Energy System and Thermoeconomic Analysis of Combined Heat and Power Fuel Cell Systems

The United States (U.S.) Department of Energy (DOE)’s Pacific Northwest National Laboratory (PNNL) is spearheading a program with industry to deploy and independently monitor five kilowatt-electric (kWe) combined heat and power (CHP) fuel cell systems (FCSs) in light commercial buildings. This publication discusses results from PNNL’s research efforts to independently evaluate manufacturer-stated engineering, economic, and environmental performance of these CHP FCSs at installation sites. The analysis was done by developing parameters for economic comparison of CHP installations. Key thermodynamic terms are first defined, followed by an economic analysis using both a standard accounting approach and a management accounting approach. Key economic and environmental performance parameters are evaluated, including (1) the average per unit cost of the CHP FCSs per unit of power, (2) the average per unit cost of the CHP FCSs per unit of energy, (3) the change in greenhouse gas (GHG) and air pollution emissions with a switch from conventional power plants and furnaces to CHP FCSs; (4) the change in GHG mitigation costs from the switch; and (5) the change in human health costs related to air pollution. CHP FCS heat utilization is expected to be less than 100% at several installation sites. Specifically at six of the installation sites, during periods of minimum building heat demand (i.e. summer season), the average in-use CHP FCS heat recovery efficiency based on the higher heating value of natural gas is expected to be only 24.4%. From the power perspective, the average per unit cost of electrical power is estimated to span a range from $15–19,000/kilowatt-electric (kWe) (depending on site-specific changes in installation, fuel, and other costs), while the average per unit cost of electrical and heat recovery power varies between $7,000 and $9,000/kW. From the energy perspective, the average per unit cost of electrical energy ranges from $0.38 to $0.46/kilowatt-hour-electric (kWhe), while the average per unit cost per unit of electrical and heat recovery energy varies from $0.18 to $0.23/kWh. These values are calculated from engineering and economic performance data provided by the manufacturer (not independently measured data). The GHG emissions were estimated to decrease by one-third by shifting from a conventional energy system to a CHP FCS system. The GHG mitigation costs were also proportional to the changes in the GHG gas emissions. Human health costs were estimated to decrease significantly with a switch from a conventional system to a CHP FCS system. A unique contribution of this paper, reported for the first time here, is the derivation of the per unit cost of power and energy for a CHP device from both standard and management accounting perspectives. These expressions are shown in Eq. (21) and Eq. (31) for power, and in Eq. (24) and Eq. (34) for energy. This derivation shows that the average per unit cost of power is equal to the average per unit cost of electric power applying a management accounting approach to this latter calculation. This term is also equal to the average per unit cost of heat recovery power applying a management accounting approach. A similar set of relations hold for the average per unit cost of energy. These derivations underscore the value of using Eq. (21) for economic analyses to represent the average per unit cost of electrical power, heat recovery power, or both, and using and Eq. (24) for energy.

The United States Department of Energy’s Pacific Northwest National Laboratory is teaming with industry to deploy and independently monitor 5-kilowatt-electric (kWe) combined heat and power (CHP) fuel cell systems (FCSs) in light commercial buildings. Results of an independent evaluation of manufacturer-stated engineering, economic, and environmental performance of these CHP FCSs are presented here. An important contribution of this paper is the precise definition and development of these essential terms for quantifying distributed CHP generator energy use within buildings: (1) electricity and heat utilization, (2) electrical and heat recovery efficiencies, (3) in-use electrical and heat recovery efficiencies, (4) percentage usage of electricity, and (5) percent usage of recoverable heat. Key additional parameters evaluated include the average cost of the CHP FCSs per unit of power and per unit of energy, the change in greenhouse gas (GHG) and air pollution emissions with a switch from conventional power plants and furnaces to CHP FCSs, the change in GHG mitigation costs from the switch, and the change in human health costs from air pollution. CHP FCS heat utilization is expected to be under 100% at several installation sites; for six sites, during periods of minimum heating demand, the in-use CHP FCS heat recovery (HR) efficiency based on the higher heating value of natural gas is expected to be only 24.4%. From the power perspective, the average per-unit cost (PUC) of electrical power is estimated to span $15–19,000/kWe (depending on site-specific installation, fuel, and other costs), while the average PUC of electrical and HR power is $7,000–9,000/kW. Regarding energy, the average PUC of electrical energy is $0.38–$0.46/kilowatt-hour-electric, while the average PUC of electrical and HR energy is $0.18–$0.23/kWh. GHG emissions were estimated to decrease by one-third after replacing a conventional system with a CHP FCS. GHG mitigation costs were also proportional to changes in GHG emissions. Estimated human health costs from air pollution emissions decreased by a factor of 1000 with changing to CHP FCS. Reported for the first time here is the derivation of the PUCs of power and energy for a CHP device from both standard and management accounting (MA) perspectives. Results show that the average PUC of combined electrical and HR power is equal to the average PUC of electric power applying an MA approach, and also equal to the average PUC of HR power applying an MA approach. Similar relations hold for the average PUC of energy. Results presented here demonstrate the value of using the equations herein for economic analyses of CHP systems to represent the average PUC of electrical power, HR power, or both, and for energy.

