basic waterflood. Plot D 14 shows the actual versus predicted rates for the pilot 15 wells. Despite the injection rates below forecast the 16 forecast and actual oil rates were close. 17 Slide 37 shows a total injection rate in 18 reservoir barrels per day versus time. This plot was 19 submitted in the final VRWAG pilot report as figure 20 4.7. The blue line shows actual water injection and 21 the red line shows actual total injection. The 22 difference between the two lines is the volume of 23 enriched gas injected while on VRWAG service. one of 24 the major benefits of VRWAG injection is the increase 25 in total injection rate or pattern throughput 58 1 illustrated by this plot. Prior to the pilot the water 2 injection rate stabilized around 2,000 reservoir i ar1eis ] Er day. Di;]"ing the pilot tota,j, 7IljeCr]_o7] ]"mite G L17r ✓uig l7p'Llt o.I1 C1. �i11E "tl c.:Ltn.�!1Ti. Ca o. 6 constant bottom hole pressure between water and gas 7 injection. The benefit is an important of the 8 increased recovery while operating under pressure 9 constraints. 10 Slide 38 compares the pre and post pilot 11 predictions. These plots were submitted in the final 12 VRWAG pilot report as figures 4.8 and 4.9. Plot A 13 shows oil rate versus time and plot B shows cumulative 14 gas injection versus time. The red is the pre pilot 15 prediction and the blue is the post pilot prediction. 16 Plot B shows that the same amount of gas is injected in 17 both cases, but it takes longer to put the gas away in 18 the post pilot case. Again this highlights the reduced 19 injection rate experienced during the pilot relative to 20 pre pilot predictions. 21 Following the conclusion of the pilot efforts 22 were made to quantify the benefits associated with the 23 VRWAG process. Slide 39 shows the three pilot patterns 24 used for the study. The green lines are producers, the 25 red lines are injectors. This plot was submitted in 1 the final VRWAG pilot report as figure 4.1. Separate 2 models o;ere developed and history matched for these 3 producer center patterns. Three forecast cases -,.,aere C,�.,--, atciflcod �tlac �1,E ene�� c�l;Yc�flco0 yaL di7-ect1O and Fl", Co. 6 In the VRWAG case injectors 1J118 and 1J164 converted 7 to VRWAG service for the purpose of rate forecasting 8 and recovery benefits for the full pattern. The 9 following slides summarize the conclusions of the model 10 study. 11 Slide 40 summarizes the rolled up sector model 12 rates for the three cases. The plot shows oil rate 13 versus time, the waterflood only case is shown in dark 14 blue, the VRWAG pilot followed by waterflood is shown 15 in light blue and the VRWAG only case is shown in red. 16 This plot was submitted in the final VRWAG pilot report 17 as figure 4.11. Two important conclusions can be drawn 18 from this data. First there's a significant 19 incremental benefit on VRWAG service. Second if the 20 pilot patterns were permanently returned to waterflood 21 there's a sustained benefit due to the three years of 22 VRWAG injection. 23 Slide 41 shows a roll up of the oil recovery 24 versus time for the five VRWAG injectors. This plot 25 was submitted in the final VRWAG pilot report as figure • • 1 4.13. The three cases are the same colors as on the 2 previous slide. The base vaterflcod recovery is 3 Pprol;imately 15 percent of oriai.nal oil in plrce. The cf t'C_1 gate i E-_Cc_,_a.l Gi iI: D1c. C.e d. T!d t heE11lE it t-o.1 6 recovery above base waterflood for VRWAG is 5.2 percent 7 of the original oil in place. This is a significant 8 increase over base waterflood. The following slides 9 build on this result and provide additional evidence 10 for the enhanced recovery using VRWAG and other 11 patterns. 12 Slide 42 shows the 10 long term injector 13 candidates used for the hydrocarbon recovery 14 estimation. The blue circles are placed over the pilot 15 wells, the green circles are placed over those wells 16 that are mechanically ready for enriched gas injection. 17 The 10 wells with colored circle overlays were used for 18 the forecast of potential hydrocarbon recovery 19 associated with expanding VRWAG in the West Sak core 20 area. The forecast is shown on the next slide. 21 Slide 43. The two plots on the right-hand side 22 show the incremental response associated with 23 converting 10 injectors on the previous slide to VRWAG 24 service. Plot A shows oil rate versus time, the peak 25 response from the 10 well conversion is approximately 61 0 1 2,500 barrels per day. Plot C shows the recovery 2 factor versus time. Incremental recovery reaches above 3 4 percent for the 23 years of VR[,IAG service. Plot B shc",rs t1,e gas rates -:gel sus- time. The pear: gas 5 injection rate is shop%n in red for the 10 patterns is 6 approximately 17 million scf per day. The black line 7 is the estimated gas production. 8 Slide 44 shows the incremental recovery for 9 VRWAG with full hydrocarbon enrichment is shown in the 10 black dashed line and with only Kuparuk blend gas is 11 shown in the red line. As shown about half of the 12 VRWAG benefit comes from the blend gas and the 13 remaining comes from the -- enriching the blend gas 14 with NGLs. The actual gas injection into the West Sak 15 will depend on the relative availability of blend gas 16 and NGLs. Currently West Sak injectant is a 17 combination of Kuparuk blend gas, indigenous NGLs and 18 Prudhoe Bay imported NGLs. However the NGL pipe line 19 from Prudhoe to Kuparuk is expected to be converted in 20 the future for fuel gas import. After the start of 21 Prudhoe Bay fuel gas import to Kuparuk, West Sak 22 injectant will be a combination of Kuparuk blend gas 23 and indigenous NGLs. 24 Slide 45. In summary the VRWAG pilot was 25 successful. Despite the water/gas injection volumes 62 1 being lower than expected well production came in on 2 target. Normal pressure events were observed in any of 3 the �;aellbores within a quarter mile of the pilot injection :cells. Expansion of the project is 5 attractive because of the rapid rate of response 6 observed in the pilot and the predicted incremental 7 recovery. In terms of overall benefit modeling results 8 indicate an incremental 3 to 6 percent recovery of the 9 original oil in place estimated for a 25 percent 10 hydrocarbon core volume slug size. This is a 25 11 percent improvement over base waterflood recoveries. 12 Increased pattern throughput is an additional benefit 13 that allows for rapid response and improved recovery in 14 the long run. 15 Slide 46. GK co -development of the N sand with 16 the West Sak sands is possible based on new appraisal 17 data and data from the adjoining Schrader Bluff 18 developments. The map on the right shows -- was shown 19 earlier during the geologic portion of the presentation 20 and shows and estimation of the updip limit of the N 21 sand oil within the Kuparuk unit. The N sand is 22 expected to be waterfloodable estimated OIP within the 23 proposed West Sak pool is 850 million standard stock 24 tank barrels. Greater complexity and lateral 25 hydrocarbon distribution and lower oil quality make rq%] 0 1 recovery estimates more uncertain. The N sand 2 waterflood recovery is estimated to be about 10 percent 3 oil in place �,,ith a potential incremental recovery% of -4 85 million stcck tan!_ barrels. The N sand is also 5 expected to benefit from VR,,T G injection. 6 That concludes my testimony and I'm happy to 7 take questions. 8 CHAIR FOERSTER: Thank you. Commissioner 9 Seamount, do you have any questions? 10 COMMISSIONER SEAMOUNT: Again this is your area 11 of expertise, why don't you start..... 12 CHAIR FOERSTER: Okay. 13 COMMISSIONER SEAMOUNT: .....Madam Chair. 14 CHAIR FOERSTER: Okay. The -- I really -- I 15 had one question and you answered it and that was the 16 cessation of MI import going to have an impact, but so 17 you answered the question. Is the impact included in 18 your modeling or have you -- in your predictions are 19 you assuming that..... 20 MR. REDMAN: I would say our base prediction is 21 the full enrichment based -- similar to injection of 22 what we had in the pilot, but in the slide I also 23 showed a rate forecast with no NGL enrichment..... 24 CHAIR FOERSTER: Okay. 25 MR. REDMAN: .....and then you got 9 1 approximately half of the benefit with just Kuparuk 2 blend gas. And so..... 3 CHAIR FOERSTER: It'll be somewhere..... 4 1-,R. BED1,17111: .1herE �E actually .-.,; 11 Le 5 be 50111E\•;here in bet•.aeen..... 6 CHAIR FOERSTER: Okay. 7 MR. REDMAN: .....depending on what the future 8 solvent supply is in Kuparuk. 9 CHAIR FOERSTER: Okay. And do you have any 10 idea when that conversion is going to occur..... 11 MR. JENSEN: The..... 12 CHAIR FOERSTER: .....when the solvent supply 13 will..... 14 MR. JENSEN: Yeah, the Oliktok pipe line will 15 be converted somewhere in the July/August time frame of 16 this year. 17 CHAIR FOERSTER: Okay. So the benefits are 18 going to be very short lived. Okay. All right. I 19 assume there are greater benefits overall from the 20 conversion. 21 MR. JENSEN: So even once we halt the imports 22 from Prudhoe Bay on natural gas liquids Kuparuk still 23 has indigenous natural gas liquids so those will still 24 be blended and will be optimized to be sent out through 25 the patterns that have the best recovery and so 65 • E 1 certainly with this new VRWAG project it would get a 2 share of the indigenous NGLs mixed with our produced 3 gas to have the MI. -4 CHAIR FOERSTER: I didn't make 5 question clear. I'm assuming that the conversion of 6 the line to fuel gas has greater positive impacts than 7 the offsetting losses at West Sak, is that correct? 8 MR. JENSEN: Yes, that's correct, Commissioner. 9 CHAIR FOERSTER: Okay. Can you quantify those 10 or just qualitate and describe what those are for me? 11 MR. JENSEN: well, the primary reason of 12 converting that Oliktok pipe line is to provide fuel 13 gas for Kuparuk. The additional benefits are to make 14 sure we have enough fuel to run the greater Kuparuk 15 area. 16 CHAIR FOERSTER: So you're short on gas 17 for..... 18 MR. JENSEN: Yes. 19 CHAIR FOERSTER: .....just daily operations? 20 MR. JENSEN: That's correct. 21 CHAIR FOERSTER: Okay. Well, I guess Kuparuk 22 trumps West Sak right now, doesn't it? 23 UNIDENTIFIED VOICE: (Indiscernible - away from 24 microphone)..... 25 CHAIR FOERSTER: That was my only set of �el 1 questions. 2 COMMISSIONER SEAMOUNT: Okay. I'm going to 3 start vaith an ignorant question coming out of a geologist. I'm care you; .,c- ]oc1_ed at all different 5 ways to reco��er this oil. First of all did you 6 consider using steam? 7 MR. REDMAN: For the N sand I think while we've 8 considered it the N sand is a relatively thin zone, if 9 we were going to consider steam injection it would be 10 up in the thicker B sand zones. So given the thickness 11 of the interval here the -- we think that waterflood 12 and potentially VRWAG are more appropriate to work for 13 the N sand interval. 14 COMMISSIONER SEAMOUNT: And the permeability 15 was good enough to where that was more economic that 16 burning a lot of gas to produce steam, is that correct? 17 MR. REDMAN: That's correct. And then also the 18 steam has a challenge of you have to go through the 19 permafrost and, you know, still I think we've got 20 challenges in terms of well integrity of being able to 21 deliver steam down to the depths that you'd be targeted 22 in the N sand. 23 COMMISSIONER SEAMOUNT: Okay. And I assume 24 that the gas that you're going to be using on this 25 project is coming from Prudhoe Bay? 0 • 1 MR. REDMAN: The gas is going to be -- the 2 blend gas from Kuparuk, indigenous NGLs from Kuparuk 3 and imported NGLs from Prudhoe Bay. -I CO1;,,IISSIGNER SEf1iOUNT: find v.hat vaould be the 5 total amount of gas for the project? 6 MR. REDMAN: The total -- the volume of gas? 7 COMMISSIONER SEAMOUNT: The volume. 8 MR. REDMAN: I don't have the number off the 9 top of my head, but it's a -- our forecast is a 25 10 percent slug size and I'll have to get that for you for 11 the record, I don't have that off the top of my head. 12 COMMISSIONER SEAMOUNT: Okay. And we're 13 talking about 1.1 billion barrels of oil in place and 14 recovering 25 percent of that? 15 MR. REDMAN: The developed area -- within the 16 core area the developed area currently is 1.1 billion. 17 The -- if all patterns were developed it would be a 25 18 percent increase. I think there are some patterns 19 within the core area we won't go to and the -- we have 20 some single casing injectors in the 1D area where we 21 would likely not expand to in this, but ultimately I 22 think we could get to, you know, 60 or 70 percent of 23 the core area developed over time. 24 COMMISSIONER SEAMOUNT: Okay. Throughout my 25 career I've heard the number as 26 billion barrels of 0 1 oil -- 26 billion barrels of viscous oil out there that's just sitting there and of course oil's worth a than gas right nov,7 and just tal'_inq about of .c4a.11 _> .cald heal me, lust t F, 1:1 Can �L:,Et ..ee 2. Taa.1 and tEir Fna 6 feathers and getting marched out of this state for even 7 bringing this up, but that would be quite a big 8 percentage of Prudhoe Bay if 25 tcf of Prudhoe Bay gas 9 being used to get this. But the question is if you 10 were to use this gas coming out of Prudhoe Bay how much 11 gas would actually -- if you were to use that would you 12 be able to recover eventually -- I mean, you're going 13 to use this to get this viscous oil, but I assume 14 you're going to be able to get it back and use it again 15 later, right, I mean, it's just not going to go into 16 the ground and you're going to lose it forever, 17 correct? 18 MR. REDMAN: I would say in terms of the VRWAG 19 process that one of the -- I think one of the features 20 of it that may be different than Prudhoe and Kuparuk 21 and the miscible process is you have a relatively low 22 amount of trapped gas. So a lot of the gas you inject 23 ultimately is reproduced at the offset wells. So you 24 can think of it as that we inject the gas, but a lot of 25 the gas isn't lost, it returns back to the facility and Z 1 is recycled to help produce more oil. 2 COIMISSIONER SE1-11,1OUNT: Okay. So you're just going to delay getting that gas? tt - lct �f the o z i_ _ � 1eti�in�ci 6 through production. 7 COMMISSIONER SEAMOUNT: Okay. Now getting back 8 more specifically to the project at hand, why are all 9 these horizontals being developed in a north/south 10 trend, is it -- is there a fracture pattern or 11 something like that? 12 MR. REDMAN: It would -- well, it was the -- 13 it's on strike to start with so your -- it's favorable 14 to do long horizontals in a strike direction so you're 15 not going say towards an oil/water contact, you're kind 16 of staying on the same level. We're also aligned with 17 maximum principal stress so it's -- so if you do 18 fracture most likely that you're going to fracture in a 19 north/south direction which is parallel to your 20 injectors versus over towards your producers. 21 COMMISSIONER SEAMOUNT: Okay. And what would 22 be the ultimate -- well, I guess you've already 23 answered that, but the ultimate recovery per well we 24 could do a back calculation on that, I mean, you're 25 talking about 25 percent. And we could figure out a Of 1 drainage area and the spacing by looking at the maps. 2 Let's see, I guess I have all my questions 01, ay Thanh jou . 6 CHAIR FOERSTER: Thank you, Mr. Redman. All 7 right. You guys may proceed. 8 MR. JENSEN: So our -- thank you, Scott, and 9 thanks to the others who provided testimony today. 10 CHAIR FOERSTER: This is Mark Jensen back on. 11 MR. JENSEN: Yes, it is. Thank you. 12 CHAIR FOERSTER: Thank you. 13 MR. JENSEN: And so I'm going to run through 14 kind of the last piece which is concluding our 15 presentation and then reviewing the amendment 16 application and specific amendments. 17 But before I do that this is slide 48 and I 18 would like to review and kind of get a summary of where 19 we've been today and what we've covered. Mike Warner 20 first started out with geology. He provided evidence 21 for the inclusion of the Schrader Bluff N sands in the 22 West Sak oil pool. Additional evidence was then 23 provided for the operation of injection at West Sak. 24 Ti reviewed the well integrity components and expansion 25 plans for VRWAG in the West Sak core area and then 71 • • 1 Scott Redman just concluded with a review of the work 2 behind the VRWAG pilot project as well as the results. 3 He also proz.rided evidence to support the expansion of t Ea]_ o-- p l aid 5 arbo , the N sands . 6 The key conclusions for this application are 7 listed on the slide. First including the Schrader 8 Bluff N sand as part of the West Sak oil pool will 9 bring consistency between the units de-reloping viscous 10 oil on the North Slope. Additionally the operational 11 limits provided in the application will clarify water 12 and gas injection operations within the West Sak oil 13 pool. Mechanically ready expansion candidates in the 14 West Sak core area are available for the expansion and 15 were listed as part of the application. And lastly the 16 pilot project demonstrated the benefits of VRWAG 17 injection as a mechanism for enhancing oil recovery 18 within the West Sak oil pool. 19 This is the much awaited slide, slide 49. So 20 these -- this slide and the next several slides will 21 review the proposed amendments for conservation order 22 406B as in baker and area injection order 2B as in 23 baker. The plot shown here shows the proposed aerial 24 changes to the West Sak oil pool as defined by 25 conservation order 406B. The unit boundaries are the 72 • • 1 dashed black lines so you can see the KRU kind of 2 southern extents. The original pool boundary is shown 3 as the sclid blue Line best noted up by the Ni]-laitchuq 4 location ;:here it -land of jags out and isn't o-,,erlaid 5 ID-Y the dashed red -line which is the proposed boundary. 6 The proposed amendment adjusts the pool boundary is two 7 areas, up towards the north where the Nikaitchuq unit 8 is located and on the eastern extent to make the pool 9 boundary consistent with the Kuparuk River unit and all 10 adjacent established oil pools. 11 This is slide 50. The application provides 12 evidence and proposes to change the vertical definition 13 of the West Sak oil pool to include the Schrader Bluff 14 N sands. The current definition in conservation 406B 15 reads, the West Sak oil pool is defined as the 16 accumulation of hydrocarbons common to and correlating 17 with the interval between the major depths of 3,742 and 18 4,156 feet in the West Sak number 1 well. The proposed 19 amendment will change the definition from 3,742 feet to 20 3,552 feet. The changes are highlighted in red in the 21 slide text. 22 This is slide 51. In connection with the 23 vertical changes to the West Sak oil pool as defined in 24 conservation 406B the authorized injection strata must 25 also be changed as defined by area injection order 2B. 73 0 I Rule one of area injection order 2B reads within the 2 affected area nonhaza.idous fluids may be injected for 3 the purpos-es of pressure maintenance and enhanced oil 'st_ata ciin' tricsE >t�< at .E ', 1. ;, *'1c t.lata. foui_d is"1 tl. .-a.Cv ;._st- Sa �� 6 River State Well number 1 between the measured depths 7 of 3,145 feet and 3,640 feet, 3,744 feet and 4,040 8 feet, 4,591 feet and 5,324 feet and 6,474 feet and 9 6,880 feet. The proposed change adjusts the measured 10 depths such that the Schrader Bluff N sand is now 11 authorized for injection. The new measured depths will 12 read or the new measured depths proposed read 3,145 13 feet and 3,552 feet, 3,552 feet and 4,156 feet, 4,591 14 feet and 5,324 feet and 6,474 feet and 6,880 feet. The 15 changes are highlighted in red in the text. 16 This is slide 52. Lastly as part of the 17 application specific rules were proposed relating to 18 VRWAG in the West Sak oil pool. The proposed rules are 19 listed on this slide and the first read VRWAG is 20 authorized in the West Sak oil pool, VRWAG must be 21 conducted in accordance with the process described in 22 the VRWAG application, attached and incorporated into 23 the area injection order by reference and all 24 applicable regulations. Additionally for existing 25 wells recompleted in the N sand prior to commencement 74 1 of VRWAG gas injection activities and injection wells 2 recompleted in the Schrader Bluff N sand the operator 3 must submit an application for sundry approval or I com:rtission form1040- These proposed rules in b addition to existing rules would make the application 6 process consistent with the other enriched gas 7 operations within the KRU. It'll help streamline the 8 management -- the overall management of gas injection 9 operations on a unit wide basis. And Ti outlined the 10 rigorous review process to be completed before the 11 submission of a 10404 when converting an existing 12 injection well to VRWAG service. We -- this -- these 13 change -- this last section differs from that that was 14 submitted in the application and we have some -- a 15 letter and accompanying materials to supplement that 16 application in regards to these proposed rules and we 17 have that supplementary information today or we can 18 submit it according to your direction. 19 And that concludes my portion. Unless there's 20 questions I'll turn it over to James for closing 21 remarks. 22 CHAIR FOERSTER: Commissioner Seamount, do you 23 have any questions? 24 COMMISSIONER SEAMOUNT: No questions. Thank 25 you. 75 0 1 CHAIR FOERSTER: Nor do I, but before you go to 2 closing remarks unless you're going to provide any more i technical detail in your closing remarks this might be 4 a good time for a recess because I don't hnovr about hi; 5 geology staff, but my engineering staff'c certainly a 6 lot smarter than I am and they might have some 7 questions that they want me to ask. So if you guys 8 don't have a problem with taking a 15 minute recess 9 this might be a good time to do that. 10 MR. ROGERS: So this is James Rogers. I do 11 appreciate that. We would like to take a recess. 12 There were a couple of questions that were asked that 13 we did not provide answers for, that I'll review those 14 questions and so we can also talk about that during the 15 recess to make sure we have the questions accurately. 16 CHAIR FOERSTER: Sure. 17 MR. ROGERS: So we had one question and I guess 18 it was from you, Commissioner Foerster, about the -- 19 are all the Schrader and West Sak pools one charge and 20 if they are one charge are they all one reservoir and 21 why are they different pools. So did I -- is that the 22 question? 23 CHAIR FOERSTER: Yeah. 24 MR. ROGERS: Okay. You also asked about are 25 the pool rules different between the different pools. viol 1 CHAIR FOERSTER: And you don't have to take 2 that one on, I can asl- rr,7 staff that. l-�a.cl_ . 6 MR. ROGERS: Okay. Thank you. Then I guess it 7 was really more of a statement really asking if we were 8 addressing all the pool rule issues in this hearing? 9 CHAIR FOERSTER: Right. 10 MR. ROGERS: And we are..... 11 CHAIR FOERSTER: Okay. 12 MR. ROGERS: .....so we feel like the pool 13 rules as we are asking them to be amended are 14 appropriate for our operational..... 15 CHAIR FOERSTER: Okay. 16 MR. ROGERS: .....departments and needs. 17 CHAIR FOERSTER: Good. 18 MR. ROGERS: And then, Commissioner Seamount, 19 you asked about the cumulative gas that would be 20 utilized and that's an answer we'd like to get back. 21 COMMISSIONER SEAMOUNT: And that doesn't need 22 to be answered today. 23 MR. ROGERS: Okay. Okay. So are there any 24 other questions or outstanding issues that I failed to 25 capture? 77 1 CHAIR FOERSTER: Not yet, but when we come back 2 after recess..... 3 MR. ROGERS: Okay. -4 CHI IR FOERSTER: . .. . . we may liave 5 MR. ROGERS: Okay. Thanl; vou. 6 CHAIR FOERSTER: All right. Now we're off the 7 record. 8 (Off record) 9 (On record) 10 CHAIR FOERSTER: We'll go back on the record. 11 Well, first, Mr. Jensen, we have some bad news and we 12 have some good news. Commissioner Seamount wanted to 13 ask if we could exclude expert recognition who were 14 born after 1983 and the good news is that our assistant 15 AG said that we could not so you're still in. 16 MR. JENSEN: Thank you. 17 COMMISSIONER SEAMOUNT: That's not true, 18 but..... 19 CHAIR FOERSTER: But it's funny. And we do 20 have a few questions. First are you anticipating any 21 H2S problems in the future? 22 MR. JENSEN: We are not anticipating any H2S 23 problems in the future. 24 CHAIR FOERSTER: Do you have any H2S at Kuparuk 25 right now? V 0 1 MR. JENSEN: At -- I can't speak for Kuparuk, at ?4est Sa]_ aze have trace amounts I think.. . .. C? -T�-1R FOERSTER: nlcay. . . . _ '�E1E =c �Ti �Cr f20m . a.;ds paLI: ]per E 6 �,ahat the last samples. 7 CHAIR FOERSTER: Okay. If you look at slide 8 22, the list of all the owners and operators that you 9 notified, there are a couple of parties on the boundary 10 that appear to be missing, Pioneer or Kalis (ph) and 11 Brooks Range. Did you not notify those 12 owners/operators? 13 MR. JENSEN: So we did not notify either of 14 those. The owners that we have notified are listed on 15 the slide with the exception we did also as a courtesy 16 notify the U.S. Air Force for the DEW line station. 17 CHAIR FOERSTER: Why did you not notify Pioneer 18 and Brooks Range given that they have acreage that 19 immediately abuts your acreage? 20 MR. JENSEN: I guess that -- I'll have to..... 21 MR. ROGERS: (Indiscernible - away from 22 microphone)..... 23 CHAIR FOERSTER: Introduce yourself, please. 24 I'm sorry. 25 MR. ROGERS: Oh, sorry. James Rogers. So the 79 1 request is really right now the 10 additional injection 2 wells to resume or to initiate the VRWAG and within the 3 quarter mile radius of those 10 injection wells we have 4 covered all the landowners in that area. So if we were 5 to expand in the future to increase the VRV,7AG to larger 6 patterns and those patterns became close enough to 7 those lease lines so that either one of those companies 8 were within that quarter mile radius we would then 9 grant notice to them. 10 CHAIR FOERSTER: Okay. Okay. My next one is 11 on -- let's go to the slide, I forget which one it is, 12 I'm sorry, but the one that shows the unit boundaries 13 near the end, the long awaited unit boundary slide. 14 COMMISSIONER SEAMOUNT: 49. 15 CHAIR FOERSTER: Okay. The -- well, and I 16 probably should to the one that shows the reservoir 17 boundaries too, but your unit boundaries appear to be 18 conforming to the unit boundaries to the north and 19 east, but not to the south and west, why is that? 20 MR. JENSEN: So we're going off of kind of the 21 original area injection order. Really the main -- the 22 changes were more housekeeping. The geologic 23 definition has not changed and our geologic 24 understanding has not changed in the west Sak oil pool, 25 but these were more to bring us in line with the other M. 1 adjoining oil pools that are established. 2 CHAIR FOERSTER: Okay. Okay. And the unit boundaries go beyond -- seem to go beyond the pool -4 boundaries. Ll 11P. JENSEN: Ol the othev way around. So the 6 pool boundaries go beyond the unit boundaries for..... 7 CHAIR FOERSTER: Okay. Right. Okay. 8 MR. JENSEN: .....the KRU. 9 CHAIR FOERSTER: But the productive limits seem 10 to be smaller than the pool so you have made no attempt 11 to make the pool boundaries fit the pool? 12 MR. JENSEN: I guess I should defer that or 13 maybe we can answer that off line, I mean..... 14 CHAIR FOERSTER: You can answer that off line. 15 MR. JENSEN: Okay. So we'll come back to that. 16 CHAIR FOERSTER: Okay. And I only have one 17 more question and it's really more -- it's something 18 definitely keeping -- you can give me a short answer 19 right now, but it's a long answer that we're waiting 20 for. We asked you about six months ago for an analysis 21 of the impacts of the conversion of the Oliktok pipe 22 line on the KRU ultimate recovery. Do you have an 23 estimate of when you might provide that analysis to us? 24 MR. ROGERS: I do not. We will have to get 25 back to you on that. I'm not aware of that request. 81 1 CHAIR FOERSTER: Yeah, we made it over six 2 months ago. R. UCGERS : ;i_' 1 -oii qet ... . iP. FC � "'I� RS- -. -. t _G� an c �,-ec;aevt. i ll tl !'