Direct Fuel Cell Experience on Renewable Biogas. FuelCell Energy, Inc., Danbury, CT

Transcription

1 / The Electrochemical Society Direct Fuel Cell Experience on Renewable Biogas M. Farooque a, J. Daly a, T. Leo a, C. Pais a, R. Venkataraman a, and J. Wang a a FuelCell Energy, Inc., Danbury, CT FCE (FuelCell Energy, Inc.) in Danbury, CT currently offers three commercial products; the DFC300MA, DFC1500, and DFC3000, rated 300 kw, 1200 kw and 2400 kw, respectively to operate on methanerich fuels including biogas. These products use the Direct FuelCell (DFC ), which has the special ability to generate electricity directly from a hydrocarbon fuel by reforming it inside the fuel cell and supplying hydrogen for fuel cell reactions. Biogas, which is available from distributed sources, contains 50-80% methane depending on the source, and is an excellent fuel for DFC power plants. FCE has placed over twenty biogas units ranging from 250 kw to 1.2MW around the world, achieving an electricity conversion efficiency of 45 to 49% (LHV). A unique feature of the DFC is that its performance is not impacted by the bio fuels diluted with CO 2 (20-50%). In fact, the biogas plants are consistently showing a higher fuel cell conversion efficiency (~1% on a normalized basis) compared to pipeline natural gas plants. Initial DFC biogas applications focused on wastewater treatment, food processing and brewery industries where the contaminants are primarily sulfur and siloxane. FCE has used operational experience with these plants to improve gas supply reliability, understanding of the biogas contaminants and improvement of removal process effectiveness. Introduction FCE (FuelCell Energy, Inc) Danbury, CT currently offers three commercial products: the DFC300, DFC1500, and DFC3000, rated 300kW, 1400kW and 2800kW, respectively, to operate on methane-rich fuels including biogas. These products use the FCE patented Direct FuelCell (DFC ). The DFC has special ability to generate electricity directly from a hydrocarbon fuel by reforming it inside the fuel cell and supplying hydrogen for fuel cell reactions. This one-step internal-reforming-fuel-cell process results in a simpler, more efficient and cost-effective energy conversion system compared with conventional external reforming fuel cells. More than 75 MW of FCE s Direct FuelCell (DFC ) power plants are operating or currently being installed at over 50 sites worldwide, and FCE has a backlog of orders for more than 33 MW of additional capacity. Two key markets have emerged for the technology: on-site power generation and utility grid support. These plants are operating with an electrical conversion efficiency of 45-49% (LHV) on high as well as medium Btu fuels. This is the highest efficiency of any distributed generation technology in a comparable size range, which results in these products having the lowest CO 2 emission rate in their size range. DFC fuel cells also have a relatively high exhaust temperature (370 C), which enables a wide variety of waste heat uses in combined heat and power applications, including steam generation, hot water production, and absorption chilling. In addition to reduced CO 2 emissions, DFC emissions of harmful pollutants such as nitrogen oxides (NO x ), sulfur oxides (SO x ), and particulate matter are orders of magnitude lower than conventional combustion-based power plants. Downloaded on to IP address. Redistribution subject to ECS 261 terms of use (see ecsdl.org/site/terms_use)

