Water content in hydrocarbon gas

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. 

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. 

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. 

The composition of the carrier gas containing the nitrogen oxides is another very important factor in NO removal. The influence of oxygen content in N2/02/N0 mixtures on the conversion of NO was investigated [26-28], The addition of water vapor [26,27,29-32], carbon dioxide [26,32] and hydrocarbons [27-35] was studied as well. 

Conventional pipeline calculations in which "dry" hydrocarbon flashes are performed to determine the hydrocarbon liquid formation the liquid water condensed is estimated using one of the available natural gas water content charts (1, 15), and the Hammerschmidt equation (11) and a graphical correlation are used to... 

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... 

In the subsurface, kerosene volatilization is controlled by the physical and chemical properties of the solid phase and by the water content. Porosity is a major factor in defining the volatilization process. Galin et al. (1990) reported an experiment where neat kerosene at the saturation retention value was recovered from coarse, medium, and fine sands after 1, 5, and 14 days of incubation. The porosity of the sands decreased from coarse to fine. Figure 8.9 presents gas chromatographs obtained after kerosene volatilization. Note the loss of the more volatile hydrocarbons by evaporation in all sands 14 days after application and the lack of resemblance to the original kerosene. It is clear that the pore size of the sands affected the chemical composition of the remaining kerosene. For example, the fractions disap-... 

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