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Home My WebLink AboutAIO 026 BINDEX AREA INJECTION ORDER NO. 26B Prudhoe Bay Unit Orion Oil Pool North Slope, Alaska 1. June 30, 2009 BPXA’s application for Amendments (Pages 21-49 and 51-63 are held confidential) 2. October 20, 2009 Notice of Hearing; affidavits of publication, email distribution, and mailings 3. October 21, 2009 Email regarding questions about Orion Application 4. April 30, 2012 BPXA’s request for standardization of authorized fluids for EOR and pressure maintenance 5. May 14, 2013 BPXA’s request for Administrative Approval to introduce radioactive tracer into the Gathering Center 2 (GC2) production facility for the purpose of oil production, plant operations, and plant/piping integrity (AIO 26B.002) 6. -------------------- Emails 7. June 6, 2013 Letter from BPXA to AOGCC regarding clarification regarding the RCRA status of the radioactive tracers to be used in the upcoming study at GC2 8. July 29, 2020 Admin Approval to allow for a polymer injectivity test (AIO 26B.003) 9. December 28, 2020 Admin Approval to allow for continued water injection operations (AIO 26B.004) 10. May 27, 2021 Hilcorp’s request for Admin Approval for continued WAG Injection Operations (AIO 26B.005) 11. June 09, 2021 Emails discussing Mechanical Integrity Tests 12. April 20, 2022 Hilcorp’s request for admin approval to continue WAG injection operations (AIO 26B.006) 13. May 11, 2022 Hilcorp’s request for admin approval well integrity (AIO 26B.007) 14. August 18, 2022 Request to amend AIO 26B.007 WAG injection operations (AIO 26B.007 Amended) 15. January 9, 2023 Hilcorp request for WAG injection ops (AIO 26B.008) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 W. Vh Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Area Injection Order No. 26B EXPLORATION (ALASKA) ) INC. for an order expanding the ) Prudhoe Bay Field area in which injection is ) Schrader Bluff Oil Pool authorized in the Orion Oil Pool, ) Prudhoe Bay Field, North Slope, ) February 3, 2021 Alaska ) ERRATA NOTICE The Alaska Oil and Gas Conservation Commission (AOGCC) notes that Area Injection Order No. 26A.002 eliminated the word "water" from Rule 6 of AID 26A, however, when AIO 26B was issued the word water was only removed from the title of the rule and not from the body of the rule itself. This correction will be reflected in a corrected Area Injection Order No. 26B to be issued by the AOGCC. DONE at Anchorage, Alaska and dated February 3, 2021. Jeremy Dns.,mp,e by ogee: nn.oz.aa M. Price s<iersosroo Jeremy M. Price Chair, Commissioner Daniel T. DT"ly signed by Daniel T. Seamount L. Seamount,Jr. X11021.02.111 lez Daniel T. Seamount, Jr. Commissioner Jessie L. Digitally signed by Jessie LChmielomki Chmielowski 110:2021.02.03 15:15:21 -09'00' Jessie L. Chmielowski Commissioner STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7tb Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Docket Number: AIO-09-17 EXPLORATION (ALASKA) INC. ) Area Injection Order No. 26B for an order expanding the area in ) which injection is authorized in the ) Prudhoe Bay Field Orion Oil Pool, Prudhoe Bay Field, ) Schrader Bluff Oil Pool North Slope, Alaska ) Nune pro tune May 4, 2010 Dated: February 3, 2021 IT APPEARING THAT: 1. On June 30, 2009, BP Exploration (Alaska), Inc. (BPXA) requested the Alaska Oil and Gas Conservation (Commission) grant a expansion of the area in which injection is authorized in the Orion Oil Pool (OOP). 2. Pursuant to 20 AAC 25.540, on October 22, 2009 the Commission published in the Anchorage Daily News notice of the opportunity for a public hearing on December 1, 2009. 3. No protest to the application or request for hearing was received. 4. Because BPXA provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. 5. The hearing was vacated on November 18, 2009. FINDINGS: 1. AIO 26, effective January 5, 2004 approved water injection for enhanced recovery purposes within the OOP and set forth rules for conducting injection operations. 2. AIO 26A superseded AIO 26 effective May 1, 2006 and approved injection of enriched hydrocarbon gas for enhanced recovery purposes. 3. This amendment action should appropriately apply to AIO 26A. 4. Coincident with entry of this action, the Commission has issued CO 505B, expanding the OOP which finds that subsurface wireline log data, pressure measurements, and newly reprocessed seismic data indicate that the OOP extends beyond the area specified in CO 505A and expands the area subject to pool rules governing the development and operation of the OOP. 5. BPXA proposes to expand water and enriched hydrocarbon gas injection operations to include the additional area defined by CO 505B. 6. The previously issued rules governing injection within the OOP continue to be appropriate for that pool. AIO 26B February 3, 2021 CONCLUSION: Page 2 1. The area within which injection into the OOP is authorized should be expanded to conform to the pool rules area defined by CO 505B. NOW, THEREFORE, IT IS ORDERED: Underground injection of fluids as described in BPXA's applications for AIO 26 and AID 26A is permitted subject to the conditions, limitations, and requirements established in the rules set out below, in Conservation Order 505B and statewide requirements contained in 20 AAC 25. The affected area of this order is: Umiat Meridian Township Rance, UM Lease Sections T12N-R10E ADL 025637 13 and 24 N/2 T12N-RI lE ADL390067 14: S/2 S/2, 23: ALL, 24: SW/4, SW/4, NW/4 (area added this action AIO 26B) ADL 047446 17, 18, 19, and 20 ADL 047447 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 ADL 028238 25 SW/4, 26, 35, and 36 ADL 028239 27, 28, 33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SE/4, and 30 N/2 NE/4 T1IN-RI 1E ADL 028240 1, 2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4 ADL 028245 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 TI IN -ME ADL 047450 7, and 8 S/2 and NW/4 AIO 26B February 3, 2021 Page 3 Rule 1. Authorized Iniection Strata for Enhanced Recovery (Source AIO 26) Fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery within the Orion Development Area into strata that are common to, and correlate with, the interval between measured depths of 4,549 feet and 5,106 feet in the PBU V-201 well and between the measured depths of 4,174 feet and 4,800 feet in Milne Point Unit well A-1. Rule 2 Fluid Infection Wells (Source AIO 26) The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412 (e). Rule 3: Authorized Fluids for Enhanced Recovery (Source as indicated) Fluids authorized for injection include: a. enriched gas from the Prudhoe Bay Unit processing facilities (AIO 26A); b. produced water from Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery (AIO 26); c. tracer survey fluid to monitor reservoir performance (AIO 26); d. source water from a sea water treatment plant (AIO 26); e. source water from the Prince Creek (Ugnu) formation (AIO 26); f. non -hazardous filtered water collected from Schrader Bluff Oil Pool well house cellars and well pads in the Orion Development Area (AIO 26); and g. non -hazardous filtered lake water employed for hydrotesting pipeline segments (AIO 26A.001). Rule 4. Monitoring the Tubing -Casing Annulus Pressure Variations (Source AIO 26A) 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 5. Demonstration of Tubing -Casing Annulus Mechanical Integrity (Source AIO 26A) 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 AIO 26B Page 4 February 3, 2021 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. 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 1,500 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 6: Multiple Completion of Infection Wells (Source AIO 26A.002) a. Injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of commingled injection, the Commission must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of injected fluids between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 7: Well Inteerity Failure and Confinement (Source AI026A) 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 (AIO 26) Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class I1 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. A10 26B Page 5 February 3, 2021 Rule 9: Pluning and Abandonment of Fluid Infection Wells (AID 26) An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25. Rule 10: Other conditions (AID 26) It is a condition of this authorization that the operator complies with all applicable Commission regulations. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 11: Administrative Actions (AIO 26) Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska, Nunc pro tunc May 4, 2010, dated February 3, 2021. Digitally signed Digitally signed by Jeremy byleremy M. Jessie L. Jessie L. Chmows ielki Digitally signed by "rice essDaniel T. Dames T. Sea mo.m.J,. Date. sonm.oa Date:2021.02.04 Dam: roll 02,N M. Price n,mss-09.00• ChmlelOWskl 09:30: 07-0900• Seamount, Jr. 09zr.«-evo, Jeremy M. Price Jessie L. Chmielowski Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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 pan 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(6), " ltlhe 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 ran 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 pm. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 71h Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Docket Number: AIO-09-17 EXPLORATION (ALASKA) INC. for ) an order expanding the area in which ) Area Injection Order No. 26B injection is authorized in the Orion Oil ) Pool, Prudhoe Bay Field, North Slope, ) Prudhoe Bay Field Alaska ) Schrader Bluff Oil Pool May 4, 2010 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 4th day of May, 2010. BY DIRECTION OF THE COMMISSION 1 J02. Colombie Sl Assistant to the Commission STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Docket Number: AIO-09-17 EXPLORATION (ALASKA) INC. ) Area Injection Order No. 26B for an order expanding the area in ) which injection is authorized in the ) Prudhoe Bay Field Orion Oil Pool, Prudhoe Bay Field, ) Schrader Bluff Oil Pool North Slope, Alaska ) May 4, 2010 IT APPEARING THAT: 1. On June 30, 2009, BP Exploration (Alaska), Inc. (BPXA) requested the Alaska Oil and Gas Conservation (Commission) grant a expansion of the area in which injection is authorized in the Orion Oil Pool (OOP). 2. Pursuant to 20 AAC 25.540, on October 22, 2009 the Commission published in the Anchorage Daily News notice of the opportunity for a public hearing on December 1, 2009. 3. No protest to the application or request for hearing was received. 4. Because BPXA provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. 5. The hearing was vacated on November 18, 2009. FINDINGS: 1. AIO 26, effective January 5, 2004 approved water injection for enhanced recovery purposes within the OOP and set forth rules for conducting injection operations. 2. AIO 26A superseded AIO 26 effective May 1, 2006 and approved injection of enriched hydrocarbon gas for enhanced recovery purposes. 3. This amendment action should appropriately apply to AIO 26A. 4. Coincident with entry of this action, the Commission has issued CO 505B, expanding the OOP which finds that subsurface wireline log data, pressure measurements, and newly reprocessed seismic data indicate that the OOP extends beyond the area specified in CO 505A and expands the area subject to pool rules governing the development and operation of the OOP. 5. BPXA proposes to expand water and enriched hydrocarbon gas injection operations to include the additional area defined by CO 505B. 6. The previously issued rules governing injection within the OOP continue to be AIO 26B May 4, 2010 appropriate for that pool. CONCLUSION: 0 Page 2 1. The area within which injection into the OOP is authorized should be expanded to conform to the pool rules area defined by CO 505B. NOW, THEREFORE, IT IS ORDERED: Underground injection of fluids as described in BPXA's applications for AIO 26 and AIO 26A is permitted subject to the conditions, limitations, and requirements established in the rules set out below, in Conservation Order 505B and statewide requirements contained in 20 AAC 25. The affected area of this order is: Umiat Meridian Township Range, UM Lease Sections T12N-R10E ADL 025637 13 and 24 N/2 T12N-R11E ADL390067 14: S/2 S/2, 23: ALL, 24: SW/4, SW/4, NW/4 (area added this action AIO 26B) ADL 047446 171 18, 19, and 20 ADL 047447 16 S/2 and NW/4 and S/2 NE/4, 21, and 22 ADL 028238 25 SW/4, 26, 35, and 36 ADL 028239 27, 28, 33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SE/4, and 30 N/2 NE/4 T11N-Rl lE ADL 028240 1, 2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NEA N/2 SE/4 ADL 028245 13 N/2 and SEA, 14 E/2 NEA, and 24 E/2 NEA T1IN-RI 2E ADL 047450 7, and 8 S/2 and NW/4 AIO 26B May 4, 2010 0 Page 3 Rule 1. Authorized Injection Strata for Enhanced Recovery (Source AIO 26) Fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery within the Orion Development Area into strata that are common to, and correlate with, the interval between measured depths of 4,549 feet and 5,106 feet in the PBU V-201 well and between the measured depths of 4,174 feet and 4,800 feet in Milne Point Unit well A-1. Rule 2 Fluid Injection Wells (Source AIO 26) The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412 (e). Rule 3: Authorized Fluids for Enhanced Recovery (Source as indicated) Fluids authorized for injection include: a. enriched gas from the Prudhoe Bay Unit processing facilities (AIO 26A); b. produced water from Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery (AIO 26); c. tracer survey fluid to monitor reservoir performance (AIO 26); d. source water from a sea water treatment plant (AIO 26); e. source water from the Prince Creek (Ugnu) formation (AIO 26); f. non -hazardous filtered water collected from Schrader Bluff Oil Pool well house cellars and well pads in the Orion Development Area (AIO 26); and g. non -hazardous filtered lake water employed for hydrotesting pipeline segments (AIO 26A.001). Rule 4. Monitoring the Tubing -Casing Annulus Pressure Variations (Source AIO 26A) 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. AIO 26B May 4, 2010 0 Page 4 Rule 5. Demonstration of Tubing -Casing Annulus Mechanical Integrity (Source AIO 26A) 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. 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 1,500 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 6: Multiple Completion of Injection Wells (Source AIO 26A.002) a. Injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of commingled injection, the Commission must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 7: Well Integrity Failure and Confinement (Source AIO26A) 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. AIO 26B it May 4, 2010 0 Page 5 Rule 8: Notification of Improper Class II Iniection (AIO 26) Injection of fluids other than those listed in Rule 3 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. Rule 9: Plugging and Abandonment of Fluid Injection Wells (AIO 26) An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25. Rule 10: Other conditions (AIO 26) It is a condition of this authorization that the operator complies with all applicable Commission regulations. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 11: Administrative Actions (AIO 26) Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated May 4, 2010. Daniel T. SeaMount, r. Commissioner, Chair Alaska (Al and Gas Conservation Commission Norman', C missioner )il dnd Gas CNLsfrvation Commission Cathy P. Foerster, Commissioner Alaska Oil and Gas Conservation Commission AIO 26B May 4, 2010 0 Page 6 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration" In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 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 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, May 04, 2010 2:43 PM To: 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); Pasqua], 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); (foms2 @mtaon line. 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; caunderwood; 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 Qarlington@gmail.com); Jeff Jones; Jeffery B. Jones Qeff.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; 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); 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; trmjrl; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M; 'Aaron Gluzman'; Bettis, Patricia K (DNR); 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; 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) Subject: aio26B PBU Schrader Bluff Oil Pool Attachments: aio26b. pdf Please disregard the previous sent Order. There was an error in the caption. Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, State 100 Anchorage, AK 99501 (907)793-1221 (phone) (907)276-7542 (/ax) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 W. 7th Avenue, Suite 100 Anchorage Alaska 99501-3192 Re: THE APPLICATION OF BPXA EXPLORATION (ALASKA) INC. for an order expanding the area in which injection is authorized in the Orion Oil Pool, Prudhoe Bay Field, North Slope, Alaska Area Injection Order No. 26B Prudhoe Bay Field Schrader Bluff Oil Pool April 15, 2014 ERRATA NOTICE The Alaska Oil and Gas Conservation Commission (AOGCC) notes that Area Injection Order No. 26B erroneously contracted a portion of the area authorized for injection. This correction will be reflected in a corrected Area Injection Order No. 26B to be issued by the AOGCC. DONE at Anchorage, Alaska and dated April 15, 2014. Cathy . Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, April 15, 2014 2:39 PM To: (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator, Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; schultz, gary (DNR sponsored); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty, Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz, Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); To: Woce, Chris D (DOA) 0 Subject: AIO 26B Errata Notice and AIO 26B Corrected Attachments: aio26b corrected.pdf, aio26b errata notice.pdf Samantha Carlisle Executive Secretary II .Alaska Oil and iCas Conservation Commission 333 'Nest 7`ti .Avenue, Suite ioo .Anchorage, AX 99501 (907) 793-1223 (yhone) (907) 276-7.542 (fax) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793- 1223 or Samantha.Carlisle@Alaska.Gov. • • Janet D. Platt Director Regulatory Compliance and Environment BP Exploration (Alaska), Inc. Post Office Box 196612 Anchorage, AK 99519-6612 • Penny Vadla George Vaught, Jr. Jerry Hodgden 399 W. Riverview Ave. Post Office Box 13557 Hodgden Oil Company Soldotna, AK 99669-7714 Denver, CO 80201-3557 40818 St. Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Darwin Waldsmith James Gibbs Post Office Box 39309 Post Office Box 1597 u Ninilchik, AK 99639 Soldotna, AK 99669 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) Docket Number: AIO-09-17 EXPLORATION (ALASKA) INC. ) Area Injection Order No. 26B Corrected for an order expanding the area in ) which injection is authorized in the ) Prudhoe Bay Field Orion Oil Pool, Prudhoe Bay Field, ) Schrader Bluff Oil Pool North Slope, Alaska ) April 15, 2014 IT APPEARING THAT: 1. On June 30, 2009, BP Exploration (Alaska), Inc. (BPXA) requested the Alaska Oil and Gas Conservation (AOGCC) grant a expansion of the area in which injection is authorized in the Orion Oil Pool (OOP). 2. Pursuant to 20 AAC 25.540, on October 22, 2009 the AOGCC published in the Anchorage Daily News notice of the opportunity for a public hearing on December 1, 2009. 3. No protest to the application or request for hearing was received. 4. Because BPXA provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. 5. The hearing was vacated on November 18, 2009. FINDINGS: 1. AIO 26, effective January 5, 2004 approved water injection for enhanced recovery purposes within the OOP and set forth rules for conducting injection operations. 2. AIO 26A superseded AIO 26 effective May 1, 2006 and approved injection of enriched hydrocarbon gas for enhanced recovery purposes. 3. This amendment action should appropriately apply to AIO 26A. 4. Coincident with entry of this action, the AOGCC has issued CO 505B, expanding the OOP which finds that subsurface wireline log data, pressure measurements, and newly reprocessed seismic data indicate that the OOP extends beyond the area specified in CO 505A and expands the area subject to pool rules governing the development and operation of the OOP. 5. BPXA proposes to expand water and enriched hydrocarbon gas injection operations to include the additional area defined by CO 505B. 6. The previously issued rules governing injection within the OOP continue to be appropriate for that pool. AIO 26B Corrected • April 15, 2014 Page 2 of 6 CONCLUSION: 1. The area within which injection into the OOP is authorized should be expanded to conform to the pool rules area defined by CO 505B. NOW, THEREFORE, IT IS ORDERED: Underground injection of fluids as described in BPXA's applications for AIO 26 and AIO 26A is permitted subject to the conditions, limitations, and requirements established in the rules set out below, in Conservation Order 505B and statewide requirements contained in 20 AAC 25. The affected area of this order is: AIO 26B Corrected • April 15, 2014 Page 3 of 6 Umiat Meridian Township Range, UM Lease Sections T12N-R10E ADL 025637 13 and 24 N/2 T12N-RI1E ADL390067 14: S/2 S/2, 23: ALL, 24: SWA and SWA NW/4 (expansion area this order) ADL 047446 17, 18, 19, and 20 ADL 047447 16 S/2 and NW/4 and S/2 NEA, 21, and 22 ADL 028238 25 SW/4, 26, 35, and 36 ADL 028239 27, 28, 33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SE/4, and 30 N/2 NE/4 T11N-R11E ADL 028240 1, 2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NEA and N/2 SE/4 ADL 028245 13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4 T11N-R12E ADL 047450 7, and 8 S/2 and NW/4 ADL 028263 16 SW/4 and S/2 NW/4, and 21 SWA and S/2 NW/4 and NW/4 NW/4 and W/2 SEA ADL 028262 17, 18, 19 N/2 and SE/4 and N/2 SW/4, and 20 ADL 047452 28 W/2 and W/2 E/2 ADL 047453 29 N/2 and N/2 SE/4 Rule 1 Authorized Injection Strata for Enhanced Recovery (Source AIO 26) Fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery within the Orion Development Area into strata that are common to, and correlate with, the interval between measured depths of 4,549 feet and 5,106 feet in the PBU V-201 well and between the measured depths of 4,174 feet and 4,800 feet in Milne Point Unit well A-1. AIO 26B Corrected April 15, 2014 Page 4 of 6 Rule 2 Fluid Iniection Wells (Source AIO 26) The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412 (e). Rule 3• Authorized Fluids for Enhanced Recovery (Source as indicated) Fluids authorized for injection include: a. enriched gas from the Prudhoe Bay Unit processing facilities (AIO 26A); b. produced water from Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery (AIO 26); c. tracer survey fluid to monitor reservoir performance (AIO 26); d. source water from a sea water treatment plant (AIO 26); e. source water from the Prince Creek (Ugnu) formation (AIO 26); f. non -hazardous filtered water collected from Schrader Bluff Oil Pool well house cellars and well pads in the Orion Development Area (AIO 26); and g. non -hazardous filtered lake water employed for hydrotesting pipeline segments (AIO 26A.001). Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source AIO 26A) 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 AOGCC inspection. Rule 5 Demonstration of Tubing -Casing Annulus Mechanical Integrity (Source AIO 26A) 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 AOGCC-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. The AOGCC 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 AOGCC, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 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 AOGCC inspection. AIO 26B Corrected April 15, 2014 Page 5 of 6 Rule 6• Multiple Completion of Injection Wells (Source AIO 26A.002) a. Injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the AOGCC. b. Prior to initiation of commingled injection, the AOGCC must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 7• Well Integrity Failure and Confinement (Source AI026AI 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 AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC 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 AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8• Notification of Improper Class II Injection (AIO 26) Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 9• Plugging and Abandonment of Fluid Injection Wells (AIO 26) An injection well located within the affected area must not be plugged or abandoned unless approved by the AOGCC in accordance with 20 AAC 25. Rule 10: Other conditions (AIO 26) It is a condition of this authorization that the operator complies with all applicable AOGCC regulations. The AOGCC may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 11: Administrative Actions (AIO 26) Unless notice and public hearing is otherwise required, the AOGCC may administratively waive the requirements of any rule stated above or administratively amend any rule 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. AIO 26B Corrected April 15, 2014 Page 6 of 6 0 40 DONE at Anchorage, Alaska IIIN4. - P Cathy P Foerster Chair, Commissioner and dated April 15, 2014. Daniel T. Seamount, Jr. Commissioner .TION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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. • Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, April 15, 2014 2:39 PM To: (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator, Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Schultz, gary (DNR sponsored); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; M1 Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee, Tony Hopfinger, trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Perrin, Don J (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Pollet, Jolie; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, lames B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); To: Waace, Chris D (DOA) 0 Subject: AIO 26B Errata Notice and AIO 26B Corrected Attachments: aio26b corrected.pdf, aio26b errata notice.pdf Samantha CarCtsCe Executive Secretary IT -Ataska Oil and -Gas Conservation Commission. 