The productivity of the system is dependent on the pressure loss which occurs in several areas of the flow system from reservoir to separator on the surface, that include: the reservoir, the wellbore, the tubing string, the choke, the flow line and the separator.

The production system

Artificial lift refers to the application of artificial means on oil wells to increase production rate by compensation for pressure loss in flow system especially in tubing string. When the natural drive energy of the reservoir is not strong enough to lift the oil to the surface or at an economic rate, artificial lift is employed to recover more production.

With sufficient reservoir energy at the beginning, well can produce oil under natural flow to the surface, that pressure depletes over time, and artificial lift is then required. Therefore, artificial lift is generally performed on all wells at some time during their production life.

Types of Artificial Lift

Although there are several methods to achieve artificial lift, the two main categories of artificial lift include gas lifts and pumping systems.

         Gas Lift

The lift process is assisted by reducing flowing pressure gradients in the tubing e.g. reducing the hydrostatic head by injecting gas into the stream of produced fluids. The injection of gas normally into the annulus between the production tubing and casing. The gas is subsequently allowed to enter the flow stream within the production tubing at some specific depth through a single or more usually a series of gas lift valves. The injection of gas into the production tubing provides an increase in the gas liquid ratio of the fluids flowing in the tubing at that depth and throughout the tubing above the injection point. This results in a reduction of the bottomhole pressure of the well. To be able to enter the tubing, the pressure of the gas in the annulus, at the valve which will permit its flow into the tubing, must be greater than the pressure of the fluids in the tubing at that same depth.

Gas lift system

By injecting gas, the gas oil ratio (GOR) of the flowing fluid is increased, its effective flowing density is reduced. In addition, the compressibility of the gas will assist in the lift process since as the gas rises up the tubing with the liquid it will expand, causing an increase in the tubing flow velocity. However, as the gas expands it will introduce some increase in the frictional pressure losses. With increasing gas injection volume, the hydrostatic head will continue to decline towards a minimum gradient at very high GOR. The benefit in fluid density may incrementally reduce whilst the increase in frictional pressure loss will increase significantly after a certain gas injection rate. Hence, an optimum gas injection rate will exist.

Gas lift is a very effective method of increasing the production rate, provided that the gas is effectively dispersed in the flowing fluid column and the optimum injection rate is not exceeded. The simplicity of gas lift system is also one of its main advantage.

        Pumping systems

The lift process is assisted by providing additional power using a pump, to provide the energy as part or all of the pressure loss which will occur in the tubing. Several active pumping systems had been introduced for artificial lift systems over time. However, Electric Submersible Pump and Sucker Rod Pump are two main and dominant systems are used widely in the industry as they have great advantages over other systems, include Plunger lift, Hydraulic pumps and Jet pumps.

             1. Electric Submersible Pumps (ESP)

This consists of a multi stage centrifugal pump located at some position downhole usually as an integral part of the tubing string. The pump suction must be flooded at the setting depth in the well for the pump. An electric cable run with the production tubing supplies the power from surface to the downhole pump. As an alternative the pump can be run on coiled tubing or on its power cable.

Electric Submersible Pump system

This type of pump is an efficient and reliable artificial-lift method for lifting moderate to high volumes up to 150000 barrel per day of fluids from wellbores.

              2. Sucker Rod Pumps

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. In this system, a plunger, cylinder and standing valve system is located downhole as part of the tubing string and connected by steel rods to a vertical reciprocation system at surface. The surface reciprocation system is referred to as a “nodding donkey” and is driven by a beam suspended on a pivot point and creates reciprocation through a rotary wheel. This type of system is suitable for very low to medium production rates i.e. < 1,000 barrel per day and can operate with wells having no flowing bottomhole pressure.

Sucker Rod Pump system


Selecting an Artificial Lift System

To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. Each artificial lift system has a preferred operating and economic envelope influenced by factors such as fluid gravity, GOR, production rate as well as development factors such as well type, location and availability of power.

Artificial lift method selection should be a part of the overall well design. As the wellbore size relatively affects to the desired production rate, wells should be drilled and completed with future production and lift methods in mind. It requires a comprehensive and collective activities throughout drilling process to well completion and production of many different parties that involve in the process and it is obvious not feasible every time. Very often a casing program has been designed to minimize well-completion costs, but it is later found that the desired production could not be obtained because of the size limitation on the artificial lift equipment. This can lead to an ultimate loss of total reserves. Even if target production rates can be achieved, smaller casing sizes can lead to higher long-term well-servicing problems.

Sucker Rod Pump Principles