3001 Porcupine Drive

Anchorage Alaska 99501-3192

Re:THE APPLICATION OF ARCO ) Conservation Order No. 443
ALASKA, INC. to classify the )
Alpine Oil Pool and establish ) Colville River Field
rules for development ) Alpine Oil Pool
March 15, 1999


1. By letter dated October 9, 1998, ARCO Alaska, Inc. ("ARCO") requested a public hearing to present testimony to define the Alpine Oil Pool and establish rules for development.

2. The Commission published notice of public hearing in the Anchorage Daily News on October 16, 1998.

3. A hearing concerning the matter of the applicantís request was convened in conformance with 20 AAC 25.540 at the Commissionís offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 a.m. on December 3, 1998.


1. The Alpine Oil Pool ("AOP") is located adjacent to the National Petroleum Reserve-Alaska, within the Colville River Delta, on Alaskaís North Slope.

2. Working interest owners are ARCO, Anadarko Petroleum Corporation and Union Texas Alaska, LLC. Landowners are the State of Alaska and the Arctic Slope Regional Corporation. The owners have agreed to voluntarily integrate their respective interests to provide for the unitized management, development and operation of the pool under the Colville River Unit Agreement. ARCO is the operator of the Colville River Unit.

3. The currently known productive limits of the AOP lie entirely within the Colville River Unit.

4. The AOP was discovered in 1994 with the drilling of the Bergschrund #1 exploratory oil well. ARCO has subsequently delineated the pool with 11 exploratory wells, two development wells and a 3-D seismic survey.

5. The AOP may be defined between 6876 feet and 6976 feet measured depth in the Bergschrund #1 well, which appears to contain a typical and representative stratigraphic section of the reservoir.

6. The AOP is contained within the Alpine Sandstone.

7. The Alpine Sandstone is a Late Jurassic-aged, informal member of the Kingak Formation. It is stratigraphically the highest sandstone unit within the Kingak Formation in the Colville Delta area.

8. The Alpine Sandstone is an Ellesmerian, shallow marine sand deposited on a southerly prograding shelf, elongated in an east-west direction. The interval consists of very fine to fine-grained, moderate to well sorted quartzose sandstone with variable glauconite and clay content. Bedding is almost horizontal, dipping about one to two degrees to the southwest. Core porosity and permeability ranges are 15% to 23% and 1 to 160 millidarcies, respectively.

9. The AOP appears stratigraphically trapped by pinch-out of Alpine Sandstone into time equivalent shales of the Kingak Formation.

10.No oil-water or gas-oil contacts have been observed to date in the AOP.

11.Faulting currently delineated in the AOP is minor, consisting of several northwest trending, down the west, normal faults with throws averaging less than 30 feet.

12.None of the stratigraphic and structural discontinuities currently identified in the AOP appear to have caused any compartmentalization of the reservoir.

13.In addition to the AOP, ARCO has identified several other oil-bearing sandstone intervals with possible productive potential in the Colville River Delta area. ARCO plans to evaluate the commercial productivity of these intervals when developing the AOP.

14.ARCO proposes to dispose of drilling waste in the annuli of wells authorized by the Commission for that purpose under 20 AAC 25.080.

15.Typical AOP development wells will have surface casing set in the basal shales of the Upper Cretaceous Schrader Bluff Formation and intermediate casing set in shales of the Lower Cretaceous Miluveach Formation.

16.The intermediate casing annulus of a typical AOP well will be in contact with approximately 1800 vertical feet of the Upper Cretaceous Seabee Formation, a predominately mudstone interval with silt and sandstone interbeds. The sandstones are very fine to fine-grained and range from unconsolidated to consolidated.

17.Over 1000 feet of shales and siltstones of the Schrader Bluff Formation will provide an upper barrier for annular disposal. Marine shales and claystones of the Lower Cretaceous Torok Formation will provide a lower barrier.