.0�. �S `1_�-:, Cle ,r,..; 6 when they would get back with you or..... 7 CHAIR FOERSTER: No. 8 MR. ROGERS: .....when we would get back with 9 you? Okay. 10 CHAIR FOERSTER: No. And sometimes if you 11 don't get back -- you know, if you don't set a timeline 12 you don't get one. 13 MR. ROGERS: Can you please tell me who you 14 made that request to if you recall? 15 CHAIR FOERSTER: It was -- I think it was staff 16 to staff. 17 UNIDENTIFIED VOICE: (Indiscernible - away from 18 microphone)..... 19 CHAIR FOERSTER: Okay. All right. I'm sorry, 20 Commissioner Seamount, I didn't let you ask questions 21 first. Do you have any questions? 22 COMMISSIONER SEAMOUNT: I have no questions. 23 CHAIR FOERSTER: Oh. Well, that worked out 24 just fine. All right. Mr. Rogers, you had closing 25 remarks you wanted to make and no guarantees that your 1 closing remarks won't generate another question or two, 2 but..... ROGERS : 0haY . "I'<__ __ F C; E7 RST ase pi oceea . o 1 e�C), ',-,n'.�;e CI O"11 C� 6 we are going to have a response to your question about 7 the geologic charge which Mike Warner will address. 8 CHAIR FOERSTER: Okay. 9 MR. WARNER: So as we demonstrated we believe 10 the Vilest Sak and N sand and the Schrader Bluff O and 1\7 11 sands do comprise a common stratigraphic interval 12 across this area and we believe the accumulations then 13 do represent a common charge event which have resulted 14 in a complex aggregate of structural blocks 15 characterized by varying degrees of post oil placement 16 by degradation. So either large accumulation, complex 17 region. 18 CHAIR FOERSTER: Okay. So it's probably just 19 unit boundaries that ultimately led to other pools, 20 kind of like Milne and Kuparuk? 21 MR. WARNER: Yes. 22 CHAIR FOERSTER: Okay. Okay. 23 MR. ROGERS: Okay. Thank you, Mike. So the 24 one question we're not prepared to answer that we 25 discussed was from Commissioner Seamount on the gas and ME 1 can I clarify are you interested in knowing the total 2 volume of gas injected or the volume of gas injected, 3 consumed in the reservoir, volume of gas returned or all of the above 5 COMMISSIONER SER3A90UNT: All of the above. 6 MR. ROGERS: It's probably all of the above. I 7 probably shouldn't have asked that question, that's an 8 easy out. Okay. So we will get back and provide that. 9 And now I'm going to have to ask -- I guess I'm a 10 little confused now when we say we would take that off 11 line, your question, Commissioner Foerster, about the 12 reservoir boundary which is the pool boundary, I would 13 say the reservoir boundary and the pool boundary are 14 the same. Did you say they were not, we could take it 15 off line. 16 CHAIR FOERSTER: Maybe I'm a little confused at 17 some of the maps I looked at, but it appeared that to 18 the southwest the pool boundary went a little bit 19 beyond the reservoir boundary. 20 MR. ROGERS: That's true. 21 CHAIR FOERSTER: So that was my question..... 22 MR. ROGERS: Okay. 23 CHAIR FOERSTER: .....why -- you know, why were 24 you not conforming the pool boundary to the reservoir 25 boundary. EI 1 MR. ROGERS: So the pool boundary covers all 2 the different West Sal: sands from the N, D, B and the A sands and we're primarily •Jzorl:ing -- looking at the N -I Sand 5 CHAIR FOERSTER,: Ulh - huh. 6 MR. ROGERS: The N sand certainly is part of 7 the aggregate pool and is certainly a smaller 8 geographic outline that the other D, B and A sands. 9 CHAIR FOERSTER: So the maps that you showed us 10 were the reservoir boundaries of the N sand? 11 MR. ROGERS: Correct. Well..... 12 MR. JENSEN: It was of the West Sak also. 13 CHAIR FOERSTER: Okay. Now I'm reconfused. 14 But I think this is a question that we can answer off 15 line. Which slide is that you're looking at? 16 MR. JENSEN: Slide 12. And really I guess for 17 clarification when we talk about the pool are we 18 talking about the accumulation of oil or, I mean, are 19 we talking oil/water contact where -- I think we're 20 getting into some other stuff that we need to kind of 21 take off line and..... 22 CHAIR FOERSTER: I think this is best addressed 23 off line. 24 MR. ROGERS: Okay. Will the record then -- can 25 I request the record stay open so we can answer these 1 other couple of questions in a couple weeks? CHAIR FOERSTER: Yeah, sae can leave the record 3 open for taro R 1 0GEi;S : C 1.c.1' . (;j-a, io1 Gl i }'car attention durng the 6 presentation today. ConocoPhillips has asked the 7 Commission to expand both the aerial and political 8 boundaries of the Vilest Sak oil pool. Additionally 9 ConocoPhillips has asked the Commission to approve 10 injection of enriched hydrocarbon gas into the West Sak 11 oil pool. The mechanisms to accomplish these request 12 are to amend conservation order 406B as in baker and 13 area injection order 2B respectively. In support of 14 these requests ConocoPhillips' experts testified for 15 justification of injection containment within the 16 target reservoir from a geologic and rock mechanic's 17 perspective. ConocoPhillips demonstrated that current 18 wells ready for injection have exhibited wellbore 19 integrity. We further outlined the process that would 20 commence to evaluate additional VRWAG injection 21 patterns prior to being submitted to AOGCC. Lastly 22 ConocoPhillips revealed that West Sak's approximately 23 four VRWAG pilot, four year pilot, confirms the 24 predicted forecast that VRWAG operations enable 25 approximately 3 to 6 percent incremental original oil M 1 in place recovery and that results in about a 25 2 percent improvement over base waterflood bringing the 3 total recovery to 18 to 21 percent. So to clarify, 4 Commissioner Seamount, you had made a couple of 5 comments earlier about 25 percent That 6 context was that the 3 to 6 percent improvement due to 7 VRWAG is about 25 percent of the waterflood recovery. 8 Those are all my closing remarks and I thank 9 you for you-all's time. 10 CHAIR FOERSTER: Thank you. Commissioner 11 Seamount, do you have any questions? 12 COMMISSIONER SEAMOUNT: I have no questions. I 13 would just like to thank ConocoPhillips for an 14 outstanding presentation, very professional and very 15 good demonstration of how we can -- how you can use 16 North Slope gas is a very valuable community -- 17 commodity to enhance recovery by keeping North Slope 18 gas on the North Slope and not necessarily having to 19 transport it off the North Slope even though it could 20 be valuable by transporting it off the North Slope, 21 but, I mean, just keeping it up there you're still 22 using it to make money and using it as a good resource 23 for Alaska. 24 Thank you. 25 CHAIR FOERSTER: You're starting to sound like A; 1 me. So thank you very much and is there anyone else 2 who wishes to testify not necessarily from 3 ConocoPhillips, but anyone else from the public? iJ0 colt mel B ) 5 CH)= FOEP.STER: Olcay. i,7ell, I just want to 6 say that Commissioner Seamount and I are disappointed 7 that we didn't get to hear from MJ and Randy. We 8 always enjoy what they have to say. But if no one else 9 wishes to testify then this hearing is adjourned at 10 11:15. 11 (Adjourned - 11:20 a.m.) 12 (END OF PROCEEDINGS) MM 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 89 are a true, 4 accurate, and complete transcript of proceedings of 5 public hearing on April 23, 2014 transcribed under my 6 direction from a copy of an electronic sound recording 7 to the best of our knowledge and ability. E: E 10 Date Salena A. Hile, Transcriber 11 M NAME STATE OF A LASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing April 23, 2014 at 9:00 a.m. AFFILIATION Testify (}yes or no) Aa rc- �7co6eey-) C FA %s CPAT No J ► `\ mc,Le-od cPA ( No t iQrt .j e� C��L' gib (���� CPA �--) l c,i11� V)eR3 Sb A- > D _..( 4^ Lam) - "5cqx� ��fl • 0 � � IA CL r� low 8 0 c O u • • O O t1,0 O UZ � cQ •- +-d n o w Ln O_ O M O U 0 O +� s- n �° 0 un O p O O n 3 o E cn U-) n L/) n v n O Q) > O cu — v °' ° >� +� Q)ro +J N `r' a-' QV)) v Q oU .`n E v N � � c s= C6 > 4--J 0 U ' U .� f6 O _ Q) .� O O -0 4-E'--v J f� O 4- m4-' � O t)o i O n o O o O SZ _0 .E. J N 4 m Q v N -0 M U U Q) O N C Q) O Q) L Om = C 4- M 0- x o N D o U (U Q)O E '-'-' Q)- Q - ■ ■ Q ■ ■ w ■ ■ N t1A tu0 Q) v c� Q) N 0 N E 0 Q) O U v L Q) U C i Q) 4- 0 a-1 C v m ■ cn i C6 V) a- J E Q) Q) .L- W O Q > O i _0 O a� � > O O O U •}, U N O O �O L/) _ �� O 2 O O O +J U V) V) Lf) O can c�i� V)= • • s� �w mc �Iam w 0 c 0 u N 0 1 �{ N L- O v D a o m +--) U L > Co Q O 06 L U }J O U u Z3 4� -O O O Q- C �� m v U QJ M ' > 00 (3) L ■ ■ • O Q N c'•I � 4-J N v ' 4= O -� _ aA Q) : _ /> O W L C) 4^ 4� c o O Ln U O �C l/1 L.L. N Q 3 U G) U m Qrl > a Ol ■ ■ rH Cl Q I ,p, L• N L O L U N C1A Q O O N o _ Q N iTc O ON (n QJ QJ L O L +� (� O v _ L O � L 4-j U 4-j O O L Q� O 1 � U n _ (O U oz C •- N ("i m O -0 _ CD a > U O ■ ■ ■ A— u CD t1A C U C6 �Tc vCD N N L 0 Q) o Ln c o E - � ca L O (� � � Q O Q) ul m CDj 00 Ln a- n r.� O O _ C) aj O 7 � w "D O ■ ■ ■ ■ N 0 • •� 1�9 4 � �II141 .� 10M. d•.. D - • N c a) > @ O 4 � Q) O x J > Ql 0 o a c � CD v +� a o > O c c v c Q) c > 6 >CU v o > O L o a� "O O O QJ Q u Q) o_ Ol o pCD p[ N C: E L } @ a a O _ � 6 +-+ fD _O E y_ O _ i p> N + O In m c �_ O L aj +� O O ra v > 0 U 0-O-0E U > Y 0 a W Q) Q) a) N O > O Q > .0 COC Q toL Q) = C Q. f0 O c c Q+ c i2 > n c to 3 Y O L Q L E @ }' c aJ QJ C ro Q tp fQ y c a1 + a v v m Q 0 c-i - c a a) a U L a U u p aJ Q a� + ++ p U a) �--' > — N c o ,u U> O Y U Q1 O v — 0 t O O O L U p u v- t0 Y> u= u; c O _ Q1 _�( W @ vCL >-0 O O O O— O ro lD W v O O OA vi �_ U Q W +'' ' L O N vUi Y Q -0 N c a� a s @ Q -a rn a) c N N L Q U Q, OO ua) , .YI- _ `V O p Q 7 vO LL O O QQ N a 1 i U N Q> � O L � L > n d > O U U N cu d Ln O o r-i ---�� 190, w O 1°,ol i r �r 0 0 0 0 o L o Ln o LA M N N ri od08 'a;e21 HO 0 Ln _0 O L 4— O L m � O L }_ a, LU 0 0 o U v p U V) p OO +-� V CL CD U � O -0 m c 2 i CO o �' U- O +J �O o p O N a-J av U N L O r1 i -0 O a U � .. N_0 r-i OO a) � +j LLd V E U Q. Ln Ln .00 >\ v +., w O V Ln w • • vi CL �w ■rrw 0 u 0 c 0 u ro V) N • • O O O Q— R. C c� Z CD L v L U Q� 4-1 L O O U N C =5 U E C- O O U `+- N Q � L m CLO _0 c m s' O c% —0 O O O O � Q m U V) - a --a L v o LID Q O a- ■ ■ 7 IIF 4 •A mis i 0 Q I a- J f� L +-j V) ■ ■ ■ • 4- a3 a _0 :D LO L LO cn o c co N cn CL w C _ O _m : t0 C G' O i N � � -0 O Y O� N L) 70 C L N in O H O cz p co O O _ O()O cn co _0 O 0_ �O m (0-o� Z Nm OUN)D � O o OOm oo o Y m N _ C �0 N Z Q .. : C i O C C C u U m O O L O cA V♦ t4 (0 -0 i m OU w O N> O C U d Y Y Y O N 0 N a U) 0 (n (n - -0 � � C U C (6 O Y � Lf 0° 0'~ �O>> 0) U5): z UmYn� O iv iD t+ po un Ln LI)m N ~_ E v _ O i � J O C zo— Iq 2 m O� L d L acU cinm Z N C w o E d o 0 n n > L!l r-1 r-7 0 • 4 N E p a) o CD CD 4 M p p U X + 00 • E O aJ p j +� Lf1 o in 4- c6 p p ra M O — u 1 M O �n U QJ O (z Q1 N n} vNi p I�-I O p V, 00 � a Y 00 O OA O Q1 QJ QJ cn QJ p 4.,} L cB p p0 u L 4- p QJ - -O N �' < co Q L tII U O O ) '- %- +-1 N O L U OA c- 4- >, m QJ p +- - '� }' i'o Q) E o OD N N N_ Q p V1 4-+ Q -p Q) 3 N O rp Ln d i N O O , Q1 Q C6 JO L G cu Q (j a) Z J �l p d d C� lD QJ v vi RS U r m m o E d o O > U ' > O to o � � � ✓�i in � L N m 0 0 v L U N M n v V f6 Q) L Q f0 v �_ > ([} c W L o U Q cn O f0 H ra aJ F— r 1 O N .-M Y v E p N O 4-1 Ln Ln C f4 Y L p n U O L O 14 Ql > a C O D s N L S- QJ 4-1 N 4+ -1 QJ p fLC � `^ = is z a z u z w z ° LL I I I L i 0) M N m m m 0 w- Z Z Z Z Z m � t 1 c o QJ L O C L n QJ O 4 ra O -L3 (O C i U 'N > L QJ L O O ' !� N Gl s. a > �G f° C LnLn Q) �n O Q a Q1 > L L O L Q > L Q) C L Q) L v C co C Y I I I • m p o V h o�t� s C 1 U Q two m 0 m m 00 c fT� O a. 1 � a m _ '- m a L �c ,v `� M 'L7 (n 4-' � v4- oM cv _ O OO N o ry, Z I L.D o Co U LIl O �- cr- m fB Q Ln p O o a m L_ N cn v Y U v O In i 4� � a 0O V) � V) a- � i O ao I � i o — a C7 O � W " Ln +� } v 4-1 v N O I I LT o v m O Q t is 0 u 0 c 0 V OM m L L1A m L a-1 N 1 C Z Q N 0 +- u i O ua- Q1 > > Oi Q _ 4_ z u Z a� l0 OLn v `n ro + J QCCJ C O a) C) c O a� r6 0) 4 � O In QJ p aA � v +� C co Ov 4-' O v '�'� u L ++ u � L +� — Qi r0 O v Q a n Z5 ro N � co V) `� � 4- u V) fD �- a� t F— p 4— �- v 3 O � Q) — LE •N U C p > }, `� u C n c N -� rB L- t U t/� -O _�C O a _� r� rp 0-> O � QJ +� � fLII O Q O p ;..j > u hA O O ro 4- � � a1 +, x w c O � z cu U w v) Q j Ln cBLn i- � o � _ O c� — u O V1 � v s z u Y L LU Q1 a' N aJ i p O + Q O � Z3 +, U W = z 0 LL VJ Y _g � ze o� 3 3 R $ $ a S a o qw fl (n E n � n n U ti ^� to �. o 0 • LA CL 0 V Q c Q V Ca � N 0 O v U U U C � (D Q N 4— p — cn O o 0 W O m Q O QLA > O O u N N •� D L Q) Q In ('� — � • — �, Y 0' x �— N N J Q•— O U O L U -a a� cn v U Lf)—' -a .� cn D M N C6 — L E Q L O o .� c�6 j a c `—�'-' +�-+ tp m ■ ■ ■ O N p •� O a-+ 2 2 U a-J - LL •(� 1 \ .N a M O0 0 a� m tx = J Ln Ln o G m i- LH N V LL .Q C m GJ Ln N L E C_ CJ �L dA i J a �' n I• CL O (A O (A O CD rn L Ln O O O O O O O O O O O g o o g o 0 0 0 o S S In n G1 ei M Ln i- Ql "q M Ln N N N M M fn M m d' q d' :4 o/ll jdaa c1i v (U N Tt L O o O 4- • � v.)?� O ca E U v — _0 Q) a) � �_ Q) • —1C:L a� o v -O • — p � f6 N U _ -0� Ln LL_ u p N Q U v uU • _ O /�^, O S� cry • — V � f� a)O -� -O N N W �.� L.n L fQ G Q E O— o �- a, -0 �7 E L -0 z�° cv > O ��. w z 1 � E L =,� C6 C E�9 o 6 i o v. �( R O O m 0O d r r N t m L O •C 7 O 0 to * Lo E O o � o d � w UJ > CV CV Q-D CD cc cu U * E O 0000 a)U ca Cfl CV O t K o y cn Co U d C CU R +' o o o m cu d ~ m W j N p E O E N •- V O Ucu C.0 _ �o =oo � ui V M O Ca () `dU) CU UO m c O i N 7+ - c N L \ LL. Q 4-1 X a) Ln N c o N Q 00 Q) Un O U v � o O ro 4 o E � Q m v '� On LLVco Q Ln O a--+ c � o fB C� — x 4-J C p n Q v C v N iJ u a ' Ca N o N a U 4-J Ln p L -0 2 a _ CON a. c Ln Q i i/ i U I i 1 • i 0 O O C6 Ul) U a-' J J Ca (a 4te-1 U C O N iJ Q N Q l� O N Li U U =3 0 C: v 'C O � O J J N c� Q— j c O U hA L � p m Q N U O U ate-J U �� O i 0 O p Q ro Q O V) i 4— O i � � i 't �- I O� w U L J 0 a x w �p L > Y — Cn D � 0 O co 4-1 U Z �(U V) r� Q Q co U w w �7 0 1 1 F c O X 4- D CT 2 Q) O o C N •� O cn [n LL M U Q � L N v "O O L Q) a=+ Q) O N u DC m C U v U 0 L Q O O u v u Q) m O � •L O � Q) 4A u Z c Q) Q= O O W E v) E C- O O U v � v C- Q) c ■ • • �' C • s ,-, 0. o V 0 O V c O a. W C— O Q) E O U L- O 4-J u . Q) U iW 0) m �/7 V U c LO O O) V � o d Lo -� Z ro Q) 4-0 U0 W � cn u O V) Q E > i. 4J � E CL Q OU a �_ _ = i G � t0 -- (1) t4A =3 +� N V Q u L m (1) N �— ro O 4A N j � N i' j • cn 4 -+ U ao O U — O Q —_ X .�? o E��•> > v U O u W Q uL .N O '� r C a-J M ca a. cn � U L t U Q O cn O N = r 1 �i Q) n oc ci z V) 0 1 \ W WJ C (� V > o ° taA - a-J C C C6 �� c = v N O 4-' ca 4- -� c N cn Q c ca N O U cn v O cn ° . (lo U Q) Q -se _ M v 2 O — o Q > ol LA a. s i°- 0 u 0 c 0 V 'r C-i Ad z- ► Co p 1 t LL t O M m 0 N 4.0 m CY) C O U as 0 14— O L N � E Z T- O O O O O O O O O O O O O� 00 1` (D U-) M N r- d3 `f%l!sO3sin HO c� c� C� C� 0 0 0 0 C/)U) Co M N U) U) m (n (6 a-r a U !n E� 0 � . -.0 m m co O C� o -O -a 'o C/) 0 M O m m m O C (!i ' 00 00 00 -r- �nLL— N x�a.a-CL >> L— ci ci 00 co � ~ ti O O O O O O Do/B `AI!SUaa po m 0 co CAI ►.0 C7 �+ O � Q 4-J O 4J •Q- -J O O00 4-J E 4 U co 0 0 N V O C-6 co � a v N O Ln O cn � o oN > = w w r! r! p +-+ +' O -C :3 •i i L i_ — a� v a� v L a—.+ U _ +-' , • O w o- u, o a a ate-+ >` a••, v O a--' e•-I 4 ' r-i a- r-1 a-+ 4-J — C O m O O tt: O+ O Q N — ate+ � v (� U Q U Q U Q U Q N N Q) oO — C °J a) a) O v U a O • � C c-' I V - G fD fII Z LLJ R r" V1 / H m - m CL S _ c z m00 C Vi 7 7 OCO _ Y �o LL j Q m 5 lllllN z , N `�.`.., au �, �, \ \ \V _ • urn .yrc JJ e l\ j/ w LU 1 \ � • • E N 0 u O cn Y l� cn N LL ULL U LL U co m com m m m 0L CD0 O LO I � I 1 N N T- T- `JO}Oe=l AJOAODO�j V O N O LO I 6- rE C O I I C N i i O. O I O'U'; 3 O i Q) 01 C Lo N i N47- O >> N N N i o > � d co E I v H 0 N { N O 0 0 i N M N O v O 0 N O O O O C. O C. O O O O O O O O O O O O O O O O O O O O O O) N I- (D O 'T Cl) N Aealeis `a;ea JeleM m 0 N m O O N 0 N N O � N � O � 0 N rn 0 0 N Cl) N (D V O O N O O O O O O O\ O O O O O O O O O O O O O O O O O O O (p Lo M N Aeol91S `elea no Q n y I • ni O 0 CD r CD 0 ZZ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o O o 0 0 0 O �f7 O 4-1 O 47 O � O 4J e-- ►wQ 91S 'aua 1!0 m 9007 LO V (� (D LL Q C C O O V I U1 (I1 M i M O (=1 0 rN n O O 0 0 0 M Cl O o o co o co O o O o O o O o o 0 0 6 0 0 0 6 0 6 O O O O O O O O 0 0 0 0 0 0 0 0 ID 'C N O N to � N fw(] JJSIN 'owd iw!laafu! se0 Q • !2 O N s 0 0 0 0 0 0ZZ 0 M 0 M 0 0 0 0 0 0 0 0 0 6 0 0 0 0 0 V 0 N 0 0 0 0 O OJ UD a 0 N Ae( 9lS `awa 1!0 a) Z2 a — a) 0 CD ZZ U o ; Q n O v' O L 0 u� LL 0 O 0 o o M 0 o O o O o o O co 0 0 o o 0 M 0 o O o 0 0 0 pp 0 ti 0 o O o 0 (O t --r M N 0 �- ' e(I 81S'n0ii0alu! iaum V • Q i � i i 1 j f t I { i I i i � I (53 I � *1� u < o o ., J f -14-1 i i 1 1 0 (-4 0 h- 0 0 LD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 I- C.4 Lr, St m C4 r A'a all °uolpeful JejOJL E, a .HE rl LA • C— O -j r ^ W O N (3) T O c- E U O u �rTS W , \V / O .0 Ul) C3- M 4A N L O +-1 � Ln O C— m a--j nu O 0 O (^.n, L W T V! �_ O U U O r- o o N O U C -] o U ' a G o c ^ N � V W O i � O a � = N 0 a16 d G m 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o c O O G G o G O G o o G G o 00 0 0 0 G N o_o 0000 0000 0 0_00000-00_ am ronmvi vri rim ommr� min are c�i �- MM a - " N c � N � � O o °a a - - < u Q U r, G 1 G] 17 o U � � r r O � LL V.I � r i 'a !, o o c a � N a 1 m o c O O O O 0 O G O ON O O G G o O v l0fl m m tv ry .- WOO • • O -I r--I i C6 � N � N 00 r-I cn � O w 4J Q) � O O E 0 Q) Q � Q) Q) L �-- U Ln O U 0 Q) L Q .F= 101 a L O Q) N D Q o a L' O Cn E E N 2 O C�0 0 D c I Ln c I �y Ia � � a iz t�J � I T ' fJ I C Cc 0CC p [�i Cp- 8 +RRJR� p4p p4p p4p pO p c� � OdOG t l) C6 U o � N O }, +_J U QO^^ or_ 0 _0 0 O 4--JO 'a O E v O 0-01 U N Ln E 4-J 4-J c c- O 4- v U tlA a i U 'L7 iA N A5 An + C N N d O C CL 4 + � � Q C C m Q L � � Ll. n o r r, JOped AJGAO:)OU CA 8 0 c 8 s rW V/ i n ] W O V) W 4 V 1 X U .N v V) 4-1 � N O E Q) T-H n� , v W W M N N N N O N m co h W N W M r�� V N � Q L N b Q L °' i E n a� cn v C h� W E O U W m N o I § I § 1 1 M G:i sw EMEMP-1 f ( ty) N i N N O CL IA 00 Q ` r ' '� N c m a 0 m L 0 i ` Y fi N t0 } LM W +� c a, o m L 00 > u p ^ a L k ! _ Lr) u N 00 8 S 8 O Od08 (1) E L.- 0 i m iq WE m • kk, a a a M, Q) c� V) Ln Q) L O v O N Q) Q) v (n Ln v Q f� E O f� z ■ un .Q) Ul Q) Ca O CL W a Q) U U Q) 0 Q QJ Q) ("6 E Q) C O Q, cn Q) f� Q) f� Q) E E ■ t0oame", • 4A _0 Q) > O Q) Q E D a U Q) v O � 0- v Q u i N _ v N � O � O N L a o � v L-r) v > >, ° O � O Q' O _ aA O o _0 a; m O Ln Q) E {�-+ v > 0 Ln m Q) N E U O Q E 4u N Ln N N cn L a) 0 U Q) L E Q) CiA O •Lp to C r • a N r • • m mm - 3 I o _ Y jo CL • J 3� — eel •' C E N u j `� a t 3• � i Fi G j � � m h m o b® cr � r , �� � Y_ • SY, �rY I i a L- • \00 00 r ry •m" H mo O 1`� ij Ir I ^c O •� •N N }, U ate-+ Ln E ro O L fY]�, E N 4— f� t/) O -� Z m Ln a aJ O 00 ? O N O c� +-J = .� (D O Q N U cc _ i U � , +, c� O N O m 4�10�0-� a) E Co a) U Q > O � QJ -0 -0 -0 u • 2 a--J — Q) •i Q f6 N O O O �+— Q} O Z O O 4-c_0 C V) U YN N Z �� V) w C7� ��� z z> IA CL 8 0 c • 0 c 44 L v 0 a) L o cn f� 0 .� 0 � U U a O O r O o M V) cn C- 4-J cn m Q X >N N L v O +-J O _v -� 0 (� > L M N C6 v Ca U 4J v w U O N O L CU a� >, 0 v o W o cu U __ .> w U CC� G Q1 E (7 Q ■ ■ ■ ■ • o m (6 aJ to ^l j i rt 1 i -0 ti C o— C, a m n z O a ti c i A V O O [ q n O O N O �� _ O Za 0 0 00 r--- Y • C O }' E E N O U N M c- 4- 0 p U O Q. v _0 _0 4- O N o ro v E v E = D c U v U QJ ` Cp > 3 aJ N � C6 M > O v ) z 4 v 4-, N Ln ° � v O � � 4-J — 2 v (A Q) v a--J 4- Ln O lD U LI ) M �- o 4-) M Fl Q) O CL O L- r) 0 0 }' E v O N U Ln Ln N M O p � N U p Q. L � o � v c� v U � U Ca QJ N CII � v (a) v •— v L 00 O +-J Ln N v L lJ'1 � N ° \ U 5 '0 v C F— 0 +-, a>J 0 z V) UO v v c- v a� Q0 Ln d' c� • r� • N N N N N U N N �-C Q) �� °� 4-' m d' N }, Ln+1 Ln L L L E Q) Q)L c- v Q) 4- Q) 4- -0 M G O- N O U +�- +-j M 0000 lD +- U M +' Ln M 0000 lD >� O Q) O c u v v U v v `(U 40- v Ln v v Ln d- N > O +� LnO _0 > c- +) d rI I� U m U m - N _ N N N O , ll,p T +� }, n' 11 W o ' n W O, ll, T T 0- +n1 W v U a) N rj C� L m n v m N" ' vCL Ln v v u v v u v c� v v v— rn v Q— C) v Ln L o > N � o > ,> +- Q) Q) U yam,. Q) Q) U 4Cl) N O N O Ln v z (A L Qm=-a o � p o ■ r f 0 O L- ro L O ,� O O a--+ E Q • - •Z5 � ro V) U > � z • _ O — c� O Ln U Q) a-' 1 •n 1� W W O �O Q ® Q) • O Ln -0 Q 4-J i Q cn QJ O Q) (3) > c� N L.. +, O v Q) 4-14-J O C ca E .N OU C6 V O Q N u Q m cv _ E Q) 4-J •Ln OU ?>> E Q U M Q) J u _ 4- � ,O u a •� a O CL � a- •� Q E 1 • .4--; E Ln N O i +-j Q) O O tA Q) � u O Q. U L a--+ O L 4-J Un u O m Ln a) � O i L� Li CL �r s 0 u 0 a T LJ • 16J. Campbell Manager, GKA Engineering & Planning Greater Kuparuk Area Development Conkc)XoPhimps May 23, 2013 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 ConocoPhillips Alaska, Inc. 700 G Street Anchorage, AK 99501 phone 907.265.6543 RE: West Sak Viscosity Reducing Water Alternating Gas Pilot Project Adn-tinistrative Approval Area Injection Order 213.044 Administrative Approval Conservation Order 406B.009 Dear Ms. Foerster: E itliAY 23 2013 Enclosed is the West Sak Viscosity Reducing Water Alternating Gas (VRWAG) Pilot Project Final Report. As per conditions described in the pilot approval document, this report was to be submitted to the Commission by May 23, 2013 and contain an evaluation of the effectiveness of the VRWAG process including an analysis comparing predicted to actual performance. Please contact Marc Jensen (265-6573) or Joe Versteeg (265-6171), if you have questions or require additional information. Sincerely, Alan J. Campbell Y Manager, GKA Engineering & Planning Greater Kuparuk Area Development cc: Wolfe, Patrick Rodgers, James Seitz, Brian ConocoPhillips WS-VRWAG Pilot Project Final Report Submitted: May 23, 2013 Prepared By: Marc ense est Sak Drillsite Petroleum Engineer Prepared By: zi J ersteeg, West Sak Reservoir Engineer 1:2- 111<' Reviewed By: Scott Redman, West Sak Reservoir Engineer Approved By: AlaA Campbell, Manag , GKA Reservoir Engineering & Planning Table of Contents 1.0 Executive Summary .................................................................................................................................2 2.0 WS-VRWAG Pilot Project Background....................................................................................................3 3.0 Project Performance, Surveillance Data, and Analysis...........................................................................5 1E-102 Pattern.......................................................................................................................................... 6 1E-102 Injection History........................................................................................................................6 1E-121 Production History and Analysis...............................................................................................7 1E-117 Pattern........................................................................................................................................10 1E-117 Injection History......................................................................................................................10 1E-170 Production History and Analysis.............................................................................................11 1J-168 Production History and Analysis..............................................................................................14 1J-170 Pattern.........................................................................................................................................17 1J-170 Injection History......................................................................................................................17 1J-166 Production History and Analysis..............................................................................................18 1J-122 Pattern.........................................................................................................................................21 1J-122 Injection History......................................................................................................................21 1J-120 Production History and Analysis..............................................................................................22 1D-141A Production History and Analysis..........................................................................................25 VRWAGPilot Performance......................................................................................................................27 OverallPerformance...........................................................................................................................27 Challenges and Lessons Learned.........................................................................................................28 ReservoirContainment.......................................................................................................................28 Operational Challenges and Lessons Learned....................................................................................28 4.0 Reservoir Simulation and Analysis........................................................................................................30 VRWAGPerformance..............................................................................................................................30 Model Calibration with History Match...................................................................................................35 AnalysisSummary ...................................................................................................................................38 5.0 Summary and Conclusions....................................................................................................................40 1 1.0 Executive Summary ConocoPhillips Alaska, Inc. (CPAI), the operator of the Kuparuk River Unit and West Sak Participating Area submits this final West Sak Viscosity Reducing Water Alternating Gas (WS-VRWAG) Pilot Project Status Report to the Alaska Oil and Gas Conservation Commission (AOGCC) as required by Area Injection Order 26.044 and Conservation Order 4066.009. The AOGCC required that the operator provide the Commission with a final report evaluating the effectiveness of the VRWAG process including an analysis comparing predicted to actual performance. Four injectors were selected for the pilot (1E-102, 1E-117, 1J-122, and 1J-170) targeting five offset producers on gas lift (1E-121, 1E-170, 1J-168, 1J-166, and 1J-120). Injector 1E-102 experienced a matrix bypass event (MBE) to offset producer 1E-121 near the beginning of the pilot which was not induced by viscosity reducing injectant (VRI). Injector 1E-102 was shut in and removed from the VRWAG pilot project. Offset producers to the 1E-102 injector did not show any significant response from the small initial VRI cycle. The WS-VRWAG Pilot Project injected hydrocarbon enriched gas for five WAG (Water Alternating Gas) cycles in one pattern at the West Sak Field 1E Drillsite and four cycles in two patterns at the 1J Drillsite. These three remaining patterns were monitored frequently for changes in gas -oil ratio, oil production rates, and produced gas sample composition. The three remaining patterns show enhanced recovery from the VRI and the pilot is considered successful. A key challenge observed during the pilot was the inability to quickly transfer from VRI injection to water. The water cycles were extended to achieve desired injection volumes. Key surveillance observations in the offset producers include: • Favorable oil response observed in most cases • Increasing GOR trends • Results of gas sample analysis show a general increase in heavier component composition when compared to the control samples taken prior to the pilot • Increased injection and withdrawal Pre -pilot simulation forecasts aligned with actual observed performance. The modeling effort was expanded after the pilot was completed with the implementation of a sector model for each pattern. The pattern models were calibrated and history matched using data from the pilot. Calibrated forecasts for continued VRWAG in West Sak indicate a potential 3-6% OOIP ultimate incremental recovery with an approximately 25% HCPV gas injection volume. • 2.0 WS-VRWAG Pilot Project Background The WS-VRWAG Pilot Project was approved by the AOGCC on 9 September 2009 and the first VRWAG cycle of the 36-month pilot began on 23 November 2009 in two of four pilot patterns. The WS-VRWAG Pilot Project premise was to inject Water Alternating Gas (WAG) cycles of enriched hydrocarbon gas into four patterns in the West Sak Field 1E Drillsite and 1.1 Drillsite over a three year period. The validity of the VRWAG process as a method of enhanced recovery for West Sak was detailed in the WS-VRWAG Pilot Project application. Simulation studies and multi -contact lab experiments demonstrated West Sak was an ideal candidate for the condensing drive mechanism associated with an immiscible flood. CPA[ forecasted an incremental recovery of 3-6% of the original oil in place in addition to the —20% waterflood recovery estimate. Four injectors were selected for the pilot (1E-102, 1E-117, 1J-122, and 1J-170) targeting five offset producers on gas lift (1E-121, 1E-170, 1J-168, 1J-166, and 1J-120). Three indirectly offset producers were monitored for potential interactions (113-101, ID-141A, and 1E-123). Table 2.1 summarizes the injector/producer well pairs including the affected injection zones. Injector/Producer Open Injector Zones Open Producer Zones 1E-102/1E-121 D Sand D and B Sands 1E-117/1E-170 D, B and A2 Sands D, B and A2 Sands 1E-117/1J-168 D, B and A2 Sands D, B and A2 Sands 1J-170/1J-166 D and A2 Sands D, B and A2 Sands 1J-122/1J-120 D, B and A2 Sands D, B and A2 Sands 1J-122/1D-141A D, B and A2 Sands D Sand The time period of VRWAG activity in the following pairs was insufficient for any interaction. 