2 FCE s DFC power plants have generated more than 650 million kwh of green electricity to date, utilizing a variety of fuels including renewable biogas from waste water gas, food and beverage processing, as well as natural gas and other hydrocarbon fuels. The biogas application is emerging as one of the important applications of the DFC technology. The biogas, which is available from distributed sources, contains 50-80% methane. Depending on the source, it is a potential carbon neutral fuel because unless used, the gas gets released into the environment as waste gas. An energy generation technology that can efficiently produce electricity and heat with low emissions when operated in a distributed generation mode is most desired for the biogas applications. The DFC was developed to provide green electricity and heat from methane in a distributed generation mode and uniquely qualifies for this application. FCE ventured into biogas applications of the DFC since the start of commercialization of DFC power plants and has used the operational experience with these early plants to improve the design (gas supply reliability, understanding of the contaminants and control). This paper will outline the FCE experiences on biogas, knowledge of the contaminants and discuss how a reliable system design and operations are evolving based on these early project experiences. Why Biogas DFC The direct carbonate fuel cells were initially developed for natural gas fuel. The biogas produced by anaerobic digestion in waste water treatment, food processing industry and decomposition of wastes in landfills contain predominantly methane and CO 2. The biogas is considered a renewable fuel since the gas was going to be released into the environment as waste gas anyway. It can be used in a DFC designed for the natural gas to produce ultra green electricity and useable heat. During the operation of a MW DFC biogas power plant, third party measurements of the power plant emissions were taken. The results showed that the emission levels from the anaerobic digester gas (ADG) DFC plant were extremely low, as they were when operating on natural gas. FCE s natural gas power plants are certified to CARB (California Air Resources Board) standards. The CO levels met the CARB 2007 standards, and NO x and SO x levels were more than an order lower than the CARB 2007 levels. CARB has not yet extended its certification program to biogas (it currently applies to natural gas), but these data indicate that when the CARB program includes biogas applications, the DFC products will do as well as they do with natural gas. The DFC offers a very high efficiency electricity conversion option for the biogas. Also, the byproduct heat of the DFC using the biogas has a good match for heat required by the anaerobic digestion process that produces the gas. The high CO 2 content in the biogas negatively impacts the performance of the anodic reaction of all fuel cells including the carbonate fuel cell. However, a unique feature of the DFC is that its performance loss at the anode due to fuel dilution is compensated by performance gain at the cathode due to higher reactant (CO 2 ) concentration at the cathode. In fact, the DFC open circuit potential in biogas systems is slightly higher than the natural gas system. The stack performances of several DFC plants operating on the biogas and the pipeline natural gas at ten different customer sites are compared in Figure 1. Although natural gas and biogas compositions are different at all sites, a slight biogas performance advantage over the natural gas is clearly evident at each site. On average the biogas plants operate at ~0.5% higher fuel cell conversion efficiency. Downloaded on to IP address. Redistribution subject to ECS 262 terms of use (see ecsdl.org/site/terms_use)

3 In the direct fuel cell, ~2/3 of the fuel cell reaction byproduct heat is used up by the reforming reaction and most of the remaining 1/3 heat is removed by the process gas as sensible heat. The higher carbon-dioxide content in the bio-gas systems process gas streams than natural gas systems results in higher heat removal capacity. Because of the higher heat removal efficiency (due to the higher heat capacity) and improved cell performance advantages, the DFC stacks operate at a lower temperature, ~15 C, than the natural gas system. A typical example is shown in Figure 2, where the DFC plant operates 17 C colder on biogas compared to the natural gas operation to produce the same 290kW power. The lower temperature operation is beneficial for extending the service life of the power producing block (fuel cell) of the plant. Biogas Clean Up Considerations Boigas containing methane is produced from anaerobic digestion of: Municipal waste water Food/beverage processing waste Waste solids from ethanol production Farm animal waste Organic material is digested to reduce waste volume, and produce gas with increased Btu content than the biomass from which the gas is produced. Biogas primarily contains methane (generally 50% to 80%), carbon dioxide, water vapor, and traces of other gases. It also potentially contains contaminants such as oxygen, sulfur, siloxane, halogens, and heavy metals. Table I provides a preview of gas compositions and potential contaminants from different potential sources of the biogas and compares them with natural gas. These gases are required to be cleaned for most of the energy recovery applications. Siloxanes are cleaned to about 1 ppm to prevent SiO 2 deposition on pistons, heat exchangers, or catalyst for emission control, and sulfur compounds are cleaned to several ppm for most potential applications. This is to prevent SO 2 release to air as well as to avoid corrosion. A deeper cleaning of sulfur compounds is required for the DFC application. The municipal and non-municipal anaerobic waste water treatment plants (WWTP) represent a significant source of biogas in the USA. The output gas from the WWTPs employing a sulfide control process contain <300 ppm of H 2 S. H 2 S content in an untreated WWTP biogas is in excess of 1000 ppm by volume. Usually, control technologies are employed to contain it to safe levels to meet emissions criteria for energy recovery use and emission to the environment. A comparison of the potential bulk sulfur control technologies are discussed by Soroushian et.al.[1]. The impurity levels in ADG even with sulfur control technology are significantly higher than natural gas. The type and level of contaminants are dependent on the gas source. An auxiliary fuel clean-up system is used for cleaning the biogas before introduction to the fuel cell. Design of the contaminant removal system requires detailed knowledge of the contaminant species, their levels and potential variation with time. Usually a dedicated auxiliary biogas treatment system as illustrated in Figure 3 (the biogas specific clean-up is shown with the natural gas power plant block flow diagram in dotted lines) is used to control the contaminant levels in biogas for use in a fuel cell. The contaminant treatment process is carried out in three steps. In the first step most of the Downloaded on to IP address. Redistribution subject to ECS 263 terms of use (see ecsdl.org/site/terms_use)

