333 West 7th Avenue, Suite 100

Anchorage Alaska 99501

Re: THE APPLICATION OF BP ) Conservation Order No. 471
for an order to establish pool rules for ) Prudhoe Bay Field
development of the Borealis Oil Pool, ) Borealis Oil Pool
Prudhoe Bay Field, North Slope, )
Alaska )
) May 29, 2002


1. By letter dated February 28, 2002, BP Exploration (Alaska), Inc. ("BPXA") in its capacity as Borealis 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 Borealis Oil Pool within the PBU and to prescribe rules governing the development and operation of the pool. Concurrently, BPXA requested authorization for water injection to enhance recovery from the Borealis Pool.

2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on March 4, 2002.

3. The Commission held a public hearing April 5, 2002 at 9:00 AM, that was continued on April 11, 2002 at 9:00 AM, and on May 2, 2002 at 9:15 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501.

4. BPXA provided revised application for Pool Rules and Area Injection Order on April 11, 2002. BPXA provided supplemental information at the Commission's request on April 10, 2002 and April 23, 2002.

5. The Alaska Department of Revenue provided written comments May 1, 2002.

6. 20 AAC 25.520 authorizes the Commission to issue orders prescribing rules to govern the proposed development and operation of a pool.


1. Proposed Borealis Oil Pool:

a. BPXA is the Operator of the proposed Borealis Oil Pool.

b. The proposed Borealis Oil Pool is totally encompassed within the Prudhoe Bay Field, Prudhoe Bay Unit (PBU), North Slope Alaska. A portion of the proposed Borealis Oil Pool is currently subject to Conservation Order 349-A (Kuparuk River Field, Kuparuk River Oil Pool) and CO 432-A.

c. The proposed Borealis Pool lies within the early Cretaceous-aged Kuparuk River Formation ("Kuparuk"), and is an accumulation of hydrocarbons common to and correlating with the interval between 6534' and 6952' measured depths ("MD") in the West Kuparuk State 1 Well.

2. Geology:

a. Pool Limits: Within the Borealis Pool, oil is trapped by a combination of structural and stratigraphic features. The accumulation is bounded to the southwest by both a series of northwest and north-south trending faults and the oil-water contact. To the north and northwest, increasing fines degrade the primary reservoir sand units to the point of being non-reservoir quality. To the northeast, the pool limit is defined by the down structure intersection of the top of reservoir with the oil-water contact. The southeastern limit of the pool occurs where the reservoir is truncated by the Lower Cretaceous Unconformity ("LCU") and the Kuparuk interval (C-4B/C-4A) Intra-Formational Unconformity. This truncation occurs coincident with the Prudhoe High, a large, basement-involved structural uplift that underlies the Prudhoe Bay Field.

b. Stratigraphy: The Kuparuk was deposited as mid to lower marine shoreface sediments, and is composed of very fine to medium grained quartz-rich sandstone interbedded with siltstone and mudstone. The Kuparuk in the Borealis Pool is stratigraphically complex, and is characterized by multiple unconformities, changes in thickness, changes in sedimentary facies, and local diagenetic cementation. The formation is divided into four stratigraphic intervals that are designated, from oldest to youngest, as the A, B, C and D intervals. The Kuparuk A and C intervals are, in turn, divided into a number of sub-intervals. The Kuparuk C sub-intervals are named, from oldest to youngest, C-1, C-2, C-3A, C-3B, C-4A and C-4B. The Kuparuk C interval contains the primary reservoir sands of the Borealis Pool, with secondary accumulations in the A interval.

At Borealis, reservoir thickness and stratigraphy are affected by the LCU and the C-4B/C-4A Intra-Formational Unconformity. The LCU truncates downward and dips to the east, where it successively removes the Kuparuk B and Kuparuk A intervals. The C-4B/C-4A Intra-Formational Unconformity also truncates downward to the south and east, progressively removing the C-4A through C-1 sub-intervals before merging with the LCU to the east of the Borealis Pool.

c. Structure: The Kuparuk structure within the Borealis Pool boundary is a northwest-to-southeast trending antiform that lies between 6,200 and 6,900 feet true vertical depth subsea ("TVD subsea"). This antiform was created by basement-involved, northwest-southeast trending faults that are intersected by a younger set of north-south striking faults. Both sets of faults are normal and en echelon, which results in a series of intersecting relay ramps.

d. Fluid contacts: At present, there is no evidence of free gas accumulation within the Borealis Pool. Based on well log data and free water level modeling, the oil-water contact in the L Pad wells is approximately 6,625 TVD subsea, and it deepens to the southeast to approximately 6,725 TVD subsea in the V-100 and Z-101 wells. Different modeled oil-water contacts and the presence of numerous faults suggest the Borealis Pool oil accumulation is highly compartmentalized.