333 West 7 f, .Avenue, Suite 10o .Anchorage, AK 99501 (907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793- 1223 or Samantha.Carlisle@Alaska.Gov. • • Janet D. Platt Director Regulatory Compliance and Environment BP Exploration (Alaska), Inc. Post Office Box 196612 Anchorage, AK 99519-6612 Penny Vadla George Vaught, Jr. Jerry Hodgden 399 W. Riverview Ave. Post Office Box 13557 Hodgden Oil Company Soldotna, AK 99669-7714 Denver, CO 80201-3557 40818 St. Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Darwin Waldsmith James Gibbs Post Office Box 39309 Post Office Box 1597 C'. Ninilchik, AK 99639 Soldotna, AK 99669 �D aE OTALb%ZKA SEAN PARNELL, GOVERNOR ALASKA OIL A" GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMI USSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.26B.001 Ms. Allison Cooke UIC Compliance Advisor BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: Authorized Fluids for FOR and Pressure Maintenance for the Schrader Bluff Oil Pool Dear Ms. Cooke: By letter dated April 30, 2012, BP Exploration (Alaska) Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) administratively amend the following Area Injection Orders (AIO): 3A, 4E, 14A, 20, 22E, 24B, 25A, 26B and 31. BPXA requested the amendments in an effort to standardize the fluids authorized for injection for enhanced recovery and pressure maintenance for the oil pools in the Prudhoe Bay Field. BPXA requested the standardization due to the complexity of managing injection operations for multiple pools, with different lists of authorized fluids, which are served by common production facilities. In accordance with terms set forth below, BPXA's request is APPROVED with a minor change to the wording proposed by BPXA. BPXA proposes that AIO No. 26B be modified to approve the following for FOR and pressure maintenance injection. - Produced water and gas; - Enriched hydrocarbon gas; - Non -hazardous water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 10 degrees F); - Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Includes but not limited to: o Freeze protection fluids; o Fluids in mixtures of oil sent for hydrocarbon recycle; o Corrosion/scale inhibitor fluids; o Anti-foams/emulsion breakers; • 0 AIO 26B.001 September 4, 2012 Page 2 of 3 o Glycols Non -hazardous glycols and glycol mixtures; Fluids that are used for their intended purpose within the oil production process. Includes: o Scavengers; o Biocides Fluids to monitor or enhance reservoir performance. Includes: o Tracer survey fluids; o Well stimulation fluids; o Reservoir profile modification fluids. As shown above, the list of fluids for which BPXA seeks approval uses the terms "includes" and "includes but not limited to." Words such as "includes" and "including" along with phrases such as "includes but is not limited to" inappropriately delegate to BPXA the authority to determine what additional fluids are approved. Therefore, this approval modifies BPXA's proposal to delete the use of any such language as set forth below. In support of its application, BPXA submitted a fluid compatibility review based on previous orders and laboratory testing. This review showed that the proper handling and treating, including the use of scale inhibitors, of the injection fluids as well as the proper operation and maintenance, including the pumping of scale remover and acid treatments, of the injection wells will prevent or counteract incompatibility effects. Thus there are no operational risks associated with injection of the proposed fluids in this pool. The change proposed by BPXA will result in increased production, is based on sound engineering and geotechnical reasons, does not promote waste or jeopardize correlative rights, and will not result in increased risk of fluid movement into freshwater. Correlative rights are protected because all lands subject to these orders have been unitized. Freshwater is protected by the proper design and completion of the wells, ongoing/periodic mechanical integrity evaluation required for all injection wells and review of the offset wells to ensure that they won't act as conduits to fluid movement. NOW THEREFORE IT IS ORDERED THAT: Rule 3 of AIO 26B is repealed and replaced by the following: Rule 3 Authorized Fluids for enhanced Recovery Fluids authorized for injection are: a) Produced water and gas from Prudhoe Bay Unit processing facilities; b) Enriched hydrocarbon gas; c) Non -hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based 0 • AIO 26B.001 September 4, 2012 Page 3 of 3 fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 10 degrees F); d) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; V. Glycols e) Non -hazardous glycols and glycol mixtures; f) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides g) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. In addition administrative approval AIO 26A.001, which specified additional authorized fluids, is hereby repealed. OIL DONE at Anchorage, Alaska and dated September 4, 2012. i Va2i/e_IT. S !mount, Jr. J rman Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), " [tlhe questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Thursday, September 06, 2012 1:36 PM To: 'Aaron Gluzman'; 'Aaron Sorrell'; 'Bruce Williams'; Bruno, Jeff J (DNR); 'CA Underwood'; 'Casey Sullivan'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Eric Lidji'; 'Erik Opstad'; Franger, James M (DNR); 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Jennifer Starck'; 'Jill McLeod'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; OilGas, Division (DNR sponsored); 'Patricia Bettis'; Perrin, Don J (DNR); 'Peter Contreras'; Pexton, Scott R (DNR); 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Hutto'; 'William Van Dyke'; '(michael.j.nelson@conocophillips.com)'; '(Von. L. Hutchins@conocophillips.com)'; 'AKDCWelllntegrityCoordinator'; 'alaska@petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker'; 'Bowen Roberts'; 'Bruce Webb'; 'Claire Caldes'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Harbour'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott; 'David Steingreaber'; 'ddonkel@cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'Francis S. Sommer'; 'Gary Laughlin'; 'Gary Schultz (gary.schultz@alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'Gregory Geddes'; 'gspfoff; 'Jdarlington Qarlington@gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones Qeff.jones@alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner'; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'Jon Goltz'; Jones, Jeffrey L (GOV); 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark P. Worcester'; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike Morgan'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker@alaska.gov)'; 'Paul Figel'; 'Paul Mazzolini'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Stephanie Klemmer'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'Tamera Sheffield'; Taylor, Cammy O (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tim Mayers'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjr1'; 'Vicki Irwin'; 'Walter Featherly'; Williamson, Mary J (DNR); 'Yereth Rosen'; Ballantine, Tab A (LAW); Bender, Makana K (DOA); 'Brooks, Phoebe L (DOA) (phoebe. brooks@alaska.gov)'; 'Colombie, Jody J (DOA) Qody.colombie@alaska.gov)'; 'Crisp, John H (DOA) Qohn.crisp@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Ferguson, Victoria L (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov)'; 'Johnson, Elaine M (DOA) (elaine.johnson@alaska.gov)'; 'Laasch, Linda K (DOA) (linda.laasch@alaska.gov)'; 'McIver, Bren (DOA) (bren.mciver@alaska.gov)'; 'McMains, Stephen E (DOA) (steve.mcmains@alaska.gov)'; Mumm, Joseph (DOA sponsored); 'Noble, Robert C (DOA) (bob.noble@alaska.gov)'; 'Norman, John K (DOA) Qohn.norman@alaska.gov)'; 'Okland, Howard D (DOA) (howard.okland@alaska.gov)'; 'Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) Qim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; Wallace, Chris D (DOA) Subject: aio26b-001 Schrader Bluff Attachments: aio26b-001. pdf 0 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group Cartography GEPS 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring NRG Associates Hodgden Oil Company President 408 18th Street Pre Box 1655 Golden, CO 80401-2433 Colorado Springs, CO 80901 Bernie Karl CIRI K&K Recycling Inc. Land Department P.O. Box 58055 P.O. Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Planning Department P.O. Box 60868 P.O. Box 69 Fairbanks, AK 99706 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith P.O. Box 190083 P.O. Box 39309 Anchorage, AK 99519 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 795 E. 94th Ct. Anchorage, AK 99515-4295 Gordon Severson 3201 Westmar Circle Anchorage, AK 99508-4336 James Gibbs P.O. Box 1597 Soldotna, AK 99669 THE STATE "'ALASKA Alaska Oil and Gas Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.26B.001 AMENDED Ms. Alison Cooke UIC Compliance Advisor BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: Authorized Fluids for FOR and Pressure Maintenance for the Schrader Bluff Oil Pool Dear Ms. Cooke: The Alaska Oil and Gas Conservation Commission has amended the Administrative Approval to correct an error in the description of non -hazardous water based fluids. The correction occurs in two locations and is shown in underlined text below. By letter dated April 30, 2012, BP Exploration (Alaska) Inc. (BPXA)requested that the Alaska Oil and Gas Conservation Commission (AOGCC) administratively amend the following Area Injection Orders (AIO): 3A, 4E, 14A, 20, 22E, 24B, 25A, 26B and 31. BPXA requested the amendments in an effort to standardize the fluids authorized for injection for enhanced recovery and pressure maintenance for the oil pools in the Prudhoe Bay Field. BPXA requested the standardization due to the complexity of managing injection operations for multiple pools, with different lists of authorized fluids, which are served by common production facilities. In accordance with terms set forth below, BPXA's request is APPROVED with a minor change to the wording proposed by BPXA. BPXA proposes that AIO No. 26B be modified to approve the following for FOR and pressure maintenance injection. - Produced water and gas; - Enriched hydrocarbon gas; - Non -hazardous water and water based fluids —'(includes seawater,` Qurce .Water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest "' , firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); - Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Includes but not limited to: • 9 AIO 26B.001 Amended October 9, 2012 Page 2 of 4 o Freeze protection fluids; o Fluids in mixtures of oil sent for hydrocarbon recycle; o Corrosion/scale inhibitor fluids; o Anti-foams/emulsion breakers; o Glycols Non -hazardous glycols and glycol mixtures; Fluids that are used for their intended purpose within the oil production process. Includes: o Scavengers; o Biocides Fluids to monitor or enhance reservoir performance. Includes: o Tracer survey fluids; o Well stimulation fluids; o Reservoir profile modification fluids. As shown above, the list of fluids for which BPXA seeks approval uses the terms "includes" and "includes but not limited to." Words such as "includes" and "including" along with phrases such as "includes but is not limited to" inappropriately delegate to BPXA the authority to determine what additional fluids are approved. Therefore, this approval modifies BPXA's proposal to delete the use of any such language as set forth below. In support of its application, BPXA submitted a fluid compatibility review based on previous orders and laboratory testing. This review showed that the proper handling and treating, including the use of scale inhibitors, of the injection fluids as well as the proper operation and maintenance, including the pumping of scale remover and acid treatments, of the injection wells will prevent or counteract incompatibility effects. Thus there are no operational risks associated with injection of the proposed fluids in this pool. The change proposed by BPXA will result in increased production, is based on sound engineering and geotechnical reasons, does not promote waste or jeopardize correlative rights, and will not result in increased risk of fluid movement into freshwater. Correlative rights are protected because all lands subject to these orders have been unitized. Freshwater is protected by the proper design and completion of the wells, ongoing/periodic mechanical integrity evaluation required for all injection wells and review of the offset wells to ensure that they won't act as conduits to fluid movement. NOW THEREFORE IT IS ORDERED THAT: Rule 3 of AIO 26B is repealed and replaced by the following: Rule 3 Authorized Fluids for enhanced Recovery Fluids authorized for injection are: a) Produced water and gas from Prudhoe Bay Unit processing facilities; b) Enriched hydrocarbon gas; 0 I* AIO 26B.001 Amended October 9, 2012 Page 3 of 4 c) Non -hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); d) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; V. Glycols e) Non -hazardous glycols and glycol mixtures; f) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides g) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. In addition administrative approval AIO 26A.001, which specified additional authorized fluids, is hereby repealed. NUNC PRO TUNC September 4, 2012 DONE at Anchorage, Alaska and dated October 9, 2012 aniel T. Sea ount, Jr. Commissioner rt AIO 26B.001 Amended October 9, 2012 Page 4 of 4 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. i ,. 0 0 MaryJones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston St., Ste. 200 5333 Westheimer, Ste. 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 cn President 40818 St. P.O. Box 1655 6900 Arctic Blvd. Golden, CO 80401-2433 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI K&K Recycling Inc. Land Department 795 Baker Oil hoofs P.O. Box 58055 P.O. Box 93330 E. Ct. Anchorage, Fairbanks, AK 99711 Anchorage, AK 99503 Anchoraa ge, AK 99515 4295 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Cir. P.O. Box 69 Barrow, AK 99723 Fairbanks, AK 99706 Anchorage, AK 99508 4336 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 0 0 Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, October 09, 2012 3:46 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; 'Colombie, Jody J (DOA) (jody.colombie@alaska.gov)'; 'Crisp, John H (DOA) Qohn.crisp@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Ferguson, Victoria L (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov)'; 'Johnson, Elaine M (DOA) (elaine.johnson@alaska.gov)'; 'Jones, Jeffery B (DOA) Qeff.jones@alaska.gov)'; 'Laasch, Linda K (DOA) (linda.laasch@alaska.gov)'; 'McIver, Bren (DOA) (bren.mciver@alaska.gov)'; 'McMains, Stephen E (DOA) (steve.mcmains@alaska.gov)'; Mumm, Joseph (DOA sponsored); 'Noble, Robert C (DOA) (bob.noble@alaska.gov)'; 'Norman, John K (DOA) Qohn.norman@alaska.gov)'; 'Okland, Howard D (DOA) (howard.okland@alaska.gov)'; 'Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) (jim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy. schwartz@alaska.gov)';'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; Singh, Angela K (DOA); Wallace, Chris D (DOA);'(michael.j.nelson@conocophillips.com)'; '(Von. L. Hutchins@conocophillips.com)'; 'AKDCWellintegrityCoordinator'; 'alaska@petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker'; 'Bowen Roberts'; 'Bruce Webb'; 'caunderwood'; 'Claire Caldes'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Harbour'; 'Dave Matthews'; 'David Boelens'; 'David Duffy'; 'David House'; 'David Scott'; 'David Steingreaber'; 'Davide Simeone'; 'ddonkel@cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Francis S. Sommer'; 'Gary Laughlin'; 'Gary Schultz (gary.schultz@alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'Gregory Geddes'; 'gspfoff; 'Jdarlington Qarlington@gmail.com)'; 'Jeanne McPherren'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner'; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'John Garing'; 'John Spain'; 'Jon Goltz'; Jones, Jeffrey L (GOV); 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karl Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark P. Worcester'; 'Marguerite kremer (meg.kremer@alaska.gov)'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike Morgan'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker@alaska.gov)'; 'Paul Figel'; 'Paul Mazzolini'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Stephanie Klemmer'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'Tamers Sheffield'; Taylor, Cammy O (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Thor Cutler'; 'Tim Mayers'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Vicki Irwin'; 'Walter Featherly'; 'Yereth Rosen'; 'Aaron Gluzman'; 'Aaron Sorrell'; 'Bruce Williams'; Bruno, Jeff J (DNR); 'Casey Sullivan'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Eric Lidji'; 'Erik Opstad'; Franger, James M (DNR); 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; Heusser, Heather A (DNR); 'James Rodgers'; 'Jason Bergerson'; 'Jennifer Starck'; 'Jill McLeod'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Matt Gill'; 'Ostrovsky, Larry Z (DNR)'; 'Patricia Bettis'; Perrin, Don J (DNR); 'Peter Contreras'; Pexton, Scott R (DNR); 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Hutto'; 'William Van Dyke' Subject: aio26b-001 amended Attachments: aio26b-001 amended.pdf w STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for Administrative Approval to inject radioactive tracers used for surface facility optimization in enhanced oil recovery injection wells. Docket Number: AIO-13-13 Area Injection Order No. 26B.002 Prudhoe Bay Unit Orion Oil Pool North Slope, Alaska June 20, 2013 By letter dated May 14, 2013, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to introduce radioactive tracers into the Gathering Center 2 (GC2) production facility for the purpose of facility optimization. After passing through the production facility the radioactive tracers would be entrained in the produced water injection system and injected in enhanced oil recovery and disposal wells. Radioactive tracers are not regulated by the Resource Conservation and Recovery Act (RCRA). The volume of radioactive tracer material will be exceedingly small in proportion to the millions of gallons of produced water that GC2 handles on a daily basis. The half-life of the proposed tracers is less than two days. The exceedingly small volume and low concentration of the radioactive tracer material in the produced water stream will have no impact on its performance as an enhanced oil recovery injectant, and will not result in any formation or reservoir fluid compatibility issues. Therefore, amending the list of approved fluids to include radioactive tracer fluids introduced to production facilities is appropriate. NOW THEREFORE IT IS ORDERED THAT: Rule 3 of AIO 26B is repealed and replaced by the following: Rule 3. Authorized Fluids for Enhanced Recovery The fluids authorized by this Order for injection are as follows: a) Produced water and gas from Prudhoe Bay Unit processing facilities; b) Enriched hydrocarbon gas; c) Non -hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based AIO 26B-002 June 20, 2013 Page 2 of 2 fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); d) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; V. Glycols; vi. Radioactive tracer survey fluids e) Non -hazardous glycols and glycol mixtures; f) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides g) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. DONE at Anchorage, Alaska al 4_0�_, Daniel T. Seamount, Jr. Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Fisher, Samantha 1 (DOA) Sent: Thursday, June 20, 2013 1:20 PM To: (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator, alaska@petrocalc.com; Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Penrose; Bill Walker, Bowen Roberts; Brian Havelock; caunderwood@marathonoil.com; Cliff Posey; Crandall, Krissell; D Lawrence; Dave Harbour, Dave Matthews; David Boelens; David Duffy, David House; David Scott; David Steingreaber; Davide Simeone; ddonkel@cfl.rr.com; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Elowe, Kristin; Francis S. Sommer; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff, Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Lastufka; news@radiokenai.com; Burdick, John D (DNR); Easton, John R (DNR); John Evans; John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz, Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Pioneer, Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Sara Leverette; Scott Cranswick; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr; Smith, Graham O (PCO); Greg Mattson; Heusser, Heather A (DNR); lames Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; Jolie Pollet; King, Kathleen J (DNR); Laney Vasquez•, Lois Epstein; Louisiana Cutler; Marc Kuck, Steele, Marie C (DNR); Matt Gill; Ostrovsky, Larry (DNR sponsored); Bettis, Patricia K (DOA); Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DNR); Pollard, Susan R (LAW); Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Wayne Wooster, Woolf, Wendy C (DNR); William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Hunt, Jennifer L (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Turkington, Jeff A (DOA); Wallace, Chris D (DOA) Subject: AIO 3A.002, AIO 26B.002, AIO 25A.016, AIO 24B.004, AIO 22E.002 (Prudhoe Bay Unit) Attachments: aio3a-002.pdf, aio26b-002.pdf, aio25a-016.pdf, aio24b-004.pdf, aio22e-002.pdf Samantha Fisher Executive Secretary 11 Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) Ea.,$y MOD labels Use Avery® Template 51600 �� Feed Paper Bend along line to a. w /EVERY® 5960TM NO expose Pop-up EdgeT Alison Cooke UIC Compliance Advisor BP Exploration (Alaska) Inc. Post Office Box 196612 Anchorage, AK 99519-6612 ttiquettes faciles A peter ; A I 1ti1ica7 to naharit AVFRV® S1fn® I Sens de Repliez A la hachure afin de rAyAlar In rehnrd Pnn.unTM C C.X.