Using palladium membrane-based fuel reformers for combined heat and power (CHP) plants

Using palladium membranebased fuel reformers for combined heat and power (CHP) plants

15

F. Gallucci1, M. van Sint Annaland1, L. Roses2, G. Manzolini3 1 Eindhoven University of Technology, Eindhoven, The Netherlands; 2 HyGear B. V., Arnhem, The Netherlands; 3Politecnico di Milano, Milano, Italy

15.1

Introduction

It is widely accepted that the problem of global warming will require a combination of solutions ranging from carbon capture and sequestration (CCS) through to improved carbon efficiency of fossil fuels and (in the long term) widespread use of renewable energy sources. In particular, as energy costs increase, the advantage of high energy-conversion efficiency becomes very important. In this respect, fuel cell (FC) systems (with significantly higher conversion efficiency than other energyconversion devices, particularly at small sizes) will become more important and their market share will increase accordingly (further enhanced by reductions in manufacturing costs). However, for FCs overall to achieve higher efficiency, the energy carrier for those FCs (mostly H2) should also be produced at higher efficiency. This can be achieved by using membrane reactors, devices that integrate separation and reaction in a single unit, thus reducing the amount of equipment required and circumventing certain thermodynamic limitations that affect conventional systems. In this chapter, the application of membrane reactors as innovative reformers for combined heat and power (CHP) systems will be discussed. An overview of actual CHP systems will be outlined first, then the advantages and disadvantages of applying novel reformers will be highlighted, and finally an energy analysis of a micro-CHP system with conventional and membrane reformers will be presented.

15.2

Current micro-CHP systems

The worldwide power-production market is based on a centralized grid structure. This structure has drawbacks, which are relevant to growing concern at the low efficiency of energy-conversion systems: high transmission losses that decrease efficiency overall and high centralized emissions can be highlighted, for example. Along with these technical disadvantages, commercial disadvantages in terms of risk, construction time and long-term financial commitment have motivated a new model based Palladium Membrane Technology for Hydrogen Production, Carbon Capture and Other Applications. http://dx.doi.org/10.1533/9781782422419.2.319 Copyright © 2015 Elsevier Ltd. All rights reserved.

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on decentralized (distributed) power production. In particular, the potential for the recovery of heat that in large, centralized power plants is usually vented (because it is uneconomical to recover) promises great benefits in generating power on-site. Micro-combined heat and power (m-CHP) generally refers to systems capable of providing electrical power up to 50 kWel while also producing low-temperature streams that can be (and are) used on-site. Various assessment studies on m-CHP systems have revealed interesting savings in terms of primary energy (PE) consumption and energy costs. The investment cost for an m-CHP system can be recouped without subsidies in a reasonable amount of time thanks to the energy cost savings. While the concept is clear, the methods for converting chemical energy into electricity and heat can be based on technologies ranging from the fairly mature internal combustion engines (ICE), through the newly available micro-scale Stirling engine (SE), to early-stage technologies such as the FCs. FCs have received much attention in recent years because of their potentially higher electrical efficiency and modularity compared with other, more traditional, systems. Interest in FCs has been represented by various research projects funded in this area, as will be discussed in the following sections. The scope of this review is to present the state of R&D on FC-based m-CHP systems, as well as to survey the latest field-test trials, development results, and characteristics of the systems offered by the most notable manufacturers. According to the EU Cogeneration Directive, electrical power for micro-CHP applications is limited to 50 kW. Typical load demands for m-CHP applications in single-family dwellings are listed in Table 15.1. Internal combustion and SE technologies are seen as promising options for m-CHP diffusion in the near future because of their advanced stage of development. A number of models based on these technologies and in the 1kWe range are already on the market. By contrast, micro-turbines are not suitable for low-power residential applications, mostly because of non-competitive prices and because they are not flexible enough for the load changes usually required in these kinds of applications. FCs, on the other hand, offer many advantages over other technologies, such as high electrical efficiency, excellent performance at partial load, negligible (if any) NOx and

Table 15.1 Typical loads for m-CHP systems applied on single family dwellings according to References [1–3] Single family 100 m2 dwellings Electrical load Thermal load Heating to electrical energy demand ratio Annual electrical energy demanda Annual space heating energy demand Annual DHW heating energy demand Technologies applicable a

1–3 kWe 8–15 kWth 3–5 3.000–3.500 kWhe 11.000–16.000 kWhth 1900–2300 kWhth PEMFC, SOFC, SE, ICE

: Not including space and Domestic Hot Water (DHW) heating energy use. Mean value in Europe.

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CO emissions, low noise level, low maintenance, and the potential for high overall efficiency (above 88%) even in small units. The factors limiting their diffusion are their high price and lack of commercial development. Field testing and demonstrations have resulted in ongoing cost reductions for FC-based m-CHP technologies. For instance, Toshiba reported that the cost of their systems in 2007 had fallen to a fifth of what they were in 2004, as a result of the METI-NEF programme. Similarly, the Vaillant systems employed in the European demonstration of a Virtual Fuel Cell Power Plant achieved a 41% cost reduction, as a result of the project. The remaining costs are expected to decrease to sufficient levels by 2015, and strong market growth is expected with the take-up of residential units.4 In 2005 the European Hydrogen and Fuel Cell Technology Platform (HFP) defined the future research and deployment strategies for this sector. An integrated 10-year programme of research, technological development and demonstration was outlined. In 2007, global funding for the FC industry was in the order of US$1.2 billion, including investment of US$360 million in the USA, US$330 million in the EU, US$156 million in Japan, and US$140 million in Germany. Public and private funding of €7.4 billion is required for the proposed programme between 2007 and 2015. The programme is divided into four Innovation and Development Actions (IDA), one of them concerning FCs for CHP and power generation. One important milestone is to have 80 000 1–10 kW FC systems for residential CHPs installed at a cost of under 6000 €/kW by 2015.5 The following sections highlight progress in developing microCHP systems in various countries.

