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Home My WebLink AboutAIO 004 A ) ) Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. r r() ()()Lf À Order File Identifier Organizing (done) ~wo-sided 1111111111111111111 0 Rescan Needed 1111111111111111111 RES CAN DIGITAL DATA OVERSIZED (Scannable) o Maps: o Other Items Scannable by a Large Scanner o Color Items: o Greyscale Items: o Diskettes, No. D Other, No/Type: o Poor Quality Originals: NOTES: OVERSIZED (Non-Scannable) ~09S of various kinds: o Other:: o Other: BY: ( ~aria ) Date: If-. 10 I oh /5/ 'ryyD 1111111111111 III mJ Project Proofing BY: ér-. Maria J Date: 4:1 0 I () (" /5/ Scanning Preparation BY: <: Maria) x 30 = + Date: Lf. I () / 0 to = TOTAL PAGES a~O (Count does not include cover Sheet)V\/\.n /5/ I Y VI 111111111111111111I Production Scanning Stage 1 Page Count from Scanned File: a (P (p (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES BY C:Maria') Date: if I tD /o/r; Stage 1 If NO in stage 1 page(s) discrepancies were found: YES NO 151 VVV'"' NO BY: Maria Date: /s/ 1111111111111111111 Scanning is complete at this point unless rescanning is required. ReScanned 11111111111111111 BY: Maria Date: Isl Comments about this file: Quality Checked 11I1III111111111111 10/6/2005 Orders File Cover Page. doc INDEX AREA INJECTION ORDER NO. 4A Point McIntyre 1) December 30,1992 Ltr from AOGCC to ARCO 2) April 5, 1993 Arco's Application for Modification to AIO 4 3) April 9, 1993 Notice of Hearing, Affidavit of Publication 4) April 22, 1993 Ltr from Copeland to AOGCC re: Extension of Protest Period for Application for Modification of AIO 4 5) April 27, 1993 Ltr from DNR to the AOGCC re: application 6) April 27, 1993 Ltr to Copeland from AOGCC re: Request for extension of time 7) October 4,1996 Notice of AOGCC re: Application being revised 8) July 5, 1994 Ltr from AOGCC to ARCO Re: UIC -Use of treated effluent as EOR fluid 9) November 15, 1995 Agenda for Meeting 10) December 1, 1995 Ltr from AOGCC to BP re: Endicott and Milne Point Class II Fluids 11) April 22, 1996 Ltr from AOGCC to BPXA re: Request for Approval- Material to Facilitate Disposal of Cuttings in a Class II well 12) May 2, 1996 Ltr from Arco to AOGCC re: Class II Oily Waste Pilot Testing 13) July 8, 1996 . Arco Alaska Field Environmental Compliance 14) July 12, 1996 Ltr from Arco to AOGCC 15) April 4, 1997 Ltr re: Classification of Spill Cleanup Material Drillsite 16 8 flowline spill 16) July 1, 1997 Ltr ffrom ARCO re: Approximate Rig Wokover costs for 12-23, 17-08 and PWDW 3-1 17) October 24, 1997 Letter regarding Reserve Pit Close Out Operations 18) November 3, 1997 Ltr from ARCO to AOGCC re: Reserve Pit Close Out Operations AREA INJECTION ORDER 4A All Annual reports are located in the Field Files • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 -3192 Re:The REQUEST OF ARCO ALASKA, ) Area Injection Order No. 4A INC., to modify Area Injection ) Order 4 to include the Point ) Eastern Operating Area Prudhoe McIntyre, Stump Island and West ) Bay Unit and Pt. McIntyre Field Beach oil pools for the purpose of ) conducting enhanced recovery and ) disposal of Class II fluids. ) August 12, 1993 Rev. October 4, 1993 IT APPEARING THAT: 1. Arco Alaska, Inc. (ARCO) by correspondence dated April 5, 1993 made application to the Alaska Oil and Gas Conservation Commission (hereinafter Commission) to modify Area Injection Order No. 4 (AIO #4) to permit the underground injection of fluids for enhanced oil recovery and disposal of Class II fluids in support of production and development of the Pt. McIntyre, Stump Island and West Beach oil accumulations. 2. Notice of an opportunity for public hearing was published in the Anchorage Daily News on April 9, 1993. 3. A request for extension of the public protest period was filed on April 22, 1993 by Copeland, Landye, Bennett and Wolf on behalf of George and Larry Ahmaogak. 4. By letter dated April 27, 1993, the Commission extended the public protest period to 4:00 PM, May 3, 1993. 5. By letter dated April 27, 1993, the Department of Natural Resources requested that any decision to modify Area Injection Order No. 4 to accommodate a proposed Pt. McIntyre participating area in the Prudhoe Bay Unit be deferred until after approval of a participating area by the state. 6. No other protest or request for a public hearing was filed. FINDINGS: 1. Commission regulation, 20 AAC 25.460, provides authority to issue an order governing underground injection operations on an area basis for all wells within the same field, facility site, reservoir, project or similar area. ' Area Injection Order No. • August 12, 1993 Revised October 4, 1993 Page 3 12. Production from the Pt. McIntyre, Stump Island and West Beach oil pools will be commingled with production from other pools and processed at the Lisburne Production Center (LPC). 13. Disposal injection in the Pt. McIntyre oil field will occur within the Colville Group /Sagavanirktok formation which correlates with the 1,900' to 6,750' measured depth interval in the Sag River State No. 1 well. This interval is underlain by an Upper Cretaceous marine, predominately shale sequence approximately 1,600' to 2,000' thick. The interval is overlain by Tertiary shale and mudstone beds 10 to 50 feet thick which act as vertical permeability barriers and approximately 1,800' of permafrost which isolates the disposal interval from surface waters. 14. No injection wells currently exist in the Pt. McIntyre oil field. ARCO's application includes proposed locations and mechanical configurations for currently planned injectors, and the locations of all existing and abandoned wells within the field. 15. None of the existing or proposed injection wells in the Pt. McIntyre oil field are within one - quarter mile of the affected area as defined under Conservation Order No. 317. 16. All operators and surface owners within a one - quarter mile of all proposed injection wells in the Pt. McIntyre oil field have been duly notified of the proposed injection project. 17. Fracture gradients are estimated to range from approximately .55 to .65 psi/ft for receiving formations and from .80 to .90 psi/ft for confining formations in the Pt. McIntyre oil field. 18. Formation water salinity is estimated to range from approximately 12,000 ppm to more than 20,000 ppm for all aquifers in the Pt. McIntyre oil field. 19. Laboratory testing indicates proposed enhanced recovery fluids are compatible with receiving formations. Some increase in the concentration of hydrogen sulfide gas in the Pt. McIntyre oil pool may be expected from the introduction of commingled gas and produced water streams from the LPC. 20. Initial enhanced recovery plans for the Pt. McIntyre oil pool call for 16 water injection wells and two gas injection wells. Initial waterflood pattern will be an inverted 9 -spot utilizing source [PRODUCED] water. 21. Enhanced recovery plans for the Stump Island oil pool will be evaluated on a well - by -well basis in conjunction with Pt. McIntyre oil pool development. No actual proposal has been submitted to the Commission for enhanced oil recovery operations in the Stump Island oil pool. · '- STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re:The REQUEST OF ARCO ALASKA, IN C ., to modify Area Injection Order 4 to include the Point McIntyre, Stump Island and West Beach oil pools for the purpose of conducting enhanced recovery and disposal of Class II fluids. IT APPEARING THAT: ) ) ) ) ) ) ) Area Injection Order No. 4A Eastern Operating Area Prudhoe Bay Unit and Pt. McIntyre Field August 12, 1993 1. Arco Alaska, Inc. (ARCO) by correspondence dated AprilS, 1993 made application to the Alaska Oil and Gas Conservation Commission (hereinafter Commission) to modify Area Injection Order No.4 (AlO #4) to pennit the underground injection of fluids for enhanced oil recovery and disposal of Class II fluids in support of production and development of the Pt. McIntyre, Stump Island and West Beach oil accumulations. 2. Notice of an opportunity for public hearing was published in the Anchorage Daily News on April 9, 1993. 3. A request for extension of the public protest period was filed on April 22, 1993 by Copeland, Landye, Bennett and Wolf on behalf of George and Larry Ahmaogak. 4. By letter dated April 27, 1993, the Commission extended the public protest period to 4:00 PM, May 3,1993. 5. By letter dated April 27, 1993, the Department of Natural Resources requested that any decision to modify Area Injection Order NO.4 to accommodate a proposed Pt. McIntyre participating area in the Prudhoe Bay Unit be deferred until after approval of a participating area by the state. 6. No other protest or request for a public hearing was filed. FINDINGS: 1. Commission regulations, 20 AAC 25.460, provides authority to issue an order governing underground injection operations on an area basis for all wells within the same field, facility site, reservoir, project or similar area. Area Injection Order NO.tJt August 12, 1993 Page 2 , 2. AlO #4, issued July 11, 1986, authorizes area injection for a "project area" described as the Eastern Operating Area of the Prudhoe Bay Unit. The project area encompasses approximately the eastern half of the Prudhoe Bay oil pool and all of the Lisburne oil pool. 3. AlO #4 establishes the vertical limits of injection for enhanced recovery operations in both the Prudhoe Bay and Lisburne oil pools and for disposal into Cretaceous and Tertiary strata. The vertical limits of injection and confining strata may be defined in the ARCO Prudhoe Bay State No. 1 and ARCO Sag River State No. 1 wells. 4. ARCO is operator of the eastern half of the Prudhoe Bay oil pool and the Lisburne oil pool. 5. The Commission issued Conservation Order No. 311 classifying the West Beach oil pool in the Prudhoe Bay field. The West Beach oil pool is composed of the Kuparuk River formation, and is defined as strata common to and which correlate with the interval between 14,548' and 14,781' measured depth in the West Beach NO.4 well. 6. The West Beach oil pool underlies the AlO #4 project area. 7. The mineral interest owners of the West Beach oil pool have designated ARCO as operator of the pool. 8. Development and depletion plans for the West Beach oil pool are uncertain at this time. Depending on the size of the pool, the operator proposes three possible depletion strategies: solution gas drive, processed gas injection, and/or waterflood. No actual proposal has been submitted to the Commission for enhanced oil recovery operations in the pool. 9. The Commission issued Conservation Order No. 317 classifying the Pt. McIntyre oil pool and the Stump Island oil pool in the Pt. McIntyre oil field. The Pt. McIntyre oil pool is composed of the Kuparuk River and Kalubik formations, and is defined as strata common to and which correlate with the interval between 9,908' and 10,665' measured depth in the Pt. McIntyre No. 11 well. The Stump Island oil pool is composed of the Seabee formation, and is defined as strata common to and which correlate with the 8,759' to 8,930' measured depth interval in the Pt. McIntyre No.3 well. 10. A portion of the Pt. McIntyre oil field underlies the AlO #4 project area. 11. The mineral interest owners of the Pt. McIntyre oil field have designated ARCO operator of both the Pt. McIntyre and Stump Island oil pools. Area Injection Order NO" August 12, 1993 Page 3 , 12. Production from the Pt. McIntyre, Stump Island and West Beach oil pools will be commingled with production from other pools and processed at the Lisburne Production Center (LPC). 13. Disposal injection in the Pt. McIntyre oil field will occur within the Colville Group/Sagvanirktok formation which correlates with the 1,900' to 6,750' measured depth interval in the Sag River State No.1 well. This interval is underlain by an Upper Cretaceous marine, predominately shale sequence approximately 1,600' to 2,000' thick. The interval is overlain by Tertiary shale and mudstones beds 10 to 50 feet thick which act as vertical permeability barriers and approximately 1,800' of permafrost which isolates the disposal interval from surface waters. 14. No injection wells currently exist in the Pt. McIntyre oil field. ARCD's application includes proposed locations and mechanical configurations for currently planned injectors, and the locations of all existing and abandoned wells within the field. 15. None of the existing or proposed injection wells in the Pt. McIntyre oil field are within one-quarter mile of the affected area as defined under Conservation Order No. 317. 16. All operators and surface owners within a one-quarter mile of all proposed injection wells in the Pt. McIntyre oil field have been duly notified of the proposed injection project. 17. Fracture gradients are estimated to range from approximately .55 to .65 psi/ft for receiving formations and from .80 to .90 psi/ft for confining formations in the Pt. McIntyre oil field. 18. Formation water salinity is estimated to range from approximately 12,000 ppm to more than 20,000 ppm for all aquifers in the Pt. McIntyre oil field. 19. Laboratory testing indicates proposed enhanced recovery fluids are compatible with receiving formations. Some increase in the concentration of hydrogen sulfide gas in the Pt. McIntyre oil pool may be expected from the introduction of commingled gas and produced water streams from the LPC. 20. Initial enhanced recovery plans for the Pt. McIntyre oil pool calls for 16 water injection wells and two gas injection wells. Initial waterflood pattern will be an inverted 9-spot utilizing produced water. 21. Enhanced recovery plans for the Stump Island oil pool will be evaluated on a well- by-well basis in conjunction with Pt. McIntyre oil pool development. No actual proposal has been submitted to the Commission for enhanced oil recovery operations in the Stump Island oil pool. Area Injection Order NO" August 12, 1993 Page 4 , 22. Maximum injection rates for enhanced recovery operations in the Pt. McIntyre oil pool are currently estimated to be about 500 MMSCF/D gas and 250 MBPD water. 23. Incremental hydrocarbon recovery of approximately 160 MMS TB is expected rrom the Pt. McIntyre waterflood and gas injection project. 24. To accommodate Pt. McIntyre, Stump Island and West Beach production, additional produced water disposal wells will be drilled at or near the LPC. The maximum combined disposal rate of produced water rrom the LPC will increase to about 240 MBPD. To accommodated disposal of exempt Class II wastes, a cuttings disposal well may be drilled at Pt. McIntyre Drill Site P2 (DS-P2); this well would have an estimated maximum disposal rate of about 2,000 BPD. 25. Estimated maximum and average injection pressures (psig) for Pt. McIntyre gas injection are 5000 psi and 4300 psi; for Pt. McIntyre water injection, 2850 psi and 2450 psi; and for Pt. McIntyre DS-P2 disposal, 1000psi and 500 psi. 26. The operator proposes to monitor tubing-casing annulus pressures of all injection wells at least weekly to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 27. All existing wells drilled within the Pt McIntyre oil field have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the Pt. McIntyre oil field have been abandoned in accordance with 20 AAC 25.105. CONCLUSIONS: 1. An order permitting the underground injection of Class II fluids on an area basis, rather than for each injection well individually, provides for efficiencies in the administration and surveillance of underground fluid injection operations. 2. The area authorized for injection operations under an area injection order has no inherent relationship to, nor affect on, the area of participation formed by the mineral interest owners and approved by the state for pool development. 3. Authorizing the underground injection of fluids on an area basis into the West Beach and Stump Island oil pools will be appropriate when injection operations are actually proposed. 4. Area Injection Order No.4 may be reissued to include the Pt. McIntyre oil field on the basis of common production facilities and a single operator. 5. Reissuing Area Injection Order No.4 to include the Pt. McIntyre oil field area is appropriate for authorizing injection of fluids for enhanced recovery operations in the Pt. McIntyre oil pool. Area Injection Order No1)t August 12, 1993 Page 5 , 6. Reissuing Area Injection Order No.4 to include the Pt. McIntyre oil field area is appropriate for authorizing injection of Class II fluids for disposal operations in support of development and production of the Pt. McIntyre oil pool. 7. Injection operations in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field will be conducted in permeable strata which can reasonably be expected to accept injected fluids at pressures less than the ftacture pressure of the confining strata. 8. Injection of Class II fluids for purposes of enhanced oil recovery and disposal operations in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field will occur in a manner that will prevent movement of fluids into sources of ftesh water and will improve ultimate recovery. 9. Authorizing the injection of fluids on an area basis for the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field will not cause waste nor jeopardize correlative rights. 10. No underground sources of drinking water (USDWs) are known to exist in the Eastern Operating Area of the Prudhoe Bay Unit and the Pt. McIntyre oil field. NOW, THEREFORE, IT IS ORDERED THAT Area Injection Order #4 is repealed and reissued as Area Injection Order No. 4A with the following rules to govern Class II injection operations in the affected area described below: UMIAT MERIDIAN T12N R14E Sections 22, 23, 24, 25, 26, 35, and 36. T12N R15E Sections 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. T12N R16E Sections 28, 29, 30, 31, 32, 33, and Section 34: W 1/2 NW 1/4, SW 1/4, SW 1/4 SE 1/4 T11N R14E Sections 1,2,9,10,11,12,13,14,15,16,21,22,23, 24, 25, 26, 27, 28, 33, 34, 35, and 36. T11N R15E Entire Township. T11N R16E Section 2: SW 1/4 NW 1/4, SW 1/4, S 1/2 SE 1/4, Sections 3, 4, 5, 6 , 7, 8, 9, 10, 11, Area Injection Order NO. August 12, 1993 Page 6 , Section 12: NW 1/4, S 1/2 NE 1/4, SE 1/4, SW 1/4 Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 28, 29, 30, 31, 32, and 33. Tl0N R14E Sections 1,2,3,4,9,10,11,12,13,14,15,16,21, 22, 23, 24, 25, 26, 27, 28, and 36. Tl0N R15E Entire Township. Tl0N R16E Sections 4, 5, 6, 7, 8, 9, 16, 17, 18, 19, 20, 29, 30, and 31. T12N R15E Section 18 T12N R14E Sections 3, 4, 9, 10, 13, 14, 15, 16, Section 17: NE 1/4, N 1/2 SE 1/4, E 1/2 E 1/2 NW 1/4, E 1/2 NE 1/4 SW 1/4, Section 21: N 1/2 NE 1/4, Those Lands in Block 605 lying northerly of the north boundary of Section 3, TI2N, RI4E, UM, AK.. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Sections 2 and 11, TI2N, RI4E, UM, AK. (Identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, TI2N, RI4E, UM, AK., and lying northerly of the south boundary of Section 7, TI2N, RISE, UM, AK. (Identical with line 6-7 on Block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79, containing 1457.32 hectares. Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, Class II fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the formations found in ARCO Prudhoe Bay State No. 1 well between the measured depths of 8, 110 - 8,680 feet for the Prudhoe oil pool and between the measured depths of 8,790 - 10,440 feet for the Lisburne oil pool and in the Pt. McIntyre No. 11 well between the measured depths of9,908 - 10,665 feet for the Pt. McIntyre oil pool. Rule 2 Authorized Injection Strata for Disposal Within the affected area, Class II waste fluids may be disposed by injection into strata defined as those which correlate with and are common to the strata found in ARCO Sag River State Well NO.1 between the measured depths of 1,900 - 6,750 feet. Area Injection Order Nolll August 12, 1993 Page 7 , Rule 3 Fluid Injection Wells The injection of fluids must be conducted: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005~ 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280~ or 3) through a well that existed as a service well for injection purposes on the date of this order. Rule 4 ·Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure 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 Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission. Rule 6 Demonstration of Tubing-Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission which ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength must be held for at least a 30 minute period with decline less than or equal to 10% of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 7 Well Integrity Failure Whenever operating pressure observations 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 to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval. Rule 8 Plugging and Abandonment ofInjection 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. August 12, 1993 Page 8 Rule 9 Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste nor jeopardize correlative rights, is based on sound engineering principles and will not result in an increased risk of fluid movement into a USDW. £?A~døa ~ ~ Russell A. Douglass, Co slOner Alaska Oil and Gas Conservation Commission ¿ -:::::> I/I.>'!L/(..~_~~~V(_~~ uckerman Babcock, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of entry of an order, a person affected by it may file with the Commission an application for rehearing. The Commission shall grant or refuse the application in whole or in part within 10 days. 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 can refuse an application by not acting within the 10- day period. An affected person has 30 days ftom 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 ftom the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). #18 , I ARCO Alaska. Inc.. :::ost Office Box I 00360 :;nchorage Alaska 9951 O-O~)60 Teiephone 907 276 1215 -. -;/' ~ ~~ ~~ David W. Hanson Staff Permit Coordinator Prudhoe Bay/GPMA (ATO-1968) 907-263-4745 907-263-4334 (fax) .COMM COMM COMM RES ENG SR ENG 9Ò NRO \¡V~ SR GEOL þø¿ GEOL A.SSr ¡~ STAT rECH STAT TECH Co November 3, 1997 David W. Johnston Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, AK 99501 FILE RE: Prudhoe Bay Unit, Eastern Operating Area Area Injection Order #4A Reserve Pit Close Out Operations Dear Mr. Johnston: On October 24, 1997 a letter detailing changes in the Grind and Inject (G&I) Project was sent to you. This letter was intended as an update to the 1986 Area Injection Order (AIO) for the Eastern Operating Area of the Prudhoe Bay Unit, the 1993 Application for an Amendment to AIO #4, and related correspondence. This letter referenced four attachments that were inadvertently omitted. These four attachments are enclosed with this letter. Our apologies for any inconvenience that this may have caused. If you have any questions, please call me at 265-4745. Sincerely, \0~~ Gà\~ David W. Hanson Attachments ARCO Alaska. Inc. is a Subsidiary of Atlantic Richfield Company C,R3B-6003-C 1~1f~-' , ~\~~~~;~",~~...1t .....'.__I.,.,C!t ~1"':I.'htlf -.I[ .~:l"" Uha~~. mr.,.. LIII.·C.O!'''O~)T£-lP"OL£ . ~Is.c \. {,,-' C .1': i'· 1"'- ~ " ~1~LI--r¡¡'(I,c:u.e !f.I~'7" syr·' ~' l'}" i~ ~fc[ I~!: , -\ . . . ~.. ~ Sf ~ . s.. Sft "'I u:" I." -;~ ,_...~_ ~... m'· I··..···· . ........ .J . <- ....m....~----,... ·'i··~ I"-."~ ... rØ , ~ <:> . "" , ..., c", .. ...... ... ~ . . ... .. mr:: ..'u¡u . ,lOCO WI roat' .aaa ¡o: l~n ~ .~ ~ .. . .1 " I' o o ~ ... ~ I .. 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L.;'h~ i ID I ..·...·._...u....._...· ......._.... ...-........-......... ....j Reference Log: DS 4-19 'ased Surfcate Wells Base Permafrost +/- 1850 ft A Y Confining Zone ^ Arresting Strata Confining Bed Surface Casing shoe \I Confining Bed " Injection Interval Initial Perfs v , . . -. Structure Cross Section PWDW 2-1 L 3-8 4 -1 9 L4-15 -- -- - J_....~ 'iff -=9 iI"W! .. ~ :!¡!i!I!" 'I I!!!¡!!,: I, 1 ;¡¡!iIl'¡1 :. ' ¡¡lil·1111 ¡ .,¡ ¡1i'·1 ·c .id¡q·¡-¡.... ." liii,!111 ..', :1~' it;.:.'~ !ill~ ~,',I ii!"L~':; ; . Confining Zone ~.:~..~~.:.¡.~....:...(.~...;...;_1~:,-~.\..~.-.Z.1c.~~L.>;~.t~:.i~.:;...:."..·.-..;':.~.·..i)t.i.;'.. ''c'.'.:.'.';):'' ;jfð·, ", .··u', .. ..._,.,.....ì*\%LA: tI··}'$ f--J =j1I·;···...'<!:··:2j,·.+i~i·:,{-··;~j{·~i !i1f~11~~>f&~~~~~i '''¡ '. I\~tií·y, . .... SY3 ):t tÇ., Confining Bed . 1if. 'j'. :~,;"'1-. ~:;."! ';'cj}";.::!ilf-;'n' Ar'UUQcr·Stflli'à,l, ~~"L'- '~..€..."..' . ..;.... ':' Cogti.ning RAn_' c..."...... ··t,i.· H: ~¡~.Ù ... tt· ~'ì" iI-~~--: S Y 1 51' ~...,1;~....r.i... ' . \If. ~ r.: ,...~,.- "'F' . _ t 1iJ, 1-r¡ . ~{ ~~¡.'.. 't,\ ~ 11 ~ ..... ii. In¡eC,;on!] .~.'..'..'.. ~'.' Interval .~.;.' iJ§ .fq ¢iP ..:f·.f.~...·,..¡.:.:..... i 8' ~r~ : t:' ~l! . C:j' . ,.. it, ~~~.~ ~L¡ UG4 ~ æ¿~; ,! '..:;:, '.,~ :,~ii': ~.; ::ll1~j¡ ~ 'II'~ "'j : :j~::ii gn %"~ ,,:',.~_ ,T~ ~}:l~ - . ~ . '-'~y;.1¡'f~' ...... '~",~t t' !..1 -', I,:' ft- ~ ~',;: ~,:!.' 't....; :'7" ji'. .~:(~.:-;,~: "" ,~'r :¡~,. ~1' j~.: UG1 I'; ,,~ WS2 CM3 5961 000 ~_._~....................................................................................................................~_ ...................... ...................~ '~~ \ 5,960,000 "'1( - #1 3671 ft #2 2518 1t fl4l Stepout Stepout L:J ~ ~ 'C ~ Ii 5,959,000 5,958,000 -< 5,957,000 > ~ UJ c( 5,956,000 ~ 5,955,000 5,954,000 5,953,000 \ Surfcote Map Target @ 6500 ft TVD ~~TTTYTTono-T> '.. , , . ¡j \~ ..'~¡ '. .,' \. u~ .: ~ . ... '\ ,x .. (^"'1············u.....··.. '~.i.:::: 4 . w······ ~ . :t. ..'.':... ..' ..:·:·<:.:.::.::.......i·.·:.~;::;::······ ....... D·..·I·· " .." . .. .'. I..·· D·····'·:·· IDS 4Ii.I.. c..:.................::::::.. ... .......... .. , , , .. , ,\/"j T T"r T J..r.., , ,<¡¡:·~·~:>.~'>,:::·tllt';"77~··y·';..s· t.."",.... .,.^'~,.. '''^' , , 'M!, , ~ ~ 5,952,000 '" ,. 'T" '" r 710,000 711,000 712,000 713,000 714,000 715,000 716,000 717,000 718,000 719,000 720,000 721,000 722,000 723,000 ASP X . 6000' TVD o 6500' TVD . -... - -SL-BHL Pad 04-08 ......,:.:........ 04-16 )I( 04-1 7 . 04-20 04-21 - 04-22A ...m<.'....... 04-23A .."..... 04-24 04-25 04-26 ,.............. 04-27 ...... 04-28 ....:::::.......... 04-33 04-34A "_'''_''m' 04-35 ................... 04-36 .............. 04-37 ..w···Iim··..·- 04-39 ~ 04-49 »( L3-18 *. L3-24 .w..{,:....... L4-03 L4-11 ~L4-15 L4-31 ~ ~. 11' . , . . C? C? C? ¡1~¡¡¡r :¡~¡¡ ~ :::::::::: ¡~~~~~~~~~~~. ~~~~~~¡~~~ : ~: ~; ~; ~:~:~ ~::.~:~:.~:~:.~:~:.~:¡:.~:~:. Base Pennafrost I.[[.[¡.¡~..~..¡ ~ ::::::::::~ +/- 1850 ft 1~~~;~;~¡ ::::::::::: I ï <~:l...~.~.¡:~.¡:~.¡:~.¡:~. :~ :::::::~: ConfUÜ11g Bed @f:r: :::::::>: ...... :::::::::: ,.... SV5 Marker +1- 3400 ft TVD r~t1 :.:.:.;<. I Arresring Strata l:illlllllll [:I!I!II! I I ConfUÜ11g Bed tt~~~~ I SV3 Marker +/- 3900 ft TVD ¡.iii: ,liS.: f Confl",;",... Bed '¡~.i.¡~.¡~.¡~.¡~.¡~ X~:1:1è1:1 ---eo ~ ::::::::;:: I SV2 Marker +1- 4100 ft TVD ::::.::::::.::::::'::::::'::::t:..[::::.:::::::.::: ¡1¡:::::::¡ I I -~ I I ~ .:.:.:.:.:.: :.:.:.:-:.:. I Injection Interval co::::::::::::: '~~;;:: I I co::::::::::::: MI¡ I I I I I ~ I I Initial Perf in :I:¡¡¡::¡¡¡i @t1m 1 ~f;¿~~;VD Ï---J T I I I Confining Zone -- Proposed Surfcote Well Design 20" Conductor Pipe 13 318" Surface Cas~ Set below SV3 Marker +1- 3900 ft TVD 7" T 1JbÏJ:1g Packer at +1- 4000 ft TVD 9 518" Injection CasÏJ:1g Set near base West Sak +1- 7000 ft TVD .... ! ::; \. ::~ .-" ; .... ~: , . .¿' ".". '-; '~,..,; #17 ARCO Alaska, Inc. . Post Office Box i 00360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 .DAY&', ~t04,,^f.¡IJO A~""þ Alo +PI. 1'0 ~^e.Po~E... £6 6,11I15 ~., o"t' 1"',,-- . 4"" D~ {uo., . ~1iIII.. IN ðr~ {o,':f J-6.....,.,~ ~~6.' .'1-/.. BE. HAPPY .... fJu-FF1QU::tf1-1 co-.IEP- _ ....AÁ .. ... " Tø ~A&:( Pt1Þ~ . ~ ,... Tom Wellman Manager Prudhoe Bay/GPMA HSET 700 "G" Street Anchorage, AK 99517 phone (907)263-4304 fax (907) 263-4540 ,.:> I "..'4~ October 24, 1997 e. ~..""~\¡...; . " ~J~ ~ #O~ 0"01" {1,~ David W. Johnston Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, Alaska 99501 Re: Prudhoe Bay Unit, Eastern Operating Area Area Injection Order #4A Reserve Pit Close Out Operations Dear Mr. Johnston: Since early 1995, the Reserve Pit Close Out Demonstration Project has utilized the Grind and Inject (G&I) Plant located at DS 4 with injection into the Tertiary/Upper Cretaceous intervals of disposal well DS 4-19 to assess the feasibility of using G&I technology. We have completed our evaluation and propose to continue using the G&I Plant at its current location to dispose of reserve pit wastes into three new injection wells to be drilled from the nearby Surfcote pad. These wells will also be completed in the Tertiary/Upper Cretaceous sands and will be manifolded such that one, two or all three wells can inject fluids at any particular time. In addition, we anticipate using this facility and wells to dispose of other Class II solid and fluid wastes. This letter is intended to provide information on this project, to update and supplement the information presented in the 1986 Eastern Operating Area, Area Injection Order Application, the 1993 Application for an Amendment to AIO #4, and related correspondence. The specific items below refer only to the Fluid Disposal references in the applications, and are intended to satisfy the informational requirements of 20 AAC 25.252 and 25.402. Type and Source of Fluid - Slurries of Solid Wastes The following lists the types of wastes, and their sources, which will be injected into the new G&I wells: . Various existing reserve pits in the Prudhoe, Kuparuk and Lisburne fields will be closed out. The material currently in the reserve pits, primarily drilling mud solids and cuttings from past drilling operations, will be excavated and processed through ARCO Alaska, Inc. is a Subsidiary of Atlantic Richfield Company AR3B-6003-C David W. Johnsto . October 24, 1997 Page 2 . the G&I Plant and a slurry of these materials will be injected into the new disposal wells. The G&I Plant process water used to create the slurry will be seawater from the Seawater Treatment Plant, treated produced water from Flow Station 2, or water produced from the· Tertiary/Cretaceous formations in the vicinity of DS 4. Analyses of these fluids were included in the Ala Applications referenced above. · Waste drilling muds and cuttings from ongoing drilling operations in the Prudhoe Bay Unit, GPMA, Endicott and other fields as well as from exploratory drilling operations will be processed through the G&I Plant and injected into the new disposal wells. These materials are currently handled at the WOA CC-2A facility. · Other Class II solid wastes, including such materials as oily solid waste removed from oil processing and treating facilities, will be processed through the G&I Plant and injected into these disposal wells. · G&I Plant process water will be injected without solids prior to solids injection and during periods of Plant maintenance and upsets. · Other Class II fluids referenced in the AIO applications and related correspondence may be periodically injected into these wells. These fluids could include reserve pit water from snow melt, workover fluids, contaminated crude, produced water, diesel gel, and glycol associated with well production operations. Estimated Maximum Amount to be Injected Daily The maximum G&I Plant injection capacity is approximately 40,000 barrels per day. The three new injection wells may be operated concurrently and or on a revolving schedule, so the long term average rate into each well will be significantly less than this amount. The composition and source of the slurry solids will vary, but the target slurry density will be between 9.5 and 11 pounds per gallon (ppg). The source of the injected materials will be one or more of the following, totaling not more than 40,000 barrels per day: · Reserve Pit Solids - The maximum disposal rate is 40,000 barrels per day of slurry containing approximately 4,000 cubic yards (about 3,300 tons) of excavated reserve pit material. · Ongoing Drilling Wastes - The maximum rate is 10,000 barrels per day of slurry. · Other Class II Solid Wastes - The maximum disposal rate is 4,000 barrels per day containing 400 cubic yards (approximately 330 tons) of solid. · Other Class II Fluids - A maximum rate of 25,000 barrels per day of reserve pit water could be injected for short periods of time. Volumes of other fluid wastes will be less than 1,000 barrels per day. David W. Johnsto . October 24, 1997 Page 3 . Injection Pressure · High pressure alarms are currently set at 2,800 psi on the G&I plant discharge. · Estimated average surface injection pressure will be between 1,300 and 2,000 psi depending on the density of the fluid and the injection rate. Geoloqic Information: Colville Group and Sagavanirktok Formation (also known as the Tertiary/Upper Cretaceous Sands). · A description of this interval is included in both the original Area Injection Order Application and the Application for an Amendment. The Authorized Injection Strata for Disposal is defined as those which correlate with and are common to the strata found in ARCO Sag River State Well No. 1 between the measured depths of 1,900 feet and 6,750 feet. (AIO 4A, Rule 2) · The injection interval for the slurry injection operations at the Surfcote site will be further limited to below the SV2 marker, approximately 4,100 feet SS at the Surfcote site. The confining and arresting strata at this location will then consist of shales and sands from below the permafrost (about 1,800 feet SS) through the SV2 shale (about 4,100 feet SS). The sands and shales between the SV5 (about 3,400 feet SS) and the SV2 in particular are thick, continuous and of good quality in this area. (See attached type log and cross section.) Well Locations and Completions · Three new disposal wells will be directionally drilled from the Surfcote site. The disposal zone locations will be approximately 2,000 feet or greater from any uncemented annuli in existing wells drilled from pads DS 4, L 3, and L 4. Specific details for each well will be included in the Applications to Drill. (See attached map.) · The well designs will conform to all AOGCC regulations. · The wells will be completed with large tubulars: 13 3/8" surface casing, 9 5/8" injection casing and 7" tubing. (See attached schematic.) · The surface casings will be set in a sand below the SV3 marker (about 3,900 feet SS) and cemented to surface. · The injection casing will be cemented to just below the surface casing shoe. Surveillance and Monitoring · Injection rate, injection pressure and the inner and outer annulus pressures will be continuously monitored. Injection volumes and pressures will be reported monthly on Form 10-406. .' . David W. Johnsto October 24, 1997 Page 4 . . · Mechanical integrity tests will be performed prior to commencing injection and at least once every two years thereafter. · Downhole logs, reservoir tests and surveys will be scheduled to provide baseline information, and periodically thereafter on an as-needed basis. The information contained in this letter provides a description of planned operations and, where appropriate, an update to the data included in the referenced applications and related correspondence. The anticipated future rates and pressures listed above are intended to represent maximum expected peak daily rates and pressures. However, in some cases these parameters will be limited by existing facilities and future well performance, so expected average values will be somewhat less. Additional updates will be provided if conditions or plans change significantly in the future, or as requested by the Commission. It is our belief that Area Injection Order #4A provides for the above activities and no change in the order is requested by ARCO at this time. If you wish to discuss these matters further, please contact me or D. W. Hanson (263- 4745) at your convenience. Sincerely, -'·"76- UW~'----_ Tom Wellman TW:dcd cc: M. L. Bill D. W. Bose R. R. Bowden W. L. Friar D. W. Hanson M. M. Ireland E. M. Oba D. G. Rodgers K. Bell M. Barker ATO 1528 ATO 1670 ATO 1576 ATO 1828 ATO 1968 ATO 1570 ATO 1526 A TO 2002 BPX MB 9-1 Exxon #16 PLANNING PRUDHOE ID:659-5917 JUL 01'97 14:54 No.008 P.Ol . ~~ ~,.. . ARca Aluka Inc. f'O$t Office Box 1 O~0360 Anchorage, Alaska 99510-0360 Telephone (907) 276·1215 July ]. ] 997 Mr. Blair Wondzell Alaska OiJ & Ga~ Conservation Commission 330] Porcupine Drive Anchorage. Alaska 99501-3192 Re: Approximate Rig Workover costs for 12-23, 17~08 and PWDW 3-1 Deal' Mr. Wondze1J: The following is a }j~t of approximate costs we incurred to repair well~ 12-23, 17-m~, and PWDW 3-1. These costs are for the repair work only and do not. include any initiaJ costs that. were incufrcd t.o control 01' diagnose the problem. J would expect. t.hat control and diagnostic costs could be any where from $30M to $75M for each we]]. ] 2-23: $689,837 17-08: $473,782 PWDW 3·1 $803,804 If YOll require additional information or clarification, pleaRe feel free to cont.act either Richard Ortiz or myself at (907) 659-5 J 02. Very Truly Your!;, AaudjL D. D. Smich ./ Problem WeB SpeciaUst RECEIVED JUL 1 1991 A\aska Oil & Gas Cons. Commission Anchorage #15 ARCO Alaska, Inc. " PO!;t Office Box 100360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 .. ~~ ~~ April 4, 1997 ~,\G ~ "- Ms. Wendy Mahan Natural Resource Officer Alaska Oil and Gas Conservation Commission (AOGCC) 300 1 Porcupine Drive Anchorage, AK 99501-3192 SUBJECT: Classification of Spill Cleanup Material Drillsite 16 Well 18 Flowline Spill Dear Ms. Mahan: The purpose of this letter is to confirm ARCO Alaska, Inco's (ARCO's) understanding of the AOGCC's classification of the subject spill material. On April 1, 1997, ARCO contacted the AOGCC to seek a regulatory determination of the Underground Injection Control (UIC) classification of fluids spilled during freeze protection operations on the flowline from DS 16 Well # 18 to the DS 16 manifold building. The material spilled was a mixture of crude, methanol, and water. ARCO inquired as to whether the AOGCC considered this material to be UIC Class II. The AOGCC response was that this material was UIC Class II and could be handled and disposed of in accordance with the regulations and orders associated with such a classification. If ARCD's understanding of the AOGCC's classification of this material is correct, please indicate your concurrence by signing below and returning a copy of this letter to ARCO for our records. If ARCD's understanding of the AOGCC's classification of this material is incorrect, please contact me at 265-6136 as soon as possible so that this matter can be promptly addressed. Sincerely, Mark Major Sr. Permit Coordinator Prudhoe Bay/GPMA Health, Safety, Environment, & Training Concur: 'r,J-"'b~' tvI"^-------- Date: ArR'1- 4, 1991 ARCO Alaska, Inc. is a Subsidiary of Atlantic Richfield Company #14 BAY ,~~12-96; 11:50 ARCO Alaska,lnç. ... Post Office Box 100360 Anchorage, AI8ska 99510-0360 Telephone 907 2761215 ARCO ENV IRONMENT' 907 276 7542;# 2/ 2 t~ AIØ·~ ~". JUly 12. 1996 PU,ASE.. fï L.~ 1 ~ 0/l.. fit.£.,. Ms. Wendy Mahan Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr. Anchorage, AK 99501 ~\\)'-\" Dear Ms. Mahan, This letter is to document and confirm my understanding of our telephone conversation on July 11, 1996. In that conversation, I described to you a waste we had produced from clean out of a production treatment vessel. The waste consists of residues of crude oil from the production stream, the former coating within the production vessel, and the sand blast media used to remove the coating and crude oil residues. The waste, of which we have approximately 10 cubic yards, consists primarily of silica residue with reacted epoxy from the coating, aluminum oxide from the sand blast material. and crude oil residues, represented by low quantities ( less than a total of 4.63 mgfkg) of benzene, xylene. ethyl benzene, and toluene. Due to the way this waste was produced, with the crude oil constituent originating from below the surface, and the other materials from being in contact with the production stream, you believed the material to be a Class II waste from the UIC standpoint. If your understanding differs from this, please contact me immediately at 659-5196. We appreciate you prompt direction on waste management questions, which greatly assist us in efficiently and safely managing our oil field waste streams. If you have any questions, please contact me or Harry Engel at the above number. RECEIVED JUL 1 2 1996 Alaska Oil & Gas Cons. Commission Anchorage ARca A1aelca, II,.. i. ~ Sut..,tI'lty 01 AII~lIlicJlIcI\II.ldCQmp.ny AA~R OOIXI-C #13 Á V9 30HŒ1Md: Á9 lN3S ~1VlN3NNOMIAN3 OJMV ~ G~:~t ~ 9G-ij -L : t #~6tgL 9L6 LOG NOTES: {µ~'õ - .¡þ,~ 0Æ'i.- ì'lk. '/::=uaA"-,,,73 T :JLs-r 5Ii>"'-.- (µ¡-rH- 'tv ó;.J ~fflt. Itfo~- ~J7. 7Ht¿j )/<J~/u~ aN f/l-ec ¡:¡,.Ib Oßv,CV-¡'o¡vp). 1v....""'a-'1, TIlt 1H>Gt-- If AÒN?/bor-, ~ val S I (þJb 19tt- ~.o L'iC¡ ~-,-- 70 '71It. IJ~ALif.. s. (lIJiTlf s.I~:J ÀJv-J~./Uï7+rió¡.J). ðvlL- ì~Ì't1J7~ '¡~ ~ Ie.~~s..s ~9t (!fjS5 '"Jt;. ¡UtL~¡"CL/~, Ït;."ibUlA-~~_ Sïõ~ Q;r D5.lþ J úJf)-fl- W'l. ~~ CU-.Jb Cl.lïtUÎ)'? ~(j Vi.-lj IhtVt --nfL. þ¿; /I si'rt. A~\Ic. 1,7S tZNI'J la-A.;..) Ì"b '7Tft- ""l:.s{ ÉtK.-1'N'ò ~D T~-;r . ~,!~!~~C)C. (J~~~. ¿'~~sceI)4 ì-P 'tv I1I1-1)L cAAs"')N~ ~ PAGES ~ FOLLOW: 3+ _ (Does N~ Inctude COVér Sheet) M. CAS¡Y/B. SORENSON A..tatant 858-sa70 FROM: R. HOFFMAN/H. ENGEL L. BARLOW/D. HANSON~ BRÒWÑÌ9.t- JONES 8up.rvl.or Coordinator (¡oordíñator IS8-'188 858..5888 858-6808 .'" Confirm No. (~~ µ~(-f(:À~ ¡ro GeL ~c.f!'o¡!.~() .. :2-1:fo-~~'2- -. .. .. . . FAX No. C~ny LocatIon Alaaka Oil & Gas Cons. Commission ~nr.lw:\()p- , Nema TO: JUL 08 1996 1-# þP .. Dete: FAX TRANSMITTAL COVER SHEET RECEIVED ~\O '-\ "- -.- ARca ALASKA, INC. FIELD ENVIRONMENTAL COMPLIANCE PRUDHOE BAY.. PRS 7 FAX (997). 65~Ø228 . . · e D5-16 Temporary Storage of PBU Vessel Solids Operational Summary 1 . Agencv Approval has been r,ceived to temporarily store 600 cubic yards of Class II .vessel soljds from p~U i~ Sump 3 a~ D5-16. This sump is lined. Copies of the request and approvals are available at FEC. 2. Standing liquids in Sump 3 must be removed before any vessel solids are stored in the sump. 3. Prior to entering DS16, contact the FS2 Control Board at x5491. They will notify the 0516 operator for coordinating the delivery of the load. 4. Each load of vessel solids must be delivered accompanied by a uPBU D5-16 Sump 3 Temporary Storage Manifest". The generator of the vessel solids must initiate and sign the manifest, the transporter must sign the manifest for transporting the load, and the 08..16 Operator must sign each manifest for acceptance. All generators and transporters must be certified by either Generator or Transporter training. 5. Vessel solids must be deposited in Sump 3 at the designated area, and 10 feet from the edges of the sump. The area will be clearly marked but confirm with the D516 operator before offloading. 6. The vessel solids will remain in the sump until the Grind & Inject Facility resumes operation in the last quarter of 1996. The solids will then be transported to the 05-4 Grind & Inject facility for processing. Volumes of the vessel solids finally removed from DS16 must be documented on Reserve Pit Excavation and Removal Manifests maintained by Heavy Equipment. 7. Please contact AAI Field Environmental Compliance prior to the start of any vessel cleanout job. Any questions regarding this operation should be directed to Chris Brown/Shellie Jones at Field Environmental Compliance ext. 5609. June101996 ~ #:~t9L 9L~ LOS .....lVJl\8NNO~IANd WID' : OC:~1 9S-9 -L ÁVg 3OHŒ1~cl:Á9 JN3S . . pBU D5-16 Sump 3 Temp. StoraÇle Manifest ... Compat1~ 0 D . . ~ . MI.... BPX . ~ SuperVisor Nama (Print) .PhonélPager: III I:) Number: CalC! (MlDlYI Time· c::J AM c::J PM Chargo Code (6 or 9 digit c~) At AFEJAFC' (ð digit çodo) I SourCÐ·Co~ (opIiOOF)/) .. . 15 SQlJrce location ~ 8 ... Facßlty and Vessel Wasto Generation ACUvity (Doscrlbe specl/lc job typo/opérat1on Which cffll:ltod wasle) Vossel Cl9~nout tOTAL. VOLUME: CubIc Verda Waste Description Waste Stream ·Classlfication % MUII\ Eaual 10Q."~ ( ) Production Félclllty Vo..se' Solids o RCRA exempt .,...el .olld. This manifest Is for the temporery stor~ge of Class II, RCRA Exempt vessel solids at the lined Sump 3 pIt at Drill SIte 16. ~ o == VI o .0. E o o .!! 1/1 ~ The vessel eollds will remaIn In Sump 3 until the DS~4 GrInd & Inject facility Gtms up In the last quarter of 1996. At that time. all the vessel Gollds wJII be transport.d 10 the DS-4 Grind & Inject facility for processing. The total volume limit for the DS-1S lined Sump 3 pit Is 800 cubic yard.. The DS·16 Operator will maintaIn copies 0' the manifests for this activity, FEC will maintain originals. e GENERA lOR'S CERTIFICAllON: CONSUlTlHE COMPANY ENVIRONMENTAL ORGANIZATIÖN IF ·UNCERTAlN OF PROPER WASte ClAsSIFICATION o ii I hereby declare that the contents 01 this conlilignmOl\t Bre tuüy Md acquralðly descl1bed aÞc3VJ, ane! is not a hazardous "Iasta, U deflnêd by applicable Federal ~ and Stale regulations. (Aliller 10 Manile$1/nsùuctlon¡¡) ~ This waste is Glasslfled !!Is: _ Exempt di,se 10 oil and Qas éAlI~PX Generator Name (or responsible managor for Srd ~ny dispa..'iRI). . (Ptlnt) .. . ----,..- EX9ßI¡)1 due to em,ply çontaJnerlload Generato"s Signature . .. _ Non exempl but non Þatardou$ wa Ii i TriMIsporter (Company Namlil) ~ ~ Driver's N.\Itne (Print) :¡¡ ¡;;. Trailelrrtuck Number Driller', $ignaluro I Ultimate dispos~i for these vessel solids ;"'11I be at D5-4 Grind A Inject Facility. Disposal volumes will be documeted on Reserve Pit E(cllvatlon and Removal Manifests. .. . . .. - Acceptance at DS-16 DS-16 Operator (Prl"t) eS·16 Operator Signature Date RECEIVED JUl 08 1996 e #:6ÞSL 9L6 L06 ~ 1V .Lt\BNNO~ I AN3 OJm' œ:61 96-9 -L Alaska 011 & Gas Cons. Commission Anc~~OH(][1~d: ÅH lNdS . e \I VII Ui,I \IV WCIJ Lt:....