Experience With Pumpoff Control in the Permian Basin
- A. Buford Neely (Shell Western E and P Inc.) | H.O. Tolbert (Shell Western E and P Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1988
- Document Type
- Journal Paper
- 645 - 649
- 1988. Society of Petroleum Engineers
- 5.4.1 Waterflooding, 3.1 Artificial Lift Systems, 3.1.1 Beam and related pumping techniques, 7.4.3 Market analysis /supply and demand forecasting/pricing, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc)
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Summary. Shell Western E and P Inc. has installed pumpoff control on more than 2,500 sucker-rod pumping wells in the Permian Basin during the last 12 years. These systems fall into three basic categories: stand-alone analog devices, stand-alone microprocessor units with optional communication capabilities to a central computer, and a centralized system where well data are communicated to a central computer for pumpoff decisions. Evaluation has shown that production can be maintained or slightly increased while energy consumption and maintenance expense are substantially reduced. The pumpoff controllers also provide well data that are beneficial in maintaining good surveillance.
Sucker-rod pumping is by far the predominant artificial lift method used in the U.S. for producing oil wells. Published data indicate that more than 85% of the artificially lifted wells in the U.S. use sucker-rod pumping. Of new installations of artificial lift made in 1983 through 1986, more than 92% were sucker-rod pumping. Rod pumping is popular because of its simplicity, ruggedness, and ability pumping is popular because of its simplicity, ruggedness, and ability to cover a wide range of producing conditions. Rod pumping is usually the artificial lift method selected, except where the volumes to be lifted exceed its capability or where surface conditions preclude its use.
The problem in design is to select a pumping installation that will obtain all the production economically available from the well while minimizing the capital expenditure required for lift equipment. If the pump capacity is less than the well's ability to produce, the well will not be produced at its maximum rate of production. On the other hand, if more pump capacity is provided than well capacity, the well will be overpumped and a pumped-off or fluid-pound condition will occur. When the liquid production from the well is inadequate to fill the pump barrel completely on each suction stroke, the barrel will be partially filled with free gas. As the pump plunger starts downward, the traveling valve will remain closed until the gas in the pump barrel is compressed to a pressure slightly greater than the pressure in the tubing above the pump. If this occurs near the top of the stroke, the plunger is moving slowly and no detrimental mechanical effects occur. As the traveling valve opens farther down in the stroke, the plunger is moving faster and pressure will build more rapidly. Because of the finite time required for the traveling valve to open, this can result in substantial overpressuring in the pump barrel, which can cause buckling in the lower rods and split pump barrels. Consequently, it is good operating practice to minimize overpumping. Changing the pump displacement is difficult. The most common method of reducing the overdisplacement is to cycle the pump on and off.
Fig. 1 shows surface pump cards for a well where a speed control device was used that allowed the pumping speed to be changed by turning a dial. The four surface dynamometer cards show the well going from severely overproduced to substantially underproduced.
Pumpoff Control Pumpoff Control Some of the earliest attempts at pumpoff control were the use of time-clock devices to produce the well on a regular on/off cycle. The most common of these was the 15- or 30-minute percentage timers that produced the well for some part of 15 or 30 minutes and shut it in for the remainder of the cycle. The 15-minute cycle was widely used because many of the power companies used 15-minute demand factors. Various flow/no-flow devices were tried as pumpoff controllers, but none achieved any appreciable success. In the 1960's, a large number of pumpoff control devices came on the market that used motor current as the parameter to determine pumpoff. Although many of these could be made to work in test pumpoff. Although many of these could be made to work in test situations, particularly when engineering provided fairly constant supervision, they did not gain widespread usage. One problem was that voltage variations would affect the current but had no relation to whether the well was pumped off. As a result of this and other limitations, motor-current pumpoff controllers have not gained wide usage.
Pumpoff controllers that use rod loading as the criterion for determining when the well is pumped off have gained the most widespread usage in the oil industry. These have various means of logic to determine when pumpoff occurs, and most have been successful. Widespread use of these pumpoff controllers really started in the 1970's with the end of proration and with the large increase in the cost of electric energy. Westerman discussed pumpoff history in greater detail. pumpoff history in greater detail. Denver Unit Pumpoff Control System
In 1975, a pilot pumpoff control system was installed in the Denver Unit of the Wasson field. The Denver Unit is a large San Andres waterflood that has been described by Ghauri et al. The unit consists of about 800 beam-pumping wells producing into eight central batteries. Depths of the wells are about 5,000 ft [1 525 m]. Aver-age total liquid production is 425 B/D [68 m3/d] per well, with limited gas problems. Fig. 2 shows a typical dynamometer card for a well soon after pumping has started and at a pumped-off condition. The degree of pumpoff selected is arbitrary but the example shown in Fig. 2 is typical for what is used in the Denver Unit. Pumpoff is considered to be that point when the pump barrel is filling about 85 to 90 % with liquid. Hunter et al. reported on the details of the pilot and the benefits resulting therefrom. From the results obtained in the initial pilot, pumpoff control was expanded to the entire unit during 1978-79. The benefits obtained will be discussed in a later section.
Fig. 3 shows the layout used in the Denver Unit system. Load and motion are measured at the well and transmitted by a remote terminal unit (RTU) to a computer in the field office. The local RTU does not have memory; it is simply an addressable unit that passes on measured load and motion data in real time. At the time passes on measured load and motion data in real time. At the time this system was installed, the current level of microprocessor units was not available. Data are transmitted from the local RTU to the computer through a buried cable system. This was used rather than radio because of the need for high-speed data transmission. The computer continually surveys the wells to collect data. A stroke of data is taken from each pumping well about every 1 to 2 minutes.
The original logic used in the Denver Unit was to integrate the surface dynamometer card and to determine pumpoff from the reduction in area.
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