THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order to establish pool rules for development of an Orion Oil Pool, Prudhoe Bay Unit, North Slope, Alaska
|Conservation Order No. 505
Prudhoe Bay Field
January 5, 2004
IT APPEARING THAT:
1. By application dated October 6, 2003, BP Exploration (Alaska), Inc. (“BPXA”) in its capacity as Unit Operator of the Prudhoe Bay Unit (“PBU”) requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") to define a proposed Orion 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 pool.
2. BPXA provided supplemental information at the Commission’s request on October 29, 2003.
3. Notice of a public hearing was published in the Anchorage Daily News on October 20, 2003.
4. The Commission held a public hearing December 4, 2003 at 9:00 AM at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska.
1. Orion Development Area of the Schrader Bluff Oil Pool
a. Operator: BPXA is the Operator of the property in the area proposed for development. BPXA uses the name Orion in reference to this development project. In this order the area proposed for development will be referred to as the Orion development area.
b. Development Area: The Orion development area is totally encompassed within the Prudhoe Bay Unit.
c. Delineation History: Oil was discovered in the Orion development area in 1968 with the Kuparuk State #1 exploratory well. Over 90 wells have penetrated the Schrader Bluff Formation (Schrader Bluff) in the Orion development area; nearly all were completed in deeper formations. In 1998, the Northwest Eileen 2-01 well was drilled, confirming hydrocarbons within the Schrader Bluff sands. Two producing wells have been completed within the Orion development area in the Schrader Bluff as of October 2003. BPXA utilized data from these wells in conjunction with a 3-D seismic survey to delineate the accumulations extent.
d. Pool Identification: The proposed Orion Oil Pool is an accumulation of hydrocarbons common to, and correlating with, the interval between the measured depths (“MD”) of 4,549 feet and 5,106 feet in the PBU V-201 well. This is the same accumulation that is common to and correlates with the interval between the measured depths of 4,174 and 4,800 feet in the Conoco Inc. Milne Point A-1 well, which has previously been defined in Conservation Order No. 477 (“CO 477”) as the Schrader Bluff Oil Pool. Differences in infrastructure and unit resources, stratigraphic changes and uncertainty in the distribution of oil quality characterize the different areas of the Schrader Bluff Oil Pool.
e. Stratigraphy: The Schrader Bluff Oil Pool encompasses reservoirs assigned to the Late Cretaceous-aged Schrader Bluff Formation. The Schrader Bluff Oil Pool contains two stratigraphic intervals that are designated, from deepest to shallowest, the “O sands” and the “N sands.” The O and N sand intervals were deposited in a marine shoreface and shallow shelf environment. In general, the O and N sand intervals are present across the entire Orion development area and, as a package, thin slightly from southwest to northeast. Reservoir quality sand units within each interval are regionally extensive but can be locally characterized by substantial thickness and net to gross variations between wells spaced less than 1000 feet apart. Sands are unconsolidated, susceptible to local diagenetic alteration and lateral facies changes.
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, to reservoir quality sandstone.
OBf and OBe Sands
The OBf and OBe intervals, each ranging in thickness from 35 to 55 feet, comprise the basal O sand units in the Schrader Bluff Oil Pool and exhibit the lowest net to gross sand facies in the O sand section. OBf and OBe sands also contain abundant pore-filling zeolites, which significantly reduce reservoir porosities and permeabilities.
The OBd sand interval ranges between 55 and 70 feet thick and forms one of the primary target horizons. OBd sands are thickest in the Z-Pad area ranging up to 64 feet net sand in well Kuparuk State 1, and thin gradually northward to between 5 and 30 feet net sand in the proposed I-Pad area. The basal 5 to 10 feet of this blocky sand interval forms the highest quality OBd reservoir unit.
The OBc sand interval, ranging between 45 and 60 feet thick, comprises a minor reservoir unit with reservoir quality sands present mainly in the V-Pad and Z-Pad areas. Up to 20 net feet of OBc sand is mapped in the V-Pad areas, while at L-Pad net sand thickness is typically 5 to 15 feet. To date, OBc sands have not been perforated in any Orion development area well.
