|Re: The APPLICATION OF||)||Conservation Order No. 452|
|PHILLIPS Alaska, Inc. ("PHILLIPS")||)||Prudhoe Bay Field|
|for an order to establish pool rules for||)||Midnight Sun Participating Area|
|development of the Midnight Sun Oil Pool||)||Midnight Sun Oil Pool|
|in the Midnight Sun Participating Area,||)|
|Prudhoe Bay Field, North Slope Alaska.||)|
|November 15, 2000|
IT APPEARING THAT:
1. By letter dated February 17, 2000 and application dated May 3, 2000, Phillips Alaska, Inc. ("PHILLIPS") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to establish pool rules for continued production of the Midnight Sun Oil Pool. PHILLIPS provided supplemental information on June 12, 2000.
2. Notice of Public Hearing was published in the Anchorage Daily News on February 25, 2000, and a hearing was scheduled for April 4, 2000. On March 27, 2000, PHILLIPS requested the hearing be rescheduled. On April 1, 2000, a Notice of Cancellation of Public Hearing was published in the Anchorage Daily News. A second Notice of Public Hearing was published in the Anchorage Daily News on May 10, 2000, and the hearing was rescheduled to June 13, 2000.
3. A hearing concerning the applicant's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 on June 13, 2000. Concurrently, the Commission heard testimony concerning proposed injection of fluids for enhanced recovery in the Midnight Sun Oil Pool.
1. PHILLIPS presented testimony in support of an application for pool rules and area injection order for the proposed Midnight Sun Oil Pool ("MSOP") on June 13, 2000.
2. The Midnight Sun Participating Area ("MSPA") is located within and adjacent to the Prudhoe Bay Unit ("PBU") on Alaska's North Slope.
3. Working interest owners are PHILLIPS, ExxonMobil Corporation and BP Exploration (Alaska) Inc. ("BPXA"). The State of Alaska is the surface owner.
4. The Commission approved the designation of BP Exploration (Alaska) Inc. ("BPXA") as sole operator of the PBU effective July 1, 2000.
5. BPXA is the designated operator of all wells within one-quarter mile of the proposed area.
6. The MSOP is a name proposed to describe an accumulation of hydrocarbons trapped within the Kuparuk Formation. This accumulation is located outside of the previously defined Kuparuk Oil Pool area within the PBU. The current, estimated limits of the MSOP lie within, and adjacent to, the PBU.
7. The MSOP was discovered in 1997 during the drilling of the Sambuca #1 well, later renamed the PBU E-100. This well encountered 100 feet of gross hydrocarbon volume, with 36 feet of gas above the oil column.
8. One delineation well, the Midnight Sun #1 (later renamed the PBU E-101) was drilled from E-pad in October 1998.
9. Well and seismic data have been used to characterize the accumulation within the MSOP.
10. The MSOP is defined as the accumulation of hydrocarbons that are common to, and which correlate with, the Kuparuk Formation accumulation in the PBU E-100 well between 11,662 and 11,805 feet measured depth (MD).
11. Petrophysical log, conventional core, RFT, and production data have been used to determine the MSOP reservoir properties.
12. A trap of combined structural and stratigraphic elements delineates the MSOP. It is bounded to the north by the Sambuca fault, to the west by the Prudhoe Mid-Field fault, to the South by the Prudhoe-bounding fault system with an apparent stratigraphic pinch out to the east.
13. The MSOP is contained within the Kuparuk Formation of Lower Cretaceous age (153-115 million years before present). Within the participating area, the Kuparuk Formation is stratigraphically complex, and is characterized by rapid changes in thickness, sedimentary facies and local diagenetic cementation.
14. The interval lies approximately 8,000 feet below sea level with a typical gross sand thickness of about 110 feet.
15. Within the MSOP, the Kuparuk Formation can be informally divided into lower and upper units.
16. The lower Kuparuk unit is about 40 feet thick, and is subdivided into two lithologic intervals. The basal non-productive sandstone is approximately five feet thick, with a discontinuous distribution that contains abundant glauconite and minor detrital shale. The overlying unit is continuous, very fine to fine grained and quartz-rich reservoir-quality sandstone.
