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Home My WebLink AboutCO 341 DINDEX CONSERVATION ORDER NO. 341D Prudhoe Oil Pool Prudhoe Bay Field 1. September 21, 2001 Letter from BPXA regarding Gas Cap Water Project (portions held confidential) 2. September 29 2001 Notice of Public Hearing, Affidavit of Publication, mailings 3. October 18, 2001 BSI GCWI Questions 4. October 30, 2001 BPXA's pre -filed testimony, sign -in sheet 5. October 30, 2001 Transcript 6. November 1, 2001 BPXA's submittal of additional information from hearing Testimony 7. November 30, 2001 BPXA's letter of non -objection 8. -------------------- PBU Annual Surveillance Reporting Requirements 9. November 9, 2005 BPXA, CPAI, and Exxon Gas Cap Water Injection Presentation (held confidential) 10. April 29, 2009 BPXA's letter and results of the collected surveillance data from the commingled production from Aurora Oil Pool and PBU (oil tracers held confidential) 11. May 24, 2011 Alaska Gasline Development Corp letter regarding Gas Off -Take For Instate Gas Pipeline 12. June 27, 2011 AOGCC letter regarding Gas Off -Take For Instate Gas Pipeline 13. September 30, 2013 BPXA letter regarding discovered lapse in reporting requirements 14. March 31, 2014 BPXA's report regarding commingled production for well S-26 INDEX CONSERVATION ORDER NO. 341D . . 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. Prudhoe Oil Pool- Modification to pool rules - Conservation Order 34lC, for injection of water into the Prudhoe Bay Gas Cap IT APPEARING THAT: ) Conservation Order 341D ) ) Prudhoe Oil Pool ) Prudhoe Bay Field ) ) ) November 30,2001 1. By letter dated September 21, 2001, BP Exploration (Alaska), Inc. ("BPXA") on behalf of the Working Interest Owners ("WIOs") of the Initial Participating Areas of the Prudhoe Bay Unit ("PBU") has applied for a modification of certain rules of Conservation Order 341 C ("CO 341 C") in conjunction with a proposed project named the Gas Cap Water Injection Project ("GCWI"). 2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on September 29,2001. 3. The Commission held a public hearing October 30,2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission at 333 West ih Avenue, Suite 100, Anchorage, Alaska 99501. 4. The Commission received no protests to BPXA's application or to the public testimony. 5. Pre-filed testimony of representatives of BP Exploration (Alaska), Inc., Phillips Alaska, Inc. and ExxonMobil Production Company is included in the record (revised October 30, 2001). All additional information requested by the Commission at the hearing was received November 1,2001 and November 6,2001. FINDINGS: 1. Authority 20 AAC 25.520. 20 AAC 25.540 Commission regulation 20 AAC 25.420 provides authority to issue orders prescribing rules to govern the proposed development and operation of a pool. The commission will, in its discretion, amend pool orders in accordance with procedures set forth in 20 AC 25.540. CO 341D November 30,2001 . . Page 2 2. Gas Cap Water Injection Project - Overview Currently, reservoir pressure is declining at 25 to 35 psi/year. The WIOs have studied options to mitigate pressure decline and have annually reported the progress of these studies to the Commission, based upon rulings in CO 290 (2/21/92), which were incorporated into CO 341C, Rule 12(d). As a result of these studies, the WIOs sanctioned the Gas Cap Water Injection project in June 2001. This project represents a new element in the depletion strategy of the Prudhoe Bay Oil Pool with the dual goals to mitigate reservoir pressure decline and improve recovery. 3. Proposed Modifications to Conservation Order 341C The most current rules governing Prudhoe Bay Field, Prudhoe Oil Pool are contained in CO 341C, dated June 12, 1997. CO 341C is a consolidation of all conservation orders in effect for the Prudhoe Bay Field, Prudhoe Oil Pool at that point in time. Specific to CO 341C, BPXA is requesting the following modifications: a) Revoke paragraph (d) of Rule 12 that requires the Operator to continue to investigate options to mitigate pressure decline and to provide an annual report to the Commission. With the implementation of GCWI, BPXA claims pressure decline will be mitigated. b) Modification of Paragraph (c) in Rule 12 which currently provides that the Operator maintain a pressure differential of at least 250 psi between the minimum miscibility pressure of the miscible injectant and the prevailing reservoir pressure. BPXA claims that as GCWI will mitigate pressure decline, a more appropriate pressure differential of 100 psi is appropriate and will allow BPXA to better optimize both the composition and volume of the miscible injectant. c) Modification of Rule 11, which describes the Prudhoe Oil Pool surveillance report, to include the results of GCWI surveillance. 4. GCWI Project Overview The project scope calls for ramping up to 650,000 barrels per day of seawater injection into the eastern portion of the gas cap from a new injection site located at the East Dock Staging Pad. Initial projected rates are 500,000 barrels per day. Water injection will increase over time with increased availability of seawater and decreased seawater demand in other projects, such as the Flow Station 2 and Point McIntyre waterfloods and Grind and Inject. Water injection is anticipated to continue for twenty years, with a final injected water volume of near four billion barrels. Increased hydrocarbon recovery of 150-200 million barrels is projected by BPXA. a) Facilities Requirements Facility construction is planned for this winter, followed by start-up of injection in mid 2002. To implement the Gas Cap Water Injection project, a new seawater CO 341D November 30, 2001 . . Page 3 pipeline from Flow Station 2 to the East Dock Staging Pad will be constructed. The new line will have a 32" diameter and a total length of approximately 18,000 feet. It will tie-in to the existing 32"seawater line running from the Eastern Seawater Injection Plant to Flow Station 2. A heated pig receiver/manifold module and well houses will be installed at the East Dock Staging Pad to accommodate five to seven new injection wells. b) GCWI Well Locations Current plans for the GCWI include drilling of up to seven water injection wells into the eastern portion of the PBU, Ivishak formation gas cap. BPXA indicates the well locations were strategically chosen to allow for sufficient Ivishak pay at the bottom hole locations of the injectors, while maintaining sufficient distance from the gas injection and oil producing areas. c) GCWI Well Completion Each gas cap water injector will be completed with 13 3/8" surface casing cemented to surface, 9 5/8" intermediate casing with cement brought to 1000' above the shoe, and a fully cemented 7" injection liner. The tubing will be 7 5/8" and will include a 7" subsurface safety valve and two 7" profiles. The tubing is large to accommodate the high volume of water to be injected. The tubing will also be plastic coated to help minimize the friction losses. Average surface pressure for these new injection wells will be approximately 2700 psi. Maximum injection pressure is expected to be approximately 3100 psi. 5. Project Benefits a) Reservoir Pressure Average reservoir pressure in the Prudhoe Bay field is declining at a rate of 25-35 psi/year. The declining pressure reduces efficiency of every recovery mechanism operating in the field. The GCWI project is designed to arrest pressure decline and maintain the reservoir pressure until water injection ends in 2022. Current average reservoir pressure is approximately 3450 psi (@ 8800' ss datum). b) Reservoir Simulation of Recovery The GCWI incremental oil recovery was predicted using BPXA's Full Field Compositional Reservoir Model, comprised of a sixty (60) acre areal grid of the Prudhoe Bay field. It includes the oil that initially was in the gas cap and is immobile. The recovery calculated by the full field model was validated using mechanistic studies of GCWI using fully compositionallD, 2D, strip, and pattern models. The increased pressure resulting from GCWI improves every recovery mechanism operating in the field. The benefits are characterized for three regions of the field; Gas Cap, Gravity Drainage, and WaterfloodlEOR. The incremental net additional recovery from GCWI is approximately 200 MMB in the full field model. The total reflects a reduction of 20 MMB in the Gas Cap region with increases of 200 MMB in the Gravity Drainage region, and 20 MMB in the waterfloodlEOR region. CO 341D November 30, 2001 . . Page 4 (1) Gas Cap Area In total, there is a net reserves reduction of about 20 MMB in the Gas Cap region. In the original gas cap, not invaded by water, BPXA projects 30 MMB additional reserves from vaporization of residual oil and retrograde condensate. In the water invaded area, some hydrocarbon liquids will be trapped and remain immobile to injected water, preventing vaporization by injected gas, which reduces liquid recovery by approximately 50 MMB. (2) Gravity Drainage Area BPXA projects improved vaporization and gravity drainage processes will yield about 200 MMB of incremental recovery from the Gravity Drainage region. Vaporization of residual oil and retrograde condensate by the injected gas is more efficient at higher pressure. Higher reservoir pressure reduces oil shrinkage and oil viscosity. Both of these effects increase oil mobility and result in more efficient gravity drainage. (3) Waterflood and EOR Area The waterflood/EOR benefits are approximately 20 MMB. The projected benefits result from: I) higher reservoir pressure increasing well production capacity; 2) lowered oil shrinkage; and 3) the higher reservoir pressure allowing leaner miscible injectant, thus greater supply, leading to more EOR recovery. 6. Water Movement The potential for water to interfere with the various recovery mechanisms has been extensively studied by the WIOs. In particular, the potential for water to finger through the gas cap, and interfere with the gravity drainage area was a prime concern. WIO studies showed that because gas is 100 times more mobile than the water that displaces it, a piston-like displacement is anticipated. Water saturations in simulation of water displacing oil were compared to simulation of water displacing gas in a reservoir containing a high permeability (5 Darcy) thief zone. In the case of water displacing oil, water fingered through the high perm streak to the producer. In the case of water displacing gas, a piston-like displacement occurred. Areal water saturation maps from BPXA's full field model were presented, showing the movement of water over time. The water is projected to move in a relatively radial to oblong shaped front. At the end of GCWI injection in 2022, water is projected to reach the waterflood area in the eastern part of the field, and the northern oil producers in the gravity drainage area. However, the western portion of the gas cap, and the major portion of the gravity drainage area are not expected to be invaded with water. Shut-down of GCWI is expected in 2022. Review of model projections through 2031 indicates little lateral movement of the water, again due to the low mobility of the water to the gas in the area. 7. GCWI - Maior Gas sale Relationship The WIOs addressed the interaction of the GCWI project with potential major gas sales and how gas sales would impact the estimated benefits of the GCWI project and CO 341D November 30,2001 . . Page 5 how gas cap water injection is expected to impact ultimate gas recovery. a) Maior Gas Sale Effect on GCWI Recovery A gas sale will reduce the incremental oil recovery from gas cap water injection. While the rate and timing have not been determined for major gas sales, a case to demonstrate the effect was shown. Assuming a 4 BCF /D gas sales rate beginning in 2008, the incremental production derived from GCWI is reduced from about 200 MMB to about 135 MMB. The reduction in the recovery results from three mechanisms: · With a major gas sale the volume of gas available for injection is reduced in order to meet the gas sale demand. This reduces vaporization recovery for gas cap water injection; . The ability of the injected gas to vaporize the oil it contacts diminishes as reservoir pressure decreases. . Gas sale will lower reservoir pressure, making the oil more viscous, which decreases efficiency of oil production and reduces oil produced by gravity drainage. b) Effect of GCWI on Gas Recovery of Maior Gas Sales The WIOs state that ultimate gas recovery should not be reduced by GCWI. Major Gas Sales off-take will require a large water free area from which to produce the gas. The simulation projections presented for the GCWI project suggest that the water will be localized and a significant portion of the gas cap will be free from water to allow blow-down of the gas reserves. Without GCWI, gas recovery is expected to exceed 80% of the original gas cap gas in place when the pressure is reduced from the original 4400 psi to about 850 psi. With GCWI, gas is expected to be trapped at a saturation of 25% within the area of water injection. When reservoir pressure is subsequently reduced during "blow down", the trapped gas expands and once again becomes mobile. In the example shown by the WIOs, at a reservoir pressure of 1500 psi the gas recovery was projected at 90% with GCWI, while by pressure depletion alone the pressure has to be blown down to 500 psi to achieve the same recovery 8. Surveillance BPXA presented plans to monitor injection well conformance, water movement and reservoir pressure. The major components of the GCWI surveillance plan are: · Injection wells will be monitored in a manner similar to other water injection wells within the Prudhoe Bay pool. · Pulsed Neutron Logs (PNLs) in existing wells will provide downhole and regional data on the water movement. · 4-D gravity will provide a general view of water movement. · Reservoir pressure monitoring will be done according to current Prudhoe Bay pool rules. CO 341D November 30,2001 . . Page 6 a) Iniection Well Monitoring Injection well monitoring will be conducted to ensure that the water injection is contained in the desired reservoir interval. The injection wells will be monitored with surface measured temperature, pressure and injection rate. These measurements will be similar to other injection wells within the Prudhoe Bay pool. With these measurements it is possible to monitor injection characteristics, particularly changes in the injectivity indices. The injectivity indices provide direct evidence of changes in well performance. Downhole measurements will provide confirmation of the surface measurements and will also help describe reservoir properties and hydraulic performance. Downhole temperature logs will provide verification of injection conformance and confirm that fracture height growth is confined within the Ivishak. Downhole pressure measurements will be used to determine tubular pressure drops and hydraulic performance. Pressure falloff tests will be undertaken to determine reservoir properties and wellbore skin. b) Water Movement Surveillance with Pulsed Neutron Logs: The leading edge of the waterflood will be detected primarily with pulsed neutron logs. BPXA identified more than nine wells surrounding the injection areas in which pulsed neutron logs can be run to monitor the movement of water. These wells are primarily Lisburne producing wells. BPXA indicated that there are no known cement problems that would prevent confinement of injection to the Ivishak. Pulsed neutron logs, specifically the RST logs, were chosen because they can be run in Lisburne wells completed with 2 7/8 inch tubing. Also, they can be run in two modes to collect data for discerning a major change in fluids (sigma & Carbon/Oxygen). The RSTs will help locate the leading edge of the waterflood, by detecting the change in saturation as water invades the Ivishak gas cap interval at the wellbore. It will also provide data in determining the regional waterflood coverage. BPXA indicated that the statistical variations seen in the RST log measurements should not substantially affect the ability to detect movement of water into the gas zones. c) 4D Gravity Technique The 4D Gravity technique utilizes very sensitive surface gravity measurements taken periodically. The method measures small changes in gravity as the low- density gas is replaced with the higher density water. Baseline measurements will be taken prior to water injection. Subsequent measurements will be made at discrete time intervals and compared to the baseline measurements. An increase in the density of the fluids in the gas cap indicates the presence of water. BPXA anticipates the 4D Gravity technique will allow them to map general water movement, determine an average waterflood front, and provide a means to perform a mass balance of the injected water. The major limitations of the 4D gravity technique are that it cannot detect small horizontal or vertical flood fronts and it cannot provide any downhole zonal information. Gravity measurements coupled with material balance and PNL measurements can aid validation of simulation predictions and fine tune history match calculations. CO 341D November 30, 2001 . . Page 7 9. Proposed chan2e to Rule 12l c) BPXA requested in the rules for GCWI that the requirements for mImmum miscibility pressure stipulated in Rule 12( c) should be modified. Currently this rule stipulated that the Operator maintain a pressure differential of at least 250 psi between the minimum miscibility pressure of the miscible injectant and the prevailing reservoir pressure. The 250 psi differential had been initially proposed by the WIOs in testimony provided 10/9/91, and approved in CO 290 dated February 21, 1992. This differential was based upon the assumption that the reservoir pressure will decline 100-150 psi during the time in which a cycle of MI is in the reservoir. A safety factor of 100 psi in addition was added to this. With GCWI pressure will be maintained in the injection patterns. As such 100 psi differential is sufficient until such time that the reservoir pressure is stabilized. This change will allow some additional flexibility of the Operator to increase overall MI volumes, and disperse MI to other areas of the field, leading to better optimization of MI throughout the field. This will not have a negative impact upon overall recovery. 10. Miti2ation of Risks Studies indicate that not implementing or further delaying GCWI will result in less recovery over the remaining life of the field. The studies and analysis appear thorough and technically sound. Though outweighed by the expected benefits to overall hydrocarbon recovery, there remain some risks that must be managed through ongoing surveillance. Oil reserves are potentially at risk if the injected water moves too far, too fast and enters the sensitive Gravity Drainage area of the field. Numerous reservoir simulation and studies show a likely tendency for the injected water to be concentrated in the eastern portion of the gas cap where it is more likely to improve oil recovery from up dip oil zone waterfloods already in progress or planned. In addition, model studies have consistently shown that water will move in a piston-like way through the gas cap, regardless of heterogeneities. Therefore, sweep efficiency of the process will be high and the water should move downdip slowly. GCWI is a recovery technique, which, though well studied, is untried at Prudhoe Bay. Despite the lack of precedents, risks to hydrocarbon reserves can be controlled. The WIOs have designed a process and outlined overall surveillance plans that should minimize losses and ensure greater ultimate hydrocarbon recovery. 11. Blowout Prevention Equipment and Practice The provisions of Rule 4 of CO 341 C are obsolete and inconsistent with current Commission regulations as stated in 20AAC 25 and current North Slope operator practice. CO 341D November 30,2001 . . Page 8 CONCLUSIONS: 1. The application requirements of20 AAC 25.520 have been met. 2. The GCWI project is expected to significantly increase overall hydrocarbon recovery from the Prudhoe Bay Oil Pool. 3. The GCWI project will mitigate pressure decline within the Prudhoe Bay Oil Pool. 4. With the planned implementation of GCWI, further investigation of options to mitigate pressure decline and annual report of these investigations is no longer necessary. 5. Further implementation of paragraph (d) of Rule 12, is unnecessary so long as the GCWI project is in operation. 6. Decreasing the minimum pressure differential requirement of Paragraph (c) of Rule 12 from 250 psi between the minimum miscibility pressure and the average reservoir pressure in the EOR injection areas will allow the Operator flexibility to provide more MI volume, and will not negatively impact recovery. Potential for increased rate and recovery exists through optimization of the MI injectant. 7. Adequate surveillance of the GCWI project is required to determine that water movement within the reservoir is confined as intended and does not negatively impact overall hydrocarbon recovery, and to determine if the project is successful in stabilizing reservoir pressure. 8. The Commission needs to be apprised of surveillance plans and results on a yearly basis. 9. The conclusions in CO 341 C and the amendments thereto are incorporated herein to the extent not inconsistent with this order. 10. Rule 4 of CO 341C is no longer current and has been superseded by 20 AAC 25.035, 25.036,25.037,25.285,25.286,25.287, and 25.288. CO 341D November 30,2001 . . Page 9 NOW, THEREFORE, IT IS ORDERED THAT (1) Conservation Order 341D supersedes Conservation Order 341C dated June 12, 1997; (2) Rule 4 of Conservation Order No. 341C is revoked, Rules 11,12, and 16 are amended, and new Rule 17 is added; and (3) In addition to statewide requirements under 20AAC 25 (to the extent not superseding these rules), the following rules now apply to the Prudhoe Oil Pool within the following described area (referred to in this order as the affected area): UMIAT MERIDIAN Township Range T. ION., R. 12E., Section 1,2,3,4,10,11,12 T. ION., R. BE., 1,2,3,4,5,6, 7,8,9, 10, 11, 12, 13, 14, 15, 16,24 T. ION., R. 14E., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18,19,20,21,22,23,24,25,26,27,28,36 T. ION., R. 15E., T. ION., R. 16E., T. llN., R. lIE., T. IIN., R. 12E., T. llN., R. BE., T. llN., R. 14E., T. llN., R. 15E., T. IIN., R. 16E., T. 12N., R. 10E., T. 12N., R. lIE., all 5,6,7,8,17,18,19,20,29,30,31 1,2,3,4,9, 10, 11, 12, 13, 14, 15,24,25 all all all all 17, 18, 19,30,31,32 13,24, 15, 16, 17, 18, 19, 20, 21, 22, 25, 26, 27, 28, 29, 30, 32,33,34,35,36 T. 12N., R. 12E., 23,24,25,26,27,28,29,30,31,32,33,34,35,36 T. 12N., R. BE., 19,20,21,22,23,26,27,28,29,30,31,32,33,34, 35,36 T. 12N., R. 14E., 25,26,27,28,29,31,32,33,34,35,36 CO 341D November 30, 2001 . . Page 10 T. 12N., R. 15E., 25,26,27,28,29,30,31,32,33,34,35,36 (Source: C. O. 145, page 7, expansions/contractions of initial participating area based on November 20, 1987 letter, Wade and Nelson to Eason, Re: Prudhoe Bay Unit Exhibits, Exhibit C, Part I Oil Rim Participating Area and Part II Gas Cap Participating Area.) Rule 1 Pool Defmition and Chan2Ïn2 the Affected Area (ref. C.O. 145) (a) The Prudhoe Oil Pool is defined as the accumulations of oil that are common to and which correlate with the accumulations found in the Atlantic Richfield - Humble Prudhoe Bay State No.1 well between the depths of 8, 11 0 feet and 8,680 feet. (Source: C.O. 145, Rule 1) (b) The Commission may adjust the description of the affected area to conform to future changes in the initial participating area by administrative approvaL (Source: C. O. 145, Rule 12) Rule 2 Well Spacin2 (ref. C.O. 145, 174) There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. (Source: C.O. 174, Rule 2) Rule 3 Casin2 and Cementin2 Reauirements (ref. C.O. 145,238) (a) Conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. Rigid high-density polyurethane foam may be used as an alternate to cement, upon approval by the Commission. The Commission may also administratively approve other sealing materials upon application and presentation of data which show the alternate is appropriate based on accepted engineering principles. (Source: C.O. 238, Rule 3a) (b) Surface casing to provide proper anchorage for equipment, to prevent uncontrolled flow, to withstand anticipated internal pressure, and to protect the well from the effects of permafrost thaw-subsidence or freeze-back loading shall be set at least 500 feet, measured depth, below the base of the permafrost but not below 5000 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. The surface casing shall have minimum axial strain properties of 0.5% in tension and 0.7% in compression. (Source: C.O. 238, Rule 3b) (c) Alternate casing programs may be administratively approved by the Commission upon application and presentation of data, which show the alternatives, are appropriate, based upon accepted engineering principles. (Source: C.O. 238, Rule 3c) CO 34ID November 30, 2001 . . Page 11 Rule 4 Blowout Prevention Eauipment and Practice (revoked c.o. 341D). Rule 5 Automatic Shut-in Eauipment (ref. C.O. 145,333,363) (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead and shutting down any artificial lift system where an over pressure of equipment may occur. (b) The safety valve system (SVS) shall not be deactivated except during repairs, while engaged in active well work, or if the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the well head and at the manifold building. 1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. 2. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated re-activation dates must be maintained current and available for Commission inspection on request. (c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS is in proper working condition. (d) The SVS must be maintained in working condition at all times unless the well is shut in and secured, or the well is being operated in conformance with other sections of this rule. ( e) Upon proper application or its own motion, the Commission may administratively waive or amend the requirements of this rule as long as the change does not promote waste, jeopardize correlative rights or compromise ultimate recovery, and is based on sound engineering principles. (t) Nothing in this rule precludes the installation of a SSSV in wells designated by the operator. If a SSSV is installed, it must be maintained in working order and is subject to performance testing as part ofthe SVS. Rule 6 Pressure Surveys (ref. C.O. 145, 165, 192,208,213,220, AA 220.1, 341B) (a) Prior to regular production, a static bottom hole or transient pressure survey shall be taken on at least one in three wells drilled from a common drilling site. (Source: C.O. 220, Rule 1, C.O. 341B) CO 341D November 30,2001 . . Page 12 (b) An annual pressure surveillance plan shall be submitted to the Commission in conjunction with the Annual Prudhoe Pool Reservoir Surveillance Report by April 1, each year. The plan will contain the number of pressure surveys anticipated for the next calendar year and be subject to approval by the Commission by May 1. These surveys are needed to effectively monitor reservoir pressure in the Prudhoe Oil Pool. The surveys required in (a) of this rule may be used to fulfill the minimum requirements. (Source: C.O. 220, Rule 6, C.O. 341B) (c) Data from the surveys required in (a) and (b) ofthis rule shall be submitted with the Annual Prudhoe Oil Pool Reservoir Surveillance Report by April 1 each year. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8800 feet subsea. Transient pressure surveys obtained by a shut in buildup test, an injection well pressure fall-off test, a multi rate test or an interference test are acceptable. Other quantitative methods may be administratively approved by the Commission. (Source: C.O. 220, Rule 7, C. O. 341C.001) (d) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (c) of this rule. (Source: C.O. 220, Rule 8) (e) By administrative approval the Commission may grant time extensions and waive requirements of this rule, and by administrative order the Commission may require additional pressure surveys in (b) of this rule. (Source: C.O. 220, Rule 5) Rule 7 Gas-Oil Contact Monitorini! (ref. C.O. 145, 165, 192,208,213, AA 213.39) (a) Prior to initial sustained production, a cased or open hole neutron log shall be run in each well. (Source: C.O. 165, Rule 9a) This requirement is waived for waterfloodlEOR areas encompassed by the expanded Prudhoe Bay Miscible Gas Project outlined in C.O. 290, and for those areas not expected to have significant GOC movement or gas encroachment from the gravity drainage area defined by the Commission through Administrative Approval. (Source: AA 213.39, excerpts from paragraph 1) (b) A minimum of 40 repeat cased hole neutron log surveys shall be run annually. (Source: C.O. 208, Rule 4) (c) The neutron logs run on any well and those required in (a) and (b) of this rule shall be filed with the Commission by the last day of the month following the month in which the logs were run. (Source: C.O. 165, Rule 9d) (d) By administrative approval, the Commission may delay, modify or waive the logging requirements of this rule or may require additional wells to be logged. (Source: C.O. 213, Rule 3) CO 341D November 30, 2001 . . Page 13 Rule 8 Productivity ProfIles (ref. C.O. 145, 165, 192,208,213, AA 213.40) (a) A spinner flow meter or tracer survey shall be run in each well during the first six months the well is on production. (Source: C.O. 165, Rule lla) This requirement is waived for wells completed with a single perforated interval, or with perforations in a single reservoir zone including highly deviated (greater than 65 degrees) and horizontal wells. (Source: AA 213.40 paragraph 3) (b) Follow-up surveys shall be performed on a rotating basis so that a new production profile is obtained on each well periodically. Nonscheduled surveys shall be run in wells which experience an abrupt change in water cut, gas-oil ratio, or productivity. (Source: e.O. 165, Rule lIb) (c) The complete spinner flow meter or tracer data and results shall be recorded and filed with the Commission by the last day of the month following the month in which each survey is taken. (Source: C.O. 165, Rule llc) (d) The Commission may administratively approve alternate methods and time periods in the enforcement of this rule provided that the data obtained is appropriate for monitoring the Prudhoe Oil Pool or may waive the requirements of (a), (b) and (c). By administrative order the Commission may specify additional surveys other than the surveys submitted under (a), (b) and (c) ofthis rule. (Sources: C.O. 208, Rule 8 and c.o. 213, Rule 2) Rule 9 Pool Off-Take Rates (ref. c.o. 145,214) The maximum annual average oil offtake rate is 1.5 million barrels per day plus condensate production. The maximum annual average gas offtake rate is 2.7 billion standard cubic feet per day, which contemplates an annual average gas pipeline delivery sales rate of 2.0 billion standard cubic feet per day of pipeline quality gas when treating and transportation facilities are available. Daily offtake rates in excess of these amounts are permitted only as required to sustain these annual average rates. The annual average offtake rates as specified shall not be exceeded without the prior written approval of the Commission. Annual average offtake rates mean the daily average rate calculated by dividing the total volume produced in a calendar year by the number of days in the year. However, in the first calendar year that large gas offtake rates are initiated, following the completion of a large gas sales pipeline, the annual average offtake rate for gas shall be determined by dividing the total volume of gas produced in the calendar year by the number of days remaining in the year following initial delivery to the large gas sales pipeline. Rule 10 Facilitv Gas Flarin2 revoked (ref. C. O. 34lC) CO 341D November 30,2001 . . Page 14 Rule 11 Annual Surveillance Reportinf! (ref. C.O. 165, 186, 195, 208, 223, 224, 279, AA 279.1) (a) An annual Prudhoe 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 project(s) implementation and reservoir management summary including engineering and geotechnical parameters. 2. Voidage balance by month of produced fluids, oil, water and gas, and injected fluids, gas, water, low molecular weight hydrocarbons, and any other injected substances (which can be filed in lieu of monthly Forms 10-413 for each EOR project). (Source C.O. 279, Rule 7 and AA 279.1 excerpt from paragraph 3) 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. 5. Results of gas movement and gas-oil contact surveillance efforts including a summary of wells surveyed and analysis of gas movement within the reservoir. The analysis shall include map(s) and/or tables showing the locations of various documented gas movement mechanisms as appropriate. (Source: C.O. 279, Rule 7) 6. Progress of the Gas Cap Water Injection project with surveillance observations including; (a) volume of water injected, (b) reservoir pressure results, maps, and analysis (in conjunction with (a) 3 of this rule), (c) water movement and zonal conformance maps derived from surveillance (such as Pulsed Neutron Logs and 4-D gravity surveys) (d) results of reservoir evaluations of performance (such as material balance and reservoir simulation studies), ( e) surveillance plans for the upcoming year, and (f) any plans for change in project operation. (b) Upon its own motion or upon written request, the Commission may administratively amend this rule so long as the change does not promote waste nor jeopardize correlative rights and is based on sound engineering principles. (Source: C.O. 279, Rule 8) Rule 12 Prudhoe Bay Miscible Gas Proiect lPBMGP) (ref. C.O. 195,290) (a) Expansion of the PBMGP and infill expansion of miscible gas injection in the NWFB is approved for the 59,740 acre portion of the Prudhoe Oil Pool defmed in CO 341D November 30, 2001 . . Page 15 the record. (Source: C.O. 290, Rule 1, AA 290.1) (b) An annual report must be submitted to the Commission detailing performance of the PBMGP and outlining compositional information for the current miscible injectant (MI) necessary to maintain miscibility under anticipated reservoir conditions. (Source: C.O. 290, Rule 2) (c) The minimum miscibility pressure (MMP) of the Miscible Injectant must be maintained at least 100 psi below the average reservoir pressure in the Prudhoe Bay Miscible Project area. When the Operator demonstrates that the reservoir pressure is no longer declining within the Prudhoe Bay Miscible Project Area (as evidenced by reservoir pressure measurements), the MMP may be maintained at or below the average reservoir pressure in the Prudhoe Bay Miscible Project area. (Source: C.O. 290, Rule 4; amended C.O. 341D) (d) Revoked (e.O. 341D). ( e) Upon its own motion or upon written request, the Commission may amend this rule by administrative action if the change does not promote waste, violate correlative rights, nor jeopardize ultimate recovery, and is based on sound engineering principles. (Source: e.O. 290, Rule 6) Rule 13 Waiver of GOR Limitation (ref. 8/22/86 letter) The Commission waives the requirements of 20 AAC 25.240(b) for all oil wells in the Prudhoe Oil Pool of the Prudhoe Bay Field so long as the gas from the wells is being returned to the pool, or so long as the additional recovery project is in operation. (Source: Letter 8/22/86, L. Smith to HeinzelNelson, paragraph 3) Rule 14 Waiver of "Application for Sundry Approval" Reauirement for Workover Operations (ref. C.O. 258) The requirements of 20 AAC 25.280(a) are waived for development wells in the Prudhoe Oil Pool of the Prudhoe Bay Field. (Source: C.O.258) Rule 15 Waterfloodine: (ref. 3/20/81 letter Hamilton to NelsonINorgaard) The commission approves the December 1980 additional recovery application for water- flooding in the Prudhoe Oil Pool subject to the requirements listed in Rule 11 above. Any proposed changes must be submitted to the Commission for approval. (Source: Letter 3/20/81, Hamilton to NelsonINorgaard) CO 341D November 30, 2001 . . Page 16 Rule 16 Orders Revoked The following Conservation Orders and associated Administrative Approvals and letter approvals are hereby revoked. Conservation orders 78, 83B, 85, 87, 88, 96, 97, 98B, 117, 117 A, 118, 130, 137, 138, 139, 140, 141, 143, 145, 145A, 148, 155, 160, 164, 165, 166, 167, 169, 174, 178, 180, 181, 183, 184, 185, 186, 188, 189, 192, 194, 195, 195.1, 195.2, 195.4, 197, 199,200,204,208,213,214,219,220,223,224,238, 258, 259, 279, 290 and 333, 341, 341A, 341B, 341C, and March 20, 1981 and August 22, 1986 letter approvals. The hearing records of these orders are made part of the record for this order. Rule 17 Gas Cap Water Iniections The Gas Cap Water Injection Project as described in the operator's application and testimony is approved. Ongoing reservoir surveillance is required to determine that water movement within the reservoir is confined as intended and does not negatively impact overall hydrocarbon recovery, and to determine that the project has resulted in stabilization of reservoir pressure. DONE at Anchorage, Alaska and dated November 30, 2001. {þ. ~..J~ Cammy ~i Taylor, Chair Alaska Oil and Gas Conservation Commission an e . Se nt, Jr., Commissioner Alaska OiLand 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 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., lOth day after the application for rehearing was filed). Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules July 29, 2005 DEVELOPMENT [PRODUCTION] WELLS No Forms Re uired 1 Form Required 2 Forms Required -10-403 Not Required -10-404 Not Required -10-403 Not Required -10-404 / 407 or other form Required -10-403 Required -10-404 / 407 or other form Required Thru-tubing Operations (D) Thru-tubing Operations (D) Thru-tubing Operations (D) • Fill tag • Permanent cement or mechanical plugs that • Perforate anew pool (D) • Set & pull retrievable plugs do not completely abandon a zone. (D) • Change GLV's • Cutting off tailpipes. (D) • Dummy & gauge ring runs • Perforate new intervals within a pool (D) • Pull &rerun SSSV's • ) ( Patches D SPECIAL (D) • Pressure surveys — unless required by On a case -by -case basis, a 10-403 will be some specific approval required for a particular well or operation • Temperature surveys —unless required by if the Commission requests it. some specific approval • Caliper surveys If a well is operating under a sundry • Reperforating existing intervals approval, a 10-403 may be required to • Bottom hole samples perform work. The operator should • Spinner surveys consult with the AOGCC to determine if • Logs — CNL, TDT, CO, CCL, CBL and a 10-403 is needed. Other Types — Unless required by some specific approval • Pump changes. • Packoff GLM (POGLM) Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 Page I of 5 Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules July 29, 2005 DEVELOPMENT [PRODUCTION] WELLS Nn Fnrmq Reauired 1 Form Reauired 2 Forms Required -10-403 Not Required -10-403 Not Required -10-403 Required -10-404 Not Required -10-404 / 407 or other form Required -10-404 / 407 or other form Required Pumping Operations, including using coil.