Water Content of Hydrocarbon Gas

The water content of hydrocarbon gas has been studied thoroughly and there are several shortcut methods that are accurate for the prediction of this behavior. It is not our intention to present a complete review of the water content of hydrocarbon gas, but to present an introduction and to contrast its behavior with that of acid gases. 

One observation can be made about the water content of sweet gas As the pressure increases, the water content decreases. This is the case for all pressures of concern to the natural gas production and processing industries - that is, for pressures up to about 100 MPa (15,000 psi). 

Normally this would be referred to as sweet gas but sweet gas includes gas that is rich in COr Thus one must be cautious with this terminology because a gas rich in C02 behaves more like sour gas than hydrocarbon gas even though by the strict definition it is considered sweet. 

AQUAlibrium is a software package available from FlowPhase. See www. flowphase.com 

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Figure 5.6 Water content of hydrocarbon gas. (Courtesy Gas Processing Supplier Association.)...

A correction for acid gas should be made when the gas stream contains more than 5% COs and/or H2S. Figures 8-2 and 8-3 may be used to determine the water content of a gas containing less than 40% total concentration of acid gas. As an example, assume the example gas from the previous paragraph contains 15% H2S. The water content of the hydrocarbon gas is 94.8 Ib/MMscf. From Figure 8-3, the water content of HjS is 400 Ib/MMscf. The effective water content of the stream is equal to (0.85 )(94.8)- (0.]5)(400)or 141 Ib/MMscf. 

The water content of acid gases is significantly different from that of sweet gas. Water is significantly more soluble in acid gas than it is in hydrocarbon gas. In addition, as will be demonstrated, the water content of acid gas mixtures exhibit a minimum. 

Water Content of Systems Containing CO7 and H S. Frequently reservoir fluids and petroleum fractions contain significant concentrations of CO2 and H2S. When these fluids are in the presence of liquid water and an equilibrium gas and/or liquid phase it is of Interest to be able to calculate the water content of the gas and hydrocarbon liquid. A suitable scheme for making these predictions is currently being developed. Preliminary indications are that the dy values for water with CO2 or H2S will have to be temperature dependent. 

Commercial applications of the Selexol solvent for simultaneous hydrocarbon dew-point control and natural gas dehydration are de.scribed by Epps (1994). A plant design used in several European installations pretreats natural gas before it enters a molecular sieve unit. The design is intended to meet a treated gas specification of a maximum of 0.50 mole% CO2 and a maximum of 6.5 mole% ethane and heavier components. A plant is de.signed to treat 26 MMsefd of gas at 32"F and 603 psia. Operating data for this plant, given in Table 14-12, show that it meets the CO2 and ethane-plus removal specifications. The plant also reduces the water content of the gas from 75 ppmv to 12 ppmv, decreasing the load on the molecular sieve unit, and removes a major fraction of the sulfur components. 

The ability of the SRK equation of state to reliably predict the vapor phase water content of natural and synthetic gas systems has been demonstrated. In addition, the ability of the PFGC-MES equation to describe the phase behavior of hydrocarbon, acid gas, methanol, water systems has been described. Both... 

Another important aspect of the water content is that acid gases tend to liquefy much more readily than light hydrocarbon gas. Furthermore, the water content of the liquefied acid gas increases dramatically. That is, the water content of liquid acid gas is significantly greater than the vapor acid gas at the same conditions. 

A Presently available equations of state can be used to accurately calculate the water content of gas and hydrocarbon liquid phases but not the gaseous or liquid hydrocarbon content of the water phase. Equations of state can predict only qualitative results for the water phase. 

Water content in fuel gas is the miyor fiictor influencing internal corrosion. Hydrates, a semisolid combination of hydrocarbons and water, will form under the proper conditions causing serious operating problems. Fuel beating value is reduced by water concentration. Water concentration levels are therefore fiequently measured in natural gas systems. A common pipdine qiedfication is 4 to 7 lb/ MMSCF. This test me od describes measurement of water vapor content with direct readout electronic instrumentation. 

Many commercial gases are generated by burning hydrocarbons (qv) eg, natural gas or propanes, in air (see Gas, natural Liquified petroleum gas). The combustion process, especially the amount of air used, determines the gas composition. For a given fuel-to-air ratio, the gas composition can be used to determine the water vapor content required to achieve a desired equiUbrium carbon content of the austenite (see Combustiontechnology). 

Tetrahydronaphthalene [119-64-2] (Tetralin) is a water-white Hquid that is insoluble in water, slightly soluble in methyl alcohol, and completely soluble in other monohydric alcohols, ethyl ether, and most other organic solvents. It is a powerhil solvent for oils, resins, waxes, mbber, asphalt, and aromatic hydrocarbons, eg, naphthalene and anthracene. Its high flash point and low vapor pressure make it usehil in the manufacture of paints, lacquers, and varnishes for cleaning printing ink from rollers and type in the manufacture of shoe creams and floor waxes as a solvent in the textile industry and for the removal of naphthalene deposits in gas-distribution systems (25). The commercial product typically has a tetrahydronaphthalene content of >97 wt%, with some decahydronaphthalene and naphthalene as the principal impurities. 

Combustion. The primary reaction carried out in the gas turbine combustion chamber is oxidation of a fuel to release its heat content at constant pressure. Atomized fuel mixed with enough air to form a close-to-stoichiometric mixture is continuously fed into a primary zone. There its heat of formation is released at flame temperatures deterruined by the pressure. The heat content of the fuel is therefore a primary measure of the attainable efficiency of the overall system in terms of fuel consumed per unit of work output. Table 6 fists the net heat content of a number of typical gas turbine fuels. Net rather than gross heat content is a more significant measure because heat of vaporization of the water formed in combustion cannot be recovered in aircraft exhaust. The most desirable gas turbine fuels for use in aircraft, after hydrogen, are hydrocarbons. Fuels that are liquid at normal atmospheric pressure and temperature are the most practical and widely used aircraft fuels kerosene, with a distillation range from 150 to 300 °C, is the best compromise to combine maximum mass —heat content with other desirable properties. For ground turbines, a wide variety of gaseous and heavy fuels are acceptable. 

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