15.2.1

Micro-CHP development in Europe

Future Cogen (2001) and the MicroMap (2002) studies are market-orientated reports that developed assessment simulations of cogeneration systems, forecasting that between 5 and 12.5 million m-CHP systems could be installed and operating commercially in EU countries by the year 2020.6 This would result in a reduction of CO2 emissions of between 3.3 and 7.8 MT/yr. In addition, there is the potential to install 700 000 units in Central and Eastern European countries. Additional EU research projects, such as FLAME solid oxide fuel cells (SOFCs), developing SOFCs (solid oxide FCs) with great flexibility in use of fuel from NG (natural gas) to biodiesel, and NextGenCell in the area of high-temperature polymer-electrolyte-membrane (HTPEM) FCs, deal with the development and the testing of new FC-based m-CHP systems. The European EU FP5 research project, the Virtual Fuel Cell Power Plant, which ran from 23 January 2004 to 11 May 2005, provided interesting insight into the application of FC technology. This exercise in cooperative entrepreneurship was pushed forward by 11 European partners, including Vaillant, Plug Power, Cogen Europe, E.ON Ruhrgas AG, E.ON Energie AG, TEE University of Duisburg-Essen, Instituto Superior Téchnico, DLR, Sistemas de Calor S.L., Gasunie Research and EWE AG. In this project, which cost €8.3 million with an EU contribution of 36%, 31 Vaillant 4.6 kWe + 9kWth decentralized standalone residential polymer-electrolyte-membrane

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fuel cell (PEMFC)-based m-CHP systems were installed in Germany, Portugal, Spain, and the Netherlands. The systems were fed with NG, which was converted to a hydrogen-rich reformate stream to feed the FCs. Successes for the project included no system failures during the programme, overall efficiencies of up to 90%, and electrical efficiencies higher than 30%. The trial achieved 138 000 accumulated hours of operation and produced nearly 400 000 kWh of electrical energy.4,7,8 The recent European project Ene.field will see up to 1000 residential FC m-CHP systems installed across 12 key member-states. This represents a step-change in the level of FC m-CHP deployment in Europe, and meaningful progress towards commercialization of the technology. The programme brings together nine mature European micro-FC-CHP manufacturers into a common analysis framework that will trial all of the available fuel cell CHP technologies. By learning the practicalities of installing and supporting a fleet of FCs with real customers, Ene.field partners will have taken the final step before commercial roll-out. An increase in volume deployment for the manufacturers involved will lead to cost reduction of the technology as it moves from hand-built products to serial production and tooling. The UK government has been active in raising awareness of FCs through the Carbon Trust, the London Climate Action Plan, the Green Light to Green Power Initiative, Transport for London (TfL), the Brighton to London Eco Car Rally, and the London Hydrogen Partnership (LHP) Hydrogen Action Plan. The UK also has two centres of excellence for demonstration of FC technology: the Centre for Process Innovation (CPI) at Teesside and Cenex (the Centre of Excellence for Low Carbon and Fuel Cell Technologies) at Loughborough in the Midlands. Between 2003 and 2007 the Carbon Trust developed the Micro-CHP Accelerator programme to investigate the potential benefits of m-CHP technology. The project involved field trials of 87 m-CHP units (ICE and SE) in both domestic and small commercial environments, as well as a field trial of 27 condensing-system boiler installations, to provide a relevant baseline for m-CHP performance. The units were sized and controlled in order to supply the thermal requirement of the user, and to sell any unused electrical energy. Domestic users received 1–3 kWe + 8–15 kWth systems, while small commercial installations were 5–10 kWe + 12–25 kWth. Up to 20 data parameters were measured at five minute intervals at every site. Field demonstrations were combined with lab tests and theoretical analysis to deliver major insights into appropriate target markets and the potential for accelerating m-CHP development. Around 44 000 days of system operation were analysed by the end of the trial, and it was demonstrated that, for example, use of SEs led to average carbon savings of 5%. Performance was better in households with higher heat demand (typically detached or large homes) – where the annual heat demand was more than 15 000 kWh, the overall saving ranged from 4% to 14%, averaging around 9%.9 Also in the UK, Newborough (2004) studied the feasibility of applying SE- and FC-based m-CHP systems to single dwellings. His results identified reductions of 16–39% in annual energy expenditure, based on various simulated configurations of a nominally 1 kWe m-CHP system.10 Australian-based Ceramic Fuel Cells Ltd. (CFCL) announced in July 2007 its partnership with E.ON, and in November of the

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same year with heating appliance developer Gledhill Water Storage Ltd. in a combined project for the development and testing of 1 kW m-CHP systems. The system, starting as NetGenPlus, evolved into BlueGen, a 2 kW m-CHP system which seems to be well on the way towards market deployment.11 The company claims to have achieved a 60% net electrical efficiency at 75% power load. By October 2013 some 359 units were up and running with an accumulated 3.9 GWh of electricity generated. Their performance can be remotely accessed by their owners through a web-based application.12 With respect to SOFC durability, the UK-based Ceres Power developed innovative cerium gadolinium oxide (CGO) electrolytes that are capable of working at around 500–600°C, instead of the typical 750–1000°C of yttria-stabilized zirconia (YSZ). These lower operating temperatures allow so-called intermediate temperature SOFCs (IT-SOFC) to use low-cost materials for the FCs and balance of plant (BOP) and lead to greater durability of the stack. The firm, through a US$4 million programme in partnership with Centrica (British Gas), integrated the FC into a 1 kWe + 1 kWth wall-mountable NG-CHP unit. Through a similar agreement with Calor Gas Ltd., Ceres Power set up a U$S3.7 million programme to develop an liquefied petroleum gas (LPG)-CHP variant, with introduction into the market anticipated for 2012.13 Field trials began in partnership with British Gas in the first half of 2011, in a programme expected to have at least 150 units running by the end of 2012.14 De Paepe et al. (2006) studied the primary energy saving (PES) ratio for a 4 kWe + 9 kWth IdaTech PEMFC-based m-CHP system installed in a single-family terrace house, for different baseline technologies. Results showed PES of 12%, 22% and 29% for a combined cycle power plant (CCPP), an average fossil-fuel power plant, and an average Belgian power plant (largely nuclear-generated electricity) respectively.15 Boehm (2004) compared a PEMFC-based m-CHP system for single-family dwellings with a reference system based on a condensing gas boiler and CCPP-generated grid electricity. Reductions in PE usage of up to 21% were evident, when the dimensions of the FC were proportional to the maximum heat load and the FC was controlled in accordance with heat demand.16 In Italy, Sasso et al. (2006) conducted an energetic, economic and environmental analysis comparing three residential ICE m-CHP systems with a conventional system for separate production of heat and electricity. The m-CHP system achieved PES up to 25% and a pollutant emissions reduction of up to 40%.17 Sibilio et al. (2007) studied the potential of m-CHP units in residential trigeneration applications. A comparison was carried out with the best available reference system for separate production of electricity based on an Italian gas-fuelled CCPP with electrical efficiency of 55%. PES were up to 14%, with a reduction in CO2 emissions of up to 17%.18 In September 2008, Acumentrics announced the start of field trials on its AHEAD system. This system is claimed to be the first fully enclosed residential CHP unit designed to meet the power and heating needs of an average European home, using a 1 kW tubular SOFC in combination with 24 kW condensing boiler operating with NG. Acumentrics is a US-based SOFC developer, which created the system jointly