(D) Pumping Operations, including using coil. Pumping Operations, including using coil • Tubing scale removal • Stimulations (frac or acid) (D) • Remedial cementing operations • Sludge removal • Remedial cementing operations (including but not limited to) • Freeze protection o Conductor Fill (D) o Casing shoes (outer annulus) (D) • Ice plug removal • Squeezes/plugs to control fluid • Repair casing • Inhibitor squeezes movement in zone (D) (including but not limited to) • Hot Oil o mechanical repairs (D) • Tubing acid jobs o "pumping" repairs (cement or gel squeezes) (D) • Fill clean out Other Operations (D) Other Operations Other Operations • Xmas tree & valve replacement • Seal welding on bradenheads (D) • Convert producer (D) to injector • Diagnostic & pressure testing — unless • Major welding repairs on wellheads required by some specific approval (D) • Conductor "cutaways" and surface casing welding repairs (D) • Annular disposal (D) (Reported on form 10-423) Rig/Coil Operations Rig/Coil Operations • Alteration of mechanical completion • Repair Casing (including but not limited to) (including but not limited to) o Pulling tubing, milling packers (D) o Mechanical repairs (D) o Install velocity strings (D) (scab liners, tiebacks, etc) Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 Page 2 of 5 Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules July 29, 2005 SERVICE [INJECTION] WELLS N F R d 1 Form Re uired 2 Forms Required 0 orms a uire -10-403 Not Required -10-404 Not Required -10-403 Not Required -10-404 / 407 or other form Required -10-403 Required -10-404 / 407 or other form Required Thru-tubing Operations (S) Thru-tubing Operations (S) Thru-tubing Operations (S) • Fill tag • Perforate new interval within a pool (S) • Perforate a new pool. (S) • Set & pull retrievable plugs • Permanent cement or mechanical • Change GLV's plugs that do not completely abandon • Dummy & gauge ring runs a zone (S) • Pull & rerun SSSV's • Patches (S) • Pressure surveys — unless required by • Cutting off tailpipes. (S) some specific approval • Temperature surveys — unless required by SPECIAL {S) some specific approval • Caliper surveys On a case -by -case basis, a 10-403 will be • Reperforating existing intervals required for a particular well or operation • Bottom hole samples if the Commission requests it. • Spinner surveys • Logs — CNL, TDT, CO, CCL, CBL and If a well is operating under a sundry Other Types — Unless required by some approval, a 10-403 may be required to specific approval perform work. The operator should consult with the AOGCC to determine if a 10-403 is needed. If operations in this column are planned on a A 10-403 should be submitted for any Please note that authorization from EPA disposal well, the operator should contact the perforating (new or reperf) operations on a Region 10 may be necessary to perform an AOGCC to determine if a 10-403 is needed. Class II disposal well. work on a Class I disposal well. Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 Page 3 of 5 Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules July 29, 2005 No Forms Required -10-403 Not Required -10-404 Not Required Pumping Operations, including using coil.(S) • Tubing scale removal • Sludge removal • Freeze protection • Ice plug removal • High pressure breakdown or inhibitor squeezes, excluding frac or acid jobs • Hot Oil • Tubing acid jobs • Fill clean out Other Operations (S) • Xmas tree & valve replacement • Diagnostic & pressure testing — unless required by some specific approval SERVICE [INJECTION] WELLS 1 Form Required -10-403 Not Required -10-404 / 407 or other form Require Pumping Operations, including using coil. • Remedial cementing operations o Conductor Fill (S) • Squeezes/plugs to control fluid movement in zone (S) Other Operations • Injection well MIT (on MIT form) (S) • Initial conversion from water injector to WAG injector (S) • Convert from injector to producer if for more than 30 days. (S) • Seal welding on bradenheads (S) L norms Kequirect -10-403 Required -10-404 / 407 or other form Required Pumping Operations, including using coil. • Stimulations (frac or acid) (S) • Remedial cementing operations (including but not limited to) o Casing shoes (outer annulus) (S) • Repair casing (including but not limited to) o mechanical repairs (S) o "pumping" repairs (cement or gel squeezes) (S) Other Operations • Major welding repairs on wellheads • Conductor "cutaways" and surface casing welding repairs (S) • Annular disposal (S) (Reported on form 10-423) Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 Page 4of5 Well Work Operations and Sundry Notice/Reporting Requirements for Pools Subject to Sundry Waiver Rules July 29, 2005 Rig/Coil Operations • Alteration of mechanical completion (including but not limited to) o Pulling tubing ,milling packers (S) • Repair Casing (including but not limited to) o Mechanical repairs (S) (scab liners, tiebacks, etc) Attachment Incorporated by reference into Conservation Orders 261 A, 297 A, 341 D Rule 14, 347 A, 351 A and 556 Page 5 of 5 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, SO 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY. MO 64110-2498 XTO ENERGY, SUSAN lILL Y 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 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 71001-0574 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 71002-8844 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, LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 IOGCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 BAP! RAJU 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 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON. TX 77010 . ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US 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 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 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 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, GARY M ROBERTS RM 3039 PO BOX2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 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 105070 W MAPLEWOOD DR LITTLETON, CO 80127 C & R INDUSTRIES, INC... KURT SAL TSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 e GAFFNEY, CLINE & ASSOC., INC., LIBRARY 1360 POST OAK BLVD., STE 2500 HOUSTON, TX 77056 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 PO BOX 4813 HOUSTON, TX 77210 EXXON EXPLOR CO, LAND/REGULATORY 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, J W KIKER ROOM 2086 POBOX 2180 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 e MURPHY EXPLORATION & PRODUCTION CO., BOB SAWYER 550 WESTLAKE PARK BLVD STE 1000 HOUSTON, TX 77079 UNOCAL, REVENUE ACCOUNTING PO BOX 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 NRG ASSOC. RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 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 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 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, ID 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 W4THAVE,STE2 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 e 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 NORTH RIDGE, 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 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE. AK 99501 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 ALASKA DEPT OF LAW. ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 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 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 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 DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 UON ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD 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 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 AND ENG SERVICE, MIKE TORPY 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICNCANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 US BLM AK DIST OFC, GEOLOGIST ARTHUR BANET 949 EAST 36TH AVE STE 308 ANCHORAGE, AK 99508 e 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 JIM STOUFFER 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 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 N-I TUBULARS INC, 3301 C Street Ste 209 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 PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 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 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, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH AV 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 e GORDONJ.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 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE. AK 99518 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 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 SHAVELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI. AK 99611-1468 PENNY VADLA POBOX 467 NINILCHIK, AK 99639 e e OPST AD & 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 CONSULT 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 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, INF( RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 M/S 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 PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS1701 VALDEZ,AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DE VEL 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 POBOX 98 VALDEZ, AK 99686-0098 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 C BURGLlN POBOX 131 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 e VALDEZ PIONEER, POBOX 367 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERI NG 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 BOX 416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 , . . ,. fl I' d Lb ~ FRANK H. MURKOWSKI, GOVERNOR AI.ASIiA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 207.17 ADMINISTRATIVE APPROVAL NO. 311B.01 ADMINISTRATIVE APPROVAL NO. 329A.01 ADMINISTRATIVE APPROVAL NO. 341D.01 ADMINISTRATIVE APPROVAL NO.345.01 ADMINISTRATIVE APPROVAL NO. 452.01 ADMINISTRATIVE APPROVAL NO. 457A.01 ADMINISTRATIVE APPROVAL NO. 471.01 ADMINISTRATIVE APPROVAL NO. 484.01 George Blankenship GPB Field Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Blankenship: Conservation Order No. 492, dated June 26, 2003, amended the conservation orders adopting pool rules for all pools within the Prudhoe Bay field to add rules addressing sustained annulus pressures in devel- opment wells. Upon further review, the Commission has determined that paragraph 6 of these annulus pressure rules should be clarified. Paragraph 6 provides that before a shut-in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree that specified annulus pressures at operating temperature will not be reached or exceeded. However, paragraph 3 of the annulus pressure rules contemplates that there may be wells that can be safely operated with an annu- lus pressure in excess of a maximum specified in paragraph 6, and in such cases it would not be practicable or meaning- ful to relieve annulus pressure to the degree required under paragraph 3 when placing a shut-in well in service. In addi- tion, the Commission may approve different pressure limits for well start-up on a case-by-case basis under paragraphs 4 and 5. Go:' <0,/ L\,''''~E'J\ r 'Uf' r, l" 2nO*) ø~H~~j'ìl .L., A l'J n .) ),1 t' July 29,2003 Page 2 of2 Accordingly, Conservation Orders No. 207, 311B, 329A, 341D, 345,452, 457A, 471, and 484 are amended to replace paragraph 6 of the annulus pressure rules adopted in Conservation Order No. 492 with the following revised paragraph 6: . . I 6. Except as otherwise approved by the AOGCC under para- graph 4 or 5 of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree (a) that the inner annulus pressure at operating temperature will be below 2500 psig for wells processed through the Lisburne Production Center and below 2000 psig for all other development wells, and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3, but not paragraph 5, of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. DATED at Anchorage, Alaska and dated July 29, 2003. fiG/< ,~, ,¡;;" BY ORDER OF THE COMMISSION #14 • Katrina Garner, P.E. Base Management Manager March 31, 2014 ,RECEWPo APR 0 2 2014 BP Exploration (Alaska) Inc. P.O. Box 196612 900 E Benson Boulevard Anchorage AK 99519-6612 UNITED STATES OF AMERICA Alaska Oil and Gas Conservation Commission 333 W. 7jh Avenue, Suite 100 Phone:+1-907-230-4212 Anchorage, AK 99501-3539 Re: Conservations Order CO 45713.003 and CO 341 D.005 for well S-26 (commingled production) Dear Commissioners, In a letter dated September 30, 2013 (copy enclosed) BP Exploration (Alaska) Inc. (BPXA) reporteda lapse in our special reporting requirements under the above -referenced Conservation Orders on well S-26, with a recommended action plan to address the allocation issues. We have completed a review of the situation and report the following. All collected samples have been analysed and we have back -calculated the impact of misallocation between the zones. The total discrepancy of 15,857 bbl was allocated to the Kuparuk that should have been allocated to the Ivishak. A plot of daily average daily production for the Aurora field is shown below with both the previously -reported splits (red) and the new correct splits (blue). • 0 Page 2 —+—Avg Daily Aurora Production 350 7 i 300 250 150 100 - N Daily Avg on 47% Aur Split 50 0 F+ N A 01 V l0 Y Y N �a lJU V 06 !-+ Y Y W to O1 00 Y Y Y W Ql N N N N O N tD Y v Qo v (n O N N O N \ p N \ N N N p N N N \ N C Y O O W O O O N O Y coo N coo Y O O O N C Y Y Y 1- O Y Y Y Y Y Y Y Y N N N N Y N W W W W W Y ja Y N W To prevent future misallocations, we have established an automated reminder system to ensure the samples are collected in a timely manner and properly allocated between the oil pools. Please contact the Base Management Team Leader for the West End Area, Werner Schinagl, or myself with any questions regarding this matter. Respectfully, Katrina Garner, P.E. Base Management Manager Attachments: Letter dated September 30, 2013 #13 Katrina Garner, P.E. Base Management Manager September 30, 2013 RECEIVED • OCT 0 2 2013 AOGCC 5 4 0 BP Exploration (Alaska) Inc. P.O. Box 196612 900 East Benson Boulevard Anchorage, Alaska AK 99519.6612 UNITED STATES OF AMERICA Phone: +1.907.230.4212 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Re: Conservation Order CO 457B.003 and C0341 D.005 for well S-26 (commingled production) Dear Commissioners, BPXA recently discovered a lapse in our special reporting requirements under CO 457B.003 and CO 34D.005 on well S-26. This well is a commingled producer completed in the Prudhoe Oil Pool and the Aurora Oil Pool. Your letter dated November 27, 2007 requires geochemical sampling every 6 months and not less frequently than every 7 months. Our last update of the allocation factors is dated May 3, 2010. Samples have been taken since then as follows: • February 21, 2011 • January 2, 2012 • June 22, 2012 • January 2, 2013 • June 26, 2013 (two samples) The delay from May 3, 2010 to February 21, 2011 resulted from the well being shut in between October 5, 2010 and February 16, 2011. Unfortunately, we did not take a sample between February 2011 and January 2012, The analysis of the samples taken is being performed now. I have asked the team responsible for the West End Area to implement the following plan: • Analyze all samples • Ensure samples are taken at the required intervals • Back -calculate any amount of impact due to potential misallocation between the zones • Update the allocation on a point -forward basis • • Page 2 I will keep you informed about any impact of misallocation between the different oil pools as well as on progress of the plan outlined above. Please contact the Base Management Team Leader for the West End Area, Werner Schinagl, or myself with any questions regarding this matter. Respectfully, zt/Vr�.P/L- Katrina Garner, P. E. Base Management Manager #12 0 • T SITATE DEF AELASEA SEAN PARNELL, GOVERNOR CONSERVATION ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMI'IISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 June 27, 2011 Dave Norton, P.E. Manager, Engineering Alaska Gasline Development Corporation PO Box 101020 Anchorage, Alaska 99510 Re: Gas Off -take for Instate Gas Pipeline Dear Mr. Norton: Thank you for the update regarding the in -state gas pipeline project. As to your inquiry regarding gas offtake rates, in 1977 the Prudhoe Bay Field rate was set, by Rule 9 of Conservation Order 341D, at a total of 2.7 billion standard cubic feet per day. Due to the reservoir's development, additional information and the passage of time, in 2005 the Commission initiated an investigation into the need to update Rule 9. On July 10, 2007, the Commission determined "no change in Rule 9 is necessary at this time." Therefore, given the parameters of your inquiry, an offtake of a half billion standard cubic feet per day would be authorized under Rule 9. .� - el, a i o • ► . Norman om ' sioner cc: Commissioner Daniel T. Seamount, AOGCC Commissioner Cathy P. Foerster, AOGCC *11 • • ALASKA ** RECEIVED * ASUNE * * * DEVELOPMENT CORP. Alaska Oil & Cons. Commission GAS FOR BLNSKNNS Anr13eraGc May 24, 2011 Alaska Oil and Gas Conservation Commission Attn: Cathy Foerster 333 W. 7 Ave., Ste 100 Anchorage, AK. 99501 Subject: Gas Off -Take For Instate Gas Pipeline Dear Commissioner Foerster: As you know from our briefing with you last June we are developing a project plan for an in -state gas pipeline that will deliver gas to Fairbanks and Southcentral Alaska. We have developed the plan to the point where we wish to clarify with the Commission the availability of a gas off -take rate. We currently envision first gas into our pipeline from the Prudhoe Bay Unit 2019 ramping up to about 500 MMscf /day by 2020. Based on this information please advise us what, if any, orders or regulatory actions would be taken by the Commission before gas off -take could commence. We wish to include your guidance in our report due July 1, so we would appreciate your response by June 15. Sincerely your. / 4. Dave Norton, P.E. Manager, Engineering cc: Dan Fauske A L A S K A G A S L I N E D E V E L O P M E N T C O R P O R A T I O N P.O. Box 101020 Anchorage, Alaska 99510 1 411 West Fourth Avenue, Suite 1E, Anchorage 99501 Tel. 907 - 277 -4488 1 Fax 907 - 277 -4484 1 www.gasline.us.com 310 bp • RECEIVED /R 2 9 ZOOS Alaska Oil & Gas Cons. Commission John Norman Anchor *. Alaska Oil and Gas Conservation Commission 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 RE: Conservation Order 457B (Rule 13) and Conservation Order 341D (Rule 18) — Commingled production from the Aurora Oil Pool and Prudhoe Oil Pool in Well S -26 Dear Chairman Norman, As set forth in Alaska Oil and Gas Conservation Commission's Conservation Orders 457B and 341D (as amended), BP Exploration (Alaska) Inc. has complied with the commingled production of the Aurora Oil Pool (AOP) and the Prudhoe Oil Pool (POP) within well S -26 to determine a reliable and acceptable production allocation method. Over the course of the six month commingled test period (August 20, 2008 through February 20, 2008) BP has fulfilled the Commission's requirements in obtaining Production Profiles, Static Bottom Hole Pressure Surveys, Geochemical Samples and Well Tests. The results of the collected surveillance data are included in this letter. Please call either of us or Danielle Ohms 564 -5759 (POP) or Pat Collins at 564 -4363 (AOP) if you have any questions or wish to discuss further. Sincerely, rank Paskv % Scott 'gent Resource Manager, GPB West Resource Manager, GPB Waterflood Attachment 1: OilTracers Report No. 09 -826 (CONFIDENTIAL) Attachment 2: Schlumberger PL Advisor for S -26 10 -10 -08 PPROF Attachment 3: Schlumberger PL Advisor for S -26 2 -16 -09 PPROF 1 • History of S -26 S -26 was originally drilled and completed as a Prudhoe producer in 1990. Zone 4 Stimulations, including both frac and acid treatments, were performed in 1991 and 1992 to maximize production. By late 2007, S -26 was producing 200 to 250 bopd at approximately 75% watercut and 6000 GOR from the Prudhoe Oil Pool. Well S -26 penetrates the AOP and POP in areas where well rates from both Pools are low. A stand alone Aurora producer in this area could not be justified due to the expected low rates and associated problems with paraffin and hydrate deposition. A RWO to commingle production from the two pools within the S -26 well -bore was planned to maximize oil production from the two oil pools. Prudhoe production was isolated on 12- 15 -07. A RWO to recomplete and enable Aurora production was completed in January 2008. Aurora perfs were added and an initial Aurora only SBHP was obtained on 4 -3 -08. The Aurora reservoir pressure at this time was 3615 psi. The well was put on production on 4 -4 -08 though total fluid rates were low and the well was SI on 4 -7 -08. An Aurora only frac placed approximately 188,000# proppant in the formation on 5/12/08. S -26 was put on production again on 5 -16 -08 with significantly increased production rates post frac from the Aurora only. Plugs were drilled out to re -open the Prudhoe on 8- 17 -08. Commingled production began on 8- 20 -08; it has remained commingled since. The commingling of the Prudhoe and Aurora pools has shown to have a positive impact on oil production from S -26. The Aurora oil production to date from S -26 is 183,500 bbls. The total incremental commingled oil rate from S -26 (over 2007 Ivishak only production) is approximately 600 bopd. Results Obtained from Commingled Test During the course of the commingled testing period, two production profiles using Schlumberger's DEFT and GHOST tool, 7 geochemical samples, and 19 welltests were gathered to assess performance of the Prudhoe and Aurora. PL Advisors interpreting the oil/ water and gas splits between the pools were performed by Schlumberger, and were completely independent from the oil Geochemical analysis performed by Oil Tracers L.L.C. Neither were privy to the other's analysis or results. Both the PL Advisors and the Oil Geochemical Report reference the Ivishak layer of the Prudhoe Oil Pool, so please note that reference to the Ivishak and Prudhoe are meant to represent the same oil. The PL Advisor reports from Schlumberger are included in the Appendix. A summary of the Production Profile logging of the Aurora and Prudhoe Oil Pools in S -26 is shown in Table 1. Oil % Water % Gas % Aurora 10/10/2008 51 16 35 2/16/2009 55 34 26 Prudhoe 10/10/2008 49 84 65 2/16/2009 45 66 74 Table 1. S -26 Aurora/Prudhoe PPROF Results Monthly geochemical samples were collected over the commingled test period and results are shown in Table 2. Separate end member samples of the Prudhoe oil (9/3/07 sample) and the 2 • • Aurora oil (5 /19/08 and 5/20/08 samples), all from S -26, were used to determine commingled oil splits. The Geochemical report from Oil Tracers L.L.C. is included in the Appendix. Geochem % Geochem Prudhoe % Aurora Date Oil Oil 8/30/08 26.83 73.17 9/18/08 51.61 48.39 10/10/08 37.09 62.91 11/14/08 46.10 53.90 12/21/08 43.81 56.18 1/5/09 59.20 40.79 2/11 /09 47.01 52.99 Table 2. S -26 Aurora/Prudhoe Geochemical Analysis Results Reservoir pressures were obtained from the separate pools during the last period they were produced in isolation. While the Prudhoe reservoir pressure is higher than the Aurora at face value, if converted to the Aurora datum of 6700' TVDss assuming a water gradient of 0.44 the pressures are very similar. Table 3 below lists the results. Reservoir Oil Pool Date TVDss Pressure Prudhoe 9/23/2007 8800' 3223 psi Aurora 4/3/2008 6700' 3615 psi Table 3. Aurora and Prudhoe Reservoir Pressures Welltests were conducted over twice a month during the commingled test period, and at least once per month for the periods of individual Aurora and Prudhoe production. Prior to obtaining PPROF data, initial commingled spills were assessed and applied to allocated pool production based on separate zone tests. Using the 11/27/07 welltest as representative of Prudhoe only production and the 8/1/08 welltest as representative of Aurora only, initial splits were calculated and shown in Table 4. A summary of all welltests since 2007 is shown in Table 5. Oil % Water % Gas % Prudhoe split 38 94 63 Aurora split 62 6 37 Table 4. Initial Splits based on Separate Zone Tests 3 • a ►- x g re rt Well Date ' o " = O r 3 3 J J (! 3 (7 (7 V a u. 3 0 t7 1- S-26 3/22/2009 4 6 1358 602 756 1797 2986 94.8 222 104 55.7 3010 1305 3540 S -26 3/3/2009 4 6 1349 617 732 2197 3559 94.8 219 102 54.3 3080 1412 3912 S -26 2/18/2009 4 6 1668 792 876 6110 7712 94.9 257 98 52.5 3680 1800 5869 S -26 2/11/2009 4 6 1408 660 748 2092 3171 94.4 222 102 53.1 3060 1367 3659 S -26 2/7/2009 4 6 1408 652 756 2096 3215 94.4 219 102 53.7 3040 1357 3648 S -26 1/21/2009 4 6 1427 691 736 2055 2973 94.4 220 101 51.6 3070 1372 3591 S -26 1/5/2009 4 8 1689 906 783 2482 2740 55.5 495 108 46.4 3580 1614 3589 S -26 12/22/2008 4 6 1447 811 636 2361 2910 93.6 231 101 43.9 3510 1555 4057 S -26 12/19/2008 4 6 1514 866 648 2334 2695 93.6 230 103 42.8 3440 1525 3814 S -26 12/17/2008 4 6 1502 870 632 2385 2741 93.6 231 102 42.1 3480 1553 3905 S -26 11/25/2008 4 6 1506 870 636 2425 2788 93.7 234 103 42.2 3460 1520 3908 S -26 11/14/2008 4 6 1584 932 652 2573 2761 94.0 235 102 41.2 3520 1560 3847 S -26 10/31/2008 4 6 1497 901 596 2710 3009 92.7 228 103 39.8 3510 1548 4155 S -26 10/18/2008 4 6 1509 885 624 2750 3107 91.6 212 101 41.4 3420 1522 4089 S -26 10/4/2008 4 6 1713 937 776 2577 2751 91.7 197 107 45.3 1910 1008 2619 S -26 10/1/2008 4 6 2646 1378 1268 2569 1865 91.7 204 119 47.9 1630 975 1587 S -26 9/20/2008 4 6 1545 813 732 1815 2233 90.6 208 110 47.4 1510 883 2152 S -26 9/9/2008 4 8 1743 942 801 2208 2345 90.6 209 112 46.0 1530 921 2145 S -26 8/23/2008 4 6 2219 895 1324 3222 3599 91.2 240 119 59.7 2140 1198 2416 S -26 8/1/2008 4 6 799 719 80 1552 2157 90.6 219 74 10.0 2000 1033 4446 S -26 7/20/2008 4 6 697 653 44 1425 2182 90.6 217 72 6.3 2030 1009 4957 S -26 6/24/2008 4 6 790 722 68 1588 2200 89.3 210 80 8.6 1940 938 4466 S -26 6/6/2008 4 6 1085 989 96 1874 1896 92.4 214 82 8.9 2000 882 3571 S -26 5/21/2008 7 4 1630 1461 169 2320 1588 92.0 340 89 10.4 1400 1900 2282 S -26 5/21/2008 4 4 3145 1369 1776 2147 1569 44.8 205 74 56.5 1570 963 1182 S -26 4/5/2008 4 6 81 61 20 602 9938 94.8 189 72 24.8 1990 1338 32000 S -26 12/8/2007 4 6 898 194 704 1197 6183 94.7 211 106 78.4 1980 1456 3538 S -26 11/27/2007 4 6 909 197 712 1172 5943 94.7 218 103 78.3 1970 1225 3457 S -26 11/19/2007 4 6 916 220 696 1395 6335 94.7 208 104 76.0 2030 1226 3739 S -26 11/11/2007 4 6 941 217 724 1406 6496 94.7 205 103 77.0 2030 1239 3651 S -26 11/3/2007 4 6 978 198 780 1422 7200 94.7 197 105 79.8 2030 1244 3530 S -26 10/21/2007 4 6 961 205 756 1490 7270 59.7 288 105 78.7 2040 1307 3673 S -26 9/4/2007 4 6 1186 406 780 1425 3509 94.8 226 112 65.8 3270 1574 3959 S -26 8/12/2007 4 6 1224 288 936 1394 4841 95.0 219 116 76.5 2070 1296 2830 S -26 7/30/2007 4 6 929 201 728 1189 5928 95.0 229 112 78.4 2030 1172 3465 S -26 7/15/2007 4 6 866 242 624 1068 4415 95.0 237 107 72.1 2070 1241 3624 S -26 6/25/2007 4 6 940 212 728 1005 4748 95.0 242 105 77.5 2040 1243 3239 S -26 6/8/2007 4 6 848 216 632 976 4525 95.0 231 103 74.6 2060 1229 3580 S -26 6/1/2007 4 6 935 227 708 1155 5096 95.0 242 104 75.8 2060 1218 3439 S -26 5/9/2007 4 6 939 239 700 1104 4627 95.0 228 104 74.6 2020 1199 3327 S -26 4/21/2007 4 3 844 197 647 969 4931 95.0 236 104 76.7 2020 1103 3541 S -26 3/3/2007 4 4 909 213 696 1570 7379 94.9 245 99 76.6 2480 1263 4455 S -26 2/8/2007 4 4 802 244 558 1578 6475 94.9 244 94 69.6 2550 1267 5147 S -26 1/19/2007 4 4 804 222 582 1641 7404 94.9 224 100 72.4 2420 1237 5051 IPrudhoe only Welltests (Aurora only Welltests (Commingled Prudhoe and Aurora Welltests Table 5. S -26 Welltest Data The average oil rate over the 7 months of commingled tests shown in the welltest data table is 843 bopd. The initial commingled welltest watercut of 59.7 % is higher than average and is attributed to the Prudhoe production cleaning up after an extend shut in period. Aside from that initial welltest, watercuts have been on a gradual increase which is expected as both pools are being waterflooded. A Welltest plot annotated with the periods of individual pool production and commingled tests is shown in Figure 1. 4 • S-26 10,000 _ =- x T • � _ p� • • • Y • • • • � ;a i t .... � W. 1,000 -- -_ -' =,-' - O • t _ , C7 _�� A 100 -4 °' ° y O m w 10 U Jan -07 Apr -07 Jul -07 Oct -07 Jan -08 Apr -08 Jul - 08 Oct - 08 Jan - 09 Apr - 09 Prudhoe only welltests Aurora only Commingled welltests -a-Gross Fluid -Oil -GOR • Gas Lift Pressure • Manifold Pressure r Manfold Temperature -1- TGLR 100.0 _ _ 100.0 iW 80 . 0 �- ��_. __ _ - 80.0 en 60.0 ~ �, • 60.0 m m 40.0 0 40.0 m 0. 20.0 _ 20.0 ° 0.0 r 0.0 Jan -07 Apr -07 Jul -07 Oct -07 Jan -08 Apr -08 Jul -08 Oct -08 Jan -09 Apr -09 -e- Water Cut -+- Choke Figure 1. S -26 Welltest Plot Conclusions A summary of the allocated production reported for both the Aurora and Ivishak pools to date is shown in Table 6. The high Aurora oil split in August is due to S -26 being produced Aurora only until 8/20/08 when production between the 2 pools was commingled. Engineered splits were applied in September and October until the 10/10/08 preliminary PPROF results were applied starting in November. Final PPROF analysis results were applied starting in January 2009. The 2/16/09 PPROF results were applied to allocated production starting in March 2009. Oil Prod Water Prod Water Gas Prod Gas Prod Oil Prod Rate Rate Aurora Prudhoe Rate Prod Rate Aurora Prudhoe Rate Rate Aurora Prudhoe STB /DAY S- STB /DAY S- Oil split Oil Split STB /DAY S STB /DAY Water Water MSCF /DAY MSCF /DAY Gas split Gas Date 26_AURA 26_PBU % % 26 AURA S -26 PBU split % Split % S -26 AURA S- 26_PBU % Split % 8/31/2008 526 121 81.3% 18.7% 53 317 14.2% 85.8% 918 446 67.3% 32.7% 9/30/2008 400 245 62.0% 38.0% 42 661 6.0% 94.0% 531 904 37.0% 63.0% 10/31/2008 560 343 62.0% 38.0% 45 713 6.0% 94.0% 1012 1723 37.0% 63.0% 11/30/2008 413 372 52.6% 47.4% 95 499 16.0% 84.0% 701 1707 29.1% 70.9% 12/31/2008 355 320 52.6% 47.4% 88 463 16.0% 84.0% 631 1538 29.1% 70.9% 1/31/2009 409 393 51.0% 49.0% 100 528 16.0% 84.0% 736 1368 35.0% 65.0% 2/28/2009 313 301 51.0% 49.0% 104 548 16.0% 84.0% 1248 2317 35.0% 65.0% 3/31/2009 299 245 55.0% 45.0% 224 435 34.0% 66.0% 679 1933 26.0% 74.0% Table 6. S -26 Monthly Allocated Production Based on the allocated production splits, the Prudhoe formation GOR increased in February and March to approximately 7800 scf /stbo. This corresponds with MI injection into Prudhoe injector S -20A in November through December of 2008 and interaction time with S -26 is typically 3 months. MI interactions between S -26 and offset Prudhoe injectors S -20A and S -06 are fairly 5 well established and are expected to be recognizable when they occur. These wells are not on MI often as the area is becoming mature for MI in the Prudhoe oil pool. A comparison of the commingled oil splits from both the production profiles (data from Table 1) and Oil Geochemical fingerprinting (data from table 2) is presented in Figure 2. Oil production splits were obtained from the commingled geochemical samples and are in close approximation with the Production profile logging results. The geochemical sample obtained on 10/10/08 and the PPROF started on 10/10/08 were over 10 hours apart. Flucuations in gas lift rates and well head pressures can have an impact on oil production splits from the 2 zones, thus the slight variation in the more frequent Geochemical analysis. S -26 Aurora vs. Ivishak Oil Splits 100.00 - _ 80.00 60.00 - 40.00 20.00 0.00 8/1/08 8/31/08 9/30/08 10/30/08 11/29/08 12/29/08 1/28/09 2/27/09 Geochem % Aurora Oil - Geochem % Prudhoe Oil 10/10/08 PPROF Aurora Oil % 10/10/08 PPROF Ivishak Oil % a 2/16/09 PPROF Aurora Oil % 2/16/09 PPROF Ivishak Oil % Figure 2. S -26 Comparison of Oil Geochem and PPROF Splits Oil production splits were obtained from the commingled geochemical samples and are in close approximation with the Production profile logging results. The geochemical sample obtained on 10/10/08 and the PPROF started on 10/10/08 were over 10 hours apart. Flucuations in gas lift rates and well head pressures can have an impact on oil production splits from the 2 zones, thus the slight variation in the more frequent Geochemical analysis. The average Aurora oil split over the commingled test period from the 2 PPROF's was 53 %. This is very closely matched by the average of the geochemical analysis Aurora oil split of 55% (for all 7 samples) or 53% (excluding initial sample when Prudhoe just reopened and cleaning up). Obtaining more frequent Oil Geochemical samples is preferred over the more intrusive PPROF logging. Geochemical analysis provides quicker insight to production changes between the pools that may occur in the future. It also reduces risk by minimizing running into the well with tool strings. Occasional PPROFs or separate zone tests may be needed to determine water and 6 • • gas splits between the 2 zones that are not readily explained by injection changes in interacting offset injectors. Based on the good agreement between the methods of measuring Aurora and Prudhoe oil splits, BP believes that geochemical analysis has been demonstrated to provide an accurate and appropriate method of allocating oil between the two pools. Therefore, BP proposes that from May 1, 2009 forward, geochemical fingerprinting be utilized for oil allocation purposes. The geochemical sampling frequency will be twice per year and not less frequently than every 7 months. When major changes in production characteristics occur, which cannot be readily explained by changes in offset injectors for either Pool, a production log will be obtained to more accurately allocate the water and gas production. Sincerely, Frank Paskvan / Scott Digert BPXA GPB Subsurface Resource Managers, WEST / WF BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 7 • • CONFIDENTIAL MATERIALS HELD IN CONFIDENTIAL ROOM • • bp :: 0 Schiumber PL Advisor Production Log Interpretation With GHOST and DEFT Company : BP Exploration (Alaska), Inc. Field : Prudhoe Bay Well : S -26 Date Logged : 16- Feb -2009 Date Processed : 12- Mar -2009 Reference Number : AYTU -00014 API Number : 50- 029 - 22047 -00 Log Analyst : Erika Bowen Alaska Data and Consulting Services 2525 Gambell Street, Suite 400 Anchorage, Alaska 99503 (907) 273 -1700 411 interpretations are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and we shall not, except in the case of gross or willful negligence on our part, be liable or responsible for any loss, cost, damages or expenses incurred or sustained by anyone resulting from any interpretation made by any of our officers, agents or employees. These interpretations are also subject to clause 4 of our general terms and conditions as set out in our current 'rice schedule. • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 1. Production Logging Objectives: The objective of this logging suite was to evaluate production splits between the Aurora and Ivishak pools. Three phase production interpretation was performed to determine oil, gas, and water splits. 2. Main Results: Table 1: Interpreted Downhole Rates from multiphase solver. Tot.DH Oil Gas Water Pool Perforation prod. % Rate % rate % rate ok From, ft To, ft B/D B/D B/D B/D Aurora 6870 6894 1695.8 31.30% 404.4 55.00% 1034.2 26.30% 257.2 34.10% Ivishak 8951 9053 3726.8 68.70% 331.4 45.00% 2899.1 73.70% 496.3 65.90% 8951 8960 2594.0 47.8% 189.5 25.8% 2404.5 61.1% 0.0 0.0% 8965 8990 539.6 10.0% 123.4 16.8% 395.1 10.0% 21.1 2.8% 8995 9012 593.5 10.9% 18.6 2.5% 99.8 2.5% 475.1 63.1% Below 9012 Trace Trace Trace Trace Total: 5422.6 735.8 3933.3 753.5 Table 2: Interpreted Surface Rates converted from downhole rates. Gas Water Pool Perforation Oil Rate rate rate To, From , ft ft STB /D % Mscf /D % STB /D % Aurora 6870 6894 359.8 55.40% 385.2 26.70% 250 34.30% Ivishak 8951 9053 289.7 44.60% 1059.1 73.30% 479 65.70% 8951 8960 167.2 25.7% 854.4 59.2% 0.0 0.0% 8965 8990 104.1 16.0% 218.2 15.1% 20.3 2.8% 8995 9012 15.7 2.4% 56.7 3.9% 456.3 62.6% Below 9012 Trace Trace Trace Total: 649.5 1444.3 729 * *Splits within the Ivishak are as requested. Zonation within a flowing interval has higher uncertainty due to instability in the flow regime. Surface rates on the day the product log was acquired were: 792 bpd oil; 876 bpd water; 1610 mscf gas 2 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3. Production Log Interpretation: BP Exploration (Alaska), Inc. (BP) well S -26 is a producing well located in Prudhoe Bay field. This well is producing from two separate pools, the upper Aurora (Kuparuk) and lower Ivishak (Prudhoe Bay). The Ivishak is producing from a perforated 7.0" cemented liner with open perforations from 8951 -9053 MD. The upper Aurora pool is producing from a 9.625" cemented casing open from 6870 -6874. 4.0" tubing is run between the two intervals and above the Aurora with gas lift mandrels (see well sketch at end of report). The S -26 well was logged with the PS Platform production logging tools consisting of gamma ray, CCL, temperature, pressure, gradiomanometer, 2.5" continuous spinner, in -line spinner, X -Y caliper, GHOST and DEFT. Both the upper and lower intervals were logged with three sets of up /down passes at both production intervals (no logged continuously between due to large distance between production zones). Station stops were recorded at 9020, 8992, 8963, 8900, 8593, 8570, 8000, and 6650 at both gas lift rates. The well was shut in for 1 hour and two station stops were recorded at 8000 MD. The downhole temperature and pressure at 9010 ft. are 223.9 °F and 1507 psi. Data quality: Field data was depth matched to open hole gamma ray recorded May 24, 1990. Data quality is high, pressure and temperature is consistent within the logging passes indicating that well production was fairly stable. DEFT and GHOST holdup corrections were applied. Interpretation: Over -all downhole rates are lower than reported surface rates. Due to the changes in ID with this completion, inflow for perforated zones was computed in the 4.5" tubing for consistency. The increase to the 9.625" casing at the upper Aurora pool is causing apparent water recirculation. 