An algebraic targeting approach for effective utilization of biomass in combined heat and power systems through process integration

The fuel-cycle energy use and greenhouse gas (GHG) emissions associated with the application of fuel cells to combined heat and power (CHP) generation and combined heat, hydrogen, and power (CHHP) generation are evaluated and compared with the combustion technologies of internal combustion engines and microturbines, as well as with the various technologies associated with hydrogen production and grid-electricity generation in the United States. Two types of fuel cells are considered in this analysis: a phosphoric acid fuel cell (PAFC) capable of following either heat or electric load and a molten carbonate fuel cell (MCFC) that typically follows the electric load. Three types of facilities (hospital, large office building, and warehouse) are examined in two different climatic regions (Chicago and Los Angeles) to span a wide range of electric-to-heat load ratios. Two different approaches for fuel cycle analysis of CHP and CHHP applications are considered in this analysis: a total demand approach and a displacement approach. The total demand approach provides an accurate assessment of the impact of actual demand on total energy use and GHG emissions, while the displacement approach projects the potential for more energy savings and GHG emissions benefits relative to the supply of electricity from the grid generation mix. The fuel cycle results are primarily impacted by the efficiencies of hydrogen production and electric power generation, as well as by the utility factor of the co-produced heat. The energy use and GHG emissions associated with the electric power generation represent the majority of the fuel-cycle’s total energy use and emissions for all pathways. More energy and GHG emissions benefits are realized from fuel cell technologies with increased use of available coproduced heat. In general, CHHP systems exhibit more energy and GHG emission benefits than CHP systems for any of the investigated fuel cell technologies.

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.

Examination of the optimal operation of building scale combined heat and power systems under disparate climate and GHG emissions rates

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 (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.

CCS Feasibility Improvement in Industrial and Municipal Applications by Heat Utilisation

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.

Assessing the climate impact of district heating systems with combined heat and power production and industrial excess heat

What is the role of distributed energy resources under scenarios of greenhouse gas reductions? A specific focus on combined heat and power systems in the industrial and commercial sectors

As awareness of the possible implications of greenhouse gas (GHG) emissions and the merits of energy efficiency increase, so do the number of facilities, institutions, and people that seek an active role in reducing their net GHG emissions and energy usage. With the increase in projects developed to achieve a targeted GHG reduction, it is becoming increasingly important to quantify CHP system performance in terms of GHG emissions. This work presents a preliminary method for evaluating the net GHG emissions of a combined heat and power (CHP) system as a means of evaluating the feasibility of installing a CHP system in a carbon dioxide reduction project.

MW cogenerated proton exchange membrane fuel cell combined heat and power system design for eco-neighborhoods in North China

BackgroundThe availability of feedstock options is a key to meeting the volumetric requirement of 136.3 billion liters of renewable fuels per year beginning in 2022, as required in the US 2007 Energy Independence and Security Act. Life-cycle greenhouse gas (GHG) emissions of sorghum-based ethanol need to be assessed for sorghum to play a role in meeting that requirement.ResultsMultiple sorghum-based ethanol production pathways show diverse well-to-wheels (WTW) energy use and GHG emissions due to differences in energy use and fertilizer use intensity associated with sorghum growth and differences in the ethanol conversion processes. All sorghum-based ethanol pathways can achieve significant fossil energy savings. Relative to GHG emissions from conventional gasoline, grain sorghum-based ethanol can reduce WTW GHG emissions by 35% or 23%, respectively, when wet or dried distillers grains with solubles (DGS) is the co-product and fossil natural gas (FNG) is consumed as the process fuel. The reduction increased to 56% or 55%, respectively, for wet or dried DGS co-production when renewable natural gas (RNG) from anaerobic digestion of animal waste is used as the process fuel. These results do not include land-use change (LUC) GHG emissions, which we take as negligible. If LUC GHG emissions for grain sorghum ethanol as estimated by the US Environmental Protection Agency (EPA) are included (26 g CO2e/MJ), these reductions when wet DGS is co-produced decrease to 7% or 29% when FNG or RNG is used as the process fuel. Sweet sorghum-based ethanol can reduce GHG emissions by 71% or 72% without or with use of co-produced vinasse as farm fertilizer, respectively, in ethanol plants using only sugar juice to produce ethanol. If both sugar and cellulosic bagasse were used in the future for ethanol production, an ethanol plant with a combined heat and power (CHP) system that supplies all process energy can achieve a GHG emission reduction of 70% or 72%, respectively, without or with vinasse fertigation. Forage sorghum-based ethanol can achieve a 49% WTW GHG emission reduction when ethanol plants meet process energy demands with CHP. In the case of forage sorghum and an integrated sweet sorghum pathway, the use of a portion of feedstock to fuel CHP systems significantly reduces fossil fuel consumption and GHG emissions.ConclusionsThis study provides new insight into life-cycle energy use and GHG emissions of multiple sorghum-based ethanol production pathways in the US. Our results show that adding sorghum feedstocks to the existing options for ethanol production could help in meeting the requirements for volumes of renewable, advanced and cellulosic bioethanol production in the US required by the EPA’s Renewable Fuel Standard program.

In the last 20 years, emerging technologies such as fuel cells and microturbines have contributed to growth in the market for combined heat and power (CHP) in small-scale (5–5,000 kW) applications. Numerous studies utilizing performance assumptions have explored the theoretical potential for distributed CHP to save energy and reduce greenhouse gas (GHG) emissions, however actual performance may differ from expectations. Incentive programs in several states are beginning to yield information about actual (as opposed to potential) performance of small-scale CHP. This paper leverages over ten years of metered data from more than 500 different projects rebated by one such program: California’s Self Generation Incentive Program (SGIP). The population of projects includes established technologies (internal combustion engines, gas turbines) as well as emerging technologies. Performance measures examined include efficiencies, utilization, and GHG emissions impacts. A variety of Federal and State policies seek to increase the amount of small-scale distributed CHP in the coming years. It is imperative that knowledge about actual performance gleaned from metered data collected during the past decade be shared widely so that CHP’s potential to reduce energy consumption and GHG emissions is actually realized in the future.

Allocation of GHG emissions in combined heat and power systems: a new proposal for considering inefficiencies of the system

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).)