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Home My WebLink AboutAIO 018 A . . INDEX AREA INJECTION ORDER lSA COLVILLE RIVER FIELD 1. February 3, 2000 2. February 4, 2000 3. February 9, 2000 4. August 16, 2000 5. July 8, 2002 6. July 29, 2002 7. May 12, 2002 8. May 5, 2004 9. July 7, 2004 10. July 26,2004 ARCO Application for Amendment to AIO 18 Core Samples Notice of hearing, Affidavit E-mail from AOGCC Re: Stormwater Silt Disposal Approval List of suspended solids Decision Document Request for Administrative Approval for Injection of Treated Camp Effluent and Approved Non-Hazardous Fluids in to Alpine Sea Water Flood Wells Letter to Mr. Alonzo from Jim Regg Re: Requirements E-mail from operation to Regg CDI-I9A Class Disposal Well Fracture Growth Estimate 11. September 27,2004 Public Notice to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells AIO 18A · t STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The APPLICATION OF ARCO ALASKA Inc. ("ARCO") for an amendment of Area Injection Order No. 18 to allow disposal into certain disposal intervals on an area basis in the Colville River Field. ) Area Injection Order No.18A ) Colville River Field ) Colville River Unit ) Alpine Oil Pool ) ) April 18, 2000 IT APPEARING THAT: 1. By application dated February 3, 2000, ARCO Alaska, Inc. ("ARCO") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to amend Area Injection Order No. 18 to allow disposal of fluids into the disposal intervals specified in Disposal Injection Order No. 18 on an area basis. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on February 9,2000. 3. The Commission did not receive a protest or a request for a public hearing. FINDINGS: 1. Commission regulation 20 MC 25.460 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. 2. The Commission has issued Disposal Injection Order No. 18 on April 19, 1999 and Area Injection Order No. 18 on January 24,2000. The findings, conclusions and administrative records are adopted by reference and incorporated into this order. 3. The Alpine Oil Pool ("AOP") is located in the Colville River Delta area on Alaska's North Slope. 4. ARCO is the only operator of all wells within one-quarter mile of the area proposed for dispsoal. The State of Alaska and Kuukpik Corporation are the surface owners. 5. ARCO anticipates drilling up to five disposal wells into the disposal interval approved for Class II disposal operations in DIO No. 18. 6. The Commission issued Disposal Injection Order No. 18 for well WD-02. The well is currently operating as a Class I well under EPA UIC Area Permit AK-1I003-A. Mea ¡nj,,"on 0_ No. t 8A . April 18, 2000 Page 2 , 7. EPA UIC Area Permit AK-1I003-A Part ILA.3 prohibits the drilling of offsetting wells into or below the arresting zone (lower Kingak) within the 'l4 mile radius area of review unless directed by EP A. 8. Salinity calculations range from 15,000 to 18,000 milligrams per liter ("mg/L") total dissolved solids ("TDS") throughout the Cretaceous and older stratigraphic sections in the Colville Delta Area. 9. Disposal well design requirements include 16-inch conductor casing set at 75'and cemented; surface holes drilled to a minimum of2200' TVDSS and either 95/8" or 7 5/8" casing set and cemented to surface; and production casing set near the base ofthe injection zone and cemented across and not less than 500' measured depth above the Alpine formation. Single tubing strings between 2 7/8" and 4 W' OD will be installed in each well. The tubing by casing annulus will be isolated within 200' of the top of the uppermost injection interval. 10. The only wellbores penetrating the disposal interval will be those wellbores intended for disposal purposes. Since these wellbores will be fully cemented across both the injection and confining intervals, there are no past, present or planned penetrations of this interval that could provide communication channels to shallower intervals. 11. ARCO estimates that oil field waste fluids could total 4 million barrels over the life of the field. ARCO also anticipates disposal of as much as 14 million barrels of produced water before the initiation ofwaterflood operations re-injecting the produced water. 12. ARCO seeks to dispose of oil field waste fluids that may include drill cuttings and fluids, completion, workover and stimulation fluids, frac sand, produced water, crude oil, production vessel sludge/sand, natural gas liquids, rig wash and well cellar fluids, diesel/methanol used as freeze protectant, plant upset fluids, snowmelt, and any fresh or seawater necessary to enable disposal. 13. Daily injection volumes are not expected to exceed 2,500 barrels, and disposal rates are not expected to exceed 5 barrels per minute. A maximum injection pressure of 3200 psi is estimated. 14. ARCO plans to run a cement quality log to verify the cement quality and top of cement behind the production casing in any well prior to use as a disposal well. 15. ARCO will demonstrate the mechanical integrity ofi11iection wells as specified in 20 AAC 25.412 prior to initiating injection operations. 16. The operator will comply with the requirements of20 AAC 25.402 (d) & (e) to monitor tubing-casing annulus pressures of injection wells periodically during injection operations to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 17. All existing wells drilled within the proposed project area have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the proposed project area have been abandoned in accordance with 20 AAC 25.105 and 20 AAC 25.112 or an equivalent precursor regulation. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An Area Injection Order is appropriate for the project area in accordance with 20 AAC 25.460. Area Injection Order No. ¡SA . April 18, 2000 Page 3 t 3. No underground sources of drinking water ("USDW's") exist beneath the permafrost in the Colville River Unit area. 4. No wells may be drilled into or below the arresting zone (lower Kingak) for the wells covered in the \.4 mile radius area of review under EPA permit AK-1I003-A. 5. The proposed injection operations will be conducted in permeable strata, which reasonably can be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 6. Disposal will be limited to produced water and oil field wastes that the Commission determines are suitable for disposal in a Class II well. 7. Well mechanical integrity will be demonstrated in accordance with 20 AAC 25.412 prior to initiation of injection operations. 8. The mechanical integrity of each injection well will be tested at least every four years after an initial test. Wells used for grind and inject purposes must be tested every two years. 9. Tubing-casing annulus pressure and injection rates will be monitored at least weekly for disclosure of possible abnormalities in operational conditions. 10. An amendment to Area Injection Order 18 to enable additional disposal wells will not cause waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED that: (1) Area Injection Order #18A supercedes Disposal Injection Order #18 dated April 19, 1999 and Area Injection Order #18 dated January 24,2000; and (2) the following rules govern Class II injection and disposal operations in the affected area described below: UMIAT MERIDIAN T11N R4E Section 1,2,3,4,5, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16,21,22,23,24,25,26,27. T11N R5E Sections 1,2,3,4,5,6,7,8,9,10,11,12,13,14,15,16,17,18,19,20, 21, 22, 23, 24, 29, and 30. T12N R4E Sections 24, 25, 26, 27, 33, 34, 35 and 36. Tl2N R5E Sections 13, 14, 15, 19,20,21,22,23,24,25,26,27,28,29,30,31,32,33,34,35 and 36. Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6876 and 6976 feet in the Bergschrund No.1 well. Area Injection Order No. 18A . April 18, 2000 Page 4 , Rule 2 Authorized Iniection Strata for Disposal Within the affected area, Class II fluids may be injected for purposes of disposal into strata that are common to and correlate with the interval between the measured depths of 8432 and 9540 feet in the Sohio Alaska Petroleum Company Nechelik No.1 well. Rule 3 Fluid Iniection Wells The underground injection of fluids must be through a well 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. Rule 4 Monitorine: the Tubine:-Casine: Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 5 Reportine: the Tubine:-Casine: Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 7 below. Rule 6 Demonstration of Tubine:-Casine: Annulus Mechanical Intee:ritv A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection and at least once every four years thereafter. For slurry injection wells, the tubing/casing annulus must be tested every two years for mechanical integrity. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, will be used. The test pressure must show a stabilizing trend and must not decline more than 10% in a thirty-minute period. The Commission must be notified at least twenty- four (24) hours in advance to enable a representative to witness pressure tests. Rule 7 Well Intee:ritv Failure Whenever operating pressure observations, injection rates, or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and obtain Commission approval to continue injection. Rule 8 Plue:e:ine: and Abandonment ofIniection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Area Injection Order No. 18A . April 18, 2000 Page 5 Rule 9 Surveillance , For slurry injection wells, a baseline temperature survey from surface to total depth, initial step rate test to pressure equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the Commission. Operating parameters including disposal rate, pressure, annuli pressures and volume of slurry pumped must be monitored and reported according to the requirements of20 AAC 25.432. For slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before April 1, in conjunction with the Alpine Pool Annual Reservoir Report. Rule 10 Notification The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 11 Administrative Action Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into a USDW. DONE at Anchorage, Alaska and dated April 18, 2000. obert N. Christenson, P .E., Chair Alaska Oil and Gas Conservation Commission ~~~ Camillé Oechsli Taylor, CommisslOne Alaska Oil and Gas Co e t' Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days ITom the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs ITom the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). " . ~~~~Œ lID~ ~~~~æ~ . A"~ASIiA. ORAND GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AlO 18A.Ol Re: The application from Phillips Alaska, Inc. to mix treated wastewater effluent with Class II EOR injection fluids as needed when the primary disposal well is unavailable in the Colville River Field, Alpine Oil Pool, North Slope, Alaska. Thomas Manson Michael Nelson Alpine Development Project P.O. Box 196860 Anchorage, AK 99519-6860 Gentlemen: By letter dated May 12, 2002, Phillips Alaska, Inc. ("PAl") requested authorization to blend treated wastewater effluent with seawater for injection into Class II enhanced oil recovery (EOR) wells in the Alpine Oil Pool when the primary disposal well (WD-02) is unavailable. The Commission may authorize the injection of fluids for enhanced recovery of oil and gas if the fluid is appropriate for enhanced recovery. The Commission has reviewed the analyses of the treated waste effluent provided in your application. Based on the effluent analysis and that of the seawater being used in the EOR process, the Commission concludes that the characteristics of the treated effluent are consistent with other aqueous fluids used for EOR injection. The estimated mix of 1 % effluent with seawater injectant will not impact properties of the seawater as it relates to EOR efficiency. Therefore, in accordance with the provisions of Area Injection Order l8A, the Commission approves the mixing of camp waste effluent with Class II fluids used for EOR. As a condition of this approval PAl must continue to collect and analyze representative samples of the mixed fluid stream to demonstrate its continued suitability for EOR injection. Analysis results shall be retained according to the provisions of 20 AAC 25.310. Volumes shall be incorporated into the monthly (Form 10-406) and annual (Form 10-413) injection reports. DONE at Anchomge, Ala,ka and dated Augost 1, 20...~~.,~... ~ ~ MdvJ-~9.I i~/ Cammy oe~sli Taylor Ò Dan e T. Seamount, Jr. Chair Commissioner BY ORDER OF THE COMMISSION #11 ~ ;~) ~ r J', 'i ,..:J .r= l <Jd 1,' :. f.J:~, \. .',1' ,:.¡I .:.J) '\" '¡ J I \¡ '. ,1 P· '.., \ . í J.w ~ J' J ¡ ,.-. \'j 'I ·1' 'I. f U J 1 1 Jìi ']¡,j ,~ .kd 1..JW 1.J '~ !m~~ FRANK H. MURKOWSKI. GOVERNOR AI,ASIiA. OIL AlO) GAS CONSBRVATlON COJDIISSION 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)27&7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integritv The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission 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. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" I Area Inj ection Orders AIO 1 - Duck Island Unit 6 7 9 AIO 2B - Kuparuk River Unit; Kuparuk River, 6 7 9 Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; 6 7 9 Western Operating Area AIO 4C - Prudhoe Bay Unit; 6 7 9 Eastern Operating Area AIO 5 - Trading Bay Unit; 6 6 9 McArthur River Field AIO 6 - Granite Point Field; 6 7 9 Northern Portion AIO 7 - Middle Ground 6 7 9 Shoal; Northern Portion AIO 8 - Middle Ground 6 7 9 Shoal; Southern Portion AIO 9 - Middle Ground 6 7 9 Shoal; Central Portion AIO lOB - Milne Point Unit; Schrader Bluff, Sag River, 4 5 8 Kuparuk River Pools AIO 11 - Granite Point 5 6 8 Field; Southern Portion AIO 12 - Trading Bay Field; 5 6 8 Southern Portion AIO 13A - Swanson River 6 7 9 Unit AIO 14A - Prudhoe Bay 4 5 8 Unit; Niakuk Oil Pool AIO 15 - West McArthur 5 6 9 ( , '~.. ~ Affected Rules "Demonstration of "Well Integrity "Administrati ve Injection Order Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River 6 7 10 Unit; Tam Oil Pool' 6 8 AIO 1 7 Badami Unit 5 AIO 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AIO 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; Aurora Oil Pool 6 9 AIO 23 Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Dis~osal Injection Orders DIO 1 - Kenai Unit; KU No rule No rule No rule WD-l DIO 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DIO 3 - Beluga River Gas No rule No rule No rule Field; BR WD-l DIO 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIO 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DIO 6 - Lewis River Gas No rule No rule 3 Field; WD-l DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-I DIO 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DIO 10 - Granite Point 2 3 5 Field; GP 44-11 Affected Rules "Demonstration of "Well Integrity " Administrative Injection Order Mechanical Fail ure and Action" Integrity" Confinement" DIO 11 - Kenai Unit; KU 2 3 4 24-7 DIO 12 - Badami Unit; VVD- 2 3 5 1, VVD-2 DIO 13 - North Trading Bay 2 3 6 Unit; S-4 DID 14 - Houston Gas 2 3 5 Field; Well #3 DID 15 - North Trading Bay 2 3 Rule not numbered Unit; S-5 DID 16 - West McArthur 2 3 5 River Unit; WMRU 4D DID 1 7 - North Cook Inlet 2 3 6 I Unit; NCill A-12 DID 19 - Granite Point 4 6 Field; W. Granite Point State 3 17587 #3 I DID 20 - Pioneer Unit; Well 3 4 6 1702-15DA WDW DID 21 - Flaxman Island; 3 4 7 Alaska S tate A - 2 DID 22 - Redoubt Unit; RU 3 No rule 6 Dl DIO 23 - Ivan River Unit; No rule No rule 6 IRU 14-31 DIO 24 - Nicolai Creek Order expired Unit; NCU #5 DIO 25 - Sterling Unit; SU 3 4 7 43-9 DIO 26 - Kustatan Field; 3 4 7 KF1 Storage In.iection Orders SIO 1 - Prudhoe Bay Unit, No rule No rule No rule Point McIntyre Field #6 SIO 2A- Swanson River 2 No rule 6 Unit; KGSF #1 SIO 3 - Swanson River Unit; 2 No rule 7 KGSF #2 Enhanced Recovery In.i ection Orders EID 1 - Prudhoe Bay Unit; No rule 8 Prudhoe Bay Field, Schrader No rule Bluff Formation Well V-I05 '-'") Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" EIO 2 - Redoubt Unit; RU-6 5 8 9 l I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO, CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATIACHED COpy OF ADVERTISEMENT MUST BE SUBMITIED WITH INVOICE F AOGCC 333 West ih Avenue, Suite 100 Anchorage, AK 99501 907-793-1221 AGENCY CONTACT DATE OF A.O. R o M DATES ADVERTISEME~T REQUIRED: T o Journal of Commerce 301 Arctic Slope Ave #350 Anchorage, AK 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRElY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of 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. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of . 2004, 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 2004, Notary public for state of My commission expires P.ublic ,NQtices ~' Subject: Public Notices From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 29 Sep2004 13:01 :04 -0800 t of ') Qf')Qf')()()~ t'1 () PM Public Notices <iseott.Öranswick@ml1ls..gpv>, ~rad McKim..<rl1ck:ìl1lbs@B~·~.cQl1l> P;1eé:\se. find the attached Not i ceancl. At tachme:nt . . for tÌle.. proJ?0E;ed atrieildmefit undèrground.injection orders and the· Public Notice Happy Valley #10. Jody COlombie ,.................--..-.,..----..................-..............---- ..--.......-..........,....---.:...........'..........--..,-.................-........-...............,'...... . ¡............ ......... ..... ............ ...... ................ ...... ......................ieq~tèìtt-~y})~: ªpp~iêatiQt1/msword; ¡Mechaulçal,(J1teg'lty.¡proposal~C1oc i..··.... ......... ......................................................................:..... ............................,... ". ....'.....'...'.',....................:....... ..... :.........,..,................... ............1..:.................. ......................£.........··......A....·.·.··.' .,. ¡,·,·€6nteDt~Eneot'l.mg...·uaseu~ ..._. ___'~__". _,.__-., m' . _;__._...._."...._~.~_,:~ .;.,.__'_~_"_"_~"_"-;_:y",-:__,,-,:,,,,~w..~,,_._.~___:_.,_~_...._. .. __'._ ,.."".___....,._y..,.,. ..~_~" _._.. _.._ "- __....,...._ _....'--_....,. ..._,_ _¥..;.~.........~..;',._----...__.,....-.,...-.__.___._ .__ "m_~._~._._._....,..____.___..._._^~-:-<_~..___..__. ..,. .._.~,.. ,. í '. ..../ .... .iê(bltelJj...~~í~: å'p]~tati~w'm$Wø~Ø: Mech.anicalJ!ntegtityof Wells'Notìçe.(JJoc¡ ..... . .............. .' ............ ../................. .. .' .... ··k· ... ····6..... .4.. !Conteof-Encø<Jing: . øetse ..- -.~.....,.. . . I Content-I'ype: ~ftj.~¡cayt;iø~mswøl"d Happy"Val.ley10 Beal'lugNotlce.d.oc c p...... '.. '. .......... ..... ......................................'..............t......:...... .:.......£.............04...·.... :. LOBt.ent...Bnc(nfiøg:·uaseu.... ~ ~-.__. .... --_. ·_____·".....____~__~_._......;.....,..,.""__·._~_.."......____,·~.___.m._..--A'~.~...___... r' ... __ ",:",__^~"____._,_.._.__,,,_:.._____.,_-,;--..",...._. ._..._¥_.........,.-_m...~.___.'._;..,-:..;...__,..._.._..,;.;.^~_.,_~__~_.__.__.'~__,_,_~_v~ A.....:..~._...,.......'" 2 of2 O/ìOnnnLi 1·1 () Pl\,f ~ublic ~~tice '~ Subject: Public Notice From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: \V'~~~(.~~..~ep 2004 -0800 ...........~~~~ Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Mechanical Integrity of Wells Content-Type: application/rnsword Content-Encoding: base64 Content-Type: application/msword Ad Order form. doc Content-Encoding: base64 1 of 1 9/29/2004 1:10PM Citgo Petroleum Corporation PO Box 3758 Tulsa. OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street. Ste 2000 Ft. Worth, TX 76102-6298 /fjall¿:d /ð/;m'1 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 SOldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna. AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 '. ['Fwd: Re~ Consistent Wording for Injection\,...,y,èrs - Well Integrity ... '-'" Subject:. [Fwd: Re: ·ConsistêntWor~Î11.~tºr IrJ.J~ctiôn.9rd.¢*~..w~n~t~gí"ìtY~ª~vised.)] From: John N orman<john~llOrrnan@a~m'¡Il~srate.a1(.u~?: 01 Oct 2004 11:09:26-0800 more -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz~law.state.ak.us> To:jim regg~admin.state.ak.us CC:dan seamount@admin.state.ak.us, john norman@admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <jim regg@admin.state.ak.us> 8/25/20043:15:06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <¡im regg~admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 1 nf" 1 f\¡'1¡'1f\f\A A .f\'7 Dl\Jf [Fwd: Re: Consistent Wording for Injection .ers - Well Integrity ... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts" Administrative Actions" title (earlier rules used" Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission ? "f? .. ^ I...... 1__"''' .. ....._~... .. .. XFwd: Re:'Consistent Wording for Injection \xs - Well Integrity... ~ Subject: [Fwd: Re: Consistent Wording for lliJëctiøii0rger$ ~WêtlIi1tègrìty€R;evis~d)] From: John Nonllan <john_notman@admin.s~äteòak.µs> Date: 01 Oct 2004 11:08:55 -0800 please print all and put in file for me to review just prior to hearing on these amendments. thanx -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz(ã¿law.state.ak.us> To:dan seamount(ã¿admin.state.ak.us, Jim regg(ã¿admin. state. ak.us, john norrnan(ã¿admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as red lines on the second document attached. »> James Regg <iim regg@¿admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIG 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions lof2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection ~rs - Well Integrity... - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman@¿admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission Content-Type: application/msword Injection Order language - questions.doc Content-Encoding: base64 ---...--.... ..--- Content-Type: application/msword Injection Orders language edits.doc Content-Encoding: base64 2of2 11ì;' ;'lìf) A A .f)"7 n1\ K --- '~ Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integritv Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Standardized Language for Injection ()rders Date: August 17,2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (exeept at least once every two years in the case of a slurry iniection \vcll), and before returning a \vcl1 to service folh.1\ving aft.eF a workover affecting mechanical integrity, and at lea~;t once e\'cr)' /1 year:; while acti';e1y injecting. For slurry injection wells, the tubing/casing ar..nulus Inust be tested for mechanical integrity e\'ery 2 years. Unless an alternate ¡-neans is approved bv the COlnnlission. Inechanic.al integrity rnust be demonstrated by a tubing pressure test using a::r.tTe M-I+-surface pressure ofnlust be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that mt:rSf-shoWâ stabilizing pressure that doesand 1nay not change more than 10Q4r- percent during a 30 minute period. --A:R-y alten1ate nleans of de1TIonstrating Inechanical integrity mu:;t be approved by the C01nnlission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as otherwise provided in this rule,3=!he tubing, casing and packer of an injection well must demonstrate Inaintain integrity during operation. \Vhenever any pressure conlmunication, leakage or lack of injection zone isolation is indicated bv injection rate. operating pressure observation, test, survey, log. or other evidence, t+he operator ~sha]l immediately notify the Commission and submit a plan of corrective action on ª-Form 10-403 for Commission approval.:. \vhencvcr any pressure comlnunicatiøn, leakage or lack of injection zone isolation is indicated by injection fate, operating pressure øbsefTv'atíon, test, survey, or log. The operator shall shut in the vveIl if so directed bv the Comnlission. The operator shall shut in the well \vithout awaiting a response horn the Comlnission if continued operation would be unsafe or would threaten contamination of freshwaterIf there is no threat to freshV";ater, injection 111ay continue until the COlTI1TIÌssion requires the '.vell t(:1 be shut in or secured. Until corrective action is successfully completed. Âª monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. ~ ..(Fwà: ~e: [Fwd: AOGCC Proposed WI Lan~e for Injectors]] \~. SubJect: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Inj~ct()rs]] From: Winton Aubert <winton_aubert@adrnin.state.ak~us> D~t~: Thu, 28Qct 2004()9:48:53-0&OO '1\ This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven¡ Engel, Harry R¡ Cismoski, Doug A¡ NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.¡ Reeves, Donald F¡ Dube, Anna T¡ NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** 1 ~¡: '1 1 f\ /,., Q 1")f\f\A 1 1 .f\Q A l\Æ [Fwd: Re: [Fwd: AOGCC Proposed WI Lan!. ~ for Injectors]] returnj_ng a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "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 * immediately*_** notify the Commission" This section could use some help/wordsmithing: "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." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte Ai Digert, Scott Ai Denis, John R (ANC) i Miller, Mike Ei McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» 2 of3 IIì j") S2 j") 1ì1ìL1 1 1 . (\Q ^ 1\ ¡f #10 l' ft~ : ~ - , ~ Co no coP hill ips Alaska, Inc. Kelli L. Hanson Production Engineer 700 G Street, ATO-1764 Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907-265-6945 dill·- C)-\ 0 ~CJ \95-~ July 26, 2004 Alaska Oil and Gas Conservation Commission Attention: Mr. James Regg, mc Manager 333 W. 7th Avenue Suite 100 Anchorage, AK 99501 Subiect: CDl-19A Class IT Disposal Well Fracture Growth Estimate Dear Mr. Regg: This letter is in response to your May 5th letter requesting an estimate of fracture growth in the Alpine Class IT Disposal Well CDl-19A. To comply with your request, a pressure fall-off (PFO) test was performed on the CDl-19A well in June 2004. The PFO data has been analyzed. Fracture extension and closure were evident in the early time fall-off data. The fracture resulting from the test closed at 7.58 minutes post injection at 6,492 psia, corresponding to a fracture gradient of 0.716 psi/foot. The gradient has increased since the initial step rate test (0.665 psi/foot) as a result of changes in well injectivity index and poroelastic effects. The fracture half-length was estimated to be 356 ft. A Nolte-Smith plot of the injection data indicates the fracture grew in length, but was height constrained. Please see the attached report for further details. If you have any further questions, please call me at 265-6945. Sincerely, J(J1;. L· 14-~~ rAfT- i~ç . \..""", 'Uti 0 J ¡L f:: ''-'oOIi l~..J J \ Kelli L. Hanson CDl Production Engineer if~Ja$¥. a O· 1 . "'" -~ '- . ~ ConocoPhillips Alaska, Inc. Date: July 26, 2004 Subject: CDl-19A Pressure Fall-Off Summary From/Location: Kelli Hanson, Alpine Production Engineer ATO-1764 Telephone: 265-6945 Test Overview -A pressure fall-off test was performed on Alpine's Class II Disposal Well, CDI-19A on June 19,2004. Dual Panex gauges were run and set in a XN lock in the XN nipple at 10,778' RKB. Little Red Services pumped 850 bbls of seawater down the well at 1.5 bpm. Following seawater injection, the well was freeze protected with 20 bbls diesel at 1.0 bpm. The well was shut in and static bottom hole pressures were recorded. Analvsis - Attachment 1 shows the pressure behavior recorded by the down hole pressure gauges. CDl-19A remained shut-in for approximately 4 days. Saphir pressure transient analysis software was utilized to analyze the data. Conventional and pressure derivative calculations were performed to calculate well/reservoir properties (permeability, skin, and wellbore storage coefficient) fromthe test. Assumed data for the analysis are given below. - " Porosi ty (<I» 0.15 Viscosity (µ) 0.499 cp Fonnation Volume Factor (Bw) 1.0 RB/STB Well Radius (rw) 0.2615 ft Total Compressibility (Ct) 4.109 x 10-b l/psi Depth (D) 11,465' MD (9,062' TVDSS) Pump Rate (Q) 1.5 bpm (2,160 BPD) water, 1 bpm (1,440 BPD) diesel FP A log-log plot of M> versus ~t was constructed and is shown in Attachment 2 with the pressure derivative. A Horner plot is shown in Attachment 3. The early time data was also analyzed to detennine fracture properties. A plot of pressure versus the square root of time (Attachment 4) was prepared to identify fracture extension and closure. Finally, a Nolte-Smith plot was created to model the fracture growth characteristics during injection. This plot is shown as Attachment 5. , ' CD 1-19A PFO Summary Page 2 Results - The following table summarizes the well/reservoir properties obtained from analysis of the pressure fall-off data. k.h 745 md.ft Skin (s) 2.96 Wellbore Storage Coeff. (C) 0.211 bbl/psi Fracture Closure Pressure 6,492 psia @ dt=7.58 min Fracture Gradient 0.716 psi/ft Fracture Half-Length (Xf) 356 ft Fluid Efficiency 1% Pressure transient analysis yielded a k.h value of 745 md.ft. If it is assumed that most of the fluid entered the top two perforation sets (higher injectivity index), the thickness (h) would be 30-45 feet, resulting in a penneability of 17-25 md. This estimate compares favorably with the calculated log model liquid penneability of 21 md. _~u_."