1E-102/113-101 D Sand D and B Sands 1E-102/1E-123 D Sand D and B Sands Table 2.1: Injector/producer pairs in the VRWAG pilot Oil production trends, gas production trends, and gas sample analyses were used to monitor FOR (enhanced -oil recovery) response in the production wells. The primary focus of the gas composition analysis was the change in composition with time as the patterns matured. Frequent gas sample monitoring was performed on wells 1E-170, 1J-168, 1J-166, 1J-120, and 1D-141A. Fig. 2.1 shows a field overview with the VRWAG pilot patterns outlined in red. Fig. 2.1: West Sak field overview with VRWAG pilot patterns 3.0 Project Performance, Surveillance Data, and Analysis The following sections discuss the project performance and interaction analysis for each of the pilot patterns. Changes in GOR (gas -oil ratio), oil production rates, and produced gas sample composition were used to determine whether a significant VRWAG interaction occurred in the pattern. An important indicator of VRWAG interaction is the change in C1/C3 and C1/C4 ratios. Table 3.1 lists the compositional ratios for lift gas, formation gas, and VRI. These values serve as a basis for discussion of the observed C1/C3 and C1/C4 ratio trends in each of the patterns. In general, a downward trend is expected in the compositional ratio of gas samples as a pattern matures in a VRWAG flood. Compositional Ratios C1 C3 C1 C4 Lift Gas 26 30 Solution Gas 188 170 VRI 12 5 Table 3.1: West Sak gas compositional ratios Injection pressure guidelines established for the waterflood were used to manage the VRWAG flood. The maximum operating injection pressure is defined by a previously determined maximum injection gradient for the field. As wells were switched from water to VRI, VRI injection rates were limited to 2.0 MMSCF/d until the wellbore was gas packed and a baseline operating injection pressure was established. Injection rate was then adjusted and limited by the maximum injection pressure. Injection rates vary according to geology, well configuration, and pore pressure. When the wells were converted back to produced water injection, the maximum injection gradient remained the limiting control. • • 1E-102 Pattern Fig. 3.1: 1E-102 VRWAG Pattern • Offset producers: 1E-121, 1E-123 & 113-101 • Well 1E-102 is a dual lateral injector selected for D lateral injection only —the B lateral was previously isolated due to pre -pilot matrix bypass event (MBE) • Began first VRI cycle 11/23/09 • Experienced an MBE in the D lateral on 12/29/09, 37 days after beginning VRI, and was shut-in • Removed from pilot • Restarted water injection on 8/15/11 following an MBE remediation attempt 1E-102 Injection History Injector 1E-102 experienced an MBE to offset producer 1E-121 near the beginning of the pilot; 1E-121 therefore did not see any effects of VRI. The MBE was not induced by VRI. Injector 1E-102 was shut-in at that time and removed from the remainder of the VRWAG Pilot Project. Fig. 3.2 details the injection history for injector 1E-102. Data from 1 January 2009 through 23 November 2012 is shown. Water injection rate is displayed in blue and gas injection rate in red. Similar plots are included in subsequent sections for each of the VRWAG pilot injectors. A cumulative volume of 60 MMSCF of VRI and 788 MSTB of water were injected into the 1E-102 pattern during the pilot. M. -Water Injection -Gas Injection 3000 2700 2400 2100 a 1800 CO 0 1500 V d Z 1200 d R 3 000 600 941 3000 2700 2400 2100 1800 0 U N 1500 c 0 V 1200 N CD 900 600 300 O i I I I '� h i r- 1�--i®1 1 —i +® "I h— 1®� I f--'I 4---}ul-^r 0 .O ,�o ,�O ,�O o ,�o N e^ N ,��. ,��. ,��. ^� ,�t, �ti �ti �eQ dos 'ac Fig. 3.2: Injection history for well 1E-102 Table 3.2 summarizes important well events for injector 1E-102 during the pilot. Date Event 11/29/2009 VR injection begins 12/29/2009 MBE detected to 1E-121; well shut-in 8/15/2011 Injection restart 9/3/2011 MBE remediation attempt in D sand 9/23/2012 MBE remediation attempt in B sand Table 3.2: Well events for injector 1E-102 1E-121 Production History and Analysis Fig. 3.3 details the production history for producer 1E-121. Data from 1 January 2009 through 23 November 2012 is shown. Oil production rate is displayed in green, watercut in blue, and GOR in red. To help illustrate producer -injector interaction, the chart background color of Fig. 3.3 changes according to type of injection in the offset injector. API values are also included in the plot. The subsequent sections include similar plots for each VRWAG capture producer. A cumulative of 3S6 MSTB oil, 331 MSTB water, and 398 MMSCF gas were produced from well 1E-121 during the pilot. Gas metering challenges for West Sak wells at 1E pad led to an uncharacteristically high GOR trend in the 1E-121 well. 7 • • 2000 1500 0 1400 tz 9 1200 O C 0 1000 a O 800 c 0 0 0 600 a O 400 200 0 Supportedby 1E-102 VRWAG well (no longerpert of pilot program) ---Oil Rate -GOR-Watercut • API tE-102 Gas Injection !1E-102 wale, Injection 100 90 so 70 2� m 60 a Q v C 50 d 40 3 30 20 10 0 N� NN ^, ^" �� �ti ^ti ^ti NIV NI" �aA �� �eQ �o4 Fig. 3.3: Production history for well 1E-121 Table 3.3 summarizes important well events for producer 1E-121 during the pilot. Date Event 9/27/2010 Well shut-in for downhole mechanical issues 12/29/2009 MBE detected to 1E-102 2/5/2011 Production restart 10/17/2012 Fill cleaned out of well Table 3.3: Well events for producer 1E-121 Fig. 3.4 details the indicative trends of VRWAG interaction in well 1E-121. Oil rate is shown in green and GOR in red. The square and star points on the chart represent the C1/C3 and C1/C4 ratios, respectively. The subsequent sections include similar plots for each VRWAG capture producer. 0 -Oil Rate 2000 1800 m 1600 LL U to 0 1400 r C o 1200 N r. (9 C 1000 r, 0 a O 800 CO C O u 600 0 a 400 O 200 0 O° O°' Oo 'Z , p° NZ' ,O p ,O O ,ZO NN 0 �ti ^ti �ti L L fee°� )ao �a� ��� )°� )a° erx� ��� �eQ°� Supported by 1E-102 VRWAG well —GOR ■ C1/C3 Ratio s CVC4 Ratio 1E-102 Gas hyection 1E-102 Waterinjectioa Fig. 3.4: Production, GOR and gas compositions for well 1E-121 200.0 180.0 160.0 140.0 N O r 120.0 U U 60.0 40.0 20.0 0.0 No production response was observed in well 1E-121. VR injection in the 1E-102 pattern was short lived. However, an important piece of data captured by the event was a gas compositional baseline for VRI. Low C1/C3 and C1/C4 gas compositional ratios were observed in two gas samples taken shortly after the MBE. These low values provide a benchmark for comparison with the other patterns. Ideally, the gas compositional ratio trends in VRWAG patterns will start high and trend lower to baseline values of 10 to 20 as the patterns mature. 4 0 • 1E-117 Pattern Fig. 3.5: 1E-117 VRWAG pattern • Offset producers: 1E-170, 1J-168 & 1E-166 (Possible) • Well 1E-117 is a tri-lateral injection well (A, B, and D sands) • Began first VRI cycle 11/23/09 • Completed five VRI cycles • No premature breakthrough events detected • Production response observed in 1E-170 and 1J-168 • Elevated GORs observed in 1E-170 and 1J-168 • No obvious production response seen in 1E-166 due to the isolating fault to the north 1E-117 Injection History The 1E-117 pattern is the largest pattern in the core area with injection and offtake in all three West Sak sands. It is effectively isolated by faults on all sides. These aspects made it an ideal candidate for the WS- VRWAG Pilot Project. Injector 1E-117 is the most mature VRWAG pattern in the pilot. A cumulative of 1489 MMSCF of VRI and 695 MSTB of water were injected into the 1E-117 pattern during the pilot. Fig. 3.6 details the injection history for well 1E-117. 10 -Water Injection -Gas Injection 2000 — -- -- — -- -- 5000 1800 4500 1600 4000 1400 3500 0 1200 3000 a a LL U m � G 1000 2500 O — u C O � Q B00 i u 2000 y 3 600 CD 1500 400 1000 200 500 0 _ 0 00 0o (§1 oo, og & p Np ,p Np ,p N^ ^ti ^ti ^ti . t- ^ti ,ac Fig. 3.6: Injection history for well 1E-117 Table 3.4 summarizes important well events for injector 1E-117 during the pilot. Date Event 7/28/2010 Obtained injection profile Table 3A: Important well events for 1E-117 Fig. 3.6 illustrates the injectivity improvements observed in injector 1E-117 while in VRI service. Injection rates were increased without breaching the maximum injection pressure established for the waterflood. 1E-170 Production History and Analysis Fig. 3.7 details the production history for producer 1E-170. A cumulative of 725 MSTB oil, 55 MSTB water, and 694 MMSCF gas were produced from well 1E-170 during the pilot. 11 C] 2000 1800 O 1400 o: 4 1200 c� C c 1° 1000 0 a O 00 B00 c 0 u 600 0 a` O 400 200 0 Supported by 1 E-117 VRWAG well —Oil Rate —GOR —watercut • API tE-117 Gas Injection t._. ..,1E-117 Wager Injection 60 55 50 45 T 40 m O 35 a 15 10 5 0 Fig. 3.7: Production history for well 1E-170 Table 3.5 summarizes important well events for producer 1E-170 during the pilot. Date Event 11/28/2010 Coiled tubing removed downhole hydrate 1/5/2011 Well shut in for TAPS proration 8/27/2012 Obtained temperature survey 9/26/2012 Coiled tubing removed downhole hydrate 10/18/2012 Coiled tubing removed downhole hydrate 11/11/2012 Coiled tubing performed fill cleanout in A sand Table 3.5: Important well events for well 1E-170 As noted for producer 1E-102, gas metering challenges for West Sak wells at 1E pad led to an uncharacteristically high GOR trend in the 1E-170 well. A relative decrease in watercut during the pilot was observed in well 1E-170. This behavior is typical of a maturing VRWAG pattern. Fig. 3.8 details other indicative trends of VRWAG interaction in well 1E-170. 12 • • —Oil Rate 2000 1800 O 1400 C 0 1200 r C 1000 0 a 0 n? 800 C 0 u � 600 0 1 a HM 200 0 Supportedby 1E-117VRWAG well —GOR ■ C11C3 Ratio x C1/C4 Ratio 1E-117 Gas Injection 1E-117 water Injection 200.0 180.0 160.0 (SbO� O� Cp (§� O°' 'gyp 'gyp Nllz� i� NO '�O 411 41 �111 -I^ N~ .1 r , 4 �� 0 �V 0 Fig. 3.8: Production, GOR and gas compositions for well 1E-170 140.0 y O 120.0 V 60.0 40.0 20.0 0.0 A production response was observed in producer 1E-170. The C1/C3 and C1/C4 compositional ratios trended below the baseline sample taken in November 2009. The trends observed in Figs. 3.7 and 3.8 indicate 1E-170 is seeing increased recovery from the VRWAG cycles. Another useful tool to understand and demonstrate response is an FOR response plot. The plot is constructed by time shifting the producer trends for oil and formation gas and overlaying them on the offset injection trend. Ideally, the peaks of the oil and gas rates should synchronize with the peak injection rates. Fig. 3.9 demonstrates this approach. Monthly VRI injection rates are shown as green bars for the offset injector. Monthly oil production rates for the producer are shown as a black line and formation gas rates as a gray line. A similar figure is included for each subsequent capture produce with identical axes. The time shift for this plot was three months. 13 n lei F — ------ I nu, .' ! A "I T oil --►— FGaa 2008 2009 2010 2011 2012 Fig. 3.9: 1E-117 to 1E-170 FOR time -shifted response Gas metering challenges at 1E pad make it difficult to draw conclusions from the gas production trend; however, the cyclic nature of VRWAG is observed in the oil production trend. 1 J-168 Production History and Analysis Fig. 3.10 details the production history for producer D-168. A cumulative of 847 MSTB oil, 30 MSTB water, and 778 MMSCF gas were produced from well 11-168 during the pilot. Supported by 1E-117VRWAG well —Oil Rate —GOR—Watercut • API 1E-117 Gas Injection 1E-117water Injection 2000 1800 m N 1600 LL U y rs0 1400 Q 1200 A c� v m 1000 0 a m 800 C O 3 600 9 Q a 400 200 0 ,a o°' o e S", le ' o� "I'll �a� e 13� �� ''o "I'll, ate 40 40 S 1 e6 1 o0 -1a11, ' a 40 Fig. 3.10: Production history for well 11-168 Table 3.6 summarizes important well events for producer 11-168 during the pilot. 30 28 26 24 22 20 A 16 a a 16 14 5 d 12 3 10 a 8 6 4 2 0 14 • • Date Event 12/24/2010 Coiled tubing removed downhole hydrate 1/5/2011 Well shut in for TAPS proration 1/16/2011 Coiled tubing removed downhole hydrate 1/30/2011 Coiled tubing removed downhole hydrate 5/10/2011 Coiled tubing performed fill cleanout in A sand 5/22/2012 Slickline tagged fill at 7056' RKB Table 3.6: Important well events for well 11-168 The production data for well 1J-168 shows an increasing GOR trend which is cyclic in nature. A sharp decline in oil rate was observed in September 2011 due to a suspected sand plug obstructing flow. Coiled tubing cleaned fill from the wellbore in early May 2012. This restored production to previous levels observed earlier in the pilot. Fig. 3.11 details other indicative trends of VRWAG interaction in well 1J-168. -Oil Rate 2000 1800 m t•- N 1600 LL U tN 21400 io tr 4 1200 m 0 v C 1000 0 IL m 600 C 0 :0 600 v 0 a` O 400 200 0 c4' 0 5§j e & & 0 "� 'is' ^, "� ", " '- " '- -° "1, 0 "ti �o )ac 1 a0 40 13` ' eQ ' o� lac 40 4 IS, 10 ' o, lac 40 40 13, 5° o '? IS-,,140 40 �� 10 �o Supported by 1 E-117 VRWAG well -GOR ■ C11C3 Ratio .r. CVC4 Ratio ' 1E-117 Gas Injection I 1E-117 Watertnjection Fig. 3.11: Production, GOR and gas compositions for well 11-168 200.0 180.0 160.0 140.0 0 m 120.0 U U 100.0 -0 C m M U 80.0 ;= U 60.0 40.0 20.0 0.0 The C1/C3 and C1/C4 compositional ratios indicate there may be more solution gas coming from the reservoir following the fill cleanout in early May 2012. Unfortunately, the wellbore fill suppressed reservoir performance and masked the FOR response. However, the GOR and watercut trend indicate well 1J-168 responded to VRWAG injection. Fig. 3.12 shows the time -shift plot for the interaction between injector 1E-117 and producer 1J-168. The time shift for this plot was four months. 15 2008 2009 2010 2011 ivii Fig. 3.12: 1E-117 to 11-168 FOR time -shifted response The match between the producer GOR peaks and injection volumes becomes more apparent as the pattern matures. The time -shift gas trend fits relatively well with the last three injection volumes indicating a likely response to VRWAG injection. 16 • • 1J-170 Pattern • Offset producers: 1J-166 & 1J-168 • Tri-lateral injecting to A & D sands only (B sand isolated from pre -pilot MBE to 1J-166) • Began first VRI cycle on 4/4/10 • Completed four VRI cycles • No premature breakthrough events detected • Possible production response seen in 1J-166 and 1J- 168 • Elevated GORs seen in 1J-166 and 1J-168 Fig. 3.13: U-170 VRWAG pattern 1J-170 Injection History The 1J-170 pattern was chosen to evaluate VRWAG behavior in a wellbore absent of B sand injection. The B sand was isolated when an MBE formed with offset producer 1J-166. Injector 1J-170 is fault bound to the east. Also, no significant VRWAG response in 1J-168 is attributed to injector 1J-170 because of the fault system that separates the two wells. A cumulative of 946 MMSCF of VRI and 434 MSTB of water were injected into the 1E-117 pattern during the pilot. Fig. 3.14 details the injection history for well 1J-170. 17 -water Injection --Gas Injection 2000 1800 1600 1400 d 1200 m c 1000 0 u 800 V 600 400 200 5000 4500 4000 3500 3000 0 U to 2500 0 2000 _ N R 0 1500 1000 500 ,^ e )J ' °p 19 )� �a 01 )J� 411 Fig. 3.14: Injection history for well 11-170 Table 3.7 summarizes important well events for injector 1J-170 during the pilot. Date Event 1/5/2011 Well shut in for TAPS proration 11/7/2011 Schmoo-Be-Gone treatment to enhance injectivity 12/2/2011 Temperature survey 12/9/2012 Schmoo-Be-Gone treatment to enhance injectivity Table 3.7: Important well events for well 11-170 Fig. 3.14 illustrates the injectivity improvements observed in injector 11-170 while in VRI service. Injection rates were increased without exceeding the maximum injection pressure established for the waterflood. Two injectivity enhancement treatments were pumped while the well was on water service. No significant improvement from the Schmoo-Be-Gone chemical blend was observed. Injectivity while on water decreased during the pilot. 1J-166 Production History and Analysis Fig. 3.15 details the production history for producer 1J-166. A cumulative of 1769 MSTB oil, 488 MSTB water, and 1133 MMSCF gas were produced from well 1J-166 during the pilot. M Supported by iJ-170 VRWAG well -Oil Rate -GOR-VJaterwt • AP{ ?._._-`1J-170Gas lnjec6on �..,,.��. 1J-170waterInjection 2000 1800 0 1400 0 a O m B00 C 0 u 600 0 a` `O 400 200 100 90 80 70 >, ra 60 O a a t 50 rcc u `m 40 6 3 a� 30 20 10 0 Fig. 3.15: Production history for well 11-166 Table 3.8 summarizes important well events for producer 1J-166 during the pilot. Date Event 1/8/2011 Well shut in for TAPS proration Table 3.8: Important well events for well 11-166 Increasing oil rate, increasing GOR, and decreasing watercut were observed in producer U-166. The oil rates and GOR values were somewhat cyclical suggesting VRWAG type behavior. These trends provide evidence that a VRWAG interaction was observed in 1J-166. Fig. 3.16 details other indicative trends of VRWAG interaction in well 1J-166. 19 • • -Oil Rate -GOR 2000 1800 ti 1400 O 1200 c� a ti 1000 O a O m 800 c 0 u 600 0 a` p 400 200 Supported by 1J•170 VRWAG well ■ C1lC3 Ratio J C1!C4 Ratio ' 1J-170 Gas InlecLon ':1J-170 Water Injection 200.0 180.0 160.0 140.0 0 rx 120.0 v U 100.0 c A c1 V 80.0 6 60.0 400 20.0 0 .{ --4—1-w�_+� 1 H �r �� 1 11 + I F t 1I I--t- j T' 0.0 �Saa �J\o�0°Qp °,o�) c� �a�^ �a�^o �J\No5°�^ °,moo �ac� ��`^ �a�^^ �J ^�5�^ N^ �xc^ ��`� �a��� �Jf `Oe, I wry Fig. 3.16: Production, GOR and gas compositions for well 1J-166 A production response was observed in producer 1J-166. The C1/C3 and C1/C4 compositional ratios trended below the baseline sample taken in June 2009 and continue to decrease. The trends in Figs. 3.15 and 3.16 indicate a response leading to increased recovery from the VRWAG cycles. Fig. 3.17 shows the time -shift plot for the interaction between injector 1J-170 and producer 1J-160. The time shift for this plot was two months. D MI E= B MI © A 411 Oil _` -- FOa 4000 000 000 0 C) 000 2008 2009 2010 2011 cvit Fig. 3.17: 1J-170 to 11-166 FOR time -shifted response • • The increasing gas production trend in for well 1J-166 indicates an FOR response following VRWAG injection. 1J-122 Pattern 9rt • Offset producer: 1J-120 & ID-141A • Tri-lateral injecting to A, B & D sands o - • Began first VRI cycle on 4/4/10 • Completed four full VRI cycles t • No premature breakthrough events detected 1 f/„ • Elevated GORs seen in 1J-120, but not in the 1D- 141A • Possible oil production response from FOR detected at offset producers iA WI ,. Fig. 3.18: U-122 VRWAG pattern 1J-122 Injection History Injector 1J-122 is an outboard injector supporting producer 1J-120 to the west. A cumulative of 823 MMSCF of VRI and 420 MSTB of water were injected into the 1J-120 pattern during the pilot. Fig. 3.19 details the injection history for well 1J-120. 21 U • 2000 1800 1600 1400 a 1200 [d c 1000 0 U d B00 G 3 600 C9IC 200 —Water Injection —Gas Injection 5000 4500 4000 3500 3000 a U_ U N 2500 c 0 U 2000 AL N c� 1500 i 1000 F 500 0 1- i. Ili 1 1 9--", # i--T .: 111 i. i+i-i---r—i.l .....It�t,J1.:1 ; �_,�::11—F--'-i-'.1-` _'- 0 NQO ,�O NQO NQ, NlO N N NN N- '``L '``L ^ti N ^ti NL �oQ �o4lac �a� �a� 131 Fig. 3.19: Injection history for well 1J-122 Table 3.9 summarizes important well events for injector 1J-122 during the pilot. Date Event 1/8/2011 Well shut in for TAPS proration 6/16/2011 Coiled tubing performed fill cleanout through mainbore into A sand 7/2/2011 Obtained injection profile 11/5/2011 Schmoo-Be-Gone treatment to enhance injectivity 11/11/2011 Obtained bottom hole injection pressure survey 12/9/2012 Schmoo-Be-Gone treatment to enhance injectivity Table3.9: Important well events for well 1J-122 Fig. 3.19 illustrates the injectivity improvements observed in injector 1J-122 while in VRI service. Injection rates were increased with each VRI cycle without breaching the maximum injection pressure established for the waterflood. Two injectivity enhancement treatments were pumped while the well was on water service. No significant improvement was observed. Injectivity while on water decreased during the pilot, similar behavior was observed in 1J-170. 11-120 Production History and Analysis Fig. 3.20 details the production history for producer 1J-120. A cumulative of 879 MSTB oil, 108 MSTB water, and 498 MMSCF gas were produced from well 1J-120 during the pilot. 22 2000 1800 m F N 1600 LL U ° 1400 R 1200 N m v 1000 0 a m 800 c 0 600 V 2 ILL 0 400 200 0 Supportedby 1J-122 VR"G well -Oil Rate —GOR-Waterc ut • API - U-122 Gas Injection -.- 1J-122 Water Injection 30 28 26 24 22 T 20 "> 18 a 16 c 14 5 d 12 3 10 8 6 4 2 0 �a� ,J� �eQ �o�, ,xc �a�, �a� ��� �� �'�, ,ac �a� �x� �J� �eQ �oA, Fig. 3.20: Production history for well 1J-120 Table 3.10 summarizes important well events for producer 1J-120 during the pilot. Date Event 4/19/2010 Obtained gas lift survey 9/4/2012 Obtained gas lift survey 9/13/2012 Obtained gas lift survey Table 3.10: Important well events for well 1J-120 The only encouraging trend observed in 1J-122 is the increasing GOR. Oil rate decreased relative to the pilot start. A meter calibration in early September 2012 decreased the watercut by approximately 10 percent making it difficult to determine watercut performance during the pilot. Plans for a coiled tubing deployed fill cleanout were in progress at the end of the pilot period. Fig. 3.21 details other indicative trends of VRWAG interaction in well 1J-120. 23 -Oil Rate -GOR 2000 1800 m LL 1600 U V) 0 1400 4 1200 U 4 C f6 1000 0 a O m 800 C O u 600 0 n` O 400 200 S upported by 1 J• 122 VRWAG Wei/ ■ CVC3 Ratio x. C11C4 Ratio i U-122 Gas lgecOoc 9J-122 Water lnlecLcn 200.0 180.0 160.0 140.0 0 120.0 v U tU R M U 80.0 U 60.0 40.0 20.0 0 4- I-- l --+.. --1--+ —i- —f -1-1 1 1 ! i-- 4---1 A _ -1 +1---+-4--I- +-- = f 1 11 1 0.0 10� Fig. 3.21: Production, GOR and gas compositions for well 11-120 The C1/C3 and C1/C4 compositional ratios are below the baseline sample taken in July 2009. The oil rate trend in Figs. 3.20 and 3.21 is inconclusive as to a definite VRWAG interaction between injector 1J-122 and producer 1J-120; however, the elevated GOR trend suggests gas breakthrough and a probable response. Fig. 3.22 shows the time -shift plot for the interaction between injector 1J-122 and producer 1J-120. The time shift for this plot was 3 months. — = D Nil 0 e Pii A MI Oil ""'._'" FGaa 2000 3 2008 2009 2010 2011 2012 Fig. 3.22: 11-122 to 1J-120 FOR time -shifted response 24 • 0 The same comments apply to well 1J-120 as those mentioned for well 1J-166. The time -shift for 1J-120 is not as well matched as the 1J-168 time -shift. However, there is a clear increase in gas production following VRWAG injection. The observed response is related to the relative immaturity of the 1J-120 pattern compared to the 1E-117 pattern. 1D-141A Production Histe y and Analysis Fig. 3.23 details the production history for producer 1D-141A. A cumulative of 219 MSTB oil, 21 MSTB water, and 819 MMSCF gas were produced from well 1D-141A during the pilot. 1000 900 0 'm 800 LL N_ 700 O x 600 9 N (� 'u0 r c n 0 400 a O Co c 300 u 3 9 Q 200 a O 100 0 Possibly supported by 1 J-122 VRWAG well —Oil Rate —GCR10 —Watercut • API 1J-122 Ges Injection 1J-122 Water Injection 30 28 26 24 22 10 r 8 6 4 2 0 SP Sao sec �aq ��� q0 '`° lac ' ap ' ao S l eQ ' °a sec le Fig. 3.23: Production history for well 1D-141A Table 3.11 summarizes important well events for producer 1D-141A during the pilot. Date Event 9/1/2010 Obtained gas lift survey 9/20/2010 Obtained gas lift survey Table 3.11: Important well events for well 1D-141A The fact that there was no appreciable change in production trend behavior indicates a response to VRWAG injection. There may be a late -time response as evidenced by GOR levels in September through November 2012, but more observation is necessary. Fig. 3.24 details other indicative trends of VRWAG interaction in well 1D-141A. 25 • • —Oil Rate—GOR;10 1000 900 0 m m 800 LL U y 0 700 .f Q 600 2 ii c 500 r O a m 400 c 0 2 300 -c c a 200 O 100 0 0 0 0 0 O° A O O O O IIF ' ac ' aA � 1 e 1°, Possibly supported by 1J-122 VRWAG well ■ C1fC3 Ratio .I C1iC4 Ratio iJ-122 Gas Injection ; 1J-122 water Injection .... 