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with the Italian Merloni TermoSanitari (MTS), who specialize in heating appliances. A unit of the standalone tubular FC has already been tested for more than 10 500 h and has met the minimum performance targets of the SECA programme. In September 2008 the German Federal Ministry for Transport, Construction and Urban Development (BMVBS) launched its Callux “lighthouse” project, to help prepare the route to market both for manufacturers of residential fuel cell (CHP) systems and for energy suppliers. Callux is one of the major elements in the German National Innovation Programme for Hydrogen and Fuel Cell Technology (NIP). Large field trials are planned eventually to involve 800 demonstration units operating for single-family houses; around 300 of these units were operating by April 2013. The task of coordinating the NIP will be managed by the National Organization for Hydrogen and Fuel Cell Technology (NOW GmbH). This includes the evaluation and selection of projects to be supported, linking R&D with demonstrations, setting up international cooperative ventures, and communication and knowledge management. Callux is a consortium that includes heating manufacturers Baxi Innotech, Vaillant, and Hexis, energy suppliers EnBW, E.on/Ruhrgas, EWE, MVV Energie and VNG Verbundnetz Gas, and the ZSW Centre for Solar Energy and Hydrogen Research in Stuttgart. The total funding for Callux amounts to €86 million, with BMVBS contributing around €40 million. Overall, BMVBS will provide up to €500 million over the next 10 years to promote hydrogen and FC technology through the NIP, with industrial partners obliged to commit at least the same amount.19

15.2.2

Micro-CHP development in North America

Gunes and Ellis (2003)20 studied a 4.1 kWe and a 5 kWe PEMFC cogeneration system for a US single-family house, with a vapour compression heat pump for cooling and heating, and a thermal storage tank. The results showed that the performance of the m-CHP system can result in a reduction in PE use of 34–55% compared with conventional all-electric or gas–electric systems. In the USA, the Industry Teams are one of the three groups constituting the SECA alliance managed by the National Energy Technology Laboratory (NETL). Its goal is to develop SOFC-system prototypes of 3–10 kWe output within a threephase programme, with the target dates for each phase being 2008, 2010, and 2015, respectively. The Industrial Teams themselves are six in number, working independently and therefore competing with each other, although all are committed to the concept of mass customization as the pathway to reducing the cost of FC systems. Among the six teams, Acumentrics, Fuel Cell Energy, General Electric Power Systems, and Siemens Westinghouse Power Corporation are focused most on stationary m-CHP applications. General Electric kicked off Phase 1 testing in June 2005, and tests concluded with Cummins in December 2006 (thus well ahead of the 2008 target date). Each team successfully conducted a series of rigorous tests on their SOFC prototypes to evaluate system performance with respect to efficiency, endurance, availability, and production costs. To verify the results, the prototype tests and system cost analyses were subjected to independent audits, with

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additional validation testing performed at NETL’s FC test facility. The prototypes surpassed the Department of Energy (DOE) Phase 1 targets, demonstrating an average efficiency of 38.5%, peaking at 41% (the DOE target was 35%); an average steady-state power degradation of 2% per 1000 h (the DOE target was 4% per 1000 h); system availabilities averaging 97% (the DOE target was 90%); and projected system costs ranging from US$724 to US$775 per kWe (the DOE intermediate target was US$800/kWe).21 The US Department of Defense (DoD) together with the Engineer Research and Development Center (ERDC) and the Construction Engineering Research Laboratory (CERL), ran the Residential PEM Demonstration Project. This programme began in FY2001, with Congress appropriating US$3.6 million to demonstrate residentialscale, stationary PEM FCs at military facilities. Subsequent project funding of US$3.4 million, US$4.3 million, and US$2.4 million saw the continuation of these projects through FY2002, 2003, and 2004, respectively. All PEM FCs installed were produced in the USA. In total, 56 were at sites where five manufacturers installed 93 FC systems, of which only 27 were used in cogeneration. This demonstration project provided valuable experience, both from its successes and from its failures. In their 2005 report, ERDC/CERL identify high availability as difficult to attain, noting as a lesson learnt the need for a reliable communication system with the FC for monitoring and quick response, or otherwise the presence of a specialized technician on-site. System efficiency was also an issue; these systems were intended for electricity generation, but the mean heat recovery was as low as 11%, which is not optimal for domestic application with the configuration utilized in the trials. However, another message to be taken from the project is that PEM systems are quite suitable for providing back-up power; in particular, it is both technically and financially realistic to use direct hydrogen FCs in a hybrid configuration with a battery array.22 The US company Plug Power, in partnership with the international NG and electricity utility National Grid and the DOE, is to conduct the first field trial of its new HTPEM-based 5 kWe m-CHP system GenSys. The firm received a US$1.4 million award from the New York State Energy Research and Development Authority (NYSERDA) to install and operate three NG-fuelled units providing electricity and heat to National Grid customers located in New York.23

