Quantifying Environmental Trade-offs Inherent in GHG

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Identifying/Quantifying Environmental Trade-offs Inherent in GHG Reduction Strategies for Coal-Fired Power Greg Schivley,*,† Wesley W. Ingwersen,‡ Joe Marriott,† Troy R. Hawkins,‡,∥ and Timothy J. Skone§ †

Booz Allen Hamilton, Pittsburgh, Pennsylvania 15220, United States National Risk Management Research Laboratory, Office of Research and Development, U.S. Environmental Protection Agency, Cincinnati, Ohio 45220, United States § National Energy Technology Laboratory, U.S. Department of Energy, Pittsburgh, Pennsylvania 15236, United States ‡

S Supporting Information *

ABSTRACT: Improvements to coal power plant technology and the cofired combustion of biomass promise direct greenhouse gas (GHG) reductions for existing coal-fired power plants. Questions remain as to what the reduction potentials are from a life cycle perspective and if it will result in unintended increases in impacts to air and water quality and human health. This study provides a unique analysis of the potential environmental impact reductions from upgrading existing subcritical pulverized coal power plants to increase their efficiency, improving environmental controls, cofiring biomass, and exporting steam for industrial use. The climate impacts are examined in both a traditional100 year GWPmethod and a time series analysis that accounts for emission and uptake timing over the life of the power plant. Compared to fleet average pulverized bed boilers (33% efficiency), we find that circulating fluidized bed boilers (39% efficiency) may provide GHG reductions of about 13% when using 100% coal and reductions of about 20−37% when cofiring with 30% biomass. Additional greenhouse gas reductions from combined heat and power are minimal if the steam coproduct displaces steam from an efficient natural gas boiler. These upgrades and cofiring biomass can also reduce other life cycle impacts, although there may be increased impacts to water quality (eutrophication) when using biomass from an intensely cultivated source. Climate change impacts are sensitive to the timing of emissions and carbon sequestration as well as the time horizon over which impacts are considered, particularly for long growth woody biomass.

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INTRODUCTION

prevented the technology from being commercially deployable.16 In this paper, we examine the potential for three different changes to existing coal-fired power plants to reduce climate impacts without the need for capturing and sequestering CO2 at the power plant. The first of these changes is an efficiency improvement, enabled by replacing a conventional subcritical pulverized coal boiler, which is the most commonly deployed technology in the U.S. coal fleet, with a state-of-the-art coal circulating fluidized bed (CFB) boiler.17,18 The second potential improvement diverts some of the produced energy, in the form of steam heat, for use in a nearby industrial application, commonly known as combined heat and power (CHP). This has the dual effect of making the combined operation more efficient, as more of the input fuel’s energy is being used in making a marketable product from a waste heat, and from an accounting standpoint, sharing the environmental burdens with the consumer of the steam. The third possible GHG reduction examined here introduces 30% biomass by

There is increasing regulatory pressure, and an environmental and social imperative, to reduce the greenhouse gas emissions (GHGs) from fossil fuel-based power generation in the United States and around the world. Commonly espoused solutions are a large scale switch to renewables or to a less GHGintensive fossil fuel such as natural gas.1−6 Other studies have investigated ways to reduce GHG emissions from coal-fired power through methods such as cofiring biomass.7−11 Recent work shows that reducing GHG emissions can also benefit air quality.12−14 This paper builds on previous studies and brings together traditional LCA impact assessment with an analysis of GHG timing. In regions of the U.S. where a large percentage of the electricity comes from coal-fired power generation − in 2012 West Virginia, Kentucky, and Wyoming produced 96%, 92%, and 88% of their power, respectively, from coal15 − alternatives need to be evaluated that can be achieved through modification of existing coal power infrastructure that is still within its service life. To continue utilizing coal power infrastructure and still reduce GHGs, carbon capture, and subsequent storage or utilization is a potential solution, but there are significant regulatory and economic barriers which, to this point, have © 2015 American Chemical Society

Received: Revised: Accepted: Published: 7562

March 4, 2015 May 15, 2015 May 22, 2015 May 22, 2015 DOI: 10.1021/acs.est.5b01118 Environ. Sci. Technol. 2015, 49, 7562−7570