>.J U!V ur UIL ftNV liA~ FAX no. 9075623852 P. 02/02 t" .. røNVIrNOUI/.Ø.GO- ~~, (f) ø;! "'~ ..0 . "*1, ":~:_. ,.. ".1 . .... ... .....' ... .,' . \.,,. .. . .. ,,,I ' '" ~ ". ... ... . - "'" .. DEPARTMENT OF NATURAL BESOURCES DJVISION OF OIL. AND GAS :tØQ1 C;:JTFI'fT. SClITE T38Q AN(;HOIfA(lS. "LASKI< HSÞ3.ø4 P.~N!~ ('07) rd~ June.5" 1996 Rod Holfmsn ARCO Alaska, Jnc. PBU Field Environmental CompJianœ P.O. Box 100360 Anchorage, Alaska 99510-Q360 RB: LOINS 9O..()1J8 DrlIl Site 16, Temporuy Stmge of Oau D VetSel SoUds Dear Mr. Hoffman.. Thank you for your letiet dated JUÞØ a, 199' notifying us of the planned attJvides at the referenced d.rill.ite. We have reviewed your requeet and find that the proposed activity falls within the scope of the origina1approval. Minor activities that are maintenance-related and do not cl\lmge tha authoriDd u.. add a new use, or substantially d\ange the ~ting ·'footprint" were authoriZM UJ1der the ~th1g Approval. The Original permit for this él(t1v1ty was found tô be consistent with the Alaska coastal Management Progrom. In addition, DBC has authorized this actWity for thts sUe. Please consider dùs leuer I11î r.uiministrilüvt approval for thl! specific activity requested. 'Each request, however, must ~ handled 01\ a ðIJ&oby~œtte basis awl this applDVal ahould not be amsidem1. an appmvallo:t other .ituatlon.. This approvalligJ:\iAa only that the State of Alaska" Dept. of NaturëÙ Reeourœa, Division of Oil and Gas has no objection to the operatiMS outlined in your letter. It does J\Ot relie\le the applicant of røpons1bility to obtain approva1s or plU'mib from other penON or govenunental agencies that mAy also be required , Tf qustions arise, please contact me at 269-8?78. ~2LJ.¿. Bruce D. Webb Natural RAMO\1K8S 0£B.œr cc; Molly 'Birnbaum, DGC Tom Lohman.. NSB Judd Peterson, DOC Terry Carpenter; COE Leon Lynch, DNR/DL AU Ott ADF&tG :.~.~~ ·-~·:;~:"I.'M~' ,¡:-..:........,;:: ",., . t #:~t£L 9L~ L06 ~1V!N3NNO~IAN3 OJ~ : ~C:~1 : 96-9 -L : ÁV9 30HOI1~d:Á9 lN3S · e '1 .-b Ï») ,(þ lr" ~j.' t.D (V (11· TONY KNOWLES, GOVERNOR DEPT. OF ENVIRONMENTAL ~.NSERVAT'ON DIVISION OF ENVIRONMENTAL HEALTH SOLID WASTE PROGRAM 555CORDOV A STRKET ANCHORAGE, AK 99501 Telephone: (907) 269-7590 Fax:(907) 269-7655 CERTIFIED MAIL l' 033 979 901 RETURN RECEIPT REQUESTED P 033 979 901 June 5, 1996 Rod Hottman, Supervisor Field Environmental Compliance ARCO Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Rf¡;; Approval of temporary storage of Class IJ mc, RCRA Exempt vessel solids at DS 16. (DEC Jile # 300.15.093) Dear Mr. Hoffman, Onder authority of AS 46.03 , 18 AAC 430(a), and the General Approval of Temporary Storage of Drilling Waste issued June 26,1995 as amended Deccmber2l, 1995, the ARCa Alaska Inc. (ARCO) notice oHcmporary storage of Class 11 UTC, RCKA Exempt vessel solids at the Drill Site 16 pit, in accordance with the plan submiUcd June 3, 1996, is hereby approved. The project consists ofihe storage of appro!l:Ünately 600 cubic yards ofvesscJ solids from the Prudhoe Bay lInillh.is summer. Vessel bottom oUy sludges are. by regulatory definition, a drilling wa.ste and may be approved for temporary storage for a I)eriod of less than one year. Storage is expected to begin on or ahout July 1,1996 and disposal is scheduled for the last quarter of 1996. In accordauclJ with the General Approval, after removal of the drilling waste from the storage area, ARCa is required 10: 1. Conduct a visual site inspection to verify that all drilling waste has been rettu.wed from the site; 2. Verbally notify the AVEC within 10 days after the tinal site inspection and provide inH.)rmatiol1 regarding ddlling waste volume and final disposition of the transferred drilling wa.<;~e, 3. Furnish the Department with a written I'cport which includes that information in 2 above. In addition, ARCO is required to submit result!; of the monitoring program as described În the June 3, t 996 temporary storage p1an. S #~ZtSL 9LZ L06 ....1VJmNNO~ I AN3 OJmr CC:(;1 96-9 -L Ava dOH(]f1~d:Aa .LNdS · e Mr. Rod Hoffman, ARCa Alaska Inc. JWle 5, 1996 Page 2 The plan is to disposal ofthil:l oily waste at the DS-4 grind and inject fttcitity. Please be advised that this solid waste processing faeilíty requires Ii permit under the rU;W solid wa.ste regulations, /8 AAC 60. These regulations went into effect January 28, 1996. This facility was initially constrLl-ctcd fOJ'thl,: purpose of dispo~al of drilling wastes from abandoned pJ'Oductiòn reserve pits as required by a court settlemcllt ARca is now proposing to expand the use of the processing facility to include the disposal of contenlporary excmpt drïJling wa.~te including exempt oily waste. ADEC supports the propo.~ u~e of this processing tacility for the disposal of the oily wastes hut we request that ARCO begin the perrnit application process for this operating facility. The rt.:guJations allow operating facUities to continue operation while permit applications are being proCe8$ed. State regulations sHow that any person who disagrees with this decision may appeal the decision by requesting an aqiudicatory hearing, using the procedures contained in 18 AAC 1 S.200-.31 O. Hearing l'equ~lS must be delivered to the Commissioner of the Departtnent of En.vironmental Co~sel'vation, 410 Willoughby Avonue, Suite 105, Juncmu, Alaska 99801-1795, withiD 30 days ofreceÎpt ofthis letter. If a hearing is Dot requested within 30 days, the right to appeal is waivud and the decision becomes final. Please contact me or Judd Peterson at 269-7622 with any questions you may have on this matter. Sincerely, e~ Soutl1central Program Coordinator LO\JP (H :\bome\rjpck:rs\1etmiMareö\ds 16. wpd) CC: Bruce Webb, ADNR James Chatham, ADF.C RECEIVED JUL 08 1996 Alaska 011 & Gas Cons, CommiSsion Anchorage 9 #:6v9L 9L6 L06 ....lV.LN3NNO~IAN3 OJ»\' vC:61 96-9 -L ÁW 3OH<Iíl~d:Á9 .LN3S e e ARCOAlaska, Inc. Post Office BOI( 100360 Anchorage, Alaska 99510-0360 Telephone 901 276 1215 I 'j;.. ~ 4o./Þ 1 .. __þc) I Þ ~~ ~, 3 June 1996 Mr. Judd Peterson Alaska Department of Environmental Conservation 555 Cordova St. Anchorage, Alaska 99501 Mr. Bruce Webb Division of Oil and Gas Alaska Department of Natural Resources 3601 C Street) Suite 1380 Anchorage, Alaska 99503.. 5948 Ae: Temporary Storage of Class II Vessel Solids Gentlemen: As we discussed, ARCO Alaska, Inc. is requesting authorization to temporarily store vessel clean out solids in a lined reserve pit at Drill Site 16. Of the two lined pits at Drill Site 1 S, only the more central one is planned for this use (Figure 1). Vessel solids are classified as Class 1/ UIC, RCRA Exempt waste. We anticipate the Prudhoe Bay Unit will generate approximately 600 cubic yards of this waste through the summer months. Our plan is to manifest this waste to temporary storage at Drill Site 16. The material will be held here until the Grind and Inject Facility is started up next winter. This is anticipated to be the last quarter of 1996. The current operation of the two fined pits at Drill Site 16 was described to Alaska Department of Environmental Conservation, Alaska Department of Natural Resources, US EPA, US Corps of Engineers, North Slope Borough and DGC in JUly. 1990 (Attachment 1). These agencies approved of this use of the lined pit for temporary containment of drilling wastes. Our proposed operation of this pit for vassel solids temporary storage is as follows. 1. Standing liquids will be removed from the pit by vacuum truck or pumping to another reserve pit. 2. Vessel solids will be deposited on top of the drilling muds within the lined pit. The vessel solids will not be mixed deeply into the mud. The deposition will vary from approximately 0.5 foot to 1.5 feet in depth, depending on how much mud is mixed with the vessel solids after placement in the lined pit. The mixing is done purposefully to facilitate later processing by the Grind and Inject Facility. RECEIVED JUL 08 1996 ARca Ala$_a, Inc. i. a Sub~ø8ry 01 AllanlcRcht~ldCólnp"ny Alaska 011 & Gas Cons. Commission Anchorag@m~oo3_c L #~~t£L 9L~ L06 ....1V.L~O~IOO OJm' : tc: &J 96-9 -L Ava 30H(](1~d:Aa JN3S e e June 3, 1996 Temporary Storage of Class II VeS$el Solids page 3. Vessel solids shall be delivered accompanied by a manifest signed by a certified trained waste generator. The drill site operator shall sign for acceptance of the waste. FEC will keep copies of all manifests of loads sent to Drill Site 16. 4. Vessel solids shall be deposited a minimum of 10 feet from the pit's edge. Either during the hauling and deposition process, or after completion of each facility turnaround which generates the vessel solids, the solids in the pit shall be mixed with drilling muds. 5. Once the Drill Site 4 Grind and Inject Facility recommences operations, the vessel sludge shall be excavated and taken to the G & I plant for processing and disposal. (At a G & I rate of 2,000 yds. per day, it would only take about 6 days to process the vessel sludge, since they are not a significant volume compared to the rate at which the plant can operate.) 6. ARCO agrees that monitoring around the pit is advisable, given the temporary storage of vessel sludges. Our proposal Is to monitor at three ponds around the south end of Drill Site 16. Every effort will be made to find monitoring locations within 50 feet of the toe of the pad, and to evenly distribute the sample points around the peñmeter of the south end of the pad evenly. Once break up is over so we can more accurately locate sample locations. the locations will be marked. A map of sample locations and the resultant water quali1y data will be submitted to ADEC by December 31, , 996. We will collect surface. water samples in June. July and August and analyze them of diesel range organic (Method AK 102) BETX (8020M). Any measurement in excess of water quality standards shall lead to an investigation. The Investigation plan will be submitted to ADEC prior to conducting any formal investigation. Your prompt attention to this request will be greatly appreciated. We currently have a vessel clean out under way, with vessel solids expected to be removed June 12. The ability to temporarily hold this waste at Drill Site 16, instead of placing them in Cell 2. will greatly speed their final disposal by grind and injection, and prolong the remaining life of cell 2 for material that cannot be injected down Class II wells. This will avoid building a ~hird cell for oily waste at Pad 3. Si~ere). ' .,1 l(d/~ Rod Hoffman Supervisor Field Environmental Compliance cc N. Welch, ADNR RECEIVED JUL 08 1996 Alaska 011 & Gas Cons. CommissiOn Anchorage 9 #:~v9L 9L~ L06 ....1V!N3NNO~IM13 OJm' 9C:~1 96-9-L AV9 30HŒ1~d: A9 !N3S e e June 3, 1996 (',.....~,Qf~ IIV8eseI Solide page A ,. K. la urnJ R. Wells/ T. Bessette B. Fowler M. Major A. Elder A. Schuyler L. Barlow/D. Hanson S. Jones/C. Brown. B. Harding/C. Backlund. BPX J. Platt, BPX M. Barker, EXXON RECEIVED JUL 08 1996 Alaska Oil & Gas Cons, Commission Anchorage 6 #:~tgL 9L~ L06 ~1V!NBWNO~IAN3 OJMV : 9C:~1 : 96-9 -L : Áva dOHŒ1~d:Áa lNdS 1/ __- ..~ 11.--- _.....~,. 10_ ..- 9 ..---- 8 a-- 7 ___ e e L_·-·l - . ./( C.-I g . ___.r-¡"e" -... r 7 -I \ . ,,+!~, + ~ ( "~ . ;:'~--:¿~'-"-)-'~.:?j~- / + ..) (0] __.' I ( 'r - ù ~ ø 0 -4 f:]./.1.h.fi '. rPROJ~T J - H . ARE~ - +~ ì I~,~ 'D~~16 5 q \ ./ J / u f J \~ rÞ\.f;)f;...., \f ~ ') 0 ~ '\ <~7" 'II\) . --- ,. f- ...J \... .~- ~~ v~ () " _...)'@+" CJJ\)' l·· .....<,s-J-..-(" .--:iï.9 . . ',). " I., .~., f. <. 1\' ~_._/ll .....~~..... UMI. ",'. ""'.............. VICINITY MAP N.T.S. "4 23.··- 24___ ~~5 22-" .-. .. . .31 11--.. ..._~ ,~ti . ...J 27."·- .., 130' ~... l4?Ž%}ª ð ~~,~ ~~~VESSEL SOLIDS - 25___ 26.·- I- .z « ..J 0.... -..J î RECEIVED 1 ,..-- -11IIII I ~!J JUL 08 1996 Alaska Oil & Gas Cons. Commission Anchorage DS-16 PAD (TYP.) EL. .38'± EXIST. DRilliNG MUD SEGTION A-A N.T,S. =--.~~~~. . ~.~ n. F. R~i!.CIt. --···-····-·l ...-.... - lliß1 ~-"'-"--'" JlI -- ..-. ,..--. '-" ..-- -- I~ -.-. n__..__ _____.~ ~J -. '-'--.- .'-'. ¡g(ñ'J(i>i.~ ..--- .-. --- - .-...-..::. ""'lUffiillWl~n Q fi/2/96.,ISStJfO '"OR WF'OIiM.o\1I()f( jJ RH ~_~.!.it. NO. ~A'II:: .. ~r:\.4S1ON . BV On!; :=:~~ ~ Ot#:Gt£L 9LG L06 DRÂWM; ëiifëKm, JACOij$ .. iiÍl iE! IiOffItAN.... 8/2/95 ~c:.' DSI65a.t JOC NO: ~- "SCiii':"-" ,'- 200' Igrl ARca Ala..-ka, Inc. <> SHF"!I¡ DRILL SITE 16 VESSEL SOLIDS CONTAINMENT AREA ~1V!N3WNO~IANd OJ~ : LC:Gt : 96-9 -L : Ava 30HOJl~d:Aa !N3S e e ARCO AJaska. Inc. Posl Office Box 100360 Anchorage. A'élsk$ 99510-0360 Telephone 907 276 1215 ~~ ~, September 10, 1991 Mr. Robert Cannone Department Of Environmental Conservation 1001 Noble St. #350 Fairbanks, AK 99701 Re: Drill Site 16 Thermistors Dear Mr. Cannone: ThiS Is to Inform you of the abandonment of three thermistor strings around the perimeter of a reserve pit liner at Drill Site 16. Attached Is a diagram showing the location of the reserve pit liner. A second diagram shows the location of four thenmslor strings, wA- through -C-. The strings were installed vertically and adlacent to the outside sides of the liner with beads at 3, 6, 9, and 12-ft Intervals. below the surface of the pad. String B at the south side of the pit began malfunctioning in July 1990 and AOEC was informed of our Intentions not to replace the string on November 19. 1990. Subsequently. strings A and C on the east and west sides respectively. were damaged during snow removal and rig move activities during the spring of 1991. The liner and thermÎstors were installed in March 1989. The liner was keyed Into the permafrost at a depth of nine feet below the pad surface. Resuhs of the thermistor readings taken since May 1969 Indicate that the liner Is keyed Into the permafrost 8t nine feet. In addition. reserve pUs are dewstered every spring to reduce hydraulic head pressure buildup inside the pits from snow melt waters thus funher ensuring there Is no leakage of pit fluids to the outside of the reserve pits. Our Maintenance Department has determined that it is not feasible to repair strings A. B, and C. The strings would have to be replaced in order to continue monitoring sub$urlace temperatures at that location. Because the thermistors, voluntarily installed bV ARCO, have accomplished their intended purpose. we do not intend to replace the strings. Please call Brad Gerken or me at (907) 659-5999 if you have any questions. Z_iO eraly, ..._ J" 7/l// ~k 0-... ¡-UUCJJLo..- Bry / F. Collver C n:tinator Reid Environmental Compliance ..,,- enclosures ARca AI..h. Inc. i. .to Su\)t'OlirV 01 AII.nl,çAlentiwlclCom"wny ..RJ8·óOO3·Ç 11#:~ÞSL 9L~ L06 .....1V.LN3NNO~IANd OJW : 9C:~1 96-9 -L Ava 30HOf1~cI:Aa .LN3S jj. ~ , 7~'±f- .. f--- ¡ I ! 310'± 200 , ~1#:~t£L 9L~ L06 t ,'t~'~ . . --7+ ~c NEW GRAVEL 7' .. _.. . BERM (1500 C.Y.) ---~----r~~~(~ .... _l"~''¡'¡'', . ©.I0- C \ ---NEW PER)MEl"ER LINER ~ SEE SECTION A-A ~ ,leY THERt.iISrOR STRING (lYP) \. '\ e e , \ o , 200 1 SCALE :N FEET 1 gO,:!: ~ ... ..-.. LqCA.T10N p~ ! 2D" ' ... - I f~ I' -: I I~ ..C ~~··~<l~' '·D··.."'!~· D' ~~ ~ ' ~:'^:'^'h. ~,. ~ UNQØIl. 'tWC TVNDItA· ~~ t.MR R£FER 10 SHf. 4 d 4 FOR MTAlU\l1DN DETAIl SECßON..A-A . N.r.$. PROPOSED RESERVE PIT· PERIWETER l..iNEft AT DRtlL SITE 1 6 ........ - NOMM SI.Øe': ......' salEar~· ~ :! . _ !'" "~"""IIC. "'1VlN'.N\lO~IAN'3 OJ~ : 6C:~1 : 96-9 -L : ÁVH 3000mld:Á9 JN3S SENT BY:PRUDHOE BAY VSVW::IÞ~_ ...~ ~.--..n AW ..... 9 ~ ].US 'WO .1. ~3NJ1 W3J3"~3d JJd 3AH:aSJai a3S0dO~d ..1' 7- 8-96; 12:39; ARCO ENVIRONMENTAL-I M31^ NY Id 91 3JJS ",~a 907 276 7542;#13 . ,.. 00" .13]J HI J'1W:)S. , . o - 1 DOt ,. ----' .e .S g- -01 .'ÞZ~· - ~ ~ .ZI t· .~z r. . ~\ _0, .., L .SIl'- .QI . ç; ~ .L t- .9l r ,~~ I i :¡ :æ . r-/ ~~-<> --:;- \ , .tÞ,fJ.) ,," r " . , .1 e e e e F~LE :'..,;,'t AACl ·.&ska. Inc. Post Office BoJC 100360 Anchorage. Alaska 99510-0360 Telephone 907 276 1215 ~~ ~, July 18, 1990 Mr. Uoyd Famer Regulatory Funcûons . Compliance Division U. S. Anny Corps of Engineers P. O. Box 898 Anchorage. AK 99506-0898 Ms. Pani Wighrm.'U1 OMB Division of Governmental Coordinaùon 675 Seventh Avenue. Station H Fairbanks. AK 99701 Mr. Wanen Maromeak Deputy Director of Planning Nonh Slope Borough P. O. Box 69 Barrow. Alaska 99723 Mr. John Wharam Alaska Department of Natural Resources P. O. Box 7034 Anchorage, Alaska 99~HO·7034 SUBJECT: DS 16 Re$erve Pit Perimeter Liner Installation Prudhoe Bay Unir/Eagtem Operaring Area LOINS 79/81: Beaufort Sea 144 Dear Ms. Wîghtman and Messrs. Fanter, Matumeak and Wharam: ARCa Alaska, Inc. (AAI) is planning to ínstall a perimeter liner around the south end of an existing reserve pit (Sump 3) at Drillsi1e 16. This lined pit will provide an area for temporary disposal of drilling wastes associated with drimng at various locations. The lined pits at DS 2, 14, and 16 comain little remaining capacity, and additional drilling is scheduled ill the very near future. Pla.ns for installation íncludeconstructing a gravel berm that will subdivide the original pit, reducing the area to be lined. The: pit perimeter will then be trenched and lined with a cunain of 80-mH High Density Polyethylene (HDPE). The liner will be keyed into pennafrosl. creating a continuous \'enic:al banier against potential seepage from th~ pk The lined pit will be approximately 3.8 acres. Approximately 1,500 cy of gravel will be placed for the new benn. The pit and pad configuration will remain unchanged and the intent of the activity is consistent with the originally pennittcd purpose. The ADEC plan appfOval package (including a detailed narrative. maps, and drawings) is attached for additional ínforma-åon. As previously determined, this work constitutes only a minor alteration of associated pennits and should not require fonnal permit modification. AAI requests that your agency review this proposal and confirm that no funher authorization is required. If funher regula.tory action is required, please notify me promptly. AA[ agrees that this permit action and the associated work will in no way restrict or preclude the District Engineer's options for reclamation of the site. in accordance with the general conditions and/or special conditions of the original authorization or any subsequent modifications. tl#:~tgL9LZ LOS A"CO À'>:;ViN3NÑoMÎXN3 öj¡f'-'~ ·Ôv: (;1 oo-~ -¿ Á W 3000mld: ÁH J,t\!3S · e f¡m._.. e[ al 7/18/90 Page 2 Due to a pressing need for additional disposal capacity, we would appreciate an expeditious response. (f you have qoestions or require additional infonnarion, ple¡\se contact me at 265-1557. Sincerely, J,,-~ J~ Sandra L. Hamann Pemùr Coordînaror A ttachrnenr.s cc : G. Zimmennan, ADNRIL WM. Fairhanks J. Beelman. ADEC, Fairbanks A. Ott, ADF&G, Fairbanks K. Mueller, USFWS, Fairbanks J. Hansen. USEPA, Anchorage R. Morris. NMFS, Anchorage *B. Cannone. ADEC, Fairbanks *wirhom attachmencs £l#:~t£L 9L~ LOS "-1V.uJ3WNO~ 1 AN3 O::>W n:~l 96-9 -L Ava 30HŒ1~d:Aa .LN3S e e ARC ~18s~a. Inc. Post Office Bal( 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 ~~ ~, July 18, 1990 Mr. Bob Cannone Ala$ka Department of Environmental Conservation 1001 Noble Street, Suite 350 Fairbanks. Alaska 99701 SUBffiCT: DS 16 Reserve Pit Perimeter Uner Installation Prudhoe Bay Unit/Eastem Operaring Area Dear Mr. Cannone: ARea Alaska, fnc. (A AI) is planning to install a perimeter liner around the south end of an existing reserve pit (Sump 3) at DriIlsite 16. This lined ph will provide nn area for temporal)' disposal of drilling wastes associated with driUing at various locations. The lined pits at DS 2, 14. and 16 contain little remaining capacity, ílnd additional drilling is scheduled in the very near future. Plans for installation include constructing a gravel berm that will subdivide the original pit. reducing the area to be lined. The pir perimeter will then be trenched and lined with a curtain of 80-mil1Iigh Density Polyethylene (HDPE). The liner will be keyed into permafrost, creating a conrinuous venicat barrier against potencial seepage from the pit. The lined pit will be approximately 3.8 a.cres. Approximately 1,500 cy of gravel will be placed for thl:: nc:w berm. l11e pit and pad configuration win remain unchanged and the inteor of the activity is consistenr with the originally permitted purpose. For additional information, a detailed narrative. maps. and plans are attached. Also au.ached for your review is a copy of the regulatOry review request issued to the Corps of Engineers. Alaska Department of Narural Resources. Division of Government;}} Coordin:ltion. and the Nonh Slope Borough_ AAI requests that your agency review and approve the planned installation. Due to a pressing need for additional disposal capacity, we would appreciate a prompt response to [his request. If you have questions or require addit:ional informarion. please contacr me at 265-1557. . Sincerely, J 1 ,J¿0~( 4< t· JŸ ~Vl/V"~'-1---- Sandra L. Hamann Permit Coordinator RECEIVED JUL 08 1996 Attachments Alaska 011 & Gas Cons. Commission Anchorage 91#:~vSL 9L~ LOG 1RCO AlautI. tnc I!S.I $uDs.ØI.a,~ of AII."hC..R.C"r'.'Q(:o,nøllnv ;--1VlN3WNO~IAN3 OJm' : n:~1 96-ij-L ,W9 30Han~cl: Á9 .LN3S ÀVij 30HOmIJ:)..g JN3S "'1VlN3WNO~IAN'3 OJ~ ~ 'Gf¡:Zl ~ 00-9 -1.. ~ e G. Ziauneman, ADNR/LWM, Fairbanks 1. Beeiman, ADEC, Faitbnnk~ A. Ott, AOF&G, Fairbanks K. Mueller. USFWS. Fairbanks J. Hansen, USEPA, Anchorage R. Morris, NMFS. Anchorage L. Fanter, COE. At\chQ~g<: W. Marumeak, NSB. Barrow 1. Wharam. DNR/OOG. Anchorage P. Wightman, DOC, Faírbanks Car. ,ne 7118/90 Page 2 . ¿1#~ZÞ9L. 91..Z LOS cc: e e LINER INSTALLATION DESCRIPTION DS-16, SUMP 3 SCOPE The soudI end of an existing Prudhoe Bay Unir (PBU) reserve pit. Sump 3 at Drill Site 16, will be Hned with a perimeter curtain liner to create a temporary disposal facility fOT driUîng wastes generated at AAI's PBU drill sites. Drill Site 16 is located On high, dry tundra, in an area. virtuaHy free from Sag River flooding. A similar lined pit was constructed in Sump 2, just west of Sump 3, in March. 1989. The lined. pit will be created by constrUcting a gravel benn across Sump 3 to subdivide it. Subsequðntly, the liner wîll be installed around the isolated south end of the pit. TIle perimeter of the new pit will be trenched and lined with 80·m.íl High Density Polyethylene (HDPE). The lined pit area will be approximately 3.8 acres. The tundra elevatíon in this area is approximately 33 feet; the gravel pad has a wp elevation of approximately 39 feet. Before the new gravel berm ìs constrUcted across the existing reserve pit. the. ex.isting drilling wastes in the footprint of the new berm will be bulldozed to the main pit. Also. existing drilling wastes in the new pit area may be bulldozed to me main pit to provide additional srorage volume. The new benn will be about 200 feet, long and 24 feet wide on top, with 3: 1 side slopes. Approximately 1.500 cubic yards of gravel will be required. Gravel will be obtained from Put 23 or other approved SOUTce. The liner will be placed in a trench excavated through the gravel embankments into the underlying tundra. Specially designed ttenching equipment will excavale a trench approximately 12 inches wide and approximarely 10 feet below the top of the gravel. The liner, consisting of 80~míl HDPE, will be placed in the trench to within 6 inches of the top of the graveL All field joints in the liner to achieve the required length (approximately 2,300 linear feet) win be made by heat bonding. Prior (0 backfilling. the lined trench will be inspected by an AAI representative. The encountered. soil conditions and liner locations wíll be documented. By keying the impermeable liner into permafrost, a barrier wilJ be fonned to prevenl seepage from the pit during its operalÎon. Eventually the contaminated pit coments will be disposed of in an approved permanent waste disposal facility. The folJowing sections provide the infonnalÎon required for ADEC approval of perimeter liners keyed into ~nnafros( for the temporary stOnige of drilling waste. Plot PI~ .- A plot plan is attached. The liner will be installed near the cenrerline of the perimeter benns. Based on 3: 1 side slopes, [he liner will be located about 25 feet from the pic bottom (toe of slope). R E C E 1 V E D ....1VlN3WNO~ I M8 OJ~ JUL 08 1996 96-9 - hlB;Ska 011 & :~cih~~0jòIl}~~3: Áa oos 91#:~t9L 9L~ L06 ~t:~1 e e T .iner Specifications " Tè;chnical information for 80-mil HDPE is attached. This robusr material is more than satisfa.ctory for [h~ application; it is also fUlly compatible with the materials contained within the pÎt. Field joints in the liner will be made by heat welding; no adhesives wìl1 be used. In~la1l3tion Procedures - The liner manufacturer does nOt have installation procedures, including bedding. for installing HOPE into perimeter trenches keyed into pennaftost, because this application is unique to petmafrost conditions of the North Slope and northern Canada. This installation will be modeled after numerous similar installarions on the North Slope, as described below. The liner will be cut to sections at least 10 feet wide. A continuous. straight (except at comers or curves in we berm) trench will be excavated at the location shown on the drawings. The trench will be excavated in a manner that minimizes sloughing or accumulation of debris at the bottom. The liner will be placed venicalJy, to full depth. to form an impermeable banier. The liner material may be posirioned intO the ttench with a blunt instrument which does not puncture the liner material. Any punctures or tears in the liner will be repair~ with heat-bonded patches prior to placing the liner in the rrench. Field joints needed to achieve the continuous length will be heat bonded to p1"ovide a durable. continuous, and irnpenneable joint. Heat bonding wíl\ be perfonned with a heat~wdding machine capable of providing a double-weld, with a separatìng .air chamber. Weld integrity will be verified by pressure testing the air chamber with 30 psi (minimum) air for 15 minutes. Pressure testing wiU be perfonned prior to installation of the field joint into the trench. After installation in the trench, the liner will be held in a venical position and secured at the top of the gravel during pJacement of backtïll. The liner will be protected at all rimes from punCture by equipmem or backfill. Backfill will be dropped from no higher than three feet above the tOp of the gravel benn. Backfill will be placed at a rate which promotes unifonn distribution of material and minimizes formation of loose zones or voids within the backfilled envelope. Surplus trench cutrings will be deposited in an approved location. AAl's geotechnical/QA representative will be on site to inspect and document the work as well as witness the pressure tesúng prior to acceptance. ~eyjnr ÙltO.. PeJTl1afros,t ~ AAI has considerable fietd data documenting the maximum depth of thaw in Nonh Slope gravel pads. The proposed 10 f~ot embedment depth is below the maximum t:haw found in gravel pads 5 - 6 feet thIck which overlie tundra vegetaùon. The underlying permafrost, about 1.800 [0 2.200 feet t:hick. wiU be a suitable bottom barrier for temporary storage of drilling waste. Free:;cepoint tests of Prudhoe drilling wastes have consistently shown freezepoint temperatutes around 310 F, so significant freezepoint depression does not occur. The liner wi)} be installed at lease 75 feet from nearby wells in order co avoid the thaw bulb associated with producing wells. 61#~~t£L 9L~ LOG ....1VlNdWNO~ 1 Ml3 OJMV Ct:~1 96-9 -¿ ÁVg 30H011~cl:Á9 lN3S ÁV9 30Han~d:Á9 1N3S 96-9 -L tt:Z1 ...1V J.N3WNO~ I Ml3 OJMV OZ#:Zt£L 9LZ LOG Thennistor Ins~allation . A new thermistor installation is not planned. The thermistors installed during lining of Sump 2 adjacent 10 this lined pit will sufficiently monitor the depth of thaw. In addition. thennistors installed in other similar facilities have shown that this liner will be adequately keyed into permafrost at the depth proposed. A summary of relevant temperature data from lined pit installations. taken during the warmest periods of 1989, a panicularly warm year. has been previously provided to ADEC. lltc.':se dara. include readings from the four thernústors at DS 16, which show th.at a. liner installed to a depth approximately 4 feet below tundra level, under a 6·£oot gravel berm. will be well-keyed into permafmst. e e e e ..... "" '. ',iioKUI< :$, ~o . -. ?,AY PRUDHOE BAY VICINITY . -.. .. . ... ~ ! ~N ~ . -.. NWtUIC '4 " ..... " IUl IS. '\ ;-~-~ .... t..J w CP\ ~ 'S&1-1 I , ~ ,. I ;~. ~. I I -,..¡~~ : !. "f¡, N :' ~ -1·\ /\ Ti'ON'" ;<GJS-j-···- {V' ., ""'~~._-."-'---~- I ' , / ~/ ì DS-6 I, "- I '. S_1.~\ . -., { tj ,If \ ¡ 1",.# .. .\... , '8000 ~. o I f.~ 1>'P£.~'- r": OS-3 1 .. )f .-. " , ~//4--' I '¥\. r~gx~g1 J' f \IY I ¡ as..~ 17 DS~ 16-1 ... t··· . , :7' - .. . -.. PROPOSED RESERVE PIT PERIMETER LINER AT DRILL SITE 16 PRUDHOe: BAY UNrr NORTH SLOPE BOROUCH STATE Of ALASKA .. l S~( IN FEET ACRtAGE: NO NEW ACREAGE IMPACTED VOLUME: APPROX, 1500 ç,y. LOCAnON: SEC.24 T1 ON-R 1'E U.M, PURPOSE: OIL FIELD OEVELOPt.tfNT AOJAÇENT LAND OWNER: STA.TE OF ALASKA DATUM: MfAN SEA LEVEL -, Aøølicatiøn bV~ 4RCO Al...ASXA INC. $hIll8' .L ')f .1. ~atx::JUL Y t 990 A40189000 I RO 1~#:~t9L 9L~ LOS ....1V .LNdNNO~ I AN'3 OJ~ 9t:~1 : gG-ij -L : Ava 30HŒl~J:Aa !N3S ÁV9 3000CUld:Á9 lNdS Ap~lita(ÍolI Dy' ".RCO ALASKA INC. SMet.l. QI,..l ~03te: Jµt Y 1 990 A4Q1890002 RO PROPOSED RESERVE PIT PERIMETER LINER AT DRilL SITE 16 SUMP .3 PRUDHOe: BAY NORTH SLOPE BOROUGH STATE OF AlASKA 96-9 -L 917:(;1 ....1V .LNdWNO~ I ANd OJm' (;~#~~ÞSL 9L~ L06 N.r.s. SECTION A-A 24' 15' , . .. . . i IO'± ¡.. '¡ ¡ 3 I ! ¡ II ~~4 I .:;^ ~. l ~ 10'1 tJ D"'"I ¿:'-' 6.o·t ..~. ,.. '?-..Y." "'}"^-'\.>·~"·Ù" 'A..\::-J. .:./. /.: , UNDERL YINC TUNDRA ~ .)'; ,/ J ~')">. v>:.w L HOPE LINER RE,,-e;R TO SHT. J of J ¡:OR INSTAU.AnON DETAIL. ¡ l. I .. \"..- PROPOSED : 0 ~ LINER I ~ I I , I I I I I I I .' SUMP I I 3 I I I I I I I I I I I I I I I , I \~J¿; NOTE: 1. APPROXIMATE VOLUME OF NEW CRAVEL BERM · 1500 C.Y. 2. APPROXIMATE LENGTH OF' HOPE LINER .. 2Joo' . 3. APPROXIMATE SURFACE AREA OF' RESERVE PIT .. J.B ACRES. J tiJ ~ I d r---'--" -.6 -<9 e THIS PRO.;e:CT SUMP 2 a\~ i ~-= IJ --- [ . S. 1 6 PLAN VIEW NTS 7- 8- 9- 10· -.-J e Á \19 3OH<JíUld: Á9 .LN3S 96-9 -L Lt>:(;l ....1\1 .LNdNNO» I AN3 WID' PROPOSED RESERVE PIT PERJMETER UNER AT DRILL SITE 16 LINER DETAIL PRUDHOE; e~y UNIT NORTH SLOP£ BOROUGH STATE OF Al.AS1<A AøjÞûe«lGn~: ~>lCO ALASKA INC. Sne~t J af ~ :;)Qle; JUL'( I 990 M0189C)()O,3 ItO LINER INSTALLATION DETAIL N.T.S. . . .- EXISllNG ~':~ a~" /: TUNDRA ·"~·4' ·0." I I Q Þ-./iiiII 0." ð. . ~~4 ",,~&Wj~ ...-> HDPf;"~ :?i »~ ~ -, LINER .- ~K. TRENCH I (80 MIl) .:. '-- CUTIINGS .., ¡ ~ ~ I !;, , ~. . <~ ,% '. ''\;5;P?};j;(.f/., ~~ {I~~" :;A. . ¡ _, . 12" NOMINAL TRENCH I ~ I , /r- TOP OF GRAVEL BERM ¡ f i r~.. .....·ë.~.. ;".' ......... ..·.·ã·~. ;'.' I 1· O.·4.·4.·~.·cI..I..q.·éII.·4I;iI.'4."<: , ~.·4./IIct.·04..'CI.·" . a..' Q'.I,IIIIiI.'dlll t Q..' ø.' .. . . I Iœ... 4..;' . ·'4.~ Q, ~:. \ ~~~: .. _ J-'_ '...j,o. ·...Go ....~ '.ð. aL ,..... '~A. .....Q '..~ :. 1II.p.'.a. ',,"0. ...0.....( .11II> '..c.. ~.ë. ".Do '.I jÞ.o. '..0. '..~ ....&. .. I . '.0 ....5- ;'.0. ."?I t . ..., ....Ò'.e.· I r ~...o.~..J ~ - -'\._Q." ........ -;0. '.. . 0""0.'. '.0. ....... co a:: w > o ü ~ PERIMETER BERM ~ ~ - C6#:&t>£L 9L6 L06 , I ~¡ ...... I i I I , I I I I , e e e ~ '" dl.1. 19 Syslemillnc GtlJJfñ1©J~@ ---..~.. æ t=:~V~ øt? MI ·0 ... C;UNOLINE' HO IS a tugh QLJ'¡¡0'Y Icrmu'ðllon 01 HIgn Density POlyetnytene CO/'llðlntng 3DOrOXlmatelll !i7.5~. DO/yrner and 2.50'. 01 caroon OlaCI(. dnll-oJlIOanrS and neal sraDIhZers. The orot:lu~1 was aeSlqn4ld speClficallv tor e.PQSed COl1(llltOns. II .:;ontalns no aaalllves or htlers wnu:" can leacn OlJ! ana cause .mannlømen, Over tlma ... "-~"",, ~. GUNDLINE! HD SPECIFICATIONS ....,. ~ , ~ J -" . TEST GAUCE PROPERTIES· ."<I£THOO (NOMINALI J JD mlt 40 mil 50mi 60 mil 80 mil 1DO M" 120 mil 140 n : .~ -"', . ;, -noo. . ~ ~ml .!~-~. .. ·.....1 J .,)~~" j =~, " : fnSIIV q 'c. I MIn I ~STM C ~~O5 ) 3.¡ ~ 94 : 94 ) 94 0)94 ') 94 )94 J9~ I.. . '4*' Flolll I/lCleX ~STM DI238 j 1 ;. J ) J )3 ., ~ J ) a 3 ) ) . !~. mill IMU.I . :;n~lflon e ' · ~~'t; 2 .(; ,I' . -~"Sllt "tQOt'fJeS ~m"OiiH T.;f." -¡p,,;alj ; .~o-crn !Il : ':" ~ensu. SllInQtll "'11!leu . :~ '~O :~Q ~.IQ 320 :1)0 ~80 ::"K . ilouACIs rnçn 'MlCrft' reM,,, Slrcnqlft III 'I'II!IØ .~ ~5 "5 '.to :90 :,so ~90 ¡JO . rOu/lØ$.lntn ..,Olhl Elo/lqJl1OfI il StUll ·~o -jO "JO '00 :'00 :';)0 ·00 ~Co , Ptft!llll . ~k¡nQ¡lQn It Y:etcl '3 ·3 'J ~3 13 "3 '3 ~) I PtfC!llIl ModUlUS DI EII$CtC:lfy ~STM 08112 . . . 1 I' 1 : 11 . " . , , ~OuPclS If' sau...,e ·neft _ 1O" ·ur fltSI$UIICC ,nil/alto/! "STM D:CO.t :),e": ¿Z ;0 Jì -5 55 tiS ðO ~!i 05. ITI'OIW! ~JW Tcmoetalurr ilrlnlcness. F ~SiM Q~lti P''1:~(ure' . '·2 - ., 2 . . ~, .::z ... ~ ~ 2 - "2 - 112 - :, rVOIc.aH :' rntnSIQn¡, SlaD1iI1V '. C hanqe ~~iM O;2~J - - - . - " - - - . . - ;;2 - . ~Jcn iJlredtoll ,M.JJI I ~. Z'F l' ò~SIStllllU 10 SO¡¡ Burllll ~.s iM 03083 ~'.r9 ',tetlll cn~ ~STM D6Ja T~Oc IV ~ UOQNI ,,¡¡to I rYO~1I :UITIO-Ort, al 2 :m rlllslit SlteR9tn il 8real( ; . cnallQf ~ 10 : 'Q " '0 , 'Q ='Q : 'Q ~IO =~O Int feIQ EICl/lliIlan I( are"'lI ' . C\¡nQc :'0 : '0 ::\0 - '0 = 10 :: '0 ::10 ='0 ¡no YICId EtIV\~ Stress Cf~. >\STM 01693 : soo '500 '500 . :00 :500 :SOO :sao ':00 i'IOIn. IftM.1 110", lçeD¡I, SO'CI ?UJIâI" Ael.t1UllCl. mAS 101 30 52 as ~o 105 130 t~O !1)9 PoundS. I TyllQll J«ernoo 20155 COdIœtf !If "'lIeU o\$TM 0696 I 2 I 2 : Z . 2 ' 2 t 2 12 ~ 2 Themw ÚØi/IIIOII. · 10-' h ¡TYIIICIII em TllIIIIIII S~ "STM 03&95 2000 lOCO 2000 ;'JOO ZOOO 2000 zooo taco OJJQ.J1IIIt 1/IðI¡a¡an "me lOin. - .:IO"C. 800 DSI 01 1.Iø.s. IMift.l "Note: All values axCIDl wn~n speC/fief! as mInimum or tnUlmum are typteal test rest/Its. ........ 17 _4..__........__1D_........__JMQ~_;_~_.._..__.._.__. ...... H...----_..aNI'Ie__. J J ] 1 ] 1 1 1 1 1 1 I 1! 11 tì#~ìtSL 9Lì L06 ....1V~O~IM13 O::>IDi' ¿Þ:ì1 96-g -L Áva 30HŒ1~d:Áa JN3S · e .. (;...IN'~ Lf5 .. Ql. _ ~ vAl.... PRODUCT DESCRIPTION JOINING SYSTEMS CrirjcallO rM success of any f81C101e mflmOfane Ilnar 1$ Ine 10111'''9 system. Qunalé:s Hot-Wedge Welding Svstem and øar.nrea EJltn.&Slon Weldtng System ars used to lOIn IndIvidual oanels ot aUNOLlNé HD. ReQuest your coPy of I"e Gundle JOIning S)'stems BUlletin lor comOlete aetall$. .. CHfMICAL RESISTANCE .. aUNOL.INE He is reStatent to a wide range of chemlCa,1S .ncludlf1g aClds_ aIll;811.. salts. alCQnols. am",... ods. iItI4 otner nVdrocaroo~. Since comOln&lIØnS of chemtcals ot different concenU'iilltlMS aI'Ø temp.ratuRl$ nave ClIHerenr cnanlCleOSbCS. consuII Gunale lor Specific applicatiOn CletaJ~. WtIte for Gunate s cnemlCaI compatibility Informarlon. SUPPlYSPECIRCAnONS The fOlloWing aeScob.S IVolcal rOil dlmenstM$lOr GUNCUNE HD. mil mm 11 m tt m ftl m~ Ib kg 30 0.75 22.5 6.86 640 256 18.900 1756 2800 1272 40 10 22.5 6.86 650 198 14.6ZS 1359 2800 1272 SO 1.25 22.5 6.8S 500 152 11.250 1043 2800 1272 60 l.S 22.5 6,66 420 128 9.450 878 2800 1272 -' I eo 2.0 22.5 6.86 32Q 98 7.200 610 2800 1272 100 2.5 22.5 6.86 2$0 76 5.625 522 2800 1272 120 3.0 22,5 6.86 210 64 4.725 439 2800 1212 140 3.5 22.5 6.86 t80 55 4,050 377 2800 1272 aUNOLINE HO 1$ rOllecJ on 6" 1.0. hOllOw cores. Eacn rOil 1$ ørov¡G&1C2 WIth 2 sungs to ala l'Ianallno on Sll'. Dimensions aM 'Nè'9nlS art aoøl'OKlmate. Custl')m lengtt1s aVillliIDle on reQuest_ Gundl. Linio9 Systems 'nc ~ .... \ ,.,-.---- . .. l~. i: ""~n .....-:n¡a ~ \~tf. ." 't...Jj\li/-~ -......;;... ":.-.:: - , . . ,=. ~~. Gundle llnang Sysrems Inc 19103 Gundle FloacJ Houston. Texas 77073 U.S.A. Phone: (713) 443-8564 Toll Free: (800) 435-2008 felex: 4620281 Gunate Hau J:ax: (713) 875-6010 ....1VJ,N3NNO~IAN3 OJm; ':' ~~~1···t 96-9 -L ~--" ).Vg doooh~d:).g OOS £~#: Zt£L -9L~ LOG e . . --- Ir~ Lc o ARCO Alaska, Inc. Post Offic@ BOx 100360 Anchorage, Alaska 9QS10-0J60 Telephone 907 276 1215 "" / ~-... ~~ .// .,., ,...... November 191 1990 Mr. Brad Fristoe . Depamnent of Environmental Conservation lOCH Noble Sa-eet . F~rbanks,AJ(,29701 Re~';:'tor Dear Mr. Fristoe: In response to our conversation today on the malfW1ctioning thernùstor string at DS 16, I am enclosing the additional information you requested. Attached is a diagram showing the location of the reserve pit perimeter liner in question. A second diagram shows the locations of the four them1Ístor strings. The strings were installed vcnically and adjacent to the outside sides of the liner with beads at 3. 6,9. and 12-ft intervals below the surface of the pad. String B at the soutll side of the pit began malfuncú.oning in July 1990; readings could not be obtained in July or in August. The liner was installed. in March, 1989 and keyed into pennafrost at a depth of nine feet below the pad surface. I have located the results of themùstor readings taken every month from May, 1989 to August, 1990 with the exceptions of July, October and December, 1990. Readings defPonsttate that the liner is leeyed into pennaffost at nine feet. The highe~t reading at nine feet was 0.1 CO taken from B thennîstor on August 23, 1989. The following table shows the túghest temperamres recorded at each depth and from each string. High Temperatures (CO) Recorded from D516 Thennistorsl . ,. .. Depth (feet) --aelow Pad ~uiface String , . 3 - ,.. - 6 ' ... . 9 -.. . ..n"A 7.3 (7190) 2.4 (8/8~ -[6 (9/89) B·· 6.3 (6/89) 6.S (8/89)·· 0.1(8J89) C 7.1 (7/90) 1.8 (6/90>"·' -1.6(9/89)·· . D -- 6.9 (7190) -0.5 (S190) :2.4(9/89) T 1 Total of 175 readings --- ... .. .. lž M3.1 (9/8~) -2.2(9/89) ~3.5(9J89) -3.9(9~9) AS I indicated. our Maintenance Department has determined that it is not feasible to repair String B. The string would have to be replaced to continue monitoring subsurface temperatures at that location. Because the thermistors, voluntarily installed by ARCa, have accomplished their intended purpose, we do not intend to replace the string. If you have any questions please call. Sincerely, ø~ Bob Elder Director Field Environmental Compliance RECEIVED JUL 08 1996 Alaska all & Gas Cons. Commission Anchorage ARÇQ A'.a'R.K.o\, h\O i. ~ $"'~.Idi...y 0. ÂUen1ÎGQ'ç....,'oC'.csComÞòJny 9~#:~t£L 9L~ L06 ~1VlNdNNOMIANd OJMV : 6t:~1 96-9-L ~'1:ï=3.:;r,;' ;,t; Ava 30HŒlMd: Aa JN3S PROPOSED RESERVE PIT PERIMETER LINER AT DRILL SITE 16 PIIUOHOE BAY NORTH Sl..0P£ 8CØJUGH $fATE OF' ALASKA· ÁV9 30HOilMd:Á9 JN3S o 400 I -.....--. .-4 SCALe IN FEET 400 '- 01 A~I \IIC'UI ~1V1NctNNOMIAN3 OJMV : OS:~1 : 96-9 -L : L~#:~tSL 9L~ L06 DRILL SITE 16 FOR DETAIL SEE SHT. J OF .... 11 .... Q I~ A Å \ '1~ ~'-ß' ~ - -- ~ is i z f- lit .¡ - 0' 16. \ 15. e1 l7e 18- 14. e2.19_ 20. j 1.3. .321. 12- .4 J 11e e524 · 10- .6 ge 8e -- ,,-' . . :..,. .... .. ..-... ...... -..... ;':':',: .:.:~~~~\;:::";~-:~~~: ::~~:: ~~~.t" r .. fF' L. ,1"- e e ~.- 'III J I I¥ ARCO ALASI<.\ INC. SfIMt..l~~ OeM: .uq '.... . .....1V.Lt\GWNO~IAN'3 OJ~ : 1£:(;1 : 96-9 -I. : ÁVg 3OHah~d:Á9 lN3S 9(;#:(;Þ£L 91.(; 1.06 PROPOSED RESERvE PIT PERIMETER UNER Â T DR'LL SITE I e PRUDHOE: 6'y NOImf SLOP£ 8OROUIiIt 'SOOE Of" ALASKA , t O'J: "-I f '~ë·~.~' ~C·-~· 5' NOtoItNN. '·D··'" '/1'..0'. . ~.....~~~~~ ~~" ~~~ru. '-LNER REFER TO SHT'. 4 r;¡ 4 FOR INSTAlLAT10N O£1'All. SEcnON A-A .. - N.T.$.. .. 20" LOCATION PlAN 190'± -... ...-. \ 200 .... 1 o _.,.1 n_ SCALE !N FEET 200 '- .. , L A ,.- rJ9.!Jf ~ 'y- --7. ~ NEW GRAVEL . is ~ BERM (1500 C.Y,) ~ ð C ~.Fff/ //"':L--. Z ~ --r::~- /'"1'"7' ~1 ui2 010 I·~ I © \~'\..7 r--NEW PERIMETER LINER SEE SECTION A.-A \ ¡L® nJERII'STOR STRING (lYP) o ~ I I I I J70'± , 75':'- t--- ,; \ ~~..__':'... r - e e - e DEPARTMENT OF THE ARMY u.s. ARMV ENGINEER DISTRICT, ALASKA P.O. vex 898 ANCHORAGE, ALASKA 996Q6.0898 ".rL,Y 'r'Q A""'&"''''O'' or. SEP I 4 (990 ! "'~ ¡ .",~? ·T·'l~:\·í "Ùiuj':o-\,t¡> j ~.J'H'~ ~. I: ._.....:..:..~_:! ..::.:" ,~.. 1 ¡.\Qjl ;:..;.'..ö..·.:.,. i~1 ;~I "o':J' (. ·190 \\Mt.:\ '~. "._.' .) I~ 1..........-- f._! '.... ¡ iiJD , I ....." ...... ~ . ~. . _....):".t.. r.. .. , ! \~:,-rt1.1·:::' :.. 1...;.:~...lpt:wr1..;::éJ I j i--- --.¡ "---'--:--~--I " :-- ~ fl.,; J .'~..:.J"~.. .'h..FJ:,J ~':".~~) v."J¡:'ï G.r... \ ! .. I ... . . .,... : ',¡.) L-.:...\.----. Regulatory Branch Compliance Section 9~790218 Ms. Sdndra L. Hamann ARCa Alaska, Incorporated Post Office Box 100360 Anchorage, Alaska 99510-0360 Dear Ms. Hamann: This is in reply to your J~ly 18, 1990, letter requesting a jurisdictional determination for new work at an existing reserve pit (Sump 3) at Drillsite 16 under Depð.rtment af the Army permit number M-7902l8, Prudhoe Bay J. The proposed work calls for installing a perimêter liner on the south end of the existing reserve pit (Sump 3) at Drills;te 16 for temporary disposal of drilling wastes. The original pit would be subdivided with a gravel berm and the pit perimeter would be tret1çhed and lined with polyethylene which would be keyed into the permafrost to create a continuous barrier to any potential seepage. We have determined that your project as proposed would not change the scope and intent of the original permit. Therefore, no further authorization is required from this agency. Your statement concerning future rehabilitation of the pad is noted and will be included in the file for this project. This determination should not be construed to me4n that the work proposed ;s not within Corps of Engineers' jurisdiction, rather that further authorization (or modification) is not necessary for this specific project. In the future, to allow this office to make a determination concerning the need for any additional authorization for projects similar in nature, please provide a letter explaining the methods to be used and plans. Nothing in this letter shall be construed as excusing you from compliance with other Federal, State, or local statues. ordinances, or regulalions which may affect the proposed work. For informational purposes, a copy of this letter is being sent to the agencies on the enclos~d list. S6#:6t£L 9L6 LOS ....1V LNdNNOll I M8 OJlIV 19:61 9S-9 -L ÁV9 30001}ld:Á9 .LNdS e e 2 Should you have any questions, please contact me at the address above, call (907) 753-2720 or by Fax at (907) 753~5567 and refer to project file number 9-790218. Sinçerely. ~~. / - pl£li ç.. }.~ ,'1 ~~ ~loyd H. Fanter ~ ~ Northern Unit Leader Compliance S@ction Enclosure OC#:6Þ£L 9L6 LOS ....1V .LNdWNO~ I AN3 OJmr 6£:61 9S-9 -L Ava 30Han~d:Aa !N3S e J.il Ott~ ~egional Supervisor, R~gion Habitdt Protection Section Alaska Department of Fish & Game 1300 College Road Fairbanks, Alaska 99701 lIf Paul E. Gertler, Field Supervisor U.S. Fish ðnd Wildlife Service Fish and Wildlife Enhancement Ecologica1 SerVices/Endangered Species Branch 101 - 12th Avenue~ Box 20 Fairbanks, Alaska 99701-6267 AJaska Department of Environmental Conservation 1001 Noble Street, Suite 350 Fairbanks, Alaska 99701 Patti Wightman, Regional Coordinator Office of Management and Budget Oivision of Governmental Coordination 675 7th Avenue, Station H Fairbanks, Alaska 99701 Mr. Dan Robison, Jr. Alaska Operations Office =nvironmental Protection Agency 222 West 7th Avenue~ No. 19 Anchorage, Alaska 99513-7588 e Ronald J. Morris, Western Alaska Ecological Supervisor National Marine Fisheries Service Federal Building, U.S. Court House 222 West 7th Avenue, No. 43 ~nchQrage, Alaska 99503-7588 Alaska Department of Natural Resources Division of Land and Water Management Northcentra1 District 3700 Airport Way Fairbanks, Alaska 99709 Thomas Duncan. Assistant Planner Advanced Planning Division Department of Community Planning Fairbanks North Star Borough Post Office Box 1267 Fairbanks, Alaska 99701 ~r. Steven Zimmerman. Chief Habitat Conservation Environmental Assessment Division National Marine Fisheries Service Post Office Box 1668 Juneau, Alñska 99802 tC#:~t£L 9L~ LOG ....1V1N3WNO~ I M8 OJäV (:g:~t 9G-9 -L À V9 3OH<1í1~d: À9 1N3S e e STEVE COWPER, GOVERNOR DEI-T. OF NATIJRAL RESOUItCES Po. BOX 101034 ANCHQA4GE.AlASKA 991110.7034 PHONe~ (907) i'ti2-25~a July 23, 1990 DIVISION OF OIL AND GAS Ms. Sandra L Hamann Permit Coordinator ARCQ Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 9951 O~0360 ··JMS j ïHP ¡ SCA I .SUi·' ~MP RGE K,C. MVERS MJF RWH \. ,. 1") c;. 1990 MJN ,- ·¡UL ."'.' - . . BJD - ~Ra/U::hurnQ - PO'l1'Iit. & Compliance -Fïle [A~lurñl HQl1cSio 1 \t: I Copy 1 Cln; Regarding: DS 16 Reserve Pit Perimeter Uner Installation LOINS 90..98 (79-81) Dear Ms. Hamann: The Division of Oil and Gas has reviewed your July 18, 1990 notification lettar which describes ARCO Alaska. Inco's proposed installation of a perimeter liner around the south end of Sump 3 at Drill Site 16. We have no objections to this project, as proposed. Since the placement of the perimeter liner does not alter pad configuration, the purpose of the facility remains unchanged, and no portion of the work will be done on-tundra, Arco is not required to obtain either lease o~rations approval or amendment to an existing lease operations approval for this project (although other permits may be necessary from other state, federal, or local government agencies). DO&G appreciates your efforts to keep us notified of proposed activities on State oil and gas lease lands. Sincerely, v~~~ John Wharam Natural Resource Officer cc: Joyce Beelman, DEC-Fbx Warmn Matumeak, NSB-Barrow AI 001 DF&G~Fbx Patti Wightman, DGC-Fbx Greg Zimmerman. DL& WM-Fbx 07268 ~~#~~t9L 9L~ L06 .... 'WJ.N3WNO~ I MB OJmr ~9:Gl 96-9 -L Ava 30HŒ1~d:Aa J.t\l3S e e STEVE COWPER, GOVERNOR .. .~ .-, - ...~..~ - i .._.... DEPT. 0.... ENVIRONMENTAL CONSERVr\TION (9071 452-1714 Sandra L. Hamann Permit Coordinator ARca Alaska, Inc. P.O. Box 100360 Anchorage, Alaska I JMS I TH~.J SCA I SLH ',(iMP RGE 1':.0. MYERS I MJF I~ . 1- ~ ~I:I ~ (} í~90 I~ . .. t BJO - F·:fHI/LI:¡Durn~ r-- 'permit!) 6. Co.TlP/lancet . I'n"lRoturn I 1-18n,:lu, I '1::\ Cl/øv[ CltC. No~thern Regional 1001 Noble Street suite 350 Fairbanks, Alaska Office July 26, 1990 99701 99510-0360 Dear Ms. Hamann: Re: DS 16 Reserve pit Perimeter Liner Installation Prudhoe Bay unit/Easte~n Operating Area Thê department has reviewed ARea Alaska, Inc. 