|Re:||THE APPLICATION OF BP||)||Conservation Order No. 477|
|EXPLORATION (ALASKA) INC.||)|
|for an order to establish pool rules for||)||Milne Point Field - Milne Point Unit|
|development of the Schrader Bluff||)||Schrader Bluff Oil Pool|
|Oil Pool, Milne Point Field, North||)|
|)||August 23, 2002|
IT APPEARING THAT:
1. By application received by the Commission on June 18, 2002, BP Exploration (Alaska), Inc. ("BPXA") in its capacity as Schrader Bluff Operator and Unit Operator of the Milne Point Unit ("MPU") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") to amend the area subject to Conservation Orders ("CO") 255, 283, and 347. BP requested revocation of CO 255 and 283 and issuance of a new comprehensive order governing the amended pool area. CO 255 defines the Schrader Bluff Oil Pool within the MPU and establishes rules for its development. CO 283 approves a waterflood project for the Schrader Bluff Oil Pool within MPU. CO 347 provides a waiver to the requirement of 20 AAC 25.280(a) that the Operator obtain approval for workover operations for all producible wells within the Schrader Bluff Oil Pool and the Kuparuk Oil Pools within the MPU.
2. BPXA submitted a revised application to amend the Schrader Bluff Oil Pool Rules on June 19, 2002.
3. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on June 28, 2002. The Commission on its on motion proposed review and modification of the Schrader Bluff Pool area to more accurately reflect the potential area for development of the Pool within the Milne Point Unit. The Commission also proposed to consolidate and consider updating the rules governing development and operation of the Pool.
4. The public hearing was tentatively scheduled for 9:00 AM on July 30, 2002. The notice of opportunity stated that the filing deadline for all written requests that the tentatively scheduled hearing be held was 4:30 pm on July 15, 2002.
5. BPXA provided supplemental information at the Commission's request on June 18 and July 25, 2002. BPXA submitted a draft copy of pre-filed testimony and supporting exhibits on July 26, 2002. BPXA submitted final pre-filed testimony and supporting exhibits to the Commission on July 30, 2002.
6. No protests to the application or timely requests for a public hearing were received, although an untimely request for a public hearing was received on July 30, 2002.
7. Because BPXA provided sufficient information on which to make an informed decision and because the untimely request for a hearing did not identify a compelling need to reschedule a hearing, the Commission determined that it would issue an order without a hearing.
1. Schrader Bluff Oil Pool
a. BPXA is the Operator of the Schrader Bluff Oil Pool.
Pool Definition: The vertical limits of the Schrader Bluff Oil Pool are defined as those sediments between the measured depths of 4,174 and 4,800 feet in the MPU A-1 well (CO 255, Rule 1). A more typical and representative stratigraphic section for the MPU Schrader Bluff Oil Pool is found between 4,100 and 4,726 feet measured depth in the MPU G-1 well.
Stratigraphy: At Milne Point, the Late Cretaceous-aged (Maastrichitian) Schrader Bluff Formation is divided into two stratigraphic intervals that are designated, from oldest to youngest, the "O-sands" and the "N-Sands". The O-sands and N-Sands are, in turn, divided into a number of sub-intervals. The O-sands sub-intervals are named, from oldest to youngest, OBD, OB and OA. The N-Sands sub-intervals are named, from oldest to youngest, NF, NE, ND, NC, NB, and NA. The O-sands were deposited under shallow marine conditions in the distal portion of a delta. They consist of very fine to fine-grained, quartz-rich sandstone interbedded with siltstone and mudstone. The two most prominent O-sands, OB and OA, are well developed, laterally extensive, and separated from one another by a persistent interval of marine siltstone and shale that acts as a hydraulic barrier.
The overlying N-Sands were deposited within a muddy marine shelf system. Mudstone and siltstone dominate the lower portion of this interval, but the sediments coarsen upward, becoming the fine to medium grained sandstone that dominates the upper part of the N-Sand interval.
The O-sands interval contains the primary reservoir sands of the Schrader Bluff Oil Pool, with secondary accumulations in the N-Sands interval.
Detailed well log correlations place an unconformity between the N-Sands and the overlying M-Sands interval of the Lower Ugnu. Vitrinite reflectance and apatite fission track studies performed by Conoco on cuttings from the MPU A-1 well suggest that erosion has removed 1,500 to 1,700 feet of sediment from the top of the N interval.