The OBb sand interval, also a minor reservoir unit, has a thickness range of between 45 and 60 feet with between 15 and 25 feet of net sand present in the V-Pad area. Regionally, the OBb interval typically contains less than 20 net feet of sand.
The Oba sand interval has a 25 to 55 foot thickness range. Two regionally extensive erosion/scour surfaces are identified in the OBa sand, one in the middle of the unit and one at 10 to 15 feet from the top of the unit. Above each erosion/scour surface are bioturbated, blocky to fining upward high permeability sands (1000 millidarcies) that are 5 to 15 feet thick and constitute a primary development target.
The OA interval is 45 to 80 feet thick, with net sand thickness of 10 to 35 feet. Similar to the OBd and OBa intervals, the high quality sand sits above a regionally extensive erosion/scour surface and is heavily bioturbated. The high quality OA sand is less than 5 feet thick at Z-Pad, and thickens to 15 to 20 feet in the L-Pad and V-Pad areas.
The N sands are subdivided into three reservoir units, designated from deepest to shallowest as Nc, Nb, and Na. The N sand interval consists mainly of non-reservoir muds and siltstones interbedded with a limited number of thin, but generally extensive, unconsolidated reservoir sands. Thick, regionally extensive silty mudstones in the lowermost N sand interval form an important regional vertical reservoir barrier which segregates lighter, higher quality, oil in the main development horizon O sands at Orion and Milne Point (D, B, and A sands at West Sak) from generally heavier oil and water saturated sands in the overlying N and M sands (Lower Ugnu sands at West Sak).
Nc net sand is typically less than 15 feet thick across the area. Individual sands are generally unconsolidated and interbedded with thicker non-reservoir muddy siltstones. Nc sands are very fine grained, laminated and moderately to highly bioturbated. Nc sands have not been perforated or tested in an Orion well.
The Nb sand interval ranges from 30 to 50 feet, and comprises the primary N sand interval completion target. Nb net sand character is highly variable in the Orion development area with net sand thickness ranging from 10 to 40 feet. The best Nb reservoir quality sand has local very high permeability (1000 millidarcies) intervals.
The Na sand interval is a thin, very low net-to-gross interval, which lies at the top of the N sand section and is consistently about 25 feet thick across the area. No Na sand tests or completions have been made in an Orion l well due to poor reservoir characteristics in this area.
f. Structure: The top of the Schrader Bluff OA sand in the Orion development area has structural dip ranging from 1 to 4 degrees to the east and northeast, and it is broken by three sets of normal fault that trend from northwest to noutheast, north to south, and east to west.
Northwest-Southeast Fault Trend
The Northwest-Southeast striking fault trend, with throws of up to 200 feet, provides the predominate structural fabric of the pool. Faults with this orientation occur throughout the area, and form the boundaries of the major structural blocks in the area. The southwestern limit of the pool is formed by a complex fault system of northwest-southeast striking faults that link up and intersect with North-South faults to form a series of fault traps.
North-South Fault Trend
North-South striking faults, downthrown to the west and east are the second most dominate fault system in the pool. These faults have throws of up to 100 feet.
East-West Fault Trend
East-West faults are the least common fault trend in the Orion development area. East-west faults form part of the complex fault system that forms the reservoir trap on the southwestern side of the pool.
g. Reservoir Compartments
Elements of the major area fault systems were used to subdivide the pool in the Orion development area into reservoir compartments for development planning. As additional wells are drilled and production data gathered, the reservoir compartment picture could change. Each compartment was defined along seismically mapped fault trends and is assumed to be hydraulically isolated by sealing faults from adjacent compartments. The sealing character of the faults forming the compartment boundaries is inferred from both limited fluid contact and pressure data in the Orion development area and from analog studies, which show a high probability of clay smear seals forming along faults in the areas low net to gross reservoirs. N and O sand oil water contacts are in general poorly defined due to the lack of well control in down structure areas. No gas/oil contacts (“GOCs”) have been logged in any sand in the Orion development area nor is the presence of free gas in Schrader Bluff intervals in the area predicted from oil PVT test results. Each sand in the N and O interval is assumed to be vertically isolated from overlying and underlying sands by low net-to-gross, non-reservoir, muddy siltstones and is assumed to have a different associated OWC depth. The best defined reservoir compartments are at L-Pad and V-Pad where oil column heights range between 150 and 310 vertical feet. Oil-water contacts have only been logged in three Orion development area wells: Kuparuk State 1 (OBa and OBd sands), L-101 (Nb sand), and Northwest Eileen 1 well (OA and Nb sands). Based on differences in rock quality and potential spill points for the various sand units, it is believed that oil-water contact depths vary by sand unit and by fault block within the area.
