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Home My WebLink AboutAIO 033AREA INJECTION ORDER Index 33 Oooguruk-Kuparuk Oil Pool 1. December 20, 2007 Pioneer Natural Resources Application for Area Injection Order for Oooguruk- Kuparuk and Oooguruk Nuiqsut Oil Pool 2. January 8, 2008 Notice of Hearing, Affidavit of Publication and mailing 3. January 24, 2008 DNR's request for a hearing on AIO 4. February 14, 2008 Transcript 5. December 4, 2008 Pioneer's Notice of Commencement of Injection Operations 6. March 11, 2009 Pioneer's request for administrative approval to modify Rule 3 of Order (Attachment 4, 4a,4b, 4c, 4d, 4e, 5, core testing 2005 Confidential) (aio33-001) and (aio33-002) 7. September 2, 2009 E-mail re: Possible Mis-injection 8. April 23, 2010 Application to amend AIO 33 & 34 (aio33-003) 9. ------------------------ Questions and Answers (Attorney Client Confidential Info) 10. November 4, 2010 Pioneer e-mail request for Admin Approval (AIO 33.004) 11. February 5, 2020 Administrative approval to Amend Rule 3. (AIO 33.005) • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 33 PIONEER NATURAL ) RESOURCES ALASKA, INC. for ) Oooguruk Field an order authorizing underground ) Oooguruk Unit injection of fluids for enhanced oil ) Oooguruk-Kuparuk Oil Pool recovery in the Oooguruk-Kuparuk ) Oil Pool, Oooguruk Unit, Beaufort ) April 11, 2008 Sea, Alaska ) IT APPEARING THAT: 1. By letter and application dated December 20, 2007, and received by the Alaska Oil and Gas Conservation Commission (Commission) on December 21, 2007, Pioneer Natural Resources Alaska, Inc. (Pioneer), in its capacity as unit operator and on behalf of the working interest owners of the Oooguruk Unit (OU}, .requests an order from the Commission authorizing the injection of fluids for enhanced oil recovery in the Oooguruk-Kuparuk and Oooguruk- Nuigsut Oil Pools. Pioneer's request regarding the Oooguruk-Nuigsut Oil Pool is addressed in Area Injection Order No. 34. 2. Notice of a public hearing was published in the ANCHORAGE DAILY NEws on January 8, 2008. 3. On January 24, 2008, the Commission received a request for a hearing. No other requests or comments were submitted to the Commission during the 30-day public comment period. 4. The Commission held the public hearing on February 14, 2008. During the hearing, the Commission requested additional information from Pioneer, and left the hearing record open until February 22, 2008. 5. On February 19, 2005, the Commission requested further technical information from Pioneer. 6. Pioneer submitted written responses to the Commission's requests on February 21, 2008. The hearing record closed February 22, 2008. FINDINGS: 1. Operator: Pioneer is the operator of the leases in the area proposed for development. 2. Project Area Pool and Formations Authorized for Enhanced Recovery: Enhanced recovery injection is proposed within the Oooguruk-Kuparuk Oil Pool, which is defined in Conservation • Page 2 Correlatim Depth Resistiviy Porosdy SP <MD ) esS(LL3 R PHIN(NPHp 30 MV 70 _ _ _ _ _ _ - _ - _ _ _ _ _ _ 2 OHMM 2000 .6 VN -0.15 GR TVDSS> ResM(ILM) RHOS 0 aPl 2~0 _ _ .2 OHMM 2000 65 GM~C 2.65 ~ _; T ~ ResD(ILD) DT(DTC) GR 'r'ellovv Gray , 2 OHMM 2000 4Q000 USAF 4D.000 ~.~i 00 41 J~ "G11~ ~~~~ F,III)~ • Area injection Order 33 April 11, 2008 Oooguruk-Kuparuk Oil Pool 16100 ~_ i_L- £1OU 5200 ~;~I~ Oooguruk-Nuigsut Oil Pool 6400 t;ar_ro 6500 ~,5~ 65170 F~,I)o -s~~ 15300 ~~~..::. s~ Figure 1. Kalubik No. 1-Type Well Log for Oooguruk-Kuparuk Oil Pool ~ ~ Figure 1 is presented for illustration purposes only. Refer to the Dual Laterolog/Micro Laterolog recorded in the Kalubik No. 1 exploratory well for the precise representation of the Oooguruk-Kuparuk Oil Pool. • • Area Injection Order 33 Page 3 April 1 1, 2008 Order No. 596. 1'he target injection zone is the Oooguruk-Kuparuk Oil Pool, which is correlative to the interval between the measured depths of 6,083' and 6,121' on the Dual Laterolog-Micro Laterolog recorded in the Kalubik No. 1 exploration well (see Figure 1). 3. Proposed Infection Area: Pioneer requests authorization to inject fluids for the purpose of enhanced recovery operations on lands in the OU. The proposed injection area includes portions of Township (T) 13N, Range (R) 7E and T 14N, R7E, Umiat Meridian (Figure 2). T 14N, R7E T; ;~4.j T1 R8E '~ 2'~ ~'° r Kuparuk C ,a_:. ~' ~,~, _ Oooguruk Unit--- - +• ; .~ ,: ~._. Oooguruk Drill Site ,~~ ~,, .._...; .. - ~14f~" . ' ~ _ ~ ~ ~. .~ E.r,zA,' Oooguruk-Kuparuk ;,' Development Area 11.90 \ 3 ~ ~~~ s e .i , +~s t f' rr~i A: t. E l c+. r ,. f. T 13N, R7E ~~ ~ T 13N, R8E C--T--~ p 2 4 Mites ~ Figure 2. Proposed Injection Area for Oooguruk-Kuparuk Oil Pool Z (highlighted in green) 2 This map was provided by Pioneer, and it is presented here for illustration purposes only. Refer to the legal description for the precise representation of the affected area. Area Injection Order 33 April 11, 2008 Page 4 4. Operators/Surface Owners Notification: All lands within the proposed development area are leased and lie within the OU. Two companies hold working interests in the proposed Oooguruk-Kuparuk Oil Pool: Pioneer and Eni Petroleum US LLC (Eni). The only affected landowner and surface owner is the State of Alaska, Department of Natural Resources. The affected operators are Pioneer, operator of the OU, and ConocoPhillips Alaska, Inc., operator of the Kuparuk River Unit (KRU), which lies immediately to the southeast of the OU. Pioneer provided a copy of the application for injection to all operators and surface owners within aone-quarter mile radius of the proposed injection wells. 5. Description of Operations: The Oooguruk-Kuparuk Oil Pool will be developed with five to eight horizontal wells, with aproducer-to-injector ratio of about 1:1. The production and injection wells will range in length from 3,000' to 5,000' within the reservoir. Production and injection wells will be parallel to one another in an alternating arrangement to form a line-drive flood pattern. Individual wells will be spaced 2,000' to 4,000' apart. The pool will be developed utilizing water injection as the enhanced recovery mechanism. Water injection is scheduled to begin shortly after production commences. Production from this pool will be commingled on the surface with produced fluids from other pools within the OU prior to shipment to the Kuparuk River Unit drill site DS-3H for processing. Annualized peak production rate for the Oooguruk-Kuparuk is expected to be between 2,000 barrels of oil per day (BOPD) and 8,000 BOPD. Annualized waterflood injection rates are expected to peak between 3,000 barrels of water per day (BWPD) and 12,000 BWPD. 6. Hydrocarbon Recovery: Estimates of original oil in place and recovery (in units of one million stock tank barrels or MMSTB) within the Oooguruk-Kuparuk development area are: Hydrocarbon Volume Low Estimate (MMSTB) High Estimate (MMSTB) Original Oil in Place (OOIP) 15 25 Primary Recovery (6% to 10% of OOIP) 1 2.5 Primary + Waterflood (26 to 34% of OOIP) 4 8.5 7. Ge lo~y: a. Stratigraphy: The Oooguruk-Kuparuk Oil Pool encompasses early Cretaceous-aged (Neocomian), transgressive sediments deposited within a marine shelf and shoreface environment directly atop the Lower Cretaceous Unconformity. This interval of bioturbated sandstones, siltstones and mudstones correlates directly to the basal portion of the Kuparuk C interval within the adjacent Kuparuk River Unit, and to the Kuparuk C interval in the Colville River and Milne Point Units. Within the OU, the Kuparuk C is generally concentrated and preserved in structural depressions and grabens on the downthrown side of syn-depositional faults, which range up to 200' in vertical displacement. Within the OU, the Kuparuk C interval ranges from 0' to about 55' thick. Along with mudstone and siltstone, it consists of very fine- to coarse-grained, fining-upward sandstone that has 5% to 25% glauconite, 10% to 35% siderite cement, and up to SO% clay matrix. Here, the Kuparuk C appears to have been deposited as part of a transgressive marine shoreface and shelf system. The sediments thicken locally on the Area Injection Order 33 ~ ~ Page 5 April 11, 2008 downthrown side of northwest-trending normal faults that occur within the development area. On the upthrown side of these same faults, and away from them, the Kuparuk C decreases in reservoir quality and becomes thin to absent. Kuparuk porosity ranges from 13% to 32%, and averages approximately 17%. Permeability ranges from 0.5 millidarcies (md) to 500 md, and averages approximately 50 and to 100 md. Average water saturation is about 30%. b. Structure: Within the Oooguruk-Kuparuk development area, the structure at Kuparuk level is anorthwest-plunging anticlinal nose centered in the southeastern-most corner of the OU, to the east of the Colville Delta No. 3 well and to the southeast of the Colville No. 2 well. The flanks of this structure are cut by northwest-trending normal faults that are more commonly downthrown toward the northeast. These faults were active during early Cretaceous time, and created accommodation space for accumulation of the Kuparuk C sediments. c. Trap Configuration: Well log and seismic information indicate that the Kuparuk C reservoir at the OU is best developed on the downthrown side of northwest-trending normal faults within the development area. The trapping mechanisms for oil within the Kuparuk reservoir are juxtaposition against non-reservoir rock across the northwest- trending normal faults and stratigraphic pinch-outs into very fine-grained, non-reservoir rock. The Oooguruk-Kuparuk Oil Pool is not in hydraulic communication with the underlying Oooguruk-Nuigsut Oil Pool. d. Confining Intervals: The Oooguruk-Kuparuk Oil Pool is overlain, in ascending order, by approximately 200' of marine shale assigned to the Kalubik Formation, about 100' of Highly Radioactive Zone (HRZ) shale, and then roughly 1,000' of shale assigned to the Hue Formation. The pool is underlain by about 150' to 350' of shale assigned to the Miluveach Formation, which separates and isolates the Oooguruk-Kuparuk Oil Pool from the underlying Oooguruk-Nuigsut Oil Pool. The overlying and underlying confining intervals are 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 Integrity and Well Design of Injection Wells: The casing programs for all injection wells will comply with 20 AAC 25.030. Pioneer requests a waiver from the requirements of 20 AAC 25.412(b) so that packers may be located more than 200' measured depth (MD) above the top of the injection zone to facilitate the completion and long-term operation of the well. However, packers will not be set above the confining zone. Tubing or other equipment will be designed and installed in accordance with 20 AAC 25.412. Cement-bond logs will be run to demonstrate isolation of injected fluids to the Oooguruk- Kuparuk reservoir as required by 20 AAC 25.412(d). Mechanical integrity tests will be performed in accordance with 20 AAC 25.412(c). Area Injection Order 33 • April 11, 2008 10. Type of Fluid /Source: Fluids requested for injection are: Page 6 a. source water from the Kuparuk sea water treatment plant; b. injection water provided by the Kuparuk River Field; c. produced water from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; and d. small amounts of the following fluids: fluids from reverse osmosis water treatment units, sumps, and hydrotests; rinsate from washing mud hauling trucks; excess well-work fluids; and treated camp waste water. These fluids will usually be injected into the ODS Class I disposal well, but may be blended with the fluids described in a, b, and c above, if necessary. The volume of these fluids is expected to be less than 0.1 %, and is not expected to affect the efficiency of recovery from the oil pool. 11. Water Compatibility with Formation: Pioneer conducted special core analyses on a limited number of core samples from the Kalubik No. 1 exploratory well. Pioneer reports that Kuparuk core samples are insensitive to formation and injection brine salinities and flow rates, and that fines did not migrate to impair permeability. 12. Infection Rates and Pressures: Injection rates will be adjusted to manage voidage for the reservoir. The maximum expected injection well rate is 10,000 BWPD, and the average injection well rate is expected to be 2,500 BWPD. Injection pressures are expected to range from approximately 1,800 psi to 2,000 psi at the wellhead. Injection will be managed to try to match voidage on an instantaneous basis. Original pressure of the Oooguruk-Kuparuk reservoir was measured at about 3,150 psi at 6,050' true vertical depth subsea, and the bubble point is about 2,600 psi. The proposed project will be operated to attempt to maintain the average pressure in the Oooguruk- Kuparuk Oil Pool within about 500 psi of original pressure. Average reservoir pressure will be maintained above the bubble point pressure. 13. Fracture Information: Although normal water injection pressure will be close to the Oooguruk-Kuparuk reservoir rock parting pressure, computer modeling indicates that, provided injection pressure is maintained below 2,900 psi, fractures will propagate to, but not into, the shale beds that bound the pool above and below. Therefore, injection fluids will remain within the Oooguruk-Kuparuk reservoir. 14. Absence of Underground Sources of Drinking Water: According to the August 18, 2006, findings and conclusions of the U.S. Environmental Protection Agency (EPA), portions of the aquifers beneath the ODS that lie within aone-half mile radius of two potential Class I waste disposal candidate wells to be drilled from the ODS, do not qualify as underground sources of drinking water.3 Formation water salinity calculations by the Commission using log data from four exploratory wells and methods compatible with the RWa method endorsed by the EPA confirm that there are no aquifers within the Affected Area that could serve as s Letter dated August 18, 2006 from Michael A. Bussell, Director of the Office of Compliance and Enforcement, U.S. Environmental Protection Agency, Region 10, to Mr. John Hellen of Pioneer Natural Resources Alaska, Inc., submitted by Pioneer to AOGCC as Attachment 1 to the Application for Proposed Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools, Oooguruk Unit, North Slope, AK, on January 8, 2008. Area Injection Order 33 • ~ Page 7 April 11, 2008 underground sources of drinking water.4 15. Mechanical Condition of Adjacent Wells: The Kalubik No. 1, Colville Delta No. 2, Ivik No. 1, and Oooguruk No. 1 exploration wells all penetrate the proposed Oooguruk-Kuparuk injection interval within, or in the near vicinity of, the Affected Area. All of these wells have been plugged and abandoned. All four of these wells have sufficient mechanical isolation to confine injected fluids to the target reservoir and prevent cross flow into other intervals. CONCLUSIONS: 1. The application requirements of 20 AAC 25.402 have been met. 2. Injection of water will significantly improve recovery. 3. There are no underground sources of drinking water beneath the proposed Affected Area. 4. Increasing the distance between the packer and top of the injection zone will not compromise well integrity, so long as the top of the production casing cement is at least 300' measured depth above the packer. 5. 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. 6. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 7. Seawater and injection water provided by the Kuparuk River Field and produced waters from the Oooguruk-Nuigsut and Oooguruk-Kuparuk Oil Pools will be compatible with the Oooguruk-Kuparuk reservoir. 8. Compatibility has not been demonstrated for mixtures of waters or the following fluids: fluids from reverse osmosis water treatment units, sumps, and hydrotests; rinsate from washing mud hauling trucks; excess well-work fluids; and treated camp waste water. 9. Reservoir pressure will be maintained above bubble point. 10. 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. 11. Sufficient information has been provided to authorize injection of water into the Oooguruk- Kuparuk Oil Pool for the purposes of pressure maintenance and enhanced oil recovery. /// /// /// /// /// /// a Colville Delta 1, Colville Delta 2, Kalubik 1, and Thetis Island 1 log data were analyzed using techniques consistent with EPA guidance document "Survey of Methods to Determine Total Dissolved Solids Concentrations," KEDA Project No. 30-956, prepared by Ken E. Davis Associates in 1988 and revised in 1989. Area Injection Order 33 April 11, 2008 NOW, THEREFORE, IT IS ORDERED that: Page 8 The underground injection of fluids for pressure maintenance and enhanced oil recovery is authorized in the following area, subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules: Affected Area: Umiat Meridian Townsh p, Range Sections _ 1, 2, 3, 4, 10, 11, 12, 13 and 14: ALL 9: NE/4 15: NE/4 T13N, R07E 23: NE/4 24: ALL 25: NE/4 25: S/2 SW/4 26: S/2 S/2 27: S/2 SE/4, NW/4 SE/4, SW/4 T14N, R07E 28: S/2 29: S/2 32, 33, 34, 35: ALL 36: S/2, NW/4 Rule 1 Authorized Infection Strata for Enhanced Recovery Authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery within the Oooguruk-Kuparuk development area into strata that are common to, and correlate with, the interval between 6,083' and 6,121' measured depth on the Dual Laterolog/Micro Laterolog recorded in the Kalubik No. 1 exploration well. Rule 2 Well Construction To facilitate wireline access, packers in injection wells may be located more than 200' MD above the top of the Oooguruk-Kuparuk Oil Pool; however, packers shall not be located above the confining zone. Production casing cement volume must be sufficient to place cement a minimum of 300' MD 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; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; and Area Injection Order 33 ~ ~ Page 9 April 11, 2008 d. tracer survey liquid to monitor reservoir performance. The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action. Rule 4 Authorized Infection Pressure for Enhanced Recovery Injection pressures must be maintained such that the injected fluids do not fracture the confining zones or migrate out of the approved injection stratum. Rule 5 Monitoring Tubing-Casing Annulus Pressure The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for Commission inspection. Rule 6 Demonstration of Tubin~/Casin~ 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 injection rate, operating pressure observation, test, survey, log, or other evidence, 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. • April 11, 2008 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. 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 is 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. ENTERED at Anchorage, Alaska, ., ~f : , '~~ , ~~ x, ~ . ` ~. ~, ~''~`s.~. April 11, 2008. T. S~am~unt, Jr., Chair Q'~ln as Conservation Commission Gas Conservation Commission Cathy P. oerster, Commissioner Alaska it and Gas Conservation Commission RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(x), 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. 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 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 / (,Y Barrow, AK 99723 ' ~~~ I /v ~ ~~ ~~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, April 11, 2008 4:05 PM Subject: AIO 33 (Ooogurek), AIO 34 (Ooogurek), CO 599 (Exploratory) Attachments: aio34.pdf; co599.pdf; aio33.pdf BCC:Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert 3 (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); '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 ; knelson@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'; 'Marguerite kremer'; 'many'; 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'inkm7200'; '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'; David Johnson; Joseph Longo; Maurizio Grandi; Tom Gennings Attachments:aio34.pdf;co599.pdf;aio33.pdf; Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 *Note new email address 4/11/2008 ~ L ,.-_a ~ ~ ~ ~ ~ ~ ~ n ~ ~ ~ ~ ~ ~ ~ ~ ~' SARAH PAL1N, GOVERNOR AI.ASBA OIL A1~TD GAS 333 W. 7th AVENUE, SUITE 100 C01~5ERQA7`IO1~T COMIIIISSIOI~T ~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 33.001 ADMINISTRATIVE APPROVAL AIO 34.001 Mr. Dale Hoffinan Pioneer Natural Resources Alaska 700 G Street, Suite 600 Anchorage, AK 99501 RE: Application to Amend Rule 3 of Area Injection Orders Nos. 33 & 34, Oooguruk- Kuparuk and Oooguruk-Nuigsut Oil Pools, Oooguruk Unit Dear Mr. Hoffman: In accordance with Rule 10 of Area Injection Order (AIO) 33, Oooguruk-Kuparuk Oil Pool, and AIO 34, Oooguruk-Nuigsut Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) grants a portion of the request of Pioneer Natural Resources Alaska (Pioneer) for administrative approval to use additional fluids for enhanced recovery. By application, dated March 11, 2009, Pioneer requests that the Commission approve the use of three additional sources of water for enhanced recovery injection purposes at the Oooguruk Unit. Due to circumstances beyond Pioneer's control, the sources of water authorized for enhanced recovery injection under Rule 3 of AIOs 33 and 34 will not be available for at least several additional weeks. Simulation results indicate that delaying water injection will adversely impact reservoir pressure and producing gas-oil-ratio and thus could reduce the near- and long-term recovery of hydrocarbons from the two pools. Accordingly, Pioneer has identified three possible additional water sources. The first source is Harrison Bay sea water, which is used to mix drilling mud for Oooguruk drilling operations. The second is the shallow source water wells which are used to feed the reverse osmosis (RO) unit that produces potable water for the Oooguruk camp. These two sources would be treated with biocide and oxygen scavenged prior to injection. The third potential source is effluent from the RO unit. The first source is essentially the same as the water that would come from the Kuparuk sea water treatment plant, which is an approved source under Rule 3 of AIOs 33 and 34, but is collected from a different location. The second source, the shallow source water wells, is also expected to be very similar to the water from the Kuparuk sea water treatment plant because they are very shallow wells, less than 100 feet measured depth, AIO 33.001 ~ • AIO 34.001 March 13, 2009 Page 2 of 3 and are believed to be charged from the Beaufort Sea. Laboratory analyses indicate that these sources are very similar to the already approved fluid. Because these two proposed sources are so similar to an already approved fluid, the water from these sources will very likely be compatible with the formation and reservoir fluids and will provide enhanced recovery benefits. The third proposed source, the effluent from the RO unit, has significantly more total dissolved solids than any of the fluids currently approved for enhanced recovery injection purposes, and therefore additional review is needed to determine whether this source is compatible with the formation and reservoir fluids and whether using it will provide an enhanced recovery benefit to the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools. 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 10 of AIOs 33 and 34, the Commission administratively amends the AIOs; to allow (as soon as possible) commencement of enhanced recovery injection operations, the Commission approves the injection of fluids from the first two sources. The Commission is not now making a decision on the RO effluent. Rule 3 of AI0 33 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; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; d. tracer survey liquid to monitor reservoir perfonnance; e. biocide-treated and oxygen-scavenged sea water extracted from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS); and f. biocide-treated and oxygen-scavenged the ODS shallow water source wells. The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action. Rule 3 of AIO 34 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; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; d. tracer survey liquid to monitor reservoir performance; e. biocide-treated and oxygen-scavenged sea water extracted from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS); f. biocide-treated and oxygen-scavenged the ODS shallow water source wells; and g. natural gas provided by the KRU CPF-3. The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action. AIO 33.001 AIO 34.001 March 13, 2009 Page 3 of 3 This administrative approval does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies. ENTERED Anchorage, Alaska, and dated March 13, ?009. ~~~~; ~. ~ ,,>y `~.. ...d ~ ~~ >~ ~, r°` ,.; ~~~._ - s ~~<~~ ~ ' ~///n/ ~~~~a^_, ,~, ~ ~~Ll Cathy P. oerster 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 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, dren 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 61ed. 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 Cotrunission 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 Coirunission 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. 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 Page 1 of 1 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'; 'Marquerite 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;aio33-001.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 s s 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 Bel! 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 pia ~ /e ~ -3/3,69 • i y~~ ' s ~ g ~ -~ t ~ ~ ~ ~ ~ SARAH PALIN, GOVERNOR ~ O ALA58A OII, Al`D GA5 333 W. 7th AVENUE, SUITE 100 CO1~T5ERQA'1`I011T COrII~1155I01~1T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AIO 33.002 ADMINISTRATIVE APPROVAL AIO 34.002 Mr. Dale Hoffman Pioneer Natural Resources Alaska 700 G Street, Suite 600 Anchorage, AK 99501 RE: Application to Amend Rule 3 of Area Injection Orders Nos. 33 and 34, Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools, Oooguruk Unit Dear Mr. Hoffman: In accordance with Rule 10 of Area Injection Order (AIO) 33, Oooguruk-Kuparuk Oil Pool, and Rule 1.0 of AIO 34, Oooguruk-Nuigsut Oil Pool, the Alaska OiI and Gas Conservation Commission (Commission) grants the request of Pioneer Natural Resources Alaska (Pioneer) for administrative approval to use additional fluids for enhanced recovery. By application, dated March 11, 2009, and received on March 13, 2009, Pioneer requests that the Commission approve the use of three additional sources of water for enhanced recovery injection purposes at the Oooguruk Unit. Due to circumstances beyond Pioneer's control, the sources of water authorized for enhanced recovery injection under Rule 3 of AIOs 33 and 34 will not be available for at least several additional weeks. Simulation results indicate that delaying water injection will adversely impact reservoir pressure and the producing gas-oil ratio and thus could reduce the near- and long-term recovery of hydrocarbons from the two pools. Accordingly, Pioneer has identified three possible additional water sources. The first source is Harrison Bay sea water, which is used to mix drilling mud for Oooguruk drilling operations. The second is the shallow source water wells, which are used to feed the reverse osmosis (RO) unit that produces potable water for the Oooguruk camp. These two sources would be treated with biocide and oxygen scavengers prior to injection. The third potential water source is effluent from the RO unit. On March 13, 2009, the Commission issued AIOs 33.001 and 34.001 approving the injection of seawater from Harrison Bay and water from the shallow source water wells at the Oooguruk Drill Site (ODS). The RO effluent has significantly more total dissolved solids than the water from the other sources approved for injection in the Oooguruk Unit (i. e., up to 100,000 mg/1 versus 40,000 to 70,000 mg/1). The RO effluent is more saline than the water from the other approved sources (i. e., up to 80,000 mg/1 versus 20,000 to 35,000 mg/1). Pioneer conducted core flood testing to evaluate potential formation damage due to injection water salinity and determined that waters measuring 100,000 mg/1 or less would not damage the formation. In the context of continuing production, Pioneer has presented reservoir simulation results that demonstrate water injection, including the use of RO AIO 33.002 AIO 34.002 March 20, 2009 Page 2 of 3 effluent, will have a significant impact on the producing gas-oil ratio, reservoir pressure, and recovery efficiency. Therefore, because the information available indicates that injecting RO effluent will improve recovery and will not damage the reservoirs, it is appropriate to permit injection of RO effluent into the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools for enhanced recovery purposes. Accordingly, pursuant to Rule 10 of AIOs 33 and 34, the Commission administratively amends AIOs 33 and 34 to allow for the injection of RO effluent for enhanced recovery purposes. Rule 3 of AIO 33 is amended to read: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk sea water treatment plant; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; d. tracer survey liquid to monitor reservoir performance; e. biocide-treated and oxygen-scavenged sea water extracted from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS); f. biocide-treated and oxygen-scavenged water from the ODS shallow water source wells; g. biocide-treated and oxygen-scavenged effluent from the ODS reverse osmosis unit; and h. mixtures of the fluids described in (e), (f) and (g) above. The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action. Rule 3 of AIO 34 is amended to read: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk sea water treatment plant; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; d. tracer survey liquid to monitor reservoir performance; AIO 33.002 • AIO 34.002 March 20, 2009 Page 3 of 3 e. biocide-treated and oxygen-scavenged sea water extracted from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS); f. biocide-treated and oxygen-scavenged water from the ODS shallow water source wells; g. biocide-treated and oxygen-scavenged effluent from the ODS reverse osmosis unit; h. mixtures of the fluids described in (e), (f) and (g) above; and i. natural gas provided by the KRU CPF-3. The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action. This administrative approval does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies. ENTERED at Anchorage, Alaska, and dated March 20, 2009. Daniel T. Seamount, Jr. Cathy . Foerster Chair Com issioner --i5~'~uf I . j j~'"~ Nor an W ly ner r ~'. j '" ~4 ,r 1`.~ ~jj ~ 4 l r 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), "[tJhe 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 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 lay ~~°~ ~~ ~~T3, ~,- Page 1 of 1 Colombie, Jody J (DOA) __ From: Colombie, Jody J (DOA) Sent: Friday, March 20, 2009 3:15 PM Subject: aio 33-002 and aio 34-002 Attachments: aio33-2.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@exxorunobil.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:aio33-2.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) 3/23/2009 • O ~ ~ a SEAN PARNELL, GOVERNOR ALASSA OII, A1~TD GAS 333 W. 7th AVENUE, SUITE 100 C01~5FiIiQA`I`IO1~T COMI~IISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 33.003 Mr. J. Patrick Foley Pioneer Natural Resources Alaska 700 G Street, Suite 600 Anchorage, AK 99501 RE: Application. to Amend Rule 3 of Area Injection Order No. 33 Oooguruk-Kuparuk Oil Pool, Oooguruk Unit Dear Mr. Foley: In accordance with Rule 10 of Area Injection Order No. 33 (AIO 33) for the Oooguruk- Kuparuk Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) GRANTS the request of Pioneer Natural Resources Alaska (Pioneer) for administrative approval to employ injection of glycol and water mixtures for enhanced recovery purposes. By application dated April 23, 2010, Pioneer requests authority to inject glycol and water mixtures for enhanced recovery purposes in the Oooguruk-Kuparuk Oil Pool of the Oooguruk Unit. Pioneer's request also notified the Commission of the unauthorized injection of glycol and water volumes in the Oooguruk-Kuparuk Oil Pool of the Oooguruk Unit during the second quarter of 2009 during commissioning of the Oooguruk injection water pipeline. That unauthorized injection is not addressed in this order. Non-hazardous fluids are authorized for injection at Oooguruk for enhanced oil recovery and reservoir pressure maintenance. AIO 33 provides for approval of other fluids by administrative action. Pioneer employed glycol and water mixtures during pressure testing and for freeze protection in pipelines that connect Oooguruk Island to shore. However, because of the layout of the facilities, all of the glycol and water mixtures cannot be removed from the pipelines. As a result, upon commencement of authorized injection operations, residual glycol and water mixture will be injected into the wells. Glycol and water mixtures have been authorized for injection for enhanced recovery purposes in other North Slope fields to maintain reservoir pressure and as a beneficial reuse of fluids as a sensible waste management practice. AIO 33.003 May 17, 2010 Page 2 of 3 • Pioneer's comparative well performance information demonstrates that injecting glycol and water mixtures has not had a detrimental impact on infectivity on well ODSK-38 which indicates the fluid is compatible with the formation. 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 10 of AIO 33 the Commission administratively amends Rule 3 of AIO 33 to allow the injection of glycol and water mixtures for enhanced recovery purposes by adding the following. i. non-hazardous glycol and water mixtures This administrative approval does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies. a` may. ~ s.,-.