3 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3.1. Interpretation Results: 16-Feb-2009 Survey The figure below shows cumulative production along with comparison between the reconstructed curves and stacked input curves for the full interval. Depth ell Sketc Z Density match Gas holdup match Water holdup match Velocity match QZT Q (ft) (in) 0 glcc 1.2 0 1 0 1 -50 fVmin 350 -500 BID 6500 -500 B/D 6500 7 ?W4 G - 6700 I r- �� ,, II 6800 MM 11! A 7000 1.1111111111111111 MO= ■ Mt 1 •PIIIMIIIIMIIIIIralliall III um MR • NIB I III I Mil III IN 1 111111111MMEM11111111 II 1. PI II MI= III MI NI MEI MI IN rt mum . al ' mu IN 11 : t - NM . • 8000 - �I- . El II II MIE11111111=1111 NW µ - �� murimmr. 'r 1111 PI ' 11111111111111, IIMME r IN 9000 =_ �I All IN 4111111111M1=■1111M1111 I 11 t -- I I I 4 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 16- Feb -2009: Cumulative production and reconstruct overlays for the upper Aurora and lower Ivishak pools. Depth Vell Sketc Z Density match Gas holdup match Water holdup match Velocity match QZT a (ft) (in) 0 g/cc 1.2 0 1 0 1 -50 ft/min 350 -500 B/D 6500 -500 BAD 6500 - 7.8Tc�74 FP -5,11 Y' *"J EFT 3511 VASP I 35,11 _ _ 1 1 1 l - - 6700 - i' — — I ,. i - - 6800 -.4. ♦' -6900 C -_ - i • - 7000 - • - 7100 - I $$ • - - - — - — I f _ I ¢¢ - - 7200 - Dept Vell Sketc - Density match Gas holdLp - notch Water holdup matcr Velocity matcr QZT a (ft) (in) 0 dcc 1 2 0 1 C 1 -50 ft/min 550 -500 B/D 6500 -500 B/D 8500 - 7.87W4 D ' 511 - _., - X - 870) ' r - _ . _. — - 6' q1 - 3300 - y is it R {( — 7 t - - 890J I i r i _ 1 — 900J — I I I I 910) I * 1 I ■ I I — 920) f 5 III BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 16- Feb -2009: Correlation display for the upper Aurora and lower Ivishak pools.. tsp. Well View #1 II Sk- Z GR TENS CCLD ID ER 21 PFC2 (ft) (g - >Top) (in) 0 GAPI 450 500 lb 1500 -8 8 -5 in 6 8 in 0 0 in 8 9'. te 1 - - , \ i ce 4. III ...? _, , i 4 .1.• pm 1 I S ,i. •11 I j 1 I I i 11 1 t ti , i I ! ;IP ,,, ... , 1 il , s t 61=10 1 fss '; I ,i y lPi 1. � a j } W e View Y1 115k- L GR TENS CCLD ID PFD 1 PFC2 (ft-> ToF) (in) 0 GAPI 457 500 b 1500 -0 8 -E. i 6 0 in 0 0 in 8 I I I i i I I 1 mi i I t� � I J 11 1 I I1. 6 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 19- Feb -2009: PSP sensors up and down passes overlay display for the upper Aurora and lower Ivishak pools Depth ell Sketc Z GR WPRE WTEP UWFD SPIN SCVL (ft) (in) 0 GAPI 450 900 psia 1120 182 °F 210 0.2 glee 1 -10 rps 45 -120 ib/min 120 - - ,:„ 1 -_ - r � '_6700- .'` I Ii it; 1f -= --- 1 I ll t ' ' -6800- \ ¢ - -- T I I11! 8900 i -700 0- — l!t ttii t - 7100 - � r) I Y f - - 7200 t .. 7• Depth ell Sketc Z GR WPRE WTEP UWFD SPIN SCVL (ft) (in) 0 GAPI 450 1380 psia 1520 214 °F 226 0.2 g'cc 1.2 -10 rps 18 -120 fUmin 120 - 8700 ' _ - ¢ f 8 0 - 0 / 4 I .,." __;_-:---11 9°_: :_::::. ' : - a � it, 9000 I. -_ _ -__— .' - i i - 5100 - - - 920 - 0 _ 7 S • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 19- Feb -2009: GHOST down passes overlay plot. Note high water holdup due to recirculation in the 9.625 casing interval. •ep. DFH1 DFH2 DFH3 DFH4 D1RB YW_DFT DEFT 32 D bb 32 (ft) 0 1 0 1 0 1 0 1 0 360 0 1 1 Fr 2 0 0 829 563 I. ( ( ( i : .1“, E ' -s .f... , i i i i I - ., I , „... i .,.. ■ 1 7l R w. .t. ; i c °'» c ' 1 j r j : f , A } A I �, ♦ Ill UFH1 UhH "l C FH3 UFHY D 1Rt3 1 "�V_Url Utr tL U CUUG ' Al 0 1 0 1 0 1 0 1 0 360 0 0 _ _ _ -, 1 2- 70. x s, .. ay 11111 ... i .... .„ 11111111 , ,, 1 ,,... _ . 4 iii i 1 A , 00. .______.. a 101 20 8 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 19- Feb -2009: GHOST down passes overlay plot Depth GHH5 GHH6 GHH7 GHHB D1RB2 YG GHOST 32 G BUB 32 (ft) 0 1 0 1 0 1 0 1 0 360 0 1 0 -1 0.75 0 a 1245.42 = 6700 — I • 'L. ,.. _ _ = f i 4 di t - 6800 - , w1. A.. -• -i s f - - , . w+ . a Ili . . — 6900 — _ kr - - - - T-. X - - lid f - 7000 — a.'! it ; - , , ~k _ 7100 _ - .1 _ - \ T. — - 7200 — .i; . 1 ) J J 4 r _ - _ x _ w — . — 7300 — 4 A= — t Depth GHH5 GHH6 GHH7 GHH8 D1RB2 YG GHOST 52 G BUB 52 ( — 0 1 0 1 0 1 0 1 0 360 0 1 0 0.75 0 1 582.751 — 8700 — L — 880 0 E r 1 ) i _ _ _ _ _ _ '. = = , - 8 900 It"- I — ,i'. r — a_ = 9000 - = i — - 9100 — 9 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3.3. Spinner Calibration: _30 • X _20 0 X _10 sf�: -200 7 0 200 _ -10 _ -20 _ -30 _ -40 rps versus ft/min Threshold ( +) 9.8 ft/min Threshold ( -) -9.8 ft /min Calib. Zone Slope ( +) Slope ( -) Int ( +) Int ( -) Int. Diff. ft ft /min ft /min ft/min ❑ 6707.8- 6747.7 0.089 N/A - 281.01 N/A 0.00 O 6779.2- 6839.5 0.089 N/A -50.22 N/A 0.00 + 6914.2- 7014.1 0.089 0.090 -50.14 -63.27 13.13 X 7065.8- 7221.8 0.089 N/A - 184.34 N/A 0.00 ❑ 8727.1- 8903.9 0.099 N/A -58.58 N/A 0.00 ✓ 9001.2- 9011.6 0.100 0.090 -0.13 -19.98 19.85 Spinner Calibration plot. 10 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 3.4. Summary Table Results: Summary table of inflow zones: Zones 1 Zones 2 Zones 3 Zones 4 Zones 5 From , ft 6870 8951 8965 8995 9022 To,ft 6894 8960 8990 9012 9053.1 Water FVF 1.0287 1.0362 1.0403 1.0414 1.0418 Viscosity, cp 0.357 0.3102 0.2854 0.281 0.2793 Density, g /cc 0.99 0.98 0.98 0.98 0.97 Oil +Gas FVF 1.126 1.144 1.1861 1.1881 1.1892 Viscosity, cp 1.918 1.5363 1.1544 1.1319 1.1219 Density, g/cc 0.81 0.8 0.78 0.78 0.78 Gas FVF 0.0174 0.0161 0.0114 0.0114 0.0114 Viscosity, cp 0.0141 0.0146 0.0158 0.0159 0.0159 Density, g /cc 0.055 0.0593 0.0835 0.0837 0.084 Temperature, 'F 187.13 207.28 220.44 223.09 224.08 Pressure, psia 945.46 1056.2 1488.6 1500.2 1508.7 Diameter, in 3.958 3.958 6.275 6.275 6.275 Deviation, ° 20.1 17.7 4.93 4.88 4.81 Roughness 1.16E -04 2.53E -04 1.59E -04 1.59E -04 1.59E -04 Rs, cf /bbl 148 160 232 233 234 Rsw, cf /bbl 6 6.45 8.67 8.75 8.79 V mixture, ft/min 267 179 20.6 10.8 0 Visc. Mixture , cp 0.54 0.39 0.31 0.28 0.28 Vpcf 0.89 0.89 0.84 0.83 0.5 dQ res., B/D 1695.79 2594.01 539.62 593.54 0 % at 31.27 47.83 9.95 10.95 0 dQw res., B/D 257.21 0 21.13 475.14 0 dQw s.c., STB/D 250.04 0 20.31 456.27 0 dQo res., B/D 404.39 189.48 123.44 18.6 0 dQo s.c., STB /D 359.78 167.22 104.07 15.65 0 dQg res., B/D 1034.18 2404.53 395.05 99.8 0 dQg s.c., Mscf /D 385.26 854.43 218.24 56.72 0 Yw 0.248 0.309 0.786 0.954 1 Yo 0.232 0.186 0.075 0.011 0 Yg 0.52 0.505 0.14 0.034 0 Vslip, ft/min 243.443 204.263 50.854 43.702 0 Vslip W-O, ft/min 2.553 3.776 19.855 19.952 Regime Froth /chum Slug liquid -gas Bubble Bubble No flow Corral. Aziz and Govier Aziz and Govier Aziz and Govier Aziz and Govier Aziz and Govier Stanford Drift Stanford Drift Stanford Drift Stanford Drift Stanford Drift Correl. W -O Flux LL Flux LL Flux LL Flux LL Flux LL 11 • S BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 4. Table of abbreviations: Tool Mnemonic Channel Description Units: Description CVEL Cable velocity CCLD / B/D Barrels per Day CCLC Casing Collar Locator Discriminated / Calibrated DFB1/2/3/ scf /bbl Standard Cubic Feet per Barrel 4 DEFT bubble count per probe DFH1 /2/3/ cp Viscosity centipoises 4 DEFT water holdup per probe ft/m Feet per minute SCV1 Depth corrected cable speed to in -line spinner g /cc Grams per cubic centimeter SCVL Depth corrected cable speed to spinner MMSCF /D Million Standard Cubic Feet per Day GHHM2 Field calculated combined gas holdup MSCF /D Thousand Standard Cubic Feet per Day DFHM Field calculated combined water holdup Res. To denote reservoir conditions (downhole) MWFD Field pressure derived density rps Revolutions per second GR Gamma Ray GHB1 /2/3/ S.C. To denote surface conditions (uphole) 4 GHOST gas bubble count per probe GHH1 /2/3/ SCF Standard Cubic Feet 4 GHOST gas holdup per probe STB /D Stock Tank Barrels per Day SPI1 In -line spinner WPRE Pressure PVT: Pressure Volume Temperature DPHZ Pressure derived density (from Emeraude) Bo Oil volume factor PFC1 / PFC2 PSP Caliper 1 and Caliper 2 Bw Water volume factor Q Rate Relative bearing for probe 1 of second tool Bg Gas volume factor D1 RB2 (GHOST) FVF Fluid volume factor D1 RB Relative bearing of probe 1 GOR Gas Oil Ratio SPIN Spinner (fullbore or turbine) Watercut Ratio of produced water to total fluids WTEP Temperature Holdup Fraction of fluid present in an interval of pipe TENS Tension Uncorrected Fluid Density (from UWFD gradiomanometer) Interpretation: WFDE Well fluid density (from gradiomanometer) Correlation Model L -G: Liquid Gas W -H: Water Correl. Hydrocarbon; O -W Oil -Water ID Internal Diameter PSP Production Services Platform Q Cumulate Rate with continuous solution DEFT Digital First Entry Tool (Water holdup) QZI Incremental rate per zone GHOST Gas Holdup Optical Sensor Tool (Gas holdup) QZT Cumulative Rate track with zonal contribution Regime Modeled Spinner Calibration: Slope of rps/ (ft/m). Defines conversion of YG Gas Holdup Slope spinner to velocity. YO Oil Holdup Int Intercept of line of slope (defines velocity) Difference between up /down passes. This is the YW Water Holdup Threshold velocity required to initiate rotation of the spinner. YW DFT Water Holdup from DEFT Z Zone: Yellow - spinner calibration Red - Perforation White - Inflow Zones Gray: Calculation (stable) zone • 12 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 5. Tool Diagram: MH-22 6 48.9 MH-22 AH - SAG G 47.3 AH u EQF - 43 1 45.8 EQF EQF - 43 1 39.8 EQF EQF - 43 33.8 EQF-43 Detail MT TelStatus CTEM .L _ 27.8 PSPT - A/B 27.8 PSC-A PSPT -A PSTC 876 PBMS -A 772 GR _ 24.1 10k Sapphire_Mano RT6 Thermometer GR — Well Temp 21.0 CCL Manometer 20.9 PBMS CCL 20.3 PBMS PSTC 19.6 PGMC - A/B ACCE 19.6 PGMC -B 852 Gradioman _ 18.1 Accelero PSOI Gradio PGMC 14.8 PILS - A 14.8 PI LS 870 Spinner _ 132 GHOST - A2 12.3 Flowmetor Probes Relative Bearing Caliper GHOC -C 701 GHOST2 Pr 7.2 GHOH -C GHOST2 Ca 7.1 GHOST2 Ca 5.1 PFCS Spin - .� PFCS Cali 1.9 PFCS - PFCS Prob 0 1 5.1 Holdup Probes GHOST2 Wa HV Spinner 2.5 GHOST2 Re Relative Bearing PFCS Wave Caliper PFCS Rela PFCC -A 856 PFCS Cart PFCH -A 856 Tension /' 0 .0 TOOL ZERO MAXIMUM STRING DIAMETER 1.69 IN MEASUREMENTS RELATIVE TO TOOL ZERO ALL LENGTHS IN FEET 13 1 11/ III BP Exploration (Alaska), Inc. Well: S -26 Job Number: AYTU -00014 Field: Prudhoe Bay 6. Well Schematic: TREE = 4" OW SAFETY NOTES: NOTIFY GC OF ANY WELL OPCDCRATION t A S TUATOR 0115 -26 EROSION RATEST03' SKID PLO POTENTIAL KB. ELEV = 05.09' V EROSION) ""GMLOMETBG "PIMIOLE LEAK IN 9 -3/8' B. ELEV= - 3749' USG' / 7200 - 8484'°" KOP= 4400' M9 =2 @51 2029' H4- 1/PF$SX NP. ID= 3.813' i5idurninc - _ 3073' Detwn T\/D- 0000' 0.S GAS LIFT ALAtJCRES 120' CONDUCTOR, D =? H 110' ST MC TVD CEV TYFE VLV LATCH PORT DATE I 4 3635 3635 0 MNAG DONE PK 16 05/14/08 13 -3'8" MG, 686, L - 30 BUTT, D - 12015' H 26$3' 3 5304 5251 23 MC DMY PK 0 04/ 181/08 2 6217 6094 22 MMG M fXAY PlC 0 05/27106 (4.1 /2 "SYA/PHONYGUASEw /1-WREIC =3.94" H 6608' I 1 6537 6391 21 MMG SO PK 22 05/27/08 I 611/ H" its X rip, = 3.813- I Minimum ID = 3.80" @ 8613' _ _ 4 - 1/2" OTIS XN NIP, MILLED OUT �� I 6691' &518'X4- 1 /2'BKRS -3 PKR, IO= 3.875' I 6715' H4- 112" HES X NP, ID= 3 813" I 4 -1/2" TBG, 12. 6#x, 13CR VAM TOP. H 6780' .C152 bpf, ID = 3.958" 6780' H4 112" W1LEG, ID= 3.958' I PN HOLE LEAK f4 9.5/8" CSG ' (8E1-IND LOWER ISOLATION STRINGI PM �. 7042' — 19 -518' X 4 -1/2' BKRS -3 PKR, 0= 3.875" I 4 -112" TBG. 12.611, 13CR VAM TOP. --I 8515' • 7066' h11 2" HES X, ID= 3:813" I .5152 bpf, ID= 3.958" 1A-1`2" TBG STL£ (12 /2607) 8520' 8531' 9 5/8" X 4 1/2' UNIQUE OVERSHOT I 0:4 ,—. 8540' H 9 618' X 4 1/2' OTIS PKR IC - 3.85" 1 ITOP OF 7' LNR 111111a1111 8570' 9-5/6" X r" 198< HUH, U = Z I I 8593' H4.12" PARYJ3tSWS MP, D =3..813' I 1 8613' I - 1 /2 " Uf6XN NP, MLLhL IL) 3.80"(12(38/0.') I 4 -112" 76G. 126#, L E0 TDS, . 0152 bpf, I D = 3.958" 8625' 4 -1 /2' WA_EG,10 = 3.958' I c -5)8" (:SC,, 4711 NM' MSCr T) = f. 681" H 8818' I e62r H ELMDTT LOGGED 08/15'90 I F'ELI-URA I ION SUTAMA KY PEP LOG SNS EIFICS ON 05/24/x0 ANGLE AT T P F 19' @ 6879' NA.k. R of xi Pi Wuaun DG for hisLLxLai pelf data I 9030' H7" 20NA- IS0 .ATION P144, (07/28/07) I SIZE: NI- N :L)RVAL Orrt/ SW DA IC 3.3/3" 4 6870 - 6894 0 04/73/08 3 -3/3° 4 8951 - 8961 0 08/26)90 `7 9139' I— FSH- BKR ECP, SCOOP G1A)E5, 3.:1//3' 4 8965 - 9053 C 08p6/90 • RLRNNC TOOL, A NO OLD BP 3 3/3' 4 9085 9130 S 00/10/94 3 -3/3' 4 9184 - 9186 S 09/10,94 I 9178' H 7" MA RKERJC4NT 1 P670 i TAG'S 01 /17,93) ma. ONOM 17" LNR, 280,L-80 LUIS, 0283 bpf, D = E276" H 943( DATE REV BY CCNIVENTS DATE REV BY COMMENTS FRJCHOE3AY UNT 08/04/90 N1IX ORIGINAL COMPLETION 05/14,08 KSB/TLH GLV G0 WELL 5-.26 01)02108 014 RWO 0501416 BAV/Tr) GLV on (5'77)00) FFRMT Uir x 1900581 04/C6/06 FR / SV PERFORATIONS (04)03100) 07/0208 01-1YYPJC DRLG DRAFT CORRECT10NS API 'Jo 50- 029 - 22047 -DC 04/50/00 DAV /PJC GLV CIO 09195,00 -A5PJC PULL rASDRLL (00/17/00) MC 35, T121 R12C 1335 rNL & 110C fWL. 04/0/08. KS8YPJG GLV U/U 05159/08 ?/ PJC DRLG DR4FTCORRECTIONS BP Exploration (Alaska) 14 • S bp oy. $ cblumberger PL Advisor Production Log Interpretation With GHOST and DEFT (Revised Format — April 2009) Company : BP Exploration (Alaska), Inc. Field : Prudhoe Bay Well : S -26 Date Logged : 10 -Oct -2008 Date Processed : 30 -Oct -2008 Reference Number : 12017505 API Number : 50- 029 - 22047 -00 Log Analyst : Erika Bowen Alaska Data and Consulting Services 2525 Gambell Street, Suite 400 Anchorage, Alaska 99503 (907) 273 -1700 All interpretations are opinions based on inferences from electrical or other measurements and we cannot, and do not guarantee the accuracy or correctness of any interpretations and we shall not, except in the case of gross or willful negligence on our part, be liable or responsible for any loss, cost, damages or expenses incurred or sustained by anyone resulting from any interpretation made by any of our officers, agents or employees. These interpretations are also subject to clause 4 of our general terms and conditions as set out in our current 'srice schedule. • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 1. Production Logging Objectives: The objective of this logging suite was to evaluate production splits between the Aurora and Ivishak pools. Three phase production interpretation was performed to determine oil, gas, and water splits. 2. Main Results: Table 1:3.5 MMSCF Gas Lift: Interpreted Downhole Rates from multiphase solver. Tot.DH Oil Gas Water Pool Perforation prod. % Rate % rate % rate % From, ft To, ft B/D B/D B/D B/D Aurora 6870 6894 1717.4 36.07% 297.9 51.40% 1367.9 35.39% 51.6 16.31% Ivishak 8951 9053 3043.4 63.93% 281.7 48.60% 2496.9 64.61% 264.8 83.69% 8951 8960 2588.2 54.4% 226.2 39.0% 2362.1 61.1% 0.0 0.0% 8965 8990 187.6 3.9% 52.7 9.1% 134.9 3.5% 0.0 0.0% 8995 9012 267.6 5.6% 2.8 0.5% 0.0 0.0% 264.8 83.7% Below 9012 0.0 0.0% 0.0 0.0% trace trace Total: 4760.8 579.6 3864.8 316.4 Table 2: 3.5 MMSCF Gas Lift:lnterpreted Surface Rates converted from downhole rates. Oil Gas Water Pool Perforation Rate rate rate To , From , ft ft STB /D % Mscf /D % STB /D % Aurora 6870 6894 263.4 52.60% 527.9 29.06% 50.3 16.51% Ivishak 8951 9053 237.4 47.40% 1288.7 70.94% 254.3 83.49% 8951 8960 190.7 38.1% 1208.1 66.5% 0.0 0.0% 8965 8990 44.3 2.6% 77.8 4.3% 0.0 0.0% 8995 9012 2.4 0.1% 2.8 0.2% 264.8 86.9% Below 9012 0.0 0.0% 0.0 0.0% trace Total: 500.8 1816.6 304.6 2 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay Table 3: 2.1 MMSCF Gas Lift: Interpreted Downhole Rates from multiphase solver. Tot.DH Oil Gas Water Pool Perforation prod. % Rate % rate % rate From, ft To, ft B/D B/D B/D B/D Aurora 6870 6894 1742 35.79% 237.6 40.83% 1443 36.46% 61.5 18.77% Ivishak 8951 9053 3125.6 64.21% 344.3 59.17% 2515.1 63.54% 266.2 81.23% 8951 8960 2650.0 54.4% 276.2 47.5% 2373.8 60.0% 0.0 0.0% 8965 8990 206.3 4.2% 65.6 11.3% 140.7 3.6% 0.0 0.0% 8995 9012 269.2 5.5% 2.5 0.4% 0.6 0.0% 266.2 81.2% Below 9012 0.0 0.0% 0.0 0.0% trace trace Total: 4867.6 581.9 3958.1 327.7 Table 4: 2.1 MMSCF Gas Lift:lnterpreted Surface Rates converted from downhole rates. Oil Gas Water Pool Perforation Rate rate rate To , From , ft ft STB /D % Mscf /D % STB /D Aurora 6870 6894 210.4 41.97% 537.7 29.36% 59.8 18.95% Ivishak 8951 9053 290.9 58.03% 1293.6 70.64% 255.7 81.05% 8951 8960 233.5 46.6% 1208.3 66.0% 0.0 0.0% 8965 8990 55.3 11.0% 82.3 4.5% 0.0 0.0% 8995 9012 2.1 0.1% 3.0 0.2% 255.7 81.0% Below 9012 0.0 0.0% trace trace Total: 501.3 1831.3 315.5 3. Production Log Interpretation: BP Exploration (Alaska), Inc. (BP) well S -26 is a producing well located in Prudhoe Bay field. This well is producing from two separate pools, the upper Aurora (Kuparuk) and lower Ivishak (Prudhoe Bay). The Ivishak is producing from a perforated 7.0" cemented liner with open perforations from 8951 -9053 MD. The upper Aurora pool is producing from a 9.625" cemented casing open from 6870 -6874. 4.0" tubing is run between the two intervals and above the Aurora with gas lift mandrels (see well sketch at end of report). The S -26 well was logged with the PS Platform production logging tools consisting of gamma ray, CCL, temperature, pressure, gradiomanometer, 2.5" continuous spinner, in -line spinner, X -Y caliper, GHOST and DEFT. Both the upper and lower intervals were logged with three sets of up /down passes at two different rates of gas lift, first at 3.5MMSCF gas lift, than allowed to stabilized for 3 hours and logged at 2.1 MMSCF gas lift. Station stops were recorded at 9020, 8900, 8593, 8570, 8000, and 6650 at both gas lift rates. The well was shut in for 1 hour and two station stops were recorded at 8000 MD. Surface rates were recorded as 2.4 MMSCF formation gas, 800 BOPD, and 560 BWPD at 3.5 MMSCF gas lift and 2.4 MSCF formation gas, 940 BOPD, and 550 BWPD at 2.1 MMSCF gas lift. The downhole temperature and pressure at 9010 ft. are 223.8 °F and 1519 psi at 3.5 MMSCF gas lift; 223.8 °F and 1508 psi at 2.1 MMSCF gas lift. 3 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay Data quality: Field data was depth matched to open hole gamma ray recorded May 24, 1990. Data quality is high, pressure and temperature is consistent within the logging passes indicating that well production was fairly stable. Variation within the station stops was less than 5 psi pressure, and under 10 rps change on spinners. DEFT probe #3 was not working after the first set of up /down passes at the Aurora pool at 3.5 MMSCF gas lift. DEFT probe #3 was removed from the water holdup computation for the remaining passes. Additionally a few minor spikes in DEFT and GHOST holdups data were removed to aid in stacking passes. Interpretation: Data indicated mostly standing water column at base of well up to 8958 MD. Spinner, density, DEFT, and GHOST indicate close to sump (no -flow) conditions below 9000MD. Over -all downhole rates are lower than reported surface rates. For the Ivishak interval, it was requested to break down the inflow into sub - zones. Since there are no stable intervals the division of production is suspect to higher uncertainty. From data indicators the lowest entry at 8998MD is majority water and some oil. The entry at 8974MD is predominately oil, and the main gas contributor is the upper perforation at 8951- 8961MD. Spinner response indicates fluid recirculation in the 7.0" casing interval below the 4.5" tubing. Due to the changes in ID with this completion, inflow for perforated zones was computed in the 4.5" tubing for consistency. The increase to the 9.625" casing at the upper Aurora pool is causing water to drop out and recirculate in this interval. This is shown with the high water holdups and spinner response. Since water is recirculating in this interval before lifting again in the 4.5" tubing the water attributed to this zone has a higher uncertainty. There is approximately only a 10 psi pressure change between 3.5MMSCF gas lift and 2.1 MMSCF gas lift. There is less than 2 rps difference in spinner response also. Apparent downhole rates between the two sets of surface gas lift rates are essentially the same. There was no enough downhole rate variation with change in surface gas lift rates for a SIP (selective inflow performance) plot to be generated. 4 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.1. Interpretation Results: 3.5 MMSCF Gas Lift 3.5 MMSCF Gas Lift: The figure below shows cumulative production along with comparison between the reconstructed curves and stacked input curves. I II Ske Density match Gas holdup match Water holdup match Veloc match OZT 0 tint 0 grcc 12 0 I 0 1 -50 ftfmin 350 -500 BID 6500 -1000 B/D 6000 > > U4 /FD Si, 11 - ''. 't I i- . ,6 Il VASPIN 56.11 yr S611 Y' / !OFT S6 11 VASPst47 Sell _ IIIIM ' I1 I! -41 1 iM I MI III: 1 All E I M1 - 1111 MINIS= ( I MI I Ell IN I I _ , 1 I It I � F I t II 111 I � I 111 I I 11. MIMI= I I m I I n. I I le I I mr. u = I �I m i . ,j 1 1 im PP f I 1 �1 N F I 1• I 1 .�r I..M AIM t .n. , 5 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: Cumulative production and reconstruct overlays for the upper Aurora and lower Ivishak pools. � - - Water holdup match • QL I Q 0 g cc 1 2 0 1 0 1 -50 fVmin 350 -500 13+D 6 6500 -1000 &D 6000 JW - LI 5�z `t YGZ -> i 11 `MI DFTZ a r? VASPIN S YG S6 11 YW DFT 5611 VASP'N7 53,11 1111 , r .1 11 ._.� 1 TIIIIIIIMI I J I TI I , , „ill, ...._. . ..... , , ... i t II V 1 11 II .. I 11 A i i i � I ■ Depthell Sket Z Density match Gas holdup match Water holdup match Velocity match OZT 0 (It) (m) 0 glcc 1 2 0 I 0 1 -50 flmin 350 -500 BID 6500 -500 B/D 7000 - 7 UWFD S6 11 __ �. ,.+ li VASP1N SO 11 YG 5611 YW DFT n = ''INZ -.- SC . _ - - L - - - I anon. s: - �� 1 , : : ,,, . I -* 1 I I !ii 1 I I I 71. , : pH i I 6 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: Correlation display for the upper Aurora and lower Ivishak pools.. ept Well View #1 Z ell Sketch ID PFC1 PFC2 COLD GR (ft) (ft -> Top) iIn) -6 in 6 2 in 8 2 in 8 -6. 8. 0 GAPI 300 9500 5800 7 — 1 1 . :, 4 :yc I t' T I 1 ___ „k, ____ . _ -- 1 1 It 1 1 z i 1oc ir 1 I i i Pept1 WeII View #1 Z Weil Sketcf� ID PFC1 PFC2 CCLD GR (ft) (ft -> Top) (in) -6 in 6 2 In a 2 in 3 -3 6. 0 GAPI 300 9500 5800 -7 7 i -- II I i I I I __ i s - - I - - 1 _ _ i L 3.121.75. — i I 1 ' 1 I 1— -_ I. , 1 I 1 ___ .6... r f -- S 1 7 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: PSP sensors up and down passes overlay display for the upper Aurora and lower Ivishak pools Depth Z Well Sketch 1 ID WPRE WTEP UWFD SPIN (ft) in -6. In 6 960 psia 1110 1 -8 F 206 0 gfcc 1 -5 rps 40 I 1. ` I l . ;,- . — — j I }11 - - 11 ) - - I I 1 5 � ti., I ' ! f - - � 1 ' i - ,,,,, i l f i .+�+ E" ! ! 1 ■ 1 I ii Depth Z Well Sketch ID WPRE WTEP UWFD SPIN eft) In -6 in 6 1340 psla 1540 212 F 226 0 g/cc 1 2 -15 rps 30 — — ; I — — I I - n.�a. - I ; I 4 l El I . 1 \ I I II - I 1 . n ■ 8 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: GHOST down passes overlay plot. Note high water holdup due to recirculation in the 9.625 casing interval. 3eptt Z GHHS GHH6 GHH7 GHH8 D1RB2 YG GHOST DN20 tft) .0 2 1.2 -O 2 1 2 -0.2 1 2 -O 2 1 2 0 360 0 1 3 :; I I I 1 1 1 1 I 1 P I ) . I.}. / ( ( a s s I 1 _ - _ } :79 L �. , (s ✓ { i / 7 .) , r I - ,,i" / ....E. _ _ L-1,4 ( I1 , Depth Z GHH5 GHH6 GHH7 GHHS D1RB2 YG GHOST Dni2 (ft1 -0.2 1.2 -0 2 1 2 -0.2 1 2 -0.2 1 2 0 360 0 1 0 IF=MMIN 1 _ _ I i ji; . , II I ! r J i. I J I , i 1 I / / / ' — 1 I --I— --.1 I r f ■ I r I; LI I — — I I I r II ii � � {r '�'�. -- �aew - -- a l _ �,�„ { '® 9 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.5 MMSCF Gas Lift: GHOST down passes overlay plot Z II Sk.e DFH I DFH2 DFH3 DFH4 D1RB Yw OFT DEFT Dn18 on; -0 2 1 2 -0 2 1.2 -0-2 1 2 -0 2 1 2 0 360 0 10 ■ 1 1 i 1 I 1 it , i I c., _ �t- !/ I/ MIMS 1 1 — 4 � _ a i x v- i zr_ ,, I � I -r - -_ "_ ,. ( = Z ISke DFH1 DFH2 DFH3 DFH4 D1RB YW_DFT DEFTDn34 (in) -02 I2 -02 12 -0.2 12 -02 12 0 360 0 1 0IMMINNE:i1 11111 I I I __ _i i ! 1 I I , I I I I ! 5 i j I I I : I i I I I I I i I I I I ~_ I I I I I i I I I II! � i r l f -- l�s+ 1 � 10 I • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.2. Interpretation Results: 2.1 MMSCF Gas Lift 2.1 MMSCF Gas Lift: The figure below shows cumulative production along with comparison between the reconstructed curves and stacked input curves. Depth II Sket Z Density match Gas holdu• match Water holdup match Veber match QZT 0 ( II) on, 0 g +cc 1 0 1 0 1 - 20 R'min 420 -500 BID 6500 -500 BID 8000 7.874 ;511 VASPIN S511 Pc'i S I YG S511 YW DM' S,'" ''ASRI/47 MN EMI 1 ■ UMW Me IIIIMMEMER 11 C I r IMMIM1111.0111 111 MI .J. a I II -- : _- 3 e. u I 111011.1M.111111.1 IIIMMININIE=1111=1111 111. T i _ _ — a AIM 11 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 2.1 MMSCF Gas Lift: Cumulative production and reconstruct overlays for the upper Aurora and lower lvishak pools. Depth ell Sket) Z Density match Gas holdup match Water holdup match Velocity match QZT 0 (ft) (in) 0 g?cc 1 2 0 1 0 1 -20 ft/min 420 -500 BD 6500 -500 BiD 8000 -7.874 VASPIN 5511 JV+°'^ - - ,, i1 < - '., S. 1 Yt. "d rIFT S5 :' VASPINZ> S°+ Ii — — i i I — y 1 t I i 1 _ 1 _ _ i _ _ .. i ...= , i _ _ 1 _ al L , T .- 1 - 1t :, i . r i – I Depth ell Sket Z Density match Gas holdup match Water holdup match Velocity match 0ZT 0 ( (in) 0 g+cc 1 2 0 1 0 1 -20 ftimin 420 -500 BID 6500 -500 B/D 8000 -7.874 r ,:; r_ ,5 I I VASPIN 55 i I UWFD S r i t VG S5 I I YW DFT S511 VAST" " ::' II I .-� Y t - _ - 1 i 1i i1 I _ i 1 – – I 1 i C Y I : – I I _ _ y I I 12 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 2.1 MMSCF Gas Lift: Correlation display for the upper Aurora and lower Ivishak pools Depth Well View #1 Z Veil Sketcr ID PFC.) PFC2 CCLD GR (ft) (ft -> Top) (in) - in 6 2 in 8 2 in = • 8 0 GAPI 300 9350 7500 - 874874 r . __ r p i t _ A . _ a t ,,,.. „,, (i ^ 1 I ! Depth Well View #1 Z Nell Sketcf ID PFCI PFC2 CCLD GR (ft) (ft -> Top) (In) -6 In 6. 2 in 8 2 in 8 -6. 8 0 GAPI 300 7500 6000 -7 874874 :£ 7-_— -. 7 — — — t P1 : 1 i 4 ono I _ _ i nn --' i � lll 7 -onn 13 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 2.1 MMSCF Gas Lift: PSP sensors up and down passes overlay display for the upper Aurora and lower Ivishak pools Dept!' Z 'ell Skett ID WPRE WT EP UWFD SCVL SPIN (hi (in) -6 in 6 960 psis 1130 178 F 208 0 9 /cc I -120 ft/min 140 -10 rps 45 1: . 1 I ■ i ____ -�, i _ II I i I - - I 1 I I 1 I ` I I 1 I {+ z 1, H ' _ 1 i ; i i '''H' 1 1 ! 1 1 - _ ! ! I I ■ !` I 1 ! ?eptF Z ellSket ID WPRE WI EP UWFD SCVL SPIN (It) On) -6 in 6 1350 psia 1520 212 F 226 0 grcc 12 -140 ft'mui 140 -15 fps 30 J � L -- I t I .., { I i , 1 1 _= - i I' - - f ----; \ ,\,.. - 1 r 1 14 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 2.1 MMSCF Gas Lift: DEFT down passes overlay display for the upper Aurora and lower Ivishak pools Depth Z DFH1 DFH2 DFH3 DFH4 DIRE YW_DFT DEFT Dn94 (ft) -0 2 1 2 -0 .2 1 2 -0 2 1 2 -0 2 1.2 0 360 0 1 0 1 T ® f, i r ; b — il 1 _. ! _ _ _ ....at, n ; " i lk I 1 r Isi - - I ! j .-:„, . -....., . 1117 , - g i 4 1 T 1 t i ..p. 1 - = .....T X 31 r i Depth Z DFH1 DFH2 DFH3 DFH4 DiRB YW_DFT DEFT Dn113 (6) -0 2 1.2 -0 2 1 2 -0 2 1 2 -0 2 1 2 0 360 0 1 0 1 - ► — �.. ' �� r ,� 1 • z l I , { , f _ = L a 1 C t--.3 i -F ,, - - -f ±_ ) - - rl - _ 1 ' � r .1 T �_ I 4 - - - � - .- .. 1 t n I 4 1 15 �� BP Exploration (Alaska), Inc. Well: S-26 Job Number: 12017505 Field: Prudhoe Bay 2.1 MMSCF Gas Lift: GHOST down passes overlay display for the upper Aurora and lower Ivishak pools. Note high water holdup due to recirculation in the 9.625 casing interval. Depth Z GHH5 *y*n Gm*" GHH8 01R62 ,s o*ooro"*^ .� 0 . o / o ` 0 / " ' 360 o . o�� _---_ ��. .�� mom. � � � | ,� � � ° = -c^__ � _ � - / | / - | — , / / � / - - _ / � � �� ' --- / [ Ii, % ' . '' ] _ 5 � � � ^~^-- - ! �--- ��_ _ — — _ — — � ~� ,. _ _ _ ��' -, �—. I / �� _ I r--- A.- � � �� __ - - - - �~.- r / I i ��' - c | ^�' __ � � | ' -. . __- ,_ -__ , � � I � � ~ �, �� J __ _,~ — � =�� , 7 � ( y ' / ' | Depth z o**o upmn GHH7 GHH8 mRBu ,G s*000"/oo '11; 0 / v / v , v / o 360 u , n KEREM ` - - - i ] | | | -` ^' -��' __ �` 1�� '� -��` _ _- - - .--- - -: . . . .7. _ ... ;:,-' . 1 ...... '''./.: . 4- ,. :7: rife `.. ' 16 • . BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.3. Spinner Calibration: 0 _30 13 _20 ® X /P ® _10 , -160 44000/frary•,, 80 160 _ -10 _ -20 _ -30 _ -40 rps versus ft/min Threshold ( +) 11.5 ft/min Threshold ( -) -11.5 ft/min Calib. Zone Slope ( +) Slope ( -) Int ( +) Int ( -) Int. Duff. ft ft/min ft/min ft/min E 6715.0- 6751.0 0.089 N/A - 285.98 N/A 0.00 ✓ 6783.0- 6853.0 0.098 N/A 40.49 N/A 0.00 + 7059,0- 7179.0 0.089 N/A - 184.45 N/A 0,00 X 8585.0 - 8642.0 0.089 0.089 - 124.17 - 146.25 22.08 L1 8699.0- 8903.0 0.089 N/A -35.35 N/A 0.00 ✓ 8967.8- 8984.9 0.112 0.057 -17.12 -40.12 23.00 * 9007.0- 9024.0 0.101 0.080 13.11 -9.89 23.00 3.5 MMSCF Gas Lift: Spinner Calibration plot. Default 0.089 spinner slope used in 4.5" tubing section for consistency between flowing rates. 17 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay _30 u - X 20 0 v j .- B ' 10 J X -160 160 _ -l _ -20 _ -30 _-40 rps versus ft/min Threshold ( +) 11.5 ft/min Threshold ( -) -11.5 ft/min Calib. Zone Slope ( +) Slope ( -) Int ( +) Int ( -) Int. Diff. ft ft/min ft/min ft/min o 6715.0- 6751.0 0.089 N/A - 302.94 N/A 0.00 Q 6783.0- 6853.0 0.080 N/A -84.45 N/A 0.00 + 7059.0- 7179.0 0.089 N/A - 199.78 N/A 0.00 X 8585.0 - 8642.0 0.089 N/A - 145.38 N/A 0.00 A 8699.0- 8903.0 0.089 N/A -44.94 N/A 0.00 ✓ 8968.2 - 8988.7 0.109 0.080 -10.69 -41.41 30.72 * 9007.0- 9024.0 0.091 0.092 5.71 -17.29 23.00 2.1 MMSCF Gas Lift: Spinner Calibration plot. Default 0.089 spinner slope used in 4.5" tubing section for consistency between flowing rates. 18 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 3.4. Summary Table Results: Summary table for 3.5 MMSCF Gas Lift. From ,ft 6870 8951 8965 8995 9022 To , ft 6894 8960 8990 9012 9053.3 Water FVF 1.0268 1.0389 1.0397 1.0412 1.0418 Viscosity, cp 0.3698 0.291 0.2875 0.2816 0.2791 Density, g/cc 0.99 0.98 0.98 0.98 0.97 Oil +Gas FVF 1.1311 1.1861 1.1889 1.1911 1.1926 Viscosity, cp 1.9065 1.1738 1.149 1.1216 1.1081 Density, g /cc 0.81 0.79 0.78 0.78 0.78 Gas FVF 0.0159 0.0114 0.0113 0.0113 0.0112 Viscosity, cp 0.0141 0.0158 0.0159 0.0159 0.016 Density, g /cc 0.061 0.0849 0.086 0.0859 0.0862 Temp. F 182.42 217.27 219.25 222.73 224.21 Press psia 1012.9 1476.6 1500.3 1511.5 1521.4 Diameter 8.681 6.275 6.275 6.275 6.275 Devi. ° 19.51 4.9 4.93 4.88 4.81 Roughness 1.42E -04 1.59E -04 1.59E -04 1.59E -04 1.59E -04 Rs, cf /bbl 164 235 238 238 239 Rsw, cf /bbl 6.42 8.6 8.73 8.8 8.86 Q tot res., B/D 5726.62 3044.4 454.8 267.63 0 dQ res., B/D 1717.44 2588.2 187.56 267.63 0 % Qt 36.07 54.36 3.94 5.62 0 Qw tot res., B/D 312.76 264.22 264.42 264.79 0 Qw tot s.c., STB/D 304.61 254.32 254.32 254.32 0 dQw res., B/D 51.64 0 0 264.79 0 dQw s.c., STB /D 50.29 0 0 254.32 0 Qo tot res., B/D 569.94 281.58 55.53 2.83 0 Qo tot s.c., STB /D 503.87 237.41 46.71 2.37 0 dOo res., B/D 297.87 226.15 52.71 2.83 0 dQo s.c., STB/D 263.35 190.7 44.33 2.37 0 Qg tot res., B/D 4843.91 2498.59 134.85 1.00E -02 0 Qg tot s.c., Mscf /D 1799.84 1288.67 80.59 2.81 0 dQg res., B/D 1367.93 2362.05 134.85 1.00E -02 0 dQg s.c., Mscf /D 527.86 1208.08 77.79 2.81 0 Yw 0.304 0.497 0.912 0.997 1 Yo 0.393 0.122 0.039 0.002 0 Yg 0.303 0.38 0.049 0.001 0 Regime Elongated bubble Elongated bubble Bubble Bubble No flow Corral. Petalas and Aziz Petalas and Aziz Petalas and Aziz Petalas and Aziz Petalas and Aziz Stanford Drift Stanford Drift Stanford Drift Stanford Drift Stanford Drift Corral. W-O Flux LL Flux LL Flux LL Flux LL Flux LL 19 0 III BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay Summary table for 2.1 MMSCF Gas Lift. From , To , ft ft ( I I I 6894 8960 8990 9012 I 2 91186 Water FVF 1.0272 1.039 1.0396 1.0412 1.0417 Viscosity, cp 0.367 0.2911 0.2881 0.2817 0.2797 Density, g/cc 0.99 0.98 0.98 0.98 0.97 Oil+Gas FVF 1.1295 1.183 1.1857 1.188 1.1892 Viscosity, cp 1.9106 1.1871 1.1638 1.1342 1.123 Density, g /cc 0.81 0.79 0.78 0.78 0.78 Gas FVF 0.0161 0.0115 0.0114 0.0114 0.0114 Viscosity, cp 0.0141 0.0158 0.0158 0.0159 0.0159 Density, g/cc 0.0594 0.0828 0.0839 0.0838 0.0841 Temp. F 183.43 217.26 218.94 222.65 223.86 Press psia 1005.4 1465.6 1489.9 1501.3 1509.1 Diameter 8.681 6.275 6.275 6.275 6.275 Devi. ° 19.51 4.9 4.93 4.88 4.81 Roughness 1.41 E-04 1.59E -04 1.59E -04 1.59E -04 1.59E -04 Rs, cf /bbl 160 230 233 233 234 Rsw, cf /bbl 6.37 8.55 8.67 8.75 8.8 Q tot res., B/D 5845.62 3126.82 475.16 269.24 0 dQ res., B/D 1742.04 2649.99 206.32 269.24 0 % Qt 35.79 54.44 4.24 5.53 0 Qw tot res., B/D 324.06 265.63 265.79 266.19 0 Qw tot s.c., STB/D 315.49 255.66 255.66 255.66 0 dQw res., B/D 61.45 0 0 266.19 0 dQw s.c., STB/D 59.83 0 0 255.66 0 Qo tot res., B/D 570.39 344.15 68.05 2.45 0 Qo tot s.c., STB/D 505 290.93 57.39 2.06 0 dQo res., B/D 237.59 276.22 65.6 2.45 0 dQo s.c., STB /D 210.38 233.54 55.33 2.06 0 Qg tot res., B/D 4951.17 2517.04 141.32 0.6 0 Qg tot s.c., Mscf /D 1811.29 1293.6 85.3 3.01 0 dQg res., B/D 1443 2373.77 140.72 0.6 0 dQg s.c., Mscf /D 537.65 1208.3 82.29 3.01 0 Yw 0.307 0.474 0.902 0.997 1 Yo 0.386 0.148 0.047 0.002 0 Yg 0.307 0.378 0.051 0.001 0 Regime Elongated bubble Elongated bubble Bubble Bubble No flow Correl. Petalas and Aziz Petalas and Aziz Petalas and Aziz Petalas and Aziz Petalas and Aziz Stanford Drift Stanford Drift Stanford Drift Stanford Drift Stanford Drift Correl. W-0 Flux LL Flux LL Flux LL Flux LL Flux LL 20 • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 4. Table of abbreviations: Tool Mnemonic Channel Description Units: Description CVEL Cable velocity CCLD / B/D Barrels per Day CCLC Casing Collar Locator Discriminated / Calibrated DFB1 /2/31 scf /bbl Standard Cubic Feet per Barrel 4 DEFT bubble count per probe DFH1 /2/3/ cp Viscosity centipoises 4 DEFT water holdup per probe ft/m Feet per minute SCV1 Depth corrected cable speed to in -line spinner g /cc Grams per cubic centimeter SCVL Depth corrected cable speed to spinner MMSCF /D Million Standard Cubic Feet per Day GHHM2 Field calculated combined gas holdup MSCF /D Thousand Standard Cubic Feet per Day DFHM Field calculated combined water holdup Res. To denote reservoir conditions (downhole) MWFD Field pressure derived density rps Revolutions per second GR Gamma Ray GHB1 /2/3/ S.C. To denote surface conditions (uphole) 4 GHOST gas bubble count per probe GHH1/2/3/ SCF Standard Cubic Feet 4 GHOST gas holdup per probe STB /D Stock Tank Barrels per Day SPI1 In -line spinner WPRE Pressure PVT: Pressure Volume Temperature DPHZ Pressure derived density (from Emeraude) Bo Oil volume factor PFC1 / PFC2 PSP Caliper 1 and Caliper 2 Bw Water volume factor O Rate Relative bearing for probe 1 of second tool Bg Gas volume factor D1 RB2 (GHOST) FVF Fluid volume factor D1 RB Relative bearing of probe 1 GOR Gas Oil Ratio SPIN Spinner (fullbore or turbine) Watercut Ratio of produced water to total fluids WTEP Temperature Holdup Fraction of fluid present in an interval of pipe TENS Tension Uncorrected Fluid Density (from UWFD gradiomanometer) Interpretation: WFDE Well fluid density (from gradiomanometer) Correlation Model L-G: Liquid Gas W -H: Water Correl. Hydrocarbon; O -W Oil -Water ID Internal Diameter PSP Production Services Platform O Cumulate Rate with continuous solution DEFT Digital First Entry Tool (Water holdup) QZI Incremental rate per zone GHOST Gas Holdup Optical Sensor Tool (Gas holdup) QZT Cumulative Rate track with zonal contribution Regime Modeled Spinner Calibration: Slope of rps/ (ft/m). Defines conversion of YG Gas Holdup Slope spinner to velocity. YO Oil Holdup Int Intercept of line of slope (defines velocity) Difference between up /down passes. This is the YW Water Holdup Threshold velocity required to initiate rotation of the spinner. YW DFT Water Holdup from DEFT Z Zone: Yellow - spinner calibration Red - Perforation White - Inflow Zones Gray: Calculation (stable) zone 21 • • BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 5. Tool Diagram: DOWNHOLE EQUIPMENT MH-22 48.9 MH SAH - G 47.3 SAH 1015 EQF - 43 1 45.8 EOF EQF -43 ' 39.8 EOF-43 EQF -43 1 33.8 EOF-43 Dotal MT TelStatus CTEM 1 _ 27.8 PSPT -A/B 27.8 P3C-A PSPT -B 870 PSTC 876 PBMS -B 878 GR _ 24.1 COG F Mono RTD Thermometer OR 676 Well Temp 21.1 CCL 876 COG Mranom — 20.7 PBMS 876 CCL = 20.3 PBMS PSTC 19.6 PGMC - A B 19.6 PGMC -A 1839 Gradioman _ 18.1 PSOI 3726 PGMC 14.8 PILS - A 14.8 PILS - A889 Spinner — 132 GHOST - A2 12.3 Flowmeter Probes 733 Relative Bearing 733 G GHOST2 Ca ,/ 7.1 GHOST2 Ca 5.1 PFCS Spin PFCS Cal 1.9 PFCS -A PFCS Prob / 5.1 Holdup Probes 762 GHOS We HV Spinner 2.5 762 GHOST2 Re Relative Bearing PFCS Wave Caliper 762 PFCS Rela PFCC -A 762 PFCS Cart PFCH -A 762 Tension \ 0,0 TOOL ZERO MAXIMUM STRING DIAMETER 1.69 IN MEASUREMENTS RELATIVE TO TOOL ZERO ALL LENGTHS IN FEET 22 BP Exploration (Alaska), Inc. Well: S -26 Job Number: 12017505 Field: Prudhoe Bay 6. Well Schematic: TREE = 4' OW �1 ^ SAFETY NOTES: NOTIFY GC OF ANY WELL A - RIATOR 0113 \ - f '� O OPEDERATION T0 SKID F OWLB�E (POTENTIAL KB. ELEV = 65.09' v EROSION) "`"CIROMETBCi'"'PINHOLE LEAK IN 9-3/8' BF. ELEV = 37.49' GSG N 7200 - 9464""' KOP= 4400' I '1a e- xAngl23 °Q D1 7 8 ' ' ' I 2029' H4- 1/7 FiES XNP ID= 3813' 1 Datum MC = 30 Datum TVD = may SS GAS LIFTMANDRE_S 120" CONDUCTOR, D = ? H 110' ST MC TVD CEV TYPE VLV LATCH PORT DATE 4 3635 3635 0 M&MG DOME PK 15 05/14/08 13 -3'8" CSG, 8811, L -30 BUTT, ID - 12.415' 2683' 3 5304 5251 23 1,94C DMV FE 0 04118/08 2 6217 6094 22 M943 DMY PK 0 05/27/08 I4 - 1/2" SYMPHONY GL/A3Ew11 - A/RE IC = 3.94" H 6608' I M 1 6537 6391 21 WAG SO PK 22 05/27/08 I I 6670' H41/2" IBS X NI', IU= 6 -813" I Minimum ID = 3.80" @ 8613' 4-1/2" OTIS XN NIP, MILLED OUT 6691' H9- 5 /8" X4 -1/2" BKRS -3 PKR iD= 3875' J I 6715' H4- 112 " FESX MPH) = 3.813" I 4-1/2" TB3, 12.6A. 13CR VAM TOP. -"I 6780' l \ .0152 bpf, ID= 3 - 958" , I 6780' H 412 "W/LEG . ID= 3.958' I P1V HOLE LEAK Fl 9-5/8" COG -o (BERND LOWER ISOLATION STRING) P0721 7042• H9- 5B " X4- 1 /2' BKR S -3PKR0 =3.875 I 4.1/2" TB3, 1264, 13CR VAM TOP. -{ 8515' j' I 7066' H4-1 I#S X NP, ID= 3.813' 1 .C152 bpf, ID = 3.958" IL- 112"TBG STtE (12/29-07) H 8520' I r / 8531' "19 60 "X41 /2" UNIQUE OVERSHOT I ,-. 8540' I 518" X 4 112' OTIS FKR IC - 3.85'1 )TOP OE T LNR 1—E83757-1 8570' H 9-5)8' X /' LM( NUN, U ='/ I I I 8593' I - 1412 " PARKER SWS NP, 0= 3.813' I I I 8613' H4 "0113Xn NN, MLLEU it) S.80 "(12 /2t /u1) I 14- 112" TBG 126#, L-E0 TDB, . 0152 tact, i0.3.958' H 8625' I — ' I 8625' H4.12" W/LEG, D= 3.958' I 1 E-5I8" CSG, 478 NTBr ntscr, O = A 6411" H 8816' 8627' H ELMOTTLOGGE006/15'9C I PEKI-ORA I ION SLIMA KY REF LOG SWS 131 - CS ON 05/24/60 ANGLE AT TOP FEFF: 19' (c) 6873' NJte. Rut ,u R r-duotiun DB for I/iatta Lral pert data I 9030' H7" ZONA ISO.ATION PKR (07/28/97) I SILL BPI IV'. EKVAL OprVSg3 DA I_ 3 -3/3' 4 8870 - 8894 0 04/33/08 3 -3/3" 4 8951 -8961 0 08/26/90 -I 9139' 1- FBH- BKR ECP. SCOOP GUDES, 3.314° 4 3965 -9063 C 08fl6U90 • RUVN*40 TOOL. AND OLD BP 33/3° 4 9085 - 9130 S 09/10194 3 -3/3" 4 9184 - 9186 S 09/10/94 I 9178' 1-1 7" MARKER JC4M 1 iPBTDiTAG:E001 /17,93) li 9 ,, ♦ , ♦ , ` , , ., 4 ,., 17° LNR 2811, L -80 343, .0293 bpf, 13= 6.276° H 943d' 1 DATE REV BY COMMENTS DATE RE)/ BY COWE4TS PRJGNOE SAY UNIT 06/04/90 N18E ORIGINAL COMPLETION 05/14,08 KSB/71H GLV GO WELL 5-26 01/02/08 014 RWO 0601;06 - )AVT1 T) Cl V CIO (5'27 +09) PERMIT Vn F 1900531 04 /C6/06 FRCI SV PERFORATIONS (04103/08) 0710208 DHCVPJC DRLG OFAFT CORRECTIONS API Vo. 50- 029 - 22047 -0C 04 /CO /00 DAV /PJC GLV 010 09'36,00 - AR/PJC MLL (A00RILL (00/17/00) 3CC 35, T12N, R12E, 1335 PHI 8116C' IVA 04 /20 /08 KSH+WLI GLV LA/ 051C9/08 ?