Structure: The Schrader Bluff structure is a homocline that dips 1 to 2 degrees to the east-northeast, and lies between approximately 3,400 and 5,200 feet true vertical depth subsea ("TVDss") within the proposed, expanded boundaries of the Schrader Bluff Oil Pool. This structure is broken by two sets of faults, one trending west-northwest and one trending north-northeast. Both sets of faults are normal, and they divide the structure into a series of grabens, half-grabens and horst blocks.
Pool Limits: Within the Schrader Bluff Oil Pool, oil distribution is controlled by structure and stratigraphy. Oil is trapped up-dip to the south and west against several west-northwest trending faults that cut the O-sands and the NE, NC and NB sands. In contrast, the up-dip limit of oil in the NF, ND and NA sands occurs where these reservoir sands pinch-out to the south and west. The accumulations are bounded to the north and east by the downdip intersection of the top of the reservoir sands and the oil-water contacts.
Fluid Contacts: There is no evidence of free gas accumulation within the Schrader Bluff Oil Pool. Complex faulting has compartmentalized this pool. At present, 15 discrete fault blocks, or independent hydraulic units, have been identified.
2. Rock / Fluid Properties and Original Oil in Place
The initial S-Pad development was envisioned as a development of the O-sands only to take advantage of the horizontal well performance potential in the thicker O-sands, while avoiding the sanding problems that are more prevalent in the N-sands. A reservoir model for the O-sands in the vicinity of S-Pad was used to predict performance. For modeling purposes, the OB and OA sands were subdivided into 13 layers, with the four layers constituting the OB sand separated from the overlying 8 layers of the OA sand by an impermeable 30-foot thick siltstone/shale layer. The following summarizes the input for this S-Pad model:
Porosity and permeability: The average weighted porosity is 27.7 percent. Horizontal permeability averages 171 millidarcies ("md").
Gross and Net Pay: Overall gross pay is 58 feet. The average weighted net-to-gross ratio is 84 percent, which yields an overall net pay of 49 feet.
Water Saturations: Average water saturation was held constant in the model at 40 percent.
Rock Compressibility: The N-sands are unconsolidated and significantly weaker than the weakly consolidated O-sands. Rock compressibility of the O sands within the model was set at 50.0 E-6 1/psi.
Relative permeability: Relative permeability curves were derived from core test of MPE-20.
Initial Reservoir Pressure: Initial reservoir pressure at 4,000 feet TVDss is approximately 1,790 psi.
Initial Reservoir Temperature: Temperature in the model was held constant at 82° F.
Fluid PVT Data: The O-sands fluid system at S-Pad was characterized by samples from wells MPH-07, MPH-08, and MPE-24A. The PVT data was generated from a Schrader Bluff equation of state to describe a hydrocarbon with in-situ viscosities of 30 and 40 centipoise ("cp"), with the region west of a large, north-south trending fault that cuts through the eastern portions of sections 2 and 11 of T12N, R10E is characterized with the 30 cp oil, and the region east of the fault is characterized with 40 cp oil. Saturation pressure is 1,287 to 1,300 pounds per square inch ("psi"). Solution gas-oil ratio is 150 to 163, and oil formation volume factor is about 1.07 reservoir barrels per stock tank barrel ("RVB/STB"). Gas gravity is 0.57.
Original Oil in Place ("OOIP"): The total estimated OOIP for the Schrader Bluff reservoirs within the MPU boundaries ranges from 1.25 to 2 billion STB, with an estimated solution gas in place of between 1.3 to 2.1 billion cubic feet ("BCF"). Within the S-Pad area, the current estimate of OOIP for the O sands ranges from 187 to 222 million STB, and the combined total OOIP for both N and O sands is between 247 to 363 million STB.
3. Reservoir Performance Predictions - S-Pad Model
Model Overview: A three-dimensional, three-phase, black oil simulator was developed for the S-Pad area. It was composed of 2-acre sized blocks arranged in 13 layers. Each layer consisted of 4,800 blocks arranged in a grid measuring 60 blocks by 80 blocks. The modeled development pattern consisted of 14 horizontal multi-lateral producers (each having a 3,000 foot-long producing interval) and 20 vertical injectors. Model properties were areally constant, but varied by depth and layer. Production was constrained to a maximum rate of 1,800 STB/D at a minimum flowing bottom-hole pressure limit of 700 psi at 4,200 feet TVDss. The initial development assumed only O-sand development to avoid sanding and associated completion and production problems in the N sand.
