Selective Exhaust Gas Recycle with Membranes for CO2 Capture from

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Selective Exhaust Gas Recycle with Membranes for CO2 Capture from Natural Gas Combined Cycle Power Plants Timothy C. Merkel,* Xiaotong Wei, Zhenjie He, Lloyd S. White, J. G. Wijmans, and Richard W. Baker Membrane Technology & Research, Inc., 39630 Eureka Dr., Newark, California 94560, United States ABSTRACT: Low natural gas prices are contributing to rapid growth in natural gas combined cycle (NGCC) power production in the United States. CO2 capture from the exhaust gas of these plants is complicated by the relatively low CO2 concentration in this flue gas (3%−4%). A membrane process using incoming combustion air as a sweep stream in a selective exhaust gas recycle configuration can be used to preconcentrate CO2 from 4% to 15%−20% with almost no energy input. Depending on the process configuration, the selective recycle membrane design reduces the minimum energy of a CO2 capture step by up to 40%. An allmembrane design using a capture step in series with a selective recycle membrane can capture 90% of CO2 from an NGCC power plant using less energy and at a lower cost than the base-case amine process analyzed by the U.S. Department of Energy. The current state-of-the-art membranes for use in this process have a CO2 permeance of 2200 gpu and a CO2/N2 selectivity of 50. Higher CO2 permeance will improve the economics and reduce the footprint of a membrane CO2 capture system, while higher CO2/N2 selectivity is of less benefit, because the process is limited by the affordable pressure ratio.

1. INTRODUCTION Anthropogenic emissions of carbon dioxide (CO2) from combustion of fossil fuels have caused a significant increase in atmospheric CO2 concentrations over the last century. There is growing concern that continuation of this trend will change the global climate.1 At the same time, world energy demands are rising because of economic expansion and modernization in developing countries. Today, ∼80% of worldwide energy demand is met through combustion of fossil fuels that produce CO2 emissions. A variety of studies indicate that even with aggressive growth in renewable and other decarbonized energy sources, fossil fuel combustion will remain the primary world energy source through at least 2050.2,3 In response to concerns about CO2 emissions, a global research effort has been directed toward reducing the carbon intensity of fossil fuel energy production. This work includes energy conservation and efficiency improvements, fuel switching, and carbon capture and sequestration (CCS). In the CCS approach, CO2 is captured from power plants or other large emission sources, and sequestered underground in geological structures for long periods of time. Three primary CO2 capture strategies are being investigated: post-combustion capture of CO2 from flue gases, pre-combustion CO2 capture from synthesis gas to produce a carbon-free fuel (hydrogen), and oxy-combustion, which burns fuel in oxygen to produce an almost-sequestration-ready CO2 effluent.4 The latter two approaches are promising for new power facilities, but involve significant changes to the power generation process and are unlikely to be retrofitted to existing facilities. Consequently, there is a desire to identify post-combustion CO2 capture technologies that can be added to existing power generation processes without drastically increasing the cost of electricity. Currently, the leading technology proposed for postcombustion CO2 capture is amine absorption.5 This technology has been used for decades to separate CO2 from industrial gas streams, and is relatively mature. However, according to a U.S. Department of Energy (DOE) economic analysis, using a © 2012 American Chemical Society

conventional amine process for post-combustion CO2 capture would be a costly proposition. For example, the DOE estimates using such an amine system to capture 90% of the CO2 in coalfired power plant flue gas would result in more than an 80% increase in the cost of electricity.6 In an effort to reduce the cost of post-combustion CO2 capture, there is ongoing research examining different separation technologies including advanced solvents, sorbents, and membranes.4 Recently, we described a novel membrane process to capture CO2 from coal power plant flue gas.7−10 This process uses combustion air as a sweep stream in a countercurrent membrane unit to strip CO2 from flue gas and recycle it back to the boiler. By selectively recycling CO2, the concentration of CO2 in the boiler flue gas is increased, making its subsequent capture easier. New CO2 capture membranes (called Polaris) were developed for this process and are currently being tested with coal-fired flue gas slipstreams containing up to 20 tons of CO2/day (the CO2 produced by 1 MWe of coal power generation). Numerous other researchers are also studying new membrane materials and processes for post-combustion CO2 capture.11−20 To date, much of this membrane work has focused on coal-fired flue gas, because these facilities represent the bulk of power industry CO2 emissions, and coal flue gas has a relatively high CO2 concentration of 10%−14%. More-dilute CO2 streams, such as gas turbine flue gas (3%−4% CO2), have received less attention, in part because the lower CO2 partial pressure seemingly makes capture with membranes more difficult. In the past decade, the emergence of technologies that can affordably extract trapped fossil fuel resources such as shale gas Special Issue: Baker Festschrift Received: Revised: Accepted: Published: 1150