15.2.3

Micro-CHP development in Japan and Australia

The METI-NEDO-NEF large-scale demonstration project for stationary FCs started in 2005 and has installed 1 kWe FC systems for demonstration tests in more than 3000 households. This governmental project was originally scheduled to conclude at the end of March 2008 but ran for an additional year, to March 2009. The systems, supplied by different technology providers, utilized three types of fuels. As a result, FC producers, energy providers, and gas and oil companies worked closely together, feeding all generated field data back to the NEF for analysis of the results, promoting advances both in system development and cost reduction while allowing end users to develop experience in operation and maintenance.24

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Two of the developers announced the market release of ENE-FARM, an FC-based CHP system for residential use. Toshiba on June 2009 and Eneos Celltech on September 2009 revealed their 700 W NG-fuelled system at a price of ¥-3 255 000 (€24 000), of which ¥1 400 000 (€10 500) was subsidized by METI. A new model of the system was released in the first half of 2011, which could generate at 40% electrical efficiency, according to the manufacturers. By 2013 the number of orders for this system exceeded 40 000 units. Panasonic, Toyota, Toshiba, and Eneos were all manufacturing the ENE-FARM system by the end of 2011, bringing it to customers through gas companies such as Tokyo Gas Co., Ltd., Toho Gas Co., Ltd., Saibu Gas Co., Ltd., Shizuoka Gas Co., Ltd., Keiyo Gas Co., Ltd., JX Nippon Oil & Energy Corp., and Osaka Gas Co. SOFC technologies have also been promoted by government, although less intensively than was the case for PEMFC. Project budgets speak for themselves: in FY2008 NEDO directed ¥2.71 billion (€20 million) to the “Demonstration of Residential PEFC Systems for Market Creation” programme and ¥0.8 billion (€6 million) to the “Demonstrative Research on Solid Oxide Fuel Cells” programme.25 In 2006, Ebara Ballard, analysing results from 480 units installed during 2005 for the METI programme mentioned above, reported an overall efficiency of 74.9% for its PEMFC system, with PES of 21.8% and CO2 emission reduction of 35.7% compared with separate heat and power production.26 Higashiguchi et al. (2004) evaluated the development of residential PEMFC-based m-CHP systems at Osaka Gas with extensive field testing of prototype units starting in April 2002, evaluating system reliability and durability in real customers houses. Over 100 000 h of operation were registered by the end of July 2004.27 In 2006, Osaka Gas and the Kyocera Corporation conducted the first trial operations in Japan of their SOFC m-CHP 1 kWe system fuelled on NG and installed in a research home (a four-person house of 108 m2 floor area) at Osaka Gas’s NEXT 21 experimental housing complex. The testing ran from the end of November 2005 to March 2006 and comprised nearly 2000 h of operation. The peak net AC output electrical efficiency was 49% (averaging 44%), while the overall efficiency achieved was 83% (averaging 78%).28 CFCL signed an agreement in 2008 with the gas appliances firm Paloma Industries in Japan to evaluate and develop integrated SOFC m-CHP products. The metal– ceramic FC stack actually runs on NG but a version available for LPG is also among the goals. CFCL supplied Paloma with a NetGenPlus unit to be run under real-world conditions. CFCL also has product development agreements with appliance partners and utility customers in Germany, France, UK, and the Benelux countries.29 The firm recently released its 2 kWe + 1 kWth BlueGen system, and has a memorandum of understanding with VicUrban, the sustainable urban developer agency for the southern Australian state of Victoria, to showcase this CHP unit. When mass-produced, the BlueGen is forecast to cost around A$8000 (€4700), with an approximately sevenyear payback period and 15-year lifetime.30 A summary of the most important projects and actual FC CHP systems is given in Tables 15.2 and 15.3.

> 300

31

January 2004 – May 2005

Operational period

> 40 000

1

PEM and SOFC NG 0.75

Various

Japan

Ene-Farm

October 2003 – May 2006 – ongoing 2007

2–9

9

PEM NG 4,6

Plug power Nuvera PEM NG-C3H8-H2 5

United States

DoE-FE-DoD

FC type Fuel Electrical nominal Power (kWe) Thermal nominal Power (kWth) N° installed

Germany, Spain, Portugal, Netherlands Vaillant/plug power

European virtual fuel cell power plant

2012 – ongoing

1000 (target)

Tbd

SOFC and PEM NG Tbd

Various

Europe

Ene-Field

Summary of most significant FC m-CHP technologies demonstrative projects

FC technology provider

Region

Table 15.2

305 (at 04/2013 800 target) 2007 – ongoing

2

Baxi Innotech, Hexis, Vaillant SOFC and PEM NG 1

Germany

Callux project

34 85 2 – – – N.d. 90 –

34 96 1.7 NG, biogas – – – – –

37 >90 1.3–1.4 NG 170 4 41–43 – –

PEM 0.2–0.75 1.0 60/-

Household FC

Viessman/ Panasonic

b

: Overall efficiency of cogeneration unit only, not including possible additional burner within CHP package. : Time before electrical power is available

a

PEM 5 7.5 –70/-

Inhouse5000

Gamma Premio

PEM 1 1.8 60/40

RBZ GmbH

Baxi Innotech

30 85 1.8 NG – – – – 0–40

HT-PEM 0.5–4.6 8.4 –

GenSys

Plug power

35 (VDC) 70 1 NG/LPG – – – – –

HT-PEM 3 3 –

EnerFuel

Fuel cell PEM based micro-CHP systems proposed by various manufacturers

FC type Electric output (kWe) Thermal output (kWth CHP) Heating water temperature Flow/return (°C) Electrical efficiency (%) Overall efficiency (%)a Q/E ratio Fuel Hot water storage (l) Service interval in ×1000 h Noise dB(A) Startup time (min)b Operating temperatures (°C)