~."...~·~-'r.·""",."",,,,, The log-log plot shows a classic damaged well response and a skin of 2.96. Near- well bore damage was expected due to the frequent disposal of dirty fluids. The skin has increased since the initial PFO, run 6/4/2000. Evaluation of that test demonstrated the well was slightly damaged, skin = 0.65. The initial test was conducted prior to regular disposal operations. During a step rate test on September 17, 2000, the fonnation fracture pressure was observed as 6,035 psi using a 9,062' column of 9.2 ppg brine and 1,700 psi on the wellhead. Using this data, a fracture gradient of 0.665 psi/ft was calculated for the reservoir. During nonnal operations, injection occurs above this fracture pressure, thus hydraulically fracturing the well. Refemng to the square root of time plot, Attachment 4, a fracture was observed to close at dt=7.58 minutes and 6,492 psia, yielding a fracture gradient of 0.716 psi/ft. The elevated fracture gradient can most likely be attributed to a reduction in well injectivity and poroelastic effects due to the long pumping period. Injection was assumed to enter the fonnation through the top two perforation sets, thus a fracture height of 35 feet was used in the early-time analysis. A regression fit to the early-time fall-off data resulted in a fracture half-length of 356 feet and a fluid efficiency of 1 %. Attachment 5 shows a Nolte-Smith plot from the injection data. The quarter slope indicates a Perkins and Kern system, i.e. a wedge-shaped contained fracture, which is growing in length. CD1-19A PFO Summary Page 3 Conclusions -Due to disposal injection operations, the near wellbore area has been damaged. Fractures extending past the damage zone have allowed continued injection. The data suggests the fractures extend in length, but are vertically contained. 51 OO~:'" ... 4900' '. 4700 i~v I ... ...,;. ... i ". .....) i.i: >.'...... 4500 o 6900 6700 6500 6300 '. - "C ~ 6100 CD ... ... 8 5900 J: .... 0- ~ 5700 I ca ëñ 8 5500 CD ... ::s () = 5300 ... 0. . , . , ,.c..~ ',' ! . .' . I , ' . I :.,.. . : .. .. ./.. I ' · I ,. ... I .> ... , ..··.,1 ',.,.- .' I .., I , . . I , . ....', . ......,...,...........". ...... "...\........,... ...,..' . ....,. ,: .... . , ... .' . . ,. .'.. :: ::. .;.. .., .. ,., ::... , . '.. . ....'. ...... . :,' .,.',. ..: .. 10 20 30 Attachment 1 CD1-19A Panex Data . . ...<.. ...... ..,. .'.' .'.. .,,:>.<': ,.,.:,.:':'. ..,".,'.'; .....: ..:... ....;., ... .., ........-"'-... ....:.::.'..:,...,.,... .,0':<: .. ·..:::'..:':'/s:' H··i,::.:.,.·'::'" : ...... ...... . .. ..' ... ,':: . ...:::..'......:...... ,';:.. ..........,..",..> ...'¡';:",;':.:.. , :;' ..:-:',0' .. > : ,.-'-".":. . " ...... . .:.': .'. .. .'. '. ,.:, > "":: . " '.' :::,' ....:.:, .....>'., ..... '/]" :. ·':":>:L.,·:" ....... . ': .<., ..,... ;..,..',.".'.' .... . . .' .ii; >: .... ,:' .. .:. ':\.:< .: ... .... .,'. ,. ..... .. " .".' ".. . .. ....: .. :..:....:.:: ..' :;, . ..,.::. ..,' ;',; ,« "; .'. .. '.... . .' ...., .. "..'" ,. ;., . ,',...'.' . . . ,: . '.' . .-..... ... . . '... , ,.. .. ..... ..,.. '., ., . ..:.... ...':".'..... . ...',..., . ..:,.; .. ,:X; , , . .. '.. ..... .... · ," ,. . .. :,. , . ,.. ....:" .....',' ,.'. . . . ....'... . '.:.:....:., . ".',' ., .'. . ,;i, , " ..,.. ,:..',, ....,:.. .', .'. .. ,..... ......'. .. ..' . ... .. ,.. ...,. .', ,'... ... , . ,:',' '.'... ., '...: .... .., ..... ,:' .,' ..,. .' .,,, ..- ..:'.. ,.., . .... ,. , . , ,..,...,.', , . ., ..,: ',....:, " . . , .. . , . < .. ":".... .:;;.... , : " '... . ,.' ..., : .. . .<,.,; ........:. ..:. '. :;'. "...'..'..' >. ',. . , .,... ,,' . ... ...:'''>:'.''. . :, ..... ,.': :>.. ....:.. .:'. . ..".. .... ....' . ( " , ( ...:. ...,:. ., ' : :' i>," ......' ',.:.' '.. . ,. .. . . . .. I 80 90 100 110 40 60 70 50 Elapsed Time (hrs) ~ Log-Log plot "" "-" Attachment 2 Company CPAI Well CD1-19A Field Alpine Test Name I #6/28/04 PFO 1E+5 1E-4 1E-3 0.01 0.1 10 100 1000 10000 1000 ïñ ..e. -0. "0 "0 100 c: ro 0. "0 10 dt [hr] top gauge (Mod) (Mod) fall-off #3 Rate 0 STBID Rate Change 1440 STBID P@dt=O 6577.49 psia Pi 4522.83 psia Smoothing 0.1 Selected Model Model Option Standard Model Well Storage + Skin WBS Type Changing Reservoir Homogeneous Boundary Infinite Results TMatch 2.09 [hr]**-1 PMatch 0.00734 [psia]**-1 C 0.211 bbl/psi Ci/Cf 0.357 Alpha 22400 Skin 2.96 Delta P Skin 403.857 psi Pi 4522.83 psia k.h 745 md.ft k 21.3 md Rinv 1970 ft Test. Vol. 1.13919E+7 Barrels Saphlr v3.10.09 - 07-2004 1-19A PF054 hrs lead.ks3 ~ KAPPA ïñ B a. ~, Horner plot ~ Attachment 3 Field Alpine Test Name / # 6/28/04 PFO Company CPAI Well CD1-19A +++ + + + 6000- 5000- I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 2 3 4 5 log(tp+dt)-Iog( dt) top gauge (Mod) (Mod) fall-off #3 Rate 0 STB/D Rate Change 1440 STB/D P@dt=O 6577.49 psia Pi 4522.83 psia Smoothing 0.1 Saphir v3.10.09 - 07-2004 1-19A PF054 hrs lead.ks3 6400 I·. ... "". 6300 -.... .....-., I Go) a- I ::J en 6200 - en CÞ a- Q. I 6100 I -I .'.,........ ,. .. I 1 . . :.. ., ,: .....:.-: ... .....:.., .... ......... ...:. ....... ...... .....;,:.... .. ..":"';.;:' ;': ....,... .. . ·\·i........-:...:···., ...... . .'-.'. ; .... '.. c..;:·: . .. ......... ' .' .'. ...,:<.... ,: . :;, ..'........ . .'.," ..' . . '.'; ,,' ." . :...... ..... ..> , ....:: ,...-,.. ..:... :::.i·'.'.>, .. ..' :', .... ...': '.' :.;: .... ':.. 'i : .. ?'~" ..... '. .....:.. , . ... ,.:.., ,.. .:. ....:. ..: ..' .',.. .. . '.'..-'.. ~.'" >',~~...i;· ,'. .... .. . .. .'::.:. :,......,.~'" ...~ ¿".:.:.- '.':.:. .,""::. "", '.' ,.. . . . i'· ':: , ", Attachment 4 Square Root of Time ',.'.'.' . . ..: ...'X·::,:"·;'· ,./ . ...:, ....,,: ;.. .:, ",:.: . . .:::.;..:.} :.. . '( ,.. " :......... .:. ... ':.. ,',/ '. .'. ,.". ',.: .... :.. :. .'. .. ....:.,.... ..,.:..': ... ........:..: :.,'.'.};:; ..., ... "...' .... . ..'~';"".. .;,:....:. .:..~..... ...., ~.:......',:... ..:. ..,.. ., '.\~ '. ..' .;~. '..', ,. èture;EXténsion ... :.. ,. :', .. ,.... .. ... , ... '. .',.' ...... ..., . .... ..' ,... .. .,:... .,.:.:.:.- ,... ' . . ..' ,.. :-.,', . ,:.:. ... .,..,"'. ."i> i:. .. ,. .'. .. .. .... : ... ..... .., ....: .'. ",,',,' .....', ,:. " .. . .'.'. .:: <:: ,., . .,::.... ./:':; ... ,..... .',...'... .. .:... ., . . ;.. . .. .:.,. ..' ,:.. . ... . . :.. :....::. : ;. .,(::..' ,. ...... 6000 . '. . .,' .... . ;. :: '. .. . ,: ,::-.'..:. '.. I 0.2 0.3 o ,. 0.1 Square Root of dT 0.4 .. ( . . , I '.. . ,; '. ..,:.,;:.: ......., .. ....,. 0.5 0.6 'ëi) a. o Ó II c: o :;:; () .¡: LL 'ëi) a. ~ ~ <0 ~ <0 II Õ a.. a> ~ :::J en en Q) ~ a.. ... Q) Z o lri o ~ o L() o o C\/ o o ~ o C\/ · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . · . . . . . . . ...................................................................~..........~............... · . . . . . . · . . . . . . · . . . . . . · . . . . . · . . . . . · . . . . . · . . . . · . . . . · . . . . · . . . · . . . ..........................~............................ · . . . · . . · . . · . . · . · . · . · · · . . · . ....................... · . · . · . . · . . · . . · . . í: : : : · . . . . · . . . . · . . . . ·t··········~·· ·~··············t···········t···········t········· . . . . . . .. . . . . . . . . . . . . . . . . . . . . · . . . . . . . · . . . . . . . · .. .... · . .. .... · . .. .... · . .. .... ·~··········t··········· ···············t············ ·<···············t······....·t·.......... ......... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... · .. . ... ···········~··············~··········4···········1····...........)......... ········.·~·····..........I...........I...........I......... · · · · . c . . . . · . . . .~ . . . . · . . .. .... · . . .. .... · . . .. .... · . . .. .... : : : : : c : : : : : : : : : ° : : : : ..~..............~..........:...........~...............~........JJ~..........~..............~...........,...........~......... · . . . . o. . . . . : : : : : c: : : : : · . . . . . . . . . : : : : : 0: : : : : : : : : : 0: : : : : · . . . . . . . . . : : : : : 0: : : : : þ................-..................................................~............................................................ · . . . . . . . . . · . . . . . . . . . · . . . . . . . . . : : : : : 0: : : : : · . . . . . . . . . · . . . . . . . . . · . . . . . . . . . : : : : : c: : : : : · . . . . . . . . . · . . . . . . . . . · . . . . . . . . . · . . . . . . . . . · . . . . . . . . . .... .... ...... ...................... ...... 2.0 5.0 10 20 100 200 500 1000 2000 50 dt ( Attachment 5 Net Pressure Plot #9 CUI-IYA Jim, As a follow-up to your request dated May 5, 2004 and our follow-up phone conversation concerning frac growth estimate on CDl-19A per Area Injection Order 18A. The status of the work required to fulfill the request via PTA using a down hole injection well pressure falloff is as follows: Ran down hole gauges on June 19th. Injected seawater into well and shut-in. Pulled Gauges June 26th. We are currently in the process of analyzing the SPFO data and will have a report out by July 23rd. Please let me know if you have further questions. Chris Alonzo Alpine Engineering Supervisor ConocoPhillips, Alaska (907) 265-6822 ~.þ..1.:~..~..§...~...9.:~.S?!2.~.?~~.S;..?~S?~gp}?:.~..~J..~..P§'._~...S;..?0 1 of 1 7/12/20042:29 PM #8 AI1A.SIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSK', GOVERNOR 333 W. -¡rn AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 May 5,2004 Mr. Chris Alonzo Alpine Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Dear Mr. Alonzo: Disposal Injection Order 18 dated April 19, 1999, and Area Injection Order 18A dated April 18, 2000, address specific requirements for waste injection into specific disposal injection intervals within the Colville River Unit. Rule 9 of DIO 18A requires an annual perfonnance report that includes "rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans." The Alaska Oil and Gas Conservation Commission ("Commission") received from ConocoPhillips Alaska, Inc. ("ConocoPhillips") the 2003 Disposal Performance Report for the Alpine Oil Pool within the Colville River Unit. The report is dated March 17, 2004, and summarizes pressure and rate performance, surveillance, and testing of disposal injection Wells WD-2 and CD 1-19A associated with Alpine Oil Pool development during calendar year 2003. The Commission has completed its review of the 2003 Disposal Well Performance Report. Regarding Well CDI-19A, ConocoPhillips states: "all fluid injection to date has occurred above fracture pressure." There is no estimate of fracture height and length as required by Area Injection Order 18A, Rule 9. ConocoPhillips notes that no data was collected to estimate fracture height and fracture length. Please provide the Commission with a summary of how ConocoPhillips' intends to resolve this deficiency in the annual surveillance requirements of Area Injection Order 18A. Sincerely, ~B J.?~C1 James Regg l ( UIC Manager cc: John K. Nonnan, Chair Daniel T. Seamount, Jr., Commissioner #7 1'II11I,IP5 œ ~ PHilliPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY \~ Alpine Development Project Alpine - HSE - ALP 14 P. O. BOX 196860 ANCHORAGE, ALASKA 99519-6860 ONLY Chair I C-omm I ~C-omm . File Telephone 907- 670-4200 Facsimile 907- 670-4778 May 12, 2002 R"};, E· (-..~ 1: I V .-. .-.~ _ t !) 1.. ?Ufìf¡? ; , I... Vb,. ......