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Home My WebLink AboutAIO 010 A . . INDEX AREA INJECTION ORDER NO. lO-A MILNE POINT UNIT 1) 2) 3) 4) 5) 6) 7)" 8) 9) 10) 11) July 27,2001 August 9,2001 August 18, 2001 August 17, 2001 August 24, 2001 August 28, 2001 September 18,2001 October 12,2001 October 29, 2001 November 29, 2001 December 14,2001 e-mail re request AIO 10 Notice of Hearing and Affidavit of Publication Notice of Hearing and Affidavit of Publication, bulk mailing list EOR Strategy and Implementation Plan and Application to Amend AIO 10 Confidential diskettes (filed in Conf. Rm, Under AIO lOA) Ltr from BPXA to AOGCC re: EOR Project (Confidential maps located in conf. Room) Ltr from BP re: possible fracturing e-mail re: Draft Geology input to AIO #10 Ltr from AOGCC to BPXA re: proposed miscible gas injection project Notification of Additional Potable Water Use and Water Sources e-mail re: Request for Administrative Approval for AIO lOA Waste Water Effluent AREA INJECTION ORDER NO. lO-A · -. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order allowing underground injection of fluids for enhanced oil recovery in Milne Point Unit. ) Area Injection Order No. 10-A ) Milne Point Unit ) Kuparuk River Oil Pool ) Schrader Bluff Oil Pool ) ) ) October 29,2001 IT APPEARING THAT: 1. By application dated August 17,2001, BP Exploration (Alaska) Inc. ("BP") requested that the Alaska Oil and Gas Conservation Commission ("Commission") amend Area Injection Order No. 10 ("AIO lO") to cover a proposed miscible gas enhanced recovery project in the Kuparuk River Oil Pool ("KROP") within the Milne Point Unit ("MPU"). BP provided supplemental information on August 27,2001 regarding the miscible gas injection project planned for the Kuparuk reservoir. 2. The Commission published notice of opportunity for a public hearing in the Anchorage Daily News on August 18, 2001. 3. The Commission did not receive a protest or written request for a public hearing. 4. BP provided sufficient information on which to make a ruling without need for a hearing. 5. BP supplied additional information on October 12,2001 at the Commission's request to help clarify certain geologic and reservoir information. FINDINGS: 1. Authority 20 AAC 25.460 Commission regulation 20 AAC 25.460 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. AIO 10, originally issued September 19, 1986 authorized enhanced recovery injection operations within the Kuparuk River Oil Pool. By an order dated December 30, 1991, AIO 10 was amended to allow enhanced recovery operations for the Schrader Bluff Oil Pool ("SBOP") within MPU. AIO 10 was amended for expansion of the effected areas of enhanced recovery operations on May 3, 1994 and November 13, 1995. Area Injection Order 1(,. October 29,2001 . Page 2 2. Summary of Injection Projects As authorized by AIO 10, BP has conducted an immiscible water/alternating gas ("IW AG") enhanced oil recovery ("EOR") project in the MPU KROP for the past several years and a waterflood project has been and continues to be conducted in the SBOP. The applications from the MPU operator upon which the Commission based the prior AIO 10 order and amendments described enhanced recovery operations utilizing produced and source water for pressure maintenance and enhanced recovery, and re- injection of produced MPU gas into the KROP. BP proposes to initiate a miscible water/alternating gas ("MW AG") project for the MPU KROP. BP's application of August 17, 2001 addressed specific requirements of 20 AAC 25.402(c) that pertain to the Kuparuk MWAG project which were not addressed in prior AIO applications. In addition to the description of the MW AG project, BP proposed that separate orders be made for the KROP and SBOP, with the described area to govern the KROP MW AG operations to coincide with the MPU boundaries. 3. Project Area (20 AAC 25.402(c)(1 )), Pool Description (Pool Information (20 AAC 25.402(c)(5) a) Proposed MW AG Area: The MW AG project area includes that portion of the Kuparuk River Field, Kuparuk River Oil Pool (CO 349A), which is encompassed within the Milne Point Unit Boundary. b) Kuparuk River Oil Pool: The KROP is the accumulation of hydrocarbons that correlates with the interval of the ARCO Alaska, Inc. West Sak River State Well No.1 between the measured depths of 6,474 feet and 6,880 feet (CO 173, 349 and 349A). c) Schrader Bluff Oil Pool: The SBOP within the MPU, as described in Conservation Order No. 255, is the accumulation of hydrocarbons that correlates and is common to the stratigraphic section occurring in the Conoco Inc. Milne Point A-I well between the measured depths of 4,174 and 4,800 feet. 4. Operators/Surface Owners (20 AAC 25.402(c)(2) and 20 AAC 25.403(c)(3)) BP has provided all designated operators within one-quarter mile of the MPU with a copy of the application for amendment of AIO 10. Those operators are: BP, operator of MPU and Prudhoe Bay Unit, Phillips Alaska, Inc., operator of the Kuparuk River Unit, and J. Andrew Bachner, operator of leases ADL 389717 and ADL 389718. The State of Alaska, Department of Natural Resources is the only affected surface owner. 5. Description of Operation (20 AAC 25.402(c)(4)). The MPU KROP is currently developed on 8 pads. Water and lean (immiscible) gas (IW AG) is injected at pads C, E, F and L, while only water is injected at pads B, H, J and K. IW AG injection wells within the planned project area will be switched to MW AG injection. The predicted daily rate of miscible hydrocarbon gas injection is Area Injection Order 10. October 29,2001 . Page 3 approximately 25 MMSCF. The miscible injectant ("MI") will be manufactured by blending 4-5 MBPD of imported natural gas liquids ("NGL's") from the Prudhoe Bay Unit with approximately 20 MMscfd of produced gas from Milne Point production. Additional facilities required to implement this project include: a) new 8" pipeline from an existing pipeline tied into the Oliktok pipeline which carries NGL's from Prudhoe Bay Unit to the Kuparuk River Unit; b) custody transfer meter which will measure the NGL's imported for use at the MPU and; c) pumps located at the Central Facilities Pad ("CFP") to increase pressure of the NGL's from 100 to 4750 psig. 6. Geologic Information (20 AAC 25.402(c)(6)) The following is a summary of the geologic information for the Kuparuk River Formation within the MWAG project area at MPU. a) Reservoir Interval for MW AG Proiect: The reservoir interval for proposed injection is the Kuparuk River Formation, which is defined as an accumulation of oil that correlates with the interval between 6,474 and 6,880 feet, measured depth in the Atlantic Richfield Company West Sak River State No.1 well. b ) Available Data: BP and Conoco have drilled over 200 exploratory, delineation and development wells that penetrated the Kuparuk River Formation within the Milne Point Unit. Well and 3-D seismic data have been used to characterize the Kuparuk hydrocarbon accumulation. c) Stratigraphy - Kuparuk River Formation: The Kuparuk River Formation comprises a sequence of very fine to fine-grained marine sandstones and associated mudstones that are Cretaceous-aged. At Milne Point, the Kuparuk River Formation is informally divided into four stratigraphic units that are named, in ascending order, the A, B, C and D units. d) Kuparuk A Unit: Within the MPU, the Kuparuk A unit consists of a sandstones, siltstones and mudstones deposited in three regressive cycles; each cycle coarsens and cleans upwards. The overall Kuparuk A unit is up to 140 feet thick, and it contains amalgamated sandstone bodies up to 40 feet thick in each cycle. These sandstone bodies are northeast trending, lenticular, shingled, and up to 15 miles in length. Their permeability and porosity average approximately 100 md and 21 %, respectively. Widespread siltstone and mudstone intervals separate the sandstone bodies. e) Kuparuk B Unit: The overlying Kuparuk B unit also consists of interbedded sandstone, siltstone and shale. In the southeastern area of the field, the upper B interval contains a thick, blocky to coarsening upward shoreface sand sequence that is about 30 feet thick. This upper B sand has an average permeability of 200 md and 21 % porosity. A major unconformity, the Lower Cretaceous Unconformity, defines the top of the Kuparuk B unit. Area Injection Order 1_ October 29,2001 . Page 4 f) Kuparuk C Unit: The Kuparuk C unit consists of fine to very fine grained sandstone that is bioturbated and highly glauconitic. There are discontinuous siderite cemented intervals in the Kuparuk C unit, which do not impact fluid movement within the reservoir. Overall, the geometry of the Kuparuk C sandstone is blanket-like, but individual sandstone bodies are poorly defined because of syndepositional faulting and erosional truncations. Penneability and porosity average approximately 100 md and 20%, respectively. g) Kuparuk D Unit: The Kuparuk D unit at the top of the fonnation consists of silty mudstone. There is no reservoir quality rock in this interval. h) Structure Overview: At Kuparuk Fonnation level, the MPU is a faulted anticlinal structure that plunges toward the northwest and the southeast. Within the field, complex faulting has rearranged the overall structure into many compartmentalized fault blocks. Stratigraphic discontinuities and differential movement along the faults have created numerous pressure barriers and trapping elements. Variable oil water contacts are present. In general, deeper oil-water contacts are found toward the northwest and they become shallower toward the south and eastern portions of the field. i) Confining Interval: Within the MPU, the confining interval above the Kuparuk reservoirs consists of more than 2,000 feet of Cretaceous age Colville shale. The lower confining interval consists of the Miluveach and Kingak shales, which exceeds 1,500 feet in combined thickness. j) Oil Properties: Kuparuk oil gravity averages 22 API in the Milne Point field, and it ranges fÌ'om 21 API to 26 API. Initial solution gas/oil ratios are approximately 300 SCFIBBL. At the 170 deg F reservoir temperature, oil viscosity is typically 2-4 cpo Initial reservoir pressure is 3,500 psi at the datum depth of 7000 feet TVD subsea. Bubble point pressure is about 2,200 psi, which is significantly below initial pressure. k) Original Oil in Place: Estimated total original oil in place (OOIP) for the Kuparuk at MPU is approximately 921 MMSTB, with distribution among the A, B, and C sandstone units at about 70.7%, 18.7% and 10.6%, respectively. The estimated OOIP within the proposed MW AG area is 396 MMSTB, with the A unit the primary target. 7. Injection Fluids (20 AAC 25.402(c)(9)). The Kuparuk MWAG project will utilize three primary types of injection fluids: source water, produced water, and miscible hydrocarbon gas. a. Source Water and Produced Water: The produced and source water (from the Prince Creek fonnation) injected in the MW AG project has been described in the prior AIO 10 applications. The approximate water injection volume needed is 60,000 barrels ("bbl") of water per day and may be increased as needed to make up reservoir voidage. Area Injection Order 1_ October 29,2001 . Page 5 b. Miscible Hydrocarbon Gas: The miscible hydrocarbon gas will be a blend of the MPU produced gas and NGL's imported from the Prudhoe Bay Unit. The specific blend of gas and NGL's will be regulated to ensure that miscibility between the injected gas and the reservoir fluids is maintained. The estimated composition of the miscible hydrocarbon gas is based on a blend ratio of 4.512 MSCF lean gaslbbl NGL for a minimum miscibility pressure of approximately 2900 psia. This composition will vary with the blend ratio of lean gas to NGL's. The predicted daily rate of miscible hydrocarbon gas injection is approximately 25 MMSCF. Fluid incompatibility problems are not anticipated with the miscible hydrocarbon gas. c. Other Fluids: In addition to the fluids specifically associated with the Kuparuk MW AG project, the following other incidental fluids might be injected into the KROP at some time during the life of the project primarily to enhance recovery of oil and gas: · Seawater to thermally fracture gas injection wells - a stimulation procedure using 20,000 - 40,000 gallons per well · Solution gas associated with oil production - re-injected for reservoir pressure maintenance · Tracer survey fluid - to monitor reservoir performance 8. Well Logs (20 AAC 25.402(c)(7)): The logs of existing injection wells are on file with the Commission. 9. Mechanical Integrity (20 AAC 25.402(c)(8)): Wells used for injection will be cased and cemented in accordance with 20 AAC 25.412. In drilling all MPU injection wells, the casing is pressure tested in accordance with 20 AAC 25.030. Injection well tubing/casing annulus pressures will be monitored and recorded on a regular basis. The MPU KROP injection wells are designed to comply with the requirements specified in 20 AAC 25.412. 10. Injection Pressures (20 AAC 25.402(c)(10)): Surface injection pressures are dependent on fluid type. The estimated average and maximum injection pressure for the Kuparuk MW AG project is as follows: Service Water injection Gas injection Surface Operating Pressure PSIG Maximum Average 3500 4800 3000 4000 11. Fracture Information (20 AAC 25.402(c)(11)): The KROP is overlain by more than 2,000 feet of confining shale that act as an impermeable barrier. While water Area Injection Order 10_ October 29,2001 . Page 6 injection pressure exceeds the fracture gradient of the Kuparuk sands in many of the injectors, fractures initiated in the Kuparuk injection interval should not significantly penetrate the confining shale. Existing surveillance results indicate that injection has remained within the targeted Kuparuk injection interval. 12. Water Analysis (20 AAC 25.402(c)(12)): The quality of the water within the formation into which fluid injection is proposed was described in the prior AIO 10 application. Subsequent samples confirm that the water quality in the MW AG injection zone is well in excess of 10,000 mgll TDS. 13. Aquifer Exemption (20 AAC 25.402(c)(13)): Aquifer Exemption Order 2 (AEO 2) was issued by the Commission on July 8, 1987 and covers Class II injection activities within the following lands: T13N, R9E, UM - Sections 13, 14,23 and 24 T13N, RlOE, UM - All sections T13N, R11E, UM - Sections 5, 6, 7, 8, 15, 16, 17, 18, 19,20,21, 22, 29, 30, 31 and 32 These lands are the same as those included in the SBOP described in CO No. 255 and the Schrader Bluff Oil Pool waterflood project described in CO No. 283. In its application for exemption, Conoco (Operator at MPU at that time) stated it was seeking an exemption for the Shallow Sand formations (Tertiary water sands) now designated the Prince Creek formation, located above the SBOP. Further information concerning the aquifer is contained in Commission records regarding AEO 2. 14. Hydrocarbon Recovery (20 AAC 25.402(c)(14)): BP predicts the MW AG project will result in an incremental ultimate oil recovery increase of 7 1/2% - 10% OOIP compared to waterflood, resulting in added reserves of about 30-40 MMSTB (excluding NGL's). IWAG alone is projected at 1% to 3% incremental over waterflood. Estimated peak production increase is 9 MBOPD. The following provides additional reservoir and surveillance information provided by BP in support of the recovery projections. More detailed information is available in the documentation submitted by BP in support of the AIO-I0A application, which is included in the record. a) Minimum Miscibility Pressure: The MW AG project utilizes a vaporizing- condensing process similar to EOR projects in the Kuparuk River Unit, Prudhoe Bay Unit, Endicott, and Point McIntyre. Slim tube laboratory work utilizing Milne Kuparuk oil and Prudhoe Bay NGL's showed that at approximately 21 % enrichment, the displacement process becomes nearly miscible with oil, which validates the earlier equation of state used in reservoir simulation. The anticipated minimum miscibility at the CFP blending point is 2935 psia, with a blend ratio of 4.6 Mscf separator off gas/stb NGL. This blend ratio will change after startup time to adjust for changes in composition of separator gas as NGL's return in the production stream. Area Injection Order 10_ October 29, 2001 . Page 7 b) Iniection Patterns. The MPU KROP was not developed on a regular pattern basis due to its complex faulted nature. BP has characterized the reservoir using fault blocks or hydraulic units ("HU"), which are based upon understanding of the water oil contacts, fault locations, pressure differences between fault blocks, and response of producers to injectors. BP characterizes the MPU KROP as 77 separate hydraulic units, with 46 currently targeted for MW AG. Each hydraulic unit is anywhere from one to five "patterns" (or area bounded by layout of injectors and producers). c) Reservoir Simulation: A generalized A-sand fully compositional pattern model was utilized for analysis of recovery under IW AG and MW AG processes, and for slug volume sensitivities. The model utilizes a 12 component Peng-Robinson equation of state, which was tuned to conventional PVT samples from Milne Point Kuparuk wells and validated by the slim tube studies noted earlier. The model simulated 80-acre pattern with one injector and two producers. BP provided documentation of this model effort for the record. d) MI Volumes: The MWAG project is planned for the injection of a 30% hydrocarbon pore volume ("HCPV") slug of MI. The average pattern throughput rate is approximately 9.4% HCPV per year. The model studies showed incremental recoveries of approximately 7.5% (20% HCPV injected) and 10% (30% HCPV injected). Prioritization of patterns to receive MW AG is required since available MI will be limited. e) WAG ratios: Current plans are to maintain a WAG injection ratio of 1 (1 BBL water to 1 reservoir BBL gas). Higher WAG ratios will be utilized in patterns with high GOR, and in patterns where potential gas breakthrough could be a detriment to the electrical submersible pumps. Reservoir simulation suggests potential for slightly higher recoveries with increased WAG ratios. Further study and review of production performance is planned to better define the effects of WAG ratios. t) Surveillance: Pattern management and optimization will be necessary to maximize recovery. BP plans significant surveillance activities to accomplish the management field-wide and within individual hydraulic units. Focus will be given to maximize areal and vertical sweep of the reservoir. This will require continual update of fault and geologic information, and well performance analysis. BP plans to monitor the injection performance through yearly reservoir pressure monitoring and injection profiles within each hydraulic unit, and regular sampling and analysis of produced oil gravities and gas compositions. g) Pressure and V oidage replacement: BP plans to maintain the reservoir pressure close to original pressure (approximately 3500 psi) with a minimum reservoir pressure of 2450 psi and a maximum of 4000 psi. Pressure surveys indicate some hydraulic units are currently outside this pressure range. Initially, voidage replacement will be adjusted to achieve these pressure targets. Ultimately, a voidage replacement ratio of 1: 1 is planned. Area Injection Order IG_ October 29, 2001 -- Page 8 15) Mechanical Condition of Adjacent Wells (20 AAC 25.402(c)(15)). BP is utilizing injection wells previously covered by AIO 10. To the best of BP's knowledge, the wells in the MW AG Area were constructed and, where applicable, have been abandoned to prevent the movement into freshwater sources. Information regarding wells that penetrate the injection zone within y,¡ mile radius of injection wells has been filed with the Commission. 16) Incorporation of AIO 10 findings: The findings of fact in AIO 10 and amendments thereto are incorporated herein to the extent not inconsistent with this order. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An area injection order is appropriate for the proposed MW AG project under 20 AAC 25.460. MW AG is only planned for the KROP at this time. 3. Revision of AIO 10 is appropriate to clarify the rules applicable to each of the Kuparuk River and the Schrader Bluff Oil Pools in the MPU, specifically as regards the enhanced recovery fluids approved for injection within the separate pools. 4. Revision of AIO 10 to coincide with the boundaries ofthe MPU is appropriate. 5. With the exclusion of miscible gas injection, the Class II fluids described in BP's application are currently injected under prior Commission approval of AIO 10. No problems with compatibility of the fluids have been observed. Similar injection of miscible gas in the Kuparuk River Pool of the Kuparuk River Unit has shown no compatibility problems. 6. Injection in enhanced recovery injection wells in the KROP in the MPU will not involve injection in, or movement of fluids into, the Shallow Sands strata aquifer described in AEO 2 application and supplemental materials. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 7. The proposed miscible gas injection for the Kuparuk Oil Pool in the Milne Point Area is likely to significantly increase hydrocarbon ultimate recovery. 8. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 9. The MPU KROP injection wells are designed to comply with the mechanical integrity requirements specified in 20 AAC 25.412. 10. The conclusions in AIO 10 and the amendments thereto are incorporated herein to the extent not inconsistent with this order. Area Injection Order 1_ October 29, 2001 . Page 9 NOW, THEREFORE, IT IS ORDERED: 1. Except as otherwise provided herein, this order supersedes Area Injection Order No. 10 and previous revisions. 2. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), govern enhanced oil recovery injection operations in the MPU. The MPU as of the effective date of this order is described below Umiat Meridian Township Range Sections T12N RI0E 1-2 (all); 11-12 (all) T12N R11E 1-12 (all) T13N R9E 1 (all); 2 (Nl/2,SEl/4); 11 (NEl/4); 12-14 (all); 23-24 (all) T13N RI0E 1 (Sl/2, SW l/4NWl/4); 2-36 (all) T13N R11E 7 (SWl/4SWl/4); 18 (NWl/4NEI/4, Wl/2SEl/4, SEI/4SEl/4, SWl/4, WII2NWl/4, NEl/4NWl/4); 19 (all); 20(Wl/2SEI/4, SWl/4,SEl/4SEl/4,Wl/2NWl/4,SEl/4NWl/4); 27-34 (all) T14N R9E 22 (SEI/4SEl/4); 23 (SEl/4, SI/2SWl/4;NEl/4SWl/4, Sl/2NEl/4, NEl/4NEl/4); 24 -26 (all), 27 (El/2, El/2SWl/4,SEl/4NWl/4); 34 (NEl/4SEl/4, El/2NE1/4, NWl/4NEl/4); 35 - 36 (all) T14N RI0E 17 (SWl/4SEl/4, Sl/2SWl/4); 18 (Sl/2SEl/4); 19 (all), 20 (SI/2, NWl/4, Wl/2NEl/4); 21 (SWI/4); 27 (Sl/2SWl/4), 28 (Wl/2SEl/4, SEl/4SEl/4,Wl/2), 29-34 (all); 35 (SWl/4, Sl/2NWl/4, Wl/2SEl/4, SEl/4SEl/4) Rule 1 MPU Authorized Iniection Strata for Enhanced Recovery and Authorized Iniection Fluids Enhanced recovery operations as described in the operator's applications are approved within the MPU for the KROP and SBOP. Part A defines the strata and authorized fluids for injection within the KROP of the MPU, and Part B defines the strata and authorized fluids for injection within the SBOP. Area Injection Order 1_ October 29,2001 . Page 10 PART A - Kuparuk River Oil Pool 1) Kuparuk River Oil Pool- Authorized Injection Strata: Within the MPU, authorized fluids may be injected into the strata that correlate with the interval between the measured depths of 6,474 feet and 6,880 feet in the ARCO Alaska, Inc. West Sak River State Well No.1. 2) Kuparuk River Oil Pool - Authorized Injection Fluids: Fluids authorized for injection for the KROP within the MPU are: a. produced water and gas from Milne Point Unit production for purposes of pressure maintenance and enhanced recovery; b. source water from the Prince Creek Formation; c. seawater to thermally fracture gas injection wells; d. tracer survey fluid to monitor reservoir performance; e. fluids injected for the purposes of stimulation per 20 AAC 24.280(2) and; f. miscible gas injectant (including NGL's imported from the Prudhoe Bay Unit) for purposes of pressure maintenance and enhanced recovery). PART B - Schrader Bluff Oil Pool 1) Schrader Bluff Oil Pool Authorized Injection Strata: Within the MPU, authorized fluids may be injected into the strata that correlate with and are common to the interval between the measured depths of 4,174 feet and 4,800 feet in the Conoco Milne Point Unit Well No. A-I. 2) Schrader Bluff Oil Pool Authorized fluids: Fluids authorized for injection for the SBOP within the MPU are: a. produced water from Milne Point Unit production for purposes of pressure maintenance and enhanced recovery; b. source water from the Prince Creek Formation; c. tracer survey fluid to monitor reservoir performance; and d. fluids injected for the purposes of stimulation per 20AAC24.280(2). Rule 2 Fluid Injection Wells The underground injection of fluids must be 1) through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the effective date of AIO 10 (September 19, 1986). Rule 3 Monitorin2 the Tubin2-Casin2 Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be Area Injection Order 10. October 29,2001 . Page 11 checked at least weekly to confirm continued mechanical integrity. Rule 4 Demonstration of Tubine:-Casine: Annulus Mechanical Intee:ritv A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. Rule 5 Notification of Well Intee:ritv Failure Whenever injection rates and/or operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must immediately shut in and secure the well, notify the Commission on the first working day following the observation, and submit a plan of corrective action on Form 10-403 for Commission approval. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. Rule 6 Notification of Improper Class II Iniection Injection of fluids other than those listed in Rule 1, above, without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the Commission, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 7 Other Conditions a. It is a condition of this authorization that the operator comply with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 8 Administrative Action Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively Area Injection Order 10_ October 29,2001 . Page 12 amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated October 29,2001. ~~..-~~. .. ~;;.~:' f~:",,I" " ....>.. , \. ~,. ,~J.. l"" " ,<, :\ ':' .:. .': ~·-·:~·~·,t~··<~ ~ ' h '}. ,'. .' . ¡ .' ¡ '0 t:). .. ,f ~ ~~ " ,\ { : ;' : .. /'~ "~"" " : "" , p ...~. ,\ 'Ø If,. ...... . ... ~":.', ......!-~ ~ .-". ... ._1 1\ : ..., >~j . ··<:~~¡sl " ".:. -',' I.~' .' '-~.~. ~»)" d'" +!-'.... t· "'.' Æ LÆI~.6i LiL<4:Á.,M~~,/ Cammy Oe· sli Taylor, Chait Alaska Oil and Gas Conservation Commission Ç) Danie T. Seamo t, Jr., Commissioner Alaska Oil and Gas Conservation Commission ~M,~ Julie M. Heusser, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the lO-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 (i.e., lOth day after the application for rehearing was filed). PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 2121 NORTH BAYSHORE DR #616 MIAMI, FL 33137 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN,IL 61820 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 - NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 e OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LlBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 10GCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MURPHY EXPLORATION & PRODUCTION CO., BOB SAWYER 550 WESTLAKE PARK BLVD STE 1000 HOUSTON, TX 77079 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC.. ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON. TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 e OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON. TX 77027 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR PO BOX 2100 HOUSTON, TX 77252-9987 TEXACO INC. R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 C & R INDUSTRIES, INC... KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 e PETRAL CONSULTING CO. DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON. TX 77042 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLOR CO. LANDIREGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 PO BOX2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 BABCOCK & BROWN ENERGY, INC.. 