3. Rock / Fluid Properties and Oil in Place:

The reservoir description for the Borealis Pool was developed from BPXA's log model, calibrated with core-derived porosity, permeability, lithologic descriptions, X-Ray diffraction and point count data. Routine core analyses used were from well S-16, S-04, S-104, Beechey Point State #1, NWE 1-01, L-101 and NWE 2-01. Supplemental core data were analyzed from wells in the eastern portion of the Kuparuk River Unit ("KRU").

a. Porosity and permeability: Model layer porosities range from 18 to 22%. Average permeabilities range from a low of 5 md to 216 md. Single plug kv/kh ratios average 0.5 and range from 0.04 to 1.5.

b. Net Pay: Net pay was determined using the following criteria: minimum porosity of 15%, clay volume less than 28%, and glauconite volume less than 40%. If the volume of siderite exceeded 30%, the net pay was discounted by a factor of 50%. The 15% porosity cut off corresponds to approximately 1 md of permeability.

c. Water Saturations: Initial water saturations were derived from mercury injection capillary pressure tests on NWE 1-01 and L-101 core plugs and application of Leverett J-function. Initial water saturation used in the reservoir model averages 32% to 54% in intervals above the oil water contact.

d. Relative permeability: Comparisons to analog reservoirs on the North Slope were conducted, and Pt. McIntyre rock type 8 relative permeability curves were selected on the basis of porosity and permeability similarities.

e. Initial Reservoir Pressure: Based on pressure data from V-100, the initial reservoir pressure is estimated at 3439 psia at the reservoir datum of 6600' TVD subsea. The reservoir temperature is 158 degrees Fahrenheit at this datum.

f. Fluid PVT Data: The reservoir fluid PVT studies conducted on Well V-100 crude oil from down hole samples are considered the most representative for the Borealis Pool. The reservoir pressure was 3442 psia and the bubble point pressure was 2761 psia at 6610' TVD subsea with a temperature of 151 degrees Fahrenheit. The API gravity was 24.1 with a solution gas oil ratio ("GOR") of 457 scf/stbo. The formation volume factor was 1.23 RVB/STB and the oil viscosity was 2.97 centipoise at reservoir pressure and temperature. Initial well tests from L Pad wells have shown API oil gravities ranging from 25.6 to 27.5 degrees.

g. Hydrocarbons in Place: The current estimate of original oil in place ("OOIP") in the Borealis Participating Area ranges between 195 million stock tank barrels of oil ("stbo") and 277 million stbo primarily due to uncertainty in the oil-water contact ("OWC") and reservoir net pay interval thickness. Associated formation gas in place ranges from 85 to 125 billion standard cubic feet. There are no indications of a free gas column in the Borealis Pool.

4. Reservoir Performance Predictions

a. Model Overview: A three-dimensional, three-phase, black oil simulator of the Borealis Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles. The model area encompasses the proposed Borealis Pool area. Details of the model construction are provided in BPXA's application. Development options evaluated include primary depletion and waterflood with a miscible gas flood also analyzed. Waterflood has been identified as the preferred development option for the Borealis Pool.

b. Aquifer Influx: The aquifer to the northeast of the Borealis Pool could provide pressure support during field development. Early production data from the flanks of the field will be evaluated to determine the extent of pressure support. Current modeling efforts both with and without aquifer pore volume do not significantly change injector requirements or location.

c. Gas Coning / Under-Running: There are no indications of a free gas column in the Borealis Pool, so coning or under-run mechanisms are not anticipated.

d. Primary Depletion: Model results indicate that primary depletion would recover approximately 13% of the OOIP within the proposed Borealis Pool area. This represents a partial development of the pool area. Predicted annualized production rate peaks above 15,000 bopd in 2002 and falls to 2,000 bopd by the year 2010.

e. Waterflood: The reservoir simulation of waterflood predicted a recovery of 23% of the Borealis Pool OOIP with 0.47 hydrocarbon pore volume injected. Again, this represents a partial development of the proposed Borealis Pool. Localized recovery factors near 40% may be attained in fully developed regions. Modeling sensitivities provided by BPXA show that primary production for up to eighteen months with pre-production of planned injectors will not reduce ultimate field recovery.

f. Enhanced Oil Recovery ("EOR"): Preliminary analysis suggests potential benefits from miscible gas flood in the Borealis accumulation of approximately 5% incremental oil recovery. Further evaluations are planned to determine the impact on total recovery.