4 sulfides are removed by treating with iron oxide under a controlled environment. The controlling parameters for this process are space velocity of the gas, residual oxygen content, relative humidity, and condensate ph, etc. The iron-oxide bed is not effective in removing the light organic sulfides. After moisture conditioning, a second clean-up bed, usually an activated carbon bed is employed for removing trace amounts of organic sulfur compounds and siloxanes escaping from the Iron-oxide treatment. A De-Ox catalyst bed is used to remove residual oxygen in the biogas. Table I. Typical fuels composition (natural gas vs. bio-gases): Bio-gas clean-up challenges include light sulfur compounds, siloxane, and halogens (in presence of moisture). Bio-gases Composition Natural Waste Food Animal Gas Water Waste Waste Landfill Methane ~50-60 ~ (Vol%) Carbon Dioxide (Vol%) Nitrogen (Vol%) Oxygen (Vol%) Higher 0-10 negligible negligible Hydrocarbons (Vol%) Impurities (ppm) H 2 S Non- H 2 S Sulfur Halogens <0.1 <0.2 <0.2 < Special attention is also required for performance monitoring of the clean-up system to ensure reliability of the gas clean-up system. The operating cost of the sulfur polishing system is high due to frequent monitoring requirements and low sulfur intake capacity of the commercial sulfur polishing agents. FCE has developed two separate equipments for inexpensive online sulfur monitoring and break through detection. Both of these equipments are currently under evaluation with DFC power plants operating on biogas at customer sites. DFC has much more stringent requirements on sulfur (<30 ppb) than internal combustion (IC) engines. The second bed designed to remove the large molecules of siloxanes to 1 ppm level have very low capacity for light sulfur compounds, such as DMS, CS 2, and COS, especially in the presence of moisture in ADG( 10% RH). There is no commercially available technology to remove these small sulfur compounds to <30 ppb level (as desired for the fuel cell application) with significant capacity. Advanced materials are being investigated by FCE as polishing media to supplement the weakness Downloaded on to IP address. Redistribution subject to ECS 264 terms of use (see ecsdl.org/site/terms_use)

