Dehydration hydrate formation, preventing

Dehydration can be performed by a number of methods cooling, absorption and adsorption. Water removal by cooling is simply a condensation process at lower temperatures the gas can hold less water vapour. This method of dehydration is often used when gas has to be cooled to recover heavy hydrocarbons. Inhibitors such as glycol may have to be injected upstream of the chillers to prevent hydrate formation. 

Methods of preventing hydrate formation include adding heat to assure that the temperature is always above the hydrate formation temperature, lowering the hydrate formation temperature with chemical inhibition, or dehydrating the gas so that water vapor will not condense into free water. It is also feasible to design the process so that if hydrates form they can be melted before they plug equipment. 

Dehydration to dew points below the temperature to which the gas will be subjected will prevent hydrate formation and corrosion from condensed water. The latter consideration is especially important in gas streams containing CO2 or H2S where the acid gas components will form an acid with the condensed water. 

Gas specifications will be inqportant only if the gas is to be delivered to a gas pipeline system. If the gas is to be injected in the producing field the only usual critical requirement is to dehydrate the gas adequately to prevent hydrate formation anywhere in the system. The gas pipeline specification which most Influences the design of oil-gas separation systems is the hydrocarbon dewpoint limitation. This is usually expressed as a maximum dewpoint temperature at a specified pressure. For onshore gas pipelines in the USA end Europe this specification may be in the range of 32°F (0°C) at 1000 paia (68 atmospheres), which is adequate to prevent condensation of liquids in the pipelines in the normal range of onshore pipeline operating pressures from 900 to 1000 psl. In the USA this specification is seldom iiqposcd on producers and is controlled with pipeline facilities. 

Hydrate formation can be prevented or avoided in two ways (1) by dehydration, in which water is removed from the gas stream so that under conditions of processing or transporting, no liquid water will condense and (2) by inhibition, which involves injecting into the gas stream a component that will dissolve the water and thus interfere with the ability of the water to form hydrates with the gas. Both procedures are widely used in the gas industry. 

Removal of water vapors from the gas. This process is called gas dewatering (dehydration). Since dehydration causes a decrease in the threshold temperature of hydrate formation, this procedure often includes additional steps intended to prevent the formation of hydrates. 

Methods used for prevention of hydrate formation are dictated by physical and chemical nature of a process. Since equilibrium parameters of hydrates formation depend on partial pressure of water vapor in hydrating medium, any action lowering such pressure reduces the temperature of hydrate formation. In practice, the two ways are used dehydration of gas from moisture and the input into gas flow of various water-absorbing substances called inhibitors. 

An effective and reliable method to prevent hydrate formation is gas dehydration during its preparation before transport in gas pipeline. It is necessary to de-water gas up to the dew-point some degrees below minimally possible temperature in gas pipeline. As hydrate inhibitor is high-concentrated water solution of glycol (DEG). The process of gas dehydration was in detail considered in the previous chapter. 

The dehydration of relatively pure carbon dioxide is of increasing interest because of its use in enhanced oil recovery (EOR) projects. These projects often require the transmission of CO2 as supercritical fluid from the production facility to the consuming locations. As with natural gas transmission, dehydration is normally required to prevent corrosion and/or hydrate formation in the transmission lines and downstream equipment. Unlike natural gas, the saturated water content of carbon dioxide increases with increased pressure at pressures above about 1,000 psia. This effect is shown in Figure 11-4 (Case et al., 1985). A much more detailed discussion of the variation of water content of C02-rich gas streams with temperature, pressure, and composition is given by Diaz et al. (1991). 

Water has to be removed from natural gas in order to prevent hydrate formation (which results in pressure loss and even plugging of gas conducts) and corrosion in pipelines. Generally containing around 500-1500 ppmv of water from the wellhead, natural gas has to be dehydrated up to 20-150 ppmv in order to prevent condensation or hydrate formation problems. So far, such an operation is realized by absorption on diethylene or triethylene glycol. This type of process is widely used in the gas processors community because of its very low investment and operating costs, as well as its reliability as an illustration, 40000 of those units are in operation nowadays on the US ground for natural gas conditioning. ... 

There are other reasons for dehydrating a stream. In the natural gas business, the gas should be "dry," relatively free of water, in order to prevent hydrates and to prevent the formation of an aqueous phase, especially during transportation. In acid gas injection, this becomes more important since aqueous solutions of acid gases are highly corrosive. 

Dehydration of natural gas is necessary to prevent the formation of gas hydrates, which can plug valves and other components of a gas pipeline, and also to reduce potential corrosion prob-... 

Liquid water and sometimes water vapor are removed from natural gas to prevent corrosion and formation of hydrates in transmission lines and to attain a water dew point requirement of the sales of gas. Many sweetening agents employ an aqueous solution for treating the gas. Therefore dehydrating the natural gas that normally follows the sweetening process involves ... 

The use of solid desiccant is limited to applications such as those with very low water dewpoint requirements, simultaneous control of water and hydrocarbon dewpoints, and in very sour gases. In cryogenic plant, solid-desiccant dehydration is much preferred over methanol injection to prevent hydrate and ice formation. 

Apparently, no attempts have been made to determine accurately the equilibria at various temperatures for the dehydration reaction, possibly because of the difficulties involved in the prevention of complicating side reactions which are invariably present in the temperature range involved, approach to the equilibrium from the hydration of ethylene side is impractical since ethylene has been found to hydrate with considerable difficulty in the vapor phase. Also, the formation of ethyl ether has been found to occur over a wide range of temperatures and is a complicating factor, especially at the lower temperatures. 

Invert emulsion drilling fluids are commonly selected for their temperature stability and their ability to prevent the wellbore stability problems associated with the hydration of clays in shale formations. The thermodynamic activity aw of the water in the aqueous (dispersed) phase is controlled by the addition of a salt (usually calcium chloride) to ensure that it is equal to or less than the activity of the water in the drilled shale formations. The emulsified layer around the water droplets is claimed to act as a semipermeable membrane that allows the transport of water into and out of the shale but not the transport of ions (61). When the activities (or, more strictly, the chemical potentials) of the water in the shale and invert emulsion are equal, then no net transport of water into or out of the shale occurs (i.e., the drilling fluid does not hydrate or dehydrate the shale). This equality of water activity has lead to the development of so-called balanced activity oil-based drilling fluids. 

In normal portland cement, hydration leads to the formation of ettringite. In many instances, the formation of ettringite leads to expansion. To prevent the formation of ettringite, a gypsum-based material with 75% hemihydrate, 20% portland cement, 5% silica fume, and a superplasticizer was fabricated. The pastes were cured in water for 1 to 10 minutes and subjected to DTA. In Fig. 10, thermograms show the stepwise dehydration endothermal peaks (shown upwards) at 150° and 200°C as is typical of gypsum. There was no indication of ettringite or monosulfate, which normally are identified by peaks at 125-130° and 190-195°C. 

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