Primary Depletion: The primary recovery mechanism is a combination of solution gas drive and compaction drive. Within the S-Pad expansion area, model results indicate that primary depletion for O-sands would recover approximately 11 percent of the OOIP. BPXA's predicted annualized production rate peaks above 15,000 barrels of oil per day ("BOPD") in 2003 and falls to 3,000 BOPD by the year 2009. The reservoir pressure approaches bubble point pressure by 2007.
Waterflood: Waterflood is the preferred enhanced recovery option for the S-Pad development area. BPXA's waterflood reservoir simulation predicts a recovery of 22 percent of the total OOIP within the O-sands of the S-Pad portion of the Schrader Bluff formation, when 1.0 hydrocarbon pore volumes of water are injected.
Reservoir faulting and hydraulic unit size will be key factors in placement of wells. The final development is anticipated to include 30 to 50 production and injection wells. The average distance between injector to producer wells in the S-Pad area will be approximately 1,380 feet. The peak rate generated from the model is 16,700 BOPD in 2003, and then production rate will decline approximately 12.5 percent per annum. Water breakthrough occurs after about 2.5 years of production. The OA sands with higher permeability have a higher recovery at the end of the simulation (year 2029). Injectors are planned to have side pocket injection valves or dual tubing to allow more efficient placement of water.
4. Schrader Bluff Oil Pool Development History
Current Development Summary: As of May 31, 2002, the Schrader Bluff Oil Pool produced an average of 12,580 BOPD from 36 active producers at an average GOR of 574 scf/STB, and a water cut of 28 percent. Water injection now totals 29,000 barrels of water per day ("BWPD") through 19 wells. The wells are producing and /or injecting from pads C, E, G, H, I, and J.
Schrader Bluff development began in 1991 with the installation of 4 gravel pads in the Tract 14 pilot development area. The initial 17 development wells were focused upon use of conventional well technology with sand control. For the first 9 years of production, the average initial rate was 300 BOPD.
In 1997, BP began a large-scale development consisting of 14 producers drilled from existing gravel pads. Most were completed as conventional wells, and they averaged about 300 BOPD. However, one horizontal well (MPU I-06) produced at over 600 BOPD. Three additional horizontal wells were drilled and completed as barefoot (openhole) producers. Unfortunately, the OB sands were wet in these wells, and productivities were low. However, these three horizontal wells demonstrated that the OA could survive up to 800-psi drawdown while producing only trace amounts of sand.
BPXA's 1999 drilling program of four horizontal OB and OA sand completions proved the concept of use of horizontal wellbores without gravel pack. A water breakthrough experiment was conducted during which water was injected below fracture pressure until full break through occurred in a nearby horizontal producer. Solids production was monitored in the producer, and only traces of sand occurred after water break through. Later investigation of the slotted liner showed no traces of sand along the length of the well.
During 2000 and 2001, BPXA designed and drilled the first three horizontal multi-lateral producers in the Schrader Bluff Oil Pool. Design concepts were finalized for the S-Pad horizontal and multilateral development wells, which include use of jet pumps to allow coiled tubing clean out if sanding becomes an issue.
5. Development Plan
a. Development Wells: BPXA's current plans are to develop Schrader Bluff Oil Pool within the expansion area by wells drilled from the newly constructed S-Pad and from existing pads E and H. The S-Pad expansion will include 30 to 50 production and water injection wells. BPXA's long-term plan is to revisit and improve the existing development in the "Tract 14" area, which encompasses the G, H, I, and J-Pads.
Rate Estimate: Peak annualized production is expected to be between 13,000 and 19,000 BOPD in 2003. Peak water injection is expected to be between 20,000 to 40,000 BWPD at a maximum bottom hole pressure of 3,000 psi.
Well Spacing: BPXA currently anticipates wells nominally spaced at 80 acres. Pattern spacing will be irregular, with well locations determined considering local faulting and reservoir stratigraphy. The well spacing in the current boundaries of the Schrader Bluff Oil Pool is 10 acres. BPXA proposes this spacing be maintained for the expansion area.