5. Development Plan:

a. Development Wells: Development plans include drilling a series of production and injection wells first at L Pad then moving to V Pad. As of May 2002, 14 wells have been drilled for completion within the Borealis Oil Pool. Four wells will be converted to water injection, but are currently being pre-produced. Between 20-50 wells are projected. BPXA is currently projecting that drilling will continue for a number of years. Future infill or peripheral drilling will be evaluated based on production performance and surveillance data.

b. Rate Estimate: Peak annualized production is expected to be between 10,000 and 15,000 bopd. Peak water injection is expected to be between 20,000 and 40,000 bwpd. Each producing well may be stimulated, if necessary, with a propped hydraulic fracture. Water injection is expected to commence once a series of injectors, the injection pipeline, and manifold construction are completed, and approvals to inject are received.

c. Well Spacing: BPXA requested a minimum well spacing of 40 acres to allow for flexibility in well placement. Pattern spacing will be irregular with well locations determined considering local faulting and reservoir stratigraphy.

d. Reservoir Management Strategy: Once water injection begins, the voidage replacement ratio ("VRR") will exceed 1.0 to restore reservoir pressure. When the reservoir pressure has been restored, a balanced VRR will be maintained. The Borealis Owners request that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices.

6. Facilities

a. Well Pad Facilities: Borealis wells will be drilled from existing L, V and possibly Z pads. Borealis fluids will be commingled with Prudhoe Bay Unit Initial Participating Area ("IPA") fluids on the surface and will be processed at PBU Gathering Center 2 ("GC-2"). Production and injection manifolds at L and V pads are capable of accommodating up to 24 new wells at each pad.

b. Well Pad Operations: The automatic well safety systems and the pad emergency shutdown system can be triggered either manually or automatically. All producers will have actuated divert valves to allow switching from the production to the test header remotely. Gas lift chokes are also actuated to allow remote adjustment of gas lift rate.

c. Data Gathering System: Well pad data gathering will be performed both manually and automatically. The SCADA data gathering system will be expanded to accommodate the Borealis wells and drill pad equipment, and will continuously monitor the flowing status, pressures, and temperature of the producing wells.

d. Pipelines: New pipelines (24" Production, 12" water injection, and 8" gas lift) have been installed for development of the Borealis Oil Pool. Existing IPA flowlines include 24" and 30" low-pressure large diameter flowlines, an 8" gas lift supply line, and a 12" water injection supply line. The oil sales line from GC-2 to Pump Station 1 and existing power distribution and generation facilities will be utilized. A miscible injection ("MI") supply line could be installed from Z Pad to L and V Pads for future EOR applications.

BPXA estimates the water injection line is sufficient to deliver water to Borealis injection wells at a rate of 40,000 bpd and a pressure up to 2800 psig. Should water injection pressures prove insufficient, injection pressure can be boosted locally. Preliminary estimates indicate that the gas lift line is sufficient to deliver gas to Borealis production wells at a rate of 80 mmscfpd and a pressure of approximately 1800 psig.

e. GC-2: The GC-2 production facilities to be used include separating and processing equipment, inlet manifold and related piping, flare system, and on-site water disposal. Facility modifications are underway to increase the deliverability and pressure of the produced water system from GC-2. No modifications to the GC-2 production system will be required to process Borealis production. Production, including that from Borealis, is not expected to exceed existing GC-2 capacity.

7. Drilling:

Borealis development drilling will utilize drilling procedures, well designs, and casing and cementing programs similar to those currently used in the Prudhoe Bay Unit and other North Slope fields, and per regulation.

a. Conductor: A 16" or 20" conductor casing will be set 80' to 120' below pad level and cemented to surface. Requirements of 20 AAC 25.035 concerning the use of a diverter system and secondary well control equipment will be met.

b. Surface Hole: In addition to the requirements of 20 AAC 25.030, the surface casing will be set at least 500' tvd below the base of the permafrost. Cementing and casing requirements similar to other North Slope fields have been adopted for Borealis. The casing head and a blowout-preventer stack will be installed onto the surface casing and tested consistent with 20 AAC 25.035.

c. Production Hole: The production hole will be drilled below surface casing to the Kuparuk, allowing sufficient rathole to facilitate logging. Production casing will be set and cemented. Production liners will be used as needed, to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells, such as high departure wells.

d. H2S Precautions: No significant H2S has been detected in the Kuparuk while drilling PBU wells or in any Borealis well drilled to date. However, with planned waterflood operations, there is potential of generating H2S over the life of the field. Consequently, H2S gas drilling practices will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellpad. All personnel on the rig will be informed of the dangers of H2S, and all rig pad supervisors will be trained for operations in an H2S environment.