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has transformed the energy landscape in the United States. Recent estimates suggest recoverable U.S. natural gas reserves have doubled in the past five years, and as a result, U.S. natural gas prices have dropped from a high of $15/MMBtu in 2006 to less than $3/MMBtu in early 2012. The current low cost of natural gas, combined with abundant supply projections for this fuel, make power generation by natural gas combustion turbines look increasingly attractive. Natural gas combined cycle (NGCC) power plants also offer advantages compared to coal-fired plants, including lower capital cost, higher efficiency, minimal particulate or sulfur emissions, and lower CO2 emissions per MWe of power produced.6 These advantages have led to NGCC plants garnering an increasing share of the U.S. power generation market. For example, the percentage of U.S. electricity produced from natural gas grew from 14% in 1997 to 23% in 2010.6 More recently, the Energy Information Administration (EIA) reported that in April 2012, U.S. natural gas-fired electricity generation was equal to that of coal-fired generation (∼32% each) for the first time since EIA began collecting data. With abundant supply driving low natural gas prices, this trend toward natural gas power generation seems likely to accelerate in the future, particularly if a price is placed on CO2 emissions. While NGCC power plants have a relatively low carbon intensity, in absolute terms, they are still large CO2 emitters and will eventually require capture technologies to meet future regulations and stabilize atmospheric CO2 levels. NGCC flue gas has a comparatively low CO2 concentration, because a large amount of excess air is used in gas combustion turbines. Many studies have shown that low CO2 content in NGCC flue gas increases the capture cost significantly for conventional separation technologies, compared to capture from a coalfired flue gas, where the CO2 content is higher.21 To address the low CO2 content in NGCC flue gas, researchers have proposed using a process called exhaust gas recycle (EGR).22−25 In this process, a portion of the flue gas is recycled to the inlet of the air compressor and replaces some of the air going to the combustor. Because natural gas turbines operate with a large excess of air (∼250%), EGR can increase the flue gas CO2 content without adversely impacting the combustion turbine performance. In this paper, we describe a membrane process that allows CO2 to be selectively recycled in an NGCC power system. By using combustion air as a sweep stream, CO2 can be stripped from flue gas, selectively recycled, and preconcentrated with little energy input. Subsequent capture of the CO2 from a concentrated stream requires less energy than capture from the original dilute flue gas and can be accomplished with membranes or another separation technology. In the following sections, key process parameters and the desired properties of the CO2 capture membrane are discussed.

Figure 1. Simplified flow diagram of an NGCC power plant with CO2 capture. Legend: GT, the gas turbine; ST, the steam turbine; and HRSG, the heat recovery steam generator.

recovery steam generator (HRSG). The steam generated in the HRSG is used to drive a steam turbine to produce additional energy. The combination of the combustion turbine (Brayton cycle) and steam turbine (Rankine cycle) yields a combined cycle power plant with efficiencies as high as 50%−55% (compared to 35%−40% in a typical subcritical pulverized coal power plant). If post-combustion CO2 capture is to be used at an NGCC plant, the most common design is to have a CO2 capture unit treat the cooled exhaust gas leaving the HRSG. The typical combustion turbine operates with a large excess of airoften between 200% and 250% of the stoichiometric oxygen requirement. The large excess of air is used to maintain the exhaust gas temperature at values that the turbine blades can withstand (50. Compared to the DOE base-case amine capture process, the membrane process uses less energy as long as the membrane CO2/N2 selectivity is higher than ∼35. At a membrane CO2/N2 selectivity of 50, the membrane process uses ∼6% less energy than the amine process. Both the membrane and amine capture processes use considerably more energy than the theoretical minimum energy of separation and compression. For example, regardless of the membrane selectivity, the membrane process uses more than three times the minimum energy to capture and liquefy 90% of the flue gas CO2. Figure 11 shows the effect of membrane CO2 permeance and CO2/N2 selectivity on the COE for the capture process described in Figure 9. For comparison, horizontal lines denoting the COE for the no-capture case and 90% CO2 capture with the base-case amine process are also shown in the figure. The COE when using the membrane capture process decreases rapidly as the membrane CO2/N2 selectivity increases 1157

