Бурение грунтовых зондов, установка энергетических колодцев

Permeable gas separation membranes in syngas service utilize differences in solu­bility and diffusion of different gases in polymer membranes. The rate of transport of a component through the membrane is approximately proportional to the differ­ence in partial pressure of the component on the two sides of the membrane. Polymer membranes have found increasing use in a number of applications, including natural gas processing (C02 removal) and in the synthesis gas environment for hydrogen separation out of the main syngas stream.

The design of a polymer membrane system exploits the different permeability rates of the components in the feed gas. An idea of the relative rates through a typical hydrogen separation polymer can be gained from Table 8-4. Thus a good separation can be achieved between, for example, hydrogen and CO or N2. Separation from C02 will be only moderately satisfactory, however.

Membrane units are usually supplied packed, typically as a bundle of hollow tube fibers. The feed is supplied to the shell side of the bundle and the permeate (hydrogen rich stream), which passes through the fiber-tube walls, is collected on the tube side. Design variables are the pressure difference selected and the total surface area of the polymer.

For the system designer, the integration of a membrane unit has two important characteristics. First, permeable membranes provide the only system leaving the carbon monoxide at essentially the same pressure level as at the gas inlet (less hydraulic losses only) and the hydrogen on the low-pressure side. This is exactly the reverse of the pressure swing adsorber.

Second, as mentioned above, it must be recognized that since all permeable membranes work on the basis of different rates of diffusion, they can only have a limited selectivity. This can be disadvantageous, since in a hydrogen extraction application, the product hydrogen is not very pure, and the diffusion of CO through the membrane can be considered as a loss of high pressure gas.

Nonetheless, skilled integration of membrane and PSA technologies can together provide some extremely attractive solutions. Consider the following situation where 20,000 Nm3/h pure hydrogen is required from a main stream of syngas in an IGCC (Figure 8-11 and Table 8-5). The membrane is used to produce a raw hydrogen at reduced pressure (but still adequate for PSA feed) with only a small loss of other syngas components for the gas turbine. The raw hydrogen has a purity of about 70- 90mol%, depending on syngas composition and pressure, which allows the PSA to have a significantly higher efficiency than would be the case with syngas feed. Fur­thermore, the much smaller quantity of tail gas to be adsorbed allows the PSA unit to be smaller too.

Care should be exercised with liquid carry over from an upstream AGR system. In some cases these can damage the membrane. Proper separation at the AGR outlet should however be sufficient to prevent problems (Collodi 2001).

Hot Gas Cleanup

For power applications the energy loss involved in cooling synthesis gas down to ambient or lower temperatures as required by current acid gas removal systems is reason enough for the interest in so-called “hot gas cleanup.” Actually, hot gas cleanup is a misnomer, and these technological developments should rightly be called “warm gas cleanup,” since the target operating temperature range is between 250 and 500°C.

Impurities that need to be considered in a warm gas cleanup system include particulates (fly ash and char) as well as gaseous compounds such as H2S, COS, NH3, HCN, HC1, and alkali species. At temperatures above about 500°C, alkaline species will pass through a particulate filter, and this together with materials issues is the principle reason why no attempts at hotter cleanup have been made.

Technologies for warm gas cleanup using zinc-based sorbents have been built at demonstration scale in Polk County and Pinon Pine without great success (Simbeck, 2002; U. S. Department of Energy 2002). In fact, neither of these units was ever oper­ated. Both of these were designed essentially as desulfurization units with removal efficiencies of up to 98%, which at the time of design conformed to existing power station emission regulations. They did not address some of the other species, such as nitrogen compounds and halides, nor for that matter mercury. Furthermore, the sulfur removal efficiencies made them unsuitable for most chemical applications.

Nonetheless, the potential in terms of efficiency improvement remains and continues to provide an incentive for research and development to find appropriate systems.

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