Role of Lignin in Reducing Life-Cycle Carbon Emissions, Water Use

Jul 2, 2014 - (17) Coal combustion is the single largest contributor to the United States' CO2e emissions, so exporting lignin (a biogenic source of c...
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Role of Lignin in Reducing Life-Cycle Carbon Emissions, Water Use, and Cost for United States Cellulosic Biofuels Corinne D. Scown,*,† Amit A. Gokhale,‡ Paul A. Willems,‡ Arpad Horvath,§ and Thomas E. McKone† †

Environmental Energy Technologies Division, Lawrence Berkeley National Laboratory, Berkeley, California 94720, United States BP Corporation North America Inc., 2151 Berkeley Way, Berkeley, 94704, United States § Department of Civil and Environmental Engineering, University of California, 215 McLaughlin Hall, Berkeley, California 94720, United States ‡

S Supporting Information *

ABSTRACT: Cellulosic ethanol can achieve estimated greenhouse gas (GHG) emission reductions greater than 80% relative to gasoline, largely as a result of the combustion of lignin for process heat and electricity in biorefineries. Most studies assume lignin is combusted onsite, but exporting lignin to be cofired at coal power plants has the potential to substantially reduce biorefinery capital costs. We assess the life-cycle GHG emissions, water use, and capital costs associated with four representative biorefinery test cases. Each case is evaluated in the context of a U.S. national scenario in which corn stover, wheat straw, and Miscanthus are converted to 1.4 EJ (60 billion liters) of ethanol annually. Life-cycle GHG emissions range from 4.7 to 61 g CO2e/MJ of ethanol (compared with ∼95 g CO2e/MJ of gasoline), depending on biorefinery configurations and marginal electricity sources. Exporting lignin can achieve GHG emission reductions comparable to onsite combustion in some cases, reduce life-cycle water consumption by up to 40%, and reduce combined heat and power-related capital costs by up to 63%. However, nearly 50% of current U.S. coal-fired power generating capacity is expected to be retired by 2050, which will limit the capacity for lignin cofiring and may double transportation distances between biorefineries and coal power plants.

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footprint.1 Given lignin’s substantial contribution to the energy and climate impacts of biofuel production, it is critical to understand the trade-offs associated with different lignin utilization options. Although onsite combustion of lignin provides net energy and climate benefits, it is also a substantial contributor to biorefinery capital costs. The boiler/turbogenerator make up ∼30% of the total installed equipment costs in a biorefinery that produces 230 million liters of ethanol per year.5 A comparable natural gas-fired combined heat and power (CHP) system could meet the biorefinery’s heat needs and increase net electricity exports at a fraction of the lignin-fired system’s capital cost. Gas-fired power generation can also reduce the

INTRODUCTION Cellulosic biofuels have the potential to lower the carbon intensity of automotive transportation, in large part because of the utilization of lignin for heat and power.1−3 Although other components of herbaceous and woody biomass can be broken down into sugars and subsequently converted to a range of liquid fuels, the aromatic polymers that comprise lignin are more difficult to break down into high-value chemicals and fuels.4 In the absence of more profitable uses for lignin, most biochemical biorefinery models assume lignin is combusted onsite to meet the plant’s process heat and power needs, with excess electricity exported to the grid.2,5−7 Onsite combustion of lignin allows cellulosic biorefineries to avoid direct reliance on fossil fuels and offset some electricity generated by other, potentially fossil fuel-reliant power plants. The grid electricity offset credits alone can reduce the life-cycle greenhouse gas (GHG) footprint of cellulosic ethanol by up to 20 g CO2e/MJ ethanol, in some cases resulting in a net negative GHG © 2014 American Chemical Society

Received: Revised: Accepted: Published: 8446

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Figure 1. Major energy and mass flows for each of the lignin utilization options assessed. (1) Base case: onsite combustion of lignin and biogas in solids boiler; (2) onsite combustion of lignin and biogas in solids boiler, additional natural gas-fired power generation; (3) offsite export of lignin, biogas, and natural gas-fired heat and power generation; and (4) offsite export of lignin, biogas, and natural gas-fired heat and power generation.