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE,VVA 98101 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 e RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 e JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, 10 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 DEPT OF REVENUE, OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 DNR, DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 e GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 US BLM AK DIST OFC, GEOLOGIST ARTHUR BANET 949 EAST 36TH AVE STE 308 ANCHORAGE, AK 99508 UOA/ ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 e DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR AND ENG SERVICE, MIKE TORPY 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 BUREAU OF LAND MANAGEMENT, GREG NOBLE 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 GORDON J. SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, RESOURCE EVAl JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHilLIPS ALASKA, STEVE BENZlER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 Al YESKA PIPELINE SERV CO, lEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 GERALD GANOPOlE CONSULT GEOl 2536 ARLINGTON ANCHORAGE, AK 99517-1303 e US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MillER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHilLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 PHilLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHilLIPS ALASKA, KUP CENTRAL WEllS ST TSTNG WEll ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 ANCHORAGE DAilY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 JWl ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 e US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 JOHN MillER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHilLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHilLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 PHilLIPS ALASKA, lEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 Al YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TElEQUANA DR. ANCHORAGE, AK 99517 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 TESORO ALASKA COMPANY, PO BOX 196272 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 RON DOLCH OK POBOX 83 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 e HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 196168 ANCHORAGE, AK 99519-6168 EXXON MOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 e OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 ENSTAR NATURAL GAS CO, PRESIDENT TONY IZZO POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSUL 10510 Constitution Circle EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST PO DRAWER 66 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ,AK 99686 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 e PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 e KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR PO BOX 98 VALDEZ, AK 99686-0098 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 · . ~1f~1fŒ (ID~ ~~~~[K{~ / / TONY KNOWLES, GOVERNOR AIASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. ]TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO lO-A.OOl Alison Cooke Air/Waste/Water Compliance BP Exploration Alaska, Inc. PO Box 196612 Anchorage, Alaska 99519-6612 Re: Injection of Treated Wastewater Effluent into MPU EOR Wells Dear Ms. Cooke: Per your E-mail to Jane Williamson dated December 12, 2001, BP requested an administrative approval to authorize injection of treated effluent from the Milne Point Wastewater Treatment Plant down EOR wells. The original Area Injection Order (AlO 10) was issued September 19, 1986 and amended May 3, 1994 and allowed that "non-hazardous fluids may be injected for purposes of pressure maintenance and enhanced oil recovery". Initial application by then Operator Conoco requested approval for injection of miscellaneous water including non- hazardous surface water and associated surfactants/solvents used in the washing and cleaning. It was anticipated at that time, that 10 BBL/D would be injected. While no direct mention was provided in the rules specifying surface water as an authorized fluid for EOR purposes, it appears that the intent at that time was to allow for this. As such, under this original authorization, Milne Point has been injecting wastewater. The Commission recently issued on October 29,2001 AlO 10-A, which supersedes AlO 10. AIO lO-A specifically addressed fluids allowed for injection into the formation. The application from BP and the subsequent AlO 10-A order did not include treated wastewater effluent as an authorized fluid for injection. Per your documentation maximum effluent is estimated at 14,710 gal/day, assuming all potable water goes into the waste water system. BP plans the addition of a new system backwash, up to 700 gal/day (with water softening), which will be routed to the wastewater. This wastewater effluent is pumped into a header that discharges into the water injection surge drum, and is mixed with produced water, source water and water from de-watering activities. Water collected from reserve pits, well house cellars and any standing ponds on the pads is pumped is either commingled with source water at A Pad or runs back through the production process and becomes part of the produced water stream. This pit water is filtered (300 micron). Based on Milne Point EOR operating experience, the low volume of wastewater effluent (less than 1 % of total EOR water flow), and a review of the analysis of a limited number of samples, the waste water effluent water appears compatible with the other EOR waters. It is understood that trace chemicals are required in the treatment of the water as outlined bye-mail from Tom Simpson to Jane Williamson dated December 14, 2001. AlD 1OA.00 1 December 14,2001 Page 2 of 2 , . The Commission approves BP's request to allow for wastewater effluent to be injected for EOR application. Accordingly, the following Part A(2) and Part B(2) of Rule I of AlO lO-A are revised as follows: AIO lO-A Rule 1 Part A (2) 2) Kuparuk River Oil Pool- Authorized Injection Fluids: The following fluids are approved for injection into the KROP within the MPU: a. produced water and gas from Mime Point Unit production for purposes of pressure maintenance and enhanced recovery; b. source water from the Prince Creek Formation; c. seawater to thermally fracture gas injection wells; d. tracer survey fluid to monitor reservoir performance; e. fluids injected for the purposes of stimulation per 20 AAC 24.280(2); f. miscible gas injectant (including NGL's imported from the Prudhoe Bay Unit) for purposes of pressure maintenance and enhanced recovery); and g. non-hazardous treated wastewater from the Mime Point Wastewater Treatment Plant and non~hazardous water collected from MPU reserve pits, well house cellars and standing ponds. Rule 1 Part B (2) 2) Shrader Bluff Oil Pool- Authorized Injection Fluids: The following fluids are approved for injection into the SROP within the MPU: a. produced water from Mime Point Unit production for purposes of pressure maintenance and enhanced recovery; b. source water from the Prince Creek Formation; c. seawater to thermally fracture gas injection wells; d. tracer survey fluid to monitor reservoir performance; e. fluids injected for the purposes of stimulation per 20 AAC 24.280(2); and f. non-hazardous treated wastewater from the Mime Point Wastewater Treatment Plant and non~hazardous water collected from MPU reserve pits well house cellars and standing ponds. £~ JU~=~'~ Commissioner Commissioner #11 Milne Point Request for Administrative ...ctio n Order lOA - Waste Water Effluent r. e Subject: Milne Point Request for Administrative Approval for Area Injectio n Order IOA- Waste Water Effluent Date: Fri, 14 Dec 2001 12:02:17 -0600 From: "MPU, Ops Support Supt" <MPUOpsSupportSupt@BP.com> To: "'Jane_ Williamson@admin.state.ak.us'" <Jane_ Williamson@admin.state.ak.us> CC: "Cooke, Alison D" <CookeAD@BP.com>, "ACT, ENV Advisor" <ACTENV ADVISOR@BP.com> In response to the requests for information concerning fluid compatibility, solids management and chemical treatment of the waste water effluent, we are providing information for the continued utilization of the waste water effluent water in the Milne Point EOR process. Fluid Compatibility Based on our Milne point EOR operating experience, the low volume of waste water effluent (approximately less than 1% of total EOR water flow) and a review of the analysis of a limited number of samples, the waste water effluent water is compatible with the other EOR waters. The water sample analysis is shown below: Produced Water Source Water Source Composite Waste Water Effluent* Tank Inlet Water Kuparak Units Date Sampled 12/4/01 8/14/01 7/3/1996 1999 1997 Calcium Total 69.31. 37 105 96.4 125 mg/l Iron Total <MDL 0.057 NR NR NR mg/l Magnesium Total 6.39 4.1 25 NR 70 mg/l Potassium Total 22.37 20 <1 7.6 63 mg/l Silicon Total 0.14 0.418 NR NR NR mg/l Sodium Total 155.1 75 963 890 9800 mg/l Chloride NR 93 1460 1450 14500 mg/l Sulfate NR 32 <10 <4 200 mg/l Alkalinity as CaC03 47 85.8 NR NR NR mg/l Hardness as CaC03 199.4 110 NR NR NR mg/l Conductivity 1295 uS/em 850 uS/em NR 3520 NR micro mho/em Total Solids 860 NR NR NR NR mg/l Total Dissolved Solids 810 526 NR NR NR mg/l Total Suspended Solids 2.9 NR NR NR NR mg/l Biochemical Oxygen Demand <MDL NR NR NR NR mg/l Ammonia-N <MDL NR NR NR NR mg/l lof3 12/14/014:15 PM Milne Point Request for Administrative ...ctio n Order lOA - Waste Water Effluent e e Percent Solids NR .06 NR NR NR % pH NR 7.03 7.66 7.5 7.7 unit Langelier Index NR -1. 08 NR NR NR unit Bicarbonate NR NR 84 117 1900 mg/l Barium NR NR 2.7 NR 25 mg/l Iodide NR NR <1 NR NR mg/l Strontium NR NR 1.0 NR 6 mg/l Carbonate NR NR NR 0 NR mg/l Silicon Dioxide NR NR NR 9.5 NR mg/l Dissolved Matter NR NR NR 2803 NR mg/l Total Matter NR NR NR 2865 NR mg/l MDL - Method Detection Limit NR - Not requested * Analysis by Northern Testing Laboratory, Inc. Waste Water Treatment Effluent Sludge The waste water treatment process captures and concentrates the majority of the solids. The solids fall to the bottom of the waste water digester unit. The solids are removed from the waste water treatment unit with a vacuum truck and transported to Pad 3 for disposal through downhole injection. Water Treatment Chemicals Our potable water is treated lake water. The majority of the potable water produced for the camp population and all of the filtered water and potable water used for regeneration and backwashing the potable water filtration and treatment units is processed in the waste water treatment unit. The following chemicals are used in the potable water and waste water treatment units: 1) Ciar-ion A405P - This polymer chemical is used to produce flocculent formation to remove suspended solids. This is the first step in the potable water treatment process improve water quality. The chemical feed rate is approximately 5 liters/day per 15,563 gals of water or .32 ml chemical per gal. 2) Sodium Hypochlorite - The sodium hypochlorite solution provides chlorine to control bacteria in the camp potable water. The average concentration is 0.5 mg/l. 3) Soda Ash (Sodium Carbonate Anhydrous) - This chemical is used to buffer and balance the potable water pH. The average feed rate is 4 liters per 26,510 gals of potable water or 0,15 ml per gal. 4) Nalco 7390 - This chemical is a corrosion inhibitor that forms a protective film reducing corrosion in the potable water copper piping and reduction in lead contamination. The chemical concentration is maintained at approximately 4 mg/l. 5) Calcium Hypochlorite - Calcium hypochlorite is mixed with water to form a chlorine solution and injected into the waste water effluent to maintain a 2.5 mg/l chlorine residual to control bacteria. All of the listed chemicals are NSF approved for potable water systems. De-Watering Solids Management Operations utilizes a 300 micron filter to capture solids in the water pumped into the A2A source water well discharge piping or the B2 production 20f3 12/14/014:15 PM Milne Point Request for Administrative ...ctio n Order lOA - Waste Water Effluent e e well piping. If you require additional information, please contact Koreen Burrow or vic Farris, ACT! Environmental Advisors, at 907-670-3382. Thanks, Tom Simpson MPU, Operations Support 907-670-3386 30f3 12/14/014:15 PM RE: Request for Administrative Approval e e Subject: RE: Request for Administrative Approval Date: Thu, 13 Dec 2001 15:43:49 -0600 From: "Cooke, Alison D" <CookeAD@BP.com> To: "MPU, Ops Support Supt" <MPUOpsSupportSupt@BP.com>, "Jane _ williamson@admin.state.ak.us'" <jane _ williamson@admin.state.ak.us> CC: "'tom _ maunder@admin.state.ak.us'" <tom _ maunder@admin.state.ak.us>, "Meek, GarryW" <Meekwg@BP.com>, "Short, James M" <ShortJM@BP.com> Jane, As I mentioned in my voicemail message, It is getting more critical that we get a verbal approval from the Commission to enable BP to start up the water softening system and inject the backflush of this treated potable water into the EOR process. The softened water is needed to reduce nitrogen oxide (NOX) emissions in gas turbines that have annual NOX emissions limits. Please call me this afternoon if you are available. I will be out on Friday. Please e-mail the Commission's response to Tom Simpson and Garry Meek at Milne Point. Their e-mail addresses are simpsotc@bp.com and meekgw@bp.com respectively. Thanks, Alison -----Original Message----- From: MPU, Ops Support Supt Sent: Thursday, December 13, 2001 10:18 AM To: Cooke, Alison D Subject: RE: Request for Administrative Approval Alison, Since you are flexing on Friday, Dec 14, who will tell us is OK to proceed with our new softening system? Tom -----Original Message----- From: Cooke, Alison D Sent: Thursday, December 13, 2001 9:45 AM To: Simpson, Tom C¡ ACT, ENV Advisor¡ Berlinger, Mark J Subject: FW: Request for Administrative Approval Tom, We will not have a response until Friday. Alison -----Original Message----- From: Jane Williamson [mailto:Jane Williamson@':t_<:l!!li:n.state.ak.us] Sent: wednesday, December 12, 2001 4:30 PM To: Cooke, Alison D Subject: Re: Request for Administrative Approval Thanks Alison, I have passed on to the Commissioners for their review. I will try to get something to you Friday. Jane "Cooke, Alison D" wrote: 1 on 12/14/01 4:16 PM RE: Request for Administrative Approval e e > Jane, > As we discussed, BP requests an administrative approval to authorize > injection of treated effluent from the Milne Point Wastewater Treatment > Plant down EOR wells. The Commission recently issued Area Injection Order > No. lOA allowing underground injection of fluids for enhanced recovery in > the Milne Point Unit. Finding 7 of the Order which deals with injection > fluids states that the three primary types of injection fluids are :source > water, produced water, and miscible hydrocarbon gas. BP requests the > administrative approval expand the eligible injection fluids to include > treated effluent. To support this approval we are including the following > information that you requested on the waste water treatment system and other > waters in the EOR process: > > Historical Waste Water Effluent Volumes Injected > We do not measure the flow from the waste water effluent plant into the EOR > system. If we assume that all of the potable water that is produced flows > into the waste water treatment plant, then a review of MPU potable water > volumes from July 27,2000 to Nov 19, 2001 shows we produced a total of > 7,075,575 gals or an average of 14,710 gal/day. > > Additional Waste Water Volumes from New System Backwashes > We estimate that the backwash for the new softening system would be > approximately 350 to 700 gals/day, dependent on water quality (water > hardness). The backwash for the new activated carbon system (chlorine > removal system) is estimated at 360 gal/day. These estimates may vary based > on actual operating experience once the system is placed in service. > > Waste Water Salinity > We have only one waste water effluent sample analysis for salinity, taken on > Aug 14, 2001, that showed a total sodium of 75 mg/l. > > Waste Water Injection into EOR Process > The treated waste water effluent is pumped into a header that discharges > into the Water Injection Surge Drum, V 5412, and is mixed with produced > water, source water and water from de-watering activities (reserve pits, > etc.). V5412 provides the water for the water injection system. > > Reserve pit Dewatering > Water collected from reserve pits, well house cellars and any standing ponds > on the pads is pumped into either the discharge piping at source water well > A2A at A Pad or the production line for B2 on B Pad. In other words, the > reserve pit water is either commingled with source water at A Pad or runs > back through the production process and becomes part of the produced water > stream. In both cases, it is ultimately used for EOR purposes. > > Annular Injection Disposal of Water > MPU Operations does not dispose of water through well annular injection. The > drilling rigs may have different permits. > > In addition to the administrative approval, BP requests verbal authorization > to proceed with the new softening system. The Commission was copied on a > notification to the ADEC concerning the use of treated potable water for > turbine water injection to decrease nitrogen oxide emissions. BP would like > Commission approval to inject the backwash from this softening system in 20f3 12/14/014:16 PM RE: Request for Administrative Approval . to > the EOR process. > > Please call me at 564-4838 if you have any questions. > Thanks, > Alison 3 on e 12114/014:16 PM #10 bp He e 0.....···..··.·.·..···.'.·...·........ ,.:"e' -."l', ..-~.. --:::..., ,~ '~,.··r" CERTIFIED MAIL # 7001 036000006101 6184 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Andlorage. Alaska 99519-6612 (907) 561-5111 November 29, 2001 Mr. Lee Johnson Alaska Department of Environmental Conservation 610 University Avenue Fairbanks, Alaska 99709 RECEIVED 07 2001 41aska Oil &. 13M CÖtíS. !,;ommissjDfi Notification of Additional Potable Water Use and Water Sources Milne Point Unit (PWS 10# 333336) Dear Mr. Johnson: BP Exploration(Alaska), Inc. (BPXA) is submitting to the Alaska Department of Environmental Conservation (ADEC) this description of a new industrial use of treated potable water from the Milne Point Unit Public Water System (MPU PWS). We are also notifying you of additional water sources that may be used at the MPU PWS to ensure adequate water supply for this new industrial use. After reviewing 18 AAC 80, Article 2., and in discussing this project with you by phone on November 13, 2001, we believe that this addition will not require plan approval under 18 AAC 80.200. As BPXA representatives discussed with you by phone on November 13, 2001, (BPXA)'s Milne Point Unit will utilize treated, potable water as a water supply to a gas turbine water injection treatment system. Water from the MPU PWS distribution will be directed first through a backflow preventer and then through a supplemental process water treatment system, which will remove chlorine and provide additional softening, if required. The water will then flow through a hose and an air gap or air break into a small storage tank. The storage tank supplies water to an Aqua-Chern vapor compressor evaporator (distiller) unit that produces distilled water for direct injection into twoGE LM 2500 turbine generators to control NOx air emissions. Due to projected delivery and installation schedule for the new equipment, the new water treatment system will be installed in two phases. Phase 1 will be the installation of a backflow preventer and the activated carbon filter to remove chlorine. The installation of the backflow preventer will be tested and Mr. Lee Johnson· .c MPU PWSID #333364 November 29, 2001 Page 2 e certified by a certified backflow preventer technician prior to placing in service. Later, Phase 2 will include the installation of the softeners and the associated brine regeneration system. The activated carbon filter and softener backwash water will be processed through the existing wastewater treatment plant. See attached drawings. The anticipated maximum potable water supply flow rate to the distiller unit is 15 gpm (21,600 gal/day). In order to satisfy the distiller water supply demand, Milne Point will transport 10,000 to 20,000 gal/day treated water from other North Slope oil field Public Water Systems (PWS) approved under 18 AAC 80 to supplement the potable water supply at Milne Point. Potable water may be transported from the following PWS's: Approved Public Water Systems PWSID # BPXA Milne Point 333364 BPXA GPB, Central Water Treatment 333013 Facility BPXA GPB, Prudhoe Bay Operations 331011 Center Phillips Alaska Inc., Kuparuk 330031 If you have any questions concerning this submittal or require additional information, please contact me at (907) 564-4456. Sincerely, Enclosures: Phase 1 and 2 Process Drawings cc: Thomas Tiley, ADEC - Anchorage Tom Maunder, AOGCC - Anchorage !I...'\i,.Œ , , , , , , ______ w __ __ _____ __ ~ _________...J PHASE BIICKI/ASH TO I/AST[ ACTlI/ATED CARBON fiLTER AIR f---- , , I/ASTEIIATER TR£A THCNl UNIT IREAK ----------------1 - POTABLE I/ATER HDR. ^_____J}lH.____, Y A ~-:::~~:iJ-~m -~ PREVENTER -§--~ A¡R~ t DRAIN HACKl/ASH SUPPLY FILTERED 1/" TER ¡'J BACKrlOI/ PR[VŒTER ~GAP t DRAIN ~~-~ ~31 ::; '" ~ - -- ___uu u -- - -- - - - - _u_ -r- mSTlllER ( />OOA CH(M ~ ~ñ AIR r-- , : : STORAGE 395 GAL. ---------------- TANK (EXIST> IREAK · IN(POII<lI CFP PROCESS TURBINE NOX I.'A TER PER- TREA TMENT PIPING L INSTRUMENT DfAGRAM ";,:;:;~GC SK-3Ï34Š'723, .,,~ 01 ~ BACKVASH TO VASTE BACJ<VASH TO VASTE VASTEVATER TREATHENT UNIT ACT!VATED CARBON nlTER - SOFTENERS e &ACKVASH SlN'?L Y fiL mED VATER l' f BACKFLOV PREVENTER ---0- ~G'\P t DRAIN '" ~ ~f!! -- ~- 0.= ~~ r--- : ¡ T ~'HOSE A 'E'" ---------------.- W 0.. 0: - - - - - - - -- ------- --- --- -- - -T -- , DlST!Ll[R AQUA Cf-[H ) PDTABlE VATER "DR, EXIST ,..----- ---------... t.___________r_A r---~ ! : ¡ I i ñ AIR BREAK STORAG£ T A~ J9S GAL. (EXIST) ---------------- #9 - ~1f~1fŒ rm~ ~~~~[K(~ AIfASIiA OIL AND GAS CONSERVATION COMMISSION October 29, 2001 Ed Lafehr BP Exploration (Alaska) Inc. Alaska Consolidated Team PO Box 196612 Anchorage AK 99519 Re: Area Injection Order 10-A Milne Point Unit Dear Mr. Lafehr: . TONY KNOWLES, GOVERNOR 333 W. 7'" AVENUE. SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 The enclosed Area Injection Order lO-A ("AIO 10-A") provides approval for BP's proposed miscible gas injection project for the MPU Kuparuk River Oil Pool (per application received August 17, 2001). AIO 10-A provided rules for enhanced recovery injection operations for the Kuparuk River Oil Pools (including MW AG, waterflood, and lean gas injection), and for the Schrader Bluff Oil Pool (waterflood operations). The applicable area for enhanced recovery operations has been made consistent with the current MPU boundaries. This order supersedes Area Injection Order No. 10 which had covered waterflood injection within the Kuparuk and Schrader Bluff Oil Pool. We wish to commend you and your staff for the extensive technical information provided to the Commission and for the very cooperative dialogue throughout this process. Specifically, Byron Haynes, Jeanne Dickey, Katy Nitzberg, XiuXu Ning, Darrel Kleppen and Bill March were extremely helpful. Good luck with your Project. SQ:relY,~. ~ camm~hsli Taylor i'- Chair COT\jjc cc: Byron Haynes Jeanne Dickey #8 Draft Geology input to AIO #10 . . Subject: Draft Geology input to AIO #10 Date: Fri, 12 Oct 2001 15:55:50 -0500 From: "Nitzberg, Katie E" <NitzbeK.E@BP.com> To: "'Jane Williamson'" <Jane_ Williamson@admin.state.ak.us>, "'Steve Davies'" <steve _ davies@admin.state.ak.us> CC: "Dickey, Jeanne H" <DickeyJH@BP.com> Dear Steve and Jane, Attached is a draft copy of my proposed addition to the August 17, 2001 Application to Amend the Milne Point Area Injection Order #10. Please let me know if you have any questions or other requirements for geologic data to include in the findings. Once I have heard from you, I will send a final copy to you. «Geologic Information AOGCC.doc» Name: Geologic Infonnation AOGCC.doc DGeologic Infonnation AOGCC.doc Type: WINWORD File (application/msword) Encoding: base64 I of I 10/15/2001 10:23 AM . . 6. Geologic Information (20 AAC 25.402(c)(6)). For the August 2001 Amendment to the Kuparuk Area Injection Order #10 The reservoir interval for proposed injection is the Kuparuk River Formation, which is defined as an accumulation of oil that correlates with the interval between 6,474 and 6,880 feet, measured depth in the Atlantic Richfield Company West Sak River State No.1 well. The Kuparuk River Formation comprises a sequence of very fine to fine-grained marine sandstones and associated mudstones that are Cretaceous-aged. At Milne Point, the Kuparuk River Formation is informally divided into four stratigraphic units that are named, in ascending order, the A, B, C and D units. Within the MPU, the Kuparuk A unit consists of a sandstones, siltstones and mudstones deposited in three regressive cycles, each cycle coarsen and clean upwards. The overall Kuparuk A unit is up to 140 feet thick containing amalgamated sandstone bodies up to 40 feet thick in each cycle. These sandstone bodies are northeast-trending, lenticular, shingled, and up to 15 miles in length. Their permeability and porosity average approximately 100 md and 21%, respectively. Widespread siltstone and mudstone intervals separate the sandstone bodies. The overlying Kuparuk B unit also consists of interbedded sandstone, siltstone and shale. In the south-eastern area of the field, the upper B interval contains a thick blocky to coarsening upward shoreface sand sequence that is about 30 feet thick. This upper B sand has an average permeability of 200 md and 21 % porosity. A major unconformity, the Lower Cretaceous Unconformity defines the top of the Kuparuk B unit. The Kuparuk C unit consists of fine to very fine grained sandstone· that is bioturbated and highly glauconitic. There are discontinuous siderite cemented intervals in the Kuparuk C unit which do not impact fluid movement within the reservoir. Overall, the geometry of the Kuparuk C sandstone is blanket-like, but individual sandstone bodies are poorly defmed because of syndepositional faulting and erosional truncations. Permeability and porosity average approximately 100 md and 20%, respectively. The Kuparuk D unit at the top of the formation consists of silty mudstone. There is no reservoir quality rock in this interval. Within the Milne Point Unit, the confining int erval above the K uparuk reservoirs consists of more than 2,000 feet of Cretaceous age Colville shale. The lower confining interval is the Miluveach and Kingak shales, which exceeds 1,500 feet in combined thickness. As defined in AIO No.1 O. At Kuparuk Formation level, the MPU is a faulted anticlinal structure that plunges toward the northwest and the southeast. Within the field, complex faulting has rearranged the overall structure into many compartmentalized fault blocks. Stratigraphic discontinuities and differential movement along the faults have created numerous pressure barriers and trapping elements. Variable oil water contacts with are present. In general, deeper oil-water contacts are found toward the northwest and shallow toward the south and eastern portions of the field. e . Kuparuk oil gravity averages 22 API in the Milne Point field, and it ranges from 21 API to 26 API. Initial solution gas/oil ratios are approximately 300 SCF/BBL. At the 170 deg F reservoir temperature, oil viscosity is typically 2-4 cpo Initial reservoir pressure is 3,500 at the datum depth of 7000 feet TVD subsea. Bubble point pressure is about 2,200 psi, which is significantly below initial pressure. #7 bp e '_ RECEIVED SEP 'I 8 2001 ... ,'~'.'I. _...~ ~.-- ~..- ~..~ ..~ ¡r.... ..,~.\. ". t. Alaska Oil & Gas Co·ns. Commission Anchorage BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage AK 99508 P.O. Box 196612 Anchorage AK 99519-6612 September 18,2001 HAND DELIVERED Ms. Jane Williamson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Milne Point Unit Area Injection Order Dear Ms. Williamson: Enclosed is the following information regarding possible fracturing of the reservoir in connection with the Milne Point Unit Kuparuk MW AG EOR project: · material balance calculations showing from pressure matches to the field data that flow is not occurring outside the Kuparuk sands · the results of two temperature warmback pass surveys on wells L-33i and L-15i showing from a comparison of temperature of the injected fluids with the surrounding formation that the injected fluid is staying confined within the Kuparuk sands · summary writeup of this information in a memo from Monte Townsend to me If you have any questions, please feel free to contact me (564-5575). Very truly YOUß ~~~ ......Byron ~n~s, Jr. Senior Reservoir Engineer Alaska Consolidated Team - ACT! Enclosures Cc: Daryl Kleppin Bill March Sean Monico Jeanne Dickey e e Sept. 14,2001 Byron, Attached is evidence that suggests injection into the Kuparuk Sands is staying within the Kuparuk reservoir and not migrating or fracing out of zone. The information provided is from two sources. The first is Temperature warmback passes acquired during injection surveys on MPU injection wells. The second is Material Balance calculations that compares predicted with measured pressure responses as fluids are withdrawn and injected into the Kuparuk reservoir. The injection surveys provide a picture of what is occurring within a few feet of the wellbore, while the Material Balance calculations provide a broader regional picture of what is occurring within the Hydraulic Units. Iniection Surveys Attached are strips from warmback passes ran on two MPU. Specifics are as follows: L-33i - Injection Survey taken on 10-5-98 with warmback passes of Y2, 1,2 & 3 hrs. This survey was done after injection of 2,450,000 bbls of water. Survey indicates the maximum extend of injection is from 13,000 to 13,210 feet, with the majority of the fluid entering from 13,000 to 13,210 feet. All of this interval is contained within the perforated interval and encompasses the Kuparuk sands. Note - this well is inverted. L-15i - Injection Survey taken on 7/31/01 with warmback passes of 24 and 30 hours. This survey was done after injection of 5,300,000 bbls of water. Survey indicates the maximum extend of the injection is well within the perforated interval, which is the Kuparuk sands. Besides the two warmback log strips, also attached are reports that interpret the results of all injection logs taken on these two wells. Material Balance Calculations Attached are graphical outputs of Material Balance calculations for four Hydraulic Units (HU) in the MPU Kuparuk reservoir (HU 290,261270280-295). These plots compare measured static reservoir pressures to predicted pressures. The predicted pressures are calculated using geological volumes and the withdrawl/injection history of each hydraulic unit. Pressures matches are very good. If there was substantial fluid loss or gain from the hydraulic unit, the predicted to measured pressures would not match. Summary The above evidence suggests that injected fluids are being contained within the Kuparuk reservoir. Injection confinement was questioned because injection pressures are higher e e than the 0.75 psi/ft frac gradient of the bounding shales. Industry experience, regional geology and typical shale properties suggest that the perceived frac gradient of 0.75 psi/ft for the shales may be in error. Typical shale frac gradients are in the order of 0.9 to 1.0 psi/ft. Therefore an explanation needs to be provided as to why the shales in this area would be an anomaly from what is the normal expectation. Monte Townsend Production Simulation - Milne Point 3600 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 ----------------+----------------~---------------------------------- 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 -----T----------------ï---------------------------------- 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 _ _.J _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _,_ _ _ _ _ _ _ _ _ _ _ 1 1 1 1 1 1 1 1 1 1 1 1 3200 o o 2800 ------------ 1 1 1 1 1 1 1 1 __.L___________ 1 09/01/1990 2000 02/0112000 01/08/1993 05/18/1995 09/24/1997 Time (date m/d/y) .. ~ Pressure HU261 Hi. HU261 si. e [ Tank Pressure o HU290 Hi. ~ HU290 Si. Milne Point e o (' ~"",,\..J,,6 production Simulation 3600 3200 2800 t> .... In ~ Q) ... ;:J In In Q) ... ø. ,>( ¡:: '" E< ) 01/01/2000 D 0 \ t-l \ ~ ~c>y~ :( M,e.o.. S \) H.. á. ~ v-tt£,S1 11/1511998 09130/1997 date m/d/y Time 08/15/1996 2400 2000 07/01/1995 Tank Pressure [] HU280-295 Hi ~ HU280-295 si Milne Point e Production Simulation 3750 3250 "" ..; (J) ~ " ... " (J) (J) " ... '" .