200.0 180.0 160.0 140.0 N O t0 120.0 U U 100.0 R M U 80.0 V 60.0 40.0 20.0 0.0 NIZ) NQ1 Fig. 3.24: Production, GOR and gas compositions for well 1D-141A No significant changes in C1/C3 and C1/C4 compositional ratios were observed from the baseline samples taken at the beginning of the pilot. There is no evidence to support a significant response to VRWAG injection in producer 1D-141A. Fig. 3.25 shows the time -shift plot for the interaction between injector 1J-122 and producer 1D-141A. The time shift for this plot was 4 months. D Mi 0 B MI A MI 'T' Oil FGo 1040 a 1I 2008 2009 2010 2011 2M Fig. 3.25: 1J-122 to ID-141A FOR time -shifted response 26 • • The time -shift match does not indicate a significant FOR response. This is most likely due to the location of producer 1D-141A relative to injector 1J-122. VRWAG Pilot Performance Some general comments apply to all the patterns regarding observations, challenges, and lessons learned during the pilot. Overall Performance Figs. 3.26 and 3.27 illustrate the gas production trends observed during the pilot. These trends do not include data from injector 1E-102 and producer 1E-121 as the pattern was not active for the majority of the pilot. Returned injectant (RI) was observed approximately one year following the start of VRI injection. A cumulative volume of 3326.7 MMSCF of VRI was injected into the three active VRWAG patterns. A cumulative volume of 1266.1 MMSF of RI was produced back. A ratio of six month average RI rates to one year average VRI injection rates is also plotted to illustrate the behavior of RI production during large and small VRI injection volumes. —Gas Produced —RI —VRI Injected —6 mo 11I/1 yr VRI 12000 — ---- — -- -- - —� 1 10800 ------- --- — -- — # 0.9 I 0.8 9600 --- ---- 0.7 8400 -- — — 0.6 7200 -- -- -- -- o 6000 - - — 0.5 4800 + ------- ---- - jjj. 0.4 fu 0.3 3600 i i _....._._ ._ .... - 0.2 0.1 1200 — 0 0 — -- PQ�~o �J\SO Date Fig. 3.26: VRWAG pilot gas production summary 27 —RI —VRI Injected —6 mo RI/1 yr VRI 3500 0.84 3000 - --- 0.72 2500 ---- ----- 0.6 LL U — - -- 0.48 o a o > oc 1500 �T. -- — ----- 0.36 a 1000 0.24 500 -- - -- - -- - -- 0.12 06A �a y PQ y �J y �L� �a PQ ��� �a , PQ O Date Fig. 3.27: VRWAG pilot cumulative gas production summary Challenges and Lessons Learned Reservoir Containment Outer annulus pressures were monitored on all wells within a quarter mile radius of the VRWAG injectors. No appreciable increase in OA pressure was observed for the duration of the pilot. Preliminary results from 4D seismic analysis show the VRI is confined to the West Sak interval in all patterns. Qualitative analysis established confinement however refinement of the data continues. Operational Challenges and Lessons Learned The inability to transfer quickly from VRI injection to water injection was an unforeseen challenge and led to the water cycles exceeding the three month injection target. This behavior highlights the injectivity changes observed in the pilot injectors. In general, a decrease in water injectivity was observed when converting the pilot injectors from gas to water. Several attempts were made to overcome this challenge by cleaning out the lateral and pumping emulsion breaker chemical. These treatments yielded mixed results when evaluating increasing injectivity in the treated injectors. However, injectivity tended to increase while on gas injection. Producer fill also hindered stable production. Sand production in West Sak wells is common and often leads to fill or blockages in the lateral completion. The blockages reduced productivity and masked the 0 • VRWAG response. Fill cleanouts using coiled tubing were an effective solution to return productivity to the wells. All VRWAG capture producers in the pilot use gas lift as the artificial lift method. Increased gas production induced by the VRWAG cycles was observed in the producers. The combination of gas lift and additional gas production increased the number of hydrating events and resulted in the affected wells being shut-in. They were returned to production following well intervention. Methanol and hot diesel pumping were effective as mitigation methods to reduce the frequency of hydrating events. Optimization continues as these observations and challenges shape the operational methods used to increase the value of VRWAG at West Sak. 29 4.0 Reservoir Simulation and Analysis VRWAG Performance The purpose of the reservoir analysis was to expand the pre -pilot modeling effort by calibrating sector simulation models for each pattern. This was accomplished through history matching the pattern models to observed reservoir performance during the VRWAG pilot period. The models have been used to project potential future performance and compare with pre -pilot forecasts. The summary that follows includes a re -cap of the pre -pilot prediction and actual performance, a summary of the history match effort, and model forecasts. Reservoir simulation models were created for the 1E-117, 1J-122, and 1J-170 VRWAG pilot patterns. The VRWAG injection wells (1E-117, 1J-122, and 1J-170), waterflood only injection wells (1J-164 and 1J- 118), and production wells (1E-170, 1J-168, 1J-166, 1J-120) are highlighted on the pattern location map in Fig. 4.1. The 1E-102 pattern was not modeled because of early removal from the pilot following an MBE. The 1E-117 pattern is ideal for evaluation since the fault interpretation indicates the area is isolated from most of the surrounding patterns and is an injection centered pattern with two offset producers. The 1J-170 VRWAG injector is parallel to a potentially bounding fault and supports the 1J-166 producer. The 1J-122 VRWAG injector is proximal to the West Sak periphery and supports the 1J-120 producer. The 1J-118 and 1J-164 waterflood only injectors also impact the performance and are converted to VRWAG injection for the forecast cases Figure 4.1 Producer IVRWAG Injector WaWLQA Injector, converted to VRWAG for prediction Fig. 4.1: Location map for VRWAG pilot patterns The pre-VRWAG pilot forecasts, as set forth in CPAI's 13 May 2009 pilot project application, for gas injection rate, water injection rate, and incremental oil rate are compared to actual rates for the pilot period in Figs. 4.2 through 4.5. CPAI expected higher gas and water injection rates than actually 30 • • observed during the pilot. Injection pressure was managed to prevent matrix bypass events and resulted in lower than expected injection. 16000 14 000 12000 10000 8000 6000 4000 2000 0 11112005 11112007 11112009 if Im11 11112013 Time, Years Fig. 4.2: Comparison of pre -pilot forecast and actual rates for gas injection 6000 7000 6 60,0000 5000 4000 3000 2000 1000 0 1/112005 11112007 1/112009 111/2011 Time, Years Fig. 4.3: Comparison of pre -pilot forecast and actual rates for water injection 111/2013 31 0 5000 4500 4000 >, 3500 a m 3000 F cn �500 2000 a 1500 1000 500 0 —Waterflood Base Forecast —Waterflood + VRWAG Actual History V V2005 11112007 11112009 1/112011 Time, Years Fig. 4.4: Comparison of projected base waterflood and actual VRWAG production 1400 1200 G H 000 600 O 400 200 0 11112005 11112007 11112009 VV2011 Time, Years 111/2013 11112013 Fig. 4.5: Comparison of the pre -pilot forecast and actual incremental VRWAG production The oil response was as expected with the variance due to multiple production well shut-in events. Fig. 4.6 shows that the variance from the oil rate forecast corresponds with the production well shut-in events. 32 400Ci 3500 3000 0 ao 2500 m 2000 1500 1000 -*--Predicted BOPD —Alai BOPD Fig. 4.6: Comparison of pre -pilot oil rate projection and actual oil rate for 1E-170, 11-120, 11-166, and U-168 A comparison of the actual total reservoir injection rate and actual water injection rate is summarized in Fig. 4.7. An increase in injection throughput observed during the VRWAG pilot is also seen in the new modeling results. Limited throughput constrains ultimate waterflood recovery in the West Sak reservoir, and the increase in throughput with gas injection during the VRWAG pilot is a positive outcome. 33 WEIIII 6000 �, 5000 m _ 4000 c w 3000 c 0 2000 H 1000 0 1111200'5 11112007 11112009 111,,12011 111120131 Time, Years Fig. 4.7: Comparison of total reservoir injection rate and water injection rate The model based oil rate forecast prior to the start of the VRWAG pilot is compared to a forecast from the post -pilot models in Figs. 4.8 and 4.9. To be consistent with the pre -pilot prediction, the 1J-118 and 1J-164 waterflood injectors were not converted to VRWAG injection for the forecast in the new models. Fig. 4.9 shows that the cumulative injection for the new pattern models was limited to the cumulative gas injection in the pre -pilot projection. The higher injection rate in the pre -pilot forecast yields an increased and more rapid oil response when compared to the new models. A longer injection period is sustained in the new models due to the lower injection rate and yields a lower magnitude oil response over a longer period of time. 34 4000 3500 3000 2500 2000 1500 1000 500 0 5112009 E412014 511f2019 4/30/2024 5/112029 511i2034 —.r— BOPD - Pre —+—BOPD -Past Fig. 4.8: Comparison of pre- and post -pilot forecast of oil rate for equivalent cumulative gas injection for the 1E-117, U-122, and iJ-170 VRWAG patterns 20, 19, 18, 17' 16, 15, a 14' 10, 7 6, 5, 4 3 2 1 00G '000-- _ 000 000 000 000 000 000- 000-- 000- 000- 000 000 OOQ 000-- 000 --'__ j 000'; 000 000 t 000 0 5/12009 '41itU14 111iLU"lV 41,VWZVZ4 a1�,cucn �v„cv.•r —6—knjedon-Pre—*-1*C§On-Po6t Fig. 4.9: Cumulative gas injection profiles for pre- and post -pilot comparison at equivalent gas injection volumes for the 1E- 117, 11-122, and 1J-170 VRWAG patterns Model Calibration with History Match The calibration of the three pattern models was accomplished through history matching to surveillance data. The history match for the three pattern models involved global and local adjustments. The local adjustments were implemented to improve the individual pattern matches. Trapped gas saturation, critical gas saturation, and relative permeability curves were global parameters that were constant 35 LJ E-I across the three models. Reservoir permeability, productivity index (PI) multipliers, lateral conformance, and injection areal allocations were adjusted locally in each of the three models. Figs. 4.10 and 4.11 are composite summaries of the water -oil -ratio (WOR) and oil rate response for three pattern models. With a cumulative gas injection volume of 25% HCPV for each of the models, Fig. 4.10 shows a 7.2 MMSTBO gross VRWAG response compared to the no gas injection case. A sustained incremental oil rate response is anticipated through the period of gas injection as summarized in Fig. 4.11. 10 1 Ct: 0.1 0.01 Figure 4.10: Three Pattern Response 1E-170, 1J-120, 1J-166 & 1J-168 Production C e 0 5000 10000 15000 20000 250002.`a0,i.z� Cumulative ON, MBO —m—Waterlood tiMWAG Pilot+ WF Prediction—+—\QWAG Fig. 4.10: Forecast WOR with cumulative oil for the three pattern models 36 • Figure 4.11: Three Pattem Response 1 E-170,1 J-120, 1 J-166 & 1 J-168 Production 5000 4500 4000 35CC, .•Ll� 0 a 2500 0 m 2000 1500 1000 500 0 1l12009 1 !I . 'D 14 1112019 l A r1024 1 A 2029 1 A P-034 .=mw,4Vate1ood --VRWAG Pilot + WF Prediction VRWAG Fig. 4.11: Forecast oil rate for the three pattern models Figs. 4.12 and 4.13 are composite summaries of the total injection throughput and recovery factor for the three pattern models. Fig. 4.12 shows a 100% increase in total injection throughput for the VRWAG process. The throughput improvement is an important factor for the increase in potential ultimate recovery expected through the VRWAG process. Figure 4.12: Three Pattern Response 1E-170,1J-120,1J-166 & 1J-168 Production 0 0 0.2 0.4 0.6 0.8 1 Total injection, Qt ■ Waterfood VRWAG POot+YVF Prediction - VRVAG Figs. 4.12: Forecast recovery factor with fraction HCPV injection for the three pattern models 37 LJ • Fig u re 4.1 T Th ree Pattern Respoin se 1E-170,1J-120,1J-166& 1J-168Production 0.3 025 n 02 t� �t 0.1 005 0 1M209 11112014 Ili12015 1N21124 MOM 11f2034 �Waterilood =VRWAG Pilot+ WF Prediction VRWAG Figs. 4.13: Forecast recovery for the three pattern models Analysis Summary In summary, results from the 1E-117, 1J-122, and 1J-170 pattern models indicate potential incremental recoveries due to VRWAG with 25% HCPV cumulative gas injection. The VRWAG process has demonstrated success in a variety of pattern conditions during the pilot period. The 1E-117 well configuration is spaced at 1500 feet between injector and producers and results in a large flood pattern. The 1J-122 pattern has relatively low throughput which further inhibits the base waterflood recovery. The 1J-170 pattern has multiple B sand MBEs resulting in the isolation of the B sand from VRWAG injection in the 1J-170 injector. For this reason, the B sand segment in the 1J-170 injector to the 11-166 producer is not included in the volume summaries. In all three of the pattern models, the potential incremental VRWAG recovery is 3-6% based on the new modeling results. The increase in throughput compared to the base waterflood case for each of the three pattern forecasts is 100% and is an important mechanism for the increase in ultimate recovery. An increase in injection throughput was observed during the VRWAG pilot period. Table 4.1 summarizes the comparison between pre- and post -pilot simulation results. There are two key facts to remember when comparing the pre- and post -pilot results. The pre -pilot results were based on four patterns (1E-102, 1E-117, 1J-122, and 1J-170). Well 1E-102 was removed from the pilot shortly after the start of VRI injection. This reduced the number of VRWAG patterns to three. Columns 2 and 3 in Table 4.1 compare the changes to pre -pilot forecasts of estimated production and injection values when 1E-102 was removed from the pilot. Additionally, the pre -pilot results maintained the 11-118 and 1J-164 injectors as waterflood only injectors. The post -pilot simulation forecasts include these as VRI injectors. 38 This more accurately estimates the VRWAG potential within these patterns. Columns 4 and 5 in Table 4.1 compare the expected benefit of converting the 1J-118 and 1J-164 injectors to VRWAG service. The "4 Pattern, 4 WAG Injectors, Pre -Pilot Forecast" case in column 2 of Table 4.1 includes the 1E-102 injector which was later removed from the VRWAG pilot. The "3 Pattern, 3 WAG Injectors, Pre -Pilot Forecast" in column 3 of Table 4.1 is the updated pre -pilot forecast excluding the 1E-102 injection pattern. The "3 Pattern, 3 WAG Injectors, Post -Pilot Forecast" case in column 4 of Table 4.1 is the post - pilot forecast for the 3 injection wells that were included in the scope of the pilot. The "3 Pattern, 5 WAG Injectors, Post -Pilot Forecast" case in column 5 of Table 4.1 is another post -pilot forecast that includes the conversion of the 1J-118 and 1J-164 injectors to VRWAG. These two injectors were not included in the VRWAG pilot. Description 4 Pattern 3 Pattern 3 Pattern 3 Pattern (4 WAG Injectors) (3 WAG Injectors) (3 WAG Injectors) (5 WAG Injectors) Pre -Pilot Forecast Pre -Pilot Forecast Post -Pilot Forecast Post -Pilot Forecast End Date 12/31/2035 12/31/2035 12/31/2035 12/31/2035 HPV 108.2 99.1 97.7 145.2 Bo 1.06 1.06 1.06 1.06 COW P 102.1 93.5 92.2 137.0 Bg 0.75 0.75 0.75 0.75 Bw 1.01 1.01 1.01 1.01 aver. rt�� Cum Oil Production, MMSTB 25.0 22.7 26.7 29.0 Cum Gas Production, BSCF 22.5 20.8 34.6 47.0 Cum Water Production, MMSTB 35.3 31.4 9.0 9.0 Cum Gas Injection, BSCF 18.7 17.5 34.2 50.0 Cum Water Injection, MMSTB 57.9 51.9 19.2 30.4 Oil Recovery Factor, 0/6001P 24.5% 24.3% 29.0% 21.1% Gas Injection, HPVi 13.0% 13.3% 26.2% 25.8% Water Injection, HPVi 54.0% 52.9% 19.8% 21.10/( Total Injection, HPVi 67.0% 66.2% 46.1% 47.0% wF Cn� Cum Oil Production, MMSTB 20.6 18.8 21.7 21.8 Cum Gas Production, BSCF 6.4 5.7 6.7 6.7 Cum Water Production, MMSTB 30.9 28.3 8.4 8.4 Cum Gas Injection, BSCF 0.0 0.0 0 0.0 Cum Water Injection, MMSTB 52.3 47.8 19.7 30.6 Oil Recovery Factor, %pOIP 20.2% 20.1% 23.5% 15.9% Gas Injection, HPVi 0.0% 0.0% 0.0% 0.0% Water Injection, HPVi 48.8% 48.7% 20.4% 21.3% Total Injection, HPVi 48.8% 48.7% 20.4% 21.3% Incremental FOR Cum Oil Production, MMSTB 4.4 3.9 5.0 7.2 Cum Gas Production, BSCF 16.0 15.2 27.9 40.3 Cum Water Production, MMSTB 4.4 3.1 0.6 0.5 Cum Gas Injection, BSCF 18.7 17.5 34.2 50.0 Cum Water Injection, MMSTB 5.6 4.1 -0.5 -0.2 Oil Recovery Factor, °/a001P 4.3% 4.2% 5.4% 5.2% Gas Injection, HPVi 13.0% 13.3% 26.2% 25.8% Water Injection, HPVi 5.2% 4.1% -0.5% -0.1% Total Injection, HPVi 18.2% 17.4% 25.7% 25.7% Table 4.1: Pre- and post -pilot forecast summary 39 5.0 Summary and Conclusions The VRWAG Pilot Project was successfully completed at the 1E and 1.1 drillsites. In general, improved oil, gas, and water responses were observed in the offset producers indicating FOR response due to VRWAG injection. The analysis of the VRWAG pilot data demonstrated that the positive results observed during the pilot period were successfully replicated in pattern simulation results. The new modeling results from the history matched simulations indicate a potential, nominal 3-6% incremental recovery for VRWAG at 25% HCPV cumulative gas injection. The positive results illustrated in this report demonstrate the effectiveness of the WS-VRWAG Pilot Project. The incorporation of this process into the development plan for the West Sak field has the potential to nominally increase ultimate recovery beyond base waterflood management. CPAI is evaluating the possibility of expanding the WS-VRWAG project and will submit an application for an amendment to the Area Injection Order should CPAI and the working interest owners determine expansion is prudent. 40 0 / i 9 0 [A L[ LA 2 T nA SEAN PARNELL, GOVERNOR ALASSA OIL AND GAS / 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 CONSERVATION COMMISSION J PHONE (907) 279-1433 FAX (907)276-7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 2B.044 ADMINISTRATIVE APPROVAL CONSERVATION ORDER 406B.009 David Jamieson Supervisor, Reservoir Engineering Greater Kuparuk Area Development ConocoPhillips Alaska, Inc. 700 G Street Anchorage, AK 99501 Dear Mr. Jamieson: ConocoPhillips Alaska, Inc. (CPAI), by letter dated May 13, 2009 (VRWAG Application), requested the Alaska Oil and Gas Conservation Commission (Commission) administratively amend Area Injection Order (AIO) 2B and Conservation Order (CO) 406B to authorize a Viscosity Reducing Water Alternating Gas (VRWAG) pilot project in a portion of the West Sak Oil Pool (WSOP) in the Kuparuk River Unit (KRU). The Commission hereby authorizes CPAI to conduct the pilot VRWAG project described in the VRWAG Application with the conditions specified below. The very large, shallow, and viscous West Sak oil accumulation is contained within several discrete sands. Early development attempts mainly utilized near -vertical producers and injectors, but multi -lateral wells that target individual sands using long, horizontal wellbores have proven to be the most effective means of recovering West Sak oil. Waterflooding is the primary enhanced oil recovery (EOR) method to date and combined with primary recovery is estimated to be capable of recovering approximately 20% of the original oil in place. A prior, small-scale FOR pilot project in the WSOP was attempted and showed some promise. The VRWAG pilot project was developed to explore additional methods to improve FOR recovery from the WSOP. The proposed VRWAG pilot project will utilize four multi -lateral wells —each having at least two horizontal laterals —that are currently serving as water injectors at KRU Drill Sites 1 E and IJ. The injectors are offset by horizontal producers completed in the same sands and thus would create a line drive injection pattern. The proposed plan calls for alternating water and gas injection (WAG) cycles of three months apiece for a total of 36 months (six cycles each of water and gas injection). Laboratory analysis and reservoir simulation work indicate that a VRWAG process should provide substantial increases in oil recovery. Gas injected as part of the VRWAG process provides two benefits over water injection alone to increase oil recovery. First, viscosity of the fluid in the reservoir will decrease, making the oil more mobile. Second, the oil in the reservoir will swell, increasing oil saturation and allowing some of the swollen oil to flow to the production David Jamieson September 10, 2009 Page 2 of 4 wells. The amount of viscosity reduction and oil swelling is a factor of the richness of the injection gas. The richer the injection gas, the greater both effects will be, and the higher recovery will be. Laboratory results indicate that, at current reservoir conditions and with the gas expected to be available for the VRWAG pilot project, oil viscosity could be reduced by over 80% and oil volume could swell by more than 5%. The estimated incremental oil recovery in the VRWAG pilot project area due to these two effects is 4% of the original oil in place, or roughly 4 million barrels in the proposed project area. hnjecting energized and highly mobile fluids such as gas increases the potential for pressure communication or leakage that might not be evident while injecting water. As such, competent sealing strata and good mechanical integrity for all wells in the proposed VRWAG pilot project area are critical. Current water injection operations are being conducted at or above formation parting pressure, and there has been no indication that these activities have breached any confining intervals. Additionally, fracture stimulations have been performed in the West Sak at pressures much greater than would ever occur during WAG operations, and these have not shown any evidence of fractures induced from these activities propagating through the confining lavers. These factors indicate that injected fluids will remain within the intended intervals. The mechanical integrity of the injection and surrounding wells will be evaluated when the operator applies to convert a water injection well to WAG service. Rule 9 of AIO 2B provides that: "Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water." Rule 14 of CO 406B provides that: "Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the confining zone." The VRWAG Application demonstrates that the above criteria for administrative approval have been met. Therefore, the Commission authorizes CPAI to conduct the VRWAG pilot project as described in the VRWAG Application, with the following conditions: 1) This authorization expires 36 months after the commencement of gas injection activities, or 24 months after the date this order is entered if gas injection activities are not commenced by that time. 2) The VRWAG pilot project must be conducted in accordance with the plan described in the VRWAG Application (attached and incorporated into this administrative approval by reference) and all applicable regulations. No changes may be made to the plan without prior approval of the Commission. 3) The operator must notify the Commission at least 10 days before beginning the VRWAG injection program, 4) Prior to commencement of gas injection activities, the operator must submit an Application for Sundry Approvals (Commission Form 10-403) for each proposed VRWAG injection well and obtain approval from the Commission as to the mechanical David Jamieson • September 10, 2009 Page 3 of 4 integrity of the proposed injection well and the nearby wells to ensure there are no conduits that would allow injected fluids to escape from the intended interval. S) By September 30t° of each year, beginning in 2010, the operator must provide to the Commission a, report on the status of the VRWAG pilot project. The reporting period shall be July I ' through June 30'h of the preceding year. The report shall include: a. a discussion of project performance and achievements during the reporting period, b. injection performance and FOR response, c. an analysis of any special monitoring or testing completed during the reporting period; d. a discussion of any matrix -bypass events occurring during the reporting period and what steps were or will be taken to address these events; and e. any other technical issues or anomalies observed during the reporting period. b) Within 6 months of the completion of the VRWAG pilot project, the operator must submit to the Commission a report evaluating the effectiveness of the VRWAG process and comparing actual to predicted performance. 7) Any expansion of the pilot project shall require the issuance of a new area injection order after the opportunity for public comment and hearing. 8) If there is any indication of pressure communication or leakage in a pilot VRWAG injection well, the operator must immediately 1) discontinue gas injection in that well, and 2) notify the Commission. 9) If there is any evidence of repressurization of annuli in wells offsetting the VRWAG injectors, gas injection must be discontinued in all VRWAG injectors that could potentially be the source of the repressurization. If the source well(s) can not be readily identified, the operator must immediately cease all gas injection authorized by this administrative approval. The operator must notify the Commission that gas injection has been discontinued. 10) VRWAG injection in any well shut in under condition 8 or 9 above may not be recommenced without prior Commission review and approval. ENTERED at Anchorage, Alaska, and da David Jamieson • September 10, 2009 Page 4 of TION 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. railure 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), " Itjhc 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. • Conocophillips May 13, 2009 Daniel T. Seamount, Jr., Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, #100 Anchorage, Alaska 99501-3539 ".'livid P. Jamieson Supervisor, Reservoir Engineering Greater Kuparuk Area Development ConocoPhillips Alaska, Inc. 700 G Street Anchorage, AK 99501 Phone 907.265.6543 RECEIVED MAY Y 4 2009 Alaska Oil & Gas Cons. Commission Anchorage RE: West Sak Viscosity Reducing Water Alternating Gas Pilot Project Administrative Action Application Dear Mr. Seamount: Enclosed is the West Sak Viscosity Reducing Water Alternating Gas (VRWAG) Pilot Project Application for Administrative Action under Area Injection Order No. 2B (Rule 9) and Conservation Order No. 406 (Rule 13). The application was also prepared in accordance with 20 AAC 25.450 (Underground Injection Control Variances). ConocoPhillips Alaska, Inc., in its capacity as Operator of the Kuparuk River Unit and the West Sak Participating Area, seeks Alaska Oil and Gas Conservation Commission endorsement and authorization for the proposed project. Please contact R. Scott Redman (263-4514), Chris Pierson (265-6112), or Bowen Roberts (265-6040) if you have questions or require additional information. Sincerely, David Jamies Supervisor, Reservoir Engineering Greater Kuparuk Area Development cc: King, Warwick Roberts, Bowen Seitz, Brian Rodgers, James ConocoPhillips WEST SAK. DSlE &DSlj VRWAG PILOT PROJECT APPLICATION FOR ADMINISTRATIVE ACTION FOR INJECTION OF ENRICHED HYDROCARBON GAS 0 SECTION A - INTRODUCTION ConocoPhillips Alaska, Inc., in its capacity as Operator of the Kuparuk River Unit and the West Sak Participating Area, hereby applies for Alaska Oil and Gas Conservation Commission ("Commission") administrative action, under Area Injection Order No. 2B (Rule 9) and Conservation Order No. 406 (Rule 13), to inject an enriched hydrocarbon gas in the West Sak Oil Pool at Drill Sites 1E ("DS-1E") and 1J ("DS- 1J") for the purposes of demonstrating the viability of a Viscosity Reducing Water -Alternating -Gas ("V'RWAG") enhanced oil recovery project in the West Sak Oil Pool. This project is referred to herein as the West Sak VRWAG ("DVS-VRWAG") Pilot Project. This application has also been prepared in accordance with 20 AAC 25.450(b) (Underground Injection Control Variances). The West Sak Oil Pool injection and production startup was achieved in December 1997, The original development consisted of vertical injectors and producers in a 5-spot pattern configuration on nominal 40- acre spacing. Because of low, injectivity and productivity, caused in part by high oil viscosity, producer and injector designs have evolved to long, horizontal wells. The current development includes production and water injection wells drilled from drill sites 1B, 1C, 1D, 1E and 1J. As of December 31, 2008, 55 water injectors and 55 producers were in service. First production from DS-1E began in July, 2004 and from DS-1J in October, 2005. Produced water from the Kuparuk Central Processing Facility (CPF)-1 is currently used for the West Sak waterflood. The West Sak production is commingled with Kuparuk Pool produced fluids at the respective drill sites and ultimately processed at CPF-1. West Sak oil production is currently about 20,000 STB/Day. The WS-VRWAG Pilot Project is an expansion of the current development plan for the West Sak Reservoir with potential to significantly increase the recovery of oil from that pool. Thus, the Kuparuk and West Sak Working Interest Owners have approved an enriched hydrocarbon gas FOR project at DS-1E and DS-1J, using Kuparuk River Unit existing enriched hydrocarbon gas. Facility modifications have been installed on DS-1E and DS-1J to include the West Sak wells slated for such service. Planned startup for enriched hydrocarbon gas injection is the third quarter of 2009. The WS-VRWAG Pilot Project will initially target gas injection into the following four patterns: 1E-102: Dual Lateral Injector (D Sand Open to Injection) 1E-117: Tri Lateral Injector (D, B and A Sands Open to Injection) 1J-170: Tri Lateral Injector (D and A Sands Open to Injection) 1J-122: Tri Lateral Injector (D, B and A Sands Open to Injection) Incremental oil recovery from the WS-VRWAG Pilot Project is expected to be about 4% of the Original Oil in Place (OOIP) of 102 MMSTBO, resulting in 4.0 MMSTB of additional West Sak oil recovery. The WS-VRWAG Pilot Project is expected to require, from KRU, a maximum annual average gas injection rate of 5 to 10 MMSCF/D of enriched hydrocarbon gas. Additional WS-VRWAG Pilot Project details are addressed in Section B through Section M. West Sak VRWAG Pilot Project Administrative Action Application SECTION B - PLOT OF PROJECT AREA Exhibit B1 is a plot showing the proposed VRWAG Pilot Project boundaries. The boundaries of the West Sak Participating Area ("WSPA") and the proposed WS-VRWAG Pilot Project area are also displayed and are wholly within the Kuparuk River Unit. Exhibit B-2 is a plot showing the locations of all existing injection wells,'/, mile buffer zones around the injection wells, production wells, abandoned wells, dry holes, and any other wellbores that penetrate the injection zone within the WS-VRWAG Pilot Project in the West Sak Oil Pool. Exhibit B-3 specifies the corners of the boundary of the proposed WS-VRWAG Pilot Project area. Exhibit B-4 specifies the quarter sections wholly or partially in the VRWAG Pilot Project area. The current West Sak water injectors and potential enriched hydrocarbon gas injector locations impacted as part of the WS-VRWAG Pilot Project are identified in Exhibit B-5. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. West Sak VRWAG Pilot Project Administrative Action Application • SECTION C - OPERATOR & SURFACE OWNERS 20 AAC 25.402(C)(2) The WS-VRWAG Project is targeting the West Sak Oil Pool, which is within the Kuparuk River Unit/West Sak Participating Area (WSPA) and is operated by ConocoPhillips Alaska, Inc. The surface owners within one -quarter of a mile radius of the proposed injection area are listed in the following table.. Surface Owners: State of Alaska Department of Natural Resources Division of Oil and Gas Attention: Ms. Temple Davidson 550 West Seventh Avenue, Suite 800 Anchorage, Alaska 99501 Kuparuk Transportation Company (ADL402294) Attention: Mr. Bill Sargent P.O. Box 100360 Anchorage, AK 99510-0360 West Sak VRWAG Pilot Project Administrative Action Application 0 • SECTION D - AFFIDAVIT 20 AAC 25.402(C)(3) Exhibit D-1 is an affidavit showing that the operators and surface owners within a one -quarter mile radius of the proposed injection area have been provided a copy of this application for injection and .Area Injection Order No. 2B. West Sak VRWAG Pilot Project Administrative Action Application SECTION E — PROJECT DESCRIPTION Enhanced recovery injection wells are used for the introduction of additional fluids into the reservoir to increase the ultimate recovery of oil. Currently at DS-1E and DS-1J, one type of injection well is in operation at West Sak Oil Pool; these wells inject produced water providing pressure support to the reservoir. As of December 31, 2008, 7 water injectors and G producers were in service at DS-lE and 14 water injectors and 17 producers were in service at DS-1J. Produced water from CPF-1 is used for the West Sak waterflood. The two West Sak producing drillsites, DS-1E and DS-1J, have production, water injection, and gas lift facilities in place, in conjunction with existing Kuparuk Participating Area ("KPA") facilities. Exhibit E-1 identifies the objectives, injection wells, scope, schedule, and the data gathering surveillance programs for each of the four injection wells of the WS-VR\X/AG Pilot Project. Implementation of the WS- VR)X/AG Pilot Project involves converting 4 existing water injectors to VRXX/AG service. The four patterns all contain offset production wells in gas lift service with packers and surface casing. Enriched hydrocarbon gas and water will be injected into the West Sak injectors in a VRWAG process. The enriched hydrocarbon gas will be manufactured and supplied from the existing CPF-1 KRU enriched gas hydrocarbon injection facility. DS-1E and DS-1J both have injection lines from CPF-1 and on pad injection facilities for the 4 VR%X/AG injectors. West Sak VRWAG Pilot Project Administrative Action Application SECTION F - POOL DESCRIPTION 20 AAC 25.402(C)(5) The D, B, & A -sand intervals of the West Sak Formation, within the Kuparuk River Unit, will be affected by the WS-SSEOR Project. The West Sak Pool is defined by Rule 2 of Conservation Order No. 406 as the strata that are common to, and correlate with, the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 Well between the depths of 3,742 and 4,156 feet, measured depth. Exhibit F-1 shows a type log of the WS-VRWAG Pilot Project area. West Sak VRWAG Pilot Project Administrative Action Application SECTION G -FORMATION GEOLOGY The D, B, and A -sand intervals of the West Sak Formation, within the Kuparuk River Unit, will be affected by the WS-VRWAG Pilot Project. The West Sak Pool is defined by Rule 2 of Conservation Order No. 406 as the strata that are common to, and correlate with, the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 Well between the depths of 3,742 and 4,156 feet, measured depth. The type log is that provided in Area Injection Order No. 2B and is derived from a wellbore within the WS- VRWAG Pilot Project area. West Sak VRWAG Pilot Project Administrative Action Application • • SECTION H - INJECTION WELL CASING DESCRIPTION Currently, 55 water injectors are in service in the West Sak Oil Pool. At DS-1E and DS-1J, there are sit and fourteen injectors, respectively. API casing specifications are included on each drilling permit application. All casing is cemented in accordance with 20 AAC 25.52(b) and tested in accordance with 20 AAC 25.030(g) when completed. In wells converted to injection, the casing is retested in accordance with 20 ACC 25.412(c). In newly drilled wells, the casing is pressure tested in accordance to 20 AAC 25.030(g). The casing pressure annulus is then monitored on a daily basis and recorded by the drill site operator. Injection well tubing sizes in the West Sak Oil Pool injectors may be either 3-1/2" or 4-1/2", with the most common size being a 4-1/2" tubing string. All West Sak water injection wells are completed with L-80 grade steel. Injection wells within the WS-VRWAG Pilot Project area utilize casing designs as detailed below. Exhibits H-1 and H-4 show typical wellbore schematics for the four basic completion designs. The casing program used for injection wells within the WS-VRWAG Pilot Project utilizes three strings of casing: 1E-102 (see Exhibit H-1) 1. 20", 94 lb casing from surface to 80 ft measured depth; 2. 10-3/4", 45.5 lb casing from surface to 3186 ft measured depth; 3. 7-5/8", 29.7 lb casing from surface to a measured depth of 6498 ft. 4. 4-1/2", 12.6 lb slotted liner from top of West Sak Formation to TD. 5. 4-1/2", 12.6 lb tubing from surface to 4-1/2" liner. 1E-117 (see Exhibit H-2) 1. 20", 94 lb casing from surface to 80 ft measured depth; 2. 13-3/8", 68 lb casing from surface to 4537 ft measured depth; 3. 9-5/8", 40 lb casing from surface to a measured depth of 10,572 feet. 4. 5-1/2", 15.5 lb liner from top of West Sak Formation to TD. 5. 4-1/2", 12.6 lb tubing from surface to 5-1/2" liner. West Sak VRWAG Pilot Project 9 Administrative Action Application 1J-122 (see Exhibit 14-3) 1. 20", 94 lb casing from surface to 80 ft measured depth; 2. 13-3/8", 68 lb casing from surface to 3640 ft measured depth; 3. 9-5/8", 40 lb casing from surface to a measured depth of 11,928 feet. 4. 5-1/2", 15.5 lb liner from top of `jest Sak Formation to TD. 5. 4-1/2", 12.6 lb tubing from surface to 5-1/2" liner. 1 J-170 (see Exhibits H-4) 1. 20", 94 lb casing from surface to 108 ft measured depth; 2. 10-3/4", 45.5 lb casing from surface to a measured depth of 3041 ft. 3. 7-5/8", 29.7 lb casing from surface to a measured depth of 11,928 feet. 4. 4-1/2", 11.6 lb slotted liner from top of West Sak Formation to TD. 5. 4-1/2", 12.6 lb tubing from surface to 4-1/2" liner. West Sak VRWAG Pilot Project 10 Administrative Action Application SECTION I — INJECTION FLUIDS The WS-VRWAG Pilot Project will initially use existing KRU enriched hydrocarbon gas from CPF-1 and CPI~-2 and be managed in conjunction with the existing KRU FOR patterns. The expected enriched hydrocarbon gas composition is shown in Exhibit I-1. The pilot could move to a leaner gas injection blend based on changes in Kuparuk WAG injectors at 11) and 1E and future NGL imports from Prudhoe. The WS-VRWAG Pilot Project is expected to inject 5 to 10 MMSCF/D of enriched hydrocarbon gas into the West Sak reservoir. Produced water is currently used for the West Sak waterflood. The WS-VRWAG Pilot Project will involve water injection alternating with enriched hydrocarbon gas injection to improve the enriched hydrocarbon injectant sweep in the reservoir. Injection fluid information pertaining to the WS-VRWAG Pilot Project is given below. Type of Fluid: Kuparuk lean gas to KRU enriched hydrocarbon gas injectant. Composition Of Fluid: See Exhibit 1-1. Source Of .Fluid: KRU lean gas enriched writh KRU indigenous NGLs and imported NGLs from Prudhoe Bay. Estimated Maximum Gas Injection: 5 to 10 million standard cubic feet per day. Compatibility With Formation And Confining Zones: Enriched hydrocarbon gas injected into the West Sak Oil Pool will be manufactured at CPF-1 and CPF-2 according to the specifications of KRU Large Scale FOR Project. Given that the hydrocarbon components in the injectant are also found in the West Sak crude oil at a lower concentration, no compatibility problems between the enriched hydrocarbon gas and the minerals in the formation are anticipated. West Sak VRWAG Pilot Project 11 Administrative Action Application SECTION J — INJECTION PRESSURES The estimated wellhead and bottomhole injection pressures for the WS-VR%yv'AG Pilot Project are listed in the follo«dng table. Estimated Wellhead Pressure Estimated Bottomhole (PS G Pressure PSIG Injection Type Average Range Average Range West Sak Water Injection 750 500-1000 2,300 2,050-2,550 West Sak Enriched 2,050 1,700-2,400 2,300 1,950-2,650 Hydrocarbon Gas Injection West Sak VRWAG Pilot Project 12 Administrative Action Application • 0 SECTION K - FRACTURE INFORMATION The estimated maximum injection rates for the WS-VRXX7AG Pilot Project wells will not initiate or propagate fractures through the confining strata and, therefore, will not allow injection or formation fluid to enter any freshwater strata. There are no indications of injection out of zone for the current water injectors at West Sak. Existing water injection operations in the West Sak Oil Pool have been at or above formation parting pressure to improve recovery of oil. In no instance have such injection pressures breached the integrity of the confining zone. The West Sak Formation is overlain by a 100-140 foot thick mudstone and clay formation (K13 Shale). This confining sequence tends to behave as a plastic medium and can be expected to contain significantly higher pressures than the West Sak formation sandstones. Extensive fracture testing confirmed that even at bottom hole pressures significantly above the initial parting pressure, the fluids continued to be confined by a relatively thin (-15-20 ft) shale/mudstone interval, provided that an adequate casing cement bond is present. All injectors that are currently online have had a cement bond log to confirm adequate cement isolation between the West Sak formation and the above strata prior to commencing water injection service. Fracture stimulation data from the West Sak Formation indicate a fracture gradient of between 0.6 and 0.7 psi/ft under initial reservoir conditions. Proppant injection pressures as high as 7,000 psig (about 2.0 psi/ft injection gradient) showed no fracture growth across any confining shale zones. In addition, long-term water injection above 0.9 psi/ft in the West Sak sands tend to part the formation horizontally, rather than fracture vertically, thus keeping all injection fluids within the intended interval. The West Sak Formation in the DS-1E and DS-1J area is underlain by the Colville Group, a sequence of impermeable inter -bedded mudstones and shales over 1000 feet in thickness. The Colville Group lithologies have similar confining properties as the overlaying K13 Shale sequence, and no injection or fracture propagation below the West Sak is anticipated. West Sak VRWAG Pilot Project 13 Administrative Action Application 0 SECTION L — HYDROCARBON RECOVERY The proposed VR-WAG process consists of the injection of enriched hydrocarbon gas into a nearly - saturated oil reservoir alternated with the injection of water. Injection of enriched gas results in a modification of reservoir oil that promotes improved recovery (b), swelling the oil and reducing oil viscosity) and provides energy and drive mechanisms to force the oil to a production well. VR-WAG is an enhanced oil recovery method. Reservoir simulation studies and Iaboratory testing under field conditions have verified that recovery can be substantially increased when compared to the injection of water alone. This method is not appropriate for all applications, but has been proven effective where the following conditions prevail: 1) The crude oil -in -place is sufficiently viscous that it leaves behind an abnormally high residual oil saturation to waterflood; 2) The injected gas can significantly swell the oil and reduce the viscosity of the oil in place. Three multi -contact experiments were performed on D Sand oil samples from West Sak Pilot Well 8I at a Commercial Laboratory (Westport). The first experiment used composition of Viscosity Reducing Injectant (" VRI"} injection gas shown in Exhibit L-1 and the experiment was run at 1600 psig and 74 deg F, which are representative reservoir conditions for the VRWAG Pilot Project. The second and third experiments used West Sak solution gas, which has a composition shown in Exhibit L-1. Laboratory tests on West Sak 8I D Sand showed that multiple gas contacts can significantly improve West Sak oil properties at reservoir conditions. In the first experiment, enriched gas condensed into the oil and increased the amount of gas in solution from 191 scf/stb to 515 scf/stb over four contacts. Adding additional gas into the crude oil affects oil properties in two ways: 1) It significantly reduces the viscosity of the crude oiL When gas in solution increases from 191 to 515 scf/STB, laboratory test show that oil viscosity at reservoir conditions decreases from 60 to 10 centipoises. This is an 83% reduction compared to the initial oil viscosity (See Exhibit L-2). 2) It causes the reservoir oil to swell. The specific oil volume increases from 1.10 cc/g with 191 scf/STB dissolved in the oil up to 1.17 cc/g when the oil contains 515 scf/STB. This is a >% increase over the initial oil volume (see Exhibit L-3). This oil swelling increases the oil saturation in the reservoir, which allows some of the swollen oil to flow to the production wells and increases the recovery factor in the proposed water -alternating -gas process. The laboratory experiments were simulated with an existing 15 component equation of state (EOS) for West Sak. The original viscosity prediction for West Sak 8I D Sand oil was adjusted to match experimental initial oil viscosity. After this adjustment, the tuned Equation of State accurately predicted the experimental viscosity decrease with multiple gas contacts for West Sak 8I D Sand oil (see Exhibit L-2) and the increase in specific oil volume with multiple gas contacts (see Exhibit L-3). Four multi -contact EOS predictions were made for the WSP 8I D sand oil and four alternative gas compositions: 100% Methane (0% C2+), West Sak Solution Gas (4% C2+), Kuparuk Lean Gas (16% C2+), West Sak VRWAG Pilot Project 14 Administrative Action Application • VRI (22% C2+), VRIx2 (28% C2+), and KRU MI (34% C2+). The viscosity reduction increases with increasing hydrocarbon enrichment (see Exhibit L-2). The specific oil volume increase is also larger with increasing hydrocarbon enrichment (see Exhibit L-3). Additional numerical simulations have been used to estimate the incremental oil recovery expected from implementing the VR-WAG process in the West Sak reservoir. This simulation employed a finely-gridded, three-ditr►ensional geostatistical representation of the West Sak stratigraphy, which has been used extensively to predict waterflood recovery. This simulation employed a fully compositional representation of the properties of the reservoir and injected fluids. Results for the West Sak D Sand oil recovery versus time are shown in Exhibit L-4 and for oil recovery versus hydrocarbon pore volume of gas and water injection are shown in Exhibit L-5. The type pattern model recoveries shown have been multiplied by a 67% de -rate factor to account for reservoir conformance, matrix bypass events and throughput uncertainties. The incremental oil recoveries increased from 3% to 6% COIP as the Enriched Fluid loading increased from 0 BBL/MSCF of gas injectant for the CPF-1 Lean Gas Composition to 150 BBL/MSCF for the Kuparuk Miscible Injectant composition (Exhibits I-1 shows gas compositions and L-6 shows incremental oil recovery as the Enriched loading increased from 0 to 150 BBL/MSCF). Current West Sak operations at DS-lE and DS-1J involve pattern waterflooding, which is expected to yield an estimated total oil recovery of approximately 15% to 20% OOIP in the West Sak Oil Pool. The planned WS-VRWAG Pilot Project is estimated to nominally increase oil recovery by an additional 4.0 MMSTB of oil, or approximately 4% OOIP of the targeted oil column at DS-1E and DS-1J, based on a total enriched hydrocarbon gas injection of 20% of the area's hydrocarbon pore volume (see Exhibits L-6). West Sak VRWAG Pilot Project 15 Administrative Action Application SECTION M — CONFINEMENT IN OFFSET WELLS The wells within, and in close proximity, of the WS-VRWAG Pilot Project area are shown in Exhibit B-2. To the best of ConocoPhillips Alaska Inc.'s knowledge, the wells within the area were constructed, and where applicable, abandoned to prevent the movement of fluids into freshwater sources. The WS-VRWAG Pilot: Project area was selected to ensure the injection of fluid into the West Sak Formation would not result in an increased risk of fluid movement into underground sources of drinking water or other hydrocarbon bearing formations. The initial selection criterion included an evaluation of the drilling and completion of all West Sak, Kuparuk and exploration wells in the proposed DS-1E and DS-1) area. Wells were evaluated for initial cement placement information, cement tops and cement integrity data, including bond logs. A further evaluation of all the mechanical integrity tests of the injection wells was then conducted, and all problem wells were also excluded. Exhibit M-1 provides details on the mechanical integrity of all wells within'/. mile of the injectors in WS- VRVIAG Area I (defined in Exhibit B-1). Summaries of the mechanical integrity of the four injection wells and the offset wells within '/+ mile of the injectors for the VRWAG Pilot Project are provided in Exhibits M- 2 to M-5. West Sak VRWAG Pilot Project 16 Administrative Action Application LIST OF EXHIBITS B-1 PLOT OF THE WEST SAK — VRWAG PILOT PROJECT B - 2 PLOT OF THE WEST SAK — VRWAG INJECTION WELLS B - 3 WEST SAK VRWAG PILOT PROJECT AREA B - 4 WEST SAK VRWAG PILOT PROJECT - QUARTER SECTIONS WHOLLY OR PARTIALLY IN THE PROJECT AREA B-5 PROPOSED WEST SAK VRWAG INJECTION WELLS D-1 AFFIDAVIT E-1 PROJECT OBJECTIVES, SCOPE AND SCHEDULE F-1 WEST SAK TYPE LOG H-1 1E-102 DUAL LATERAL INJECTOR H-2 1E-117 TRI LATERAL INJECTOR H-3 1J-122 TRI LATERAL INJECTOR H-4 1J-170 TRI LATERAL INJECTOR I-1 VISCOSITY REDUCING INJECTANT COMPOSITIONS L-1 MULTICONTACT EXPERIMENT — VISCOSITY VS NUMBER OF GAS CONTACTS L-2 MULTICONTACT EXPERIMENT — DENSITY VS NUMBER OF GAS CONTACTS L-3 1E-102 D SAND TYPE PATTERN MODEL — RECOVERY VS TIME L-4 1E-102 D SAND TYPE PATTERN MODEL — RECOVERY VS HPVI OF TOTAL INJECTION L-5 WEST SAK VRWAG PILOT PROJECT — PRODUCTION AND INJECTION FORECASTS West Sak VRWAG Pilot Project 17 Administrative Action Application LIST OF EXHIBITS (CONTINUED) M-1 WEST SAK VRWAG PILOT PROJECT — CONFINEMENT IN OFFSET WELLS M-2 WEST SAK VRWAGG PILOT PROJECT — INJECTOR 1.E-102 M-3 WEST SAK VRWAG PILOT PROJECT — INJECTOR 1E-117 M-4 'WEST SAK VRWAG PILOT PROJECT — INJECTOR 1J-170 M-5 WEST SAK VRWAG PILOT PROJECT — INJECTOR 1J-122 West Sak VRWAG Pilot Project 18 Administrative Action Application EY.HIBITB-1: PLOT OFTHE WEST SAK- VRWAG PILOT PROJECT EXHIBIT B-2: PLOT OF TFiE VIEEST SAK - VR%I G PILOT 1NJEC'I'ION WEI.I.S Log ond _ f WS Horizontal Producer — WS Horizontal Injector J — WS Deviated Well Other KRU Well R - / —WS Major Fault —WS Faults •Sp• F 1 � \ y .,�4" `� R Producer SI Producer �i, p �� � $ `9 # . Injector P and A ��<. `• , 114 mi buffer zone ED WS PA Boundary • a'k. rp ; e Drills#e Boundary r1. N J Ao cis os m • EXHIBIT B-3: \'iTs,r SAK VRWAG PILOT PROJECT' AREA AREA X - ASP4 NAD83 Y - ASP4 NAD83 1 E-102 Area 1693038 5974932 1 E-102 Area 169K10 5975134 1E-102 Area 1694416 5975153 1 E-102 Area 1695601 5969768 1E-102 Area 1694828 5969655 1E-102 Area 1694847 5968807 1E-102 Area 1694602 5968411 1E-102 Area 1694413 5967976 1E-102 Area 1694131 5966658 1E-102 Area 1693509 5964133 1E-102 Area 1693056 5962324 1E-102 Area 1693038 5962079 1 E-102 Area 1690023 5962663 1 E-102 Area 1690438 5964434 1E-102 Area 1691418 5968166 1 E-102 Area 1692134 5973330 1 E-102 Area 1693038 5973330 1 E-102 Area 1693038 5974932 1E-117 170 Area 1690757 5952922 1 E-117 170 Area 1 M48 5953236 1 E-117 170 Area 1696949 5943992 1E-117 170 Area 1690791 5943774 1E-117 170 Area 1690826 5951206 1E-117 170 Area 1690767 5952922 1J-122 Area 1704570 5955664 1J-122 Area 1707586 5955705 1J-122 Area 1707752 5945270 1J-122 Area 1704528 5945187 1J-122 Area 1704694 5946468 1 J-122 Area 1704611 5948369 1J-122 Area 1704487 5952916 1J-122 Area 1704446 5954196 1J-122 Area 1704570 5955664 EXHIBIT B-4: N'RWAG PILOT PROJECT - QUARTER SECTIONS WHOLLY OR PARTIALLY IN THE PROJECT AREA Area Meridian Township Range sectioli portion 1 E-102 Area Umiat 11N 10E 3 Ail 1 E-102 ,area Umiat 11N 10E 10 Alt 1 E-102 Area Umiat 11N 10E 15 N 112 1 E-102 Area Umiat 11N 10E 16 NE 1/4 1E-117 170 Area Umiat 11N 10E 26 W 1/2 1 E-117i_170 Area Umiat 11N 10E 27 Ali 1 E-117 170 Area Umiat 11N 10E 34 Ail I E-117^170 Area Umiat 11N 10E 35 W 1/2 U-122 Area Umiat 11N 10E 24 SE 1/4 1J-122 Area Umiat 11N 10E 25 E 1/2 1,1122 Area Umiat 11N 10E 36 E 1/2 U-122 Area Umiat 11N 11 E 19 SW 1/4 U-122 Area Umiat 11N 11 E 30 W 1/2 U 122 Area Umiat 11N 11 E 31 W 1/2 EXHIBIT B-5: PROPOSED WEST SAK-VRXY.-kG INJECTION WELLS Proposed WS-VRWAG Injectors 1E-102 — Dual Lateral Horizontal Injector 1E-170 — Tri Lateral Horizontal Injector 1J-122 — Tri Lateral Horizontal Injector 1J-170 — Tri Lateral Horizontal Injector EXHIBIT D-1: AFFIDAVIT STATE OF ALASKA THIRD J UDICIAI, DISTRICT I, David P. Jameson, declare and affirm as follows: 1. I am the Supervisor of Greater Kuparuk Area Satellite Development for Coriocoph liips Alaska, Inc., the designated operator of the Kuparuk River Unit, and as such have responsibility for West Sak operations_ 2. On c& 13 , 2009, I caused copies of the Application for Injection and Area Injection Order No. 2B with regard to the West Sak Viscosity Reducing Water Alternating Gas Pilot Project in the West Sak Oil Pool to be provided to the following surface owners and operators of all land within a quarter -mile radius of the proposed injection areas: Operator: ConocoPhilhps Alaska, Inc. Attention: Mr. David P. Jamieson P.O. Box 100360 Anchorage, AK 99510-0360 State of Alaska Department Of Natural Resources Division of Oil and Gas Attention: Ms Temple Davidson 550 West Seventh Avenue, Suite 800 Anchorage, Alaska 99501 Kuparuk Transportation Company P.O. Box 100360 Anchorage, AK 99510-0360 Dated:CLA. 2009. i `���o" elf: LIC Davi J eson 20 Declared and affirmed before me this l-& day of /t ' 12009. G4J/ otaq Public in and for Alaska My commission Expires: Exhibit E-1 — VRWAG PILOT PROJECT SCOPE, SCHEDULE, AND SURVEILLANCE DATA Objectives • Determine initial gas breakthrough times for horizontal injectors. Injection • 1E-102, 1E-117, 1J-122 and 1J-170 (existing wells). Well(s) . Currently active water injection wells in the West Sak Oil Pool waterflood project. • 1E-102 is a D-sand only injector • 1 E-117 and 1J 122 are D/B/A2 sand horizontal injectors. • 1J-170 is a D/A-sand horizontal injector Scope • Injection of gas injection into 1E-102, 1E-117, 1J-122 and 1J-170 for a nominal period of three months. • Upon completion of gas injection place 1E-102, 1E-117, 1J-122 and 1J-170 on water injection for a nominal period of three months. • Repeat the process for an additional five gas and five water cycles. • Expected total volume of gas and water injected per well is 1700 MMSCF and 550 MBW, respectively, over 36 months. Expected Schedule M 102/IEE-117 • Start up of first VRWAG cycle in 2Ad Qtr 2009. • Complete last VFWAG cycle in January 2012. IJ-122/1f--170 • Start up of first VRWAG cycle in 3" Qtr 2009. • Complete last VRWAG cycle in January 2012. • Completion of objectives by April 2012. Surveillance Injection Wells Data • Injection rates — Daily • Wellhead injection pressures - Daily Offset Production Wells • Well test (total liquid production, watercut, gas production) — twice monthly * I,� � c rA .PO" ,�o b' PC pa O o AD - ON AVd t�aaar _ 4 A CL. In n < uiui m- .- to j N N N a3ddn N 01OZON3D Sn030V13id0 aissranr Y 4 aoNanoas 03SH1fUl10lftVi� NON3n03S NVINOONB NVIH3WS3l13 o HI y ma`s CD J CD 777777%iiiiii j £ 4 = E t Z O O ? 4 Y J � y Cw C-4 x Ix t i � N E l: 00 in Ir u o rapt ok�Ll vw 5 �"m jn«M H 1'1 pp Q Q �.171 G Cg ii Fc u a E0o e 9 xJ= V Z :t m G 1v° Q G'ti J 1 Ap XIE ^ C-4 i'f 1"n 7k ao °i C 4 i j�ys9 CD o ^ � 7i • M `i p [ d L' p 12$ dNQ S 2.4 R Vi 2 .o f't Q� ;t F = o o a " • R g� sF O V CA i. • • 0 03 C7 o � :a W ,. NMt-O V Ot-r(0C) 00t*-O �crir(PO v MNCOrO)Cot'- OOO V` R O 0 a) (O U) N (C) e- N t- CD C) O O CL a z a 0 0 0 0 0 0 0 0 o a o 0-!Z 0 0 0 N O(o(orr (DCl) t-ttC*)LOr 000 {L'NN(DvC) 3>M000OMOOOOO Q ► G7+ ci r� O co •-- �t O C) Ci C7 C) O O r .>Y col tz s�s� C8 U (D z 0 0 o a o o o 0 0 0 0 0 0 0 0 l-^ U > s- (D M 00 �t{} CD Co v r M r C) CD C).� MNOCA OMC�Cn►C7NOOOOO w CD i- 00 00 tt) s- N O O O C) C3 C) C) C) d3 �! V 042, w V��-e.R�eR R����� o 0 0( 0 0 0 0 0 0 C- 0 0 0 �C) Qw U 0 3r OCC)CQOOh-C')O)OONOOO c Qr"T(o(00)I-Mf-W0r 0000 �+ -tOr CM cr 66C6 cidOOOO � �+ roc. co C t~ a A. Cp o 0 0 0 0 0 CAt- r-U')0 N 0 W MM 0000 �Mr-T��f` N r~' C+ a 11NNOOOOOO V. cow t�C�)orC;oc000000 Q o tsocn = o a)r w am+ 'o H L ) to 0 c°i 4 (u F c N to 0 w 0 N N 0 N N 0 N N 0 c a c c c c c c a c c c .� 0 cnwwcv UMM(2mmm( w8 0 W m N V O d lu m C? z� Z .._ cn.t1 II C c � z�N r; E tU � W N ;E N c U x ui i V � to O o � M o � m 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N�- O(O0)Ot.-00ONt`t-000 O C ttf (V (p I` r- t[) M to e- N N O 0 0 C) O- CV COOc6OOOOOOU66ci066 E � v O O cc U p a� 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o >LOONCOOr-'14NON�tOOOO OC co C) oD Un C) It 0 (O to N 0 0 0 0 0 p e- 6 oi (6 r' c6 6 6 6 0 0 0 6 0tl-0 0 U O � UZZ O ; O > co C N N O N tv O N O N U) N N N Y -�G N Q C C C C C C C C C C C C m m is cts c� ca m 2 m m m w m m cn Co U o W 0 m m0v 0� �?4 u n z g CL.� a.a== c 0 z -r-: (V is MOM M m M 00 00 U)VJ cn � ca t0 0 to U _ C cn E CO c o M .M m J mmR1 0Cu C U) �!"WOMLL—EWWWW X�ddLL �3:U »Y3�?,>S 00ff E.4* W do `I4ISOOSIA 110 Loa 7 0 A J cncn c c 00 on M tii CO U N VzNzN� 0 E G G� JOO ' m N m c U) CCco co 00 C r (na�L<�n u cancan >>Y��� rn (0 N co 0 0 0 co 6 0 owB `lC1isuap Rio 0 m w TT 0 c> un m CNI x E — c (D > > T ca (Q cg (!) 2 N LL N Q LE i N > � N O d T d T Y N 0 N N O to O % `JO;De.4 /JOAO*alj v M 0 C _ � 7 _X ir > N N Y U) ]G co Y r LL U ~S CZ Y 11111 r = > a > 0 c o Q o O O OAS C M/ •- Y tQ to � � C1 N O O CV m O to O CN r r t!) O �/o 'Jo;:)e:j fJaAODaa 7 f,ea 91s `oxa Dorm 1 1 1 1 1 1 91Sr4OSLAJ `dOJ kc) O � � O 6f o $ .Y, Q Ix O O O f V I C7 V O N tD o W) Kra dOSW 141PU SMJ r-+ w � 9� 6 C-T O U � y NPi NN �� O NP 'tW U� I�t3 LT. 0 z S" rrz'� i� ^z U U P- V rt1'i ti H (D t` n to L7 w (D Q L7 t- L7 Q (D (D V) t- (D mL-)F- O 00000 0 0 0 0 0 0 0 0 0 0 0 o z o 0 o Z 0 0 0 0 o 0 0 0 c o o 0 0 0 N N Q N N N N N N N N N N N N N N U a ` O N `7 (` LJ 0 r V Z N O tD ` N �V N h C) N N N (.D m O r N r Q d. J FC- t� 0 er- tD 6 O O N Ica N X) C M(Dv0Lr) 0)0Mv co co M V 0C) t�QQ .�.+ C ,2N (D N N L7 CO (O t` (D Co u ) CO a, M N M L7 t\ (D (n cc Co (D M 1- (.0 Z Z N N L7 M t- M V t- (J LO N L7 LO V (O d U � U Q O 0 0 Q Q CD )n Q Q Q f� L7 O Lo Q O C = Z Z ON OO t- z Z (D 'M z Z Z O M Z c) d. d M V N M tD V )O M V .N E t2 U F- 0 00C)aa CD 00 ON < 0¢Q c m (fl(o -zz U-) cov zz oo"IIzz vzz v U Ma) co n v o L7 M Un 0 U o F- •fJ 'o M CO a CO v '0 M M C c M M a M M _> O In O O O D U O O U O O U U Q) a� U U 00 U U a s o o C`J r- o o m m 0 0 0 0 U ai4 zz z zz zz zz a1 t0 N Ln LO M t- r (D (D M r (D O n O N N Q) (D t` L7 CC)O r o t` N r t` 41 tl r t0 M M .--_ N (n (t7 L7 C) M N t� ' n () co co Q) N '- to to V LO to (n M t- 0 (D M V O J O (O (O (O (O 1c a)rnrn () t0 (O V V v rnrna)a)rnrna) v (n v v rnrnaic v v (n a)rnrn vi LO ui LO LO Lo (ri LO LO LO (ci to U') tri to to (ri LO ui a) LO O (D V n r to r a) t- N V;; Cl) LO N CD co a) Cl) Cl) N a) (O v a) t` (") N (() to to U a) a) M tl- M M (D (D W V O Cl N '` P) h .- tD Q) N V N M O N V (O V) V) (D to V V O J Q) a) a) a) a) (D (:) t0 (D (D r a) a) O a) a7 O C) t? (D (D (D td (7 (O .= . .