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Figure 1. Scenario and System Description. Scenarios with CHP use system expansion and displacement of steam produced from a natural gas boiler for midpoint impact assessment results. For the time series results scenarios without CHP also include forcing from the steam production.

behind the life cycle approach is to also quantify other potential impacts in order to avoid a finding that would demonstrate a technology to be superior at the expense of potential impacts to other sources. Therefore, it is most informative when it is used to quantify as many of the relevant impacts as possible. The primary metric used to measure the GHG reduction when multiple GHGs are accounted for is to convert them into carbon dioxide (CO2) equivalents using Global Warming Potential (GWP).22 The effects of biogenic carbon uptake and release at different times in the cofiring life cycle are not captured well by traditional measures of climate impact like GWP.23,24 To more accurately compare global warming effects of fossil and biomass-fueled power scenarios it is necessary to use a time series method that accounts for uptake and emission timing. Many biomass sources have been proposed and evaluated for use in biopower in the United States, including short-rotation perennial herbaceous and woody crops, medium-to-long rotation forestry sources and forestry residues, as well as waste products such as storm debris and C&D waste.19,25−28 Therefore, when evaluating cofiring options from a life cycle perspective, it is important to consider a sufficient range of alternatives, as different sources may show life cycle environmental performance that varies across impact categories. Our goal in this study is to examine whether the aforementioned technology and fuel source improvements to coal power plants, either separately or combined, can reduce the climate impact of coal-fired power production below current U.S. coal fleet performance without incurring additional human health and environmental impacts. We evaluate these

energy into the fuel stream for use in a CFB plant. The use of biomass as a feedstock for electricity generation and heat production is attractive because it offers renewable energy derived from a domestically available feedstock and the potential for reductions in GHG emissions and other environmental impacts. Biomass has also been demonstrated by some to be used more efficiently as an energy source for power generation than for transportation fuel.19 Drivers for the adoption of biomass-based power and heat include renewable portfolio standards, renewable energy credits, proposed GHG regulation in the power sector, and compatibility with existing industrial processes and electricity infrastructure.20 Co-firing biomass with coal allows for flexibility in biomass feed levels based on feedstock prices and availability and offers the potential for the utilization of biomass in existing facilities with retrofits. Biomass cofired with coal is a bridge technology that offers a means of realizing the benefits of biomass utilization in the near-term while technologies offering more dramatic CO2 emissions mitigation potential in conjunction with coal utilization such as carbon capture and sequestration are being refined. Combining biomass-coal cofiring with the utilization of CHP has the potential to provide additional benefits associated with offsetting other means of steam production. In order to ensure that reductions at the point of power generation are not offset by increases at other places in the life cycle, we evaluate scenarios for upgrading coal power plants and biomass cofire using life cycle assessment (LCA). LCA is a framework based in a systems approach for evaluating and comparing technologies over their full life cycle.21 Although LCA models may be used to evaluate just GHGs, the theory 7563

