333 West 7th Avenue, Suite 100

Anchorage Alaska 99501

Re: THE APPLICATION OF BP ) Conservation Order No. 484
for an order to establish pool rules ) Prudhoe Bay Field
for development of the Polaris Oil ) Polaris Oil Pool
Pool, Prudhoe Bay Field, North )
Slope, Alaska ) February 4, 2003


1. By letter dated September 12, 2002, BP Exploration (Alaska), Inc. ("BPXA") in its capacity as Polaris Operator and Unit Operator of the Prudhoe Bay Unit ("PBU") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") to define a proposed Polaris Oil Pool within the PBU and to prescribe rules governing the development and operation of the pool. Concurrently, BPXA requested authorization for water and miscible gas injection to enhance recovery from the Polaris Oil Pool.

2. BPXA provided supplemental information at the Commission's request on October 31, 2002.

3. By letter dated October 31, 2002, BPXA amended its Polaris Oil Pool Rules and Area Injection Order ("AIO") application and withdrew its request for approval of injection of miscible injectant as part of the current Enhanced Oil Recovery project.

4. Notice of a public hearing was published in the Anchorage Daily News on November 8, 2002.

5. The Commission held a public hearing December 9, 2002 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501.

6. On December 18, 2002 and January 22, 2003, BPXA submitted for the public record exhibits containing information previously submitted within confidential exhibits.


1. Proposed Polaris Oil Pool

a. Operator: BPXA is the Operator of the proposed Polaris Oil Pool.

b. Pool Area: The proposed Polaris Oil Pool is totally encompassed within the Prudhoe Bay Field. The area of the Polaris Oil Pool conforms to the Participating Area approved by the Department of Natural Resources, Division of Oil and Gas in the Polaris Participating Area Interim Decision dated May 11, 2001.

c. Wells Drilled: The proposed Polaris Oil Pool was discovered in 1969 with the drilling of the North Kuparuk State 26-12-12 exploratory well. Currently, 64 wells penetrate the Polaris structure, and 59 of those wells are hydrocarbon-bearing. BPXA utilized data from these wells in conjunction with a 3-D seismic survey to delineate the pool limits.

d. Pool Definition: The proposed Polaris Oil Pool is an accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths ("MD") of 5,393 feet and 6,012 feet in the Prudhoe Bay Unit S-200PB1 well. The interval between 5,393 feet and 5,603 feet MD is known as the Ugnu Formation ("Ugnu"). The interval between 5,603 feet and 6,012 feet MD is known as the Schrader Bluff Formation ("Schrader Bluff").

e. Stratigraphy: The proposed Polaris Oil Pool encompasses reservoirs assigned to the Late Cretaceous-aged Schrader Bluff Formation and the Early Tertiary-aged Ugnu Formation. The Schrader Bluff is divided into two stratigraphic intervals that are designated, from deepest to shallowest, the "O-Sands" and the "N-Sands." The overlying Ugnu reservoir intervals proposed as part of the Polaris Oil Pool are informally termed the "M-Sands." The O- and N-Sand intervals were deposited in a marine shoreface and shallow shelf environment. M-Sand sediments were deposited in deltaic and fluvial environments.

The O-Sands are divided into seven separate reservoir intervals that are named, from deepest to shallowest, OBf, OBe, OBd, OBc, OBb, OBa, and OA. Each of these intervals coarsens upward from non-reservoir, laminated muddy siltstone at the base to reservoir quality, thinly bedded sandstone at the top.

The basal portion of the overlying N-Sands interval consists of non-reservoir mudstone and siltstone that forms a regionally extensive hydraulic barrier. This barrier separates lighter, higher quality oil in the O-Sands from heavier, more viscous oil in the overlying N- and M-Sand intervals.

Mudstone and siltstone dominate the lower portion of the N-Sand interval, but the sediments coarsen upward, becoming the fine to medium-grained sand that is prevalent in the upper part of the interval. Three reservoir quality sands exist within the N-Sand interval. They are named, from deepest to shallowest, NC, NB, and NA. These sands are unconsolidated, thin, and generally extensive.