5 of the currently available polishing medium. The performance of these advanced materials is compared with the state-of-the-technology materials in Figure 4 (obtained with 20 times accelerated space velocity than the commercial design). The results show that the capacity of these new materials for the difficult to remove organic sulfur, DMS in humid gas is at least five times higher than materials presently used. Biogas DFC Experiences The DFC power plants are currently produced in low volumes and as a result the capital costs tend to be higher than the conventional distributed generation technologies, due to its high efficiency and clean emissions, a variety of capital cost rebate programs are making the biofuel DFCs economical and competitive with natural gas IC engines and microturbines [2]. FCE has placed over twenty biogas units ranging from 250kW to 1.2MW around the world, achieving an electricity conversion efficiency of 45 to 49% (LHV) without accounting for power consumption by the biogas auxiliary clean-up process. Potential issues encountered for biogas applications primarily relate to steadiness of fuel gas supply. Advanced control systems were developed to allow the power plant to adjust load based on fuel availability, or to allow the transfer to a back-up fuel in the event of loss of the biogas. FCE s first sub-mw ADG plant encountered unique site fuel supply issues. The plant was operated on a relatively concentrated digester gas (~80% methane) produced from effluent from the brewery process. The brewery and the digester operated only during the weekdays, and as a result, on weekends the fuel supply would stop completely. The fuel cell required a fuel to stay in hot standby mode. A propane back-up system was introduced. When the digester gas supply was lost, the power plant automatically switched to hot standby mode using the propane fuel (operating on-load with propane would require too much fuel and too large a storage system). This off-load switch from digester gas to a back-up fuel was developed in response to project fuel supply logistics and later was extended to switching on-load in a MW-Class power plant. FCE encountered unpredictable digester gas supply variation at another sub-megawatt power plant operating on WWTP gas. The fuel supply at the site was not prone to complete interruption, but the volume of flow would occasionally drop below the level needed for full-load operation. When this occurred, the fuel pressure would become too low and the unit would trip off-line. Control techniques were developed which allowed automatic adjustment of the power plant load in the event of a drop in available fuel supply. This fuel following feature increased the availability of the power plant significantly, and this approach has now become a part of FCE s digester gas flow variation mitigation strategy portfolio. The first biogas MW-class DFC1500 power plant was operated by the King County Wastewater Treatment Plant in Renton, Washington. This project occurred early in the commercialisation effort, and allowed FCE to evaluate WWTP gas in DFC power plants. The plant produced 1 MW (net AC) from ADG. The facility also produced a scrubbed gas from raw digester gas removing sulfur, water, siloxanes, as well as most of the CO 2 diluents. This scrubbed gas was essentially ADG processed to pipeline natural gas quality, and the WWTP operator sold the gas to the local natural gas distributor. When Downloaded on to IP address. Redistribution subject to ECS 265 terms of use (see ecsdl.org/site/terms_use)

6 the gas did not meet pipeline gas specifications, it was returned to the system, and mixed with the fuel cell feed. Consequently the fuel cell supply gas experienced rapid increases in Btu content from 550 Btu/ft 3 up toward the 900 Btu/ft 3 scrubbed gas level. Since this event was preceded with some warning, a system was devised that allowed a controlled switch from the low Btu gas to the high Btu gas when the divert event was about to occur. The digester gas line was backed up by pipeline gas and the power plant was first switched to pipeline gas during the divert event and then seamlessly transferred to the high Btu scrubbed gas. Through a process of software logic development and actual experiments with the power plant, an automatic approach to switch from the primary fuel to a secondary fuel while on full load was achieved. This capability proved extremely useful later in applications where the fuel supply was not stable. In a subsequent early application, the Sierra Nevada Brewery installation consisted of four DFC300A power plants, as shown in Figure 5. The size of the installation was determined on the facility s base load power needs, not on biogas availability. The amount of digester gas available from the waste water digester at the site can support approximately 25% of the 1 MW total power generation capacity. A fuel blending feature was developed, which allows the power plants to use all of the available digester gas, and then blend in enough natural gas to make full power output. This fuel blending application is another example of a new product feature that helped to enhance the ability of the product in biogas applications with limited or varying fuel supply rates. This fuel blending approach with natural gas backup has become the standard feature for biogas DFC plants to assure fuel supply reliability. FCE experiences with these and other early power plants have identified an important point relating to digester gas availability. In real world applications, digester plant operators do not consider maintaining steady supply of ADG to be a high priority. To them it is a waste stream, which has little impact on their day-to-day operations. When the ADG supply is interrupted, which it sometimes can be due to maintenance activities or changes in sewage waste composition entering the plant, the fuel cell power plant needs to be able to respond. The solution to solve the fuel supply issue is to install a back-up natural gas fuel line, which is relied upon to keep the fuel cell in operation with natural gas blending when ADG supply is short or operate on natural gas when the ADG supply is interrupted. Figure 2, shown earlier, provides an example of automatic switchover from natural gas to digester gas, dual-fuel operation and back to natural gas based on digester gas availability while maintaining full power production. With each succeeding installation, FCE developed product enhancements to improve availability of the power plant. Smooth operation of biogas pretreatment for fuel cells (for removal of sulfur compounds and siloxanes discussed previously) is an important component of the system for reliable operation. Operation of the early units was affected by the reliability of the pretreatment skids, which are supplied by the end user or a distributor. This has improved over time as lessons-learned from early units were incorporated into design and maintenance of the newer systems. Cumulative power produced in a 300KW power plant which was started in September 2007 in the US is shown in Figure 6. Building on early project lessons and design improvements, FCE has executed several DFC300 and DFC1500 projects. Except for one older unit, all current bio-gas DFC plants have incorporated the natural gas back-up with blending option. FCE products are increasingly being used at waste water treatment facilities in California. The projects are Downloaded on to IP address. Redistribution subject to ECS 266 terms of use (see ecsdl.org/site/terms_use)

