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Home My WebLink AboutAIO 035INDEX AREA INJECTION ORDER NO. 35 Colville River Field Colville River Unit Qannik Oil Pool 1. April 3, 2008 ConocoPhillips Alaska, Inc.’s (CPAI) Application for Area Injection Order 2. April 9, 2008 Notice of Public Hearing, Affidavit of Publication, mailings 3. May 15, 2008 Transcript 4. May 27, 2008 AOGCC’s request to CPAI for more information 5. May 27, 2008 Operator’s supplemental information 6. May 28, 2008 Operator’s supplemental information 7. February 27, 2009 Operator’s request for Administrative Approval to amend the fluids authorized for enhanced oil recovery (AIO 35.001) 8. November 5, 2010 Backup information AIO 35.002, corrected on 12/2/10 9. May 8, 2013 – August 16, 2013 Amendment of Alternative MIT schedule for UIC injection Wells and background information 10. February 28, 2018 CPA Request for Administrative Amendment, CRU (AIO35.003) 11. May 26, 2021 CPAI request to reinstate AIO 18A with modifications (AIO 35.004) INDEX AREA INJECTION ORDER NO. 35 ORDERS • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 35 CONOCOPHILLIPS ALASKA, ) Docket No. AIO 08-24 INC. for an order authorizing ) underground injection of fluids for ) Colville River Field enhanced oil recovery in the Qannik ) Colville River Unit Oil Pool, Colville River Unit, Arctic ) Qannik Oil Pool Slope, Alaska ) July 7, 2008 NOTICE CLOSING DOCKET BY THE COMMISSION: The Commission has the closed the Docket in the above captioned matter. ENTERED AND EFFECTIVE at Anchorage, Alaska and this 7th day of July, 2008. BY DIRECTION OF THE COMMISSION h Jo J. Colombie S ial Assistant to the Commission • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) CONOCOPHILLIPS ALASKA, ) INC. for an order authorizing ) underground injection of fluids for ) enhanced oil recovery in the Qannik ) Oil Pool, Colville River Unit, Arctic ) Slope, Alaska ) Area Injection Order No. 35 Docket No. AIO 08-24 Colville River Field Colville River Unit Qannik Oil Pool July 7, 2008 IT APPEARING THAT: 1. By letter and application dated April 3, 2008, and received by the Alaska Oil and Gas Conservation Commission (Commission) that same day, ConocoPhillips Alaska, Inc. (CPAI), in its capacity as unit operator and on behalf of the working interest owners of the Colville River Unit (CRU), requests an order from the Commission authorizing the injection of fluids for enhanced oil recovery in the Qannik Oil Pool. 2. A notice of a public hearing was published in the ANCHORAGE DAILY NEws, on the State of Alaska Online Public Notice Web site, and on the Commission's Web site on Apri19, 2008. 3. The Commission received no comments or requests for a public hearing. 4. The Commission held a public hearing on May 15, 2008, and left the record open so that CPAI could provide additional information requested at the hearing. 5. On May 27 and May 28, 2008, as requested by the Commission at the public hearing, CPAI provided revised information concerning existing wells penetrating the Qannik reservoir. FINDINGS: 1. Operator: CPAI is the operator of the leases in the area proposed for development. 2. Project Area Pool and Formations Authorized for Enhanced Recovery: Enhanced oil recovery injection is proposed within the Qannik Oil Pool, which is defined in Conservation Order No. 605. The target injection zone is the Qannik Oil Pool, which is correlative to the interval between the measured depths of 6,086' and 6,249' on the Electromagnetic Wave Resistivity (EWR) well log recorded in well CRU CD2-11 (see Figure 1, below). 3. Proposed Injection Area: CPAI requests authorization to inject fluids for the purpose of enhanced recovery operations on lands in or near the CRU within portions of Township (T) l ON, Range (R) 4E; T l ON, RSE; T 11 N, R4E; T 11 N, RSE; T 12N, R4E; and T 12N, RSE, Umiat Meridian (see Figure 2, below). • Area Injection Order 35 July 7, 2008 Figure 1. CRU CD2-11 -Type Well Log for Qannik Oil Pool ~ Page 2 4. Operators/Surface Owners Notification: All lands within the proposed development area are leased and lie in or near the CRU. The only affected surface owners are the State of Alaska, Department of Natural Resources and Kuukpik Corporation. The affected operator is CPAI, which operates the CRU. CPAI provided the application for injection to all operators and surface owners within aone-quarter-mile radius of the proposed injection operations. ~ Figure 1 is for illustration purposes only. Refer to the EWR well log measurements recorded in well CRU CD2-1 1 for the precise representation of the Qannik Oil Pool. • Area Injection Order 35 July 7, 2008 • Page 3 Figure 2. Proposed Injection Area for Qannik Oil Pool'- (highlighted with yellow) 5. Description of Operations: The Qannik Oil Pool will be developed initially with nine horizontal wells: the CD2-404 well and eight new wells. The producer-to-injector ratio will be about 2:1. The production and injection wells will range in length from 6,000' to 9,000' within the reservoir, and will be parallel to one another. Three central, north-trending injection wells will be arranged end-to-end and flanked on both sides by outboard production wells; this alternating arrangement will form aline-drive flood pattern. Individual wells will be spaced about 2,700' to 3,400' apart. The wells will be oriented to maximize use of the expansion drive and minimize gas influx from the gas cap, which lies to the east. Additional producers and injectors may be added at a later date based on net oil pay and reservoir performance. CPAI proposes to develop the pool utilizing water injection as the enhanced recovery mechanism, supplemented by expansion drive from the gas cap. Water injection is scheduled to begin in the third quarter of 2008. Production from the Qannik Oil Pool and other CRU oil pools will be commingled on the surface prior to processing and custody transfer. 6. Hydrocarbon Recovery: Estimates of original oil-in-place and recovery (in units of one million stock tank barrels or MMSTB) within the Qannik Oil Pool development area are: ' This index map is for illustration purposes only. Please refer to the legal description for the precise representation of the proposed affected area. Area Injection Order 35 July 7, 2008 Page 4 Nine-Well Eighteen-Well Hydrocarbon Volume Development Development (MMSTB) (MMSTB) Original Oil-in-Place (OOIP) 79 127 Primary Recovery with Gas Cap Expansion 12 19 (15% of OOIP) Primary + Waterflood (a total of 22% of OOIP) 17 28 The annualized peak production rate for the Qannik Oil Pool is expected to be between about 3,000 and 6,000 barrels of oil per day (BOPD). The expected maximum and average waterflood injection rates are 12,000 barrels of water per day (BWPD) and 5,000 BWPD, respectively. 7. Geolo~y: a. Stratigraphy: The Qannik Oil Pool encompasses late Cretaceous-aged sediments deposited as top-set beds in a shallow, north-trending, eastward-migrating marine shelf environment that is the age-equivalent to the Nanushuk Group of the central Arctic Slope. The Qannik sediments consist of very fine-to fine-grained sandstone deposited as a thin (up to 35' of gross sand), elongate deposit that extends at least 12 miles north-to-south, along depositional strike, and about 6 miles west-to-east, along depositional dip. Within the CRU, the Qannik sandstone is very fine-grained and lithic-rich. Net pay is up to 22' thick, and averages 10' to 15'. Porosity is 20 to 25 percent, and permeability ranges from 10 to 50 millidarcies. Qannik core averages 38 percent water saturation. b. Structure: Within the proposed development area, the Qannik reservoir sandstone occurs in anorth-south, very low-relief syncline. No seismically mappable faults are present. c. Trap Confi urg ation: Well log and seismic information indicate that the Qannik accumulation is a stratigraphic trap. The Qannik sandstone is truncated to the west and shales out to the east. A gas-oil contact exists at about -4,000 feet true vertical depth subsea (TVDSS). An oil-water contact has not been observed in the proposed development area. d. Confining Intervals: The Qannik Oil Pool is overlain and underlain by thick accumulations of marine shale and siltstone that are assigned to the Torok Formation and laterally continuous throughout the proposed development area. 8. Well Lois: Logs of injection wells will be filed with the Commission according to the requirements of 20 AAC 25. 9. Mechanical Inte rity and Design of Injection Wells: The casing and cementing programs for all injection wells will comply with 20 AAC 25.030. • Area Injection Order 35 July 7, 2008 Page 5 Cement-bond logs will be run to demonstrate the isolation of injected fluids to the Qannik reservoir as required by 20 AAC 25.412(d). Mechanical integrity tests will be performed in accordance with 20 AAC 25.412(c). To facilitate wireline access, CPAI requests an exception to 20 AAC 25.412(b) to allow packers in injection wells to be located more than 200' measured depth above the top of the injection zone; however, packers will not be located above the confining zone. 10. Type of Fluid /Source: Fluids requested for injection are: a. source water from the Kuparuk sea water treatment plant; b. produced water from other pools within the Colville River Field; and c. produced water from the Qannik Oil Pool. 11. Water Compatibility with Formation: CPAI conducted a formation damage study using Qannik reservoir core and high salinity brine (149,000 ppm total dissolved solids (TDS)) and low salinity brine (24,600 ppm TDS). No catastrophic loss of permeability was observed with either brine; however, the injection of low-salinity brine caused a gradual reduction in permeability, which was attributed to the migration of fines. 12. Infection Rates and Pressures: Injection rates will be adjusted to manage reservoir voidage. The maximum expected injection well rate is 12,000 BWPD, and the average expected injection well rate is 5,000 BWPD. Injection pressures are expected to average approximately 2,400 psi at the wellhead. Injection wells may be choked to lower wellhead pressures to manage injection rate. Original pressure of the Qannik reservoir was measured at about 1,850 psi at 4,000' TVDSS, and the bubble point is about 1,850 psi. The proposed project will be operated to attempt to maintain the average Qannik Oil Pool pressure within plus or minus 200 psi of original pressure. 13. Fracture Information: Normal water injection pressure will exceed the Qannik reservoir rock parting pressure. Computer modeling indicates fractures will propagate into, but not through, the Torok shale beds that bound the pool above and below. Injection fluids will remain within the Qannik reservoir. 14. Absence of Underground Sources of Drinking Water: According to the findings and conclusions of Area Injection Orders 18, 18A, and 18B, there are no underground sources of drinking water beneath the permafrost in the Colville River Unit area. Examination of well log data from exploratory wells in and near the proposed Qannik development confirms that there are no aquifers within the affected area that could serve as underground sources of drinking water. 15. Mechanical Condition of Adjacent Wells: There are 20 penetrations of the Qannik reservoir within a 1/4-mile radius of the proposed injection well trajectories. 1 penetration is a plugged and abandoned exploration well; 9 penetrations are active Alpine development wells; 9 penetrations are active Alpine service wells; and 1 penetration is an active Qannik service well (CD2-404). With the exception of one recently drilled Alpine service well and CD2- 404, the Qannik reservoir is not cemented in any of the remaining wellbores. Where L~ • • Area Injection Order 35 July 7, 2008 Page 6 uncemented annuli exist, there is a potential for fluids to migrate from the Qannik reservoir. CPAI does not believe that migration from the Qannik is likely due to the presence of dehydrated mud in the annuli, collapse of shales in the intervals above and below the Qannik due to exposure to water based drilling mud, and the need for any applied hydraulic pressure to exceed formation leakoff pressures. CPAI is proposing to expand the annuli pressure monitoring program required by Enhanced Recovery Injection Order No. 4 (ERIO 4) for the well CD2-404 Pilot Injection Project in what was referred to at that time as the Qannik accumulation,. The outer annuli (OA) of all wells within'/4 mile of the proposed injection well trajectories will be equipped with wireless pressure transducers to allow continuous monitoring of OA pressures. No pressure anomalies were identified during the ERIO 4 pilot injection project. CONCLUSIONS: 1. The requirements of 20 AAC 25.402 have been met. 2. The injection of water will significantly improve oil recovery from the Qannik Oil Pool. 3. There are no underground sources of drinking water beneath the proposed affected area. 4. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbores and appropriate operating conditions. 6. Setting the packers in the injection wells more than 200' MD above the injection interval to facilitate wireline access will not increase the risk of an injection fluid confinement failure. Provided that the packer is set at least 300' MD below the top of the production casing cement and is not above the confining zone. 7. Laboratory testing has shown that the fluids proposed for injection are compatible with the Qannik reservoir. 8. Reservoir pressure will be maintained within plus or minus 200 psi of original reservoir pressure. 9. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests, will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 10. The Qannik is not cemented in 18 of 20 penetrations within a '/4-mile radius of the proposed injection well trajectories. In order to ensure injection fluid confinement, an outer annular pressure monitoring program is necessary. 11. Sufficient information has been provided to authorize injection of water into the Qannik Oil Pool for the purposes of pressure maintenance and enhanced oil recovery. • Area Injection Order 35 July 7, 2008 NOW, THEREFORE, IT IS ORDERED that: Page 7 The underground injection of fluids for pressure maintenance and enhanced oil recovery is authorized in the following area, subject to the following rules and, to the extent not superseded by these rules, the statewide requirements of 20 AAC 25: Affected Area: Umiat Meridian Township, Range Sections T10N, R04E 1 - 4 T10N, ROSE 4 - 6 T11N,R04E 1 -4;9- 16;21-28;33-36 T11N,ROSE 4 -9; 16 -21;28-33 T12N, R04E 1 - 4; 9 - 16; 21 - 28; 33 - 36 T12N,ROSE 4 -9; 16 -21;28-33 Rule 1 Authorized Infection Strata for Enhanced Recovery Authorized fluids (under Rule 3, below) may be injected for purposes of pressure maintenance and enhanced oil recovery within the Affected Area into strata that are common to, and correlate with, the interval between the measured depths of 6,086' and 6,249' on the EWR log recorded in well CRU CD2-11. Rule 2 Well Construction To facilitate wireline access, packers in injection wells may be located more than 200' measured depth above the top of the Qannik Oil Pool; however, packers shall not be located above the confining zone. The production casing cement volume must be sufficient to place cement a minimum of 300' measured depth above the planned packer depth. Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk sea water treatment plant; and b. produced water from the Colville River Field. Any other fluids shall be approved by separate administrative action. Rule 4 Authorized Infection Pressure for Enhanced Oil Recovery Normal injection pressures must be maintained such that the injected fluids do not fracture the confining zones or migrate out of the approved injection strata. • • • Area Injection Order 35 July 7, 2008 Rule 5 Monitoring Tubing-Casing Annulus Pressure Page 8 The tubing and casing annuli pressures of each injection well and the OA pressures of all wells that are not cemented across the Qannik reservoir located within a 1/4-mile radius of a Qannik injector must be monitored at least daily, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for Commission inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 7 Well Integrity and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence (including OA pressure monitoring of all wells within a '/4-mile radius of where the Qannik is not cemented), the Operator shall notify the Commission by the next business day and submit a plan of corrective action on a Form 10-403 for Commission approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Notification of Improper Class II Infection Injection of fluids other than those listed in Rule 4 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the Commission, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injection wells. Injection may not be restarted unless approved by the Commission. • Area Injection Order 35 July 7, 2008 Page 9 Rule 9 Other Conditions The Commission may suspend, revoke or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 10 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission 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 date~i,July 7, 2008. Daniel T.~eamount, Jr., Chair Alasl~ Il andC~as Conservation Commission and Gas Conservation Commission ~~ Cathy P. F erster, Commissioner Alaska O' and Gas Conservation Commission RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration aze FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." • In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, July 07, 2008 10:51 AM Subject: aio35 - CRU - Qannik Oil Pool Attachments: aio35.pdf BCC:'Dale Hoffman'; Fridiric Grenier; Joseph Longo; 'Lamont Frazer'; 'Mary Aschoff ; Maurizio Grandi; Tom Gennings; 'Willem Vollenbrock'; 'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth ; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg M (DEC); 'Gregg Nady'; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; keelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'marty'r 'Matt Rader'; 'Meghan Powell'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:aio35.pdf; Jody Jaylene Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 7/7/2008 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Mark Wedman Baker Oil Tools 200 North 3rd Street, #1202 Halliburton 4730 Business Park Blvd., #44 Boise, ID 83702 6900 Arctic Blvd. Anchorage, AK 99503 Anchorage, AK 99502 Schlumberger Ciri Ivan Gillian Drilling and Measurements Land Department 9649 Musket Bell Cr.#5 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99507 Anchorage, AK 99503 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burgiin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl North Slope Borough Williams Thomas K&K Recycling Inc: PO Box 69 Arctic Slope Regional Corporation PO Box 58055 Barrow, AK 99723 Land Department Fairbanks, AK 99711 PO Box 129 Barrow. AK 99723 {may /(.f-//L° ~~ J. 70 ~ JC • ~i ~ ' ~ 1 ~) ~ B~ ~ ~ ~ ~ SARAH PALIN, GOVERNOR L~i4[>•a7~ OII/ ~ IZAS 333 W. 7th AVENUE, SUITE 100 CO1~T5ERQATI011T COMI~II551O1Q ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 35.001 Mr. Scott Reed ConocoPhillips Alaska Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: The application from ConocoPhillips Alaska, Inc. to amend the fluids authorized for enhanced oil recovery injection into the Qannik Oil Pool, Colville River Unit, North Slope, Alaska. Dear Mr. Reeder: ConocoPhillips Alaska, Inc. ("CPAI") requested by letter dated February 27, 2009 an amendment to Area Injection Order (AIO) 35, Rule 3 ("Authorized Fluids ,for Enhanced Recovery") for the Qannik Oil Pool. CPAI's specific request is the inclusion of small amounts of fluids collected from sumps, hydrotests, rinsate from washing mud hauling trucks, excess well work fluids, and treated camp waste water for injection into the Qannik Oil Pool for enhanced oil recovery. The requested amendment will make consistent the fluids authorized for injection in the other AIO's associated with Colville River Unit oil pools. CPAI's request is approved. Fluids authorized for injection into the Qannik Oil Pool for purposes of enhanced oil recovery are limited to source water from the Kuparuk seawater treatment plant and produced water from the Colville River Field. AIO 35 provides for the approval of other fluids by administrative action. The Commission was notified on December 15, 2008 of a misinjection of treated waste water originating from the Alpine camp. Dates of the misinjection were December 8-12, 2008. CPAI stated that 27 barrels of treated waste water were injected into 3 Qannik wells -CD2-404, CD2-466, and CD2-467. CPAI reasoned that the misinjection was in part an oversight, noting that they inadvertently missed including a broader list of fluids including treated waste water in its injection order application for the Qannik Oil Pool. CPAI further cites as evidence the inclusion of these additional fluids for injection in all other approved enhanced oil recovery projects within Colville River Unit -oil pools. This misinjection is addressed by separate correspondence. The Commission agrees with CPAI's assessment that there is no reason to believe that including the requested fluids -namely small amounts of fluids collected from sumps, hydrotests, rinsate from washing mud hauling trucks, excess well work fluids, and treated camp waste water - in the fluids authorized for injection in AIO 35, Rule 3 will have a detrimental impact to enhanced oil ADMINISTRATIVE APPROVAL. AIO 35.OOi • March 11, 2009 Page 2 of 2 recovery from the Qannik Oil Pool. The Commission further finds that injecting the subject fluids will not promote waste or jeopardize correlative rights, and will not contribute to the potential for fluid movement outside of the injection zone. DONE at Anchorage, Alaska y, Daniel T. Seamount, Jr. Chair RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs unti15:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, March 17, 2009 2:01 PM Subject: aio2b-041; aio33-001; aio34-001; aio35-001 Attachments: aio35-001.pdf; aio34-001.pdf; aio33-001.pdf; aio2b-041.pdf BCC:'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil ; 'Gregg Nady'; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; Thompson, Nan G (DNR); 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; 'Aaron Gluzman'; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:aio35-001.pdf;aio34-001.pdf;aio33-OO l .pdf;aio2b-041.pdf; Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793-1221 (phone) (907)276-7542 (fax) 3/17/2009 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 . � s WE OF ALASKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GALS 333 W. 7th AVENUE, SUITE 100 CONSERTATION C01101ISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AIO 18C.001 ADMINISTRATIVE APPROVAL AIO 28.003 ADMINISTRATIVE APPROVAL AIO 30.004 ADMINISTRATIVE APPROVAL AIO 35.001 Mr. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 RE: Application to Allow Injection of Kuparuk River Unit Produced Water into the Following Oil Pools No. 18C Alpine Oil Pool No. 28 Nanuq Oil Pool No. 30 Fiord Oil Pool No. 35 Qannik Oil Pool Colville River Field Dear Mr. Walker: In accordance with Rule 11 of Area Injection Orders (AIO) 18C, 28, and 30, respectively governing the Alpine Oil Pool, Nanuq Oil Pool, and Fiord Oil Pool, and Rule 10 of AIO 35 governing the Qannik Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) CONDITIONALLY GRANTS ConocoPhillips Alaska, Inc.'s (CPAI) request for administrative approval to inject produced water from the Kuparuk River Unit (KRU) into the aforementioned oil pools. Due to a fuel gas line failure, the CPAI- operated seawater treatment plant in the KRU is unable to move seawater to the Colville River Field (CRF). In order to prevent the seawater transport pipeline from freezing, CPAI has begun to displace the line with warmer produced water from the KRU. CPAI expects the displacing operation to require approximately 26,000 bbls of produced water obtained from the CPF -2 facility in the KRU. Once the seawater treatment plant is back in operation, CPAI will begin shipping seawater to the CRF again and thus displace the KRU produced water that will be occupying the seawater transport pipeline. Currently, the aforementioned AIOs, as amended, do not authorize injection of produced water from the KRU for enhanced recovery purposes, so the only option currently available to accommodate the AIO 18C.001 AIO 28.003 AIO 30.004 AIO 35.001 November 5, 2010 Page 2 of 3 produced water from the KRU is to inject it into one or both of the Class I disposal wells in the CRF. These two wells don't have a high injection rate capability, so it would take several days to completely purge the seawater pipeline of KRU produced water. As such CPAI has requested authorization to inject the KRU produced water into the aforementioned oil pools for enhanced recovery purposes. CPAI has provided compositional analyses of the produced water from the KRU and CRF as well as compositional analysis of the Beaufort seawater shipped to the CRF. The composition of the KRU produced water is very similar to the CRF produced water, so there should not be any formation compatibility issues with injection of this water. There are some differences between the KRU produced water and the Beaufort seawater that could lead to scale deposition, however the use of scale inhibitors and the small relative volume for the produced water to be injected, 26,000 bbls versus the normal monthly injection volume of 3 mmbbls, should result in negligible amount of scale deposition. The Commission has determined that the proposed action does not require notice and public hearing, will 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. Therefore, in accordance with Rule 11 of AIOs 18C, 28, and 30, and Rule 10 of AIO 35, the Commission administratively amends the orders to authorize the injection of up to 30,000 barrels of KRU produced water for enhanced oil recovery purposes. CPAI must use an appropriate scale inhibitor to minimize the possibility of formation damage due to scale deposition when mixing of KRU produced water and Beaufort seawater from the seawater treatment plant. This administrative approval does not exempt CPAI from obtaining additional permits or approvals required by law from other governmental agencies. ENTERED at Anchorage, Alaska, d d vember 5, 2010. "LIG c es � ani T. Se ount, Jr. J . N Cathy P. Foerster I , Chair om �10 r Commissioner ��t. II AI0 18C.001 AIO 28.003 AIO 30.004 AIO 35.001 November 5, 2010 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Fisher, Samantha J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, November 05, 2010 4:04 PM To: Aaron Gluzman; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; Dale Hoffman; David Lenig; Gary Orr; Jason Bergerson; Joe Longo; Lara Coates; Marc Kuck; Mary Aschoff; Matt Gill; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; Sandra Lemke; Talib Syed; Tiffany Stebbins; Wayne Wooster; William Van Dyke; Woolf, Wendy C (DNR); (foms2 @mtaonline.net); ( michael .j.nelson @conocophillips.com); (Von. L. Hutchins@conocophillips.com); AKDCWellintegrityCoordinator; Dennis, Alan R (DNR); alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; Dave Matthews; David Boelens; David House; David Steingreaber; ddonkel @cfl.rr.com; Deborah J. Jones; Delbridge, Rena E (LAA); Dennis Steffy; Elowe, Kristin; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Rogers, Gary A (DNR); Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff; Harry Engel; Jdarlington (jarlington @gmail.com); Jeanne McPherren; jeff.jones @alaskajournal.com; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; news @radiokenai.com; John Garing; Katz, John W (GOV); John S. Haworth; John Spain; John Tower; Jon Goltz; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kim Cunningham; Ostrovsky, Larry Z (DNR); Laura Silliphant; crockett @aoga.org; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark Kovac; Mark P. Worcester; Marquerite kremer; Michael Dammeyer; Michael Jacobs; Mike Bill; mike @kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Figel; PORHOLA, STAN T; Randall Kanady; Randy L. Skillern; rob.g.dragnich @exxonmobil.com; Robert Brelsford; Robert Campbell; Rudy Brueggeman; Ryan Tunseth; Scott Cranswick; Scott Griffith; Scott, David (LAA); Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Steve Moothart; Steven R. Rossberg; Suzanne Gibson; tablerk; sheffield @aoga.org; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); yjrosen @ak.net; Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: aiol8 -001, aio 28 -003, aio 30 -004 and aio35 -001 (All within the Kuparuk River Unit) Attachments: aiol8c -001, aio 28 -003, aio30 -004 and aio 35 -001 KRU.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil ho o fs P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider US Geological Survey Gordon Severson P.O. Box 69 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 0 ALASKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GRAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION CommSSIOH ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 CORRECTED ADMINISTRATIVE APPROVAL AIO 18C.001 ADMINISTRATIVE APPROVAL AIO 28.004 ADMINISTRATIVE APPROVAL AIO 30.004 ADMINISTRATIVE APPROVAL AIO 35.002 Mr. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 RE: Application to Allow Injection of Kuparuk River Unit Produced Water into the Following Oil Pools No. 18C Alpine Oil Pool No. 28 Nanuq Oil Pool No. 30 Fiord Oil Pool No. 35 Qannik Oil Pool Colville River Field Dear Mr. Walker: The Commission has corrected the Administrative Approval to reflect the correct number in AIO 28 and AIO 35. In accordance with Rule II of Area Injection Orders (AIO) 18C, 28, and 30, respectively governing the Alpine Oil Pool, Nanuq Oil Pool, and Fiord Oil Pool, and Rule 10 of AIO 35 governing the Qannik Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) CONDITIONALLY GRANTS ConocoPhillips Alaska, Inc.'s (CPAI) request for administrative approval to inject produced water from the Kuparuk River Unit (KRU) into the aforementioned oil pools. Due to a fuel gas line failure, the CPAI- operated seawater treatment plant in the KRU is unable to move seawater to the Colville River Field (CRF). In order to prevent the seawater transport pipeline from freezing, CPAI has begun to displace the line with warmer produced water from the KRU. CPAI expects the displacing operation to require approximately 26,000 bbls of produced water obtained from the CPF -2 facility in the KRU. Once the seawater treatment plant is back in operation, CPAI will begin shipping seawater to the CRF again and thus displace the KRU produced water that will be occupying the seawater transport pipeline. Currently, the aforementioned AIOs, as amended, do not authorize injection of produced water from the KRU AIO 18C.001 • AIO 28.004 AIO 30.004 AIO 35.002 December 2, 2010 Page 2 of 3 for enhanced recovery purposes, so the only option currently available to accommodate the produced water from the KRU is to inject it into one or both of the Class I disposal wells in the CRF. These two wells don't have a high injection rate capability, so it would take several days to completely purge the seawater pipeline of KRU produced water. As such CPAI has requested authorization to inject the KRU produced water into the aforementioned oil pools for enhanced recovery purposes. CPAI has provided compositional analyses of the produced water from the KRU and CRF as well as compositional analysis of the Beaufort seawater shipped to the CRF. The composition of the KRU produced water is very similar to the CRF produced water, so there should not be any formation compatibility issues with injection of this water. There are some differences between the KRU produced water and the Beaufort seawater that could lead to scale deposition, however the use of scale inhibitors and the small relative volume for the produced water to be injected, 26,000 bbls versus the normal monthly injection volume of 3 mmbbls, should result in negligible amount of scale deposition. The Commission has determined that the proposed action does not require notice and public hearing, will 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. Therefore, in accordance with Rule 11 of AIOs 18C, 28, and 30, and Rule 10 of AIO 35, the Commission administratively amends the orders to authorize the injection of up to 30,000 barrels of KRU produced water for enhanced oil recovery purposes. CPAI must use an appropriate scale inhibitor to minimize the possibility of formation damage due to scale deposition when mixing of KRU produced water and Beaufort seawater from the seawater treatment plant. This administrative approval does not exempt CPAI from obtaining additional permits or approvals required by law from other governmental agencies. ENTERED at Anchorage, Alaska, and dated November 5, 2010. Corrected on December 2, 2010. , "01 Daniel T. Seamount, Jr, o . orman Commissioner, Chair Com ssioner oy N�a AIO 18C.001 AIO 28.004 AIO 30.004 AIO 35.002 December 2, 2010 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, December 02, 2010 1:22 PM To: (foms2 @mtaonline.net); ( michael .j.nelson @conocophillips.com); (Von. L. Hutchins@conocophillips.com); 'AKDCWelllntegrityCoordinator'; Alan Dennis; alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; caunderwood; Chris Gay; Cliff Posey; Crandall, Krissell; dapa; Daryl J. Kleppin; Dave Matthews; David Boelens; David House; David Steingreaber; 'ddonkel @cfl.rr.com'; Deborah J. Jones; Delbridge, Rena E (LAA); 'Dennis Steffy'; Elowe, Kristin; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary 9 Schultz' , hammons; Gordon Pospisil; Gorney, David L.; 'Greg Duggin'; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @gmail.com); 'Jeanne McPherren'; Jeff Jones; Jeffery B. Jones Qeff.jones @alaska.gov); Jerry McCutcheon; Jill Womack; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'Michael Dammeyer'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike[ Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g. drag nich @exxon mobil. com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; Tamera Sheffield; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; 'Valenzuela, Mariam'; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary, J (DNR); Yereth Rosen; 'Aaron Gluzman'; Bettis, Patricia K (DNR); 'Dale Hoffman'; David Lenig; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; Marc Kuck; 'Mary Aschoff; 'Matt Gill'; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Sandra Lemke'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Shartzer, Christine R (DOA) Subject: aio18c -001, aio28 -004, aio30 -004, aio 35- 002.pdf - KRU Attachments: aio18c -001, aio28 -004, aio30 -004, aio 35- 002.pdf Attached is a corrected Administrative Approval correcting the numbers. I apologize. Jody Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K &K Recycling Inc. Land Department Baker Oil ho o fs P.O. Box 58055 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider US Geological Survey Gordon Severson P.O. Box 69 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE Alaska Oil and Gas ofAT ASKA Conservation Commission GOVERNOR BILL WALKER ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 28.007 AREA INJECTION ORDER NO. 30.010 AREA INJECTION ORDER NO. 35.003 Mr. Stephen Thatcher Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Re: Docket Number: A10 18-014 Request for administrative approval to amend approved fluids for enhanced oil recovery injection for the Colville River Field. Colville River Field Colville River Unit Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the list of fluids authorized for injection for enhanced oil recovery (EOR) purposes in the Colville River Field (CRF) to allow the injection of produced water from the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU).1 In accordance with Rule 11 of Area Injection Orders (AIO) No. 28, 30, and 35, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to amend the list of fluids approved for EOR purposes in the CRF. ' The application only applies to AIOs for the Nanug, Fiord, and Qannik Oil Pools because the language currently in the AIO for the Alpine Oil Pool will allow the injection of the produced water from the LOP for enhanced recovery purposes. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 2 of 4 CPAI plans to commence production from the LOP in late 2018 and will ship produced fluids from the LOP to the CRF where they will be commingled with production from the Alpine Oil Pool, Nanuq Oil Pool, Fiord Oil Pool, and Qannik Oil Pool before being processed at the Alpine Central Facility (ACF). Since production is commingled prior to processing, the produced water and gas streams to be used for EOR injection at both the CRF and the LOP will contain fluids from both fields. Only the AIO for the Alpine Oil Pool in the CRF allows injection of gas and water from the LOP for EOR purposesz. The AIO's for the Nanug3 and Fiord' Oil Pools allow the injection of miscible injectant from the ACF and produced water from the CRF5. The Qannik Oil Pool AIO does not allow gas injection but does allow the injection of produced water from the CRF. The LOP is an Alpine formation development, as is the Alpine Oil Pool, so no fluid compatibility issues are anticipated to arise from injecting the produced water from the LOP into the CRF oil pools, provided any required treatment is continued. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented by being able to use the produced water from the LOP for EOR purposes in the LOP and CRF. Correlative rights are protected because all of the affected pools are within the Colville River Unit. The injection of the commingled fluids is based on sound engineering and geoscience principles. Sharing of production facilities and infrastructure helps to lessen environmental impacts and increase ultimate recovery through the sharing of expenses. There will be no increased risk of fluids moving into freshwater because all injection operations will be conducted in accordance with the appropriate AIOs and regulations. Now therefore it is ordered that Rule 4 of AIO 28 is amended to read as follows: Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. enriched gas obtained from the Alpine Central Facility c. produced water treated with scale inhibitors to reduce the possibility of scale deposition in the formation from the Alpine Central Facility. 1 Rule l of AIO 18D specifies that produced water and miscible injectant from the ACF, as well as lean gas with no source restrictions, can be injected for EOR purposes. 3 Rule 4 of AIO 28 authorized the injection of MI from the ACF and AIO 28.002 changed the MI requirement to enriched gas, authorized the injection of treated commingled produced water from the CRF, and authorized the injection of other sources of water with conditions. Rule 4 of AIO 30 authorized the injection of MI from the ACF and AIO 30.002 authorized the injection of commingled produced water from the CRF. ' Lean gas injection is not authorized for the Nanuq and Fiord Oil Pools. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 3 of 4 d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. CPAI shall monitor injection rated and pressures when injecting fluids from c. and d. above. If the monitoring indicates the possibility of loss of injectivity or formation damage, CPAI shall cease injection of such fluids immediately and notify the AOGCC. CPAI shall not recommence injection of these fluids until authorized by the AOGCC. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Nanuq reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC. That Rule 4 of AIO 30 is amended to read as follows: Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. Enriched gas obtained from the Alpine Central Facility. c. Produced water from the Alpine Central Facility. d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Fiord reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC. A10 28.007, 30.010, and 35.003 August 13, 2018 Page 4 of 4 And that Rule 3 of AIO 35 is amended to read as follows: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk sea water treatment plant; and b. produced water from the Alpine Central Facility. Any other fluids shall be approved by separate administrative action. DONE at Anchorage, Alaska and dated August 13, 2018. 1 Hollis S. French Cathy . Foerster Daniel T. Se ount, Jr. Chair, Commissioner Commissioner Commissioner 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. 1'lII." STMT "ALASKA (JOVERNOR 131L1. W'AI.6FR Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS AREA INJECTION ORDER NO. 28.007 AREA INJECTION ORDER NO. 30.010 AREA INJECTION ORDER NO. 35.003 Mr. Stephen Thatcher Manager, WMS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Re: Docket Number: AIO18-014 Request for administrative approval to amend approved fluids for enhanced oil recovery injection for the Colville River Field. Colville River Field Colville River Unit Nanuq Oil Pool Fiord Oil Pool Qannik Oil Pool Dear Mr. Thatcher: By letter dated February 28, 2018, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to amend the list of fluids authorized for injection for enhanced oil recovery (EOR) purposes in the Colville River Field (CRF) to allow the injection of produced water from the Lookout Oil Pool (LOP) in the Greater Moose's Tooth Unit (GMTU).t In accordance with Rule 11 of Area Injection Orders (AIO) No. 28, 30, and 35, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request to amend the list of fluids approved for EOR purposes in the CRF. The application only applies to AIOs for the Nanug, Fiord, and Qannik Oil Pools because the language currently in the AID for the Alpine Oil Pool will allow the injection of the produced water from the LOP for enhanced recovery purposes. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 2 of 4 CPAI plans to commence production from the LOP in late 2018 and will ship produced fluids from the LOP to the CRF where they will be commingled with production from the Alpine Oil Pool, Nanuq Oil Pool, Fiord Oil Pool, and Qannik Oil Pool before being processed at the Alpine Central Facility (ACF). Since production is commingled prior to processing, the produced water and gas streams to be used for EOR injection at both the CRF and the LOP will contain fluids from both fields. Only the AID for the Alpine Oil Pool in the CRF allows injection of gas and water from the LOP for EOR purposes'. The AIO's for the Nanuq' and Fiord' Oil Pools allow the injection of miscible injectant from the ACF and produced water from the CRF'. The Qannik Oil Pool AID does not allow gas injection but does allow the injection of produced water from the CRF. The LOP is an Alpine formation development, as is the Alpine Oil Pool, so no fluid compatibility issues are anticipated to arise from injecting the produced water from the LOP into the CRF oil pools, provided any required treatment is continued. The administrative action rules for the affected orders allow the AOGCC to amend an order administratively if the proposed action will not result in waste, will not jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in increased risk of fluid movement into freshwater. Waste is prevented by being able to use the produced water from the LOP for EOR purposes in the LOP and CRF. Correlative rights are protected because all of the affected pools are within the Colville River Unit. The injection of the commingled fluids is based on sound engineering and geoscience principles. Sharing of production facilities and infrastructure helps to lessen environmental impacts and increase ultimate recovery through the sharing of expenses. There will be no increased risk of fluids moving into freshwater because all injection operations will be conducted in accordance with the appropriate AIOs and regulations. Now therefore it is ordered that Rule 4 of AID 28 is amended to read as follows: Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. enriched gas obtained from the Alpine Central Facility c. produced water treated with scale inhibitors to reduce the possibility of scale deposition in the formation from the Alpine Central Facility. 3 Rule 1 of AIO 18D specifies that produced water and miscible injectant from the ACF, as well as lean gas with no source restrictions, can be injected for EOR purposes. J Rule 4 of AID 28 authorized the injection of MI from the ACF and AIO 28.002 changed the MI requirement to enriched gas, authorized the injection of treated commingled produced water from the CRF, and authorized the injection of other sources of water with conditions. 4 Rule 4 of AID 30 authorized the injection of MI from the ACF and AIO 30.002 authorized the injection of commingled produced water from the CRF. 5 Lean gas injection is not authorized for the Nanuq and Fiord Oil Pools. AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 3 of 4 d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. CPAI shall monitor injection rated and pressures when injecting fluids from c. and d. above. If the monitoring indicates the possibility of loss of injectivity or formation damage, CPAI shall cease injection of such fluids immediately and notify the AOGCC. CPAI shall not recommence injection of these fluids until authorized by the AOGCC. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Nanuq reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC That Rule 4 of AIO 30 is amended to read as follows: Rule 4 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from a sea water treatment plant; b. Enriched gas obtained from the Alpine Central Facility. c. Produced water from the Alpine Central Facility. d. sump fluid, hydrotest fluid (excluding fluids derived from tests of transportation pipelines), rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp effluent and mixtures involving such fluids. In addition, the following fluids may be authorized by future administrative approval for injection upon demonstration of compatibility with the Fiord reservoir: a. tracer survey liquid to monitor reservoir performance; In the event any mixture of fluids is injected, the following additional requirements apply: The operator shall continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its non -hazardous characteristics and its continued suitability for EOR injection. Analysis results must be retained according to the provisions of 20 AAC 25.310. Volumes of injected mixed fluids must be reported in the monthly (Form 10-406) and annual (Form 10-413) injection reports. The injection of lean gas will require separate authorization from the AOGCC AIO 28.007, 30.010, and 35.003 August 13, 2018 Page 4 of 4 And that Rule 3 of AIO 35 is amended to read as follows: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk sea water treatment plant; and b. produced water from the Alpine Central Facility. Any other fluids shall be approved by separate administrative action. DONE at Anchorage, Alaska and dated August 13, 2018. //signature on file// //signature on file// //signature on file// Hollis S. French Cathy P. Foerster Daniel T. Seamount, Jr Chair, Commissioner Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such farther 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 most 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 m decision denying reconsideration, UNLESS the denial is by inaction, in which case rhe 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 coon. 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 inthe period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 I1 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 18E.001 AREA INJECTION ORDER NO. 28.009 AREA INJECTION ORDER NO. 35.004 AREA INJECTION ORDER NO. 40.003 AREA INJECTION ORDER NO. 43.001 January 27, 2022 Mr. Stephen Thatcher, Manager North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-21-010 Request to Reinstate Area Injection Order No. 18.001with Modifications Colville River Unit, Alpine Oil Pool Dear Mr. Thatcher: By letter dated May 26, 2021, ConocoPhillips Alaska, Inc. (CPAI) requested reinstatement of Area Injection Order (AIO) No. 18A.001, which allowed for the mixing of treated effluent with Class II enhanced oil recovery (EOR) fluids for injection into the Alpine Oil Pool (AOP) when the Class I disposal well was unavailable. AIO 18A.001 was rescinded when AIO 18E was issued on March 4, 2021. The Alaska Oil and Gas Conservation Commission (AOGCC) does not reinstate rescinded orders. However, the substance of CPAI’s request is for administrative approval to authorize an additional fluid to be for injection, and AOGCC will treat it as such. Since AIO 18A.001 was issued, four additional pools have been tied into the EOR injection system that serves the AOP. These pools and the AIOs that govern their injection operations are: Pool Governing AIO Nanuq Oil Pool (NOP) AIO 28 Qannik Oil Pool (QOP) AIO 35 Lookout Oil Pool (LOP) AIO 40 Rendezvous Oil Pool (ROP) AIO 43 The NOP and QOP are in the Colville River Unit (CRU), and the LOP and ROP are in the Greater Moose’s Tooth Unit (GMTU). AIO 18E.001, AIO 28.009, AIO 35.004, AIO 40.003, & AIO 43.001 January 27, 2022 Page 2 of 2 There are currently two usable Class I disposal wells (a third Class I well was suspended in 2013) in the CRU, and there are none in the GMTU. Well CRU WD-02 (PTD 198-258) is used for disposal of treated effluent, and CRU CD1-01A (PTD 212-099) is the primary drilling waste disposal well. Having the ability to mix small amounts of treated effluent into the EOR injection stream when using a Class I well is not possible due to required mechanical integrity testing, well damage, well workover operations, or any other incident that may make a well temporarily unusable provides operational flexibility for the remote CRU and GMTU developments. Under the authorization of AIO 18A.001, CPAI has periodically mixed treated effluent with the EOR injection water with no indication of fluid incompatibilities or formation damage that reduces injectivity. In accordance with 20 AAC 25.556(d), the AOGCC hereby amends AIO numbers 18E, 28, 35, 40, and 43 to include the following in the list of authorized fluids in Rule 1 of AIO 18E, Rule 4 of AIO 28, and Rule 3 of AIO 35, 40, and 43: - Treated effluent, subject to the following conditions: o Treated effluent injection may occur when the Class I disposal well for effluent disposal is unavailable; o Treated effluent will be mixed with other EOR injection fluids (seawater or produced water); and o Injection of treated effluent may not exceed 1% by volume of the total annualized average water injection at the Colville River Unit and Greater Moose’s Tooth Unit. DONE at Anchorage, Alaska and dated January 27, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner, 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. Dan Seamount Digitally signed by Dan Seamount Date: 2022.01.27 08:48:32 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.01.27 09:05:42 -09'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.01.27 13:57:28 -09'00' From:Salazar, Grace (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order Nos. 18E.001, 28.009, 35.004, 40.003 and 43.001 (ConocoPhillips, Alpine Pool) Date:Thursday, January 27, 2022 2:53:56 PM Attachments:AIO 18E.001_ AIO 28.009_ AIO 35.004_ AIO 40.003_AIO 43.001.pdf The Alaska Oil and Gas Conservation Commission has issued the attached administrative approval amending a number of Area Injection Orders for ConocoPhillips Alaska, Inc.’s Colville River Unit, Alpine Oil Pool. Grace ____________________________________ Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/grace.salazar%40alaska.gov AOGCC 333 W 7th Avenue, Anchorage, AK 99501 TO: BERNIE KARL K&K RECLYCLING, INC. PO BOX 58055 FAIRBANKS, AK 99711 Mailed 1/28/22gs Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 605A.002 AREA INJECTION ORDER NO. 35.005 Mr. Ian Ramshaw Manager, WNS Development North Slope Development ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Numbers: CO-23-010 and AIO-23-020 Administrative Amendment to Conservation Order 605A and Area Injection Order 35 Adjustment of Affected Area Colville River Unit, Qannik Oil Pool Dear Mr. Ramshaw: On its own motion the Alaska Oil and Gas Conservation Commission (AOGCC) is amending the affected area of Conservation Order No. 605A (CO 605A) and Area Injection Order No. 35 (AIO 35), the pool rules and area injection order for the Qannik Oil Pool (QOP), in order to make them consistent with the current boundary of the Colville River Unit (CRU). On February 6, 2020, ConocoPhillips Alaska, Inc. (CPAI) applied to expand the vertical limits of the QOP and to contract a portion of the affected area to remove acreage that CPAI no longer operated due to the contraction of the CRU and subsequent releasing of the acreage. At the time the AOGCC declined to contract the affected area since a pool should ordinarily be defined by its geologic limits and not arbitrarily established property lines. Since that order was issued development of Nanushuk Formation projects has occurred in the CRU (where the Nanushuk Formation is known as the QOP and the Narwhal Reservoir), the Pikka Unit (where Oil Search (Alaska), LLC (OSA) recently applied for pool rules for the Nanushuk Oil Pool), and the Kuparuk River Unit (where the Nanushuk Formation is known as the Coyote Reservoir).All evidence points to these developments occurring in one broad geologic formation. While the Nanushuk Formation across the CRU and Pikka Unit (PU) is a single pool from a geologic point of view, from an operational standpoint having a single set of rules that applies across two units is impractical as each operator may have somewhat different ideas about the best way to develop the Nanushuk Formation on their acreage. Additionally, regulations restrict AIOs to a single operator, so they must be constrained only to land that an operator has legal rights to. CO 605A.002 AIO 35.005 July 20, 2023 Page 2 of 3 Therefore, while the AOGCC recognizes the Nanushuk Formation across the CRU and PU and likely on acreage outside of those units is geologically a single pool, rules and injection orders for projects in that pool will have the affected area limited to the unit boundaries upon which the operator has the rights to operate. As such the affected area of CO 605A and AIO 35 will be contracted to conform to the CRU boundary as of the date of this order. Having one pool being developed by multiple operators across multiple units, as is being done with the Nanushuk Formation across the CRU and PU has the potential to result in the waste of resources along the unit boundaries if the operators do not coordinate their operations and because of the property line offset requirements in place to protect correlative rights. As such, the AOGCC strongly encourages CPAI and OSA to coordinate their development activities across the Nanushuk Formation and investigate ways to prevent waste of resources along property lines. In accordance with 20 AAC 25.556(d), the AOGCC hereby amends CO 605A and AIO 35 as follows: Affected Area: Umiat Meridian Township, Range Sections T10N, R04E 1 – 4 T10N, R05E 5 – N1/2NW1/4, SW1/4NW1/4, & NW1/4SW1/4 6 - All T11N, R04E 1 – 4; 9 – 16; 21 – 28; 33 – 36 T11N, R05E 4 – 9; 16 – 21; 28 – 33 T12N, R04E 1 – 4; 9 – 16; 21 – 28; 33 – 36 T12N, R05E 4 – 9; 16 – 21; 28 – 33 DONE at Anchorage, Alaska and dated July 20, 2023. Brett W. Huber, Sr. Jessie L. Chmielowski Gregory C. Wilson Chair, Commissioner Commissioner Commissioner Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.07.20 14:06:44 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.07.20 14:51:30 -08'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.07.20 19:06:50 -05'00' CO 605A.002 AIO 35.005 July 20, 2023 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] CO 605A.002 and AIO 35.005 (CRU) Date:Thursday, July 20, 2023 4:19:57 PM Attachments:CO 605A.002 and AIO 35.005.pdf Administrative Amendment to Conservation Order 605A and Area Injection Order 35 Adjustment of Affected Area Colville River Unit, Qannik Oil Pool Samantha Carlisle 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 INDEXES By Grace Salazar at 1:21 pm, May 26, 2021 wt ConocoPhillips February 28, 2018 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 Stephen Thatcher Manager, WNS Development North Slope Operations and Development ConocoPhillips Alaska, Inc. ATO -1770 700 G Street Anchorage, AK 99501 phone 907.263.4464 En MAR q 1 RE: Request for Administrative Amendments, Colville River Unit, North Slope, AK Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPAP') as operator of the Colville River Unit ("CRU") and Greater Mooses Tooth Unit ("GMTU"), requests that the Alaska Oil and Gas Conservation Commission administratively amend area injection orders for the Fiord, Nanuq, and Qannik oil pools to allow injection of GMTU Lookout Oil Pool ("LOP") produced water into any of the other CRU oil pools. CPAI also requests that the conservation orders for the Fiord and Qannik oil pools be amended to allow commingling of LOP production in surface facilities prior to custody transfer. This request is being made concurrently with applications for a LOP Conservation Order and Area Injection Order. Those applications provide further background for this request. The CO application explains that LOP production is expected to be compatible with production from the CRU oil pools. The Fiord, Nanuq and Qannik pools area injection orders have specific rules for "fluids authorized for injection." LOP produced water is not specifically listed as a fluid authorized for injection. The recent Commission order authorizing the expansion of the Alpine Pool Area Injection Order provides that "[p]roduced water from the Alpine Central Facility" is a fluid authorized for injection. See Area Injection Order No. 18D, Rule 1 b. CPAI requests that the Alpine pool language be used to amend the Fiord, Nanuq and Qannik area injection orders to allow for injection of any produced water from the Alpine Central Facility including LOP produced water injection. This amendment will provide for consistency in CRU oil pool area injection orders. CPAI also requests that the Fiord, Alpine and Qannik pool rules be amended to allow for the commingling of LOP production in CRU surface facilities prior to custody transfer. The Nanuq oil pool rules allow production to be"commingled with production from other pools in surface facilities prior to custody transfer." See Conservation Order 562, Rule 7a. CPAI requests that similar language be adopted for the Fiord, Alpine and Qannik pools to allow for the commingling of production from these oil pools with other production at the Alpine Central Facility. Request for Administrative Amendments February 28, 2018 Page 2 of 2 Please contact John Cookson (265-6547) if you have questions or require additional information. Regards, (/"_ Stephen Thatcher Manager, WNS Development North Slope Operations and Development Cc: Land Manager - Alaska, Anadarko E&P Onshore LLC Bruce W. Hunt, Petro -Hunt LLC #9 THE STAVE Alaska Oil and Gas Conservation Commission GOVERNOR SEAN PARNELL Mr. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 August 16, 2013 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7009 2250 0004 3911 5884 Re: Amendment of Alternative MIT schedule for UIC injection Wells Dear Mr. Dethlefs: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 By a letter received on May 9, 2013 ConocoPhillips Alaska, Inc (CPAI) requested approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. The Alaska Oil and Gas Conservation Commission (AOGCC) hereby APPROVES the requested amendment establishing the MIT due date for Kuparuk River Unit 1 J-pad injection wells as May, and Colville River Unit pads CD3 as February and CD4 as June. AOGCC also APPROVES CPAI's request to allow for a test month for MITs in lieu of an anniversary date. No further action is deemed necessary regarding MITs in Area Injection Orders 213, 16, 18C, 21A, 28, 30 and 35. Should you have any questions, please contact Chris Wallace at 907-793-1250. P Cathy P. Poers er Chair, Commissioner DERATION 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. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event he period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. PostalService CERTIFIED MAIL, RECEIPT Momestic Mail . ,. ,. Ln �r a IF Postage M Certified tree E Return Receipt Fee Postmark Here t� (Endorsement Required) G Restricted Delivery Fee t3 (Endorsement Required) U-1 rU Total Postage f r1J 11— Sent To Mr. Jerry Dethlefs O ' Well integrity Director orP0Box No. ConocoPhillips Alaska, Inc. City Staffs, ZIP+< Post Office Box 100360 Anchors e AK 99510-0360 • Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. ■ {print your name and address on the reverse so that we can return the card to you. • Attach this card to the back of the mailpiece, or on the front if space permits. Article Addressed to: Mr. Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchoraee. AK 99510-0360 A. Sig ure X ❑ Agent b� 0 Addressee R rued by (Printed'N -a ) C. Date of Delivery D. Is deliv ry address different from item 1? ❑ Yes If YES, enter delivery address below: ❑ No 3. ice Type Certified Mail ❑ Express Mail ❑ Registered ❑ Return Receipt for Merchandise ❑ Insured Mail ❑ C.O.D. 4. Restricted Delivery? (Extra fee) ❑ Yes 2. Article Number 7009 2250 0004 3911 5884 (Transfer from service fabeQ PS Form 3811, February 2004 Domestic Return Receipt 102595.02-M-1540 Alaska Oil and Gas of A ,--,LASi GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 i/i Qiii. 7vi 907 .i 79433 Fax:907.276.7542 August 16, 2013 AOGCC lndustiy Guidance Bulletin No. 10-02A Mechanical .Integrity Testing The Alaska Oil and Gas Conservation Commission (AOGCQ provides the follownnt<r clarification of injection well mechanical integrity pressure test (MIT) requirements set forth in 20 AAC 25.252 and 25.402. Injection orders supplement AOGCC regulations by providing additional operating and testing obligations. MIT Preparation - The AOGCC must be notified at least 24 hours in advance (48 hours for wells remote from the nearest AOGCC office) for an opportunity to witness the MIT; - Pumping into and bleeding pressures from annuli should be avoided for 24 hours prior to the MIT; if necessary, information should be available to document such activity; - The well's annulus must be fluid packed before the AOGCC Inspector arrives; - Calibrated pressure gauges with suitable range and accuracy must be installed on the tubing, inner (tubing by casing) annulus, and outer (casing by casing) annuli, current calibration should be evident with proper labels or other documentation; - Suitable flow measurement equipment should be available to determine the volume of fluids pumped into and returned from the tested space; - Other equipment (e.g., tanks, lines, bleed trailers, etc.) necessary for the safe pressure testing and suitable for the operating environment should be rigged up prior to AOGCC Inspector arrival at the location. The following information must be available at the location for AOGCC Inspector review: - Valid approved waivers, if any, relating to the integrity of the tested well; - Current well schematic; - Graph of tubing, inner annulus, and outer annulus pressures for the preceding 90 days. Equipment Pressure Rating Equipment subject to test pressure must have a rated working pressure that meets or exceeds the planned test pressure. API defines the rated working pressure of equipment to be the maximum internal pressure that the equipment is designed to contain or control. Guidance Bulletin M-02A Mechanical Integrit)' Testis Pagc 2 of Test Cycle After the initial MIT, Class 11 disposal wells injecting solid slurries (used muds, cuttings; produced sa.tld, etc.) require an MIT once every 2 years; otherwise, MITs must be conducted ortce every 4 years. Injection wells used for enhanced recovery operations must be tested once every 4 years. The AOGCC may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the test month, unless a specific anniversary date for the MIT has been established by AOGCC approval (e.g., Area Injection Order administrative approval). For example, a test due August 14, 2014 would — under the new "test month" approach - be allowed to be tested not later than August 30, 2014. Operators are encouraged to take advantage of operating efficiencies in scheduling groups of MITs; and to initiate scheduling early in the month to increase inspector availability and allow time for retests or unplanned events. The AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. The AOGCC may require a witnessed test to be rescheduled to accommodate workload priorities. A pre -injection MIT performed prior to demobilizing a drilling rig from a well should be documented oil the AOGCC's MIT Form 10-426 and emailed to the AOGCC addressees noted oil the test report form. Test Pressure Unless otherwise required by the AOGCC, an MIT of the inner annulus is required to a mimnrurn pressure of 1500 psi or a pressure determined by multiplying 0.25 psi per foot times the true vertical depth of the packer — whichever is greater. A minimum pressure differential of 500 psi should be maintained between the tested annulus and tubing or adjacent annulus. The operator has the discretion to test to a higher pressure. A passing MIT will have no more than a 10 percent decline in pressure (based on the actual test pressure), a stabilizing pressure trend, and a final pressure that is at or above the required test pressure. For example, the operator may choose to start a required 1500 psi test at or above 1650 psi (additional 150 psi to allow for the 10 percent pressure decline over test duration). Reporting Unless otherwise required by the AOGCC, MIT results must be verified by an operator's designated ts representative and submitted electronically using Form 10-426 to the AOGCC no later than the fi calendar day of the month following the testing. Guidance Bulletin 10-02A �techanical Integrity Testing PaL,e 2 of Shut-in Wells The AOGCC's preference is to witness an MIT while a well is actively injecting and wellborc conditions (rate and temperature) are stable. If the well is in a short-term shut-in status when the MIT is due, the AOGCC should be notified and provided an alternate date for testing based on when injection will be recommenced. Injection wells that are shut in long-term (undetermined when injection will restart) need not be tested until they are ready to recommence injection. In lieu of an MIT for the long term shut-in well, the operator must provide to the AOGCC a quarterly graph of tubing, inner annulus and outer annulus pressures. Please share this Guidance Bulletin with all appropriate members of your organizations. Questions or discussion regarding this guidance bulletin should be directed to Chris Wallace at (907) 793-12% Sincerely; Cathy P. oerster Chair, Commissioner • ConocoPhillips May 8, 207.2 Mr. Chris Wallace Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVA. Subject: Amendment of alternative MIT schedule for UIC injection wells Dear Mr. Wallace: Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 ConocoPhillips Alaska, Inc. (CPAI) requests approval to amend the permanent Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. The amendment is to include new pads installed since the original approval and to clarify the affected Area Injection Orders (AIO). On February 13, 2006, CPAI requested approval to adopt an alternate MIT schedule for their North Slope Class II injection wells so as to allow the majority of the wells to be tested during the summer months (schedule attached). On March 23, 2006, administrative approval was granted for the alternate schedule by the AOGCC (attached). The approval letter states "The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." The alternative test schedule also complies with the AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. The section titled "Test Cycle" reads: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval)." ....."Operators are encouraged to take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window"...... A key component of the 4-year testing program is that each pad is assigned a specific month to be tested every four years (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. All injection wells on a pad will be tested during the visit. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. • • CPAI is requesting an amendment to incorporate new drillsites and clarify the affected AIOs. Drillsites 1J, CD3 and CD4 have been added to the list. The administrative approval regards Rule 6 in AIOs 26, 16, 18C, 28, 30 and 35, and Rule 4 in 21A. The MIT schedule applies only to CPAI wells on the standard 4-year test frequency, with the exception of 2P (Meltwater) which is on a 2-year cycle due to recent changes in AIO 21A. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, Jerry Dethlefs Well Integrity Director cc: Jim Regg Cathy Forester Attachments • 0 ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Revised May 7, 2013 Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk Alpine May 2A, 2B, 2G, 2H June 1 F, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R, 2P* Year 2 May 3K June 1 B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1 C, 1 J June 1 E CD2 July 1D August 2L, 2N, 2P*, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1A, 1G, 31 August 3G, 2Z Note: Year 1=2012 Revised 05-07-13 Contact: CPAI Problem Well Supervisor, 907-659-7224 • • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7ch Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule 0 Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, Jerry Dethlefs Problem Well Supervisor Attachment 0 0 ConocoPhillips Alaska, Inc. Proposed UIC MIT Permanent Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1C June 56 1 B, 3H, 30, 1 E July 54 1D, 1Q, 1Y,3F' August 48 1A', 1 R', 2G', 2K', 2L, 2N, 2P, 21J, 2W', 2Z', 3G', 3S CD2 29 Total 180 Year 2: 2007 May 21 1 R, 2W June 53 2K, 2T, 2X, 3B, 3F July 28 1 A, 1 G, 31 August 25 1 F', 2D, 21', 2H', 2M', 3G, 3M', 2Z Total 127 Year 3: 2008 - - May - 23 2A, 2B, 2G, 2H _ June 38 1 F, 1 L, 2M, 2V July 30 2E, 2F, 3J, 3M CD1' 2 August 24 3N, 3Q, 3R Total 115 Year 4: 2009 May 14 3K June 39 1 B, 2T, 3H, 30 July 19 1Q, 1Y August 35 1 H, 2C, 2D, 3A, 3C CD1 22 Total 107 ar et 4- ear Cycle: The following schedule repeats evea 4 years Year 6 May 22 1 C June 31 1 E July 34 1 D August 32 2L, 2N, 2P, 2Z, 3S CD2 29 Total 119 Year 6 May 21 1 R, 2W June 38 2K, 2X, 3B, 3F July 18 1 A, 1 G, 31 August 18 3G, 2Z Total 95 Year 7 May 23 2A, 2B, 2G, 2H June 38 1 F, 1 L, 2M, 2V July 30 2E, 2F, 3J, 3M August 24 3N, 3Q, 3R Total 115 Year 8 May 14 3K June 40 2T, 1 B, 3H, 30 July 27 1Q, 1Y August 35 1 H, 2C, 2D, 3A, 3C CD1 24 Total 116 Notes: 1)' Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service • 2 ffA E 0 11 JAA SEA FRANK H. MURKOWSKI, GOVERNOR Alr,A HA OIL AND GAS 333 W. 71 AVENUE, SURE 100 CONSERVATION COPOIISSIO � ANCHORAGE, ALASKA 99501-3539 j PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhilhps Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: North Slope MIT Schedule Dear Mr. Dethlefs: On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanicalintegrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsideration,k4 been requested. Alaska and dated March 2S, 2006 1 o an Dan T. Seamount, Jr. iairm Commissioner Cathy Y. Foerster Commissioner • • ConocoPhillips April 8, 201� Mr. Dan Seamount Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Jerry Dethlefs Well Integrity Director ConocoPhillips Alaska, Inc 700 G Street Anchorage, AK Phone 907-265-1464 �� 5 � �3 ( t?" Do c, 1 )3 . ► co Subject: Administrative Approval for alternative MIT schedule for UIC injection wells (revised) Dear Mr. Seamount: ConocoPhillips Alaska, Inc. (CPAI) requests approval for a modified Mechanical Integrity Test (MIT) schedule for Class II injection wells in fields operated by CPAI on the North Slope of Alaska. A provision in AOGCC Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing, under "Test Cycle" states: "Injection wells used for enhanced recovery operations must be tested once every 4 years. The Commission may, in its discretion, approve an alternate MIT schedule. A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval)." CPAI is requesting administrative approval from Rule 6, Area Injection Orders 2B, 16, 18B, 27, 28, 30 and 35, and Rule 4, AIO 21, in order to "take advantage of operating efficiencies in scheduling groups of MITs within the 2- or 4-year window" (reference Bulletin 10-002). On February 13, 2006, CPAI requested approval to modify the MIT schedule for their North Slope Class II injection wells so as to allow the majority of the wells to be tested during the summer months (attached). On March 23, 2006, approval was granted for the modified schedule by the AOGCC (attached). The approval letter states "The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification." CPAI complied with the MIT schedule as approved until the AOGCC issued Industry Guidance Bulletin No. 10-002 Mechanical Integrity Testing. According to the AOGCC, as of the date of the Guidance Bulletin the administrative approval for the MIT test schedule was revoked. Although the Guidance Bulletin may meet the needs of other operators in the state, it also results in placing CPAI back to the point of the initial schedule modification request. Therefore, CPAI is again requesting approval to modify the MIT schedule by Area Injection Order administrative approval. The justification for the schedule change request has not altered since the original request in 2006. CPAI requests relief from the requirement in Bulletin 10-002: "A 2- or 4-year MIT means the test must be performed not later than the 2- or 4-year anniversary of the most recent test date, unless a specific anniversary date for the MIT has been established by a Commission approval (e.g., Area Injection Order administrative approval). " CPAI proposes a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing the same schedule as that approved in 2006; that each pad be assigned a specific month to be tested every four years (see attached schedule). The number of pads and wells are divided over the four year period so that roughly one-fourth of the required MITs are performed each year. The specified month is the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. This method was adopted and put into practice with the March 23, 2006 approval and has proven to work well. Please note that CD3, due to lack of summer road access, is scheduled for February by prior AOGCC approval. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather to minimize risks regarding personnel safety and releases to the environment. The AOGCC is being requested to approve the "due month" concept of this plan rather than the "exact, due date" specified in Bulletin 10-002. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call Brent Rogers or Kelly Lyons at 659-7224, or me at 265-1464 if you have any questions. Sincerely, /1Z Jerry Dethlefs Well Integrity Director cc: Cathy Forester Jim Regg Attachments • s ConocoPhillips Alaska, Inc. UIC MIT Permanent Test Schedule Target 4-year Cycle: The following schedule repeats every 4 years Year 1 Kuparuk p� Alpine May 2A, 2B, 2G, 2H June IF, 1 L, 2M, 2V July 2E, 2F, 3J, 3M August 3N, 3Q, 3R Year 2 May 3K June 1B & WSW, 2T, 3H, 30 CD1 July 1Q, 1Y August 1 H, 2C, 2D, 3A, 3C Year 3 February CD3 May 1C, 1J June 1 E CD2 July 1 D August 2L, 2N, 2P, 2U, 3S Year 4 May 1 R, 2W June 2K, 2X, 3B, 3F CD4 July 1 A, 1 G, 31 August 3G, 2Z Note: Year 1=2012 Revised 04-05-12 Contact: CPAI Problem Well Supervisor, 907-659-7224 • • ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 February 13, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 Subject: Proposal for permanent MIT schedule on UIC injection wells Dear Mr. Maunder: On December 19, 2005, ConocoPhillips Alaska, Inc. (CPAI) requested approval to delay UIC 4-year Mechanical Integrity Tests (MIT) due in 2006 for a limited time beyond their due date so the tests could be performed during the summer months. The request was approved by the AOGCC on December 29, 2005, with the stipulation no further extensions would likely be granted for future years. CPAI is proposing an alternative test plan that should meet the objectives of both CPAI and AOGCC. The AOGCC position is that UIC MIT tests be performed no later than the exact due date of the previous 4-year test on each well, as specified in 20 AAC 25.412 and in Area Injection Orders 2B and 18B. The justification for this date enforcement is lack of precedent within the regulations for an Operator to alter the due date without specific approval from the AOGCC. Previously these tests had routinely been delayed to the summer months due to safety and spill potential issues and efficiency/cost savings associated with performing these tests during warm weather. CPAI is proposing a schedule for UIC MIT testing patterned after the AOGCC required program used for testing the Safety Valve System (SVS). In that program each pad is assigned to two specific months of the year for testing. To prevent schedule creep over time, there is some flexibility to perform the tests anytime during the assigned month. The pads are scheduled to roughly balance the workload from one month to the next. For 4-year UIC MIT testing, CPAI is proposing that each pad be assigned a specific month to be tested every four years. The number of pads and wells will be divided over the four year period so that roughly one-fourth of the required MITs will be performed each year. The specified month will be the due date, rather than the specific day of the prior test, to eliminate schedule creep over time. To implement this schedule • • Mr. Tom Maunder Page 2 of 2 02/13/06 CPAI will accelerate testing on a number of wells over the next few years. The proposed schedule and pad/month assignments are attached. There are a number of benefits to this proposal: • Each well will be tested close to the previous 4-year test if a small allowance is approved to prevent schedule creep. This should meet the "every 4-year" test frequency requirement in the UIC regulations. • All the injection wells on a given pad will be addressed during the same testing operation, regardless of when the last test was performed on a particular well. This will keep all the wells on the same schedule, results in efficiencies in time and reduces fluid handling risk. • Eliminates requests to "reset" the 4-year clock when tests are performed during the year, eliminating significant record keeping efforts. • The proposed months are in the May through August time period that meets the CPAI goal of testing during warmer weather. The AOGCC is specifically being requested in this proposal to approve the "due month" concept of this plan rather than the "exact due date" specified in the letter dated December 29, 2005. In addition, the proposal applies only to CPAI wells on the standard 4-year test frequency. Wells with specific approvals or variances on 2-year test cycles will continue to be tested on or before the exact 2-year anniversary date. Approval of this request at your earliest convenience is appreciated. Please call MJ Loveland, Marie McConnell, or me at 659-7224 if you have any questions. Sincerely, Jerry Dethlefs Problem Well Supervisor Attachment • • 0 AIASKA FRANK H. MURKOWSKI, GOVERNOR AT-ANA 011L AND GAS � 333 W. TH AVENUE, SURE 100 CONSERVATION COMMISSION � ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Jerry Dethlefs Problem Well Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: North Slope MIT Schedule Dear Mr. Dethlefs: On February 13, 2006 ConocoPhillips Alaska, Inc ("CPAI") requested approval to modify the schedule for demonstrating mechanical. integrity on their North Slope injection wells so as to allow the majority of the wells to be tested on a rotating schedule during the summer months. The requested schedule modification will allow for greater operating efficiency and will reduce risks to personnel and the environment. The Commission hereby APPROVES the requested modification. In order to allow opportunity for AOGCC Inspectors to witness the testing, CPAI is requested to provide the planned schedule for Summer 2006 as soon as practical. If you have any questions, please contact Jim Regg at 793-1236. As provided in AS 31.05.080(a), within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless reconsiderations been requested. 1 / •�•:741 11. . 11• A Dan T. Seamount, Jr. Commissioner �MII�4-�� Cathy Y. Foerster Commissioner ConocoPhillips Alaska, Inc. Permanent UIC MIT Test Schedule Initial 4-year Cycle: Requires accelerating tests for all wells on a pad to be on same cycle Year 1: 2006 Total Wells Kuparuk Pads Alpine Pads Total Wells May 22 1C June 56 1B & WSW, 1E, 3H, 30 July 54 1 D, 1 Q, 1 Y, 3F* August 48 1A*, 1 R*, 2K*, 2L, 2N, 2P, 2U, 2W*, 2Z*, 3G*, 3S CD2 29 Total 180 Year 2: 2007 May 21 1 R, 2W June 53 2K, 2T, 2X, 3B, 3F July 28 1 A, 1 G, 31 August 25 1 F*, 2D*, 21`*, 2G*, 2H*, 2M*, 3G, 3M*, 2Z Total 127 Year 3: 2008 May 23 2A, 2B, 2G, 2H June 38 1F, 1L, 2M, 2V CD1* 2 July 30 2E, 2F, 3J, 3M August 24 3N, 3Q, 3R Total 115 Year 4: 2009 May 14 1J*, 3K June 39 1B & WSW, 2T, 3H, 30 CD1 22 July 19 10, 1Y CD4* 15 August 35 1 H, 2C, 2D, 3A, 3C Total 144 I I i Target 4-year Cycle: The following schedule repeats every 4 years Year 5 _- Feb ----- ----- - -- CD3 .- ____ -_ ---- - ---- - --- May i - ------ 37 ---- --- --- - 1C, 1J -- - - - - ---- - ---- - June - - 31 --- -- --- - --- 1 E CD2 29 July i 34 lb August 32 ... - 2L, 2N, 2P, 2U, 2Z, 3S Total 119 Year 6 - May - - I 21 1R 2W --- - - - - - - --- --- - ---- ----- ---- - - -- --- --- . - - - -- June--- ---- ---- 38 --- --- -- - 2K, 2X, 3B, 3F CD4 -----JuI �8 11G31Y August 3G 2Z Total 95 ..... Year 7 May 23 2A 2B, 2G, 2H June a----- 38--..._ 1 F, 1 L, 2M, 2V ---- _--- ------- ----- --- --..- --. July_. -- 1._ 30 .° ---_ --- ----- -- -_--v------ 2E 2F 3J, 3M _ August ... _ . j 24 3N 3Q,3R Total j 115 Year 8 t May ; 14 3K - ---- --- -- -- - - - __ -- -- June - _ 40�--- - - --- -1 B &WSW, 2T, 3H 30- CD1 __.. 24 July i.. 27. .._ 1Q, 1Y August I 35 1 H 2C 2D, 3A 3C _._._...---._._ ..._._ . ..__.__.. .......... Total i 116 Notes: 1) * Denotes pads to be accelerated prior to due -date for combining all wells on a pad to same test date 2) New pads will be added to the schedule as they are brought in service; load leveling may be required Revised 08-16-06 i V Roby, David S (D ®A) From: Walker, Jack A [ Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Attachments: Colville RiverWaterAnalyses.As Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack I 1 Colville River Field and CPF -2 Produced Water Comparison 100000 10000 Q 1000 J 100 ■ ■ E ■ ■ c 10 ■ ■ E Q a 1 a ■ m ■ 0.1 CD E OCRU Produced Water (Range) o ■ c 0.01 D ■ CPF -2 PW Average - Last 10 Samples U 0.001 ■ ■ K%, �`a O�� O� 58, r�J y�J \�G `�a�� Ga�o Gr\ 5 SJ P�� 6 �� '�� '� C'� Colville River Field Seawater and CPF -2 Produced Water Comparison 100000 10000 ■ 1000 J 100 ■ CD ■ E ■ c 10 ■ o ■ Q 1 ■ ■ ■ 0.1 0 Seawater (Range) ■ 0.01 ■ CPF -2 PW Average - Last 10 Samples 0.001 ■ a'` �� v .J� `�a o o °� 0 SAMPLE NUM Date Time Location ravity @ 60 pH 6298863 10/3/2010 22:33 Separator 1.0179 7.48 6298864 10/3/2010 22:27 Separator 1.0201 8.37 AB71202 714/2010 4:00 Drum 1.0204 7.81 AB71201 7/4/2010 4:00 Separator 1.0206 7.76 AB71200 7/4/2010 4:00 Separator 1.0188 8.59 AB68013 4/4/2010 2:50 Separator 1.0201 8.43 AB68012 4/4/2010 2:30 Separator 1.0208 7.63 AB64673 1/5/2010 3:00 Separator 1.0201 8.59 AB64672 1/5/2010 2:50 Separator 1.0198 7.58 AB61378 10/12/2009 15:00 Drum 1.0207 7.6 Seawater - AB42201 7/4/2008 Summer 1.0026 7.01 Seawater - AB36364 2/8/2008 Winter 1.0338 6.75 Specific Gravity @ 60 pH PW Minimum 1.0179 7.48 PW Maximum 1.0208 8.59 Difference 0.0029 1.11 SW Minimum 1.0026 6.75 SW Maximum 1.0338 7.01 Difference 0.0312 0.26 SAMPLE NUM Date Time MPLE POI ravi 60 pH CPF -2 Prod. Water Tank AB65778 2/6/2010 14:09 Outlet 1.0168 7.98 CPF -2 Prim. Sep. Water AB62075 11/4/2009 0:00 Outlet 1.0191 7.87 CPF -2 Prim. Sep. Water AB61846 10/29/2009 12:40 Outlet 1.0198 7.9 CPF -2 Prim. Sep. Water AB61525 10/21/2009 13:02 Outlet 1.0192 7.74 CPF -2 Prim. Sep. Water AB60990 10/5/2009 12:45 Outlet 1.0191 7.79 CPF -2 Prim. Sep. Water AB59666 9/5/2009 0:00 Outlet 1.0188 8.05 CPF -2 Prod. Water Tank AB59106 8/22/2009 13:40 Outlet 1.02 7.9 CPF -2 Prod. Water Tank AB50294 2/6/2009 0:00 Outlet 1.0188 7.98 CPF -2 Prod. Water Tank AB43457 8/10/2008 0:00 Outlet 1.0194 7.9 CPF -2 Prim. Sep. Water AB42709 7/17/2008 0:00 Outlet 1.0188 7.73 Min 1.0168 7.73 Max 1.02 8.05 Average 1.01898 7.884 Previous 10 Samples Bicarbonate 1230 1140 1225 1223 1136 Carbonate 0 95 0 0 109 Chloride 15050 14620 15260 14960 14400 Sulfate 250 250 172 172 180 Sulfide Aluminum <0.1 <0.1 < 0.1 < 0.1 < 0.1 Boron 28.6 3.4 28 28 28 Barium 4.3 <1.0 8 3 13 Calcium 148.9 21.5 138 138 147 Chromium <0.2 <0.2 < 0.2 < 0.2 < 0.2 Iron 1.3 1.1 0.9 1.3 2.6 Potassium 67.6 7.9 55 58 56 Lithium 3.2 <0.5 2 2 2 Magnesium 62.1 7.7 57 57 58 Manganese 0.027 0.009 0.033 0.029 0.037 Sodium 11700 14600 10470 10330 10400 Phosphorus 0.9 0.1 0.6 1.1 0.3 Silicon 23.3 2.3 22 21 21 Strontium 15.3 1.9 16.4 15.9 16.2 Zinc 0.1 <0.1 < 0.1 < 01 < 0.1 Specific Gravity 60 degrees F 1.0179 1.0201 1.0204 1.0206 1.0188 H 7.48 8.37 7.81 7.76 8.59 on uctsvity micro -m os cm 40100, 401]2 Notes: 1. Min / Max values taken from 10 most recent PW samples and typical summer / winter SW samples 2. Averages derived from 10 most recent CPF -2 PW samples. 0 • tivit micro- Bicarbonate I Carbonate I Chloride I Sulfate I Sulfide Aluminum Boron 1230 0 15050 250 <0.1 28.6 1140 95 14620 250 <0.1 3.4 40100 1225 0 15260 172 < 0.1 28 40100 1223 0 14960 172 < 0.1 28 40100 1136 109 14400 180 < 0.1 28 34900 1108 97 14790 205 0.1 28.3 35700 1253 0 15180 228 < 0.1 30.4 28200 1178 185 15500 280 < 0.1 27.1 29800 1280 0 15600 290 < 0.1 28.4 30500 1403 0 15310 219 < 0.1 27 5960 100 0.001 1814 279 0.001 0 1 51900 140 0 24960 3580 0.001 0.1 4.9 Itivity micro- Bicarbonate Carbonate Chloride Sulfate Sulfide I Aluminum Boron 28200 1108 0 14400 172 0 0.1 3.4 40100 1403 185 15600 290 0 0.1 30.4 11900 295 185 1200 118 0 0 27 5960 100 0 1814 279 0.001 0 1 51900 140 0.001 24960 3580 0.001 0.1 4.9 45940 40 0.001 23146 3301 0.0001 0.1 3.9 Ftivity micro- carbonate m arbonate m Chloride mg/l mg/l Sulfate m /l Sulfide m /I luminum mgi Boron m /l 35200 1515 0 12050 42 9.4 < 0.1 16.2 30000 1541 0 13920 34 5.9 < 0.1 16.8 29800 1571 0 14550 65 16 <0.1 15 29400 1585 0 14400 69 8.7 < 0.1 16 29700 1589 0 13750 42 8.5 < 0.1 19.6 29900 1538 0 13920 36 11.6 < 0.1 17 i 29300 1581 0 14700 59 7.2 < 0.1 15.5 32300 1880 0 13110 53 < 0.1 16.6 34400 1991 0 14590 49 12 < 0.1 16.1 33800 1929 0 13980 47 6.7 < 0.1 14.7 29300 1515 0 12050 34 5.9 0 14.7 35200 1991 0 14700 69 16 0 19.6 31380 1672 0.001 13897 49.6 9.55555556 0.001 16.35 Colville - Minimurn (mglL) 1108 1253 1178 1280 1403 100 140 100.0 97 0 185 0 0 0.0 0.0 0.0 14790 15180 15500 15600 15310 1814 24960 1814.0 205 228 280 290 219 279 3580 172.0 0.0 0.0 0.0 0.1 < 0.1 < 0.1 < 0.1 < 0.1 0.0 0.1 0.0 28.3 30.4 27.1 28.4 27 1 4.9 1.0 11 2 5 4 67 0.0 1.0 0.0 185 192 121 132 133 54 515 21.5 < 0.2 < 0.2 < 0.2 < 0.2 < 0.2 0.0 0.2 0.0 2.4 2.5 0.6 1.8 0.9 0 0.5 0.0 104 143 54 65 68 44 609 7.9 2 2 2 2 2 0.0 0.5 0.0 82 83 52 57 58 124 1530 7.7 0.051 0.051 0.032 0.036 0.03 0.014 0.001 0.0 11280 11670 9560 9696 10400 509 13960 509.0 0.6 0.6 0.3 0.3 0.2 0 0.1 0.0 21 23 20 21 19 0 1 0.0 16.8 18 15.6 15.4 13 1 10.2 1.0 < 0.1 < 0.1 < 0.1 < 0.1 < 0.1 0 1 0.0 1.0201 1.0208 1.0201 1.0198 1.0207 1.0026 1.0338 1.0 8.43 7.63 8.59 7.58 7.6 7.011 6.75 6.8 34 57 59601 51900 5960.0 Barium I Calcium I Chromium Iron Potassium I Lithium I Ma nesium Man anese 4.3 148.9 <0.2 1.3 67.6 3.2 62.1 0.027 <1.0 21.5 <0.2 1.1 7.9 <0.5 7.7 0.009 8 138 < 0.2 0.9 55 2 57 0.033 3 138 < 0.2 1.3 58 2 57 0.029 13 147 < 0.2 2.6 56 2 58 0.037 11 185 < 0.2 2.4 104 2 82 0.051 2 192 < 0.2 2.5 143 2 83 0.051 5 121 < 0.2 0.6 54 2 52 0.032 4 132 < 0.2 1.8 65 2 57 0.036 67 133 < 0.2 0.9 68 2 58 0.03 0 54 0 0 44 0 124 0.014 1 515 0.2 0.5 609 0.5 1530 0.001 Barium Calcium I Chromium Iron Potassium Lithium Magnesium Man anese 2 21.5 0 0.6 7.9 2 7.7 0.009 67 192 0 2.6 143 3.2 83 0.051 65 170.5 0 2 135.1 1.2 75.3 0.042 0 54 0 0 44 0 124 0.001 1 515 0.2 0.5 609 0.5 1530 0.014 1 461 0.2 0.5 565 0.5 1406 0.013 Barium m /I Calcium m / hromium md Iron m /I totassium md Lithium m / a nesium m an anese m 29 135 < 0.2 < 0.5 87 2 98 0.018 43 105 < 0.2 < 0.5 66 2 101 0.015 36 93 0.2 0.3 56 1 95 0.03 28 97 < 0.2 1.3 62 2 104 0.025 34 112 < 0.2 < 0.5 96 2 107 0.011 • • 43 91 <0.2 <0.5 61 2 100 <0.01 42 99.9 < 0.2 < 0.5 62.5 < 0.5 101 < 0.001 34 109 < 0.2 < 0.5 63 1 78 0.011 22 111 < 0.2 5.5 91 2 103 0.048 28 105 < 0.2 < 0.5 81 2 102 0.013 22 91 0.2 0.3 56 1 78 0.011 43 135 0.2 5.5 96 2 107 0.048 33.9 105.79 0.2 2.4 72.55 1.8 98.9 0.021375 River Field PW & SW Maximum DiNrenEe (m9JL) (m9 /L) 1403.0 1303.0 1515.0 1541.0 1571.0 1585.0 1589.0 1538.0 185.0 185.0 0.0 0.0 0.0 0.0 0.0 0.0 24960.0 23146.0 12050.0 13920.0 14550.0 14400.0 13750.0 13920.0 3580.0 3408.0 42.0 34.0 65.0 69.0 42.0 36.0 0.0 0.0 9.4 5.9 16.0 8.7 8.5 11.6 0.1 0.1 < 0.1 < 0.1 <0.1 < 0.1 < 0.1 < 0.1 30.4 29.4 16.2 16.8 15.0 16.0 19.6 17.0 67.0 67.0 29.0 43.0 36.0 28.0 34.0 43.0 515.0 493.5 135.0 105.0 93.0 97.0 112.0 91.0 0.2 0.2 < 0.2 < 0.2 0.2 < 0.2 < 0.2 < 0.2 2.6 2.6 < 0.5 < 0.5 0.3 1.3 < 0.5 < 0.5 609.0 601.1 87.0 66.0 56.0 62.0 96.0 61.0 3.2 3.2 2.0 2.0 1.0 2.0 2.0 2.0 1530.0 1522.3 98.0 101.0 95.0 104.0 107.0 100.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 < 0.01 14600.0 14091.0 13700.0 9059.0 9780.0 9195.0 6625.0 9899.0 1.1 1.1 0.5 0.6 0.6 1.6 1.3 1.0 0 18.0 16.0 17.0 21.0 18.0 23.3 23.3 17. 18.0 17.0 10.1 12.1 9.0 9.7 13.0 9.7 1.0 1.0 <0.1 <0.1 <0.1 <0.1 <0.1 0.4 1.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 8.6 1.8 8.0 7.9 7.9 7.7 7.8 8.1 1 54 0. 29700.0 • 1 0 Sodium I Phosphorus Silicon I Strontium Zinc nded Solids 0_45 u mg /I 11700 0.9 23.3 15.3 0.1 92 14600 0.1 2.3 1.9 <0.1 32 10470 0.6 22 16.4 < 0.1 10330 1.1 21 15.9 < 0.1 10400 0.3 21 16.2 < 0.1 11280 0.6 21 16.8 < 0.1 109 11670 0.6 23 18 < 0.1 153 9560 0.3 20 15.6 < 0.1 80 9696 0.3 21 15.4 < 0.1 10400 0.2 19 13 < 0.1 509 0 0 1 0 13960 0.1 1 10.2 1 Sodium Phosphorus Silicon Strontium I Zinc nded Solids 0 45 u m 9 /l 9560 0.1 2.3 1.9 0.1 32 14600 1.1 23.3 18 0.1 153 5040 1 21 16.1 0 121 509 0 0 1 0 0 13960 0.1 1 10.2 1 0 13451 0.1 1 9.2 1 0 Sodium m /I os horus mi Silicon m /I Otrontium mgj Zinc m /t Tota Dissolved Solids 13700 0.5 17 10.1 < 0.1 9059 0.6 18 12.1 < 0.1 30096 9780 0.6 16 9 <0.1 9195 1.6 17 9.7 < 0.1 6625 1.3 21 13 < 0.1 9899 1 18 9.7 0.4 33700 9890 1.7 17 < 1 < 0.1 8044 1 18 9 < 0.1 9264 1.1 18 11.1 < 0.1 9599 0.4 18 11.9 < 0.1 6625 0.4 16 9 0.4 30096 13700 1.7 21 13 0.4 33700 9505.5 0.98 17.8 10.6222222 0.4 CPF -2 P1N Average (mg /L) 1581.0 1880.0 1991.0 1929.0 1515.0 1991.0 1672.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 14700.0 13110.0 14590.0 13980.0 12050.0 14700.0 13897.0 59.0 53.0 49.0 47.0 34.0 69.0 49.6 7.2 12.0 6.7 5.9 16.0 9.6 < 0.1 < 0.1 < 0.1 < 0.1 0.0 0.0 0.0 15.5 16.6 16.1 14.7 14.7 19.6 16.4 42.0 34.0 22.0 28.0 22.0 43.0 33.9 99.9 109.0 111.0 105.0 91.0 135.0 105.8 < 0.2 < 0.2 < 0.2 < 0.2 0.2 0.2 0.2 < 0.5 < 0.5 5.5 < 0.5 0.3 5.5 2.4 62.5 63.0 91.0 81.0 56.0 96.0 72.6 < 0.5 1.0 2.0 2.0 1.0 2.0 1.8 101.0 78.0 103.0 102.0 78.0 107.0 98.9 70.001 0.0 0.0 0.0 0.0 0.0 0.0 9890.0 8044.0 9264.0 9599.0 6625.0 13700.0 9505.5 1.7 1.0 1.1 0.4 0.4 1.7 1.0 17.0 18.0 18.0 18.0 16.0 21.0 17.8 < 1 9.0 11.1 11.9 9.0 13.0 10.6 < 0.1 < 0.1 < 0.1 < 0.1 0.4 0.4 0.4 1.0 1.0 1.0 1.0 1.0 1.0 1.0 7.9 8.0 7.9 7.7 7.7 8.1 7.9 93 34400.01 33800.01 29300.0 35200.0 31380.0 • • SAMPLE NUM 6298863 6298864 AB71202 AB71201 AB71200 Da 10/3/2010 10/3/2010 7/4/2010 7/4/2010 7/4/2010 Time 22:33 22:27 4:00 4:00 4:00 Inlet Separator Flash Inlet Separator Previous 10 Samples Separator Water Drum Separator Water Bicarbonate 1230 1140 1225 1223 1136 Carbonate 0 951 0 0 109 Chloride 15050 14620 15260 14960 14400 Sulfate 250 250 172 172 180 Sulfide Aluminum <0.1 <0.1 < 0.1 < 0.1 < 0.1 Boron 28.6 3.4 28 28 28 Barium 4.3 <1.0 8 3 13 Calcium 148.9 21.5 138 138 147 Chromium <0.2 <0.2 < 0.2 < 0.2 < 0.2 Iron 1.3 1.1 0.9 1.3 2.6 Potassium 67.6 7.9 55 58 56 Lithium 3.2 <0.5 2 2 2 Magnesium 62.1 7.71 57 57 58 Manganese 0.027 0.009 0.033 0.029 0.037 Sodium 11700 14600 10470 10330 10400 Phosphorus 0.9 0.1 0.6 1.1 0.3 Silicon 23.3 2.3 22 21 21 Strontium 15.3 1.9 16.4 15.9 16.2 Zinc 0.1 <0.1 < 0.1 < 0.1 < 0.1 Specific Gravity (60 °F) 1.0179 1.0201 1.0204 1.0206 1.0188 H 7.48 8.37 7.81 7.76 8.59 Conductivity micro - mhos /cm 40100 40100 40100 • . AB68013 AB68012 AB64673 AB64672 AB61378 4/4/2010 4/4/2010 1/5/2010 1/5/2010 2:50 2:30 3:00 2:50 15:00 Colville River Field PW CPF -2 PW Separator Inlet Separator Inlet Hash Minimum Maximum Difference Average Water Separator Water Separator Drum (mg /L) (mg/L) (mg /L) (mg/L) 1108 1253 1178 1280 1403 1108 1403 295 1672 97 0 185 0 01 0.0 185.0 185.0 0.001 14790 15180 15500 15600 15310 14400 15600 1200 13897 205 228 280 290 219 172 290 118 49.6 9.56 0.1,< 0.1 <0.1 <0.1 <0.1 0.0 0.1 0.1 0.001 28.3 30.4 27.1 28.4 27 3.4 30.4 27.0 16.35 11 2 5 4 67 2.0 67.0 65.0 33.9 185 192 121 132 133 21.5 192 170.5 105.79 70.2 < 0.2 < 0.2 < 0.2 < 0.2 0 0 0.0 0.2 2.4 2.5 0.6 1.8 0.9 0.6 2.6 2.01 2.4 104 143 54 65 68 7.9 143 135.1 72.55 2 2 2 2 2 2.0 3.2 1.2 1.8 82 83 52 57 58 7.7 83 75.3 98.9 0.051 0.051 0.032 0.036 0.03 0.009 0.051 0.042 0.02 11280 11670 9560 9696 10400 9560 14600 5040 9505.5 0.6 0.6 0.3 0.3 0.2 0.1 1.1 1.0 0.98 21 23 20 21 19 2.3 23.3 21 17.8 16.8 18 15.6 15.4 13 1.9 18 16.1 10.62 70.1 < 0.1 < 0.1 < 0.1 < 0.1 0.1 0.1 0.0 0.4 1.0201 1.0208 1.0201 1.0198 1.0207 1.0179 1.0208 0.0029 1.01898 8.43 7.63 8.59 7.58 7.6 7.48 8.59 1.11 7.884 349001 357001 282001 298001 30500 28200 0 11 11900 31380 Roby, David S (DOA) From: Davies, Stephen F (DOA) Sent: Friday, November 05, 2010 11:00 AM To: Roby, David S (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison I'm not an very familiar with scale formation, but the sulfate content differs (PW = 172 -290 vs seawater = 279 - 3580), carbonate content differs (PW avg. = 0 -185 vs seawater = — 0- 0.001), and bicarbonate differs (PW = 1108 -1403 vs seawater = 100 -140), as does the pH (pw = 7.5 — 8.6 vs seawater = 6.75 -7.0). However, the amount of water proposed to be injected is insignificant compared with the volume of fluid injected into the Alpine Pool alone on a regular basis (3,163,281 bbls in Sept 2010), so I think that any formation damage would be minimal. From: Roby, David S (DOA) Sent: Friday, November 05, 2010 10:32 AM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: FW: Colville River Field & Kuparuk River Field Water Comparison Guys, attached as a comparison of CRU and CPF -2 produced waters as well as seawater. After a quick glance they look pretty similar to me. What do you guys think? Dave Roby (907)793 -1232 From: Walker, Jack A [mailto: Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack 1 Roby, David S (DOA) From: Roby, David S (DOA) Sent: Friday, November 05, 2010 11:04 AM To: Davies, Stephen F (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison They are aware of the possibility for scale creation when seawater and produced water mix and were planning on adding scale inhibitors. Dave Roby (907)793 -1232 From: Davies, Stephen F (DOA) Sent: Friday, November 05, 2010 11:00 AM To: Roby, David S (DOA); Maunder, Thomas E (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: RE: Colville River Field & Kuparuk River Field Water Comparison I'm not an very familiar with scale formation, but the sulfate content differs (PW =172 -290 vs seawater = 279 - 3580), carbonate content differs (PW avg. = 0 -185 vs seawater = — 0- 0.001), and bicarbonate differs (PW = 1108 -1403 vs seawater = 100 -140), as does the pH (pw = 7.5 — 8.6 vs seawater = 6.75 -7.0). However, the amount of water proposed to be injected is insignificant compared with the volume of fluid injected into the Alpine Pool alone on a regular basis (3,163,281 bbis in Sept 2010), so I think that any formation damage would be minimal. From: Roby, David S (DOA) Sent: Friday, November 05, 2010 10:32 AM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Regg, James B (DOA) Subject: FW: Colville River Field & Kuparuk River Field Water Comparison Guys, attached as a comparison of CRU and CPF -2 produced waters as well as seawater. After a quick glance they look pretty similar to me. What do you guys think? Dave Roby (907)793 - 1232 From: Walker, Jack A (mailto: Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 10:20 AM To: Roby, David S (DOA) Subject: Colville River Field & Kuparuk River Field Water Comparison Dave, Enclosed is the comparison we discussed on the phone. The two charts show the range of dissolved solids for Colville produced water and seawater plotted with the average value for Kuparuk CPF -2 produced water which is basis for our belief that the CPF -2 water is compatible with the Colville River Field formations. I'll follow up with more background regarding the request for authorization to inject Kuparuk River Field produced water into the Colville River Field Oil Pools. Jack Roby, David S (DOA) From: Walker, Jack A [ Jack .A.Walker @conocophillips.com] Sent: Friday, November 05, 2010 12:28 PM To: Roby, David S (DOA) Subject: CRU Seawater P/L Follow Up Dave, To follow up the compositional analyses data for seawater, Colville River Field produced water, and Kuparuk produced water that I sent to you earlier for your consideration, this email describes our situation and reasons for requesting authorization to inject produced water from the Kuparuk River Field in the Alpine, Fiord, Nanuq and Qannik Oil Pools. Seawater from the Kuparuk River Unit Seawater Treatment Plant is normally supplied to the Colville River Field for enhanced oil recovery via a pipeline approximately 34.6 miles long. There was an unplanned shutdown of the seawater pipeline, and freeze protection was subsequently implemented by pumping warm Kuparuk River Field produced water into the pipeline to displace the cold seawater. This freeze protection will be good for a period, and within this period we expect resumption of normal seawater operations. When normal seawater operations are possible, the seawater will displace the Kuparuk produced water used for freeze protection toward the Alpine Central Facility. Two operational options exist for routing the freeze protection fluid at the Alpine Central Facility: (1) inject it into properly permitted Class I disposal wells, or (2) if AOGCC authorizes, inject it into WAG service wells in the Alpine, Fiord, Nanuq, and Qannik Oil Pools. Option (1) is feasible, but this operation will require significantly more time than Option (2) due to the disposal well system capacity. Option (1) has a minor risk of freezing the seawater pipeline due to the time required for the seawater to displace the freeze protect fluid. Option (2) is recommended because the Kuparuk produced water (freeze protect fluid) is compatible with the Colville River Field formations, because the freeze protect fluid can be beneficially used for enhance oil recovery, and because this displacement operation will require about one tenth of the time required for Option (1) resulting in less risk of freezing the seawater pipeline during the displacement of the freeze protect fluid. We expect normal seawater to be available as early as 6 p.m. tonight. Thank you for the time you have put into this. Jack Walker North Slope Development ConocoPhillips Alaska, Inc. 907 - 265 -6268 office 907 - 250 -1749 cell i ~ 7 ConocoPhillips Alaska, I~ • Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-276-1215 February 27, 2009 Jim Regg Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Conoco hilli s ~~ ~-~~ ~~ ~' > :, ?.,. ~~~~~~ Subject: Qannik Oil Pool, Area Injection Order No. 35 (AIO 035.000) Request for Administrative Action Rule 3 Authorized Fluids for Enhanced Recovery Dear Mr. Regg: ConocoPhillips Alaska, Inc. (CPAI) is requesting from the Alaska Oil and Gas Conservation Commission (AOGCC) an administrative action to the Qannik Oil Pool, Area Injection Order No.35 (AIO 035.000). CPAI would like to modify AIO 035.000 Rule 3 "Authorized Fluids for Enhanced Recovery" to a include: "Small amounts of fluids collected from sumps, hydrotests, rinsate from washing mud hauling trucks, excess well-work fluids, and treated camp waste water." This administrative action would make AIO 035.000 consistent with the other AIO's for the Colville River Unit. It was CPAI's initial intent to include these fluids as part of AIO 035.000, however. it was inadvertently left out of our initial application. As a result of this over sight a small amount (27 bbls) of treated waste water was unintentionally injected into the Qannik Oil Pool on December 8-12th without proper authorization. This was verbally reported to AOGCC and documented in the attached a-mail correspondence (Attachment I). An action item from this incident was to seek an administrative action to authorize these fluids for injection under AIO 035.000. Treated wastewater injection is authorized in all other AIOs pertaining to the Colville River Unit. There is no reason to believe that including treated wastewater under the area injection order would have any detrimental effect on oil recovery from the Qannik field. If you have any questions or require further information, please contact Scott Reed, 265- 6548, or Tim Schneider at 265-6859. Sincerely, Scott Reed Production Engineer C~ bcc: Sharon Allsup Drake ATO 1530 Chris Wilson ATO 1770 Lamont Frazer ATO 1754 Randall Kanady ATO 1534 Jack Walker ATO 1740 Tim Schneider ATO 1768 • Attachment I .. . .,~ Re I' t Reply ko All .: Forward ~ -;~ ' ~' ,. JY', s ,~ ~~ ~, J Py _ - File Edit b'iew Inserk Format Tools ackions Help - _- _ e. _. .._ .. _ . _ ._ w~ You Forwarded khis message nr, 1 fa~2ULia 12;51 Phi, From; _ Schneider, Tim S. Sent; h~lon 12t15f200~ ~F;32 PM To; 'Jim Regg' Cc: Kanady, Randall B; DeGeorge, Lynn A; Wilson, Chris Subjer_t; AIU 08-24. Notirirakion dim, ConocoPhillips is self disclosing an injection of treated Waste Water into the Qannik reservoir. In the Colville River Unit area, all Area Injection Orders (AIQ); except the Qannik AIQ, allow injection of camp Waste Water as an "Authorized Fluids for Enhanced Recovery". This inadvertent misinjection in the Qannik Pool has been recognized and is being reported as per Rule 8 of AIQ a8-24 (Qannik Oil Pool in the Colville River Unit. Tom Maunder With AQGCC Was notified by Randy I~anady, Lynn DeGeorge, and Tim Schneider from CPAI and he recommended that we provide this notice to you. Treated Waste Water from the Alpine camp is typically injected down the Class I Disposal Well 1ND-a2. UVD-a2 Was shut-in last Week to perform a static pressure survey requested by EPA. Qn December 8th - 12th;, D-02 Was SI and treated Waste Water from the Alpine camp Was commingled With other injection Water and sent to CD2 and CD4 far injection. This resulted in 27 bbls of treated Waste water being injected into 3 Qannik injectors, CD2-4a4, CD2-466 &CD2-467 While camp Waste Water Was diverted from VdD-a2. The total Water injected into these 3 Wells during this time Was approximately 2a,aaa B. Our proposal to prevent this violation of the applicable AIO from re-occurring Will be to submit an amendment to the existing Qannik AIO t^ include camp Waste Water as an "Authorized Fluid for Enhanced Recovery" When VtiID-a2 is not available. Based an previous diversions of waste Water to the injection system, na short term ar long term infectivity has been realized affecting injection performance. I will be calling you in the near term to discuss this matter with you. Sincerely, c~U11L ~] , ~Clb~r~0ta~u Subsurface Development Staff Rraduetion Engineer NS-Alpine 'i? Rhone: 907-265-6859 '~ Fax: 907-265-1515 ~ Ntiobi le: 907-632-8186 OEmail: tim.s.schneiderCconacaphillips.cam ~~ ConocoPhillips Alaska, Inc. 700 G. ST. ANCHORAGE, ALASKA 99510-0360 Lamont Frazer North Slope Operations and Development, ATO 1754 Telephone 907- 263-4530 Facsimile 907- 265-1515 E-mail lamont.c.frazer@conocophillips.com May 28, 2008 Commissioner Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Qannik Area Injection Order 20 AAC 25.402 Additional Information Dear Commissioner Seamount: R~~~~~~ MAl' 2 8 200$ Alaska Oil & Gas Corns. Commission At~c#~vrage The purpose of this letter is to provide additional information to support the ConocoPhillips Alaska, Inc. application to the Alaska Oil and Gas Conservation Commission for approval of an area injection order to conduct an enhanced recovery operation involving water injection in the Qannik Oil Pool, consistent with 20 AAC 25.402 (a). Testimony for the application was provided on May 15, which included reference to the mechanical condition of all wells within one- quarter mile of the proposed Qannik injection wells. A list of these wells with their completion date and service was also provided in the written area injection application (page 22). Commissioner Foerster subsequently inquired about the mechanical condition of all wells that fall within the proposed area injection order boundary. A letter dated May 27 provided information to address. Commissioner Foerster's question. This letter provides additional information to help ensure Commissioner Foerster's inquiry is adequately addressed. A list of all wells that fall within the proposed area injection order boundary is attached. This is the same list that was provided in the May 27 letter with the following enhancements: (1) wells within one-quarter mile of the proposed Qannik injection wells are shown in bold red font and (2) additional details are provided in the comments section. There are no mechanical problems associated with these wells that would impact Qannik production or injection. Please contact me if you have any questions regarding the Qannik area injection order application. Sincerely, Lamont Frazer Qannik Coordinator All Penetrations Within The Proposed Qannik Area Injection Order Boundary Well Service Completion Date Comments ALPINE 1 EXPLOR 02/16/95 P&A ALPINE 1A EXPLOR 03/01/95 P&A ALPINE 1 B EXPLOR 03/23/96 P&A - 5/1/05 ALPINE 3 EXPLOR 03/11/96 P&A BERGSCHRUND 1 EXPLOR 04/14/94 P&A BERGSCHRUND 2 EXPLOR 02/27/96 P&A BERGSCHRUND 2A EXPLOR 04/17/96 P&A - 4/21/05 CD 1-01 INJ 06/29/99 CD 1-02 INJ 11 /26/00 CD 1-03 INJ 01 /05/00 CD1-04 PROD 11/08/00 CD 1-05 INJ 01 /23/00 CD 1-06 INJ 07/11 /00 CD1-07 INJ 02/15/04 CD1-08 PROD 05/14/04 CD1-09 PROD 06/17/00 CD1-10 PROD 12/09/00 CD1-11 INJ 11/07/04 CD1-12 PROD 11/23/04 CD1-13 INJ 07/14/99 CD1-14 INJ 05/11/01 CD1-16 INJ 10/23/99 CD1-17 PROD 10/22/00 CD1-18 PROD 12/07/04 CD1-19A DISP 04/22/00 CD1-20 INJ 12/26/04 CD 1-21 INJ 02/25/01 CD1-229 INJ 08/09/99 CD1-22A PROD 08/13/00 CD 1-23 INJ 08/09/99 CD1-24 PROD 08/05/00 CD1-25 PROD 03/07/00 CD1-26 INJ 10/05/99 CD1-27 PROD 03/03/00 CD1-28 PROD 12/23/00 CD1-30 PROD 10/01/00 CD1-31 INJ 09/14/00 CD1-32 PROD 07/30/00 CD1-33 INJ 01 /05/01 CD1-34 PROD 05/04/00 CD1-35 PROD 07/24/00 CD 1-36 INJ 12/07/99 CD1-37 INJ 08/26/99 CD1-38 PROD 02/15/00 CD1-39 INJ 09/17/99 CD1-40 PROD 07/17/00 CD1-41 PROD 04/01/00 CD1-42 INJ 12/21/99 CD1-43 PROD 08/30/00 CD1-44 PROD 05/21/00 CD 1-45 INJ 11 /09/99 CD 1-46 INJ 04/27/04 CD2-01 PROD 09/16/05 Page 1 of 3 • Well Service Completion Date Comments CD2-02 INJ 08/22/05 CD2-03 PROD 07/30/05 <1/4 mile from CD2-404 CD2-05 PROD 08/22104 <1/4 mile from CD2-467 CD2-06 INJ 10/21 /03 CD2-07 INJ 12/07/03 CD2-08 INJ 02/08/03 CD2-09 PROD 09112/04 <1/4 mile from CD2-404 CD2-10 PROD 12/27/03 CD2-11 INJ 10108/05 <1/4 mile from CD2-404 CD2-12 INJ 05119/03 <1/4 mile from CD2-404 CD2-13 PROD 11/03/02 CD2-14 PROD 10/03/01 CD2-15 INJ 10/30/01 <1/4 mile from CD2-467 8~ CD2-404 CD2-16 INJ 08/24/02 CD2-17A INJ 10/21 /05 CD2-18 INJ 09/23/03 CD2-19 PROD 06/21/02 CD2-20 PROD 07/13/03 CD2-21 PROD 02/08/05 CD2-22 INJ 05/28/02 CD2-23 PROD 07/24102 <1/4 mile from CD2-404 CD2-24 PROD 06128/01 <114 mile from CD2-467 8~ CD2-404 CD2-25 PROD 04/23/02 CD2-26 INJ 01 /20/02 CD2-27 INJ 11 /18/03 CD2-28 PROD 12/29/02 CD2-29 INJ 10/07/02 CD2-30 INJ 10/30/03 <1/4 mile from CD2-467 CD2-31 PROD 07/02/04 CD2-32 INJ 03/05/02 <1/4 mile from CD2-467 CD2-33B PROD 09/02/01 <1/4 mile from CD2-467 CD2-34 PROD 01/01/02 CD2-35 INJ 01 /18/03 CD2-36 INJ 03/12/03 CD2-37 PROD 11/28/02 CD2-38 INJ 09/08/02 CD2-39 PROD 09/20/01 CD2-40 INJ 08/25103 <1/4 mile from CD2-467 CD2-404 INJ 05/24/06 CD2-41 PROD 06/30/02 CD2-42 PROD 06/01/01 <1/4 mile from CD2-467 CD2-43 PROD 01/20/04 <1/4 mile from CD2-467 CD2-44 INJ 09/23/02 CD2-45 PROD 01/06/03 CD2-46 INJ 05/15/02 CD2-47 PROD 12/16/01 <1/4 mile from CD2-467 CD2-48 INJ 06/13/02 Tubing by Inner Annulus Communication CD2-49 INJ 02/04102 <1/4 mile from CD2-467 CD2-50 PROD 03/17/02 CD2-51 INJ 05/03/03 Tubing by Inner Annulus Communication CD2-52 PROD 06/27/03 CD2-53 PROD 07/18/04 CD2-54 INJ 10/22/04 CD2-55 INJ 10/01/03 <1/4 mile from CD2-467 CD2-56 INJ 10/03/04 Page 2 of 3 R Well Service Completion Date Comments CD2-57 INJ 06/04/04 CD2-58 PROD 06/09/03 CD2-59 INJ 06/07/05 CD2-60 INJ 07/10/05 <1/4 mile from CD2-467 CD2-72 PROD 06/03/07 Qannik cemented CD3-107 PROD 02/28/07 CD3-108 INJ 04/11 /05 CD3-109 PROD 03/04/06 CD3-110 INJ 02/01 /06 CD3-111 PROD 03/25/06 CD3-112 INJ 04/13/06 CD3-113 PROD 02/25/08 Qannik cemented CD3-114 INJ 04/08/07 Qannik cemented CD3-301 PROD 04/29/07 CD3-302 INJ 03/17/07 CD3-316A INJ 02/12/08 CD4-05 PROD 12/08/07 Qannik cemented CD4-07 PROD 10/14/07 Qannik cemented CD4-16 PROD 07/13/07 Qannik cemented CD4-17 INJ 10/04/06 Qannik cemented CD4-208 INJ 12/24/05 CD4-209 INJ 06/11 /06 CD4-210 PROD 06/30/06 CD4-211 PROD 12/05/06 Qannik cemented CD4-213 INJ 02/19/08 Cased, Qannik cemented, Suspended CD4-214 INJ 11/14/06 Qannik cemented CD4-215 PROD 12/25/06 Qannik cemented CD4-3016 PROD 01/07/08 Qannik cemented CD4-302 INJ 06/21/07 Qannik cemented CD4-304 PROD 11/13/07 Qannik cemented CD4-306 INJ 07/25/07 Qannik cemented CD4-318A PROD 09/10/06 CD4-319 INJ 11 /29/05 CD4-320 PROD 07/28/06 CD4-321 INJ 10/26/06 Qannik cemented CD4-322 INJ 08/22/07 Qannik cemented NANUK 1 EXPLOR 03/24/96 P&A NANUK 2 EXPLOR 05/07/00 P&A NANUQ 3 EXPLOR 03/17/01 P&A - 3/6/07 NANUQ 5 EXPLOR 04/05/02 Cased, Qannik cemented, Suspended NECHELIK 1 EXPLOR 03/17/82 P&A NEVE 1 EXPLOR 04/23/96 P8~A; <1/4 mile from CD2-467 TEMPTATION 1 EXPLOR 04/04/96 P&A TEMPTATION 1 A EXPLOR 04/23/96 P&A WD-02 DISP 04/04/99 Notes: 1) Unless stated otherwise in the comments section, the Qannik interval is not cemented. 