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Membrane performance requirements for carbon dioxide capture using hydrogen-selective membranes in integrated gasification combined cycle (IGCC) power plants
Journal of Membrane Science 367 (2011) 233–239
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Journal of Membrane Science journal homepage: www.elsevier.com/locate/memsci
Membrane performance requirements for carbon dioxide capture using hydrogen-selective membranes in integrated gasification combined cycle (IGCC) power plants Anthony Y. Ku ∗ , Parag Kulkarni, Roger Shisler, Wei Wei GE Global Research, 1 Research Circle, Niskayuna, NY 12309, United States
a r t i c l e
i n f o
Article history: Received 25 August 2010 Received in revised form 23 October 2010 Accepted 29 October 2010 Available online 9 November 2010 Keywords: CO2 capture H2 membrane Precombustion Syngas Targets
a b s t r a c t Precombustion CO2 capture is an important option for the management of greenhouse gas emissions from power generation, because the higher concentrations can lead to improved separation economics. Membranes can provide a significant boost in the performance by separating CO2 at high temperature and at high pressure, provided they are properly integrated into a power plant. In this study, membrane performance targets were derived for CO2 capture using H2 -selective membranes in integrated gasification combined cycle (IGCC) power plant systems. Three key differences were found relative to plants configured for the production of industrial-grade H2 . First, the H2 /CO2 selectivity requirement is lower when the permeate is combusted in a gas turbine, as opposed to purified for industrial use. Second, the membrane is subject to additional selectivity requirements. For example, CO2 product purity specs impose a H2 /N2 selectivity requirement. Third, the plant design must account for the energy associated with unshifted CO, CH4 and other fuel components that are not separated by the membrane. In contrast to H2 production systems where the high H2 /CO2 selectivity requirement favors ultra-high selectivity metal-based membranes, the requirements for IGCC indicate a wider range of materials, including ceramic, zeolite, and polymeric membranes, should be considered. © 2010 Elsevier B.V. All rights reserved.
1. Introduction Traditional pulverized coal-fired power plants have among the highest average specific rates of carbon dioxide (CO2 ) emissions per unit energy produced (∼0.32–0.35 ton/MWh) and account for over half of total global electricity generating capacity [1]. Concerns about the climate impacts of these emissions have prompted interest in technologies for CO2 capture and sequestration (CCS) [2]. Since coal is expected to remain a major player in the global electricity generation mix through at least 2030, economically competitive CCS technologies will be an important enabler for any greenhouse gas emissions management strategy. Approaches for CO2 capture from power plants can be grouped into three modes—post-combustion, which involves capture from flue gases, pre-combustion, which involves capture from high pressure synthesis gas (syngas) streams, and oxy-fuel, which involves combustion with pure oxygen [3]. Conventional liquid solventbased technologies for separating CO2 are used commercially in the chemical industry [4]. An analysis by the U.S. Department of Energy (DOE) estimates that post-combustion capture using con-
∗ Corresponding author. Tel.: +1 518 387 4628; fax: +1 518 387 7563. E-mail address: [email protected] (A.Y. Ku). 0376-7388/$ – see front matter © 2010 Elsevier B.V. All rights reserved. doi:10.1016/j.memsci.2010.10.066
ventional solvents will increase the cost of electricity by about 80%, and incur a $68/ton avoided cost for CO2 . Corresponding projections for pre-combustion capture are a 30–40% increase in COE and $32–42/ton avoided cost [4]. Although the adoption of CCS technologies is ultimately dependent on policy, the development of next-generation technologies with reduced costs can expand the slate of carbon management options and potentially accelerate the timeline to implementation. This paper focuses on pre-combustion capture for integrated gasification combined cycle (IGCC) power plants. In IGCC systems, coal is gasified to produce syngas comprising carbon monoxide (CO) and hydrogen (H2 ). The syngas is cleaned to remove sulfur and heavy metals, and then combusted to produce electricity. CO2 capture based on conventional solvent technology can be implemented today. For example, GE standard 630 MW IGCC Reference Plants include the GE Carbon IslandTM , either at initial plant construction or as a retrofit, resulting in net CO2 emissions equivalent to that of an F-class natural gas combined cycle plant (∼0.1 ton/MWh) [5]. In an IGCC plant, the syngas stream is at high pressure, offering a unique advantage for carbon capture. Two changes to the base IGCC plant are necessary to accommodate CO2 capture [6]. First, a water-gas-shift (WGS) reactor is introduced to convert CO with steam into CO2 and additional H2 . This is necessary to achieve high CO2 capture rates in a precom-
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Nomenclature ASU CCS CH4 CO CO2 DOE GEE GPU
air separation unit carbon capture and sequestration methane carbon monoxide carbon dioxide Department of Energy GE energy gas permeation unit. 1 GPU = 1 × 10−6 cm3 /cm2 s cm Hg = 3.3e−10 mol (STP)/m2 /Pa/s H2 hydrogen H2 S hydrogen sulfide IGCC integrated gasification combined cycle N2 nitrogen WGS water-gas-shift WGS-MR water-gas-shift membrane reactor A membrane area [m2 ] Flow rate of component i in stream k [mol/m2 /s] ji,k Ki permeance of component i across the membrane [mol/m2 /Pa/s] ˙i m mass flow rate of component i across the membrane [mol/s] log-mean partial pressure difference of component pi,lm i across the membrane [Pa] SF,a/b module separation factor for gases a and b ideal mixed gas selectivity for gases a and b ˛a/b
bustion mode by transforming the syngas into a CO2 - and H2 -rich gas stream. From a plant efficiency perspective, it allows recovery of the fuel energy associated with the CO. The shifted syngas stream is then cooled, and separated using a low temperature solvent system into a fuel-rich H2 stream that can be combusted in a gas turbine and a CO2 -rich product stream that can be purified, compressed, and geologically sequestered. Second, the gas turbine operation must be adjusted to handle a fuel stream with high H2 content. Common practice is to blend with N2 before the combustor in order to adjust the fuel-to-mass ratio towards levels encountered for natural gas feeds [4,7]. The key factors responsible for the incremental cost of CO2 capture are intrinsic energy losses from the water-gas-shift reaction, parasitic energy loads associated with the solvent separation system, thermal integration losses in reheating the fuel, CO2 compression energy and the capital costs associated with the shift reactor, the solvent capture system, and CO2 compressors [6,8]. Membranes have attracted interest as a CO2 separation technology because of their potential for reducing the parasitic energy loads associated with fuel conditioning and CO2 compression, and the decreasing the capital cost of the separation sub-system. Membranes can be integrated into power plants in a variety of ways, but they are most effective when applied to concentrated, high pressure streams due to the greater driving forces for separation. Their use for CCS has been discussed in several review papers [9–12]. To date, most membrane development efforts for precombustion capture have focused on H2 -selective membranes because of wider availability of H2 -permeable materials suitable for the conditions of interest [11,13]. There has been significant public and private sector investment in the development of membranes for high purity H2 production, with several technologies are entering the pilot scale/engineering design stage [14]. Globally, there are active research and development in the areas of materials
Fig. 1. System layouts for IGCC system with conventional liquid solvent-based CO2 capture (top) and membrane-based CO2 capture (bottom).
performance, module design, and integration with water-gas-shift reactors [15–19]. In electricity generation applications, the permeate stream is combusted to produce power. Gas turbines capable of accepting feed streams with up to 45 vol.% hydrogen have been in operation for over 10 years, with more than 80,000 h of operation of the fleet leader [20]. This can be used to advantage in membrane systems, by using the N2 diluent as a sweep gas to increase the separation driving force [21,22]. Studies of the expected performance of systems using known membranes have shown it possible to improve overall plant efficiency, and also have suggested that membranes with lower selectivities are practical when a sweep configuration is used [23]. Several questions related to system integration must still be addressed in order to fully realize the benefits of membrane technology for power generation. First, what is the H2 /CO2 selectivity requirement for the IGCC application, given the relaxed purity requirements for gas turbine feeds? Second, what other selectivity requirements are imposed by the system-level constraints, such as emissions regulations or sequestration-grade CO2 specifications? Finally, a key performance metric for power generation is thermal efficiency, but it is difficult for membrane technologies to economically recover all of the fuel components in the syngas. What are the options for managing fuel slip due to unrecovered H2 , CO, and methane (CH4 ) and how do the technology trade-offs with complementary technologies impact membrane requirements? This paper addresses these questions by deriving system-driven membrane performance targets for high temperature H2 -selective membranes used for CO2 capture in IGCC power plants. A top-
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down approach is used to account for the myriad constraints introduced by the upstream and downstream unit operations, as well as the overall system performance metrics. The resulting membrane targets provide insight into the readiness of current materials for the IGCC application, and also suggest opportunities for further research and development. These include the improvement of membrane materials to maximize their effectiveness in the system, as well as system solutions that can compensate for areas where improvements in membrane performance are difficult.