itself: softwoods contain 25−35% lignin by mass, hardwoods contain 18−25%, and herbaceous biomass contains 14−19%.10 These fractions will also vary within a single plant species because lignin production is linked to stresses such as wounding, pathogen infection, or metabolic stress.9 On average, wheat straw contains 17%, corn stover contains 18%, and Miscanthus contains 25%.11,12 If traumatic events such as extreme cold, heat, or drought become more common as a result of climate change, these averages may increase. The primary challenge in deriving value from lignin lies in selectively breaking lignin’s C−O bonds to produce smaller aromatic compounds suitable for blending in gasoline.13 Some progress has been made in the conversion of lignin to high-value chemicals and fuels, but so far, combustion for heat and power remains the only commercially viable use.4,13−15 During cellulosic ethanol production, lignin is typically separated postfermentation, compressed into cakes, dried, and sent to the combuster alongside biogas from the wastewater treatment unit, where power is generated and waste heat is recovered for use elsewhere in the biorefinery.5 Although this strategy allows the biorefinery to avoid purchasing electricity or fossil fuels for the most part, combusting lignin onsite requires a solids boiler, which is more expensive than its gas counterpart.16 Owners hoping to lower capital costs are likely to consider installing a gas-fired CHP unit, supplementing the biogas generated onsite with purchased natural gas. If the purchase of a solids boiler is avoided, lignin must be sent offsite. Lignin can be cofired alongside a variety of solid fuels, although there are practical limits on its share of total fuel input before costly modifications are required.17 Coal combustion is the single largest contributor to the United States’ CO2e emissions, so exporting lignin (a biogenic source of carbon) to be cofired with coal presents an opportunity to offset a fraction of coal demand while reducing GHG and criteria air pollutant emissions.18 Switching to either a simplecycle gas turbine or combined-cycle system at the biorefinery also has the potential to reduce onsite cooling water needs.

biorefinery’s water footprint. However, selecting a gas-fired CHP system necessitates off-site export of lignin, thus requiring pelletization and additional freight transportation. Potential offsite uses of lignin include cofiring with coal at existing power plants and application as a soil organic carbon (SOC) amendment.8 In this paper, we focus only on the option of cofiring lignin at coal-fired power plants. Despite lignin’s substantial impact on the cost and environmental impacts of producing cellulosic biofuels, existing literature lacks a comprehensive assessment of the utilization options available and their implications for GHG emissions and water use at a large scale. To better understand these alternatives from a capital cost, GHG, and water perspective, we complete a life-cycle assessment (LCA) of four lignin utilization options: (1) onsite combustion for heat and power; (2) onsite combustion for heat and power with additional gasfired power generation; (3) export to coal-fired power plants, biogas/natural gas used to meet biorefinery heat requirements and a fraction of electricity demand; (4) export to coal-fired power plants, biogas/natural gas used to meet all biorefinery heat and power requirements. Details for each of these options are outlined in the Biorefinery Test Cases section. We first simulate the choices available to a single representative biorefinery using Aspen Plus, subsequently scaling the analysis up to a multibiorefinery national scenario. Our national analysis is based on a U.S. cellulosic biofuel production scenario in which corn stover, wheat straw, and Miscanthus × giganteus are converted to 1.4 EJ (60 billion liters) of ethanol annually, although the results are applicable to any biofuel production process with similar energy needs that cannot break down lignin.1

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BACKGROUND AND MOTIVATION Lignin is a heterogeneous mix of aromatic polymers that are rigid and impervious, serving to protect cell wall polysaccharides from degradation.9 The lignin content of biomass varies across feedstock categories, as does the makeup of the lignin 8447