The Ugnu M-Sands are divided into four reservoir intervals named, from deepest to shallowest, MC, MB2, MB1, and MA. The M-Sands interval consists of unconsolidated, clean sands separated by thin, but extensive, intervals of non-reservoir silty mudstone. These silty mudstones act as hydraulic barriers that segregate individual hydrocarbon and water-bearing intervals within the M-Sands. MC sands are separated from the underlying NA sands by a 15- to 25-foot thick silty mudstone, which forms a regional seal. A 15- to 35-foot thick mudstone at the base of the MB2 interval forms a regionally continuous hydraulic barrier. A 9- to 15-foot thick silty mudstone overlies the uppermost MA sand and provides a second, regionally extensive upper seal.

f. Structure: The proposed Polaris Oil Pool lies between approximately 4,800 and 5,300 feet true vertical depth subsea ("TVDss"). The Polaris structural dip ranges up to 4 degrees to the east and northeast, and it is broken by three sets of normal faults: one trending northwest, the second trending north, and the third trending west. These faults divide the structure into a series of reservoir compartments. The northwest- and north-trending faults are primary controls for oil distribution in the W-Pad, S-Pad and M-Pad areas, and they range in vertical displacement up to 200 feet. West-trending faults occur most commonly to the east and northeast in the down-dip portions of the pool, but they do trap oil in the center of the pool, near the Term Well C, near N-Pad, and along the southern margin of the pool. These faults range up to 100' in vertical displacement.

g. Reservoir Compartments: Elements of each of the three major fault sets subdivide the Polaris Oil Pool into reservoir compartments. Six main compartments are currently recognized within the pool. They are, from north to south: S\M-Pad North, S\M-Pad Graben, S\M-Pad South, Horst Block, W-Pad \ Term Well C, and K 22-11-12. These compartments are shown on BPXA's Exhibit VIII-1 "Reservoir Static Pressure Acquisition Area Map" submitted December 18, 2002.

h. Hydrocarbon Distribution: The primary reservoirs of the proposed Polaris Oil Pool lie in the O-Sands. Secondary oil accumulations occur in the N-Sands. The M-Sands also contain significant hydrocarbon accumulations, but oil in the M-Sands is biodegraded, making it dense (12 to 14 degrees API) and viscous.

Oil distribution within the proposed Polaris Oil Pool is complex. Within the O- and N-Sands, ten hydrocarbon-bearing intervals are recognized. A single oil-water contact of -5226' TVDss was logged in the OBd sand in the W-201 well. Estimated oil-water contacts for the remaining intervals are currently placed at the structural spill points for each sand or at the midpoint between the shallowest water-up-to levels and the corresponding deepest oil-down-to levels observed on well logs.

Oil distribution in the M-Sands of the Polaris Oil Pool is better defined because M-Sand oil-water contacts are concentrated in the crestal portions of the structure, where wells are most common. Different apparent oil-water contacts in different M-Sands suggest that each behaves as a separate reservoir unit.

2. Rock and Fluid Properties

a. Porosity/Permeability: Porosity and permeability values were measured by routine core analyses of core plugs from wells S-200PB1 and W-200PB1.

b. Water Saturations: Water saturations were derived from air/brine capillary pressure analyses of cores from wells S-200PB1 and W-200PB1. Relative permeability curves for the Polaris accumulation are based on core experiments and analogy to the nearby Schrader Bluff accumulation at Milne Point.

c. Initial Reservoir Pressure: Average initial reservoir pressure is estimated to be 2180 psi at 5000' TVDss in the S-Pad area and 2240 psi at 5000' TVDss in the W-Pad area. Reservoir temperature is about 98 degrees Fahrenheit at this datum.

d. Fluid PVT Data: Downhole reservoir PVT analyses were conducted on oil recovered from the OBd and OBe sand in well W-200, and from the OBd, OBb, OBa and OA sands in well S-200. Analyses show significant variations in fluid properties both horizontally and vertically. This may reflect varying levels of bio-degradation of the Polaris oil. Actual measurements from the downhole samples are provided on BPXA's Exhibit II-3 "Polaris Fluid Properties".

