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Home My WebLink AboutAIO 004 ) ) 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. A:to ODlf Order File Identifier Organizing (done) o Two-sided 111111111111111111I o Rescan Needed 1111111111111111111 R~CAN tJ Color Items: D Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) o Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, NolType: D Poor Quality Originals: o Other: OVERSIZED (Non-Scannable) ~09S of various kinds: NOTES: o Other:: vv) II 1I111 II m-.? = TOTAL PAGES .2 ~O (Count does not include cover sheet) N¡ J Isl I I Isl BY: ~Mar~~ ) Date: ~ fd-/b~ Project Proofing BY: ¿--Maria J I Dale: It. I~, (J to Isl Scanning Preparation BY: ~ x 3q = I Date: Lþ 1;)- O~ + Production Scanning Stage 1 Page Count from Scanned File: ~:ì.. j (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES BY ~ Date: 4-/I;)"¡O~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES 11111111111111111I NO /5/ m 0 NO BY: Maria Date: Isl I1111111I11111111 Scanning is complete at this point unless rescanning is required. ReScanned 111111111111111111 BY: Maria Date: /s/ Comments about this file: Quality Checked III1I111I1111111111 10/6/2005 Orders File Cover Page. doc 1) December, 1980 2) May 21, 1986 3) November 4, 1986 4) October 17, 1988 5) March 13, 1989 6) July 15, 1990 7) July 16, 1990 8) April 19, 1991 9) May 8, 1992 ') ¡' ~i INDEX AREA INJECTION ORDER NO. 4 PRUDHOE BAY UNIT Application for Additional Recovery by Waterflood Application (Confidential Information filed) EPA's Ltr : Termination ofEPA Emergency Permit Injection Well Annular Communication verbal notification ARCO requested information PWI/SWI Ltr from ARCO to AOGCC re: Injection well state mechanical integrity testing Ltr from ARCO to AOGCC re: Injection well state mechanical integrity testing Ltr from ARCO re: Annulus Pressure Monitoring ofUIC Wells Ltr from ARCO to AOGCC re: updated information AREA INJECTION ORDER 4 All Annual reports are located in the Field Files '. 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: THE REQUEST OF ARCO ALASKA, ) INC. for an Area Injection ) Order for that portion ) of the Prudhoe Bay Unit ) commonly known as the ) Eastern Operating Area ) Area Injection Order No. 4 Eastern Operating Area Prudhoe Bay Unit July 11, 1986 IT APPEARING THAT: 1. ARCO Alaska, Inc. (ARCO) requested the Alaska Oil and Gas Conservation Commission to issue an Area Injection Order permitting the underground injection of fluids within the Eastern Operating Area df the Prudhoe Bay Unit for purposes of enhanced hydrocarbon recovery and the disposal of non-hazardous oil field waste fluids. 2. Notice of an opportunity for a public hearing on July 16, 1986 was published in the Anchorage Times on June 9, 1986. 3. Neither a protest nor a request for a public hearing was timely filed. Accordingly, the Commission will, in its discretion, issue an order without a public hear- ing. . FINDINGS: 1. An order permitting the underground injection of non-hazardous fluids on an area basis, rather than for each injection well individually, provides for effi- ciencies in the administration and surveillance of underground fluid injection operations. 20 AAC 25.460 provides the Commission with the authority to issue an order governing underground injection operations on an area basis. 2. The Eastern Operating Area constitutes a compact "proj- ect area" for the operation of a portion of the Prudhoe Bay Unit and can readily be described by governmental subdivisions. The Project Area is operated by a single operator. 3. The Project Area encompasses approximately the eastern one-half of the Prudhoe Oil Pool and~li of the Lisburne Oil Pool. The Project Area includes all existing injection wells and injection well sites planned for enhanced recovery from this portion of the er' 6' ~\~'\~ f-'I', II I ¡I! t'i¡ n 20 ('¡II ~"""rM \1 hH= r,,, , d ~J \j ,;1: ~ß '- u... ,~ \ Area Injection Order No. 4 Page 2 July 11, 1986 & '~I, Prudhoe Oil Pool, and from all of the Lisburne Oil Pool. The Project Area includes all existing injection wells and injection well sites planned for disposal by injection into Cretaceous and Tertiary strata of oil field waste fluids developed from the operation of this portion of the Prudhoe Bay Unit. 4. The vertical limits of injection strata and the con- fining formations may be defined in the ARCO (Atlantic Richfield-Humble) Prudhoe Bay State Well No. 1 and the ARCO Sag River State Well No.1. 5. Within the Project Area, injection into, through, or above a fresh water aquifer or underground source of drinking water will not occur. 6. The strata into which fluids are to be injected will accept fluids at injection pressures which are less than the fracture pressure of the injection strata and their confining formations. 7. Less stringent requirements for well construction, operation, monitoring and reporting of injection operations may be more appropriate than would be required when injection occurs into, through or above portions of aquifers not exempted. 8. Statewide regulations and conservation orders govern field operations except as modified by this order. 9. To ensure that fluids injected are confined to in- jection strata, the mechanical integrity of an in- jection well should be demonstrated periodically and monitored routinely for disclosure of possible abnor- malities in operating conditions. 10. Injection wells existing on the date of this order were constructed and completed in accordance with regu- lations which conform to the requirement of 20 AAC 25.412. NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth govern Class II underground injection operations in the following described area referred to in this order as the affect- ed area: UMIAT MERIDIAN T12N R14E Sections 22, 23, 24, 25, 26, 35 and 36 ,JUN 3\ () 2004 .~~ \ Area Injection O~uer No. 4 Page 3 July 11, 1986 T12N R15E Sections 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35 and 36 T11N R14E Sections 28, 29, 30, 31, 32, 33 and Section 34: W ~ NW \, SW \, SW \ SE \ Sections 1, 2, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 33, 34, 35 and 36. T12N R16E T11N R15E Entire Township. T11N R16E Section 2: SW \ NW \, SW %, S ~ SE % Sections 3, 4, 5, 6, 7, 8, 9, 10, 11 Section 12: NW %, S ~ NE %, SE %, SW Sections 13, 14, 15, 16, 17, 18, 19, 21, 28, 29, 30, 31, 32 and 33. 3:- 4 20, T10N R14E S e c t i on s 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28 and 36. T10N R15E T10N R16E Entire Township Sections 4, 5, 6, 7, 8, 9, 16, 17, 18, 19, 20, 29, 30 and 31. Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, non-hazardous fluids may be injected for purposes of pressure maintenance and enhanced oil recovery into strata defined as those strata which correlate with the strata found in ARGO (Atlantic Richfield-Humble) Prudhoe Bay State No. 1 between the measured depths of 8110 feet and 8680 feet for the Prudhoe Oil Pool and between the measured depths of 8790 feet and 10,440 feet for the Lisburne Oil Pool. Rule 2 Authorized Injection Strata for Disposal Within the affected area, non-hazardous oil field fluids may be injected for the purpose of fluid disposal into strata defined as those strata which correlate with the strata found in ARGO Sag River State Well No. 1 between the measured depths of 1900 feet and 6750 feet. Rule 3 Fluid Injection Wells The underground injection of fluids must be: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAG 25.005; 2) through an existing well that has been approved for conversion to a service SCP~NNEJ.) cítIN ~i () 20D)J· Area Page July ,~i \ '\ Injection Oraer No. 4 4 11, 1986 l \ 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. Pumping of excess non-hazardous fluids that are developed solely from well operations, or necessary to control the fluid level of reserve pits, into surface/production casing annuli is exempted from the above requirements. Rule 4 Monitoring The Tubing/Casing Annulus Pressures 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% 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 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, which ever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength, 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 pressure tests. Rule 7 Well Integrity Failure Whenever operating pressure observances or pressure tests indi- cate pressure communication or leakage of any casing, tubing or packer, the operator must immediately cease injection, notify the Commission, and obtain approval for corrective action. Rule 8 Plugging and Abandonment of Fluid Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accor- dance with 20 AAC 25.105. Rule 9 Administrative Relief Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Com- mission's satisfaction that sound engineering practices are 7/25/86 Revision c'::'tt"/I!\~\\arì..~El1' 1111 fl\ì!: I.Í); H ')00 ( ð~(I"'M'ö~~-c'J ~hJI:\~ ,il') U f.. .¿J ;I ~ Area Injection Oraer No. 4 Page 5 July 11, 1986 maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. DONE at Anchorage, Alaska and dated July 11, 1986. Cll@ln - Alaska Oil and as Conservation Commission bsæ~oner Alaska Oil and-- Gas Conservation Commission ~t/. ~. / Wil~iam W. Barnwel~ Commissioner Alaska Oil and Gas Conservation Commission ;SCANNED ~JUN 3 OJ 2004 } '¡ ~ Bill Sheffield, Governor ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 TELEPHONE (907) 279-1433 TELECOPY NO. (907) 276-7542 July 25, 1986 TO WHOM IT MAY CONCERN: Attached is a corrected copy of a July 11, 1986 Area Injection Order No.4. The correction occurs in the last sentence of Rule 3 at the top of Page 4. Please discard all copies of Area Injection Order No. 4 which do not display a 7/25/86 Revision note at the bottom of Page 4. ours, o~ dlf:C.AIO.04 rev Attachment ~~, ../ ?Pp·4. ~Çl-\NNEU ~!¡UN ~; 0 2004' jo/3.M AIO 4.1 (/C. c~reU.· .' /-1/. /~ 1.1. / "'/7(71 .... /- /~ 4'~..' ,ð. ,!:h~"7i / / i:1't.<;,".)Ø;~;f; "'--. 't/' '- / ~tOt1 c. V. Chatter Chairman Whenever operating pressure observations or pressure tests indicate pressure communication or 'leakage of any casing, tubing or packer, the operator must [IMMEDIATELY CEASE INJECTION,] . notify the Co~nission on the first working day following the observation, [AND] obtain Commission approv'al [FOR CORRECTIVE ACTION] of a plan for corrective action, and when an USDW is not endangered, obtà~n co~lss~on app~ovalto continue injectiön. Rule 7 _~e~ !-ntegrity Failure The Cormnission has determined that Rule 7 of AIO No. 4 as set forth is unclear as to the Commission's intent. Therefore, Rule 7 i.s amended to rea.d: Dear Mr. Hart: Re: Amend Rule 7 of Area Injection Order (AIO) No.4 Mr. J. W. Hart Prudhoe Operations Manager ARCa Alaska, Inc. ~. P. O. Box 100360 Anchorage, AK 99510-0360 N o. 4.1 APPROVAL . \ . \ ADM I N 1ST RAT I V E October 28, 1986 Telecopy No. (907) 276-7542 #9 ( ( ARCO Alaska, Inc. \ Prudhoe Bay'l:ngineering Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4248 Donald F. Scheve Operations Engineering Manager ~-~ ~NG1 SR ENG k SR ENG ~ ¡ ENG ASST I . ENG ASS~ SA GEOL GEOL AS ,- ~3EOL ASSrp ~YfAt-TEtHI :'~T~~TTECHT (.fiLE .._=J May 8, 1992 Alaska Oil and Gas Conservation Commission 3001 Porcupine Road Anchorage, Alaska 99501 Re: Prudhoe Bay Unit, Eastern Operating Area, Underground Injection Operations, Area Injection Order #4 Gentlemen: As you know, changes in the operations of the Prudhoe Bay Field will result from several field development projects now in progress. Changes in the development plan for the Lisburne Participating Area (LPA) have also occurred. Therefore, it is appropriate at this time to update some of the information presented in the Eastern Operating Area, Area Inj ection Order Application and in subsequent correspondence. No reference to the pt McIntyre development is included in this letter; information concerning anticipated injection streams will be supplied in a separate document. The specific references below refer to pertinent sections in the Application. Ivishak Operations The installation of additional gas handling equipment will result in increased residue natural gas and miscible gas injection rates in the Ivishak formation. Waterflood and EOR expansions, along with increasing water production as these projects mature, will result in increased produced water injection. Changes in field handling practices for snow melt and other reserve pit water can result in seasonal injection rate increases. The following paragraphs provide updated information on specific injection streams. Source Water injected into the Ivishak formation (ref. Section J, Subsection lA, Pages 22-23, Section K, page 29) Source water injection rates will decline over time as produced water injection increases. Current EOA source water rates are less than 550,000 BWPD with wellhead injection pressures . normally less than 2100 psi. Wellhead injection pressures in the future are expected to remain below 2700 psi. R E eEl V E D SCANNED ~]UN 3 0 20D4 MAY 111992 Alaska Oil &A~ç,gP-~. Commiss\on Anchorage ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany ( Alaska Oil ano May 8, 1992 Page 2 ~ as Conservation Commission RE€EIVED Produced Water injected into the Ivishak formation (ref. Section J, Subsection IB, page 23, Section K, page 29) Current EOA produced water injection rates for waterflood and enhanced recovery projects total about 600,000 barrels per day, with wellhead inj ection pressures normally less than 2200 psi. Injection and water treatment equipment capacities will limit total injection rates to approximately 1,000,000 BPD. It is projected that total produced water injection into the Ivishak could approach this rate for short periods of time. Injection pressures are limited by facility constraints and are expected to remain below 2700 psi. Natural Gas injected into the Ivishak formation (ref. Section J, Subsection lC, pages 23-24; Section K, page 29) Current injection of EOA Ivishak residue natural gas is about 4.5 billion standard cubic feet per day with wellhead injection pressures normally less than 3700 psi. Equipment installed as part of the GHX-2 project will result in an increase in the annual average field gas offtake from 5.2 BCFD to about 7.5 BCFD. This expansion will require additional gas injection wells and could result in daily inj ection rates up to approximately 7.75 BSCFD. Surface injection pressures at high gas rates contain a significant friction component but are expected to remain below 4250 psi. Miscible Gas injection into the Ivishak formation (ref. Section J, Subsection ID, page 24; updated 11/5/87) Additional equipment which will be installed as part of the GHX-2 project and expansion of the PBMGP enhanced oil recovery project could result in EOA Ivishak miscible gas injection rates of approximately 450 million standard cubic feet per day. Current injection is about 250 MMSCFD with wellhead inj ection pressures normally less than 3500 psi. Wellhead injection pressures in the future are expected to remain below 4500 psi. Produced Water Disposal into the Tertiary/Cretaceous formations (ref. Section J, Subsection 2A, pages 24-25; updated 11/5/87; Section K, page 29) Current EOA produced water disposal is about 150,000 BPD with wellhead injection presstires normally less than 2100 psi. Several of the disposal wells are now tied directly to the MAY 111992 Alaska au & Gas Cons. Commission Anchorage 8CANNEL) (.JUN 3 0 2004 ~. " Alaska Oil ana May 8, 1992 Page 3 !t dS Conservation Commission ' Ivishak produced water injection systems at the various facilities, so wellhead injection pressures could approach the maximum expected pressures for those systems. Produced water disposal well capacities in the EOA total approximately 350,000 barrels of water per day. Within equipment limitations and other operational constraints, disposal of produced water into the Tertiary/Cretaceous interval will continue to be minimized, however disposal rates could approach this value. Non Hazardous Waste Disposal into Tertiary/Cretaceous formations (Ref. Section J, Subsection 2B, page 25) Snow seasonally accumulates in the EOA Drill Site reserve pits. An intense effort is made each summer to gather and inject the fluids in the pits (mainly snow melt water and at times drilling related liquids) into the Tertiary/Cretaceous formations. Occasionally, some of this material is treated and injected into the Ivishak formation. Injection rates could reach as high as approximately 50,000 barrels per day. This is in addition to the routine injection of other non hazardous waste indicated in the application. Lisburne Operations Currently the LPA is not injecting source or produced water into the Wahoo formation. In the future, there is potential for a limited waterflood project in the LPA. An evaluation of the reservoir mechanisms associated with the responses observed during the DS- L2 waterflood has been initiated. The results will determine the potential for future secondary recovery in selected areas of the Lisburne Reservoir. The following paragraphs provide updated information on specific LPA injection streams. RE(EIVED Source Water injected into the Wahoo formation (ref. Section J, Subsection lA, pages 22-23) Currently the LPA is not injecting source water into the Wahoo formation. The maximum future source water injection rate in the Wahoo is estimated at approximately 100,000 BWPD. The maximum surface pressure expected is about 3000 psi. Produced Water injected into the Wahoo formation (ref. Section J, Subsection 1B, page 23) LPA Wahoo injection of ·produced water is currently suspended. The maximum future produced water injection MAY 111992 Alaska Oil & Gas Cons. Commission Anchorage SCANNED JUN ,~ íJ 2004 \ Alaska Oil and May 8, 1992 Page 4 ( as Conservation Commission \ rate in the Wahoo is now estimated at approximately 100,000 BWPD. The maximum surface pressure expected is about 3000 psi. Natural Gas injected into the Lisburne formation (ref. Section J, Subsection lC, pages 23-24; Section K, page 29) Current injection of Lisburne residue natural gas is about 0.5 billion standard cubic feet per day with wellhead injection pressures approximately 4700 psi. Produced Water Disposal into the Tertiary/Cretaceous formations (ref. Section J, Subsection 2A, pages 24-25) Currently all Lisburne produced water is injected into the Tertiary / Cretaceous formations. This averages less than 15,000 BWPD with wellhead injection pressures normally less than 1 700 psi. The information contained in the above paragraphs provides a description of current operations and, where appropriate, an update to the data included in the referenced application. The anticipated future rates and pressures listed above are intended to represent maximum expected peak daily rates and pressures in some cases limited by existing or planned facilities and wells; expected average values will be somewhat less. We intend to provide additional updates if conditions or plans change significantly in the future, or as requested by the Commission. It is our belief that Area Injection Order #4 provides for the above activities and no change in the order is requested by ARCO at this time. As indicated above, information concerning anticipated injection streams associated with pt McIntyre development will be supplied in a separate document. If you wish to discuss these matters further, please contact me or M. A. Major (265-6136) at your convenience. Yours very truly, ¡~#¿k- Donald F. Scheve MLB/019 SC/'!bNNED· JLJN 3 Q¡ 20D~~ RECEIVED MAY 1 11992 Alaska au & Gas Cons. (ìomm\ss\O~\ Anchorage #8 /' ì) ARCO Alaska, Inc. 1 Post Office Box 100360 Anchorage, Alaska 99510*0360 Telephone 907 276 1215 ,,' April 19, 1991 Lonnie C. Smith Commissioner . Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Annulus Pressure Monitoring of UIC Wells Dear Commissioner Smith: " 7t:yf),¡tt L¡ ~~... leG': '._" ¿52/' ;'(. ~ 1\'(\'.-- .[ .L.,J \' T . . '!:\:~.. >_ j\-::\ "r.: I, .~ :~:~.J>~~~) }. .__ "i" .:.... ¡\~s ï \ ..::.:~:\~:~:-:. ..-----.\........- \ t" :'.~ b.EOl......._ \ "r-'JjC'ASST\ II \.', 1-. '~~----è~ ¿. T 1-- , (- i: 1.1 L 1\.-),.) ..I.~ ~';I' ..'~. ~(:(;~;~ \~\ £~~____r-. jJo ,....A...p ~ C ¿")i?Y'v'" . . ARCO Alaska, Inc.(AAI), as Operator of the Prudhoe Bay Unit EOA, Lisburne Participating Area, the Kuparuk River Unit, and several Cook Inlet properties, has received your letter requesting that we maintain the tubing/casing annulus pressure on UIC Class II injection wells below 500 psig. Also, you have requested that we begin reporting tubing and casing pressures on Form 10-406 for the Prudhoe Bay EOA per the requirements of AOGCC regulations AAC 25.430 and 432. As discussed with you in a meeting on February 15, 1991, AAI has not been reporting PBU EOA tubing and casing pressures on Form 10-406 based on a variance to AAC 25.430 granted on March 28, 1986 by the Commission. Per your request, the PBU data reporting system will be modified, beginning with the March report, to include the tubing and casing pressures in our monthly data transmission tapes submitted to you as a substitute to Form 10-406. The other fields will continue to report these pressures as has been done in the past. ' As also discussed with you during our meeting of February 15, we feel that your request to maintain less than 500 psig on the tubing/casing annulus is a significant deviation from current operating practices and would create an increased operating and administrative burden with minimal positive contribution towards the goals of the UIC program. Instead of placing a 500 psig pressure IimHation on the tubing/casing annulus, we offer the following alternate proposal for your consideration: A quarterly report will be submitted summarizing mechanical integrity tests (MIT's) performed during that quarter on UIC Class II injection wells. Additionally, the report will include brief comments on all injection wells which have an average tubing/casing annulus pressure within a 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: ~~t;Ahr¡\Jcr I I! flJITV! ç~ f\ ')nr I '-' ~" ~ ,1,1 <'þ \¡j (, J"I.:.) ARCO Alaska, Inc. is a Subsidiary 01 AllanlicRlchlieldCompany RBC?EIVED MA Y 1 4 1991 Alaska 011 &AGas Cons. Gomml~~jºQlJ03'c nchorage Lonnie C. Smith April 19, 1991 Page 2 ') "} A) Diagnostic Evaluation Complete: Form 10-403 waiver received B ) Diagnostic Evaluation Complete: Minor pressure communication noted, continue 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 We will Implement these guidelines in all the AAI operated fields on a 6 month test basis to determine the operating feasibility of the proposal. We propose that we meet again with you at the end of the 6 month period to discuss our findings. Each field will submit these quarterly reports on an individual basis. We appreciated the opportunity to meet with you to discuss AAI injection well operations. Please review and provide comments on the above proposal at your earliest convenience. We appreciate your efforts in working with us and we are confident that we can arrive at a mutually acceptable monitoring program. If there are any questions, comments or clarifications that you wish to discuss, please do not hesitate to contact Eric Skaalure at 263-4234 or Mark Drumm at 263-4212. Sincerely, jJø$4~ D. F. Scheve PB Operations Engineering Manager -1 h/d~ T. Mark Drumm Kuparuk Operations Representative -r Wt/I1/Vt~ T. Wellman bZ'" 0~~ Cook Inlet Regional Engineer . EWS/066 ~':~ {~ 2nO ") cl U .' U 1(ìJ. #7 .- ~RCO Alaska, Inc. ) Intimal Correspondence ) A:I '~J<0 'F-t~S' '~,.,;.-"'~ -....;..,·.D..-.-.......... -. ~. ,,): '. .," ~', ' Sff" ~-. .~:- --". . ~ea.r:- I' ".- , Date: July 16, 1990 Subject: Injection Well State Mechanical Integrity Testing - 1991 Test E f'!"' -, -- "- . From/Locati on: D.D. Smith 1 J. M. Heusser ::. : ~ ..~ ',~:" 1._ _.. , -" .! G:': ': '_ .', ".: :~--î ëfË í' . ,-".' j S .,-;. -,- -: -~ " ! SïAT ":::':~ . .. j <:1: ~ ~ Telephone: To/Location: 659-5102 K.M. Kennedy 1 W.S. Wilder I.D. Ottoson 1 S.J. Massey The AOGCC has been contacted regarding the yearly State Witnessed MIT's on 25% of the Prudhoel Lisburne injection wells. Per a phone conversation this morning with Lonnie Smith (AOGCC), an AOGCC representative (Doug Amos) will be available from August 24 - 26, 1990 to witness some of the MITIs. It is my understanding that the State may choose to witness selected MITIs as opposed to having a representative on site for all the MITS. The wells to actually be State Witnessed will be selected by the Slope AOGCC testing representative from the list noted below. The State rep will be contacted again on August 23 to verify his availability (659-3607). As noted on the 7/15/90 letter to the State outlining the tentative testing schedule, the following injectors will be tested during August: Drill Site Wells 1 13 NGI PWDW 1 LGI LPC 8 9, 15, 16, 17, 18, 19, 20, 21, 22, 23A, 24, 25, 32 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14 1 2 1 As in the past, the Pad #3 Disposal Wells will be MITld in the May 1991 timeframe. Over the course of the next month, pre-test 9-5/8" MITIs will be carried out on all of the wells scheduled for the August 24 - 26 testing. We will be coordinating this pre-testing with Wes. and Mike and the appropriate Drill Site. Supervisors. If you have any questions or comments regarding the MIT testing schedule, please contact either Dave Smith or I at 659-5102 or Beeper 191-154. ~~ RECEI'/ED I. M. Heusser Sr. Engineer Annular Communication cc: '\J JUL 23 1990 Alaska Oil & Gas Cons. Commission Anchorage C.P. Fanner 1 J.C. Ferguson, PRB 24 C.L. Clark 1 B.R. Robertson, PRB 14 R.L. Powell 1 J.D. Ashford, PRB 37 E.D. Fitzpatrick 1 Vacant, PRB 20 L.C. Smith, AOGCC, 3001 Porcupine C.B. Hurst 1 D.B. Montgomery, PRB 15 J.P. Winters 1 C.W. Shumway, PRB 13 D. Venhaus 1 E. Rael, PRB 24 Street, Anchorage. Alaska Ii ~ 'f'\~ 9 {0 20 OR '" ~) è,~ (I' \.1; . ..' "~. STATE ANNULUS TESTlNG DATABASE FOR PRUDHOE/LISBURNE INJECTlON WELLS FLOW STATION #1 STATE TUBING PACKER TEST LAST TEST TEST WEll ANNULUS FLUID SIZE MD'/TVD' CASING PRESS. DATE YEAR 1 -08 5 bbl diesel + 10.6 CaCI2 5-1/2" 11395/7886 9-5/8". 47#. MN-80 to 8540'. SOO~95 below 1500 10/7/86 87 12-02 62 bbl crude + 8.5 NaCI 7" 11673/8464 9-5/8". 47#. L-80 2451 10/?4/89 90 12-19 30 bbl diesel + 9.6 NaCf 5-1/?" 1 0821/8423 9-5/8" . 47#. L-80 1918 10/2/87 88 12-20 30 bbl diesel + 9.6 NaCI 5-1/2" 10031/8396 9-518". 47#. L-80 1912 10/2/87 88 12-21 Crude 5-1/2" 9412/8432 9-5/8" . 47#. L-80 2791 10/24/89 90 12-23 30 6bl diesel +9.6 NaCI 5-1/2" 8561/8453 9-5/8". 47#. L-80 1924 10/2/87 88 12-25 30 bbl diesel + 9.6 NaCI 5-1/2" 10428/8465 9-5/8". 47#. L-80 1927 10/2/87 88 12-27 105 bbl di~sel + 8.5 NaCI 5-1/2" 8900/8394 9-5/8" . 47#. L-80 2505 1/1/88" 88 c~ NGI-1 15 bbl diesel + 10.8 CaCI2 7" 8671/7299 9-5/8" . 47#. M N-80 1500 9/30/87 88 NGI-? 15 bbl die~el + 10.8 CaCI? 7" 8329/7?35 9-5/8". 47#. M N-80 1500 9/30/87 88 NGI-3 61 bbl diesel + 8.5 NaCI 7" 8033/7371 9-518" . 47#. M N-80 ?~?4 5/?7/69" 69 NGI-4 20 bbl diesel + 10.9 CaCI2 7" 9400/7399 9-5/8" . 47#. M N-80 1500 9/30/67 88 NGI-5 S bbl diesel + 10.9 CaCI2 7" 7892/7284 9-5/8" . 47#. MN-80 1500 9/30/87 88 NGf-6 51 bbl diesel + 9.4 NaCI 7" 8066/7426 9-5/8", 47#. MN-80 1950 2/8/88" 88 -::fJ NGI-7 20 bbl diesel + 10.8 CaCI2 7" 7399/7 351 9-5/8" . 47#. N-80 1500 9/30/87 88 ~c NGI-8 20 bbl diesel + 10.8 CaCI2 7" 8929/7388 9-5/8". 47#. M N-80 1500 9/30/87 88 ~~. NGI-9 5 bbl diesel + 10,9 CaCI2 7" 920517327 9-5/8". 47#. M N-80 1500 10/1/87 88 r~~ NGI-10 5 bbl diesel + 10.8 CaCI2 7" 8386/7319 9-5/8". 47#. N-80 1500 10/4/87 88 ~""=:L NGI-11 15 bbl diesel + 10.8 CaCI2 7" 8973/7313 9-5/8". 47#. JL-95 to 2301'. N-80 below 1500 10/1/87 88 l-.--ÇJI, l: ¡ NGI-12 60 bbl diesel + 8.5 NaCI 7" 835317 423 9-5/8" . -47#. N-80 2235 12/25/87" 88 NGI-13 20 bbl diesel + 10.8 CaCI2 7" 7602/7344 9-5/8". 47#. N-80 1500 10/1/87 88 -=- 10 bbl diesel + 10.8 CaCI2 8011/7171 9-5/8". 47#. L-80 ~ NGI-14 7" 1500 9/30/87 88 :2 ~ª PWDW 1-1 TEG (glYcol) 4-1/2" 3232/3232 9-5/8". 47#. N-80 to 2456'. 800-95 below 1500 10/~/86 87 ~ f'0 WGI-1 15 bbl diesel + 10.8 CaCI2 7" 790?/7415 9-5/8". 47#. N-80 1500 10/1/87 88 C;::) -" e;::) WGI-2 60 bbl diesel + 8.5 NaCI 7" 8273/7541 9-S/8". 47#, 8-95 & N-80 2267 5/14/89* 89 cÇ.'c.n WGI-3 1S bbl diesel + 10.8 CaCI2 7" 614S/7346 9-S/8". 47#. N-80 1500 10/1/87 88 WGI-4 15 bbl diesel + 10.8 CaCI2 7" 8228/7276 9-~/8". 47#. 8-95 & N-80 1500 10/1/87 88 WGI-5 54 bbl diesel + 8,S NaCI 7" 7800/7800 9-5/8". 47#. N-80 4000 5/27/90" 90 WGf-6 60 bbl diesel + 8.5 NaCI 7" 8298/7869 9-5/8". 47#. N-80 2350 5/9[90" 90 WGI-7 60 bbl diesel + 8.5 NaCI 7" 8061/7868 9-5/8" , 47#. N-80 4000 5/22/90" 90 WGI-8 60 bbl diesel + 8.5 NaCI 7" 7961/7724 9-5/8" , 47#. N-80 4000 5/25/90* 90 " Tested on Rig Page 1 Revised 7/15/90 STATE ANNULUS TESTING DATABASE FOR PRUDHOE/USBURNE INJECTION WELLS FLOW STATION #2 STATE TUBING PACKER TEST LAST TEST TEST WEU ANNULUS FLUID SIZE MD'/TVD' CASING PRESS. DATE YEAR 3-04 10.4 CaCI2 5-1/2" 10927/8274 9-5/8". 47#. MN-80. S-95 1575 8/25/88 89 3 -0 6 5 bbl diesel + 10.3 CaCI? 5-1/?" 8565/7928 9-5/8". 47#. M N-80 1650 8/25/88 89 3-07 5 bbl diesel + 10.2 CaCI2 5-1/2" 10527/8458 9-5/811. 47#. MN-80 to 8171'. 800-95 below 1750 8/25/88 89 3-10 65 bbl diesel + 8.9 NaCI 5-1/?" 8561/8028 9-5/8". 47#. L-80 to 5780'. S-95 below 2200 8/25/88 89 3 -11 65 bbl diesel + 8.9 NaCI 5-1/2" 10142/8152 9-5/8". 47#. N-80 to 7159'. 500-95 below 2300 8/25/88 89 3 -12 8.5 ~aCI 711 8895/8461 9-5/8". 47#. L-80 to 6194'. S-95 below ?310 2/24/89· 89 3 -13 200 :t>bl diesel + 8.5 NaCI 4-11211 10929/8717 7-5/811. 29#, L-80. Scab Liner to 11630' 3500 4/17/90· 90 3 -16 25 bbl diesel + 9.4 NaCI 5-1/211 11533/8352 9-5/8", 47#, L-80 to 10857', 5-95 below 2000 8/25/88 89 3 -11 82 bbl diesel + 8.5 NaCI 5-1/2" 8426/8158 9-5/8", 47#, L-80 to 8213'. S-95 below 2425 8(25/f)8 89 3 -18 65 bbl diesel + 8.6 NaCI 5-112" 10008/8416 9-5/8". 47#, L-80 to 9330'. JL-95 below 2450 8/25/88 89 ~ 4-06 20 bbl diesel + 10.4 CaCI2 5-1/2" 1048717834 9-5/8". 47#. MN-80 1500 1/8/88 88 4-08 Diesel 5-1/2" 10039/8514 9-5/8". 47#. MN-80 to 6855'. RS-95 bE1low 3120 10/14l88 89 4-09 65 bbl diesel + 9.1 NaCI 5-1/211 10711/8083 9-5/8". 47#. MN-80 to 8662', RS-95 below 2180 10/14/88 89 4-10 Diesel 5-1/2" 7964/7830 9-5/8", 47#. MN-80 to 5470'. 5-95 below 2900 10/14/88 89 4 -11 15 bbl diesel + 10.5 CaCI2 5-1/2" 10829/8468 9-5/8", 47#, N-80 to 5723'. S-95 below 1540 11/17/88 89 4 -13 30 bbl diesel + 9.0 NaCI 5-1/2" 9950/8415 9-5/8", 47#, N-80 to 4903', RS-95 below 2160 10/14/88 89 4 -14 10 bbl diesel + 10.2 CaCI2 5-1/2" 8672/8386 9-5/8", 47#. N-80 to 4903', S-95 below 1600 10/14/88 89 4-15 10 bbl diesel + 10.6 CaCI2 5-1/211 9787/8314 9-5/8". 47#. N-80 to 5471'. 5-95 below 1540 11/17/88 89 4 -17 50 bbl diesel + 9.3 NaCI 5-1/2" 9144/8262 9-518", 47#, L·80 2100 10/14/88 89 4-19 61 bbl diesel + 9.0 NaCI 7" 3000/3000 9-5/8". 47#. L-80 1550 11/17/88 89 4-20 33 bbl diesel + 9.8 NaCI 5-1/2" 10993/8173 9-5/8", 47#. L-80 1802 7/11/89 90 4-22 35 bbl diesel + 9.4 NaCI 4-1/2" 11844/8264 9-5/811, 47#. L-80 2000 10/14/88 89 4 -25 100 bbl diesel + 9.4 NaCI 4-1/2" 10573/7686 9-5/8" . 47#. L-80 1997 7/11/89 90 ~ 4-27 52 bbl diesel + 9.3 NaCI 4-112" 11926/8482 9-5/8" , 47#. L-80 2150 10/14/88 89 =.~ ~ 4-28 Diesel 4-1/211 13269/8592 9-5/8", 47#. L-80 3160 9/8/88 89 ',== ~ ~ Q;ª 9-08 5 bbl diesel + 10.3 CaCI2 5-1/?" 1 0744/8302 9-5/8". 47#. MN-80 to 10737', 800-95 below 1510 8/3/89 90 Q 9-10 15 bbl diesel + 10.6 CaCI2 5-1/2" 11478/7773 9-5/8", 47#. $-95 to 2242'. N-80 to 9251' 1500 ---' 8/3/89 90 N 9 -1 ? 98 bbl diesel + 8.5 NaCI 5-1/211 11500/8207 9-5/8", 47#. N-80 . 500-95 2440 8/3/89 90 ~ ~ 9 -14 140 bbl diesel + 8.5 NaCI 1 X 5-1/?" 9944/8257 9-5/8", 47#. N-80 to 6555', R$-95 below ?451 4/3/90· 90 · Tested on Rig Page 2 Revised 7/15/90 STATE ANNULUS TESTING DATABASE FOR PRUDHOE/USBURNE INJEC110N WELLS FLOW STATION #2 (Cont'd) STATE TUBING PACKER TEST LAST TEST TEST WEll ANNULUS FLUID SIZF MD'/TVD' CASING PRESS. DATE YEAR 9 -15 8e bbl diesel + 8.5 NaCI 5-1/2" 9341/8469 9-5/8", 47#. N-80 to 6083'. 5-95 below 2490 8/4/89 90 9 -16 88 bbl diesel + 9.4 NaCI 5-1/2" 11917/8728 9-5/8". 47#. SOO-95 2250 4/?2/8~· 89 9-17 65 bbl diesel + 8.5 NaCI 5-1/')" 10002/8564 9-5/8". 47#. R8-95 to 2403', N-80 to 7707' 2470 8/4/89 90 9-18 51 bbl diesel + 8.5 NaCI 8705/8482 9-5/8". 47#. L-80 NSCC to 2200'. N-80 to 7084' 2493 4/3/90* 90 9 -19 98 bbl diesel + 8.5 NaCI 5-1/2" 11051/8668 9-5/8". 