's proposal to install a perÜneter liner around the south end of existing Sump 3 at Drillsite 16. The department is not issuing a formal plan approval for this activity; however, the department has no objection to the installation, as proposed. Please contact me at 452-1714 if you have any questions concerning this matter. Sincerely, t!4 /1 ~ Robert P. Cannone Environmental Engineer rpc/pg cc: Brad Fristoe 300.15.148 RECEIVED JUL 08 1996 A\askª QII Rt Ga$ Cons. Commission .".. Af\chOfage CC#~6t£L 9L6 L06 ;.-1\1 IN'3WNO~ 1 AN3 OJW t£:61 96-9 -L Ava 30H(J(l~d:A9 lN3S . e Warren Matumeak.. Director ,NORTH SLOPE BOROUGH PLANNING DEPARTMENT ~. P.o. Box 69 Barrow, Alaska 99723 Phone: (907) 852~2611 FAX: (907) 85.2-5406 o 508 West 2nd Avenue, Suite 310 Anchorage, Alaska 99501 Phone: (907) 279·9505 FAX: (907) .277-1443 July 23, 1990 !JMs·I!HP IBc~l sLi-t· EMP " RGld ~c, MvERS IMJf RWI1 '1 '1 '"t r.' '990 ' MJN· I ,I... I) I . . BJO -I - ~F.a/l..; :J:¡urrtQ \Perm!~:I 11 C'?,Mof/_l\nC$ _.. I'¡IOI R8_I~rl' i HOMIIII5,J: J COPYl CI~C Sandra L. Hamann, Permit Coordinator ARCO Ãlaska, Inc. P.D.Box 100360 Anchorage, Alaska 99510-1215 Re: MINOR ALTERATION DS 16 RKSERVE PIT INSTALLATION, PR.UDHOE BAY UNIT ¡EASTERN SECTION 24, Tl0N, R15E, UMIAT MERIDIAN PERIMETER LINER OPERATING AREA Dear MS. Hamann: We have reviewed your letter dated July 18, 1990 in which you have requested authorization to install a perimeter liner around the south end of an e~isting reserve pit (Sump 3) at Drillsite 16. We understand this lined pit will provide an area for temporary disposal for drilling wastes associated with dri.1.1ing at various locations. The lined pit will be approxima.tely 3.8 acres; the pit and pad configuration will remain unchanged and the intent of the activity is consistent with the o~iginal permitted purpose. Approximately 1500 cy of gravel will be placed [or the new berm. Th.is action and the a.ssociated work will in no way restrict or preclude the District Engineer's options for reclamation of the site in accordance with the general conditions and/or special conditions of the original authorizat:i.on or any subsequent modifications. It is my determination that the above proposal is a minor alter.ation to an e}(isting use, as detîned under NSB 19.20.020 (43), hence excluded from the term "Development" pursuant to NSB 19.20.020 (30), and thus does not require ô. permit from this office. t£#:~t£L 9L~ L06 ....lVlN3NNO~ I AN3 OJ~ t£:~1 96-9 -L A V9 30HO!1~d: A9 J,N'3S . \ . '. l e . Minor Alteration DS 16 Reserve pit .July 23, 1990 We have no objections to the proposed activity and are recommending consistency with our Coastal Management P~ogram to the State by copy of this letter. If you should have any questions, please contact Terry Rail at 852-2611, extension 247. Sincerely, ø~~,-.¿- Warren Matumeak I,and Management Administrator cc: George N. Ahrnaoga~, Sr., NSB Mayor James Sceeles, NSB Permitting Division Ben Nageak, Director, NSB Dept. of Wildlife Management NSB Planning Commission Members Karen Burnell, Manager, NSB Assessing Department Jerry Wilt, Prudhoe Bay Operations and Industry Liaison Mike Disler/Ward Wiebe, Mgrs. NSB Industrial Development Michael G. O'Connor, piquniq Management Corp., Barrow Rick Smith, DNR/DL&WM, Fairbanks Al ott, .DF6iG, Fairbanks Paul Gertler, USF&WS, Fairbanks Patti Wightman, OMB/DGC, Fairbanks Paul Bateman, DEC, Fairbanks Georgina Akers, COE Zaccharias Hugo, Acting Mayor, Anaktuvuk Pass Elizabeth Hollingsworth, Mayor, AtqasuK Don Long, Mayor, Barrow Herman Aishanna, Mayor, Kaktovik Thomas Napageak, Mayor, Nuiqsut David Stone, Mayor, Pt. Hope R E ( E I V E D Amos Agnassagga, President, Pt. Lay IRA Counc . David BOdfish, Sr., Mayor, wainwright Chuck. Joy, Acting Arctic Area Manager, SLM JUL 08 1996 June WeinstOCk, Fairbanks John Whar-am, ADNR/DO&G, Anchorage Alaska Oil & Gas Cons. commiSsion Anchorage WM/m-l frm. £C#:6Þ£L 9L6 L06 ....1V j,N3NNO~ I AN3 OJMV ££:61 96-9 -L Ava 3OHŒ1~cI:Aa lN3S #12 .. ARca Alaska, Inc. Posl Office 80.. 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 . ~~ ~, J . I" . May 2, 1996 ~\G "3> ~\O ~~ Mr. David Johnston Chainnan Alaska Oil & Gas Conservation Commission (AOGCC) 3001 Porcupine Drive Anchorage, AK 99501-3192 RE: Class II Oily Waste Pilot Testing North Slope Grind & Inject Facility (G&IF) Prudhoe Bay Unit - Eastern Operating Area (PBU - EOA) 4(,s ~ °ü ~~ ~~<. . ~ ð., ?,., I.<~ ~ '~ Dear Mr. Johnston: Per our discussion on March 18, 1996, ARCO Alaska, Inc. (ARCO), operator of the PBU - EOA, is performing pilot testing of Class II oily waste disposal utilizing the G&IF located at DS 4. The purpose of this letter is to provide the AOGCC with information regarding this pilot testing. Prior to addressing the pilot testing referenced above, at the March 18, 1996 meeting, the AOGCC requested information regarding other grind and inject operations in service on the North Slope. This information is summarized as follows: There are currently 2 grind and inject types of operations in service at Prudhoe Bay. These operations are the CC2A facility and the DS 4 G&IF. Although both of these operations utilize Class II - D wells completed in the Tertiary/Cretaceous formation to dispose of wastes, there are some differences in these operations. The CC2A facility actually consists of 2 plants, which are commonly referred to as the "ball mill" and the "injection skid". The ball mill is used to process and inject (non - oily) solid wastes suitable for Class II disposal, such as drilling cuttings. The injection skid is used to inject fluids suitable for Class II disposal, such as water based drilling muds. Both plants use the same disposal well. The CC2A Class II - D well is an open hole completion with injection occurring at about 3600' TVD. The DS 4 Class II - D well used by the G&IF (i.e. DS 4-19) is a cased hole completion with injection occurring through perforations below 5600' TVD. The CC2A disposal facility operates in a "batch" fashion (i.e. processing and injection of wastes suitable for Class II disposal is done in a startup/shutdown mode as wastes are brought to the facility) whereas the G&IF is a continuous operation (i.e. processes and injects wastes around the clock during the "winter" operating season). The CC2A ball mill plant typically injects wastes at rates of about 3.5 - 7.0 bbls/minute and the CC2A injection skid typically injects fluids at rates of about 4 bbls/minute. On occasion, both the ball mill and the injection skid are operated at the same time, yielding injection rates of up to about 11 bbls/minute. The G&IF typically injects wastes at rates of around 20-25 bbls/minute. CC2A injection pressures typically average about 600 psi. G&IF injection pressures have averaged about 1190 psi. The CC2A facility has injected about 7.5MM bbls total volume (including an estimated 300,000 cubic yards or about 1.44 MM barrels of solid wastes) during the +/-5 years that it has been at its present location. The G&IF has injected about 4.0MM barrels total volume (including over 190,000 cubic yards or over 912,000 barrels of solid material) since startup in March, 1995. In previous years, a portable ball mill commonly referred to as the "Pool ball mill" has been set up at the CC2A location as well as at drilling locations in the Kuparuk field to handle drilling wastes. The Pool ball mill operates in a AR3B,6003-93 2422603 May 2,1996 . AOOCC Corr. - 0&11"' Pilot Testing Page 2 . batch fashion at rates of about several barrels/minute and is incapable of handling oily material suitable for Class IT disposal. This unit is currently shut down. Regarding the pilot testing of oily material suitable for Class II disposal, as you are aware, oil production operations often result in accumulation of sands and other sediments inside of production vessels. This phenomenon occurs routinely in the PBV. In order to efficiently operate the various production separation and treatment vessels, this sandy material is periodically removed from these vessels in the PBV flow stations and gathering centers. Material removal is conducted using what is referred to as sandjet systems or by other mechanical means, depending on the particular vessel and facility. This sandy/sediment material, hereinafter referred to as "sandjet material", is a material appropriate for injection into a Class II disposal well since it originated from downhole within the producing formation and has been in continuous contact with other downhole fluids (i.e. produced oil, water, and gas) until removal from the production vessels. Currently, Flow Station 2 in the PBV EOA is the largest generator of sandjet material. This facility produces about 125 - 150 cubic yards of sandjet material per quarter. Other PBV production facilities typically generate lesser volumes of this material. This sandjet material has previously been disposed of at the temporary storage cells located at the Pad 3 facility located near DS 6 in the PBV - EOA. Storage of such material (as well as storage of other non-hazardous solid material) is conducted under regulatory approvals issued by the AK Department of Environmental Conservation (ADEC). However, the only active storage cell at this facility (i.e. Cell 2) is nearing its permitted capacity. Construction of additional cells at Pad 3 is an option which is viewed as a "last resort" for dealing with future non-hazardous solid wastes, due to new cell construction costs, double handling of waste material, and other similar factors. The PBV has constructed an oily waste skid, which is located at the CC2A pad in the Western Operating Area of the PBV. This oily waste skid will be used for processing of oily wastes suitable for Class II disposal after startup.· The oily waste skid and the existing CC2A facility will utilize the same Class II - D well. The current CC2A ball mill facility is not designed to handle oily material, which is the reason that the oily waste skid was designed and built. This new facility, which arrived on the North Slope last summer, is undergoing modifications to allow this facility to be able to accept oily wastes suitable for Class II disposal in the physical forms that such wastes are generated. The startup date of this oily waste skid is currently scheduled for the first part of June. 1996. ARCO (and the PBV Owners) have been examining other options to handle oily wastes suitable for Class II disposal, such as sandjet material. The pilot testing of handling and disposal of this sandjet material at the DS 4 G&IF is being conducted as an alternative management method for these types of oily waste material. The pilot testing plan is summarized as follows: · The roughly 125 cubic yards of sandjet material is layered in the OS 4 drilling waste temporary storage area with drilling wastes excavated from the development reserve pits undergoing waste removal. · The sandjet material/drilling waste mixture. which is in a frozen state. enters the G&IF via the normal waste feed system (i.e. - a hopper and conveyor belt). This waste mixture is further mixed with drilling wastes as it enters the facility by the addition of May 2,1996 . AOGCC Carr. - G&lt< Pilot Testing Page 3 . extra loads of routine drilling wastes for every load of the mixed waste that is introduced into the hopper. · This waste mixture is then thawed, ground, and slurried in the semi autogenous grinding or SAG mill at the facility. The wastes are then routed to injection pumps for disposal into DS 4-19, which is a Class II - Dwell. · ARCO has performed calculations concerning this resulting mixture to ensure that levels of compounds contained in these wastes (e.g. benzene, hydrogen sulfide, etc.) as well as explosive levels of this mixture when introduced into the G&IF remain below human health regulatory thresholds and internal safety and personnel protection criteria. · As an additional precautionary measure, plans call for monitoring of pilot testing operations by industrial hygiene personnel. Adverse monitoring results would dictate revisions to or discontinuance of the pilot testing. ARCO is aware of other regulations that could come into play with this pilot testing, such as AK Dept. of Labor and/or Federal Occupational Safety and Health Administration (OSHA) requirements for personnel exposure. However, we believe that the advance planning for this pilot testing addressed any foreseeable concerns in these types of areas. This pilot testing has also been discussed with the AK Department of Environmental Conservation (ADEC). As we discussed in the March 18, 1996 meeting, this pilot testing was slated to be conducted during the latter part of March. The pilot testing was postponed until the beginning of April due to G&IF operational difficulties associated with the rubber liner in the SAG mill. The pilot testing was completed during the first week of April, 1996. Although final results are unavailable at this time, preliminary data from this pilot testing were encouraging. No apparent formation damage occurred from this pilot test and no significant safety or environmental issues surfaced from this test. We plan to continue with limited pilot testing of a similar nature using material suitable for Class II disposal and the G&IF in the future. We will keep you informed on these activities. If you have any questions or desire additional information regarding the subject pilot testing, please do not hesitate to contact me at 265-6136 at your convenience. Sincerely, ~~ Mark Major Sf. Permit Coordinator Prudhoe Bay Operations c: James Chatham, ADEC - Anchorage Wendy Mahan, AOGCC - Anchorage Janet Platt, BPX - Anchorage #11 ~~~~E (ill r lÆ~fÆ~~~fÆ . AIfASIiA. OIL AND GAS CONSERVATION COMMISSION / TONY KNOWLES, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE. ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 April 22, 1996 Janet Platt Supervisor, Compliance EnvironmentaI/Regulatory Affairs BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage,AJe 99519-6612 ~\C) ~ Á. \\) '-\ ~ Re: Request for Approval-Material to Facilitate Disposal of Cuttings in a Class IT well Dear Ms. Platt: The CominÍssion has received your request to use either newly mixed or recycled mud to facilitate the disposal of drill cuttings from the planned extended reach. wells in the Niakuk field. The extended reach wells will be drilled from late April 1996 through January 1997. A mineral oil based mud will be used, because conventional water based muds are deficient in both stability and lubricity for the drilling of these extended reach wells. The approximately 2,000 bbls of cuttings generated on each well will be coated with mineral oil. According to your letter dated April 3, 1996, it will be necessary to mix another 7,000 bbls of either recycled or new mud (if recycled is unavailable) with the cuttings to create a pumpable slurry for injection at the CC-2A class IT facility. Traditionally, water or seawater is used to create a pump able slurry for injection. If the mineral oil coated cuttings are mixed with water only, the resultant emulsion will be unsuitable for injection due to operational constraints of the Oily Waste Skid. The recycled mud that you propose to use has already been downhole, is RCRA exempt and acceptable for injection in a Class IT disposal well. The Commission views the use of this mud to facilitate disposal of the drill cuttings as a beneficial reuse option before ultimate disposal of the fluid. In the March 2~, 1993 "Clarification of the Scope of the Oil and Gas Exemption" published by the EnvironrneÍ1taI Protection Agency in the Federal Register, treatment of exploration and production exempt wastes prior to disposal does not negate the exemption. Since unused water based drilling mud is a nonhazardous fluid, the use of water based drilling mud to facilitate disposal of the cuttings is an acceptable practice. _. ~ 1. David Norton, P .E. Commissioner cc: Robert Mintz, Dept. of Law .... ... . . BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Certified Mail # d g I i-£/- 3 c¿?4- April 3, 1996 '''"'ICoJ.i ",.. Y" f'" \".I n....'.... "'" ,-- r~str- ~ fN:..~~'¡.::71--·~~ ¡.~(;:~~:~: -f' I t '.' ...··"r'" --' /":'.:..'''.''-[ I ¡~';' ..=i.~~ L::~'.'; . f ¡i:;"'-~=~·. _J.' r··-·-......-·' - I*Ê~L-·· ';-¡-~'j ¡;;:¡~:r~·;~: .".-¡ ...~~....,!.'::;_',__,.,:,:.:.. ....ao- ~ I '·~Tú-;':< - f .::'...!.....:..:,.. ·"--1 : ~ ---"-','1 "''''.j! JiLE .. f Mr. David Johnston, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr. Anchorage, Alaska 99501 Request for Approval - Material to Facilitate Disposal of Cuttings in a Class II well Dear Mr. Johnston: BP Exploration (Alaska) Inc. (BPX) is seeking approval from the Alaska Oil and Gas Conservation Commission (AOGCC) to use either newly mixed and/or recycled mud to facilitate the disposal of drill cuttings from upcoming wells at the Niakuk Field into Class II wells. Beginning late April 1996 through January 1997, BPX plan to drill several extended reach wells at Niakuk. These wells have a horizontal reach of approximately 20,000 feet and will require the use of mineral oil based mud. Water based mud properties are inadequate for wellbore stability and lubricity on extended reach wells. A Material Safety Data Sheet (MSDS) for the L VT 200 oil base mud is included for your review. The mineral oil based cuttings generated from drilling these wells will be disposed of at the CC-2A Class II Facility. However, due to operational constraints at the Oily Waste Skid, the cuttings must be in a pumpable slurry form to be acceptable for disposal. Each well drilled will generate ±2000 bbls of cuttings. In order to facilitate disposal, it will become necessary to mix ±7000 bbls of mud with the cuttings in order to achieve the viscosity needed to suspend the cuttings in a slurry. BPX requests AOGCC approval to use either newly mixed and/or recycled mud to facilitate disposal of these cuttings. Please contact myself at 564-5501 or Karen Thomas at 564-4305 if you have any questions or need further clarification with regard to this request. RECEIVED APR 0 5 1996 Alaska 011 & Oat Cont. commiøiOØ Anchorage Mr. David JOh. . April 3, 1996 Page 2 . Sincerely, I 1~(tV. RMi- a et D. Platt, Supervisor En iron mental Compliance, Alaska JDP/KMT cc: w/attachment Wendy Mahan, AOGCC RECE1VED APR 05 199& AIakI Oil , Gal ConI· CM¡1r.i"i;p AildllrJII . ~onoccÐ® . CSPlOO22 Revised 28-SEP-1993 Printed 5-0CT-1993 L VT 200 CHEMICAL PRODUCT/COMPANY IDENTIFICATION Material Identification "LVT" is a registered trademark of Conoco. CAS Number CAS Name Tradenames and Synonyms Paraffinic Solvent Company Identification MANUFACTURER/DISTRIBUTOR CONOCO INC. P.O. BOX 2197 HOUSTON, TX 77252 64742-47-8 Hydrotreated Distillate, Light PHONE NUMBERS Product Information Transport Emergency Medical Emergency 1-713-293-5550 CHEMTREC 1-800-424-9300 1-800-441-3637 COMPOSmONjlNFORMATION ON INGREDŒNTS Components Material CAS Humber 64742-47-8 % Cycloparaffinic, Isoparaffinic, and Normal Paraffinic Hydrocarbons >99 HAZARDS IDENTIFICATION Potential Health Effects Substance Information Primary Routes of Entry: Ski~, inhalation (Continued) Printed on Recyded Paper . . HAZARDS IDENTIFICA110N(Continued) The product may cause irritation to the eyes, lungs, or skin after prolonged or repeated exposure. Extreme overexposure or aspiration into the lungs may cause lung damage or death. Overexposure may cau'se weakness J headache, nausea, confusion, blurred vision, drowsiness, and other nervous system effects; greater overexposure may cause dizziness, slurred speech, flushed face, unconsciousness, and convulsions. Carcinogenicity Information None of the components in this material is listed by IARC, NTP, OSHA or ACGIH as a carcinogen. FIRST AID MEASURES First Aid INHALATION If inhaled, remove to fresh air. If not breathing, give artificial respiration. If breathing is difficult, give oxygen. Call a physician. SKIN CONTACT Wash skin thoroughly with soap and water after handling. If irritation develops and persists, consult a physician. EYE CONTACT In case of contact, immediately flush eyes with plenty of water for at least 15 minutes. Call a physician. INGESTION If swallowed, do not induce vomiting. Immediately give 2 glasses of water. Never give anything by mouth to an unconscious person. Call a physician. Notes to Physicians Activated charcoal mixture may be administered. To prepare activated charcoal mixture, suspend 50 9rams activated charcoal in 400 mL water and mix thoroughly. Adminlster 5 mL/kg, or 350 mL for an average adult. FIRE FIGHTING MEASURES Flammable Properties Flash Paint Method Flammable limits in Air, LEL UEL >200 F (>93 C) PM % by Volume 1.0 6.0 RECEIVED (Continued) APR 0 5 '99& A\aSklOI&BøCald. ~ ~ CSPf0022 Page 2 · e FIRE FIGHTING MEASURES(Con1inued) NFPA Classification Class IIIB Combustible Liquid. Extinguishing Media Water Spray, Dry Chemical, C02, Alcohol Resistant Foam. Fire Fighting Instructions Special Fire Fighting Procedures: Water or foam may cause frothing. Use water to keep fire-exposed containers cool. Water spray may be used to flush spills away from exposures. Unusual Fire and Explosion Hazards: Products of combustion may contain carbon monoxide, carbon dioxide and other toxic materials. Do not enter enclosed or confined space without proper protective equipment including respiratory protection. ACCIDENTAL RELEASE MEASURES , , , ¡ Safeguards (Personnel) NOTE: Review FIRE FIGHTING MEASURES and HANDLING (PERSONNEL) sections before proceeding with clean-up. Use appropriate PERSONAL PROTECTIVE EQUIPMENT during clean-up. Initial Containment Remove source of heat, sparks, flame, impact, friction or electricity. Dike spill. Prevent material from entering sewers, waterways, or low areas. Spill Clean Up Recover free liquid for reuse or reclamation. Soak up with sawdust, sand, oil dry or other absorbent material. HANDLING AND STORAGE Handling (Personnel) Wash thoroughly after handling. Wash clothing after use. Handling (Physical Aspects) Keep away from heat, sparks and flames. Close container after each· use. Storage Store in accordance with National Fire Protection recommendations. Keep container tightly closed. oxidizers, heat, sparks and flames. Association Store away from (Continued) R£CE\VED APR 0 5 '996 Atas\(¡ Oil. Oae Qq\~. CQmmi&&iøn Anchorøg8 CSPI0022 Page 3 -. . e EXPOSURE CONTROLS/pERSONAL PROTECTION Engineering Controls VENTILATION General mechanical ventilation normally adequate. Personal Protective Equipment RESPIRATORY PROTECTION Select appropriate NIOSH-approved respiratory protection for organic vapors where necessary to maintain exposures below the exposure limits given below. PROTECTIVE GLOVES Should be worn when any potential exists for skin contact. NBR or neoprene recommended. EYE PROTECTION Chemical splash goggles or face shield recommended where splashing can occur. OTHER PROTECTIVE EQUIPMENT Sufficient protective clothing to minimize skin exposure. Coveralls with long sleeves if splashing is probable. Exposure Guidelines Exposure Limits LVT 200 PEL (OSHA) TLV (ACGIH) AEL * (Du Pont) 500 ppm, 2000 mg/m3, 8 Hr. TWA None Established . None Established · AEL is Du Pont's Acceptable Exposure Limit. Where governmentally imposed occupational exposure limits which are lower than the AEL are in effect, such limits shall take precedence. PHYSICAL AND CHEMICAL PROPERTIES Physical Data Boiling Point Vapor Pressure Vapor Density % Volatiles Evaporation Rate Solubility in Water Odor Form Color Specific Gravity 430-550 F (221-288 C) 0.4 mm/Hg ~ 100 F (38 C) 6.2 (Air = 1) Nil Not Applicable Insoluble Nil Liquid Clear, colorless 0.82-0.83 (Water = 1) (Conlinued) I \ CSPI0022 PaS:¡6 4 · e STABILITY AND REACTIVITY Chemical Stability Stable. Incompatibility with Ot~er Materials Incompatiblè with oxidizing materials. Avoid excessive heat and flame. Decomposition Hazardous gaseslvapors produced are carbon dioxide and possibly carbon monoxide. Polymerization Polymerization will not occur. TOXICOLOGICAL INFORMATION Animal Data Animal studies have shown that prolonged or repeated inhalation exposures to high concentrations of some petroleum distillates have caused liver tumors in mice and kidney damage and tumors in male rats. However, kidney effects were not seen in similar studies involving female rats, guinea pigs, dogs, or monkeys. Present studies indicate the kidney effects will only occur in male rats. Also, human studies do not indicate this peculiar sensitivity for kidney damage and studies reported in 1992 showed that this particular type of rat kidney damage is not useful in predicting a human health hazard. The significance of liver tumors in mice exposed to high doses of chemicals is highly speculative and probably not a good indicator for predicting a potential human carcinogenic hazard. DISPOSAL CONSIDERATIONS Waste Disposal Treatment, storage, transportation, and disposal must be in accordance with applicable Federal, StatelProvincial, and Local regulations. Recover nonusable free liquid and dispose of in approved .and permitted incinerator. TRANSPORTATION INFORMATION # Shipping Information DOT Not Regulated. DOT Placard None ICAO/IMO Not Restricted. Placard None RECEIVED (Continued) APR 05 199& Q Oil & Gas Qgna. commission Atll _ Anchorag8 CSPI0022 Page 5 " . . . TRANSPORTATION INFORMATION(ContinUed) MEXICO Not Regulated. Placard : None Shipping Information Canada This material is Not Regulated. TOG Placard None REGULATORY INFORMATION u.s. Federal Regulations OSHA HAZARD DETERMINATION This material is hazardous as defined by OSHA's Hazard Communication Standard, 29 CFR 1910.1200. CERCLA/SUPERFUND Not applicable; this material is covered by the CERCLA petroleum exclusion. Releases are not reportable. SARA, TITLE III, 302/304 This material is not known to contain extremely hazardous substances. TITLE III HAZARD CLASSIFICATIONS SECTIONS 311, 312 - Acute Yes Chronic Yes Fire No Reactivity No Pressure No SARA, TITLE III, 313 This material is not known to contain any chemical(s) at a level of 1.0% or greater (0.1% for carcinogens) on the list of Toxic Chemicals and subject to release reporting requirements. TSCA This material is in the TSCA Inventory of Chemical Substances (40 CFR 710) andlor is otherwise in compliance with TSCA. RCRA This material, when discarded or disposed of, is not specifically listed as a hazardous waste in Federal regulations. It ~ould become a hazardous waste if it is mixed with, or comes in contact with, a listed hazardous waste. If it is a hazardous waste, regulations at 40 CFR 262-266 and 268 may apply. CLEAN WATER ACT The material contains the following ingredient(s) which is considered hazardous if spilled into navigable waters and (Continued) RECEIVED t. CSPI0022 Page 6 APR 05 1996 Alaska au & Gal CDns. CønJniItjøø Anchorage " - ,. .... . . r REGULATORY INFORMATION(Conlinued) therefore reportable to the National Response Center (1-800-424-8802). Ingredient(s) Reportable Quantity Petroleum Hydrocarbons Film or sheen upon or discoloration of any water surface State Regulations (U.S.) CALIFORNIA ·PROP 65· This material is not known to contain any ingredient(s) subject to the Act. PENNSYLVANIA WORKER & COMMUNITY RIGHT TO KNOW ACT This material is not known to contain any ingredient(s) subject to the Act. Canadian Regulations CLASS D Division 2 Subdivision B - Toxic Material. Skin or Eye Irritant. Transport/Medical Emergency Phone Number: 1-613-348-3616 OTHER INFORMATION NFPA, NPCA-HMIS NFPA Rating Health Flammability Reactivity NPCA-HMIS Rating Health Flammability Reactivity o 1 o 1 1 o Personal Protection rating to be supplied by user depending on use conditions. The data in this Material Safety Data Sheet relates only to the specific material designated herein and does not relate to use in combination with any o-thermaterial or in any process. Telephone MSDS Administrator Conoco Inc. PO Box 2197 Houston, TX 77252 713-293-5550 Responsibility for MSDS Address H Indicates updated section. End of MSDS RECEIVED CSPI0022 Page 7 APR 0 5 1996 AIaSØ 011 & Oa, CCln,· cQmm\$i\Qn Anohoflgtt . R.e-g.i..ter I Vol. ~8. No. 53 I Monchy. March 22. 1993 I Rules and ReguJat10IU . r ,: , .:.:':: , ..~. , ' I······ teGc:raJ 25H6), Tho R~uletory Detennination included elist of exunple wastes ÙlIIt generally ere exempt and II list of ex.emple wastes thaI generelly ere not .;. . exempt Neither of these lists wes intended to be a complete itemiution o{ .11 possible exempt or non-i:xempt wastes. Also. because definitions of the tenns used in these lists vary. !be criteria identified in ilie Report to Congres.s remain the authoritative source for detenninins !be scope of the exemption, The reader is referred to the Jul)' 6. 1968. notice {or detailed badground on aU aspects of !be Regulatory Detennination. Since 1987. ilie terms uniquely e.ssocit.!ed and iri trirui c ba V1! been used as interchangœble S)"':'Ionyms in various documents in reference to oil and gas wastes qu~Jifying {or the exemption froro Subtitle C ~lation. (For simplicit~"t we. whe-n referring to __ exempt WWM. thù notice combines the .. ' use of these two tenns into the Jingle tenn uniquely u.sodat&d.J A ~irnple rule of Ù1umb for detennining the Ja)pe of ~e exemption i~ whether the waste in. question hu Ctlme from down·hole (i.e,. : ~: " brought to the sumœ during oil U1d r;a.s ,- UP o~tions} or hu olhènrlu been generated by contact with Úle oil wd gas production stream during the rrmoval of produced water or other contaminants from the product (e.g_ waste demuIsiIif1rs. s~t iron sponge). .If tho an~r to either quomon is yes. ,,:. tho ~stl! is m~ 11l:ely a:msidered ' :~~ exempt. . ;~ Since the Agency's Regulatory ~f..' DderminatiO'!1. numerous requests have _ .' be-cn f'eCei\'ed for determination. on a "',- ¡:ite-spccifie ~!is, of the regulatory ..... r;t8(US of 'wa.stes not itemized in the .,' R~18t':lry Dete:mination's list of ex.e:nples. Ma.'1Y of these requests ha\'e ~._ de;:¡lt ""ith broad categories of $imilar' ~~ wastes (e.g.. crude oil reclaimer wastes. service Ctlmpw)' ....-astes. .pipeline wastes). Toda:..·s notice responds to the' _ . mOlDY requests for clarification of the scope of the e~eI:1ption. IL Cbrifiation of the Scope.ofthe Oü and G.u Exemption ;r A Crude 9í/ Redamation Industry ...:. The erode oj] reclamation industry ~. recovers. marl.:etable aude oil and other :.. hydrocubons from produced water. . crude oil .can!: bottoms and other oily . __ wastes 0at are generated by !be production of crude oil and natural gas. .... In general. !be mari:cLBble crude oil is ':Overed from thtl waste materials by .1ple therm¡¡1 and/or physical .0 proce~s (e.g.. heat LInd gravity '-Gpuahon). Oa:asionaJly. demulsifiers l1è1Y be added to produced wat!!TS from - '::. ." - .. ~"'. .... :~...~... -< ""hieh crude oil cannot be ~parated with heGt and utuing time .Ione. The typical residual material. left after removal of the avde oil by WI! reclaimeT3 are also produced water and tani: bottom solids. Thes.ð residulIls wiJl ohen'exhibit the same charllcteristk:s as We parent waste, although lbl! concentnltions of JOme constituents may vary from thos.e in ilie parent. . In September 1990. lbe avde oj] reclamation industry requutod lbat the ^gency provide an interpn!taüon of the language in ilie1988 Rðgulatory Determjnation pertaining to RCRA Subtitle C conreg1! of wast8$ from crude oil and tani bottom reclaime~. (The list of"non~xempt" wastes in the Regulatory Determination included "liquid and JOlid wastes generatød by crude oiJ wd Wl1: bottom ~aimen."J In particular. Ù1ey iequested !bat EP A clarify ",-hetber any wastes genented by C"'Udf1 oil red4imers r.n: included within thf1 oil and gas f1Xempûon. p41'Ûcularly iliose originating from the crude oil itself. s-uch as produced water and the ~r e.xtra.neow m&.teriak Ú1 crude oil. otherwís.e .t:nown u huic s.edimant and water (BSk W). . In .April 1SH11. the hgeDcýt1!$ponded to the request with I letter Ù1at included. broad guicWtœ on the status of wastes from the crude oil rec:i4mation industry. CA ccpy of Ù1e letter is includød in the docl:et to this nO't.ia.) EPA explained thai the indu~o:1 of "liquid and JOlid ~es" from cude oil naclam.ation on the list of non~xcmpt wutes contaIned in the Regulatory Deten:::1lnatian WaJ: inhIDded to r-efer only to those non-Eå.P waste$ ~nerated by recla1m~ (e.g.. waste solvents from cleaning recl4imers' equipment) and was not intended to refer to wastes remaining' from the treatment o{ exempt wastes originilly generated by Ù1e exploration. development or production of crude oil or natural g2S. EP A's basis for Ù1is position is &everal-folcL Fi."'S1., Ù1e Agency lw c:msistentlr ta~en Ù1e positiOIl that wastes derived from the treatment of an exempt waste. induding eny recovery of product from an exempt waste. " generally remain exempt from the _requirements of Rc::RA. Subtitle C. Treatment o{, or product recovery from. E!r.P exempt wastes prior to disposal ,joes not negate the exemption. (The S<lme principle applies to exempt mining and mineral processing wastes. Sec, S4 fR at 36621 cSept. 1. 1989}.) For example. waste ~iduals (e.s.. BSlcW) from We on-sÏle or off-~Ïle process of recoverinf: crude oj) from tank bottoms obtained from avde oil ~orage facilities at primary field operaûoru (i.e.. opentions at or neer the wellhead) are 15285 exempt from RotA Subtitle C bðCa~ the crude oil storage tani: boUomt at primary IieJ.d operations are exempL In effect. reclalmers are conducting a specialized lonn of waste treatment in which valuable product is recovereå and removed /Tam waste uniquely associated with UP operaûons.In addition. in many cases, product recovery or treatment reduœs the volume and overall toxicity of the waste an~ thereby contributes to the Agency', pohcy and goals for waste minimization and treatment of wl!.Ste prior to di~po.ul. £FA furtber notes iliat the off-lite transport of exempl waste from a . primary field site for treatment. . reclamation. or disposal does Dot negate !be exemption. The change of cwtody criterion (wbichJs discu~d in the Report to Congress) {or the purpose of def1ning transportation refers to the transport of product (crude oil. natural gas) and does not apply to exempt wastes moving orr-~ite for tre.atment oc disposal since these Wl!.Stes wen! generated by the exploration. development or production operations and not by !be transporution .proc:eu. Thus. the off-site transport ADd/ar Ale of exempt oil·field wast~ to crude 011 recJaimers {or tre.Blment doez not terminate the exempt ~atus e.lthcr of the - .::. ", wastes or tbe residuals from., . reclamation process applied to thes:.s -. -' ._>. 'A wastes.. . . .:, ;~~ However. Ù1m-e are .solid and ?quid -':; ./~ ~es from roclamal1on ope11rt.ío~ tlat . . :':S: are not exempt from RCR.A Subtitle C. . '.' ,.~' These are wastes which Ù1e ^r;mq . .. , Intended to refer to In its eXAmple with.in tho 1988 Regulatory . Detennination. Generally, tbe;,e redaimer wastes are derived from non- exempt oi1field wastes or otherwise contain materials that are not uniquely usoc:iated with exploration. . development or production operations. }.n eumple would be waste solvents generated from the solvent cleaning of tank trow Ù1at are used to ~ort oilfield tan!:: bottoms. Such wastes . would not be exempt from Subtitle C because the use of cleaning solvents is not uniquely associated with the production of crude oiL ' . GeneraIJ.... crude 011 reclaimer wast~ that are derived from exempt oilfield wastes (e.g.. produœd water, BS&W) IJ'1 not subject. to the SubütJe C wute management requirements of RŒA. Such wastes. however. n!main subject to any applicable stnte solid waste management requirements. Moreover. this exemption from Rc::RA. Subtitle C requirements may not apply if the crude oil reclaimer wastes are combined with other wastes that are $ubfect to RŒ.A Subtitle C requirement£. . -. '. ·f·" -:. .'-:. .::::..:~ . :' ·::·:·{i . .- '. . - . - ., . "- . .. Federal R.e-gÍJ:ler I .01. 58. No. 53 I Monday. March 22. 19::0.1 I Rules and Regulations .,.r' . .... =~ 15Z66 -. .': '.- D. S~n'íce Companí~s Oil and gll~ servicII companies are (hose compa.nies hired by ilie principal operating com pan)" to. among otiler things. supply materials for use at II drilling or production site or pro\'ide a serviœ to 00 performed. Some of the octivities of urvice compenies take place on-site while otilef"$ may ta1:8 place off-site. .Examples of the types of activities tilat mey ta1:e pIece off-site are product formula lion, transport of materials. laborelory anelysis. and wasle handling and disposal. The 1988 Re6uJ.~lory Determination stated ~t "oil and gas service company. wastes, such as empty drums. drum . rinute. vacuum trud rinsate. s.andble.st media. painting WAStes, spent ~Ivents. spi1led chemicals. and waste lcids".are n~t covered by the oil and gas EA:P exemption. The Agency intended this statement to identify \base wastes, . induding unused and disa.rded . product materials. generated by service companies that are not uniquely associateå with primary field operatiocs.. (primAry field operations occur at òr near the wellhead or gas pl~t and include only thOSð oper;¡üons neo::s.s.ary to locate and recover oil.nd gas frorå the ground &nd to remove impurities.' Siaùlu to the refe."'8nce to crude oil tedamatioc wastes. the Agency did not intend to imply t1ut under DO circumsU.Dces will I $MVÍce ....". compL"IY ever genents a RŒ.A Subtitle ,;. : Cexecnpt \Nute. For example. if. servic8 company generate~ q>ent acid retWU$ from a well worl.:-over, the waste is exempt since the waste acid in this . case came from down-hole and we.s part of pómary field operations. '. . £PA is aware that some confusion exists in various segments of the . industry with regard to the scope of the exemption from RŒA Subtitle C for solid wastes not uniquely associated with oil and gas exploration and production. One common belief is that ar.y wastes generated by. in sùppor1 of. or intended for use by the oil and gas E&P indU$try (including most service . company wastes) are exempt. This is not the case: in !act. only wastes generated by activities uniquely associated with the exploration. development or production of crude oil or natural gas at prima.ry field operations (i.o., wastes from d0Y07l-hole or Voõ1stes that have otherwise been generated br contact with the production stream during the removal of produced water or other contaminants from the product) are exempt from regulation under ReM Subtitle C regardless of whether they are generated on-sHe by a service company or ùy the principal operator. In other :..."': .,þ :..-... ~... ". ~ ~; ~: ~., G~~:~ ':'.. ..' ~ .r g fti -~ ,I f~ {I s ~Y! i ¡. I. '. I'. IS-' ;"¥'~ . ;-1" .' '·or ¡it .!.' ,.... , -- I I, I !~; .!;.' þ.. .t i" : .'.. .: ; ¡:f¡ '1 i i " <~ , I ! -.; " ~ words. wastes generated by a service company (e.~.. unus.ed fnc or stimulation fluids and wasle products) thaI do not meet the basic crileria listed in the Report to Congress (i.e.. are not uniquely associated with oil and gas ,. E&P opera lions) are not exempt from Subtitle C under the oil and g;¡S exemption. just ðS wastes generated by r. principal operalor that do not meet these crileria tore not exempt from cc\'err.ge by RCR^ Subtitle c.. . The 1988 Regulalory Determmatlon also state<! thaI "vacuum trod and drum rinsate from trow !lnd drums transporting or contejnin~ n~n~xempt waste" is not included wlt111n the exemption (emphasis added). The unstated corollary to this is that vacuum trueJ: and drum rinsate from trucks and drums tr;¡nsportjng or contajning exempt wastes is exempt. provided that the truds or drums only contain Ekp· related exempt wastes &.Dd that tile we.ter or fluid used in the rinsing is not subject to RŒA Subtitle C (i.e.. js itself non-hazardous). This is consistent ,,;th the gener;¡l policy prinople t.h41 certain wastes derived. exclusively from RCR.A Subtitle C~xempt wastes remain e~pt from RŒA Subtitle C. C. erode Oi! PipeJjnes Crude oil is produced. from the ground through I system of 01M! or more wells in an oilfield. The oj) !lnd any rela.ted produced water tJ'Pic:aUy is dirT:cted. to a. s.eri~ of Lana bOWD a..s . I tani: battery where the water lIüd oil ~par.ate naturally due to gravity: ~mc:times, separation is enhanced by the use of heaL Most water is upuated from the oil at the tan};;. battery. The volume oC oil produced is then metered prior to a change in custody or own~rship of the oil and/or its transportation off-s.ite. In the C%.se of crude oil. aU production-related activities occ'ur as . part oC primary field operations .at or near tile wellhead. W¿$les generated as p<lrt of the process of transporting products away from primary field operations are not exempL Generally, for crude oil production, a custody. transf~r or the oil (i.e., the product) or, in the absence of custody transfer, the end point of initial product separation of the oil and wlter. will define the end point of primary field o~rations and the beginning of transport!tion. Only wastes generated before the end point or primary field operations are exempt. In this context. the tenn end point of initial product separation me;¡ns the point lit which crude oil leave!> the lllst vessel. including the stock tt.nk. in the tank b:llte'1' associated wilh the well or wells. The purpose of the tank ballery is to sepuate the crude oil from the produced waler and/or Ras. The movement of crude ojl by pipeline or other means after the poinl of cUE;tody transfer or initiol product separation is not pllrt of primary field operlllions. Therefore. IIn)' waste generated by the trensportation or handling of the crude oil (product) lifter custody transfer or. in the absence of custody transfer. after the end point of initial product ,eparation of the oil and wllter, is not within the scope of the exemption. Examples of non~xempt wastes resulting from trans porta Ii on include transportation pipeline pigzing W8stes. contaminated water and snow resulting from spills . from transportation pipelines or other forms oC transport of the product. and soils contaminaled from such spills.. It should be noted that the hydrDCllrbon- bearing ~ils identified in the 1987 Repon to Congress and listed in the 1988 Regullltory Determination as being exempt are limited to those hydrocarbon-beering ~oils that occur It .-. oil or gas E&P ,ites or result from spills' . of exempt waste. As di,scussed above. ~ the exempt sllltus of wastes generateå by ~ primary field operations and .' .:>: transported off-~ite for (raiment or ..; :. '~):. disposal ~s not affect&d by custody '. :~.:=. transfer. . . · ..' . '.' D. Cas Plants and F~der pjpeIines'_ ;. . ~::. Natunl gas is produœd from the . _ ~~. . ground through II sys:tem or ODe or mo.ré '. wells in a gllS field. Some water may be: ." ~paraled from the gas al the wellh6ðd. ,... but due to economy of sale, the gas . from several weBs is generally commingled and sent to a O:Dt.ral ga..s plant where additional water and other impurities are removed.. The ownersbip, or custod}', oC the natural g~ commonly changes hands betw~n the wellhead and the gas plant. yet the removal of impurities from the gas at a gas plant is still a liecessaJ}' part or the production process for natunil gas. . Fo:- natural Gas. primary field operations (as defined in the 1987 Report to Congress) indude those production-related ectivities at or near the wellhead and at the gas plant (regardless of whether or not the gas plant is al or near the wellhead) but póor to transport of the natW1ll gas from the g;¡S plant to marbL Because the movement of the natural gas between the wellhead and the gas plant is considered a necessary part of. the production operation. uniquely' ASsociated wastes derived from the production stream along the gas plant ft:i:der pipelines (e.g., produced water. g:1S condensate) are considered exempt wllstes. even if 8 change of custody oT the natural gas has occurred bel ween r--.... . . . --. .._. __ . "'-__" ."-- .-. ."".....'C:I> ..uu ^c¡<u'öUulIS 1~~87 the wellhud An~ Ú1~ g~' plant. so. volume generaled by ~he Jnitial · All supporting ò~mentation for wutes gcncreted 6t this product~on prOduc.1ion.ln e,rrect. in tbe cxmtext of the r~u}atory determination. includillg t:uJ:e me)' not be uniquel)" assocustlld the E&P exemption. Ùle Jtonge of public comments on the Report 10 wl:h the nalural glls production stream nlltura~ gas in natural undeJ'tTound Congress and EP A response to and are. therefore. nol exempl (e.g.. formaltons returns the glls to Ù1a comments. and pump lube oil. waste m~rcurJ lr~m beginning point of the production · Transcripts from the public meters and gauses). SimlJarly. SOIls process. heanngs on t~e Report to Congress. contaminatcd by spills of wastes that are III Ad . . t t· P__ h.1 11._ AU supportmg documentalion for this . J .. d 'lb d cti . aunts ra lYe. mceuure "" Fed -. R . I N r 'I bl not umque y a:~oClat~J WI pr~ u don Rt'1luin:ments , ~I"~ e~l..(der_\.. 0tlC8 a:ø nF'al II e lor operations. suu.¡ as SOl s contammate mspectlon In ou..e numoer -93- b}' roe:CUJ)' hom gaugesöare not exempt Today's notice is issued without OGRC·FFFFF. wastes. request for pubHc comment since it d~ ~tc:d: March 11. 1993. Westes generated at compressor not revise. amend. repeal. change. or . Jtich.ud r G' d stations and facilities located alonR the otherwise alter any EP^ regulation. nor . . wmOI:l . transportation and disUibutjon nelwork constitute a change to £Ph's 1988 ~S$~tta~~~an ~r.e~!. USPHS. downsu-eam from t.he gas plant or at t.he Res;uJatory Determination r-egarding oil ct.iIIg ulant. mlnltlraCor. marbt end of lbe transportation s)'~tem and gas exploralion and produ~on IFR Doc. 9J-61SJ FIled 3-1HJ: 8:.