3. Net Pay and Pool Limits

a. Pool Limits: The limits of the proposed Polaris Oil Pool are defined up-dip to the west and south by fault barriers, and down-dip to the north and east by the intersection of the each reservoir sand with the oil-water contact.

b. Net Pay Methodology: Net pay thicknesses were derived using a petrophysical log model based upon well log and core data. Cut-off values of 6 millidarcies permeability and 55% water saturation were used to determine net pay within the pool.

4. Hydrocarbons in Place

Based upon current well control and stratigraphic analysis, BPXA estimates oil in place in the proposed Polaris Oil Pool (excluding the MB and MA sands) between 350 million and 750 million stock tank barrels of oil ("stbo"). The large variation is primarily due to uncertainty in the oil-water contact and reservoir net pay interval thickness. Of this volume, 300 to 550 million stbo are estimated within the main target intervals, the O-Sands. The oil is undersaturated, containing between 84 and 250 billion standard cubic feet ("scf") of gas in solution (excluding MB and MA-Sands), with 75 to 195 billion scf attributable to expected oil production from the O-Sands.

5. Pilot Well Performance

Pilot production from the proposed Polaris Oil Pool has been attempted in 7 wells: S-200, S-201, S-213, S-216, W-200, W-201, and W-203. Stable production rates have been attained in wells S-200, S-213, W-200, W-201. Conversion to jet pump operation eliminated hydrate formation in wells S-201 and S-216.

Allocated cumulative production through December 2002 is about 1.6 million barrels of oil, 2.1 billion scf of gas, and 211,000 barrels of water. Average Polaris Oil Pool allocated production in December 2002 was 2,714 bopd, 578 bwpd, and 2,725 mscfd. The majority of the production is from W-Pad, with multi-lateral well W-203 contributing 1,206 bopd and, 1,021 mscfd. Bottomhole pressure measurements suggest W-Pad wells are above bubble point pressure (low of 1,733 psi at 5000' TVD in W-200 on 10/29/02).

6. Development Plans

Reservoir models have been used to evaluate primary depletion, waterflood, and other enhanced recovery options for development of the proposed Polaris Oil Pool. Reservoir predictions are based on fine scale, three-dimensional black oil models using Polaris rock and fluid properties from wells S-200 and W-200. The models included the Schrader Bluff Formation O- and N-Sand intervals. The Ugnu M-Sand intervals have not been evaluated. Model studies performed to date within the developed area show about 5 to 10% recovery of OOIP under primary production and about 15 to 30% under waterflood (inclusive of primary).

Initial development of the proposed Polaris Oil Pool is planned in three phases, beginning near the crests of the structure and progressively moving toward the outer margins of the pool.

a. Phase I Development: Phase I development targets the O- and N-Sands in two fault blocks. Development of the S/M-Pad North Block includes a sidetrack of well S-200 and conversion to water injection to support production from well S-201. In the W-Pad \ Term Well-C Block, drilling of W-211 is underway and injection well W-212i is proposed to support existing well W-200. In the K 22-11-12 Block, well W-203, a tri-lateral horizontal producer, is now on production. Additional offset injectors are planned in this area.

b. Future Phases of Development: Phase II development targets down-dip areas with higher water saturation, greater structural complexity and higher-risk. Development of these areas is expected to require 12 to 20 addition producers and 9 to 15 injectors. Phase III may include development of extreme down-dip areas and higher risk fault blocks.

c. Rate Estimate: Peak production rates are expected to be between 12,000 and 15,000 barrels of oil per day ("BOPD"). Waterflood injection rates are estimated to peak between 20,000 and 25,000 barrels of water per day ("BWPD").

d. Well Spacing: BPXA requests a minimum well spacing of 20 acres to allow for flexibility in well placement because of local faulting and reservoir stratigraphy.

e. Reservoir Management Strategy: Expected producer to injection ratio is about 1.5 or 2 to one. Once water injection begins, voidage replacement ratio will be balanced and reservoir pressure will be maintained above the bubble-point.

