TECHNICAL PAPERS: Gas Turbines: Electric Power

CO2 Sequestration From IGCC Power Plants by Means of Metallic Membranes

[+] Author and Article Information
Paolo Chiesa

Dipartimento di Energetica, Politecnico di Milano, P.zza Leonardo da Vinci, 32, 20133 Milan, Italypaolo.chiesa@polimi.it

Thomas G. Kreutz

Princeton Environmental Institute, Princeton University, 25 Guyot Hall, Princeton, NJ, 08544 USAkreutz@princeton.edu

Giovanni G. Lozza

Dipartimento di Energetica, Politecnico di Milano, P.zza Leonardo da Vinci, 32, 20133 Milan, Italygiovanni.lozza@polimi.it

According to Rogner et al. (1), reserves of coal (known resources that can be recovered with current technology and today's prices) are about 20,700 EJ, whereas resources (which include additional coal in the ground at sufficiently high concentration that it is estimated to be recoverable in the future with some combination of better technology and higher prices) are 199,700 EJ. Global coal consumption was 92 EJ in 1998.

As an alternative to the usual approach where H2S and CO2 are removed from the syngas in different steps, “co-capture” is realized when H2S and CO2 are captured, dried, compressed, transported and stored together in the same reservoir. It has been shown (7) that “co-capture” can provide some economic benefits with respect to the separate removal of CO2 and H2S. The co-capture and co-storage of H2S and CO2 is a process sometimes carried out at natural gas fields to clean the gas before delivery to the pipeline (8).

Alternative processes might be considered as a means to solve these issues; for instance, a modification of the WSA-SNOX system proposed by Haldor-Topsøe (11), producing H2SO4 as the final sulfurated compound. A detailed study of this problem is beyond the scope of this paper.

The ASU is sized to produce the oxygen required for coal gasification and, in MO configuration, to feed the catalytic combustor. Aside from the N2 used to regenerate the filters, the pure nitrogen flow available for use as “sweep gas” is about three times the mass flow of oxygen.

Fueling a gas turbine with diluted hydrogen increases the water concentration in combustion products and leads to a higher heat transfer to the turbine blades compared to natural gas operation. Two options are possible: (i) lowering the firing temperature, (ii) increasing the coolant flow. For conceptual simplicity we preferred the second option that also yields the best achievable performance.

Cycle efficiency is not affected provided that the compressor efficiency does not change as the VGVs close, as is assumed in this paper. This is a simplification, but is sufficiently accurate, to the authors' knowledge, within the limited range of VGV positions considered here (80% to 100% airflow).

The efficiency loss caused by fuel cooling to 300°C (a value compatible with the IGCC standards) can be estimated in 0.3 percentage points when heat is recovered to generate HP steam.

J. Eng. Gas Turbines Power 129(1), 123-134 (Sep 06, 2005) (12 pages) doi:10.1115/1.2181184 History: Received August 30, 2005; Revised September 06, 2005

This paper investigates novel IGCC plants that employ hydrogen separation membranes in order to capture carbon dioxide for long-term storage. The thermodynamic performance of these membrane-based plants are compared with similar IGCCs that capture CO2 using conventional (i.e., solvent absorption) technology. The basic plant configuration employs an entrained-flow, oxygen-blown coal gasifier with quench cooling, followed by an adiabatic water gas shift (WGS) reactor that converts most of CO contained in the syngas into CO2 and H2. The syngas then enters a WGS membrane reactor where the syngas undergoes further shifting; simultaneously, H2 in the syngas permeates through the hydrogen-selective, dense metal membrane into a counter-current nitrogen “sweep” flow. The permeated H2, diluted by N2, constitutes a decarbonized fuel for the combined cycle power plant whose exhaust is CO2 free. Exiting the membrane reactor is a hot, high pressure “raffinate” stream composed primarily of CO2 and steam, but also containing “fuel species” such as H2S, unconverted CO, and unpermeated H2. Two different schemes (oxygen catalytic combustion and cryogenic separation) have been investigated to both exploit the heating value of the fuel species and produce a CO2-rich stream for long term storage. Our calculations indicate that, when 85vol% of the H2+CO in the original syngas is extracted as H2 by the membrane reactor, the membrane-based IGCC systems are more efficient by 1.7 percentage points than the reference IGCC with CO2 capture based on commercially ready technology.

Copyright © 2007 by American Society of Mechanical Engineers
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Figure 1

Conceptual scheme of a low CO2 emission IGCC plant based on commercially ready technology

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Figure 2

Conceptual scheme of a low CO2 emission IGCC plant based on a hydrogen separation membrane reactor (HSMR)

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Figure 3

Detailed scheme of the CP plant configuration

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Figure 4

Detailed scheme of the MO plant configuration

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Figure 5

Detailed scheme of the MC plant configuration

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Figure 6

HSMR shell-and-tube arrangement

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Figure 7

Detail of the membrane reactor assembly. The oxide layer between Pd–Cu film and support is sometimes used in experimental membranes to limit molecular interdiffusion that dramatically reduces performance at high temperatures.

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Figure 8

Average H2 flux and resulting membrane area as a function of the HRF for the HSMR of the MC plant, reported as a ratio with respect to the 85% HRF case

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Figure 9

—Operating condition of the hydrogen separation membrane water gas shift reactor placed in the MC plant (HRF=85%)

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Figure 10

Detailed scheme of the cryogenic process adopted in the MC configuration to separate the incondensable gases from the CO2 stream. For individual stream properties (see Table 4).

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Figure 11

Aggregate temperature-heat duty diagram for the heat exchangers included in the cryogenic process of Fig. 1



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