Hydrocarbon Compression

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Gas Processing Design

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The design of any of the distillation processes discussed requires choosing an operating pressure, bottoms temperature, reflux condenser temperature and number of trays. This is normally done using any one of several commercially available process simulation programs which can perform the iterative calculations.

Some typical parameters for design are shown in Table 9-4. The actual optimum to use for any given process will vary depending on actual feed properties, product specifications, etc.

 Gas Processing Design

 Gas Processing Design

In Table 9-4 the actual number of trays are included. This is because complete equilibrium between vapor and liquid is normally not reached on each tray. For calculation purposes the number of theoretical flashes may be quite a bit less than the number of trays. For smaller diameter towers packing is used instead of trays. Manufacturers supply data for their packing material which indicates the amount of feet of packing required to provide the same mass transfer as a standard bubble cap tray.

Some recent advances in structured packing are being used by some operators in larger diameter towers where they would have normally used trays. The structured packing is said to allow both smaller diameter and less height of tower.

Once the operating conditions are established for a tower, its diameter and height can be chosen using data available from tray and packing manufacturers. The details of tower diameter selection, tray spacing, and internal design are beyond the scope of this text.

Written by Jack

September 21st, 2009 at 2:03 pm

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Fractionation Gas Processing

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The bottoms liquid from any gas plant may be sold as a mixed product. This is common for small, isolated plants where there is insufficient local demand. The mixed product is transported by truck, rail, barge or pipeline to a central location for further processing. Often it is more economical to separate the liquid into its various components and sell it as ethane, propane, butane, and natural gasoline. The process of separating the liquids into these components is called fractionation.

Figure 9-4 shows a typical fractionation system for a refrigeration or lean oil plant. The liquid is cascaded through a series of distillation towers where successively heavier and heavier components (fractions) are separated as overhead gas. In this figure the liquid from the still of an absorption plant or the de-methanizer (or de-ethanizer) tower of an expansion or refrigeration plant is routed to a de-propanizer. If there is too high a fraction of butanes-plus in the propane, this can be reduced by adjusting the de-propanizer pressure upward or reflux condensing temperature downward. If the vapor pressure of the propane exceeds the required specification this means that the fraction of methane and ethane in the inlet stream is too high. This fraction can be adjusted downward by increasing the temperature or decreasing the operating pressure of the still or tower that feeds liquid to the de-propanizer.

 Fractionation Gas Processing

The de-butanizer works in a similar manner. The upstream tower (depropanizer) determines the maximum vapor pressure of the butane product. If the concentration of propane-minus is too large in the inlet stream, the vapor pressure of the butane overheads will be too high. Similarly, the concentration of pentanes-plus in the butane will depend upon the reflux condensing temperature and tower operating pressure. If the pentanes-plus exceed specifications, further reflux cooling or a higher operating pressure will be needed to condense pentanes-plus from the butane overheads.

The temperature at the base of the de-butanizer determines the vapor pressure of the gasoline product. If its vapor pressure is too high, the temperature must be increased or the tower pressure decreased to drive more butanes-minus out of the bottoms liquids.

If the feed to the fractionator contains recoverable ethane, such as is likely to be the case with a cryogenic plant, then a de-ethanizer tower would be installed upstream of the de-propanizer.

Written by Jack

September 21st, 2009 at 12:55 pm

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Cryogenic Plants Gas Processing

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Figure 9-3 shows a typical cryogenic plant where the gas is cooled to -100°F to ~150°F by expansion through a turbine or Joule-Thompson (J-T) valve. In this example liquids are separated from the inlet gas at 100°F and 1,000 psig. It is then dehydrated to less than 1 ppm water vapor to assure that hydrates will not form at the low temperatures encountered in the plant. Typically, a mole sieve dehydrator is used.