>: r:: III ¡.. 3000 01/01/2000 12/16/1998 12/01/1997 Time date m/d/y 11/15/1996 2750 11/01/1995 Milne Point Production Simulation e Tank Pressure o HU270 Hi. ~ HU270 Si. o 360 3200 01/01/2000 04/02/1998 07/02/1996 Time date m/d/y 10/02/1994 2800 2000 01/01/1993 2400 ~ .... .. Eo Q ... :; .. .. Q ... '" ~ lIS E< e e BP Exploration Alaska: Milne Point To: Diane Richmond/Brian Huff MPU Development Team Date: August 21 st 2001 From: Stuart Shaw MPC-Pad Production Engineer Subject: MPL-33i Injection Survey Interpretation OBJECTIVE: In an attempt to understand the conformance in hydraulic unit 230, the historic injection surveys for L-33i have been re-interpreted and the results are presented below: HYDRAULIC UNIT BACKGROUND: L-33i is situated in hydraulic unit 270 with the following wells in its immediate locality: Well Zones Current Status Comments F-05 A Sand ESP Producer Well came on in June 1997 with A sand frac. L-28A A Sand ESP Producer Well came on in March 1999 with an A sand frac. L-13 A and B Sand ESP Producer Well came on in June 1993 with an A/B sand frac F-13 A Sand ESP Producer Well came on in February 1998 with an A sand frac F-09 A Sand ESP Producer Well came on in August 1997 with an A sand frac L-33i SURVEY INTERPRETATION: Date Comment 7/4/1997 Drilled and completed as a horizontal injector with the A and C sand perforations in the heel of the well designed to support F-05/L-13 and the A sand perforations in the toe designed to support L-28A, F-13 and F-09. The perforations in the heel of the well are isolated behind a straddle packer arrangement which can be used to selectively inject by installing/removing dummy GLM's. Survey Date C and A Sands A1 Sand in Toe A2 Sand in Toe A2 Sand in Toe in heel 1 0/5/98 65 18 17 0 1 0/5/98 Warmback passes conducted during the survey indicate that the majority of the injection in the toe of the well is going into the A2 and A3 sand after leavina the perforations even though spinner splits suggest otherwise. 3/25/00 Dummy GLM's set in heel of well to direct all injection to the toe. 6/5/01 Pressures continue to rise in F-05 (heel) and decline in L-28A (toe) despite the dummies beina set. New survev ordered. Survey Date C and A I A1 Sand in Toe A2 Sand in Toe ~ Sand in Toe Sands in heel e e 6/5/01 53 20 127 I 0 OBSERVATIONS: The two main observations from the injection surveys on L-33i are: . Historically the majority of the injection has entered at the heel of the well to support F-05 (also seen in the rise in F-05 SBHP: 4411 psi 6/2/01). The survey conducted in June 2001 identified a leak in the tubing which has shown that with the current completion it is impossible to direct injection only to the toe of the well. The effect of the reduced injection at the toe can also be seen in the decline in SBHP's at L-28A: 2525psi (11/7/00) and F-09: 2197psi (11/5/99). . The warmback passes taken during the March 1998 survey show that the injection to the toe of the well is going into the A2 and A3 sands even though the spinner surveys indicate that the water leaves the wellbore through the A1 and A2 perforations. CONCLUSIONS/PLAN FORW ARC: L-33i has a tubing leak between the straddle packers in the heel of the well that is preventing selective injection. A program is in place to patch this leak and the execution date is scheduled for the last week in August. By monitoring the response at L-28A and F-09, evidence for communication between the wells will be confirmed if production increases are seen as a result of increased reservoir pressures. If the tubing patch is unsuccessful, or the wells are not found to be in communication, then other options such as sidetracking L-33i will be considered to provide the necessary pressure support. The warmback passes in 1998 show that the A3 sand is taking water injection in the toe of the well, even though the spinner counts indicate that no water leaves the wellbore here. This could be explained by A3 perforation damage. The warm back passes also show that the A1 sands may not be effectively being swept, as although water leaves the wellbore through the A1 perforations, the sand warms back quicker than either the A2 or A3. &. e e BP Exploration Alaska: Milne Point To: Diane Richmond/Brian Huff MPU Development Team Date: August 2ih 2001 From: Stuart Shaw MPC-Pad Production Engineer Subject: MPL-15i Injection Survey Interpretation OBJECTIVE: In an attempt to understand the conformance in hydraulic unit 270, the historic injection surveys for L-15i have been re-interpreted and the results are presented below: HYDRAULIC UNIT BACKGROUND: L-15i is situated in hydraulic unit 270 with the following wells in close proximity: Well Zones Previous Status Current Status Comments L-13 A and B Sand - ESP Producer Well came on in May 1993 with A/B sand frac. Well saw pressure support from the beginning of 1998 (due to L- 33i injection) and a recent decline in supporVPI since beginning of 2000. F-69 A and B Sand - ESP Producer Well came on in Feb 1996. Frac'd in the A sand and then perfs were subsequently added to the B. Water breakthrough 6/97 and gas slugs seen as a result of injection in F-62i F-62i A and C Sand - WAG Injector Well began injecting in the A and B sands in November 1995. L-33i A and C Sand - WAG Injector Well began injecting in the A and C sands in November 1997. F-37 A Sand - ESP Producer Well came on in November 1995 with A sand frac. Good response to F-62i injection. F-25 A Sand - ESP Producer Well came on in November 1995 with A sand frac. L-15i SURVEY INTERPRETATION: Date Comment 7/2194 Completed as an Injector with a hydraulic fracture in the A/B sand. Survey Date B Sand I Ä3 Sand I A2 Sand I At Sand 12/5/94 9 I 26 I 30 I 35 .. e e 12n /97 Conversion to WAG Injector 12/28/98 Injection survey unable to get down to survey individual A sands due to mung problems. Survey Date B Sand I ~ Sand I A2 Sand A1Sand 12/28/98 5 I 95 6/99-1 0/00 Increasingly difficult to inject gas. "Mung" was suspected as causing the problem. Hot water/diesel treatments were unsuccessfully tried in advance of swapping well to gas. 7/11/01 CT clean-out performed in advance of an injection survey. WHP so high that well was flowed to a tank initially before coil could safely enter the well. 7/31/01 Injection survey including warmback passes on e-line. Shut-in profile indicates that there is crossflow from the A1 to the A3 sand. Warmback passes after 30hrs indicate that water is entering the A 1, A2 and the bottom of the A3 sand in equal proportions. Survey Date B Sand I ~ Sand A2 Sand A1Sand 7/31/01 10 I 30 15 45 OBSERVATIONS: · Unclear as to which well is supported by L-15i, (no direct evidence in most likely candidate L-13). · The A sand has taken over 90% of the overall injection through time. · Spinner splits show that the At sand receives more injection support than the A2/A3 sands. · There is cross flow from the At to A3 sand in the wellbore when the well is shut-in. · The current shut in WHP is over 3300psi from the clean-out performed in 2001. · The II for this well has declined over time. · E-line was used to obtain warmback passes for this well, as there was some uncertainty as to the required shut in time to obtain good data. L-15i has injected over 5MMbbls of produced water, and this survey showed that -24hrs shut-in is required. · The warm back passes indicate that significant water floods the At, A2 and the bottom of the A3 sand. CONCLUSIONS: The At sand has a higher pressure than the A2/A3 sand, and is receiving more injection than the other two sands. This would suggest that this sand has a higher II (i.e. permeability than the A2 and A3). Shut-in times of -24hrs are required to obtain good warm back pass results for wells which have injected -5MMbbls of produced water. This compares to 3hrs for L-33i which had injected -2.4MMbbls of produced water. Only the bottom of the A3 sand appears to being swept, which could mean that we are leaving behind reserves in the upper part of this sand. The declining II for this well and the high WHP would indicate that the reservoir pressure has increased over time. This observation would also explain the problems in injecting gas (due to the reduced hydrostatic of gas), as opposed to suspected "mung" plugging off perforations. ~MPL-15 API:500292247300 SCALE: 1:480 PLOT DATE:06-Apr-2000 kn.....,padbook ..t -'= Del .&J ø. -0 (Q ! œ c H IØ 0 :' ~ Šë œ (f) CALI J.f ~Ë CD .µ De 6 IN 16 Q) g PI z GR 0 GAPI TKtJA '.rXA !tAL 'l'MLV IT ~. 1. :'* , ..... I ~ i .- Mr~ , .. .... , , I , , L --'5~ t , / I...... ~ . "" 't>l~ lot 9 . . I. ....... I I c; , I ; ...... : , , ... , , , ;> I..... , I c: , . , ..... f""""!Io. , . 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""1...:.: " . ... ~ ~ : =Gamma Ray " ~~ "\. ,- J '\. ,~ - "",' , , ,'- - ~ .. . "" I .... I '" ::':0 ..... ..... ...... ~ - - -- - - Gamma Ray 1UOI 100 Temperature Base Pass 1lU 10 CCl 100 0.5 hr. Warm back Pass 120 30 106' 1 hr. Warm back Pass 120 ...................................................................................................................................................................... 100 2 hr. Warmback Pass 120 -------------------------------------------------------------- 100 3 hr. Warm back Pass 120 --.-..-..-----.---.-.-..-..-.---.---.-.--------------------------- 7250 Borehole TVD 7050 ,.... . ....! . . .... . . ~ , , . , . , , '" MPq . ~ I .. il9 -'- J.- l.:-'~; , ~~ I I' " .. . '" '/51/DI . ," ~ . ,~ , ..... , ., , .~ . I '"' I ,,, , , -- ,I{ . .. - . ..... 13600 , "" , -- ,/ ..... ,; --...; . ., ~ :, , ~ " < ~ " ., 1-<.., . L/ I...... . ~~~ . .....- . . :... . ~ . """-1. . « { . , ~ , ~~ . I ~'!I , I I,...... . ~... ~ ~ J ~~ , ~l ç -- -::- L; ~ , <.' , - J - ~ .... ""~ ..... "'; L. --,. ~- ~ ~ ~ · · I .' · 13700 · ~ , , iJc. , ......-: . ". . · r · , /} · , ,... .\ - ... \ .... ") .", ". ~, -:>.. , c " , ::..' '\ .-- ""- ..... -......;;; i""<.. '. "- '\I ," , , '" ...r ~, -== ""- ""- "- . "' - "' ~.. ""- .. .r ........ -..;;; ""C ~ ~ "- " , ..... c. -....... -.. .. ...., . .~ I' .... , .. " :;.-: ~ r-- .. "- :..- . "" ""- " "- .~ "' " , "' < 'A'.. '~ :Cl . Baseline Pass (P01 CCl) OPEN ~_______~~~L~m~mu~Pa~œ~m~________ (V) 1 PERFS 114 (DEGF) 154 m. Ray - B=~; P.. CPOI LG~=ii4U- - - - m__ - _Om - ~!j!,!,!- T~_'!'~[¡¡"ê:j-!~- !~~~¡ - - - - _u - -- - - - - - - "154 ~!I.~~Y:.~.I::I~'!~.P.~J~~º!!L Baseline Temperature Pass (P01TMP) (GAPI) 100 114 (DEGF) 154 !!'!. F!!Y...: ~ !;!o,!!, Pa.!,8 ~03LG.ID _ I SHUT IN TEMPERATURE PASSES OVERLAY I (GAPI) 100 #6 , bp . . .,. ..\If.'''', _...~ ~.-- ~..- ~..--- 4ì'~ ~.... ·'i'~i\" ". Ms. Jane Williamson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Rf:Gt:/V€D AUe 2 !~iaskaOil 8200! & Gas C ~/)r; ,017s. Co . . ho, Edge !7ì!7ì/SSion HAND DELIVERED Re: Milne Point Unit EOR Project Dear Ms. Williamson: Pursuant to your request for additional technical information regarding the Kuparuk MW AG EOR project in the Milne Point Unit, BP Exploration (Alaska) Inc. is enclosing the following materials: · Milne Kuparuk EOR Performance Prediction · Milne Point Field Kuparuk Reservoir Depletion Plan · Formation Integrity Test Results · Milne Kuparuk Waterflood Sweep Polys with spreadsheet "Material Balance" · VIP Material Balance History Match · Two disks marked "BP Confidential" which contain spreadsheets and VIP text files We are also enclosing the following confidential maps: · Kuparuk Formation Pressure Map (December 2000) · Milne Point Field Wide Cross Section (map and confidential cross section labeled "ejp_wsec9" dated August 15,2001) · Top Structure Maps for AI, A2, A3, A456, BL, B7L, B7U, Cl · Average Porosity Maps for AI, A2, A3, A456, BL, B7L, B7U, Cl · Average Permeability Maps for AI, A2, A3, A456, BL, B7L, B7U, Cl · Average Water Saturation Maps for AI, A2, A3, A456, BL, B7L, B7U, Cl · Net Sand Maps for AI, A2, A3, A456, BL, B7L, B7U, Cl · Gross Isopach Maps for AI, A2, A3, A456, BL, B7L, B7U, B8 Cl We request that those items marked "BP Confidential" be kept confidential pursuant to AS 31.05.035( d). . . Ms. Jane Williamson Alaska Oil and Gas Conservation Commission August 27,2001 Page 2 If you have questions or would like to discuss any of the materials, please contact Byron Haynes at 564-5575. Sincerely, ~¿{/~¡;¿ Edward D. Lafehr ACT Development Manager Enclosures Cc: Byron Haynes Bill March Jeanne Dickey Daryl Kleppin . . Milne Kuparuk EOR Periormance Prediction RECEIVED AUG 2 8 2001 Overview of the Milne Point Kuparuk EOR Strategy ('" & r:' ^ ,J/i vas Gons. Commission 4nchorage The Milne Point Kuparuk EOR project (Milne KEOR) is planned to increase production over the base oil production by approximately 9 Mbopd through the injection of an enriched lean gas solvent (MI) into the reservoir utilizing a water-alternating-gas (WAG) injection scheme. Currently, Milne Kuparuk is operating under an IWAG scheme where lean separator gas is injected and alternated with water injection. The IWAG process is relatively inefficient at sweeping oil to producing wells but the process improves conventional waterflood recovery slightly by introducing a trapped gas phase that reduces water mobility and forces water to displace oil in the smaller pores of the rock. The Milne Point Kuparuk reservoir is currently developed on 8-pads, 4 waterflood pads (B, H, J and K-pads) and 4 IWAG pads (C, E, F and L-pads). The plan for EOR is to inject MI into the IWAG pads and switch the IWAG pads from lean gas injection to miscible gas injection (MWAG) by October 31, 2001. 25 MMscfpd of MI will be manufactured at the field by importing approximately 4 - 5 mbpd of NGL's from Prudhoe Bay to blend with approximately 20 MMscfpd of lean gas from the Milne Point Field. The resulting gas will be miscible with the Milne Kuparuk oil and will be distributed to C, E, F and L-pads by injecting in a WAG scheme at a nominal WAG ratio of 1:1 (Le., 1 reservoir barrel of water per 1 reservoir barrel of MI or approximately 1 barrel of water per 1.2 Mscf of MI), adjusting as necessary to maintain GOR's at a manageable level. Phase Behavior and EOS Development The compositional simulation work to predict Milne KEOR performance is based on a 12- component Peng-Robinson EOS developed in 1997. Conventional PVT data from wells MPL-1, MPF-78 and MPF-34 were used to tune the 12 component EOS. The result of tuning to this data was a match of the EOS to laboratory data During early 1998, an MME MI composition was designed based on the 12-component EOS. The MI uses separator off gas enriched with PBU NGLs. A slim tube compositional simulation was performed to define an MME composition based on an oil recovery at 1.2 pore volumes injected. The slim tube pressures used were 3200 and 3000 psia respectively at 1670 F. Subsequent to the slim tube modeling work, a laboratory slim tube test program was initiated during 1998. In the slim tube tests, two enrichments were carried out: 15% and 21 %. Figure 1 shows the EOS-model predicted oil recoveries at 1.2 pore volumes injected for different NGL enrichment levels compared to the laboratory-measured oil recoveries. This comparison shows that the EOS-model oil recoveries compare well to the laboratory-measured oil recoveries and validates the accuracy of the EOS for the gas injection EOR processes. From these experiments it is determined that at about 21 % NGL enrichment the displacement process becomes nearly miscible with oil recovery in excess of 100% (contributed by NGL condensate production). Figure 2 shows the slim tube results for 21 % NGL enrichment. As can be seen in this figure, at 21 % NGL enrichment a nearly miscible process was achieved, as evidenced by gas breakthrough at about 0.98 PVI with high oil recovery. Table 1 shows the MI composition for this enrichment level. . -~ ( . Model Description The Milne KEOR project results were predicted by simulating an IWAG and MWAG injection process in the Kuparuk A-sands using a VIP compositional simulator. The geologic description and rock properties of the KRU Drillsite 30 area were used to construct the model (adjacent and south of the Milne Point L-pad area). The model was built as a generic rectangular pattern strip model with one injector and one producer each located at opposite ends of the model. The dimensions of the model were 2640' X 1320' to approximate the 80 acre well spacing for Milne Kuparuk wells. Gridblock size for the model is 50'X 50' with variable thickness for the layers. Model dimensions are 52 X 26 X 18. Figure 3 shows the geometry of the pattern model. The pattern model was controlled with injection and production at voidage replacement with a total hydrocarbon throughput of 6% HCPV per year. The MWAG sensitivities were run with a 20% and 30% HCPV slug and followed with water injection. WAG ratios for the 30% slug were varied at 1, 2 and 5 with slug sizes of 1.5% HCPV per cycle. For the 20% case, numerical problems with the WAG=2 run did not allow a full run. Therefore only the results for WAG Ratios of 1 and 5 will be reported here. The slug sizes in the 20% case were 1 % HCPV per cycle. All simulations were stopped once the producer reached a 95% watercut. All cases were run out to a total injection of approximately 2.2 HCPV (or 40 years). This model used the 12-component Peng-Robinson equation of state with volumetric shift factors as described above to simulate the miscible process. Table 2 shows the parameters of the EOS. Case Sensitivities Waterflood, immiscible WAG (IWAG), miscible WAG (MWAG) and IWAG/MWAG sensitivities were run with this model to help understand the range of recoveries that could reasonably be expected from implementing MWAG in the field. At the end of gas injection, all WAG cases were turned to waterflood. Eight cases from the modeling results were chosen to examine MWAG flood sensitivities. Two IWAG cases were run with a 10% and 30% lean gas slug to evaluate the impact that lean gas injection combined with water injection has on recovery. Five MWAG cases were run with a 20% and 30% HCPV slug of gas at various WAG ratios and finally one case was run with IWAG followed by MWAG with a 30% HCPV miscible gas and a 10% HCPV of lean gas. These cases were chosen to cover the range of reservoir mechanisms that could exist in the IWAG pads. For example, the C and E-pad areas have the longest history of IWAG performance whereas most of F-pad's history is from waterflooding. The waterflood case is considered the base case for comparison with all WAG processes. Table 3 illustrates the cases run with their incremental recoveries. Incremental oil recoveries were calculated by subtracting the cumulative produced oil volume in the waterflood run from the cumulative produced oil volume in the MWAG run then subtracting the volume of returned NGL's at the same pore volume injected. Equation 1 shows an example of an incremental recovery calculation. Eq. 1 Incremental Recovery = MWAG Cum. Oil Prod. (@ 0.5 PVI) - WF Cum Oil Prod. (@ .5 PVI) - Cum. Returned NGL Volume from MWAG (@ .5 PVI) Figure 4 shows the incremental recoveries of these cases plotted on a pore volume basis. The method for calculating the returned NGL volumes is documented in Appendix. .- . Note from Table 3 and Figure 4 that the MWAG cases with the higher the WAG ratios give higher incremental recoveries. This result is consistent with the concept that in a miscible WAG injection the displacement of oil with miscible gas is a poor mobility ratio flood. By injecting water with gas has the effect of lowering the gas mobility such that the volumetric sweep of the gas is improved which increases the amount of oil contacted. Performing an MWAG flood at low WAG ratios results in an earlier rate response from the flood and depending on when the flood is cutoff. a higher recovery from the lower WAG ratio can be observed. Refer to Figure 5 and compare those results with Figure 4. Figure 5 shows the incremental MWAG recovery on a time basis for a 30% HCPV slug of gas injected. This figure shows that implementing an MWAG flood with a high WAG ratios pushes the recovery benefits out in time but generally obtains higher recoveries than the lower WAG ratio cases. This analysis suggests the need to optimize the MWAG flood for WAG. ratio and pattern flood rate to achieve the maximum oil recovery and the best rate performance. In summary, the MWAG and MWAG/IWAG cases for the 20% and 30% HCPV slug and WAG ratios from 1 to 5, range in incremental oil recoveries from 7.5% to 10% OOIP while incremental recoveries for IWAG only run around 3% OOIP. Furthermore, the Milne Kuparuk IWAG results are deemed reasonable since the KRU Kuparuk IWAG predictions show incremental recoveries of 1- 5% OOIP1. Scale-up of Pattern Model Results to Field Peñormance The recoveries from the MWAG and IWAG model results were scaled to the HCPV of the IWAG patterns in C. E, F and L-pads. These results were documented as Table 1 of the "Milne Point Kuparuk Reservoir EOR Strategy and Implementation Plan"2. These results are shown again here in Table 4. The cumulative recovery for these patterns ranges from 30 - 40 MMstb. Note that the pattern volumes are based on old interpretations of the faulting, pattern performance and the oil-water contacts. New performance data and an improved understanding of the oil-water contacts are currently being used to update the pattern volumes. Therefore the OOIP and recoveries may change slightly. 1 Ma, T.D. and Youngren. G.K., "Performance of Immiscible Water-Alternating-Gas (IWAG) Injection at Kuparuk River Unit, North Slope, Alaska", SPE 28602, 1994. 2 Haynes and Ning, "Milne Point Kuparuk Reservoir EOR Strategy and Implementation Plan", July, 2001. Figure 1: MPU-Kuparuk: MI Enrichment, lab Tests and Model Prediction (P=3200 psi) 110 I 100 I ~ ~ 1- - - - - .... I I ... 90 - ~ __L ~ I I 0 80 I (,) -.-+--- c I 0::: 70 - - --. I Õ I 60 - - ~ I - - ~ ::::ó1 '" 50 40 0 5 10 15 20 25 % NGl Mixed in lean Gas for MI Figure 2: MPF-34 Oil Slim Tube laboratory Data DP Rho*100 % Rec wlo Drop Out Residual GOR -__-----Ò 100.0 21 % NGl Solvent Slim Tube MPU F·34 West Port lab Report 1:1.. C cð 80.0 ~ CI.I > 0 (,) 60.0 CI.I 0::: ~ '" cð 40.0 Q Q ..... .. 0 .I: 0:: 20.0 40000 lalive recovery 35000 30000 25000 0:: 20000 0 C) 15000 10000 5000 0.0 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 Pore Volume Injected o 1.8 2.0 Figure 3,52 X 26 X 18, MWAG Model Figure 4, Case Sensitivities for the Milne Kuparuk Pattern Model on a HCPV Basis KEOR Pattern Model Case Sensitivities Incremental Recovery to Waterflood ~ <II >- 8 10.00% <II a:: Õ 8.00% ¡¡ 1: <II E e (,) .= ";ft 6.00% ¡+30O/:,WAG=n'0 . I _30%, WAG=2.0 I I 30%, WAG=5.0 20%, WAG=1.0 I I _20%, WAG=5.0 ¡ II 10% ¡WAG, WAG=2.0 I --+--30% ¡WAG, WAG=2.0 I """'è-10% ¡WAG and 30% MW AG 14.00% 12.00% 4.00% 2.00% 0.00% 0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 Total HCPV Injected (Water and MI) Figure 5: MWAG Recoveries on a Time Basis KEOR Pattern Model MWAG Performance, 30% HCPV Slug 60.0"/0 10.0% 50.0% 40.0'%'\ '" ~ ~ 8 30.0°/(1 ~ '" õ 20.0% 0.0% 0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0 40.0 45.0 Time, Years Table 1: MI Composition from 21% NGl Enrichment MPU Kuparuk Compositions (Mole Fraction) 3200 psia Pseudo- MW Milne Lean Gas PBU-NGl MI - MPU Components CO2 44.01 0.0131 0.0000 0.0103 N2 28.01 0.0079 0.0000 0.0062 C1 16.04 0.8649 0.0000 0.6832 C2 30.07 0.0507 0.0000 0.0401 C3 44.1 0,0334 0.0331 0.0333 I-C4 58.12 0.0073 0.1158 0.0300 N-C4 58.12 0.0113 0.3466 0.0817 I-C5 72.15 0.0035 0.1091 0.0256 N-C5 72.15 0.0031 0.1345 0.0307 C6 85.18 0.0051 0.1420 0.0338 C7 92.03 0.0970 0.0204 C8 104.2 0.0218 0.0046 C9 120.7 0.0000 C10 134 0.0000 C11-13 158.3 0.0000 C14-19 214.4 0.0000 C20-26 300.9 0.0000 C27 -35 403.1 0.0000 C36+ 668.3 0.0000 otal Moles 1 1 1 Molecular We! ht 19.64 69.21 30.05 . . Table 2, Peng-Robinson EOS Parameters Pseudo- Components MW TC PC ZC ACENTRIC OMEGAA OMEGAS VSHFT CO2 44.01 87.57 1071.6 0.275 0.225 0.457236 0.077796 -0.0577 C1 16.04 -116.96 667.8 0.29 0.013 0.457236 0.077796 -0.118 C2 30.07 89.76 707.8 0.285 0.0986 0.457236 0.077796 -0.107 C3 44.1 205.68 616.3 0.277 0.1524 0.457236 0.077796 -0.0848 C4 58.12 305.32 550.7 0.274 0.201 0.457236 0.077796 -0.0686 C5 72.15 385.37 488.6 0.2663 0.2539 0.457236 0.077796 -0.041 C6 84 463 483.77 0.2575 0.2583 0.457236 0.077796 0.0212 C7-9 108.9 581.9 414.43 0.2439 0.3158 0.457236 0.077796 0.2337 C10-13 153.26 739.64 255.39 0.203 0.4255 0.457236 0.077796 0.32441 C 14-19 223.51 885.27 203.89 0.2187 0.5762 0.457236 0.077796 0.28358 C20-35 373.52 1082.91 153.31 0.2167 0.7657 0.457236 0.077796 0.29489 C36P 722 1500.81 96.2 0.224 1.1312 0.457236 0.077796 0.36191 Table 3: Case DescriDtions Case Description WAG Incremental Recovery % 1 MWAG 30% HCPV 1.0 9.1 2 MWAG 30% HCPV 2.0 9.2 3 MWAG 30% HCPV 5.0 10.2 4 MWAG 20% HCPV 1.0 7.5 5 MWAG 20% HCPV 5.0 7.9 6 IWAG 10% HCPV 2.0 3.1 7 IWAG 30% HCPV 2.0 3.6 8 IWAG 10%, MWAG 1.0 7.7 30% . . Table 4: MWAG Recoveries Based on Modeling Results Inc. EOR Inc. EOR Oil, Oil, Pattern Lean Gas MMstb, Cumulative MMstb, Pattern HCPV/yr Slug Size, Cumulative Average 10% Inc. % of MWAG 7.5% Inc. Pattern OOIP avg %HCPV OOIP, MMstb GOR RF Reserves RF F-95 15.179 8.60% 0.607% 15.2 229 1.5 4% 1.1 L-21 9.161 1.86% 2.921% 24.3 234 2.4 6% 1.8 F-85 6.500 9.07% 0.820% 30.8 235 3.1 8% 2.3 F-92 11.000 3.89% 2.226% 41.8 240 4.2 11% 3.1 L-42 1.363 8.84% 6.047% 43.2 248 4.3 11% 3.2 F-82 17.4 9.68% 0 60.6 250 6.1 15% 4.5 F-83 8.7 9.38% 0 69.3 250 6.9 18% 5.2 L-33 21.123 6.99% 0.529% 90.4 273 9.0 23% 6.8 L-09 12.588 3.79% 2.960% 103.0 313 10.3 26% 7.7 C-36 4.031 11 .22% 11 .276% 107.0 349 10.7 27% 8.0 L-08 14.486 3.13% 3.054% 121.5 479 12.2 31% 9.1 C-39 1.500 3.52% 5.680% 1.5 760 12.3 31% 9.2 F-41 8.603 0.85% 4.373% 10.1 160 13.2 33% 9.9 F-42 8.546 10.99% 3.207% 18.6 210 14.0 35% 10.5 F-84b 14.200 9.17% 0.000% 32.8 214 15.4 39% 11.6 F-46 24.862 4.57% 0.000% 57.7 223 17.9 45% 13.4 F-10 9.516 6.78% 0.183% 67.2 240 18.9 48% 14.2 F-49 12.531 8.46% 0.525% 79.8 242 20.1 51% 15.1 L-24 12.337 4.59% 4.394% 92.1 248 21.4 54% 16.0 L-15 16.553 3.65% 0.800% 108.6 256 23.0 58% 17.3 F-74 18.211 4.16% 0.000% 126.9 257 24.8 63% 18.6 F-70 17.205 5.83% 3.692% 144.1 266 26.6 67% 19.9 F-62 10.486 9.74% 3.350% 154.6 266 27.6 70% 20.7 F-30 13.814 3.48% 1.822% 168.4 280 29.0 73% 21.7 L-16A 10.888 9.88% 0.056% 179.3 281 30.1 76% 22.6 F-26 11 .124 6.02% 0.155% 190.4 282 31.2 79% 23.4 L-34 1.514 38.79% 34.062% 191.9 330 31.3 79% 23.5 E-17 2.821 29.60% 23.256% 194.7 394 31.6 80% 23.7 C-17 3.520 1.25% 18.842% 198.2 654 32.0 81% 24.0 C-06 9.182 3.22% 10.924% 207.4 694 32.9 83% 24.7 C-10 4.308 4.98% 23.548% 211.7 789 33.3 84% 25.0 E-23 2.683 26.95% 24.872% 214.4 889 33.6 85% 25.2 C-19 16.026 12.22% 49.675% 230.4 1019 35.2 89% 26.4 C-02 7.314 2.86% 5.305% 237.7 1113 35.9 91% 26.9 C-15 7.203 2.85% 10.502% 244.9 1283 36.6 93% 27.5 C-28 1.747 24.50% 48.488% 246.7 1957 36.8 93% 27.6 E-05 2.376 24.02% 44.951% 249.1 2391 37.1 94% 27.8 E-07 6.876 10.68% 47.190% 255.9 2482 37.7 95% 28.3 C-08 3.740 8.54% 41.923% 259.7 2501 38.1 96% 28.6 E-16 9.688 8.46% 14.120% 269.4 3200 39.1 99% 29.3 C-25A 4.957 8.95% 58.392% 274.3 3847 39.6 100% 29.7 . . Appendix Methodology for Calculating Returned NGL Volumes in the Milne Kuparuk KEOR Production stream This note documents a procedure for calculating returned NGL volumes from the Milne Point KEOR production stream. Background In the Milne Kuparuk EOR scheme, NGLs are imported from the Oliktok pipeline and blended with the off gas from the Milne CFP to produce a miscible injectant for injection into the Kuparuk reservoir at Milne Point. The blending of the lean gas and NGLs to produce the MI is based on the minimum miscibility pressure of the oil and MI at the injection location in the reservoir. Approximately 36 MMstb of NGLs will be imported over the life of the KEOR project. By determining the amount of NGLs returned during the flood will help to evaluate the EOR process efficiency in Milne Kuparuk. NGLs are predominately C4 - Ca alkane hydrocarbons with some C3. Table A-1 shows a typical composition of an NGL stream that will be used for the KEOR project in terms of the EOS pseudo-components. Returned NGL production is calculated using the difference in molar production between the compositional simulation output of a miscible WAG process and a waterflood. The simulations for Milne Kuparuk wére performed using a VIP pattern model with a single injector and producer. The area of the pattern simulated is 80 acres and the geologic description was based on the Kuparuk A-sand south and adjacent to the L-pad area of Milne Point. The simulation was performed using a 12 component Peng-Robinson EOS tuned to Milne Point Kuparuk oil, MPF-34 and KRU slim tube experiments. The model dimensions are 52 X 26 X 18 with approximately 2640 feet between producer and injector. Based on this work the cumulative NGLs returned with the stock tank oil is approximately 33% of the cumulative NGL volume used to blend MI. Figure A-1 shows the NGL demand rate and NGL recovery vs time. Methodology for Calculating Returned NGL in the Oil Phase First, the approach subtracts the waterflood oil rate, bow, from the MWAG oil production, born, to calculate the incremental EOR oil production, qxe; refer to Figure A-2. qxe = born - bow - Eq A-1 . Next, the incremental EOR oil production qxe, is represented as a sum of black oil rate (boe), and returned NGL in oil rate (nglx). qxe = boe+ nglx - Eq A-2 . Let B represents the moles of boe, Xi, it's composition (available from the waterflood simulation), and nglx¡, the moles of ngl component i returning in the oil phase. Then, qxe¡ = B*Xi + nglx¡ - Eq A-3 , . . Since the C10+ components are negligible in nglx, summing equation A-2 for components heavier