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cofired alongside coal in existing power plants. Case 4 also assumes lignin is exported and increases natural gas imports relative to case 3 such that all biorefinery heat and power requirements are met with the onsite CHP system. Because cases 3 and 4 cofire lignin with coal, the resulting ash cannot be applied as fertilizer, and thus, a small amount of supplemental fertilizer is required. The base case biorefinery model we consider, case 1, was developed in the chemical engineering software Aspen Plus at NREL and documented by Humbird et al.5 This biorefinery processes 104 Mg of wet biomass per hour and produces 28 kL of ethanol per hour. Biomass is deconstructed using dilute acid pretreatment, followed by enzymatic hydrolysis; glucose and xylose derived from cellulose and hemicellulose are fermented to ethanol, and lignin is separated out for combustion to produce heat and power. The solids sent to the boiler enter with an average moisture content of 44% and are combusted alongside the biogas from the wastewater treatment unit to produce steam with an efficiency of 80%, consistent with the NREL model.5 Through the use of lignin and biogas, the biorefinery meets its 28 MW power demand and exports 13 MW of power to the grid. Our process model indicates that the biogas produced onsite in the NREL model is nearly sufficient to meet the biorefinery’s process heat needs, which is confirmed by Pourhashem et al.8 Although burning biogas for heat, exporting lignin to coal-fired power plants, and importing 100% of the biorefinery’s power needs is the lowest capital-cost option available (see Table 1),

However, the U.S. coal-fired power plant inventory is aging, and many plants are expected to be retired in the next four decades.19 This raises the question of how much cofiring capacity will be available through 2050 and whether the remaining coal-fired power plants will be sufficiently close to likely biorefinery locations. Although the importance of lignin utilization for heat and power has been highlighted in previous literature,1,2,8 only Pourhashem et al.8 have compared a series of options on the basis of cost and environmental metrics. Pourhashem et al.8 evaluated the cost and GHG trade-offs between returning lignin to the fields as an SOC amendment, drying and selling lignin as a coal substitute, and combusting lignin onsite to produce heat and electricity. They conducted their analyses for three sample sites in Iowa, Maryland, and North Carolina and did not include cases in which biorefineries generate electricity using biogas and natural gas. Our objective is to evaluate a set of likely cellulosic biorefinery configurations on the basis of expectations for capital and operating costs. Each lignin utilization strategy described here results in different costs, GHG emissions, mixes of primary energy consumed, and water use. To our knowledge, no other publication has evaluated lignin utilization options at the scale of a national cellulosic biofuel production scenario, nor has any publication explored the life-cycle water use trade-offs.

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MATERIALS AND METHODS We use an LCA approach to evaluate the GHG, water use, and net energy production impacts of competing options for the utilization of lignin produced by cellulosic ethanol facilities.3 Our approach is grounded in the basic concept of consequential LCA, meaning that our analysis is meant to quantify the net system-wide change in water use and GHG emissions resulting from increased biofuel production. Consistent with this approach, we use system expansion where possible in lieu of coproduct allocation methods, such as energy content-based or mass-based allocation. We do not quantify indirect/market effects. For example, we assume that demand for primary fuels and electricity remains constant, so an increase in a biorefinery’s net power exports must be met with an equivalent decrease in power generation elsewhere on the grid. We also do not model indirect land use change, which can be highly uncertain.20 Biorefinery Test Cases. Figure 1 shows the differences in major mass and energy flows between the four lignin utilization options. Case 1 serves as the base case and is largely identical to the most recent National Renewable Energy Laboratory (NREL) corn stover-to-ethanol model.5 We adjusted the inputs to the NREL model to account for the slight differences in the ratios of cellulose, hemicellulose, and lignin as well as moisture content between corn stover, wheat straw, and Miscanthus, resulting in minor differences in ethanol yield and electricity generation. Case 2 consists of a solids boiler similar to case 1 with an additional simple-cycle gas turbine operated using biogas and imported natural gas. Case 2 allows for more efficient capture of energy from the biogas and serves to represent biorefineries with very high electricity exports. Both cases 1 and 2 allow for lignin ash to be collected and returned to crops as supplemental fertilizer; we assume cofiring lignin with coal makes this practice infeasible because of the harmful contaminants present in coal ash. Case 3 eliminates the solids boiler entirely, using a combination of biogas and imported natural gas to serve the biorefinery’s heat needs, as well as more than half of its electric power needs. Lignin is exported to be

Table 1. Biorefinery Heat and Power Options Evaluated

case

natural gas import (GJ/h)

effective gas power (MW)

effective steam power (MW)

net power export (MW)

Δ turbogenerator CAPEX (% change)