~ f "`~~ m~~ at Anchorage, Alaska and dated May 17, 2010. The A Daniel T Zount, Jr. Chair Commission Cathy . Foerster 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 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. z Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 18, 2010 3:16 PM To: 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood@marathonoil.com; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; 'Jason Bergerson'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); (foms2@mtaonline.net); (michael.j.nelson@conocophillips.com); (Von.L.Hutchins@conocophillips.com); Alan Dennis; alaska@petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; Dan Bross; dapa; Daryl J. Kleppin; David Boelens; David House; David Steingreaber; 'ddonkel@cfl.rr.com'; Deborah J. Jones; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Harry Engel; Jdarlington (jarlington@gmail.com); Jeff Jones; Jeffery B. Jones (jeff.jones@alaska.gov); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; Jon Goltz; Joseph Darrigo; Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Kovac; Mark P. Worcester; Marguerite kremer; 'Michael Dammeyer'; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker@alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Raj Nanvaan; Randall Kanady; Randy L. Skillern; rob.g.dragnich@exxonmobil.com; Robert A. Province (raprovince@marathonoil.com); Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; 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; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M; 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); Mahnken, Christine R (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) Subject: aio 33-003 Oooguruk-Kuparuk Oil Pool Attachments: aio33-003.pdf Jody .I. Colombie Special Assistant Alaska Oil and C:as C.'onservativn Commission 333 West 7th Avenzre, Suite 100 Anchorage, AK .9.9501 (907)?93-1221 (phone) (9071276-752 (fax) • Mary Jones David McCaleb George Vaught, Jr. XTO Energy, Inc. IHS Energy Group PO Box 13557 Cartography GEPS Denver, CO 80201-3557 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18th Street President 6900 Arctic Blvd. Golden, CO 80401-2433 PO Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Schlumberger Ciri Baker Oil Tools Drilling and Measurements Land Department 4730 Business Park Blvd., #44 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 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 Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99701 Soldotna, AK 99669-2139 Richard Wagner Bernie Karl North Slope Borough PO Box 60868 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99706 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 jug 5~~~ ZU ED ALASKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AIO 33.004 ADMINISTRATIVE APPROVAL AIO 34.004 Mr. Pat Foley Pioneer Natural Resources Alaska 700 G Street, Suite 600 Anchorage, AK 99501 RE: Application to Amend Rule 3 of Area Injection Orders No. 33 Oooguruk- KuparukOil Pool & No. 34 Oooguruk - Nuiqsut Oil Pools Oooguruk Unit Dear Mr. Foley: In accordance with Rule 10 of Area Injection Order (AIO) 33, Oooguruk - Kuparuk Oil Pool, and AIO 34, Oooguruk - Nuiqsut Oil Pool, the Alaska Oil and Gas Conservation Commission (Commission) GRANTS Pioneer Natural Resources Alaska's (Pioneer) request for administrative approval to employ seawater from the Prudhoe Bay Unit Seawater Treatment Plant for enhanced recovery at Oooguruk. At this time, the Commission DENIES, without prejudice, Pioneer's request to add methanol (< 100 bbls) as an enhanced recovery fluid. Due to a fuel gas line failure, ConocoPhillips Alaska, Inc. (CPAI) is unable to operate the Kuparuk Seawater Treatment Plant (STP). CPAI provides water from the plant to Pioneer to use for enhanced oil recovery (EOR) operations at Oooguruk. By electronic messages, dated November 3 and 4, 2010, Pioneer requested that the Commission approve methanol (< 100 bbls) as an FOR fluid should it be necessary to remove the water from the Oooguruk subsea water supply line. Based on additional information that normal seawater supply could be available over the coming weekend, Pioneer subsequently requested the authorization to use seawater from Prudhoe Bay Unit (PBU) Seawater Treatment Plant (STP) for enhanced recovery injection purposes at the Oooguruk Unit. Pioneer is proposing to truck seawater from PBU STP and pump it into the water supply line to the island to maintain a minimum flow until the normal water supply is restored. The Beaufort Sea is the raw water source for both seawater treatment plants and similar processes of filtering and de- aerating are employed in each plant. AIO 33.004 • • AIO 34.004 November 4, 2010 Page 2 of 3 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 10 of AIOs 33 and 34, the Commission administratively amends the Rule 3 authorizing seawater from Prudhoe STP to be employed for enhanced recovery in the Oooguruk - Kuparuk and Oooguruk - Nuiqsut Oil Pools. Rule 3 of AIO 33 is hereby amended to read as follows: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk or Prudhoe Bay sea water treatment plants; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk- Kuparuk and Oooguruk - Nuiqsut Oil Pools; d. tracer survey liquid to monitor reservoir performance; e. biocide - treated and oxygen- scavenged sea water extracted from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS); f. biocide - treated and oxygen- scavenged water from the ODS shallow water source wells; g. biocide - treated and oxygen- scavenged effluent from the ODS reverse osmosis unit; and h. mixtures of the fluids described in (e), (f) and (g) above. i. non - hazardous glycol and water mixtures The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action. Rule 3 of AIO 34 is hereby amended to read as follows: Rule 3 Authorized Fluids for Enhanced Recovery Fluids authorized for injection are: a. source water from the Kuparuk or Prudhoe Bay sea water treatment plants; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk - Kuparuk and Oooguruk - Nuiqsut Oil Pools; d. tracer survey liquid to monitor reservoir performance; e. biocide - treated and oxygen- scavenged sea water extracted from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS); f. biocide - treated and oxygen- scavenged water from the ODS shallow water source wells; g. biocide - treated and oxygen- scavenged effluent from the ODS reverse osmosis unit; AIO 33.004 AIO 34.004 November 4, 2010 Page 3 of 3 h. mixtures of the fluids described in (e), (f) and (g) above; and i. natural gas provided by the KRU CPF -3. j. Injection of glycol and water mixtures is approved within the affected areas of AIO 34 in the Oooguruk - Nuiqsut Oil Pool until December 31, 2010. i. Quarterly injectivity plots must be provided to the Commission for each Nuiqusut well receiving a mixture of glycol and water by July 15, 2010 and January 17, 2011. ii. A separate application for permanent approval for injection of mixtures of glycol and water for enhanced recovery purposes into the Oooguruk- Nuiqsut Oil Pool must be made no earlier than October 31, 2010 The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action. This administrative approval does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies. r KA ENTERED at Anchorage,,Alaska, d dated November 4, 2010. Jo o a C thy Fo rster om ner 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 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, November 04, 2010 4:04 PM To: (foms2 @mtaon line. net); ( michael .j. nelson @conocoph ill ips.com); (Von. L. Hutchins@conocophillips.com); AKDCWellintegrityCoordinator; Alan Dennis; alaska @petrocaic.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 Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington @g mail. 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; Mikel 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.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; Tamera Sheffield; 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); Yereth Rosen; Aaron Gluzman; Bettis, Patricia K (DNR); Dale Hoffman; David Lenig; Gary Orr; Jason Bergerson; Joe Longo; 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: Revised and Amended aio 1 -007 and aio 1 -009 (DIU) and aio 33 -004 and aio 34 -004 (Oooguruk- Kuparuk and Oooguruk - Nuiqsut) Attachments: aio33- 004.pdf; aiol -007 revised and amended.pdf; aiol -009 revised and amended.pdf; aio34- 004.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 best 71h Avenue, Suite 100 Anchorage, AK 9950.1 (907)793 -1221 (phone) (907)276 -7542 (fax) i 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 Schlumberger CIRI Drilling and Measurements Land Department Baker Oil ho o fs 2525 Gambell St, #400 P.O. Box 93330 795 E. 94 Ct. Anchorage, AK 99515 -4295 Anchorage, AK 99503 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 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 Bernie Karl P.O. Box 60868 K &K Recycling Inc. Fairbanks, AK 99706 P.O. Box 58055 Fairbanks, AK 99711 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 33.005 AREA INJECTION ORDER 34.011 Mr. Keith Lopez ENI US Operating Co. Inc. 3800 Centerpoint Dr. Suite 300 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission RE: Application to Amend Rule 3 of Area Injection Order No. 33 Oooguruk-Kuparuk Oil Pool, Oooguruk Unit Docket No. AIO-20-001 Application to Amend Rule 3 of Area Injection Order No. 34 Oooguruk-Nuiqsut Oil Pool, Oooguruk Unit Docket No. AIO-20-002 Dear Mr. Lopez: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax. 907.276.7542 Wvna.aogccalaska.gov In accordance with Rule 10 of Area Injection Order (AIO) 33 for the Oooguruk-Kuparuk Oil Pool (OKOP) and AIO 34 for the Oooguruk-Nuiqsut Oil Pool (ONOP), the Alaska Oil and Gas Conservation Commission (AOGCC) GRANTS the request of ENI US Operating Co. Inc. (ENI) for approval to inject into the OKOP and ONOP, for the purpose of avoiding operational problems, a 60/40 methanol to water mixture used in water supply line commissioning. In an application, dated February 5, 2020, that the AOGCC received on February 11, 2020, ENI requested approval to inject methanol and water mixtures for enhanced oil recovery (EOR) purposes in the OKOP and ONOP, which are in the Oooguruk Unit (OU). This activity would be part of the commissioning process of a new water supply line from the Kuparuk River Unit. ENI proposes to pump approximately 400 bbls of a 60/40 methanol to water mixture through the new pipeline to warm up the pipeline, thereby mitigating the risk of freezing. This methanol/water slug would precede normal seawater throughput in the pipeline. To avoid operational disruptions and complications arising from the need otherwise to divert the mixture to tanks, to shut down operations, and to reconfigure operations to restart injecting seawater into the EOR wells, ENI requests approval to pump the mixture down the EOR wells in the OKOP and ONOP. The methanol/water mixture would provide an EOR benefit by helping to maintain reservoir pressure. Also, approving ENI's request would avoid increasing the chances that the mixture spills and, during the changeover, that pipes freeze. AIO 33.005 AIO 34.011 March 18, 2020 Page 2 of 3 The AOGCC does not foresee the methanol/water mixture having any adverse reactions with the formations or formation fluids that would impair injectivity because when, on other occasions, a 60/40 methanol to water mixture was pumped into the OKOP and ONOP injection wells to protect them from freezing while shut in, no injectivity issues were observed when normal injection operations resumed and the freeze protect fluids were pumped into the OKOP and ONOP ahead of the non -mixture EOR injection fluids. Nor does the AOGCC foresee any other problems, including unanticipated fluid movement into sources of freshwater, because (1) ENI does not propose mechanical changes to the EOR wells, and (2) the injections will occur in accordance with the established injection pressure limitations. The AOGCC has determined that the proposed action would (1) provide an EOR benefit and not harm the reservoir and, therefore, would not promote waste, (2) not jeopardize correlative rights because all affected lands are in the OU, (3) is based on sound engineering and geoscience principles as evidenced by the operational advantages the work would provide and the lack of damage to the injection zones, and (4) not increase the risk of freshwater contamination due to the lack of mechanical work on the wells and the adherence to the existing injection pressure limitations, which are designed to ensure injection fluid containment. Consequently, the AOGCC can decide ENI's request without notice and a public hearing. For these reasons, in accordance with Rule 10 of AIO 33 and AIO 34, the AOGCC amends Rule 3 of AIO 33 and AIO 34 to allow the injection of the 60/40 methanol to water mixture used in commissioning the new seawater supply pipeline into the OKOP and ONOP EOR wells. DONE at Anchorage, Alaska and dated March 18, 2020. Daniel . Seamount, Jr. Je e L. Chmielowski Commissioner Counissioner AIO 33.005 AIO 34.011 March 18, 2020 Page 3 of 3 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. February 5, 2020 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 ernni ins ®perrwrinng eni us operating co. inc. 3800 Centerpoint Dr., Suite 300 Anchorage, AK 99503 - U.S.A. Tel. 907-865-3300 Fax 907-865-3380 RECEIVED AIO No. 33 and AIO No. 34 Authorized Fluids Administrative Approval Request Dear Commissioner Chmielowski: FEB 11 2020 AOGCC ENI US Operating Co. Inc., is requesting per Rule 10, Administrative Approval to allow injection of methanol used in the commissioning of the water injection line from Conoco's STP to OTP into the Kuparuk and Nuitsqut injectors at ODS. We currently expect to commission the Seawater Injection System Lite (SWISL) in mid to late March 2020. It is estimated that the line will be initially flooded with 400 bbls of 60/40 (methanol to water) and pushed down the line with treated seawater from Conoco's STP. This will be used to warm up the line and avoid any freezing issues during startup. It is ENI's desire to push this methanol and water mixture down the injectors at ODS to avoid operational disruptions and complications. The injectors open during commissioning are expected to be a mixture of Kuparuk and Nuitsqut. ENI does not see there to be any compatibility or formation damage concerns with this fluid and the formations it will come in contact with. Normal ENI operations use the same 60/40 methanol mixture for injector freeze protects, hydrate control and mitigation, and wellwork activities. Please contact me at (907) 865-3316, or by email at keith.lopez@eni.com if you have any questions or need any additional information. Sincerely, Keith Lopez Senior Production Engineer ENI US Operating Co, inc. • ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF PIONEER ) Area Injection Order No. 33 NATURAL RESOURCES ALASKA, INC. ) for an order authorizing underground ) Oooguruk Field injection of fluids for enhanced oil recovery ) Oooguruk Unit in the Oooguruk-Kuparuk Oil Pool, ) Oooguruk-Kuparuk Oil Pool Oooguruk Unit, Beaufort Sea, Alaska ) April 11, 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 11th day of April, 2008. BY DIRECTION OF THE COMMISSION Jody J. Cglbmbic ` Special Assista>,t to the Commission 410 Page 1 of 3 Maunder, Thomas E (DOA) From: Foley, Pat [Pat.Foley @pxd.com] fA Li Sent: Thursday, November 04, 2010 9:25 AM 1 To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: Hart, David Subject: RE: AIO 33 - McOH Injection - Oooguruk Water Supply Line Evacuation We have learned that KRU water systems may be up and running as early as this weekend. We now plan to truck seawater from the PBU STP over to Oooguruk to bump our water supply line with 120 degree seawater. The water will ultimately be injected into the Oooguruk - Kuparuk Oil Pool through the ODS K -38i. A10 33 does not specifically allow PBU STP seawater as an approve fluid for EOR. Pioneer asks for an administrative approval to allow PBU STP seawater as an approved fluid under A10 33. The current planned operation will utilize roughly 550 bbl of PBU STP seawater. Should similar operational problems arise in the future we would like to be able to use similar volumes as needed in the future. Pioneer will proceed with the activity as we discussed in this morning's phone conversation and we look forward to you reply email or letter confirming the Commission's administrative approval. Thank you for your swift and favorable assistance in this matter. Please call me or Dave if you have any questions. Best regards, Pioneer Natural Resources Alaska, Inc. Manager of Land and External Affairs 700 G St., Ste 600, Anchorage, AK 99501 Office (907) 343.2110 Mobil (907) 830 -0999 Fax (907) 343 -2190 Email: pat.foley@pxd.com From: Foley, Pat Sent: Wednesday, November 03, 2010 4:04 PM To: Jim Regg aim.regg @alaska.gov); Maunder, Thomas E (DOA) Cc: Hart, David Subject: AIO 33 - McOH Injection - Oooguruk Water Supply Line Evacuation 11/4/2010 Page 2 of 3 As you may know the KRU has experienced damage to its gas distribution system that delivers fuel gas to the STP. Oooguruk receives all of its injection water from the KRU at DS -3A under terms of a Production Processing and Services Agreement. All water deliveries to KRU DS -3A have been suspended until further notice. Pioneer intends to purge its water supply line from KRU DS -3A to ODS within the next 24 hours. The water line evacuation procedure is as follows: 1. Place a methanol (MeOH) slug of greater than 10 bbls into water supply line at DS -3A 2. Insert pig into DS -3A pig launcher 3. Place a second McOH slug of greater than 10 bbls into water supply line at DS -3A 4. Insert a second pig into DS 3 -A pig launcher 5. Push pigs and McOH slugs with gas 6. Remove pigs from the ODS pig receiver upon arrival Total McOH volume will be less than 100 bbls. As the pigs are close to arriving at the ODS all water injection will be diverted to the ODS K -38i, if KRU gas pressure has sufficient energy to allow injection of water into K -38i. Some or all of the McOH placed into the water supply line may ultimately be injected into the Oooguruk - Kuparuk Oil Pool at the time waterflood injection resumes into the ODS K -38i. McOH is not an authorized fluid for enhanced recovery under AIO 33. The amount of McOH that will be injected into the Kuparuk Oil Pool is de minimis (less than 100 bbls) when compared to the total fluids injected for EOR. The evacuation of the water supply line is a freeze protect operation necessary to ensure the line's mechanical integrity while water deliveries to the ODS are temporarily suspended during periods of cold weather. The McOH will serve the dual purpose of acting as a freeze protect medium for the ODS K -38i. The intended operation and the resulting fluid injection is standard oil field practice. Pioneer has obtained guidance in the past for the Commission indicating that activities such as this do not constitute a misinjection and that no additional approval is required from the Commission. Out of an abundance of caution, Pioneer informs the Commission of its intended freeze protect operation and the ultimate injection of McOH into the Oooguruk- Kuparuk Oil Pool through the ODS K -38i and seeks your confirmation that the intended activity will not constitute a misinjection under AIO 33. Your response email would be appreciated at your soonest opportunity as the operation will be conducted promptly. Please contact the undersigned, or Dave Hart, Pioneer Alaska Operations Manager, if you have any questions on this matter. J. Patrick Foley Pioneer Natural Resources Alaska, Inc. Manager of Land and External Affairs 700 G St., Ste 600, Anchorage, AK 99SOI Office (907) 343 -2110 Mobil (907) 830 -0999 Fax (907) 343 -2190 Email: pat.foley @pxd.com 11/4/2010 Page 3 of 3 Statement of Confidentialit This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e -mail and delete the message and any attachments. 11/4/2010 NTWOI WiLM • Page 1 of 3 Maunder, Thomas E (DOA) From: Foley, Pat [Pat.Foley@pxd.com] Sent: Friday, May 14, 2010 8:11 AM To: Maunder, Thomas E (DOA) Cc: Roby, David S (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Hart, David; jwleppo@stoel.com; Kleinman, Mark; Sturtevant, Craig Subject: Re: Oooguruk AIO Modification Request Thank you. Pat from: Maunder, Thomas E (DOA) <tom.maunder@alaska.gov> To: Foley, Pat Cc: Roby, David S (DOA) <dave.roby@alaska.gov>; Davies, Stephen F (DOA) <steve.davies@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; Hart, David; Leppo, Jeffrey W. <JWLEPPO@stoel.com>; Kleinman, Mark; Sturtevant, Craig Sent: Fri May 14 11:09:02 2010 Subject: RE: Oooguruk AIO Modification Request Pat, et al, Thanks for clarifying the notice dates. Your requests for AIO amendments are being finalized. We will notify you when they are completed. Tom Maunder, PE AOGCC Prom: Foley, Pat [mailto:Pat.Foley@pxd.com] Sent: Friday, May 14, 2010 8:04 AM To: Maunder, Thomas E (DOA) Cc: Roby, David S (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Hart, David; Leppo, Jeffrey W.; Kleinman, Mark; Sturtevant, Craig Subject: RE: Oooguruk AIO Modification Request Tom, I response to your questions: 1. The fluid balance below accurately summarizes what Pioneer believes has occurred with respect to the glycol/water mixture. As reflected in the original information, some of the figures are measurements in which we have high confidence, and some of the figures are estimates based upon experience and conservative judgments. 2. Besides the September 2, 2009 notice from Joey Hall, Pioneer provided AOGCC of notice regarding injection of glycol at the meeting with Cathy Foerster on April 22, 2010, followed by written notice via email on April 23, 2010. These are the only notices from Pioneer to AOGCC regarding injection of the glycol/water mixture of which we are aware. Again, I am happy to address all of the Commissions questions and concerns. I am hopeful that a formal response to our AIO expansion request is in the works and will be swiftly forthcoming. Anything you can share regarding timing and likely outcome will be appreciated. 5/17/2010 Thank you for working this issue with priority, as our desire to initiate WAG flood is strong. ~.~~~ Pioneer Natural Resources Alaska, Inc. Manager of Land and External Affairs 700 G St., Ste 600, Anchorage, AK 99501 Office (907) 343-2110 Mobil (907) 830-0999 Fax (907) 343-2190 Email: pat.foley@_pxd.com Page 2 of 3 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, May 13, 2010 4:29 PM To: Foley, Pat Cc: Roby, David S (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Hart, David; Leppo, Jeffrey W.; Kleinman, Mark; Sturtevant, Craig Subject: RE: Oooguruk AIO Modification Request Pat, et a1, Thanks for the information. Here is the fluid balance I determine from your document. Starting glycol/water mix volume: 266, 000 gallons Transferred to others: 190, 000 gallons Remainder: 76, 000 gallons Used for other purposes: 5, 419 gallons Remainder: 70, 581 gallons Injected into ODSK-38 (5/2009): 35, 331 gallons Injected into ODSK~8 (5128/09): 9,596 gallons Remainder: 25,654 gallons Residual removed via gas lift: 4,125 gallons Remaining in gas line: 4, 125 gallons Remainder: 17, 404 gallons Transferred to Pollard: 1, 150 gallons Remainder: 16, 254 gallons Final transfer to Price Gregory: 16, 254 gallons The notification of possible mis-injection of freeze protection fluids was given September 2, 2009, Was there another notification made to the Commission regarding the glycol/water volumes injected into OSDK-38? 1 have not found any such notice in our files. Thanks in advance, Tom Maunder, PE AflGCC From: Foley, Pat [mailto:Pat.Foley@pxd.com] Sent: Wednesday, May 12, 2010 10:49 AM To: Maunder, Thomas E (DOA) Cc: Roby, David S (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA); Hart, David; Leppo, Jeffrey W.; Kleinman, Mark; Sturtevant, Craig 5/17/2010 i Subject: RE: Oooguruk AIO Modification Request Tom, Please see the attached document that responds to your questions. If you have further questions please call me. ~.~.~~ Pioneer Natural Resources Alaska, Inc. Manager of Land and External Affairs 700 G St., Ste 600, Anchorage, AK 99501 Office (907) 343-2110 Mobil [907) 830-0999 Fax (907) 343-2190 Email: pat.foley_C?pxd.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, May 10, 2010 4:22 PM To: Foley, Pat Cc: Roby, David S (DOA); Davies, Stephen F (DOA); Schwartz, Guy L (DOA) Subject: FW: Oooguruk AIO Modification Request • Pat, As I mentioned when we spoke a few moments ago, a few additional questions have developed. Page 3 of 3 Ina 9/2/09 email (copy attached) Joey Hall informed Jim Regg of a possible misinjection of freeze protection fluids (which included glycol, diesel and crude oil) and that the volume "...could be no more than 120 bbls (5040 gallons). In the response it was communicated that freeze protection using diesel, crude or glycol was a routine activity necessary to preserve well integrity. In your latest application to modify the AIOs it is stated that about 49,000 gallons of a 50/50 glycol/water mixture was injected. 1) Is the originally estimated 5040 gallons included in the 49,000 gallons? 2) Were there multiple separate instances of where about 5040 gallons of glycol/water mixtures was injected or was the remaining ~ 44,000 gallons injected at one time? 3) If there were multiple separate injection events, was it for freeze protection? Thanks in advance, Tom Maunder, PE AOGCC Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. 5/17/2010 • Page 1 of 2 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, September 02, 2009 11:46 AM To: 'Hall, Joey' ' ~ t! Subject: RE: Possible Misinjection Notice Freeze protecting injection wells in arctic work environment is necessary to ensure a well's continued mechanical integrity while shut in for an extended period of time. As we understand this, the feeeze protect fluid (e.g., diesel, dead crude, or glycol) will be pushed out of the tubing and into the formation with the commencement of FOR injection. This is a standard procedure for freeze protecting wells. Flow back of the fluids might be possible but represent concern with increased handling and storage and the use of extraneous energy (gas lift) to displace the diesel back to surface. As such we consider the displacement of freeze protect fluids into the formation upon commencement of injection to be incidental to the operation of the well. The freeze protect fluid should be compatible with the formation and enhanced recovery fluids injected in the formation. There is no need for additional approval and the displacement of freeze protect fluids from ODSK-38 as described in your notice does not constitute a misinjection. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Hall, ]oey [mailto:7oey.Hall@pxd.com] Sent: Wednesday, September 02, 2009 10:36 AM To: Regg, James B (DOA} Cc: Foley, Pat; Smith, Bonnie; Hall, Joey CAD SK-3~ Subject: Possible Misinjection Notice ~ ~j$ - (~ Jim, lt)Pf~=~j~c:l-a~- In arecent review of our operations, we determined that it is possible and even probable that glycol, diesel and Oooguruk crude oil have been injected into the Oooguruk Kuparuk Pool down hole through our injection well (ODSK 38i) .This can happen following an event where freeze protection of piping or a well becomes necessary. In this case, it is not practical to evacuate the freeze protect fluid from the piping or wellbore prior to resuming operations; thus, the fluid would get injected into the reservoir. Any injection was a result of operational practices and not an intentional disposal or purposeful injection. This note serves two purposes: 1. To notify the AOGCC that a misinjection has likely occurred. It is not possible for us to quantify the amount of liquid injected but we expect that it could be na more than 120 bbls. 2. To request a path forward allowing the use of glycol, methanol, diesel or Oooguruk crude for freeze protection with the understanding that it would be injected into the reservoir once normal operations resume. In our initial Areawide Injection Order applications for both the Nuiqsut and Kuparuk Pools we included a request to inject small blended amounts of non-hazardous fluids (i.e. hydrotest fluids, rinsate, etc.). The Inject Orders issued by the Commission authorized a narrow and specific list of compatible fluids 9/2/2009 ~ .. _ .~ Page 2 of 2 authorized for injection. We seek your guidance regarding an application to expand the allowed injection fluids to better match real oil field operation practices. Please feel free to contact me if you need additional information. Regards, J. D. "Joey" Hall Operations Manager Pioneer Natural Resources Alaska, Inc. Phone: 907.343.2120 Mobile: 907.529.1728 Email: ioey.hall@pxd.com 9/2/2009 • Is the on ig Wally estimated 5,040 gallons included in the 49,000 gallons? Pioneer's investigation has led it to conclude that of the 120 bbls reported by Joey Hall to AOGCC as injected in 2009 for freeze protection, most of the freeze protestant, if not all of it, was diesel. The statement, "we determined that it is possible and even probable that glycol, diesel and Oooguruk crude oil have been injected" was intended to broadly cover the range of possible injection fluids. Glycol was included in the list out of an abundance of caution because glycol is a freeze protection fluid in common usage on the North Slope. However, through our investigation we have not found evidence. of any measurable volume of glycol that was placed into wells for freeze protect purposes. Therefore, when we present a more complete glycol inventory we will not attribute any glycol/water mixture usage, including any injection of glycol/water mixture, to use as freeze protestant as described in Joey Hall's 2009 email. 2. Were there multiple separate instances of where about 5040 gallons of glycol/water mixtures was injected or was the remaining ~ 44,000 gallons injected at one time? As explained above, Pioneer does not believe that any measurable volume of glycoUwater mixture was in fact used for freeze protection and injected as addressed in Joey Hall's email and as subsequently authorized by the AOGCC. There have been multiple events involving the return of a well to service and the resulting injection of freeze protestant fluids; however, the fluids involved would have been primarily, if not exclusively, diesel. The volume reported by Joey Hall with respect to freeze protestant was his best estimate of the total amount of freeze protestant injected due to multiple events to that point in time. 3. If there were multiple separate injection events, was it for freeze protection? Within the next week, Pioneer will be providing to AOGCC, as well as to EPA and ADEC, a detailed response to the broad range of concerns raised by a former employee. That response will include a very detailed discussion of glycol use and injection. The following is an excerpt from the more detailed letter. Pioneer acquired six 32,000 gallon tanks (maximum total volume of 192,000 gallons or 5,000 barrels) and installed them at the OTP within a secondary containment area. Virgin glycol was purchased in Apri12007 for use in hydrotesting the subsea pipelines after they were constructed. The glycol was purchased in a 90/10 concentration and diluted to a 50/50 glycol/water mixture for use. Records associated with the hydrotesting confirm that the 12-inch three-phase production flowline, and the 2-inch diesel/mineral oil supply pipeline were hydrotested in May 2007 and pigged to remove residual glycol. The mixture was transferred into the 8-inch and 6-inch_pipelines for hydrotesting. After hydrotesting of these lines, and with the glycol/water mixture still_inahe_lnes, custody of the 8-inch and 6-inch lines was transferred from H.C. Price to Pioneer. Pioneer has assembled a history of the uses of this glycol/water mixture after transfer of custody to Pioneer. Some of the figures in the assembled history are • reasonably certain~e ~ the starting volume of 26b 000 gallons and the ending volume of 0 gallons). Other figures cannot be known with certainty and are estimated by Pioneer based upon the available information and Pioneer's best judgment. In brief, the key events and uses of the glycol/water mixture have been as follows: • The total measured volume of the glycol/water mixture used for hydrotesting of the 8-inch and the 6-inch pipelines is 266,OOO.gallons. ____~w_ Accordingly, for purposes of accounting for the disposition of the glycol/water mixture, this volume is the starting point as of Mav 2007. • Between May 2007 and Apri12009, x190,000 measured gallons of the 1 col/water mixture and r of the be r ere transferred to third- parties for beneficial reus 1 • An additional estimated 5,419 gallons were used for various purposes (and not injected) not directly pertinent to here (except for in accounting for all of the glycol/water mixture). • In-M~' 2009, Pioneer commenced waterflood injection via FOR Well K- 38iusing seawater supplied by ConocoPhillips via the KRU seawater treatment plant. Pioneer believes that an estimated residual volume of 35,331 gallons of the glycol/water mixture remained in the 8-inch ~~ ~ ~~~s seawater supply line as a result of prior hydrotesting and warm-up of the 8-inch pipeline. This residual fluid was injected into the Kuparuk formation via Well K-38i with the commencement of waterflood injection. On May 28, 2009, during a shutdown of the seawater supply line, an uncertain quantity of the remaining glycol/water mixture from the one OTP storage tank in use was pumped into the de-pressured line. The intent of the operators involved was to beneficially reuse this non- hazardous glycol/water mixture as an FOR fluid in lieu of disposing of it into the Oooguruk Class I disposal well. Pioneer estimates that the maximum volume of glycol/water mixture that could have been pumped into the seawater supply line was 9,596 gallons. There is some reliable ~~ ~~~~information to suggest that a smaller volume than the maximum was actually pumped into the pipeline; however, Pioneer is not able to reliably determine the actual quantity of fluid. Pioneer believes that the ~~~~~~` ~n~~L~\~ ~~e~~ ~7 ~ 1 rr~ ~~ 7° -~-----~ ~`~ ~ ~ ~ ~n'~c7h`~\5 glycol/water mixture pumped into the seawater supply line on May 28, 2009 was injected into the Kuparuk formation via Well K-38i on May 29, 2009 after the seawater supply line was put back into service.Wrv~~W~~~ `` 1 42,000 gallons were originally borrowed from H.C. Price and were then returned to H.C. Price in May 2007; 24,000 gallons was sold to ConocoPhillips in February 2009; and 124,000 gallons (and 4 of the original beer tanks) were sold to Price Gregory in April 2009. • • Pioneer estimates that approximately one-half of the estimated volume of residual glycol/water mixture in the gas supply pipeline - 4,125 gallons - was stripped from the 6-inch line in June 2009 during gas lift operations to support Nuigsut formation development. The glycol/water mixture was circulated in the well bore with the gas and then transported as part of the production stream to processing facilities where it was separated from the crude oil. Pioneer estimates that approximately 4125 gallons of residual glycol/water mixture remain in the 6 inch gas. sunnly nipel:__ ine_at this time.2 As one outcome of its investigation of allegations regarding Oooguruk operations, Pioneer determined that the remaining glycol/water mixture in the one OTP storage tank was a greater source of potential problems than of potential use/value for operations. A preference for beneficial reuse of the remaining volume was established rather than disposal in the Oooguruk Class I well. Accordingly, in March 2010, a measured volume of 1,150 gallons of the remaining glycol/water mixture was transferred to Pollard vWireline, Inc.. On April 6, 2010, all of the remaining glycol/water mixture (a measured volume of 16,254 gallons), and the two remaining beer tanks, were transferred to Price Gregory. Price Gregory has removed the tanks and, theglycol/water mixture from the OTP. ._ _ . a The above information differs from and corrects the record in one respect from the notice previously provided to AOGCC. Pioneer's notice to AOGCC states that approximately half of the residual glycol/water mixture that remained in the 6-inch gas supply line (i.e., 4,125 gallons) is estimated to have been injected into the Nuiqsut formation during gas lift operations. This statement is in error because, as explained above, gas and the glycol/water mixture stripped from 6-inch line were pumped into the well bore and would have been transported with the production stream to the surface and on to KRU processing facilities. For this reason, the referenced 4,125 gallons of glycol/water mixture were never injected as an FOR fluid into any formation. As a result of this correction, the total volume of glycol/water mixture injected without prior AOGCC authorization is approximately 45,000 gallons Winstead of approximately 49,000 gallons originally reported to the AOGCC).