17. The upper unit ranges from 0 to 70 feet in thickness, and consists of poor to well sorted sandstone interbedded with minor amounts of muddy siltstone. The sandstones contain varying amounts of glauconite and siderite and are prone to reductions in porosity and permeability due to intergranular siderite cementation and compaction.
18. Mean porosity and permeability in the reservoir interval of the lower Kuparuk unit are 27.3% and 760 millidarcies, respectively. Average water saturation is 12.6% in the reservoir interval of the lower Kuparuk unit.
19. Mean porosity in the upper Kuparuk unit is 20.7% and mean permeability is 200 millidarcies. Average water saturation is 26.4% in the upper Kuparuk Formation.
20. The estimated original oil in place ("OOIP") in the MSOP ranges from 40 to 60 MMBO. Total gas in place is estimated to be 100 to 130 bscf. Free gas volume associated with the gas cap is estimated to range between 60 and 80 bscf.
21. The MSOP gas-oil contact lies at a true vertical subsea depth of 8,010 feet, based on Repeat Formation Test data. No oil-water contact has been observed.
22. Heavy oil was encountered below a true vertical depth of 8,107 feet in the PBU E-101 well. The areal extent of this heavy oil accumulation is uncertain.
23. MSOP crude oil properties were obtained from a recombined sample from the PBU E-101 well. API gravity of the oil is approximately 25.5 degrees, solution gas-oil ratio is 717 scf/stb, formation volume factor is 1.33 reservoir barrels per stock tank barrel and viscosity measures 1.68 cp at the reservoir bubble point pressure, 4045 psia.
24. Initial reservoir pressure is 4058 psia and temperature is 160 degrees at the reservoir datum of 8050 true vertical depth sub sea.
25. The MSOP has low structural dip, good vertical permeability and contains a relatively large gas cap.
26. MSOP production started from the PBU E-100 in October of 1998. Production from the well was restricted to mitigate gas coning and was shut-in to limit depletion.
27. The PBU E-101 production was affected by gas under-running and has been restricted to 5000 BOPD.
28. Based on reservoir data evaluation and simulation studies, PHILLIPS has planned a three-well field with a midfield waterflood. The plan includes drilling one additional upstructure producing well and converting one well to injection.
29. Recovery estimated from reservoir simulation of primary depletion is approximately 14% of the OOIP, about 6 to 8 MMBO. Estimates of incremental waterflood recovery ranges from 15 to 25% of the OOIP, or 10 to 15 MMBO, with 0.7 pore volumes of water injected.
30. Initial waterflood will begin third quarter 2000 with source water injection at E-Pad. Produced water from Gathering Center One (GC1) may supplement the flood at some point in the future.
31. PHILLIPS has requested minimum well spacing of 80 acres to allow flexibility in planning infill and/or peripheral wells.
32. PHILLIPS will measure initial reservoir pressure in producers and injectors. Periodic reservoir pressure measurements will be done to monitor reservoir performance. Other surveillance such as profile logs may be applied where multiple intervals are open for production or injection.
33. Casing and cement plans will adhere to 20 AAC 25.030 with designs based on performance factors to withstand permafrost and downhole conditions.
34. PHILLIPS proposes to commingle MSOP fluids with Ivishak Participating Area (IPA) fluids on the surface at E-Pad. Commingled fluids will be transferred to the GC1 production facilities for processing and shipment to Pump Station One.
35. Initial production will be allocated to the MSOP on the basis of monthly well tests in IPA facilities as previously approved by the Commission. A new metering skid, to be installed, will continuously meter Midnight Sun production prior to commingling with IPA fluids.
36. A 15 kV power line from GC1 to the Midnight Sun facilities at E-pad will provide power for the new Midnight Sun drill site equipment.
1. Pool rules for the development and delineation of the Midnight Sun Oil Pool are appropriate at this time.
2. Initial development will be conducted on leases within the Prudhoe Bay Unit.
3. Minimum well spacing of 80 acres will not cause waste, compromise ultimate recovery or jeopardize correlative rights.
4. Implementation of water injection will preserve reservoir energy and increase ultimate recovery from the pool by a significant amount.
5. Monitoring of reservoir performance by measurement of production and reservoir pressure on a regular basis will help to ensure proper management of the pool.
6. Commingling MSOP and IPA fluid at the surface is appropriate provided there are adequate well tests to assure accurate production allocation.