The widespread use of combined heat and power (CHP) distributed generation (DG) for buildings could significantly increase energy efficiency and reduce greenhouse gas and air pollution emissions. By displacing both electricity from conventional centralized power plants and heat from decentralized boilers, CHP DG could reduce primary feedstock fuel consumption in the U.S. by approximately 20%, or 6,000 terawatt hours. However, optimally integrating CHP DG within buildings is challenging. This work aims to elucidate optimal system sizing and design of micro-CHP fuel cell systems (FCSs) integrated with commercial buildings. This modeling effort compares and contrasts the performance of high temperature polymer electrolyte membrane (PEM) fuel cell systems (HTPEM FCSs) and solid oxide fuel cell (SOFC) systems for commercial buildings. A parallel research effort is independently analyzing measured data from HTPEM FCSs installed in commercial buildings. Measured data from that effort is integrated into this modeling work. In certain regions, there has been a research and development and commercialization trend moving from using low temperature PEM FCSs (e.g. with a stack temperature of around 80°C) to using HTPEM FCSs (e.g. with a stack temperature of around 160°C) and to using SOFC systems (e.g. with a stack temperature of around 700°C) for CHP building applications, given the higher temperature of the available waste heat from these systems. In this work FCS performance data is coupled with building energy system models from the U.S. Department of Energy (DOE) using EnergyPlus™ whole-building energy simulation software. Using these baseline reference commercial building model data, parameters are examined including heat demand for space heating and for domestic hot water heating over time, temperatures and water flow rates associated with this heat demand, and building electrical demand over time, to evaluate FCS integration within the building. Examining the data obtained through the simulation exercise in this work, it is found that in a large office building, with heat demand temperatures in the range of 82°C for space heating and 60°C for hot water heating, an HTPEM FCS with an exhaust temperature of 47°C can potentially access, at a maximum, 19% of the total building heating demand. By contrast, in a small office building, with heat demand temperatures in the range of 23°C (supply air temperature) for space heating and 60°C for hot water heating, it is found that this HTPEM FCS can potentially access, at a maximum, 90% of the total building heating demand. Examining the temporal characteristics of the building heat demand to determine FCS sizing, it is found that a maximum of 50% of the time, the heat demand can be served with an HTPEM FCS with a thermal capacity of 8 kilowatts (kW) (0.05 kW for small office) and an electrical capacity of approximately 4.5 kilowatts-electric (kWe) (0.45 kWe for small office). A maximum of 80% of the time, the heat demand can be served with an HTPEM FCS with a thermal capacity of 85 kW (0.16 kW for small office) and an electrical capacity of approximately 73 kWe (0.14 kWe for small office). The simulation results further indicate that an SOFC has advantages over an HTPEM FCS that originate from its higher exhaust temperature (between 25°C and 315°C), which allows it to meet a greater percentage of the building heating demand (up to 100%). This enables an SOFC to serve a larger percentage of the building stock and a wider variety of building heating systems. Furthermore, if the CHP FCSs are grid independent (i.e., it is not possible to supply electrical power back to the grid), then the heat-to-power ratio of an FCS can be an important parameter. In such a scenario, the heat-to-power ratio of an SOFC (approximately 0.33) is closer to the heat-to-power ratio of a building (approximately 0.081, averaged over an entire year). In a stand-alone configuration, when the CHP DG has a heat-to-power ratio that more closely matches that of the buildings, the utilization of the DG system is likely to be higher and its economics and environmental impacts more favorable.

