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Home My WebLink AboutAIO 014 ) ) 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:r 0 0 I t+ Order File Identifier Organizing (done) D Two-sided 1111111111111111111 o Rescan Needed 1I11I11111111111111 RESCAN ~olor Items: o Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, No/Type: o Poor Quality Originals: D Other: OVERSIZED (Non-Scannable) ~s of various kinds: NOTES: BY: ( Mar10 '1 Date: d-- iJ 0 h D Other:: mQ 1111111111I11111111 !J /5/ V14 '" TOTAL PAGES '8' h ''1 (Count does not include cover sheet) V\AJ /5/ , r~ 1111111111111111111 /s/ Project Proofing BY: ~aria J Date: . , ð-- <l Dh Scanning Preparation BY: ~aria ) x 30 ¡: 1 Date: ~ 'it 0 0 + Production Scanning Stage 1 Page Count from Scanned File: t67 (Count does include cover sheet) VYES Page Count Matches Number in Scanni/lg Preparation: BY C<Mar~ ') Date: ~ /6, tJ(p Stage 1 If NO in stage 1 page(s) discrepancies were found: /5/ NO tMP YES NO BY: Maria Date: /5/ 1111I111I1111111111 Scanning is complete at this point unless rescanning is required. ReScanned 1I1II 111111 BY: Maria Date: /5/ Comments about this file: Quality Checked 1111111111111111111 10/6/2005 Orders File Cover Page. doc '} \1, J INDEX AREA INJECTION ORDER NO. 14 PRUDHOE BAY FIELD NIAKUK OIL POOL 1. 2. 3. 4. 5. 6. 7. November 16, 1994 November 26, 1194 December 12, 1994 December 22, 1994 January 16, 1995 January 23, 1995 August 13, 2001 Application for Niakuk Injection Order (BPXA) Publication, Hearing Notice, affidavit BP's supplemental information BP Request to delay approval BP supplemental information BP supplemental information AOGCC response to BP requests AREA INJECTION ORDER 14 ) ~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The REQUEST OF DP ) EXPLORATION (ALASKA) INC. to ) inject fluids for enhanced recovery into the ) Niakuk Oil Pool. ) Area Iqjection Order No. 14 Prudhoe Bay Field Niakuk Oil Pool March 22, 1995 IT APPEARING THAT: 1. SF Exploration (Alaska) Inc., by correspondence dated November 16, 1994 made application to the Commission for authorization to inject fluids for enhanced recovery into the Niakuk oil pool. 2. Notice of an opportunity for public hearing was published in the Anchorage Daily News on November 22, 1994. 3. No protest was filed. FINDINGS: 1. Commission regulation, 20 AAC 25.460, provides authority to issue an order governing underground injection operations on an area basis for all wells within the same field, facility site, reservoir, project or similar area. 2. SP Exploration (Alaska) Inc (SP) is operator and 100% working interest owner of the area proposed for enhanced oil recovery operations in the subject application. 3. Conservation Order No. 329 defines the Niakuk oil pool in the Pmdhoe Bay Field as strata common to the 12,318 to 12,942 foot measured depth interval in the Niakuk 6 well. 4. The area proposed for enhanced oil recovery operations in the subject application includes the Niakuk Pool Rules Area and SP-operated acreage which is outside the currently defined Niakuk Pool Rules Area. 5. Development plans for the Niakuk oil pool inelude approximately ten development wells producing through primary dcpletion for a period of one year. The primary production phase will end about April, 1995 when four or five of the original producers will be convcrted to ,vater injectors. ) ,) Area Injection Order No. 14 March 22, 1995 Page 2 6. The exact number, type, and location of wells ultimately drilled into the pool will depend on an analysis of well performance data obtained during the production life of the pool. 7. Production from the N iakuk oil pool will be commingled with that from other Greater Point McIntyre Area pools at the surface and processed at the Lisburne Production Center (LPC). 8. Produced gas from the Niakuk oil pool will be injected into other Greater Point McIntyre Area reservoirs. 9. No injection "veils currently exist in the Niakuk oil pool. BP's application includes proposed locations and mechanical configurations for currently envisioned injectors, and the locations of all existing and abandoned wells within the pool area. 10. All operators and surface owners within one-quarter mile of the currently plaIUled injectors have been notified as required by 20 AAC 25.402 (c) (2). 11. Performance data may indicate optimal injection well locations other than those proposed in the application. 12. Specific approvals to convert or drill injection wells will be obtained pursuant to 20 AAC 25.507 or 20 AAC 25.005. 13. Estimated maximum and average surface pressures for Niakuk oil pool water injection wells are 2,850 and 2,450 psig respectively. 14. Data from sandstone intervals analogous to the Niakuk oil pool reservoir indieate parting pressure gradient is in the range of .6 to .63 psi/ft. 15. The Kuparuk River Fonnation is overlain by the HRZ shale. The HRZ is a thick sequence which behaves as a plastic medium, and can be expected to contain significantly higher pressures than the underlying Kupamk River Formation sandstones. 16. Injection into the Kuparuk River Fonnation at pressures above the fonnation parting pressure will be necessary in order to maximize oil recovery. 17. Pressure tests indicate the HRZ shale has a leak off gradient of .82 psi/ft at Niakuk 5 and a fracture gradient estimated at .86 psi/ft at Niakuk 6. 18. Injection induced fractures within the Kuparuk River Fonnation are not expected to propagate through the overlying HRZ shale interval. ) Area Injection Order No. 14 March 22, 1995 Page 3 19. Analysis of water samples and open hole wireline log data indicate no freshwater aquifers, or water bearing sandstones with a total dissolved solids (TDS) concentration of less than 10,000 ppm (USDWs), are present in the proposed prqject area. 20. Injection water for the Niakuk oil pool will be 1) water from the Prudhoe Bay Unit Seawater Treatment Plant, 2) a mix of Pt. McIntyre, West Beach, North Prudhoe Bay, Niakuk, and Lisbunle pool produced water separated through the LPC, or 3) formation waters from Upper Cretaceous to Tertiary aged sandstones within the project area. 21 . Laboratory analysis and computer modeling of the chemical compatibility between the Upper Cretaceous/Tertiary formation water, Niakuk formation water, and Beaufort seawater have shown that mixing of these fluids will cause precipitation of moderate volumes of calcite and barite scale. 22. Scaling due to mixing of ÎI1iection waters will be controlled through the appropriate use of scale inhibitors. 23. The salinity of injection water from the Pnldhoe Bay Unit Seawater Treatment Plant will periodically be less than that of the Kuparuk River formation water in the project area because of seasonal salinity changes. 24. Detailed clay mineralogy investigations have detenllined reservoir intervals in the project area contain minor volumes of clay. Clay types identified are only moderately susceptible to swelling. 25. The estimated maximum daily injection rate in the project area is 50,000 barrels of water per day. 26. Waterflooding the currently defined Niakuk oil pool is expected to result in an incremental recovery of 49 million stock tank barrels of oil beyond primary depletion. 27. The operator proposes to monitor tubing-casing annulus pressures of all injection wells at least weekly to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 28. All existing wells drilled within the project area have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the project area have been abandoned in accordance with 20 AAC 25.105 CONCLUSIONS: 1. An order permitting the underground injection of fluids on an area basis, rather than for each injection well individually, provides for efficiencies in the administration and surveillance of underground fluid injection operations. ) ) Area Injection Order No. 14 March 22, 1995 Page 4 2. The area authorized for injection operations under an area injection order has no inherent relationship to, nor affect on, the area of participation formed by the mineral interest owners and approved by the state for pool development. 3. An area injection order is appropriate for the project area in accordance with 20 AAC 25.450 and 20 AAC 25.460. 4. An area injection order covering the project area will neither cause waste nor jeopardize correlative rights. 5. Specific approvals to convert or drill injection wells will be required. 6. The proposed injection operations will be conducted in permeable strata which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 7. Injection of Class II fluids at proposed pressures will not propagate fractures through the confining zone. 8. There arc no USDWs \vithin the project area. 9. Fluids injected for enhanced recovery will consist of Class II fluids. 10. Proposed injection fluids are compatible with formation fluids. 11. Well mechanical integrity must be demonstrated in accordance with 20 AAC 25.412 prior to initiation of injection or disposal operations and at reasonable intervals thereafter. 12. Tubing-casing annulus pressures, injection rates and pressures, and operational parameters will be monitored weekly. 13. The cumulative effects of drilling and operating proposed injection wells in the project area arc consistent with proven engineering practice and arc acceptable to the Commission. NOW, THEREFORE, IT IS ORDERED THAT Area Injection Order No. 14 is issued with the following rules to govern Class II injection operations in the following affected area: UMIAT MERIDIAN T12N RI5E TI2N Rl6E Sections 13, 14,23,24, 25, 26, and Section 36 N 1/2. Sections 28, 29, 30, Section 3 1 N 1/2, and Section 32 N 1/2. ) ) Area Injection Order No. 14 March 22, 1995 Page 5 Rule I Authorized h~jection Strata for Enhanced Recovery Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those that correlate with and are common to the formations found in SP Niakuk No.6 between the measured depths of 12,318 - 12942 feet. Rule 2 Fluid h~jection Wells The injection of fluids must be conducted 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; or 2) through an existing well that has been approved for conversion to a service well for injection in confon11ance with 20 AAC 25.280. Pumping of excess non-hazardous fluids that are developed solely from well operations, or necessary to control the fluid level of reserve pits, into surfaee-production casing annuli is exempted from the above requirements. Rule 3 Reporting the Tubing-Casing Annulus Pressure Variations The tubing casing annulus pressure of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70%) of the casing's minimum yield strength. Rule 4 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, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength, must be held for at least a thirty-minute period with decline less than or equal to 10%) of test pressure. The Commission must be notified at least twenty-four (24) hours in advance to enable a representative to witness pressure tests. Rule 5 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and obtain Commission approval to continuc injection. Rule 6 Administrative Action Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not rcsult in an increased risk of fluid movement into a USDW. Area Injection Order No. 14 March 22, 1995 ) ') Page 6 DONE at Anchorage, Alaska and datcd March 22, 1995. ( l :: ,--- David W. Jocainna ~P¿J. ~,. d'/ · ¡A ({{1L~- ()/tl;/t; C-- uckerman Babcock, Commissioner AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (Le., 10th day after the application for rehearing was filed). ) ) @c-:1~~-e @ _ 1, _ 1, ~ f JL~l,~~~!