47#, 800-95 to 2320', N-80 to 9446' 2565 8/3/89 90 ·9-20 65 b~1 diesel + 9.4 NaCI 5-1/2" 8950/8564 9-5/8". 47#, 500-95 to 2348'. N-80 to 7689' 2139 8/4/89 90 9-?2 30 bbl diesel + 9.6 NaC! 5-1/2" 12493/8575 9-5/8", 47#, L-80 1951 8/4/89 90 9-25 5 bbl diesel + 9.6 NaCI 5-1/2" 12588/8666 9-5/8" . 47#. L-80 1887 8/4/89 90 9-38 96 bbl diesel + 8.5 NaCI 5-1/2" 10290/8317 9-5/8" , 47#, L-80 2466 4/30/89* 89 --- 11-0? 30 bbl diesel + 9.8 NaCI 5-1/')" 9363/8282 9-5/8" , 47#. L-80 1840 6/30/88 88 11-07 30 bbl diesel + 9.8 NaCI 5-1/2" 8590/8148 9-5/8". 47#, L-80 to 7488'. 800-95 below 1850 6/30/88 88 11-08 30 bbl diesel + 9.4 NaCI 5-1/2" 9292/8134 9-5/8" . 47#. L-80 2020 6/30/88 88 f?J; 11-10 Crude to 8092 5-1/2" 10642/8092 9-5/8". 47#, L-80 2800 12/21/88 89 fP"':. 11-26 Diesel + 9.4 NaCI 5-1/2" 10031/8088 9-5/8".47#. L-80 2250 6/30/88 88 ~ :z 16-01 5 bbl diesel t 9.6 NaCI 5-1/2" 12175/8620 9-5/8" , 47#. L-80 1877 8/6/89 90 =- ~ 16-02 Diesel 5-1/2" 9745/8492 9-5/8", 47#, L-80 to 8858', SOO-95 below 3074 8/6/89 90 m í~ 16-03 Diesel 4-1/2" 11199/8664 9-5/8". 47#. L-80 3137 8/6/89 90 ,~ 16-05 Diesel 5-1/2" 9520/8560 9-5/8", 47#, L-80 to 8852', 8-95 below 3099 8/6/89 90 ..~ ç~ 16-10 Diesel 4-1/2" 9215/8504 9-5/8". 47#. L-80 to 8835', 8-95 below 3079 8/6/89 90 "-' 2 16-11 5 bbl diesel + 9.5 NaCI 5-1/2" 8605/8465 9-5/8", 47#, L-80 to 8286'. 8-95 below 1887 8/6/89 90 ~~ 16-16 76 bbl diesel + 8.6 NaCI 5-1/2" 9826/8438 9-5/8". 47#, L-80 2423 8/6/89 90 ~ ~ 17-06 5 bbl diesel + 9.6 NaCI 5-1/2" 9339/8314 9-5/8". 47#, L-80 to 8995', 800-95 below 1880 10/14/88 89 ::;, ~ 17-08 30 bbl diesel + 9.6 NaCI 5-1/2" 8581/8440 9-5/8" . 47#. L-80 1960 10/14/88 89 ~-:, 17-10 30 bbl diesel + 9.6 NaCI 5-1/2" 9109/8462 9-5/8". 47#, L-80 to 8765'. SOO-95 below 2000 10/14/88 89 PWDW ')-1 Diesel 7" 3392/3392 9-5/8", 47#, NM-80 1500 11/13/87* 88 ~/ · Tested on Rig .. 7" to 5118', 5-1/2" below Page 3 Revised 7/15/90 STATE ANNULUS TESl1NG DATABASE FOR PRUDHOE/LISBURNE INJEC110N WELLS FLOW STATION #3 STAlE TUBING PACKER TEST LAST TEST TEST WEll ANNULUS FLUID SIZE MD'/TVD' CASING PRESS. DATE YEAR 7 -1 6 127 Qbl diesel + 9.8 NaCI 5-1/')" 9497/8036 9-5/8" . 47#, L-80 2014 6/17/89 89 7 -2 7 51 bbl diesel + 8.4 NaCI 9067/8212 9-5/8" . 47#. L-80 2452 6/17/89 89 7-33 86 bbls diesel + 8.5 NaGI 5-1/2" 10141/8190 9-5/8" . 47#. L-80 2410 6/28/89* 89 7 -34 107 bbl diesel + 8.4 NaCI .. * . 9711/8209 9-5/8". 47#, L-80 2566 6/17/89 89 13-06 1471>bl diesel + 8.5 NaGI 5-1/2" 10350/8503 9-518" , 47#, L-80 2500 3/29/90 90 13-09 30 bbl diesel + 9.6 NaCI 5-1/2" 10154/8510 9-5/8". 47#. L-80 to 9218'. SOO-95 below 1937 10/2/87 88 13-15 9.6 NaCI 5-1/2" 9841/8549 9-5/8", 47#, L-80 1845 10/2/87 88 13-16 30 bbl diesel + 9.6 NaCI 5-1/2" 8715/8462 9-5/8". 47#. L-80 to 8125', 800-95 below 1926 10/2/87 88 -- 13-17 25 bbl diesel + 9.6 NaGI 5-1/2" 10508/8397 9-5/8", 47#. L-80 to 9852'. 800-95 below 1896 10/2/87 88 13-18 88 bbl diesel + 8.5 NaGI 5-1/2" 10321/8346 9-5/8", 47#. L-80 to 9366'. SOO-95 below 2457 10/2/87 8e 13-19 30 bbl diesel + 9.6 NaCI 5-1/2" 9058/8338 9-5/8", 47#, l-80 to 8108'. 800-95 below 1899 10/2/87 88 13-20 30 bbl diesel + 9.7 NaCI 5-1/2" 951118396 9-5/8". 47#, L-80 to 8707', 800-95 below 1872 10/2/87 88 13-21 30 bbl diesel + 9.8 NaGI 5-1/2" 12204/8525 9-5/8", 47#, L-80 to 11462'. 800-95 below 1858 10/2/87 88 13-22 30 bbl diesel + 9.6 NaCI 5-1/2" 9128/8451 9-518". 47#. L-80 to 8390', 800-95 below 1924 10/2/87 88 13-23a 30 bbl diesel + 9.6 NaCI 5-1/2" 11851/8422 9-5/8", 47#. L-80 to 10601', 800-95 below 1918 10/2/87 88 13-24 30 bbl diesel + 9.6 NaCI 5-1/2" 9706/8438 9-5/8", 47#. L-80 to 8709'. SOO-95 below 1921 10/2/87 88 13-25 30 bbl diesel + 9.6 NaGI 5-1/2" 8575/8388 9-5/8". 47#. L-80 to 7820'. SOO-95 below 1910 10/2/87 88 13-32 30 bbl diesel + 9.6 NaGI 5-1/2~ 11191/8546 9-5/8", 47#, L-80 to 10348', SOO-95 below 1944 10/2/87 88 14-13 9.6 NaC! 5-1/2" 9571/8327 9-5/8", 47#. l-80 to 8805'. SOO-95 below 1797 10/1/87 88 14-14 9.6 NaGI 5-1/2" 11033/8406 9-5/8", 47#. L-80 to 10026', 800-95 below 1814 10/1/87 88 , 14-17 112 bbl diesel t 8.5 NaCI 5-'1/2" 10129/8519 9-5/8" ,47#. L-80 3500 5/6/90* 90 14-21 310 bbl crude + 8.5 NaCI 5-1/2" 11707/8643 9-5/8" A7#.L-80 2700 8/3/89 90 .. 14-')5 165 bbl diesel + 8.6 NaGI 5-1/2" 9427/8386 9-5/8" , 47#. L-80 3500 5/24/90· 90 2 14-27 30 bbl diesel + 9.6 NaGI 5-1/2" 9111/8447 9-518" . 47#. L-80 1923 10/3/87 88 ç~\~j 14-36 97 bbl diesel + 8.5 NaCI 5-1/?" 8694/8438 9-5/811. 47#. L-80 2500 6/17(88" 88 .~ .~ ~ · Tested on Rig c::J 9 u 7" to 2234', 5-112" below ...~ ..u 7" to 2212', 5-1/2" below Page 4 Revised 7/15/90 (J; ~ :~ ~: 1=cr-(¡. .~ ~ ::~:ê ,~ ~ c::> c:::) qÄ FLOW STATION #3 (Cont'd) STATE ANNULUS TESTING DATABASE FOR PRUDHOE/USBURNE INJECTION WELLS WEll ANNULUS FLUID TUBING SIZE PACKER MD'ITVD' CASING TEST PRESS, LAST TEST DATE OWDW-NW TFG (glycol) 2-3/8" 1880/1880 5-1/2", 17#, L-80 1740 5/19/90 OWDW-NF COLLAPSED TUBING (â) 30', 2-3/8" 1940/1940 P&A ~ t\EVER OWDW-SF TEG (alycol\ 2-3/8" 1885/1885 5-1/2", 17#, N-80 1700 5/19/90 OWDW-SW TFG (alycol) 2-3/8" 1 89811 ~9~ , _q-J(2", _ t7#, L-BO 1705 5/19/90 OWDW-CTR SUSPENDED WELL - - - - - - - - - - - - - - - - - - - - - - - 50/50 G~ YCOllWATER IN WELL - NO TUBING. NOT PE ~FORATED. f\EVER , I 4-1/2" 3801/3801 I 9-5/8", 47#, N-80 1500 PWDW 3-1 TEG (Qlvcol) 10/3/87 Page 5 STA1E TEST YEAR 90 90 90 88 ~ _/ Revised 7/15/90 STATE ANNULUS TESTING DATABASE FOR PRUDHOE/LISBURNE INJECTION WELLS LISBURNE INJECTORS STAlE . TUBING PACKER TEST LAST TEST TEST WEU ANNULUS FLUID SIZE MD'/TVD' CASING PRESS. DATE YEAR L5-29 7" 13216/8~50 9-5/8". 47#. L-80 2500 ~/24/90 90 . lGI·~ 30 bbl diesel + 9.4 NaÇI 5-1/')" 8966/8265 9-5/8" J 47#. L-80 1962 10/26/86* 87 LGI-6 88 bbl diesel + 8.5 NaGI 5-1/')" 12466/8231 9-5/8". 47#. L-80 2500 4/2~/8~ 89 LGI-10 25 bbl diesel + 9.4 NaGI 5-1/')" 13335/8268 9-5/~" . 47#. L-80 1948 1014/87 88 .. LPC-1 44 bbl diesel + 9.2 NaGI 5-1/2" 3030/3030 9-518". 47#. L-80 1500 12/5/86 87 * Tested on Rig ~,/ (~ c: 2 Ç;:;; ~ C') {'0 c:::> c:::> o Page 6 Revised 7/15/90 #6 " ARCO Alaska. Inc. ) Post Office Box I v" 360 }~nchorage. Alaska 99510-0360 Telephone 907 276 1215 July 15, 1990 ~~i~~1 ~,~ ~ ~ . -R~~~~-~I;":Ö -~l-· " , -~ ... "-. 'is ~ ". SRErJt ·1·'·--1 . SR..~fj-G~~rJ _~.~G ASSï, 1 ENG AS-Sf!) ~r; 'GECL-r-¡ G~EOL A-Š-3~1 GEO'_ ÄŠ:s:n- ~J~~_J~C:-:!' STAT TEC;-¡ I-I ~!I ¡:: -------/ L.C. Smith Alaska Oil and Gas Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 _·'__i Re: Injection Well S tate Mechanical Integri ty Testing - 1991 Test Year Dear Mr. Smith: Please find listed below the injection wells ARCO proposes to test per Area Injection Order No.4. during the 1991 test year (July 1, 1990 through June 30, 1991). The 35 wells listed account for >25% of the current 118 PrudhoelLisburne injection wells. As we discussed, the wells were selected such that all the injectors on a pad will be tested in the same year, with the exception of wells already tested following a recent workover. To take advantage of the summer weather, we would like to begin testing as soon as possible after August 21, 1990. As you are probably aware, the Pad 3 Oily Waste Disposal Wells were recently tested during May 1990 for the 1990 test year. Our current plans call for 1991 testing of these OWDW wells during May 1991. 1-08 PWDW 1-1 NGI-Ol 13-09 OWDW-NW NGI-02 13-15 OWDW-SE LGI-02 LPC-Ol NGI-03 13-16 OWDW-SW N G 1-04 13-17 NGI-05 13-18 NGI-06 13-19 NGI-07 13-20 NGI-08 13-21 NGI-09 13-22 NOI-10 13-23A NOI-ll 13-24 NGI-12 13-25 NOI-13 13-32 NGI-14 Also attached is a copy of our State MIT database (current as of 7/15/90). Should there be any questions, please contact either Dave Smith or myself at 659-5102. ~~ J.M. Heusser Sr. Engineer Annular Communication RECEIVED ~UL 2 L) 19~) AReo Alaska. Inc. is a Subsidiary at AtlanticRichfieldCampany þl.. n':l OH& Gas CÒr.3. CQmr::!~:._J Anchorag3 <) tH~ ~1\ 0 200c~ , , '\ 1 cc. ø C.P. Falmer / J.C. Ferguson, PRB 24" J.D. Ottoson / S.J. Massey, PRB 2f.fY C.L. Clark / B.R. Robertson, PRB 14 J.A. Minier, ATO 1568 M.L. Bill, A TO 1550 E.W. Skaalure, ATO 1526 '-J ) K. M. Kennedy/W. S. Wilder, PRB 20 C.B. Hurst / D.B. Montgomery, PRB 15 J.P. Winters / C.W. Shumway, PRB 13 L.L. Gantt, A TO 1596 J.W. Groth, ATO 1570 D. F. Scheve, A TO 1576 RECEIVED !JUL2519SJ A!=~;,d. Oil & Gas C':''''s Com"'-¡"'~ :1 VI ~ · ,....~;J , ',Anchorag.a - ,.~. JUN 3 0 2nOJî, ~tJ ' , ~,¡. #5 f fUlJ{1 oe,. C1ø..y.. wø..+e.rfþ«:l - t:Sevte~1 ) ....-.... ~~ ) ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Jo''' 1"'1. '-... GIO(-€-ser ~~ A('eClL ~Vl7r 26]- q.rS'.3 March 13, 1989 Mr. B. Wondzell Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Wondzell: ~c - ._S?~~'l ~A--7 _<?~~\'!Mf" !~~~~!~ l~·..,-.· " f _I\J"~ A (~r"ì"'I" 'r:.: ;,i:':,'" -" ,-' "<,.. c, ',. ï t, c,'..,..¡" '/' "" '",' .1 I ....; ,'j I -2{~()~:,:~E~~~!··.~·=L~~ ._,~.'L. I\û:.:) if . .S f:Lq 1 :-;\,~~ ~~> ;r{···· SïA -r Tr:("·I.1 '{"-'" (:;;,'. '''. ,;'.:;, .. ."1 I ? ,~(~I EC;! {" , Fli:§=='.~..~,I~~~ Enclosed is the information you requested on PWI/SWI system. I have also enclosed a report from our automation system that gives actual pressures. If you would like a further explanation, please give me a call at 263-4553, and we can come talk to you about it. Very truly yours, ~\~ J. L. Glaeser Sr. Area Engineer J LG/ab/026 Enclosures cc: D. F. Scheve - ATO 1576 Sf'Æ\\~'\h~~:L" 'HJN 3 Q 2DDl~ ~' VI"..\, ). t .., t!.,. v ,REéEJ.VED ARCO Alaska, Inc. Is a Subsidiary 01 AtlantlcRlchlieldCompany MAR 11; }~Rq 't\, ........ ~.. ~~~ p~I.& Gas Cons.. Commission "~I~¡;~, &Ichoragø ; ('J~ ('; :Þ ~ ~ f11 C c_ c: NZ ~ ~~, C':J ¡-..,) C=' c:¿ ~.J-- ü5 ~ !2 ~ ~Qo ~ ~ C) ......., g.~ ,..... ::> C") _":- OJ O. C = I-' CD. S'1 . !..CJ ~.n j~ ,ª '-D :1 ëñ ~. q; OS A.N\ ~-r-;- ßI:J PRUDHOE SAY UNIT 6.8 SOURCE WATER (WATERFLOODING) FIGURE 6.8-1 SEAWA1ER INTAKE .. . IMRlNE UFE RE1URN MAIN 0U1FAU. .. EOA FACILITIES WOA FACIUllES WA TERFLOOD SYSTEM SEAWA 1ER 1IIEA1U!NT PLANT ·IIAIIIIE LH "ASS ...-cIUL ..... 2-50 rslt¡ ..... I ...... .. ...111I flED ...... HrAT ÐCØtAHCEIII ~ INØ1IGN I ....'IDS DrAEJtA1ION CQI..IMI __ PUMPS ~ ..... ;;c in n nï N01ES: '- It AND X-PADS CAN IIEI'a1YE _ Ale ... ....TANm&a.Y. ALL na WDA WIU. PADS_1M WA1DIfLOOD F~ CAN II!œNE _ (It "'- lIlT NDT 8tI'R I. T-PAD IIIaIVD WA1EIt WA F-PAD --Þ .<: 1M t:7 3. .-nt ... AND _ LAID MIll. CN.Y INITAL1D AT ONE DMJ.STE NIt FLOW STA1IOIII DS-1t. ... 1J.. crntER DML S1D CAN IBINE II1HIII _ .. N. ..-r NOT .-mt. LEGEND MGDUCID WA1EIt LIND IEAWA1EIt UND EAST IN.IEC1ION PLANT (NEAR FS-1) III.£T ~ HEAT IXOIAHIØt ND TAHICI ..... PUIP8 IIØIION ..... /1IIIWJIS ÞIOtl'Jl« ~ -..... (FS-2)-~~ pSI,. ,,_/ 1 1 > ,...-1 DRIU. 't 251Y ~i~ = -=-~:::~_-: ~~ ' 2 " 1. ' I "Z. IRLL . 17 Hø --' 'Z. 'i3 '" .. SITES ~ ~ \, '-'H1 ------------~ , Zoo/:!. '--, 1 12 I... ~.__ .... _-a- 0 4--1 FS-1 , 2.0/3 ps/(., DRIU. "tI.o J ~ -r--- \ /~ -p''-.)'I: o.:t.. 1:>$ \Z- ~- EAST _______~ SITES MAN. V/fI(' PSI(;,... I ~ I S'¡" J "2.1~f3 2.51'1 PSI&, 3 ..-. ~; . \1..\ Z.'lB7 "'-, . 1FS-3}:-J ~,_/ \n"-f5'9 ~. f'wx S-Nr -- 2.~ '-0"-. ~Ict Z?/l9 'ZS'1'f PSI/;, EAST""" 'IIE-IAE lEST IN.IEC'ßON PLANT (NEAR GC-1) HÐ~ HEAT EXCIINIIIIIS N.ET TMIC --- ....... IN.IEC1IDN ..... /1IIIWJIS ~ IWIf'IU ~-..... 1GC-3\...-, \....,,/ . I WEU. -tl1EST..-1 PÞD . 1"~ --------: X A ~-{~------~ ~ ~ ......-/ , lEST --------J PAD MAN. . . II Y 2 ..-. H N Ù I It ~-, I {CC-2}--J ......-/ .~ 1".1.":;' " PWI/SWI WATER INlECTION STATlS ') FLOW STATION 1 ) , 03-13-89 0903 . tow STATION DISCHARGE HEADER PRE&:--JJRE 2013 PSlG} ~ this r.\o\M.\?~r ;~ S\I1"t. ~'u~C(dt"" &r"~SSw"f. .W' ~Il rtfor+:. ......... . ., WELL . REC INJ. RATE 1 SWI ClIRRENT IN...!. RATE YEST IN...I VOL MAX IN...! HEAD WELL JELL PWI SWI PUMP PWI SWI PWI SWI CHOKE WHIP WHIP INDEX TEMP TYPE RILL SITE 1 8 0 2000 o o 2634 PWI SWI ----- 0 2947 90 0 2100 9.47 74 SWI VEST BAL FAC 1.135 1.004 M-T-D BAL FAG 1.070 1.000 DS HDR PRESS -8192 ·2013: OS HDR TEMP -8192 74 -- -- -- 'OTAl o 2000 o o 2634 o 2947 RILL SITE 12 PWI SWI 19 0 20000 0 0 20235 0 15145 47 967 '2000 31.87 73 SWI VEST BAL FAG 1.135 0.965 20 0 2000 0 0 2598 0 1650 7 ~'º '.: 2(1(10 8.25 74 SWI M-T-D BAl FAG 1.070 0.995 23 0 18000 0 0 18443 0 13303 57 1465 2000 11.71 73 SWI* [IS HDR PRESS .·2466) 24b7~:~ 25 0 0 0 0 0 0 0 1 2478 2000 0.00 91 SWI* DS HDR TEMP 64 ~~ 27 0 '0 0 0 '0 '" 0 0 *f' '*** 2000 0.00 HI SWI* ------ ---- ------ ------ ------ OTAl .~ 0 40000 0 0 41276 0 30098 WDW 1 ( 1-51> 65894 70700 1997 LOW STATION OTAl 0 42000 0 65894 43910 70700 33045 DENOTES WAG WELL tOTE: CHOKE STATUS IS MANUAL FOR ALL INdECTING WELLS $ .... ,'".,................. .".. ."- ,."-.............--.....,, -'.","~,""..,. .~...'.,,'-'"... . C,... ....,." ...._._. ..... ". ...-' ... ...., ,. ~, . . ...., . ... . . ,'..... ... --~'.- RECEIVED t\~AR 1 2: 1S~~ .':-"Jaska Dil.& Gas Cons. CommissloE . ¡ :;}. ~chorage "p t. 20 (~) :;J~.; O~ [12 2 ~I/SWI WATER INJECTION STATUS ) FLOW STATION 2 03-13-89 0903 ") .ow STATION DISCHARGE HEADER PRESStlRE ~ 2/8'2 PS't7 _)'>"'1- St..Þ?t!- t!:MC SY~EITM REC I~I. RATE 1 SWI aJRRENT INJ. RATE VEST INJ VOl MAX INJ HEAD WELL ::LL PWI SWI PUMP PWI SWI PWI SWI CHOKE WHIP WHIP INDEX TEMP TYPE ULL SITE 3 PWI SWI ---- 4 0 28100 8000 0 28571 0 9235 75 1423 1700 28.69 82 SWI* VEST BAL FAC 1.015 0.997 6 0 25000 5000 0 25140 0 11987 47 787· 2300 44.11 84 SWI* I-T-D BAL FAC 0.984 0.999 7 0 0 0 0 0 0 0 1 2384 1700 0.00 1** SWI* DS HDR PRESS -8192 ..:2388. 10 0 15000 15000 0 14795 0 7514 35 ·592· 2400 26.33 85 SWlf OS HDR TEMP -8192 77 11 0 10000 9000 0 10479 0 9502 32 1144 1600 8.01 83 SWI* 12 0 0 0 0 0 0 0 2 ··-2390 2400 0.00 fH SWI* 13 0 0 0 0 0 0 0 2 2390) 2200 0.00 *** SWIi~ 16 0 10000 0 0 10360 0 6762 22 ..!:369 , 2300 23.49 84 SWlf 17 0 116t)0 3000 '0 12124 0 8804 3b ",847~ 2400 13.59 83 SWIf 18 0 21200 6000 0 21920 0 7057 51 . 897·~ 2300 31.91 83 SWI -- ----- ---- OTAL 0 120900 46000 0 12::-œ9 0 60861 RILL SITE 4 PWI SWI --- -- 6 0 13300 4000 0 13300 444 9350 3 673" 1400 20.59 83 SWI YEST BAL FAC 1.015 0.938 8 0 20000 6000 0 20943 689 14019 18 1193~ 1700 21.66 84 SWI M-T-D BAL FAC 0.984 1.001 9 15000 0 0 10623 0 10392 0 11 :1639: 1800 6.46 150 PWI DS HDR PRESS ·2052 2046· 10 40000 0 0 36657 0 34647 0 175 -1933' 2250 30.62 151 PWI DS HDR TEMP 108 64 11 4000 0 0 11596 0 10983 0 1 . 15..E:ä8: 2050 7.06 151 PWI 13 0 13900 4000 0 14579 418 10237 21 1042 'J 2150 13.77 83 SWI 14 40000 0 0 36206 0 34717 0 333 1936 ~ 2325 28.51 152 PWI 15 0 0 0 0 5568 61 3994 14·1982 2400 2.68 80 SWI ·.RECEIV.ED 17 0 23000 8000 0 27793 0 28196 125 1776: 2500 20.54 ...80 SWI 20 0 0 0 0 0 0 0 98 ......, 6 ~ 1900 0.00 150 PWI 25 0 7000 0 0 6487 0 4918 56 .1851J 1900 -3.26 79 SWI 27 0 10500 3000 0 10183 253 7069 47,·1617.~ 2150 6.49 81 SWI MAR 1 h 1S~9 28 0 4800 1000 0 7100 43 5373 24 1413 '~2(J00 -2.80 79 SWI ------ ----- ----- --- ------ ¡OTAL .. 99000 97500 . . 26000 95082 105953 9264783156 ........... . .,..". ,.~...."" ,"" ".,_..._~'..~......_-- .._..'.....~~,~"",",' ...,.'...........'... .''''.._".. _·_··_······t~IaskaOil.& Gas Cons. Commission .: ï,ít,.;!~. ~ctïorage I :tRILL SITE 9 PWI SWI --- --- 8 0 4500 4500 0 4072 . 0 2593· 24 1285 1550 2.82 80 SWI YEST BAL FAC 1.015 0.926 10 "'0 ·····2500 2500 0 ·······2388 o '·'2052 . 15 '1361'\1500 '1.56 80 SWI M-T-D BAL FAC 0.984 0.993 12 0 4500 4500 0 3977 0 3M6 34 1742 2000 2.08 80 SWI* [IS HDR PRESS -8192 2338'·) 14 .0 32000 15000 0 31599 0 11002 62 1011 2400 88.51 82 SWI DS HDR TEMP -8192 64 15 0 21000 21000 0 20134 0 10167 52 1301'·:' 1600 18.01 82 SWI 16 0 32000 32000 0 31816 0 20426 71 1300 .,; 2000 58.16 82 SWI 17 0 0 0 0 0 0 0 3 1965' 2000 0.00 85 SWI* 18 0 25000 25000 0 26432 0 18880 62 1195') 1500 30.88 81 SWI 19 0 0 0 0 0 0 0 9 r.ß8, 1600 0.00 85 SWI* 20 0 21000 6000 0 26349 573 19683 48 897:; 2400 51.26 83 SWlf 22 0 4000 4000 0 2527 31 1719 18 1170 1500 1.98 81 SWI 25 0 16100 5000 0 14539 303 11047 39 940,; 1600 15.21 82 SWI -- - -- --- TOTAl 0 162600 119500 0 163833 907 102015 DRILL SITE 11 PWI SWI 2 30000 0 0 32317 0 24140 0 332 2034 1800 20.86 149 PWI YEST BAL FAC 1.015 1.012 7 35000 0 0 41294 0 36259 0 333 1997 1800 35.14 149 PWI I'I-T-D BAL FAC O. 984 0.997 8 0 10000 10000 0 10635 0 5638 'ð 1272 2000 8.09 80 SWI DS HDR PRESS 2127 -8192 10 0 10000 10000 0 9194 0 6717 4b 1797 2000 4.89 78 SWI DS HDR TEMP 131 -8192 26 0 10000 10000 0 0 0 0 48 ·:;,9' 2000 0.00 54 SWI - -- ----- TOTAL 65000 30(100 30000 74111 19829 60399 12255 SlJ\~\~hJF-(' fUN ~¡i C 00QR DRILL SITE 16 .. ...~.. 1.,,,: ,~L".. 1!.J'~.. '.1 ()I )' (,.... . ,(ir PWI SWI , 1 0 4000 0 0 3104 0 2745 26 958) 1600 3.06 81 SWI* VEST BAL FAC 1.015 1. 007 2 0 7800 0 0 8004 -) 0 6609 25 4Q2~ 2100 16.30 81 ]If M-T-D BAL FAG 0.984 O. 998 3 0 2000 0 0 1661 . 0 1506 18 34t: 1350 3.94 81 _, 1* OS HDR PRESS -8192 24:-f4 5 0 2900 2900 0 2643 0 1823 15 235:; 1370 7.80 79 SWI DS HDR TEMP -8192 69 10 0 1800 1800 0 2021 0 956 13 82T~ 1500 2.19 78 SWI . 11 .0 0 0 0 0 0 0 4 HH 2400 0.00 69 SWlf 16 0 6000 0 0 ~i69 0 4m 23 1088'1440 4.32 80 SWIf -- ---- roT AL 0 24500 4700 0 27d02 0 18416 JRILL SITE 17 PWI SWI ---- - ó 0 17000 17000 0 17024 0 135M 38 .....900) 1650 19.70 81 SWI VEST BAL FAG 1. 015 0.985 8 0 4600 4600 0 4701 0 3163 29 ···326' 1500 9.25 82 SWI M-T-D BAL FAC 0.984 1.050 10 0 3700 3700 0 10617 0 2379 20 :,251 1380 38.19 82 SWI DS HDR PRESS -8192 2417 DS HDR TEMP -8192 58 --- -- -- roT AL 0 25300 25300 0 32342 0 19106 =1rIDW 2 ( 4-19) 40995 41439 1865 ::.wDW 2 (11-51) 82925 72895 1861 =tOW STATION TOTAL 164000 460800 251500 293113 468148 2~~87 295909 . . . DENOTES WAG WELL \(ITE: CHOKE STATUS IS MANUAL FOR ALL INJECTING WELLS ~$ .' ._..'.. . "4.~....·"..,. ,"'." .. ,h ._,,'. . 4.... ' . .., ~.""_~"'_~'ø'_'_""~',""M'" ._........._.....__.."..,. .._,..". _._"."_.,.,,~_,,,_., ",', ... _... '_w" .._,.,~",~_.... _""'~_'" ,_. "._..._-_....,,~...""~............._-"_...-, ...-......-........... ..~...""..,,.~ ~,......._-,_...,.._.,."...'.., ....,..~.._,.". ...... .......-..,...." ,,,,,, ",'....".. ..... ~............",'~,~..''''..." "..,."... ".,..~...,.. ~.. ,_."........., . . ........ .,. ...-..,.".....,"" '..'~,," . " " .",......,...... ,.... .. .. ".- ".. .' ~, .... .~..,_.~- ...-.~, ~.._- 3 0 2GDl}. :,',j "! i I\J 9 n 2 0 1:-'1 FJ . 1 - ~)I (, ~ Ij c." ~:) ,.. iJ~J' -.,. ~.. .--'- . - ..'.-...~ ".. ,..... '" "' ~. . .... ,~.... '.'. "" ...._..~--.....,......... . DENOTES WAG WELL IIOTE: CHOKE STATUS IS MANUAL FOR ALL INJECTING WELLS ~$ 1039 ~DW 3 ( 6-51> 8105 7603 .,-", ''"'' .........,..........,-.,.,,".."'. . . .. .... ,'..".~~ ''''~~''';'''''''''"'-'~'''-'-'''''''''''.~'''''''''' ,....,.."..'....~'...'.,.....',_...-....._...__.........' . i.OW STATION rOTAL 136500 44400 10000 126686 39044' 114338 4022 ...,,,..., . ..,"'_...._.~-. PWI SWI ---- -- 12 1135:. 1600 4.51 81 SWI VEST BAl FAC 0.951 0.606 10·,..25(1 ~1600 13.22 84 SWI M-T-D BAL FAC 0.960 0.966 20 ~927' 1500 26.11 82 SWI DS HDR PRESS -8192 ",,2487, o . e260 0 0.00 90 SWI* DS HDR TEMP -8192 69 14:*~850.: o 12.01 82 SWI* o 4982 0 343 o 3226 0 214 o 20183 0 2837 o 0 0 0 o . 10653 0 628 -- - --- o 39044 0 4022 4000 3000 "'"3000 o o 10000 5000 4400 '25000 o 10000 44400 )fULL SITE 14 13 0 14 0 25 (I 27 0 36 0 ·OTAL 0 , J.J. .:: oj PWI/SWI WATER INJECTION STATUS ) flOW STATION 3 ) 03-13-89 0903 lOW STATION DISCHARGE HEADER PRESSURE 1726 PSIG...1 WELL REC I~I. RATE 1 SWI CURRENT I~I. RATE VEST INJ vet MAX INJ HEAD WELL ELL PWI SWI PUMP PWI SWI PWI SWI CHOKE WHIP WHIP INDEX TEMP TYPE - --------- IRILL SITE 13 PWI SWI -- --- 6 "11500 0 0 11190 0 9842 0 59 1333- 1800 8.27 147 PWIf YEST BAL FAC 0.951 1.000 9 3bOO 0 0 3291 0 3236 0 10 326· 1800 8.64 150 PWI* M-T-D BAL FAG 0.960 1.000 15 2700 0 0 .. 619 0 ~~ 0 173 ,1553· 1800 0.40 148 PWI* DS HDR PRESS ~1561 ~~,~2483 ~ 16 8300 0 0 8114 0 7029 0 55 1272 1800 6.53 146 PWIf OS HDR TEMP 109 116 17 22400 0 0 19405 o 18046 0 87 1355) 1800 16.70 160 PWI 18 11000 0 0 10214 (I &.~9 0 86-1492~ 1800 7.01 143 PWI 19 16000 0 0 15888 o 13944 0 tH ·1324> 1800 13.08 152 PWIf 20 8700 0 0 8712 0 8246 0 39 1121 ..:> 1800 7.86 148 PWI 21 14000 0 (I 11062 o 10150- 0 ..' 65 1147:> 1800 10.74 150 PWI* 22 14500 0 0 12097 o 11121 0 54 IObb 1800 12.60 149 PWIf 23 6900 0 0 3529 0 3840 0 5 735 .. 16'00 4.98 146 PWI* 24 0 0 0 0 0 0 0 1 1648 1800 0.00 80 SWIf 25 11500 0 0 8718 0 7267 0 165 1468 1800 6.24 148 PWI* 32 5400 0 0 5742 0 4947 0 14 1040. 1800 5.91 135 PWI* --- --- -- --- ----- 'OTAL 136500 0 (I 118581 o 106735 0 , <HJN ~~ 0 20ß!j. ~,." ,- .._-.. ...' '.- "" - .' ~.._, '. . '..~ ~...'.... "--._,, -. ~ - .-.,.-......... . -........-.._... .'.. .......' ,.._.".._......_..~'..._,_ ~.' <' ".... .. 4 ,,~'_ '''~ ..._.,~ ""~' ... ,~.. . .,. . ...-,"" -".".--'''- .~. .~,,-,.,~.. .,. ~ ",-.,-,,",. -...., "-. -~'.","'. - '.'......... '.. _.".~.,., '.,,-. . -....--j,o... "'''-''__'''_''',.~.-.'' ,.. L.._.,..._.,,., ". . ...n .',. ....c. ""..,",,,.,, "~~' . ".."."'1"_..'.....".,..." -'~'''''''''''''''' ...··'1..'..·......·,,·......·'..." ........'"....'.-~"..,. ,. _.,' ..."."...,.....,.~'.',." .,.....,.....'.,.~..."",_....,_..........._.,.".....__,..'....-........,....,. "''''''0 "'''''''~'''''''''.'''' '~"...~ ~," .,'''..,."..,.... ...,,:... . . . .~-..,~" ,,"~.., . ~N20 10869 H P 'lITES) ) 3IPC ONE HOUR HISTORY (LAST 60 03-13-89 0904 31l0-P-424IL INJ PUMP MANIFOLD DISCH PRESS )\/ID 10869 rrME READING TIME READ I NG TIME READ! N6 TIME READING )805 2583.9 0820 2512.2 0835 2492.4 ~o 2445.1 )806 25...C(). 9 0821 2506. 1 083b 2487.8 0851 2446.6 )807 2582.4 0B22 2504.6 0837 2486.3 0852 2449.6 )808 2585.5 om 2500.0 0838 2484.7 0853 " 2457.3 )809 25B0.9 0824 2495.4 0839 2489.3 0854 2477.1 )810 2577.8 om 2493.9 0840 2490.8 0855 2478.6 )811 2576.3 0826 2493.9 0841 2493.9 0856 2486.3 :>812 2574.8 0827 2492.4 0842 2495.4 0857 2495.4 )813 ?="~2. b 0828 2492.4 0843 2490.8 0858 2498.5 )814 2553.4 0829 2489.3 0844 2486.3 0859 2500.0 >815 2551.9 0830 2489.3 0845 2481.7 0900 2509.2 )816 ?=".A2.7 0831 2489.3 0846 2474.0 0901 2509.2 )817 2536. 6 0832 2490.8 0847 2471.0 0902 2504.6 )818 2525.9 0833 2489.3 0848 2463.4 0903 2513.7> >819 "2518.3 "0834 "." 2492.4 . "0849'2454.2 ." 0904·' 2507. 6 ~$ P J 1\1; ~1;, f:. ?f'I nIJ fÌ I: .. t... t:'~ (,! \~~i: t~.. U !l...~':- ll\~R 1 ,'-. 1S~}'~' tJas~<a Oi\ & Gas Cons. commission 'Anchorage RE<:.E\\jEO .~"'."-' .....-. --. '. '".. .",. ,~. .,~"... -. -... .~"'"'''' ..."......... "'-'" ..,,, ....,..,... ,"'.,....,~".._.,.-..,.. ."...,._,.~--.__.".....~,_......,._...,..,-..-. ......,. ".-.....,. ...".... ..."..,."....".."~, .,...,....,.~,...'.,¡ ""~'.'''' .,............"".,,". ~ 10870 H P )TES) } HPC ONE HOllR HISTORY (LAST bO , 03-13-89 0905 1140-P-77IL IMF2 XFER LINE PRESSURE (PSIG) :'VID 10870 rIME READ I 00 TIME READING TIME READING TIME READING ~OO6 2565.6 0821 2486.3 0836 2467.9 0851 2426.7 )S07 25b4.1 0822 2486.3 0837 2466.4 0852 2428.3 )808 25b8.7 0823 2477.1 0838 2463.4 0853 2442.0 )809 2564.1 0824 2475.6 0839 2469.5 0854 2457.3 )810 2559.5 0825 2474.0 0840 2471.0 0855 2463.4 ~811 2561.0 0826 2472.5 0841 2475.6 0856 2%6.4 )812 2556. 5 0827 2472.5 0842 2474.0 O'æil 2477.1 )813 2542.7 0828 2472.5 0843 2471.0 0858 2481.7 )814 2536.6 0829 2471.0 0844 2466.4 0859 .2480.2 )815 2532.0 0830 2469.5 0845 2461.8 0900 2490.8 )816 2524.4 0831 2467.9 0846 2454.2 0901 2492.4 )817 2516.8 0832 2469.5 0847 2451.2 0902 ' 2484.7 )818 2507.6 0833 2471.0 0848 2442.0 0903 ·2493.9 )819 2500.0 0834 2472.5 0849 2432.8 0904 2489.3 )820 2492.4 0835 2472.5 0850 2422.2 0905 2483.2 ~$ ÄN20 10871 H P >~ITES) ') SIPC ONE HOlIR HISTORY (LAST 60 03-13-89 0905 3140-P-8SIL IMF3 XFER LINE PREK-;LIRE (PSIG) PVID 10871 TIME READING TIME READ I NG TIME READING TIME READING 0806 2~t8. 0 0821 2478.6 083b 2460.3 0851 2417.6 0807 2559.5 0822 2478.6 0837 2460.3 0852 2420.6 0S08 ' 2561.0 0823 2469.5 0838 2457.3 0853 2432.8 0809 2556.5 0824 2467.9 0839 2463.4 0854 2449.6 0810 2553.4 ~~5 2466.4 0840 2463.4 0855 2455.7 0811 2554.9 0026 2464.9 0841 2466.4 0856 2460.3 0812 2550. 4 ' 0827 2464.9 0842 2467.9 0S'5ì 2471.0 0813 2538.2 0828 2464.9 0843 2463.4 0858 2475.6 0814 2529.0 0829 2463.4 ,0844 2458.8 0859 2474.0 0815 2524.4 0830 2461.8 0845 2452.7 0900 2483.2 0816 2516.8 0831 2%0.3 0846 2446.6 0901 2484.7 0817 2510.7 0832 2461.8 0847 2443.5 0902 2477.1 0818 2500.0 0833 2464.9 0848 2434.4 0903 2486.3"' 0819 2492.4 0834 2466.4 0849 2426.7 0904 2483.2 0820 '2484.7 0835 . 2466.4 ······0850 "'2416.1 0905 - 2477.1 $$ .,.' '.... ""..""". ..... ..."~ , ..." ._,...._.w._·" .....,.. .....L~.·" , '", ,... ''''''', ,_." "." ,~..,,_. ....,," "..' ._, ,,'....._'.~.... ,. "'-"~ .. ,~.,,,. ". .,'.' ..., -,,,._- ".. .'.... '". ........,..,.-.,.~-,'., ""~"."""""~.""._"""""" "-'~" ".....'~_._'.. ,-.......,-...-.,....-.--- ,_..~ .----~'....._,..-'.~-..-.--"."~......,' .....,..-.. ....."~..,'....,.--,,~-~_...............~.....,.'"...,, ..... .......,..." -, .~'''" .-...,. ..,.,.". ....,..~. '... . .... ".~.",..__...". '''''''. ..... . .. ..._~.~,,,... '."'___""'"~~'~'. .......,... ........ ...,.,"'..,_.,.,.... ".·r'" '_.".." '. ..........~~""~ -,"", ....~,-,~ ,'~_...~~ ..-."_......,~~..... . .."~.......-.~~., ~- ... .......... ~, , ." .~. . ,.....,.,....' .~..._~,,_. ........". ...... .,.,~... "~'.' ...._ . "..._..~. ...h~..._.__·.,...~..... '''~ ,.......... ,.. .... .... .... '. ".. ........... M._...... '.. .... ~,,_._ ,,,~."" .... ",.. w~ .." .....,. ,. " ""_"". .,,, ........ . "",.,. ._~. _,""'.. .... "_.'_".". '.' __'~"""'" . ~""~_"_""'~_'''.~''~''~'''''''''' '_~"""'~"_'" "'._...,........ .~.. ,"~. ..... . ".-.... - "þ ~ '. .. . ...... .. _.. . ~ "....... -.... ......, ......... .. ~ VJ.Ct\'it\) 1. h '{-,~ 1"1, ~.j\~?~ cotntn\SS\()(\ t'~ns. ' 1 & Gas vu \\as\œ. ~\ \' ·~tho~qe . "fi' f, h.ii ~.~ tii' GJ. DDff - c, t I:i \0 V {,. ,'-it ~20 10076 H P ONE HL1.JR HISTORY (LAST 60 MJ.I~hS) ) ¡PC 03-13-89 0905 l30-P2S-301CI EIP SUPPLY LINE PRESS (PSIG> lID 10876 [ME READING TIME READING TIME READING TIME READI NG 306 250.0 ..0821 250.0 0S3b 250.0 0851 250.0 :tJ7 250.0 0S22 250.0 0837 250.0 0852 250.0 BOO 250.0 0S23 250.0 0838 250.0 0853 250.0 309 250.0 0824 250.0 0839 250.0 0854 250.0 810 250.0 0825 250.0 0840 250.0 0855 250.0 811 250.0 0826 250.0 0841 250.0 085b 250.0 312 250. 0 . ..-- 0827 .... 250. 0 0842 ,. 250.0 0857 250.0 813 ~...o. 0 0828 250.0 0843 250.0 0858 250.0 814 . 250.0 0829 250.0 0044 ......250.0 .0859 250.0 815 250.0 0830 250.0 0845 250.0 0900 250.0 816 250.0 0831 250.0 0846 250.0 0901 250. 0 817 250.0 0832 250.0 0847 .... ..... 250.0 0902 250.0 818 250.0 0833 250.0 0848 250. (I 0903 250.0' 819 :r:-...o. 0 0834 250.0 0849 250.0 0904 250.0 820 ... "'250.0 0S35 250.0 0050 250.0 . 0906 250.0 .$ "~.... ""-~,~. ...-..--..,-,- --,.-,.~-,,,..,~...'."".~' '. ,',' . ............ .,...."...., ......'..." , , . ....,_'._.....,. '~""""""_'~'''''.'''. ,.",~.'.'..........".,.''',_ _,~'" ,."..."."..."".,. .,.,....''''.."....,.,...'','\.....,.........,...,.._.....ø..._..._".,,",,,,,_,,,,,,,.._., .~ ."., , , "'~'" ."......~......_."....,'-..., . ' " ..'......,.. '.' .. ...'_., -...., -........". ... ..·'I..·~--..--."·..~~'-...........~,-."....'..'.'"....,,.' "_,,, ," '..' .."....~-,,-_..-.....". .""" -..... ,.. """"...-..,,,. .,.',.,....~,~...'~._.,_.... ...........'".'.,. .,.....'...-.. . . .,....,,~.......\ ,~. '....... ..."...,..,~._..... '....__...._'_..TUU. '.'''~.'' ...,........' ,,'ri. ,. ...........,. ..... ~. '''~'' " .....~" , '... ". ."-'" . .' '."~.-.__. _._-.. -. '.... . ,·(¡UN ~] 0 2.0D4 N 0\ ~t,.) '.-----;;.- ~< ,~ª o f'...) C:t C.;.J ~ I~i':"!l' p:¡ tn ~ -'0 ¡) -. .- - 'Qo ~ø n$:U ::rcn 0g ~::s Q3. 5'1 C") - 0 a ë. en (J) õ' ¡.:;:} ..--.. PRUDHOE SAY UNIT . 6.8 SOURCE WATER (WATERFLOODING) FIGURE 6.8-2 ----------._-- - -+ - ---.- -_..~--,--- ---.- ._-- .MAIN AREA WA TERf'LOOD DISTRIBUllON SYSTEM . I ~ SEAWA ÌER THEA 1WENT PLANT \ ( f' S-/!.,AD ~\\.R-PAD .C :P:PAD ,,~_... "I U-PAD '- ".ZI ( _Po AD I J-PAD G-PAO 1112) ----- , (1112) I rzJ ~ GC-1 OS-15 I q'GC-2 . (1812) I U P . . / . ßC-PAD 1'1 \ - AD CJ H-PAO ~ . T (1188) \ . :;t7 D-PAD GC-J D5-7 \ DS-5 OS-11 DS';"4 s: m (UUI2) (1188) j)S-~\.. (1182) Q g ?b ('1 V-PAD c:: 1· (1882) ~ ~ 5-2 to- m A-PAD Ü -PAD r ~~ .; <: is':j. P.flt Ò OS-1 :~ rn X-PAD '9 05-8 o 05-14 '(1882) U DS-1J .~ LEGEND o II . o -/ DRILL SITE / WELL PAD INTERMEDIATE MANIFOLD INJECl1 ON" PLANT FLOW STA110N / GAlHERING CENTER HIGH PRESSURE UNE LOW PRESSURE SEAWATER UNE FU1URE DRILL SITE / WELL PAD . EXPANSION ----- FUTURE HIGH PRESSURE UNE o D5-12 D5-17 ~ OS-UI N 0\ W .~ -- -- ~ ~ ~ o r<~ c:::> ~ <('~ /",..-.. '. -.-....." \ PRUDHOE 8A Y UNIT 6.8 SOURCE WATER (WATERFLOODING) FIGURE 6.8-3 SEAWATER 'TREATMENT PLANT PROCESS FLOW DIAGRAM < 1mgJt "'" suspÐmm , ~'V '1)$ ( 4 A UARINE UFE RETURN 4-...--.-.-----...-----~--1 I I II. .., I 1-, SEAWATER . f III · 2.2 UUBD III· INTAKE ~ (DESIGN) . III --þ RESERVOIR ... · t1.6 0 WUBD LtAX. III WAQTY wI CURRENT III' \. -/ EQUIPMENT IN USE) . . III . FILTER FEED ~ ~IU '. . ~M~ III . (4)-17:10 HP EA. S1RAltERS SCREENS A ( ) 1______-----.---- - ____-.-____, ,- RECYCLE S'(SlEM ~ UNE to WEST r---" INÆC110H PlANT I I ~ (1.0 ......80 ORIG. I OESlGN CAPAa'N) I ::~ PSlA 40- UNE TO EAST I ,.. ~ . lNoIEClIDN PLANT I I ... (1.2 U&.tBD ORIG. I I DESIGN CAPACI"M t___.J OUltET lRANSFER MANIFOLD PUMP (1x3OO ...80 AT 1750 HP fA. . IN USE) /' < 20 ppb 02 .~ " / BOOSTER . PUUP DEAERATORS Ix300 MIlD AT ./ (I OF IIN USE) 700 HP EA. . IN USE) r---'" I I I I I I I I .. --: I I I I : I L.__-' . HEATER INLET MANIFOlD ---...-- .- ---- .- F1L TERS (1. IN USE.1 '-. . ~yc:. HEAllNG SYSTEU (4) I I I , 4O"F ,.- )- -' . . .. - -..., . PRUDHOE BAY UNIT 6.7 PRODUCED WATER HANDUNG FIGURE 6.7-5 FLOW STATION 1 PROCESS FLOW DIAGRAM PROOUŒD WATÐt (JIW'} f'ROU f1.OW STA 110M ~ IIPAMl10N 11tAId ~ ~ DRÜ'" ) t ~ -f( f] PRODUCED WA1ER TANK 2-BOOS1ER PUUPS 2-INJEC11ON PULtPS 1.71 ... £A. -- SKIt.t OIL TANK f{f I BOOS1ER I I PUMP I L--W-J BOOSTER PUUP f] . J-. TO INJECl10N ww.s N U1 ....... .+ I I I I I t" . I I fNJECl10N PUWP .... -- ~ OVERFLOW DIRTY WATER TANK . TO s.oP (XL TANKS . - ~ ...- C~ -Þ I I I I I I I :::.:.:. :.:: :.: :.:.:""::: :.::. ~.:.::.:: I ........................ ...-..:::::~:~~WO~TER~.:::::::: -....... '" ....... ~... ~~}}~:~~~~g~~~~~- ~' BOOSTER PUWP . f] f] --. TO CRETACEOUS . WEU.S -' .....~ f"~ c::::> ~ DIRTY WA1ER PUUPS DISPOSAL PUMPS vm FU1URE (1181) IÑSTAlLAl10N FU1URE (1181) INSTAU..A 11 ON e':·:':':·:':':] FU1UR£ (1111) INSTAUA 110M ---- FU1URE (1111) INSTAU..A 11 ON C'~ "jo p;Î tn ~ l~ i' 't? .-"'" S20 ,tD ~ Ci) I, (") ~ C-...ðn "'"~ ~ 0 ::~ (Q ~ é~"'Ç:J CD . (:..Sì ,~ f-....:;¡ r.:::J c::.) c!.~J >- N U1 CO ("') C) 3 :3 ëñ" tn g" ~ ::=c ::Þ m :U n ¡..-a rI' .- -- '--' < '[,~ ):, n1 ,') CJ · PRUDHOE 8A Y UNIT 6.7 'PRODUCED WATER HANDUNG FIGURE 6.7-6 ",OOUCED .Am ntOU now ITA'ßOH R'PMA'ftON 11WNI FLOW STATION 2 PROCESS FLOW DIAGRAM OVElVLOW DIRTY WATEIt luu.lf.ft INÆC110N TANK PUMPS PUMPS 10 INoIIC1IOM ,--...-----~Øh--r.;a.'a' ~ . I i:""J §J IIWt . >- E I .. .}::1 . = ~t1:s 1. I ~__J 11111 IHSTAl.LAlION ft----------------------------J.W--- ~ . IOOSTER IN..EC11ON PUWPS PUUPS t~ ._~~ tg~--~--l . r- WP~ ~. r4~/.. ;~(}ß ~--~------j . (;í0i t PRODUŒD . WA1ER DRUt.t _ -~? ..-: ¡¡~ PUUPè ~œa-; PRODUŒD WA 1ER TANK -~ > 5KIt.t OIL TANK 1D1LOP aa. TANK ~ DlR1Y WA1ER PUWPS ~ ~ -' NOTE: Rm.ECTS CONROURA.l1ON FOt.1OVt1NO 11n ADDIl1ON. - - - - -- - ~- .-- - -- -.-' ~ - --- 6.7 PRODUCED WATER HANDLING FIGURE -6.7-7 PRUDHOE 8A Y UNIT FLOW STATION 3 PROCESS FLOW DIAGRAM PItODU('C1\ WA 1!It (pvt) FROU FlOW STATIOff . SEPAftA 1ION 1ItAINS N U1 \.0 . (D:U) + ~ '-" -:. PRODUCED WATER TANK .~ ~ 10 1f.£1lGN Ml.LI SKJWon. TANK F1L TER . PUUPS ~~--l . ........... Ø()()SlB ~::::::::::: puups L-- ............ - '~ :::....:::..:... r........... ~ ...................:.... r ........... ........... ............. , ',f1L TERS _, ::0·'·'·'·'·0·'·'·'·'·' . '------.... INJECl10N PUMPS -Þr. cf ~. ~ NEW PWT fAauTY rn OVERFlOW DIRTY WATER TANK . 10 SLOP (L TAlI( " r~ _/ c: ¿';, --tÞt ~ ~ Þ 10 aErAc-tQI W!U.S e}~ C'~ ,..'-' t:::) C-~ _.f-:.> DIRTY WATER PUMPS DISPOSAL PUUPS ~ INDICA'ID NI' fAQIJ1Y NOT IN SÐMŒ 'tV.......ASS (TANK AND fLTER TO BE PlAŒD IN SElMŒ If 1880). -------...--- ............ ........... þ........... ........... ............ ........... ,-....... ..............._-'iII INOK:A 1!S NI' FACIJ1Y IGTAU.ED IN 1110. // ./ . / #4 ") 1\ J¡ - /3 ) ) INJECTION WELL ANNULAR COMMUNICATION VERBAL NOTIFICA TION OF AOGCC PER AREA INJECTION ORDER #4 DATE: 10/17/88 TIME: 10:00 am NOTIFIED BY: Ellen Fitzpatrick AOGCC CONTACT: Mike Minder REASON: Injection Well i:.1.3. Annular Communication Per Rule 7 Requirements of Area Injection Order N.o. 4 ) DISCUSSION: OS 4-13 failed a State-witnessed MIT on 10/14/88. The 9-5/8" test pressure of 2160 psi declined to 1600 psi in 30 minutes. A repeat test had the 9-5/8" pressure decline from 2190 psi to 1940 psi in 30 minutes. During this repeat test, the 13-3/8" pressure increased from 520 psi to 1160 psi indicating 9-5/8" X 13-3/8" communication. The MIT was repeated on 10/16/88 (no State witness was present) with 2000 psi on the 13-3/8" and 2160 psi on the 9-5/8" . Both casings passed the pressure test verifying that the 9-5/8" leak is above the 13- 3/8" shoe and there is no leak from the casing to the formation. The tubing is intact with no bleeding required to maintain the 9-5/8" pressure below 1000 psi while tubing injection pressure is at 1750 psi. OS 4-13 will be a water injector only (no gas injection). Permission was requested to continue injection indefinitely unless annulus pressures indicate a tubing leak develops. If such evidence of a tubing leak occurs, a remedial workover plan will be developed. . AOGCC RESPONSE: - Approval granted verbally to leave on injection for 1 week with a formal request to extend injection past one week. - State witness of 9-5/8" X 13-3/8" MIT is not required. Sundry Notice Req'd at this time? YES .2l NO _ SIGNED: é!JfiJ!ài1J0:' a ,.{;¡,.. P.S.Piuc.e... prOdUCti@Jšupport Superintendent Orig: Ann Comm Eng, PRB 24 Billingsley/Lucich cc: Prod Sup Supt, PRB 20 Skaalure/Pierce Sr Wireline Supv, PRB 20 Kennedy/Wilder Field Area Eng, PRB 24 Sennett/Zibell OS Supv, FS#2 Clark/Robertson FS Supt, FS#2 Beaudry/Cavin OS Eng, OS#3 Surritt A TO-1586 p \:.ct \\J\~\) \', t- o ø \r- ~ P) -í "\.-, :>1)' ('\ (' \ ~ . .J ,J 0 '~C'\fjí1 ... CO\í\\íì\~';;' . & C\3.f, Cl:'n.J· ''';\ 0\\. ..,,::.f\e f\\'ðs,,1. p,n::-Xìr:.1 :~.' 0) AcJ/G eel ó - '-t 6 3 C(, (? / () rI Q ¿ ( 0 /2 6/ {) fJ ~ 8 - É1 08 . " ) .JUN ¿~ 0 20D¿~ #3 --\\~£O srJf)': -::;~ ~.s> r"......{, ~ -. %. ~~~ o "f \ ~ «'1- J....{) ;-"'l. PRO'~v U.S. ,-,tIRONMENTAL PROTECTION AGb)CY REGION 10 1200 SIXTH AVENUE SEATTLE, WASHINGTON 98101 NOV .. 1986 REPLY TO ATTN OF: MIS 409 J. W. Hart, Manager Prudhoe Operations ARCO Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 RE: Termination of EPA Emergency Permits at the Prudhoe Bay Unit (Prudhoe Bay Field - Eastern Operating Area) Dear Mr. Hart: The Alaska Oil and Gas Conservation Commission issued the ARCO Alaska, Incorporated an Area Injection Order No. 4 for the Prudh~e Bay Unit (Prudhoe Bay Field - Eastern Operating Area) on July 11, 1986. Therefore, the following EPA Emergency Permits for injection wells are terminated in accordance with 40 CFR 144.40: AK-2R0046-E through AK-2R0072-E AK-2D0105-Eand AK-2D0106-E AK-2D0254-E AK-2R0255-E through AK-2R0258-E AK-2R0271-E through AK-2R0278-E. Also, EPA rule authorization under either 40 CFR 144.21 or 40 CFR 144.22 for other existing Class II injection wells is terminated. Sincerely, (l&f~ Robert S. Surd Director, Water Division cc: C. V. Chatterton, AOGCC - ,..,... ..... JUN¡ ~. (] 200lJ. #2 ,JiUN 3 0 2004· ~"- ð 1t l\ \ ) PRUDHÓÊ BAY. UNIt EASTERN. OPERA TIN'(J:; AREA AREA .INJECTION· ORDER APPLICATION .~ ( I I I I l I ( (' :1'" , Prudhoe Bay Unit Eastern Operating Area Area Injection Order Application TABLE OF CONTENTS Section/Regulatory Cite Subject Page A. 20 AAC 25.460 Area Injection Order 1 B. 20 AAC 25.402(c)( 1) Plat 2 20 AAC 25.252(c)( 1) C. 20 AAC 25.402(c)(2) Operators/Surface· Owners 4 20 AAC25.252(c)(2) D. 20 AAC 25.402(c)(3) Affidavit 5 20 AAC 25.252(c)(3) E. 20 AAC 25.402(c)(4) Description of OperatiQn 6 F. 20 AAC 25.402(c)(5) Pool Information 8 G. 20 AAC 25.402(c)(6) Geologic Informatìon 9 20AAC25.252(c)(4) H. 20 AAC25.402(c)(7) Well Logs 18 20 AAC 25.252(c)(5) I. 20 AAC 25.402(c)(8) Casing' Infor ma tion 20 20 AAC 25.252(c)(6) J. 20 AAC 25.402(c)(9) Injection Fluid 22 20 AAC 25.252(c)(7) K. 20 AAC 25.4-D2(c)(10) Injection Pressure 29 20 AAC 25.252(c)(8) L. 20 AAC 25.402(c)(ll) Fr acture Infor ma tion 30 20 AAC 25.252(c)(9) M. 20 AAC 25.402(c)(l2) Formation Fluid 33 20 AAC 25.252(c)(l0) N. 20 AAC 25.402(c)(l3) Aquifer Exemption 36 20 AAC 25~252(c)(l1) O. 20 AAC 25.402(c)(l4) Hydrocarbon Recovery 4-0 P. 20AAC 25.402(d) Mechanical Integrity 4-1 20 AAC 25.252(d) Q. 20AAC ,2.5,.402(h) Wells Within Area 42 20AAC 25.252(h) R. 20 AAC 25'~450(a) Var iance Request 43 8Gt:òr¿INJEr) nli ¡n,\)i ".f. '.,:¡ 2,' PO Ii ~., "-II Q) b ,I c,¡} \1,:1 _ d U¿~ Figure. A-I Figure A-2 Figure A~3 Figure B-1 Figure G-l Figure H..; 1 Figure 1-1 FigureJ-1 Figure 3-2 Figure L-1 Figure M-1 Figure M-2 Figure N...l Figure N-2 I¡" ~. (. Prudhöe Bay Unit Eastern Òperàting Area Area Injection Order Application List of Figures Ti tIe Legal Description of Area List of Injection Wells with EP A Permits List of Injection Wells Authorized by Rule Plat Map Structural Cross Section Type Lpg: Sag River State III Wellbore Schematic Typical Fluid Analyses - Ivishak Typical Fluid Analyses - Lisburne Fracture Gradient Curve Fluid Analysis - Wèll GC-3C Fluid Analysis - Well GC-3D Documentation of Equations Calculated Wire line Salinities ~1)Cf\NNEu ~JUN ¿:~ 0 200((J t { SECTION .A . Area Injection Order 20 AAC 25.460 ARCO Alaska,. Inc., as operator of the Prudhoe Bay Unit, Eastern Opera~ing Area (EOAl, requests an areajnjection order beissued for current and prpposed injection wells: 1) for disposal of fluids that are brought to the surface in connection with conventional oil and gas: operations and comingled with non-hazardous waste fluids from ~acilities which are an integral part of produstion and operation, and 2) for the enhanced recovery of oil· or gas. The area injection order is requested to encompass all lands within the boundary of the EOA, except for K-Pad, as detailed in Figure A-I. ARÇO requests that the ord~r allow A;RCO to drill, operate, conxert or plug and abaoQon wells within this area by filing Form 10-401 or Form 10-403. The Oil and Gas Conservation Commission may, in its discretion, issue an area 'Ïnjectiöo order if certain requirements are met. The EOA injectioo.operations meet the requirements of 20 AAC 25.460(a). Existing wells are described and identified by type. InJection wells are within the same field, are operated byasingle operator and .are used for other than hazardous waste injection. The cumulative effect 9f drilling and operating additional enhanced recovery injection wells wiU result in an increase in hydr.ocarbon recovery. The cumulative effect of additional fluid disposal wells is anticipated to be economic disposal of non-hazardous oilfield waste streams. Disposal of produced water and associated Waste is necessary to allow prqdlJction of oil. Both types of injection wells will be dl:"illed, constructed, operated, and abandoned in accordance with the Commission rules to prevent movement of fluids into freshwater strata.. Figure A-2 is a list of injection wens in theEOA with EPA permits. Figure A-3 is a list of injection wells iothe EOA authorized by rule under EPA's injection well regulations for Alaska. 1 ~'í(" #~ t,,~~~,,~ ~?)~:'ð1\h;lhEL.':1 IIJUN Jt t~ 200/1) TI0N..RI4E Sees. TI0N-RI5E Sees. TI0N-RI6E Sees. TIIN-R14E Sees. TI1N-R15E Sees. TIIN-R16E Sees. ( ;( Figure A-I Legal Description of Application Area (EOA Excepting K-Pad) 1, 2, 3, 4,9, 10,11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26,.27, 28, 36 ' 1, 2, 3, 4, 5, 6, 7, 8,9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28', 29, 30, 31, 32, 33, 34, 35, 36 4, 5, 6, 7, 8, 9,16, 17, 18~ 19.,20,29,30,31 /( 1, 2, 3,~ 9, 1 0, 11, 12, 13; 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 33, 34, 35, 36 ' 1, 2, 3, 4, 5, 6, 7, 8,9, 10, 11, 12, 13, 14, 15, 16, ~?, 18, 19,20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 3, 4, 5,6,7, 8,9,10,11, S/2NE/4, NW/4, S/2 Sec. 12, SW/4NW/4, SW/4, S/2SE/4 Sêc.2, 13, 14, 15, 16, 17, 18, 19,20,21,28,29, 30, 31, 32, 33 T 12N-:-R 14E Sees. 22, 23, 24, 25, 26, 27, 28, 34, 35, 36 T 12N-R 15E Sees. 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N~RI6E Sees. 28, 29, 30,31,32,33, SW/4, W/2NW/4,SW!4SE/4, 34 5)t;j:,~~~NED ~JUN i] I{J 2001J ~I ",{ \ Figure, A-2 Prudhoe Bay Unit Ea~tern Ope'rating Area Injection Wells with EPA Permits Well Permit Number Well Per mit Number LGI-6 AK-2R0255-E 3-16 AK...2R0054-E LG 1-8 AK-2R0256-E 3-17 AK-2R0055:-E LGI-10 AK...2R0257 -E 3-18 AK-2ROO56-E LGI-12 AK-2R0258-E 4.;.6 AK-2R0057-E LPC-l AK-2D0254-E 4-9 AK-2ROO58-E L2-6 AK..2R0278-E 4-11 ' AK.;.2ROO59-E' L2-20 AK-2R0273-E 4-13 AK-2ROO60-E L2-24 AK-2R0274-E 4~14 AK-2R'OO61.;.E L2-26 AK-2R0275-E ,4-15 AK.;.2ROO62~E L2-28 AK-2R0276-E 4-11.., AK-2R0271.;.E L2- 30 AK-2R0277 -E 9-22 AK-2R0063-E SE AK-2D0105-E 9-25 AK.;.2ROO64-E SW AK..2DOI06-E 11;..2' AK.;.2ROO65,-E 1..8 AK-2R0046-E 11-7 AK"'2ROO66-E 3~4 AK-2ROO47-E 11-8 AK-2R0272-E 3-6 AK-2ROO48-E 12-23 AK-2R0067 -E 3-7 AK..2ROO49-E 12-25 AK-2ROO68-:-E 3-10 AK-2ROO50-:-E 12-27 AK-2ROO69-E 3-11 AK-2ROO51-E 14-25 AK-2ROO70-E , )-12 AK-2R0052-E 14-27 AK-2ROO71-E. 3~13 AK:-2R0053-E 14- 36 AK-2ROO72-E ~t- , ~ÇANNE[\~ ~~UN i] 0 200~· {' ( Figure A-3' Prudhoe Bay Unit Eastern Operating Area · In jeçtion W ells Author izedby Rule Well Well NGI-l NGI-2 NGI-3 NGI-lJ. NGI-5 NGI-6 NGI-7 NGI-8 NGI-9 NGI-IO NGI-ll-'- NGI-12 NGI-13 NGI-1l¡. OWD-NE OWD-NW : PWD 1-1 PWD 2-1 PWD 3-1 WGI-l WGI-2- ., WGI-3 ..' WGI-l¡. 40;;.8 4-.10' 5-17 9~8 9...10 9-12 9-1l¡. 9-15~- 9-16 9-17 9-18 9-19, 9-20 12-19 12-20 13-6 13-9 13-15 13..16 13-1~ 13-18 13,,:,19 13~20 13-21 13-22 13-23 A 13-24 13-25 13-3? 14-13 14-14 16-1 '16-2 16-3 16-5 16-10 16-11 16-16 17-~_ 17-8 17-10 «::~I{" 1/\ it. ~. 'li.~.W IF C'/ U ~ U i\TI ;1 f¡) 2004 ù\.1r~D'''I\ 1 ðl!.-¡-." ~;)' ,·H '8 v ' i( Section· B Plat 20. AAC 25.402(c)(1). 2() AAC 25.252(c)(l) ( Figure ß..;J is a plat showing the location· öf allw~Us that penetrate the uppermost injection zone withit1 the· EOA boundary.. Thelégal desçription of the area covered' by this are~: injection order apP.1ication (i.e., EOA excepting K-Pád) is listed in Figure, A-I. 2 ~ÇANrt~EU JUN ¿~ 0 20n~~ ( l \ SECTION C Op~( ator.~/5~rfaçe{O¡~'f~~.(_s,,~_, '20.,;:AAC: ;~-:4Q2(c)(:!l:. 20, AAç;.~.2'1(c)(2};\: The s\ltfiiCee ()w.oet~, and oper á'tQrswi~tþe ¡¡rJ¥1 of this ar~a Jnje<?tí9~; ord@t,·ill'Íq, e xt~n:<;t~\ng 11~ :,mile"fbêyondthe 1)~~np~r~'(~I~çll~d'¡rlg, AFtCO) ',~rè: i$cxon Co fnp~r~~" q cS~A,.., -A~~~, ar.,uœ~,H6wen .1;¡.,5-:'". :,HiMcx¡¡~,$;;t Dr ive, ê~::Ø. Box"5Ø~'5 tnø~~rdS&'ks" CA913 59, . 'VI{ ak~9ß:"Ahnl~~g*., P~..O'c ; ~;x 274 I, i '~::', ",." " Btt..rr()~"",;' ,!\~:,;.9,91;2~·' '5.ti,smdattil£J~J;(a Pr()dÚè'ti~n·,j~ø'm1?äfiY :" Â'ijh: J\~·ari':'£få;tSØf\$. 900 E.. Bènsftttt ,Blvd,,;,· P,.O."Box 19~fi,~¡2' A:hctìørage, '~I?Ç:' 99:'19 . :Än~:~~;:;Oëf.1gå P~",ß,~!'~Q¡¡k'2Ø:l 1·, : or,. '. ",,.\ 'l,'~.' .:' "'~ "i, ," ,~-Àt ¿- ,}' ~ ·\~.~'J't"O>W, ",~K'7'9? ~,::1~: A~}'¢§ka P!.~J,lôes.~(~Æç~,:Ç?-ft1P~~ Y , I\tfn:\ \liSôfi Dep~;~'1~~~·~~~' l:~'~:5's~~ag~w S~¡~i '.:, AnêhPr~i~, AK9:~~~~'" ~~±e of tu~:k~, - Qê.þ,ê,.1" tm\ttlt of:.Nä:tt!ý:ài R~sourœ,~ Attn:: , ~,âY"ißt'OWO J~'4I o. 80:*/70:34 Ancho~ág~'" t\~¥;~'9'!:t:,e 4 t)CA~~~~E~ > IJlllì~fl '~! I(~ ')." [\[','1,1 () ',...~ (I.) .,ß j\ ~~1 \}I~ (l, (" ,~ ,: ell '( { SECTION D Affidavit 20 AAC 25.4()2(c)(3l 20 AAC 25.252(c)(3) , Affidavit of Julie A. AthåhS STATE OF ALASKA THIRD JUDICIAL. ,DISTRICT 1, JuHe·.A. Athans"d~clare .andaffirm as foUÖws: L. lam over 19 years of age.. :Iam émploYéd,by ARC'O Alaskâ; Inc. as an ,Envirônmenta1"'Coordinator. I have ,personal knowledge of thé rnattersset fOrth inthi~ a'~fidavi t. 2. 'On , :- ./_ ,~~, L-...) ___ _ _, 1986, the ,surface oW'nersloperators listed in Section C were provided' acöpy () f this permit applicatiOn. ' , DATED at Anchor age, , 1986. Alaska; this ~ ""- ~) 'day o.f ,_ (\." t.. __"';'~_:;"'.o::.._.......__,___ - - --------_.:-_- ,. /... - ~".;., I . /' '-, , ',~-~ ,Julie A. A thahs Subscribed and a'ffirmed before' me at Anchoragej Alaska:' on. \.)fA.J¿if __~_, 1986. /1' , ¡/ I'·.. / !/t/. ,1( /<, /:~ ~,2.-t tL_ )A';," '. 'x:' '-, - --~~,~ -'~.... ~--' Notary Pùblic irt and lot, the State of Alaska / (,' ,'·7 My commission e'xpires: ! , :):f:/ ------~~-- j, 5'CtìN1NE[,iI t;JIUNI ~~ (~ 2004 ( ( SECTION E Description of Operation 20 AAC 25.402(c)(4) , Current anØ proposed injection opera~ions at the EOA are divided into two broad ca tegòr ies: Subsection 1 - enhanced recovery, and Subsection 2 ~ disposal of flui<:Is brought to the s,urface and comiogled with non- ha4ardous waste fluids from operations. Subsection 1 Enhanced Rècovery Enhanced recovery injection wells are used for the introduction of additional fluids into the oil reservoir to increase the Ultimate recovery of oil., Three types of ~nhanced recovery injection wells are currently ,used: water injection, gas injection, and water-alternating-gas injection. Adç:litional methods of enhanced oil recovery may be used in the future. Future injection wells will continue to be designed, construc,ted, operated (and monitored) to ensure the injection fluid is entering the' öil reservoir., The Ivishak and Lisburne formations arêlwillbe used for enhanced oil recovery., Subsection 2 Fluid Disposal Produced wa~er disposal wells are used for,the disposal of produced water and oth~r fluidsgènerated during operations. The produced water is water which is produced with the oil and separated from the oUand gas at the Flow Stations and Lisburne 6 ~CA~\~~~ED ~JJUN ¿.~ 0 20D~~ :\ " Production Center . The remaining injection fluids are· non-hazardous fluids generated by drilling and production. operations. Flow Stations 1, 2, a~d 3 and the Lisburne Production Center have. produced waterdisPQsaJ well$. Fluìd, Q.ispos~lwells are currently in operation. at Pad .3 j.ost·SOuth 9f DriU Site 6. Non-unìt, non~nazardous wastes associated with North SlO:peoil production activities are also injected ~:t these wells. Additional fluid disposal wells ~reªnticipat~d~ Future fluid disposa'I wells will be. designed, construçted operated (anÔroonitore<O· to enSure the injection . fluid is entering the injection zone'. Injection is' into the Sagq.vanir.I<.~ok Forma.tioo/Colville . . Group. 7 SC¡'~t~i~~~ED JUN ~~ ~ 200(~ ( It SECTION F Pool Information 20 AAC 25.402(c)(5) The strata affected by, inJe'(:tion for enhanced recovery from the Prudhoe Oil, Pool, are defined by Rule 1 of Conservation Order No. 145as the strata that are common to and cortelªte with the accumulation found in the Atlantic Richfield - Humble Prudhoe Bay , ' State' No.1 Well betwe~n the depths of,8,110 and 8;680 feet, MD. The strata a,fféctèd by injection for enhanced r~covery from the Lisburne are defined for the Lfsburne Oil Pool in Conserva,tiol) Order Nó·. 207 ,as the accumulation of oil , found in the Atlantic Richfield -Humble ,'Prodhoe Bay State No'~ lwen between the, measured'dèpths' ofg,,7'0 and 10,440 feet. 8 ~..,. f" ,~ ~), ~" u::" r \ )'1 q 1\)1 ~)) r~ ') ('I n III ~:'))~p¿i"':M~! ~~Ifr.:·.L- .,~,!) I J; ,;n \:}¡ (.. [I, ( ( SECTION G Geologic Information 20 AAC 25.402(c)(6) 20 AAC 25.252(c)( 4) Subsection 1 Prudhoe Bay Unit Eastern OperGlting Area Colville Group and Sagavanirktok FormatioQ Strata of the upper Colville Group and Sagavanirktok Formation comprise the la.te Cretq.ceous and early Tertiary shallow aquifers in the EOA area of the Alaskan ¡\lorth Slope 'and c~ntain water of less than 10,000 mg/l TDS (see also Section N, page 36, and Figure H-l). Subsection 2 Prudhoe Bay Unit f;.astern Operating Area Ivishak Formation 1. In.Jection Il1terva:l A. Stratigraphy and Lithology The Ivishak Group, Late Permian to Early Triassic in age, is divided into three distinctive geologic formations: the basalE.chooka Formation, The Kavik. Shale, and the overlying Ivishak Fprmation. Stra.tigraphically,above thelvj~t1åk Formation, in ascending order, are the Shublik, Formation and the Sag.River Formation. .Within the field lirrÜts of the EOA, th~ Ivishak Formation varies' in thickness from zero fèêt (by truncatiön)to about 700 feet, and the structural top of. the Ivishak varies in depth from about. 7900' feetsubsea''to slightly'over 9000 feet subsea.(Figure G-3). ~CAIMNEU' (,~UN :J; [~ 2001J { ~ I( The Ivishak reservoir is dominantly a sandstone interval that has been divided into four zones (I-IV). Zones IV and III are the primary injection intervals with Zones II and I receiving relatively minor amounts of injection fluids. Zone I, the lowermost zone within the Ivishak reservoir averages 125 feet in thickness. Zone 1 is comprised of thin to moderately" thick interbeds of mudstone, sil~stone, silty sandstone and sandsto'ne. The relatively ,clean sandsto,n~s commonly have porosities from 20-25% and permeabilities from 250-350 md~ Zone II is a lithologically variable unit up to 280 feet thick that consists of ~nterbeddedsandstone and conglomeratic sandstone with'lesser amounts of conglomerate, siltstone, mud$tone. Zone II sandstones usuallyhaveaboÜt 25% porosity and 500-1000 mdpermeability. Zone III consists predominantly of poorly sorted conglomerate ánd conglomeratic sandstone, with occasional thinly bedded siltstone and mudstone. This zone ranges from 0-100 feet in thickness across the EOA. Zone:U por~sitiesare typically 16..d8%ahd permeabilities range from 800";' 1200 md. Zone IV, the uppermost divis,ion of the Ivishak reservoir at Prudhoe Bay, is comprised of interbedded fine to medium grained sandstones with lesser amounts of sandy conglomerate, silty sandstone and mudstone. Thickness varies from 0-225 ,feet in the EOA. Average porosity is about 24% and', aVèrage petmeabilityÎs about 250 md. The Sag River Forni'fLtionisa minor reservoir stra'Ùgraphk:-ally' above the , ' , Ivishak reservoir in the EOA. The Sag River ranges in thicknes$ftomO feet (by trunc:ation) tö 50 :feet and is~.é;paratedfrolTl the mé!,in Ivishak re$erVoitby' 35-75 feet of limestones, siltstones (lod shales of the Shublik Formation. The Sag River ,sandstone i~'very finé to fine grained and contains glauconite andan~erite cemeh't'~ Porosity values usually range from 7-20% (averag~ 1.5%Lq.nd permeabilities range from 3-30 md (average 20md). S(C!\INNEU ~jUN ~:JJ f) 2[O~j ( ( B. For ma tion Water Salinities Laboratory analyses of formation wâter salinities prodùced from the Ivishak sandstones indicate: an average salinity of 18,500 ppm NaCI equivalent and a total dissolved solids (TDS) content slightly in excess of 20,0'00 ppm (Jones and, Speers, 1976). , , . There are no salinity data available for the Sag River. In the EOA; all of the Sag River wells contain hydrocrbons. 5iríèe only one EOA well (PS 17.::. 14) hs been tested for Sag Rivèr potential, no t0r:'nate water samples are available. Accurate salinity calculations cadnot be done with hyd,rocarbGns present in the formation. However~ the Sag River is believed to be in communication with the Îvishak rèservoir along faults and at the , , , truncation. Therefore, it would be re~sonable to ~re~ict th~7 the Sag River has similar formation water salinity values (20,000 ppm TDS). c. Structure The Prudhoe Bay Field is Pé1.rt of a northwest-southeast trending ánticlinal structure. Closure in the EOA is provided by gentle structurat' dip to the sou~h ~nd west, truncation .by the Lower Cretaceous Unconformity to the east, and nor mal faults in the north. II. GonfiningIntervals The Ivishak Formation in theEOA of Prudhoe Bay is confined aboveålid belO'w by impermeable sequences of Kavik Shale, Kingak Shale and Cretaceous shales,. The confining zone àt th~ base of the Ivishak~andstone reservoir is the,Kavik Shale. This shale aV'ell'agesabout 150 feet in thickness in the EOA and v~ries from less than 1 QO feet to over 200 feet, thickening to~ the south. Overlying :the Ivis,hak For'matioo are two thin stratigraphic intervals which are minor" reservoirs, ,at Prudhoe Bay. In ascending order these are the' Shuqlik F'ormation (@ 70' thick) and the 'Sag River Formation (@ 35' thick)~ Overlying 8CA~~NEt,.) ~JUN ¿}Q) 20D'~ [ r [ [ r I [ I [ I I I [ l [ I l l (" ¡ these units is the confining Kingak Shale. In the fOA, the Kingak shale attains a maximum thickness of about 800 feet. This shale thins markedly to zero feet eastward across the EOA as a result of truncation by the Lower Cretaceous Unconformity. Overlying the Lower Cretaceous Unconformity and sealihg the truncated Ivishak, Shublik, and Sag River reservoirs at Prudhoe Bay are the Cretaceous shales. These shales, range in thickness fro m 1600 to 2000 feet and blanket the Prudhoe EOA. III. References Jone's,H~ P. and Speers, R. G. (1976) Permo-Triassic Reservoirs of Prudhoe Bay Field, North Slope, Ala~ka, in North American Oil and Gas Fields, AAPG Memoir 24, p. 2J-50~ Subsection 3 Prudhoe Bay Unit Eastern Operating Area Lisburne Group I. Injection Interval A. Stratigraphy and Lithology The Lisburne Group is a thick sequence of Mississiþpian and Pennsylva.nian carbonate rocks that underlie the Ivishak Group. The contact of the Lisburne with overlying formations is urîconformable, and isea$Hy recognized 'on most well logs. The Lishutneoccurs at approximately -8300' subsea along the nórthernedge of the Prudhoe Bay Field and becomes ' progressively deeper to the south and west. (Figure G~3) , The: Lisburne' Group is subdivided into the Wahoo and Alapah Form~tions, each of which isappróximately 100:0' thick in the EOA. The Wahoo consists predominantly' of limestone with lesseramouots of dolomite, ,siltstone, .. ("2 (\ fI 1'\ -" \' \~~ç;:\' '; ~ON ~1 {~ ... jU'!' b~,f~Nn'~c-t.~ ~ ,. ( ( SECTION G - GEOLOGJC INFORMATION 6/26/86 ADDENDUM The Colville Group/Sagavanirktok Formation (also known as the Tertiary and Cretaceous Sands) are currently used for disposal by ARCO Alaska, Inc. in the EOA through wells at each of the Flow Stations, th~ LPC and Pad 3 (just Sou.th of Drill Site 6). For purposes of this appliçation, the disposal zone for the Colville Group/Sagavanirktok Formation should be defined as the intervàl between· 1900 feet and 6750 feet md, and lateralequivalen~s·, in the ARCO/EXXON Sag River State III well. 8 . {I, ·)nfl.~ ..-. ... . 1 \ ~~. V Ll¡!J'-~ ~j)ç¡~NNEL J\UN ç} .) A ( ( ( A' ( Figure G-l W E ARGO ARGO ARCO BP ARGO Put River #1 D.S. 6-1 Sag River 51. # 1 Sag Delta Delta St. #2 7-10-14 2-10-14 4-10-15 31-11-16 35-11-16 \ __ C 4.4 MILES ) e c 3.6 MILES )*c 4.2 MILES )-¢-c 3.6 MILES ) -¢-~ SEA LEVEL ,,- SEA LEVEL BASE OF PERMAFROST ., -2000' - - -2000' l ! I I I I I I I I 1 I SAGAVANIRKTOK FM - -4000' -4000' - UGNU I WEST SAK SANDS - -6000' -6000' CRETACEOUS SHALES lCU - -8000' -8000' ~ KINGAK SHALE UBLIK I \V\SHAK / KAVIK I ECHOOKA SAG RIVER I SH -10,000' - LISBURNE GROUP - -10,000' I _, I -12,000' _ KAYAK / KEKIKTUK - -12,000' .~ ~~~ ~ -------~ f J j ) f J - f 'f f f ) ) 5 r ) BASEMENT LOCATION MAP 5 MILES J~ A _____~~,~,:¿';'~~.I . 1000 FEET ;- APPROX. 5: 1 VERT. EXAGG. , 1 MILE A ~9,!2 ~~~~~~~_<>-1 PRUDHOE BAY UNIT EASTERN OPERATING AREA STRUCTURAL CROSS SECTION A-A' WITH GENERALIZED STRATlGRAPI;IC UNITS -- SEA LEVEL -2000' - -4000' - -6000' ....... -8000' ~ -10,000' - -12,000' _ A W ( ARCO Put River #1 7-10-14 I tit· 4.4 MILES ~ ( (' A' E ( ARCO ARCO BP ARCO D.S. 6-1 Sag River St. # 1 Sag De/ta De/ta 5t.#2 2-10-14 4-10-15 31-11-16 35-11-1¡6 ..e· 3.6 MILES }*c 4.2 MILES _-¢-c 3.6 MILES . -¢-, SEA LEVEL BASE OF PERMAFROST SAGAVANIRKTOK FM UGNU I WEST SAK SANDS .. CRETACEOUS SHALES lCU KINGAK SHALE BL'K I \V\SHAK I KAVIK I ECHOOKA SAG R\VER I SHU ) ) f r LISBURNE GROUP KAYAK I KEKIKTUK r f r BASEMENT f - -2000' - -4000' - -6000' - -8000' ..----........... i --10,000' - -12,000' --------' ~ (" . ) f f r f j ; Figure G-l LOCATION MAP 5 MILES v~ ._'_.--'-~:~::;':~JA' A ______-~.. :,," .,..' '., .. 0.'" '" ., . ,...1"·..·01 --,- 1000 FEET ;- APPROX. 5: 1 VERT. EXAGG. I 1 MILE ARCO Alaska, Inc. <>-1 Subsidiary o',~~~~~_~.~:~~~~~:'_rt1.P.""!__" < PRUDHOE BAY UNIT EASTERN OPERATING AREA STRUCTURAL CROSS SECTION A-A' WITH 'GENERALIZeO S.~fiA:-¡'IGF¡:¡('f'H'C.UNITS ... ( Ii' SECTION H Well Logs 20AAC".25.402(c)(7) 20 AAC 25.252(c)(5) All openhole logs from EOA wells ar,e. sent to the Commission as the logs are cömpleted. Attachment H-I is a type-log for the,· EpA with stratigraphic and mark~r horizons annotated, and representative salinity.da,ta.· The Sag River State No.1 well, l<?cated in Section 4, TION, RI5E, UM, was chos~n as the type-logÎorthe EOAbecause it is a centrally located deep test well that penetra~ed the total prosp"ective stratigraphic column into "basement" . It .is evident from the well data studied that aU of the major and minor reservoir h9ri~ons within the E9A have formation,'w,atersin excess of 10,000 ppm TQS. 18 . () 7..0 Ü I~' ,( (' SE~Tl~'.l~ I ~ ,..::.: Ca$irig~ In fQr roe. tier! t'·- - '", 20.' AÅ:Ç15~.402.(ç:)(g» 20' AAÇ·,25e,~52(tJ(.6l) Typiof:ìlirf~ection . ~e~ls ar~ ,:.cas'ed·'·as.'shò~vnii·¡O, ,Figure ····1-1. ,So,mê. ,f$W,I~FèÜ$:', may v:aî~Y , , :fromd~,c~jng s~wfdn Figur;~H. TI1eatJual ç~¡~gprogr,~f&r'eaßñw.e1k~ on file :~ith..::th~\AQ)GeC <in ;:t~ pQ,mple;t:iQo l~~~?rd. . API" c~~ing··sp,~~ifi();~tlø,l1$·' a'rè:~i~~Iüc1~'~::.on ie~ch::dç:~U.i~ig:, per~it \?,I?R.licatiQO::",. AJ;:l ,;injeçtioo CÎir:~i:qg:;'i"i~cerrä~rttèd qri:~ :ta~tëd, Ù'î .~qcqr-dt\n~e::W'ith20;\J\AÇ ·'25~4.l2, \fQ;~~!;bb¡~h.'I')~~ly\ dr~H~ß./$.lj\d\\cÓnvert~,ø ih.J.~ttiori·'wélt~·k 20 II' II /:'\ ';, n n }j Figure 1-1 -TYPICAL PÉ>J WELLBORE SCHEMATIC (NOT TO SCALE) o IJ::O= :::()::[] ~ 5000 PSI WELLHEAD . G'ROUND'LEVEl '........, - - - " --- ....... ......... --.:.' L ~.... 20· CONDUCTOR. 8'Q· L ~. 1,3-318'· SURFACE C5G @ 2500·TVD INTERNALLY TE5r£D'TO, 2000 PSI -4 II 5~1/2· OR 4-1/2- TUB I NG :WITH PACKER 40· AB,QVE TOP OF II NER -- - - L ~..... 9-51~·PRODUCTION CSG @" 10·,ABOVE,SADLEROCHIT tNTER~A1L Y TESTED TO 3000',' PSI L. . ~~. "7 ·PROÐtJCTI(U~;':l.JN~~'R::@':' f~O· BELOW":BA5EOf SADlERQqHlT O'R OWC,.f NTERNALL Y TÉSTED TO 3000 PSI 5C!ì~\H~Er) ~JUN 3 0 200,' JG' 5/2,1/86 21 ( ,II'" ~~ SECTION J Injection Fluid 20 AAC 25.402(c)(9) 20 AAC 25.252(c)(7) The injection fluid for the two types of injection at the EOA are: 1) water and gas for enhanced recovery, and 2) fluids brought to the surface and comingled with non- hazardous" waste streams for disposal wells. Subsection 1 Enhanced Recovery A. Type of Fluid - Source Water. This fluid is treated seawater injected into the oil production zone for pressure maintenance. Small amounts of chemical used for water treatment at this time, or planned for future use, are coagulants, anti- foam products, scale inhibitors, biocides, and oxygen scavengers. Current, typical treatment volumes of these products are: coagulant: 0 to 1 ppm anti-foam: 0 to .35 gal. per 1000 barrels scale inhibitors: 0 to 4 ppm biocide: four shock treatments per month, 500 ppm over. duration of 6.5 hours· Oxygen scavenger: 0 to 2.5 Ibs. per 1000 barrels These treatment amounts are subject to revision, based on operational needs and requirements. Analysis of Composition of Typical Fluid - See Attachment J-l SO(J.rce of. Fluid - Beaufort Sea Estimated Maximum Amount to be Injected Daily - 22 .q;;,~ {(v 1,\ t~ h:t¡.M"'" r," p H\ ~ ~~ n 2 0 0 ~ ø~Û·'~~"<jð~J;.(".;I QJ' i!)r~ <:~ t/I ..l. .,~ ( Ivishak - less than approximately 800,000 BWPD, decreasing as produced water injection increases. Lisburne - approximately 500,000 BWPD, decreasing as produced water injection increases (maximum of 20,000 BWPD during pilot water flood testing). Compatibility with Formation and Confining Zones - 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 oil and separated from the oil and gas at the Flow Stations and Lisburne Production Center. The produced water may contain trace amounts of scale inhibitors, corrosion inhibitors, emulsion breakers, and other products used in the production process. Analysis of Composition of Typical Fluid - See Attachment J-l - Ivishak and see Attachment J-2 - Lisburne. Source of Fluid - producing formations Estimated Maximum Amount of be Injected Daily - Ivishak - increasing from currently 170,000 BWPD to approximately 655,000 BWPD by 1989. Lisburne - estimated 6,000 BWPD initially, increasing to approximately 500,000 BWPD (will be injected in PWDW at startup, see Subsection 2.A.). Compatibility with Formation and Confining Zones - fluid is returned to the reservoir from which it was produced; no compatibility problems anticipated. C. Type of Fluid - Natural Gas. This fluid consists of natural gas and natural gas liquids produced with the oil and reinjected into the same reservoir. Analysis of Composition of Typical Fluid - See Attachment J-l Source of Fluid - producing formation 23 S':{~\ 11\~~~J~:.:::r: W~...J. M "..Þ.1) f.'\ 200 fJ.· -" '~.6"';&.,~ L',,'5~"""I" ~..:Þ~)r~ ~~ ~j; __ ' ...'L.J ( (" Analysis of Composition of Typical Fluid - See Attachment J-l, "Produced Water." Source of Fluid - producing formation, small amounts of non-hazardous chemicals or waste from operations. Estimated Maximum Amount to be Injected Daily - Produced Water Disposal Wells (Ivishak production) - facilities currently limited to approximately 75,000 BWPD, could be expanded to 655,000 BWPD or greater. Produced Water Disposal Wells (Lisburne Production) - pump design currently limits disposal to 25,000 BWPD, piping is designed for 100,000 BWPD. B. Type Source of Fluid - Non-hazardous Wastes. The injection fluid includes numerous non-hazardous waste streams generated during the course of drilling and production operations, including non-unit wastes. The injection stream includes drilling mud, reserve pit waters, contaminated crude, diesel gel, glycol, domestic wastewater, workover fluids and other non-hazardous waste streams. Estimated Maximum Amount to be Injected Daily - 10,000 BFPD. 25 "'rr' ~\ t~N~\~'I""f ~~ ~11.~ Ií\ f;¡ 20r i l;:Dvf'M'~,,\jt:u ~,.ßt}n~ ¿J ~j . . U4 ( t Estimated Max~f!1um Amount to be Injected Daily - Ivishak - currently approximately 2.6 billion standard cubic feet per day increasing to approximately 3.2 billion standard cubic feet per day. _ Lisburne - Estimated 100 million standard cubic feet per day at startup /' increasing to approximately 1 billion standard cubic feet per day. Compatibility with Formation and Confining Zones - fluid is returned to the reservoir from whic~ it was produced; no compatibility problems anticipated. D. Type of Fluid - Miscible Injectant. This fluid is a mixture of produced natural gas that is enriched with natural gas liquids. Analysis of Composition of Typical Fluid - See Attachment J-l Source of Fluid - producing formation Estimated Maximum Amount to be Injected Daily - Ivishak - maximum of approximately 174 million standard cubic feet per day. Lisburne - no miscible injection anticipated at this time. Compatibility with Formation and Confining Zones - fluid is returned to the reservoir from which it was produced; no compatibility problems anticipated. Subsection 2 Fluid Disposal J A. Type of Fluid - Produced Water Disposal. The injection fluid for disposal is nearly entirely produced water. Minor amounts of non-hazardous chemicals or waste associated with the production of oil and gas may occasionally be injected along with the produced water. I I ! 24 SCA~)~\I~EI) ~JUN ¿~ 0 200t.1 (, Attachment J-1 :( Typical Fluid Analyses - Ivishak Produced Water (Ivishak): Total Dissolved Solids Sodium Calcium Magnesium Iron Barium Boron Silicon Potassium Strontium Chlor ide Biocar bona te Sulpha te Carbonate Hydroxide Specific Gravity pH (in lab) Suspended Solids Source Water (Beaufort Sea): Specific Gravity @ 600F pH Biocar bona tes Calcium Magnesium Sodium and Potassium Sulfa te Chlor ide Iron Barium Total Dissolved Solids Carbon Dioxide Calc. Hydrogen Sulfide Suspended Solids Strontium Res. Ohms/m @ 700F Summer Sea Water 1.013 7.5 85 mg/1 196 mg/l 631 mg/1 5680 mg/l 1380 mg/l 9880 mg/l o mg/l o mg/l 17852 mg/l -- mg/l o mg/l 6. 0 mg/l -- mg/l 0.422 26 21 , 100 mg/l 7,700 mg/l 190 mg/l 30 mg/l 15 mg/l 2.8 mg/l 130 mg/l 26 mg/l 90 mg/l 19 mg/l 10 , 700 mg/l 2 , 800 mg/l 70 mg/l o mg/l o mg/1 1.014 6.8 2 Winter Sea Water 1.024 7.8 142 mg/l 365 mg/l 1190 mg/l 10400 mg/l 2490 mg/l 18200 mg/l o mg/l o mg/l 32787 mg/l -- mg/l o mg/l 1 . 0 mg/l -- mg/l 0.255 sct\NNEL>JUN ¿t Ü 2nDI~) (. ( Produced Gas: Nitrogen liMe thane Carbon Dioxide & Ethane Propane Iso-Butune N-Butane Iso-Pentane N-Pentane C6+ SP Gravity (calc.) SP Gravity (meas.) .31 74.32 12.45 6.56 3.35 .46 1.18 .26 .34 .77 .794 .785 MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL % ------ ------ Miscible Gas Injectant: FS3IP( 1) PBMGP( 2) Nitrogen .07 .01 MOL % IIMethane 35.32 23.50 MOL % Carbon Dioxide 15.14 21.60 MOL % & Ethane 14.10 24.03 MOL% Propane 15.27 28.43 MOL % Iso-Butane 2.76 1.22 MOL% N-Butane 7.29 1.19 MOL % Iso- Pen tane 1.99 .01 MOL % N-Pentane 2.46 .01 MOL % C6+ 5.60 Trace MOL% (1) Typical composition currently injected into Flow Station 3 Injection Project. (2) Projected solvent composition for Prudhoe Bay Miscible Gas Project. 