-Moreover, all of the mixture was injected into the Kuparuk formation only. - -----~ ~~ --~~ ~~..... ,. . . Page 1 of 3 Maunder, Thomas E (DOA) From: Roby, David S (DOA) Sent: Tuesday, May 04, 2010 1:27 PM To: Maunder, Thomas E (DOA) Cc: Davies, Stephen F (DOA); Regg, James B (DOA) Subject: RE: Oooguruk AIO Modification Request Attachments: AIO 033.pdf Looking at the data provided by Pioneer I did not see any discernible difference in infectivity after the glycol was previously injected in the ODSK-38i well, so glycol does not seem to pose a compatibility problem with this formation. However, there is no data available for the Nuiqsut reservoir so I would recommend proceeding with caution (i.e. granting a conditional approval that could be made permanent at a later date once some data on glycol injection into the Nuiqsut formation is available). Looking through the files I did find something interesting though. In an email from Joey Hall to Jim dated 9/2/09 (see attached) Pioneer stated that it was impossible for them to quantify the volume of liquid (which was freeze protection fluids comprised of glycol, diesel, and crude oil) that was injected in the "misinjection" incident but did say "...we expect it could be no more than 120 bbls." However, in their recent application they state that "... approximately 49,000 gallons of a 50/50 mixture of water and glycol" was injected. This is a significantly larger, nearly 10 fold, volume than what was previously reported. The difference could be due to the fact that additional such injections took place after their initial report that Pioneer did not report because in an email from Jim to Joey Hall also dated 9/2/09 Jim informed them that what they had done was incidental to the operation of the well and therefore did not require additional approval and did not constitute a misinjection. So this begs a couple of questions: 1) If we have already told them that this type of injection is considered incidental to the operation of the well and therefore not a misinjection why are they now asking for approval to do this and are also asking for a retroactive approval for the prior "misinjection"? 2) Was there only one instance of the "misinjection", in which case Pioneer seriously understated the volumes involved in their initial notification, or have there been several? Dave Roby (907)793-1232 m: Foley, Pat [mailto:Pat.Foley@pxd.com] Sen . uesday, May 04, 2010 11:39 AM To: Mau r, Thomas E (DOA) Cc: Bond, An • Foerster, Catherine P (DOA); Roby, David S (DOA); Davies, Stephen F (DOA); L effrey W. Subject: RE: Ooo uk AIO Modification Request Tom, Please see the requested backup mate The glycol analysis are not on actual sam oft lycol in the gas supply line, but are identical in nature and operational history. It is not pos ' to collect a samp urrently resident in the line. We believe that ycol miss-injection has gone into the Kuparu it pool through the K-38i. Please see the attache r book containing injection history information. We belie that the data and plots demonstrate e well's ability to accept fluids has not changed as a result of the fluff 'ection. 5/8/2010 Page 1 of 3 Maunder, Thomas E (DOA) From: Foley, Pat [Pat.Foley@pxd.com] Sent: Tuesday, May 04, 2010 11:39 AM To: Maunder, Thomas E (DOA) Cc: Bond, Andy; Foerster, Catherine P (DOA); Roby, David S (DOA); Davies, Stephen F (DOA); Leppo, Jeffrey W. Subject: RE: Oooguruk AIO Modification Request Attachments: Glycol Analysis 03-12-10.pdf; Glycol Analysis 03-25-09.pdf; K-38i Injection Ver2007.x1sx Tom, Please see the requested backup material attached. The glycol analysis are not on actual samples of the glycol in the gas supply line, but are identical in nature and operational history. It is not possible to collect a sample currently resident in the line. We believe that all glycol miss-injection has gone into the Kuparuk oil pool through the K-38i. Please see the attached workbook containing injection history information. We believe that the data and plots demonstrate that the well's ability to accept fluids has not changed as a result of the fluid injection. If you have other questions please let me know. As we plan the exact sequence of events to initiate gas injection I have come to learn that immediately prior to injection of gas we will send a small (5 bbl) slug of methanol down the wellbore to prevent hydrates. We believe that such methanol injection is incidental to gas flood operations and there is not a need to expand our AIO allowed fluids, but I seek your guidance on this activity along with our other request. ~~~~ Pioneer Natural Resources Alaska, Inc. Manager of Land and External Affairs 700 G St., Ste 600, Anchorage, AK 99501 Office (907) 343-2110 Mobil (907) 830-0999 Fax (907) 343-2190 Email: ~at.foley@pxd.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, May 04, 2010 10:32 AM To: Foley, Pat; Bond, Andy Cc: Roby, David S (DOA); Davies, Stephen F (DOA) Subject: RE: Oooguruk AIO Modification Request Importance: High 5/4/2010 • Page 2 of 3 Pat and Andy, When might we be receiving a response to our questions? We have done no further work on the requests pending your response. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Monday, April 26, 2010 9:17 AM To: Pat Foley (pat.foley@pxd.com); Andy Bond Cc: Foerster, Catherine P (DOA); Roby, David S (DOA); Davies, Stephen F (DOA) Subject: RE: Oooguruk AIO Modification Request Pat and Andy, Review of your AA application is underway. Steve, Dave and I have a couple of questions ... 1) In the application you mention that glycol and water mixtures "have been proven by testing to be non- hazardous". Is this determination based on testing conducted by Pioneer of the fluids in the gas supply line? 2) Does Pioneer have any individual well infectivity plots that would indicate that the prior injection (2009) of glycol and water mixtures has not adversely affected either the Kuparuk or Nuiqusut formations? Thanks in advance for your reply. Tom Maunder, PE AOGCC From: Foerster, Catherine P (DOA) Sent: Friday, April 23, 2010 1:29 PM To: Maunder, Thomas E (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA) Subject: FW: Oooguruk AIO Modification Request FYI From: Foley, Pat [mailto:Pat.Foley@pxd.com] Sent: Friday, April 23, 2010 12:14 PM To: Foerster, Catherine P (DOA) Cc: Colombie, Jody J (DOA); Hart, David; Leppo, Jeffrey W.; Bond, Andy; Sheffield, Ken; Sturtevant, Craig Subject: Oooguruk AIO Modification Request Commissioner Forester, Earlier today I filed a paper copy of a request for an Administrative Approval to modify Area Injection Orders 33 and 34. For your convenience, I have attached a pdf copy of our filing to this note. If you or your staff have questions about our request or require additional information do not hesitate to contact me. ~.~~~ Pioneer Natural Resources Alaska, Inc. Manager of Land and External Affairs 5/4/2010 • . Page 3 of 3 700 G St., Ste 600, Anchorage, AK 99501 Office (907) 343-2110 Mobil (907) 830-0999 Fax (907) 343-2190 Email: pat.foley@pxd.com Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. 5/4/2010 ~\ ~~~ ~ ~~.~ ~ ~ `srtcv~r ~ l Vim) ~~~ Date 1/1/1016:00 01 Jan 2010 16:00:00:000 1 /1 /1017:00 01 Jan- 201017:00:00:000 1/1!1018:00 01 Jan 201018:00:00:000 1/1/10 19:00 01 Jan 2010 19:00:00:000 1/1/10 20:00 01 Jan 2010 20:00:00:000 1 /1 /i 0 21:00 01 Jan 2010 21:00:00:000 111/10 22:00 01 Jan 2010 22:00:00:000 1/1/10 23:00 01 Jan 2010 23:00:00:000 1/2!10 0:00 02 Jan 2010 00:00:00:000 1 /2/101:00 02 Jan 2010 01:00:00:000 1/2/10 2:00 02 Jan 2010 02:00:00:000 1/2/10 3:00 02 Jan 2010 03:00:00:000 1/2/10 4:00 02 Jan 2010 04:00:00:000 1/2110 5:00 02 Jan 2010 05:00:00:000 1!2110 6:00 02 Jan 2010 06:00:00:000 1/2/10 7:00 02 Jan 2010 07:00:00:000 1/2!10 8:00 02 Jan 2010 08:00:00:000 112/10 9:00 02 Jan 2010 09:00:00:000 1 /2110 10:00 02 Jan 201010:00:00:000 1!2/10 11:00 02 Jan 2010 11:00:00:000 1 /2/10 12:00 02 Jan 2010 12:00:00:000 1 /2/10 13:00 02 Jan 2010 13:00:00:000 1/2/10 14:00 02 Jan 2010 14:00:00:000 1/2110 15:00 02 Jan 201015:00:00:000 1 /2/1016:00 02 Jan 201016:00:00:000 1 /2/10 17:00 02 Jan 201017:00:00:000 1/2/1018:00 02 Jan 201018:00:00:000 1/2!10 19:00 02 Jan 201019:00:00:000 1 /2/10 20:00 02 Jan 2010 20:00:00:000 1 /2110 21:00 02 Jan 2010 21:00:00:000 1/2/10 22:00 02 Jan 2010 22:00:00:000 1 /2/10 23:00 02 Jan 2010 23:00:00:000 1 /3110 0:00 03 Jan 2010 00:00:00:000 1/31101:00 03 Jan 2010 01:00:00:000 1!3/10 2:00 03 Jan 2010 02:00:00:000 1/3/10 3:00 03 Jan 2010 03:00:00:000 1/3/10 4:00 03 Jan 2010 04:00:00:000 1/3110 5:00 03 Jan 2010 05:00:00:000 1!3/10 6:00 03 Jan 2010 06:00:00:000 1/3/10 7:00 03 Jan 2010 07:00:00:000 1 /3/10 8:fl0 03 Jan 2010 08:00:00:000 1 /3/10 9:00 03 Jan 2010 09:00:00:000 1/3/10 10:00 03 Jan 2010 10:00:00:000 113/10 11:00 03 Jan 2010 11:00:00:000 1/3/10 12:00 03 Jan 201012:00:00:000 1/3/10 13:00 03 Jan 2010 13:00:00:000 1/3/10 14:00 03 Jan 2010 14:00:00:000 113/10 15:00 03 Jan 201015:00:00:000 1/3/10 16:00 03 Jan 2010 16:00:00:000 1/3/10 17:00 03 Jan 2010 17:00:00:000 2 3 4 24 hr rolling avg FI_34201 Injection Rate, K-38i Mster, bwpd bwpd 3016.282227 3049.147217 6616.197754 6603.806641 6601.8505$6 6516.399414 8559.967773 1760.04$95 1449.318115 7049.660645 6969.399414 6941.125977 6865.154785 6897.788086 6867.795898 6667.374023 6855.302246 7074.558594 7062.547852 7342.603516 7297.57959 7300.143555 3032.258545 3055.805176 3080.673096 6894.099121 7194.842773 7168.636719 7099.621094 7107.854004 7102.758789 7095.386719 7069.033691 7085.205566 2874.986572 2904.924316 7149.727539 7100.876465 7112.135254 6978.280273 7150.085449 7113.084961 7050.618164 7050.77(7996 7i i 4. i 71875 7071.226074 7182.799316 10591.2207 6090.077'148 8239.760742 5 K38i DH Pressure, psi Switched to Pl,_27201J 3763.440674 3756.51123 4041.104492 4055.409912 4064.067139 4066.731689 4199.218262 3844.427979 3664.090332 4054.362793 4080.603271 4090.74292 4096:068359 4100.218262 5894 5$97. 6057. 6081'. 6104 6125 6150; 6089: 6311 6546 6547- 6376'. 6208 6220' 6229 6239 6252: 6264 6266'. 6265 6253 6245. 6236 6409 6723 6848'., 6904 4102.971191 4092.046875 4106.691406 4123.896973 4127.942871 4145.976074 4149.274414 4151.490723 3869:854248 3801.771484 378fi.008789 4042.731689 4102.205078 4119.882324 4126.165527 4130.419922 4130.745605 4132.501953 4134.200684 4135.894531 3816.600098 3780.813721 4100;058594. 4117.573242 4125.17041 4110.228516 4128.19388 4130.831543 41 32221 1 91 4133 , 84 5703 413; .~i049$ 4140.7$3203 4147.6713$7 ..4358.196777 4071..090332 4221.9J~1211 POLLEN ENVIRONMENTAL, LLC. Pouch 3x0135 Prudhoe Bay, AK 99734 (907) 659-2324 Phone (907) 659-2325 Fax Pol IenEnv(+1lastacalaska. tom CHAIN OF CUSTO[)YJWORKOROER FORM CLIENT INFORMATIiDN Contact ,~`~ ~ Person ~~C`: Requested Analysts Company: t ~'-.J~~ ~r'4~{{ /~ f [.,.F, {~fta~"YankV2 !~!idFU Page ~ of Address: Puhht Water t©:+: City, State Zip: M. -.-- Phone: / 1 ., / G,^' Send Results to RDEC: ~ '"1. ~' ^ Normal Turnaround Fax: ^ Yes Na _~: ""~ f ' ~~, J Email: ~... { .~GY,'C.z~~'V~ ~3~, ~'~ .~ ; tC•~..~.tS} ? J(r,'~.l'G:' Purchase QrderJCharcte Ccd+~: ~ ~ ~~ ,~ > ..+ ~ .,~ ,'~ J l~ ,.,-y- RUSH -day(s) Project Name: ~ u ~^ " ~- ~ ~~ ~ ~ Sampled By: '~ }{ `~" ' ~-t , Sam id Itieatfon Sam le Data Sam Troia Matrix Lafy 2Dd Sam Ie Comments ' ~~ io /~ Possl6Je Hazard Idontffication: Sample condition: ^ Non-Hazardous ^ flammable ^ Skin trritant ^ tJnknawn Temperature an arrival ~`,), ~ °C Chain of Custody Seal: ^ Jntact ^ Sroke Abse/~t ~- ~ e-a Spectaltn~instructionafQ/C Requirements & Co/mme~nts./ O~ ~' ltG Cvt,.S ~»cl~~~c..f" 1~ 1~+~G~. Sort ~~ 15 ~,.-ro / Relinquished by: /~ Company: ~, `~Z j'Ri Date & Tlme: ~~G`, I ,.v Receive Comp ny: mr~.. Date Ti t r~ L Relinquished by. Company: Date & Tlme: R i y:~ Company: Dat & T me; Relinquished by: Company: Date & Tlme: Received by: Company: Date & Ttme: Accuracy, Precision, and Professional Service p• ' • ~ ~~ • Certificate of Analysis 3/25/2010 Pioneer Natural Resources Attn: Quinn Selitsch /Derek Helmricks 700 G Street, Suite 600 Anchorage, AK 99501 Phone: 907-670-6625 Fax: 907-670-6604 ooogurukhsespecialist@pxd.com pioneeracstech@pxd. com Project Name: Glycol Sampled By: Derek Helmericks Definitions MRL =Method Reporting Limit E =Exceeds Regulatory Limit I =Matrix Interference T =Analyzed Past Hold Time P/A =Presence /Absence CFU =Colony Forming Units MPN =Most Probable Number PPM =Parts Per Million Attached are the results for analysis of your samples. A portion of this sample was analyzed by Test America in Beaverton, OR. Tracking information is as follows: Analysis Requested: TCLP Metals, TCLP VOC, TCLP SVOC Sample ID: Pollen Env ID: Test America ID: Date Sampled: Time Sampled: Glycol3/11/10 PE10823 PTC0522-01 3/11/2010 17:30 Analysis Analysis Parameter Result Units Flag ~~ Method Date Flash Point EPA1020 >145 °F 3/12/2010 pH EPA150.1 8.23 @ 21.0 C Units 3/12/2010 ~ ,. ,. :J 1~~~ L ~. ~~ ' Y Jerry Pollen /Jeff Shannon Pollen Environmental, LLC -Prudhoe Bay Pollen Environmental, LLC ~~ ~~ ~ PORTLAND, OR 9405 S. W. NIMBUS AVENUE A~y~//~~ BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 7H~ t_l`AF)~R ItJ ~NVIRC3NFA~NTAL Tf=S7`ING Pollen Environmental Project Name: Main Pouch 340135 Project Number: 10-348/Glycol Report Created: Prudhoe Bay, AK 99734 Project Manager: Jerry Pollen 03/25/10 16:23 TCLP Metals per EPA 1311/6000/7000 Series Methods TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PTC0522-OIREl (PE10823 (Glycol 3/11/10)) Other wet Sampled: 03/11/1017:30 Arsenic 1311/6020 ND ----- 0.100 mg/I lx 1000622 03/22/1013:25 03/22/1017:38 Barium Np ----- 0.100 " " " " Cadmium ND ---- 0.100 " Chromium ND ---- 0.200 " Lead " ND ----- 0.100 " " ' Selenimn ND ----- 0.100 " Silver " ND ----- 0.100 " " " TestAmerica Portland ~," ~~ Vanessa Frahs, Project Manager She results in lhls repor! apply to the sanrples~ analyzed 1n accordance x~ith Lhe chain of weslody dwumen7. phis analy8eal repor/ slwll not be reproduced except in fill. withoat the written approval of the laboramrv. w w w .te sta m e r ica in c .co m Page4of15 • T~tr~r~ 7HE I_EFtDEi~ IN E=N1/CF~C)fYl~A7=NTAL 7ES1`CNG PORTLAND, OR 9405 S. W. NIMBUS AVENUE BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 Pollen Environmental Project Name: Main Pouch 340135 Project Number: ] 0-348/Glycol Report Created: Prudhoe Bay, AK 99734 Project Manager: Jerry Pollen 03/25/10 16:23 TCLP Mercury per EPA Methods 1311/7470A TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PTC0522-O1 (PE10823 (Glycol 3/11/10)) Other wet Sampled: 03/11/1017:30 Mercury 131 ]/7470A Np ----- oosoo mg/1 Ix 1000528 03/18/10]7:38 03/19/1010:20 RLI TestAmerica Portland yy~~ ~y ~'y Vanessa Frahs, Project Manager The results in this report apply to the samples anal~~zed in accordance with the chain oJ'ce~stody docameni. This anall~(lcal report shnll not be reproduced except in full, without the wrliten approval of the laboratory. W W W .te sta m e r ica 111 C CO m Page5of15 • Ti ~~~ ~~ I~ - ~ j PORTLAND, OR 9405 S.W NIMBUS AVENUE ~/ '~M1' 1/~ BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 7HE 1.~AE7~F1 IN ENVIRONMEN7Al_ 1`~STING Pollen Environmental Project Name: Main Pouch 340135 Project Number: 10-348/Glycol Report Created: Prudhoe Bay, AK 99734 Project Manager. Jerry Pollen 03/25/10 16:23 TCLP Volatile Organic Compounds per EPA Method 1311/8260B TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PTC0522-O1 (PE10823 (Glycol 3/11/10)) Other wet Sampled: 03/11/1017:30 RLl Benzene 1311/8260B Np ----- 0.0200 mg/I 2x 1000702 03/24/1011:29 03/24/1015:30 Carbon tetrachloride Np ---- 0.0200 " Chlorobenzene Np ----- 0.0200 " Chloroform Np ----- 0.0200 1,4-Dichlorobenzene ND ----- 0.0200 " 1,2-Dichloroethane ND ----- 0.0200 " 1,]-Dichloroethene Np ----- 0.0200 " 2-Butanone (MEK) Np ----- 0.200 " Tetrachloroethene Np ---- oA200 " Trichloroethene Np ----- 0.0200 " " Vinyl chloride Np ---- 0.0200 " Surroga7e(s): d-BFB !09% 75 - 130 % O.Iz " DibromoJluororne/have 118% 75 -130 Toluene-d8 113% 75-130% " TestAmerica Portland f ~>~ ~~ Vanessa Frahs, Project Manager The results fn [his report apply to the samples analyzed in accordance wllh the chafn of e¢es~ody document. This ana[yNca7 report shnl[ not be reprodaeed except in full, without the written approval of the Taboralorv. W W W. t e S t a m e f I C a I n C c o m Page 6 of 15 • ~~~ [ ~ ~~ ` ~ PORTLAND, OR 9405 S. W. NIMBUS AVENUE 1111///"' ~y~- BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 THE t_EAEIER IN E=NVII~tSNtviEiV7AL TE571NG Pollen Environmental Project Name: Main Pouch 340135 Project Nwnber- 10-348/Glycol Report Created: Prudhoe Bay, AK 99734 Project Manager: Jerry Pollen 03/25/10 1623 TCLP Semivolatiles per EPA Method 1311/8270 TestAmerica Portland Analyte Method Result MDL'~ MRL Units Dil Batch Prepared Analyzed Notes PTC0522-O1 (PE10823 (Glycol 3/ll/lll)) Other wet Sampled: 03/ll/lO 17:30 1,4-Dichlorobenzene 1311/8270 ND ----- 0.0500 mg/I ]x 1oC0573 03/19/tol0:o0 03/19/1021:59 2,4-Dinitrotaluene ND ----- 0.0500 " Hexachlorobenzene ND ----- 0.0500 Hexachlorobutadiene ND ----- o.oS00 " Hexachloroethane ND ----- 0.0500 " Nitrobenzene ND ----- 0.0500 " Peniachlorophenol ND ----- 0.100 " Pyridine " ND ----- 0.200 " " " 2,4,5-Trichloropheno] ND ----- 0.0500 " Total Cresols ND ----- 0.100 " 2,4,6-Trichlorophenol Np ---- 0.0500 " Surrogate(s): 2-l7uorophetto! 28.7% 10 - I5o % " Phenol-d6 I6. o/ 10 -150 / " 2,-1,6-Tribromophenol 6Z 6/ 10-750/ " Nitrobenzeue-d5 72.7/ 20 - /50 2-f~'TuorobTpheny! 64.0/ 20 -150 / " p-Terpheny!-d19 72.v~ 20-]soi TastAmeriea Portland ''/'he resa7ts ]n tl7ls report apple m the snnples analyzed ]n accordance with the chain o/~cuslody doenmenl. phis ana7yllca7 report shall not be reproc&rced ereepl ]n h~lJ, ~` ~~te'~ ~~ ~~~~ ~ without tlve wrlnen approval ol'the Taboralory. Vanessa Frahs, Projec[ Manager w w w .te sta m e r ica 111 C .CO m Page7of15 • Interoffice MEMORANDUM TO: File FROM: John Hellen DATE: 4/20/09 SUBJECT: Glycol Reuse for Freeze-Protect PIONEER NATURAL RESOURCES Oooguruk Operations intends to use glycol left over from hydro-testing/pipe-warming as freeze-protect media for the disposal well (DW-1 ). This memo has been prepared to document the decision and a series of lab analyses on the glycol. Jim Gilroy provided the following description of the source and use of the glycol. "The 8" water line was communicated with the 6" gas line filled with glycol and circulated to pre-warm the pipeline bundle. Once the pre-warming was completed, the glycol was de- inventoried into the OTP storage tanks. The glycol that was flushed into the flowback tank was residual from the pipeline warmup that was left in the line. The flowlines were never placed in service and in as new condition. The glycol was leftover hydrotest fluid from the pipeline." Although the glycol is not a waste when used for freeze protection, several samples were collected to verify that the glycol would not be considered hazardous waste even if it were disposed of by injection. The first two samples collected were reported to contain benzene greater than 0.5 mg/kg. The benzene was suspected to be the result of mixing with well fluids (Class II exempt waste) in the flowback tank and lines. A final sample was collected from the OTP glycol storage tanks, since that represented the glycol prior to mixing with Class II fluids. Benzene was not reported in the final sample, thereby confirming that the glycol would not be considered hazardous waste if disposed. Attachment: Lab Reports Analytical Services ©rcier and Chain of Custody Fc-rm Arctic ~vx Environm.entat~ .nc. Pouch 340043 I Prudhoe Bay, AK 99734 ~~}'~ Phone: (907) 659-2145 /Fax: (907} 659-2146 arcticfgxQastacalaska.cam ! www arct~cfoxenv~c,~mm _- . }4 ~~ ~e a Address: ~ Account Number: Preservative 8 Requested Analysis Lot Number ;~n~ 6 odtSgkY~`~ ~~.11 P.O. or Co~IU~N D(<r k `~ 4UG2 (~' ,,.. Authorization Number. Contact Person: ~ l'~ t1,~`~ ~~('~ (y ~ ~'y hone Number: Fax Nu r: Sampled By: ~~~ ~ ~- ~ tf~ E-mail: - PWS Numtser: ., ,~ G ~ 4 `~ ~ ~ V ~aject Name: ---- ' ~ `!' ~ ~( Data Deliverables: Send Resufts to ADEC: ~ ~~ ~, Level 1 C] Level U L] level III U EDDIFomtat: ^ YES O No ~ ~ ~ ~ \" ~ 1 Requested Turnaround Time ~~, ~ (, ~ ~ ~ `^1 and Special InsWctiorts: J\ CIieM Sample ID Sa ~~ ~ ~~ Matrix AF!Sampla ID ~ Remarks !YS Y (~ ~ .1 n 1 r-1-~ir~-- ~,~,~T-2ti ~ :1; ~{r, C.~di ~ i d ~: ~ !r 3Y +" X13 ~ ~ ~ ~ ~ _- - '~ Relinquished By (1 ): Date: Time: Received By: Relinquished By (2): ate: Time: Received By: Relinquished By (3): Date: Time: Received for lab Location Receivedt ANC C:l °C FBIC D °C PB C~ °C Temp art Arrival: Chain of Custody Seal 0 INTACT C7 BRAKEN Ct ABSENT Shipping. Bill Number. Page of Arctic Fox Environmental, Inc. Pouch 340043 -Prudhoe Bay, AK 99734 Phone: (907) 659-2145 /Fax: (907) 659-2146 / arcticfox@astacalaska.com • Pioneer Natural Resources, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Attn: Greg Garvin/Johnathon Allen Phone: (907) 670-6540 Fax: (907) 670-6510 Email: pioneerenvironmental(a~pxd.com pioneeracstech(c~pxd.com greggarvin(c~pxd.com Arctic Fox Lab #: AF30743 Client Sample ID: OTP Glycol Location/Project: Oooguruk COC#: 60163 Sample Matrix: Glycol PW S#: Report Date: 4/16/2009 Date Arrived: 3/25/2009 Date Sampled: 3/25/2009 Time Sampled: 2:30 PM Collected By: GG Flaa Definitions MRL =Method Reporting Limit B =Below Regulatory Minimum H =Above Regulatory Maximum M =Matrix Interference J =Best Available Estimate U =Less Than Detection Limit D =Lost to Dilution Comments: Attached are the results for analysis of your sample. A portion of this sample was analyzed by Test America in Beaverton, OR. Tracking information is as follows: Pioneer Natural Resources Sample ID: OTP Glycol Analysis Requested: TCLP Metals, TCLP VOC, TCLP SVOC Arctic Fox ID: AF30743 Test America ID: PSD0040-01 Appearance: Pale green clear single phase liquid. Analysis Analysis Parameter Result Units Flag MRL Method Date EPA 150.1 pH 7.73 Units EPA150.1 3/26/2009 EPA1020 Flash Point >140 Deg F EPA1020 3/26/2009 ~~`~ ~ r ~P-~ ifs Reported By: Ralph E. Allphin Prudhoe Bay Laboratory Tt~4rr~ria THE LEADER Ihl EN-f113f3NM~F1'TAL TESTtNG PORTLAND, OR 9405 S. W. NIMBUS AVENUE BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Number: 0309-4983/Waste Determination Repor[ Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 04/15/09 )4:01 TCLP Metals per EPA 1311/6000/7000 Series Methods TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSD0040-O1 (AF30743 - OTP Glycol) Other wet Sampled: 03/25/09 14:30 Arsenic 1311/6020 ND ----- 0.100 mg/1 lx 9040136 04/03/0910:35 04/03/0918:38 Bariwn ND ----- 0.100 " " " Cadmium NtD ----- 0.0500 " Chromium Np ----- 0.200 " Lead Np ----- 0.100 " ' Selenium " 0.174 ----- 0.0500 " 04/04/0916:05 Silver ~rD ----- 0.100 04/03/0918:38 TestAmerica Portland The results in This report apply !o the samples analyzed in accordnnce wish the cha/n ofcxstody document. This analvlical report shall not he reproduced ezcep! in fidl, + _ wilhou! the writtew approval of the laboratory. ~~~ L~ Vanessa Frahs, Project Manager W W W .te sta m e r ica Ill C CO m Page3of15 Tstt~ria "THE L~AElI=#2 IN ~?vIV1l~C7Ntvt~t+1TA~ TESI`ENCa PORTLAND, OR 9405 S. W. NIMBUS AVENUE BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Number: 0309-4983/Waste Determination Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 04/15/09 14:01 TCLP Mercury per EPA Methods 131 l/7470A TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSD0040-O1 (AF30743 - OTP Glycol) Other wet Sampled: 03/25/0914:30 Mercury ]311/7470A ND ----- 0.0800 mg/I lx 9040200 04/06/0911:39 04/06/0918:54 RLl TestAme[lca Portland The resahs in tldr report apple m (he snmples analyzed in accordance with the chain of castaly document. T7~is analytical report shall not be reproduced except in full, ~„r ~ withwa the wrltfen approval of the laboratory. Vanessa Frahs, Project Manager W W W .te sta m e r ica 111 C CO m Page4of15 T~~m i ~ ~~ ~ J PORTLAND, OR 9405 S W. NIMBUS AVENUE V ~/~ BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 TFtlE= LEACIE#2 IN ENV113C3NM)<NTAL 7E51`ING Arctic Fox Environmental, >[nc. Project Name: Main Pouch 340043 Project Number: 0309-4983/Waste Determination Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 04/15/09 14:01 TCLP Volatile Organic Compounds per EPA Method 1311/8260B TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSD0040-O1 (AF30743 - OTP Glycol) Other wet Sampled: 03/25/0914:30 Benzene 1311/8260B ND ----- 935 ugQcg ]x 9040080 04/02/0916:00 04/03/0911:57 Carbon tetrachloride ND ----- 935 " Chlorobenzene ND ----- 935 " Chloroform ND ----- 935 " 1,4-Dichlorobenzene ND ----- 935 1,2-Dichloroetbane ND ----- 935 " l,l-Dichloroethene j.]j~ ----- 935 " 2-Butanone (MEK) ND ----- 9350 Tetrachloroethene ND ----- 935 " Trichloroethene ND ----- 935 " Vinyl chloride ND ----- 935 " Surrogate(s): d-BFB 92.7% 75-130 % O.OIx Dibromo/luoronte[hane ]oa/ 75 -130 L'oluene-d8 lOh% 75 - 130 TBatAmenea Portland The resul[s 9n Ihis report apply to the samples analyzed in accordance wish the chain .- of custody docxment. ,This analyn'cal report shall not be reproanced except in fill, ff,' A~ ~~ ~ wiihmn the wrinen approval of the laboralorp. ~~~ 1#vv~~~- Vanessa Frahs, Project Manager W W W .te sta m e t ica 111 C CO m Page5of15 • • j Tit ~~ ~ j PORTLAND, OR 9405 S. W. NIMBUS AVENUE 1 // ~~ 11Y~/I77 BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 fiH~ 1_~ADER ItJ ENVI~C?MMEN'I`P.L 7E~'ftNG Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Number: 0309-4983/Waste Determination Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 04/15/09 14:01 TCLP Semivolatiles per EPA Method 1311/8270 TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSD0040-01 (AF30743 - OTP Glycol) Other wet Sampled: 03/25/0914:30 RL3 1,4-Dichlorobenzene 1311/8270 ND ----- 0.100 mg/1 2x 9040336 04/09/0913:20 04/10/0923:44 2,4-Dinitrotoluene ND ----- 0 ] 00 " Hexachlorobenzeoe ~tD ----- 0.100 " Hexachlorobutadiene ND ----- 0.100 " Hexachloroethane ND ----- 0.100 " Nitrobenzene ND _____ O,t00 ~~ ~~ ~~ ~~ ~~ Pentachlorophenol ND 0200 " Pyridine ND ----- 0.400 " " " " 2,4,5-Tdchlorophenol ND ----- o.too " Total Cresols ND ----- 0.200 " 2,4,6-Trichlorophenol ND ----- 0.100 " Surrogate(s): 2-Fluorophenol 33.3% l0 -150 Phenol-dh 76vi 10-150 i " 2,1,6-Tribron~ophenol 7d.1% 10-150% Nitrobenzene-d5 8L0% 20-150 % " 2-Flvorofiiphenyl 86.3% ?0-150 % " p-Terphenyl-d14 95.7% 20-150 % " TestAmerica Portland ~~~*~ ~- Vanessa Frahs, Project Manager The resulLS in th9s report apply to the samples analyzed in accordance with the chain ofeustody document. %his ana7pNCa7 report shall notbe reprodrmed Cxcept in full, without the written approval of the laboratory. w w w .t e s t a m e r i c a l n C . C O m Page6of15 Ts~,~rrr~ ~~ PORTLAND, OR 9405 S. W. NIMBUS AVENUE BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 7HE L~AE)~R IN t=NYIRC3NMi=NTAL TESTING Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Number: 0309-4983/Waste Determination Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 04/15/09 14:01 TCLP Extraction Only TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSD0040-O1 (AF30743 - OTP Glycol) Other wet Sampled: 03/25/09 14:30 Extraction EPA 1311 ND ----- l.oo N/A lx 9040108 04/02/09 ]8:54 04/02/0922:25 Extraction ND ---- l.oo TestAmerica Portland '` ~.- ~- Vanessa Frahs, Project Manager 't'he resaltc in this report apple to the samples analyzed 1n aeeordaace with the chain of custody document This nnalytlcal report shall not be reproduced ex pt in fill. without the wr7tten approval of the laboratory. WWW.testamericaihC COm Page7of15 • Jjj ~~~~J'-Z+~ ~~ L j PORTLAND, OR 9405 S. W. NIMBUS AVENUE ••MM~~ VVVV // ~7 1r/~ BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 7HE Lf`ADEi2 IN ~NVIRiCDNt•1l~N7Al T~S1"ING Arctic Fox Environmental, Inc. Project Na,ne: Main Pouch 340043 Project Number: 0309-4983/Waste Determination Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 04/15/09 14:01 Notes and Definitions Report Specific Notes: LS - Analyte recovery outside of specified criteria. Individual analyte criteria exceedences allowed for multi-component analyses without disqualification of data per NELAC Standard, DOD QSM and/or AFCEE QAPP. R4 - Due to the low levels of analyte in the sample, the duplicate RPD calculation does not provide useful information. RLl - Reporting limit raised due to sample matrix effects. RL3 - Reporting limit raised due to high concentrations ofnon-target analytes. Z3 - The sample required a dilution due to the nature of the sample matrix. Because of this dilution, the surrogate spike concentration in the sample was reduced to a level where the recovery calculation does not provide useful information. LaboratorYReporting Conventions: DET - Analyte DETECTED at or above the Reporting Limit. Qualitative Analyses only. ND - Analyte NOT DETECTED at or above the reporting limit (MDL or MRL, as appropriate). NR/NA _ Not Reported /Not Available dry - Sample results reported on a Dry Weight Basis. Results and Reporting Limits have been corrected for Percent Dry Weight. wet Sample results and reporting limits reported on a Wet Weight Basis (as received). Results with neither'wef nor'dry' are reported - on a Wet Weight Basis. RPD - RELATIVE PERCENT DIFFERENCE (RPDs calculated using Results, not Percent Recoveries). MRL - METHOD REPORTING LIMIT. Reporting Level at, or above, the lowest level standard of the Calibration Table. MDL* - METHOD DETECTION LIMIT. Reporting Level at, or above, the statistically derived limit based on 40CFR, Part 136, Appendix B. *MDLs are listed on the report only if the data has been evaluated below the MRL. Results between the MDL and MRL are reported as Estimated Results. Dil - Dilutions are calculated based on deviations from the standard dilution performed for an analysis, and may not represent the dilution found on the analytical raw data. Reporting - Reporting limits (MDLs and MRLs) are adjusted based on variations in sample preparation amounts, analytical dilutions and Limits percent solids, where applicable. Electronic - Electronic Signature added in accordance with TestAmerica's Electronic Reporting and Electronic Signatures Policy. Signature Application of electronic signature indicates that the report has been reviewed and approved for release by the laboratory. Electronic signature is intended to be the legally binding equivalent of a traditionally handwritten signature. TestAmerica Portland ~~~ ~ _~~ Vanessa Frahs, Project Manager The resvps in Ihis report Apply to the samples analyzed in accordance with The challt of custody document. This analytical report shall not be reproduced except in fill, without the written approval of the laboratory. W W W. t e S t a m e r I C a I I1 C C O m Page 15 of 15 ~' -`7 I~- ARCTIC FC}X ENVtRQNMENTAL, INC. Pouch 340043 Prudhoe Bay, AK 99734 (907) 659-2145 phone (907) 659-2146 fax Analytical Services Order and Chain of Custody Farm PB-54772 lent Name and Address: ~ Account Number: Reque sted Analy sis Preservat,~~e 8 Lot NUrn!)8r `~pl~ ~~~ ,,_.,, Contact Person:. ~,~`~'"~ / P O. or ontract Number° Authonzatian um r: ~ /"' one Number: 8 a be : ~ / ',~ ca- , .. Sampled By u- -mail: ~ .~ PWS Number.. Project Na e: ~„ ~ f~ ~~,~„ < ~~.^~ /~ Data Deliverables: Level t ~ Level tl J Level 111 J EDD/Format:. '-' "~G elf ~ Send Results to ADEC. ~ YES ~ NO T 1 .~,.i _ 1 N _ -- --- - Requested Turnaround Time and Special Instructions: ` Client. Sample ID Date Time Sartsplad j Sampled Matrix AF Sample 10 Remarks ~ -~ b'1 ~ ; ~30.3~ I r ~ j ~r ~v ~v~l~~~t /'~. ~ /S" ~f f ~'/y j ~'" F3 o3~s ~ ___ _ ..,~ _._. _._~ ___a.._.__mm~_ _~ i __ - Relinquished y (1): ~y~~, _~ `_~!+.1._.,__..-' 1 -- Relinquis d By (2). Date. _. Time: ~ i ^4 ~ ~ 14L.~ _~. } ~~.;_......._ ~ Date; ;Time, ~. G-,~ ~ ~ ~ a ~ ~~ ttece~ved By f ~ ~ -_.-~:.