= _ O a) O O () (D (D (D O O O t-- t- n X t- (D (D W N 0) 0) co M V N a) V CD V LO Z Q M (D (D (() a) V CD h t- N t� O N O (D O O O L7 (O O L' M V N N cl N r V to V 'V'_ tD tD (D F_ > M co co M M m M M M M M M Cl) Cl) Cl) M Cl) Cl) E 0- jrO O LL a) N CO CO t0 V V n M M o r CO 0 Lf) O )n Z O 0 O t- V v 0 O a f c0 a0 m M O O c0 (.a M M ca t� V M n V (D tXJ V N )n O. a) V (D N N to to V V to V O LO V O W 0 M (D f\ N (O 0 to t` Q al �O O I N ci a) a) (1) 0) 0) 4) 0) a) a) a) d N N 4) O 0 a) N QQQQQ QCQCQQd QQQQ dQQ fl. c A � Q ~ `o `o `o `o 0 0 u u o>> u o 0 j o L) L) m uuuav uuaaua� uuaa uaa d o d o 0 a)d o o d o X 0 0 0 0 0 0 0 �fLL �a`a =a`w �a`a` i5, (L O Y -VY co 0 m Y Y Y Y Y Y (0 Y Y Y Y Y d Y 2 2(n(n m m O m 2 (n0(nto0(n (a m Y W wU) to ca (0 .Y onto 2 LL N M M N N m OL n N N fN N M fn N V) M Y) a i I!) t0 Cl m (D 0 0 0 a) 0 0 0 i m 0 0 a) !v OOON I—'- ID (D h_(OD COON nOO(OD NN "- rOCD wcnmchw a wwww-�-;� �r r -;w,=, r CV7 -;-;o t-rrrr rrr--r- • :7 �i E .Z7 C N m C v `t U 0 -O � a� U Q a) C �_ C E u O � N (Z m = �_ S 3 � a) Q CL N S� l� Q. a) v a O d LL O . E,O E u 1 O u) C] O +A_+' N tCi � N � U} ND `GN T • C o T T r W L11 COO m OW T r U T ci .O O O E a� O -W 0 0 1 co C3 m i� O co T w E .O c O ca .�c = U a) N CD -S v- O O a) O N u Ri C N C CD O � > V E N a) CL O c a) a a) > O a) a) i N ,� N N v a) C 7FD C a) CM �O F— D r- r- W 4. 0 a� rn c V � � 0 tci5 t� 0 t4 v v CL u m Q 111=VVV u V L 'a C 5 -0 '� N T p -J -J ..6 0 o W w E a;coai c� Q c 'c Q� o o 0 —" s Vo -Y .V w V c 0 cYa N 0 0 cry w to 0 cq 0 m 0 ••+ a.+ O Z. ` 0 L *Fm Y 'S E S S n C OD M O pa 0- N c CN C C CD : GDFn t • c T If- • r • di Co Lb Lb W W `:3 1J..i70 „a C� • a C_ LO -C LO ' N N U � 0 U -C N N � -� C a C w m N Q1 M U U a C Q d _ a (�/� _ .� a 0) 0 (N Q L a C � r C C a E C a L ...+ .._1 .a) c L w V/ a y-- 0 Q) U .� 3 L i2 tCL Q. c� N � �— o N ♦.► C .s] • cm • �t M N �— ' r r rn c U a U 'a Q C_ #5 0 0 CPAI Supplement to Request for Amendments CO 406B & AIO 213 April 22, 2014 Page 1 of 6 James T. Rodgers Manager, GKA Development North Slope Operations and Development ConocoPhillips ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage, AK 99501 phone 907.263.4027 April 22, 2014 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission APR 2 3 2014 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 OGCC RE: Request to Amend Conservation Order No. 406B and Area Injection Order No. 213: Request to Expand the West Sak Oil Pool Request to Expand VRWAG Project in West Sak Oil Pool Kuparuk River Field North Slope, Alaska Dear Ms. Foerster: ConocoPhillips Alaska, Inc. ("ConocoPhillips') respectfully submits this letter to supplement its request presented to the Alaska Oil and Gas Conservation Commission (`AOGCC") to modify Conservation Order No. 406E and Area Injection Order No. 2B dated January 30, 2013. This letter and the accompanying materials supplement the request with respect to the following topics: • Section C: Operators & Surface Owners. On April 21, 2014, ConocoPhillips also provided a copy of the application to the North Slope Borough. Please find attached a revised list of operators and surface owners. • Section D: Please find attached an affidavit confirming that ConocoPhillips provided the North Slope Borough a copy of the application on April 21, 2014, • An alternate proposed rule for VRWAG for AIO 2B. A copy of this proposed rule is attached. The AOGCC's consideration of this additional submission is appreciated. Please contact Marc Jensen (265-6573) or Scott Redman (263-4514), if you have questions or require additional information. Sincerely, d iJ es T. Rodgers anager, GKA Development North Slope Operations and Development cc: Wolfe, Patrick Campbell, Alan Seitz, Brian 0 • CPAI Supplement to Request for Amendments CO 406B & AIO 213 April 22, 2014 Page 2 of 6 SECTION C — OPERATOR & SURFACE OWNERS 20 AAC 25.402(c)(2) ConocoPhillips Alaska, Inc. is the designated operator of the West Sak PA and NEWS PA. The surface owners and operators within one -quarter mile radius of the proposed injection area are listed below. Surface Owners: North Slope Borough Planning and Community Services Dept Attention: Rhoda Ahmaogak, Director P.O. Box 69 Barrow, AK 99723 State of Alaska Department Of Natural Resources Division of Oil and Gas Attention: Mr. Bill Barron, Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 99501-3557 Operators: 70 & 148 LLC 1421 Blake Street Denver, CO 80202 ASRC Exploration LLC 3900 C Street, Ste. 801 Anchorage, AK 99503 AVCG LLC Land Department 510 L Street, Suite 601 Anchorage, AK 99501 BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Chevron U.S.A. Inc. 1029 West 3rd Ave., Ste. 150 Anchorage, AK 99501-1972 Eni US Operating Co. Inc. 1201 Louisianna, Suite 3500 Houston, TX 77002 Great Bear Petroleum Ventures I, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 Great Bear Petroleum Ventures Il, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 Daniel K. Donkel 2000 North Atlantic, Ave. 6th Floor Daytona Beach, FL 32118 Repsol E&P USA Inc. 2001 Timberloch PI., Ste, 3000 The Woodlands, TX 77380 • • CPAI Supplement to Request for Amendments CO 406B & AIO 2B April 22, 2014 Page 3 of 6 SECTION D — AFFIDAVIT 20 AAC 25.402(c)(3) Exhibit D-1 is an affidavit showing that the operators and surface owners within a one -quarter mile radius of the proposed injection area have been provided a copy of this application for modification to AIO 2B. CPAI Supplement to Request for Amendments CO 406B & AIO 213 April 22, 2014 Page 4 of 6 EXHIBIT D-1: AFFIDAVIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, James T. Rodgers, declare and affirm as follows: 1. 1 am the Greater Kuparuk Area Satellite Development Manager for ConocoPhillips Alaska, Inc., the designated operator of the Kuparuk River Unit, and as such have responsibility for West Sak operations. 2. On January 301h, 2014, 1 caused copies of the West Sak Area Injection Order Amendment Application to be provided to the following surface owners and operators of all land within a quarter -mile radius of the proposed injection areas: Surface Owners: State of Alaska Department Of Natural Resources Division of Oil and Gas Attention: Mr. Bill Barron, Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 99501-3557 Operators: 70 & 148 LLC 1421 Blake Street Denver, CO 80202 ASRC Exploration LLC 3900 C Street, Ste. 801 Anchorage, AK 99503 AVCG LLC Land Department 510 L Street, Suite 601 Anchorage, AK 99501 BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Chevron U.S.A. Inc. 1029 West 3rd Ave., Ste. 150 Anchorage, AK 99501-1972 Eni US Operating Co. Inc. 1201 Louisianna, Suite 3500 Houston, TX 77002 ExxonMobil Alaska Production Inc. P. O. Box 196601 Anchorage, AK 99519-601 Great Bear Petroleum Ventures I, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 Great Bear Petroleum Ventures 11, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 Daniel K. Donkel 2000 North Atlantic, Ave. 6th Floor Daytona Beach, FL 32118 Repsol E&P USA Inc. 2001 Timberloch PI., Ste. 3000 The Woodlands, TX 77380 3. Additionally, on April 215t, 2014, 1 caused copies of the West Sak Area Injection Order Amendment Application to be provided to the following surface owners and operators of all land within a quarter -mile radius of the proposed injection areas: Surface Owners: North Slope Borough Planning and Community Services Dept. Attention: Rhoda Ahmaogak, Director P.O. Box 69 Barrow, AK 99723 • 0 CPAI Supplement to Request for Amendments CO 406B & AIO 2B April 22, 2014 Page 5 of 6 _ Dated: r, 2— 2014. v James T. Rodgers i Declared and affirmed before me this day of /7 ii 2014. ��``� Notary Public in and for Alaska ,�.�.••''"• ti � -/� Zvi a'�:• My commission Expires: /D S NOTARY °. PUB r4, � s' ;,r ®F �` ��,�.� CPA[ Supplement to Request fore endments CO 406B & AIO 2B April 22, 2014 Page 6 of 6 Attachment 5: Proposed changes to AIO 2B AIO 2B Rule 1. Authorized Injection Strata for Enhanced Recovery Current: "Within the affected area, non -hazardous fluids may be injected for the purposes of pressure maintenance and enhanced oil recovery into strata defined as those strata which correlate with the strata found in the ARCO West Sak River State Well No. 1 between the measured depths of 3145 feet and 3640 feet-,3744 feet and 4040 feet; 4591 feet and 5324 feet; and 6474 feet and 6880 feet." Proposed: "Within the affected area; non -hazardous fluids may be injected for the purposes of pressure maintenance and enhanced oil recovery into strata defined as those strata which correlate with the strata found in the ARCO West Sak River State Well No. 1 between the measured depths of 3145 feet and 3552 feet; 3552 feet and 4156 feet; 4591 feet and 5324 feet; and 6474 feet and 6880 feet." Proposed New Rules relating to VRWAG in the West Sak Oil Pool: "VRWAG is authorized in the West Sak Oil Pool; VRWAG must be conducted in accordance with the process described in the VRWAG Application (attached and incorporated into this Area Injection Order by reference) and all applicable regulations." "Prior to commencement of VRWAG gas injection activities in an injection well recompleted in the Schrader Bluff N Sand, the operator must submit an Application for Sundry Approvals (Commission Form 10-403). #4 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Thursday, April 17, 2014 4:32 PM To: Colombie, Jody J (DOA) Subject: FW: West Sak AIO Amendment Application Jody, Please add this to docket CO 14-003 instead of what I sent you earlier. Thanks, Dave Roby (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). it may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it io you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.gov. From: Roby, David S (DOA) Sent: Thursday, April 17, 2014 4:31 PM To: 'Jensen, Marc D' Subject: RE: West Sak AIO Amendment Application Marc, Ok, sounds good. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.gov. From: Jensen, Marc D [mailto:Marc. D.JensenC@conocophillips.com] Sent: Thursday, April 17, 2014 4:26 PM To: Roby, David S (DOA) Subject: RE: West Sak AIO Amendment Application Dave, The intent is for current water injection wells being converted to WAG service. Newly drilled wells will follow the established permitting and sundry process. Additionally, no producer conversions are anticipated at this time. • • I will make sure this is clearly stated in our testimony. Regards, Marc Jensen West Sak Drillsite Petroleum Engineer 907-265-6573 Erona� Roby, David S (DOA) [mailto:dave.roby(a>alaska.gov] Sent: Thursday, April 17, 2014 3:54 PM To: Jensen, Marc D Subject: [EXTERNAL]RE: West Sak AIO Amendment Application Marc, Can you clarify what you mean by "new VRWAG injectors"? Do you mean newly drilled wells, producers converted to VRWAG injector, and/or water injector wells convert to VRWAG service? The reason I ask is that the sundry waiver matrix that covers KRU West Sak operations has different requirements for different types of wells. For example it requires a 403 and 404 for converting a producer to an injector but only requires a 404 for converting a WINJ well to WAG service. I just want to make sure your proposal will not be counter to the existing rules, or if it is counter you provide adequate justification for why West Sak should be treated differently. Regards, Dave Roby (907) 793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.aov. From: Jensen, Marc D [mailto: Marc. D.Jensen@conocophillips.com] Sent: Thursday, April 17, 2014 3:25 PM To: Roby, David S (DOA) Subject: West Sak AIO Amendment Application Dave, I wanted to notify you ahead of the hearing next week regarding a proposed change to the application. In the application, we propose to submit an Application for Sundries Approval (Form 10-403) for new VRWAG injectors. Our well integrity group noted this is inconsistent with similar WAG injectors at Kuparuk. To maintain consistency with current unit operations, we plan to amend the application to propose the submission of a Report of Sundry Well Operations (Form 10-404) instead of Form 10-403. The same level of detail will be part of the review process. This review process will be discussed as part of our testimony. I was unable to reach you by phone today, but felt this was an important detail to provide to you. Please contact me if you have any questions or concerns. Thanks, Marc Jensen 0 West Sak Drillsite Petroleum Engineer ConocoPhillips Alaska, Inc. 907-265-6573 1 marc.d.lensen@conocophillips.com #3 • • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing ConocoPhillips Alaska, Inc. Docket No CO 14-003 April 1, 2014 at 9:00 a.m. NAME AFFILIATION Testify (yes or no) Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, March 17, 2014 8:34 AM To: 'Jensen, Marc D' Subject: RE AOGCC Hearing Marc, I have checked with the Commissioners and their calendars and April 23ra at gam works fine. There is no need for you to show up on April lrl at gam. Commissioner Seamount will go on the record for calendaring purposes only and continue it. Thank you Again! Jodp J. Colombie Special StaffAssistan: Alaska Oil and Gas Conservation Commission _33.3 West 71h Avenue Anchorage, Alaska 99301 Jodu. Colombie(a�laska. gov Office: (907) 793-1221 Fax. (907) 276-7542 From: Jensen, Marc D fmailto:Marc.D.Jensen0conocophillips.com) Sent: Thursday, March 13, 2014 1:56 PM To: Colombie, Jody J (DOA) Subject: AOGCC Hearing Jody, As per our phone conversation, one or more of the technical team will be unavailable from April 2"d through April 16tn. We can accommodate any date the following week, April 21St through April 25t'; however, we prefer to schedule it on April 23rd. Please let me know if you have any questions or concerns. Thanks, Marc Jensen West Sak Drillsite Petroleum Engineer ConocoPhillips Alaska, Inc. 907-265-6573 1 marc.d.*ensen(@conocophillips.com #2 • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: West Sak Oil Pool, Kuparuk River Field Proposed Amendment of Pool Rules and Area Injection Order ConocoPhillips Alaska Inc., by application dated January 30, 2014, has requested that Conservation Order No. 406B and Area Injection Order No. 213, which establishes rules governing development of the West Sak Oil Pool, Kuparuk River Field, be amended to expand the West Sak Oil Pool and authorize the expansion of the Viscosity Reducing Water Alternating Gas Project from a pilot project to a full field development. The AOGCC has tentatively scheduled a public hearing on this application for April 1, `h 2014 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be fled with the AOGCC no later than 4:30 p.m. on March 18, 2014. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after March 20, 2014. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 71h Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on March 27, 2014, except that, if a hearing is held, comments must be received no later than the conclusion of the April 1, 2014 hearing. 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 March 25, 2014. Cathy P. Foerster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRE F AOGCC R 333 W 7th Ave, Ste 100 D Anchorage, AK 99501 M o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 0 NOTICE TO PUBLISHER 0 ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A �-� A "ZC AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF A J ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AGENCY CONTACT Jody Colombie PHONE DATE OF A.O. February 28, 2014 PCN 7 —1221 DATES ADVERTISEMENT REQUIRED: ASAP THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement Legal® ❑ Display Classified ❑Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE I AOGCC, 333 W. 7th Ave., Suite 100 TO Anchorage, AK 99501 REF TYPE NUMBER AMOUNT 1 VEN 2 ARD 02910 FIN AMOUNT sY CC PGM 14 02140100 PAGE t OF I TOTAL OF 2 PAGES ALL PAGES LC ACCT FY I NMR DIST 73451 02-902 (Rev. 3/94P Publisher/Original Copies: Department Fiscal, Department, Receiving AOTRM 270227 • .RECEIVED 0000930895 $ 209.18 MAR 1 12014 AFFIDAVIT OF PUBLICATION AOGCC 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 March 01, 2014 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed ZJ?q1[r&4JUk- F '-V Subscribed and sworn to before me this 3rd day of March, 2014 f Notary Pu lic in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES .Nonct:Of SI A7 L 0T kLASK,1 Ala k, Oil and teas Con seave4ion Commission Re: West Sak Oil Pool, Kuparuk River Field Proposed Amendment of Pool Rules and Area Injection Order ConocoPhiliips Alaska Inc., by application dated January 30, 2014, has requested that Conservation Order No. 406E and Area Injection order No. 26, which establishes rules governing development of the West Sak Oil Pool, Kuparuk River Field, be amended to expand the West Sak Oil Pool and authorize the expansion of the Viscosity Reducing Water Alternating Gas Project from a pilot project to a full field development. The. AOGCC has tentatively scheduled a public heariniggI on this Conservation ationcation orcommission,il 4att 333 West atthe eAlaska Avenue, Oslo and as Anchorage, Alaska 9950100, 1. To request that the tentatively scheduled hearing be held, a written request must be filed with the AO lie ed later than 4:30 p.m. on March 18, 2014.no I` a request for a hearing is not timely filed, the AOGCC may consider t' , issuance of an order without a hearing. To learn if the AOGCC Hrll hold the hearing, call 793-1221 efter March 20, 2014, In addition, written comments regarding this application may be submitted to the Alaska oil and Gas Conservation Commission, at 333 YJest 7th Avenue, Suite 100, Anchorage, Alaska 995o1. Comments that,ifheariing is no later muust be received no, later thanct tee conclusion of the April 1, 2014 hearing. 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 March 25, 2014. It blished: March 1, 2014 Cathy P. Foer3ter Chair, Cc << e;is�fonec • • STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /� O_14-025 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF / 1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE IF I AOGCC R 333 West 7"' Avenue. Suite 100 o Anchorage_ AK 99501 M o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 United states of America State of AGENCY CONTACT I DATE OF A.O. PHONE iPCN t 7V' I /%J -lL�� DATES ADVERTISEMENT REQUIRED: ASAP THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 AFFIDAVIT OF PUBLICATION REMINDER ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HER 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 2012, and thereafter for consecutive days, the last publication appearing on the day of . 2014, 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 2014, Notary public for state of My commission expires. 0 Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, February 28, 2014 10:56 AM To: 'Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov)'; 'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; 'Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody 1 (DOA) oody.colombie@alaska.gov)'; 'Crisp, John H (DOA) 0ohn.crisp@a1aska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); 'Ferguson, Victoria L ("DOA)(victoria.ferguson@aiaska.gov)'; Toerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; Trystacky, Michal (michal.frystacky@alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; Hill, Johnnie W (DOA)1- 'Hunt, Jennifer L (DOA)'; 'Johnson, Elaine M (DOA) (elaine Johnson@alaska.gov)'; 'Jones, Jeffery B (DOA) oeffjones@alaska.gov)'; 'Mumm, Joseph (DOA sponsored) ooseph.mumm@alaska.gov)'; 'Noble, Robert C (DOA) (bob.noble@alaska.gov)'; 'Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) 0im.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; 'Turkington, Jeffrey (DOA sponsored) Qeffrey.turkington@alaska.gov)'; 'Wallace, Chris D (DOA) (chris.wallace@alaska.gov)'; '(michael.j.nelson@conocophillips.com)'; 'AKDCWellIntegrityCoordinator'; 'Alexander Bridge'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Barron'; 'Bill Penrose'; 'Bill Walker'; 'Bob Shavelson'; '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 McCaleb'; 'David Scott'; 'David Steingreaber'; 'David Tetta'; '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'; 'Gary Schultz (gary.schultz@alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff'; 'Jacki Rose'; 'Jdarlington oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'John Garing'; 'Jon Goltz'; Jones, Jeffrey L (GOV); 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Kari Moriarty'; 'Keith Wiles'; 'Kelly Sperback'; 'Klippmann'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Lisa Parker'; 'Louisiana Cutler'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark P. Worcester'; 'Mark Wedman'; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'M1 Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'Nikki Martin'; 'NSK Problem Well Supv'; 'Oliver Sternicki'; 'Patty Alfaro'; 'Paul Decker (paul.decker@alaska.gov)'; 'Paul Mazzolini'; Pike, Kevin W (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'Randy Redmond'; 'Rena Delbridge'; 'Renan Yanish'; 'Robert Brelsford'; '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'; 'Steve Kiorpes'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'Tamers Sheffield'; 'Tania Ramos'; 'Ted Kramer'; 'Temple Davidson'; 'Terence Dalton'; 'Teresa Imm'; 'Thor Cutler'; 'Tim Mayers'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Tyler Senden'; 'Vicki Irwin'; 'Vinnie Catalano'; 'Walter Featherly'; 'Yereth Rosen'; 'Aaron Gluzman'; 'Aaron Sorrell'; 'Ajibola Adeyeye'; 'Alan Dennis'; 'Andrew Cater'; 'Anne To: Hillman'; 'Bruce Williams'; Bruno, Jeff J (DNR); 'Ca•Sullivan'; 'David Lenig'; 'Donald Perrin'; 'Donna Vukich'; 'Eric Lidji'; 'Erik Opstad'; 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; 'Hans Schlegel'; Heusser, Heather A (DNR); 'Holly Pearen'; 'James Rodgers'; 'Jason Bergerson'; 'Jennifer Starck'; 'Jill McLeod'; 'Jim Magill'; 'Joe Longo'; 'Josh Kindred'; 'Kenneth Luckey'; King, Kathleen J (DNR); 'Laney Vazquez'; 'Lois Epstein'; Longan, Sara W (DNR); 'Marc Kuck'; 'Marcia Hobson'; 'Marie Steele'; 'Matt Armstrong'; 'Matt Gill'; 'Mike Franger'; 'Morgan, Kirk A (DNR)'; 'Pat Galvin'; 'Peter Contreras'; 'Pollet, Jolie'; 'Richard Garrard'; 'Richard Nehring'; 'Ryan Daniel'; 'Sandra Lemke'; 'Scott Pexton'; 'Shaun Peterson'; 'Susan Pollard'; 'Talib Syed'; 'Terence Dalton'; Todd, Richard 1 (LAW); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'Wendy Wollf'; 'William Hutto'; 'William Van Dyke' Subject: Notice of Public Hearing West Sak Expansion Attachments: Notice of Public Hearing West Sak Expansion Sc�111t�i11ltr� (.���rlisl.i> {)1� iili[ir (ill's �.Olist'7-vailt►!i {.�t►illl)th�it►I1 IJ.11t'. 1O0 2 0 ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, AK 99510-0360 • • Jerry Hodgden Penny Vadla George Vaught, Jr. Hodgden Oil Company 399 W. Riverview Ave. Post Office Box 13557 408 18`h St. Soldotna, AK 99669-7714 Denver, CO 80201-3557 Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Darwin Waldsmith James Gibbs Post Office Box 39309 Post Office Box 1597 Ninilchik, AK 99639 Soldotna, AK 99669 #1 ,Times T. eRod'nie!s �-/ (Manager, GKA Development North Slope Operations and Development ooc-OPhilli s ConocoPhillips Alaska, Inc. ATO-1326 700 G Street Anchorage AK 99501 V: 1F I x 1r ph ne 9' ; 263 4U2 JAN 3 12014 AOGGG Catherine P. Foerster, Commission Chair Alaska Oil a,:d Gas Conservation Commission 333 W 7th Ave #100 Anchorage, Alaska, 99501-3539 RE Request to Amend Conservation Order No. 405B and Area Injection Order No. 2B Request to Expand the West Sak Oil Pool Request to Expand VRWAG Project in West Sak Oil Pool Kuparuk River Field North Slope, Alaska Dear Ms. Foerster, ConocoPhillips Alaska, Inc. ("CPAI") requests that the Alaska Oil and Gas Conservation Commission ("Commission") approve amendments to Conservation Order 406B ("CO 406E") and Area Injection Order 2B ("AIO 2B") for the West Sak Oil Pool ("WSOP") within the Kuparuk River Unit ("KRU"). CPAI submits this request in its capacity as the Operator on behalf of the working interest owners of the West Sak Participating Area, North East West Sak (NEWS) Participating Area, and the Kuparuk River Unit. CPAI respectfully requests that the Commission approve an administrative amendment to CO 406B to allow for the vertical expansion of the WSOP to include the Schrader Bluff N Sands. The proposed pool redefinition in CO 406B would make the WSOP consistent with the definition of and the stratigraphic equivalents of other West Sak/Schrader Bluff developments on the North Slope. The proposed vertical redefinition includes the Schrader Bluff N sand which is analogous to the definition used by other Schrader Bluff developments. The reasons for the proposed amendments to CO 4066 are discussed below in Part 1: Amendments to CO 406B. CPAI also proposes a minor modification to the areal extent of the WSOP. The proposed WSOP revision is intended to conform the WSOP to the current unit boundaries of the existing pool rules of other Schrader Bluff units. CPAI also requests that the Commission approve amendments to AIO 2B and issue a new AIO, which would allow for the expansion of the Viscosity Reducing Water -Alternating -Gas ("VRWAG') enhanced oil recovery project in the WSOP. Pursuant to Section 7 of AIO 2B.044 dated November 12, 2012, any expansion of the VRWAG project requires the issuance of a new area injection order after the opportunity for public comment and hearing. CPAI hereby submits its request to expand the VRWAG project in the WSOP through its Application for a Modification of AIO 2B: For Injection of Enriched Hydrocarbon Gas in the West Sak Oil Pool (Attachment 6). The reasons for this request are discussed in Part 2: Amendments to AIO 2B and in Attachment 6. CPAI Request for Amendmentso;06B & AIO 213 . January 30, 2014 Page 2 of 54 Discussion of Proposed Anrmndmcr&� Part 1: Amendments to CO 406B Proposal for Expanded West Sak Oil Pool WSOP Expanded Stratigraphic Definition, The WSOP is currently defined in CO 446E as the strata that are common to. and correlate with, the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 Well between the depths of 3,742 and 4,156 feet. measured depth. CPAI proposes arr,ending the WSOP to include the overlying Schrader Bluff N Sands, and to redefine the WSOP as the strata that are common ,o, and correlate with, the aum cculation found in the Atlantic Richfield Company West Sak River State No. 1 Well between the depths of 3,552 and 4; i 56 feet, measured depth This proposed definition is consistent voth the Schrader Bluff Pool Rules of the adjoining Milne Point, Prudhoe Bay and Nikiatchua, Units where the West Sak equivalent Schrader Bluff O Sands and the Schrader Bluff N Sand intervals are both included in the pool rules interval. Attachment 1 shows a type log of the proposed Schrader N Sand - West Sak geologic column. Attachment 4 contains the geologic explanation and data in support of CPAI's proposed vertical expansion of the WSOP. The proposed WSOP revision will include the current WSOP near -term future drilling locations plus lands which the KRU owners plan to develop. The proposed WSOP, when expanded vertically, overlaps the current WSOP and will facilitate the potential to pursue development of the West Sak and Schrader Bluff N Sand intervals in the Kuparuk area. CPAI believes that with appropriate reservoir management, injected fluids will remain confined to the redefined WSOP. Such reservoir management includes monitoring injection volumes and pressures by continuous metering at each injection well, and testing producing wells at least once per month to monitor reservoir withdrawal. Casing pressures will continue to be monitored in accordance with Rule 13 of CO 406B. Modification to Areal Extent of WSOP. This modification is proposed as a "housekeeping" amendment, due to changes in the geographic extent of the KRU and the West Sak Participating Area since the time the original pool rules and AIO were issued. This modification would result in the WSOP boundary conforming to the boundaries defined in the pool rules of the other Schrader Bluff units. If the Commission determines that a realignment of the area is prudent, the affected area in the CO and the AIO would then be described as encompassing the lands shown in Attachment 2. Attachment 3 lists the current pool rules and the proposed changes to CO 406E as described in the preceding paragraphs. With the proposed redefinition of the WSOP, the rules set forth in CO 406E are appropriate for continued operations in the WSOP. Part 2: Amendments to AIO 26 Application for a Modification of A10 28: For Injection of Enriched Hydrocarbon Gas in the West Sak Oil Pool (`Application'). In addition to CPAI's request that CO 406E be expanded to include the N Sands, CPAI requests the modification of AIO 26 (as supplemented by AIO 28.044) as set out in the Application (Attachment 6) and in Attachment 5 to allow for the expansion of VRWAG and seeks the Commission's authorization for VRWAG in the WSOP. The purpose of this Application is to provide the Commission with evidence of the additional benefit of VRWAG injection to recover additional hydrocarbons from the WSOP. There are no known or .anticipated compatibility problems between the WSOP and the proposed injectants. The proposed injection operation will be conducted in permeable. strata, which can reasonably be expected to accept injection fluids at pressures less than the fracture pressure of the confining strata. Injected fluids will be confined within the appropriate intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests, will demonstrate appropriate performance of the enhanced oil recovery or disclose possible abnormalities. CPAI Request for Amendments 006B & AIO 213 January 30, 2014 Page 3 of 54 Conclusion Including the Schrader Bluff N Sands under CO 406B and AIO 2B as proposed and to expand VRWAG in the WSOP requires consideration to insure that the CO and AIO rule changes are appropriate CPAI believes the proposed changes are appropriate based on the information presented as part o, Attachment 4 and the Application (Attachment 6). CPAI believes the requested amendment approvals are bBSE� Cn nF SOUnd eng:eting ai'C C`Ev C� 1C2 ;;`rnCIL�IES v� iJ increase ul,tw-,ate `e.d reC'Ovf;iy v!il not orcmotc .vaSte OI" Ieo(;aidize r.