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(a 33% increase in total energy output), the CHP plants require 16% more fuel input. The CFB technology is able to cofire 10− 30% biomass (by energy) with coal, in contrast with the pulverized coal plants, which usually burn a maximum of 10% biomass.8 In all cofiring scenarios, we assume that biomass is cofired at 30% energy content. We modeled cofiring both with and without CHP for two feedstocks: hybrid poplar (HP) from the Midwestern U.S. and forest residue (FR) representative of the U.S. national average. Data. The feedstocks considered for power generation are coal and biomass. Data sets for coal mining, coal transport, and power plants are based on existing NETL models. Data on the biomass feedstocks come from NETL data and other public sources. Additional information on feedstock processes is included in the Supporting Information. All coal is transported 400 miles by rail from the coal mine to power plant, and the empty train makes the return trip to the coal mine for a total round trip distance of 800 miles. Unit processes for rail transport and construction were developed by NETL. Biomass is transported 21 miles by truck. In contrast to coal transport, the smaller scale of biomass harvesting operations and the logistics of biomass transport prevent long haul transport distances of biomass feedstocks.31 A loss rate of 7% is used for the transmission and distribution of electricity. This step is also responsible for the emissions of sulfur hexafluoride (SF6), which is used as an electrical insulator in high voltage equipment.32 No efficiency losses are modeled for steam transportation to an adjacent industrial facility. The steam coproduct from CHP is exported to an adjacent industrial facility that would otherwise have used an on-site natural gas boiler. Data on steam production is based on emission factors from the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) model with fuel inputs developed by NETL.32−34 Nitrous oxide (N2O) emissions are a small source of GHG emissions from PC boilers, but they may be much more significant from CFB facilities.35 The emissions levels are difficult to predict and depend on a number of variables such as feedstock characteristics, temperature, and excess oxygen.35−37 The U.S. Environmental Protection Agency (EPA) publishes an N2O emission factor for coal-fired CFB boilers, but it is based on a single 8 MW facility and does not account for variability in emissions due to design or coal type, or emission reductions seen elsewhere when cofiring biomass.35,36,38,39 Life Cycle Impact Assessment and Cumulative Radiative Forcing Time Series Analysis. Climate and nonclimate impacts are calculated using a subset of TRACI 2.1 impact factors, 100-year GWP factors with climate-carbon feedbacks from IPCC 2013, and nonrenewable cumulative energy demand.40,22,41 Four midpoint impact categories were selected from TRACI 2.1: acidification, eutrophication, human health particulates, and photochemical oxidant (smog) formation. These impact categories are largely driven by criteria air pollutants, particularly SOX, NOX, and PM2.5, which are all emissions that are closely tracked in the power sector. Human and Eco-toxicity categories from TRACI 2.1 are not included due to limited inventories of toxic releases for these power plant combustion scenarios. An important feature of GHG emissions associated with the use of biomass for energy is the difference in time between CO2 uptake and release. This phenomenon has been referred to as carbon debt and is not well represented in conventional methods of accounting for climate impacts in life cycle

options by constructing a number of scenarios to identify combinations of technologies and fuel sources that are likely to lead with greater certainty to GHG emission reductions. We also seek to identify options where there are potential environmental trade-offs that need to be managed and minimized or avoided.

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MATERIALS AND METHODS LCA is a tool for quantifying potential environmental and human health impacts from all operations associated with a product or service.21 The collection of processes representing the life cycle of a product and all associated support activities (e.g., mining, transportation, waste treatment) is known as a product system.29 An inventory of all resources from and releases to the environment for every process in the product system is calculated based on the production or delivery of a functional unit. Using a functional unit allows different systems to be compared on an equivalent basis. In this study we use a functional unit of 1 MWh of electricity delivered to a customer in the U.S. The analysis is conducted without respect to a particular geographic location of the power plant, and assuming access to a steady source of local biomass as well as coal. The scope of the study is “cradle-to-point-of-use” and includes all activities associated with the extraction and or growth of the feedstocks and other raw materials for electricity production, the refining and transport of those materials to the power plant, the operation of the power plant, and distribution of electricity to the point of use, as well as background activities supporting any of the inputs to these life cycle stages. Since our evaluation includes CHP scenarios where a steam coproduct is generated, we model this using the principles of system expansion and displacement,29 where the steam produced is assumed to substitute for intermediate-pressure industrial steam. In these cases, the plant produces 1200 MJ of steam in addition to the 1 MWh of electricity. A diagram of the systems modeled is presented in Figure 1. A modified functional unit of both electricity and steam is used for time series GHG calculations. In the process of system expansion and displacement emissions from natural gas combustion are subtracted from the emissions of the CFB with CHP. This subtraction is an accounting mechanism that maintains the functional unit as a single product (electricity). Emissions from all processes in the dual functional unit are included in the time series calculations. Modeling Scenarios. A number of power generation scenarios are modeled in order to estimate the effectiveness of the coal power technologies and cofiring of various biomass sources in reducing life cycle GHG emissions, while also comparing their impacts in terms of air and water quality, human health, and total energy demand. Figure 1 summarizes these scenarios. The baseline scenario consists of a fleet average coal power plant, without combined heat and power and using only coal as a combustion fuel. The coal is assumed to be a national average of bituminous and subbituminous coal for all scenarios. Data from eGRID are used to model the current fleet average coal technology.30 A state of the art CFB technology with new source performance standards compliant emission controls is used to model all other scenarios, first assuming no cogeneration of steam and 100% coal to compare against the fleet average. CHP is also modeled with the CFB technology. We assume that CHP provides 1200 MJ of medium-pressure steam for industrial use per MWh. To generate 1 MWh of electricity in addition to 1200 MJ of steam 7564