Reservoir Management Strategy: Injection will commence with the startup of the S-Pad development. The reservoir management objection is to maintain a balanced voidage replacement ratio.
The S-Pad development will impact various field facility systems: oil/gas/water processing systems and electrical power generation. All of these systems presently have capacity to accommodate the S-Pad development or will have capacity before first oil from S-Pad.
Well Pad Facilities: Schrader Bluff wells are currently producing and/or injecting from pads C, E, G, H, I and J. The proposed expansion area will be developed primarily from a single pad, S-Pad, which has been constructed 0.7 miles west of the main Milne Point spine road.
Pipelines: Two new pipelines (12-inch production and 8-inch water line) have been constructed for development of the Schrader Bluff reservoir from S-Pad. The 12-inch line will be tied in to the existing K pad production line at the point where the K pad line nears the Milne Point spine road. The vertical support members have been designed to allow for a possible third pipeline to be installed in the future for miscible gas injection.
Gathering Center: MPU has a single gathering center, known as the Central Facilities Plant ("CFP"). MPU's CFP is currently handling approximately 57,000 barrels of oil, 45,000 barrels of water, and 35 million scf of gas daily. The CFP processes reservoir fluids from various pads and producing zones in the MPU. MPU's estimated facility capacity is currently 65,000 barrels per day of pipeline-quality oil.
7. Well Design and Completion
a. Surface Safety Valves: Actuated surface safety valves ("SSVs") are included in the wellhead equipment for the Schrader Bluff Oil Pool for all wells. These devices can be activated by high and low pressure and temperature sensing equipment on the flowline and are designed to isolate produced fluids upstream of the SSV if alarm limits are exceeded. The valves can be activated remotely from the Electrical Control Module on the pad, at the Central Facilities Pad, or at the well divert shelter.
b. Subsurface Safety Valves ("SSSVs"): Schrader Bluff wells produce low GOR oil at relatively low rates using artificial lift. The initial pool rules did not require subsurface safety valves in these wells. However, if gas injection or miscible gas injection is started, BPXA has indicated that nipple profiles are included in current injectors, in such a manner that a downhole flow control device or injection valve may be installed when required to prevent backflow of injected gas.
c. Producers: The typical multilateral well and completion design for producing wells on S-Pad include 7-inch or 7 5/8-inch casing landed in the lowermost reservoir interval, normally the OB sand. A 6 1/8-inch hole is drilled horizontally in the reservoir and 4 1/2-inch liner set. Subsequent laterals in overlying zones are drilled and completed in the same way, with the 4 1/2-inch liner hung off in the casing using a hookwall hanger system or liner hanger. The wells will be completed using 4 1/2-inch tubing and jet pumps, with a single packer set above the reservoir interval. Each producer is equipped with downhole pressure and temperature sensors capable of providing real time measurements at the surface.
d. Injectors: The injectors planned for S-Pad are all single string 7-inch casing design, with either a single string of production tubing or dual tubing strings to control injection. Each tubing string is equipped with a landing nipple below the base of the permafrost to facilitate setting sub-surface safety devices with slickline if needed.
e. Well Logs: Measurement while drilling ("MWD") and logging while drilling ("LWD") will typically begin at surface. MWD will typically include drilling parameters such as direction and inclination. LWD measurements will typically include gamma ray ("GR"), resistivity 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 Schrader Bluff well sections. A 9 to11 pound per gallon ("ppg") freshwater, low-solids, non-dispersed mud system or equivalent will typically be used to drill the production / injection hole to the 7-inch casing point. For the horizontal section, the mud system parameters may be optimized.
g. Artificial Lift: Producing wells at S-Pad are lifted with reverse flow jet pumps that utilize produced water for the power fluid. Jet pump performance is monitored in real time using permanently installed downhole gauges that measure intake and discharge pressure and temperature. Produced water is separated on pad with inclined separators to provide a produced fluid ratio of approximately 2 to 1. Power fluid pressure is boosted to approximately 3,500 psi prior to sending it to the well. Drawdowns of 800-1,000 psi are expected with produced oil of up to 1,800 BOPD. Pumps may be set and retrieved using slickline. Water will be chemically inhibited to mitigate corrosion.