-,, restjjt in an ;!sk cf f1mO n-�Ovelne."Jt into fresliVvater CPAI respectfuilly quests tl)a? file Co;nnlission approve, the chances to the Orders as shown in 3 and Please contact Marc Jensen (265-6573), Joe Versteeg (265-6171), or Scott Redman (263-4514). it you have questions or require additional information. Sincerely, t,. J�anes T. Rodgers Manager, GKA Development North Slope Operations and Development cc: Wolfe, Patrick Campbell, Alan Seitz, Brian 0 �... _ U U m '.L' C• r Y -� CD C� % @ tU u, p m 0 W � O m ,O CO ro : N .(6 � U7 � � p 0 p C U a., ';1 ? V C p z7 T C Q- c r- -gyp M C cu U) V C a N w V a) E p D () Lr-) 'O 2 O '.0 U C_ C V A-dcA ro to �� ro W Cf)`O > vw a. co -a Z 1.. O a �in M E 1 c � � A Q• U (� a, LL y C v b � 15 CL C y. A C1 m 4! M w M �FM II 1 � 1 CPAI Request for AmendmentsO406B & AJO 2B January 30, 2014 Pace 6 of 54 i,tt E:t�trn�nt �: f�tc� a eta cllai ry4Uf,E Affected Area Current: Umiat Meridian ovrnshi Range Sections FN 1 r1V ;i i i S_LiiOi i $. i 20. l9N R'i(J All -i 9N R�L All T9N R8E All T9N R7E All T10N R11E Sections 3-10, 15-22, 29-32 T10N R10E All T10N R9E All T10N R8E All T10N R7E All T11N R11E Sections 5-8, 16-22, 27-34 T11N R10E All 711 N R 9E All T11N R8E All T11N R7E All T12N R10E Sections 3-10, 14-23, 25-36 T12N R9E All T12N R8E All T12N R7E All SW/4 Section 2, W/2& SE/4 Section 11, Sections 3-10, 15-22, T13N R9E 25-36 T13N R8E Sections 1-3, 10-12, 13-15, 19-36 T14N R9E Sections 19, 30, 31 T14N R8E Sections 24, 25, 36 CPAI Request for Amendments G� 406B & AIO 2B January 30, 2014 Page 7 of 54 Proposed: Umiat Meridian Townshi_p Range Sections T8N R7E Sections 1-13 i 9N R1 1F Sections 5-8. 17-20., 29-32 i�N R,iOE �! I J h: f L' 1- ./-�.. T9N Rf;E P,!I T9N R-t E T10N R 1 1 E Sections 3-10. 15-227 29-32 T10N R10E All T10N R9E All T10N R8E All T10N R7E All T11N R11E Sections 5-8, 16-22. 27-34 T11N R10E All T11N R9E All T11N R8E All T11N R7E All T12N R10E Sections 3-10, 14-23, 25-36 T12N R11E Section 31 T12N R9E All T12N R8E All T12N R7E All SW/4 Section 2, W/2& SE/4 Section 11, Sections 3-10, 15-22, T13N R9E 25-36 T13N R8E Sections 1-3, 10-12, 13-15, 19-36 CO 406E Rule 2 Pool Definition Current: "The West Sak Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 3742 feet and 4156 feet in the West Sak No. 1 well." Proposed. "The West Sak Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 3552 feet and 4156 feet in the West Sak No. 1 well." CPAI Request for Amendments •0613 & A10 2B is January 30, 2014 Page 8 of 54 Attachment 4: Schrader bluft N Sand geology Schrader Bluff N Sand Geology STRATIG RAPHY Stratigra,o11ic _Igomc nclaturq Ile 1!Vesi S?lC OII Pool R'Ple 1' of Gonse!vat!on Ofdei No 4r h F]s the sflaiq'nFal are C01111110ii i0, and CGrrelcJ"te `dv"�.til, the aCCUITWIi !V! fOUnd' In the Atla!ltic Richfield Company West ��ilI R!ve.r State No 1 Well Between ih& Ceti ils of 3 742 grid 4,1`.;6 feet, measured depth. As part of this application, CPAI requests that the Commission expand the West Sak Oil Pool definition to include the overlying Schrader Bluff N Sands which are common to, and correlate with, the interval found in the Atlantic Richfield Company West Sak River State No. 1 Well between the depths of 3,552 and 4,156 feet, measured depth. Exhibit 1 shows a type log of the proposed Schrader N Sand - West Sak geologic column. This expanded definition is consistent with the Schrader Bluff Pool Rules of the adjoining Milne Point, Prudhoe Bay and Nikiatchuq Units where the West Sak equivalent Schrader Bluff 0 Sands and the Schrader Bluff N Sand intervals are both included in the pool rules interval. Furthermore, it facilitates the potential to pursue future co -development of the West Sak and N Sand intervals in the Kuparuk area. The Schrader Bluff N Sands are correlated to the Schrader Bluff Formation of the Colville Group in the Umiat afea2. The N Sand and its stratigraphic equivalents extend across the Kuparuk River Unit area. Typical gross N Sand interval thickness along the eastern side of the Kuparuk River Unit is 180 ft. The N Sand interval thickens regionally from 160 feet in the northeast KRU to over 300 ft. in the southwest (Exhibit 2) In the area of the Kuparuk River Unit, the N Sand interval is divided into four stratigraphic intervals (Exhibits 1, 3 and 4). From oldest to youngest these are the Nf, Nc, Nb and Na intervals. These zones are correlated to the Schrader Bluff N Sands in the Milne Point, Prudhoe Bay and Nikiatchuq Units, and are persistent across the Kuparuk River Unit. Stratigraphic Description The Schrader Bluff N Sand interval in the Kuparuk River Unit generally represents a shallowing upward, deltaic sequence between the underlying West Sak lower shoreface system and the overlying fluvially dominated Ugnu interval. The basal, distal lower shoreface/pro-delta facies of the Nf and Nc are largely mudstones which coarsen upward into interbedded silt and fine sand. However, the Nf includes a southward thickening wedge of sand in the extreme southern portions of the Kuparuk area (Exhibit 4). The Nb interval near the middle of the N Sand interval (Exhibits 1, 3 and 4) is dominated by discontinuous sands deposited in prograding distributary channels and delta front environments. It is the predominant hydrocarbon bearing portion of the Schrader Bluff N Sands in the eastern Kuparuk area where it typically contains from 5 to 30 feet of net sand (Exhibit 5). The uppermost Na interval is predominately interdistributary mudstones with local channel and overbank sands. There are limited N Sand core samples in the Kuparuk area. Conventional cores from the Nb in West Sak Pilot 4 and the Ugnu SWPT 1 (see Exhibit 7) show the Nb interval consists of unconsolidated very fine to medium grained, moderately to well sorted litharenites. Porosities are between 30% and 37%, with t CO 406B.000 - Rule change affecting well spacing within the West Sak Oil Pool, Kuparuk River Unit 2 Werner, M.R., 1984, Tertiary and Upper Cretaceous heavy -oil sands, Kuparuk River Unit Area, Alaskan North Slope: in American Association of Petroleum Geologists Studies in Geology 25, Exploration for Heavy Crude Oil and Natural Bitumen, p. 537-547. CPAI Request for Amendments Cv406B & A10 2B • January 30, 2014 Page 9 of 54 permeability ranging up to seveiai darcies. Penneabil;ties of bounding mudstones are typically only several millidarcies. Aq_q of Sediments Fused upon CPAI in-house n-ricropaleontoiogic and palynologic data, the Schrader N Sands n the K r'an.,k al`ea are nter,:;reted to he Late C retaceous (("aasirlcht+ari) !n age. Proposed Vertical Pool Boundaries 1 he lower boundary of the West Sak Pool remains unchanged and is placed at 4156 feet rneasured depth in ARGO West Sak No. 1 and its lateral equivalents in the KRU (Exhibit 1). This depth marks the base of the first definitive coarsening upward cycle at the top of the Colville Group mudstones and corresponds to the base of the West Sak Al. The underlying Colville Group is a sequence of impermeable inter -bedded mudstones and shales over 1000 feet in thickness which provide an effective lower boundary to the West Sak Pool interval. Within the Pool interval, the West Sak Sands are immediately overlain by the Schrader Nf and Nc which are pro -delta sequences comprised predominately of mudstones. The basal mudstone portion of this interval ranges from 80 to 100 feet in thickness throughout the Kuparuk area. This interval provides an effective upper boundary to the West Sak Sands. The proposed upper boundary of the West Sak Pool is placed at 3552 feet in the ARCO West Sak No. 1. This corresponds to the top of the Schrader Na interval and is the base of the overlying Ugnu A interval throughout the KRU. The Schrader Na and the Ugnu A intervals are delta front and lower delta plain sequences characterized by discontinuous sands within a mudstone dominated interval. In aggregate, these mudstone rich intervals range from 140 to 180 feet thick across the KRU and typically have a net sand -to -gross ratio less than 0.50. The mudstones in this interval have similar mechanical properties to the Nf and Nc mudstones immediately above the West Sak Sands, and provide a regional seal and an effective confining zone above the sands in the Schrader Bluff N interval. STRUCTURE The top of the Schrader Bluff N Sands (base of the Ugnu A) is not seismically distinct in the Kuparuk River area, but appears structurally conformable with the underlying top of West Sak The top West Sak is a monocline that strikes north-northwest and dips gently to the northeast between 1 and 2 degrees. The West Sak has been mapped throughout most of the Kuparuk River Unit using the 1989-91 KRU 3D survey. A map representing the top N Sand interval has been constructed by isopaching up to the top of the N Sand interval (Exhibit 6). Within this mapped area, the top N Sand extends from 1400 feet subsea in the west to 4000 feet subsea to the east. Based on well control, depth at the top N Sand continues to rise to 600 feet subsea in the south westernmost portion of the West Sak Pool area. In this area, the top of the N Sand interval intersects the base of permafrost at approximately 1000 feet subsea. The Schrader Bluff N Sands are cut by both north -south trending and east -west trending normal faults as seen at the top West Sak (Exhibit 6). Both faults sets appear to be of similar age, and post-date deposition of the N Sand interval. Down to the north and down to the east is the more common direction of offset. Throws typically are 20 to 40 feet, with maximum throws locally of 100 to 150 feet. 0, CPAI Request for Amendments 406B & AIO 26 January 30, 2014 Page 10 of 54 T raooina Mechanism and Oil Distribution Hydrocarbons in the Schrader Bluff N Sand interval appear to be limited to the eastern side of the Kuparuk River Area (Exhibit 7) were they generally occur below 2600 feet subsea. The lateral continuity of the hydrocarbon column in the N Sands is still poorly defined but the trapping mechanism is considered to be both structurai and stratioraphic in nature N .uiI;iS ,Lit �Zailc i,Ul!S ..cI5 \.rl:.n vES'� c-I< L�.Cw u L� cnd segment the !aterally continllOU� lCV'��Er �hereface sands of the West Sak. re.servoli Into !^!oci<ti v,'ith contacts it is lth,:sc san-IC, aults contifbUtC- significantly iu v(ui;iL c.,,iis, i?i the lateral distribution of hydrocarbon content and cll-water contacts in the N Sand interval. Stratigraphic trapping is believed to play a larger role in the Schrader Bluff N Sands than it does in the West Sak due to the high degree of lateral variation in N Sand net sand thickness and net -to -gross ratio. The N Sand accumulations in the eastern Kuparuk area (Exhibit 7) are predominately confined to the delta front and distributary mouth bar sand facies. The rapid lateral variation in these facies augments lateral trapping and makes characterization of hydrocarbon extent and oil -water contacts difficult. Additionally, in this area the overlying mudstones have sufficient thickness and continuity to provide vertical seals. To the west where the N Sands are more fluvial, hydrocarbons accumulations have not been identified by drilling to -date. Oil Accumulations Hydrocarbons in the N Sand interval appear to be limited to the eastern side of the Kuparuk River Area (Exhibit 7). The current expected (P50) estimate of oil -in -place for the Schrader Bluff N Sand interval in the Kuparuk River Unit is 850 million stock -tank barrels The oil is characterized by a greater degree of biodegradation than the deeper West Sak Sands, but is not as severely biodegraded as oil characteristic of the overlying Ugnu Sands. API gravity measured from a PVT sample in the West Sak Pilot 4 was 12.3° API with a viscosity of 2288 cp viscosity at reservoir conditions. API gravities estimated geochemically from sidewall cores in the 3K-102, 1 R-East, 1 H-North and 1 H-South wells in the Northeast West Sak Area (NEWS) range from 10.8° — 13.2° API (see Exhibit 7 for well locations). RESERVOIR DEVELOPMENT As a result of appraising the NEWS (North East West Sak) area and data from the adjoining Prudhoe Bay, Milne Point and Nikiatchuq Unit, opportunities for co -development of the Schrader Bluff N Sands with the West Sak are now recognized in the eastern Kuparuk area. Although oil gravities to -date are lower than similar developments in these adjoining areas, they should be water floodable and would benefit from VRWAG injection. As a result of the apparent greater complexity in lateral hydrocarbon distribution, N Sand data acquired in subsequent West Sak and Kuparuk drilling will be required to more fully characterize and optimize any development plans. Potential hydrocarbon recovery expected from the N Sands is estimated at 85 million barrels of oil, which is 10% of the currently estimated 850 million barrels of original oil in place. LIST OF EXHIBITS Exhibit 1: Schrader Bluff N —West Sak Sands geologic column type log Exhibit 2: Schrader N Sand interval total isochore — Confidential Exhibit 3: Stratigraphic section A -A' Exhibit 4: Stratigraphic section B-B' Exhibit 5: Schrader Nb net sand isochore — Confidential Exhibit 6: Top Schrader N Sand depth structure map with top West Sak faults — Confidential 0 CPAI Request for Amendments C•'406B & NO 2B January 30: 2014 Page 11 of 54 Exhbt T Schrauer N Sand gross pay with Faults at -Cop of West Sak -- Confidential • • era ci o �; ,p _� _t •Y 'L .� 4_ GJ ` 6- 'Ili,� — 'Ili, � cu (f7 co ^y W -C Z G .0 ` n- o U c C O N N 'O V C7 ll_ C N Z- N > V) a. C C— (D -lid,� _ �,s _ C O e_G') N _ = Ul �J .� 'j > N Ln nK V ..i co CD o 7 N m�. d -a C G �i O .O `7 .� Y M m o f C S U c -N O 0O (C Q F Q om N o �� aaN OS > LO a c -_ c c a O LC c� oo u a' Q) N` N N O o N=` n o� >-0 �� ����C) G OC C Q a rn_ a E > O J c ' E c O V E ca `► C3 `� o_^ C m > g u C) n 0) O 0 LL. 0 v Z N � o .'Ur h N mHE Z OQ Cl) ]C G! p V a) N N O ' C- .:. 'C m,/At� am co co r x i i U --, d W EXHIBIT 2 HELD IN SECURE STORAGE w z z r ��t��itaal•rr����� ®�■LE®��■1tJ�f.'■�� �errrrar�a�a�rarr� arrr�nrarrira.rrrrrrr���rnrr Q' y m cial N 0 Q ,a m �•+ 0 am t� 0 0 U v w d c tN. a L� a a� . o o� `tm 0NN� lf) w U) aa� �/ yy w w � _Lm vi N a x coro Unm W A 1� 1a I. 1. li ',%C1 \:NN -1-: \ i a0 moll Iwa0A1 r►MiM FM alMilu�s,M�w ft7l�ilE■��80�� ��[�lEsi�■' rr...rr.n.n......w......�rMra.-..—+.+..r.......r....n...m...+.�...n..W....r+�r�M, SO M-,=, 1.1ME � MOL �a®���.. �rm�r�� NINA li 11 1• 1.]. 1. 11 11 \l %% \. N. \' _��,9FAM NMI �t�M.�■..II a� �-imam j W s r. Q N Ef M N P _ ��3y i 1 ' i .. !'� �_. i" i l�, i�r_ '� � � yi�Y�^ � �.y�,Y Yy��,r ��-!.•-t-"�-'�_'Y_ y.w 2 »;I i t,C�'1` �' �,r. l!� i �W�i'b`?L� •p li'^"` e c ! . . 14.`.t � T -I--- 1 )4-,}{'fir -�y •�..-... �. /.J�I:•�J `sW j� g�+ T S r !flEREEMEPlSA E 1.4"�' NIiWilf�IrYle�i��flWit�ylY�l�l�sia_� R i'FAS � i Ask • - r SIB llu MEM� i am""' i, EXHIBITS 5-7 HELD IN SECURE STORAGE CPAI Request for Amendments 066B & AIO 2B ,January 30, 2014 Page 19 of 54 Ailaullri cnt 5: E"°topo::ed changes to A10 kb, A10 28 Rule Current Within the affected area. non-hazardGtls fluids may be 7,ectee for the purposes of prez-0— maintenance and enhanced oil recovery into strata defined as t1".use 5tr2t3 : l fCh c rreiaie Vdhtt 11 the strata found in the ARCO West Sak River State Well No 'i between the measured depths cf 5224 < ,. F474 feel a��; Z.�, le(''.t cr0 .',�'(� feE;'t_ �7,UG feet -.' 4040 fE%t, �t C11 fE?Ct �, ,d J:� R6� r Authorized Injection Strata for Enhanced Recovery Pmlrosed Witi-iin the affected area; iron-hazardu os duds may be uijec,ied fo! the {uir_� es cf ress�,r, maintenance and enhanced oil recovery into strata defined as those strata VA -lick correlate with the strata found in the ARCO West Sak River State Well No. 1 between the measured depths of 3145 feet and 3552 feet; 3552 feet and 4156 feet; 4591 feet and 5324 feet; and 6474 feet and 6880 feet." Proposed New Rules relating to VRWAG in the West Sak Oil Pool: "VRWAG is authorized in the !Nest Sak Oil Pool; VRWAG must be conducted In accordance with the process described in the VRWAG Application (attached and incorporated into this Area Injection Order by reference) and all applicable regulations.' °Prior to commencement of VRWAG gas injection activities in an injection well, the operator must submit an Application for Sundry Approvals (Commission Form 10-403) for each proposed new VRWAG injection well and obtain approval from the Commission as to the mechanical integrity of the proposed injection well and nearby wells to ensure there are no conduits that would allow for injected fluids to escape from the intended interval." CPAI Request for Amendments C0406B & AIU 2B • January 30, 2014 Page 20 of 54 l,ttacF�rnent 6: Application fc r mcditication (A Alta 2€,: lu) unriul,,Ed hVdro(.art::c>ri the West Sak Oil Pool h*11" Conoc P 1ps A1))''1 1(.:A]-10N I- ()RN M()DIFIGAJ 10N 01-- AREA INJECTION ORDER 213: FOR. INJECTION OF ENRICHED HYDROCARBON GAS IN THE WEST SAK OIL POOL January 30, 2014 Section A — Introduction Section H — Plot of Pfoject Area 24l AAG 25A02{c){1) Section C — Operator & Surface Owners 20 AAC 25.402(c)(2) Section D — Affidavit 20 AAC 25.402(c)(3) Section E — Description of Operation 20 AAC 25.402(c)(4) Section F — Pool Description 20 AAC 25.402(c)(5) Section G — Formation Geology 20 AAC 25.402(c)(6) Section H — Mechanical Integrity of Injection Wells 20 AAC 25.402(c)(8) Section I — Injection Fluids 20 AAC 25.402(c)(9) Section J — Injection Pressures 20 AAC 25.402(c)(10) Section K — Fracture Information 20 AAC 25.402(c)(11) Section L — Formation Water Quality 20 AAC 25.402(c)(12) Section M — Aquifer Exemption 20 AAC 25.402(c)(13) Section N — Hydrocarbon Recovery 20 AAC 25.402(c)(14) Section 0 — Confinement in Offset Wells 20 AAC 25.402(c)(15) List of Exhibits CPAI Request for An-iendments C006B & A10 213 January 30, 2014 Page 21 of 54 SECT ION A - INTRODUCTION ConocoPhillips Alaska, Inc , in its capacity as Operator of the Kuparuk River Unit and the West Sak Participating Area, hereby applies for modification of Area Injection Order No. 26 (AiO 2F); to inject an enriched hydrocarbon gas in the West Sak Oil Pool for the purpose of expanding the Viscosity Reducing Water-A!ternating-Gas ( VRV1/AG') enhanced cil recovery project throughout the West Sak Oil Pool This t!c f Lo M Cr C la ail cil' �i iw.,ccerdz!)ce ,v.th 20 A-,C 2511.2 (Enhanced Recovery OpFratior s) 20 l,AC 25.46ii and 20 P,AC l: i-IdeigrounL liljeC,IGII Cci-troi Varicnces,i- Injection and production startup in the West Sak Oil Pool was achieved in December 1997. The origina! development consisted of vertical injectors and producers in a 5-spot pattern configuration on nominal 40- acre spacing. Because of low injectivity and productivity, caused in part by high oil viscosity, producer and injector designs have evolved to Jong, horizontal wells. The current development includes production and water injection wells drilled from drill sites 1B, 1C, 1D, 1E, 1J, and 3K. As of December 31, 2012, there were 102 active wells in the West Sak Oil fool - 49 producers, 50 water injectors, and 3 water alternating gas injectors (1E-117, 1J-122.. and 1J-170). Produced water from the Kuparuk Central Processing Facilities (CPFs) and treated seawater from the Seawater Treatment Plant (STP) are used for the West Sak waterflood. Production from the West Sak Oil Pool is commingled with Kuparuk Oil Pool produced fluids at the respective drill sites and processed at the CPFs. West Sak oil production is currently about 15,000 STB/Day. The VRWAG Pilot Project demonstrated positive oil, gas, and water responses from the VRWAG process The encouraging results observed during the pilot period were successfully replicated in pattern simulation models. The new modeling results from the history matched simulations indicate a potential 3- 6% original oil in place (OOIP) incremental recovery for VRWAG with an average 25% hydrocarbon pore volume (HCPV) cumulative gas injection. The incorporation of this process into the development plan for the West Sak field has the potential to nominally increase ultimate recovery beyond base waterflood management. Thus, the Kuparuk and West Sak Working Interest Owners have approved injection of existing enriched hydrocarbon gas from the Kuparuk River Unit. Facility modifications were previously installed on DS-1B, DS-1C, DS-1E and DS-1J to include the West Sak wells slated for such service. Upon Commission approval for VRWAG process for the WSOP, enriched hydrocarbon gas injection will likely begin in the first quarter of 2014. Expected performance for the VRWAG process in the core area of West Sak is based on the pattern simulation results which project 3-6% incremental oil recovery. The estimated expansion target volume for the West Sak core area is approximately 320 MMSTB OOIP (Original Oil in Place). Scaling the pattern simulation results to this target volume yields approximately 13.6 MMSTB of additional West Sak oil recovery from the VRWAG process. A summary of this VRWAG recovery projection for the core area is reviewed in Section N. The estimated amount of viscosity reducing injectant (VRI) required in the core area is a maximum annual average gas injection rate of approximately 20 MMSCF/D of enriched hydrocarbon gas. Additional details are addressed in Section B through Section 0. CPAI Request for Amendments*0613 & A10 2B 10, January 30, 2014 Page 22 of 54 SEG—) lON P — PLOT OF PRO.9EC`i AREA 20 AAC 25.402(c)(1) Exhibit B-1 shows all existing ':.iection wells, production wells, abandoned wells. dry holes, and any other wells within the \hest Sak Participating Area (PA) as of ` May 2011,. Exi-iibit B-2 shows all existing in+ection v clls I..roductJon wells F'Dandoneci wells dry holes and any other y.Yells within the North East 'A`e�)i .!U ) a�liC i�cI IIC C if raj c„ C:' '� i'Vi :11'. C�i (.'Xlslslly :J( tG i'c� '_Gli,', itcC; 'to 'ljeciiC i e :'c;: c o lc 2., 280 E, ," 2 5rn c'i oii' ar j=,!!C�;r;18 �:;CCG SOf rEgUli ii(. i. CPAI Request for Amendments C ;ub & A10 2B January 30, 2014 Page 23 of 54 SEc: `I ION C - OFERAi OR & SURFACE OWNERS 20 AAC 25.402(c)(2) ConocoPhillips Alaska. Inc. is the designated operator of the West SEA PA and NEWS PA The surface owners and operators within one -quarter niile radius of the proposed injection area are listed below Suliace O'WrwlI State. of Alaska Division of Oil and Gas Attention. Mr. Bill Barron; Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 99501-3557 Operators: 70 & 148 LLC 1421 Blake Street Denver, CO 80202 ASRC Exploration LLC 3900 C Street, Ste. 801 Anchorage, AK 99503 AVCG LLC Land Department 510 L Street, Suite 601 Anchorage, AK 99501 BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Chevron U.S.A. Inc. 1029 West 3rd Ave., Ste. 150 Anchorage, AK 99501-1972 Eni US Operating Co. Inc. 1201 Louisianna, Suite 3500 Houston, TX 77002 ExxonMobil Alaska Production Inc. P. O. Box 196601 Anchorage, AK 99519-601 Great Bear Petroleum Ventures I, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 Great Bear Petroleum Ventures 11, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 7.OGO North Atlantic, Ave (ill IF loor (-) ;:,fir t Repsol E&P USA Inc. 2001 Timberloch PI.; Ste. 3000 The Woodlands, TX 77380 � t CPAI Request for Amencimenis i—) 406B & NO 2B January 30, 2014 Page 24 of 54 sECTIO14 D — AFFIDAVIT 20 A.AC 25.402(c)(3) Exhibit D- i is an affidavit showing that the operators and surface owners wiihin a one -quarter mile raciius of the proposed Injection area have 1 ec,;l provided a copy of this replication for modification to AlO 2B. CPAI Request for Amendments 006B & A10 2B January 30, 2014 Page 25 of 54 SEC-ilON E — DESCsRIP-11ON OF OPERATION 20 AAC 25.402(c)(4) Enhanced recover; injection wells are used for the introduction of additional fluids into the. reservcir to increase the ultimate recovery of oil. As of December 31, 2013, there were 102 active welis in the West Sal,, C1ii Pool - 49 „cducers 50 water injectors and 3 water alternating gas injectors OE 117 1J 122. c"lC� J � 7U1 i'1C(; ;C:C'd u��a��i ICI iite ,..�<,,C: I r<2t""C`lt c;a f ;i;C '... r. S;k �� ,,.. "��� C �_!'','� ' ale �, O:'l!C .n c^,ter 'e < e n 1. and C n� c conjunction vNith existing f<upr, ruk Participating Area ( KPA' j facilities Enriched hydrocarbon gas and water will be injected into the West Sak injectors in a VRVVAG process. The enriched hydrocarbon gas will be manufactured and supplied from existing KRU enriched gas hydrocarbon injection facilities DS-1B, DS-1C, DS-1E, and DS-1J have injection lines and on pad injection facilities for the VRWAG injectors. CPAI Request for Amendments 006B & A10 2B is January 30, 2014 Paoe 26 of 54 SECTION F — POOL DESCRIPTION 20 AAC 25.402(c)(5) T l-,e D B and A, Sand intervals of the West Sak Formation; and the Schrader Bluff N Sands: within the ilp ,(lJk FZ;Vi'f Url i \"Jill : PffcCtcd �' f i;' \'Ji�.°v '.� r*C)CESS ! he'\'Vest sc k Pool ''dc C it ilia ij defined by Ilc; 2, of �-GlSe"J.::I(l UrGer Nc ziOr„- tiC'U 406 P� ncF � t� I lc< <>(f� C'„�nCii U n] COr(Ea 1, Ch, tile accumulation found in the Atlantic Conlpail'y `v'VeSt Sak Rlvei State No. 1 VVeII bet✓✓e'lrl the ce,pths of 742 and 4.156 feet. measured depth In coniunciion with this application. CPAI has requesters that the Coirtission expand the VVest Sak Pool definition to include the Schrader Bluff N Sands. The m Schrader Bluff N Sands are common to, and correlate with, the accumulation found in the Atlantic Richfield Company West Sak River State No. 1 Well between the depths of 3,552 and 4,156 feet; measured depth. A type log of the Schrader N Sand - West Sak geologic column is provided as Attachment 1 of the accompanying documents. This expanded definition is consistent with Pool Rules of other stratigraphically equivalent Schrader Bluff intervals. CPAI makes this application based on its proposed changes to CO 406B and the new definition for the \•Nest Sak Pool, which includes the Schrader Bluff N Sands. CPAI Request for Amendments C040W & A10 213 • January 30, 2014 Page 27 of 54 SECTION G — FORMATION GEOLOGY 20 AAC 25.402(c)(6) 1 he C B and A Sand intervals of the West Sak Fonrnation, and the Schrader Bluff N Sands, witl-1in the !< 'pci�i Af ll� l c �,e�.tE h� flee \1RAi4�i;C r ncES il:' r r(�I'osFd Weil sak POCI C'fl'1nIG1 f`!:�,i �V :'� �i� Clctl e0 as, the. S�lotd "hal ale c i'?thou lo. 'nd co' jute \,v i i�E fcund n the Atlantic Richfield Company VVest Sal; F'ivcr State No. v"Vell Lety een "ne a�J:'Ed de.p'h Tr'E tAltOf thetype 10(7 IiS ce;tl'sOf C 56 feel, I P accompanying docun'ients A comprehensive overvie-vv of the Vest Sak formation geology *aS SL&n-iltfeG' in the original West Sal: Pool application. Additionally, supporting information regarding the formation geology in the Schrader Bluff N Sand was submitted concurrently with this application. See Attachment 4, "Schrader Bluff N Sand Geology" attached to CPAI's request for an amendment to CO 406B dated January 30, 2014 CPAI Request for Anlendmentsoi. & A10 2B January 30, 2014 Page 28 of 54 SECT ION I -I -- MECHANICAL INTEGR I Y OF IN JEC'f M4 WELL:, 20 AAC 25.402(c)(8) All casing is cemented in accordance with 20 AAC 25 52(b) and tested in accordance with 20 AAC 25.030(g) when completed. In swells converted to injection, the casing is retested in accorcance wiih 20 ACC 25Al2(c) API casing specifications are included on each drilling permit application. �rl il:,./ Gi;rE �c tt..G L-.SI i. i; J� fE: :E_ iE:�� I:. c-..,CrC'•Fil'r;e �O .. AAC afl!