The Maximizing Emission Reductions and Economic Savings Simulator (MERESS) is an optimization tool that allows users to evaluate avant-garde strategies for installing and operating combined heat and power (CHP) fuel cell systems (FCSs) in buildings. This article discusses the deployment of MERESS to show illustrative results for a California campus town, and, based on these results, makes recommendations for further installations of FCSs to reduce greenhouse gas (GHG) emissions. MERESS is used to evaluate one of the most challenging FCS types to use for GHG reductions, the Phosphoric Acid Fuel Cell (PAFC) system. These PAFC FCSs are tested against a base case of a CHP combined cycle gas turbine (CCGT). Model results show that three competing goals (GHG emission reductions, cost savings to building owners, and FCS manufacturer sales revenue) are best achieved with different strategies, but that all three goals can be met reasonably with a single approach. According to MERESS, relative to a base case of only a CHP CCGT providing heat and electricity with no FCSs, the town achieves the highest 1) GHG emission reductions, 2) cost savings to building owners, and 3) FCS manufacturer sales revenue each with three different operating strategies, under a scenario of full incentives and a $100/tonne carbon dioxide (CO2) tax (Scenario D). The town achieves its maximum CO2 emission reduction, 37% relative to the base case, with operating Strategy V: stand alone operation (SA), no load following (NLF), and a fixed heat-to-power ratio (FHP) [SA, NLF, FHP] (Scenario E). The town’s building owners gain the highest cost savings, 25%, with Strategy I: electrically and thermally networked (NW), electricity power load following (ELF), and a variable heat-to-power ratio (VHP) [NW, ELF, VHP] (Scenario D). FCS manufacturers generally have the highest sales revenue with Strategy III: NW, NLF, with a fixed heat-to-power ratio (FHP) [NW, NLF, FHP] (Scenarios B, C, and D). Strategies III and V are partly consistent with the way that FCS manufacturers design their systems today, primarily as NLF with a FHP. By contrast, Strategy I is avant-garde for the fuel cell industry, in particular, in its use of a VHP and thermal networking. Model results further demonstrate that FCS installations can be economical for building owners without any carbon tax or government incentives. Without any carbon tax or state and federal incentives (Scenario A), Strategy I is marginally economical, with 3% energy cost savings, but with a 29% reduction in CO2 emissions. Strategy I is the most economical strategy for building owners in all scenarios (Scenarios A, B, C, and D) and, at the same time, reasonably achieves other goals of large GHG emission reductions and high FCS manufacturer sales revenue. Although no particular building type stands out as consistently achieving the highest emission reductions and cost savings (Scenarios B-2 and E-2), certain building load curves are clear winners. For example, buildings with load curves similar to Stanford’s Mudd Chemistry building (a wet laboratory) achieve maximal cost savings (1.5% with full federal and state incentives but no carbon tax) and maximal CO2 emission reductions (32%) (Scenarios B-2 and E-2). Finally, based on these results, this work makes recommendations for reducing GHG further through FCS deployment. (Part I of II articles discusses the motivation and key assumptions behind the MERESS model development (Colella 2008).)

Stationary combined heat and power (CHP) fuel cell systems (FCSs) can provide electricity and heat for buildings, and can reduce greenhouse gas (GHG) emissions significantly if they are configured with an appropriate installation and operating strategy. The Maximizing Emission Reductions and Economic Savings Simulator (MERESS) is an optimization tool that was developed to allow users to evaluate avant-garde strategies for installing and operating CHP FCSs in buildings. These strategies include networking, load following, and the use of variable heat-to-power ratios, all of which commercial industry has typically overlooked. A primary goal of the MERESS model is to use relatively inexpensive simulation studies to identify more financially and environmentally effective ways to design and install FCSs. It incorporates the pivotal choices that FCS manufacturers, building owners, emission regulators, competing generators, and policy makers make, and empowers them to evaluate the effect of their choices directly. MERESS directly evaluates trade-offs among three key goals: GHG reductions, energy cost savings for building owners, and high sales revenue for FCS manufacturers. MERESS allows users to evaluate these design trade-offs and to identify the optimal control strategies and building load curves for installation based on either 1) maximum GHG emission reductions or 2) maximum cost savings to building owners. Part I of II articles discusses the motivation and key assumptions behind MERESS model development. Part II of II articles discusses run results from MERESS for a California town and makes recommendations for further FCS installments (Colella 2008 (a)).