8. Well Spacing
Rules 2 and 3 of CO 255 state that the pool shall not be opened in any well closer than 300 feet to the exterior boundary of the affected area. A search of the testimony and records submitted in support of CO 255 did not reveal any request for a 300-foot set back or any rationale for deviating from the standard statewide set back requirement presented in 20 AAC 25.055(a)(1). This regulation specifies that a wellbore may be open to test or regular production within 500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line. In their current application, BPXA did not provide testimony or evidence to support deviation from the 500-foot set back specified in 20 AAC 25.055(a)(1). In review of existing wells, it appears that all are set back more than 500 feet from the proposed pool boundary.
9. Reservoir Surveillance Plans
An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 4,000 feet TVDss. 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 production or injection service well. BP proposes to acquire bottom hole pressure surveys yearly from a number of wells equal to the number of governmental sections within the Schrader Bluff Pool that contain active producing wells. Data and results from all relevant reservoir pressure surveys will be reported annually and upon Commission request.
BPXA will run injection surveys on at least one-third of multiple sand injectors annually and on new multiple sand injectors within 12 months of injection to ensure injection conformance within the zone of interest. Cement bond logs are planned on each injector to confirm adequate zonal isolation behind pipe. Once a well is placed on injection, a water flow log or borax/pulsed neutron log may be run if necessary to confirm that injection is staying within zone.
10. Production Allocation
No changes are being proposed for allocating Schrader Bluff production, which is based on a minimum of two well tests per month as specified in CO 255. A single field wide allocation factor is applied equally to all pools within the MPU.
1. The expansion requested by BPXA for the area to be covered by pool rules for the Schrader Bluff Oil Pool is appropriate at this time. In addition, the Commission has determined that the pool rules area boundary requires additional modifications to better reflect the current understanding of the hydrocarbon distribution within the Schrader Bluff Oil Pool.
2. Consolidation and clarification of existing rules for the Schrader Bluff Oil Pool is appropriate.
3. To better protect the correlative rights of the owners and landowners of offset acreage, the set-back requirement for the Schrader Bluff Oil Pool must be changed to conform with 20 AAC 25.055(a)(1).
4. BPXA's current plan is to develop the Schrader Bluff Oil Pool within the boundaries of the Milne Point Unit.
5. Water injection will significantly improve recovery.
6. Miscible or immiscible gas injection is not part of the current plan of development.
NOW, THEREFORE, IT IS ORDERED:
1. This Conservation Order supersedes Conservation Order 255, dated July 2, 1990, and Conservation Order No. 283, dated December 30, 1991.
2. Conservation Orders 282, 347 and 390 remain in effect and are not modified by this order.
3. In addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), the following rules apply to the Schrader Bluff Oil Pool within the following affected area:
|Township - Range||Sections|
|T12N, R10E||1, 2, 11, 12|
|T12N, R11E||2, 3, 4, 5, 6, 7, 8, 9, 10, 11|
|T13N, R9E||1, N 1/2 of 2, SE 1/4 of 2, NE 1/4 of 11, 12, 13, 14, 23, 24|
|T13N, R10E||W 1/2 of 2, SE 1/4 of 2, 3, E 1/2 of 4, W 1/2 of 6, SE 1/4 of 6, 7, 8, 9, 10, 11, S 1/2 of 12, 13 to 36|
|T13N, R11E||18, 19, W 1/2 of 20, SW 1/4 of 27, 28 to 33, W 1/2 of 34|
|T14N, R9E||N 1/2 of NE 1/4 of 34, SE 1/4 of NE 1/4 of 34, NE 1/4 of SE 1/4 of 34, 35, 36|
|T14N, R10E||SW 1/4 of 31|
Rule 1 Pool Designation and Definition
The Schrader Bluff Oil Pool is defined as that accumulation of oil and found within stratigraphic sections that correlate with the stratigraphic section occurring in the Conoco Inc Milne Point A-1 well between the measured depths of 4,174 and 4,800 feet. (CO 255, Rule 1, modified by this order)
Rule 2 Well Spacing
Nominal 10-acre drilling units are established for the pool within the affected area. Each drilling unit shall conform to a quarter-quarter-quarter governmental section as projected. The pool shall not be opened in any well closer than 500 feet to the exterior boundary of the affected area. (CO 255, Rule 2, modified by this order)
Rule 3 Horizontal/High Angle Completions
A horizontal or high angle wellbore through the pool may be completed in one or more drilling units so long as the wellbore remains 500 feet from exterior boundary of the affected area. (CO 255, Rule 3, modified by this order)
Rule 4 Casing and Cementing Requirements
To provide proper anchorage for the blowout prevention equipment, surface casing shall be set at least 500 feet below the base of the permafrost, and the annulus shall be filled with cement. To withstand anticipated internal pressure and the potential forces generated by thaw subsidence and freeze back, the casing shall meet normal design criteria and have minimum axial strain properties of 0.5 percent in tension and 0.7 percent in compression. (CO 255, Rule 4)
Rule 5 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 new wells capable of unassisted flow of hydrocarbons 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.