1 2 3a 3b 4

0 550 65 65 300

0 65 45 45 70

45 45 0 1 6

13 50 −10 −9 0

+36 −63 −63 −54

we expect that biorefinery owners are likely to favor some onsite power generation given the favorable price outlook for natural gas and the efficiencies achieved by CHP systems. Cases 2−4 convert the same quantity of biomass as case 1, but vary in their treatment of lignin and energy sources. Table 1 provides an overview of the natural gas needs, turbine sizes, net power exports, and capital costs associated with each biorefinery case. Capital expenditures (CAPEX) are listed only for the CHP section of the biorefinery, which makes up ∼30% of total biorefinery CAPEX in case 1.5 These cases were simulated by creating a separate Aspen model for alternative CHP systems capable of meeting the biorefinery high- and low-pressure steam needs as determined in the original Aspen model. Using the electric power requirements determined in the biorefinery process model, we also calculated the net power input/output for the entire system. Case 2 represents a system in which the solids boiler and steam turbine from case 1 remain operational, but imported natural gas is used to operate an additional 65 MW gas turbine, resulting in a net power output of 50 MW. This case effectively colocates a simple-cycle gas-fired power plant with the original biorefinery with the goal of nearly quadrupling net power exports. Case 2 will be considered economically attractive if 8448

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Figure 2. U.S. national cellulosic biofuels scenario, including biomass production by county, simulated biorefinery locations, and optimal rail paths for feedstocks.

sufficient for a small gas turbine.21 If only imported natural gas is used in the gas turbine, a compressor is required just for intake air. The biogas collected from the wastewater treatment unit, however, is supplied at 1 atm and must be compressed to 20 atm. In addition, methane in biogas is diluted with water, CO2, oxygen, and nitrogen; methane comprises only 25% of the total 22 Mg/h of biogas delivered to the combustor. This dilution means that ∼75% of the energy used to compress biogas is compressing nonfuel components. Biogas compression currently requires 3 MW. CO2 separation technologies could eventually reduce this need to 60% reductions in GHG emissions relative to gasoline (which is estimated by Farrell et al.36 to be 95 g CO2e/MJ). Case 2 using the NGCC grid electricity mix reduces GHG emissions relative to gasoline by only 36%. This is because case 2 uses a simplecycle natural gas-fired generator, which is only 20−30% efficient, as compared with up to 50% efficiencies achieved by new NGCC plants. However, because case 2 maximizes net power exports, it achieves the second-smallest GHG footprint if power exports are likely to offset coal. Case 4, although it achieves a substantial 54% reduction of CHP CAPEX and reduces net grid imports to zero, is not favorable from a GHG standpoint, regardless of the grid mix. The error bars in Figure 4 highlight the fact that many variables remain highly uncertain until the feedstock production and cellulosic biorefining industry further develops. N2O emissions are highly variable and depend on fertilizer application rates as well as soil type and climate. Coal-fired power plant efficiency can vary substantially, as well: previous analyses indicate that plant efficiency varies by approximately 20% of the national mean. More details regarding the sensitivity analysis are provided in the SI.37 Life-Cycle Water Use. Life-cycle water use includes direct water demand, process and cooling water used to manufacture inputs and generate electricity, and water for extraction and

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DISCUSSION Through a detailed comparison of different lignin utilization options for cellulosic ethanol production, we have evaluated the capital cost, GHG emissions, and water use trade-offs between likely cellulosic biorefinery configurations in the United States. The analysis highlights the substantial differences in capital cost between the installation of a solids boiler and steam turbine to utilize lignin onsite and the use of biogas combined with imported natural gas for heat and electricity. Blend wall concerns for ethanol combined with regulatory uncertainties surrounding biofuels may motivate companies to minimize biorefinery capital costs. The results indicate that exporting lignin to be cofired with coal and importing natural gas to supplement biogas captured from onsite wastewater treatment can be a viable option from a capital expenditure, GHG, and water standpoint. Our life-cycle GHG inventory highlights the importance of both the marginal unit of electricity supplied and the marginal unit ramped down, retired, or not constructed as a result of increased power supply from biorefineries. If variations in grid electricity demand are met by increases or reductions in NGCC power generation, biorefineries that export lignin to coal-fired power plants and rely on some imported natural gas and grid electricity (cases 3a and 3b) perform comparably to the base case (case 1) on a GHG basis. Otherwise, combusting lignin onsite for heat and power achieves the lowest carbon footprint. However, it should be noted that substantial uncertainty makes drawing close comparisons challenging; we expect some uncertainty associated with feedstock cultivation and conversion will be reduced as the industry grows and matures. In the future, applying electricity grid models that incorporate the effects of fuel prices, regulatory policy, and transmission 8453