8. Well Completion

Both horizontal and conventional wells may be drilled at Borealis. The horizontal well sections may be completed with perforated casing, slotted liner, barefoot 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.

a. Surface Safety Valves: Surface safety valves ("SSV") are included in the wellhead equipment for the Borealis Pool for all wells. These devices can be activated by high and low pressure sensing equipment on the flowline and are designed to isolate produced fluids upstream of the SSV if pressure limits are exceeded.

b. Subsurface Safety Valves: BPXA indicates the characteristic of the Borealis Pool should not require the installation or use of subsurface safety valves on production wells. Borealis producers are relatively low rate oil wells produced by artificial lift in a water flood development. Subsurface safety valves ("SSSV") will be installed on gas or MI injection wells when in service. All well completions will be equipped with a nipple profile at a depth just below the base of permafrost, should the need arise to install a downhole flow control device or pressure operated safety valves for future MI service or during maintenance operations.

c. Producers: Borealis producers will be completed in a single zone (Kuparuk). Producers will be gas lifted. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Additionally, jewelry will be installed so that jet pumps can be utilized providing further flexibility for artificial lift.

d. Injectors: The injectors will be designed to enable multi-formation injection where appropriate to the Kuparuk, Schrader Bluff, Sag River and Ivishak Formations. Injectors may be pre-produced prior to converting to permanent injection. Production from these wells could improve their injectivity and be used to evaluate reservoir productivity, connectivity and pressure response, enabling refinement of current reservoir models and depletion plans.

e. Well Logs: Measurement while drilling ("MWD") and logging while drilling ("LWD") will typically begin after setting the 9-5/8" or 7-5/8" surface casing. LWD measurements will typically include gamma ray ("GR"), resistivity and density and neutron porosity throughout the reservoir section. Open hole electric logs may supplement or replace LWD logging, including GR, resistivity, density and neutron porosity and other logging tools when wellbore conditions allow their use.

f. Drilling Fluids: Freshwater low solids, non-dispersed fluids will be used to drill the upper and Kuparuk well sections. In the future, water-based KCl mud or other mud may be used in order to minimize skin damage from drilling and enhance performance.

g. Stimulation Methods: Fracture stimulation has been implemented for all Borealis producers drilled to date and may be implemented to mitigate formation damage and stimulate future Borealis wells. It may also be necessary to stimulate horizontal wells, depending upon well performance. Acid or other forms of stimulation may be performed as needed in the future.

9. Reservoir Surveillance Plans An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 6,600' TVD subsea. Pressure data could be stabilized static pressure measurements at bottom-hole or extrapolated from surface (assuming single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, repeat formation test, permanent gauges, or an open hole formation test. An initial static reservoir pressure will be measured on each regular production or injection service well. BPXA proposes a minimum of four surveys will be taken each year in representative areas of the Borealis Oil Pool to insure representative areal coverage, with more pressure surveys during initial field development to identify potential compartmentalization and fewer measurements as the development matures. BPXA proposes to report annually data and results from all relevant reservoir pressure surveys.

Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, may be periodically run to help determine reservoir performance (i.e., production profile and injection profile evaluations). Surveillance logs are planned on multi-zone injection well completions to assist in the allocation of flow splits as necessary.

10. Production Allocation

a. Applicable Regulations: BPXA requested commission approval under 20 AAC 25.215(a) for commingling of production from the Borealis Pool with the production from other pools within the Prudhoe Bay Unit. Other applicable regulations are 20 AAC 25.230 Measurement, Allocation and Reporting of Well Production.

b. Proposed PBU Western Satellite Production Metering Plan: BPXA requested that Borealis production use the interim allocation scheme (using a 1.0 well allocation factor) until the PBU Western Satellite Production Metering Plan is implemented.

By letter dated April 23, 2002 BPXA outlined the PBU Western Satellite Metering Plan and formally requested concurrence with the plan. The following are key components of the plan.