__- " Received 8y: ~ T4 BE CQMPLETEO BY LABC?RATORY location Receivedl ANC CJ ~C FBK U °C PB ©~"C Tern on Arrival:; R Chain of Custody Seal ~ INTACT C] BR©KEN C} ABSENT j Ralinquished By t3) ~jat T/im/e,~ h~~'~j~i~~ / ~~i''G'' Received for lab by ~ J Shipping Bilf Number: ayG Arctic Fox Elnironmental, Inc. Pouch 340043 -Prudhoe Bay, AK 99734 Phone: (907) 659-2145 /Fax: (907) 659-2146 / arcticfox@astacalaska.com Pioneer Natural Resources, Inc. 6751 South Airpark Place Anchorage, Alaska 99502 Attn: Selitsch/ McCrary Phone: (907) 670-6622 Fax: Email: oioneeracstechCcr~oxd.com Arctic Fox Lab #: Client Sample ID Location/Project: COC#: Sample Matrix: PW S#: AF30324-30325 ODS Flowback Glycol 8" Produced Water Line 54772 Liquid Report Date: 2/28/2009 Date Arrived: 2/18/2009 Date Sampled: 2/18/2009 Time Sampled: 10:15 AM Collected By: GG Comments: Attached are the results for analysis of your sample. This sample was analyzed by Test America in Beaverton, OR. Tracking information is as follows: Pioneer Natural Resources Sample ID: ODS Flowback Glycol Bottom Layer Analysis Requested: TCLP Metals and Total Benzene Arctic Fox ID: AF30324 Test America ID: PS60573-01 Pioneer Natural Resources Sample ID: ODS Flowback Glycol Top Layer Analysis Requested: Total Benzene Arctic Fox ID: AF30324 Test America ID: PSB0573-03 Pioneer Natural Resources Sample ID: Travel Blank Analysis Requested: Total Benzene Arctic Fox ID: AF30325 Test America ID: PSB0573-02 Reported By: Ralph E. Allphin Prudhoe Bay Laboratory • 7HE L~A17~1'2 MN ENVIRQNM~N fAL T~STtNG PORTLAND, OR 9405 S.W. NIMBUS AVENUE BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Nwnber: 0209-4895/Glycol Hydrotest Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 02/27/09 17:34 BTEX per EPA Method 8021B TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSB0573-O1 (AF30324 ODS Flowback Glycol) Other wet Sampled: 02/18/0910:15 Benzene EPA 8021B 7750 --- 250 ug/I SOOx 9020701 02/23/091]:10 02/24/0907:09 Toluene 9560 ---- 250 " Ethylbenzene 1870 250 " Xylenes (total) 10800 500 Surrogate(s): d-BFB (Y/D) 93.]% 70-130% Jx PSB0573-02 (AF30325 -Travel Blank) Other wet Sampled: 02/18/09 10:15 Benzene EPA 8021B Np ----- 0.500 ug/I ]x 9020701 02/23/0911:10 02/23/0918:35 Toluene Np ----- 0.500 " Ethylbenzene Np ----- 0.500 " Xylenes (total) Sp ----- 1.00 " Surrogate(s): 4-BFB (PID) 9d.5% 70 -130 PSB0573-03 (AF30324 Top layer) Other wet Sampled: 02/18/0910:15 Benzene EPA 8021B 2g$ ----- 27.8 mglkg wet 20x 9020717 02/23/09 18:00 02/24/09 05:02 Toluene 987 55.6 " Ethylbenzene 521 55.6 " Xylenes (total) 3570 1 ll " m,p-Xylene 2650 ----- 55.6 " o-Xylene 923 ----- 55.6 " Surrogate(s): a, a, a-TFT (PLD) 2850% 60- /30 % Z3 TOSTAmerlca Portland The re~sulls in this report apply to /he sanples analyzed iw accordance with (he chnin ofcustody c]oeumenl. This analvlleal report shn/! not be reprochard except in fiJ( '~ _ ~.- withoullhe wr7tterx approval of(helaborarorp- Vanessa Frahs, Project Manager w w w. t e s t a m e r i c a i n c. c o m Page 3 of 14 Tt~4r Sri a PORTLAND, OR 9405 S. W. NIMBUS AVENUE BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 THE I_EACIER (tJ EtVVIRC3NMENTAL TESTING Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Number: 0209-4895/Glycol Hydrotest Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 02/27/09 17:34 TCLP Metals per EPA 131 ]/6000/7000 Series Methods TestAmerica Portland Aualyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSB0573-O1 (AF30324 ODS Flowback Glycol) Other wet Sampled: 02/18/0910:15 Barium 1311/6020 0.133 ---- 0.100 mg/1 ]x 9020806 02/25/0913:06 02125/0919:51 Cadmium Np ----- 0.0500 " Chromium ND ----- 0.200 " Lead NI) -- 0.100 " " " " Selenium NI) ----- 0.0500 Silver NrD ----- 0.100 " PSB0573-O1RE1 (AF30324 ODS Flowback Glycol) Other wet Sampled: 02/18/0910:15 Arsenic 1311/6020 ND ----- 0.100 mg/1 lx 9020854 02/2610912:21 02/27/0906:04 TeStAlnenea POr[land The re5ulis in Ihfs report apple to the samples analyzed in accordance with the chain .- of evestody doa~ment. This analytical report shall not be reproduced except fn fill, ~f w `~ _{~~ without fhe wriften approval of the laboratory. Vanessa Frahs, Project Manager w w w .te sta m e r ICa Ifl C .CO m Page4of14 ~( ~~~ i ' ~~ \ ~ PORTLAND, OR 9405 S. W. NIMBUS AVENUE V /// ~~` ~/' '~1~/ BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 7H~ LEACJ~~F2 IN ENVIf2C3NAAEN7AL 7~5TlNG Arctic Fox Environmental, Inc. Project Nalne: Main Pouch 340043 Project Number: 0209-4895/Glycol Hydrotest Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 02/27/09 17:34 TCLP Mercury per EPA Methods 1311/7470A TestAmerica Portland ~Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSB0573-O1 (AF30324 ODS Flowback Glycol) Other wet Sampled: 02/18/0910:15 Mercury 1311/7470A ND ----- 0.0800 mg/1 lx 9020860 02/26/09 ]3:23 02/27/0908:38 RLl TestAmerica Portland ~v'f ~ Vanessa Frahs, Projec[ Manager The res¢dts itt tMs report apply to the snmples analyzed in accordance wish the chain of cusrodr dacamenl. TMs analytical report shnll not be reproduced ezcepi in full. wi7hout the wntien approval o(the laboratory. W W W. t e S t a m e r I C a 1 f1 C C O m Page 5 of 14 ~ i ~ T~~' ' ^ e ~ ~ J PORTLAND, OR 9405 S.W. NIMBUS AVENUE LLL ~~` ^^^ ~Mr/' ! 1 1r~ \\rr/AA BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503)906.9210 'i'HE ~EADEft IN ~td'V112QNN1EN7AL 7~ST`ING Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Number: 0209-4895/Glycol Hydrotest Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph A1lphin 02/27/09 17:34 TCLP Extraction Only TestAmerica Portland Analyte Method Result MDL* MRL Units Dil Batch Prepared Analyzed Notes PSB0573-O1 (AF30324 ODS Flowback Glycol) Other wet Sampled: 02/18/09 10:15 Extraction EPA 1311 ND ----- l.oo N/A Ix 9020775 02/24/091731 02/24/0919:56 TestAmerica Portland +~~ Vanessa Frahs, Project Manager The results in phis report apply to the samples analyzed in accordance with the chain ojcusiody don~menl. T his ana!)•Ncol report shall not be reproduced except in fidl, wlfhou/ the ealtten approvn] of the laboratory. w w w .te sta m e r ICa Ifl C .CO m Page6of14 • T( y~~ [ y ~~ ~ ~ PORTLAND, OR 9405 S.W. NIMBUS AVENUE V ~~F BEAVERTON, OR 97008-7132 ph: (503) 906.9200 fax: (503) 906.9210 7H~ I_EAE7ER IN ENVIRClNMENYAL 7ES7ING Arctic Fox Environmental, Inc. Project Name: Main Pouch 340043 Project Nrimber: 0209-4895/Glycol Hydrotest Report Created: Prudhoe Bay, AK 99734 Project Manager: Ralph Allphin 02/27/09 17:34 Notes and Definitions Report Specific Notes: M7 - The MS and/or MSD were above the acceptance limits. See Blank Spike (LCS). R4 - Due to the low levels of analyte in the sample, the duplicate RPD calculation does not provide useful information. RL1 - Reporting limit raised due to sample matrix effects. Z3 - The sample required a dilution due to the nature of the sample matrix. Because of this dilution, the surrogate spike concentration in the sample was reduced to a level where the recovery calculation does not provide useful information. Laboratory Reportine Conventions: DET - Analyte DETECTED at or above the Reporting Limit. Qualitative Analyses only. ND - Analyte NOT DETECTED at or above the reporting limit (MDL or MRL, as appropriate). NR/NA _ Not Reported /Not Available dry - Sample results reported on a Dry Weight Basis. Results and Reporting Limits have been corrected for Percent Dry Weight. wet Sample results and reporting limits reported on a Wet Weight Basis (as received). Results with neither'wef nor'dry' are reported - on a Wet Weight Basis. RPD - RELATIVE PERCENT DIFFERENCE (RPDs calculated using Results, not Percent Recoveries). MRL - METHOD REPORTING LIMIT. Reporting Level at, or above, the lowest level standard of the Calibration Table. MDL* - METHOD DETECTION LIMIT. Reporting Level at, or above, the statistically derived limit based on 40CFR, Part 136, Appendix B. *MDLs are listed on the report only if the data has been evaluated below the MRL. Results between the MDL and MRL are reported as Estimated Results. Dil - Dilutions are calculated based on deviations from the standard dilution performed for an analysis, and may not represent the dilution found on the analytical raw data. Reporting - Reporting limits (MDLs and MRLs) are adjusted based on variations in sample preparation amounts, analytical dilutions and Limits percent solids, where applicable. Electronic -Electronic Signature added in accordance with TestAmerica's Electronic Reporting and Electronie Signatures Policy. Signature Application of electronic signature indicates that the report has been reviewed and approved for release by the laboratory. Electronic signature is intended to be the legally binding equivalent of a traditionally handwritten signature. TestAm~err~ic~a~Po~rtland [,~r~ Vanessa Frahs, Project Manager The results in this report apply to the sanplea attalyzed 7n accordance with The chain of castnd~~ document. This analytical report shall not be reproduced excepl7n full, without the written approval of IMe laboratory. w w w. t e s t a m e r i c a i n c. c o m Page 14 of 14 ~~ t'IONEER ~ NATURAL RESOURCES ALASKA J. Patrick Foley Manager of Land & External Affairs Pioneer Natural Resources Alaska, Inc. 700 G Street, Suite 600 Anchorage, Alaska 99501 Voice (907) 343-2110 -Fax (907) 343-2190 Apri123, 2010 Commissioner Daniel Seamount ~~~~~~ Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 APR 2 ~ 201D Anchorage, AK 99501 ~01t~GacCnr~,~ss~ord ,At~bOi' Re: Application to Amend Area Injection Orders No. 33 and 34, Rule 3 to include glycoUwater mixtures Oooguruk Unit, North Slope Alaska Dear Commissioner Seamount: Pioneer Natural Resources Alaska, Inc. (Pioneer) applied to the Alaska Oil and Gas Conservation Commission (AOGCC) for an Area Injection Order (AIO) on December 20, 2007 requesting enhanced recovery ("EOR") injection for both the Oooguruk-Kuparuk and Oooguruk- Nuigsut pools within the Oooguruk Unit ("OU"). The AOGCC approved such application and issued AIOs 33 and 34 effective April 11, 2008. Pioneer came before the Commission requesting administrative approval of a modification and expansion of Rule 3 of each order. Such request was approved and authorized on March 13, 2009 by Administrative Approval AIO 33.001 and AIO 34.001. Pioneer now comes before the Commission seeking administrative amendments of AIO 33 and AIO 34 to expand the authorized FOR injection fluid sources to specifically include glycol and water mixtures, which have been proven by testing to be non- hazardous. On the date of this writing, Rule 3 of said Orders allows the following sources for FOR injection fluids: a. source water from the Kuparuk sea water treatment plant; b. injection water provided by the Kuparuk Field; c. produced water from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; d. tracer survey liquid to monitor reservoir performance; e. biocide-treated and oxygen-scavenged sea water extracted from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS); and f biocide-treated and oxygen-scavenged the ODS shallow water source wells. Additionally, AIO 34 includes; g. natural gas provided by the KRU CPF-3. The modified Orders further provide, "The injection of any other fluids, or mixtures of the above fluids, shall be approved by separate administrative action." Such Order continues in Rule 10 Application to Amend Area Injection~ders No. 33 and 34, • Rule 3 to include glycol/water mixtures Oooguruk Unit, North Slope Alaska Apri123, 2010 providing for modification by administrative approval "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." At present, the Oooguruk 6-inch gas supply line likely contains a 50/50 water/glycol mixture estimated to be roughly 4,125 gallons, and such fluid will, subject to the Commission's approval, be pushed into the Oooguruk Nuigsut Injection wells upon the commencement of gas injection associated with the Nuigsut US-WAG flood. The mixture is a residual, assumed to be lying in the bottom of the line, remnant from earlier hydrotesting, freeze protection and pipeline warm-up operations. Pioneer desires to convert from water injection to gas injection as soon as possible to facilitate hydrocarbon production from the Nuigsut formation. We therefore request the Commissions' review and favorable consideration of this application at your earliest convenience. In addition, Pioneer seeks amendment of its two AOIs for after-the-fact injection authorization of water/glycol mixtures for both the Oooguruk-Kuparuk and Oooguruk Nuigsut Oil Pools. As previously reported to the Commission, in 2009, Pioneer injected approximately 49,000 gallons of a 50/50 mixture of water and glycol. This mixture was residual fluid in the seawater supply line after hydrotesting, freeze protection and pipeline warm-up (approximately 35,300 gallons), residual fluid in the gas supply line after hydrotesting, freeze protection and pipeline warm-up (approximately 4,125 gallons), or pumped into the seawater supply line for beneficial reuse as an FOR fluid (maximum potential amount of 9,600 gallons). It is not feasible for Pioneer to extract these injected fluids other than what may occur through normal production operations; nor would such extraction be useful if it were possible given that the mixture served and serves a beneficial FOR purpose. Accordingly, insofar as this fluid mixture remains in the formation due to these unauthorized injection events and circumstances, we seek after-the-fact amendments in order to bring Pioneer's FOR operations into compliance with the Commission's AIOs. In requesting this amendment, Pioneer is not seeking to insulate itself from regulatory action by the Commission, if any, for having used a fluid mixture that at the time of its injection was not authorized as an FOR fluid by the applicable AOIs. Injection of water/glycol mixtures as FOR injection fluids is a beneficial re-use of glycol and no detrimental impact to enhanced oil recovery from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools will result. A similar request was authorized by the Commission under AIO 3.028 and AIO 4E.034. As the Commission found there: The Commission agrees with BPXA that there is no reason to believe injecting the used glycol mixed with flush water will have a detrimental impact to enhanced oil recovery from the Prudhoe Bay Oil Pool. The Commission further finds that injecting the subject fluids is consistent with guidance from EPA that encourages the beneficial reuse of fluids as a sensible waste management practice. In this case, injecting the glycol/water mixture will provide additional fluids for reservoir pressure maintenance rather than serve as a disposal waste stream that requires surface transport and additional handling. The injection of used glycol mixed with water for FOR purposes will not promote waste or jeopardize correlative rights, and will not contribute to the potential for fluid movement outside of the authorized injection zone. Application to Amend Area Injection~ders No. 33 and 34, Rule 3 to include glycol/water mixtures Oooguruk Unit, North Slope Alaska April 23, 2010 Consistent with the Commission's previous determination, we believe that the requested injection source is a sensible and responsible management practice which does not promote waste or jeopardize the correlative rights of other parties. As a part of our initial AIO application we provided information on rock properties and fluid compatibility for both the Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools. We are confident that the effect of water/glycol mixture injection will be substantially similar to the currently approved injection source fluids and will not damage the reservoir. Please contact Pat Foley (office: 907-343-2110, cell: 907-830-0999, or pat.foley@pxd.com) or Andy Bond (office: 907-343-2105 or andy.bond@pxd.com) if you have any questions or require additional information regarding this application. Thank you for your prompt attention to this application. Sincerely, ~~~ ~ J Pat Foley Manager, Land & External Affairs Andy Bond Reservoir Engineering Manger ~7 ~ • Page 1 of 2 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, September 02, 2009 11:46 AM To: 'Hali, Joey' ~ `~ ~Z~ 7,~~~~ ~ Subject: RE: Possibie Misinjection Notice Freeze protecting injection wells in arctic work environment is necessary to ensure a well's continued mechanical integrity while shut in for an extended period of time. As we understand this, the freeze protect fluid (e.g., diesel, dead crude, or glycol) will be pushed out of the tubing and into the formation with the commencement of EOR injection. This is a standard procedure for freeze protecting wells. Flow back of the fluids might be possible but represent concern with increased handling and storage and the use of extraneous energy (gas lift) to displace the diesel back to surface. As such we consider the displacement of freeze protect fluids into the formation upon commencement of injection to be incidental to the operation of the well. The freeze protect fluid should be compatibie with the formation and enhanced recovery fluids injected in the formation. There is no need for additiona~~roval and the displacement of freeze protect fluids from ODSK-38 as described in your notice doe.s not constitute a misinjection. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Hall, )oey [mailto:Joey.Hall@pxd.com] Sent: Wednesday, September 02, 2009 10:36 AM To: Regg, James B (DOA) Cc: Foley, Pat; Smith, Bonnie; Hail, Joey C~ Slt-~~, Subject: Possible Misinjection Notice ~?~j~ e ~~ Jim, l.~P~-~r~t~e;4-o~ In a recent review of our operations, we determined that it is possible and even probable that glycol, diesel and Oooguruk crude oil have been injected into the Oooguruk Kuparuk Pool down hole through our injection well (ODSK 38i) . This can happen following an event where freeze protection of piping or a well becomes necessary. In this case, it is not practical to evacuate the freeze protect fluid from the piping or wellbore prior to resuming operations; thus, the fluid would get injected into the reservoir. Any injection was a result of operational practices and not an intentional disposal or purposeful injection. This note serves two purposes: 1. To notify the AOGCC that a misinjection has likely occurred. It is not possible for us to quantify the amount of liquid injected but we expect that it could be no more than 120 bbls. 2. To request a path forward allowing the use of glycol, methanol, diesel or Oooguruk crude for freeze protection with the understanding that it would be injected into the reservoir once normal operations resume. In our initial Areawide Injection Order applications for both the Nuiqsut and Kuparuk Pools we included a request to inject small blended amounts of non-hazardous fluids (i.e. hydrotest fluids, rinsate, etc.). The Inject Orders issued by the Commission authorized a narrow and specific list of compatible fluids i ~ 9/2/2009 ~ ~ Page 2 of 2 authorized for injection. We seek your guidance regarding an application to expand the allowed injection fluids to better match real oil field operation practices. Please feel free to contact me if you need additional information. Regards, J. D. "Joey" Hall Operations Manager Pioneer Natural Resources Alaska, Inc. Phone: 907.343.2120 Mobile: 907.529.1728 Email: ~o~._hal_ I c~~xd.com 9/2/2009 ~~ ~ ~ PIONEER NATURAL RESOURCES ALASKA ~~ March 11, 2009 Commissioner Daniel Seamount Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 MAR 1 3 2009 Alaska tlil $~ leas Coos. Conunission Anchorage Application to Amend Area Injection Orders No. 33 & 34, Rule 3 - Oooquruk Unit Dear Commissioner Seamount: Pioneer Natural Resources Alaska, Inc. (Pioneer) applied to the Alaska Oil and Gas Conservation Commission (AOGCC) for an Area Injection Orders (A1O) on December 20, 2007 requesting enhanced recovery ("EOR") injection for both the Oooguruk-Kuparuk and Oooguruk-Nuigsut pools within the Oooguruk Unit ("OU"). The AOGCC approved such application and issued A1O 33 and A1O 34 effective April 11, 2008. Pioneer now comes before the Commission requesting administrative approval of a modification and expansion of Rule 3 of each order. Rule 3 of said orders approved the following sources of FOR injection water: a. source water from the Kuparuk sea water treatment plant; b. injection water provided by the Kuparuk Field; c. produced water from Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools; d. tracer survey liquid to monitor reservoir performance Rule 10 of said orders authorized modification or minor amendment by administrative approval. Specifically, we ask that the list of acceptable FOR injection fluids be expanded to include the following: 1. Seawater extracted by Pioneer directly from Harrison Bay, adjacent to the Oooguruk Drill Site (ODS). Such seawater will be treated with biocide and will be oxygen scavenged prior to injection. The water composition will be substantially the same as the KRU seawater supply approved for injection into the Kuparuk reservoir. Details regarding the anticipated injection water composition are found in Attachment 1. 2. Source water that is extracted from shallow water source wells located upon ODS. The shallow water source water composition is similar to sea water as it is believed to be charged by the ocean. Details regarding the anticipated injection water composition from this source are found in Attachment 2. 700 G STREET, SUITE 600 -ANCHORAGE, ALASKA 99501 -MAIN 907-277-2700 -FAX 907-343-2190 3. Effluent from the ODS reverse osmosis (RO) unit. The RO unit processes water extracted from the same ODS water source wells and makes potable water. Details regarding the anticipated injection water composition of this source are found in Attachment 3. Pioneer requests the Commission consider each requested FOR fluid change separately. We understand the authorization for some sources may require additional information and/or evaluation time. For this reason we appreciate receiving authorization for any or all sources that may be approved expeditiously and allow other source approval to follow as rapidly as possible. Pioneer has planned for and is prepared to immediately commence FOR waterflood injection into the Oooguruk-Kuparuk pool; however, projected injection water from the KRU is not currently available at our DS 3A tie in point. With observed increasing gas-oil ratios in the K-33 well, Pioneer believes it is prudent to commence water injection from the sources currently available until such time as the KRU source is back in service. Attachment 4 to this application, which we request AOGCC maintain as CONFIDENTIAL pursuant to 20 AAC 25.537, is a discussion of the current Oooguruk-Kuparuk pool characteristics and model results demonstrating the significant benefits of near term injection support. We are hopeful that KRU supplied water will become available soon; however, our desire for continued responsible reservoir management practices drives Pioneer to seek authorization for alternative water sources. As a part of our initial A1O application we provided information on rock properties and fluid compatibility for both the Nuiqsut and Kuparuk pools. Supplemental information on the requested FOR fluids may be found in Attachment 5, which we request AOGCC maintain as CONFIDENTIAL pursuant to 20 AAC 25.537. We are confident that the seawater extracted from source wells at ODS or lifted directly from Harrison Bay, after treatment, will be substantially similar to the currently approved KRU provided seawater and will not damage the reservoir. We would be pleased to meet with AOGCC Commissioners and/or staff to provide any other additional information or analysis. Prudent reservoir management requires swift approval for some or all of the alternative water sources. Our staff will be available at your convenience. Please contact Pat Foley (907-343-2110 office, 907-830-0999 cell, or pat.foley@pxd.com) or Andy Bond (907-343-2105 or andy.bond@pxd.com) if you have any questions or require additional information regarding this application. Thank you for your prompt attention to this application. Sincerely, Dale Hoffman Attachments • • Attachment 1: Raw Beaufort Seawater Analysis Seawater extracted offshore of the ODS will be treated with oxygen scavenger and appropriate biocide before being injected into the Kuparuk reservoir. The water chemistry will be substantially the same as the Kuparuk River Unit seawater that has been approved for injection into Kuparuk reservoir. Below is a chemical comparison of raw Beaufort seawater followed by a winter and summer composition of seawater as measured at the KRU STP (seawater treatment plant). ~~ W. Sew &wu~e c wtA9r Aneysk Yr6pt ~l MOteY Peucat+ro ta. xYSrw 1;rror DaY: Mre a496e Swt1: tw tNritteit $M Wa1N fwl MrlgB X011 Yty varxe 11108 ICP 0.01 f$iy ?A ..000 t ICP AA9B tf2A 20 086 101 8.0 9lAO ~ ~ ICP AABT 020 SA 0.00 tcP .aot e9s 4a 0A0 MP c0.00B 695 4A t~ tCP QOB 55a 4A OAO Y/n Icv o.0 9,0 4A OAt c.w tcP ers Pots 20 0m LIOrYP tCP 0.4 B,0 to 0.05 iCP 1800 21.5 2.0 118.01 tCA OA0 51;9 4.0 OAD '1 iCP d1AM 05.9 .0 0.00 ti7iy rl'd It:P AA4 58.T OAO Pi0 ICP A.ta 81.0 4A Pugarrn N' ICP 88.1 to 451 ffirran 1GP t2 48.9 ,17 8oou0 Y.' 1eP ,060 4sA t.o 5.80 Slurrcn tiPt IGP t0 pb 4A OY,Y MYNrun Y't ICP AAt 04. 4 Lat IC>P ~ 004 66A 4A OAO Mr000 I ~ I YW I YY1Pw I Y908 I 9W CBFOe~ 785 m rtrr~ are M 15A15 m errs om5 1151x! lOD'f -tA9 sYaYVUmrmO~r _._ owr D1r h Or. Y.00 O/vYNOO inlet II~ acv: rna¢Irey cougw PtY1M IC tm p.u0eb0~wa0T tsar awr41/ rat7wt __...._..~. .._..._ __..... -. -- --____... _._.. .,_ _._..,._... ..... ., _ _____. wv ._ _ . . .. _._, _ i _. .. ... __,. .____.. . ,. _ ____.___ as ' ~ a w cas pE~, q noanrr saa60Yptaur M 19090M Ry~P rpmN aigedtilrrer ~blaOnrEiE k :wn+avPOnll.o.mm•nnreszi..az ennoosrwtar • Attachment 1: Raw Beaufort Seawater Analysis Kuparuk Seawater Winter Composition Kuparuk Laboratory Report of Analysis Report Date: 02/16/06 To: Distribution Slltmple Description. I'WI, SWI Survey {Revised) S le ID _ AB08805 Sample point SOSPD-W Well Num 0 Loc Descriptor Collection Date 02/16/06 Collection Time 00:00 Analysis Unlt Result pH --- 7,23 Specific Gravity @ 60 -- 1.0296 degrees F Conductivity micro-mhos/cm 4400 Bicarbonate mg/l 186 Carbonate mg/l 0 Chloride mg/l 20930 Sulfate mg/I 2850 Sulfide mg/t Not Available Aluminum mg/I N.1 Boron mg/l 4 Baripm mg/l <t Calcium mg/l .484 Chromium mg/l X0.01 Iron mg/t N.O1 Potassium mg/1 4b6 Lithium mg/L 0.5 Magnesium mg/l 1536 Manganese mgA <0.001 Sodium mg/1 12$90 Phosphorus mg/1 a0.1 Silicon mg/1 0.5 Strontium mgJl 11 Zinc m N.1 If there are any questions regarding this data, please call ICI.S at 659-7214. Completed By:_MA Reviewed By:.-,._MG S- • Attachment 1: Raw Beaufort Seawater Analysis Kuparuk Seawater Summer Composition Kuparuk Laboratory Report of Analysis Report Date: 0812$106 To: Sampie Description: CPF1, 2, 3, STP Comp. Water ie ID AB l 5089 Sample point SOSPD-'W Well Num 0 Loc Descriptor Collection Date 48/24/06 Collectron Time 00:00 Analysis Unit Resnlt pH -- 7.48 Specific Gravity C~ 60 --- 1.0060 degrees F Conductivity micro-mhos/cm . 13060 Bicarbonate mg[I 9S Carbonate mg/l 0 Chloride mgll 40S 1 Sulfate mgll 602 Sulfide mgll Not Available Alaminum mg/1 <0.1 Boron mg/t <i Barium mgJl cJ Calcium mg/1 102.6 Chromium mgll <t1.2 Iron mgll <0.5 Potassium mg/1 104.9 Lithium mglL <0.S Magnesium mg!! 320.8 Manganese mg/l 0.004 Sodium mg/f 2610 Phosphorus mglt ,c0.1 Silicon mg/l 1.01 Strontium mg/I 1.89 Zinc m <0.1 If there are any questions regarding this data, please call 1{.I.S at bS9-7214. Completed By: MG Reviewed By: MA • Attachment 2: Oooguruk Source Water Wells Analysis The ODS is equipped with two very shallow (<100' MD) water source wells to use for making domestic potable water. Listed below is a chemical composition of the water from both wells. The water is believed to be charged from the ocean so the composition is somewhat similar to raw Beaufort seawater (Attachment 1). The water will be oxygen scavenged and treated with necessary biocide. Kuparuk Laboratory Report of Analysis Report Date: 5/6/06 To: coastal(akoastalfrontiers.cotn Ldl! ID ABl 1263 ABl 1264 Sau~le Dcscxiptiotr . Non-Unit Kupatvk Area S les Noa-Unit Kuparuk Area S les WtlliVum Dau 05/03/06 05/03106 T~ 00:00 00:00 L r PNR-MW02-001 PNR-MW02-042 Ana]vsis U Result R Chloride 31420 31170 Sulfate 960 970 Aluminum < 0.1 ~ 0.1 Barium < 1 < 1 Boron c 1 < l Calcium 726 657 ~ <-a.2 < 0.2 ~~ < 0.5 < 0.5 Lithium < 0.5 < 0.5 Ma Gsium 2400 2300 M ~~ 0.18$ 0.189 ~ orus < O.I < 0,1 Potassium 317 296 Silicon 2 2 Sodium 15990 16154 Strotrtium 11.7 12.6 Zinc < 0.1 < O.i Bicarbonate 2096 2055 Carbonate 0 0 Conductivi rtricro-mhos/cm 55700 55900 ~ 7.15 7.20 Specific Gravity ~ b0 de es F 1.0435 1,0433 Sulfide Not Ana d Not Anal d Total Dissolved Solids 68240 57080 1f there are any questions regarding tbu data, please call KLS at 659.7214. Corrg~leted By: TN Reviewed By: MTG Attachment 3: Oooguruk RO Effluent Water Analysis The RO effluent is the water left over after making domestic potable water. This water has a level of TDS about twice as high as raw Beaufort seawater. Again, this water should not cause any issues with formation damage when injected into the Kuparuk C Sand. ROSA Detailed Report Soling Calculations PH L.angelier Saturation Index Stiff & Danis Stability Index Ionic Strer~~gth (Mola1) TDS .{rng/f) ~HC03 C02 CD3 Cas04 (% Saturation) BaSO4 {% S8turation) Sl'.~~4 (% S8tUr8tlOn~ CaF2 (% Saturation) Si02 (% Saturation) Ivlg{OH)2 (% Saturation) Raw Water ?.15 1.z3 0.13 1.40 b8099.04 2621.31 1 b6.73 24.25 9.52 ~.~ ?.lad ] 50.95 2.38 0,02 Adjusted Feed ?.15- 1.23 0.13 1.40 68099.66 2621.31 166.?3 24.25 9.52 0.00 ?.~ l so.9s 2,38 4.02 Concentrate 7.50 1.89 0.?6 2.07 97i 12.35 3?03.28 1 ?6.96 s l .52 16.84 O.OU 14.01 a3?.?9 3.39 0.12 To balance: 0.62 mg/l Cl added to feed. RO Effluent water analysis ~5 ~PIONEER~ NATURAL RESOURCES ALASKA December 4, 2008 Mr. Dan Seamount, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West 7~ Avenue, Suite 100 Anchorage, AK 99501 Notice of Commencement of Injection Operations, Oooguruk Unit, North Slope, AK Dear Mr. Seamount: In accordance with 20 AAC 25.420, Pioneer Natural Resources Alaska, Inc. (Pioneer) as operator of the Oooguruk Unit and on behalf of the Working Interest Owners, hereby notifies the Alaska Oil and Gas Conservation Commission (Commission) of its intention to commence injection operations in the Oooguruk-Kuparuk oil pool with the ODS K38i well (API # 50-703-20584-00 and permit to drill # 208-146) pursuant to Commission Area Injection Order No. 33. Pioneer anticipates commencing injection on or after January 15, 2009. If you have any general questions or need any additional information, please call me at 343-2108 or e-mail at dale.hoffman@pxd.com. Sincerely, Dale Hoffman cc: D. Lawler, Eni T. Davidson, DNR 700 G STREET, SUITE 600 -ANCHORAGE, AK 99501 -MAIN 907-277-2700 -FAX 907-343-2190 #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 • • ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: Daniel T. Seamount, Chairman John K. Norman, Cathy Foerster In the Matter of the Application by PIONEER NATURAL RESOURCES ALASKA, INC. for Area Injection Orders for Oooguruk-Nuigsut and Oooguruk-Kuparuk Oil Pools, Oooguruk Field, Arctic Slope and Beaufort Sea, Alaska ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska February 14, 2007 9:00 o'clock a.m. VOLUME I PUBLIC HEARING BEFORE: Daniel T. Seamount, Chairman John K. Norman, Commissioner Cathy Foerster, Commissioner 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 II 15 16 17 18 19 20 21 22 23 24 25 • TABLE OF CONTENTS Opening remarks by Chairman Seamount Dale Hoffman Greg Sanders Andy Bond Robert Cook 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 03 05 24 26 26 r • 1 2 3 4 5 6 7 8 9~I 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 Tape 1 0050 (On record - 9:04 a.m.) CHAIRMAN SEAMOUNT: Okay. I'd like to call this hearing to order. The date is Thursday, February 14th, 2008. The time is 9:04 a.m. We're located at 333 West Seventh Avenue, Anchorage, Alaska. Those are the offices of the Alaska Oil and Gas Conservation Commission. At the head table -- this is the bench -- see, last time I did this we had a table, now we have a bench. At the bench here my name is Dan Seamount. The name plates are gone, I see. To my right is Commissioner John Norman and to my left is Commissioner Cathy Foerster. And out there in the crowd is Alan Birnbaum our assistant Attorney General. And th person here to help you out if there's any special needs is Jody Colombie at the very back. She's our special staff a sistant, correct? MS. COLOMBIE: Corre t. CHAIRMAN SEAMOUNT: orrect, okay. In the notice we said that anybody that has any special needs we will try to accommodate them. If any ody does have any special needs, please see Jody. The purpose of this Baring is to consider an application for Pioneer Natural Resou ces Alaska, Incorporated as operator 0 811 G STREET (907)2 7-0572/Fax 274-8982 A CHORALE, ALASKA 99501 3 1 2 3 4 5 6 7 8I 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • and on behalf of the working interest owners requesting area injection orders for the Oooguruk, did I say that right? UNIDENTIFIED VOICE: Right. CHAIRMAN SEAMOUNT: Oooguruk. Oooguruk-Nuigsut and Oooguruk-Kuparuk oil pools, Oooguruk Field, Arctic Slope and Beaufort Sea, Alaska. This is in accordance with 20 AAC 25.402. Notice of the hearing was published on January 8th, 2008 in the Anchorage Daily News and State of Alaska on-line notices, as well as the AOGCC website. The proceedings will be held in accordance with 20 AAC 25.540, those are regulations governing Public Hearings. R & R Court Reporting (sic) will record the proceedings. You can get a transcript from R & R Court Reporting. And obviously the hearing will be recorded. We'd like to remind anyone testifying to speak into the microphones. There's two right there. You've got to speak into both of them so the persons in the rear of the room can hear and so the Court Reporter can get a clear recording. So let's see, where's the sign-in sheet? Oh, here it is. Okay. It's looks like we just have one person volunteering to testify, is that true? Anybody else in here? Okay. MR. FOLEY: Mr. Chairman, we also have technical, geologic and engineering staff that can supplement and answer questions if necessary, but the bulk of the testimony will be done by 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 • ~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 I II Dale . CHAIRMAN SEAMOUNT: Okay. And can you state your name for the record? MR. FOLEY: Sure, for the record my name is Pat Foley, Pioneer Natural Resources. CHAIRMAN SEAMOUNT: Thank you, Mr. Foley. Well, we'll hear from the applicant first and if anybody decides they want to say anything after that then we'll allow the opportunity for other interested parties to ask questions. Now, the way to do -- at this point the way to ask the questions, if you're another interested party, is you write your questions down and give 'em to Ms. Colombie and she'll forward them to the head table and we will -- the Commissioners will ask the questions for you if they're deemed appropriate. So at this point we'd like to invite the applicant to introduce himself, themselves and approach the Commission. Are you going to be giving sworn testimony? MR. HOFFMAN: I believe I am. CHAIRMAN SEAMOUNT: Okay. Then please raise your right 2 0 II hand . 