-.L 2.r, t 2c, k3 www.avery.com 9.flnn r.n.AVFRV Ea4Y Seel® Labels i ♦ Bend along line to Use Avery® Template 51600 0 feed Paper expose Pop-up EdgeTm i AVE1W@5qfi0TM David McCaleb Penny Vadla IHS Energy Group 399 W. Riverview Ave. GEPS Soldotna, AK 99669-7714 5333 Westheimer, Ste. 100 Houston, TX 77056 Jerry Hodgden Richard Neahring Hodgden Oil Company NRG Associates 40818' St. President Golden, CO 80401-2433 Post Office Box 1655 Colorado Springs, CO 80901 Bernie Karl CIRI K&K Recycling Inc. Land Department Post Office Box 58055 Post Office Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Planning Department Post Office Box 69 Post Office Box 60868 Fairbanks, AK 99706 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith Post Office Box 190083 Post Office Box 39309 Anchorage, AK 99519 Ninilchik, AK 99639 N`( `-41 George Vaught, Jr. Post Office Box 13557 Denver, CO 80201-3557 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 795 E. 94' Ct. Anchorage, AK 99515-4295 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 James Gibbs Post Office Box 1597 Soldotna, AK 99669 ttiquettes fadles a peter Sens de Repliez A la hachure afin de www.averycom I_Qnn_r.n_wvcav TI IE STA"fE ALASKA Alaska Oil and Gas Conservation Commission GOVERNOR MICHAEL). DUN 11AVY 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.olaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 26B.003 Mr. Stan Golis Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Dr., Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-20-017 Administrative Approval to allow for a polymer injectivity test Prudhoe Bay Unit Schrader Bluff Oil Pool Well L-213 (PTD 206-053) Dear Mr. Golis: On July 29, 2020, Hilcorp North Slope, LLC (HNS) submitted a sundry application to conduct a polymer injectivity trial in the Prudhoe Bay Unit (PBU) L-213 well (PBU L-213). Because polymers were not approved for enhanced oil recovery (EOR) injection in the Schrader Bluff Oil Pool (SBOP) in the PBU the Alaska Oil and Gas Conservation Commission (AOGCC) determined that an administrative approval authorizing the polymer injection is necessary. On its own motion, and in accordance with Rule 11 of Area Injection Order (AIO) 26B, the AOGCC hereby AUTHORIZES the injection of polymers in the subject well in the SBOP at PBU under the conditions stated below. Polymer enhanced water flooding has the potential to increase ultimate recovery of oil from a reservoir over a standard waterflood by modifying the properties of the injected water, principally by increasing the viscosity, desirably affecting the mobility ratio and increasing the sweep efficiency of the flood. HNS's sister company Hilcorp Alaska, LLC has had success with polymer injection in the Schrader Bluff formation in the Milne Point Unit. HNS's sundry application requested authorization to conduct an approximately 5 -week polymer injectivity test (approximately one week each into the individual OA, Oba/OBb, OBc, and OBd sands, then a week with all intervals open at the same time) to demonstrate whether polymer injection is viable in the PBU's SBOP. On July 29, 2020, the AOGCC asked for more information about the project, specifically the rates, pressures, and volumes expected during the injection trial. On July 31, 2020, HNS provided the requested information. AIO 26B.003 August 12, 2020 Page 2 of 2 HNS plans to inject water into each zone to establish a baseline and then inject polymer enhanced water at two different concentrations to evaluate the impacts on injectability to evaluate if polymer injection would be a viable EOR process in the SBOP. In accordance with Rule 11 of AIO 26B the AOGCC finds that the polymer injectivity test will not promote waste or jeopardize correlative rights and is based on sound engineering and geoscience purposes and grants HNS permission to conduct a polymer injectivity test subject to the following conditions: 1) This authorization is limited to the PBU L-213 well and to the project as described in the sundry application from July 29, 2020, and the additional information on the project provided on July 31, 2020; 2) Expansion of the polymer injection test beyond this well will require separate approval from the AOGCC; and 3) Within 30 days of completion of the injectivity test HNS shall provide the AOGCC with a summary of the results of the injectivity test. DONE at Anchorage, Alaska and dated August 12, 2020. Jeremy M. dgmiry L9nM Ey xrerey m. nx. Price I5:3&13LBC0' Jeremy M. Price Chair, Commissioner Jessie L. ° ieiyCh.he .0 Chmlelowskl '141T W" la�asl osroo Jessie L. Chmielowski Commissioner NOTICE As provided in AS 31.05.050(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 recomidemtion 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 atter 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 act included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl Gordon Severson Richard Wagner K&K Recycling Inc. 3201 Westmar Cir. P.O. Box 60868 P.O. Box 58055 Anchorage, AK 99508-4336 Fairbanks, AK 99706 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 THE STATE Mr. Bo York °'ALASKA GMT.KNOR MIKl�: PUNLLAV) Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 2611.004 PBE Operations Manager Hilcorp North Slope LLC. 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-20-030 333 West Seventh Avenue Anchorage, Alaska 9950 1-357 2 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well L-221 (PTD 20803 10) to be online in water only injection service with a known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) Orion L-221 (PTD 20803 10) Prudhoe Bay Field Schrader Bluff Oil Pool Dear Mr. York: By letter dated December 28, 2020, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 2613.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request for administrative approval to continue water only injection in the subject well. On November 21, 2020 Hilcorp placed the well on produced water injection following a cement packer squeeze workover. Hilcorp was granted up to 45 days injection for monitoring and diagnostics to investigate a potential IA repressurization. Hilcorp completed a water flow log around the packer squeeze verifying no flow. Hilcorp completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 30, 2020 which indicates that L-221 exhibits at least two competent barriers to the release of well pressure. AOGCC believes Hilcorp can safely manage the IA repressurization with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 26B.004 January 5, 2021 Page 2 of 2 AOGCC's approval to continue water injection only in PBU Orion L-221 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. Hilcorp shall limit the well's IA operating pressure to 2100 psi, and the outer annulus operating pressure to 1000 psi; 5. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of December 2022. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated January 5, 2021. Daniel T. Digitally signed by Daniel T. Seamount, Jr. Jessie L. Digitally signed by Jessie L. Chmielowski Seamount, Jr.°0z,.°'.05U8270z 09'09,00, ' Daniel T. Seamount, Jr. Chmielowski Date: 2021.01.0508x49:45 -09'00' Jessie L. Chmielowski Commissioner Commissioner RECONSIDERA 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 ofthe 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 Al and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Al 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. Bernie Karl Recycling Inc. Gordon Severson Richard Wagner K&K P.O. Box 3201 Westmar Cir. P.O. Box 60868 Anchorage, AK 99508-4336 Fairbanks, AK 99706 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 THE STATE 01ALASKA GOVERNOR N41KI: DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.26B.005 June 11, 2021 Mr. Stan Golis PBW Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-21-011 Request for Administrative Approval to Area Injection Order 26B: Water Alternating Gas Injection Operations Prudhoe Bay Unit V-218 (PTD 2070400), Orion Oil Pool Dear Mr. Golis: By letter dated May 26, 2021, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water alternating gas (WAG) injection in the subject well. In accordance with Rule 11 of Area Injection Order (AIO) 26B.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp's request for administrative approval to continue WAG injection in the subject well. On May 18, 2021, Hilcorp reported that the well experienced slow inner annulus pressure loss while on gas injection. Hilcorp performed diagnostics and monitoring including a passing state witnessed Mechanical Integrity Test (MIT) of the inner annulus on May 25, 2021 which indicates that V-218 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AI026B.005 June 11, 2021 Page 2 of 2 AOGCC's approval to continue WAG injection in V-218 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. Hilcorp shall limit the well's inner annulus operating pressure to 2100 psi and the outer annulus operating pressure to 1000 psi; 5. Hilcorp shall monitor the inner annulus and outer annulus pressures with wireless pressure gauges; 6. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The next required MIT shall be completed before or during the month of May 2023. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated June 11, 2021. Dan Digitally signed by Jessie L. Digitally signed by Jessie Dan seamount L. Chmielowski Seamount M.24:1b' ar' Chmielowski Date:2D2,.8W 08:2132 I.N.1 Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner Commissioner AND As provided in AS 31.05.080(a), within 10 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 reconsidemtion, 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 ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl Gordon Severson K&K Recycling Inc. 3201 Westmar Cir. P.O. Box 58055 Anchorage, AK 99508-4336 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Salazar, Grace (CED) From: Salazar, Grace (CED) <grace.salazar@alaska.gov> Sent: Friday, June 11, 2021 9:42 AM To: AOGCC Public Notices Subject: [AOGCC_Public_Notices) AOGCC Administrative Approval A10266.002 Attachments: A1026B.005.pdf Please see attached. Docket Number: AIO-21-011 Request for Administrative Approval to Area Injection Order 26B: Water Alternating Gas Injection Operations Prudhoe Bay Unit V-218 (PTD 2070400), Orion Oil Pool Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 71^ Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: grace.salazar@alaska.gov Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc_Public_notices/grace.salazar%40alaska.gov Salazar, Grace (CED) From: Sent: To: Cc: Subject: Attachments: Please see attached. Salazar, Grace (CED) Friday, June 11, 2021 9:38 AM sgolis@hilcorp.com; Abbie Barker; PBFieldWelllntegrity@hilcorp.com; Oliver.Sternicki@hilcorp.com; David.Wages@hilcorp.com; Jerimiah.Galloway@hilcorp.com Wallace, Chris D (CED) RE: PBU V-218 (PTD# 207-040) Request for Administrative Approval A1026B.005.pdf From: Salazar, Grace (CED) Sent: Thursday, June 10, 20217:48 AM To: sgolis@hilcorp.com; Abbie Barker<abbie.barker@hilcorp.com>; PBFieldWelllntegrity@hilcorp.com; Oliver.Sternicki@hilcorp.com; David.Wages@hilcorp.com; Jerimiah.Galloway@hilcorp.com Subject: RE: PBU V-218 (PTD# 207-040) Request for Administrative Approval Please see attached. Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ From: Carlisle, Samantha J (CED) <samantha.carlisleoalaska.gov> Sent: Thursday, May 27, 2021 10:46 AM To: Salazar, Grace (CED) <grace.salazar@alaska.gov> Subject: FW: PBU V-218 (PTD# 207-040) Request for Administrative Approval From: Abbie Barker <Abbie.Barker@hilcorp.com> Sent: Thursday, May 27, 2021 10:41 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Alaska NS - PB - Field Well Integrity <PBFieldWelllntegrity@hilcorp.com>; Oliver Sternicki Salazar, Grace (CED) From: Sent: To: Cc: Subject: Attachments: Please see attached. Salazar, Grace (CED) Thursday, June 10, 2021 12:57 PM Cody Terrell Boyer, David L (CED) AOGCC Conservation Order No. 790 CO790.pdf Re: THE APPLICATION OF Hilcorp Alaska, LLC for an exception to the spacing requirements of 20 AAC 25.055(a)(1) and (a)(2) to drill, complete, test, and produce the Whiskey Gulch No. 1 exploratory well within 500' and 1,500 feet property lines where the owner and the landowner are not the same on both sides of the lines. Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7`h Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ Docket Number: CO-21-001 Conservation Order No. 790 Whiskey Gulch No. 1 Exploration Oil/Gas Well Kenai Peninsula Borough, Alaska June 10, 2021 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 26B.006 Mr. Stan Golis PBW Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-22-010 Request for Administrative Approval to Area Injection Order 26B;Water Alternating Gas Injection Prudhoe Bay Unit V-221 (PTD 2050130), Orion Oil Pool Dear Mr. Golis: By emailed letter dated April 18, 2022, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water alternating gas (WAG) injection with a known tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue WAG injection in the subject well. Hilcorp reported a potential TxIA pressure communication to AOGCC on April 2, 2022, while the well was on miscible injectant (MI)/gas injection. Hilcorp requested and AOGCC approved a monitoring and diagnostics period on MI. On April 10, 2022, Hilcorp performed additional diagnostics including a passing non state-witnessed mechanical integrity test (MIT) of the inner annulus (to a test pressure of 3,352 psi which is greater than the anticipated gas injection pressure of 2,900 psi). This indicates that V-221 exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes Hilcorp can safely manage the TxIA communication with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 26B.006 May 23, 2022 Page 2 of 3 AOGCC’s approval to continue WAG injection in V-221 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a MIT of the inner annulus every two years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Hilcorpshall limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 5. Hilcorpshall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 6. Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 7. Hilcorp shall maintain the Production Control Center (PCC) remote shut down capability for V-221 when on gas or miscible injectant operation. During gas injection, the IA protocols will include a drill site operator and PCC alarm set at 2,100 psi, and a high alarm set at 3,000 psi that will prompt the PCC to remotely shut in the well; 8. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 9. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 10. The next required MIT is to be before or during the month of April 2024. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated May 23, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.05.23 09:10:39 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.05.23 09:28:33 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.05.23 11:23:19 -08'00' AIO 26B.006 May 23, 2022 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:Stan Golis Subject:FW: Area Injection Order 26B.006 and 26B.007 (Hilcorp, Prudhoe Bay Unit) Date:Monday, May 23, 2022 12:48:00 PM Attachments:aio26B.006.pdf aio26B.007.pdf From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Monday, May 23, 2022 12:46 PM To: AOGCC_Public_Notices <AOGCC_Public_Notices@list.state.ak.us> Subject: [AOGCC_Public_Notices] Area Injection Order 26B.006 and 26B.007 (Hilcorp, Prudhoe Bay Unit) Docket Number: AIO-22-010 Request for Administrative Approval to Area Injection Order 26B; Water Alternating Gas Injection, Prudhoe Bay Unit V-221 (PTD 2050130), Orion Oil Pool and Docket Number: AIO-22-013 Request for Administrative Approval to Area Injection Order 26B; Water Alternating Gas Injection, Prudhoe Bay Unit V-213A (PTD 2220010), Orion Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Mailed 5/23/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 26B.007 May 23, 2022 Mr. Stan Golis PBW Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-22-013 Request for Administrative Approval to Area Injection Order 26B;Water Alternating Gas Injection Prudhoe Bay Unit V-213A (PTD 2220010), Orion Oil Pool Dear Mr. Golis: By emailed letter dated May 10, 2022, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water alternating gas (WAG) injection with a “cement packer” that reduces the monitorable inner annulus (IA). The cement packer design doesn’t meet the requirement of 20 AAC 25.412(b) that “an injector be equipped with tubing and a packer… the packer must be placed within 200 feet measured depth above the top of the perforations…”. The well, currently, has no known pressure communication integrity issues. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue WAG injection in the subject well. The completion of V-213A left the 3-1/2”x 7” IA cement (cement top @ 3,110 ft 04/21/2022) functioning as a “cement packer” with the 7” whipstock/casing shoe located at 3,491 ft. Hilcorp performed a cement squeeze to ensure cement is present in the IA from an originally estimated 3,323 ft (03/03/2022) to now 3,110 ft. The cement squeeze was required to establish IA isolation as a combined mechanical integrity test of the tubing and IA (CMIT-TxIA) performed on March 3, 2022 failed. The cemented IA effectively prevents tubing integrity verification by IA monitoring from 3,110 ft to the perforations, so there is potentially an increased risk of fluids undetectably being injected outside of the approved injection zone. AOGCC proposed additional testing and monitoring be completed to assure in zone injection and confinement of the injected fluids. On May 9, 2022, Hilcorp performed diagnostics including a passing non state-witnessed mechanical integrity test of the inner annulus (MITIA). After the cement squeeze, on AIO 26B.007 May 23, 2022 Page 2 of 3 April 30, 2022, Hilcorp completed a passing state-witnessed mechanical integrity test of the tubing (MITT) (to a test pressure of 3,217 psi which is greater than the anticipated gas header injection pressure of 3,200 psi) and a CMIT-TxIA to 3,283 psi. This indicates that V-213A exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes Hilcorp can safely manage injection operations without periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in V-213A is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) Hilcorp shall perform a MITIA every two years to the greater of the maximum anticipated header injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) Hilcorp shall perform a MITT every year to the greater of the maximum header injection pressure (approx. 3,200 psi on gas) or 0.25 x packer TVD, but not less than 1,500 psi; 5) Hilcorpshall limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 6) Hilcorpshall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8) Hilcorp shall maintain the Production Control Center (PCC) remote shut down capability for V-213A when on gas or miscible injectant (MI) operation. During gas/MI injection, the IA protocols will include a drill site operator and PCC alarm set at 2,100 psi, and a high alarm set at 3,000 psi that will prompt the PCC to remotely shut in the well; 9) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10)After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 11)The next required MIT of the tubing is to be before or during the month of April 2023. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. AIO 26B.007 May 23, 2022 Page 3 of 3 DONE at Anchorage, Alaska and dated May 23, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.05.23 09:11:39 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.05.23 09:29:36 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.05.23 11:24:57 -08'00' From:Carlisle, Samantha J (OGC) To:Stan Golis Subject:FW: Area Injection Order 26B.006 and 26B.007 (Hilcorp, Prudhoe Bay Unit) Date:Monday, May 23, 2022 12:48:00 PM Attachments:aio26B.006.pdf aio26B.007.pdf From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Monday, May 23, 2022 12:46 PM To: AOGCC_Public_Notices <AOGCC_Public_Notices@list.state.ak.us> Subject: [AOGCC_Public_Notices] Area Injection Order 26B.006 and 26B.007 (Hilcorp, Prudhoe Bay Unit) Docket Number: AIO-22-010 Request for Administrative Approval to Area Injection Order 26B; Water Alternating Gas Injection, Prudhoe Bay Unit V-221 (PTD 2050130), Orion Oil Pool and Docket Number: AIO-22-013 Request for Administrative Approval to Area Injection Order 26B; Water Alternating Gas Injection, Prudhoe Bay Unit V-213A (PTD 2220010), Orion Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Mailed 5/23/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 26B.007 AMENDED Mr. Stan Golis PBW Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-22-022 Request to Amend Area Injection Order 26B.007; Water Alternating Gas Injection Prudhoe Bay Unit V-213A (PTD 2220010), Orion Oil Pool Dear Mr. Golis: By emailed letter dated July 23, 2022, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to amend Area Injection Order (AIO) 26B.007 to continue water alternating gas (WAG) injection with a recently determined tubing by inner annulus (TxIA) pressure communication. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue WAG injection in the subject well. AIO 26B.007 was initially issued May 23, 2022 as the well has a “cement packer” that reduces the monitorable inner annulus (IA). The cement packer design doesn’t meet the requirement of 20 AAC 25.412(b) that “an injector be equipped with tubing and a packer… the packer must be placed within 200 feet measured depth above the top of the perforations…”. Hilcorp confirmed slow TxIA pressure communication and reported this to AOGCC on July 7, 2022 after an extended IA bleed returned gas. The completion of V-213A left the 3-1/2”x 7” IA cement (cement top @ 3,110 ft 04/21/2022) functioning as a “cement packer” with the 7” whipstock/casing shoe located at 3,491 ft. Hilcorp performed a cement squeeze to ensure cement is present in the IA from an originally estimated 3,323 ft (03/03/2022) to now 3,110 ft. The cement squeeze was required to establish IA isolation as a combined mechanical integrity test of the tubing and IA (CMIT-TxIA) performed on March 3, 2022 failed. The cemented IA effectively prevents tubing integrity verification by IA monitoring from 3,110 ft to the perforations, so there is potentially an increased risk of fluids undetectably being injected outside of the approved injection zone. AOGCC proposed additional AIO 26B.007 Amended August 18, 2022 Page 2 of 3 testing and monitoring be completed to assure in zone injection and confinement of the injected fluids. After the cement squeeze, on April 29, 2022, Hilcorp completed a passing state-witnessed mechanical integrity test of the tubing (MITT) (to a test pressure of 3,217 psi which is greater than the anticipated gas header injection pressure of 3,200 psi) and a CMIT-TxIA to 3,283 psi. On May 9, 2022, Hilcorp performed diagnostics including a passing state-witnessed mechanical integrity test of the inner annulus (MITIA). This indicates that V-213A exhibits at least two competent barriers to the release of well pressure. Hilcorp maintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes Hilcorp can safely manage injection operations with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in V-213A is conditioned upon the following: 1) Hilcorp shall record wellhead pressures and injection rate daily; 2) Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3) Hilcorp shall perform a MITIA every two years to the greater of the maximum anticipated header injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4) Hilcorp shall perform a MITT every year to the greater of the maximum header injection pressure (approx. 3,200 psi on gas) or 0.25 x packer TVD, but not less than 1,500 psi; 5) Hilcorpshall limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 6) Hilcorpshall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7) Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8) Hilcorp shall maintain the Production Control Center (PCC) remote shut down capability for V-213A when on gas or miscible injectant (MI) operation. During gas/MI injection, the IA protocols will include a drill site operator and PCC alarm set at 2,100 psi, and a high alarm set at 3,000 psi that will prompt the PCC to remotely shut in the well; 9) Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10)After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 11)The next required MIT of the tubing is to be before or during the month of April 2023. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. AIO 26B.007 Amended August 18, 2022 Page 3 of 3 DONE at Anchorage, Alaska and dated August 18, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.08.18 14:17:29 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.08.18 14:58:37 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.08.19 08:39:31 -08'00' 3U\VXQND$QQH(2*& )URP&DUOLVOH6DPDQWKD-2*&VDPDQWKDFDUOLVOH#DODVNDJRY! 