Table 15.3

0.33 > 90 2 NG – – 49 – –

HT-PEM 0.3 0.6 –

Elcore 2400

Using palladium membrane-based fuel reformers for CHP plants

15.3

329

Membrane reactor fuel processing for fuel cell-based micro-CHP systems

FCs are promising candidates for future distributed power generation, thanks to distinctive advantages which include very high efficiency, extremely low pollutant emission, and low noise. A key issue for the deployment of FCs is the use of NG as the primary fuel, thus exploiting the gas distribution network that already exists in most industrialized countries. While high-temperature FCs (molten carbonate FCs and SOFCs) may use NG through internal reforming, thanks to their high operating temperature, low-temperature PEM FCs must rely on an external fuel processing unit to generate the uncontaminated (especially CO-free) hydrogen-rich stream required to feed the FC anode. It is thus particularly important to design an efficient and potentially compact fuel processing unit. The use of a traditional gas reformer (such as a high-temperature methane steam reformer) requires many processing steps downstream of the main reformer, especially to convert the produced CO into hydrogen through water-gas-shift (WGS) steps (generally two steps working at different temperatures), with a final purification step to reduce the amount of residual CO to ppm levels and thus avoid poisoning the FC anode. An improvement in overall efficiency can therefore be achieved by using membrane reactors, in which a dense membrane, completely perm-selective towards hydrogen, is integrated in the reformer so that reaction and purification can be performed simultaneously. The application of membrane reactors for dehydrogenation reactions was first proposed by Gryaznov in the late 1960s. Removal of hydrogen through a thick membrane resulted in a shift of the equilibrium reaction towards the separated product. Membrane reactors in dehydrogenation reactions were a scientific curiosity, with few papers published per year, until around 1996. Then, with the increasing interest in hydrogen as a potential clean energy carrier, the scientific community rapidly turned its attention towards membrane reactors as highly efficient hydrogen production systems (Fig. 15.1). Along with the increase in published papers, the number of patents awarded for hydrogen production in membrane reactors has also increased rapidly in the last 20 years. In fact, most of the patents have been awarded in the last decade.31 Pure hydrogen production can be achieved in different types of membrane reactors. An ample literature already exists for packed bed membrane reactors (PBMR) for hydrogen production, and an increasing interest can now be observed in novel configurations, especially fluidized bed membrane reactors (FBMR) and micro-membrane reactors (MMR), because better heat management is possible, with reduced mass-transfer limitations, in these reactor configurations. PBMRs have been used for such purposes as producing hydrogen via reforming of methane,32,33 reforming of alcohols,34,35 and autothermal reforming of methane.36 In a packed bed membrane reactor the catalyst is confined in a fixed bed configuration (either in the membrane tube or in the shell side) and in contact with a perm-selective membrane. Permeation through the membrane is driven by the difference in hydrogen partial pressure between the two sides of the membrane. To increase the driving force,

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Number of articles

150

100

50

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

0

Years

Figure 15.1 Number of papers on hydrogen production in membrane reactors per year. Database Scopus (www.scopus.com). Keywords: “membrane reactor” and “hydrogen production”. September 2013.

a sweep gas is often used on the permeation side, which reduces the partial pressure of the permeation hydrogen and hence lowers the membrane area required for hydrogen separation. This practice is also beneficial if hydrogen is being produced for an ammonia plant, in which case nitrogen can be used for sweeping the permeation side, producing a synthesis stream (N2/H2 = 1/3) ready for the final reaction step. If a sweep gas is used on the permeation side, then a packed bed membrane reactor can be used, in either co-current (Fig. 15.2a) or counter-current (Fig. 15.2b) mode. Use of a counter-current mode leads to completely different partial-pressure profiles, on the reaction and permeation sides, from the co-current mode (independently of the reaction system considered), as shown in Fig. 15.3. It is evident that in co-current mode, hydrogen partial pressure on both the reaction side (here indicated as lumen) and permeation side (shell side) increases along the reactor. Moreover, the driving force for hydrogen permeation, which arises from the difference between the hydrogen partial pressures on the lumen side and on the shell side, decreases with increasing reactor length because the hydrogen partial pressure in the shell side then tends towards the hydrogen partial pressure in the lumen side. With the driving force tending to zero, the membrane then has no effect. For counter-current mode, the hydrogen partial pressure in the lumen side increases in the first part of the reactor, mainly due to the reaction, and afterwards it diminishes, mainly due to permeation through the membrane. The hydrogen partial pressure at the exit of the reaction side can also be as low as zero, but there is still a residual driving force for permeation, even with the partial pressure in the permeation side being zero, because of the inlet of fresh sweep gas. In almost the whole reactor there is a positive driving force for hydrogen permeation and consequently, by just using the counter-current mode instead of the co-current mode, it is

Using palladium membrane-based fuel reformers for CHP plants

(a)

331

Sweep gas

Feed

Retentate

Membrane

Catalyst Permeate

(b) Permeate

Feed

Retentate

Membrane

Catalyst Sweep gas

Figure 15.2 Co-current configuration (a) and counter-current configuration (b) for membrane reactor.

theoretically possible to recover 100% of the hydrogen produced, assuming the ideal case of infinite membrane surface area. A straightforward way to increase the membrane area in a packed bed, relative to the tube-in-tube configuration, is to use the shell-and-tube configuration.37 An example of multi-tube membrane housing has been patented by Buxbaum (2002) and is shown in Fig. 15.4. In this case the catalyst is loaded in the shell side of the reactor while the membrane tubes are connected to a collector for the pure hydrogen. The possibility of using a catalyst in a separate chamber is shown in the figure; in the case of reforming reactions, this chamber acts as a pre-reforming zone where the greatest temperature profiles are confined, and in this way the membranes can work at an almost constant temperature. The membrane area required for separation can be reduced by increasing the membrane flux (by keeping the same high perm-selectivity). Membrane flux is inversely proportional to membrane thickness, and very thin, dense membranes are nowadays available. For example, for Pd-based membranes, defect-free separation layers as thin as 1–2 μm are commonly produced in the laboratory.38 The thinner the separation layer, the higher is the hydrogen flux through the membrane, and hence the lower is the membrane area required for any given hydrogen recovery.

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Hydrogen partial pressure (bar)

(a)

0.8 Lumen side 0.6

Shell side

0.4

0.2

0.0 0

5

10

15

20

Reactor length (cm)

Hydrogen partial pressure (bar)

(b)

1.0 Lumen side 0.8 0.6 Shell side 1.0

0.4

0.8 0.6 0.4

0.2

0.2 0.0 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0

0.0 0

5

10

15

20

Reactor length (cm)

Figure 15.3 Hydrogen partial pressure in co-current configuration (a) and counter-current configuration (b) for ethanol reforming in packed bed membrane reactors. Source: Reprinted from Gallucci et al., 2008c with permission of Elsevier.