21 22 23 24 25 (Oath Administered) MR. HOFFMAN: I do. TESTIMONY OF DALE HOFFMAN CHAIRMAN SEAMOUNT: And please state your name and who you represent? And do you want to be an expert witness? 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 5 6 7 8, 9 10 11 12 13 14 15 16 17 18 19 'i 20 21 22 23 24 25 • MR. HOFFMAN: Yes, I do. CHAIRMAN SEAMOUNT: Okay. So go ahead, name, who you represent, what the subject is, what are your qualifications and proceed. MR. HOFFMAN: Thank you, Mr. Chairman. Good morning, Mr. Chairman, members of the Commission, my name is Dale Hoffman and I'm a staff land man with Pioneer Natural Resources Alaska located here in Anchorage. And I am here today on behalf of the company to present for the hearing our 0ooguruk development area injection order application. My qualifications are I started in the oil and gas industry as a land man in 1977 with Union Oil Company California in Ventura, California. I worked for them for several years before going to Conoco and working as a land man for them. I moved to Alaska in 1982 as a district land man when Conoco started up its Milne Point field and worked in Alaska for 1982, '83. Subsequent to that I moved to Houston and was the land manager for the Western Gulf Division for Conoco. After that I moved back to California and I was the land manager for Alaska and offshore California. Subsequent to that I've worked for Vanico (ph) in Santa Barbara, California, Royal Energy in San Diego. And for the last two and half years have worked for Pioneer Natural Resources back here in Anchorage, Alaska. So my background is as a land man. 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 6 • • 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. When did you work for Vanico? MR. HOFFMAN: I worked for Vanico in 2001, 2002 and actually started with them about midway in 2000. CHAIRMAN SEAMOUNT: One of my old bosses from Unocal worked for Vanico. I don't know if you overlapped with him. MR. HOFFMAN: Mr. Chairman, who was the..... CHAIRMAN SEAMOUNT: I can't remember his name it's been so long. MR. HOFFMAN: Oh, I'm sure I worked with him so --..... CHAIRMAN SEAMOUNT: Okay. MR. HOFFMAN: .....'cause half the company was from Union Oil, so..... CHAIRMAN SEAMOUNT: That's right. Commissioner Norman, do you have any questions of the witness? COMMISSIONER NORMAN: I have no questions. MR. HOFFMAN: Thank you. CHAIRMAN SEAMOUNT: Do you, Commissioner Forester? COMMISSIONER FOERSTER: No, I don't. CHAIRMAN SEAMOUNT: And I don't hear any objections as to Mr. Hoffman being an expert witness so you are an expert witness. MR. HOFFMAN: Thank you, sir. Any chance we can dim the lights just a little bit or a lot? (Off record comments) MR. HOFFMAN: Well, thank you very much. So, again, I'm 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 51 6 7 8 9 10 11 12 13 14 ', 15 16 17 18 19 20 21 22 23 24 25 here to present the Ubik (ph) unit area injection order. Much of this information you will -- is already in your packet. It will be somewhat redundant given the fact that we were here a month and a half ago to talk about the pool rules, but for the record we'll run through some of the basics again for you. This is just an area vicinity map. (Slide 1) You've seen this before. Our island ODS is located about five and a half miles offshore in the Colville Delta. It runs onshore. We've got about two and a half miles of flowline subsea from the island to the surface. There's a transitionary and then it runs about two and a half miles to our OTP adjacent to drill site 3H. We will be producing from the island and fluids will go to the OTP and then it will go over to the Kuparuk River unit for processing, so..... And the Village of Nuiqsut which is the closest local effected community is about 26 miles south of our ODS there. And this is just the regional setting. (Slide 2) I'm sure you're very familiar with this. You can see our island out here. You've got -- I mentioned Milne Point, my old employer's field up here. Prudhoe Bay, Kuparuk. You see some other. Alpine here. We're just north and east of Alpine. Prudhoe Bay, so we're located in oil country up there. You're familiar with that. And the two horizons that we're targeting are the Kuparuk and Nuiqsut. And if I go through any of this too quickly, I'm 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 '~I 13 14 15 16 17 18 19 20 21 2 2 II 23 24 25 assuming it's just review though. So brief project summary. (Slide 3) Our field life cycle, we're currently in the development phase. It's an oil with an enhanced (ph) recovery. Our gross acres is about 58,000 acres. We've got a 70 percent working interest as the operator. ENI Petroleum US, LLC is our non-working interest (sic) partner. Gross reserves are in the range of 50 to 90 million barrels.. Our first production is expected some time this year. Peak production -- yes, ma'am. COMMISSIONER FOERSTER: Did you say that your non-working interest partner? MR. HOFFMAN: Our non- -- I meant non-operated, excuse me. Thanks for the correction. COMMISSIONER FOERSTER: Okay, sorry. MR. HOFFMAN: First production this year with an estimated peak flow of 15 to 20 million (sic) barrels of oil per day. Excuse me, gross. Productive life 25 years and we're expecting approximately 35 wells. COMMISSIONER FOERSTER: Okay. 20,000 barrels a day or 20 million barrels? MR. HOFFMAN: 20,000. COMMISSIONER FOERSTER: Thank you. CHAIRMAN SEAMOUNT: 15 to 20,000. MR. HOFFMAN: So the project summary. (Slide 4) We sanctioned this in 2006. We constructed the island drill site 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~I 10 11 12 13 14 15 16 17 18 19 20 I 21 22 23 24 25 which I showed you on the plat there. We've installed the subsea flowlines. We've built and installed about 120 modules. We're in the beginning of the three year development phase for our drilling as we mentioned earlier. We had about 600 contractors at its peak working on the island and OTP. Our capex at present is estimated at $550 million. And we expect first oil again this year. And that's a picture of our drilling rig out there on the island in the summertime. So a brief reservoir description and this is included in our application. (Slide 6) For the Kuparuk sandstone it's the Kup C. It's the lower Cretaceous basal transgressive sandstone. The analogue is obviously from Kuparuk River and the Kup C there. We're looking at 10 to 40 feet of estimated gross thickness on that. Twenty-four percent average porosity. And 100 to 500 millidarcies permeability. The other objective in the projects are Nuigsut sandstone and that's an Upper Jurassic, inner shelf sandstone. It's highly bioturbated -- turbated, excuse me. The analogues are Fiord and Alpine. We're looking at 80 to 120 feet of estimated gross thickness with 10 to 20 percent porosity and .1 to 50 millidarcies permeability so..... COMMISSIONER NORMAN: Mr. Hoffman? MR. HOFFMAN: Yes, sir. COMMISSIONER NORMAN: Just for the purpose of keeping 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 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 record clear in the future as you're referring to the slides if you could say I'm now talking from slide..... MR. HOFFMAN: Certainly. COMMISSIONER NORMAN: .....number 6 that will help both the Court Reporter..... MR. HOFFMAN: Certainly. COMMISSIONER NORMAN: .....and those in the future. MR. HOFFMAN: Thank you. Here we're looking at slide number 7 right now. It talks about basic depletion and our development plan so for the Oooguruk-Nuigsut we're looking at approximately 29 horizontal wells. It's an under-saturated water alternating gas. We refer to it (ph) US-WAG. It's a line-drive waterflood for patterns if the gas is limited. And we're looking at approximately a one to one injector to producer ratio. As for the Kuparuk we're looking at approximately six horizontal wells. We're looking at line-drive waterflood only for that and it's one to one, again, injector ratio with electronic submersible pumps on all the producers. And then our production will be commingled at surface, that's downstream of the measurement and it will go to the Kuparuk River Unit facilities. Slide 8, just a brief overview of our estimated reserves. For the Nuiqsut we've got original oil in place as 250 to 350 million barrels. Primary recovery we anticipate 5 to 20 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 13 14 15 16 17 18 19 20 21 'i 22 23 2 4 l 2 5 II million barrels for the Nuiqsut. Incremental waterflood will add an additional 30 to 60 million barrels. Incremental US-WAG recovery two to 10 million barrels and in our total estimated recoverable reserves 37 to 90 million barrels and that's for the Nuiqsut. For the Oooguruk-Kuparuk reservoir we're looking at original oil in place 15 to 25 million barrels. The primary recovery one to two. Incremental waterflood recovery three to six million barrels and total estimated recoverable reserves four to eight million barrels and, again, that's for the Kuparuk. Expected Fluid Properties. In the Oooguruk-Kuparuk our gravity is 19 to 24 degrees API. And this is on slide 9, by the way. The viscosity 4.5 to 6.5. Total GOR is 250 to 400. On our Oooguruk-Kuparuk gravity is 23 to 26 degrees. Viscosity is two to three and total GOR is 450 to 550. So now I'd like to talk a little bit about our drilling, completion and well operations and this is shown on slide 10. So for Oooguruk-Nuiqsut wells they'll be open hole completions drilled parallel to our major faults. Undulating lateral sections up to 9,000 feet in length and then 1,700 foot injector/producer lateral spacing. For the Oooguruk-Kuparuk we'll do slotted line completions and we'll also drill parallel to the faults with approximately 5,000 foot lateral lengths and three to 3,000 foot 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 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 injector/producer lateral spacings. And the production wells have subsurface valves and subsurface...... COMMISSIONER FOERSTER: Surface safety valves and surface controls and (simultaneous speech)..... MR. HOFFMAN: Surface safety valves and surface sub..... COMMISSIONER FOERSTER: .....surface control subsurface safety valves. MR. HOFFMAN: Thank you. CHAIRMAN SEAMOUNT: Stop helping him out. COMMISSIONER FOERSTER: Okay, sorry. MR. HOFFMAN: Yeah, don't help me out. And the injection wells have double check valve or single check valve with a subsurface valve -- safety valve. COMMISSIONER FOERSTER: Surface safety value. MR. HOFFMAN: Surface safety valve. We're on slide 11 now. This slide shows the proposed injector wells inside the unit.. This is the unit outline here. This is the area we have described and presented for our pool area for the Nuigsut and then there are the proposed injectors and producers wells. And you can see that we're looking at a one to one ratio on all these wells. Likewise with the Kuparuk, same thing, you've got a unit outline here and this is on slide 12. You can see a much smaller aerial extent (ph) and then just a few producers and -- and, excuse me, injection wells that we're proposing there. 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 13 ~ • 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 Under our application we were required to notify the -- any operators within, I think, it's a quarter mile so we've notified ConocoPhillips, as well as the surface owner which is the State of Alaska, Department of Natural Resources. We've also provided an affidavit indicating such and that was included in the packet. (Slides 13 and 14) Talk a little bit in more detail about our proposed operations. Again, this is slide 15. We're looking at a total of 35 to 47 -- or excuse me, total 35 to 47 horizontal wells and that's for the entire development. Five to eight of those are for the Kuparuk and 30 to 39 for the Oooguruk-Nuigsut reservoir and, again, that would be matched up on about one to one ratio producers to injectors. The depletion plan of both reservoirs will utilize long horizontal wells oriented parallel to one another and parallel to the fault system. I don't know, Commissioners, how much of this you would like me to discuss in detail? If you would like me to read it for the record or just..... CHAIRMAN SEAMOUNT: Does this automatically go into the record or do we have to submit it? COMMISSIONER NORMAN: It will go into the record because he's referring to it..... CHAIRMAN SEAMOUNT: Okay. COMMISSIONER NORMAN: .....as part of his testimony so it R& R C O U R T R E P O R T E R S 811 G STREET 1907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 • ~ 1 2 3 4 5 6 7 81 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 II will be attached. CHAIRMAN SEAMOUNT: So does anybody want this read? COMMISSIONER FOERSTER: No, I just (simultaneous speech) .... . CHAIRMAN SEAMOUNT: It's all right -- okay, that's fine, you don't have to read it. MR. HOFFMAN: Okay. Any questions on it or..... CHAIRMAN SEAMOUNT: Commissioner..... COMMISSIONER NORMAN: I have just one on..... MR. HOFFMAN: Yes, sir. COMMISSIONER NORMAN: .....relevant parties as to whether you've received any communications or objections or concerns expressed directly to you? Our file doesn't, to my knowledge, reflect any from either ConocoPhillips or the State of Alaska, DNR. UNIDENTIFIED VOICE: Commissioner, the question was about objections to this, no, we've not received any verbal or written objections from either party. COMMISSIONER NORMAN: Thank you. MR. HOFFMAN: (Slide 16) And, again, now we go into more information about the names, descriptions and depths of the effected pools. I can read the pool descriptions, if you'd like, for the record or if there are any questions I'd be happy to answer those. This text was also included in the application and it's similar to the text you've seen in 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 15 • • 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 pool rules also. CHAIRMAN SEAMOUNT: Well, we heard testimony at the pool rule hearings and it's in the record in a couple of places, so you're fine. MR. HOFFMAN: Okay, thank you. Likewise for slide 17 it's a continuation of that. So the next issue is, on slide 18 we're talking about AAC 25.402(c)(7) it talks about logs for the injection wells. We've not drilled any oft he injection wells yet so we haven't logged anything. We have no plans to log, but in the event there is any logging that would occur obviously that would be provided to the AOGCC under the regulations, so..... Description of the proposed method, this is slide 19. Description of the proposed method for demonstrating mechanical integrity of the casing and tubing. We'll be doing cement bond logs to demonstrate the isolation of the injected fluids. Mechanical integrity of the tubing and annulus will be tested to the maximum pressure anticipated during injection to satisfy the requirements of AAC 25.412. Also, one of the things that we're asking for is due to the wellbore directional profiles, these are high angle directional wells we're looking for a waiver from the requirements of 20 AAC 25.412 (b) of having the packer set within 200 feet measured depth of the injection interval to facilitate the completion and long term operation of the well. 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 II 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Packers will need to be set at a depth of more than 200 feet from the injection interval, however, packers will not be set above the confining zone. And I don't know if there are any questions on that, but we are requesting that exception. And, again,..... COMMISSIONER FOERSTER: I have one MR. HOFFMAN: .....that's due to the high angle of the wells which are above 70 degrees. COMMISSIONER FOERSTER: I have a couple questions, but you may not be the one to answer them. MR. HOFFMAN: I would be the one to try, but if you would like COMMISSIONER FOERSTER: All right. MR. HOFFMAN: .....if you would like we certainly have engineers and geo-scientists here for the technical stuff. COMMISSIONER FOERSTER: Well, I do guarantee that I won't answer them, how's that? MR. HOFFMAN: And so the question to the Commission then is would you want to swear these people in now in the event of questions or would you rather wait till the end of the presentation? CHAIRMAN SEAMOUNT: I'm wondering if we ought to wait and then take a..... COMMISSIONER FOERSTER: Take a break and ask all the questions then, okay, that's fine. 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 4 5 6 7 8 9I 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 2 5 I' CHAIRMAN SEAMOUNT: And then we'll compile all the questions. COMMISSIONER FOERSTER: That's fine. MR. HOFFMAN: Okay, thank you. So progressing to slide 20, Section 25.402(c)(9) talks about injection fluid analysis and injection rates. And, again, this has been submitted in the application and this was also in the record for our pool rules. One of the issues was just maximum expected in average injection rates and, again, for the Kuparuk there will be no gas injected. There will be a maximum of 10,000 barrels of water per day. Average water would be 2,500 barrels of water. And then for the Nuiqsut the gas maximum is about 8,000 -- excuse me, yeah, 8,000 -- eight million cubic feet a day. Average gas would be 2.5 million cubic feet and maximum water is 6,000 barrels maximum and about 1,500 average. And this is in the application. Slide 21, this talks about the estimated average and maximum injection pressures, excuse me. We're expecting about 4,000 psi maximum from our onshore tie-in pad gas compressors. We expect that there will be some pressure loss, maybe in the range of 200 pounds per square inch and we may end up choking those wells, the injection rates back a little bit to manage wellhead pressure. Seawater injection pressure at OTP, the onshore tie-in pad 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 is expected to average about 2,200 pounds per And, again, due to loss in the distribution s' 200 to 400 pounds per square inch to that and that back to maintain reservoir pressure. Slide 22, this is evidence that proposed not fracture through confining zones enabling square inch, stem we may lose again may choke injection will fluids to reach fresh water strata. We've done some modeling on the pools for the Oooguruk and the log data from the Kalubik 1 was processed and estimated that actual fracturing pressure -- oh, excuse me, I'm sorry. Log data from the Kalubik 1 was processed to estimate elastic properties and in-situ stress. We also did some work with the Ivik number 1 well which we drilled in the Nuiqsut zone and indicated a .7 psi per foot fracture gradient. We believe maximum water injection pressure will exceed the parting pressure of both the Oooguruk-Nuiqsut and Oooguru]~- Kuparuk zones. However, the Nuiqsut zone fracturing due to gas injection is not expected to grow beyond the injection interval, based on maximum injection pressure of gas less than that of water injection. And we have included in the application, but I've not included in this presentation a copy of the fracture modeling that was -- it was with our original application. Quality of the formation water, this is slide number 23, we find no oil-water contacts observed in Nuiqsut or Kuparuk 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 7i 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 zones within the Oooguruk development area. However, water was produced within the area from the Kalubik 1, the Colville Delta 2, the Colville Delta State 1 Ivishak and the Kalubik Creek 1 Kuparuk, but no analyses were reported. Salinity calculations used by standard Archie correlation for wet Ivishak reservoirs in nearby wells yield approximately 17 to 18,000 parts per million of sodium equivalent. Oil water contacts have been seen in the area only in the Kuparuk field about 12 miles east of us and the Nanuq formation 20 miles to the southwest. Formation water salinity in the Kuparuk field is reported to be 25,000 parts per minute (sic) total dissolved solids. The Nanuk number 2 well has produced water from the Torok with about 19,000 parts per million. Reference to any applicable fresh water, we haven't requested any fresh water exemptions as stated in AOGCC Disposal Injection Order 31, salinities for the Torok disposal interval in 10 wells within six miles of the disposal well range from 17,000 to 24,000 milligrams per liter. Accordingly, EPA -- and we mentioned we do have a copy of this EPA letter which was submitted with the pool rules and I have a copy here for submittal if you would like a copy of that letter for the record, but EPA rule on August 18th, 2006 that aquifers beneath ODS, that would be our offshore drill site, Oooguruk drill site, do not qualify as underground sources of drinking water. (Slide 24) 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 25 So obviously one of the key questions is what's the expected incremental increase in recovery. We talked about that a little bit earlier, but this is slide 25. For the Nuigsut zone incremental waterflood is expected to be 12 to 20 percent of original oil in place above the primary recovery of four to 10 percent of the original oil in place. Numerical simulation of US-WAG supports an incremental recovery factor over waterflood of two to four percent in the original oil in place. Nuiqsut original oil in place is estimated to be 250 to 300 million barrels within the development area. For the Kuparuk incremental waterflood is expected to be 20 to 24 percent of original oil in place above primary of six to 10 percent. Kuparuk oil in place is estimated at 15 to 25 million barrels within the development area. And then we can talk about -- I can read about the annualized peak production rate. We talked about those a little bit earlier in the testimony. A report on AAC 25.402(c)(15), this is on slide 26, talks about a report of the mechanical condition of each well that has penetrated the injection zones within a quarter of a mile. There are four of those wells and they are. the Kalubik 1, the Colville Delta 2, the Ivik and the Oooguruk number 1. All of those wells have been plugged and abandoned. The reports are filed with the AOGCC and copies were originally submitted with the pool rules application. (Slide 26) 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 21 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 1s 19 20 21 22 23 24 25 And that's all the prepared testimony. If there are any questions we'd be happy to answer any questions you might have. CHAIRMAN SEAMOUNT: Thank you, Mr. Hoffman. I guess it would be appropriate to take a recess and normally we take 10 minutes and it always takes us 20 minutes, so we'll call for a 15 minute recess and maybe we'll be back in 25 minutes. MR. HOFFMAN: Thank you, Mr. Chairman. CHAIRMAN SEAMOUNT: Thank you. (Off record - 9:30 a.m.) (On record - 9:43 a.m.) CHAIRMAN SEAMOUNT: We feel that in the interest of -- in the best interest of Pioneer that when we ask questions that apply to a specific discipline we ought to get the specific engineer or geologist up here and swear them in, make 'em an expert witness and all that. So, I think, we'll start -- we have a few questions for you. Commissioner Norman, do you have any questions at this time? COMMISSIONER NORMAN: I have nothing. CHAIRMAN SEAMOUNT: Okay. Commissioner Foerster. COMMISSIONER FOERSTER: I have a quite a few. Should we swear in the witnesses in mass or just -- so that they can..... CHAIRMAN SEAMOUNT: What do your questions pertain to? COMMISSIONER FOERSTER: They contain (sic) to reservoir pressure, pressure management, well construction, mechanical 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~ 6 7 8 9 10 11 12 13 14 15 16 17 18 I~ 19 20 21 22 23 24 integrity..... CHAIRMAN SEAMOUNT: Okay. How many expert witnesses do you have out there? I would think there would be a drilling engineer and a reservoir engineer or can just one an- ..... MR. HOFFMAN: We have two engineers. CHAIRMAN SEAMOUNT: Huh? MR. HOFFMAN: We have two engineers. UNIDENTIFIED VOICE: WE have two reservoir engineers. CHAIRMAN SEAMOUNT: Okay. Could we get the two reservoir engineers up here, please. MR. HOFFMAN: Mr. Chairman, can I make a comment, also, for the record? CHAIRMAN SEAMOUNT: Yes. MR. HOFFMAN: This is Dale Hoffman again for the record. On slide 18 I indicated that we're not running any logs in our injection wells. We will actually run some wireline sic (ph) line logs on that, so just to clarify that point. CHAIRMAN SEAMOUNT: Okay. MR. HOFFMAN: Thank you. COMMISSIONER FOERSTER: Will you also be doing drilling? MR. HOFFMAN: The question was will we be doing (indiscernible) drilling? UNIDENTIFIED VOICE: There's no wireline (ph) 1og5. It's MWD. 25~~ MR. HOFFMAN: It will be MWD, thank you. Excuse me, 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 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 • • correct that, please, it's MWD. COMMISSIONER FOERSTER: It's not wireline, it's MWD. MR. HOFFMAN: Right, thank you. CHAIRMAN SEAMOUNT: Are we allowed to swear people in I mass? COMMISSIONER NORMAN: Yes. CHAIRMAN SEAMOUNT: Okay. Is there a geologist, is there -- okay. All three of you please raise your right hand? (Oath Administered) IN UNISON: Affirmative. COMMISSIONER NORMAN: You want to have them state their names for the record. CHAIRMAN SEAMOUNT: Okay. Please -- let's start with engineer number one. UNIDENTIFIED VOICE: To the left or to the right? CHAIRMAN SEAMOUNT: Well, you know who number one is, I don't. Please state your name, who you represent. I assume you want to be an expert witness and then let me know what discipline -- or let us know what discipline and proceed. COMMISSIONER FOERSTER: And your qualifications. CHAIRMAN SEA.MOUNT: I think I said that. TESTIMONY OF GREG SANDERS MR. SANDERS: Thank you, Mr. Commissioner. For the record..... CHAIRMAN SEAMOUNT: Qualifications. 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 24 • • 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. SANDERS: For the record my name is Greg Sanders. I'm currently employed with Pioneer Natural Resources as senior staff reservoir engineer. My experience is in the oil and gas industry in Alaska for the last 21 years. I've worked in a number of different capacities with ARCO, Phillips, ConocoPhillips and now Pioneer for the last almost four years. The last 12 years has been primarily expertise in reservoir engineering and that's what I'm here as an expert witness as a reservoir engineering witness. COMMISSIONER FOERSTER: Mr. Sanders, is not a lot of your reservoir engineering expertise in the Kuparuk reservoir? MR. SANDERS: Right, yeah, a couple things I forgot to mention here. Yeah, my expertise pertains with ARCO it was both Prudhoe Bay and Prudhoe Bay PPU and KRU with ConocoPhillips most recently. And also I forgot to mention I have a Bachelor of Science from the University of Missouri at Rolla. CHAIRMAN SEAMOUNT: Commissioner Norman. COMMISSIONER NORMAN: I commend you on a fine education. MR. SANDERS: Yeah, of course, you do. CHAIRMAN SEAMOUNT: Commissioner Forester. COMMISSIONER FOERSTER: Nothing more than what I already asked. CHAIRMAN SEAMOUNT: Is there are no objections Mr. Sanders is ruled an expert witness. 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 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 TESTIMONY OF ANDY BOND MR. BOND: For the record my name is Andy Bond. I'm currently the reservoir engineering manager for Pioneer Alaska. I've been also here in Alaska for 21 years with ARCO, Phillips and ConocoPhillips and mostly recently for the past two and a half years with Pioneer. I have a BS in Petroleum Engineering from the Colorado School of Mines and I have various engineering experience in the Prudhoe Bay Unit, Kuparuk River Unit and .exploration over those past 21 years. CHAIRMAN SEAMOUNT: Commissioner Norman. Commissioner Foerster. Okay, Mr. .Bond, we rule you as an expert witness. Thank you. TESTIMONY OF ROBERT COOK MR. COOK: Mr. Chairman, my name is Robert Cook. I'm the geo-science manager for Pioneer. Been in Alaska now for six months so I'm not an expert in Alaska, but I do have 20 years of industry experience. I'm a Bachelors and Masters graduate in geophysics from the University of Oklahoma. I've worked in -- over this -- is that a good thing. CHAIRMAN SEAMOUNT: Not for her. MR. COOK: Twenty years experience. I begin my career with Exxon working mid-continent and Gulf of Mexico. I moved on from there to a company called Union Texas Petroleum, no longer exists, but in that capacity I worked internationally, R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572IFax 274-8982 ANCHORAGE, ALASKA 99501 26 i • 1 2 3 4 5 6 71 8 9 10 11 12 13 14 15 16 17 II 18 I 19 20 21 22 23 24 25 Tunisia, Venezuela and then moved on to Pioneer 10 years ago. And in my capacity at Pioneer I've been an exploration geophysicist, geoscientist and working in West Africa, South Africa, North Africa and a couple of stints in the Gulf of Mexico for Pioneer. I moved into management for the West Africa project and was the West Africa manager and then most recently, last September, moved up here as the geoscience manager for our Alaska operations. CHAIRMAN SEAMOUNT: Okay. Thank you, Mr. Cook. Commissioner Norman. COMMISSIONER NORMAN: No, questions. CHAIRMAN SEAMOUNT: Commissioner Foerster. COMMISSIONER FOERSTER: None. CHAIRMAN SEAMOUNT: Okay. Without objection Mr. Cook you are ruled an expert witness. So what we'll do is we'll start off with questions and whoever is the appropriate one to answer the question just speak up, state your name first for the record and then we'll have fun. Okay. Commissioner Norman, any questions? COMMISSIONER NORMAN: No questions. CHAIRMAN SEAMOUNT: Commissioner Foerster. COMMISSIONER FOERSTER: I have quite a few. What`s the original reservoir pressure in each reservoir? MR. SANDERS: And, Mr. Commissioner, my name is Greg Sanders. 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 27 • • 1 2 3 4 5 6 7 81 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COMMISSIONER FOERSTER: I'm Mrs. Commissioner. MR. SANDERS: Oh, I'm sorry, Mrs. Commissioner. For the Kuparuk reservoir at a datum (ph) of 6,050 TBD subsea. The estimated average reservoir pressure is 3,150 psi and for the Nuigsut reservoir at a datum of 6,350 TBD subsea. The estimated average reservoir pressure is 3,200 psi. COMMISSIONER FOERSTER: And what's the bubble point pressure for each of those reservoirs? MR. SANDERS: Yeah, the bubble point pressure for the Nuiqsut reservoir is estimated at -- there's a range, but the average is probably either at about 1,900 psi. For the Kuparuk oil the bubble point pressure is estimated at 2,600 psi. COMMISSIONER FOERSTER: Thank you. Are you planning to maintain reservoir pressure at the initial (ph) pressure throughout the production? MR. SANDERS: Ms. Commissioner, the -- we will initiate injection as soon as practically possible. Of course we have a drilling program that will drill producers and then fill in with the injectors as soon as practically possible. So based on what I've seen from the simulation we probably will drop a little bit below average res- -- the initial reservoir pressure as the average pressure for a little while and then do some catchup. And I'm talking about within probably 500 psi of the original pressure is probably the lowest we would go. 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 28 • • 1 2 3 4 5 6 7 8 9~ 10 11 12 13 14 15 16 17 18 19 20 21 22 23 I 2 4 I'' 2 5 II And while the mobility of the reservoir improves with continued water injection that average reservoir pressure would continue to climb. We have approximately a one to one ratio of injector to producer so we will try to match voidage on an instantaneous basis as much as possible. COMMISSIONER FOERSTER: So if you stay within 500 psi it looks like for the Nuiqsut that's not going to even approach bubble point pressure, but for the Kuparuk that could be an issue. MR. SANDERS: Ms. Commissioner, on the Kuparuk I think it's probably an easier story there. At the Kuparuk we will likely be able to match voidage because of the permeability and the mobility in that reservoir, the connectivity of well to well. So I'm not going to commit to the fact that we might go 500 psi below initial reservoir pressure in the Kuparuk. We're more than likely able to maintain a little bit higher pressure in the Kuparuk and that would be -- you know, and that would be the intent. COMMISSIONER FOERSTER: Okay. Let's see, (indiscernible - voice lowers). Which one do I want to ask next. All right. What do you expect the injection pressure to be at the sand face? You gave us injection pressures at the surface. What do you expect injection pressures to be at the sand face? MR. SANDERS: Ms. Commissioner, do I have to state my name every time or am I still, kind of, there. Okay. 