6HQW)ULGD\$XJXVW30 7R$2*&&B3XEOLFB1RWLFHV 6XEMHFW>$2*&&B3XEOLFB1RWLFHV@$UHD,QMHFWLRQ2UGHU%DPHQGHG $WWDFKPHQWVDLR%DPHQGHGSGI Request to Amend Area Injection Order 26B.007; Water Alternating Gas Injection Prudhoe Bay Unit V-213A (PTD 2220010), Orion Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 ͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺͺ >ŝƐƚEĂŵĞ͗K'ͺWƵďůŝĐͺEŽƚŝĐĞƐΛůŝƐƚ͘ƐƚĂƚĞ͘ĂŬ͘ƵƐ zŽƵƐƵďƐĐƌŝďĞĚĂƐ͗ƐĂŵĂŶƚŚĂ͘ĐĂƌůŝƐůĞΛĂůĂƐŬĂ͘ŐŽǀ hŶƐƵďƐĐƌŝďĞĂƚ͗ŚƚƚƉƐ͗ͬͬůŝƐƚ͘ƐƚĂƚĞ͘ĂŬ͘ƵƐͬŵĂŝůŵĂŶͬŽƉƚŝŽŶƐͬĂŽŐĐĐͺƉƵďůŝĐͺŶŽƚŝĐĞƐͬƐĂŵĂŶƚŚĂ͘ĐĂƌůŝƐůĞйϰϬĂůĂƐŬĂ͘ŐŽǀ Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 8/18/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 26B.008 Mr. Stan Golis PBW Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: AIO-23-001 Request for Administrative Approval to Area Injection Order 26B: Water Alternating Gas Injection Prudhoe Bay Unit Z-223 (PTD 2220800), Orion Development Area, Schrader Bluff Oil Pool Dear Mr. Golis: By emailed letter dated January 9, 2023, Hilcorp North Slope, LLC (Hilcorp) requested administrative approval to continue water alternating gas (WAG) injection with a high set packer that reduces the monitorable inner annulus (IA). The packer design doesn’t meet the requirement of 20 AAC 25.412(b) that “an injector be equipped with tubing and a packer… the packer must be placed within 200 feet measured depth above the top of the perforations…”. The well, currently, has no known pressure communication integrity issues. In accordance with 20AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS, subject to conditions, Hilcorp’s request for administrative approval to continue WAG injection in the subject well. The completion of Z-223 left the 4-1/2” tubing packer set at 4,058 ft measured depth (MD) which is now 2,410 ft above the shallowest open perforation of 6,468 ft MD. The high set packer effectively prevents tubing integrity verification by IA monitoring from 4,058 ft to the perforations, so there is potentially an increased risk of fluids undetectably being injected outside of the approved injection zone. AOGCC proposed additional testing and monitoring be completed to assure in zone injection and confinement of the injected fluids. On December 21, 2022, Hilcorp completed a waterflow log which showed no upward movement of fluids indicating fluid is confined to the approved injection interval. On October 13, 2022, Hilcorp had performed diagnostics including a passing state-witnessed mechanical integrity test of the inner annulus (MITIA). This indicates that Z-223 exhibits at least two competent barriers to the release of well pressure. Hilcorpmaintains live transmitters on the inner and outer annulus and alarm and remote shut down functions in the Supervisory Control and Data Acquisition (SCADA) system that create layers of protection from an over-pressure event. AOGCC believes Hilcorp can safely manage injection AIO 26B.008 January 24, 2023 Page 2 of 3 operations with periodic pressure bleeds by maintaining the inner annulus to a pressure not to exceed 2,100 psi and the outer annulus not to exceed 1,000 psi. Accordingly, the AOGCC believes that the well’s condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC’s approval to continue WAG injection in Z-223 is conditioned upon the following: 1. Hilcorp shall record wellhead pressures and injection rate daily; 2. Hilcorp shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Hilcorp shall perform a MITIA every two years to the greater of the maximum anticipated header injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Hilcorp shall perform a waterflow log with temperature warm backs every two years with stations at 200 ft intervals from above the tubing packer at 4,058 ft MD to the lowermost wireline accessible depth of approximately 5,550 ft MD; 5. Hilcorp shall limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 6. Hilcorp shall limit the well’s outer annulus operating pressure to 1,000 psi. Audible control room alarms shall be set at or below these limits; 7. Hilcorp shall monitor the inner and outer annulus pressures in real time with its SCADA system; 8. Hilcorp shall maintain the Production Control Center (PCC) remote shut down capability for Z-223 when on gas or miscible injectant (MI) operation. During gas/MI injection, the IA protocols will include a drill site operator and PCC alarm set at 2,100 psi, and a high alarm set at 3,000 psi that will prompt the PCC to remotely shut in the well; 9. Hilcorp shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 11. The next required MIT of the tubing is to be before or during the month of October 2024. AOGCC must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated January 24, 2023. Brett W. Huber, Sr. Jessie L. Chmielowski Greg C. Wilson Chair, Commissioner Commissioner Commissioner Gregory Wilson Digitally signed by Gregory Wilson Date: 2023.01.24 13:49:44 -09'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.01.25 14:45:38 -09'00' Brett W. Huber. Sr. Digitally signed by Brett W. Huber. Sr. Date: 2023.01.25 15:58:31 -09'00' AIO 26B.008 January 24, 2023 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 26B.008 (PBU) Date:Thursday, January 26, 2023 7:38:29 AM Attachments:aio26B.008.pdf Docket Number: AIO-23-001 Request for Administrative Approval to Area Injection Order 26B: Water Alternating Gas Injection Prudhoe Bay Unit Z-223 (PTD 2220800), Orion Development Area, Schrader Bluff Oil Pool Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 1/26/23 15 Hilcorp North Slope, LLC Stan Golis, PBW Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 01/09/2023 Commissioner Jessie Chmielowski and Commissioner Greg Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Orion well Z-223 (PTD# 222080). Request for WAG injection operations. Dear Commissioner Chmielowski and Commissioner Wilson, Hilcorp North Slope, LLC requests administrative approval for WAG injection into Orion well Z-223 with high set injection packer. Z-223 (PTD#222080) was recently drilled as a Schrader Bluff WAG injector, completed on 8/30/2022. While running the 4.5” injection liner to bottom, the rig encountered issues getting liner to target depth resulting in the injection packer being set roughly 1432’ MD above the permitted set depth. An MIT of the 9-5/8”casing on 8/14/2022 passed to 2663 psi, confirming integrity of the casing below the liner top packer now set at 3938’MD. An AOGCC witnessed offline MIT-IA passed to 3570 psi on 10/13/2022. With permission from the AOGCC, Z-223 was placed on water injection for a 2-month evaluation period. On 12/21/2022 a waterflow log (WFL) was conducted with the well on injection, looking for upward movement of water out of the approved injection zone from the top most perforated liner at 6468’MD. No out of zone injection was found. Hilcorp North Slope, LLC has determined that well Z-223 is safe to operate in its current condition and requests permission for WAG injection based on the following: x Injection is isolated to the approved injection interval. x Passing pressure test of the primary and secondary barriers. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8356 or Oliver Sternicki at 907-564-4891. Sincerely, Stan Golis PBW Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic Sincerely, Stan Golis By Samantha Carlisle at 8:45 am, Jan 12, 2023 Orion Well Z-223 Technical Justification for Administrative Approval Request 01/09/2023 Well History and Status Orion well Z-223 (PTD#222080) was drilled as a Schrader Bluff WAG injector, completed on 8/30/2022.The rig encountered issues running the 4.5” liner to bottom, eventually working it from ~9500’ to 15391’ MD at which point no further progress could be made and the liner was set short of the 17,549’ MD target. The liner top packer and the injection packer were set high with the injection packer set at 4058’ MD, roughly 1432’ MD /1087’ TVD above the planned and permitted set depth of 5490’ MD. The packer depth of 4058’ MD places the bottom of the monitorable annulus above the top of the Schrader Bluff injection zone at ~ 5430’ MD/4544’TVD and into the Ugnu formation. The top of the Ugnu formation is at ~3670’ MD. The 9-5/8” casing tested good on the rig to 2500 psi on 8/14/22 confirming integrity of the casing below liner top packer, ensuring current isolation of injected fluids to below the 9-5/8” casing shoe. The upper three sliding sleeves have been left closed. The uppermost injection from the liner occurs through perforations at 6468’ MD within the lower OBC sand in Schrader Bluff formation, ~ 1038’ MD below the top of the Schrader Bluff. An open hole metal expandable packer set below the 9-5/8” casing shoe at 6227’ MD, providing additional isolation of injection fluids to the open hole section of the OBC sand within the Schrader Bluff formation. An AOGCC witnessed offline MIT-IA passed to 3570 psi on 10/13/2022. An AOGCC witnessed online MIT-IA passed to 1852 psi on 11/14/2022. The well was placed on water injection on 11/11/2022 for a 60-day evaluation period to establish injection and conduct a WFL/ temperature warm back log to look for upward flow of water outside of the 9-5/8” casing indicating possible out of zone injection. This log was executed on 12/21/2022, no indications of upward flow were seen in the log. Forecasted Benefit of WAG vs PWI Benefits of WAG injection over PWI only injection are concentrated in the first 6 years of injection with Z-223 on a 1-year WAG cycle. Analogue Schrader Bluff well performance benefits for WAG vs PWI only indicate an 8% increase in total recovery for this pattern resulting in an estimated additional ~1200 MBO of production. Recent Well Events: 12/21/2022 Online WFL showed no out of zone injection. 11/14/2022 Online passing AOGCC witnessed MIT-IA to 1852 psi 11/11/2022 Well placed on water injection for 60-day evaluation period. 10/13/2022 Shut-in passing AOGCC witnessed MIT-IA to 3570 psi 8/14/2022 Passing MIT of 9-5/8” casing on rig to 2663 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing online pressure test conducted on 11/14/2022, which tested both barriers, demonstrates competent primary and secondary barrier systems. The WFL/ temperature warm back log showed no upward movement of water indicating fluid is confined to the approved injection interval. A WFL/ temperature warm back log with the well on water injection is the best option for evaluation of potential upward movement of fluids adjacent to the wellbore due to its ability to determine direction and velocity of water movement with the pulsed neutron log and the ability to detect the accumulation of injected fluids out of zone adjacent to the wellbore with the temperature warm back log. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rates daily; 2. Submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Perform a MIT-IA every two years to the greater of the maximum anticipated wellhead injection pressure or 0.25 x packer TVD, but not less than 1,500 psi; 4. Perform waterflow log (well on water injection) with temperature warm backs every 2 years with stations at 200’ intervals from above the tubing packer at 4058’ MD to lowermost wireline accessible depth(~5550’ MD). 5. Limit the well’s inner annulus operating pressure to 2,100 psi. Audible control room alarms shall be set at or below these limits; 6. Limit the well’s outer annulus operating pressure to 1000 psi. Audible control room alarms shall be set at or below these limits; 7. Monitor the inner and outer annulus pressures in real time with its SCADA system; 8. Maintain the Production Control Center (PCC) remote shut down capability for Z-223 when on gas or miscible injectant (MI) operation; 9. Immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 10. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; TIO/ Injection Plot Wellbore Schematic Oxygen Activation Evaluation Water Flow Detection Company: Hilcorp North Slope, LLC. Well: Z-223 Field: Prudhoe Bay Borough: North Slope State: Alaska API#: 50-029-23720-00 Geoscience & Production Center of Excellence, North America Analyst: Fanny Haroun Email: fanny.haroun@halliburton.com Phone: 907-342-5550 Report: 12/23/2022 HALLIBURTON DOES NOT GUARANTEE THE ACCURACY OF ANY INTERPRETATION OF THE LOG DATA, CONVERSION OF LOG DATA TO PHYSICAL ROCK PARAMETERS OR RECOMMENDATIONS WHICH MAY BE GIVEN BY HALLIBURTON PERSONNEL OF WHICH APPEAR ON THE LOG OR IN ANY OTHER FORM. ANY USER OF SUCH DATA, INTERPRETATIONS, CONVERSIONS OF RECOMMENDATIONS AGREES THAT HALLIBURTON IS NOT RESPONSIBLE EXCEPT WHERE DUE TO GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, FOR ANY LOSS, DAMAGES, OR EXPENSES RESULTING FROM THE USE THEREOF Page 2 of 33 TABLE OF CONTENTS 1.0 EXECUTIVE SUMMARY ................................................................................................................... 3 2.0 WELL INFORMATION ...................................................................................................................... 4 3.0 TOOL STRING DIAGRAM ................................................................................................................ 5 4.0 WATER FLOW LOG EVALUATION ................................................................................................. 7 4.1 IMPULSE TESTS RESULT ........................................................................................................... 10 4.1.1 Impulse Test @ 3900 ft MD ................................................................................................ 10 4.1.2 Impulse Test @ 4100 ft MD ................................................................................................ 12 4.1.3 Impulse Test @ 4300 ft MD ................................................................................................ 14 4.1.4 Impulse Test @ 4500 ft MD ................................................................................................ 16 4.1.5 Impulse Test @ 4700 ft MD ................................................................................................ 18 4.1.6 Impulse Test @ 4900 ft MD ................................................................................................ 20 4.1.7 Impulse Test @ 5100 ft MD ................................................................................................ 22 4.1.8 Impulse Test @ 5300 ft MD ................................................................................................ 24 4.1.9 Impulse Test @ 5500 ft MD ................................................................................................ 26 4.1.10 Impulse Test @ 5700 ft MD ................................................................................................ 28 4.1.11 Impulse Test @ 5798 ft MD ................................................................................................ 30 5.0 TEMPERATURE OVERLAY ........................................................................................................... 32 Page 3 of 33 1.0 Executive Summary Well: Z-223 Oxygen Activation Evaluation Survey date: 22-DEC-2022 Logging Objective The logging objective is to perform water flow log to determine water flow behind pipe. Injection rate during logging is 2800 BWPD. Conclusions The TMD3D and RMT3D Tools were run in oxygen activation impulse mode in the 4.5” tubing and liner taking impulse tests at several station depths. The tool was run in normal configuration (generator positioned below the detectors) for water up flow detection. Impulse tests with TMD3D were done in 6 different depths: 3900, 4100, 4300, 4500, 4700, and 4900 ft MD. Impulse tests with RMT3D were done in 5 different depths: 5100, 5300, 5500, 5700, and 5798 ft MD. The impulse tests show no detectable water moving upward at the station depths. Page 4 of 33 2.0 Well Information Page 5 of 33 3.0 Tool String Diagram Page 6 of 33 Page 7 of 33 4.0 Water Flow Log Evaluation The TMD3D was run using stationary impulse tests across the zones of interest. Water flow can be detected by measuring gamma rays originating from activated oxygen within any water flowing past the neutron generator (activation) then moving past the detector section (decay). The fluid/water velocity is estimated from oxygen activation using impulse test data. The flow direction is determined by the position of the sensor relative to the neutron generator. The flow region, near or far, is derived by the ratio of Compton backscatter gamma rays compared to original gamma r ay counts from activated oxygen. Lower Compton ratio indicates a flow region further from the tool i.e., behind the next string of pipe. Total oxygen activation will be a function of: • volume of water in the region of neutron cloud • flow velocity of water • tool speed • flow distance to detector • time exposure Below is a representation of the sequence of radioactive excitation and subsequent relaxation of Oxygen. Figure 1: Sequence events of oxygen activation The tool is configured in the normal mode with the neutron generator below the detector section. In the normal configuration, water will only be detected when moving up relative to the tool, in both the stationary impulse mode and continuous mode. Any oxygen activation detected by far and long detector should be from water flow upward. If there is water flow in the downward direction the GR sensor below the neutron generator will detect the activated oxygen. The near detector is not use for the calculation due to its proximity to the neutron generator. Page 8 of 33 Figure 2: Flow scenario related to TMD3D log tool Stationary Impulse Method This technique is a travel-time measurement and has the significant advantage of not requiring any calibration of the detectors. When the tool is stationary at a specified depth, the generator is turned on and allowed to stabilize. The count rate in each detector is then recorded for one or two minutes, at which time the generator is shut down. At some time later (depending on the fluid flow velocity and distance from the various detectors to the source), the count rate recorded in the detectors will drop to background level. The count rate will drop to zero in the spectral window encompassing the oxygen peak. The surface computer records the various detector count rates, steps down the generator, measures the time until the recorded count rates fall to one-half full value, and then computes a velocity from the travel time. The fluid velocity is the distance from the source to the detector divided by the time between the count-rate drop and the time when the generator was shut down. The procedure is completely automated. The spectral data can be processed to provide fluid velocity in one step because the count rate falls to zero after the activation passes. Processing the total gamma ray count rates requires two steps. The natural Page 9 of 33 background must be measured for approximately one minute after the drop to correct for the nonzero background activity. Fig. 3 is a graphical representation of the timing cycle used by the stationary impulse method. Figure 3: Stationary Impulse timing sequence The rate computation: Outer Casing ID = 3.958 inch (4.5” tubing), Inner Casing OD = 1.6 inch (the tool OD) Vavg = average water velocity Qw (bpd) = Vavg (ft/min) x 1.4 x (Outer CasingID2 (inch) – Inner CasingOD2 (inch)) Page 10 of 33 4.1 Impulse tests result 4.1.1 Impulse Test @ 3900 ft MD The impulse test at depth 3900 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below TMD3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 11 of 33 Page 12 of 33 4.1.2 Impulse Test @ 4100 ft MD The impulse test at depth 4100 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below TMD3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 13 of 33 Page 14 of 33 4.1.3 Impulse Test @ 4300 ft MD The impulse test at depth 4300 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below TMD3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 15 of 33 Page 16 of 33 4.1.4 Impulse Test @ 4500 ft MD The impulse test at depth 4500 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below TMD3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 17 of 33 Page 18 of 33 4.1.5 Impulse Test @ 4700 ft MD The impulse test at depth 4700 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below TMD3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 19 of 33 Page 20 of 33 4.1.6 Impulse Test @ 4900 ft MD The impulse test at depth 4900 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below TMD3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 21 of 33 Page 22 of 33 4.1.7 Impulse Test @ 5100 ft MD The impulse test at depth 5100 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below RMT3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 23 of 33 Page 24 of 33 4.1.8 Impulse Test @ 5300 ft MD The impulse test at depth 5300 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below RMT3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 25 of 33 Page 26 of 33 4.1.9 Impulse Test @ 5500 ft MD The impulse test at depth 5500 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below RMT3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 27 of 33 Page 28 of 33 4.1.10 Impulse Test @ 5700 ft MD The impulse test at depth 5700 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below RMT3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. Page 29 of 33 Page 30 of 33 4.1.11 Impulse Test @ 5798 ft MD The impulse test at depth 5798 ft. MD shows no water flow up as indicated by the far and long detector and background not detecting any reliable change in counts. The GR sensor below RMT3D tool shows different readings during generator on and off, due to the active water injection in the wellbore. 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ilcorp North Slope, LLC Stan Golis, PBW Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 05/10/2022 Chairman Jeremy Price Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Orion Well V-213A (PTD# 222001). Request for Administrative Approval to document well integrity testing requirements by the AOGCC. Dear Chairman Price, Hilcorp North Slope, LLC requests administrative approval for Orion well V-213A due to the AOGCC agreed integrity testing requirements beyond those stipulated in AIO 26B. Due to the completion of V-213A, the inner annulus (IA) cement top, functioning as the “packer”, is greater than 200’ MD above the top of the perforations. This completion does not meet the requirement stipulated in 20AAC 25.412(b). Within PTD #222001, dated 01/19/2022, additional pressure testing is required as part of the conditions of approval to ensure continued well integrity. The PTD #222001 requirement: 1. Annual MIT-T with a deep-set plug just above the top injection mandrel to 3200 psi (maximum header injection pressure*). Most recently completed on 04/29/2022 to 3217 psi based on a maximum anticipated header injection pressure of 3200 psi. *”Maximum header injection pressure” is determined by review of the previous year of daily header injection pressure or forecasted maximum header injection pressure, whichever is more applicable. Additional Operating and Monitoring Plan: 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. 2-year MIT-IA online to AIO 26B Rule 5 pressure requirements. Most recently completed on 05/09/2022 to 3102 psi. 4. IA MOASP= 2100 psi, OA MOASP= 1000 psi. Well shut-in pressures: IA= 3000 psi, OA = 2000 psi. Annulus pressures between MOASP and the shut-in pressure will be managed by bleeding the annulus. 5. IA and OA pressures will be monitored with wireless pressure gauges through the SCADA system. 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 7. Shut-in of the well can be accomplished remotely from the Production Control Center when the well in on MI or locally at the well by the pad operator when the well is on water injection. 8. After well shut-in due to a change in the well’s mechanical condition, AOGCC approval shall be required to restart injection. Hilcorp North Slope, LLC has determined that well V-213A is safe to operate and requests administrative approval to document specific testing requirements for the well. If you have any questions, please call me at 907-777-8356 or Oliver Sternicki at 907-564-4891. Sincerely, Stan Golis PBW Operations Manager By Samantha Carlisle at 12:32 pm, May 11, 2022 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2022.05.10 13:34:02 -08'00' Stan Golis (880) Attachments TIO/ Injection Plot Wellbore Schematic TIO/ Injection Plot Wellbore Schematic 222-001 12 Hilcorp North Slope, LLC Stan Golis, PBW Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 04/18/2022 Chairman Jeremy Price Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Orion Well V-221 (PTD# 205013). Request for Administrative Approval to continue WAG injection operations. Dear Chairman Price, Hilcorp North Slope, LLC requests administrative approval for continued WAG injection into Orion well V- 221 with slow tubing x inner annulus (IA) communication. V-221 was reported to the AOGCC on 04/02/2022 at which time the well was placed under evaluation for suspected slow tubing by IA pressure communication based on IA pressure trends while on MI service. On 04/03/2022 a tubing hanger pack-off test passed to 5000 psi. An online AOGCC witnessed MIT-IA passed to 3352 psi on 04/10/2022. The passing MIT-IA confirms both the primary and secondary well barrier integrity. Hilcorp North Slope, LLC has determined that well V-221 is safe to operate in its current condition and requests an AA for WAG injection based on the following: x IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. x MIT-IA passed to 3352 psi. x IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8356 or Oliver Sternicki at 907-564-4891. Sincerely, Stan Golis PBW Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic By Samantha Carlisle at 8:15 am, Apr 20, 2022 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2022.04.19 15:31:03 -08'00' Stan Golis (880) Orion Well V-221 Technical Justification for Administrative Approval Request 04/18/2022 Well History and Status Orion well V-221 is a WAG injector that was originally drilled in 2005. Prior to the discovery of the IA pressure anomaly on V-221, the most recent AOGCC witnessed MIT-IA passed to 2349 psi on 03/14/2021. On 04/02/2022 V-221 was found to have IA repressurization while on MI and was reported to the AOGCC and placed under evaluation. An AOGCC witnessed MIT-IA passed to 3352 psi on 04/10/2022. Recent Well Events: 04/10/2022 AOGCC witnessed MIT-IA passed to 3352 psi. 04/03/2022 PPPOT-T Passed to 5000 psi 04/02/2022 TxIA pressure communication noted and notification sent to the AOGCC 03/14/2021 AOGCC witnessed MIT-IA passed to 2349 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3352 psi on 04/10/2022, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics/ repair will be pursued at this time due to the low likelihood of being able to determine the leakage point. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform a MIT-IA every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi. 4. IA MOASP= 2100 psi, OA MOASP= 1000 psi. 5. IA and OA pressures will be monitored with wireless pressure gauges through SCADA system. 