27 S~·'-{J'·~J[~u::r. vWiN ICJ fl ,. 001' v' W',!!-1:.;, .. r ~Jæ,.;;:,L. ~ tJ ' ell 1i,H 2 i} { Attachment J-2 ( Typical Fluid Analyses - Lisburne Produced Gas: Nitrogen Methane Carbon Dioxide Ethane Propane Iso-Butane N-Butane Iso-Pentane N-Pentane C6+ Hydrogen Sulfide Produced Water (Well L 3-8): Ca tions I I I I [ [ [ I I I I Sodium (Calc) Sodium (AA) Calcium Magnesium Iron Bar ium Strontium 10555 mg/1 13875 mg/1 105 mg/1 50 mg/1 1 . 1 mg/1 1 . 1 mg/1 3 . 8 mg/ I .59 77.48 13.95 5.26 1.76 .21 .43 . 1 .12 . 1 5 Total dissolved solids, mg/1 28573 pH 8.5 Anions Sulfa te Chlor ide Car bona te Bicarbonate Hydroxide MOL % MOL % MOL % MOL % MOL % MOL% MOL % MOL % MOL% MOL % PPM 750 mg/1 14261 mg/1 228 mg/1 2618 mg/1 Source Water (Beaufort Sea): Same as Ivishak source water. 28 8CANr1~EL JUN ~~ 0 2004 ( t SECTION K Injection Pressure 20 AAC 25.402(c)(lO) 20 AAC 25.252(c)(8) The estimated maximum and average injection pressures for enhanced recovery and fluid disposal wells are listed in the following table: Type Well Maximum Injection Pressure (psig) 2700 4500 4000 3000 5000 2100 1400 Aver age Injection Pressure ( psig) 1000 2600 3700 2000 4500 1800 600 Ivishak Water Injection Ivishak Miscible Gas Injection Ivishak Natural Gas Injection Lisburne Water Injection Lisburne Natural Gas Injection Produced Water Disposal Fluid Disposal Note: In some cases, maximum pump discharge pressure is used to establish maximum injection pressure. 29 5~J\N!!\~E[) JUN ¿t () 2002J ( ( SECTION L Fracture Information 20 AAC 25.402(c)(ll) 20 AAC 25.252(c)(9) The proposed maximum injection pressures for the enhanced recovery and fluid disposal wells will not initiate fractures in the confining strata which might enable the injection or formation fluid to enter freshwater strata. Subsection 1 Enhanced Recovery Injection in the Ivishak Formation, above formation parting pressure, 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 Ivishak Formation is overlain by approximately 2000 feet of confining shales which act as an impermeable confining zone. Figure L-l shows an estimated fracture gradient curve used in the well plans for wells drilled in EOA. This curve has been verified through drilling experience and numerous leakoff tests. It should be noted that the curve is applicable only to clean sandstones and is the pressure required to initiate fractures. Pressures required to propagate fractures will exceed this pressure. Thick shale sequences tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. A leakoff test in the Kingak shale above the Ivishak and Sag River formations demonstrated leakoff at a gradient of .85 psi/ft. 30 -, ''\ !)d I~ ,.,- ~._' n ! N ,,» f' 6) 0 f\ 1'1 S(,,¡·~np\I~::::!:.) .ru, ,Ùì IU c. ,IV"! ( (' Recent studies (Perkins and Gonzales) indicate fracture gradients may be reduced in typical waterflooding situations due to reduced thermal stresses associated with the injection of colder water. Declining reservoir pressure can also reduce formation stresses, thereby reducing the fracture gradient. Given the present reservoir pressure and injected water temperatures, the fracture gradient ranges approximately between 0.52-0.63 psi/ft. in a typical water flood situation in the Ivishak Formation. This has been verified by numerous step rate tests, multi-rate analyses, and pressure falloff analyses on water injection wells in the Ivishak waterfloods. Injection profile logs, with emphasis on temperature logs, indicate that there is no vertical propagation of fractures within the Ivishak sandstone, much less propagation into the confining strata, at pressures exceeding the measured fracture gradient. Reference: Perkins, T. K. and Gonzales, J. A., "Changes in Earth Stresses Around a Wellbore caused by Radically Summetrical Pressure and Temperature Gradients," SPE 10080, 1981. Subsection 2 Fluid Disposal The injection zones for fluid disposal and all zones above and below the injection zones contain greater than 10,000 mg/l TDS and are not freshwater strata. Therefore injection at above parting pressure would not result in formation or injection fluid movement into freshwater strata. Recent studies of the fluid disposal wells at Pad 3 substantiate the lack of pressure buildup in the zone and lack of fluid movement ., outside the injection zone. The confining shales below the injection zone are in excess of 2000 feet vertical thickness. The upper confining zones consist of numerous interbedded confining shales and mudstones averaging 10 to 50 feet thick and over 1800 feet of permafrost. 31 .. W~ ~N ~ 02004. ..n~N ~ 0 ?o04 32 TYPICAL SADLEROCHIT 'NELL. EOA PRE 3SUHE PP'OFiL.:: ARCO ALASK.A, I ì<.:. · . · t 5 ,0 I . 14,0 I 0.6 GRADIENT (PSI/FT) (LBS/GAL) 10.0 11.0 12.0 13.0 I , I I 17.0 I t6.0 I 0.9 0.8 0.7 0.5 ¿. -I · I I I I I , I- I I I I I . . . . . .:. . . . - . I I I I I I I I I I · I I · , , .. ,.._......~.............~.............~.... I I I I I , I I I I I I I I , , I I I I I , I I I I I I I I I I , ..~..~......,.............~.............,..... I' 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 ··--·r······~·············~······4......~...... " , , . I I I , I , ... ......~... -. , I , · , I · · , I , I I III. . . . . .t' .. . ~ . 9.2 'IGAL 1 13-3/8" @ 2500'TVD · · 9.0 I 8.0 I 0.4 - , ':' t 1 TVD K-10 7 -F-7150' K-5 -.:" 7875' 8 . SAG RIVER ~ 8535' TOP SAD : 8640' BASE SAD 9 : 9190: TD : 9220 10 . 0.3 , . · , I I · I , , ., I .....J..............~ , , , , , I , . I , · I I I , I , , · I I I , . , , , I ~····~·······r······~ I I , I I I I , , ': I : I . , I .. : t : ...... ....:. . .. . . .1. ... . . .:. , , I I , I , · . · . · . · . · , .....~......_....... · , · . · . · . · . , , , , , , · , , , · . I I " , .....~..............~ '. I , , , , ,J" 6 ~ ~ <:> 0 0 0 0 0 .- .- "-' '-" ~ :J: ..... .... a. LLJ a.. 0 LLJ 0 Q ...J L&J < æ ;::) u - en .... < æ LLJ LLJ 1: > · . , I . , I I I . , . . , . I I , . . · . fl. I I I . I · L· , , · 1St . . . . . ... ~ . .. I .. . . . .. . . . . . . . . - . . . . .. . . . . . . i . . . . . . · . . . . . . - . . . . ... . . . - . · I , , . · : : : ~ : : I : I : / : : ~ ! I : I . , . . · . I I . ¡ 9.6 -I GAL : ¡ ¡ · ,.. ......_......~....................~....................-......-...... · . . . . , , . · , . , , , I , . , . , · . . · .. . : - -- 9.4 -/GAL ¡ 9-5/8" ~ : : : : 863STVD : ······~·~··..I·······,·············I............ .~.~ ! . ! ¡ 7" @ ¡ ! ¡ 9220TVD : :: .: " I " . " , " , , t . _ t ......~.............;.............,.............,.........I...~...... · . t t I , I · I Figure L-l I ¡ I I . it I I I · I" I . 'I . . . I . ,. I . . . . I , , :PORE PRESSURE -... ..MUD PRESSURE .~..~.............~.............:.. .._. :GRADIENT ,,~ GRADIE.NT ~ ¡ ~ · 'r' , , , .. . . . . . , ... I t I I_ · . . . , . · . . , · . I , , , , , · I I I · . . . ...··········......~....................4......4......_...... · I I I · , I : : FRACTURE: ; : GRADIENT ¡ I · I . . : : ~: : · . . . 'I I .. I.........,...... .......1............. . ........Jd.._. I I I . I It. , , , , 5 4 3 2 o ~ I~, SECTION M Formation Fluid 20 AAC 25.402(c)( 12) 20 AAC 25.252(c)(lO) A typical water analysis for the Ivishak formation is included in Figure J-l. A typical water analysis for the Lisburne formation is included in Figure J-2. Two typical water analyses for the Colville Group from just west of the EOA, are included as Figures M-l and M-2. 33 ,HJN ~ @ 2QO!~\ ~ , t ( Figure M-l Marti n Water Laboratories. Inc ( ~.o,.ox,... MONAHAN'. TUA. .,..,.e ~HONK ..3·121. 0.. '.1·10.0 RUUL T OP' WA T." ANAL v.a COMP_NY At"1J:1nt"i,..-'Ri,..hfip1rt r.nntpSl'\Y l..EASE P"l'nrtnnp R-\y W'Arprf1ood FIEL.D OR POOL. SECTION_ 8L.OCK_ SURVEY COUNTY STATE SOURCE OF SAMPL.E AND DATE TAKEN: Raw water-taken from Sohio water well #GC-3C @ 11:15 am. 11-4-78 (pressure CylindeJ NO.1 Raw water-taken from Sonio water well #GC-3C @ 10:20 am. 11-4-78 (plastic bottle) NO. 2 EQual mixture of Sohio water well HGC-3C taken 11-4-78& Sohio water well IGC-,3B NO. 3 taken 8-20-78 (pressure cylinders). NO. . IIIEMARKS: Cretaceous CH.MICAL AND ~VSICAL. ....O.....TI.. NO.1 NO.1 1 .O'U 'Ï1 .0110 TO: M'r_ .L 'P~ M,..OnnSllrt, .Tr. 'P.O.Rny 'A1Q. nAl1AQ. TpYA~ Specific Gravity at tI1' pro pH When $amøled pH When Received BicarDonate a. HCO] SupersacuraCio" .. CaCO] Uftde,.acuration .. CaCo, Toea I Hard"e.. .. CaCO] Calcium .. Ca 7.07 464 5 5.'ÏOO 950 7C59 15..43..4 o 27,520 6.1 1R? 1 h 4C5,'OQ Mal"e.ium a. MI Sodium and/or Pocaa.ium SultaN .. SO.. Chloride.. CI Iron u Fe Bari um .. Ba TUrOidity, Etecu-ic Color as Pt Toeal Solid., Calculaced Te"",erature OF. Carbon Cloxide. Calculated Oi..olyed o.yte" , Winkler Hydrol'" Sulfide Re.ì.tiyity, ohms/m a, 1~ F. Suspended 011 Filtrable Solid. a. mill Volume Pi Itered. ",I Carbon Dioxide, Titrated *Total Carbon Dioxide. Gravimetric Strontium. as Sr 74 0.0 0.173 o 5.0 520 44 993 53 l.. ABORA TOfltY NO. SAMPl..E RECEIVED 'AESUL. TS REPORTED 7.17 464 14 '5.1:)00 990 71'Ï 15.537 o 27.697 5.9 ?17 7S1 W. INDIANA M'DLAND. ftXM 7'''0' ~ONI "~..1 117A19R 11-'1-78 1?-C5-7R NO.3 1.0"9 NO.4 6.76 1.757 o '.700 690 4RO 11 ,,844 24 19'.885 1 . 1 7R 4C5,n40 14,7'Ï~ ,7 C;ñ, 0.0 0.0 0.171 0.226 19.1 11.9 910 488 53 AdditIonal Oeuumìnatio", AndRemarIca A.esula Reported ~ Millilra". Per Liflar Form No. 3 34 By , s"'þ, ¡~ijL~,~F¡i ',; UMJN ~:-¡¡,', ,r\)" 2, O,r,J-Iì ". v" "¡jolt! ~ '\k"..W ~,,~ ~ 'b t!J 'i:J " vii' &.., ~ ( Figure M-2 ¿ Marti n Water Laboratories. Inc ( ".O..O.'~.. MONAHAN.. TDAa "8., S. "HONK .~3·111~ o. ..I·IO~O TO: !(10-. ,T. P. MI'T\Orua' A. .Tr. p.n.RnY 'A19. n."AA. TpY~A l.ABORATORY NO. SAMPl.E RECEIVEO RESUL TS REPORTED 71t W. INDIANA MIDLAND. TUM 7.701 '1781 Qg (l:'~I,ra-6··1 11-'1-7A "-t;-7R "aul. T 0.. WA T." ANA~ via COMPANY A~'Aft~il'-Ril'hfi~'d r.n~~~ l.EASE P~1nhnp R~ W~~~rf'nnn FIEl.D OR POOL. SECTION_ 8L.OCK_ SUIltVEY· COUNTY STATE SOURCE 0" SA"'''l.E AND DATE TAKEN: NO. I ~:a.w w~1"P:t"-r:d[pn from ~nhi n w~"'pr up 11 Ir:r.-3n @ t;: 50~m. 11-5-78 (Prp~~t1re 1'31 inner) Raw water-taken from Sohio water well DGC-3D @ 5:30pm. 11-5-78 (plastic bottle) NO. 2 Equal mixture of SohioWiter well ØGC-3D taken 11-5-78 & Sohio water well #GC-3B NO. J taken 8-20-78 (pressure cylinders). NO. 4 ".MA"KS: CHIEMICAI. AND IIIHVS.CAL ~"O~."TIU NO.' NO.1 NO.1 NO.4 Søec:lfc Gravley at W ..~ 1.0291 1.0286 1.0'11 pH Wh.,. $em,led pH When Recei ved 7.16 7.0' 6.74 Bicarbonate a. HCO) 195 176 1.63t; Su.,.,..cu,atIOft .. CaCO) l' R AO UncI.....cu...tlon .. CaC03 Toea I Hard... a. CaCO) 6.600 6.ñOO 1,QOn " Calcium.. Ca 1.t;,0 1,ñOO 1 ,onn Malnu i um .. MI 6AO ñ1' 1/·0 Sodium ancl/or Poea..lum 11.996 11,9'C; 11 , ~ 70 Sulface .. SO. 0 0 '1 Chloride.. CI '6.'77 ?ñ,?ii 1 Q ; ~ 1n Iron .. Fe 9.3 9.? '.' Sari um .. ea 252 ?45 9' Turt)jdICy. elaccric 4 Color.. Pt 8 Toeal Solidi, Calculacad 4'.Q?O 4?Rt;~ 14,OQO T .mø....cu,. of. Carbon Dloxid.. Calculac. 25 34 523 Dinolved OxYI.n. Wlnkl.r Hydro,.,. Sulfld. 0.0 0.0 0.0 R.Slscivicy, ohm./m at 7'1" F. 0.185 0.186 0.229 Suspended 011 0 Filtrabl. Solidi .. mall 4.3 25.8 ' 18.1 Volume Fi Iter.. ml 490 910 465 Carbon Dioxide. Titrated 35 *Total Carbon Dioxide. Gravimetric 1.039 Strontium. as Sr 73 73 Ra.u ca Reported ~ Mlllllr.",. P.r I..j ter " Addiclonal Oecarmination. Aftd RetMrIca * This includes both free carbon dioxide ann the carbon ciio:J[ide that is tipd un as bicarbonate. T.A~~pr nf rp('nmmpnñ~~i"" ;t~~;trhpn_ ( By I "- -- - ", :.,.. /,'...,.-;.. ".;<:..,-. ,<" ... ---::-- -' ...., Form No. 3 , .. ",' ...., .. ", Way Ian C. Martin, M. A. 35 o 2.004 f (' SECTION N Aquifer Exemption 20 AAC 25.402(c)( 13) 20 AAC 25.252(c)(1l) Estimates of formation water salinity values have been made across the EOA and no USDW (less than 10,000 mg/l TDS) were found. By utilizing well log data, an approximation of the formation water salinity can be made using resistivity and porosity well logs. Standard industry log evaluation equations, including the Archie equation for unconsolidated sandstones, were used to determine the salinity values (Figure N-l). Calculated salinities correlate well with the results from laboratory water analysis from the Upper Ugnu water supply well 113 in the Kuparuk River Unit. The good relationship between the laboratory measured salinities and the log based equations permit salinity calculations at many more data points than are available from actual laboratory measured salinity. Although the log calculated and laboratory salinity values do not match exactly, the log calculated salinity values are generally representative of the actual formation water salinity. Formation water salinity values were calculated using "clean" sandstones for six stratigraphic intervals from six wells across the EOA (Figure N-2). No salinity values less than 10,000 ppm were computed for any of the intervals. In wells 7-10-14, 14-5 and 6-4, the T -3 interval is believed to contain minor amounts of hydrocarbons which raise the measured formation resistivity and lower the calculated salinity. Thus, the presence of hydrocarbons invalidates the formation water salinity calculations in these intervals. The salinity values for each horizon were averaged and placed on the Sag River State type log for reference (Figure H-l). Based on the Alaska Test Lab core analysis of the B. P. Permafrost Test well 12-10-14, no USDW is present at the base of the permafrost (1858'). Laboratory analysis of formation water in the porous and permeable sandstones and gravels at the base of the permafrost indicate that intervals capable of flowing formation water contain salinity values in excess of 10,000 mg/l TDS. The TDS concentration is greater than 10,000 mg/l at 1823' (Appendix G, Sheet 61 of 67; Alaska Test Labs Report). The 36 ~,nJN ~] 0 2004· ( ~, equation used to convert millequivalents of sodium chloride (last column of sheet 61) to milligrams is as follows: mg/l = (meq/l) 1 mmol 58.5 mg 1 meq 1 mmol = (220) (1) (58.5) = 12,870 mg/l NaCI. 37 ~r""c' t: r\~¡;;,uc;:r I!~ Ð1A.I¡ ~) /{';¡ 2nO ~ ~)~Ð"'~lr~I\'(jI.\¡¡¡.,(... ~hJ~~ ~;}J ~IJ ,.1.1 'I_} (' ( Figure N-l Documentation of Equations Used to Calculate Formation Water Salinities From Well Logs 1. Formation Temperature: Tfm = 0.0222 (Depth fm - Depth base of permafrost) +320 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 = ø 2.15 x Rt 0.62 5. Water Resistivity @ 750F: Rw @ 75 = Rwa Tfm + 6.77 81.77 6. TDS (NaCI equivalents) = (3.562 - Log (Rw ca 75 - 0.0123) 10 0.955 Step I) 2) 3) Determine formation temperature. Determine porosity from either the sonic or density logs. 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 750F. (Schlumberger equation) I I I I I 5) Calculate TDS in ppm. (Dresser Atlas equation) 38 JlJN ~ 0 2DD(~ ( t ~. Figure N-2 Prudhoe Bay, EOA, Calculated Wireline Salinities (See Also Figure H-l) Interval Well Subsea Depth Calculated TDS (ppm) T-8 7-10-14 (-2666) 22,985 14-5 (-2827) 24,419 6-4 (-2885) 31,240 7-6 (-2966) 35,708 1-6 (-3053) 32,220 9-6 (-3286) 44,651 T-5 7-10-14 (-3011) 14,784 14-5 (-3162) 13,353 6-4 (-3295) 12,503 7-6 (-3306) 14,208 1-6 (-3468) 17,816 9-6 (-3706) 22,222 T-3 7-10-14 (-3616) Hydrocarbons 14-5 (-3757) Hydrocar bons 6-4 (-3897) Hydrocar bons 7-6 (-3916) 11,829 1-6 (-4083) 16,620 9-6 (-4316) 40,086 U. U gnu 7-10-14 (-5271) 36,509 14-5 (-5353) 57,059 6-4 (-5500) 55,621 7-6 (-5474) 43,890 1-6 (-5728) 40,865 9-6 (-5991) 48,844 L. U gnu 7-10-14 (-5461) 31,453 14-5 (-5602) 44,105 6-4 (-5710) 31,514 7-6 (-5651) 42,320 1-6 (-5878) 38,054 9-6 (-6426) 46,332 W. Sak 7-10-14 (-5898) 15,878 14-5 (-6042) 27,427 6-4 (-6090) 20,194 7-6 (-5957) 29,790 1-6 (-6058) 47,834 9-6 (-6806) 34,632 39 SC,A¡I'~~\jED JUN 3 0 2004 ( ( SECTION 0 Hydrocarbon Recovery 20 AAC 25.402(c)(l4) As stated in the "Application for Additional Recovery," December, 1980, fieldwide oil recovery from the Ivishak Reservoir is expected to be increased by 6 to 9% of original oil-in-place as a result of the water flood project. Recovery in the Flow Station Three Injection Project Area is expected to be increased by 5.5% of original oil-in-place above that attainable with waterflooding as a result of miscible injection (reference: application dated August, 1982). Recovery in the Prudhoe Bay Miscible Gas Project area is expected to be increased by 5.2% of original oil-in-place above that attainable with waterflooding as a result of miscible injection (reference: application dated December, 1983). Total expected hydrocarbon recovery from the Lisburne formation is 200-600 MMBO, or 7-20% of currently estimated oil originally in place. Water flood is expected to contribute up to 400 MMBO of the total. 40 \JUN 3 0 20nJ :( :( SECTION P Mechanical Integrity 20 AAC 25.402(d) 20 AAC 25.252(d) In newly drilled EOA wells, the casing is pressure tested in accordance with 20 AAC 25.030(g}. If converted to injection, the casing is again pressure tested in accordance with 20 AAC 25.412(c}. The casing pressure is then monitored on a frequent basis and recorded by the drill site operator. 41 ~~UN ~~ 0 200i~. ( (' SECTION Q Wells Within Area 20 AAC 25.402(h) 20 AAC 25.252(h) The wells within the area of review (i.e., EOA) are shown on the plat (Figure B-1). To the best of ARCO Alaska, Inc.'s knowledge, the wells within the area were constructed, and where applicable, abandoned to prevent the movement of fluids into freshwater sources. 42 ,HJN ~ 0 20n:~\ ARca AlaSka.( Prudhoe Bay Engineering Post Office Box 100360 Anchorage. Alaska 99510-0360 Telephone 907 263 4248 ( SECTION R ~~ ~~ Donald F. Scheve Operations Engineering Manager March 27, 1986 Mr. Chat Chatterton Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: Prudhoe Bay Unit, Eastern Operating Area Dear Mr. Chatterton: ARCO Alaska, Inc. has reviewed the recently adopted regulations governing the control of underground injection related to the recovery and production of oil and natural gas. Two variances to these regu- lations are request~d with regard to operations in the Eastern Operat- ing Area of the Prudhoe Bay Field. Paragraph 20 AAC 25.450(a) allows the Commission to authorize less stringent requirements if: (1) injection does not occur into, through, or above a freshwater source, and (2) the reduction in requirements will not result in an increased risk of movement of fluids into a freshwater source. No underground sources of drinking water are currently prespnt in the Eastern Operat- ing Area, and thus less stringent requirernpnts may be authorized at the discretion of the Commission. Varianee Number 1: Relief is requested from the reporting requirements of Paragraph 20 AAC 25.432 wherein monthly reporting of casing and tubing pressures may be required for injection wells. This information is not included in our automated data reporting system because it has not previously been required by the Commission. Reporting of casing pressure for injection wells has not been required by the EPA, and time consuming manual reports that include tubing pressures havp. b~en prepared for the EPA for only a portion of the injection wells. Submittal of these pressures on a monthly basis would require either extensive reworking of our automated reporting system or extensive manual compilation. The expense associated with monthly submittal of this additional information does not appear warranted. In thp. event periodic pressure monitoring in the field shows non-compliance with any regulation, the Commission will be notified and corrective action taken. Variance Number 2: Paragraphs 20 AAC 25.252(e) and 20 AAC 25.402(e) require immediate notification of the Commission, and Commission-approved corrective action taken if the casing-tubing annulus pressure subjects the casing to a hoop stress that exce~ds 70 percent of the minimum yield strength 43 Ar1C,j ~:iS~J ,ne ~ d SuOS,r1IJry ')1 Atlant,cR'CI'llel.::C,"''''P,1r1Y ~JUN ¿)~ n 200··1' Mr. Chat~· 'terton March 27, .. ~.36 Page 2 ( of the casing, or if there is more than a 200 psi change in the pressure between consecutive pressure readings. ARCa Alaska, Inc. requests relief from the 200 psi change requirement, and requests that the 70 percent limit alone be used as the sole criteria for immediate notification of the Commission. Changes in casing pressure of 200 psi or more occur frequently in response to changes in injection pressure and temperature. This being the case, using a prp.ssure change of 200 psi or more between consecu- tive readings is not a viable means of identifying tubing leaks at Prudhoe Bay. In any case, periodic monitoring of casing pressures and pressure trends will continue in order to assess the condition of each injection well's tubing string ~nd packer. The Oil and Gas Conservation Commission's consideration of these requested variances is respectfully requested. Very truly yours, i nt ~¿Þ ,lÆ'-'-0 Donald F. Scheve JLG/ab/64 cc: J. W. Hart R. Iden 44 ¡JUN ~ 0 2004~\ (' ( eo-·.'~f r "'-- (7 f ("""" ~ ') f-" te... - f v- <-<-& t-..... ~ v r.:.. -r- t ~ } .. 1. f1:to :# f Revised Narrative and Legal Description of the Area Covered by the Application (replacement for Section A and addition of Figure A-D, RECE\\IED jULO q \9ß6 . com«\\SS\on . &. Gas Cons. ~\as\<a 0\\ Anchorage ~) 6\ tj ~}J ( ( SECTION A Area Injection Order 20 AAC 25.460 ARCO Alaska, Inc., as operator of the Prudhoe Bay Unit, Eastern Operating Area (EOA), requests an area injection order be issued for current and proposed injection wells: 1) for disposal of fluids that are brought to the surface in connection with conventional oil and gas operations and comingled with non-hazardous waste fluids from facilities which are an integral part of production and operation, and 2) for the enhanced recovery of oil or gas. The area injection order is requested to encompass all lands within the boundary of the EOA, except for K-Pad, as detailed in Figure A-I. ARCO requests that the order allow ARCO to drill, operate, convert or plug and abandon wells within this area by filing Form 10-401 or Form 10-403. The Oil and Gas Conservation Commission may, in its discretion, issue an ar~a injection order if certain requirements are met. The EOA injection operations meet the requirements of 20 AAC 25.460(a). Existing wells are described and identified by type. Injection wells are within the same field, are operated by a single operator and are used for other than hazardous waste injection. The cumulative e~fect of drilling and operating additional enhanced recovery injection wells will result in an increase in hydrocarbon recovery. The cumulative effect of additional fluid disposal wells is anticipated to be economic disposal of non-hazardous oilfield waste streams. Disposal of produced water and associated waste is necessary to allow production of oil. Both types of injection wells will be drilled, constructed, operated, and abandoned in accordance with the Commission rules to prevent movement of fluids into freshwater strata. Figure A-2 is a list of injection wells in the EOA with EPA permits. Figure A-3 is a list of injection wells in the EOA authorized by rule under EP A's injection well regulations for Alaska. 1 tct\~~\) ~ q \~~'ò .i>\\)~ ~ \) \.. () 'V~\~~'\ ~Q~C;;,' û?,.~ C\~ ~~ ~ c~Ç)t.'().~ ~~S"'~ ~~ ,JUN 3 ~ 200(.~' ( If ~~~ .~ Figure A-I Legal Deser iption of Appliea tion Area (EOA Exeepfing K-Pad) TI0N-R14E Sees. 1,2,3,4,9,10,11,12,13,14,15,16,21,22,23,24,25,26,27, 28, 36 T10N-R15E Sees. 1,2,3,4,5,6,7,8,9,10,11,12,13,14,15,16,17,18,19,20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T10N-R16E Sees. 4,5,6,7,8,9, 16, 17, 18, 19, 20, 29, 30, 31 T11N-R14E Sees. 1, 2, 3,4,9, 10, 11, 12, 13, 14, 15, 16,21,22,23,24,25,26,27, 28, 33, 34, 35, 36 T11N-R15E Sees. 1,2,3,4,5,6,7,8,9,10,11,12,13,14,15,16,17,18,19,20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T11N-R16E Sees. 3,4, 5,6,7,8,9,10,11, S/2NE/4, NW/4, S/2 See. 12, SW/4NW/4, SW/4, S/2SE/4 See. 2, 13, 14, 15, 16, 17, 18, 19, 20, 21, 28, 2.9, 30, 31, 32, 33 I ';:'>f/ .', ,~ø' 22, 23, 4'4, 25, 26,~~,.~~#;;~35, 36 ¡is \.,.1', 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36 T12N-R14E Sees. TI2N-RI5E Sees. T12N-R16E Sees. 28,29,30,31,32,33, SW/4, W/2NW/4, SW/4SE/4, 34 ~JUN 3, ij 2004· ( :i 2. List of EOA Injection Wells Permitted by EPA (Addition of Figure A-2) 2 tv ~V\~ ~ 0 2004· ~! \ ~ Figure A-2 "- Prudhoe Bay Unit Eastern Operating Area Injection Wells with EPA Permits Well Permit Number Well Permit Number LGI-6 AK-2R0255-E 3-16 AK-2ROO54-E LG 1-8 AK-2R0256-E 3-17 AK-2R0055-E LGI-10 AK-2R0257 -E 3-18 AK-2R0056-E LGI-12 AK-2R0258-E 4-6 AK-2R0057 -E LPC-1 AK-2D0254-E 4-9 AK-2R0058-E L2-6 AK-2R0278-E 4-11 AK-2R0059-E L2-20 AK-2R0273-E · 4-13 AK-2R0060-E L2-24 AK-2R0274-E 4-14 AK-2R0061-E L2-26 AK-2R0275-E 4-15 AK-2R0062-E L2-28 AK-2R0276-E 4-17 AK-2R0271-E L2-30 AK-2R0277-E 9-22 AK-2R0063-E SE AK-2D0105-E 9-25 AK-2R0064-E SW AK-2D0106-E 11-2 AK-2R0065-E 1-8 AK-2R0046-E 11-7 AK-2R0066-E 3-4 AK-2R0047-E 11-8 AK-2R0272-E 3-6 AK-2R0048-E 12-23 AK-2R0067 -E 3-7 AK-2R0049-E 12-25 AK-2R0068-E 3-10 AK-2R0050-E 12-27 AK-2R0069-E 3-11 AK-2R0051-E 14-25 AK-2R0070-E 3-12 AK-2R0052-E 14-27 AK-2R0071-E 3-13 AK-2R0053-E 14-36 AK-2R0072-E ~JUN ~ 0 20n~ ( ,t 3. List of,EOA Injection Wells Authorized by Rule by EPA (Addition of Figure A-3) 3 JUN 3 ij 2.004 ~' \ ( Figure A-3 Prudhoe Bay Unit Eastern Operating Area Injection Wells Authorized by Rule Well Well NGI-1 9-17 NGI-2 9-18 NGI-3 9-19 NGI-4 9-20 NGI-5 12-19 NGI-6 12-20 NGI-7 13-6 NGI-8 13-9 NGI-9 13-15 NGI-10 13-16 NGI-11 13-17 NGI-12 13-18 NG 1-13 13-19 NGI-14 13-20 OWD-NE 13-21 OWD-NW 13-22 PWD 1-1 13-23A PWD 2-1 13-24 PWD 3-1 13- 2 5 WGI-l 13-32 WGI-2 14-13 WGI-3 14-14 WGI-4 16-1 4-8 16-2 4-10 16-3 5-17 16-5 9-8 16-10 9-10 16-11 9-12 16-16 9-14 17-6 9-15 17-8 9-16 17-10 ~ ~ ÎDn~1 ~ \ ( 4. Revised Narrative and Map of Eastern Operating Area (Replacement for Section B and Figure B-O 4 scts!N~~E[:' JUN ¿~ {) 200¿~· SC!\NNE[) ~nJN ¿ì 0 2DtH 5 .... 1" . ~ (Repl~ç~rn,~r~t' ;~é?r SectionC, s~bsecti;;n ì) . , , " ,', ' . .'" ; '" i ;", ,,""<:1::~': '.. :: t~(~ ;,:.¡::: .: ;o',t..:: ;~; fr. ..~.',-~;..~t r:;;~¢Vi$ed Narta~iýe f9r Colville (... ç;ro~p. ~d ~~ª!~rkt.Qk Form4.'tioh ,t : ; ,.' ";:;~;',~;~:n'~ :,ì~ ", "1~.i;:t.,~ F' i j~ ~ ,f ,( ( SECTION G Geologic Information 20 AAC 25.402(c)(6) 20 AAC 25.252(c)(4) Subsection 1 Prudhoe Bay ~nit E~stern Operating ,Area Colvi1!e Groupand Sagavanirktok Formation Strata of the upper Colville Group and Sagavanirktok Formation comprise the late Cretaceous and early Tertiary shallow aquifers iri the EOA area of the Ala.skan North Slope and contain water of less than 10,000 mg/l TDS(see also Section N, page 36, a¡;)d Figure H-l). GCAN~I;~ED J~JN 3 0 20D4. ( (, 6. Revised Figure for ~tern Operating Area Structural Cross Section (Replacement for Figure G-3, now labeled as Figure G-l) 6 SC¡~~~~NE[) JUN ¿~ Wi 200¡~, It (Addition to Section G) ~', 7. Request for Specific Injection Interval 7 ~)tAÐ~Nf[) ,)UN ~ (J) 2DfM (' ~, 9. Revised List of Figures (Replacement for List of Figures) 10 ~{C~/ìNN[·:J.J ~JUN ~ 0 2DnL~ Figure A-I Figure A-2 Figure A-3 Figure B-1 Figure G-l Figure H-l Figure 1-1 Figure J-l Figure J-2 Figure L-l Figure M-l Figure M-2 Figure N-l Figure N-2 (' Prudhoe Bay Unit Eastern Operating Area Area Injection Order Application List of Figures Ti tIe Legal Description of Area List of Injection Wells with EP A Permits List of Injection Wells Authorized by Rule Plat Map Structur al Cross Section Type Log: Sag River State III Wellbore Schematic Typical Fluid Analyses - Ivishak Typical Fluid Analyses - Lisburne Fracture Gradient Curve Fluid Analysis - Well GC-3C Fluid Analysis - Well GC-3D Documentation of Equations Calculated Wireline Salinities (Ç'" fi'"An [1 "~ U E·· ~ n n H .;:~ 0 t2' 0 n~ I<.-?)~'" 'a~\ ~'ìJ r~ L) ~,"H,H\I (:;1) ~J1 _~ "J2~, ( ~ SECTION G - GEOLOGIC INFORMATION 6/26/86 ADDENDUM The Colville Group/Sagavanirktok Formation (also known as the Tertiary and Cretaceous Sands) are currently used for disposal by ARCO Alaska, Inc. in the EOA through wells at each of the Flow Stations, the LPC and Pad 3 (just South of Drill Site 6). For purposes of this application, the disposal zone for the Colville Group/Sagavanirktok Formation should be defined as the interval between 1900 feet and 6750 feet md, and lateral equivalents, in the ARCO/EXXON Sag River State III well. 8 t-'\.I(·"^¡i\~)I\~ri:·f' n ~M (.'~ Jr¡ 20n~ r¡:)Lt-;~6 \1 J\:\ tL,:.) di~) jìjI (;;1 t: ,:, _. ï'y,L/J' ( 8. Revised Labeling on Type Log (Replacement for Figure H-l) 9 (G.".'-((' i'\l<\\i~~Ic::rl II~ ~¡¡,,~ ~~ n ZOOl} '~. PVb"""~ð\~1 tì ''it1L..L'.;;.a'' ~J I!) II \.... ,'-' ARca Alaska, Inc~ Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 ( ~~ ~~ [ro -fie¡- July 9, 1986 C. V. Chatterton Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RECEIVED JUL 0 91986 Alaska Oil & 6' C dS ons. Commission Anchorage RE: Prudhoe Bay Unit, Eastern Operating Area, Area Injection Order Application, Addendum Dear Mr. Chatterton: The enclosed information is submitted as an Addendum to the Prudhoe Bay Unit EOA Area Injection Order Application. As delineated below, portions of the information are intended as replacements and the remaining as additions to the Application. The following information is enclosed: 1. Revised narrative and legal description of the area covered by the application (replacement for Section A and addition of Figure A-l), 2. List of EOA injection wells permitted by EP A (addition of Figure A-2), 3. List of EOA injection wells authorized by rule by EP A (addition of Figure A-3), 4. Revised narrative and map of Eastern Operating Area (replacement for Section B and Figure B-l), 5. Revised narrative for Colville group and Sagavanirktok formation (replacement for Section G, Subsection 1 and delete Figures G-l and G-2), 6. Revised figure for Eastern Operating Area structural cross section (replacement for Figure G-3, now labeled as Figure G-l), 7. Request for specific injection interval (addition to Section G), 8. Revised labeling on type log (replacement for Figure H-l), and 9. Revised List of Figures (replacement for List of Figures). ARCO Alaska, Inc. òs a Subsidiary 01 AllanlicRichlíe!diCom¡oan~1 ,JUN 3 ~ 2004 ~. I( Mr. C. V. Chatterton July 9, 1986 Page 2 A copy of the permit application with the additions/replacements indicated above is included for your convenience. Please contact either Julie Athans (265-1345) or me (265-6136) if you have ·any questions. Sincerely, ~~ Mark A. Major Operations Coordinator MAM:pln Enclosures cc: L. Smith, AOGCC Rt.Ct.\\]t.t) CJ q \9'ð'ò ~ \) \.. n\\&$\OU Com", . &. ûaS C,O{\s. Þ.\a.$~a 0\\ J'.\t\cnota\\e SCt.\NNED ~JUN 3 0200iq. ( ( Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of ARCO ALASKA, Inc. for an Area Injection Order for the Eastern Operating Area of the Prudhoe Bay Un it. The Alaska Oil and Gas Conservation Commission has been requested, by letter dated June 5, 1986, to issue an order for area inj ection to provide authorization for utilizing existing service wells permitted for injection by the U.S. Environmental Protection Agency and subsequent service wells permitted in accordance with 20 AAC 25.005 or 20 AAC 25.280 to inject fluids underground for purposes of enhancing oil recovery from both the Prudhoe Oil and the Lisburne Oil Pool, as defined by Conservation Orders No. 145 and 207 respectively, and the disposal of non-hazardous oil field fluids into tertiary and cretaceous strata. Parties who may be aggrieved if the referenced order is issued granting the request are allowed 15 days from the date of this publication in which to file a written protest stating in detail the nature of their aggrievement and their request for a hearing. The place of filing is the Alaska Oil and Gas Conserva- tion Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501. If such a protest hearing request is timely filed, a hearing on the matter will be held at the above address at 9: 00 AM on July 16, 1986 in contormance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433, after June 23, 1986. If no such protest is time1¥ filed, the Commission will consider the issuance of an order w1thout a hearing. ~' " æCJ '7Þl ~~ Lonnie C. Smith Commissioner Alaska Oil & Gas Conservation Commission Published June 9, 1986 SCÞ\~\]NED !