2. Rock and Fluid Properties
a. Porosity/Permeability: No core information is available for the Schrader Bluff Oil Pool within the Orion development area. Porosity and permeability values were derived from routine core analyses of core plugs from Polaris Oil Pool wells S-200PB1 and W-200PB1, and Kuparuk Field West Sak wells WS1-01 and 1R-07, and one Milne Point Unit Schrader Bluff Oil Pool well MPE-20. Porosity and permeability values used for reservoir simulation are based upon the Polaris log model. O sand reservoir simulation porosities range between 25 and 30% and permeabilities typically range from 50 to 250 md. Net pay thicknesses were derived using a petrophysical log model based upon well log and core data. Log-model cutoffs of 6 md permeability, 65% water saturation and 35% clay volume were used.
b. Water Saturations: Water saturations were derived from Polaris air/brine capillary pressure analyses of cores from wells S-200PB1 and W-200PB1. Leverett J-function curves were used to distribute water saturation according to porosity and permeability. Relative permeability curves for the Orion development area are based on analogy to the nearby Schrader Bluff accumulation at Milne Point.
c. Initial Reservoir Pressure: Average initial reservoir pressure in the Orion development area is estimated to be 1970 psi at 4400’ TVDss. Reservoir temperature is about 87 degrees Fahrenheit at this datum.
d. Fluid PVT Data: A total of 23 PVT analyses have been performed on Orion development area O sand oil samples. Geochemical analysis of 19 of these samples suggests that at least two oil charges are present. O series sand oil API gravities range from the low twenties to the mid teens.
3. Pool Limits
The Schrader Bluff oil-bearing sands extend into the Milne Point Unit to the North and are present to the West in the Kuparuk River Unit West Sak Oil Pool. The Orion development area is the portion of the Schrader Bluff Oil Pool located within the Prudhoe Bay Unit. BPXA has requested a well spacing standoff of 500 feet from the exterior boundary of the Prudhoe Bay Unit, which is consistent with the Milne Point Field Schrader Bluff Oil Pool Rules and statewide regulation (20 AAC 25.055). BPXA as Operator of the Milne Point Unit submitted a letter on September 15, 2003 stating that the Milne Point Owners have no objection to the requested Orion pool rules and Area Injection Order application. On-going development operations in the Western PBU will provide additional information about the productive limits of the Schrader Bluff Oil Pool.
4. Hydrocarbons in Place
Original oil in place within the Orion development area of the Schrader Bluff Oil Pool is estimated at 1,070-1,785 million stock tank barrels (“STB”), with 845 to 1,410 MMSTB in the O sands and 225 to 375 MMSTB in the N sands. All gas is in solution, and totals 210-345 billion standard cubic feet (“SCF”).
5. Pilot Well Performance
Two wells are producing from the Schrader Bluff Oil Pool within the Orion development area, V-201 and V-202. The V-201 was fracture stimulated within the OA, OBa, OBb, and OBd sands. Initial production in April 2002 was 1080 barrels of oil per day (“BOPD”) at gas oil ratio of 400 SCF/STB. As of August 2003, the well had declined to 600 BOPD, 7% water, and 400 SCF/STB. Total production was 174,000 barrels.
V-202 is a 3000-foot single lateral drilled within the OBd. Initial test in July 2003 was 7100 BOPD, 350 SCF/STB. OA and OBa laterals are scheduled to be drilled in the fourth quarter 2003. No tests of the N sands were reported.
On October 14, 2003, the Commission approved dual injection into the Kuparuk and Schrader Bluff intervals in the Well V-105i. The purpose of this initial injection test is to determine the injectivity into the Schrader Bluff formation, determine the operability of commingled injection into two pools, and confirm that geological barriers will contain the injection fluid when injected at injection pressures above fracture gradient.