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Table 1 Assumptions. 1. Isothermal No change in material or gas properties due to temperature gradients 2. No mass transfer limitations Expected to impact membrane area, but have limited impact on selectivity 3. No pressure changes along membrane length Ignore pressure drops due to flow 4. Fickian relationship for mass transport across membrane Applicable for materials with solution-diffusion or activated transport mechanisms No interaction between gas molecules—superposition of transport rate for different gases
2. Approach Process simulations were performed for IGCC systems using baseline and H2 -selective membrane-based CO2 capture subsystems. The DOE bituminous coal power plant analysis for GE Energy gasifiers, as described in Case 2 of reference [4], was used for the baseline case. For the membrane-based cases, the constraints imposed by upstream and downstream unit operations were tabulated and used to define “system-level” requirements for the membrane sub-system. Permeate and retentate stream compositions were computed using a mass balance. Membrane material performance targets were then estimated using a simple log-mean pressure difference model for gas transport. 2.1. IGCC system layout and membrane sub-system requirements Fig. 1 shows plant layouts for an IGCC system using a conventional liquid solvent-based CO2 capture system, and a system using a membrane-based clean-up. The performance of these systems was analyzed using Aspen PLUSTM process simulation software and benchmarked against the DOE baseline analysis [4]. DOE basecase assumptions for upstream and downstream plant operations (e.g., water-gas-shift reactor efficiency, power block operation, and CO2 compression) were used for the membrane analysis. Thermal efficiencies were computed by calculating the heat loads from the converged mass and energy balances for the plant. In the baseline system, the shifted syngas is cooled to remove water and sent to liquid solvent columns that remove H2 S and CO2 [4]. Typical CO conversion rates for two stage WGS reactors are over 85%. The residual fuel gas is then reheated and combusted in a gas turbine to generate electricity, while the H2 S is processed into sulfur product, and the CO2 is compressed for pipeline transport for geological sequestration. In the membrane cases, the shifted syngas is sent to a high T membrane module, which splits the stream into a H2 -rich permeate and a CO2 -rich retentate. The H2 permeate is blended with a compressed nitrogen (N2 ) stream from the air separation unit and sent to a gas turbine without further compression for electricity generation. The retentate stream is cooled, cleaned of hydrogen sulfide (H2 S) and other contaminants, and fed through a catalytic combustor to generate steam from the unrecovered H2 , and other fuel components such as CO and CH4 . The resulting water is removed by condensation, and the CO2 is compressed to pipeline transport specifications. Fig. 2 summarizes some of the constraints imposed by upstream and downstream unit operations, and overall system performance metrics for the membrane-based cases. The feed stream is the output of a low temperature water-gas-shift reactor configured for high CO conversion (96%) [4]. All values for the stream temperature, pressure, flow rate, and composition, as well as assumptions about gasifier operation, the power block, and the CO2 compression equipment, were taken from the DOE bituminous coal baseline analysis for IGCC using a GE Energy gasifier [4].
The N2 sweep stream is the product of the air separation unit. In the baseline case, the N2 is conditioned to meet gas turbine inlet temperature (200 ◦ C) and pressure specifications (3.1 MPa) before mixing with H2 in the combustor. In the membrane cases, this conditioning was performed on the sweep stream, so that the permeate product of the membrane sub-system can be fed directly to the gas turbine without additional compression. The permeate stream is constrained by the target CO2 capture rate, target H2 recovery rate, feed specifications to the gas turbine, and emissions regulations. Since CO2 is not recovered from the turbine flue gas, any CO2 that permeates into the turbine feed stream cannot be sequestered. At a DOE target capture rate of 90%, only 10% of the total carbon in the syngas feed stream, can permeate into the fuel stream. The H2 recovery rate directly impacts the thermal efficiency of the plant by determining the split of power generation by the gas turbine and the less efficient catalytic oxidizer. Simulations were performed at 70% and 90% H2 recovery to evaluate this effect. The gas turbine feed specifications limit the total H2 content due to the combustor temperature capability and turbine fluid mechanics. The flow rate of the N2 sweep was set to a H2 content of 43% mol, to match the gas turbine inlet in the DOE bituminous baseline analysis [4]. The pressure is set to 3.1 MPa to allow the stream to be fed to the gas turbine combustor without additional compression. The retentate stream contains the residual fuel components, along with the CO2 that will eventually be sequestered. Sequestration-grade CO2 must be supercritical for pipeline transport and injection. Current pipeline specifications call for about 140 bar, with no more than 4% mol N2 , to ensure that the supercritical CO2 and N2 remain miscible [24,25]. This purity requirement limits the amount of N2 from the sweep that can back-diffuse through the membrane into the retentate. For this study, the total N2 content in the retentate was limited to no more than 1/25th that of the CO2 . 2.2. Membrane material performance requirements Quantitative targets for membrane selectivity were computed for the simplified case of a single-stage membrane module with countercurrent flow. A mass balance was performed to calculate the compositions of the gas streams entering and leaving the membrane module. The mass transport rate for each component was estimated, and used to compute required membrane module separation factors for H2 /CO2 and H2 /N2 . The membrane selectivity target was estimated by normalizing the module separation factor by the average feed partial pressure of the gases. Table 1 lists the assumptions used in the calculation. These simplifying assumptions allowed order-of-magnitude estimates of the membrane performance requirements for the purposes of elucidating the system design trade-offs needed to fully integrate the membrane into the IGCC system, and identifying gaps in current materials capabilities. Quantitative targets can be rigorously derived using detailed models of the energy and mass transfer and
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Fig. 2. Membrane sub-system. Detailed information about feed streams can be found in Exhibit 3-33 of reference [4].
membrane geometry. However, these calculations require additional definition of the material properties and membrane module form factors, and, as such, are beyond the scope of this paper. The mass balance requires that each component of the gas stream satisfy:
ji,k = 0
(1)
where ji,k is the flow rate of component i in stream k. The transport mechanism was assumed to be linear with the partial pressure difference at each point along the membrane, allowing a log-mean partial pressure driving force to be defined as ˙ i = (Ki A)pi,lm m pi,lm =
(2)
pi,14 − pi,23
(3)
ln(pi,14 /pi,23 )
where mi is the mass transport rate of component i across the membrane, Ki is the permeance for component i, A is the membrane area, pi,lm is the partial pressure driving force for component i, and pi,14 and pi,23 are the partial pressure gradients at the two ends of the membrane module, as shown schematically in Fig. 2. The assumption of a linear relationship between permeance and the partial pressure driving force applies to membranes where the transport mechanism involves molecular sieving or solutiondiffusion, such as porous ceramics, zeolites, or polymer materials. It is not valid for metal membranes, which obey a non-linear “Sievert’s law”-type relationship between pressure and permeance [26]. The module separation factors, SF , for the gas components are given by SF,H2 /CO2 =
KH2 A KCO2 A
,
SF,H2 /N2 =
KH2 A
performance gaps and development opportunities. A more formal analysis, using a suitably rigorous treatment of multicomponent transport model such as the Maxwell–Stefan treatment, is beyond the scope of this initial study. Moreover, the exact numerical targets will be sensitive to the feed composition variability, the details of the membrane module design and operation, and the possibility of advanced configurations such as multiple membrane stages. It should also be noted that the development process itself, is expected to be iterative, with improvements in capability arising from both improved membrane materials and more sophisticated process designs. 3. Results and discussion The successful integration of H2 -selective membranes into an IGCC system requires that the membrane sub-system operates in concert with the other unit operations in the syngas clean-up system to produce both a fuel stream conditioned for combustion in a turbine and a CO2 stream of sufficient purity and pressure for pipeline transport and geological sequestration. Fig. 3 illustrates the relationship between system-level requirements and membrane performance targets, and also acts as a roadmap for this section. 3.1. System performance: process simulation results The system performance simulations were performed for baseline IGCC with no capture, IGCC with conventional liquid solvent CO2 capture, and IGCC with membrane-based H2 /CO2 separation at 70% and 90% H2 recovery. Together, these cases illustrate the rel-
(4)
KN2 A
where SF is the module separation factor. This is the bulk separation by the membrane module needed to satisfy the mass balance. Ideal mixed gas selectivity targets were computed from the ratio of the module separation factor and normalizing by the average gas stream compositions to obtain ideal mixed gas selectivities. Membrane selectivity targets for H2 /CO2 and H2 /N2 are given by ˛H2 /CO2 =
KH2 pCO2 ,avg KCO2 pH2 ,avg
,
˛H2 /N2 =
KH2 pN2 ,avg KN2 pH2 ,avg
(5)
This approach neglects interactions between the multiple permeating species, and as such, the performance targets obtained in this study are intended to provide initial insight into the readiness of the existing membrane material options, as well as highlight
Fig. 3. Relationship between system-level requirements and membrane performance targets.