This research explores the thermodynamics, economics, and environmental impacts of innovative, stationary, polygenerative fuel cell systems (FCSs). Each main report section is split into four subsections. The first subsection, 'Potential Greenhouse Gas (GHG) Impact of Stationary FCSs,' quantifies the degree to which GHG emissions can be reduced at a U.S. regional level with the implementation of different FCS designs. The second subsection, 'Optimizing the Design of Combined Heat and Power (CHP) FCSs,' discusses energy network optimization models that evaluate novel strategies for operating CHP FCSs so as to minimize (1) electricity and heating costs for building owners and (2) emissions of the primary GHG - carbon dioxide (CO{sub 2}). The third subsection, 'Optimizing the Design of Combined Cooling, Heating, and Electric Power (CCHP) FCSs,' is similar to the second subsection but is expanded to include capturing FCS heat with absorptive cooling cycles to produce cooling energy. The fourth subsection, - Thermodynamic and Chemical Engineering Models of CCHP FCSs,' discusses the physics and thermodynamic limits of CCHP FCSs.

Assessing the economic efficiency of bioenergy technologies in climate mitigation and fossil fuel replacement in Austria using a techno-economic approach

The maximizing emission reductions and economic savings simulator (MERESS) is an optimization tool that evaluates novel strategies for installing and operating combined heat and power (CHP) fuel cell systems (FCSs) in buildings. This article discusses the deployment of MERESS to show illustrative results for a California campus town and, based on these results, makes recommendations for further installations of FCSs to reduce greenhouse gas (GHG) emissions. MERESS is used to evaluate one of the most challenging FCS types to use for GHG reductions, the phosphoric acid fuel cell (PAFC) system. These PAFC systems are tested against a base case of a CHP combined cycle gas turbine (CCGT). Model results show that three competing goals (GHG emission reductions, cost savings to building owners, and FCS manufacturer sales revenue) are best achieved with different strategies but that all three goals can be met reasonably with a single approach. According to MERESS, relative to a base case of only a CHP CCGT providing heat and electricity with no FCSs, the town achieves the highest (1) GHG emission reductions, (2) cost savings to building owners, and (3) FCS manufacturer sales revenue each with three different operating strategies, under a scenario of full incentives and a $100/tonne carbon dioxide (CO2) tax (scenario D). The town achieves its maximum CO2 emission reduction, 37% relative to the base case with operating strategy V: stand-alone (SA) operation, no load following (NLF), and a fixed heat-to-power ratio (FHP) (SA, NLF, and FHP; scenario E). The town’s building owners gain the highest cost savings, 25% with strategy I: electrically and thermally networked (NW), electricity power load following (ELF), and a variable heat-to-power ratio (VHP) (NW, ELF, and VHP; scenario D). FCS manufacturers generally have the highest sales revenue with strategy III: NW, NLF with a FHP (NW, NLF, and FHP; scenarios B, C, and D). Strategies III and V are partly consistent with the way that FCS manufacturers design their systems today, primarily as NLF with a FHP. By contrast, strategy I is novel for the fuel cell industry, in particular, in its use of a VHP and thermal networking. Model results further demonstrate that FCS installations can be economical for building owners without any carbon tax or government incentives. Without any carbon tax or state and federal incentives (scenario A), strategy I is marginally economical with 3% energy cost savings but with a 29% reduction in CO2 emissions. Strategy I is the most economical strategy for building owners in all scenarios (scenarios A–D) and, at the same time, reasonably achieves other goals of large GHG emission reductions and high FCS manufacturer sales revenue. Although no particular building type stands out as consistently achieving the highest emission reductions and cost savings (scenarios B-2 and E-2), certain building load curves are clear winners. For example, buildings with load curves similar to Stanford’s Mudd chemistry building (a wet laboratory) achieve maximal cost savings (1.5% with full federal and state incentives but no carbon tax) and maximal CO2 emission reductions (32%) (scenarios B-2 and E-2). Finally, based on these results, this work makes recommendations for reducing GHG further through FCS deployment. (Part I of II articles discusses the motivation and key assumptions behind the MERESS model development.)

