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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

## Abstract

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.

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## Figures

Figure 1

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

Figure 2

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

Figure 3

Detailed scheme of the CP plant configuration

Figure 4

Detailed scheme of the MO plant configuration

Figure 5

Detailed scheme of the MC plant configuration

Figure 6

HSMR shell-and-tube arrangement

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.

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

Figure 9

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

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).

Figure 11

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

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