(S a..nl are not covered by the ~ exemption. wastes. This notice mereJy pro\'ides t.cUJHc COO(: ~ These w~stes are not uniquely further clarification o{ EP A's statements t.SSOCiated ~itb oil or gu exploration regarding the scope of the exemption for and prod.u.ction and ue not exempt. oil and gas wastes. Thus. EP.A does nol ln, ad~ltlon. wastes ~e~~rat~d by non- believe that today's notiœ constitutes an proauctlon ,relaled aCtiVJtJes (J,e.. action (or which notice and comment is manufactunng) !.hat may occur at a gas 'd d th Admin' '-U' I reqUJr& un er e IS.... ve p ant are n~t exem,p~. ,Th~ non-i!xempt Procedure.Act (.APA.). manufactunng act.JvlUes mcJude ÙI ..,. d operations tbat go 1>6yond the removal . ,To e ex!~nt today s nOüce:$ covere of impurities from Ù1e raw gas and the ~). APA req~U'emen~. EP~ belie\"es that pb)"Sica.1 $eparation of the gas into its It :$ ~erely U1terpretiDg the sco.p8 of the component fractio~ ManufActuring e::1stmg RCRA statutory e~duslo? for activities would be thoso that are .ïmilar 011 and gas wastes, ~or-~'hich noUce ADd . to petrochemical plant operations. such COClmen,t Js not ordin~ly t'equ1red. 2.S the c:racl:.ing and reforming oIllie Altemllhvel)'. EPA. believes It has good molecular structures of the various ga..s cau~ u.nder ~~n 5S~(b) of th~ M' A, bcûons e.nd ilio addition of odOJUlts or to pub~ this noUce W1lbout . . où::er substa.nces. The end point of the opportunity for ca::nmen~ EP A hM ~pe of the exemption for natun..! gllS alreadr ~ved substantial. C?mment . IS in the g.u: plant ODC8 nanub.cturing reg~..u;tg ilie ~pe of lbe .011 and gas ~ or, if no manufacturing CJCCt.tn, lit ~empUon 1n ~ponse to 1(.¡; 1987 . the point .r..t whielt the natural gas Iu\"es Report to Congress. and further the gas plant for transportation to comment o:t the i£we 1¡; unn~, mar!:.et. p:lrticularly slnC8 EP.A is not aIter.ng its . It should be noted that the production position !rom that which the Agency . or el~ental sulfur from hydrogen 2Dl1ounced in-the 1988 Regulatory. . ¡;ulflde ga..s at a gas plant is considered Determination. lre:1tment o( an exempt waste (i.e.. the bydrOhen sulfide gas is a uniquely associated waste). This waste t~alment process reduces the volume and/or toxicity of the exempt waste and produces a Aleable product. Iu rocl:t, this process is simil2.r to crude aU reclamation and any residual' waste deriv~d (rom the bydrogen sulfide J'1Im.ams exempt. FlOaJJy. wastes uniquely associaled with operations to reçoli'er natural ga.s from underground sas storage fields are covered by the exemption íust as if the gu were being produced [or the fim time. This is bcçause ope~licns to store and retrie\'e naluI111 gas from natural .underground formations. as weB ~s Ù1e types of wastes generated. are \'irtuClI1y identical to those in\'olved with the production of nalural gas for I1le first 'time. althoush the volume of wesles 'gðneraled by nalUral ges 'toOige end l"f' val j, t)'pic~llly smaller tha.n Ú1e ; ~.. I ~..-.. i . I ',. I -. / ........" r·· .. ,.. .,... '." . ". . " " '. 40 CFR Part 300 [FRL~-2J NaUonal Oll.nd H.az.a:rdow Substan~s Pollutloo Contingency Plan; National Pr1orttle, U&'t AG£NCY: Environmental Protection Agency. ACilOt{: Notice of deletion of the Woodbury O1emical Company Site !rom the Nl1tional,Priorities Li~ (NFL). WUJU.AY: The Environmental Protection Agency (EP A.) announ~ the deletion of Ù1e Woodbury Chemical Company Superfund Site (Site) in eo.ømcros City, Colorado. from the NatiOnAl Prloriüec List (NFL). The NPL is appendix B of <iO .. ŒR p.a.rt 300 which is the National Oil and HAnrdousSubm.næs Pollution Contingency Plan (NCPJ. promulgated pumutnt to ,:-::tion 105 of the Comprehens.i va Envir:::1mentd Respo~, Com~n.sation. and Liability Act of 1980 (CERa..A). as amended. IV. EP A RCRA Docl:et EP ^ end !.he Stale of Colorado have The ~A RCRA dodet is located at: detennined that all appropriate United States Environmental Protection response actiom have been ^genc}'. RCRA Information Cttnter, implemented at the Site and that no room l.U427. 401 M Street. SW., further cleanup by responsible puûes is Washington. DC %0,(60. appropriate. Moreover. EPA and the The RŒA In[onnation Center is open Stale of Colorado have determined that fro::t 9:00 to 0(:00 Monday through. ~ remedial activities conducted at the SHe Friday. except for federn1 holidays. The are protective of public health. weIIare. public must make an appointment to and the environment. . . review docket mate..rial;. Call the doc:1:et ~EFFEC'TlV!: DATE: March 22. 1993. 6t (202) 2.60-9327 ror appointments. FOR FURTHER INFORW.T100 COHTACT': Ms. Copies cost S.lS per page. ' Laura Williams (8H\VM.SR). Rsmsdi41 The following documents rel.,ted to Project Manager. U.S. EPA. Region VllI. the July 6, 1966 regulatory 999 18th Street. roile 500, Denver. determination are available for Colorado 602.02-20(66, (303) 293-1531, inspection in docl:et number F-88- or Mr. PatriC± Bustos (80Eh). Office of OGRA-FFFFF. Extemðl.tVfal~. U.s. EPA. Reg£on vm. · Report to ConeleSS on MCIJ1agement 999 18th Street. suite 500. Denver, of Wastes from the ExploratJon. . Colorado 80202-2466. (303) 2*-1139. !>:velopment. and Production o(Crude ADDRESSES: Comprehensive Information Oil, Natural Gas. and Geothennal on this Site i, available a.l the following Energy: addresses:. .. " ..:~ . -- ". ....:..:; ·r:.'~ =:-.: ~t f·,,: ..: j. :õ! .: ¿: .~ .z..;J: . - . .-: : .C .~ ~ :l . .j . :J t: ~! . .. ~ .t ::- ., ~ . .~ ',' ,.It ;: 'I t.~ ...... ...... ~ -! "! .~ . ~ .~ '1 i ·: . A. The review will include an examination of financial expenditures, progress towards program implementation, changes in the program description, and progress on program elements. Each mid-year review will include a meeting with AOGCC representatives to discuss program progress and performance. The review may also include the examination of any AOGCC files pertaining to the Alaska Class II UIC program. After the completion of its mid-year performance review, EPA will submit a draft of its findings to the AOGCC, outlining any deficiencies in program performance and recommendations for improving AOGCC operations. The draft report may also provide guidance for the development of the upcoming grant application. After receipt of the AOGCC's comments on these proposed findings, EP A will develop a final report of the mid-year performance evaluation and provide the AOGCC with a copy of this report. B. .. C. EP A may conduct not more than one performance audit of the Alaska Class II UIC program each grant year. These audits will follow essentially the same procedures as the regular mid-year review but will include more thorough examinations of AOGCC's records and more extensive discussion of program performance. EPA will notify AOGCC at least 30 days in advance of conducting a performance audit and specify the subject matter to be audited and the date of the audit. í.-::c~::~~=:.~ Definition of Class II Wells and Fluids Uu. 0 .. od.n , " . . ~~';;þ~~ô:i~~~:~~~:~:;:,~~~-;~;::':"~~~~~:~~;~:: _:..". ..- .:--':...~"~;-.. ,.'_,~-_~"~"'-" "w_.._'_n,,_~_.....,~.:_.. ._,_::.,:~..,_..___.,......,~ ._. 0. _.'~__'~ ..~_......'~,._,,~~ ~;::~~'E.::~~~;I;:·:~~9; ·~":'~·The AOGCC and EPA agree that Classll wells are defined as wells which injectijf~~~-§~g: .. ~~,. ;.._~ c;,.. : fluids: 'd.._ 'n__.... ..... ·'c.,''':. ..;:.·;;;:::~;.~;~~;;-.:-;l~~;:~..=.=,~~:=: .. ~ -.. .-. -- -_.. ---.. - -.---_.. .-, -"." .-- -.... '-'~ .~.._-... "-'-_..,.~ a) which are brought to the surface in connection with natural gas storage operations, or with conventional oil or natural gas production and may be commingled with waste waters from gas plants which are an integral part of production operations, unless those waters are classified, at the time of injection, as a hazardous waste under 40 C.F.R. s261.3 (A II-D well under EPA's classification system}; b) for enhanced recovery of oil or natural gas (A II-R well under EPA's classification system); and c) for storage of hydrocarbons which are liquid at standard temperature and pressure (A II-H well under EPA's classification system). 10. The pumping away of drilling muds and precipitation from reserve pits (not runoff) into an exploratory or stratigraphic test well, or into the annuli of any well approved in accordance with 20 MC 25.005, is an operation incidental to the drilling of the well, and is not a disposal operation subject to regulation as a Class II well. \. Page 3 of 6 R r- r ~ 1\/ r 0 ¡ C,,-LI ~ C !.~ .....\.¡ 11 I) ¡C'C1 t__.. L 'J ItJwt ,~:2s!\a Qii G. ~~~ C~::s. ~~~~".~TIi:s\~O /:,;:::,::'2.:; ~ - -.--------- . ..~-- - -. ---'. '.' ----- ..-._._~. t::...' .. .-,>_. 12. . . The term "fluids" as used in this Agreement shall have the same meaning as the term "fluid" under 40 C.F.R. s 144.3. To determine whether a waste fluid from oil . and gas production is a hazardous waste the following procedures shall be followed: A. AOGCC will determine whether the fluid would fall within the scope of the exemption from RCRA regulation for "drilling fluids, produced wastes, and other wastes associated with the exploration, development, or production of crude oil or natural gas or geothermal energy." See the Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes (RCRA Regulatory Determination). 53 Fed. Reg. 25446,25453-54 (1988).(Resource Conservation and Recovery Act s3001 (b)(2) (A), 42 U.S.C. s6921 (b)(2)(A». B. If the fluid is not one of the listed exempt wastes under the RCRA Regulatory Determination, the AOGCC will determine whether the waste is listed as hazardous or if it exhibits one of the hazardous characteristics under 40 C.F.R. Part 261. c. If the fluid is a listed or characteristic waste under 40 C.F.R. Part 261, then AOGCC will determine whether the fluid may still fall within the scope of the RCRA exemption by ascertaining if the fluid is: 1) intrinsic to ~.exploration, development or production activities; 2) uniquely associated with these activities, or; 3) not generated as part of a transportation or manufacturing operation. . '._ ._,.."... . ..- ._-.-.-.-- -.---.----.-.---. -~.~ --. . . .. -- -. .- For enhanced recovery injection wells, AOGCC and EP A agree that the injected fluids must function primarily to enhance recovery of oil and gas and must be recognized by AOGCC as being appropriate for enhanced recovery. In determining fluids appropriate for enhanced recovery, the AOGCC will promote waste minimization by encouraging the beneficial recycling of fluids, which if not used in this manner would otherwise be considered a waste. "....,-.. ....., 13. AOGCC shall immediately notify, by telephone or facsimile transmission, the Chief of the Drinking Water Programs Branch at EP A if it learns of hazardous waste injection in what would otherwise be considered a Class II well. Aquifer Exemptions 14. Aquifer exemptions shall be processed in the following manner: A. The AOGCC agrees to encourage applicants for aquifer exemptions to submit any aquifer exemption application in conjunction with a permit application or an application to amend an existing permit. ~ "'rr" n:f\ ;1:" r-. ,- I '\J ~ ¡,./ 1'1........._1 - Page 4 of 6 L~ -.\/ ~ ~~ ~SS1 I......,.. '- 'J ,;J~:;!\a Q;i ~. c.:~:: c;:-<·;~. c~;,:~ni:S\c.n ¡-.:;':::1:;:·2~:: . . The following flowchart depicts the various possible mixtures and their exempt and non-exempt status. Possible Was'e Mixtures Exempt Waste ~ . _ .c Exempt Waste ~ I Exempt Waste r -1 Exempt Waste r- No 6 Exhibit Any Hazardous Characteristic Exhibited by Non-exempt y ~ ~ Non-exempt Characteristic Hazardous Waste Yes I Exempt Waste ~ +(Ha~~~~~us) Waste listed Hazardous - Waste ~''''''''''''''''''''''''';'',''''''"'.' Non-hazardous Waste Exempt Waste Exempt Waste (See Note on Previous Page) .. Non-exempt Characteristic Hazardous Waste ... -0 c: C7 t S Õ ~ -, l~¡ff t ~ , b ::Þ (J\ If. >. /I' .J) (i. 11\ ;\ t) U)';;C ð- - ~ ) '" '¡! .1'\' (1\ ."'.... 0õ~] ~ ~ () -4 ~ ~ g ~ o ~ t ~ l õ G' ... 't J> o (f è .... #10 ,r.-:::\:,::-;:: i"'-;-~ =-= ;-;::: ; :...; ¡ I i '\ \ i I' :! \. " : I / I, ¡ 1 ¡ '_ .'\\ ~I ,U\!I ir n" J I¡--" ,. ¡' \...::::-J .~ i....J U i.-,; :.-= it i ,\ \ Î i I ,\ \ (c-J! V/ ¡.\ \ , i '. 'I I I \: ','\.; i 11.. ! ~ \ : I í...... \ . \, \ ! \ \ ;!...J. \ , -' I· , - . ..,; i\. 1,-,·, ~' !.J i L... U U i~..:::!J u \.l J L " TONY KNOWLES, GOVERNOR "'4' ¡ .I ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE. AlASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 December 1, 1995 Janet Platt Supervisor, Compliance Environmental/Regulatory Affairs BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AJ.T.( 99519-6612 ~ \ C) '~ 3> ~ \\J~ Re: Endicott and .:vElne Point Class II fluids Dear Ms. Platt: You have asked the Commission for guidance in determining if certain waste products produced by Endicott are appropriate ~or underground injection. The Commission's Memorandum of Agreement ("MOA") with EPA recognizes that Class II injection wells, which are regulated by the Commission, include, in addition to hydrocarbon storage wells, the following two types of wells, First are wells that inject fluids brought to the surface in connection with conventional oil or gas production (and certain related activities). These may be referred to as Class II disposal wells. Second are wells that inject fluids for enhanced recovery of oil or gas. These may be referred to as EOR wells. With regard to class II disposal wells, I understand that drilling rig washing machine fluids are used to clean clothes (with \vater) that are soiled with drilling mud and other fluids that have been downhole. They appear to be the same type of fluids as rigwash and as such are potentially approvable for injection in Class II disposal wells. Water rinseates from containers used for fluids that have been brought to the surface are also potentially approvable for such injection. With regard to EOR wells, the MOA provides that "the injected fluids must function primarily to enhance recovery of oil and gas and must be recognized by AOGCC as being appropriate for enhanced recovery." The Commission \\'ill apply these criteria in evaluating particular fluids proposed to be injected. In general, the following substances appear to be potemially approvable if sample analyses confirm that their composition is similar to produced warer. Treated effluent from the sewage treatment plant Drilling and workover fresh\vaterlmakeup water that is unused or leftover Water rinses used to facilitate removal of residue from drilling operations, provided solids will not plug the formation . Vehicle wash water collected in sumps from washing vehicles, as long as a low solids content is also maintained Snowmelt and rainwater from containment areas and the drilling pads Snowmelt with spin clean up residue from drilling operations and reserve pit snowmelt fluids Hydro test fluids, such as glycol and methanol ~ .' c .....,.. ' ", . ;...... . '. ". ~ .. Janet Platt December 1, 1995 page 2 . " Certain drilling wastes may also be disposed of in the annular space of a well in certain circumstances. This is the subject of proposed regulations that are now being circulated for public comment. The Commission also received a letter from Steven Taylor, dated November 15, 1995. The letter requests Commission concurrence to continue using Milne Point treated effluent for EOR operations. The accompanying <l.t'1alysis of the treated effluent indicates that the fluid is in fact similar to produced \vater and has a sìighrIy lower total suspended solids (TSS) content than thm of produced water at Milne Point. Tne treated efrluent from the sewage treatmem plant at Milne Poim is approved for EOR use under Area Injection Order 10 as long as the composition remains similar to that of produced \-vater. TIle Commission looks forward to takíng steps to clear up some of the confusion experienced when dealing ,vith class II fluids. Please feel free to contact us if you have any addirional questions. Sincerely, l cc: Robert Mintz, Dept. of Law Grover Partee, EP A y '-," :";. ". ,. . ·-;~~~:i·:i~~h~~;~~~~: ,:~~~. ~~.~:':_-:~:. : -~-~ ~~~~~{i~. -.-:' - ~:~~:.: - ....... . :j2.:;L~L{t.~..-.:~J:~~ - .'..'- .."... ..;_:. ..: . '.-;~:~..,«'.~::;rj- ·7,~.. -.. #9 . . Agenda UIC Meeting With AOGCC 11/15/95 9 :00 am 1. Class II fluids requiring AOGCC concurrence for Class II-R recycle wells a. Types of wastewater fluids for EOR Treated Effluent Drillling freshwater/makeup water that is unused or leftover Workover freshwater/seawater that is unused or leftover Rinses to facilitate removal of residue Vehicle wash water collected in sumps from washing vehicles in shops Snowmelt and rainwater from containment pits, troughs, and vaults Snowmelt and rainwater from the pad Snow melt with spill clean up residue Reserve pit snowmelt fluids Hydro test fluids (glycol/methanol) b. AOGCC documentation requirements on EOR fluids c. Milne followup d. Endicott followup 2. Class II fluids requiring AOGCC concurrence for Class 11-0 disposal wells Mixtures of freshwater/saltwater and produced water Drilling Rig washing machine fluids Rigwash Ri nseates 3. EPA and AOGCC concurrence on equating RCRA exempt fluids as Class II Ri nseates Mud that has not been downhole Unused Seawater/Freshwater 4. Fluids for Annular injection requiring AOGCC concurrence a. Types of fluids for Annular injection Cement Rinsate Drilling Rig washing machine fluids Rigwash #8 ... WALTER J. HICKEL, GOVERNOR ~. " ALASKA OIL AND GAS CONSERVATION COMMISSION July 5, 1994 3001 PORCUPINE ORIVE ANCHORAGE, AlASKA 99501-3192 PHONE: (907) 279-1433 TElECOPY: (907) 276-7542 Mark Major ARCO Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 Re: UIC--Use of treated effluent as EOR fluid. Dear Mr. Major: The Commission has reviewed your proposal to augment EOR fluid with sanitary effluent from the Prudhoe Bay Seawater Treatment Plant. The treated effluent is chemically· similar to seawater currently injected for enhanced recovery. The Commission concludes that the treated effluent will function to enhance recovery and will not jeopardize well integrity. Accordingly, under the authority of AIO No. 4A, Rule 1, the Commission approves the use of treated effluent rrom the Seawater Treatment Plant to augment EOR fluids. @ printed on recycled pap!"r b y G. n _ 't ,1 ..~ " '~,,, 1... . ' ARCO Alaska, Inc. -. Post Office B::W360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 ~~~~ .:ts...\ ~~~I"~ ~~1A. June 27, 1994 Mr. David Johnston Chainnan Alaska Oil & Gas Conservation Commission (AOOCC) 3001 Porcupine Drive Anchorage, AK 99501-3192 Dear Mr. Johnston, RE: Addition of Sanitary Effluent Stream to Enhanced Oil Recovery (EOR) Fluid Prudhoe Bay Seawater Treatment Plant (STP) Per our discussion on June 22, 1994 regarding this topic, ARCO Alaska, Inc. (ARCO), operator of the Prudhoe Bay STP, requests AOGCC approval for the addition of the sanitary effluent stream from this facility to the EOR fluids processed at this facility. As you may be aware, the sanitary effluent stream from this facility is processed prior to discharge to the Beaufort Sea under an EPA National Pollutant Discharge Elimination System (NPDES) permit. ARCO proposes to process this effluent as is currently done but would reroute the sanitary effluent stream to be introduced into the EOR stream just prior to shipment to the various underground injection facilities at Prudhoe Bay. Preliminary research indicates that no additional oxygen scavenging will be needed for corrosion minimization; however, this situation will be monitored and actions taken as appropriate over time. Attached for your use is a copy of a recent laboratory analysis of the sanitary effluent stream and the EOR fluid stream from this facility. This analysis demonstrates these fluids are extremely similar from a compositional standpoint. Also, it should be pointed out that the current sanitary effluent stream volumes averages about 3,000 to 5,000 gallons of fluid/day while the EOR fluid stream has averaged about 669,000 barrels of fluid/day (or about 28,098,000 gallons of fluid/day). This situation equates to an addition of less than .02% to the EOR stream. Although near term plans call for a reduction of EOR fluid from the STP by up to about 100,000 barrels/day (due to increased utilization of produced water), the addition of the sanitary effluent stream will still equate to an addition of about .02% to the EOR stream. ARca is proposing this change as an additional waste minimization measure in our operations. We believe that this proposal is an excellent pollution prevention activity which meets both the letter and the intent of nationwide efforts in this area. For your information, we are in the process of notifying EPA and ADEC of this proposed change. We do not envision any objections from either agency since this proposal will result in the elimination of a discharge to the waters of the United States. If you have any questions or desire additional information to act on this request, do not hesitate to call me at 265-6136. Sincerely, ~~ Mark Major Permit Director - Prudhoe Environmental Permitting Prudhoe Bay Operations RECEIVED Attachment dUN 2.81994 2: Gas Corm. CommissIon Anchon:~j¡ ARca Alaska, Inc. is a Subsidiary of Atlantic Richfield Company {. .~....'''' ,0·." . '- 5:39 PM SAT., 11 JUNE, 1994 .A' ...../ " ARCO ALASKA PRUDHOE BAY CENTRAL LABORATORY ANALYTICAL REPORT ****************************************** SAMPLE NUMBER: 45861 FACILITY STP SAMPLE DATE 06/03/94 SAMPLE POINT SEAWATER & WWTP EFFLUENT SAMPLE DESC. ANALYSIS Miscellaneous METER # WELL NUMBER: SAMPLE TIME: 00:00 *** ============================================================================ Sp. Grav. pH Bicarbonates Total Dissolved Solids (calc) Resistivity @ 68 F Chlorides Suspended Solids (>0.45 um) Sulfides Calcium Magnesium Sodium Potassium Strontium Barium Iron Sulfate East Supply Line 1. 0143 7.9 105 mg/l 22370 mg/l 0.430 ohm-m 10347 mg/l 1.9 mg/l <2 mg/l 210 mg/l 680 mg/l 5404 mg/l 217 mg/l 4.1 mg/l <0.2 mg/l <0.2 mg/l 1410 mg/l Sulfate analysis run by WOA laboratory. '.. BROWN / JONES PRB 7 STP PLANT AIDE #23 WWTP Effluent 1. 0007 8.2 296 mg/l 280 mg/l 100.0 ohm-m 84 mg/l 32.0 mg/l <2 mg/l 16 mg/l 2 mg/l 250 mg/l 15 mg/l <1 mg/l <0.2 mg/l <0.2 mg/l 101 mg/l COMPLETED BY c¡j¡( ~~) REVIEWED BY :r~ R ECE IVED R !!i Cas Cons. Commission i\nchorab:l1 #7 ,., ALASKA OIL AND GAS J CONSERVATION COMMISSION / WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 October 4, 1993 TO WHOM IT MAY CONCERN: Re: Area Injection Order No. 4A The Commission has revised Area Injection Order No. 4A as of this date. The revision is minor and consists of replacing the word 'produced' with 'source' in finding number 20 on page 3 of said order. Please replace the appropriate pages in your current copy of Area Injection Order No. 4A with the enclosed pages. Sincerely, '- Ð " - t' . . STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive ~chorage,AJaska 99501-3192 Re:The REQUEST OF ARCO ALASKA, INC., to modify Area Injection Order 4 to include the Point McIntyre, Stump Island and West Beach oil pools for the purpose of conducting enhanced recovery and disposal of Class II fluids. IT APPEARING THAT: ) ) ) ) ) ) ) Area Injection Order No. 4A Eastern Operating Area Prudhoe Bay Unit and Pt. McIntyre Field August 12, 1993 Rev. October 4, 1993 1. Arco AJaska, Inc. (ARCO) by correspondence dated April 5, 1993 made application to the AJaska Oil and Gas Conservation Commission (hereinafter Commission) to modify Area Injection Order NO.4 (AlO #4) to permit the underground injection of fluids for enhanced oil recovery and disposal of Class II fluids in support of production and development of the Pt. McIntyre, Stump Island and West Beach oil accumulations. 2. Notice of an opportunity for public hearing was published in the ~chorage Daily News on April 9, 1993. 3. A request for extension of the public protest period was filed on April 22, 1993 by Copeland, Landye, Bennett and Wolf on behalf of George and Larry Ahmaogak. 4. By letter dated April 27, 1993, the Commission extended the public protest period to 4:00 PM, May 3,1993. 5. By letter dated April 27, 1993, the Department of Natural Resources requested that any decision to modify Area Injection Order NO.4 to accommodate a proposed Pt. McIntyre participating area in the Prudhoe Bay Unit be deferred until after approval of a participating area by the state. 6. No other protest or request for a public hearing was filed. FINDINGS: 1. Commission regulation, 20 AAC 25.460, provides authority to issue an order governing underground injection operations on an area basis for all wells within the same field, facility site, reservoir, project or similar area. .. . ,. . ' Aiea Injection Order No. August 12, 1993 Revised October 4, 1993 Page 3 . 12. Production £Tom the Pt. McIntyre, Stump Island and West Beach oil pools will be commingled with production from other pools and processed at the Lisburne Production Center (LPC). 13. Disposal injection in the Pt. McIntyre oil field will occur within the Colville Group/Sagavanirktok formation which correlates with the 1,900' to 6,750' measured depth interval in the Sag River State No.1 well. This interval is underlain by an Upper Cretaceous marine, predominately shale sequence approximately 1,600' to 2,000' thick. The interval is overlain by Tertiary shale and mudstone beds 10 to 50 feet thick which act as vertical permeability barriers and approximately 1,800' of permafrost which isolates the disposal interval £Tom surface waters. 14. No injection wells currently exist in the Pt. McIntyre oil field. ARCO's application includes proposed locations and mechanical configurations for currently planned injectors, and the locations of all existing and abandoned wells within the field. 15. None of the existing or proposed injection wells in the Pt. McIntyre oil field are within one-quarter mile of the affected area as defined under Conservation Order No. 317. 16. All operators and surface owners within a one-quarter mile of all proposed injection wells in the Pt. McIntyre oil field have been duly notified of the proposed injection project. 17. Fracture gradients are estimated to range from approximately .55 to .65 psi/ft for receiving formations and from .80 to .90 psi/ft for confining formations in the Pt. McIntyre oil field. 18. Formation water salinity is estimated to range £Tom approximately 12,000 ppm to more than 20,000 ppm for all aquifers in the Pt. McIntyre oil field. 19. Laboratory testing indicates proposed enhanced recovery fluids are compatible with receiving formations. Some increase in the concentration of hydrogen sulfide gas in the Pt. McIntyre oil pool may be expected from the introduction of commingled gas and produced water streams from the LPC. 20. Initial enhanced recovery plans for the Pt. McIntyre oil pool call for 16 water injection wells and two gas injection wells. Initial watertlood pattern will be an inverted 9-spot utilizing source [PRODUCED] water. 21. Enhanced recovery plans for the Stump Island oil pool will be evaluated on a well- by-well basis in conjunction with Pt. McIntyre oil pool development. No actual proposal has been submitted to the Commission for enhanced oil recovery operations in the Stump Island oil pool. #6 . . WALTER J. HICKEL, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) Z16-7542 April 27, 1993 David S. Case Copeland, Landye, Bennett and Wolf 550 West Seventh Ave. Suite 1350 ~chorage, AJaska 99501 Re: Extension of protest period Dear Mr. Case: The Commission has received your letter of April 22, 1993 requesting an extension of the protest period for ARCD's application to modify Area Injection Order No.4. The Commission hereby approves your request to extend the period to file a protest in this matter until 4:00 PM, May 3, 1993. Please understand that a proper protest must raise a substantial and material issue crucial to the Commission's decision in this matter. Sincerely ¿...#¿J 1L-jM- ~ Russell A. Douglass Commissioner 8ct\N\\!EG v): 1'.; '2· nn/i ',i \.. ~V.......· J , ! ~ #5 ... ..¡ . WALTER J. HICKEL, G7R ~ p.o. BOX 107034 ANCHORAGE. ALASKA 99510-7034 PHONE (907) 762-2553 DEPT. OF NATURAL RESOURCES DIVISION OF OIL AND GAS (907) 762-2547 April 27, 1993 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attn: Russell A. Douglass Commissioner Subject: Application for Modification of Area Injection Order No.4 for Prudhoe Bay Unit (PBU) EOA Dear Mr. Douglass: The Alaska Department of Natural Resources approved the West Beach Participating Area within the current boundaries of the PBU on April 2, 1993. On March 18, 1993, the department received an application to expand the PBU and form the Pt. McIntyre Participating Area (P A) within the expanded PBU. The application to expand the PBU is currently considered incomplete by the department pending submittal of additional required information by the applicants. While modification of the area injection order appears timely as it regards the West Beach Participating Area in the PBU, the department feels that it is premature to consider that the proposed Pt. McIntyre PA will be part of thé PBU, and premature to modify any PBU conservation orders to accommodate the proposed Pt. McIntyre PA in the PBU. At this point in time, substantial differences remain between the Pt. McIntyre lessees and the state. There is the possibility that the proposed participating area will not be part of the PBU. Rf(!EIVED APR 2 B 1993 Alaska Oil & Gas Gons. Commission Anchorage .. r . . . Russell A. Douglass April 27, 1993 Page 2 Accordingly, modifications to the Area Injection Order No.4 for the PBU EOA as those modifications would apply to the proposed Pt. McIntyre P A should be deferred pending approval of the participating area by the state. Sincerely, t;2Wí1-AVo!J- '-r James E. Eason .. Director cc: Patrick Coughlin - ADOL PBU.Injorder.N04.Txt REC:EIVED APR 2 B 1993 Alaska Oil & Gas Cons. Lommlssìol Anchorage #4 . ."...- . . MARK G. COPELAND, P.C. ** THOMAS M. LAN DYE. P.C. ~. DAVID BENNETT. P.C. DAVID P. WOLF, INC.* ROBERT B. HOPKINS. P.C. RICHARD L SADLER. P.C. RANDALL L. DUNN, P.C.*** ,JAMES S. CRANE, P. C. ** ROBERT H. HUME, ,JR., INC. ** MITCHEL R. COHEN, P.C. DAVID L BLOUNT DAVID S.CASE.P.C.* THANE W. TIENSON *** DAVID N. GOULDER P. STEPHEN RUSSELL III, P. C. ROBERT P. OWENS **** THOMAS R. BENKE ATTORNEYS AT LAW 550 WEST SEVENTH AVENUE. SUITE 1350 ANCHORAGE. ALASKA 99501 ~ ])43 OREGON OFFICE jtA4 COPELAND,LANDYE,BENNETTANDWOLF A PARTNERSHIP INCLUDING PROFESSIONAL CORPORATIONS 19071276·5152 3S00 FIRST INTERSTATE TOWER PORTLAND. OREGON 97201 IS03) 224-4100 FACSIMILE (907) 276-8433 "'ALASKA STATE BAR **ALASKA STATE AND OREGON STATE BARS ***WASHINGTON STATE AND OREGON STATE BARS ****ALASKA STATE AND WASHINGTON STATE BARS ALL OTHERS OREGON STATE BAR ONLY April 22, 1993 VIA COURIER Mr. David Johnson, Chairman Alaska oil and Gas Conservation commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Extension of Protest Period for Application for Modification of Area Injection Order No. 4 Dear Commissioner Johnson: This follows up on my April 21 phone conversation with commissioner Douglas. I am writing on behalf of George and Larry Ahmaogak to request an extension of the protest period for the above-referenced application. We request that the period be extended one (1) week from April 26 to May 3, 1993. As I explained to Commissioner Douglas, this extension is necessary due to the fact my clients live in Barrow and that I have not been able to get a complete copy of the application until yesterday (April 21, 1993). I am now traveling to Kotzebue, and have scheduled a meeting for April 26 with representatives of ARCO to review the activity proposed under the application. ARCO's attorney, Mark Worcester, has advised that ARCO would not oppose a short extension of the protest period. Extending the protest period will enable us to meet with ARCO to make a rational determination as to whether there is any need to request a public hearing on the application. If the period cannot be extended, then please consider this letter to be a protest and written request for a hearing under 20 AAC 25.540 by persons who may be harmed if the requested order is issued. If the requested extension is granted, we stipulate that this protest is withdrawn and would have to be re-filed with the Commission by 4:00 p.m. on May 3, 1993. REeEIVED APR 22 1993 Alaska Oil & Gas Cons. Commission Anchorage I .. __. è:PELAND. LANDYE, BEN. AND WOLF . Page 2 April 22, 1993 Thank you for your consideration. Sincerely, c;;:~z BENNETT AND WOLF David S. Case, P.C. Attorney for George and Larry Ahmaogak cc: Mark Worcester (via telefax: 265-6998) DSC\1126\LComm.01A:mrs RE~EIVED APR 2 2 1993 Alaska o¡¡ & Gas Cons. Commission Anchorage #3 . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO Alaska Inc. to modify Area Injection Order NO.4 authorizing underground injection operations in the Eastern Operating Area of the Prudhoe Bay Unit. ARCO Alaska, Inc. by letter dated April 5, 1993 has requested a modification of Area Injection Order No. 4 in conformance with 20 AAC 25.402, 20 AAC 25.460 and 20 AAC 25.252. This modification would authorize disposal injection of Class II oil field waste and enhanced recovery injection operations in the recently formed West Beach and Point Mcintyre participating areas. The proposed changes include expanding the affected area of Area Injection Order No. 4 to the Northwest to include all of the Point Mcintyre area reservoirs. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM April 26 1993 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, AK 99501, and request a hearing on the matter. If the protest is timely filed, and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 am May 11, 1993 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, at (907) 279-1433, after April 26, 1993. If no proper protest is filed, the Commission will consider the issuance of an order without a hearing. Russell A Douglass Commissioner Alaska Oil and Gas Conservation Commission ~¿l Published April 9, 1993 STATE OF ALASKA. THIRD JUDICIAL DISTRlCf. . . AFFIDAVIT OF PUBLICATION N()tiç~ Ön)ij\)llcHearin~ I STATE OF ALASK·A Ala!ikaOil and Gas ConservationCommi!;!iiOrl #9835 STOF0330 AO-085741 $60.80 April 9, 1993 Re: The application of ARCO Alaska Inc. to mOdify Area InjectionOrdèr ·NO. 4 authoriz- ing undergrou:nd injection operations in th.e Ea!itern Op- erating Area. of the Prudhoe Bay Unit. . ARCO Alaska, Inc. by letter dated. April -5, 1993 has re- quested a mOdificatiòn of Area injection Order No. 4 in· con- formance Witfl 20 AAC 25.402, 20 AAC 25.460. and 20 AAC 25.252. This modification would authorize disposal injec- tion of Class I L oil field. waste and enhanced recovery in ¡ec- lion operations In the recèntly formed West Beach and Point Mcintyre partlclpatingarèas. The proposed changes· include expanding the affected area of Area Injection Order NO.4 to thè Northwest to include all of Ihe Point Mclntyre·area reser- voirs. .., , A person who may be harm- èd if the requested order is issu~ may file a written pro- tesl prior to 4:00 PM April 26, ~m ~6~~hr~a~:6~kac~À\r;r~ sion, 3001 PorcUpine Drive, Anchorage, AK99501, and re- quest a hearing on Ihe matter. If the protest is timely filed and raises a substantial and material issue cructal to the Commission's, deten;"inafion, a hearing on the matter will be held at the ab9ve address at 9:00 AM on May 11, 1993 in conformance '-Vith 20 AAC 25.540. If a hearing .,is to be held, interested parties may confirm thiS. by caUing Ihe Commission's office, (907) 279-1433 after April 26, 19n If no proper protest is filed, the Commis!iionWill consider the issuance of an order withoul a hearing. . IslRussell A. Dougla!;!i Commissioner' Alaska Oil ancl"·Gas , conservatiol)¡~ommisS¡)1) ~April 9, jJl.9_3 ; _ . ....... .EN"a. M. . Kaufmann. ........ .... being first duly sworn on oath deposes and says that he/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 E.nglish 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 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 ~~:~~:~c&-- f[~~ '.J Subscribed and sworn to before me this 14th day of .(lp;,~~... 19 r:r3 ..~..Q.q3fl¡)âV7 Notary pu(L In and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIR[S MY COMMISSION EXPIRES JULY 24, 1996 ................. ............. ........... 19...... RECfl'] r·' ¡ 1\./"" ·1 ,. ¡ ¿j .AJaska Oil 8: G¿1, Anch)fa te #9835 STOF0330 AO-085741 ,,$60.80 . . AFFIDAVIT OF PUBLICATION ..", ..E.va..M.. Kaufrot;W.JJ.,.........,., being first duly sworn on oath deposes and says that he/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 April 9, 1993 -NotlceOr-pUblic Hearinp STATE OF ALASKA Alaska Oil and Gas CO!\S1Òrvatlon CommiSSion Re:, The application of ARCO Alaska ,'nc. to modify Area Injectfo!\ Order No.. 4 authoriz- ing underground inj!!ction operations in the ea,stern Op- erating Area of the. Prudhoe; Bay Unit, ~ STATE OF ALASKA, THIRD JUDICIAL DISTRIŒ. 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. ~ >;gnedT~~.t~~ Subscribed and sworn to b~fore me this liJthday of rJ.pW.... q3 19...... ÜµÛ::VOj~1.I){X.1£) Notary ~bllC In and for the State of Alaska. Third Division. Anchorage. Alaska MY COMMISSION EXI.'JB,£:S MY COMMISSION EXPI~ JULY 24, 1996 . ..............,... .... ..... .... .........19...,.. ARCO Alaska, Inc. by letter dated April 5, 1993 has r!!- quested.a modificativn of Area inj!!ction Order No 4 in con. formance . with 20 ÅAC 2s.402, 20 AAC 25.460 and 20 AÄC 25.252. This modification would authorize disposal injec- tion .of Class f f oil field waste and enh,mcedrecovery injec- tion oP!!rationsin the n~cently i formed West Beach and Poi!\f i MClntyr!! participating areas: I The propos!!d changes include j!!xpanding the affecteçlar!!a of Area Injection Order NO.4 to the Northwest fo include all of th~ Point Mcintyre area reS\!r- vOJrS. A person who may be harm- ed if the r!Quested order is issu!!d. may fiI!! a writt!!n pro- tes,t prior to 4:00PM April 26, 1993 with the Älaska Oil and Gas ConS!!rvation Commis- sion. ,3001 Porcupine Driv!!, Anchorage, AK 99501, and reo quest a hearing on the matter. If th!! protest is -timely filed and raiS\!s a substantial and material issue crucial to the Commission's determination. a hearing on the, matter will be held at the above address at 9:09 AM on May 11, 1993 in conformance with 20 AAC 25.540. If a h!!aring is to b!! held, interested parties may confirm this' bY calling the Commission's office, (907) 279-1433 atterApril 26, 1993. If no prop!!r protest ,is filed, the Commission will consider the issuance of a!\ or-d!!r Without a hearing. ' IslRussell A. Douglðss . Commissioner Alaska Oil and Gas ConservationComm ission \ Pub!. April 9 ,1993 #2 i' /'t . ~ .. . ARCO Alaska, Inc. Post Office Box 100360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 . ~~ ~~ " AprilS, 1993 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Application for Modification to Area Injection Order No.4 Dear Mr. Johnston: Enclosed is an application by ARCO Alaska, Inc. (AAI) to modify the Area Injection Order No.4 for the Prudhoe Bay Unit EOA. This application requests that the existing area injection order be modified to include current and future injection wells, as described in the application, that will be utilized in support of production and development of the Point Mcintyre and West Beach Participating Areas (PA). Some existing Lisburne injection wells, covered under the existing area injection order, will be utilized for Point Mcintyre and West Beach development in addition to future wells that will be developed specifically for those PAs. This application is being submitted in accordance with our discussions at meetings in your office and incorporates changes suggested by your staff since the draft which we previously submitted. In the application AAI requests injection approval for three types of injection wells - fluid disposal, enhanced recovery, and muds & cuttings disposal. In addition to the injection zones covered in the original order, AAI proposes in this application to include the Pt." Mcintyre Oil Pool (the Kalubik and Kuparuk Formations) and the Stump Island Oil Pool (the Seabee Formation) from the PI. Mcintyre PA and the West Beach Oil Pool (the Kuparuk Formation) from the West Beach PA. Should you have any questions or need additional information please feel free to contact me at (907) 263-4678 or George Phillips at 263-4280. ,~ William M. Fowler Senior Permi~ C rdinator Prudhoe Bay / Lisburne Attachment cc: W. J. Pish, Exxon Company, U.S.A., Houston W. D. Morgan, Exxon Company, U.S.A., Houston S. M. Bennett, BP Exploration (Alaska), Inc. A. W. Janes, BP Exploration (Alaska), Inc. D. F. Scheve, ARea Alaska, Inc. A. D. Simon, ARea Alaska, Inc. REEEIVED APR .~ 'r 1993 . r Alaska UiI & Gas Cons l.,\JiU\T\\SSIO! Ancl10rage ARca Alaska, Inc. is a Subsidiary of Atlantic Richfield Company ..., . . .. ~ i. Application for an Amendment to Area Injection Order No.4 20 AAC 25.460 20 AAC 25.252 20 AAC 25.402 RE<:Ei\/ED A Pp - "f 1°9-1. . ~ l .. ~.J" ~ Alaska OU & Gas Cons, Gommlssìon Anchorage April 5, 1993 .. . . .~ SECTION A Application for an Amendment to Area Injection Order No.4 20 AAC 25.460 20 AAC 25.252 20 AAC 25.402 ARCO Alaska, Inc., in its capacity as a Working Interest Owner (WIO), and the Operator of the Prudhoe Bay Unit, Eastern Operating Area ŒOA), hereby applies for an amendment to the existing Area Injection Order No.4, issued July 11, 1986. This application follows the same general format and exhibit numbering as found in the original application and covers proposed and existing injection operations in the Lisburne Participating Area (P A) and the planned Pt. McIntyre P A and West Beach P A. Exhibit A-I details the area proposed to be included in the Pt. McIntyre P A. Exhibit A-2 details the area to be included in the West Beach PA. On March 24, 1993, the Commission was provided a copy of the application to the Department of Natural Resources for formation of the Pt. McIntyre PA and the expansion of the Prudhoe Bay Unit. It was labeled Exhibit 41 to the Field Rules proceeding. The application for the West Beach P A was approved by the Department of Natural Resources on April 2, 1993. The legal descriptions of the West Beach P A and planned Pt. McIntyre P A are listed in Exhibits A-3 and A-4. As proposed, the Pt. McIntyre P A will include two oil pools, the Pt. McIntyre Oil Pool (the Kalubik and Kuparuk Formations) and the Stump Island Oil Pool (the Seabee Formation). The West Beach PA will include the West Beach Oil Pool (the Kuparuk Formation). ARCO's application assumes that the amendment to Area Injection Order No.4 will be effective consistent with the unit area and participating areas as ultimately constituted. Pt. Mdntyre The current Pt. McIntyre development plan includes a combination of processed gas reinjection into the Pt. McIntyre Pool and pattern waterflooding for pressure maintenance into the Pt. McIntyre and potentially the Stump Island Pool. Gas reinjection capabilities will be in place concurrent with field start-up, while waterflood capabilities should be in place by the fall of 1994. The planned development well program currently consists of up to 93 total wells on an average well spacing of 80 acres: approximately 75 producers, 16 water injectors, and 2 gas injectors. The field will initially be drilled on 160-acre well spacing. This will provide additional reservoir description data and . . ... r. some production history, which will enable the WIOs to optimize placement of the 80-acre infill wells. The 80-acre wells will help sustain production capacity and enhance recovery by improving volumetric sweep efficiency. The initial waterflood pattern for the Pt. McIntyre Pool will be an inverted 9-spot utilizing source water from the Prudhoe Bay Seawater Treatment Plant. This pattern selection provides maximum flexibility for future potential conversions to other pattern configurations as changes in reservoir description and/or performance dictate. Depending on reservoir description and performance, select areas may require more dense wen spacing than 80 acres to maximize recovery. For example, in select areas of the reservoir, faulting may dictate tighter well spacing in order to recover bypassed oil. For these reasons, certain areas of the reservoir could potentially be developed using 40-acre well spacing for depletion optimization purposes. Oil within the Stump Island Pool is stratigraphically trapped in discontinuous bodies of sandstone. Due to the discontinuous nature of these sandstones, their development will be evaluated on a well-by-weIl basis in conjunction with development of the Pt. McIntyre Pool. A dedicated drill cuttings disposal well (UIC Class II-D), completed in the Tertiary/Upper Cretaceous interval, is also planned at Pt. McIntyre Drill Site P2. The injection well will be used for injection of slurried drill cuttings, drilling mud, and well completion fluids and other exempt fluids. The initial average daily injection rate will be 1,000 BPD. This rate is based on a single drilling rig operating in the Pt. McIntyre field. The production stream from Pt. McIntyre will be processed at the Lisburne Production Center (LPC). Gas volumes equivalent to the volumes produced from Pt. McIntyre, less fuel gas, flare gas, and NGL shrinkage, are planned to be reinjected into the Pt. McIntyre gas cap. Initially, the produced water will be disposed of into the Tertiary/Upper Cretaceous via LPC Class II-D wells. When sufficient volumes of produced water are available at the LPC to replace the Pt. McIntyre voidage, the produced water may be reinjected into the oil column of Pt. McIntyre. West Beach Only two wells, West Beach Nos. 3B and 4, have penetrated this reservoir. Neither well encountered a fluid contact; therefore, the original oil in place (OOIP) is uncertain. The ultimate development plan for the West Beach accumulation is also uncertain. To assess the economic viability of long-term development strategies, the immediate development plans for West Beach are to begin producing West Beach No.4 in April of 1993. Pressure monitoring after producing West Beach No.4 will allow the WIOs 2 ., . . , to design a development plan for long-term depletion. Oil in place estimates will also be refined with production data. An additional West Beach welI is planned for late 1993, or early 1994 if the estimated reservoir size is sufficiently large. Beyond initial production of West Beach No.4, one of three strategies for long-term depletion will be implemented: solution gas drive, processed gas injection, and/or waterflood. If technicalIy and economically feasible, gas injection and/or waterflood could be implemented as early as 1995. The actual depletion plan will be dependent upon the size of the reservoir. The production stream from West Beach will be processed at the LPC. Due to the uncertainty associated with the West Beach development, at least initialIy the gas stream will be reinjected into the Lisburne and/ or Pt. McIntyre gas caps and the produced water will be disposed of into the Tertiary/Upper Cretaceous. Lisburne Production streams from the West Beach, Pt. McIntyre, and Lisburne PAs will be commingled at the LPC. No facility modifications to the LPC are planned specifically to accommodate West Beach production. However, facility modifications are planned to accommodate Pt. McIntyre production. These modifications focus on liquid handling and produced water injection/handling expansions. The LPC was originally built to process a nominal oil rate of 100 MBOPD, a gas rate of 440 MMSCFPD, and a produced water rate of 25 MBWPD. With the planned modifications, the LPC will be expected to process 135 MBOPD and 200 MBWPD. No modifications are planned at this time for the LPC gas handling system. Currently, gas reinjection compression capacity is 460 MMSCFPD, based on a yearly average. The commingling of production fluids from the Lisburne, Pt. McIntyre, and West Beach PAs at the LPC will create a need to inject into existing Tertiary /Upper Cretaceous Injector LPC-01 at increased rates and may generate the need for up to two additional produced water injectors. The additional Tertiary/Upper Cretaceous injectors will be drilled from the LPC or connected Lisburne drill site facilities. Further, commingling will cause the reinjection of a mixed processed gas stream into the Lisburne and Pt. McIntyre Pool gas caps and potentially the West Beach Pool gas cap. 3 ~ . . , SECTION B Plat 20 AAC 25.402(c)(1) 20 AAC 25.252(c)(1) Exhibit B-1 is a plat showing the location of all existing wells that penetrate the uppermost injection zone within the proposed Pt. McIntyre PA as of February I, 1993. Exhibit B-2 is a plat showing the location of all wells that penetrate the uppermost injection zone within the West Beach P A. Exhibit B-3 is a plat of all the potential bottom-hole locàtions of future Pt. McIntyre producers/injectors. At this time, all the specific wells which will become injectors have not been selected. The current proposed locations for the gas and water injectors and potential drill cuttings disposal well are included in the plat shown in Exhibit B-3. Specific approvals will be obtained pursuant to 20 AAC 25.507, or any applicable successor regulation. 