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Figure 2. Summary of timing of sequestration and GHG emissions. Sequestration and emissions occur throughout the time periods indicated by the solid bar. For “Infrastructure, coal mine” all emissions are assumed to occur in one year (−10).

assessment studies.24,42 A number of studies have shown the importance of accounting for emission and uptake timing.24,43,44 A time series calculation of cumulative radiative forcing can be especially useful for biomass with long growth periods, where uptake and re-emission to the atmosphere are separated by several decades. We address the sensitivity of growth time by modeling long-growth (LG) biomass that has a 60 year growth cycle. IPCC GWP factors are widely used to evaluate climate impacts from GHG emissions, and factors from the 2013 IPCC report are used here.22 We also use direct calculation of cumulative radiative forcing (CRF) to more accurately assess the temporal effects associated with the biomass CO2 uptake and GHG emissions. Impulse response functions (IRFs) and the radiative efficiency (RE) of GHGs from IPCC’s 2013 report and Supporting Information are used to calculate the atmospheric mass and radiative forcing (RF) of GHGs over time based on the emission and uptake profiles of each scenario.22 This method uses a convolution of the IRF and the emission function to calculate the RF: RF(t ) = RE

∫0

Stromman and Hertwich24 and Guest, Cherubini and Stromman.45 Life Cycle Assessment and Greenhouse Gas Time Series Modeling. All original unit processes were developed in standardized NETL unit process templates and are available online.47 A time-series model built in Microsoft Excel is used to calculate annual forcing and cumulative radiative forcing (CRF) for all of the scenarios. This model is included in the Supporting Information. Some calculations are performed analytically using equations from Alvarez et al. and other calculations are performed numerically.3 We model CRF to compare differences in temporal effects of uptake and emissions of power generation based on purely fossil sources versus hybrid poplar. The LG biomass with 60 year growth cycles is used to test the sensitivity of growth time and the difference in modeling uptake before and after combustion. Forest residue is not included in the time series model because of the uncertainty regarding the age of biomass collected. We do not displace steam production after system expansion in the time series model because there is no physical method in the system to subtract or remove the methane emissions from natural gas. Instead the emissions associated from independent natural gas-based steam production are added to the total emissions for the non-CHP scenarios. We model emissions beginning with the planting of LG biomass, through a 30 year assumed lifetime of the power plant, and then for 200 years following the start of operation. Figure 2 summarizes when sequestration and emissions activities by type and process are assumed to occur. Direct emissions from production of the electricity are modeled to occur from year 0 to 30. Ancillary process (feedstock acquisition and transportation) for coal and biomass options are assumed to occur throughout power generation. Uptake of CO2 for LG biomass planted before combustion begin 60 years prior to power plant use; those for HP begin 5 years prior to combustion, and continue through operation. For HP, direct and indirect land use change emissions occur through year 75, 80 years following the initial planting.48 Additional documentation is provided in the SI.

t

g (t ′)y(t − t ′)dt ′

(1)

where g(t′) is the emission function, y(t′) is the IRF for each GHG, and RE is its radiative efficiency. CRF is calculated by integrating eq 1 over time: CRF(t ) =

∫0

t

RF(t )dt

(2)

The role of biomass carbon uptake on atmospheric CO2 concentrations requires careful treatment due to secondary effects that are sometimes overlooked.45 As biomass grows it removes CO2 from the atmosphere. The lower atmospheric concentration of CO2 leads to less absorption by oceans (or reduced ocean off-gassing), which partially offsets the biomass uptake. These effects of atmospheric CO2 removal have also been reported by Cao and Caldeira46 We account for them using methods described by Cherubini, Peters, Berntsen, 7565

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Figure 3. Life cycle impact assessment results relative to fleet average coal. The Gross and Net results for CHP with displacement are offset slightly to the right of the stacked bar for each case. The difference between the gross and net values is equal to the potentially displaced impact from natural gas. Each of the net results represents the expected value and is bounded by high and low expected results. The GWP results are based on the application of 100-year GWPs, not the time-series method, and do not include N2O emissions from the CFB plants.

