A Pump for All Reasons

July 24, 2006
The types of pumps used in the oilfield are almost limitless. They are used in exploration technologies and almost every facet of production to move liquids or gas.

The types of pumps used in the oilfield are almost limitless. They are used in exploration technologies and almost every facet of production to move liquids or gas. They’re placed on the surface, downhole, or on the seabed. Pumps are a kid of a hammer used for thousands of different tasks. There are even multiphase pumps such as those produced by Bornemann Pumps that enable the entire production stream - oil, gas, water, sand - to be moved from the wellhead to a centralized processing facility. In the oil industry, there is a pump for all reasons and lifting oil to the surface is one of them.

A Look at Artificial Lift

An ESP system incorporates an electric motor, seal, gas separator, and multi-stage centrifugal pump unit run on a production string. The system is connected back to a surface control mechanism and transformer via a heavy-duty armored electric power cable usually banded to the outside of the tubing. Pump and motor are generally installed at the end of the tubing string just below the fluid level. The pump typically comprises several staged centrifugal pump sections that can be specifically configured to suit the well and characteristics of a given application.

This form of lift can be utilized on various points of the decline curve even when the reservoir still has sufficient pressure but the operator wishes to increase flow rates. ESPs provide an effective and economical means of lifting fluids and are often considered the high volume and depth champions among artificial lift systems. They provide flexibility over a range of sizes and output flow capacities. Wells deeper than 12,000 ft can be produced efficiently with these pumps, which can be used in casing as small as 4.5” outside diameter. Production rates generally range from 70 to 64,000 BFPD.

The use of ESPs depends on the economics associated with producing incremental oil. For instance, if it is no longer economically feasible to produce an oil well through gas lift operations, an ESP may subsequently be the appropriate form of artificial lift, depending on the amount of gas being produced. When other lift systems seem to be over-matched by well depths, creating heavy columns of oil, or by large volumes of water that must be pumped-off a well to free gas production, an ESP is usually the system of choice.

Electric submersible pumps are deployed on approximately 60% of non-rod pump wells that require artificial lift, representing possibly 15% to 20% of the artificial lift market. Russia has the largest population of wells using ESP systems and they comprise over 50% of the country’s artificial lift systems.

ESPs are the fastest growing form of artificial lift and have grown to be the second most common method since their introduction. Baker Hughes Centrilift, Schlumberger, Wood Group ESP and Weatherford are the major manufacturers in this market with Smith Lift a recent entry. Today, more than 100,000 ESPs are operating globally.

Progressive Cavity Pumps (PCPs)

The concept of PCPs was originally used in drilling as the mud motor for rotating drill bits where the pump system operated by rotating a steel helical-shaped rotor inside an elastomer stator. Cavities would then generate an auguring action.

PCP systems typically consist of a surface drive, drive string and downhole PC pump. The stator is attached to the production tubing string and remains stationary during pumping. In most cases, the rotor is attached to a sucker rod string, which is suspended and rotated by the surface drive. As the rotor turns eccentrically in the stator, a series of sealed cavities form and progress from the inlet to the discharge end of the pump. The result is a non-pulsating positive displacement flow with a discharge rate proportional to the size of the cavity, rotational speed of the rotor and the differential pressure across the pump.

PCPs are known for their ability to pump viscous fluids (heavy oil) or to handle solids. As a relatively new technology, they have improved significantly year-to-year with respect to elastomers, sizes, and features. They are typically used in lower volume applications where abrasives are present or viscosity of the produced fluid is high. Although they have pumped some deep wells, 3-4,000 ft is a reasonable depth limit for long-term runs. They have weaknesses in light oil, hot wells, deviation, and gas production.

Hydraulic Lift

Introduced in the 1930s, these systems consist of a surface power fluid system, a prime mover, a surface pump, and a downhole jet or reciprocating/piston pump. There are two main types of hydraulic pumps for artificial lift: a fixed-pump design and a free-pump design. In fixed installations, the downhole pump is attached to the end of the tubing string and run into the well. Free-pump installations allow the downhole pump to be circulated into and out of the well inside the power-fluid tubing string, or they can be installed and retrieved by wireline operations.

One major advantage to either system is the ability to hydraulically circulate the pumps to the surface for maintenance, dramatically reducing well downtime and eliminating pulling unit expenses. In a piston pump installation, power fluid actuates the engine, which in turn drives the pump, and power fluid returns to the surface with the produced oil and is piped to the storage tank.

Jet pumps are a special class of hydraulic subsurface pumps and are sometimes used in place of reciprocating pumps because they have no moving parts. They achieve their pumping action by means of momentum transfer between the power fluid and produced fluid. These pumps are particularly suitable for producing gas wells and reducing wellhead backpressures. In certain applications, the hydraulic jet pump is quickly, if it has not already, replacing the hydraulic piston pump as the pump of choice.

Hydraulic lift methods are typically applied to deeper, low volume applications e.g. from multiple locations in close proximity, where deviated well conditions exist. They are also good offshore, and handle moderate gas. On the short side, they are low in efficiency with added costs and footprints for surface power equipment.

Plunger Lift

This form of artificial lift can be effectively used in maintaining production levels and stabilizing the rate of decline in production. To be functional, there must be sufficient gas present to drive the system.

Plunger lift systems consist of a plunger, often referred to as a piston, two bumper springs, a lubricator to sense and stop the plunger as it arrives at the surface, and a surface controller of which several types are available. Various ancillary and accessory components are used to complement and support applications.

This method uses an intermitting technique, along with a free traveling plunger in the tubing string that acts as an interface between the liquid phase and the gas phase. Because of the action of the plunger in the tubing, there is less than a 5% fluid fallback rate over the entire length of the tubing string irrespective of well depth. As a result, the well can be operated at a lower flowing bottomhole pressure, as all liquid is removed from the wellbore, thus enhancing production.

Plunger lift is good for dewatering gas wells, and cheap and effective in the right wells because it uses the well’s energy to lift. Well conditions must be right, however.

The Market Mix

As mentioned, each lifting type has its own production niche. There are good reasons to use the different forms of artificial lift, many of these dependent upon the volume of fluids.

The share of participation in the artificial lift market varies, depending upon the measuring base and the industry survey. If you’re counting wells, beam/sucker rod artificial lift holds a dominant position around the world followed by gas lift, ESP and plunger systems.

In terms of revenues, ESP is the biggest benefactor with an estimated 50% of the market dollars. Also, in volumes lifted annually, ESP accounts for more than half of the fluids moved. Although used on a dominant portion of wells worldwide, beam and rod lift only account for roughly 10% of the volume.