5 .. . . , SECTION C Operators/Surface Owners 20 AAC 25.402(c)(2) 20 AAC 25.252(c)(2) The Pt. McIntyre P A and West Beach P A will be operated by ARCO Alaska, Inc. The Surface Owners within the proposed Pt. McIntyre P A and West Beach P A are listed in the following table. The Native Allotment Landowners are listed by allotment parcel. Exhibit C-1 is an areal map of the parcels. Surface Owners Parcel 15 State of Alaska Department of Natural Resources Attn: M. Kotowski P.O. Box 107034 Anchorage, AK 99510 Lawrence Ahmaogak P.O. Box 411 Barrow, AK 99723 Parcel 18 Parcel 16 Barbara Ahmaogak 1628 Hilton Ave. Fairbanks, AK 99701 John Nicholls (minor) c/o Ely Varner (guardian) P.O. Box 473 Barrow, AK 99723 Parcel 17 Lawrence Ahmaogak P.O. Box 411 Barrow, AK 99723 Alice Glenn 899 Blair Ave. Sunnydale, CA 94087 George Ahmaogak P.O. Box 338 Barrow, AK 99723 7 " . . SECTION D Affidavit 20 AAC 25.402(c)(3) 20 AAC 25.252(c)(3) Exhibit D-l is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area included in the Pt. McIntyre and West Beach PAs have been provided a copy of the amended Area Injection Order No.4. ~;þ f(. ~ ~~~ Ãi j~ ~ ~ .\.ø L :~ ;}j'~' .~ ,~ ~....;c 9 . . SECTION E Description of Operation 20 AAC 25.402(c)(4) Future injection operations for Pt. McIntyre are divided into two broad categories: Subsection 1 - Enhanced Recovery, and Subsection 2 - Disposal of Class II Fluids. Subsection 1 Enhanced Recovery Enhanced recovery injection wells are used for the introduction of additional fluids into the reservoir to increase the ultimate recovery of oil. Two types of enhanced recovery injection wells are planned for Pt. McIntyre: water injection and gas injection. Gas reinjection capabilities for the Pt. McIntyre Pool will be in place concurrent with field start-up, while waterflood capabilities for the Pt. McIntyre and/ or Seabee Pools should be in place by the fall of 1994. The planned development well program currently consists of up to 93 total wells on an average well spacing of 80 acres: approximately 75 producers, 16 water injectors, and up to 2 gas injectors. The field will initially be drilled on 160-acre well spacing. This will provide additional reservoir description data and some production history, which will enable the WIOs to optimize placement of the 80-acre infill wells. The 80-acre wells will help sustain production capacity and enhance recovery by improving volumetric sweep efficiency. The initial waterflood pattern for the Pt. Mdntyre Pool will be an inverted 9-spot utilizing source water from the Prudhoe Bay Seawater Treatment Plant. This pattern selection provides maximum flexibility for future potential conversions to other pattern configurations as changes in reservoir description and/or performance dictate. Depending on reservoir description and performance, select areas may require more dense well spacing than 80 acres to maximize recovery. For example, in select areas of the reservoir, faulting may dictate tighter well spacing in order to recover bypassed oil. For these reasons, certain areas of the reservoir could potentially be developed using 40-acre well spacing for depletion optimization purposes. 11 . . Because the oil within the Stump Island Pool is stratigraphicaHy trapped in discontinuous bodies of sandstone, their development, with respect to enhanced recovery, will be evaluated on a weH-by-well basis in conjunction with development of the Pt. McIntyre Pool. The potential for water injection and gas injection in the West Beach also exists. The development plan for the West Beach accumulation is uncertain. To assess the economic viability of long-tenn development strategies, the immediate development plans for West Beach are to begin producing West Beach No.4 in the spring of 1993. Pressure monitoring after producing Wèst Beach No.4 will allow the WIOs to design a development plan for long-term depletion. With production data, we will be able to refine our oil in place estimates. An additional West Beach well is planned for late 1993, or early 1994 if the estimated reservoir size is sufficiently large. Beyond initial production of West Beach No.4, one of three strategies for long-term depletion will be implemented: solution gas drive, processed gas injection, and/or waterflood. If technicaHy and economically feasible, gas injection and/ or waterflood could be implemented as early as 1995. The actual depletion plan will be dependent on size of the reservoir. Additional methods of enhanced oil recovery may be used in the future in both the West Beach and Pt. McIntyre. Injection wells will continue to be designed, constructed, operated, and monitored to ensure the injection fluid is entering the oil pool. Subsection 2 Ruid Disposal Disposal wells will be used for the disposal of produced water and other exempt fluids generated during operations. The Pt. McIntyre and West Beach produced water is water which is produced from the Pt. McIntyre and Seabee or West Beach Pools with the oil and separated from the oil and gas at the LPC. The remaining injection fluids are exempt fluids generated by drilling and production operations. Injection will be into the Tertiary /Upper Cretaceous interval, as defined in existing Area Injection Order No.4. The LPC currently has a single fluid disposal well, LPC-01. Additional fluid disposal wells in the vicinity of the LPC or connected Lisburne drill site facilities are anticipated. In addition, an exempt fluids disposal well is being considered at Pt. McIntyre Drill Site P2 to be used primarily for the disposal of slurried drill cuttings, drilling mud, and well completion fluids along with other exempt fluids. The injection interval will again be the Tertiary /Upper Cretaceous. If drilled, this 12 . . disposal well will be similar to the CC-2A disposal well now in operation in the Western Operating Area (WOA). Well CC-2A disposed of approximately 240M BBLs of slurried drill cuttings and 800M BBLs of other exempt fluids during 1992. A PNL/borax wireline log (a channel detection tool) run at the end of 1992 in CC-2A indicated no near wellbore vertical fracturing or channels. All future fluid disposal wells will continue to be designed, constructed, operated, and monitored to ensure the injection fluid is entering into and remaining in the injection zone. 13 . . SECTION F Pool Information 20 AAC 25.402(C)(5) The proposed Pt. McIntyre P A will include two oil pools: the Pt. McIntyre Oil Pool (the Kalubik and Kuparuk Formations) and the Stump Island Oil Pool (the Seabee Formation). The primary strata, the Kuparuk, targeted for enhanced recovery within the Pt. McIntyre P A by injection, are defined in the field rules as the strata that are common to and correlate with the accumulation found in the Pt. McIntyre No. 11 wen between the depths of 8,650' and 9,366' subsea (55) [9,908' and 10,665' measured depth (MD)]. The 5eabee, a secondary set of strata which may also be targeted for enhanced recovery within the Pt. McIntyre PA by injection, is defined as the strata that are common to and correlate with the accumulation found in the Pt. McIntyre No.3 well between the depths of 8,200' and 8,370' 55 (8,759' and 8,930' MD). The strata targeted by potential injection for enhanced recovery from the West Beach P A are defined in the field rules as the strata that are common to and correlate with the accumulation found in the West Beach No.4 well between the depths of 8,751' and 8,950' 55 (14,548' and 14,781' MD). 15 . . SECTION G Geologic Information 20 AAC 25.402(c)(6) 20 AAC 25.252(c)(4) Subsection 1 Prudhoe Bay Unit Eastern Operating Area Colville Group and Sagavanirktok Formation 1. Injection Interval A. Stratigraphy and Lithology The Colville Group/Sagavanirktok Formation (also known as the Tertiary/Upper Cretaceous Sands) are currently used for disposal by ARCO Alaska, Inc., in the Eastern Operating Area (BOA) through wells at each of the flow stations, the LPC, and Pad 3 (just south of Drill Site 6). Disposal operations into the Tertiary/Upper Cretaceous are also currently planned in the Pt. McIntyre PAvia a cuttings disposal well at Pt. McIntyre Drill Site P2. For purposes of this application, the disposal zone for the Colville Group/Sagavanirktok Formation should be defined as the interval between 1,900' and 6,750' MD, and lateral equivalents, in the ARCO/Exxon Sag River State No.1 well. The disposal interval includes all the interval between the base of permafrost and the K-12 marker as shown in the Generalized Stratigraphic Section (Figure G-1). In the Kuparuk River Unit (KRU) to the west, significant amounts of low gravity oil occur in two zones which ARCO refers to as the West Sak Sands and the Ugnu Sands. A type log for the West Sak and Ugnu Sands from the KRU is shown in Figure G-2. These zones are not oil-bearing in the EOA, but tract data from the West Sak and Ugnu in the KRU provide the best data for characterizing the Colville/Sagavanirktok Formation in the EOA. The Upper Cretaceous in the EOA area includes the West Sak Sand interval. The West Sak consists of fine to very fine-grained silty sand with interbedded silt and clay and has an average thickness of 225 feet in the EOA. Individual sand beds range from 2 to 40 feet 17 . . in thickness. Core data in the KRU show that porosity ranges from 25 to 35 percent and permeability ranges from 10 to 800 MD. The remainder of the underlying Cretaceous consists of an impermeable mudstone and shale sequence over 1,600-2,000 feet thick in the EOA. The top of the West Sak Sand occurs between about 6,000' and 7,800' SS in the EOA, and dips gently to the east/northeast. The Tertiary includes the Ugnu Sands and related overlying strata. Ugnu Sands consist of fine to coarse-grained sand interbedded with siltstone, shale, and minor amounts of coal. Total thickness averages 500 feet in the EOA. Individual sands range from 10 to 100 feet in thickness and are on average 30 feet thick. Core data in the KRU indicates sand porosity values between 25 and 40 percent and permeabilities from 200 to 3,000 MD. The top of the Ugnu Sands occurs between 5,500' and 7,000' SS in the EOA and also dips gently to the east/northeast. The Tertiary strata between the top of the Ugnu and the base of permafrost are 3,700 to 5,400 feet thick and are similar to the Ugnu based on available data. B. Structure A cross section of the disposal interval from Prudhoe Produced Water Disposal Well PWDW 1-1 to Pt. McIntyre No.6 is included in Exhibit G-3. An areal plat of the wells used in the section is included as Exhibit G-4. The Tertiary/Upper Cretaceous interval is characterized by a monoclinal dip towards the northeast. The magnitude of dip for the T5 marker through the K-12 marker from Prudhoe Produced Water Disposal Well PWDW 1-1 to Pt. McIntyre No.6 is less than 1°. Faulting within this interval is limited to minor offset within the West Sak by the Prudhoe Bay Fault just south of Well West Beach No. 1. C. Formation Water Salinities Consistent with Area Injection Order (AIO) No.4, wireline log-based salinity analysis for the Point McIntyre P A indicates salinity values above 10,000 PPM TDS for all the Tertiary /Upper Cretaceous intervals. Section N contains the log-based analysis results. 18 . . II. Confining Intervals The Tertiary interval contains laterally continuous mudstones and shales 10 to 50 feet thick which act as vertical permeability barriers. In addition, all stratigraphic intervals intersect the base of the permafrost between 1,800' and 2,000' SS to the west. This isolates these formations from communication with surface waters. The West Sak, Upper Cretaceous Sands are bounded below by approximately 1,600 to 2,000 feet of Cretaceous shale. Subsection 4 Prudhoe Bay Unit Eastern Operating Area Pt. McIntyre Reservoir 1. Injection Interval A. Stratigraphy and Lithology The Pt. McIntyre Reservoir is comprised of the Lower Cretaceous, Kuparuk, and Kalubik Formations. These formations were deposited during the Lower Cretaceous geologic time period. Exhibit G-5 illustrates Stratigraphy in the Pt. McIntyre reservoir on a "type log" from Pt. McIntyre No. 11. The log is scaled in true vertical depth subsea (TVD 55), with MD also shown in the center track. The top of the Kuparuk Formation, the principal producing reservoir, occurs at 8,717' TVD 5S (9,980' MD), and the base occurs at 9,366' TVD SS (10,665' MD). The top of the Kalubik occurs at 8,650' TVD 5S (9,908' MD), and the base occurs at 8,717' TVD 55 (9,980' MD), the top of the Kuparuk. The Kuparuk Formation in the Pt. Mclntyre field is stratigraphically complex, characterized by rapid changes in thickness, lithofacies, and cementation. Lithology is dominantly sandstone with lesser amounts of pebbly sandstone, siltstone, and sandy mudstone. Referring to the type log in Exhibit G-5, the Kuparuk Formation can be subdivided into "upper" and "lower" units. The basal portion of the "lower unit" is non-productive, tight, silty sandstone; siltstone; and sandy mudstone. Moving up in the lower unit, the lithology changes abruptly to porous, quartz-rich sandstone, which is typically about 200 feet thick (TVD). The lithology of the "upper unit" is more variable including interbedded sandstone, pebbly sandstone, and minor amounts of muddy sandstone. This interval is also rich in glauconite and more prone to reductions in porosity and permeability due to cementation and compaction. 19 . . The upper and lower units have distinctly different thickness trends. The lower unit maintains a more uniform thickness throughout the Pt. Mcintyre area suggesting that its deposition pre-dates many of the faults that presently cut the reservoir. In contrast, the thickness and lithology of the upper unit is more variable and has been influenced by syndepositional faulting. Intergranular cements such as siderite and other iron-bearing minerals are common particularly in the upper unit and play an important role in determining reservoir quality. Cementation is especially abundant on the western side of the field where it forms a permeability barrier and contributes to the hydrocarbon trapping mechanism. Exhibit G-6 is an annotated "type log" from the Point McIntyre No.3 discovery well showing the stratigraphic position of the Stump Island Reservoir. The Stump Island Reservoir is a secondary reservoir of limited and varied areal extent within the Point McIntyre Proposed P A. In Point McIntyre No.3 the top of the Stump Island Reservoir occurs at 8,200' TVD SS (8,759' MD) and the base occurs at 8,370' TVD SS (8,930' MD). This interval has been referred to stratigraphically as the Seabee Formation. Oil within the Stump Island Reservoir is stratigraphically trapped in discontinuous sandstones of the Seabee Formation. Development of the Stump Island Reservoir will be evaluated on a well-by-weII basis in conjunction with development of the Point McIntyre Reservoir. B. Structure Exhibit G-7 is a structure map on the top of the Kuparuk Formation with a contour interval of 50 feet. Top Kuparuk structure in the Pt. McIntyre area is characterized by a gently northward plunging, faulted, anticlinal nose. Large areas of the field have dips of one to three degrees. In the southern parts of the field, dips of up to ten degrees are present. The Pt. McIntyre Reservoir is bounded on the south by a major east-west trending down-to-the-north normal fault called the Pt. Mcintyre fault. This fault provides structural closure on the south side of the Pt. McIntyre field and plays a dominant role in controlling the distribution of the Kuparuk Formation Reservoir. South of the fault, the Kuparuk Formation is absent to very thin due to erosional truncation. North of this fault the Kuparuk Formation has been preserved. Other east-west trending normal faults, both down-to-the-south and down-to-the-north, are common throughout the Pt. McIntyre 20 . . field. The field oil-water contact (OWO occurs at a depth of 9,069' TVD 55. The gas-oil contact (GOO occurs at 8,582' TVD 55. Exhibit G-8 is an isochore map of the Kuparuk Formation with a contour interval of 50 feet. This map illustrates the control that faulting has exerted on Kuparuk Fonnation thickness. Other controls on thickness are paleogeography and erosional truncation. Exhibit G-9 is a north-south structural cross-section through the Pt. McIntyre field showing gentle northward dip within the field and north-south thickness variations in the Kuparuk Formation across east-west trending normal faults. In particular, note the absence of Kuparuk south of the Pt. McIntyre Fault, an intermediate thickness between the Pt. McIntyre fault and the Terrace Block Fault, and an expanded upper Kuparuk section north of the Terrace Block Fault. Based on existing well data, faults within the Pt. McIntyre field do not appear to separate the Kuparuk Formations into hydraulically isolated reservoirs. Exhibit G-I0 is an east-west cross-section across the Pt. McIntyre field, north of the Terrace Block Fault. The permeability barrier forming the western boundary of the field is shown schematically. The Kuparuk is thickest in the west and gradually thins to the east where it is eventually truncated by unconformities below the overlying shales of the Kalubik and HRZ. This truncation is an important component of the hydrocarbon trap on the east side of the field. C. Fonnation Water 5aJinities Laboratory analysis of water from Pt. McIntyre Wells Nos. 8 and 9 indicates salinity values of approximately 20,000 PPM NaCl equivalent. Because the Pt. McIntyre is only in an initial stage of development, no further salinity data is available. The 20,000 PPM NaCl equivalent salinity value is supported by log analysis results. II. Confining Intervals The Kuparuk Formation is bounded below by the Lower Cretaceous Miluveach Fonnation. The contact is defined by a change in lithology and electric log character. The Mi1uveach Formation is a highly impermeable, low resistivity (1 to 3 ohm-meters) shale with a thickness of approximately 200 feet. The overlying Kuparuk Formation is characterized by higher resistivity (3 to 6 ohm-meters). 21 . . The Kuparuk Formation is typically bounded above by the Lower Cretaceous Kalubik Formation. The contact is defined by a change in lithology and electric log character. The Kalubik Formation is a low resistivity (1 to 2 ohm-meters) shale and shaly mudstone. In the western part of the field, oil-bearing sandstones are present. The underlying Kuparuk Formation is dominantly sandstone with subordinate pebbly sandstone, siltstone, and sandy mudstone. Resistivity in the Kuparuk is in excess of 2 ohm-meters. In the south-central part of the Pt. McIntyre field, the Kalubik Formation is absent due to non-deposition or erosion. In this area, the Kuparuk Formation is overlain by the HRZ. This is a black, organic-rich shale recognized on electric logs by its high radioactivity as measured by the gamma ray log. The HRZ varies in thickness from approximately 20 to 50 feet and is overlain by the Cretaceous and the Tertiary shale/sand sequences and approximately 1,800 feet of permafrost. Where the Seabee is found above the HRZ, the Seabee is bounded above by the Cretaceous and the Tertiary shale/ sand sequences and approximately 1,800 feet of permafrost. Subsection 5 Prudhoe Bay Unit Eastern Operating Area West Beach Reservoir I. Injection Interval A. Stratigraphy and Lithology The West Beach reservoir is in the Kuparuk Formation. The Kuparuk Formation was deposited during the Lower Cretaceous geologic time period. Exhibit C-11 presents a portion of the electric log from the West Beach No.4. This "type log" illustrates the stratigraphic definition of the Kuparuk Formation in the West Beach field. The log is scaled in TVD 55. The depth track displays TVD data on the right with MD values immediately to the left. The top of the Kuparuk Formation occurs at 14,548' MD (8,751' TVD 5S), and the base occurs at 14,781' MD (8,950' TVD 55). The Kuparuk Formation in the West Beach area is overlain by the HRZ. The Kuparuk Formation is bounded below by the Lower Cretaceous Miluveach Formation or the Upper Jurassic Kingak Formation. Core in the West Beach Pool is very limited. Although four conventional cores were taken in the West Beach No. 3B, no rock was recovered over the Kuparuk interval. 22 . . Thirteen sidewall cores were recovered in the Kuparuk in this well. Three conventional cores were taken in the West Beach No.4 with a total recovery of 31 feet. Based on the core data, the lithologies are summarized as poorly sorted conglomerates and conglomeratic sandstones and very coarse grained sandstones. Porosities range from 8 to 35 percent. Well data and 3-D seismic data indicate that the Kuparuk reservoir thickens dramatically from west to east, as is illustrated in Exhibit G-12. This structural cross-section is constructed west to east from North Prudhoe No.2, through West Beach No.3, to West Beach No.4: a horizontal distance of approximately 12,000 feet. The Kuparuk true vertical thickness in these three wells is 0, 13, and 199 feet, respectively. This eastward thickening is also illustrated on the Kuparuk isopach map (Exhibit G-13). B. Field Limits Drilling at West Beach has not encountered either a GOC or OWC for this accumulation. Therefore, the OWC based on West Beach No.4 is below 8,950' TVD 55. The GOC is between 8,540' TVD 55 (the base of the gas at West Beach No. 3B) and the top of the Kuparuk at West Beach No.4 (8,751' TVD 55). Information relating to potential fluid contacts in surrounding wells is summarized in Exhibit G-14. Given the limited data available at this time, it is difficult to estimate oil in place volumes with confidence. Exhibit G-13 is an isopach map of gross Kuparuk which depicts the estimated reservoir limits. Exhibit G-15 is a top Kuparuk depth map for the West Beach fault block using a 50-foot contour interval. The structure for the West Beach accumulation is best described as monoclinal northeast dip with the reservoir bounded on the north and south by faults. To the south, the east-west trending Prudhoe Bay bounding fault provides closure. This down-to-the-north fault is presumed to also have controlled deposition at Kuparuk time. On the upthrown side of this fault (south), no Kuparuk is present due either to erosion or non-deposition. Sealing across this fault is provided by juxtaposition of the Kuparuk on the downthrown side against Kavik shale or impermeable Lisburne group carbonates on the upthrown side. The northern fault bounding this field is the Pt. McIntyre fault, another east-west trending down-to-the-north fault. Across this fault, the West Beach field is positioned against the HRZ or other late Cretaceous shales. The loss of reservoir facies or cementation within the Kuparuk may also be a component of the trap along this fault to the east where the throw becomes much less significant. Although the exact 23 . . trapping mechanism to the north is complex and not fully understood, pressure data indicates the West Beach accumulation is separate from the Point McIntyre accumulation. The remaining elements of the trap for this accumulation are northeast dip providing the eastern closure and the onlap/pinchout/truncation of the Kuparuk to the west. This is illustrated in Exhibit G-12, an east-west structural cross section A-A', and Exhibit G-13, an isopach of the gross Kuparuk with 25-foot contours. C. Formation Water Salinities No formation water has been produced from the West Beach Pool. As stated earlier, the OWC for this accumulation has yet to be contacted. Salinity data from the Kuparuk Formation in the Pt. McIntyre Pool just north of the West Beach Pool indicates NaCL equivalent values of approximately 20,000 PPM. As soon as salinity data becomes available from the West Beach it will be forwarded to the Commission. II. Confining Intervals The Kuparuk Formation in the West Beach area is overlain by the HRZ. This contact is defined by an abrupt lithology and electric log character change. The HRZ is a dark gray to black, organic-rich shale characterized by very high gamma ray counts which are often greater than 150 API units. The HRZ varies in thickness from 20 to 50 feet and is overlain by a thick shale wall and the Tertiary shale sequence. The Kuparuk Formation is comprised of interbedded conglomerates and sandstones with gamma ray counts typically less than 80 to 100 API units. The Kuparuk Formation is bounded below by the Lower Cretaceous-age Miluveach Formation or the Upper Jurassic-age Kingak Formation. The contact is also defined by a change in lithology and electric log character. The Miluveach and Kingak Formations are a thick sequence, approximately 200 feet, of dominant shales with low resistivities <typically 1 to 3 ohm-meters). The overlying Kuparuk Formation in West Beach No.4 is hydrocarbon-saturated and has resistivities from 8 to 31 ohm-meters. 24 . . SECTION H Well Logs 20 AAC 25.402(c)(7) 20 AAC 25.252(c)(5) All openhole logs from EOA wells, including Pt. McIntyre and West Beach, are sent to the Commission as the logs are completed. Exhibits G-5, G-6, and G-ll are type logs for the Pt. McIntyre and West Beach P As, respectively, with stratigraphic and marker horizons annotated. 25 . . SECTION I Casing Information 20 AAC 2S.402(c)(8) 20 AAC 2S.2S2(c)(6) Currently, approximately 16 water injectors and at least 1 gas injector are planned for Pt. McIntyre. A number of the water injection wells are planned for pre-production prior to conversion to waterflood injection. A wide range of departures will be drilled in Pt. McIntyre with a maximum injection departure of over 12,000 feet expected. Tubing sizes in the Pt. McIntyre field will vary from 3 1/2 to S 1/2 inches with the only current exceptions being 2 718 inches in Pt. McIntyre No.7 and 7-inch tubing in the gas injector PI-GI. In general, the production casing will be sized to the tubing in the Pt. McIntyre wells. Typical development wells will utilize either a "conventional," "slimhole," or "ultra slimhole" design similar to Kuparuk and Prudhoe Bay. The "conventional" design wells requiring S 1/2-inch tubing will utilize 13 3/8-inch surface casing, 9 S/8-inch production, or intermediate casing with a 7-inch liner for the high stepout wells. The "slimhole" design wells requiring 4 1 12-inch tubing will utilize 10 3/4-inch surface casing, 7 S/8-inch production, or intermediate casing with a 5 1/2-inch liner for high stepout wells. The lower rate wells will utilize the "ultra slimhole" design, a 3 1/2-inch tubing string inside a 7-inch production string with 9 S/8-inch surface pipe. The West Beach waterflood with gas injection development case includes; five production wells, five water injection wells, and one gas injection well. In general, West Beach wells will utilize either a "slimhole" or "ultra slimhole" design. "Slimhole" designs will consist of 10 3/4-inch surface casing, 7 S/8-inch production or intermediate casing with a 5 1/2-inch liner for the higher stepout wells. "Slimhole" designs will accommodate both 3 1 12-inch and 4 1/2-inch tubing. The "ultra slimhole" designs will consist of 9 5 18-inch surface pipe, 7-inch production string, and 3 1/2-inch tubing. All dedicated Pt. McIntyre and West Beach water injection wells will be completed with L-80 grade steel. The injection wells planned for pre-production may utilize corrosion-resistant material where applicable. All tubing jewelry will be completed with 9-Cr 11 Moly, which is compatible with both L-80 and 13-Cr. Most Pt. McIntyre water injection completions are currently envisioned as single zone, single string with a single packer. Where both the Pt. McIntyre and Seabee are present, the current plan is to run single packer completions. A straddle completion may be run when both the Pt. McIntyre and Seabee are 27 . . present, if sufficient Seabee reservoir quality is observed. Exhibits I-I through 1-7 show typical wellbore schematics for the three basic completion designs and the straddle completion previously discussed for Pt. McIntyre. All West Beach water injection completions are currently envisioned as single zone, single string with a single packer. Exhibits 1-8 through 1-10 show typical wellbore schematics for the two basic completion designs to be used for West Beach. As shown in the schematics, gas lift mandrels with dummy valves will be run to provide flexibility in artificial lift, which will enhance production in the injection wells planned for pre-production. Sufficient mandrels will be run to provide flexibility for well production and gas lift supply pressure. A dedicated drill cuttings disposal well is also planned for Pt. McIntyre Drill Site P2. The well is planned for the second quarter 1993. The current plan is to TO the well in the Tertiary. The current completion schematic is included in Exhibit 1-11. The actual casing program is included with the" Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. Further, all drilling and production operations will follow approved operating practices in reference to the presence of H2S in accordance with 20 AAC 25.065 (a), (b), and (c). 28 . . SECTION J Injection Fluid 20 AAC 25.402(c)(9) 20 AAC 25.252(c)(7) Subsection 1 Enhanced Recovery A. Type of Fluid - Source Water. Pt. McIntyre and West Beach are planning to inject Beaufort Sea source water; the same water that is currently being injected into the Ivishak Formation. Analysis of Composition of Typical Fluid - Exhibit J-l is a listing of the composition of the Beaufort Sea source water. Estimated Maximum Amount to be Injected Daily - Pt. McIntyre - Peak injection approximately 250,000 BWPD. Initially, the development plan includes only source water injection into the Pt. McIntyre P A. Source water needs may decrease in the future as the combined produced water volumes from Pt. McIntyre, West Beach, and Lisburne increase. West Beach - Peak injection approximately 50,000 BWPD. Conditional1y, the development plan indudes only source water injection into the West Beach Pool. Future potential exists for a decreased need for source water as the combined produced water volumes from Pt. McIntyre, West Beach, and Lisburne increase. The West Beach and Pt. McIntyre fields wil1 use a single pipeline for their waterflood water. Therefore, should Pt. McIntyre switch from source to produced water injection, West Beach wil1 most likely do the same. Compatibility with Formation and Confining Zone - Lab analysis results indicate no significant problems with formation plugging or day swel1ing due to fluid incompatibilities. B. Type of Fluid - Produced Water. This fluid is water that was produced with the Lisburne, Pt. McIntyre, and West Beach oil and separated from the oil and gas at the LPC. Produced water 29 . . may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. Analysis of Composition of Typical Fluid - See Exhibits J~2 and J-3 for the composition of the Lisburne and Pt. McIntyre formation waters, respectively. The Pt. McIntyre water sample was taken from exploration well Pt. McIntyre No.8. No formation water has been produced from the West Beach Pool. Once salinity data is obtained from the West Beach Pool, the results will be forwarded to the Commission. Estimated Maximum Amount to be Injected Daily - Pt. McIntyre - Future produced water injection rates at Pt. McIntyre may reach 250 MBWPD. West Beach - Produced water injection rates at West Beach may potentially reach 50 MBWPD. Compatibility with Formation and Confining Zones - The produced water returning to the Pt. McIntyre and West Beach Formations will be a mix of Pt. McIntyre, West Beach, and Lisburne produced water separated through the LPC. The current development programs for these three fields indicates the majority of the produced water will come from Pt. McIntyre (current maximum estimated at 250 MBWPD) with minimal amounts coming from West Beach (current maximum estimated at 50 MBWPD) and Lisburne (current maximum estimated at 20 MBWPD). Since the origin of a vast percentage of the produced water will be the Kuparuk Formation, minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. Lab analysis results also indicate no significant compatibility problems. C. Type of Fluid - Natural Gas. This fluid consists of Lisburne, Pt. McIntyre, and West Beach natural gas and natural gas liquids produced with the oil and separated from the oil and water at the LPC. Analysis of Composition of Typical Fluid - See Exhibit J-4 for the composition of the Pt. McIntyre, West Beach, and Lisburne processed gas streams. The Lisburne composition represents the processed gas stream currently being reinjected into the Lisburne, while the Pt. McIntyre and West Beach compositions represent produced gas streams. The actual commingled processed gas stream reinjection should be closer to the Lisburne composition as the heavy ends listed in the Pt. McIntyre, and West Beach compositions will be removed through processing at the LPC natural gas liquids facility. 30 . . Estimated Maximum Amount to be Injected Daily - Pt. McIntyre - Injection could potentially reach approximately 500 MMSCFPD. West Beach - If economically feasible, facilities to reinject gas into the West Beach could be in place as early as 1995. Potentially, a maximum of approximately 250 MMSCFD could be injected. Compatibility with Formation and Confining Zones - a. Pt. McIntyre - The H2S levels detected to date have been very low in the Pt. McIntyre reservoir. The processed gas injected into the Pt. McIntyre gas cap will be a mixture of Lisburne, Pt. McIntyre, and West Beach produced gas processed through the LPC. The Lisburne processed gas stream is expected to initially contain higher levels of H2S compared to the initial Pt. McIntyre and West Beach produced gas streams. This circumstance will tend to increase the presence of H2S within the Pt. McIntyre reservoir. Although the H2S levels are expected to increase with time at Pt. McIntyre, independent of the Lisburne injection gas due to current plans to waterflood the Pt. McIntyre Pool, minimal compatibility impacts are anticipated as a result of the gas injection into the Pt. McIntyre reservoir. b. West Beach - There are no compatibility problems anticipated with West Beach. Currently, no H2S has been detected in the West Beach reservoir, and current development plans do not include gas injection at West Beach at start-up. If gas injection is initiated, some H2S impacts are anticipated. Experience gained at Pt. McIntyre will provide operational guidance. Subsection 2 Fluid Disposal A. Type of Fluid - Produced water disposal. Analysis of Composition of Typical Fluid - See Exhibit J-3, "Pt. McIntyre Produced Water." Source of Fluid - Produced water from the Lisburne, Pt. McIntyre, and West Beach PAs. ,REŒEi'/E -'" t § 31 & Gas Cons. AnchQraga . . Estimated Maximum Amount to be Injected Daily - Produced Water Disposal Wens (LPC Disposal Fluids) - The LPC injection fluid for disposal is predominantly produced water from the Pt. McIntyre, West Beach, and Lisburne PAs. Upgraded pump design and piping along with the workover of existing Injector LPC-Ol and the drilling of one to two additional disposal wells will place the maximum disposal capacity at approximately 80 MBWPD per well, or 240 MBWPD. B. Type Source of Ruid - Exempt waste. Source of Fluid - The injection stream could include drilling mud, reserve pit water, contaminated crude, diesel gel, glycol (associated with wen production operations), and workover fluids. Only exempt fluids generated from Pt. McIntyre, West Beach, and Lisburne are planned for injection at this time. Estimated Maximum Amount to be Injected Daily - Exempt Waste Disposal Wells (DS-P2 Cuttings Disposal Well) - Expected maximum daily rate of 2,000 BPD. 32 . SECTION K Injection Pressure 20 AAC 25.402(c)(10) 20 AAC 25.252(c)(8) . The estimated maximum and average injection pressures anticipated for Pt. McIntyre and West Beach enhanced recovery and LPC produced water disposal wells are listed in the following table: Type Well LPC Produced Water Disposal Pt. McIntyre Gas Injection Pt. McIntyre Water Injection DS-P2 Cuttings Disposal Well West Beach Gas Injection West Beach Water Injection Estimated Maximum Injection . Pressure (Psig) 2,700 5,000 2,850 1,000 5,000 2,850 Estimated A verage Injection Pressure (Psig) 2,200 4,300 2,450 500 4,300 2,450 (pressures represent pump discharge pressures) 33 . . SECTION L Fracture Information 20 AAC 25.402(c)(11) 20 AAC 25.252(c)(9) The estimated maximum injection pressures for enhanced recovery and fluid disposal wells will not initiate or propagate fractures through the confining strata, which might enable the injection or formation fluid to enter freshwater strata. Subsection 1 Freshwater Strata There is no freshwater strata in the area of issue (see Section N). Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Subsection 2 Enhanced Recovery Injection in the Kuparuk and Seabee Formations, above fracture parting pressure of these formations, may be necessary in the future to allow for additional recovery of oil. In no instance would such injection pressures breach the integrity of the confining zone. The Kuparuk Formation is overlain by the Kalubik and HRZ shales. The HRZ is a thick shale sequence which would tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. Mechanical properties log data for the HRZ and Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. The Seabee is overlain by the K-l0 shale interval. Mechanical properties log data for the K-l0 interval also indicates a fracture gradient from approximately 0.8 to 0.9 psi/ft. 35 . . Fracture data from the Kuparuk intervals of the Pt. McIntyre and West Beach Pools indicate a fracture gradient of between 0.60 and 0.63 psi/ft in current virgin reservoir conditions. Fracture data from Pt. McIntyre No.9 gave a fracture gradient of 0.624 psi/ft, while data from West Beach No.4 indicated a fracture gradient of 0.602 psi/ft. No fracture data is currently available for the Seabee. However, based on known characteristics of the Seabee, its fracture gradient should fall in the same range as the Kuparuk and Ivishak Fonnations, from approximately .55 to .65 psi/ft. The Kuparuk Formation is underlain by the Miluveach/Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrated leakoff at a gradient of 0.85 psi/ft. The Seabee is underlain by the HRZ shale, the properties of which were described earlier. Prudhoe field data also indicates that sandstone fracture gradients may be reduced during waterflooding operations due to reduced in-situ stress associated with the injection of colder water. Declining reservoir pressure can also reduce formation stresses, thereby reducing the fracture gradient. The Pt. McIntyre Pool will be produced for a minimum time prior to the start-up of waterflood operations allowing the reservoir pressure to decline somewhat. However, once waterflood operations are initiated, field average pressures will be managed to mitigate fluid migration and sustain reservoir energy. Subsection 3 Fluid Disposal Consistent with existing Area Injection Order No.4, the injection zones for fluid disposal and all zones above and below the injection zones contain greater than 10,000 mg/I TDS and are not freshwater strata. Therefore, injection at above parting pressure would not result in formation or injection fluid movement into freshwater strata. Based on Prudhoe Bay EOA step-rate test data, the fracture gradient for the Tertiary/Upper Cretaceous injection intervals is approximately.6 psi/ft. The confining shales below the injection zone are in excess of 2,000 feet vertical thickness. The upper confining zone consists of numerous interbedded confining shales and mudstones averaging 10 to 50 feet and over 1,800 feet of permafrost. Fracture gradient data for the confining shales is limited. However, rock mechanical properties data indicates that the confining shale fracture gradients would be in the range of .8 to .9 psi/ft, significantly higher than.6 psi/ft. The planned disposal of produced water into the Tertiary/Upper Cretaceous will be in addition to existing EOA and WOA injection operations. Pressure impacts are expected but are not anticipated to be 36 . . significant. The exact impacts are not currently quantifiable due to uncertainties in injection rates and timing. ARCa will continue pressure monitoring of the Tertiary/Upper Cretaceous. 37 . . SECTION M Formation Fluid 20 AAC 25.402(c)(l2) 20 AAC 25.252(c)(lO) A typical water analysis for the Pt. McIntyre reservoir is included in Exhibit J-3. As stated earlier, no water analysis is currently available from the West Beach Formation. Once water composition data is obtained, the data will be forwarded to the Commission. Exhibits M-l and M-2 are typical water analyses for the Tertiary /Upper Cretaceous as found in existing Area Injection Order No.4. 39 . . SECTION N Aquifer Exemption 20 AAC 25.402(c)(13) 20 AAC 25.252(c)(11) No aquifer exemption was applied for or granted in regard to Area Injection Order No.4, as a lack of freshwater (less than 10,000 mg/l TDS) was demonstrated in the EOA. The inclusion of the proposed Pt. McIntyre P A will expand the EOA to the north (see Exhibit N-1). To confirm the lack of freshwater in the expanded operating area, estimates of TDS have been made for the Pt. McIntyre P A. As in the original Area Injection Order No.4, resistivity and porosity log data was utilized to approximate formation TDS values. Exhibit N-2 describes the methodology used to calculate the salinity values in the original injection order and this amendment. Exhibit N-3 is a summary of the analysis results. The lack of freshwater found in the Pt. McIntyre P A eliminates the need for an aquifer exemption in the expanded EOA. 41 . . SECTION 0 Hydrocarbon Recovery 20 AAC 25.402(c) 14 The current recommended Pt. McIntyre development scenario includes a combination of processed gas reinjection and pattern waterflooding. A total oil recovery of between 42 to 45 percent OOIP is expected for this development scenario. This compares to an estimated 20 percent OOIP oil recovery attributable to primary depletion. Incremental hydrocarbon recovery of approximately 160 MMSTB is expected to result from Pt. McIntyre waterflood and gas reinjection projects. Due to the uncertainties associated with the extent of the West Beach Pool, the current estimated OOIP ranges from 12 to 65 MMSTB. Primary depletion is expected to recover up to approximately 10 percent OOIP. Reinjection of processed gas could increase the recovery to approximately 20 percent OOIP. Waterflood operations could increase the ultimate recovery to approximately 29 to 44 percent OOIP, depending on the extent of the West Beach Pool. A maximum increase in recoverable reserves of 22 MMBO may result from the West Beach waterflood and gas reinjection projects. 