2) CD2-21 was listed in the area injection order written submittal as being within 1/4 mile of the proposed Qannik injectors. However, the well is actually further away than 1/4 mile. The closest planned Qannik injector (CD2-404) is 1630' away from CD2-21. Page 3 of 3 Submittal Date • ~ Page 1 of 1 Colombie, Jody J (DOA) From: Foerster, Catherine P (DOA) Sent: Friday, May 23, 2008 12:54 PM To: Soria, Dora I Cc: Seamount, Dan T (DOA); Norman, John K (DOA); Colombie, Jody J (DOA) Subject: RE: Submittal Date Since Monday, May 26 is a holiday, CPAI may submit the requested data on Tuesday, May 27. From: Soria, Dora I [mailto:Dora.I.Soria@conocophillips.com] Sent: Friday, May 23, 2008 12:46 PM To: Foerster, Catherine P (DOA) Subject: Submittal Date Cathy, Per our conversation, CPAI plans to submit the data requested by the AOGCC at the recent pool rule and area injection order hearing (due within ten days) on Tuesday May, 27, 2008 since Monday is a holiday. Please indicate you approval of this submittal date by responding to this a-mail. Thank you, -dora Dora I. Soria Staff Landman ConocoPhillips Alaska, Inc. Exploration and Land P.O. Box 100360, Anchorage, AK 99510 email - dora.i.soria@conocophillips.com (907) 265-6297 (telephone), (907) 263-4966 (fax) 5/30/2008 ~5 ConocoPhillips Alaska, Inc. • • 700 G. ST. ANCHORAGE, ALASKA 99510-0360 Lamont Frazer North Stope Operations and Development, ATO 1754 Telephone 907- 263-4530 Facsimile 907- 265-1515 p~ E-mail lamont.afrazer@conowphillips.com /^-~ May 27, 2008 tijq~, ~~~,,~ Commissioner Dan Seamount, Chairman q/~~ C~f~ ~ 2 ~ 2D~8 Alaska Oil ah d Gas Conservation Commission q~ ho Gans, Comm 333 West 7 Avenue, Suite 100 9e ~~~~~ Anchorage, AK 99501 Re: Qannik Area Injection Order 20 AAC 25.402 Supplemental Information Dear Commissioner Seamount: ConocoPhillips Alaska, Inc., in its capacity as operator of the Colville River Unit, provided testimony on May 15 in support of its application to the Alaska Oil and Gas Conservation Commission for approval of an area injection order to conduct an enhanced recovery operation involving water injection in the Qannik Oil Pool, consistent with 20 AAC 25.402 (a). This testimony included reference to the mechanical condition of all wells within one-quarter mile of proposed Qannik injection wells. Commissioner Foerster subsequently inquired about the mechanical condition of all wells that fall within the proposed area injection order boundary. This letter address's the inquiry from Commissioner Foerster. A list of all wells that fall within the proposed area injection order boundary is attached. (A plat showing these penetrations was included as Slide 5 of the area injection order testimony.) All of the wells have either competent production casing or have been plugged and abandoned. There are no mechanical problems associated with these wells that would impact Qannik production or injection. However, two of the wells-CD2-48 and CD2-51-have tubing/production casing communication. A workover is planned for CD2-48 and further diagnostics are planned for CD2-51. Please contact me if you have any questions regarding the Qannik are injection order application. Sincerely, v~ ~~ Lamont Frazer Qannik Coordinator • • May 27, 2008 Commissioner Dan Seamount Re: Qannik Area Injection Order 20 AAC 25.402 Supplemental Information Bcc: Brian Noel ATO-1700 Dora Soria ATO-1468 Chris Wilson ATO-1770 • • All Penetrations Within The Proposed Qannik Area Injection Order Boundary Well Service Completion Date Comments ALPINE 1 EXPLOR 02/16/95 P&A ALPINE 1A EXPLOR 03/01/95 P&A ALPINE 1B EXPLOR 03/23/96 P&A - 5/1/05 ALPINE 3 EXPLOR 03/11/96 P&A BERGSCHRUND 1 EXPLOR 04/14/94 P&A BERGSCHRUND 2 EXPLOR 02/27/96 P&A BERGSCHRUND 2A EXPLOR 04/17/96 P&A - 4/21/05 CD 1-01 INJ 06/29/99 CD 1-02 INJ 11 /26/00 CD 1-03 INJ 01 /05/00 CD1-04 PROD 11/08/00 CD 1-05 INJ 01 /23/00 CD 1-06 INJ 07/11 /00 CD 1-07 INJ 02/15/04 CD1-08 PROD 05/14/04 CD1-09 PROD 06/17/00 CD1-10 PROD 12/09/00 CD 1-11 INJ 11 /07/04 CD1-12 PROD 11/23/04 CD 1-13 INJ 07/14/99 CD1-14 INJ 05/11/01 CD 1-16 INJ 10/23/99 CD1-17 PROD 10/22/00 CD1-18 PROD 12/07/04 CD1-19A DISP 04/22/00 CD 1-20 INJ 12/26/04 CD 1-21 INJ 02/25/01 CD1-229 INJ 08/09/99 CD1-22A PROD 08/13/00 CD 1-23 INJ 08/09/99 CD1-24 PROD 08/05/00 CD1-25 PROD 03/07/00 CD 1-26 INJ 10/05/99 CD1-27 PROD 03/03/00 CD1-28 PROD 12/23/00 CD1-30 PROD 10/01/00 CD 1-31 INJ 09/14/00 CD1-32 PROD 07/30/00 CD1-33 INJ 01 /05/01 CD1-34 PROD 05/04/00 CD1-35 PROP 07/24/00 CD1-36 INJ 12/07/99 CD 1-37 INJ 08/26/99 CD1-38 PROD 02/15/00 CD 1-39 INJ 09/17/99 CD1-40 PROD 07/17/00 CD1-41 PROD 04/01/00 CD 1-42 INJ 12/21 /99 CD1-43 PROD 08/30/00 CD1-44 PROD 05/21/00 CD 1-45 INJ 11 /09/99 CD1-46 INJ 04/27/04 CD2-01 PROD 09/16/05 Page 1 of 3 • • Well Service Completion Date Comments CD2-02 INJ 08/22/05 CD2-03 PROD 07/30/05 CD2-05 PROD 08/22/04 CD2-06 INJ 10/21 /03 CD2-07 INJ 12/07/03 CD2-08 INJ 02/08/03 CD2-09 PROD 09/12/04 CD2-10 PROD 12/27/03 CD2-11 INJ 10/08/05 CD2-12 INJ 05/19/03 CD2-13 PROD 11/03/02 CD2-14 PROD 10/03/01 CD2-15 INJ 10/30/01 CD2-16 INJ 08/24/02 CD2-17A INJ 10/21 /05 CD2-18 INJ 09/23/03 CD2-19 PROD 06/21/02 CD2-20 PROD 07/13/03 CD2-21 PROD 02/08/05 CD2-22 INJ 05/28/02 CD2-23 PROD 07/24/02 CD2-24 PROD 06/28/01 CD2-25 PROD 04/23/02 CD2-26 INJ 01 /20/02 CD2-27 INJ 11 /18/03 CD2-28 PROD 12/29/02 CD2-29 INJ 10/07/02 CD2-30 INJ 10/30/03 CD2-31 PROD 07/02/04 CD2-32 INJ 03/05/02 CD2-336 PROD 09/02/01 CD2-34 PROD 01/01/02 CD2-35 INJ 01/18/03 CD2-36 INJ 03/12/03 CD2-37 PROD 11/28/02 CD2-38 INJ 09/08/02 CD2-39 PROD 09/20/01 CD2-40 INJ 08/25/03 CD2-404 INJ 05/24/06 CD2-41 PROD 06/30/02 CD2-42 PROD 06/01/01 CD2-43 PROD 01/20/04 CD2-44 INJ 09/23/02 CD2-45 PROD 01/06/03 CD2-46 INJ 05/15/02 CD2-47 PROD 12/16/01 CD2-48 INJ 06/13/02 CD2-49 INJ 02/04/02 CD2-50 PROD 03/17/02 CD2-51 INJ 05/03/03 CD2-52 PROD 06/27/03 CD2-53 PROD 07/18/04 CD2-54 INJ 10/22/04 CD2-55 INJ 10/01 /03 CD2-56 INJ 10/03/04 Page 2 of 3 i . ,* t Well Service Completion Date Comments CD2-57 INJ 06/04/04 CD2-58 PROD 06/09/03 CD2-59 INJ 06/07/05 CD2-60 INJ 07/10/05 CD2-72 PROD 06/03/07 Qannik cemented CD3-107 PROD 02/28/07 CD3-108 INJ 04/11 /05 CD3-109 PROD 03/04/06 CD3-110 INJ 02/01 /06 CD3-111 PROD 03/25/06 CD3-112 INJ 04/13/06 CD3-113 PROD 02/25/08 Qannik cemented CD3-114 INJ 04/08/07 Qannik cemented CD3-301 PROD 04/29/07 CD3-302 INJ 03/17/07 CD3-316A INJ 02/12/08 CD4-05 PROD 12/08/07 Qannik cemented CD4-07 PROD 10/14/07 Qannik cemented CD4-16 PROD 07/13/07 Qannik cemented CD4-17 INJ 10/04/06 Qannik cemented CD4-208 INJ 12/24/05 CD4-209 INJ 06/11 /06 CD4-210 PROD 06/30/06 CD4-211 PROD 12/05/06 Qannik cemented CD4-213 INJ 02/19/08 Cased, Qannik cemented, Suspended CD4-214 INJ 11/14/06 Qannik cemented CD4-215 PROD 12/25/06 Qannik cemented CD4-301 B PROD 01/07/08 Qannik cemented CD4-302 INJ 06/21/07 Qannik cemented CD4-304 PROD 11/13/07 Qannik cemented CD4-306 INJ 07/25/07 Qannik cemented CD4-318A PROD 09/10/06 CD4-319 INJ 11 /29/05 CD4-320 PROD 07/28/06 CD4-321 INJ 10/26/06 Qannik cemented CD4-322 INJ 08/22/07 Qannik cemented NANUK 1 EXPLOR 03/24/96 P&A NANUK 2 EXPLOR 05/07/00 P&A NANUQ 3 EXPLOR 03/17/01 P&A - 3/6/07 NANUQ 5 EXPLOR 04/05/02 Cased, Qannik cemented, Suspended NECHELIK 1 EXPLOR 03/17/82 P&A NEVE 1 EXPLOR 04/23/96 P&A TEMPTATION 1 EXPLOR 04/04/96 P&A TEMPTATION 1 A EXPLOR 04/23/96 P&A WD-02 DISP 04/04/99 Page 3 of 3 ~ 4 Page 1 of 1 • ~ Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Tuesday, May 27, 2008 2:37 PM To: 'lamont.c.frazer@ConocoPhillips.com' Cc: Davies, Stephen F (DOA); Roby, David S (DOA) Subject: Additional Information - Qannik AIO Lamont, This message follows-up our conversation of a few minutes ago. We have received CPAI's May 27 letter responding to Commissioner Foerster's request in the hearing for information regarding well integrity for all wells that penetrate the Qannik. With regard to the data table submitted, the following requests are made; 1. Please identify the wells actually in the %< mile Area of Review and the Qannik well that is proximate. It is acceptable to "bold" such wells. 2. Please clarify that where there is no comment entered if this is to indicate that there is no cement across the Qannik. 3. The comments regarding the T x IA communication for CD2-48 and CD2-51 should be entered as comments in the table. Thanks in advance. The revised table should be submitted to the Commission Office by close of business today. Call or message with any questions. Tom Maunder, PE AOGCC 5/27/2008 ~3 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: Daniel T. Seamount, Chairman Cathy Foerster 3 John K. Norman 4 In the Matter of the Proposed ) 5 Establishment of Pool Rules and ) Area Injection Order for Qannik ) 6 Oil Pool by ConocoPhi llips ) 7 ALASKA OIL and GAS CONSERVATION COMMISSION 8 Anchorage, Alaska 9 May 15, 2008 9:02 o'clock a.m. 10 VOLUME I 11 PUBLIC HEARING 12 BEFORE: Danie l T. Seamount, Chairman Cathy Foerster, Commissioner 13 John K. Norman, Commissioner 14 15 16 17 18 19 20 21 22 23 24 25 R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 1 2 3, 4 5 6 7 8 9 10 11 12 13 14 15 16 17 I 18 19 20 21 22 I 23 24 25 • TABLE OF CONTENTS Opening remarks by Chairman Seamount 03 Testimony by Lamont Frazer 05 Testimony by Dora Soria 09 Testimony by Doug Knock 31 Testimony by Brian Noel 65 Testimony by Jack Walker R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 • • 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 P R O C E E D I N G S (On record - 9:02 a.m.) CHAIRMAN SEAMOUNT: On the record. I'd like to call this hearing to order. The date is May 15th, 2008, the clock on the wall says 9:02 a.m. We're located at 333 West Seventh Avenue, Suite 100, Anchorage, Alaska. Those are the offices of the Alaska OiI & Gas Conservation Commission. To my right is Commissioner John Norman, to my left is Commissioner Cathy Foerster and I'm Dan Seamount. If anyone has special needs please see Special Staff Assistant Jody Colombie who's sitting in the back. R & R Court Reporters will be recording these proceedings. You can get a copy of the transcript from R & R Court Reporters. And we'd like to remind anybody testifying that we have two microphones in front of you, you need to speak into both of them. One's for the hearing room and the other's for the recorder. The purpose of this meeting is to hear a request by ConocoPhillips Alaska, Incorporated to classify the Qannik Reservoir in the Colville River Field as an oil pool and to prescribe rules to govern development of the proposed oil pool in accordance with 20 AAC 25.520. Concurrent with the application the operator is requesting an area injection order to authorize water flood operations in the same proposed pool. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 3 1 This hearing is held in accordance with 20 AAC 540 of the 2 Alaska Administrative Code. 3 So I see that we've got three -- no, four people wanting 4 to testify today and it looks like they're all with the 5 operator, ConocoPhillips. And I don't see that any other 6 parties are going to testify at this time. We'll give 7 opportunity at the end just in case somebody changes -- if 8 somebody else changes their mind. 9 So I guess it's appropriate we start off with the 10 applicant. Let's see, from -- are you giving sworn testimony? 11 MR. FRAZER: Yes, I am. 12 CHAIRMAN SEAMOUNT: Okay. Raise your right hand, please. 13 (Oath administered) 14 MR. FRAZER: Yes, I do. 15 CHAIRMAN SEAMOUNT: And could you, please, state your 16 name? 17 MR. FRAZER: My name is Lamont Frazer. 18 CHAIRMAN SEAMOUNT: Okay. And who do you represent? 19 MR. FRAZER: I represent ConocoPhillips. 20 CHAIRMAN SEAMOUNT: And do you wish to be an expert 21 witness? 22 MR. FRAZER: Yes. 23 CHAIRMAN SEAMOUNT: Okay. Please state what the subject 24 is and what your experience is? 25 MR. FRAZER: The subject would be reservoir engineering. R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 • • 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 I have a bachelor's degree from the University of Michigan in chemical engineering, a master's degree from the University of Alaska at Anchorage in environmental quality engineering. I have six years of lower 48 experience and 20 years of Alaska experience working fields within the Prudhoe Bay Unit, the Kuparuk River Field and the Colville River Unit. CHAIRMAN SEAMOUNT: Commissioner Foerster, do you have any questions or objections? COMMISSIONER FOERSTER: No, I don't. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: No. CHAIRMAN SEAMOUNT: Do we have to make a motion to accept him as an expert witness? COMMISSIONER NORMAN: The Chair can just say. CHAIRMAN SEAMOUNT: Okay. You are accepted as an expert witness, Mr. Frazer, please proceed. MR. FRAZER: Thank you. TESTIMONY BY LAblONT FRAZER MR. FRAZER: What we're going to do today is talk about the -- I'll provide testimony for the Qannik Conservation Order. Just an outline of what we're going to talk about, I'll provide an introduction, ownership and development area will be covered by Dora Soria, Doug Knock will cover geoscience, then I'll provide testimony on reservoir and production issues, I'll also talk about the surface facilities and Brian Noel will talk R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5 • • 1 2 3 4~ 5I 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 about drilling completions. The intent of our testimony is to provide information that will form the basis for a conservation order with the goals of preventing waste, promoting conservation, protecting correlative rights, promoting maximum ultimate recovery and when possible, when it makes sense, to maintain consistency with other Colville River Unit pools. Just to provide an introduction, this is a slide that shows the relative location of Alpine relative to the other North Slope fields. We have Prudhoe, Kuparuk and Alpine. The Colville River Unit is shown here. We're going to show in more detail the actual mapping associated with Qannik, but basically it's an accumulation that overlies the Alpine Field. Primarily it's CD2, in some it's CD4. The expansion that we have proposed is a seven and a half acre expansion, a gravel expansion at CD2. Whenever possible we're going to use existing infrastructure. The development plan is a phased development. Our initial development is a nine well horizontal development covering about 5,000 acres. We plan or would like to implement a waterflood. The oil in place in the initial development area, we'll talk more about this later, is 79 million barrels with projected ultimate recovery of 17 million barrels. That's about a 22 percent recovery factor. If we're successful we've identified up to nine additional locations we'd like to proceed R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 6 • • 1 2 I 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 with in the next two years. We'll provide testimony as to where those locations are. And our working interest is 78 percent with Anadarko having 22 percent, that's the same as the Alpine Field. COMMISSIONER FOERSTER: If you're successful, what is the upside in additional reserves with those up to nine upside wells? MR. FRAZER: I have a slide that directly..... COMMISSIONER FOERSTER: Okay. MR. FRAZER: .....covers the information there. Just to provide an introduction as to where we are with regard to the project, we drilled our initial appraisal well, the CD2-404 in June of '06. We obtained all our permits by March of '07. we filed a PA application May of this year. We're currently undergoing facility construction, we started in February, we'll have all the insulation, all the work done by August. We plan to start development drilling in June and right now as of yesterday our plans were start production in July. Or our goal is and I think it's a realistic goal. COMMISSIONER FOERSTER: As of yesterday, are they different today? MR. FRAZER: No, but I haven't checked. With that I'll turn over the -- to Dora to talk about ownership. CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MS. SORIA: Yes, I am, Commissioner -- Mr. Chair. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 7 • ~ 1 2 3 4 5 6~ 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 I 2 3 ~~ ~I 24 25 CHAIRMAN SEAMOUNT: Please raise your right hand. (Oath administered) MS. SORIA: I do. CHAIRMAN SEAMOUNT: Please state your name? MS. SORIA: My name is Dora Soria, I'm a staff landman with ConocoPhillips. I -- my background is I have been a landman since 1990, I started my career with ARCO in Lafayette, Louisiana and worked in Houston and subsequently in Alaska. I have 10 years of experience in Alaska. I have worked the Cook Inlet, the North Slope and more recently I'm particularly focused on the Colville River Unit area and also in NPRA. I went to the University of Texas at Dallas, I have an undergraduate degree in -- a BA. I went to the University of Texas at Austin for law school and I graduated in 1990. COMMISSIONER FOERSTER: I'd like to have her entered as an extra special witness because of her education. MS. SORIA: Let that be on the record that I am a Texas longhorn and quite proud of it. COMMISSIONER NORMAN: Nothing -- no objection, Ms. Soria is well known to the Commission. I welcome you. CHAIRMAN SEAMOUNT: I think the first hearing I ever chaired is in this building, you were testifying. We do consider you an expert witness. MS. SORIA: Thank you. I appreciate that. TESTIMONY BY DORA SORIA R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 8 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 r MS. SORIA: Well, good morning, Commissioners, and good morning Chair. The little piece that I have is relative to ownership and development in the area. This is just to orient you a little bit with regard to the area out here. Everything that you see in yellow is ConocoPhillips land within that outlined box. Further orientation here is -- it's kind of hard to see, but there is a stippled outline there that corresponds with the Colville River Unit outline as well. In this box that you see right in here, and it will be more specifically addressed on the next page, but it's 78/22 ConocoPhillips land. This is the outline that encompasses both the pool rule area and the area injection order. You will also see within here the proposed participating area that we are -- will be asking the State and ASRC, they are joint mineral owners here so we will be applying for that participating area. That is based on using a circle and tangent method regarding the proposed wells in the area and so that will be how that is configured and accepted. In addition to that you are seeing a purple outline in here and that purports to represent -- the outline that you saw earlier is just an ellipse or an elliptical portion that will be the reservoir area that we purport to encompass in this area. And that will be more specifically addressed by others that have more expertise in that area. Here you see again the Colville River Unit area, that is R& R C O U R T R E P O R T E R S 811 G STREET (907>277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 9 • • 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 more specifically shown right in here. This is just kind of the exhibit that we will attach to our application to the State and ASRC for the creation of the PA. And that was just to show you that the leases, you know, are within the Colville River Unit, that ConocoPhillips is the unit and will be the participating area operator. The participating area encompasses about 18,000 acres and you see where they are located and defined. In addition to that we are talking about 70,000 areas that are in the pool outline that I've not reflected on here. Again participating ownership is the working interest owners are 78 and 22 in the PA and all the tracts adjacent to the PA are 78/22, and in addition to that all the pool area and injection order area is ConocoPhillips 78 and 22. And there other ownerships at deeper horizons, but they are at 10,000 and greater and then some of them are 8,000 and greater, but they are not affecting our current request from you. That's all I have. Are there any questions? CHAIRMAN SEAMOUNT: Thank you, Ms. Soria. Commissioner Foerster? COMMISSIONER FOERSTER: None. CHAIRMAN SEAMOUNT: None? COMMISSIONER FOERSTER: None. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Just one question and I think it's R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 10 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 • • evident from the map, but I wanted to make sure. Well, first of all when do you plan to apply for the PA? MS. SORIA: June 15th. COMMISSIONER NORMAN: June 15th. And the area that you will be making application for includes the entire reservoir here? MS. SORIA: The way that it is styled with the DNR and ASRC is we can only apply for a PA that purports to encompass our two year program from (indiscernible), so that is what that outline represents. So obviously the purple outline that you saw in that exhibit is a bigger outline, that is the reservoir outline. But we can only include in the participating area again what we can drill in the next two following years. And then we will provide for revisions as we increase our program. COMMISSIONER NORMAN: So your plan would be then as you delineate to expand? MS. SORIA: That is correct. CHAIRMAN SEAMOUNT: Okay. MS. SORIA: Thank you. CHAIRMAN SEAMOUNT: Thank you, Ms. Soria. MR. FRAZER: The next individual to testify will be Doug Knock. CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MR. KNOCK: I am, yes. CHAIRMAN SEAMOUNT: Please raise your right hand. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 11 • • 1 2 3 4 5 6 7 8 9 10 11 12 I 13 14 15 16 17 18 19 20 21 22 I 23 24 25 (Oath administered) MR. KNOCK: I do. CHAIRMAN SEAMOUNT: Okay. Please state your name, who you represent, whether you want to be an expert witness and what your qualifications are? MR. KNOCK: I would like to be an expert witness. My name is Doug Knock, I'm a geologist with ConocoPhillips. I have 20 years of industry experience. I have a bachelor's degree in geoscience from the University of Idaho, I have a master's degree in geoscience from the University of Alaska at Fairbanks. And I've worked for ARCO, Phillips and ConocoPhillips over that 20 year period on all the North Slope fields just about. CHAIRMAN SEAMOUNT: Commissioner Foerster? COMMISSIONER FOERSTER: I have no objection. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: No objection. CHAIRMAN SEAMOUNT: Yeah, I worked with Mr. Knock's father in Caster, Wyoming for a number years. It's a geological family. Okay. Please proceed, Mr. Knock. TESTIMONY BY DOUG KNOCK MR. KNOCK: The first slide the pool name and unit and pool reservoir. The unit is the Colville River Unit in the blue background. The pool name here is the -- going to be the Qannik Oil Pool and the reservoir is the Qannik Reservoir. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 12 1 Also on the slide are pads CD1, 2, 3 and 4, with the Qannik 2 development most at CD2. 3 Qannik Oil Pool definition. From the CD2-11 type log. 4 I'm going to go ahead and read the definition here. The Qannik 5 Oil Pool is defined as the accumulation of oil and gas common 6 to and correlating to the stratigraphic interval between 6086 7 and 7249 feet measured depth in the CD2-11 well and its lateral 8 equivalents. So we have the CD2-11 logs on the left display, 9 measured depth, and you can see the top of the Qannik which is 10 also informally known as the K-2 at 6086 and then on down to 11 the bottom of the Qannik which we're calling K-2 Basal. And 12 that is the Qannik Oil Pool. 13 Also on the slide is a TVD representation of the logs to 14 the right. So you've got to the left I believe the well went 15 through Qannik at 59 degrees. So there's a lot of major depth 16 footage on the measured depth display there. 17 North Slope stratigraphy. Qannik is broadly equivalent to 18 the Nanushuk Group, late cretaceous in age. It's the youngest 19 of the six reservoirs in the greater Alpine area, it's also the 20 newest discovery of the -- of those six reservoirs in the 21 greater Alpine area. 22 CHAIRMAN SEAMOUNT: And that was page 12. I forgot to ask 23 you all to -- when you're referring to the slides that -- refer 24 to the slide number so that the reporter can get it accurate -- 25 as accurately as possible. r •~,,//~ 2~9 _ ~t~, A I'+~Ktt_3 «~G?~2S R & R COURT REPORTERS ~tV e~n~~IC.~'f~~"''~+. 811 G STREET / //\ (907)277-0572/Fax 274-8982 /J~L3 ANCHORAGE, ALASKA 99501 1 3 77.0 ~ • 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 MR. KNOCK: Okay. CHAIRMAN SEAMOUNT: Thank you. MR. KNOCK: Slide 13, a brief geologic overview, a structure map for top Qannik on the left showing the nine -- or eight proposed development wells with the one existing horizontal well drilled in blue in the center. (Indiscernible) environment is a shallow marine sandstone. The sand body is north-south elongate, the approximate depth is 4,000 feet subsea TVD. The trap is a combined structural and stratigraphic trap with onlap, a pinch out to the west, and a shale out to the east. CHAIRMAN SEAMOUNT: Are those -- what are the red dots? MR. KNOCK: Those are the 100 plus well penetrations we have going through this 4,000 foot interval on down to Alpine and other reservoirs. CHAIRMAN SEAMOUNT: They're the tag points then? MR. KNOCK: Those are the tag points for the top of the Qannik structure. So a lot of well control in the CD2 and the CD1 pads which are shown to the left and the right there. CHAIRMAN SEAMOUNT: And I assume all those areas without the tag points are based on seismic? MR. KNOCK: They are. So you -- the structure is highly controlled by all those penetrations around the pads and then you lose some structural control the north and the south. And highlighted on there is the 4,000 foot structural contour and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 • ~ 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 that is the approximate GOC. CHAIRMAN SEAMOUNT: It looks like your main part of the reservoir is this syncline, is that correct? MR. KNOCK: It's pretty much a very low relief, very low relief structure. I think those are -- what are those, 54 -- contour interval looks like 40 feet on here -- 20 feet, sorry, 20 feet contour interval management. I'm not very good at reading those contours, but I believe those are 20 foot contours so very low structural relief. Lithology is a very fine grained lithic rich sandstone, approximately equal parts of quartz grains and lithic grains, a lot of sedimentary rock fragments. Net pay is up to 22 feet, average 10 to 15 feet. Porosity 20 to 25 percent and permeability up to 50 millidarcies. COMMISSIONER FOERSTER: So is the Qannik something that you discovered as you were drilling deeper? MR. KNOCK: We drilled through it for, you know, a long period of time with the Alpine development. It was always deemed to be thin and not real impressive on the logs. There was always a question from a couple of rotary sidewall cores we got when we drilled the Alpine 1 well, they appeared to be pretty tight. I think we had MDT data way back then that also suggested low mobility. So we didn't really think it was developable being that it was deemed to be pretty tight and thin. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 15 • • 1 2 3 4 5 6 7~ 811 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I COMMISSIONER FOERSTER: So what changed your mind? MR. KNOCK: We got -- we finally got funding for a core and once we got a look at it with the core and we saw that it was fully oil saturated, there's always a question also on whether it was gas or oil. And getting that core convinced us that it was an oil reservoir as well and it had some reasonable reservoir properties. COMMISSIONER FOERSTER: Thank you. MR. KNOCK: Next slide, slide number 14 data and exploration history. Up to a -- or more than 120 well penetrations in the CD1 and CD2 pad area with gamma ray and resistivity. About half of those we have density and neutron for porosity logs. We have mud logs and pretty much all the named wells on the slide and what do you want me to do with that? (Off record comments) MR. KNOCK: Mud logs in the CD2 pad area, approximately five around the CD2 pad. RFT/MDT data, Alpine 1, Nanuk 2, Nigliq lA, Nanuq 5 from the 1995 to 2002 time range. Rotary sidewall cores in the Alpine 1 well in 1995 and in Nigliq lA well in 2001 up to the north. We -- really what determined that it was going to be a reservoir, going to be a development was the CD2-11 core in 2005. Oil samples from MDT in Nanuq 2, Nanuq 5 and then oil samples from core extract in CD2-11, ail samples from the production test in CD2-404, the horizontal R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 16 • • 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 well. The well test in 2006 which was our appraisal well and 3D seismic, the Colville 3D shoot from 1996 covers the area. Log model analysis, as I said we'd -- on slide 15 we got a core in the CD2-11 well, we had our petrophysicist Jim Cline (ph), use that core to calibrate a log model for the Qannik interval. On the slide you can see the red curve with the core data points tied to the porosity log, a pretty good match between core porosity and log porosity. From this well we have it and a half feet of net pay from the log model and that agrees with the core data. 22 percent porosity, 16 millidarcy perm and about 37 percent water saturation. In 2006 as I said, sorry, slide 16, we drilled the horizontal well shown on the map on the bottom, just north of the CD2 pad. We drilled almost 6,000 feet horizontal. Didn't have any significant trouble drilling the well. We have a net to gross of about two-thirds, about two-thirds of the horizontal footage is in what we would call net sand. We spent some time in between what we were calling lobe one, the upper lobe and the lower lobe. So we spent a fair amount of time in the sort of paleocsoapy (ph) section between the two lobes. We had some uncertainty in structural control, but no problem getting the liner down and no problem completing the well. So it all worked out very good. CHAIRMAN SEAMOUNT: Thank you, Mr. Knock. MR. KNOCK: You bet. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 17 • • 1 2 3 4j 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. FRAZER: Okay. I'm Lamont Frazer, I'm on slide 17. I wanted to provide a little bit of additional testimony with regard to why we didn't initially proceed with Qannik development. Oil price paid a tremendous role in changing our minds. COMMISSIONER FOERSTER: So for either one of you. When you originally started working up in Alaska, 10, 20 years ago, did you ever think you'd be developing 11 feet of net pay? MR. FRAZER: Eleven, no, I really did not. MR. KNOCK: No. MR. FRAZER: The other issue associated with Qannik is -- and I'll talk more about this in terms of fluid properties, but reservoir temperature is nominally 90 degree Fahrenheit so it's cool. It's 38 PI gravity crude, so it's not as good as Alpine. It's going to be much more viscous. Our in situ viscosity is two centipoise. So relative to Alpine this is a -- it's not a viscous crude by any stretch of the imagination, but relative to Alpine which has .5 centipoise in situ viscosity, it is viscous. In addition there was consolidation issues associated with Qannik. We didn't know if we could drill long lateral sections as horizontal wells. We proved that we could do that with our CD2-404 exploration well. Okay. I'm going to talk about reservoir and production. On slide 18 I have a fluid properties summation. And it shows R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 18 • • 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 that we've got oil samples from basically four wells over the Qannik interval. And they're all nominally 38 PI gravity crude. The reservoir temperature is nominally 90 degrees Fahrenheit, our saturation pressure and our initial pressure is approximately 1,850 at 4,000 feet TVD subsea which is the approximate oil gas contact. As I mentioned we have two centipoise in situ viscosity, our density's about .88 grams per cc. Our solution GOR is just over 400 SCF per barrel. The -- our FVF (ph), formation volume factor, is about 1.2 reservoir barrels per stock tank barrel. And our compressibility is about eight times 10 to the minus six per psi. We do not have a water sample from the Qannik. We have not seen water in the Qannik reservoir however we did obtain a water sample from the Torok formation which the Qannik is a part of. This is much deeper, this is about 6,200 feet subsea in the number 2, but what it showed is that we had nominally 18,000 ppm sodium chloride, brackish type water. Our development plans. Initially we would like to go with the nine well development, those nine wells are shown here. We're going to keep our CD2-404 appraisal well and we'll drill eight additional new wells. Our recovery mechanism will be waterflood from inboard water injectors and gas cap expansion from the east. I'm currently on slide number 20. There is a potential that we may have some gas cap expansion from the west, but the reservoir quality degrades so severely in that R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 19 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 • direction that we're not really counting on it. I'm now on slide 21. And this shows the expanded opportunities that we have. We have three additional updip (ph) injectors that we plan to drill to the east if we're successful and we've identified six locations from CD4 that we'd like to pursue if we're successful. With these nine additional locations we'd have 18 development wells that we've identified. Here though our recovery mechanism would change. Because we'd be isolated from the gas cap expansion to the east, we'd be primarily a waterflood. There is the potential again that we might get some gas cap expansion benefits from the west, but we can't count on that. I'd like to talk about on slide 22 the CD2-404 production results. This is a plot showing rate versus time for the summer '06 CD2-404 production test. We produced the well for 19 days and averaged about 1,200 barrels a day, then we shut it in. We shut it in for seven days. During that time we used a geomodel that was calibrated to our reservoir model to the initial 19 day draw down and the seven day build up, and we'll talk more about the results of that model in the following slides. What we then did is we produced the well periodically throughout the summer. We encountered some problems though and I've highlighted those problems with the circles. What we found is our rates would suddenly drop off very precipitously and when we'd go into the well we found that we had hydrates. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 20 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 I 25 So we tried it again and we found out we had hydrates again so we started methanol injection to address the hydrate problem and it did appear to address the hydrate problem, we had no problems while we were using methanol. We stopped using methanol, shut in our lift gas and the well basically died on us, we went in and we found hydrates again. I'm now on slide 23. Commissioner Foerster, you had asked OOIP for the upside case, that's shown here. We estimate our OOIP about 127 million barrels and our expected recoveries about 28 million barrels. I'd like to talk about how we derived these numbers here. For our nine well case as I mentioned earlier, we have 79 million in place, ultimate recovery projected at 17 million with a range of 11 to 25. We're expecting a recovery factor of about 22 percent. The incremental benefit of waterflood is about 5 million barrels or 7 percent original oil in place. That means that through primary depletion and gas cap expansion we're expecting about a 15 percent recovery factor. Our peak annual rate is about 4,000 barrels with a range of three to six which translates to an average expected yearly rate of about 700 barrels per day per producer. Now this is simulation based. We didn't simulate the 18 well case, however we did scale the simulation result from the nine well case to approximate what the 18 well case would give us. And that gave us a recovery of about 28 million barrels, R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 21 • ~ 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 18 to 40, again since we're scaling we're using the 22 percent recovery factor and an incremental benefit to waterflood of 9 million barrels or 7 percent original oil in place. CHAIRMAN SEAMOUNT: Do you know the extent of the pool north south? MR. FRAZER: Do we know the extent? CHAIRMAN SEAMOUNT: Where you run out of well control, I mean..... MR. FRAZER: I'll let Doug answer that. MR. KNOCK: No, we do not. We don't have sufficient well control to north or south and seismic doesn't really show it up very clearly. CHAIRMAN SEAMOUNT: So your original oil in place is just based on an assumption of how far each well will drill, correct? MR. FRAZER: The original oil in place was calculated for these purposes by using half the well distance. Our spacing is nominally 3,000 feet so we've gone out 1,500 feet around the boundary of each well and that's how we've calculated our oil in place. CHAIRMAN SEAMOUNT: Okay. But so it could be a lot bigger, right? MR. FRAZER: It could be, yes. We've done some calculations and as mapped within the area that we're seeking pool rules for, it's about 160 million in place. But there's a R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 22 • • 1 2 3 4 5 i 6 7~ 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 lot of uncertainty there. I'm now on slide 24 where I'm going to talk about reservoir management and surveillance plans. Reservoir management, what we plan to do to optimize rate and recovery is use undulating horizontal wells. The remaining wells are targeted for seven and a half to 9,000 feet lateral section. As a guideline we plan to have peak to trough distances of about 2,000 feet. Clearly if we have good reservoir quality rock we'll want to stay in that reservoir quality -- good quality rock longer distances, but as a guideline 2,000 feet to trough. We also have the updip injectors that you saw if things go well for our expanded phase development. There's a chance we'll want to drill the updip injectors to the east at CD2 even if things don't go well. The case that would entail that is if our gas gap encroachment is more severe than our reservoir simulations are projecting, we'll want to isolate that gas. To do that we'll drill the three updip injectors that I previously showed. In terms of voidage replacement, we do ultimately plan to target a voidage replacement of one, however it's going to be a function of our pattern and configuration. For example, in the upside case where we have isolation from the gas gap our target will be one and we'd like to measure it within the floodable area. Let me go back and show you that. I'm going to go back R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 AHCHORAGE, ALASKA 99501 23 • ~ 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 to slide -- I'm going to go back to slide 21. In this scenario where we drill the updip injectors and we have 18 wells, within the floodable patterns our target pressure will be plus or minus 200 psi from initial conditions. However in the case where we go to the initial development and we don't drill the updip injectors because our results are bad, I'm now on slide 20, in this case we'll target 200 psi plus or minus initial conditions in the floodable area. Of course we will not be able to maintain pressure in the gas cap and, in fact, in order to realize the gas cap expansion benefits we'll have to have that go below saturation pressure. So our voidage replacement will be a function of our ultimate patterns. COMMISSIONER FOERSTER: Do you have adequate water? MR. FRAZER: Do we have adequate water? We will have adequate water for Qannik. We -- our latest projections are we can get adequate water from Alpine without hurting its flood, but, Commissioner, there is some issues with our coner (ph) in terms of whether we can maintain that supply. But that affects more than just Alpine, it affects all Colville River Unit fields whether or not we'd be able to maintain our supply of water from Kuparuk. COMMISSIONER FOERSTER: Well, what would you suggest would be the appropriate course of action if you're not able to get adequate water? MR. FRAZER: We have a team investigating alternatives R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 24 • • 1 2 3 4 5' 61Ii i 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 right now. There's a number of options that we're looking at. I don't know which will be deemed the most economic, but there is other sources of water rel -- other than the Kuparuk River seawater treatment plant. There's a lower K-2 that's below us that could act as a source of water, there's the cretaceous source water wells at Kuparuk located at drill site 1-B that could be investigated. There's a number of options that are being looked at. COMMISSIONER FOERSTER: So are we saying it's being looked at because you anticipate problems here or because water's been a bottleneck and you need to -- you foresee further expansions, a combination of the above or something different or D, all of the above? MR. FRAZER: We believe that modifications can be made to the seawater treatment plant that will provide adequate water for the Colville River Unit. The amount of water that we're talking about using for Qannik is a relatively small amount and I'll talk about our expected injection rates. But nominally we're talking about 5,000 barrels of water per day for our nine well case. The water issue is a much a state of flux, but it has to ConocoPhillips and BP that are whether or not we'd be able to want from the seawater treatme R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 broader issue and it's still in do with relations between currently being worked and maintain the amount of water we zt plant. And I'm not qualified 25 • • 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 to talk move about that other than to say that we will do everything we absolutely can to get water, if that means having to look for other sources beyond the seawater treatment plant that's on the books right now that we're looking at. COMMISSIONER FOERSTER: Thank you. COMMISSIONER NORMAN: Mr. Frazer? MR. FRAZER: Yes. COMMISSIONER NORMAN: Could you go back to slide 21 for a moment, I just want to make sure that I under -- I believe I understand, but could you indicate there the area of the gas cap? MR. FRAZER: The gas gap -- in fact, I have a slide that will detail this in much more detail, but I'll..... COMMISSIONER NORMAN: Then I'll wait on that. MR. FRAZER: Okay. COMMISSIONER NORMAN: I'll wait until you come to that. MR. FRAZER: But let me -- let me show here because I believe that slide that details it might be in the confidential section so I'll detail it for the public. The gas gap is to the east. We've seen GOCs, Doug, correct me if I'm wrong, but I'm pointing to the approximate area where we're seeing the GOC because we cross the GOC with these injectors. MR. KNOCK: That's correct. MR. FRAZER: At the injectors even though we're penetrating into the GOC because it's a very low release system R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 26 • • 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 we have mostly oil. Yes, we have gas, maybe a couple feet of gas on top of nine or eight feet of oil, so it's still a very enticing area to put our injectors. Of course we have uncertainty in terms of what the GOC does up here because we don't have well control. And the GOC to the west follows something like this, but again the reservoir is so poor there that it's unlikely it's going to give us much support. I'm back on slide 24. In terms of surveillance we plan to use well tests, pressure measurements and when appropriate surveillance logs. With regard to slide 25 I have a summary. This is Rule 3. In our written application we requested a specialized waiver specifically because we're drilling horizontal wells we'd like to come closer than the 1,000 foot well spacing minimum. Our heel to toe distances we'd like to be closer than that. And we would plan to notify the Commission any time that we drill within 500 feet of a boundary that has an ownership change. Another specialized waiver that we're looking at is..... COMMISSIONER FOERSTER: Do you have any boundaries with ownership changes? MR. FRAZER: I'll refer that to Dora. Dora, do we? MS. SORIA: Not in our blocks. COMMISSIONER FOERSTER: Okay. I didn't remember any. Okay. MR. FRAZER: On slide 26 we are seeking a GOR exemption in R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 27 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 I 15 16 17 18 19 20 21 22 23 24 25 accordance with regulation 25 240(b) With enhanced recovery operations we'd like exemption from the GOR limits. And, of course, if we have the gas cap expansion benefits, we would have to have relief from those benefits otherwise we could -- or the regulations otherwise we couldn't produce the wells. Now I'm going to talk about surface facilities on slide 28. This is an outline of the CD2 drill site. What I have here is I have a overview of where we added our additional gravel and that's shown with a crosshatched area. And then I have blown up details in terms of what equipment, what additional facilities we added. We have our Qannik well row that can hold up to 18 additional wells, we have a chemical injection skid and we have a REIM or remote electrical instrumentation module. We do not yet have methanol storage on the facility although it's a possibility given the hydrate problems that we have, but we have identified space for it if we can't overcome those problems. We've also identified space for a future heater and separator if necessary, but right now neither of those are currently planned. In terms of metering the separation involves using divert valves to route production to a test separator. CD2 has a two phase test separator. We then measure the fluids, our produced gas is measured using a Coriolis mass meter corrected to STP. Our produced liquids are metered with a Coriolis mass meter. We use a microwave analyzer for water cut determiner and, of R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 28 • • 1 2 3 4 5 6 71'~ 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 course, we correct the old to STP. Other liquids or other fluids that we're metering including water injection, we use Orifice plate meters for each well and lift gas where we're using Coriolis mass meters for each well and, of course, we correct to STP. Fluid allocations, we're now on slide 30. We're going to use the same methodology as we use throughout the Colville River Unit and that is to -- basically what we do is we come up with an allocation factor that's calculated by summing the individual well tests for all the wells and dividing by the metered production and then we multiply that allocation factor by the test volumes for an individual well to come up with an allocated oil volume. And that concludes surface facilities and I'll turn it over to Brian Noel to talk about drilling and completions. CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MR. NOEL: Yes, I am. CHAIRMAN SEAMOUNT: Please raise your right hand. (Oath administered) MR. NOEL: Yes, sir. CHAIRMAN SEAMOUNT: Please state your name, who you represent, whether you want to be an expert witness and what your qualifications are on what subject? Thank you. MR. NOEL: All right. My name is Brian Noel, I'm a drilling engineer with ConocoPhillips and I will be giving R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 29 • • 1 2 3 4i 5 61 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 expert testimony. I have a bachelor of science in geology from the University of Illinois and also a bachelor of science in petroleum engineering from the University of Wyoming. I have over 25 years of varied industry experience in the Rocky Mountains and Alaska, I've been working as an engineer here in Alaska since 1991 for Conoco and their predecessor ARCO. And the last 10 years have been working in drilling. And in 2002 I obtained my PE license in petroleum engineering in the state of Alaska. CHAIRMAN SEAMOUNT: So you became a traitor to geology then. Any..... MR. NOEL: The downturn did that to me. CHAIRMAN SEAMOUNT: I don't blame you. Any questions, Commissioner Foerster? COMMISSIONER FOERSTER: No, I have none. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: You said you're working toward your PE license or you have your PE license? MR. NOEL: I obtained it in the fall of 2002. CHAIRMAN SEAMOUNT: Okay. So you are ruled an expert witness in petroleum engineering or drilling -- drilling engineering or both? MR. NOEL: Drilling engineering is my testimony..... COMMISSIONER FOERSTER: He's done both. R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 30 • • 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 CHAIRMAN SEAMOUNT: He -- okay. MR. NOEL: .....but I've done both. CHAIRMAN SEAMOUNT: We'll even throw in geology too. MR. NOEL: Thank you. COMMISSIONER FOERSTER: Don't forget to say what slides you're talking off of. TESTIMONY BY BRIAN NOEL MR. NOEL: Okay. We're currently on slide number 32. As you already heard it's -- the Qannik for the initial development is nine wells. We have drilled the CD2-404 well in 2006, a very successful operation. And what this slide portrays is the Qannik well spider map, it's a planned view of the wells. And then the grayed out underneath are the 60 Alpine sand wells that have been drilled from this CD2 pad to date. The base plan for Qannik is seven to 9,000 foot horizontals. The initial well we drilled was 6,000 feet so we've increased the length to span more of the reservoir as currently mapped. And we have been drilling in the Colville River delta since 1999, over 130 horizontal wells to date to various reservoirs, initially Alpine and then the Alpine satellites. Here's just a brief overview of our joint practices. These are consistent with the drilling that's been done to date in the Colville delta. These are all deviated wells so the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 31 • • 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 directional surveys with MWD tools. The open hole logs would be obtained logging while drilling, no plans for wireline logs given the hole angles. We have the same horizontal wellhead system we've been using for all the development out there, it allows a single BOP rig up and a much more efficient operation for the following casing runs. And the North Slope muds we're using are typical across the Slope, it's the same we've been using for Alpine and the satellites. The first two hole sections, the surface and intermediate are both water based mud systems. And then for the horizontal in the Qannik sand we drilled the first well with a mineral oil based fluid in it, it's mainly being used due to the interbedded shales and trying to minimize reservoir damage. And we plan to continue with annular disposal of our drilling fluids and cuttings. The area injection order for Alpine recognized that there was no underground sources of drinking water in the area. We have a ball mill with the rig, we wash all the surface gravels and if they pass the test for contaminants we reuse those gravels for the spill on the gravel pads or roads out there at Alpine. And then the remainder of the cuttings we grind with a slurry and annular dispose with the mud. Our disposal interval under CD2 and consistent with all the Alpine pads is the top of the CB formation. It really R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 32 • • 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 accepts the fluids and our wells will be constructed and permitted under the regulation 25.080 for annual disposal. So we'd apply for each of those annual disposal permits separately as we move forward. Slide 34 is an outline of the drilling construction process. This is consistent with Alpine and the Alpine satellites. The new well on CD2 pad, the wells are spaced on 20 foot centers. We have a conductor pipe which is insulated and thermo siphons installed to help with subsidence so we don't get enlarged thaw bulbs and have sink holes developing on the pad. Surface casings plan at 2,400 tvd and cemented back to surface in a single stage job. We've had no problems out there getting cement to surface on our wells. Then we install our BOPE and test it, test the casing and drill out our shoe, drill ahead less than 50 feet, perform the leak off test to show we have integrity. Drill our intermediate hole section and this is the directional part of the well where we turn the well so it's pointed north-south and land horizontally in the sand. We run our second string of pipe, the production casing, it's cemented in zone. We'll bring cement according to regulations above the top of the Qannik sand a minimum of 500 feet of coverage. Once that's in place we drill out 50 feet, perform a formation integrity test to show that we can drill the horizontal and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 33 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 • • have integrity within the sand and the casing shoe. Drill the horizontal section with the mineral oil mud, clean the well up. We plan slotted liners for the Qannik. If we do encounter significant shale beds we'll run blank pipe across the shale. And then we have what we call constrictors which are small, swellable packing elements so we can blank off that shale and won't get fine movement within the horizontal section and plug up the well. The injectors, we plan to submit quality log before we run our packer and tubing. And then on the producers you've heard we did experience some hydrates in the first well so we plan to install thermo centralizers which are plastic centralizer on the tubing so we get stand off from the casing wall and that modeling shows will give us enough extra temperature in the tubing to keep us out of hydrate window. On slide 35 the two wellbore schematics are shown. On the left if the producer and on the right is the injector. The two main differences are the producers, we plan gas lift so there's gas lift mandrills (ph) in the tubing string right here. And the base plan is it just two given the shallow depth were at to lift the well adequately. The producers will also have like all the other wells at Alpine a subsurface -- a surface controlled subsurface safety valve and also a fail-safe surface safety valve. On the injector we have a profile at the same depth as the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 34 • • 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 producer's subsurface safety valve, but it accepts a wireline run injection valve. And we'll also have a surface safety valve. And then consistent with Alpine and the Alpine satellites, there was two waivers we are asking to be incorporated in the pool rules. The first one was in lieu of the regulation on what is required to be submitted for the directional plan. Our proposal was -- is more comprehensive and has become the accepted standard with the permit to drill packages where we have the plan view vertical section, all the close approach data and a very detailed directional drilling program and any close approaches involved. And the second waiver in lieu of obtaining logging data from the conductor to the reservoir on every well out here since they're all in close proximity on the same pad, we were proposing just to obtain data at least on one well out there to meet that regulation's requirement. And that was it from the drilling completions unless there are any questions. CHAIRMAN SEAMOUNT: Any questions? COMMISSIONER FOERSTER: I have a few. Are you proposing any special safety valve system rules or are you anticipating that the amendments we're making to the statewide safety valve rules will be adequate for you guys? MR. NOEL: Those will be fine with us. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 35 • • 1 2 3 4 5 6 7 8' 9 10 'I 11 12 13 14 15 16 17 18 19 20 21 22 2 3 '' 24 25 COMMISSIONER FOERSTER: Okay. And the second one is did you encounter any of the unconsolidation concerns that you anticipated and if so how did you deal with them and what -- is there anything you're going to have to do for them? MR. NOEL: The production tests we didn't see any formation fines during the production and also we injected water and flowed it back and had very little solids coming back. COMMISSIONER FOERSTER: Thank you. MR. NOEL: And drilling the well we didn't see any issues with the -- trying to keep the horizontal open, that was one big concern. COMMISSIONER FOERSTER: That's all. I have no questions. CHAIRMAN SEAMOUNT: Commissioner Norman, do you have any questions? COMMISSIONER NORMAN: Mostly just about the sequence of your presentation. I'm guessing now that you will go into some of the material for which your asserted -- ConocoPhillips is asserting confidentiality, is that right? MR. FRAZER: What I'd like to do is address a couple questions, give an outline of some of the confidential material and then we'd like to go into the confidential section. COMMISSIONER NORMAN: Sure. CHAIRMAN SEAMOUNT: Okay. COMMISSIONER NORMAN: Good. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 36 • • 1 2 3 4 5 6 7 8 9' 10' 11~~I 12 13 14 15 16 17 18 19 20 21 22 23 2 4 ', 25 CHAIRMAN SEAMOUNT: So you're going to generally describe what kind of information you want to present in camera? MR. FRAZER: Yes. CHAIRMAN SEAMOUNT: And confidentiality always adds some complication. So, yeah, that would be real instructive. Also could you point out the people in this room that you would allow to stay in for this presentation? MR. FRAZER: Let me first address a couple of questions. CHAIRMAN SEAMOUNT: Come on up to the table, please. MR. FRAZER: Commissioner Foerster asked about the fines and flowing back. There was no appreciable fines that flowed back during the production test when we were flowing oil. After we injected water we did have 1 to 2 percent fines flowing back. It's not necessarily indicative of what we'll see in the field with water breakthrough because we injected well above (indiscernible) pressure and we did not attempt to gradually bring the well on, we just opened the choke and everything came back. So yes, we did have fines with water. COMMISSIONER FOERSTER: But not -- it's not something that you expect to see is it, to continue with -- the situation to..... MR. FRAZER: Nothing that we would expect to see with continuous oil production. We recognize there's a risk that we will see it with water production, it's not a certainty. If we do see it with water production we believe that we can handle R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 37 • • 1 2 3 4 5' 6 7 8 9 10 it 12 13 14 15 16 17 18 19 20 21 22 1 23 24 25 I it with chemicals to break any type of emulsions and vessel clean out. COMMISSIONER FOERSTER: And you're not -- you don't anticipate that i just fill us your MR. FRAZER: COMMISSIONER MR. FRAZER: COMMISSIONER is going to be so severe that it's going to wells, sand up your wells? Oh, no. No. FOERSTER: Okay. It's a -- no. FOERSTER: Obviously with no screens in your liners..... MR. FRAZER: The other thing I was going to address is you'd asked about ownership earlier, was there an ownership change. The specialized waiver in that case was more of a consistency request because it is similar to what we have with our other oil pools in the Colville River Unit and if we were to expand this pool so we don't get confused in having different rules to follow, that was the logic behind it. COMMISSIONER FOERSTER: And so if you're really lucky and it does extend to a greater area than you anticipated..... MR. FRAZER: It's possible. It's possible. COMMISSIONER FOERSTER: So we don't rule -- you know, to throw in rules that don't -- that we don't think will ever apply. MR. FRAZER: Right. The logic there, if the Commission agrees, was one of consistency. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 38 • • 1 2 3 4 5 611 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 I 23 24 25 COMMISSIONER FOERSTER: Thank you. MR. FRAZER: With regard to the confidential section, we had submitted a confidential written section with our application. That was a document that was intended to serve as a stand alone document. It contained both public and confidential figures in there. I think much of what -- or some of the key items that were placed in that document have been brought forth today during the testimony. If the Commission feels that there are either confidential figures in there that you need to have brought forward as public domain or in the confidential section that we're about to have, if you let us know I'm relatively optimistic given a relatively a short period of time, a week maybe two, we could with permission through our management system to get those in the public domain. We just ask that you let us know if there's any figures that you would like for us to try to put through the approval process. COMMISSIONER FOERSTER: Okay. Let me understand. The reason that you're asking confidentiality isn't that they need to be confidential for trade secret purposes or..... MR. FRAZER: The reason -- no. The reason we're asking for confidentiality is trade secret, they're interpretive data, they're trade secrets data, they're considered proprietary. However if the Commission feels it's necessary to make a ruling to move some -- a figure or two into the public domain we can R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 39 • • 1 2 3 4 5 6 7 8 9 10 I 11 12 13 14 15 16 17 18 19 20 21 I 22 23 24 25 -- there hasn't been a final determination by our management to say no, under no circumstances, these will be held confidential . CHAIRMAN SEAMOUNT: So it's -- they're the figures, right, not the wording within the document or the..... MR. FRAZER: It would be both. CHAIRMAN SEAMOUNT: It would be both? MR. FRAZER: It would be both. CHAIRMAN SEAMOLTNT: And what kinds of data are they, are they..... MR. FRAZER: In terms of the confidential data? CHAIRMAN SEAMOUNT: Like are they seismic data, are they maps? MR. FRAZER: There's seismic data, there's -- there's seismic data, there's core data. MR. KNOCK: There's some maps that show the trend of the sand body outside the unit area, you know, away from..... CHAIRMAN SEAMOUNT: Okay. MR. KNOCK: .....maybe where we hold acreage. CHAIRMAN SEAMOUNT: Okay. So they go onto unleased acreage? MR. KNOCK: I can't state that specifically, but certainly outside..... CHAIRMAN SEAMOUNT: But it might? MR. KNOCK: .....certainly the trend of the sand body on R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 40 • • 1 2 3 4 5 6 7 8 I 9 10 it 12 13 14 15 16 17 18 19 20 21 22 I 23 24 25 one of the displays would suggest it goes outside the unit. MS. SORIA: If I may address that comment, this is Dora Soria, staff landman for ConocoPhillips. The lands are pretty secure, they're all leased either by us or by others. In addition to the confidentiality of this information being vital to proprietary data, interpretative data that is outside the scope that we usually provide to AOGCC, we also have partners to consider in this area and we have not had approval from partners to expose any of this data. And like I said it is proprietary to the company and it is subject to trade secrets, et cetera. So the fact that you would ask for us, still may not be that we would respond that we will make it public, we would just make a big effort to try to make it public in the event that you requested that. CHAIRMAN SEAMOUNT: Okay. Well, you hit on something that -- it seems like so far and we're going to have to go into recess to discuss this among the staff, but so far you've given a very -- I think a very complete presentation. And we may not need to look at the confidential information although we would love to see it, but it may not be necessary. COMMISSIONER FOERSTER: And we have a concern with accepting information as confidential, but, you know, then it becomes vaccinated as confidential forever and that may not be an appropriate move for us to make. So we would rather err on the side of not accepting data that we don't need and then R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 41 • • 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 deeming it confidential. MR. FRAZER: Okay. MS. SORIA: Well, we would appreciate your ruling one way or the other and like I said we..... CHAIRMAN SEAMOUNT: Okay. MS. SORIA: .....we will defer to you. Thank you. CHAIRMAN SEAMOUNT: I..... COMMISSIONER NORMAN: I have one question. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Yeah. My question is -- relates to a different subject that I don't think is confidential. So if it's appropriate I'd like to ask it now before we start talking about the confidential. CHAIRMAN SEAMOUNT: Okay. COMMISSIONER NORMAN: Mr. Frazer, you used the term gas cap expansion and you also mentioned in a different context gas cap encroachment. MR. FRAZER: Yes. COMMISSIONER NORMAN: And can -- could you explain to me a little more the encroachment, your use of the term gas cap encroachment..... MR. FRAZER: Yes. COMMISSIONER NORMAN: .....as opposed to expansion? MR. FRAZER: They're basically synonymous. What I'm trying to illustrate though is that we can produce R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 42 • • 1 2 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 (indiscernible) above solution gas up to a limit. Our facility limits right now are nominally a 5,000 GOR in the summer. Our projections are that we won't have appreciable facility limits around 2012, 2013, time frame from a gas handling standpoint. So as long as we can maintain a GOR below 5,000 through 2012, 2013 time frame, we don't view that as a concern. If we too much gas coming at us in the next couple of years and the GOR's rise four or 5,000, that is a concern, we'll have to try to stem the gas encroachment. COMMISSIONER NORMAN: And my final question, all the gas we're talking about in this particular context is situated and confined within the proposed pool? MR. FRAZER: Yes. The..... COMMISSIONER NORMAN: In other words there's no one else's gas that you see coming from the..... MR. FRAZER: There is no one else's gas I can see coming in. There is a very poor quality, non-reservoir quality zone that is gas saturated above the Qannik interval. It's possible that trace amounts from sub one millidarcy rock could expand in, but nothing appreciable. COMMISSIONER NORMAN: That's all, Commissioner. CHAIRMAN SEAMOUNT: Well, what I -- anything else, Commissioner Forester? COMMISSIONER FOERSTER: I wanted to compliment the entire suite of presenters on a very clear to understand and complete R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 43 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 presentation of the information now. • But no other questions right CHAIRMAN SEAMOUNT: Ditto. So what I'd propose right now is we'll go into a 10 to minute recess and the discussion will be whether we have enough information in order to make a decision on this application and also whether we have some questions of clarification. And we may come back and want to go into the confidential section or we may come back with just a -- with some questions. And if any of those questions involve confidential information be sure to let us know. MR. FRAZER: Very good. Thank you. CHAIRMAN SEAMOUNT: Okay. COMMISSIONER FOERSTER: And while we're at recess there are cookies out there. I've tested them, they're high quality. CHAIRMAN SEAMOUNT: There's coffee too. MS. SORIA: If I may address the Commissioners, please, this is Dora Soria again, ConocoPhillips. You had earlier asked that -- you would ask the public if there were additional comments, would this be the appropriate time or would you prefer that those comments be addressed after the recess? CHAIRMAN SEAMOUNT: Do you -- do you have any public testimony following the in camera session? MR. FRAZER: I don't know. I'm sorry, I didn't understand your question. CHAIRMAN SEAMOUNT: (Indiscernible) area injection order. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 4 1 2 3 4 5 6' i 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ~ • MR. FRAZER: We have an area injection order. CHAIRMAN SEAMOUNT: Yeah, I'm wondering whether to go to the area injection order, the public part of that right now. That may answer some questions that we come up with or should we take a recess? COMMISSIONER NORMAN: I would -- excuse me, I think it's cleaner if we finish this part of it and..... COMMISSIONER FOERSTER: Yeah, that's what I think. Take a recess. CHAIRMAN SEAMOUNT: Okay. Off the record. (Off record) (On record) CHAIRMAN SEAMOUNT: Okay. The time is 10:33. We just came back from recess and we have a number of questions. And then we will reach a decision on whether the application for pool rules -- we have enough information to make a decision. Okay. So first we'll start with Commissioner Foerster. COMMISSIONER FOERSTER: I apologize, this is more of a curiosity question than anything. As you're drilling to the north where you -- and Brian goes that would be me. As you're drilling to the north you're going into an area where you don't have well control and certainty. If you're still drilling in pay when you reach the -- your projected end, are you going to keep drilling or are you going to stop? MR. NOEL: The current plan is to stop or -- we're about R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 45 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 I 24 25 at our limits of torque and drag to reach out that far. COMMISSIONER FOERSTER: That's all I had. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Yes. My question -- I think probably slide eight would -- do you have the ability to recall the slides? If you don't it's all right. The question just relates to the ownership in the southwest corner of the area, just to be sure that we're clear in that southwest corner of the proposed pool area. MS. SORIA: This is Dora, ConocoPhillips, is this the corner that you were referring to? COMMISSIONER NORMAN: Yes, generally the south -- that -- yes, right there. MS. SORIA: Okay. All of that is ConocoPhillips 78 percent, Anadarko 22 percent. Below the line there is different ownership, but other -- like I said the entire box is 78 and 22. COMMISSIONER NORMAN: Okay. And the lessor is ASRC, the lessor? MS. SORIA: The lessor varies, I don't have this outlined by ownership. Up in this area there's 100 percent state lands..... COMMISSIONER NORMAN: Uh-huh. MS. SORIA: .....and just for the public, I am looking at slide number one. This area in here is 100 percent state or R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 46 • • 1 2 3 4 51 6 71 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I some of it. There's a combination of state and ASRC ownership in the center section, primarily the whole of new PA and then some of the boundaries on this is 100 percent ASRC land. COMMISSIONER NORMAN: Okay. MS. SORIA: Thank you. CHAIRMAN SEAMOUNT: Okay. I have a question for Mr. Knock. Is it mister or doctor? MR. KNOCK: Mister. CHAIRMAN SEAMOUNT: Mister. MR. KNOCK: I'm sorry. CHAIRMAN SEAMOUNT: Do you see any significant faulting or fracturing that would affect the reservoir performance and if you do is that why you're drilling in the direction you're drilling? MR. KNOCK: Very good questions, Commissioner Seamount. No, we -- seismically we do not have any mapped faults in the development -- in the nine well development area. In fact, we've only been able to map one fault to date that's sort of on the west side of the box there, but outside of our planned development. And that fault is a north-south fault. Based on regional data and just knowledge of normal breakout and whatnot, we feel strongly we have a north-south dominant horizontal stress, a maximum horizontal stress north-south to north-west. So we had oriented the wells with that in mind and, of course, our fairway with the gas to the east and to the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 47 • • 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 west really makes us want to go north-south. CHAIRMAN SEAMOUNT: Okay. That -- okay. Now let's see. On your delineation well, did you say you ran any fracture indicator -- indicating logs? MR. KNOCK: Not to my knowledge. We ran just density, neutron and then we have the core and the whole core did not show significant fractures at all. So no, we don't have any real evidence from image logs of any significant fracturing. I believe we may have one image log across the zone in Alpine 1 and I don't recall seeing any fractures. It..... MR. FRAZER: If I may supplement? We ran a production log in the well and got about two-thirds down the lateral section and we saw no indication of flow into the well that would suggest fracturing. It's a relatively even distribution based on KH. CHAIRMAN SEAMOUNT: You're running liners all the way? MR. NOEL: That's correct. To total depth. MR. FRAZER: Slotted liners with blank pipe along the non- pay sections and then we can use the blank pipe as an indication of flow. CHAIRMAN SEAMOUNT: So -- but you don't do that in the Alpine pool, do you, those are just open hole completions, is that correct? MR. KNOCK: Correct. Although we're switching to running more liners because we're fracking more wells and if we find -- R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 48 • • 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 we can focus the fracks with the perforated liner. CHAIRMAN SEAMOUNT: And I believe Commissioner Foerster has another question. COMMISSIONER FOERSTER: On slide number 10, you know, just so Dora gets enough exercise, I know she's not going to hike this evening, this one's for Dora. On slide number 10 there's a hole in your ownership or a hole in the unit boundary? MS. SORIA: This I think -- this is Dora Soria, ConocoPhillips. I think we're looking at slide 10 and you're referring to this north western area. That is a -- not a hole in ownership, ConocoPhillips and Anadarko own that 78/22, it is just a hole in the unit, it is not part of the unit currently. COMMISSIONER FOERSTER: Is there a reason for that? MS. SORIA: Because in order to bring something in the unit usually we either have to have a well that compels that or we have to have evidence that they're -- that it is part of a PA expansion and so forth and to date we have not gotten to that point. We hope to with this area or some other area. COMMISSIONER FOERSTER: Thank you. MS. SORIA: You're very welcome. CHAIRMAN SEAMOUNT: Any more questions, Commissioner Norman? Okay. As far as the confidential section, obviously we would like to get as much as we can into the public record, but having heard your very complete presentation today, we're going to give you the opportunity to withdraw the confidential R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 49 ~ • 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 I section. We don't feel we need any more information to make a decision. So would it be your preference to withdraw it? MR. FRAZER: Yes. CHAIRMAN SEAMOUNT: Okay. So be it. MR. FRAZER: I had a follow-up question though. The hard copies of the presentation we gave you as well as the CD had the confidential section attached. Would you destroy that then, is that the procedure that would..... COMMISSIONER FOERSTER: We'll give all that to you. MR. FRAZER: Oh, you'd give it to us? COMMISSIONER NORMAN: We'll return it so you can cancel it all, we'll..... MR. FRAZER: Okay. COMMISSIONER NORMAN: .....we'll return every copy to you that way they'll be no misunderstanding. MR. FRAZER: Thank you. COMMISSIONER FOERSTER: In fact before you leave today I would prefer that you walked out the door with it. MR. FRAZER: Okay. CHAIRMAN SEAMOUNT: Okay. So I guess that concludes the pool rules part of this hearing. And I understand that you want to go to the area injection order? MR. FRAZER: Yes, sir. CHAIRMAN SEAMOUNT: Okay. And you're all under oath still and you're all still experts. R& R C O U R T R E P O R TER S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 50 • • 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 (Off record comments) MS. SORIA: This is Dora Soria again, ConocoPhillips. And still staying with the same matter I would like to make a correction to some of my earlier testimony. This is in regard to a question that was asked with regard to the submittal of the application for the Qannik participating area. I had already moved onto my next project and my next state, but the actual submission of the Qannik PA application was April 30 of this year. Thank you. COMMISSIONER NORMAN: As opposed to June..... MS. SORIA: Correct. Which is the next project. COMMISSIONER NORMAN: Okay. Good. Good. MS. SORIA: Apologies for the confusion. COMMISSIONER FOERSTER: That's forward thinking, forward thinking. MR. FRAZER: I'd like to start the testimony for the Qannik area injection order. On slide two I have an outline of the topics that we're going to talk to. I'll start off providing an overview and sundry information on various regulations. Doug Knock will address geoscience and the associated regulations with that. Brian Noel will talk about wellbore integrity and then Jack Walker will talk about injection confinement. With regard to regulation 25.402(c), there's 15 requirements that we need to meet. Six of those were covered R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 51 1 2 3i 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • during the pool hearings and we'll refer to the pool hearings testimony if that's okay. And then nine we'll provide additional testimony for. The pool hearing reference will include these six regulations, namely -- I'm on slide four, this has to do with surface owners within a quarter mile, a description of the proposed operation, description and depth of affected pool, casing description and testing methods for injectors, the quality of the formation water and incremental increases associated with ultimate recovery. With regard to additional testimony we'll start out with 25.402(1). This is a plat showing existing penetrations within a quarter mile. There's 125 that fall within the quarter mile. This is slide number -- it's actually covered up a little bit by the map, it was slide number 5. On slide number 6 providing an affidavit of notification. I did on April -- I believe it was during April, I provided notification to the operator, ConocoPhillips as well as state owners state of Alaska and Kuukpik of our intent to file for an application for an area injection order. Injection fluid analysis and rates. What this slide shows is our drilling brine, a synthetic formulation that provides cation and ations (ph) for -- or this is cations for our synthetic drilling brine, a synthetic mixture representing summer Beaufort Sea water and a synthetic mixture representing typical Colville River produced water. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572lFax 274-8982 ANCHORAGE, ALASKA 99501 52 • • 1 2 3 4 5 6 7 8 g 10 11' 12' 13 14 15 16 17 18 19 20 21 22 23 2 4 25 The point I want to make here is if you look at the summer Beaufort Sea water and the Colville River produced water, in terms of total dissolved solids, I'm on slide seven, nominally 25,000 versus 23,000, very, very similar. In terms of salinities, calculated chlorine is 13,600 for Beaufort Sea water versus 13,000 for Colville produced water, very, very similar. We did a lab study looking at impacts on cores associated with injecting the waters. This is a slide showing permeability as a function of cumulative injection volume. Our cores have a core volume of about 15 cubic centimeters so these are numerous core volumes. What it illustrates is that with the synthetic drilling brine there's no indication suggesting we have any kind of damage whatsoever. With regard to the synthetic Beaufort Sea water, what you see here is that initially there's an increase in permeability that's a relative perm effect (ph) as we're displacing the mineral oil from the core. As we begin to flush the core you'll see that permeability does decrease with time. This 500 cubic centimeters, it's about 33 core volumes right here. What this suggests is that there is slight damage mechanism, nothing catastrophic. COMMISSIONER FOERSTER: Mr. Frazer, you called it synthetic Beaufort Sea water, was that a slip of the tongue or are you creating Beaufort Sea water in this case? R& R C OUR 7 R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 53 • • 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 MR. FRAZER: We created a brine in the lab that is representative from an ion..... COMMISSIONER FOERSTER: So it is a synthetic? MR. FRAZER: It is a synthetic. COMMISSIONER FOERSTER: Okay. I heard you correctly. MR. FRAZER: This is a -- this was an interesting core. What we did is we took one of the worst cores that we had that we could flood. And you look at the permeability here, this is very poor quality rock, nominally .l millidarcy. This is the rock that would be most suspectable to fines migration to -- which we expected we were having when we saw the decrease in perm. If you look at this it confirms that we do have fines migration. When you suddenly reverse flow as we have here, going from a forward flow to a reverse flow and you see large step changes, you're mobilizing fines, pushing them against the core throats and causing dramatic decreases in your injection. This confirms that we do have some fines migration that's occurring. In the written application we had numerous plots that showed a variety of cores. It's typical that you in those core flood that the stabilized rate was nominally about one-fourth what the initial permeability was and that's what you'll see here, .08 to .02. So with regard to injection waters, they are compatible with Qannik, there is absolutely no catastrophe permeability R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 54 • • 1 2 3, 41'I ~i 5 6 7 81 91 10 ~I 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 loss from the synthetic brines that were used in the lab study. And in addition we did pump Beaufort Sea water into CD2-404 as a short term infectivity test. Jack Walker will provide additional details on that test later in the talk, but we injected about 26,000 total barrels of Beaufort Sea water, we saw no indication suggesting damage. In terms of the produced Colville water what we were seeking is the ability to also inject that. We did not run any specific lab studies looking at Qannik core with the synthetic produced Colville River Unit water, but given that the compositions are so similar to the synthetic Beaufort Sea water, we're asking that the Commission accept that as indications that there is not going to be a catastrophic. failure and that the brines are compatible with the reservoir. We had no significant adverse affects -- or I should say (indiscernible) adverse affects expected from fines. The reason we don't expect it is that if you look in the lab we have numerous core volumes before we see damages. In the field you expect to pump it at -- we'll be lucky if we got one core volume of water through the reservoir. The only places in the reservoir that we're going to see numerous core volumes pumped is either new wellbore injectors or new wellbore producers. Well, at the injectors we have the ability to exceed (indiscernible) pressure so that's not an issue. In the reservoir itself actually diversion is beneficial because it R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 55 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 I • helps -- it's a self diverting agent that will help improve your flood. At the producers we have tremendous flow area. We have opened whole sections between 7,500 and 9,000 feet. We don't expect to have any appreciable problem there. Hopefully with better quality rock we'll be able to flow some of these fines out so we don't have them plugging us. And in addition if we do have problems we have the ability to stimulate the wells. With regard to injection fluid rate analysis, I'm on slide 12, with our initial nine well development we expect an average injection rate of about 5,000 barrels of water a day. Our maximum injection rate is going to be about 12,000 barrels of water per day. If we go to our 18 development upside scenario case, there we expect the average injection to be about 7,000 barrels of water per day and our maximum rate to be about 17,000 barrels of water per day. Aquifer exemption reference on slide 13. Actually this is a incorrect titled slide. What this slide actually refers to is discharge pressures. We expect the Alpine central facility discharge pressure to be about 2,500 pounds. By the time it reaches the Qannik the surface injection pressure is about 2,400 pounds which translates into a subsurface injection pressure of about 4,100 pounds. Now we're at slide 14 talking about the aquifer exemption reference. As previously mentioned there are no underground R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 56 • • 1 2 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 sources of drinking water that exist below the permafrost in the Colville River Unit area. And that is a determination that was published in area injection order 18B in October of '04, conclusion number 3. And with that I'll turn it over to Doug Knock who will talk about geoscience. COMMISSIONER FOERSTER: Before you do that I have one question, Mr. Frazer. You mentioned on slide five that there are 125 penetrations within a quarter of a mile. Is the future testimony going to discuss the mechanical integrity of the request? MR. FRAZER: Yes. COMMISSIONER FOERSTER: Okay. Great. CHAIRMAN SEAMOUNT: Commissioner Norman? MR. KNOCK: I'm not sure that was quite correct, 125 within a quarter of a mile. I think it may be 20. COMMISSIONER FOERSTER: Well, we can look back at slide five, but that's what was said. MR. NOEL: There's 20 wells within a quarter mile of the three proposed injection..... MR. KNOCK: Yeah, there's 125 in both pads, but they're about two, three miles apart, the two pads. So..... MR. FRAZER: The 125, I made the mistake and I got that count from looking at everything that when the -- that fell within the pool area..... R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 57 ~ • 11 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. KNOCK: The big area. MR. FRAZER: .....which is the larger area on that map with all those red dot penetrations. COMMISSIONER FOERSTER: But within the area that we need to be concerned with, what's..... MR. FRAZER: Within the area that we need..... COMMISSIONER FOERSTER: That we need to be concerned with for this area injection order? MR. KNOCK: We have a display coming up that shows that. We're going to talk..... COMMISSIONER FOERSTER: Was that a statement or a question? MR. KNOCK: It -- we do (indiscernible) section, we have a map, it's under -- well, that one will work to. MR. FRAZER: The 125 that I was referring to is everything that fell within this out -- larger boundaries. COMMISSIONER FOERSTER: Okay. So within the quarter mile of the Qannik participating area and the area injection order area, it's a smaller..... MR. FRAZER: The area for the injection order is this blue outline. COMMISSIONER FOERSTER: Okay. So the 125 is a valid number? MR. FRAZER: If it -- if we're referring to within the blue outline it's a valid number to the best of my knowledge. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 58 • ~ 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 COMMISSIONER FOERSTER: If you want your area injection order to be for the blue outline then that's a valid number. MR. FRAZER: Thank you. MR. KNOCK: This slide shows the lithologies above and below the Qannik formation. The Qannik -- this is slide number -- looking at the bottom, let me see what it would have been, it's slide number 16, I believe. The Qannik is at 4,000 foot depth. This lithology is taken from the Burgeon (ph) 1 mud log. And looking at the log data so that the Qannik is here where we have a sandy interval approximately, you know, 40 feet of potential sand. Going to the upper part of that being prospective. Above that we have 1,500 feet of largely mudstone interval with some thin sand interbeds and what we're calling the CB formation. And then we get up to the 2,400 foot TVD level and that's where we have a sand package that's oh, .100, 200 feet thick. Not an impressive sand, but a sand based on mud log analysis from cuttings. And that we call the C-30 interval. And that is our annular disposal interval below 2,350, 2,400 foot TVD. We've been disposing annularly in that interval in -- throughout the Alpine CDl, CD2, CD3 and CD4 drill sites. Again that's about 1,500 feet above the 4,000 foot depth Qannik. Below Qannik, a couple hundred feet below it, there is a sand, not real well developed over here in this part of CD1, but a little better developed underneath the CD2 pad and we call that the lower K-2 sand for lack of a better R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 59 • • 1 2 3 4 5 6' 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 i 24 25 name. And that sand is water bearing. And it's aerially (ph) restricted and most impressive under CD2 which I'll show on the next slide. Below that we go for really 2,000 feet down towards some sands in the basal torok above HRZ. So there's just a lot of mudstone and siltstone below Qannik other than that more isolated sand at about 4,200 feet. And that sand is shown a little better on more of a blowup here. This goes across the CD2 pad, this cross section goes from southwest to northeast across CD2 and on it you can see the C- 30 disposal interval is this sand here. Here's where we set service casing at in all these wells, you can see the gamma ray go hot or the resistivity (ph) go off scale where we've set casing at. So we successfully are disposing of cuttings into that interval. Qannik is down here at 4,000 feet. Here's the sequence -- the (indiscernible) upper sequence that makes up Qannik. Down here is the sand at about 4,200 feet that we find in the CD2 area and it is wet by all indications on the resistivity log. So those are really the other sands that are in the vicinity of the Qannik interval. Other than that you -- like I said you've got to go way deep to run into more sands in the column down to 6,00 feet or so. And you can see that the other point of this slide is that the stratigraphy is very continuous in the upper part of the cretaceous here from surface down to below 4,000 feet we have very continuous stratigraphy. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 60 • • 1 2 3 4 5 6 711 8 9 10 11 12 13 14 I 15 16 17 18 19 20 21 22 23 24 25 I CHAIRMAN SEAMOUNT: That cretaceous section sure looks like Rocky Mountain cretaceous. MR. KNOCK: Yeah, and we -- we're a -- we don't have the tertiary (ph) they have over in Prudhoe, some of the nice sands over here, that's been scrubbed off. We've got mostly cretaceous from surface down. So the C-30 interval here in summary, there's 1,500 feet of interval above the Qannik, we call that the CD. The C-30 thickness is 100 to 200 feet thick, it's not an impressive sand, but it's well enough to dispose of our cuttings into. There's some log model analysis saying it's 28 percent porosity, 4 millidarcies perm from an RFT mobility, but this lower K-2 and is 200 feet below. It can be oh, up to 50 feet thick or so, it is wet, it is aerially (ph) restricted and it is completely separate from the Qannik formation 200 feet above it. And that's all I'm going to really say about the surfisual (ph) geology above and below Qannik. CHAIRMAN SEAMOUNT: Any questions, Commissioner Foerster? COMMISSIONER FOERSTER: None. CHAIRMAN SEAMOUNT: Commissioner Norman? Thank you, Mr. Knock. MR. NOEL: And I have two slides on the wellbore integrity. As you've already seen in the pool rules hearing, here's a schematic of the proposed injector completion again. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 61 • • 1 2 3 4 5 6 7 8 9 10 I 111, 12 13 14 15 16 17 18 19 20 21 22 23 24 25 And as previously discussed, this is drilled, cased and cemented per all the existing regulations and would have the cement quality log. And the tubing factor completions are all pressured tested and show a mechanical integrity prior to injection. There is one regulation, 412 (b) that requires a packer to be placed within 200 feet of your injection zone. Given the high departure and high angle of these wells, we were asking for a waiver just like we did on Alpine and the Alpine satellites to allow us to move that packer up for more efficient wireline access. And in this case the packer's still below -- 300 feet below the cement. And that only applies to one of the furthest north wells at this point. And so that's the plan for the two remaining injectors of the nine well initial development plan. The CD2-404 which will be the third injector was drilled, cased and completed just like the two future planned ones. And then our three injectors in the nine well program, there are 20 wells drilled to the Alpine sand. They're within a quarter mile of those three horizontal injectors. The one, NEVE number 1, was plugged and abandoned, the other 19 are Alpine wells that are currently operational, either producers or injectors. And they all have current integrity, there are no mechanical issues with them. COMMISSIONER FOERSTER: These 20 plus the ones that you're R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 62 • • 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 talking about on the page before, the slide before, cover the whole 125. So all 125 wells within the area of interest you can assure have mechanical integrity? MR. NOEL: Of the 125 I'm not aware of any on CD1 or the other wells on CD2 that have mechanical problems. And all of the exploration wells have been P&A'd. COMMISSIONER FOERSTER: Okay. There's a difference between not being aware of a problem and being aware that there's no problem. MR. NOEL: Okay. COMMISSIONER FOERSTER: Are you -- can you -- do you understand my question? MR. NOEL: Right. COMMISSIONER FOERSTER: My mother's not aware of any problems with any of these wells either, but that doesn't make me feel better about it. MR. NOEL: I'd have to ask our production engineers there for -- on CD1. We only looked at the wells that were within a quarter mile of the proposed injectors we're drilling..... COMMISSIONER FOERSTER: Well..... MR. NOEL: .....and verify those records. COMMISSIONER FOERSTER: Well, that will be information that we'll be looking forward to getting from you. MR. NOEL: Okay. We can -- we'll research that. COMMISSIONER FOERSTER: Thank you. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 63 • • 1 2 3~i 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. NOEL: Those were the two slides I had and Jack Walker's going to talk about the remainder of the injection plans. CHAIRMAN SEAMOUNT: Commissioner Norman? Thank you, Mr. I Noel. (Off record comments) CHAIRMAN SEAMOUNT: Are you giving sworn testimony? MR. WALKER: Yes, sir. CHAIRMAN SEAMOUNT: Please raise your right hand. (Oath administered) MR. WALKER: Yes, sir. CHAIRMAN SEAMOUNT: Okay. Please state your name, who you represent, whether you want to be an expert witness in what discipline and what your qualifications are? MR. WALKER: Okay. My name is Jack Walker and I would like to be qualified as an expert witness. I am currently employed by ConocoPhillips as a staff production engineer and I have been employed by ConocoPhillips and predecessor companies in Alaska since 1980 with supervisory and engineering assignments at the Prudhoe Bay Field, the Kuparuk River Field, and most recently the Colville River Field with the focus on the -- what we call the western North Slope satellites. I have a bachelor of science in mechanical engineering from the University of Tulsa in 1979 and also hold a master of science in petroleum engineering from the University of Alaska R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 64 • • 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 I Fairbanks that was earned in 2005. I think that answers your questions. CHAIRMAN SEAMOUNT: Any questions? COMMISSIONER FOERSTER: Well, I feel obligated to have some problems with Mr. Walker because of this kind of tradition that we have. But since he has a mechanical engineering degree from the other UT I guess I'll let him go. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Just curious, I have no questions regarding your qualifications. There was a Jack Walker very active in the Alaska oil industry some years ago, are you in any way related to him? MR. WALKER: Well, I've been active in the oil industry for quite a while, but I'm not sure I'm the right..... COMMISSIONER NORMAN: I mean -- let's say pre 1980, pre -- in the '70s? MR. WALKER: No, before 1980 I was not in Alaska. So..... CHAIRMAN SEAMOUNT: Okay. Well, Mr. Walker, you are considered an expert witness. MR. WALKER: Thank you. TESTIMONY BY JACK WALKER MR. WALKER: Okay. I'm going to cover two topics that relate to injection confinement and the first one will be fracture and modeling and then the second one would be open annuli in some of the existing Alpine wells that we've been R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 65 • • 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 referencing earlier. Fracture modeling of the Qannik injection wells was based on simulations using the Nolte Smith international software called Stem Plan (ph) and I use version 5.51. The fracture pressure from the CD2-404 injection test conducted in 2007 was used to calibrate the model also using -- or actually calibrate the Alpine 3 dipole sonic log, in situ stress and other mechanical properties from the Dipole sonic log at Alpine 3 were used for creating a fracture model. Shown on this slide are -- this is slide number 23, are -- on the left-hand side is the in situ stress that was used in the model, but was based on the Alpine 3 dipole sonic log. And the stress is shown on the horizontal axis and the depth is shown on the vertical axis. And that's the most sensitive element in the fracture containment at the Qannik injector well or in the injector well for that matter. Stem Plan includes a implicit finite difference solution for the fracture geometry and in this particular case for Qannik injection modeling was based on a vertical well injecting at 4,320 barrels per day and this would simulate a much greater stress than the expected stress in a horizontal well. Expected stress on the confining layers that is. After modeling of 2 million barrels of injection, the model revealed the graph on the right side as a summary of the injector confinement. Its width profile and vertical profile R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 66 • • 1 2 3 4 5', ~I 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 with a width of approximately 0.2 inches and the stress profile and the model indicate that the confine -- the fracture induced by water injection would be confined to the Qannik interval and invested in the siltstone overlying the Qannik and then the shaley intervals underlying the Qannik. With that I'd like to move on to the -- some open annuli if there are no questions. And I'll define open annuli in a moment, but when we approached this project like any project that ConocoPhillips operates, our guiding principles were to have safe and environmentally prudent operations and to maximize resource recovery. Our strategy with regard to Qannik in particular was to implement enhanced recovery operations, waterflood only with no plans to inject gas into the Qannik interval. That we..... COMMISSIONER FOERSTER: Why is that? MR. WALKER: The gas has a lower viscosity and can tend to migrate more freely in other strata or in the near wellbore region. And so we believe that it's a more prudent course to inject only water. Coupled with that is our plan to refine some well monitoring on the existing Alpine wells and if we see any communication with the Qannik injectors and the Alpine wells with open annuli or uncemented annuli, we'll remediate if necessary. This is a -- slide number 25 showing a schematic of the -- R& R C O U R T R E P O R T E R S 811 G STREET (907>277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 67 • • 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 what we call the open annuli. Before recognizing Qannik as -- interval as a significant hydrocarbon zone, several wells were drilled and completed in the Alpine Oil Pool underlying the proposed Qannik Oil Pool. And those wells were constructed with nine and five-eighths in surface casing, cemented to surface with a casing shoe (ph) at about 2,400 feet TVD. And the production casing, seven inch production casing, cemented into the top of the Alpine interval and with the designed cement jobs at more than 500 feet cement top -- top of the cement more than 500 feet above the top of the Alpine interval. Between the surface casing shoe and the design top of cement for the Alpine wells there's an open annuli. In other words the Qannik interval is not cemented in the existing Alpine completions. We don't -- do not expect that cross flow has occurred or is occurring from the Qannik either to the lower K-2 sand that Doug Knock referenced earlier nor the C-30 disposal interval that Mr. Knock also referenced earlier. We have -- the reason we believe there's no cross flow is that the annuli began as a freshwater based mud earlier when the well was constructed and then we believe that the shales have collapsed around that casing and that several hundred -- or a few thousand feet of shale between the Qannik interval and the other zones. Further we conducted some annuli monitoring during the 2007 injection test of well CD2-404, Qannik injection test, and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 68 • • 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 I we saw no evidence of cross flow during that injection test and I'll discuss that in more detail. But nevertheless we have some monitoring planned over the long term of the Alpine wells with open or uncemented annuli near the proposed Qannik injectors. This next slide is slide 26, it's a graph that shows -- is an example of monitoring that will be done in the future and was actually done during the CD2-404 injection test in 2007. And plotted on this slide are several curves and I'll try to describe those. On the left-hand vertical axis pressure is plotted and the right-hand vertical axis rate is plotted for the CD2-404 injection tests. And the horizontal axis is time. So the blue curve shows the CD2-404 injection rate plotted on the vertical -- right-hand vertical scale, injection rate versus time for the CD2-404. The red curve shows the CD2-404 wellhead injection pressure plotted on the left-hand vertical axis. And while we were conducting the CD2-404 injection test we were monitoring the -- what we call the outer annuli or that nine and five-eighths by seven inch annuli in the off -- nearest offset Alpine well, CD2-11 and CD2-23. And those curves are shown in the purple color the CD2-11 outer annulus and in the pinkish color in the CD2-23 outer annulus. And there's no relationship between the outer annulus pressures in CD2-11 nor CD2-23 and the injection pressure, injection rate of CD2-404. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 69 • • 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 CHAIRMAN SEAMOUNT: How far apart are those wells? MR. WALKER: Mr. Chairman, the wells are shown on the -- the Qannik penetrations of the CD2-11 and the CD2-23 well are shown on this snap, this is CD2-23 penetration and CD2-11 Qannik penetration. This would be the CD2-404 injection well penetration in the Qannik interval. So there's 700 feet, CD2- 11 and CD2-23 are both 700 feet from the -- what we call the production hole and CD2-404, the penetration of the CD2-404 in the Qannik interval. COMMISSIONER FOERSTER: Were they selected because they were the closest? MR. WALKER: Yes. COMMISSIONER FOERSTER: Okay. MR. WALKER: Yes. They were selected to monitor during that test because they were the nearest wells to CD2-404. If I may move on to the open annuli monitoring plan. We plan to install pressure transmitters on the outer annuli of the Alpine wells within a quarter mile of the Qannik injectors and that is the same list that Mr. Noel showed you earlier that he had testified had no mechanical integrity or problems that happen with mechanical integrity. COMMISSIONER FOERSTER: Okay. If in the review of the additional however many wells, you discover that there are any with mechanical integrity concerns would you be willing to put monitoring on those wells as well? would it be acceptable to R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 70 • ~ 1 2 3 41 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 you to have that be part of the area injection order that any wells that are discovered that have mechanical integrity issues to also be part of the monitoring program? MR. WALKER: I believe it would be acceptable to us depending on the nature of the mechanical integrity problem. I'm not sure if -- if we have catalysts. We have rule -- you know, pool rules or (indiscernible) inspection order for the Alpine Oil Pool addresses the (indiscernible) casing pressures and we follow those rules very carefully. And so I don't believe we will have -- find a mechanical problem. So depending on the nature of the problem I think it would be acceptable to us that -- it's hard to say without defining what the problem is. Anyway the -- these pressure transmitters would be connected to automated monitoring system we call it (indiscernible) and we have (indiscernible) capabilities in that system and we do a quarterly review of those outer annuli pressures to investigate the trends and look for communication. And just to summarize the open annuli presentation is we do not expect cross flow will occur in the Qannik interval with the other zones open in the existing Alpine wells. We plan to enhance the outer annulus monitoring of those wells that are within a quarter of a mile of the planned Qannik injectors. And then if we do observe any communication we would remediate as necessary. And the first step would be reduce Qannik R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 71 • • 1 2 3 4 5 6 7, 8~, 91I 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 injection and then there are some concepts that we've discussed for creating barriers in the existing Alpine wells if we see communication. And that concludes my prepared testimony. CHAIRMAN SEAMOUNT: Commissioner Foerster, any questions? COMMISSIONER FOERSTER: I rudely interrupted Mr. Walker will all my questions. Thank you. CHAIRMAN SEAMOUNT: Okay. We'll -- you'll be chastised later. COMMISSIONER FOERSTER: Oh, good. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: Just one question. In simple terms for the public record and for my understanding, what could go wrong in this operation if you were asked to play devil's advocate, what could go wrong that would allow cross flow and migration of fluid to a place where it's not intended? Is this fail-safe or what -- and the word expected is used there understandably. What could go wrong here that we'd get these fluids into a zone where they're not intended? MR. WALKER: The question about the -- what could go wrong from a public safety perspective I think is fail-safe as you put it. There's really no -- with the surface casing cemented to surface I don't think there's any chance of injection fluids reaching the surface. So I would say it's fail-safe in that regard. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 72 • • 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 CHAIRMAN SEAMOUNT: Okay. I don't have any questions, Mr. Walker, thank you very much. Now I'm wondering do we need to take another recess? COMMISSIONER FOERSTER: I'm looking at that (indiscernible - simultaneous speech)..... CHAIRMAN SEAMOUNT: Yeah, I want a vote from down there too. Do you guys have any questions? You're all satisfied and happy? Well, I am too then. COMMISSIONER NORMAN: I have one last..... CHAIRMAN SEAMOUNT: Okay. COMMISSIONER NORMAN: .....technical question. There is a requirement that the surface owner be notified and there is a proper affidavit in the file showing that notification was sent to the surface owner. But I wasn't able to see from that whether that was sent certified mail. And so my question is does the -- do you have evidence that that notification was received and the surface owner is aware of these proceedings? MS. SORIA: This is Dora Soria responding to your question and yes, I do and we will provide it to the Commission. COMMISSIONER NORMAN: It won't, I -- we will accept your..... MS. SORIA: Thank you. COMMISSIONER NORMAN: .....your representation. Thank you. CHAIRMAN SEAMOUNT: Okay. Any other questions, comments? R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 73 • • 1 2 31 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COMMISSIONER FOERSTER: Once again I just want to thank you for a technically superior and clearly conveyed presentation. CHAIRMAN SEAMOUNT: Commissioner Norman? COMMISSIONER NORMAN: And I just want to join in that very briefly, but we see a lot of presentations and it was very good to receive a thorough presentation like this. It's what we would expect of an operator as experienced in here, but it is appreciated, it makes our job easier and I think it helps set a standard for what is expected in presentations before the Commission so we thank you. COMMISSIONER FOERSTER: And don't forget to get your confidential material before you leave. CHAIRMAN SEAMOUNT: Yeah, I'd like to -- well, I agree with what the other two Commissioners have said about your professional testimony today. I think I'll make Mr. Steve Davies the team leader on getting the confidential stuff bacJ{ to you guys before you leave. And you guys probably have some too in your -- in your area. Is there anyone else that wished to testify with the public? Other interested parties? Hearing none, I'm wondering do -- do you have something? COMMISSIONER FOERSTER: I was going to move to adjourn. CHAIRMAN SEAMOUNT: No, it's -- you're too early. I -- and I'm doing this for you. I think that you're waiting for an R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 74 ~ • 1 2 3 4 5 6 7 8 91 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 answer so we need to hold the record open until you get that answer..... COMMISSIONER FOERSTER: Yes, we do. CHAIRMAN SEAMOUNT: .....and what is COMMISSIONER FOERSTER: The question mechanical integrity in all 125 wells in a mile of the area injection order area. wells lack adequate mechanical integrity address that. the question? is what is the -- within a quarter of And if any of the chat is the plan to CHAIRMAN SEAMOUNT: Okay. And then my question to the lawyer Commission is it appropriate to adjourn the hearing or do we not adjourn it until we get the question answered? COMMISSIONER NORMAN: We can adjourn the hearing, but leave the record open for a fixed period of time to get the answer to that one last question. CHAIRMAN SEAMOUNT: So be it. COMMISSIONER FOERSTER: So how long do you guys think it'll take you to get that? MR. NOEL: A few days. CHAIRMAN SEAMOUNT: Let's give them 10 days. COMMISSIONER FOERSTER: Ten days. CHAIRMAN SEAMOUNT: Okay. Ten days. Again is there anyone else wishing to testify, ask questions or make a comment? Okay. It's your turn. COMMISSIONER FOERSTER: I move we adjourn. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 75 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 • • CHAIRMAN SEAMOUNT: So be it, we are adjourned. (Adjourned - 11:24 a.m.) (END OF PROCEEDINGS) R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 76 ~ • 1 2 3 4 5' 6' 7' 8'I 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 C E R T I F I C A T E UNITED STATES OF AMERICA ) ss. STATE OF ALASKA ) I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R Court Reporters, Inc., do hereby certify: THAT the annexed and foregoing Public Hearing held on May 15th, 2008 was taken by William P. Rice, commencing at the hour of 9:00 o'clock a.m, at the Alaska Oil and Gas Conservation Commission of Alaska in Anchorage, Alaska; THAT this Public Hearing, as heretofore annexed, is a true and correct transcription of the proceedings taken by William P. Rice and transcribed by Lynn Hall. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 20th day of May 2008. Notary Public in and for Alaska My Commission Expires:l0/10/10 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 • ~ STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION QANNIK HEARING May 15, 2008 AT 9:00 AM NAME AFFILIATION PHONE # TESTIFY (Yes or No) ~.. ~~ /~~z~~" ,~~~as}et~cv ~~:aa«~M ~~~ G3G 3~~( n17 ~+A~~J~~ FvtLrnc~e.. CP~.:~ :~(~~ 13~r( ~ • • • Qannik Area Injection Order Hearing Qannik Area Injection Order Hearing 5/15108 May 15, 2008 1 • ~anocoPhilli s p Qannik Area Injection Order Hearing Outline of Oral Testimony* • • Overview & Sundry Information • Plat of Penetrations within '/4 Mile • Affidavit of Notification • Injection Fluid Analysis and Rates • Injection Pressures • Aquifer Exemption Reference Geoscience • Formation Description • injection Well Type Log. Wellbore In#egrity • Existing & Planned Injection Wells • Adjacen# Wells Injection Confinement • Fracture Modeling • Alpine Open Annuli (20 AAC 25.402)(c)(1) (20 AAC 25.402)(c)(3) (20 AAC 25.402)(c)(9) (20 AAC 25.402)(c)(10) (20 AAC 25.402)(c)(13) (20 AAC 25.402)(c)(6) (Z0 AAC 25.402)(c):(7j (20 AAC 25.402)(c)(15) (20 AAC 25.402)(c)(11) *A Detailed Written Application Has Also Been Submitted May 15, 2008 2 Lamont Frazer Doug Knock Brian Noel Jack Walker ConocoPhilli s Qannik Area Injection Order Hearing Overview Application Requirements 20 AAC 25.402(c) 15 Requirements • 6 COVered During Pool Hearings • 9 Covered with Additional Testimony May 15, 2008 3 • • ConocoPhilli s p • • Qannik Area Injection Order Hearing tJverview Pool Rule Hearing Reference • ,,. .. ~) ~_ • Operators & Surface Owners within '/4 Mile • Description of Proposed Operation • Description and Depth of Affected Pool • Casing Description & Testing Methods for Injectors • Quality of Formation water • Incremental Increase in .Ultimate Recovery 20 AAC 25.402 (c)(2) 20 AAC 25.402 (c)(4) 20 AAC 25.402 (c)(5) 20 AAC 25.402 (c)(8) 20 AAC 25.402 (c)(12) 20 AAC 25.402 (c)(14) ~~ May 15, 2008. 4 ConocoPhilli s • • Qannik Area Injection Order Hearing Plat of Existing Penetrations within One-Quarter Mile • --_ i :: ,. _- Proposed Qannik Pool Rules & Area Injection Order 7 ~ ~ .+ ~~ • .~ d • a na,n _, Proposed Qannik ,~ : Partici- atin Brea ~ 4 nu_usw w~ .m w_a ~ • • • not k ~~ ~ ~ • • 4 .ttnews uxwro~ .u~em.. ~ ,~„~, May 15, 2008 nnsaru Legend Existing Well Initial Phase Producer Initial Phase Injector Planned Future Producer Planned Future Injector - Ex~stno~^!- Pe~e!~auor O MILES 20 AAC 25.402 (c)(1) ConocoPhillips • • Qannik Area Injection Order Hearing Affidavit of Notification • • 20 AAC 25.402 (c)(3) Operators and Surrace Owners within One-Quarter Mile of Injection Operations Operator: ConocoPhillips Alaska, Inc. Attention: Matt Elmer AT0-1750 P.O. Box 100360 Anchorage, Alaska 99:510-0360 Surface Owners: State Of:Alaska Department of Natural Resources Mike Kotowsk 550 W 7th Ave .Suite 1100 Anchorage AK 99501-3560 Kuukpik Corporation Mr. Isaac Nukapigak P.O. Box 187 Nuigsut, Alaska 99789-0187 May 15, 2008 6 COt1oCOP~'11~~1 S ~" • Qannik Area Injection Order Hearing ~ ..,. ~ .. Injection Fluid Analysis & Rates ~~_/ 20 AAC 25.402 (c)(9} Synthetic Brine Cation Concentrations Component Na K Ca Mg, Ba Sr TDS Calculated [CI] May 15, 2008 7 Drilling Brine ~ppm ) 35,031 31,44$ 0 0 0 0 66,4.78 149,000 82,500. Summer Beaufort Seawater 7508 281 297 929 _0 0 9015 24,600 13,600 .Colville River Unit Produced W ater 8461 159 127 97 3 9 8856 23,000 13,000 ~Ot10C0Phi~~t S C3 • Qannik Area Injection Order Hearing ; ~~~ ,, '~~ Injection Fluid Analysis & Rates _~ Drflling Brine Injection ~.a~Q ~.SC~o .~ 1 .5~ a~ '~ 1.~~~ C~.S~~ 0 a~t~ -~- Q.S.cclmin um'~olume, ~ s May 15, 2008 g ~®noCO~~~'~pJ i ~ Qannik Area Injection Order Hearing ~:-~~~, i ~~ ~ == .. ,~_ Injection Fluid Analysis & Rates ~` Beaufort Sea Water Injection 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 o.o + 0 May 15, 2008 -~- 1 cclmin 0.5 cclmin ~ 1 cclmin 500 loo0 1500 Cum Volume, cc 9 2000 2500 ConocoPhillips s • • Qannik Area Injection Order Hearing Injection Fluid Analysis & Rates _~ ;~ ~ .. ;,. --' Beaufort Sea Water Injection 0.12 0.10 0.08 06 0 . 0 04 . 0 02 . 0 00 . 0 600 1000 1500 2000 2500 Cum Volume, cc May 15, 2008 1 + Fonnrard @250psi Forward @500psi -f- Forward a~71000 si p + Reverse @ZOOpsi -~-Reverse @500psi ~ Reverse @1000psi ~ --~-Shut & Rev a~71000psi ~ Forward (c~1000psi ConocoPhillips :] • • • Qannik Area Injection Order Hearing ^~ ,. ~ Injection Fluid Analysis & Rates ~~~ • Injection Waters Compatible with Qannik • No Catastrophic Permeability Loss from Seawater Lab Study • No Catastrophic. Permeability Loss from CD2-404 in Seawater Inj Test • Produced Colville River Unit Water - Similar Composition to Summer Beaufort Seawater - Nearly Ldentical Salinity to Summer Beaufort Seawater • No Appreciable Adverse Impacts Expected from Fines • Numerous Pore Volumes Needed to Observe Fines Migration in Lab • Fines Mitigation Strategy - Injectors-Injection Above Parting Pressure - Producers-Surface Area, Fines Production & Potential Well Stimulations - Potential Sweep Benefits from Diversion May 15, 2008 1 1 Cono~©P~illi s p Qannik Area Injection Order Hearing Injection Fluid Analysis & Rates ^'~ ~1 :: ,, ~_/ • 9 Well Development Expected Injection Rates • Average of 5 M BWPD • Maximum of 12 MBWPD • 18 Well Development Expected Injection Rates • Average of 7 MBWPD • Maximum of 17 MBWPD conocaP'~illi s May 15, 2008 12 ~ s Qannik Area Injection Order Hearing Aquifer Exemption Reference • 20 AAC 25.402 (c)(10) • Alpine Central Facility Discharge Pressure2500 psi • Qannik Surface Injection Pressure2400 psi:... • Qannik Subsurface Injection Pressure 4100 psi May 15, 2008 13 ConocoPhilli s p Qannik Area Injection Order Hearing Aquifer Exemption Reference • • 20 AAC 25.402 (c)(13) • No underground sources of drinking water exist beneath ~ the permafrost in the Colville River Unit area. • Area Injection Order 18B (October 7, 2004) conclusion #3. May 15, 2008 14 ~Ono~o~'11~'1 5 ~~ Qannik Area Injection Order Hearing ~ ,., i .,• 1 `~_ ~~ Geoscience Doug Knock May 15, 2008 I S ConocoP'hilli s p Qannik Area Injection Order Hearing Lithology Above & Below Qannik May 15, 2008 `'~ : ssTVO _ Lifhdogy zao _ ~- '- ~_ • • • • • • • Y ~ •....•••. ••••.. •. •• O {{{ • •• •• •• Y 100 - { r ~ ~ ~ ~ ~ ~ ~ ~ •SAND AND GRAVEL'••• Z ~ •~ ~••~ ~••~ ~••~ j 600 _ f j •• •..• •• •• • a eoo ~. l ~ ~~ -_ • . ••SAND••. •• ~ txoo ^ - , , uoo • • • BASE LL -SILTSTONE, ----------- PERM ~ tsao _ .COAL INTERBEDS . m ~ W ~ - - - BARRIER +eoo i, ------- - (800 ft) = xooo ------ U - - - - - - '~ Mudstone, Volcanic Ash ca o ----------- 2d0a _~' - - _ • Annular Disposal C-30 _ _ _ _ - _ _ _ __-____- - - Interval x600 zeoo -- _- --. J- _-- - - - - - _ - -Mudstone with - - - sandstoneinterbeds - W ,y, ]oa° -.-____- W -_ _ _ _ _ = UPPER BARRIER ]x°° ~ ~' --~- _ _ _ _ _ _ _ (1,500 ft) ]600 K 3 ]eoo I - - - - --------- Y dooo K -y ~/"~~ - - - - - - - -- N 3 1300 - - - - - - -.---- _-.----- - Lowet ~ z - -_ _ _ _ _ - Sand uoo --..---- __ __-_ LOW ER BARRIER 16aa - Mudstone - ---------- (2 000+ ft) o ~~ -_=__= _ ~ _ -------- --- - +~ ... -,. ,~ (20 AAC 25.402)(c)(6) (20 AAC 25.402)(c)(7) IAFROST SURFACE CASING ~NIIK K-2 ConocoPhillips • • Qannik Area Injection Order Hearing SW-NE CD2 Cross Section • . ~~ . ~~ l~ :.. ~ .. CD2-56 CD2-05 CD2-30 CD2-40PB1 CD2-42PB1 CD2-49 CD2-50PB1 CD2-17 CD2-28PB1 CD2-29 dace asing lar sal • • nik 'r K-2 nd ~$ May i u, cuuo i i Qannik Area Injection Order Hearing ~ .. 1 o en Annuli--Geo1o is Summar dal p J Y C-30 Interval • ~ 1500' Above Qa n n i k • Interval Thickness 175' • Limited Log Porosity Measurements & No Core - High Vsh Content (from GR, N/D) PhiD Avg. 28% Low Perm (3.8 and from RFT Mobility in Alp-1-Cleanest C-30) Lower K-2 Sand • 200' BelowQannik Oil Bearing Zone • .Limited Areal Extent • Not Connected to Qannik • Sands are wet May 15, 2008 1 g ConocoP'hilli s p • ~ • • Qannik Area Injection Order Hearing ~~ .•~. 1 ., l ~~~ Wellbore Integrity Brian Noel May 15, 2008 19 Conoc©Philli s p • • Qannik Area Injection Order Hearing - ~- ~~ i~' In'ection Wellbore Inte rit `~., ~~ ;~~ J J Y ,_ _, Alpine CD2 -Qannik Injector Completion 20 /`1/`1V 25.402 (c)(15) 16" Insulated Condudor to 114' 4-1/2" DB Nipple at +/- 2000' TVD w/ A-1 injection valve (differential pressure controlled SSSV) 103/4" 45.5 ppf L-80 BTCM Surface Casing at+/-2400' TVD. cemented to surface 4-tY2" 12.6 ppf L-80 IBT Mod. tubing GLM wl dummy valve above Packer Production Slidk stinger w/fluted Packer H/LEG and shear sub XN nipple Liner top hanger w/ tieback receptable 6000 -9000' MD Horizontal 7-5/6" 29 ppf L-80 BTC Mod 4-V2" 12.6 ppf L~0 SLHT liner Produdion Casing @ +/-g5° w/ slots across sand antl blank across s'na~e • Drilled, cased and cemented per regulations, cement quality log • Tubing and packer completion, pressure tested • Accommodate efficient wireline operations -waive 20 ACC 25.412(b) - 200 feet maximum spacing between packer and top of injection zone • Ensure production casing cement top extends minimum 300 feet above packer placement May 15, 2008 2~ ConocoPhillips • Qannik Area Injection Order Hearing Adjacent Alpine Vl/ells • • • Twenty Alpine wells within 1 /4 mile of the three initial proposed Qannik injection wells are in good mechanical condition or have been P&A'd • These wells, their current service and completion date are listed below. • Well Service Completion Date • CD2-03 Producer 7/30/05 • CD2-09 Producer 9/12/04 • CD2-11 Injector 10/8/05 • CD2-12 Injector 5/19/03 • CD2-21 Producer 2/8/05 • CD2-23 Producer 7/24/02 • CD2-15 Injector 10/30/01 • CD2-24 Producer 6/28/01 • CD2-33B Producer 9/2/01 • CD2-42 Producer 6/1/01 • CD2-32 Injector 3/5/02 • CD2-49 Injector 2/4/02 • CD2-40 Injector 8/25/03 • CD2-30 Injector 10/30/03 • CD2-43 Producer 1/20/04 • CD2-55 Injector 10/1/03 • CD2-47 Producer 12/16/01 • CD2-05 Producer 8/22/04 • CD2-60 Injector 7/10/05 • NEVE #1 Exploration P&A - 4/22/96 May 15, 2008 21 ~OC1t)CO~'11~~1 S ~' • • • Qannik Area Injection Order Hearing ~~~ •. 1 ,.- ~,~ J/ • Injection Confinement Jack Walker 2 CanocoP~illi s May 15, 2008 2 • • Qannik Area Injection Order Hearing = :--~~ i :: .. M elfin ~, Fracture od g ~- -- 20 AAC 25.402 (c)(11) • CD2-404 Test for Fracture Extension Pressure • Alpine 3 Dipole sonic log for Mechanical Properties ~annik Injection Confinement 1' May 15, 2008 TVD ft 3900 4000 4100 4200 4300 23 Max Wi01h 0.10 in itlth Profile at Shut-In 0.'~;, b b.1„ Frac Width Profile ConocoPhillips • Stress (psi) i ~ Qannik Area Injection Order Hearing Open Annuli-Well Integrity Plan • ~~ ,.. ,,. _i • Guiding Principles . • Safe & Environmentally Prudent Operations • Maximize Resource Recovery • Strategy • Implement Enhanced Recovery Operations Waterflood - No Gas Injection/MWAG Plans • Refine Existing Alpine Well Monitoring • Remediate if necessary May 15, 2008 24 ~anocoPhilli s • ~ • ., Qannik Area Injection Order Hearing ~~~ i .. AI ine 0 en Annuli '~~~,"~' p p ~-_, Typical Alpine Well 16" Insulated Conductor to -114' 9-5/8" - 2400' TVD C-30 Annular Disposal Interval I - 1650 ft TVD ~ K-2 or "Qannik" I 200 ft TVD Top of Cement ' minimum 500 ft - 2600 ft TVD above Alpine • 9-5/8" x 7" (Outer) Annulus not ! cemented across Qannik in CD2 wells completed in Alpine Oil Pool before Nov 2005 • Cross flow not expected - Mud-filled annuli - Likely shale collapse around casing in open annuli ~ - No evidence of cross flow during 2007 Qannik injection test • Outer Annulus monitoring planned Top Alpine 7" 26 ppf Reservoir May 15, 2008 25 ConocoPhillips • Qannik Area Injection Order Hearing =~~~ ,+. ~~' , : `~ O en Annuli - No evidence of cross flow ~``~~,_~~,=~' p CD2-11 and CD2-23 OA Pressures During CD2-004 Injection 1400 1200 1000 ~' 800 d N ~ 600 a 400 200 0 e N e_ O R e R e R R R R e e e e O N ~ R R e e ~ ~ R e R e R e R R R e e e R e R e e e m _ ; e ~ ; ; ~ c c c c ~ e e _ O _ O _ _ _ O O O O _ _ O O _ O O _ O _ O O O N O N O Date --- CD2-404 Injection Pressure CD2-11 OA CD2-23 OA ~- CD2-404 Injection Rate May 15, 2008 26 5000 4500 4000 3500 3000 5 2500 d 2000 ~ 1500 1000 500 0 ConocoPhillips • • Qannik Area Injection Order Hearing -.-_ .. Open Annuli Well Locations '' ,, ~~,;' May 15, 2008 CD2-11 mz~ z-0zrn , -0y m _„ •~ ~ mz-m mz-~z ms-zarn mz-~ss~ mz-~amz-zany m z~~n~ • mz • mz CD2-23 z~~" mz • •mz_ ~. mz; ~~ mz•sn.i •mz~z m~ mz~ a iaoo moo soon ~ooo soon ®~ i "l-/ m z~rs~ ,mz-0~ra~ z ,„ mz-z9 ~~f~~' -sors~ mz~~u mz~s • mz~s mz_Q •mz-s~ •mz-n ConocoPhillips • • i • • Qannik Area Injection Order Hearing ,,.. Open Annuli-Monitoring Plan "~ ~_ • Install pressure transmitters on OA of Alpine Wells within 13.20' Of Qannik Injectors • ~ ~ •• ~ • Automated mOnrtonng rn Setcim with alarm capab~l~ty • Quarterly Review of OA Pressures to Investigate Treinds May 15, 2008 2 ConocoP'~illi s s ~ Qannik Area Injection Order Hearing Open Annuli-Summary ~- l .~ ,. l ~~_i • Downhole Cross-Flow not Expected • Plan to Implement Enhanced OA Monitoring • Remediate if necessary - Reduce Qannik injection - Inject Alpine Well OA barrier May 15, 2008 29 ConocoPhilli s ! • ~ Qannik Area Injection Order Hearing ; ~~ .. 1 ,, •` l ~_~ Backup • May 15, 2008. 3 ~onocoP~illi s • Qannik Area Injection Order Hearing ;,;~~ ~.. O en Annuli Lower K2 Sand '~ ~~~ ~, , p ~Orl'AT10N_1 5990000 5980006 5970000 K-2 Lower Sand Isopach ~ s ~w •w w uw~ 1:49277 May 15, 2008 1490000 1500000 1510000 5960000 ~l-L LOW@f Jaf1Q Depth below K-2 reservoir: 200ft TVD Area: 8500 Acres Avg Thick: 11 ft GRV: 93500 Acre-ft Phi. Avg: 25% Net Rock Vol: 23375 Acre-ft Phillips .WW.M KLr A19 STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A O_02814043 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF M ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM-.FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 Jod Colombie A ri18 2008 ° Anchorage, AK 99501 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News Apri19, 2008 PO Box 149001 Arichora e AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN g ~ ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classified ^Other (Specify) SEE ATTACHED SEND INVOICEIN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO Anchora e AK 99501 REF TYPE NUMBER AMOUNT 1 VEN z A1'.D 02910 FIN AMOUNT SY CC PGM ~ 08 02140100 z REQUISITIONE BY: \~ , . PAGE t OF 1 TOTAL OF 2 PAGES J ALL PAGE LC ACCT FY NMR oisr 73451 DIVISION APPROVAL: 02-902 (Rev. 3/94) V Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing State of Alaska Alaska Oil and Gas Conservation Commission Re: Request for Pool Rules and Area Injection Order for proposed Qannik Oil Pool, Colville River Unit, Arctic Slope, Alaska ConocoPhillips Alaska Inc. (CPAI), by letter and application dated and received on April 3, 2008, requests the Alaska Oil and Gas Conservation Commission (Commission) establish pool rules in accordance with 20 AAC 25.520 and issue an area injection order in accordance with 20 AAC 25.460 for the proposed Qannik Oil Pool. CPAI's application may be reviewed at the offices of the Commission, 333 West 7th Avenue, Suite 100, Anchorage, Alaska, or a copy may be obtained by phoning the Commission at (907) 793-1221. The Commission has tentatively scheduled a public hearing on this application for May I5, 2008 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on April 28, 2008. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221 after May 9, 2008. In addition, a person may submit a written protest or written comments regarding this application and proposal to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must be received no later than 4:30 pm on May 12, 2008, except that if the Commission decides to hold a public hearing, protests or comments must be received no later than the conclusion of the May 15, 2008, hearing. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact the Commission's Special Assistant Jody Colombie at 793-1221. Daniel T. Seamount, Jr. Chair Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, April 08, 2008 1:34 PM To: 'Ads, Legal' Subject: Public Notice Attachments: D00080408.pdf; Ad Order ADN form.doc Please publish tomorrow. Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 *Note new email address 4/8/2008 ~chorage Daily News ~ 4~1°-~°es Affidavit of Publication 1001 Northway Drive. Anchorage. AK 99308 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD # DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 461323 04/09/2005 02814043 STOF0330 $199.20 $199.20 $0.00 $0.00 $0.00 $0.00 $0.00 $199.20 STATE OF ALASKA THIRD JUDICIAL DISTRICT Angelina Benjamin, being first duly sworn on oath deposes and says that she is an advertising 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 the above dates 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. / r Signed ~~ ct Subscribed and sworn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRE.:=_ ..~ a ~.~ ~~.t~ ~ ~ ~~~ . , .,~ '~ _; ~ ~ 9r %'i Nonce of PublicHearing State of Alaska Alaska Oil and Gas Conservation Cotttmission Re: Request for Pool Rules and Area Injection Order for proposed Qannik OiI Pool, Colville River Unit, Arctic Slope, Alaska. CdnocoPhillips Alaska Inc. (CPAp, by letter and application dated and received on April 3, 2008, requests the Alaska Oil and Gas Conservation Commission (Commission) establish pool rules in accordance with 20 AC 25.520 and issue an area injection order in accordance with 20 AC 25.460 for .the proposed Qanriik OiIPOOI. CPAI's application may,tie reviewed at the offices of the-0ommission, ~ 333 Wesf7th Avenue, Suite t00, Anchorage, Alaska; or a'copy may be obtained by-phoning the Commissionat(907)793-1221.. The Comrr)ission has tentatively scheduled a' public hearing on this application for May,15, 2008,_ at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Ayenue, Suite 100, Anchorage, Alaska 99501 A`person may' request that the tentatively scheduled he9nng be held by filing a written request;with the Commissign. no laterthan 4:30 pm on ApriIJ28, 2008 >. If a request for a heanng is not Umely filed; =the Commission may consider the issuance'of an order without a hearing. To learn if the Commission will hold the public heanng, please cal1,793--1221 after -. 'May 9; 2008.. - _ - - - In addition, a person may submit a written_ protest or written comments're$arding this .application and proposal to the Alaska Oil and Gas Conservation Commissron af333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must,be received no later than 4:30 pm on May 12, 2008, except that if the. Commission decides to hold a public hearing protests or comments must be received no later than the conclusion of the May 15;,2008, hearing: If you are a person with a disability who may need special accommodations ih order to comment or to attend the public hearing, please contact the Commission's Special Assistant7ody Coiombie at - 793-1221. - Daniel T. Seamouht, Jr. Chair A0-02814043 Published; April 9, 2008 C: • ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF /~ O_O2$14043 /'1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE80TTOM-FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R Suite 100 333 West 7th Avenue . Anchorage. AK 9951 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News April 9, 2008 PO Box 149001 Anchora e AK 99514 g THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN Y ON THE DATES SHOWN NTIR ~ . ITS E ET SPECIAL INSTRUCTIONS: Account # STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of 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 HERE. 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 2007, and thereafter for consecutive days, the last publication appearing on the day of , 2007, 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 2007, Notary public for state of My commission expires • Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, April 08, 2008 1:41 PM Subject: Public Notice Qannik CO and AIO Attachments: Qannik Pool and AIO Public Notice.pdf BCC:'Arthur C Saltmarsh'; Birnbaum, Alan J (LAW); 'Catherine P Foerster'; 'Charles M Scheve'; 'Chasity R Smith'; 'Christine R Mahnken'; 'Cynthia B Mciver'; 'Daniel T Seamount JR'; 'Elaine M Johnson'; 'Howard D Okland'; 'James B Regg ; 'Jeffery B. Jones ; 'John H Crisp'; 'John K. Norman'; Latham, Tanya M (LAW); 'Louis R Grimaldi'; 'mail=linda_laasch@admin.state.ak.us'; 'Maria Pasqual'; 'Robert C Noble JR'; 'Robert J Fleckenstein'; Roby, David S (DOA); 'Stephen E Mcmains'; 'Stephen F Davies'; 'Thomas E Maunder'; 'Trade Paladijczuk (tracie~aladijczuk@admin.state.ak.us)'; Williamson, Mary J (DOA); Joseph Longo; Maurizio Grandi; Tom Gennings; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg M (DEC); 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah ; 'James Scherr ; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon ; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; keelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail-Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:Qannik Pool and AIO Public Notice.pdf; Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 "Note new email address 4/8/2008 ~ ~ Ma Jones ry David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 I ~ (((..YYY ry Barrow, AK 99723 ~J~ UI • Conoc Phillips Alaska, Inc. 700 G. ST. ANCHORAGE, ALASKA 99510-0360 Lamont Frazer North Slope Operations and Development, ATO 1754 Telephone 907- 263-4530 Facsimile 907- 265-1515 E-mail lamont.c.frazer@conocophillips.com April 03, 2008 Commissioner Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue, Suite 100 Anchorage, AK 99501 Re: Qannik Area Injection Order 20 AAC 25.402 Dear Commissioner Seamount: • RE~~IV~~ APR 0 3 200$ 14(SSka ~?i(& Gas Cons. Commission ~.,.,__. _ . Anchorage ConocoPhillips Alaska, Inc. (COP), in its capacity as operator of the Colville River Unit, submits this letter as an application for Alaska Oil and Gas Conservation Commission approval of an area injection order to conduct an enhanced recovery operation involving water injection, consistent with 20 AAC 25.402 (a). Approval of this application would permit these operations to be conducted in the Qannik Pool. (COP is also applying for approval for a participating area and pool rules in separate applications.) COP briefed Commission Staff on Qannik during a January 16, 2008 meeting and is prepared to provide additional technical information at the commission staff's convenience. Approval of this application would permit waterflood operations to be conducted in the Qannik Oil Pool. Supporting documentation is attached pursuant to 20 AAC 25.402 (c). Please contact me if you have any questions regarding this application. Sincerely, ~ , Lamont Frazer ~~L Qannik Coordinator • April 03, 2008 Commissioner Dan Seamount Re: Qannik Area Injection Order 20 AAC 25.402 Cc: Anadarko Petroleum Corporation Mr. Kim Bowen 3201 C Street, Suite 603 Anchorage, AK 99503 State of Alaska Department of Natural Resources Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 • • April 03, 2008 Commissioner Dan Seamount Re: Qannik Area Injection Order 20 AAC 25.402 Bcc: Matt Elmer ATO-1720 Dora Soria ATO-1468 Chris Wilson ATO-1770 • • • Application to the Alaska Oil and Gas Conservation Commission for the Qannik Area Injection Order Colville River Field ConocoPhillips Alaska, Inc Anadarko Petroleum Corporation April 3, 2008 • • Table of Contents Introduction 20 ACC 25.402 (c)(1) Plat of Wells Penetrating Injection Zone 20 ACC 25.402 (c)(2) Operators and Surface Owners within 1/4 Mile of Injection Operations 20 ACC 25.402 (c)(3) Affidavit of Lamont C. Frazer Regarding Notice to Surface Owners 20 ACC 25.402 (c)(4) Description of the Proposed Operation 20 ACC 25.402 (c)(5) Description and Depth of Pool to be Affected 20 ACC 25.402 (c)(6) Description of the Formation 20 ACC 25.402 (c)(7) Logs of the Injection Wells 20 ACC 25.402 (c)(8) Casing Description and Proposed Method for Testing 20 ACC 25.402 (c)(9) Injection Fluid Analysis and Injection Rates 20 ACC 25.402 (c)(10) Estimated Pressures 20 ACC 25.402 (c)(11) Fracture Information 20 ACC 25.402 {c)(12) Quality of Formation Water 20 ACC 25.402 (c)(13) Aquifer Exemption Reference 20 ACC 25.402 (c)(14) Incremental Hydrocarbon Recovery 20 ACC 25.402 (c)(15) Mechanical Condition of Wells Within'/. Mile of Proposed Area List of Figures Figure 1 Proposed Affected Area for Qannik Area Injection Order Figure 2 Well Location Map with Recovery Mechanisms Figure 3 Qannik Type Log Figure 4 Typical Well Log-CD2-404 GR/Resistivity Figure 5 Typical Qannik Injector Well Schematic Figure 6 Typical CD2 Alpine Wellbore Schematic Attachments Qannik Area Fracture Containment Modeling NEVE #1 P&A Schematic Qannik Field Formation Damage Study to Brine Injection 1 2 3 4 5 8 10 11 12 14 15 17 18 19 20 21 2 6 9 11 13 21 Pagei A lication to the AOGCC for the Qannik Area In'ection Order ~ Aril 3, 2008 PP J P Colville River Field Introduction This area injection order application seeks Alaska Oil and Gas Conservation Commission authorization for the proposed Qannik Development Project in the Colville River Unit (CRU). This project involves the development of the Qannik reservoir. An initial nine well development is planned from Drill Site CD2; however, potential expansion opportunities have been identified at both Drill Site CD2 and Drill Site CD4. This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). The proposed Qannik Development Project employs secondary recovery operations (using seawater and/or produced water) to maximize oil recovery from the proposed Qannik Oil Pool, which is located within the CRU on the North Slope of Alaska. The proposed Qannik Oil Pool comprises the Qannik reservoir in the Torok Formation of the Nanushuk Group. Concurrent with this application for an Area Injection Order, under separate cover ConocoPhillips Alaska, Inc., as operator of the CRU and on behalf of the working interest owners (WIOs), is seeking a Conservation Order by the Commission regarding the classification and rules to govern the development of the proposed Qannik Oil Pool. The WIOs plan to form a separate participating area within the CRU to facilitate Qannik development. Preliminary boundaries for the planned Participating Area are shown on Figure 1. ConocoPhillips Alaska, Inc., as operator and on behalf of the WIOs, is concurrently applying to the State of Alaska Department of Natural Resources and Arctic Slope Regional Corporation to form the Qannik Participating Area. Development drilling is planned to start during June 2008 with production start-up expected during July 2008. Page 1 ConocoPhillips Alaska, Inc. Application to the AOGC~or the Qannik Area Injection Order ~ April 3, 2008 Colville River Field 20 AAC 25.402 (c)(1) Plat of Wells Penetrating Injection Zone Figure 1 below shows all existing wells penetrating the injection zone in the proposed injection area. The map also shows the areal extent of the injection zone relative to existing participating areas within the CRU and the proposed Qannik Participating Area. The map shows the initial nine horizontal well development and planned future locations (with their expected well service). The total number, type and locations of wells ultimately drilled into the Qannik Oil Pool will be a function of net oil pay and well performance data. Proposed Qannik Pool Rules & Area Injection Order .~ ~..,, .~ a _ • ~ nun ~ 4 . eouinrn Proposed Qannik Partici~ atin Brea ~ ~~,~~ B • •ix xraw; ~ •nwssx w~. +oi • ~ ~aae • oaeroe ~ • • 8 • a none • • • ~ •m a~. wu. xo~wrn i.oi .s ~ , ~~, Legend ~,~'``~ • • Existing Well • Initial Phase Producer a • • Initial Phase Injector ~~~~ , Planned Future Producer Planned Future Injector ~ Existing Well Penetration ~xseas •ar~ni 0 2 ,oi~w, 3 MILES M~]PV»1 nO~s~MxAp~1n~J~i~ nDl?a~fi+~~ nn~.~at.~,~ Figure 1: Proposed Affected Area for Qannik Area Injection Order Page 2 ConocoPhillips Alaska, Inc. Application to the A OGC~or the Qannik Area Injection Order April 3, 2008 Colville River Field 20 AAC 25.402 (c)(21 Operators and Surface Owners within'/4 Mile of Infection Operations Operator: ConocoPhillips Alaska, Inc. Attention: Matt Elmer P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 Page 3 ConocoPhillips Alaska, Inc. Application to the AOGC~for the Qannik Area Injection Order ~ April 3, 2008 Colville River Field 20 AAC 25.402 (c)(3) Affidavit of Lamont C. Frazer Regarding Notice to Surface Owners AFFIDAVIT OF LAMONT C. FRAZER Lamont C. Frazer, on oath, deposes and says: 1. I am the Qannik Reservoir Engineer for ConocoPhillips Alaska, Inc., the operator of the Colville River Unit. 2. On April 3, 2008, I caused copies of the application for the Qannik Area Injection Order to be provided to the surface owner and operator of all land within a quarter mile of the proposed injection wells as listed below: a. State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 b. Kuukpik Corporation Mr. Isaac Nukapigak P.O. Box 187 Nuigsut, Alaska 99789-0187 c. ConocoPhillips Alaska, Inc. Attention: Matt Elmer ATO-1750 P.O. Box 100360 Anchorage, Alaska 99510-0360 ~~ .. '~ f Lamont C. razer STATE OF ALASKA THIRD JUDICIAL DISTRICT SUBSCRIBED AND SWORN to before me this 3~d day of April, 2008. NOTARY PUBLIC IN AND FOR ALASKA My Commission Expires: -aN . f ~ ~ Z~ I ~ Page 4 ConocoPhillips Alaska, Inc. Application fo the AOGC~or the Qannik Area Injection Order April 3, 2008 Colville River Field 20 AAC 25.402 (c)(4) Description of the Proposed Operation The Qannik Area Injection Order is needed to develop the Qannik Reservoir. The expected scope of the initial development project involves drilling eight horizontal wells and hooking-up the existing Qannik horizontal exploration well (CD2-404). Although Figure 1 shows additional wells planned beyond the nine Qannik wells, this is considered an upside case and will be undergoing continuing evaluation as the development drilling progresses. Field Development Overview Development wells will be drilled from Drill Site CD2. Initial development drilling operations are planned to start during the second quarter of this year. The drilling program will initially focus on developing the main portion of the reservoir and testing the periphery. Well performance data and improved seismic calibrations acquired from the initial development wells will help guide the extent of the overall development drilling program. The main reservoir risks involve (1) structural uncertainty and location of the associated gas-oil contact and (2) sand quality in the most western planned development wells. Successful results from initial development activities would likely lead to additional drilling phases that would include expanded development at Drill Site CD2 to the east and Drill Site CD4 to the south. Subsurface Plan Optimization and subsequent rate forecasts were based on Qannik full field model runs. The Qannik full-field model was developed from a geomodel and history matched to a three week drawdown and subsequent buildup on the CD2- 404 exploration well. Reservoir development options, rate forecasts and risk mitigation plans were evaluated with the Qannik full-field model. Hundreds of reservoir simulation runs have been conducted to investigate sensitivities and analyze various reservoir development schemes. Reservoir development sensitivities included varying the development area, well number, pattern configuration, well spacing, well length, well orientation, and recovery mechanism. Simulation runs were conducted using undulating horizontal wells with a complete (peak-to-peak) cycle of 2000'. (The undulation cycle length was based on technical limitations associated with drilling operations.) This effort resulted in the selection of a 9-well case as the optimum Qannik Drill Site CD2 development. Figure 2 is a well location map that illustrates the basic plan from a reservoir recovery mechanism standpoint. The development incorporates six outboard horizontal production wells and three horizontal inboard water injection wells. The eastern production wells receive additional pressure support from the known gas cap to the east. The inboard water injectors provide both pressure support and secondary oil recovery to the production wells. Page 5 ConocoPhillips Alaska, Inc. Application to the AOGC~or the Qannik Area Injection Order April 3, 2008 Colville River Field Proposed Qannik Pool Rules & Area Injection Order 1~ CD 3 Proposed Qannik • Participating Area i AI ine PA ~ Gas Cap ~ ' .. •: • ~. Expansion p Y ••r Drive from •f ..» :z • ~~.. East • D 4 ~egene .. . • • \ ~ Exlsarq Weq • ~ Inaal Phese InleClor • \ ~ ~ Inaal Phase Proeucer \ PlannBe Fu Nle Pr00uCer - Plannee Future Inledor • EKisung Well Penevatwn Waterflood from Inboard Injection Wells o z r, I Miles Figure 2: Location Map with Recovery Mechanism Figure 2 also illustrates well spacing and orientation. Planned well spacing varies from 2700' in the north to 3400' in the south. (Actual well spacing will be based on well results encountered during development drilling.) Well orientation of the top row is shifted approximately 20° from the bottom two rows. This is intended to minimize gas influx while maximizing oil rate and recovery. The targeted horizontal well length in the southern row is 9000'. The targeted horizontal length for planned wells in the middle and northern rows is 7500'. Upside development opportunities include expanding the development to the south at Drill Site CD4 and drilling updip injectors to the east at Drill Site CD2. Surface Plan Qannik development will use existing infrastructure to the extent possible. Qannik oil resources would be developed from a 7.5 acre pad expansion of Drill Site CD2. This will provide space for up to 18 additional wells on 20' centers Page 6 ConocoPhillips Alaska, Inc. Application to the AOGCC"for the Qannik Area In'ection Order ~ April 3, 2008 J Colville River Field (i.e., 8 new Qannik wells planned for `08, 3 potential upside Qannik wells drilled to the east, and 7 future wells for other targets). Drill Site CD2 is located approximately three miles west of the CRU Alpine Central Facility (ACF) and is accessible by an all-season gravel road. The surface production facility design is based on a standard trunk and lateral piping design with five common headers that support the respective well service requirements. These headers include the following: (1) Production, (2) Test, (3) Gas Lift, (4) Arctic Heating Fuel and (5) Water Injection. The Qannik wellhead shelters will contain the instrumentation and control valves needed for remote control of production, testing & injection. New Qannik surface facility equipment will include a Remote Electrical and Instrumentation Module (REIM) and Chemical Injection Module. The ACF will process produced fluids and supply electrical power. Unitized substances produced from the proposed Qannik Oil Pool will be commingled on the surface with substances from existing Colville River Unit oil pools at CD2 and the ACF. Qannik production will be allocated based on periodic well tests and producing conditions as detailed in the proposed Qannik Pool Rules. Water injection is scheduled to begin in the third quarter of 2008. The injection may consist of either sea water or produced water from other oil pools within the CRU. Surface facilities will be installed to deliver and meter water at each of the three planned injection wells. Qannik Drill Site CD2 expanded surface facilities include the following: • 7.5 acre gravel expansion • Production, test, artificial lift gas injection, and water injection headers • Tie-in slots for 18 wells with wellhead shelters and space for 7 additional wells • REIM with transformers, switch gear, and telecommunications • Chemical Injection Module with associated storage • Wellhead hydraulic panels (centralized, located in the Chemical Injection Module) Page 7 ConocoPhillips Alaska, Inc. Application to the AOGG~"for the Qannik Area Injection Order • Apri13, 2008 Colville River Field 20 AAC 25.402 (cZ(5) Description and Depth of Pool to be Affected Location The proposed Qannik Oil Pool is located in the CRU approximately 3 miles west of the CRU ACF. As shown on Figure 1, the affected area proposed for the Qannik Area Injection Order is: Umiat Meridian T11N R4E sections 1-4, 9-16, 21-28, 33-36 T11 N R5E sections 4-9, 16-21, 28-33 T12N R4E sections 1-4, 9-16, 21-28, 33-36 T12N R5Esections 4-9, 16-21, 28-33 T10N R4 ,:'sections 1-4 T10N l sections 4-6, - Pool Definition ~• !3' rl~''' ~~ The proposed Qannik Oil Pool is the hydrocarbon-bearing interval between 6086 and 6249 feet measured depth in the CD2-11 well (Figure 3) and its lateral equivalents. Pool Description The proposed Qannik Oil Pool is a north-south elongate sand body that is the shallow marine top-set component of an eastward prograding shelf edge sequence broadly age equivalent to the Nanushuk Group. In the CRU, the Qannik sequence is composed of thin (5-35' gross sand) shallow marine sands that extend for at least twelve miles parallel to depositional strike (north-south) and six miles in the E-W depositional dip direction. The