7. Facilities

Polaris wells will be drilled from existing S, M, and W-Pads. Production will be commingled with PBU Initial Participating Area ("IPA") fluids on the surface and will be processed at PBU Gathering Center 2 ("GC-2") to maximize use of existing IPA infrastructure, minimize environmental impacts, reduce costs, and maximize recovery.

No modifications will be required at GC-2 to process Polaris production. An expansion of existing S-Pad to accommodate additional wells was completed in April 2000. Water for injection will be supplied through exiting IPA injection lines. Existing well test equipment will be utilized at S, M, and W-Pads. Gas lift or jet pumping is the plan for artificial lift.

8. Drilling

Polaris development drilling is designed to utilize drilling procedures, well designs, and casing and cementing programs that conform to Commission regulations. Conductors will be spaced 15' apart.

a. Conductor: A 16" or 20" conductor casing will be set 80 feet to 120 feet below pad level and cemented to surface.

b. Surface Hole: In addition to the requirements of 20 AAC 25.030, surface casing will be set at least 500 feet TVD below the base of the permafrost. Because of the potential for coal and hydrate-related shallow gas, the requirements of 20 AAC 25.035 concerning the use of a diverter system and secondary well control equipment will be met.

c. Well Logs: Measurement while drilling ("MWD") and logging while drilling ("LWD") will typically begin at surface. MWD will include drilling parameters such as direction and inclination. LWD measurements will typically include gamma ray ("GR") and resistivity logs throughout the reservoir section. Openhole electric logs may supplement or replace LWD logging when wellbore conditions allow their use. These openhole logs may include GR, resistivity, density, neutron porosity, and/or other tools.

d. Drilling Fluids: Freshwater low solids, non-dispersed fluids will be used to drill the Schrader Bluff and Ugnu well sections.

e. H2S Precautions: No significant H2S has been detected in any Polaris well drilled to date. However, because planned waterflood operations may generate H2S over the life of the field, H2S gas drilling practices will be followed.

9. Well Completion Design

Horizontal, multi-lateral and conventional wells may be drilled at Polaris. The horizontal well sections may be completed with perforated casing, slotted liner, open-hole section, or a combination. All conventional wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Tubing sizes will vary from 2-3/8" to 5-1/2" depending upon the estimated production and injection rates, and will rely on premium alloys and corrosion inhibitors as needed.

a. Surface Safety Valves: Surface safety valves ("SSV") are included in the wellhead equipment for all Polaris Oil Pool wells.

b. Subsurface Safety Devices: BPXA requested that subsurface safety valves not be included because they are relatively low rate oil wells produced by artificial lift. All wells will be equipped with nipples below the permafrost should the need arise for installation of a storm choke or other downhole flow control device. BPXA intends to install such flow control devices if wells are utilized for gas or miscible gas injection

c. Producers: Polaris producers will be completed in the Polaris Oil Pool only and will comply with AOGCC regulatory specifications. Artificial lift capability is designed into each producing well.

d. Injectors: Injection wells will have surface casing set below the base of the SV3 sand at about 2,800 feet TVD and cemented to surface. The longstring will be cemented from TD to above the highest significant hydrocarbon-bearing interval in the Ugnu section. Injectors may be completed to enable multi-pool injection where appropriate to the Schrader Bluff, Kuparuk, Sag River and Ivishak Formations. Packers will be installed for zonal isolation in multi-pool injectors. Injection valves sized for water injection rate control will be run within mandrels between the packers. Spinner logs will be run to verify injection rates to the separate pools.

e. Stimulation Methods: Fracture stimulation has been used successfully for Polaris producers and may be implemented to mitigate formation damage and stimulate future Polaris wells. Acid or other forms of stimulation may be performed.