However, the availability of thin membranes (with correspondingly high flux) requires the design of more advanced membrane reactor concepts. When the membrane flux is increased, the bed-to-wall mass-transfer limitations that occur in packed beds become the limiting factors. As long as the hydrogen flux though the membrane is a limiting step, the effect of external mass-transfer resistances, such as limitations on hydrogen transport between the bulk of the catalytic bed (where hydrogen is produced) and the membrane wall (where hydrogen is recovered), can be neglected; this is the case for PBMRs operated with thicker membranes (50 microns or more). However, by increasing the membrane flux, the external mass-transfer limitations become limiting and determine the extent of membrane area. An example of this was given by Tiemersma et al.39 and is shown in Fig. 15.5. The authors claimed that with

Using palladium membrane-based fuel reformers for CHP plants

(a)

333

(b)

(c)

Figure 15.4 Membrane housing (a), catalyst distribution (b) and membrane connectors (c) for a multitube membrane reactor (Buxbaum, 2002).

Relative H2 wt fraction [-]

1.0 0.8 0.6 0.4 z/L = 0.10 - experimental flux expression z/L = 0.10 - doubled permeability z/L = 0.10 - quadruped permeability

0.2 0.0 0.0

0.2

0.4

0.6

0.8

1.0

r /R

Figure 15.5 Relative H2 weight fraction profiles at changing membrane permeability. Source: Reproduced from Tiemersma et al., 2006 with permission of Elsevier.

the membranes available in 2006 the effect of mass-transfer limitations was quite small, but that by increasing the experimental membrane flux (to a level foreseen in a couple of years of membrane developments), the external mass-transfer limitation could become a limiting step (as indicated in the figure). The authors have also clearly shown by 2D simulation that temperature control is important in membrane reactors, because a temperature decrease on the membrane surface reduces the hydrogen flux through the membrane, while temperature increase

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(as in the case shown by Tiemersma) could result in damage to the membrane surface and consequent decrease of perm-selectivity and deterioration in membrane reactor performance. Heat management and temperature control in PBMRs is quite challenging, and temperature profiles along the membrane length are difficult to avoid in such a reactor. The combination of these drawbacks has driven research towards new reactor concepts, such as MMRs and FBMRs. A typical fluidized membrane reactor (or membrane-assisted fluidized bed reactor (MAFBR)) for hydrogen production consists of a bundle of hydrogen perm-selective membranes immersed in a bubbling catalytic bed. FBMRs reduce bed-to-wall masstransfer limitations and can operate under virtually isothermal conditions (due to the movement of the catalyst). This makes possible the autothermal reforming of hydrocarbons inside the membrane reactor, and prevents the formation of hot (or cold) spots on the membrane surface. According to Deshmukh et al.40 the main advantages of the MAFBR are: • Negligible pressure drop, which allows small particle sizes and avoidance of internal massand heat-transfer limitations; • (Virtually) isothermal operation (due to the circulation pattern of solids inside the membrane reactor); • Flexibility in membrane and heat-transfer surface area and arrangement of the membrane bundles; • Improved fluidization behaviour (in the case of immersed bundles of membranes) as a result of compartmentalization (i.e. reduced axial gas back-mixing) and reduced average bubble size due to enhanced bubble fragmentation (resulting in improved bubble-to-emulsion mass transfer).

An example of an MAFBR is shown in Fig. 15.6.41 In this reactor, both pure hydrogen production and CO2 capture can be achieved by making use of dead-end membranes for hydrogen recovery and U-shaped membranes for heat supply via hydrogen combustion. The interested reader is referred to Reference [42] for a better comparison between FBMRs and PBMRs. Both reactors can be used for (micro-)cogeneration systems, as is highlighted below. These results are better reported and explained in the paper by Roses et al.43

15.4

Comparison between fixed and fluidized bed membrane reactors for micro-CHP systems

Roses et al.43 studied the application of membrane reactors (MREF) for a residentialscale FC-based micro-CHP system, with a net electric output of 2 kW. They also compared the system with conventional fuel processing (traditional reforming (TR)). The two different system layouts are presented in Figs 15.7 and 15.8, respectively. The authors performed an energy/exergy analysis to identify the most important losses in the system. In particular, four distinct sections of the system can be identified: (i) the steamer, where the superheated steam required for the reforming reaction

Using palladium membrane-based fuel reformers for CHP plants

335

CO2 + H2O Air

H2

N2 + H2O

H2 membranes

Reforming/shift catalyst

H2O

CH4

Figure 15.6 Hydrogen combustion configuration for pure hydrogen production through autothermal reforming of methane.41

Steamer

Fuel processor

Heat recovery

PEMFC

Hot gas CH4+H2O

Reformer (830°C)

Burner

Air

Heat Recovery

NG

NG Superheater

WGSR(400°C)

Air

Sep

Anode PEM FuelCell Cathode

Rec Heat Exch

WGSR(250°C) Water receiver

Sep Boiler PROX(200°C) Preheater

Pump

Figure 15.7 Layout of PEMFC micro-CHP unit using TR for NG processing.

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Steamer

Heat recovery

PEMFC

Fuel processor Hot Gas Air MREF Burner (600°C)

CH4+ NG

H2O

Heat recovery

Retentate

Super heater H2

H2

H2 cooler

Anode PEM FuelCell Cathode Sep

Air

Rec heat exch.1

Boiler

Water receiver

Preheater Pump

Figure 15.8 Layout of PEMFC micro-CHP unit using membrane reformer (MREF) for NG processing.

is produced; (ii) the fuel processor, which includes reactors for hydrogen production and their respective heat exchangers; (iii) the PEMFC and auxiliaries section, which includes the FC but also auxiliaries and power conditioning systems; and (iv) the heat recovery section. This division is useful in the exergy analysis for understanding the electric efficiency losses. The most proven technology for hydrogen production from NG is based on steam methane reforming (SMR), where the following three reactions take place: CH4 + H2O ⇔ CO + 3H2 CO + H2O ⇔ CO2 + H2