than C10, B can be calculated as, . B = L qxe / L (Xi) i = C10+ - Eq A-4. Having solved for B, equation A-2 is rearranged to calculate the moles of each component i in nglx, nglx¡ = qxe¡ - B*Xi - Eq A-5 Table A-2 illustrates an example calculation of the returned NGLs determined from VIP compositional output at one period in time. Column A represents the MW AG oil production and Column B represents the waterflood oil production. Column C represents the incremental EOR oil production as calculated from Eq. A-31. Column 0 represents the waterflood oil composition. The total moles of incremental EOR oil, B, from Eq. A-4 is calculated as 7215 moles. Finally, the returned NGL moles in the oil phase, calculated from Eq. A-5 are presented in Column E. The moles are converted to volumes using the Standing molar volumes. Estimating Returned NGL Volumes in the Field Estimating the cumulative volume and production rate of returned NGLs from the KEOR project requires calculating returned NGL volumes from simulation output and scaling those volumes to the field based on field values for NGL blending rates and the total HCPV injected. First, the returned NGLs are calculated from the technique described above. Next, at each value of HCPV injected, the ratio of returned NGL rate to the maximum NGL injection rate is calculated (refer to Table A-3, see column D). Finally, once a ratio table has been developed for the simulation output, the ratio of returned NGL production to maximum NGL blending rate for the field can be developed based on a lookup of Table A-3 of total HCPV injected. Figure Ä-1: KEOR NGL Demand and Returned Volume Production KEORNGL Demand and Production 6000 5000 4000 't:I J5 ûi 3000 .sf !II CI:: 2000 1000 0 2000 2005 2010 2015 2020 Date 2025 2030 Figure Ä-2: Returned NGL Calculation Schematic 50.0% 45.0% 40.0% 35.0% 30.0% 25.0% 20.0% 15.0% 10.0% 5.0% 0.0% 2035 2040 bow - wf oil Igw - wf gas -I- -I-- Waterflood .... ... bom Igm mwag oil - mwag gas Miscible WAG . . Table A-1: NGL Composition EOS Pseudo- Components C02 C1 C2 C3 C4 C5 C6 C7-9 Sum Mol frac o o o 0.032581 0.446475 0.272988 0.159975 0.087982 1.000 Table A-2: Example Spreadsheet Calculation of Returned NGL Volume for One Period in Time Time, Days 2557 Column-> A B C D E MWAG Liquid Wtrfld Liquid Standing Molar EOS Pseudo Moles Moles Incremental Wtrfld liquid Volumes, nglx¡ Components produced produced EOR, qxe¡ composition xi nglx¡ bbl/lbmole bbl CO2 7.8 6.0 1.8 0.0002 0.375242 C1 77.7 75.8 1.9 0.0025 -16.1046 C2 66.2 60.7 5.5 0.002 -8.88219 C3 294.8 261.0 33.9 0.0086 -28.1802 C4 1090.5 495.1 595.4 0.0163 477.8062 0.289405 138.2794 C5 1144.1 574.1 570.0 0.0189 433.6781 0.328095 142.2877 C6 1071.1 683.8 387.3 0.0226 224.2447 0.370714 83.1307 C7-9 5952.1 4607.3 1344.8 0.1519 248.8536 0.461667 114.8874 C10-13 7421.8 5930.4 1491.4 0.1955 C14-19 8158.9 6597.5 1561.4 0.2176 C20-35 8172.1 6633.9 1538.2 0.2188 C36P 5416.9 4401.8 1015.1 0.1451 1: 29169.7 23563.6 5606.1 1: C4-C9 Bbls 478.5852 :EX; (C10-C36+) 0.777 Blk Oil Moles from EOR B= 7215.053 . Table A-3: Scaling Table for Returned NGLs from Simulation A Total HCPV Injected o o o o o o o 0.017991 0.048916 0.081862 0.114463 0.144587 0.176962 0.205039 0.236968 0.267164 0.296916 0.327434 0.357439 0.387897 0.448165 0.50857 0.568946 0.627733 0.686294 0.745839 0.805418 0.865194 0.924641 0.984088 1.043864 1.103311 1.162759 1.222534 1.281982 1.341429 1.401205 1.460652 1.520428 1.579875 1.87744 2.175004 B NGL blending Rate, stbld o o o o o o o 67.8228435 59.949178 62.724487 68.0109702 64.4152348 65.1665768 61.883513 63.489326 63.2608087 61.6352 71.8482696 62.5589569 61.815313 66.9581633 68.7137753 70.1913005 32.9688986 o o o o o o o o o o o o o o o o o o C NGL Return Rate, stbld o o o o o o o o o o o o o 2.422633 7.489649 12.25414 15.55658 17.54455 18.27069 19.30832 19.76045 19.98479 20.35648 19.45525 10.84068 5.831779 4.39417 3.625402 3.11615 2.718065 2.413269 2.163328 1.964126 1.801973 1.67449 1.556073 1.460083 1.375999 1.302259 1.238538 1.100059 0.914415 . D Returned NGL rate Rate/Maximum NGL Blending Rate o o o o o o o o o o o o o 0.03371874 0.10424259 0.17055576 0.21651987 0.24418886 0.25429541 0.26873743 0.27503028 0.27815271 0.28332591 0.27078242 0.15088297 0.08116798 0.06115903 0.05045914 0.04337127 0.03783062 0.03358841 0.03010967 0.02733714 0.02508026 0.02330592 0.02165776 0.02032176 0.01915145 0.01812513 0.01723824 0.01531086 0.01272703 . . RECEi\/ED BP Exploration Alaska - Milne Point Field AUG 282001 Kuparuk Reservoir Depletion Plan Aíaska 0,'/ & Gas Con (' "" IS. vommlSSIOl¡ The Milne Kuparuk reservoir is a highly faulted and compartmentalized, highly undersaturated reservoir'~~age reservoir acts like a collection of small accumulations that all need to be managed separately. Voidage replacement, reservoir pressure and gas management, and assessment of sweep are the keys to optimum depletion of the reservoir. Due to the faulted nature of the reservoir, it is split up into a number of blocks referred to as "hydraulic units". In most cases, wells were drilled to exploit each of these blocks as if they were separate fields. Each block contains 1 to 18 wells. These units are important as they are critical to the depletion strategy and they are the basis of most of our reservoir performance evaluations/calculations, Critical data defining the hydraulic units includes 1) a 3D reservoir model accurately representing the fault systems, 2) pressure histories in each block, and 3) changing oil- water-contacts throughout the field. The hydraulic units are treated as separate reservoirs. Analysis methods that apply to a reservoir as a whole must be applied to each individual hydraulic unit. Also, the data required to evaluate the parameters listed above needs to be gathered in sufficient quantity for each of the units. The hydraulic units are the basis for our production forecasts. Each hydraulic unit will have a forecast for oil/water/gas and injection. For hydraulic units that have wells from more than one pad, the forecast volumes will be allocated to the pads based on 1) the number of producers from each pad and 2) the amount of injection from each pad. Within each hydraulic unit there is anywhere from one to five "waterflood patterns". The waterflood patterns are defined as the area bounded by the layout of injectors and producers. This can be defined as either 1) a polygon drawn through the producers surrounding an injector, or 2) a polygon bounded by a combination of the producers and injectors and the hydraulic unit boundaries. The waterflood patterns more closely approximate the area that one might expect to be swept by a secondary or tertiary displacement process. They form the breakdown for an additional set of reservoir performance evaluationslcalculations, including 1) recovery efficiency (particularly secondary or tertiary), 2) injectant throughput versus recovery, 3) IW AG slug size, and 4 )injectant targets. Basic Reservoir Manaaement/DelJletion Objectives Pressure Maintenance "IaœmenI OJ "Ira ee:v: Maintain reservoir pressure as close to original pressure (= 3,500 psi) in all hydraulic units, and all sands within a hydraulic unit. This pressure achieves maximum inflow without requiring high brine weight fluids for rig workovers and reduces the amount of MI required for EOR. Pressure will be maintained with a combination of water and gas injection, with priority given to water injection. Realizing that there are limits to what can be injected, priority should be given to units/patterns with: 1) low maturity (low watercut, high injection efficiency), 2) low pressure, and 3) !WAG capability (EOR targets). The minimum pressure we should allow in the reservoir is the bubble point pressure of 2,450 psi. We should not allow the reservoir to drop below bubble point for two reasons: 1) increases the amount of high GOR production, and 2) increases the oil viscosity, allowing the mobility ratio to become less favorable; thus reducing waterflood sweep efficiency and ultimate recovery. Maximize Recoverv Statement of Stratee:v: Maintain maximum areal and vertical coverage of the reservoir within the waterflood patterns within each hydraulic unit. This is accomplished by utilizing fault interpretation, geologic information, well performance, and surveillance logging to optimally place injection and withdrawal points throughout the reservoir. Focus on unswept areas caused by faulting, lack of continuity between producers and injectors and poor vertical conformance. Relative permeability data, core studies, and simulation results suggest we should be targeting for at least 40% recovery efficiency within the developed waterflood patterns. With the injection of MI, an incremental 9% recovery can be expected. ~ Statement of Stratee:v: Use gas injection to augment water injection for voidage replacement, to provide lift energy, and to displace some additional oil. Schedule IW AG gas injection to minimize producer downtime due to gas breakthrough. VIP Material Balance ¡st ry Match ~~------ new 0 web d ry pore vol increase pore vol decrea leaky fault attached to aquifer perm increase Milne Point Unit K u par u k Full Fie Id Mod e I OW C Polygons 15 Septem ber, 1998 Milne u ruk Wate I od ep Polys . . Material Balance Numbers in Red Indicate Changes From FFM Milne Point Cumulative Production as of 3/31/99 Static Jan-98 J an-98 J an-98 Jan-98 XiuXu Cum Cum Cum Cum Cum Water Model MatBal MatBal MatBal MatBal Latest Oil Gas Water Water Gas Inj Rate Hydraulic HU MatBal MatBal MatBal MatBal MatBal Oil Water W-Inj G-Inj Pressure Pressure Prod Prod Prod Inj Inj (CD) Unit Wen Name OOIP OOIP Aquifer Aq. Size Initital Current Potential Potential Potential Potential Wen Name (psi) Comments MBO MM MB M MM bbls HU HU WName MMBO MMBO Model MMB Pressure Pressure BID BID BID MCFD WName Pressure Comments Ocurn Geum Wcum WICum GlCum WIRate HU 110 26.26 21.70 Radial 929 3,500 3.400 3,180 Current 851 278 76 1,022 - 110 K-18Ai K-18A 3,156 Used K·33 - 1.022 - 110 K-30 13.13 K-30 3.300 9/98 PBU 851 278 76 - 110 K-33 13.13 K-33 3,097 IuitialSBHP 110 122 3.56 3.56 Radial 19 3.600 3,180 3,170 Late-98 - 509 131 558 758 122 K-38 3.56 K-38 2.513 9/98 PHD chang 509 J3J 558 0 K-43Ai K-43A 3,819 2198 758 0 126 9.97 9.97 Radial 733 3.612 2,630 2,760 Late-98 684 214 1,560 126 K-06 4.98 K-06 2.828 12/98 346 109 1,550 - 0 K-13 4.98 K-13 2.695 1199 SBHP 338 105 10 - 0 134/135 12.33 12.40 Radial 162 3,622 2,705 2,880 Latc·98 2,234 839 1,374 2,703 605 134/135 K-17 3.08 K-17 3.144 9/98 PHD Stabl 273 74 132 - 0 K-2li K-21 2,883 12198PFO - 295 0 K-37 3.08 K-37 2,862 9/98 PHD Stabl 256 61 598 - 0 E-17i E-17 Too Old - 2.408 605 0 K-02 3.08 K-02 3,011 10/98 PHO, 248 181 59 521 0 K-05 3.08 K-05 2,510 11/98 SBHP 1,524 645 123 0 141 13.99 13.99 Radial 198 3,500 3.400 3,420 Late-98 - 2,549 2,315 3,896 6,316 1,933 141 E-05i E-05 Too Old 3.585 1.376 0 E-09 4.66 E-09 2,796 9198 PHD chang 1,392 669 469 - 0 E-II 4.66 E-Il 3,610 1/99 SBHP 929 1.395 1.507 - 0 E-22 4.66 E-22 3,610 UsedE-ll 228 251 1,919 0 E-23i E-23 3.663 12/98 2,731 557 0 142 11.46 11.46 Radial 2,225 3,562 3.130 3,100 Late-98 - 3,064 880 6,793 3,475 142 B-05Ai B-05A Too Old - - 3.475 - 0 B-13 SI 0.40 B-13 3.394 11/98 SBHP 4 78 792 - 0 E-04 3.69 E-04 2,370 9/98 PHO Stabl 2.395 611 1,297 0 E-08 3.69 E-08 3.535 9/98 PHD Drop 405 118 3.219 - 0 E-1O 3.69 E-1O Too Old 261 73 1.485 - 0 151 16.31 16.31 Radial III 2,700 3,350 3,070 Late-98 2,821 1,493 8,997 15,176 - 151 B-14i B-14 Too Old - 13,372 0 B-15 7.73 B-15 Too Old 1,082 652 2.075 0 B-16 SI 0.84 B-16 Too Old 842 396 1.407 0 B-20 7.73 B-20 3,067 12/98 SBHP 897 445 5,515 0 CFP-2 CFP-2 Too Old 1,804 0 152 11.85 11.85 Radial 501 3.521 4,125 4,030 Latc·98 - 1,782 717 6,241 14,034 197 152 B-03 11.85 B-03 3,716 9/98 SBHP 1,782 717 6,241 0 B-12i B-12 4,343 12/98 SBHP 8,576 0 B-17i B-17 Too Old 5.458 0 E-02 SI E-02 Too Old 197 0 153 16.62 16.62 Radial 1,413 3,500 3,380 3,350 Late-98 2,923 3,757 1,426 3,138 2,447 153 B-21 5.54 B-21 Too Old 1.640 1.634 204 - 0 E-06 5.54 E-06 3.342 9/98 PHD Slabl 766 1.894 646 0 E-07i E-07 Too Old 82 35 113 3,138 2.447 0 E-14 5.54 E-14 3,350 9/98 PHO chang 434 194 464 154 11.59 11.59 Radial 491 3,500 2.270 2,630 Early-97 2,772 3,853 1,281 2,220 498 154 B-06 3.86 B-06 Too Old - 859 949 1,158 - 0 B-09 3.86 B-09 Too Old 1.130 1.876 82 - 0 B-22 3.86 B-22 2,633 Used E-16 784 1,028 41 0 E-16i E-16 2.626 1/97 SBHP 2.220 498 0 Page 1 . . Material Balance 181 28.91 28.92 Radial 0 3.510 3.000 2,990 Late·98 - 5,057 4,725 6.886 10,154 11,214 181 B-04A 13.50 B-04A Too Old - 1,624 1.872 1,118 0 B-07 SI 0.20 B-07 TooOJd 203 401 3 0 B-08i B-08 Too Old - 1,407 0 B-lO 13.50 B-lO 2.985 11198SBHP 835 1.314 1.978 0 B-lli B-11 Too Old 687 293 529 1.314 0 B-18i B-18 Too Old 7,433 0 B-23Si 0.83 B-23 Too Old 828 707 2.916 - 0 D-02A SI 0.88 D-02A Too Old 881 138 343 - 0 E-03i E-03 None - 11.214 0 182 3.85 3.85 Radial 164 3.500 2.175 2,560 Mid-98 188 148 19 . . 182 E-19 3.85 E-19 2.560 5/98 SBHP 188 148 19 - 0 183 3.37 3.37 Radial 54 3.533 3,570 3,6IHI Late-98 320 129 33 536 183 B-25i B-25 None - 536 0 E-18 3.37 E-18 3.599 9/98 PHO Stabl 320 129 33 - 0 200 8.19 8.19 None N/A 3,500 2,980 3,030 89190 885 1,109 243 776 200 C-16 SI 0.89 C-16 2.758 6190 SBHP 885 1.109 243 0 C-18iSI C-18 3,295 5189 SBHP - - 776 - 0 210 15.76 15.77 3,560 Latc-98 4,940 2,972 3,668 10,438 1,030 210 C-02 5.25 C-02 3,391 9/98 PHD Stabl 2.229 1.147 1.023 0 C-lliSI C-Il 3,808 2199 SBHP - - 3,890 - 0 C-14 5.25 C-14 3,488 5/98 SBHP 2.461 1,687 2.077 0 C-15i C-15 Too Old 15 5 6.548 1.030 0 C-20 5.25 C-20 Too Old 236 133 568 0 211 13.34 13.34 4,250 Late-98 2,240 1,253 1,665 4,958 1,286 211 C-06 5.84 C-06 Too Old 25 12 0 4.958 1,286 0 C-13 SI 1.55 C-13 Too Old 1,548 719 1.634 - 0 C-22S1 0.11 C-22 None 108 133 6 - 0 C-22A 5.84 C-22A 4.245 11198 SBHP 560 389 25 0 212 7.08 7.08 3,570 Early-98 - 1,150 575 544 3,937 774 212 C-04 3.54 C-04 Too Old 891 423 220 - 0 C-lOi C-lO Too Old 3.937 774 0 C-26 3.54 C-26 3,568 1198SBHP 259 152 324 0 220 12.77 22.39 Linear/Sealed 36 3,570 2.900 2,990 1996 2,545 1,651 88 2,926 483 220 C-03 12.77 C-03 Too Old 2.545 1,651 88 - 0 C-12i SI C-12 Too Old - 2,670 - 0 C-28i C-28 2,990 4/96 SBHP - 256 483 0 230 54.89 75.00 Linear/Sealed 71 3.503 3,050 2,970 Late-98 11,316 5,438 1,711 10,355 6,533 230 C-07 9.03 C-07 Too Old 1,458 1.074 139 - 0 C-08i C-08 Too Old 113 33 0 3.244 763 0 C-09 9.03 C-09 3,009 10198 SBHP 3.044 1,731 903 0 C-17i 1 C-17 Too Old 711 414 28 619 942 0 C-19i C-19 Too Old 6,434 1,869 0 C-25i SI C-25 None 58 0 C-25Ai C-25A None - 2,959 0 L-06 9.03 L-06 2,786 9/98 PHD chang 1,716 918 358 0 L-07 9.03 L-07 2.601 9/98 PHD chang 2,577 890 257 - 0 L-11 9.03 L-11 3.247 9/98 PHO CUm 961 229 13 - 0 L-29 9.03 L-29 3.214 9/98 PHO stahle 736 149 13 - 0 235 1.57 5.20 None N/A 3,550 1,380 Latc-98 - 585 284 28 - 235 C-21 1.57 C-21 1.379 9/98 SBHP 585 284 28 - 0 240 2.23 2.23 5,030 Latc-98 . - 1,145 288 240 L-16i 2.23 L-16 5.034 12/98 PFO - 1,145 288 0 251 27.21 20.00 Linear/Sealed 36 3.450 5,460 4,880 Late-98 40 7 13 1,482 331 251 F-4li F-41 5,287 12/98 WHP 915 0 F-57 27.21 F-57 3.905 12197 SBHP 40 7 13 - 0 L-2li L-21 5,452 11/98 SBHP 567 331 0 Page 2 . 290 F-OI F-06 F-lOi F-14 F-18 F-26í F-29 F-46i F-50 F-79 F-84i Page 3 10.40 10.40 10.40 10.40 10.40 F-61 F-66A F-74i 72.82 10.40 10.40 19.04 9.52 9.52 281 F-17 F-3Oi F-34 F-38 F-45 F-53 F-70i F-78 F-22 F-42i F-54 F-92i F-95i 6.55 16.55 16.55 16.55 16.55 16.55 16.55 . 280/295 F-05 F-09 F-13 F-25 F-37 F-62i F-69 L-13 L-15i L-28A L-33i 32.37 16.55 5.46 5.46 6m 7.59 7.59 7.59 7.59 7.59 270 261 252 7.59 7.59 7.59 262 F-73 L-02 L-03 i::õ4 L-05 L-08í L-09í L-24i F-49i F-65 L-14 L-25 10.64 10.64 10.64 51.77 12.94 12.94 12.94 12.94 31.92 50.00 Linear/Sealed 45 3.400 3.290 - - - 51.78 None N/A 3,530 2.290 5.50 60.76 None N/A 3.578 3,000 32.40 None N/A 3.550 2.820 - - - - - - - - - - - - 12.00 None N/A 3,520 2,635 - - 72.82 None N/A 3,490 2,3'8õ F-OI F-06 F-lO F-14 F-18 F-26 F-29 F-46 F-50 F-79 F-84 2,133 2,847 .849 chang chang 1/99 Imtial SBH 308 681 5 86 84 I 5 2 o Too Old 9/98 PHO 9/98 PHD 2,330 1,796 2.055 3.000 1.983 2.993 2,263 4/98 BHP 9/98 rHO Slabl 11197PFO 9/98 PHO chang 9/98 rHO chang T~ /98 PHO Oro 823 261 7 2,021 3.488 .668 ,974 491 504 2 18 F-61 F:66A F-74 2.985 3,054 2,881 2,49õ 2,220 2,766 Late-98 9198 PHD Stab ~...;;hang Too Old Late 98 8,063 .366 .238 1,565 .002 563 F-17 F-30 F-34 F-38 F-45 F-53 F-70 F-78 F-22 F-42 F-54 F-92 F-95 2.887 2.650 .916 2,007 2.7Œ F-05 F-Œ F-13 F-25 F-37 F-62 F-69 L-13 L-15 L-28A L-33 2,7(HI 3.207 1,690 1.686 3,130 3.308 3,032 2,933 Material Balance F-73 L-02 L-03 L-04 L-05 L-08 L-Œ L-24 F-49 F-65 L-14 L-25 2,409 542 340 434 301 33 1198 2198 9/98 PHO S abl -- Too Old -- 9/98 PHD S abl -- ~;ang Too Old 9/98 PHD C I 9198 PHD d Too Old 2198 SBHP 3.840 2.903 2,546 2.800 4.048 ~ 2,740 1,934 2.162 2.8 3,180 37 2 1 23 14 9 ,158 ial S8 hang ang 3.318 Late·98 6198PFO Too Old Late-98 10198 PHO Late.98 9/98 PHO chang 9/98 PHO chang 9/98 PHO chang Too Old 9/98 PHD chang Too Old 9198 PHO chang 9/98 PHO chang None 2199 lnit. SBHP 2/99 SBHP Too Old 11198PBU 6/98 SBHP Late-98 Too Old 9/98 PHD PBU Too Old 12/98 SBHP Late-98 9198 PHD Stab ,994 .588 7 ;6j6 86 520 1,588 726 ,667 ,070 228 ,675 ,563 ,801 8,730 171 i7i 9,089 578 699 ~ 1.263 1.727 2,413 66s 839 910 9,837 2.676 2,784 2,421 ,8~ 38 47 574 172 190 ill 3,480 %š 984 957 554 12 8 12 3 4 5' 501 233 90 24 11 21 23 4,116 4.:.!.!.?, .293 9,524 1,927 .927 1 177 397 293 55 422 595 569 20 ,722 ,923 417 162 272 439 873 194 194 3 9 I 9 I 9 5 2,508 181 Ï8Ï 2,869 195 252 418 428 502 o o o o 262 o 27õ o o o o o o o o o o o 280i295 o o o o o o o o o o o o o 2si o o o 29õ o o o o o o o o o o o 2,375 3,556 1 127 6 473 595 35 702 11 2 '2 769 2 3 3 7 38 3 2,751 8,62s 90 1,901 4.212 10,404 3,441 14 171 241 17 129 252 o o o -0 26i o o . . Page 4 F-85i F-85 2,415 2199 Initial S8H 133 0 301 11.84 11.84 4,240 Late-98 - 37 13 57 7,195 301 F-80 11.84 F-80 4,241 12/98 Initíal 58 37 13 49 0 3R-IOAi 3R-IOA Too Old 0 8 7.195 0 305 1.04 6.20 4,670 Lale-98 - 54 305 L-39i 1.04 L-39 4,665 12/98PFO 54 0 310 1.31 2.36 2,110 Latc-98 - 146 109 21 . 310 1.-40 1.31 L-40 2,106 9/98 PHO Drop - 146 109 21 0 312 2.49 2.50 2,1IHI Late-98 72 22 347 . 312 L-17 2,49 L-17 2.097 9/98 PHD Stabl 72 22 347 0 320 16.36 16.37 Radial 87 3.524 2.785 3,110 Latc-98 2,075 768 562 2,713 320 C-05A 5,45 C-05A 3.016 2/99 SBHP 543 296 21 0 C-36i C-36 3,447 7/98 SBHP 122 0 L-OI 5,45 L-01 3.814 2/99 SBHP 941 259 536 0 L-lOi L-IO 2,591 0 L-12 5,45 L-12 2,175 9/98 PHD ¡;hang 591 213 5 - 0 321/325 10.14 20.10 Radial 283 3.500 1.870 2,670 Late-98 - 1,558 993 41 24 120 321/325 CoOl 10.14 C-01 1.912 2/99 SBHP - 1,558 993 41 0 C-39i C-39 3,436 2198 InitialSBH 24 120 0 335 3.82 3.83 Radial 10 3.658 2.750 2,780 Late-98 - 178 60 16 221 335 J-18 3.82 J-18 2.138 9/98 PHO chang - 178 60 16 - 0 L-42i L-42 3,425 10/98 Initial 58 221 0 342 2.83 ? 3,900 Late-98 - 769 342 J-16 2.83 J-16 3.900 11198 SurfaceP - 769 0 345 10.69 14,40 Radial 77 3.500 1,400 1,2IHI Latc·98 - 1,649 1,247 17 507 345 J-06 5.35 J-06 Too Old - 872 821 3 0 J-09i SI J-09 Too Old - 507 0 HI 5.35 J-11 1,200 11/98PHD 778 426 14 - 0 346 12.59 13.10 Radial 70 3,500 2.850 2,840 Late·98 2,132 609 905 3,699 - 346 J-IO 6.29 J-IO 2,836 9/98 SBHP 1.866 548 44 - 0 J-12 6.29 J-12 Too Old 266 61 861 - 0 J-13i J-13 2.846 UsedJ-12 - 3,699 - 0 380 0.88 3.00 Radial 16 3,550 3.370 3,400 Lale-g8 827 228 769 1,460 380 H-05 0.88 H-05 3,404 9/98 PHD chang 827 228 769 - 0 H-06i H-06 Too Old - 1,460 0 500 11.30 11.30 3,730 Latc-98 - 525 195 174 632 169 500 3K-24 3K-24 3,835 2/99 Initial 58H - 107 60 2 - 0 L-34i L-34 Too Old - 632 169 0 L-35 11.30 L-35 3.623 9/98 PHO chang 419 135 172 0 511 17.50 14.05 3,940 Lale-98 378 158 327 2,914 1,278 511 1.-32 17.50 L-32 3.938 6/98 PHO 171 85 326 - 0 30-07 30-07 Too Old 207 73 0 1,933 1.278 0 3R-20 3R-20 Too Old 0 1 981 0 512 17.50 13.66 2,720 Late-98 793 298 47 1,447 1,925 512 30-14 30-14 Too Old - 124 90 1,447 1,925 512 L-20 8.75 L-20 2,741 9/98 PHO Stabl 598 191 40 - 512 L-36 8.75 L-36 2,698 Used L-20 72 17 6 512 iTôtãls JEE IEM 99.259 49,700 51.749 145,335 29.634 Material Balance . . Milne Point LOT Data o 3000 - - ui (/ c > I- 4000 1000 2000 5000 6000 8 9 10 11 12 13 EMW, ppg 14 15 16 17 18 . BP Amoco ~''''/'~'':_L''-!''_~ - " III ~ -- ~ ~ ~ ~ ~ ~ - , 1 t ~~ .. ~r¡W . Kingak Wellbore Stability Study, Prudhoe Bay, Alaska S/UTG/041/99 Sophie Louise Dowson Well Integrity Team Laboratory experiment simulating drilling fissile shale at high angle (reproduced from Ok land and Cook, 1998) BPAmoco Upstream Technology Group, Sunbury August 1999 GQS38254 I I I 1 , , , , - - ~ ~ 1 :þ :¡:;" en "C. t ~ .J>G) ;~ ill ,~'~.' ::J ~., C' o :3 I ,: ~ -- ~ I I ,. . 'pelldiX A: Field lriformatíon S/UTG/041/99 Well Casing I Test Depth Formation Hole Test Result Hole Size Arœ:le Tvpe (PPWpsi/ft) MDbrt TVDbrt TVDss F9 95/s" / 8.5 9400 8432 8365 Kingak 20 FIT 13.7/0.71 F10 95/S" /8.5 9267 8435 8368 Possibly 24 FIT 13.7/0.71 Kingak H12 95/S" / 8.5 10431 - 8600 8523 Kingak 37 FIT 13.5/0.70 10460 110 95/s" / 8.5 8812 - 8323 8254 Kingak 10 FIT 13.5/0.70 8866 W12A 95/S" / 8.5 13599 No Dati No Dati Below 50 FIT 10.0/0.52 Kingak X33 95/s" / 8.5 3754 3220 No Dati Above 50 FIT 13.26 I 0.69 Kingak Z38 T' /6 10998 8282 No Dati Kingak 37 FIT 12.5/0.65 Z35 T' /6 8903 -6603 No Dati Above 31 FIT 15.2 / 0.79 Kingak EllA T' /6 10995 No Dati 8640 Kingak 72 FIT 9.6/0.47 (PBI) DS10- 95/S" / 8.5 8520 7508 No Dati Creticeous No Dati XLOT 13.8/0.72* 15A Shales above the Kingak NOTES: Possibly Kingak; formation interval not clear from formation tops information Well Z35; morning Reports stite that formation was not broken down at this pressure *Minimum horizontal principal stress (Formation broke down at pressures of between 14.23 to 14.38 ppg) TABLE A2: Formation Integrity Test Results D c: Ci) I:~ co I'V = = ;u fT" 5 r"-, \, # m ~:r":,, <' IT] o Work conducted by both Chan9 and Foxl used a minimum horizontal stress gradient of 0.60 psi/ft (11.5 ppg) within the reservoir below the Kingak. which also agrees with values reported by Addis. Within the Kingak. however, this value is likely to be greater. Within well OSlO-I5A. results of an XLOT within the Cretaceous Shales above the Kingak (reported by Exxonll) indicate a minimum horizontal stress gradient of 0.72 psi/ft (13.8ppg). Altttœgtl">.:cond1.t<;ted in formations. above the Kingak, the result is in reasonable agreement wiaí~'b.Prizooial stress magnitude ~..for the reœnt Niakuk study (Le. 0.738 PPg)· ·~.tJ1e.,FITda~oompiIC(l. ~~that br~ pre5suresWithln t.,he.KingakJ.. ·~ttt·I'Þ!(P~9)~possiblY eveiígreater than 15.2 ppg (2-35),lIthough actual values wiD be dependent OIl a number of factors inclu<ÜlJg well deviatiœalld pore pressure. Since fracture propagation values (approximately equal to the minimum horizontal streSs) are typically less than pressure required for breakdown (except perhaps for high angle wells), a 0.72 psi/ft (13.8ppg) minimum horizontal stress gradient seems a reasonable value to use for the purpose of this study. A3.4 Maximum Horizontal Stress Gradient Determination of the intermediate principal stress is often difficult. Based on a knowledge of the maximum and minimum principal stress, the intermediate stress may be constrained from an adequate knowledge of mechanical rock failure (i.e. breakout width or drilling induced tensile cracks) in offset wells (ideally vertical). For this study, however, such data was limited. Although within problem wells drilling records detail occurrences of instability, ilÛormation on breakout widths from calliper or image data was not available. For the purpose of this study, therefore, the magnitude of the regional maximum horizontal stress is taken to be 0.80 psi/ft (I5.4Oppg). lbis value is also used by both Chan9 and Foxl in their structural analyses of Prudhoe Bay. II "",,(Of 1000 prynro ""7 ·~-~, e MPC-Ol ~.;i'¡'" ~ ... ,:,,': APl:500292066300 SCALE: 1:1200 PLOT DATE:16-Aug-2001 /wnB/geolog/mpu_kuparuk/layoutB/dwg_cur O\}-uvs.A~ þ~ . TD - ~ O/J rÇ.oO ~ F~ £ 61cXaA./ .!1 .u iJI t/) QJ tI) Q 4-1 tI) H ~fq ~Ë tV QJ\1 ø.. ):.... GR 0 GAPI 150 :II~~~ ..""""", ..............¡......¡-.....¡.......¡.....-j--....¡-....".[...... ~ I-;:S î- .".." "..". ¡.., , ~ ,,,,,,,...,,,,,,,,'" ..''I' --,,== ~..... l"i .... ,;,""'""..." "."." L....I ,.... """ .......~. . 1- .............,,,..... ,. .. .... I ff':" """"1...... "."" I. I. ~ JC'" iíi. ~ ,....1.".."...".." "."",,,~. - '" "" t - SFl, NPHI v/v 0 -'-'-~~- o 2 200 0 6 OllMtI ILV RHOB 200 1 65 G/C3 ;¡ 65 o ;¡ OHMM jm!~""- i¡¡¡ji~"..." ~; ~l t. '''''~[t .. I .... H......··..~· .;t:. ':1'-" I .... ·1- i"" ~ ......I~_........... 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I¡¡¡!........ .~ 6 9 5 0 ¡¡¡~!..,",.. jji!~,'-, ~ ".1: "=,. - I' --1'5- 1_ iF, - ': .-.. ~~10 ......~ :~.....:.. -.·~n-J:~I....... .... ....~............. ...... ~.m··I··..···1 I....···· ..... ..II:::'~~~:± I 1m! .. ··!;jl4:! I ...... ·...,,1.........··... ···....1·":- ,;.:..1........,,, ¡...... ....., .....: ·····tII' :=....... , . "".....' "",-=.. - - =_... - ., . .... ",.. "..... ;¡¡r.¡¡"",,~ IInm'''''''' ';';1"7 050 \~!:::' ........~7000 ",,,,,, ""111"'''''' ""..,. ¡¡¡i¡¡"",,,~ ... t ;:":'1"" f~·"···· ....1'. II L.._ . ......1..1, ........I....... :\ I! I ; " ! I[ '.U #5 . . Gon r¡c!.eJ1{7t:JL.) ))'1 k . ~ CA ., -P t d..tz..". Îi4 L ROðY>') #4 bp .,. ,\tf.'". ~:~ ~~.. .,.....~ -F~'" .;~'.j~\" "~ Jeanne H. Dickey Senior Counsel BP Legal BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage AK 9950B P.O. Box 196612 Anchorage AK 99519-6612 August 17,2001 HAND DELIVERED voice: 907 564 4053 fax: 907 564 4031 dickeyjh@bp.com www.bp.com Alaska Oil and Gas Conservation Commission 333 West th Avenue, Suite 100 Anchorage, Alaska 99501 RECEIVED :\IJC: I '{ 2001 Re: Milne Point Unit Area Injection Order A!(1!2ka Uil & Gas Cons. Commission Anchora!)o Dear Commissioners: Enclosed is a signed copy of the application of BP Exploration (Alaska) Inc., Milne Point Unit Operator, to amend the Milne Point Unit Area Injection Order No. 10 to reflect changes in pool boundaries and the description of the enhanced oil recovery project for the Kuparuk River Oil Pool. BP also proposes that separate orders be issued covering the Kuparuk River Oil Pool and the Schrader Bluff Oil Pool in the Milne Point Unit. I understand that Jane Williamson and Byron Haynes have been discussing certain technical information the Commission would like to review concerning the MW AG project. I am enclosing the Milne Point Kuparuk Reservoir EOR Strategy and Implementation Plan dated July 2001 prepared by Byron and Samson Ning. Byron will be providing additional technical information separately. If you have any questions regarding the application, please feel free to contact me or Sean Monico (564-5643). Very truly yours, ~1 (l:::U:~SUII Cc: Jane Williamson, AOGCC Byron Haynes Daryl Kleppin Bill March Sean Monico . . RECEIVED AUG 17 2001 Alaska Oil & Gas Cans. Commission Anchorage APPLICATION TO AMEND ALASKA OIL AND GAS CONSERVATION COMMISSION AREA INJECTION ORDER NO. 10 MILNE POINT UNIT BP EXPLORATION (ALASKA) INC. AUGUST 17,2001 . . . APPLICATION TO AMEND AREA INJECTION ORDER NO. 10 MILNE POINT UNIT BP Exploration (Alaska) Inc. (BP), Milne Point Unit Operator, files this application to amend Area Injection Order No. 10 (AIO No. 10) for the Milne Point Unit. AIO No. 10 governs Class II underground injection operations in the Kuparuk River Oil Pool and Schrader Bluff Oil Pool in the Milne Point Unit. BP requests amendment of AIO No. 10 to (1) provide separate AIOs for the Milne Point Unit Kuparuk River Oil Pool and the Milne Point Unit Schrader Bluff Oil Pool, (2) amend the described area in the AIO for the Kuparuk River Oil Pool to coincide with current Milne Point Unit and pool boundaries, and (3) to describe the proposed miscible gas enhanced hydrocarbon recovery project in the Milne Point Unit Kuparuk River Oil Pool. AIO No. 10 presently allows the injection of non-hazardous fluids for pressure maintenance and enhanced oil recovery into the Schrader Bluff Oil Pool and the Kuparuk River Oil Pool in the Milne Point Unit. AIO No. 10, originally issued September 19, 1986 pursuant to an application by operator Conoco, Inc., permitted the injection of non-hazardous fluids into the Kuparuk River Oil Pool for pressure maintenance and enhanced oil recovery. By an order dated December 30, 1991, AIO No. 10 was amended to include Class II underground injection into the Schrader Bluff Oil Pool. BP has conducted an immiscible water/alternating gas (IW AG) enhanced oil recovery (EOR) project in the Kuparuk River Oil Pool for the past several years and proposes to initiate a miscible water/alternating gas (MW AG) project for the Kuparuk River Oil Pool. A waterflood project has been and continues to be conducted in the Schrader Bluff Oil Pool. This application addresses the specific requirements of 20 AAC 25.402(c) that pertain to the Kuparuk MW AG project that were not addressed in prior AIO No. 10 applications. . . MILNE POINT UNIT KUP ARUK OIL POOL AREA INJECTION ORDER The Milne Point Unit Kuparuk MW AG project was described in a presentation and slides previously provided to the Commission. In association with the MW AG project, three types of injection fluid will be utilized: · Source water · Produced water · Miscible hydrocarbon gas In addition to the fluids specifically associated with the MW AG project, the following other incidental fluids may be injected at some time provided such fluids function primarily to enhance recovery of oil and gas and are appropriate for enhanced recovery: · Sea water to thermally frac gas injection wells · Solution gas associated with oil production · Tracer survey fluids to monitor reservoir performance 1. Plat of Proiect Area (20 AAC 25.402(c)(l)). Exhibit A-I is a plat showing the location of the Kuparuk River Oil Pool in the Milne Point Unit, which is the Kuparuk MW AG project area ("MW AG Area"), the Schrader Bluff Oil Pool, existing and/or proposed injection wells, abandoned or other unused wells, existing and/or proposed production wells, dry holes, and other wells within Yt mile of the MW AG Area. Exhibit A-2 is a legal description of the lands in the MW AG Area. 2. Operators/Surface Owners (20 AAC 25.402(c)(2) and 20 AAC 25.403(c)(3)). The operators and surface owners within Yt mile radius of the MW AG Area are: Operators BP Exploration (Alaska) Inc. Milne Point Unit Operator and Prudhoe Bay Unit Operator P.O. Box 196612 Anchorage, Alaska 99519-6612 Phillips Alaska, Inc. Kuparuk River Unit Operator P.O. Box 100360 700 G Street Anchorage, Alaska 99510-0360 2 . . J. Andrew Bachner P.O. Box 82130 Fairbanks, Alaska 99708 Surface Owners State of Alaska Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, Alaska 99501 Exhibit B is an affidavit showing that the operators and surface owners within a If4 mile radius of MW AG Area have been provided a copy of this application. Milne Point Unit oil and gas lessees have also been provided a copy. 3. Description of Operation (20 AAC 25.402(c)(4)). Approval is requested for amendment of AIO No. 10 to include the Kuparuk MW AG project and to segregate AIO No. 10 as it pertains to injection for enhanced recovery in the Schrader Bluff Oil Pool. Development plans and further details regarding the project were previously provided to the Commission. 