Stationary combined heat and power (CHP) fuel cell systems (FCSs) can provide electricity and heat for buildings and can reduce greenhouse gas (GHG) emissions significantly if they are configured with an appropriate installation and operating strategy. The maximizing emission reduction and economic saving simulator (MERESS) is an optimization tool that was developed to evaluate novel strategies for installing and operating CHP FCSs in buildings. These novel strategies include networking, load following, and the use of variable heat-to-power ratios, all of which industry typically has not implemented. A primary goal of models like MERESS is to use relatively inexpensive simulation studies to identify more financially and environmentally effective ways to design and install FCSs. Models like MERESS can incorporate the pivotal choices that FCS manufacturers, building owners, emission regulators, competing generators, and policy makers make, and empower them to evaluate the effect of their choices directly. MERESS directly evaluates trade-offs among three key goals: GHG reductions, energy cost savings for building owners, and high sales revenue for FCS manufacturers. MERESS allows one to evaluate these design trade-offs and to identify the optimal control strategies and building load curves for installation based on either (1) maximum GHG emission reductions or (2) maximum cost savings to building owners. Part I discusses the motivation and key assumptions behind MERESS model development. Part II discusses run results from MERESS for a California town and makes recommendations for further FCS installments (Colella , 2011, “Optimizing the Design and Deployment of Stationary Combined Heat and Power Fuel Cell Systems for Minimum Costs and Emissions—Part II: Model Results,” ASME J. Fuel Cell Sci. Technol., 8(2), p. 021002).

Energy network optimization (ENO) models identify new strategies for designing, installing, and controlling stationary combined heat and power (CHP) fuel cell systems (FCSs) with the goals of 1) minimizing electricity and heating costs for building owners and 2) reducing emissions of the primary greenhouse gas (GHG) — carbon dioxide (CO2). A goal of this work is to employ relatively inexpensive simulation studies to discover more financially and environmentally effective approaches for installing CHP FCSs. ENO models quantify the impact of different choices made by power generation operators, FCS manufacturers, building owners, and governments with respect to two primary goals — energy cost savings for building owners and CO2 emission reductions. These types of models are crucial for identifying cost and CO2 optima for particular installations. Optimal strategies change with varying economic and environmental conditions, FCS performance, the characteristics of building demand for electricity and heat, and many other factors. ENO models evaluate both “business-as-usual” and novel FCS operating strategies. For the scenarios examined here, relative to a base case of no FCSs installed, model results indicate that novel strategies could reduce building energy costs by 25% and CO2 emissions by 80%. Part I of II articles discusses model assumptions and methodology. Part II of II articles illustrates model results for a university campus town and generalizes these results for diverse communities.

