Elsevier

Journal of Membrane Science

Volume 389, 1 February 2012, Pages 441-450
Journal of Membrane Science

Carbon dioxide capture with membranes at an IGCC power plant

https://doi.org/10.1016/j.memsci.2011.11.012Get rights and content

Abstract

Integrated Gasification Combined Cycle (IGCC) power plants are being developed as an economical method of producing electricity from coal while simultaneously capturing carbon dioxide (CO2) for sequestration. In these plants, conventional cold absorption processes are considered the baseline technology to separate CO2 from gasified coal syngas. Separation and sequestration of the CO2 by these methods increases the levelized cost of the electricity (LCOE) produced by about 30%. This paper describes the use of hydrogen-selective and CO2-selective membranes used in various process designs to perform the same separation. The best design, using recently developed membranes, has 40% of the capital cost and uses 50% of the energy of cold absorption. The resulting increase in the LCOE to separate and sequester the CO2 is then about 15%. If higher permeance, and especially more selective, membranes can be developed, the cost of the technology described will be reduced even further.

Highlights

► Evaluates hydrogen-selective and CO2-selective membranes for IGCC CO2 capture. ► The best membrane design has lower cost and uses 50% of the energy of cold absorption. ► Higher permeance, and especially more selective, membranes will help.

Introduction

The ways in which the world makes electricity, liquid transportation fuels and chemicals are going to change dramatically in the next few decades. Future restrictions on CO2 emissions will alter the way fossil fuels are processed to produce power and chemicals. One of the most important changes will be the increasing use of coal (and biomass) as feedstock for the production of syngas that can be converted to power and chemical products, while simultaneously capturing CO2 in an economical manner. This will be especially true in countries with abundant coal reserves such as China and the United States.

The gasification processes used to make syngas were developed early last century, mostly in Germany and later in South Africa. These processes received renewed attention after the first oil shock in the early 1970s [1]. Over the intervening 30 years, more than 140 syngas plants have been built, many using petroleum coke to make chemicals [2]. The technology has not been widely used to make electricity because of process economics. The gasifier feedstocks – coal, biomass and petroleum coke – are all significantly lower cost than oil or natural gas, but gasification and downstream processing of syngas to make electricity is expensive. However, gasification is much more economically attractive if the objective of the process is to produce power while simultaneously capturing and sequestering the CO2 produced as a by-product.

Consider the production of electric power by an Integrated Gasification Combined Cycle (IGCC) process when compared to the production of electric power by burning pulverized coal. Block flow diagrams of both processes are shown in Fig. 1.

A world-scale pulverized coal (PC) power plant, although a massive operation, has a relatively straightforward flow scheme. Coal is burned with air in a boiler to make high-pressure steam, which is then sent to a steam turbine to make power. The flue gas from the boiler, at low pressure (slightly above atmospheric pressure), is sent through an electrostatic precipitator (ESP) or baghouse to remove particulates, scrubbed to remove sulfur dioxide (SO2) in a flue gas desulfurization (FGD) unit, and then emitted directly to the atmosphere. Removal of CO2 from the flue gas, although being considered [3], is not currently used at any of the 5000 coal power plants in operation around the world.

The IGCC process flow scheme is significantly more complex. Typically, an air separation plant is first used to produce oxygen, which together with water is then used to gasify coal at high pressure and temperature. The syngas produced (carbon monoxide and hydrogen) is contaminated with CO2, nitrogen, methane, argon, hydrogen sulfide, particulates and tars. The gas is quenched and scrubbed to eliminate tar and particulates. If CO2 capture or hydrogen (H2) production is desired, high and low-temperature shift reactors are used to convert carbon monoxide and water to hydrogen and CO2. Sulfur compounds, and optionally CO2, are then removed by a low-temperature absorption process. The high-pressure syngas is then burned with air and the hot high-pressure gas product is used to drive a gas turbine and make electricity. The hot turbine exhaust is used to produce steam that makes additional electricity in a steam turbine. The cooled gas is vented to the atmosphere. An IGCC plant has an overall heat to electric power efficiency of about 45%, significantly better than the 35% efficiency of a conventional subcritical PC power plant. However, this advantage is more than offset by the higher capital cost of an IGCC plant. The result is that without CO2 capture, the electric power produced at an IGCC plant is expected to be 25% more expensive than electricity produced in subcritical PC power plants [4].