10. Reservoir Surveillance Plans

An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 5,000 feet TVDss. An initial static reservoir pressure will be measured on each regular production or injection service well. BPXA proposes to report data and results annually from all relevant reservoir pressure surveys and surveillance logs. A minimum of two pressure surveys will be taken each year in the main area S/M-Pad North and the W-Pad \ Term Well-C reservoir compartments. One reservoir pressure will be taken each year in the remaining compartments when at least one Polaris production well has been completed in the respective compartments. Spinner logs are planned on multi-pool injection well completions to assist in the allocation of flow splits as necessary.

11. Production Allocation

PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 through August 2003, governs satellite production within the Western Operating Area of Prudhoe Bay Unit, including the Polaris Oil Pool. The GC-2 allocation factor is currently applied to adjust total Polaris production.


1. Pool Rules for the development of the Schrader Bluff Formation and the MC Ugnu Sand within the proposed Polaris Oil Pool are appropriate at this time.

2. The Polaris Oil Pool reservoir is compartmentalized and will require irregular spacing to optimize waterflood and recovery. Minimum well spacing of 20 acres is appropriate for efficient development of the pool.

3. The Polaris Oil Pool is in the early stages of development. Phase I development has focused upon determination of reservoir delivery and well operability.

4. Initial development is limited to the O- and N-Sands of the Polaris (Schrader Bluff Formation). No plan has been provided for development of the oil accumulations within the M-Sands (Ugnu Formation).

5. Monitoring of reservoir performance on a regular basis will help ensure proper management of the pool. Annual reports and technical review meetings will keep the Commission apprised of reservoir performance results and will ensure that future development plans promote greater ultimate recovery.

6. Water injection into the O- and N-Sands will preserve reservoir energy and increase ultimate recovery from the pool.

7. Completion of water injectors to allow injection in multiple pools within one wellbore is appropriate so long as isolation of the pools is demonstrated and water injection is allocated between pools.

8. Exception from the gas-oil-ratio limitations of 20 AAC 25.240 is appropriate provided enhanced recovery operations maintain reservoir pressure above the bubble point pressure.

9. PBU Western Satellite Production Metering Plan that governs allocation of production from the Western Operating Area of the PBU is appropriate for development of the Polaris Oil Pool.


1. Pool Name, Classification, and Definition:

The Polaris Pool is classified as an oil pool. This pool is defined as the accumulation of hydrocarbons common to, and correlating with, the interval between 5,544 feet and 6,012 feet measured depth MD in well PBU S-200PB1.

2. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), apply to the following affected area:

Umiat Meridian

Township/Range Lease Sections
T12N-R12E ADL 28256 Sec 22 S/2 S/2 and NE/4 SE/4
  ADL 47448 Sec 23 S/2 NW/4 and SW/4
  ADL 28257 Sec 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26, 35, 36
  ADL 28258 Sec 27, 33 SE/4 SE/4, 34 E/2 W/2 and SW/4 SW/4 and E/2
T12N-R13E ADL 28279 Sec 31 SW/4 NW/4 and SW/4
T11N-R13E ADL 28282 Sec 6 W/2 and SE/4 and S/2 NE/4 and NW/4 NE/4,
Sec 7 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4,
Sec 8 W/2 SW/4
T11N-R12E ADL 28260 Sec 1, 2, 11 W/2 and NW/4 NE/4, 12 N/2 N/2 and SE/4 NE/4
  ADL 28261 Sec 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10
  ADL 28263-1 Sec 15, 16 E/2
  ADL 28263-2 Sec 21 NE/4 NW/4 and NE/4 SE/4 and NE/4,
22 N/2 and N/2 SW/4 and SE/4 SW/4 and SE/4
  ADL 47451 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4
and SE/4 NE/4
  ADL 28264 Sec 26 N/2 N/2
  ADL 47452 Sec 27 NE/4 NE/4

Rule 1 Well Spacing

Spacing units within the pool shall be a minimum of 20 acres. The Polaris Oil Pool shall not be opened in any well closer than 500' to an external boundary where ownership changes.