A.Y. Ku et al. / Journal of Membrane Science 367 (2011) 233–239 Table 2 AspenPlus process simulation results.
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the sequestration spec. The sweep side partial pressure decreases because of the permeation of H2 .
Capture technology
Efficiency
No capture Liquid solvent (selexol) − 90% CO2 capture H2 membrane (90% recovery) + catalytic oxidizer − 90% CO2 capture H2 membrane (70% recovery) + catalytic oxidizer − 90% CO2 capture
Baseline −6.7 pts −5.0 pts −7.0 pts
ative impact of generating electricity using a gas turbine compared to a catalytic oxidizer, and the importance of managing the fuel content of the syngas stream. The relative plant thermal efficiencies computed from AspenPlus simulations are listed in Table 2. The energy efficiency penalty associated with CO2 capture using conventional liquid solvents is 6.7 points. The use of a membrane can reduce this penalty to 5.0 points, provided the membrane can recover 90% of the H2 in the shifted syngas feed. The net benefits accrue from the avoided need for reheating of the fuel after the H2 /CO2 separation, and the reduced CO2 compression loads, due to the higher recovery pressure of the CO2 . However, reducing the H2 recovery by the membrane erodes these benefits. This is because the power produced by the catalytic oxidizer does not quite offset the reduced gas turbine output. At 70% H2 recovery by the membrane, the net thermal efficiency penalty is 7.0%, making the membrane-based solution unfavorable compared to the conventional liquid solvent system. This trend suggests that the highest possible H2 recoveries are desirable, to maximize the power generation by the gas turbine. However, the catalytic oxidizer cannot be completely eliminated. This is because one inherent limitation of the membrane approach is its inability to recover the non-H2 fuel components from the feed stream. Since no known membrane materials exhibit significantly higher transport rates for CO and CH4 over CO2 , downstream operations on the retentate stream are needed to recover the energy from CO, CH4 and unrecovered H2 .1 3.2. Selectivity targets Syngas produced from coal contains a variety of other components besides H2 and CO2 . These components must also be accounted for in system integration efforts. In addition, the effects of CO2 transport and sequestration specs must be considered. Table 3 lists selectivity targets for H2 /CO2 and H2 /N2 for moderate (70%) and high (90%) H2 recovery by the membrane system. It is possible that they can be relaxed through the introduction of upstream or downstream unit operations, as part of the system optimization. For example, downstream unit operations that purify the CO2 could enable membranes with lower H2 /N2 selectivity. The selectivity was estimated from the partial pressure profiles in the feed and sweep for H2 , CO2 , and N2 for a single stage countercurrent module. The partial pressure gradient for H2 and CO2 drives permeation of these gases from the shifted syngas feed into the sweep. In contrast, the higher N2 partial pressure in the sweep can result in back-diffusion of N2 from the sweep stream into the CO2 -rich retenate. The extent of allowable N2 back-diffusion is constrained by the purity specs for the CO2 product. For N2 , the transport rate is sufficiently low that the partial pressure of gas on one side of the membrane does not change appreciably. For the N2 case, the N2 content in the syngas retentate gradually increases until it meets the constraint derived from
1 Membranes that operate via a Knudsen diffusion mechanism show ideal CO/CO2 and CH4 /CO2 selectivities of 1.25 and 1.67, respectively.
3.2.1. H2 /CO2 selectivity: impact of gas turbine inlet requirements The estimated H2 /CO2 membrane selectivity requirement for IGCC ranged from about 20 to 60, considerably lower than for industrial H2 production. This is not surprising given the ultra-high purity requirement (99.999%) for the latter case [14]. However, in power generation, the thermomechanics of gas turbines favor high pressure, lower purity feeds. This fundamental trade-off in the IGCC case considerably opens the design and materials space because pressure is as important and can be traded-off against purity. For the high H2 recovery rate (Case 1), the computed membrane selectivity target was approximately 60. This is slightly higher than the overall membrane separation factor, because the H2 driving force decreases along the membrane module. The H2 /CO2 selectivity decreases as the H2 recovery rate decreases. Physically, the higher average driving force for H2 permeation at lower recovery leads to higher average H2 flux. This implies a higher permissible leak rate of CO2 into the permeate stream. At a 90% overall CO2 capture rate, the required H2 /CO2 selectivity drops from about 60 to about 20 as the H2 recovery is reduced from 90% to 70%. H2 /CO2 selectivities of order 10–100 in the 250–400 ◦ C range are well within the capabilities of a wide range of materials, including ceramics, composites, and some polymers [27–29]. 3.2.2. H2 /N2 selectivity: impact of CO2 transport and sequestration specifications Sequestration-grade CO2 must be supercritical for pipeline transport and injection. In addition, secondary components must be maintained at sufficiently low concentrations to minimize complications with phase separation, pipeline corrosion or reservoir injectivity [25]. Surprisingly, the H2 /N2 selectivity requirement is more aggressive than both the H2 /CO2 requirement. This is due, in large part, to the high partial pressure driving force for N2 backdiffusion from a pressurized sweep stream. However, it should be noted that these requirements are based on the assumption that the downstream CO2 clean-up operations do not remove N2 . A number of unit operations are needed to remove moisture, heavy metals, residual organics, and particulate matter. Depending on the subsequent clean-up unit operations, lower H2 /N2 selectivities could very well be possible. 3.3. Management of fuel slip Fuel slip refers to the fuel components from the syngas feed that are not transferred to the membrane permeate stream. This includes unpermeated H2 , along with unshifted CO, CH4 and other components with fuel value. Since one of the primary performance metrics of power plants is thermal efficiency, the recovery of energy from these components is of critical importance to achieve economical membrane-based CO2 capture. In the proposed design, a catalytic oxidizer combusts the fuel slip in the retentate stream to produce steam. The thermal efficiency of the power plant is improved by using the steam to generate electricity in a steam turbine or for heat integration. The catalytic oxidizer approach is necessary for CO and CH4 , since these components are remain in the retentate stream. The H2 recovery rate describes the partitioning of H2 between the gas turbine and catalytic oxidizer paths. As seen in Table 2, higher recoveries are favorable because the gas turbine is a more effective method for extracting power. In a simple single-stage module, recovery can be increased by increasing the membrane area. Fig. 4 shows the relative area requirement as a function of H2 recovery rate, for a membrane module configured for 90% CO2 capture. The area requirement increases non-linearly with the
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Table 3 Computed membrane performance requirements. H2 /CO2
Case 1: High H2 recovery – 90% Case 2: Moderate H2 recovery – 70%
H2 /N2
Module SF
Membrane ˛
Module SF