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RESULTS Life Cycle Impact Assessment Results. Life cycle environmental impacts for the power scenarios are shown in Figure 3. The expected range of results for fleet coal varies widely for acidification, eutrophication, and smog impacts. This variation is driven by the wide range of SOX and NOX control technologies employed by existing baseload coal power plants. The use of CFB, CHP, and cofiring biomass in coal power plants are able to reduce GHG emissions below the level of fleet coal, although it is possible that high N2O emissions from the CFB may negate the GHG reductions seen through the increase in efficiency. These technologies can also reduce the other environmental and human health impacts considered in nearly all scenarios considered. The reductions can be significant. Upgrading the combustion platform to CFB reduces nonrenewable energy use by 12% and leads to significant (56− 85%) decreases in eutrophication, acidification, human health particulate and smog impacts. Co-firing biomass with coal in a CFB plant may decreases the GWP by up to 20−37%, depending on the N2O emission level. If N2O emissions from a CFB with cofired biomass are half of EPA’s published factor then GHG reductions are 11−27%. Nonrenewable energy use is reduced by 32−35% from the fleet coal averages. The GWP of systems with cofired biomass is lower because biomass is credited for the uptake of CO2, which is then released back to the atmosphere during combustion. Any time difference between uptake and combustion is neglected in GWP. The effects of GHG timing are explored further below. Compared to CFB with coal only, cofiring can have mixed results on other impacts due to potential upstream effects associated with biomass acquisition. Co-firing FR with coal shows the greatest potential nontime dependent GHG reductions and may further reduce impacts by 9% and 6% for human health particulates and acidification when compared to coal CFB (smog impacts are nearly unchanged). But cofiring HP could increase impacts in acidification and smog formation by 30% and 20% when compared to coal CFB, and nearly double eutrophication impacts. Overall, the difference in

improvement for acidification and particulate impacts between cofiring and 100% coal in a CFB plant is much smaller than the overall reductions seen compared to fleet coal. The uncertainties in impact reductions are high for cofiring HP due to variability in yields and potential land conversions. It is possible that hybrid poplar with low long-term average yields can increase life cycle GHG emissions compared to only using coal. The expected yield of HP is 6,214 kg/acre-yr; at around 3750 kg/acre-yr the GHG emissions of cofired HP are the same as coal. This is a result of both the land use change (LUC) emissions and the direct emissions from fuel consumption being allocated over a smaller amount of harvested biomass. The impact of LUC on GHG emissions can be seen in the difference between HP and the other biomass scenarios. Each of the non-CHP biomass scenarios uptake just under 300 kg of CO2 per MWh, and LUC emissions (direct and indirect) in this location are 110 kg CO2. This value will vary based on the location of the HP production. It may double in parts of the southeastern U.S., quadruple in the northeast, or drop by more than half in other regions of the country. If combined heat and power is used to further improve the efficiency of a CFB power plant, this leads to a slight increase in GHG emissions when burning coal or cofiring with HP, and a slight reduction with FR. The nonclimate impacts are almost always reduced by CHP. The results for displacement depend on the relative impact of the displaced fuel and the CHP system life cycles. Displacing steam from natural gas has the potential to lower smog, eutrophication and acidification impacts for all feedstock mixes because the natural gas boiler can have higher NOX emissions rates. For cofired HP and FR, the biomass component of the cofire system has higher non-GHG life cycle impacts than both the coal component and the displaced natural gas. This increases the overall impact per unit of energy produced and decreases the benefit of the CHP system. In impact categories such as acidification, eutrophication, human health particulates, and smog formation, displacing 30% of the low-impact natural gasthe fraction of biomass cofiredwith higher-impact biomass feedstocks decreases the benefit of CHP. 7566

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Figure 4. Cumulative Radiative Forcing over time for production of 1 MWh and 1200 MJ steam per year. Fleet coal uses a natural gas boiler for steam generation. All CFB scenarios are shown with thick lines for CHP and thin lines for steam production from a natural gas boiler. LG biomass is modeled with a 60 year growth cycle before and after combustion.