/ PJC DREG DRA FTCORRECTIONS BP Exploration (Alaska) 23 • 6 • • November 9, 2005 Presentation BPXA, CPA and Exxon Gas Cap Water Injection Presentation (held confidential) ~8 Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Group 1 IPA Group 2 GPMA Group 3 Satellites Annual Surveillance Report 15-Mar 15-Jun 15-Sep Annual Overview Presentation 22-Mar 22-Jun 22-Sep Production Period to be Covered Jan 1-Dec 31 Apr i-Mar 31 Jut 1-Jun 30 e e Amends Order/Rule Order Date Comment Group 1 - IPA Oil Pools Note C0341 E (modified Pool Definition to Prudhoe Oil Pool C0341 0 Rule 11 11/30/2001 include a portion of Put River Sandstone) Put River Oil Pool C0559 11/22/2005 Corrected 2/14/2006 Group 2 - GPMA Oil Pools Lisburne C0207,207A No rule on Surveillance reports Niakuk C0329A Rule 9 6/4/1996 North Prudhoe Bay C0345 Rule 8 12/16/1994 pt. Mclntvre C0317B Rule 15 4/19/2000 Raven Oil Pool C0570 Rule 10 8/9/2006 West Beach Oil Pool C0311B Rule 13 8/1/2000 Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Rule 8 6/25/2004 (corrected 8/9/2004) Boreallis C0471 Rule 4 5/29/2002 Midnight Sun C0452 Rule 11 11/15/2000 Orion C0505A Rule 9 4/28/2006 Polaris C0484A Rule 9 11/3/2005 [Fwd: [Fwd: Re: surveillance report dates]] . . Subject: [Fwd: [Fwd: Re: surveillance report dates]] From: Jane Williamson <jane _ williamson@admin.state.ak.us> Date: Fri, 20 Apr 2007 13:03:59 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us>, Dave Roby <dave_roby@admin.state.ak.us>, Cathy P Foerster <cathy _ foerster@admin.state.ak.us>, Alan J Birnbaum <alan _ birnbaum@law.state.ak.us> CC: Stephen E Mcmains <steve_mcmains@admin.state.ak.us>, art Saltmarsh <art _saltmarsh@admin.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us> There is something I didn't get around to before I left and that was to administratively amend the COs for PBU to include reporting dates agreed to verbally with BP (and DNR). Really, only pt. Mcintyre and Borealis have the wrong dates in the CO's. The others are either ok, or not explicit. Attached are the COs affected. I'm not sure how you want to handle. Jody. Please put this in the following CO files along with the attachment. Group 1 - IP A Oil Pools Prudhoe Oil Pool C0341D Put River Oil Pool C0559 Group 2 - GPMA Oil Pools Lisburne C0207, 207 A Niakuk C0329A Rule 9 North Prudhoe Bay C0345 Pt. McIntyre C0317B Raven Oil Pool C0570 West Beach Oil Pool C0311B Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Boreallis C0471 Midnight Sun C0452 Orion C0505A Polaris C0484A -------- Original Message -------- Subject:Re: surveillance report dates Date:Thu, 31 Aug 2006 17:27:45 -0800 From:Jane Williamson <¡ane williamson(cì¿admin.state.ak.us> Organization:State of Alaska To:Lenig, David C <David.Lenig(iì)bp.com> References:<CBF4D8E92B5A 704 79F64416582F6A17CB81AEO(cì¿bp 1 ancex005. bp 1.ad.bp.com> Oops Lenig, David C wrote: Hi Jane, 10f3 4/23/2007 9:50 AM [Fwd: [Fwd: Re: surveillance report dates]] . . I didn't get the attachment. David From: Jane Williamson fmailto:jane williamson@admin.state.ak.us] Sent: Thursday, August 31, 2006 5:14 PM To: Lenig, David C Subject: Re: surveillance report dates E-mail is fine. Attached is a list of the pools and orders/rules that will be amended with the Admin approval. Take a look and see if this looks right to you. (Note, I'm only listing the rules that are affected by the new dates - there may be additional amendments unrelated to the surveillance requirements that I've not listed.) J'm flexible on the date for the Overview presentation. I'd be fine with specifying it to be within one or two months of the report date rather than the POD overview that you've noted. What would you prefer? Lenig, David C wrote: Jane, Here is a table showing the dates for the various Reports and Presentations. I've added the production period as well. The IPA review date remains problematic due to the proximity to spring break but we seem to work around it each year. Would you prefer that I put this in a letter requesting the changes? I know we talked about this a little while ago I just haven't found the time. Thanks, David Plan of Development Production Period Jull-Jun30 IPA GPMA March 15 June 15 September 15 March 22 June 22 September 22 March 30 June 30 September 30 Janl-Dec31 Aprl-Mar31 Satellites Annual Surveillance Report Annual Overview Presentation -----Original Message----- From: Jane Williamson [mailto:jane williamson@admin.state.ak.us] Sent: Thursday, August 31, 2006 2:30 PM To: Lenig, David C Subject: surveillance report dates Hi David. When you get a second, could you please send back an e-mail that lists all the surveillance report dates that we've agreed to for all PBU pools (including GPMA)? Also, do you have dates for surveillance reviews? I'll go through the list and make sure the Conservation orders are correctly worded, then put out administrative amendments as necessary. I checked with Cammy and she said an e-mail is fine for starting the 200 4/23/2007 9:50 AM [Fwd: [Fwd: Re: surveillance report dates]] . administrative action Icess. . Thanks. Jane Williamson, PE <iane williamson((l}admin.state.ak.us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission Content-Type: application/vnd.ms-excel surveillance report.xls Content-Encoding: base64 300 4/23/2007 9:50 AM *7 bp - .. o B P Exploration (Alaska) Inc. 900 East Benson Boulevard PO. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 November 30, 2001 Cammy Oechsli Taylor Chairperson Alaska Oil and Gas Commission 333 West ih Ave, Suite 100 Anchorage, Alaska 99501 Re: Prudhoe Oil Pool Gas Cap Water Injection Letter of Non-Objection Dear Ms. Taylor: BPXA, as Operator of the Prudhoe Oil Pool, does not object to the AOGCC's plan to revoke Rule 4 of Conservation Order 341 C. We understand that the effect of this revocation will be to make the practices that are currently covered by Rule 4 subject instead to the Commission's regulations, as revised in 1999. Please let me know if you have any further questions or comments on this issue. æ;UII~ Perry Richmond Manager, East/West Group Prudhoe Bay BP Exploration (Alaska) Inc. RECE\\/ED Alaska on & Gas líQfl5~,t;oInmlSSï(ìf Äl'!cnorag . ~6 bp .. November 1, 2001 Cammy Oechsli Taylor Chairperson Alaska Oil and Gas Commission 333 West 7th Ave, Suite 100 Anchorage, Alaska 99501 Re: Prudhoe Oil Pool - 0···················· :_·,C" BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Gas Cap Water Injection Hearing Testimony Additional Information Dear Ms. Taylor: Enclosed please find the additional information requested at the Hearing: 1) Section 4 - Water Movement Exhibits 7-11 2) Section 5 - MGS Relationship Exhibit 6 3) Section 6 - Surveillance Exhibits 5-6 4) Pressure Decline by region 5) Detailed Gas Cap map with well locations 6) Testimony Exhibits and text including movies 7) Section 4 - Water Movement Movies 8 1 /2x11 hard copy 8 1/2x11 hard copy 8 1 /2x11 hard copy hard copy graphs desk top size hard copy digital format on CD 8 1 /2x11 hard copy We understand upon receipt of this information, the record is closed. Please let me know if we can be of further assistance. Respectfully --P~æ;( Perry Richmond Manager, EastlWest Group Prudhoe Bay BP Exploration (Alaska) Inc. RECEIVED NOV 0 1 2001 Alaska Oil & Gas Cons. CommIssIon Anchorage · -- The following provides a list of additional material provided to the AOGCC from BP (Perry Richmond) in support of the GCWI testimony. Provided 11/06101. List and Addendum #'s compiled by Jane Williamson. ADDENDUM DESCRIPTION A-I 1980 OIL SATURATION MAP A-2 1990 OIL SATURATION MAP A-3 2000 OIL SATURATION MAP A-4A A-4B 2010 OIL SATURATION MAP wi GCWI 2010 OIL SATURATION MAP nol GCWI A-5A A-5 B 2020 OIL SATURATION MAP wI GCWI 2020 OIL SATURATION MAP nol GCWI A-6A A-6B 2031 OIL SATURATION MAP wi GCWI 2031 OIL SATURATION MAP nol GCWI B-1 Year 2000 Filed C1/C3 Ratio B-2 Year 2000 C1/C3 C Water Saturations - X-Section Model Locations Shown for C and D x-section slices Vertical Water Saturations Year 2005 GCWI Vertical Water Saturations Year 2010 GCWI Vertical Water Saturations Year 2015 GCWI Vertical Water Saturations Year 2020 GCWI Vertical Water Saturations Year 2025 GCWI Vertical Water Saturations Year 2031 GCWI C-l C-2 C-3 C-4 C-5 C-6 D-l D-2 D-3 D-4 D-5 D-6 Vertical Water Saturations Year 2005 GCWI Vertical Water SaturationsYear 2010 GCWI Vertical Water Saturations Year 2015 GCWI Vertical Water Saturations Year 2020 GCWI Vertical Water Saturations Year 2025 GCWI Vertical Water Saturations Year 2031 GCWI E Water Saturations - X-Section Model Locations Shown for E x-section slices Vertical Water Saturations Year 2005 GCWI Vertical Water Saturations Year 2010 GCWI Vertical Water Saturations Year 2015 GCWI Vertical Water Saturations Year 2020 GCWI Vertical Water Saturations Year 2025 GCWI Vertical Water Saturations Year 2031 GCWI E-l E-2 E-3 E-4 E-5 E-6 GCWI ADDENDUM A-I BP FFCM BP provided to AOGCC ¡ J /06/0 J Base Case at 1/1/1980 Base of Zone 3, Model Layer 10 GCWI ADDENDUM A-2 1990 OIL SATURATION MAP BP FFCM BP provided to AOGCC 11/06/01 Base Case at 1/1/1990 Base of Zone 3, Model Layer 10 GCWI ADDENDUM A~3 2000 OIL SA TURA TION MAP BP FFCM BP provided to AOGCC 11/06/0 J A-4A OIL SATURATION MAP wI GCWI BP FFCM BP provided to AOGCC ] 1/06/0] GCWI ADDENDUM A-4 B 2010 OIL SATURATION MAP No GCWI BP FFCM BP provided to AOGCC 11/06/0] Base Case at 1/1/2010 Base of Zone 3, Model Layer 10 A-SA OIL SA TURA TION MAP GCWI P FFCM provided to AOGCC I J/06/0 j GCWI ADDENDUM A-5 B 020QIL SATURATION MAP o GCWI BP FFCM BP provided to AOGCC 11/06/01 GCWI ADDENDUM A-6 A GCWI at 1/1/2031 of ZOl1e 3, Model Layer 10 ÇWI ADDENDUM A~6 lOlL SA TURA TION MAP No GCWI BP FFCM BP provided to AOGCC ¡ ¡ /06/0 ¡ at 1/1/2031 Base of Zone 3, Model Layer 10 Vertical Water Saturations Year 2005 GCWI BP FFCM 1=65 provided to AOGCC 11/06/01 1=65. 30X Vertical Exaggeration CWI ADDENDUM Vertical Water Saturations Year 2010 GCWI BP FFCM 1=65 BP provided to AOGCC 11/06/01 GCWI at 1/1/2010 1=65, 30X Vertical Exaggeration "'CWI ADDENDUM C~3 erticaI Water Saturations Year 2015 GCWI BP FFCM 1=65 BP provided to AOGCC 11/06/01 1=65, 30X Vertical Exaggeration GCWI ADDENDUM C-4 Vertical Water Saturations Year 2020 GCWI BP provided to AOGCC 11/06/01 1=65, 30X Vertical Exaggeration GCWI ADDENDUM C-5 Vertical Water Saturations Year 2025 GCWI BP provided to AOGCC 11/06/01 1=65, 30X Vertical Exaggeration GCWI ADDENDUM C-6 Vertical Water Saturations Year 2031 GCWI BP provided to AOGCC 11/06/01 GCWI at 1/1/2031 1=65, 30X Vertical Exaggeration GCWI ADDENDUM D-l Vertical Water Saturations Year 2005 GCWI BP provided to AOGCC 11/06/01 GCWI at 1/1/2005, Base Zone 3 Cross Section #2 GCWI ADDENDUM Vertical Water Saturations Year 2010 GCWI BP provided to AOGCC 11/06/01 GCWI at 1/1/2010, Base Zone 3 GCWI ADDENDUM D-3 Vertical Water Saturations Year 2015 GCWI BP provided to AOGCC 11/06/01 GCWI ADDENDUM D-4 VemcalWater Saturations Year 2020 GCWI BP provided to AOGCC 11/06/01 GCWI at 1/1/2020, 8ase Zone 3 Cross Section #2 GCWI ADDENDUM D-5 Vertical Water Saturations Year 2025 GCWI BP provided to AOGCC 11/06/0 1 GCWI ADDENDUM Vertical Water Saturations Year 2031 GCWI BP provided to AOGCC 11/06/01 GCWI at 1/1/2031, Base Zone 3 Cross Section #2 GCWI ADDENDUM E BP provided to AOGCC 11/06/01 3 GCWI ADDENDUM E-l W3ter S3tur3tions Year 2005 GCWI BP provided to AOGCC 11/06/01 GCW¡ at 1/112005 30X Vertical GCWI ADDENDUM E-2 Vertical Water Saturations Year 2010 GCWI BP provided to AOGCC 11106/01 at 1/112010 Vertical Exaggeration GCWI ADDENDUM Vertical Water Saturations Year 2015 GCWI BP provided to AOGCC 11/06/01 GCW¡ at 1/1/2015 GCWI ADDENDUM E-4 Vertical Water Saturations Year 2020 GCWI BP provided to AOGCC 11/06/01 at 1/112020 GCWI ADDENDUM E-5 Water Satu.rations 2025 GCWI BP provided to AOGCC 11/06/01 at 1/112025 GCWI ADDENDUM Vertical Water Saturations Year 2031 GCWI BP provided to AOGCC 11/06/01 GCWI at 1/112031 30X Vertical Exaggeration FFCM Pressure Prediction .. Cap Area 00 3900 3700 3500 3300 3100 . 2900 2700 500 1990 2 0 010 2020 030 04 GCW! MJW 11/13/01 100 3900 3700 35 3300 31 27 GCWI BP FFCM Pressure Prediction - Gravity Drainage Area 1 5 o 1 o 5 MJW 11/13/01 GCWI ADDENDUM B-1 Year 2000 Filed CVC3 Raito Actual Field Measunnents Id 3 tio BP provided to AOGCC J J/06/0] :;CWI ADDENDUM B-2 i ear 2000 C1IC3 3P FFCM Prediction tio provided to AOGCC 11/06/01 4100 3900 3700 3 0 3300 31 2700 GCWI BP Prediction", Gravity DrainagelWF 1 2035 o 15 MJW 11/13/01 100 3900 3700 3500 - 3300 3100 2900 700 2500 GCWI FFCM Prediction M Western 2000 2005 2010 201 o 2025 o MJW 11/13/01 4100 3900 3700 3 3300 3100 27 GCW! Pressure Prediction - Mid and Eastern 1 5 10 201 2020 2025 MJW 11/13/01 of Pulsed Neutron Logging 30,2001 Exhibit 5 ater . emaln r Slowdown 8 9DVIEW Stwdy[udv$] Caaer] T$me[01-JAN-20j5. 1 dayaJ T"i tneStep[ 28] Az. Inj ectors Water Movement Exhibit 9 9DVIEW Study[udv$] Daae[] T$me[Ql ~AN-2a2Q_ 15588 daya] T $ me S t e p [ 27 ] Az GCWI ectors 30,2001 Movement Exhibit 10 9DVIEW Stwdy[udv~] Ca.~[] T !I IT! ~ [ a j - .J AN 2 a 9 j _ :I 98 a 4 day $; ] T'im~St~p[ 29] Ax. GCWI Inj Movement 11 11III Map of , case , time::: 0.01 , case = III , time::::: 60.01 of , time:: 90.01 , case !III 1 x2 Dimensions: 42xlx50 Map of 'SW', case 'Otest', time == 120.01 11II 1 x2 42xl Map of , case 'Dtest', time::: 150.01 ::::: 180.01 Map of 'SW', case , time::: 0.01 Map of ::::: , case III! = 11III ft, x50 Map == , case 11II 'SW', case ,time:::: iIII lx50 = 360.01 , case Di1nensions: 42x 1 x50 of = , case III Map of 'SW', case ::::: II , case 'Otest', time :::::: II of , case 'Otest', time::::: 480.01 II of , case ,time = 51 of 'SW', case ,time::::: 11II 'SW', case =: Map , time::::: 600.01 11II of , case 'Dtest', ::::: IIIi Map of '5W', case , time::: 660.01 iii lx50 of :: , case B lx50 'SW', case ::::: II of 'SW', case 'Otest', := of := 780.01 , case 11II :: 0..01 118 Map of 'SW', case ::: 840.01 III! 'SW', case = fill! Map 'SW', case , time = 900.01 of , time = , case 11II ::: IIIi Map of :::::: , case :::: 1 , case III 1 lx50 Map of ::: , case Map of , time = 1 , case iii! of := 111 , case of 'SW', case == 11 11II lx50 of :::::: 11 , case II of 'SW', case ::::: 11II == 1 11II Map , time:::: 1 , case 11II e , time:::: 1 III Map =1 1 lx50 of :::: 1 , case III of 'SW', case =1 11II :::: 1 , time =: 1 11III of , case =: 11II 1 x 2 42xlx50 of 'SW', case :::: of 'SW', case , time:::: 60.01 iii of 'SW', case ,time= 1 ac x 2 1 of , case 'Otest', time =: 120.01 x 2 ft, lx50 of == 1 , case III 1 x 2 . 42xl of 'SW', case 'Otest', ::::: 180.01 of 'SW', case ,time:::::: 210.01 of ,time:::::: , case ill 1 ac x 2 lx50 of 'SW', case 'Dtest', time ::::: 11III 1 x 2 42xl of 'SW', case 'Dtest', time == 300.01 1 ac x 2 42xlx50 of == 330.01 , case III of 'SW', case 'Otest', == 11II 1 x 2 : 42xl of 'SW', case , time =: 390.01 11II of 'SW', case 'Dtest', :: 1 2 . 42xlx50 of case :: x50 of 'SW', case 'Otest', = 480.01 of , time =: 0.01 , case ill cf , time := 540.01 , case 1 2 1 x 50 of 'SW' case ·Otest·, time = 570.01 11III of 'SW', case 'Otest', time == of 'SW', case ,time:::: 1 x2 1 of'SW', == 11II of 'SW', case , time::::: 690.01 II!! of 'SW', case , time::::: 7:20.01 III cf , time == 750.01 , case 1/1 lac x 42xl of 'SW', case 'Otest', time :::: of 'SW', case , time:= 810.01 2 42xlx50 of 'SW', case , time :::::: III of 'SW', case , time::::: 870.01 .. of , case = ..;e. of := 930.01 , case ~ . . .." ... ",. . e 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 PUBLIC HEARING 3 In Re: 4 Application of BP Exploration (Alaska) 5 Inc., Prudhoe oil Pool - Modification to Pool Rules - Conservation Order 6 341C - Injection of Water into the Prudhoe Bay Gas Cap. 7 8 TRANSCRIPT OF PROCEEDINGS 9 10 Anchorage, Alaska October 30, 2001 9:00 o'clock a.m. CAMMY OECHSLI TAYLOR, Chairperson JULIE HEUSSER DAN SEAMOUNT 11 COMMISSIONERS: 12 13 ALSO PRESENT: ROBERT E. MINTZ Assistant Attorney General 14 * * * * * * 15 16 17 18 19 20 21 22 23 24 25 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 2 1 PRO C E E DIN G S 2 (On record) 3 CHAIR TAYLOR: Good morning. We'll call this meeting 4 -- this hearing to order. Today is Tuesday, October 30th, 5 2001, and the time is approximately 9:04. We're at the 6 offices of the Oil and Gas Conservation Commission at 333 West 7 Seventh Avenue. The subject of this hearing today 1S BP's 8 request for modification of the pool rules for implementation 9 of a Gas Cap Water Injection project in the Prudhoe Bay Oil 10 Pool. 11 First, I'd like to introduce people here at the head 12 of the room. To my far left is Julie Heusser. To my 13 immediate left is Rob Mintz, our Assistant Attorney General, 14 who is here to advise the Commission on procedural and legal 15 questions. My name is Cammy Taylor. To my right is Dan 16 Seamount. To our very far right is Julie Gonzales from Metro 17 Court Reporting. This proceeding will be recorded and 18 transcribed. If you wish to make arrangements for copies of 19 that transcript, you may do so directly with Ms. Gonzales 20 after the hearing. We would also ask that after the hearing 21 if all those people who are providing statements or testimony, 22 if you have cards with the correct spelling of your name, if 23 you wouldn't mind giving her a copy that would be helpful to 24 her. 25 Notice of this hearing was published in the Anchorage METRO COURT REPORTING, ING. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 e e 3 · 1 Daily News on September 29th, 2001. These proceedings today 2 will be held in accordance with 20 AAC 25.540. We will ask 3 that the applicant present testimony first, and if there are 4 any other persons wishing to testify, we will hear from them 5 afterwards. We would ask that all persons who are going to 6 testify today, that when they're sworn, that they provide 7 their full name, spell their last name, and identify who they 8 are representing so that that's clearly on the record. If you 9 wish to be considered as an expert witness, we ask that you 10 identify in what field you wish to be considered as an expert 11 and then provide us with that background. If there are any 12 other folks who wish to provide your statements afterwards, we · 13 will do so after all the testimony has been taken. 14 We ask that persons not ask questions directly. If 15 you have questions that you would like to have put to 16 particular witnesses, we ask that you write them down, that 17 you write down the name of the witness you wish the question 18 to be put to, identify yourself as well in the note and pass 19 it to one of the Commission representatives. And I'll ask 20 that -- there are at least four people in the back room, if 21 you can just raise your hand. If you'll pass whatever 22 questions you'd like to one of them, they'll make sure that it 23 comes up to the head table. 24 If there aren't any specific questions otherwise, why 25 don't we go ahead and start. We'll ask the applicant to · METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 4 1 introduce themselves and then we'll proceed. 2 MR. RICHMOND: Good morning, my name is Perry 3 Richmond. That's R-i-c-h-m-o-n-d. I am the East/West Prudhoe 4 Bay Waterflood Resource Manager for BP Exploration Alaska Inc. 5 BP is the Operator of the Prudhoe Bay Unit. 6 This hearing has been scheduled to consider 7 information supporting the modification of pool rules for 8 implementation of gas cap water injection in the Prudhoe Bay 9 Oil Pool. The Gas Cap Water Injection project is a result of 10 studies to mitigate reservoir pressure decline for the Prudhoe 11 Bay Oil Pool. It is a new element in the depletion strategy 12 of the Prudhoe Oil Pool and will improve recovery. 13 BP has previously submitted a request for revision to 14 the pool rules in correspondence to the Commission dated 15 September 21, 2001. I would like -- now like to give to the 16 Commission a copy of the testimony and exhibits we will be 17 presenting today. We will use a projector to display the 18 exhibits as we read our prepared testimony. 19 The testimony we are presenting will be given by 20 representatives of the Owners, BP, ExxonMobil and Phillips, 21 and is divided into seven parts. I will provide an overview 22 of the Gas Cap Water Injection project and a summary of other 23 pressure support options that were considered. I will also 24 give a closing statement summarizing requested changes to 25 Conservation Order 341C. Bharat Jhaveri will testify about METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 5 1 recovery benefitsl Matt Maguire about water movement I Lynn 2 Schnell about the relationship to major gas salesl and Jerry 3 Brady about surveillance. 4 A few notes about acronyms. We may occasionally use 5 the letters GCWI to refer to the Gas Cap Water Injection 6 project. You may also hear GDI which refers to the gravity 7 drainage area 8 of the field I and GDWFII G-D-W-F-II which identifies that part 9 of the field where gravity drainage and waterflood interact. 10 We will keep these terms to a minimum. We are asking that 11 each witness be qualified as an expert and each of us is 12 prepared to respond to questions concerning our testimony and 13 related exhibits. lId now like to be sworn and qualified as 14 an expert witness. 15 CHAIR TAYLOR: Before I swear you inl Mr. Richmondl is 16 this the binder that you provided to us this morning I is 17 that different than the one that was prefiled on Friday? 18 MR. RICHMOND: There are a few changes that we have in 19 the testimony here today and weIll note those when we give the 20 testimony. 21 CHAIR TAYLOR: Okay I thank you. Would you go ahead 22 and raise your right handl please. 23 (Oath administered) 24 MR. RICHMOND: I do. 25 CHAIR TAYLOR: Would you proceed and why don/t -- you METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . . . e e 6 1 wish to be considered as an expert witness? 2 MR. RICHMOND: Okay. 3 In the field of? Engineering? CHAIR TAYLOR: 4 Petroleum..... 5 MR. RICHMOND: Yes. 6 . . . . . Engineering? Okay. Would you go CHAIR TAYLOR: 7 ahead and state your qualifications for the record? 8 MR. RICHMOND: Okay. My name is Perry Richmond. I am 9 a Resource Manager for BP, currently responsible for managing 10 the Prudhoe Bay waterflood in the Northwest Fault Block and 11 Flow Station 2 areas. Technical staff in my group will be 12 responsible for implement -- implementing and monitoring the 13 Gas Cap Water Injection project. I received a Bachelor of 14 Science Degree in Petroleum Engineering from Texas A&M 15 University. I was employed by ARCO in 1982 and have worked on 16 numerous engineering projects in Texas, Alaska, and overseas. 17 I have worked on the Prudhoe Bay field since January, 1998. I 18 have been employed by BP since July, 2000. 19 CHAIR TAYLOR: Commissioner Heusser, Commissioner 20 Seamount, do you have any questions or any objection? 21 COMMISSIONER HEUSSER: No objection. 22 CHAIR TAYLOR: We'll go ahead and consider your 23 testimony as an expert witness. 24 MR. RICHMOND: I will now provide an overview of the 25 project. Since field startup in 1977, cumulative production METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 e e 7 · 1 from the Prudhoe Bay Oil Pool is now over 10 billion barrels. 2 This surpasses the original estimate of 9.6 billion barrels. 3 This excellent performance has resulted from optimizing total 4 recovery by progressively using multiple recovery mechanisms, 5 such as gravity drainage, gas cycling, oil vaporization, 6 waterflooding, and miscible flooding. These same recovery 7 mechanisms, particularly gravity drainage and gas cycling, 8 result in liquid hydrocarbon and gas voidage from the 9 reservoir, leading to a steady decline of reservoir pressure. 10 Exhibit 2 shows the history and forecast of reserVOlr 11 pressure under the existing recovery mechanisms. Currently, 12 reservoir pressure is declining at 25 to 35 psi per year. The · 13 Working Interest Owners have studied options to mitigate 14 pressure decline and have reported annually the progress of 15 these studies to the Commission. As a culmination of these 16 studies, the Working Interest Owners sanctioned the Gas Cap 17 Water Injection project in June, 2001. This project 18 represents a new element in the depletion strategy of the 19 Prudhoe Bay Oil Pool and will mitigate reservoir pressure 20 decline and improve recovery. 21 The project scope calls for ramping up to 650,000 22 barrels per day of seawater into the eastern portion of the 23 gas cap from an injection site located at the East Dock 24 Staging Pad. As shown by the chart, injection increases over 25 time. This is caused by the availability of more seawater as · METRO COURT REPORTING, INC. 745 West Fourlh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 8 1 demand decreases in other projects, such as the Flow Station 2 2 and Point McIntyre water floods and grind and inject. 3 Facility construction is planned for this winter, 4 followed by start-up of injection in mid 2002. Water 5 injection is anticipated to continue for 20 years, with a 6 final injected water volume near four billion barrels. The 7 increase in hydrocarbon liquid recovery is expected to be 150 8 to 200 million barrels. 9 To implement the Gas Cap Water Injection project, a 10 new seawater pipeline from Flow Station 2 to the East Dock 11 Staging Pad will be constructed. The new line will have a 32 12 inch diameter, with a total length of approximately 18,000 13 feet. It will tie into the existing 32 inch seawater line 14 running from the Eastern Seawater Injection Plant to Flow 15 Station 2. 16 Upgrades to pumps, piping, filters and plant control 17 systems are required at the Seawater Treatment Plant to 18 accommodate the seawater demand. For the Eastern Seawater 19 Injection Plant, waste heat louvers will be upgraded. A 20 heated pig receiver/manifold module and well houses will be 21 installed at the East Dock Staging Pad to accommodate five to 22 seven new injection wells. 23 Exhibit 5 shows the proposed bottomhole locations of 24 the new injection wells. The wells are strategically located 25 away from the gas injection areas to the west, oil production METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 9 1 at drill site 18 to the southwest¡ and truncation of the 2 Ivishak formation to the east. Basically¡ we want to optimize 3 injection by having sufficient Ivishak pay at the bottom hole 4 locations of the injectors¡ while maintaining sufficient 5 distance from the gas injection and oil producing areas. The 6 majority of the drill site 18 producers and all the gas 7 injectors are more than two miles from the water injection 8 wells. However¡ three producers have been sidetracked to 9 within two miles. For the record¡ the last two sentences are 10 a change to the pre-filed testimony. 11 Exhibit 6 shows a representative well completion plan. 12 Each completion will include 13 and three-eighths inch surface 13 casing cemented to surface¡ nine and five-eighths inch 14 intermediate casing with cement brought to 1¡000 feet above 15 the shoe¡ and a fully cemented seven inch -- seven inch 16 injection liner. The tubing will be seven and five-eighths 17 inch and will include a seven inch subsurface safety valve and 18 two seven inch profiles. The tubing is large to accommodate 19 the high volume of water to be injected. The tubing will also 20 be plastic coated to help minimize the friction losses. 21 Average surface pressure for these new injection wells will be 22 approximately 2¡700 psi. Maximum injection pressure is 23 expected to be approximately 3¡100 psi. 24 This concludes the project overview. I will now begin 25 my testimony on the other pressure support options that were METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 e e 10 · 1 considered. 2 The Owners formed a multi-companYr pressure studies 3 initiative team in 1991 to evaluate pressure mitigation 4 options for the Prudhoe Bay Oil Pool. Prior to the PSI teamrs 5 focus on gas cap water injectionr several pressure support 6 options were screened. These options included supplemental 7 hydrocarbon gas injectionr nitrogen or flue gas injectionr 8 fuel gas alternativesr additional water injection in oil rim 9 areasr and gas cap water injection. 10 Many of the options considered were not viabler 11 primarily due to high capital costs and/or recovery benefits 12 limitations. These projects are summarized on Exhibit 8. 13 For supplemental hydrocarbon gas injectionr limited · 14 gas sources exist. A Point Thomson type source was evaluated 15 in the screening study; howeverr high capital costs associated 16 with developmentr distributionr and compression facilities 17 makes this option unattractive. 18 Nitrogen or flue gas injection are also unattractive 19 since these options would require high capital costs for 20 compression or air separationr result in reduced vaporization 21 efficiency compared to lean hydrocarbon gasr and contaminate 22 the reservoir gas. 23 Options to replace the fuel gas used by Prudhoe 24 facilitiesr and thereby reduce reservoir voidager were also 25 screened. Fuel gas options included importing gasr using oil · METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 11 1 as fuel, importing electricity, or developing gas hydrates. 2 The fuel gas options are unattractive due to high capital 3 costs, unproven technology, and the fact that replacing the 4 fuel gas causes a reduction in field gas off-take, resulting 5 in an immediate decrease in oil rate. 6 Exhibit 9 shows projects that have been identified as 7 viable and are now in various stages of implementation. 8 Projects that increase water injection into the oil Rim areas 9 have been justified based on overall recovery benefits, rather 10 than just pressure support benefits. Eileen West End 11 Waterflood, Updip Zone 4 Water/Miscible Injection, and Flow 12 Station 2 Updip Victor WAG Injection are being implemented as 13 projects with related pressure support benefits; however, they 14 have limited pressure support potential when compared to gas 15 cap water injection. 16 Gas cap water injection was screened and found to have 17 significant recovery benefits with reasonable capital cost 18 requirements. The PSI team thought this option was 19 potentially attractive to very attractive. The PSI team 20 recommended gas cap water injection be their focus for more 21 detailed study. 22 This concludes my prepared testimony. Are there any 23 questions? 24 CHAIR TAYLOR: Commissioner Heusser? 25 I have just a couple of COMMISSIONER HEUSSER: METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 12 1 questions. Here on page six at section two, you quote the 2 average surface pressures for these new water injection wells. 3 Do you know off the top of your head what the current gas 4 injection pressures are? At AGI, WGI, NGI? 5 MR. RICHMOND: The surface injection pressure there? 6 COMMISSIONER HEUSSER: Yeah. 7 MR. RICHMOND: I don't know offhand what those -- 8 those are. 9 MR. BRADY: I can answer (indiscernible) They're 10 running about 32 to 33 (indiscernible)..... 11 COMMISSIONER HEUSSER: Thirty-two to 33? So..... 12 CHAIR TAYLOR: If I could just ask that if you speak 13 up or come up to the table so that the transcriber can pick it 14 up on the tape. Thank you. 15 MR. BRADY: My name is Jerry Brady, B-r-a-d-y. Those 16 pressures are roughly 32, 3,300 pounds. In that ballpark. 17 COMMISSIONER HEUSSER: Thanks, Jerry. And I'm looking 18 again at page seven of this same section, and the statement 19 was made that several pressure support options were screened. 20 In kind of general terms, can you describe the level of 21 screening that took place for these other options? 22 MR. RICHMOND: Well, when they looked at the other 23 options, basically they scoped out what those projects would 24 entail, and did some cost estimating for those options, and 25 then compared those to the various options that were METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 13 1 considered, including gas cap water injection, and then made 2 recommendations for which projects were worthy for consider- 3 for what we call more of a phase two set of studies, which 4 is where the Gas Cap Water Injection project became the focus. 5 COMMISSIONER HEUSSER: Okay. Another question here on 6 page eight, the same section. And you talk about Prudhoe Bay 7 fuel gas. What volume of fuel gas is currently being sold to 8 other fields? 9 MR. RICHMOND: Could you -- volume of..... 10 COMMISSIONER HEUSSER: Fuel gas. 11 MR. RICHMOND: .... .fuel gas? 12 COMMISSIONER HEUSSER: Right. At one time Prudhoe Bay 13 was selling fuel gas to other fields. 14 MR. RICHMOND: Yeah. Right now the fuel volume 15 overall is about 450 million, but I don't know offhand what 16 the volume that is being sold. 17 COMMISSIONER HEUSSER: Okay. So you don't know if 18 it's a significant volume that -- even if it's still being 19 sold, or whether or not there is a significant volume being 20 sold to other fields? 21 MR. RICHMOND: Do you know that? 22 MR. MAGUIRE: My name is Matt Maguire, M-a-g-u-i-r-e. 23 In terms of fuel gas, there are sales to -- minor sales to 24 like Norgasco, I believe, which supplies gas in Deadhorse. 25 The only field I'm aware of that will shortly be taking fuel METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 14 1 gas lS Northstar. And I think they have a little bit right 2 now to run some equipment, but I know it's under 100 million. 3 COMMISSIONER HEUSSER: Okay. So fuel gas sales to 4 Kuparuk is no longer going on? 5 MR. MAGUIRE: As I understand it, we have NGL's sold 6 to Kuparuk. 7 COMMISSIONER HEUSSER: Okay, but not fuel gas. 8 MR. MAGUIRE: If we have fuel gas, I'm not aware of 9 it. 10 COMMISSIONER HEUSSER: Okay, thank you very much. And 11 in on page nine, same section. One of the projects that 12 you mention here is the Flow Station 2 Updip Victor WAG Injection. That is not something that I believe that we know much about. Can you either describe that in general terms 13 14 15 here or submit what is involved in that? 16 MR. RICHMOND: Yeah, I'll go ahead and summarize what 17 that project entails. That is located in the Flow Station 2 18 area, which is currently where we have waterflood operations. 19 The Updip Victor WAG project will essentially extent the 20 waterflood patterns about one pattern -- updip of existing 21 waterflood patterns in Zones 2 and 3. And also that project 22 includes expanding the MI injection to include drill sites 4 23 and 11, which is where these patterns will be operated out of. 24 So this project will essentially go after reserves in Zones 2 25 and 3 with both expanded waterflood operations as well METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 15 1 miscible injection operations. 2 COMMISSIONER HEUSSER: Okay. So you're going to add 3 WAG up there, okay. Thank you. 4 CHAIR TAYLOR: Do you have any questions? 5 COMMISSIONER SEAMOUNT: I have no questions, thank 6 you. 7 CHAIR TAYLOR: Go ahead and proceed. Are you finished 8 and you're ready for somebody else or..... 9 MR. RICHMOND: Yes, the next four presentations will 10 describe key results from the detailed studies of gas cap 11 water injection. And first, Bharat Jhaveri will review the 12 recovery benefits. 13 CHAIR TAYLOR: Thank you. 14 MR. JHAVERI: Good morning. My name is Bharat S. 15 Jhaveri. I would now like to be sworn and qualified as an 16 expert witness. 17 CHAIR TAYLOR: In what field? 18 MR. JHAVERI: I'm a Consulting Reservoir Engineer with 19 BP Exploration Alaska Incorporated since 1995. I received a 20 PhD in chemical engineering from Stanford University in 1979. 21 I have been involved with the development and reservoir 22 management of the Prudhoe Bay field for over 20 years, from 23 1981 to 1994 at ARCO, and since 1995 at BP. 24 CHAIR TAYLOR: Mr. Jhaveri, do you want to be 25 considered an expert witness in the area of reservoir METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 16 1 engineering? 2 MR. JHAVERI: Yes. 3 CHAIR TAYLOR: Would you raise your right hand, 4 please? 5 (Oath administered) 6 MR. JHAVERI: Yes, I do. 7 CHAIR TAYLOR: Do either of you have any questions or 8 any objection to Mr. Jhaveri being considered an expert 9 witness in the field of reservoir engineering? 10 COMMISSIONER HEUSSER: None at all. 11 COMMISSIONER SEAMOUNT: I have no questions. 12 CHAIR TAYLOR: Go ahead and proceed. 13 MR. JHAVERI: I will now testify about the recovery 14 benefit of the Gas Cap Water Injection Project. Average 15 reservoir pressure in the Prudhoe Bay field is declining at a 16 rate of 25 to 35 psi per year, as shown by the dashed blue 17 curve in this exhibit. The declining pressure reduces 18 efficiency of every recovery mechanism operating in the field. 19 The proposed Gas Cap Water Injection project injects up to 20 650,000 barrels per day of seawater in the eastern gas cap 21 area beginning mid 2002. The -- the pressure forecast with 22 GCWI is shown by the solid green curve in this exhibit. As 23 can be seen, the project essentially maintains a level 24 reservoir pressure until water injection ends in 2022. 25 The GCWI incremental. oil recovery was predicted using METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 17 1 BP's Full Field Compositional Reservoir Model. It includes 2 the oil that initially was in the gas cap and is immobile. 3 The model uses a 60 acre areal grid of the Prudhoe Bay field 4 as shown in this Exhibit. The recovery calculated by the full 5 field model was validated using mechanistic studies of GCWI 6 using fully compositional one dimensional, two dimensional, 7 strip, and pattern models. 8 The increased pressure resulting from GCWI improves 9 every recovery mechanism operating in the field. The next few 10 exhibits use a cross section schematic of the field, all the 11 way from the gas cap in the north to the aquifer in the south, 12 to explain GCWI recovery mechanisms. The benefits are 13 characterized for three regions in the field. Gas cap, 14 gravity drainage, and waterflood/EOR. I will now describe the 15 benefits associated with each region starting with the gas 16 cap. 17 In the area of the original gas cap not invaded by water, the vaporization of residual oil and retrograde condensate by injection gas is more efficient at higher 18 19 20 pressure. The incremental recovery here is approximately 30 21 million barrels. In the water invaded area, some hydrocarbon 22 liquids are trapped by the injected water. This prevents 23 vaporization by injected gas, reducing liquid recovery by 24 approximately 50 million barrels. In total, there is a net 25 reduction of about 20 million barrels in the gas cap region. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 18 1 I will now describe the benefits associated with the gravity 2 drainage region. 3 As in the gas cap region, vaporization of residual oil 4 and retrograde condensate by the injected gas is more 5 efficient at higher pressure. The higher reservoir pressure 6 also reduces oil shrinkage and oil viscosity. Both of these 7 effects increase oil mobility and result in more efficient 8 gravity drainage. The improved vaporization and gravity 9 drainage processes yield about 200 million barrels of 10 incremental recovery from the gravity drainage region. I will 11 now describe the benefits associated with the WaterfloodjEOR 12 region. 13 The higher reservoir pressure increases well capacity 14 ln the waterflood area. which in turn increases throughput. 15 Additionally, there is less oil shrinkage. And finally, the 16 higher reservoir pressure allows leaner miscible injectant, 17 thus greater supply and more EOR recovery. The WaterfloodjEOR 18 benefits are approximately 20 million barrels. 19 The incremental recovery from GCWI is approximately 20 200 million barrels in the full field model. The total 21 reflects a reduction of 20 million barrels in the gas cap 22 region, with increases of 200 million barrels in the gravity 23 drainage region and 20 million barrels in the WaterfloodjEOR 24 region. 25 In summary, the Gas Cap Water Injection project METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 19 1 outlined here arrests pressure decline in the field and 2 increases recovery. All recovery mechanisms benefit from the 3 higher pressure. Vaporization, gravity drainage, waterflood 4 and EOR. Total incremental liquid recovery ranges from 150 to 5 200 million barrels. The range reflects modeling 6 uncertainties and the availability of sea water. 7 This concludes my prepared testimony. Are there any 8 questions? 9 CHAIR TAYLOR: Commissioner Heusser? 10 COMMISSIONER HEUSSER: I do. Dan, do you have any? 11 COMMISSIONER SEAMOUNT: I have one question. COMMISSIONER HEUSSER: Go ahead. COMMISSIONER SEAMOUNT: Mr. Jhavari? 12 13 14 MR. JHAVERI: Yes. 15 COMMISSIONER SEAMOUNT: Mr. Richmond testified that 16 there were a number of other options that you guys had 17 considered and had discounted for a number of good reasons. 18 Do you have numbers on incremental recovery that would be -- 19 that would occur due to those other options? 20 MR. JHAVERI: I actually do not have the exact numbers 21 on top of my head, but I can tell you qualitatively that in 22 terms of the -- the scale of benefit, GCWI was actually the 23 largest, just in terms of the sheer benefits. 24 COMMISSIONER SEAMOUNT: It was larger than the other 25 -- what was it, five options? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 20 1 MR. JHAVERI: Yes. 2 COMMISSIONER SEAMOUNT: Okay, thank you. 3 CHAIR TAYLOR: Commissioner Heusser? 4 COMMISSIONER HEUSSER: I'm looking at page three of 5 your testimony. 6 MR. JHAVERI: Page..... 7 COMMISSIONER HEUSSER: Page three, and you've got a 8 picture of your model. 9 MR. JHAVERI: Yes. 10 COMMISSIONER HEUSSER: The model that you're using, I 11 know that there have been a variety of models used over the 12 years. Some modeled apex water inject and some modeled east 13 dock water injection. The picture presented here, or the 14 model that you're talking here, does that is that east 15 water injector~ or apex water injectors? That -- you know, 16 this general discussion? 17 MR. JHAVERI: Yes. This is the model of the Prudhoe 18 Bay field where we actually have okay. Actually, we have 19 used this model to investigate both the apex injection and the 20 east dock injection. So the model is basically capable of 21 simulating a variety of injection scenarios. 22 COMMISSIONER HEUSSER: I'm looking at page SlX of your 23 presentation. 24 MR. JHAVERI: Page six, okay. 25 COMMISSIONER HEUSSER: Right. And I have to ask this METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 21 1 question. Here in the very first line, it talks about -- as 2 in the gas cap region, and then it talks about retrograde 3 condensate. Is there retrograde condensate in the gravity 4 drainage area? 5 MR. JHAVERI: What we mean is, this is the gravity 6 drainage area which is the expanded gas -- you know, as the 7 gas cap expands and the oil drains, it creates this expanded 8 gas cap area where there is a residual oil saturation of 9 somewhere around 30, 35 percent. Now as the gas expands into 10 this region, there is maybe a possibility of some of the gas 11 cap liquid initially to drop out. Now later on when the 12 injected gas do come in contact with any dropped out 13 condensate, it will vaporize it. So what we mean is higher 14 vaporization efficiency. At higher pressure it's more 15 efficient not only to vaporize any residual oil left behind in 16 the expanded gas/oil contact, but also to pick up -- if there 17 were any dropped out condensate. 18 COMMISSIONER HEUSSER: Okay, great. I'm looking at 19 page nine of your presentation. 20 Page nine? Okay. MR. JHAVERI: 21 COMMISSIONER HEUSSER: And what caught my eye on this 22 one 1S you talk -- the incremental recovery was going to be a 23 function of the availability of seawater, I think you said. And you further said that - - you or somebody else said that Point Mac, Flow Station 2, and NGI currently were using 24 25 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 22 1 seawater injection? I thought there was only like one well at 2 GC- -- at Flow Station 2 that had seawater injection, the rest 3 was all produced water. 4 MR. JHAVERI: The - - the.... . MR. RICHMOND: Do you want me to answer it? MR. JHAVERI: Yeah, you go ahead. MR. RICHMOND: Flow Station 2 is a combination of both 5 6 7 8 seawater and produced water injection. 9 COMMISSIONER HEUSSER: So it doesn't produce enough 10 water for its injection needs? 11 MR. RICHMOND: That's correct. 12 COMMISSIONER HEUSSER: I am so surprised. Okay. We 13 I had heard talk about a waterwheel project kind of going 14 on in the field, moving produced water from the point where 15 it's produced, utilizing existing perhaps oil flow lines and 16 moving it around the field to areas where produced water was 17 needed. When will that take place? will that take place? 18 MR. RICHMOND: Waterwheel is still under evaluation. 19 It hasn't been sanctioned yet by the Owners. I can't tell 20 exact timing then of -- of when that project could actually be 21 implemented. The purpose of waterwheel as it relates to gas 22 cap water injection will -- it could give us additional 23 seawater for gas cap water injection, and that's primarily 24 because some of the produced water within the Prudhoe Bay 25 could be then injected at Point McIntyre which is currently on METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · . e 23 1 seawater. And if that's converted from seawater injection to 2 produced water injection, then that would free up additional 3 seawater to be placed into the Gas Cap Water Injection 4 proj ect. 5 So there is the possibility with waterwheel coming on 6 line to have more water and higher injection rate closer to 7 the 650,000 barrel a day level than the chart that I showed in 8 my testimony. 9 COMMISSIONER HEUSSER: So what's the maximum volume of 10 water that the 32 inch pipeline will carry? 11 MR. RICHMOND: The 32 inch line actually has a 12 capacity very similar to what the eastern seawater injection 13 plant capacity is, which is maybe somewhere around 900 to 14 950,000 barrels a day is what would be possible. 15 COMMISSIONER HEUSSER: And the seawater treatment 16 plant was originally designed for one million, two million 17 barrels of water per day? 18 MR. RICHMOND: I believe that's..... 19 COMMISSIONER HEUSSER: Barrels of seawater? 20 MR. RICHMOND: I'm not quite sure what the original 21 design is, but the capacity that we'll be up to with gas cap 22 water injection will be around the 900, 950,000 barrel a day 23 level. 24 COMMISSIONER HEUSSER: Okay. So ESIP will take 25 900,000, the flow line is 900,000, and then mods to STP will METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 24 1 provide 900,000? 2 MR. RICHMOND: Yeah, STP -- the upgrades that we're 3 applying at STP are to bring it up to levels so that we can 4 maximize the ESIP capacity of the 900, 950,000. So STP will 5 be able to deliver that as well. 6 COMMISSIONER HEUSSER: Okay. Thank you. 7 MR. JHAVERI: Okay. This concludes my prepared 8 testimony. If there are no more questions. Thank you. Next 9 Matt Maguire will review water movement. 10 MR. MAGUIRE: Good morning. My name 1S Matt Maguire, 11 M-a-g-u-i-r-e. I'd now like to be sworn and qualified as an 12 expert witness in reservoir engineering. 13 CHAIR TAYLOR: Thank you. Would you raise your right 14 hand, please? 15 (Oath administered) 16 I am a Senior Reservoir Engineer MR. MAGUIRE: Yes. 17 with Phillips Alaska, Incorporated, currently assigned to the 18 Greater Prudhoe Area Team. In 1988, I received a Bachelor of 19 Science Degree in Petroleum Engineering from the University of 20 Alaska Fairbanks. I started working for ARCO Alaska out of 21 college and am currently in my fourteenth year of working 22 Prudhoe Bay engineering projects. I will now testify about 23 water movement. 24 CHAIR TAYLOR: Before you do that, do either 25 Commissioner Heusser or Commissioner Seamount have any METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 e e 25 · 1 questions or any objections to him being considered an expert 2 witness in the field of reservoir engineering? 3 COMMISSIONER HEUSSER: Absolutely none. 4 COMMISSIONER SEAMOUNT: No questions, no objections. 5 CHAIR TAYLOR: Why don't you go ahead and proceed. 6 Thank you. 7 MR. MAGUIRE: Thank you. In my presentation, I am 8 going to talk about water movement and describe how and where 9 the water moves once it is injected into the gas cap. I will 10 begin this by summarizing the water movement objectives for 11 the GCWI project. 12 Shown here is a map of the area surrounding the 13 proposed location of the GCWI injectors. The location of the · 14 water injectors was chosen to keep the injected water in the 15 eastern part of the gas cap and limit interference with 16 operations in three other areas of the field. These three 17 areas are the gas injection area to the west, the waterflood 18 area at drill sites 4 and 11, and the gravity drainage area at 19 drill site 18. 20 In the gas injection area, we want to avoid 21 significant impact to the gas injectors. This is important 22 because reduced gas injectivity reduces field gas offtake and 23 therefore oil production. 24 The following paragraph filed in the prefile had 2 25 errors which I will correct here in my testimony. The closest · METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 26 1 oil producers in the waterflood area are at drill sites 4 and 2 11. Water encroachment here is not a concern. This area is 3 already being waterflooded, waterflood -- water from the GCWI 4 injectors should complement the existing flood. Within the 5 gravity drainage area, we want to preserve oil recovery. 6 To accomplish this objective, the piston-like flood 7 font is desired. This slide shows two flood fronts that are 8 relevant to the discussion of this project. Each of these is 9 pictured in a 2D cross section. Our preference is the piston- 10 like flood front. This is characterized by efficient and 11 uniform displacement as opposed to having channels develop. 12 Here, the front is stable, moves slowly, and takes much longer 13 for water to break through. 14 With the channeling front, it is easy to see how water 15 breakthrough would occur earlier. As you can imagine, this 16 type of behavior within the GCWI project is not desirable. 17 For gas cap water injection, the displacement of gas 18 by water is very efficient and essentially piston-like. This 19 is because gas is 100 times more mobile than the water that 20 displaces it. I will now demonstrate this for you with a flow 21 model. 22 I have two reservoir simulations to show you. Each 23 uses the reservoir description shown on this slide. The model 24 is 2D cross-sectional in nature, with an injector on the left 25 and a producer on the right. The cells are 208 feet square METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 27 1 and two feet thick. The green cells have 500 millidarcy 2 permeability and the orange cells 5,000 millidarcy. The 3 orange cells represent a 20 foot thick thief zone in the 4 middle of the model. 5 The main difference In the model runs will be the 6 fluid within it. In one simulation the model contains oil, 7 and in the other, gas. In each simulation we will inject 8 water. The purpose of these comparison cases is to show how a 9 high permeability zone has little effect when water displaces 10 gas. 11 This first simulation is of water displacing oil. 12 Here we would expect the permeabilities to playa major role. 13 (Pause) 14 This is the end of the run. Let's run that one more 15 time. 16 (Pause) 17 Okay. Note water breakthrough right there. 18 (Pause) 19 As you've seen, the thief zone caused early water 20 breakthrough and channeling of the water. Now let's take a 21 look at the same simulation, however this time the model will 22 be loaded with gas instead of oil. So, this simulation is of 23 water displacing gas. Keep in mind the thief zone is in the 24 middle of the model. 25 (Pause) METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 28 1 This is the end of the run. Let's run this one more 2 time. 3 (Pause) 4 As you have seen, even a high permeability thief like 5 this one significantly dampened -- is significantly dampened 6 by such a favorable displacement process. 7 I have one comparison slide to summarize what we just 8 viewed. The water displacing oil case shows the water moving 9 significantly faster through the high permeability channel In the water displacing on the flood front, such 10 leading to early water breakthrough. 11 gas case, the thief has little effect 12 that the displacement is nearly piston-like. The water 13 doesn't channel through the gas. This is because the gas is 14 approximately 100 times more mobile than the water. As a 15 result, this displacement process dampens the effect of 16 geologically reasonable variations in reservoir permeability. 17 At this point, I would like to show you some areal 18 water saturation maps from BP's full field model. This slide 19 shows water saturation within the high permeability Zone 3 on 20 1/1/2005, approximately 3 years after the start of injection. 21 The blue circle represents the bulb of water that has been 22 injected up to this date. 23 The next paragraph has a clarification to the prefiled 24 testimony. For illustrative purposes, some of the GCWI 25 injectors are shown, as are some of the gas injectors closest METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 29 1 to the project. Additionally I have noted where some of the 2 closest oil producers are located within the gravity drainage 3 and waterflood areas. 4 This slide shows the continued growth of the water at 5 2010, or after approximately eight years of injection. 6 This slide shows the continued growth of the water at 7 2015, which is approximately 13 years of injection. 8 And 2020, which is approximately 18 years of 9 injection. 10 And this is 2031. Water injection was stopped in 11 2022. Due to its low mobility, the water moves very little 12 between 2022 and 2031. So a picture at 2031 is almost the 13 same as a picture at 2022. 14 As you can see water eventually reaches the closest 15 gas injectors and some oil producers at drill sites 4, II, and 16 18. Let me show you the effect on these three areas on the 17 next three slides. 18 First, GCWI has a small impact on gas injection. It 19 occurs primarily late in field life when the gas oil ratios 20 are higher. This impact is incorporated into the benefits 21 analysis. 22 Second, this plot shows the cumulative oil production 23 for drill sites 4 and 11 with and without GCWI. As you can 24 see, oil recovery is slightly higher with GCWI. This is 25 because the additional water from GCWI drives updip oil METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 30 1 towards the drill site 4 and 11 producers. 2 And finally, this plot shows cumulative oil production 3 for drill site 18 with and without GCWI. Oil recovery lS 4 slightly higher with GCWI because the water limits gas 5 encroachment and displaces some updip oil. 6 This concludes my prepared testimony. Are there any 7 questions? 8 CHAIR TAYLOR: Mr. Maguire, just for the record, real 9 quickly if you wouldn't mind identifying -- you showed two 10 video clips. If you would, just for the record, explain where 11 those are contained in the slides of the prefiled testimony. 12 MR. MAGUIRE: Tab 4A and 4B. 13 CHAIR TAYLOR: Okay. So 4A is the water displacing 14 oil and 4B is the water displacing gas, is that correct? 15 MR. MAGUIRE: That's correct. 16 CHAIR TAYLOR: Thank you. 17 MR. MAGUIRE: You're welcome. 18 CHAIR TAYLOR: Commissioner Seamount, Commissioner 19 Heusser, do you have any questions? 20 COMMISSIONER HEUSSER: Basic question. 21 MR. MAGUIRE: Sure. 22 COMMISSIONER HEUSSER: For those presentations that 23 are included in 4A and 4B, does the official exhibit include 24 full size copies of these slides? 25 MR. MAGUIRE: Oh, does it include real size..... METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 31 1 COMMISSIONER HEUSSER: Yeah, real size copies in..... 2 MR. MAGUIRE: No, they're in handout size. So we can 3 certainly provide them, though. 4 COMMISSIONER HEUSSER: I think that for our record 5 that would be useful. 6 MR. MAGUIRE: Okay. 7 COMMISSIONER HEUSSER: Likewise, would you be able to 8 provide a larger size of page seven, eight, and nine, 10, and 9 11, again, to make our record easier to read? 10 MR. MAGUIRE: I'm not sure if I caught all the pages. 11 Seven, eight, nine, 10..... 12 COMMISSIONER HEUSSER: Seven, eight, nine, 10, and 11. 13 It's Zone 3 beginning in 1001 (sic) to 2005, going up to 1000 14 January 1st, 2031. 15 MR. MAGUIRE: Okay. 16 COMMISSIONER HEUSSER: I just find them pretty 17 difficult to read and I think our record needs to be readable. 18 I do have one last question, Mqtt. 19 MR. MAGUIRE: Yes. 20 COMMISSIONER HEUSSER: I always pictured that there 21 would be a significant gradient between the gas injection 22 wells, NGI, WGI, AGI, and the waterflood area. In the course 23 of your modeling, did you notice that? Or is it just..... 24 MR. MAGUIRE: And when you say gradient, are you 25 talking about pressure..... METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 32 1 COMMISSIONER HEUSSER: Pressures. 2 MR. MAGUIRE: . . . . .gradient? 3 COMMISSIONER HEUSSER: Pressure gradientsl yeah. 4 MR. MAGUIRE: The gas cap has very good conductivity. 5 As suchl I don/t believe there/s a very large gradient between 6 those two areas. If you follow the growth of the bulb as 7 welll there is a tendency of the bulb to grow a little bit 8 farther towards the gravity drainage and almost be pushed from 9 the side by the gas injectors. 10 COMMISSIONER HEUSSER: So the gas injectors work to 11 push the water down towards drill site 18 probably a little 12 faster than it -- than the water would head on over to those 13 drill site 4 wells? Off to the right? 14 MR. MAGUIRE: Yeahl that/s a good way to look at it. 15 The water tends to move radially outward I however it is 16 slightly compressed by the gas injectors. Certainly the 17 producers also intend to pull the bulb towards them. I think 18 there might a small tendency to move a little bit faster 19 towards drill site 181 but it/s -- it would be a very minimal 20 effect. 21 COMMISSIONER HEUSSER: So it IS an even radial movement 22 of water out from the east dock injectors? Kind of nice..... 23 MR. MAGUIRE: It is approximately radial I yes. 24 COMMISSIONER HEUSSER: And so when you commented that 25 the gas cap has good conductivitYI do you assume that the -- METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 33 1 relic (ph) oil saturation in the entire gas cap area is the 2 same? I mean, i.e. in that east side where there has actually 3 been no gas injection? 4 MR. MAGUIRE: The -- as I understand it, the BP full 5 field model 1S initialized with the oil saturations that we 6 expect were in the gas cap throughout at the beginning of the 7 field. For the purposes of all the simulation work, that oil 8 is immobile. I'm not sure if that answers your question. 9 COMMISSIONER HEUSSER: The gas cap oil is immobile? 10 MR. MAGUIRE: Yes, to waterflood. It's purely 11 recovered through vaporization. 12 COMMISSIONER HEUSSER: Okay. So do the modeling 13 results show that some of that oil has already been recovered? 14 MR. MAGUIRE: Has already been..... 15 Recovered through ga- -- you 16 COMMISSIONER HEUSSER: know, the normal. . . . . MR. MAGUIRE: Yes. COMMISSIONER HEUSSER: MR. MAGUIRE: Yes. COMMISSIONER HEUSSER: Okay. 17 18 . . . . .gas injection? 19 20 21 MR. MAGUIRE: The - - yes. The lean gas siphoning project is recovering. . . . . COMMISSIONER HEUSSER: From the eastern part? 22 23 24 . . . . .oil from the gas cap. And as I MR. MAGUIRE: 25 understand it..... METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 34 1 COMMISSIONER HEUSSER: From the entire gas cap area? 2 MR. MAGUIRE: As I understand it, it is, yes. 3 MR. JHAVERI: Can I (indiscernible). Yeah, I think 4 the..... 5 CHAIR TAYLOR: Excuse me, could you come up -- on the 6 table there, there's a microphone at the table. Thank you. 7 I think the as you can see MR. JHAVERI: 8 (indiscernible) . I think there is injection in this NGI -- 9 NGI area of the gas cap, and the gas basically advances 10 just like the water is injected right here in this dark area. 11 We have been having injection in the AGI and NGI area. So 12 there is a -- from the gas point of view, now I'm talking 13 about injected gas, the injected gas that has been injected 14 moves outside and has been, you know, sweeping (ph) this area 15 of the gas cap. So obviously there is more vaporization that 16 has occurred closer to the gas injector area. And as you get 17 farther and farther away, there is less and less vaporization. 18 And I don't know if you can put one of my slides back? Is it 19 possible to..... 20 UNIDENTIFIED VOICE: Which one? 21 MR. JHAVERI: The one with you saw water invaded 22 areas in the (indiscernible) section. Benefits testimony. 23 Yeah, just go back one and then I'll ask you to stop. Keep on going back. This lS good enough, actually. So like - - so let me just start again. So here is the 24 25 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · 2 3 4 5 6 7 8 9 10 11 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · e e 35 1 AGI, WGI, and here is where we are injecting, okay? And this is the water invaded area. In our benefits analysis, we do it is a fully compositional model, so we do include all the process that has happened in the field since the beginning of gas injection. And at the time the water injection starts, the gas here is somewhat richer and there is somewhat less vaporization of liquid than if you had been in the NGI, AGI area. Now let me also add to my -- your answer, and that is that some of the benefits that I do describe by the model, this minus 20 did include -- if you remember I testified earlier, minus 50 million barrels, somewhat of a reduction in liquid in this area. So those results include somewhat higher yield and somewhat less vaporization of oil in this part of the gas cap. COMMISSIONER HEUSSER: Okay. So the minus 50 does include the area in the eastern part of the gas cap, . . . . . MR. JHAVERI: Yes. COMMISSIONER HEUSSER: . . . . .but the oil that would not be..... MR. JHAVERI: That's where it is -- now this is a positive part that also I mentioned, which is the -- in the area which is not invaded by the water, the injected gas continues to vaporize the relic oil, but at a higher efficiency, because the pressure is higher, the thermodynamics METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 36 1 is better. So the net effect of that is actually additional 2 30 million positive benefits of improved vaporization. Thus 3 the net effect of these two is only, you know, minus 20. But 4 what I want to add, you know, when I came into help out Matt 5 here lS, yes, we understand your question and that the gas is 6 going to be sweeping more of the -- the oil at the time of the 7 injection compared to the eastern area. And all this is -- 8 and all these mechanisms are included, you know, with benefits 9 analysis. 10 COMMISSIONER HEUSSER: Thank you. 11 MR. RICHMOND: And just for the record, Bharat was 12 referencing Benefits Exhibit 8. 13 CHAIR TAYLOR: Thank you. 14 COMMISSIONER HEUSSER: That's it for me. 15 CHAIR TAYLOR: Commissioner Seamount? 16 COMMISSIONER SEAMOUNT: Mr. Maguire, have you modeled 17 any potential streaks of greater than five darcys, to see if 18 -- you know, is there a point where channeling would start to 19 have an effect? Some permeability? 20 MR. MAGUIRE: We have performed sensitivities to look 21 at high perm thief. The only geologic occurrence that we can 22 come up with that might be such a thief would be the open 23 framework conglomerate (ph). Geologically, none of the 24 geologists believe that that deposition would be channel-like. 25 The idea is it'd be very thin, would not be laterally METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 37 1 continuous. But for our sensitivity case -- one of the 2 sensitivity cases, we did run a channel directly from the east 3 dock injectors straight down to drill site 18. And we 4 characterized it as a 40 darcy channel with a perm 5 modification to the bottom of layer -- to a bottom of a layer 6 in Zone 3. When we looked at the sensitivities between the 7 base case and this sensitivity, the expected time of arrival 8 of the water changed. It became earlier by about two years. 9 That was a sensitivity that indicated that a thief of that 10 magnitude, even in the full field model, did not necessarily 11 change your arrival time or change your flood front. 12 COMMISSIONER SEAMOUNT: Do you perceive the 13 possibility of any faults acting as high permeability 14 conduits? 15 MR. MAGUIRE: There were sensitivities also run with 16 faults. What I can say on that is that, just as in the 17 example of the channel, if you have a mechanism that will pull 18 the water out in a certain fashion, the water still wants to 19 displace the gas. And unless you seal up the fault somehow, 20 you're still going to have the water going through it and 21 dissipating it pretty rapidly. So you still continue to 22 dampen the effects of any kind of reservoir heterogeneities 23 like faults or potential thief zones. 24 COMMISSIONER SEAMOUNT: Now once the water reaches -- 25 I think you -- did you mention that the water would reach some METRO COURT REPORTING, INC. 745 West Fourlh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 38 1 of the oil areas, like the northern oil producers, and you 2 talked about drill sites 4, 11, and 18? 3 MR. MAGUIRE: That's correct. 4 COMMISSIONER SEAMOUNT: Now once the water reaches 5 there, I guess I understand that the plot you showed, showed 6 there would actually be benefit. Is there a possibility if 7 the water reached there sooner that there would not be a 8 benefit? 9 MR. MAGUIRE: Yes. 10 COMMISSIONER SEAMOUNT: Okay. 11 MR. MAGUIRE: I think -- we could certainly come back 12 to this topic if you want. Jerry Brady will be talking about 13 surveillance and we'll certainly be monitoring the water front 14 to try to prevent that. 15 COMMISSIONER SEAMOUNT: Okay. Thank you, Mr. Maguire. 16 MR. MAGUIRE: You're welcome. CHAIR TAYLOR: Thank you. MR. MAGUIRE: Thanks for your time. The next section, 17 18 19 major gas sale relationship, will be presented by Lynn 20 Schnell. 21 MR. SCHNELL: Good morning. My name is Lynn W. 22 Schnell. I'd now like to be sworn and qualified as an expert 23 witness in reservoir engineering. 24 CHAIR TAYLOR: Raise your right hand, please. 25 (Oath administered) METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 39 1 MR. SCHNELL: Yes, I do. 2 Please proceed with your CHAIR TAYLOR: 3 qualifications. 4 I've been employed by ExxonMobil MR. SCHNELL: 5 Production Company and its predecessors since graduating from 6 Washington State University in 1965 with a Bachelor of Science 7 degree in electrical engineering. I've been involved with the 8 development and reservoir management of the Prudhoe Bay Field 9 almost continuously since June, 1968. 10 CHAIR TAYLOR: Thank you. Do either Commissioner 11 Heusser or Commissioner Seamount have any questions or any 12 objections? 13 COMMISSIONER SEAMOUNT: No questions, no objections. 14 COMMISSIONER HEUSSER: No questions, no objections. 15 CHAIR TAYLOR: Thank you, please proceed. 16 MR. SCHNELL: I will now testify about the 17 relationship of a major gas sale to the Gas Cap Water 18 Injection Project. 19 The purpose of this presentation is to address the 20 interaction of the Gas Cap Water Injection project with a 21 potential major gas sale. The primary focus will be on how a 22 gas sale would impact the estimated benefits of the project. 23 The secondary focus will be on how gas cap water injection is 24 expected to impact ultimate gas recovery. 25 Since the timing and rate of a gas sale have yet to be METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 40 1 determined, a gas sale will be addressed broadly. As such, I 2 will focus on the mechanisms involved and will not try to 3 quantify these factors. 4 In general, the water injection project will maintain 5 reservoir pressure at a higher level under any currently 6 foreseeable gas sales scenario. A gas sale will reduce the 7 incremental oil recovery from gas cap water injection. This 8 will be shown and explained. Finally, the impact of the 9 project on ultimate gas recovery will be addressed. I will 10 show that gas recovery potential is virtually unchanged when 11 compared to a no gas cap water injection case. 12 This chart represents the average reservoir pressure 13 as predicted by the BP full field model. It shows that gas 14 cap water injection results in a uniformly higher reservoir 15 pressure with major gas sales. In this case, approximately 16 140 psi. 17 The blue dashed curve shows the pressure declining at 18 25 to 35 psi per year until a four bcf a day gas sale begins 19 in 2008, at which time the pressure drops at about 135 pounds 20 per year through 2025. The rate of pressure decline is 21 proportional to the gas sales rate. The pressure decline 22 moderates in the later years as the gas sales rate drops due 23 to pressure depletion. 24 The solid green curve is for the same gas sales 25 scenario, but with gas cap water injection. Initially, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 41 1 reservoir pressure remains essentially constant until the 2 start of the gas sale in 2008. At that time, the pressure 3 parallels the case without injection. This same relationship 4 lS characteristic of other gas sales rates and timing. 5 The higher pressure with the project means that even 6 with a major gas sale, the oil recovery mechanisms will 7 operate more efficiently. This is depicted in the next chart. 8 This graph shows the cumulative incremental oil 9 recovery due to gas cap water injection through 2030. While 10 the gas sale reduces the recovery, the incremental recovery 11 remains significant and the project remains viable. 12 The upper dashed blue curve represents the 200 million 13 barrels shown in Bharat Jhaveri's testimony. The solid green 14 curve represents the 135 million barrel incremental recovery 15 with a four bcf a day gas sale starting in 2008. 16 This reduction in recovery is caused by three 17 mechanisms. First, with a major gas sale, the volume of gas 18 available for injection is reduced in order to meet the gas 19 sale demand. Thus, less oil is vaporized by injected gas. 20 This reduced vapor- -- this reduces vaporization recovery for 21 gas cap water injection. Secondly, the ability of the 22 injected gas to vaporize the oil it contacts diminishes with 23 lower reservoir pressure. And finally, with the lower 24 pressure due to a gas sale, the oil becomes more viscous. It 25 drains more slowly and less is recovered. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 42 1 With this understanding of how major gas sales impacts 2 gas cap water injection, I would now like to address how gas 3 cap water injection would impact a major gas sale. 4 This chart is a plot of cumulative gas sales with time 5 through 2050 as forecasted by the BP full field model. It 6 shows that ultimate gas recovery will be essentially unchanged 7 by gas cap water injection. The primary reason for this is 8 that similar abandonment pressures can be realized with and 9 without the project. This requires a large water-free area 10 from which to produce the gas. During the final stages of 11 field life, after the recoverable liquids have been produced, 12 the operating objective will be to maximize gas recovery. 13 This is accomplished by blowing down the reservoir pressure 14 with the remaining wells. These will likely be former oil 15 wells that have been recompleted as gas wells into the 16 expanded and original gas cap. As you know, there are many 17 candidate wells in the gravity drainage area. 18 Gas well producing capacity is a strong function of 19 both reservoir pressure and water production. Without water, 20 a gas well can flow at economic rates with relatively low 21 relative reservoir pressure. However, if water is produced 22 along with the gas, a much higher reservoir pressure is needed 23 to sustain production. Consequently, a large water-free area 24 must remain in the reservoir late in field life. As shown on 25 the next slide, water injected into the cap remains highly METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 43 1 localized. 2 This chart shows the water and hydrocarbon saturation 3 as predicted by the BP full field model in the high 4 permeability Zone 3 at 2035. The blue represents high water 5 saturation. Red represents high gas saturation in the 6 original gas cap. The somewhat darker, almost brownish 7 colored represents the high gas -- represents where gravity 8 drainage and vaporization have been responsible for oil 9 recovery. 10 The water injected into the gas cap is readily 11 apparent. This water remains relatively close to where it was 12 injected because of its low mobility compared to the gas it 13 displaces. The blue area around the lower edge is the 14 aquifer. 15 Although not apparent on this chart, most of the red 16 and brownish areas have been penetrated by many wells on 17 approximately 80 acre spacing. It is through these wells that 18 the bulk of the late life gas reserves will be produced. 19 Within the red and brownish areas, the gas recovery mechanism 20 will be simple pressure depletion. 21 Because of this large water-free area, the gas cap 22 injection will not materially impact the final reservoir 24 23 pressure as shown on the next chart. 25 This is the same pressure chart shown earlier. Notice how close the pressures are at the end. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · 1 2 3 4 5 6 7 · · e e 44 The next chart will then illustrate how reservoir pressure depletion impacts gas recovery. This chart shows gas recovery by pressure depletion as a percent of the original gas in place. Gas recovery varies inversely with pressure. Notice that recovery exceeds 80 percent when the pressure is reduced from the original 4,400 psi to about 850 psi. This is representative of what happens 8 in the absence of water in the original gas cap and throughout 9 much of the gravity drainage area. 10 The next chart will show what happens when water is 11 injected into the gas cap. 12 The solid green line in this chart depicts gas 13 recovery in the case where water has been injected into the 14 gas cap after the reservoir pressure has dropped from the 15 original 4,400 psi to 3500 psi. For reference, the pressure 16 depletion curve from the previous chart is also shown. 17 When water is injected, it displaces most of the gas. 18 In this example, gas saturation is reduced from an original 90 19 percent pore volume to a trapped gas saturation of 25% pore 20 volume. Just as water is able -- is unable to displace all of 21 the oil In a waterflood, it is unable to displace all of the 22 gas in the gas cap. 23 The solid green curve shows that prior to water 24 injection, about 17 percent of the original gas volume had 25 been recovered, or in this case expanded down into the gravity METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 45 1 drainage area, by pressure depletion. 2 When water is injected, gas is physically displaced so 3 that almost 80 percent has been removed from the water invaded 4 pore volume. When reservoir pressure is subsequently reduced 5 during blow down, the trapped gas expands and once -- once 6 again becomes mobile. 7 Notice that at a reservoir pressure of 1,500 psi, the 8 gas recovery in the water invaded area is 90 percent. In 9 order to realize this level of recovery by pressure depletion 10 alone, the pressure has to be blown down to 500 psi. 11 Thus, it can be seen that gas recovery from the gas 12 cap where water is injected may exceed that from the rest of 13 the gas cap and gravity drainage area. 14 Now to summarize. In conclusion, gas cap water 15 injection has been shown to yield higher reservoir pressure 16 with and without a major gas sale. Any water injected serves 17 to reduce total net voidage and thus maintain a higher 18 pressure. The gas sale does, however, reduce the incremental 19 oil recovery due to gas cap water injection for three reasons. 20 First, it reduces the volume of vaporized oil because less gas 21 is injected into the gas cap. Second, the ability of the 22 injected gas to vaporize residual oil is somewhat lower at the 23 lower reservoir pressure associated with the gas sale. 24 Finally, gravity drainage is reduced. 25 Gas recovery will be virtually unchanged by the gas METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 46 1 cap water injection. This is because the large water-free 2 area that remains during late field life enables effective 3 pressure depletion with only a slightly higher final pressure. 4 Also, it is likely that the gas recovery from the water 5 invaded area will be somewhat increased. 