Membrane ˛
40 18
62 21
250 130
870 290
recovery rate because the driving force for separation becomes very low as the separation progresses. This leads to an economic tradeoff where the benefits in improved thermal efficiency associated with high H2 recovery are offset by the increased capital expense due to the large membrane areas needed to achieve high H2 recovery. Since the capital cost of the membrane is proportional to the area and the specific cost for the membrane, this trade-off can be partly mitigated by improving the membrane permeance, leading to a lower total area required needed to achieve a given H2 recovery rate, or by reducing the specific cost of the membrane. The system-driven performance requirements in power generation applications favor membranes with lower H2 /CO2 selectivity, relative to the H2 polygeneration case. However, high H2 permeance and low specific costs are favorable for both applications. 3.4. Survey of current materials capabilities Current efforts to develop materials have succeeded in producing materials with a range of properties, manufacturability, and economics. These have been reviewed extensively in recent years [15]. Most of these efforts have focused on improving H2 /CO2 selectivity and H2 permeance. Fig. 5 summarizes the current state of the art in H2 /CO2 performance under the conditions of interest, along with the targets. The H2 permeance has set at 1000 GPU, which corresponds to a flux rate comparable to the target set by the U.S. DOE for membranes to be used in high purity H2 production [30]. Metal membranes are a leading candidate for high purity H2 production [27]. They are also being considered for WGS-MR systems [16]. They have outstanding selectivity to all gases, but stability to sulfur remains an area of active research. Performance estimates of metal membranes indicate that they can economically achieve H2 recoveries up to about 70%. Porous ceramic and zeolite-based membranes have also received considerable attention. These materials show promising selectivity and H2 permeance [28]. However, given the mechanism for gas transport through these materials, it is not unreasonable to expect that these materials will be able to achieve the desired selectivity. Sulfur tolerance is less of a concern for ceramic materials, but the effects of steam on long-term stability is an area of concern. High temperature polymers exhibit close to the target H2 /CO2 selectivities computed for Case 2 in Table 3 [29]. Current research
Fig. 5. Membrane performance targets for IGCC with single-stage module CO2 capture and estimated materials performance capabilities. The green region represents the approximate target space for membrane development. The lower manufacturing costs for polymer membranes suggests they may be feasible at lower H2 permeance. 1 gas permeation unit (GPU) = 1 × 10−6 cm3 /cm2 s cm Hg = 3.3e−10 mol (STP)/m2 /Pa/s. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)
indicates that complementary technologies or advanced module designs with innovative staging will be necessary to achieve all of the selectivity requirements. The lower permeance in polymers can be potentially offset by the lower cost, and the development of syngas-compatible polymer modules remains an active area. 3.5. Future development opportunities Efforts to develop H2 -selective membranes for CO2 capture in IGCC should continue to include fundamental work on materials processing. Once candidate materials are capable of achieving the necessary H2 /CO2 selectivity, optimization efforts should shift their focus to other selectivity targets, such as H2 /N2 , and improving the H2 permeance. Although not discussed in this paper, research and development is also needed to improve the stability of the materials under high pressure syngas conditions, and their manufacturability at the scales needed for power plant applications. In addition, there are opportunities for advanced system and module designs to fully optimize membrane-based CO2 capture for IGCC systems. New schemes for managing fuel slip, advanced module designs including staging and recycle streams, and hybridization of membranes with other clean-up technologies are all areas ripe for innovation. 4. Conclusion
Fig. 4. Plot of relative area vs. H2 recovery.
High temperature membranes can separate CO2 at high temperature and at high pressure and provide a significant boost in the performance when properly integrated into IGCC power plants. In contrast to H2 production systems where the high H2 /CO2 selectivity favors ultra-high selectivity membranes, the requirements for IGCC indicate a wider range of materials, including ceramic and zeolite-based membranes, should be considered. How-
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ever, candidate materials must satisfy a number of performance requirements, including H2 /CO2 and H2 /N2 selectivity targets, in addition to exhibiting promising permeance, stability, and manufacturability. As candidate membranes move from the lab to field demonstrations, and ultimately commercialization, it is important that development efforts involve both materials improvements and systems design components to ensure the optimal benefits of the technology are realized. Acknowledgments The authors would like to acknowledge Johanna Wellington, Kelly Fletcher, Raul Ayala, Bill Livingood, Scott Miller, James Ruud, M. Mahendhra, and Ashok Anand for helpful discussions. This work was supported by the Sustainable Energy Advanced Technology program at GE Global Research. References [1] Energy Information Administration, International Energy Outlook 2009, http://www.eia.doe.gov/oiaf/ieo/pdf/electricity.pdf. [2] B.D. Hong, E.R. Slatick, CO2 emission factors for coal, originally published in Energy Information Administration, Quarterly Coal Report, January–April 1994, DOE/EIA-0121(94/Q1) (Washington, DC, August 1994), pp. 1–8, http://www.eia.doe.gov/cneaf/coal/quarterly/co2 article/co2.html. [3] K. Damen, M. van Troost, A. Faaij, W. Turkenburg, A comparison of electricity and hydrogen production systems with CO2 capture and storage. Part A. Review and selection of promising conversion and capture technologies, Prog. Energy Combust. Sci. 32 (2006) 215. [4] J.M. Klara, et al. Cost and performance baseline for fossil energy plants. Volume 1: Bituminuous coal and natural gas to electricity final report, DOE/NETL-2007/1281, 2007, http://www.netl.doe.gov/energyanalyses/pubs/Bituminous%20Baseline Final%20Report.pdf. [5] K. White, GE’s Carbon IslandTM Gasification Technologies Conference, Washington DC, October, 2008, http://www.gasification.org/uploads/downloads/ Conferences/2008/03WHITE.pdf. [6] P. Chiesa, S. Consonni, T. Kreutz, R. Williams, Co-production of hydrogen, electricity and CO2 from coal with commercially ready technology. Part A. Performance and emissions, Int. J. Hydrogen Energy 30 (2005) 747. [7] D.M. Todd, R.A. Battista, Demonstrated applicability of hydrogen fuel for gas turbines, http://www.netl.doe.gov/technologies/coalpower/turbines/ refshelf/GE%20Hydrogen-Fueled%20Turbines.pdf. [8] T. Kreutz, R. Williams, S. Consonni, P. Chiesa, Co-production of hydrogen, electricity and CO2 from coal with commercially ready technology. Part B. Economic analysis, Int. J. Hydrogen Energy 30 (2005) 769. [9] A. Brunetti, F. Scurra, G. Barbieri, E. Drioli, Membrane technologies for CO2 separation, J. Membr. Sci. 359 (2010) 115. [10] T.C. Merkel, H. Lin, X. Wei, R. Baker, Power plant post-combustion carbon dioxide capture: an opportunity for membranes, J. Membr. Sci. 359 (2010) 126.