Æ TONY KNOWLES, GOVERNOR ~ ALASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. yrn AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 14.002 Anne L Shaw BP Exploration Alaska, Inc. PO Box 196612 Anchorage, Alaska 99519-6612 Re: Interim authorization to inject in Niakuk well NK-28 Dear Ms. Shaw: BP Exploration (Alaska) Inc., ("BPXA") by letter dated August 13, 2001 requested authorization for interim injection into well NK··28 to allow for water injection while gathering data and information to update the administrative record in support of the expansion of AlO 14. On August 20, 2001, the AOGCC provided BPXA with interim approval for injection operations into NK-28, pending submittal of technical information requested by the Commission in support of expansion of AlO 14. Expansion of AlO 14 is necessary for long-term allowance of water injection to recover greater volumes of oil from the Western Area of the Niakuk Oil Pool. BPXA submitted a revised application with the additional information requested (received by Commission October 26,2001). We understand that you will be providing clarification of certain items as outlined in e-mail to you from Jane Williamson dated November 1, 2001. The application will be complete with submittal of that infonnation. The Commission authorizes continued injection into NK-28 for enhanced recovery operations. This administrative approval will expire on February 1, 2002. Amendment to AIO-14 for expansion of the Niakuk Area Injection will be fmalized prior to this date. DONE in Anchorage, Alaska and dated Novem fl2 f. aniel T. eamount, J r. Commissioner ~~~dw\,'~l.¡ Cammy ~chsli Taylot) Chair ~J\J\ ~ ~uY)2f'''' Julie M. Heusser Commissioner BY ORDER OF THE CO~~SION 4i~~-OJ1... ~1A~ ~7~~~~'~:O ~~. ~ V/ ". :j,? \. ~ j ( ! /~". (;'1, :)\ ~jl' \, r.;~. ~ \ ! f I ~ ' ..,,;~. T-:;? "" (.... I ...~"'-..... \1i,,,..'X .~. ~~" ~.h;~('·".':<:._ _..' .~~\;r \ ¡~ ..'.-' ..... '" -. " ... ~ J. "st'" X' :', '.'.:.~,...:..'..',:.;.:.'.:,:....;.......;,..~.:',.,:~.:,:.t) "J.~'~' ~~::~..:.'~':':~",~:',~,~: .~. , _ .::.:. ~ ; \ ) ) ~~~~'E : F !Æ~!Æ~'~~:Æ ALASKA. OIL AlWD GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. 7"i AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 14.001 Re: Request for interim authorization to inject in Niakuk well NK-28. Anne L Shaw BP Exploration Alaska, Inc. 900 East Benson Boulevard PO Box 196612 Anchorage, Alaska 99519-6612 Dear Ms. Shaw: BP Exploration (Alaska) Inc., ("BPXA") by letter dated August 13, 2001 requested authorization for interim injection into well NK-28 to allow for water injection while gathering data and infonnation to update the administrative record in support of the expansion of AIO 14. Expansion of AIO 14 is necessary for long-tenn allowance of water injection to recover greater volumes of oil from the Western Area of the Niakuk Oil Pool. V oidage replacement by waterflood in Segment 3/5 of the western portion of the Niakuk Pool is not being maintained. BPXA proposes to convert well NK-28 to injection status. The well had produced 2 l\.1J\.1BO, but has watered out. Increase in water injection will improve pressure support in this area and will increase overall production and reserves. ill addition, the conversion allows better utilization of water production into the LPC, and in the near tenn, will alleviate production impacts associated with planned workover of Cretaceous water disposal well LPC-02. BPXA has assured the commission that additional infonnation in support of the request to expand AIO 14 is forthcoming. However, in the interim, the commission authorizes the use ofNK-28 for injection for enhanced recovery operations consistent with AIO 14. This administrative approval will expire on November 1, 2001. ~.~~ Cammy Oechsli Taylor Chair , (2~~9ñ.~ Daniel.T..Seamount,Jr. .~. 'm\ ,1', f~~ CommISSIoner ~\ .. / ~&\þ'Ì\ ..\~,~ \ " . ". ~-"'.. ~- . f·" .4¡;;,t.1 /"""'\1-~~"~' ~ . ~~~¿;-¡'~;'.:'" n·~d·:./~,h.". (!þ. A " I . " ;'' ·1 J)i r·~,·.', "l, ,.,f . ¿;? Îi ~,\. ."¡..........:.:,.. ' ?<-' : ~ ,.., 1 F! ¡: . )?I:<~J.:.¡. '~ , I" ~ ,,;,~ ( A:')o" J ;". '- '. 1\'· ,..'; ·.·,,~'I;·I··· .~ . 9. ~!'\~4 (/I,:\~f:;~~~~ ~ \'~~ i,~·'·"·!(·~4~\~~¡:J~~ Õ' \ ..t.. ~\'i~{ff';:~;~N0~~;' ~ \. 'to.:. ~". 4).,_~~~o:.'!J '\.è:--"", '\.,. V ~!&lJIJS~9 l;··~1"ìON CO~\~ DONE in Anchorage, Alaska and dated August 20, 2001. BY ORDER OF THE COMMISSION #7 bp ) ) 0·:····"""':'·, ',1, ',1.' ::", "~ r·' ~f:, ·..·:.:",I'i":·':':,¡'.t, BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 August 13, 2001 Alaska Oil & Gas Conservation Commission 333 W. ih Avenue, Suite 100 Anchorage, Alaska 99501 Attn: Cammy Taylor, Commissioner Jane Williamson, Engineer Jack Hartz, Engineer Bob Crandall, Geologist Re: Request for~njection and Response to 8/1/01 AOGCC Request for Additional Data to-Support the Revised Niakuk Area Injection Order 14 BP would like to request interim permission for 60 days to convert well NK-28 to water injection while we collate the data you require for the Revised Area Injection Order (AIO). As per our telephone conversation on August 7, we are supplying the information below to provide a better understanding of why a timely conversion is desired. The Niakuk accumulation is separated into Eastern and Western areas due to a complete loss of Kuparuk sand across the mid-field high (see Figure 3, Revised AIO first draft). In the Western accumulation, separate OWCs and production history indicates that Segment 1 is separated from Segment 3/5 (see Figure 4, Revised AIO first draft). This results in three main Niakuk pools: Segment 1, Segment 3/5, and Segment 2 (East Niakuk). Attachment 1 in this note depicts a net oil pore foot map for Western Niakuk, the sealing fault that separates Segment 1 from Segment 3/5, and the area of expansion for the Revised Area Injection Order. Production at Niakuk has been sustained by pressure maintenance. In Segment 3/5 this support has come from water injection in NK-15. Simulation work has demonstrated an opportunity to improve the depletion strategy for Segment 3/5 and advance the waterflood into more of a peripheral pattern. The first step in this involves converting NK-28 to injection. Although this well produced close to 2.0 MMBO, it cut water from its initial production and is currently watered out. Other conversions will be considered in the future to optimize recovery. RECEIVED AUG 1 3 2001 Alaska Oil & Gas Cons. Commission Anchorage ) ) Page 2 It is evident from material balance (see Attachment 2) that Segment 3/5 is in need of additional injection. The recently redrilled NK-08A has increased off-take by over 4,000 BOPD from the heart of Segment 3/5 (see Attachment 3). In addition, injectivity at NK- 15 has declined since being converted to produced water injection approximately one year ago. Included for your reference is a diagram showing the relative volumes of production and injection that are desired once NK-28 is converted to injection (see Attachment 4). Without injection support from NK-28, reserves will likely be left behind. Any additional water we can inject at the Niakuk field directly increases our water handling capacity at the LPC, thus boosting our overall GPMA oil rate. Having NK-28 on injection during our planned rework of our cretaceous injector LPC-02 will greatly alleviate the associated production impact. This work is scheduled for early September. Within the agreed 60-day period, we will provide you with the additional information for the revised Area Injection Order per our conversation on August 7. This includes the four geologic reservoir maps for net sand, porosity, hydrocarbon pore foot, and water saturation, as well as a more complete write up of the requested sections in your letter of August 1. Please let us know at your earliest convenience when we may commence injection into NK-28. Sincerely, ~y~ Anne L. Shaw GPMA Team Leader cc: M. Cole - BP M. Evans - ExxonMobil J. Johnson - Phillips Alaska, Inc. M. Johnson - ExxonMobil G. Limb - Phillips Alaska, Inc. - 40000 Nlakuk Reservoir Material Balance, Segment 315 35000 30000 -Injection (ReD) -~Flux(RBD) ~ Pressures 8000 - 7000 ~ GOR(scfpbo) 6000 25000 ~ 5000 œ: 0 i ~ <:> z ~ i ~ ~ II) z (¡') «i 20000 4000 ~ œ: Q.. >- (.) t 13 g.¡ ::ii 15000 3000 10000 5000 o Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jaln-98 Jan-99 Jan-OQ Jan-01 2000 1000 o 20000 18000 16000 14000 12000 10000 sooo 6000 4000 2000 o Jan-93 Niakuk Production History, Segment 315 -Oil BOPD -Water B\I\IPD -Gas MCFPD - Jan-94 Jan-95 Jan-96 Jan-S? Jan-98 Jan-99 Jan-OO Jan-01 . ..... ..... , :x 2 . .....("t') ID...... CI..' .....:x ......2 , :x. 2 . . Injection . Production RBPD --~ '""-- -- ......-....-..-........ N . en ...... I :x z . #6 ) ) BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 January 23, 1995 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Supplemental Information - Niakuk Area Injection Order, Possible Cretaceous/Tertiary Source Water Dear Mr. Johnston: The water sample analysis provided to the Commission on January 16, 1994, from well DS 15-6 was obtained from the same stratigraphic intervals that are potential source water zones at Niakuk. It is therefore believed that the sample provided is a likely representation of the waters in the intervals from the Cretaceous and/or Tertiary that are identified on the attached Niakuk #1 log froIn measured depths 3695 to 7934 feet (Sagavanirktok SV5 through Lower West Sak Sands). As stated in our January 16, 1995 letter, in the event it was decided to inject Cretaceous/Tertiary water into Niakuk, BP would design and implement a program as required to minimize detrimental impacts. The first step in this process would be to sample and analyze the specific potential source water zone(s) frorn a Niakuk well. Please note that our January 16, 1995 letter referred to "Cretaceous water" . We would like to ammend the reference to "Cretaceous/Tertiary" . Please feel free to contact me or Bob Janes if you need any additional information or have any questions. Sincerely, ¡J~~. W.L. Bredar Manager, Geosciences Greater Pt. McIntyre Area, Alaska RECEIVED JAN 2 6 1995 Aiaska Oil & Gas Cons. Commission Anchorz ;p #5 ) ') Ei BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 January 16, 1995 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Supplemental Information - Niakuk Area Injection Order Dear Commissioner Johnston: As you are aware, BP Exploration (Alaska), Inc. requested the Commission to delay issuing the Niakuk Area Injection Order until January 17, in order to allow us time to evaluate use of Cretaceous water as a possible source of water for Enhanced Oil Recovery in the Niakuk Injection Area. BP currently has no firm plans to utilize Cretaceous water, but wanted to take this opportunity to obtain approval of this water source in the Injection Order for increased flexibility in the future. Attached is a report on an evaluation of Cretaceous water injection conducted by Daniel Hsi, a senior production chemist in our Corrosion, Inspection, and Chemical Group. The report concludes that injection of Cretaceous water does increase scale formation tendencies, but that proper use of chemical inhibitors both during the initial stages of injection and in the production wells after breakthrough can effectively mitigate any potentially negative effects. In the event it was decided to inject Cretaceous water into Niakuk, BP would design and implement a program as required to minimize detrimental impacts. Please feel free to contact me at (907) 564-4623 if you need any additional information or if you have ny questions. S~' Robert W. Jan s Manager, Reservoir and Production Engineering Greater Pt. Mcintyre Area Attachment cc: A. N. Bolea rl if- I/. ile II.) í< 10. ß. L L{ k. (:)/\..) 