Foam at the interface may occur when gas bubbles are liberated from the liquid. This foam can be stabilized with the addition of chemicals at the inlet. Many times a more effective solution is to force the foam to pass through a series of inclined parallel plates or tubes as shown in Figure 4-8 so as to aid in coalescence of the foam bubbles.
In long horizontal vessels it is necessary to install wave breakers, which are nothing more than vertical baffles spanning the gas-liquid interface and perpendicular to the flow.
There are many types of inlet diverters. Two main types are baffle plates (shown in Figure 4-6) and centrifugal diverters (shown in Figure 4-7). A baffle plate can be a spherical dish, flat plate, angle iron, cone, or just about anything that will accomplish a rapid change in direction and velocity of the fluids and thus disengage the gas and liquid. The design of the baffles is governed principally by the structural supports required to resist the impact momentum load.
The advantage of using devices such as a half sphere or cone is that they create less disturbance than plates or angle iron, cutting down on re-entrainment or emulsifying problems. Centrifugal inlet diverters use centrifugal force, rather than mechanical agitation, to disengage the oil and gas. These devices can have a cyclonic chimney or may use a tangential fluid race around the walls. Centrifugal inlet diverters are proprietary but generally use an inlet nozzle sufficient to create a fluid velocity of about 20 fps. Centrifugal diverters work well in initial gas separation and help to prevent foaming in crudes.
A scrubber is a two-phase separator that is designed to recover liquids carried over from the gas outlets of production separators or to catch liquids condensed due to cooling or pressure drops. Liquid loading in a scrubber is much lower than that in a separator. Typical applications include: upstream of mechanical equipment such as compressors that could be damaged, destroyed or rendered ineffective by free liquid; downstream of equipment that can cause liquids to condense from a gas stream (such as coolers); upstream of gas dehydration equipment that would lose efficiency, be damaged, or be destroyed if contaminated with liquid hydrocarbons; and upstream of a vent or flare outlet. Vertical scrubbers are most commonly used. Horizontal scrubbers can be used, but space limitations usually dictate the use of a vertical configuration.
Cyclone separators are designed to operate by centrifugal force. These designs are best suited for fairly clean gas streams. The swirling action of the gas stream as it enters the scrubber separates the droplets and dust from the gas stream by centrifugal force. Although such designs can result in significantly smaller sizes, they are not commonly used in production operations because (1) their design is rather sensitive to flow rate and (2) they require greater pressure drop than the standard configurations previously described. Since separation efficiency decreases as velocity decreases, cyclone separators are not suitable for widely varying flow rates. These units are commonly used to recover glycol carryover downstream of a dehydration tower. In recent years, demand for using cyclone separators on floating facilities has increased because space and weight considerations are overriding on such facilities.Two-barrel separators are common where there is a very low liquid flow rate. In these designs the gas and liquid chambers are separated as shown in Figure 4-4. The flow stream enters the vessel in the upper barrel and strikes the inlet diverter. The free liquids fall to the lower barrel through a flow pipe. The gas flows through the gravity settling section and encounters a mist extractor en route to the gas outlet. The liquids drain through a flow pipe into the lower barrel. Small amounts of gas entrained in the liquid are liberated in the liquid collection barrel and flow up through the flow pipes. In this manner the liquid accumulation is separated from the gas stream so that there is no chance of high gas velocities re-entraining liquid as it flows over the interface. Because of their additional cost, and the absence of problems with single vessel separators, they are not widely used in oil field systems.
Another type of separator that is frequently used in some highgas/low-liquid flow applications is a filter separator. These can be either horizontal or vertical in configuration. Figure 4-5 shows a horizontal two-barrel design. Filter tubes in the initial separation section cause coalescence of any liquid mist into larger droplets as the gas passes through the tubes. A secondary section of vanes or other mist extractor elements removes these coalesced droplets. This vessel can remove 100% of all particles larger than about 2 microns and 99% of those down to about 1/2 micron. Filter separators are commonly used on compressor inlets infield compressor stations, final scrubbers upstream of glycol contact towers, and instrument/fuel gas applications. The design of filter separators is proprietary and dependent upon the type of filter element employed.