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[11] R. Bredesen, K. Jordal, O. Bolland, High temperature membranes in power generation with CO2 capture, Chem. Eng. Proc. 43 (2004) 1129. [12] J.D. Figueroa, T. Fout, S. Plasynski, H. McIlvried, R.D. Srivastava, Advances in CO2 capture technology—The U.S. Department of Energy’s Carbon Sequestration Program, Int. J. Greenhouse Gas Control 2 (2008) 9. [13] C.A. Scholes, K.H. Smith, S.E. Kentish, G.W. Stevens, CO2 capture from pre-combustion processes—strategies for membrane gas separation, Int. J. Greenhouse Gas Control 4 (2010) 739–755. [14] Hydrogen from Coal Program, Research, Development and Demonstration Plan for 2009 to 2016, U.S. Department of Energy, 2009, http://www.netl.doe.gov/technologies/hydrogen clean fuels/refshelf/pubs/ 2009 Draft H2fromCoal Sept30 final hires cover.pdf. [15] N.W. Ockwig, T.M. Nenoff, Membranes for hydrogen separation, Chem. Rev. 107 (2007) 4078. [16] J.W. Phair, R. Donelson, Developments and design of novel (non-palladiumbased) metal membranes for hydrogen separation, Ind. Eng. Chem. Res. 45 (2006) 5657. [17] M.-B. Haag, R. Quinn, Polymeric facilitated transport membranes for hydrogen purification, MRS Bull. 31 (2006) 750. [18] A. Criscuoli, A. Basile, E. Drioli, O. Loiacono, An economic feasibility study for water gas shift membrane reactor, J. Membr. Sci. 181 (2001) 21. [19] G.Q. Lu, J.C. Diniz da Costa, M. Duke, S. Giessler, R. Socolow, R.H. Williams, T. Kreutz, Inorganic membranes for hydrogen production and purification: A critical review and perspective, J. Colloid Interface Sci. 314 (2007) 589. [20] S. Rahm, J. Goldmeer, M. Moliere, A. Eranki, Addressing gas turbine fuel flexibility, GER4601 (06/09), http://www.gepower.com/prod serv/ products/tech docs/en/downloads/GER4601.pdf. [21] P. Chiesa, T. Kreutz, G. Lozza, CO2 sequestration from IGCC power plants by means of metallic membranes. GT2005-68023, in: Proceedings of GT2005 Turbo Expo 2005, Reno-Tahoe, NV, June 6–9, 2005. [22] S.P. Kaldis, G. Skodras, G.P. Sakellaropoulos, Energy and capital cost analysis of CO2 capture in coal IGCC processes via gas separation membranes, Fuel Proc. Technol. 85 (2004) 337. [23] M. Bracht, P.T. Alderliesten, R. Kloster, R. Pruschek, G. Haupt, E. Xue, J.R.H. Ross, M.K. Koukou, N. Papayannakos, Water gas shift membrane reactor for CO2 control in IGCC systems: techno-economic feasibility study, Energy Convers. Manage. 38 (1997) S159. [24] U.S. Department of Energy, National Energy Technology Laboratory website, Carbon sequestration: CO2 capture, http://www.netl.doe.gov/technologies/ carbon seq/core rd/co2capture.html. [25] K. Havens, CO2 transportation, Kinder Morgan, http://www.purdue.edu/ discoverypark/energy/pdfs/cctr/presentations/Havens-CCTR-June08.pdf. [26] A. Caravella, F. Scura, G. Barbieri, E. Drioli, Sieverts law empirical exponent for Pd-based membranes: critical analysis in pure H2 permeation, J. Phys. Chem. B 114 (2010) 6033. [27] D.S. Scholl, Y.H. Ma, Dense metal membranes for production of high-purity hydrogen, MRS Bull. 31 (2006) 770. [28] H. Verweij, Y.S. Lin, J. Dong, Microporous silica and zeolite membranes for hydrogen production, MRS Bull. 31 (2006) 756. [29] J.D. Perry, K. Nagai, W.J. Koros, Polymer membranes for hydrogen separations, MRS Bull. 31 (2006) 745. [30] Hydrogen from Coal R&D plan, NETL, September 2010, http://fossil.energy. gov/programs/fuels/hydrogen/2010 Draft H2fromCoal RDD final.pdf.
Contents lists available at ScienceDirect
Journal of Membrane Science journal homepage: www.elsevier.com/locate/memsci
Membrane performance requirements for carbon dioxide capture using hydrogen-selective membranes in integrated gasification combined cycle (IGCC) power plants Anthony Y. Ku ∗ , Parag Kulkarni, Roger Shisler, Wei Wei GE Global Research, 1 Research Circle, Niskayuna, NY 12309, United States
a r t i c l e
i n f o
Article history: Received 25 August 2010 Received in revised form 23 October 2010 Accepted 29 October 2010 Available online 9 November 2010 Keywords: CO2 capture H2 membrane Precombustion Syngas Targets
a b s t r a c t Precombustion CO2 capture is an important option for the management of greenhouse gas emissions from power generation, because the higher concentrations can lead to improved separation economics. Membranes can provide a significant boost in the performance by separating CO2 at high temperature and at high pressure, provided they are properly integrated into a power plant. In this study, membrane performance targets were derived for CO2 capture using H2 -selective membranes in integrated gasification combined cycle (IGCC) power plant systems. Three key differences were found relative to plants configured for the production of industrial-grade H2 . First, the H2 /CO2 selectivity requirement is lower when the permeate is combusted in a gas turbine, as opposed to purified for industrial use. Second, the membrane is subject to additional selectivity requirements. For example, CO2 product purity specs impose a H2 /N2 selectivity requirement. Third, the plant design must account for the energy associated with unshifted CO, CH4 and other fuel components that are not separated by the membrane. In contrast to H2 production systems where the high H2 /CO2 selectivity requirement favors ultra-high selectivity metal-based membranes, the requirements for IGCC indicate a wider range of materials, including ceramic, zeolite, and polymeric membranes, should be considered. © 2010 Elsevier B.V. All rights reserved.
1. Introduction Traditional pulverized coal-fired power plants have among the highest average specific rates of carbon dioxide (CO2 ) emissions per unit energy produced (∼0.32–0.35 ton/MWh) and account for over half of total global electricity generating capacity [1]. Concerns about the climate impacts of these emissions have prompted interest in technologies for CO2 capture and sequestration (CCS) [2]. Since coal is expected to remain a major player in the global electricity generation mix through at least 2030, economically competitive CCS technologies will be an important enabler for any greenhouse gas emissions management strategy. Approaches for CO2 capture from power plants can be grouped into three modes—post-combustion, which involves capture from flue gases, pre-combustion, which involves capture from high pressure synthesis gas (syngas) streams, and oxy-fuel, which involves combustion with pure oxygen [3]. Conventional liquid solventbased technologies for separating CO2 are used commercially in the chemical industry [4]. An analysis by the U.S. Department of Energy (DOE) estimates that post-combustion capture using con-
∗ Corresponding author. Tel.: +1 518 387 4628; fax: +1 518 387 7563. E-mail address: [email protected] (A.Y. Ku). 0376-7388/$ – see front matter © 2010 Elsevier B.V. All rights reserved. doi:10.1016/j.memsci.2010.10.066
ventional solvents will increase the cost of electricity by about 80%, and incur a $68/ton avoided cost for CO2 . Corresponding projections for pre-combustion capture are a 30–40% increase in COE and $32–42/ton avoided cost [4]. Although the adoption of CCS technologies is ultimately dependent on policy, the development of next-generation technologies with reduced costs can expand the slate of carbon management options and potentially accelerate the timeline to implementation. This paper focuses on pre-combustion capture for integrated gasification combined cycle (IGCC) power plants. In IGCC systems, coal is gasified to produce syngas comprising carbon monoxide (CO) and hydrogen (H2 ). The syngas is cleaned to remove sulfur and heavy metals, and then combusted to produce electricity. CO2 capture based on conventional solvent technology can be implemented today. For example, GE standard 630 MW IGCC Reference Plants include the GE Carbon IslandTM , either at initial plant construction or as a retrofit, resulting in net CO2 emissions equivalent to that of an F-class natural gas combined cycle plant (∼0.1 ton/MWh) [5]. In an IGCC plant, the syngas stream is at high pressure, offering a unique advantage for carbon capture. Two changes to the base IGCC plant are necessary to accommodate CO2 capture [6]. First, a water-gas-shift (WGS) reactor is introduced to convert CO with steam into CO2 and additional H2 . This is necessary to achieve high CO2 capture rates in a precom-
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Nomenclature ASU CCS CH4 CO CO2 DOE GEE GPU
air separation unit carbon capture and sequestration methane carbon monoxide carbon dioxide Department of Energy GE energy gas permeation unit. 1 GPU = 1 × 10−6 cm3 /cm2 s cm Hg = 3.3e−10 mol (STP)/m2 /Pa/s H2 hydrogen H2 S hydrogen sulfide IGCC integrated gasification combined cycle N2 nitrogen WGS water-gas-shift WGS-MR water-gas-shift membrane reactor A membrane area [m2 ] Flow rate of component i in stream k [mol/m2 /s] ji,k Ki permeance of component i across the membrane [mol/m2 /Pa/s] ˙i m mass flow rate of component i across the membrane [mol/s] log-mean partial pressure difference of component pi,lm i across the membrane [Pa] SF,a/b module separation factor for gases a and b ideal mixed gas selectivity for gases a and b ˛a/b
bustion mode by transforming the syngas into a CO2 - and H2 -rich gas stream. From a plant efficiency perspective, it allows recovery of the fuel energy associated with the CO. The shifted syngas stream is then cooled, and separated using a low temperature solvent system into a fuel-rich H2 stream that can be combusted in a gas turbine and a CO2 -rich product stream that can be purified, compressed, and geologically sequestered. Second, the gas turbine operation must be adjusted to handle a fuel stream with high H2 content. Common practice is to blend with N2 before the combustor in order to adjust the fuel-to-mass ratio towards levels encountered for natural gas feeds [4,7]. The key factors responsible for the incremental cost of CO2 capture are intrinsic energy losses from the water-gas-shift reaction, parasitic energy loads associated with the solvent separation system, thermal integration losses in reheating the fuel, CO2 compression energy and the capital costs associated with the shift reactor, the solvent capture system, and CO2 compressors [6,8]. Membranes have attracted interest as a CO2 separation technology because of their potential for reducing the parasitic energy loads associated with fuel conditioning and CO2 compression, and the decreasing the capital cost of the separation sub-system. Membranes can be integrated into power plants in a variety of ways, but they are most effective when applied to concentrated, high pressure streams due to the greater driving forces for separation. Their use for CCS has been discussed in several review papers [9–12]. To date, most membrane development efforts for precombustion capture have focused on H2 -selective membranes because of wider availability of H2 -permeable materials suitable for the conditions of interest [11,13]. There has been significant public and private sector investment in the development of membranes for high purity H2 production, with several technologies are entering the pilot scale/engineering design stage [14]. Globally, there are active research and development in the areas of materials
Fig. 1. System layouts for IGCC system with conventional liquid solvent-based CO2 capture (top) and membrane-based CO2 capture (bottom).
