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[LCA UP] Biomass Pelletization (2022)
This unit process quantifies the energy requirements that are expected to result from woody biomass or torrefied woody biomass pelletization.
[LCA UP] Biomass Land Preparation (2023)
This unit process models land preparation activities for various biomass types.
[LCA UP] LNG Ocean Shipping
This unit process includes operation of a liquefied natural gas (LNG) ocean tanker using steam, DFDE/TFDE, ME-GI or X-DF engines. The tanker is fueled by a combination of boil-off gas (BOG) produced via evaporation of LNG, fuel oil, and diesel.
[LCA UP] Processing and Liquefaction of NG and Storage of LNG DY2020
This unit process includes pipeline gas input, energy requirements, emissions, and losses, associated with processing, liquefaction and storage of natural gas at six different U.S. liquefaction facilities before it is exported.
The National Energy Technology Laboratory’s New Unit Process Template Design - LCAXIX
This work was presented at the American Center for Life Cycle Assessment 2019 Conference (LCAXIX) in Tucson, AZ on September 25, 2019. The National Energy Technology Laboratory (NETL) maintains a large unit process (UP) library which holds all documentation for each unit process created by the NETL Life Cycle Analysis (LCA) team. Each NETL unit process includes a Microsoft Excel spreadsheet containing calculations and an accompanying PDF, which thoroughly documents the calculations, parameters, and underlying reasoning and assumptions contained in the Excel file. However, as more and larger public data sources become available, the NETL LCA team has incorporated more data science techniques into their unit process development. NETL is demonstrating a new template which will allow for more flexible and advanced calculation and documentation methods. The new template will support NETL’s dedication to transparency by continuing to provide all information necessary to replicate the UPs.
[LCA UP] Biomass Harvesting (2023)
This unit process models harvesting activities for various biomass types.
[LCA UP] Biomass Drying (2022)
This unit process quantifies the energy requirements and airborne emissions that are expected to result from the biomass drying process, where the biomass type being dried is woody crop biomass.
A Gate-to-Gate Life Cycle Assessment for the CO 2 -EOR Operations at Farnsworth Unit (FWU)
Greenhouse gas (GHG) emissions related to the Farnsworth Unit’s (FWU) carbon dioxide enhanced oil recovery (CO 2 -EOR) operations were accounted for through a gate-to-gate life cycle assessment (LCA) for a period of about 10 years, since start of injection to 2020, and predictions of 18 additional years of the CO 2 -EOR operation were made. The CO 2 source for the FWU project has been 100% anthropogenically derived from the exhaust of an ethanol plant and a fertilizer plant. A cumulative amount of 5.25 × 106 tonnes of oil has been recovered through the injection of 1.64 × 106 tonnes of purchased CO 2 , of which 92% was stored during the 10-year period. An LCA analysis conducted on the various unit emissions of the FWU process yielded a net negative (positive storage) of 1.31 × 106 tonnes of CO 2 equivalent, representing 79% of purchased CO 2 . An optimized 18-year forecasted analysis estimated 86% storage of the forecasted 3.21 × 106 tonnes of purchased CO 2 with an equivalent 2.90 × 106 tonnes of crude oil produced by 2038. Major contributors to emissions were flaring/venting and energy usage for equipment. Improvements on the energy efficiency of equipment would reduce emissions further but this could be challenging. Improvement of injection capacity and elimination of venting/flaring or fugitive gas are methods more likely to be utilized for reducing net emissions and are the cases used for the optimized scenario in this work. This LCA illustrated the potential for the CO 2 -EOR operations in the FWU to store more CO 2 with minimal emissions.