~ t Cammie Taylor Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Alaska OH & Gas Comt Commission AnchoraQ8 RE: Administrative Approval for Injection of Treated Camp Effluent and Approved Non-hazardous Fluids in to Alpine Sea Water Flood Wells Dear Ms. Taylor: The Alpine facility is a stand-alone development, geographically isolated from neighboring infrastructure. There are no permanent roads connecting Alpine to other facilities. Access is- by winter ice road during the months of February through April, and by aircraft only during other times of the year. As a result of this isolation, the Alpine facility must be self-sufficient and equipped with on-site facilities and procedures to effectively manage all manner of contingencies, particularly in the summer months. Under normal operating conditions, treated camp effluent and other approved non- hazardous fluid waste, such as snowmelt, stormwater, sump fluids, and wash waters are disposed of by injection in the permitted Class 1 well, WD-02. Camp effluent is hard-piped_ to the Class 1 disposal well, while the other wastes fluids are typically disposed in batch loads offloaded in holding tanks associated with the well. Area Injection Order 18A states Class 2 EOR "fluids may be injected for purposes of pressure maintenance and enhanced recovery" and does not describe or limit the appropriate fluids. In testimony, the Alpine recovery process has been described as a "water alternating gas" (MWAG) process. With this letter, Phillips Alaska, Inc. respectfully requests administrative approval by the Commission to utilize a blend of seawater and treated camp wastewater effluent as the ' water phase of the Alpine recovery process, injecting these fluids into Class 2 EOR wells on- an as needed basis, such as periods when well WD-02 is not operable due to annual mechanical integrity testing (MIT), maintenance activities, or in the event of an operational failure of WD-02. Phillips Alaska, Inc. is a Subsidiary of PHilLIPS PETROLEUM COMPANY Administrative Approval for :",-.;tion of Treated Camp Effluent May 12, 2002 Page 2 '''-''' The fluid would be injected using the existing grey water pumps to feed the SWI system. The grey water pumps maximum capacity is approximately 40 US GPM, thereby minimizing any potential to significantly dilute the seawater. The anticipated blend ratio, based on normal daily rates, would be approximately one hundred parts seawater to one part effluent. wJ \J !0Ú) t ( L.t7L' The injection water would be distributed to various water flood wells currently taking SWI and completed in the Alpine formation. PAl experts have reviewed the physical properties of the anticipated effluent blend ratio, and more concentrated effluent blend ratios. Given normal operating conditions, it is not anticipated that the proposed mixture will be detrimental to the reservoir, surface, or subsurface facilities. The proposed dilution ratio will be high enough to reduce oxygen content to levels where accelerated corrosion is not a concern. Corrosion levels will be monitored to assure actual conditions are as anticipated. In the reservoir, the difference between the proposed mixed water injectant and seawater is not expected to have any significant impact on injection performance or hydrocarbon recovery. While the mixed water bacterial content will be higher than in seawater alone, the Alpine recovery process is expected to have relatively low water throughput, hence, it is expected there will be little impact to produced fluid hydrogen sulfide levels at the end of field life. Included for your review is analytical for a representative sample of treated effluent from the Alpine waste water treatment plant (WWTP) demonstrating the waste in non-hazardous. Also included is a copy of an approval previously granted to Kuparuk Operations for injection of treated effluent for EOR, illustrating this disposal request is consistent with other approved· practices. Thank you for your consideration of the proposal. Please do not hesitate to contact us at (907) 670-4200 should you have any questions or additional information needs. Sincerely, ~~ Thomas Manson/Michael Nelson Field Environmental Coordinator Attachments: Analytical Results Letter from AOGCC to ARCO Alaska (Now Phillips Alaska) Phillips Alaska, Inc. is a Subsidiary of PHilLIPS PETROLEUM COMPANY #6 ....~ ~ Decision Document July 29, 2002 Request: Authorization to periodically mix treated wastewater effluent with Class II enhanced oil recovery (EOR) injection fluids when the primary disposal well (WD-02) is unavailable because of maintenance or in the event of failure. Company: Phillips Alaska Inc. Date: May 12, 2002, letter Relevant Data and Considerations in the Decision I. Chemical make-up of effluent stream to be mixed with EOR fluids; is it hazardous? Does it exhibit characteristics of hazardous wastes (per 40 CFR 261.20 through 261.24)? a. Analysis provided by Phillips at AOGCC request documents the chemical make-up of the EORjZuid, and the EORjZuid with treated wastewater. The estimated mix of 1% effluent with seawater injectant will not significantly impact properties of the seawater. 2. Susceptibility of formation to react negatively with EOR fluid mix; will it cause plugging or other reservoir impacts that will prevent efforts to achieve ultimate recovery? a. The characteristics of the treated effluent are consistent with other aqueous jZuids used for EOR injection. The estimated mix of 1% effluent with seawater injectant will not significantly impact properties of the seawater 3. Threat to fluid movement from intended confined zone, and potential for fluid mixture to change potential for movement? If the fluid mixture would change the potential for movement, then a detailed reassessment of the well construction and an AOR would be needed. a. Nothing in the jZuid make-up, fluid quality, or injection process compromises the well integrity. The process is a simple mixing ofjZuid streams. 4. Alternatives to the proposed action? a. Facility shutdown; b. Developing additional surface storage as a buffer when it is not possible to use the WD- 02 well for disposal; i. Lined pits - an unacceptable approach for temporary storage given the injection capabilities and the potential risk to the surface environment (and well documented concerns for such). ii. Alpine's reduced footprint leaves little space for buffer tanks to provide storage of the wastewater effluent 5. Logistical issues and the significance of such? a. Alpine is a remote development that is accessible only by air in the summer, and by ice road in the winter months (January - May). Transportation from Alpine in either case would increase handling of the waste that is historically where most large volume releases occur. 6. Performance standards and compliance responsibilities a. Sampling and analysis of representative mixture; b. Retention of records; available to AOGCC upon request; c. Volumes of treated wastewater mixed with EORjZuids and injected in wells on Forms 10- 406 (Monthly Injection Report) and 10-413 (Annual Injection Report). 7. Other Factors a. Kuparuk Field approved to mix effluent waste water in EOR #5 ""~/ 90"7-670- Jul07 200~ 8:39PM PAt CNST - ALPINE ..~ ¡FAX FROM: Tom Manson A/pine Production Facility HEST-ALP 14 P.O. Box 196860 Anchorage, AK 99519 TO: Jack Harts Or Pouch Phone Fax (907) 670-4200 907 670..4778 Phone Fax 793-1232 276-7542 I CC: I REMARKS: D Urgent 181 For your review D Reply ASAP 0 Please Comment Mr. Harts, Randy Kanady, my alternate, asked me to forward information on our wastewaster treatment plant suspended soils (85) and on SS for the seawater we are injecting into our EOR wells. This information is in support of the Phillips Alaska, Inc. request to inject wastewater into our seawater water flood wells (Class 2R) on an as needed basis. I have attached a spreadsheet of the May and June SS for the wastewater plant effluent and the Seawater Treatment Plant monthly report for March - June and a report showing the average todate for July 2002. Please contact us if you have any further questions. Tom Manson Alpine Environmental Coordinator RECEIVED JUL 8 2002 Alaska on & Gas ConI. Commission And10fage Jul 07 2002 8:39PM p~T CNST - ALPINE 90"'-670-4778 p.2 ~, "-'" Alpine Sewage Treatment Emuent Suspended Solids The following is a ·list -of the ·suspended 'solids, 1n mgA~ leaving the Alpine wastewater plant. Please ootetbat these figures only show suspended solids, not total solids. We t d est fj dis lved r ds present '¡ o·not t . or so SOl Date 8.S., Date 8.S. mgI1 mg/l 5/1 40 6/1 88 Total flow for May 'WaS 835,230 5/2 100 ·6/2 66 gallons for ·an average of26,943 5/3 60 ·6/3 84 gallons per ·day. 2-6,943 x 8.34= 5/4 100 6/4 6"8 224,705 Ibs of water per day. The 5/5 160 6/5 30 average eft1uent suspended solids 5/6 240 6/6 52 per day in May was 85.2 mg/L 5/7 140 .6/7 132 (224,70S/1,~,OOO) x 85.2=19.1 5/8 na ·618 88 Ibs of.suspended solids per day in 5/9 260 '6/9 80 the efiluent. Or, ·about 592 Ibs, for 5/10 120 6/10 28 the month·of May. 5/11 200 6/11 18 5112 118. 6/12 12 5/13 8 ·6/13 94 5114 21 6/14 1"6 5/15 52 6/15 44 5/16 9 6/16 28 5/17 4 6/17 34 S/18 46 '6113 12 5/19 9 6/1-9 22 5/20 15 6/20 78 5/21 28 6/21 30 5/22 52 6/22 10 5123 50 ·6/23 36 5/24 174 6/24 60 5/25 28 6/25 43 5126 24 6/26 5/27 126 6/27 5/28 177 ·6/28 5/29 na 6/29 # 5/30 76 6/30 5/31 66 Avg 85.2 . Avg 50.3 . ._.____~~.._._....____~._.~.__._... .. ____..._________ ..... ___._~ :_¥_____.__. _...__.,_... M _..______._____..._. .--.-....---- ~ ; î i i TREATED I¡ EOUIPMENT I RUN 5CHE UNSCHEI SEAWATER (TOTAL) 5515704 BBLS11 D D SEAWATER (KRU) 3385674 BBLS! I FEED PUMP A 0.00 0.00 O.OO! SEAWATER (ALPINE) 2130030 BBLS[I FEED PUMP B 744.00 0.00 0.001 i I TEMPERATURE 56 DEG F\ I FEED PUMP C 744.00 0.00 O.OO( I (AVERAGE) !! FEED PUMP D 0.00 0.00 O.OO! " PRESSURE 333 PSIGll 11 (AVERAGE) ! I TRANSFER 743.50 0.00 O.OO! 11 GAS RATIO 7.22 SCF/BBII PUMP A (AVERAGE) Lj I TRANSFER 0.00 0.00 O.oo DISSOLVED OXYGEN 15 PPS! I PUMP B :1 (AVERAGE) I i TRANSFER 744.00 0.00 O.OO! il FREE CHLORINE 0.05 PPMII PUMP C :1 (AVERAGE) 0.001 __ /:!TSSAVERAGE 0.7 MG/LI CLARIFIER 0.00 0.00 ·1 ¡I PUMP ¡ .-:-'-:~'-:':"';' ... .~..:.·.·.·.:·.~·1~;";'':.''.---''M''.~'''''.''---.':_-'.~:_.:..'.',_.. .... . ¡ I PERMIT ! I CLARIFIER A 0.00 0.00 O.OO! " FOR COMPLETE ¡ I CLARIFIER B 0.00 0.00 O.OOi MONTHLY PERMIT 15-005 SUMMARY, SEE 744.00 0.00 O.OO! 'I NPDES DISCHARGE j STRAINER MONITORING I 5-003 0.00 0.00 744.00 REPORT I STRAINER . -·1...·.·:.:.·.·..:;:~*..":'""·'.-~·;-_:_-__:__:__-·; ._.. .~. UTILITIES ¡¡FEED HEX A 0.00 0.00 744.00 'ì 'I TOTAL FUEL GAS 133,817 MSCFil FEED HEX B 744.00 0.00 0.00 , ¡ POWER GENERATED 3,521,000 KWHlllNTAKE HEX A 0.00 0.00 0.00 KUPARUK SEAWATER TREATMENT PLANT MONTHLY REPORT FOR: MAR-02 As ofOS-JUL-Q2 13:44:10.9 . _ NSK Lab Chemist ":1' " 07/0512002 01 :44 PM -rrr{·Pll~l~f:'·:f- To: ALP Env CoordlPPCO@Phlllips cc: Subject: C:\TEMP\STP _MON...,MAR..02.J .HTML '"-' '-. p.3 907-670-4778 Jul 07 2002 8:39PM PAl CNST - ALPINE Jul 07 2002 8:39PM PAl CNST - ALPINE '-' 907-670-4778 ..... I.' l..j...... ." NSK Lab Chemist f ~ ~.~ . . ' .: ·07/05/2002 01:43 PM - . . '0' j "p-' "I ~. To: ALP Env CoordlPPCO@Phillips C~ . Subject: C:\TEMP\STP _MON_APR-02_1.HTML .~. p.4 KUPARUK SEAWATER TREATMENT PLANT MONTHLY REPORT FOR: APR-oZ As ofOS-JUlr02 13:43:12.5 'r·····-·---····· .....------...--.--....----.-. - .....---.... :¡ ¡¡TREATED :1 SEAWATER (TOTAL) 7409783 j! SEAWATER (KRU) 4753774 j SEAWATER 2656009 ¡ (ALPINE) \1 TEMPERATURE !I (AVERAGE) :' PRESSURE :1 (AVERAGE) :1 GAS RATIO ¡ (AVERAGE) :1 DISSOLVED ~!OXVGEN ¡I (AVERAGE) :1 FREE CHLORINE II (AVERAGE) ~¡TSSAVERAGE . ¡ '""'=~7.''''· --.-~~~"'='"'="''"......_~,,="~"~~_____. ¡I PERMIT 11 FOR COMPLETE I¡ MONTHLY PERMn ; ¡ SUMMARY, SEE 11 NPDES DISCHARGE : I MONITORING :! REPORT 6.39 0.04 ,.-...-.-..---..--.-.--......... ..__.-._._...~-~--. : UTIUTIES .----. .------. ..~._------_._. .-.-..- . ----..-.. .....-...--.-...-..- 54 ; ! EOUIPMENT BBLSi BBLSr FEED PUMP A BBLS: FEED PUMP B ¡ FEED PUMP C DEG F¡ FEED PUMP D RUNSCHED 0.00 719.00 719.00 0.00 PSIGi TRANSFER PUMP 719.00 iA SCF/BS¡ TRANSFER PUMP 0.00 LI B PPB¡ TRANSFER PUMP 719.00 C 326 6 0.6 PPM! CLARIFJER PUMP ¡ CLARIFIER A MG/L CLARIFIER B ! 5-CJ05 : STRAINER i S-CJ03 : STRAINER FEED HEX A FEED HEX B INTAKE HEX A 0.00 0.00 0.00 0.00 0.00 0.00 0.00 UNSCHE D 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 719.00 0.00 0.00 51.00 0.00 668.00 0.00 719.00 0.00 0.00 0.00 0.00 719.00 0.00 0.00 ~~~ Jul O~ 2002 8:39PM PAT CNST - ALPINE 907-670-4778 '__J .' NSK Lab Chemist 1.. ":4::l-' .. . , . _ . . 07/05/2002 01 :42 PM . .-.~,.~.. .'. - To: ALP Env CoordlPPCO@ Phillips oc: Subject: C:\TEMP\STP _MON_MAY-02_1.HTML KUPARUK SEAWATER TREATMENT PLANT MONTHLY REPORT FOR: MAY-02 M of05-JUL.02 13:41:30.0 .1·..··.. . -.....-...---..--..-.. ". .. ..... .......-.--..-..-..-. ... HTREATED i SEAWATER (TOTAL) I SEAWATER (KRU) II SEAWATER (ALPINE) :1 TEMPERATURE ¡I (AVERAGE) .!I! PRESSURE ¡ (AVERAGE) ;1 GAS RATIO II (AVERAGE) II DISSOLVED OXYGEN ;1 (AVERAGE) !! FREE CHLORINE ~:¡ (AVERAGE) ;¡TSSAVERAGE ¡ Ii ....:~,.".... .... .~~-".-.,.,-,.",~.-.....-.-.......,..._- .-................---..." .......-~,.'" :" PERMIT i i\ FOR COMPLETE II! MONTHLY PERMIT ¡ SUMMARY, SEE ;, NPDES DISCHARGE ¡ I MONITORING ¡ ¡ REPORT ~ Í _w_.___._...._..__ _... 8267798 5536104 2731694 55 6.46 0.03 t f'":.,~=.'::.~......'t'f'Pt'.:".~~~..~..... ... .~:..~...~'"'1':.~':7:.~-;-:--~~..~:-..~-:. i .1 UTIUTIES : TOTAL FUEL GAS 113,629 : POWER GENERATED 1,897,000 p.5 _....~----¡ r·-·-·-·· ---------- . ------..----. . ..-...---¡ I UNSCHE Di í 0.001 0.001 0.0°1 O.OO¡ i 0.001 316 ¡ I EOUIPMENT BBLS\I BBLS FEED PUMP A BBLSJ FEED PUMP B DEG Fj I FEED PUMP C ¡ FEED PUMP D PSIGi/ ! I TRANSFER SCF/BB! PUMP A L¡ TRANSFER ! , PPSI I PUMP B ¡ I TRANSFER PPM! PUMP C MG/L[¡ CLARIFIER ¡I PUMP i I CLARIFIER A II CLARIFIER B : 15-005 ! ¡STRAINER 15-CJ03 ¡ I STRAINER ! f 9 1.4 ¡!FEED HEX A MSCFj I FEED HEX B KWH! I INTAKE HEX A RUN SCHE D 0.00 0.00 744.00 0.00 343.50 0.00 400.50 0.00 744.00 0,00 0.00 0.00 744.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 744.00 0,00 744.00 0.00 0.00 744.00 0.00 0.00 0.00 0.00 0.00¡ o.ooi ¡ 0.001 O.ooj 0.001 i 0.00! O.OO( I 744.00 ¡ O.OO¡ 0.00, r··-······...···-·-··-·····------··.···.··---..·· .. .....--.....--.-----..-.-.....], ...- .--- .-......-..---.-.--.-......... ... I ; I TREATED !·EOUIPMENT RUN SCHE UNSCHE II· SEAWATER (TOTAL) 6853557 BBLSI D D :1 SEAWATER (KRU) 4498566 BBLS FEED PUMP A 0.00 0.00 0.00 ,I SEAWATER (ALPINE) 2354991 BBLSI FEED PUMP B 702.50 0.00 0.00 I ; ¡I TEMPERATURE 57 DEG pi FEED PUMP C 193.00 0.00 0.00 11 (AVERAGE) ! FEED PUMP D 512.50 0.00 0.00 ;1 PRESSURE 317 PSIGj ij (AVERAGE) ¡ TRANSFER 704.50 0.00 0.00 ;1 GAS RATIO 7.01 SCF/BBj PUMP A :1 (AVERAGE) Li TRANSFER 631.25 0.00 0.00 :1 DISSOLVED OXYGEN 25 PPB! PUMPS I ; ! (AVERAGE) i TRANSFER 70.00 0.00 0.00 :¡ FREE CHLORINE 0.04 PPM! PUMP C :1 (AVERAGE) ~·¡TSSAVERAGE 2.8 MG/LJ CLARIFIER 0.00 0.00 0.00 ,[ j PUMP .!' ..'".,...,.........~~.-~'''"=.".,~.~.=~,=w...~~=.,.._."...--- 1 :1 PE~MIT ¡ CLARlFIERA 0.00 0.00 0.00 'I FOR COMPLETE 1 CLARIFIER B 0.00 0.00 0.00 :1 MONTHLY PERMIT ;1 SUMMARY, SEE ; S-CJOS 703.50 0.00 0.00 )1 NPDES DISCHARGE STRAINER :1 MONITORING 5-003 703.50 0.00 0.00 'I REPORT STRAINER ~ I .. ··..."...··-f..~ ........_..~_........:"'-....-:-:;...:-=:.-.:.:~';'"_.;~~:-:;-;-;.-.:::-:-~.~.~. ..~. ~~ '_.,._.w :1 :1 UTI LInES FEED HEX A 0.00 0.00 720.00 :1 TOTAL FUEL GAS 121,618 MSCF FEED HEX B 702.00 0.00 0.00 ,I POWER GENERATED 3,507,000 KWH INTAKE HEX A 0.00 0.00 0.00.. KUPARUK SEAWATER TREATMENT PLANT MONTHLY REPORT FOR: JUN-02 As vf05-J1JL..02 B:16:39.7 .. -I-.!..' .1 .. NSK Lab Chemist H_ .,07/05/200201:40 PM ;H'.t:~:. . . r y.