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 29 • • 1 2 3 4 5 6 7 8 9 10 i 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 injection pressure we want to be able to inject below fracture gradient and that will be approximately 4,400 psi bottom hole injection pressure, so that would be probably our maximum injection pressure ideally. There's a chance that the injection rate will be too low to match voidage and we may increase the injection pressure above fracture gradient. And the maximum pressure we would ever be able to get to is probably 4,600. It depends on -- well, it depends on Delta P (ph) in our lines so it's -- there is a function of total rate to ODS, but I would -- the estimated maximum pressure is probably in the 4,600 to 4,800 psi range on bottom hole, slightly above fracture gradient. COMMISSIONER FOERSTER: Thank you. Now I've got some questions on well construction. Okay. We understand why you want to have the packer set higher. Could you give us the total vertical depth approximately at which you intend to set the packer in the wells? MR. BOND: This is Andy Bond, Commissioner Foerster. We could anticipate setting those packers within about 200 TVD feet of the reservoir, but because of the high well angles we won't be able to make it within 200 feet measured depth. COMMISSIONER FOERSTER: Okay. And can you give me an approximate measured depth that you anticipate? MR. BOND: Well, all the wells are different obviously. COMMISSIONER FOERSTER: Okay. So if we go with just 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 30 • • 1 2 3 4 5 6' ~~ 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 2 5 II TVD than you can..... MR. BOND: Yeah. COMMISSIONER FOERSTER: .....get that for each of the wells. Thanks. Do you intend -- how high do you intend to place cement in each of the wells? MR. BOND: Commissioner Foerster, I don't know that exact number, but we would certainly meet any regulations for bringing cement top above the producing intervals. COMMISSIONER FOERSTER: Okay. So you do intend to go above the Kuparuk? MR. BOND: Oh, yeah. COMMISSIONER FOERSTER: Okay. How about above the packer? MR. BOND: The cement top? COMMISSIONER FOERSTER: Yeah. MR. BOND: Commissioner Foerster, I would anticipate that in most cases that cement top should be above the packer depth. COMMISSIONER FOERSTER: I only have one more question. I'm told that you did some injectivity tests in your disposal well. Looking at slide 22 you've got some information. Did you use the info that you got from your injection well injectivity tests in putting together what you show on slide 22 and is that information available to us? MR. BOND: Commissioner Foerster, actually the information shown on slide 22 is from the Ivik number 1 exploration well from the fracture treatment that was performed there, but 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 31 • • 1 2 3 4 5 6 ~~~ 8 9 10 11 12 13 14 I, 15 16 17 18 19 20 21 22 23 24 25 are correct, we have done some mini frac (ph) work on our recently drilled disposal well and that information would be available to the Commission. We did a breakdown in -- for the Nuigsut interval as well as the shale above the Nuiqsut interval. COMMISSIONER FOERSTER: So is that information consistent then with what you've shown on slide 22? MR. BOND: Yes, yes. COMMISSIONER FOERSTER: Okay, okay. I think that's all of my questions right now. CHAIRMAN SEAMOUNT: Okay. I have just a few questions. In 2006 EPA gave an aquifer exemption. What area did that aquifer exemption cover, is it the same as the unit or does it go beyond it or..... MR. HOFFMAN: For the record this is Dale Hoffman. I believe it goes beyond the unit. I've got a copy of it here if I could take a look at it. CHAIRMAN SEAMOUNT: Okay. MR. HOFFMAN: Thanks. If you'd care to go on with other questions while I find it..... CHAIRMAN SEAMOUNT: Yeah, we'll go on. MR. HOFFMAN: .....in my packet. CHAIRMAN SEAMOUNT: Okay. MR. HOFFMAN: Thanks. CHAIRMAN SEAMOUNT: Actually you probably answered my 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 I 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 question. If it goes beyond the unit I don't care where it goes. It would be nice to know where it goes, you know, for the future and we probably have that in our records, so..... MR. HOFFMAN: Okay, thank you. CHAIRMAN SEAMOUNT: I was just interested in making sure it was within the area of the injection. Are the proposed injection areas the same as those specified in your pool rules application? MR. HOFFMAN: I'm sorry, was that for me? CHAIRMAN SEAMOUNT: I guess so, no one else has answered. MR. HOFFMAN: This -- could you -- I'm sorry, apparently it is. CHAIRMAN SEAMOUNT: Are your proposed injection areas the same as those specified in your pool rules? MR. HOFFMAN: This is for the record, this is Dale Hoffman. I believe they are. CHAIRMAN SEAMOUNT: Okay. MR. HOFFMAN: I might add that I also hope that if I'm incorrect Pat will smack me on the shoulder and let me know, but I believe they're the same. CHAIRMAN SEAMOUNT: Maybe what we ought to do, we'll leave the record open for a few days so you can double check on that. MR. HOFFMAN: Okay. CHAIRMAN SEAMOUNT: Okay. Injection water compatibility, it wasn't clear whether you tested all the proposed injection 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 91 10 11 12 13 14 15 16 17 i 18 19 20 21 22 23 24 25 fluids for compatibility with formation water within the pools. Have you done the tests or are you waiting to get samples, do the test? (Off record comments) MR. HOFFMAN: Mr. Commissioner, can we get back to you on that? Can that be..... CHAIRMAN SEAMOUNT: Yes. MR. HOFFMAN: .....one of the questions that left for the open..... MR. HOFFMAN: Thank you. CHAIRMAN SEAMOUNT: It seems to me when I was reading through it, it was pretty clear that you tested one, but there were, I think, four other fluids that you listed that had not been tested and if they haven't been tested what are you plans to test the compatibility? I think that's all the questions I have. Do you have any more, Commissioner Norman? COMMISSIONER NORMAN: I have just one question and don't read anything into it 'cause it's a general question that I sometimes ask when we have a panel and various people asking, but my question, again, just to keep the record straight is I would like each of you to answer the question by first stating your name and confirming that you understand that you remain under Oath and that the testimony you have given has been under Oath. So beginning with you, perhaps Mr. Cook and Mr. Hoffman, 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 34 • • 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 could you state your name and just indicate that -- you can simply say what I have said is correct or that you do understand. MR. COOK: Yes, this is Robert Cook and yes, I do understand and agree and my testimony as given is under Oath. MR. HOFFMAN: For the record this is Dale Hoffman and I do understand that my testimony was given under Oath. MR. SANDERS: For the record this is Greg Sanders. I do understand my testimony is under Oath. MR. BOND: And this is Andy Bond. I also understand that my testimony was given under Oath. COMMISSIONER NORMAN: Thank you. CHAIRMAN SEAMOUNT: Are there any questions for comments. from any other interested parties? Yes, Mr. Hoffman. MR. HOFFMAN: Mr. Chair, this is Dale Hoffman for the record. I just want to make sure, will we be getting a list of any follow-up questions as you guys did the last time where we were e-mailed a couple of questions from your office, is that the way you'd care to handle this? CHAIRMAN SEAMOUNT: We have a couple of questions outstanding. I guess for the purposes of good communication we'll have our staff repeat those questions to you to make sure that we're not going crosswise with each other. MR. HOFFMAN: Thank you. CHAIRMAN SEAMOUNT: And we will leave the record open 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 I 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 II 22 23 24 25 until the end of business -- is the 24th a business day? Ten days from now. I don't think it is. (Simultaneous speech) COMMISSIONER NORMAN: The 22nd. CHAIRMAN SEAMOUNT: The 22nd. We'll leave the record opened for the answers to these questions end of business on the 22nd. Okay. Do we have any other comments from the bench? COMMISSIONER NORMAN: Just one comment, Mr. Chairman. I would like to commend generally Pioneer. We may not be satisfied with .some of your questions, but I think your presentation was excellent. MR. HOFFMAN: Thank you. COMMISSIONER NORMAN: You had personnel here that could respond to our questions and I don't mean to disparage others, but we see a variety of presentations and we appreciate very much your taking the time to put things together and to have the personnel here and in the end that saves a lot of time and helps us make a good record and so I thank you and commend you. COMMISSIONER FOERSTER: I'm going to behave. CHAIRMAN SEAMOUNT: You're going to behave. COMMISSIONER FOERSTER: I'm not going to give Mr. Cook any difficulty over his education. CHAIRMAN SEAMOUNT: You ought to see her office. Her office is a shrine and it's not to Oklahoma. 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 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I'd like t:o ditto what Commissioner Norman said and congratulate you guys on this historic development on the North Slope and in Alaska. And without objection..... MR. HOFFMAN: One comment if I may, Mr. Chairman. For the record this is Dale Hoffman and given that it is Valentine's Day and we're spreading the love around I would just like to say that much of the preparation far this was facilitated by your staff sending out a list of recommended items for presentations a:nd that's very helpful, so .thank you for that. CHAIRMAN S:EAMOUNT: And I agree with you on that, too. I think we have an outstanding staff and I'd like to thank you for reminding me that today is Valentines Day. Okay, without objection we'll -- we won't adjourn this hearing. COMMISSIONF~R NORMAN: We are adjourned, but leave the record (simultaneous speech)..... CHAIRMAN SF,AMOUNT: We're adjourned, but we leave the record open. Okay. Thank you very much. (Recessed - 10:03 a.m.) R J R C OUR T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 37 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) }ss. 3 STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5I Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Hearing In the Matter of the Application by PIONEER NATURAL RESOURCES ALASKA, 7 INC. for Area Injection Orders governing development and operation of Oooguruk-Nuigsut and Oooguruk-Kuparuk Oil Pools, 8 Oooguruk Field, Arctic Slope and Beaufort Sea, was taken by William Rice on the 14th day of February, 2008, commencing at 9 the hour of 9:00 a.m., at the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska; 10 THAT this Hearing Transcript, as heretofore annexed, is a 11 true and correct transcription of the proceedings taken by William Rice and transcribed by Suzan Olson; 12 IN WITNESS WHEREOF, I have hereunto set my hand and 13~ affixed my seal this 19th day of February, 2008. 14 ~~~_~. 15 Notary Public in and for Alaska My Commission Expires: 10/10/10 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 • • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION PIONEER NATURAL RESOURCES OOOGUREK-KUPARUK AND OOOGUREK NUIQSUT OIL POOL AREA INJECTION ORDER February 14, 2008 at 9:00 am NAME -AFFILIATION ADDRESS/PHONE NUMBER TESTIFY (Yes or No) (PLEASE PRINT) _-_ ~~.~~ ~I~J ~ ;?~5~~~ ~ ~®~ ~~~ ~~~ ~~ r~ ,~~ ~~~~`° ; ~~~ ~ d 2 ~- ~ -~- ~~ ~_~ ° ~~ y :...~ ~ t, ~`. ~otise o'f Pwhlis ~eaa-ing ~ ' ~~.9~' a State of Alaska ~~, Alaska ®il and Gas C'orese~~ation C®mrr~ission Re: Request for Area Injection Orders for proposed Oooguruk-Nuigsut and Oooguruk-Kuparuk Oil Pools, Oooguruk Field, Arctic Slope and Beaufort Sea, Alaska Pioneer Natural Resources Alaska, Inc. ("Pioneer"), by letter and application dated December 20, 2007, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on December 21, 2007, requests the Commission issue Area Injection Orders ("AIO"), in accordance with 20 AAC 2.460, for their proposed Oooguruk- Nuigsut and Oooguruk-Kuparuk Oil Pools. Pioneer's application may be revie~~~ed at the offices of the Commission, 333 West 7`" Avenue, Suite I00, 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 February 14, 2008 at 9:00 am at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7`" Avenue, Suite 100, Anchorage, Alaska 9901. 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 January 24, 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 February 12, 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 7`" Avenue, Suite 100, Anchorage, Alaska 9901. Protests and comments must be received no later than 4:30 pm on February 11, 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 February 14, 2008 hearing. If you are a person with a disability w o ~ay need special accommodations in order to comment or to attend the u 'c earin ,please contact the Commission's Special Assistant Jody Colombie 793-12 ~~ Orman • • Future Operating Statistics Field Life Cycle Development Project Type Oil, FOR Gross Acres 58,000 Working Interest 70% (Operator) Partner ENI (30%) Gross Reserve Potential 50 - 90 MMBO First Production 2008 Gross Peak Flow Rates 15 - 20 MBOPD Productive Life 25+ Years Development Wells ~35 • ^ Sanction in February `06 ^ Constructed island drill site ^ Installed subsea flowlines ^ Fabricate/set ~ 120 modules ^ Three year development drilling ^ 600+ contractors at peak ^ Total capex $550+ MM ^ First oil in 2008 4 i • :~ NPHI 6 GR St~,Tr ILD_SMf DT_SMP RHOB 15 1 0 40 .75 2.7 -- --- -- - ------- ----- ---- --- - - - - -- - - - --- ---- f~ - - - ---- ----- ---- - ---- ---- --- ---- ---- ---- t15 TGP HRZ I?9 BASE HRZ 132_KUPC. ~S® I.}4 LCU 141_BCU 155 NUIQs'UT 15d NECHELIK 157_N_N EC H ELI K 15s_nt~u Figure 2: Kalubik-1 Type Log. Top Kuparuk C (6083 MD, -6046 TVDSS}, Base KuparukiLCU (6120 MD, -6083 ~I TVDSS), Top Nuiqsut (6354 MD, -6317 TVDSS), Base Nuigsut/Top Nechelik (6473 MD, 6436 TVDSS). ~ I ^ Kuparuk C Sandstone - Lower Cretaceous basal transgressive sandstone `' -Analogue: KRU Kuparuk C - 10' to 40' Estimated Gross Thickness -- 24% Average Porosity - 10-500 and Permeability ^ Nuigsut Sandstone • -- Upper Jurassic, Inner shelf sandstone, highly bioturbated - Analogues: Fiord (Nechilik) and Alpine - 80' to 120' Estimated Gross Thickness -- 10-201 Porosity -- 0.1-50 and Permeability 6 ^ Oooguruk - Nuigsut (Jurassic) - -29 Horizontal Wells Planned - Under-Saturated Water Alternating Gas (US-WAG) - Line-drive Waterflood for patterns if gas is limited - 1:1 injector ratio w/ ESPs on all producers ^ Oooguruk - Kuparuk (Cretaceous) - -6 Horizontal Welts Planned ~ -Line-drive Waterftood - 1:1 injector ratio w/ ESPs on all producers ~'~ ^ Production Commingled at Surface - downstream of measurement ~~ ~ z ~~~~ . _ ~~; ~'~ Oooguruk-Nuigsut Reservoir: - OOIP 250-300 MMstbo - Primary recovery 5-20 MMstbo - Incremental Waterf food recovery 30-60 MMstbo - Incremental US-WAG recovery 2-10 MMstbo - Total Estimated Recoverable Reserves 37-90MMstbo ^ Oooguruk-Kuparuk Reservoir: • - OOIP 15-25 MMstbo - Primary recovery 1-2 MMstbo -Incremental Waterflood recovery 3-6 MMstbo Total Estimated Recoverable Re er 4- s ves 8 MMstbo ~~ - Gravity: -- Viscosity: -- Total GOR: 19 ° to 24 ° API 4.5 to 6.5 cp 250 to 400 scf/STB ^ Oooguruk - Kuparuk - Gravity: 23° to 26° API -- viscosity: -- Total GOR: 2-3 cp 450 to 550 scf/STB 9 ^ Oooguruk-Nuigsut Wells: - Open hole "barefoot completions" ', -Drilled parallel to major faults ~~~ - 7 Undulating lateral sections up to 9,000 in length - 1,700 Injector/Producer lateral spacing ^ Oooguruk-Kuparuk Welts: - Slotted liner completions - Drill parallel to faults - Approximately 5,000' foot lateral length - 3,000' to 5,000' Injector/Producer lateral spacing ^ Production Wells have SSV & SCSSSV ^ Injection Wells have double check valve or single check valve w/ SSV 10 ,v Y;-'rdg µVi _ _ _. ~i k_, y..P63 ~ r=j[+ F t~2t; 41i~ OLVILLE dELTA BT f ~ A' d_CI ~a~s U~ COLVILLE DELTA 1 ~,, I~` \, ~~ ~~' T." ~: ~ ~~. t 1 1 I ~i:l a ~ r;~;' ..__. _. _ !\ TIC E;z'~.-'~" _. _ _._ ETIS 1 SAND 1 `~ ~:, 12 0 A total of 35 to 47 horizontal wells are planned for the Oooguruk development. Five to eight wells for the Oooguruk-Kuparuk reservoir development and 30-39 wells for the Oooguruk- Nuigsut reservoir, split roughly evenly between producers and injectors The depletion plan of both reservoirs will utilize long horizontal wells oriented parallel to one another in a line drive flood pattern with alternating injector and producers. The enhanced recovery flood wilt involve US-WAG in the Oooguruk-Nuigsut .and waterflood in the Oooguruk-Kuparuk. electric submersible pumps (ESPs) will be utilized for lift mechanism in the producers to maximize the value of the reservoir. Se arate injection wells will be used for the Oooguruk-Nuigsut and Oooguruk-Kuparuk poolp. Unitized substances produced from the proposed Oooguruk Oil Pools will be commingled on the surface. Production allocation for the proposed Oil Pools will be based on periodic well tests and producing conditions (e.g. up-time). Injection allocation for the proposed pools will be based on meters on each injection well. Water injection is scheduled to begin as early as May 2008, followed by gas injection when, and if, gas becomes commercially available. Two injection wells for the Kuparuk and 13 injection wells for the Oooguruk-Nuigsut are included in the scope of the project. Surface facilities will be in place on ODS to meter both gas~and water injection volumes to each injector well. Horizontal development wells will be drilled from ODS. For both zones, well layout is a direct tine drive attern confi uratyon with alternatin in'ector and roducers. Planned lateral wells acipn is a roximatel 1500-1700 feet for Nui sut and 2000-4000 ft for P g PP Y q Oooguruk-Kuparuk wells. Different welt spacing may be implemented after analysis of reservoir performance. Horizontal production and injection lateral lengths a ppanned up I' to 9000 feet in the Oooguruk-Nuigsut zone and 3000-5000 feet in the Oooguruk-Kuparuk zone. 15 The Oooguruk development would provide for production from the Oooguruk-Kuparuk and Oooguruk-Nuigsut Pools, as shown in the plats above, in ADL 355036, 355037, 355038, 355039, 389958, 389954, 389950, 389952, and 389959. The Oooguruk-Nuigsut Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Ivik No. 1 well between the depths of 6,408 and i b,488 feet measured depth. The Oooguruk-Kuparuk Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the ARCO Kalubik No. 1 well between the ' depths of 6,083 and 6,120 feet measured depth. I Oooguruk-Kuparuk Pool Description The Kuparuk C Sand at the Kalubik #1 well is the same stratigraphic interval as the upper producing member of the super-giant Kuparuk River Field, which lies dust to the southeast of the Kalubik/Oooguruk area. The stratigraphy, lithology, and interpreted depositional environments of the C member of the Kuparuk Formation have been documented in numerous published studies of the Kuparuk River oil field and are consistent with what has been penetrated in the Oooguruk area. The Kup C sandstone is interpreted as shallow marine transgressive sandstone which was deposited immediately on top of the regional Lower Cretaceous Unconformity (LCU). Regional well correlations in the Colville Delta area indicate that a deposit of more than 10 feet of reservoir-quality Kuparuk sandstone is rare and limited in areal extent. However, in this area, the Fiord, Palm, and Kalubik discoveries all contain over 20' of good quality Kuparuk C oil sand. The Kuparuk C sand consists of a basal transgressive sandstone deposited as shelfal and shoreface sands in early Cretaceous (Neocomian) time. The base of the C sand unit -the LCU - is a regional unconformity that locally represents erosion down to basement along the Barrow arch. The C sand is composed of a i, sequence of bioturbated marine sandstones, siltstones, and mudstones. The presence of glauconite, siderite or other minerals can reduce reservoir quality. Sand thickness and properties are controlled by ~, the marine shelf, accommodation space and the availability of sandy sediment from the source areas. The Kuparuk C sand is concentrated in structural depressions on the downthrown side of syn- depositional faults and within grabens. Across section from the Kalubik No. 3 well to the northwest to the KRU 3W-07 well to the southeast is shown in Figure 2 below. Seismic amplitude and well correlations indicate that the Oooguruk-Kuparuk pool is about one mite wide and seven miles long, associated with a downfaulted northwest-southeast graben. The Kalubik well found 38' of Kuparuk within this graben, whereas only thin, poorly developed Kuparuk was found in wells outside the feature. 16 Oooguruk-Nuiqsut Pool Description ~' The Nuiqsut Sand is one of several Upper Jurassic age oil-bearing sandstones that have been encountered in the Colville Delta area. These are, from oldest to youngest, the Nechelik, Nuiqsut and Alppine sandstones. All three Upper Jurassic sandstones share similar depositional and lithologic characteristics. They are very fine to fine grained quartz aren~tes which were deposited on an inner shelf, likely as marine bars, and contain up to 15% siderite and glauconite in some intervals. Log correlations and regional seismic correlations suggest. that during the Late Jurassic, the Colville delta area was part of a broad, very low gradient marine shelf on a south facing passive margin. Core descriptions from several wells indicate abundant burrowing and bioturbation, carbonaceous material, wavy bedding, asymmetrical ripple lamination, lenticular bedding and interlaminated mudstone. These sedimentary structures are consistent with a lower shoreface depositional setting with limited accommodation space and relatively low rates of sedimentation. Correlations indicate that the Nuigsut sands are relatively continuous on depositional strike for tens of miles and associated with a shoreline that was oriented approximately northeast-southwest. The Nuiqsut interval shales out rapidly downdip toward the Natchiq well to the southeast and is erosionally truncated updip to the northwest by the regional LCU. The structure of the Nuiqsut is controlled by a broad southeast dip, with the subcrop against the LCU to the northwest. Shown in Figure 3 below is a seismic line and log cross section of the Nuigsut subcropping below the LCU. Shown in Figure 4 is structure map of the Nuigsut sand. 17 - ~: ;x The proposed Injection wells have not been drilled and no logs are planned. in the event there are any, copies of the logs will be provided to the commission for review according to the requirements of 20 AAC 25. 18 1~~ ~~'_~ Cement bond logs will be run to demonstrate isolation of injected fluids as required in 20 AAC 25.412(d). Mechanical integrity of the tubing and annulus will be tested to the maximum pressure anticipated to be seen during injection to satisfy the requirements in 20 AAC 25.412(c). Due to the wellbore directional profiles for the injection wells and to facilitate future wellbore interventions, Pioneer requests a waiver from the requirements in 20 AAC 25.412(b) of having the packer set within 200' measured depth of the injection interval to facilitate the completion and long term operation of the well. Packers will need to be set at a depth of more than 200' from the injection interval; however, packers will not be set above the confining zone. 19 ~~ A1:..aasY+~.~ • ~>. Seawater will be used in the foreseeable future, with the possibility of produced water or mixed seawater/produced water used in the distant future. Produced water would be utilized following waterflood breakthrough. Small amounts of non-hazardous fluids (NHF) occasionally may be blended with seawater and produced water for in]ection. These NHF include reverse osmosis brine water, sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp waste water. These NHF will normally be injected into the ODSDW1-44 Class 1 disposal well, but will be blended with the entire stream of Oooguruk Field injection water if necessary. The volume of NHF is expected to be less than 0.1 % and is not expected to affect recovery efficiency in the oil pools. Injection rates will be managed based on voidage in both zones. Individual well injection rates will vary according to reservoir properties encountered. Injection of water and gas will alternate in each injection wells. The maximum expected and average injection well rates are: Max.Gas(MSCFD) Ave.Gas(MSCFD) Kuparuk NA NA Nuiqsut 8,000 2,500 Maximum Water(BPD) 10, 000 6, 000 Average Water(BPD) 2, 500 1,500 20 The gas injection header pressure available from OTP gas compressors is approximately 4,000 psi. Due to pressure losses in the distribution system, welt head injection pressure is expected to be 200 psi lower. Injection wells may be choked to lower wellhead .pressure to manage injection rate. Seawater injection pressure at OTP is expected to average approximately 2,200 psi. Due to pressure losses in the distribution s stem well head injection ressure is ex c ed - y ) p pet to be 200 400 psi lower, depending upon the total field injection rate. Water injection may be choked to lower wellhead pressure to manage ~n)ection rate. 21 ,~.;5~ t Modeling of the proposed Oooguruk Oil Pools indicates that injection fluids will remain within the injection zones, even though the water and gas injection pressure may exceed the parting pressure of both the Nuiqsut and the Kuparuk zones. Log data from Kalubik- 1 well was processed to estimate elastic properties and in-situ stress. Actual fracturing pressure of the Ivik-1 well in the Nuiqsut zone indicated a 0.70 psi /ft. fracture gradient. • Maximum water injection pressure will exceed the parting pressure of both the Oooguruk-Nuiqsut and Oooguruk-Kuparuk zones. Nuiqsut zone fracturing due to gas injection is not expected to grow beyond the injection interval, based on maximum injection pressure of gas less than that of water injection. A report on Oooguruk fracture modeling is included in the application. 22 No oil-water contacts have been observed in the Nuigsut or Kuparuk zones within the Oooguruk development area. Water has been produced within the area, however, from the Kalubik-1, Colville Delta-2, Colville Delta State-1 Ivishak (7 miles west) and the Kalubik Creek-1 Kuparuk (6 miles southeast), but no analyses were reported. Salinity calculations using a standard Archie correlation for wet Ivishak reservoirs in nearby wells yield approximately 17- 18,000 ppm NaCI equivalent. i~ Oil-water contacts have been seen in the area only in the Kuparuk field (about 12 miles east) and the Nanuq formation (20 miles southwest). Formation water salinity in the Kuparuk field is reported to be 25,000 ppm TDS. The Nanuk-2 well has produced water from the Torok Formation with about 19,000 ppm TDS. 23 • • ;,h:'' No freshwater exemptions have been requested or granted. As stated in AOGCC Disposal Injection Order 31, salinities for the Torok disposal interval i n 10 wells within six miles of the disposal well range from 17,000 mg/l to 24, 000 mg / 1. Accordin~l y, EPA ruled on August 18, 2006 that aquifers beneath ODS do not qualify as underground sources o f drinking water. 24 s1. _` _~n~, 4,~~~,~~a,. For the Nuigsut zone, incremental waterflood recovery is expected to be 12-20% of original oil in place (OOIP) above primary recovery of 4- 10% of OOIP. Numerical simulation of US-WAG process supports an incremental recovery factor over waterflood of 2-4% OOIP. Nuigsut ~ ~~ OOIP is estimated at 250-300 MMSTBO within the development area. Annualized peak production rate for the Nuigsut is expected to be between 9,000 and 20,000 BOPD. Annualized waterflood injection rates are estimated to peak between 15,000 and 35,000 BWPD and gas injection rate is estimated to peak between 3 to 20 million standard cubic feet per day (MMSCFD), depending upon the commercial availability of gas. For the Kuparuk zone, incremental waterflood recovery is expected to ~ be 20-24% of original oil in place (OOIP) above primary recovery of 6- 10% of OOIP. Kuparuk OOIP is estimated at 15-25 MMSTBO within the development area. '~ Annualized peak production rate for the Kuparuk is expected to be between 2,000 and 8,000 BOPD. Annualized waterflood injection rates are estimated to peak between 3,000 and 12,000 BWPD. 25 Four abandoned wells penetrate the proposed injection ~ zone within '/4 mile of the injection area. They are the ~, Kalubik-1, Colville Delta-2, Ivik-1 and Oooguruk-1. • 26 #3 Yage 1 of Colombie, Jody J (DOAj From: Davidson, Temple (DNR) Sent: Thursday, January 24, 2008 11:06 AM To: Colombie, Jody J (DOA) Subject: FW: Public Hearing Notice Oooguruk AIO Hi Jodie, A confirming email. I would like to request a hearing for the Oooguruk areawide injection order approval request. Let me know if you need something more, Thank you, Temple Ms. Temple Davidson Petroleum Land Manager State of Alaska Department of Natural Resources Division of Oil and Gas Suite 800 550 West 7th Avenue Anchorage, Alaska 99501 (907) 269-8784 From: Colombie, Jody J (DOA) Sent: Tuesday, January 08, 2008 11:39 AM To: Davidson, Temple (DNR) Subject: RE: Public Hearing Notice Oooguruk AIO ok From: Davidson, Temple (DNR) Sent: Tuesday, January 08, 2008 11:22 AM To: Colombie, Jody J (DOA) Subject: RE: Public Hearing Notice Oooguruk AIO Ni Jody, Thanks - I will make sure to check by !an 24 - if no one else has requested a hearing, then I will ! Ms. Tempfe Davidson Petroleum Land Manager State of Alaska Department of Natural Resources ' Division of Oil and Gas Suite 800 550 West 7th Avenue Anchorage, Alaska 99501 !9071269-8784 From: Colombie, Jody J (DOA) Sent: Monday, January 07, 2008 3:33 PM Subject: Public Hearing Notice Oooguruk AIO 1/24/2008 ~2 STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS F AOGCC R 333 W 7th Ave, Ste 100 ° Anchorage, AK 99501 M 907-793-1238 o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 AGENCY CONTACT GATE OF A.O. Jod Colombie Janu 7 PHONE PCN DATES ADVERTISEMENT REQUIRED: January 8, 2008 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN 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 INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO Anchors e AK 99501 REF TYPE NUMBER AMOUNT 1 VEN z AR1~ 02910 FIN AMOUNT SY CC PGM ~ 08 02140100 2 REQUISITIONED BY: DA TOTAL OF PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS LC ACCT FY NMR DIST 73451 DIVISION APPROVAL: 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A O_02814039 AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF /'1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO.FRM • Notice of Public Hearing State of Alaska Alaska Oil and Gas Conservation Commission Re: Request for Area Injection Orders for proposed Oooguruk-Nuigsut and Oooguruk-Kuparuk Oil Pools, Oooguruk Field, Arctic Slope and Beaufort Sea, Alaska Pioneer Natural Resources Alaska, Inc. ("Pioneer"), by letter and application dated December 20, 2007, and received by the Alaska Oil and Gas Conservation Commission ("Commission") on December 21, 2007, requests the Commission issue Area Injection Orders ("AIO"), in accordance with 20 AAC 25.460, for their proposed Oooguruk- Nuigsut and Oooguruk-Kuparuk Oil Pools. Pioneer'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 February 14, 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 January 24, 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 ca11793-1221 after February 12, 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 February 11, 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 February 14, 2008 hearing. If you are a person with a disability w o ~ay need special accommodations in order to comment or to attend the u 'c earm ,please contact the Commission's Special Assistant Jody Colombie 793-12 s~ Orman • Colombie, Jody J (DOA) From: Ads, Legal [legalads@adn.comJ Sent: Monday, January 07, 2008 3:31 PM To: Colombie, Jody J (DOA) Subject: RE: Please publish tomorrow Attachments: Please publish tomorrow; STOF0330 - Preview.pdf; STOF0330 - Verification.pdf 1 /7/2008 rage i or i Anchorage Daily News lno/zoos Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD # DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 409369 01/08/2008 02814039 STOF0330 $202.52 $202.52 $0.00 $0.00 $0.00 $0.00 $0.00 $202.52 t_ ; ;. ~„ 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 supplemenfal 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. Signed > ~ ~ ~ ; ~ ~~ Notice of Publicliearing StateofAlaska Alaska Oil and Gas Conservation Commission Re: Request for Area ln)ection Orders forpropposed Oodguruk-NUgsut and Oooguruk-KUparuk Oil - Pools, Oooguruk Field, Arctic Slope antl Beaufort Sea, Alaska ' Pioneer NffiUral RBSOUrCeS Alaska; 1nC: ("Pioneer"), by letter andapplication dated,December 20, 2007, and ou Pools. Pioneer's appucation maybe reviewed at the. offices of the Commission, 333 west7th Avenue, Suite 100; Ahchorage, Alaska, or a copy may be obtained y,phpning tllerCOmmission at (907) 793-1221 The Commission has tentatively scfteduled a public hearing on this application for February 1 a, 2008 at 9;00 am at the offices ofthe Alaska oil and Gas Conservation Commission at 333 west 7th Avenu@, suite 100, Anchorage,. Alaska 99501. A person may requestthat the tentatively scheduled hearing be held by filing a written request with the: Commission no later than 4:30 pm on January 24; ' zoo8. If a request for a. hearing is not timely filed, the Commission may consider the issuahce afan order without a hearing: To learn if the:Commssion will hold the public hearing, please-ca11 7 93-1 22 1 after February 12, 2008. - In adtlition,.a person maysubmitawritten protest, or written comments regarding this application and proposal td the Alaska OiI ahd Gas Subscribed and sworn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIR ~ D ~~ A . ~~ ,~ ,,, ~- ,,, ~ ~. ~~1. ... ~~ ~~'~~ ~) } D ? T~=1 comments must be received no later than 4:30 pm on February 11, 2008 except that if the Commission decides to hold a public hearing protests or co(nments must be received no later than the conclusiprrof the February 14, 2008 hearing:. If you are a person with a disability who may need special accommodations ih order to commenter to attend the public hearirig, please contact the COmmission'sSpecial Assistant Jody Colombie at 793-1221. John K. Ndrmap AO-02814039_ Published:'January 8, 2008 • l ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /~ O_02814039 !1 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE 80TTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R Suite 100 333 West 7th Avenue ° . Anch~rage_ AK 9951 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News January 8, 2008 PO Box 149001 Anchorage, AK 99514 TS ENTIRETY ON T SEDATES S pyyN E LINES MUST BE PRINTED IN 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 t'age 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Monday, January 07, 2008 3:33 PM Subject: Public Hearing Notice Oooguruk AIO Attachments: Oooguruk AIO Public Notice.pdf BCC:McIver, C (DOA); Colombie, Jody J (DOA);'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; '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'; 'Catherine P Foerster'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin ; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg ; 'James M. Ruud`; `James Scherr; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; '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; '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'; 'Marguerite kremer'; 'marry'; 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 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.