|Re: THE APPLICATION OF||)||Conservation Order No. 456|
|PHILLIPS ALASKA, INC. for an||)|
|order to establish pool rules for||)||Kuparuk River Field|
|development of the Meltwater Oil||)||Meltwater Oil Pool|
|Pool in the Meltwater Participating||)|
|Area, Kuparuk River Field, North||)||August 1, 2001|
1. By letter dated March 12, 2001, Phillips Alaska, Inc. ("PHILLIPS") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") that defines the proposed Meltwater Oil Pool and prescribes rules to govern the development and operation of the Meltwater Oil Pool ("MOP"). PHILLIPS provided supplemental information on March 22, April 26, June 6, and June 19, 2001.
2. Notice of opportunity for public hearing was published in the Anchorage Daily News on March 23, 2001. A second public hearing notice changing the date of public hearing was published in the Anchorage Daily News on April 5, 2001.
3. The Commission did not receive a protest.
4. A hearing concerning PHILLIPS request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 333 W. 7th Avenue, Suite 100, Anchorage, Alaska 99501 on May 7, 2001. Concurrently, the Commission heard testimony concerning proposed injection of fluids for enhanced recovery from the MOP.
1. The proposed MOP is located in the western portion of Township 8 North and Range 7 East, Umiat Meridian, on Alaska State Leases ADL-373111, ADL-373112, ADL-389058, and ADL-389059. The MOP is located within and adjacent to the current boundaries of the Kuparuk River Unit ("KRU"), North Slope, Alaska.
2. PHILLIPS is the operator of the MOP. PHILLIPS, BP Exploration (Alaska) Inc., Unocal Corporation, ExxonMobil Corporation, and Chevron U.S.A. Inc are working interest owners. The State of Alaska is the surface owner.
3. PHILLIPS has applied to the Alaska Department of Natural Resources to expand the existing Kuparuk River Unit ("KRU") to encompass the southern half of the proposed MOP and approve a Meltwater Participating Area ("MPA").
4. PHILLIPS drilled three exploratory wells, Meltwater North 1, 2 and 2A, into the proposed MOP. Well and 3-D seismic data have been used to characterize the hydrocarbon accumulation within the proposed MOP.
5. The proposed MOP is defined as an accumulation of hydrocarbons that is common to, and correlates with, the interval between 6411' and 6974' measured depth ("MD") in the Meltwater North #2A well.
6. The proposed MOP is a sequence of very fine to fine-grained sandstones and associated mudstones that are late Cretaceous-aged (Cenomanian-Turonian) and lie within the Seabee Formation. The proposed MOP is informally divided into two stratigraphic units that are named, in ascending order, the Bermuda Interval and the Cairn Interval.
7. The Bermuda Interval is interpreted as a channel fill and lobate sandstone turbidite fan accumulation, deposited in a slope-apron environment below an incised Cenomanian age shelf. This interval lies between 6785' and 6974' MD in the Meltwater North #2A well, and, to date, is the only demonstrated productive interval within the proposed MOP.
8. The top of the Bermuda Interval dips approximately 2 to 3 degrees to the east-southeast. Complex faulting occurs along the western (updip) margin of the MOP. Shale filled channel complexes and stratigraphic pinch-outs act as lateral boundaries for the MOP.
9. Hydrocarbons are stratigraphically trapped in the Bermuda Interval, and their distribution is controlled by the distribution of sand. No gas cap or water has been encountered in Bermuda Interval within the MOP.
10. The MOP Bermuda interval is the stratigraphic equivalent and has similar lithology to the Tarn accumulation to the north. Drilling at Tarn has shown these deposits to be compartmentalized, primarily due to discontinuous sandstone distribution.
11. Petrophysical log, conventional core, sidewall core and cased-hole test data have been used to determine Bermuda Interval reservoir properties.
12. The Bermuda Interval sands are fine to very fine-grained, lithic-rich, and have common mudstone laminations and interbeds. X-ray diffraction analyses indicate clay content ranging from 15 to 25%, but the clay minerals occur dominantly as framework grains rather than as matrix.
13. Sandstone cores from the Bermuda Interval average 20% porosity and 12 millidarcies air permeability. Facies dependent water saturation values calculated from well logs range from 32% to 45%.