¡ i t·T ',. - + '. = . To: ALP Env CoordlPPCO@ Phillips co: Subject: C:\TEMP\STP _MON_JUN-02_1.HTML ~ p.6 90":1-670-4778 Jul 07 2002 8:39PM ppT CNST - ALPINE , Ju 1 '07 2002 8: 39PM ppT CNST - ALP I NE 907-670-4778 ~ ... ._ .' . _ _ NSK Lab Chemist o· .' ~_ _.."1" +: 07105/200201:15 PM . . - - ,7 :" - . ì To: ALP Env CoordlPPCO@Phillips cc: Subject: C:\TEMP\STP _MON_JUL-Q2.-1.HTML p.7 KUPARUK SEAWATER TREATMENT PLANT MONTHLY REPORT FOR: JUL-02 .As ofOS-JUL.02 13:03:48.8 ¡r-O-.---.-..-----.-----------.---O-O--.---------------------! 1"-----------0-_0-_-..--.-.-..----.-_-00------0.-.-00 . ¡ TREATED i SEAWATER (TOTAL) i. SEAWATER (KRU) i II SEAWATER (ALPINE) J, TEMPERATURE il (AVERAGE) 'I j) PRESSURE (AVERAGE) í GAS RATIO I (AVERAGE) I DISSOLVED OXYGEN i¡ (AVERAGE) j' FREE CHLORINE ! (AVERAGE) -:> i TSS AVERAGE .---_.. .-....---..-.......--..........-...-.-..- ..------.-.................----.---.--.. PERMIT FOR COMPLETE . MONTHLY PERMIT , SUMMARY, SEE NPDES ¡DISCHARGE ¡ MONITORING REPORT : UTIUTIES : TOTAL FUEL GAS . POWER GENERATED '·-~I"'-.~:·I:r~ ~~~.":: :.:~r:~7'-::-:-:-~· ~:-::-:-:=::=::: ::;~...::._ __...:~.: .:.....;.:.:.-~ 697879 544492 153387 59 0.04 12,440 469,000 i 10EOUIPMENT BBLSil ¡ i BBLS¡ I FEED PUMP A BBLSI I FEED PUMP B DEG Fi ¡ FEED PUMP C ¡ i FEED PUMP D ¡ i PSIGil SCF/BB¡ITRANSFERPUMP 78.25 LilA PPsl I TRANSFER PUMP 74.75 i!B PPM: ¡ TRANSFER PUMP 0.00 ¡!C MG/Lil .! CLARIFIER PUMP 53.75 ! CLARIFIER A 53.75 : i ; ¡ CLARIFIER B 53.75 265 7.1 28 9.9 ! ¡ , t 5..005 '; I STRAINER ; I S-CJ03 i I STRAINER , ¡ , ; MSCF¡ I FEED HEX A KWH!, FEED HEX B . i INTAKE HEX A 0_ RUN SCHED 0.00 79.00 96.00 0.00 96.00 96.00 0.00 77.25 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0,00 UNSCHE D 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 96.00 0.00 0.00 . , Ja~:)B-OZ 11:00am' From-Ph¡//¡psAKSafety-Trn, -. ~ 9076597861 T-315 P.D5/D7 F-9Z8 ~ U ~ ~ ~ lW ~ ~11~@ ~lA\ ~~::fI';;;~~~ñ~ - ¡'" I ,\L~\.Sli.c\ OIL ,\YD Gl\S CONSEII.\',,\.TION CO~I~IISSI0N ~1·POJCUPJNe; OAM ,A.NC...afUGE. AL.4SU t9!0t.:s11a p...oN€. (9Øn Z7t-1t3:1 TEL£C:CP"l': twIIm-7s.a March 4, 1991 Mark. D l"UrDID Kupandc: OperaûoD.S Representative ARCe AJaska P 0 Bax 100360 AÞcborage, AK 99510-0:160 RE: Use of Kuparuk Waste Water Trcatmcøt Plant (WWTP) treated ecnueDt to perl%1llnently ~ugœent water injecûoD supply at CPF-l, Kuparuk River Unit. Dear Mr. Drumm: We have evaluated your proposal of February 5 t 1991 to use WWTP treated einUelll to augment the EOa water injection supply system at Cl'F-l. The Commission has reviewed the chemical amùysis that you proVided. Cor the WWTP treated ecnuel1t. Based. upau that 8.%I81ysis., the Commis$ioD. has caacluded. that the chemic:a1 characterisûcs of the treated eCfJuea.t are similar to other fluids used in the EOR project. In accordance with the provisions at AtO 2 J w. hereby approve the. us. or WWTP cffiuents to permanently augmeat the water injectioa supply at CPF-l. As a CODcUÛ9D.. at this app~va19 you will continue to u.œ1ne the efnuect todelDQQstrate its continued suitability r~r EOa Injectioa.. Capies or the cbemical aaaJysis sbaJl be provided to AÇGCC as requested. SiAceNIy. David W. Jo Chairmaø. AOG cc: Huale! Scott . #4 Re: S(0nn~ater S~·Jt.. Disposal Approval It ~-- ~ Subject: Re: Stormwater Silt Disposal Approval Date: Wed, 16 Aug 200009:24:17 -0800 From: Wendy Mahan <Wendy_Mahan@admin.state.ak.us> Organization: doa-aogcc To: Donnelly&Manson <n1508@ppco.com>, Dan Seamount <dan _ seamount@admin.state.ak.us>, Camille Oechsli <cammy _ oechsli@admin.state.ak.us> f\ \ Ü \'6 f::\ Mr. Manson, The Commission will grant a waiver under 20 AAC 25.450(a) to allow the Class II injection of nonhazardous silt that has settled out of snowmelt collected at the Alpine Development Project this summer. Although there is a Class I well on site, you have stated that it is currently operating at maximum capacity with the construction/startup activity. In subsequent conversation with myself, you indicated that the current containment takes up a lot of space that Phillips would like to use, and that once construction activities are complete, the pad will be graded. You stated that the construction activities created what you consider to be an unusual situation with increased traffic and the piling of snow onto the gravel pad from ice pad areas in an effort to minimize tundra impacts. In the future, you intend to use the Class I well to inject this or similar wastes. Due to the extenuating circumstances created by Alpine startup, the Commission will allow the one-time injection of the snowmelt silt into the CD 1-19A well. Please call if you have any further questions. Wendy Mahan Natural Resource Manager > > Donnelly&Manson wrote: > > > > This is a request by Phillips Alaska, Inc. (PAI) to dispose of silt/mud > by > > injection into our Class II disposal Well (CDl-19A), which accumulated > > during management of stormwater runoff at the Alpine Development Project > > (ADP) this past breakup period. > > > > As the weather warmed during breakup at the ADP large pools of snowmelt > > water formed around the drilling rig and elsewhere on the pad. Due to > the > > construction activity at the time these pools were frequently stirred up > by > > vehicle and foot traffic resulting in water with a high turbidity. The > > high turbidity prevented PAI from discharging this snowmelt off the pad > as > > part of our stormwater management plan. Due to the large number of > > construction personnel on-site at this time the Alpine Class I well was > > running at full pump capacity injecting wastewater from the living > quarters > > and dining camps. Therefore, the snowmelt could not be injected into the > > Class I well. Since the ADP Class II well was not operational at this > time > > we developed a system to capture the snowmelt and settle out the solids > in > > a 50 ft by 50 ft settling pond. PAI proposes to remove this material 1 "f'J 8/16/009:25 AM Re: Srormwater S~t Disposal Approval ,/ ~ > from > > the settling pond and to dispose of it by creating s slurry and pumping > it > > down the Class II well. The ADP engineering group recommends use of > > either the hot oil truck or the cement unit on the Grind and Inject > > Facility to accomplish this. > > > > PAL feels that injecting the residual silt form the snowmelt into the > Class > > II well is proper and appropriate. The silt has been sampled, tested, > and > > found to be RCRA non-hazardous. > > character, similar to the slurry > > approved for injection into the > settled > > out of the snowmelt collected from the pad in areas around the drilling > > operations as well as other areas. The April 18, 2000 amendment to Area > > Injection Order No. 18A , Colville River Field, Colville River Unit, > > Alpine Oil Pool allows for the injection of snowmelt (Finding 12) . > > > > We respectfully ask that you consider and grant our request to inject > this > > snowmelt residual silt into the ADP Class II well CDl-19A. > > > > Thomas Manson > > Alpine Environmental Coordinator The material also has a fluid, mud-like from our drilling operations which is class II well. Finally, the silt ') Af., 8/16/009:25 AM Re: Class II designation for gravel w/i well houses .,~. Subject: Re: Class II designation for gravel w/i well houses Date: Tue, 20 Jun 2000 13:29:12 -0800 From: Wendy Mahan <Wendy_Mahan@admin.state.ak.us> Organization: doa-aogcc To: Lipchak&Rea <P2075@ppco.com> CC: Camille Oechsli <cammy _ oechsli@admin.state.ak. us>, Dan Seamount <dan _ seamount@admin.state.ak.us> ~\ C) d-~ ~\a '-'''- r'\\G \~(\- Ms. Rea, It is reasonable to consider the small amount of gravel stained with nonhazardous hydraulic fluid within a wellhouse "associated waste" directly related to the production process. Furthermore, it would be preferential to allow the disposal of this waste in the Grind & Inject facility along with the Class II waste generated from cleanup activities in the wellhouse area. The Commission approves the Class II disposal of this small amount of nonhazardous associated waste consisting of soil from within wellhouses in the Eastern Operating Area contaminated with hydraulic fluid. Please call with any questions. Wendy Mahan Lipchak&Rea wrote: > > Wendy: > In response to concerns expressed by ADEC's IPP group following field > inspections last fall, we are implementing a comprehensive well house cleanup > program ·in the Eastern Operating Area that involves removal of hydrocarbon > stained gravel from within well houses. As a fol10wup to our discussion on June > 16th, I am sending you this email to request AOGCC approval to dispose of all > gravel within a wel1house (inside and outside of a cellar) to a Class II > disposal well. In some cases, the gravel outside the cellar may have some minor > staining of hydraulic fluid from the Surface/Subsurface Safey Valve (SSSV) > control panels in each well house. The SSSV systems are uniquely associated > with production activities. The control panels provide positive hydraulic > pressure to the surface/subsurface safety valves. The hydraulic fluid is cycled > from the panels to the safety valves located in the wellhead and tubing string > at a depth below permafrost. Therefore as the safety valves are operated, the > hydraulic fluid is moving back and forth from within the wellhead and tubing > systems to the panel. Given that the quantity of gravel containing these > leaks/drips of hydraulic fluid will be very minimal and the fluid is > non-hazardous and considered to be part of the oil and gas production process, > we request that the gravel containing this fluid be acceptable for disposal in > Phillip Alaska'sClass II wells at the Grind & Inject facility. > > We believe that managing stained gravel within wel1houses through the Grind & > Inject facility is the preferred option, both from a best practices and > environmental perspective. We would appreciate a decision from AOGCC on this > matter, as it would have significant impacts on the well house cleanup programs > being undertaken across the North Slope. > > We look forward to hearing from you, > ca ryn rea > (907) 659-5999 I of I 6/20/00 1 :29 PM Re: Ô;ass 11 designation for gravel w/i well houses ~ Subject: Re: Class II designation for gravel w/i well houses Date: Fri, 23 Jun 2000 15:40:35 -0800 From: Wendy Mahan <Wendy_Mahan@admin.state.ak.us> Organization: doa-aogcc To: Colegrove&St Pierre <N1037@ppco.com> CC: Camille OechsIi <cammy_oechsli@admin.state.ak.us>, Dan Seamount <dan _ seamount@admin.state.ak.us> ~\ 0 ~ß f\\ O~~ (\ \0 \ 'bP\ Shellie, Thanks for the clarification. Again, it is reasonable to consider the small amount of gravel stained with nonhazardous hydraulic fluid from Safety Valve System control panels within a wellhouse as "associated waste" that is directly related to the production process. Also, the most environmentally sensible practice would be to allow the disposal of this waste in Class II Grind & Inject facilities along wiht the Class II waste generated from the cleanup activities in the wellhouse area, rather than segregate and send the small volume of nonhazardous waste to the Class I wells for disposal. The Commission approves the Class II disposal of this small amount of nonhazardous associated waste consisting of soil from within wellhouses in the Kuparuk and Alpine areas contaminated with hydraulic fluid. The snow meltwater commingled with fluids from within the wellhouse area and the nonhazardous hydraulic fluid may also be injected into a Class II disposal well. Please call if you have any additional questions. Wendy Mahan Colegrove&St Pierre wrote: > > Wendy, > Sorry for the fragmented sentence. My request includes contaminated gravel from > within the well cellars and well houses at both Kuparuk and Alpine. Like > Prudhoe EOA, Kuparuk is also conducting a comprehensive clean up program of > removing stained gravel within the well cellars and well houses throughout the > field. > > What I meant by the fragmented sentence is that we also hydraulic fluid panels > that support surface safety valve actuators that, in some cases, have leaked > onto the gravel pad within the wellhouse, but outside the well cellar. The > clean up program includes removal of stained gravel within the well cellar and > the gravel contaminated with the non-RCRA-hazardous hydraulic fluid from the > hydraulic fittings and valves. We anticipate minimal contaminated gravel and > have been experiencing about 3 cubic yards per 1-3 drill sites including > cleanups at various wells on the drill sites, as required. The percentage of > hydrocarbon contamination will be less than 1%. > > In addition to the gravel, during break up, we have snowmelt water which > naturally accumulates in low spots on the pad, including cellars, assisted by > the slight grade on gravel drill sites sloping toward the wells and reserve > pits. The snowmelt water may collect in the cellar and may also contact the > gravel that is contaminated with hydraulic fluid stains within the wellhouse, > but outside the cellar. We would like to know whether this meltwater now 1 ^I',,) 6/23/00 3 :40 PM Re: Glass II designation for gravel w/i well houses \"'''w' > commingled with fluids within the well cellar and the non-RCRA-hazardous > hydraulic fluid stains may be injected into a Class II disposal well. > Shellie. > > ?of? 6/23/00 3 :40 PM #3 "-¥ Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Colville River Unit - Alpine Area ARCO Alaska, Inc. by letter dated February 3, 2000, has requested an amendment to Area Injection Order No. 18. The requested amendment would expand the scope of the Area Injection Order to allow disposal injection of Class II fluids in the Alpine area of the Colville River Unit. A person who may be harmed if the requested order is issued may file a written protest prior to 4: 00 PM, March 1, 2000 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on this matter. If the protest is timely filed a hearing on the matter will be held at the above address at 9:00 AM on March 21, 2000, in conformance with 20 AAC 25.540. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 before March 14, 2000. Robert N. Christenson, P .E. Chair Published February 9, 2000 ADN AO# 02014025 Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 Ad # Date Puchase Order Edition Account Price Per Day 279048 02/09/2000 02014025 ON STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. C (LU¿ ~ Lega I Cle rk_~ÇE::-_----~E-"::~'------ Subscribed ands,^,grnJ9prYl~~þ~fºE~~~is_.<:J-ª!~:~~_____<___~_ _ --_léj1£Ltl-8_Jj;-r~rlQ____- Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: !é.,k ~ ,;2ðIJt} --_71_~{--------- {\.\ \ ~~~'{ a~ rrr/" \''' ~\"". . . . . . .c..(, r;;.. .¢ ~ . ><4",d!"~~ ..0 -;:.. ~ .~,/~OTA~ .~,- ~ 1/ Ai'-i~- ~... ~ ~ :\~~StIC.l: ~ -=:,\~ --... .~. ~ - . >~: ..fA..... . . :'\ ~ . . "OF,At;;p'': . :Y ~ . . . . . . 'I' /// * ,\" :Jj}J/))})))\ì STOF0330 $73.53 $73.53 #2 Phillips Alpine Environmental Phillips Alaska, Inc., Alp-] 4 PO Box ] 96860 ~chorage,AJ( 995]9-6860 Attn: Jolin/Graika Phone: (907) 670-4527 Fax: (907) 670-4712 NTL Lab#: Client Sample ID: LocationlProject: COC #: Sample Matrix: Comments: )~ "-". NORTHERN TESTING LABORATORIES, INC. 3330 INDUSTRIAL AVENUE 8005 SCHOON STREET POUCH 340043 FAIRBANKS, ALASKA 99701 ANCHORAGE, ALASKA 99518 PRUDHOE BAY, ALASKA 99734 (907) 456-3116' FAX 456-3125 (907) 349-1000 - fAX 349-1016 (907) 659-2145 -FAX 659-2146 Report Date: Date Anived: Date Sampled: Time Sampled: Collected By: 2/4/02 1/31/02 1/30/02 07:00 JB NT]} 062 WWTP EIDuent Alpine WWTP 27625 Liquid FI82Definitions MOL = Method DeteCtion Limit B = Below Regulatory Minimum H = Above Regulatory Maximum M = Matrix Interference J = Best Available Estimate U= Less Than Detection· Limit D = Lost To Dilution Analysis Analysis Parameter Result Units Flag MDL Method Date EPA 9045 pH 7.61 Unit EPA 9045 1/31/02 EPA 1020 Flash Point > 140 Deg F EPA 1020 1/31/02 By: Jerry Pollen Pruahoe Bay Laboratory Supervisor >",-----,,< \.-- NORTHERN TESTING LABORATORIES, INC. 3330 INDUSTRIAL AVENUE 5761 SILVERADO WAY; UNIT N POUCH 340043 FAIRBANKS, ALASKA 99701 ANCHORAGE, ALASKA 99518 PRUDHOE BAY, ALASKA 99734 (907) 456-3116· FAX 456"3125 (907) 349-1000· FAX 349-1016 (907) 659-2145 . FAX 659-2146 Phillips Alaska Inc. Alpine Development pf(~ject PAl BEST-ALP 14 PO Box 196860 Anchorage, AK 99519-6105 Attn: Jeff Barnett Phone: (907) 670-4527 Fax: (907) 670-4712 NTL Lab#: F304085 Client Sample ID: WWTP Effluent Location/Project: COC #: 27625 Report Date: Date Arrived: Date Sampled: Time Sampled: Collected By: 2115102 2/1/02 1/30/02 7:00 ·m Sample Matrix: Liquid Flae:Definitions MDL = Method Detection Limit MCL = Maximum Contaminant Level B = Below Regulatory Minimum H = Above Regulatory Maximum M = Matrix Interference J= Best Available Estimate U= Less Than Detection Limit Comments: Prep Prep Analysis Analysis Parameter Result Units Flag MDL MCL Method Date Method Date Arsenic by TCLP <MOL mgIL U 0.06 5 EPA 1311 2/14/02 EPA 6010B 2/15/02 Barium by TCLP 0.012 mgIL J 0.006 100 EPA 1311 2/14102 EPA 6010B 2/15/02 Cadmium by TCLP <MDL mglL U 0.009 1 EPA 1311 2/14/02 EPA6010B 2/15/02 Chromium by TCLP <MDL mglL U 0.02 5 EPA 1311 2/14/02 EPA 6010B 2/15/02 Lead by TCLP <MDL mgIL U 0.04 5 EPA 1311 2/14102 EPA 60 lOB 2/15/02 Selenium by TCLP <MOL ingIL U 0.02 1 EPA 1311 2/14/02 BPA 6010B 2115/02 Silver by TCLP <MOL mgIL U 0.01 5 EPA 1311 2/14102 BPA 60 lOB 2/15/02 Mercury by TCLP <MDL mgIL U . 0.002 0.2 EPA 1311 BPA 7470 2/15/02 ~ _:rZL .....J ) Repeí!íed by Barry Durbrow Fairbanks Chemistry Supervisor '-' ',,-,,' NORTHERN TESTING LABORATORIES, INC. 3330 INDUSTRIAL AVENUE 5761 SILVERADO WAY; UNIT N POUCH 340043 FAIRBANKS, ALASKA 99701 ANCHORAGE, ALASKA 99518 PRUDHOE BAY, ALASKA 99734 (907) 456-3116· FAX 456-3125 (907) 349-1000· FAX 349-1016 (907) 659-2145 . FAX 659-2146 Phillips Alaska, Inc.; PAl HEST-ALP 14 P.O. Box 196860 Anchorage, AK 99519-6105 Attn: Jeff Barnett Phone: (907)670-4527 Fax: (907) 670-4712 Report Date: 3/12/02 Date Anived: 2/4/02 Sample Date: 1/30/02 Sample Time: 7:00 Collected By: JB NTL Lab#: Client Sample ID: Location: Client Project: COC#: Sample Matrix: Comments: A300831 WWTP Effluent Flag Definitions MRL = Method Report Level MCL = Max. Contaminant Level B = Present in Method Blank H = Above Regulatory Maximum M = Matrix Interference ] = Estimated Value Below MRL D = Lost to Dilution E = Estimated Value 27625 Water Analysis Method Result Flag MRL MCL Units Prep Prep Analysis Parameter Method Date Date EPA 8270 Hexachloroethane <MRL 0.100 3 mg/L EPA 1311 2/6/02 3/11/02 Nitrobenzene <MRL 0.100 2 mg/L Hexachlorobutadiene <MRL 0.100 0.5 mg/L 2,4- Dinitrotoluene <MRL 0.100 0.13 mg/L Hexachlorobenzene <MRL 0.100 0.13 mg/L 2,4,~Trichlor~henol <MRL 0.100 2 mg/L 2,4,5- Trichlor~henol <MRL 0.100 400 mg/L Pentachlor~henol <MRL 0.100 100 mgIL Pyridine <MRL 0.250 5 mgIL o-Cresol <MRL 0.100 200 mgIL m,p-Cresol <MRL 0.100 200 mgIL Total Cresols <MRL 0.100 200 mgIL 2-Fluorophenol (Surr) 61 % Recovery Phenol-d6 (Surr) 66 % Recovery Nitrobenzene-dS (Surr) 75 % Recovery 2-Fluorobiphenyl (Surr) 72 % Recovery ~, ..~ i ~.""'r.k. U Reported By: Wendy Mitchell Anchorage Laboratory Manager --. ',-,,' NORTHERN TESTING LABORATORIES, INC. 3330 INDUSTRIAL AVENUE FAIRBANKS, ALASKA 99701 5761 SILVERADO WAY; UNIT N ANCHORAGE, ALASKA 99518 POUCH 340043 PRUDHOE BAY, ALASKA 99734 (907) 456-3116 - FAX 456-3125 (907) 349-1000 - FAX 349-1016 (907) 659-2145 -FAX 659-2146 Phillips Alaska, Inc.; PAl HEST-ALP 14 P.O. Box 196860 Anchorage, AK 99519-6105 Attn: Jeff Bamett Phone: (907) 670-4527 Fax: (907) 670-4712 NTL Lab#: A300831 Client Sample ID: WWTP Effiuent Location: Client Project: COC#: Sample Matrix: Report Date: 3/12102 Date .Arrived: 2/4/02 Sample Date: 1/30/02 Sample Time: 7:00 Collected By: m 27625 Water FlaK Definitions MRL = Method Report Level MCL= Max. Contaminant Level B = Present in Method Blank . H = Above Regulatory Maximum M = Matrix Interference . 1 = Estimated Value Below MRL D = Lost to Dilution B = Estimated Value Comments: Analysis Method Result Flag MRL MCL Units Prep Prep Analysis Parameter Method Date Date 2,4,6- Tribromophenol (Surr) 83 % Recovery EPA1311 2/6/02 3/11/02 p- Terphenyl-d14 (Surr) 94 % Recovery EP A 8260 Benzene <MRL 0.100 0.5 mg/L EPA1311 2/4/02 2/5/02 Carbon Tetrachloride <MRL 0.100 0.5 mgIL Chlorobenzene <MRL 0.100 100 mgIL Chloroform <MRL 0.100 6 mgIL 1,4-Dicblorobenzene <MRL 0.100 7.5 mgIL 1,2-Dicbloroethane <MRL 0.100 0.5 mgIL 1,I-Dicbloroetheœ <MRL 0.100 0.7 mgIL 2-Butanone (MEK) <MRL 0.500 200 mgIL Tetrachloroetheoe <MRL 0.100 0.7 mgIL TrichloroetbeDe <MRL 0.100 0.5 mgIL Vinyl Chloride <MRL 0.100 0.2 mgIL DBFM (Surr) 98 % Recovery Toluene-d8 (Surr) 102 % Recovery 4-Bromoftuorobenzene 103 % Recovery ~ ~~~~1t-k.J'. Reported By: Wendy Mitchell Anchorage Laboratory MaDager #1 ARca Alaska, Inò..-' Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 ~~ ~~ February 3, 2000 - - Mr. Blair Wondzell Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: Application for Amendment to Injection Orders Alpine Oil Pool/Colville River Field ...... Dear Mr. Wondzell: ~ ARCO Alaska, Inc., as an owner and the operator of the Colville River Unit, seeks Alaska Oil and Gas Conservation Commission approval to amend Area Inj ection Order No. 18 (dated January 24, 2000) to authorize additional disposal wells in the disposal intervals specified in Disposal Injection Order No. 18 (dated April 19,1999). Enclosed please find a copy of ARCO's application which was prepared in accordance with 20 AAC 25.460 (Area Injection Orders) and 20 AAC 25.252 (Underground Disposal of Oil Field Wastes and Underground Storage of Hydrocarbons). ~ Please note that to minimize operational constraints we propose spudding well CD 1-19 A no later than April 17, 2000 in order to complete one Class II well before the end of this ice road season. Your consideration and any recommendations regarding the expedient processing of this request will be very much appreciated. -- Inquiries regarding this application may be directed to either Mike Erwin or Doug Chester at this office. - Sincerely, RiGINAl Mark M. Ireland Alpine Development Manager RECE\VED fEBO 4 [000 askI 0" & GaaCani. eomm\Mion At.. ~ ~ - ... y",-,," - Application for DIO November 1, 1998 Page 2 - ""'" cc: Mr. Kenneth A. Boyd, Director Alaska Department of Natural Resources Division of Oil & Gas 3601 C Street, Suite 1380 Anchorage, Alaska 99503-5948 Mr. Robert N. Christenson, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 ~ Ms. Teresa Imm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 99518-3035 - - Mr. Isaac Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 - ~ Jonathan Williams Us EPA, Region 10 Groundwater Protection Unit 1200 Sixth Avenue (OW-137) Seattle, WA 98101 (letter only) - Mrs. Catherine Lively Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 ~ Todd Liebel Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 ....... ~ ~ ~ Area Injection Order No. 18 Colville River Unit Colville River Field Alpine Oil Pool Amendment No.1 ARC a Alaska, Inc Anadarko Petroleum Corporation -.- Union Texas Petroleum, LLC - February 3, 2000 -- - - Table of Contents 20 AAC 25.252 Page (c) 1 Well Locations 4 (c) 2 Surface Owners and Operators 5 - (c) 3 Affidavit (see Exhibit 10) (c) 4 Geologic Details 6 (c) 5 Well Logs 9 (c) 6 Mechanical Integrity and Well Construction 10 (c) 7 Waste Sources and Characteristics 12 (c) 8 Inj ection Pressure 14 (c) 9 Waste Confinement 15 (c) 10 Formation Water Salinity 17 (c) 11 Aquifer Exemption Request 21 (c) 12 Offset Well Status 22 Exhibits 1 2 3 4 5 6 7 8 9 10 Colville River Unit Location Map Type Log - WD-02 Geologic Cross-Section Seismic Cross-Section Structure Map - Kingak Depth Structure Map - Sag River Depth Structure Map - Lisburne Depth Class II Typical Well Schematic Well Head Schematic Affidavit of Notice to Surface Owners ~ - 2 ~ Introduction ~ On April 19, 1999, the Commission issued Disposal Injection Order No. 18 which authorizes ARCO to inj ect Class II fluids into the Colville River Unit well WD-02. The disposal intervals include the Permo-Triassic Ivishak and the Triassic Sag River Formations. - On January 24,2000, the Commission issued Area Injection Order No. 18 which establishes an Area Injection Order for enhanced oil recovery operations in the Alpine Oil Pool (Exhibit 1). - ARCO recently recognized the need to expand its Class II operations to include additional disposal wells. Hence, this application seeks Commission approval of amendments to Disposal Injection Order No. 18 and Area Injection Order 18 to authorize additional disposal wells in the injection zones specified in Disposal Injection Order No. 18. This application has been prepared in accordance with 20 AAC 25.460 (Area Injection Orders) and 20 AAC 25.252 (Underground Disposal of Oil Field Wastes and Underground Storage of Hydrocarbons 3 ~ - Well Locations 20 AAC 25.252 (c) 1 - The attached map (Exhibit 1) shows all known wells penetrating the inj ection zone in the proposed inj ection area. The map also shows the areal extent of the inj ection zone relative to the Colville River Unit boundary. - Arco proposes to drill up to five penetrations into the proposed injection intervals for Class II disposal purposes. Three locations are described in Arco's Application for Disposal Order dated December 3, 1998. The three wells are shown on Exhibit 1 as wells WD-O 1, WD-02, and WD-03. In addition, Arco is now considering the addition of two well locations to be drilled from the well pad to facilitate access workover fluid disposal as well as drilled fluids and cuttings from the Grind and Inject module which works in tandem with the drilling rig. These two locations are shown as wells CD 1-19 A, and WD- 04. There are no additional disposal well requirements for the foreseeable future. ~ - - ~ 4 - - ....... Operator: - - Surface Owners: ~ ~ ~ - - -- .~ Surface Owners and Operators 20 AAC 25.252 (c) 2 Operators and Suñace Owners within One Quarter Mile of Injection Operations ARCO Alaska, Inc. Attention: Mark Ireland P. O. Box 100360 Anchorage, AK 99510-0360 State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 5 '~ - Geologic Details Type Log, Cross Section, Structure and Stratigraphy - - 20 AAC 25.252 (c) 4 Introduction The geology of Permo-Triassic and Jurassic age sediments within the Colville River Unit area is described with specific reference to the proposed injection and confining intervals. The intervals of interest comprise clastic and carbonate rocks of the Kavik, Ivishak, Eileen, Shublik, Sag River, and Kingak Formations, in ascending order (Exhibits 2 and 3). These formations are continuous across the Colville River Unit and eastward to the Kuparuk and Prudhoe Bay fields. A seismic section is presented as Exhibit 4. Structure maps on key horizons are presented (in Exhibits 5-7) with the location of proposed disposal well CD 1-19 A noted. ~ The Jurassic and Permo-Triassic sediments comprise the Ellesmerian sequence characterized by marine transgressive-regressive cycles deposited on a slowly-subsiding passive-margin ramp to the south with a broad, stable platform to the north. The Permo- Triassic Ivishak formation consists of lowstand t1uvial-deltaic-marginal marine deposits that accumulated along the south-facing Ellesmerian ramp. Triassic transgression blanketed this interval with shallow marine sandstone and siltstone (Eileen), organic-rich calcareous shale and limestone (Shublik) and finally shelf sandstone (Sag River) across the tectonically stable northern platform. The overlying Jurassic section (Kingak) consists of southward prograding marine clastics. The Sohio Nechelik #1 well was cored throughout the Ivishak Formation. The Ivishak is described as white, gray, clear quartz-rich sandstone, with minor amounts of chert, coal, pyrite, dolomite, calcite cement, and occasional mudstone pebbles. The sandstone is well consolidated, fine to medium grained, moderately sorted with thin conglomerate bands. Sedimentary structures include massive bedding, trough and planar crossbeds outlined by muddy and silty laminae, and some ripple cross-lamination. Formation Nomenclature .