1. The current WOA allocation technique for flowing wells will be used. Daily production from flowing wells will be based on the flowing tubing pressure and a modified Vogel curve, or equivalent, developed from well tests.

2. The EOA allocation technique for gas-lifted wells will be used in place of the current WOA procedure. Daily production from gas-lifted wells will be based on empirical well performance curves derived from 3-phase flow equations and production well test data, and will be a function of flowing tubing pressure and gas-lift rate.

3. A minimum of one well test per month will be performed on each well. Efforts will be directed towards increasing the availability of the well test separators through improved analysis of well stability test data.

4. All wells flowing to a gathering center (GC) will use that GC's well allocation factor for oil, gas, and water. Improvements to the GC bank oil meters are in progress as part of the oil gathering system leak detection process and will provide improved allocation factors.

5. All salient oil and water flow meters on GC 2 well test separators will be upgraded to Micromotion meters. Use of these meters should improve both gross fluid rate and water-cut measurement over results obtained using vortex meters and capacitance probes.

6. Zero-rate tests will be performed on all WOA pads and gathering center test banks once a quarter (every three months). If leak rates are not within acceptable tolerances, corrective measures will be taken. Leak rates from the zero-rate test will be used to correct test rates as necessary.

7. Reservoir specific shrinkage factors will be used to correct metered fluids to stock tank barrels. BPXA recommended this plan be implemented within 3 months of approval of the Borealis Participating Area by the Department of Natural Resources. BPXA testified that they could meet an implementation date of August 1, 2002.

c. Department of Revenue Comments: By letter dated May 1, 2002, the Alaska Department of Revenue ("DOR") endorsed approval of the PBU Western Satellite Metering plan outlined in BPXA's letter of April 23, 2002 on a tentative or interim basis, for up to one year, with the following stipulations:

1. Periodic review sessions for tracking of progress.

2. Implementation of item (b)(4), above, no later than August 1, 2002.

d. Procedures and Process reviews: In support of their proposed Western Satellite Metering plan, BPXA committed to the following actions:

1. Provide a metering and allocation policy and procedures document to the Commission by August 1, 2002.

2. Conduct performance reviews at 4, 8 and 12 months after the plan is implemented.

3. Improve bank meter accuracy by providing density measurement on appropriate bank meters.

4. Provide for an inflow performance curve based process for produced fluid allocation of all gas lifted wells.

5. Completion of micromotion meter upgrades to GC-2 well test separators.

6. Provide for interim performance reviews and process assurance.


1. Pool Rules for the development of the Borealis Oil Pool are appropriate at this time.

2. The Borealis Pool will be developed within the Prudhoe Bay Unit.

3. A portion of the proposed Borealis Pool rules area is currently subject to Conservation Order No. 349A. It is appropriate to remove the area encompassed by the Borealis Pool from the affected areas of CO 349A and CO 432A.

4. The reservoir appears to be compartmentalized and will require irregular spacing to optimize waterflood and recovery. Minimum well spacing of 40 acres is appropriate for efficient development of the Borealis Pool.

5. Monitoring of reservoir performance by measurement of production and reservoir pressure using standard industry practices on a regular basis will help ensure proper management of the pool. Annual reports will keep the Commission sufficiently apprised of surveillance plans and results and future development plans.

6. Implementation of water injection will preserve reservoir energy and increase ultimate recovery from the pool by a significant amount.

7. Completion of water injectors to allow injection in multiple pools within one wellbore is appropriate so long as the mechanical isolation of the pools is assured, injection operations are conducted according to the corresponding Injection Order and approved methodology for the allocation of water injection.

8. Exception from the gas-oil-ratio limitations of 20 AAC 25.240 is appropriate provided enhanced recovery operations have begun by May 1, 2003.

9. Allocation of production through intermittent well tests has been utilized in the industry and on the North Slope for years. While production allocation by intermittent well tests of multiple production phases does not meet the accuracy standards of single phase custody transfer metering, production commingling may allow pools of marginal economics to produce, where separate processing facilities would be prohibitive.

10. Uncertainty in oil production through well test allocation in the GC-1 and GC-2 Western Operating Area appears to be higher than that of other North Slope oil pools for which the Commission has approved commingling. Well allocation factors currently derived from GC-1 and GC-2 Initial Participating Area well tests have averaged less than 0.9. Other process facilities on the North Slope, such as the Lisburne Production Facility, show historical allocation factors in the range of 0.95 and 1.0. BPXA's proposed modifications of allocation processes and metering equipment should improve accuracy to a level consistent with other North Slope Operations.