4' I-)/}N/éi- ¡-¡,S'.z (/L.t'71Tì-IS"i ("¡P¿. /2.""'1 Cl~) RECEIVED JAN 20 1995 Alaska Oil & Gas Cons. Commission Anchora. ~0 ) ') NIAKUK W A TERFLOOD INJECTION WATER COMPATIBILITY STUDY Daniel Hsi Corrosion, Inspection, and Chemical Group SUMMARY The Cretaceous formation is being considered as a potential source for the Niakuk waterflood project. The chemical compatibility between Cretaceous formation water with Niakuk formation water and Beaufort seawater was evaluated using a scale prediction computer model. Model calculation results show that mixing of Cretaceous water ,vith Niakuk formation or Beaufort seawater will cause calcite and barite scales to form. The scaling problems are considered moderate. They can be controlled by adding scale inhibitors during the initial startup of Cretaceous water injection and also during the switching back to seawater injection. INTRODUCTION BP presently plans to inject seawater or produced water into the Niakuk field over the project life. However, in order to maximize options for potential sources of water for enhanced oil recovery, an analysis of chemical compatibility between Cretaceous water and either seawater or formation water has been conducted. Cretaceous well water was considered as one potential source and operation engineers want to know the chemical compatibility between Cretaceous well water and Niakuk formation water. A scale prediction computer model (SPAM3 ) was used in this study to predict the chemical compatibility between Cretaceous well water and Niakuk formation water. This model has been found to match field results well in the Western Operating Area of Prudhoe Bay and Endicott fields in Alaska, and in the Forties and Miller fields in the UK. FORMATION WATER COMPOSITIONS A Cretaceous formation water composition was provided by the Prudhoe Bay Lab. The water sample was collected on Feb. 15, 1990 at DS 15-6 well. A Niakuk produced water composition was provided from sample analysis done on produced water from Niakuk 8. Chemical compositions of these two waters are listed in Tables 1 and 2. Two possible scenarios were considered in the computer model calculations. In the first case, it was assumed that Cretaceous water was injected initially and will mix directly with Niakuk formation water downhole in the injection well. In the second case, it was assumed that seawater has been injected for a significant period of time prior to REGEIVED JAN 2 0 1995 Aiaska Oil.&, Gas Cons. Commission ) ) Cretaceous water injection. This results in the injected Cretaceous water contacting injected seawater in the near wellbore region of the injector instead of contacting formation water as in Case 1. Case #1 Direct Mixing of Cretaceous Water with Niakuk Formation Water In Case 1 the injected Cretaceous water mixes with Niakuk formation water in the near wellbore region upon the startup of Cretaceous water injection. The bottomhole flowing pressure (BHFP) is estimated to be around 6000 psi. The initial bottomhole temperature will be close to the reservoir temperature of 189°F. As more Cretaceous water is injected, the bottomhole temperature will soon cool down to close to the injection water temperature of 70 of. Scale model predictions were carried out for three different temperatures of 189°F, 100 of, and 70°F. Calculation results show that mixing of these two waters will cause barite (BaS04) and calcite (CaC03) scales to precipitate. Other potential scaling minerals such as gypsum, celestite, anhydrite should not precipitate under any of these mixing conditions. The calculated saturation ratios of barite and calcite are plotted in Figures 1 and 2 for different mixing ratios. The worst scaling conditions occur at a mixing ratio about 40- 50% Cretaceous water. The worst saturation ratio for calcite is 24 and for barite is 75. These are approximately 2 to 3 times higher than those between Niakuk formation and Beaufort seawater and also between Endicott or Prudhoe Bay formation water and Beaufort seawater. This suggests that slightly more severe scaling problem may occur during Cretaceous water injection. However, the calculated saturation ratios are far less than those observed in several North Sea fields such as Forties and Miller fields where the barite scaling is a problem and the saturation ratios are typically as high as 400 to 800. The model also calculated the amount of scale precipitation under thermodynamic equilibrium conditions (this is the worst case scenario since chemical equilibrium rarely occurs in actual field conditions). The model predicts that approximately 120 mg/L (42 Ib/l000 bbls of water) of barite and 850 mg/L (294Ib/l000 bbls of water) of calcite will precipitate under the worst conditions. Again, this amount of scale precipitation is 2-3 times higher than those predicted between Niakuk formation water and Beaufort seawater or between Endicott or Prudhoe Bay formation water and Beaufort seawater. The anloun t of barite preci pi ta tion is 3 to 4 times less than those predicted for the Forties or Miller fields where severe barite scaling problems have been reported. In summary, the scaling problems of mixing Niakuk formation water and Cretaceous water are considered to be moderate. However, they can be effectively controlled by adding scale inhibitors in the injection Cretaceous water especially during the first one or two days of injection startup. Scale inhibitors should be also added in the seawater for one or two days when switching back to seawater injection. REGEIVED JAN 2 0 1995 Alaska Oil & Gas Cons. Commission Anchort, ) ) CASE #2 Injection of Cretaceous Water Into Niakuk Formation That Was Previously Flooded With Beaufort Seawater The second case assumes seawater injection has been ongoing for a significant period of time. In this case the pore space surrounding the injector wellbore should be saturated with seawater, creating a condition where Cretaceous water contacts seawater in the near wellbore area of the injectors. The bottomhole injection temperature should be close to the injection seawater temperature of 80 of. Model calculations were repeated by mixing Cretaceous water and seawater at bottomhole injection pressure of 6000 psi and temperature of 80°F. Calculation results are plotted in Figures 5 and 6. Only barite scale will form under these conditions. However, because of the high sulfate ion concentration in the seawater (2960 ppm) and high barium ion concentration in the Cretaceous water (137 ppm), the barite scaling problems would be significant compared to those observed during seawater injection into Niakuk Formation (Figures 7 to 10). The worst case saturation ratios of 800's are approaching those observed at the North Sea fields. However, the amount of barite scale precipitation, 200 mg/l (69Ib/1000 bbls of water) is about half of that predicted for the North Sea fields. This barite scaling problelTI is considered moderate to moderately severe. Scale inhibitors would be required during the initial startup of Cretaceous injection, nominally for the first one or two days, or during the switching back to seawater injection. CONCLUSIONS AND RECOMMENDATIONS 1. Mixing of Cretaceous water and either Niakuk formation water or seawater will cause barite and calcite scales to form. 2. Based on saturation ratios and the amount of scale precipitation, the scaling problem is considered moderate to moderately severe. It will be more severe than those observed between Niakuk formation water and Beaufort seawater or between Endicott or Prudhoe Bay formation water and Beaufort seawater. However, the scaling problem is less severe than those observed at Forties or Miller fields. 3. Scale inhibitors should be added in the Cretaceous water during the first one or two days of Cretaceous water injection to minimize scale buildup in the near injection wellbore region. Similarly, scale inhibitors should be also added in the seawater when switching back to seawater injection. If seawater injection starts prior to Cretaceous water injection, scale inhibitors should be added in both waters during the first one or two days of the startup of seawater injection or Cretaceous water injection. If long term injection of Cretaceous water is continued beyond breakthrough, barium sulfate scale precipitation is likely to occur in producers. In this event the operator will implement a scale inhibitor squeeze treatment program in production wells to mitigate scaling problems. RECEIVED JAN 2 0 1995 Alaska. on & Gas Cons. Commission Anchor, '. ) TABLE 1 ) CHEMICAL COMPOSITION OF CRETACEOUS FORMATION WATER ARca ALASKA PRUDHOE BAY CENTRAL LABORATORY ANALYTICAL REPORT ****************~**************~******.**** (Rr~JUE NUMBER: 694 ARCHIVE VOLUME:90 F AC I L I T'Y: f) r i 1 , :=. i t III ~~ 1 S Cc)MPHt~Y ~ ARCO SAMPLE: NtJt18ER: 1 :?~41 SAMPLE DATE/TI11Ë.~ Q21S90/09: 00 S~~MPl.E TVPE; PRODUCE:D ~)('1'r E R SAMPLE PCII'-T./1'1¡;:TE:R ~~= D5 ~~1;-~ SAMPLE DESCRIPTION: CRËTAC~OUS WATER ~ r R~T s~~r1PLE R~QUESTOR: J.8RADY ATO-l~O~ /' DrrfPt" I H(.(T I C"JH l)AI I II=' ~~~--~~~~~._-=========e......p=a===_~.....======~~ø...~ma=c=~=~B~====~~~==aEG. ~.;; T ATU~3 .-...-----------... ., UHITS .... - - - - - - - - - .... .... oil!' ... _ ... ..... ,.,... - - - _ _ _ ... _ _..., .... ... - _ _ _ _...' .. WIll _ ..... ... .- _ .._ _ .... ,'.. ." M"'\ "" _ _ _ _ _ pH TUldl Di5~olv~d Golid~ R~&i~livil~ @ 60 d~grC~5 F. Sod i urn Ca lc iurn M!lgn"!!ium Iron 8!!Jriwm Strontium Lhloride Hyd rox~) I ,Carbonate Blcðrbonate Sulfðte Fluorid~~ SiJicon Aluminum COMt1ENTS: 6.4 4701:15. 0.178 l~eSO. 1~6 0 . 9904 12. 13;". 6 (I. 29439. O. O. )48. 0( 1 . c; 1 . ~. <.1.00 Mg./I OHr1-- M Mg"'L Mg/L r19./L. Mg./L r1gJL Mg....L Mg ,/L Mg"L M 9 ,.í L M9/L r1g I'L t1':;1/L t1g/L r"1çV"L PH & ALI<'ALA I HI TY MEASURED ON ~H~Mt--'L'=- COLLEC.TED IN P ISTO'~ C'(L r NDf.· R. SULF~TE ANALYZED BY 8P LAB. TDS IS A CALCULATED VALUE. Completed by Reviewed b)l F . s. 4F:~ DR [l-L. S 1 TF. SlIPERI...! I SOR ~13 OPER ENGINEER COORDINATOR t24 OPER ENG CE~TRAL FILES ATO-l~29 LAB F1LE -P-..--.--.... .....,. '-- --.-- - WI REL I NE SUPERU I SOR P81"1[ '2 J t;. T. CAHALANE ATO-1734 R. 51" EUEt~S AT D- 1 (:. ~. ~:t L.L. HOWARD ATO-loSS RECEIVED JAN 2 0 1995 .\taska Oil & Gas Cons. Commission Anr'1or; TABLE 2 ) CHEMICAL COMPOSITION OF NIAKUK FORMATION WATER pH Calcium Magnesium Sodium Potassium Strontium Barium Iron Bicarbonate Chloride Sulfate Total dissolved solids 7.0 95 mg/l 22 mg /1 9925 mg/l 147 mg/l 16 mg/l 1.7 mg/l 5.2 mg/l 3870 mg/l 11440 mg/l 190 mg/l 25712 mg/l RE(EIVED JAN 2 0 1995 ¡\Iaska Oil & Gas Cons. Commission Anchon: ' 100 90 80 U) 0 70 ~ a: z 60 0 ~ 50 a: ::) ~ 40 U) W I- æ 30 « m 20 ;:Þ 10 p:;- en fS ;:0 0 ~ § c...... $Ï!C' J> ïT1 0 >Cj') z n ::2 þ) g.Ch N m o C") 0 - :::1 0 , ::2 < ~Sfl W C':i <.D rT1 0 CT1 3 0 3 ëir en õ' :::J FIGURE 1 SATURATION RATIOS OF BARITE IN MIXTURES OF NIAKUK FORMATION WATER AND CRETACEOUS INJECTION WATER 70 of IBHFP = 6000 PSI. --------- ......... / .... .......... ~ .... / " , .... " / .... , " / .... 100 of " , / ~~¡"~h~~~<:-"--_."'______ .... , 189 of .... , , I / ..-- ---- --- ----------- -~--- -...- --- --... --... --.... ~ r# 10 20 30 40 50 60 70 80 % CRETACEOUS WATER - .... , .~ .... 90 100 100 . "-,,,' ~ % CRETACEOUS WATER 90 60 50 40 30 20 10 80 70 70 of ------ , , , , , , , , , I , , , , ......----------- .__-_-_'O:<:«-"<P....-<:<C-~<:.,:«,;~O'9""_;;.-----·--'O:'!:--":·,.·~......-.;_:--~~_!',;y_...."'.:!J:!:«;:~____- 1 00 of .... " 'II¡, 'lito " " "110 -- -- , .... .,. .... , ......... tII' , "'" ""'" ... --"'511III: _JIIØ!-- """...