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 7. After well shut-in due to a change in the well’s mechanical condition, AOGCC approval shall be required to restart injection TIO/ Injection Plot Wellbore Schematic 1 Carlisle, Samantha J (OGC) From:Wallace, Chris D (OGC) Sent:Friday, April 29, 2022 9:42 AM To:PB Wells Integrity Cc:Regg, James B (OGC); Oliver Sternicki; PB Wells Integrity Subject:Re: Approval to keep WAG Injector V-221 (PTD #2050130) online while AA is processed Andy, Approved for injection while AA is being processed. Regards Chris From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Friday, April 29, 2022 8:46:09 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: Approval to keep WAG Injector V‐221 (PTD #2050130) online while AA is processed Mr. Wallace, WAG Injector V‐221 (PTD #2050130) is currently Under Evaluation after it was discovered to have anomalous IA re‐ pressurization. On 04/03/22 DHD performed a passing PPPOT‐T to 5000 psi proving the wellhead seals have integrity. On 04/10/22 an online MIT‐IA passed to 3352 psi. On 04/20/22 Hilcorp submitted a request for Administrative Approval to continue WAG injection. Hilcorp is requesting your approval to keep the well online while the AA is processed. Please respond at your earliest convenience. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Saturday, April 2, 2022 4:21 PM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; John Condio ‐ (C) <John.Condio@hilcorp.com>; Stan Golis <sgolis@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: UNDER EVALUATION: WAG Injector V‐221 (PTD #2050130) Anomalous IA Pressure Trend Mr. Wallace, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 WAG Injector V‐221 (PTD #2050130) is currently on MI and had an IA bleed on 03/31/22. Follow up monitoring shows an increasing IA pressure trend that does not appear to be attributed to thermal effects from Injection temperature or rate. The well will now be classified as UNDER EVALUATION for diagnostics and monitoring. Plan Forward: 1.DHD: PPPOT‐T 2.DHD: Monitor Pressures/Quantify re‐pressurization trend if applicable 3.Fullbore: (Pending): MIT‐IA 4.Well Integrity: Additional diagnostics as needed. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this 1 Carlisle, Samantha J (OGC) From:Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent:Monday, April 25, 2022 9:11 AM To:Wallace, Chris D (OGC) Subject:RE: PBU V-221 (PTD # 205-013) Request for Administrative Approval Attachments:MIT PBU V-213 V-221 04-10-22.xlsx Chris, I was talking to Andy on the Slope this morning about the AA Request for V‐221 and submission of the PT form. I made a mistake on the AA request stating that the test was witnessed, when in fact the witness was waived by Adam Earl. He was on location and witnessed the V‐213 test, but the triplex pump ended up having some issues for the V‐221 test and he had left location by the time the crew got it resolved and were ready to conduct the V‐221 test. Please see the attached PT for your records. Regards, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1 Carlisle, Samantha J (OGC) From:Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent:Tuesday, May 3, 2022 5:19 PM To:Wallace, Chris D (OGC) Subject:RE: PBU V-221 (PTD # 205-013) Request for Administrative Approval Chris, I got an additional clarification on the remote dump capabilities through PCC. For injectors the remote dump from PCC only ties into wells on MI service, not wells on water injection. This is due to the risk of a pad shut‐in simultaneously shutting off all water injection to the pad and the subsequent water hammer affect causing potential safety, environmental and equipment damage issues. Automatic shut‐in of the water injection wells is handled by low pressure pilots. Local isolation of these wells can be accomplished by the drillsite operator on the pad. Oliver From: Oliver Sternicki Sent: Tuesday, May 3, 2022 2:32 PM To: chris.wallace@alaska.gov Subject: PBU V‐221 (PTD # 205‐013) Request for Administrative Approval Chris, Per our conversation yesterday regarding further details on the V‐221 WAG Administrative Approval request, please see below: 1.The determination of the Maximum Anticipated Injection Pressure value for pressure testing of the well is based off of a review of the previous year of daily injection data or forecasted maximum injection pressures predicted to be seen by the next pressure test cycle, whichever is more applicable. As the injection pressure on an individual well varies over time due to allocation of MI and water to various pads this approach makes the pressure testing of an individual well more fit for purpose. The MIT‐IA conducted on 4/10/2022, which passed to 3352 psi was based on a maximum tubing pressure of 2913 psi seen on 2/8/2022. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 2.Shut‐in of V‐221 can be done remotely by the Production Control Center (PCC) Operator who is monitoring annulus pressures and injection rates through the SCADA system or by the drillsite operator on location. As specified in the Prudhoe Bay Well Integrity Practice, the PCC operator or the drillsite operator would take action to shut the well in based on the following guidelines, otherwise annulus pressure would be controlled by bleeding: 3 Let me know if you have any other questions, Regards, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com From: Abbie Barker <Abbie.Barker@hilcorp.com> Sent: Tuesday, April 19, 2022 3:38 PM To: aogcc.permitting@alaska.gov Cc: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Stan Golis <sgolis@hilcorp.com>; Brodie Wages <David.Wages@hilcorp.com> Subject: PBU V‐221 (PTD # 205‐013) Request for Administrative Approval 4 Hello, Please find the attached Request for Administrative Approval to continue WAG Injection into Orion Well V‐221. If you have any questions, please contact Stan Golis at 907‐777‐8356 or Oliver Sternicki at 907‐564‐4891. Thanks, Abbie Abbie Barker Regulatory Tech, Prudhoe Bay West Team Hilcorp North Slope Email: Abbie.Barker@hilcorp.com Office: (907)564‐4915 Cell: (907)351‐2459 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Carlisle, Samantha J (OGC) From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent:Saturday, April 2, 2022 4:21 PM To:Wallace, Chris D (OGC) Cc:Regg, James B (OGC); Oliver Sternicki; John Condio - (C); Stan Golis; PB Wells Integrity Subject:UNDER EVALUATION: WAG Injector V-221 (PTD #2050130) Anomalous IA Pressure Trend Mr. Wallace, WAG Injector V‐221 (PTD #2050130) is currently on MI and had an IA bleed on 03/31/22. Follow up monitoring shows an increasing IA pressure trend that does not appear to be attributed to thermal effects from Injection temperature or rate. The well will now be classified as UNDER EVALUATION for diagnostics and monitoring. Plan Forward: 1. DHD: PPPOT‐T 2. DHD: Monitor Pressures/Quantify re‐pressurization trend if applicable 3. Fullbore: (Pending): MIT‐IA 4. Well Integrity: Additional diagnostics as needed. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659‐5102 M: (307)399‐3816 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Wallace, Chris D (CED) From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Wednesday, June 9, 2021 9:59 AM To: Wallace, Chris D (CED) Subject: RE: [EXTERNAL] RE: V-218, L-119 AA 90 day plots Attachments: MIT PBU L-119 L-218 05-25-21.xlsx; MIT PBU V-218 V-219 05-25-21.xlsx Chris, The forms for these 2 wells were sent in on 6/1 so they probably just haven't been uploaded yet. See the attached sheets for another copy. Oliver From: Wallace, Chris D (CED) <chris.wallace@alaska.gov> Sent: Wednesday, June 9, 20218:58 AM To: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Subject: [EXTERNAL] RE: V-218, L-119 AA 90 day plots Oliver— I do not seem to have these MITs so could you please send. Maybe they were sent on the 51h in a batch but they haven't been uploaded into our database and so I do not have a record. Thanks, Chris From: Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Sent: Thursday, June 3, 20219:55 AM To: Wallace, Chris D (CED) <chris.wa[lace@alaska.gov> Subject: V-218, L-119 AA 90 day plots Chris, Something must have happened when the documents got signed where it cut out a couple pages. Here are unsigned copies that include the TIO/ Injection plots. Oliver Sternicki Hilcorp North Slope LLC Well Integrity Engineer Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com The information contained in this email message is confidential and maybe legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical 14egnty Test Submit to: rm.rem0alaskaaov: AOGCC Insoectorsfite ske pow phoebe bmokst®alaska.gov OPERATOR: Hlmrp Alaska LLC FIELD / UNIT / PAD: Prudhoe Bay / PBU I V Pad DATE: 05/25121 OPERATOR REP: Ryan Holt AOGCC REP: Lou Laubenstein Chris.wallace0alaskd pay Well V-218 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD 2070400 Type lnj W Tubing 909 911 910 909 Type Test P Packer TVD 4516 BBL Pump 3.6 IA 438 3347 3260 32" Interval O Test psi 1500 BBL Retum 3.6 OA 200 210 217 220 Result P Notes: Apply for AA for slow lAOA communication Well V-219 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2081420 Type Inj W Tubing 801 801 798 800 Type Test P Packer TVD 4491 BBL Pump 1.8 IA 724 1743 1681 1674 Interval 4 Test psi 1500 BBL Retum 1.8 OA 288 292 292 291 Result P Notes: 4 Year AOGCC MIT -IA Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi I BBL etuml OA Result Notes: Well Pressures. Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min, PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD1 I BBL Pump I I IA I Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Tesl Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer WD BBL Pump IA Interval Test psi BBL Realm OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type hit Tubing Type Test Packer WD BBL Pump IA Interval Test psi BE Return OA Result Notes: TYPE INJ Carties W=Water G = Gas 5=slurry I- Industrial Wastewater N =Not Injecting TYPETESTCoCes INTERVAL Codes P=pleasure Test I Irdal Test G=GNer nee lee N Notes) 4=Four Year Cyck V . Repused ley Venance 0= aner tdearncem nntan Result parties P - Pew F = Fail 1=lnconcluarve Form 10-426 (Revised 0112017) MIT Pau V-218 V-2190S2681.r1as Hilcorp North Slope, LLC Stan Golis, PBW Operations Manager 3800 Centerpoint Or, Suite 1400 Anchorage, Alaska 99503 RECEIVED 05/26/2021 By Grace Salazar at 11:25 am, May 27, 2021 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West Vh Avenue Anchorage, Alaska 99501 Subject: Orion Well V-218 (PTD# 207040). Request for Administrative Approval to continue WAG Injection Operations. Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued WAG injection into Orion well V-218 with slow inner annulus (IA) leakage. WAG injector V-218 was found to have slow inner annulus pressure loss and was reported to the AOGCC on 5/18/2021 and placed under evaluation. There is no indication of tubing by inner annulus communication or inner annulus by outer annulus communication based on pressure trends. The well had a passing AOGCC witnessed online MIT -IA on 05/25/2021 to 3240 psi which confirms both the primary and secondary well barrier integrity. Hilcorp North Slope, LLC has determined that well V-218 is safe to operate in its current condition and requests an AA for WAG injection based on the following: • MIT -IA passed to 3240 psi. • IA and CA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-564-5231 or Ryan Holt/ Andy Ogg at 659- 5102. Sincerely, �� ,) 4- Stan Golis PBW Operations Manager Orion Well V-218 Technical Justification for Administrative Approval Request 05/26/2021 Well History and Status Well V-218 is a WAG injector that was drilled in April 2007. The OA was cemented during the completion of the well with cement returns to surface. V-218 has predominantly been on produced water injection except for in 2008 when it saw MI service. Prior to the recent discovery of the IA pressure anomaly on V-218 the most recent AOGCC witnessed MIT -IA passed to 1959 psi on 11/07/2017. On 05118/2021, V-218 was found to have slow IA pressure loss and was reported to the AOGCC and placed under evaluation. Based on analysis of the annulus and tubing pressure trends the IA does not appear to be in communication with the tubing or the OA. An AOGCC witnessed MIT -IA passed to 3240 psi on 05/25/2021. Recent Well Events: 05/25/2021 AOGCC witnessed MIT -IA passed to 3240 psi 05/19/2021 PPPOT-IC passed to 3500 psi 05/18/2021 IA pressure leakage flagged and notification sent to the AOGCC 11/07/2017 AOGCC witnessed MIT -IA passed to 1959 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3240 psi on 05/25/2021, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics/ repair will be pursued at this time due to the low likelihood of being able to determine the leakage point based on the low fall -off rate. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA to maximum anticipated injection pressure. 4. IA MOASP= 2100 psi, OA MOASP= 1000 psi 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. Orion Well V-218 Technical Justification for Administrative Approval Request 05/26/2021 Well History and Status Well V-218 is a WAG injector that was drilled in April 2007. The OA was cemented during the completion of the well with cement returns to surface. V-218 has predominantly been on produced water injection except for in 2008 when it saw MI service. Prior to the recent discovery of the IA pressure anomaly on V-218 the most recent AOGCC witnessed MIT -IA passed to 1959 psi on 11/07/2017. On 05/18/2021, V-218 was found to have slow IA pressure loss and was reported to the AOGCC and placed under evaluation. Based on analysis of the annulus and tubing pressure trends the IA does not appear to be in communication with the tubing or the OA. An AOGCC witnessed MIT -IA passed to 3240 psi on 05/25/2021. Recent Well Events: 05/25/2021 AOGCC witnessed MIT -IA passed to 3240 psi 05/19/2021 PPPOT-IC passed to 3500 psi 05/18/2021 IA pressure leakage flagged and notification sent to the AOGCC 11/07/2017 AOGCC witnessed MIT -IA passed to 1959psi' Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3240 psi on 05/25/2021, which tests both barriers, demonstrates competent primary and secondary barrier systems. No further diagnostics/ repair will be pursued at this time due to the low likelihood of being able to determine the leakage point based on the low fall -off rate. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA to maximum anticipated injection pressure. 4. IA MOASP= 2100 psi, OA MOASP= 1000 psi 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. TIO(Injection Plot � o- Wellbore Schematic JR11 + 4 1r16.ON VAHIIAO' ---IM: AB4UTOR• tM KII II IV = 215' Br E-EV ` 515 KOP = 300 Mu Aljb- 67'�f YAK 29•CL"X-:lM 108' Y Olala fin- 6621' IL1aa1WD- 4400 SS TO-•J9' If5 FS [H.FNIFH -I 3010• F9-0A5*C G• 40e. LW BTC. 0 = 9 9J5• 3201' I7_MG'ML-WVAMTOPICXOT06MU 1 7 51 I/-MAH091JOMwIRATAGj I 6Y69' Minimum ID =2.76" H@ 7028' 3-112" HES XN NIPPLE �J In'MAPotFR dOM wlRA IA<:i 7A09' l'MAfb(k1i.UN7w/M 7AG r6921' / PERFORATCNSIA1191Rf AI+ LO13 SLB L6R ON0V11/07 ANGLE Al TOP Hllf 50'®GBDO' Note: NIa1 b Raducuon GB for �ebleel tl d91a EZI: 2ON I MI INAI I OIxd59x M1I' 41IZ• S OBl RBI/.'+-67f+.1 O /- Vr 5 OE! 6926 - 6903 O 13 1CY 1Iif1.97x. 19u +ct. Dour fiat. u • 2.992• - �- 7060'.. V-21 V IAFETYNOTES: NKNDIONCBAVE RAGE WHEN ON ML WELL RK44RFS A SSSV WMW ON NL --^ (""THI TOSNf Af}... Ifs HOC ®6514'6 'FULL TO RELEASE BLI1 CAN ALSO BE F8FA5 BY PRESS DO FUT E%®2WD PSI ON TFE N w A711T R330N.NC TBO MWEB4F CALClUT10N5 A DUQ SNGw/A/C•- 2Af/' i]-ur �cszr4r,D=29+3• GAS LIFT NANIFSL.S _ST�NO 4TVD1 1V.. WAG .I_:1.0 CH � Dk-TE0517 EE I 1W'111e 1' ♦1 Nf1i/ 1 ti1 1111111111111 r1N 1111N1 cvsrar•c^9r9retsl�e�lemlw:aevlsa�eeecc��Neewe e1111111111 1 3 SO MM G.W P-15X.R RK 9L J 49 MNG-W afY Pot 0 �6=13§5 2 AM3 49 MMG-W P15XR RK V1 1 69761 49 MMO.W RISxR RK 61 r-TI f81 PKFI U - 2 985' ----------- 869T � H OF7JN iP7S/TCA1P SFN9[IR SIH, O. 7 Y4^' i va•1isx NP,n-7au• IF[IDIIR NRU-79115' 41701- R[NAIX SINSd1SW. U-TmZ r• x s m• rcti s1a;L1. Hfllnval R(11, n • 2 96s• IS In'193x N`n-2$1J' --� n6D II071OGxi11], OFOON LMT MIL V 218 1i19.91 M 62vol o ARNa 50029-21150M at: 11, nlR R11L• 4q®' F.til A 15/6' FH Hilcorp North Slope, LLC Bo York, PBE Operations Manager 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 11 12/28/2020 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Orion Well L-221 (PTD# 208031). Request for Administrative Approval to continue Water Injection Operations. Dear Mr. Price, Hilcorp North Slope, LLC requests administrative approval for continued water injection into Orion well L-221 with slow tubing (T) by inner annulus (IA) repressurization post IA packer squeeze. No increase to Maximum Operating Annulus Surface Pressure (MOASP) is required. WAG injector L-221 was found to have a packer leak after failing an MIT -IA on 7/29/2016. The packer leak was repaired on 12/31/2018 with a cement packer squeeze under Sundry #318- 119. The well had a passing AOGCC witnessed MIT -T on 4/19/2019 to 2480 psi and a passing AOGCC witnessed MIT -IA on 5/13/2019 to 3127 psi which confirms both the primary and secondary well barriers. On 11/21/2020 L-221 was placed on produced water injection to evaluate the success of the IA packer squeeze job. During this evaluation period the well has shown slow IA repressurization while on produced water injection which can be managed with periodic bleeds. Hilcorp North Slope, LLC has determined that well L-221 is safe to operate in its current condition and requests an AA for water injection based on the following: • IA pressure can be maintained below MOASP by managing the IA repressurization with periodic annular bleeds. • MIT -IA passed to 3127 psi. • IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-777-8345 or Ryan Holt/ Andy Ogg at 659- 5102. Sincerely, Digitally signed by Bo York Bo York DN _Bo York ao=Hllcorp Alaska LLC, ou=Alackska North Slope, email=byork@hilcorp.com Dale: 2020.12.28 09:45'.37 -09'00' Bo York PBE Operations Manager Attachments Technical Justification TIO/ Injection Plot Wellbore Schematic Orion Well L-221 Technical Justification for Administrative Approval Request 12/21/2020 Well History and Status Well L-221 is currently a WAG injector that was originally drilled in April 2008. On 7/29/2016 an MIT -IA failed and the leak was found at the packer on 8/22/2016 with a leak detection log. On 12/31/2018 an IA cement packer squeeze was completed under sundry # 318-119 placing 572' of cement above the packer. An IA top of cement was logged with a SCMT on 4/17/2019. An AOGCC witnessed MIT -T passed to 2480 psi on 4/19/2019 and the well was classified under evaluation and placed on produced water injection on 5/11/2019. An AOGCC witnessed MIT -IA passed to 3127 psi on 5/13/2019. During this evaluation period the well was found to have slow TxIA repressurization when on produced water injection and was made not operable on 6/8/2019. To complete the sundry work for the packer cement squeeze and evaluate the repressurization rate the well was placed on produced water injection on 11/21/2020. On 12/15/2020 a water flow log was completed with no flow seen in the annulus around the packer squeeze. Monitoring from 11/21-12/21/2020 shows that on produced water injection the IA�p+repressurization can be managed with periodic bleed and maintained belovV IA IVIOAJr Uf L I VV psl. Recent Well Events: 12/15/2020 Water Flow log completed, no flow seen. 11/21/2020 On injection under evaluation for TAA repressurization. 6/8/2019 Not operable due to IA repressurization 130psi/day) on water injection . 5/13/2019 AOGCC Witnessed MIT -IA passed to 3127 psi. 5/11/2019 Placed on water Injection under eval. 4/19/2019 AOGCC Witnessed MIT -T passed to 2480 psi. 4/17/2019 SCMT logged IA TOC= 4545' MD. 12/31/2018 Placed 572' of cement in IA repairing packer leak at 5117' MD. Sundry #318-119. 8/22/2016 LDL Identified a packer leak 5117'. 7/29/2016 Failed MIT -IA, LLR= 0.25 BPM. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3127 psi on 05/13/2019, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below MOASP of 2100 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Water injection only 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to 1.1x maximum anticipated injection pressure or 0.25 x packer TVD, whichever is greater. 5. IA MOASP= 2100 psi, OA MOASP= 1000 psi 6. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. i l.imw.w�e s NII UM`I�: MlFl i� daft TRf£= 4-1/16" CNV WBJ.HEAD = FKC ACTUATOR = GLEO K8. ELEV = 77.4' BF. ELEV = 51.51' KOP = -- 300' Max Angle = 53'(g 2980' Datum ND = 564T Datum TVD, = 4409.SS i 20" CONDUCTOR, 91.5#, A-53, ID = 19.124" 108' 9-5/8" CSG, 40#, L-80 BTC, D = 8.835" 3117' IA CMT SQZ TOC (01/01/19) (SCMT 04/17/19) -4545- 17- CSG, 26#, L-80 TCI XO TO L-80 BTGM 467W 7" X 3-1/2" HES DtbAL FBaM- IJ PKR, D= 2.965" 511 T Minimum ID (L-221) = 2.75" @ 5772' 3-112" HES XN NIPPLE T MARKER JOINT w IRA PP TAG I 5157' 3-12" RA PP TAG 5245' I7" X 3-1/2" HES SINGLE FEIDTFRU WR, D = 2.965" 1--I 5318" 7" X 3-12' FES DUAL FEEDTFRU PKR, ID = 2.965" 1-1 5459' PERFORATION SUMVWRY REF LOG: USIT LOG ON 04/07/08 ANGLE AT TOP PERF: 471 @ 5024' Note: Refer to Production DB for historical perf data SIZE SPF ZONE INTERVAL OpNSgz DATE 4-12" 5 Nb 5206-52-28 O 04106/08 4-12" 5 OA 5396-5448 O 04/06/08 4-12" 5 OBa 5487-5530 O 04/06/08 4-12" 5 OBb 5548-5568 O 04/06/08 4-12" 5 OBc 5622-5649 O 04/06/08 4-12" 5 OBd 5692-5757 O 04/06/08 1-12" TBG, 9.2#, L-80 TCI, .0087 bpf, D = 2.992' -- 5794' PBTD 5955' 7" CSG, 2611, L-80 BTGM, .0383 bpf, ID = 6.276" 604V SAFETY NOTES: H2S READINGS AVERAGE 125 ppm L-221 WHEN ON MI. WELL REQUIRES A SSSV WHEN ON Ml. HES PKR(jP 511T IS -PULL TO RELEASE' BUT CAN ALSO BE RELENSED BY PRESS. DO NOT IXC® 2000 PSI ON THETA wIOUT PERFORMING TBG MOVEMENT CALC'S & DISCUSSING w/ APE""' 24' 4-12" X 3-112" XO, D = 2.992" 2721' 3-12" HES X NP, ID = 2.813" GAS LIFT MANDRELS ISTI MD I TVDIDEVI TYPE I V LV ILATCHI PORTI DATE 11015068140731 47 1 MMG IRWF-Bi RK 1 0 10/29/18 6096' 3-1/2" HES X NP, D = 2.813' 6131' 3-1/2" NDPG MULTI -SENSOR SUB WATER N IFf .Tww MAMIRFI C ST MD TVD DEV TYPE VLV LATCH PORT DATE 9 5143 4124 47 MMG-W DMY RK 0 04/07/08 8 5236 4187 47 MMG-W P-15XJR RK 12 0421/19 7 5344 4263 46 MMG-W DMY RK 0 04/07/08 6 5438 4328 45 MMG-W P-15XJR RK 12 0421/19 5 5485 4362 45 MMG-W P-15XJR RK 12 0421119 4 5516 4384 45 MMG-W DMY RK 0 0421/19 3 5570 4422 44 MMG-W DMY RK 0 04/07/08 2 5641 4473 44 MMG-W DMY RK 0 1029/18 1 5722 4532 43 MMG-W DMY RK 0 1029/18 6297' [--13-1/2" HES X MR D = 2.813" 6331' 1--13-1/2- NDPG MULTI -SENSOR SUB, ID = 2.992 6461' 1--� 3-1/2" HES X NP, D = 2.813" 6473' 1-13-12" NDPG MULTI -SENSOR SUB. D = 2.992 6636' —) 7" X 3-12" SINGLE FEEDTHRU PKR, D = 2.965- 664V 3-12" NDPG MULTI -SENSOR SUB, D = 2.992 6662' 1—j 3-1/2" HES X NIP, D = 2.813- 6670- 1—i 7" X 3-12" SINGLE F®THRU PKR, D = 2.965- 6683' —13-1/2- NDPG MULTI -SENSOR SUB, D = 2.992 6701' 3-1/2" H6 X NR D —=2-8-1-3- h 6761' I-13-1/2" HES X NP, D = 2.813- 6772' 3-1/2" HES XN NP, D = 2.750" 5772' 3-12' RMX w/DMY PRONG (04/19/19) 6794' --x3-1/2" % LEG, D = 2.992" ELMD NOT LOGGED 6860' CMT FISFt MILLED & PUSHED CBP (01/01/19) ORION UNIT WELL: L-221 PERMIT No:'1080310 AR No: 50-029-23385-00 SEC 34, T12N, Rl l E, 2404' FSL & 1663' FWL DATE REV BY CONVENTS DATE REV BY CONTENTS 04/09/08 NKS ORIGINAL COMPLETION 01/07/19 MWJI D IA CMT SQZ, MLL CBP, FISH 09/05/08 JANPJC DRAWING CORRECTIONS 01/10/19 MTHJND SET XXN PLUG (01/08/19) 0125/18 EZ/JMD ADDED SPRING W13GHT TO WR 0422/19 M-VJMD+ IA TOC PER 4/17/19 SCMT 11112118 GJB/JI D WFR C/O (10/29/18) 0422179 RCB1J RIND( SET/GLVS C/0 (0422/19) 11/12/18 1 JMG/JI D PULLEDPLUGS (1029118) 05/09/19 DD/JM� CHANGED 2 SINGLE PIQRS TO DUAL Hilcorp North Slope LLC 1123/18 KFMJMD SET WFD CBP (11/16/18) Colombie, Jody J (CED) From: Brodie Wages <David.Wages@hilcorp.com> Sent: Friday, July 31, 2020 6:26 AM To: Roby, David S (CED) Cc: Colombie, Jody J (CED); Davies, Stephen F (CED); Boyer, David L (CED); Wallace, Chris D (CED); Rixse, Melvin G (CED) Subject: RE: [EXTERNAL] Sundry application for PBU L-213 well (PTD 206-053) Attachments: L-213 Shrader Polymer Pilot Sundry Supplement.docx Categories: Yellow Category I didn't see a question in this note, but I've included the pump schedules we will be following. Please let me know if you need anything else. David "Brodie" Wages Hilcorp Energy GC -2 (LVZMNH Pads) Ops Eng O: 907.564.5006 C: 713.380.9836 From: Roby, David S (CED) [mailto:dave.roby@alaska.gov] Sent: Wednesday, July 29, 2020 5:07 PM To: Brodie Wages <David.Wages@hilcorp.com> Cc: Colombie, Jody J (CED) <jody.colombie@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov>; Rixse, Melvin G (CED) <melvi n.rixse@a laska.gov> Subject: [EXTERNAL] Sundry application for PBU L-213 well (PTD 206-053) Mr. Wages, In the referenced sundry application you seek permission for a polymer injectivity test in the Schrader Bluff/Orion oil pool. Rule 3 of AID 26B specifies the fluids that are authorized for injection in the pool for EOR purposes, and this list does not authorize the use of polymers. As such, you'll need to get an administrative approval from the AOGCC authorizing polymer injection for this pilot project. Hilcorp's application should indicate the purpose of conducting the pilot project, discuss compatibility of the proposed fluids with the reservoir, and provide details about the planned rates, pressures, durations, and volumes of the various stages of the testing program. Some of this information is already contained in the sundry application and where applicable the administrative approval application can reference the data that has already been submitted. Let me know if you have any questions. Regards, David Roby Senior Reservoir Engineer Alaska Oil and Gas Conservation Commission 907-793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at 907- 793-1232 or dave.robv@alaska.