Qannik sands pinch-out to the west (updip) due to either onlap or truncation beneath a ravinement surface. The seismically defined time equivalent shelf-slope break is roughly five miles east of CD2 pad. The Qannik reservoir trap is formed by a favorable combination of the stratigraphic pinchout/onlap of the reservoir units and the generally low-relief mononclinal southeast dip of the top of the reservoir unit. In the vicinity of the CD1 drill site, afour-way dip closure is interpreted to be coincident with the contact between the gas column and the underlying oil zone. Page 8 ConocoPhillips Alaska, Inc. Application to the AOGC~or the Qannik Area Injection Order • April 3, 2008 Colville River Field CD2-11 p Qannik 6086' M D ease K3) se Qannik 6249' M D Figure 3: Qannik Type Log Page 9 ConocoPhillips Alaska, Inc. Application to the AOGG~or the Qannik Area Injection Order r April 3, 2008 Colville River Field 20 AAC 25.402 L (6) Description of the Formation The Qannik zone sands are lower very fine to lower fine-grained lithic arenites with average compositions of 30% quartz, 5% feldspar, 35% lithics, and 8% matrix. Average core properties are 23% porosity, 21 millidarcies air permeability, and 38% water saturation. Sands with matrix content greater than 15% are generally non-pay. Geochemical analyses have been completed on oil extracted from the CD2-11 core and from MDT oil samples in Nanuk #2 and Nanuq #5. API gravities from these samples, the CD2-11 core extract, and the CD2-404 production test, ranged from 27-31 degrees. Pressure-Volume-Temperature test results are summarized in Table I for Qannik crude. These results include gas-oil ratio, relative oil volume, and API gravity data based differential vaporization tests from MDT samples obtained from Nanuq #5 exploration well. Reservoir temperature is 89 degrees F. Table I: PVT Summary Property Reservoir Fluid Viscosity Oil Gravity Solution Gas-Oil Ratio Relative Oil Volume Value 2.0 cp 30 Degrees API 404 scf/bbl 1.19 bbl /bbl Page 10 ConocoPhillips Alaska, Inc. Application to the AOGG'~for fhe Qannik Area Injection Order • April 3, 2008 Colville River Field 20 AAC 25.402 (c)(7) Logs of the Infection Wells Atypical well log for proposed injection wells is shown in Figure 4. C X2-404 Horizontal Section 6 3l4" • 5,979 Feet Gross Sandstone - 4,094 Feet coz-oa ~o~o Bozo ala coz.n a aia {1 ~ j~ coz-0 s _ ~ i J( ~ooo aoao i' ' i ~' I ~ ~ ~ v~oio~ian sod weal f ( ~1 D~Ofecteo ]00' east prolB<ieo 6I0' Baal 6050 ~ $ ~ $ 8 § g g g g g ~ ~ ~ 8 E E '~ ~ ~ ~1^~ 1 kMM y ~ ~' ~~ ~~ N~~ 6 h 'SM1~r 1,~'R' ~ "M'W~"'^~+"~t~w `i1 ~ 7~~ry", 4, ...,M w.y _~.,~y ~ "~ "."'W'y' '4M1~ y~ ~Y",' ~J /M'"^ Figure 4: Typical Well Log--CD2-404 GR/Resistivity Page 11 ConocoPhillips Alaska, Inc. Application to the AOGor the Qannik Area Injection Order • April 3, 2008 Colville River Field 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testing All underground injection into the proposed Qannik Oil Pool will be through wells permitted as service wells for injection in conformance with 20 AAC 25.005, or approved for conversion to service wells in conformance with 20 AAC 25.280. A typical injector well schematic is included as Figure 6. The proposed Qannik Oil Pool will be accessed from wells directionally drilled from a gravel pad utilizing drilling procedures, well designs, casing and cementing programs consistent with current practices in other North Slope fields. For proper anchorage and to divert an uncontrolled flow, 16-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements may be installed on the conductor. Primary, secondary, and general well control for drilling and completion operations will be performed in accordance with 20 AAC 25 Articles 01 and 06. Casing and cementing will be performed in accordance with 20 AAC 25.030. Surface casing, cemented to surface, is planned at approximately 2400 feet true vertical depth. Intermediate hole will be drilled to the target zone and production casing will be cemented with the shoe in the target zone. Either leakoff or formation integrity tests are planned after drilling 20 to 50 feet beyond the respective surface casing shoe and the production casing shoe. The production casing will be cemented with a volume sufficient to protect any significant hydrocarbon zones. Production and injection holes will be drilled beyond the casing shoe horizontally in the target zone. Slotted liners are planned for both producers and injectors. Tubing and packer, or other equipment, will be run to isolate pressure to the injection interval consistent with 20 AAC 25.412, but the maximum spacing of 200 feet measured depth between the pressure isolation equipment and the top of the injection zone, as specified in 20 AAC 25.412(b), should be waived to accommodate efficient wireline operations down to the pressure isolation equipment. In wells where this distance is more than 200 feet, the casing cement volume will be sufficient to ensure that cement extends a minimum of 300 feet measured depth above the planned packer depth. Casing-tubing annulus pressures will be monitored and reported during injection operations in accordance with 20 AAC 25.402(e). Automated monitoring of injection rates, tubing and casing-tubing annulus pressures is planned. Prior to commencement of injection, each injection well will be pressure tested in accordance with 20 AAC 25.412(c). In the event pressure observations or tests indicate communication or leakage of any tubing, casing, or packer, ConocoPhillips will notify the Commission within 24 hours of the observation to obtain Commission approval of appropriate corrective actions. Commission approval will be received prior to commencement of corrective actions unless the situation represents a threat to life or property. Page 12 ConocoPhillips Alaska, Inc. i Application to the AOGC~or the Qannik Area Injection Order Colville River Field Alpine CD2 -Qannik Injector Completion 16" Insulated Conductor to 114' 4-1/2" DB Nipple at +/- 2000' ND w/ A-1 injection valve (differential pressure controlled SSSV) 10-3/4" 45.5 ppf L-80 BTCM Surface Casing at +/-2400' ND, cemented to surtace 4-1/2" 12.6 ppf L-80 IBT Mod. tubing GLM w/dummy valve above Packer Production Packer Slick stinger w/fluted WLEG and shear sub XN nipple Qannik Reservoir 7-5/8" 29 ppf L-80 BTC Mod Production Casing @ +/-85° Liner top hanger w/ tieback receptable April 3, 2008 6000 - 9000' MD Horizontal 4-1/2" 12.6 ppf L-80 SLHT liner w/ slots across sand and blank across shale Figure 5: Typical Injector Wellbore Schematic Page 13 ConocoPhillips Alaska, Inc. Application to the AOGC~or the Qannik Area In'ection Order April 3, 2008 J Colville River Field 20 AAC 25.402 L)(9) Infection Fluid Analysis and Infection Rates The water injection plan for the Qannik Oil Pool is premised on using existing infrastructure. The water injection distribution system, which employs a common injection line from the ACF to Drill Sites CD2 and CD4, will supply injection water for Qannik. Seawater will initially be used for water injection followed by produced water or mixed produced water/seawater later in the field life. Potential scaling issues associated with mixing waters will be managed using scale inhibitors. Injecting seawater, produced water, or combinations of the two, is a standard operating practice in North Slope fields. Injection rates will be managed based on voidage. Individual well injection rates will vary according to voidage targets and reservoir properties. The expected maximum and average injection rates for the planned nine well development are 12 MBWPD and 5 MBWPD, respectively. A formation damage study is attached. This study was conducted with Qannik reservoir core from CD2-11 using a high salinity (149,000 ppm total dissolved solids) and low salinity brine (24,600 ppm total dissolved solids). No catastrophic loss of permeability was observed with either brine. This suggests the Qannik reservoir is compatible with brines over a wide range of salinities. The low salinity brine did cause a gradual reduction in permeability that is attributed to fines migration. No appreciable permeability reduction is apparent until after numerous pore volumes have flowed through the core. Since the fines are mobilized by brine flow and not oil flow, they act as a self correcting diversion control mechanism and can subsequently improve sweep. Plans are to produce mobilized .fines from the producers as attempting to screen them from the production stream could cause formation damage in the near-wellbore region of the producers. The large surface area associated with horizontal wells should also help minimize formation damage in the near-wellbore area of the producers. Although producer stimulation treatments (e.g., hydraulic fracturing, acid stimulation, etc.) are not expected to be needed, they can be employed if necessary. Potential injector near-wellbore formation damage is not a concern as this damage can be mitigated by injecting above parting pressure. The recipe for the synthetic high salinity and low salinity brine used in the Qannik core floods is shown in Table II with corresponding cation concentrations shown in Table III. The high salinity brine is intended to represent drilling brine while the low salinity brine is intended to represent Beaufort seawater during summer conditions. Tables II and III also show the recipe and cation concentration of the synthetic brine used in lab studies to represent produced water from the Colville River Unit. The synthetic Colville River Unit produced water brine and the synthetic Beaufort seawater brine have similar compositions and nearly identical salinities. Hence, the lab study supports the contention that the Qannik reservoir is compatible with both Beaufort seawater and Colville River Unit produced water injection. Page 14 ConocoPhillips Alaska, Inc. Application to the AOGG'C'for the Qannik Area Injection Order Colville River Field Table II: Synthetic Water Recipe Component NaCI KCI CaC12 MgCIZ BaCl2 SrCIZ NaHCO3 Na2SO4 HZO Drilling Brine Grams 89.100 60.000 0 0 0 0 0 0 850.900 1000.0 Summer Beaufort Seawater Grams 16.713 0.536 1.089 7.772 0 0 0.175 2.745 970.969 1000.0 Table III: Synthetic Brine Cation Concentration Component Na K Ca Mg Ba Sr Drilling Brine ~1 35,031 31,448 0 0 0 0 66,478 Summer Beaufort Seawater (ppm) 7508 281 297 929 0 0 9015 Page 15 April 3, 2008 Colville River Unit Produced Water Grams 20.282 0.303 0.466 0.812 0.005 0.027 1.020 0.624 976.442 1000.0 Colville River Unit Produced Water ~ppm) 8461 159 127 97 3 9 8856 ConocoPhillips Alaska, Inc. A lication fo the AOGC~for the Qannik Area In'ection Order ~ A ri13, 2008 pP 1 P Colville River Field 20 AAC 25.402 jc~(10) Estimated Pressures The seawater injection pressures from the ACF pump discharge are expected to average approximately 2500 psi. Due to pressure losses in the distribution system, wellhead injection pressures are expected to be 2400 psi with water. Injection wells may be choked to lower wellhead pressures to manage injection rate. Page 16 ConocoPhillips Alaska, Inc. A lication to the AOG~or the Qannik Area In'ection Order ~ Aril 3, 2008 PP J P Colville River Field 20 AAC 25.402 r,r; (11) Fracture Information A qualitative assessment of the potential for fracturing of the Qannik interval was evaluated using a fracture model. This work indicates injection fluids will remain with the proposed Qannik Oil Pool. Digital log data from the CD2-404 well were processed to estimate elastic properties and in-situ stress. Bottomhole pressure and rate data were input to a fracture simulator and the derived rock properties and stresses were used to simulate frac performance. The model indicated height growth occurred throughout the Qannik sands. Maximum water injection pressure will exceed the parting pressure of the Qannik reservoir rock. Under long term water injection conditions at maximum injection pressure, the fracture model indicated that the fractures will not propagate through the shales of the Torok formation above and below the Qannik reservoir. Fracture modeling reports are attached. Page 17 ConocoPhillips Alaska, Inc. Application to the AOG~for the Qannik Area In'ection Order ~ Aril 3, 2008 J p Colville River Field 20 AAC 25.402 (c (Z 12 Quality of Formation Water Water has not been produced from wells in the proposed Qannik Oil Pool, nor have water-oil contacts been observed in the Qannik reservoir. Connate water resistivity was estimated using the same connate water salinity as was used for the CRU Alpine and Fiord reservoirs. This equates to approximately 0.20 ohm-m at reservoir temperature. Salinities in the CRU were calculated in the Nechelik #1 approximately 4 miles northeast of the proposed Qannik Oil Pool in zones deeper than the proposed injection zone. Using the standard Archie correlation and open hole log data, the salinities in the Sag River (8432-8480 feet MD) and Ivishak (9420-9460 feet MD) formations were calculated to be 18,000 and 17,000 parts per million (ppm) NaCI equivalent, respectively. Approximately 5 miles south of the proposed Qannik Oil Pool, the Nanuk #2 well produced water from downdip, deep water equivalent Torok Formation sands. From perforations at 7,048 to 7,108 feet MD (approximately 6200' TVDSS), the Nanuk #2 well produced formation water with the following composition: Sodium Potassium Calcium Magnesium Bicarbonate Sulfate Chloride 7,000 ppm 150 ppm 200 ppm 0 ppm 800 ppm 0 ppm 10,600 ppm Page 18 ConocoPhillips Alaska, Inc. Application to the AOGG~ for the Qannik Area Injection Order April 3, 2008 Colville River Field 20 AAC 25.402 L)(13) Aquifer Exemption Reference No underground sources of drinking water exist beneath the permafrost in the Colville River Unit area. See Area Injection Order 18B (October 7, 2004) conclusion #3. The proposed Area Injection Order has an affected area entirely within the Colville River Unit area. Wells in the proposed Qannik Oil Pool are planned with surface casing set below the base of permafrost. Annular disposal of drilling waste is planned at Drill Site CD2 after application and authorization under 20 AAC 25.080. Page 19 ConocoPhillips Alaska, Inc. A lication to the AOGC~for the Qannik Area In'ection Order ~ Aril 3 2008 pP J P Colville River Field 20 AAC 25.402 (cZ(14) Incremental Hydrocarbon Recovery Numerical simulation projections indicate the nine well development plan with secondary recovery operations will provide a total ultimate recovery of 17 MMBO (22% OOIP) with a range of 11 - 25 MMBO. The corresponding peak annual production rate is estimated at approximately 4 MBOPD in 2009 with a range of 3 - 6 MBOPD. The annual average peak water injection rate is estimated at approximately 5 MBWPD with a range of 4 - 7 MBWPD. Simulation results also indicate that the incremental recovery benefit of secondary operations is over 5 MMBO (7% OOIP) compared to primary depletion with gas cap expansion. Gas cap encroachment is a risk as production will be processed by the ACF, which has gas handling constraints. Gas production from the Qannik pool will cause wells with the highest GOR feeding the ACF to be shut-in. These shut-in wells will eventually be reopened as oil and gas production rates feeding the plant decline, freeing-up facility capacity for higher GOR production. However, no appreciable gas handling limitations are forecast after 2012. Gas cap encroachment is therefore more of a near-term rate risk, as opposed to a long- term reserve risk. Simulation runs using a variety of reservoir descriptions suggest that eastern producers can be within 1000' of the GOC and still remain safely below the ACF marginal GOR (i.e., the GOR of the highest well on-line). A minimum standoff distance of 1000" was therefore incorporated in the development plan. If this standoff is insufficient and gas encroachment causes GORs to rapidly increase, updip injectors could be drilled in the GOC to reduce gas influx. Simulation sensitivities suggest this strategy can successfully restrict gas influx and increase overall recovery. The updip injectors are considered marginal wells that will be reevaluated once performance data are available from the initial nine-well development. However, if GORs of the eastern producers rapidly rise due to gas cap encroachment, the likelihood of expanding the development further to the east and drilling updip injectors significantly increases. Expanding Qannik development south to Drill Site CD4 appears viable based on existing reservoir information. However, a phased development approach is planned to minimize development risk. If the nine-well CD2 development is successful, plans would be to pursue Qannik development at Drill Site CD4. Analytical calculations scaled to the initial nine well development area suggest that the total ultimate recovery for the upside 18 well development case (which includes three additional CD2 wells and six CD4 wells) with secondary recovery operations should be approximately 28 MMBO with a range of 18 - 40 MMBO. The incremental secondary recovery benefit is estimated at 9 MMBO (7% OOIP). Page 20 ConocoPhillips Alaska, Inc. Application to the AOGC~; for the Qannik Area In'ection Order • A ri13 2008 1 P Colville River Field 20 AAC 25.402 (c)(15) Mechanical Condition of Wells Within '/4 Mile of Proposed Area The Qannik interval was not considered a significant hydrocarbon bearing interval and was therefore not cemented during initial Colville River Field development efforts. However, improvements in horizontal drilling technology coupled with increased oil prices have caused Qannik to now be considered a viable development opportunity. The primary concern involves cross-flowing injected fluids from the Qannik reservoir into either the C-30 annular disposal interval, or the Lower K2 interval, via the open annuli of existing CD2 Alpine wells. The potential for this type of cross-flow is most prevalent in the near wellbore region of Qannik injectors, where Qannik reservoir pressures are at their highest. Although the cross-flow would have no appreciable impact on ultimate recovery, it would make the planned waterflood less efficient. Cross-flow is not expected to initiate due to three main factors: (1) 1650' TVD of annulus is filled with dehydrated drilling mud, (2) shales likely collapsed along the casing from long-term exposure to water based drilling mud and (3) mud is in the hole, so leak-off pressure would need to be exceeded to initiate flow from Qannik to the C-30 or Lower K-2. A wellbore schematic of a typical CD2 Alpine showing the relative position of the Qannik interval is presented in Figure 6. Typical Alpine Well 16" Insulated Conductor to -114' 9-5/6" - 2400' ND C-30 Annular Disposal Interval 1650 ft ND K-2 or "Qannik" 200 ft ND Top of Cemen[ ~ minimum 500 ft " 2600 ft ND above Alpine i 7" 26 ppf I I I l Roeservoie Figure 6: Typical CD2 Alpine Wellbore Schematic Page 21 ConocoPhillips Alaska, Inc. A lication to fhe AOGG~for the Qannik Area In'ection Order ~ Aril 3, 2008 pp J p Colville River Field Remedial zonal isolation techniques for CD-2 wells were considered prior to initiating a waterflood, but have significant disadvantages. Potential remediation techniques include (1) block squeezing the Qannik interval in Alpine CD2 wells, (2) Arctic Packing, (3) injecting water conformance and/or matrix sealants, and (4) top cement squeezing the surface casing shoe to C-30. Each method of remediation listed eliminates any monitoring options to further understand cross-flow issues and each is unlikely to eliminate potential problems. Block squeezing the Qannik interval in existing Alpine wells is not considered a viable option as it takes wells with no mechanical integrity problems and introduces potential casing leak points. A comprehensive monitoring plan is incorporated in the Qannik development plan to address the Alpine CD2 well open annuli situation. The monitoring plan includes the installation of wireless pressure transducers on the outer annuli of the 19 Alpine CD-2 wells that fall within one quarter mile of planned Qannik injectors. This would allow continuous monitoring of the outer annuli in order to set pressure safety alarms in the Setcim SCADA system to alert operators to review well activities that may explain observed pressure changes. In addition, a quarterly review of pressure trends would be conducted in these Alpine CD2 wells with wireless pressure transducers. Unexplainable pressure changes would trigger a diagnostic process to identify the next course of action, whether it is reduced injection in offset Qannik wells, down-hole diagnostic services, or potential remediation of CD-2 wells. All existing wells within one quarter mile of the three initial proposed injection wells are in good mechanical condition or have been plugged and abandoned. These wells, their current service and completion date are listed below. Well Service Completion Date CD2-03 Producer 7/30/05 CD2-09 Producer 9/12/04 CD2-11 Injector 10/8/05 CD2-12 Injector 5/19/03 CD2-21 Producer 2/8/05 CD2-23 Producer 7/24/02 CD2-15 Injector 10/30/01 CD2-24 Producer 6/28/01 CD2-336 Producer 9/2/01 CD2-42 Producer 6/1 /01 CD2-32 Injector 3/5/02 CD2-49 Injector 2/4/02 CD2-40 Injector 8/25/03 CD2-30 Injector 10/30/03 CD2-43 Producer 1 /20/04 CD2-55 Injector 10/1 /03 CD2-47 Producer 12/16/01 CD2-05 Producer 8/22/04 CD2-60 Injector 7/10/05 NEVE #1 Exploration P&A - 4/22/96 Page 22 ConocoPhillips Alaska, Inc. • • Area Injection Order Attachment Qannik Area Fracture Containment Modeling ~~~~IV~Q aPR x o zoos Alaska (~ & Gas Cons. Commission Jack Walker March, 2008 Qannik Interval Fracture Containment Modeling March 2005 Summary Fracturing the Qannik interval with injection water was modeled with Stimplan software. The Alpine injection system has the capability of exceeding the parting pressure of the Qannik sands on water injection. However, insitu stress contrast is adequate to confine fractures initiated in the Qannik sands. Upward fracture growth for water injection will be arrested in the siltstone above the Qannik sands. The base of fracture growth will be within 50 feet of the base of the Qannik interval. Analysis Mechanical properties were calculated from open hole logs and tuned to the actual injection data collected in CD2-404. Step rate test analysis indicated a fracture extension pressure of 0.625 psi/foot2. Based on mechanical property trends, the Qannik sands and surrounding intervals were divided into 18 subintervals between 3800 and 4400 feet subsea, including the productive sands. Mechanical properties were averaged over these subintervals. Figure 1 shows the in-situ stress plotted with depth. At a depth of approximately 4050 feet (true vertical), the fracture closure fracture extension pressure is 2531 psi. Maximum surface delivery pressures are expected to be 2400 psi. The injection system is capable of delivering injection water at pressures exceeding the parting pressure. However, the model indicates that maximum injection pressures will be lower than the maximum facility capacity because permeability of the formation allows leakoff of injection fluid at a high rate. Figure 2 shows the stress input for the fracturing modeling. 2 • Qannik Interval Fracture Containment Modeling March 2005 Kanik Theoretical PPG from Logs -Alpine3 Min. ppg -Alpine3 Max ppg 8 10 Kanik TOP 16 18 3700 --- Kanik BASE 3800 -- -- ---~- - ---------' --~----- ---'r--- ---- 3900 - -- - --- --- ---- - ---- - - - 4000 -- -----~ -- ~ - - -~------ - - - ' --- -'. .. r 4100 - ----------~--------------- -----'~- ~--- - a -- -- 0 4200 -----'-- --------- ~------ --------~---------------~---- 4300 - ---' --------------~--------------~---------------~------ -------= 4400 - -------- -------~---------------~--------------',~ - 4500 -- --~ -- - ~ - -. ~- - - - --, Figure 1 Mechanical Properties from Alpine 3 Dipole Sonic Analysis Leakoff was estimated based on reservoir and fluid properties3. Permeability, relative permeability and fluid viscosities were taken from CD2-11 core and Nanuq 5 fluid studies. High injection rate (4320 BPD) was chosen to model water injection. This rate would impose greater than planned injection pressure and greater stress on confining layers than that likely to be encountered during planned operations. The modeled rates are 150% of the maximum planned rate. The specific injection rate per foot of interval for the vertical well fracture model was more than 100 times greater than the expected specific injection rate of interval open in the planned horizontal injectors. The much higher than expected rate was modeled as a conservative approach to ensure induced fractures will be confined. Water injection was modeled at 3 BPM for a cumulative injection volume of 2 million barrels. The fracture geometry with vertical stress profiles are shown in Figure 2. 3 Qannik Interval Fracture~tainment Modelin ~ March 2005 9 Qannik Injection Confinement TVD f1 3900 4000 4100 4200 4300 Figure 2 Qannik Water Injection Fracture Geometry Conclusions 1. Fracturing the Qannik sands is possible with the delivery pressure and rate expected to be available at Drill Site CD2. 2. Fracture growth will be confined by the siltstone above the Qannik sands. 3. The fracture model indicated that water fracturing in a vertical well will grow throughout the Qannik interval and will be arrested in the shaley interval immediately below the Qannik interval. 4 Qannik Interval Fracture Containment Modeling March 2005 NSI Technologies Inc., Version 5.51 z Fra2er L., personal communication, March 26, 2008 s Gidley, et. al., Recent Advances in Hydraulic Fracturing SPE Monograph Volume 12, 1989, pp. 147-157 5 • • Area Injection Order Attachment NEVE #1 P&A Schematic ;~ , ~- .. NEVE #y FINAL P&A SCHEMATIC _~- ,- _ - ~'~' ~'~ ~'"~ ~ - - PLUG #3 TUBING PERFS 260-263' PLUGS #3 & #4 ARE ,__. __ _ ,,__,__,_ ARCTICSETCEMENTS 11.0 ppg MUD:IN 7" X OPEN .HOLEANNULU$ KILL WEIGHT BRINE BETWEEN ALL `PLUGS -AND IN 3-1 /2" X 7" ANNULUS; 10.6 ppg .P&A CEMENT = .FILL I TOP OF PLUG #1 ONSIDE TUBING AT 7155' {COILED TBG REF DEPTH) ~~ 9-5/8" CSA 1841' RKB CEMENTED TOSURF=ACE WITH ARCTICSET eEMENTS 3-1/2° 9.3# L80 EUE 8RD "MOD TBG I PLUG #2 CEMENT TOPS: ~~tl INSI.pE TUBING, 6672' INSIDE 3-112" X 7", 6846' I GAS LIFT MANDREL @ 7046' - BLANKING PLUG IN XN NIPPLE @ 7092' UPPER PACKER @ 7145' SQUEEZE PERFS @ 7220' {SQUEEZED 3/12/96) LOWER PACKER @ 7240' TUBING TAIL @ 7265' (7259' WLM) J-4 SAND TEST PERFS ''` 7268-7376' TOP OF PREVIOUS FILL @ 7459' (COILED TBG REF DEPTH) EXPENDED TCP PERF GUNS @ 7458' ORIGINAL PBTD .7576' 7" CSA 7679' RKB TWM, 5/6/96 • • Area Injection Order Attachment Qannik Field Formation Damage Study to Brine Injection • ~ • ConocoPhillips Upstream Technology People • Integration • Innovation 3M RESERVOIR MECHANISMS and LABORATORIES BARTLESVILLE TECHNOLOGY CENTER BARTLESVILLE OK 74004 TO: B. R. Buck DATE: May 8, 2007 TITLE: Qannik Field Formation Damage Study to Brine Injection, CD2-11 Well, Alaska REPORT: Reservoir Mechanisms and Laboratories WBT160192-JHH-2007-1 AUTHOR(S): J. H. Hedges SUMMARY We measured permeability on fresh state core plug samples with oil and synthetic Beaufort Sea Water (sample MG-6 was also injected with 9.21b/gal drilling brine). • The injection of oil showed the development of stable permeability. • The injection of Beaufort Sea Water showed signs of increasing, decreasing and stable permeability indicative of formation damage due to fines mobilization. No catastrophic loss of permeability was observed. • The high salt 9.21b/gal drilling fluid showed signs of improving to stable permeability (sample MG-6). RECOMMENDATIONS Production facilities should be prepared to handle some fines production upon injection water breakthrough. Rock mechanics testing could be used to help define this potential further. SHAREPOINT LINK: 4annik Field Formation Dama eg Study to Brine Injection, CD2-11 Well, Alaska Open folders: Technical Services Reports -Alaska Fields • • Hed-02-2007 Page 2 REPORT DISTRIBUTION LIST Title Page (E-mail) J. J. Jurinak; J. L. Hand; A. Rezigh; H. E. Farrell; M. E. Vienot; J. A. Spencer; B. M. Borland; D. H. Beardmore; R. M. Hodge; D. R. Zornes; J. H. Hedges; J. J. Howard; W. T. Siemers Complete Report (Hardcopy) E&P Technical Files -Houston (RC) L. C. Frazer -Anchorage D. G. Knock -Anchorage J. W. Yeaton -Anchorage T. W. Crumrine -Anchorage R. E. Hannon -Anchorage B. D. Noel -Anchorage J. C. Eggemeyer -Anchorage C. L. Alvord -Anchorage J. H. Hedges (2) -Bartlesville Reservoir Mechanisms and Laboratories Sharepoint site contact: Debbie Walker Teri L. Nichols 918-661-9682 918-661-3617 mail to: debbie.j.walker(a(aJconocophillips.com mailto:teri.l.nichols(a~conocophillips.com THIS IS A CONFIDENTIAL RESERVOIR TECHNOLOGY CENTER REPORT PREPARED FOR THE EXCLUSIVE USE OF CONOCOPHILLIPS COMPANY AND ITS AFFILIATES. THIS IS A PROFESSIONAL REPORT PRESENTING THE OPINION OF THE AUTHOR AND HAS BEEN ISSUED WITH THE KNOWLEDGE AND CONSENT OF HIS SUPERVISORS. STATEMENTS, CONCLUSIONS, RECOMMENDATIONS, AND EXHIBITS CONTAINED HEREIN SHOULD NOT BE CONSTRUED AS REPRESENTING MANAGERIAL AUTHORITY, NOR IS IT THE INTENT TO LESSEN OR CHANGE EXISTING MANAGERIAL RESPONSIBILITIES, AUTHORITIES, OR ACCOUNTABILITY. ConocoPhillips Interoffice Correspondence Bartlesville, OK 74004 B. R. Buck (3) E&P -Alaska • May 8, 2007 Qannik CD2-11 Well, Qannik Field -Alaska Formation Damage Potential -Water Injection Hed-2-2007 This report presents data concerning formation damage testing of fresh state core samples from the Qannik CD2-11 Well, Qannik Field, Alaska for the purpose of testing how the laminated Qannik sandstone would react to the injection of Beaufort Summer Sea Water. (Tests at MI showed that the inter-bedded shales were very sensitive.) We measured permeability on fresh state core plug samples with oil and synthetic Beaufort Sea Water (sample MG-6 was also injected with 9.21b/gal drilling brine). • The injection of oil showed the development of stable permeability. • The injection of Beaufort Sea Water showed signs of increasing, decreasing and stable permeability indicative of formation damage due to fines mobilization. No catastrophic loss of permeability was observed. • The high salt 9.21b/gal drilling fluid showed signs of improving to stable permeability. Fresh state plug samples were drilled with kerosene, trimmed and placed into a Hassler sleeve core holder. We injected kerosene and measured permeability to kerosene. Figures 1, 3, 5 and 7 (samples MG-4C, MG-3, MG-5 and MG-6, respectively) present measured oil permeability at O.Scc/min versus cumulative volume of oil injected. • The permeability to oil remained constant for all four plugs. We injected Beaufort Summer Sea Water and measured permeability. See Figures 2, 4, 6, and 8 (samples MG-4C, MG-3, MG-5 and MG-6, respectively) for permeability results. • For sample MG-4C (see Figure 2), Beaufort Sea Water injection was operated with increasing pressure drop (200 to 1000psi), forward and reverse flow directions, shut-in and re-start operation, and continued injection. o Increasing pressure drop increased permeability, changing flow directions both increased and decreased permeability, shut-in and re-start operation decreased permeability, and continued injection both decreased and increased permeability. o Haphazard flow is indicative of fines migration effects. • For sample MG-3 (see Figure 4), Beaufort Sea Water injection was operated with changing injection rates (lcc/min and O.Scc/min) and continued flow. o Changing injection rates decreased and increased permeability. o Continued flow decreased permeability. • For sample MG-5 (see Figure 6), Beaufort Sea Water injection was operated with constant injection (O.Scc/min). o Continued flow decreased permeability and then stabilized after injecting 2000cc of brine. • • Hed-02-2007 Page 4 • For sample MG-6 (see Figure 8), 9.21b/bbl drilling brine injection was operated under constant injection (O.Scc/min) followed with Beaufort Sea Water (see Figure 9) under constant injection (O.Scc/min). o The 9.21b/bbl drilling brine increased to stabilized permeability. o The Beaufort Sea Water decreased permeability. After the injection testing, the plug samples were cleaned using hot solvent extraction with toluene and methanol solvents and dried in a vacuum oven at 60°C. Routine core analysis results are presented in Table I. Photos of the plugs are presented in Figures 10 through 13 (samples MG-3, MG-4C, MG-5 and MG-6, respectively). Fines migration problems were observed while flowing. Beaufort Sea Water in core plugs from the Qannik CD-11 Well as evidenced by slowly decreasing permeability with throughput, abrupt changes from stopping and starting flow and abrupt changes during flow. Catastrophic permeability loss to Beaufort Sea Water was not observed. Problems were not observed while flowing oil or the 9.21b/gal brine (6% KCl and 8.9% NaCI). If we can be of further assistance, please contact us. J. H. Hedges 130 GB, Bartlesville Technology Center (918-661-9515) (j im.h.hedges(a~conoconhillips.com) JHH:dw Attachments Hed-02-2007 Page 5 Table I. Qannik CD2-11 Plug Samples Sample # Depth ~ Dia. cm Length cm Gr Den /cc Porosity ~ Kg and ,.~.:~„i ;3~~'i~li~l~ „ ~ .:.i ~:: ! '. ibiN i ... .... ::, .,: ~;:~,x ~~ ~ ...;::...::~::: K >....: .. I :ee ieeeu;;;3;;3.... ,;,; .;: ~z.:,:,;:. ; I ~;~ ~;31~3 .y .~:I.:I~WI .L:.3... .... i. ;; :;, ,.:~:,;,,,~ ;~; ~r ~ i .......,... .~ ,~~ z ;; (I~l134 ,„ ;: it ~'~.... .... i ~; I; ~ ; ~I a~ ..L9 ...., i.. L3a 1 i I ..ran i MG-3 6121.5 3.87 5.66 2.71 24.1 15.3 MG-4C 6131.2 3.75 2.80 2.70 28.2 xx MG-5 6090.6 3.75 6.15 2.70 25.4 19.8 MG-6 6098.6 3.79 5.92 2.69 24.6 9.0 XX -Sample became unstable after cleaning. Hed-02-2007 Page 6 Table II. Summer Beaufort Sea Water 7/11/98 GRAMS/COMPONENT NA CL ........................... 16.713 NA CL ......................... 133.701 K CL .............................. 0.536 K CL ........................... 4.289 CA CL2 2H2O ............... 1.089 CA CL2 2H2O ............ 8.716 MG CL2 6H2O ............. 7.772 MG CL2 6H2O ............ 62.178 NA HC03 ...................... 0.175 NA HC03 ................... 1.399 NA2 S04 ....................... 2.745 NA2 S04 .................... 21.963 H2O ............................... 970.969 H2O ............................. 7767.754 GMS SOLUTION .......... 1000 GMS SOLUTION ....... 8000 TDS (PPM) .................. 24,616 CALC CLs PPM ........ 13,618 INPUT VALUES INPUT VALUES CATION (PPM) ANION (PPM) NA ................................ 7508 HC03 ........................ 127 K .................................., 281 S04 ........................... 1856 CA ................................ 297 MG ............................... 929 SUMMATION ............ 1983 SUMMATION ............ 9015 • Hed-02-2007 Page 7 Table III. Qannik Drilling Brine - 9.2 Ib/gal GRAMS/COMPONENT NA CL 89.100 NA CL 712.797 K CL 60.000 K CL 480.000 H2O 850.900 H2O 6807.204 GMS SOLUTION 1000.0 GMS SOLUTION 8000.0 TDS (PPM) 149013 CALL CLs(PPM) 82534 INPUT VALUES INPUT VALUES CATION (PPM) ANION (PPM) NA 35030.6 HC03 0 K 31447.7 S04 with Na 0 SUMMATION 66478.3 SUMMATION 0 Hed-02-2007 Page 8 Figure 1. Qannik MG-4C Oil Injection 0.5 0.4 ~ + 0.5 cc/mi n ~ 0.3 w a~ 0.2 0.1 0.0 0 50 100 150 200 250 300 Cum Volume, cc ~.' J Hed-02-2007 Page 9 Figure 2. Qanni k MG-4C Beauford Sea Water Injection 0.12 0.10 0.08 0.06 0.04 0.02 0.00 0 500 1000 1500 2000 2500 Cum Volume, cc ~ Forward @250psi f Forward @500psi ~ Forward @1000psi -~ Reverse @200psi ~- Reverse @500psi ~ Reverse @1000psi _ ~ Shut & Rev @1000psi ~ Forward @1000psi ~. Hed-02-2007 Page 10 Figure 3. Qannik MG-3 Oil Injection 7.0 6.0 5.0 ~- 2.5 cc/mi n 4.0 ~ 3.0 0. 2.0 1.0 0.0 0 200 400 600 800 1000 1200 Cum Volume, cc • • Hed-02-2007 Page 11 Figure 4. Qannik MG-3 Beaufort Sea Water Injection 4.0 3.5 -~ 1 cc/min 3.0 ~ 0.5 cc/mi n 2.5 ~ 1 cc/min 2.0 1.5 1.0 0.5~ 0.0 0 500 1000 1500 2000 2500 Cum Volume, cc • Hed-02-2007 Page 12 Figure 5. Qannik MG-5 Oil Injection 16 14 12 10 --•- 0.5 cc/min 8 ~. 6 4 2 0 0 200 400 600 800 Cum Volume, cc s • Hed-02-2007 Page 13 Figure 6. Qannik MG-5 Beaufort Sea Water Injection 7 6 5 -~- 0.5 cc/min ~ 4 3 a 2 1 0 0 1000 2000 3000 4000 5000 Cum Volume, cc Hed-02-2007 Page 14 Figure 7. Qannik MG-6 6.o Oil Injection 5.0 4.0 --~- 0.5 cc/min 3.0 2.0 1.0 0.0 0 200 400 600 800 Cum Volume, cc Hed-02-2007 Page 15 Figure 8. Qannik MG-6 Drilling Brine Injection 3.000 2.500 ~ 2.000 -+- 0.5 cc/min ~ 1.500 L °- 1.000 0.500 0.000 0 200 400 600 800 Cum Volume, cc Hed-02-2007 Page 16 Figure 9. Qannik MG-6 Beaufort Sea Water Injection 3.0 2.5 -~- 0.5 cc/min 2.0 ~ 1.5 L 0. 1.0 0.5 0.0 0 500 1000 1500 2000 Cum Volume, cc • • Figure 10. MG-3 Core Sample. Before Extraction After Extraction ~ 1 21 .5 • Hed-01-2007 Page 18 Figure 11. MG-4C Core Sample. I. Y::, '~ '- [ ~ {l .. r ~. ° \ ll i 1 'i~~ C Y Qa~n~k Cp2_,, 6~ ~'! _2 v ti k:~s i ~yy~, ,. . ~~-i .`. ,~]J/~~ ~ T ~T tl~ J . i~ ~ i• i t~ i.~ ~ ~ y~ ` ~ Y ~ ~. Qannik C~2-11 Plug- MG-4C Depth - fit 31 _2 ft. Before Extraction After Extraction • ~ Figure 12. MG-5 Core Sample. ~^` '.p, ~q'r~i~•~}R r ~f9~tj M'lr~p ~~*y' f i w. ~. ~vF _ v ~ ~ , ~-a ~, 'fib' d ~,.. c`+'~x: '~~ ~+ t.. i ~ { f s ~~ .re.~ '~ gr,` 7i+,~ a~y~, b. Hed-O1-2007 Page 19 Before Extraction so9a _s After Extraction