>~ 0 200é~, d 0 -~, , ( THE ANCHORAGE TIME{ P.O. BOX 40 ANCHORAGE, ALASKA 99510-0040 'ROOF OF PUBLICATION ~K OIL & GAS CONSERVATION COMM ;001 PORCUPINE DR. INCHORAGE, AK 99501 ;AROLINE 8RIGHT , BEING DULY .WORN, ACCORDING TO LAW DECLARES: rHAT SHE IS THE LEGAL CLERK OF THE ~NCHORAGE TIMES, A DAILY NEWSPAPER )UBLISHED IN THE TOWN OF ANCHORAGE :N THE THIRO JUDICIAL DIVISION, )TATE OF ALASKA, AND THAT THE 40TICE OF.......................... THe PRICE OF THIS AÐ ¡S...........~. S 23.68 .~otlceof Public Hearing STA TEO¡:¡:AL.ASKA ,'.' I , .' QUancl G(,'IS ,. ..' " ,'! Conse"atlq" commls.lon "Re: ,The apPI!catloJ:l,of ,ARÇO ,ALAS(A"lnc. for an Area",ln- 111:,ehl~i:~~.~D.rd~~1:,r,':.&,'·,',~. ~I',fhiap,s, ~~~~., ~...ól'BaV·I·Unlt;"'''r,' I'> · , ':"f:~.::'~¡'a;~kå"O;I~~~~þS Con- \,.~ . tl)n,CQr.nl1!llsslonljcls~en· i~li', ,.~tbY:'lettër',date(hJvne' Sf , "to "ssue an order. for :. nh:rØlonto PCœLIdl..JUrthQ::. "\ n, I ~Qrut,ZI,rlfi ·8xlsflnlil 'I .. ,. ~ii WltI Is:;: Pítrmltted ,for,: In- Igij.Ç;.tIOJ1þ,YI,.t,I:I.I,'U, .S.. EnVI. ron~.en.- t ~;:~~ote(:tlonAg8nc:y and sub- ¡ U'nt.sllrvlce wel.l~ ptrmlttecl' In'll:cicC~'dâr/ê:e with,' 20 ,AAC . 25~00$"or ,,2ØI*'~C 25;280·tQ IQlect fllllds,under:gl"ound ,for :purPOses ,:~~tt~~~~F:~lu~~ø~eîf'Y:"~~dfrf~ I::.lsb",rne,OUi¡"OOI, ds,d,flned by C:oo.ervatlôn, . 'Orden' No. ,145 ·.'an.ø;,..207. r. e, S. ~"C'. fl, V. ely"and:"th..e ,,\dl'sÞØlol ,.of'·IQnoharZardous QII ':,fl".IØ~'IIJI.dsJn ~. "¡.te. ;;tla.r'Y:and ere. t'iJceous strafl ~'i¡"', '. "r, I, I 'I' 'I,: ,J ' ".~,I\,I ,: " J: " , , . , , s,' , qv ,·þ'e . ;ag- 'i ,Ifr:,"~tä order :;1~)W'd'::I!.! d~h~~~~·~r~J ·~dOt81.0'~,tl'lls: )c'~IC'!ltlon In'IWhlct) ;to.. .1:1.18. a writ, ' , r:o.., test... statIng ",IO:d!llt(,'lll thë, re 'óf tnelr ag- ·~:"II~ement ,.'. ,':,hf!lr'rf!Quest .l'~r:ó':hf!arlng;'·" 'e place·of filing ';,1". itÞe.. Alaska'OJI. .. ,gnd, ~as' Con- ,I~J~~~Y~~ . I g~~~ls~~~h~r:¡~ ~Iøi¡ka 99501:'Jf:;..uchi 'eI protl$t ""arlng '1'f!1I"','I, I.:,tlmelv ' flied, a ,hearli'll onth" ",atter will' be helø at the, above' address at '.. :00, .A~. M .01'1. 'J~Y,:," ",' '986 In co. ,'n.- I ' formance,wlthl'20:AA~ '25.550. : If I· cf hearlng,.,ls·tOI:be,h,ld, Inter- . .,t.d parties .mav confirm this II·· by .calllng t.he"c, º,. mmlSs. Ion, 's ,.Of- flcl,(907) 279~JI;U3, âfter Jurie f I i 23, J 986.1 f no" 'Sl,IC;t! pr:otestl. 1,;:":m~~~n:f~~,::,.R=I',.~~:'~':"::':: 1:¡:,~~,~::WltWO..tQ~"'l'lnll!.~ . ~...'.",' ;<1':' ,~,' ,,' ,'\'ì¡!:~),;~ 1:1',.',' , . ,". " , ",'. ',- I~.'(,(" 'I, I, r' I i "I:i\i,,:: :, .,Lonl'\le..'C; '$:nlt" .'..!.:.. ., ·!~Î~s~acii~~.~:s~~:~Iervât'Ori"· :.:;~·~r~p~o;:¡~~~~I:!~,., ! .:: r:PÞ: June 9;1"9116;1:: ...! I .'. po: AO-Oa-.5563 , COpy OF WHICH IS HERETO ATTACHEO, dAS PUBLISHED IN................... )f THE ANCHORAGE TIMES. ~eGINNING ON....................... ENDING ON.......................... 1 ISSUES 06/09/86 06/09/86 THE SIZe Of THIS AD WAS............ 74 LI NfS SIGNED.......... d~~ THE AD NUMBER IS.................... 2364956 SUBSCRIBED AND SWORN TO BEFORE ME THIS................... 09 DAY OF JUN,1986 NOTARY PUBLIC OF, THE STATE OF .'H.J~SKA d:" . @,.,..,.. ~- /1A2Ú /--* -~~- - ~~~ MY COMMISSION EXPIRES............... ~_·/g-·Jc;¡9o ~~--~~-~--~-~~---~- JUN 3 D 20Q,';} ARca Alaska, Inc( Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 ( ~~ ~~ June 5, 1986 Mr. Chat Chatterton Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Prudhoe Bay Unit EOA, Area Injection Order Application Dear Mr. Chatterton: Enclosed is the Prudhoe Bay Unit EOA area injection order application. ARCO Alaska, Inc. as operator of the EOA, requests an area injection order be issued for current and future injection wells, as described in the application. The application was prepared in accordance with the recently revised Commission injection regulations. ARCO requests injection approval for two types of injection wells - fluid disposal and enhanced recovery. Three injection zones are included in the application - the Sagavanirktok/Colville, the Ivishak and the Lisburne Formations. The process associated with the transfer of authority from the EPA to the Commission effects both existing and new injection wells. Existing wells are authorized by permit and rule by EPA and those authorizations remain in place until a replacement permit is issued by the Commission. New injection wells (newly drilled or converted) require prior authorization under AOGCC rules. A mechanism for permitting new injection wells after termination of the EP A program (June 19, 1986) and prior to issuance of our area injection order under the new AOGCC rules is not clearly defined. ARCO proposes that in the event a new injection well is necessary during the interim period, the injection well be temporarily authorized by the Commission upon submittal of an acceptable sundry notice or drilling permit, pending issuance of the area injection order. ARCO requests the area injection order be issued as soon as possible to allow normal field operations to continue. Please contact Mark Major (263-6136) or Julie Athans (265-1345) if you have any questions or require additional information. Your timely action is apprecia ted. Si~CW+-~ - ~. Hart ~d'hoe Operations Manager Enclosure R f- ( ç \\n: D JUN 0 S \gßG , .,. í\ÚS'3,IO'O ,,' ¡~), vlj, II '\\ask() v II ';.;. ;nC\1orage JAA/jhl cc: L. Smith, AOGCC SCA~\ij~\jEI'11 ,.JUN 0~ {ì! 200,3 ARCO Alaska, Illc. is a Subsidiary 01 AllanticRichlieldCompanv I I I I I I I I I I ( I I I I I I I I .'1 It ~, It:Óft( PRUDHOE BAY UNIT EASTERN OPERATING AREA AREA INJECTION ORDER APPLICATION R,tC,t~\ tD JUN 0 5 1986 , .' " \Ju,,¡¡HISS,lon A\aska Oil & t,d.:::' I.,v,';:> Anchorage JUN ;~~ 0 2DrM I ;{ ~; ( Prudhoe Bay Unit Eastern Operating Area Area Injection Order Application I T ABLE OF CONTENTS Section/Regulatory Cite Subject Page I A. 20 AAC 25.460 Area Injection Order 1 I B. 20 AAC 25.402(c)(l) Plat 2 20 AAC 25.252(c)( 1) C. 20 AAC 25.402(c)(2) Operators/Surface Owners 4 I 20 AAC 25.252(c)(2) D. 20 AAC 25.402(c)(3) Affidavit 5 I 20 AAC 25.252(c)(3) E. 20 AAC 25.402(c)(4) Description of Operation 6 I F. 20 AAC 25.402(c)(5) Pool Information 8 G. 20 AAC 25.402(c)(6) Geologic Information 9 I 20 AAC 25.252(c)(4) H. 20 AAC 25.402(c)(7) Well Logs 18 I 20 AAC 25.252(c)(5) I. 20 AAC 25.402(c)(8) Casing Infor ma tion 20 20 AAC 25.252(c)(6) I J. 20 AAC 25.402(c)(9) Injection Fluid 22 20 AAC 25.252(c)(7) I K. 20 AAC 25.402(c)( 1 0) Injection Pressure 29 20 AAC 25.252(c)(8) I L. 20 AAC 25.402(c)(l1) Fr acture Infor ma tion 30 20 AAC 25.252(c)(9) [ M. 20 AAC 25.402(c)(l2) Formation Fluid 33 20 AAC 25.252(c)(l0) I N. 20 AAC 25.402(c)(l3) Aquifer Exemption 36 20 AAC 25.252(c)(l1) o. 20 AAC 25.402(c)(l4) Hydrocarbon Recovery 40 I P. 20 AAC 25.402(d) Mechanical Integr i ty 41 20 AAC 25.252(d) I Q. 20 AAC 25.402(h) Wells Within Area 42 20 AAC 25.252(h) R. 20 AAC 25.450(a) Variance Request 43 SCANNED ~JUN 3 0 20(J;:, I I I I I I I I I I I [ [ I I I I, Figure B-1 Figure G-l Figure G-2 Figure G-3 Figure H-l Figure 1-1 Figure J-l Figure J-2 Figure L-l Figure M-l Figure M-2 Figure N-l Figure N-2 ,1 l¡. ( , Prudhoe Bay Unit Eastern Operating Area Area Injection Order Application List of Figures Title PaRe Plat Map 3 Generalized Stratigraphic Section 15 Type Log: West Sak and Ugnu Sands 16 Structural Cross Section 17 Type Log: Sag River State III 19 Wellbore Schematic 21 Typical Fluid Analyses - Ivishak 26 Typical Fluid Analyses - Lisburne 28 Fracture Gradient Curve 32 Fluid Analysis - Well GC-3C 34 35 38 Fluid Analysis - Well GC-3D Documentation of Equations Calculated Wire line Salinities 39 SC,AN!\]ED JUN 3 ~) 200¿,~ I I I I I I I I I :( ( SECTION A Area Injection Order 20 AAC 25.460 ARCO Alaska, Inc., as operator of the Prudhoe Bay Unit, Eastern Operating Area (EOA), requests an area injection order be issued for current and proposed injection wells: 1) for disposal of fluids that are brought to the surface in connection with conventional oil and gas operations and comingled with non-hazardous waste fluids from facilities which are an integral part of production and operation, and 2) for the enhanced recovery of oil or gas. The area injection order is requested to encompass aU lands within the boundary of the EOA, as shown on Plat B-1. ARCa requests that the order allow ARCO to drill, operate, convert or plug and abandon wells within the EOA by filing Form 10-401 or Form 10-403. I I I I I The Oil and Gas Conservation Commission may, in its discretion, issue an area injection order if certain requirements are met. The EOA injection operations meet the requirements of 20 AAC 25.460(a). Existing wells are described and identified by type. Injection wells are within the same field, are operated by a single operator and are used for other than hazardous waste injection. The cumulative effect of drilling and operating additional enhanced recovery injection wells will result in an increase in hydrocarbon recovery. The cumulative effect of additional fluid disposal wells is anticipated to be economic disposal of non-hazardous oilfield waste streams. Disposal of produced water and associated waste is necessary to allow production of oil. Both types of injection wells will be drilled, constructed, operated, and abandoned in accordance with the Commission rules to prevent movement of fluids into freshwater strata. I I I I I 1 SCANNED: ~JUN ~ 0 2004 I I I I I I I I I I [ I I I I I I [ / ~ ( Section B Plat 20 AAC 25.402(c)( 1) 20 AAC 25.252(c)(l) Figure B-1 is a plat showing the location of all wells that penetrate the uppermost injection zone within the EOA boundary, i.e., the area covered by this area injection order application. 2 SC!\~\~NED Q.JUN 3 0 200L¡. I ,I r I !( ( SECTION C Operators/Surface Owners 20 AAC 25.402(c)(2) 20 AAC 25.252(c)(2) I I I The surface owners and operators within the area of this area injection order and extending 1/4 mile beyond the boundary (excluding ARCO) are: Exxon Company, U.S.A. Attn: Bruce Bowen 225 W. Hillcrest Drive P. O. Box 5025 Thousand Oaks, CA 91359 · Walton Ahmaogak P. O. Box 274 Barrow, AK 99723 I I r 1 I I I Standard Alaska Production Company Attn: Jean Parsons 900 E. Benson Blvd. P. O. Box 196612 Anchorage, AK 99519 · Andrew Oenga P. O. Box 201 Barrow, AK 99723 · Alyeska Pipeline Service Company Attn: Land Department 1835 S. Bragaw St. Anchorage, AK 99512 Sta te of Alaska Department of Natural Resources Attn: Kay Brown P. O. Box 7034 Anchorage, AK 99510 4 cr.:"'r:A~Q¡Ä~E-:'r" U~ n\~ cI) fÏ';¡ 20['11 ~,'~l,:, "..;W~ _L) "HJ ~'\I (;,~ ~il ,_' ,t, I I ( I ( I I f I ( I ( [ ( I ( :t SECTION D Affidavi t 20 AAC 25.402(c)(3) 20 AAC 25.252(c)(3) Affidavit of Julie A. Athans STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Julie A. Athans, declare and affirm as follows: 1. I am over 19 years of age. I am employed by ARCO Alaska, Inc. as an Environmental Coordinator. I have personal knowledge of the matters set forth in this affidavit. / I 2. On J'u IV.e ..5- __, 1986, the surface owners/operators listed in Section C were provided a copy of this permit application. DATED at ,l~~ Anchorage, , 1986. Alaska this ~-f ~ ~ day of ~////é Jl /ÍJ-MAJS Julie A. Athans / Subscri;:ed and affirmed \/~e... d_____, 1986. before me at Anchorage, Alaska on ! ~ y; ,/ ß~ ft{ , ~,~,::/-I!!~'C-::--. Notary Public in, anq for the , State of Alaska /)-' I / My commission_expire:';: t;t jlf '1_ 5 SC/\N~\~ED JUN 3 Ð 2nrl/\ ( ( I ( SECTION E Description of Operation I I 20 AAC 25.402(c)(4) Current and proposed injection operations at the EOA are divided into two broad categories: I I I Subsection 1 - enhanced recovery, and Subsection 2 - disposal of fluids brought to the surface and comingled with non- hazardous waste fluids from operations. Subsection 1 Enhanced Recovery ( t I I I I I Enhanced recovery injection wells are used for the introduction of additional fluids into the oil reservoir to increase the ultimate recovery of oil. Three types of enhanced recovery injection wells are currently used: water injection, gas injection, and water-alternating-gas injection. Additional methods of enhanced oil recovery may be used in the future. Future injection wells will continue to be designed, constructed, operated (and monitored) to ensure the injection fluid is entering the oil reservoir. The Ivishak and Lisburne formations are/will be used for enhanced oil recovery. Subsection 2 Fluid Disposal Produced water disposal wells are used for the disposal of produced water and other fluids generated during operations. The produced water is water which is produced with the oil and separated from the oil and gas at the Flow Stations and Lisburne 6 SCANNE[\' JUN 3 0 2004 I r ( I' I I I ( (t Production Center. The remaining injection fluids are non-hazardous fluids generated by drilling and production operations. Flow Stations 1, 2, and 3 and the Lisburne Production Center have produced water disposal wells. Fluid disposal wells are currently in operation at Pad 3 just South of Drill Site 6. Non-unit, non-hazardous wastes associated with North Slope oil production activities are also injected at these wells. Additional fluid disposal wells are anticipated. Future fluid disposal wells will be designed, constructed operated (and monitored) to ensure the injection fluid is entering the injection zone. Injection is into the Sagavanirktok Formation/Colville Group. I I I I [ I I I I I I 7 ,JUN 3 0 2nO/l I I I I I I I I I ( { SECTION F Pool Information 20 AAC 25.402(c)(5) The strata affected by injection for enhanced recovery from the Prudhoe Oil Pool, are defined by Rule 1 of Conservation Order No. 145 as the strata that are common to and correlate with the accumulation found in the Atlantic Richfield - Humble Prudhoe Bay State No.1 Well between the depths of 8,110 and 8,680 feet, MD. The strata affected by injection for enhanced recovery from the Lisburne are defined for the Lisburne Oil Pool in Conservation Order No. 207 as the accumulation of oil found in the Atlantic Richfield - Humble Prudhoe Bay State No. 1 well between the measured depths of 8,790 and 10,440 feet. ¡- . I " ~ I I I I I I 8 sCt~NNE[) <JUN 3 0 200ft I I I ( I r I I [ [ I [ I I ( [ I I I { { SECTION G Geologic Information 20 AAC 25.402(c)(6) 20 AAC 25.252(c)(4) Geologic information and figures on the zones used for injection in the EOA are included in three subsections: Subsection 1 - Colville Group & Sagavanirktok Formation, Subsection 2 - Ivishak Formation, Subsection 3 - Lisburne Group. Subsection 1 Prudhoe Bay Unit Eastern Operating Area Colville Group and Sagavanirktok Formation Strata of the upper Colville Group and Sagavanirktok Formation comprise the late Cretaceous and early Tertiary shallow aquifers in the EOA area of the Alaskan North Slope. This includes all the interval between the base of permafrost and the K-12 marker as shown on the Generalized Stratigraphic section (Figure G-l). The EOA is injecting waste water (such as produced waters from the EOA), into sandstone beds in the Colville Group and Sagavanirktok Formation at Flow Stations 1, 2 and 3 and certain drill sites. Significant amounts of low-gravity oil occur in two zones which ARCO refers to as the West Sak sands and the Ugnu sands in the Kuparuk River Unit ( KRU) to the west. A type log for the West Sak and Ugnu Sands from the Kuparuk River Unit is shown in Figure G-2. These zones are not oil-bearing in the EOA, but rock data from the West Sak and Ugnu in the KRU provide the best data for characterizing the Colville/Sagavanirktok formation in the EOA. 9 I I ( I I I I I I ( I I I I r I I f I { " ( The upper Colville Group 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 in thickness. Core data in the KRU show that porosity ranges from 25 to 35 percent and permeability ranges from 10 to 800 millidarcies. The remainder of the underlying Colville Group consists of an impermeable mudstone and shale sequence over 1600-2000 feet thick in the EOA. The top of the West Sak Sand occurs between about 6000 and 7800 feet subsea in the EOA, and dips gently to the east/northeast. The Sagavanirktok Formation 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 average 30 feet thick. Core data in the KRU indicate sand porosities between 25 and 40 percent and permeabilities from 200 to 3000 millidarcies. The top of the Ugnu Sands occur between 5500 and 7000 feet subsea in the EOA and also 'dip gently to the east/northeast. The Sagavanirktok strata between the top of the Ugnu and the base of permafrost are 3700 to 5400 feet thick and are similar to the Ugnu based on available data. The Sagavanirktok Formation 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 permafrost between 1800 and 2000 feet subsea to the west. This isolates these formations from communication with surface waters. Subsection 2 Prudhoe Bay Unit Eastern Operating Area Ivishak Formation 1. Injection Interval A. Stratigraphy and Lithology The Ivishak Group, Late Permian to Early Triassic in age, is divided into three distinctive geologic formations: the basal Echooka Formation, The 10 sct\NNED ,JlJN 3 :0 20n,,~ I ~' ( r I I I I I I I I [ Kavik Shale, and the overlying Ivishak Formation. Stratigraphically above the Ivishak Formation, in ascending order, are the Shublik Formation and the Sag River Formation. Within the field limits of the EOA, the Ivishak Formation varies in thickness from zero feet (by truncation) to about 700 feet, and the structural top of the Ivishak varies in depth from about 7900 feet subsea to slightly over 9000 feet subsea (Figure G-3). The Ivishak reservoir is dominantly a sandstone interval that has been divided into four zones (I-IV). Zones IV and III are the primary injection intervals with Zones II and I receiving relatively minor amounts of injection fluids. Zone I, the lowermost zone within the Ivishak reservoir averages 125 feet in thickness. Zone 1 is comprised of thin to moderately thick interbeds of mudstone, siltstone, silty sandstone and sandstone. The relatively clean sandstones commonly have porosities from 20-25% and permeabilities from 250-350 md. Zone II is a lithologically variable unit up to 280 feet thick that consists of interbedded sandstone and conglomeratic sandstone with lesser amounts of conglomerate, siltstone, mudstone. Zone II sandstones usually have about 25% porosity and 500-1000 md permeability. I I I I I I I I Zone III consists predominantly of poorly sorted conglomerate and conglomeratic sandstone, with occasional thinly bedded siltstone and mudstone. This zone ranges from 0-100 feet in thickness across the EOA. Zone II porosities are typically 16-18% and permeabilities range from 800- 1200 md. Zone IV, the uppermost division of the Ivishak reservoir at Prudhoe Bay, is comprised of interbedded fine to medium grained sandstones with lesser amounts of sandy conglomerate, silty sandstone and mudstone. Thickness varies from 0-225 feet in the EOA. Average porosity is about 24% and average permeability is about 250 md. 11 I I I I I I I r I ( I I I I I I I I ~, ~ '\ The Sag River Formation is a minor reservoir stratigraphically above the Ivishak reservoir in the EOA. The Sag River ranges in thickness from 0 feet (by truncation) to 50 feet and is separated from the main Ivishak reservoir by 35-75 feet of limestones, siltstones and shales of the Shublik Formation. The Sag River sandstone is very fine to fine grained and contains glauconite and ankerite cement. Porosity values usually range from 7-20% (average 15%) and permeabilities range from 3-30 md (average 20 md). B. For ma tion Water Salinities Laboratory analyses of formation water salinities produced from the Ivishak sandstones indicate an average salinity of 18,500 ppm NaCI equivalent and a total dissolved solids (TDS) content slightly in excess of 20,000 ppm (Jones and Speers, 1976). There are no salinity data available for the Sag River. In the EOA, all of the Sag River wells contain hydrocrbons. Since only one EOA well (OS 17- 14) hs been tested for Sag River potential, no connate water samples are available. Accurate salinity calculations cannot be done with hydrocarbons present in the formation. However, the Sag River is believed to be in communication with the Ivishak reservoir along faults and at the truncation. Therefore, it would be reasonable to predict that the Sag River has similar formation water salinity values (20,000 ppm TDS). C. Structure The Prudhoe Bay Field is part of a northwest-southeast trending anticlinal structure. Closure in the EOA is provided by gentle structural dip to the south and west, truncation by the Lower Cretaceous Unconformity to the east, and normal faults in the north. II. Confining Intervals The Ivishak Formation in the EOA of Prudhoe Bay is confined above and below by impermeable sequences of Kavik Shale, Kingak Shale and Cretaceous shales. 12 ,SCl~\N,NEiD .JUN 3 0 2004 I I I I I I I r I ( I I I I I r r I ~: ( The confining zone at the base of the Ivishak sandstone reservoir is the Kavik Shale. This shale averages about 150 feet in thickness in the EOA and varies from less than 100 feet to over 200 feet, thickening to the south. Overlying the Ivishak Formation are two thin stratigraphic intervals which are minor reservoirs at Prudhoe Bay. In ascending order these are the Shublik Formation (@ 70' thick) and the Sag River Formation (@ 35' thick). Overlying these units is the confining Kingak Shale. In the EOA, the Kingak shale attains a maximum thickness of about 800 feet. This shale thins markedly to zero feet eastward across the EOA as a result of truncation by the Lower Cretaceous Unconformity. Overlying the Lower Cretaceous Unconformity and sealing the truncated Ivishak, Shublik, and Sag River reservoirs at Prudhoe Bay are the Cretaceous shales. These shales range in thickness from 1600 to 2000 feet and blanket the Prudhoe EOA. III. References Jones, H. P. and Speers, R. G. (1976) Permo-Triassic Reservoirs of Prudhoe Bay Field, North Slope, Alaska, in North American Oil and Gas Fields, AAPG Memoir 24, p. 23-50. Subsection 3 Prudhoe Bay Unit Eastern Operating Area Lisburne Group I. Injection Interval A. Stratigraphy and Lithology The Lisburne Group is a thick sequence of Mississippian and Pennsylvanian carbonate rocks that underlie the Ivishak Group. The contact of the Lisburne with overlying formations is unconformable, and is easily 13 SCAW\~NE[) IJUN 3 D 2004 I I I I I I I I I I I I I I I I I recognized on most well logs. The Lisburne occurs at approximately -8300' subsea along the northern edge of the Prudhoe Bay Field and becomes progressively deeper to the south and west. (Figure G-3) The Lisburne Group is subdivided into the Wahoo and Alapah Formations, each of which is approximately 1000' thick in the EOA. The Wahoo consists predominantly of limestone with lesser amounts of dolomite, siltstone, shale, and chert. Pyrite and glauconite are present in minor amounts. Porosity development is determined by a complex interaction of diagenetic processes and is extremely variable. Some intervals have porosity in excess of 20% and permeability in the 20 millidarcy range, while other intervals have porosity of 1-2% and no measurable permeability. The Alapah is made up of limestones and dolomites, with minor siltstone, shale, and chert. Porosity development in the Alapah is controlled by dolomitization, cementation, and leaching. Extensively leached dolomite intervals can have porosity exceeding 25% and permeability approaching 300 millidarcies. Highly cemented limestone intervals have essentially no porosi ty or per meabili ty . B. Formation Water Salinity Laboratory analysis of a sample of formation water from the South Bay State III well, located in the NW corner of section 22 - T 11 N - R 15E, indicates a salinity value of 26,520 ppm TDS. Because the Lisburne is only in an initial stage of development, no further salinity data is available. II. Confining Intervals The upper confining zones for the Lisburne are the Kavik and Cretaceous shales, which have been discussed in the previous section. The underlying confining zone is the Kayak Shale, which consists of dark-gray shale with varying amounts of sandstone and limestone. The Kayak exceeds 500' in thickness in the EOA and does not have appreciable porosity or permeability. 14 SCfìN,Nff::D JUN 3 0 20D4 r I I ( ( ( ( ( I PERIOD > a: < - I- a: w t- ( ( [ ( ( Figure G-l GENERALIZED STRATIGRAPHIC SECTION LlTH- MARKU OlOGY DESCRIPTION :1\~{: z o - to- e( :æ a: o u. ?t~~~~0.~ ...... 0', ,_.... (}~)~/:; ~~)i{:i~: !~m~;~¡ BASE ~:~~~ PERMAFROST: Interbedded gravels, sands and shales. PERMA-:'.:·~···.;" .- fROST '. :':::...:: I " I ..0. . .. ~ ,~,,,'. ~ó.- r-3 i~ª~î~ T-3: ~~~~e~a~~:~e~~~ ~~~~~a~~da~~a~~~~rlain with inter- -----. K-15 ~I~ K-15: First coal marker underlain with sands, silts and ~~]~~i shales. Localized coals occur within this interval. j.JJ:\0.~};. .----- itiì ~'~: ,.:0·...\·, "- ---.. ~ o to- ~ a: ~ > « " < en UPPER '::y.:::,;:.i.':'i( UPPER UGNU: I nterbedded coarse to fi ne sands and sha 1 es. UGNU ~~iJ~ LO~ER~~i;:? LOWER UGNU: Interbedded coarse to fine sands and shales. - - - - - - - UGNU ~~~é~:::: ~----- (J) ;:) o w () < I- W a: () [ I I I I ..----- a. ::) o a: e" , ~EST !.:~·/:r;::::;:,!; SAK -:-:-:-:-:- ------ SANDS :;:?'/:::::)7 ._---,- WEST SAK SANDS: Interbedded fine-sandstones, siltstones, and clays. ..----- ~. ~..~:::;~:;.~~ ------ -----. W ..J ..J ~ o u ::.f:'.:'7. .:::. :r'o: ------ ':':?'!::::"r:.'~ .----- I( 12 :::-:-:-::--:~ .----- -----.. -----... :~~~~~~ .----- -----. ------ -----.. -----.. ------ -----.. ------ .----- -----. ------ -----. ..----- -----. K-12: Interlaminated silty mudstones and shales with minor silty sandstones. Based on data from: ARCO West Sak River State #1 15 "-'6"/~ ¡i\~L UW--~\ ~m ~M tÕj) ff':I ?O['\II b)l~Lr:M'ÌJ~\jt;:L,J ~J\hJn Qi) í~.JI I.... .1 .J·~;r I (' Figure G-2 ( ARCO I WEST SAK RIVER ST ATE 1 SEC. 2, T.11 N., R.10E., UM r GR LL8 50 100 1 10 100 I ~ ~ ~ t ..---:::> t 3200 '- .. I .----S' ~ UPPER UGNU > l y-- SANDS - t ~ I t ./ -< f " I I 3400 '- ~ .-3:' ì .s- f ~ LOWER UGNU ./ ~ ¡ SANDS ( ~ I 3600 '- ~ > + ~ ~ ( \- I ~ S > t I 3800 '- ~ .f I < ~ WEST SAK SANDS f I 4000 '- ---> ?- + .,.$ K-12 I ..... 16 I (\:«,,1' ~~~\)Er ~UN 3 n 20n'l ~,_1)"II.J\ :.) ~"" ,ç.) ,~ _ ~ 1_,' ---.. ~'._.'- - - -.. ,'.~ - ;-. ~" ... ---- WJfH OEffERAlfZEO SfRATlGJlAF'K1C UNITS PRUDHOE BAY UNIT EASTERN OPERATING AREA STRUCTURAL CROSS SECTION A-A' -- ~--~- --1 ARCO Alaska, Inc. <> I Sub,idl.ry 01 AllanUcAlctlnekK:omøany I 1 MilE APPROX. 5: 1 VERT. EXAGG. ~. 1000 FEET - ---------------- .--~- . ,~ '1 _._~_.--- LOCATION MAP 5 MILES ~- ':-i.;:':~- 1 ; J - -12,000' f f f 5 - f . ----- r r -----rT --10,000' --8000' --6000' _ -4000' - -2000' SEA LEVEL þ-¢- ARCO Delta St. #2 35-11-16 A' E 3.6 MilES r f BASEMENT f f KAYAK I KEKIKTUK LISBURNE GROUP SAG RIVER I SHUBU\( , tv'SHAK I KAVIK I ECHOOKA KINGAK SHALE LCU CRETACEOUS SHALES UGNU I WEST SAK SANDS SAGAVANIRKTOK FM BASE OF PERMAFROST Þ-¢-c Þ*c 3.6 MILES ~.c 4.4 MILES ..... 4.2 MILES BP Sag Delta 31-11-16 ARCO Sag Rive, St. # 1 4-10-15 ARCO D.S. 6-1 2-10-14 ARCO Put Rive, #1 7-10-14 -12.000' _ -10,000' - -4000' - -2000' _ w ,., C-:J N C:J c:::J ~ G-~ :-¡=-' ......." :;Z fJj", ¡~ ~ I J:; ;Z z tQ -8000' -6000' SEA LEVEL I A it A' '( Figure G-3 W E r ARCO tCO Put River #1 St. #2 ( 7-10-14 1-16 , e· 4.4 MILES> I SEA LEVEL SEA LEVEL -- ( ( -2000' - - -2000' ( I' -4000' - - -4000' IÉ~'- [ -6000' - -6000' [ lOCATION MAP 5 MILES [ -8000' - -8000' L,/,r,,~ --- - - -'*-"'" .... ...-....,--- ..----~- --.......... ---"""""""--~ . K.I~GAK SHALE I SAG R\VER I SHU --------- A ___~~,:¿';'~,;., . r -10,000' - --10,000' 1000 FEET ... I APPROX. 5: 1 VERT. EXAGG. - - ï 1 MiLE I ARca Alaska, Inc. <> Subsidiary of AllanIlCRh::hfi.ldCompa~. -12,000' _ - -12,000' PRUDHOE BAY UNIT EASTE.RN OPERATING AREA STRUCTURAL CROSS SECTION A-A' I ",. ~ /' WITH GENERALIZED STRATIGRAPHIC UNITS I f ) 5 _"'011" J JO' If'.'" J S T ", '.u JUNi'ï" '.... 17 I ~ ~ ~ n ;."',~.) ~J ~.; Ji~1 , D 2004 I I I I I I ( I I [ ( :~ ( SECTION H Well Logs 20 AAC 25.402(c)(7) 20 AAC 25.252(c)(5) All openhole logs from EOA wells are sent to the Commission as the logs are completed. Attachment H-l is a type-log for the EOA with stratigraphic and marker horizons annotated, and representative salinity data. The Sag River State No.1 well, located in Section 4, TI0N, R15E, UM, was chosen as the type-log for the EOA because it is a centrally located deep test well that penetrated the total prospective stratigraphic column into "basement". It is evident from the well data studied that all of the major and minor reservoir horizons within the EOA have formation waters in excess of 10,000 ppm TDS. "- ( I I I I I I 18 SCA~\'~\jEC "JUN ,~ ~ ?O(U! I ~\ ( I SECTION I I Casing Infor ma tion I 20 AAC 25.402(c)(8) 20 AAC 25.252(c)(6) I I I I Typical injection wells are cased as shown in Figure I-I. Some few wells may vary from the casing shown in Figure 1-1. The actual casing program for each well is on file with the AOGCC in the completion record. API 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. ( :[ t I I I I I I 20 "ru~~ ~X Figure I-I I -TYP I CAL PBli WELLBORE SCLcMA TIC I I I I (NOT TO SCALE) '0' [J::():: =O=D -+- '5000 PSI WELLHEAD . GROUND LEVEL I~- -- - -- ......... ........ ~ I I I I I I I I I L I I JG 5/21/86 I L ~"-20-CONDUCTOR @ 80' -. L ~ ......- 13-3/8- SURFACE CS6 . @ 2500' TVD I NTERNALl Y TESTED TO 2000 PSI ~ 5-1/2" OR 4-1/2- TUBING WITH PACKER 40' ABOVE TOP OF LINER - ._. - - L .[:::s.'..... .9-5/8- PRODUCTION CSG .' @1 O' ABOVE SADLEROCHIT INTERNALLY TESTED TO ' . 3000 PSI L . ~.~ 7-PRODUCTION LINER ~150' BELOW BASE OF SADLEROCHIT OR OWC. INTERNALLY TESTED TO 3000 PSI 21 11;."'(' ~ í;~¡<Ù::'['" ~UN' .(f~ 2nr,VJ, . ft-,....~, Þ'fi'-':~~1 \~ M',HC \,....' \I.J I ( I ( I I' ( r l ,( I :1 I I I l I I I ( ( SECTION J Injection Fluid 20 AAC 25.402(c)(9) 20 AAC 25.252(c)(7) The injection fluid for the two types of injection at the EOA are: 1) water and gas for enhanced recovery, and 2) fluids brought to the surface and comingled with non- hazardous waste streams for disposal wells. Subsection 1 Enhanced Recovery A. Type of Fluid - Source Water. This fluid is treated seawater injected into the oil production zone for pressure maintenance. Small amounts of chemical used for water treatment at this time, or planned for future use, are coagulants, anti- foam products, scale inhibitors, biocides, and oxygen scavengers. Current, typical treatment volumes of these products are: coagulant: 0 to 1 ppm anti-foam: 0 to .35 gal. per 1000 barrels scale inhibitors: 0 to 4 ppm biocide: four shock treatments per month, 500 ppm over duration of 6.5 hours Oxygen scavenger: 0 to 2.5 lbs. per 1000 barrels These treatment amounts are subject to revision, based on operational needs and requirements. Analysis of Composition of Typical Fluid - See Attachment J-l Source of Fluid - Beaufort Sea Estimated Maximum Amount to be Injected Daily - 22 SC.^.N~\~EC! ,JUN j (~ 2004 [ I I I I l I I f I I ..., I I I I I \ it Ivishak - less than approximately 800,000 BWPD, decreasing as produced water injection increases. Lisburne - approximately 500,000 BWPD, decreasing as produced water injection increases (maximum of 20,000 BWPD during pilot water flood tes ting). Compatibility with Formation and Confining Zones - 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 oil and separated from the oil and gas at the Flow Stations and Lisburne Production Center. The produced water may contain trace amounts of scale inhibitors, corrosion inhibitors, emulsion breakers, and other products used in the production process. Analysis of Composition of Typical Fluid - See Attachment J-1 - Ivishak and see Attachment J-2 - Lisburne. Source of Fluid - producing formations Estimated Maximum Amount of be Injected Daily - Ivishak - increasing from currently 170,000 BWPD to approximately 655,000 BWPD by 1989. Lisburne - estimated 6,000 BWPD initially, increasing to approximately 500,000 BWPD (will be injected in PWDW at startup, see Subsection 2.A.). Compatibility with Formation and Confining Zones - fluid is returned to the reservoir from which it was produced; no compatibility problems anticipated. C. Type of Fluid - Natural Gas. This fluid consists of natural gas and natural gas liquids produced with the oil and reinjected into the same reservoir. Analysis of Composition of Typical Fluid - See Attachment J-1 Source of Fluid - producing formation 23 SCANNEr) JUN 3 0 2004 I i( ( ( I I I I I I I I ( Estimated Maximum Amount to be Injected Daily - Ivishak - currently approximately 2.6 billion standard cubic feet per day increasing to approximately 3.2 billion standard cubic feet per day. Lisburne - Estimated 100 million standard cubic feet per day at startup increasing to approximately 1 billion standard cubic feet per day. Compatibility with Formation and Confining Zones - fluid is returned to the reservoir from which it was produced; no compatibility problems anticipated. D. Type of Fluid - Miscible Injectant. This fluid is a mixture of produced natural gas that is enriched with natural gas liquids. Analysis of Composition of Typical Fluid - See Attachment J-l Source of Fluid - producing formation Estimated Maximum Amount to be Injected Daily - Ivishak - maximum of approximately 174 million standard cubic feet per day. Lisburne - no miscible injection anticipated at this time. Compatibility with Formation and Confining Zones - fluid is returned to the reservoir from which it was produced; no compatibility problems anticipated. I I I I I I Subsection 2 Fluid Disposal A. Type of Fluid - Produced Water Disposal. The injection fluid for disposal is near ly entirely produced water. Minor amounts of non-hazardous chemicals or waste associated with the production of oil and gas may occasionally be injected along with the produced water. 