performance, module design, and integration with water-gas-shift reactors [15–19]. In electricity generation applications, the permeate stream is combusted to produce power. Gas turbines capable of accepting feed streams with up to 45 vol.% hydrogen have been in operation for over 10 years, with more than 80,000 h of operation of the fleet leader [20]. This can be used to advantage in membrane systems, by using the N2 diluent as a sweep gas to increase the separation driving force [21,22]. Studies of the expected performance of systems using known membranes have shown it possible to improve overall plant efficiency, and also have suggested that membranes with lower selectivities are practical when a sweep configuration is used [23]. Several questions related to system integration must still be addressed in order to fully realize the benefits of membrane technology for power generation. First, what is the H2 /CO2 selectivity requirement for the IGCC application, given the relaxed purity requirements for gas turbine feeds? Second, what other selectivity requirements are imposed by the system-level constraints, such as emissions regulations or sequestration-grade CO2 specifications? Finally, a key performance metric for power generation is thermal efficiency, but it is difficult for membrane technologies to economically recover all of the fuel components in the syngas. What are the options for managing fuel slip due to unrecovered H2 , CO, and methane (CH4 ) and how do the technology trade-offs with complementary technologies impact membrane requirements? This paper addresses these questions by deriving system-driven membrane performance targets for high temperature H2 -selective membranes used for CO2 capture in IGCC power plants. A top-
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down approach is used to account for the myriad constraints introduced by the upstream and downstream unit operations, as well as the overall system performance metrics. The resulting membrane targets provide insight into the readiness of current materials for the IGCC application, and also suggest opportunities for further research and development. These include the improvement of membrane materials to maximize their effectiveness in the system, as well as system solutions that can compensate for areas where improvements in membrane performance are difficult.
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Table 1 Assumptions. 1. Isothermal No change in material or gas properties due to temperature gradients 2. No mass transfer limitations Expected to impact membrane area, but have limited impact on selectivity 3. No pressure changes along membrane length Ignore pressure drops due to flow 4. Fickian relationship for mass transport across membrane Applicable for materials with solution-diffusion or activated transport mechanisms No interaction between gas molecules—superposition of transport rate for different gases
2. Approach Process simulations were performed for IGCC systems using baseline and H2 -selective membrane-based CO2 capture subsystems. The DOE bituminous coal power plant analysis for GE Energy gasifiers, as described in Case 2 of reference [4], was used for the baseline case. For the membrane-based cases, the constraints imposed by upstream and downstream unit operations were tabulated and used to define “system-level” requirements for the membrane sub-system. Permeate and retentate stream compositions were computed using a mass balance. Membrane material performance targets were then estimated using a simple log-mean pressure difference model for gas transport. 2.1. IGCC system layout and membrane sub-system requirements Fig. 1 shows plant layouts for an IGCC system using a conventional liquid solvent-based CO2 capture system, and a system using a membrane-based clean-up. The performance of these systems was analyzed using Aspen PLUSTM process simulation software and benchmarked against the DOE baseline analysis [4]. DOE basecase assumptions for upstream and downstream plant operations (e.g., water-gas-shift reactor efficiency, power block operation, and CO2 compression) were used for the membrane analysis. Thermal efficiencies were computed by calculating the heat loads from the converged mass and energy balances for the plant. In the baseline system, the shifted syngas is cooled to remove water and sent to liquid solvent columns that remove H2 S and CO2 [4]. Typical CO conversion rates for two stage WGS reactors are over 85%. The residual fuel gas is then reheated and combusted in a gas turbine to generate electricity, while the H2 S is processed into sulfur product, and the CO2 is compressed for pipeline transport for geological sequestration. In the membrane cases, the shifted syngas is sent to a high T membrane module, which splits the stream into a H2 -rich permeate and a CO2 -rich retentate. The H2 permeate is blended with a compressed nitrogen (N2 ) stream from the air separation unit and sent to a gas turbine without further compression for electricity generation. The retentate stream is cooled, cleaned of hydrogen sulfide (H2 S) and other contaminants, and fed through a catalytic combustor to generate steam from the unrecovered H2 , and other fuel components such as CO and CH4 . The resulting water is removed by condensation, and the CO2 is compressed to pipeline transport specifications. Fig. 2 summarizes some of the constraints imposed by upstream and downstream unit operations, and overall system performance metrics for the membrane-based cases. The feed stream is the output of a low temperature water-gas-shift reactor configured for high CO conversion (96%) [4]. All values for the stream temperature, pressure, flow rate, and composition, as well as assumptions about gasifier operation, the power block, and the CO2 compression equipment, were taken from the DOE bituminous coal baseline analysis for IGCC using a GE Energy gasifier [4].
The N2 sweep stream is the product of the air separation unit. In the baseline case, the N2 is conditioned to meet gas turbine inlet temperature (200 ◦ C) and pressure specifications (3.1 MPa) before mixing with H2 in the combustor. In the membrane cases, this conditioning was performed on the sweep stream, so that the permeate product of the membrane sub-system can be fed directly to the gas turbine without additional compression. The permeate stream is constrained by the target CO2 capture rate, target H2 recovery rate, feed specifications to the gas turbine, and emissions regulations. Since CO2 is not recovered from the turbine flue gas, any CO2 that permeates into the turbine feed stream cannot be sequestered. At a DOE target capture rate of 90%, only 10% of the total carbon in the syngas feed stream, can permeate into the fuel stream. The H2 recovery rate directly impacts the thermal efficiency of the plant by determining the split of power generation by the gas turbine and the less efficient catalytic oxidizer. Simulations were performed at 70% and 90% H2 recovery to evaluate this effect. The gas turbine feed specifications limit the total H2 content due to the combustor temperature capability and turbine fluid mechanics. The flow rate of the N2 sweep was set to a H2 content of 43% mol, to match the gas turbine inlet in the DOE bituminous baseline analysis [4]. The pressure is set to 3.1 MPa to allow the stream to be fed to the gas turbine combustor without additional compression. The retentate stream contains the residual fuel components, along with the CO2 that will eventually be sequestered. Sequestration-grade CO2 must be supercritical for pipeline transport and injection. Current pipeline specifications call for about 140 bar, with no more than 4% mol N2 , to ensure that the supercritical CO2 and N2 remain miscible [24,25]. This purity requirement limits the amount of N2 from the sweep that can back-diffuse through the membrane into the retentate. For this study, the total N2 content in the retentate was limited to no more than 1/25th that of the CO2 . 2.2. Membrane material performance requirements Quantitative targets for membrane selectivity were computed for the simplified case of a single-stage membrane module with countercurrent flow. A mass balance was performed to calculate the compositions of the gas streams entering and leaving the membrane module. The mass transport rate for each component was estimated, and used to compute required membrane module separation factors for H2 /CO2 and H2 /N2 . The membrane selectivity target was estimated by normalizing the module separation factor by the average feed partial pressure of the gases. Table 1 lists the assumptions used in the calculation. These simplifying assumptions allowed order-of-magnitude estimates of the membrane performance requirements for the purposes of elucidating the system design trade-offs needed to fully integrate the membrane into the IGCC system, and identifying gaps in current materials capabilities. Quantitative targets can be rigorously derived using detailed models of the energy and mass transfer and
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Fig. 2. Membrane sub-system. Detailed information about feed streams can be found in Exhibit 3-33 of reference [4].