R.1 R.2

CH4 + 2H2O ⇔ CO2 + 4H2

R.3

In PEM-based CHP, a hydrogen-rich stream is required to feed the anode of the FC. To safeguard this anode in current PEM FCs, the concentration of CO in the fuel stream should not exceed 10 ppm. This target is achieved by adopting four different reacting stages, as shown in Fig. 15.7. NG is first converted in the reforming reactor at temperatures of 800–850°C, where heat is required for the endothermic reforming reaction. Downstream of the reforming, the syngas is fed to two water-gas-shift (WGS) reacting stages to increase the H2 content as much as possible and, simultaneously, to decrease the CO concentration; the adoption of different operating temperatures, the first at around 300–350°C (where a high reaction rate is achieved) and the second at about 200–250°C (where a high conversion rate is achieved), and of two different catalysts, is necessary to maximize CO conversion. Finally, a preferential oxidation (PROX) reactor converts the remaining CO before delivering the hydrogen

Using palladium membrane-based fuel reformers for CHP plants

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to the FC anode. As shown in the layout, the heat required by the endothermic SMR is supplied via the combustion of additional NG and the remaining hydrogen in the anode tail gas (hydrogen utilization in PEM is about 75%). Each conversion process is followed by a cooling step in order to achieve the best conditions at the inlet of each reactor (two WGS and the PROX). This is done through the cooling circuit used for heat recovery. The innovative small-scale CHP system using the membrane reformer is shown in Fig. 15.8. The steamer, PEMFC and heat recovery sections do not significantly change from the conventional case; the main difference is in the fuel processor, which consists of a single reactor capable of delivering a stream of pure hydrogen, which feeds the anode after being cooled down. The reference working conditions for the reforming reaction (600°C and a total pressure of 8 bar) were taken from previous studies and are summarized in Table 15.4. A sensitivity analysis of these conditions was carried out, and at this operating temperature the conversion of methane is not complete; however, it is not a problem in this case, because the unconverted fuel and the un-permeated hydrogen (the retentate stream of the membrane reactor) are combusted in order to support the endothermic reaction. The advantages of MREF technology over a conventional fuel processor are higher electrical efficiency and equipment savings. Figure 15.9 shows schematically the energy balances for the micro-CHP systems in the reference cases indicated for the conventional fuel processor and the membrane reformer, outlining the thermodynamic advantages of the latter. In the MREF case, the 4.7 kW stream on the left represents the NG energy input fed into the reactor after pressurization and preheating. As mentioned before, the unconverted CH4 and CO, and the un-permeated H2 at the membrane reactor outlet are combusted to provide the heat required by the endothermic reaction. This is indicated by the stream bringing 1.3 kW of heat for reforming back from the reformer output. The required methane conversion rate is approximately 80–85%, which is just able to produce enough hydrogen to sustain the permeation needed and still have sufficient fuel left in the retentate stream to preserve the heat balance mentioned above. The resulting hydrogen recovery factor (HRF), defined as the ratio between the permeated hydrogen and the maximum hydrogen flow that can theoretically be produced, is around 66%. The recovered hydrogen is fully converted in the FC. From this conversion, the 2 kW stream represents the net electrical output, and the remainder consists of cogenerated heat, thermal losses and consumption of power by auxiliaries. In the conventional processing case, the methane entering the reactor represents an input of 4.2 kW, which is a value similar to that in the MREF case. All reformate produced in the reformer goes to the FC, so the NG conversion rate must be as high as possible. The reformer therefore operates at 830°C, in contrast to the MREF case where the reaction takes place at 600°C. The higher operating temperature, together with the higher methane conversion rate (typically over 97%), generates a greater demand for heat, which is supplied by burning the hydrogen that exits the FC anode and additional methane, as also shown in the layout in Fig. 15.7. Fuel utilization in the PEMFC is 75%, in contrast with the previous case where it was virtually complete, thanks to the dead-end configuration. The energy diverted towards heat recovery and powering of

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Table 15.4

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Operating conditions and assumptions for the reference

case SMR on TR case

PEM fuel cell

Equilibrium temperature Inlet pressure

°C

830

Current density

mA cm−2

210

Bar(a)

1.4

V

0.728

S/C ratio at inlet Thermal lossesa

%

3.55 4

Operating voltage for diluted H2 feed (TR) Operating voltage for pure H2 Feed (MREF) Operating pressure Average working temperature Oxygen utilization factor

V

0.784

Bar(a) °C

1.2 75

%

50

°C

13

°C

10

% °C

1 5

°C

25–50

% % %

97.8 96.5 70

WGSR and PROX Inlet temperature for HT-WGSR Inlet temperature for LT-WGSR S/CO ratio at HT-WGSR inlet WGSRs thermal lossb PROX thermal lossb

°C

280

°C

210 6.6

Heat exchangers

%

2

%

1

ΔT of pinch point for boiler Minimum ΔT for water preheater Thermal lossesc ΔT of pinch point for recovery heat exchangers for cogeneration Temperature range of water on circuit for heat recovery Electrical and auxiliaries efficiencies DC/DC converter DC/AC inverter Compressors polytropic efficiency

MREF Equilibrium temperature Inlet pressure

°C

600

Bar(a)

8.0

Thermal lossesa NG input

%

3

LHV Inlet pressure Molar composition:

MJ kg−1 mbar(g)

46.9 40

CH4 83.9%; CO 1.8%; C2H6 9.2%; C3H8 4.7%; N2 0.4% a b c

Referred to heat required by reaction. Referred to heat of reaction. Referred to heat transferred.