14. Initial reservoir pressure is approximately 2,400 psi and reservoir temperature is 135( F at datum level 5400'true vertical depth sub-sea ("TVDss").
15. Bermuda Interval crude oil gravity is 37( API, formation volume factor at reservoir pressure is about 1.33 reservoir barrels per stock tank barrel, solution gas-oil ratio is about 620 standard cubic feet of gas per barrel of oil ("SCF/B"), and the viscosity of the oil is 0.76 cps.
16. Recovery estimates range from 18% of original oil in place ("OOIP") by primary depletion to 29% with a waterflood (11% incremental recovery).
17. Model studies of alternating cycles of water and miscible gas injection ("MWAG") are estimated to increase recovery 20 % over primary depletion and 9% over waterflood. These model studies assumed a 20% hydrocarbon pore volume slug, which is approximately 46 billion cubic feet of gas ("BCF"). Total recovery with an MWAG process is estimated to be 38% OOIP.
18. The MWAG project is scheduled to commence within six months of production start-up. Existing Kuparuk River Field facilities will be used to supply Miscible Injectant ("MI"). An 8-inch MI injection line will be constructed from KRU Drill Site 2N to the Meltwater Drill Site 2P.
19. Secondary and tertiary recovery efforts will maintain reservoir pressure at or near initial conditions.
20. In the absence of field data, producer/injector interactions will likely be difficult to predict. Development plans call for minimizing the number of injection wells until producer/injector interactions are better understood. Producers will be converted to injector service as necessary in order to provide pressure support and minimize injectant cycling. Pattern configuration will be determined based upon reservoir performance.
21. Core flood studies suggest that water injection will not cause formation damage in the MOP Bermuda Interval.
22. PHILLIPS interprets the Cairn Interval within the proposed MOP as a marine, contourite-like, channel fill sand deposit that formed in a base of slope setting. This interval lies between 6411' and 6785' MD in the Meltwater North #2A well, and is a potential source of hydrocarbons.
23. Exploration targets within the Cairn Interval are offset along the eastern margin of the Bermuda hydrocarbon accumulation and are down dip from the western portion of the field.
24. Reservoir quality sandstones have not been encountered within Cairn Interval, but may be present near the center of the proposed MOP area. This interval is expected to be a stratigraphic trap.
25. Phillips will attempt to evaluate the productivity of the Cairn interval early in the development of the Bermuda interval.
26. Communication between the Bermuda and Cairn Intervals is uncertain at present.
27. The Bermuda Interval OOIP is estimated to be 125 million stock tank barrels of oil ("MMSTB"), with an additional possible 7 MMSTB OOIP within the Cairn Interval.
28. The current scope of the Meltwater Drill Site 2P development involves drilling 26 wells from a single new drill site.
29. PHILLIPS will construct a 24-inch common line and a 12-inch water injection line to connect Meltwater Drill Site 2P to the KRU 4-Corners. An 8-inch MI Injection line will be constructed from KRU Drill Site 2N to Meltwater Drill Site 2P.
30. PHILLIPS plans to commingle Meltwater production with Tarn and Kuparuk production in Kuparuk River Unit surface process facilities. Production from each pool will be allocated by using individual well production tests.
31. PHILLIPS proposes that the minimum total number of bottom-hole pressure surveys measured annually will be equal to the number of producing or injecting governmental sections.
1. Pool rules are appropriate for the initial development of the MOP.
2. Development of the MOP will occur within the proposed expanded portion of the Kuparuk River Unit.
3. The Bermuda Interval lying between 6785' and 6974' MD in the Meltwater 2A well will be the focus of initial development. The Cairn Interval will be tested and evaluated early in the Bermuda development program.
4. Insufficient information is available to include the Cairn interval in the MOP at this time.
5. Minimum well spacing units of 10 acres will not cause waste, compromise ultimate recovery, or jeopardize correlative rights. Ten-acre spacing will allow the operator sufficient flexibility to locate wells to accommodate geologic features throughout the MOP area.
6. Implementation of an enhanced recovery operation involving injection of alternating cycles of water and miscible gas, MWAG, will preserve reservoir pressure (energy) and enhance ultimate recovery.
7. Exception from the gas-oil-ratio limitations of 20 AAC 25.240 is appropriate provided enhanced recovery operations begin within six months of regular production.