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(2) Spatari, S.; Zhang, Y.; MacLean, H. L. Life Cycle Assessment of Switchgrass- and Corn Stover-Derived Ethanol-Fueled Automobiles. Environ. Sci. Technol. 2005, 39, 9750−9758. (3) McKone, T. E.; Nazaroff, W. W.; Berck, P.; Auffhammer, M.; Lipman, T.; Torn, M. S.; Masanet, E.; Lobscheid, A.; Santero, N.; Mishra, U.; Barrett, A.; Bomberg, M.; Fingerman, K.; Scown, C. Grand Challenges for Life-Cycle Assessment of Biofuels. Environ. Sci. Technol. 2011, 45, 1751−1756. (4) Zakzeski, J.; Bruijnincx, P.; Jongerius, A.; Weckhuysen, B. The Catalytic Valorization of Lignin for the Production of Renewable Chemicals. Chem. Rev. 2010, 110, 3552−3599. (5) Humbird, D.; Davis, R.; Tao, L.; Kinchin, C.; Hsu, D.; Aden, A.; Schoen, P.; Lukas, J.; Olthof, B.; Worley, M.; Sexton, D.; Dudgeon, D. Process Design and Economics for Biochemical Conversion of Lignocellulosic Biomass to Ethanol; 2011; National Renewable Energy Laboratory: Golden, CO; http://www.nrel.gov/docs/fy11osti/47764. pdf (Accessed March 13, 2014). (6) Klein-Marcuschamer, D.; Oleskowicz-Popiel, P.; Simmons, B. A.; Blanch, H. W. Technoeconomic Analysis of Biofuels: A Wiki-Based Platform for Lignocellulosic Biorefineries. Biomass Bioenergy 2010, 34, 1914−1921. (7) Klein-Marcuschamer, D.; Simmons, B. A.; Blanch, H. W. TechnoEconomic Analysis of a Lignocellulosic Ethanol Biorefinery with Ionic Liquid Pre-Treatment. Biofuels, Bioprod. Biorefin. 2011, 5, 562−569. (8) Pourhashem, G.; Adler, P. R.; McAloon, A. J.; Spatari, S. Cost and Greenhouse Gas Emission Tradeoffs of Alternative Uses of Lignin for Second Generation Ethanol. Environ. Res. Lett. 2013, 8, 025021. (9) Vanholme, R.; Demedts, B.; Morreel, K.; Ralph, J.; Boerjan, W. Lignin biosynthesis and structure. Plant Physiol. 2010, 153, 895−905. (10) Carriera, M.; Loppinet-Serania, A.; Denuxa, D.; Lasnierc, J.-M.; Ham-Pichavantc, F.; Cansella, F.; Aymonier, C. Thermogravimetric Analysis As a New Method to Determine the Lignocellulosic Composition of Biomass. Biomass Bioenergy 2011, 35, 298−307. (11) Mu, D.; Seager, T.; Rao, P. S.; Zhao, F. Comparative Life Cycle Assessment of Lignocellulosic Ethanol Production: Biochemical Versus Thermochemical Conversion. Environm. Manage. 2010, 46, 565−578. (12) Brosse, N.; Sannigrahi, P.; Ragauskas, A. Pretreatment of Miscanthus x giganteus Using the Ethanol Organosolv Process for Ethanol Production. Ind. Eng. Chem. Res. 2009, 48, 8328−8334. (13) Sergeev, A. G.; Hartwig, J. F. Selective, Nickel-Catalyzed Hydrogenolysis of Aryl Ethers. Science 2011, 332, 439−3443. (14) Huber, G. W.; Corma, A. Synergies between Bio- and Oil Refineries for the Production of Fuels from Biomass. Angew. Chem. 2007, 46, 7184−7201. (15) da Silva, E. A. B.; Zabkova, M.; Araújo, J. D.; Cateto, C. A.; Barreiro, M. F.; Belgacem, M. N.; Rodrigues, A. E. An Integrated Process to Produce Vanillin and Lignin-Based Polyurethanes from Kraft Lignin. Chem. Eng. Res. Des. 2009, 87, 1276−1292. (16) McAloon, A.; Taylor, F.; Yee, W.; Ibsen, K.; Wooley, R. Determining the Cost of Producing Ethanol from Corn Starch and Lignocellulosic Feedstocks; National Renewable Energy Laboratory: Golden, CO; 2000; http://www.nrel.gov/docs/fy01osti/28893.pdf (accessed March 13, 2014). (17) Biomass Cofiring in Coal-Fired Boilers; Report DOE/EE-0288; Federal Energy Management Program: Washington, D.C., 2004; http://www.nrel.gov/docs/fy04osti/33811.pdf (accessed March 13, 2014). (18) Inventory of U.S. Greenhouse Gas Emissions and Sinks; Report EPA 430-R-12-001; U.S. Environmental Protection Agency: Washington, D.C., 2012; http://www.epa.gov/climatechange/Downloads/ ghgemissions/US-GHG-Inventory-2012-Main-Text.pdf (accessed March 13, 2014). (19) Sathre, R.; Masanet, E. Long-Term Energy and Climate Implications of Carbon Capture and Storage Deployment Strategies in the US Coal-Fired Electricity Fleet. Environ. Sci. Technol. 2012, 46, 9768−9776. (20) Searchinger, T.; Heimlich, R.; Houghton, R. A.; Dong, F.; Elobeid, A.; Fabiosa, J.; Tokgoz, S.; Hayes, D.; Yu, T.-H. Use of U.S.