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4. CONCLUSIONS A membrane process using incoming combustion air as a sweep stream in a selective exhaust gas recycle configuration can be used to preconcentrate CO2 in NGCC flue gas from 4% to 15%−20% with little energy input. This enrichment in flue gas CO2 content is greater for gas combustion than it is for a coal flue gas, because gas combustion turbines use a larger amount of excess air than coal boilers, and, therefore, more CO2 can be recycled in a gas turbine cycle without approaching stoichiometric oxygen limits. An energy analysis shows that this selective recycle membrane design applied to an NGCC system can reduce the minimum energy of a CO2 capture step by up to 40%. The selective recycle membrane may be used in series, in parallel, or in a combination of these configurations with any capture technology (absorption, cryogenics, membranes, etc.) that benefits from a higher CO2 driving force for separation. For some separation technologies, this preconcentration of CO2 may be an enabling step that allows them to be considered for post-combustion capture at an NGCC plant. A process using a membrane capture step in series with a selective recycle membrane can remove 90% of CO2 from an NGCC flue gas, using less energy and at a lower cost than that of a base-case amine process analyzed by the U.S. Department of Energy (DOE). For example, at 90% CO2 capture, the cost of electricity (COE) for the membrane process is 7.9 cents/ kWh, compared to a COE of 8.8 cents/kWh when amine absorption is used. A state-of-the-art Polaris membrane for use in this process has a CO2 permeance of 2200 gpu and a CO2/ N2 selectivity of 50. Higher CO2 permeance will improve the economics and reduce the footprint of a membrane CO2 capture system, while higher CO2/N2 selectivity is of little benefit, because the process is limited by the affordable pressure ratio.

Figure 11. Effect of membrane CO 2/N 2 selectivity and CO2 permeance on the cost of electricity for 90% CO2 capture from an NGCC power plant.

up to 30. For selectivities higher than 30, there is little further improvement in the economics of the membrane capture process. This is due to the fact that the membrane process is pressure-ratio-limited, and higher selectivity does not produce a significantly purer CO2 permeate. Compared to the DOE basecase amine process, the membrane process shows lower COE for all of the membrane permeances examined, as long as the membrane CO2/N2 selectivity is greater than ∼20. Increasing the membrane CO2 permeance will reduce the required membrane area and, therefore, the cost of the membrane system. However, Figure 11 shows that further increases in permeance beyond that of today’s Polaris membrane have a relatively modest impact on COE. For example, at a fixed membrane CO2/N2 selectivity of 50, the COE decreases from 7.9 cents/kWh to 7.7 cents/kWh as CO2 permeance is increased from that of today’s membrane (2200 gpu) to that of an advanced membrane (5000 gpu). Even if the membrane permeance is increased to 10 000 gpu, there is little further decrease in the COE. Similarly, fixing the membrane permeance and reducing the membrane unit cost also has a small impact on COE (because changing membrane permeance almost linearly varies the required membrane area and cost). This insensitivity of COE to membrane permeance (or cost) occurs because, at $50/m2 and >2000 gpu, the membrane capital cost contributes a relatively small amount to the COE. Most of the increase in COE above the no-capture case is caused by the energy used for capture and the compression equipment capital cost. Perhaps the most beneficial effect of higher membrane CO2 permeance for this process design is to reduce the footprint of the membrane system, which can be an important issue in space-limited facilities. The calculations in Figures 10 and 11 demonstrate that a membrane process using selective exhaust gas recycle can be competitive with amine absorption for CO2 capture from an NGCC power plant, from the standpoints of both energy use and cost. With today’s high-performance membranes, much of the remaining cost of the membrane process (using a 3 bar feed) is in energy use and compression equipment. This finding suggests that a way to improve the economics of a membrane process would be to run at an even lower feed pressure. Such an approach will reduce the driving force in the CO2 capture step and favor the use of very-high-permeance membranes.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare the following competing financial interest(s): The authors are grateful to the U.S. Department of Energy for funding parts of this work through DOE Project Nos. DE-FE0007553 and DE-FE0005795.

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REFERENCES

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