Because they lack sufficient reservoir pressure to produce fluids to the surface, the majority of the world’s oil and gas wells are unable to produce at economic rates without assistance. This condition may be the result of pres- sure depletion over time or be caused by low original reservoir pressure.
To compensate for the lack of natural energy in these formations, operators equip the wells with artificial lift (AL) systems. Artificial lift well candidates are those completed in formations that have economically viable reserves and sufficient permeability for the fluids to move to the wellbore but do not have sufficient reservoir drive to lift those fluids to the surface. Secondary recovery efforts, such as waterfloods designed to capture remaining reserves in pressure-depleted reservoirs, often result in increased fluid volumes that can be lifted to the surface only through AL methods.
When choosing a specific AL system, engineers must consider—in addition to surface conditions based on location—a host of parameters, including reservoir characteristics, production properties, fluid types and operational considerations. Choice of an optimal AL system may be influenced by subsurface conditions, expected production rates, fluid composition, well geometry, reservoir depths, completion configuration and surface facilities. In addition, operators must consider the potential return on their investment by balancing the value of increased production against the cost of hardware for and installation and maintenance of an AL system.
Artificial lift systems are deployed predominantly to extend well life. But these systems may also help shorten the time from first production to well abandonment. For example, operators may gain an economic advantage by accelerating recovery rates, a process that more quickly drains the reservoir, thus saving expenses in situations characterized by high operating costs.
After an operator has established that an AL system is advisable, production engineers choose the type best suited to the situation. For example, electric submersible pumps and gas lift systems are often chosen to boost production in offshore wells because such systems have small footprints, are able to handle high production volumes and may be deployed at significant depths below the wellhead. On the other hand, sucker beam pumps, which require a significant amount of surface space but are reliable, easily serviced and one of the least expensive of the AL options, are often the optimal solution for land-based, marginally economic wells.
Artificial lift systems fall into two basic types: pumping and gas lift. Pumping systems include electric submersible pumps, beam pumps, progressing cavity pumps, plunger lifts and hydraulic pumps.
Electric Submersible Pumps
Perhaps the most versatile AL systems are electric submersible pumps (ESPs). These pumps comprise a series of centrifugal pump stages contained within a protective housing. A submersible electric motor, which drives the pump, is deployed at the bottom of the production tubing and is connected to surface controls and electric power by an armored cable strapped to the outside of the tubing.
An ESP derives its versatility from a wide range of power output drives and from variable speed drives that allow operators to increase or decrease volumes being lifted in response to changing well conditions. Additionally, modern ESPs are able to lift fluids with high gas/oil ratios (GORs), can be designed using materials and configurations able to withstand corrosive fluids and abrasives and can operate in extreme temperatures.
A beam pump system is composed of a prime mover, a beam pump, a sucker rod string and two valves (Figure 1). The gas- or electric-driven prime mover turns a crank arm, which causes a beam to reciprocate. The resulting up and down movement lifts and lowers a rod string attached to one end of the beam. The motion of the rod string opens and closes traveling and standing ball valves to capture fluid or allow fluid to flow into the wellbore. In some configurations, the valves are part of an integrated assembly called an insert pump, which can be retrieved using the rods while leaving the production tubing in place. Beam pump equipment and parameters (valves, prime mover, rod and tubing diameter, and stroke length) are determined according to reservoir fluid composition, depth to the fluid top and reservoir productivity. The systems are typically equipped with timers that turn the pumps off to allow fluid time to flow through the formation and into the wellbore. The timer then restarts the pump for a period calculated to produce the fluid that has accumulated in the well.