¢ov. The information contained in this email message is confidential and maybe legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby noted that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. n llil.,p Alaska, LLC Well: L -213i Date:7/28/20 Well Name: L -213i API Number: 50-029-23306 Current Status: Online -Injecting Pad: L -Pad Estimated Start Date: 8/15/2020 Rig: 60 Reg. Approval Req'd? NA Date Reg. Approval Rec'vd: 70 Regulatory Contact: NA Permit to Drill Number: NA First Call Engineer: David Wages 907.564.5006 713.380.9836 Brief Well Summary/Purpose: 1100 1 120 Hilcorp has had good success with polymer floods over in Milne, we want to test the concept in PBU Shrader. In 2015, open pocket injection tests were performed in each interval using diesel as the injected fluid (screenshot of findings below). Obiective: Execute polymer injection into each individual zone then open all zones and obtain final injection profile. Pump schedule and volumes: Pump schedule: MAX PRESSURE=1200 PSI Step Rate test for plant water using pad injection header: Tubing Pressure Duration Expected Vol. Cum. Vol (psi) (Hours) (Bbls) (Bbls) 700 1 60 60 800 1 70 130 900 1 80 210 1000 1 90 300 1100 1 120 420 1200 1 150 570 Total water needed day 1: —600 bbls MAX PRESSURE=1200 PSI Step Rate test for Polymer, using polymer unit: Tubing Pressure Duration Expected Vol. Cum. Vol (psi) (Hours) (Bbls) (Bbls) 700 1 60 60 800 1 60 120 900 1 60 180 1000 1 60 240 1100 1 60 300 1200 or max rate 6 360 660 Polymer water vol required per day pumping: —700 bbls U 11A.,p Meek.. LLC MAX PRESSURE=1200 PSI Step Rate test for source (Milne clean) water or polymer in source water, using polymer unit: Tubing Pressure Duration Expected Vol. Cum. Vol (psi) (Hours) (Bbls) (Bbls) 700 1 30 60 800 1 40 70 900 1 50 120 1000 1 60 180 1100 1 60 240 1200 1 60 300 Total source water needed: —600 bbls Well: L -213i Date: 7/28/20 For each zone, a baseline water step rate test (SRT) will be obtained using pad injection header before moving on to the polymer injections. There will be several different polymer loadings tested. We are not testing WFRVs at this time, only if we can get the reservoir to take our polymer. Fall off tests will be obtained in each zone, once the pump is shut down, leave the well alone. The falloff data is extremely sensitive. It may be necessary to call in a cement van for the higher pressures/rates. n llikwrp Alu4u. LLC WBD: Well: L -213i Date:7/28/20 TREE= 12' WJFL% PU FORATION SLOAARY DEV NELLHEAD- 11' RT[: DATE 7 SAFETY NOTES: NQS READINGS AIPMAGE 128 ppw ACTLNTOR = ON W -80 L SIZE 0E' ON MI. WELL REQUIRES A SSS V SAFETY MNL KB. ELE 78 1' -213 4.12' 5 IN H FV = 488 04728'08 4-144 5 KOP= 401 0026M 4.12'S 4 091 0202-0307 O - 4-112•X]-10'XO. D=2.99T hbx Angle- 61•®2758 20'CONDl1CTOR O 4428448 412• 5 -{]-12'4415 %NP,D•2BIT ODI MNO 6378 2 6366 4467 17 N.G-W R15XR RL IBL r DDWMTVD= 446055 1215 59. A-53, ID 17 WA w P-I5X.R RK t8L 11111115 _ 4-72• TBG, 126 /, L -W TAI -� 0152 8pf, D - 3 958• GAS LFI kIANOTH.S ST kb TVO DE! TYLE VLV LATT71 POITr DATE 9-5X1• CSG, 909, L -9D BTC, D = B 9]5• 888r P,IGD36141551 21 1 MMD I 081'7 I FB( 1 9 04D1D6 WRIER NJ :CTDN kNNOTaB-S Ir MAF6QBtJONFw/ RA TAG Minimum ID =2.813^ @ 3300' 3-1/2" HES X NIPPLE 7'1MRK9i J014T w l RA TAC 0180' OOB7 6pl. D= 2Mr BTC -M..0383 ST NO PU FORATION SLOAARY DEV TYPE VLV LATCH FEF LOGANAOLal LWDON 04/28X18 DATE 7 AN GLE AT TOPFHF: 18' ® 8197 4275 NA9. Ww to Roducton DS lot holDncal pwf dale SIZE SPF ZONE NTHNAL OpNSw SHIN SOL 4.12' 5 OA 6188 - 8228 O 04728'08 4-144 5 088 6208 - 8280 O 0026M 4.12'S 4 091 0202-0307 O 0412m 4-Irr S Oft 0350-6382 O 4428448 412• 5 OBd 8002 - U50 O 04/AM OOB7 6pl. D= 2Mr BTC -M..0383 ST NO ND DEV TYPE VLV LATCH PORT DATE 7 6160 4275 19 46 W OW RK O 04!28818 6 6213 4321 18 MA[iW RiSXJR RK 18L11111115 _ 5 8259 0365 18kMCrW C6FY FB( 0 04 2808 4 6298 4402 18 kM(iW R15XJR RK IRL 11!11!/5 3 6338 4440 17 M.r w Din R( 0 OO28A6 2 6366 4467 17 N.G-W R15XR RL IBL 11111115 1 6412 4511 17 WA w P-I5X.R RK t8L 11111115 8321' Hr%3-12•BIO PREMRG(D-2 6461' }12'IBXI4P,D•2A13' RPV RV COkO@!IS ORONL"T WELL L-213 PHitT M: 7080530 ARM. 5&02&2330&00 SEC 34. T12N M IE 1409' FSL 8 1673 FVYL DATE REV BY 008/7805 OA TE 0412UB8 NUBB INTLAL COMPLELION 10/02/15 fW&WJk4 VrTR(70(OWM15) 03/1080 JLIMNC T CSG COR6CITON OL29I76 JRGIlTI TUL SRJG 8 WFR 170 (i 1!11!15 1271V10 GTVWW SETS%G(12A)Wl0 07!12/16 RCTIJW FUl®'FFSETR FLUE& 02!15171 ABIJAD A00®SSSU SAFETY NOTE 0112910 PZJJ1.0 A00®SRMq W(3GFFT TO WFR 01/18112 TWJMD A00® I12S SAFELY' NOTE 12AY14 DUJK) my 001112914) — _ BP rxplorallon lAleka) �7 bp • • BP Exploration(Alaska)Inc. a. - 900 E.Benson Blvd `• ��_ P O.Box 196612 Anchorage,AK 99519-6612 USA Main 907 561 5111 Fax 907 564 5020 June 6, 2013 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Suite 100 Anchorage, AK 99501 Attention Mr. David Roby Dear Mr. Roby: Thank you for your request for clarification regarding the RCRA status of the radioactive tracers to be used in the upcoming study at GC2. The GC2 Capacity Study involves the injection of low level radioactive tracers upstream of the slug catchers in GC2 to study the separation efficiency of various vessels. Once injected into the vessels, the tracer will be commingled with production fluids at the gathering center, follow the normal separation process, and be routed to the Class II well system for either enhanced oil recovery or injection. The project is scheduled to start June 20, 2013. Here are responses to your questions: 1. Evidence and legal authority in support of BP's assertion that radioactive tracer wastes are not regulated under RCRA; RCRA regulates hazardous solid wastes. Therefore, the threshold question when determining the RCRA status of a material is whether it is a "solid waste." In order to be a solid waste, a material must be "discarded." RCRA section 1004(27).1 Therefore, products being used for their intended purposes are not wastes because they are not being discarded. In this case, the facility will be injecting low level radioactive tracers upstream of the slug catchers in GC2 to study the separation efficiency of various vessels. The purpose of this injection is not to discard or dispose of the tracers, but to utilize them for their intended, useful purpose (conducting the separation efficiency study). RCRA does not regulate this activity because the purpose of the injection is not to discard the tracers. 1 42 U.S.C. § 6903(27). • • Once used, the radioactive tracers are not regulated under RCRA because they are specifically excluded from the definition of "solid waste" under 40 CFR 261.4(a)(4). Radioactive tracers are instead regulated under the Atomic Energy Act. As you note in your letter, radioactive tracer waste is not E&P exempt because such waste is not uniquely associated with oil and gas; many other industries use radioactive tracers. 2. Evidence to support a determination whether radioactive tracer waste is hazardous or whether it exhibits hazardous characteristics under 40 CFR Part 261 As noted above, radioactive waste is excluded from the definition of "solid waste" under RCRA. Therefore, such waste is not a "hazardous solid waste" regulated under the statute. 3. Evidence and legal authority to support a claim that radioactive tracer waste may otherwise fall under a RCRA exemption. Disposal of the mixture comprised of produced water and the radioactive tracers is covered under the RCRA Mixture Rule, which allows non-hazardous, non- E&P exempt waste (e.g., used radioactive tracers) to be commingled with E&P exempt waste (produced water), with the resulting mixture retaining the E&P exemption.(See page 17 of the EPA RCRA E&P Guidance Document you cited in your May 31, 2013 email.) Note that this result is consistent with how produced water exposed to radioactive tracers injected during well logging is regulated as E&P exempt waste. We hope that this explanation satisfies your request for clarification. As noted above, the study is scheduled to begin June 20, 2013. Please contact as soon as possible if you have additional questions or want to discuss further at 907-564-5501 or contact Alison Cooke at 564-4838. I), Janet D Platt Director, Regulatory Compliance and Environment, Alaska Cc: Alison Cooke, BP Cc Cathy Foerster, AOGCC Cc: Jim Regg, AOGCC -46 • • Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Friday, May 31, 2013 12:45 PM To: Cooke, Alison D Cc: Regg, James B (DOA); Wallace, Chris D (DOA); Lau, Glenn L; Crandall, Krissell Subject: RE: BPXA Request for Administrative Approval Alison, BP's assertion that "Radioactive tracers are not regulated under the Resource Conservation and Recovery Act (RCRA) so the fluids would not be designated hazardous or non-hazardous.Therefore,the diluted radioactive tracer which BP proposes to use at GC2 would not be categorized as hazardous or non-hazardous under RCRA ..." cannot be reconciled with a RCRA Guidance document which lists "radioactive tracer wastes" as a Non-Exempt Waste. See, http://www.epa.gov/osw/nonhaz/industrial/special/oil/oil-gas.pdf at page 13 of 40. As a result, the AOGCC requests BP provide the following: 1. Evidence and legal authority in support of BP's assertion that radioactive tracer wastes are not regulated under RCRA; 2. Evidence to support a determination whether radioactive tracer waste is hazardous or whether it exhibits hazardous characteristics under 40 CFR Part 261. 3. Evidence and legal authority to support a claim that radioactive tracer waste may otherwise fall under a RCRA exemption. Regards, Dave Roby (907) 793-1232 From: Cooke, Alison D [mailto:Alison.Cooke@bp.com] Sent: Tuesday, May 14, 2013 11:38 AM To: Foerster, Catherine P (DOA) Cc: Roby, David S (DOA); Regg, James B (DOA); Wallace, Chris D (DOA); Lau, Glenn L; Crandall, Krissell Subject: BPXA Request for Administrative Approval Ms. Foerster: Attached is a request from BPXA for administrative approval to inject dilute volumes of radioactive tracer that has been used for the purposes of studying vessel inefficiencies in Gathering Center 2 in the Prudhoe Bay Field in either FOR wells or Class II disposal wells. A hard copy of the letter is also being sent to you by certified mail. BPXA had a teleconference with your staff on April 25,2013 to discuss this project and our request. We would appreciate the Commission's timely review of this request. If possible we would appreciate a response by May 31. «BPXA to AOGCC GC2 Tracer.pdf>> If you or your staff have any questions please contact me at 440-8167 or alison.cooke @bp.com. • • R gards, Alison Alison D. Cooke 907-564-4838 tel. 907-440-8167 cell 907-564-5020 fax. cookeadna.bp.com 2 12 b p • •MAY 15 2013 AOGCC BP Exploration(Alaska)Inc P O.Box 196612 CERTIFIED MAIL: 7011 2970 0001 9241 2635 900E Benson Boulevard Anchorage,AK 99519-6612 USA May 14, 2013 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Radioactive Tracer Injection: PBU 2013 GC2 Optimization Administrative Approval Request: Prudhoe Oil Pool, Area Injection Order 3A Aurora Oil Pool, Area Injection Order 22E Borealis Oil Pool, Area Injection Order 24B Polaris Oil Pool, Area Injection Order 25A Orion Oil Pool, Area Injection Order 26B Dear Ms. Foerster: BP Exploration (Alaska) Inc. (BPXA) requests approval under Area Injection Order (AIO) 3A Rule 1, AIO 22E Rule 10, AIO 24B Rule 2, AIO 25A Rule 3, and AIO 26B Rule 3 to introduce radioactive tracer into the Gathering Center 2 (GC2) production facility for the purpose of oil production, plant operations, and plant/piping integrity. Radioactive tracers are not regulated under the Resource Conservation and Recovery Act (RCRA) so the fluids would not be designated hazardous or non-hazardous. Therefore, the diluted radioactive tracer which BP proposes to use at GC2 would not be categorized as hazardous or non-hazardous under RCRA. The tracer will comingle with produced fluids and be diluted prior to enhanced oil recovery (EOR) reservoir injection. Mixing the radioactive tracer with produced fluids meets the criteria of fluids suitable for Class II disposal well injection. The tracer has been deemed to have no negative impact on the reservoir. Alyeska Pipeline Service Company has been informed of the test and noted no concerns with handling the diluted tracer. In order to keep standardized and consistent language referencing the fluids authorized for injection for enhanced recovery and pressure maintenance for all Prudhoe Bay Field (PBF) AlOs, BPXA also requests that radioactive tracer fluids • • Ms. Cathy Foerster May 14, 2013 Page 2 be specifically included as fluids introduced to production facilities for the purpose of oil production, plant operations, and plant/piping integrity in AIO 4E Rule 1, AIO 14A Rule 1, AIO 20 Rule 1, and AIO 31 Rule 3. GC2 Optimization The West End Developments program consists of several projects to debottleneck base production and increase future GC2 production. As part of the program, the optimization of GC2 and its separation capabilities will be reviewed. The current separation and sand handling capabilities will be evaluated in the study and changes will likely be recommended to process future production streams. Capacity Study The study will determine current vessel inefficiencies and propose upgrades to the facility. Radioactive tracer is needed to calculate the residence time of the oil and water phases in the slugcatchers and the water residence time in the skim tanks. For this determination, a total of 300 mL of radioactive tracer (lanthanum nitrate hexahydrate) will be injected upstream of the GC2 slugcatchers and skim tanks to trace the water phase. It is expected that minor amounts of the 200 mL bromoanthracene oil tracer will be carried into the produced water system. The half-lives of each tracer used in this study will be less than 2 days. Reservoir tracers typically used include cobalt-57, cobalt 60, carbon-14, or tritium which have half-lives of 270 days, 5.26 years, 5730 years, and 12.32 years, respectively. The shorter half-life in conjunction with the smaller injection sizes proposed exposes the reservoir to minimal radioactivity for a short duration (see table and chart Appendix 1). Alternatives to radioactive tracer have been considered. The main benefit of a tracer is the ability to detect concentration as a function of time, which correlates to vessel residence time and can characterize inefficiencies of internals. A non-radioactive tracer would require frequent sampling, and there is a possibility the tracer would pass through the system between samples, yielding no data. The ability to characterize vessel inefficiencies would be compromised with a non-radioactive tracer. Correct assessment of the separation capabilities of GC2 is necessary to determine appropriate upgrades to the facility for increased separation capacity. The most effective way to evaluate the separation capability of the facility is to use a radioactive tracer. To summarize, BPXA requests Commission approval to • • Ms. Cathy Foerster May 14, 2013 Page 3 inject dilute volumes of radioactive tracer (that have been used in production facilities for diagnostic purposes) in all PBF AlOs and in Class II disposal wells. Should you have any questions, or require additional information, please contact me at 564-4838 or alison.cooke @bp.com. Sincerely, r Alison Cooke (y UIC Compliance Advisor Attachment: Appendix 1 —Tracerco Information cc: James Regg, AOGCC Dave Roby, AOGCC Chris Wallace, AOGCC • Ms. Cathy Foerster May 14, 2013 Page 5 Appendix 1 —Tracerco Information Tracerco Tracers Reservoir Tracers B-82 La-140 Co-57 Co-60 C-14 Tritium Injection Size (mCi) 120* 160* 200"* 500** 2000*" 10000" Half Life 35 hrs 40 hrs 270 days 5.26 yrs 5730 yrs 12.32 yrs * Proposed Amount to be Used for Study ** Typical Amounts Used for Reservoir Studies The following decay chart assumes starting activities of 200 mCi for comparison. Actual activities are shown in the chart above. Decay Chart-Tracerco Tracers vs. Other Reservoir Tracers 250 — w 200 _. ... .. a• 150 –41-8r•82(Tracerco) –0-0-140)Trac*YCo) —e—C-14 —1E^M-3 100 4 .._ _ ..._ _... _... —1e—0040 i--Co-57 0 ! 5 10 15 20 25 30 35 Time(rays) 44 bpS • BP Exploration (Alaska) Inc. P 0. Box 196612 900 E. Benson Boulevard Anchorage, AK 99519 -6612 USA 7 CERTIFIED MAIL # 7011 2970 0003 5821 9955 E^EIth April 30, 2012 MAY 0 2 2012 Kathy Foerster, Commissioner OGCC Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Prudhoe Bay Field Area Injection Orders, Standardization of Authorized Fluids for EOR and Pressure Maintenance Dear Ms. Foerster, This letter is to request a change to Prudhoe Bay Field (PBF) Area Injection Orders (AIO) to standardize the language in the rule referencing the fluids authorized for injection for enhanced recovery and pressure maintenance. BP Exploration (Alaska) Inc. (BPXA) is requesting this change in order to address the complexity of field operations with multiple pools serviced by common facilities and potential confusion that results from the differing language in the various orders. This proposed change is intended to clarify and document the fluids that are authorized for enhanced oil recovery (EOR) and pressure maintenance injection within the PBF and provide greater compliance assurance for our field operations. A review of AIOs for pools in the PBF indicates that some contain very general language and some are very specific in defining which fluids are authorized for injection. The language defining fluids that may be injected has changed over time in successive versions of some of the orders. For instance, AIO 4 language has changed from "non- hazardous fluids ", to "Class II fluids" to "authorized fluids ". In addition, some fluids have received specific authorization via administrative approvals. The diversity of language and changes over time has resulted in confusion over which fluids are actually authorized for injection. The enclosed list (Attachment A) shows the various PBF pools, AIOs, and a summary of the current rule and /or administrative approvals that authorize fluids that may be injected for purposes of pressure maintenance and enhanced recovery. Also included is a summary of findings regarding the compatibility of fluids authorized for injection. As discussed with your staff, BPXA proposes to standardize the list of authorized fluids for the various pools within the PBF. Attachment B is proposed language for this change. In some pools, additional clarification may be required to capture specific conditions or restrictions contained in current orders. Attachment C is a list of historical fluids injected for EOR and pressure maintenance • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 2 Should you have any questions, or require additional information, please contact me at 564- ' 4838. Sincerely, Y Alison Cooke UIC Compliance Advisor Attachments cc: Jim Regg AOGCC Dave Roby AOGCC • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 3 Attachment A Prudhoe Bay Field: fluids specifically authorized for enhanced recovery and pressure maintenance in Area Injection Orders AIO Rule Pool Fluids Authorized Compatibility with Formation 3 1 Prudhoe non - hazardous fluids; Area Injection Order Application for PBU WOA Bay AIO 3.03 rinsate (minus FOR and Fluid Disposal Wells: Section I: 1. (West) solids) from cleaning aerial Water: Beaufort Sea water and Produced gas coolers; Sadlerochit water; Compatibility: Water AIO 3.018 filtered and sensitivity tests on core samples showed no chemically treated lake significant problems with formation plugging or water used for hydrotesting clay swelling over the anticipated operating range replacement pipeline of salinities for produced and Beaufort Sea water; segments; 2. Miscible Gas from CGF; Compatibility: Full AIO 3.028 mixtures of glycol compatibility - reinjected into producing zone; 3. and water Produced Gas from Sadlerochit and Sag River reservoirs; Compatibility: Full compatibility - reinjected into producing zone 4E 1 Prudhoe authorized fluids; AIO4D, Finding 12: The main fluid source will be Bay (East) AIO 4C.02 rinsate (minus source water from the Seawater Treatment Plant. Put River solids) from cleaning aerial No significant compatibility issues are anticipated Lisburne gas coolers; between the formation and injected fluid. Pt. AIO 4E.022 filtered and Analyses of core samples from Put River McIntyre chemically treated lake Formation sandstone in Prudhoe Bay West water used for hydrotesting Unit Well 2 -14 demonstrate similar clay mineral Beach replacement pipeline types and proportions as those in Kuparuk River Stump segments for Greater Point Formation reservoirs in adjacent North Slope Island McIntyre; fields. Each of the analog fields has a successful AIO 4E.023 filtered and history of waterflooding and based on these chemically treated lake comparisons the water used for hydrotesting Put River Formation is not anticipated to have replacement pipeline compatibility issues related to seawater injection. segments for Prudhoe Bay AIO4C, Finding 20: Seawater is currently injected Unit fields; in the Pt. McIntyre waterflood. It is possible that AIO 4E.034 mixtures of produced water will be used later in the project. glycol and water Both water sources have previously been approved in Area Injection Order No. 4B Finding 34: Laboratory testing, core analyses and geochemical modeling indicate no significant problems are likely due to clay swelling or in -situ fluid compatibility problems between WBOP and Tertiary formation waters. Finding 35: WBOP waterflood source water from the Sagavanirktok Formation is expected to have excess barium ion which could precipitate barium sulfate scale if mixed with PMOP produced water. WBOP produced water will be inhibited upstream of the commingling point with PMOP fluids to prevent scale precipitation. • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 4 PBU EOA Area Injection Order Application, Section I Enhanced Recovery type of fluid: A. source water - treated seawater; Compatibility: no significant problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated; B. produced water from Flow Stations and LPC; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated; C. Natural Gas and NGL; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated; D. Miscibile Injectant; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated. 14A 1 Niakuk produced water from LPC, AIO14A, Finding 7: Injection will utilize either Beaufort seawater, produced or source water. The wells are currently trace amounts of scale configured to allow 60,000 Barrels of Water per inhibitor, corrosion inhibitor, Day ( "BWPD ") total, with a maximum injection of emulsion breakers, other up to 70,000 BWPD. The produced water will be products used in production a mix of Pt. McIntyre, West Beach, North process, stimulation fluids Prudhoe Bay, Lisburne and Niakuk produced water separated through the Lisburne Production Center ("LPC"), with the majority coming from Pt. McIntyre. Seawater has been injected as well. SEM, XRD and ERD analyses conducted on Niakuk core indicate very low clay content in reservoir intervals. As a result no significant problems with formation plugging or clay swelling due to fluid incompatibilities is expected. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. 