Wells – Processes – With indicating – testing – measuring or locating
Reexamination Certificate
2001-07-11
2003-10-14
Neuder, William (Department: 3672)
Wells
Processes
With indicating, testing, measuring or locating
C053S105000
Reexamination Certificate
active
06631762
ABSTRACT:
FIELD OF THE INVENTION
The present invention relates to the field of oil pumping systems and, more particularly, to a system and method for the cost-effective production of oil from economically marginal, low volume oil wells.
BACKGROUND OF THE INVENTION
Three pumping methods are typically used in low pressure or no-pressure wells for lifting crude oil and water from subsurface formations to the surface. For low volume wells at relatively shallow depths, nearly all wells are pumped using beam pumping units. Beam pumping units trace their origin to “pitcher pumps” found on farms in rural areas in Europe and the United States in the 18
th
and early 19
th
century. For residential and commercial water supply, such pitcher pumps have largely been replaced by water distribution systems from municipal sources. However, the principle of using a rod to reciprocate a positive displacement pump element found application in lifting crude oil and produced water in oil fields and has been one of the three major lift methods employed world wide since 1912.
Today, beam pumping units used in oil production are part of a pumping system that employs pump off controllers that have either timers or other sensors located near the well head. When timers are employed, the pump is operated periodically at a rate that approximates the rate the well fills from natural drainage from the formation. Pump off controllers based on weight or power sensors operate the pump until a change in pump load is detected indicating that the pumping operation is no longer lifting fluid.
Many attempts have been made to improve the overall efficiency of beam pumping units by improving the pump off control system. However, these systems continue to rely on measurements of the surface observable characteristics of the pump or on surface control of the driving motor. Various improvements to these two basic techniques have been proposed. For example, U.S. Pat. No. 5,984,641 to Bevan, et al. teaches a controller for controlling the pump unit of an oil well which includes a sensor having probes in the flow of oil from the well bore to determine oil flow rate. A pump control signal is generated in response to the flow rate, and the pump control signal varies a predetermined parameter of a pumping unit during operation.
Other systems operate on other surface measured characteristics such as pump rod loading, such as for example U.S. Pat. No. 3,824,851 to Hahar, and drive motor power. In contrast, Adams, Jr.; in U.S. Pat. No. 4,570,718; proposed a system for controlling production in an oil well which included a surface-located controller for activating the means for causing reciprocation of the sucker rod of a beam pumping unit. A sensor was secured to the outer surface of the production tubing near the lower end of the tubing. The sensor comprised a radioactive source spaced from a radioactivity detector such that oil at that level would fill the space. Oil in the space would modify the amount of radioactivity sensed by the detector, and provide some indication of the level of oil in the well.
A principal drawback of such systems is that they draw an inordinate amount of power in order to operate, and when such wells produce only limited quantities of oil, they quickly become uneconomical. When such marginal or low volume wells cannot justify the cost of the installation and operation of the lifting system, they are typically closed in, even though there may be large quantities of hydrocarbons left underground.
Low volume wells typically produce less than 20 barrels (“bbl”) of total fluid (oil and water) per day. Lifting 20 bbl of fluid a height of 1000 feet over a period of 20 hours typically requires 5 to 20 Hp in beam pumping systems. Further, such beam pumping units suffer increasing power requirements to operate the rod string, stuffing box, and to overcome viscous forces of the fluid at greater depths. In low volume wells, power losses in the stuffing box can exceed the actual power required to lift the fluid. Since production tubing is rarely sufficiently straight to allow the rod string to reciprocate without contacting the tubing, significant wear on both production tubing and the rod string is common, even with rod guides installed on the sucker rod.
In conventional beam pumping systems, the fluid is removed from a well in the annulus between the reciprocating rod string and a conduit of production tubing attached to the downhole pump. Geyer; in U.S. Pat. No. 4,830,113; recognized this phenomenon and proposed a small down hole pump and a relatively small motor as a replacement for the existing system. The Geyer system, however, met with two operational problems. First, the Geyer system required coil tubing as the production conduit. Most existing oil field tubulars consist of segments of steel pipe which precludes the cable installation method of Geyer as the tubular must be separated into segments during removal from the well. In contrast, the present invention uses a method which allows installation of the power cable after the production string is installed into the well. Second, the Geyer system provided no improvement over conventional provisions for the control of the down hole apparatus. Detection of the pump off condition in Geyer was accomplished by sensing changes in the required power. The present invention, however, uses sensors located near the pump to determine the level and condition of the fluid to be pumped. By employing a closed loop control scheme, the fluid level can be maintained within a specified range above the pump.
Many different pump off controllers have been proposed in the art, and many such controllers have been installed for production from low volume wells. For low volume wells which are typically pumped with beam pumps, pump off control methods depend on recognition of pump loading either through direct measurement of forces on the sucker rod or these methods rely on various schemes to control the pump using the motor loading. In some systems, a direct measurement of well fluid level is attempted, such as in Adams, Jr. as previously described. In these systems, either a conductive liquid is required and the only liquid level that can therefore be detected is produced brine or a single physical parameter is measured which leads to ambiguity in the determination of liquid level. This ambiguity results from the varying makeup of produced fluids from a pumping well, including often unpredictable mixtures of oil, water, brine of varying salinity, and various gases.
In some areas a well may produce a frothy crude oil mixed with oil field brine. In this type of production, it is impossible to determine the liquid level below the foam using reflective acoustic measurement because of the attenuation of the transmitted acoustic signal in the foam. Entrained gas in the froth above the oil/water liquid level also has an unpredictable effect on both velocity and amplitude of the transmitted acoustic signal and thus renders such measurements inaccurate.
Attempts to unambiguously determine the liquid level by measurement of a dielectric constant have also failed because the produced fluid typically contains three constituents in a pumped off well. These constituents are gas, oil, and water of varying salinity. Combinations of the dielectric properties of these three constituents may result in multiple combinations having the same dielectric constant.
Attempts to directly measure electron density by gamma ray attenuation have encountered limitations resulting from the varying density of produced crude oils over the life of an oil well. Occasionally, produced crude oils have the same density as water. And, over the life of an oil well the effervescence of produce crude may change. This results in a variation of oil density and ultimately the ability to determine fluid level from density measurements alone. It may be possible to employ neutron diffusion differences to unambiguously determine hydrogen density and infer a liquid level. However, this type of measurement system would require either a long
Browning & Bushman P.C.
Neuder William
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