membrane geometry. However, these calculations require additional definition of the material properties and membrane module form factors, and, as such, are beyond the scope of this paper. The mass balance requires that each component of the gas stream satisfy:
ji,k = 0
(1)
where ji,k is the flow rate of component i in stream k. The transport mechanism was assumed to be linear with the partial pressure difference at each point along the membrane, allowing a log-mean partial pressure driving force to be defined as ˙ i = (Ki A)pi,lm m pi,lm =
(2)
pi,14 − pi,23
(3)
ln(pi,14 /pi,23 )
where mi is the mass transport rate of component i across the membrane, Ki is the permeance for component i, A is the membrane area, pi,lm is the partial pressure driving force for component i, and pi,14 and pi,23 are the partial pressure gradients at the two ends of the membrane module, as shown schematically in Fig. 2. The assumption of a linear relationship between permeance and the partial pressure driving force applies to membranes where the transport mechanism involves molecular sieving or solutiondiffusion, such as porous ceramics, zeolites, or polymer materials. It is not valid for metal membranes, which obey a non-linear “Sievert’s law”-type relationship between pressure and permeance [26]. The module separation factors, SF , for the gas components are given by SF,H2 /CO2 =
KH2 A KCO2 A
,
SF,H2 /N2 =
KH2 A
performance gaps and development opportunities. A more formal analysis, using a suitably rigorous treatment of multicomponent transport model such as the Maxwell–Stefan treatment, is beyond the scope of this initial study. Moreover, the exact numerical targets will be sensitive to the feed composition variability, the details of the membrane module design and operation, and the possibility of advanced configurations such as multiple membrane stages. It should also be noted that the development process itself, is expected to be iterative, with improvements in capability arising from both improved membrane materials and more sophisticated process designs. 3. Results and discussion The successful integration of H2 -selective membranes into an IGCC system requires that the membrane sub-system operates in concert with the other unit operations in the syngas clean-up system to produce both a fuel stream conditioned for combustion in a turbine and a CO2 stream of sufficient purity and pressure for pipeline transport and geological sequestration. Fig. 3 illustrates the relationship between system-level requirements and membrane performance targets, and also acts as a roadmap for this section. 3.1. System performance: process simulation results The system performance simulations were performed for baseline IGCC with no capture, IGCC with conventional liquid solvent CO2 capture, and IGCC with membrane-based H2 /CO2 separation at 70% and 90% H2 recovery. Together, these cases illustrate the rel-
(4)
KN2 A
where SF is the module separation factor. This is the bulk separation by the membrane module needed to satisfy the mass balance. Ideal mixed gas selectivity targets were computed from the ratio of the module separation factor and normalizing by the average gas stream compositions to obtain ideal mixed gas selectivities. Membrane selectivity targets for H2 /CO2 and H2 /N2 are given by ˛H2 /CO2 =
KH2 pCO2 ,avg KCO2 pH2 ,avg
,
˛H2 /N2 =
KH2 pN2 ,avg KN2 pH2 ,avg
(5)
This approach neglects interactions between the multiple permeating species, and as such, the performance targets obtained in this study are intended to provide initial insight into the readiness of the existing membrane material options, as well as highlight
Fig. 3. Relationship between system-level requirements and membrane performance targets.
A.Y. Ku et al. / Journal of Membrane Science 367 (2011) 233–239 Table 2 AspenPlus process simulation results.
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the sequestration spec. The sweep side partial pressure decreases because of the permeation of H2 .
Capture technology
Efficiency
No capture Liquid solvent (selexol) − 90% CO2 capture H2 membrane (90% recovery) + catalytic oxidizer − 90% CO2 capture H2 membrane (70% recovery) + catalytic oxidizer − 90% CO2 capture
Baseline −6.7 pts −5.0 pts −7.0 pts
ative impact of generating electricity using a gas turbine compared to a catalytic oxidizer, and the importance of managing the fuel content of the syngas stream. The relative plant thermal efficiencies computed from AspenPlus simulations are listed in Table 2. The energy efficiency penalty associated with CO2 capture using conventional liquid solvents is 6.7 points. The use of a membrane can reduce this penalty to 5.0 points, provided the membrane can recover 90% of the H2 in the shifted syngas feed. The net benefits accrue from the avoided need for reheating of the fuel after the H2 /CO2 separation, and the reduced CO2 compression loads, due to the higher recovery pressure of the CO2 . However, reducing the H2 recovery by the membrane erodes these benefits. This is because the power produced by the catalytic oxidizer does not quite offset the reduced gas turbine output. At 70% H2 recovery by the membrane, the net thermal efficiency penalty is 7.0%, making the membrane-based solution unfavorable compared to the conventional liquid solvent system. This trend suggests that the highest possible H2 recoveries are desirable, to maximize the power generation by the gas turbine. However, the catalytic oxidizer cannot be completely eliminated. This is because one inherent limitation of the membrane approach is its inability to recover the non-H2 fuel components from the feed stream. Since no known membrane materials exhibit significantly higher transport rates for CO and CH4 over CO2 , downstream operations on the retentate stream are needed to recover the energy from CO, CH4 and unrecovered H2 .1 3.2. Selectivity targets Syngas produced from coal contains a variety of other components besides H2 and CO2 . These components must also be accounted for in system integration efforts. In addition, the effects of CO2 transport and sequestration specs must be considered. Table 3 lists selectivity targets for H2 /CO2 and H2 /N2 for moderate (70%) and high (90%) H2 recovery by the membrane system. It is possible that they can be relaxed through the introduction of upstream or downstream unit operations, as part of the system optimization. For example, downstream unit operations that purify the CO2 could enable membranes with lower H2 /N2 selectivity. The selectivity was estimated from the partial pressure profiles in the feed and sweep for H2 , CO2 , and N2 for a single stage countercurrent module. The partial pressure gradient for H2 and CO2 drives permeation of these gases from the shifted syngas feed into the sweep. In contrast, the higher N2 partial pressure in the sweep can result in back-diffusion of N2 from the sweep stream into the CO2 -rich retenate. The extent of allowable N2 back-diffusion is constrained by the purity specs for the CO2 product. For N2 , the transport rate is sufficiently low that the partial pressure of gas on one side of the membrane does not change appreciably. For the N2 case, the N2 content in the syngas retentate gradually increases until it meets the constraint derived from
1 Membranes that operate via a Knudsen diffusion mechanism show ideal CO/CO2 and CH4 /CO2 selectivities of 1.25 and 1.67, respectively.
