A drain system that is connected directly to pressure vessels is called a “pressure” or “closed” drain system. A drain system that collects liquids that spill on the ground is an “atmospheric,” “gravity,” or “open” drain. The liquid in a closed drain system must be assumed to contain dissolved gases that flash in the drain system and can become a hazard if not handled properly. In addition, it must be assumed that a closed drain valve could be left open by accident. Once the liquid has drained out of the vessel, a large amount of gas will flow out of the vessel into the closed drain system (gas blowby) and will have to be handled safely. Thus, closed drain systems should always be routed to a pressure vessel and should never be connected to an open drain system.
Liquid gathered in an open drain system is typically rain water or washdown water contaminated with oil. With the oil usually circulated back into the process, every attempt should be made to minimize the amount of aerated water that is recycled with the oil. This goal is best achieved by routing open drains to a sump tank that has a gas blanket and operates as a skimmer. To keep gas from the skimmer from flowing out the drain, a water seal should be built into the inlet to the sump tank. Water seals should also be installed on laterals from separate buildings or enclosures to keep the open drain system from being a conduit of gas from one location in the facility to another.
The skim pile is a type of disposal pile. As shown in Figure 7-18, flow through the multiple series of baffle plates creates zones of no flow that reduce the distance a given oil droplet must rise to be separated from the main flow. Once in this zone, there is plenty of time for coalescence and gravity separation. The larger droplets then migrate up the underside of the baffle to an oil collection system.
Besides being more efficient than standard disposal piles, from an oil separation standpoint, skim piles have the added benefit of providing for some degree of sand cleaning. Most authorities having jurisdiction state that produced sand must be disposed of without “free oil.” It is doubtful that sand from a vessel drain meets this criterion when disposed of in a standard disposal pile.
Sand traversing the length of a skim pile will abrade on the baffles and be water washed. This can be said to remove the free oil that is then captured in a quiescent zone.
Disposal piles are large diameter (24- to 48-inch) open-ended pipes attached to the platform and extending below the surface of the water. Their main uses are to (1) concentrate all platform discharges into one location, (2) provide a conduit protected from wave action so that discharges can be placed deep enough to prevent sheens from occurring during upset conditions, and (3) provide an alarm or shutdown point in the event of a failure causing oil to flow overboard.
Most authorities having jurisdiction require all produced water to be treated (skimmer tank, coalescer, or flotation) prior to disposal in a disposal pile. In some locations, disposal piles are permitted to collect treated produced water, treated sand, liquids from drip pans and deck drains, and as a final trap for hydrocarbon liquids in the event of equipment upsets.
Disposal piles are particularly useful for deck drainage disposal. This flow, which originates either from rainwater or washdown water, typically contains oil droplets dispersed in an oxygen-laden fresh or saltwater phase. The oxygen in the water makes it highly corrosive and commingling with produced water may lead to scale deposition and plugging in skimmer tanks, plate coalescers, or flotation units. The flow is highly irregular and would thus cause upsets throughout these devices. Finally, this flow must gravitate to a low point for collection and either be pumped up to a higher level for treatment or treated at that low point. Disposal piles are excellent for this purpose. They can be protected from corrosion, they are by design located low enough on the platform to eliminate the need for pumping the water, they are not severely affected by large instantaneous flow rate changes (effluent quality may be affected to some extent but the operation of the pile can continue), they contain no small passages subject to plugging by scale buildup, and they minimize commingling with the process since they are the last piece of treating equipment before disposal.
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