6 This concludes my prepared testimony. Are there any 7 questions? 8 CHAIR TAYLOR: Mr. Seamount, do you have any 9 questions? 10 COMMISSIONER SEAMOUNT: Mr. Schnell, what is the 11 sensitivity of oil and gas recovery to water injection rate or 12 water injection volume? Is there a big sensitivity? I mean, 13 if you injected twice as much, would your recoveries change 14 quite a bit? 15 If you inject so much water that it MR. SCHNELL: 16 basically fills the whole gas cap, then, you know, you could 17 certainly have a major impact on the oil recovery. The effect 18 on gas recovery could also be negative to the extent that you 19 no longer had a water-free area from which to pressure 20 deplete. 21 So there'd be a breakover COMMISSIONER SEAMOUNT: 22 point then, right? Where your benefit goes away for the gas. Now for the oil, is there a breakover point? MR. SCHNELL: Yes, there is - - there is a breakover 23 24 25 point, or there is an optimum time and rate at which to inject METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 47 1 the water for a given field life scenario, for a given timing 2 and rate of major gas sales. I think what we have now is a 3 project that is pretty much optimized given the uncertainty 4 that remains with regard to the rate and timing of gas sale. 5 COMMISSIONER SEAMOUNT: Okay, thank you. 6 CHAIR TAYLOR: Commissioner Heusser? 7 COMMISSIONER HEUSSER: A couple of just general questions and you're the lucky person to get to answer these because of your extensive Prudhoe Bay history. Why is this 8 9 10 gas cap water injection appropriate now and it wasn't five 11 years ago? 12 MR. SCHNELL: Well, it's appropriate now because five 13 years ago the oil rim was much less mature than it is today. 14 As such, there would have been a greater potential for having 15 some adverse impacts. More so in, say, drill site 18 area 16 than what we see today. More so also in reducing our ability 17 to inject gas. But now with a more mature field, I think it's 18 a better time to be injecting this water. 19 So when you use the term mature COMMISSIONER HEUSSER: 20 field, you're -- are you saying that more oil has been 21 recovered..... 22 MR. SCHNELL: Yes. 23 COMMISSIONER HEUSSER: .... . from that up-structure 24 area? 25 MR. SCHNELL: Yeah. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 48 1 COMMISSIONER HEUSSER: And so there's less to lose -- 2 less reserves at stake? 3 MR. SCHNELL: There are fewer barrels at stake. 4 Development in the updip area has progressed with time, such 5 that the wells up there now are all producing at very high 6 gas/oil ratios. 7 COMMISSIONER HEUSSER: Okay. Lynn, again because of 8 your lengthy history with Prudhoe Bay reservoir development, 9 and for our record, would you provide just kind of a general 10 time line history of the evaluation process that all the co- 11 owners went through for this Gas Cap Water Injection project? 12 Just kind of walk us through that, please? 13 MR. SCHNELL: Oh, boy. I'm probably weak on dates, 14 Julie, but I think -- you know, this is something gas cap 15 water injection was looked at back in the early '70s. I 16 remember plugging it into a 2D three phase reservoir simulator 17 model that I was running back as early as about 1971 and '72. 18 I think the unit began looking very seriously at this in the late '80s, early '90s. And I think there was work that was done in-house by certain Exxon, and ARCO, and I'm sure BP as 19 20 21 well. Then the unit team was formed I believe in, what, 1991. 22 And that team has been active from then, you know, through 23 really this last spring when the project was sanctioned. 24 COMMISSIONER HEUSSER: So basically this project or a 25 variation of this has been under consideration since the early METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 49 1 '70s, even before Prudhoe Bay field came on line? 2 MR. SCHNELL: That's right. 3 COMMISSIONER HEUSSER: Okay. So this is not a project 4 that was just thought up yesterday, this is a project that has 5 been considered over a fairly lengthy period of time? 6 MR. SCHNELL: That's right. We considered it from the 7 beginning and, you know, one of the first things that I 8 learned about this project in the early runs that I made was 9 that you could inject too much water too soon relative to the 10 producing life of the oil run. 11 COMMISSIONER HEUSSER: Thank you, that's all my 12 questions. 13 CHAIR TAYLOR: Thank you very much. 14 COMMISSIONER HEUSSER: Oh, I do have one other 15 request. Just like with Mr. Maguire's presentation, your 16 exhibit that's presented on page six, could you provide us 17 with a copy that..... 18 MR. SCHNELL: Eight and a half by 11 version? 19 COMMISSIONER HEUSSER: Yes, please. 20 MR. SCHNELL: You bet. 21 COMMISSIONER HEUSSER: Thank you. For our record. 22 MR. SCHNELL: Okay. Next Jerry Brady will discuss the 23 surveillance of the project. 24 CHAIR TAYLOR: Thank you. 25 MR. BRADY: Good morning. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 50 1 CHAIR TAYLOR: It's a surprise chair for you. There 2 lS actually a lever on either the left or the right side 3 one of them actually locks it into place, if that's..... 4 COMMISSIONER SEAMOUNT: Be careful, though. 5 MR. BRADY: I'll take it as it is. My name is Jerry 6 Brady, B-r-a-d-y. I'd like to be sworn and qualified as an 7 expert witness in petroleum engineering. 8 CHAIR TAYLOR: Would you raise your right hand, 9 please? 10 (Oath administered) 11 MR. BRADY: Yes. 12 CHAIR TAYLOR: Please proceed with your 13 qualifications. 14 MR. BRADY: I'm a Staff Engineer for BP Alaska 15 currently working as a Production Engineer on the Gas Cap 16 Water Injection project. I received a Bachelor of Science 17 Degree in petroleum engineering from Montana Tech in 1980. I 18 began my career with ARCO International in 1981 and moved to 19 Alaska in 1984 for ARCO Alaska. Since then I have worked on a 20 variety of production engineering projects in Alaska. I began 21 working on the GCWI surveillance plans in 1993. 22 CHAIR TAYLOR: Thank you. Commissioner Seamount, 23 Commissioner Heusser, do you have any questions or any 24 objections? 25 COMMISSIONER SEAMOUNT: No objections. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 51 1 COMMISSIONER HEUSSER: No objections. 2 CHAIR TAYLOR: Please proceed. 3 I will now testify about surveillance for MR. BRADY: 4 the Gas Cap Water Injection project. 5 Let's begin with the objectives of the GCWI 6 surveillance plan. The objectives are to monitor the project 7 performance and ensure that the injection project is 8 performing as expected. Critical elements of the plan are the 9 monitoring of the injection well conformance, water movement, 10 and reservoir pressure. Injection well monitoring ensures 11 that the water injection is contained in the desired reservoir 12 interval. Water movement monitoring is assuring that the 13 water moves in the reservoir as expected. General waterflood 14 movement will be monitored using 4D surface gravity and 15 downhole pulsed neutron logs in offset wells. The leading 16 edge of the waterflood will be detected primarily with pulsed 17 neutron logs. Reservoir pressure will be obtained with the 18 current pressure reporting requirements for the Prudhoe Bay 19 oil pool. 20 The first component of the GCWI surveillance plan is 21 water injection well monitoring. The injection wells will be 22 monitored with surface measured temperature, pressure, and 23 injection rate. These measurements will be similar to other 24 injection wells within the Prudhoe Bay pool. With these 25 measurements it is possible to monitor injection METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 52 1 characteristics, particularly changes in inject- -- in the 2 injectivity indices. The injectivity indices provide direct 3 evidence of changes in well performance. 4 Downhole measurements will be -- will provide 5 confirmation of the surface measurements and will also help 6 describe reservoir properties and hydraulic performance. 7 Downhole temperature logs will provide verification of injection conformance and confirm that the fracture height growth is confined within the Ivishak. Downhole pressure 8 9 10 measurements will be used to determine tubular pressure drop 11 and hydraulic performance. Pressure falloff tests will be 12 undertaken to determine reservoir properties and wellbore 13 skin. 14 Water movement lS monitored to make sure it remains in 15 zone and it remain- -- and it moves as expected. Two 16 techniques will be utilized to provide information on the 17 water movement. They are pulsed neutron logging in off- in 18 offset wells and 4D surface gravity survey. The pulsed 19 neutron logging will provide the downhole information on which 20 zones are being flooded, along with the regional information 21 on where the water is moving. 4D gravity will augment the 22 pulsed neutron logging by providing general water movement 23 information. 24 The next major component of the surveillance plan is 25 the pulsed neutron logging. This slide highlights the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 53 1 approximate area of interest for early time pulsed neutron 2 logging program. 3 The light blue region surrounded by the heavy dashed 4 line is the area of primary interest. In the center of the 5 blue reglon lS a smaller dashed line that shows the proposed 6 location of the water injection wells. The wells to be logged 7 will be selected from the suite of wells shown as green dots. 8 These wells are primarily Lisburne producing wells, none of 9 which have known cement problems that would prevent 10 confinement of injection into the Ivishak. 11 Pulsed neutron logs, specifically the RST logs, were 12 chosen because they can be run in the Lisburne wells completed 13 with two and seven-eighths inch tubing. They can also be run 14 in two modes to collect data for discerning a major change In 15 fluids, sigma and carbon/oxygen. The RST will help locate the 16 leading edge of the waterflood. It will also provide data in 17 determining the regional waterflood coverage. 18 The 4D gravity technique utilizes very sensitive 19 surface gravity measurements taken periodically. The method 20 measures small changes in gravity as the low density gas is 21 replaced with the higher density water. Baseline measurements 22 will be taken prior to water injection. Subsequent 23 measurements will be made at discrete time intervals and 24 compared to the baseline measurements. An increase in the 25 density of the fluids in the gas cap indicates the presence of METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 54 1 water. 2 This slide shows the area for gravity monitoring which 3 covers the area of expected water movement. The gravity 4 stations are shown by red dots. The center portion of the 5 gravity grid is the most important region and it is set up on 6 a 2,500 foot grid spacing. The center is also overlain with a 7 few closely -- with a few more closely spaced gravity lines to 8 improve the lateral sensitivity of the gravity processing. 9 Finally, the outer portion of the gravity grid is set up on a 10 station spacing of 5,000 ft. 11 The 4D gravity technique will enable us to map general 12 water movement, determine an average waterflood front, and 13 provide a means to perform a mass balance of injected water. 14 The major limitations of the 4D technique is that it cannot 15 detect small horizontal or vertical flood fronts and it cannot 16 provide any downhole zonal information. 17 In summary, the major components of the GCWI 18 surveillance plan are, one, injection wells will be monitored 19 as other water injection wells within the Prudhoe Bay pool. 20 Two, PNLs in -- in existing wells will provide downhole and 21 regional data on the water movement. Three, 4D gravity will 22 provide a general view of water movement. And four, reservoir 23 pressure monitoring will be done according to Prudhoe Bay pool 24 rules. 25 This concludes my prepared testimony. Are there any METRO COURT REPORTING, INC. 745 West Fourlh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 55 1 questions? 2 CHAIR TAYLOR: Commissioner Seamount? 3 COMMISSIONER SEAMOUNT: I guess I have no questions at 4 this time. Thank you. 5 CHAIR TAYLOR: Commissioner Heusser? 6 COMMISSIONER HEUSSER: I do have several. The first 1S just a - - the basic request for BP to provide the exhibit on page five and page SlX in kind of eight and a half by 11 7 8 9 size so it can be read, for our record. Jerry, what 10 surveillance options were considered -- or what was the range 11 of surveillance options that were considered for this project? 12 MR. BRADY: Well, obviously early on, the first 13 requirement that we looked at was the well spacing and seeing 14 what wells were there to try and use traditional methods to 15 log, you know, through using Lisburne wells, exploration 16 wells, whatever wells that might be in the area. After taking 17 a look at the spacing of those wells in the area where water 18 injection was, we considered other possibilities and that's 19 when we looked at the 4D gravity. We also briefly looked at 20 4D seismic. Those are the two that come to mind right away. 21 I think there were others, Julie, but I don't remember right 22 off. 23 COMMISSIONER HEUSSER: Was the option of using any of 24 the newly drilled water injection wells for early surveillance 25 one of the options that you considered? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · . - 56 1 MR. BRADY: We -- I'm not -- for monitoring the water 2 move men t ? 3 COMMISSIONER HEUSSER: Yeah. MR. BRADY: Those wells will be logged with injection profiles as soon as the well is put on line to see where the 4 5 6 water is going within the zones in the well. It's -- am I 7 answering your question? 8 COMMISSIONER HEUSSER: Let me ask it in a different 9 way. Were -- I know that the drilling is going to be staged. 10 Was it con- -- were any of the newly drilled wells slated for 11 water injection considered for surveillance? For example, 12 hold off on water injection in -- down one of them for the 13 first year and use it as a surveillance well to get a feel for 14 how the water is moving, l.e. is it moving as a piston or is 15 there any fingering going on? 16 MR. BRADY: So pre-drill an injection well and use 17 that as a monitoring well? 18 COMMISSIONER HEUSSER: Uh-huh, was that something..... 19 MR. BRADY: That was discussed. I. . . . . 20 MR. RICHMOND: Yeah, I can comment on that. That was 21 discussed as a possibility, and with the presence of some of 22 the Lisburne wells and the other wells in the area, as options 23 to do the neutron logging surveillance. That option was not 24 carried forward because we had this other option that we 25 thought was more preferable, and use the wells that we drill METRO COURT REPORTING, INC. 745 West Fourlh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 57 1 for the injection operations and not for the surveillance. 2 COMMISSIONER HEUSSER: Okay. So you intend to, as 3 soon as you drill these wells, put water down them right away? 4 MR. RICHMOND: Right. 5 COMMISSIONER HEUSSER: Okay. I have another general 6 question and I'm not sure who the correct person to respond to 7 this is. We have had a question that asks, in that entire gas 8 cap area, including whatever Lisburne wells, what is the areal 9 spread of oil saturation data in the original gas cap area? 10 MR. JHAVERI: What is the area of..... 11 COMMISSIONER HEUSSER: Yeah, what wells do you have 12 data on in the original gas cap area? 13 MR. JHAVERI: For the oil saturation? 14 COMMISSIONER HEUSSER: Right, in the original. 15 CHAIR TAYLOR: Excuse me, could you just move up to 16 the table so that you're closer to the microphone, so that the 17 court reporter can pick up your voice. 18 MR. JHAVERI: Again, somebody else can help me out 19 here. What I am aware of as far as the original oil 20 saturation in the gas cap is concerned was primarily derived 21 from some of the logged wells. And I think we have a - - actually, if not constant, we have a sort of a coalition of oil saturation in the gas cap which averages around 7.69 22 23 24 (indiscernible). But it based on some of the logs, logged 25 wells. I don't know if anybody else has more information. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 58 1 UNIDENTIFIED VOICE: (Indiscernible) . . . . . 2 MR. JHAVERI: Okay, yeah. And -- yeah, all right. 3 And this coalition was actually evaluated with some of the oil 4 based cores from the gas cap. 5 COMMISSIONER HEUSSER: Any idea how many wells you 6 used in order to come up with your data? 7 MR. JHAVERI: Let -- you have more information than 8 (indiscernible). . . . . 9 COMMISSIONER HEUSSER: It doesn't need to be precise, 10 just kind of your best memory, kind of general range of number 11 of wells. 12 MR. SCHNELL: To my recollection, there was a lot of 13 work that was done in conjunction with redetermination of 14 participation in the gas cap oil rim. And this relied very 15 heavily on the number of key wells that were cored, oil base 16 cores, the intent being to get good initial hydrocarbon 17 saturation information. I don't remember the exact number, 18 but I think the technique and all was well described in the 19 literature papers that were written by Ed Holstein (ph), for 20 one, and I think he had an ARCO counterpart that also co- 21 authored some of these papers. But it was a very small number 22 of wells because of the extremely high cost, and this was also 23 state of the art coring at the time. But what they found in 24 general was that immediately above shales they found oil 25 saturations that on the order of 10 percent or thereabouts, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e . 59 1 and that as you got away from these shales the oil saturation 2 was less and less. 3 COMMISSIONER HEUSSER: Thank you. 4 CHAIR TAYLOR: Any other questions? 5 COMMISSIONER SEAMOUNT: No. 6 CHAIR TAYLOR: Thank you. 7 MR. BRADY: Thank you. Perry Richmond will provide a 8 closing statement summarizing the requested changes to 9 Conservation Order 341C. 10 MR. RICHMOND: The presenters have provided summary 11 exhibits at the end of each section of testimony. We hope the 12 Commission finds this helpful when deriving findings and 13 conclusions for the Gas Cap Water Injection project. 14 In closing, I would like to reference our letter 15 submitted September 21, 2001, which contains our requested 16 pool rule changes to Conservation Order 341C. I will 17 summarize these changes here. 18 Paragraph (d) of Rule 12 provides that the operators 19 are directed to continue to investigate options to mitigate 20 pressure decline and to provide an annual report to the 21 Commission. With the implementation of gas cap water 22 injection, BP and the other owners should not be directed to 23 continue investigating options to mitigate pressure decline 24 and provide an annual report to the Commission on such 25 activity. Therefore, we request that the Commission revoke METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · 7 8 9 10 11 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · . . 60 1 paragraph (d) of Rule 12. 2 We also request modification of paragraph (c) in Rule 3 12 which currently provides that the operator maintain a 4 pressure differential of at least 250 psi between the minimum 5 miscibility pressure of the miscible injectant and the 6 prevailing reservoir pressure. Recognizing that gas cap water injection will mitigate pressure decline, a more appropriate pressure differential of 100 psi is requested based on thermodynamic uncertainty only. This change will allow BP to better optimize both the composition and volume of the miscible injectant. Finally, the Commission may wish to consider modifying Rule 11, which describes the Prudhoe Oil Pool surveillance report, to include the results of gas cap water injection surveillance. This concludes our testimony on the Gas Cap Water Injection project. Thank You. CHAIR TAYLOR: We've been going for about an hour and 45 minutes. I propose a 10 to 15 minute break and we can regroup, we can gather all our questions, see if there's any other testimony from other members here in the audience, and we'll come back. So help yourself to -- I guess there's some water here, restrooms are out in the hall. (Off record - 10:40 a.m.) (On record - 11:30 a.m.) METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 61 1 CHAIR TAYLOR: We're back on record. It's 2 approximately 11:30, but really only 15 minutes have passed. 3 Sorry for the delay. Mr. Richmond, I think we'll start with 4 you. Jack Hartz, our senior reservoir engineer, last week 5 forwarded you some questions that a contract expert for the 6 Commission had posed, Frank Leskovich (ph). Did you receive 7 those questions? 8 MR. RICHMOND: Yes. CHAIR TAYLOR: Did you have a chance to review those? MR. RICHMOND: Yes, we have reviewed those questions 9 10 11 and we reviewed our prepared testimony to ensure that we've 12 covered those topics that those questions were addressing. 13 CHAIR TAYLOR: And do you feel that the testimony 14 today then addressed all those questions, or were you planning 15 on responding in some other fashion to those? MR. RICHMOND: Yes, I think it does a good job of addressing those questions. I did send Jack a note that if 16 17 18 the prepared testimony doesn't do a good job of covering 19 those, that -- to ask any clarification questions at the 20 hearing. 21 CHAIR TAYLOR: Okay, thank you. I think what I'll do 22 right now is turn over questions to Commissioner Heusser. 23 COMMISSIONER HEUSSER: Does Dan want to go first? 24 CHAIR TAYLOR: After you. 25 COMMISSIONER HEUSSER: Okay, let's see. I'm going to METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e! 62 1 start basically at the front of the presentation and kind of 2 work my way back some. Perry, I'm not sure if you're the 3 right person to answer this, so if there is somebody else 4 that's going to respond, would you please come up to the front 5 desk and state your name for our record, please. Okay, I'm 6 looking at section two -- I'm looking at page two, the plot of 7 reservoir pressure of the Prudhoe Bay oil field. And then the 8 text says that currently the reservoir pressure is declining 9 at 25 to 35 psi per year. And I note that this plot 10 represents some sort of averaged reservoir pressure, but what 11 would be useful is this pressure decline plot by major area of 12 the field as gas cap water injection affects it. For example, 13 you know, how does the pressure in the northwest fault block 14 area respond. You know, how does the gravity drainage area 15 respond. You know, just kind of the individual areas. 16 So you'd like to comment on -- us to MR. RICHMOND: 17 comment on how the --..... 18 COMMISSIONER HEUSSER: Yes, uh-huh. 19 . . . . . how the individual areas may be MR. RICHMOND: 20 impacted by the..... 21 COMMISSIONER HEUSSER: Yes, the individual areas, how 22 they may be impacted by gas cap water injection, the 23 pressure..... 24 I can address that. The -- we don't MR. RICHMOND: 25 have plots of the individual areas such as what you might get METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 63 1 from a full field model, like taking segments out of the full 2 field model and plotting up the pressures. However, I will 3 state that the pressure support from the gas cap water 4 injection we are expecting all regions of the field to benefit 5 from this pressure support. Now the exact magnitude each area 6 will have, we don't have those details to share with you 7 today. 8 COMMISSIONER HEUSSER: Will you have those details to 9 share? 10 MR. RICHMOND: We can provide some additional detail 11 on that. 12 (Indiscernible) . . . . . UNIDENTIFIED VOICE: 13 MR. RICHMOND: She said will you provide more detail 14 on it. Would you like us to provide that detail? 15 COMMISSIONER HEUSSER: Yes, that would be very useful. 16 UNIDENTIFIED VOICE: What kind of details do you have 17 in mind? 18 COMMISSIONER HEUSSER: A plot of reservoir pressure 19 decline by what I call major field area. You know, northwest 20 fault block, gravity drainage, WPWZ, EPWZ, Flow Station 2, and 21 then a comparison that also includes this kind of average 22 field pressure decline. 23 MR. JHAVERI: I can kind of -- Bharat Jhaveri. I can 24 kind of comment on that. I think the key thing, this is 25 the pressure decline that we are talking about is the the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · 3 4 5 6 7 8 9 10 11 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · e e 64 1 weighted hydrocarbon full volume average, weighted pressures. 2 And when we look at the pressure decline in almost all of the areas of the field, different regions that you just specif- -- you know, just said, like northwest fault block, Flow 2, you know, updip (indiscernible), downdip (indiscernible), and all that, what you find is that pretty much all of the areas on average are declining with time as far as this pressure plot is concerned. Key thing to consider here is that there is a pressure gradient in the field, so in general the areas which are closer to the gas cap, they are at higher pressure than compared to the area that is, you know, down deep. You know, mostly because the pressure in the -- you are injecting gas in the gas cap, so there is somewhat higher pressure while you are your pressures sink in the oil rim. So as the pressure sinks, it is (indiscernible) out of the oil rim sometimes at the lower pressure. And typically you are looking at the pressure gradient in the field, from the gas cap to the oil rim, that could be as much as a few hundred psi (indiscernible). So what you will see is a -- you know, in general is the pressure declining in the field, typically around this block, and this is an average pressure which is hydrocarbon weighted average pressure of all these areas. But you'll see a -- you know, some gradient between the polygons (ph) which are closer to the gas cap. METRO COURT REPORTING, INC. 745 West Fourlh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e . 65 1 COMMISSIONER HEUSSER: Yes. Okay, thank you. I am 2 looking at section six, and it's the area of pulsed neutron 3 logging. It's -- I'm looking at the map here, but I have a 4 general question about the sensitivity of pulsed neutron logs. 5 Jerry, what is the sensitivity spin of measurement of pulsed 6 neutron logs when you go from an environment that's 80 percent 7 gas and, you know, when you inject water it goes to 80 percent 8 water? 9 I can't remember off the top of my head. MR. BRADY: 10 We did get -- Schlumberger did model their RST in the sigma 11 mode to determine the difference between the gas cap with gas 12 versus with water. It's significant. It's greater than what 13 you would certainly see trying to monitor the difference 14 between oil and water. I'm sorry, I can't remember off the 15 top of my head what those numbers were, but it was several 16 sigma units. 17 COMMISSIONER HEUSSER: Okay. So when you're doing a 18 comparison you know, a time lapse comparison, the 19 difference in measurements is so significant that kind of the 20 statistical part of it washes out? I mean, so you will truly 21 see a difference? 22 MR. BRADY: According to their models, we should be 23 able to see a significant change. It should be greater the 24 oil/water change. 25 COMMISSIONER HEUSSER: Okay. I believe that when we METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 66 1 asked a question about hydrocarbon saturation in the gas cap, 2 I heard, I think it was Lynn, say that the open hole logs were 3 calibrated to some oil base cores? And are there plans to log 4 these new water injection wells? 5 MR. BRADY: I'm sorry, what was the last part again? 6 COMMISSIONER HEUSSER: Are there plans to log these 7 new water injection wells? Open hole log them? 8 MR. BRADY: Yes, we will we're planning on open 9 hole logging them, but I'm not sure if we've come up with the 10 actual logging program yet at this time. 11 COMMISSIONER HEUSSER: Okay. And if you're going to 12 do an open hole logging program, are you going to go ahead and 13 see how the results of these open hole logs fit in with that 14 little -- the model that you have that calculates hydrocarbon 15 saturation based on the model developed from the oil base 16 cores and those original logs? 17 MR. BRADY: I'm not sure that we've made plans for 18 that at this point. I don't think we've developed the 19 detailed drilling program and logging program to go into it at 20 this point. 21 COMMISSIONER HEUSSER: There is still some question 22 about what the hydrocarbon saturation is in the eastern part 23 of the gas cap and we were wondering what technique you were 24 going to use in order to, you know, kind of evaluate that and 25 give yourself a starting spot. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 67 1 MR. RICHMOND: You're talking about in reference to 2 the current saturation conditions..... 3 COMMISSIONER HEUSSER: Right. 4 .... .In that part of the field? MR. RICHMOND: 5 COMMISSIONER HEUSSER: Uh-huh. 6 MR. RICHMOND: Yeah, right now we do not have a 7 surveillance plan completed that would include further 8 quantification of the saturations in that part of the field. 9 The sanctioning of the project is based on the confidence that 10 we have in the saturation based on our modeling of that part 11 of the field and our understanding of the of the general 12 saturation from the cores and the history of how the fluids 13 were initialized in the reserVOlr. And we rely a lot of our 14 anticipated saturations on that historical knowledge. 15 COMMISSIONER HEUSSER: So I -- did I hear you say that 16 you hadn't firmed up your plans or that you didn't intend to 17 take a well or two and look at saturations in that..... 18 MR. RICHMOND: We don't have..... 19 . ... . eastern gas cap area? COMMISSIONER HEUSSER: 20 MR. RICHMOND: We haven't finalized our plans yet on 21 the wells that we're going to be drilling. The surveillance 22 related to the saturation question that you bring up is still 23 a possibility, but I want to be clear, though, that we don't 24 have any current plans, though, to even include that into the 25 surveillance plans, but it's still a possibility that we could METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · 5 6 7 8 9 10 11 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · e e 68 1 consider. 2 COMMISSIONER HEUSSER: What kind of time frame are you 3 looking at to firm up your drilling and open hole logging 4 plans? MR. RICHMOND: Probably over the next few months. As we head into next year, we will be trying to firm up our drilling plans. COMMISSIONER HEUSSER: Okay. I've got a question from our staff. I understand -- or we understand that the estimated recovery in the gas cap was on the order of 50 million barrels. And are you able to provide us with estimated recoveries for residual oil and condensate to help us put this 50 million barrels in perspective? MR. JHAVERI: Let me understand the question again. The net recovery in the gas cap, as I said earlier, was minus 20, which is made up of plus 30 in the non-invaded vapor -- non-water invaded area, and minus 50 in the water invaded area. Your question is the estimate of this minus 50 in terms of -- in terms of, you said, relic..... COMMISSIONER HEUSSER: Right. MR. JHAVERI: I'm sorry, you said..... COMMISSIONER HEUSSER: Basically gas cap liquids, a total recovery. MR. JHAVERI: Total -- maybe I'm not quite sure what you're asking, because the minus 50 represents basically the METRO COURT REPORTING, INC. 745 West Fourlh Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 69 1 total recovery that you would have from this area of the gas 2 cap had you not done the gas cap water injection, which would 3 be a (indiscernible) of total liquids that would have been 4 there at the end of the field life. And then the gas cap 5 water injection scenario would give you a recovery. And the 6 difference between the two in this region, in the water 7 invaded area, is minus 50. So that is the estimate. I'm not 8 really clear on what you're..... 9 COMMISSIONER HEUSSER: Okay. You know, I haven't 10 asked the question very well and what I'd like to do is allow 11 one of our staff to ask the question better than I have. Jack 12 Hartz, would you please ask the question? 13 MR. HARTZ: Yeah, Jack Hartz at OAGCC. 14 CHAIR TAYLOR: Would you come to the microphone, 15 please? 16 MR. HARTZ: The question does not you've 17 characterized the loss of gas cap liquids in your 18 presentation. I just wanted to see it or we wanted to see 19 it put in perspective of the estimated recovery of liquids 20 from the gas cap over the life of the field. I believe 21 there's a component of retrograde condensate as well as 22 vaporized residual oil that are going to be recovered from the 23 gas cap, and just to give us a perspective of that total 24 recovery from gas cap liquids with respect to the projected 25 losses based on the gas cap injection scenario. That's the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 70 1 question. 2 MR. JHAVERI: Okay, I can answer again, you know, some 3 of that right now. If you were to look at the total recovery 4 from the gas cap in the base case, and again I'm going to talk 5 in terms of order of magnitude. So, you know, I'm going to 6 quote some numbers, but they are order of magnitude. They are 7 not -- they are out of the top of my head, you know. And we 8 are looking at -- if you didn't do a gas cap water injection, 9 and if you look at all the total liquids that would have been 10 left in the gas cap, that would include vaporization of the 11 original oil saturation which I mentioned earlier, which was 12 7.69 percent on average in the gas cap. That oil 13 vaporization, plus any original liquids that are held by the 14 gas in the gas cap, altogether within the gas cap in the base 15 case would be of order of -- you know, I'm just going to say a 16 number off the top of my head. Anyone here can correct me. 17 You know, 800 million sort of number I'm looking at. 18 What this means is that when you end up doing the gas 19 cap water injection, from the area which includes both the 20 invade and non-invaded area of the gas cap, you would have 21 about 20 million barrels left, which means it's a very small 22 percentage of the total recovery coming out of the gas cap. 23 MR. HARTZ: Yeah, we wanted that perspective. 24 MR. JHAVERI: Okay, I hope I helped. 25 COMMISSIONER HEUSSER: Bharat, you're probably the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 71 1 correct person to answer this next question, too. What kind 2 of worst case recoveries did you see? 3 From the model? MR. JHAVERI: 4 COMMISSIONER HEUSSER: From the model, uh-huh. 5 MR. JHAVERI: The worst case recovery from the model 6 that we have seen are around 150 to 170 million barrels. Some 7 of the lowest numbers actually were a result of lower than 8 650,000 barrels per day of water injection into the gas cap. 9 For example, if we inject the water for -- as Perry Richmond 10 showed, which is not 650, but it's a ramp up, we can get at 11 less -- as much less as 175 million barrels. And some of the 12 worst case scenario on top of that, we could get as less as 13 100, 150 million barrels out of the full field model. 14 So basically the worst case COMMISSIONER HEUSSER: 15 scenarios that you've just described are really a function of 16 water injection rate. Did you have any cases where -- did you 17 identify a worst case where perhaps you had non piston-like 18 displacement? 19 MR. JHAVERI: No, in fact, that's a very good 20 question. We must have tried for -- a lot of people over many 21 years tried to come up where you would have a worse than a piston-like displacement for a variety of reservoir description sensitivity, and we couldn't. And the reason 22 23 24 being, as we have talked about in the testimony today, that 25 the water displacing gas inherently set up the variable METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 72 1 mobility ratio displacement. That it basically -- the 2 reservoir hydrogeneity (ph) is basically not a parameter. 3 It's not important. So much hydrogeneity you might have. So 4 essentially it dissipates (indiscernible)..... 5 COMMISSIONER HEUSSER: Okay. Is -- what triggers in 6 your surveillance operations would cause you to shut off gas 7 cap water injection? 8 MR. RICHMOND: The surveillance data we'll be taking 9 over the years of the project, we'll be continually digesting 10 that information. So anything that we see as it relates to 11 water movement that's different than our expectations, we'll 12 have to study that and adjust to that. And as far as the 13 actions that we would take at that point, I really can't say 14 right now until we see the outcome that would make us want to 15 do a change. One change that would be possibility would be 16 the cumulative water that we would inject into the gas cap. 17 The project that we've shown you today is approximately a 20 18 year project. We'll continue to monitor the project and see 19 if we want to continue on that course as we review the 20 surveillance data. 21 COMMISSIONER HEUSSER: Is there a chance that the 22 project could be shorter lived? 23 MR. RICHMOND: There is that chance. 24 COMMISSIONER HEUSSER: Fifty-fifty? Sixty-forty? 25 Eighty-twenty? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 73 1 MR. RICHMOND: And I would -- our 20 year project is 2 what we've, you know, based these benefits on. But when you 3 say 50/50 or some percentage, if you're going to go higher and 4 lower, I think there's a reasonable chance it'd be both longer 5 and shorter. We don't really have a preferred outcome when it 6 comes to any kind of statistical opinion on being longer or 7 shorter. 8 So the modeling and COMMISSIONER HEUSSER: 9 surveillance that you'll be doing will allow you to -- will it 10 allow you to expeditiously evaluate whether or not this 11 project is proceeding as you expect it? 12 MR. RICHMOND: We are very intent that our 13 surveillance will give us a -- good information for making 14 those decisions, but I can't -- I can't say until we actually 15 see those results how -- how complete the story will be when 16 it comes to -- how every barrel of water we would inject, 17 exactly where its locale is in the reservoir. So we'll just 18 have to look at those evidence in composite and see where that 19 information leads us. 20 I have a question on -- it's in COMMISSIONER HEUSSER: 21 your conclusion remarks. I believe it's paragraph three. One 22 of the things that BP has requested is a -- instead of a 250 23 psi pressure differential, you're requesting 100 psi pressure 24 differential? And we've got some great history here at the 25 Commission, and I didn't understand where the 250 came from, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e It 74 1 but I've been told that the 250 psi represents a 30 psi 2 pressure decline plus a residence time of the fluids in the 3 reservoir of five years plus 100 psi buffer. So if you're 4 asking for 100 psi rather than the 250, what are you basing 5 that on? How did you come up with that number? 