_'UII S MCSSlfrc 1ieli ':viii be checked ed %y A 1 U 2L' W6li �-'Zt S b{ 'E t'VrSt a IiOo:!1 P-Ctols r"Te tyj� cdii 2 Gr 4 th 4���e n'OSt common size being a 4-1/2' tubing string most West Sak water injection wells are completed with L-80 grade steel tubing. A generic well design for West Sak injectors is included as Exhibit H-1. All injection wells are completed in accordance with 20 AAC 25.412 and 20 AAC 25.030. Additionally, each injector has been on water injection prior to this application, with full Commission witnessed testing prior to being placed on injection. Exhibit H-2 lists the proposed West Sak injection wells as of 31 December 2013 which may be used for VRI injection service. An Application for Sundry Approvals (Commission Form 10-403) will be filed and approval obtained from the Commission for each proposed injection well prior to the initial VRI injection cycle. Injection cycles will be maintained and optimized according to best practices for management of a WAG -type FOR flood CPAI Request for Amendments 006B & A10 2B •+ January 30, 2014 Page 29 of 54 SECTION I — INJECTION FLUIDS 20 AAC 25.402(c)(9) The VR\/VAG process in the VVest Sak Oil Pool will be managed in conjunction wilth the existiri` i<RU FOR patterns using existing KRU enriched hydrocarbon gas from CPF-1 and CPF-2. The expected enriched hvdrocaibon gas composition is shown in Exhibit 1-1. The pilot could move to a leaner gas inject!on blend lCcrC1 C. �I'r�IIC;(`i n KUIjO�.',NAG I'('afirGEiiii6 �! �I;Ci ,llf'':: ��;L In�pCltS Ir0'1 ii: IIOE'. P[o(UCeU \.`,�aier alid seawotei care Currently used for the \'Vest Sak waterf!cod the ✓i VVi�,`' p10ceSS 'Vvlve.s ' er Ime"1lc;n SItC '1r�tinG with eflrlChfd !I,,+drocaibon gas !itiection to mpr(}Ve lire Cnl!CI'lEd hydrocarbon inicctant sweep In lire reseivolr Injection fluid information pertaining to the VRWAG process is given below. Type of Fluid: Kuparuk lean gas to KRU enriched hydrocarbon gas injectant. Composition of Fluid: See Exhibit 1-1. Source of Fluid: KRU lean gas, KRU indigenous NGLs, and/or imported NGLs from Prudhoe Bay. Estimated Maximum Gas Injection. 15 to 25 million standard cubic feet per day is estimated to be used for VRWAG service in the existing West Sak PA. Future wells in the West Sak Oil Pool on VRWAG service are estimated to require 2 to 6 million, standard cubic feet per day per well. Compatibility with Formation and Confininq Zones: Enriched hydrocarbon gas injected into the West Sak Oil Pool will be manufactured at CPF-1 and CPF-2 according to the specifications of the KRU Large Scale FOR Project. No compatibility problems have been observed between the enriched hydrocarbon gas and the minerals in the formation. CPAI Request for Amendrnents 006B & A.IO 2E • January 30, 2014 Page 30 of 54 SECTION J — INJECTION PRESSURES 20 AAC 25.402(c)(10) The estimated \,,jellhead and bottomhole injection pressures for the Vf;V\IP,G process are ;sled in the .,,Inir''ir I �. lcJ i f• Injection tyl)e West Sak Water j Injection I Eslimatcd Wellhead Estinyatetl hcttarratarlle Pressure (PSIG) Pressure TSIG) Average' Maximum" Average" Maxif uum— i, 'I 750 500-1600 I 2,300 11,300-3,500 West Sak Enriched I, Hydrocarbon Gas 2.050 1,000-2,800 2,300 1 1,300-3,500 Injection "Based on current operations at a true vertical depth of 3500 feet "Maximums vary according to correlated depth The estimated bottomhole pressure is the product of the correlated depth and the maximum expected injection gradient (0.8 psi/ft.). The estimated wellhead pressure is the difference between the bottomhole pressure and the hydrostatic pressure associated with the injection fluid- A minimum depth of 1600 ft. and a maximum depth of 4300 ft, were used to determine the pressure ranges. The maximum expected injection gradient is below the overburden fracture gradient and was chosen to provide flexibility in operation to enhance injectivity and improve recovery of oil. Section K discusses the fracture behavior of the West Sak and Schrader Bluff N Sands in more detail. Current operating practices at West Sak maintain injection gradients at or below 0.7 psi/ft. to mitigate the formation of matrix bypass events (MBEs). Innovative completion designs and new technology will further mitigate MBEs and allow for increased throughput to improve overall oil recovery. The maximum expected injection gradient of 0.8 psi/ft. will preserve optionality for future development and optimization of the waterflood in the West Sak Oil Pool. CPAI Request tor Amendmentso,06E & A10 2E �i January 30, 2014 Pagc 31 of 54 SE.C1ION K — FRACTURE INFORMATION 20 AAC 25.402(c)(11 ) The estimated maximum injection rates for the wells in VRWAG service will not iniiiate or propagate fractures through the confining strata. and, therefore, will not allow injection or formation fluid to enter arty freshwater strata. 1 here are no indications of injection cut of .one for the current water injectors at West WES4 SAt' f RACTURE AND CONIAINIVIFN1 In no instance has injection pressure breached the integrity of the West Sak confining zone during field operations The West Sak is immediately overlain by the Schrader Nf and Nc which are pro -delta sequences comprised predominately of mudstones. This confining interval ranges from 100 feet thick along the eastern boundary of the KRU to over 200 feet in the southwest KRU. This confining sequence tends to behave as a plastic medium and can be expected to contain significantly higher pressures than the West Sak formation sandstones. Extensive fracture testing confirmed that even at bottom hole pressures significantly above the initial parting pressure, the fluids continued to be confined by a relatively thin (-15-20 ft.) shale/mudstone interval, provided that an adequate casing cement bond is present. All injectors currently online have had a cement bond log to confirm adequate cement isolation between the West Sak formation and the above strata prior to commencing water injection service. Fracture stimulation data from the West Sak Sands indicate a fracture gradient of between 0 6 and 0.7 psi/ft. under initial reservoir conditions. Pfoppant injection pressures as high as 7,000 psig (about 2.0 psi/ft. injection gradient) showed no fracture growth across any confining shale zones. In addition, long- term water injection above 0.9 psi/ft. in the West Sak Sands tend to part the formation horizontally, rather than fracture vertically, thus keeping all injection fluids within the intended interval. The West Sak Formation is underlain by the Colville Group, a sequence of impermeable inter -bedded mudstones and shales over 1000 feet in thickness. The Colville Group lithologies have similar confining properties as the overlaying No interval sequence, and no injection or fracture propagation below the West Sak is anticipated. A comprehensive discussion of the geology for the West Sak Sands was submitted previously as part of the original West Sak Pool Rules application. SCHRADER BLUFF N SAND FRACTURE AND CONTAINMENT The Schrader Nb Sands are overlain by the Schrader Na and the Ugnu A intervals. These are delta front and lower delta plain sequences characterized by discontinuous sands within a mudstone dominated interval. In aggregate, these intervals range from 140 to 180 feet thick across the KRU and provide a regional seal. Operational data from the 1R-18 disposal well demonstrate matrix -dominated injection above 0.9 psi/ft. These data suggest long-term water injection in the Schrader Nb will behave similarly to the West Sak Sands. Surface pressures and injection rates for the disposal wells are submitted to the Commission as part of the monthly production and injection reporting process. Attachment 4,"Schrader Bluff N Sand Geology." attached to CPAI's request for an amendment to CO 406E dated January 30, 2014 provides a comprehensive overview of the Schrader Bluff N Sands and provides illustrations in support of the discussion. The West Sak and Schrader Bluff intervals in the KRU are characterized by north -south and east -west trending faults which post-date deposition and burial of the pool intervals. These faults are not seen as a risk to containment. Faults range up to 100 feet offset; but are typically in the 20-40 foot range. Due to the generally high clay content and thin bedded nature of the reservoir layers and the interbedded mudstones, faults with throws as little as 20 feet can form effective reservoir barriers due to shale gouge. These faults divide the reservoir into distinct compartments that control oil -water -contacts and fluid properties as evidenced by geochemical data. Additionally, there have been no instances in the current • i CPAI Request for Amendments 406B & A1O 2B January 30, 2014 Page 32 of 54 Wesi Sak deveiopments of fiord ions when diiiiing across fauits, or evidence of injecied iuic;s along faults or fault zones. CPAI Request for Amendments 6B & A10 2B January 30, 2014 Page 33 of 54 SEC'T10N L - FC)KPAAl1014 V'><'A"i ER QUALITY 20 AAC 25.402(C)(12) Compositions of injection water 'imiii the CPF-. and STP VJEIG suilmitted as Pali Of itl'0 01191112-1 area injectl0fi Order F,-T!Icat!0'l I Ile West `.yak Oil POOI connate water C011-)posiloon Is provided in Exhibit L-1, CPAI Request for Amendments �� 406B & A10 2B • January 30, 2014 Page 34 of 54 SECTION 14 — AQUIFER EXEMPTION 20 AAC 25.402(c)(13) All aquifers or portions of aquifers lying below and within one -quarter mile of the Kuperuk giver Unit 2re exen-pted aquifers (ref 40 CFR 147 102(b)(3) and 20 AAC 25.440(c)). CPAI Request for Amendments*15B & A10 2B January 30, 2014 Page 35 of 54 SEC110N N — HYDROCARBON RECOVERY 20 AAC 25.402(C)(14) 'oNest Sate potentiai hydrocarbon recovery by wstertlood was subm+ tted as part of the original area njection order. The purpose of this application is to provide the Commission with evidence of the �,ddit�onal he'nefil of \/RWA(-' inir;clion to recover additional hydrocarbons from the West Sak Oil Pool. )'C,, l C cl t.: S t� ldtEd �ii le eft"CII c:�tein.:tc.0 �.liil Ii� 1 :Cction Of , ajc'I' I jE Ct n of enriched qcs i n 2 h^OdfiGatlO!1 Of rESefv(iU G'I ihat F=r011iGiE innl?!oved iecoveiy (bySVdilling the oil viscosity) and provides energy and drive mechanisms to force the oil to a production well. This method is not appropriate for all applications, but has been proven effective where the following conditions prevail: 1) The crude oil -in -place is sufficiently viscous that it leaves behind an abnormally high residual oil saturation to waterflood, 2) The injected gas can significantly swell the oil and reduce the viscosity of the oil in place Data and conclusions following extensive laboratory testing and pre -pilot studies were submitted and discussed as part of the application for administrative action for injection of enriched hydrocarbon gas for the West Sak DS1E and DS1J VRWAG Pilot Project. VRWAG PILOT PROJECT RESUI-TS Surveillance data and conclusions from the VRWAG pilot project were submitted to the Commission on May 23, 2013 in the form of a final report. The report detailed the positive oil response, increase in gas production, and an increase in total throughput observed during the operation of the VRWAG pilot. Additionally, it included gas compositional data indicating an increase in heavier components during the pilot period. Post-VRWAG pilot pattern simulation models were history matched and used to forecast the potential benefits for the VRWAG process. The results and analysis for these pattern models were detailed in the final report submitted to the Commission. The following three cases were evaluated in the pattern models: 1) the waterflood only case with no gas injection, 2) the waterflood only case with gas injection volume from the VRWAG pilot included, and 3) the VRWAG case with gas injection included in the predictive cases. Exhibit N-1 shows the combined oil recovery versus time for the three pattern models. Exhibit N-2 demonstrates the increase in total throughput with the VRWAG process and the associated increase in oil recovery. The resulting oil rate response in the three pattern models is summarized in Exhibit N-3. The results from the pattern models are the basis for the estimate of projected West Sak core area incremental recovery due to the VRWAG process. Exhibit N-4 is an estimate of the projected oil rate for implementation of VRWAG in the West Sak core area. The projected oil rate is a result of scaling the pattern simulation model outputs to the estimated expansion volume of the new candidate wells. Pattern level simulation results indicate a potential 3-6% incremental recovery for VRWAG at 25% HCPV cumulative gas injection. The estimated expansion target volume is approximately 320 MMSTBO and yields an incremental VRWAG recovery of approximately 13.6 MMSTBO, or 4.3% of OOIP. The base waterflood forecast is derived from the West Sak full field model. Exhibit N-5 shows the projected incremental VRWAG recovery for the West Sak core area is approximately 4.3% of OOIP. Estimates of gas injection and gas production for the West Sak core area were generated based on the pattern simulation results. Exhibit N-6 summarizes the projected gas injection and gas production for the West Sak core area with implementation of VRWAG expansion. The projection estimates a maximum gas injection demand for the West Sak core area of approximately 20 MMSCFD. CPAI Request for Amendments C, 406B & AIO 2B 91 January 30, 2014 Page 36 of 54 As a result of appraising the NEWS (North East West Sak) area and data from the adjoining Prudhoe Bay; Milne Point and Nikiatchuq Unit, opportunities for co -development of the N Sands with the West Sak are now recognized in the eastern Kuparuk area Although oil gravities to -date are lover than similar develo,Dnnents in these adjoining areas, they should be water floodab!e and would benefit from VRVVAG injection As a result of the apparent greater complexity in lateral hydrocarbon distribution N Sand data CG.! rF<i In Sl1I]�Ci7l, h.t 1r�PSt �:;�: andKUt)clti�, �iif"C- A?rlli be rEgw, rcd tl) 1'IOrE IOiij� Gf � cCi'c�i- �;!1Cf op Inav C%F:`JE'IOF"InC;f�! l�ianF. PC)tC I]11a1 hydi 0%aff C ❑ rE ;;C'�,c=.ry Gx1:;Cct6d fro" 1 fhe N Sandi IS EStI'�1ated at �.`; 1111i1!On harrP!5 of O.I. IS 10'/o C lie Currently E SilnlatEd ���� rlltllion iial,els of original oil In place. CPAI Request for Amendments 0,406B & A10 2B January 30, 2014 Page 37 of 54 SECTION O — CONFINEMENT IN OFFSET WELLS 20 AAC 25.402(c)(15) Exhibit 0-'I is a table listing all wells within one -quarter mile of the proposed injectors referenced ctic�� `I i :!�r- best o� C.;.,o� �;rl :J'�� r s r;i<<.ka Inc 's kr,o�v!edce� 'he v��ei�!s v,,itF��:,n the area were: r r :'� C , ,.,'fi r ,, ''C;.''l=;(i t�, lil(;`.•'c'it M, ni.,,.�1�1 ") Oi i�,l'�CiC IrIIU fIC Si': "✓ tei �Cl' I11ieGtl011 WciiS and aS`>C C :cII;d C c erS SEic:CfGd for VR1rVAC :;er\/ CC: ,JI i 've F c r G i e C' I O eis l E' in�eC.tlpn Gf ill 'C I!'t0 the`,ric`_ f J21: f Ol nl �G.l 'l� nCi `eSUlt in c>n Ir;c cased r-st: of f!oid 'G 'C:I''iC' underground sources of drinking water or other hydrocarbon bearing formations. i he initial selecticn criterion includes an evaluation of the drilling and completion of all West Sak., Kuparuk and exploration wells in the proposed area. Wells will be evaluated for initial cement placement information, cement tops and cement integrity data, including bond logs where available to verify compliance with 20 AAC 25.030. Additionally, the mechanical integrity and completion style of each injection well and associated pattern producers will be evaluated to ensure that all wells in each pattern have acceptable completions and sound well integrity. CPAI Request for Amendmentso406B & A10 2B January 30, 2014 Pa �e 38 of 54 I I;b'l ()v I:Xt11Eiix" R-1: PLOT OF THE WEST SAK PA AND ALL EXISTING WELLS F� 2: 11[ OT OF T I I F NFWS FA AND AI I FX 11NG '0F1 I.`; L) I A I' I I I) A V I 'I I 1,IV LS'I SAK 1YPI I ()G li 1 GI NL R I C WI: S'I SAK IN' )L+,CT0r) WFI.[ DFSI(.�N H 2: WEST SAK INJEC:1 ION WELLS I VISCOSITY REDUCING INJECTANT COMPOSITIONS L. 1 WEST SAK CONNATE: WATER COMPOSITION N 1: POS1-VRWAG PILOT SIMULATION - OIL. RECOVERY VS TIME N-2: POST-VRWAG PILOT SIMULATION -- OIL RECOVERY VS H P V I N-3: POST-VRWAG PILOT SIMULATION — OIL RATE VS TIME N-4: WEST SAK CORE AREA PROJECTED OIL RATE N-5: WEST SAK CORE AREA PROJECTED RECOVERY N-6: WEST SAK CORE AREA PROJECTED GAS 0-1 WELLS WITHIN 1/4 MILE RADIUS OF PROPOSED INJECTORS 40 CPA| Roqvegfo,Anendmemn B &�|0 2B Janvary3O.2O14 EXH|BIT B'1PLOT OF THE YVEST SAK PA AND ALL EXISTING VVEL LS 7-1 Vj CPAI Request for Amendments406B & A10 2B January 30, 2014 Paoe 40 of 54 EXHIBIT B-2: PLOT OF THE NEWS PA AND ALL EXISTING WELLS 166eeee 16'leeee IEeeeee ■14MBIE\S! hRs s l.ea rheaff aces kSHT\ � 91\B i([1 SIIIkTLTB CommPhillips KUPRRUK RIVER UNIT NE NEST SRK PART ICIPRTNG AREA NEST SRK OEVELOPMENT NELL POSTED IN BLUE KUPRRUK WELL N SRK PENETRATION IN PURPLE FILL HELLS POSTED AT TOP NEST SRK I kIeR � M. R. YE RM[R ^� •RUL•1611� RRehl. RlRR .m 01 0 AVCG LLC Land Department 510 L Street, Suite 601 Anchorage, AK 99501 BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Chevron U.S.A. Inc. 1029 West 3rd Ave., Ste. 150 Anchorage, AK 99501-1972 Eni US Operating Co. Inc. 1201 Louisianna, Suite 3500 Houston, TX 77002 CPAI Request for Amendments CO 406B & AIO 213 ,January 30. 2014 Page 41 of 54 E X H I E, 11 D - 1 AFLIL)AV1-f STATE OF ALASKA THIRD JUDICIAL DISTRICT I Jarees T. Rodgers. declare..and affifm as follows i. lam tt,e Greater Kuparuk iJr . Sa?eilite Developnient Manager for Conoco Phillips Alaska, Inc the designated Operator of the Kupuitl -, iv.':! Unit, and as such have responsibility for West Sak operations.. 2 On + /1r.Rlt t' 6C, , 2014, 1 caused copies of the West Sak Area Injection Order Amendment Application to be provided to the following surface owners and operators of all land within a cluarter-mile radius of the proposed injection areas: Surface Owners: State of Alaska Department Of Natural Resources Division of Oil and Gas Attention: Mr. Bill Barron, Director 550 West Seventh Avenue, Suite 1100 Anchorage, AK 99501-3557 Operators: 70 & 148 LLC 1421 Blake Street Denver, CO 80202 ASRC Exploration LLC 3900 C Street, Ste. 801 Anchorage, AK 99503 Dated: ExxonMobil Alaska Production Inc. P. 0.Box 196601 Anchorage, AK 99519-601 Great Bear Petroleum Ventures I, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 Great Bear Petroleum Ventures II, LLC 601 West 5th Ave. Ste. 505 Anchorage, AK 99501 Daniel K. Donkel 2000 North Atlantic, Ave. 6th Floor Daytona Beach, FL 32118 Repsol E&P USA Inc. 2001 Timberloch PI., Ste. 3000 The Woodlands, TX 77380 Declared and affirmed before me this `" day of a , 2014. ZT- Notary Public in d for Alaska My commission Expires: m N O Q 06 m 0 v O U c E c a) E Q o N Qc) O ONr Q C N d M U-)d J w x O U w z Y Q w U w z w C7 F- co x w 0 a� c � c w CO C co U) I` m V I 1V N r h y i 3 O U � na -0 N orn � I O U � o a Ln oi • m N O Q 06 m O O O U N C E c CD E Q or QN N 7 O '�- Q ch 0 7 Q) 4 N f�9 U n W � � L L W t� O Cr O O O O O O O `J w O0 -� -, U w w U w w w w w W --) W -) z W 0-Z W Z Z Z Z Z z Q Z W J W W J_ W W LLI W w Q Q ~ Q Q Q Q U_ J J W c� Q w _ W -y Z WLn 0 'V' co:) 0 0000 O b O Y " O O O O CD CD 0N 0N N N N N Q 0 N D N O N (Diz ( CD N N r r N r r r N M r N tC) f O O O O r O CDr O CD CDr 0 0 r- O O <- O O O O W O cD O O (D (D O 0 (D O O (D Co O (D (.O (D 0 c0 w (D O O O (0 (D 4- � r i- r r w m m m R � �' � b N N N N N N N N N M M M N N N M M M N N N M M M Z cM M Co N M M M M M M M M M M M m M M M M M c`7 M co M N N N O N CY) N N N N N N" N N N N N N N N N N N N N N Q N N N Q N N N N N N N N N N N N N N N N N N N N N O O CD CD 0 0 0 0 0 0(D 0 0 0 0 0 0 0 0 0 0 0 0 = p o0�000000 �`OOOO00000000 Q cW _ G r N N N r N ® Q N J N J J r J J 0) N J J J J O J J J J O J J C)--N----r-NN (Lo o (DO (D(Dr t-t` Z J i i r r ' r r ' i r r ' r r ' r r ' r r �" r x W W W i W W i '7 -� r W W W W of r r r r r r r r r r r r r r r • I • u LO 7 CO CD C r C-, -j C, c c z -0 0 -.-1 -I -C -.-1 000 0�o < x (D - - (D M I` ,I M LO 0 0 CD _0 E " CV Co-zT (Z) M c-) co M M CD 0 CD C:) C: IL ice"> 0 00 ',;1- CD CD CD CD CD CD 0 m u Q. Z) CD ro .-o o-o > (D Co co ,:r CD (o �z 0 0 C, Cl) N 0 m co M 0) LO U-) C',j CD 0 CD CD CD cn 0 cn --`� m cD co oo LC) CIJ CD (D CD CD CD CD C) CD CD U to 0 0 LU 0 C2 0 U) CD UJ -0 -o-O -.-1 -.0 0-0 --o0 m -0 LO - IL C) U-) (D M CD r- Co MCC) CD " CD CD C) a) _0 0 (D u-) m I\- M r- (D (D - 0 0 C) CD r- < m M Co CO C) (D CD CD CD CD CD m Ln 2 (n 3: � X m co > IY > CL F Li Y Ln (D _0 0 0 In 1.10 0 .10 0-0-0 0 0 �80- �80- - -.- 10- 0 0 10 ; Q) C: U-) (D CN co U') M 00 - CD 0 0 0 -Z I-- -I- CIJ. ". C). CD. 0. CD. CD. C). E m . r- . . I c 0 C 0 M CD (D CD CD Q CD 0 Q 0 m (D - CD 02 m co CD - CL — G) 0) 0 C: 0 0 0 '0 < d:r LL D 0 C-6 m U) a_ a-0 —i > u E M F- C0 c c c c c q c '0 C) 00 c c c c c m m m m m m M m 0 c 0 z r- CL x C: L) - w 0 C(D 0 C) E L-IJ -0 CZ0, m w 0 z a- E w �R cl- a- cl- a: c a) CN E 0 '.4, N- 0 c- m 0 Q) >< co w =s (1) C)- C 0) (D Co - 0 z L) -) n- 1 CPAI Request toi Amendments 0+06B & A10 213 January 30, 2014 Page 45 of 54 EXHIBIT L"1: WEST SAK OIL POOL CONNATE WATER C0MP0SIT1ON Kuparuk Lab Analytical Report [late: ,lure 41"' W� 17fi 1p 1^Jsitr r'i".rri►;ti, l .,t:41 j 244 +�rn{:u. rir:�nt t ,rig r i,t9;i1ic� + ,�,t;rrri Ch,lr;nde Fluoride ` 1 Ci Iodide 4.8 Sulfate 18 Calcium 9.8 Iron <1 0 (Magnesium 19 Sodium 3480 Barium 3 Strontium 1.4 Silicon 8 Potassium 62 Aluminum 0.3 Chromium < 1 Manganese Lithium 1 Boron 15 Phosphorus 1 PH 7.7 Bicarbonate 6538 m N O Q m 0 v O U c E C N E O � O t� N N _ CT m O N (6 N 7 a M Jo).a4. /(Ja"awaakj it t � b Fo Ui CO N Q 05 a7 UO O 0 U m C N E c E L o� Q)O� mow QM O c� 2 � coo U�d VP Y1 b 7E' f, t I t N fi T15 141.e_ m N O Q CO 0 0 c O U N C N E C N E Q O � w r O11 Qw co O cz Q C 0) a�CD u� F rr as d LU F— U uj n O Q LU LU x O U Y Q N F- V) LU F- OQ 2 X uj p B D D1 T1 1U-dDB N m CL' a: LLl U LU C3 LU U LU O CC a. LU a Q LU w Q U Y Q V) I— uj m N O Q 06 z m o F- lo, O m U _ X E W 0 c E O � LO O 7 p 0 �M � O _ N Q :3 1� In =T Yi ri rn xv r4 rl -1 ti t� JUPOd AJVADCAM N ti D ri to ri in T" V, rq m ,-� tN m 0; 0 CO CV O Q 06 fl] O O U N C E c E Q o� �CLO QM O a C� f9 a C @ r_r a W i U a Q W Q 11.1 0 v Q w cD z m LU v p C) ti Lf1 O O O O O N tD (O N M LA N N N C'J m co m G' C✓J - co C-) O Cl) co 07 N .. V CO C: Ln c,j V C+ O O N N N N CD O c C r c c 7 C., O O O O M (0 ,2 co M co N V J J O O O m m O O O U U 0 a a o 0 z z 1- r- N CD r M Cki (3) LA Lb (D' m M M M M � cc 0 co co Ln In In Ln r` r- N h O Ln m N m m O .- M O N (D (V M N M N m 0 0 0 0 m m m m m (D (D O O M V rn r N N W OJ O M N M O r M w O O 00 v V V V M M M M m N O Q 06 m O Q O U N C N E 'O c aC) C L O LLO N _ O — QM O d - Lo (0 � N m O O m m O O U U U a C. 0 z z W Ln N V 1- N to O O I) N M m 0) O O m mLf) m (.0m m m m m L17 :C') Ln to M 0 � 0 fn N N rn M N N N M O m m 0 m m m m co (D co to (DtD M CD N V V N c,•) M M M LD (D (O m lD N m M T Ln M M n N M Ln d V (D > > > Q Q Q Q O U U U U 0 CO O O a` a a` C)p - (D W W W W @ J C m a) m U o 0 z Ln V V r CO O N O (O m � M � M (n m m Ln Ln Ln (D 00 m Lrn Ln N M N N M m m O m m m CO toLO � 0 Ln Ln m V co O a N rOi cn cn tD O O rcn r M m LD V V C > U U L Q Q Cn O u O u 0 u O al 'c c - a - 0 O O U N N N V CO V N N to UL (O IN OD 11 co CO z r7 'Y , r•, L.n cr' O O V N In (n Ln J J J J � m m m .C)m U U °0 U U b o o n o c z z z z � fp m O co O V N O w N O N M M M CO M m Lo O Ln, (D •- M V 0) m O 0) m m to n (D LA LLn Ln Lo V m rn in rn M rn ITLn Ln Lo In Ln U') Ln m (D ('- N N M M N N M N C,.) V' M m m M m r- O m m O m N m o m m m 0 m (D (D o 0 0 (� m w Lo Ln (C N rn m a0 O V LD ID N O m V N (D m M In m cc c N M M ch co v m 7 7 n 1� M m Ln O M C M �; Ln Ln M V M co L17 N M CO N Ln O (O V t! LL Q Q Q Q Q Q Q N N N O 6 O U U O L) C t� Z) = U D V y U '0 y �o G7 Z t o o a c - a a a n C) (O Lo N co (D N (D �. 4 �2 M -- �2 �!! N �2 `- (< W W W W W W w W W r Y Y Y Y Y Y Y (n (n (n (n CO cn (n 0 cD c0 Y ! i>> Y ` ol o r O O O aY d V N N (D m Ln M (c CID m O t, QL L<') Ln O CC G) CU C� 1- D r, Ln M M co Lr) V c, C? C) O O N Ln ui Ln V to In Ln 0 om-o 8mm 0 0 U O O D U C7 a o a 0 0 z z z v � d' N P- o co m d " N 0 0 r M O N CO rn m h O M L.7 r- C)Ln V V m m m m In Ln � LA Ln Ln Un V V V' in m m rn m m m Ln Li Ln Lo Li) Ln In a O (O m N N M Ln M 0) LD N N O ro M co N N O ct m M M rn m r� r n O O m m 00 O 10 rn (n (D m m rn D 0 m (D m (D 0 (n r Ln < r (D m (D N N N V O m Ln (D Ln (D <t O N O O O O (h M M M M M M 0 C, rl n s s clj c-I �n z 2 Ln a) 0 0 CD W �D 0 _q (D 0 o 0) (,-) o f'- ;1 01 L) M cCVW LNc m O LD NN Cl) NI cl) N ('A LLJ n m M cc -o cn o o c; C-) o o a 0 (-) u 0 o o CD 0 0 CL z z Lli —(D .- C) Lo Lo a� M rn CD r M 4 '7 a) p c:) C:) n o N cl) V rl) N p M o Um C-i -; 03 6 (N c3i Lr -3 CO, a) Lncl) 0) In l co NC) 10 cy) f- Ln o' mo Lo r- Ln o Cc Ln Ln q n N No o Ln tn L") Ln Li)Lo Lr) Lo LnInLn LnLo E 4 -tr q -z I�r v V IT �T �r Iq 1: ", IT 17 ,, 0 C) m a) a) a) G) 0) L, G) cy) m (3) 0) o) o) m a) m Ln Ln U') Lo Ln U-) tr) LO In In In IX) Ln Ln T) Ln co M ;r Ln C) c 2) LO o �q a) 'o 06 N r- Ln 6 (D Lo ;z (3) CN r- 03 a) m 0 Ln w o o 0 m o m L) 'D ED w w oo w w m 0 oo co M m w w m w w m m m m m m m cr) (3) T �2 CO ❑ m Lo n O N oo co u Lr) o) < Lo o (D co Z Z Z Z co co z z z N z Z Z Z u ZI c4 (1) cl) co Cl) cl) r Lo Lo a a < n TO < n < < < < z z z z m Lo (1) Z0 o (D r oo Cl) Cl) N u (1) C M co N M Cl) (1) z CN 0 < < < <a a< < KS 06 C-5 06 06 06 .6 �d .6 -6 0, 0- a- a- 0- a 06 V) < < < < - ID UD 0 W C C C C C C C C C C C c c c E E 2 .2 2 .2 .2 .0 0 0 0 0 o 0 o 0 0 2 -2 �2 .2 o o 2 9 2 — — — — — cn -2 -2 -2 .2 'E' 2 2 E aa a aa EL a- a cl - - Q- cL CL DL a- x x x x X x x x x x x x x x x x a—. LU w w LU w Lij w w w w w w w w W ui E Jro _0 ui q Lo o Fj E _j _j _j �] -j -j -j -4 N o' q _j _j LO CL Q- IL n- a- a- CL a- CL a. a. a. LD to Cl- < < < < < < < < < < < < < < < < 0 LO Z) 0— or c) 0 -le -y- Lo m m m m m m m m ro m m m m m m m m m m v) M cz 2v LL m w o o o w w w w 0 W 0 0 i> i>> i>> �: 3 3 3 —) :� !-� : - 0;1 ei C, 0 Q �2 :4 N2�N Cli Cli ! .0 0 7 E2 * v z Q Q0 Ln Lo u) 'o 6 mU� i) m— C� Cl L3 (D Lf� N0 m v) I- c-) N- cD G, cc r) N o� cO, t- c) " G) v) c, cl, 1+ ul cD cv LO M ;: I-q j r- CD I- LI) (D L) I-r) C c-� C (4 (f) cc) Gh Lo N j- n oo M n n In LO D" Co -oU -0 _j _j -j -o Co Cn Ca cc Co -o -0 !DO CD M 110 um Uo C) U o Uu o o 0 0 o CD 00 0 (D (3 000 (D 000 Ci z z z z z z z z z z Llj Co Co m Lo r- ZT It G) (D 1p Ln LO I- "I cl) Lo C) n "I a) m r) m co m n r) �T o — v) -4 r- " co m c-) 'q 04 6 c6 6 c m I'- 0 r� Ci r- Co r- - I - (v m o v) I,. 'n ko 'T v Lo IQ3 cr) u� 4n ID v u) Go q Lo clo u5 Lo Lo v v 4:P V) o In W Lo Lr) LO 0 0 (n -j .I Lr) q q 'T 'ZT m c7) c) m d) a) v 'I Lo q a) (D m Lo 'It Ln ;T q 't C) (3) m M v) w Ln Lo Ln Lo Lo In u) L11) Ln LO Lo LLnLn in Lo 'o CL o) N CO OD r-- N oo a) w CO CC) - Mco Mr,� DOo) M Lo co Ln cc) NX m U) C a) 0 4 ui N O O 4 -i Lo N N O N 6 6 LL u 'Z ra th N Ln — 0 oo C') ,I r- Fq N ID co C-) t- Lo ID r- r- o) , o m co oo r� OD p ;z a) mm t- m (D r- o C u Co I- (D r- oo o oo m m m w o w w w mo a) a) w oo 0 w a) 0) o o) = 0 oo oo co cn o) a) G) 0 V) -1 0) a) a) m (7) a) to (D (.D Qo u:) (D CD rl- Co (,4 LO m (D cc) c� co 0) r- C) a) w m oo CY, I'- U) co co N co 00 . r Ln m Ln ro 'IT -,+ CD mLO < C >1 7 c6 6 oo rl- Iq N Lo r- (D oo Co Gi r-� -�r c) r- C6 cqo o Z; ,zr r� m Ln c\l Lr) m" 10 — = .01 ., S N n N N N 0 Nro N m NLn r Ln 'Y� 0 0 0 0 0 M co U z m Co C) n c') l) o-) Cl) M(1) m M m (o w Lo co 11) m LO 'LP Ln 1 c7, " ko rp c� M m 0 Co (D cc) r- (6 0) cN CD o) Ln r- C) co CN F- co c�) Ln t- c) c) -T a) Ln Ln C) ro Lo -Z. Lo (o q r-- 'T to m "q Lo oo a) C�, 1, ID to ff) In 'IT -T r- G) N1-7 0 < (J) (f) 21 a) z t Co U < < < < QQQQ < < < QQQQQ (D (n 0 0 (D� -0 -W DL) 0 L) u C) .2 L) U t : L) U U L) U m 7 =) -o -o 'D U U :3 M c) -o3 (L 2 'E 0 S (D 2 2 2 02 2 2 R, c 2 2 c: E r C Q) E C� u� (D (D co C) v �o to to NC:) o) cq NM 0 o N co (f) to (D LO t- Lu 1� N'It (L) - tr) :3 CD — 0 x y Je -'e -,me -,me %e -,If x x IC m m m m Lo m m m m m - 0 LO 0 0 LO 0 0 (n U) co N (n cL (n (1) (n V;Vn �w Z6 N a) LL a) a) =3 a) (k) a) -a)
