Stabilizers condensate

The need to obtain greater recoveries of the C9, C3, and C4S in natural gas has resulted in the expanded use of low-temperature processing of these streams. The majority of the natural gas processing at low temperatures to recover light hydrocarbons is now accomphshed using the turboexpander cycle. Feed gas is normally available from 1 to 10 MPa. The gas is first dehydrated to a dew point of 200 K and lower. After dehydration the feed is cooled with cold residue gas. Liquid produced at this point is separated before entering the expander and sent to the condensate stabilizer. The gas from the separator is... 

From a hydrate melting standpoint it is possible in the winter time to have too cold a liquid temperature and thus plug the liquid outlet of the low temperature separator. It is easier for field personnel to understand and operate a line heater for hydrate control and a multistage flash or condensate stabilizer system to maximize liquids recovery. 

The liquids that are separated from the gas stream in the first separator may be flowed directly to a tank or may be stabilized in some fashion. As was discussed in Chapter 2 of Volume 1, these liquids contain a large percentage of methane and ethane, which will flash to gas in the tank. This lowers the partial pressure of all other components in the tank and increases their tendency to flash to vapors. The process of increasing the amount of intermediate (C3 to C5) and heavy (C + ) components in the liquid phase is called stabilization. In a gas field this process is called condensate stabilization and in an oil field it is called crude stabilization. 

Gas condensate, on the other hand, may contain a relatively high percentage of intermediate components and can be easily separated from entrained water due to its lower viscosity and greater density difference with water. Thus, some sort of condensate stabilization should be considered for each gas well production facility. 

The simplest form of condensate stabilization is to install a low-pressure separator downstream of an initial high-pressure separator. Unless the gas well produces at low pressure (less than 500 psi) and the gas contains very little condensate (less than 100 bpd), the additional expend -... 

Figure 6-3 shows a condensate stabilizer system. The well stream flows to a high pressure, three-phase separator. Liquids containing a high fraction of light ends are cooled and enter the stabilizer tower at approxi-... 

Figure 6-4. CokJ-feed dish llation tower of condensate stabilization system.

A condensate stabilizer with reflux will recover more intermediate components from the gas than a cold-feed stabilizer. However, it requires more equipment to purchase, install, and operate. This additional cost must be justified by the net benefit of the incremental liquid recovery, less the cost of natural gas shrinkage and loss of heating value, over that obtained from a cold-feed stabilizer. 

The number of actual equilibrium stages determines the number of flashes that will occur. The more stages, the more complete the split, but the taller and more costly the tower. Most condensate stabilizers will normally contain approximately five theoretical stages. In a refluxed tower, the section above the feed is known as the rectification section, while the section below the feed is known as the stripping section. The rectification section normally contains about two equilibrium stages above the feed, and the stripping section normally contains three equilibrium stages. 

HETP for a 2-in. slotted metal ring in a condensate stabilizer is about 36 in. This is slightly more than a typical tray design, which would require 34 in. (1.4 trays X 24-in. tray spacing) for one theoretical plate or stage. 

A gas-processing plant, as described in Chapter 9, is designed to recover ethane, propane, butane, and other natural gas liquids from the gas stream. A condensate stabilizer also recovers some portion of these liquids. The colder the temperature of the gas leaving the overhead condenser in a reflux stabilizer, or the colder the feed stream in a cold-feed stabilizer, and the higher the pressure in the tower, the greater the recovery of these components as liquids. Indeed, any stabilization process that leads to recovery of more molecules in the final liquid product is removing those molecules from the gas stream. In this sense, a stabilizer may be considered as a simple form of a gas-processing plant. 

It is difficult to determine the point at which a condensate stabilizer becomes a gas plant. Typically, if the liquid product is sold as a condensate, the device would be considered a condensate stabilizer. If the product is sold as a mixed natural gas liquid stream (NGL) or is fractionated into its various components, the same process would be considered a gas plant. The least volatile NGL stream has an RVP between 10 and 14 and has sufficient light hydrocarbons such that 25% of the total volume is vaporized at 140°F. 

It should be clear from the description of LTX units in Chapter 5 that the lower pressure separator in an LTX unit is a simple form of cold-feed condensate stabilizer. In the cold, upper portion of the separator some of the intermediate hydrocarbon components condense. In the hot, lower portion some of the lighter components flash. 

In a trayed absorber the amine falls from one tray to the one below in the same manner as the liquid in a condensate stabilizer (Chapter 6, Figure 6-4). It flows across the tray and over a weir before flowing into the next downcomer. The gas bubbles up through the liquid and creates a froth that must be separated from the gas before it reaches the underside of the next tray. For preliminary design, a tray spacing of 24 in. and a minimum diameter capable of separating 150 to 200 micron droplets (using the equations developed in Volume 1 for gas capacity of a vertical separator) can be assumed. The size of packed towers must be obtained from manufacturer s published literature. 

The contactor works in the same manner as a condensate stabilizer tower described in Chapter 6. As the glycol falls from tray to tray it becomes richer and richer in water. As the gas rises it becomes leaner and leaner in water vapor. Glycol contactors will typically have between 6 and 12 trays, depending upon the water dew point required. To obtain a 7 Ib/MMscf specification, 6 to 8 trays are common. 

The tower operates in the same manner as a condensate stabilizer with reflux. The inlet liquid stream is heated by exchange with the gas to approximately 30 F and is injected in the tower at about the point in the tower where the temperature is 30 F. By adjusting the pressure, number of trays, and the amount of reboiler duty, the composition of the bottoms liquid can be determined. 

The de-methanizer is analogous to a cold feed condensate stabilizer As the liquid falls and is heated, the methane is boiled off and the liquid becomes leaner and leaner in methane. Heat is added to the bottom of the tower using the hot discharge residue gas from the compressors to assure that the bottom liquids have an acceptable RVP or methane content. 

Stabilizer T. [GrOnau] Protein fatty acid condensate stabilize f(v bleaching. 

A small-scale fluidized-catalyst test unit has been described by McReynolds (25). A standard gas-oil is vaporized and passed through a fluidized catalyst bed (400 g. of powdered catalyst) at 920°F. and at a rate of 925 ml. (800 g.) of liquid per hour for thirty minutes. The product is condensed, stabilized, and fractionated to 400°F. end-point gasoline. The activity of the catalyst is reported in terms of total conversion and per cent D + L."... 

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