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This page discusses the specific artificial-lift technique known as beam pumping, or the sucker-rod lift method. Many books, technical articles, and industry standards have been published on the sucker-rod lift method and related technology.Additionally, the other components of a sucker-rod pumping installation are discussed, including applicable engineering and operating information. The complete operating system should be understood and addressed to properly design, install, and operate this or any other type of artificial lift system. The Gipson and Swaim “Beam Pump Design Chain” is used as a foundation and built upon using relevant, published technology and the latest industry practices.
Beam pumping, or the sucker-rod lift method, is the oldest and most widely used type of artificial lift for most wells. A sucker-rod pumping system is made up of several components, some of which operate aboveground and other parts of which operate underground, down in the well. The surface-pumping unit, which drives the underground pump, consists of a prime mover (usually an electric motor) and, normally, a beam fixed to a pivotal post. The post is called a Sampson post, and the beam is normally called a walking beam. Figs. 1 and 2 present a detailed schematics of a typical beam-pump installation.
This system allows the beam to rock back and forth, moving the downhole components up and down in the process. The entire surface system is run by a prime mover, V-belt drives, and a gearbox with a crank mechanism on it. When this type of system is used, it is usually called a beam-pump installation. However, other types of surface-pumping units can be used, including hydraulically actuated units (with and without some type of counterbalancing system), or even tall-tower systems that use a chain or belt to allow long strokes and slow pumping speeds. The more-generic name of sucker-rod lift, or sucker-rod pumping, should be used to refer to all types of reciprocating rod-lift methods.
Linked rods attached to an underground pump are connected to the surface unit. The linked rods are normally called sucker rods and are usually long steel rods, from 5/8 to more than 1 or 1 1/4 in. in diameter. The steel rods are normally screwed together in 25- or 30-ft lengths; however, rods could be welded into one piece that would become a continuous length from the surface to the downhole pump. The steel sucker rods typically fit inside the tubing and are stroked up and down by the surface-pumping unit. This activates the downhole, positive-displacement pump at the bottom of the well. Each time the rods and pumps are stroked, a volume of produced fluid is lifted through the sucker-rod tubing annulus and discharged at the surface.
Selecting the sucker-rod pumping method
Many factors must be considered when determining the most appropriate lift system for a particular well. Artificial lift selection methods presents a discussion of the normally available artificial-lift techniques, their advantages and disadvantages, and the selection of a method for a well installation.
Sucker-rod pumping systems should be considered for new, lower volume stripper wells, because they have proved to be cost effective over time. Operating personnel usually are familiar with these mechanically simple systems and can operate them efficiently. Inexperienced personnel also can operate rod pumps more effectively than other types of artificial lift. Most of these systems have a high salvage value.
Because of its long history of successfully lifting well fluids, the sucker-rod lift method is normally considered the first choice for most onshore, and even some offshore, installations all over the world. This method is limited by:
- Size of the casing, tubing, and downhole pump
- Strength and size of the various rods
- Speed with which they can be reciprocated
Under favorable conditions, approximately 150 BFPD can be lifted from greater than 14,000 ft, while more than 3,000 BFPD can be lifted from less than 2,000 ft.  Some of the major advantages and disadvantages of this lift technique are shown in Table 1.
Understanding the reservoir
Understanding the makeup of the producing reservoir, its pressure, and the changes that occur in it are important to attain maximum production. Because reservoir conditions change as fluids are produced, ongoing measurement of the reservoir conditions is necessary. The main considerations in measuring and understanding the reservoir are the types and volumes of reservoir fluids being produced, their pressures in both the reservoir and at the wellbore or pump intake, and the effects these fluids have as they pass through the producing system.
The relationship between the reservoir fluid inflow and the produced fluid outflow is extremely important for any artificial lift method. This should be monitored and controlled so that any excessive damage to the lift equipment is avoided while profitably obtaining the maximum amount of fluids. Undesirable effects result when the producing equipment’s capacity is not properly balanced with reservoir fluid inflow. These effects include the following:
- Loss or deferment of production.
- Excessive producing costs.