~ Age Jurassic Triassic Triassic Triassic Permian Formation Kingak Sag River Shublik Eileen Ivishak ~ - Permian Kavik - Depositional Environment and Lithology Marine shelf and prodelta shales Shallow marine sandstones Shallow to deep marine shales and limestone Shallow marine sandstones and siltstones Fluvio-deltaic sandstones, conglomerates, and siltstones, and shales Prodelta and shelf shales 6 - "'~ - .- Geology of the Waste Disposal Zones Exhibits 2 and 3 show the geologic subdivisions for the proposed injection and confining zones. Well WD-02 is the type log because of its proximity to the proposed development area. Proposed Class 2 disposal well CDl-19A is 4000' northeast ofWD-02. The table below relates the injection and confining zones to the formations displayed in the exhibits. The formations described here are easily correlative to the fields to the east. Expected formation thickness is prognosed primarily from WD-02. Age Jurassic Triassic Triassic Permian Permian Formation Kingak Sag River Shublik/Eileen Ivishak Kavik Injection and Confining Zones Confining Zone Upper Injection Zone Major Barrier Lower Injection Zone Lower Confining Zone ~ {-~ - Lower Confining Zone Permian Kavik Formation: Within the Colville River Unit area, the Kavik is 200 to 250 feet thick and consists of a fairly uniform, medium to dark gray, silty shales which are pyritic, noncalcareous and micaeous. The Kavik shale is interpreted to have been deposited as shelfal and pro-deltaic deposits. This section is easily correlatable and extends across the entire Alpine Unit and west to Kuparuk. WD-02 reached TD 75 feet into the Kavik shale. Below the Kavik Shale are additional siltstones and shales of the Echooka Formation. This formation has very poor porosity and permeability and will probably act as an additional confining zone. The interbedded limestones and mudstones of the Lisburne Group occur beneath the Echooka Formation. Based on Nechelik 1 and Fiord 1, the Lisburne Group has very poor porosity and permeability. - Lower Proposed Injection Zone Permo-Triassic Ivishak Formation: Class 1 disposal well WD-02 is currently completed in the Ivishak with 191 feet of perforations. The Ivishak is interpreted to be deposited as fluvial-deltaic sandstones. The gross interval thickness is 600-700 feet and consists of thick-bedded, fine-medium grained sandstones, thin-bedded conglomerates, and siltstones and mudstones. WD-02 has 327 feet of gross sandstone within 659 feet of interval. Using a 15% porosity cutoff, 57 feet of net sandstone is present. The net sandstone averages 17% porosity and 50 millidarcies permeability based on log calculations. ~ - 7 .- - Major Barrier Between In,jection Zones Triassic Eileen Formation: The Eileen Formation consists of interbedded very-fine grained sandstone, siltstone and mudstone. The gross interval thickness is 150-200 feet. Calculated sandstone porosities are less than 15%. ~ Triassic Shublik Formation: The Shublik Formation consists of250 to 350 feet of shale, siltstones, and limestones deposited during a Triassic marine transgression. The Lower Shublik consists predominantly of siltstones and shale. This interval is extremely correlative and consistent in character and thickness. The high resistivity limestones of the Upper Shublik overlie this section. These limestones are interpreted to have been deposited in a shallow marine environment during a period of quiescence with minimal clastic input. This horizon is also easy to correlate and very uniform in thickness. Porosity and permeability are poor. - Upper Proposed Injection Zone Triassic Sag River Formation: The upper injection zone within the Colville River Unit is the Sag River Formation which was deposited in a shallow marine shelf setting. The gross interval thickness is 35-50 feet and consists of quartzose, very fine grained, glauconitic sandstones. In well WD-02, using a 15% porosity cutoff, 35 feet of net sandstone is present within 38 feet of interval. The net sandstone averages 20% porosity and nearly 100 millidarcies permeability based on log calculations. Confining Zone The Jurassic Kingak Formation is 1000-1300 feet thick and consists predominately of shales deposited as marine shelf and/or prodelta mudstones. This thick shale horizon is extremely consistent on a regional basis. The upper 500 feet of Kingak is an overall coarsening upward sequence with thin siltstone interbeds more common near the top of the sequence. The Kingak is characterized by very poor horizontal and vertical permeability and therefore, represents a competent barrier to vertical fluid movement. ~ Occurrence of Hydrocarbons There are no hydrocarbon accumulations within the Permo-Triassic proposed inj ection intervals in the Colville River Unit. Extremely faint residual oil shows are present in the Nechelik well. This is to be expected as these beds probably acted as migratory routes long ago for hydrocarbons that are now accumulated elsewhere. Wireline logs indicate that these zones are now wet. - Outcrops and Recharge None of the Permo-Triassic or Jurassic formations outcrop in the local area or intercept the 1300-1500 foot thick permafrost zone. The injection zones occur 8000 feet below the permafrost. - 8 ~~ "-"" - Well Logs 20 AAC 25.252 (c) 5 W ell logs and cuttings have been previously provided to the Commission following completion of well WD-02 in April, 1999. Logs from early exploration and development wells have already been filed with the Alaska Oil and Gas Commission. - - - - 9 '-. Mechanical Integrity & Well Construction - 20AAC 25.252 (c) 6 Mechanical Integrity Prior to commencement of injection, the well will be cased and cemented in accordance with 20 AAC 25.030 to prevent leakage out of the injection interval. Additionally, Arco will provide a cement quality log or other well data approved by the Commission to demonstrate isolation of the injected fluids in the injection interval, in accordance with 20 AAC 25.412(d). And each injection well will be pressure tested in accordance with 20 AAC 25.412(c), with notice to the Commission in accordance with 20 AAC 25.412(e). During operation casing-tubing annulus pressures and injection rates will be monitored no less than weekly by trained and qualified operators to ensure there is no leakage and that pressures will not subject the wellhead or tubulars to pressures exceeding 70% of their minimum yield strength. In the event pressure observations or tests indicate communication or leakage of any tubing, casing, or packer, Arco will notify the Commission no later than the first working day following the observation to obtain Commission approval of appropriate corrective actions, as well as permission to continue injection operations. Commission approval will be received prior to commencement of corrective actions unless the situation represents a threat to life or property. Drilling/Well Design All underground injection into the Permo-Triassic and Jurassic Formations will be through wells permitted as service wells for injection in conformance with 20 AAC 25.005, or approved for conversion to service wells for inj ection in conformance with 20 AAC 25.280. Additionally, all injection wells will be constructed in accordance with 20 AAC 25.030, 20 AAC 25.412, and Conservation Order 443 (Colville River Field, Alpine Oil Pool). A typical wellbore schematic is included as Exhibit 8, and a typical wellhead is included as Exhibit 9. - The inj ection interval will be accessed from wells directionally drilled from one of two gravel pads utilizing drilling procedures, well designs, casing and cementing programs consistent with current practices in other North Slope fields. The following will preview an Alpine drilling proposal for both producing and injection wells. - For proper anchorage and to divert an uncontrolled flow, 16-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements will be installed on the conductor. - 10 ~ - Surface holes will be drilled to a minimum of2200' TVDSS for proper anchorage, prevention of uncontrolled flow, protection of aquifers, and protection from permafrost thaw and freeze back. This casing setting depth provides sufficient depth for kick tolerance while drilling through to the next casing point. Either 9-5/8" or 7 5/8" surface casing strings will be cemented to surface using lead slurry of lightweight permafrost cement, followed by tail slurry in a single stage. No hydrocarbon bearing intervals have been encountered to this depth in previous wells. ~. The casing head and blowout preventer stack will be installed and tested consistent with Commission requirements. A Leak-Off Test (LOT) or Formation Integrity Test (FIT) will be performed upon drilling no more than 50' beyond the surface casing shoe in accordance with 20 AAC 25.030(f). Production casing will be set near the base of the injection zone and cemented across and not less than 500 feet measured depth above the Alpine. ~ Cement Quality Evaluation Prior to running the completion, a cement quality log will be run to verify the cement quality and top of cement behind the production casing. Completion Design Single tubing strings, 2-7/8" up to 4-1/2" OD, will be installed in each well. Isolation of the tubing by casing annulus will be carried out within 200' of the top of the uppermost inj ection interval. This isolation will be provided by use of either a permanent hydraulic set packer or a polished bore receptacle / seal assembly combination (in the case of a mono-bore completion). Subsurface safety valves will be installed below the permafrost depth. At this time there are no specific plans in place for mandrels or other freeze protection hardware, although they may be added at a future date. In addition to conventional perforated completions, additional designs may be presented for administrative approval after submitting and presenting data demonstrating that such alternatives are based on sound engineering principles. Abandonment All abandonment procedures will be performed following Commission approval in accordance with 20 AAC 25.105. ~ ~ 11 .,,,-",, - Waste Sources and Characteristics - 20 AAC 25.252 (c) 7 ~ Class II disposal wells are defined as wells which inj ect wastes brought to the surface in connection with oil and gas production, with natural gas or liquid hydrocarbon storage operations. Class II fluids may be mixed with other wastes from plant operations, unless those wastes are classified as hazardous waste under 40 CFR 261.3. - Typical RCRA exempt wastes which are acceptable for injection can include the following: - - Drill Cuttings, Drilling fluids, Cement fluids, Completion fluids, W orkover fluids, Stimulation fluids, Frac Sand, Produced Water, Crude Oil, Production Vessel Sludge/Sand, Fresh or Sea Water, Natural Gas Liquids, Rig Wash, Well Cellar Fluids, and others allowed under 40 CFR 261.4. ~ - Typical Injection Rates and Volumes Exempt wastes routinely generated by drilling, well workovers, contaminated crude oil, vessel sludge/sand, diesel/methanol usage, spent acid, fracturing operations, snow melt, and plant upsets could total 4 million barrels over the life of the field. These fluids will be disposed of into wells located on the drilling pad, such as WD-04 and CDl-19A. Each well could potentially dispose of 2-3 million barrels of fluid over their life. Daily injection volumes are not expected to exceed 2,500 bbl., and rates are not expected to exceed 5 BPM. - Produced water disposal could reach 14 million barrels before produced water (PWI) handling facilities are commissioned to commence waterflood re-injection of produced water. This potentially 18 million-barrel waste stream is currently destined for injection into well WD-02. Expectations are that wells WD-O 1 and WD-03 will be drilled to - 12 .- provide disposal capacity as necessary prior to initiating PWI injection in the waterflood. Each of those wells could receive 3-5 million barrels of produced water injection at rates not expected to exceed 5 BPM. -- There is concern that high density slurries will screen-out or plug a Sag River/Ivishak well rendering a disposal interval useless. Therefore the disposal of drilling mud and cuttings will be performed with sufficient volumes of water to maintain slurry densities which maintain cuttings transport. Large solids may be captured and washed for reclamation by the grind and inject facility associated with the drilling rig. ~ - - """'" 13 "- ",..,. Injection Pressure 20 AAC 25.252 (c) 8 .- - """" The following table shows the range of injection pressures that are estimated to occur through the life of a single well over many years. They reflect behavior of the tighter Ivishak formation since the Sag River is clean sand with significantly better porosity and permeability. The Ivishak sand intervals containing clay, are tightly cemented, and are interspersed with enough shale stringers that it may be difficult to push dirty fluids into a completion interval for an extended period. The smaller pore throats will progressively become plugged in the region around the wellbore. This damage zone will restrict well injectivity so that in order to maintain the required disposal rate, it will be necessary to stimulate or fracture past the restriction. It is anticipated that near-wellbore fractures will be required to establish new flow paths to undamaged rock. The projected pressures reflect what is expected to occur because of variations in lithology and changes in the well injectivity index with time. Should use of the Sag River formation be required, fracturing would be much less prevalent. Further discussion on fracturing is included in the next section. Surface In.iection Pressure Early time frame: No fracturing of the injection zone required but assumes zones are originally slightly over pressured. 