6 MR. RICHMOND: Well, the basis for the 250 versus the 7 100 would be, if you stabilize reservoir pressure then you 8 won't have that ongoing decline in reservoir pressure that 9 that residence time, that 150 psi, which is the component that 10 was based on that ongoing decline. So if you remove that 150 11 psi component out of the composite 250 psi, that's where you 12 end up with the 100 psi. So that was the basis of settling on 13 the 100 pSl. 14 COMMISSIONER HEUSSER: And you're asking for this from 15 day one of the project? I mean, how long will it take for the 16 pressure decline in the field to kind of stabilize out from 17 the day that you begin water injection? 18 MR. RICHMOND: Yeah, when it comes when it comes to 19 the length of time, I can't say exactly every point in the 20 reservoir what the time change -- what -- how much time is 21 required for the -- every subsequent year we expect the 22 reservoir pressure, on average, to be at a higher level. So 23 we think this impact will be -- at least in a 12 month period, 24 to be relevant to when it comes to looking at reservoir 25 pressure. The 100 psi that we we're requesting is actually METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 75 1 more of a minimum. If we see any evidence that we want to be 2 higher than 100 psi, we'd still have that flexibility. But as 3 we look at pressure being stabilized, it also gives us the 4 flexibility to go as low as 100 psi. 5 COMMISSIONER HEUSSER: Thank you. I have two kind of 6 requests for Dan as to his question. One of the things that 7 would be very useful is what we're calling a desk size map 8 with the entire gas cap area identified, along with the wells 9 including the Lisburne monitoring wells. Something that would 10 be similar to -- I guess the closest thing is section six, 11 page five. But a presentation that just has those gas cap 12 area wells on it, including AGI, NGI, WGI, the Lisburne 13 monitoring wells. That would be a useful map to have. Can 14 you provide us with that? 15 MR. RICHMOND: You said desktop size? Is that what 16 you prefer? 17 COMMISSIONER HEUSSER: What's desk -- yeah, so we can 18 okay. And then my last request is is -- because we're 19 moving into the electronic age here, can you provide us an 20 electronic copy of your presentation today, along with that 21 nice little video presentation, the powerPoint presentation 22 that shows how the fluids are moving through the reservoir? 23 Can you do that? 24 MR. RICHMOND: Yes, we can provide that. 25 COMMISSIONER HEUSSER: Great. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · 3 4 5 6 7 8 9 10 11 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · e e 76 1 MR. RICHMOND: In the format for that, we would 2 provide it in a CD. Is that okay? CD form? COMMISSIONER HEUSSER: Yes, that would be just fine. Thank you. That's it for me. CHAIR TAYLOR: Mr. Seamount, do you have any questions? COMMISSIONER SEAMOUNT: I have no questions, thank you. CHAIR TAYLOR: Is the sign-in sheet someplace out In the back of the room? Oh, here it is. Are there any additional folks who have come in since they signed in that would be interested in testifying this morning or in making a statement? I see no response to that question. It appears there's nobody else to provide either additional testimony or statements. We will make the binders that you provided to us part of the record. COMMISSIONER HEUSSER: One more question. I'll nickel and dime you to death here. This gets back to the list of questions that -- from Mr. Leskovich that I believe that you've seen. And it has to do with wetability. And the question that I have is is that previously we have heard testimony identifying concern if water was injected into the gas cap, and I'm just going to pull a few sentences from this list of questions. But one was -- one of those was that the gas cap rock tends to be oil wet. Oil wetability at lower METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 77 1 water saturation such as found in the Prudhoe Bay gas cap 2 could present problems. And he goes on to say in an oil 3 reservoir it's normally unadvisable to inject water if the 4 rock is oil wet because of the high residual saturations. 5 What would happen in the Prudhoe Bay gas cap with its relic 6 oil saturation likely to be filling the smaller pore spaces? 7 MR. JHAVERI: Yeah, I can -- likely -- following that 8 question, we actually did modify our attitude thinking of our 9 testimony, and that is that in the way we deal with this is 10 out in the gas cap, the residual oil that is in the gas cap, 11 is basically immobile, and that it won't move. And the second 12 thing is that the water that is injected into the gas cap does 13 actually trap that oil, and in addition it will also trap gas. 14 So in the base case, you're not COMMISSIONER HEUSSER: 15 recovering any of this residual gas cap oil? 16 MR. JHAVERI: Even -- that's correct. Even in the 17 base case, that reliced (ph) oil is not going to be residual 18 oil however we say that. It's not going to have any recovery 19 by mobility in the oil phase. In fact, that is one of the 20 reason we are -- the gas injection, that is the only way we 21 can recover any hydrocarbons from this oil is by vaporization. 22 COMMISSIONER HEUSSER: Okay. I believe that you've 23 answered his question, thank you. 24 CHAIR TAYLOR: Mr. Richmond, with respect to the 25 additional materials that you were going to submit to the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suiie 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 78 1 Commission, I'd like to keep the record open until such time 2 as those materials arrive. Do you have some indication about 3 how long that would be? 4 MR. RICHMOND: We'll try to get you as soon as 5 possible. So if not today, over the next couple of days. 6 CHAIR TAYLOR: Shall we say by next Monday? November 75th? 8 MR. RICHMOND: If you receive -- if you receive it 9 earlier than that, does the record become closed sooner? Or 10 how does that work? 11 CHAIR TAYLOR: I hadn't thought about it. We can 12 treat it as having closed at the time that we get it in, 13 unless we have some additional questions that we would forward 14 to you. So I'll keep the record open until the 5th unless we 15 receive all the information before then. 16 MR. RICHMOND: Sounds good. 17 CHAIR TAYLOR: Okay. Well, thank you very much for an 18 excellent presentation. Thank you all. I'm sorry that we 19 stretched the 15 minute break out to 45 minutes, but we 20 appreciate your time. Thank you. 21 (END OF PROCEEDING) 22 * * * * * * 23 24 25 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 1 C E R T I FIe ATE 2 UNITED STATES OF AMERICA) )ss. 3 STATE OF ALASKA ) 4 I, Cari Ann Ketterling, Notary Public in and for the 5 State of Alaska, and Reporter for Metro Court Reporting, do 6 hereby certify: 7 That the foregoing Alaska Oil & Gas Conservation 8 Public Commission Public Hearing was taken before Julie o. 9 Gonzales on the 30th day of October, 2001, commencing at the 10 hour of 9:04 o'clock a.m., at the offices of Alaska Oil & Gas 11 Conservation Commission, 333 West Seventh Avenue, Suite 100, 12 Anchorage, Alaska¡ 13 That the meeting was transcribed by Julie o. Gonzales 14 to the best of her knowledge and ability. 15 IN WITNESS WHEREOF, I have hereto set my hand and 16 affixed my seal this 7th day of November, 2001. 17 18 Notary Public in and for Alaska My commission expires: 07/19/04 19 20 21 22 23 24 25 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 #4 e e . Prudhoe Bay GCWI AOGCC Hearing Testimony October 30,2001 . 1. Introduction 2. Overview 3. Benefits 4. Water Movement a. Water displacing oil movie b. Water displacing gas movie 5. Major Gas Sales Relationship 6. Surveillance 7. Conclusion . AOGCC Hearing - GCWI October 30, 2001 e e . Prudhoe Bay GCWI AOGCC Hearing October 30,2001 1. Introduction Perry Richmond BPX (Alaska) Inc. October 30, 2001 Introduction Exhibit 1 . Good morning, my name is Perry Richmond. I am the East/W est Prudhoe Bay Waterflood Resource Manager for BP Exploration (Alaska) Inc. BP is the Operator of the Prudhoe Bay Unit. This hearing has been scheduled to consider information supporting the modification of pool rules for implementation of Gas Cap Water Injection in the Prudhoe Bay Oil Pool. The Gas Cap Water Injection project is a result of studies to mitigate reservoir pressure decline for the Prudhoe Bay Oil Pool. It is a new element in the depletion strategy of the Prudhoe Oil Pool and will Improve recovery. BP has previously submitted a request for revision to the pool rules in correspondence to the Commission dated September 21,2001. . Page 1 · · · e e I would now like to give to the Commission a copy of the Testimony and Exhibits we will be presenting today. We will use a projector to display the exhibits as we read our prepared testimony. [Introduce Evidence] The testimony we are presenting will be given by representatives of the Owners, BP, ExxonMobil and Phillips and is divided into seven parts. I will provide an overview of the Gas Cap Water Injection project and a summary of other pressure support options that were considered. I will also give a closing statement summarizing requested changes to Conservation Order 341 C. Bharat Jhaveri will testify about recovery benefits, Matt Maguire about water movement, Lynn Schnell about the relationship to major gas sales and Jerry Brady about surveillance. A few notes about acronyms. We may occasionally use the letters GCWI to refer to the Gas Cap Water Injection Project. You may also hear GD which refers to the Gravity Drainage area of the field and GDWFI which identifies that part of the field where Gravity Drainage and Water flood Interact. We will keep these terms to a minimum. We are asking that each witness be qualified as an expert, and each of us is prepared to respond to questions concerning our testimony and related exhibits. Page 2 e e · Prudhoe Bay GCWI AOGCC Hearing October 30, 2001 2. Overview Perry Richmond BPX (Alaska) Inc. October 30. 2001 Overview Exhibit 1 · I'd now like to be sworn and qualified as an expert witness. [Administration of Oath) My name is Perry Richmond. I am a Resource Manager for BP, currently responsible for managing the Prudhoe Bay water flood in the Northwest Fault Block and Flow Station 2 areas. Technical staff in my group will be responsible for implementing and monitoring the Gas Cap Water Injection project. I received a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University. I was employed by ARCO in 1982 and have worked on numerous engineering projects in Texas, Alaska, and overseas. I have worked on the Prudhoe Bay Field since January, 1998. I have been employed by BP since July, 2000. [Acceptance as Expert Witness) I will now provide an over view of the project. Since field startup in 1977, cumulative production from the Prudhoe Bay Oil Pool is now over 10 billion barrels. This surpasses the original estimate of9.6 billion barrels. This excellent performance has resulted from optimizing total recovery by progressively using multiple recovery mechanisms, such as gravity drainage, gas cycling, oil vaporization, waterflooding, and miscible flooding. These same recovery mechanisms, particularly gravity drainage and gas cycling, result in liquid hydrocarbon and gas voidage from the reservoir, leading to a steady decline of reservOIr pressure. · Page 1 Reservoir Pressure - Prudhoe Bay on Pool 0) "'- ~ III III ~ D. ø 0) 3000 lIS "'- ø ~ 2500 October 30, 2001 Overview Exhibit 2 Exhibit 2 shows the history and forecast of reservoir pressure under the existing recovery mechanisms. Currently, reservoir pressure is declining at 25 to 35 psi/year. The Working Interest Owners have studied options to mitigate pressure decline and have reported annually the progress of these studies to the Commission. As a culmination of these studies, the Working Interest Owners sanctioned the Gas Cap Water Injection project in June, 2001. This project represents a new element in the depletion strategy of the Prudhoe Bay Oil Pool and will mitigate reservoir pressure decline and improve recovery. Gas Cap Water Injection Project · Ramp up to 650 mbd seawater into eastern gas cap area · Mid 2002 project start-up · 150-200 mmbl gross reserves 700 Ii! 600 :::¡¡ 500 i .S! 400 Ü .!. 300 .5 ! 200 ~100 o 2000 2005 2010 2015 2020 2025 East Dock Injection October 30,2001 Overview Exhibit 3 The project scope calls for ramping up to 650,000 barrels per day of seawater into the eastern portion of the gas cap trom an injection site loc.ated at the East Dock Staging Pad. As shown by the chart, injection increases over time. This is caused by the availability of more seawater as demand decreases in other projects, such as the Flow Station 2 and Point McIntyre water floods and Grind and Inject. Facility construction is planned for this winter, followed by start-up of injection in mid 2002. Water injection is anticipated to continue for twenty years, with a final injected water volume near four billion barrels. The increase in hydrocarbon liquid recovery is expected to be 150 to 200 million barrels. Page Gas Cap Water Injection - Facilities Scope · New SWI Line, FS2 to East Dock · STP/ESIP Upgrades · East Dock Injection Facility · 5-7 Injection Wells SiP -~¡),,;¢¡,; Sto__ AGI Prudhoi! Bay NWGI October 30, 2001 Overview Exhibit 4 To implement the Gas Cap Water Injection project, a new seawater pipeline from Flow Station 2 to the East Dock Staging Pad will be constructed. The new line will have a 32" diameter and a total length of approximately 18,000 feet. It will tie-in to the existing 32"seawater line running from the Eastern Seawater Injection Plant to Flow Station 2. Upgrades to pumps, piping, filters and plant control systems are required at the Seawater Treatment Plant to accommodate the seawater demand. For the Eastern Seawater Injection Plant, waste heat louvers will be upgraded. A heated pig receiver/manifold module and well houses will be installed at the East Dock Staging Pad to accommodate five to seven new injection wells. October 30, 2001 Overview Exhibit 5 wells. areas e e . Gas Cap Water Injection - Well Completion Plan "",·WCIW WElllE~D:., or.- .~.. 13 :uaw TAM Port Collar _1000' 7" SCSSay ·1800' 13 3/8",... Surface CIg -.UO· SS TYD 15/8" 29.7', ST.....IPC !njullon TubinG w17~ ICC...ort.. 1-5/S" . 7"lnjectlon Packe, 7" Profil.. (2) TOL line' Hano.rl Packer -8150' S8 TVD '-51S", 4ft I"honudlst. Cso -8210' SS TYD 7" 29. injection l.lne, -8580' as TVD Det. Rev 8 Commenw Oa. Cap Wet., In}ectlon Generic Completion Design BP Alu.8 Drilling & Wella October 30, 2001 OvelView Exhibit 6 . Exhibit 6 shows a representative well completion plan. Each completion will include 13 3/8" surface casing cemented to surface, 9 5/8" intermediate casing with cement brought to 1000' above the shoe, and a fully cemented 7" injection liner. The tubing will be 7 5/8" and will include a 7" subsurface safety valve and two 7" profiles. The tubing is large to accommodate the high volume of water to be injected. The tubing will also be plastic coated to help minimize the friction losses. Average surface pressure for these new injection wells will be approximately 2700 psi. Maximum injection pressure is expected to be approximately 3100 psi. This concludes the project overview. I will now begin my testimony on the other pressure support options that were considered. . Page 6 e e · Gas Cap Water Injection Project Pressure Support Options October 30. 2001 Overview Exhibit 7 · The Owners formed a multi-company, Pressure Studies Initiative (PSI) Team in 1991 to evaluate pressure mitigation options for the Prudhoe Bay Oil Pool. Prior to the PSI Team's focus on Gas Cap Water Injection, several pressure support options were screened. These options included supplemental hydrocarbon gas injection, nitrogen or flue gas injection, fuel gas alternatives, additional water injection in oil rim areas, and gas cap water injection. · Page 7 . e · Pressure Support Options Considered Supplemental Hydrocarbon Gas Injection c Limited sources, high cost Nitrogen or Flue Gas Injection c Expensive to implement c Hurts vaporization relative to lean gas c Contaminates gas stream Fuel Gas Options (Import gas, oil as fuel, import electricity, gas hydrates) c High Cost c Results in immediate Field Gas Offtake reduction, not attractive October 30.2001 Overview Exhibit 8 · Many of the options considered were not viable, primarily due to high capital costs and/or recovery benefits limitations. These projects are summarized on Exhibit 8. For supplemental hydrocarbon gas injection, limited gas sources exist. A Point Thomson type source was evaluated in the screening study; however, high capital costs associated with development, distribution, and compression facilities makes this option unattractive. Nitrogen or flue gas injection are also unattractive since these options would require high capital costs for compression or air separation, result in reduced vaporization efficiency compared to lean hydrocarbon gas, and contaminate the reservoir gas. Options to replace the fuel gas used by Prudhoe facilities, and thereby reduce reservoir voidage, were also screened. Fuel gas options included importing gas, using oil as fuel, importing electricity, or developing gas hydrates. The fuel gas options are unattractive due to high capital costs, unproven technology, and the fact that replacing the fuel gas causes a reduction in field gas off-take, resulting in an immediate decrease in oil rate. · Page 8 e e . Pressure Support Options Being Implemented Oil Rim Water Injection D Justify by overall recovery benefits of each project D EWE waterflood, Updip Zone 4, and Updip Victor WAG currently being implemented D Limited pressure support potential compared to gas cap water injection Gas Cap Water Injection D Low cost / high benefit potential D Recommended for detailed study by PSI Team October 30, 2001 Overview Exhibit 9 . Exhibit 9 shows projects that have been identified as viable and are now in various stages of implementation. Projects that increase water injection into the Oil Rim areas have been justified based on overall recovery benefits, rather than just pressure support benefits. Eileen West End Waterflood, Updip Zone 4 Water/Miscible Injection, and Flow Station 2 Updip Victor WAG Injection are being implemented as projects with related pressure support benefits. However, they have limited pressure support potential when compared to gas cap water injection. Gas cap water injection was screened and found to have significant recovery benefits with reasonable capital cost requirements. The PSI Team thought this option was potentially attractive to very attractive. The PSI Team recommended gas cap water injection be their focus for more detailed study. This concludes my prepared testimony. Are there any questions? Thank you. The next four presentations will describe key results from the detailed studies of Gas Cap Water Injection. First, Bharat Jhaveri will review benefits. . Page 9 e e . Prudhoe Bay GCWI AOGCC Hearing October 30, 2001 3. Benefits Bharat s. Jhaveri BPX (Alaska) Inc. October 30, 2001 Benefits Exhibit 1 . Good morning. My name is Bharat S. Jhaveri. I'd now like to be sworn and qualified as an expert witness. [Administration of Oath) I am a Consulting Reservoir Engineer with BP Exploration (Alaska) Inc. since 1995. I received a PhD in Chemical Engineering from Stanford University in 1979. I have been involved with the development and reservoir management of the Prudhoe Bay field for over twenty years, from 1981-1994 at ARCO and since 1995 at BP. [Acceptance as Expert Witness) I will now testify about the recovery benefits of the Gas Cap Water Injection Project. . Page 1 4000 3500 3000 l 2500 l!f 2000 ;:¡ If ~ 1500 CI.. 1000 500 o 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030 ..... r"" .- '" i - ~--ww - -. ·r····~." ,L . . -without GCWI -with GCWI i October 30,2001 Benefits Exhibit 2 e October 30, 2001 Benefits Exhibit 3 Ii s October 30,2001 Benefits Exhibit 4 I now II! s October 30,2001 Benefits Exhibit 5 IS IS a I now III s October 30, 2001 Benefits Exhibit 6 As IS more more I now / N s October 30.2001 Benefits Exhibit 7 are s October 30,2001 Benefits Exhibit 8 e e . Summary - Benefits · GCWI arrests pressure decline · Increased pressure improves oil recovery mechanisms + Vaporization + Gravity Drainage + Waterflood + EOR · GCWI provides 150-200 MMB of liquid reserves October 30, 2001 Benefits Exhibit 9 . In summary, the gas cap water injection project outlined here arrests pressure decline in the field and increases recovery. All recovery mechanisms benefit from the higher pressure: vaporization, gravity drainage, waterflood and EOR. Total incremental liquid recovery ranges from 150-200 MMB. The range reflects modeling uncertainties and the availability of sea water. This concludes my prepared testimony. Are there any questions? Thank you. Next Matt Maguire will review water movement. . Page 9 e e · Prudhoe Bay GCWI AOGCC Hearing October 30, 2001 4. Water Movement Matt Maguire Phillips Alaska Inc. October 30,2001 Water Movement Exhibit 1 · Good morning. My name is Matt Maguire. I'd now like to be sworn and qualified as an expert witness. [Administration of Oath) I am a Senior Reservoir Engineer with Phillips Alaska, Inc., currently assigned to the Greater Prudhoe Area Team. In 1988, I received a Bachelor of Science Degree in Petroleum Engineering from the University of Alaska-Fairbanks. I started working for ARCO Alaska out of college and am currently in my 14th year of working Prudhoe Bay engineering projects. [Acceptance as Expert Witness) I will now testify about water movement. · Page 1 October 30, 2001 Water Movement Exhibit 2 lam water movement cap. I moves once it is objectives GCWI IS I will correct here area are at we want to can we is to an Flood Front Examples · Piston-like Flood Front I Injection ~ " c'" 0'1;.c~ '9 '--- 'V ,,?oÇJ .. Channeling Type Flood Front I Injection ~ " c'" 0'1;·c~ '9 ~ 'V ,,?oÇJ October 30, 2001 Water Movement Exhibit 3 This slide shows two flood fronts that are relevant to the discussion of this project. Each ofthese is pictured in a 2-D cross-section. Our preference is the piston-like flood front. This is characterized by efficient and unifonn displacement as opposed to having channels develop. Here, the front is stable, moves slowly, and as a result takes much longer for water to breakthrough. With a channeling front, it is easy to see how water breakthrough would occur earlier. As you can imagine, this type of behavior within the GCWI project is not desirable. For gas cap water injection, the displacement of gas by water is very efficient, and essentially piston-like. This is because gas is 100 times more mobile than the water that displaces it. I will now demonstrate this for you with a flow model. Homogeneous Model with 5 Darcy Thief Grid Size: 1 ac x 2 ft, Dimensions: 42xlx50 October 30.2001 WatBr Movement Exhibit 4 1 have two reservoir simulations to show you. Each uses the reservoir description shown on this slide. The model is 2-D cross-sectional in nature with an injector on the left and a producer on the right. The cells are 208 feet square and 2 feet thick. The green cells have 500 md permeability and the orange ceHs 5000 md. The orange cells represent a 20-foot thick thief zone in the middle of the model. The main difference in the model runs will be the fluid within it. In one simulation the model contains oil; and the other, gas. In each simulation we wil1 inject water. The purpose of these comparison cases is to show how a high permeability zone has little effect when water displaces gas. <Testimony just before running the water displacing oil "video"> This first simulation is of water displacing oil. Here we would expect the permeabilities to playa major role. <Run water displacing oil video> <Testimony during water displacing oil "video" at breakthrough point> Note at this point that breakthrough has occurred at the producer. <Testimony during water displacing oil "video" at the end> This is the end of the run. Let me run this one more time. <Run water displacing oil video second time, no comments> As you have seen the thief zone caused early water breakthrough and channeling of the water. Page 4 Homogeneous Model with 5 Darcy Thief Grid Size: I ac x 2 ft, Dimensions: 42xlx50 October 30,2001 Water Movement Exhibit 5 <Testimony just before running the water displacing gas "video"> Now let's take a look at the same simulation, however this time the model will be loaded with gas instead of oil. So, this simulation is of water displacing gas. Keep in mind the thief zone is in the middle of the model. <Run water displacing gas video> <Testimony during water displacing gas "video" at the end> This is the end of the run. Let me run this one more time. <Run water displacing gas video second time, no comments> As you have seen, even a high permeability thief like this one is significantly dampened by such a favorable displacement process. 5 Comparison of Displacements in Thief Model .. Water Displacing Oil .. Water Displacing Gas - Thief causes Channeling - Effect of Thief Dampened M>t>ot_',,,,,,.~'j....t',to_~'f:OJ!' October 30,2001 MItØ'llW'._o'O_._'":þ$.8! Water Movement Exhibit 6 I have one comparison slide to summarize what we just viewed. The water displacing oil case shows the water moving significantly faster through the high penneability channel leading to early water breakthrough. In the water displacing gas case, the thief has little effect on the flood front, such that the displacement is nearly piston-like. The water doesn't channel through the gas. This is because the gas is approximately 100 times more mobile than the water. As a result, this displacement process dampens the effect of geologically reasonable variations in reservoir penneability. Page 6 a to to producers are areas. the 11/1/2010 1 GCWI Injectors October 30,2001 Water Movement Exhibit 8 This shows the continued growth ofthe water at 2010, or after approximately 8 years of injection. Page 8 1111120151 GCWI Injectors October 30,2001 Water Movement Exhibit 9 This shows the continued growth ofthe water at 2015, which is approximately 13 years of injection. Page 9 11/1/2020 I GCWI Injectors And 2020, which is approximately 18 years of injection. Page 10 GCWI Injectors October 30,2001 Water Movement Exhibit 11 And this is 2031. Water injection was stopped in 2022. Due to it's low mobility the water moves very little between 2022 and 2031. So, a picture at 2031 is almost the same as a picture at 2022. As you can see water eventually reaches the closest gas injectors and some oil producers at drill sites 4, 11, and 18. Let me show you the effect on these three areas on the next three slides. Page 11 Minimal Impact on Gas Injection 8.0 e IJ.. 7.0 0 IQ G) 6.0 .. (\ n:: 5.0 !: 4.0 0 .- ... y 3.0 @ ..... 2.0 !: If¡ 1.0 (\ CD 0.0 2000 2005 2010 October 30,2001 with GCWI 2015 2020 2025 2030 Water Movement Exhibit 12 First, GCWI has a small impact on gas injection. It occurs primarily late in field life when the gas oil ratios are higher. This impact is incorporated into the benefits analysis. Page 12 Q 600 11II I 550 is 500 i u 450 October 30, 2001 GCWI Complements Waterflood Area DS4 <IDS 0811 Cum 011 Production 650 400 20002005 2010 2015 2020 2025 2œ0 2035 Water Movement Exhibit 13 Second, this plot shows cumulative oil production for drill sites 4 and 11 with and without GCWI. As you can see, oil recovery is slightly higher with GCWI. is because the additional water from GCWI drives updip oil towards the drill site 4 and 11 producers. Page 13 GCWI Preserves Gravity Drainage Recovery DS18 Cum Oil PrøWction 160 140 o I:I! 120 I 100 80 Õ 60 § 40 u 20 o 2000 2005 2010 2015 2020 2025 2030 2035 October 30, 2001 Water Movement Exhibit 14 And finally this plot shows cumulative oil production for drill site 18 with and without GCWI. Oil recovery is slightly higher with GCWI because the water limits encroachment and displaces some updip oil. 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Water Displadng Gas in a X-Section with 5 Darcy Streak _"'iW".,...~....._._-'I1 e Water Displacing Gas in a X-Section with 5 Darcy Streak _ot..........,,_.....·_., Water Displacing Gas in a X-Section with 5 Darcy Streak _".....,_"..........-»0.0' e Water Displacing Gas ín a X-Section with 5 Darcy Streak ....".........."............,..., 4 e e . Prudhoe Bay GCWI AOGCC Hearing October 30, 2001 5. Major Gas Sale Relationship Lynn W. Schnell ExxonMobil Production Co. October 30. 2001 MGS Relationship Exhibit 1 . Good morning. My name is Lynn W. Schnell. I'd now like to be sworn and qualified as an expert witness. [Administration of Oath) I've been employed by ExxonMobil Production Company and its predecessors since graduating from Washington State University in 1965 with a BSEE. I have been involved with the development and reservoir management of the Prudhoe Bay Field almost continuously since June, 1968. [Acceptance as Expert Witness) I will now testify about the relationship of a major gas sale to the Gas Cap Water Injection Project. . Page 1 e e . GCWllnteraction with Major Gas Sales · Focus is on the impact of ¡.. Gas sales on GCWI recovery benefits ¡.. GCWI on gas recovery · Reservoir pressure maintained at higher level · MGS reduces GCWI oil recovery estimate · Gas recovery is preserved October 30, 2001 MGS Relationship Exhibit 2 . The purpose of this presentation is to address the interaction of the Gas Cap Water Injection project with a potential major gas sale. The primary focus will be on how a gas sale would impact the estimated benefits of the project. The secondary focus will be on how gas cap water injection is expected to impact ultimate gas recovery. Since the timing and rate of a gas sale have yet to be determined, a gas sale will be addressed broadly. As such I will focus on the mechanisms involved, and will not try to quantify these factors. In general, the water injection project will maintain reservoir pressure at a higher level under any currently foreseeable gas sales scenario. A gas sale will reduce the incremental oil recovery from gas cap water injection. This will be shown and explained. Finally, the impact of the project on ultimate gas recovery will be addressed. I will show that gas recovery potential is virtually unchanged when compared to a no gas cap water injection case. . Page 2 Higher Pressure Maintained by GCWI 5000 1000 ,ii ~ 3000 2! ::¡ <II ~ 2000 0.. o 2010 2020 2030 2040 2050 Year October 30. 2001 MGS Relationship Exhibit 3 This chart represents the average reservoir pressure as predícted by the BP fun field model. It shows that gas cap water injection results in a uniformly higher reservoir pressure with a major gas sales; this case, approximately 140 psi. The blue dashed curve shows the pressure declining at until a 4 Bcf/d gas sale in 2008, at which time the pressure drops at about 135 psi/year through 2025. The rate of pressure decline is proportional to the gas sales decline moderates later years as gas sale rate pressure depletion. The solid green same gas sales scenario; but with gas cap water injection. reservoir pressure remains essentially constant until the start in 2008. . At that time the pressure parallels the case without relationship is characteristic of other gas sales rates and The the oil recovery depicted in the next chart. the project means that even with a will operate more efficiently. GCWI Recovery Reduced by MGS 250 CD ~ 200 . è:' ~ 150 o u &!. ¡¡¡ 1 00 ë CD E I!! 50 u .E o 2000 2005 2010 2015 2020 2025 2030 October 30, 2001 MGS Relationship Exhibit 4 This graph shows the cumulative incremental oil recovery due to gas cap through 2030. While the gas sale reduces the recovery, the incremental significant; and the project remains viable. The upper dashed blue curve represents the 200 MMB shown in Bharat presentation. The solid green curve represents the 135 MMb incremental oil recovery with a 4 Bcf/d gas sale starting in 2008. This reduction in recovery is caused by First, with a major volume meet the gas sale oil is vaporization cap water injection. Secondly, the ability of the injected gas to vaporize the oil it contacts lower reservoir pressure. Finally,with the lower pressure due to a gas sale the oil becomes more viscous. It drains more slowly and With this MGS impacts GCWI, I would now like to address how gas cap water injection would impact a major gas sale. mechanisms. available for injection is reduced in order to by injected gas. This reduces Gas Recov~ry Maintained with GCWI 30000 ~ 25000 I~ v, 20000 .i ~ 15000 tlI «I C) 10000 E c3 5000 o 2000 2010 2020 2030 2040 2050 October 30. 2001 MGS Relationship Exhibit 5 This chart is a plot of cumulative gas sales with time through 2050 as forecasted by the BP full field model. It shows that ultimate gas recovery win be essentially unchanged by gas cap water injection. The primary reason for this is that similar abandonment pressures can be realized with and without the project. This requires a large water free area from which to produce the gas. During the final stages of field life after the recoverable liquids have been produced, the operating objective will be to maximize gas recovery. This is accomplished by "blowing down" the reservoir pressure with the remaining wells. These will likely be former oil wells that have been recompleted the expanded and original gas cap. As you know there are many candidate wens in the gravity drainage area. Gas wen producing capacity is a strong function of both reservoir pressure and water production. Without water a gas well can flow at economic rates with relatively low reservoir pressure. However, is produced along with the a much higher reservoir pressure is needed to sustain production. Consequently a large water free area must remain in the reservoir late in field life. As shown on the next slide the water injected into the cap remains highly localized. Page 5 Water Free Area Remains for Slowdown October 30. 2001 MGS Relationship Exhib.it 6 This chart shows the water and hydrocarbon saturation predicted by the BP full field model in the high permeability Zone 3 at 2035. Blue represents high water saturation; red represents the high gas saturation in the original gas cap. The orange area is where gravity drainage and vaporization have been responsible for oil recovery. The water injected into the gas cap is readily apparent. water remains relatively close to where it was injected because of its low mobility compared to the gas it displaces. The blue area around the lower edge is the aquifer. Although not apparent in this chart, most ofthe red and orange been penetrated by many wells on approximately 80 acre spacing. It through these wells that the bulk of the late life gas reserves will be produced. Within the red and orange area the gas recovery mechanism will be simple pressure depletion. Because of this large water free area, gas cap water injection will not materially impact the final reservoir pressure as shown on the next chart. Similar Late Life Pressures 5000 1000 4000 ¡¡¡ ';- 3000" :!! :::¡ If¡ ~ 2000 0... o 2000 2010 2020 2030 Year October 30, 2001 MGS Relationship Exhibit 7 This is the same chart shown earlier. Notice how close the pressures are the end. The next chart will illustrate how reservoir pressure depletion impacts gas recovery. Page 7 'Gas Recovery by Pressure Depletion 100% 90% CI. 80% ¡:; o 70% "¡ft . 60% ~ 50% ~ _ 40% ~ 30% :3 CJ 20% 10% 0% Reservoir Pressure - psi October 30, 2001 MGS Relationship Exhibit 8 This chart shows gas recovery by pressure depletion as a percent of original gas in Gas recovery varies inversely with pressure. Notice that recovery exceeds 80% when the pressure is reduced from the original 4400 psi to about 850 psi. This is representative of what happens in the absence of water in the original gas cap and throughout much of the gravity drainage area. The next chart shows what happens when water is injected into the gas cap. PageS Gas Recovery by Displacement 100% 90% 0. 80% ¡; 0 70% '#- . 