There are several basic factors which will affect the operation and separation between the liquid and gas phases in a separator.

1. Separator operating pressure;

2. Separator operating temperature;

3. Fluid stream composition.

Changes in any one of these factors on a given fluid well stream will change the amount of gas and liquid leaving the separator. In most applications the well stream composition is a fact of nature and cannot be controlled by the operator. Only in plants or where several streams are mixed can the fluid stream composition can be varied, affecting the oil and gas separation. Generally speaking, an increase in operating pressure or decrease in operating temperature will increase the liquid recovered in a separator. However, there are optimum points in both cases beyond which further changes will not aid in liquid recovery. In fact, storage system vapor loses may become too great before these points can be reached.

In the case of wellhead separation equipment an operator generally wants to determine the optimum conditions for a separator to produce the maximum income. Again, generally speaking, the liquid recovered is worth more than the gas. So high liquid recovery is a desirable feature, providing it can be held in the available storage system. Also, pipeline requirements for the BTU content of the gas may be another factor affecting the separator operation. Without the addition of expensive mechanical refrigeration equipment it is often not feasible to try to affect the operating temperature of a separator. However, on most high pressure wells an indirect heater is used to heat the gas prior to pressure reduction in a choke to pipeline pressure. By careful operation of this indirect heater the operator can prevent overheating of the gas stream prior to choking, more than what is required, and therefore affect the temperature of the separator downstream from the indirect heater.

The operator can also control the operating pressure to some extent with the use of back pressure valves within the limitation of the flowing characteristics of the well against a set pressure head and the transmission line pressure requirements. As previously mentioned, higher operating pressure will generally result in higher liquid recovery.

An analysis can be made using the well stream composition to find the optimum temperature and pressure at which a separator should operate to give the maximum liquid and/or gas phase recovery. These calculations, known as “Flash Vaporization Calculations,” require a trial-and-error solution and are more generally adapted to solution by a programmed computer. However, an operator can also make trial settings within the limitations of the equipment to find the best operating conditions to result in the maximum amount of gas or liquids that are desired. In the case where separators are used as scrubbers or knockouts ahead of other treating equipment or compressors, it is generally desired to remove the maximum amount of liquid from the gas stream to prevent operational damage to the equipment downstream from the scrubber.

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