8. Monitoring of reservoir performance by measurement of production and reservoir pressure using standard industry practices on a regular basis will help ensure proper management of the pool.
9. Commingling of MOP fluids at the surface with produced fluids from the Tarn and Kuparuk Pools is appropriate provided there are adequate well tests to assure accurate production allocation.
NOW, THEREFORE, IT IS ORDERED THAT the following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), apply to the affected area described below:
|T8N||R7E||1 through 36: All State lands|
Rule 1 Field and Pool Name and Classification
The field is the Kuparuk River Field. The hydrocarbon bearing Bermuda interval underlying the affected area is an oil and gas reservoir called the Meltwater Oil Pool (MOP).
Rule 2 Pool Definition
The MOP is defined as the accumulation of hydrocarbons common to, and correlating with, the interval between the 6785' and 6974' MD in the Meltwater North #2A well.
Rule 3 Spacing Units
Spacing units within the pool will be 10 acres. The pool shall not be opened in any well closer than 500 feet to an external boundary of the affected area.
Rule 4 Casing and Cementing Practices
a) In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface.
b) In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' MD below the base of the permafrost.
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. The wells must be equipped with a landing nipple at a depth, which is suitable for the future installation of a downhole flow control device to control subsurface flow.
c. Surface safety valve systems must be maintained in good working order at all times and must be tested at six-month intervals or on a schedule prescribed by the Commission.
Rule 6 Common Production Facilities and Surface Commingling
a) Production from the MOP may be commingled with production from the Tarn and Kuparuk River oil pools in surface facilities prior to custody transfer.
b) The allocation factor for the MOP produced fluids will be based on Meltwater well tests. The allocation factor will be calculated on a monthly basis utilizing the Satellite Allocation Technique detailed on Exhibit 18 of the written testimony dated April 26, 2001, and it will be capped at 1.02000 on an interim basis subject to review after the first year of regular production is evaluated.
c) A hearing will be scheduled for September 12, 2002 to review the allocation quality, the impact of allocation factor cap on produced volumes reported to Meltwater Oil Pool and the Kuparuk River Oil Pool and reconsider Rule 7 in its entirety.
d) Each producing well must be tested a minimum of twice per month.
e) The Commission may require more frequent or longer tests if the allocation quality deteriorates.
f) The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.
g) The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report.
Rule 7 Reservoir Pressure Monitoring
a) Prior to regular production or injection, an initial pressure survey must be taken in each well.
b) The minimum number of bottom-hole pressure surveys acquired each year will equal the number of governmental sections within the MOP that contain active wells. A minimum of four surveys will be required each year in representative areas of the MOP. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement.
c) The reservoir pressure datum will be 5,400 feet 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 all relevant reservoir 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.
f) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule.
Rule 8 Gas-Oil Ratio Exemption
Wells producing from the MOP are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a).
Rule 9 Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations
Enhanced oil recovery or reservoir pressure maintenance operations must be initiated within six months of the start of regular production from the MOP.
Rule 10 Reservoir Surveillance Report
An annual reservoir surveillance report for the prior calendar year will be 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 implementation and reservoir management summary including results of reservoir simulation techniques.
b) Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval.
c) Summary and analysis of reservoir pressure surveys within the pool.
d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring.
e) Review of pool production allocation factors and issues over the prior year.
f) Future development plans.
g) Review of Annual Plan of Operations and Development.
Rule 11 Production Anomalies
In the event of oil production capacity proration at or from the Kuparuk River Unit facilities, all commingled reservoirs produced through the Kuparuk River Unit facilities will be prorated by an equivalent percentage of oil production, unless this will result in surface or subsurface equipment damage.
Rule 12 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 or jeopardize correlative rights, and is based on sound engineering and geoscience principles.
Rule 13 Statewide Requirements
Except where a rule stated above substitutes for a statewide requirement, statewide requirements under 20 AAC 25 apply in addition to the above rules.
DONE at Anchorage, Alaska and dated August 1, 2001.
Camillé Oechsli Taylor, Chair
Alaska Oil and Gas Conservation Commission
Daniel T. Seamount, Jr., Commissioner
Alaska Oil and Gas Conservation Commission
Julie M. Heusser, Commissioner
Alaska Oil and Gas Conservation Commission