- 189 of IBHFP '" 6000 PSI. AGURE2 SATURATION RATIOS OF CALCITE IN MIXTURES OF NIAKUK FORMATION WATER AND CRETACEOUS INJECTION WATER o 24 22 20 (J) 18 0 i= <c 16 0: z 14 0 ~ 12 0: ~ l- e:( 10 (J) w .... 8 Õ ..J e:( 6 0 4 :¡;;.- 2 "p.; ~ ?Co QJ g e..- rn þ {20 ::z (':"\ >c;:> rv M"1 =' ~ o en -- ::r"" 0 <:::. ~ 0 ~, :::I .--A ': sn (..Q rn c.D C') C7'\ 0 (:) 3 ê. (f) !!!. 0 ::J ",..,. FIGURE 3 AMOUNT OF BARITE PRECIPITATION IN MIXTURES OF NIAKUK FORMATION WATER AND CRETACEOUS INJECTION WATER 140 120 '_7 - ..J m 100 E - 189 of z o ~ .... c:: õ w a: c. w .... æ <C m .~- ..Y ~ 0 CJ' ~ '/0 ~ c- O J:."? rn $20 --> () » G') :::I p) rn (") (í) N ::r 0 ("') 0 .- ~ 0 < :::I y> ~ -' u:> C') <.0 rn 0 ()i 0 S :3 Cij" (I) ër ::J 1 0 20 30 40 50 60 70 80 90 100 0/0 CRETACEOUS WATER 1000 900 - 800 -I t» E 700 - z 0 ¡:: 600 <C .... is: 500 Õ w a: 400 c.. w .... Õ 300 -I <C 0 200 RGURE4 AMOUNT OF CALCITE PRECIPITATION IN MIXTURES OF NIAKUK FORMATION WATER AND CRETACEOUS INJECTION WATER , , , , , , , , , I , - , , , , , -; , , , , 18,» of fill' -_ #,fIII''''''''- --..., 100 of , , " , .. '" .. "" , - .... , .. , " " "'- ... " .. , .. , .. .. , " , ... , .......... III! ~I ~ ! 100 :Þ ~- (ji '" 0 Ø;! ;;C g C- $20 J> íM 0 >Ci) ::z n ::I ØJ N m g.en o C") 0 -- ~ 0 < 1'1 :::J --" ~ t..D C") f...O rn 0 c..n 3 0 :3 ëi)" en õ' =' ~ - -----.....- -- ..... .... 70 of BHFP = 6000 PSII 10 20 30 50 0/0 CRETACEOUS WATER 40 .... 60 70 80 90 ~ 100 900 --------~- , ~ 800 /' "" '- , " 700 /';' 80 of ... ......... BHFP '" 6000 PSI. , , / ' 600 , , / ' 500 ' \ / ' , \ 400 / , \ , / \ 300 \ , / \ 200 - \ ~ , / \ 100 \ I o tl \ 0 1 0 20 30 40 50 60 70 80 90 100 % SEA WATER FIGURE 5 SATURATION RATIOS OF BARITE IN MIXTURES OF CRETACEOUS WATER AND INJECTION SEAWATER þ p; (/) ?C ~ g <::..- rn J> $(0 :z (":"\ >Ci) ("'0 m ::::J Ø) (") en - ::r~ 0 < ~ 0 !', ::::J -" ~ u:> rn <.J:) ~ Q'\ '=' 0 3 ë. en ~. 0 ::I en o !i a: z o !i a: ::J ~ en w l- i%: « m 100 60 50 % SEA WATER 40 30 20 90 80 70 .., , .... , , , , , '----,,' , " , , , " , , .... " .... , , , , " .... " .... " .... " IBHFP", 6000 PSI. 80 of .... " " ...., -....,..-' FIGURE 6 AMOUNT OF BARITE PRECIPITATION IN MIXTURES OF CRETACEOUS FORMATION WATER AND INJECTION SEAWATER , ~O (::'\ 0 10 rT1 - < m CJ , , , , , , , , , , , 40 - - ..J -- C) E - 160 z o ¡:: c:( ~ ã: 120 - Õ w c:: c.. w ~ 80-- æ c:( m 200 240 ~ ~ UJ ~ g c..... ::t> $20 ::z :Þø :::::I ØJ N (") en ::rC') 0 ~ 0 tI' ::s ~ ~ c..o C') c..o 0 Qi 3 ª. en ~. 0 ::s 100 90 .... -~ 80 60 50 % SEA WATER 30 20 10 40 70 - .... -----------....-----....--............---....----- ---- -- 189 of " .... ....~.;:wjo;.;:w·-----·--·o!:·~-:·:-.;;w-·----------¥.~~.,.~....-:~~«":---.-.,;.,;.;:-:-:>Ø~_..-_:;.w;.:'='*"_-__. " .... , " 100 of - .... ......... - ........-......... ------- , - -----~ -- 70 of BHFP = 6000 PSI. -'" RGURE7 SATURATION RATIOS OF BARITE IN MIXTURES OF NIAKUK FORMATION WATER AND INJECTION SEAWATER ~ 5 0.' (fl ~ - - - g C- ?O 0 $i1C J> ïM »'" z n 0 :::J þJ §.cn N ïM o ~ 0 -- PJ g < en --'" <..0 ~ <..0 r-n 0 CJ1 3 0 3 w' (J) õ· =' , ", 50 45 40 en 0 - 35 !cc a: Z 30 0 ~ a: 25 :J I- ~ 20 w l- ce 15 « m 10 , » 63'" U"J " ØJ ê c...... Qo J> J> ø ::z ::J OJ C') N ~ rn 0 '"' <:) -.¡: 0 PJ ::J ~ ë:D '"' <.0 0 Qi 3 3 w· en õ· :;, 24 22 20 en 18 o !i a: 16 z o 14 ~ a: 12 :J !i en 10 w I- 8 ...--- Õ ...J ~ 6 4 - - -- ..,. FIGURE 8 SATURATION RATIOS OF CALCITE IN MIXTURES OF NIAKUK FORMATION WATER AND INJECTION SEAWATER 189 of -....--...-------iBIIS --- --- -...- """ ........""" =- """ =- .... ..... ..... 100 of '"'" .... .... 2 :::::."_~-^=-<.,-:.'--v=^'-.:.~-.:»»'=---"--:-----~~-:-W^=-:'"-:"'-~;F·'~-:...:~---:'---'- _n___=_ -- =-<V"*_-._-~___ ------ ?C 0 rTI 0 n iM - < m 0 1 0 20 40 60 80 70 30 50 0/0 SEA WATER .... 90 .... -- ---- """ ""'" .... "!!L- 100 100 90 80 70 60 50 0/0 SEA WATER 40 30 20 10 o ;Þ ~ ø '" !:P A:J g c....- Qo J> rn >ø ::z: r\ ::J Ø) g.r.n ('\.) r-n oC') 0 - P3 0 _ ::J < C" r.n W -;> . C') <.0 m 0 (J"1 3 0 :3 ëñ en õ' ::I """"".... .... _Y:-:^V'~: .~wn___.,_ m"_^~, '" ~^n_:::--':'n'n:'Y^w"«, ""<WM--"V. u_u___M ::J. ~ 18 C) E - 16 z o ~ 14 ~ D.. 12 o w a: 10 D.. ~ 8 ã: ~ 6 4 2~ o 189 of I 100 of 70 of ~' BHFP '" 6000 PSI. 20 '~ 22 24 FIGURE 9 AMOUNT OF BARITE PRECIPITATION IN MIXTURES OF NIAKUK FORMATION WATER AND INJECTION SEAWATER FIGURE 10 AMOUNT OF CALCITE PRECIPITATION IN MIXTURES OF NIAKUK FORMATION WATER AND INJECTION SEAWATER 1000 900 - 800 ..J 1:» E 700 - z 0 ¡:: 600 <C to- õ: 500 Õ w a: 400 a.. w to- Õ 300 ..J <C -- () .,. 200 --,¡ø fill 100 --- - 2:: Po' (J) 0 ~ ?C g c..... » rn 0 QCI :J>C) ::z (J ::I Ø) g.en ("IV r-n o n 0 - @ g < ">j 51' -'"' c.o n c.o r-n 0 c.n :3 0 :3 ëñ' en õ' = 189 of .....___5!iI555K!m_.. .... - - -- - -- .... .... .... ....... ... ""'" - .... ",. fill .... ",. 100 of .... ",. ø .... .... 'III¡, ^"'·_-.-""'....v~--'---'-·_-_·_-_-;;_-_·_-_-··_,.v_;,.:----:¡.n--···;,. 'III¡, .... .... ~---------- .... - -- - -- - --- 70 of 10 20 30 40 50 % SEA WATER 60 70 80 .... 90 , -tun .... . . .--- "'-' ... .... .... 100 #4 't ) ) BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P,O, Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 December 22, 1994 David W. Johnston, Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr Anchorage AK 99501-3192 Dear Commissioner Johnston: Please delay approval of the Niakuk AIO until January 17, 1995. The additional time will allow us to review Cretaceous injection issues. By January 17, we will either submit a request to modify our original Ala to allow Cretaceous water injection or request that the original Ala be approved as previously submitted. Thank you for your assistance. Sincerely, f1;1 ~ Ff!)fI" R. W. Janes Reservoir/Production Engineering Greater Pt. Mcintyre Area ce.,' F/¿£ ~"llro¡VK /<-l/fJT II ¡Jß RECE\\JEO JAM - 6 1995 1" 0'" & Gas Cons. Commission f\\asl\a Anchora~'~ #3 ~1'! ') ) ~1~ æJ BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 December 12, 1994 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Niakuk Area Injection Order - Supplemental Information Dear Commissioner Johnston: Please find attached additional information in support of BP's Niakuk Area Injection Order application. This information was recently requested by AOGCC staff. Please feel free to contact me at (907) 564-4623 if you need any additional information or if you have any questions. s.¡,:....(..n.·6"G reIY.,f~/ )1 ~/'i I, rJL/ kObert~. Jan# Manager, Reservoir and Production Engineering Greater Pt. Mcintyre Area Attachment cc: A. N. Bolea, BP Exploration (Alaska), Inc. !'liE-.J /. 'Iò Il/k' RECEIVED DEe 1 6 1994 Alaska Oil & Gas C AnChor~n,~' Commission ) ) NIAKUK AREA INJECTION ORDER APPLICATION Supplemental Data SECTION L 20 AAC 25.402(c)(11) The following data is supplied as a supplement to that contained in the original Niakuk Area Injection Order application made by BP on November 16, 1994. This data is supplied in response to a request for additional information on the integrity of the confining interval above the Kuparuk reservoir, which is the HRZ interval. 1) NK-5 HRl Leakoff Test 1 Niakuk 5 was drilled in March 1985 within the proposed Niakuk Injection Area Boundary. The 9-5/8" casing shoe was set in HRl at 9,770' MD. A leakoff test was performed at 15.7 PPG equivalent, corresponding to a 0.82 psi/ft. gradient. 2) NK-6 HRl Integrity Test2 Niakuk 6 was drilled in January 1986 within the proposed Niakuk Injection Area Boundary. The casing shoe was set at 12,041' MD and a mechanical integrity test was performed at 12,049' MD in the HRl to 1500 psi, equivalent to 13.5 PPG. The actual formation fracture pressure was estimated to be 16.6 PPG, which corresponds to a 0.86 psi/ft gradient. Sunlmary Available data for the overlying HRl interval above the Kuparuk indicate a fracture gradient in excess of 0.82 psi/ft. Additionally, in the nearby Pt. Mcintyre field reservoir mechanical properties log data for the HRZ indicate the same fracture gradient of 0.8 to 0.9 psi/ft. This is significantly in excess of the expected fracture gradient of the Kuparuk interval of 0.6-0.65 psi/ft based on data from the Kuparuk horizon in the nearby West Beach and Pt. Mcintyre fields. It is also significantly in excess of the average and maximum expected injection wellhead pressure during enhanced recovery operations. 1) Leakoff data for NK-5 was listed in ADT Well Summary Report by NL Baroid March 1985. 2) Integrity data for NK-6 was listed in the ADT Well Summary Report by NL Baroid April 1986. RECEIVED DEC 1 6 1994 A~aska Oil & Gas Cons. Commission Anchorz. #2 ) STAR PUBLISHING CO., INC. 16941 N. Eagle River Loop Road Eagle River, Alaska 99577-7499 ) PHONE (907)694-2727 FAX 694-1545 ~ AD bC~ 'ffl- Dd-6-l4-Wb AFFIDAVIT OF PUBLICATION UNITED STATES OF AMERICA) ) STATE OF ALASKA )ss ) THIRD JUDICIAL DIVISION ) BEFORE :ME, the undersigned, a Notary Public, this day personally appeared ~-(JJ( ~ II'h, l-"fu fLfl..tV' who, being fIrst du»: ..s:,o,rn,, ' according to la~,says that he/she is the rA- t- I ((J 11Attt'1(M~e"f of the CHUGIAK - EAGLE RIVER ALASKA STAR published at Eagle River in said Division and State of Alask~ and that the advertisement, of which the annexed is a true copy, was published in said,publication on ' tV () f' (9[p i q (1 LI and that the rate charged theron is not in excess ot the rate C~ar d private indi~i~uals. ,otP.Å }--l,-. C{ \:::1U...JL,..,J¿ L- Subs ribed and sworn to before me this-7 day of ;) é- C 19 9' c/- /} /)<.) /l/tVu/~ é" ~(Y'~ Notary Public fo~·tate of Al~fh My CoTtImlssio-n tJ(pifSE Aui11. 1aw My COmIIÙssion Expires Your Neighborhood Good News Newspaper "~" ~............ _. . TION (ALASKA) Inc. for an Area . ;",'~. ..'~:' ", InjectlonOrderauthorlzIngctassll.. '. ,'.. , '. , " Inlactlon adivitles.for the.ourposa , ..1""--,,' ..~-.._~..... --~ ofenhancadrecoveryinthåNiakul< 750-Storage ' Oil Pool. . BP Exploration (Alaska) Inc. by letter dated November 16,1994 has applied for an Area Injection Order to aulhorize enhanced recovery opera- tions In the Niakuk 011 Pool on the North Slope. The order would pennltclass II Injection activities solely for the pur- pose of enhanced recovery within the Niakuk Oil Pool In the currently defined Niakuk Oil Pool Area and, In an adJa- cent to the north, BP exploration (Alaska) Inc. operated lease, which maycontaln an extension of the Nlakuk Oil Pool. · A person who may be hanned If the . . requested order Is Issued may file a written protest prior to 4:00 PM Decem- ber 12,1994 with the Alaska Oil and Gas Conservation Commission, 3001 - Porcupine Drive, Anchorage, Alaska 99501, ana request a hearing on the matter. If the protest Is timely filed and raises a substantial and material issue crucial to the Commission's determi- naUon, a hearing 0(1 the matter will be held at the above address at 9:00 am ·onDecember28,1994inconfonnance with 20 AAC 25.540. If a hearing is to be held, Interested parties may con- · firm this by calling the Commisison's offIce, (907) 279-1433 after December 28, 1994. If no protest is filed, the ..-.. Commission wiH consider the Issuance · . of thé order without a hearing. . If you are a person with a disability who may need a special modification In order to comment or to attend the public hearing, please contact Diana · Aeck at 279-1433 no later than De- cember 21, 1994. Russell A. Douglass, CommIssIoner , Alaska Oil and Gas .'. Conservation CommIssion AQ.02-5-14-026 Published: November26, 1994. The Best In Service ' . Spa and Hot Tub Repairs ' "'. 272-SPAS (7727) ,. Bear Mtn. Paperhanging Ucensed · Bonded · Insured Please call Sandy, 688-3040. 