20 1 Midnight fluids appropriate for A1020 Finding 21: Geochemical model results Sun enhanced recovery; indicate that a combined Tertiary water and AIO 20.001 filtered and connate water is likely to form calcium carbonate chemically treated lake and barium sulfate scale. Similar scale water used for hydrotesting precipitation is anticipated for produced water. replacement pipeline Scale will be controlled with commonly available segments inhibitors. • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 5 22E 10 Aurora produced water, Prince A1022B, Finding 9: The compositions of injection Creek source water *, water and AOP connate water were provided in enriched hydrocarbon gas *, Exhibit IV -4 of the original AIO application. Water immiscible hydrocarbon analysis from the nearby Milne Point Prince gas *, tracer survey fluid, Creek Formation was provided in the April 28, non - hazardous filtered 2003 application for rehearing water from pads and cellars *conditions for authorization are included in the current order 24B 2 Borealis produced water, non- AIO24A, Finding 9: As previously approved by hazardous filtered water the Commission, produced water from GC -2 is from pads and cellars, used as the primary water source for Borealis tracer survey fluid, treated injection. Injection performance, core, log and seawater, enriched pressure - buildup analyses indicate no significant hydrocarbon gas *, Prince problems with clay swelling or compatibility with Creek source water; in -situ fluids. BPXA analysis of cores from the AIO 24A.001 filtered and BOP wells indicates relatively low clay content. chemically treated lake Petrographic analysis indicates that clay volumes water used for hydrotesting in the better quality sand sections ( >20 md) are in replacement pipeline the range of 3 - 6 %. Clay volumes increase to segments approximately 6 - 12% in rock with permeabilities in the range of 10 - 20 md. Below 10 md, clay volumes increase to a range of 12 - 20 %. Most of the identified clay is present as intergranular matrix, having been intermixed with the sand through burrowing. The overall clay composition is a mixture of roughly equal amounts of kaolinite, illite and mixed layer illite /smectite. No chlorite was reported during petrographic analysis. The presence of iron - bearing minerals suggests that *conditions for authorization the use of strong acids should be avoided in are included in the current breakdown treatments, spacers, etc. Water from order the seawater treatment plant has been successfully used for injection within the Kuparuk of the Pt. McIntyre Oil Pool. Geochemical modeling indicates that a combination of GC -2 produced water and connate water is likely to form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Scale precipitation will be controlled using scale inhibition methods similar to those used at Kuparuk River Unit and Milne Point Unit. Miscible gas is a hydrocarbon with similar composition to reservoir fluids in the BOP therefore no compatibility issues are anticipated with the formation or confining zones. The composition of injection water from the Prince Creek aquifer is expected to fall within the range of Well W-400 and MPF -02 produced water • • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 6 compositions, less than 10,000 -ppm total dissolved solids. Milne Point Unit F -Pad Prince Creek source water has been injected since 1996 into the Milne Point Kuparuk Reservoir, lithologically similar to the BOP, with no apparent formation damage. A single well chemical tracer test in BOP well L -122 conducted using 640 barrels of Prince Creek Source water did not detect any formation damage. 25A 3 Polaris produced water, tracer AIO 25A, Finding 11: The enriched gas proposed survey fluid, enriched for injection is a hydrocarbon with similar hydrocarbon gas, treated composition to reservoir fluids in the Polaris Oil seawater, non - hazardous Pool and therefore no compatibility issues are filtered water from pads and anticipated. cellars, enriched AIO 25, Finding 12: BPXA provided laboratory hydrocarbon gas; analysis of the injection and produced waters. No AIO 25A.001 filtered and significant compatibility problems are evident chemically treated lake from these analyses. Disposal of PBU produced water used for hydrotesting water within the Ugnu sands has successfully replacement pipeline occurred in other parts of the field. segments 26B 3 Orion enriched gas, produced AIO 26A, Finding 11: The enriched gas proposed water, tracer survey fluid, for injection is a hydrocarbon with similar treated seawater, Prince composition to reservoir fluids in the Orion Oil Creek source water, non- Pool and therefore no compatibility issues are hazardous filtered water anticipated. from pads and cellars, non- AIO 26, Finding 11: The composition of produced hazardous filtered lake water will be a mixture of connate water and water employed for injection water, and will change over time hydrotesting pipeline depending on the rate and composition of segments injection water. Based on analyses of Polaris water samples, no significant compatibility problems are expected between connate water and injection water. 31 3 Raven produced water, tracer AIO 31, Finding 14: Water compatibility problems survey fluid, stimulation are not expected because of the successful fluids, source water from history of both sea water and produced water STP, and non - hazardous injection into the Prudhoe Bay Reservoir. No clay water collected from well swelling problems have been seen in the Ivishak house cellars and standing Formation in the Ivishak Participating Area of the ponds. PBU (IPA) with either source water injection or produced water injection. When present, scaling in the Ivishak Formation in the IPA has been limited to calcium carbonate deposition, which has been eliminated with acid treatments and controlled with the use of inhibitors. Minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. • • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 7 Attachment B Proposed Standardized List of Fluids Authorized for Injection in Prudhoe Bay Field Pools Fluids authorized for injection include: • Produced water and gas; • Enriched hydrocarbon gas • Non - Hazardous Water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 140 degrees F) • Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas and water separation in the facility. Includes but not limited to: • Freeze protection fluids; • Fluids in mixtures of oil sent for hydrocarbon recycle • Corrosion /Scale inhibitor fluids • Anti - foams /emulsion breakers • Glycols • Non - hazardous glycols and glycol mixtures • Fluids that are used for their intended purpose within the oil production process. Includes: • Scavengers; • Biocides • Fluids to monitor or enhance reservoir performance. Includes: • Tracer survey fluids; • Well stimulation fluids • Reservoir profile modification fluids r • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 8 Attachment C Historical Fluids Injected for FOR and Pressure Maintenance: these fluids were authorized and injected under the general descriptions of authorized fluids: AIO 4, 4A, and 4B: Class II fluids; AIO 4C: authorized fluids; AIO 3: non - hazardous fluids Treated Seawater supplied from PBU STP. Contains small amounts of chemicals: coagulant, anti -foam, scale inhibitor, biocide, oxygen scavenger and other process chemicals. Produced water from PB field producing formations. Contains small amounts of entrained produced oil and gas, and chemicals: scale inhibitor, corrosion inhibitor, emulsion breaker, and other production process chemicals. Natural Gas (including natural gas liquids) from PB field producing formations. Miscible Injectant from PBU Central Gas Facility. Reserve Pit water from pit dewatering operations. Consists of precipitation and small amounts of drilling wastes and chemicals (oxygen scavenger and biocide). Source water from shallow formations. Contains small amount of production chemicals (scale inhibitor). ~3 Page 1 of 2 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Wednesday, October 21, 2009 9:47 AM To: knelson@petroleumnews.com Cc: Colombie, Jody J (DOA) Subject: RE: question on Orion application Kristen According to the records we publish on our website the L-233 injection was permitted on September 23 and the L-203 hexalateral producer was permitted on September 30th. Neither well has been completed as of yet. Dave Roby (907)793-1232 From: Kristen Nelson [mailto:knelson@petroleumnews.com] Sent: Wednesday, October 21, 2009 9:33 AM To: Roby, David S (DOA) Subject: RE: question on Orion application Dave-thank you; I have looked at the DOG decision ... I was hoping for an update on drilling plans, as in looking through drilling permits I can't find that the injection well they talked about drilling into the expansion acreage (ADL 390067) was ever drilled, but they just got permits for the hexalateral they talked about earlier with bottomholes to the south and west of 390067 ... Kristen From: Roby, David S (DOA) [mailto:dave.roby@alaska.gov] Sent: Wednesday, October 21, 2009 9:20 AM To: knelson@petroleumnews.com Cc: Colombie, Jody J (DOA) Subject: RE: question on Orion application Kristen I have a call into BPXA regarding Attachment 4 but haven't heard back from them yet. I will let you know what I find out as soon as I hear back from BPXA and will scan and send any non-confidential portions of Attachment 4 to you after I get clarification from BPXA. In the meantime, Attachment 4 is a copy of something BPXA submitted to the DNR Division of Oil and Gas so you may try asking them for a copy. In case you don't have it yet, here is a link to the DOG's decision to expand the Prudhoe Bay Unit and defer expansion of the Orion Participating Area until more well data is available. hatp://www dog....d..nr.state ak.us/oil/programs/units/2.009/pbu-orion_expan_sion._decisio.n._021809.pd.f Regards, Dave Roby (907)793-1232 From: Kristen Nelson [mailto:knelson@petroleumnews.com] Sent: Wednesday, October 21, 2009 9:02 AM To: Roby, David S (DOA) Subject: question on Orion application 10/27/2009 Page 2 of 2 Dave Jody referred me to you with question on the Orion pool rules amendment application. Attachment 4 was not noted as confidential on the attachment list, but Jody said the pages were marked confidential-she said the commission had to check back with BP on that attachment. Do you know yet if it is really confidential? It's the amended Orion plan of development and operations; I'd really like to see that if it's a public document. Jody e-mailed me the rest of the non-confidential application yesterday; if the plan is a public document I could really use it today, thanks, Kristen Kristen Nelson Petroleum News (907) 245-5553 knelson@petroleumnews.com 10/27/2009 • • Page 1 of 1 Colombie, Jody J (DOA) From: Roby, David S (DOA) Sent: Wednesday, October 21, 2009 9:20 AM To: knelson@petroleumnews.com Cc: Colombie, Jody J (DOA) Subject: RE: question on Orion application Kristen: I have a call into BPXA regarding Attachment 4 but haven't heard back from them yet. I will let you know what I find out as soon as I hear back from BPXA and will scan and send any non-confidential portions of Attachment 4 to you after I get clarification from BPXA. In the meantime, Attachment 4 is a copy of something BPXA submitted to the DNR Division of Oil and Gas so you may try asking them for a copy. Incase you don't have it yet, here is a link to the DOG's decision to expand the Prudhoe Bay Unit and defer expansion of the Orion Participating Area until more well data is available. http://www.dog....d.nr.state.ak.us/oil/programs/units/2.009/pbu.. ori.o..n._expansion_deciso..n._021809 p.d.f Regards, Dave Roby (907)793-1232 From: Kristen Nelson [mailto:knelson@petroleumnews.com] Sent: Wednesday, October 21, 2009 9:02 AM To: Roby, David S (DOA) Subject: question on Orion application Dave Jody referred me to you with question on the Orion pool rules amendment application. Attachment 4 was not noted as confidential on the attachment list, but Jody said the pages were marked confidential-she said the commission had to check back with BP on that attachment. Do you know yet if it is really confidential? It's the amended Orion plan of development and operations; I'd really like to see that if it's a public document. Jody e-mailed me the rest of the non-confidential application yesterday; if the plan is a public document I could really use it today, thanks, Kristen Kristen Nelson Petroleum News (907) 245-5553 knelson@petroleumnews.com 10/27/2009 IPT.7 kiin� STATE OF ALASKA NOTICE TO PUBLISHER ~ ADVERTISING ORDER NO. ADVERTISING ORDER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE A O-03014012 /'1 SEE BOTTOM FOR INVOICE ADDRESS F R AOGCC Ste 100 333 W 7th Ave AGENCY CONTACT Jod Colombie DATE OF A.O. October 20, 2009 ° M , Anchorage, AK 99501 907-793-1238 PHONE - PCN DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News PO Box 149001 Arichora e AK 99514 g ~ October 22, 2009 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 Classif ied ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchors e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN z Aim 0291 0 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIQ ~ 10 02140100 73451 2 REQUISITIONE BY: DIVISION APPROVAL: 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket #s CO-09-23 and AIO-09-17; The June 30, 2009, application of BP Exploration (Alaska) Inc. to expand the Schrader Bluff Oil Pool, Orion Development Area, as currently defined in Conservation Order SOSA and Area Injection Order 26A, by adding the following lands: T12N, R11E, Umiat Meridian (UM), Sec. 14: S/2 S/2 T12N, R11E, UM, Sec. 23: All T12N, R11E, UM, Sec. 24: SW/4, SW/4NW/4 all within the North Slope Borough, Second Judicial District, State of Alaska. The Commission has tentatively scheduled a public hearing on this matter for December 1, 2009 at 9:00 a.m. at the Commission. To request that the hearing be held, a written request must be filed by 4:30 p.m. on November 9, 2009. If a request is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold a hearing, call 907-793-1221 after November 16, 2009. Written comments regarding the application may be submitted to the Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on November 23, 2009, except that, if a hearing is held, comments must be received no later than the conclusion of the hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, call 907-793-1221 by November 25, 2009. Daniel T. Seamount, Jr. Chair • • lo~?z~~a>`/ Anchorage Daily News ...Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER AD # DATE PO ACCOUNT PER DAY CHARGES 703940 10/22/2009 AO-03014 STOF0330 $156.04 $156.04 $0.00 STATE OF ALASKA THIRD JUDICIAL DISTRICT Shane Drew, being first duly sworn on oath deposes and says that he is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed Subscribed and sworn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES:~~ ~,~ ~ i .!' 7 C ~ . !QO ~~. --- . '. ~~ tl~Ll ~.. . ~~ app. , ,1 .. OTHER OTHER GRAND CHARGES #2 CHARGES#3 TOTAL $0.00 $0.00 $156.04 NoU~ of Public Hearbrg STATE OPAIASHA Alaska oq and cos Conser~ratlon Commtsston Re: Docket #S CO-09-23 and AIO-09-17{ The Jr; 30, 2009, appplication of BP Exploration (Alaska) I to expand the Schrader Bluff Oit Pool, Ori Development Area. as currently defined ~oH, oy aaang me ronowmg itmas: T12N, R11E,.Umiat Meridian (UM), SeC. 14CS/2 S/2 T12N, R11E, UM, Sec: 23: All T12N, R11E, UM, Sec, 24: Sw/4, SW/4NW/4 all within the North Slope Borough, Second Judicial District, State of Alaska. The Commission has tentatively scheduled a public hearing on this matter for December 1, 2009 at 9:00 a.m. at the Commission. To request that the hearing be held, a written request must be filed by 4~ p.m. on November 9.2009:... . If a request is not timely filed, the Cogmission may consider the issuance o~an orderwithbut a (rearing To learn if the Commission will hold a hearing, call 907-793-1221 after November 16, 2009. Written commems regarding ti1e application may tie commems must oe receives no carer tnan asu p.m. on November 23, 2009, except that; if a hearing is held, comments must be received nn later than the conclusion of the hearing. If, because of a disability, special accommodations maY.be needed to comment or attend the hearing, call907-793-1221. by November 25, 2009:- Daniel T. Seamdunt, Jr. 'Chair A0-03014012 Published: October 22, 2009 Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, October 20, 2009 2:29 PM To: Legal Ads Anchorage Daily News Subject: Public Notice Orion Expansion Attachments: Ad Order ADN.doc; Orion expansion.doc Thank you Jody J. Colorrtbie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (y07)793-1221 (,r~hone) (907)276-7542 (fax) 10/20/2009 • STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE A • NOTICE TO PUBLISHER ADVERTISING ORDER NO. AFFIODAVITIOF PUBL CATIONI PART 2 OF THIS ORM) W TIH ATTACHED LOOPY OFIFIED /~ 0_03014012 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE /`1 F AOGCC R 333 West 7th Avenue. Suite 100 ° Anchorage. AK 9951 M 907-793-1238 o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 AGENCY CONTACT ~ DATE OF PCN / 7 7 - I GG 1 ADVERTISEMENT REQUIRED: October 22, 2009 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 United states of America State of division. AFFIDAVIT OF PUBLICATION REMINDER SS INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. 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 2009, and thereafter for consecutive days, the last publication appearing on the day of .2009, 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 2009, Notary public for state of My commission expires _ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, October 20, 2009 2:30 PM To: Ballantine, Tab A (LAW); 'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Bowen Roberts'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Charles O'Donnell'; Chris Gay; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Gorney'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; Deborah Jones; Decker, Paul L (DNR); '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'; 'gspfofF; 'Hank Alford'; 'Harry Engel'; 'jah'; 'Janet D. Platt'; 'jejones'; 'Jerry Brady'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; Joseph Darrigo; 'Julie Houle'; 'Kari Moriarty ; 'Kaynell Zeman'; 'Keith Wiles ; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Elowe'; 'Laura Silliphant'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; Melanie Brown; 'Michael Nelson'; 'Mike Bill'; 'Mike Jacobs'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Winslow'; 'peter Contreras'; Rader, Matthew W (DNR); Raj Nanvaan; 'Randall Kanady'; 'Randy L. Skillern'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Province'; 'Rudy Brueggeman'; 'Sandra Pierce'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Susan Roberts'; 'tablerk'; 'Tamera Sheffield'; 'Ted Rockwell'; 'Temple Davidson'; Teresa Imm; 'Terrie Hubble'; 'Thor Cutler'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Von Hutchins'; 'Walter Featherly'; Williamson, Mary J (DNR); Aubert, Winton G (DOA); Brooks, Phoebe; Crisp, John H (DOA); Darlene Ramirez; 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); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: Public Notice -Orion Expansion Attachments: Public Notice Schrader Bluff-Orion dev.pdf Jody .l. Colombie Special ,'I ssistant :1laska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 .lncho~•age, AK 99.101 ('907)793-1221 (phone) (907)276-7542 (fax) 10/20/2009 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 a,iQ y, ~o~ lol ~~ ~ • by June 30, 2009 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, AK 99501 BP 6cploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 DELIVERED BY HAND RE: Amendments to Orion Pool Rules and Area Injection Order ,Dear Commissioners: Enclosed for your review and action is the Prudhoe Bay Unit Working Interest Owners' application for amendments to Conservation Order 505 and Area Injection Order 26, the Orion Pool Rules and the Area Injection Order for the Orion reservoir. These amendments are necessary because BP Exploration (Alaska), Inc. (BPXA), as Orion Operator and Unit Operator, has applied to the Department of Natural Resources to expand the Prudhoe Bay Unit. Accordingly, BPXA hereby petitions the Commission to amend the above referenced rules as necessary to accommodate this expansion. BPXA requests that Section #1 of Conservation Order 505 and Section #2 of Area Injection Order 26 be amended as follows to reflect the revised legal description describing the expanded area affected by these orders. Umiat Meridian Township Range, UM Lease Sections T12N-R11E ADL 390067 Sec.14: S/2S/2 Sec.23: All Sec.24: SW/4, SW/4NW/4 Information in support of these amendments is attached. Please maintain as confidential those certain attachments attached and labeled "CONFIDENTIAL" in accord with 20 AAC 25.537(b). • • Should you have any questions or require additional information, please do not hesitate to contact me at (907) 564-5749. Sincerely, ~~l r Diane Richmond Prudhoe Bay Western Region Resource Manager Attachments: Attachment 1 Location Map of the OPA/PBU Expansion Area Attachment 2 Lease Map of Expanded OPA/PBU Attachment 3 Amended Orion Participations and Tract Allocations Attachment 4 Amended Orion Plan of Development and Operations Attachment 5 Orion Typelog Well L-216 -Confidential Attachment 6 OBd Structure Map -Confidential Attachment 7a Dip Cross-Section -Confidential Attachment 7b Strike Cross-Section -Confidential Attachment 8a Orion Seismic Dip Cross-Section A-A'-Confidential Attachment 8b Orion Seismic Strike Cross-Section B-B'- Confidential Attachment 8c Seismic Line Index Map -Confidential Attachment 9a Net Oil Pore Foot Thickness (NB Interval) -Confidential Attachment 9b Net Oil Pore Foot Thickness (OA Interval) -Confidential Attachment 9c Net Oil Pore Foot Thickness (OBa Interval) -Confidential Attachment 9d Net Oil Pore Foot Thickness (OBb Interval) -Confidential Attachment 9e Net Oil Pore Foot Thickness (OBc Interval) -Confidential Attachment 9f Net Oil Pore Foot Thickness (OBd Interval) -Confidential Attachment 10 Composite Net Pay Thickness Map -Confidential Attachment 11 Reservoir Compartment Map -Confidential Attachment 12a Orion Oil-Water Contact Data (OA Sand) -Confidential Attachment 12b Orion Oil-Water Contact Data (Upper OBa) -Confidential Attachment 12c Orion Oil-Water Contact Data (Lower OBa Sand) -Confidential Attachment 12d Orion Oil-Water Contact Data (OBb Sand) -Confidential Attachment 12e Orion Oil-Water Contact Data (OBc Sand) -Confidential Attachment 12f Orion Oil-Water Contact Data (OBd Sand) -Confidential Attachment 12g Orion Oil-Water Contact Data (Nb Sand) -Confidential Attachment 13 Orion Tops and Rock Properties -Confidential Attachment 14 Orion Polygon lA Production History -Confidential Attachment 15 Index to Digital Data Attachment 16 Orion Well L-203 and Unit Expansion Acreage Context -Confidential Attachment 17 Notice of Intent to Enlarge OPA/PBU 2 cc: Mike Utsler, BPXA Sherri Gould, BPXA Claire Sullivan, BPXA John Cyr, BPXA Jeff Spatz, BPXA Gary Benson, BPXA Gabriela Boersner, ExxonMobil Craig Haymes, ExxonMobil Mark Pohler, ExxonMobil Joe Falcone, ConocoPhillips Erec Isaacson, ConocoPhillips Jon Goltz, ConocoPhillips Glenn Frederick, Chevron Dave Roby, AOGCC Cammy Taylor, DO&G Judy Buono, BPXA Don Ince, ConocoPhillips Dan Kruse, ConocoPhillips Mark Menghini, ConocoPhillips Hank Bensmiller, ExxonMobil Steve Krohn, ExxonMobil Greg Peters, ExxonMobil Cheryl Wiewiorowsky, BPXA Alan Mitchell, BPXA • ~a ~~ ~~ ~~ CD ~ ~~ o Oo 0 0. o ~ ~ ,~ ~ ~ ~ ~ a~ ~y 0 c~ >v ~~ C ~~ m ~ ~ O~ a.... `~° ~ ____ ~ ____-._-~_ -__r . ______ ,, ~. ( ~ ,v w ~ to to J_~' ' t 1 i f _. __ __ _ __ ~ - _.~. j.:4 I ~ - .. / ~- t~~ ~t z2 ~3 ~ s t~ zo 2t i g. ~. I t ~-- ,~, ,`, ~~ ~ za a-r ~t ~ zs as r- ~~ __ ~ ~~ a ~~ ~~~ i _ ~ ~ ~~ _-, I ~ `'~ ---- - _ ~ •~- - ---. --~ - --ti ~ i; - - -..___ - - --_ ! ~~'- _ _ - v • -- - ~ ~ --- ~ ~- _ ~^ 2t __ ~s ~'~ as 1 a~ ~ ~ ~. ,,' ~ ~~ __•~g ~ a~.__._. .. ~~ _.~_ zs _I ~_ BP EXPLORATION A ~ (I_ASKA) INC. .,,.,. CurrontPruahoo6ayUnrt Prudhoe Bay Unit I CurrnntOrianPartlcipaaingArca _ 7 _ a _ Proposed PBU Expansion Areas ~ CPA 8 PBU @xpansan 0 ~_..._ _ ... 2 ~ o t aMU.> DATE' SCALE: Figure June 2008 1:110.000 1 .p Attachment 2 -Lease Map of Expanded OPA/PBU j " ,.~ - ---- ~, ~. - _ - ~ ., - °,,; ~ zy s __~ ~ i ~3A 3S _ 32 33 ~ 34 35 .ii5 3 i 33 ~ ~ ~ ~ IT13N 1 Tt2w ~- • _ 1 - ___-. _.. - _. ~ _ .L ,u w _ _- 2 1 u- ~_~ a 2 - S 4 j _,.. _.__. __. ___._.. _. . ' 1 ~~ ' _..,, ~. ~"~" '~ t2 e,~ ' I 5111 - 1' I ~~ AD D256 37 ADLfcl47446 ADL047447 ADL39006 7 - - I -- -_ 28 :'. ~_; _~ ' - l PAD i _ ~ ADLO Ya49 ADLCt2B23~ ADLO.?8 238 _ I _ 1 ` ` V PAD ~ a 4 ~ ., ,, -_ •, "f ~ -- --_ Z 7At]~ ~ I '.b' PAD i , Y ~ ~ to ,~ --~ ADL 8245 - ~}1DLC28262 a AD~C2B263 i _..- --_ - ~_ ._.__. ~- 3~ 29 2i3 27 _ ~, .1. _. __ ~ i_.. _ __. 31 32 33 34 ADLG47a53 A~7LOf17452 1 ~ S 4 3 2 ', ~. - 10 11 12 7 . ~ ~ ~ I ~ ?a..QFY~: 8.4YUM 3Q..Mp~.9Y - - ulexm .'..l NUMBEP. ia.a r..~.w;,l r- -. i 3b1~t'.•i ~' Attachment 2 -Lease Map of Expanded OPA/PBU 5 Amendment to Orion Pool Rules and Area Injection Order • • Attachment 3 -Amended Orion Particiaations and Tract Allocations. Tract Lease T & R ection: Description Acres Royalty - - - - - - - -Tract Ownership %- - - - - - - - - - Tract Partici ation p BPXA CPAI xxonMob' Chevron % 13 39006 12N-11E Sec 14: S/2S/2 1,000 16.66667 26.360567% 36.076746% 36.402687% 1.160000% 0.117% Sec 23: All Sec 24: SW/4, SW/4NW/4 14 04744 12N-1 lE Sec 16: S/2,NW4, 1,840 12.5 26.360567% 36.076746% 36.402687% 1.160000% 7.234% S/2NE4 Sec 21: All Sec 22: All 15 04744 12N-11E Sec 17: All 2,448 12.5 26.360567% 36.076746% 36.402687% 1.160000% 22.438% Sec 18: All Sec 19: All Sec 20: All 16 02563 12N-10E Sec 13: All 960 12.5 26.360567% 36.076746% 36.402687% 1.160000% 10.012% Sec 24: N/2 17 04744 12N-11E Sec 29: N/2, SE/4 553.5 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.404% Sec 30: N/2NE/4 18 02823 12N-11E Sec 27: All 2,320 12.5 26.360567% 36.076746% 36.402687% 1.160000% 12.504% Sec 28: All Sec 33: E/2, N/2NW/4 Sec 34: All 19 028238 12N-11E Sec 25: SW/4 2,080. 