43 . . SECTION P Mechanical Integrity 20 AAC 25.402(d) & (e) 20 AAC 25.252(d) & (e) In drilling all Pt. McIntyre and West Beach injection wells, the casing is pressure tested in accordance with 20 AAC 25.030(g). When a producing weIl is converted to injection, the casing pressure test will be repeated in accordance with 20 AAC 25.412(c). Injection well tubing/casing annulus pressures will be monitored and recorded on a regular basis by the Production Operations Group. The following is a summary of the current Commission rules pertaining to the mechanical integrity of an injection well. The summary is not meant as an amendment but rather as a summary of the current mechanical integrity rules in reference to the EOA. ARCO intends to remain in compliance with both for the original and expanded area. Tuly 11, 1986 1 The tubing/casing annulus pressure of each injection well must be checked weekly as a routine duty 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 percent of the casing's minimum yield strength. Tubing/ casing pressure variations between consecutive observations need not be reported to the Commission. A schedule must be developed and coordinated with the Commission which ensures that the casing/annulus for each injection well is pressure tested prior to initiating injection and at least every four years thereafter. A test surface pressure of 1,500 psi or 0.25 psi/ ft multiplied by the vertical depth of the packer, whichever is greater, must be held for 30 minutes with no more than a 10 percent decline. The Commission must be notified at least 24 hours in advance to enable a representative to witness the pressure test. 45 . . 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. October 28, 1986 2 Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing, or packer, the Operator must; (1) notify the Commission on the first working day following the observation, (2) obtain Commission approval of a plan for corrective action and when USDW is not endangered, and (3) obtain Commission approval to continue injection. April 19 , 1991 3 The following describes the current procedure used by ARCO to report the results of mechanical integrity testing done for ARCO's North Slope properties. A quarterly report will be submitted summarizing mechanical integrity tests (MITs) performed during that quarter on VIC Class II injection wells. Additionally, the report will include brief comments on all injection wells which have average tubing/casing annulus pressure within 500 psig differential to the average tubing pressure during the middle month of the quarter. Wells with an annulus pressure less than 500 psig will not be commented on. These comments will describe the nature of the well annulus pressure performance such as: A. Diagnostic Evaluation Complete: Form 10-403 waiver received B. Diagnostic Evaluation Complete: Minor pressure communication noted, continued to operate and observe significant changes in status C. Diagnostic Evaluation Complete: Annulus pressure history indicates no leaks D. Diagnostic Evaluation Complete: Recording error or failed gauge E. Diagnostic Evaluation Underway 46 . . References: 1. "The Request of ARCO Alaska, Inc., for and AIO for the EOA," AOGCC memo to AAI, July 11, 1986. 2. "Amend Rule 7 of Area Injection Order No.4," AOGCC memo to Prudhoe Operations Manager, October 28, 1986. 3. "Annulus Pressure Monitoring of VIC Well," AAI memo to AOGCC, April 19, 1991. 47 . . SECTION Q Wells Within Area 20 AAC 25.402(h) 20 AAC 25.252(h) To the best of ARCO Alaska, Inc.'s knowledge, the wells within the area of review (i.e., the EOA including the Pt. McIntyre P A and West Beach P A) were constructed, and where applicable, abandoned to prevent the movement of fluids into freshwater sources. 49 Exhibit A-I: Exhibit A-2: Exhibit A-3: Exhibit A-4: Exhibit B-1: Exhibit B-2: Exhibit B-3: Exhibit C-I: Exhibit D-I: Exhibit G-I: Exhibit G-2: Exhibit G-3: Exhibit G-4: Exhibit G-5: Exhibit G-6: Exhibit G-7: Exhibit G-8: Exhibit G-9: Exhibit G-lO: Exhibit G-ll: Exhibit G-I2: Exhibit G-I3: Exhibit G-I4: Exhibit G-I5: Exhibit 1-1: Exhibit 1-2: Exhibit 1-3: Exhibit 1-4: Exhibit 1-5: Exhibit 1-6: Exhibit 1-7: Exhibit 1-8: Exhibit 1-9: Exhibit 1-10: Exhibit 1-11: Exhibit J-I: Exhibit J-2: Exhibit J-3: Exhibit J-4: Exhibit N-I: Exhibit N-2: Exhibit N-3: Exhibit M-I: Exhibit M-2: . . List of Exhibits Location of Proposed Pt. McIntyre P A Location of West Beach P A Legal Description of Proposed Pt. McIntyre P A Legal Description of West Beach P A Plat of Wells Within Proposed Pt. McIntyre P A Plat of Wells Within West Beach P A Plat of Potential Wells Within Proposed Pt. McIntyre P A Native Allotment Parcel Map Affidavit Generalized Stratigraphic Section of Tertiary /Upper Cretaceous ARCO West Sak River State 1 Log-Ugnu and West Sak Sands North-South Cross Section of Tertiary /Upper Cretaceous Plat of the Wells used in Tertiary /Upper Cretaceous Section Pt. McIntyre Field Type Log - ARCO Pt. McIntyre No. 11 Well ARCO Pt. McIntyre No.3 Log-Seabee Formation Top Kuparuk Formation Structure Map Kuparuk Formation lsochore Map North-South Cross Section (A-A') East-West Cross Section (B-B') West Beach Field Type Log-West Beach No.4 Well East-West Structural Cross Section (A-A') Kuparuk Formation Isopach Map Fluid Contact Correlation Chart-Prudhoe Bay Area Top Kuparuk Formation Structure Map Pt. McIntyre Well Schematic Ultra Slimhole 3.5-inch Tubing Pt. McIntyre Well Schematic Slimhole 4.5-inch Tubing Pt. McIntyre Well Schematic ConventionaI5.5-inch Tubing Pt. McIntyre Well Schematic Slimhole 3 .5 or 4 .5-inch Tubing Pt. McIntyre Well Schematic Conventional with Liner 5.5-inch Tubing Pt. McIntyre Well Schematic Gas Injection Completion Pt. McIntyre Well Schematic Straddle Completion - 4 .5-inch Tubing West Beach Well Schematic Ultra Slim hole - 3 .5-inch Tubing West Beach Well Schematic Slimhole 4.5-inch Tubing West Beach Well Schematic Slimhole 3 .5 or 4 .5-inch Tubing Pt. McIntyre Cuttings Disposal Well Schematic Beaufort Sea Source Water Analysis Lisburne Produced Water Analysis Pt. McIntyre Produced Water Analysis Injected/Produced Gas Stream Analysis Expanded Eastern Operating Area Equations Used in Formation Water Salinity Calculations Pt. McIntyre Calculated Wireline Salinities Tertiary /Upper Cretaceous Water Analysis Tertiary/Upper Cretaceous Water Analysis 51 -- . ! . ~ Native Allotment Parcel Map ~GGIS. ~ ") , - ~ ~Áv" \6 ß DEW SITE (\ PT. : ~ \ M cl N TY R E .>~ I I I I STUMP IS. 15 PT. STOR~ERSEN ~. " S.T.P. . . ".( I' I\. '- I WE . . Exhibit C-l TERM WELL A i I N P.B. \ \ 5T.#2 \ \ I i \ ' \ . Plat of Potential Wells Within Proposed Point McIntyre PA - ------- ~ BPX V r; 1 :áÞ PM 9 B-2 . 11 . C2 . .. H2 F3 . C3 . 12 .. . H3 . PM 6 ~L . J3 H4 . . /4 C5 .. J4 . Hli . , 15 C6 . .. PA 4 J5 . . H'l J6 . . K6 .. ENTERP. 312809 EXXON 34622 A-2 . f;;¿ . D3 . D4 . E3 . PM 'l .. F4 . D6 :3 B-1 . ~ . D'l . PM 11 rB . =:r . "". DB 0" . .4-1 ""0 - . ~ ("!J PM 8 I . . VJ '- E-1 ... D-1 . C'l . . . PM 3 e-e · '1 H9 98 . Potential Producer .. Potential Water Injector \ Potential Gas Injector . Potential Cuttings Disposal Well A-E 28297 /9 . ~\ l~ \" ¡;; .. ---.----~ ( i J7 . K'l . IŒ . BPX 36554B ./0 . ó'O . LV J1 . C-2 . . LI J2 . . K2 .. L2 . M2 K3 . PM 13 .. . K4 M3 .. . L4 . C-2 ... L5 . M4 . M5 . N5 . L6 . L? . PM 5 .. NtJ . AI? . L8 . N'l MB . . . F-2A . F-2 P7 . lJ{j . ~ ~,-- tr 05 r- . 06 .. . l'ö . A-E 34627 Plat of Wells Within West Beach P A rt1 >< ::r ..... 0'" ..... f"Io tj:j I N BPX 365548 ~ ~ BPX 365549 . ~-~-.._-----------_.-._---------~---------------.-----.--------------------------..-----...---------.-.--------- WB 3 ?:B WR 4 ~ Gull / 1 ~- WEST BEACH PARTICIPATING ARSA ¡--- --------.------- · · · · · · · · · · · · , .......... --...."........, WB ARGO-EXXON 28300 I · I · I · I , I , I , , J ARCO Alaska. Inc. Lisburne/point Mcintyre Engineerine ARCO-EXXON 34627 ARCO-EXXON 34628 West Beach Location Map r8J Abandoned Wells ® Suspended Wells . Drilled Wells E. Zuøpan 07-211-92 ARCO-EXXON 34626 C8J Is1. 3 ARGO-EXXON 34629 PBU BOUNDARY --> q b. . D . J'38888 fEET' Z0~0. 10~0 . 60~0 . 80~0 . 10800 fEEl 51"TUTE HilES 8 ~ Sf"WfE HILES ARCO Aleeke. Inc. U,Þurne/Pt. IIclntyre £n.ln..rln. Plat of Wells Within Proposed Point McIntyre P A ,... ... ...... I I I . Drilled Wells 181 Abandoned Wells ~ Suspended "ells -œ- Poinl Mcintyre Participating Area ARCO 3'ì'G 136-·---- _m_______________ ARCO-~ºN 34623 C· ...~::~::~::::.~;:::::::-.::::::-... ( ,. .r:.......J''''.,...:.:........'';i:.r "a';' .... I., -.. .. ......' . ...:::...., ~ '.................. ....~.... P2-55 P2-49 ~~ . . . ~ I "-':". PM 7 : ,~. . I ..--., - - -.. u. __ _ _. -_ _ -....._ _ _.._ ___ __ _..".__.__ .. ______________ __..::..;;~~..._ _.___._._ ___ _...h_........._ _ ___._________.__..f.I.. _6____.. .____ _._....______. __ _____eO_e. __.._______._. _.. _ ___ ___. _ t------- ~.. . : ~ . "~:- \ \ : .\ PI-II '~~~,' PM 13 ! ~ : \\ . .: rr1 PM 2 \\ : >< ¡ J \. 181 \\ ! ::r ~l- \ \\ PM 1 ! ;: . " r~l\ ... PM U \ \ 181 PM 4 ! =: ! \!.J .\ · \~\ ....t. P2-30 ¡ = --------; ....--..-. :' t... '" 1 I . , '. ..\ ~., ....... . ..!.... : ).--':'. pJ 20 J ~ \ '/'. PM 8 . - .\ ...... : ¡....... ..... .....--- .. 1 ..".. . ...,........ " \\ I u- il \.. .. .. ¡ .....:. \. .. ) \..., \,\ ..,".... .........,#,. \ \ '. .. I. \l , PN 3 \ \ · \...... :>N 10 \\ II I-Gl , \ . \ \." PBU Boundry ,-...............-.. .... .. .~..""":.--'."""".""'.~..""'.."'..1:'''''..aoutØ..,v.......'I.''''..'''''..'''..~''''..~ .···············.....·......······...···v_ .....-. ~::I.. ..,::'" P2 48 :' .....\ ..:.1 ... - ;.,::: \. /{. QII P2-50 ". ./,., \.. ~ . ~,.,'~._.~.~._.,I.. { ;. ... .......1... ..... :' \.,"",..~~~ ....-.... AReO-EXXJN 34622 '---'--BPX'O áä55~ïä·..-..····..·..·· ....-.. PM 9 . . P2- 51 . Pro Josed Pl. Mclnlyre PA Ðoundry---> PM 5 . . ARCO-EXXON 28298 .-- ---...--...--~-- <_ _____ ~RÇQ__:__E}Q ON 28297 , ¿R6Q-Ex]ON 34624 . I i AReO-EXXON' 34627 '. '. '. '. '. ...., . . Exhibit A-4 Legal Description of West Beach Participating Area UMIAT MERIDIAN T12N, RISE Section 19 51/2 Section 20 SI/2 T12N, R14E Section 24 51/2 T12N, R14E Section 25 Nl/2, SEl/4 T12N, RISE Section 29 Nl/2 Section 30 Nl/2 T12N, RISE Section 28 Nl/2 Exhibit A-4 . . Exhibit A-3 Legal Description of Proposed Pi. McIntyre Participating Area UMIAT MERIDIAN T12N, RISE Section Section T12N, R14E Section Section Section Section T12N, R14E Section Section Section Section T12N, R14E Section T12N, R14E Section Section Section Section 18 All 19 N1/2 13 All 14 All 23 N1/2NW1/4, N1/2 NE1/4, SW1/4 NW1/4 24 N1/2 15 All 16 All 21 N1/2 NE1/4 22 N1/2 17 N1/2, N1/2 SE1/4, NE1/4 SW1/4 excluding U.S. Survey 4044 3 All 4 All 9 All 10 All Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Sections 2 and II, T12N, R14E, UM, AK (Identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, RISE, UM, AK (Identical with line 6-7 on Block 60S), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.CS. Block Diagram," approved 12/9/79. Exhibit A-3 c BPX 365548 .... I·· · · .. .. · · .. · .. .. · · · .,.~.-p._-----.' , I I , , · '\ ~- BPX 365549 ARCO-EXXON 34627 ARCO-EXXON 34626 . .....................................................= ......................................................... J . · · · · · PBU BOUNDARY --:>: · · · · ........ tTj >< ::r' "". 0'" "". .... ; > , I : N , , I I , ! ARCO-EXXON 28300 , I I t · · I · · · · · I I ARCO-EXXON 28301 ARca Alaska, Inc. Llsburne/polnl Mclnt.yre Englneerln. West Beach <:--- P) PROPOSED WEST BEACH PARTICIPAT: NG AREA ARCO-EXXON 34828 -, ARCO-EXXON 34629 Location of West Beach P A Proposed Participating Area E. ZuaPIUI --.-. -.- --.- -- - .- '.~ '- -- Q?-t'-a2 ".... -,- I'm, STRTUtI KILIt' q b.. ¿¡ . -'-" II ,.... 21.. 11' .... .... ...."EfT a STllTIIT! "ILU ARCO Aluka. IDa. ,J.........1Pt. .......t.... Ir ·r-.....rL Location of Proposed Point McIntyre P A Point Mcintyre Participating Area -0 , -.. I } ARca 370 13tt·---· --------------..--- ARCO-E¥.XQN 34623 ,- ..~:::....... ..:::::s ................ ( ." ,......-...~...... ... ll~$~~tl...-\~~ :::~ '. ., " .... ... -. ..., .....:'. '.~'. '. " , '. ,..... " .... . .----...--..---- ...-.. - ---.. ..-- --... ----...... .-- -...- --. .-- ............_-..---... -_.--~~---, ... .----------.-_..-------.-... ..---.- -.---. -.. ---....--_...... ..------.---.---....-.--....-....-.. ..-... -...--...... ---- -..- ----...... ~ . ~.. ......-- -.... ..,~ . ~ t=' I ~ ¡ ~ I . \ i ~ ~ ¡ " '.. .. -.' \ . \\ \\ ... ~ 1 \\ \ \\ . '.. \\ .... . ~\ PBU Boundr, \ ... , ....._.....__.__......,..,.··v,', ...·v -.........., &.... ............ . .,......",......I.......UM.......~..UII...,.".IIUI'........·_··.,-··.·..··..·.."·...,,......suaI.JIJ I . ~\ / ' .e.;)"" A:' "~t(._- r . - .... . '-", , .... ..""., .... '. ARCO- E~º.~.~~~_p..ª_...___...__'4I.n..........!B.Çº.::EQON 28297 Aim<t-:-EXXON 34624 , , ........ EXXON 34822 - - - ....-....... .--.................. ....... -.- r- ... ..- .... ........ .......... -11-............ ....... BPX 365548 . rrJ So ..... 0- ..... .... Pro ~oaed Pt. Yclnt}'l'e PA Bounclry-:---> > . þooo\ -1\\ .\ '-~) \ r- ,.. to. " \&1 ..l --..---.-. ~ '. ')\ "s.. \ ·ll \ .... "- ..]' \ . . .. ... :::.~ .... f . . \ ...~I " .... I .. .fI ............\ .' \ \ ARCO-EXXON 34627 · -- Exhibit 0-1 AFFIDAVIT OF GEORGE K. PHILUPS REGARDING NOTICE TO SURFACE OWNERS IN THE VICINITY OF THE PROPOSED INTECTION WELLS George K. Phillips, on oath, deposes and says: 1. I am an Engineering Supervisor at ARCO Alaska, Inc. the operator of the Eastern Operating Region of the Prudhoe Bay Unit. 2. On April 5, 1993, I caused copies of the application to amend Area Injection Order No.4 to be provided to the Surface Owners of all land within a quarter mile of all proposed injection wells within the West Beach and proposed PI. McIntyre Participating Area as listed below: State of Alaska Department of Natural Resources Attn: M. D. Kotowski P.O. Box 107034 Anchorage, AK 99510 Lawrence Ahmaogak P.O. Box 411 Barrow, AI< 99723 George Ahmaogak P.O. Box 338 Barrow, AI< 99723 Barbara Ahmaogak 1628 Hilton Ave. Fairbanks, AK 99701 John Nicholls (minor) c/o Ely Varner (guardian) P.O. Box 473 Barrow, AI< 99723 Alice Glenn 899 Blair Ave. Sunnydale, CA 94087 ~~/C~¥ George K. Phillips STATE OF ALASKA ) ) ) 85. THIRD JUDICIAL DISTRICT SUBSCRIBED AND SWORN to before me this 5 day of April, 1993. QQ~ÇcL ) NOTARY PUBLIC IN AND FOR ALASKA My Commission Expires: \ - Ln - 9 tÞ Exhibit D-l ~~.,~.:' ":,'~'; ;~~~~~:.:.:~ ?:?Ús: ~:.~ ~.~ :~.~ : '-=" ~ .::'~::~ '.:: :'; :: {~î~~ii .. .1-. ,t .'~' . ". IASI ~:~:?- PERMAFROST: Interbedded gravels, sands and shales. t'I~·.;.··':·" 'lOS' (' :.:::...:: 1'-3 f(~'~:~:, T-3: Sand marker bed overlain and underlain with inter- f·:-;:ö:;...·:·.::; (TT6) bedded gravels, sands and shales. P.~~··;·:::. ~~~~~~~i-~ --:-ø..' . I: ~': :" ~. : K.I. ~~-_-~ K-15: First coal marker underlain with sands, silts and ;r"~::·.;:-i (TKl) shales. Localized coals occur within this interval. ~i¡}~~{ - -.- - - ",. '. . . , .~.~ U,"I ¡~~~ UPPER ~~: UGNU~·~~;;_:'~--~. :'7~..I...~:.: ". .',. .. . " ........... I '. ":.'~: ~ .::, '~-.'-~~..,~.~ LOW.I .'::~.: ::./:,.~:. LOWER UGNU: - - - - - -. UGNU ---:-:-,:-_ ~.-:-~-.-- .:-:-:-:-:.. WIS' ~~~~~~. WEST SAK SANDS: Interbedded fine-sandstones, siltstones, SA. t=:=::::::: and clays. SANDI ~~~~gi~@ ~~~~~~~~~~ ;[i7~::¿~ , :.....~ ~::~'·-::'4 K 12 Þ;~~~~~~ K-1Z: '.~.".':'':''' (TK6) ~~~~~~:~~~ - -. -. - -".-. ----- :-:-:-:-:-; ----.-.-.-. E~::::~: '-'" -- -. --- > a: cC - I- a: W J- tn :;:) o w CJ cC J- W a: CJ ~I'IOO Go ð a: " W .J .J ~ o CJ . . GENERALIZED STRATIGRAPHIC SECTION LITH- MA.... O~OO' OIlC."TlON z o - !ë :E a: o .. ~ o ... ~ a: I > 4( CJ 4( o Interbedded coarse to fine sands and shales. Interbedded coarse to fine sands and shales. Interlaminated silty mudstones and shales with minor silty sandstones. Based on data from: ARCa West Sak River State '1 Exhibit G-l . . ARCO WEST SAK RIVER STATE 1 SEC. 2, T.11 N., R.10E., UM OR LL8 10 100 1 10 100 ~ t t 3200 '- ¿ UPPER UGNU ? > SANDS - ? ~ t 3400 '- -S- ~ ~ ~ i ~ LOWER UGNU ~ I SANDS J ~ 3600 '- , + 3800'- t ~ 4000 '- ? ~ ¿' t WEST SAK SANDS + K·12 . , .- Exhibit G-2 . . Plat of the Wells used in Tertiary/Upper Cretaceous Section ~---------------------: I I , "-, I , I --, '-- ~-, ~ I --, I_- I ~ PII'iN McIntyre #6 , I I ....-----f"------- 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 WOA 1 EOA 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 , ~ q ~ .. WE r.n B.aDIt. ~ . LPC-l ~ . PWDW 1-1 -------- ~---------------------~ .-------, .-------- , , I I , , I , , I I I , I , , , , , I I , I I , I I , , I I I I I I , I o ,---,. I ----I I__a Q ------------------------------------------------------... ¿,,,,,,,,, (~"'~ Exhibit G-4 ò{ t c c 0.2 10.. - -m _ N 0= Q) E C Q) o C N .- := ~ ~I . Pt. ~clntyre Field Kuparuk Fm. Type Log Pt. Mcintyre #11 ~! I ~-) \ f! .J:¡ ,,~ ~.:...;:-~ 'I i ~>::; I! ~I ,":':.~ i t , ~. -'.,~ I ¡ I ~:{.~;.,':~; I_ I . .,:.:.....:.,~! '~10150 1 ¿.;'.:~:·;·:;I, ;: ¡ ~ ?'~:··.Yj~ tl0200 I· ~:.L') 1- ~. ..'~ I 10250 ! I "":j1 ! ~.\t'1 {'I I......;·::J:.~ ~ ,I C:~··"I:·.1 !" ¡~····"··I I -..,::-,' !i:ci} . ~..:. .'. ..,. .~. ; ¿,'.:-..... , ~...~ 1 j I -ISO. o. t-----¡¡.--¡¡ÿ------I 110. .... I 011 011I' I I O. I 011 GA~ I ~~" U ' I i I ! ~i I 150. I MD SS aaoo .: "- 1900 1950 8700 ::'10000 r .: '- ::-10050 aaoo 10100 10300 ..,... ,- 10350-- . r \, i -10400 ,: - . l e: I d 10450 '1\ 10500 9200 {. ;:' . ¡ ,- :1 ~10550 i ~ : \¡ :'101100 9300 \: : , .: 101150 I - .I ~ \ 10700 9400 1\- I I~ , I 10750 ,- ,- 11900 9000 9\00 9500 .2 200. t-----s,ï:ü-õi1ftii-----¡ .2 200. I IL" ~ I .2 200. I (LD 0""" ' -. "\t 1Io: \ ~ ~ ~ ..-- :c·e=:= '2 ::» -;':-2:'( 1 ~ :;r- -- ~- . HRZ Kalubik Fm /14. '- ... Q) Q, Q, ::» Kuparuk Fm t r.JIW o4IUöj' I- ~ .4'--- ...... r- '-, ? i Exhibit G-5 9908' MD -8649.5' TVDSS A ... .- o ~ CI) U) I) a: CI) '- >- ... C - u :E -- := C ::» ... Q) 3: 0 ..J : W ... a.. ." 10,665 MD -9365.8' Miluveach TVDSS Fm . . Pt. ~clntyre Field Seabee Fm. Type Log Pt. Mcintyre #3 O. 100. ~-------~---"ÿ--------~ -100. o. !-----~--i1v------, 110. SOCI. I 11II 0IIf'1 I 11..¡ : I ~ i1 ~: ; ~'00 I ~ :_"" ~ 11/'"7' 3750 ! ,......-1" :~; :: I f I ~ I_ I ..l_~.¡ ~ I I I.. -I tJ i~..:.o,:~ I . ~,I ~ I !":"'l'~. , : :...+r" i í 1 F ,- ~.,!Ii,¡' , I ' ,I , ¡ : . , ;~, ,,\ 9000 1{t1 : : : i·"," . i· r~ ~~ 'J.; ·U.;:- Ii,·.'.,::.: . '!9.~'";.~~':':-~: 'Ir~·:. ;f- .~.... ~~). :~ ~)/:.:~.: i I ! O. ,... i I ~ OII~ ( ISO. I ~ , , -, 8950 :- "100 _ , ~ ~ 9150. __ i ;: 8&00 í I ,- j I i ,- I '! [200 _250 I~' \ I:: '-" ~ I ~ ::"00 -tf' ': ~)! I ! Çog'50 ~.: 7) , i ~.oo I' i ! ì ,: '-9.50 .... MD 8800 8850 8900 . 8993' MD -8432.6' TVDSS (1)4 ,-,- - - ~ ·-0 ..... c > - '- o (1) :æ~ ""'[t ~t 9288' MD - 8 724' TVDSS .2 200. ~----¡¡lü-¡¡¡;'¡;¡-----' .2 2011. I ILII ~ I .2 200. t (La OHIIII I SS 8100 ~ 8200 ,I :(' '.. ill .., ...'1 Seabee Fm (Stump Island SS) noD ...;.~ .... 8.00 ,1- HRZ ,.-. 8500 ~~ i);.. A ~/.¡- Q..- .// /,_ Q. s:: ~¡f-- ? ::) t~ -- ~n ;.. .....' . " ï: Kuparuk GIO ·8582' ,.,;;:or- ::) :'..:.:~ ~ Fm ....~ i .~':..,~ .3 IS t 8700 + 8800 ~iluveach Fm 8100 Exhibit G-6 Top Kuparuk Formation Structure Map 8eoooo ...000 I eaepoo 1'72000 I I'JIOOO I 110OOO I ...000 1180OO neooa I 100000 ! i LJV .' 0 -I , ~. I _I :- (). § 1 r > > :J f, I . I-~t -I .. ~ ~ g .. ( :660r "11 III EX..IBIT. . T(~ KUPARUK FOR HAT ION STRUCTURE HAP C r :: 50' I ., 4000 · AI ·0 ALASKA INC. PT. HCINTYRE 371138 MR_yr~ .f ALK-2309 ~ ~ a-30-75D .~ 6 ICONOI ~ ""' I I ".000 H8000 I 812000 o I 4000 ...... I 8eoooo 8000 f..t I I 8..000 I 8112000 111IOOO 1 mil. Preliminary Kuparuk Formation Isochore Map 8,·,'??oo ;-- H.ooo 1 HIOOO 1 17zpoo 171000 I i- ... ~ .......... ~ " ~8¡OOOO . - I ~ EXHIBIT. (. ".000 I KUlltARUK' 'OR HIOOO CI' = SO.r HArlON ISOCHORE HAP A'i!) ALASKA I NC t -, 4000 . . pr. HCINrYRE .- - I 172000 I HIOOO /4- ~ 8~ ~ ",.,11; H I-swlal "In It200Q I 11IOOO ADl 28291 171000 ADL 34824 I ...000 I 11000O 8000 f..t I o I 4000 ...., Preliminary 1 mile 700000 ~ -I _I I -I ì -~~----:~~.... ...... . ".. 'ij'~~I~~~THt~m\1jt:_.._ .... _ m ....._-- . ~...... ..-. . .... . .. ".. .. ... .. ':1 . - - --T --J:." .... . . . .- .. ...,¡ ......- · .,. ..~. . . ",. "-' .. I . ._ - ....~. ( ..... ~, , ." ~. Kingak I Miluveach ? . '~"H'" '. .._ Kuparuk Gamma Ray Shale (HRZ) . ... .... " . ,. ,,_. " .,./.. .<l)/13. l~;Jr{¡'i'¡iiss¡(,11 ,~\ I :,~··:onlJe . .... ...... ..-- .. ....-.. . .. .-. ',:. 1<'. ......_. a............ .., _ ,"f·'\ ")I 1ng' .' -, .. ,. il~~, ,j EIV'E'l) o. , NPH[ PU ) ~ ¡ '>--t- \. '. iL; . .. ~ J ¡ 1 . j -. . . .. ' Exhibit G-II ... -.- - . ,........ -14 850 9000 - -~ t ,...... -14800 · ,..... .... .... !? ~ 1>. 1 : ¿ -'4750 ..~ ~.. ... I 8900 , -14100 · "". ., ... -14650 '" -14600 8800 "'~""'" ....... L14~~U· .... ..........c:r I ···f .. ~ .-14snq. 8100 . . h. . II- , .... . .J'~ ... -. ..,.. -14450 '- MD TVDSS (FT) (FT) .2 2000. I- ---- -ILr1--0HiiH---- --I .2 2000.45. .....---TLÕ-õHññ----... SOIt GAP. $OR GAP. 300. I 160. I West Beach Field Type Log ARCa West Beach #4 ') ... . .. .,. . . '. ~... ...... .... -- o. I 110. I . . . .... . . . . . . . ,,\l\~I3>éåch Field Area '. VV~·::~ f;'¡'Structural Cross Section A-A . . 10001 ":ARca ~. ·..·~·..<>I..:. N. :Prudhoe #2 ,. i~oo()1 -6- rr1 >< :T þooio 0- þooio ,... CJ I ¡-\ N .. - ~·860ö· - ~20·0~ . .. . .....;. .:: ..... .: ~84QØt --.""., '·~'H;·:'·<'·· Gas "..:~~% down to -8540' } Kuparuk River Formation ~ Oil down -8950· Gamma Ray Shale ARCa t(HRZ) W Beach #3 ARCa * Beach #4 .... .. ... ~Ww~ . 'ÃI Oil up to -87511 I AK92 081301 tTj tw r;r'J ...... , ~ ~ r;r'J ...... Cfj ...... 2 ~ ...... t:: ~ Q.) ..... n ~ o C/'J C/'J Cfj ~ ~ ....,. ~. o ~ ,,-.. > I > - '-' A02 Reusing Kuparuk Formation Isopach Map ~ ~ ~ ~ r ~ i ~ ; PBU Boundary --------------------------~-------------~ ~ ~ ~ ~ ~ . ~ AK92102023 AOO Reusing ARCa-Exxon 34626 ! ¡ ~ ~ ARCa-Exxon 34627 ~ ~ ~ < ~ --- ~ -~ ^- "--"to. ,~-__-^'V,-" · I Gull Is 3 · · · ARCa-Exxon 34629 ..................~ I . I I ~ ~ ~ ~ , ~ ~ ~ ARCa-Exxon 34628 WB1 , ~ ~ ~ ~ ~ ~ ( ~ ~:!~~fP- ~:;. .~:. \ ":f:.. 7% t!"j >< =-' ÞOO' . 0'" ÞOO' . ~ C) I ~ W ~ Beach Accumulation Gross Kuparuk Isopach West -9300· -91 00· -8900· -8700· -8500· 'Gu//1 .'J ~.GUII~ Exhibi~~~ ¡~~.: ... - i. ··...::..:T _ .L WB4 ..,. -89501 PM4 .:1! P~5 'j - I ---- "';;~ :¡ WB4 ;e- -8751' ':.:..;~>-:. d .,::".~: .;.~~ ; ;"~.'. ''',:;' "..) ",;>' "':'T . "'I · E Not to Scale w· West Beach Fluid Contact Information ä ; ~ c g c 8 f; ... S Top Kupamk Formation Structure Map A RCO-Exxon ARCO-Exxon , 34624 34627 , AK92-102024 Þoo Reusing ARCO-Exxon 34626 ...--. ~ .,,- ARCO-Exxon 34629 ~ , ~ ~ ~ ~ N r~1 ~ ~ " ~ == < F"r'? ¡ ~1 =~ (.t:) (.C ~ Qo Þ c;:. ~ Pc'; g,w o r-"\ .... Ö ª~ CD . r £ (j)- ARCO-Exxon 34628 ~- trj >< ~ ÞOOO'e c:r ÞOOO'e ,... ø I ~ (J1 Kuparuk Structure Beach Accumulation Top of West PT. MCINTYRE :VELOPMENT WELL SCHE~ ·'....IC 5000' DEPARTURE ULTRA SLIMHOLE (3-1 /2" TUBING) j 3 -4 J ....5 J 6 J 7 J J .... 8 ::r 9 lOX X :::: 9 .11 ~ 12 14 o o o o o g 13 o o o o o o :, """"""""'" . ""'" "'" "" ",. """"""""",. """"""""'" ~~~~~~~~~~~~~~~~~~~ 1 5 """""""" """"""" ~""""" . ~"'" 16 Revision Date: 8-20-92 l2 Well Status: Producer or Injector*. Surface Location: DS-P1 or DS-P2. Top of Kuparuk: -10,300' MD/8800' TVD. Minimum 10: 2.75" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 3-1/2", 9.3# 13-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 9-5/8" 47# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7" 29# L-80 PRODUCTION CASING (SURFACE TO -10,000' MD). 7. GAS LIFT MANDRELS (3-1/2" X 1-1/2"). 8. Xo: 7" 29# L-80 TO 7" 29# 1 3-Cr @ -10,000' MD (-100' MD ABOVE PACKER). 9. 3-1/2" PROFILE NIPPLE (2.813" 1.0.). 1 O. 3-1/2" X 7" PERMANENT PACKER @ -10,100' MD. 11. 3-1/2" NO-GO NIPPLE (2.75" I.D) . 12. WIRELlNE REENTRY GUIDE @ -10,200' MD (-100' ABOVE TOP PERFORATION) . 13. KUPARUK PERFORATIONS. 1 4. PBTD @ -10,850' MD. 1 5. 7" 29# 13-Cr PRODUCTION CASING @ -10,900' MD/9300' TVD. 1 6. TOTAL DEPTH @ -10,900' MD/9300' TVD. Exhibit I-I PT. MCINTYRE Dr)ELOPMENT WELL SCHEMA~") 5000' DEPARTURE SLIMHOLE (4-1 /2" TUBINü) j 3 =4 ..... J ....5 J 6 J 7 J J 8 8JE9 10 5<: ><: mm 9 .11 ~ 12 õ o o o o g 13 o o o o o o 14 ~"~~~""""""" ."""""""",'v .,""""""""" .,""""""""" """"""""'" .~~~~~~~~~~~~~~~~~~~ 1 5 """""""" """"""" . """"" . """ 16 Revision Date: 8-20-92 l2 Well Status: Producer or Injector*. Surface Location: DS-Pl or DS-P2. Top of Kuparuk: -10,300' MD/8800' TVD. Minimum 10: 3.725" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-1/2", 12.6# 13-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 10-3/4" 45.5# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7-5/8" 29.7# L-80 PRODUCTION CASING (SURFACE TO -10,000' MD). 7. GAS LIFT MANDRELS (4-1/2" Xl"). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr @ -10,000' MD (-100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" I.D.). 10. 4-1/2" X 7-5/8" PERMANENT PACKER @ -, 0,100' MD. 11. 4-1/2" NO-GO NIPPLE (3.725" I.D). 12. WIRELlNE REENTRY GUIDE @ - 10,200' MD (-100' ABOVE TOP PERFORATION). 13. KUPARUK PERFORATIONS. 14. PBTD @ -10,850' MD. 15. 7-5/8" 29.7# 1 3-Cr PRODUCTION CASING @ -10,900' MD/9300' TVD. 1 6. TOTAL DEPTH @ -10,900' MD/9300' TVD. Exhibit 1-2 PT. MCINTYRF EVELOPMENT WELL SCHE~' TIC 5000· DEPARTURt: CONVENTIONAL (5-1/2" TUBING) j -4 ...... J J 8 J 7 J J ~9 lOX X ::::9 III" ~ 12 14 3 ....5 6 '0 o o o o g 13 o o o o o o :,"""""""~'" . """"""""",. ,""""""""'" """"""""'" ~~~~~~~~~~~~~~~~~~~ 1 5 """""""" """"""" """"" .~"'" 16 Revision Date: 8-20-92 Lz Well Status: Producer or Injector*. Surface Location: DS-P1 or DS-P2. Top of Kuparuk: -10,300' MD/8800' TVD. Minimum 10: 4.455" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 5-1/2" GEN. IV TREE (INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 5-1/2", 1 7# 13-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 13-3/8" 68# L-80, SURFACE CASING @ -3800' MD/3S00' TVD. 6. 9-5/8" 47# L-80 PRODUCTION CASING (SURFACE TO -10,000' MD). 7. GAS LIFT MANDRELS (5-1/2" X 1-1/2"). 8. Xo: 9-5/8" 47# L-80 TO 9-5/8" 47# 13-Cr @ -10,000' MD (-100' MD ABOVE PACKER). 9. 5-1/2" PROFILE NIPPLE (4.562" 1.0.). 1 O. 5-1/2" X 9-5/8" PERMANENT PACKER @ -10,100' MD. 11. 5-1/2" NO-GO NIPPLE (4.455" 1.0) . 1 2. WIRELlNE REENTRY GUIDE @ -10,200' MD (-100' ABOVE TOP PERFORATION) . 13. KUPARUK PERFORATIONS. 1 4. PBTD @ -10,850' MD. 15. 9-5/8" 47# 13-Cr PRODUCTION CASING @ -10,900' MD/9300' TVD. 16. TOTAL DEPTH @ ...., 0,900' MD/9300' TVD. Exhibit 1-3 PT. MCINTYRE -~VELOPMENT WELL SCHEtl·fIC , 2,500' DEPARTURE SLIMHOLE (3-1/2" OR 4-1/2" tUBING)"" ..J 3 4 .... J "'5 J 6 J J7 8 J ;:.:;:;:;:::::::::;:.:;:::::.:~ 9 10 :8: :8: ::::::::::::::::::::::::::::::~ 9 )pøamnnn 1 1 12 13 '&1 ~ ~ ~ 14 0 0 0 0 15 0 0 .2- 16 17 18 Revision Date: 8-20-92 Well Status: Producer or Injector**. lz Surface Location: DS-Pl or DS-P2. Top of Kuparuk: - 16,200' MD/8800' TVD. Minimum 10: 3.725" (No-Go Nipple). * 4-1/2" tubing is shown in schematic. With 3- 1 12" tubing, tail would extend one joint into top of 5-1/2" liner. ** Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-1/2", 1 2.6# 1 3-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 10-3/4" 45.5# L-80, SURFACE CASING @ -4900' MD/4000' TVD. 6. 7-5/8" 29.7# L-80 INTERMEDIATE CASING (SURFACE TO -15,600' MD). 7. GAS LIFT MANDRELS (4-1/2" Xl"). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr@ -15,600' MD (-100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" 1.0.). 1 O. 4- 1/2" X 7-5/8" PERMANENT PACKER @ -15,700' MD. 11. 4-1/2" NO-GO NIPPLE (3.725" 1.0) . 1 2. TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @ -15,800' MD. 13. 5-1/2" x 7-5/8" LINER HANGER WITH TIE-BACK RECEPTACLE @ -1 5,800' MD (-300' MD ABOVE INTERMEDIATE CASING SHOE). 14. 7-5/8" 29.7# 1 3-Cr INTERMEDIATE CASING @ - 1 6,1 00' MD/8700' TVD (100' MD ABOVE TOP KUPARUK) 1 5. KUPARUK PERFORATIONS. 16. PBTD @ -1 7,1 50' MD. 1 7. 5- 1 12" 1 7# 1 3-Cr PRODUCTION LINER @ - 1 7,200' MD/9200' TVD. 18. TOTAL DEPTH @ -17,200' MD/9200' TVD. Exhibit 1-4 PT. MCINTYr" DEVELOPMENT WELL SCH~""- ~ATIC , 2,500' DEPARì LJRE CONVENTIONAL (5-1/2'· TUBING) j 3 4 ~ .J ~5 .J 6 .J 7 .J 8 .J :::::::::::::::::::::::::::/ 9 10 :8: z :.;.:.:.;.:.:.:.:.:.:.:.:.:.:. 9 ~ 11 12 13 ~ ~ ~ ~ 14 0 0 0 0 15 0 0 0 16 17 18 Revision Date: 8-20-92 Well Status: Producer or Injector*. lz Surface Location: DS-P1 or DS-P2. Top of Kuparuk: ....16,200' MD/8800' TVD. Minimum 10: 4.455" (No-Go Nipple). * Schematic shown is for produdng well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 5-1/2" GEN. IV TREE (INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ ....80'. 3. 5-1/2", 17# 1 3-Cr TUBING. 4. SSSV @ ....2000' TVD. s. 13-3/8" 68# L-80 SURFACE CASING @ ....4900' MD/4000' TVD. 6. 9-5/8" 47# L-80 INTERMEDIATE CASING (SURFACE TO .... 15,600' MD). 7. GAS LIFT MANDRELS (5-1/2" X 1 -1 /2"). 8. Xo: 9-5/8" 47# L-80 TO 9-5/8" 47# 1 3-Cr @ .... 15,600' MD (.... 100' MD ABOVE PACKER). 9. 5-1/2" PROFILE NIPPLE (4.562" 1.0.). 1 O. 5-1/2" X 9-5/8" PERMANENT PACKER @....1 5,700' MD. 11. 5-1/2" NO-GO NIPPLE (4.455" 1.0) . 1 2. TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @....1 5,800' MD. 13. 7" x 9-5/8" LINER HANGER WITH TIE-BACK RECEPTACLE @ ....15,800' MD (....300' MD ABOVE INTERMEDIATE CASING SHOE). 14. 9-5/8" 47# 1 3-Cr INTERMEDIATE CASING @ ....16, 100' MD/8700' TVD (100' MD ABOVE TOP KUPARUK) 15. KUPARUK PERFORATIONS. 1 6. PBTD @ .... 1 7,1 SO' MD. 17. 7" 29# 13-Cr PRODUCTION LINER @ ....17,200' MD/9200' NO. 1 8. TOTAL DEPTH @ .... 1 7,200' MD/9200' TVD. Exhibit 1-5 ...J 3 4 ... 7 ..16 aK - :><: =9 _ 10 r 1 I I 12:><1 11 I~ ~ o o o o 14 o o .Q. 15 17 Revision Date: 1 2-1 5-92 P1 -CJ .)PROPOSED COMPLETION ) 7" GAS INJECTION WELL lz ....5 "'13 16 Well Status: Gas Injector. Surface Location: P1-G1. Top of Kuparuk: -8,618' MD/8,468' TVD. Minimum 10: 5.770" (No-Go Nipple). 1. 7" GEN. IV TREE. 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 7", 26# L-80 IPC TUBING. 4. 7" SSSV LANDING NIPPLE (5.963" I.D.) @ -2,000' MDITVD. 5. 13-3/8" 68# L-80 SURFACE CASING @ 3,485' MD. 6. (1) GAS LIFT MANDREL (7" X 1-1 /2") 7. 7" PROFILE NIPPLE (5.770" I.D.). 8. 7" X 9-5/8" PERMANENT PACKER (6.00" BORE) @ -8,330' MD. 9. 5-1/2" PROFILE NIPPLE (4.562" I.D) . 10. 5-1/2" NO-GO NIPPLE (4.455" I.D) . 11. 5-1/2" TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @ 8,432' MD. (TAIL IS PERFORATED BELOW NO-GO NIPPLE). 12. 7" x 9-5/8" LINER HANGER WITH TIE-BACK RECEPTACLE @ 8,432' MD. 13. 9-5/8" 47# L-80 INTERMEDIATE CASING @ 8,607' MD. 14. KUPARUK PERFORATIONS (8,615'- 8,710' MD). 15. PBTD @ 8,750' MD. 16. 7" 26# IPC 13-Cr PRODUCTION LINER (8,432' - 8,840' MD. 17. TOTAL DEPTH @ 8,840' MD/8,677' TVD. Exhibit 1-6 STRADDL.... COMPLETION WELL SCHE~.r\ TIC 5000' DEPARTURE SLIMHOLE (4-1/2" TUBING) j 3 4 ~ .J .J .J .J .J Well Status: Injector lz Surface Location: DS-Pl or DS-P2 Top of Kuparuk: - 1 0,300'MD/8800' TVD Minimum 10: 3.725" (No-Go Nipple). 1. 4-1/2" GEN. IV TREE. 2. 20" H-90 CONDUCTOR CASING @ -80'. .... 5 3. 4-1/2", 12.6# L-80 TUBING. 4. SSSV @ -2000' TVD. 6 5. 10-3/4" 45# L-80 SURFACE CASING @ -3,800' MD/3500' TVD. 7 .............. 8 .;...........:...:... 9X x 10 :::::::::::::::::::\.J J 11 131 1 ~'2 ~14 >< X 15 1 6 ::::: !!IS!!IIEm 17 J .18 o o g 19 o Revision Date: 1 2-22-92 6. 7-5/8" 29.7# L-80 PRODUCTION CASING (SURFACE TO -10,000' MD). 7. GAS LIFT MANDRELS (4-1/2" Xl"). 8. 4-1/2" PROFILE NIPPLE (3.813" 1.0.). 9. 4-1/2" X 7-5/8" CR PERMANENT PACKER @ - 10,000' MD. 10. 4-1/2" PROFILE NIPPLE (3.813" I.D) . 11. 2 - 4-1/2" Xl" GLM. 1 2. STUMP ISLAND SANDSTONE PERFORATIONS. 13. 4-1/2" BLAST RINGS. 14. 4-1/2" xl" GLMs. 1 5. 4-1/2" X 7-5/8" CR PERMANENT PACKER @ - 10,200' MD 16. 4-1/2" PROFILE NIPPLE (3.813" 1.0) . 1 7. 4-1/2" NO-GO NIPPLE (3.725" 1.0) . 18. 4-1/2" WIRELlNE RE-ENTRY GUIDE (100' ABOVE TOP PERFORATION). 19. KUPARUK PERFORATIONS. Exhibit 1-7 WEST BEACH DF'·-~LOPMENT WELL SCHEMAT ) , 0,000' DEPARTURE LJL TRA SLIMHOLE (3-1/2" TUBING) j 3 -4 l2 J ....5 J 6 J 7 J J ... 8 Ei9 10:X: ~ !![9 .11 ~ 12 14 õ' o o o o g 13 o o o o o o :""""""""", .,""""""""" .""""""""", """"""""'" ~~~~~~~~~~~~~~~~~~~ 1 5 """""""" ',"",""',' """"'" . """ 16 Revision Date: 8-24-92 Figure 1 Well Status: Producer or Injector·. Surface Location: West Beach Pad. Top of Kuparuk: - 13,900' MD/8800' TVD. Minimum ID: 2.75" (NcrGo Nipple). · Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 3-1/2", 9.3# 1 3-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 9-5/8" 47# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7" 29# L-80 PRODUCTION CASING (SURFACE TO - 13,600' MD). 7. GAS LIFT MANDRELS (3-1/2" X 1-1/2"). 8. XO: 7" 29# L-80 TO 7" 29# 1 3-Cr @ - 13,600' MD (- 100' MD ABOVE PACKER). 9. 3-1/2" PROFILE NIPPLE (2.813" 1.0.). 1 O. 3- 1/2" X 7" PERMANENT PACKER @ - 1 3,700' MD. 11. 3-1/2" NO-GO NIPPLE (2.75" 1.0). 12. WIRELlNE REENTRY GUIDE @ -13,800' MD (- 100' ABOVE TOP PERFORATION) . 13. KUPARUK PERFORATIONS. 14. PBTD @ - 14,650' MD. 1 5. 7" 29# 1 3-Cr PRODUCTION CASING @ - 14,700' MD/9300' TVD. 1 6. TOTAL DEPTH @ - 14,700' MD/9300' TVD. Exhibit 1-8 WEST BEACH ~VELOPMENT WELL SCHEtJ . TIC 10,000' DEPARfURE SLIMHOLE (4-1/2" TUbiNG) j 3 -4 J ....5 J 6 J 7 J J .... 8 !!!9 lOX X J]]9 .11 ~ 12 14 ~ o o o o g 13 o o o o o o :""""""""", ., """",....", """ . ,.... ,........, ""........",...., , " """""...."""" ~~~~~~~~~~~~~~~~~~~ 1 5 """",........"", ........"""...."", ",...."....", . ",....,.... 16 Revision Date: 8-24-92 Figure 2 l2 Well Status: Producer or Injector*. Surface Location: West Beach Pad. Top of Kuparuk: -13,900' MD/8800' TVD. Minimum 10: 3.725" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ .....80'. 3. 4-1/2", 12.6# 13-Cr TUBING. 4. SSSV @ .....2000' TVD. 5. 10-3/4" 45.5# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7-5/8" 29.7# L-80 PRODUCTION CASING (SURFACE TO -13,600' MD). 7. GAS LIFT MANDRELS (4-1/2" Xl"). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr @ .....13,600' MD (.....100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" 1.0.). 10. 4-1/2" X 7-5/8" PERMANENT PACKER @ ...13,700' MD. 11. 4-1/2" NO-GO NIPPLE (3.725" 1.0) . 1 2. WIRELlNE REENTRY GUIDE @ .....13,800' MD (...100' ABOVE TOP PERFORATION). 13. KUPARUK PERFORATIONS. 14. PBTD @ ...14,650' MD. 15. 7-5/8" 29.7# 13-Cr PRODUCTION CASING @ ...14,700' MD/9300' TVD. 16. TOTAL DEPTH @ ...1 4,700' MD/9300' TVD. Exhibit 1-9 WEST BEAC~' lEVELOPMENT WELL SCHE' }TIC 1 2,500' DEPARTURE :)LIMHOLE (3-1/2" OR 4-1/2.··· TUBING)* j 3 4 ~ J "'5 J 6 J .J7 .J 8 ~:.:.:~".:.:.:.:.:.:.:.:.:. 9 ¡¡........................ 10 :8: :8: ~:::::::~:::::::::::;:::::/ 9 ~ 11 12 13 ~ ~ ~ ~ 14 0 0 0 0 15 0 0 .Q. 16 17 18 Revision Date: 8-24-92 Figure 3 Well Status: Producer or Injector**. lz Surface Location: West Beach Pad. Top of Kuparuk: -16,200' MD/8800' TVD. Minimum 10: 3.725" (No-Go Nipple). * 4-1/2" tubing is shown in schematic. With 3-1/2" tubing, tail would extend one joint into top of 5-1 /2" liner. ** Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-1/2", 12.6# 1 3-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 10-3/4" 45.5# L-80, SURFACE CASING @ -4900' MD/4000' TVD. 6. 7-5/8" 29.7# L-80 INTERMEDIATE CASING (SURFACE TO -15,600' MD). 7. GAS LIFT MANDRELS (4-1/2" X 1 "). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr @ -15,600' MD (-100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" 1.0.). 10. 4-1/2" X 7-5/8" PERMANENT PACKER @ -15,700' MD. 11. 4-1/2" NO-GO NIPPLE (3.725" I.D). 12. TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @ -15,800' MD. 13. 5-1/2" x 7-5/8" LINER HANGER WITH TIE-BACK RECEPTACLE @ -1 5,800' MD (-300' MD ABOVE INTERMEDIATE CASING SHOE). 14. 7-5/8" 29.7# 13-Cr INTERMEDIATE CASING @ -16,100' MD/8700' TVD (100' MD ABOVE TOP KUPARUK) 15. KUPARUK PERFORATIONS. 1 6. PBTD @ -1 7,1 50' MD. 17. 5-1/2" 17# 13-Cr PRODUCTION LINER @ -17,200' MD/9200' TVD. 18. TOTAL DEPTH @ -17,200' MD/9200' TVD. Exhibit 1-10 j T5 Marker > T3 Mark~~ x \. Pt. McIntyre Cuttings Disposal Well Schematic 3 5 ,,,. .... - X6 7~ , 8 , / 10 4 . 9 Lz 1. 4-1/2" GEN. IV TREE 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-1/2" L-80 TUBING. 4. 7-5/8" L-80 INTERMEDIATE CASING. 5. Sliding Sleeve/Ported Nipple. 6. 4-1/2" X 7-5/8" CR PERMANENT PACKER. 7. 4-1/2" PROFILE NIPPLE (3.813" 1.0) . 8. 4-1/2" WIRELlNE RE-ENTRY GUIDE 9. 100' OPEN-HOLE 10. TO Exhibit 1-11 ') ) Exhibit J-l Beaufort Sea Source Water Analysis Determina tion Summer Winter Units Specific Gravity 1.013 1.024 pH 7.5 7.8 Mg/L Calcium 196. 365. Mg/L Magnesium 631. 1190. Mg/L Sodium & Potassium 5680. 10400. Mg/L Strontium O. O. Mg/L Barium O. O. Mg/L Iron O. O. Mg/L Bicarbonate 85. 142. Mg/L Carbon Dioxide Calc. O. O. Mg/L Total Dissolved Solids 17852. 32787. Mg/L Hydrogen Sulfide O. O. Mg/L Resistivity @ 700P 0.422 0.255 Ohms Chloride 9880. 18200. Mg/L Sulfate 1380. 2490. Mg/L Suspended Solids 6.0 1.0 Mg/L R.."· ['" f'"' Ii"'" "II ' (' r t" ~ Ii! ç' f\ ':' ~~. ~ ~ ~ ¡~;r.:: r{..,;.t APR - 1 1993 Alaska Oil & G"'" r> ' dò::l ""ons, LUlIiiinSS¡C" ,Anchoraae ,I Exhibit J-1 Exhibit J-2 Lisburne Produced Water Analysis Determina tion Value Units pH 8.5 Mg/L Calcium 105. Mg/L Magnesi urn 50. Mg/L Sodium(ca1c} 10555. Mg/L Sodium (AA) 13875. Mg/L Strontium 3.8 Mg/L Barium 1.1 Mg/L Iron 1.1 Mg/L Hydroxyl o. Mg/L Carbonate 228. Mg/L Bicarbonate 2618. Mg/L Chloride 14261. Mg/L Sulfate 750. Mg/L Total Dissolved Solids 28753 Mg/L Exhibit J-2 } Exhibit J-3 ') Pt. McIntyre Produced Water Analysis Determina tion pH Calcium Magnesium Sodium Potassium Strontium Barium Iron Hydroxyl Carbonate Bicarbonate Resistivity @ 68°P Chloride Silicon Value 7.2 24. 9. 8540. 179. 7. 11.0 1.4 O. O. 3262. 0.373 10597. 24. Exhibit J-3 Units Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Ohms Mg/L Mg/L Exhibit J-4 Injected/Produced Gas Stream Analysis Component Lisburne Pt. McIntyre West Beach Mole % Mole % Mole % Hydrogen Sulfide 0.01 * 0.00 0.00 Carbon Dioxide 13.27 5.92 9.88 Nitrogen 0.72 0.51 0.52 Methane 77.74 81.48 75.90 Ethane 5.23 7.59 7.08 Propane 2.27 3.02 3.10 I-Butane 0.31 0.34 0.58 N-Butane 0.40 0.67 0.93 I-Pentane 0.03 0.13 0.22 N-Pentane 0.03 0.15 0.24 Hexane 0.00 0.09 1.56* Heptane+ 0.00 0.11 Sample date: 3Q 1992 2Q 1989 3Q 1991 * 94 PMM H2S *C6+ The Lisburne composition represents the current injection gas stream. The Pt. McIntyre and West Beach compositions represented produced gas streams. Exhibit J-4 ) ) Expanded Eastern Operating Area ~- I I I .....-----"....---...-- I I I I I t \ I I t I , I I , I I , I I I I I I I I I I I \ I I , I I 1 , , I I I I \ I \ t I I I WOA 1 EOA I I I \ I I I I I I , I I I I I I 1 I I I I I I I 1 I I I I t I I I I I --------~ I I I r I 1_- __ _______ __ __ ___ __. _-¡ I I I I I J ~ PeriN Mcintyre h PnIIihH B'!I! __ __ __ . ________________J_____________________________ : I I I ~ 1----------------------1 0 I , I , I I ,-, I , I --I '-. ~-, ~ , --I '--I '1 r... B.CJDh, q .. .. 1___. I ----I '--1 c::::3 ¡ a f ,-------- \ I I I I I I I I I I I I I / I I I \ I I I -------- I I I I I t I 1 I I I I I , .-------, ----------------------- ---------------------------------- Exhibit N-l Exhibit N-2 Documentation of Equations Used to Calculate Formation Water Salinities From Well Logs 1. Formation Temperature: Tfrn = 0.0222 (Depth fm - Depth base of permafrost) +32°F 2. Porosity from Density Log: 0d = Dma - Db; Dma = 2.65, Of = 1.0 Dma - Of 3. Porosity from Sonic Log: 0s = 0.625 (dt - 55) dt 4. Apparent Formation Water Resistivity: Rwa = 02.15 x Rt 0.62 5. Water Resistivity @ 75°F: Rw @ 75 = Rwa Tfm + 6.77 81. 77 6. TDS (NaCI equivalents) = (3.562 - Log (Rw @ 75 - 0.0123» 10 0.955 Step 1) Determine formation temperature. 2) Determine porosity from either the sonic or density logs. 3) Calculate apparent formation water resistivity by using: F = 0.62 02.15 Humble equation for unconsolidated rocks Rt = True resistivity of 100% water saturated formation 4) Convert to water resistivity at 75°F. (Schlumberger equation) 5) Calculate TDS in ppm. (Dresser Atlas equation) Exhibit N-2 TO: )fp_ .T_ P_ M,.n,,,,.,,,, .T",~ p n_Rfty ,,,,q, n&ll&a, T.Y·f ) Marti n Wallr LaÞoratarill. Inc ) Tertiary /Upper Cretaceous Water Analysis '-Aeo-ATO.V"'O. 117R1gR 'A....'-C .acalvao 11-?1-7R .~'UL.TI "._O.Tao 1 ?-C;-7R "t W. .NDIAN& IIIIIDP.AND. 1'DM ,,'JOt ....... ........ .. & ".0.10.'.'. 11I0........... TQA. ,.,.. PMO..' ...,.,... ".'0.0 COM~A"''' WI CL.O 0" "OOL. 'eCTION _ ...OCt( _ I",..vav sou..ce 0' SA....'-C AHO DATa TAKaN: p.W water-taken fraœ Sohio water well IGC-3C @ 11:15 am. 11-4-78 (pr...ura cY~d. NO. 1 Raw water-taken fro. Sonio watar well IGC-3C @ 10:20 aœ. 11-4-78 (p1aat1c bottle) NO.2 ,.aual mixture of Sohia watar well 'GC-3C takan 11-4-78& Sahio water well IGC-3B NO.1 taken 8-20-78 (oreslur. cylinders). NO.. "KMARICI. CrecaceouI CM~ICA" AND ~V'ICA'" JlRO~."T'U NO. , NO. I ,.n1'" l.n'nn AP1."pi~_ai,."'i_1A r~~.~ '- CA'& P~tt4'hn. 'R2V w. ,.",1' ru"',t COUNTV STATe hMlflc Grew.ty u fill ~. .... -..... s.... .... __ 1Iteat.. .'carMft.. .. Þ<Ot SU..,......... .. c::.c:o, u.............. .. c.c:os T... .......... AI c.cow Calc I "'" .. c:. ........,'"" .. .... s..h"" MIll. --.....-- $wI fa. .. so. OIOf'I~.. <:1 I raft .. II. B.,."", .. I. T"rti4U ty. II..... c:... .. lit Tota' Sefl... Ca'.I_" T~retII... .~. c:..r.- QI..i". CaICy..- 01........ 0.,.... Wiftlll_ ~"'I" h''''. JIt"..Þ,"". .....,... .. 7'- ~. SU........ 01. Piln." s..ift .. ...". V.'Wfte II. I~o III' NO.1 '.0"9 MO. 6 Carbon Diox1de. Titrated *Total Carboa Diox1de. Gravimetric Strond.ua. as Sr 7.n7 7.17 6.76 464 464 1.7~7 I§ 14 n I§.~nn I§...nn '.7M 9..n 99n 69n 7"g 7'~ 4Rn 1-;.414 '''.'''7 1 t, "44 0 0 '4 27.520 27.697 , go. AR" 6. , C;.9 , ~ , lR' "7 7R 1 " "tt,1nQ 1..-; , ,.'·n 1',- 7t;~ 74 1§7 I§'" &:î73 0.0 0.0 0.171 0.22.6 0 5.0 19.1 11.9 520 910 488 44 993 53 53 ........ ~ ~ ""I~ ~ &.i_ ...u,....- 0...-....__ ~ ___ ~..... .... J I, Exhibit M-l Exhibit N-3 Prudhoe Bay Field Pt. McIntyre Pool Calculated Wireline Salinities Interval Well Subsea Depth Calcula ted TDS (ppm) T-8 P2-49 (-3,850) 19,469 T-5 P2-49 ( -4,279) 13,935 PM -08 (-4,153) 17,047 T-3 P2-49 (-4,690) 14,726 PM -08 (-4,503) 17,604 Ugnu P2-49 (-6,834) 19,773 PM -08 (-4,931) 21,900 W.Sak P2-49 (-7,114) 10,402 PM-08 ( -6,630) 20,418 Kuparuk P2-49 (-9,119) 20,000 PM-08 (-9,290) 17,000 .I'ì' :1 .,. I' 8;~ Exhibit N-3 Martin Wafer Laboratories. Inc Tertiary /Upper Cretaceous Water Analysis ..o:;.:.":AN,~.,O' "'A.O"ATO." NO. 11 1A1QA (/'~,.,,......, SAM"~& lIteC&Iveo 11.".7A lit ESU'" TS 1It.~O.T.t' 1'_"_7. .." ) . ~ .. A ".0.80_'... ..OMA....... TaAa .,..,.. ,...ON8 ..a·'IM.. ....0.. TO: ~.. .T.. P.. M"-I}gQa'''.. .Tr. p..n,Rnw 'A14.. n.".c.. T.y~. ) COM.-ANY ...4W"....,..-R4,..h'''-1tf r~~.'\Y ....AIC P"'ttU,n. RJ\Y t.lJU·.~'1nntl "I.&.O 0- "001. S.CTI0H_ ....OCÞC_ SU"".v· COUNTY STATe SOUIltCC 0" IAMIIt\.& AND O.T. TAK&N: NO.1 Raw va",,:p-"~.ft f"l'''''' ~nhi" va,..", ,.,.11 Ir-(;-1n (I 1\:l\nn",.. 11-5-7,:1 (Pr-IIIII¡IIu.,.-, t"v1ift"er) Raw water-cakaQ fro- Sobia vatar vel' ICC-3D @ S:30om. 11-5-78 (ølaat1~ bottle) NO. Z !;:: m:t.xt:ura of SoMo .tar well IGC-3D takeD 11-5-78 , Sohl0 water weU 'GC-3B NO.1 t 8-20-18 (pre..ura cyl1Adara). NO. . ".""1'1(.. CN_ICA&. AND IIMY.ICAI. ,...O.....T'.. NO.t NO.1 1.0291 1..0'86 0.0 o ."8~ o 4.3 490 l~· 1..039 7' 73 ....... -..... ~ ...11I..... ... '-'. ~1C1"'" 0...-..,............... * 1.'h1a includ.. bot'h .'p~~h01' _~L1 oyof t1e that. u e.iact II,. u bicarbo!l.&t... s.c.". ~.~ .. fII" II~ JH -- s....... '" ..... Race¡... Ilr ..,...,- .. HCOt s..,.....,..... .. c:.co. ~....- .. CaCOI T... t Wi" I'. .. CaCOI Ca........ .. Ca ,.........". .. .... ,.."'" ..,,¡., ~....... Su'''. .. so. Q'er¡4. .. CI I,. u fl. .....'" .. .. T".-..u&y. .1..... Co.. .. tit "0" Seh4.. <:a....... T........cw.I ..., c:.... 0'..,4IC. c:.tc"t... 01....". 0.".... ....II'er Hydro... I"If'. "....uv,c,r. .....,... .. ,.,. .., s......... 011 "11ft.'. Set.... .. ....,. v....... ,. I..... "'I CarbOll Dioxide. Titratad *total CaZ'b91l Dio9'ftle.. Gr.v1_tric , StP01ld.ua... u S" T~~~.p ~f P.~~~ft~·~i~ .~p.~9.d- II.,. ..... I 7 II. 16 7.n' 195 176 l' ~ 6.ACl~ I\.,;nn l..lt,n 1,l\nn ~I\O ,;" t'..99" 1'..9'~ n n '''..?77 '" ,) '1.. 9.1 9.' ,,,, '41\ 4 A "'_92n "',~lill; 25 34 0.0 o .1 86 25.8 910 NO.1 t.n", NO.. "..74 t _"'11; An '_Qnn 1 J'f\.n "·n 11_~7p " 1Q~"'n '..' g? , 1" ..øqn. S¡3 0.0 O. , ~9 l8.. 465 ~ ~iO~{~' and ~hl t"~rhftft I Exhibit M-2 I" I ",,'-. .ø~c:·i-. ...........__~_~ ~ , ., ".. "..' ~ ,,, . - ........ W., 11A C. Ma~tiA. K. A. ., ARCO Alaska, Inc. ) Post Office Box 100360 Anchorage Alaska 99510-0360 Telephone 907 2761215 ) ....,~,....';\i.~'.,~~. -~l~ ~ R ENG~·- -----._..__ I 3R ENG--···--- .---.----._____.. I ~~~__~~Sf--·-r· ENG ASS't"··_- SR GEOC----L ----__._._...., '. I G ~Q.!=__~~'Sfr C?_~2~_,.~~ S'l=r :;TAT TÈë':'{j .,tr AT -t·ECH( :"fE ~ -:.::-.~~._...".,.... . i A,IO '-f A ) February 24, 1993 ORIGINlL Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Draft Application for Modification to Area Injection Order No.4 Dear Mr. Johnston: Enclosed is a draft application by ARCO Alaska, Inc. (AAI) to modify the Area Injection Order No.4 for the Prudhoe Bay Unit EOA. This draft application requests that the existing area injection order be modified to include current and future injection wells, as described in the application, that will be utilized in support of production and development of the Point Mcintyre and West Beach Participating Areas (PA). Some existing Lisburne injection wells, covered under the existing area injection order, will be utilized for Point Mcintyre and West Beach development in addition to future wells that will be developed specifically for those PAs. This draft application is being submitted for your review and comment prior to AAI submitting a formal application in accordance with our discussions at a meeting in your office on January 14, 1993. ) In the application AAI requests injection approval for three types of injection wells - fluid disposal, enhanced recovery, and muds & cuttings disposal. In addition to the injection zones covered in the original order, AAI proposes in this application to include the Pt. Mcintyre Oil Pool (the Kalubik and Kuparuk Formations) and the Stump Island Oil Pool (the Seabee Formation) from the Pt. Mcintyre PA and the West Beach Oil Pool (the Kuparuk Formation) from the West Beach PA. AAI proposes that we meet with you and your staff to discuss the contents of this draft application in greater detail. We will contact you in the near future to make arrangements for this meeting. Should you have any questions or need additional information please feel free to contact me at (907) 263-4678 or George Phillips at 263-4280. 