- Premature equipment failure.
- Ineffective use of energy.
- Increased operating expenses.
A variety of well tests and measurements may be used to determine production rates for oil-, gas-, and water-supply wells and to observe the status of the reservoir. Each test reveals certain information about the well and the reservoir being tested. The main reservoir considerations are determining bottomhole pressure and the inflow relationship of the fluids with changing reservoir and pump-intake pressure.
Bottomhole pressure determination
Bottomhole pressure measuring equipment (pressure bombs) makes it possible to determine reservoir and tubing intake pressures within the desired range of accuracy. When this test is conducted at scheduled intervals, valuable information about the decline or depletion of the reservoir from which the well is producing can be obtained. However, it is difficult to obtain either bottomhole reservoir or operating pressures while the rod-pump system is installed and operating.
Calculations of the bottomhole pressures can be obtained by using instruments that detect the fluid level in the casing/tubing annulus. The simplest instrument is a fluid-level sounder with a strip chart. Bottomhole pressures can be estimated from the gravity of the fluids (i.e., oil, water, and gas), the volumes produced, and the fluid level. If producing and shut-in conditions are known, then approximate producing and shut-in reservoir pressures can be determined.
The key to accurate bottomhole pressure determination in any pumping well is the ability to predict the gradient of the fluid in the casing/tubing annulus. In 1955, W.E. Gilbert (Unpublished internal report: “Curve Annulus Gradient Correction for Gas Bubbling Through Static Liquid Column,” Shell Oil Co.) developed an iterative calculation procedure on the effect of gas bubbling up a static fluid column. This can be used in a trial-and-error method to determine a gradient correction factor (F) to determine the pressure at the desired depth in the presence of gas production. If the term Q /(aP)0.4 is greater than 0.25, this method should be used with caution because this is an indication that liquid flow up the annulus may occur. Also, the crude pressure/volume/temperature (PVT) characteristics alter the results. The Gilbert curve and a calculation example are presented in "The Beam Pump Design Chain." 
Currently, the same fluid-level sounder equipment can be interfaced with a computer to determine the downhole pressures more easily.  However, there still needs to be verification of the fluid level indication to ensure that "false" or incorrect annulus fluid levels are not recorded. Additionally, the fluid gravities and produced volumes must be accurate and reflect actual conditions.
Knowing the reservoir and pump intake pressures during static and operating conditions will allow a determination of the well's production capacity. This is required to optimize the artificial-lift equipment and properly size the equipment that is installed. The well productivity under varying production conditions must then be known.
Inflow performance relationship (IPR)
One of the most critical decisions in an artificial-lift system is the selection and design of equipment appropriate for the volume of fluid the reservoir produces. Reservoir inflow performance detaisl the productivity index and IPR of fluids with changes in reservoir pressure. Because most fluid produced by an artificial lift method is not single phase, it is not in a steady-state condition. Also, because most pumping operations occur after the fluid is below the bubblepoint pressure, the IPR method is usually considered. This technique takes into account various fluid phases and flow rates. It was originally devised by Vogel and described by Eickmeier.  Each revision increased the accuracy of estimating flow rates from a well.
In the design of an artificial lift system, it is necessary not only to predict production of the various fluids during existing conditions and reservoir pressure, but also to make a second type of prediction: future pressure performance. This can be accomplished with the IPR method and multiple, or a family of, IPR curves. Furthermore, the family of curves can be used to predict estimates of fluid production increases if the reservoir is repressurized from waterflooding or other secondary or tertiary methods.
Producing rates can be estimated within the desired range of accuracy using the IPR technique with two stabilized producing rates and corresponding stabilized producing pressures. This makes it possible to use the IPR without needing to shut in the well and lose production to obtain shut-in information. Obtaining a bottomhole pressure equal to 10% of the shut-in reservoir pressure is recommended for determining maximum production rates for sucker-rod lifted wells. At this pressure, the maximum well productivity will be 97% of the well's theoretical maximum production rate. However, the maximum lift-design rate should, in most cases, be slightly higher to permit some downtime and decreased pump efficiency.