4. Pool Information (20 AAC 25.402(c)(5)). The Kuparuk MWAG project affects the Kuparuk River Oil Pool. The Kuparuk River Oil Pool is the portion of the Kuparuk River Field in the Milne Point Unit that correlates with the strata found in the ARCO Alaska, Inc. West Sak River State Well No.1 between the measured depths of 6,474 feet and 6,880 feet. See Conservation Orders Nos. 173,349 and 349A. The Schrader Bluff Oil Pool, Kuparuk River Field, as described in Conservation Order No. 255, is the accumulation of oil and gas within the following area within the stratigraphic sections which correlate with the stratigraphic section occurring in the Conoco Inc. Milne Point A-I well between the measured depths of 4,174 and 4,800 feet: Umiat Meridian T13N, R9E T13N, RlOE T13N, EIIE Sections 13, 14,23,24 All Sections Sections 5, 6, 7, 8,15,16,17,18,19,20,21,22,29,30,31 and 32 3 . . 5. Geologic Information (20 AAC 25.402(c)(6)). The name, description, depth, and thickness of the formations into which MW AG project fluids are injected is described in the relevant Conservation Orders governing the Kuparuk River Oil Pool. See Conservation Orders Nos. 173, 349 and 349A. Geological data on the injection zones and confining zones, including lithologic descriptions and geologic names have been provided in applications, proceedings and reports to the Commission regarding reservoir development and performance in the Milne Point Unit, including the Kuparuk River Oil Pool IW AG project and the Schrader Bluff Oil Pool waterflood project. See AIO No. 10 and CO No. 283. 6. Well Logs (20 AAC 25.402(c)(7)). The logs of existing injection wells are on file with the Commission. Exhibit C-l and Exhibit C-2 are type logs for MW AG Area injection wells MPF-18 and MPC-39, respectively. 7. Mechanical Integrity (20 AAC 25.402(c)(8)). Wells used for injection will be cased and cemented in accordance with 20 AAC 25.412. In drilling all Milne Point Unit injection wells, the casing is pressure tested in accordance with 20 AAC 25.030. Injection well tubing/casing annulus pressures will be monitored and recorded on a regular basis. BP as Milne Point Unit Operator 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 casing's minimum yield strength. If an injection well is deemed to have anomalous annulus pressure, it will be investigated for tubing/annulus communication using a variety of diagnostic techniques and a mechanical integrity test. If a subsequent 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. A schedule will be developed and coordinated with the Commission which ensures that the casing/annulus for each injection well is pressure tested prior to initiating injection. The test will be at a 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 70% of the casing's minimum yield strength. The test pressure must be held for 30 minutes with no more than a 4 . . 10 percent decline. The Commission will be notified at least 24 hours in advance to enable a representative to witness the pressure test. Alternative EP A 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 MW AG Area will not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. 8. Iniection Fluids (20 AAC 25.402(c)(9)). The Kuparuk MW AG project will utilize three primary types of injection fluids: source water, produced water, and miscible hydrocarbon gas. Source Water and Produced Water. The produced and source water injected in the MW AG project was previously described in the application for the IW AG project. The approximate water injection volume needed is 60,000 bbl. water per day and may be increase as needed to make up reservoir voidage. Miscible Hydrocarbon Gas. The miscible hydrocarbon gas will be a blend ofthe hydrocarbon gas associated with oil produced through the CFP and NGLs imported from the Prudhoe Bay Unit. The specific blend of gas and NGLs will be regulated to ensure that miscibility between the injected gas and the reservoir fluids is maintained. Exhibit D shows the estimated composition of the miscible hydrocarbon gas based on a blend ratio of 4.512 MSCF lean gas/bbl. NGL for an MMP of 2900 psia. This composition will vary with the blend ratio of lean gas to NGLs. The predicted daily rate of miscible hydrocarbon gas injection is approximately 25 MMSCF. Fluid incompatibility problems are not anticipated with the miscible hydrocarbon gas. Other Fluids. In addition to the fluids specifically associated with the Kuparuk MW AG project, the following other incidental fluids may be injected into the Kuparuk River Oil Pool at some time during the life of the project provided such fluids function primarily to enhance recovery of oil and gas and are appropriate for enhanced recovery: · .Sea water to thermally frac gas injection wells - stimulation procedure using 20,000- 40,000 gallons per well · Solution gas associated with oil production - re-injected for reservOIr pressure maintenance 5 . . . Tracer survey fluid - to monitor reservoir performance Additional fluids may be injected after treatment to ensure they are compatible and appropriate for EOR. 9. Injection Pressures (20 AAC 25.402(c)(10)). The estimated average and maximum injection pressure for the Kuparuk MW AG project is as follows: Water injection Gas injection 3500 4800 Estimated Average (psig) 3000 4000 Service Estimated Maximum (psig) 10. Fracture Information (20 AAC 25.402(c)(11)). The estimated maximum injection pressures for the Kuparuk MW AG project will not initiate or propagate fractures through the confining zones that might enable the injection fluid or formation fluid to enter freshwater strata. 11. Water Analysis (20 AAC 25.402(c)(12)). The quality of the water within the formation into which fluid injection is proposed was described in the prior AIO No. 10 application. Subsequent samples confirm that the water quality in the MW AG injection zone is well in excess of 10,000 mg/l TDS. 12. Aquifer Exemption (20 AAC 25.402(c)(13)). Aquifer Exemption Order No.2 (AEO No.2) was issued by the Commission on July 8, 1987 and covers Class II injection activities for the following lands: T13N, R9E, UM - Sections 13, 14,23 and 24 T13N, RlOE, UM - All sections T13N, R11E, UM- Sections 5, 6, 7,8,15,16,17,18,19,20,21,22,29,30,31 and 32 These lands are the same as those included in the Schrader Bluff Oil Pool described in CO No. 255 and the Schrader Bluff Oil Pool waterflood project described in CO No. 283. In its application for exemption, Conoco (who was Milne Point Unit Operator at that time) stated it was seeking an exemption for the Shallow Sand formations (Tertiary water sands) now designated the Prince Creek formation, located above the Schrader Bluff Oil Pool. Further information concerning the aquifer is contained in Commission records regarding AEO No.2. 6 . . 13. Hydrocarbon Recovery (20 AAC 25.402(c)(14)). The expected incremental increase in ultimate hydrocarbon recovery attributable to the MW AG project is 8% - 9% OOIP in the affected areas. 14. Mechanical Condition of Adiacent Wells (20 AAC 25.402(c)(15)). To the best of BP's knowledge, the wells in the MW AG Area were constructed and, where applicable, have been abandoned to prevent the movement into freshwater sources. Information regarding wells that penetrate the injection zone within Y4 mile radius of injection wells has been filed with the Commission. BP believes it would be more appropriate for the two oil pools covered by AIO No. 10 - the Kuparuk River Oil Pool and the Schrader Bluff Oil Pool - to be governed by a separate area injection orders so that the development of each pool can be considered and regulated individually. Further, BP requests that the area governed by each area injection order coincide with the areal extent of the pools as described in the relevant conservation orders for each pool. BP respectfully requests that the proposed Area Injection Orders attached hereto as Exhibits E and F be issued by the Commission. Respectfully submitted, BP Exploration (Alaska) Inc. Milne Point Unit Operator By tJJ¡,-£~ ¿: '1 ûA d- Its FAel'-I1't~~ 1J£L,1)6~yŒÆrlI£Aj)EI!!. 7 EXHIBIT A-I EXHIBIT A-2 EXHIBIT A-3 EXHIBIT B EXHIBIT C-l EXHIBIT C-2 EXHIBIT D EXHIBIT E EXHIBIT F . . EXHIBITS PLAT OF MILNE POINT UNIT KUP ARUK OIL POOL PLAT OF MILNE POINT UNIT SCHRADER BLUFF OIL POOL LEGAL DESCRIPTION OF KUP ARUK RIVER OIL POOL MW AG AREA AFFIDA VIT TYPE LOG FOR MPF-18 INJECTION WELL TYPE LOG FOR MPC-39 INJECTION WELL KUP ARUK RIVER OIL POOL MW AG MI COMPOSITION PROPOSED AREA INJECTION ORDER 10-A MILNE POINT UNIT KUP ARUK RIVER OIL POOL PROPOSED AREA INJECTION ORDER 10-B MILNE POINT UNIT SHCRADER BLUFF OIL POOL Projection InformatiQn ~or<Qll;,¡(;l.Qtorjg;~ lOOOO'OO,(jQ' D&¡I¡%~W!¡~¡ Q,9000000000 1!il4i)Q.30&EF$Øt P.olJfoi Fo~\ ~002r,a7H)J6F06¡ 1;2eA.w~o Ssm,majqr>1Xil ~~~lWrto. Q::I Þ<: ::r:: H tJj H H > ¡ >-' Milne Point Unit, Kuparuk River Oil Pool Area Injection Order Legend WtM~G~1on FaGllltteaandw.tlPt\d$ ...... :> I r---.: Injection Order Pool Area Schrader Bluff Oil fÞIlitm 11IM Well PMD ..... legend ~~ØaIIM'riø .1D'X1~"-1).OI A(4M,~C.1I Coo, 1¡;()OO'OOJW'DIt(I',*,~W~ "'","0??oo 1ó~400,3O!'i E F",,\ . . EXHIBIT A-3 LEGAL DESCRIPTION OF KUP ARUK RIVER OIL POOL MW AG AREA T12N, RI0E, UM TI2N, RIlE, UM T13N, R9E, UM T13N, RI0E, UM T13N, RIlE, UM TI4N, R9E, UM TI4N, RI0E, UM Sections 1, 2, 11 and 12 Sections 1,2,3,4,5,6, 7, 8, 9, 10, 11 and 12 Sections 1, E/2 and NW/4 of2, NE/4 of 11, 12, 13, 14,23 and 24 All Sections Sections 7, 8,17,18,19,20,27,28,29,30,31,32,33 and 34 Sections 11, 12, 13, 14, 15,22,23,24,25,26,27,34,35 and 36 Sectionsl7, 18, 19,20,21,25,26,27,28,29,30,31,32,33,34,35 and 36 . . EXHIBIT B AFFIDAVIT STATE OF ALASKA ) ) ss THIRD JUDICIAL DISTRICT ) r\CtLtR- ~t-" , on oath, deposes and says: 1. I am employed by BP Exploration (Alaska) Inc. 2. On August 17, 200 I, I caused copies of the Application to Amend Alaska Oil and Gas Conservation Commission Area Injection Order No. 10, Milne Point Unit, to be mailed first class, postage prepaid, to the following: J. Andrew Bachner P.O. Box 82130 Fairbanks, Alaska 99708 3. On August 17,2001, I caused a copy of the Application to Amend Alaska Oil and Gas Conservation Commission Area Injection Order No. 10, Milne Point Unit, to be hand delivered to the following: Pat Pourchot, Commissioner, Alaska Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, Alaska Phillips Alaska, Inc., Kuparuk River Unit Operator Attn: Jim Ruud, Land Manager Anchorage, Alaska BP Exploration (Alaska) Inc. Milne Point Unit Operator and Prudhoe Bay Unit Operator Attn: Neil McCleary and Mark Bly 900 East Benson Blvd. Anchorage, Alaska i,p--o/- R Q#j Subscribed and sworn to before me this 1 ih day of August'i-\OO 1. /tPA~iItJ /c~ ¡ Notary Public in and for Alp.ska VMy Commission Expires:!(..(Þ-¿ (p ( 2---.ðD L EXIIIBIT C-l MPF-18 API:500292268100 SCALE: 1:480 PLOT DATE:18-Jul-2001 \LAYOUTS/MPU_KUP-padbook.layout ..fI ItS .¡J s:: Q¡ iØ GI II Q œ œ II-! œ I'J,) ~ fII¡¡, ~ë CD elM Øa ~tJ 0 þ¡ Ef TMLV EXHInIT C-2 MPC-39 API: 500292284900 SCALE: 1:480 PLOT DATE:18-Jul-2001 \ LAYOUTS/MPU_KUP -padbook. layout .c! '8 .aJ ø. lIS ~ Æ OJ OJ 11-I OJ I'.Q J.¡ 1IIe. ~t ø. . CIIf/I øø ~~ E-i~ ~ 0 200 I TXA TXA v . . EXHIBIT D KUP ARUK RIVER OIL POOL MW AG MI COMPOSITION BASED ON A BLEND RATIO OF 4.512 MSCF LG/BBL NGL FOR AN MMP OF 2900 PSIA Component Mole Fraction CO2 0.0079 Cl 0.6739 C2 0.0634 C3 0.0385 i-C4 0.0255 n-C4 0.0789 i-C5 0.0247 n-C5 0.0358 C6 0.0331 C7 0.0146 C8 0.0036 Total 1.0000 . . EXHIBIT E PROPOSED AREA INJECTION ORDER NO. 10-A MILNE POINT UNIT KUP ARUK RIVER OIL POOL IT APPEARING THAT: 1. By application dated August 17, 2001, BP Exploration (Alaska) Inc. ("BP") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to amend Area Injection Order No. 10 (AIO No. 10) to provide separate orders for the Kuparuk River Oil Pool and Schrader Bluff Oil Pool in the Milne Point Unit with respect to the injection of fluids for the purposes of enhanced oil recovery and to amend the Kuparuk River Oil Pool area authorized for Class II injection to coincide with the Kuparuk River Oil Pool in the Milne Point Unit. BP provided supplemental information on 2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on 3. [The Commission did not receive any protest or request for a public hearing.] FINDINGS: 1. Commission regulation 20 AAC 25.460 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. 2. The Milne Point Unit Kuparuk River Oil Pool is the portion of the Kuparuk River Field Kuparuk River Oil Pool as defined in Conservation Order No. 349A that lies within the Milne Point Unit on Alaska's North Slope. 3. BP has provided all designated operators within one-quarter mile of the Milne Point Unit Kuparuk River Oil Pool with a copy of the application for amendment of AIO No. 10. 4. BP has operated an immiscible water alternating gas ("IW AG") enhanced oil recovery project in the Milne Point Unit Kuparuk River Oil Pool for the past several years pursuant to AIO No. 10. 5. BP plans to begin a miscible water alternating gas ("MW AG") enhanced oil recovery project in the Milne Point Unit Kuparuk River Oil Pool. . . 6. Aquifer Exemption Order No.2 (AEO No.2) exempted portions of aquifers lying directly below certain lands, a portion of which are included within the MW AG project area, for Class II injection activities. 7. Injection in Class II enhanced recovery injection wells in the Kuparuk River Oil Pool in the Milne Point Unit will not involve injection in or movement of fluids into the Shallow Sands strata aquifer described in AEO No.2 application and supplemental materials. 8. The mechanical integrity of the Milne Point Unit Kuparuk River Oil Pool injection wells will comply with the requirements specified in 20 AAC 25.412. 9. The operator will comply with the requirements of 20 AAC 25.402(d) and (e) to monitor tubing-casing annulus pressures of injection wells periodically during injection operations to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 10. All existing wells drilled within the proposed project area have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the proposed project area have been abandoned in accordance with 20 AAC 25.105 and 20 AAC 25.112 or an equivalent precursor regulation. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An area injection order is appropriate for the project area under 20 AAC 25.460. 3. 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. 4. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 5. The proposed MW AG project will result in recovery of 8% - 9% OOIP in the affected areas. 6. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 7. Amendment of AIO No. 10 enabling enhanced oil recovery activity will not cause waste nor jeopardize correlative rights. 2 ¡ . . . 8. Amendment of AIO No. 10 to provide separate orders for the Kuparuk River Oil Pool and the Schrader Bluff Oil Pool in the Milne Point Unit is appropriate. 9. Amendment of AIO No. 10 to include the portion of the Kuparuk River Field Kuparuk River Oil Pool within Milne Point Unit, as defined in Conservation Order No. 349A, is appropriate. NOW, THEREFORE, IT IS ORDERED, that the following rules, in addition to statewide requirements under 20 AAC 25, govern Class II enhanced oil recovery injection operations in the affected area described below: UMIAT MERIDIAN T12N, RI0E, U.M. TI2N, RIlE, U.M. T13N, R9E, U.M. T13N, RI0E, D.M. T13N, RIlE, U.M. TI4N, R9E, D.M. TI4N, RI0E, U.M. Sections 1, 2, 11 and 12 Sections 1,2,3,4,5,6, 7, 8, 9, 10, 11 and 12 Sections 1, E/2 & NW/4 of2, NE/4 of 11, 12, 13, 14,23 and 24 All Sections Sections 7,8,17,18,19,20,27,28,29,30,31,32,33 and 34 Sections 11, 12, 13, 14, 15,22,23,24,25,26,27,34,35 and 36 Sections 15, 16, 17, 18,19,20,21,22,27,28,29,30,31,32,33,34 and 35 Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to those found between the measured depths of 6,474 feet and 6,880 feet in the ARCO Alaska, Inc. West Sak River State Well No. 1. Rule 2 Fluid Injection Wells The underground injection of fluids must be 1) through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of AIO No. 10 (September 19, 1986). Rule 3 Monitoring the Tubing-Casing Annulus Pressure Variations 3 . . . The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage. The tubing/casing annulus must not be allowed to exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4 Reporting the Tubing-Casing Annulus Mechanical Integrity Tubing-casing annulus pressure variations of more than 200 psi between consecutive pressure readings made when injecting under steady state conditions of fluid temperature, rate, and pressure must be reported to the Commission on the first working day following the observation. Rule 5 Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission which ensures that the tubing/casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength, will be used. The test pressure must be held on the tubing/casing for 30 minutes with no more than a 10% decline. Alternative EP A 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). Wells with tubing-to-casing communication must be surveyed or logged every other year and wells which must be surveyed or logged every other year and wells which demonstrate mechanical integrity every fourth year. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests or the application of alternative methods. Rule 6 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must immediately cease injection, notify the Commission, and obtain approval for corrective action. Rule 7 Plugging and Abandonment of Fluid Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC25.105. 4 .. ). . . Rule 8 Administrative Action Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. Rule 9 Orders Revoked AIO No. 10 and any associated Administrative Approvals and letter approvals are hereby revoked and superceded by this Area Injection Order No. 10-A and the accompanying Area Injection Order No.1 O-B covering the Milne Point Unit Schrader Bluff Oil Pool. 5 ..-. . . . EXHIBIT F PROPOSED AREA INJECTION ORDER lO-B MILNE POINT UNIT SHCRADER BLUFF OIL POOL IT APPEARING THAT: 1. By application dated August 17, 2001, BP Exploration (Alaska) Inc. ("BP") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to amend Area Injection Order No. 10 (AIO No. 10) to provide separate orders for the Kuparuk River Oil Pool and Schrader Bluff Oil Pool in the Milne Point Unit with respect to the injection of fluids for the purposes of enhanced oil recovery. 2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on 3. [The Commission did not receive any protest or request for a public hearing.] FINDINGS: 1. Commission regulation 20 AAC 25.460 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. 2. The Milne Point Unit Schrader Bluff Oil Pool is the portion of the Kuparuk River Field Schrader Bluff Oil Pool as defined in Conservation Order No. 255 (CO No. 255) and applies to the following area: Umiat Meridian T13N, R9E Sections 13,14,23 and 24 T13N, RI0E All Sections T13N, R11E Sections 5, 6, 7, 8, 15, 16, 17, 18, 19,20,21,22,29,30,31 and 32 3. Conservation Order No. 283 (CO No. 283) approved the Schrader Bluff Oil Pool waterflood project and established certain reporting requirements for the lands described in paragraph 2 above. 4. AIO No. 10, initially issued September 19, 1986, governed Class II underground injection wells in the Kuparuk River Oil Pool in the Milne Point Unit. 5. AIO No. 10 was amended December 30, 1991, to govern Class II underground injection wells in the Schrader Bluff Oil Pool, as well as the Kuparuk River Oil Pool. .. ) .. . . 6. Aquifer Exemption Order No.2 (AEO No.2) exempted portions of aquifers lying directly below the lands described in paragraph 2 above for Class II injection activities. 7. No injection in the Shallow Sands strata described in the AEO No.2 application and supplemental materials is taking place in the Milne Point Unit. 8. Milne Point Unit operator has operated waterflood enhanced oil recovery project in the Milne Point Unit Schrader Bluff Oil Pool pursuant to AIO No. 10 and CO No. 283. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. Amendment of AIO No. 10 to provide separate orders for the Kuparuk River Oil Pool and Schrader Bluff Oil Pool in the Milne Point Unit with respect to the injection of fluids for the purposes of enhanced oil recovery is appropriate. NOW, THEREFORE, IT IS ORDERED, that the following rules, in addition to statewide requirements under 20 AAC 25, govern Class II enhanced oil recovery injection operations in the affected area described below: Umiat Meridian T13N, R9E T13N, RI0E T13N, R11E Sections 13, 14,23 and 24 All Sections Sections 5, 6, 7, 8, 15, 16, 17, 18, 19,20,21,22,29,30,31 and 32 Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to those found between the measured depths of 4,174 feet and 4,800 feet in the Conoco Milne Point Unit Well No. A-I. Rule 2 Fluid Injection Wells The underground injection of fluids must be 1) through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a 2 ..¡ ) r. . . . well that existed as a service well for injection purposes on the date of AIO No. 10 (September 19, 1986). Rule 3 Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage. The tubing/casing annulus must not be allowed to exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4 Reporting the Tubing-Casing Annulus Mechanical Integrity Tubing-casing annulus pressure variations of more than 200 psi between consecutive pressure readings made when injecting under steady state conditions of fluid temperature, rate, and pressure must be reported to the Commission on the first working day following the observation. Rule 5 Demonstration of Tubing/Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission which ensures that the tubing/casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength, will be used. The test pressure must be held on the tubing/casing for 30 minutes with no more than a 10% decline. Alternative EP A 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). Wells with tubing-to-casing communication must be surveyed or logged every other year and wells which must be surveyed or logged every other year and wells which demonstrate mechanical integrity every fourth year. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests or the application of alternative methods. Rule 6 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must immediately cease injection, notify the Commission, and obtain approval for corrective action. 3 .. -"I . . . Rule 7 Plugging and Abandonment ofPluid Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8 Annual Reservoir Surveillance Report An annual Schrader Bluff Oil Pool surveillance report will be required by April 1 of each year. The report shall include but is not limited to the following: 1) Progress of enhanced recovery proj ect implementation and reservoir management summary. 2) V oidage balance by month of produced fluids (oil, water and gas) and injected fluids (gas, water, low molecular weight hydrocarbons, and any other injected substances). 3) Analysis of reservoir pressure surveys within the field. 4) Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys. Rule 8 Administrative Action Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. Rule 9 Orders Revoked Conservation Order No. 283 and AIO No. 10 and any associated Administrative Approvals and letter approvals are hereby revoked and superceded by this Area Injection Order No. lO-B and the accompanying Area Injection Order No. 10-A covering the Milne Point Unit Kuparuk River Oil Pool.e 4 r . . RECEIVED AUG 1 7 2001 A.laska Oil & Gas cems. Commisslo.n Anchorage Milne Point Kuparuk Reservoir EOR Strategy and Implementation Plan July, 2001 Byron Haynes, Jr. and Samson Ning H:\Milne\A 0 G C C\KEOR Strategy41.doc 1 . . Milne Point Kuparuk Reservoir EOR Strategy and Implementation Plan List of Figures........ .............. ...... ........... .... ...... ....... ............... ........ ...... ..... .......... ............. .... 3 List of Tables ................... .......... ....... ...................... .... ..... ... ......... ..... ........... ................. ...... 3 Executive Summary ... ................................... ... ......... ........ ............ ...... ................................ 4 Startup Injectors..................... ............ ..................... ..... ....................... ...... ............ .......... 4 Blending............. ..... ..... .......... ............ .......................... ......... ................ ................ .......... 5 Surveillance..................................................................................................................... 5 Introduction.................................................................................................................. ....... 6 Project Scope.............................. ............. ............... ......................................... ................... 6 Overview of Milne Point Kuparuk EOR Strategy.................. ........ .................................... 6 Pattern Development Schedule........................................................................................... 7 Pattern Management.................. ..... ............... ... .......... ............................................. ........... 8 Pattern Base Performance.................. ............................................. ................................ 8 Reservoir Pressure Strategy........ .......................... ............... ......... ................................ 10 V oidage Replacement.......... .... ............................. ...................,...... ......... ............ ......... 11 MI Distribution in the Reservoir...... ........ .... ............ ... ........ .................... ................. ..... II Fluid Compositions.............................. ............................ ........................ ..... ................ 12 WAG Strategy................. ..... ...... .... ..................... ....... ................................................... 13 MI Blending and Quality Control........................... .... ...................... ...................... .......... 13 Blend Gas Source and Facility Capacity ...................................................................... 13 Recommended EOR Surveillance........ .... ......... ...... .......... ...... ............. .... ....... .................. 14 CFP Gas Composition Monitoring ... ........... ............. ...... ............... ............................... 14 NGL Composition.......... ....... ......... ....... .............. .................. ............. ......... ...... ............ 15 Miscible Solvent Composition and MMP Determination ............................................ 15 Produced Gas Composition...... ........ ..... ....... ..... ......... ........... ............................... ......... 16 RMI Monitoring Plan........ ........... ................. ................. .... ........ ........... ....... .... ......... 16 RMI Sampling Guidelines .. ......... ............. ...... ..... ........ ....... ......... ............. ......... ....... 17 Produced Oil Samples ... ........... ............ ...... ......... ............. .... ....... ...... .......... .... .............. 17 Bottomhole Pressures.................................................................................................... 17 Injection Profiles............................................................... ............................................ 18 Well Testing.................................................................................................................. 18 Reporting Requirements ........ .............. .......... .................... ................ ........... .......... .......... 18 Responsibilities .. ....... ..... .... ...... ................. ..... ....... ................... ........ ........... ...... ....... .... ..... 18 WAG Conversions, Ratios and Scheduling .................................................................. 18 Management of MW AG During Upset Conditions .......................................................... 19 KEOR Safety Guidelines .. ....... ... .............. ...... ............. ...... .... .... .............. ......... .... ......... ... 19 H:\Milne\A 0 G C C\KEOR Strategy41.doc 2 . . List of Figures Figure 1: KEOR Process Flow Diagram...........................................................................20 Figure 2: Milne Point Hydraulic Units with Wells.......................................................... 21 Figure 3: Milne Point Kuparuk Waterflood Patterns....................................................... 22 Figure 4: IWAG Pattern Cumulative Gas Slug Size vs Average pattern GOR............... 23 Figure 5: KEOR Cumulative Pattern OOIP Versus GOR and Incremental EOR Benefit 24 Figure 6: Reservoir Pressures of Kuparuk sands across EOR pattern Areas.................... 25 Figure 7: Pressure Impact on FVF of MI... ....... .................... .... ................ ................... ..... 25 Figure 8: GOR Distribution across the IW AG Patterns.................................................... 26 Figure 9: Total Throughput Across the IW AG Patterns................................................... 26 Figure 10: Milne Point Gas Forecast ....... ............................... .......................................... 27 Figure 11: Blend Gas to NGL Ratio. ................ ............... ................................ ................. 28 List of Tables Table 1: KEOR Pattern Ranking based on Patterns with 1998 Tax Credit wells, Average GOR and HCPV Throughput... .............................. ..... ........ ............... ....................... 29 Table 2: KEOR Initial Pattern Classification....................................................................30 Table 3: 1998 EOR Tax Credit Injectors .......................................................................... 30 Table 4: 1998 EOR Tax Credit Producers ........................................................................30 Table 5: Injector MI Volumes, Pattern GOR and Throughput .........................................31 Table 6: Mole Fraction of Lean gas and NGL's for Blending.......................................... 31 Table 7: EOR Surveillance Summary ............................................................................... 32 Table 8: Gas Lifted WAG patterns ................................................................................... 32 H:\Milne\A 0 G C C\KEOR Strategy41.doc 3 . . Executive Summary The KEOR project will startup in November, 2001 by injecting approximately 25 MMscfpd of miscible injectant (MI) into select wells on C, E, F and L-pads. The MI will be manufactured by blending 4 - 5 Mbpd of imported NGLs with approximately 20 MMscfpd of CFP lean gas. This summary briefly lists the required injectors and rates necessary for startup and the initial blend ratio of CFP lean gas and NGLs at the two blend points that will make the EOR process viable. Also listed are the surveillance requirements necessary for monitoring the EOR process. Additional detail on these issues and others pertaining to startup and implementation of the KEOR project are documented in the body of this report. Startup Injectors MI will be injected initially into wells where EOR tax credits were taken in 1998 or in injectors supporting EOR tax credit producers. The table belo.w lists the wells that will startup the KEOR project. KEORSt rt I· t a up nJec ors Tax Credit Injectors Supported Producers MI volume* (MSCFPD) C-36i C-05a and L-12 1900 C-39i C-Ol 2800 F -84bi F-Ol and F-14 3000 F-85i F-79, F-06 750 F-92i F-38 1300 F-95i F-17, F-34 and F-78 1300 L-08i L-03 1800 L-09i L-02 1700 L-42i J-18 1200 Supportin2 Iniectors Tax Credit Producers F-83i F-80 3000 L-33i L-28 2800 F -82i L-40 3000 Extra In.iection if Needed Supported Producers E-23i** B-06 3000 L-16a L-07, L-ll, L-29 4000 Total 31,550 * Estimated MI rates, ** An E-pad injector will always need to be on MI to keep the C-5531a and C- 5531b compressors in operation After these injectors have reached the required slug size for the initial MI cycle length (as determined by the injection coordinator), the MI will be swapped to other injectors based on, pattern GOR and pattern throughput rate until returned MI at the producers is H:\Milne\A 0 G C C\KEOR Strategy41.doc 4 . . detected in the producers. Once MI shows up at the producers then the patterns will be ranked and MI will be distributed based on the amount of returned MI seen. The ranking of the patterns and distribution of MI is detailed in the Pattern Base Performance section of this document. After startup, the injection coordinator and pad engineers will implement the MI swap schedule. Blending The MI will be blended from lean gas and imported NGLs at the CFP and at C-pad. The MI will be blended to ensure that its composition is at the minimum miscibility pressure (MMP) with the Kuparuk oil at reservoir conditions at these two locations. For startup, the MMP at the CFP blend point is calculated to be 2935 psia which results in a blend ratio of 4.6 Mscf lean gas I stb NGL. For startup, the MMP at the C-pad blend point is calculated to be 2534 psia which results in a blend ratio of 3.9 Mscf lean gas I stb NGL. The blend ratio of the lean gas and NGLs will change after startup time and will be adjusted based on the composition of the lean gas, the composition of the NGLs and the reservoir pressure in these areas. Surveillance The KEOR project will be managed to maximize oil benefits. Therefore various process parameters will need to be monitored to predict the overall performance of the program. The parameters are reservoir pressure, injection profile, produced oil gravities and gas compositions from wells, MMP of the MI, CFP produced gas composition and well tests. To make timely measurements of these parameters, it is necessary to have a joint effort from town and field personnel to implement the surveillance program. The table below and reproduced in Table 7 lists the surveillance requirements, frequency and responsible parties for the measurements. Well performance will be monitored by the pad engineers and injection coordinator and they will be responsible for coordinating with the field to carry out the surveillance program. EOR Surveillance Summa Location CFP CFP or PBU C- ad and CFP Test Separator Produced Well Gas samples Test Separator Operator Bottomhole Pressures Well Injection Profiles Well Well Tests Test Se arator o erator H:\Milne\A 0 G C C\KEOR Strategy4 I .doc 5 . . Introduction This document outlines the startup and operational guidelines for the MPU Kuparuk Enhanced Oil Recovery project (KEOR). The intent of this document is to provide general guidelines and information to assist in optimizing the Kuparuk EOR project performance. As the KEOR project matures these guidelines should be modified to conform to field performance. Project Scope Presently, Milne Point produced gas is stored in the Kuparuk reservoir through a water- alternating- immiscible gas process (IW AG). The IW AG process is relatively inefficient at sweeping oil to producing wells and contributes to immiscible gas breaking through to the producers relatively quick, resulting in gas-processing bottlenecks that limit oil production. The water-alternating-miscible gas process (MW AG) is superior to IW AG because it mobilizes oil to the producers better and because miscible gas tends to dissolve in oil thereby reducing gas breakthrough. These mechanisms combine to increase ultimate recovery by approximately 9%. The MPU KEOR project requires installation of a new 8" pipeline from a tie-in point on the Oliktok pipeline currently providing natural gas liquids (NGL's) to the Kuparuk River Unit (KRU) from Prudhoe Bay (GPB). The new 8''NGL import pipeline will be a regulated common carrier owned by the Milne Point Pipe Line Company (BP Transportation (Alaska) 100% equity interest) and operated by Milne Point personnel. Additional facilities infrastructure is required at the Central Facilities Pad (CFP) to pump the NGL's to injection pressure and to mix the NGL's with high pressure "lean gas". The resulting miscible injectant will be distributed through a combination of new and existing pipelines to the target wells. A custody transfer meter at Central Facility Pad (CFP) will measure approximately 4 - 5 mbpd of NGL's required for the project. Pumps located at CFP will pressurize the NGL's from approximately 100 to 4750 psig. The pressurized NGL's will be blended with 20 MMscfpd of lean gas to manufacture approximately 25 MMscfpd of miscible solvent and injected into the reservoir utilizing the existing IW AG facilities (see Figure 1 ). Overview of Milne Point Kuparuk EOR Strategy The Milne Point Kuparuk EOR project (Milne KEOR) is planned to increase production over the base oil production by approximately 9 Mbopd through the injection of an enriched lean gas solvent (MI) into the reservoir utilizing a water-alternating-gas (WAG) injection scheme. Currently, Milne Kuparuk is operating under an IW AG scheme where lean separator gas is injected and alternated with water injection. Figure 1 shows a simplified process flow diagram of the KEOR project. H:\Milne\A 0 G C C\KEOR Strategy41.doc 6 ·' . The Milne Point Kuparuk reservoir is currently developed with 8 pads; 4 waterflood pads (B, H, J and K-pads) and 4 IW AG pads (C, E, F and L-pads). The plan for EOR is to switch the IW AG pads from lean gas injection to miscible gas injection (MW AG) by October 31, 2001. 25 MMscfpd of MI will be manufactured at the field by importing approximately 4 - 5 mbpd of NGL's from Prudhoe Bay to blend with approximately 20 MMscfpd from the Milne Point field. This gas will be miscible with the Milne Kuparuk oil and will be distributed to C, E, F and L-pads by injecting in a WAG scheme at a nominal WAG ratio of 1: 1 (i.e., 1 reservoir barrel of water per 1 reservoir barrel of MI or approximately 1 barrel of water per 1.2 Mscf of MI), adjusting as necessary to maintain GOR's at a manageable level. Pattern Development Schedule The Milne Point Kuparuk reservoir was not develòped on a regular pattern basis due to its complex faulted nature. The reservoir is broken up into a number of fault blocks referred to as "hydraulic units (HU)". Each HU contains up to 12 wells with well spacing of approximately 160 acres / well. The hydraulic unit concept was developed based on an understanding ofthe Kuparuk sands by the following characteristics: 1. Oil-Down- To (ODT) and Water-Up- To (WUT) depths 2. Individual fault blocks 3. Pressures in the fault blocks 4. Producer and Injector response - there are few instances where there is observed support across faults. There are 77 Hydraulic Units based on oil-water-contacts (OWC's), however 46 Hydraulic Units are targeted for EOR. Figure 2 is a map of the Milne Point Kuparuk sands with the hydraulic units outlined. Existing in each hydraulic unit are "waterflood patterns" defined as the producer groups that receive pressure support and fluid responses from the nearby injector(s). The waterftood patterns were defined in 1998 and have been used to manage the IW AG scheme. Figure 3 is a map showing the waterftood patterns overlaying the hydraulic units. These patterns are the basis for the reservoir performance evaluations and calculations. They include the following: 1. Reservoir pressure 2. Recovery efficiency 3. V oidage and voidage replacement 4. Material balance 5. Aquifer interaction 6. IW AG H:\Milne\A 0 G C C\KEOR Strategy41.doc 7 . . Pattern Management Pattern management will be key to optimizing the value of the KEOR project. Several key performance indicators should be tracked on a pattern basis during the project. These indicators include understanding the base performance, reservoir pressure, injection pressure strategy, distribution of the MI in each individual layer, changes in oil and gas compositions resulting from the miscible process, voidage replacement and WAG strategy. This information is acquired through well-planned and careful surveillance and routine well testing. Pattern Base Performance The IW AG patterns consisting of the 41 patterns on E, C, F and L-pads were analyzed in an attempt to understand MW AG performance and to rank the patterns for initial MI distribution at startup. The patterns were analyzed for GOR performance, cumulative lean gas volume injected as a %HCPV for the pattern, pattern throughput rate, %HCPV /yr and patterns with EOR tax credit. In an attempt to understand the MW AG performance prior to implementation tools such as the Milne Kuparuk Full Field Frontsim model will be used for WAG pattern management along with VIP pattern models of the Milne Kuparuk sands that will help evaluate future EOR performance. Since these patterns have been used to manage the IW AG process they will continue to be used as a basis to manage the MW AG flood. Since the IW AG flood is a gas storage scheme whereby produced gas is injected into the Kuparuk sand, it was not necessary to optimize for oil recovery benefits where the lean gas was injected. However injection into the MW AG wells will be optimized to get the greatest incremental oil recovery from the project. Therefore the patterns will be ranked based on the following criteria: 1. Ensure the capture of the 1998 tax credits 2. Initially inject into the IW AG patterns with lowest producing gas-oil ratio (GOR) 3. Operability of electric submersible pumps (ESP) in the patterns 4. Pattern throughput rate The pattern volumes used in 1998 KEOR work were used in this work to evaluate the HCPV throughput rates. I To rank the KEOR patterns it was necessary to analyze the performance of the existing IW AG patterns for wells with 1998 EOR capital tax credit, average producing GOR of the pattern producing wells, average HCPV throughput per year and the lean gas slug size injected into the pattern. This ranking was used as a guide for starting up the patterns to understand initial MW AG performance. Table 1 presents IW AG patterns that will be switched to MW AG. These patterns are sorted based on patterns with 1998 EOR tax credit wells, low GOR patterps and high throughput patterns. 1 "Milne Point unit Kuparuk EOR Startup and Operational Guidelines-Draft", January 4, 1999, Curt Bidinger H:\Milne\A 0 G C C\KEOR Strategy41.doc 8 . . The performance of the patterns where gas has been injected (36 patterns) were analyzed by plotting the volume of gas injected compared to average producing GOR in the pattern (see Figure 4). This method was used as an attempt to categorize the IW AG maturity of the pattern. It is believed that patterns with high producing GOR's have high volumes of gas that have been injected into the pattern and that gas is cycling through the pattern and there are low volumes of oil remaining to be recovered from a gas injection process. Although these patterns would still receive MI, high WAG ratios would be used for these patterns(~ 4:1). Figure 4 was constructed as an aid to predicting how the patterns would perform when they are converted to MW AG. In most cases it is observed that, GOR generally increases linearly with increasing gas slug size. There were a few cases where high GOR's are produced with small volumes of gas injected into the pattern. This performance suggests gas is channeling through high perm streaks that may exist in patterns such as E-16i (supports B-06 and B-09). ,. At a 14% HCPV slug of lean gas injected the offset producers are producing on the average at 3200 scf/stb. Or in some case where the points lie below the trend may suggest that more gas is being trapped in the pattern. Therefore based on this trend, gas slug size in the pattern does not have to be used to rank the patterns but rather GO R. Some other things to note in this table are the addition of patterns F-82i and F-83i have while there are 5 wells missing; L-I0, C-11, E-02, E-03 and F-17 from the 1998 KEOR pattern list. Well F-82i supports L-40 and F-83i supports F-80 both tax credit producers. Since 1998, well F-17 has been converted to a producer, well E-03 will not be used for MI injection because this well is dedicated for the emergency plant fuel gas supply; wells E-02 and C-ll have been shut-in and there are no plans for putting MI to well L-I0 because this well does not have tubing joints rated for gas service and it supports well L- 01 which has watered out. Also, field data suggests that well F-42i may not be supporting well F-54. Therefore this well will be used for a lean gas disposal well during upset conditions - see section on Management of MW AG during Upset Conditions. The throughput rates in this table were calculated based on a one-year sum of the gas and water volumes injected into the pattern divided by the HCPV of the pattern (January 2000 - January 2001 and in some cases May 2000 - May 2001). The average KEOR pattern throughput rate is approximately 9.37% HCPV/yr. The pattern GOR's were calculated based on the average GOR's of the producers supported by the above injectors. By averaging the pattern GOR it appears to equal the average for the produced gas swings experienced in the producers during IW AG cycles. Based on the above analysis the GOR is a good indication of the IW AG flood maturity in a pattern and GOR was used as an MI ranking criteria for deciding which patterns receive MI injection first. Figure 5 illustrates how the GOR ranking of the patterns shows where the MI should initially be distributed. Approximately 70% of the EOR reserves are located in the patterns with low GOR «400 scf/stb). These are patterns on F and L-pads where the IW AG process is immature because current WAG ratios are high and the pressure is H:\Milne\A 0 G C C\KEOR Strategy41.doc 9 . . high. Figure 5 shows three regions to the GOR plot that can be used to classify the patterns based on IW AG performance. These characteristics are low maturity, medium maturity and high maturity. Table 2 shows the breakdown of the patterns by GOR and associated reserves. The KEOR project is planned for the injection of a 30% HCPV MI slug. However, with the possibility that the S-pad Schrader Bluff EOR project will be implemented within the next 4 - 5 years there will potentially exist competition for the lean gas within the Milne Point facility to produce MI for both projects. If the S-pad EOR project is implemented, only a 20% HCPV MI slug will be injected in the KEOR project. Using the smaller slug results in a 7% OOIP incremental recovery to waterflood compared to the 9% OOIP incremental recovery in the KEOR project. As the KEOR patterns mature, the patterns will be re-classified based on the ratio of returned MI produced (RMI) to MI injected (RMI Ratio). The four classifications are as follows: 1. Very Favorable: patterns liberate the greatest EOR oil per volume of MI injected as defined by a RMI ratio less than of equal to 20%. 2. Normal: patterns have intermediate EOR oil recovery efficiency as defined by patterns that have RMI ratio's greater than 20% but less than or equal to 50%. 3. Less favorable: patterns that have the lowest EOR oil recovery efficiency as defined by patterns with RMI ratios greater than 50% but less than or equal to 70%. 4. Suspended: patterns that have very low EOR oil recovery efficiency so that no further MI solvent is allocated to these patterns. The patterns have RMI ratios greater than 70%. This criteria is based on the experience from the KRU-LSEOR (Large Scale EOR). As the KEOR project matures these definitions will be changed to reflect field performance and project EOR efficiencies. The project EOR efficiency depends on the oil-in-place, injection rates, projected incremental EOR recovery, returned MI predictions and WAG ratios. Reservoir Pressure Strategy Reservoir pressure is an important factor in EOR implementation. The MPU Kuparuk reservoir has been undergoing an injection process for some time and in general the reservoir pressure has increased over time. There is a was concern about low-pressure hydraulic units where reservoir pressure may be below the oil bubble point pressure of 2100 psia and the MI will not be miscible with the oil. However, as can be seen in Figure 5, on average the patterns are well above the bubble point. Another concern is about high-pressure patterns (> 4000 psia, the F-pad area). High pressures will make the MI less efficient for two reasons. First, high pressures will tend to cause flux toward normally pressured regions. As with waterfloods, significant flux creates inefficient streamlines between injector and producer, resulting in delayed EOR production and in some cases EOR reserves migrating to areas where it may not be recovered. H:\Milne\A 0 G C C\KEOR Strategy41.doc 10 . . The second negative impact is related to the formation volume factor (FVF) of the miscible injectant in terms of reservoir volume per Mscf. As pressure increases, the MI is compressed. A given amount of compressed MI will occupy less volume in the reservoir, slowing down the migration of MI through the reservoir thus delaying or "smearing out" the EOR benefits. The effectiveness of the miscible WAG process from the standpoint of minimum miscibility pressure and the effective blend of lean gas to NGLs is dependent on the reservoir pressure of the hydraulic units. Therefore it is important to maintain the reservoir pressure of the effected hydraulic units at or above the minimum miscibility pressure (MMP) of the MI with the reservoir oil and the upper range of the oil bubble point of 21 00 psia. Figure 5 shows the reservoir pressures of the wells in the affected wells of the Kuparuk sands across the EOR areas. The arrows in the figure are the minimum pressures of the E-pad and C, F and L-pad areas. The average pressure in these areas are important for two reasons: (1) MI will be. blended at C-pad for the C, F and L- pads, and at the CFP for E-pad and (2) minimum reservoir pressure in these areas will set the MMP of the MI at these blend points. Therefore based on this figure, the MI will need to be blended to an MMP of 2734 psig at the C-pad blend point and 3185 psig at the E-pad blend point. Voidage Replacement Each pattern should maintain a voidage replacement ratio (VRR) of 1.0 and not to exceed the original reservoir pressure of 3500 - 4000 psia. MI Distribution in the Reservoir Knowledge of which Kuparuk sands are being flooded and the volumes of MI injected into each sand is important to evaluate the efficiency of the project. This is especially important as individual sands are flooded out and injection well work is being considered. The objective is to inject a total of 20 - 30% HCPV of MI into all EOR patterns to recover an additional 7 - 9% of original oil in place (OOIP). The guiding principles for MI distribution at startup are the following: 1. EOR Tax credit preservation 2. The average pattern GOR for the past year 3. The total pattern lean gas slug size injected, %HCPV 4. Total pattern injection throughput At startup, the first patterns to receive MI will be those with either the producer or the injector drilled in 1998 for which EOR tax credits had been taken and injection must occur within three years of taking the credit. According to the IRS rules, a "non- insignificant" amount of MI must be injected into those patterns within three years of well completion. Once MI has been allocated and injected to protect wells with tax credits, the remaining MI will be distributed to patterns based on the lowest average producing GOR and the highest injection throughput for the past year. As mentioned previously, the lower GOR is a reflection of the low IW AG flood maturity that suggests large reserves are remaining to be produced in these patterns compared to the higher H:\Milne\A 0 G C C\KEOR Strategy41.doc 11 . . GOR patterns where gas appears to be cycling through the pattern. High GOR patterns are on C and E-pads. To identify the remaining injectors needed for startup the patterns with the lowest GOR were sorted from low to high and with a secondary sort of those with the highest throughput were identified. Placing MI in the highest throughput patterns will insure that an early EOR response can be observed Table 3 is a summary of the 9 injectors and that took the 1998 EOR capital tax credit along with the producers supported and the injection rates. These will be the first wells to receive MI at startup. Table 4 is the list of the producers that took the 1998 EOR tax credit and the injectors that support them. These injectors will have to take MI at startup as well as those in Table 3. The rates for the injectors are estimated based on the average lean gas rates from the previous two months of recorded gas injection. The rates for F-84bi, F-83i and F-82i are not certain because no gas injection has occurred in these wells to date. The total injection startup rate for these wells is approximately 25,000 Mscfpd. After MI is distributed, these wells may not accept the entire 25,000 Mscfpd of MI produced. Therefore it will be necessary to distribute the remaining MI elsewhere in the Kuparuk Reservoir. This volume will need to be distributed to the IW AG patterns based on the above criteria and at least one E-pad injector. An E-pad injector will always have to be on MI injection to prevent the C-5531a and C-5531 b compressors from being idled. For safety's sake it will probably be necessary to have two additional injectors ready to be put on MI injection to handle the additional volume of MI, if necessary. Figure 8 shows the distribution of GOR of the 37 IW AG patterns analyzed. As can be seen in Figure 8, the lowest GOR patterns are those on F and L-pads having seen little gas injection. Figure 9 shows the distribution of throughput rates in the IW AG patterns. Ranking the patterns based on lowest GOR, lean gas slug and highest throughput using the data from these two figures results in three injectors that will need to be used for injecting the remaining MI at startup. The injectors and their estimated injection rates are shown in Table 5. After the KEOR startup and MI breakthrough, patterns will be ranked based on injection efficiency as measured by the amount of returned miscible injectant (RMI) to producing wells. MI will be preferentially injected into patterns with the highest injection efficiency. Priorities for MI distribution will be determined based on the following factors listed in the order of importance: 1. ESP protection, and 2. EOR efficiency Fluid Compositions As the KEOR project matures, changes in the produced oil and gas compositions will be an indicator of when the EOR front is arriving at the production well and the flood efficiency. Typically a volume of lean gas is produced prior to the incremental EOR oil bank reaching the production well. As EOR oil is produced the oil API gravity should increase because of a higher concentration of intermediate components. The fluid composition data collected along with other indicators will be used to classify each H:\Milne\A 0 G C C\KEOR Strategy41.doc 12 . . WAG Strategy It is an optimization problem with WAG ratios for the pattern. The adverse mobility ratio between the miscible solvent and the MPU Kuparuk reservoir oil reduces the horizontal sweep efficiency at lower WAG ratios. Larger WAG ratios improve the horizontal sweep efficiency because water displacement is more efficient in sweeping mobilized EOR oil towards the producers, thus improving recovery. Initially, miscible injectant should be alternated with water at a nominal 1: I WAG ratio (1 reservoir bbl of water injected for every reservoir bbl of gas injected) delivering 1 to 2% HCPV miscible injectant slug per cycle. In ESP patterns the WAG ratios will nominally be 2: 1. Actual WAG ratios and cycles will be adjusted on a pattern-by-pattern basis as actual field performance data becomes available. MI Blending and Quality Control· The purpose of the EOR project is to blend 20 MMscfpd of lean hydrocarbon gas with 4 - 5 mbpd of imported Prudhoe Bay NGL's to make approximately 25 MMscfpd MI to inject into the Kuparuk formation at C, E, F and L-pads. The MI blending for the various pads will be downstream of the four gas injection compressors from the following locations: 1. The produced field gas off the IW AG I compressor (C-2605) and IW AG II compressor (C-2901) discharge on C-pad to make MI for C, F, and L pads. 2. The produced field gas off the compressors C5531A and C5531B at the CFP to make MI for E-Pad. The total injection capacity of the IW AG I and II compressors is 14 MMSCFD each providing high pressure gas (4800 psi) to C, F, and L pads. The total injection capacity of the two compressors at the CFP is 8 MMSCFD that provides gas to E-pad at 4200 psi. Blend Gas Source and Facility Capacity Based on the latest gas production and injection forecast, lean gas available for injection is between 20 to 28 MMSCFPD for the next 15 years and the total gas flowing into the plant will be between 40 to 50 MMSCFPD. Figure 10 shows the gas balance forecast in the CFP over the next 20 years. Current gas handling capacity at the CFP is about 40 MMSCFD. Installation of a fuel gas compressor in the CFP would increase gas handling capacity by 10 MMscfpd to 50 MMscfpd. However, economic justification of the fuel gas compressor is presently viewed as unlikely. Earliest startup would be 4Q2002. Several years after start of MI injection, significant amounts of some components of the injectant will be produced out of production wells. These components will increase the molecular weight of the gas off the separators in the CFP. Engineering studies indicate that the existing gas compressors will be minimally impacted by the increased molecular weight and that no change in hardware should be necessary. H:\Milne\A 0 G C C\KEOR Strategy41.doc 13 . . The forecasted composition of field gas and NGL for blending is listed in Table 6. Blending ratios at these two locations will be controlled automatically (using PLC control) and ratios will require flow measurement of the lean gas and NGL's at each of the two blending locations. Sample taps will be provided at all locations where required and will be designed to minimize or eliminate the exposure ofNGL's to the atmosphere during testing. The blending ratio will be based on one or both of the following methods: 1. Compositional samples taken of the lean gas and the NGL's on a weekly basis, then plugging the corresponding calibration values into the PLC via an MI station. 