9l.ncer Iy, ~ ~ William M. Fowl Senior Permit 00 inator Prudhoe Bay l Lisburne Attachment cc: W. J. Pish, Exxon Company, U.S.A., Houston W. D. Morgan, Exxon Company, U.S.A., Houston S. M. Bennett, BP Exploration (Alaska), Inc. A. W. Janes, BP Exploration (Alaska), Inc. A. G. M. Oba, ARCO Alaska, Inc. A. D. S6mon, ARCO Alaska, inc. RE€EiV~D ) FEB ~ 4 1993 Alaska Oil & Gas Cons. commission Anchorage ARea Alaska, Inc. is a Subsidiary of Atlantic Richfield Company ·,.~ '.. . ) ) ) Application for an Amendment to Area Injection Order No.4 20 AAC 25.460 20 AAC 25.252 20 AAC 25.402 ) REEEiVED FES 2 4 1993 Alaska .OH& Gas Cons. CommissiO.íl Anchorage ~J February 22, 1993 ) ') SECTION A ) Application for an Amendment to Area Injection Order No.4 20 AAC 25.460 20 AAC 25.252 20 AAC 25.402 ARCO Alaska, Inc., in its capacity as a Working Interest Owner (WIO), and the Operator of the Prudhoe Bay Unit, Eastern Operating Area (EOA), hereby applies for an amendment to the existing Area Injection Order No.4, issued July 11, 1986. This application follows the same general format and exhibit numbering as found in the original application and covers proposed and existing injection operations in the Lisburne Participating Area (PA) and the planned Pt. McIntyre PA and West Beach PA. Exhibit A-I details the area to be included in the Pt. McIntyre P A. Exhibit A-2 details the area to be included in the West Beach P A. The legal descriptions of the planned Pt. McIntyre and West Beach PAs are listed in Exhibits A-3 and A-4. The Pt. McIntyre P A will include two oil pools, the Pt. McIntyre Oil Pool (the Kalubik and Kuparuk Formations) and the Stump Island Oil Pool (the Seabee Formation). The West Beach P A will include the West Beach Oil Pool (the Kuparuk Formation). ) Pt. McIntyre The current Pt. McIntyre development plan includes a combination of processed gas reinjection into the Pt. McIntyre Pool and pattern waterflooding for pressure maintenance into the Pt. McIntyre and potentially the Stump IslandPooI. Gas reinjection capabilities will be in place concurrent with field start-up, while waterflood capabilities should be in place by the fall of 1994. The planned development well program currently consists of up to 93 total wells on an average well spacing of 80 acres: approximately 75 producers, 16 water injectors, and 2 gas injectors. The field will initially be drilled on 160-acre well spacing. This will provide additional reservoir description data and some production history, which will enable the WIGs to optimize placement of the 80-acre infill wells. The 80-acre wells will help sustain production capacity and enhance recovery by improving volumetric sweep efficiency. The initial waterflood pattern for the Pt. McIntyre Pool will be an inverted 9-spot utilizing source water from the Prudhoe Bay Seawater Treatment Plant. This pattern selection provides maximum flexibility for '~ ,I 1 '\ .1 ) future potential conversions to other pattern configurations as changes in reservoir description and/or performance dictate. Depending on reservoir description and performance, select areas may require more dense well spacing than 80 acres to maximize recovery. For example, in select areas of the reservoir, faulting may dictate tighter well spacing in order to recover bypassed oil. For these reasons, certain areas of the reservoir could potentially be developed using 40-acre well spacing for depletion optimization purposes. ) Oil within the Stump Island Pool is stratigraphically trapped in discontinuous bodies of sandstone. Due to the discontinuous nature of these sandstones, their development will be evaluated on a well-by-well basis in conjunction with development of the Pt. McIntyre Pool. A dedicated drill cuttings disposal well (UIC Class II-D), completed in the Tertiary/Upper Cretaceous interval, is also planned at Pt. McIntyre Drill Site P2. The injection well will be used for injection of slurried drill cuttings, drilling mud, and well completion fluids and other exempt fluids. The initial average daily injection rate will be 1,000 BPD. This rate is based on a single drilling rig operating in the Pt. McIntyre field. The production stream from Pt. McIntyre will be processed at the Lisburne Production Center (LPC). Gas volumes equivalent to the volumes produced from Pt. McIntyre, less fuel gas, flare gas, and NGL shrinkage, are planned to be reinjected into the Pt. McIntyre gas cap. Initially, the produced water will be disposed of into the Tertiary/Upper Cretaceous via LPC Class II-D wells. When sufficient volumes of produced water are available at the LPC to replace the Pt. McIntyre void age, the produced water may be reinjected into the oil column of Pt. McIntyre. ) West Beach Only two wells, West Beach Nos. 3B and 4, have penetrated this reservoir. Neither well encountered a fluid contact; therefore, the original oil in place (OOIP) is uncertain. The ultimate development plan for the West Beach accumulation is also uncertain. To assess the economic viability of long-term development strategies, the immediate development plans for West Beach are to begin producing West Beach No.4 as early as the spring of 1993. Pressure monitoring after producing West Beach No.4 will allow the WIOs to design a development plan for long-tenn depletion. Oil in place estimates will also be refined with production data. An additional West Beach well is planned for late 1993, or early 1994 if the estimated reservoir size is sufficiently large. Beyond initial production of \Vest Beach No.4, one of three strategies for long-term depletion will be implemented: solution gas drive, processed gas injection, and/or waterflood. If technically and ) 2 ) ) economically feasible, gas injection and/or waterflood could be implemented as early as 1995. The actual ) depletion plan will be dependent upon the size of the reservoir. The production stream from West Beach will be processed at the LPC. Due to the uncertainty associated with the West Beach development, at least initially the gas stream will be reinjected into the Lisburne and/or Pt. McIntyre gas caps and the produced water will be disposed of into the Tertiary/Upper Cretaceous. Lis burne Production streams from the West Beach, Pt. McIntyre, and Lisburne PAs will be commingled at the LPC. No facility modifications to the LPC are planned specifically to accommodate West Beach production. However, facility modifications are planned to accommodate Pt. McIntyre production. These modifications focus on liquid handling and produced water injection/handling expansions. ) The LPC was originally built to process a nominal oil rate of 100 MBOPD, a gas rate of 440 MMSCFPD, and a produced water rate of 25 MBWPD. With the planned modifications, the LPC will be expected to process 135 MBOPD and 200 MBWPD. No modifications are planned at this time for the LPC gas handling system. Currently, gas reinjection compression capacity is 460 MMSCFPD, based on a yearly average. The commingling of production fluids from the Lisburne, Pt. McIntyre, and West Beach PAs at the LPC will create a need to inject into existing Tertiary /Upper Cretaceous Injector LPC-Q1 at increased rates and may generate the need for up to two additional produced water injectors. The additional Tertiary/Upper Cretaceous injectors will be drilled from the LPC or connected Lisburne drill site facilities. Further, commingling will cause the reinjection of a mixed processed gas stream into the Lisburne and Pt. McIntyre Pool gas caps and potentially the West Beach Pool gas cap. ,) 3 ) ) } ) ) SECTION B Plat 20 AAC 25.402(c)(1) 20 AAC 25.252(c)(1) Exhibit B-1 is a plat showing the location of all existing wells that penetrate the uppermost injection zone within the Pt. McIntyre P A as of February 1, 1993. Exhibit B-2 is a plat showing the location of all wells that penetrate the uppermost injection zone within the West Beach P A. Exhibit B-3 is a plat of all the potential bottom-hole locations of future Pt. McIntyre producers/injectors. At this time, all the specific wells which will become injectors have not been selected. Current proposed injectors are included in the plat shown in Exhibit B-3. Specific approvals will be obtained pursuant to 20 AAC 25.507, or any applicable successor regulation. 5 ) ,) SECTION C } Operators/ Surface Owners 20 AAC 25.402(c)(2) 20 AAC 25.252(c)(2) The Pt. McIntyre PA and West Beach PA will be operated by ARCO Alaska, Inc. The Surface Owners within the Pt. Mcintyre PA and West Beach PA are listed in the following tables. The Native Allotment Landowners are listed by allotment parcel. Exhibit C-1 is an areal map of the parcels. Surface Owners ParcellS State of Alaska Department of Natural Resources A ttn: P.O. Box 7034 Anchorage, AI< 99510 Lawrence Ahmaogak P.O. Box 411 Barrow, AI< 99723 ) Parcel 18 Parcel 16 Barbara Ahrnaogak 1628 Hilton Ave. Fairbanks, AI< 99701 John Nicholls (minor) c/o Ely Varner (guardian) P.O. Box 473 Barrow, AI< 99723 Parcel 17 Lawrence Ahmaogak P.O. Box 411 Barrow, AI< 99723 Alice Glenn 899 Blair Ave. Sunnydale, CA 94087 George Ahmaogak P.O. Box 338 Barrow, AI< 99723 ), I'· 7 ) } SECTION D ) Affidavit 20 AAC 25.402(c)(3) 20 AAC 25.252(c)(3) Exhibit D-l is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area included in the Pt. McIntyre and West Beach PAs have been provided a copy of the amended Area Injection Order No.4. ') \ ~, 9 ) ) SECTION E ) Description of Operation 20 AAC 25.402(c)(4) Future injection operations for Pt. Mcintyre are divided into two broad categories: Subsection 1 - Enhanced Recovery, and Subsection 2 - Disposal of Gass II Fluids. Subsection 1 Enhanced Recovery Enhanced recovery injection wells are used for the introduction of additional fluids into the reservoir to ) increase the ultimate recovery of oil. Two types of enhanced recovery injection wells are planned for Pt. McIntyre: water injection and gas injection. Gas reinjection capabilities for the Pt. McIntyre Pool will be in place concurrent with field start-up, while waterflood capabilities for the Pt. McIntyre and/or Seabee Pools should be in place by the fall of 1994. The planned development well program currently consists of up to 93 total wells on an average well spacing of SO acres: approximately 75 producers, 16 water injectors, and up to 2 gas injectors. The field will initially be drilled on 160-acre well spacing. This will provide additional reservoir description data and some production history, which will enable the WIOs to optimize placement of the SO-acre infill wells. The SO-acre wells will help sustain production capacity and enhance recovery by improving volumetric sweep efficiency. The initial waterflood pattern for the Pt. McIntyre Pool will be an inverted 9-spot utilizing source water from the Prudhoe Bay Seawater Treatment Plant. This pattern selection provides maximum flexibility for future potential conversions to other pattern configurations as changes in reservoir description and/or performance dictate. Depending on reservoir description and performance, select areas may require more dense well spacing than 80 acres to maximize recovery. For example, in select areas of the reservoir, faulting may dictate tighter well spacing in order to recover bypassed oil. For these reasons, certain areas of the reservoir could potentially be developed using 40-acre well spacing for depletion optimization purposes. 11 ) ) Because the oil within the Stump Island Pool is stratigraphically trapped in discontinuous bodies of sandstone, their development, with respect to enhanced recovery, will be evaluated on a well-by-well basis in conjunction with development of the Pt. McIntyre Pool. -) The potential for water injection and gas injection in the West Beach also exists. The development plan for the West Beach accumulation is uncertain. To assess the economic viability of long-tenn development strategies, the immediate development plans for West Beach are to begin producing West Beach No.4 in the spring of 1993. Pressure monitoring after producing West Beach No.4 will allow the WIOs to design a development plan for long-term depletion. With production data, we will be able to refine our oil in place estimates. An additional West Beach well is planned for late 1993, or early 1994 if the estimated reservoir size is sufficiently large. Beyond initial production of West Beach No.4, one of three strategies for long-term depletion will be implemented: solution gas drive, processed gas injection, and/or waterflood. If technically and economically feasible, gas injection and/or waterflood could be implemented as early as 1995. The actual depletion plan will be dependent on size of the reservoir. Additional methods of enhanced oil recovery may be used in the future in both the West Beach and Pt. McIntyre. Injection wells will continue to be designed, constructed, operated, and monitored to ensure the injection fluid is entering the oil pool. ) Subsection 2 Fluid Disposal Disposal wells will be used for the disposal of produced water and other exempt fluids generated during operations. The Pt. McIntyre and West Beach produced water is water which is produced from the Pt. McIntyre and Seabee or West Beach Pools with the oil and separated from the oil and gas at the LPC. The remaining injection fluids are exempt fluids generated by drilling and production operations. Injection will be into the Tertiary/Upper Cretaceous interval, as defined in existing Area Injection Order No.4. The LPC currently has a single fluid disposal well, LPC-Ol. Additional fluid disposal wells in the vicinity of the LPC or connected Lisburne drill site facilities are anticipated. In addition, an exempt fluids disposal well is planned at Pt. Mcintyre Drill Site P2 to be used primarily for the disposal of slurried drill cuttings, drilling mud, and well completion fluids along with other exempt fluids. The injection interval will again be the Tertiary/Upper Cretaceous. Future fluid disposal wells will continue to be designed, -) 12 ) ) constructed, operated, and monitored to ensure the injection fluid is entering into and remaining in the injection zone. ') ) 13 , > ) ) SECTION F » Pool Information 20 AAC 25.402(c)(5) The Pt. McIntyre P A will include two oil pools: the Pt. McIntyre Oil Pool (the Kalubik and Kuparuk Formations) and the Stump Island Oil Pool (the Seabee Formation). The primary strata, the Kuparuk, targeted for enhanced recovery within the Pt. McIntyre P A by injection, are defined in the field rules as the strata that are common to and correlate with the accumulation found in the Pt. McIntyre No. 11 well between the depths of 8,650' and 9,366' subsea (55) [9,908' and 10,665' measured depth (MD)]. The Seabee, a secondary set of strata which may also be targeted for enhanced recovery within the Pt. McIntyre P A by injection, is defined as the strata that are common to and correlate with the accumulation found in the Pt. McIntyre No.3 well between the depths of 8,200' and 8,370' 55 (8,759' and 8,930' MD). The strata targeted by potential injection for enhanced recovery from the West Beach P A are defined in the field rules as the strata that are common to and correlate with the accumulation found in the West Beach No.4 well between the depths of 8,751' and 8,950' 55 (14,548' and 14,781' MD). ') ) 15 'I~ ./ ) ) ) SECTION G Geologic Information 20 AAC 25.402(c)(6) 20 AAC 25.252(c)(4) Subsection 4 Prudhoe Bay Unit Eastern Operating Area Pt. McIntyre Reservoir 1. Injection Interval A. Stratigraphy and Lithology The Pt. McIntyre Reservoir is comprised of the Lower Cretaceous, Kuparuk, and Kalubik Formations. These formations were deposited during the Lower Cretaceous geologic time period. Exhibit G-l illustrates Stratigraphy in the Pt. McIntyre reservoir on a "type log" from Pt. McIntyre No. 11. The log is scaled in true vertical depth subsea (TVD S5), with MD also shown in the center track. The top of the Kuparuk Formation, the principal producing reservoir, occurs at 8,717' TVD 55 (9,980' MD), and the base occurs at 9,366' TVD SS (10,665' MD). The top of the Kalubik occurs at 8,650' TVD 55 (9,908' MD), and the base occurs at 8,717' TVD SS (9,980' MD), the top of the Kuparuk. The Kuparuk Formation in the Pt. McIntyre field is stratigraphically complex, characterized by rapid changes in thickness, lithofacies, and cementation. Lithology is dominantly sandstone with lesser amounts of pebb!'y sandstone, siltstone, and sandy mudstone. Referring to the type log in Exhibit G-l, the Kuparuk Formation can be subdivided into "upper" and IIlower' units. The basal portion of the "lower unit" is non-productive, tight, silty sandstone; siltstone; and sandy mudstone. Moving up in the lower unit, the lithology changes abruptly to porous, quartz-rich sandstone, which is typically about 200 feet thick (TVD). The lithology of the "upper unit" is more variable including interbedded sandstone, pebbly sandstone, and minor amounts of muddy sandstone. This interval is also rich in glauconite and more prone to reductions in porosity and permeability due to cementation and compaction. 17 The upper and lower units have distinctly different thickness trends. The lower unit maintains a more uniform thickness throughout the Pt. McIntyre area suggesting that its deposition pre-dates many of the faults that presently cut the reservoir. In contrast, the thickness and lithology of the upper unit is more variable and has been influenced by syndepositional faulting. Intergranular cements such as siderite and other iron-bearing minerals are common particularly in the upper unit and play an important role in determining reservoir quality. Cementation is especially abundant on the western side of the field where it forms a permeability barrier and contributes to the hydrocarbon trapping mechanism. Exhibit G-2 is an annotated log from the Pt. McIntyre No.3 discovery well showing the stratigraphic position of the Seabee Formation (also referred to as the Stump Island Sandstone) above the gamma ray shale (HRZ). The Seabee Formation contains a secondary reservoir of limited areal extent within the Pt. McIntyre P A. As development drilling proceeds, it is anticipated that similar secondary reservoirs may be encountered throughout the interval above HRZ. Oil within the Seabee Formation is stratigraphically trapped in discontinuous bodies of sandstone. B. Structure Exhibit G-3 is a structure map on the top of the Kuparuk Formation with a contour interval of 50 feet. Top Kuparuk structure in the Pt. McIntyre area is characterized by a gently northward plungin~ faulted, anticlinal nose. Large areas of the field have dips of one to three degrees. In the southern parts of the field, dips of up to ten degrees are present. The Pt. McIntyre Xeservoir is bounded on the south by a major east-west trending down-to-the-north normal fault called the Pt. McIntyre fault. This fault provides structural closure on the south side of the Pt. McIntyre field and plays a dominant role in controlling the distribution of the Kuparuk Formation Reservoir. South of the fault, the Kuparuk Formation is absent to very thin due to erosional truncation. North of this fault the Kuparuk Formation has been preserved. Other east-west trending normal faults, both down-to-the-south and down-to-the-north, are common throughout the Pt. McIntyre field. The field oil-water contact (OWC) occurs at a depth of 9,069' TVD S5. The gas-oil contact (GOC) occurs at 8,582' 1VD SS. 18 ) ) ) Exhibit G-4 is an isochore map of the Kuparuk Formation with a contour interval of 50 feet. This map illustrates the control that faulting has exerted on Kuparuk Formation thickness. Other controls on thickness are paleogeography and erosional truncation. Exhibit G-5 is a north-south structural cross-section through the Pt. McIntyre field showing gentle northward dip within the field and north-south thickness variations in the Kuparuk Formation across east-west trending normal faults. In particular, note the absence of Kuparuk south of the Pt. McIntyre Fault, an intermediate thickness between the Pt. McIntyre fault and the Terrace Block Fault, and an expanded upper Kuparuk section north of the Terrace Block Fault. Based on existing well data, faults within the Pt. McIntyre field do not appear to separate the Kuparuk Formations into hydraulically isolated reservoirs. Exhibit G-6 is an east-west cross-section across the Pt. McIntyre field, north of the Terrace Block Fault. The permeability barrier forming the western boundary of the field is shown schematically. The Kuparuk is thickest in the west and gradually thins to the east where it is eventually truncated by unconformities below the overlying shales of the Kalubik and HRZ. This truncation is an important component of the hydrocarbon trap on the east side of the field. ) C. Formation Water Salinities Laboratory analysis of water from Pt. McIntyre Wells Nos. 8 and 9 indicates salinity values of approximately 20,000 PPM NaCI equivalent. Because the Pt. McIntyre is only in an initial stage of development, no further salinity data is available. The 20,000 PPM NaCI equivalent salinity value is supported by log analysis results. II. Confining Intervals The Kuparuk Formation is bounded below by the Lower Cretaceous Miluveach Formation. The contact is defined by a change in lithology and electric log character. The Miluveach Formation is a highly impermeable, low resistivity (1 to 3 ohm-meters) shale with a thickness of approximately 200'. The overlying Kuparuk Formation is characterized by higher resistivity (3 to 6 ohm-meters). ) 19 The Kuparuk Formation is typically bounded above by the Lower Cretaceous Kalubik Formation. The contact is defined by a change in lithology and electric log character. The Kalubik Formation is a low resistivity (1 to 2 ohm-meters) shale and shaly mudstone. In the western part of the field, oil-bearing sandstones are present. The underlying Kuparuk Formation is dominantly sandstone with subordinate pebbly sandstone, siltstone, and sandy mudstone. Resistivity in the Kuparuk is in excess of 2 ohm-meters. In the south-central part of the Pt. Mcintyre field, the Kalubik Formation is absent due to non-deposition or erosion. In this area, the Kuparuk Formation is overlain by the HRZ. This is a black, organic-rich shale recognized on electric logs by its high radioactivity as measured by the gamma ray log. The HRZ varies in thickness from approximately 20 to 50 feet and is overlain by a thick shale wall and the Tertiary shale sequence. Where the 5eabee is found above the HRZ, it is bounded above by thick shale wall and the Tertiary shale sequence. Subsection 5 Prudhoe Bay Unit Eastern Operating Area West Beach Reservoir 1. Injection Interval A. Stratigraphy and IJthology The West Beach reservoir is in the Kuparuk Formation. The Kuparuk Formation was deposited during the Lower Cretaceous geologic time period. Exhibit G-7 presents a portion of the electric log from the West Beach No.4. This "type log" illustrates the stratigraphic definition of the Kuparuk Formation in the West Beach field. The log is scaled in TVD 55. The depth track displays TVD data on the right with MD values immediately to the left. The top of the Kuparuk Formation occurs at 14,548' MD (8,751' TVD 55), and the base occurs at 14,781' MD (8,950' TVD 55). The Kuparuk Formation in the West Beach area is overlain by the HRZ. The Kuparuk Formation is bounded below by the Lower Cretaceous Miluveach Formation or the Upper Jurassic Kingak Formation. Core in the West Beach Pool is very limited. Although four conventional cores were taken in the West Beach No. 3B, no rock was recovered over the Kuparuk interval. Thirteen sidewall cores were recovered in the Kuparuk in this well. Three conventional 20 " ) \, ,¡: } cores were taken in the West Beach No.4 with a total recovery of 31 feet. Based on the core data, the lithologies are summarized as poorly sorted conglomerates and conglomeratic sandstones and very coarse grained sandstones. Porosities range from 8 to 35 percent. Well data and 3-D seismic data indicate that the Kuparuk reservoir thickens dramatically from west to east, as is illustrated in Exhibit G-8. This structural cross-section is constructed west to east from North Prudhoe No.2, through West Beach No.3, to West Beach No.4: a horizontal distance of approximately 12,000 feet. The Kuparuk true vertical thickness in these three wells is 0, 13, and 199 feet, respectively. This eastward thickening is also illustrated on the Kuparuk isopach map (Exhibit G-9). B. Field Limits Drilling at West Beach has not encountered either a GOC or OWC for this accumulation. Therefore, the OWC based on West Beach No.4 is below 8,950' TVD 55. The GOC is between 8,540' TVD 55 (the base of the gas at West Beach No. 3B) and the top of the Kuparuk at West Beach No.4 (8,751' TVD 55). Information relating to potential fluid contacts in surrounding wells is summarized in Exhibit G-10. Given the limited data available at this time, it is difficult to estimate oil in place volumes with confidence. Exhibit G-9 is an isopach map of gross Kuparuk which depicts the estimated reservoir limi ts. Exhibit G-11 is a top Kuparuk depth map for the West Beach fault block using a 50-foot . contour interval. The structure for the West Beach accumulation is best described as monodinal northeast dip with the reservoir bounded on the north and south by faults. To the south, the east-west trending Prudhoe Bay bounding fault provides closure. This down-to-the-north fault is presumed to also have controlled deposition at Kuparuk time. On the upthrown side of this fault (south), no Kuparuk is present due either to erosion or non-deposition. Sealing across this fault is provided by juxtaposition of the Kuparuk on the downthrown side against Kavik shale or impermeable Lisburne group carbonates on the upthrown side. The northern fault bounding this field is the Pt. McIntyre fault, another east-west trending down-to-the-north fault. Across this fault, the West Beach field is positioned against the HRZ or other late Cretaceous shales. The loss of reservoir facies or cementation within the Kuparuk may also be a component of the trap along this fault to the east where the throw becomes much less significant. Although the exact trapping mechanism to the north is complex and not fully understood, pressure data 21 indicates the West Beach accumulation is separate from the Point McIntyre accumulation. The remaining elements of the trap for th.is accumulation are northeast dip providing the eastern closure and the onlap/pinchout/truncation of the Kuparuk to the west. This is illustrated in Exhibit G-8, an east-west structural cross section A-A', and Exhibit G-9, an isopach of the gross Kuparuk with 25-foot contours. C. Formation Water Salinities No formation water has been produced from the West Beach Pool. As stated earlier, the OWC for this accumulation has yet to be contacted. Salinity data from the Kuparuk Formation in the Pt. McIntyre Pool just north of the West Beach Pool indicates NaCL equivalent values significantly above 10,000 PPM. As soon as salinity data becomes available from the West Beach it will be forwarded to the Commission. II. Confining Intervals The Kuparuk Formation in the West Beach area is overlain by the HRZ. This contact is defined by an abrupt lithology and electric log character change. The HRZ is a dark gray to black, organic-rich shale characterized by very high gamma ray counts which are often greater than 150 API units. The HRZ varies in th.ickness from 20 to 50 feet and is overlain by a thick shale wall and the Tertiary shale sequence. The Kuparuk Formation is comprised of interbedded conglomerates and sandstones with gamma ray counts typically less than 80 to 100 API units. The Kuparuk Formation is bounded below by the Lower Cretaceous-age Miluveach Formation or the Upper Jurassic-age Kingak Formation. The contact is also defined by a change in lithology and electric log character. The Miluveach and Kingak Formations are a thick sequence of dominant shales with low resistivities (typically 1 to 3 ohm-meters). The overlying Kuparuk Formation in West Beach No.4 is hydrocarbon-saturated and has resistivities from 8 to 31 ohm-meters. 22 SECTION H ) ! Well Logs 20 AAC 25.402(c)(7) 20 AAC 25.252(c)(S) All openhole logs from EOA wells, including Pt. McIntyre and West Beach, are sent to the Commission as the logs are completed. Exhibits G-l, G-2, and G-7 are type logs for the Pt. McIntyre and West Beach PAs, respectively, with stratigraphic and marker horizons annotated. ) ,) 23 } SECTION I ) i Casing Information 20 AAC 2S.402(c)(B) 20 AAC 2S.2S2(c)(6) Currently, approximately 16 water injectors and at least 1 gas injector are planned for Pt. McIntyre. A number of the water injection wells are planned for pre-production prior to conversion to waterflood injection. A wide range of departures will be drilled in Pt. Mcintyre with a maximum injection departure of over 12,000 feet expected. ) Tubing sizes in the Pt. Mcintyre field will vary from 3 1/2 to S 1/2 inches with the only current exceptions being 2 71B inches in Pt. Mcintyre No.7 and 7-inch tubing in the gas injector P1-GI. In general, the production casing will be sized to the tubing in the Pt. McIntyre wells. Typical development wells will utilize either a uconventional," uslimhole," or uuItra slimhole" design similar to Kuparuk and Prudhoe Bay. The uconventional" design wells requiring S 1/2-inch tubing will utilize 13 3lB-inch surface casing, 9 SIB-inch production, or intermediate casing with a 7-inch liner for the high stepout wells. The uslimhole" design wells requiring 4 1/2-inch tubing will utilize 10 3/4-inch surface casing, 7 SIB-inch production, or intermediate casing with a S 1/2-inch liner for high stepout wells. The lower rate wells will utilize the uultra slimhole" design, a 3 1/2-inch tubing string inside a 7-inch production string with 9 SIB-inch surface pipe. The West Beach waterflood with gas injection development case includes; five production wells, five water injection wells, and one gas injection well. In general, West Beach wells will utilize either a "slim hole" or "ultra slimhole" design. "Slimhole" designs will consist of 10 3/4-inch surface casing, 7 SIB-inch production or intermediate casing with a S 1/2-inch liner for the higher stepout wells. "S1imhole" designs will accommodate both 3 1 12-inch and 4 1/2-inch tubing. The "ultra slimhole" designs will consist of 9 SIB-inch surface pipe, 7-inch production string, and 3 1/2-inch tubing. All dedicated Pt. Mcintyre and West Beach water injection wells will be completed with L-BO grade steel. The injection wells planned for pre-production may utilize corrosion-resistant material where applicable. All tubing jewelry will be completed with 9-Cr I1Moly, which is compatible with both L-80 and 13-Cr. Most Pt. McIntyre water injection completions are currently envisioned as single zone, single string with a single packer. Where both the Pt. McIntyre and Seabee are present, the current plan is to run single packer completions. A straddle completion may be run when both the Pt. McIntyre and Seabee are ) 2S present, if sufficient Seabee reservoir quality is observed. Exhibits 1-1 through 1-7 show typical wellbore schematics for the three basic completion designs and the straddle completion previously discussed for Pt. McIntyre. All West Beach water injection completions are currently envisioned as single zone, single string with a single packer. Exmbits 1-8 through 1-10 show typical wellbore schematics for the two basic completion designs to be used for West Beach. As shown in the schematics, gas lift mandrels with dummy valves will be run to provide flexibility in artificial lift, which will enhance production in the injection wells planned for pre-production. Sufficient mandrels will be run to provide flexibility for well production and gas lift supply pressure. The actual casing program is included with the" Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. Further, all drilling and production operations will follow approved operating practices in reference to the presence of H2S in accordance with 20 AAC 25.065 (a), (b), and (c). 26 ) ) SECTION J ) Injection Fluid 20 AAC 25.402(c)(9) 20 AAC 25.252(c)(7) Subsection 1 Enhanced Recovery A. Type of Fluid - Source Water. Pt. McIntyre and West Beach are planning to inject Beaufort Sea source water; the same water that is currently being injected into the Ivishak Formation. Analysis of Composition of Typical Fluid - Exhibit J-l is a listing of the composition of the Beaufort Sea source water. ) Estimated Maximum Amount to be Injected Daily- Pt. McIntyre - Peak injection approximately 250,000 BWPD. Initially, the development plan includes only source water injection into the Pt. McIntyre PA. Source water needs may decrease in the future as the combined produced water volumes from Pt. McIntyre, West Beach, and Lisburne increase. West Beach - Peak injection approximately 50,000 BWPD. Conditionally, the development plan includes only source water injection into the West Beach Pool. Future potential exists for a decreased need for source water as the combined produced water volumes from Pt. McIntyre, West Beach, and Lisburne increase. The West Beach and Pt. McIntyre fields will use a single pipeline for their waterflood water. Therefore, should Pt. McIntyre switch from source to produced water injection, West Beach will most likely do the same. Compatibility with Formation and Confining Zone - No significant problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. B. Type of Fluid - Produced Water. This fluid is water that was produced with the Lisburne, Pt. McIntyre, and West Beach oil and separated from the oil and gas at the LPC. Produced water tl 27 may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other prod ucts used in the production process. Analysis of Composition of Typical Fluid - See Exhibits J-2 and J-3 for the composition of the Lisburne and Pt. McIntyre formation waters, respectively. The Pt. McIntyre water sample was taken from exploration well Pt. McIntyre No.8. No fonnation water has been produced from the West Beach Pool. Once salinity data is obtained from the West Beach Pool, the results will be forwarded to the Commission. Estimated Maximum Amount to be Injected Daily- Pt. McIntyre - Future produced water injection rates at Pt. McIntyre may reach 250 MBWPD. West Beach - Produced water injection rates at West Beach may potentially reach 50 MBWPD. Compatibility with Formation and Confining Zones - The produced water returning to the Pt. McIntyre and West Beach Formations will be a mix of Pt. McIntyre, West Beach, and Lisburne produced water separated through the LPC. The current development programs for these three fields indicates the majority of the produced water will come from Pt. McIntyre (current maximum estimated at 250 MBWPD) with minimal amounts coming from West Beach (current maximum estimated at 50 MBWPD) and Lisburne (current maximum estimated at 20 MBWPD). Since the origin of a vast percentage of the produced water will be the Kuparuk Formation, minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. C. Type of Fluid - Natural Gas. This fluid consists of Lisburne, Pt. McIntyre, and West Beach natural gas and natural gas liquids produced with the oil and separated from the oil and water at the LPC. Analysis of Composition of Typical Fluid - See Exhibit J-4 for the composition of the Pt. McIntyre, West Beach, and Lisburne processed gas streams. The Lisburne composition represents the processed gas stream currently being reinjected into the Lisburne, while the Pt. McIntyre and West Beach compositions represent produced gas streams. The actual commingled processed gas stream reinjection should be closer to the Lisburne composition as the heavy ends listed in the Pt. McIntyre, and West Beach compositions will be removed through processing at the LPC natural gas liquids facility. 28 \ .! ') Estimated Maximum Amount to be Injected Daily- Produced Water Disposal Wells (LPC Disposal Fluids) - The LPC injection fluid for disposal is predominantly produced water from the Pt. McIntyre, West Beach, and Lisburne PAs. Upgraded pump design and piping along with the workover of existing Injector LPC-Dl and the drilling of one to two additional disposal wells will place the maximum disposal capacity at approximately 80 MBWPD per well, or 240 MBWPD. ) B. Type Source of Fluid - Exempt waste. Source of Fluid - The injection stream could include drilling mud, reserve pit water, contaminated crude, diesel gel, glycol (associated with well production operations), and workover fluids. QIÙY exempt fluids generated from Pt. McIntyre, West Beach, and Lisburne are planned for injection at this time. Estimated Maximum Amount to be Injected Daily - Exempt Waste Disposal Wens (D5-P2 Cuttings Disposal Well) - Expected maximum daily rate of 2,000 BPD. ) } 30 Estimated Maximum Amount to be Injected Daily- Pt. McIntyre - Injection could potentially reach approximately 500 MMSCFPD. West Beach - If economically feasible, facilities to reinject gas into the West Beach could be in place as early as 1995. Potentially, a maximum of approximately 250 MMSCFD could be injected. Compatibility with Formation and Confining Zones - a. Pt. McIntyre - The H2S levels detected to date have been very low in the Pt. McIntyre reservoir. The processed gas injected into the Pt. McIntyre gas cap will be a mixture of Lisburne, Pt. McIntyre, and West Beach produced gas processed through the LPC. The Lisburne processed gas stream is expected to initially contain higher levels of H2S compared to the initial Pt. McIntyre and West Beach produced gas streams. This circumstance will tend to increase the presence of H2S within the Pt. McIntyre reservoir. Although the H2S levels are expected to increase with time at Pt. McIntyre, independent of the Lisburne injection gas due to current plans to waterflood the Pt. Mcintyre Pool, minimal compatibility impacts are anticipated as a result of the gas injection into the Pt. McIntyre reservoir. b. West Beach - There are no compatibility problems anticipated with West Beach. Currently, no H2S has been detected in the West Beach reservoir, and current development plans do not include gas injection at West Beach at start-up. If gas injection is initiated, some H2S impacts are anticipated. Experience gained at Pt. McIntyre will provide operational guidance. Subsection 2 Fluid Disposal A. Type of Fluid - Produced water disposal. Analysis of Composition of Typical Fluid - See Exhibit J-3, "Pt. McIntyre Produced Water." Source of Fluid - Produced water from the Lisburne, Pt. McIntyre, and West Beach PAs. 29 ) SECTION K ) Injection Pressure 20 AAC 25.402(c)(10) 20 AAC 25.252(c)(8) ) The estimated maximum and average injection pressures anticipated for Pt. McIntyre and West Beach enhanced recovery and LPC produced water disposal wells are listed in the following table: ) Estimated Maximum Injection Pressure (Psig) LPC Produced Water Disposal 2,700 Pt. McIntyre Gas Injection 5,000 Pt. McIntyre Water Injection 2,850 DS-P2 Cuttings Disposal Well 1,000 West Beach Gas Injection 5,000 West Beach Water Injection 2,850 (Pressures represent pump discharge pressures) Type Well ~ 31 Estimated Average Injection Pressure (Psig) 2,200 4,300 2,450 500 4,300 2,450 ) ) SECTION L ) Fracture Infonna tion 20 AAC 25.402(c)(11) 20 AAC 25.252(c)(9) The estimated maximum injection pressures for enhanced recovery and fluid disposal wells will not initiate or propagate fractures through the confining strata, which might enable the injection or formation fluid to enter freshwater strata. Subsection 1 Freshwater Strata ) There is no freshwater strata in the area of issue (see Section N). Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Subsection 2 Enhanced Recovery Injection in the Kuparuk and Seabee Fonnations, above fracture parting pressure of these fonnations, may be necessary in the future to allow for additional recovery of oil. In no instance would such injection pressures breach the integrity of the confining zone. The Kuparuk Fonnation is overlain by the Kalubik and HRZ shales. The HRZ is a thick shale sequence which would tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. Mechanical properties log data for the HRZ and Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. The Seabee is overlain by the K-IO shale interval. Mechanical properties log data for the K-I0 interval also indicates a fracture gradient from approximately 0.8 to 0.9 psi/ft. ) 33 ) ) " Fracture data from the Kuparuk intervals of the Pt. McIntyre and West Beach Pools indicate a fracture gradient of between 0.60 and 0.63 psi! ft in current virgin reservoir conditions. Fracture data from Pt. McIntyre No.9 gave a fracture gradient of 0.624 psi/ft, while data from West Beach No.4 indicated a fracture gradient of 0.602 psi! ft. No fracture data is currently available for the Seabee. However, based on known characteristics of the Seabee, its fracture gradient should fall in the same range as the Kuparuk and Ivishak Formations, from approximately.55 to .65 psi/ft. ) The Kuparuk Formation is underlain by the Miluveach/Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrated leakoff at a gradient of 0.85 psi! ft. The Seabee is underlain by the HRZ shale, the properties of which were described earlier. Prudhoe field data also indicates that sandstone fracture gradients may be reduced during waterflooding operations due to reduced in-situ stress associated with the injection of colder water. Declining reservoir pressure can also reduce formation stresses, thereby reducing the fracture gradient. The Pt. McIntyre Pool will be produced for a minimum time prior to the start-up of waterflood operations allowing the reservoir pressure to decline somewhat. However, once waterflood operations are initiated, field average pressures will be managed to mitigate fluid migration and sustain reservoir energy. Subsection 3 Fluid Disposal ) Consistent with existing Area Injection Order No.4, the injection zones for fluid disposal and all zones above and below the injection zones contain greater than 10,000 mg/l IDS and are not freshwater strata. Therefore, injection at above parting pressure would not result in formation or injection fluid movement into freshwater strata. The confining shales below the injection zone are in excess of 2,000 feet vertical thickness. The upper confining zone consists of numerous interbedded confining shales and mudstones averaging 10 to 50 feet and over 1,800 feet of permafrost. The planned disposal of produced water into the Tertiary/Upper Cretaceous will be in addition to existing EOA and WOA injection operations. Pressure impacts are expected but are not anticipated to be significant. The exact impacts are not currently quantifiable due to uncertainties in injection rates and timing. ARCO will continue pressure monitoring of the Tertiary/Upper Cretaceous. ) 34 " ) ,) SECTION M '} Formation Fluid 20 AAC 25.402(c)(12) 20 AAC 25.252(c)(10) A typical water analysis for the Pt. McIntyre reservoir is included in Exhibit J-3. As stated earlier, no water analysis is currently available from the West Beach Formation. Once water composition data is obtained, the data will be forwarded to the Commission. Exhibits M-l and M-2 are typical water analyses for the Tertiary/Upper Cretaceous as found in existing Area Injection Order No.4. ) ) 35 , I ) ) SECTION N ) Aquifer Exemption 20 AAC 25.402(c)(13) 20 AAC 25.252(c)(11) No aquifer exemption was applied for or granted in regard to Area Injection Order No.4, as a lack of freshwater (less than 10,000 mg/l IDS) was demonstrated in the EOA. The inclusion of the Pt. McIntyre P A will expand the EOA to the north (see Exhibit N-l). To confirm the lack of freshwater in the expanded operating area, estimates of TDS have been made for the Pt. McIntyre P A. As in the original Area Injection Order No.4, resistivity and porosity log data was utilized to approximate formation TDS values. Exhibit N-2 describes the methodology used to calculate the salinity values in the original injection order and this amendment. Exhibit N-3 is a summary of the analysis results. The lack of freshwater found in the Pt. McIntyre P A eliminates the need for an aquifer exemption in the expanded EOA. ) l 37 ,) " SECTION 0 ') Hydrocarbon Recovery 20 AAC 25.402(c) 14 The current recommended Pt. McIntyre development scenario includes a combination of processed gas reinjection and pattern waterflooding. A total oil recovery of between 42 to 45 percent OOIP is expected for this development scenario. This compares to an estimated 20 percent OOIP oil recovery attributable to primary depletion. Incremental hydrocarbon recovery of approximately 160 MMSTB is expected to result from Pt. Mcintyre waterflood and gas reinjection projects. Due to the uncertainties associated with the extent of the West Beach Pool, the current estimated OOIP ranges from 12 to 65 MMSTB. Primary depletion is expected to recover up to approximately 10 percent OOIP. Reinjection of processed gas could increase the recovery to approximately 20 percent OOIP. Waterflood operations could increase the ultimate recovery to approximately 29 to 44 percent OOIP, depending on the extent of the West Beach Pool. A maximum increase in recoverable reserves of 22 MMBO may result from the West Beach waterflood and gas reinjection projects. ~) 39 ) SECTION P ) Mechanical Integrity 20 AAC 25.402(d) & (e) 20 AAC 25.252(d) & (e) In drilling all Pt. McIntyre and West Beach injection wells, the casing is pressure tested in accordance with 20 AAC 25.030(g). When a producing well is converted to injection, the casing pressure test will be repeated in accordance with 20 AAC 25.412(c). Injection well tubing/casing annulus pressures will be monitored and recorded on a regular basis by the Production Operations Group. The following is a summary of the current Commission rules pertaining to the mechanical integrity of an injection well. The summary is not meant as an amendment but rather as a summary of the current mechanical integrity rules in reference to the EOA. ARCO intends to remain in compliance with both for the original and expanded area. .» July 11, 1986 1 The tubing/casing annulus pressure of each injection well must be checked weekly as a routine duty 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 percent of the casing's llÙnimum yield strength. Tubing/ casing pressure variations between consecutive observations need not be reported to the Commission. A schedule must be developed and coordinated with the Commission which ensures that the casing/annulus for each injection well is pressure tested prior to initiating injection and at least every four years thereafter. A test surface pressure of 1,500 psi or 0.25 psi/ ft multiplied by the vertical depth of the packer, whichever is greater, must be held for 30 minutes with no more than a 10 percent decline. The Commission must be notified at least 24 hours in advance to enable a representative to witness the pressure test. ) 41 ) ) 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. ) October 28, 19862 Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing, or packer, the Operator must; (1) notify the Commission on the first working day following the observation, (2) obtain Commission approval of a plan for corrective action and when USDW is not endangered, and (3) obtain Commission approval to continue injection. April 19 , 19913 The following describes the current procedure used by ARCO to report the results of mechanical integrity testing done for ARCas North Slope properties. A quarterly report will be submitted summarizing mechanical integrity tests (MITs) performed during that quarter on DIC Class II injection wells. Additionally, the report will include brief comments on all injection wells which have average tubing/casing annulus pressure within 500 psig differential to the average tubing pressure during the middle month of the quarter. Wells with an annulus pressure less than 500 psig will not be commented on. These comments will describe the nature of the well annulus pressure performance such as: ) A. Diagnostic Evaluation Complete: Form 10-403 waiver received B. Diagnostic Evaluation Complete: Minor pressure communication noted, continued to operate and observe significant changes in status c. Diagnostic Evaluation Complete: Annulus pressure history indicates no leaks D. Diagnostic Evaluation Complete: Recording error or failed gauge E. Diagnostic Evaluation Underway ,) 42 ) ) References: ) 1. "The Request of ARCO Alaska, Inc., for and AIO for the EOA," AOGCC memo to AAI, J ul Y 11, 1986. 