that cofired hybrid poplar with CHP has higher CRF than fleet coal until year 14 of electricity generation. While the relative difference in impact during these first years is large−up to an order of magnitude higher before electricity production begins−the absolute difference is very small. The impact of both systems increases by 3 orders of magnitude within the next 100 years. Results for production of power and steam are similar for both CHP and electricity with natural gas steam. The increase in efficiency with CHP is not enough to counter the higher CO2 emission factor of coal-only CFB, which has higher impacts over the whole time period. CHP always results in lower impacts for cofired LG biomass when growth is modeled as taking place before harvesting. Interestingly, cofired HP and LG biomass with regrowth after harvesting both start with higher impacts for CHP but transition to lower impacts over time. The transition happens in year 24 for HP and year 68 for LG biomass with regrowth. Although the difference in these results is very small this crossover is not something that GWP could predict.

Upgrading control equipment when installing a CFB boiler to meet current regulations allows for reductions of 82−87% for acidification, 78−80% for particulate, and 56−64% for smog impacts. Impacts in these three categories are primarily from PM, SOX, and NOX emitted at the power plant. Reducing direct emissions of these pollutants from power production is the most effective way to decrease life cycle impacts of acidification, particulate, and smog categories. Time Series GHG Emissions. Cumulative radiative forcing results for the production of 1 MWh and 1200 MJ for each of the scenarios are shown in Figure 4. All systems are shown producing both power and steam−either through CHP or with an external natural gas boiler−to allow for better comparability of the climate effects over time. Emissions from the coal-only systems almost all take place in the year of electricity production. CO2 uptake from biomass growth in the hybrid poplar cofire system takes place relatively close in time to the biomass combustion, but land use change emissions take place over a time period that extends beyond the service life of the facility. LG biomass uptake can be modeled as taking place before or after combustion, changing the time boundaries of the system. Accounting for carbon uptake before biomass combustion extends the time frame of the study backward and reduces the CRF when compared to uptake that is accounted for in replanted biomass. The reduction is due to the large amount of time during which uptake occurs with no emissions. Because the CRF is a cumulative result, this long period of negative forcing has a large impact on the result, which may not be the case with a different metric such as temperature change. Moving from fleet coal to both a more efficient power plant, and cofiring biomass in that more efficient power plant, reduces CRF at 100 years but not over all time periods. Hybrid poplar emissions from land preparation and cultivation start before electricity generation begins. These emissions are large enough

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DISCUSSION This study provides a unique analysis of the potential environmental impact reductions from upgrading existing subcritical pulverized coal power plants to increase their efficiency, improve environmental controls, allow for cofiring biomass, and export steam for industrial use. Upgrading existing coal-fired power plants and accounting for the effect of GHG emission and uptake timing are both new contributions to the LCA literature in this area. Our results show that the three possible changes to current coal-fired power plants (upgrade to CFB with the potential to cofire biomass and add CHP) all have the potential to reduce climate impacts, measured both as GWP and CRF. Higher N2O emissions from the CFB may offset much of the reduction in CO2 seen through increased 7567

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overshadowed by the cycle of sequestration, harvest, combustion and replanting, which improves their performance relative to a 100% fossil feedstock scenario. And in this study we found that for long-growth period feedstocks, timing of growth can change the rank order of results in time horizons of up to 100 years. The strategies to reduce climate impacts that are considered here also tend to reduce other human health and environmental impacts. The largest portion of these reductions comes from upgrading the pollution control equipment to meet new source performance standards when the boiler is upgraded to CFB. These reductions in NOX, SOX, and PM lead to lower acidification, eutrophication, smog, and particulate impacts. The efficiency gains from a CFB provide some benefit, but not at the same scale as improving control equipment. Co-firing cultivated biomass tends to increase impact categories other than climate change and nonrenewable energy use because of the impacts from cultivation and acquisition, but not enough to overcome the improvement gained from state-of-the-art emissions control equipment. Improvements to efficiency of the U.S. coal power fleet and the use of low-impact biomass as a cofire fuel can help lower climate impacts while still making use of existing coal infrastructure.

