Reservoir production method

Details Reservoir production method Reservoir production method

1999-03-10

2001-11-27

Dang, Hoang (Department: 3672)

Wells

Processes

Distinct, separate injection and producing wells

C166S270100

Reexamination Certificate

active

06321840

ABSTRACT:

BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates generally to oil production and, more specifically, to methods of producing oil reservoirs having a gas cap. In particular, this invention relates to simultaneous production of the gas cap and oil column while introducing an injection fluid at the gas-oil contact.
2. Description of Related Art
The conventional way of producing most oil reservoirs having a gascap is to attempt to produce only from the oil column while keeping the gascap in place so that it expands to provide pressure or energy support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas may either cone down to the oil production wells and/or may breakthrough as a front, leading to substantial increases in the gas-oil ratio of the oil production wells. Direct production from the gas cap is typically delayed until such time that the oil zone is depleted, which may be many years after oil production is initiated. At such time, the gascap is usually directly produced or “blown down.”
SUMMARY OF THE INVENTION
Disclosed is a method of simultaneously producing the gascap and oil column of an oil-productive reservoir, while at the same time introducing an injection fluid (such as water) at the reservoir gas-oil contact to create a water barrier to separate or segregate the gascap from the oil column, as well as to provide pressure support. Using this method, production from the gas cap may be immediately realized (increasing net present value of production) with little or no reduction in the ultimate oil zone recovery over conventional production methods in which the oil column is produced first. Surprisingly, any reduction in gascap recovery due to entrapment of gas by water at higher reservoir pressures is typically more than offset by increased present value due to early gas sales. Furthermore, production problems associated with gas coning are typically minimized. This may be particularly advantageous where submersible pumps are employed.
The method may be employed with oil-productive reservoirs having a relatively low-dip angle, relatively large gascap, and a relatively low residual gas saturation to water. However, benefits may be realized in reservoirs having a variety of other dip angles, gas cap sizes and residual gas saturation to water values. Advantageously, recovery from a gas cap is typically minimally affected by heterogenities in the reservoir. Thus, significance of early gas production becomes even greater in those cases where reservoir heterogenities adversely affect oil recovery efficiencies.
In one respect this invention is a method of producing fluids from a subterranean formation having a gas cap, an oil column, and a gas-oil contact therebetween, including introducing a first injection fluid into the formation at a first location adjacent the gas-oil contact; and producing gas and oil from the subterranean formation by simultaneously producing gas from a second location in the gas cap and producing oil from a third location in the oil column. The first injection fluid may be introduced at the first location through a wellbore penetrating the subterranean formation, with an angle of deviation at the subterranean formation of greater than about 75 degrees with respect to the vertical. The first injection may be introduced at a flow rate effective to overcome gradient segregation of the oil and the water so that the water moves upward into the gas cap. The gas may be produced from the second location and the oil is produced from the third location through wellbores penetrating the subterranean formation at each location with an angle of deviation at the subterranean formation of greater than about 75 degrees with respect to the vertical.
The first injection fluid may be introduced at a flow rate sufficient so that the first injection fluid moves upward into the gas cap. For example, the first injection fluid may be water or other aqueous-based fluid, and may be introduced at a flow rate effective to overcome gradient segregation of the oil and the first injection fluid so that the first injection fluid moves upward into the gas cap. The first injection fluid may be introduced into the formation at a flow rate effective to substantially separate the gas in the gas cap from the oil in the oil column in an area of the formation adjacent the first location where the first injection fluid is introduced. The first injection fluid may be introduced into the formation at the first location and displace oil downdip toward the third location.
The subterranean formation may have an average angle of formation dip less than or equal to about 45 degrees, alternatively less than or equal to about 20 degrees, alternatively less than or equal to about 15 degrees, alternatively less than or equal to about 10 degrees, alternatively from about 20 degrees to about 1 degree, alternatively from about 15 degrees to about 1 degree, alternatively from about 10 degrees to about 1 degree, alternatively from about 10 degrees to about 2 degrees from the horizontal at the location of the gas-oil contact.
The first injection fluid may be introduced at a flow rate effective to maintain the reservoir pressure at a substantially constant value in at least a drainage area defined between the first location and the second and third locations during production of gas and oil from the subterranean formation from the respective second and third locations. The first injection fluid may be at least one of an aqueous-based liquid, a gas that is liquid under conditions of reservoir temperature and pressure, or a mixture thereof. The first injection fluid may be introduced at a flow rate effective to prevent or substantially reduce migration of the gas in the gas cap downdip in the subterranean formation in an area adjacent the first location in the subterranean formation. The oil may be produced from the third location using a submersible pump. A second injection fluid may be introduced into the subterranean formation at a fourth location in the oil column, the fourth location being positioned within the oil column. The second injection fluid may be an aqueous based fluid, a gas, a gas that is liquid under conditions of reservoir pressure and temperature, or a mixture thereof. The gas-oil ratio of the oil produced at the third location may be maintained at a value about equivalent to the solution gas-oil ratio of the oil in the oil column. The reservoir voidage rate from a production of reservoir fluids from the subterranean formation may be substantially balanced by the introduction rate of the first and second injection fluids into the subterranean formation. In this regard “reservoir fluids” means any fluids (whether native or introduced into the reservoir from an outside source) produced from the reservoir.
The majority of the upper surface area of the oil column may not be in contact with the gas cap. The subterranean formation may have an angle of dip of less than or equal to about 10 degrees from the horizontal. The first injection fluid may have a viscosity greater than the viscosity of the gas in the gas cap. A pressure drop in the subterranean formation between the second point and the first point may be high enough so that viscous forces acting on the first injection fluid are sufficient to overcome gravitational forces acting on the injection fluid so that the first injection fluid moves within the subterranean formation in a direction toward the second point in the subterranean formation. The first injection fluid introduced into the subterranean formation at the first location may form a fluid barrier at the gas-oil contact, the fluid barrier separating the oil from the gas over at least a portion of the area of the gas-oil contact. A gas-fluid barrier contact and a oil-fluid barrier contact may be defined at the respective interfaces between the fluid barrier and the gas cap and the fluid barrier and the oil column; and the gas-fluid barrier contact may move in a direction updip in the subterranean formation, and the oil-fl

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