12.5 26.360567% 36.076746% 36.402687% 1.160000% 10.991% Sec 26: All Sec 35: All Sec 36: All 49 47450 11N-12E Sec 7: All 1,076 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.798% Sec 8: NW/4, S/2 50 28240 11N-11E Sec 1: All 2,320 12.5 26.360567% 36.076746% 36.402687% 1.160000% 16.067% Sec 2: All Sec 11: E/2, E/2NW/4 Sec 12: All 51 28241 11N-11E Sec 3: N/2, N/2S/2 720 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.927% Sec 4: NE/4, N/2SE/4 53 28245 11N-11E Sec 13: N/2, SE/4 640 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.002% Sec 14: E/2NE/4 Sec 24: E/2NE/4 54 28262 11N-12E Sec 17: All 1,764.875 12.5 26.360567% 36.076746% 36.402687% 1.160000% 7.737% Sec 18: All Sec 19: N/2, SE/4, N/2SW/4 54A 28262 11N-12E Sec 20: All 640 12.5 26.360567% 36.076746% 36.402687% 1.160000% 4.388% 55 28263 11N-12E Sec 16: SW/4, 240 12.5 26.360567% 36.076746% 36.402687% 1.160000% 0.008% S/2NW/4 SSA 28263 11N-12E Sec 21: SW/4, 360 12.5 26.360567% 36.076746% 36.402687% 1.160000% 0.602% S/2NW4, NW/4NW/4, W/2SE/4 80 47452 11N-12E ec 28: W/2, W/2E/2 480 12.5 26.360567% 36.076746% 36.402687% 1.160000% 0.379% 81 47453 11N-12E Sec 29: N/2, N/2SE/4 400 12.5 26.360567% 36.076746% 36.402687% 1.160000% 1.392% Attachment 3 -Amended Orion Participations and Tract Allocations Amendment to Orion Pool Rules and Area Injection Order • Total = 19,842.375 acres BPXA = BP Exploration (Alaska), Inc. CPAI = ConocoPhillips Alaska, Inc. ExxonMobil = ExxonMobil Alaska Production Inc. Chevron =Chevron U.S.A. Inc. Attachment 3 -Amended Orion Participations and Tract Allocations 7 Amendment to Orion Pool Rules and Area Injection Order • • Attachment 4 -Amended Orion Plan of Development and Operations 2009 PLAN OF DEVELOPMENT (5TH) ORION PARTICIPATING AREA PRUDHOE BAY UNIT JANUARY 1, 2009 -DECEMBER 31, 2009 Attachment 4 -Amended Orion Plan of Development and Operations 8 Amendment to Orion Pool Rules and Area Injection Order • TABLE OF CONTENTS 1.0 INTRODUCTION 2.0 FIELD STATUS 3.0 SUMMARY OF ACTIVITIES 4.0 PLAN OF DEVELOPMENT 4.1 RESERVOIR MANAGEMENT 4.2 DEVELOPMENT DRILLING 4.3 PRODUCTION ALLOCATION 4.4 PROJECTS LIST OF ATTACHMENTS ATTACHMENT 1 : ORION WELL LOCATION MAP • ATTACHMENT 2: TABLE OF ORION WELLS, BY SPUD DATE ATTACHMENT 3: TABLE OF ORION / BOREALIS COMMINGLED INJECTION WELLS, BY SPUD DATE ATTACHMENT 4: CHART OF ORION PRODUCTION AND INJECTION HISTORY ATTACHMENT 5: ORION SCHRADER BLUFF TOP OBA DEPTH STRUCTURE MAP (CONFIDENTIAL ATTACHMENT 6: L-219 WELL PROFILE (CONFIDENTIAL ATTACHMENT 7: PRESSURE AND FLUID DATA FROM L-219 MDT (CONFIDENTIAL Attachment 4 -Amended Orion Plan of Development and Operations 9 Amendment to Orion Pool Rules and Area Injection Order • 1.0 INTRODUCTION • As provided for in the Findings and Decision for formation of the Orion Participating Area, BP Exploration Alaska, Inc. (BPXA) as operator of the. Prudhoe Bay Unit is providing this annual update to the Orion Plan of Development. This document provides an overview of the projects and operations that comprise the development program for the Orion Participating Area (OPA). The OPA development plan is consistent with the current business climate and understanding of the Orion reservoir. Changes in business conditions, new insights into the reservoir or other new information could alter the timing, scope, or feasibility of one or more of the plan components. 2.0 FIELD STATUS Development of the Orion Reservoir has entailed phased drilling of 36 producers and injectors from L-, V- and Z-Pads. Initial drilling commenced in December, 2001 with production startup in April, 2002. Orion production is commingled with. IPA and Borealis production and flows to GC-2 for processing. Water injection started in December 2003. The pattern waterflood is designed to increase recovery and provide pressure support in the Orion reservoir. Tertiary recovery, utilizing miscible gas for WAG (Water-Alternating-Gas injection) was initiated in October 2006. Central and southern areas of Orion will be developed using existing and expanded infrastructure at L-Pad, V-Pad, W-Pad, and Z-Pad. Northern Orion may be developed in the future from a proposed I-Pad. Additional surface facilities and pipelines maybe added to support future Orion production, injection and artificial lift requirements. Listed below is additional information regarding the Orion field as of May, 2008: • 17 wells drilled at L-Pad - 5 oil producers: 4 on-line - 12 water injectors: 9 on-line - (1 commingled Orion/Borealis water injector utilized) • 18 wells drilled at V-Pad - 4 oil producers: all on-line - 14 water injectors: 11 on-line. • 1 well drilled at Z-Pad - 1 water injector: SI until offset producer is drilled The average rates since the previous report are: • Oil Production Rate: 10,100 BOPD Attachment 4 -Amended Orion Plan of Development and Operations 10 Amendment to Orion Pool Rules and Area Injection Order • • • Gas Oil Ratio 1404 SCF/BO • Water Production Rate 1500 BWPD • Water Injection Rate: 6300 BWPD • Gas Injection Rate: 5.4 MMSCFD As of Apri130, 2008 the cumulative totals are: • Cumulative Oil Production: 12.7 MMSTBO • Cumulative Gas Production: 13.1 BSCF • Cumulative Water Production: 1.1 MMSTB • Cumulative Water Injection: 10.2 MMSTB • Cumulative Gas Injection 2.6 BCF 3.0 SUMMARY OF ACTIVITIES Summarized below are significant activities at Orion since the previous report (July 31, 2007 through April 30, 2008): • Spudded the L-205 hexa-lateral with coring operations underway at report time. • Drilled 4 vertical injection wells; V-220, V-223, L-221, L-220, to provide pressure support to existing and future Orion production wells. • Drilled the first high angle injection well, L-219. The tail of this well was drilled across the OWC in the OBd sand to enable data collection across the OWC. • Approval for an enhanced oil recovery project using Prudhoe Bay miscible injectant in Orion was granted by the Alaska Oil and Gas Conservation Commission on April 28, 2006 in Conservation Order SOSA. The first water-alternating-gas injection flood began in October, 2006. Currently, MI is being injected into 6 Orion wells, V-210, V-211, V- 212, V-214, V-215 and. V-218. • MI injection profiles have been run L-213, V-210, V-211, V-214 and V-216. This data will be used to calibrate models of the MI flood and adjust future injection strategy. Attachment 4 -Amended Orion Plan of Development and Operations 11 Amendment to Orion Pool Rules and Area Injection Order • • • Multi-zone injector V-2231 became the initial completion of an Orion well in the OBe sand. This injection interval will be sampled for future geochemical allocation of offset production. It will then be then be left SI until offset production is established in V-207. • Afield trial of multi-phase metering technology was performed on V-pad in 1 Q 2008. Data from this trial is used to complete select phase engineering analysis for improvements in well testing on L and V pads. • Production heater installed at Z-pad with start-up in June, 2008. • GC2 D-bank modifications began in May 2008 for improved separation. • Two matrix bypass events (MBE) were identified during this reporting period: o An MBE was identified in V-222 in the OA sand on February 26, 2008 using the sandface gauge. Continued monitoring indicated that V-222 was in direct communication with V-202. Initial OA pressure in V-222 was 1285 psi. This may have indicated proximity to the original V-201 MBE or to another wormhole. o An MBE between V-216 and V-204 was suspected due to rapid MI breakthrough and confirmed with an interference test on March 22, 2008. Location of the MBE is in the OBa sand. Timing of the actual MBE is uncertain, but should be subsequent to installation of waterflood regulators in September of 2006. • Average producer uptime during the reporting period was 71 %. L-200 has been problematic, and is currently SI until the GC2 D-bank cleanout is complete. On-time for the other producers ranged from 74% to 87%. 4.0 PLAN OF DEVELOPMENT 4.1 RESERVOIR MANAGEMENT Orion is being developed with primary depletion and enhanced recovery. A MI flood is underway in Polygon 2. Water injection began in December 2003. Water rate is down since the last report reflecting injector swaps to MI. Individual well injection rates range from 300 to 1200 bwpd, or 1 to 3 MMSCFPD MI. MI injection commenced in October 2006 in the updip portion of Polygon 2. During the reporting period, several downdip injectors have been swapped to MI to test MI response in the lower quality oil near the OWC. The Orion Field is being developed with the emerging technology of multilateral production wells, typically supported by two to three vertical injectors per producer. Attachment 4 -Amended Orion Plan of Development and Operations 12 Amendment to Orion Pool Rules and Area Injection Order • • Some producers are choked back initially to manage reservoir pressure during early high- rate flush production. Currently, the Orion reservoir is being produced from six Schrader Bluff sands (Nb, OA, OBa, OBb, OBc, & OBd). A lateral in V-207 is planned to establish offtake from a seventh zone, the OBe. Because of the variability in sand and oil quality between zones, reservoir surveillance work has been undertaken to develop a better understanding of the reservoir performance by zone and design a development program to maximize recovery. For producers, production allocation efforts focus on using geochemical fingerprinting analysis on produced oil. This technique is in use world-wide and has proven useful in the Schrader Bluff fields, KRU West Sak and Milne Point. The complex nature of multilateral designs makes conventional production logging for zonal contribution difficult, so this fingerprinting technique is very useful. For injectors, efforts include injection logging and zonal control using flow regulators. Work is ongoing to balance waterflood pattern voidage and provide pressure support. Field pressure measurements are collected per AOGCC CO 585.5 and submitted with the annual surveillance report. 4.2 DEVELOPMENT DRILLING Five development wells (one high angle injector and 4 vertical injectors) were drilled during the reporting period and are listed in Attachment 2. An updated Orion structure map incorporating recent drilling is included in confidential Attachment 5. Downhole MDT fluid sampling was performed on L-219. A well profile depicting the MDT sample points is shown in confidential Attachment 6 and the MDT pressure and APT gravity data results are shown in confidential Attachment 7. N and O sand coring is in progress on multilateral producer L-205. Up to seven additional development wells (2 producers and 5 injectors) from L-Pad and V-Pad are being evaluated and maybe drilled through 2009. Drilling of additional high angle injectors V-224, and V-227 will depend on successful coiled tubing deployment of waterflood regulators in L-219. Approximate coordinates for the 2008-2009 drilling program under evaluation are listed below, and shown in Attachment 1. Also included are wells listed in the previous 2008 POD. Wellname X Y Z(tvdss)ft Comments Drilling Date L-2191 589,370 5,982,360 -4475 Top OBa Spud 12/2007 V-220i 593,390 5,974,715 -4480 Spud 2/2008 V-2231 593,960 5,968,915 -4430 Spud 3/2008 Attachment 4 -Amended Orion Plan of Development and Operations 13 Amendment to Orion Pool Rules and Area Injection Order ~ • L-2211 583,485 5,975,650 -4200 Spud 3/2008 L-2201 582,870 5,977,435 -4200 Spud 4/2008 L-205 580,925 5,978,010 -4130 Heel Target (OA leg) Spud 5/2008 581,950 5,973,640 -4170 Toe Target (OA leg) V-207 595,120 5,973,080 -4610 Heel Target (OBa leg) July 2008 594,450 5,975,940 -4625 Toe Target (OBa leg) V-2191 597,584 5,969,888 -4825 Top OBd V-2241 596,274 5,974,494 -4933 TD L-203 588,610 5,984,235 -4650 Heel Target (OBd leg) 584,373 5,987,016 -4588 Toe Target (OBd leg) V-227i 595,813 5,976,447 -4875 TD V-225i 590,374 5,969,155 -4771 TD 4.3 PRODUCTION ALLOCATION Orion production allocation is being performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust the total Orion production. At least one well test per month is used to check the performance curves and to verify system performance. No NGLs are allocated to Orion. 4.4 PROJECTS Schrader Bluff viscous oil production has affected GC-2 operation by a decrease in the inlet separation temperature, an increase in composite oil viscosity, an increase in the amount of solids entering the plant, and the introduction of overly stable emulsion layers formed by the mixture of formation fluids, solids, and oil-based drilling mud. Changes to GC-2 operations to deal with these challenges have been made in three areas: heat, chemicals, and hygiene. Added heat reduces viscosities, improves oil /water separation, and reduces required in- vessel residence times. Heat is added in the form of hotter, light-oil-related oil and water production with additional process heat. Plant testing has resulted in a new regimen of chemicals to break emulsions. Improving plant hygiene involves keeping vessels free of solids to maximize in-vessel residence times which allow fluids to separate properly. To help accomplish this, upgrades to the B-Train slug catcher and oil dehydrator were completed during the September, 2005 GC-2 shutdown. Upgrades to the D-Train slug catcher and oil dehydrator are in progress. Emulsion handling upgrades are also in progress. Attachment 4 -Amended Orion Plan of Development and Operations 14 Amendment to Orion Pool Rules and Area Injection Order • C A production heater has been installed on Z-Pad, which will handle the oil from L- and V- Pads and raise the temperature of the colder viscous oil to improve separation performance. The heater was put in service on 6/4/2008. Minor gravel pad expansion maybe needed to support the drilling program discussed in Section 4.2. Define Engineering has been completed for the potential installation of a gas partial processing plant (GPP) at Z-Pad. Gravel installation for GPP has been completed at Z- Pad. The GPP would increase oil production by expansion of existing gas handling capacity and of pipeline infrastructure in the western region. The long-lead materials order for the GPP turbine compressor unit was placed in July 2007. The GPP sea-lift is currently estimated for 2011, with a startup in 2012. I-Pad Define Engineering has been completed based on a new surface location. This resolves the geotechnical concerns raised by the discovery of the ice lens last year. Development of I-pad is currently under evaluation. Attachment 4 -Amended Orion Plan of Development and Operations 15 Amendment to Orion Pool Rules and Area Injection Order • ATTACHMENT 1- ORION WELL LOCATION MAP Orion Production Well Jr u203 Completed Pre-8/1AD7 /' Orion Production Well Completed between y/'~ ~=~i75 811 N7 and 511 N8 Orion Production WeII Planned for Completion f 4207 between 511108 and 12(31108 Orion Injection Well - ~ 3 Completed Pr e•8/1107 Orion Injection Well Completed between 8l1N7 and 5/1A08 Orion Injection WeII Plannedtor 511l08to ~ 12131i0S Orion Participating Area Boundary Prudhoe Bay Unit Boundary Well Base Map MI~~~! Illh ® 1~ nN~ n~lH • Orion Poolllnjection Area Attachment 4 -Amended Orion Plan of Development and Operations 16 Amendment to Orion Pool Rules and Area Injection Order • • ATTACHMENT 2 - ORION PARTICIPATING AREA WELLS. BY SPUD DATE Orion Participatin g Area Wells, by Spud Date Well Name API No. Spud Date Well Type V-201 500292305400 12/25/2001 Suspended V-202 500292315300 5/4/2003 Horizontal Oil Producer V-202L1 500292315360 11/26/2003 Horizontal Oil Producer V-202L2 500292315361 12/3/2003 Horizontal Oil Producer L-210 500292318700 12/31/2003 Vertical Water Injector L-200 500292319100 1/18/2004 Horizontal Oil Producer L-200L1 500292319160 2/6/2004 Horizontal Oil Producer L-200L2 500292319161 2/ 14/2004 Horizontal Oil Producer L-211 500292319700 2/24/2004 Vertical Water Injector L-201 500292320200 3/17/2004 Horizontal Oil Producer L-201L1 500292320260 4/6/2004 Horizontal Oil Producer L-201L2 500292320261 4/14/2004 Horizontal Oil Producer L-201L3 500292320262 4/23/2004 Horizontal Oil Producer L-216 500292320600 5/2/2004 Vertical Water Injector V-213 500292321300 7/12/2004 Vertical Water Injector V-204 500292321700 7/29/2004 Horizontal Oil Producer V-204L1 500292321760 8/13/2004 Horizontal Oil Producer V-204L2 500292321761 8/19/2004 Horizontal Oil Producer V-204L3 500292321762 8/27/2004 Horizontal Oil Producer V-216 500292321600 9/2/2004 Vertical Water Injector Z-210 500292322600 10/10/2004 Vertical Water Injector V-210 500292323100 10/31/2004 Vertical Wag Injector V-211 500292323200 11/12/2004 Vertical Wag Injector V-221 500292324600 2/22/2005 Vertical Water Injector L-212 500292325200 3/23/2005 Vertical Water Injector L-202 500292322900 6/5/2005 Horizontal Oil Producer L-202L1 500292322960 6/20/2005 Horizontal Oil Producer L-202L2 500292322961 6/27/2005 Horizontal Oil Producer L-202L3 500292322962 7/3/2005 Horizontal Oil Producer L-218 500292327200 8/24/05 Vertical Water Injector L-215 50029232744 09/08/05 Vertical Water Injector L-250 500292328100 10/24/05 Horizontal Oil Producer L-250L1 500292328160 11/12/05 Horizontal Oil Producer L-250L2 500292628161 11/21/05 Horizontal Oil Producer V-214 500292327500 10/29/05 Vertical Wag Injector V-212 500292327900 12/02/05 Vertical Wag Injector V-203 500292328500 01/08/06 Horizontal Oil Producer V-203L1 500292328560 01/08/06 Horizontal Oil Producer V-203L2 500292328561 01/08/06 Horizontal Oil Producer V-203L3 500292328562 01/08/06 Horizontal Oil Producer V-203L4 500292328563 01/08/06 Horizontal Oil Producer L-214A 500292325801 03/13/06 Vertical Water Injector Attachment 4 -Amended Orion Plan of Development and Operations 17 Amendment to Orion Pool Rules and Area Injection Order • I-100PB1 500292324570 03/20/06 Appraisal plug-back L-213 500292330800 04/19/06 Vertical Wag Injector L-217 500292331200 07/03/06 Vertical Water Injector L-204 500292331400 07/16/06 Horizontal Oil Producer L-204L1 500292331460 8/3/06 Horizontal Oil Producer L-204L2 500292331461 8/9/06 Horizontal Oil Producer L-204L3 500292331462 8/16/06 Horizontal Oil Producer L-204L4 500292331463 8/25/06 Horizontal Oil Producer V-217 500292333400 1/8/07 Vertical Water Injector V-205 500292333800 1/19/07 Horizontal Oil Producer V-205L1 500292333860 2/1/07 Horizontal Oil Producer V-205L2 500292333861 2/10/07 Horizontal Oil Producer V-218 500292335000 4/1/07 Vertical Wag Injector V-215 500292335100 4/16/07 Vertical Wag Injector V-222 500292335700 6/4/07 Vertical Water Injector L-219 500292337600 12/12/07 Vertical Water Injector V-220 500292338300 2/24/08 Vertical Water Injector V-223 500292338400 2/24/08 Vertical Water Injector L-221 500292338500 3/28/08 Vertical Water Injector L-220 500292338700 4/10/08 Vertical Water Injector L-205 500292338800 4/15/08 Drilling Attachment 4 -Amended Orion Plan of Development and Operations 18 Amendment to Orion Pool Rules and Area Injection Order • • ATTACHMENT 3 - ORION/BOREALIS COMMINGLED INJECTION WELLS, BY SPUD DATE Orion Participating Area Commingled Orion /Borealis Injection Wells, by Spud Date Well Name API No. Spud Date Well Type L-117 500292303900 9/13/2001 Vertical Water Injector L-103 500292310100 7/26/2002 Vertical Water Injector V-105 500292309700 8/27/2002 Vertical Water Injector Attachment 4 -Amended Orion Plan of Development and Operations 19 Amendment to Orion Pool Rules and Area Injection Order • • ATTACHMENT 4 - ORION PRODUCTION AND INJECTION HISTORY 16000 O ~ 14000 V ~ 12000 m .• ~ , 10000 - m ~ ~ ' y 8000 m y m ~ 6000 .• a O 4000 o~ 2000 3 0 o`~ oti o`~ o`~ o`~ o`~ o`~ o°` o°` o°` o°` o`' o`' o`' oh o`O o`O o`O o`O o~ o~ o~ o~ o~ 00 PQ~ ~~~ OG~ lac PQ~ ~J~ O~~ lac PQ~ ~J~ O~~ lac PQ~ ~J~ OG~ lac PQ~ ~J~ OG~ lac PQ~ ~J~ OG~ ,ac PQ~ 100% 90 80 70 60 50% 3 40 30 20 10% 0% Attachment 4 -Amended Orion Plan of Development and Operations 20 Amendment to Orion Pool Rules and Area Injection Order • • Attachment 15 -Index to Digital Data 1 zmap grid for Nb Structure 2 zmap grid for OBc Structure 3 zmap grid for OBd Structure 4 fault centerline file Attachment 15 -Index to Digital Data 50 Amendment to Orion Pool Rules and Area Injection Order Attachment 17- Notice of Intent by • BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, Alaska 99508 VIA CERTIFIED MAIL- RETURN RECEIPT REQUESTED June 18, 2008 Kevin Banks Division of Oil and Gas Department of Natural Resources 550 West 7`~ Avenue, Suite 800 Anchorage, AK 99501 RE: Notice of Intent to Enlarge the Prudhoe Bay Unit to Encompass Expansion to the Orion Participating Area Dear Mr. Banks: Pursuant to Section 9.1 of the Prudhoe Bay Unit Agreement and Section 1.003 of the Prudhoe Bay Unit Operating Agreement, BP Exploration (Alaska), Inc., acting in its capacity as Operator of the Prudhoe Bay Unit, hereby gives notice of the proposed enlargement of the Prudhoe Bay Unit Area to encompass proposed expansion to the Orion Participating Area. The proposed effective date for the enlargements is the first day of the calendar month following the date of the final approval of the enlargements by the Alaska Department of Natural Resources. The leases or portion of leases contemplated for inclusion in the Prudhoe Bay Unit Area ("Enlargement Areas") are listed on Exhibit A and depicted on Exhibit B, both of which are attached hereto and incorporated herein. As provided by Section 9.1 of the Prudhoe Bay Unit Agreement, the tracts included in the Enlargement Areas have been reasonably determined to be within the Orion Reservoir, a portion of which is within the Prudhoe Bay Unit Area. The inclusion of the Enlargement Areas in the Prudhoe Bay Unit Area will enable the timely development of the Orion Reservoir by facilitating the sharing of existing Prudhoe Bay Unit facilities. The expansion of the Prudhoe Bay Unit Area to include the Enlargement Areas will promote conservation of natural resources, promote the prevention of economic and physical waste, and will protect all parties, including the State of Alaska. The expansion also provides for the protection of Attachment 17 -Notice of Intent 64 Amendment to Orion Pool Rules and Area Injection Order • • the environment through planned development that optimizes the use of existing facilities and prevents unnecessary duplication of facilities. Pursuant to Section 9.1(b) of the Prudhoe Bay Unit Agreement, any interested party may file with the Unit Operator written objections, and reasons therefore, to the proposed enlargements within thirty (30) days of the date this Notice was mailed. If you have any comments or questions, please contact Sherri Gould at (907) 564-5492. Sincerely, Mike Utsler Greater Prudhoe Bay Business Unit Leader Attachments: Exhibit A- PBU Enlargement Area to Encompass the Orion Participating Area Expansion Exhibit B- Map of Proposed PBU Enlargement Area CC: Sherri Gould, BPXA Claire Sullivan, BPXA John Cyr, BPXA Lewis Westwick, BPXA Gary Benson, BPXA Gwendolyn Dawson, ExxonMobil Craig Hayrnes, ExxonMobil via certified mail Mark Pohler, ExxonMobil Joe Falcone, ConocoPhillips Erec Isaacson, ConocoPhillips via certified mail Jon Goltz, ConocoPhillips Glenn Frederick, Chevron via certified mail Jane Williamson, AOGCC Cammy Taylor, DO&G Judy Buono, BPXA Don Ince, ConocoPhillips Mark Menghini, ConocoPhillips Hank Bensmiller, ExxonMobil Scott Cooley, ExxonMobil Sonny Rix, ExxonMobil Dan Kruse, ConocoPhillips Frank Paskvan, BPXA Michael Wortham, BPXA Attachment 17 -Notice of Intent 65 Amendment to Orion Pool Rules and Area Injection Order • • EXHIBIT A PBU ENLARGEMENT AREA TO ENCOMPASS THE ORION PARTICIPATING AREA EXPANSION I. Tract 13 Orion Participating Area/PBU Expansion -1000 Acres Descri to ion T12N-R11E Section 23 (all) Section 14: S/2S/2 Acreage ADL 1000 390067 Rovaltv WIO%' 16.66667% EM 36.402687% CPAI 36.076746% BPXA 26.360567% Chevron 1.160000% Section 24: SW/4, SW/4NW/4 Legend EM - ExxonMobil Production Alaska, Inc. CPAI - ConocoPhillips Alaska, Inc. BPXA - BP Exploration (Alaska), Inc. Chevron- Chevron U.S.A. Inc. ~ BPXA, CPAI, EM, and Chevron now own the above referenced Orion PA/PBU expansion acreage in ADL 390067 in aligned PBU ownership decimals indicated above. Attachment 17 -Notice of Intent 66 Amendment to Orion Pool Rules and Area Injection Order ~a ~~ ~~ ~. ~ N ~ '+ ~ ~-' O J ~ ~ O p ~ ^. b ~ O O ~-• '-h (D N ~ r-. Cy ~5 n O O (~ J ~'~ X92;0? 9 i9(11k1' t _57133 : *~~1' ., .., .'.9~.^.SUA ~ __ --- - -- - _. _. ~ U'~II ~XI'r~N ,lis., 3a ~riS ' C-_ I ~ ~ i ,6~7 w. - 2825G-2 ~ ~ ~I 1 ~ - - • I ~~ ::1tl2 ~5 ~ U4744b-2 'G474+a4-y S9i)477 3. • c ~ sr. i t~ i `,l , J2, ,-, ~ t'iJ Ac. L'47<46r ; 244H Ac.U47447 1664 Ac. .5~U067 39'209 ~, U?tSLGb .. 125 A::.O~d2.:, '92G Ac 047448 .,.}3K:) nC "474c9 ~- - ------- liil} Ac. E 04744 r .. ~J . ~ _ -_? -- - .. Z ~~z~ , ~ 9 ' --. x'443-2 968 Ac. ().>r. .59 F 160 A[ , G2B2.,8 254p ,tr..::lH?S9 i - 2459 Ar, 02d25d -- ^09279 A~,U7827o I'i60 kc 028257 '76rJ xc. ~t --- 25G0 .. C• I `I ` I I ~ ~ .N L- ~ , ~ r , ~ ~ -rte _ - - - I ~ - y i ~ ~ '`.•- _ _ ,:'l~1+FL , ~ 229241 2507 Ac . OZS ~ 40 ~ ~ "~ - 7T~p~ ?' c 0 7 2469 Ae. ~~ ~ "'-Y~' . ~ 1..100 .2460 A~:. " ,-_ 2~~C.". :..: ~ _~r r.4 .4~. ~ ~ 25b0 Ac :. _ _ ~` ~ ~` ~ - ~ 229244 ,gyp Ac I i G2?245 i ~ ~~ I Oy'~5~e' h 1 123; A;, i~ r,i. ~..,. ~ 429252 ' - ~ ~~ 028213 ~ G2e244- 2 cd245-c _ „ 192 ax:• '9aG AW. 28262 1 64:1 nr. U982fi~- c j (1"R"fi 2 t~SU Ac. 0474..1 '?a6U A:. 028?83 480 ac: ~ ~-4 2560 A_. r' i i f ; _L _ , :, 2.~ / 1 ~ °2$24° ____#3 540 ~c - } ~ BP EXPLORATION (ALASKA) INC. l'. 1 2 •rl~c:: ~ 1 I I -. ~ ' Exhibit B ~ U-M ETY _I~f tlJ_q_oF, i+2824G-2, t1a?a55 -- Ac, 249 q <~ • )1 z,6U A. ( ....... .~r.,.:_~ ~°~~:~.~~....r.,... ~ Prudhoe Bay Unit - °'°"` "~~`~~;~„ ~ 047454 Proposed PBU Expansion Areas -rCe o-a. _~~ -+~ DATE: SCALE: Exrlc~c ^?^49 , H 474x4-~ 15''' - is wT.nzoos I:I~o,oc~a a R~Xr. C:ir:ra~.q:hr:l,'•~€4f,6s~~ 7 ~ y ~x 7 ~ N a • • • • Pages 21 through 49 Pages 51 through 63 of applicants application are held confidential