Systems Analysis of Biomass and Coal Co-firing Power Plants with Deep Carbon Capture Toward Net-zero Emissions
Achieving a net-zero emission economy in the United States requires integrating diverse low-carbon and negative-emission technologies into the existing fossil fuel-dominant power fleet. Potential technologies from the low-carbon portfolio include renewable power, fossil power with carbon capture and storage (CCS), bioenergy with CCS (BECCS), and direct air capture (DAC). Renewable power is a clean energy source but has to pair with costly battery storage to provide dispatchable electricity. Fossil power with CCS offers dispatchable electricity yet still relies on DAC to offset residual emissions, even when deploying deep CCS with more than 90% CO2 capture. Coal-biomass co-firing with CCS, a subset of BECCS, is a reliable energy production technology that can be retrofitted from existing electricity generation units (EGUs). Power plant retrofit maximizes the use of the current U.S. coal power fleet without the need for large-scale deployment of new renewable power, battery storage, or DAC. Retrofitting coal-biomass co-firing with deep CCS in EGUs is a promising option, but not a universal solution. Biomass co-firing at a power plant introduces economic challenges and indirectly poses pressure on land and water resources. Meanwhile, retrofitting deep CCS affects plant efficiency and raises electricity generation costs. Overall, the technical feasibility and economic viability of plant retrofits vary across EGUs, as they are contingent upon the regional availability of biomass, unit-specific characteristics, site-specific fuel supply costs, and adjacent CO2 storage potential. Government incentives like 45Q can improve the retrofit viability, though the impact requires further quantification. A comprehensive analysis at the unit level is essential to address the question regarding the fate of the U.S. coal-fired electricity generation fleet toward the net-zero emission goal. This study conducts a systematic techno-economic-environmental assessment of EGUs to identify the viability of biomass co-firing and deep CCS retrofits in the U.S. coal-fired power fleet. Specifically, it characterizes the techno-economic performance of deep carbon capture, estimates life cycle greenhouse gas (GHG) emissions, and conducts a fleet-level assessment on retrofit viability. The key objectives are (1) to estimate the unit-specific performance and retrofitted cost under various biomass co-firing levels and CO2 capture rates; (2) to determine the possibility of reaching net-zero emission at the fleet level; (3) to quantify the cumulative capacities that are suitable for plant retrofits under current and future biomass supply scenarios; and (4) to improve the understanding of policy impacts on such retrofits to help the power sector’s transition to a net-zero economy. Techno-economic Model of Deep Carbon Capture. This study develops the performance and economic models for Monoethanolamine-based post-combustion CO2 capture at 95–99% capture rates. The process is simulated in Aspen Plus, analyzing the performance of carbon capture technology by varying the plant sizes, solvent lean loading, CO2 concentrations, and flue gas inlet temperature. Based on the key inputs and output parameters of CO2 capture, a reduced-order performance model of deep carbon capture is formulated. In addition, an engineering-economic model integrating the performance metrics is developed to estimate the capital as well as operation and maintenance (O&M) costs. Capital cost estimations follow the framework of the Integrated Environmental Control Model (IECM) and incorporate data regressions from three technical reports by IECM, the National Energy Technology Laboratory (NETL), and the National Renewable Energy Laboratory. The O&M cost estimation utilizes the actual inventory consumption rate and labor requirements. Both performance and cost models are embedded into IECM v13.0-beta, a fossil-fuel power plant modeling tool. Life Cycle Assessment of Power Plants. This study estimates the GHG emissions of power plants through life cycle assessment (LCA). The LCA scope includes fuel supply, combustion-based power generation, and CO2 transport and storage. The fuel-based life cycle module is designed following the framework of the NETL Unit Process Library and CO2U LCA Guidance Toolkit. The module is then incorporated into IECM v13.0-beta. The process-based LCA is applied to estimate the GHG emissions of coal and biomass supply, coal- and coal-biomass co-firing power plant operation, as well as CO2 pipeline transport and geographical sequestration. An uncertainty analysis is conducted to quantify the variability and uncertainty associated with the LCA using the Latin Hypercube Sampling (LHS) method. Fleet-level Assessment. This study evaluates the technical and economic feasibility of selected coal-fired EGUs, examines the role of tax credits in retrofit viability, and assesses the competitiveness