infrastructure can further reduce the uncertainty associated with our results. Another important finding is that, from a water use perspective, exporting lignin to coal-fired power plants and installing an onsite biogas/natural gas-fired CHP system results in a 40% reduction in life-cycle water consumption. In cases that net power exports from biorefineries result in early retirement of aging coal-fired power plants, large water withdrawals are avoided because older coal-fired power plants typically utilize open-loop cooling systems. This offset credit results in net negative withdrawals, and maximizing net biorefinery power output maximizes this benefit. Although exporting lignin to coal-fired power plants is environmentally and economically attractive in some cases, it is unclear whether GHG regulations will make this practice feasible. Central to this question is which stakeholders will receive credit for offsetting coal: biofuel producers or coal-fired power plant owners? Biorefineries receive electricity offset credits in the methodology underlying current life-cycle GHG regulations for transportation fuels, which implies that a similar method could be used to account for lignin exports to coal-fired power plants.39 In each case, if both power plants/electric utilities and biorefineries are granted credit, the benefits of generating power from lignin are essentially double-counted. A scheme for allocating a portion of emission offset credits to both power plants and biorefineries could be a solution to this problem. If the necessary regulatory framework is in place and options for lignin utilization are weighed carefully on a facilityby-facility basis for all environmental and economic performance metrics, this coproduct can achieve substantial reductions in GHG emissions while also minimizing capital costs and water use.

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ASSOCIATED CONTENT

S Supporting Information *

A detailed description of data, sources, analytical methods, and tables with numerical results. Additional data sets are available from the corresponding author. This material is available free of charge via the Internet at http://pubs.acs.org.

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AUTHOR INFORMATION

Corresponding Author

*Phone: (510) 486-4507. Fax: (510) 486-5928. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS We wish to thank John Myers from the Department of Chemical Petroleum Engineering at University of Wyoming for fruitful conversations regarding modeling various power generation scenarios. Preparation of this article was financially supported in part by the Energy Biosciences Institute at the University of California, Berkeley. This work was carried out in part at the Lawrence Berkeley National Laboratory, which is operated for the U.S. Department of Energy under Contract Grant No. DE-AC03-76SF00098.

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