c. SSSV or injection valves capable of preventing backflow to the surface must be installed at a depth below the permafrost on gas or miscible injection wells when in service.
d. Operation and performance tests must be conducted at intervals not exceeding six-months or as otherwise prescribed by the Commission to confirm that the SSV system, SSSV system, and associated equipment are in proper working condition. (New rule, this order)
Rule 6 Common Production Facilities and Surface Commingling
a. Production from the Schrader Bluff Oil Pool may be commingled on the surface with production from the Kuparuk River Oil Pool and the Sag River Oil Pool, Milne Point Unit, prior to custody transfer. (CO 255, Rule 6a, modified by this Order)
b. Schrader Bluff Oil Pool wells will use the allocation factor for oil, gas, and water derived from the CFP. (New rule, this order)
c. Each producing well shall be tested at least twice a month for a minimum of six hours each test. (CO 255, Rule 6b)
d. The Commission may require more frequent or longer well tests if the summation of the calculated monthly production volume for both pools is not within 10 percent of the actual LACT metered volume. (CO 255, Rule 6c)
e. The operator shall provide the Commission with a Well Test and Allocation Report of commingled regular production from all Milne Point Unit wells on April 1, 2003 and annually thereafter. The report will consist of a thorough analysis of all surveillance data relative to the well test system and the resulting allocation factors. (CO 255, Rule 6d, modified by this order)
Rule 7 Reservoir Pressure Monitoring
a. Prior to regular production a pressure survey shall be taken on each well to determine reservoir pressure. (CO 255, Rule 7a)
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. (CO 255, Rule 7b)
c. The datum for all surveys is 4,000 feet subsea. (CO 255, Rule 7c)
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. (CO 255, Rule 7d, modified by this order)
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. (CO 255, Rule 7e, modified by this order)
f. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted in accordance with part (e) of this rule. (CO 255, Rule 7f)
Rule 8 Pool-wide Waterflood Project
A waterflood project to maintain reservoir pressure must be implemented within eighteen months after regular production from the Schrader Bluff Oil Pool has started. Water injection must be implemented within the expanded S-Pad area within eighteen months of initial production. (CO 255, Rule 8a, modified by this order)
Rule 9 Gas-Oil Ratio Exemption
Wells producing from the Schrader Bluff 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. (CO 255, Rule 9, modified by this order)
Rule 10 Schrader Bluff Oil Pool Annual Reservoir Surveillance Report
An annual Schrader Bluff Oil Pool surveillance report is required by April 1 of each year. The report shall include, but is not limited to, the following:
a. Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir studies. (CO 283, Rule 2, Part 1, modified by this order)
b. Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval. (CO 283, Rule 2, Part 2, modified by this order)
c. Summary and analysis of reservoir pressure surveys within the pool. (CO 283, Rule 2, Part 3, modified by this order)
d. Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. (CO 283, Rule 2, Part 4, modified by this order)
e. Review of pool production allocation factors and issues over the prior year. (New rule, this order)
f. Future development plans. (New rule, this order)
g. Review of Annual Plan of Operations and Development. (New rule, this order)
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. (CO 255, Rule 10, modified by this order)
DONE at Anchorage, Alaska and dated August 23, 2002.
Cammy Oechsli Taylor, Chair
Alaska Oil and Gas Conservation Commission
Daniel T. Seamount, Jr., Commissioner
Alaska Oil and Gas Conservation Commission