1700 psi Several years into field life: Some fracturing of the near wellbore region may occur to get past early plugging caused by dirty fluids. Assumes a clean sand fracture gradient of 0.65 psi/foot. 2200 psi Later in field life: Fracturing of the near wellbore region is required. Assuming a tighter shaley/sand fracture gradient of 0.70 psi/foot and a higher injection rate, this level of pressure is required to overcome estimated fracture mechanics and tubing frictional losses. 3000 psi Maximum inj ection pressure: This generates a static fracture gradient ranging from 0.77 - 0.80 psi/ft. If friction losses are taken into account these gradient values would be smaller. 3200 psi. - 14 - Waste Confinement 20 AAC 25.252 (c) 9 ~ This section discusses potential confinement issues, how these issues will be addressed, and how they will be handled in the unlikely event that problems occur. ~ Un cemented Wellbores The Permo-Triassic and Jurassic Formations represent the deepest active reservoirs in the Colville River Unit. As such, the only wellbores penetrating this interval are for disposal purposes and fully cemented throughout both the injection and confining intervals. There are no past, present, or planned penetrations in this interval that will provide communication channels to shallower horizons. ~ Wellbore Channeling No oil reservoir development wells will penetrate the confining zone. Production well casing strings will be cemented across the oil reservoir and 500-1000 feet into the shale that overlays it. There is no confinement risk associated with wellbore leakage due to development wells. The only leakage that could occur would be associated with channeling adjacent to an injection well. Tracer, temperature, or water flow log detection would be followed by squeeze cementing to repair the channel. Verification of the repair by pressure testing and logging would follow. ~ Natural Faulting As shown on the structure maps, and on Exhibit 7, there are normal faults cutting the injection and arresting zones in the local area. They are minor compared to the thickness of the overlying Kingak shale. At this depth, sand intervals will generally produce a rubble zone that permits flow along the fault plane; however, brittle shales typically do not follow this pattern. Experience has shown that it would take a very large pressure differential to create flow along a normal fault where dense shales are juxtaposed against each other. - ~ At Prudhoe Bay, major faults extend from the main oil/gas reservoirs at +/- 8500 feet to the Cretaceous water disposal zone at +/ - 6000 feet. With a large gas cap present in the Ivishak, obviously there was no upward gas migration or the Kingak shale would not have become the cap rock for hydrocarbon accumulations. By the end of 1996, the main oil reservoir pressure had declined 1000 psi. Conversely, the over lying Cretaceous aquifers have been over-pressured several hundred psi due to a billion barrels of produced 15 ~ water disposal. This imbalance creates a pressure gradient of over 0.4 psi/ft (1000 psi/2500 feet). No cross flow has been detected from the Cretaceous zone. - Fracturing of the Confining Zone Wellbore damage is expected to accumulate from the periodic disposal of dirty fluids. This will necessitate wellbore stimulations and near-wellbore fracturing to inject past the damaged zone while maintaining effective disposal rates. Fractures are not expected to be laterally extensive since fluid leak off will be rapid once new rock is contacted. <i..~ Due to boundary lithology contrasts, fracturing will be vertically contained. Poisson's Ratio has been derived from dipole sonic logs of wells WD-02 and Fiord #1. They support a fracture gradient in the Lower Kingak of 0.76 psi/ft. The fracture gradient measured in well WD-02 and reported in the EPA Completion Report, dated 4/19/1999, was 0.66 psi/ft. With the shales fracturing at a gradient of 0.76 psi/ft, and disposal interval sands at 0.66 psi/ft, the stress contrast is 0.10 psi/ft. At an arresting zone base depth of 8,650 feet SS, this generates a stress contrast of 865 psi. This suggests that fractures initiated in the Sag River Formation could not penetrate the overlying Kingak shale. Even assuming limited vertical fractures grew upward from the Sag River, it is highly unlikely they could penetrate the 660 feet of Kingak confining zone and reach even the Alpine. Confinement risk associated with fracturing is minimal. >~ Comparison With Similar Projects There are similar but no direct comparisons with other North Slope disposal projects because dirty water/wastes have not been injected into these formations on a long-term basis. However, since 1985, produced water and seawater injected into 206 Prudhoe Bay Sag River and Ivishak wells has totaled 6.146 billion barrels. At the Endicott field, 506 million barrels has gone into 26 wells and at the new Pt. McIntyre field, 205 million has gone into 13 wells. The average per well ranges from 30 MMB at Prudhoe to 16 MMB at Pt. McIntyre. Many of the above wells have minor fracture systems associated with their injection zone, some caused by thermal fracturing due to injection of cold surface waters and others by fracturing past wellbore damage zones. Some of the fractures are permanent and others probably open and close. In the rare case where injected fluids are not confined to the desired sub-interval, it is usually associated with a poor casing cement job. Fluids are confined within the Ivishak gross section. ~ Summary The risk of non-confinement of injected wastes must be viewed as minimal to non- existent. A competent confining zone and successful large scale water injection at other locations, coupled with proper well monitoring, all indicate wastes can be confined without environmental damage. - 16 .--. ~ Formation Water Salinity 20 AAC 25.252 (c) 10 - - Salinity Calculations In the Alpine project area only the Nechelik #1 well has been logged from surface through the injection zone. No clean sands were encountered above the confining zone; however, the Alpine #1 well did cut some thin Albian sands at 5150-5204 feet and Bergschrund #1 found a thin shelf sand at 4220 feet. Salinity calculations made on available intervals resulted in the following. · Bergschrund # 1 (4220 feet) 15,000 ppm NaCI eq. · Alpine # 1 (5150-5204 feet) 15,000 ppm NaCI eq. · N echelik # 1 (Sag River FOffilation) 18,000 ppm NaCI eq. - · Nechelik #1 (Ivishak FOffilation) 17,000 ppm NaCI eq. The methodology used and results obtained from salinity calculations on the Albian/Nanushuk Shelf sand stringers (Alpine #1 and Bergschrund #1), Sag River, and Ivishak FOffilations (Nechelik #1 well) are as follows. The calculations use the standard Archie correlation and log derived data to obtain an Rwa value using the following fOffilula: Rwa = (porosity) m (Rt) / a ........... with the following definitions: ~ Rwa Porosity Rt m a Resistivity of water necessary to make a zone 100 % wet Porosity in decimal from logs FOffilation resistivity from logs Cementation exponent Assumed to be 1.0 per the Archie correlation The cementation exponent is the variable of least certainty. The best source for deteffilining this value is from special core analysis (SCAL) when available. No SCAL is available for the Albian interval; however, such data does exist for analogous fine to very fine grain sand in the area. This data has yielded: ~ 17 '~' Alpine section SCAL from the Alpine # 1 well Sag River SCAL as documented in ARCa TSR 95-46, internal report m = 1.55 m = 1.6 The following exponents will be used in these salinity calculations. - Shallow intervals (4000- 5000 feet) Sag River Formation Ivishak Formation m = 1.6 m = 1.7 m = 1.8 ~ · Nanushuk Shelf Sand: (Bergschrund #1 well depth 4220 feet) This shelf sand is evident in two wells at approximately 4200 feet subsea. - Rt = 4.0, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The calculation yields an Rwa equal to 0.356. Using Schlumberger Chart Gen-9 and a formation temperature of80 degrees F, gives a salinity of 15,000 ppm NaCl equivalent. - · Albian Interval: (Alpine #1 well depth 5150-5204 feet) There is a collection of thin sands in this well and a complete set of logs is available. Rt is taken from the shallow MWD tool because of minimum exposure time to invasion and superior vertical resolution in three foot thick beds. Porosity comes from the density log. Rt = 3.2, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 ~ The Calculation yields an Rwa equal to 0.293. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 100 degrees F, gives a salinity of 15,000 ppm N aCl equivalent. · Sag River Formation: (Nechelik #1 well depth 8432-8480 feet) This is a thick, clean, uniform sand interval with a complete set of logs. Rt = 1.9, Raw density = 2.32, m = 1.7, Porosity = (2.65-2.32) / (2.65-1.0) = 0.20 - The calculation yields an Rwa of 0.145 and with a formation temperature of 165 degrees F, produces a salinity value of 18,000 ppm NaCl equivalent. - ~ - 18 · Ivishak Formation: (Nechelik #1 well depth 9420-9460 feet) This lower sand member has the lowest resistivity and greatest SP excursion. Rt = 3.3, Raw density = 2.35, m = 1.8, Porosity = (2.65-2.35) / (2.65-1.0) = 0.18 The calculated Rwa equals 0.15 and with a formation temperature of 185 degrees F, a salinity of 17,000 ppm NaCI equivalent is obtained from the Schlumberger chart. ~ Water Sample Analyses The following water samples were obtained from drill stem and production tests in the general Colville Delta area. · Colville #1 well 7922 feet · 14 miles Northeast · 22,485 mg/l TDS (tested) Shublik Formation · Colville # 1 well 9073 feet · 14 miles Northeast · 24,004 mg/l TDS (tested) Lisburne Formation · Kalubik #1 well 5050-5250 feet Albian Interval · 17 miles Northeast · Flowed 151 barrels to surface · 24,300 mg/l TDS (average of tests) ~ · Kalubik Cr. #1 well 9047-9188 · 21 miles East · Flowed 325 barrels of water · 21,847 mg/l TDS (tested) Lisburne Formation · Mukluk well 7490-7520 Ivishak Formation · 23 miles North · Flowed 984 barrels of water · 11,000 ppm chloride tested · 18,150 mg/l TDS (calculated) ...... 19 '- ~ · Mukluk well 8145-9860 Lisburne Fonnation · 23 miles North · Flowed 1750 barrels of water · 11,000 ppm chloride tested · 18,500 mg/l TDS (calculated) Laboratory data and other reports can be made available if desired. Reference is also made to the Class I Well Pennit Application, Appendix D, previously submitted to the Commission in September 1997. ~ ~ 20 ~ Aquifer Exemption 20 AAC 25.252 (c) 11 Aquifer Exemption No underground sources of drinking water (USDW) have been identified within the Colville River Unit area. In the absence ofUSDW's, an aquifer exemption is not applicable. ~ ~ - ~ 21 \~ - Offset Well Status 20 ACC 25.252 (12) ~ - There are only 3 wells currently penetrating the disposal interval within 1/4 mile of the Colville River Unit boundary. Well WD-02 operates under Disposal Order No. 18 and an EP A Class I permit. It is currently disposing of camp waste in the Ivishak. Mechanical integrity is demonstrated annually. Completion reports are on file with the Commission, and additional information will be provided upon request. The Fiord #1 (Permit #91-147) is an exploration well drilled and abandoned in 1992. It's completion report and abandonment schematic are on file with the Commission, and additional information will be provided upon request. The Sohio Nechelik #1 an early exploration well drilled and abandoned in the 1980's. No corrective actions at this time are planned for any of the above wells in preparation for additional drilling. ~ ~ 22 ---------..----..--.... Colville River Unit Location Map LPINE River Unit I I I I I I I I I I I I I I I I I I I 200 E 327 ft gross -------..----------- Exhibit 4 ARCO Alaska Inc. Alpine Project Seismic Section SW - NE Transect ------------------- Structure Map Kingak Depth ------------------- Structure Map Sag River Depth ---..-..------------- Structure Map Lisburne Depth I I I I- I I I I I I I I I I I I I I I Class II Exhibit 8 roposed Completion Diagram 9-5/8" to Surface Casing set below 2200' and cemented to , , , , , , , , , , , , , , , , ! > : ¡ i : ! : t ¡ i i ! ¡ Drilling Mud TOC @ +/-6600' TVD (500' above Alpine Reservoir) 16" Conductor below 75' MD Base Permafrost @ +/-1500 ft TVDss~ Subsurface Safety Valve (SSV) below the Permafrost at +/-1700' TVD 2-7/8" up to 4-1/2" tubing to the packer Packer Fluid: 8.6 ppg KCL brine with diesel freeze protection to +/-2000' Permanent Packer set within 200' of the injection interval top to 7" Intermediate Set in or below the Sadlerochit and cemented above the Alpine Injection perfs River and Sadlerochit I I I I I I I I I I I I I I I I I I I . . Exhibit 9 - Wellhead Schematic 10.5 " f I . . I Exhibit 10 I Alpine Injection Order I Affidavit of Michael D. Erwin STATE OF ALASKA I THIRD JUDICIAL DISTRICT I I, Michael D. Erwin, declare and affmn as follows: 1. I am the Alpine Production Engineer for ARCO Alaska, Inc., the designated operator of the Colville River Unit (which includes the Alpine Pool). 2. On February 3,2000, I caused copies of the Area Injection Order Application to be provided to the following surface owners and operators of all land within a quarter-mile radius of the proposed injection area: I I Operator: ARCO Alaska, Inc. Attention: Mr. Mark Ireland P.O. Box 100360 Anchorage, AK 99510-0360 I I Surface Owners: State of Alaska Department of Natural Resources Division of Oil and Gas P.O. Box 107034 Attention: Mr. Mike Kotowski Anchorage, AK 99510 I I Kuukpik Corporation Attention: Mr. Isaac Nukapigak P.O. Box 187 Nuiqsut, AK 99789-0187 I I Dated: fehWC\f13> ,2000. ~/v .?~" I ~~{Mk l). Ú~ Micna .1 D. Erwin I .-("/) r . Declared and affirmed before me this ;)-- day of íW(ùJ,..'~:J ,2000. I I \.\.\1 (((í(fff/" <\\ . E. HO, I'"/",...- \.':-\~' . . . . . "(.." r;-- ~ <Ç>-.' --- . . "';;.-::::- ~~·~O"ARY:,.¢~ ,'C{. ~ --- .;2:.- ......~ ~ ::: : PUB\..\C, : *~ ~*.. .-- ~ ~ ... : ~ -=-- ". ....J...~:Y ~./ ffiìÉ 'OF' ~\.t>-':I~\\' /J)})})))}))) ~)¿-~t-~ Notary Pu c ill and for Alaska My commission Expires: '?j·t \ -5 l20C ¡ I I