60% ~ 50% <I> ~ 40% ~ 30% '" «I 20% CI 10% 0% 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 Reservoir Pressure· psi October 30, 2001 MGS Relationship Exhibit 9 The solid green lìne in this chart depicts gas recovery the case has been injected into the gas cap after the reservoir pressure has dropped from the original4400 psi to 3500 psi. For reference the pressure depletion ITom the previous chart is also shown. When water is injected it displaces most In this example, saturation reduced from an original 90% PV to a trapped saturationof2~% PV. Just as water is unable to displace the oil a waterflood, it is also unable to displace all the in the gas cap. The solid green curve shows that prior to injection, about original gas volume had been recovered (expanded down drainage area) by depletion. When water is removed from the subsequently again becomes Notice that at a the water invaded area is 90%. realize depletion alone pressure has to be blown down to 500 psi. Thus it can recovery ITom the gas cap where water is injected may exceed that from the rest of the gas cap and gravity drainage area. Now to summarize.. e e . Interactions with Major Gas Sales · GCWI yields higher pressure throughout remaining oil producing life regardless of MGS rate & timing · MGS slightly reduces GCWI incremental oil recovery » Less gas cycled " Lower vaporization efficiency " Less Gravity Drainage · Gas recovery is virtually unchanged " Water free GD area is preserved for final blowdown » Abandonment pressure only slightly increased October 30, 2001 MGS Relationship Exhibit 10 . In conclusion, gas cap water injection has been shown to yield higher reservoir pressure with and without a major gas sale. Any water injected serves to reduce total net voidage and thus maintain a higher pressure. The gas sale does, however, reduce the incremental oil recovery due to gas cap water injection for three reasons. First it reduces the volume of vaporized oil because less gas is injected into the gas cap. Second, the ability of the injected gas to vaporize residual oil is somewhat lower at the lower reservoir pressure associated with the gas sale. Finally, gravity drainage is reduced. Gas recovery will be virtually unchanged by gas cap water injection. This is because the large water free area that remains during late field life enables effective pressure depletion with only a slightly higher final pressure. Also it is likely the gas recovery from the water invaded area will be somewhat increased. This concludes my prepared testimony. Are there any questions? Thank you. Next Jerry Brady will describe the surveillance program. . Page 10 e e · Prudhoe Bay GCWI AOGCC Hearing October 30, 2001 6. Surveillance Jerry Brady BPX (Alaska) Inc. October 30, 2001 Surveillance Exhibit 1 · Good morning. My name is Jerry Brady. I'd now like to be sworn and qualified as an expert witness. [Administration of Oath] I am a Staff Engineer for BP Alaska currently working as a Production Engineer on the Gas Cap Water Injection Project. I received a Bachelor of Science Degree in Petroleum Engineering from Montana Tech in 1980. I began my career with ARC a International in 1981 and moved to Alaska in 1984 for ARCa Alaska. Since then I have worked on a variety of Production Engineering projects in Alaska. I began working on the GCWI surveillance plan in 1993. [Acceptance as Expert Witness] I will now testify about surveillance for the Gas Cap Water Injection Project. · Page 1 e e · Objectives of Surveillance Plan · Injection Wells - Injection Conformance · Water Movement - General Water Movement - Leading Edge Detection · Reservoir Pressure Monitoring - Current Reporting Requirements October 30, 2001 Surveillance Exhibit 2 · Lets begin with the objectives of the GCWI surveillance plan. The objectives are to monitor project performance and ensure that the injection project is performing as expected. Critical elements of the plan are the monitoring of injection well conformance, water movement and reservoir pressure. Injection well monitoring ensures that the water injection is contained in the desired reservoir interval. Water movement monitoring is assuring that the water moves in the reservoir as expected. General waterflood movement will be monitored using 4-D surface gravity and downhole pulsed neutron logs in offset wells. The leading edge of the waterflood will be detected primarily with pulsed neutron logs. Reservoir pressure will be obtained from the current pressure reporting requirements for the Prudhoe Bay oil pool. · Page 2 e e · GCWI Surveillance Plan !.ojection Wells · Surface Injection Measurements - Temperature - Pressure - Rate · Downhole Measurements - Temperature, pressure & spinner surveys · Injection profile analysis · Hydraulics (correct surface calculations) Pressure Falloffs October 30,2001 Surveillance Exhibit 3 · The first component of the GCWI surveillance plan is water injection well monitoring. The injection wells will be monitored with surface measured temperature, pressure and injection rate. These measurements will be similar to other injection wells within the Prudhoe Bay pool. With these measurements it is possible to monitor injection characteristics, particularly changes in the injectivity indices. The injectivity indices provide direct evidence of changes in well performance. Downhole measurements will provide confirmation of the surface measurements and will also help describe reservoir properties and hydraulic performance. Downhole temperature logs will provide verification of injection conformance and confirm that fracture height growth is confined within the Ivishak. Downhole pressure measurements will be used to determine tubular pressure drops and hydraulic performance. Pressure falloff tests will be undertaken to determine reservoir properties and wellbore skin. · Page 3 e e · GCWI Surveillance Plan Water Movement · General Waterflood Movement - Pulsed Neutron Logging of wells · Downhole zonal information · Regional water movement - 4-D surface gravity survey · Regional water movement October 30, 2001 Surveillance Exhibit 4 · Water movement is monitored to make sure it remains in zone and it moves as expected. Two techniques will be utilized to provide information on the water movement. They are pulsed neutron logging in offset wells and 4D surface gravity survey. The pulsed neutron logging will provide the downhole information on which zones are being flooded along with regional information on where the water is moving. 4D gravity will augment the pulsed neutron logging by providing general water movement information. · Page 4 Area of Pulsed Neutron Logging October 30,2001 Surveillance Exhibit 5 The next major component of the surveillance plan is the pulsed neutron logging. This slide highlights the approximate area of interest for the early time pulsed neutron logging program. The light blue region surrounded by the heavy dashed line is the area of primary interest. In the center of the blue region is a smaller dashed line that shows the proposed location ofthe water injection wells. The wells to be logged will be selected from the suite of wells shown as green dots. These wells are primarily Lisburne producing wells, none of which have known cement problems that would prevent confinement of injection to the Ivishak. Pulsed neutron logs, specifically the RST logs, were chosen because they can be run in Lisburne wells completed with 2 7/8 inch tubing. Also, they can be run in two modes to collect data for discerning a major change in fluids (sigma & Carbon/Oxygen). The RSTs will help locate the leading edge of the waterflood. It will also provide data in determining the regional waterflood coverage. 4..D Gravit Station Grid o. o'M!lii¡~t --===- ·t· eN m .. ....... iJU· . ... _t4 ~ ~-'~ ... --.'··1""""~-----r"""""~·-·"~·C~."·i,~nn,--,-_--_··--c1"".:C--·'--··'=-".~,.~.._m.'~~~r~.--r'.-~. .tlœfI!).....~-.~ IìIIþ- 4IIOIiQO.... 1óOIII» 'IœfO/I '1fIIØO& 1flIII» 12ØIÞ ~ ~ EeoiI!Iø(j) October 30.2001 Surveillance Exhibit 6 The 4D Gravity technique utilizes very sensitive surface gravity measurements taken periodically. The method measures small changes in gravity as the low density gas is replaced with the higher density water. Baseline measurements will be taken prior to water injection. Subsequent measurements will be made at discrete time intervals and compared to the baseline measurements. An increase in the density of the fluids in the gas cap indicates the presence of water. This slide shows the area for gravity monitoring which covers the area of expected water movement. The gravity stations are shown by red dots. The center portion ofthe gravity grid is the most important region and it is setup on a 2500 ft grid spacing. The center is also overlain with a few more closely spaced gravity lines to improve the lateral sensitivity of the gravity processing. Finally, the outer portion ofthe gravity grid is setup on a station spacing of 5000 ft. The 4D Gravity technique will enable us to map general water movement, detennine an average watert100d front, and provide a means to perfonn a mass balance ofthe injected water. The major limitations ofthe 4D gravity technique is that it cannot detect horizontal or vertical flood fronts and it cannot provide any downhole zonal infonnation. Page 6 e e · GCWI Surveillance Plan Summary 1. Injection wells will be monitored as other water injection wells within the Prudhoe Bay pool. 2. PNLs in existing wells will provide downhole and regional data on the water movement. 3. 4-0 gravity will provide a general view of water movement. 4. Reservoir pressure monitoring will be done according to Prudhoe Bay pool rules. October 30,2001 Surveillance Exhibit 7 · In summary, The major components of the GCWI surveillance plan are: 1) Injection wells will be monitored as other water injection wells within the Prudhoe Bay pool. 2) PNLs in existing wells will provide downhole and regional data on the water movement. 3) 4-D gravity will provide a general view of water movement. 4) Reservoir pressure monitoring will be done according to Prudhoe Bay pool rules. This concludes my prepared testimony. Are there any questions? Thank you. Next Perry Richmond will provide a closing statement summarizing requested changes to Conservation Order 341 C. · Page 7 e e . Prudhoe Bay GCWI AOGCC Hearing October 30, 2001 7. Conclusion Perry Richmond BPX (Alaska) Inc. October 30. 2001 Conclusion Exhibit I . The presenters have provided summary exhibits at the end of each section of testimony. We hope the Commission finds this helpful when deriving findings and conclusions for the Gas Cap Water Injection project. . Page 1 . . . e e Conservation Order 341 C Reauest: Rule 12 paragraph (d) - revoke requirement to investigate and report pressure mitigation options Paragraph (c) - modify the pressure differential between minimum miscibility pressure and reservoir pressure from 250psi to 100psi. Consider: Rule 11 add requirement to report on surveillance of GCWI October 3D, 200l Conclusion Exhibit 2 In closing, I would like to reference our letter submitted September 21, 2001 which contains our requested pool rule changes to Conservation Order 341 C. I will summarize these changes here. Paragraph (d) of Rule 12 provides that "The Operators are directed to continue to investigate options to mitigate pressure decline and to provide an annual report to the Commission". With the implementation of Gas Cap Water Injection, BP and the other owners should not be directed to continue investigating options to mitigate pressure decline and provide an annual report to the Commission on such activity. Therefore, we request that the Commission revoke paragraph (d) of Rule 12. We also request modification of Paragraph (c) in Rule 12 which currently provides that the Operator maintain a pressure differential of at least 250 psi between the minimum miscibility pressure of the miscible injectant and the prevailing reservoir pressure. Recognizing that GCWI will mitigate pressure decline, a more appropriate pressure differential of 100 psi is requested based on thermodynamic uncertainty only. This change will allow BP to better optimize both the composition and volume of the miscible injectant. Finally, the Commission may wish to consider modifying Rule 11, which describes the Prudhoe Oil Pool surveillance report, to include the results of Gas Cap Water Injection surveillance. This concludes our testimony on the Gas Cap Water Injection project. Thank You. Page 2 GCWI testimony . . Subject: GCWI testimony Date: Thu, 01 Nov 2001 16:21:42 -0900 From: Jane Williamson <Jane_ Williamson@admin.state.ak.us> Organization: Alaska Oil & Gas Conservation Commission To: Daniel T Seamount JR <dan_seamount@admin.state.ak.us>, Camille 0 Taylor <cammy _ taylor@admin.state.ak.us>, John D Hartz <jack_hartz@admin.state.ak.us>, Robert P Crandall <bob _ crandall@admin.state.ak.us>, Robert E Mintz <robert mintz@law.state.ak.us>, Stephen F Davies <steve _ davies@admin.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Julie M Heusser <julie_heusser@admin.state.ak.us>, Jody J Colombie <jody_colombie@admin.state.ak.us> Perry brought by the CD containing their testimony, hard copies of the 8 1/2 x 11 slides we requested, a desk size map showing the GCWI surveillance area. They also brought plots which show pressure over time by area (23 separate areas of the field) with and without GCWI. In addition, Perry and Bahradt hopefully will provide us with slices of the model (showing water saturations) which will help answer questions concerning water movement after GCWI is shut-in and impact upon the gravity drainage area. Jack and I will be discussing with Perry and Bahradt data and information which could better alleviate concerns as to loss of gas cap liquids, particularly in the eastern area, and to fill in gaps, if any, on information in that area. Additionally, we will discuss further with them the request to lower the MMP to 100 psi above the prevailing pressure, to better understand the impact (may free up additional MI for injection to other areas). The individual exhibits and testimony are provided on the M drive. Steve Davies copied the pressure plots to the M drive as well. The are in //MI/gcwi testimony/ The slides are in JPEG format, and I cant directly read, as I don't have comparable software (might be a discussion item). I will later put in powerpoint (not fully understanding why they couldn't use that but there was some legal reason). However, if you also don't have the appropriate software, you can open power point, click insert, picture, from file, then point to the M drive, gcwi testimony, and the particular slide you want to view. Further update after tomorrow's meeting. Jane 1 of 1 11/2/01 5:28 AM e " STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION GAS CAP WATER INJECTION PROJECT NAME - AFFILIATION October 30. 2001 9:00 am ADDRESS/PHONE NUMBER TESTIFY (Yes or No) (PLEASE PRINT) Fe.-rr'j R~c.. ~MD)"'" BP S 3()f (,'yQ. ~"ì~ Pr. S¡'f-~}f<¿ fer 1írè~Nel>ðY1 PNA ~13MC-(¿;q,e dJ.lg-ø36à8- N(') ~ë:.A.~'f ß~Að1-'ßP /f}(.,e/ ~~ lJl(. .jY6"1Y9? ~ 5" B\--(A.-I2-Ir1" d:~A-véU- ßP lc>~a. \.-A.çA-'tG..1.'tE... Cl~, '3~4.CI&4.3 't~ 516,J,; CBAI.%..l ~:f:{;;~ U\ j?nsj 1Q~\o~ 6.1> 4"'-"'<- W,{ (; t>.... ~01 ('C\~ N'\~ C>9\~C ~--r - h oJ'tn1 .:J 0 ~ .sol') S4-'W\ De1-iN l ~ di ~~~~// CJ~ !~f2.. \'-(".3\ E:"s~cr"y c";;-c..\o. . ~cJn"~1:. C\CfS)<c::o . "BY 56 ~ ~ '5'2~ { ~;~7~ 7 - 6 -C( \.( ~ 51-tt - tfJ 5"' ) c:¡ 5 - /~ 2G:, ') ?o- 'O(Cf 2C, 3-37o~ 'BP s-u -f~ '1s- ,40(;{'/ 77i ~/z..-b ;[b6¡ CC- 1C¡ -.; -I 'Z- ¿ L-- Y<..s µi) ~~ b ý\O ,#¿> Po )../ö /Úð Nè .~ ~ . . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION GAS CAP WATER INJECTION PROJECT October 30. 20019:00 am NAME - AFFILIATION ADDRESSIPHONE NUMBER TESTIFY (Yes or No) (PLEASE PRINT\ C5 1--€.- t/ <- -1Y- vies AO()Cé~ 7Q3-/ZZ4 /\~ *3 e e October 18,2001 To: Jack Hartz Alaska Oil and Gas Conservation Commission From: Frank Blaskovich Blaskovich Services, Inc. Re: GCWI Questions I have reviewed the GCWI presentation materials provided at our 9/19 meeting with the WIOs. This is a wealth of good information and has really helped me to understand the reasoning behind starting a water injection project in the gas cap at Prudhoe Bay. The Owners have done a great deal of work over the years and the model results seem consistent in their support of the project. In fact, this has made my job somewhat harder. I have tried to look beyond the WIO materials to find anything that hasn't been addressed that might still be a factor in the decision to go ahead. The following is a small set of questions that emerged from my investigations. I am confident that the Owners will be able to quickly address these issues and that their omission has either been an oversight or because they were not considered important. As always, thanks for your patience and cooperation. Very best regards, Frank Blaskovich Vice-President Blaskovich Services, Inc. e e GCWI Project Review Questions The following is a series of questions derived from studying the 9/18/01 GCWI Project Meeting notes and other documents. They are designed to clarify a few issues that surfaced after the meeting and any remaining risk factors not fully discussed to date. Wettability During the MIINGL hearings in 1995, Arco's Dr. SimonI listed several reasons for concern if water was inj ected in the gas cap. One of those was that the gas cap rock tends to be oil-wet. Oil wettability at low water saturations, such as found in the Prudhoe Bay gas cap, was also discussed by Jerauld and Rathmell2 in 1997. In an oil reservoir, it is normally unadvisable to inject water if the rock is oil-wet, because of high residual saturations. What would happen in the Prudhoe Bay gas cap with its relict oil saturation likely to fill the smaller pores? Has the relict saturation in the cap been modeled as a residual oil saturation to water displacement? Does some of the retrograde remain behind the water front as part of the residual saturation? Has this issue been considered or addressed as a risk factor? Water Movement After examining the model water saturation maps and profiles provided, it seems clear that water continues to migrate downdip after water injection stops in 2020. I assume that this is due to a combination of the natural gravity forces and the flow field created by the continuing movement of fluids from the updip gas injectors to the downdip oil producers. I understand your plans for surveillance and think they have merit. However, what are your plans for controlling the water movement? It seems that the water will not stay in place just by shutting in the water injection. Based on recent estimates3, Prudhoe Bay could still be producing nearly 200,000 stbld by 2030 and I suspect most of it will be from the gravity drainage area. Are these reserves at risk due to invasion? Do any model results show this invasion of the oil column? Or do they indicate that the water gets to the oil column so late that it doesn't appreciably impact oil recovery? Trapped Gas Recovery I understand that all trapped gas is now expected to be recoverable during blowdown. Virtually all of this gas can be remobilized according to recent lab experiments. (A paper by Ancell4 also supports this argument, although that process involved producing at high water-cuts.) This appears to be part of your justification for claiming that no gas reserves will be lost due to the GCWI project. Where will this gas be produced? Will GCWI injectors be turned around or will this gas migrate over several miles to the NGI/WGI or AGI injectors? Could it somehow move downdip to be produced from the oil column? Well Locations It would have been better to show more results from the final East Dock Water Injection Case rather than the older Apex Water Injection Case. The latter has a different relationship with the NGI/WGI gas injectors and appears to water out several of these wells - based on materials presented on 9/18/01. High volume gas injection (~5 mmrb/d) directly downdip from the apex water injection probably tends to slow down and stabilize e e . the movement of the water front. Water literally has to push past this gas somehow to get further downdip. In the East Dock case, this seems much less likely to happen. Water should have an easier time moving downdip and may even be pushed along by the western and apex gas injection. I expected to see the water front being pushed from a radial into a more elongated front (north to south) by the presence of the gas injection. This could be a good thing because it may prevent the water from reaching the gravity drainage area in the western half of the field. However, it may result in water reaching the oil column in the eastern half of the field more quickly. Are there any simulation results that show this? Model Calibration and Gas Sweep Efficiency While all of your model studies tend to show similar results, I am still concerned about the accuracy of predictions based on very limited data. It appears that there is little if any hard data to define the rock or fluid properties in the East Dock area at this time. Less is known about it than any other part of the field and now we are planning to introduce an entirely new, untested process as well. How confident are you that the gas liquids (condensate and relict oil) have been efficiently swept in the eastern gas cap? Are there any measurements that you have matched with the models to confirm good sweep efficiency? From your model work, is it possible to see a simulator map (from 3D-View) of current gas cap liquid saturations and an idea of current gas yields? Adding a few "dummy gas producers" around the gas cap, running the PBU FFM for one timestep at the end of history, and tabulating the results could generate these yields. My understanding is that you have not taken this possibility into account ill your gas cap liquids calculations. 1 MIINGL Hearing Minutes, May 1995, p. 645 2 Jerauld, G.R. and Rathmell, J.J.: "Wettability and Relative Permeability of Prudhoe Bay: A Case Study of Mixed-Wet Reservoirs, SPERE, February 1997. 3 2000 Annual Report, Department of Natural Resources, Division of Oil and Gas. 4 Ancell, K.L. and Trousil, P.M.: "Remobilization of Natural Gas Trapped by Encroaching Water", SPE 20753 presented at the 65th Annual SPE Technical Conference and Exhibition, New Orleans, La., September 1990. [Fwd: GCWI Questions] e -- Subject: [Fwd: GCWI Questions] Date: Tue, 23 Oct 2001 17:33:47 -0800 From: Jack Hartz <jack_hartz@admin.state.ak.us> Organization: AOGCC To: Jody Colombie <jody _ colombie@admin.state.ak.us> Jody, Could you please print the email and attached document and add to the record file for the BPX - Prudhoe Bay Oil Pool - Modification 341C. Thanks, Jack t., ,····..··.··,~"~"wmum~.m~~' ,"-',-. . .~,~,~,~,,~,~""" '" ,wr' _, ',,,_.N~,,~,,,,,,,_.m·H "'_'.. ,,_, _~~~@"..""',,. "". ,~...~~~~'mm.m@~~mumm'ijumw.@~~" ""'" mmm""''''''_~~~mm·,,'··m·.· Subject: GCWI Questions Date: Tue, 23 Oct 2001 17:08:37 -0800 From: Jack Hartz <jack_hartz@admin.state.ak.us> Organization: AOGCC To: "Richmond, Perry" <richmopl@bp.com> Perry, First - Frank Blaskovich forwarded several questions to us based on the review of 9/18/01. I have reviewed the questions and think they are appropriate for us to consider in the context of the project. He has taken care to set the question is a context that helps explain his thinking and what he is after. We'd appreciate if you can address the questions during the course of the hearing. Let me know if there are any problems. Second - I mentioned to the Commission that testimony may not be ready to pre file before the hearing. In that case, you'd be expected to present the testimony so the Commissioners and all could hear it and formulate questions. If the testimony is timely pre filed, then a summary is ok. The pre filing has to give the Commission and staff enough time to review the testimony and consider it before the hearing. Jack Hartz L_~_..'_m~~~_~~___ ..............,....... _~,._^"~¥_m_.wmmm ,__.·,·@.....w.._...._...._'_mmw,_ '^'.. . .,_......,..._._.,.~.....~......~.."......,.,..~ ,-,.....,.."., .......,.............._.......~..................... .··w"wu··m^·.·.wm_N..."·.'·~~'m_w__mmm.m .__. Name: GCWI Questions.doc ~ GCWI Questions. doc Type: WINWORD File (applicationlmsword) Encoding: base64 Jack Hartz <iack hartz(ll),admin.state.ak.us> Sr. Petroleum Reservoir Engineer Alaska Oil & Gas Conservation Commission lof2 10/24/01 11 :40 AM *2 STATE OF ALASKA ADVERTISING ORDER . NOTICE TO PUBLISHER - INVOICE BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO.WTIFIED AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02214009 AGENCY CONTACT DATE OF A.O. 333 W 7th Ave, Ste 100 o Anchorage, AK 99501 M Jod Colombie PHONE Se tember 28 2001 PCN ¿ Anchorage Daily News POBox 149001 Anchorage, AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement X Legal o Display Account #STOF0330 Advertisement to be published was e-mailed o Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING DATE 2 ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIO 01 02140100 73540 2 3 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM e e Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Prudhoe Oil Pool- Modification to Pool Rules - Conservation Order 341 C By letter dated September 21, 2001, BP Exploration (Alaska), Inc. on behalf of the working interest owners of the Initial Participating Areas of the Prudhoe Bay Unit has applied for a modification of certain Rules of Conservation Order 341 C in conjunction with a proposed project named the Gas Cap Water Injection Project. A person may submit written comments regarding this application no later than 4:30 pm on October 30,2001 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 October 30, 2001 at 9:00 am 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 October 15, 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. If you are a person with a disability who may need a special modification in order to comment or to attend a public hearing, please contact Jody Colombie at 793-1221 before October 23,2001. (ß~ [l¿¿~ ~ Cammy dechsli Taylor Chair Published September 29,200 I ADN AO# 02214009 I certify that on q.a ð?O / a copy of the above was faxed/mailed to eecIp of the fo!JqWing at their add..,. of 18CC11d: ¡¿¡ C ðJ5 ð ¡-zcX' , ~( e e Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 AD# DATE PO ACCOUNT 152107 09/29/2001 02214009 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 dunng all saiâ time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexeâ 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 p . tion is not in excess of the rate charged private indivi ua s. Signed_ / Subscribed and sworn to me before this date: ~~;a~ ;~~1~cl1~fS~~te~;----- Alaska. Third Division. Anchorage, A aska A ( -z" . / -1L-- I\\(!([({ff/r \\\' ,\!,;! £i. /J!<'ì;,. \: ~~":"'" "f,,'·-'" ~ 0:·· .-.=- . ~ .'~~,?~~_~ ~te: 01ARþ.~·o-:;:. , . ~ ___ It.,.,,__ .... . - ...... . (> '""" ~ :. PUSUC : ~ =2 _11!.. , ___ ~. &<1-. __:z:.. . . ì'I:l~ -::. 0,' ;.'. '.. fA.. . "" .' ,"~" ~ ...._;~·:(fCf~V. 'V:'\ ~,;'¥&.". . , , ' . \#.\'"\ /.1 ìVfQ¡¡ Ex¡jteS oJ ", <//}))JJJ})\\ PRICE PER DAY OTHER CHARGES $101.08 $0.00 $0.00 $0.00 $0.00 $101.08 NOI'NI.h.,.pobljcHeOrin!il i STATE OF ALASKA Alaska Oil and Gas Conservalion Commission Re:Prodhoe Oil Pool - Modification 10 Pool ::"1~lè Conser\lQllon Or" A .~Çsulimif i wrIlle .... . .ìtimen.ts re-, gOrdingltl1sbþtjliêáliOn . no laler Ihan 4:30 pm on Oclober 30, 2001 10 Ihe Alaska Oil and Gas Con-' serval;!!n Commission al 1.33J.¡.VlI.,h 71h Avenue, I Soi~eIQO, Anchorage, ..A r~S....k...a...'p... 950.1. In ad dillon, IhecCoriimisslon has len- !att\f~l\' sel a puliUc hear- ' mg orl(Octolier 30, 2001 al I )',...,..... OTHER CHARGES #2 GRAND TOTAL $0.00 $0.00 $0.00 $0.00 $101.08 $0.00 $0.00 $101.08 ~h~~~~~¿~~~~r~~ I Cammissian of 333 West 7lhAvenue. Slme 100. ' Anchorage. Alasko W501. A "ers()nm(\'.~requesl Ihat thetenf~'iv~IY ~1:Iedu.1!td ~i'!9:~ fteld by fHlng a wrrtten re- quest witlt IlteCommis- sion nø ia~ fflcÎII4:30 pm 0",qc~r~5.290J. If a requesltar a hearing is not Iirne1y filed. the Commission wilt con- sider thll issuance of on orÖ!!r Wilho"t ( hearing To learn if tlte Cammis: sian will hold the public ~~I~g. please c.all It you a~:o ~ kith 0 disalillit"i'; .1i)Ìho, ma'y'",eed a speçial modification in ardllr 10 co1Tlfflel11 or tQ attend a pubUc hlaril1g.· r;:;''J:j:~f'W~~M~.. f.~.. ~J: Oêfober·23. 2001. ., ~~::1:.n\' Oechsli Tav'or Pub: SeptemDer' 29/2001 RECEIVED OCT 0 5 2001 Alaska Oil & Gas CO .A h ns, COmmìss¡or nCOrage' STATE OF ALASKA ADVERTISING ORDER .. NOTICE TO PUBLISHER . INVOICE'- BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., IFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COP F ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-02214009 F AGENCY CONTACT DATE OF A.O. AOGCC 333 West ih Avenue, Suite 100 o Pu1chorage,AJ( 99501 M R PHONE DATES ADVERTISEMENT REQUIRED: T o Pu1chorage Daily News POBox 149001 Pu1chorage,AJ( 99514 September 29,2001 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 helshe 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 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 US 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 PO BOX 370 GRAN BURY, TX 76048 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 e 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, LIBRARY/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 PO BOX 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 EXXON MOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 TEXACO INC, R Ewing Clemons POBOX 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 C & R INDUSTRIES, INC." KURT SAL TSGAVER 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, LAND/REGULATORY 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 POBOX 2180 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, WA 98101 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, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 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 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 e JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE,ID 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 PO BOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 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 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 OIL & GAS WILLIAM VAN DYKE 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 ANADARKO, MARK HANLEY 3201 C STREET STE 603 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 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 e 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 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 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 N-I TUBULARS INC, 3301 C Street Ste 209 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 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 UOA/ ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 e GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 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 HDRALASKA INC, MARK DALTON 2525 C ST STE 305 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 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 US BLM AK DIST OFC, GEOLOGIST ARTHUR BANET 949 EAST 36TH AVE STE 308 ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 GORDONJ.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 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 e 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 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, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR ATO 1968 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 A V #13 ANCHORAGE, AK 99513-7599 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 e 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, 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, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 SBRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 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 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 TESORO ALASKA COMPANY, PO BOX 196272 ANCHORAGE, AK 99519 MARATHON OIL CO, LAND BROCK RIDDLE 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, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 RON DOLCHOK 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, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle 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 POBOX 467 NINILCHIK, AK 99639 e OPST AD & 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, PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 M/S LR2-3 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 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 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 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 e PACE, SHEILA DICKSON PO BOX2018 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 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 PO BOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 e KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 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 ~1 ~ .. . . , bp e e o BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561·5111 September 21, 2001 Commissioners Alaska Oil and Gas Conservation Commission 333 W. 7th Ave. Suite 100 Anchorage, Alaska 99501 Re: Prudhoe Oil Pool- Gas Cap Water Injection Project Dear Commission~rs, The Working Interest Owners of the Initial Participating Areas (IP A) of the Prudhoe Bay Unit have studied options to mitigate pressure decline in the Prudhoe Oil Pool. The progress of these studies has been reported annually to the Commission as provided in Rule 12 of Conservation Order 341C. As a culmination of these studies, the IPA Owners recently sanctioned the Gas Cap Water Injection (GCWI) project. This project represents a new element in the depletion strategy of the Prudhoe Oil Pool and should mitigate reservoir pressure decline and improve recovery from the Prudhoe Oil Pool. Facility construction is planned for this winter, followed by start-up of injection in 2Q 2002. BP Exploration (Alaska) Inc. (BPXA), as Operator of the Prudhoe Bay Unit, has previously provided information to the Commission on the GCWI project on an informal basis, and is proceeding with technical reviews for your staff. From these interactions and correspondence received from the Commission, we understand that the Commission intends to publish notice regarding the GCWI project (and schedule a public hearing). In addition, although we believe that GCWI operations will be consistent with Area Injection Order 4C, some modifications to the pool rules for the Prudhoe Oil Pool (Conservation Order 341C) are appropriate. The first section of this letter provides a description of the GCWI project. This is followed by a section that describes certain specific changes to Conservation Order 341 C that would be appropriate in conjunction with the GCWI project. Please consider this letter as an application for revisions to the pool rules to the extent requested herein. .... . e e Gas Cap Water Iniection Proiect Scope of Operations The Gas Cap Water Injection project involves installation of 5 to 7 new injection wells at the East Dock pad. The proposed location of these wells is shown in Attachment 1. The wells are planned to begin injection of seawater in the gas cap of the Ivishak formation in 2Q 2002. The seawater injection rates for these wells are expected to ramp up to approximately 650,000 BWPD. A pipeline to supply the water will be built from the seawater injection line at Flow Station 2 to the East Dock pad as shown in Attachment 2. Injection Wells The gas cap water injection wells will differ from typical injection wells in that the tubing will be larger (7-5/8") to accommodate the high volume of water to be injected. The tubing will be plastic coated to help minimize the friction losses and maximize rate. A representative well completion diagram is shown in Attachment 3. Average design wellhead pressure for these new injection wells is approximately 2700 psi. Maximum injection pressure is expected to be approximately 3100 psi. Surveillance Surveillance will playa key role in monitoring the performance of the injection wells, movement of injected water in the reservoir, and the overall effectiveness of the project. Plans include monitoring surface injection rate, temperature, and pressure on each of the injection wells. Temperature logs and pressure surveys will be run on the injectors as well. Offset wells accessing the Lisburne formation will be used to monitor movement of the water by means of cased hole logs, such as the Reservoir Saturation Tool. 4D Gravity surveys also are planned to periodically monitor the overall movement of injected water. Recovery Benefits The objective of the GCWI project is to mitigate pressure decline and enhance production performance. Increased reservoir pressure should affect recovery in several ways. First, pressure support increases reservoir energy, which improves well inflow performance. Second, pressure maintenance improves oil fluid properties by decreasing viscosity and reducing shrinkage. Third, pressure support allows dilution of MI (higher MMP) increasing MI supply and improving EOR recovery. Finally, vaporization of residual oil by lean injected gas is more efficient at higher pressure. The expected incremental increase in hydrocarbon liquid recovery for this project is estimated to be 150 - 200 million barrels. .. e e Modifications to Conservation Order 341 C Paragraph (d) of Rule 12 of Conservation Order 341C provides that "The operators are directed to continue investigating options to mitigate pressure decline and to provide an annual progress report to the Commission." With implementation of GCWI, BPXA and the other owners should not be directed to continue investigating options to mitigate pressure decline and provide an annual report to the Commission on such activity. Therefore, we request that the Commission revoke paragraph (d) ofRu1e 12. We also request modification of paragraph (c) in Rule 12. Paragraph (c) currently provides: ( c) The operator will maintain a pressure differential of at least 250 psi between the minimum miscibility pressure (MMP) of the MI and the prevailing reservoir pressure at the time of injection. This differential is based on a projected prevailing reservoir pressure decline of no more than 30 psi/year over the life of the project. (Source: C.O. 290, Rule 4) We request (c) be modified as follows: ( c) The operator will maintain a pressure differential of at least 100 psi between the minimum miscibility pressure (MMP) of the MI and the prevailing reservoir pressure at the time of injection. The 250 psi pressure differential is based on the existence of a prevailing reservoir pressure decline of approximately 30 psi/year and thermodynamic uncertainty. Recognizing that GCWI should mitigate pressure decline, a more appropriate pressure differential of 100 psi is requested based on thermodynamic uncertainty only. This change will allow BPXA to better optimize both the composition and volume of miscible injectant. The Commission also may wish to consider modifying Rule 11, which describes the Prudhoe Oil Pool surveillance report, which is submitted annually to the Commission. To accommodate surveillance activity associated with the GCWI project, the Commission could add the following requirement: 6. Results of surveillance of injected water volumes into the gas cap of the pool. We believe that the injection operations associated with the GCWI project can be carried out consistent with provisions of Area Injection Order No. 4C. Therefore, no change in the Order is requested by BPXA . <. e e We hope that this information provides the Commission with enough information to publish the notice and schedule a public hearing. If this is not the case, please contact me at your earliest convenience. We look forward to working with the Commission in moving forward with the GCWI Project. If you have any questions, please give me a call at (907) 345-6811 or email me at RichmoPL@BP.com. Respectfully, æ/!;/ p~hmond Manager, EastJWest Group Greater Prudhoe Bay BP Exploration (Alaska) Inc. Enclosures (3) .. . 1 Attachment 2 Prudhoe Bay '" . F 1.~.D/fJ..b:i11l ?1fIPI6¡fØIV. vcu.ttIi\III.i:k ia .su. t5M Fif.CI Date 8-29-00 3290 3i1S9 3$98 4100 44I!4 9803 5051 524$ 5$86 6415 660$ 6$01 7<131 7674 80$4 8267 $267 $267 $267 $26$ 8270 8297 $56$ $584 ~ Attachment 3 Proposed Generic Design RKSoOu. 3:J 13 3.e·· TA M Peri Collar ^'IOOO· 7" SCSSSV ^'ISOO· 13 s.e", 68# Sulface Csg@_·MO,--4$50· SSTVO 7 5.e" 29.7#, ST-L,lpC hjl!ctic.-. Tû;>ingw/7'·accessories 9-M" x r h¡eeli en Packer OL Unor Hongor I Packer @ ~ _'MO 9-5J8".47Nlrtermeclate Csg~' MO.S210· SS NO 7"2911 h¡eelic.-. Uner@_· MO.8560· SSTVO Rev By CommrmtS LRC Generic C"mpléti"... Prop,,", Pressure Support Initiative WEll: PSI Generic API NO: BP Al8Sk:a Drilling &. WellS;