3.2.1. H2 /CO2 selectivity: impact of gas turbine inlet requirements The estimated H2 /CO2 membrane selectivity requirement for IGCC ranged from about 20 to 60, considerably lower than for industrial H2 production. This is not surprising given the ultra-high purity requirement (99.999%) for the latter case [14]. However, in power generation, the thermomechanics of gas turbines favor high pressure, lower purity feeds. This fundamental trade-off in the IGCC case considerably opens the design and materials space because pressure is as important and can be traded-off against purity. For the high H2 recovery rate (Case 1), the computed membrane selectivity target was approximately 60. This is slightly higher than the overall membrane separation factor, because the H2 driving force decreases along the membrane module. The H2 /CO2 selectivity decreases as the H2 recovery rate decreases. Physically, the higher average driving force for H2 permeation at lower recovery leads to higher average H2 flux. This implies a higher permissible leak rate of CO2 into the permeate stream. At a 90% overall CO2 capture rate, the required H2 /CO2 selectivity drops from about 60 to about 20 as the H2 recovery is reduced from 90% to 70%. H2 /CO2 selectivities of order 10–100 in the 250–400 ◦ C range are well within the capabilities of a wide range of materials, including ceramics, composites, and some polymers [27–29]. 3.2.2. H2 /N2 selectivity: impact of CO2 transport and sequestration specifications Sequestration-grade CO2 must be supercritical for pipeline transport and injection. In addition, secondary components must be maintained at sufficiently low concentrations to minimize complications with phase separation, pipeline corrosion or reservoir injectivity [25]. Surprisingly, the H2 /N2 selectivity requirement is more aggressive than both the H2 /CO2 requirement. This is due, in large part, to the high partial pressure driving force for N2 backdiffusion from a pressurized sweep stream. However, it should be noted that these requirements are based on the assumption that the downstream CO2 clean-up operations do not remove N2 . A number of unit operations are needed to remove moisture, heavy metals, residual organics, and particulate matter. Depending on the subsequent clean-up unit operations, lower H2 /N2 selectivities could very well be possible. 3.3. Management of fuel slip Fuel slip refers to the fuel components from the syngas feed that are not transferred to the membrane permeate stream. This includes unpermeated H2 , along with unshifted CO, CH4 and other components with fuel value. Since one of the primary performance metrics of power plants is thermal efficiency, the recovery of energy from these components is of critical importance to achieve economical membrane-based CO2 capture. In the proposed design, a catalytic oxidizer combusts the fuel slip in the retentate stream to produce steam. The thermal efficiency of the power plant is improved by using the steam to generate electricity in a steam turbine or for heat integration. The catalytic oxidizer approach is necessary for CO and CH4 , since these components are remain in the retentate stream. The H2 recovery rate describes the partitioning of H2 between the gas turbine and catalytic oxidizer paths. As seen in Table 2, higher recoveries are favorable because the gas turbine is a more effective method for extracting power. In a simple single-stage module, recovery can be increased by increasing the membrane area. Fig. 4 shows the relative area requirement as a function of H2 recovery rate, for a membrane module configured for 90% CO2 capture. The area requirement increases non-linearly with the
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Table 3 Computed membrane performance requirements. H2 /CO2
Case 1: High H2 recovery – 90% Case 2: Moderate H2 recovery – 70%
H2 /N2
Module SF
Membrane ˛
Module SF
Membrane ˛
40 18
62 21
250 130
870 290
recovery rate because the driving force for separation becomes very low as the separation progresses. This leads to an economic tradeoff where the benefits in improved thermal efficiency associated with high H2 recovery are offset by the increased capital expense due to the large membrane areas needed to achieve high H2 recovery. Since the capital cost of the membrane is proportional to the area and the specific cost for the membrane, this trade-off can be partly mitigated by improving the membrane permeance, leading to a lower total area required needed to achieve a given H2 recovery rate, or by reducing the specific cost of the membrane. The system-driven performance requirements in power generation applications favor membranes with lower H2 /CO2 selectivity, relative to the H2 polygeneration case. However, high H2 permeance and low specific costs are favorable for both applications. 3.4. Survey of current materials capabilities Current efforts to develop materials have succeeded in producing materials with a range of properties, manufacturability, and economics. These have been reviewed extensively in recent years [15]. Most of these efforts have focused on improving H2 /CO2 selectivity and H2 permeance. Fig. 5 summarizes the current state of the art in H2 /CO2 performance under the conditions of interest, along with the targets. The H2 permeance has set at 1000 GPU, which corresponds to a flux rate comparable to the target set by the U.S. DOE for membranes to be used in high purity H2 production [30]. Metal membranes are a leading candidate for high purity H2 production [27]. They are also being considered for WGS-MR systems [16]. They have outstanding selectivity to all gases, but stability to sulfur remains an area of active research. Performance estimates of metal membranes indicate that they can economically achieve H2 recoveries up to about 70%. Porous ceramic and zeolite-based membranes have also received considerable attention. These materials show promising selectivity and H2 permeance [28]. However, given the mechanism for gas transport through these materials, it is not unreasonable to expect that these materials will be able to achieve the desired selectivity. Sulfur tolerance is less of a concern for ceramic materials, but the effects of steam on long-term stability is an area of concern. High temperature polymers exhibit close to the target H2 /CO2 selectivities computed for Case 2 in Table 3 [29]. Current research
Fig. 5. Membrane performance targets for IGCC with single-stage module CO2 capture and estimated materials performance capabilities. The green region represents the approximate target space for membrane development. The lower manufacturing costs for polymer membranes suggests they may be feasible at lower H2 permeance. 1 gas permeation unit (GPU) = 1 × 10−6 cm3 /cm2 s cm Hg = 3.3e−10 mol (STP)/m2 /Pa/s. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)
indicates that complementary technologies or advanced module designs with innovative staging will be necessary to achieve all of the selectivity requirements. The lower permeance in polymers can be potentially offset by the lower cost, and the development of syngas-compatible polymer modules remains an active area. 3.5. Future development opportunities Efforts to develop H2 -selective membranes for CO2 capture in IGCC should continue to include fundamental work on materials processing. Once candidate materials are capable of achieving the necessary H2 /CO2 selectivity, optimization efforts should shift their focus to other selectivity targets, such as H2 /N2 , and improving the H2 permeance. Although not discussed in this paper, research and development is also needed to improve the stability of the materials under high pressure syngas conditions, and their manufacturability at the scales needed for power plant applications. In addition, there are opportunities for advanced system and module designs to fully optimize membrane-based CO2 capture for IGCC systems. New schemes for managing fuel slip, advanced module designs including staging and recycle streams, and hybridization of membranes with other clean-up technologies are all areas ripe for innovation. 4. Conclusion
Fig. 4. Plot of relative area vs. H2 recovery.
High temperature membranes can separate CO2 at high temperature and at high pressure and provide a significant boost in the performance when properly integrated into IGCC power plants. In contrast to H2 production systems where the high H2 /CO2 selectivity favors ultra-high selectivity membranes, the requirements for IGCC indicate a wider range of materials, including ceramic and zeolite-based membranes, should be considered. How-
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ever, candidate materials must satisfy a number of performance requirements, including H2 /CO2 and H2 /N2 selectivity targets, in addition to exhibiting promising permeance, stability, and manufacturability. As candidate membranes move from the lab to field demonstrations, and ultimately commercialization, it is important that development efforts involve both materials improvements and systems design components to ensure the optimal benefits of the technology are realized. Acknowledgments The authors would like to acknowledge Johanna Wellington, Kelly Fletcher, Raul Ayala, Bill Livingood, Scott Miller, James Ruud, M. Mahendhra, and Ashok Anand for helpful discussions. This work was supported by the Sustainable Energy Advanced Technology program at GE Global Research. References [1] Energy Information Administration, International Energy Outlook 2009, http://www.eia.doe.gov/oiaf/ieo/pdf/electricity.pdf. [2] B.D. Hong, E.R. Slatick, CO2 emission factors for coal, originally published in Energy Information Administration, Quarterly Coal Report, January–April 1994, DOE/EIA-0121(94/Q1) (Washington, DC, August 1994), pp. 1–8, http://www.eia.doe.gov/cneaf/coal/quarterly/co2 article/co2.html. [3] K. Damen, M. van Troost, A. Faaij, W. Turkenburg, A comparison of electricity and hydrogen production systems with CO2 capture and storage. Part A. Review and selection of promising conversion and capture technologies, Prog. Energy Combust. Sci. 32 (2006) 215. [4] J.M. Klara, et al. Cost and performance baseline for fossil energy plants. Volume 1: Bituminuous coal and natural gas to electricity final report, DOE/NETL-2007/1281, 2007, http://www.netl.doe.gov/energyanalyses/pubs/Bituminous%20Baseline Final%20Report.pdf. [5] K. White, GE’s Carbon IslandTM Gasification Technologies Conference, Washington DC, October, 2008, http://www.gasification.org/uploads/downloads/ Conferences/2008/03WHITE.pdf. [6] P. Chiesa, S. Consonni, T. Kreutz, R. Williams, Co-production of hydrogen, electricity and CO2 from coal with commercially ready technology. Part A. Performance and emissions, Int. J. Hydrogen Energy 30 (2005) 747. [7] D.M. Todd, R.A. Battista, Demonstrated applicability of hydrogen fuel for gas turbines, http://www.netl.doe.gov/technologies/coalpower/turbines/ refshelf/GE%20Hydrogen-Fueled%20Turbines.pdf. [8] T. Kreutz, R. Williams, S. Consonni, P. Chiesa, Co-production of hydrogen, electricity and CO2 from coal with commercially ready technology. Part B. Economic analysis, Int. J. Hydrogen Energy 30 (2005) 769. [9] A. Brunetti, F. Scurra, G. Barbieri, E. Drioli, Membrane technologies for CO2 separation, J. Membr. Sci. 359 (2010) 115. [10] T.C. Merkel, H. Lin, X. Wei, R. Baker, Power plant post-combustion carbon dioxide capture: an opportunity for membranes, J. Membr. Sci. 359 (2010) 126.
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