2. "Amend Rule 7 of Area Injection Order No.4," AOGCC memo to Prudhoe Operations Manager, October 28, 1986. 3. "Annulus Pressure Monitoring of DIC Well," AAI memo to AOGCC, April 19, 1991. ) ), _..,l 43 ) Exhibit A-I: Exhibit A-2: Exhibit A-3: Exhibit A-4: Exhibit B-1: Exhibit B-2: Exhibit B-3: Exhibit C-l: Exhibit D-l: Exhibit G-l: Exhibit G-2: Exhibit G-3: Exhibit G-4: Exhibit G-5: Exhibit G-6: Exhibit G-7: Exhibit G-8: Exhibit G-9: ) Exhibit G-I0: Exhibit G-ll: Exhibit 1-1: Exhibit 1-2: Exhibit 1-3: Exhibit 1-4: Exhibit 1-5: Exhibit 1-6: Exhibit 1-7: Exhibit 1-8: Exhibit 1-9: Exhibit 1-10: Exhibit J -1 : Exhibit J-2: Exhibit J-3: Exhibit J-4: Exhibit N-l: Exhibit N-2: Exhibit N-3: Exhibit M-I: Exhibit M-2: ) ') ) List of Exhibits Location of Pt. Mcintyre P A Location of West Beach P A Legal Description of Pt. McIntyre P A Legal Description of West Beach PA Plat of Wells Within Pt. Mcintyre P A Plat of Wells Within West Beach P A Plat of Potential Wells Within Pt. McIntyre PA Native Allotment Parcel Map Affidavit Pt. McIntyre Field Type Log - ARCO Pt. McIntyre No. 11 Well ARCO Pt. Mcintyre No.3 Log-Seabee Formation Top Kuparuk Formation Structure Map Kuparuk Formation Isochore Map North-South Cross Section (A-A') East-West Cross Section (B-B') West Beach Field Type Log-West Beach No.4 Well East-West Structural Cross Section (A-A') Kuparuk Formation Isopach Map Fluid Contact Correlation Chart-Prudhoe Bay Area Top Kuparuk Formation Structure Map Pt. McIntyre Well Schematic Ultra Slimhole 3.5-inch Tubing Pt. McIntyre Well Schematic Slimhole 4.5-inch Tubing Pt. McIntyre Well Schematic Conventional 5.5-inch Tubing Pt. McIntyre Well Schematic Slimhole 3 .S or 4 .S-inch Tubing Pt. McIntyre Well Schematic Conventional with Liner 5.S-inch Tubing Pt. Mcintyre Well Schematic Gas Injection Completion Pt. McIntyre Well Schematic Straddle Completion - 4 .5-inch Tubing West Beach Well Schematic Ultra Slimhole - 3 .S-inch Tubing West Beach Well Schematic Slimhole 4.5-inch Tubing West Beach Well Schematic Slimhole 3 .5 or 4 .5-inch Tubing Beaufort Sea Source Water Analysis Lisburne Produced Water Analysis Pt. McIntyre Produced Water Analysis Injected/Produced Gas Stream Analysis Expanded Eastern Operating Area Equations Used in Formation Water Salinity Calculations Pt. McIntyre Calculated Wireline Salinities Tertiary/Upper Cretaceous Water Analysis Tertiary/Upper Cretaceous Water Analysis 45 '- cl._... 1 f, \ .-.1 \c \\ \\ \ '. n \ '. . \1 . \~ \ \~ , .\ .. \. ", . ~... PBU Boundry \ ' , _ _ ___ ___. _____ ,..,...~._......._.:};..... ...-.__ '~'."""'.IIIIWAI._.u.I."'-.WUI"UU'M.VJ.LV.I. ,,,.. - ..."..."...... ·.u....··... u.o.&.U.I-I ., I '. ,. *.~ ..'" 1',:..... ,lj' \, \ .jr ~- \ Ii:' \, ·9 \:(' l . . - ... ~ . '... I '.. .."'J " \ ARCa - E~º_~...ª~ª~.ª....__"...__....,,__..........!ß.Çº.:::~ON 28297 Ãìm<t- ~ON 34824 ~ ~ ~ ..,.... I ) ARCO-EXXON 34627 ARCO 370 13tt---h -------..--------.- ARCO- qxPN 34623 EXXON 34822 .II - -----ŠPjf385Š4ã----·..·..··..·· :.:n...", ······----··'----r--------· J. ...-:::=..... i .::::O::;·-..h........ I' ,."......... ....... ( /1~.<1.t~,..~~.,.;; :~::--.. '\ \:, "','" ............. ..'..:', II -.~.. '.. -., ~~ I' ""~'. . .-.----.-..--- .-- -- --- - .----0 - ------..--------... -...-.---..---------.:~~--. 0-.-------.---..--------.-..-- .-----..---.0.---------.-----------.-.----.---.---------- .-- .--- .--.--. .-- ----.-- - - t.------. ~ . ~.~ I Pro;osect Pt. "clnt," .:... '( " - ! PA Boundry---> "~ of ,. ,\ ~\ '. , '. ~ ~ ~\ -' " \ -. ,'.: ,.\1. .... ; '"\1:1 t .----'------:~hJ (~ III . I.. I ' )o.}\ .' \ , : [:... '.. .....--.....\ " .,:J./ \.., // \ \ /~I \ ...... ...... \1 . ~ > . I--i tT1 >< =r .... ~ þooI. .... r ",__'...J. - Point Uc[nt yre Participating Area ---- ~' Location of Point McIntyre Proposed P A ARCO Aluka. IDa. U~bllqa.1Pt. IIoIntYn h"n-.rtQL '-' c BPX 365548 BPX 365549 ~ ,... ..........-..... · · · · · · · · · · · · · . .... .. - . .. . .. . ., I I ~ I:Tj 1 >< =" ~. 0- ~. ~ ~ ARCO-EXXON 34627 ARCO-EXXON 34626 ..........................................................................: .................................... : · · · · PEU BOUNDARY -->: · · · · ........ )- I N \ 1 I ARCO-EXXON 28300 ARCQ-EXXON 28301 · ,I 1 · · I · · I · · · · · · · ARca Alaska lIne. U~burne/polnl McIntyre Englneerlns West Beach Proposed Participating Area E. Zuapua 0?-a'-92 f) <--- PROPOSED WEST BEACH PARTICIPAT:NG AREA ARCQ-EXXON 34628 '- -, ARCO- EXXON 34629 q b. ~ II3.ua I"ffT . 2lai 1&!U 1111 ~¡¡ii ~yu fEET STATUTI! "ILU. ~ 'TRTUTE "[LU Location of West Beach Proposed P A ) ) ) Exhibi t A-3 Legal Description of Pt. McIntyre Participating Area UMIAT MERIDIAN T12N, RISE Section Section T12N, R14E Section Section Section Section T12N, R14E Section Section Section Section T12N, R14E Section ) T12N, R14E Section Section Section Section 18 All 19 Nl/2 13 All 14 All 23 Nl/2 NWl/4, Nl/2 NE1/4, SWl/4 NW1/4 24 N1/2 15 All 16 All 21 N1/2 NEl/4 22 Nl/2 17 Nl/2, Nl/2 SEl/4, NEl/4 SWl/4 excluding U.S. Survey 4044 3 All 4 All 9 All 10 All Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Sections 2 and II, T12N, R14E, UM, AK (Identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, RISE, UM, AK (Identical with line 6-7 on Block 60S), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79. } Exhibit A-3 Exhibit A-4 Legal Description of West Beach Participating Area UMIA T MERIDIAN T12N, RISE Section 21 SWl/4 TI2N, RISE Section 19 51/2 Section 20 SI/2 T12N, R14E Section 24 51/2 T12N, R14E Section 25 NI/2,5EI/4 T12N, RISE Section 29 Nl /2 Section 30 Nl /2 TI2N, RISE Section 28 Nl /2 Exhibit A-4 - - - - ._-----~- "-' Plat of Wells Wrdtin Point McIntyre PA --- ARea Alaska. Inc. - . 1J,t»lU"nelP\. Mclntyr. F.n.ln..r1n. t- ... _.... I I' . Drilled Wells ~ Abandoned Wells Ð Suspended "ells ~ Poinl McIntyre Participating Area ARCO-~ºN 34623 ARCO-E~N 34622 ,. ...,:(:~.;~;~::~;;:;;;\~,~~~ ~ :::::~:>.. ....::.... P2 - 55 '. . .....:-.. . "'::::'" PM 7 '. ". . - ----- - - - - - - - - -- - -. -- - - --- - - - -. -- -, - - --, - - - --- --. - - --- -- .--- - -. -- -- ---":...:~......--- -- --- - --. --- -_________.____. - - _e. ___ .__ ___ __ ____P.M_ _6_ ---- ---------__________ -___________, _ _ __ _ .,___, _ _ -. _ --. -- --- - - t-------. -":-" . ",:, ..:.. '\::~'" \\ \.. \\ . . \ \, \ \ \\ ,,, 0: P2 - 51 . mn...~~~.. á6554.ä...... ...... ...., . ......~.. P2-49 . ------- ..RCO 375136'''--- - .----...--..------ PN ~ .1..' \ '...... 1 '.. \ ....J \ .- \\ \\ \\ ,.. q . PN 3 \\ '....\.. . :)14 I 0 \~ . . \ \'" - - -...... -.. - --. ........ r··~:,.....·...,......,.,..·......··..,...··...,...··...-..··T:·.....··.......··,v..."......v.e.........&........,.,......,.,........ ...................................; ........... ,~:. ...:..-. :" .:~~. // ' . 1'2-48 \\ '\ ./': Qþ P2-S0 .:....\ .l..·· \I.t~··'(.. \ 'J.' ". ...."...l .....,. A~CO-E~9~u 2~?ªtt___uu_._.~_____.uu__ At!.Çº-~J-Kt ON 28297 ARt30,-EXXON 34624 ". '. ...... ·..·1 , ~~r \, ::r · ,. . ~. ·:.1'" tT i {~I" ... .... I ", t.l ~ ; ·-------1··---·::·--; (\:\ · : .:.'..)\ n1 20 t-I ~ PM 8 . ___~ - ¡ 1:~:'1ì \........ · (/.. \~... i . '... ..~ :- "-'" ........ (I PM 2 B PI-II . \.-..\ ." : i : PN 13 . Pro ]osed Pl. Nclnlyre PA Ðoundry---> PN 11 . PM 1 181 1'2-30 . . . P1-G1 PM 5 . --/ PBU Boundry I . I . I ARCO-EXXONi 34327 07-2'-92 E. Z\I"-"n ~ Abandoned Wells o Suspended Wells . Drilled Wells West Beach Location Map '3BBBB fEET ~ 2BßB 1BßB 6BßB BBBB J B~BB fEET J STRTUTE HILES ~ ( _~ STATUTE HILES ARca Alaska] Inc. Lisbume/Poini McIntyre Engineering --.------ , 1 I I I I I I I I I I I I I .1. ) ARCO-EXXON 34629 AReO-EXXON 34628 ARCO-EXXON 28300 ARCO-EXXON 28301 G to. WE 3 WB 3B ·~tÐ WR 4 . ~ ~ ~" / ~ Gull Is1. 3 ~ / ~ ~ \~~- WEST BEACH \ PARTICIPATING AR~:A ~ , N D ARCO~EXXON 34626 ARCO-EXXON 34627 _~ 20297 '" _..~~----_.-._--_.._. I " j ~\ I ..~ ¡ LJ' I I ..----..---_....._.1 t'!'j >< :r þoOI . 0- þoOI. ,.,. PBU BOUNDARY --> --..--..-..---.--..--.......----.-.---.....--...-.-------.---.-.-....---.----.--...-.--...-..--...........--.- ------ c , ".~ ~, ~ \ ~. ~ BPX 365549 BPX 365548 --~-- _u_~_____~ Plat of Wells Within West Beach PA -..., A-E 28297 98 A-E 34627 - -- -- -----.------ ~---~-~ Plat of Potential Wells Within Point McIntyre P A BPX ENTERP. 312809 1 1 . (;1 A-2 ~'2 . BPX 365548 EXXON 34622 . . PM 9 .10 D3 B-2 . 11 . 1,"0 ~ G2 . . . . LV E3 .. . . F3 H2 JI C-2 D4 . 12 . . . C3 .. . L1 PM 7 . J2 . ",-. '-'- . F4 H3 . K2 . PM 6 . C4 C . .. £2 J3 . .. H4 . K3 M2 . PM 13 .. D6 D-1 . 14 . ;3 B-1 . . C5 .. J4 . . HS K4 M3 . . . ~~\ . (f) IS £4 . D'I C6 . . ~ . PM II .. P'¡ Jï J5 ..... ..... ('8 . . . C-2 M4 :9 . - .- . L6 à ..c:. lJB C"I >< . A-I . ~ . . H7 J6 ,(:y . . K6 M5 . F-B, C-8 .. £6 N5 . ~. J7 . O:j . . . PM 5 . K'/ .. N6 E-1 PM 3 e-e . £"1 . PM 10 . 06 . ~ . . M7 .. hB H9 J9 . I '(j . . LB N7 . . MB . . . F-2A (llj · F-2 J>7 . . Native Allotment Parcel Map ~'-.. .,...- 'L::::::>", EGG IS. \ '~'-' ) STUMP IS. 15 PT. STOR~ERSEN ~ J", ~S "\~ ~~-~~ì PT. S-r ~ ~\~ I~ Y R E I ,~ / ,;) \ M c N T ~ ~~ DEW SITE f'\\~~' -,17 I \ I \ I \ I \ ._. S.T.P. ~ ;?"::'. . /";t- \ , / '. \ , \~~ 118 Y:= "'-. ~. WE Exhibit C-l - ... ------ "., N P.G. ST.#2 TERM Ò WELL A \ . \ : ) ) Exhibit D-1 ) AFFIDAVIT OF MARK P. WORCESTER REGARDING NOTICE TO SURFACE OWNERS IN THE VICINTIY OF THE PROPOSED INTECI10N WELLS Mark P. Worcester, on oath, deposes and says: 1. I am a Senior Attorney for the Atlantic Richfield Company, and I serve as an in-house counsel in Anchorage, Alaska, for ARCD's wholly owned Subsidiary, ARCO Alaska, Inc. 2. On March , 1993, I caused copies of the application to amend Area Injection Order No.4 to be provided to the Surface Owners of all land within a quarter mile of all proposed injection wells within the Pt. McIntyre and West Beach Participating Areas as listed below: '.) State of Alaska Department of Natural Resources Attn: P.O. Box 7034 Anchorage, AK 99510 Alice Glenn 899 Blair Ave. Sunnydale, CA 94087 Lawrence Ahmaogak P.O. Box 411 Barrow, AI< 99723 Lawrence Ahmaogak P.O. Box 411 Barrow, AK 99723 John Nicholls (minor) c/o Ely Varner (guardian) P.O. Box 473 Barrow, AI< 99723 Barbara Ahmaogak 1628 Hilton Ave. Fairbanks, AK 99701 George Ahmaogak P.O. Box 338 Barrow, AI< 99723 Mark P. Worcester STATE OF ALASKA ss. THIRD JUDICIAL DISTRICT SUBSCRIBED AND SWORN to before me this day of March, 1993. }I :¡ NOTARY PUBLIC IN AND FOR ALASKA My Commission Expires: Exhibit 0-1 Pt. ~clntyre Field Kuparuk Fm. Type Log Pt. Mcintyre #11 -150. O. I------~--;;-------' 1M. !)GO. I 011 ON" I t O. 150. .2 I 011 QflI"1 t I MD SS -J-- +"" 8aoo C I. ~ \, I I ,-9900 ~ , i I I , :;¡ r, . ;"" ,: ~; I ; .l· , I ~l !'- I : : I ~.. ~10050 : : :::~.J :. '- 8800 I ~7J"~ · 10100 , : , ..iq:..ï~~, : :~~l:····::·:··,·f ..;; I ~:r::J;l,- ¡rtf·T. 1 ". I . -'à. '·r ..~ ~ I I ~··I'" ~ I -/<:,,: ,I \ I ~...:!...! <'~ ~~...¡, ·1 ' 1~.I., I .\ I I ~""l ". J'" I , __ i ('·;.·~,·1 ~ -~ ~ 10350-- ; '-·..·:Y.·1 ; }- , I : ...1':.::.·1:.' , !\ ' :'10400 9100 i..!,"'·,·'·1'·:',·¡,····1 ' I'): - , -1t,\.,:: .~,. I 1\' 1 r\:,>,:,~ ,.. ., J.I , , i' 10450 ...~.....,.'vi 1(' t~~iH", t ~. '2" '/f':·:.~·l~1 I ~ 10500 .. '.:-...;.... I I { ,... ·:··'f~'.·:~·..:.:>.i : ! ) ~10550 iT>1-·...·:·..···::'·..1 I : ;: ¡¡if; ~ ~"".".. ! I : ~: I 10850 r ; ~¡ " , . \ 10700 9400 , \ I I;: 1.-10750 ,.... ,.... 9950 8700 ,.... .-10000 c c 0.2 to- - -ca _ N 0= G,) ~ C Q) o c:: N .- :: t ~: ;:'10150 ,.... 8900 - -10200 10250 9000 10300 I I J ' I , I , ¡ I I I I I I 1 9500 .2 200. t-----'5FLü-õH,;;¡-----i .2 200. I I L" oe... I LD 0""" 200. t ....... ~ ~ -i& 1J- ~ --r - , -"' - ,>, -- ;··_·,~·c :J ... :_~ . .~c. ~ ~ '--- ~ \ UIW -~"ö~· t .# < J ~- ) l i -- Exhibit G-l HRZ Kalubik Fm ,. ~ Q) Cl. Cl. :J = Kuparuk Fm - C ::J ~ Q) 3: o -J = 9908' MD -8649.5' TVDSS ,. '- o ~ CD f1 t) a: CD '- >- ~ c - u ~ -- ..., a. w w 10,665 MD -9365.8' Miluveach TVDSS Fm ) ') '-~) Pt. ~clntyre Field Seabee Fm. Type Log Pt. Mcintyre #3 O. 100. ~-------~---~ÿ--------~ ~IOO. O. ....---------------. SI" "y 110. O. I 0It GAP I !)It GAl"' !OD. t 150. I MD SS 11100 , : ¡ J, :,. !.: I .: I I I I :-'700 I . \ \- . I I" I '- I I I : :: i J :< _ --""-' ) I j I -''''-i-' I i.~. ! 'i .! I r-~ , ....r-. t...:.. . ; _-,1"; .- F· -. ~:i.'J)¡ FT": : . '\ i :_..~: 1(: ~5~, " .'f.1., t > ì "I:~ .....~~...j ~"..:... -~r- .:, ", ¡... !,', ,,4 '~.,":,::,' :~~ .~¿ , ! , I ¡ ì .> I I , I 8750 11200 S800 ell50 e,oo 8900 8950 ...... 8400 9000 9050 8S00 :,'1100 _ I , .. ¡ISO. -- 111100 , ,.. ,.. ,- ,..g200 r I ,.. r I ,- I I ,..g2S0 r I I I , 11100 f"'"i300 r: r-93S0 8100 - '-9400 '- C. t'94SO 8toO .2 200. Þ------s;rü-õii;,:¡-----, .2 toO. I I L" 0HfWI ' .2 t I LoO OH"" 200. I .. ': þ ~ ~ .... Seabee Fm (Stump Island 5S) .... ..;.¡ :~.;:.~ . - .. ,.. .;.- .r; HRZ 8993'MD -8432.6' TVDSS (»4 ~ ~ - - - ~·o- ~ c: > - ~ o (1) :E~ ~a: Q.t 9288' MD -8724' TVDSS GIO -8502' .. ,~ c :::J Kuparuk Fm '- :: .. C1J )~ ~ .. . -.oJ ~ "- : Milu;;aCh Exhibit G-2 Top Kuparuk Formation Structure Map 6aoooo H'OOO I n8000 I I7ZOOO I 111000 I .eoooo I '''000 I lleooo I llZOOO 700000 S 'j LJl/ .f - I o i _tT'1 , >< J =r J .... . I-~ [ I CJ < I - VJ g~ ., ( ~6SOC "0 In EX,d61T.. . H" KUPARUK FORHfH ION STRUCTURE HAP C1 :: 50' 1".4000' AfO ALASKP · ~C. PT. HC I NTYRE / M~~yr~ .f It r--( RLK-2309 ~ C) ~-30-1S() ..~ 6 ICOHDI ~~ ~ I I I 8"000 aeeooo 1112000 ADL ~'i1 118000 4000 . I 1180000 8000 f..t I I 11"000 o , I 1 mile Pre I i m i n a r }' Preliminary 1 ."IIq UI = -.. I I I f.. 8000 I..' I I 4000 . o I I I 112000 1110OO I 188000 ADL 34124 I 18.000 I 18000O ADI 21Z17 178000 I 172000 RlK-Z309 9-30-15 .J ~ , &CONO) ~ I g- . - I I 116tOOQO (. 11.000 eaaooo /I EXHIBIT KU~ARUK'~OR"ATION ISOCHORE HAP CI = 50' .-.4000' Afi·~ ALASKA INC. PT. "CINTYRE /~ "- ~ ~.. øpt:H 3-sIlDL S1~Z1 RDL 311131 ftx~c ntyre ~fault' H- CII CJI .n ....... -I ~ ' ._1 I 100000 § I 1910OO ~ 882000 I lleooo I 18.000 I IDOOOO I 812000 I ~( <> VEX~ON Q,Q (CONol 0 () " ..~ -I c -Q ~ j\U \~~ u~ ~.~~r .. ... · ^ v 17SOOQ I IIINJOO I ...000 I I'· '??oo i ~. Kuparuk Format~ Isochore Map ..~ !? ß- . ¡ .. ..... .... -141M r{ ..,¿!.... I . . . . .. '4" I . . . . . .- .. ..q. _..... . .. J .. ;;J :1 '- ! (--'·"1 . ......-..... .. .......... ·····lE-; - - -..... .. . ...... j _ 8700 . ..1-1 45Q\ - o· . .' ¡ -- :.. .... ... t= Exhibit G-7 Kingak I Miluveach? -14:;):!U' .~... ......... .;... ..... '. ....¥..-... ....~ I .¡,,,. ..... .....". . ...,..~., .',. . ....- -14850 9000 1...·····..~ ..".. '. . ;.....- ..,~, .¡"..~.....- ...... ]1 . ....:: . . ...~ .. :. ,. .'.'- .......... ... .. f . ...... . . ....- . . .. ........... - 14800 -14750 8900 Kuparuk _..-... ._~::=}::: . - ... ::-·:~:::::·~l: :::: :::::: ...~. ..;........ .......;.,........ -14600 8800 -14650 ;........,............"..,. .... '..,........... ::: Gamma Ray Shale (HRZ) .. ,......."..... I;.·.........·" MD TVDSS (FT) (FT) O. I NPHI PU .2 2000. I- - - - - -( L;--o"Hiir1---- --I .2 2000.45. I----ï(õ-õttññ---- I West Beach Field Type Log ARC a West Beach #4 ) ) .i) . --\ .. ~ ~ ~ .;¡j¡¡¡¡¡r ~ J . 1 300. I 160. -t SOIt GAP I SOft GAP I 150. I o. I ) '"'v'" nt:u::iIlIH m ~ 'JJ ...... I ~ rc U'J ~ [fJ ...... 8 f'j ~ ~ ~ ÞO--' n ~ o 'JJ U'J (fJ rc f'j t"T ÞO-I . o ~ .-- > I > - ~ ,",r\~'" VO I.JV I $ruk V4!r .. at ion tTj >< =r ~. 0'" ~. ~ CJ I 00 "'-' Kupamk Formation Isopach Map ~ ~ 102023 AOO Reusing PBU Boundary -----------~--------------~-------------~ :,.. ~ ~ < ~ ~ AK92 ARCO-Exxon 34626 I ;. ~ ~ ~ ~ ~ ARCO-Exxon 34627 ~ ~ < I ~ ~ < '~¡I::V- '.:.~ .~:~. ".:. ':;" ':'. ~:'. "':'. ':'. .:: '.:. ':', .:. ':', r:~~ ~:~::. 7 ~~ "' ......~--' Proposed West Beach Participating Area . ..................-r.......~ } . ARCO-Exxon 34629 ~ ;. ~ ~ , ~ > ARCO-Exxon 34628 rT1 >< ::r þoooI- ~ þoooI- .... CJ I \.0 Beach Accumulation Gross Kuparuk Isopach West 11-5 Exhibit -9300· -91 00· -8900· -8700· Gul11 ."'; "GUII3 ... ,. . Exhibit G-IO ....... ...... .. .-....- _ J. WB4 -e:r -89501 I ~ ..,.... '"í J . ;'J - '. " "I.. '\ WB4 ~ -8751' . . . ". ' " . . . ~ . .:. ;~,::'. ';, ":<.~:..:.! "~. "~'J,.~~',..~ :i .":'.:'. "; , :,':, . ·'.'::-1 .,.... ."'::.. ".' ...:,'~ " . -. . ,I · E -8500. Not to Scale w.. West Beach Fluid Contact Information Ii ; ~ c o o C g ~ "" GO :.: c Map Top Kuparuk FOrmí,_~Dn Structure -~ -- AK92-102024 AOO Reuai~g ARCO-Exxon 34626 ARCO-Exxon 34627 ARCO-Exxon 34624 > > PBU Boundary ---------~-------------- ~ --...-/ j ~ 3 ullls 1 ARCO-Exxon 34629 , ARCO-Exxon 34628 tTj )( =r ~. 0"" ~. "" CJ I ~ ~ Beach Accumulation Top of Kuparuk Structure West 11-6 Exhibit PT. MCINTYRE r-'!ELOPMENT WELL SCHEM!~IC 5000' DEPARTURE LJL TRA SLIMHOLE (3-1 /2" TLJdING) Figure 1 j l2 3 -4 .... J ....5 J 6 J 7 J J 8 - 9 ~ lOX X - ~ 9 .11 ~ 12 a o o o o g 13 o o o o o o 14 ~~,~"""'~"""'~ .""""""""",. .""""""""",. . """" """"",. """"""""'" ~~~~~~~~~~~~~~~~~~~ 1 5 """""""'" """""""" """"""" """"" . .."", 16 Revision Date: 8-20-92 Well Status: Producer or Injector*. Surface Location: DS-P1 or DS-P2. Top of Kuparuk: -10,300' MD/8800' TVD. Minimum 10: 2.75" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 3-1/2", 9.3# 1 3-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 9-5/8" 47# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7" 29# L-80 PRODUCTION CASING (SURFACE TO -10,000' MD). 7. GAS LIFT MANDRELS (3-1/2" X 1 -1 /2"). 8. XO: 7" 29# L-80 TO 7" 29# 1 3-Cr @ -10,000' MD (-100' MD ABOVE PACKER) . 9. 3-1/2" PROFILE NIPPLE (2.813" 1.0.). 1 O. 3-1/2" X 7" PERMANENT PACKER @ -10,100' MD. 11. 3-1/2" NO-GO NIPPLE (2.75" 1.0) . 1 2. WIRELlNE REENTRY GUIDE @ -10,200' MO (-100' ABOVE TOP PERFORATION). 13. KUPARUK PERFORATIONS. 14. PBTD @ -10,850' MD. 1 5. 7" 29# 1 3-Cr PRODUCTION CASING @ -10,900' MD/9300' TVD. 1 6. TOTAL DEPTH @ -10,900' MD/9300' TVD. Exhibit 1-1 ) j ) PT. MCINTYRE [ )ELOPMENT WELL SCHEM/·-')c 5000' DEPARTURE SLIMHOLE (4-1/2" TUBING) l2 3 -4 ~ J ~5 J 6 J 7 J J 8 - 9 ~ lOX X EE 9 ." ~ 12 õ' o o o o g 13 o o o o o o 14 : "" """ """",. .,""""" '" """ .""""""""", """"""""'" .~~~~~~~~~~~~~~~~~~~ 1 5 """""""" """"""" -""""" .."'"", 16 ) Revision Date: 8-20-92 ;~j Figure 2 Well Status: Producer or Injector*. Surface Location: DS-P1 or DS-P2. Top of Kuparuk: -10,300' MD/8800' TVD. Minimum 10: 3.725" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-1/2", 12.6# 13-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 10-3/4" 45.5# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7-5/8" 29.7# L-80 PRODUCTION CASING (SURFACE TO ... 10,000' MD). 7. GAS LIFT MANDRELS (4-1/2" X 1"). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr @ -10,000' MD (-100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" 1.0.). 1 0. 4-1/2" X 7-5/8" PERMANENT PACKER @ -10,100' MD. , 1. 4-1/2" NO-GO NIPPLE (3.725" 1.0) . , 2. WIRELlNE REENTRY GUIDE @ -'0,200' MD (-100' ABOVE TOP PERFORATION). 13. KUPARUK PERFORATIONS. 14. PBTD @ - 10,850' MD. 1 5. 7-5/8" 29.7# 1 3-Cr PRODUCTION CASING @ - 10,900' MD/9300' TVD. 16. TOTAL DEPTH @ -10,900' MD/9300' TVD. Exhibit 1-2 PT. MCINTYRE r-VELOPMENT WELL SCHEM"~IC I 5000' DEPARTURI:: ~ONVENTIONAL (5-1/2" TlJdING) j -4 J ~ J 8 J 7 J J ~9 lOX X ::::: 9 .11 ~ 12 14 3 : """"""""",. ."""""""""V ~""""""""'" """"""""'" ~~~~~~~~~~~~~~~~~~~ 1 5 ~"""""""" """""""" """"""" """"" . ~"'" 16 Revision Date: 8-20-92 ....5 6 o o o o o g 13 o o o o o o l2 Figure 3 Well Status: Producer or Injector*. Surface Location: DS-Pl or DS-P2. Top of Kuparuk: ~ 10,300' MD/8800' TVD. Minimum 10: 4.455" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 5-1/2" GEN. IV TREE (INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 5-1/2", 1 7# 13-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 13-3/8" 68# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 9-5/8" 47# L-80 PRODUCTION CASING (SURFACE TO -10,000' MD). 7. GAS LIFT MANDRELS (5- 1/2" X 1-1/2"). 8. Xo: 9-5/8" 47# L-80 TO 9-5/8" 47# 1 3-Cr @ -10,000' MD (-100' MD ABOVE PACKER). 9. 5-1/2" PROFILE NIPPLE (4.562" 1.0.). 1 O. 5-1/2" X 9-5/8" PERMANENT PACKER @ -10,100' MD. 11. 5-1/2" NO-GO NIPPLE (4.455" 1.0) . 1 2. WIRELlNE REENTRY GUIDE @ -10,200' MD (- 100' ABOVE TOP PERFORATION). 13. KUPARUK PERFORATIONS. 14. PBTD @ -10,850' MD. 1 5. 9-5/8" 47# 1 3-Cr PRODUCTION CASING @ -10,900' MD/9300' TVD. 1 6. TOTAL DEPTH @ ~ 10,900' MD/9300' TVD. Exhibit 1-3 PT. MCINTYREìVELOPMENT WELL SCHE')TIC , 2,500' DEPARTURE SLIMHOLE (3-1/2" OR 4-1/2" TUBING)* ) ..J 3 4 .... J "'5 J 6 J J7 8 J } ;:::::;:::::;:::;:::::::::;::::: 9 , 0 :8: :8: ::;:;:::::::::;:;:;:;:::::::} 9 ~ 11 12 , 3 :&1. ~ ~ ~ 14 0 0 0 0 15 0 0 .Q. 16 17 \\ .Y 18 Revision Date: 8-20-92 Figure 4 Well Status: Producer or Injector**. l2 Surface Location: DS-Pl or DS-P2. Top of Kuparuk: -16,200' MD/8800' TVD. Minimum ID: 3.725" (No-Go Nipple). * 4-1/2" tubing is shown in schematic. With 3-1/2" tubing, tail would extend one joint into top of 5-1/2" liner. *'* Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-1/2", 12.6# 13-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 10-3/4" 45.5# L-80, SURFACE CASING @ -4900' MD/4000' TVD. 6. 7-5/8" 29.7# L-80 INTERMEDIATE CASING (SURFACE TO -15,600' MD). 7. GAS UFT MANDRELS (4-1/2" Xl"). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr @ -15,600' MD (-100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" I.D.). 10. 4-1/2" X 7-5/8" PERMANENT PACKER @ -15,700' MD. 11. 4-1/2" NO-GO NIPPLE (3.725" I.D). 12. TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @ -15,800' MD. 13. 5-1/2" x 7-5/8" UNER HANGER WITH TIE-BACK RECEPTACLE @ -15,800' MD (-300' MD ABOVE INTERMEDIATE CASING SHOE). 14. 7-5/8" 29.7# 1 3-Cr INTERMEDIATE CASING @ - 16,100' MD/8700' TVD (100' MD ABOVE TOP KUPARUK) '5. KUPARUK PERFORATIONS. '6. PBTD @ -17,150' MD. 17. 5-1/2" 17# 13-Cr PRODUCTION UNER @ -17,200' MD/9200' TVD. , 8. TOTAL DEPTH @ -, 7,200' MD/9200' TVD. Exhibit 1-4 PT. MCINTYRF r')EVELOPMENT WELL SCHF··~TIC , 2,500' DEPARTvl<E CONVENTIONAL (5-1/2' fUSING) j 3 4 ...... .J ~5 .J 6 .J .J7 8 .J ::::.:: 9 . ... . 10 :8: :8: . ......,.... 9 ... 11 12 13 zt ~ ~ ~ 14 0 0 0 0 15 0 0 0 16 17 18 Revision Date: 8-20-92 Figure 5 Well Status: Producer or Injector*. l2 Surface Location: DS-P1 or DS-P2. Top of Kuparuk: -16,200' MD/8800' TVD. Minimum 10: 4.455" (No-Go Nipple). * Schematic shown is for produdng well. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 5-1/2" GEN. IV TREE (INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 5-1/2", 1 7# 13-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 13-3/8" 68# L-80 SURFACE CASING @ -4900' MD/4000' TVD. 6. 9-5/8" 47# L-80 INTERMEDIATE CASING (SURFACE TO -15,600' MD). 7. GAS LIFT MANDRELS (5-1/2" X 1- 1/2"). 8. Xo: 9-5/8" 47# L-80 TO 9-5/8" 47# 1 3-Cr @ - 15,600' MD (- 100' MD ABOVE PACKER). 9. 5- 1/2" PROFILE NIPPLE (4.562" 1.0.). 1 O. 5-1/2" X 9-5/8" PERMANENT PACKER @ - 15,700' MD. 1 1. 5-1/2" NO-GO NIPPLE (4.455" 1.0) . 1 2. TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @ -15,800' MD. 13. 7" x 9-5/8" LINER HANGER WITH TIE-BACK RECEPTACLE @ - 15,800' MD (-300' MD ABOVE INTERMEDIATE CASING SHOE). 14. 9-5/8" 47# 13-Cr INTERMEDIATE CASING @ -16,100' MD/8700' TVD (100' MD ABOVE TOP KUPARUK) 15. KUPARUK PERFORATIONS. 16. PBTD @ - 17,1 SO' MD. 17. 7" 29# 13-Cr PRODUCTION LINER @ -17,200' MD/9200' TVD. 1 8. TOTAL DEPTH @ -1 7,200' MD/9200' TVD. Exhibit 1-5 ) ..J 3 4 ..... ) 7 ...16 ~ . .. .......... ::::::::::::::::::;:::::::::::: 8K .5<: ~9 11III 10 r 1 I I 12 5(1 11 Ijg ~ o o o o 14 o o .º- 15 ) 17 Revision Date: 1 2-1 5-92 P1-G I )PROPOSED COMPLETION ) 7" GAS INJECTION WELL lz ....5 "'13 16 Well Status: Gas Injector. Surface Location: Pl-Gl. Top of Kuparuk: ....8,618' MD/8,468' TVD. Minimum ID: 5.770" (No-Go Nipple). 1. 7" GEN. IV TREE. 2. 20" H-90 CONDUCTOR CASING @ ....80'. 3. 7",26# L-80 IPC TUBING. 4. 7" SSSV LANDING NIPPLE (5.963" 1.0.) @ ....2,000' MD/TVD. 5. 13-3/8" 68# L-80 SURFACE CASING @ 3,485' MD. 6. (1) GAS LIFT MANDREL (7" X 1-1 /2") 7. 7" PROFILE NIPPLE (5.770" J.D.). 8. 7" X 9-5/8" PERMANENT PACKER (6.00" BORE) @ ....8,330' MD. 9. 5-1/2" PROFILE NIPPLE (4.562" 1.0) . 1 O. 5-1/2" NO-GO NIPPLE (4.455" J.D) . 11. 5-1/2" TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @ 8,432' MD. (TAIL IS PERFORATED BELOW NO-GO NIPPLE). 12. 7" x 9-5/8" LINER HANGER WITH TIE-BACK RECEPTACLE @ 8,432' MD. 13. 9-5/8" 47# L-80 INTERMEDIATE CASING @ 8,607' MD. 14. KUPARUK PERFORATIONS (8,615'- 8,710' MD). 1 5. PBTD @ 8,750' MD. 16. 7" 26# IPC 13-Cr PRODUCTION LINER (8,432' - 8,840' MD. 17. TOTAL DEPTH @ 8,840' MD/8,677' TVD. Exhibit 1-6 STRADDLL ~OMPLETION WELL SCHEN.. . .-IC 5000' DEPARTURE SLIMHOLE (4- 1 /2" TUBING) ..J 3 4 ... .J .J .J .J .J Well Status: Injector lz Surface Location: DS-P1 or DS-P2 Top of Kuparuk: - 1 0,300'MD/8800' TVD Minimum 10: 3.725" (No-Go Nipple). 1. 4-1/2" GEN. IV TREE. 2. 20" H-90 CONDUCTOR CASING @ -80'. ~ 5 3. 4-1/2", 1 2.6# L-80 TUBING. 4. SSSV @ -2000' TVD. 6 5. 10-3/4" 45# L-80 SURFACE CASING @ -3,800' MD/3500' TVD. 7 :-..............,:. 8 9X x 10 ::::=:J 11 J 131 I ID1Z ..J14 >< X 15 1 6 :::::: BE 17 , ,18 o o g 19 o Revision Date: 12-22-92 6. 7-5/8" 29.7# L-80 PRODUCTION CASING (SURFACE TO - 10,000' MD). 7. GAS LIFT MANDRELS (4-1/2" X 1 It). 8. 4- 1 /2" PROFILE NIPPLE (3.81 3" 1.0.). 9. 4-1/2" X 7-5/8" CR PERMANENT PACKER @ - 10,000' MD. 10. 4-1/2" PROFILE NIPPLE (3.813" 1.0) . 11. 2 - 4- 1 /2" X 1" GLM. 1 2. STUMP ISLAND SANDSTONE PERFORATIONS. 13. 4-1/2" BLAST RINGS. 1 4. 4-1/2" x 1 " GLMs. 1 5. 4- 1/2" X 7-5/8" CR PERMANENT PACKER @ - 10,200' MD 16. 4-1/2" PROFILE NIPPLE (3.813" 1.0). 17. 4-1/2" NO-GO NIPPLE (3.725" 1.0). 18. 4-1/2" WIRELlNE RE-ENTRY GUIDE (100' ABOVE TOP PERFORATION). 19. KUPARUK PERFORATIONS. Exhibit 1-7 <> .... . ,WEST BEACH Dr )~LOPMENT WELL SCHEMA~l 1 0,000' DEPARTURE ULTRA SLIMHOLE (3- 1/2" TlJSING) )..J l2 3 -4 .... J "'5 J 6 J 7 J J 8 _9 ~ -) 10 X :8: i1E9 .11 ~ 12 'õ o o o o g 13 o o o o o o 14 :""""""""", .,""""""""" .,""""""""" """"""""'" ~~~~~~~~~~~~~~~~~~~ 1 5 """""""" """"""" ~""""" . ......,..." 16 ) Revision Date: 8-24-92 , Figure 1 Well Status: Producer or Injector*. Surface Location: West Beach Pad. Top of Kuparuk: -13,900' MD/8800' TVD. Minimum ID: 2.75" (No-Go Nipple). * Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no 1 3-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 3-1/2", 9.3# 1 3-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 9-5/8" 47# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7" 29# L-80 PRODUCTION CASING (SURFACE TO -13,600' MD). 7. GAS UFT MANDRELS (3-1/2" X 1 -1 12"). 8. Xo: 7" 29# L-80 TO 7" 29# 13-Cr @ -13,600' MD (-100' MD ABOVE PACKER). 9. 3-1/2" PROFILE NIPPlE (2.813" I.D.). 1 O. 3- 1/2" X 7" PERMANENT PACKER @ -1 3,700' MD. 11. 3-1/2" NO-GO NIPPlE (2.75" I.D) . 12. WIRELlNE REENTRY GUIDE @ - 13,800' MD (- 100' ABOVE TOP PERFORATION). '3. KUPARUK PERFORATIONS. 14. PBTD @ -14,650' MD. 1 5. 7" 29# 1 3-Cr PRODUCTION CASING @ -14,700' MD/9300' TVD. , 6. TOTAL DEPTH @ -, 4,700' MD/9300' TVD. Exhibit 1-8 WEST BEACH rr-VELOPMENT WELL SCHEMÞ TIC 1 0,000' DEPAR I ~RE SLIMHOLE (4-1 /2" TUbll~G) ..J 3 =4 .... J ....5 J 6 J 7 J J 8 :::9 lOX X :::39 .11 ~ 12 õ o o o o g 13 o o o o o o 14 : "" '" ""'" """ . """""'" ""'" . """" """"",. """"""""'" ~~~~~~~~~~~~~~~~~~~ 1 5 """""""" """"""" """"" . ~ """ 16 Revision Date: 8-24-92 Figure 2 l2 Well Status: Producer or Injector*. Surface Location: West Beach Pad. Top of Kuparuk: -13,900' MD/8800' TVD. Minimum 10: 3.725" (No-Go Nipple). * Schematic shown is for producing weH. Injection well tubing and production casing is L-80 (no 13-Cr). 1. 4-1/2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-1/2", 1 2.6# 1 3-Cr TUBING. 4. SSSV @ -2000' TVD. 5. 10-3/4" 45.5# L-80, SURFACE CASING @ -3800' MD/3500' TVD. 6. 7-5/8" 29.7# L-80 PRODUCTION CASING (SURFACE TO - 13,600' MD). 7. GAS LIFT MANDRELS (4-1/2" X 1 It). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr @ -13,600' MD (-100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" 1.0.). 1 O. 4-1/2" X 7-5/8" ÆRMANENT PACKER @ -13,700' MD. 11. 4-1/2" NO-GO NIPPlE (3.725" 1.0) . , 2. WIRELlNE REENTRY GUIDE @ - , 3,800' MD (-100' ABOVE TOP PERFORATION). 13. KUPARUK PERFORATIONS. 14. PBTD @ -14,650' MD. 1 5. 7-5/8" 29.7# 1 3-Cr PRODUCTION CASING @ -14,700' MD/9300' TVD. , 6. TOTAL DEPTH @ -, 4,700' MD/9300' TVO. Exhibit 1-9 WEST BEACJ-J ~VELOPMENT WELL SCHE- ·'t TIC , 2,500' DEPARTURE -:>LIMHOLE (3-1/2" OR 4-1 I£. TUBING)* Figure 3 )j 3 4 ... J "'5 J 6 J ...17 8 ...1 ) ~:;:':':':;';':.::;';':...:.:: 9 10 g :8: ~::;:::;:::::':::::::::::::/ 9 -. " 12 13 :& ~ ~ ~ 14 0 0 0 0 15 0 0 .Q. 16 17 18 ,) Revision Date: 8-24-92 Well Status: Producer or Injector**. lz Surface Location: West Beach Pad. Top of Kuparuk: -16,200' MD/8800' TVD. Minimum 10: 3.725" (No-Go Nipple). * 4- 1 /2" tubing is shown in schematic. With 3-' /2" tubing, tail would extend one joint into top of 5-1 12" liner. ** Schematic shown is for producing well. Injection well tubing and production casing is L-80 (no' 3-Cr). 1. 4-' /2" GEN. IV TREE (STAINLESS STEEL OR INCONEL INLAID). 2. 20" H-90 CONDUCTOR CASING @ -80'. 3. 4-' 12", 12.6# , 3-Cr TUBING. 4. SSSV @ -2000' TVD. S. 10-3/4" 45.5# L-80, SURFACE CASING @ -4900' MD/4000' TVD. 6. 7-5/8" 29.7# L-80 INTERMEDIATE CASING (SURFACE TO -15,600' MD). 7. GAS LIFT MANDRELS (4- 1/2" X 1 "). 8. Xo: 7-5/8" 29.7# L-80 TO 7-5/8" 29.7# 13-Cr @ -15,600' MD (-100' MD ABOVE PACKER). 9. 4-1/2" PROFILE NIPPLE (3.813" I.D.). 10. 4-1/2" X 7-5/8" PERMANENT PACKER @ -15,700' MD. 11. 4-1/2" NO-GO NIPPLE (3.725" I.D). 12. TUBING TAIL LOCATED IN TIE-BACK RECEPTACLE @ -15,800' MD. 13. 5-1/2" x 7-5/8" LINER HANGER WITH TIE-BACK RECEPTACLE @ - 1 5,800' MD (-300' MD ABOVE INTERMEDIATE CASING SHOE). 14. 7-5/8" 29.7# 1 3-Cr INTERMEDIATE CASING @ -16,100' MD/8700' TVD (100' MD ABOVE TOP KUPARUK) 1 5. KUPARUK PERFORATIONS. 16. PBTD @ -17,1 SO' MD. 17. 5-1/2" 1 7# 1 3-Cr PRODUCTION LINER @ -17,200' MD/9200' TVD. 1 8. TOTAL DEPTH @ -, 7,200' MD/9200' TVD. Exhibit 1-10 Exhibit J-l Beaufort Sea Source Water Analysis Oetermina tion Summer Winter U ni ts Specific Gravity 1.013 1.024 pH 7.5 7.8 Mg/L Calcium 196. 365. Mg/L Magnesi urn 631. 1190. Mg/L Sodium & Potassium 5680. 10400. Mg/L Strontium o. o. Mg/L Barium o. o. Mg/L Iron o. o. Mg/L Bicarbonate 85. 142. Mg/L Carbon Dioxide Calc. o. o. Mg/L Total Dissolved Solids 17852. 32787. Mg/L Hydrogen Sulfide o. o. Mg/L Resistivity @ 70°F 0.422 0.255 Ohms Chloride 9880. 18200. Mg/L Sulfate 1380. 2490. Mg/L Suspended Solids 6.0 1.0 Mg/L Exhibit J-l ) ) Exhibit J-2 ) Lisburne Produced Water Analysis Detennina tion Value Units pH 8.5 Mg/L Calcium 105. Mg/L Magnesium 50. Mg/L Sodium(calc} 10555. Mg/L Sodium (AA) 13875. Mg/L Strontium 3.8 Mg/L Barium 1.1 Mg/L Iron 1.1 Mg/L Hydroxyl O. Mg/L Carbonate 228. Mg/L Bicarbonate 2618. Mg/L Chloride 14261. Mg/L Sulfate 750. Mg/L Total Dissolved Solids 28753 Mg/L ) ,) Exhibit J-2 Exhibit J-3 Pt. McIntyre Produced Water Analysis Oeterrnina tion Value U ni ts pH 7.2 Mg/L Calcium 24. Mg/L Magnesium 9. Mg/L Sodium 8540. Mg/L Potassium 179. Mg/L Strontium 7. Mg/L Barium 11.0 Mg/L Iron 1.4 Mg/L Hydroxyl o. Mg/L Carbonate o. Mg/L Bicarbonate 3262. Mg/L Resistivity @ 68°F 0.373 Ohms Chloride 10597. Mg/L Silicon 24. Mg/L Exhibit J-3 ) ,) ) Exhibit J-4 ) Injected/Produced Gas Stream Analysis Component Lisburne Pt. McIntyre West Beach Mole % Mole % Mole % Hydrogen Sulfide 0.01 * 0.00 0.00 Carbon Dioxide 13.27 5.92 9.88 Ni trogen 0.72 0.51 0.52 Methane 77.74 81.48 75.90 Ethane 5.23 7.59 7.08 Propane 2.27 3.02 3.10 I-Butane 0.31 0.34 0.58 N-Butane 0.40 0.67 0.93 I-Pentane 0.03 0.13 0.22 N-Pentane 0.03 0.15 0.24 Hexane 0.00 0.09 1.56* Heptane+ 0.00 0.11 Sample date: 3Q 1992 2Q 1989 3Q 1991 * 94 PMM H2S "'C6+ The Lisburne composition represents the current injection gas stream. The Pt. McIntyre and West Beach compositions represented produced gas streams. ) Exhibit J-4 1 - ~ i- i 7? ~ ~ Exhibit N-l -1 ~ 0 Ll i....... ~"1 ~ '--: L-, CI L.-.,- 1 I t - \- Q.. q .. . ~~ West. Beaêh Prudhoe Bay Poinl McInlyre ~ Expanded Eastern Operating Area i WOA EOA ~ I~\, ¡ ~ ) Exhibit N-2 ') Documentation of Equations Used to Calculate Formation Water Salinities From Well Logs 1. Formation Temperature: Tfm = 0.0222 (Depth fm - Depth base of permafrost) +32°F 2. Porosity from Density Log: Ød = Dma - Db; Dma = 2.65, Df = 1.0 Dma - Df 3. Porosity from Sonic Log: Øs = 0.625 (dt - 55) dt 4. Apparent Formation Water Resistivity: Rwa = ø2.15 x Rt 0.62 ) "I 5. Water Resistivity @ 75°F: Rw @ 75 = Rwa Tfm + 6.77 81. 77 6. TDS (NaCI equivalents) = (3.562 - Log (Rw @ 75 - 0.0123» 10 0.955 Step 1) Determine formation temperature. 2) Determine porosity from either the sonic or density logs. 3) Calculate apparent formation water resistivity by using: F = 0.62 ø2.15 Humble equation for unconsolidated rocks Rt = True resistivity of 100% water saturated formation 4) Convert to water resistivity at 75°F. (Schlumberger equation) 5) Calculate TDS in ppm. (Dresser Atlas equation) ) Exhibit N-2 Exhibit N-3 Prudhoe Bay Field Pt. McIntyre Pool Calculated Wireline Salinities Interval Well Subsea Depth Calculated TDS (pprn) T-8 P2 -4 9 ( -3,850) 19,469 T-5 P2 -4 9 ( -4,279) 13,935 PM -08 (-4,153) 17,047 T-3 P2 -4 9 ( -4,690) 14,726 PM -08 ( -4,503) 17,604 Ugnu P2 -4 9 ( -6,834) 19,773 PM -08 (-4,931) 21,900 W.Sak P2 -4 9 (-7,114) 10,402 PM-08 ( -6,630) 20,418 Kuparuk P2-49 (-9,119) 20,000 PM-08 (-9,290) 17,000 Exhibit N-3 ) Tertiary /Upper Cretaceous Water Analysis ,-"eoaaToav NO, 1'1.7"'~R '''....\.I..el.vla '1. 1 -" .7A ~~SU'-TI.c.oaT.~ 1'-~-7R ~OM~AHY AP1.ftP~~_Q.~~'i.1A r~~.~ 1'1 ~'- 0 oa -OOL. SICTtON _ ."OCK _ Iuavcy sou"CI 0' S"""\.I "NO OAT. TAKIN: p2w water-taken from Sahio water well ICC-3C @ 11:15 am. 11-4-78 (ør...ura cyl!Ddt NO. t Raw watar-taken fro~ Sanio watar well IGC-3C ~ 10:20 am. 11-4-78 (plastic bottle) NO.2 F.Qual mixture of Sohio watar wall IGC-JC taken 11-4-78& Sahio water wall IGC-31 NO.1 taken 8-20-78 (preslur. cvliDdars). NO.' "þU"UClI Cre taeaoUI CN....c::A1. AND flMVI.CAI. IItItO.....TIU NO. t NO. I t.n1'~ '1..n"n . . & ) ~,o. eo.,... ...O..A..A.... TDA. ,.,.. ~MCNt. ...,... .. ....0.0 ) TO: MP _ . L It _ M,.. f\to!¡'\I 1 tI, . Top - P n ~~Y ?AtQ, Q~. T_y-. ) ,...."c c:¡,e..ty .. .. fl. .... ...... s...e.. .... '"-' ........ IICIñeft- .. t<Ot 541..,........... .. c:.c:oJ \JftMruDll'M1. .. CaCOt T... ~..... u c::.cot Ca.Ch.... .. Ca ~...'"" .. .... s..."", MIfI. ......i... "'1". .. so. Ohwl". . C:I I,.,. .. ~. I.""", .. I. Tw,...lrr. If...,. c:..., u lIlt Teca. Sell... CaI.I." T ...........,. .-. ~ 01..... <:alcu..... 01.".'" 0..,... .,..... ~"'" h''''. _...,þ""'. .....,... . ,,. fl. ~....... oe. IIi I era'" Sefift _ ...". V.tWfte lit IceNIt. .... Carbon D1oxid.~ Titrated *Toeal c.arbOll D1ox1d.... c;ravimacr1c Strontium. u Sr Marti n Wattr laboratarill. Inc "" W, INDIANA MIIM.YID. ftXM .,.701 ....... ........ L.IASI P~,t4h,.,. RV W. r.-rf' ru~d COUNTy S"AT. NO. a 1 A 0"9 NO.. 7 .n7 7. 17 6.76 464 464 1.7'i7 t; '4 (] 'i_t;M 'i.tinn '.7M 9~n 99n 690 7ti9 "" 4An l'i.414 1~.-;'7 t t "'44 0 0 '4 2.1.520 27.~97 19' . R A ti 6.1 5.9 1~'\ 1A' "7 7A '\ ,. /a-~,'nQ ~fj _ ~v·n 1'\., 7 Ii ~ 74 -;7 'if" 8:î73 0.0 0.0 0.171 0.226 0 5.0 19.1 11.9 52Q 910 488 44 993 53 53 ..Ie,..... 0...-...... .... "-- -...... ~'n t - ~ ~ ............ ,.., 1.,;_ ) ~ et'!t .... J ." Exhibit M-l ---,~'."., _..,,-----",'''~ .~ . Martin Water laboratories. Inc Tertiary /Upper Cretaceous Water Analysis ",~.=AN7~"O' JI'MOHtI ......... I.A.OIIIA TOIIIY NO. 117Rl qA (~. IL 'J sA....'-a lIt.calvea 11-21-7A ØIIESU'" TS ØII.,.OIltTC'" 1 '-C;-7A ".0.80.'... ..O..A"A.... TDAa 7"7'. ..MO... ..~..." .. ....0.0 1'0: ~. .r. P. Mr-1'Qla1't. fr. PaO.Kny 1R19. n.',.._ T~T~. CO....ANy At"1""~1....-1li...nfi_1t4 r.n"\P-V I.EASe PT'urlhna RJ\Y ~At"..~f'nnA Ifte",o 0" "OOL SEC:TION_ aLOCK_ SUftVey COUNTY STATC soulllc:a Oil' SAMII'1..& AHO OAT. TAKaN: NO.' Raw wa;..~-t~~-" f~o~ ~nhin w~r_r w_11 fr~-ln ~ ~:~On~. 11-5-7R (Pr"~~ur~ I""v1inri.r) Raw water-eaka~ f~oft Sobio watar well ICC-3D @ S:30øm. 11-5-78 (plastic bottle) NO. Z Equal 1Iixtura of SoMo atar wall IGC-3D taken 11-5-78 & Sohio water 'lieU IGC-3B NO. I takaD 8-20-18 (pr...ura cylindar.). NO. . ".MARK.. 0.0 o . 1 85 o 4.3 490 1~ 1.039 71 73 "-_,. ,.~ t - ~ ...111..... ~ Li... A4411t1..... O"""',.þ......... ........ * Th11t n,.1 W".. bo"hfre~r"~ rtioYirt~"{. ,.~,4 tift u b1carbot1ata. s..ciftC Grew'ey .. W ..~ .... ..... s...... ÞM Wheft ~... .,..,..... .. HCOt ,.,..,............ .. c.cos UMeru........ .. CM:OJ T... . h[ ."'88 .. CaCOI Ca'CiUM .. c:a ,........,... .. .... S..uM ~_ ~....... Su,". .. so.. o.lorl.. .. <:1 I".. .. ,.. Ian"", .. .. 1'",...I~. .Iean. Color .. ~ T'ocat $ea.... Ca........ T emeeraawe .,.. Cat1Mft 01..14". Calcyl." 01....... 0."..... Wl....._ H,od....... S...,... "....b".cy. oftIRe/'" M 7~ fl. s"......... 011 ~lIn... s..la .. "",. V.'ume "1 I~. ",. C:HIIMICA&. AND .....V.ICA... ""O".RTf" NO. t NO. I 1.0291 1.0186 7. 16 7.O? 19' 176 l' ~ 6..6o.n 6.~On t_~'n t_~nn 6An ~~, 1 "L 99" 1,_g?1I} n n '';a'77 ''','77 9.1 9.' ~t;, '4t} 4 A ""g?n 4',~1)-; 2S )4 0.0 O. 186 25.8 910 Carbou D1o"lP"'f rie. Ti "r.ted *total ~b01' Di oY'f tie. Grav1mat:r:f,. Stronri JmI. tI S:r TA"~.~ n' ~.~n~ft~.r1nn ~rr.,.~A_ NO.1 1.n"~ NO.. 6.74 1_"~tI} An l,qnn 1 ,nnn "In 11 ,~7n " lQ'I\'m '..? 9' 1/, ,nqo 5'3 0.0 0."9 18.t 465 Aio7trt, .nA th, r~rhnn II...... He. J / ,,-- .Co".,. . "'---- - ;- .,' . .. Exhibit M-2 . '" .... -,.., ~ .,. ... , - ". ".. . ", Ip Way 1. c. MartiA, K. A. , ... . -¡¡-'..., .!". lID TVDIÍ .. -, · - __-.:_i.è-~_ 0_. ==- _ ., _ " pt- ~~.... .. _jo.. ::: -.. r-_ ~-1~: :: '~T ~. ~ so;:- ~-:fo:: ----~- Se~==~~_:: - < :::. - "t- - ? . a \ _ _ _ _ _ '¡- -~~:::~-::=;~-~;;;- -:~~~::~.:.~~:... -r:~--l- :~~,_:~ J ~._ _ ~ . -\-~~. !:'~~": -If Kalublk .~_ '~:=rC:::__~,._ _ . "_: .,_, _ ; ~::'"':- -,: _ _ . _ ~ ~ - . i· ~ "- · ~ - - ~_ C>- - ~. ~ "7- ~____m_ . ,"<,:' -. - . . --. -f¡------- - ~ - '-<. or-: .J:: - J¡t Ka u ~ ____________~ ""pp" "";0- M''''' d l:- -::: ¡ . Kuparuk :1,' ( !..' 4:~ ~____________ _~ y~__. . {____""" -. --. · !. -: i: ", "'" -~~~-.;~:_-_~-_~~~.{~~~-~~:~~::.;==::~~~~~~:::~-~:;-~:::-1,0 -~::.~ -KuparL k___~_{ - ~ ------- --- )1'LOW~: "";0- 011 _ _ 1. ____ __ __~ . :\. . < ----"4 __.. , "" , . -wãi;'- _+__.__ - .... -<, , ~,~ ~_ '; ') ~ t 1 ~ . - - .. ..L. i .~-., ~ -outh , ~ 1 ~ 1 ~ . MCIN1YRE 3 ~ ~ ~ 029 - 2 I 7 7 9 -. 00 . MCINTYRE 4 PT ' 2 00 50-029-2191 - A' North . MC INTYRE 6 PT. 22000-00 50-029- . MCINrYRl 9 P 1 . 6 00 029-2209 50· '~a .',..~ -. . ...._~.- ~. .. o ~--- 6300'-' ~_._'" "ï- ... t ..._-iiPt.... ,. - .... ... . .!. ... -. ;:·'_-4000'_- c )-- ::_5600'~~ ,W , - "" 0..- -. , 1,,0 '.~. ~DIII , "D "'.osS 'M. lID ~ ì¡D~ - ..' -.--- - ... . ----.. I . ' . . . . Mlluveech ~ ( ( ( Index Map :' ..,' A - "--7' ( 1 Mtly.. 1. ..: ." .:r " , A Vcrtlçul Sçulo 1'" 100' I Horizontal ~çalo 1"~2000 crlll'.(. Vertical Exogg ... 20:1 t Exhibit (;·5 A~ I ka Inc. ",. ARGO ~.~~....~<~~_, .......d~ ····--·---······Fi Id .......---..-.pl. Mclntyro 0 h North Sout . - c...('tion (' oss ...x: , Structural Á~A' ~'~f;;.J-,·' ¡")::2 :::~. AK91 ~'¡19Õ:; AOO ( Index Map '''I., 1'1 I' ._--~- \' .~ 'k-,IJ~. - ~.'_~':~'~ ..-~. :1' ..,(.. \. '''I'' , I. ~I'" ):.~ . \:1 ~I ' U;~. t. ' . ' 1"" , · ~ < .. ,. " 3_ . . J~ ~~:' \ " ~:s.'. .. Hille ARC:O Alaska, Inc. Õ- ~~...~ ..,.... -.... . PI. Mclntyn field . West - East Structural Cro.. Section 8-8' ·1-. I @_----4 . I .I..~'.. - "I.... \ I '" \~;, .", ~' I· I~ - - --,-.-¡;;;;;;;-- . .t-·"L AKI1 071to:J 800 .1. \1' ' '1 ". . " III.. ..........-¡t~ ............. ~'.- ......:~··AL" Vertical Sc." ,'. 100' B West. ---. Horlzont.1 Seal. ,".2000' V.rtlcal Exagger.llon 20:1 Exhibit G-b -9- PT .STORKERSEN 1 50-029-20015-00 . PI. MllNllRI 11 S Ü . lJ;~ 9 . :~ ~'I \ 4 110 . 1-'1. M(INl1Rl ,.\ SO·· u 2 9 - :: I 'I I :-, I I . f· I. t11 I tJ I I R I ' ~,ll IC'I '.' 1' (I \111 l [j East 'Ii! . ..,' _..... - - "'- · ' - n'" ...... -' ~.. -....., ...... .; ..'" ~:, ,~: ' ~ ~ . ___ --:T1E~' ~=_-J.]~~:"~ì:-:~-··t- "--:~:m~~ ,,- :~"""" \:.---"'"'~ :;::¡:¡.. 11 .-- ~~ HIIZ _. .,,; -' - -~- ~-., iä.;.~' ,;,: .', .;..;.--} - -, --?----- ~~ H1U~J'f=:..- î.~' ~'-7~:~='''( ________~~~:~.=t' HRZ W:lr #~. J ~?~ .1i-~~:\~-i-';: .__~_..___..K8IUb'k~ /----.~.-.... .-\.... .....:.. .,. 2" ~~.. '.,: ~.:._....~,' \. L.L, \ j.~_~. ~, ;~.~ ~ -t ..~?- . -.t:. ...~ ~ ~_: 1 . ~< ........... '--.'V .-" --~ ' ¥ -' -... ~ I ' '+4-;; , ' . .- -------- ct" =--- - ....." ""'" .¡: . . . . Kalublk -/ .- . . .-- ,.:1- --------.. ~ 1+ßn\:: ___ n=-~--~= :.:':~~(=: --~~:~~~-'"..,<.<" - "_-~~~::~~//'l~'-:c-'~-: . . t ~. t...~: l'.;!; j¡. ~!:-~.¡.:.-.'.~.'~~ .... 1- --t~~~;=¡;¡':'::'_-";- _~-;;~,-----_-~':.2!1:-_,,:;,~~;;;;;~,,::,,----.'~--:;;:'__--!~2~'___- - . ·:S·..:. ...:, 1:" ..-...-....----- '-..", _ ' Kup.",k . . . . -- W.I", t:- t - ----------- ~-----~..------ ___.~-______"'c_______ ..1\ ¡ i ¡ t" .._- "'---. ~ . ~.:.':" - :.;_.~ .:-_-_.~--:>--~-). ~ = ~-~- :'.. . '\ ,n~" .. ~ ----- :.:FI)I' \.~..t.......+-............. ---¡"------ ",,,----- -.--- LowerUnU" .--.........---. - :1. ..'. ... _____ . ,¡.; . ..' ..... . 1 I ( : 1.,- h..-· ---- " p--:: '-'.". ..' ---'" ~ . - -. r- .., -1- Mllu...ch f L~:~.::'t·~j··": ~ /\' \¡\!::=-j,==~,::..=·t:-:·· ~- · ... ~_. --~---- ~ \ ¡'\ \.1~.·_';""· - .-- ~' : ___i_~.. -r·· ... .... . . . _~_....: ...._._ ¡.~ ....___.___. -J..-. -..--.. . .. .-.. - . 0- " ,.. ,. .-. - . ·a, .. . - .. .... ,.. ( ( ( ( #1 )) I /:\\ 111;, (I i J) .II /d\ I 11\\" ,\ li,¡ It\ ~::J It \ :}) ../ \\ L \. \ 'it WALTER J. HICKEL, GOVERNOR 'I' , ,I ALASliA ()IL ANI) GAS C«)l\TSEII.VA'l1IOl\T COl'll'IISSIOl\T 3001 PORCUPINE DRIVE ANCHORAGE. ALASKA 99501-3192 PHONE: (907) 279·1433 TELECOPY: (907) 276-7542 Dccember 30, 1992 Mark J. Schindler, Director Exploration Permits and Compliance AR CO Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 f\ \\:) d- \S k\ü ~~ Dear Mr. Schindler: The Commission has review your December 18, 1992 proposal, as modified by Lisa Humphrey's submittal of December 28, 1992. The Commission now understands that ARCO desires to use treated domestic wastewater for use in mixing drilling muds for exploratory wells. The Commission supports environmentally sensible practices that minimize waste production through beneficial use or recycling operations. ARCO's proposal to use treated effluent as a make up stream for drilling muds is far superiof to surface discharge of this waste stream. We have no objections to this proposed practice. The Commission does not view the preparation of drilling muds as a practice regulated under the UIC program. Ultimate disposal of drilling muds in a Class II well would depend on whether Of not the drilling mud has been brought to the surface. c cc. Simon Mawson, DEC H. Geren, EPA L. Humphrey, ARCa '0" ,"'" ,.