11. Temporary approval of the PBU Western Operating Area Satellite Metering Plan is appropriate on a one-year basis. Implementation, documentation, and surveillance of equipment and production allocation modifications will take several months. The Commission will require thorough documentation of the allocation process, periodic review of progress, and monthly reports and file(s) containing daily allocation data and daily test data to adequately monitor the effects of the allocation process.


1. Pool Name, Definition and Classification: The Borealis Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between 6534' and 6952' MD in the West Kuparuk State 1 well, in the Prudhoe Bay Field. The Borealis Pool is classified as an Oil Pool.

2. CO 432-A and CO 349-A no longer apply to this affected area.

3. 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

T12N-R10E: ADL 25637 Sec 13, 24
T12N-R11E: ADL 47447 Sec 16 (SW/4 and W/2 NW/4 and W/2 SE/4), 21,
22 SW/4 and W/2 NW/4 and S/2 SE/4
ADL 47446 Sec 17, 18, 19, 20
ADL 28238 Sec 26 S/2 and W/2 NW/4 and SE/4 NW/4, 35, 36
ADL 28239 Sec 27, 28, 33, 34
ADL 47449 Sec 29, 30, 32
T11N-R11E: ADL 28240 Sec 1, 2, 11, 12
ADL 28241 Sec 3, 4, 9, 10
ADL 28245 Sec 13, 14, 24
ADL 28244 Sec 15
ADL 28246 Sec 25
T11N-R12E: ADL 28261 Sec 9 W/2
ADL 47450 Sec 5 S/2, 6 S/2 and NW/4 and W/2 NE/4, 7, 8
ADL 28263 Sec 16 W/2, 21 W/2
ADL 28262 Sec 17, 18, 19, 20
ADL 47452 Sec 28 W/2, 33 W/2
ADL 47453 Sec 29, 30, 31, 32
T12N-R12E: ADL 28259 Sec 31 W/2 and W/2 SE/4

Rule 1 Well Spacing

Spacing units within the pool shall be a minimum of 40 acres. The Borealis 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 feet 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 detecting and preventing an uncontrolled flow.

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

c. Subsurface safety valves (SSSV) must be installed on gas or miscible (MI) injection wells when in service.

d. Operation and performance tests must be conducted at intervals and times as prescribed by the Commission to confirm that the SSV system, SSSV system, and associated equipment are in proper working condition.

Rule 4 Common Production Facilities and Surface Commingling

a. Production from the Borealis Pool may be commingled with production from Prudhoe Bay, and other oil pools located in the Prudhoe Bay Unit in surface facilities prior to custody transfer.

b. The Prudhoe Bay Unit Western Operating Metering Plan, described in the letter dated April 23, 2002 is conditionally approved for one year beginning August 1, 2002.

c. As of August 1, 2002, all Borealis wells must use the Gathering Center 2 well allocation factor for oil, gas, and water. Until August 1, 2002, the Borealis Oil Pool allocation factor shall be 1.0.

d. All wells must be tested a minimum of once per month. All new Borealis 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.

e. A metering and allocation procedures document shall be submitted to the Commission by August 1, 2002. A draft copy of the procedures shall be provided to Commission staff for technical review by July 8, 2002.

f. Technical process review meetings shall be held quarterly to review progress of the implementation of the plan.

g. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.

h. Commission approval of the Prudhoe Bay Unit Western Operating 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.

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 four surveys shall be required each year in representative areas of the Borealis Pool. Bottom-hole surveys in paragraph (d) may fulfill the minimum requirement.

c. The reservoir pressure datum will be 6600' TVD sub-sea.

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 Borealis 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

Water injection for pressure maintenance must commence before reservoir pressure drops below 2761 psi at the datum depth of 6600' or by May 1, 2003, whichever occurs first.

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 there is mechanical isolation between pools.

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 must be supplied in the yearly reservoir surveillance report.

d. An approved area injection order is required for each pool prior to commencement of injection in that pool and injection must comply with the rules of the associated area injection orders.

Rule 9 Reservoir Surveillance Report

An annual reservoir surveillance report for the prior calendar year must be filed on April 1st.

a. Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques.

b. Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval.

c. Summary and analysis of reservoir pressure surveys within the pool.

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

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

f. Future development plans.

g. Review of Annual Plan of Operations and Development.

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 May 29, 2002.

Cammy Oechsli Taylor, Chair
Alaska Oil and Gas Conservation Commission

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

Conservation Order Index