24 SC!\NNEni JUN 3 (~ 7004 I ( I I I I I I I B.. [ I, I [ I I I I I ( Analysis of Composition of Typical Fluid - See Attachment J-l, "Produced Water .." Source of Fluid - producing formation, small amounts of non-hazardous chemicals or waste from operations.. Estimated Maximum Amount to be Injected Daily - Produced Water Disposal Wells (Ivishak production) - facilities currently limited to approximately 75,000 BWPD, could be expanded to 655,000 BWPD or greater.. Produced Water Disposal Wells (Lisburne Production) - pump design currently limits disposal to 25,000 BWPD, piping is designed for 100,000 BWPD.. Type Source of Fluid - Non-hazardous Wastes.. The injection fluid includes numerous non-hazardous waste streams generated during the course of drilling and production operations, including non-unit wastes.. The injection stream includes drilling mud, reserve pit waters, contaminated crude, diesel gel, glycol, domestic wastewater, workover fluids and other non-hazardous waste streams.. Estimated Maximum Amount to be Injected Daily - 10,000 BFPD.. 25 Ç"(" ~ ~~~\uFr'! ]UN 3 ij 2GO,~· ~.j1\ ./!Ü""\ß\. Ö 3 ø···- " I I I I I I I ( Attachment J-1 ,", 1'1, Typical Fluid Analyses - Ivishak Produced Water (Ivishak): Total Dissolved Solids Sodium Calcium Magnesium Iron Barium Boron Silicon Potassium Strontium Chlor ide Biocar bona te Sulphate Car bona te Hydroxide Specific Gravity pH (in lab) Suspended Solids II I I ( I I ( I I I I I Source Water (Beaufort Sea): Specific Gravity @ 600F pH Biocar bona tes Calcium Magnesium Sodium and Potassium Sulfate Chlor ide Iron Bar iu m Total Dissolved Solids Carbon Dioxide Calc. Hydrogen Sulfide Suspended Solids Strontium Res. Ohms/m @ 700F Summer Sea Water 1.013 7.5 85 mg/1 196 mg/1 631 mg/1 5680 mg/1 1380 mg/1 9880 mg/1 o mg/1 o mg/1 17852 mg/1 - - mg/1 o mg/1 6. 0 mg/1 - - mg/1 0.422 26 21,100 mg/l 7,700 mg/1 190 mg/1 30 mg/1 15 mg/1 2.8 mg/1 130 mg/1 26 mg/1 90 mg/1 19 mg/1 10,700 mg/l 2,800 mg/l 70 mg/l o mg/1 o mg/1 1.014 6.8 2 Winter Sea Water 1.024 7.8 142 mg/l 365 mg/1 1190 mg/1 10400 mg/1 2490 mg/1 18200 mg/1 o mg/l o mg/l 32787 mg/l - - mg/l o mg/l 1 . 0 mg/l -- mg/1 0.255 .', U' n --ï-' ¡tiN C:) .!) 200A SC,A~~N!J::J) d j" ~,ß U - .... I I I I I I I Produced Gas: Nitrogen IIMethane Carbon Dioxide & Ethane Propane Iso-Butune N-Butane Iso-Pentane N-Pentane C6+ SP Gravity (calc.) SP Gravity (meas.) Miscible Gas Injectant: Nitrogen II Methane Carbon Dioxide & Ethane Propane Iso-Butane N-Butane Iso-Pentane N-Pentane C6+ I I ( [ I I I I I I I { FS3IP(l) .07 35.32 15.14 14.10 15.27 2.76 7.29 1.99 2.46 5.60 .31 74.32 12.45 6.56 3.35 .46 1.18 .26 .34 .77 .794 .785 ( MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL % ------ ------ PBMGP( 2) .01 23.50 21.60 24.03 28.43 1.22 1.19 .01 .01 Trace MOL % MOL% MOL% MOL% MOL % MOL % MOL% MOL% MOL % MOL % (1) Typical composition currently injected into Flow Station 3 Injection Project. (2) Projected solvent composition for Prudhoe Bay Miscible Gas Project. 27 SCANNEL; ~~UN ~i Q 2004 I ( :( Attachment J-2 I Typical Fluid Analyses - Lisburne Produced Gas: I I I I r I I I I I r I I I I I Nitrogen Methane Carbon Dioxide Ethane Propane Iso-Butane N-Butane Iso-Pentane N-Pentane C6+ Hydrogen Sulfide Produced Water (Well L 3-8): Ca tions Sodium (Calc) Sodium (AA) Calcium Magnesium Iron Barium Strontium 10555 mg/l 13875 mg/l 105 mg/l 50 mg/l 1 . 1 mg/l 1 . 1 mg/l 3. 8 mg/l .59 77.48 13.95 5.26 1.76 .21 .43 . 1 .12 .1 5 Total dissolved solids, mg/1 28573 pH 8.5 Anions Sulfa te Chlor ide Car bona te Bicarbonate Hydroxide MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL % MOL% MOL % PPM 750 mg/1 14261 mg/1 228 mg/1 2618 mg/1 Source Water (Beaufort Sea): Same as Ivishak source water. 28 SCANNEr." JUN ~ 0 200A" ( .~ I I I I I I I I I I I I I I I I I I SECTION K Injection Pressure 20 AAC 25.402(c)( 10) 20 AAC 25.252(c)(8) The estimated maximum and average injection pressures for enhanced recovery and fluid disposal wells are listed in the following table: Type Well Ivishak Water Injection Ivishak Miscible Gas Injection Ivishak Natural Gas Injection Lisburne Water Injection Lisburne Natural Gas Injection Produced Water Disposal Fluid Disposal Maximum Injection Pressure ( psig) 2700 4500 4000 3000 5000 2100 1400 Aver age Injection Pressure ( psig) 1000 2600 3700 2000 4500 1800 600 Note: In some cases, maximum pump discharge pressure is used to establish maximum injection pressure. 29 SCANNED ,JUN ~ (I 2.tJü4 I I I I I I I ( I ( ( ( ( ( ( I I I I ( ~ SECTION L Fracture Information 20 AAC 25.402(c)(ll) 20 AAC 25.252(c)(9) The proposed maximum injection pressures for the enhanced recovery and fluid disposal wells will not initiate fractures in the confining strata which might enable the injection or formation fluid to enter freshwater strata. Subsection 1 Enhanced Recovery Injection in the Ivishak Formation, above formation parting pressure, 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 Ivishak Formation is overlain by approximately 2000 feet of confining shales which act as an impermeable confining zone. Figure L-l shows an estimated fracture gradient curve used in the well plans for wells drilled in EOA. This curve has been verified through drilling experience and numerous leakoff tests. It should be noted that the curve is applicable only to clean sandstones and is the pressure required to initiate fractures. Pressures required to propagate fractures will exceed this pressure. Thick shale sequences tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. A leakoff test in the Kingak shale above the Ivishak and Sag River formations demonstrated leakoff at a gradient of .85 psi/ft. 30 SCl\NNE[) ,JUN 3 0 2004 I I f ( ( ( I I I I I ( I I I I I I I j '\ Recent studies (Perkins and Gonzales) indicate fracture gradients may be reduced in typical waterflooding situations due to reduced thermal stresses associated with the injection of colder water. Declining reservoir pressure can also reduce formation stresses, thereby reducing the fracture gradient. Given the present reservoir pressure and injected water temperatures, the fracture gradient ranges approximately between 0.52-0.63 psi/ft. in a typical water flood situation in the Ivishak Formation. This has been verified by numerous step rate tests, multi-rate analyses, and pressure falloff analyses on water injection wells in the Ivishak water floods. Injection profile logs, with emphasis on temperature logs, indicate that there is no vertical propagation of fractures within the Ivishak sandstone, much less propagation into the confining strata, at pressures exceeding the measured fracture gradient. Reference: Perkins, T. K. and Gonzales, J. A., "Changes in Earth Stresses Around a Wellbore caused by Radically Summetrical Pressure and Temperature Gradients," SPE 10080, 1981. Subsection 2 Fluid Disposal The injection zones for fluid disposal and all zones above and below the injection zones contain greater than 10,000 mg/l TDS and are not freshwater strata. Therefore injection at above parting pressure would not result in formation or injection fluid movement into freshwater strata. Recent studies of the fluid disposal wells at Pad 3 substantiate the lack of pressure buildup in the zone and lack of fluid movement outside the injection zone. The confining shales below the injection zone are in excess of 2000 feet vertical thickness. The upper confining zones consist of numerous interbedded confining shales and mudstones averaging 10 to 50 feet thick and over 1800 feet of permafrost. 31 SÇ!~NNEK) ~JUN 3 0 200f~ SCANNE[: (JUN 3 0 2004 32 ARca ALASK.A, I~,JC. PRESSURE PROFILES TYPICAL SADLEROCHIT 'NELL. EOA ~ . r 0.3 0.4 0.5 0.6 0.7 0.8 0.9 . GRADIENT (PSI/FT) (LBS/GAL) 1 1 I 8.0 9.0 1 0 .0 1 1.0 12.0 1~.0 14.0' t 5.0 16.0 17.0 , , I '. I '. I r ! t í i I I ; I ;': ; · . . . . r I . . . :PORE PRESSURE -..... MUD P.RESSURE ....:.............:.............L ..-. :GRADIENT "'t GRADIE.NT ~,~ ~ · · Y· . . . ... . . . . , , . , I . , . . , . · . . . . · . . I . · . . . . · . . I . · . . . I ..... ~ -. -...,... _...~ ......................................................~........ · . . f . I · , , . . . · . . . , , : : : : FRACTURE: : : : : : GRADIENT: : · . . . . . · . . .~ . · . . . . . · . .. . .....J..............~ .. ..........,.............1............. .........~._. · . . . . . I , . . . . · . . . · . . . · . . . · . : : · . · . · . . · . . · . . · . . ............\.............1.............1.... · . I · . · . · . · . · I · . · . . · . . · . . · . . · . . · . . . . I . .. ~.........,.............~.............~..... I . . I . I I . . . · . . . I I . . I . I . , I . · . . . I 'J . . . . · . I f I I . , . . , . . , . t , . . I · . . . . I . . , I --·····1··············p ............p.................................. · II . I . . · . . I I , . . . . : : : : : I · . . . I ; : i : ; · . I . . · . . . . · . . . . · , I . II · . . , . ......~..... Ir·····_·····_····_·····················_··--·····~··.--. I . . . , , . . II I I . , . , .'~. : : : : ~l : · . f , . , r f . I I . , . . I I . I I : 9.6 # /GAL: : : I .. J . ......~.__...~..................._.........._...4.......__....~...__. I . . I I · . . . . I . . I . · . I . . · . . . . : : : : : i - - 9~4 -/GAL i 9-5/8" @ ¡ : : : 8635TVD : . . .. . .'-. ... _I. . .. . . . ,.... . . . .. · . .. I. .. .. . . . . . . . .'-.. .Jtt. : : : 7" @ : '" : · : : 9220TVD : · , . .. . · I. .1 · .. . · ., , · I' . · . f . · .. . ......~..... ....... .~............. ~.,.......... .~~~.~ ...... · . . . . · · · I \ ¿ 9190' 9220' . 8535' : 8640' .7875' . 7150' TVD I · · I I I I I · · · · · . . . .. . ... . . . - . · · · I I · ........~...~. · · · · · · · · · I · · I ..'w.....,.... _. · . · . · . · . · . .. . .....~..............~ · · · · · I · · . · I · . · . · . · . .....~.__...........~ 9.2 #/GAL 13-3/8" @ 2500TVD Figure L-l ..t I ~: 10 SAG RIVER TOP SAD BASE SAD 9 TD 8 K-5 K-10 7 ...... Ii ~. 6 :I: f- a.. UJ C -J <[ u I- ~ UJ > ", . ... 5 ..... ---- ~ o o 4 o 3 2 o J,,4,f~1 S/': 1 }' I::r-I I ( I I I' I .-.. (:, I 0 0 ..... "'-'"' :r: I I- a.. LLJ 0 0 I LIJ ~ ::J (J1 <[ LLJ I: [ ! I I I I I I I I I I ( I I [ [ I I ~, { SECTION M Formation Fluid 20 AAC 25.402(c)(l2) 20 AAC 25.252(c)(l0) A typical water analysis for the Ivishak formation is included in Figure J-1. A typical water analysis for the Lisburne formation is included in Figure J-2. Two typical water analyses for the Colville Group from just west of the EOA, are included as Figures M-l and M-2. 33 SG!\NNE~) .JUN 3 0 2004 r ( r I' [ ( I [ I [ I [ [ ,~ ~ . ( I. ~.O. .OX,"'.. MONAHAN.. TUA. 78718 ~HONI ."'3'323'" Oil 583-10"'0 Figure M-l Martin Water Laboratories. Inc ( RESULT Oil' WATER ANAL VSES COMPANY Àt"bant"i t"-Ri rh fi p 1 n r:n1'l\P~1'\Y LEASE P'1"'nnhnp R"1 W;:¡tPrf1ood FIELD OR POOL SECTION_ BLOCK_ SURVEY· COUNTY STATE SOURCE OF SAMPLE AND DATE TAKEN: NO.1 Raw water-taken from Sohio water well #GC-3C @ 11:15 am. 11-4-78 (pressure cylinder) Raw water-taken.fram Sonio water well #GC-3C @ 10:20 am. 11-4-78 (plastic bottle) NO. 2 Equal mixture of Sohio water well #GC-3C taken 11-4-78& Sohio water well #GC-.3B NO. 3 taken 8-20-78 (pressure cylinders). NO. 4 REMARKS: Cretaceous CHEMICAL AND "HYSICAL ..ROPERTIU NO.1 NO.2 1.0l1;1.031.D TO: MT' _ .T _ P. MrOnn;:¡l d, ,TT'_ p_n_~ny ?R1Q, O~11~~, Tpy~~ SpeCific Gravity ac 6/J" F=. pH When Sampled pH When Recei ved Bicarbonate a. HCe)] Supersaturacion as CaCO] Undersacuracion .. CaCO] Total Hardness .. CaCO] Calcium a. Ca Malnesium as MI Sodium and/or Pota..ium Sulfate as SO.. Chloride as C I Iron as F=e Bari um as Ba Turbidity. Electric Color as Pt Total Solids. Calculated Temperature OF. Carbon Dioxide. Calculated Dissolved OxYlen. Winkler Hydrolen Sulfide ResistivitY. ohms/m at 77° F. Sus pended 01 I Filtrable Solids as mill Volume F=i Itered. ml Carbon Dioxide, Titrated *Total Carbon Dioxide. Gravimetric Strontium. as Sr LABORATORY NO. SAMPLE RECEIVED RESUL TS REPORTED 7.07 464 5 7.17 464 14 5,;QO 950 7;9 15.434 o 27t520 6.1 1 R? 1 6 4;,10Q 5.;00 990 71; 15..537 o 27..691 5.9 '17 4;,640 74 .; 7 0.0 0.171 0.0 0.173 o 5.0 520 44 993 53 19.1 910 53 Additional Determinations And Remarks Results Reported~ Mil1ilrams Per Liter Form No.3 By 34 731 W. INDIANA MIDLAND. nxM 7''101 PHON. ..a"..1 1178198 11-?1-78 1'-1)-7R NO.3 1.0229 NO.4 6.76 1..757 o .1. 700 690 480 11,844 24 19'.885 1 .1 78 14,7;~ 1)6' 0.0 0.226 11.9 488 " SCJ.\NNEr.:! JUN 3 (\) 200l:\. I r I I I I I I I I I I ( i, " Figure M-2 Marti n Water laboratories. Inc If ~, ~.O. BOX'... MONAHAN.. TO"'. 7875. ~HONK ..3·~a~. 0.. 583.10.0 RaUL T OP' WA TaR ANAL YSIU TO: !ofr. J. P. Mt"nonRl d.. .Tr. P.O.Rox 'Rl9.. nRl1~~.. Tpx~~ LABORATORY NO. SAMPLE RECEIVED RESUL TS REPORTED 731 W. INDIANA MIDLAND, TU.A8 7'701 ~HON. ,as.... I 117RlqR (P~iP 'J) 11-"-7R l'-11-7R COMPANY AtlRntit"-Rirhfipld r.n~R~ LEASE Pn,nhnp R~ WRtprflnnn FIELD OR POOL. SECTION _ BL.OCK_ SURVEY· COUNTY STATE SOURCE OF SAMPL.E ANO OATE TAKEN: NO.1 Raw wRter-tRkpn from ~ohio w~tPr wp1' /1C:r.-3n @ 5:50\>m.11-5-78 (Prpssn,.e t"v,1inder) Raw water-taken from Sohio water well #GC-3D @ 5:30pm. 11-5-78 (plastic bottle) NO. 2 Equal mixture of Sohio¡ater well #GC-3D taken 11-5-78 & Sohio water well #GC-~B NO. 3 taken 8-20-78 (pressure cylinders). NO. 4 REMARKS: CH.MICAL AND ~YSICAL PROPKRTIU NO.' NO.1 1.0291 1.0286 Specific Graviey ae 60- p~ pH'When S8mpled ' pH When Recei ved Bicarbonaee as HCO] Supersacuraclon a. CaC03 Under.acuraelon .. CaCO) Toeal Hardnes. a. CaC03 Calcium a. Ca Ma,nesium.. Me Sodium and/or Poea..lum Sulfaee a. SO.. Chloride.. C I Iron .. Fe Barium .s Ba Turbidley. Electric Color as Pc Total Solid., Calculated Temperature of. Carbon Dioxide, Calculated Dissolved OxYlen, Winkler Hydrocen Sulfide Resistivity, ohms/m at 77" F. Suspended 011 Filtrable Solids a. mell Volume Fi leerad. ml Carbon Dioxide. Titrated *Total Carbon Dioxide. Gravimetric Strontium, as Sr 7.16 195 12 7.02 176 8 6.600 1..'5'0 6A.Q 1~..99~ o '6,'77 9.3 252 4 8 41,970 6,600 1,600 617 11,9711 o 76,777 9..' 245 47,HI1I1 25 34 0.0 0.185 o 4.3 490 35 1.039 73 0.0 0.186 25.8 910 73 ) NO.3 1 .O'.1.~ NO.4 6.714- , .. 6111 HO 1,QOO ',OOQ ~/,O 1',~70 7~ 1 Q ; t; ~o ?0.7 97 14 ,OQO. 523 0.0 0.229 . 18.1 465 Re.ults Reportad'~s Mlllilrams Per L.iter Additional Determination. And Remarks * This includes both free carbon dioxide an9, the car~9n dioxide that is tied UÐ as bicarbonate. T.p..tt'Pf nf r'::'r.nmmpnn~t'i on .::ttt¡¡t"hpd.. Form No. 3 -- I /:..-,. ~/ < ",,;~.~ By / ~)~_.,~-... .4'" ., ''--.......~_.- ) ,..ø:" .-,' ,.....'<: - ", Waylan C. Martin, M. A. 35 .sr··J~N,· ~~[;r) j¡JN ~.~ !P 200·~ ...s.;,.I;" I~, <1:', ,g " i.~i._ 'I~.~, '¡",t .\\,g .... . r_( I I f I ( I I ( I ( 11 SECTION N Aquifer Exemption 20 AAC 25.402(c)( 13) 20 AAC 25.252(c)(1l) ( ( I I I I I I I Estimates of formation water salinity values have been made across the EOA and no USDW (less than 10,000 mg/l TOS) were found. By utilizing well log data, an approximation of the formation water salinity can be made using resistivity and porosity well logs. Standard industry log evaluation equations, including the Archie equation for unconsolidated sandstones, were used to determine the salinity values (Figure N-l). Calculated salinities correlate well with the results from laboratory water analysis from the Upper Ugnu water supply well 113 in the Kuparuk River Unit. The good relationship between the laboratory measured salinities and the log based equations permit salinity calculations at many more data points than are available from actual laboratory measured salinity. Although the log calculated and laboratory salinity values do not match exactly, the log calculated salinity values are generally representative of the actual formation water salinity. Formation water salinity values were calculated using "clean" sandstones for six stratigraphic intervals from six wells across the EOA (Figure N-2). No salinity values less than 10,000 ppm were computed for any of the intervals. In wells 7-10-14, 14-5 and 6-4, the T -3 interval is believed to contain minor amounts of hydrocarbons which raise the measured formation resistivity and lower the calculated salinity. Thus, the presence of hydrocarbons invalidates the formation water salinity calculations in these intervals. The salinity values for each horizon were averaged and placed on the Sag River State type log for reference (Figure H-l). Based on the Alaska Test Lab core analysis of the B. P. Permafrost Test well 12-10-14, no USDW is present at the base of the permafrost (1858'). Laboratory analysis of formation water in the porous and permeable sandstones and gravels at the base of the permafrost indicate that intervals capable of flowing formation water contain salinity values in excess of 10,000 mg/l TDS. The TDS concentration is greater than 10,000 mg/l at 1823' (Appendix G, Sheet 61 of 67; Alaska Test Labs Report). The 36 SC/\NNE[i' JUN 3 0 2.0D~- I I I I ( ( I ( ( I ( ( ( ( ( I I I I ;t equation used to convert millequivalents of sodium chloride (last column of sheet 61) to milligrams is as follows: mg/l = (meq/l) 1 mmol 58.5 mg 1 meq 1 mmol = (220) (1) (58.5) = 12,870 mg/l NaCl. 37 SCAN~~E[;' ,JUN €~ 0 200~· I I I I I I I I I ( I I I ( I I I I I 4 , Figure N-l Documentation of Equations Used to Calculate Formation Water Salinities From Well Logs 1. Formation Temperature: Tfm = 0.0222 (Depth fm - Depth base of permafrost) +320 F 2. Porosity from Density Log: Ød = Dma - Db; Dma = 2.65, Df = 1.0 Dma - Of 3. Porosity from Sonic Log: Øs = 0.625 (dt - 55) dt 4. Apparent Formation Water Resistivity: Rwa = ø 2.15 x Rt 0.62 5. Water Resistivity @ 750F: 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) 3) Determine porosity from either the sonic or density logs. 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 750F. (Schlumberger equation) 5) Calculate TOS in ppm. (Dresser Atlas equation) 38 SCANNE~'::\; ~JUN 3 0 200¿~ I Il I Figure N-2 I Prudhoe Bay, EO A, Calculated Wire line Salinities (See Also Figure H-1) I Interval Well Subsea Depth Calculated TDS (ppm) T-8 7-10-14 (-2666) 22,985 I 14-5 (-2827) 24,419 6-4 (-2885) 31,240 7-6 (-2966) 35,708 1-6 (-3053) 32,220 I 9-6 (-3286) 44,651 T-5 7-10-14 (-3011) 14,784 I 14-5 (-3162) 13,353 6-4 (-3295) 12,503 7-6 (-3306) 14,208 1-6 (-3468) 17,816 I 9-6 (-3706) 22,222 T-3 7-10-14 (-3616) Hydrocarbons I 14-5 (-3757) Hydrocarbons 6-4 (-3897) Hydrocarbons 7-6 (-3916) 11,829 I 1-6 (-4083) 16,620 9-6 (-4316) 40,086 U. U gnu 7-10-14 (-5271) 36,509 I 14-5 (-5353) 57,059 6-4 (-5500) 55,621 7-6 (-5474) 43,890 I 1-6 (-5728) 40,865 9-6 (-5991) 48,844 I L. U gnu 7-10-14 (-5461) 31,453 14-5 (-5602) 44,105 6-4 (-5710) 31,514 7-6 (-5651) 42,320 I 1-6 (-5878) 38,054 9-6 (-6426) 46,332 I W. Sak 7-10-14 (-5898) 15,878 14-5 (-6042) 27,427 6-4 (-6090) 20,194 I 7-6 (-5957) 29,790 1-6 (-6058) 47,834 9-6 (-6806) 34,632 I I 39 I SCAN~\MEt,) ,JUN 3 0 2004 I I I I I ( ( I I I ( ( ( ( ( ( I I I ( l SECTION 0 Hydrocarbon Recovery 20 AAC 25.402(c)(l4) As stated in the "Application for Additional Recovery," December, 1980, fieldwide oil recovery from the Ivishak Reservoir is expected to be increased by 6 to 9% of original oil-in-place as a result of the water flood project. Recovery in the Flow Station Three Injection Project Area is expected to be increased by 5.5% of original oil-in-place above that attainable with waterflooding as a result of miscible injection (reference: application dated August, 1982). Recovery in the Prudhoe Bay Miscible Gas Project area is expected to be increased by 5.2% of original oil-in-place above that attainable with waterflooding as a result of miscible injection (reference: application dated December, 1983). Total expected hydrocarbon recovery from the Lisburne formation is 200-600 MMBO, or 7-20% of currently estimated oil originally in place. Water flood is expected to contribute up to 400 MMBO of the total. 40 SCANNE[) JUN 3 {1 2004 I I I I I I I I I I I I I I I I. I I I ( SECTION P Mechanical Integrity 20 AAC 25.402(d) 20 AAC 25.252(d) In newly drilled EOA wells, the casing is pressure tested in accordance with 20 AAC 25.030(g). If converted to injection, the casing is again pressure tested in accordance with 20 AAC 25.l¡.12(c). The casing pressure is then monitored on a frequent basis and recorded by the drill site operator. 41 S'(' 1\ N" ~~uEIr"': JUN ~~ (¡'~ 2004 '\.. \'#3(JIi"'~,' n".1 .....l~.:) , ~J t - I I I I I I I I I I I I I I I I I I I ( SECTION Q Wells Within Area 20 AAC 25.402(h) 20 AAC 25.252(h) The wells within the area of review (i.e., EOA) are shown on the plat (Figure B-l). To the best of ARCO Alaska, Inc.'s knowledge, the wells within the area were constructed, and where applicable, abandoned to prevent the movement of fluids into freshwater sources. 42 SCAN~\!ED JUN 3 0 200T~ J ( ARca Alaska, Inc Prudhoe S, "gmeenng Post Office Box 1 00360 Anchorage, Alaska 99510-0360 Telephone 907 263 4248 ( ~~ ~~ SECTION R I Donald F. Scheve Operations Engineering Manager March 27, 1986 I Mr. Chat Chatterton Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 I I Re: Prudhoe Bay Unit, Eastern Operating Area r Dear Mr. Chatterton: I ARCO Alaska, Inc. has reviewed the recently adopted regulations governing the control of underground injection related to the recovery and production of oil and natural gas. Two variances to thesp. regu- lations are requested with regard to operations in the Eastern Operat- ing Area of the Prudhoe Bay Field. Paragraph 20 AAC 25.450(a) allows the Commission to authorize less stringent requirements if: (1) injection does not occur into, through, or above a freshwater source, and (2) the reduction in requirements will not result in an increased risk of movement of fluids into a freshwater source. No underground sources of drinking water are currently present in the Eastern Operat- ing Area, and thus less stringent requirements may be authorized at the discretion of the Commission. I I I Varianee Number 1: ( Relief is requested from the reporting requirements of Paragraph 20 AAC 25.432 wherein monthly reporting of casing and tubing pressures may be required for injection wells. This information is not included in our automated data reporting system because it has not previously bep.n required by the Commission. Reporting of casing pressure for injection wells has not been required by the EPA, and time consuming manual reports that include tubing pressures have been prepared for the EPA for only a portion of the injection wells. Submittal of these pressures on a monthly basis would require either extensive reworking of our automated reporting system or extensive manual compilation. The expense associated with monthly submittal of this additional information does not appear warranted. In the event periodic pressure monitoring in the field shows non-compliance with any regulation, the Commission will be notified and corrective action taken. I ( I I Variance Number 2: I Paragraphs 20 AAC 25.252 (e) and 20 AAC 25.402 (e) require immediate notification of the Commission, and Commission-approved corrective action taken if the casing-tubing annulus pressure subjects the casing to a hoop stress that exceeds 70 percent of the minimum yield strength 43 ARC a Aldska, Inc. is ¡¡ Subsidiary of AtlantícRlchlìeldCompanv SCP~NNED JUN 3 0 2GDP} , I Mr. Chat Cha~~~rton March 27, 19f Page 2 . ,t" I of the casing, or if there is more than a 200 psi change in the pressure between consecutive pressure readings. ARCO Alaska, Inc. requests relief from the 200 psi change requirement, and requests that the 70 percent limit alone be used as the sole criteria for immediate notification of the Commission. I Changes in casing pressure of 200 psi or more occur .frequently in response to changes in injection pressure and temperature. This being the case, using a pressure change of 200 psi or more between consecu- tive readings is not a viable means of identifying tubing leaks at Prudhoe Bay. In any case, periodic monitoring of casing pressures and pressure trends will continue in order to assess the condition of each injection well's tubing string and packer. I r The Oil and Gas Conservation Commission's consideration of these requested variances is respectfully requested. I Very truly yours, I j In r¿¡¡J j.,g~. Donald F. Scheve I JLG/ab/64 cc: J. W. Hart R. Iden I I I Drrr~I'\¡ffÇ\) r'. JUN 0 5 1986 I I 'AlasKa u¡¡ ~, A,~1ct·ior:.lQB uv ~,i' ~!~ ~~'~~Jion I I [ SCÞ\NNEC JUN 3 0 2004 44 CONFIDENTIAL INFOR~ATION ) ) r ) 'ì) .f Petition To Form the DAAFT '4 Lisburne Participating Area Within the Prudhoe Bay Unit An economically viable hydrocarbon accumulation within the Prudhoe Bay Unit has been discovered and delineated in a Pennsylvanian/ Mississippian aged limestone/dolomite reservoir within the Lisburne group (Exhibit 1), which is separate and distinct from the Sadlerochit sandstone/ conglomerate group of Permo-Triassic age. The undersigned owners are in the process of developing the Lisburne reservoir and want to establish a Lisburne Participating Area (LPA) pursuant to Article 5.3 of the Prudhoe Bay Unit Agreement (PBUA), and Article 21 of the Prudhoe Bay Unit Operating Agreement (PBUOA). ARCO Alaska, Inc. will be the Operator for the LPA in both the Eastern and Western Operating Areas for Lisburne Operations. Commencement of sustained commercial production is targeted for late 1986. Approximately 30 wells will be available for production and injection purposes at three of the six planned drill sites and the Lisburne Gas Injection Pad (LGI). Electric logs, core analyses, and production test data from the wells shown on Exhibit 2 have been used to determine reservoir liquids saturation and fluid contacts. These determinations were based on well tests, such as those tabulated on Exhibit 3. Develop- ment plans are based on a reservoir containing some 3 billion barrels of oil and 500 billion cubic feet of gas cap gas with a gas/oil contact at approximately -8,600' subsea and a producing water/oil contact at approximately -9,150' subsea. The primary recovery mechanisms of this tight, naturally fractured reservoir are solution gas and gas cap expansion, with possibly some gravit)~ drainage but little or no aquifer support. Well stim~lation, primarily acidizing and fracturing, have greatly improved production test rates. Initially, all produced gas in excess of fuel require- ments will be injected into the reservoir. Further testing and analyses are necessary to determine if some other~!o~~f pressure t· ,.. -- ! } support is justifiable. . ,. - - - ~ ~., ',",., ,'~~"I':¿I\P:::' C ¡.: q ¡ N ~J 0 20ß;j· .' "~.:<,., '\\: ',' .I,I·,·........,lH,c····· . ,r. :. - ~:: ~;.~::3I:! 7" \ 1 ) DÞA~., .~,,'.-. 4 In keeping with our other North Slope operations, a minimum number of work pads and interconnecting roads have been, or will be, constructed for the Lisburne operations. A Facilities Sharing Agreement with the Prudhoe Bay Unit Initial Participating Areas (IPAs) minimizes the surface utilization for the development of this oil reservoir. All facilities for the first increment of develop- ment (Exhibit 4), have been or are being placed following the 1986 sealift J except Drill Site L4 flowlines, the gravel island Drill Site L6, and its connecting causeway. Wells will be drilled from drill sites with three phase production shipped to the Lisburne Production Center (LPC) for treatment prior to delivery to TAPS. Produced water will be injected, and gas will be used as fuel, sold, or injected. The LPC will have a nominal design capacity of 100,000 STB/D oil, 10,000 STB/D water, and 400-600 MMSCF/D gas. Hydrogen sulfide detection equipment, safety flares, and a complete fire fighting system, including both halon and water deluge insure compliance with both regulatory and industry standards to protect personnel, the environment, and equipment. The tracts to be included in the LPA all lie within the Prudhoe Bay Unit boundaries. In accordance with Section 2.5 of the PBUA, Exhibits C-1 and D-3 are submitted herewith. Exhibit C-1 describes the LPA and tract participation, and Exhibit D-3 depicts the boundary lines of the LPA. The proposed Lisburne Plan of Develop- ment and Operations (which will become Exhibit E-2 to the PBUA when the LPA is formed) is being submitted separately as Exhibit 45-D to the Lisburne Special, Supplemental Provisions (Lisburne Provisions). These provisions will be supplemental to, and in accordance with, the General Provisions of the PBUOA and apply only to the LPA. The Lisburne Provisions will be submitted before the commencement of sustained commercial production from the LPA. ,......" - ¡" '- ì \ L : ~ ~.' . .- --... - ~.' .. , C ø· :. .....'.:... f . _ _ . 1-..- _ " ~- -,,-., ... ~ . ....., -' ~.' - ... ~........ ,. '... scltÜ~~\SEU ,j 1\ ":;1 ;j '?U ['/). .. ') TRACT OWNERS WITHIN THE LISBURNE PARTICIPATING AREA ARCO Alaska, Inc. By: Exxon Corporation By: Standard Alaska Production Company By: Date: Date: Date: :. :-... I' ) DRAFT \: ~ .~ : ~ ~, : ~ n . :.-......... ;.. _: ~ 2 S 2 S B S ..,__t'': .........-......~ I -.,......_ .....'... ..1 ~......, ~ ~._ . -...... -- - JUN J G 2Un~· ,al"~ -,aft .. QUA~ 1'IR1'IMY ..... CMTACIOUI LØWIJI ~~-- Low. CMTACIOUI .IUMIIIC TIU8III: . ---- - ~ -........ -~n " -".. . ~'I"'" ........ .... ~ tn. N."I .,..._~"IC UMT .. .'......,... I' .. .. .. ". . .. ~::: '~'. .,.. .. ~. .' . J ...... \ 100:. ,. " ' ~··\..·'l: .... "e.':!... :~~~~~:"'-~-~' t{ rfi.·...~:1:. ,... .\Ç. ~ ~~. .~~ '11:..-.--.....---- ~,~~:~_t :;;~~f~- c;¡;;,;.¿.._.... ~.-...~----- ,. ....J:ii! u :.Y\ ~ ex. .... tc '~~~r;--~--:-..-:-~ WØT 1M IAIØ IC 7'NII1 ~.. i- .;. - ~. ~.... tc ,.., ;i-=-~-:_j UMWU INALlte ZII1 ~"J!="¡:~-: Nt MYP IMOIfONI 100"" .·---__~~tl IQIItAIUUWIJt......., ,- l' -...... -~~ v-=-:::-=-~-~ ICJIIQM IMALI ~_-_-_-_-. .'.., ~=======-:= 1M M'IIR ....te ., t=====:==;: ..........te.., ~==:::::.:':'~ - N...., UGAV~ No ....,.., ~,:----' 'VIr'. .:C., MOW ....., :~,~~ ,,,.1 .':" ., ". , '. . t· I . \ . <> . a r. . .. ~. ~\) ~ t -. < -.~ . ~ , ..." . , . - 1~;.):.-' ~.-!Þ~;! ~ ~ LaaIMI MOW ....., IUGCG,. CIROW t-.IIOW\ ~...--. ) Lot Olno1lrtt u.IIurM IftterqI ~ aey ..... ., I 1 . II. I OR o APt ]~~ t S~ I . 't- J ~ --..-.,--' . Z -' -:..;..s c ~ L-:- ; I 11 ë! I I I ! ¡ I I ¡,~; I-r=' L ~..- Dk ¡~ '¡I~ '..-' c: -- r - ~ . > ~ L ~- ~ .. ~ Exhibit 1 II.D. 10C ft. 2.0 . 11'10 110O UIO 110O i 11IO I 1000 101O '100 .110 ' t200 ' ntO ' 1:10O t:IIO ... MIO · 110O tØO 110O tIIO t100 1710 MOO tIIO tIOO · tHO i 1 DOOO 10050 I '0100 . '0150 ,10200 102S0 , 10300 , '0350 , , '0.00 (::, I I , I i , ¡ I ! I I ...... .IL -- . i , t I I I ! ¡ I I ¡ I i ! i , , ! I I ! I I , I ¡ , . \.. þ~ DRAFT ,-o(.N4C)8 OramstCC 3.0 ¡ I ; r--- I i , -:1. ~ ~.. '~ ~ .... L- ~ .;I: I . ! I I , I I I ! t ..,-' r- -- .. > .. . ¡ ! $ .Q . ~ ~: ~ ...... ~ -,.r W!"- ~ I "? "'C' ~ -> --- -...- -=<.: : I --- F' ~ ~ ~ -, c ",':::'~' 4..,; \,; .. ... ..~... ....... , .- "'. ,...... '"'.... ,.... ,. -...--'" f~~(t.