18.Calculated water salinity ranges from 15,000 to 18,000 milligrams per liter (mg/l) total dissolved solids (TDS) throughout the Cretaceous and older stratigraphic section in the Colville Delta area. Water samples collected from drill stem and production testing of several wells in the Colville Delta area yielded 18,500 to 24,000 mg/l TDS.

19.The U.S. Environmental Protection Agency ("EPA"), in compliance with the provisions of the Safe Drinking Water Act (SDWA), has authorized ARCO to inject non-hazardous industrial waste through class I injection wells at the Colville Field of the Colville River Unit. (EPA Alpine Class I well permit, dated February 3, 1999.)

20.Petrophysical analysis indicates that thick sections of the Seabee Formation have less mechanical strength than the basal Schrader Bluff Formation.

21.Data available at this time indicate that annular disposal into the Seabee Formation can occur in AOP development wells, which have been authorized for that purpose by the Commission under 20 AAC 25.080, without causing fractures proximal to the surface casing shoe.

22.Development drilling to the Alpine Oil Pool is projected to begin in the first quarter of 1999. Commercial production is expected to begin in June 2000.

23.ARCO plans to drill a large number of high departure horizontal wells, with interwell spacing dictated by reservoir performance.

24.ARCO proposes to establish the Alpine Participating Area within the Colville River Unit next year. ARCO will seek additional pool rules regarding drilling and completion practices, production practices, reservoir monitoring and other topics, as appropriate, following the completion of initial development wells and prior to commercial production.

25.Initial reservoir pressure of the AOP is 3175 psig at 6864 feet TVDss. Average reservoir temperature is 160° F. Fluid samples indicate the reservoir is undersaturated with a bubble point pressure of 2454 psig. Solution GOR is 850 SCF/STB. Oil gravity and viscosity at reservoir conditions are 40° API and 0.46 cp., respectively.

26.Volumetric estimates of original oil-in-place range from 900 to 1100 MMSTB.

27.ARCO has divided the scope of currently planned AOP development into two phases. Phase one provides for 50 wells and phase two for 42 additional wells. Under the plan, total development will include 32 horizontal wells and 60 vertical wells (through the reservoir), with well spacing of 275 acres per horizontal well and 160 acres per vertical well. ARCO may revise the development plan following assessment of miscible-water-alternating-gas (MWAG) for EOR throughout the field. Under a revised MWAG development plan, well spacing could be reduced to 135 acres per well, with as many as 140 wells throughout the field, in order to take full advantage of the MWAG process.

28.ARCO'S plan for secondary oil recovery includes water and gas injection, beginning concurrently with production startup. ARCO will conduct studies to optimize depletion plans based on initial production and injection performance, and will consider the viability of miscible gas injection.

29.ARCO proposes to measure reservoir pressure periodically in injection wells with static measurements and other industry standard techniques at a datum level of 7000í TVDss. ARCO does not propose to take pressure measurements in producing horizontal wells because production models show these wells take an inordinately long period of time to stabilize.

30.ARCO requests authorization to test production wells less frequently than once per month as required under statewide regulation, 20 AAC 25.230.

31.The Alaska Department of Natural Resources requests that a minimum of two well tests per month per well be required as the initial testing frequency in order to ensure that the well tests accurately represent oil, gas and water production rates and production volumes from the various tracts that comprise the AOP. (Kenneth A. Boyd, letter dated Dec. 16, 1998)

32.Reservoir model simulation will be used to allocate production to participating tracts in the Colville River Unit. Accurate well test data is necessary to calibrate the reservoir model.


1. Defining the AOP and establishing rules for initial development is appropriate at this time.

2. The Alpine Oil Pool is not completely delineated at this time.

3. Recovery methods to enhance and maximize ultimate recovery from the AOP are currently being evaluated.

4. Statewide spacing requirements under 20 AAC 25.055, which limit drilling one well per government quarter section, may not provide adequate flexibility in well locations to optimally develop the AOP.