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:0ooguruk AIO Public Notice.pdf; 1 /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 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 Kari 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 ~/j, PO Box 129 } ((~~ Barrow, AK 99723 , 1 /'l_; I ~1 ~- • December 20, 2007 ---... ,, ~: ~~- \ _ x PIONEER NATURAL RESGURCES AiASKA, INC. Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission Alaska Department of Revenue 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Application for Area Injection Order Oooguruk-Kuparuk and Oooguruk Nuiqsut Oil Pools, North Slope, AK Dear Mr. Norman: In accordance with 20 AAC 25.402, Pioneer Natural Resources Alaska, Inc. (Pioneer) as operator of the Oooguruk Unit and on :behalf of the Working Interest Owners,. requests the commission approve the application for Injection Order for the Oooguruk-Kuparuk and Oooguruk-Nuiqsut reservoirs. Enclosed are two printed originals and a disc containing an electronic version of the application. Construction of infrastructure to support development of the proposed oil pools from Oooguruk Drill Site (ODS) is in progress and development drilling is scheduled to commence later this month. First injection into the proposed Oooguruk-Kuparuk and Oooguruk-Nuiqsut Oil Pools is scheduled for 2008 after facilities are completed and additional development wells are drilled. If you have any general questions, please call me at 343-2108. Any technical questions regarding the application should be directed to Greg Sanders, 343-2118 or email, greg.sanders@pxd.com. Sincerely, Dale Hoffman cc: D. Lawler, Eni D. Brown, CPAI K. Banks, DNR Attachment 700 G STREET. STE. 600 ANCHORAGE, ALASKA 99501 ~ MAIN: (907) 277-2700 • Application to the Alaska Oil and Gas Conservation Commission for the Oooguruk-Kuparuk and Oooguruk-Nuigsut Area Injection Order Oooguruk Unit Pioneer Natural Resources Alaska, Inc. (Operator) Eni Petroleum US LLC • Table of Contents :] 1. Introduction 2. 20 AAC 25.402 (c) (1) Plat of Wells Penetrating Injection Zone 3. 20 AAC 25.402 (c) (2) Operators and Surface Owners within'/4 mile of injection operations 4. 20 AAC 25.402 (c) (3) Affidavit Regarding Notification to Operators and Surface Owners 5. 20 AAC 25.402 (c) (4) Description of Proposed Operations 6. 20 AAC 25.402 (c) (5) &(6) Names, Descriptions, and Depths of the Affected Pools & Reservoirs 7. 20 AAC 25.402 (c) (7) Logs of the Injection Wells 8. 20 AAC 25.402 (c) (8) Description of the proposed method for demonstrating mechanical integrity of the Casing and Tubing 9. 20 AAC 25.402 (c) (9) Injection Fluid Analysis and Injection rates 10. 20 AAC 25.402 (c} (10) Estimated Average and Maximum Injection Pressures 11. 20 AAC 25.402 (c) (11) Evidence that proposed injection will not fracture through confining zone(s) enabling fluids to reach fresh water strata 12. 20 AAC 25.402 (c} (12) Quality of Formation Water 13. 20 AAC 25.402 (c) (13) Reference to Any Applicable Fresh Water Exemption 14. 20 AAC 25.402 (c) (14) Expected Incremental Increase in Recovery due to Injection 15. 20 AAC 25.402 (c) (15) A report on the Mechanical condition of each well that has penetrated the injection zone(s) within'/a mile of an injection well. List of Figures Figure 1 - Oooguruk Type Log Figure 2 -Northwest -Southeast Cross Section of Kuparuk C Sand Figure 3 - Nuigsut Subcrop Beneath the LCU Figure 4 -Nuigsut Structure Map Figure 5 -Cross Section Through Nuigsut Sand from Southwest to Northeast Figure 6 -Kalubik-1 Type Log Figure 7 -Kalubik-1 Example Injection Well Log Suite List of Attachments Attachment 1 -Proposed Oooguruk-Nuigsut and Proposed Oooguruk-Kuparuk Oil Pools Attachment 2 -Plats showing all existing and currently proposed wells penetrating the injection zones in the proposed injection area Attachment 3 -Affidavit Attachment d - ~plyillc rlclta 7 \ff/e11 ~~mpl8t1.7i i Repvrt Attachment 5 - Ivik-1 Well Completion Report 1 • • Attachment 6 - Kalubik-1 Well Completion Report Attachment 7 - Oooguruk 1 Well Completion Report Attachment 8 -Fracture Containment for Oooguruk-Kuparuk and Oooguruk-Nuigsut during Water Injection Operations 2 • Introduction • Pioneer Natural Resources Alaska, Inc., as operator of the Oooguruk Unit (OU), submits this document to the Alaska Oil and Gas Conservation Commission (AOGCC) on behalf of the Pioneer Natural Resources Alaska, Inc. (Pioneer), the Operator, and Eni Petroleum US LLC (Eni), 70% and 30% working interest owners (WIOs), respectively. This area injection order application seeks AOGCC endorsement and authorization for the proposed Oooguruk under-saturated water-alternating-gas (US-WAG) project in the OU. This project involves the development of two zones from Oooguruk Drill Site (ODS): Oooguruk-Kuparuk and Oooguruk-Nuigsut. This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). The Oooguruk-Kuparuk Oil Pool will employ a horizontal well line-drive pattern waterflood as a secondary recovery project. A horizontal pattern Under-Saturated Water-Alternating-Gas (US-WAG) flood is planned for the Oooguruk-Nuigsut Oil Pool. This Pool will employ cyclic injection of immiscible gas and water as an enhanced recovery project. Lab experiments show that Oooguruk-Nuigsut under-saturated oil swells when in contact with gas, which lowers the in-situ viscosity thus improving waterflood recovery. It should be noted that given the commercial uncertainties surrounding the availability and delivery of gas to the Oooguruk project, the future volume and rate of injected gas cannot be predicted. Nevertheless, one or more Oooguruk-Nuigsut patterns will likely employ some form of WAG injection. For each proposed oil pool (Oooguruk-Kuparuk and Oooguruk-Nuigsut), the WIOs plan to form a corresponding separate participating area within the Oooguruk Unit. Preliminary proposed pools are shown on Attachment 1 with the present Oooguruk Unit boundary. Pioneer, as operator and on behalf of the WIOs, will apply to the State of Alaska for the formation of an Oooguruk-Nuigsut Participating Area and an Oooguruk-Kuparuk Participating Area roughly concurrent with this application (Attachment 2). Concurrent with this application for Area Injection Order, Pioneer, as operator of the OU and on behalf of the WIOs, is seeking a Conservation Order by the Commission regarding the classification and rules to govern the development of the proposed Oooguruk-Kuparuk and Oooguruk-Nuigsut Oil Pools. Development drilling will start in November 2007 at ODS and Oooguruk production startup is planned for 2nd_3rd quarter 2008, with injection startup as early as February 2008, creating the need to establish an Area Injection Order for the proposed Pools. 3 • • 20 AAC 25.402 (c) (1) Plat of Wells Penetrating fniection Zone Attachment 2 shows all existing and currently proposed wells penetrating the injection zones in the proposed injection area. The map also shows the areal extent of the planned development and injection wells relative to preliminary participating areas within the Oooguruk Unit. 20 AAC 25.402 (c) (2) Operators and Surface Owners within'/4 mile of iniection operations Operator: Pioneer Natural Resources Alaska, Inc. Surface Owner: State of Alaska, Department of Natural Resources 20 AAC 25.402 (c) (3) Affidavit Reaarding Notification to Operators and Surface Owners Please see Attachment 3 20 AAC 25.402 (c) (4) Description of Proposed Operations Pioneer is proposing to. develop the Oooguruk Unit with wells drilled from the Oooguruk Drillsite (ODS), a man-made gravel drillsite in Harrison Bay of the Beaufort Sea, with offshore and onshore flowlines with a tie into existing onshore production facilities at KRU drillsite DS-3H. ODS is located in four feet of water approximately 2'/z miles northeast of the mouth of the Colville River Delta and nine miles west of Oliktok Point. The trench-buried subsea flowline would transfer produced fluids from the production drillsite to shore, then transition to above ground flowline supported on vertical support members (VSMs) for atie-in at DS-3H of the Kuparuk River Unit. A total of 35 to 47 horizontal wells are planned for the Oooguruk development. The Oooguruk-Nuigsut reservoir development is planned with 30-39 wells split roughly evenly between producers and injectors. The Oooguruk-Kuparuk reservoir development is planned with five to eight wells, again roughly evenly split between producers and injectors. The depletion plan. of both reservoirs will utilize long horizontal wells oriented parallel to one another in a line drive flood pattern with alternating injector and producers. The enhanced recovery flood will involve US-WAG in the Oooguruk-Nuigsut and waterflood in the Oooguruk-Kuparuk. electric submersible pumps (ESPs) will be utilized for lift mechanism in the producers to maximize the value of the reservoir. Separate injection wells will be used for the Oooguruk-Nuigsut and Oooguruk-Kuparuk pools. Unitized substances produced from the proposed Oooguruk Oil Pools will be commingled on the surface. Production allocation for the proposed Oil Pools will be based on periodic well tests and producing conditions (e.g. up-time). Injection allocation for the proposed pools wilt be based on meters on each injection well. Water injection is scheduled to begin as early as February 2008, followed by gas injection when, and if, gas becomes commercially available. Two injection wells for the Kuparuk and 13 injection wells for the Oooguruk-Nuigsut are included in the scope of the project. Surface facilities will be in place on ODS to meter both gas and water injection volumes to each injector well. Horizontal development wells will be drilled from ODS. For both zones, well layout is a direct line drive pattern configuration with alternating injector and producers. Planned lateral well spacing is approximately 1500-1700 feet for Nuigsut and 2000-4000 ft for Oooguruk-Kuparuk wells. Different well spacing may be implemented after analysis of reservoir performance. Horizontal production and injection lateral lengths a planned up to 9000 feet in the Oooguruk-Nuigsut zone and 3000-5000 feet in the Oooguruk-Kuparuk zone. The ODS is a typical North Slope drillsite with drillsite facilities for managing and measuring fluids and space for the drilling rig and consumables. Produced fluids and injection fluids will exit and enter the drillsite via a 5.5 mile subsea buried flowline bundle to shore and a 2.5 mile YSM s~~pported f!o:~~!ines to Oooguruk Tie-in Pad (OTP) immediately adjacent to DS 3H of the Kuparuk River Unit. 4 • • The project utilizes many of the same technologies that are standard to North Siope fields, with. one exception. A multiphase meter wil{ be used for custody transfer from Oooguruk field to the KRU owned process facilities. The on-pad facilities, pipelines and power lines are being constructed and installed using standard oilfield materials and equipment and experienced North Slope contractors. The design chosen for the ODS and OTP facilities has been engineered based on accepted engineering practices for the North Slope. The project includes produced fluid, water injection, and gas injection flowlines that connect to the KRU facilities, adjacent to DS 3H. Drillsite facilities at ODS include the following: • Production, test, gas lift, gas injection, and water injection headers; • Tie-in slots for 48 wells (including spares) within wellbay modules; • Electrical and instrumentation modules with transformers, switch gear, and telecommunications; • Multiphase meter for individual well tests; • Emergency shut down (ESD) system; • Water injection line pig launcher/receiver, • Production line pig launcher/receiver, • Chemical injection and storage module; • Wellhead hydraulic panels (between well bays on interconnects); and • Lighting, surveillance, and communication equipment. Four cross-country flowlines have been constructed to connect the ODS to the OTP. The following pipelines are in-place: • 12" diameter produced fluid flowline • 8" diameter water injection flowline • 6" diameter gas injection flowline • 2" diameter diesel/base oil flowline The approximate length of flowlines from OTP to the coast line is 2~/z miles. The approximate length from the coastline to ODS is 5'/z miles. Power and fiber optic cables were buried alongside the flowlines. The pipe bundle was installed in a trench approximately four to six feet below the mudline and back-filled with native soil. Power and fiber optic cables were suspended by messenger cable below the pipeline VSMs. The onshore section was installed on VSMs which span a distance of approximately 65 feet. Additionally, tie-ins at the OTP include a produced line pig receiver, a water injection line pig launcher, storage tanks, power generation, and gas compressors. 20 AAC 25.402 (c1 (5) &(6) Names Descriotions and Depths of the Affected Pools & Reservoirs Location The Oooguruk development would provide for production from the Oooguruk-Kuparuk and Oooguruk- Nuigsut Pools (Attachment 1) in ADL 355036, 355037, 355038, 355039, 389958, 389954, 389950, 389952, and 389959. Application is being made during 2007 to the State of Alaska, Department of Natural Resources, Division of Oil and Gas ("the Division") to approve a Nuigsut Participating Area and a Kuparuk Participating Area. Attachment 2 depicts the proposed Participating Area lands. Ultimately, all lands that are reasonably estimated through use of geologic, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities will be included within the respective participating areas. • • Pool Definitions: The Oooguruk-Nuigsut Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Ivik No. 1 well between the depths of 6,408 and 6,488 feet measured depth. The Oooguruk-Kuparuk Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the ARCO Kalubik No. 1 well between the depths of 6,083 and 6,120 feet measured depth. K~LUBIK 1 GR_SMT ILD_SMT 0 150 1 100 - -~-------- ---- r ----- --- -- - 1- - i- = ------a-- - --- -- - - - ------ - ---- ~ ---- - - ~ - ; ------1---- I--- -- - - 1 - ------------- --~- - - -- ' - - -~- - I- - --- -~--- -- - - -----------------= --- - ------ ----- 7-- - - - _ I ~ __________________i_ ___._ _-_.____ ~ -.. ____~ __- __ - _ - - __. _-.. y_.--- ___ __ _ ~ ~-- 1 _________________ I_'____'-___ _____ - ~ - _ ___ -_ - _ . - . . f __-_ '-- - ___ -~ __ _ _ _ _ ___ _ _ _ _ _ _I___ ____ _______ ~ _____ ___ __ _ _ _ _ 1 ______~-___ ___ __ _ _ i - ---- ---------°-I---- ------------- ------ - - -- - - - - ; a ------ ---- --- -- - - - --- -_--- ---I--- ----------- --- ~ --- - --- -- - ------;_-- ~ --- -- - - ~ ------------- ----j----- --- - - -- --- - - (~ ----- 1 ---- -- - - - - } ~ - -- -~- ~ -- - - ---- ---- ------------- ------ ------- --- d'- -- ------~ - ---- - - - + ---- --- --a--- _ - _ _ ~ --- - -- ---- - - -- - ---- - - -- - - 1 ------------- ------------ ---- - '----- ---- -- '1 - - - - - - ~ --....--i---- --- -- - - - - ________________ __________________ ____-_ __-_ _ _ - _ 1 --__--J_--_ - __ _ _ - s CO Figure 1- Oooguruk Type Log Oooguruk-Kuparuk Pool Description 32_KUPC ~i aru 55_NUIQSUT 56_NECHELIK 57_B_NECHELI K The Kuparuk C Sand at the Kalubik #1 well is the same stratigraphic interval as the upper producing member of the super-giant Kuparuk River Field, which lies just to the southeast of the Kalubik/Oooguruk area. The stratigraphy, lithology, and interpreted depositional environments of the C member of the Kuparuk Formation have been documented in numerous published studies of the Kuparuk River oil field end are consiste~~t vvith vJhat has bee.. penetrated in the Ooogiariak area. The Kup C sandstone is interpreted as shallow marine transgressive sandstone which was deposited immediately on top of the regional Lower Cretaceous Unconformity (LCU). Regional well correlations in the Colville Delta area 6 • • indicate that a deposit of more than 10 feet of reservoir-quality Kuparuk sandstone is rare and limited in areal extent. However, in this area, the Fiord, Palm, and Kalubik discoveries all contain over 20' of good quality Kuparuk C oil sand. The Kuparuk C sand consists of a basal transgressive sandstone deposited as shelfal and shoreface sands in early Cretaceous (Neocomian) time. The base of the C sand unit -the LCU - is a regional unconformity that locally represents erosion down to basement along the Barrow arch. The C sand is composed of a sequence of bioturbated marine sandstones, siltstones, and mudstones. The presence of glauconite, siderite or other minerals can reduce reservoir quality. Sand thickness and properties are controlled by the marine shelf, accommodation space and the availability of sandy sediment from the source areas. The Kuparuk C sand is concentrated in structural depressions on the downthrown side of syn-depositional faults and within grabens. Across section from the Kalubik No. 3 well to the northwest to the KRU 3W-07 well to the southeast is shown in Figure 2 below. Seismic amplitude and well correlations indicate that the Oooguruk-Kuparuk pool is about one mile wide and seven miles long, associated with a downfaulted northwest-southeast graben. The Kalubik well found 38' of Kuparuk within this graben, whereas only thin, poorly developed Kuparuk was found in wells outside the feature. NW ~-KALUBIK-3 •KALUBIK-1 -~KRU 3UV-07 SE B!00 6400 8500 6500 Figure 2: Northwest -Southeast Cross Section of Kuparuk C Sand Oooguruk-Nuiqsut Pool Description The Nuiqsut Sand is one of several Upper Jurassic age oil-bearing sandstones that have been encountered in the Colville Delta area. These are, from oldest to youngest, the Nechelik, Nuiqsut and Alpine sandstones. All three Upper Jurassic sandstones share similar depositional and lithologic characteristics. They are very fine to fine grained quartz arenites which were deposited on an inner shelf, likely as marine bars, and contain up to 15% siderite and glauconite in some intervals. Log correlations and regional seismic correlations suggest that during the Late Jurassic, the Colville delta area was part of 7 • • a broad, very low gradient marine shelf on a south facing passive margin. Core descriptions from several wells indicate abundant burrowing and bioturbation, carbonaceous material, wavy bedding, asymmetrical ripple lamination, lenticular bedding and interlaminated mudstone. These sedimentary structures are consistent with a lower shoreface depositional setting with limited accommodation space and relatively low rates of sedimentation. Correlations indicate that the Nuiqsut sands are relatively continuous on depositional strike for tens of miles and associated with a shoreline that was oriented approximately northeast-southwest. The Nuiqsut interval shales out rapidly downdip toward the Natchiq well to the southeast and is erosionally truncated updip to the northwest by the regional LCU. The structure of the Nuiqsut is controlled by a broad southeast dip, with the subcrop against the LCU to the northwest. Shown in Figure 3 below is a seismic line and log cross section of the Nuiqsut subcropping below the LCU. Shown in Figure 4 is structure map of the Nuiqsut sand. J. 8 ~ • S N 9 Figure 4: Nuiqsut Structure Map Figure 5: Cross Section Through Nuiqsut Sand from Southwest to Northeast • • The Nuiqsut sand has similar reservoir characteristics to the Alpine sand being developed further west by ConocoPhillips, but has considerably more clay. Clay content ranges from 20 - 30% in the net pay intervals of the Nuiqsut sand over the region of interest. Petrographic and thin section analysis shows the dominant Nuiqsut facies to be bioturbated sand composed of clean fine-grained sand mixed with millimeter-scale clay-filled burrows. The bulk of the connate water is bound in these burrows. The Nuiqsut reservoir in the development area has been divided into five reservoir zones or flow units (Figure 5). The Kuparuk C reservoir is overlain by thick Cretaceous marine shales of the Kalubik (about 200'), HRZ (about 100') and Hue formations (> 1000'). Brookian turbidites that are found locally within the Hue are poorly developed in this area. Figure 6 shows Kalubik-1 type log. Between the Kuparuk C and Nuiqsut reservoirs is the Lower Cretaceous Milluveach shale which ranges in thickness from 350' to the southeast to 150' to the northwest. There is no Kuparuk A development in this area. Underlying the Nuiqsut reservoir is 50-100' of Upper Jurassic Nechelik formation, which in this area is very fine grained sand and silt with poor porosity and permeability. Underlying the Nechelik is over 1000' of Lower to Middle Jurassic Kingak marine shales. 10 • KCAL LI ~ I ~J 11' TGP HRZ 129 IiA1.U 51 F. ,~~' ,~a~~U NUIt~SUT 1 ~~'_~VEGHELIK KINGi~}: LUUP, 1.F,S hA.IU t1U SHf+' RI'•~:EF Fht ?12 U SHUBLIK. Oooguruk-Kuparuk oil is expected to be similar in characteristics to the Kuparuk formation oil within the KRU. Whole oil gas chromatography from Kalubik and KRU 3A-16 oil samples • Kalubik-1 Kuparuk measures 26° API and 1.5% sulfur vs KRU 3A-16 at 23° API and 1.7% sulfur. • Kuukpik-3 Kuparuk is similar (23° API and 1.5% sulfur). Lab analyses of Kalubik-1 Kuparuk DST • 25.5° API and 450 scf/stb GOR (stated as similar to KRU 2A-02 PVT) 11 Figure 6: Kalubik-1 Type Log • • PVT samples for analyses of local Kuparuk oils were not taken. Oil characteristics of KRU from AOGCC reported by operator based on PVT analyses. • 24° API, 2.2 cp viscosity, 516 scf/stb GOR, 0.7 sg gas gravity, 1.26 FVF, 2600 saturation pressure Nuiqsut fluids were characterized with samples from the Ivik No. 1 production test, augmented with subsurface samples from Oooguruk No. 1 gathered via wireline deployed Repeat Formation Tester (RFT). PVT relationships were determined for the Nuiqsut interval with recombined samples of gas and oil sampled from Ivik No. 1. Described below are the fluid properties that describe the Nuiqsut oil. These properties are based on preliminary studies in 2003 and a more comprehensive set of tests performed in 2005. PVT from Oooguruk No. 1 Nuiqsut RFT samples. • Lab-measured oil gravity range of 19.1 ° to 23.9°, but good compositional consistency of flash oils. • Crude viscosities at reservoir conditions range from 4.5 cp to 6.5 cp. Variation due in part to range of observed GOR (238 ~ 305 scf/STB) • Psat 1856 to 2401 psi Surface measurements from flow test • Oil gravity range 20.1 ° to 21.2°, inconsistent tank-oil compositions, final sample more in line with RFT measurements • Total GOR's -250 to -400 scf/STB Lab Measurements • Pour point (< -32° F) -not an issue. Wax (2% to 4% weight). Asphaltenes are possible. Experimental PVT Lab Measurements • Results indicate that 1950 psi saturated oil swells and reduces in viscosity with introduction of gas. Experimental Data %mol gas Psat in GOR Visc Oil FVF psi mixture scf/stbo cp stb/rvb 1950 0% 265 5.46 1.1522 2349 20% 333 5.12 1.1909 3057 20% 440 3.91 1.2323 3875 30% 570 3.23 1.274 5564 45% 869 2.09 1.3573 12 • • 20 AAC 25.402 (c) (7) Logs of the Infection Wells The proposed Injection wells have not been drilled. When they are, copies of the logs will be provided to the commission for review according to the requirements of 20 AAC 25. Atypical log suite for the injection wells is provided for the Kalubik-1 well in Figure 7. KALU BI K 1 NPHI o.s o GR_SMT ILD_SMT RHOS PEF 0 150 1 100 1.75 2.75 0 ~ 10 t _ I r 7 ~'? + } I j ~ i =4 _ - - ' - ~ - f r ~- -- -- - ~ i J I ~ _ - r , - - ;- _.. h ~r _ F - .- _ ~ -- - ~ _ T - -- - q -- ~ F - - - - ,~ j ~ 1 ~'~ I ~ - ~ 1 f j r t - j` ~ z }- 1 _ - _ = - - ~ ~ i a{} - - E - ~ -I - _ -- ~ - 1 1 _ ~ ~- -- g -- - i= + ~ ___ _ ~ _ ~ ±_ - -i -Ft . _ _ - ~ - -~- ~ ~ - = ~rt _ a - I i - -- - O ~} t- - ~ - + - - -~ - ~ ' -- - ____________ _ ________ M L ~ ~ __-___ __-_- _,_-_ -- __ __ ___ _ - -..-... -.... . -__J. - _ _ _ .. I_ ... - - - . _ . I _ I. ._.-_ .-..-.. -~..._-_ ....' _.. ~ .--_ _ .. .- _- -... -. _'~ y - 1._.-- 1 - ..-- --. - -- - --- -- --._--__ -_------~. -,- - - _- - r L .S J Q _ t~-_-_ __ _ _ _ F -_-_- -_. _ - __- --_ __ -~_~ _ __ ___ __ ___ __ - 1 ____________ __ ________ _-. _ - _ s_--_ _ -_ - _ - i r : __ - _-_ _.-__ I --_ ____-_ _ - __ _- _-_ ___ --- - - -- - - -- ~ a a-- - + ~ I - - - ~ -- _ ~ -- ____ ~ - - t ~ ~` - 1 - ..... ........ ........... ._. ~.- .-_-_ -_ _ - 4 ___-- -_..-..~-_-_ --_-. ~~ --_. __ ~ n _ _~___ ____ ________ __ _______ ___.- _ _ i-_-- t__-- _ - _ _ , _ _ _ 132_KUPG t^7 to11UJYE4GH 741 BrL~ 155_NUIQSUT 156_NECHELIK KINGCU:_LWR Figure 7 -Kalubik-1 Example Infection Well Lop Suite 20 AAC 25.402 (c) (8) Description of the proposed method for demonstrating mechanical integrity of the Casing and Tubing: Cement bond logs will be run to demonstrate isolation of injected fluids as required in 20 AAC 25.412(d). Mechanical integrity of the tubing and annulus will be tested to the maximum pressure anticipated to be seen during injection to satisfy the requirements in 20 AAC 25.412(c). Due to the wellbore directional profiles for the injection wells and to facilitate future wellbore interventions, Pioneer requests a waiver from the requirements in 20 AAC 25.412(b) of having the packer set within 200' measured depth of the injection interval to facilitate the completion and long term operation of the well. Packers wilt need to be set at a depth of more -than 200' from the injection interval; however, packers will not be set above the confining zone. 13 • • 20 AAC 25.402 (c) (9) Infection Fluid Analysis and Infection rates: The water injection plan for the Oooguruk-Kuparuk and Oooguruk-Nuigsut Pools is based on a single injection flowline between CPF-3 and DS-3A, which is the takeoff point for Oooguruk water. Seawater will be used in the foreseeable future, with the possibility of produced water or mixed seawater/produced water used in the distant future. Produced water would be utilized following waterflood breakthrough. Small amounts of non-hazardous fluids (NHF) occasionally may be blended with seawater and produced water for injection. These NHF include reverse osmosis brine water, sump fluid, hydrotest fluid, rinsate generated from washing mud hauling trucks, excess well work fluids, and treated camp waste water. These NHF will normally be injected into the ODSDWI-44 Class 1 disposal well, but will be blended with the entire stream of Oooguruk Field injection water if necessary. The volume of NHF is expected to be less than 0.1 % and is not expected to affect recovery efficiency in the oil pools. The anticipated gas injection composition from CPF-3 gas lift system is as follows: Component Mol Fraction Methane 0.81887 Ethane 0.07184 Propane 0.04455 Iso-Butane 0.01225 N-Butane 0.02548 Iso-Pentane 0.00385 N-Pentane 0.00337 N-Hexane 0.00085 Heptane 0.00025 CO2 0.01179 Nitrogen 0.00690 Representative seawater composition is as follows: Water Anal sis Unit Result Chloride m /I 20190 Sulfate m /I 2810 Aluminum m /I <0.1 Barium ~ m /I <1 Boron m /I 5 Calcium m /I 410 Chromium m /I <0.2 Iron m /I <0.1 Lithium m /L <0.5 Ma nesium m /I 1207 Man anese m /I 0.006 Phosphorus m /I <0.1 Potassium m /I 291 Silicon m /I <1 Sodium mg/I 10130 Strontium m /I 10 Zinc m /I <0.1 Bicarbonate m /I 310 Carbonate m /I 0 H --- 7.33 Specific Gravity Q 60° F --- 1.0283 14 • • Injection rates will be managed based on voidage in both zones. Individual well injection rates will vary according to reservoir properties encountered. Injection of water and gas will alternate in each injection wells. The maximum expected and average injection well rates are: Maximum Gas Average Gas Maximum Water Average Water Injection Rate Injection Rate Injection Rate Injection Rate (MSCFD) MSCFD) (BPD) (BPD) Kuparuk Well N/A N/A 10,000 2,500 Nuiqsut Well 8,000 2,500 6,000 1,500 20 AAC 25.402 (c) (10) Estimated Average and Maximum Iniection Pressures The gas injection header pressure available from OTP gas compressors is approximately 4,000 psi. Due to pressure losses in the distribution system, well head injection pressure is expected to be 200 psi tower. Injection wells may be choked to lower wellhead pressure to manage injection rate. Seawater injection pressure at OTP is expected to average approximately 2,200 psi. Due to pressure losses in the distribution system, well head injection pressure is expected to be 200-400 psi lower, depending upon the total field injection rate. Water injection may be choked to lower wellhead pressure to manage injection rate. 20 AAC 25.402 (c) (11) Evidence that proposed Iniection will not fracture through confining zone(s) enabling fluids to reach fresh water strata Modeling of the proposed Oooguruk Oil Pools indicates that injection fluids will remain within the injection zones, even though the water and gas injection pressure may exceed the parting pressure of both the Nuiqsut and the Kuparuk zones. Digital log data from Kalubik-1 well was processed to estimate elastic properties and in-situ stress. Actual fracturing pressure of the Ivik-1 well in the Nuiqsut zone indicated a 0.70 psi/ft. fracture gradient. Maximum water injection pressure will exceed the parting pressure of both the Oooguruk-Nuiqsut and Oooguruk-Kuparuk zones. Nuiqsut zone fracturing due to gas injection is not expected to grow beyond the injection interval, based on maximum injection pressure of gas less than that of water injection. A report on Oooguruk fracture modeling is in Attachment 8. 20 AAC 25.402 (cl (12) Quality of Formation Water No oil-water contacts have been observed in the Nuiqsut or Kuparuk zones within the Oooguruk development area. Water has been produced within the area, however, from the Kalubik-1 and Colville Delta-2 wells. Neither well reported analysis of the water. Muddy formation water was also produced from the Colville Delta State-1 Ivishak (7 miles west) and the Kalubik Creek-1 Kuparuk (6 mites southeast), but no analyses were reported. Salinity calculations using a standard Archie correlation for wet Ivishak reservoirs in nearby wells yield approximately 17-18,000 ppm NaCI equivalent. Oil-water contacts have been seen in the area only in the Kuparuk field (about 12 miles east) and the Nanuq formation (20 miles southwest). Formation water salinitiy in the Kuparuk field is reported to be 25,000 ppm TDS. The Nanuk-2 well has produced water from the Torok Formation with the following composition, about 19,000 ppm TDS: Sodium 7,000 ppm Potassium 50 ppm Calcium 200 ppm Magnesiu~ ~ ~ 0 pp. Bicarbonate 00 ppm Sulfate 0 ppm Chloride 10,600 ppm 15 • • 20 AAC 25.402 (c) (13) Reference to Any Applicable Fresh Water Exemption No freshwater exemptions have been requested or granted. As stated in AOGCC Disposal Injection Order 31, salinities for the Torok disposal interval in 10 wells within six miles of the disposal well range from 17,000 mg/1 to 24,000 mg/I. Accordingly, EPA ruled on August 18, 2006 that aquifers beneath ODS do not qualify as underground sources of drinking water. 20 AAC 25.402 (c) (14) Expected Incremental Increase in Recovery Due to Iniection A horizontal pattern US-WAG flood is proposed for the Oooguruk-Nuiqsut reservoir with alternating producer/injector patterns. Injection and subsequent absorption of gas into the under-saturated reservoir oil will result in lower in-situ viscosity and improved enhanced oil recovery (EOR) in the Oooguruk-Nuigsut reservoir. Lab experiments show that Nuiqsut under-saturated oil swells when in contact with gas, which lowers the in-situ viscosity and swells the oil. Reservoir simulation has shown incremental recovery from this process. Implementation of FOR is integral to the Oooguruk project. The injected water helps maintain reservoir pressure. The gas should effectively be absorbed into the contacted oil. However, by alternating between gas and water injection, any potential gas channeling is minimized. The Kuparuk reservoir will be waterflood only, which will maintain reservoir pressure and result in incremental recovery over primary recovery process. For the Nuiqsut zone, incremental waterflood recovery is expected to be 12-20% of original oil in place (OOIP) above primary recovery of 4-10% of OOIP. Numerical simulation of US-WAG process supports an incremental recovery factor over waterflood of 2-4% OOIP. Nuiqsut OOIP is estimated at 250-300 MMSTBO within the development area. For the Kuparuk zone, incremental waterflood recovery is expected to be 20-24% of original oil in place (OOIP) above primary recovery of 6-10% of OOIP. Kuparuk OOIP is estimated at 15-25 MMSTBO within the development area. Annualized peak production rate for the Nuiqsut is expected to be between 9,000 and 20.000 barrels of oil per day (BOPD). Annualized waterflood injection rates are estimated to peak between 15,000 and 35,000 -barrels of water per day (BWPD) and gas injection rate is estimated to peak between 3 to 20 million standard cubic feet per day (MMSCFD), depending upon the commercial availability of gas. Annualized peak production rate for the Kuparuk is expected to be between 2,000 and 8,000 barrels of oil per day (BOPD). Annualized waterflood injection rates are estimated to peak between 3,000 and 12,000 barrels of water per day (BWPD). 20 AAC 25.402 (c) (15) A report on the mechanical condition of each well that has penetrated the Iniection zone(s) within'/a mile of an Iniection well. Four abandoned wells as shown in Attachment 2 penetrate the proposed injection zone within'/a mile of the injection area: Kalubik-1, Colville Delta-2, Ivik-1 and Oooguruk-1. Well completion reports and schematics are attached for the four abandoned wells. 16 • Attachnnent 1 Proposed Oooguruk-Nuigsut and Proposed Oooguruk-Kuparuk Oil Pools :7 - „ i I ,'~ r ,. i t I ~, r:~ax,~.:~ ;r ; r -..~ ~ -tET,. ~.:, ~,.. ~ , F£uparuk C . I i Oooguru k Unit --r. -. ~ ,_.,_;au+~ ~ t ~T ___. i s~ f ~ ~ _..~ Ui ~`._ `.,r ; ~,-t~L'~r¢ i E H ~ , a;'a^r a7 1 ~ ~d~i. r. ~~ ~ ~ ~ __t. ~L=E~~-~., ` ~~~,~ Area of Nuiq" ut , ~:- ~~;,r~~'E_-,,~ ~ ~~ Deueloprnen i i ~ Li. 1.3: { N7J! 