~þlr,,\1~~~ltT·) JUN 3 ~ 20Dt~ . .. C' . - - I B£'4UF'ORT SCA -+ ...", '" t- ot ~ ...... '\ + Lot '0 " e ' wu~ Sf.,. + ... el(. e _ ~ · Q 12 LO! a tID.OLl.L ...ST..... L~ l' 14 DS-L8 OS f . ~i' L.'O PRUOHOE" BAY ~. + l1 2 t.RAY ST." ... - ... LI · · l2 30 U 28._ 'p e l t l2 J.1.. . . U 5. I) PRUDK)[ lAY $T." 1 .. l2 28 I 2 1. . l2 ~3 11 ~ 2 2t POINT_ '" "~9OVn- 8AYDS~4 " sr.,,- -. l' + .. 2 u"'. DS-L3 + U 13 l2 . . l>_~ -' . - - . ' . . L' " + + + + - , h + ~ 31 ... + ... 3e "1 -I . + ... 38 \ & ~ ; SAC. DO. fA IT L¡,. ~ "",,,."-fA'] ~ <--~- + + . / _._4>~ _ W,ðUoa< 5'.'2 ... - . TlRN MlL It. I -'1 II 3' . . ... + It . . . + + + + DELTA i," '''"f\ é) ~¡;.~ rl';~ i::=r'¡.-- ~ ~ IF'0- t ~ 'I ~-.- ~ ~ . , , J ~ ,":t .. - ... " 1 + ,,',. ...a .... \ ',I + + ..\. ... ~q. ~ ...0 " + ... + + ... ...\1 ~' ... 4- _ ~\..v ~ .......a riG + + + + + + ~ ..." .. f + ...a "- ... + .. ... 0 ~ II '~~- . --I... ... ... + . - . - + + + R17 ... 604285010 : .;;, - I r,.) : .... C~ + + + + + ... ... ~"t - . J ~wEi.d;: :6ÈUNEATING . L:,SBURNE FIELD EXHIBIT 2 31 31 ". . " 1- , ~ ... + + + ... - , . , ) EXHIBIT 3 ) DRAFT WELL TESTS INDICATING FLUID CONTACTS Cas-Oil Contact Approximately -8600' 55 Well Cull Island No. 2 West Bay St. No. 1 West Beach St. No. 2 Test Interval (SS) Results ConInents -8538' to 7.7 "'SCF/D rate Cas as low as -8585' 55 -8585' -8638' to 3080 85TO/D rate Oil as high as -8638' 55 -8721' -8506' to 10.4 HHSCF/D Cas as low as -8585' 55 -8585' -8643' to 3300 85TO/D rate Oil as high as -8643' 55 -8691' -8376' to 16.1 MMSCF/D rate Cas as low as -8479' 55 -8479' -8528' to 3.3 "'SCF/D + ECOC between -8528' and -8632' 55 -8632 ' 320 85TO/D Producing Water-Oil Contact Approximately -9150' 55 Test Interval Well (55) Resul ts Pingut St. No. -9074' to 448 BTF, 85\ oi 1 -9170' -9218' to 166 BTF, -9300' essentially all water South Bay St. No. 1 -9026' to 120 BSTO/D rate -9090' -9181' to 147 BTF, oil cut -9210' varied 40 - 70\ South Point No. 1 -9066' to 700 BSTO/O and -9146' 260 BSTW/O West Beach St. No. 2 -9158' to 750 BSTW/O rate -9285' Conments EWOC between -9170' and -9074' 55 Water as high as -9218' 55 Oil as low as -9090' 55 EWOC near -9181' 55 EWOC near -9150' 55 Water as high as -9158' 55 . . - ~ .- -..-" ~ ~~- ..... .~Sf:A~\W~~E7"':-- ,JlJN ~~ 0 ?OOI1 ---7~--~' K-PAD ---~--, I t -,,~---~~- -- V"""" "...oõ¡~~""-.......""""'_c"..,..-.--~ cr:, """". / ~¡JI- ~ .......~. "'iif!i'j::. ..,._...., t : . "';';" :::~: ~ . . NGIJ:-. /. . ../ WGJ '" l":.R ,1,.. ) .~~.' f..: ð~O..d Ie'and ~ ~- - - ~-"':--"'----' , PRUDHOE BAY ~. yt y (~ ~I 'I J -- .-~. EAST DOCk ~ ~, -' -- -- '--- I -- -- .....- /" .~~ ':~;: ...- - . . :;. z , I: D '==' $ ~ :::: J .) :J :;) tJ -/ ;" ,,/ ,,/ ./ / LISBURNE SITE DEVELOPMENT PLAN SCALE: ,- = , MILE ) ) DRAFl Lisburne ADL Working Tract Tract No. of Serial Basic Lessee O.R.R. Interest Participatior, ..!2:... Description Acres No. Royalty of Record Interest Ownership \ 66 T11N-R16E,Secs.17,18,19 1,MO 28339 1/8 SAPC * SAPC-100\ 3.155 66A T11N-R16E,Sec.20 MO 28339 1/8 SAPC * SAPC-100\ 1 .083 67 T11N-R16E,Secs.15,16 1,280 28340 1/8 SAPC * SAPC-100\ .030 67A T11N-R16E,Sec.21 6It0 283,.0 1/8 SA PC .. SAPC-100\ .200 69 T11N-R16E,Secs.30,31,32 1,851 283,.3 1/8 SA PC .. SAPC-100\ 2.~ 13 69A T11N-R16E,Sec.29 640 28343 1/8 SAPC * SAPC-100\ 1.116 70 T11N-R15E,Secs.25,26,35,36 2,560 28324 1/8 ARCO&Exxon ARCO-50\ 4.325 Exxon-50\ 71 T11N-R15E,Secs.27,28,33,34 2,560 28325 1/8 ARCO&Exxon 'ARCO-50\ 3.718 Exxon-50\ 72 T11N-R15E,Secs.29,30,31,32 2,"91 28326 1/8 ARCO&Exxon ARCO-50\ 1 .975 Exxon-50\ 73 T11N-R14E,Secs.25,26,35,36 2,560 28308 1/8 ARCO& Exx on ARCO-50\ .246 Exxon-50\ 74 T11N-R14E,Secs.27,28,33,34 2,560 28309 1/8 SAPC * SAPC-100\ .089 91 T1 ON-R15E, Sec. 5 640 28329 1/8 ARCO&Exxon ARCO-50\ .019 Exxon-50\ 92 T10-N-R15E,Secs.3,4 1,280 28328 1/8 ARCO&Exxon ARCO-50\ .026 Exxon-50\ 93 T10N-R1SE,Secs.1,2 1,280 28327 1/8 ARCO&Exxon ARCO-SO\ .CltO Exxon-SO\ 94 T10N-R16E.Secs.S,6 1,249 2834S 1/8 ARCO&Exxon ARCO-SO\ .117 Exxon-50\ 9S T10N-R16E,Sec.4 640 28344 1/8 ARCO&Exxon ARCO-SO\ .025 Exxon-SO\ 114 T11N-R16E,Secs.28,33 1,280 28342 1/8 SAPC * SAPC-100\ ~ 83,187 100.000 * BP Alaska, Inc. owns an overriding royalty interest equal to 7S\ of all net profits from production between certain levels of oil production. All tracts are within the Umiat He~idian - - -,--,..:-'"'-\ , ... '-- .... , - _ C .. ". ' . ......... ,-" l.,¡:"~..:__ . ... -- --- . -". -- '\-.-.......-........ r. ... . _....... ~ n W~ a:¡¡ f1¡ €)n ftQ LISBURNE r APRAERTAICIP -ATING PRU-'HOE BAY UNIT " . . , , 7. , S, ~ .5, , 4, ,. , , . . , . , " "", - , _, , I , , $APC ARC()- :~~N" ' ~~~~~~Ñ" ';c:P~ &i~' ~,' -,.fl~~~~;;'t,\~c;,~~X;~N ' · .' ' .' .(~~~ · .' ' .. .. · .'S¿;é.' · .. ' ' '.'~¿ . ~ ",' ',', #, ',' ',', ~, ' ~ " #, I, '4 , #, " " "'\, 25. ", , 2b'. " "1.1 " '. '28, ., , 29 " ',36, " " 31, " , 32 ' . 33, ,. , " , ,. · ,. , .' , " , . ' , ,. , ,. , " , ,,' , " , " , " , " , , <. · ,. . ,,' '0.' , " , " · " .. ,.' , " . " . .' , " . " , " , .;. 11 .' . ,. , " , " , " , .' . .'. "~,..,, ~ " - · .. , .' I' I.' , :. , .' " '.". ,,~I"'" -. '." '. '" ',",', · '. - . ,. .~' ,,' , . ~. · , . , . , , , " , (' , , , , " ,.. '~ ·,~é"·AAq;~É.XX~~· ~éa':~XXo'~"AA~':EX~O~ '~éo~~~xó~ 'AR~O~X~~',·"· '''t{C, ',','sÁPé;", ',',' , ',"'/b " . " , " , " , .' , " , , ' , ,', ",",",",",', '.", .", ,'",' ~C · ..... ' " , 4~' , ,. , .. 2 ' " , .' '41' . ,. , ,'..0,', ",39,,' , , 38,' , " , , 37 " , .38 · , , , , , , , , , , . " """ " " ".",",",",', ., ,",",",",' ,",",". ','. ".' " I, " , " ,'1#"" P' I... ' r '.. I'.. " " " , ~ . .. - I " ( . , MOO-EXXON MOO EXXOt-. SAPC ~C 76 75 II I. . I (f:: M4r~~HESS ARCO-EXXON ~;; Z ¿,: VI ~ / C-. c: z 87 88 · , ARCO-EXXOt-. SHELL ET AI.. 10-4 103 ~:;;J~ ;~ ~" C) C:~ ~ .. II I I SAPC 89 MOBIL - PtflLlIPS 0.. ~ '\: ~ .. ~ 102 ...~ ~ ARCO-EXXON 106 ~ "" ARCO-EXXO~ ARCO-EXXON SAPC ~ I I SAPC ":£~ON ·.ARCo:-EXx~N .~eo ·-EXX~ 90 91 93 94 95 SAPC $APC 101 100 ARoo- E XX()t., fØ ~ MOO-EXXON MOO-EXXON 98 q.. 'Iþ 98 97 + ,0 ~ EXIIIBIT D-3 BOUNDARIES OF USß1JRNE PARTICIPATING AREA 99 CH[V 107 CHEV ~d CH-MO-PH ~g7ÁJ-41~08 C ~":~PH 109 ~ : PRl DHOE BAY o . ~I .. nIt to.ooo . $APC SAPC 110 111 . at. f UNIT · · rr' ,O~ eOO2ßAoOt H t" .1 ¡ RECFJVFD !\ I ¡~ 2 19 P.d,--: 9 86 :ka OJ¡ 6: \.:¡.;.~ c:::~ AnCh::ìí2.;S ARCO AIeIka, Inc. J ,.. Office ~.. .00380 Anchorage, A"" 11510-0380 Telephone 107 26S 8513 ) ~.~ ~"'L ~ ~ H. P. Foat..., Jr. Senior VIce Prestdenl August 26, 1986 Ms. Esther Wunnicke Commissioner . Natural Resources Department State of Alaska P.O. Box M Juneau, Alaska 99811 DRAFT Re: Petition to Form a Lisburne Participating Þ.rea -'" Within the Prudhoe Bay Unit Dear Ms. Wunnicke: Pursuant to the provisions of Article 5.3 of the Prudhoe Bay Unit Agreement ("PBUA") and 11 AAC 83.351, to the extent it does not conflict with the PBUA, ARCO Alaska, Inc., Exxon Corporation and Standard Alaska Production Company (collectively referred to as the "lisburne Owners") hereby petition the Commissioner to approve the formation of the Lisburne Participating Area within the Prudhoe Bay Unit with ARCO Alaska, Inc. as operator. The lisburne Participating Area and supporting documen- tation are more specifically described in the enclosed Petition and Exhibits. In compliance with the criteria set forth in Article 5.3 of the PBUA, the proposed Lisburne Participating Area has been reasonably proven to be capable of sustained commercial production of Unitized Substances in sufficient quantities to justify the L~sburne Owners developing and producing the Lisburne Reservoir. The proposed division of interest for purposes of sharing production a·nd costs is set forth in Exhibit C-l. In summary, the sharing of productior and costs results in ARCO Alaska, Inc. and Exxon Corporation each having a 40% share and Standard Alaska Production Company hëving a 20% share. This proposed sharing is fixed for the term of the lisburne Participating Area within the initial area. ", _,', I ;::3Slon The provisions for establishing a new Participati~g A~ea within the Prudhoe Bay Urit arE c~ntained 1n Article 21 of the Prudhoe Bay Unit Operating Agreement ("PBUOAII). As required by the PBUOA, the Lisburne Owners are negotiating Special, Supple~ental Provision~ AP~C' Alaaka. Inc. il a Subaidlary o' A:.antlcPichfieldCv..,.,.ny \ ~-1i ,¡r ¡\~ '-··~f ,,~,.~QA.\~· t,:'1 (... e \i ,~: ~j £:lJl~~~i~ ) ') Ms. Esther Wunnicke August 26. 1986 Page 2 DRAFT to the PBUOA for the Lisburne Participating Area. As required by 11 AAC 83.366. the subject supplement to the PBUOA will be submitted to the Commissioner before it takes effect as to the State's interest. The Lisburne Owners respectfully assert that the formation of the Lisburne Participating Area meets the criteria of 11 AAC 83.303. The formation of the Lisburne Participating Area will promote the conserva- tion of oil and gas, promote the prevention of economic an d p h Y sic a 1 was t e , and pro t e c t the i n t ere s t s 0 fall parties of interest including the State of Alaska. If you have any questions or require any additional information, please contact John S. Dayton (263-4206) or Don K. Chancey (265-6330). Sincerely, H. P. Foster, Jr. vg Enc. r¡rr;l\í!'D t· :- ~ ~-! V r I . \ -.' .' ~ ..':^ 2 r 198" ., .. - -..¡ þoo-, :-.._.\..... .." ...J A~?s.<:~ ~', ;" '~..: ~-::;::. (,~;¡iiTI~ssi~n A;-:::¡::~:~: S(;Çì~"J~~El~ JUN ¿;; tJ 20D/J ~ ) ) ",. DRAFT EXHIBIT 45-D to the Lisburne Provisions and Exhibit E-2 to the Prudhoe Bay Unit Agreement PLAN OF DEVELOPMENT AND OPERATION FOR THE LISBURNE PARTICIPATING AREA The Lisburne Participating Area will be developed and operated in accordance with the following plan. The first increment of development described in Part I below, provides for the design, implementation, and operation of the initial development of the Lisburne Reservoir. Possible future development increments are outlined in Part II. PART I - FIRST INCREMENT OF DEVELOPMENT Summary Initial development of the Lisburne Reservoir will include up to 200 development wells directionally drilled for production, injection, and water disposal purposes. Commencement of sustained commercial production is targeted in late 1986 at which time approximately 30 wells will be available for production and injection purposes. Produced well fluids will be directed to the Lisburne Production Center (LPC). The centrally located LPC is a stand-alone facili- ty with a nominal Hydrocarbon Liquids handling capacity of 100,000 stock tank barrels per day (STB/D). Hydrocarbon Liquids will be processed to pipeline specifications and transported to TAPS Pump Station # 1 (PS-1). Produced gas in excess of that needed to meet gas lift or fuel requirements will be injected into the Lisburne Reservoir or sold. Exhibit 45-D 1 nj. ~N:' '~11 r ì r¡n f) l' ,,I, ~ . ¡.I \:il' U cUu¿~' . 8/26/86 ) ) DRAFT The following summarizes the plans for initial development of the Lisburne Reservoir. The surface location of Lisburne facilities is shown in Figure 1. 1. Drill Sites There will be five onshore drill-sites (DS-Ll through DS-L5) for oil production. Present plans include an offshore gravel island drill site (DS-L6) for production and in- jection purposes to be constructed in Prudhoe Bay with a gravel causeway connection to shore. The Corps of Engineers is planning to prepare an Environmental Impact Statement for the DS-L6 causeway and island, thus, DS-L6 development is subject to their findings. There will be one additional onshore gravel pad used primarily for Lisburne gas injection (LGI pad). Gravel for the five onshore drill sites and LGI pad has been placed. Drill site modules were sealifted and the onshore modules were installed in 1985. At each drill site, production will be commingled near the wellhead, heated, and transferred in pipelines to the LPC for processing. Well testing facilities will be provided at each of the drill sites. Gas lift headers have been in- stalled in the mini-manifold and space on vertical support "members (VSMs) will be provided at the drill sites for future gas lift. 2. Lisburne Production Center (LPC) The LPC will contain oil, gas, and water processing facil- i ties. The nominal design handling capacities of the LPC will be 100,000 STB/D oil, 600 million standard cubic feet per day (MMSCF/D) gas, and 10,000 STB/D water. The oil will be processed in three stages of separation to satisfy Exhibit 45-D 2 8/26/86 II \ U I~,j 't! f\ ? n n ,~ .) ~OJj l\J ~ \~ () ~!,' 1,1 ; .. \J ~J \..~. J DRAFT pipeline specifications, metered, and pumped to Pump Station 41 (PS-l). Produced gas will be gathered from the three stages of separation, dehydrated, compressed, and transferred by pipeline to either the LG! pad or other appropriate drill sites for injection into the Lisburne Reservoir. The gas compression facilities at the LPC will initially be sized for a nominal 400 MMSCF/D gas. A second increment of compression facilities, sized for a nominal 200 MMSCF /D gas, may be added after start-up as dictated by reservoir gas producing trends. A depropanizer plant will be included in the LPC with a nominal capacity of 400 MMCF/D gas. Produced water will be injected into one or more water disposal wells located on the LPC pad. Power generation facilities will be installed at the LPC. Distribution to the drill sites will be accomplished by overhead, VSM supported, or buried electrical transmission lines. The LPC modules were sealifted in 1986. 3. Support Facilities Certain support facilities will be shared with the Initial Participating Areas. These include the Co-User Camp core facilities, potable water and waste disposal facilities, shop and maintenance facilities, certain roads and bridges, crawlers, rubber tire vehicles (RTVs), module movement and placement equipment, mobile, non-mobile and construction equipment, airstrip, construction pad, storage and warehouse space, fire fighting equipment, medical facilities, communi- cation facilities, and oily waste disposal facilities. Additional non-shared support facilities will be constructed including living quarters, warehouse space, and a tele- communications system. Exhibit 45-D 3 8/26/86 --,_. I' H' II ¡--. r In ~ 1\\1 G) 6':1 "") n f1\ n ~o''1'!{( J~t\'11\~h ' ,H]!,'\\ (0 \:i.!1 [;..uv'-' J 1) DRAFT 4. Pipelines Pipelines have been installed to transfer produced fluids from the onshore drill sites to the LPC for processing. There are also pipelines for gas which is returned to the onshore drill sites and LGI pad for injection, fuel, and gas lift gas. Gas may be delivered to each drill site and the LGI pad at injection pressure allowing for possible gas injection at any drill site. The gas pressure will be reduced at each drill site to a pressure suitable for use in fuel gas and gas lift gas systems. A Hydrocarbon Liquid sales pipeline has been installed between the LPC and PS-l for Lisburne production. Necessary metering and custody transfer equipment will be provided at PS-l. 5. Wells Up to 200 wells are planned for oil productionj water disposal and injection. To maximize economic recovery within the Lisburne, it may be necessary to drill on irreg- ular spacing, selectively complete wells, provide dual completion capability, work over wells to limit gas or water production and/or provide selective pressure support. All wells will probably require some type of stimulation. At commencement of sustained commercial production approxi- mately 30 wells will be available for production, injection, and water disposal. -. -þ - .... Exhibit 45-D Page 4 8/26/86 ,HJN ;J: ~ ZOO.!}' ') \ ) DRAFT PART II - ADDITIONAL DEVELOPMENT INCREMENTS The Lisburne Owners are currently conducting studies to evaluate the potential for future development increments. The Lisburne facilities have been designed to allow for the future addition of facilities required for additional development increments. 1. Waterflood The implementation and timing of a large scale water flood is dependent upon the outcome of waterflood feasibility studies. Special well tests and core studies are underway to evaluate waterflood potential in the Lisburne Reservoir. A pilot water injectivity test is planned at DS-L2 with water injection beginning in late 1986. Critical tie-ins for future produced water handling facil- ities have been allowed for in the design of the LPC. 2. Low Pressure Separation and Expanded ðrtificial Lift The Lisburne Owners have preinvested in critical tie-in connections and have allowed space for future low pressure separation and for expansion of gas lift capabilities. The timing of these expansions is dependent upon reservoir performance and the timing ,of waterflood. 3. Gas Sales The Lisburne Owners have pre-invested in a tie-in on the gas injection flow line for connection into a future gas pro- cessing facility. The timing of gas sales is dependent upon market demands and the availability of a tr~nsportation system. Exhibit 45-D 5 8/26/PJ Ç:: .~,', : I" ;1 ¡~- ," ',.U' N1 ~ fì ') (' [!i U1l,d-'~:f~1,~Jt:~_.' ,J j ,:J '.'J '- j r~ )1 1 ') DRAFT 4. Other Enhanced Recovery Techniques Feasibility studies will be undertaken to determine the potential of enhancing the economic recovery of hydrocarbons through the use of infill drilling, miscible injectants or other appropriate means. - -- -, -~ .~ .. ...... - ." . Exhibit 45-D 6 8/26/86 ~~ ~ :¿[!(J,1 p ~ ý ( ~~ f(-PAD .....~.....:.. . I... . '. :. . I'. . .~.:.. . . . . I' ----0 prOPO..d ....nd ~ - ~...~ _f _._ . "~~ .: ~ ......................:{...:.? ..... ..~:~ . :I:!I:M~:. .:: 00)/:"-' ~f WG I' ~.þ I i- '/ PRUDHOE BAY t J -- -- EAST DOCk ~ -- -- -- -- ...-- It ~~âi_i:: .~ .................. T3-Ch .i::.... / ;~V J ~ -~.:.. . . .. -,' . . " :...........::.:. . :':" .: .~.........)~ :" . 'ii::~' : . ...... . .'~' .~ \ {/) r--:: DS-7 ~~ r/ :z :-;r~ IT: ~~~-1 '. ) .~- ,- ,/ , ,~:'- ....:... ~ '.~- - ./ " , >,. LISBURNE SITE DEVELOPMENT PLAN : , I' . . I SCALE: I· = I MILE '~ g CONFIDENTIAL INFOR~A TION #1 I I DECEMBER, 1980 I I I I I APPLICATION FOR ADDITIONAL RECOVERY BY WATERFLOOD IN THE PERMO-TRIASSIC (SADLEROCHIT) FORMATION PRUDHOE OIL POOL, NORTH SLOPE, ALASKA ( ~( I I I I I [ I I I I I I I I I I ~, PURPOSE The Prudhoe Bay Unit Operators request approval by the Alaska Oil and Gas Conservation Commission (AOGCC) to apply waterflooding to the Permo-Triassic (Sadlerochit) reservoir. SCOPE I I I This application to conduct water injection in the Prudhoe Bay Unit Permo-Triassic (Sadlerochit) formation specifically addresses the near term commencement of produced water injection and the longer term plans to use Beaufort Sea (source) water to increase oil recovery from this reservoir. Produced water injection will start in late 1980 with low volume injection in the Flow Station 2 area and will begin in other flow stations and gathering centers as volumes increase to an anticipated ultimate rate of approximately 1 million barrels of water per day (MMBWPD). Beaufort Sea water injection will begin in mid-1984 at 1.5 MMBWPD and expand to a total of 2 MMBWPD with the completion of the second major flood increment in 1985. A total of about 3 MM barrels per day of produced and source water will be injected into the field toward the end of this decade. 'I I :1 The Operators recognize that variations in reservoir quality and primary producing mechanisms demand thorough performance analysis and jUdicious use of waterflooding. Water injection in those areas of the field with low natural depletion recovery is economically justified because it increases ultimate recovery and provides the pressure support needed to help sustain the producing capacity. In order to successfully design, install, and operate this major project, a high degree of flexibility is needed to permit the use of new data from the ongoing development and operation of the field to our maximum advantage. -1- I I I I I I I I I I I I I I I I 'I I I .~ The ongoing surveillance of reservoir performance will be supplemented by water injection data as produced water injection is implemented. As discussed below, the new data will impact the current plans for the ultimate disposition of the peak water injection volume. The Unit Owners believe that water injection is one of many major, capital intensive efforts which will be used to maximize economic oil recovery from this field. CONTENT In accordance with Article 5, Section 400, of the AOGCC regulations, April, 1980, the information required by 20 AAC 25.400. (b). (1-9) is submitted in this application. Questions concerning the material presented here should be addressed to the Unit Operators. SPECIAL REQUESTS A. Administrative Flexibility The waterflood concept proposed in this application is predicated on a mid-1984 source water flood start-up. Design is based on reservoir and operating information available today. These secondary recovery plans must remain flexible to ensure efficient implementation and operation of a project of this magnitude. The Operators request that the AOGCC provide for administrative flexibility to accommodate changes and additions to the 2lans presented in this application. Such key items as injection well selection and spacing, pattern selection, major flood area start-up sequence, and other major elements of this additional recovery program could require modification as field development continues and as more is learned about reservoir performance. The needs and expectations of the State of Alaska a~d -2- I I I I I I I I I I I I I I I I I I I SPECIAL REQUEST{,Administrative Flexibilit} the Prudhoe Bay Unit Owners will be served best by providing for administrative action to approve changes wherever possible. B. Surveillance and Reporting Prudent operation of this waterflood will require continuous surveillance. Prior to implementation of source water injection, the Operators will develop a comprehensive surveillance program designed to ensure that the necessary data are obtained. In the interim the Operators will submit a semi-annual report on the performance of the active water injection wells. This report will be in addition to the monthly reporting required by 20 AAC 25.430. As discussed herein, changes in these plans can be expected as additional information is obtained. The Operators propose to inform the AOGCC of water flood development progress and identify changes with semi- annual reports. The first report will be submitted approximately six months after approval of this application. 20 MC 25.400. (b) . (1): OPERATORS EASTERN OPERATING AREA ARCO OIL AND GAS COMPANY DIVISION OF ATLANTIC RICHFIELD COMPANY P. O. BOX 360 ANCHORAGE, ALASKA 99510 ATTENTION: P. B. NORGAARD WESTERN OPERATING AREA SOHIO ALASKA PETROLEUM COMPANY POUCH 6-612 ANCHORAGE, ALASKA 99502 ATTENTION: G. N.·NELSON -3- I I I I I I 20 AAC 25.400. (b) . (2): PLAT OF PROJECT AREA AND OFFSETTING ACREAGE This plat, Figure A, shows the Prudhoe Bay Unit boundary, the locations of all existing oil and gas wells, abandoned or suspended wells," and possible future wells on 160 acre spacing within the current development limits. Also included are water injection well locations common to the waterflood schemes currently under consideration and discussed in Section (b). (9) of this application. These locations are based on Unit approved structure maps. Refinement of these maps will continue as development drilling proceeds. Consequently, some of the injection well locations may be revised as new structural interpretations become available. I I There are no Operators offset to the Prudhoe Bay Unit. 20 AAC 25.400. (b). (3): CURRENT ZONE OF COMPLETION All existing and possible future development wells shown on the plat in Section (b). (2) are completed in the Permo- Triassic (Sadlerochit) formation of the Prudhoe Oil Pool. 1 1 I 1 1 I I I 20 MC 25.400. (b) . (4): ZONE AFFECTED BY INJECTION The Permo-Triassic (Sadlerochit) sandstone formation identified on the type log, Figure B, and located at approximately 8800' subsea is the producing formation of the Prudhoe Oil Pool and is the target reservoir to be affected by water injection. 20 AAC 25.400. (b) . (5): LOGS OF EXISTING INJECTION WELLS Waiver of this requirement is requested since all well logs have been submitted to the AOGCC in accordance with Conservation Order 145. -4- , ~ ( I ..~ I I r I r r r r r I I r r r r I I I 20 AAC 25.400. (b). (6): INJECTION WELL CASING PROGRAM AND TESTING A. CASING PROGRAM 1. Existing Producers: Producing wells which are to be converted to water injection service will require no change in casing. 2. New Injectors: Wells drilled specifically for water injection service will be cased in a manner consistent with current production wells. B. CASING TESTS All current and future casing strings have been and will continue to be tested in accordance with AOGCC Regulation 20 MC 25.030 as a minimum. Waiver of further submittal of information for this section is requested since well completion data including casing, cementing, and test programs are submitted for each well on the State of Alaska Oil and Gas Conservation Commission Form P-7, "Well Completion or Recompletion Report and Log" in accordance with AOGCC Regulation 20 AAC 25.030 Casing And Cementing. 20 AAC 25.400. (b). (7): INJECTION FLUID The Operators intend to use water as the injection fluid in this additional recovery project. The two sources of water and the approximate volumes of each are listed below. Produced (Sadlerochit) Water Beaufort Sea (Source) Water 1 MMBWPD 2 MMBWPD -5- I I I I I I I ( I I I I 1 I I I I I I . 20 AAC 25.400. (b). (8): TABULATION OF PRODUCTION TESTS Waiver of this requirement is requested since semi-annual well test data are submitted in accordance with Conservation Order 145. The last report was submitted as of July 1, 1980 on State of Alaska Oil and Gas Conservation Commission Form P-9, "Well Status Report and Gas-Oil Ratio Tests". 20 AAC 25.400. (b). (9): PLAN AND RATE OF DEVELOPMENT A. CONTINUED FIELD DEVELOPMENT Field development will continue as discussed in the May 7-8, 1980, Prudhoe Oil Pool Public Hearing. These plans are summarized in the Prudhoe Bay Unit Annual Progress Report submitted to the Director, Division of Minerals and Energy Management, Department of Natural Resources on July 21, 1980. This report was submitted to meet the requirements of the Prudhoe Bay Unit Agreement and is included as an appendix. B. WATERFLOOD PROGRAM Secondary recovery operations are planned at Prudhoe Bay t.~ increase oil reco_very by 6-~..~_...~~P. The proposed waterflood consists of approximately 2.0 MMBWPD of Beaufort Sea (Source) water supplemented by full return of produced Sadlerochit water. Water will be injected into those portions of the reservoir which will have low primary recovery. Of these areas, those identified as Flow Station 2, Northwest Fault Block, and the Peripheral Wedge Zone offer the greatest potential and will be waterflooded first, Figure C. Also shown are possible areas of expansion which include the Updip Wedge Zone, the Mid-Field Tango, and the Gas Cap. As fill up is reached in the initial flood areas and as produced water volumes increase, water will be available for -6- I I I r I I I I I I I I I I I I I I I WATERFLOOD PROGRl continued i{ injection into these expansion areas. However, additional geologic data and reservoir performance studies are needed to confirm that waterflooding is an attractive additional recovery process in these portions of the reservoir. 1. Initial Waterflood Areas a. Flow Station 2 The Flow Station 2 area is characterized by extensive shales. These shales and the unconformity which truncates the Sadlerochit in part of the Flow Station 2 area are severely inhibiting gravity drainage and are reducing gas cap pressure support. Consequently, pressure has declined in this area faster than in the rest of the field. Horizontal gas movement under the shales from the gas cap and the accumulation of liberated solution gas have caused the average gas-oil ratio (GOR) to rise faster than in other areas of the field. Though these natural barriers are hampering the gravity drainage recovery mechanism, their presence will improve water flood performance. Two waterflood patterns are under consideration at this time: an inverted nine spot, Figure D, and a multiple line drive, Figure E. These patterns do not exclude other approaches but appear well suited to this part of the reservoir. These two patterns have a number of common injection wells which are shown on the field plat, Figure A. It is likely that these common wells will be used with additional wells in the ultimate injection program to develop an effective waterflood. -7- I I I ( ( I I I ( (' ( I I I I I I I I WATERFLOOD PROGRAÎ.. . Initial Waterflood Areasj~ L'low Station 2 In simulator studies, ultimate recovery and oil rate projections for the inverted nine spot and line drive patterns are virtually the same. The key to pattern selection is an improved reservoir description which can only be obtained through longer term observation of reservoir performance and the analysis of ongoing injection tests. Thus, we plan to collect as much data as possible prior to making a timely decision on the ultimate pattern selection. The Flow Station 2 water flood plan calls for injection of 800-1000 MBWPD. After fill up injection will be reduced to balance withdrawals. b. Northwest Fault Block The Northwest Fault Block is another area of the field where reservoir pressure decline has been greater than the field average. The pressure has declined in this area because the down thrown fault blocks are remote from the main field gas cap and have limited aquifer influx, Figure F. The limited pressure support in this area makes waterflooding look attractive. Currently two waterflood plans are under consideration in this area: a peripheral pattern, Figure G, and a center line plan, Figure H. Several injection wells are common to both patterns. As in the Flow Station 2 area, the Operators expect to convert these wells and add other wells to complete the appropriate injection pattern. Simulation -8- I I I r I 1 I I I I 1 r r r r r 1 I I WATERFLOOD PROGRAlt. Ini tial Wa terflood Areas) lo'4orthwest Faul t Block studies suggest that both patterns would yield similar ultimate recovery and oil production profiles. Uncertainties regarding the transmissibility across the faults and the efficiency of gravity drainage recovery in the southern fault block make ultimate pattern selection inappropriate at this time. The extension of a pressure sink across the southern fault confirms that fluids can move across some major faults. However, additional field performance and development drilling is needed to resolve these uncertainties. Work to date indicates the range of required water injection rates to be from 500-700 MBWPD. This rate will be reduced after fill up to balance voidage. c. Peripheral Wedge Zone The Peripheral Wedge Zone is characterized by poor aquifer suppor~ the lack of a directly overlying gas cap, and a relatively thin oil column. This is expected to encourage horizontal gas movement along the top of the Sadlerochit formation and will cause high GOR's, low oil production rates, and low oil recoveries. Thus, the area appears to be a good waterflood candidate. As with the other two initial flood areas, reservoir studies identify two possible patterns for the Peripheral Wedge Zone: a peripheral pattern, Figure I, and a multiple line drive pattern with updip injectors located so as not to interfere with gravity -9- I I I I I I I I I I I I I I I I I I I WATERFLOOD PROG~t_. ¡ Ini tial Wa terflood Areas~ ~ eripheral Wedge Zone drainage, Figure J. Additional work to define the optimum pattern, injection well count and spacing, and injection interval includes further definition of the geologic description and aquifer performance, and an analysis of the interaction between the water displacement and the gravity drainage mechanisms in the updip areas. Waterflooding in this area will begin with low volume-produced water injection and increase as additional volumes become available. 2. Potential Waterflood Expansion Areas a. Mid-Field Tango A Mid-Field Tango waterflood would be conducted under Tango shales of adequate areal extent. Primary oil recovery under these shales is expected to be very low. Above the shale, the oil column is thick and overlain by gas. Oil recovery by gravity drainage above the shales should be quite high. _Pr71iminary work has shown that waterflooding under these shal~s ....~s desirable only if they ~re a~.:.