5. There are no freshwater aquifers in the Colville River Unit.

6. The depth and thickness of the proposed receiving zone and confining zone are sufficient to demonstrate confinement of drilling waste.

7. Exception to the gas-oil ratio limitations of 20AAC 25.240 is appropriate provided a pressure maintenance project is begun within six months of regular production and the requirements of 20 AAC 25.240(c) are met.

8. Reservoir pressure should be measured in wells using standard industry practices on a regular basis to manage production and monitor reservoir performance.

9. A minimum of two well tests per month will help ensure that accurate well test data is available for reservoir management and production allocation.

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

Umiat Meridian

T11N R4E Section 1, 2, 3, 4, 5, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27.


T11N R5E Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 29, 30.


T12N R4E Sections 24, 25, 26, 27, 33, 34, 35, 36.


T12N R5E Sections 13, 14, 15, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36.


Rule 1 Field and Pool Name

The field is the Colville River Field. Hydrocarbons underlying the affected area within the defined pool interval of the Kingak Formation constitute a single oil and gas reservoir called the Alpine Oil Pool.

Rule 2 Pool Definition

The Alpine Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6876 feet and 6976 feet in the Bergschrund No. 1 well.

Rule 3 Well Spacing

Development wells may not be completed within 500 lineal feet of another Alpine Oil Pool development well nor closer than 500 feet from the exterior boundary of the affected area.

Rule 4 Drilling and Completion Practices

(a.) After drilling no more than 50 feet below a casing shoe set in the Alpine Oil Pool, a formation integrity test must be conducted. The test pressure need not exceed a predetermined pressure.
(b.) Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles.
(c.) Permit(s) to Drill deviated wells within the Alpine Oil Pool shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of 20 AAC 25.050(b).
(d.) A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite.

Rule 5 Automatic Shut In Equipment

(a.) All production wells must be equipped with a fail-safe automatic surface safety valve (SSV) and a surface controlled subsurface safety valve (SSSV).
(b.) Injection wells must be equipped with a double check valve arrangement.
(c.) Safety Valve Systems (SVSís) must be tested on a six-month frequency. Sufficient notice must be given so that a representative of the Commission can witness the tests.
(d.)Subsurface safety valves may only be removed after demonstrating to the Commission that the well is not capable of unassisted flow of hydrocarbons. Sufficient notice must be given so that a representative of the Commission can witness the tests.

Rule 6 Reservoir Pressure Monitoring

(a.) Prior to regular injection, an initial pressure survey shall be taken in each injection well.
(b.) A minimum of six bottom-hole pressure surveys shall be measured annually. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement.
(c.) The reservoir pressure datum shall be 7000 feet TVD subsea.
(d.) 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, and open-hole formation tests.
(e.) Data and results from pressure surveys shall be reported annually 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 shall be made available to the Commission upon request.
f.) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule.

Rule 7 Gas-Oil Ratio Exemption

Wells producing from the Alpine 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 8 Reservoir Surveillance Report

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

(a.) Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters.
(b.) Voidage balance by month of produced fluids and injected fluids.
Analysis of reservoir pressure surveys within the pool.
(c.) Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys.
(d.) Future development plans,

Rule 9 Well Testing

(a.) All wells must be tested at least twice per month.
(b.) The operator shall optimize stabilization and test duration of each test to obtain a representative test.
(c.) The operator shall record well and field-operating conditions appropriate for maintaining an accurate field production history.
(d.) The operator shall install and maintain test separator meters and gas system meters in conformance with the API Manual of Petroleum Measurement Standards.
(e.) The operator shall maintain records to allow verification of approved production allocation methodologies.

Rule 10 Administrative Action

Upon proper application or its own motion, 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, or compromise ultimate recovery and is based on sound engineering principles.

DONE at Anchorage, Alaska and dated March 15, 1999.

Robert N. Christenson, P.E., Chairman

Camillé Oechsli, Commissioner

David W. Johnston, Commissioner

Conservation Order Index