710-Cleaning Services " Storage Units; all sizes, heated or unheated, starting at $17/mo. Also, storage for boats, autos & R.V.'s. Military SpecIal, 1st mo... 1/2 price. Intematlonal Self Storage . C St. & Intemational, 563-3287 755-Movlng Apartment and Home MovIng Affordable local and long distance rates. Inrt. Moving & Storage, Inc. H' . '<"561~116 "", AsK fòr Military Discount - 10004 760-Trans./Freight HousehokIGØods . &FrelghtShlpplng . Anywhere In USA Palletized or Crated . Door-to-door service can save you blgmo~eYI~~-:!~~~"",>:: ": _," . , . , " ..::-: aOO~Sales' :'.~' . '. - WANTED . OUAUTYCONSIGNMENTS Clothing, fumlture, art work. anything · andeverythlngforindoorwinterweek- end garage sale, 688-1585. . .' . 990-tegal Notice U.S. DEPARTMENT OF JUSTICE UNITED STATES MARSHALS . SERVICE DISTRICT OF ALASKA ;'_ .- NoUce of Sale. By Virtue of a Declaration' of for- ,.. felture Issued by the Federal Bureau of Investigation, United States Depart- · ment of Justice, notice Is hereby given , . that I will sale by public auction the"~ following property to wit: . 1987 BuIck Grand National. Vln'1 G4GJ1173HP446882 " Appraised Value $9,500.00 > 1991ToyotaTercel., :. Vln#JT2EL43A4MOO11039 NADA Average' Loan Value " , $4,975.oo,~ . ~- . · Thesevehlcles arå offered for sale 88 Is. where Is. free and clear of any · liens. The sale will be conducted on Wednesday, November 30, 1994 at . , ~:oo p.m., at the GSA Parldng Lot located at the comer of 7th Avenue and C Street. Subject property may be "inspected two hours prior to sale from ·11:00 a.m. to 1:00 p.m. on November 30, 1994. High bidder must deliver cash or certified check, made payable . '.' to the u.S. Marshals Service for 15 % , of the high bid at the conclusion ofthe .: = . "sale. Remaining balance is due and . ; payable to the U.S. Marshals Service nolaterthanFriday,December2,1994 at 12:00 noon. Payment should be remitted to U.S. Marshals Service 222 · West 7th Avenue, Room #189. An- · chorage, Alaska. Failure to remit :e- · maining balance timely will result In forfeiture of the 15 % deposited and , vehicle will be offered to the second . highest bidder at the second highest bid. . The U.S. Marshals Service re- serves the right to reject any and all bids. Interested parties seeking addi- tlonàllnformation may contact Deputy U.S. Marshal Marvin L. Goffena or Michael Gave, Property Custoœan at 907-271-5154 in theAnchorageofftce. JOHN R. MURPHY' United State Marshal District of Alaska No.3030-94-OO3I303O-94-005 Published: Nov~r19,23.26! 1994. · ; 990-Legal.: Notlce...;~· 9g0-Legal Notice . . NOTICE OF AUCTION , . TobesoldatAuctiononNovember 29th,1994at1:ooP.M.,225Boniface, A Sentry Mini Storage, Anchorage, AK , 99504. · : JackeVSkl pants, gIrls size 8Í10, $10, '-. · . 694-4586. a99-Fre'ebles . Windows, 27x30. sing. fixed alum, 10/ $100,243-8932. . .: Windows, sing. alum. snders, 4'8"x27", .- 61$150,243-8932. . Queen size mattress. exc. cond.,· $100,688-5639. . . " FreebIes are' limited to fourltems Per . person,. ~ne time only please. . , NOTICE OF PUBUC HEARING STATEOF ALASKA ALASKA OIL AND GAS CONSER- . VA11ONCOMMISSION . -' . " };, Prepay your. . - 'ad for 3 ·times / 'and get the 4th . ad FREE! Call > 694..2727. ,.' (excluding legals.) J ') Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of BP EXPLORATION (ALASKA) Inc. for an Area Injection Order authorizing class II injection activities for the purpose of enhanced recovery in the Niakuk Oil Pool. BP Exploration (Alaska) Inc. by letter dated November 16, 1994 has applied for an Area Injection Order to authorize enhanced recovery operations in the Niakuk Oil Pool on the North Slope. The order would permit class II injection activities solely for the purpose of enhanced recovery within the Niakuk Oil Pool in the currently defined Niakuk Oil Pool Area and, in an adjacent to the north, BP Exploration (Alaska) Inc. operated lease, which may contain an extension of the Niakuk Oil Pool. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM December 12, 1994 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 am on December 28, 1994 in conformance with 20 MC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433 after December 28, 1994. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 279-1433 no later than December 21, 1994. Russell A. Douglass, Commis oner Alaska Oil and Gas Conservation Commission ~(/ Published November 26, 1994 #1 ) ) \'" BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 November 16, 1994 Mr. David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Application for Niakuk Area Injection Order Dear Commissioner Johnston: Enclosed is an application by BP Exploration (Alaska), Inc. (BP) for a Niakuk Area Injection Order. This application requests that an injection order be granted to cover injection operations in which BP will act as Operator, including the Niakuk Participating Area as currently defined, as well as certain adjacent areas in which BP may conduct injection operations in the future. All information as required by 20 AAC 25.460 and 20 AAC 25.402 is included in the application. BP requests injection approval for only one type of injection well in the application, enhanced recovery. Please feel free to contact me at (907) 564-4623 if you have need any additional information or if you have any questions. rrel:/J' Robert W. Ja~s Manager, Reservoir and Production Engineering Greater Pt. Mcintyre Area Attachment cc: A. N. Bolea, BP Exploration (Alaska), Inc. Realty Officer, Arctic Slope Native Association Limited RECEIVED Nav 1 6 1994 AJas.ka .ŒI.& Gas Cons C .. , An h . ommlsslon c Or2ge <. ' , ) Application for Niakuk Area Injection Order 20 AAC 25.460 20 AAC 25.402 R"ECEIVED NOV 1 6 1994 Alaska Oil & Gas Cons. Commission AnchoT2~;8 11 ) SECTION A Application for Niakuk Area Injection Order 20 AAC 25.460 20 AAC 25.402 BP Exploration (Alaska), Inc. (BP) in its capacity as a Working Interest Owner (WIO) and as Operator* of the Niakuk Participating Area within the Prudhoe Bay Unit, hereby applies for an Area Injection Order to cover proposed water injection operations. BP is requesting that the injection order be granted to cover operations in which BP will act as Operator, including the Niakuk Participating Area as currently defined, as well as certain areas that may be included in the Niakuk PA in the future (Exhibit A-1). Initially injection operations will be confined to the area within the Niakuk Oil Pool. However, adjacent areas to the Niakuk Oil Pool are being included in BP's proposed Injection Area to allow enhanced recovery operations in a manner similar to that within the current Niakuk Oil Pool should conditions warrant. Current plans are to drill a test well into this area in 1994 or 1995, depending on economic conditions and oil prices. Waterflood in the interval defined as the Kuparuk interval in the Niakuk Oil Pool rules (Conservation Order 329) is the only subsurface injection operation currently planned within the Niakuk Injection Area. Initially, water injected into the Niakuk Oil Pool will be source water from the Prudhoe Bay Seawater Treatment Plant. Produced water will be processed at the LPC and disposed of by injecting it into the Tertiary/Upper Cretaceous interval in Injectors LPC-01 and LPC-02. When sufficient volumes of produced water are available at the LPC to replace Niakuk voidage, the produced water may be reinjected into the Niakuk Pool. The production stream from Niakuk will be processed at the Lisburne Production Center (LPC). This application follows the same general format and exhibit numbering as found in previous applications and covers proposed injection operations in the Niakuk Injection Area. Exhibit A-1 details the area included in the Niakuk Injection Area. The legal description of the area included in the Niakuk Area Injection Order is listed in Exhibit A- 2. * Pursuant to Section 21.009 of the Prudhoe Bay Unit Operating Agreement, the Niakuk Working Interest Owners, with the approval of the Director, Division of Oil and Gas, Department of Natural Resources, designated BP to act as Sub-Operator in place and stead of the Eastern Operating Area Operator, ARCO Alaska Inc. In this application, all references to Operator shall mean BP in its capacity as Sub-Operator. ) ') Niakuk Development Plan The development plan for the Niakuk Oil Pool within the Niakuk Injection Area consists of a phased approach. Production began in April 1994 and plans are to produce from approximately ten wells for a one-year period. The exact number of wells ultimately drilled and their locations will ultimately be determined based on results from the first several wells. In April 1995, plans are to have permanent drillsite facilities available and waterflood operations will begin in the Niakuk Participating Area within the Niakuk Injection Area. Four to five water injectors will be utilized within the Niakuk Oil Pool area to conduct enhanced oil operations; however this number may change if conditions warrant. Produced gas will not be re-injected into the reservoir, and model studies indicate that produced gas reinjection would not increase recovery beyond that obtained by waterflood alone. An agreement, covering the gas management in the greater Pt. Mcintyre Area (GPMA), is in place among the owners of the fields in the GPMA that allows produced Niakuk gas to be injected into other reservoirs within the GPMA. Niakuk gas, less gas sold or used for lease purposes, is being injected into the Lisburne reservoir. "1¡ ) ) SECTION B Plat 20 AAC 25.402(c)(1) Exhibit B-1 is a plat showing the location of all existing wells that penetrate the injection zone within the Niakuk Injection Area as of October 1, 1994. At this time, all the specific wells which will become injectors have not been selected. The first 4 proposed locations for water injectors are included in the overlay of Exhibit B-1. Specific approvals will be obtained pursuant to 20 AAC 25.507, or any applicable successor regulation. RECEiVED "10' v," ..\ I:::' 1°06- Pi ,-,I ,J..J, A!aska .Oil & Gas Cons. Commíssion ~Anchor[ ') ,) SECTION C Operators/Surface Owners 20 AAC 25.402( c )(2) The surface owners and operators within a one-quarter mile radius of the Niakuk Injection Area are: Surface Owners/Operators State of Alaska Department of Natural Resources Attn: M. Kotowski P. O. Box 107034 Anchorage, AK 99510 Native Allotment Parcel B Owners: ARCO Alaska, Inc. Attn: Dan Siekenin P.O. Box 100360 Anchorage, AK 99510-0360 Mr. Leroy Oenga P.O. Box 201 Barrow, AK 99723 Ms. Georgene Shugluk P.O. Box 91003 Atqasuk, AK 99791 Ms. Jenny Oenga c/o 309 paystreak Fairbanks, AK 99712 Mr. Michael M Delia P.O. Box 201 Barrow, AK 99723 Mr. Wallace Oenga P.O.Box 201 Barrow, AK 99723 ') ) SECTION D Affidavit 20 AAC 25.402(c)(3) Exhibit D-1 is an affidavit showing that the Operators and Surface Owners within a one- quarter mile radius of any proposed injection well in the Niakuk Injection Area have been notified and provided a copy of the application. ) ') SECTION E Description of Operation 20 AAC 25.402( c)( 4) This is an injection order for the injection of Class II fluids in connection with an Enhanced Oil Recovery (EaR) operation. It does not include gas injection or the drilling of wells for dedicated Class II disposal operations. Subsection I Enhanced Recovery Enhanced recovery injection wells are used for the introduction of additional fluids into the reservoir to increase the ultimate recovery of oil. Only one type of enhanced recovery injection wells is currently planned within the Niakuk Injection Area: water injection. Facilities for waterflood within the Niakuk Pool should be in place by the spring of 1995. Well SpacinQ The base development plan for Niakuk is for approximately 14 wells in the Pool area, yielding an average ultimate well spacing in excess of 160 acres per well. However, this spacing may be modified as results of drilling and reservoir performance data dictate. Well ~ount~ Well counts have been discussed previously and will depend upon reservoir description and performance. Current plans are to develop the reservoir with approximately 14 wells, nine producers and five injectors, but this number may vary depending on drilling and reservoir performance results. RECEIVED f\! Or "1 6 1991Í it¡ . ¡ , y .