~~.~..~el~__~x!:-~~~ive and sealing. If the shales are too small areally, early water injection could interfere with gravity drainage and reduce oil recovery from above the shale. Thus, it appears prudent to delay waterflooding in this area until more confidence can be gained about the reservoir description. Additional well control and production history should provide the needed information. -10- WATERFLOOD PROGRÁ _. Potential Wa terflood ExJc...üsion Areas b. Updip Wedge Zone I I I I I I I I I 1 I I I I I I I The upstructure area of the field under the Lower Tango shales appears to be another waterflood candidate. The natural depletion recovery in this part of the field is expected to be quite low because the thin oil column in the area is overlain by the gas cap. Producing wells are expected to have gas-oil ratios that rise quickly making them poor producers. Preliminary work has indicated that oil recovery can be improved by waterflooding wherever relatively continuous sealing Lower TangD shales are present. Future development drilling will define the geology of this area. If extènsive shales are encountered, the Operators envision that the Updip Wedge Zone could be included later in the overall Prudhoe Bay waterflood. c. Gas Cap Fieldwide simulation studies indicate that injection into the Gas Cap area for pressure support may be beneficial. However, the total impact of such water injection on either oil zone performance or ultimate gas cap gas recovery has not been thoroughly evaluated. Significant additional work will be required prior to any decision concerning gas cap injection. C. WATERFLOOD IMPLEMENTATION The following implementation plans are consistent with the previous discussion of the individual waterflood areas. Produced water injection will continue beyond the current field tests and complement source water injection as full scale waterflooding begins. -11- I I I I r I I I I I I I I I 1 I 1 I I WATERFLOOD IMPLEMENTATION 1. Produced Water Injection To conserve reservoir energy and increase ultimate recovery, the Operators intend to return virtually all of the associated produced water to the Sadlerochit oil reservoir. Fieldwide water production rates up to about 1 MMBWPD are expected as the waterflood project matu~es. Although the volumes are expected to be very low initially, early injection of produced water will provide valuable data regarding water flood performance. These data, data from injectivity tests, the drilling program, and continuing reservoir studies will be used to optimize the waterflood plan. a. Eastern Operating Area (EOA) Flow Station 1 The currently active water injectivity test at Drill Site 5-17 is scheduled to continue until 1983. By that time, produced water injection capability will be available at Drill Site 12. The downdip wells at that drill site will be converted as warranted by the increasing produced water volumes. Flow Station 2 A long term produced water injection evaluation program will begin at Drill Site 4-8 in late 1980. Water injection at Drill Site 4 will expand as water production at Flow Station 2 increases. Additional wells will be converted to injection service as required. -12- I I I I ( ( I I I I ( I I I I I I I I WATERFLOOD IMPLEMt..rATION: Produced Water IJ~~ction/EOA Flow Station 3 Produced water injection at Flow Station 3 is scheduled to begin in late 1981. The downdip wells at Drill Site 14 will be converted initially and wells at Drill Site 13 will be added as produced water volumes increase. b. Western Operating Area (WOA) Gathering Center 1 Recent forecasts show that less than 10 MBWPD will be produced here prior to mid-1984. Consequently, plans are to continue disposal of the produced water into the Cretaceous formation until start-up of the source waterflood. Gatherin9 Center 2 Produced ~ater injection at Gathering Center 2 will begin in 1982. The peripheral wells at R pad will be converted to water injection as the produced water volume rises. This injection location is part of the planned Northwest Fault Block waterflood. Gathering Center 3 Produced water injection at Gathering Center 3 is scheduled to begin in 1982. Downdip wells at Pad X will be converted as the produced water volumes increase. 2. Source Water Injection The source water facilities are scheduled for start-up in two increments. The first increment -13- I I I I I I ( I I I I I I I I I I I I WATERFLOOD IMPLEl~NTATION: it Source Water Injection of 1.5 MMBWPD will start up in mid-1984 and serve the Flow Station 2 and Northwest Fault Block areas primarily. Water in excess of the requirements of these areas may be injected into the Peripheral Wedge Zone. A second increment of 0.5 MMBWPD will be added in 1985 to provide the planned 2.0 MMBWPD of source water volume. This will supply additional water volumes to the Peripheral Wedge Zone area. 3. Waterflood Implementation Summary The following tables summarize the implementation of the Prudhoe Bay Unit waterflood. Shown are the water rates and the minimum number of injectors currently estimated. More injectors may be added if indicated by ongoing studies, well performance, and development drilling. -14- -15- I I I I I I I I I I I I r r I I I 1 I INJECTION WATER DISPOSITION (MBWPD) MINIMUM NUMBER WATERFlCOD AREA STARr 1984 1985 1988-90 OF INJECTORS Flow Station 2 1980 800-1000 800-1000 800 35 N:>rthwest Fault Block 1982 500-700 500-700 650 28 Peripheral Wedge Zone 1981 100-500 800-1200 1000-1200 30 Mid-Field Tango Post 1985 0 0 100 10 Updip Wedge Zone Post 1985 0 0 250-450 20 1800 2500 2800-3200 123 TABLE 2 INJECTION WATER SUPPLY (MBWPD) TYPE START OF INJECTION 1984 1985 1990 Produced 1980 300 500 800 - 1200 Beaufort Sea 1984 1500 2000 . '2.000 1800 2500 ;¿800-j;¿UU TABLE 1 WATERFLOOD IMPLEMENTATION: Water flood Implementation Summary I I I I I I I I I I I I I I I I I I I ~ D. WEST END (EILEEN AREA) DEVELOPMENT Development of the West End (Eileen Area) of the Prudhoe Oil Pool is included in the Unit Owners' ultimate field development plans. Preliminary reservoir studies of primary depletion and waterflooding have been made. The Operators will continue to evaluate this area and formulate appropriate plans consistent with the prudent, continued development of the entire Prudhoe Oil Pool. The ARCO Highland State #1 well, Sec.24,TllN,RllE, and the Kuparuk well, Sec. 22, TIlN, R12E are currently being completed as observation wells in the Sadlerochit to observe pressure changes which will result from Main Area development, production, and waterflooding. These wells will provide valuable input into reservoir studies to determine the optimum timing and approach to oil recovery in the West End. Further geologic and fluid data will also become available from the drilling of several new wells which will occur in the near future. CONCLUSIONS Throughout this application and the May, 1980, Prudhoe Oil Pool Public Hearing, the Operators have emphasized the need for flexibility in the waterflood design. The Operators intend to gather as much field data as possible and request that the AOGCCallow them to continue to evaluate all options until the final waterflood pattern selections must be made. To meet the planned 1984 source waterflood start-up, the Unit Owners are actively pursuing the study of all the factors which will affect these decisions. -16- --- -~-'--t- -- --- - - - .-.-- - ---¡--- - , . .- I'lIu¡;¡¡.¡of UT I ¡ I ,II> II '" - - t t" ¡ t .... APPLICATION FOR AOOmONAL I I ! ! RECOI/ERY PERMIT I . · I ... ,. ......... - -t + I ~ 1 to.'" ð...oo l.ul; ! I I ! Sk.n_ .Acnoo iMllL$ -")' . ! · , ! ~rp PArH_ , ! I CCMO< I 1 (I..fJOjrlf~ wC.J.'i t i I i I - ¡ I ì i I . - " · I I . I j I I ""'----- U:I"TUlilE~ t. 1'iMC · I I ,,',,' m. ~ -~ - .J.__ -- -- -- --- - - - ----'-- - --- -- ....c A-' ...., -- - - --T I I I ... f ¡ . I OAH..L PA.oS AHO CH1:H...L. SITES T. _I 2 \- ¡ p IHUH 8 = !J<tSTt.... " 3 .:::: I UN! BOUI\I ~1VI'1JI'IIiIE - ! ".--'" "'" A-.... liIIt-t "-C A"': I ::<- + -~.- ¡:..., ..-::( .......... ."-it ....., ... - I . "'[1.1..' .. 010 ACI'IiE M...U..;:¡....iEIn ff -I~ U II - .. Vlt:5'!'I.... '" I ¡Ø I . · m .. . I 5 . - '" . i · " ~1'VT1JII'III: .ø --p , '''JECTtO'' WiEl..UI .. $""""" A-( - A-! -"" - !It /If. - · . P, iEl<'ST1"'(; &.os - . - WELLS W æ . _.:»-~ k"':¡;'¡' it- JØ )II. r<:R ,""",CTa ~ . · - · 0 "'ATEII .. ,TEll O<SI'OSA4.. ø ~ - .. --44 .e-- ~ · ( . . II ill ..ØAN!)(; MSIl~ .. \ WELl. - - .._~- ;;; ....... ...... ¿ ---' - - Sð ü- ?" ,,-t , - . . ,. - '" . ~ \15: .. .. - - - I-I ./'-1':.. .. .. .....1':,. - . ..:- 0 .. ~ .,--- :r>-'~ -" I .- :. - ..,.. ~ . - - . -- -. - . .. ;""..., t ~ t t I ~i . II .. 15, I . - g I I I I I I I I I I I I I I I I I I I I FIGURE 8 - ~¿â&- ~~t{Y: .. .. :.. -.:. . , :::/0):: - 916"Ô:- ';0.:: ::; MAJOR :/::/~ CORRELATIVE ';':o:ó' SHALES . ~~2 II 000 Q .0 -'9200- ~.~oo o~~:o ~ ~:~ : .~: ~ ::- '." ..... - ....... .. .. Ó'b~;~ [ ~ .~~OO- . . .... C :{(~'~' . 0 ..' G ~ 6.0 \~{r t. ~.§;íÕo.~:'- B ,¡~.:'::~;~ OQ?o,!» lfÆ~: -£ .·.ö·¿"~· ~ :~'~89- A . .. ~ .. .. '1 ... : .." . .. .. . "0 ..-"; "0:: :-......:.... -:.:.}( c~--c·... INTERVAL TRANSIT TIME 100 50 o \II 1 ROMEO .., w 2 TANGO II. X-RAY 11\ VICTOR 3 \Ii ~- A 4 ZULU f 11\ GAMMA RAY API-UNITS o 100 150 ZONATION GEOLOGICAL SHALE MAPPING TEAM PRUDHOE Oil POOL PERMO- TRIASSIC (SADLEROCHIT) RESERVOIR TYPE LOG - - - - ,.-- - - - - - - - ~. - - -- ..-. -- - - ~ ~, ~ - ----- -- ~ ~ ~ ~ ---. ~ -- ~ ~ ~ ~ {T PRUDHOE OIL POOL MAJOR WATERFLOOD AREAS R13£ RI4E RI5E I ) I I ï 1 I' I I SOHIO . ARCO ¡ OPERATING . OPERATING . ........... } , , . ..........::...........:.... ï ___ ~ ARE A ARE A .........::;;:;;~m:::::::::::........···-·::: ::m:::::..... N W F- AT ~ ·u L:r B LO' C( K .....:. ..".l·:'¡¡';';;;"¡;;¡¡t¡Um:,.,......." GAS ·..··"·",·,.,·:::\i\. - . ....::.:.:.:.:.{:.:;..:.~:.:.:~:::::.. ':~~::" .~::.,::{.~::.. 100 FOOT CAP ":::}" ...::.:.:.:~.:.:.:.:.;.;,:.::.;... ..;::::~:::::::~ ~õU~%~~~N ,. "'\:;': . ~£~i';;:~~~~·- " ~ g~~~~ :-II! - '.",.¡~.- \~\¡¡¡:::...... ~D~ I~. / "'::::,::-:. .:~..-;. ry ~ D "/~ ;)!';;;;:~\",-:,:.'!!/()~ G~ ZONE '- é A ..::\::::.... I ~ L..D "' 'I:: A ! ^·-<\\"~$.·~·":::.."..s·,, :.... ì /I ÑG ' T/I"-J L1 .......,. .'. ':. '. ~ 0 I t ~~. -.' '. .':..::::::::::.:-:::...... ....~:~:::::.. ~ . <..;; J :< ..~..(~:-::...~.~~~.........;:::~.-::::.:: .... ...., _..... -,,\-: I. '. ...... :::-...... ,..:.~~~:::::::::::,.#) . ~ ...:::,:::.:.., '" ~... ~ W~DG FS-2 . '£: ZONE \ - I I I~ - -" - ~ i - i :, I RI4E RI5E RI6E RI2E I RI6E I 11: ,,-= - ~ I RI2E I RI3E FIGURE C ..,n,...._ . .._ _ FIGURE D NUMBER OF INJECTORS = 35 ð POSSIBLE INJECTORS o 160 ACRE DEVELOPMENT WELLS 1 I RI6E RI5E j RI4E I RI3E I RI2E 0 0 0 0 0 0 0 0 0 0 01 Å \ 0_ 0 0 0 0 0 0 0 t 0_0 0 0 0 0 o & 0 Â Â Â 0 ':7~ ·A o. o. 00000 o 0 - o 0 0 O~. 0 0 ~. o 0 o 0 0 · · · . . 0 0 .. · ~......,...::<'::':'J:::::.:::::::.~::::;, "o~' ..... ..0 ......:....- 0' 0 0 .....;<ft-? 0 .'. 'A ~ ~ oJII'f'... ..' · .'. .'. ~' ~:.._ ..;.., o. 0 '. ....:. · o 0 lit:·:··:;:.:;, · .. 0 0 · . 0 · 0 ~:~. 0 0 ::. ::. · -100 FOOT "'::"~ '¿::' ~~: . .. ~ · 0 .. Ol~"- ... · 0 COL o' ¡\\. 0 · 0 · U .. o· R · BOUNMN 0 .....;.,.. ~ULTS ~o 0 _ DARY 0 0 ,.:::'::.. 0 0 ....11_....9.. 0 0 0 .' .' '::::':~' o. 0 · 0 o . .~.. · 0 (__ ':-:::''i,¡."¡,:..o. 0 . .. o. 0 0 0 0 o . 0 .,':....0. · 0 0 0 . . '.. .. 0 0 o 0 . 0 ..!::,. .. 0 0 0 · o ....... ....:..... 0 . 0 · o 0....... ":':" .. 0 · , ":::'... . . . . , o . o. ....:,..... ... · · 0 0 . ."'>" .. ., ~ o . ., ... · · 0 .. , o ., ......... 0 o ~ .."....-.,.... · · o 0 o. 0 : :: 0 0 ..-:::.~¡I¡?¡!!;!¡!!.'~I!!; : '. · ~ :.. : ~ ~ 0 0 ..~..........::......' o 0 0 0 ...::~::::,::.<::",;?,.,. ~ 0 · 0 . o· .' ....,;¡;¡;;;:~.. o 0 . 0 o. .. ....~.~.:, o · 0 0 0 0 0 · · "1 0 ., o · · 0000 0000 A o 0 0 ~ 0 Â o 0 0 0 0 o ~--:'- I 'I SOHIO OPERATING AREA o RI6E I RI4E I ARCO OPE R A TI N G 1 ...,......:::::::::... A RE A ....·....1 ~::::::::::::::::::.......-::::::::::...... ......~..; ~:~ ......,,'1...... .....::::::::: ;-', ........""..... \ "':'., .:::::!.::..,^. .".-- "':::::::'" .... '.' E XT ENT OF ...:::::::::... ORIGINAL "::::::" GAS CAP ----.Jl·f RI5E I I · · · o 002 R13£ I RI2E I PRUDHOE OIL POOL FS-2 NINE SPOT WATERFLOOD PATTERN ~"} -- - - - - - FIGURE E NUMBER OF INJECTORS: 36 POSSIBLE INJECTORS 160 ACRE DEVELOPMENT WELLS o ð. " 1 RI3£ I RI2E 0 0 0 0 0 0 0 0 "r~ " 0 0 0 0 0 0 0 0 0 0 AAâ 0 0 0 0 , 0 0 0 0 0 0 0 0 ~ I R15£ RI6E 1 R14£ o o o 1--- 0000000000 ,#>~.~ " 00 ø 0,:\0 . ....:'..;.:::.q,..:~::.:..:::. '. 0 ,," 0 Jt.J, ..~"....Y:::::r.. " 0 0 0 " " o " ". 0 0 .'. ...~,.'i.,~',:,,';f..:\,,¡ ~..... :,,,~,:.. · · .. : ~ 0 t') 0 0 '.(..9;.......'-......;. I) n I). 0 " (> ~. .~; ::.'.' 0 tÍ':::¡":'::¡¡;::::~::.:.:.:~ o "" 0 0 " '0 (\ " " ~" A o 0 0 0 o 0 0 0 Q 0 ~o \9· . o 0 o 0 0 0 0 ... ,.' . 0 .... o · · ......... .....)£ o 0 0 " ..9-')\..-/;-::::............ "'i' " 0 o ~.,.., 0 0" o 0 0 0 ....~ 0 Q .~ ". ...'~... 0 0 "-" , " " ...:~? ". ." . o ~ ~,,::.,. " 0 o ~..:;.... · · 0 0 · · -100 FOOT 0.. I[~O 0 '~:.::::~,;/'i~\.." · J;ULTS~O 0 COLUMN " ··...of,';".." " .-~ BOUNDARY 0" ""¡;~!\¡~i&¡'. " · 0 ) .. 0 . L~;.\.. · 0 . 0 0 o . ::'~':,:~.,::,. . .. '~'\") 0 0 " o \oi:l:::- . ,,!,,'. . 0 0 . " Þ;'\':,~.... . . o o o " o 0 o o o o 0 o ð o 0 o 0 000 0 0 0 0 0 0 0 u 0 0 0 0 () 0 û 0 0 0 0 R16£ r RI4E I ARCO OPE RAT IN G ~ ........;;;;::;:::::.. ARE A ..::.. ':.;: H~":::'Åq::::::::::::::: :.........~.::.:::::::::::::.:.: :;:'. ....··1 III..· \ " . , ....:::·:.::·.:tt...· ,,-- "'::::::'" .... '.' -.-:. ...... EXTENT OF \:::::" OR I GIN A L "':::::'" GAS CAP--JII RI5E I I ' .\ · · · · I SOHIO OPERATING AREA R13£ I RI2E I ~,- PRUDHOE OIL POOL FS-2 MULTIPLE LINE DRIVE WATER FLOOD PATTERN - - - - - - - FIGURE F FAULTS "" -c;:.: ~ "--." ~-- OIL COLUMN MAIN FIELD SOUTH FAULT BLOCK NORTH FAULT BLOCK ~.. -- -.. .... . y I. :.;;-;- N:::::··· .;~ ¿:;:; 0:- ~::::::~ ..... ....... r ·····..1 J11 .<:{ :.:. ifl .:~:~~ AQUIFER --- --- OIL WATER CONTACT . ....c, -- -. ~. ::;=:' 1~ NORTH FAULT , ."" GAS CAP -- -- --- - --- - - -- - - - - - - - - - -- --._----_.-. .---- --, - . - CENTER FAULT SOUTH FAULT AI PRUDHOE OIL POOL NORTH WEST FAULT BLOCK I CROSS-SECTIONAL VIEW A-A ~ ~ .-------..o¡____~_ FIGURE G ð POSSIBLE INJECTORS o 160 ACRE DEVELOPMENT WELLS NUMBER OF INJECTORS = 28 I RI6E o r ~ 0 r 0 ·c 0 1 0 ~ 0 r RI5E o 0 o o 0 0 o 0 ~ooooooo o 0 0 0 0 .... ... - -. - 0 2 0 o 0 ° hO 0 · 0 0 · I · · · I RI4E f R13£ I RI2E o o o 0 0 o o 0 .. .. .. .. 0 .. '0" 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 o o o o 0 0 o o 0 ~. , ~ o 0 o o o o o o o '\ ° 0 0 0 0 0 0 0 0 o ~.~~!~~. 0 o r:~ ° ~:: 0 .,;::::1 ~' 0 o 0 0 0 0 0 0 0 0 0 0 0 . 0 . O~o 000 o 000 o 0 o 00. o 0 _ 0 0 o 0 o o o o 0 o 0 0 . o 0 0 o 0 o o o o 0 o . . o o --100 FOOT OIL'-- 0 COLUMN BOUNDARY RI6E r RI4E I A RCO ~ .....::::::::::.......... ERA TIN G .....:..............,.. .,......::,.." ~ o p . .......... :::.<1\ I'm;:;:""'...... . ..... ..... "'"\::''' ARE A ..,""ii....".. \ ":":'. :::r.:::::::· · \:i;\ EXTENT OF '\}'" ~ · .. ORIGINAL ":,\ .. ... · GAS CAP ___ 1¡¡ "^ o.ooo.~. · Iii o .:~ fH o :;: o ... 0 o 0 <> 0 0;:: 000 o 0 o 000 o 0 . o · FAULTS·~ ° · 0 0 o~ o 0 . 0 o ~---- RI5E I I SOHIO OPERATING AREA RI3E I RI2E f PATTERN PRUDHOE OIL POOL PERIPHERAL WATER FLOOD NW FAULT BLOCK ~ -. -- -. --..¡ - --.; --- - -...._ ...n__ FIGURE H L1 POSSIBLE INJEC TORS o 160 ACRE DEVELOPMENT WELLS NUMBER OF INJECTORS = 30 I RI6E o,._o~. \0 0 0 I - i RI5E 0 .. ·0·· 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 0 o 0 0 K: I' I I . . I RI4E I RI3E I RI2E 0 0 0 0 0 0 0 000\ 0 0 0 o 0 0 0 0 0 0 o 0 0 0 0 0 0 o 0 0 0 0 o o 0 o 0 0 0 0 \0_0)0000000 " ~;" - - o 0 0 0 o 0 o o 000 o 0 o o 0 o o o o 0 o o o Q 0 o o 0 o o o 0 0 0 ¡~ o 4:: 0 o tf 0 o ~ .::,:::::: ~ 0 0 0 0 0 0 0 0 0 0 0 0 .~o 0 0 . 0 0 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o o o o o o 0 o o o o 0 0 0 0 0 0 . 0 0 0 0 0 . 0 0 0 0 0 0 0 0 100 FOOT -OIL COLUMN/' BOUNDARY o o o o 0 o o o o o RI6E I RI4E I ARCO O PE RAT. N G ~ .......:::::::..... . ...... ::::: .:: ::: :...., ..:::: .::::::::.. '.,... ..........\ ,1::::::::...... .......,,::::::....... A RE A ..::iiiim¡¡~~......" ':1\ "'::':'" '.::1:::::::;;'· . \!;:::.. EXTENT OF "{:::.. ORIGINAL '..::;:::" GAS CAP ~I êi¡ 0 o o o o o o o ~ '^o 0 o 0 0 o 0 RI5E I I SOHIO. OPERATING AREA RI3E I RI2E I PRUDHOE OIL POOL BLOCK CENTER LINE WATER FLOOD PATTERN NW FAULT - - - .. -- - r\\lJf':: Þ.IO [') C _ I ." co .... FIGURE I I RI6E o (" o 0 o 0 0 ~ 0 0 0 0 0 ....... 0 0 0 ~ RI6E . J - å POSSIBLE INJECTORS o 160 ACRE DEVELOPMENT WELLS NUMBER OF INJECTORS = 30 o ~ I RI4E I RI2E I RI3E o 0 0 0 0 " 0 0 0 , 0 0 0 0 0 0 01 0_ or 0 0 0 0 0 0 0 0 0.0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o o . o 0 . - o 0 .. 00000 o 0 0 0 0 0 O~o 0 ..;~::::: . . 0 0 0 ~..o 0 0 0 ° 00 o~"¡¡~iii~¡¡'?~i,?L:';¡:~:":¡i;~~~¡~:¡;~\:~~~~~¡';'¡;¡i!il:~. o 0 .. . 0 o o o o~~ o ~¡¡ 0 I .~::::I : o 0 o o o 0 o o o o o . o 0 o o o o o 0 o o o o o . o . o o o BOUNDARY RI4E I ARCO OPE R AT IN G 1 .........::::::::::... A R.~. ~ ... ,:::: iiii¡ii~~¡:~:~\ ~m::: ::: ::::::::........ -::::' H:m:::::::: :~:;:. ..'. "...1. \ . " ........ ". . \ EXTENT o:~i:~\. o ORIGINAL "'~:::." GAS CAP r d:: 0 o o 0 o o (;) o o o o 0 . FAULTS~~o .¿¿. 0 0 0 0 ..... . 0 0 0 . o . 0 0 0 0 0 0 0 0 . 0 0 . 0 0 o o ~,...... 000 · · · · , SOHIO OPERATING AREA RI5E I RI3E I RI2E . r PATTERN PRUDHOE OIL POOL PERIPHERY- PERIPHERAL WATERFLOOD --=-! - -. --. - - - ...n __ . .. _ _ FIGURE J t R16£ o 0 0 o ( 0 -"- (I (I 0 0 ~"'o.. R16£ I --..oi! _ _ A. POSSIBLE INJECTORS o 160 ACRE DEVELOPMENT WELLS NUMBER OF INJECTORS = 50 I 'I RI4E , RI3E I RI2E 000 o 0 o 0 o .0 o 0 0 0 0 0 10 0 0 0 ( 0 ( gOo 000 o 0 o 0 o 0 0 RI4E . I _ ~TING · A RCO o .' 0 0 EA' OPERATING o . . 0 0 0 ~o · ARE A .....................~t........·......·........· o 0 .0 0 0 ~ .0 . :.. "~;..:::~.:::::~.:...,¡ . '. :::\:'.:',:::..1'" """:'''''' R<.. '::""''''''''''''''''''';¡;¡fii!!iiiii!ii!! !!\::" . . o' · ø~"""" · 0 .... . 0 ~ ":':'. :;--... 0 o:.:.:.:..~.::¡tii.~· ~ -: .. 00 .' . .......<{. V\)O : . · . ··::i\.. ~,..,... . 0 "^. 0 o. . EXTENT OF '::'. ~_. . 0 ORI ';". f'¡-' .~..1¡... . . 0 0 0 0 0 · 0 0 o. · GINAL "::':". -190 FOOT ~o .<>~lt' ~\\ ., · 0 .' · 0 0 · GAS CAP ":,::" OIL COLUMN 0 ··.·0 \¡\ . 0 . --:F~ULTS ~o 0 ----.;¡¡ BOUNDAR 0 '.bi>",.. 0 ~ Iii y . 0 6'-.""........... 0 0 0 0 :" '. ,,:,,::~ o. 0 '" ..;f.... · 0 0 i!i '::",\:::,.:...0 · : : : : 0 0 : : : : : : 0 0 .III 0 . 0 . 0 ' o 0 0 0 0 Q 0 0 0; 0 o 0 0 ::. 00 0 ~:' : . .~:/:.: . 0 (I 0 0 0 0 g 0 g 0 ø .~. 0 . . 0 0 0 . ( 0 ( 0 o ø 0 0 0 ø ø ( 0 0 0 0 RI5E r , SOHIO o PER. AR I . R13£ I RI2E r PRUDHOE OIL POOL PERIPHERY-MULTIPLE LINE WATER FLOOD PATTERN - -'- - - III--.¡ I I [ ( I I I I I I I I I I I APPENDIX I I I r r r I r I I r I I I { ARCO Oil & Gas Company P.O. Box 360 Anchorage, Alaska 99510 July 21, 1980 Sohio Alaska Petroleum Company Pouch 6-612 Anchorage, Alaska 99502 Director State of Alaska Division of Minerals & Energy Management Department of Natural R.esources 703 E. Northern Lights Boulevard Anchorage, Alaska 99503 Subject: Prudhoe Bay Unit Annual' Progress' Report Dear Sir: In accordance with the requirements of the Prudhoe Bay Unit Agreement, we are submitting an annual progress report of the activities performed under the Plan of Development included as Exhibit 'E'. If you should have questions regarding this report, please do not hesitate to contact the undersigned. Sincerely, ~\~~~Ù'^ P.B. Norgaard Vice President ARCO Oil & Gas Company cc Attachment ~ C' n ( J~ / G.N. Nelson Assistant General Manager (Opera.tions) Sohio Alaska Petroleum Company I f I r r r r I , I I r I I I -1- ( PPRUDHOE BAY UNIT ( ANNUAL PIDGRESS REPORI' In accordance with provisions of the Prudhoe Bay Unit Agreerrent, this Annual Progress Report has been prepared for sul:mission to the Director, Division of Minerals & Energy Managerrent, Depart:rrent of Natural Resources. 'Ihe purpose of this rep:>rt is to surrmarize the previous years I acti v- i ties tmder the plan of deve10prent and operation, which is incorporated in the Unit Agreement as Exhibit I E I . Oil Production Since July 1, 1979 production to the TAPS line has 1:een essentially continuous, with only very brief interruptions. During the periexi of July 1, 1979 to May 31, 1980, a total of 484 MMB were delivered to the pipeline at an average rate of 1442 MBPD. Total net oil prc:duction from the field fran April 1, 1977 (the effective date of the Prudhoe Bay Unit) to May 31, 1980 is l212~, including approxi- mately 2.45 MMB net to the crude oil topping plant. G:I.s ·Product.iön·and Injection Since July 1, 1979 to May 31, 1980 a total of 480æ.1SCE' of gas has been produced from the field and 437 MMMSCF was reinjected into the gas cap of the Prudhoe Oil Pool. The majority of the renaining 43 MMMSCF ha,s been used as fuel, purge and pilot gas, with only a minor aItOunt flared. Flaring has been reduced to practical minimums and has been in accordance with the rules established by the State of Alaska, Division of Oil & Gas Conservation in Conservation Order No. 145-A, of January 12, 1978. I I I I I I I I ( , I I I I [ -2- ,J( '~ Water Production Water production to date has been rn:U1imal. From July 1, 1979 to May 31, 1980 a total of 7.88 MMB of water has been produced, essen- tially from 32 wells. This water has teen dis¡:x::>sed of by mjection into the CretaceousjTertiary sands through dis¡:x::>sal wells located at each of the FlCM Stations/Gathering Centers. Additìonà.lWells and Fàcilities As of July 1, 1979, 191 oil wells were connected and capable of pro- ducing to the Flow Stations/Gathering Centers. A further 30 wells were added in the Westem Operating Area (IDA) with. the tie in of manifold extension facilities at each Gathering Center. 23 new wells were added in the Eastem Operating Area (EOA) which includes 15 expansion wells associated with previously installed drill sites and 8 wells associated with the addition of one new drill site. '!be total number of oil production wells connected on May 31, 1980 was 244. Of these, 133 are in the Eastem Operating Area and 111 in the Western Operating Area. In addîtion, 37 wells have been drilled, but are awaiting either completion or connection of surfaœ facilities. The rottan hole locations of the oil production wells drilled as of July 1, 1980 are shO\VIl in Figure 1, together with }?Ossible future l60-acre locations. I I I f I f I I I I I I f I I I I -3- An additional 3 gas inje~ In wells were perforated at th(' 'lorth Gas Injection Pad during the year, bringing the total number of gas in- jection wells to 14. Drilling is currently in progress at D.S. 2,6,11 and 17 in the IDA. In the IDA drilling is in progress on well pads C,D,E,X, and Y. Figure 2 shows the location of existing production facilities, pipelines, roads I bridges I airstrips and base camps I together with facilities under construction and possible future facilities. 'COntinued I:'eveloprtent Well and facility additions are continuing in order to ensure that adequate field capacity is available to neet oil pipel.ine demand up to a maximum annual average oil rate of 1.5 r-MB/D, plus condensate production, in accordance with Conse:tVâ.tion Order No. 145. Field facilities will also be available to accamcdate gas pipeline del- iveries of 2.0 BCF/D when a gas pi¡:::eline and plant to condition gas to specification can be COI'C'q?leted. In the WOA, well pad manifold facilities to connect future wells are being fabricated. The first increrrent of these facilities is scheduled for installation in late 1980, with subsequent increm=nts in following years. Current plans envision a total of 257 wells in the Western ÇPerating Area by 1984. Likewise in the EOA, facilities are being fabricated in conjunction with installation of new drill sites. In addition, expansion of several existing drill sites is scheduled during the coming years. An estimated 283 wells will have been drilled and connected in the IDA by 1984. I I I I I I I I I I I I I I I I I I I It -4- it cne addi lional lCM stage ccrnpressor is scheduled for installation at the Central Gas Compression Plant in late 1981 bringing the total to 9 lav and 4 high stage units. In addition, 4 wells at the West Gas Injection Pad have been drilled, and are awaiting a:.mpletion and connection of surface facilities. Conceptual and detailed engineering design studies have continued through the past year for additional gathering systems, low pressure gathering and separation systems, artificial lift systems, and addit- ional produced water injection systems. 'n1e low pressure systems will·be installed in annual increrœnts covering a four to six-year interval. The first increment is in the procurerœnt stage and is scheduled to be operational in early 1982. This initial incre:nent will be installed at Flow Station 2. The next increrœnt of T.I::M Pressure facilities will be installed at Flow Station 3, and Gathering Center 2, and is scheduled to be in operation by early to mid-1983. Eventually, the low pressure system, consisting of a gathering system, separation facilities and ccmpression facilities, will be installed at each of the Flow Stations and Gathering Centers. Several concepts of gas lift facilities are currently under revie.w. The configuration and timing of installation of these facilities is de:pend.ent upon the results of the current studies. !he first increment of additional produced water injection facilities will be operational in early 1981. These facilities will be capable of I ( I I I I I I I I I I I I I I I I I -5- . injecting produced wa~ 'into the Sadlerochit reservo~ It is currently planned that by 1982 five of the six Gathering Centers and Flow Stations will have this capabi1i ty . During the past year, considerable engineering effort was devoted to the continued conceptual and preliminary design studies for a source water injection system. In August 1979, applications for rrajor pennits were submitted to the U. s. Army Corps of Engineers and to the Alaska State Division of Minerals and Energy Managerrent, with (X)pies to other various federal, state and local agencies. The penni.t applications cover the construction and or:eration of a 2.2 MMBWPD source water injection system using Beaufort Sea water. In April, 1980, an Enviro:n.mental Assessrrent was issued, and, after receiving ca:mrents from interested agencies, the Draft Envirornrental Impact Sta1:enent was issued during June, 1980. A final EIS will be prepared and penni. ts for the source water injection system are targetted for issuance by Novem'ber, 1980. '!he current concept for the source water injection system envisions an intake structure and water treatment plant located at the end of a 3700' causeway extension beyond Dock No.3. !DÑ pressure water would be distributed to two central pumping stations located in the East and West Operating Areas. Fran thesepump:ing stations, high pressure water would be distributed to the appropriate Drill Si tes/Drill Pads for injection into the Sadlerochit reservoir. r:eta,iled design for the source water injection system is scheduled to begin in July, 1980. If approval of the EIS and all other required penoits are received. by late 1980, a mid-1984 start-up of the Beaufort Sea, waterf100d is possible. If the pennits are not received and equip- ment ordered by January, 1981, availability of rrodules for the 1983 sealift would be seriously jeopardized with associated delay in the waterf100d start-up to mid-1985. I -'--'-T---~-l-- " I ' I I ~ . ~~, . ..,..~ . ",(I,; 8: ' 7 ~ . I "~P '~ S0l110 1------sOHIO ~. ';:;~IO' ".:.=- - ::-~¢-. r); .-E . o~?··_;~ '. " !" ,. .. L ~' , \. . I' 0 '~9 2-~ . ~~2 - ~---2-4' 27 0.1 "\..\:f,'/O ."... J..o 25 t¿;;' 0 0 T--,~~¿~' - 0 . ". p.... ,.' I·' - . - , .0" 0-(>-....,.9 S : " :: ... ;0 ,- 0 0 .! . .,': . '. ( R . , .---,-', _' ., 1_ T ",.... ... 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II-P " ii+<\' ill 2,2 .S· . ~- "-.-', SOHIO ", II-P II-P-C A-£ 26 2.5 23 T 2.0& ' C" R " ...." " '. SOHIO '.. ..... " PIPELINES FLOWLINES EXISTING POSSIBLE FUTURE (wi'" occns roodS) OIL GATHERING AND OIL TRANSIT LINES GAS GATHERING AND GAS TRANSIT LINES POSSIBLE FUTURE OIL AND GAS GATHERING LINES GAS INJECTION UNE FUEL GAS LINE .... Tt-3.o& 33 \ "-E A-E " ,,-£ A-E _" "",,,...."JoI. ........~ 50HI0 ./. A':£,~ ..,{') ,rrvn.... 1,,1.. OTOlSlOO f" :~~...-: .",~~ 9 10 "',....~ 11 '-- ....-Q-~ ~ ~ '\~ 5 6 '.2....000' ~~~ ( --.- --,- --.- - --1~-~ - ~ . -~ - - ~ ~-- - -- r~~ ~ -.-~_-- - ~ ~.---.- ~ - -T-·- -- ~ - ~ --: - - ---- -1 ~~ ~ -.- - - ~ ~ -.~ ~ -~~ -~ 1-- -- -- - - - ---- _n --- Ii! ! I I' ., I ' .:- I' . I I I ~ _ ~1- ---. ---' t· -'.'-- -. .., - - . -,1,1'- .~~ - -- ,--Ii ~ I + I ~ ~ /~ ! - /~ -- - r /~ f - - /~ - : ~ -~ ~ ~ , <..," \,7 J <.,,,> ! ",,- ~ - .. I ., I ! I . - t· - . - I - -- - .. - I , " ~ I "... ,~ I.,. ~ I 'I I I - ~ I i ! I I ___--1.._ ------ ---- ------ -- __..-l..._ -- --- - -- - -- T--- T I , I I I, . .' '.J. I . .. I I - .~ I I I r BOUNDARY OF COMBINED GAS CAP AND :OIL RIM PARTICIPATING AREAS 0..<,,,'<- ~,,~ , 14 A..-ÿ 15 Tr.-16 __1 ~"'...T""---r 12 13-_ 10-£ II-P Io-E ~' Io-E A-f: M-e w-e A-5-8 .. c:J EXISTING ~ POSSIBLE FUTURE PRUDHOE BAY UN I.' BúU~DA"Y 3 2 Tt-1 t . . ---..:' c:::::J EXISTING ~ POSSIBLE FUTURE DRILL PADS AND DRILL SITES A-f; 10-£ M-C tOßOO' - Q f' ," - ~ ! I. LEGEND ~[ET JULY 1 IlaSO .. ..~ - .' &-£ -AllCO-EXXON ~ -""!ilL - CM""RC"O .~ -wceIL-P"'ILL~ ~c -"C"311..-~I..WP'5-C,",,£(~"1Ii¡ """to - se.....o PE.T" ~::) A.11..., ... of - AoW(I:PADA ME~, .t ~ A..K.-.;cTTY -....f.J1,AOA I1€oS:; -::;EfTY ...... - .11(;0 -50",0-.. Ex" ,.f:!, /~ "..;i!- .. _ J,,',,'." ~~T . I ~{J~' / I.EA,f I.EGENO SIt'Ht... ..Hili" T.10-12M. R.IO-ISE. Umlal IHridiOl'l ..."., Slope of Ala.ka PRUDHOE BAY UNIT Bli. PRODUCTION FACILITIES (' I ' I I r I I I I r I I I I I r r r I I " I{ f ARCO Oil & Gas Company P.O. Box 360 Anchorage, AK 99510 Sohio Alaska Petroleum Company Pouch 6-612 Anchorage, AK 99502 July 21, 1980 Director Division of Minerals & Energy Management Department of Natural Resources 703 W. Northern Lights Boulevard Anchorage, Alaska 99502 Subject: EXHIBIT E-l PLAN OF DEVELOPMENT AND OPERATION FOR LANDS OUTSIDE THE INITIAL PARTICIPATING AREAS ~ 'PRUDHOE BAY UNIT AGREEMENT STATE OF ALASKA Dear Sir: Sohio Alaska Petroleum Company and ARCO Oil & Gas Company, as Operators of the Prudhoe Bay Unit, respectfully submit herewith a progress report for the twelve (12) months ending June 1980, as required by the final paragraph of Exhibit E-1 to the Prudhoe Bay Unit Agreement. Sincerely, G. N. Nelson . Assistant General Manager (Operations) Sohio Alaska Petroleum Company ~~à~V-Vt h P.S. Norgaard Vice President ARCO Oil & Gas Company QrV) cc Attachment (" ~ PLAN OF DEVELOPMENT AND OPERATION FOR LANDS OUTSIDE THE INITIAL PARTICIPATING AREAS PROGRESS REPORT JULY 1, 1979 TO JUNE 20, 1980 I I I I I I I I LISBURNE RESERVOIR AREA The only Lisburne penetration during the report period was by ARCO in Term Well A on Lease No. 28300 located 1250' FNSL and 22001 FWEL, Sec. 33, T12N, R14E, UPM. The well was spudded January 9, 1980 and drilled to a total depth of 97151 M.D. The results are confidential and are on file with the State Oil and Gas Conservation Commission. Sohio permitted their Sag Delta 34630 No.5 (36-12-15) located in the western half of Section 36, T12N, R15E to investigate the Lisburne Reservoir area. They will not be able to drill the well until the 1980-1981 winter season due to the rig shortage. Evaluation of the Lisburne continues to determine its development possibilities. Minimal additional seismic data was obtained. The seismic data is under study and should provide a better understanding of the structural properties and gross rock characteristics. ARCO'splans for next year involve using existing wellbores to collect additional data. There will also be an extended production test of the West Bay State No.1 well in the next few years. Additional Lisburne penetrations will be considered during the next year. I I I KUPARUK AND NORTH PRUDHOE BAY AREAS No wells have been drilled in either of these areas during the report period. Geological studies of the Kuparuk are continuing. ARCO has begun a Kuparuk development program approximately two miles west of the Prudhoe Bay Unit. This program may assist in evaluating the Kuparuk area of the PrudhQe Bay Unit. Additional seismic data will be gathered during the next year in this area. I I I I