In any artificial lift system, the volume of gas produced should be considered in designing the system and in analyzing the operation after the system has been installed. A complete analysis requires knowing the volume of gas in solution, the volume of free gas, the formation volume factors, and whether gas is produced through the pump or is vented. If PVT analyses of reservoir fluids are available, they are the most accurate and easiest to use as a source of solution gas/oil ratio (GOR), formation volume factors, etc. The next best source is an analysis from a nearby similar reservoir.
A means of estimating PVT data is contained in Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems.  With the produced GOR, gas gravity, oil gravity, and reservoir temperature, the following can be estimated using the instructions included on each chart:
- Chart 1: The formation volume factor for the gas plus the liquid phases.
- Chart 2: The bubblepoint pressure.
- Chart 3: The formation volume factor of the bubblepoint liquid.
When pumping through tubing in the absence of a production packer, free gas, which breaks out of the oil, should be vented up from the casing/tubing annulus. However, when it is necessary to produce from beneath a production packer, a vent string can be installed. The possibility of needing a vent string should be considered when planning casing sizes for a new well.
Both the size of the vent string and the location of its bottom, with respect to the location of the pump intake and producing perforations, will influence the string's effectiveness in removing free gas. The string's diameter should be designed to allow the production of the anticipated free-gas volume with a pressure drop no greater than the desired producing bottomhole pressure minus the surface backpressure. If the required pressure drop is greater than this, a portion of the free gas will have to go through the pump. Fig. 2 is an indication of the effect of vent-string size on the pressure drop through it. Care should be taken if small-diameter tubing is used, because it may not allow all the gas to flow up the vent or may simply load up and prevent most gas flow.
Effects of gas on pump performance
Gas that remains in solution when the liquid enters the pump increases the volume of total fluid through the pump compared to the liquid measured at the surface by the formation volume factor at pump-intake conditions. The gas also decreases the density of the fluid and, thus, the head or pressure to be pumped against in the tubing. Free gas that enters the pump must be compressed to a pressure equivalent to the head required to lift the fluid. This free gas will reduce the volume of both the produced liquid that enters the pump and the liquid measured at the surface. Any time the pump does not compress the free gas to a pressure greater than that exerted on the pump by the fluid column in the producing string, production ceases and the pump is said to be "gas locked." This condition can exist in both plunger and centrifugal pumps.
Intake pressure is the pressure in the annulus opposite the point at which the fluid enters the pump. If the pump intake pressure is increased by increasing the pump submergence, the free gas volume decreases because the fluid retains more gas in solution. Reducing the pressure drop in the pump-suction piping also reduces the free gas to be produced. The pump intake should not be deeper than is necessary to maintain the desired intake pressure. A pump intake that is too deep results in unnecessary investment and increased operating costs.
Fig. 3 is a graph of the liquid produced as a percent of the displacement of a plunger pump plotted against the pump intake pressure for a typical reservoir.  If the pressure is greater than the bubblepoint (Point A to B), the volumetric efficiency remains nearly constant. If all the gas can be vented rather than passed through the pump, the volumetric efficiency will increase as the formation volume factor decreases (Point B to C). If all the gas must be pumped, the volumetric efficiency decreases as the intake pressure drops to less than the bubblepoint (Point B to F). The lines B–D and B–E indicate the volumetric efficiency with a partial venting of gas as its presence declines. Note that the efficiency declines to a minimum at less than the bubblepoint and with further pressure reduction, starts to increase. A general conclusion is that to obtain better efficiencies, the pump intake pressure should be maintained at or greater than the bubblepoint, or decreased to as low as possible to take advantage of the increased separation efficiencies at the low pressure end. However, this considers only pump efficiency and not maximum production rate.
Gas bubbles entrained in the produced liquid(s) tend to rise because of the difference in the liquid and gas densities. The rate of bubble rise depends on the size of the bubbles and the physical properties of the fluid. The size of the bubbles increases as the pressure decreases. At low pump-intake pressures, the rate of gas-bubble rise in low-viscosity fluids will approximate 0.5 ft/sec, assuming a 400-μm bubble rise in water. The increase in bubble size and rate of rise as the pressure decreases causes the reversal in curves B–D and B–E in Fig. 3.
