Water removal from natural gas

Water removal Water removal from natural gas Air drying Gas drying 109, 110... 

In summary, the specific implementation of this absorption system provides another approach to the problem of water removal from natural gas stteams. Humidity levels as low as 300ppm were detected in the treated gas stream. This is still above the levels established by the regulations, but corresponds to a yield of 92.5% in the absorption capacity of the microemulsions. The surfactants used in this investigation do contain a certain amount of water in their original constitution, and no previous treatment was performed with them. Interestingly, their potential as good components in desiccant fluid formulations was demonstrated in the results presented herein, since high water absorption capacity was effected by the system... 

Nobrega, G. A. S. 2003. Water removal from natural gas via absorption using microemulsion systems, M.Sc. dissertation, PPGEQ, Chemical Engineering Department, UERN, Brazil (in Portuguese). 

Moisture must be removed from natural gas to reduce corrosion problems and to prevent hydrate formation. Hydrates are solid white compounds formed from a physical-chemical reaction between hydrocarbons and water under the high pressures and low temperatures used to transport natural gas via pipeline. Hydrates reduce pipeline efficiency. 

Drizo A variation of the glycol process for removing water vapor from natural gas, in which the water is removed from the glycol by stripping with a hydrocarbon solvent, typically a mixture of pentanes and heavier aliphatic hydrocarbons. The process also removes aromatic hydrocarbons. Last traces of water are removed from the triethylene glycol by stripping with toluene in a separate, closed loop. Invented in 1966 by J. C. Arnold, R. L. Pearce, and H. G. Scholten at the Dow Chemical Company. Twenty units were operating in 1990. U.S. Patent 3,349,544. 

The formation of acid in water is another reason that acid gases are often removed from natural gas. The acidic solutions are very corrosive and require special materials to handle them. 

One option is CO2 disposal (disposal in ocean, injection in aquifers, confination in depleted gas or oil wells, injection for enhanced oil recovery). This is now done in Norway (Sleipner gas field) where 2740 t of CO2 per day are removed from natural gas. This CO2 is then compressed and injected into a water-filled sandstone reservoir (deep aquifer) [2]. 

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 ... 

Sulfoxides and sulfones (Figure 9.13) contain both sulfur and oxygen. Dimethylsulfoxide (DMSO) is a liquid used to remove paint and varnish, as a hydraulic fluid, mixed with water as an antifreeze solution, and in pharmaceutical applications as an anti-inflammatory and bacteriostatic agent. Sulfolane dissolves both organic and inorganic solutes and is widely used in BTX processing to selectively extract benzene, toluene, and xylene from aliphatic hycbocarbons as the solvent in the Sulfinol process by which thiols and acidic compounds are removed from natural gas as a solvent for polymerization reactions and as a polymer plasticizer. 

Zeolites Zeolites are natural or synthetic crystalline aluminosilicates which have a repeating pore network and release water at high temperature. Zeolites are polar in nature. Properties of zeolites are discussed in detail in Chap. 8 (Vol. 2). Therefore, we will only say that zeolites exhibit micropore structure with very small size and uniform distribution, as depicted in the pore size distribution shown in Fig. 12.1. The channel diameter of zeolite cages usually ranges from 0.2 to 0.9 mn. Applications of zeolites include gas drying, CO removal from natural gas, CO removal from reforming gas, and... 

Hgure 6-11. Simplified flow diagram of pilot plant used to study HzS removal from natural gas by water absorption. Data of Bradley and Dunne (1957)... 

Carbon Dioxide, Hydrogen Sulfide, and Water Removal, 1270 Helium Removal from Natural Gas, 1281 Air Separation, 1282 Solvent Vapors, 1288... 

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. ... 

Natural gas enrichment (CO2/CH4 membrane separation) is employed to remove CO2 from natural gas streams as well as for recovering CO2 in enhanced oil recovery processes. Methane recovery from landfill sources is an additional application. Membranes are employed for hydrogen recovery in ammonia ptuge gas, H2/CO ratio adjustments in hydrogen production (HYCO process), in hydrocracker and hydrotreater ptuge gas, and in catalytic reformer off-gas. With the very high permeability of water versus common gases, membranes have fotmd applications for air dehydration and natural gas dehydration. Additional applications include helium recovery and H2S removal from natural gas. 

The solubilities of the various gases in [BMIM][PFg] suggests that this IL should be an excellent candidate for a wide variety of industrially important gas separations. There is also the possibility of performing higher-temperature gas separations, thanks to the high thermal stability of the ILs. For supported liquid membranes this would require the use of ceramic or metallic membranes rather than polymeric ones. Both water vapor and CO2 should be removed easily from natural gas since the ratios of Henry s law constants at 25 °C are -9950 and 32, respectively. It should be possible to scrub CO2 from stack gases composed of N2 and O2. Since we know of no measurements of H2S, SO, or NO solubility in [BMIM][PFg], we do not loiow if it would be possible to remove these contaminants as well. Nonetheless, there appears to be ample opportunity for use of ILs for gas separations on the basis of the widely varying gas solubilities measured thus far. 

The production of synthesis gas from natural gas and coal is the basis of the 33 000000 tpa methanol production and is also used in the production of ammonia. After removal of sulfur impurities, methane and water are reacted over a nickel oxide on calcium aluminate catalyst at 730 °C and 30 bar pressure. The reaction is highly endothermic (210 kJmol ) (Equation 6.6). 

Sulfinol A process for removing hydrogen sulfide, carbon dioxide, carbonyl sulfide, and organic sulfur compounds from natural gas by scrubbing with di-isopropanolamine dissolved in a mixture of sulfolane and water. Developed in the 1960s by Shell International Research Mij N.V, The Netherlands and Shell Development Company, Houston. In 1996, over 180 commercial units were operating or under construction. 

Townsend A process for removing hydrogen sulfide from natural gas by absorption in triethylene glycol containing sulfur dioxide. Part of the sulfur produced is burnt to sulfur dioxide in order to provide this solution. The hydrogen sulfide and sulfur dioxide react in the presence of water to generate elemental sulfur. Invented in 1959 by F. M. Townsend. 

B. Sour gas treating involves the removal of the acid gas components CO2 and H2S from natural gas. Most ways of doing this involve water solutions. Treating is normally at near ambient temperatures and at pressures to 7100 kPa (70 Atm). The treating of high acid gas content natural gas is becoming more important as the value of natural gas increases. 

As with the sweetening application our most common need for CO2 removal is from natural gas prior to liquefaction. In this application we are often faced with amounts of oxygen in the feed that may range up to several hundred ppm by volume. The process is often limited to adsorption at a total pressure of about 3 5 bar. In this application however the feed gas is most often pipeline natural gas which gas will have been pre-dried to pipeline standards or about seven pounds (1 lb = 0.45 kg) of water per MMSCF of gas. In some cases the gas source may be other than pipeline and the water load needs to be estimated based on a given mole fraction. The liquefaction process, which runs at -260°F (127°C), demands very low levels of water in the product as well as trace levels of CO2 so that the heat exchangers in the downstream process remain clean. 

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