In applications where there is very little liquid flow, often a horizontal separator will be designed with a liquid sump on the outlet end to provide the required liquid retention time. This results in an overall smaller diameter for the vessel.
A typical spherical separator is shown in Figure 4-3. The same four sections can be found in this vessel. Spherical separators are a special case of a vertical separator where there is no cylindrical shell between the two heads. They may be very efficient from a pressure containment standpoint but because (1) they have limited liquid surge capability and (2) they exhibit fabrication difficulties, they are not usually used in oil field facilities. For this reason we will not be discussing spherical separators any further.
Figure 4-2 is a schematic of a vertical separator. In this configuration the inlet flow enters the vessel through the side. As in the horizontal separator, the inlet diverter does the initial gross separation. The liquid flows down to the liquid collection section of the vessel. Liquid continues to flow downward through this section to the liquid outlet. As the liquid reaches equilibrium, gas bubbles flow counter to the direction of the liquid flow and eventually migrate to the vapor space. The level controller and liquid dump valve operate the same as in a horizontal separator.
The gas flows over the inlet diverter and then vertically upward toward the gas outlet. In the gravity settling section the liquid drops fall vertically downward counter to the gas flow. Gas goes through the mist extractor section before it leaves the vessel. Pressure and level are maintained as in a horizontal separator.
The gas flows over the inlet diverter and then horizontally through the gravity settling section above the liquid. As the gas flows through this section, small drops of liquid that were entrained in the gas and not separated by the inlet diverter are separated out by gravity and fall to the gas liquid interface.
Some of the drops are of such a small diameter that they are not easily separated in the gravity settling section. Before the gas leaves the vessel it passes through a coalescing section or mist extractor. This section uses elements of vanes, wire mesh, or plates to coalesce and remove the very small droplets of liquid in one final separation before the gas leaves the vessel.
The pressure in the separator is maintained by a pressure controller. The pressure controller senses changes in the pressure in the separator and sends a signal to either open or close the pressure control valve accordingly. By controlling the rate at which gas leaves the vapor space of the vessel the pressure in the vessel is maintained. Normally, horizontal separators are operated half full of liquid to maximize the surface area of the gas liquid interface.
Produced wellhead fluids are complex mixtures of different compounds of hydrogen and carbon, all with different densities, vapor pressures, and other physical characteristics. As a well stream flows from the hot, high-pressure petroleum reservoir, it experiences pressure and temperature reductions. Gases evolve from the liquids and the well stream changes in character. The velocity of the gas carries liquid droplets, and the liquid carries gas bubbles. The physical separation of these phases is one of the basic operations in the production, processing, and treatment of oil and gas. In oil and gas separator design, we mechanically separate from a hydrocarbon stream the liquid and gas components that exist at a specific temperature and pressure. Proper separator design is important because a separation vessel is normally the initial processing vessel in any facility, and improper design of this process component can “bottleneck” and reduce the capacity of the entire facility.
Separators are classified as “two-phase” if they separate gas from the total liquid stream and “three-phase” if they also separate the liquid stream into its crude oil and water components. This chapter deals with two-phase separators. In addition, it discusses the requirements of good separation design and how various mechanical devices take advantage of the physical forces in the produced stream to achieve good separation. Separators are sometimes called “gas scrubbers” when the ratio of gas rate to liquid rate is very high. Some operators use the term “traps” to designate separators that handle flow directly from wells. In any case, they all have the same configuration and are sized in accordance with the same procedure.
FACTORS AFFECTING SEPARATION
Characteristics of the flow stream will greatly affect the design and operation of a separator. The following factors must be determined before separator design:
• Gas and liquid flow rates (minimum, average, and peak)
• Operating and design pressures and temperatures
• Surging or slugging tendencies of the feed streams
• Physical properties of the fluids such as density and compressibility
•Designed degree of separation (e.g., removing 100% of particles greater than 10 microns)
• Presence of impurities (paraffin, sand, scale, etc.)
• Foaming tendencies of the crude oil
• Corrosive tendencies of the liquids or gas