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112 IPCC Special Report on Carbon dioxide Capture and Storage around 2% by volume (although this amount varies in different places) to prevent pipeline corrosion, to avoid excess energy for transport and to increase the heating value of the gas. Whilst accurate figures are published for annual worldwide natural gas production (BP, 2004), none seem to be published on how much of that gas may contain CO2. Nevertheless, a reasonable assumption is that about half of raw natural gas production contains CO2 at concentrations averaging at least 4% by volume. These figures can be used to illustrate the scale of this CO2 capture and storage opportunity. If half of the worldwide production of 2618.5 billion m3 of natural gas in 2003 is reduced in CO2 content from 4 to 2% mol, the resultant amount of CO2 removed would be at least 50 Mt CO2 yr-1. It is interesting to note that there are two operating natural gas plants capturing and storing CO2, BP’s In Salah plant in Algeria and a Statoil plant at Sleipner in the North Sea. Both capture about 1 MtCO2 yr-1 (see Chapter 5). About 6.5 million tCO2 yr-1 from natural gas sweetening is also currently being used in enhanced oil recovery (EOR) in the United States (Beecy and Kuuskraa, 2005) where in these commercial EOR projects, a large fraction of the injected CO2 is also retained underground (see Chapter 5). natural gas started in the early 1980s for small units, with many design parameters unknown (Noble and Stern, 1995). It is now a well-established and competitive technology with advantages compared to other technologies, including amine treatment in certain cases (Tabe-Mohammadi, 1999). These advantages include lower capital cost, ease of skid-mounted installation, lower energy consumption, ability to be applied in remote areas, especially offshore and flexibility. 3.2.3 Steel production Depending on the level of CO2 in natural gas, different processes for natural gas sweetening (i.e., H2S and CO2 removal) are available (Kohl and Nielsen, 1997 and Maddox and Morgan, 1998): The iron and steel industry is the largest energy-consuming manufacturing sector in the world, accounting for 10-15% of total industrial energy consumption (IEA GHG, 2000a). Associated CO2 emissions were estimated at 1442 MtCO2 in 1995. Two types of iron- and steel-making technologies are in operation today. The integrated steel plant has a typical capacity of 3-5 Mtonnes yr-1 of steel and uses coal as its basic fuel with, in many cases, additional natural gas and oil. The mini-mill uses electric arc furnaces to melt scrap with a typical output of 1 Mtonnes yr-1 of steel and an electrical consumption of 300-350 kWh tonne-1 steel. Increasingly mini-mills blend direct-reduced iron (DRI) with scrap to increase steel quality. The production of direct-reduced iron involves reaction of high oxygen content iron ore with H2 and CO to form reduced iron plus H2O and CO2. As a result, many of the direct reduction iron processes could capture a pure CO2 stream. • Chemical solvents • Physical solvents • Membranes An important and growing trend is the use of new iron- making processes, which can use lower grade coal than the coking coals required for blast furnace operation. A good example is the COREX process (von Bogdandy et. al, 1989), which produces a large additional quantity of N2-free fuel gas which can be used in a secondary operation to convert iron ore to iron. Complete CO2 capture from this process should be possible with this arrangement since the CO2 and H2O present in the COREX top gas must be removed to allow the CO plus H2 to be heated and used to reduce iron oxide to iron in the secondary shaft kiln. This process will produce a combination of molten iron and iron with high recovery of CO2 derived from the coal feed to the COREX process. Natural gas sweetening using various alkanolamines (MEA, DEA, MDEA, etc.; See Table 3.2), or a mixture of them, is the most commonly used method. The process flow diagram for CO2 recovery from natural gas is similar to what is presented for flue gas treatment (see Figure 3.4, Section 3.3.2.1), except that in natural gas processing, absorption occurs at high pressure, with subsequent expansion before the stripper column, where CO2 will be flashed and separated. When the CO2 concentration in natural gas is high, membrane systems may be more economical. Industrial application of membranes for recovery of CO2 from table 3.2 Common solvents used for the removal of CO2 from natural gas or shifted syngas in pre-combustion capture processes. Solvent name type Chemical name vendors Rectisol Physical Methanol Lurgi and Linde, Germany Lotepro Corporation, USA Purisol Physical N-methyl-2-pyrolidone (NMP) Lurgi, Germany Selexol Physical Dimethyl ethers of polyethylene glycol (DMPEG) Union Carbide, USA Benfield Chemical Potassium carbonate UOP MEA Chemical Monoethanolamine Various MDEA Chemical Methyldiethylamine BASF and others Sulfinol Chemical Tetrahydrothiophene 1,1-dioxide (Sulfolane), an alkaloamine and water ShellPDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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