The real benefit of IGCC technology kicks in if a cost is placed on CO2 emissions. This is because CO2 removal from high-pressure, high-concentration gasification streams will be significantly less costly than CO2 removal from conventional PC power plant flue gas [4], [5]. The reason for the lower cost of CO2 removal from an IGCC plant is apparent from Fig. 1. In a conventional PC power plant, CO2 has to be separated from a very large (typically 500 N m3/s), dilute (13% CO2), low-pressure (∼1 psig) gas stream. Currently, CO2 capture with amine absorption seems to be the leading candidate technology. Reports predict that an amine system used to capture 90% of the CO2 in flue gas will result in CO2 capture costs of $40–100/ton CO2 and an 80% increase in the LCOE [6]. New technologies including membrane-based approaches are being developed, and may reduce these costs [3], [7].

If CO2 capture is to be used at an IGCC plant, the raw syngas will be reacted with steam in a shift reactor to produce more hydrogen by the reaction:CO+H2OCO2+H2

The gas leaving the shift reactor is usually at a pressure of ∼50 bar and contains about 56% hydrogen, 40% CO2 and 4% other gases (carbon monoxide, methane, nitrogen, argon, and hydrogen sulfide). Separation of CO2 from this gas stream is far easier and less costly than separation from flue gas. Currently, absorption of the CO2 in chilled methanol or ethylene glycol would be used (the Rectisol® or Selexol™ processes, respectively) for CO2 capture.

The U.S. Department of Energy (DOE) has recently completed a cost analysis of electricity produced by an IGCC plant using a Selexol unit to separate the CO2 for sequestration [8]. This study indicates that capturing and sequestering 90% of the CO2 from a new IGCC plant using Selexol will result in about a 30% increase in LCOE. This value is far higher than the DOE target of <10% increase in LCOE at 90% CO2 capture. In this work, we will compare results of the DOE study with the use of selective membranes for the same separation.

Section snippets

Membrane background

This paper describes the use of membranes to separate hydrogen–CO2 gas mixtures produced in an IGCC power plant. A wide variety of membranes have been considered for this separation. For example, inorganic hydrogen-permeable membranes – including those based on palladium and palladium alloys, ceramics, carbons, and zeolites – have been the subject of research for many years. Palladium alloy membranes are almost infinitely selective for hydrogen over all other gases and can be used at very high

Process design background

This paper describes various membrane process designs for capturing CO2 from IGCC syngas. The properties of the CO2-selective and hydrogen-selective membranes used in these designs are shown in Table 1. The performance numbers given are achievable with today's MTR membranes, and can be considered a baseline. Ultimately, even better membranes may be made. The impact of potential second-generation membranes on process economics is discussed later in the paper.

Two types of membranes are used in

Single-stage membrane process designs

As discussed earlier, a number of authors have investigated membrane processes to separate IGCC CO2/H2 mixtures. Most of these studies used membranes to perform the total separation. Membranes with hard-to-achieve selectivities and permeances are then required to bring the processes into the economically feasible range. In this paper, we will show that an integrated process combining membranes with cryogenic condensation and fractionation produces a better result than can be achieved with

Membrane designs with sweep

A variation of the hydrogen-selective membrane design is shown in Fig. 5. This design makes use of nitrogen available from the on-site air separation plant as a sweep gas to reduce the energy cost of recompressing permeated hydrogen going to the combustion turbine. In the conventional IGCC process flow scheme shown in Fig. 1, pressurized nitrogen from the air separation plant (at 30 bar) is mixed with hydrogen before the hydrogen is burned in the gas turbine combustor. The hydrogen going to the

Targets for membrane development

The final section of this paper describes how development of membranes with enhanced properties could improve the economics of membrane-based CO2 capture.

The design shown in Fig. 6 is based on membranes with the permeation properties shown in Table 1. These values reflect the properties of current developmental membranes already being produced as modules and tested in the field. The bulk of the membrane area in the Fig. 6 process is in the hydrogen-permeating sweep modules, and improvements in

Conclusions

The economic feasibility of using IGCC technology as a way of producing electricity while simultaneously capturing CO2 is connected to the cost of separating the CO2 from high-pressure CO2-hydrogen streams. Currently, Selexol or Rectisol absorption technology is the preferred CO2 capture approach. These processes will increase the LCOE by 30% at 90% CO2 capture. This paper shows that hybrid membrane-condensation processes using today's polymer membranes can be a competitive IGCC CO2 capture

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