boiler efficiency, but more research into the exact emissions from each scenario is necessary. The efficiency gain from switching to a CFB design reduces fuel inputs to the boiler, which results in a proportional reduction of power plant and upstream GHG emissions. Adding 30% biomass by energy to the CFB further reduces net GHG emissions to the atmosphere. While the growth of cultivated hybrid poplar may result in slightly higher CRF than fleet coal for 14 years at the start of electricity generation, it has lower CRF for all subsequent time periods. Cultivated, residual, and long-growth biomass types each have different GHG profiles but all result in lower climate impacts than the coal that they replace. The only exception is when cultivated hybrid poplar has lower than expected yields. For the fuel mixes that we consider, the use of CHP does not provide a significant improvement in climate impacts over a power plant that only produces electricity. The steam from CHP must be considered in the context of what it will displace or substitute for. We assume that intermediate pressure steam will be used in place of steam from a natural gas boiler. The lower GHG profile of natural gas is almost completely offset by the increased efficiency from CHP. As a result, CHP only provides a small improvement in climate impacts. Although direct comparisons with findings from other LCA studies should not be performed without further harmonization of results49 or conducting the LCA studies in accordance with a common standard or set of rules,50 our findings for reductions in GHG reductions associated with cofiring biomass with coal generally match the trends from the literature.9,10,25,26,28 Here we found a 22−38% decreases in GWP when increased N2O emission are not included, and an even greater reduction in some of the nonclimate impact categories. However, the timing effects of GHG emissions and the time horizon considered for the analysis are generally not considered in LCA studies. Cofiring biomass with coal shows greater reduction potential when uptake and emission timing is considered (a 30−44% decrease in CRF at 100 years) than when all uptake and emissions are assumed to occur at the same time as combustion, which is the general assumption in LCA studies. But this result only holds when biomass carbon uptake occurs prior to combustion. If uptake is modeled after combustion, as in the case of LG biomass replanted after combustion, the opposite result could hold true−global warming reductions might be less pronounced than results obtained using GWPs. The model developed here to examine the cumulative radiative forcing effects (akin to global warming potential) over time for the power generation scenarios is presented as an alternative to other proposed methodologies that also acknowledge the influence of emission timing on the climate. Whereas some of these methods produce static indicators,24,43 our method shows annual effects over a 100+ year time horizon, which shows differences in outcomes depending on the time horizon of interest, as has been found elsewhere.6,51,52 Our related finding was that a short-term woody biomass feedstock (HP) showed increased radiative forcing over the 100% coal combustion scenarios in the short term due to land use change and agricultural activities, but reduction in radiative forcing in the long term due to uptake. Others have reported similar findings of early emissions due to land use change as demonstrating more severe global warming impacts using time-dependent methods,53 but a unique contribution here is in modeling those impacts over the full life of a power plant, through which these land use change emissions become

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ASSOCIATED CONTENT

S Supporting Information *

The code for numerical calculations, excel file with time series GHG calculations and results, and additional information on unit process data are provided. The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.5b01118.

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AUTHOR INFORMATION

Corresponding Author

*Phone: 412-386-5818; e-mail: [email protected]. Present Address ∥

(T.R.H.) Enviance, Inc., Carlsbad, California 92008, United States Author Contributions

The manuscript was written through contributions of all authors. All authors have given approval to the final version of the manuscript. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS We thank Chris Sherry, Greg Cooney, Matt Jamieson, James Littlefield, Francesco Cherubini, Rebecca Dodder, Carlos Nunez, and Michael Gonzalez for their assistance and insight. Research support provided by the Air, Climate, and Energy Research Program of the U.S. Environmental Protection Agency, Office of Research and Development. This work was performed as a collaboration between EPA NRML and DOE NETL staff with support from Booz Allen Hamilton under DOE NETL Contract Number DE-FE0004001.

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REFERENCES

(1) Ingwersen, W. W.; Garmestani, A. S.; Gonzalez, M. A.; Templeton, J. J. A systems perspective on responses to climate change. Clean Technol. Environ. Policy 2014, 16 (4), 719−730 DOI: 10.1007/s10098-012-0577-z.

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Policy Analysis

Environmental Science & Technology

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DOI: 10.1021/acs.est.5b01118 Environ. Sci. Technol. 2015, 49, 7562−7570

Policy Analysis

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DOI: 10.1021/acs.est.5b01118 Environ. Sci. Technol. 2015, 49, 7562−7570