'Y Fa?', - - f ~_ ~ C a u.. t.c l ~cf Yi. ~ ... :. ~# i ~~ Q ~ 4 ~Ii2S ~ ,:I i 1 IC + U~`1K C • I ~7 • • Attachment 2 Existing and currently proposed wells penetrating the infection zones in the proposed iniection area Current and Proposed Wells Penetrating the Oooguruk-Nuigsut Pool r as -c- ETIS LANO1 x.4'.5„ J~- COLVILLE DELTA ST 1 a ~ _~, COLVILLE DELTA 1 COLVILL -, KUUKSPIK 3 CgWILLED LTA 251 - '... s. coi ®~„~ ~ ~E~3 RIS SN~HAY STt ;., ~~ ~ ~~ ~ ~ ~ I ~ _ ~. \ ARUK RIV UNIT 3W-07 • 3 Current and Proposed Wells Penetrating the Oooguruk-Kuparuk Pool 18 • • Attachment 3 Affidavit Dale Hoffman, on oath, deposes and says: 1. I am a Senior Staff Landman for Pioneer Natural Resources Alaska, Inc., the Operator of the Oooguruk Unit. f~,/,~ 2. On Decemberv~007 I caused copies of the application for the Oooguruk Area Injection Order to be provided to the surface owners and operators of all land within'/4 mile of the proposed injection wells as listed below. Operator: ConocoPhillips Alaska, Inc. Surface Owners: State of Alaska, Department of Natural Resources P ~/ ~c.~~ Dale Ho an State of Alaska ) Third Judicial District ) Subscribed and Sworn to me before this .~D ~z-~-( ~'~ ~~`~.-`.~ 2 ~ ~~~ ~ 'L~-~.--G~. Notary Public in and for Alaska ~ ®~®~' + ~[L0~ s 19 • Attachment 4 Colville Delta 2 Well Completion Report t. Stat s o Well ratory Wildcat Expl o l ,ttl OIL ^ GAS ^ SUSPENDED C ABANDONED Ls SERVI-0E^ 2. Name of Operator 7. Permit Number Texaco 85-210 3. Atldress 550 W. 7th Ave. , #1320 8. API Number 5D- 103-20047 4. Location of well at surface 550' South and 1519' East of Northwest s. unit pr Lease NameC01 vi Ile Del t R7E U M Corner Se T13N 23 Tract 38, Sale 39 , . . , c. , At Top Protlucing Interval 10. Well Number Vertical Hole -Survey data attached #2 At Total Depth 71. Field and Pool olvilie Delta Wildcat 5. Elevation in feet lindicate KB, DF, ate.) 6. Lease Designation and Serial No. KB is 32.5' Above Sea Level ADL #355038 12. Date Spudded 13. Date T.D. Reached 74. Date Comp.. Susp. °r Ahand. 15. Water Depth, it offchore i6. No. of Completions 123 86 2/8/86 Aband. on 3/16 86 1' teetMBL Pone 17. Total Depth (MD+TVDI 18. Plug Back Depth lMDfNDI 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost 6800' Abandon vas o NO ~J -- teat MD 1470' 22. Type Electric ar Other logs Run ~ ~ ~+, ~; "";'" ~ n ~S' `" M " ~- ,~:. , '!.:..i..": i' :; ? ^ DIFL-LSS-GR-SP-CAL-USP-CNL-LDT-NGT-SDTA-Texaco EMW 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD ~` CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING R~GORD 'AMOUNT BULLED o t r t ~, ~ .. 7 " Surface 2257' 12-1 4" 2090 cu. ft:Nehtriafros Cut & Recovered " - Surfac 6778' 8-1 2" 575 cu.ft."G" KCL 9-5 8" & 7" 5 below on final round level 24. Perforations open toR~414 i~tM IMD+TVD of Top and Bottom and ~ 25. TUBING RECORD iptarvai, size and number) SIZE DEPTH SET IMDi PACKER SET (MD) 25 Holes DST #1: 6236' - 6406' 30" „ , 6300'-22, DST #lA: 6236' - 6272' 6280'-40 , , 6330'-44, 6358'-40', 6400'-lO', 26. ACID, FRACTURE,CEMENT SOUEE2E, ETC, 12" 1/2° HPF DEPTH INTERVAL IMDI AMOUNT & KING OF MATERIAL USED . DST #2: 5137'-5183' 8 1/2a HPF DST 1 ractured w/Diese an , DST #1 utual Solvent S ueeze T A e- r tur 1 & Sand z7. Dri 11 Stem 1p16141b1F~i(a(~G1(rEST Date First Production Method of Operation (Flowing, gas lift, etc.) Flow after frac from Nui sut Date of Test Houre Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE 812E GAS-OIL RATIO 2/14/86 269.5 ". TEST PERIOD • 4941 24 - 64/64 200-500 _ Flow T~ - Casing Pressure CALCULATED • OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY•API (corrl ° Press: -. -- 24-HOUR RATE .409 -- 2 RPF 24 - 4D 28. CORE DATA -Brief deuription of iithology, Porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Core #1: 6144' to 6166', recovered 19'; medium sandstone. Core #2: 6237' to 6297', recovered 60'; shale, fine sandstone w/shale interbeds. Core #3: 6297' to 6329', recovered 32'; shale, fine sandstone w/shale interbeds. Core #4: 6329' to 6389', recovered 60'; shale, fine sandstone. Core #5: 6389' to 6449', recovered 60'; shale, fine sandstone w/st~a~ ~itf~t,~~b~ds. Core #6: 6449' to 6493', recovered 44'; shale: - .(U;. ~? 7 19s3 Forth lD-aD7 jjjyyy~~~ ~ Cc115. (iBtlFfltli~V9Auplicate Rev. 74E0 CONTINUED ON REVERSE SIDE ~'Q`~'~~~~~~~,>t • STATE OF ALASKA ~ CONFIDENTI•' ALASKA_ .~ AND GAS CONSERVATION CO. "ISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG u f Classification of Service Well a' 20 • • GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, Oressure data, all fluldz -ecovered and yravl W, MEAS. DEPTH TRUE VERT. DEPTH - GOR, and time of each phase. Base Permafrost; 1470' I 1470' i I A Top Torok 5047' ~ 5047' DST tested wet. Top Nuigsut I' 6233' 6233' I DST after fracture w{diesel ISIP = 2770 psi production results summarized ~ under paragraph f,+21. ~~~``t~~~ gs ~~ ~~~~p, '; r .v'c~~~.. .. ,f .,.} y d .. 1:.::.. _ I i. ~ ' q~ 31. LIST OF ATTACRMENTS -- Drilling, Testing, Abandonment History, Drift Survey 32. I hereby cerrify tha[ the foregorng is true and correct m the best of my knowledge I , ~ I rice District Mananr~Da[e 7- .~-~lo INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown{ for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item }6, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such irtervaL Item 21: Indicate whether from ground level (G L) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool, Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". 21 • • Attachment 5 Ivik-1 Well Completion STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status M weq Classi5cabon of Service Weti Oii Gae ^ Suspended ^ Abandoned 0 Service ^ _ 2. NemadOperat~r ~~ Pioneer Natural Resourses. 7. Permit Number 202-225 3. Atldreas -. 310 K Stroet, Suge 2(A; Anchorage, AK 99501 S. 8. API Number 50-703-20436 a. Caption of we3 at wrface Abg;n d ~~ 1349.8' FSL & 536.9' FWL of Sec6 T13N RBE UM '. !'~'~fc?r ' 9. Unk or Lease Name Ivik At Tap Producing Imerval ] n' ~T 1450' FSL 8 500' FWL of Sec 6 T13N R8E UM at 6x10' MD f ~-- v~~ wf>I!- 70. Wea Number 1 At Total Depth 1g VF„~F:FIi t 5 ~ IrO T 1345.3' FSL 8 535.6' FWL of Sec 8 T13N RBE UM at 6943' MD 4=..,.t 11. FkM and POW 5. Elevation In teat (indicate KB, OF, eta) 51 feet 6. Lase Oesignatbn and Serial No. 3899501 EtQloratl0n 12. Date SpWdetl February 25, 2003 t3. Da[e T.D. Readied March 5, 2003 14. Dale Camp., Susp. OrAband. April9, 2003 (PSA'd) 15. Water Depth, If ortshore 10.5' Iasi MBL 16. No. of Compktlons 1 77. Total Oeptlt (MD . ND) 6943' MD / 6941.8' TVD t a. Plug Back Depth (MO ~ ND) 30' below the mud line 19. Directional Survey YES Q No ^ 20, Depth whero SSSV set Pulled feat MD 21. Thictmess of Pemnboat WA 22. Type Elsxtrk: or Otlrer lAga Run LWD: GRIRes/CNL/FDC. E-Line: GR/Res/FDCICNLCagDSUCMR/FMIIMOT/SVYC 23. CASING, LINER AN D CEMENTING R ECORD CASINO SRE WT. PER FT. GRADE SETTING TOP DEPTH MD BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PVILED 13.3/8" 6&C K-55 Surface 171' WA Drive Pipe 50' 7-5/8" 29.7# 480 Surface 2998' 9.718" 451 sz ASL & 130 sx G 59' 5-112" 177E L-0D 2835' 4310' 6-3/4" e5 sz G Lead (73 ppg) 6 4as ss G 3-1/2" 9.2K L-80 4310' 6943' 6.3/4" 'F-+~mna" Cmt 24,Penorations o pen to Production (MD r TVD oI Ta p and BotlOm and 26. TUBING RECORD interval, site ant number) SIZE DEPTH SET (MD) PACKER 6ET (MD) 3-1/2" 4310' CSR at 4310' ' Plugged & Abandoned all perforations after teat 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. with EZSV of 6375' MD and 25' of Dement. DEPTH INTERVAL (MD) AMOUNT 6 KIND OF MATERUtI USED 6410' -6478' 28,325# 20/40 Carbo Life 27. PROWCT ION TEST Date first Production WA McMatl of DPeroeon (Flowing, gas lift, etc.) Plugged & Abandoned after flaw test: rm artlflDiat I8L Date of Teat 4/1/2003 Hours Tasted 48 Production for TeatPeMd> OIL-BBL 2000 GA54rICF 600 WATER$BL N/A CHOKE SRE GASAII RATIO 1/2" Flow Tubing PresB. 310 psi Casing Preaeuro 368 psi Calculated 24-Hour Rate> OIL-89L 1000 GASMCF 300 WATER-BBL N/A OIL GRAVITY-API(wrt) 20° API 28. CORE DATA grief description ar IiBglogy, poroslry, freWUrres, apparent dips and pressmce of dl, gas or water. Submit core ehlpa. RECEIVED 6100.8107 • SS, mod. well cemnted, oil-saturated 6102-6144-sh,dk brown,induraled APR 2 3 2003 Alaska Oil 8t Gas Cons. Commissi6n Anchorapa L, ~ Form tOdD7 Rev. 7-t-ad CONTIN~~t~S~ SIC~~~ Submit in dupfirate SAS BFI_ AFR 3 0 203 !!lYY==7' ,R*ry1^ Report 22 • • ze. ac. GEOLOGIC MARKERS FORMATION TESTS NAME InGUtle interval testetl, pressure data, all fluids recovered antl gravity. MEAS. DEPTH TRUE VERT. DEPTH GOR, antl lime of each phase. Top !Middle Brookian 4409' 4408' Top !HRZ 5843' 5842' Base !HRZ 5961' 5960' Top 1 Torok 5220' 5219' Top / Kuparuk C 6095' 6094' Top / Nuiqsit 6396' 6395' RECEIVED APR 2 3 Zp03 Alaska 0-~ & Gas Cona. Commission Anchors 31. LIST OF ATTACHMENTS 32. I hereby certny that the folbwim~ is bve and coaect to the best of my knowledge. t~ s Signed ~~ TPoe _ For Ken Stremeld. Preaidem Dat¢ 7 2 Q i Pat Foley INSTRUCTIONS Prepared by PaW Raur263d990. General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item S: Indicate which elevation is used as reference (where net otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 18 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 18, and in item 24 show the producing intervals for the interval reported in Rem 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground levei (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersibie, Water Injection, Gas Injection, Shut-in, Other-explatn. Item 28: If no cores taken, indicate "none". Form 10.401 23 • • ., ::: :<:; PIONEER NANPALR60Uk E 2835' 2998' 1/ i i r Ivik #1 Final Status 7-5/8", 29.7#, L-80, BTC-M 3-1/2" Sliding Sleeve at 3113' (120' below the shoe) 2.81" "X" nipple at 4275' 4310' ' r i t i i i ~ _. i 6943' i i s--1 i t ppg LSI~ID drilling mud •EZSV set at 6375' w/ 25' of cement an top: PBTD = 6350'. Tested to 2000 psi Perforations: 6410' - 6478' x-1/2" Liner Tail 24 • • Attachment 6 Kalubik-1 Well Completion Report . ._......_ .. ..... a.e~...... t. ._ uuW U..1 MaiU LUl>r t Statue of Wal Claeadim6on a Service Wal OIL ~ OAS ~ SUSPENDED Q ABANDONED © SERVICE 2 Name d Oparetor ARCO Alae Inc 7 Panne Number 82-13 3 Addlws P.O. Box 100360, Ancho . AK 99510-0360 S API NurMnr 50103.207&5 s Location a well at eudace 1JCS710N$ - 222T FSL, 648' FWL, SEC 11, T13N, R7E CAM~E-f0N ~ I~ ~ s Unl or lease Narre NA Al Tap Pnduoing IaenM r ~~ _ WA '"~If~7®'G~ 10 WW NMnMr KALUBIK it At Taal Depth 2215' FSL 634' FYJL, SEC it, T13N R7E tt Field and Pool EXPLORATION 5 Ebvetbn in last (Ireli®ro 103. DF, aa) K8 37' ABOVE ML 0 Lesw Dwgnetlon end Serbl No. ADL 365038 12 Dets Spudded 03/05/92, 13 Date T.O. Reached 04/04/92. /4 Dete Conp. , Susp. or Aberd 05/01192. /5 Water Depth, d o6shan 16 No. of CorrplMWne 3' bat MSL WA 17 Total Oeptlt (A~aTt7D) 6273' MD, 8279' 1'VO 79 PIU9 Bads Depth (MDaTVD) SURFACE 19 DinctlorW Survey YES XD NO ~ Z0 Daplh whoa SSSV set 21 Thkbtwe a psrtMrost NONE fM MD 22 Type Eleade aOlher lags Run CMi,GtaCM2DiJ1EMP,DIR. dRIMM MlWtlARRENP.CtR DP/TEAV/IDUfanCri MDTAR 9DNIC 9PA: NDTaK U81T Dl1All1A7W'CNLCAL MA1NR ZDarCNKtR,CALiICMT VeP tIT9C 23 - - CASIPX3, UNER AND CEMENTING RECORD CASING SIZE . WT. PER Fi. SETTING DEPTH MD GRADE TOP BOT7OM HOLE Siff CEMENRNO RECORD AMOUNT PULLED 30' 3fOi X-52 SURF i31' 36' 797 SXPF'C"CMT Z,Q' 169i 1F52 SURF 625' 28' 1578 SX PF'C' 13.3/8' 72# L-80 SURF 2758' 17-tf2' t 193 SX PF "E', 500 SX CLASS O, t50 8X PF'E' TOP J08. 9-5/8' 47i L-80 SURF 6818' 72-1/4' 1000 SX CLASS G Za PedorMiora cgen to Pnduabn (MMTVD of Top end BoOam arW - 25 Ti7BihXi RECORD Intenel, size end number} SRE DEPTH SET PACKER SET N/A 0. 26 ACID, FRACTUf~. CEMENT 80UEEZE. ETC DEPTH OYTERVAL D AMOUNT 6 qND OF MATERIAL USED ' See ettuhed ns summ 27 PROWCTKX4 TEST Date Fup Pnaductlort Method d Operetlon (FlowMp, gw ID. slc) Dols of Twt Hour Twbd PRODUCTION FOR TEST PERIOD ~ Otl-BBL OA&MCF WATER-BBL CHOI~SIZE OASOIL RATK) Fbw TuhNg Pose. Geeing Pnwure CALCVIATED 24•HOUR RATE OIL438L OAS-MCF WATER•BBL OIL OfiAVITY~API (Dort) 29 CORE DATA Bdei dwaiptbn d phobgy, pans(ry, inaurec, apparent dpc erW P~ww of d4 gas or water. Submit con clips. R 1~~P 'Con dale aM log Irdotmamon to W submltled by Esplontlon Depwlmerd. , ` E C E ~ V 1. D JUN 101992 Alaska Oil & Gas Cons. Comm[sek~ Fotm 10.907 9utyuarawyv evn,., ,,,uw.~w Rev. 7-t-tt0 lX]NTINJED ON REVERSESOE CONFIOENTIQL 9 25 • • cEaoc~ctAr~RS POiSAAi1ON TES75 IVAA~E Irulude interval lasted, pressure data, ap fluids racoveN and graviy, tvEAS. DEPTH TRUE VERT. DEPTH GOR, and time of eadt phase. 'Formation markers to b0 suWntted by Espioratlan Dept. •See Attaeheo RECEIVED ~uN t o ~ss2 Alaska Oil & bas Cons. Camm[SSigA 31. LIST OF ATTACHMENTS P eA 3CNBA4TIC,FORMATION lE3T d1TA, GYRO, REPOFTf OF OFEfiATgN9 32. 1 hereby oanlly that the foregoing is true arM correct to IM best of my knowledge Signed _ __ _ Tide cor=e DRS Date ~-/--l~_ Y"" 7 - -- ---------'--- INSTRUCTIONS General: This form is designed for submitting a complete and corcect well completion report and log on elf types of lands and leases in Alaska. Item t : Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (mult~le completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separatety produced, showing the data pertinent to such interval. Item 21: Indicate whether Irom ground level {GL) or other elevation (DF, KB, etc.). j Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ;' ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- ~ '~ jectian, Gas Injection, Shut-in, Other•explain. ~ -' , 4tem 28: It no cores taken, indicate "none". _ Form 10-407 ~~~ j 1 ri~ ... 26 KALUBIK #1 P&A SCHEMATIC CONFIDENTIAL (All depth s RKB, 37 above mud tine) 13-3/8' csg cut ~ BO' Mud Une (37' RKB) 20' csg cut (~ 53' 30'. csg an Q 53' ~ ~~~%~% ; ~~' 7' +' ' ~ 48' Screw pipe shoe (gl 79' 48" pipe cut ~ 53' . . iha ?'s'f l`;~ . , ~ ,;,•:7r.+~,~.,~ 30" Csg shoe ~ 133' 35 bbl Permafrost crm -~.y~ ~.~~ ~~~ s ~ , „ s"~i~i+' e'y ~. Bridge plug ~ 290' 9-5/8" csg cut off ~ 300' I I ' 20' Csg afros ~ 525' 10.2 PP9 brine 10 bbl cmt Squeezed 30 bbls cmt 10.2 ppg brtrw 3 bbl cnrn Squeezed 25 bbls crtri t 0.2 ppg brine 3 bbls omit Squeezed 13 bbla crm 10.2 ppg brMa 2 bbls cant Squeezed 14 bbis cmt 10.2 ppg brine 9 bbts cmt - Squeezed 16 bbb cmt ~ Cmt rotelner ~ 2700' ~- Squeeze perfs 2725'-2727' "•- t3-3/8" Csg shoe ~ 2758' ~~ TC+C ~ 4981' ~- Cmt retainer Qs 5022' •- Pads 5050'-5250' f"- TC+C @ 80118 ~--- Cmt retainer (~ 6050' ~- Perte 6084'-6120' f- TqC ~ 8333' ~.- Cmt retainer ~d 6360' f- Perts 6368'-6445' ~'- TC+C ~ 8738' ~- Cmt retainer-Q 6747` .•- 9.518' Csg shoe ~ B818' t t RECEi~ ED 9.8 PPe mud --} ~ u~ 1992 ~, i J ~ ~ 1s5 --- !-TD(g18273' ~~Da G0 mm & ~''` 27 ~J Attachment 7 Oooguruk 1 Well Completion Report ' STATE OF ALASKA ' ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG t. Status dwell ClassifiWtkm Of Service Well Oit ^ Gas ^ Suspended ^ Abandoned I_I Service ^ 2. Name of Operator Pioneer Natural Resources Alaska 7. Permit Number 202-226 3. AdtlRSC 310 K Street, Suite 200, Anchorage, AK 99501 8. API Number 50-703-20437 4. Location of welt a<surtace _ , f(~A 7550' FNL 8 2050' FEL of Sec 31 T14N R8E UM ~ • ~ S 9: Unit or Lease Name Ooo aruk At Top Producing Inteml 3, z~,p~`' $tl ii ~ 10. Wetl Number 1 At Total Depth ~ ~'~`. , „~ ~~ ~ • 1593 FNL & 2109' FEL of Sec 31 T14N R8E UM ~ -~ yJGAr 5(t 0 3 11. Field and Pool Expk>ratron 6. Elevatbn in feet (indicate KB, DF, etc.) RKB 51 feet 6: Lease Designation and Serial No. ADL 389954 12. Data Spudtled •~ Marchy/;'2003 13. Date T.D. Reached March 21, 2003 1a. Date Camp., Susp. Or Abend. March 29, 2003 15. Water Depth, if offshore 12.5 feet MSL 19. No. of Completions 0 1T. Total DepN (MD+TVD) 6900' MD ! 6900' TVD 76. PIu9 Back OepM (AAD * TVD) 6.5' below the mud line .J/ 79. Oireclional Survey vE8 ~ No ^ 20. Depth where SSSV eel NIA rer raD 2t. Thidcrres d Permafrost WA 22. Type Eteeeic or Other L.oga Run LWD: GRlReslCNIJFDC. E-Line: GWResiFDCiCNLCaVDSLiCMR7FMI1MDT18WC 23. CASING, LINER AND CEMENTING R ECORD CASING SIZE WT. PER FT. GRADE SETTING TOP DEFTH MD BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 13.3!8" $8 K-56 Surtace 172' N/A Dritre Pipe 37.5' 7-5l8" 29.7 L-80 Surtece 3000' 9.7/B" 310 ax AS I, 200 sx Class G 4$.5' 2a. Perforations o pen to Production (MD + ND d To p arM Bosom an d 26. TUBING RECORD interval, size and number) SIZE DEPTH SET (MO) PACKER SET (MD) 28. ACID, FRACTURE, CEMENT SQUEEZE, ETC. NIA DEPTH INTERVAL (MO) AMOUNT 8 KIND OF MhT ER1Al USED 2T. PRODUCT ION TEST Date First Production NIA Method o/Operation (Fbwing, gas ItR, etcJ WA Date of Test Haurs Te6tetl Protludibn for Tesl Pariod> OIL-BBL GAS-MCF WATER•BBL CHOKE SIZE GAS-OIL RATIO Flow Tubktg press. psi Casing Pressure Calculated 24-Hour Rala ~ OIL-BBL GAS-MCF WATER$BL OIL GRAVITY-API (coM 28. CORE DATA Brill tlescnpson d IiNdogy, porosity, fractures, apparent tlips and presence of oil, gas or water. Submd core chips. RECEti/~t7 To Be Sera Under Separate Cover APR 2 3 2pp3 1 BFl. APB 3 0. ; seats Gil ~ GAe Cony. ~QftUfIUlIQfl ~(= Fonn t0.a07 Rev. 7-1.80 CONTINUED~~ ~ S~i ~~ ~ Submit In tluplicate 28 • • zg. ~ 30. GEOLOGIC MARKERS FORMATION TESTS NAME MEAS. DEPTH TRUE VERT. DEPTH Top !Middle Brookian -4469 -4469 ToplHRZ -5929 -5928 Base/HRZ -6049 -6048 ToplTorok -5329 -5328 Top I Kuparuk C -6179 -6178 MDT: 3268 psi at 6252' MD/TVD/DF Top! Nuiqsit -6459 -6458 MDT: 3306 psi at 6514' MDlTVDlDF 31. LIST OF ATTACHMENTS Summary of Dally Operations, Directional Survey, As-Sulk, Final weN diagram, logs 32. 1 hereby certify that the following Is true and oorreet to the beat of my knowledge. Signed T'Ne For Kan Shetfiled. Presidem Date y CJ j rParFOay INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells; Gas injection, water injection, steam injection, air injection, sak water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. kem 18 and 24: tt this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. kem 21: Indicate whetherfrom ground lave! (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the decals of any multiple stage cementing and the location of the cementing tool item 27: Method of Operation: Flowing, Gas lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas injection, Shut-in, Other-explain. Item 28: If no cores taken, indicake "none". Form 10407 29 • Cut & pulled 7-518" casing 15.5' below mud line. Cut & pulled 13-3/8" casing 6.5' below mud line. 13-318" 68# L-80 172' Balanced Cement Plug #4: 90' - 292' DF 26.5' below mud line to 228.5' bekow mud line. 60 sx (10 bbl} of Arcticset Pull up 8~ circulated excess cemat from 90' DF. 7-518" 29.7# L-80 3000' Balanced Cement Plua #3: 2867' - 3159' 159' below shoe to 133' above shoe. 100 sx (20 bbl) of "G". Pressure tested #3 to 750 psi. Tagged Plug #3 wl 15,000#: J Spaulding Balanced Cement Plua #2: 5176' - 5625' 100 sx (20 bbi) of "G": 1 S.8 ppg,1.16 cflsx Tagged plug t12 at 5176' DF wl 10,000# Balanced Cement Plua #1: 5919' - 6725' 190 sx (39 bbl) of "G":15.8 ppg,1.16 cf/sx Tagged plug #1 at 5919' DF w/ 10;000# • Ooogaruk #1 Final StaEus t 30 • • Attachment 8 G~ -, Summary Modeling of Fracture Containment for Water Injection Induced Fractures in Oooguruk field, Kuparuk and Nuiqsut Formations Robert D. Barree October 12, 2007 Modeling the growth of hydraulic fractures induced by water injection to the Kuparuk and Nuiqsut zones in the Oooguruk area was conducted using the three-dimensional numerical simulator GOHFER. Results indicate that hydraulic fractures can be created and extended if water injection is conducted at surface pressures above 1700-1900 psi. Vertical growth of these fractures will be arrested by the high confining stress contrast in bounding layers surrounding the injection zones. Created fractures will be contained within the Kuparuk and Nuiqsut intervals unless the surface injection pressure rises to more than 2900- 3200 psi. Introduction Water injection is planned into the Nuiqsut and Kuparuk formations in the Oooguruk field area. Injection pressures may exceed the observed hydraulic fracture propagation pressure, in which case fracture extension could continue at a low rate during the injection period. Rate of lateral fracture growth is determined by formation permeability and storage capacity and rate of face plugging caused by injection water quality. In the event that the injection pressure exceeds the fracturing pressure, the fracture height and degree of containment will be determined by the in-situ stress profile and variation of rock properties with depth. This study is intended to determine the expected degree of fracture containment and expected fracturing pressures for continuous water injection into the two target intervals. Figure 1shows across-section through the Oooguruk area. The locations of the wells in the cross-section are shown in the map view inset at top-left. The Kuparuk sands appear to be locally present in the Kalubik 1 well. The thickness and quality of both the Kuparuk and Nuiqsut sands varies across the section. Data from the Kalubik 1 fog suite has been used as the suggested "best analog" for a typical injection site. The model for fracture geometry and treating pressure is based on this well. 31 • • C[~ ~ KALUBIK 1 I'~IK 1 tC}GUF~tJK 1 N~T~~II~ 1 _ _ _ __ 4 _ ~~ __ - . ~ _u 1 ~ ~r~ _ - ~. ~' ..,~ ~__:~.~.~.. ~ t ~ ~ -~..~.. ~ ~- ~ ~ = t _ __ 7 ^ --~{ `' - - .t ~~-- ~~ _~ ~`t ~ ~~._ _ ., ~~ ~, ~ ._ ~ ~ .~ ~ r ~ ~ ~ - - ~ ~ _ -~--~~-~ .~ -- - . F , ~ _ .... ~_ t __ _ ~ ~ --. _ s f F Figure 1: Regional cross-section through Oooguruk area Figure 2 is a structure map based on the top of the Nuiqsut interval. Primary regional faults, trending NW- SE, define the approximate present-day regional stress orientation. The field will be developed using extended high-angle or near-horizontal wells drilled parallel to the major faults. Water injection is planned at matrix injection rates into the horizontal wells. In the Nuiqsut formation the planned matrix injection rates are 800-2000 bwpd at 4000 psi BHP, injecting into 50-100% of an 8000 foot lateral section. For the Kuparuk interval, matrix injection is assumed at 500- 2500 bwpd into 100% of a 4000 foot lateral section. Induced fractures are expected to roughly paral-el the major faults and the wellbore axis if the fracture extension pressure is exceeded. Fracture extension is expected in the Nuiqsut at 4500 psi BHP. The expected injection rate for fracture injection in the Nuiqsut is 2000 bwpd into 2000 feet of lateral. Similarly, in the Kuparuk the fracture extension pressure is assumed to be 4500 psi BHP. Planned fracture injection. rates for the Kuparuk are 3000 bwpd into 2000 ft of lateral. 32 • • Fracture Height Modeling Procedure This study addresses the case of injection above fracture parting pressure in both zones. The planned injection rate of 2000-2500 bpd is equivalent to 1.4-1.7 bpm for 24-hour injection operations. The models have been run assuming continuous injection at 1.5 bpm. To obtain a "worst case" projection of fracture growth the total injection rate is assumed to exit the wellbore at a single point, rather than distributed over an extended lateral length. This condition could occur if the wellbore sand-face is plugged by entrained solids in the injection stream, resulting in a point breakdown of the well. The expected fracture pressures of 4500 psi BHP will be validated based on calibration to past fracturing treatments and log-derived stresses. The Kalubik 1 well was selected based on its location within the development area and the character of the Kuparuk and Nuiqsut sands in the well. A complete open-hole log suite was also available for the well. Table 1 lists the formation tops in the Kalubik 1 in terms of measured depth. 33 Figure 2: Oooguruk area Nuiqsut structure map • • MD formation tops in Kalubik 1: Kup C 6083 LCU 6120 Nuiqsut 6362 Nuiqsut 2 6403 Nuiqsut 3 6408 Nuiqsut 4 6416 Nuiqsut 5 6421 Nechelik 6473 Base Nechelik 6549 Table 1: Kalubik formation tops The full-waveform sonic log was processed, along with the complete open-hole log suite, to derive consistent rock mechanical properties and in-situ stress profile for the well. Figure 3 shows a summary of the final processed log results. The pre pressure and closure stress magnitude have been calibrated based on data from hydraulic fracture treatments in the Nuiqsut interval in offset wells. The variations in the total fracture closure stress curve (shown in red in the log track adjacent to the lithology image) are driven by changes in rock elastic properties. The results show a high stress contrast between the sands and bounding silt/shale layers sufficient to contain a hydraulic fracture to the sands. Kalubik 1 Processed L og Data - 5925.00 -- -- -- - ---- - -- 5950.00 - _ -- - - -- 5975.00 -- - - ~ - 6000.00 - - --- -- -~ - - -_ _ -_ -. 6025.00 ..,c._ _ ,- _- _~ _'. ~...- _- --: y"-_ __-_ -__~ 6050.00 __- ___~ - ___ _ _ 8075.00 - -~ - 6,oa.oo <: ~ = -_ - -=-=-~'~-~--~-~-~~~~-~ - - --. KuparukC t 50 00 __- ___ _-. - ____._ _ __.._________ _- ___.._ _____ _- __ _ _-_ ____ 6 . -_-_ 61 75.00 _____.-__ -___- _- ___ - • _- ____._ --. _ - 6200 00 - - - -- - 8225.00 --- ----- -- ~ - -.- _~ _ _ .. - 62.~O.oO - ~ ~ - -.. _ 627.>.00 . 6300.00 6325'00 .... tn.. ~ -_ -- --- -_ - _ __~.- ._ --. 6350.00 .rr r. __--- ~ " _ - _ _ _ _ _ ~~ -- _ - - ---- - B3T5 00 --_ ~ . ,:: ---- - --- ...._..___ - ~ . _ ~ . Nuiqsut ----_ --- -- 6aoo.oo - ---_ -- ~ -_ -------=---- -=--- -~--_- ----- - 6425.00 _ - ' - - -- 6500.00 >_~~~ - ='_'-' - -- -~-~-- - Nechelik --- 6szs.oo - - - ' '_-_ _ ___ -- - -- - 6sso-oo '" " - - 6600 00 -_~ -,-.- - _- 6625.00 -- -- ~_ _.- .. _-: _ .. _- _____ _ 6650 O ____ ~. O _ .._ _ __-.~~ ~ -'.. -- ~_ - - - 6675.00 BTOO~.00 -___ - - _ ~ __ ____ Fiaure 3: Kalubik 1 processed loa data Pore pressures for the Nuiqsut are defined by MDT tests summarized in the plot in Figure 4. At 6450' TVD the reservoir pressure is expected to be approximately 3280 psi or 0.508 psi/ft. The gradient within 34 • • the oil-bearing interval is 0.365 psi/ft, which is driven primarily by the oil density. These data were used to compute the pore pressure curve used as input to the total closure stress computation. Ivik-1 (Nuigsut) MDT Pressure Pressure, psia 3200 3230 3260 3290 3320 3350 6400 6450 0 m 6500 s a d D 6550 6600 s pi = 250Q psia @ -- gauge~e t~= 431O~t mD __ r __-_ --- -- • I i e Ivik-1 -~-Gradient Fit--oil • Telephone Data • Oooguruk-1 ^ Ivik-1 Pre-Frac PBU adient = 0.365 psJft Figure 4: Oooguruk area pore pressure gradient A fracture-rate injection/falloff test was conducted with water in the Ivik 1 well, Nuiqsut zone. After fracture closure the pressure decay is controlled by the reservoir properties and pore pressure. A transient analysis of the pressure-time data was conducted to determine the reservoir flow regimes developed during the falloff test. For the Ivik 1 test a post fracture-closure pseudo-linear reservoir flow regime was identified. Figure 5 shows the Cartesian Linear Flow Analysis plot for that test. Extrapolation of the linear flow regime data from the falloff test gives a reservoir pressure estimate of 3440 psi. This is in good agreement with the MDT data shown. 35 • • Confirmation of Pore Pressure: Ivik #1 ACA Linear Flow Plot GohWin Pumping Diagnostic Analysis Toolkit ACA -Cartesian Pseudolinear __ Analysis Events LFTF B HCP' '~ 2' End of Pseudolinear Flow 0.54 3960 _ l 1 '', Start of Pseudolinear Flow 0.61 4030 ®Bottom Hole Calc Pressure (psi) 4250-- - -- -- ' I , 420 ', -,~ __. 415 410 -_ , _ _ 4050 ', 400 ' ' - Results 395 I Reservoir Pressure = 3440.92 psi ~l ' i Start of Pseudo Linear Time = 9.93 m~n ' i ? ; I ' ~ End of Pseudo Linear Time = 15.63 rr~in 390 - T- 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Linear Flow Time Function Figure 5: Ivik #1 pore pressure estimate trom in~ectionnaiiott test Data from the same fracture injection test were used to determine the fracture closure pressure, which is equivalent to the minimum horizontal in-situ stress in the reservoir. This value was used to calibrate the derived stress profile obtained from the log processing. The pressure decline after the fracture-rate injection test was analyzed using the G-function derivative method. Results of the analysis are shown in Figure 6. Fracture closure is observed at G=2.13 and BHP=4219 psi (0.65 psi/ft fracture closure gradient). This is equivalent to a wellhead pressure of 1400 psi. The fracture extension pressure, in the absence of perforation friction and near-well tortuosity, is 4590 psi. This is in good agreement with the assumed fracture pressure for the study. The fracture extension pressure for water injection at low rate is therefore approximately 1700 psi at surface. 36 ~ • Calibration of In-Situ Closure Stress: Ivik #1 G-Function Analysis GohWin Pumping Diagnostic Analysis Toolkit Minifrac - G Function _ __ Time BHCP SP DP ~ Bottom Hole Calc Pressure (psi) A' ~1 1 End of PDL L23 4418 4431 171.6 '~ -;,i -SmouihcdP~L~;ure(psil ~~~ ~~ - 1st Derivative (psi) D ~ ~ Closure 2.13 4219 422 L 370.6 73.°0? A G*dP/dG (psi) D ' -_ - ,Dn Figure 6: Ivik #1 fracture closure stress determination Similar log processing and calibration to the available pore pressure and stress data were used in the post-frac modeling of the Ivik 1 fracture treatment of the Nuiqsut interval. Figure 7 shows the actual job data (red) and the post-job model results (black). A good treating pressure match was obtained using the calibrated input data. The results of the post-frac model of the Ivik #1 Nuiqsut fracture treatment are presented to demonstrate the validity of the stress model and calibration its to field observations. 37 V.J 1.V i..~ c.v ~-.-~ -, ... -•- G(Time) • • Verification of Model Calibration: Ivik #1 Post-Frac Model Results Wellhead Pressure (ps A Clean Rate (bpm B i S!urt}' Ratz (bpm; -- ~ Surface Proppant Cone (lb/g C -' ~ `~ GOf{FER Surface Pressure (p_'- ~ A GOHFER 5hirry R~t~ (bpr B GOHFER Surface Prop Conc Ub/gatj C' p - _~ B C 8000-1 --- --- ---- -- -- - -- -- ------T40 ~ l6 I ~ 14 700 -30 2 I- 60001 t 0 __ - ~10 500 ' ' 20 ~ 8 400 - ..._ - ~_ ` , i 300 _ _ _ _ _ -- t ~ L6 200 10 ~ 4 100 i ~2 ~ --- 0 -0 16:40 16:45 16:50 16:55 ~mnoos Time sn~n_oos Figure 7: Ivik #1 Nuiqsut fracture treatment model results After calibrating the pore pressure and total closure stress to observed values, the processed log data were imported to the three-dimensional hydraulic fracture numerical simulator (GOHFER). The model constructs a rectangular grid for the numerical simulation of the fracture growth process. In the averaging process used to construct the numerical simulation grid, the foot-by-foot logs are averaged over 10' vertical .intervals and the numerical average of each rock property and stress are used to construct the model. Figure 8 shows the final model input data used for the Kalubik 1 prediction of fracture growth. 38 • • Fracture Growth Simulation Results Nuiqsut Injection: Injection of water into the Nuiqsut zone at a constant rate of 1.5 bpm (2160 bpd) showed a stable injection pressure of 4600-4700 psi at bottomhole conditions, or 1900-2000 psi at surface. These values include frictional pressure losses. A cumulative injection volume of 100,000 barrels was modeled. Total fracture height created by this injection was less than 100 feet and the fracture remained contained within the Nuiqsut interval. Rate of fracture length extension had slowed to near standstill at the end of the injection period. Actual rate of lateral growth will be more determined by water quality and filtration issues at long injection times. In the model a fracture half-length of 500 feet is predicted. The final predicted fracture width profile for the simulation is shown in Figure 9. The plot shows vertical TVD on the y-axis and lateral length from the wellbore on the x-axis. The color-fills represent created fracture width while pumping. Colors refer to the scale bar shown at the bottom of the plot, with fracture width given in inches. 39 • • WinParse Version 2007.0.0 Generated 10/11/2007 12:48:00 PM Figure 9: Nuiqsut fracture geometry model results Similar results were obtained for the Kuparuk injection model. A stable bottomhole injection pressure of 4300-4400 psi was predicted by the model. This is equivalent to 1700-1800 psi at surface, assuming water density and friction in the well. The fracture was predicted to remain contained within the Kuparuk sand. After 100,000 barrels of injection a fracture half-length of 450 feet was predicted with a height of 30- 40 feet. The gross created fracture height is determined by the local sand thickness and is controlled by high stress contrasts between the sand and bounding silt/shale layers. The results of the Kuparuk fracture geometry model are shown in Figure 10. 40 Pioneer : Kalubik 1 Nuiqsut Water Injection Model WinGOHFER Fracture Width Fracture Width ~in 'i 66000.19Minutes ,. • WinParse Version 2007.0.0 Generated 10(11/2007 1:44:35 PM Figure 10: Kuparuk fracture geometry model results Conclusions Based on the computed and calibrated stress profile, and the model results presented here, it is possible to initiate and propagate fractures with water injection in the Kuparuk and Nuiqsut formations at surface pressures above 1700 and 1900 psi respectively. Any created fractures will be contained within the sands by the in-situ stress contrast between the sands and bounding silt/shale layers. An increase in fracture treating pressure of more than 1200 psi above the original fracture extension pressure values specified for each zone is required before excessive fracture height growth develops. The calibrated stress and fracture model is capable of predicting height growth and containment, but is not able to accurately predict the lateral extent of the created fractures. Rate of fracture extension (laterally) depends primarily on the balance between injection rate and leakoff rate to the surrounding formation. This can be affected by spatial changes in pore pressure and reservoir quality, and by progressive plugging or damage to the formation sand-face caused by injected suspended solids and contaminants. Based on experience with other water injection and disposal projects, continuous monitoring pf injection pressures is recommended. If this is impractical, then daily surface shut-in pressures should be obtained to track any long-term variations in observed injection pressure. 41 Pioneer : Kalubik 1 Kuparuk Water Injection Model WinGOHFER Fracture Width FractureW(dtlt din _i 6@OOQ,i2Minutes _... .. _... ...