GAS-SEPARATORS

Separators



  1. Introduction: Hydrocarbon streams as produced at the wellhead are composed of a mixture of gas, liquid hydrocarbons and sometimes free water. In most cases, it is desirable to separate these phases as soon as possible after bringing them to the surface and handle or transport the two or three phases separately.
  2. This separation of the liquids from the gas phase is accomplished by passing the well stream through an oil-gas or oil-gas-water separator. Different design criteria must be used in sizing and selecting a separator for a hydrocarbon stream based on the composition of the fluid mixture. In the case of low-pressure oil wells, the liquid phase will be large in volume as compared to the gas phase. In the case of high-pressure gas-distillate wells, the gas volume will be higher as compared to the liquid volume. The liquid pr9oduced with high-pressure gas is generally a high API gravity Hydrocarbon, usually referred to as a distillate or condensate.
  • However, both low-pressure oil wells and high-pressure gas-distillate wells may contain free water. Separators are used in many other locations than wellhead production batteries, such as gasoline plants, upstream and downstream of compressors, and liquid traps in gas transmission lines. They are also found on inlets to dehydration units, gas sweetening units et cetera. At some of these locations, separators are called knockouts, Free liquid knockouts or traps. Sometimes they are called scrubbers. All of the vessels mentioned above are designed to separate gas and free liquids and serve the same purpose.
  1. The principal items of construction present in a good separator are common regardless of shape or configuration. They are as follows:
        1. An inlet device for primary separation of liquid and gas
        2. A settling section of sufficient size to allow liquid droplets to settle out of the gas with adequate surge room for slugs of liquid.
        3. A mist extractor or vane pack near the gas outlet that will coalesce the small particles of liquid that will not settle out by gravity alone.
        4. Adequate controls consisting of a level controller, liquid dump valve, gas back pressure control valve, safety relief valve, pressure gauge, level gauge(s), instrument gas (or air) regulator(s) and piping for each phase.
  1. It has been found that the bulk of gas-liquid separation takes place in the inlet section. Here the incoming stream is knocked, or centrifugally spun to up to 500x gravity. This stops the horizontal motion of the free liquid and forces liquid droplets together so they can fall to the bottom of the separator.
  2. The settling section is required to allow turbulence of the fluid stream to subside and allow the liquids to fall to the bottom with the aid of gravity. Special quieting baffles are sometimes used, but also often avoided in cases where sludge, paraffin or asphaltenes might cause plugging problems. Surge room or settling volume sizing can be difficult to determine based on well test data alone, so in most cases, the separator size used for an application is often a compromise between initial cost and estimated surge requirement assumptions.
  • The mist extractor or vane pack is designed to effect good liquid-gas separation. Small liquid droplets that will not settle out of the gas stream will be entrained and pass out of the separator without a mist eliminator section. The mist eliminator sections have a large impingement area for small droplets to hit, coalesce and collect and to form larger droplets which will then drain back into the liquid section at the bottom of the separator. Woven Stainless Steel wire mist extractors are the most efficient and are proven to be up to 99.9% efficient. Vane packs or other packing materials are also used and offered in special cases, such as where entrained solids could collect and plug a mistex, or special very high flow conditions.
  • There are two common separator configurations:
        1. Vertical
        2. Horizontal
  1. A typical low-pressure oil –  gas separator with mechanical controls and features as previously described is described in figure 8 (Andre insert figure 8 from Sivalls College package Chapter 1 Separators, here) Figure 9 illustrates a typical vertical high pressure or low-pressure oil-gas separator with pneumatic controls. The vertical separator has the advantage that it will handle greater slugs of liquid without carrying over to the gas outlet and the action of the liquid level control is not quite as critical. Due to the greater vertical distance between the liquid level and the gas outlet, there is less tendency to re-vaporize the liquid int the gas phase. Some disadvantages are that it is more difficult and expensive to fabricate and ship this type of separator in skid mounted assemblies and it takes a larger diameter separator for each given gas capacity than a horizontal vessel. From this, it can be seen that this type of separator is most often used on fluid streams with low gas-oil ratios; in other words, handling considerably more liquid than the gas.
  2. The horizontal separator has several different advantages particular to this type of construction. Figure 10 illustrates a typical horizontal high or low-pressure oil-gas separator with pneumatic controls. The horizontal separator configuration has several advantages over the vertical separator as it is easier to skid mount, less piping is required for field connection and a smaller diameter is required for a given gas capacity. This type of vessel also has a larger interface area between the liquid and gas separation phases which aids separation. When gas capacity is a design criterion, the horizontal vessel is more economical in high-pressure separator, due to the increased wall thickness required with larger diameters. However liquid level control placement is more critical than in a vertical separator and the surge space is somewhat limited.
  3. Three phase oil -ga-water separation can easily be accomplished in any type of separator by installing internal baffling to construct a water leg or siphon arrangement or by use of an interface liquid level control. With three phase operation, two liquid level controls and tow liquid dump valves are required. Figure 11 shows a typical high or low-pressure separator equipped for oil-gas-water three phase operation. Figure 12 is an illustration of a typical horizontal high pressure or low-pressure oil-gas-water separator.
  • An evaluation of the advantages and disadvantages of the various types of separators determined the horizontal separator to have the most efficient operation for initial investment costs for high-pressure gas distillate wells with high gas-oil ratios. For high liquid loading, either low pressure or high pressure, vertical type separators should be considered.
  • Factors affecting Separation:
        1. Operating pressure
        2. Operating temperature
        3. Fluid stream composition
  • Changes in any 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. Generally speaking, an increase in operating pressure or a 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.
  1. In the case of wellhead separation equipment, an operator wants to determine the optimum conditions for a separator to produce maximum return on investment. Generally speaking, the liquid recovered is worth more than the gas, so high liquid recovery is desirable. Pipeline requirements for the BTU content of the gas may be another factor affecting the separator design.
Sivalls