STATE OF ALASKA
 ALASKA OIL AND GAS CONSERVATION COMMISSION
3001 Porcupine Drive
Anchorage Alaska 99501-3192
Re: THE APPLICATION OF BP                    )                       Conservation Order No. 423
EXPLORATION (ALASKA) INC. to                )
present testimony for classification of a new   )                       Milne Point Field
pool and the establishment of pool rules for    )                       Milne Point Unit
development of the Sag River oil pool in the    )                       Sag River oil pool
Milne Point Unit.                                          )

                                                                                         May 6, 1998
 

IT APPEARING THAT:

By letter dated December 5, 1997, BP Exploration (Alaska) Inc. ("BPX") requested a public hearing to present testimony to define the Sag River oil pool in the Milne Point Unit and establish pool rules for development and production of the reservoir.

The Commission published notice of public hearing in the Anchorage Daily News on December 23, 1997.

A hearing concerning the matter of the applicant's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 am on January 27, 1998.

FINDINGS:

The vertical limits of the Sag River oil pool may be defined in the Milne Point Unit A-01 ("MPA-01") well between the measured depths of 8810 feet to 8884 feet, which appears to contain a typical and representative stratigraphic section of the reservoir

The MPA-01 well is located near Kavearak Point in Section 23, Township 13 North, Range 10 East, Umiat Meridian.

The portion of the pool that BPX proposes to develop is within the Milne Point Unit.

BPX evaluated five Sag River wells within the proposed project area with either conventional core or rotary sidewall cores and borehole geophysical data and an additional six Sag River wells with borehole geophysical data only.

BPX integrated petrophysical information with an extensive seismic grid throughout the proposed project area to develop more complete knowledge of the reservoir.

The Sag River Formation is late Triassic to early Jurassic in age and consists primarily of thin marine shelf sand intervals throughout the central portion of the North Slope.

BPX has subdivided the Sag River Formation within the Milne Point Unit into four laterally extensive sub-zones, A through D. The zones are fairly uniform in thickness and have similar reservoir properties.

Zone A is the basal Sag River sandstone unit, which uncomformably overlies the Shublik Formation. The interval in the proposed project area is composed almost entirely of non-reservoir sandstone, with porosity to 18%, permeability to 1.2 millidarcies, and an average gross thickness of about 16 feet.

Zone B is the primary Sag River reservoir interval, with porosity to 21%, permeability to 23 millidarcies, and an average gross thickness of 30 feet.

Zone C is the uppermost Sag River Formation sandstone interval. Zone C is generally non-reservoir with porosity to 17%, permeability to 2.9 millidarcies and an average gross thickness of 10 feet.

Zone D is non-reservoir siltstone and shale at the top of the Sag River Formation; its average gross thickness is about 21 feet.

The combination of moderate to good porosity and poor permeability observed in zones A through C are the result of two processes, bioturbation and diagensis.

Core data shows extensive carbonate cementation and greater grain densities in Zones A and C.

BPX estimates Sag River net pay to range from 9 to 18 feet and permeability-thickness to range from 30 to 68 millidarcy-feet within the proposed project area.

The trapping mechanism observed in the Sag River oil pool is predominately structural, consisting of three-way anticlinal closures sealed against the downthrown side of faults, with throws generally greater than 50 feet.

An orthogonal fault pattern segments the oil column into three known equilibration regions throughout the project area. The known oil-water contacts are at 9150 feet, 9050 feet, and 8950 feet subsea.

Flexibility in well placement will be needed because of the area's structural complexity and complex faulting.

The Ivishak, Shublik and Lisburne Formations, which are productive elsewhere on the North Slope, have not been shown to contain more than residual hydrocarbon saturation in the proposed project area. The Ivishak Formation contains high water saturation even when encountered in fault blocks above the Sag River oil-water contacts.

BPX used permeability values on the order of ten times those observed in core data to realize accurate simulation of well performance in the Sag River Formation

Core and borehole geophysical data show extensive fracturing within the Sag River Formation.

BPX estimates the original oil-in-place (OOIP) at 62 MM STB oil and the reservoir area about 8500 acres based upon seismic and log data.

Sag River crude oil properties are: gravity 39.2( API, solution gas-oil ratio 974 SCF/STB, formation volume factor 1.56 RB/STB, viscosity .277 centipoise, gas gravity .8, and bubble point pressure 3513 psi.

BPX recorded an initial reservoir pressure of 4425 psi and a temperature of 235( F at 8750 feet subsea datum.

BPX estimates primary recovery at about 15% of OOIP assuming solution gas drive with some limited aquifer pressure support.

Some form of gas or water injection, or a combination of both, will be needed to obtain maximum ultimate recovery. Full field model studies by BPX indicates as much as 38% of OOIP may be recovered depending on the timing and type of pressure maintenance project implemented.

The current development plan proposed by BPX will require 25 wells, with 16 producers and 9 injection wells.

BPX plans on surface commingling Sag River production with Kuparuk River and Schrader Bluff production for processing at existing Milne Point surface facilities. Production from each pool will be determined by using production tests in a common test separation facility. BPX proposes to apply a single allocation factor for all pools in the MPU production system.

BPX has no plans to commingle the separate pools within any wellbore in the Milne Point Unit.

BPX will use electric submersible pumps (ESP) for primary artificial lift. ESP wells will not utilize packers or subsurface safety valves as part of their completion.

BPX proposes to measure reservoir pressure annually in newly drilled and existing wells.

Enhanced recovery injection will use gas from the Sag River oil pool, and may require additional make up gas from the Kuparuk River and Schrader Bluff pools. High-pressure gas lines may be added to allow gas injection into the Sag River oil pool.