Rule 2 Casing and Cementing Practices

a. In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75' below the surface.

b. In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' TVD below the base of the permafrost.

Rule 3 Automatic Shut-in Equipment

a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of preventing an uncontrolled flow.

b. All wells must be equipped with landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device. The Commission may require such installation by administrative action.

c. Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the safety valve systems are in proper working condition.

Rule 4 Common Production Facilities and Surface Commingling

Production from the Polaris Oil Pool may be commingled with production from other Prudhoe Bay Field oil pools and tract operations in surface facilities prior to custody transfer.

Commission approval of the Prudhoe Bay Unit Western Satellite Production Metering Plan will expire on August 31, 2003. Continued authorization of metering and allocation procedures will be determined at a hearing to be scheduled no later than July 31, 2003. Until superseded by Commission action, the following rules apply.

a. All Polaris wells must use the GC-2 well allocation factor for oil, gas, and water.

b. All wells must be tested a minimum of once per month. All new Polaris wells must be tested a minimum of two times per month during the first three months of production. The Commission may require more frequent or longer tests if the allocation quality deteriorates.

c. Technical meetings must be held quarterly to review progress of the implementation of the Western Satellite Production Metering Plan.

d. The Operator must submit a monthly report (in printed and electronic form) including well tests and daily allocated production and allocation factors for the Pool.

Rule 5 Reservoir Pressure Monitoring

a. Prior to regular production or injection, an initial pressure survey must be taken in each well.

b. A minimum of two pressure surveys shall be taken each year in the main area S/M-Pad North and the W-Pad \ Term Well-C reservoir compartments, and one reservoir pressure each year in the remaining compartments when at least one Polaris production well has been completed in the respective compartments.

c. The reservoir pressure datum will be 5000' TVDss.

d. Pressure surveys may be stabilized static pressure measurements at bottom-hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests.

e. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the Commission upon request.

f. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule.

Rule 6 Gas-Oil Ratio Exemption

Wells producing from the Polaris Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC 25.240(b) are met.

Rule 7 Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations

Waterflood is required for purposes of pressure maintenance and enhanced oil recovery in strata correlative to PBU well S-200PB1 between the measured depths of 5,603 feet and 6,012 feet (within the Schrader Bluff Formation of the Polaris Oil Pool). Production and injection operations must ensure the reservoir pressure is maintained above 1,633 psi at the datum depth of 5000 feet TVDss.

Rule 8 Multiple Completion of Water Injection Wells

a. Water injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission.

b. Prior to initiation of co-mingled injection, the Commission must approve methods for allocation of injection to the separate pools.

c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report.

d. An approved injection order is required prior to commencement of injection in each pool.

Rule 9 Annual Reservoir Review

An annual report must be filed on or before April 1 of each year. The report must include future development plans, reservoir depletion plans, and surveillance information for the prior calendar year, including:

a. Voidage balance by month of produced, and injected fluids and cumulative status.

b. Reservoir pressure map at datum, summary and analysis of reservoir pressure surveys within the pool.

c. Results and, where appropriate, analysis of production and injection surveys, tracer surveys, observation well surveys, and any other special monitoring.

d. Review of pool production allocation factors and issues over the prior year.

e. Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation studies.

By June 1 of each year, the Operator shall schedule and conduct a technical review meeting with the Commission to discuss the report contents and to review items that may require action within the coming year by the Commission. The Commission may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans.

Rule 10 Administrative Action

Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater.

DONE at Anchorage, Alaska and dated February 4, 2003.

Cammy Oechsli Taylor, Chair
Alaska Oil and Gas Conservation Commission

Daniel T. Seamount, Jr., Commissioner
Alaska Oil and Gas Conservation Commission

Michael L. Bill, P.E., Commissioner
Alaska Oil and Gas Conservation Commission

Conservation Order Index