2. Compositional samples taken of the MI fluid on a weekly basis then plugging the corresponding calibration value into the PLC via an MI station. The composition of the MI fluid will be maintained at an MMP approximately 300 psi above the Kuparuk oil bubble point of 2100 psia. The blending of the NGL's with the lean gas (combined fluids) must be maintained at an MMP corresponding to the minimum reservoir pressure in the E, C, F and L-pad areas. The future lean gas volume for the Kuparuk EOR project may decrease by 10 MMscfpd to accommodate the startup of the Schrader Bluff S-pad EOR project2. A new source of blend gas may come from MPU's Sag River reservoir gas or an enriched CO2 gas imported from the Prudhoe Bay unit. The import of an enriched C02 rich gas is in the early planning stages but tentatively will begin in the 2005 - 2007 time frame to coincide with the startup of the twister/mixer or the Major Gas Sales (MGS) project. Once an enriched CO2 gas stream is used for blending, the overall effect on the MI will be a reduction of 7 - 12% by volume in the amount of NGL's needed for the MI blend to achieve an MMP of 2900 - 3200 psia, thus reducing the NGL import requirements for the Milne Point KEOR project. However at this time, it is planned that Schrader Bluff S-pad and Milne KEOR will be competing for the same lean gas. Recommended EOR Surveillance Various process parameters will be monitored to better predict the overall effectiveness of the KEOR program. These parameters are reservoir pressure, injection profiles, produced oil gravities and gas compositions from wells, MMP of miscible solvent, CFP produced gas composition and well tests. Table 7 summarizes the EOR surveillance requirements. CFP Gas Composition Monitoring The CFP lean gas will be monitored for composition and rate measurements to help assure MI quality control. The lean gas composition and rate will be monitored once every week at the CFP. 2 Communication with Curt Bidinger H:\Milne\A 0 G C C\KEOR Strategy41.doc 14 . . NGL Composition The NGL's imported to Milne Point will be monitored for composItIOn and rate measurements to help assure MI quality control. The NGL composition and rate will be monitored once every week. If Prudhoe Bay operations measures the NGL Composition, this information is suitable. Miscible Solvent Composition and MMP Determination The MI composition and rate will be measured at both blending points to verify the blending ratio and to help insure that the solvent is miscible with Kuparuk oil at reservoir conditions. The MI composition will be estimated from the blended lean gas and NGL compositions and rates. The MI composition and rate will be measured once a week and from that measurement the MMP will be calculated and compared to the MMP calculated from the calculated MI composition. The MMP wIll be calculated from the following correlation: MMP = a [(b + Ly¡Tcic)] MW C7+ Nomenclature: a = -0.0017054 b = -26618.5 c = 1.6 y¡ - mole fraction of component i in the MI T ci - critical temperature (OR) of component i MW C7+ = molecular weight of the C7+ fraction of the Kuparuk oil. Used here as 285 lbmllbmole The summation in the parentheses of this equation is over all of the single carbon number components in the MI and iC4, nC4, iCs and iCs are treated separately. Note that Tc for . CO2 is taken to be 435°R rather than 548°R based on the fact that C02 is known to be much more effective in developing miscibility than indicated by T c of 548°R. The MI needs to be blended to the minimum reservoir pressure in the area at the two blending points to ensure that the solvent composition will be miscible with the reservoir oil in these two areas of the field. As seen in Figure 5, the lowest pressure observed in the E-pad area is 2784 psia and for the C, F and L-pad areas is 3185 psia. Note that the upper range of the Kuparuk oil bubble point is approximately 2100 psia. This means that the MMP of the MI should be maintained well above the oil bubble point to insure miscibility. Furthermore, the range of uncertainty in the MMP correlation is approximately 640 psi3 (-250 psi to 390 psi) which suggests that the MMP spec at both blending points should be above the bubble point pressure and 250 psi below the minimum reservoir pressure to insure the calculated composition for miscibility is rich 3 "A Revised MMP Correlation for Kuparuk EOR" by G.K. Youngren, 1994. H:\Milne\A 0 G C C\KEOR Strategy41.doc 15 . . enough. Figure 11 shows a plot of the MMP correlation as compared to the blend ratio. Therefore at startup, the CFP (E-pad) and C-pad the blend ratio will be 4.574 Mscf/stb and 3.937 Mscf/stb for an MMP of2935 and 2534 psig, respectively. Produced Gas Composition Detection of MI thief zones, development of a pattern ranking, and confirmation of the reservoir response to the MI flooding will be accomplished by sampling produced gas composition. After the producing GOR at a supported KEOR well is seen to be increasing, the produced gas will be sampled at the test separator and the composition will be measured twice per well per MI cycle. RMI Monitoring Plan Monitoring the production of RMI during a miscible gas flood allows for tracking the movement of MI in the reservoir and estimating thé reserve benefits for injecting MI into that pattern. When MI breakthrough occurs, it is recommended that producers be logged to determine from what zone the RMI is being produced. Ifthe'producer is a multi-zoned producer, then high gas zones may be closed off, allowing for continued production of EOR oil from other zones. Another use for the tracking RMI rates is to optimize the distribution of MI effectively to less mature patterns, A returned MI ratio (RMIR) can be calculated for each injector as shown below: RMIR = RMI Rate (all associated producers) I MI injection Rate A high RMIR indicates that the pattern is mature and the injector is no longer using MI effectively as it could in a less mature pattern. A decision can be made to increase the WAG ratio in the well or to move the MI to a new more efficient injector. The basis for monitoring RMI is collecting data from well tests and gas sampling. All EOR pattern producer wells including off pattern wells should be tested and sampled at least monthly. Gas sampling requires collecting a sample of produced gas from the test separator and sending the sample to the Prudhoe Bay field lab to be evaluated for compositional analysis by gas chromatograph, The analysis of the gas sample should be broken down into the components, CO2, C¡, C2, C4, Cs and C6+. Based on the gas sample data and the well test data are recorded in the FINDER database. From gas sample and well test data, an RMI rate may be determined for each well by utilizing the Milne Point excel based RMI spreadsheet (yet to be built, 2001). Prior to the startup of MI injection, a series of gas samples need to be taken on Milne Kuparuk wells from the planned EOR pads; E, C, L and F as well as a sample of lean gas from the CFP. These samples are required to establish a baseline produced gas composition along with a baseline lean gas composition for calculating blending ratios with Prudhoe NGL volumes. RMI rates will be calculated using the methodology presented by Gary Youngren, 19964. This methodology uses a dimensionless RMI concentration to find what percentage of the 4 Youngren, Gary K.,"Estimating the Rate of Retumed Miscible Injectant at Prudhoe Bay", 1996 H:\Milne\A 0 G C C\KEOR Strategy41.doc 16 . . well's produced gas is RMI. The dimensionless RMI concentration is calculated using the MI composition, the solution gas composition and the produced gas composition. While the MI composition and produced gas composition are easily measured, the solution gas composition must be determined using a PVT program. By flashing the original oil composition used for the Milne Kuparuk Field at the separator temperature and pressure the solution gas composition is easily obtained. In addition, those producers with gas lift must have the lift gas composition back out of the produced gas. The lift gas composition is also easily measured. Once RMI rates are calculated, they are to be inserted into the FINDER database. RMI Sampling Guidelines Gas samples should be taken while the well is being tested on all EOR producers at least once a year. Once samples are collected, they should be sent to the Prudhoe Bay field lab for analysis. Proper sampling techniques are essential to obtaining a valid saJp.ple analysis in the lab. Gas samples should be analyzed using a GC to obtain the following breakdown of components; CO2, C 1, C2, C4, Cs and C6+. If any concerns arise about the quality of a well test, gas sample or gas sample analysis of the data obtained from any of these three procedures, then testing sampling and analysis should be repeated as soon as possible. Data from well tests required for calculating RMI rate should include produced gas rate, gas lift rate (where appropriate), separator temperature and pressure. This data should be recorded in the PDB. Data from gas sample analyses needed for computing RMI rates should include the gas component name and mole percent in the produced gas. Each sample should be given a unique number based on the date of the test and the well number, in the format: yyyymmddwwwww, where wwwww is the well name. For example, a sample taken from well MPFO 1 on June 10, 2002 would be numbered 20020610MPFOl. Gas sample data should be e-mailed to town for loading into the Finder. Produced Oil Samples After the producing GOR for a supported KEOR well is seen to be increasing, two oil samples will be taken at the test separator per well per MI cycle. From these samples the measurement of produced oil API gravity and compositional analysis of the oil (30 hydrocarbon components) will aid in confirming the EOR response and returned NGLs. Bottomhole Pressures Measurement of bottomhole pressure will be used to monitor the miscibility pressure and aid in ranking pattern efficiency. Two pressure surveys are required per hydraulic unit per year. H:\Milne\A 0 G C C\KEOR Strategy41.doc 17 . . Injection Profiles To predict EOR performance it is critical to understand which intervals are receiving the injected fluids as a basis for setting MI flooding strategy, determining remaining reserves in the pattern and injected fluid allocation to each zone. Baseline spinner surveys for each phase will be performed in each injector within nine months of the onset of injection, as required by the state. Afterward performing the initial survey, one survey will be performed every two years or after injection profile modifications have been made Well Testing Accurate well testing of Kuparuk wells will provide information needed for well performance evaluation, confirmation of EOR response along with well interactions and production allocation. As patterns mature accurate and consistent water cut measurements are critical in monitoring EOR performance. Each Kuparuk production wells in the affected areas should be tested twice per month. Reporting Requirements The AOGCC requires that the MW AG performance be included in the annual waterflood Surveillance Report submitted by the end of March each year. Responsibilities The injection coordinator a town based RE and pad engineers will be responsible for establishing the WAG cycles and monitoring EOR performance. They will recommend and interpret EOR surveillance. The field lead technicians and pad operators will be responsible for injection well swaps and the sampling operations. The C-pad and CFP lead tech are responsible for MI blending operations at these pads. WAG Conversions, Ratios and Scheduling The injection coordinator will establish the WAG conversions and scheduling. The objective is to maintain a WAG ratio of 1: 1 and voidage balance while minimizing the number of WAG conversions during the year. Injection of a miscible solvent can be used as a tracer to help understand hydraulic unit performance. Therefore, the scheduling of WAG conversions should consider how to maximize the amount of information collected during each WAG cycle. WAG ratio is defined as the ratio of the volume of injected water to the volume of injected gas at the reservoir conditions during one WAG cycle. The ideal WAG ratio equals 1: 1 for EOR process from an ultimate oil recovery perspective. However, it may be difficult to implement in the Milne Point field because the producing GOR can be too high for ESP's to handle in the producers. ESP motors will fail from overheating when there is not enough liquid passing through them to cool them down. Experience has H:\Milne\A 0 G C C\KEOR Strategy41.doc 18 . . shown that when the total gas to liquid ratio is higher than 1000 SCF/BBL, ESP's will not operate smoothly and are more likely to fail. The strategy is to use smaller gas slugs and a larger WAG ratio within the ESP patterns to control the GLR in the producers. 1. WAG ratio in gas lifted patterns will be 1: 1. See Table 8. 2. WAG ratios will start at 2: 1 in ESP patterns to avoid ESP failures due to high gas rates. 3. MI slug sizes will vary from 0.5% to 1.6% HCPV (3-10 weeks on gas injection) based on gas-to-liquid ratio (GLR) performance in the producers 4. WAG ratios and slug sizes will be adjusted to control GLR of less than 1000 in ESP producers. Management of MWAG During Upset Conditions The MI flood pattern process conditions will be maintained as designated. Excursions above the MMP will be allowed for short durations (less than 2-3 days) and at frequencies of no less than every 30 days. Additionally, lean gas injection into MW AG wells will be allowed only for short durations (less than 2-3 days) and at frequencies of no less than every 30 days. Otherwise, lean gas can be redirected to historically high volume injection wells and wells that do not visibly support producers. These wells are C-25, C-08, E-03 and F-42. This will ensure maximum benefit from the MI injectant. KEOR Safety Guidelines Disclaimer: These safety guidelines express general concerns around the KEOR project, particularly things that are different from pre-KEOR operations. These guidelines are not to be taken as operating procedures. Refer to the appropriate controlled document(s) for safe operating procedures. The KEOR Project will introduce NGL as a new separate material at Milne Point. NGL is a volatile, flammable, potentially explosive, potentially suffocating material. It is a liquid at normal operating pressures and temperatures. At atmospheric conditions, the lighter components of NGL, e.g., propane, will vaporize and the heavier components, e.g., pentane, will remain liquid. Some of the vaporized lighter components are heavier than air and therefore will accumulate in low spots. Components that are liquids at cold temperatures can be vaporized by a temperature rise, such as by contacting residual liquids with warm water. Because of these characteristics, special precautions are warranted around NGL. For example, special bleed trailers have been procured for operations in which NGL or NGL residue must be removed from facilities/piping. The KEOR Project involves high pressures. Although high pressures are not unique to the KEOR project, be aware that the NGL stream is pumped to approximately 5,000 psi, and miscible injectant also exists at that pressure range. H:\Milne\A 0 G C C\KEOR Strategy41.doc 19 . . Figure 1: KEOR Process Flow Diagram SIMPLE PROCESS FLOW DIAGRAM KUPARUK ENHANCED OIL RECOVERY (KEOR) PROJECT MILNE POINT UNIT /----------------------------------------------------------, CENTRAL FACILITIES PAD IGAS INJI ~ III 1 C-5531, : : ' --------------------------~ ----------------~-------~ I (' MOD 48 NGL RECYCLE i \1 : COOLER X-4801 XV ! XV:: ¡ I I : I I : I I : , ~~ -----, ! ¡ I I II : : I I I 1 I I I I , I I I 1 I I 1 I I I I 1 1 I , I '-- --------------------------------------------------~ I I , / ---- ----------------------------------------------------- JULY 2001 CORIOLlS FLOW METERS ( -0LTRASOÑïc'" : FLOW METER: 1 I I I 1 XV I ~. MOD 68 PAD) - ----------- TO KRU -------------- , \ I I I f r I MOD 26 I I I I I I I I I I \ \, 111 ! .~m_ I I I I I ,---------- XV ------------------------ / --------------------------~) ~---------- * NGL INJECTION PUMP P-4801 OLlKTOK PIPELINE H:\Milne\A 0 G C C\KEOR Strategy41.doc TO F & L PAD INJECTION WELLS TO C PAD INJECTION WELLS TO E PAD INJECTION WELLS FROM PBU 20 . . Figure 2: Milne Point Hydraulic Units with Wells H:\Milne\A 0 G C C\KEOR Strategy41.doc 21 . . Figure 3: Milne Point Kuparuk Waterflood Patterns Wateñlood Polygons - March 2001 \NeD Status - Abandoned (I Disposal Well CI Disposal Well Shut~n · Rowing oa Well D Gas Injector f< Gas Injector Shut~n .. Gas Ufted Oil Well « Gas Producer D Miscible Injector f< Miscible Injector Shut~n · Oil Producer · Shut In Oü Well D Water Injector D Water Injector Shut-in ~ Water Producer "- .~G-4, ....I$DJIMoI' .....,J.... ! R I D ....J ~~ I-·------."~~..""-_·"~_·~~ JC:~ ø ...u I - .......,... D 11_,"" ... ~oI~ 11-,. Ie." ' ....... H:\Milne\A 0 G C C\KEOR Strategy41.doc 22 . . Figure 4: IW AG Pattern Cumulative Gas Slug Size vs Average pattern GOR 4500 4000 3500 3000 .tI ..... 1/1 2500 ;;: u 1/1 ~ 2000 0 C) 1500 1000 500 IWAG Pattern Gas Slug Size vs GOR ~'---"-"-'-~--~._'-'---- + I ~--- ---------------------------1 ~____________ ~_ Trend J I -----1 I I i + --"._-~.---_.".. ---+--- + + + --~~---- + + --+--- + + + o 0.00% 10.00% 30.00% 40.00% 50.00% 60.00% 20.00% 70.00% Cumulative Gas Slug Size, %HCPV H:\Milne\A 0 G C C\KEOR Strategy41.doc 23 . . Figure 5: KEOR Cumulative Pattern OOIP Versus GOR and Incremental EOR Benefit ~ 3000 ;;:: u II) ~ o 2500 C) c: .... G) =: ~ 2000 G) 01 ~ G) ~ 1500 Pattern GOR vs MWAG Pattern OOIP and Pattern IWAG Maturity 4500 4000 -+- Average GOR 3500 ___Inc. EOR Oil, MMstb, 9% Inc. RF -'-Inc. EOR Oil, MMstb, 7% Inc. RF 1000 500 o o 50 100 150 Cumulative MWAG Pattern OOIP, MMstb H:\Milne\A 0 G C C\KEOR Strategy41.doc High Low 200 350 400 250 300 40 35 30 25 .c ;¡ :; :; ð a: 20 ß .. ë " E I! 15 ~ 10 5 o 450 24 . . Figure 6: Reservoir Pressures of Kuparuk sands across EOR pattern Areas E, C, F and l-Pad pressure Distribution 5000 500 C, F and l-pad Minimum Press ure = 2784 psig E-pad Minimum Pressure = 3185 ~ -_._._---~.- -------_._--~_. ~ \ --"------ ---~- ~ -- -.-- ~--- -----~--- --- - -- -- "'" ~_. sig 4500 4000 3500 .21 3000 II) Co I!! 2500 ::s II) II) Q) Q.. 2000 1500 1000 o ¡¡; ~ ¡;; ¡¡; ~ t: ¡¡; õ Õ Ñ ;;; Õ .. iñ Ñ ¡¡; « ~ . Ñ -g c .. c .., .., ... ... ... .. ... .. c ~ .., ... w w w ù ù ù ù u. u. u. u. u. u. .. U. ..J ..J ..J ..J Q. U. ..J W Wells Figure 7: Pressure Impact on FVF ofMI Pressure vs 89 of MI 0.9 0.85 ... - CJ U) :æ 0.8 - .c ... C) m 0.75 1--.- 0.7 2000 . I 2500 3000 3500 4000 4500 5000 Pressure, psia , -~---- H:\Milne\A 0 G C C\KEOR Strategy41.doc 25 . . Figure 8: GOR Distribution across the IW AG Patterns 4.50 4.00 --.------------ ~-~--------~------~-----_._.._._------_._.~-------_..-. -J 3.50 - ---~-- -_._---~------------_._-_.-- ------------ 3.00 .~~- --------~-_.,~._-~,-~----_.. ...---.-- .Q ~ 2.50 " VI :! ~ 2.00 C) .-..----- -----j 1.50 1.00 0.50 0.00 N i!i ~ 0 ~ ~ ~ :\ VI VI ~ ~ 0 VI ~ N 0 VI 0 J 1 '1 ~ N 0 ~ ~ N ~ VI ~ ~ N ~ ;1; N 0 0 N ~ ~ 0 N ~ ;j' VI ~ ~ 0 <0 ~ U U U U U U U ~ U U U w w w w W "- "- "- "- "- "- .;. "- "- ~ ~ ~ ~ ~ -" ~ 0 Pattern Figure 9: Total Throughput Across the IW AG Patterns 45.00% 40.00% 35.00% 30.00% ~ 25.00% > a- o ~ 20.00% o 15.00% 10.00% 5.00% 0.00% ~ 0 0 'i' ~ ~ 'i' 0 g ~ ~ m ~ 1)1 ~ ~ ~ ;¡; z: ~ ~ "!. ~ ~ ~ ~ ~ ~ ~ .... r;- z .... .... :::; .... r;- g & " g 0 g '" w t; '" ô '" ~ ;¡; ~ ;;; .. 0 .. .. '" .. w .. > Injector H:\Milne\A 0 G C C\KEOR Strategy41.doc 26 . . Figure 10: Milne Point Gas Forecast -- .-...------------ -.------ - ___u____n_____ -_._---~--_.__._.~ ----- -------_.__.._._--_.._..~-- ----- 60 Milne Point Field Field Gas Balance Forecast With Gas Lift System _ Remaining Capacity _Gas Lift ""'Available Inj. Gas _ Miscellaneous _ Heater Fuel __ Turbine Fuel -+--Solution Gas -<>-Total Gas Production 50 40 Q ... U ¿ ~ 30 ~ .. cc: '" .. í.:ì 20 10 o 199920002001200220032004200520062007200820092010 2011201220132014201520162017201820192020 -~-----~~ H:\Milne\A 0 G C C\KEOR Strategy41.doc 27 8.000 7.000 6.000 .. ..J C) Z ~ 5.000 a ..J 'ü 4.000 .. :=;; ò '.; ..: 3.000 '" c: .. ¡¡; 2.000 1.000 . . Figure 11: Blend Gas to NGL Ratio Blend Ratio vs MMP .. -- --..------ ----,.-------------.- .. -----------.- ~/-- -~--- / /~ / -.---- _/. _m_ ~ _// ~ . -.---.-.-.-.------ _..~~-- -- -- --.--- -.--- ....-- ... _......................---- .. -/--E-pad Blend = 4.574 Msct lean gas I stb NGL I ~ ~ ¡ . ---.----i ... +------, (~ ---------.---- C-pad Blend = 3.937 Mscf lean gas I stb NGL I ~~..._- -- ..---------- -----~-- .. '''--l I ------~---~ 1---- _u_ ..--.......----1 I --.....--.-. - . ----- 0.000 2100 3300 3500 3700 3900 4100 2700 2900 3100 MMP. psia 2300 2500 H:\Milne\A 0 G C C\KEOR Strategy41.doc 28 . . . Table 1: KEOR Pattern Ranking based on Patterns with 1998 Tax Credit wells, Average GOR and HCPV Throughput Patterns Inc. EOR With Cumulative Oil, 98'EOR Lean Gas Inc. EOR MMstb, Pattern Tax Slug Size, Average Cumulative Oil, MMstb, 7% Inc. Pattern Pattern OOIP HCPV/yr avg Credits %HCPV GOR OOIP, MMstb 9% Inc. RF RF F-95 15.179 8.60% y 0.607% 229.242 15.179 1.366 1.063 L-21 9.161 1.86% Y 2.921% 234.122 24.340 2.191 I. 704 F-85 6.500 9.07% Y 0.820% 235.147 30.840 2.776 2.159 F-92 11.000 3.89% Y 2.226% 239.575 41.840 3.766 2.929 L-42 1.363 8.84% Y 6.047% 247.909 43.203 3.888 3.024 F-82 17.4 9.68% Y 0 250 60.603 5.454 4.242 F-83 8.7 9.38% Y 0 250 69.303 6.237 4.851 L-33 21.123 6.99% Y 0.529% 273,070 90.426 8.138 6.330 L-09 12.588 3.79% Y 2.960% 312.731 103.014 9.271 7.211 C-36 4.031 11.22% Y 11.276% 349.484 107.045 9.634 7.493 L-08 14.486 3.13% Y 3.054% 479.489 121.531 10.938 8.507 C-39 1.500 3.52% y 5.680% 759.687 123.031 11.073 8.612 F-84b 14.200 9.17% 0.000% 213 .546 137.231 12.351 9.606 F-46 24.862 4.57% 0.000% 223.493 162.093 14.588 11.347 F-74 18.211 4.16% 0.000% 257.103 180.304 16.227 12.621 F-41 8.603 0.85% 4.373% 160.052 188.907 17.002 13.223 F-42* 8.546 10.99% 3.207% 209.646 197.453 17.771 13.822 F-I0 9.516 6.78% 0.183% 240.081 206.969 18.627 14.488 F-49 12.531 8.46% 0.525% 241.576 219.500 19.755 15.365 L-24 12.337 4.59% 4.394% 248.122 231.837 20.865 16.229 L-15 16.553 3.65% 0.800% 256.452 248.390 22.355 17.3 87 F-70 17.205 5.83% 3.692% 265.566 265.595 23.904 18.592 F-62 10.486 9.74% 3.350% 266.114 276.081 24.847 19.326 F-30 13.814 3.48% 1.822% 280.280 289.895 26.091 20.293 L-I6A 10.888 9.88% 0.056% 280.559 300.783 27.070 21.055 F-26 11.l24 6.02% 0.155% 282.373 311.907 28.072 21.833 L-34 1.514 38.79% 34.062% 330.393 313.421 28.208 21.939 E-17 2.821 29.60% 23.256% 393.715 316.242 28.462 22.137 C-17 3.520 1.25% 18.842% 653.728 319.762 28.779 22.383 C-06 9.182 3.22% 10.924% 694.122 328.944 29.605 23.026 C-lO 4.308 4.98% 23.548% 788.966 333.252 29.993 23.328 E-23 2.683 26.95% 24.872% 888.973 335.935 30.234 23.515 C-19 16.026 12.22% 49.675% 1019.198 351.961 31.676 24.637 C-02 7.314 2.86% 5.305% 1112.933 359.275 32.335 25.149 C-15 7.203 2.85% 10.502% 1282.780 366.478 32.983 25.653 C-28 1.747 24.50% 48.488% 1957.312 368.225 33.140 25.776 E-05 2.376 24.02% 44.951% 2391.004 370.601 33.354 25.942 E-07 6.876 10.68% 47.190% 2481.677 377.477 33.973 26.423 C-08 3.740 8.54% 41.923% 2500.656 381.217 34.310 26.685 E-16 9.688 8.46% 14.120% 3200.360 390.905 35.181 27.363 C-25A 4.957 8.95% 58.392% 3846.649 395.862 35.628 27.710 * Not sure if F-42i supports F-54. F-42i will be used for lean gas disposal during upset. See section on Management of MW AG During Upset Conditions H:\Milne\A 0 G C C\K.EOR Strategy41.doc 29 "^ . . Pattern Type Average GOR OOIP 9% RF, EOR 7% RF, EOR %of Maturity Scf/stb MMstb Inc. Inc. Reserves Level Recovery Recovery MMstb MMstb Low 244 279 25.1 19.6 71% Medium 697 87 7.8 6.0 22% High 2729 29 2.7 2.1 7% Table 2: KEOR Initial Pattern Classification Tax Credit Injectors Producers Supported MI volume* (MSCFPD) C-36i C-05a and L-12 1911 C-39i C-Ol 2816 F -84bi F-Ol and F-14 . . 3000 F-85i F-79, F-06 750 F -92i F-38 1321 F-95i F-17, F-34 and F-78 1324 L-08i L-03 1751 L-09i L,.02 1740 L-42i J-18 1226 Total 15,839 Table 3: 1998 EOR Tax Credit Injectors Tax credit Producers Supporting Injectors MI Injection V olume* (Mscfpd) F-80 F-83i 3000 L-28 L-33i 2761 L-40 F -82i 3000 Total 8761 Table 4: 1998 EOR Tax Credit Producers H:\Milne\A 0 G C C\KEOR Strategy41.doc 30 " . . a e : nJector o urnes, attern an oug Jut Injector Estimated Producers in Average Pattern Total Average Injection Pattern GOR, scf/stb Pattern Rate, Throughput, Mscfpd %HCPV /yr E-23* 3000 B-06 - - L-16a 4000 L-07, L-II, L- 276 9.9% 29 Total 7000 T bl 5 I . MIV I P GOR d Thr h *wiU be used for startup to keep the C-5531a and C-5531 b compressors in operation Table 6: Mole Fraction of Lean gas and NGL's for Blending Component Lean Gas NGL CO2 0.01 . . C¡ 0.85 C2 0.08 C3 0.04 0.0325 iC4 0.005 0.1040 nC4 0.01 0.3408 iCs 0 0.1190 nCs 0.005 0.1541 C6 0 0.1602 C7 0 0.0706 Cg 0 0.0189 H:\Milne\A 0 G C C\KEOR Strategy41.doc 31 · J. . . Proe;ram Frequency Location Responsibility CFP Lean Gas 1 gas sample per week CFP Plant Operator Composition NGL Composition 1 sample per week CFP or PBU Plant Operator Miscible Solvent I samples per week C-pad and C-pad and Plant Composition CFP Operator Produced Well Oil Once GOR increases, 2 Test Separator Operator samples samples per producer per MI cycle Produced Well Gas Once GOR increases, 2 Test Separator Operator samples samples per producer per MI cycle Bottomhole Pressures 2 surveys per hydraulic Well unit per year Injection Profiles Baseline for each phase Well in each injector within nine months of onset of injection, as required by state. Then, once per phase every two years or after profile modifications Well Tests 2 per month per Test Separator Operator producer Table 7: EOR Surveillance Summary Table 8: Gas Lifted WAG patterns Injector Supported Producers C-19i C-09, L-06 E-16i B-06, B-09 E-26i B-22 H:\Milne\A 0 G C C\KEOR Strategy41.doc 32 O,,·.UfJ . '. e . ~~~VVLVt--f Milne Point Unit, Kuparuk River r¡¡Poòl Area Injection Order \ TD~ \ 5-e-1ù r~ ~(2~01 <; by Doug W~lson '..... '-..... .....", '>,<' .." '- /1' ~"'" '-................. "- I~ I '. \X I / .-NMII:NE:ð1~ .-------"j.' ~ _ _ _ _ .- _ _ . _ _ J I -----------------....___.... . .NMlLNE.02 ADL3~55M i 1.1 e P'~F.j n 1j""Uh ¡tL355016 '-- - --". - -1 - ._-.._~_.---------_. 158 - --. - j I , __po' -NWMILNF.·OI ,_ .J ~11~~<~'~' ~ . ......::r.::. :t: ~ ~ .It.> I ~pt-45 ADL3E ADl381 L. I ADl355017 --- L"I ~!'\'p'104 .. ......n::; ADL315848 P'-Qpg'1'8- \ MPC-18 C-21A ' MI'!.t3A, Not MIt04j \ I'IIN,,".' « '"ot"'J.' #3 STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER ,. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-0221400S F AOGCC R 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M AGENCY CONTACT DATE OF A.O. Jod Colombie PHONE Au st 16 2001 PCN ~ Anchorage Daily News POBox 149001 Anchorage,AK 99514 DATES ADVERTISEMENT REQUIRED: August 18, 2001 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal D Display Account #STOF0330 Advertisement to be published was e-mailed D Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING DATE 2 ARD 02910 3 4 FIN AMOUNT sv CC PGM LC ACCT FY NMR DIST LID 01 02140100 73540 2 3 ¡ 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM . . SUPPLMENT AL Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Kuparuk Oil Pool, Milne Point Unit - Amendment to Area Injection Order 10 BP Exploration (Alaska), Inc. by letter dated August 1, 2001, has applied for an amendment to Area Injection Order 10 under 20 AAC 25.460 to govern the injection of miscible hydrocarbon liquids for the purpose of enhanced recovery operations for the Kuparuk Oil Pool ofthe Milne Point Unit, North Slope, Alaska. A person may submit written comments regarding this application no later than 4:30 pm on September 11,2001 to the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. In addition, the Commission has tentatively set a public hearing on September 11, 2001 at 1 :00 pm at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on September 3, 2001. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. This notice supplements the previous public notice in this matter. The public has until September 11, 2001 to submit written comments to the Alaska Oil and Gas Conservation Commission, not August 24, 2001 as previously announced. Furthermore, a person may request a hearing as set out above; the initial notice advertently omitted reference to this procedure. 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 Jody Colombie at 793-1221 before September 4,2001. b' ^~'AJI'II1.i 'MJ,.r ~ð'-"'-- Cammy chsli Taylor Chair Published August 18,2001 ADN AO# 02214005 AD# DATE 1001732 08/18/2001 . . Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PO ACCOUNT 02214005 STOF0330 STATE OF ALASKA THIRD JUDICIAL Lorene Solivan, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all saia time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper wasregularl distributed to its subscribers during all of said period. That the amount of the fee charged for the foregoing . tion is at in cess of the rate charged private individua s. \ \ "^'" Signed Subscribed and sworn to me before this date: ~~~':;~:~l~c-;n~~~t~~;----- Alaska. Third Division. Anchorage, Alaska \ \\\{¡(((((If/: \\ \ES.o "'/;": \\ ...'-:..... ~A;> ./ ~otb.. ...... . .....~~ §~:+o~!'f~~'" ~ ::: : PUJaL\C : ~ -. '" / ~.... -:::'~'.~ ...... :~:::: -::. ~'?f>- .'~'" ~ .:c:'Cf ~ .....0 ...'\ :.¿ . . . .' ~~:" ' :./.1.1 Ex¡jtEP '\ \ :I/}I) )))))\, PRICE PER DAY OTHER CHARGES $126.35 $0.00 $0.00 $0.00 $126.35 II' SUPPLEMENTAL Notice Of Public Heol'i1î9 ST4TE 01' /l,LASKA 1·.·co=~kO~i~:~~:rsSion., "Re:Kuparuk Oil'Poo, ! MIlne Point lJ nit - I f~f:nd~r~~~ ~g Area In- ' I r,ic~::~:ftt;~o d~:~&: ! 9ust ,I, 2001. has applied [tor on ame»dfflltllt to i Area Inlêctlon Ortler 10 !. under 20 AAC 25.460 to ! govern the, IOÎectlon ot I'. miscible Iwdrocorbon fiq-" uIds.for the purpose of ,enhOllcild recovery op- l~erQtíQns' tor ttle !<uP<1ruk.· all Pool at the Milne :- Peínt. Unit, North Slope, ¡-mó$kO. A þerson r\1Iay submit :~m~; t1~;à~:n~~tr;~ ,no loter than 4:30 pm Oil Septêmber n, 2OOlto the OTHER CHARGES #2 GRAND TOTAL $0.00 $0.00 $0.00 $126.35 $0.00 $126.35 I Aloska 011 and Go . servatlan Co~ml 333 Wes t 7th. A Suite 100, ÂIIC Äloska 99501.111 the Com~lssion ,.' n- tatlvely seta ÞUblio,~ear- Ing on September n,,~1 ~\II¿~~ ~~sa2::e~Jtf;~ Commission at 333,West' Ä'n~~~ri;:-eA~~~e~~: '.' A person .m9Y h that the ì ' schedUled ~~~W ~fthat e ~mlt: sian no later than 4 :30 11m on SéPt$1l'!bfJr :f, 2O\)'f;: if a leqvestJor O"flearlng Is riot tim~'.1' flled.,the Commis~ian will COÐ- I,slder the issuance of an I order ..,ithout a heorlll9. , To learn If the Com~is- I slòn wlllhoiEl the þublic hearing, please call 793-1221. ThiS notice suPPlements the previouS.publ!C no- tice In this matter., The publlchcisuntll ~eptem, ber 11, 2001 to submit written éomtneJ1ts to the Alaska Oil and Gor, Con- servotionCommlSSlan, not AugUst 24,2001 as previously annouO"cêd. I Furt'ie,rmore,a person may request a flearlOll as sêt out abQve; t~ InitIal notice a<:lllertentlYamlt- 1ed referlOnceto this pro- cedure' . . IfYO¡j are o person with II disability who may nee<:l a special modiflcatlon.i.n order to commelît or to attend the public hearing, please cQntClctJø4Y Co- 'c>m)iecit~'"22Jþe,ore ~-.mbel"4,~1. . ~tyW ()echsH TaylOr Chair¡. Pub: AU9"s~,.J8,2001 , . Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 AD# DATE PO ACCOUNT 990698 08/09/2001 STOF0330 02214004 STATE OF ALASKA THIRD JUDICIAL Lorene Solivan, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and dunng all saia time was printed in an office maintained at the aforesaid ¡:>lace of publication of said newspaper. That the annexed is a copy of an advertisement as it was puolished in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of saId period. That the full amount of the fee charged for the foregoing pub' 'on is not in excess of the rate charged private individua1s ""-.. Subscribed and sworn to me before this date: ------JP~/ -------- . .....- Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska A- \ \\1 ((({ ((1ft: \\\\.\.\~. ~'. 0-tl"l"r...-: \"O~ .' --- '. ~,,~ \.:. .....- g~:+O~!:.ltr·" ;. ª : ÞuB\-\<Ï =,ê -~'cII.... ;..... """'s ~~ --- , ~~""~OF~ "'~:f ~ . . . . . . . ..·.AÞ \'" /..1.1 ~~\' :I)JJ}JJ)J))\\ PRICE PER DAY OTHER CHARGES $73.15 $0.00 $0.00 $0.00 $73.15 Notice of Public Hearing ~:s~~. g~:n'tJ~A Conservllflon Commission Re:KupôrukOil 1"001. Mill1è PI. Unit - Amend' menl t~ Area Inlecllon Ordèr BP Explprallon (Alaska). I ~~~t t i~J:~h:sa~~dplt~ for amendm!lnllo Are.a InlectionGr<ler .10 uri~' 20AA(;, 25.460 to govern Ihe ¡nl!lclion øf misclbl!l hvdrøcarbon liquids for Ihe purpose of enhançed: recOV!lrv opera lions for the Kuparuk Oil Pool øf the Milne PI. \.Inll. Nørth SløP8.Aloska. .' ThøC;:(fnmiSSiOn has len- ¡..II:I.'....I..iV. e.lv.se.la PU.blich.!I.ar- ¡ng an SIIplember 11, 2001 øt 1 :OO'pm allhe Alaska 011 and Gas Conseryalion OTHER CHARGES #2 GRAND TOTAL $0.00 $0.00 $0.00 $73.15 $0.00 $73.15 .__.._-_.~._.-.-._._-- I I' Commisålon at 3nWst , 71h Avenu!l. Sulle 100. Anc·hora!òl!l., Alaska. :':1 n additian,.a p,,"son m\lY submitwrHte:IlcÒm- ments re~ardill9ll1e orêo, inle.ction ordé," prIor to Aug"s. 24. ,2001 to the, Alask.a OiiQfft/GoS"Ç9n- se.....alion.GommlssfÐil. ât 333 W..sf,~'lh A....n"". Suite 100. An<;horolÍe AK 99501. For i nformotiôn.îl\lé"~ preterser.vices or other <occam mQø. a....'. O.ns,. 1;0;11 +907) 793- fñt·-"fO~étle,.. tember4,200J. ponSeamoul'Il' Commissioner' PUb: AugUsf9. 2001 STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER . INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-0221400S AOGCC R 333 West 7th Avenue, Suite 100 o Anchorage,AJ( 99501 M AGENCY CONTACT DATE OF A.O. T o Anchorage Daily News POBox 149001 Anchorage,AJ( 99514 August 18, 2001 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account #STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2001, and thereafter for _ consecutive days, the last publication appearing on the _ day of .2001, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2001, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER Re: Ad Order and Notice . . Subject: Re: Ad Order and Notice Date: 16 Aug 2001 16:39:34 -0800 From: Lorene Solivan <lsolivan@adn.com> To: Jody Colombie <jody_colombie@admin.state.ak.us> thank you On Thursday, August 16, 2001, Jody Colombie <jody_colombie@admin.state.ak.us> wrote: >Lorene: > >Please publish the attached notice by August 18, 2001. If you have any >questions, please e-mail or call 793-1221. > >Jody > > lof1 8/16/014:43 PM . . SUPPLMENT AL Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Kuparuk Oil Pool, Milne Point Unit - Amendment to Area Injection Order 10 BP Exploration (Alaska), Inc. by letter dated August 1, 2001, has applied for an amendment to Area Injection Order 10 under 20 AAC 25.460 to govern the injection of miscible hydrocarbon liquids for the purpose of enhanced recovery operations for the Kuparuk Oil Pool ofthe Milne Point Unit, North Slope, Alaska. A person may submit written comments regarding this application no later than 4:30 pm on September 11,2001 to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. In addition, the Commission has tentatively set a public hearing on September 11, 2001 at 1 :00 pm at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on September 3,2001. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the public hearing, please call 793-1221. This notice supplements the previous public notice in this matter. The public has until September 11, 2001 to submit written comments to the Alaska Oil and Gas Conservation Commission, not August 24, 2001 as previously announced. Furthermore, a person may request a hearing as set out above; the initial notice advertently omitted reference to this procedure. 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 Jody Colombie at 793-1221 before September 4, 2001. bc~~r~ Chair Published August 18,2001 ADN AO# 02214005 1 certify that on q.1 T D I a copf of the above was faxed/mailed to .- of the following at their add...... dI record: )~a"\(\¿ O'IC~uj jQ., OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LlBRARYIINFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 . PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN,IL 61820 MURPHY E&P CO, ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 10GCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 . NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 UN IV OF ARKANSAS, SERIALS DEPT UN IV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXON MOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 105070 W MAPLEWOOD DR LITTLETON, CO 80127 . RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL 0 MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 . CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 C & R INDUSTRIES, INC." KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH,CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 . JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, 10 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN V ACTOR POBOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 . NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 DEPT OF REVENUE, OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 US BLM AK DIST OFC, RESOURCE EV AL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507-2899 . YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 GAFO, GREEN PEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DNR, DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 UOAI ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 . PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 VECO ALASKA INC., CHUCK O'DONNEll 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, FRANK MillER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAl JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHilLIPS ALASKA, lEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHilLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHilLIPS ALASKA, KUP CENTRAL WEllS ST TSTNG WEll ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 US BUREAU OF LAND MGMT, Oil & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 . TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 JOHN MillER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHilLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHilLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 PHilLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 Al YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAilY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 JWl ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 . US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 GORDON J. SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHilLIPS ALASKA, STEVE BENZlER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 Al YESKA PIPELINE SERV CO, lEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TElEQUANA DR. ANCHORAGE, AK 99517 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 JACK 0 HAKKI LA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 196168 ANCHORAGE, AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA) INC, PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHA VELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 . DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 ENSTAR NATURAL GAS CO, PRESIDENT TONY IZZO POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 RON DOLCHOK POBOX 83 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 . ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST PO DRAWER 66 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 C BURGLlN POBOX131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 . BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 . JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 VALDEZ PIONEER, PO BOX 367 VALDEZ,AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG POBOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 #2 STATE OF ALASKA ADVERTISING ORDER . . ADVERTISING ORDER NO. ~ NOTICE TO PUBLISHER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE. AO-02214004 F AOGCC R 333 West 7th Avenue o Anchorage, AK 99501 M AGENCY CONTACT Jod Colombie PHONE DATE OF A.O. Au ust 7 2001 PCN ~ Anchorage Daily News PO Box 149001 Anchorage, AK 99514 Fax # 279-8170 DATES ADVERTISEMENT REQUIRED: August 9,2001 THE MA TERIAL-UE1WEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement XX Legal o Display Account #STOF0330 Advertisement to be published was e-mailed. o Classified DOther (Specify) SEE ATTACHED (pUBLIC HEARING NOTICE) DATE ARD 02910 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LID 02 02140100 73540 2 3 REQUISITIONED BY: ~ 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Kuparuk Oil Pool, Milne Pt. Unit - Amendment to Area Injection Order BP Exploration (Alaska), Inc. by letter dated August 1, 2001, has applied for amendment to Area Injection Order 10 under 20 AAC 25.460 to govern the injection of miscible hydrocarbon liquids for the purpose of enhanced recovery operations for the Kuparuk Oil Pool ofthe Milne Pt. Unit, North Slope, Alaska. The Commission has tentatively set a public hearing on September 11, 2001 at 1 :00 pm at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska. In addition, a person may submit written comments regarding the area injection order prior to August 24, 2001 to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage AK 99501. For information, interpreter services or other accommodations, call (907) 793- 1221 before September 4,2001. Dan Seamount Commissioner Published August 9, 2001 ADN AO# 02214004 J led· ìn (/¡cÞ (þ' . YI:1' l rf) .þt v tJ;b,. ~o1 J ¡ìJ,o ~ lJ-f I ~~ 0(1/ D rf\(}; ... .-1) 1'1 I íf. (} ?LLD i.¡1'O 4/:990698 STOF0330 $73.15 . . AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Lorene Solivan being fIrst duly sworn on oath deposes and says that he/she is an representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an offIce maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on August 9, 2001 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged p e individuals. \,.. Notice Of Public HeariO!l S"fATeOF ALASKA Alaska Oil aod Gas Cooservatiorr CommissiòO . Re:Kuparuk Oil Pool, Milne Pt. Unit - Amend- . m",nl 10, Areø In¡",clion Order BP t;xporationJAlaskø, II nc. bv letter dØt"'d Au- 'Ø'Ust 1, 2001, høs apPlied for amendment tøAreø IniectiOnOrder 10 under ¡,..go AAC25.460 10 govern Ihe .iniectionof miscible' bvdrocørboO liquids for t,b", purpose of "'nhanced recoverVQperøtiÇlns for Ihe Kuporuk Oil Pool pf tbeMilne PI/Unit, North Slop"" Aløska. The commlsslÇln has ten- lotlvelv set ° public h"'or- Ing on September 11 , 2001 ot 1:00pm Qt th", Alaska I Oil and Gos ConSli!fvati,on. Signe Subscribed and sworn to before /ìJf~0 me this, ".é I day 0 Notary Public in and for the State of Alaska. Third Division Anchorage. Alaska MY COMMISSION EXPIRES , /" f /: . /", .' .-"j¿. ,f !;;;····f/;{?/:J " I \ll(( (({((fft: \\ \ \E. S. 06 t'"/'..- \.\: ...'" . . . . . :(~ A" \: &."r...... ...." r,- ~Ó~·· ~'t~R'=·. ~ ....O:.~O '- ~ . ~ .-- .- :: : PU8\o\V : ~ê ~~~"'~lJ:-;"~!~'ff ~ .. . . .' ~:\'\ =-'// ~,,\ :lj}J}JJJ)))\\ Commissio,n øt:!33\IV",st' 7th Av",nue, Suite 100, Ancho,rog"" Alaskø In addition, ø persol1c may' submil writtenCQn'k' m",nts regørdlng t"",ørea' in iection order prior IQ August. 24. 2001 to Ih"" Aloska Oil (Jnd~os·Con. serv.otiQn CQmmlsslon at ' 333 West 7th Avenue.' Suile 100. Anchorage AK 99501. For informotlQ)\. 'inter- , preterservices Qr Qther' occommOdollQns" eoU :~~~9g~~.beforeSep-' Don Seomc¡unf Cc¡mmlssioner . put AU9ust 9, 2001 . . STAT~ OF ALASKA · ADVERTISING ORDER NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF AO-02214004 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE. F AGENCY CONTACT DATE OF A.O. AOGCC R 3001 Porcupine Drive o Anchorage, AK 99501 M PHONE ¿ Anchorage Daily News PO Box 149001 Anchorage, AK 99514 Fax 279-8170 August 9, 2000 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 19_, and thereafter for _ consecutive days, the last publication appearing on the _ day of ,19_, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 19_, Notary public for state of My commission expires 02-901 (Rev. 3/94) Page 2 AO.FRM PUBLISHER #1 Re: BPs request AID 10 . . Subject: Re: BPs request AIO 10 Date: Fri, 27 Jul2001 10:16:03 -0800 From: Jane Williamson <Jane_ Williamson@admin.state.ak.us> Organization: Alaska Oil & Gas Conservation Commission To: Robert E Crandell <robert_crandell@correct.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Wendy D Mahan <wendy_mahan@admin.state.ak.us>, John D Hartz <jack _ hartz@admin.state.ak.us> CC: Camille 0 Taylor <cammy_taylor@admin.state.ak.us>, Daniel T Seamount JR <dan_seamount@admin.state.ak.us>, Julie M Heusser <julie _ heusser@admin.state.ak.us> Cammy talked with Jêa.lfÐïeky on this and Cammy has asked Jean to have BPs technical contact call me as regards technical information we need to for evaluation ofthis EaR project. I would like to meet with you on (Tentative Tuesday 1-3) to finalize our needs, so that we can provide a complete list to BP on Wed (meet with Byron Haynes 1-3). Please let me know if you can meet on Tuesday. As noted in my E-mail to Cammy of july 18 (below), the Ala 10 ammendment request doesn't adequately address the technical information for justification of the project for us to evaluate. I talked with Byron Haynes (BP Sr. Res. Eng) who is coordinating this EOR project. He sent the Power Point slides of our July 2 meeting to us. Much of the information I need is in this Power point presentation. Byron and I tentatively scheduled 1 pm Wed, to meet. Please review the AIOlO draft of July 13 (I can get you a copy if you don't have one), and also review the PP documents (I attached shortcut) It resides on the M drive fìle:/IIMI/Presentations/BP Mi1ne Pt. Kup EOR proi/AOGCC S1ide Presentation.ppt . Thanks. Jane Jane Williamson wrote: Cammy, I have taken a quick initial stab at review of BPs application for ammendment of Ala 10. The following are my observations. I ams cc: commissioners/staff to take a look and make comments/change as appropriate so that you can get something out to Jean Dicky. Let me know if you want to discuss. - This application in my opinion provides insufficient information as to the reservoir justification for miscible gas injection. I am wondering if this should be covered under a Conservation Order as well as an AIO? -This application should remain specific to MW AG in the Kuparuk reservoir in my opinion, but it is a bit difficult, as other AIOI0 ammendments brought in water injection for Schrader Bluff Somehow though, must be very specific that MW AG is only for Kuparuk, and new/more information will be required for MW AG into Schrader. lof4 8/16/01 3:38 PM Re: BPs request NO 10 . . Specifics: Item 3 Page 4- Desciption of Operation - As stated above, insuffient information. This should have sufficient information to allow for conclusion that the project is sound. It should include a Project description including: · Injection volumes, rates, pore volume injection over time, projected life of project, etc · Reservoir Pressure information · Reservoir evaluation of injection - backup material providing the basis for increased recovery o Reservoir mechanics and/or modeling studies o Correlation ofMW AG at Milne Pt to other injection projects (Kuparuk River unit correlation) · Fluids analysis · Well Spacing, injection well location · Surveillance information o Results of water injection and IW AG operations to date and correlation to MW AG project · Development Plan - Including Facilities associated with the project, timing, surveillance activities · Other Project Specifics - Facilities associated with the project. Item 4 Page 4 -Geologic information pertaining to the flood area. Referring to CO 173, 349 and 349 A - porosities/perms/faultingllithology/ cross-sections/structure maps, etc Item 7, page 5 Mechanical Integrity- Wording from 20AAC25.412 and 20 AAC25.402 (e)(f) should be used. Strike ("In addition, a variance will be obtained from the AOGCC to continue safe operation...." The wording in Paragraph 3 was in prior AIOlO. Other: An explanation of the facilities system for MW AG/IW AG would in my opinion be important. It doesn't look like the AOGCC generally gets into this, but a PFD of the system, with information on the surface safety system would be in order in my opinion. Item 8 Injection fluids: Source and Produced Water, - I cannot find an application for the IW AG project as mentioned in the application. A restatement of the waters information should be included in my opinion, so that we don't have to go back to prior orders. The source water here is Prince Creek water which is a cretaceous water. There hasn't been any problems using this water, no problems of note when I was at Milne. No H2S, very low C02 in the production stream. Miscible Hydrocarbon gas - More information on miscibility vs. pressure. Information alluded to in meeting on use of rich gas, and mixing with the NGLs. Need compositional analysis. Other fluids - It appears to me that AIO 10 did allow for the injection of ponded water, and of cource solution gas from production. Not sure about gray water, Sea water for thermal frac. I don't see a problem with this. In addition, I believe there may be some chemicals associated with waterflood, and production, such as de-emulsifier, scale inhibitor, corrosion inhibition, but this is part of normal operations. The Sea water to thermally frac gas injection wells is a new one since I was there. Item 9 and 10. Injection Pressures/fracture information. Within the Kuparuk Reservoir, water is injected above frac gradient. This should be stated. Information about fractures and showing that the fractures will not propagate out of the confining zones is required. From an oil recovery standpoint, injection above frac gradient is not a problem" in fact while I was there, the ability to inject above frac gradient allowed repressurization of some zones, 2of4 8/16/01 3:38 PM Re: BPs request AIO 10 . . where facilities had been delayed for waterflood, and has been a big boon for production. A bigger problem may be balancing pressures in fault blocks. Some fault blocks have been overpressured during IW AG, which has caused problems in drilling activities. Some ofthis is due to not having enough wells equipped for gas injection. Also, I do not thing the Aquifer Exemption Order #2 belongs here. Item 11 Water Analysis - Yes water quality was addressed in prior AIOI0, but it wouldn't hurt to have all in this record. Item 12 Aquifer Exemption - This is true, Aquifer Exemption Order 2 applies Item 13 Hydrocarbon Recovery. -Need more information as noted above on the incremental reserves. Affected area, results from their modeling, pore volume injection planned, etc. This is inadequate. Item 14. Mechanical Condition of Adjacent Wells - I'm not sure if they need to supply information on all wells. Perhaps a summary? Historical Background: The following supplies prior AIO, CO, AEO list as affecting Milne Point Unit, Kuparuk River Field, Kuparuk and Schrader Bluff Oil Pools. Area Injection Orders and ammendments at Milne Point AIO 10, (original 10/19/86 pertained to water injection into the Kuparuk Oil Pool underlying Milne Point Unit. revisions: AIOlO.001 administrative ammendment 10/28/86 amends Rule 6 AIO 10 AIO 10.002 2/10/88 administrative ammendment Rule 2 AIO 10 AIO 10 Ammendment 12/30/91 to include injection into the Schrader Bluff Oil Pool, AIO 10 Ammended 5/3/94: BP sole operator and Expansion of AIO and AIO 10 Ammended 11/13/95: Expansion of AIO Conservation Orders affecting Milne Point Unit (following does not include individual well spacing exceptions, changes in surface casing setting and other Special exceptions): CO 173 (Pool Rules Kuparuk River Pool, Kuparuk River Field, includes Milne Pt Kuparuk sands in pool) CO 173.004 12/12/83 Conoco as operator of Milne Pt. CO 205 10/9/84 Approves water flood for MPU Kuparuk Pool CO 255 7/2/90 Pool Rules define Schrader Bluff Oil Pool CO 283 12/30/91 Waterflood in Schrader Bluff Oil Pool approved CO 173.011 6/14/94 Use LLC valves in MPU wells completed with ESPs CO 349 12/16/94 Expanded effective area of Kuparuk Rive Field, Kuparuk Oil Pool, as regards Milne Pt Unit - establish BP operator CO 349 A 12/23/96 Further amends affected areas ofKuparuk Oil Pool, delineation into PB Field and Kuparuk River Field (again, MP Unit, part of Kuparuk River Field, Kuparuk Oil Pool CO 390 3/7/97 Grant exception to allow completion of producing wells w/out a packer when electric submerible pups are installed. CO 205.001 Change injection Well Survey Requirements of Rule 4. AEO 2 7/8/87 Exemption of portions of freshwater aquifer below MPU for injection activities 30f4 8/16/013:38 PM Re: BPs request AIO 10 . . ! Name: AOGCC Slide Presentation.ppt ! ~AOGCC Slide Presentation.ppt Type: POWERPNT File (apPlication/ppt) Encoding: base64 I 40f4 8/161013:38 PM BP Milne Pt EOR - ammendment to AIO 10 . . . . Subject: BP Milne Pt EOR - ammendment to AIO 10 Date: Mon, 06 Aug 2001 10:10:23 -0800 From: Jane Williamson <Jane _ Williamson@admin.state.ak.us> Organization: Alaska Oil & Gas Conservation Commission To: Julie M Heusser <julie_heusser@admin.state.ak.us>, Camille 0 Taylor <cammy_taylor@admin.state.ak.us>, Daniel T Seamount JR <dan_seamount@admin.state.ak.us>, Robert@admin.state.ak.us, John D Hartz <jack_hartz@admin.state.ak.us> CC: Thomas E Maunder <tom_maunder@admin.state.ak.us>, Wendy D Mahan <wendy _ mahan@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us> FYI. I senVByroøthe list of my requests for additional information in their AID 10 application. He did not seem to have any problems with my request, through it will take some time to get together. Per my discussions with Cammy on Thursday, this is the course of action I understand. - BP Milne Pt. send in their application for EOR in Milne Point Kuparuk (essentially as is) so that we can get public notice out. (Note: I talked with Cammy before she left. She said she would "change her own rule" for this case, on requiring a full application, as long as they get the full information in time. BP Milne Pt. to send an updated full application (with expanded information per my request attached). Need within 2 weeks of hearing date (by Sep 27 to allow us to finalize comments/questions and send to them) Tentatively set a hearing date for 30 days after the public notice. Around Sep II? Crandall will be gone, and possibly Hartz. All others here. Byron wants to know why/if we require a hearing on this. Can you Help answer these questions: 1) Is the desire for the AOGCC to go to hearing with this application mainly for the purpose of getting the application and supporting data into the record? (2) If BP gets the data requested delivered to the AOGCC to be put into the record will a hearing be necessary? If not who will make that decision, Cammy? (3) Jeanne will send a new draft app this week. Can you take a look at it...Will that draft suffice for an application to be and can it be used for public notice? - PER Cammy - will suffice for public notice, must follow through with full application. lof2 8/16/013:36 PM BP Milne Pt EOR - ammendment to AlO 10 . . . . L ,- ,_,,,,,,,.·.v..~.,,,,,,,·«,,,,, <"""w"v««««ww,>,w""v"'»««' « ,"'V ..·,....·_,.,..«.,.,<.",.<Wv...__. ._··,,··,,<......······v<M"»'«'·w"'"'' ,·_,···,·......w...,..w«·."",.·w Name: Notes to BP MP.doc ~Notes to BP MP.doc Type: WINWORD File (application/msword) Encoding: base64 20f2 8/16/01 3:36 PM . . Date: 8/3/01 Draft Comments on BP draft application of 7/13/01 on AIOI0 MJW Review Introduction Note: while Ala 10 was worded that injection of "non-hazardous fluids" for pressure maintenance, all correspondence and backup material we have indicate that prior applications for Ala 10 was to provide for waterflood. Item 3 Pa!!e 4- Desciption of Operation AOGCC Regulation 20 AAC 25.402 (c) (4) requires a full description of the particular operation for which approval is requested. While some of the information is available in the 2001 Annual Surveillance Report, the information must be incorporated into the record. The description needs to provide development plans for the MW AG area, and should tie in to the full Kuparuk Pool reservoir plans. . Overview of Project · Discussion area/wells impacted · Discuss the wells planned for MW AG injection · Refer to maps with well location noted (Note: Need the maps to identify Kuparuk Pool producers/injectors. Out line the projected reservoir limits). · Facilities requirements · Description and simplified PFD · How will miscibility be maintained · Rates for injection · Planned timing of injection project · Production, injection rate projections · Development plan - Longer term vision for development of area Reservoir evaluation of injection Item 4 Page 4 -Geologic information pertaining to the flood area The information on file with the Commission concerning the Kuparuk reservoirs at Milne Point consists primarily of small, simplified, and generally 1980's to mid-1990's vintage maps and cross-sections that are contained in several different orders and reports. To adequately understand the geology of the Kuparuk reservoirs within the Milne Point Unit and to adequately access the impact of the proposed miscible gas enhanced hydrocarbon recovery project, AOGCC requests the following supporting information for the affected reservoir sands: 1) Structure map for the Kuparuk within the Milne Point Unit showing faults, depth contours, and fluid contacts 2) Gross thickness isopach map 3) Net sand isopach map 4) Average porosity map 5) Average permeability map 6) Average water saturation map 7) Net hydrocarbon pore-foot map 8) Cross-sections through the project area demonstrating key structural or stratigraphic relationships within the affected reservoirs Each map should be desk-sized, and the information provided should be sufficient in detail to permit understanding of each hydraulic unit. Item 7, page 5 Mechanical Integrity- The requirements of the following AOGCC Regulations apply: 20 AAC 25.402 (e), (t), (g), (h), (i), 20AAC25.412 And 20 AAC 25.030(d)(7) Item 8 Injection fluids: I have not found an application for the IW AG project as mentioned in this application. Need the fluid and composition ofthe waters and Miscible gas injectant. The source water here is Prince Creek water. Information alluded to in meeting on use of rich gas, and mixing with the . . NGLs. Need compositional analysis. The gray water and ponded and/or stonn water that accumulate on the pad area is something that we'll need to discuss some more. AOGCC memorandum agreement with the EP A on this states "For enhanced recovery injection wells, AOGCC and EP A agree that the injected fluids must function primarily to enhance recovery of oil and gas and must be recognized by AOGCC as being appropriate for enhanced recovery. In detennining fluids appropriate for enhanced recovery, the AOGCC will promote waste minimization by encouraging the beneficial recycling of fluids, which if not used in this manner would otherwise be considered a waste" (Nov. 22, 1991 - Memorandum of Agreement between the Alaska Oil and Gas Conservation Commission and the US. Environmental Protection Agency, Region 10.) Please provide an explanation of how these fluids will function to enhance recovery. Item 9 and 10. Injection Pressures/fracture information. Within the Kuparuk Reservoir, water is injected above frac gradient. Infonnation about fractures and showing that the fractures will not propagate out of the confining zones is generally needed if going above frac gradient. SWhat is the frac gradient of the Kuparuk. What is the frac gradient (from leakofftests?) ofthe confining zones. How much confining zone is in place. Is there potential to exceed the frac gradient of the confining zones? Has any modeling been done to show that injected fluid will not go out of confining zone? Item 11 Water Analysis - Yes water analysis was addressed in prior AIOlO, but it would be nice to include in this record. Item 12 Aquifer Exemption - This is true, Aquifer Exemption Order 2 applies. We need to review Aquifer Exemption Order 2 boundaries and AIO 10 boundaries. Cammy indicated that they aren't the same. Item 13 Hydrocarbon Recovery. This section needs to provide reservoir justification for Miscible Gas Injection. Hydrocarbon recovery needs to be supported with full technical backup. Our infonnation is dated, does not include infonnation on the expansions that have taken place in NW Milne or Cascade. While we have the surveillance reports, and your power point presentation, it is only a partial picture, plus we must get the infonnation into the record. In order to evaluate the injection proposal, add Surveillance Results, Material Balance review Surveillance infonnation - review of infonnation to date V oidage analysis, maps or spreadsheets showing infonnation on voidage by hydraulic units or segments for the Kuparuk Oil Pool. Problem areas? Underlover injected blocks, gas or water cycling? Reservoir Management Pressure map V oidage/flood management expectations Provide infonnation to relate the MW AG to the current IW AG injection Methods used for detennination ofMW AG recoveries, and plan for injection Description of the reservoir simulation Miscible Hydrocarbon gas - More infonnation on miscibility vs. pressure Scale up of model. Where applied. Results of model runs - sensitivities Profiles production (oil, water, gas), water, IW AG and MW AG injection volumes over time Recovery infonnations