BPX plans on using alternative completions methods such as different liners types, open hole completion, multi-laterals, horizontal wellbores and combinations of the above to optimize drainage and improve recovery.

 CONCLUSIONS:

Pool rules for the initial development of the Sag River oil pool are appropriate at this time.

Initial development of the Sag River oil pool will occur on leases participating in the Milne Point Unit.

The eastern and northern productive limits of the Sag River interval within the Milne Point Unit vicinity have not been delineated.

Well spacing units of 40 acres will allow the operator sufficient flexibility to locate wells to accommodate geologic, stratigraphic and structural factors throughout the project area.

Alternative completion practices will allow flexibility and enable the operator to optimize drainage and maximize ultimate recovery.

Early implementation of an enhanced recovery operation to support reservoir pressure will preserve reservoir energy and enhance ultimate recovery.

Sag River production will be allocated using exiting test facilities and methods applied to the Kuparuk River and Schrader Bluff pools.

Reservoir pressure will be measured at injection and production wells using standard industry practices on a regular basis to manage production and monitor reservoir performance.

Exception from the gas-oil-ratio limitations of 20 AAC 25.240 is appropriate provided a pressure maintenance project starts within six months of the start of regular production.
 

NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth, in addition to statewide requirements under 20 AAC 25 apply to the following affected area referred to in this order.

Umiat Meridian

 T12N
R11E
Sections 2, 3, 11

T13N
R11E
Sections 18, 19, 29, 30, 31, 32

T13N
R10E
Sections 2, 3, 4, 5, 6, 9, 10, 11, 12, 13, 14, 15, 22, 23, 24, 25, 36

T14N
R10E
Sections 29, 30, 31, 32, 34, 35

T14N
R9E
Sections 25, 36

Rule 1 Field and Pool Name

The field is the Milne Point River Field. Hydrocarbons underlying the affected area within the Sag River Formation constitute a single oil and gas reservoir called the Sag River oil pool.

Rule 2 Pool Definition

The Sag River oil pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 8810 feet and 8884 feet in the Milne Point Unit No. A-01 well.

Rule 3 Spacing Units

Nominal spacing units within the pool will be 40 acres. The pool shall not be opened in any well closer than 500 feet to an external boundary where ownership changes.

Rule 4 Casing and Cementing Practices

Conductor casing shall be set at least 75 feet below ground level and cemented to surface.

Surface casing shall be set at least 500 feet below the permafrost and cemented to the surface.

Rule 5 Completion Practices

The following alternative completion methods are allowed:

Liners, to include but not limited to slotted, pre-drilled, pre-packed and sintered, or a combination thereof, landed inside of cased hole and which may be gravel or frac packed.

Open-hole completions provided that the casing is set not more than 100 feet above the uppermost oil bearing zone.

Multi-lateral completions, in which more than one branch of the wellbore is completed in the Sag River oil pool, connected to a single common wellbore with production gathered and routed through common production tubing to the surface.

Injection into the Schrader Bluff, Kuparuk and/or the Sag River pools using a common wellbore with packers and down-hole flow control devices to regulate injection into each interval.

The Commission may approve other completion methods upon application.

Rule 6 Well Completions

Production or injection wells may be completed with tapered casing provided a sealbore, packer, or other isolation device is positioned not more than 200 feet above the top of the productive interval.

Rule 7 Automatic Shut-in Equipment

All wells capable of unassisted flow of hydrocarbons must be equipped with a fail-safe automatic surface safety valve.

Injection wells must be equipped with a double check valve arrangement.

Surface safety valves must be tested at six-month intervals.

Rule 8 Common Production Facilities and Surface Commingling

Production from the Sag River oil pool may be commingled with production from the Kuparuk River and Schrader Bluff oil pools in surface facilities prior to custody transfer.

Each producing Sag River well must be tested a minimum of two times per month.

The Commission may require more frequent or longer tests if the allocation quality deteriorates.

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

Rule 9 Reservoir Pressure Monitoring

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

At least one bottom-hole pressure survey per four producing or injecting governmental section shall be measured annually. No less than four reservoir pressures will be measured annually. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement.

The reservoir pressure datum will be 8750 feet subsea.

Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, representative ESP pressure measurements, and open-hole formation tests.

Data and results from pressure surveys must be reported quarterly on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412 but must be available to the Commission upon request.

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

Rule 10 Gas-Oil Ratio Exemption

Wells producing from the Sag River oil pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply.

Rule 11 Pressure Maintenance Project

A pressure maintenance project must be initiated within six months after the start of regular production from the Sag River oil pool.

Rule 12 Reservoir Surveillance Report

A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following:

Progress of enhanced recovery project implementation and reservoir management summary including engineering and geotechnical parameters.

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

Analysis of reservoir pressure surveys within the pool.

Results and where appropriate, analysis of production and injection log surveys, tracer surveys and observation well surveys.

Review of pool allocation factors over the prior year.

Future development plans.

Rule 13 Production Anomalies

In the event of oil production capacity proration at or from the Milne Point Unit facilities, all commingled reservoirs produced through the Milne Point Unit facilities will be prorated by an equivalent percentage of oil production, unless this will result in surface or subsurface equipment damage.

Rule 14 Administrative Action

Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles.

DONE at Anchorage, Alaska and dated May 6, 1998.
______________________________________
David W. Johnston,
Chairman
______________________________________
Robert N. Christenson, P.E.
Commissioner
 

Conservation Order No. 423 Page

May 6, 1998

Return To The Conservation Orders Index