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Production enhancement of geothermal wells

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Higher-temperature wells are normally self-energized and produce without stimulation. Initial production of a well is usually allowed to discharge to a surge pit to allow for cleanup of the wellbore of debris from drilling operations. If a well is self-energized, it is also important to know whether the produced fluid remains single phase in the wellbore. Friction losses are much greater for two-phase flow, so increasing the casing diameter at the point where the fluid flashes to vapor will increase production. A well that does not discharge spontaneously will require stimulation. There are several methods of stimulation used.


This technique involves lowering a swab down the well, below the water or mud line. A one-way valve in the swab permits the fluid to pass by the swab as it is lowered into the well. Raising the swab lifts the water column out of the well to reduce the hydrostatic pressure on the producing formation so the well begins to discharge fluids spontaneously. This method may take several trips in and out of the well to initiate flashing and induce flow.

Coil tubing and liquid nitrogen

The removal of fluid from the top of the column can be achieved by running tubing into the well below the fluid level and injecting liquid nitrogen to lighten the column and induce boiling in the well. This method is the most common method of bringing a well back online after well remediation or surface facility shutdowns.

Compressed air

Compressed air can be deployed instead of nitrogen and is preferred over swabbing, mainly for safety and well control reasons. Standard air compressors are used in conjunction with drill pipe. The annulus is pressurized with air and the column of liquid is reverse-circulated through the drill pipe.

Foaming agents

Foaming agents help reduce the weight of the water column by emulsifying air or nitrogen in the liquid, thus keeping the gas entrained in the liquid and providing greater lift.


This method has been used to stimulate water wells for agricultural purposes and is sometimes effective in starting a geothermal well. This method consists of pressurizing the wellbore with compressed air and quickly depressurizing the well to atmospheric pressure to induce boiling.

Pumped wells

If the well does not produce spontaneously and does not respond to stimulation or if the power production facility is designed to only handle geothermal liquids and not two-phase or vapor flows, it will be necessary to install a pump. Conventional technology for many years was a line-shaft pump with the motor at the surface and the impeller set some distance below the drawdown water level in the well. This arrangement requires a straight, vertical wellbore down to the pump depth. There also may be restrictions on pump depth because line-shaft pumps have limits on how far torque can be effectively transmitted down the wellbore. Recently, high-temperature-capable submersible pumps have been developed that give good service up to about 200°C. The pump must be located at a depth sufficient to avoid cavitations at all flow rates expected.


Curtailments are planned or unplanned circumstances that require wells to either be shut-in completely or throttled. Examples of curtailments include intentionally throttling production back during off-peak power needs (load following), unexpected tripping of generation equipment, or other surface problems that may require forced outages. Some wells may load up with liquid and stop flowing if any flow constraint is imposed. These wells might then require stimulation to restart production. In cases where short down-time is expected, or to prevent the well from cooling, a plant bypass system might be installed at the surface to keep the well flowing. The bypass system can be a turbine bypass that passes the steam through a condenser (and the condensate back into the resource) or route steam to an atmospheric muffler system. When venting steam to atmosphere is a safety or environmental concern, a condensing system is generally used.


Injection initially started as a disposal method but has more recently been recognized as an essential and important part of reservoir management. Sustainable geothermal energy use depends on reinjection of produced fluid to enhance energy production and maintain reservoir pressure. A simple volumetric calculation shows that over 90% of the energy resides in the rock matrix; hence, failure to inject multiple pore volumes results in poor energy recovery efficiency. When the usable energy is extracted from the fluid, the spent fluids must be disposed, reused in a direct use application, or injected back into the resource. Despite efforts to maximize the fraction of fluids reinjected, it is common for losses to approach 50%, mainly through evaporative cooling tower loss. Frequently, makeup water is used to augment injection. Failure to reinject can lead to severe reductions in production rates from falling reservoir pressure,[1] interaction between cool groundwater and the geothermal resource,[2] ground subsidence,[3] or rapid dryout of the resource.[4]


  1. Benoit, D. 1992. A Case History of Injection through 1991 at Dixie Valley, Nevada. Geothermal Resources Council Trans. 16: 611.
  2. Benoit, D. and Stock, D. 1993. A Case History of Injection at the Beowawe, Nevada, Geothermal Reservoir. Geothermal Resources Council Trans. 17: 473.
  3. Allis, R.G. et al. 1999. A Model for the Shallow Thermal Regime at Dixie Valley Geothermal Field. Geothermal Resources Council Trans. 23: 493.
  4. Barker, B.J. et al. 1992. Geysers Reservoir Performance. Geothermal Resources Council Special Report 17: 167.

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See also

Hydraulic fracturing

Geothermal production measurement

Geothermal drilling and completion

Geothermal reservoir engineering

Geothermal energy