Other auxiliaries % of net power

1.0

Using palladium membrane-based fuel reformers for CHP plants

4.7 kW CH4

Membrane reformer + steamer

0.9 kW

339

Heat for reforming 1.3 kW 2 kW

PEMFC 3.8 kW 66% (Hydrogen recovery factor)

ηel ≈ 43% 1.8 kW Heat recovery and thermal losses

1.5 kW (anode tail gas) 4.2 kW CH4

Conventional processing + steamer

2 kW

PEMFC 5.5 kW

CH4 5.9 kW

1.7 kW

75% (Hydrogen utilization factor) 1.9 kW

ηel ≈ 34% 2.0 kW Heat recovery and thermal losses

Figure 15.9 Scheme of the energy balance of the micro-CHP systems.

auxiliaries here is about the same order of magnitude as in the MREF case, but there is a significantly larger difference in the heat rejected from the fuel processing section: 1.9 kW in the conventional processing system and 0.9 kW in the MREF system. This is mainly due to the fact that the heating stream leaves the reactor with higher enthalpy and is destined for the heat recovery section after steam production. In conclusion, the operation of the reforming reactor at a lower temperature and control of methane conversion is mainly what leads to higher electrical efficiency of the system as a whole. In addition, the pure H2 produced in the membrane reformer allows greater fuel utilization in the PEMFC and the operating FC voltage can be higher (0.784 V for the membrane case, as against 0.728 V for the reference case), with further advantages for the electrical efficiency of the integrated system. Exergy losses decrease efficiency, and analysis is useful for understanding where such losses occur. Figure 15.10a shows the results of absolute exergy losses for a system with a net electrical output of 2 kW using either a conventional processor or a membrane reformer. Figure 15.10b depicts the distribution of exergy input into losses and the remaining exergy output as second-law efficiency. The total exergy for the streams (in mole-specific terms) is calculated as: e

(h − h0 )

T0 ( s s0 ) + ech

[15.1]

where ech is the chemical contribution to the total exergy, and the reference values of T0 and P0 are set at 288 K and 101 325 kPa, respectively. The exergy inputs are

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(a) 1450 W

1650 W 1500 W Conventional Processor Membrane Reformer

730 W 580 W 230 W

< 60 W Fuel processor

Steamer

(b)

PEMFC and Auxiliaries

Heat recovery

Exergy analysis PEM micro CHP unit Inner : with conventional fuel processor Outer : with membrane reformer 4.8% 9.6%

15.6% Steamer Fuel processor

38.1% 24.0%

47.5%

FC and auxiliaries Heat recovery Second law efficiency

1.0% 27.3%

31.9%

0.2%

15.10 (a) Schematic view of the exergy losses in the micro-CHP systems in absolute terms; (b) Exergy losses in terms of exergy input and remaining second-law efficiency.

associated with the fuel inlet, and the outputs of the systems are the net electrical power and the exergy transferred in the heat recovery exchanger. Figure 15.10a and 15.10b show that the losses from the heat recovery section are low compared to the other terms; thus, from a thermodynamic point of view, this section should not require much (research) attention. Heat transfer in the system considered takes place between similar temperatures, and so water condensation in the exhaust stream makes this transfer feasible even under small differences in temperature. Moreover, heat recovery cannot be further optimized other than by reducing heat-transfer losses in the fuel processor. Correct design of the heat recovery section is in all cases essential for high total efficiency (electricity + heat generation efficiency)

Using palladium membrane-based fuel reformers for CHP plants

341

of the system, and the total efficiency is important from the point of view of energy savings in real applications. It is also important for efficient recovery of condensed water to use as a feed to the steamer, thus avoiding use of an external water supply. By contrast, the PEMFC and auxiliaries section presents the most significant exergy losses, because of FC irreversibility, power conditioning losses and power supply to auxiliaries. The calculation shows that the losses in this section remain mostly unchanged in absolute terms between the two reactive systems, although losses in the MREF case are higher in relative terms (27.3% and 31.9% in the TR and MREF cases, respectively, as proportions of the exergy input) because less fuel is supplied. Moreover, auxiliary losses are influenced by the increase in power consumption of the NG compressor, which is required to bring the pressure up to that needed by the MREF. Calculations for the fuel processor section show that the traditional reformer has losses about twice that of the membrane reformer, in absolute terms. This can be explained firstly by considering that the former option requires four reacting stages instead of one, and with each catalytically activated reaction dealing with intrinsic irreversibilities. In particular, the water-gas-shift and PROX convert the chemical energy of the reformate into heat that cannot be efficiently recovered. Secondly, a higher methane conversion rate is obtained in the traditional reformer, in contrast to the MREF concept where typical methane conversion would not be above 85%. Finally, larger temperature differences for the heat transfer (recall that the maximum reforming temperature is 830°C in the TR case and 600°C in the MREF case) increase the losses in TR. In the steamer section the losses are again higher for the conventional processor, caused mostly by the higher temperature differences between the streams exchanging energy, but also because a greater amount of water has to be evaporated in the traditional reformer. Figure 15.10b shows that the second-law efficiency is 47.5% for the MREF case and 38.1% for the conventional system. The steamer and fuel processor sections taken together cause exergy input losses of 33.6% and 20.4% in the conventional and MREF cases, respectively.

15.5

Conclusions and future trends

This chapter has highlighted the benefits of applying a membrane reformer for the processing of NG within a PEM-based micro-cogeneration system. It was shown that in comparison with the use of traditional four-step processing (SMR + HTWGS + LTWGS + PROX), an electrical efficiency of around 43% rather than 34% can be achieved. Through an analysis of exergy loss and overall energy balance it was possible to show that the higher temperature at the reforming stage and the higher rate of methane conversion in the traditional process are the main reasons for this difference in electrical performance. The next step in this research is to prove the principle of a membrane reactorbased micro-CHP system. The JU-funded project REFORCELL (project number 278997) aims at demonstrating the feasibility and long-term stability of a novel

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Palladium Membrane Technology

membrane reformer-based CHP system for 5 kW applications. An additional step could be the integration of membrane reactors in larger-scale CHP systems where the CO2 capture step can also be integrated in the system.

Note for the reader The content of this chapter is based on our previously published articles and reports. No new calculations have been performed for this chapter.

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42. F. Gallucci, M. Van Sintannaland and J.A.M. Kuipers (2010), Theoretical comparison of packed bed and fluidized bed membrane reactors for methane reforming, Int. J. Hydrogen Energy. 35 7142–7150. 43. L. Roses, F. Gallucci, G. Manzolini, S. Campanari and M. Van Sint Annaland (2011), Comparison between fixed bed and fluidized bed membrane reactor configurations for PEM based micro-cogeneration systems, Chem. Eng. J. 171 1415–1427.