Downhole gas separators and anchors
Downhole gas separators are used in gassy wells to increase the volume of free gas removed from the liquids before reaching the pump. However, they are not 100% effective in separating the gas. In sucker-rod-pumped wells, these separators are normally called "gas anchors." Gas anchors are usually designed and built in the field; Fig. 4 contains schematic drawings of six common types. The most commonly used are the "natural" gas anchor (A) and the "poor boy" gas anchor (C). Typically, there are two major components for these gas anchor assemblies, the mud anchor run on the bottom of the tubing string and the dip tube or strainer nipple run on the bottom of the pump.
The largest downhole gravity separator is normally the casing/tubing annulus. This area provides a maximum down passage for liquid and up-flow area for gas. This allows the oil (and water) to move relatively slowly, typically, downward from the perforations to the pump, and permits the gas to separate and flow upward. For this reason, a natural gas anchor should be used whenever practical because it takes advantage of the entire casing internal cross-sectional area. This type of separator typically should be placed approximately 15 ft below the lowest most-active well perforations. However, if there is insufficient distance in the well to place the pump intake below the perforations, then the pump intake should be placed approximately 15 ft above the top-most perforation and a poor boy separator should be properly designed and installed.
There are limitations on how much gas can be handled by the downhole separator. If more gas is produced than can be handled by the separator, the gas will not separate completely. The downhole pump must then handle the excess gas. If the wells exceed these theoretical gas rates, then:
- Pump volumetric efficiency decreases
- Liquid production decreases
- Energy is wasted
- Operating costs rise
The situation worsens if excessive gas enters the pump and there is insufficient compression ratio to pump all the fluids, resulting in a gas-locked pump. When this occurs, operating costs for this well increase dramatically because when there is no production, there is no revenue. However, a properly designed and spaced pump should not gas lock if the well is not pumped off.
Example calculations of the gas capacity of various casing/tubing annuli vs. different intake pressures have been presented in 'Hein. This reference also discusses the types of downhole separators and emphasizes the need to run a natural gas anchor assembly whenever possible.  Detailed discussions on design of the different types of separators, the arrangement of components, and example calculations for sizing components are presented by Gipson and Swaim.  Improved gas separators with decentralized intakes have been introduced.  This design aids in separation efficiency because it increases the local distance from the casing's inner diameter (ID) to the mud anchor, which results in an increased separation area. However, as with all specialty devices, the need to run this new design should be demonstrated by ensuring that the appropriate, standard systems have been properly installed and operated.
It is often recommended that the outside diameter (OD) of the gas anchors' steel mud anchor be less than the ID of the largest overshot or wash pipe that can be run in the well casing. This limits the gas-anchor separation capacity that can be secured in wells with small casings. Reinforced plastic mud anchors that can be drilled up, or steel designs that can be recovered with spears, should be considered when mud anchor OD must approach casing-drift diameter. This design would then be considered the "modified poor boy." Agreement should be obtained from the field before installation to ensure acceptance of the possible problems when trying to pull this type of installation.
Components of sucker-rod lift system
The major components of a sucker-rod lift system are discussed in separate articles:
- Downhole sucker-rod pumps
- Sucker rods
- Miscellaneous downhole equipment
- Sucker-rod pumping units
- Prime movers
- Miscellaneous surface equipment
Gipson and Swaim did an excellent job of summarizing a sucker-rod lift-system design in The Beam Pump Design Chain with the API RP 11L approach. This recommended practice should be consulted for continued discussion of this equipment, along with a review of a sample problem and a recommended solution. In summary, use the design procedure presented in API RP 11L or a suitable wave equation. Several commercial wave-equation computer programs are available that many operators have successfully used.
|Q/aP0.4||=||parameter from Gilbert used to determine gradient correction factor, where Q is gas flow rate, Mscf/D; a is the casing-tubing cross-sectional area, in.2; and p is the producing pressure, psia|
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