Бурение грунтовых зондов, установка энергетических колодцев

The principal gaseous effluents arising from the use of fossil fuels are oxides of sulfur and nitrogen and particulate matter. Others that require attention are not fully combusted components, such as carbon monoxide.

Currently in gasification systems the first three components are all removed in the intermediate fuel gas, where sulfur and nitrogen are present as reduced species and in higher concentrations than would be the case in flue gas. Both features make removal of these species to low levels easier. In a comparison with ultra — supercritical PC technology using SCR and wet FGD, O’Keefe and Sturm 2002 shows that an IGCC power plant can achieve significantly lower emissions than the PC unit (Figure 9-4). In fact, his figures do not disclose the potential in the IGCC for further reductions should it be required, as is discussed under the specific pollutants below.

The U. S. air pollution regulations are at the time of this writing in a state of flux while the Clear Skies Initiative is being debated. Under the proposals made in the draft legislation, a coal-gasification-based IGCC would clearly fall under the same

regulations as for any other coal-based technology, a situation that, at least as far as NOx is concerned, is currently the subject of different legal interpretations. The national limits proposed are contained in Table 9-3.

German legislative limits for large liquid-feed power plants, which are largely drawn from European legislation, are shown in Table 9-4 with the comparison of values achievable from a residual-oil-based IGCC.

Sulphur emissions. Sulfur compounds have historically received the most attention when it comes to environmental impact because they are the major cause of acid rain. The fact that it is so much easier to remove sulfur as H2S from high-pressure fuel gas than as S02 from the flue gas has been an important factor motivating the development of gasification-based power stations and the IGCC concept.

When serious interest in IGCC developed around 1980, it was already possible to remove 99% of the sulphur in an IGCC based power plant. In fact, the technology for sulphur removal at orders of magnitude lower than this had already been operat­ing reliably in commercial situations for many years, whether downstream of coal gasifiers (e. g. Sasol) or of oil gasifiers (in e. g. ammonia plants). In comparison,

state-of-the-art sulphur removal in a conventional power station was at this time only about 85-90%.

This situation has changed somewhat. Now sulphur removal can also be achieved in conventional power stations with two-stage flue gas scrubbing 98-99%. Dry processes can result in over 99.5% sulphur removal. Nonetheless it remains true that desulfurization of fuel gas can be achieved to any level desirable with proven technology.

For chemical applications such as methanol production, the sulphur levels in the syngas can be reduced to below 100 ppbv, which translates into some 10-12 ppbv in the flue gas or less than 0.001 lb S02/MWh. This is two orders of magnitude less than current expectations, as shown in Figure 9-4. Given today’s regulations, this is more costly than necessary for power production, however it is an indication that gasification-based technology is ready to meet the tougher standards of the future.

Nitrogen. An important feature of coal as a fuel is its high organic nitrogen con­tent of 1-2 wt%. Upon combustion a significant part of this nitrogen is oxidized to NOx, which must be removed from the flue gas in an SCR unit where it is catalyti- cally reduced with NH3 to elemental nitrogen.

In gasification, virtually no NOx is formed, but the organic fuel nitrogen is partially converted into HCN and NH3. These components are removed in a water wash or— in the case of HCN—by catalytic conversion to NH3 together with the COS. The gas combusted in the gas turbine is therefore essentially free of any nitrogen compounds except molecular nitrogen. NOx from the gas turbine is therefore limited to thermal NOx. Current burner designs are capable of values as low as 15 ppmv NOx when firing syngas (Jones and Shilling 2002). Individual units are reported as having single-figure NOx emissions (Hannemann etal. 2002). Should lower values be required, then it would be necessary to add an SCR, but at present such a demand would appear illogical, since the IGCC without the SCR can already achieve better results than any other coal-fired technology. Only firing with natural gas can achieve better values (9 ppmv). Flue gas recycle and or wet compression offer potential to reduce the thermal NOx even further.

Mercury. Mercury is an element that is present in coals in very differing amounts and is difficult to remove. The risk to engineering materials and downstream plant equipment is described in Section 6.9.9.

Mercury emissions to the atmosphere, particularly from conventional coal-fired power plants, are causing increasing concern, and it will in the near future be subject to emissions regulations in the United States.

One of the difficulties with mercury capture from flue gas streams is the uncertainty about the distribution of the various species. In addition to elemental mercury vapor, it can exist in flue gas as an oxide, chloride, sulfide, or sulfate, the proportions depending on the levels of other contaminants in the coal. Thus not every mercury capture technology is suitable for every fuel.

The IGCC concept has a natural advantage over conventional combustion tech­nologies in the removal of mercury. Removal to over 90% from synthesis gas has been demonstrated at Eastman Chemical Company’s coal-to-chemicals facility in Kingsport, Tennessee, since 1983 using technology developed and used as standard for natural gas applications (Trapp 2001). In fact, only difficulties with measure­ment in the ppb range have prevented a determination whether even higher removal efficiencies are achieved or not. Certainly no product contamination has ever been detected. Against this is the continued recognition that “no single technology has been proven that can uniformly control mercury from power plant flue gas emissions in a cost-effective manner” (U. S. Department of Energy 2003). In a recent investiga­tion into the costs of mercury removal from flue gas, EPRI estimated the costs of 90% sulfur removal at U. S.$2.80 to $3.30 per MWh (Chang 2001). Rutkowski, Klett, and Maxwell (2002) have compared this with the application of sulfur- impregnated activated carbon beds, as in the Eastman plant to a 250 MWe IGCC configuration. The resulting cost obtained was U. S.$0,254 per MWh.

An additional aspect to consider is the clear destination of the mercury on removal from syngas with activated carbon whereas research is still in progress to determine the fate of mercury removed from flue gas by various techniques. In conventional coal-fired power stations equipped with flue gas scrubbing, there is concern that mercury may end up in the gypsum wallboard, Portland cement, or manufactured aggregates that are produced. This issue is being addressed in leach — ability studies on a broad range of solid by-products and wastes (Schwalb, Withum, and Statnick 2002). Final clarity on this issue is unlikely, however, until commercial introduction of mercury capture.

Arsenic. Arsenic is currently not regulated as an emission, although there is increas­ing concern about it. Arsenic is only present in coals and mainly in those coals that have a high pyrite content. Under reducing conditions, compounds of these elements are volatile and are entrained in the gas of slagging gasifiers. When fuel gas treating is applied, compounds of these elements will eventually gather in the water treatment plant and end up in the settler/filter cake of the flocculation section that has to be considered as chemical waste. Alternatively, where raw gas shift is applied, it will deposit on the catalyst. In the case of flue gas treating, the nonvolatile As203 will deposit in any filter or end up in the gypsum.

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