~ ,. A!aska Oil & Gas Cons. Commission AnchoŒ ) SECTION F Pool information 20 AAC 25.402(c)(5) The Niakuk Injection Area includes the Niakuk Oil Pool in the Kuparuk Formation. The sole stratum, the Kuparuk, targeted for enhanced recovery within the Niakuk Injection Area by injection, is defined in the pool rules as the stratum that is common to and correlates with the accumulation found in the Niakuk 6 well between the depths of 9,351' and 9,842' subsea (88) [12,318' and 12,942' measured depth (MD)]. ) ':) SECTION G Geologic Information 20 AAC 25.402(c)(6) Subsection 1 Prudhoe Bay Unit Niakuk, Kuparuk Formation Reservoir I. Injection Interval A. Stratigraphy and Lithology The reservoir to be affected by injection is the Kuparuk Formation. This formation was deposited during the Lower Cretaceous geologic time period. Exhibit G-1 illustrates stratigraphy in the Niakuk Reservoir on a type log from Niakuk 6. The log is scaled in true vertical depth subsea (TVO SS), with MO also shown in the center track. The top of the Kuparuk Formation, the producing reservoir, occurs at 9,351' TVO SS (12,318' MO), and the base occurs at 9,842' TVO SS (12,942' MO). Exhibit G-2 is a log of the Niakuk 3 well, which demonstrates Kuparuk stratigraphy in the northern part of the Niakuk Injection Area. The Kuparuk Formation in the Niakuk Injection Area is stratigraphically complex, characterized by rapid changes in thickness, lithofacies, and cementation. The Kuparuk Formation is comprised of shale, siltstone and sandstone, with the latter occurring predominantly in the upper portion. The zonal stratigraphies of the Kuparuk Formation in each of the field's segments have been developed from well data augmented by seismic data. In Segment 1, Zones have a numerical designator while in Segment 2 a letter based naming scheme exists. Kuparuk zones in the northern portion of the Injection Area are defined primarily through seismic data, and therefore are less certain than those in Segments 1 and 2. Niakuk #6 contains the entire Segment 2 stratigraphic interval including Zones A through C (undifferentiated) and 0, E, and F. Exhibit G-3, a structural cross-section from west to east, shows the Segment 1 stratigraphic zones. The logs are scaled in true vertical depth subsea. Niakuk #1 A contains the entire Segment 1 stratigraphic interval including Zones 1 and 2 (undifferentiated), 3, and 4. Zones A through 0 of Segment 2 are interpreted to be equivalent to Zone 1 of Segment 1. Zone E of Segment 2 is equivalent to Zone 2 of Segment 1, and Zone F of Segment 2 is equivalent to Zones 3 and 4 of Segment 1. Interpretation of cores and logs from the Niakuk #5 and #6 wells indicates that the reservoir in Segment 2 is present in Zones 0 and F. Zone 0, the lower zone, is stratigraphically complex but can be correlated between Niakuk #5 and #6 and over the remainder of Segment 2 using seismic. Cores indicate it is a fine to occasionally medium grained sandstone. A predominantly siltstone unit, Zone E, is usually present between sandstones of Zone 0 and Zone F. Zone F, the upper zone, consists of sandstone, pebbly sandstone, and conglomerate. Cores indicate this sediment is mineralogically mature. It varies from poor to well sorted, with grain size ranging from fine to pebbly. ) ') : B. Structure As shown on Exhibit G-4, top Kuparuk River Formation Structure map, the overall Niakuk structure is a system of grabens and half-grabens. The units for structure contours on Exhibit G-4 are subsea depths, and the contour interval is 50 feet. The Segment 1 graben consists of a centrally dipping synclinal structure, while the Segment 2 area contains an easterly dipping trough cut by faults en echelon to the bounding Niakuk Fault. For visual clarity, not all of the intra-reservoir faults are shown on the map. Structural relief and complexity decrease northward. Structural dip on the top Kuparuk varies from 1.7 to 7 degrees, with an average between 2 and 3 degrees. The large distances between well control require that structure depth maps and faults be determined from seismic data that is controlled by well data. In some parts of the Injection Area, the top Kuparuk is a strong reflector which is easily traced on seismic. In other areas, the top Kuparuk has been derived by isochronning the HRZ shale. Structural and stratigraphic features are summarized on Figure G-3, the west to east structural cross section. Vertical to horizontal exaggeration is 17 to 1. Exhibit G-5 is an isochore map of the Kuparuk Formation with a contour interval of 100 feet. This map illustrates the strong control that faulting has exerted on Kuparuk Formation thickness in the sourthern part of the Injection Area. Thickness ranges from o to 900 feet. The isochore in the less faulted northern portion of the Injection Area ranges from 100 to 350 feet. II. Confining Intervals The Kuparuk Formation is bounded below by the Jurassic age Kingak Formation over virtually the entire Niakuk Injection Area. The contact is defined by a change in lithology and electric log character. The Kingak Formation is a highly impermeable, low resistivity (2 to 3 ohm-meters) shale with a thickness varying from 400 to 800 ft.TVD. The overlying Kuparuk Formation is characterized by higher resistivity (3 to 6 ohm- meters). In the extreme SE corner of the Injection Area, the Kingak Formation has been interpreted as absent on seismic in a 350 ft. (EW) x 2100 ft. (NS) area. In this small area, located in the extreme SE 1/4 of section 28 T12N, R16E, confinement of injected fluids will be provided by Lower Kuparuk siltstones and shales as encountered in the NK-23 well. The Kuparuk Formation is overlain by the Lower Cretaceous age HRZ interval over the entire Injection Area. It is comprised of a 200 ft. thick, black, organic rich shale exhibiting high radioactivity as measured by the gamma ray log, typically greater than 150 API units. ) ') SECTION H Well Logs 20 AAC 25.402(c)(7) All openhole logs from Niakuk wells are sent to the Commission as the wells are completed. Exhibit G·1 is the type log for the Niakuk Injection Area with stratigraphic and marker horizons annotated. RECEIVED NOV '1 6 1994 Alaska Oil & Gas Cons COt'''m' . . 1/1 iSSIOXi Anchon " '\ ) ) SECTION I Casing Information 20 AAC 25.402( c )(8) 20 AAC 25.252(c){6) Approximately 4-5 water injectors are planned for Niakuk. A number of the water injection wells are planned for pre-production prior to conversion to waterflood injection. Tubing sizes in the Niakuk field will vary from 3 112 to 5 112 inches. In general, the production casing will be sized to the tubing in the Niakuk wells. Typical development wells will utilize either a "conventional," or "slimhole," design similar to Kuparuk and Prudhoe Bay fields. The "conventional" design wells will utilize 13 3/8-inch surface casing, 9 5/8-inch production, or intermediate casing with a 7-inch liner for the high stepout wells. The "slimhole" design wells requiring 4 1 12-inch tubing will utilize 10 3/4- inch surface casing, 7 5/8-inch production, or intermediate casing with a 5 1/2-inch liner for high stepout wells. All Niakuk wells initially designated as water injection wells will be completed with L-80 grade steel. The injection wells planned for pre-production may utilize corrosion- resistant material where applicable. Most Niakuk water injection completions are currently envisioned as single zone, single string with a single packer. Where potentially advantageous, isolation packers may be run between intervals. Exhibits 1-1 and 1-2 show typical wellbore schematics for the two basic completion designs. As shown in the schematics, gas lift mandrels will be run to provide flexibility in artificial lift, which will enhance production in the injection wells planned for preproduction. Sufficient mandrels will be run to provide flexibility for well production and gas lift supply pressure. The actual casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. Further, all drilling and production operations will follow approved operating practices in reference to the presence of H2S in accordance with 20 AAC 25.065 (a), (b), and (c). ) SECTION J Injection Fluid 20 AAC 25.402(c)(9) 20 AAC 25.252( c )(7) Subsection 1 Enhanced Recovery Two types of injection fluid will be utilized in the Niakuk Injection area: A) Source water and; B) Produced water. Source water will be obtained from the Beaufort Sea and is the same water that is currently being injected into the Ivishak Formation in the IPA, and into the Pt. Mcintyre Participating Area. Produced water is water that is produced with Lisburne, Pt. Mcintyre, West Beach, North Prudhoe Bay State and Niakuk oil and separated from the oil and gas at the LPC. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. A. Source Water 1) Analysis of Composition of Typical Fluid - Exhibit J-1 is a listing of the composition of the Beaufort Sea source water. 2) Estimated Maximum Amount to be Injected Daily - Ni~kuk - Peak injection is currently anticipated to be approximately 50,000 BWPD. Initially, the development plan includes only source water injection into the Niakuk PA. Source water needs may decrease in the future as the combined produced water volumes from Niakuk, Pt. Mcintyre, West Beach, and Lisburne increase. 3) Compatibility with Formation and ConfininQ Zone - SEM, XRD and ERD analyses conducted on Niakuk core indicate very low clay content in reservoir intervals (see Exhibit J-2). As a result no significant problems with formation plugging or clay swelling is expected due to fluid incompatibilities. B. Produced Water 1) Analysis of Composition of Typical Fluid - See Exhibits J-3, J-4, and J-5, respectively, for the compositions of Niakuk, Lisburne, and Pt. Mcintyre formation water. ) ) 2) Estimated Maximum Amount to be Injected Daily - Niakuk - Future produced water injection rates at Niakuk may reach 50,000 BWPD. 3) Compatibility with Formation and Confinino Zone - The produced water returning to the Niakuk formation will be a mix of Pt. Mcintyre, West Beach, North Prudhoe Bay State, Lisburne and Niakuk produced water separated through the LPC. The current development programs for these fields indicates the majority of the produced water will come from Pt. Mcintyre (current maximum estimated at 250 MBWPD) with minimal amounts coming from West Beach (current maximum estimated at 50 MBWPD), Lisburne (current maximum estimated at 20 MBWPD), and Niakuk (current maximum estimated at 50 MBWPD). Since the origin of a vast percentage of the produced water will be from the Kuparuk formation, minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. ) SECTION K Injection Pressure 20 AAC 25.402(c)(10) '\ } The estimated maximum and average injection pressures anticipated for Niakuk wells are listed in the following table: Type Well Estimated Maximum Injection Pressure (Psig) Niakuk Water Injection 2,850 Estimated Average Injection Pressure (Psig) 2,450 (Pressures represent pump discharge pressures) ) ) SECTION L Fracture information 20 AAC 25.402(c)(11) The estimated maximum injection pressures for enhanced recovery wells will not initiate or propagate fractures through the overlying confining strata, which might enable the injection or formation fluid to enter freshwater strata. Subsection 1 Freshwater Strata There is no freshwater strata in the area of issue (see Section N). Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Subsection 2 Enhanced Recovery Injection in the Kuparuk above fracture 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 overlying confining zone. The Kuparuk Formation is overlain by the HRZ shale. The HRZ is a thick shale sequence which would tend to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. Fracture data from the Kuparuk intervals of the Pt. Mcintyre and West Beach Pools indicate a fracture gradient of between 0.60 and 0.63 psi/ft iat original reservoir conditions. Fracture data from Pt. Mcintyre NO.9 gave a fracture gradient of 0.624 psi/ft, while data from West Beach No.4 indicated a fracture gradient of 0.602 psi/ft. While no fracture gradient data has been obtained in the Kuparuk interval at Niakuk, it is expected that the fracture gradient will be similar since it is Kuparuk rock with similar character. Prudhoe field data also indicates that sandstone fracture gradients may be reduced during waterflooding operations due to reduced in-situ stress associated with the injection of colder water. Declining reservoir pressure can also reduce formation stresses, thereby reducing the fracture gradient. The Niakuk Pool will be produced prior to the start-up of waterflood operations allowing the reservoir pressure to decline somewhat. However, once waterflood operations are initiated, field average pressures will be managed to mitigate fluid migration and sustain reservoir energy. ) ) SECTION M Formation Fluid 20 AAC 25.402(c)(12) A reasonable estimate of total dissolved solids (TDS) using wireline log analysis is not possible in the Kuparuk Formation of the Niakuk Injection Area because of the ubiquitous presence of live and residual hydrocarbons. An analysis of formation water samples obtained from the Kuparuk sandstone indicate that Total Dissolved Solids are 25,700 ppm. Clean, 100 % water wet sands are present in the formations above the Kuparuk. As shown below, wireline log TDS calculations on these sands indicate a lack of fresh water (NaCI equivalents of greater than 10,000 ppm). The wells shown are areally representative of the injection area. The method used in these calculations is described in Exhibit M-1. Ugnu Well TVDss TDS (ppm) NK-#1 3940 15,650 NK-#3 NK-#6 5106 12,000 Sag Delta # 8 NK-#1 4273 12,192 NK-#3 NK-#6 4414 16,850 Sag Delta # 8 4731 13,288 NK-#1 4657 11,619 NK-#3 4917 16,610 NK-#6 4611 14,709 Sag Delta # 8 4949 14,574 NK-#1 5332 14,727 NK-#3 5502 20,512 NK-#6 5029 13,147 Sag Delta # 8 5378 13,162 NK-#1 5431 16,253 NK-#3 5751 21,995 NK-#6 5502 16,655 Sag Delta # 8 5940 13,007 NK-#1 6679 15,137 NK-#3 NK-#6 Sag Delta # 8 Interval T-8 T-5 T-4 T-3 Wsk ) ) SECTION N Aquifer Exemption 20 AAC 25.402(c)(13) The lack of fresh water and underground sources of drinking water in the Niakuk Injection Area eliminates the need for an aquifer exemption. The presence of hydrocarbons, either live or as residual, causes the Kuparuk Formation of the Niakuk Injection area to be unsuitable as a source of drinking water. In addition, Kuparuk Formation water analysis indicates 25,700 ppm total dissolved solids (TDS). Calculation of TDS from wireline logs indicates NaCI equivalents of greater than 10,000 ppm in the formations above the Kuparuk Formation (see Section M and Exhibit M-1). Therefore, no aquifer exemption is requested nor needed. ,) ) SECTION 0 Hydrocarbon Recovery 20 AAC 25.402(c) 14 The Niakuk development scenario as currently planned includes waterflooding, initially within the Niakuk Oil Pool. A total oil recovery of approximately 40 percent OOIP is expected for this development scenario. This compares to an estimated 4 percent OOIP oil recovery attributable to primary depletion. Waterflooding the Niakuk reservoir within the Niakuk Oil Pool is expected to result in an incremental 49 MMSTB beyond primary depletion. R"ECEIVED NOV 1 6 1994 Alaska Oil & Gas Cons. Commîssion Anchor2 ) ) SECTION P Mechanical Integrity 20 AAC 25.402(d) & (e) In drilling all Niakuk injection wells, the casing is pressure tested in accordance with 20 AAC 25.030(g). When a producing well is converted to injection, the casing pressure test will be repeated in accordance with 20 AAC 25.412(c). Injection well tubing/casing annulus pressures will be monitored and recorded on a regular basis. BPX, as sub- operator of the Niakuk oil pool, will be responsible for the mechanical integrity of injection wells and for ensuring compliance with monitoring and reporting requirements. The tubing/casing annulus pressure of each injection well will be checked weekly as a routine duty to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70 percent of the casings minimum yield strength. If an injection well is deemed to have anomolous annulus pressure, it will be invetigated for tubing/annulus communication using a variety of diagnostic techniques and a mechanical integrity test. If a subsesquent investigation proves hydraulic communication between the tubing/casing exists, then a plan for remedial action will be formulated and scheduled. In addition, a variance will be obtained from the AOGCC to continue safe operations, if technically feasible, until the remedial solution is implemented. BPX will also maintain annular pressure data in the WOA Injection Well Status Database and will provide copies with future monthly Injection Reports (Form 10-406) to provide annular pressures, diagnostic comments, and scheduled remedial action. Tubing/casing pressure variations between consecutive observations need not be reported to the Commission. A schedule must be developed and coordinated with the Commission which ensures that the casing/annulus for each injection well is pressure tested prior to initiating injection and at least every four years thereafter. A test surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 700/0 of the casing's minimum yield strength. The test pressure must be held for 30 minutes with no more than a 10 percent decline. The Commission must be notified at least 24 hours in advance to enable a representative to witness the pressure test. Alternative EPS approved methods may also be used, with Commission approval; including but not necessarily limited to timed-run radioactive tracer surveys (RTS), oxygen activation logs (OAL), temperature logs (TL), and noise logs (NL). An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. ) ) SECTION Q Wells Within Area Report on Mechanical Condition of Wells 20 AAC 25.402(h) 20 AAC 25.252(h) To the best of BP's knowledge, the wells within the Niakuk Participating Area were constructed, and where applicable, have been abandoned to prevent the movement of fluids into freshwater sources. Exhibit A-1 : Exhibit A-2: Exhibit B-1: Exhibit C-1 : Exhibit 0-1 Exhibit G-1 : Exhibit G-2: Exhibit G-3: Exhibit G-4: Exhibit G-5: Exhibit 1-1 : Exhibit 1-2: Exhibit J-1 : Exhibit J-2: Exhibit J-3: Exhibit J-4: Exhibit J-5: Exhibit M-1 : ) ) List of Exhibits Plat of Proposed Niakuk Injection Area Legal Description of Proposed Niakuk Injection Area Plat of Existing Wells Within Proposed Niakuk Injection Area Niakuk Injection Area Surface Ownership Affidavit Niakuk #6 Type Log Niakuk #3 Type Log West to East Structural Cross Section Top Kuparuk Formation Structure Map Kuparuk Formation Isopach Map Typical Niakuk Well Schematic Slim hole 4.5-inch Tubing Typical Niakuk Well Schematic Conventional 4.5/5.5-inch Tubing Beaufort Seawater Composition Niakuk Clay Content Niakuk Produced Water Composition Lisburne Produced Water Composition Pt. Mcintyre Produced Water Composition Documentation of Water Salinity Calculations From Well Logs RECEIVED Nav 1 6 1994 Alaska OH & Gas Cons C . A h . ommlssfon nc or2.) G - :"C";L -3'3_:'-50:9 i I ~ I ! ! ~ ! ~ ! ---, I r I ':-.r.C:cj :.'J.O:=! ::X.;ÚJi- ADL. ~JÒ2t: ~<;!~EI PLAT OF PROPOSED NIAKUK INJECTION AREA EXHIBIT A-1 NK-Q3 A. __u .. .. ..... -" NK-02À~" : NK,02 . NK-Q8 . A_~_C:G 5C: ,({r ~-_..~~ ..--. -- = "-:.=.-.:.-.:..-' PRUDHO:::: BlÙ' Uf\JiT ~ '.............. '_'""õ'_"_"_' t I ~ E f~X~jr- S'JJ:O p, D ~ ;~' 4-'::: 2'; GUll IS. T12N ,--- .. ~~-~Ñ--~ ~';:~~h~~;c~~, PRUDHOE BAY ~., , . NK-Q7 NIAKUK ISLANDS ~_. r' ,~~-.~~ ''7'2--=. : / / NK-12A '. o NK-Q1 A. NK-Q1A . NK-10 (Î W 10 cr: ';e fA ~ €-; 'S20 <:::. >Ci) 'ö.JØ) ~ g.cn o ð (j) p§ -- '"'(0 sn w J"f~ CO) (.0 p~ å .þ ~SO-N~' SO~ _ ---- -- _ . .----- ---- . ____ ___ _ __ _.... __ ·u, ". "~'__~~5~~~~ D é> 6 ~¡~ r/'j !P ~ - 'ì - NK-20 . NK-42 . ~ NK-D4 o I NK-12 I NK-D5 Â NK-23 . . NK-21 NK-22 ø NK-Q6 . NK,18 ."':;:-!m' - -J - ~ - - - - -- 11[\ .ø J \ It /?! t -. - - - ¿-- ~Ä '\ \\ 0.\- \\ ~ \--------¡ --------- ?C I . i f"'"' I I i --- ~ rn o 0.5 0 ~ ~ LEGEND o ABANDONED WELLS . DRILLED WELLS Â. SUSPENDED WELLS - - - NIAKUK INJECTION AREA 1 MILE w W <0...... rr. cr: 6 --- SG,oa o --- --- --- --- -~--- ~----- ------ ~---- ---- - @ RES~ll -- -- --'--- MPI -- -- ~ J' -", --- --- -.- --- 1"=,, ~ 31 T12N T11N ww <0...... cr:a: WL12379.dgn ') ) EXHIBIT A-2 Niakuk Area Injection Order Legal Description of Niakuk Injection Area T12N, R15E UM Protracted Sections 13, 14, 23, 24, 25, 26 Protracted Section 36: N/2 T12N, R16E UM Protracted Sections 28-30 Protracted Sections 31 : N/2 and 32: N/2 RECE\VED NOV ~\ tl 1994 '\ I,. ~!(~ Oii& Gas Cons. Commission h\ê..~í,.1.4 Anchor" WL 1237R.oon ww CD"- eta: i5~E _eæ T12N .__..=-"~~....---.----~--,-~ {W:It iŒ}.íJ\J JU',L ~Ø,.~ 31 MPI !S>'J( i !>:1.i») AD:'" :~~$ -----_.----.-.-.,.....,.~....--, - .-.. ........, 'I<~~ 8. 'Ú} " L..~~ 4.,.' 'l ~ 'Y& . ~/,. .~.. ·1 .~~. ...-'" In'_~ (~ ~., , - -.-.l fMõ~ 100.00 0 RESou.mc:W.18. lID ~ .,.,..... E ___ rJ ~ s ~ AD:. '!~8{~..: NIAKUK INJECTION AREA POlENTlAl WATER INJECTOR --- ~ LEGEND w~ LtJ W ""~~'>"<" 1 ~ ~ 6 ':""""""":'.'" a: a: w,..".,.<.:,.,..".,.,.,....,."...:.:...:.,...:.,.....:,.:.,.....:.>:.:.:.:.:.:...w.w..>:.:..........:.:.:....:- 1 MJLE 0.5 0 --. 1_.~1 ap1 . ~ (!(! .:.r:;L :J.5:>:r; \\ ñ ~~ a:ø: .~ PRUDHOE BAY BF;< ¡ D'J.¡}(): AC:_ ~ !\.'jOO C; ¿r 8 N¡(1'; M.OO ~..Y$M ß.~.f:f) ',','I.W:I. ~?.ii. (!(;.OO "-l'i. 2S¡~:.20) T12N T11N -1::- 'R' - - - - ..,. - - - - - -"~ NK-23 ~ .. NK-20 ·~--_·,--.........""->---~--""^'~---·--if",~o----....... ....,~,.. ~~~... .......~ .......~...,,\-,,~, ~-~'=*"-'%"-*l~ MiER-\'I)-\ HEW ü-~.OO im:. 5O.{Io} ADi..1V&7 S~--t \ WJ'SO<v \ SOÙÑð" NlAKUK ISlANDS ,. ~. S?), ~OO.OO AC:i. J4006 ~ ... NK-10 Ii N!CO ~O.OO [,><X.V!' !Äi.OO AOi..~~g , GULL IS, fJPX 100.00 AI'.il ~\O .w._LL NK-12A~ ~Õf. 8AV· uÑrr - -., ._" _.-- SPX 1)0.00 AfJ¡.~!j. N{\.~O ro.((¡ ii.x.«:/I ~O.OO ^f)j.~·1~ " " fW"!. 100.il'J ADl.J~ ··......Y.,'<-·..,!...,^:......~··,"'..,:.."~.,..:-,,~.:..."'.:.,.w..."wl.w,,......:W...,.:.,:.""""""",,,,,,,,,,,,,,,,,,,,,,,,J:v¢"" PLAT OF EXISTING WELLS WITHIN THE NIAKUK INJECTION AREA r;m .. ~ ~ ~ g2 <:> ~ PLAT OF EXISTING WELLS WITHIN THE NIAKUK INJECTION AREA EXHIBIT B-1 0.5 0 1----1 1----1 1 MILE ?C m Qo ª'&' ~ g.cn ~ b' cJ") E~ CD- ( ~ J rn < rT1 o w W <0...... 6 a: a: .-.Ao c..o c..o -Þ> C") o Sf~p § ;p 44:'; Cir ~SO-Ñ S" So ::J ~b LEGEND o ABANDONED WELLS ::':1". --- ~D,- 33'0348 --'~-~~--~,O,q:¡S.}I}:---- E~~;~rj~~~~~C . ... DRILLED WELLS NK-03 A SUSPENDED WELLS . . -~. ~~~ - -- . - .. - -... __ ... ..u.. __ .. _ .... ..._ -- - .- - . . -- - - - -. -- - - - NIAKUK INJECTION AREA -----. ~-~.- ._-~-.~ ~~~~1iiI' . --" NK'û2Ã JjJf'-. I I 0 NK-02 : ~ '- "--'---"- SG-08 o ----- ------ -----~ ----- --~- NK-12A , NK-{)8 . "~"~"~~~~~~~- - - --- === --- - -~ -~. ~~~~- PRUDHOE BAY ~ R=woor Ui\J!T o NK-01 £. NK-{)1A . NK-1O a ''''''''': ..; --,--. .