Implications of CO2 Sequestration for Gas Turbines

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1.2.2
Implications of CO2
Sequestration for Gas
Turbines
Ashok Rao, Ph.D., P.E.
Chief Scientist, Power Systems
Advanced Power and Energy Program
University of California
Irvine, CA 92697-3550
phone: (949) 824-7302 ext 345
email: adr@apep.uci.edu
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1.2.2-1 Introduction
A variety of industrial processes such as power plants, oil refi neries,
cement works, and iron and steel production emit large amounts of CO2. Ap-
proximately a third of all the CO2 emissions due to human activity, however,
come from fossil fuel-based power plants, with each power plant capable of
emitting several million tonnes of CO2 annually. These emissions could be
reduced substantially by capturing and storing the CO2 while other sources of
emissions, such as transport and domestic buildings, cannot be tackled in the
same way because of the large number of small sources of CO2.
The capture of CO2 in an IGCC power plant consists of gasifying the
feedstock in an O2 blown gasifi er system and shifting the CO to H2 by catalytic
reaction with steam1:
CO + H2O = CO2 + H2. (1)
The CO2 is then removed for sequestration from the syngas to pro-
duce a “decarbonized” fuel gas for combustion in a gas turbine. There are
primarily two schemes for these processing steps consisting of shifting, CO2
removal and desulfurization of the syngas for current or near term technology
plants, i.e., plants incorporating cold gas cleanup:
• Employ sour shifting of the syngas followed by desulfurization and CO2
recovery within the same acid gas removal unit; or,
• Desulfurize the syngas fi rst followed by shifting and then removal /recovery
of the CO2.
The choice of either scheme depends primarily on the gasifi cation heat
recovery system employed (i.e., the extent to which cooling of the raw gasifi er
effl uent is accomplished in a syngas cooler before the syngas is quenched /
scrubbed with water to remove particulate matter).
1.2.2-2 Implications for Gas Turbines
Syngas Composition and Thermal Diluents
Table 1 shows the composition of a decarbonized syngas (shifted and
then 90% of the CO2 removed) as well as an “un-decarbonized” syngas leav-
ing the acid gas removal unit of a high-temperature slurry-fed entrained-bed
gasifi er fed with a bituminous coal2. The H2 content of both the syngas streams
is considered high enough to preclude the use of current design pre-mixed gas
turbine combustors to limit the formation of NOx. Diluent addition is required
to the syngas in order to reduce the NOx generation when utilizing “diffusion”
type combustors, the amount of diluent addition required by decarbonized syn-
gas, however, being higher than that required for the un-decarbonized syngas.
Two types of diluents are available in an IGCC plant, water vapor introduced
into the syngas stream by direct contact of the syngas with hot water in a coun-
ter-current column while recovering low temperature waste heat and / or N2
supplied by an elevated pressure air separation unit. The choice of the diluent
depends on a number of factors such as
• amount of low temperature waste heat available for the humidifi cation
operation, and
• amount of excess N2 available from the air separation unit.