 Cryogenic Plants Gas Processing

The gas is routed through heat exchangers where it is cooled by the residue gas, and condensed liquids are recovered in a cold separator at approximately -90°F. These liquids are injected into the de-methanizer at a level where the temperature is approximately -90°F. The gas is then expanded (its pressure is decreased from inlet pressure to 225 psig) through an expansion valve or a turboexpander. The turboexpander uses the energy removed from the gas due to the pressure drop to drive a compressor, which helps recompress the gas to sales pressure. The cold gas {-150°F) then enters the de-methanizer column at a pressure and temperature condition where most of the ethanes-plus are in the liquid state.

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.

The gas turbine driven compressor is required since there are energy losses in the system. The energy generated by expanding the gas from 600 psig to 225 psig in the turbo-expander cannot be 100% recovered and used to recompress the residue gas from 225 psig to 600 psig. In this particular plant it is only capable of recompressing the gas to 400 psig, Thus, even if the inlet gas and sales gas were at the same pressure, it would be necessary to provide some energy in the form of a compressor to recompress the gas.

Because of the lower temperatures that are possible, cryogenic plants have the highest liquid recovery levels of the plants discussed. Typical levels are:

 Cryogenic Plants Gas Processing

Written by Jack

September 21st, 2009 at 11:31 am

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Refrigeration Gas Processing

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In a refrigeration plant the inlet gas is cooled to a low enough temperature to condense the desired fraction of LPG and NGL. Either freon or propane is used as the refrigerant. Figure 9-2 shows a typical refrigeration plant.

The free water must be separated and the dew point of the gas lowered before cooling the feed to keep hydrates from forming. It is possible to dehydrate the gas with TEG or mole sieves to the required dew point. It is more common to lower the hydrate temperature by injecting glycol in the gas after separation of free water. The glycol and water separate in the cold separator where they are routed to a regenerator, the water is boiled off and the glycol is circulated back to be injected into the inlet stream. Some glycol will be lost with time and will have to be made up, The most common glycol used for this service is ethylene glycol because of its low cost and the fact that at the low temperatures it is not lost to the gas phase.

 Refrigeration Gas Processing

The chiller is usually a kettle type exchanger. Freon (which is cooled in a refrigeration cycle to -20°F) is able to cool the gas to approximately -15°F. Propane, which can be cooled to ~40°F, is sometimes used if lower gas temperatures and greater recovery efficiences are desired.

The gas and liquid are separated in the cold separator, which is a three phase separator. Water and glycol come off the bottom, hydrocarbon liquids are routed to the distillation tower and gas flows out the top. If it is desirable to recover ethane, this still is called a de-methanizer. If only propane and heavier components are to be recovered it is called a de-ethanizer. The gas is called “plant residue” and is the outlet gas from the plant.

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.

By decreasing the pressure and increasing the bottoms temperature more methane and ethane can be boiled off the bottoms liquid and the RVP of the liquid stream decreased to meet requirements for sales or further processing. Typical liquid recovery levels are:

 Refrigeration Gas Processing

These are higher than for a lean oil plant. It is possible to recover a small percentage of ethane in a refrigeration plant. This is limited by the ability to cool the inlet stream to no lower than -40°F with normal refrigerants.

Most refrigeration plants use freon as the refrigerant and limit the lowest temperature to ~20°F. This is because the ANSI piping codes require special metallurgy considerations below -20°F to assure ductility.

Written by Jack

September 21st, 2009 at 11:15 am

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Lean Oil Absorption Process

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The oldest kind of gas plants are absorption/lean oil plants, where a kerosene type oil is circulated through the plant as shown in Figure 9-1. The “lean oil” is used to absorb light hydrocarbon components from the gas. The light components are separated from the rich oil and the lean oil is recycled.

 Lean Oil Absorption Process

Typically the inlet gas is cooled by a heat exchanger with the outlet gas and a cooler before entering the absorber. The absorber is a contact tower, similar in design to the glycol contact tower. The lean absorber oil trickles down over trays or packing while the gas flows upward counter current to the absorber oil. The gas leaves the top of the absorber while the absorber oil, now rich in light hydrocarbons from the gas, leaves the bottom of the absorber. The cooler the inlet gas stream the higher the percentage of hydrocarbons which will be removed by the oil.