~~, - - ~_o.~.=~- ~n¡ '':'_.·';::~C' . NK-{)7 .NK~ ,-'-"-.KC--Q 5C: .G(' NK-42 . ." E ;:-;xG¡-! SCU~~G NK-20 . ~.rli ::' J.;=;~)~:'. o I NK-12 ! GULL IS. NK-23 . NK-û5 A ~ NIAKUK ISLANDS NK-22 , NK-{)6 . NK-21 MPI ~ . NK-18 -l~ ~ - - t- - oe9 - - - - - - -1 - - - - - - - - - - - - - - - - - - - - - - , - - - - - - - - - - - - - - - - - - - - - - - - - 31 I ~__ ¡ un _ T12N T11N T12N T11N :~~1~-CO - _ H . ~~.~~ _"c~cc"(/ 1 / ,~^ - - - --- ,'" "\\ 6 w w \\, CO ...... \, a: a: C> 6 ~j,..~ /7 a:'D: ¡ !F> \ '7 C? ,} k -~ ~.~ --- --- --- --- PRUDHOE BAY \\ 1· -. -' WL 12377 .don BPX 100.00 AOL 365549 -- -- --~--'=~"-""""""'~--=~~-==--- ARCO 50.00 EXXOII 50.00 ADL ~"'626 ~2~-""Z--~F¡ -I - -~~~ PRuDHõE'BÂV UNIT ¡ I ¡ ð, ARCO 50.00 EXXO~ 50.00 ADL :::'4629 GUll. IS. T12N T11N ARea 50.00 EXXON 50.00 ADL 34631 I e-I PRUDHOE BAY NIAKUK INJECTION AREA SURFACE OWNERSHIP ~ (J) lS ~ UJ LO a: ~ ~£' g.cn o C') r~ g co ~ C"') o 3 3 ur rn õ' "::'I BPX 1 00.00 ADL ~25 AMERADA HESS 50.00 BPX 50.00 ADL 132827 ~-- === .~== - z o < ~j rTI. ~' .-n - < rTI CJ ~ en W <..0 -Þ> EXHIBIT C-1 0.5 0 1--1 1----1 1 MILE Sf~ P4¿y ~SON J'OÙj 'Ít7-l) BPX 100,00 ADL 34830 ~----- - - -- - - BPX . 00.00 .. AOL 34635 I ~ NIAKUK IS .AND 4/5 t i BP EXPLO ={ATION , /11 .. I ~ , I~'i:~~stoi'" 3!r !!,~ull~E~r~N!~ - - - J Sj^TE OF AlASKA '- ~~:~6~LA~OTMENT i i - BPX 100.00 ADL 28320 C1 C' 6 (/"~ J \ \ 'ì \\ ~'''-.,.''' BPX 100.00 ADL 28338 J / - í l\ í/I . II) \ 1// . \ It? Ii r UJiUJ LOiw èi:Jèi: ¡--'F' (, ~ ~~ '~\----( ADL 132828 UJ W <D r-- 6 a: èi: ~ --- --- --- --- ----== ------ ----- --~- BPi.100.00 tV RESOLUTION'S. ~c~M I I ~ ~ ~ ðvo+ ~1ð~~~~ 1~ ~~ ~:a~ v~)o t i BPX 100.00 ADL 34633 BPX 100.00 AOL 34636 - MPI 31 T12N T11N ww tOr-- èi:èi: "\\ 6 ,', \~: 1· WL12420.dgn ') ) Exhibit D-1 AFFIDAVIT OF ROBERT W. JANES REGARDING NOTICE TO SURFACE OWNERS IN THE VICINITY OF THE PROPOSED INJECTION WELLS Robert W. Janes, on oath, deposes and says: 1. I am an Engineering manager at BP Exploration (Alaska), Inc., the Operator of the Niakuk Participating Area within the Niakuk Injection Area, Prudhoe Bay Unit; 2. On November 16, 1994, I caused copies of the application for the Niakuk Area Injection Order to be provided to the surface owners and operators of all land within a quarter mile of all proposed injection wells within the Niakuk Injection Area as listed below: State of Alaska Department of Natural Resources Attn: M. Kotowski P. O. Box 107034 Anchorage, AK 99510 ARCO Alaska, Inc. Attn: Dan Siekenin P.O. Box 100360 Anchorage, AK 99510-0360 Mr. Leroy Oenga P.O. Box 201 Barrow, AK 99723 Ms. Georgene Shugluk P.O. Box 91003 Atqasuk, AK 99791 Ms. Jenny Oenga c/o 309 paystreak Fairbanks, AK 99712 Mr. Michael M Delia P.O. Box 201 Barrow, AK 99723 Mr. Wallace Oenga P.O.Box 201 Barrow, AK 99723 RECEIVED NOV 1 6 1994 ¡ : t ! \} ^'askaOil & Gas Cons. Commission / ' Anchor~ Robert W. Janes v STATE OF ALASKA THIRD JUDICIAL DISTRICT ss. SUBSCRIBED AND SWORN to before me 'is 16th day of November, 1994. ,,/j¿~œ0..J ¡Jçb/Í NCJTARY PUBLIC IN ANEYFOR ALASKA ~,J"""" ~ ,...J:......., .... ,~~ OfHCIAL SEAL 8T ATE OF ALASKA SUSAN F. HOLLY NOTARY PUBLIC My ~,~~~:.~x~;J!,re.; N.orch 13, 1997 .~ ~',~'. -",', ,,-..:,"'(,. .._,.....,~<~',/J~~...... ,I-- ...-..;:,~ My Commission Expires:1ì1o~~ / ~ /99/ Exhibit G-1 .. .. . ........... ......-...._....____. ..... ..........._............._..... ....._... u.....~.._... 'U .... .......__._ .__. _._._ .._....00__. ..._. . . .. . .. . . . . . . .. .. · ' .. '0- . . . . ." ..._u.....;. n.._......_..~.___....... ..._.u...:.n....._..~..:...._.. ......... ............. ._.. _.. ._..... _.__ ....... ...._. '.'_.' ..._....._. , . . .... . . , ".. · . .... . . . . .... · . . . ..... "" , ".. ::~: '::J :~~~::::·:~r·~:¡I¡{.:~:: :::l:~:r::~:l:¡:I':r~ :~::.~~. .:::::: '.::::~:~: ::: ::=~:: :::: ::::: :::: ::::::::::: : . :~¡;tS~~:tI¡¡·,i~~:~.~~;:~~~.~ii ._....~~......~._w........._.....~_.,._,.~: .., . 1 -ï;:d ~ ~~ :::~~t:tä¡¡II.:: :EFU1£¡¡:~~ :~j~~:~l~~~lg: ~ ~~~. I . 200.1&0. '0. .-.-----ITD-OHMiï------+---------..õy·--· ··ü¿ï¡·-..·-·---··....·· 1. 200.GO. 0.. f---------Jlñ--ÕHMÏt---------I------ j¡¡;HT-'tT------"-( I. 200.' .113 :.66 I 5f LU DHM I RHOB (;/(;3 I A,laska Oil & Gas Cons. Commission Anchon NOV 1 6 1994 '~fPj~~ I~IE:~::: ;::~J ;~:¡-'25 00. ..-..--...: . .._.~ ¡... ·:0;..·....1..·--· ....... ......- ............... -·.._··I-··..·I~ ... ...p-:;::; "'-'" .......- ....- ~--~ 1 .~::::~~~~~:::~! =-:-IZGOO I 9600 ········I....··I............·..I·~· ....+.. ~ I - ··..·r···· r···T····.. ....~.. ·T·····~ ..,. .. . . .¡~~: .~f~~ ¡-¡::~I!:( ~ ~ 127 DO '....... -.... ...-....-... ..·~l·..·· ......t¡........ ...... --12800 ~~~:=~ i~:;~~~~r~:l ~~~ 2900' 960e .-.... ...... .-.-.. ........ . I .~ it. ....... ..-.. ..-... ....-. ....... ... "'f'~"'''''I'''} .-- TOP K NGAK ~~::::::::::: ::::: :::ª::'::Il ::= -·1 3000 _ 9900 .~~=t~~ L::: ~~~~:I::::::: .:: :::t:::::::.::::::: =:::::: ::::::_ ,,·±I·....····....·· ........... ..·t..·-···-..··· -..... ...... 9700 -100. o. .-.-----~-~7------"-( "0. 300. I G/\ fir I o. "0. t CR AI'¡ I NIAKUK NO 06 RECEIVED LOG NIAKUK#6 TYPE ) ) > i~ ) NIAKUK #3 TYPE LOG .-. -·'-~3SØ - -- _.~ ·H'lI 50029-2035ØØ0 NIAKUK-03 --'i) 4 [I ~ -';'4-';'l~ 1ST LOG: PJ2/28179 B AND ~ GR RES DT PHI - 1 t1~fDLL J____..1.I;j~u...__ 1 I DlIr:r 1lLl. 1 RE~ t1....D lID 18Ø &80 D'nr81D~ 1M 180 1 . !.L-_-I!JJlli!..J!.'I{(L__---1-~_ 11!Ø 6Ø NPHI CNL ø 11!Ø 1.115 RHOS DENS 1.M . . ~.. ..':::... ..'>.. ¡~ - -.:.~ - - - _.-:- --·::i~L '-j.~::.: -- :.: -.. -~ é:. - -.-~;-:::- u,____, r -.-.--.-.-- u._.·n:_.~_~·~ -'-. u:~ ',,- -,,~ - -t- ,,\~ .. ., . ... ., ......... f. ., .~ .. ... .. .. ..., ..... .,. .. .t.,. .f. ... .,.. . .. ...,' .:: -;_:.::_- :: -:K_n:::::_n_·_~;r_e~::;_-:..::.:":- :-. .:\: ; r:· . ... . ! n. :-.-... _ -- --;j _ :--. .--::.- ::n:_..- .~.- .:.::.-..-...-:.<-.:..- - -~ - - I'. . __ ,,)_._ 0 _ _. __ _.. _~ m_ ·nom_ - u'_ ~ --'~ ~ ,,:~t~- :.~ .'~- - .. {-" . :....::.: :'.::':.:...:.::'~. ç~£'" '::.: XPI: M-91 .Y'IV!I-4 111:117:2-4 DEPTH lMIT - F1'TT -1~e Sf' <DLL> II !.___-St.81..L_J2Et::!$_____~_ :I OR CR œJIICS 1.5Ø ss DEPn-t ø OR mID 150 HRZ ~1 ':~~~~:~~~~;~:~~~~:::: ¡(!r~::~;J::~::1'jl~'~'~:1"-~'Ö:'~',r' ' __.....,.l!,..,,'- ..., -~. .... I· tI:3-[\ ::.~.~ '~'~:'~:'f,';f:;:') ::··.f . ) - -::; ::_.~ ..,..W: .,..1.. .' .:.> ' ':~:,·l··=~b'~'.:'~.' .. . _..r-':' ,- .=: ~t::~t .~ ··";'.:b '- I... ·.:I.:-~ 'ij .~t :~ :¡;: _ ;:~ :~: .:.~. i.~;: ~.I. _, ';., Kuparuk :-::: L"~'I. ...1. .'..... .-. : . -:,1. _.I. oç... .:·~·r:~ ¿:.~~::~ ~~~f·. ~:=:::~··=··~.::-~~b·- ; ·:i:t·::..:::~'~·:·~ .'~.,.~ Format ion ~:~~·~.i>~:~ - -. _.~: ·-=T~¡>J~ :'~i' u' - ~- '_'~ .' ¡ :'. '''1·: ..,r" , . ::' .~.~. L;.o I r".~ TI'-~ ;':~'3<~;'::~::'; ~;·:~:~:':'~Cf:¡;~il. : . -, _. - - .._..L. 0 - - -~g¡-~_._._. -.s.-....¡~l' Kingak .":'.] ".1.' "-:1...'.; .>(~ ., ~.' -';f ,:.(\ " Formation ~-t:~~;·:::;·: :; :'·f:~ .,~.~ ..~ -- ~ ., ... . ...... .................. Exhibit G-2 ww U) (D Ó:Œ H N '-' M7 Trunætion of ~ Kupan.k Riv.e.r or " Non-Deposition ..... M 7 Trunætion of Kup aruk R iv.~r or Non-De p 051tlO n o SO' Contour Interval i " Mile I 1 I -p-- T12N T11N Map.' . . r n Structure Top Kuparuk Forma 10 Exhibit G-4 ~ ~ ~ \; '" 'Q) ~ l ...A ~ ~ '~ ~Q'/ ¿,..- ~~ Ô' ~ ~<6 (Q ~ ~..~ ~ (". ...-- ~& CJ ~ \ % ~ WW 1.l)<D ŒŒ JI4.. . N 200- í - SAG DELTA 8 Non-Deposition .... M7 Truncation of Kuparuk River or Non-Deposition o \ ,,-,' Contour Interv al - 100' I Mile I T12N T11N Exhibit G-5 Kuparuk Formation Isochore Map. ) ) EXHIBIT 1-1 TYPICAL SLlMHOLE WELL SCHEMATIC TREE: 4-1/16", 5M, CIW WELLHEAD: 13-5/8", 5M, FMC ACTUATOR: BAKER 10-3/4", 45.5#/ft, NT-80, BTC. 4-1/2" TUBING DATE PBTD 7-518", 29.7#Ift, NT-80, NSCC. REV. BY ............ , :JI!!I!II!!!!I ...........................¡ ... II~ KB. ELEV", BF. ELEV.. 4-1/2" OTIS CP-2 TRSSV (3.81" ID) .. GASLlFT MANDRELS I I "X" NIPPLE ~ B - PACKER ~ .. " " " " " ,', ~~,~,~,~,~,~,~,~ COMMENTS "X" NIPPLE "X" NIPPLE WLEG NIAKUK WELL: API NO: SEe : TN : RGE BP Exploration (Alaska) EXHll )1-2 TYPICAL CONVENTIONAL WELL SC )VlATIC (41/2" OR 51/2" TUBING) TREE: 7 1/16" CIW WELLHEAD: 135/8" FMC ACTUATOR: Baker 13-3/8", 72 #/ft, L-80, BTRS 5 1/2" TUBING OR 4-1/2" TUBING TOP OF 7" LINER 9-5/8", 47#/ft, L-80, NSCC PBTD 7", 29 #/ft, L-80, NSCC DATE REV. BY (1) .. :1:1111111:11111111111111111::1 I g I g Z7t ~~ .. "'\, '" "' "' "" """"". , , , , , ~ .JI' "' ~ ~ COMMENTS KB. ELEV = BF. ELEV = ( Otis Model 10 TRSV) ( 4.562 " ID) ~ GAS LIFT MANDRELS "SWS" NIPPLE - PACKER "SWS" NIPPLE "XN" NIPPLE TBG TAIL ~ MARKER JOINT R t.c.t.\\jt.U X) \994 ~ 0 \j \ corom\ss\O' \ . GaS cons. ~f' Û\\ &. .. ~\'ö.S1i'a. j\nc\\OT" NIAKUK WELL: API NO: SEC : TN :RGE BP Exploration (Alaska) ) ) Exhibit 1-1 Beaufort Sea Source Water Analysis Determination Summer Winter Units Specific Gravity 1.013 1.024 Mg/L pH 7.5 7.8 Mg/L Calcium 196.0 365.0 Mg/L Magnesium 631.0 1190.0 Mg/L Sodium & Potassium 5680.0 10400.0 Mg/L S tronti urn 0.0 0.0 Mg/L Barium 0.0 0.0 Mg/L Iron 0.0 0.0 Mg/L Bicarbonate 85.0 142.0 Mg/L Carbon Dioxide Calc. 0.0 0.0 Mg/L Total Dissolved Solids 17852.0 32787.0 Mg/L Chloride 9880.0 18200.0 Mg/L Sulfate 1380.0 2490.0 Mg/L Resistivity @ 70°F 0.422 0.255 Ohms Suspended Solids 6.0 1.0 Mg/L ,) ) Exhibit J-2 Clay Content in Niakuk Reservoir Zones Zone/ Well Sampled Zone 3 (NK #1 A) Zone 0 (N K #5) Zone E (NK #6) Zone F (NK #6) Clay Content· 0-1 % kaolinite, 1-2% illite trace to 1 % illite, trace kaolinite &/or chlorite trace only of illite trace only of kaolinite, trace only of illite · Based on Scanning Electron Microscopy, X-ray diffraction, and Energy Dispursive X-ray Spectroscopy '" ) Exhibit J-3 Niakuk Produced Water Analysis Determination pH Calcium Magnesium Sodium Potass i urn Strontium Barium Iron Bicarbonate Chloride Sulfate Total Dissolved Solids Value 7.0 95.0 22.0 9925.0 147.0 16.0 1.7 5.2 3870.0 11440.0 190.0 25711.9 ) Units Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L '1~\) ~C:.~\~ ~ \?J?Jb. ,I \ ~ .~$\O~ \\.\ a '{ ~o'{{\~'\ \'\ fòo'r\'S· .~ ~ G'ò.s r I;:¡ ~\,~ \)\: f\.~t"O~ (". . ' ~'ò.~t" t'\ 0" ) Exhibit J-4 ) Lisburne Produced Water Analysis Determination pH Calcium Magnesium Sodium (calc) Sodium (AA) Strontium Barium Iron Hydroxyl Carbonate Bicarbonate Chloride Sulfate Total Dissolved Solids Value 8.5 105.0 50.0 10555.0 13875.0 3.8 1.1 1.1 0.0 228.0 2618.0 14261.0 750.0 28753.0 Units Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L .:¡. ) Exhibit J-5 ) Pt. McIntyre Produced Water Analysis Determination pH Calcium Magnesium Sodium Potassium Strontium Barium Iron Hydroxyl Carbonate Bicarbonate Resistivity @ 68°P Chloride Silicon Value 7.2 24.0 9.0 8540.0 179.0 7.0 11.0 1.4 0.0 0.0 3262.0 0.4 10597.0 24.0 Units Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Mg/L Ohms Mg/L Mg/L 1<\." '~ ) ) Exhibit M-1 Documentation of Water Salinity Calculations from Well Logs The four wells, NK-1, NK-3, NK-6 and SO-8, were selected for the calculation because they are spatially representative of the Niakuk Injection Area and have wire line logs up-section and through the Kuparuk Formation. The steps in the calculation were: 1) Formation Temperature: Tfm = 0.0222 (Depth fm - Depth base of permafrost) + 32 deg. F 2) Porosity from Sonic Log: 0.625 * (dt-55) Phi = --------------------------- dt 3) Apparent Formation Water Resistivity (m and a from Humble equation): Phi**m * Rt Rwa = ------------------------- a 4) Water Resistivity @ 75 deg. (Schlumberger): Rwa * Tfm + 6.77 Rw@75 = ---------------------------- 81.77 5) Total Dissolved Solids in NaCI Equivalents (Dresser Atlas): (3.562 - log10 (Rw@75 - 0.0123)) TDS = 10** ----------------------------------------------------- 0.955