7 now tending to involve higher capacities: multiple submw units or MW-scale units for more favorable plant economics. In 2010, the DFC MW module output has been up-rated to 1.4MW from 1.2MW by upgrading the stack technology. FCE has sold its first 1.4MW bio-gas plant to UTS Bioenergy LLC who will sell the power generated to San Jose/Santa Clara Water Pollution Control Plant, CA under a 20-year power purchase agreement. FCE has also sold a DFC 3000 plant (2.8MW) to the same customer which will be installed at a waste water treatment plant operated by Inland Empire Utilities Agency in Chino, CA. FCE has 8 MW of power plants currently operating on renewable bio-gas and has another additional 12MW of power plants in production backlog with the majority of these renewable fuel power plants are located in California. The California SGIP (Self Generation Incentive Program) has facilitated the marketing of DFC power plants. The SGIP cap was raised from 1MW to 3MW. It provides capital cost rebates of 4,500$/kW for the first 1MW fuel cells operating on biogas vs. $2,500/kW for natural gas; decreasing to 50% of the first 1 MW credit for 1MW to 2MW portion, and decreasing to 25% for the 2 MW to 3MW portion for a 3MW plant. Further market penetration of this unique technology will be facilitated by the SGIP price incentive coupled with more favorable economics for the larger MW size plants. Conclusion FuelCell Energy has had considerable experience with biogas applications, which have become one of the most important market segments addressed by its DFC products. The product enhancements from the initial projects have result in the development of features which address the specific needs of the biogas market: operate efficiently at fullload despite the presence of the CO 2 diluents, adjust to the changing fuel composition and quantity, and operate with minimal emissions and minimal operator intervention. References 1. Soroushian, F., Shang, Y., Whitman, E., Garza, G., and Zhang, Z.; Development and Application of Biological H2S Scrubbers for Treatment of Digester Gas. Proceeding of WEFTEC 06, Leo, A. and Pais, C., Biogas Applications for Molten Carbonate Fuel Cells, Proceedings of the International Colloquium on Environmentally Preferred Advanced Power Generation, ICEEPAG Downloaded on to IP address. Redistribution subject to ECS 267 terms of use (see ecsdl.org/site/terms_use)

8 Figure 1. DFC performance comparison, ADG vs. natural gas (at different customer sites): On average ~4mV higher cell voltage is seen with the digester gas. ADG Flow NG Flow Net AC Output Stack Temperature Natural Gas Operation Anaerobic Digester Gas Operation Natural Gas Operation Figure 2. Thermal advantage, ADG vs. natural gas: The ADG DFC operates 17 C cooler to produce the same 290 kw output. Downloaded on to IP address. Redistribution subject to ECS 268 terms of use (see ecsdl.org/site/terms_use)

9 Digester H 2 S Removal Moisture Conditioning Siloxanes Removal Biogas Auxiliary Cleanup System 370 o C waste heat HRU De-Ox Pre-reforming Anode Cathode Treatment Oxidizer Air Water Natural Gas AC Power Figure 3. Schematic showing bio-gas adaptations to natural gas DFC: An auxiliary cleanup up system is needed to control sulfur and siloxane compounds A dvanced Materials Sulfur Capacity (wt%) Commercial materials Figure 4. DMS adsorption capacity comparisons of advanced materials with commercial materials: The advanced materials promise > five times more capacity for the DMS than the baseline compounds. Downloaded on to IP address. Redistribution subject to ECS 269 terms of use (see ecsdl.org/site/terms_use)

10 Figure 5. Four DFC300 power plants at Sierra Nevada Brewing Company: Fuel blending with natural gas backup developed for this plant has become a standard biogas DFC feature. Figure 6. Cumulative output of a DFC plant on ADG fuel: Stable fuel cell and system operation shown. Downloaded on to IP address. Redistribution subject to ECS 270 terms of use (see ecsdl.org/site/terms_use)