The life cycle based greenhouse gas (GHG) balances of Fatty Acid Methyl Esters (FAME also called "Biodiesel") from various resources have been set in the Renewable Energy Directive (RED). Due to technology and scientific progress there are various options to improve the GHG balances of FAME. In this Supporting Action 10 most interesting options were assessed: 1) "Biomethanol": Substitution of fossil methanol with biomethanol; 2) "Bioethanol": Substitution of fossil methanol with bioethanol; 3) "CHP residues": Use of residues and co-products in an CHP plant; 4) "New plant species": Examination of new plants for vegetable oils, that could increase the biomass weight without any detrimental effect on the oil seed; 5) "Bioplastics and biochemicals": Production of bioplastics and biochemicals from process residues; 6) "Advanced agriculture": Advanced agricultural practices in terms of N2O emissions and soil carbon accumulation; 7) "Organic residues": Use of organic versus mineral fertilizer for feedstock cultivation; 8) "FAME as fuel": Use of FAME in machinery for cultivation, transportation and distribution; 9) "Retrofitting multi feedstock": Retrofitting of single feedstock plants for blending fatty residues; and 10) "Green electricity": Use of renewable electricity produced in a PV plant on site. The assessment approach started with the GHG standard values of the RED and the corresponding background data documented in BioGrace. For the most relevant FAME production possibilities in Europe, characterized by the feedstock (rapeseed, sunflower, palm oil, soybean, used cooking oil, animal fat) and FAME production capacity (50 - 200 kt/a), the technical and economic data of "Best Available Technology in 2015" (BAT) were used as starting point to assess the improvement options. Based on the calculation of GHG emissions (g CO2-eq/MJ) and production cost (€/tFAME) an overall assessment (incl SWOT-Analyses and Stakeholder involvement) of the options was made and summarized in "Fact Sheets". A significant GHG reduction compared to the RED values in processing is possible, if best available technology (BAT) is applied. The GHG emissions of cultivation compared to RED are higher due to improved data on the correlation between fertilizer input and yields. The assessed GHG improvements options show that the potential to reduce emissions is relatively large in agriculture cultivation, but a relatively low in processing. The production cost analysis shows that revenues from co-produced animal feed and oil yield per hectare have a strong influence on total production costs, e.g. mainly animal feed from soybeans. The total FAME production cost of BAT are 280 – 1,000 €/tFAME, including revenues from co-products. Cost ranges arise due to different feedstock and capacities. The greenhouse gas analysis of the improvement options results in a GHG reduction potential of 0 - 37 g CO2-eq/MJ compared to BAT. The greenhouse gas mitigation costs of improvement options range between -260 and +1,000 €/t CO2-eq. Options with negative greenhouse gas mitigation costs generate economic benefits compared to the base case. Summing up the assessment one can conclude that the future FAME production has several options to further improve its GHG balance thus contributing substantially to a more sustainable transportation sector.

Urban water cycle systems(UWCS), including water treatment facilities, distribution facilities, sewers, and wastewater treatment facilities, are energy intensive and significant source of greenhouse gas (GHG) emissions, making the reduction of GHG emissions and the transition to eco-friendly energy essential. This study identifies specific GHG emission sources at each stage of the UWCS and proposes detailed methods to achieve a 40% reduction in GHG emissions, implement RE100, and attain Net Zero by employing insets and offsets. This study develops scenarios for insets and offsets based on the baseline process of the UWCS, and investigates potential pathways to reduce GHG emissions by quantifying emissions from each process. Internal insets, which are self-implemented and technical measures, are prioritized, while external offsets are applied to compensate for the remaining emissions. Internal insets include the application of anaerobic digesters and combined heat and power(CHP), improvements in energy efficiency of equipment, reduction in water pipe leakage, implementation of water footprint labeling, and installation of on-site photovoltaic system. External offsets comprise renewable energy certificates(REC), power purchase agreements(PPA), green hydrogen fuel for vehicles, natural sequestration improvement, and emission trading system. GHG emissions at each stage within the UWCS are quantified using modeling software. Based on these results, the effectiveness of insets and offsets in achieving a 40% GHG emissions reduction, Net Zero, and RE100 goal is analyzed. The baseline total GHG emissions for the UWCS are estimated at 4,732.8 tCO2eq/yr, of which 56.8% is identified as targets for internal insets, and the remaining 43.2% is reduced through external offsets. A 40% GHG reduction can be achieved through internal insets, and Net Zero can be attained by incorporating additionally applying external offsets. The total power demand of UWCS facilities and equipment is calculated as 572.8 kW. Renewable energy is generated through anaerobic digesters and CHP(116.1kW) as well as on-site PV(395.0 kW), while RE100 compliance is achieved by securing an aditional 61.7 kW through REC/PPA. Achieving Net Zero and RE100 requires prioritizing strategies for insets, offsets and efficient resource allocation. For this, the technical feasibility and self-implementation potential of reduction efforts and the external conditions for offsets, should be carefully reviewed to optimize implementation strategies. GHG reduction and renewable energy utilization in the UWCS are key priorities for addressing the climate crisis and achieving sustainable water resource management, requiring technological innovation and institutional support. The comprehensive and systematic application of GHG insets and offsets is the optimal approach to achieving these goals. Furthermore, modeling software serves as a key tool for quantifying GHG emissions and formulating concrete, viable GHG reduction strategies. In addition to the technical and institutional approaches proposed in this study, achieving Net Zero and implementing RE100 requires the integrated consideration of economic factors in the future.