Rich oil flows to the rich oil de-ethanizer (or de-methanizer) to reject the methane and ethane (or the methane alone) as flash gas. In most lean oil plants the ROD unit rejects both methane and ethane since very little ethane is recovered by the lean oil. If only methane were rejected in the ROD unit, then it may be necessary to install a de-ethanizer column downstream of the still to make a separate ethane product and keep ethane from contaminating (i.e., increasing the vapor pressure of) the other liquid products made by the plant.

The ROD is similar to a cold feed stabilizing tower for the rich oil. Heat is added at the bottom to drive off almost all the methane (and most likely ethane) from the bottoms product by exchanging heat with the hot lean oil coming from the still. A reflux is provided by a small stream of cold lean oil injected at the top of the ROD. Gas off the tower overhead is used as plant fuel and/or is compressed. The amount of intermediate components flashed with this gas can be controlled by adjusting the cold lean oil reflux rate.

Absorber oil then flows to a still where it is heated to a high enough temperature to drive the propanes, butanes, pentanes and other natural gas liquid components to the overhead. The still is similar to a crude oil stabilizer with reflux. The closer the bottom temperature approaches the boiling temperature of the lean oil the purer the lean oil which will be recirculated to the absorber. Temperature control on the condenser keeps lean oil from being lost with the overhead.

Thus the lean oil, in completing a cycle, goes through a recovery stage where it recovers light and intermediate components from the gas, a rejection stage where the light ends are eliminated from the rich oil and a separation stage where the natural gas liquids are separated from the rich oil.

These plants are not as popular as they once were and are rarely, if ever, constructed anymore. They are very difficult to operate, and it Is difficult to predict their efficiency at removing liquids from the gas as the lean oil deteriorates with time. Typical liquid recovery levels are:

 Lean Oil Absorption Process

 

Written by Jack

September 21st, 2009 at 11:06 am

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Natural Gas Processing

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The term “gas processing” is used to refer to the removing of ethane, propane, butane, and heavier components from a gas stream. They may be fractionated and sold as “pure” components, or they may be combined and sold as a natural gas liquids mix, or NGL.

The first step in a gas processing plant is to separate the components that are to be recovered from the gas into an NGL stream. It may then be desirable to fractionate the NGL stream into various liquefied petroleum gas (LPG) components of ethane, propane, iso-butane, or normal-butane. The LPG products are defined by their vapor pressure and must meet certain criteria as shown in Table 9-1. The unfractionated natural gas liquids product (NGL) is defined by the properties in Table 9-2. NGL is made up principally of pentanes and heavier hydrocarbons although it may contain some butanes and very small amounts of propane. It cannot contain heavy components that boil at more than 375°F.

In most instances gas processing plants are installed because it is more economical to extract and sell the liquid products even though this lowers the heating value of gas. The value of the increased volume of liquids sales may be significantly higher than the loss in gas sales revenue because of a decrease in heating value of the gas.

In deciding whether it is economical to remove liquids from a natural gas stream, it is necessary to evaluate the decrease in gas value after extraction of the liquid. Table 9-3 shows the break-even value for various liquids. Below these values the molecules will be more valuable as gas.

The difference between the actual sales price of the liquid and the break-even price of the liquid in Table 9-3 provides the income to pay out the capital cost, fuel cost, and other operating and maintenance expenses necessary to make the recovery of the gas economically attractive.

Another objective of gas processing is to lower the Btu content of the gas by extracting heavier components to meet a maximum allowable heating limit set by a gas sales contract. If the gas is too rich in heavier components, the gas will not work properly in burners that are designed for lower heating values. A common maximum limit is 1100 Btu per SCE Thus, if the gas is rich in propane and heavier components it may have to be processed to lower the heating value, even in cases where it may not be economical to do so.

 Natural Gas Processing

Written by Jack

September 21st, 2009 at 10:32 am

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