6. Development Plans
Reservoir models have been used to evaluate primary depletion, waterflood, and other enhanced recovery options for development of the Schrader Bluff Oil Pool within the Orion development area. Reservoir predictions are based on fine scale, three-dimensional black oil models. Model studies performed to date for the Orion development area show about 5 to 10% recovery of OOIP under primary production and about 20-25% under waterflood (inclusive of primary).
Initial development is planned in three phases, beginning near the crest of the structure and progressively moving toward the outer margins of the pool.
a. Phase I Development: Phase I development targets the areas with good seismic quality and/or well control. This includes expansion of the development at V pad and drilling of at least one L pad tri-lateral producer. A well within the W pad area may be drilled in 2004 testing the southeast area of the field.
b. Future Phases of Development: Phase II development will be completion of locations that can be drilled from existing gravel pads. This would include drilling of 10-20 producers and 20-40 injectors in the L, V, Z Pads. An additional 2 producers and 4-8 injectors may be drilled from W pad. Phase III development will target the northwest portion of the field. A new pad will be required for this development. 10-20 producers and 20-40 injectors are envisioned.
c. Rate Estimate: Peak production rates are expected to be between 30,000 and 50,000 barrels of oil per day (“BOPD”). Waterflood injection rates are estimated to peak between 100,000 and 125,000 barrels of water per day (“BWPD”).
d. Well Spacing: Initial plans are to develop on an average spacing of 160 acres. BPXA requests a minimum well spacing of 20 acres to allow for flexibility in well placement because of local faulting and reservoir stratigraphy. CO 477 for Milne Point Field, Schrader Bluff Oil Pool allows a minimum well spacing of 10 acres. BPXA recommends a minimum offset of 500’ from external lease boundaries, which is consistent with CO 477.
e. Reservoir Management Strategy: Once water injection begins, voidage replacement ratio will be balanced and reservoir pressure will be maintained above the bubble-point.
Orion wells will be drilled from existing V, L, Z and W-Pads, and a potential new I-Pad. 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. Some debottlenecking is anticipated for water injection at Orion. The options are currently being reviewed.
No modifications will be required at GC-2 to process Orion development area production. Existing low pressure oil, water injection, gas lift and possibly miscible injectant lines will be shared. Existing well test equipment will be utilized at V, L, Z and W pads. Gas lift, jet pumps and electrical submersible pumps are all being evaluated for artificial lift.
Orion development area drilling will 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 Prince Creek well sections.
e. H2S Precautions: No significant H2S has been detected in any Orion development area 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 Orion. 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 wells.
b. Subsurface Safety Devices: BPXA requested that subsurface safety valves not be not be required due to 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.
c. Producers: Orion development area producers will not be completed in multiple pools. Artificial lift capability is designed into each producing well.
d. Injectors: 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.
e. Stimulation Methods: Fracture stimulation has been used successfully for Orion development area producers and may be implemented to mitigate formation damage and stimulate future Orion development area 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 of 4,400 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. BPXA also proposes a minimum of two pressure surveys be taken each year in each reservoir compartment as shown in Exhibit I-13 when at least one Orion development area production well has been completed in the respective compartment. Spinner logs are planned on multi-pool injection well completions to assist in the allocation of flow splits as necessary.
11. Production Allocation
The PBU Western Satellite Production Metering Plan, approved by the Commission in CO 471 through August 2003, will be used for allocation of production. The GC-2 allocation factor will be applied to adjust total Orion development area production. New wells will be tested a minimum of two times per month during the first three months of production and at least once per month thereafter.
1. The proposed Orion Oil Pool is equivalent to the Schrader Bluff Oil Pool.
2. Pool Rules for the development of the Schrader Bluff Oil Pool within the Orion development area are appropriate at this time.
3. The Schrader Bluff Oil Pool within the Orion development area is compartmentalized and will require irregular spacing to optimize waterflood and recovery. Minimum well spacing of 10 acres is appropriate for efficient development of the pool and is consistent with pool rules (CO 477) for Schrader Bluff Oil Pool development with the Milne Point Field.
4. The Orion development area is in the early stages of development. Phase I development has focused upon determination of reservoir delivery and well operability.
5. Differences in existing infrastructure and uncertainties in the distribution of oil quality justify, at least for the time being, having separate pool rules for the Milne Point Unit and the Prudhoe Bay Unit (Orion development area) portions of the Schrader Bluff Oil Pool.