A life-cycle assessment (LCA) of corn ethanol was conducted to determine the reduction in the life-cycle greenhouse gas (GHG) emissions of corn ethanol compared to gasoline by integrating biomass fuels in a 190 million liter (50 million gallon) per year dry-grind corn ethanol plant to replace fossil fuels (natural gas and grid electricity). The biomass fuels studied are corn stover and ethanol co-products [dried distillers grains with solubles (DDGS), and syrup (solubles portion of DDGS)]. The biomass conversion technologies/systems considered are process heat (PH) only systems, combined heat and power (CHP) systems, and biomass integrated gasification combined cycle (BIGCC) systems. The key inventory components of the LCA are corn production, stover production, ethanol production, fertilizer inputs, truck transport, co-product credits, ethanol transport to blending, biomass fuel conversion systems, and combustion of anhydrous ethanol (E100). The life-cycle GHG emission reduction for corn ethanol compared to gasoline (97.7 g CO2e/MJ gasoline) is 42.5% for PH with natural gas, 61.3% for PH with corn stover, 82.2% for CHP with corn stover, 81.6% for IGCC with natural gas, 127.7% for BIGCC with corn stover, and 119.1% for BIGCC with syrup and stover. These GHG emission estimates do not include indirect land use change effects. GHG emission reductions for CHP, IGCC, and BIGCC include power sent to the grid which replaces electricity from coal. BIGCC results in greater reductions in GHG emissions than IGCC with natural gas because biomass is substituted for fossil fuels. In addition, underground sequestration of CO2 gas from the ethanol plant’s fermentation tank could further reduce the life-cycle GHG emission of corn ethanol by 31.5% compared to gasoline.

As awareness of the possible implications of greenhouse gas (GHG)emissions and the merits of energy efficiency increase, so do the numberof facilities, institutions, and people that seek an active role in reducingtheir net GHG emissions and energy usage. With the increase in projectsdeveloped to achieve a targeted GHG reduction, it is becoming increas-ingly important to quantify CHP system performance in terms of GHGemissions. This work presents a preliminary method for evaluating thenet GHG emissions of a combined heat and power (CHP) system as ameans of evaluating the feasibility of installing a CHP system in a carbondioxide reduction project

The purpose of this study is to compare the effect of a reduction in greenhouse gas (GHG) emissions between the combined heat and power (CHP) plant and boiler, which became the main energy-generating facilities of “anaerobic digestion” (AD) biogas produced in Korea, and analyze the GHG emissions in a life cycle. Full-scale data from two Korean “wastewater treatment plants” (WWTPs), which operated boilers and CHP plants fueled by biogas, were used in order to estimate the reduction potential of GHG emissions based on a “life cycle assessment” (LCA) approach. The GHG emissions of biogas energy facilities were divided into pre-manufacturing stages, production stages, pretreatment stages, and combustion stages, and the GHG emissions by stages were calculated by dividing them into Scope1, Scope2, and Scope3. Based on the calculated reduction intensity, a comparison of GHG reduction effects was made by assuming a scenario in which the amount of biogas produced at domestic sewage treatment plants used for boiler heating is replaced by a CHP plant. Four different scenarios for utilizing biogas are considered based on the GHG emission potential of each utilization plant. The biggest reduction was in the scenario of using all of the biogas in CHP plants and heating the anaerobic digester through district heating. GHG emissions in a life cycle were slightly higher in boilers than in CHP plants because GHG emissions generated by pre-treatment facilities were smaller than other emissions, and lower Scope2 emissions in CHP plants were due to their own use of electricity produced. It was confirmed that the CHP plant using biogas is superior to the boiler in terms of GHG reduction in a life cycle.