NOW, THEREFORE, IT IS ORDERED THAT the following rules apply to the following affected area:
|T12N||R13E||Sec 25, S 1/2; Sec 36, N 1/2, SE 1/4, E 1/2 of SW 1/4|
|T12N||R14E||Sec 29, all; Sec 30, S 1/2, S 1/2 of NE 1/4, S 1/2 of NW 1/4;|
|Sec 31, N 1/2, SW 1/4, N 1/2 of SE 1/4; Sec 32, NW 1/4|
|T12N||R14E||Sec 28, W 1/2, W 1/2 of NE 1/4, W 1/2 of SE 1/4|
Rule 1 Field and Pool Name
The field is known as the Prudhoe Bay Field. Hydrocarbons underlying the affected area and within the referenced intervals of the Kuparuk Formation constitute a single oil and gas reservoir called the Midnight Sun Oil Pool.
Rule 2 Pool Definition
The Midnight Sun Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the intervals between the measured depths of 11,662 feet and 11,805 feet in the PBU E-100 well.
Rule 3 Spacing Units
Nominal spacing units within the pool will be 80 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
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 feet, MD, below the base of the permafrost but not below 5000 feet true vertical depth (TVD).
c.) In addition to variances under 20 AAC 25.030(g), alternate casing programs may be administratively approved by the Commission upon application and presentation of data, which show the alternatives are consistent with good oil field engineering practices.
Rule 5 Injection Well Completion
Injection wells may be completed with tubingless completions, (monobores or tapered casing) provided a sealbore assembly, packer, or other isolation device is positioned not more than 200 feet above the top of the injection or perforated interval.
Rule 6 Automatic Shut-in Equipment
a.) All wells capable of unassisted flow of hydrocarbons must be equipped with a fail-safe automatic surface safety valve.
b.) Injection wells must be equipped with a fail-safe automatic surface safety valve.
c.) Surface safety valves must be tested at six-month intervals.
Rule 7 Common Production Facilities and Surface Commingling
a.) Prior to installing a continuous metering skid, production from the Midnight Sun Oil Pool may be commingled with Initial Participating Area production in surface facilities prior to custody transfer. Producing Midnight Sun wells must be tested a minimum of two times per month and production must be allocated by interpolating between well test results. b.) After installation of a continuous metering skid, the requirements of 20 AAC 25.230 will be satisfied by measuring production from the Midnight Sun Oil Pool as a whole and allocating the production to each well daily. c.) The allocation factor for the Midnight Sun Oil Pool will be 1.00. d.) The operator shall submit a monthly file(s) containing daily production metering, allocation data and daily test data for agency surveillance and evaluation.
Rule 8 Reservoir Pressure Monitoring
a.) A minimum of one bottom-hole pressure survey shall be measured annually for the Midnight Sun Oil Pool.
b.) The reservoir pressure datum must be 8,050 feet true vertical depth subsea.
c.) 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.
d.) 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 must be available to the Commission upon request.
e.) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (d.) of this rule.
Rule 9 Gas-Oil Ratio Exemption
Wells producing from the Midnight Sun Oil Pool are exempt from the gas-oil-ratio limit set forth in 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply.
Rule10 Pressure Maintenance Project
Water injection for pressure maintenance must commence before reservoir pressure drops below 3300 psi at the datum or within two years of initial production.
Rule 11 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.
c.) Analysis of reservoir pressure surveys within the pool.
d.) Results and where appropriate, analysis of production and injection logs, tracer surveys and observation well surveys.
e.) Results of well allocation and test evaluation for Rule 7(d.) and any other special monitoring.
f.) Future development plans.
g.) Review of Annual Plan of Operations and Development.
Rule 12 Production Anomalies
In the event of oil production capacity restrictions at or from the Gathering Center One facilities, all commingled reservoirs produced through the IPA facilities must be prorated by an equivalent percentage of oil production, unless it will result in surface or subsurface equipment damage.
Rule 13 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.
Rule 14 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 November 15, 2000.
Camillé Oechsli Taylor, Commissioner
Alaska Oil and Gas Conservation Commission
Daniel T. Seamount Jr., Commissioner
Alaska Oil and Gas Conservation Commission