6. The full extent of the pool and the individual reservoir compartments are not yet known.
7. A well standoff of 500’ minimum from the external boundaries of the Prudhoe Bay Unit is consistent with statewide regulations and with rules for the Milne Point Unit portion of the Schrader Bluff Oil Pool.
8. The Owners of the Milne Point Unit have no objection to BPXA’s proposal to establish pool rules to govern development within the Orion development area.
9. Due to the incompletely understood nature of compartmentalization of the reservoir, and communication with the portion of Schrader Bluff Oil Pool located within the Milne Point Unit, pressure monitoring is necessary.
10. 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 and will ensure that future development plans promote greater ultimate recovery.
11. Water injection into the O and N Sands will preserve reservoir energy and increase ultimate recovery from the pool.
12. 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.
13. 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. 14. Use of the PBU Western Satellite Production Metering Plan that governs allocation of production from the Western Operating Area of the PBU is appropriate for production from the Orion development area of the Schrader Bluff Oil Pool.
NOW, THEREFORE, IT IS ORDERED:
1. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), apply to the Schrader Bluff Oil Pool within the following affected area referred to here as the Orion development area:
|Township Range, UM||Lease||Sections|
|T12N-R10E||ADL 025637||13 and 24 N/2|
|T12N-R11E||ADL 047446||17, 18, 19, and 20|
|ADL 047447||16 S/2 and NW/4 and S/2 NE/4, 21, and 22|
|ADL 028238||25 SW/4, 26, 35, and 36|
|ADL 028239||27, 28, 33 E/2 and N/2 NW/4, and 34|
|ADL 047449||29 N/2 and SE/4, and 30 N/2 NE/4|
|T11N-R11E||ADL 028240||1, 2, 11 E/2 and E/2 NW/4, and 12|
|ADL 028241||3 N/2 and N/2 S/2, and 4 NE/4 N/2 SE/4|
|ADL 028245||13 N/2 and SE/4, 14 E/2 NE/4, and 24 E/2 NE/4|
|T11N-R12E||ADL 047450||7, and 8 S/2 and NW/4|
|ADL 028263||16 SW/4 and S/2 NW/4, and 21 SW/4 and S/2 NW/4 and NW/4 NW/4 and W/2 SE/4|
|ADL 028262||17, 18, 19 N/2 and SE/4 and N/2 SW/4, and 20|
|ADL 047452||28 W/2 and W/2 E/2|
|ADL 047453||29 N/2 and N/2 SE/4|
Rule 1 Well Spacing
Spacing units shall be a minimum of 10 acres. The Schrader Bluff 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
a. Production from the Schrader Bluff Oil Pool within the Orion development area may be commingled with production from Prudhoe Bay Oil Pool, 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 by letter from BPXA dated April 23, 2002 and detailed within the “Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan – Policies and Procedures Document” dated August 1, 2002 is approved for allocation of production from Schrader Bluff Oil Pool wells within the Orion development area.
c. All Schrader Bluff Oil Pool wells must use the Gathering Center 2 well allocation factor for oil, gas, and water.
d. All wells must be tested a minimum of once per month. All new 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. Technical process review meetings shall be held at least annually. f. The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.
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 one bottom-hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements.
c. The reservoir pressure datum will be 4400’ 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 Schrader Bluff Oil Pool within the Orion development area 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
Waterflood is required for purposes of pressure maintenance and enhanced oil recovery in the Orion development area of the Schrader Bluff Oil Pool. Production and injection operations must ensure the average reservoir pressure is maintained above bubble point.
Rule 8 Multiple Completion of Water Injection Wells
a. Water injectors may be completed to allow for simultaneous 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.
f. Progress of plans and tests to expand the productive limits of the pool, including any work within the Prince Creek formation.
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: Operation of Development
Wells with Pressure Communication or Leakage in any Casing, Tubing, or Packer Requirements of Conservation Order No. 492 are incorporated by reference.
Rule 11 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 January 5, 2004.
Sarah Palin, Chair
Alaska Oil and Gas Conservation Commission
Daniel T. Seamount, Jr., Commissioner
Alaska Oil and Gas Conservation Commission