of retrofitted units against other low-carbon options. Unit screening identifies EGUs for the study, focusing on new, efficient baseload units with air pollution controls. The power plant databases are then established to organize unit-specific information on performance and operating conditions from the relevant public databases. Biomass for co-firing retrofits is selected based on home and neighboring county availability, ensuring sustained operation with at least a 5% co-firing level. The CO2 storage site is determined by state-level storage potential, with ArcGIS Pro and NETL CO2 Saline Storage Cost Model used to identify the optimal balance between the nearest transport distances and affordable storage costs. The latest IECM v13.0-beta is then employed to configure and evaluate the eligible EGUs with or without the deployment of deep CCS and biomass co-firing. A supply curve is established to illustrate the cumulative installed capacity suitable for retrofits at different cost levels. A sensitivity analysis on tax credits for carbon sequestration is performed. Finally, a unit-level cost comparison is conducted among retrofitted plants, renewable power with battery storage, and abated fossil fuels with DAC. Expected Results. This study evaluates the technical, economic, and environmental metrics of each EGU across an array of CO2 capture rates and biomass co-firing level scenarios. Unit-level comparisons will identify critical factors influencing technical performance. The supply curves with and without tax incentives will provide insights into the impact of tax credits on biomass co-firing and CCS deployment. The cost comparisons with renewables and DAC-retrofit will assess the competitiveness of the retrofitted units. Life cycle emissions from each unit will be assessed to identify the scenarios under which net-zero emissions can be achieved. These analyses are expected to determine the total coal-fired capacity suitable for serving as a low-carbon energy source with or without tax incentives. The study results are novel in identifying optimal unit-specific strategies for producing carbon-neutral power, whether through retrofitting EGUs with deep CCS, biomass co-firing, DAC, or installing renewable power with battery. The findings will provide insight into nationwide efforts to ensure reliable, affordable, and low-carbon electricity. It also will inform investment decisions and policies in the deployment of deep carbon capture and negative emission technologies for a net-zero energy future.
Introduction to NETL Natural Gas LCA
This work presents an overview of NETL natural gas (NG) life cycle modeling. The content covers: introduction, model structure and unit processes, co-product management, and highlights from the recently published NETL NG baseline report.
Development of wind turbine blade recycling baselines in the United States
Over the past several years, the wind energy industry has received scrutiny regarding wind turbine blade (WTB) recycling due to the landfilling of WTBs caused by a lack of industrially viable recycling solutions. The amount of WTBs that will need to be recycled is set to increase in the United States as the deployment of wind energy is expected to rapidly grow to meet the nation's energy goals by 2035. While significant progress has been made worldwide, it is still unclear which WTB recycling solutions would be the most cost and energy effective within the United States for the existing fleet of wind turbines. To guide researchers and industry with a clear path forward, a range of options for WTB recycling in the United States are modeled through development of baseline scenarios and the use of formal life cycle assessment (LCA). Model data have been collected through literature review, industry engagement, and expert opinion regarding current end of life practices and considerations surrounding equipment, labor, and logistics. A detailed baseline for WTB decommissioning processes has been developed and used to assess alternative approaches, such as on-site shredding to compare the impacts on greenhouse gas (GHG) emissions. The developed LCA model and baseline scenarios for WTB recycling is used to assess the current WTB decommissioning practices in the United States along with emerging recycling pathways, including cement kiln co-processing and pyrolysis. Initial findings indicate that there are different approaches to decommissioning WTBs in the United States, each of which has unique implications for recycling. In light of this finding, additional results from the modeling will be used to better understand decommissioning practices and assist in making educated decisions on recycling pathways for the future. Throughout the analysis, focus was given to where international efforts might differ from the United States. WTB recycling is occurring worldwide, and different countries have different drivers for creating markets for recycled WTB materials. The contrasts and similarities between the United States and other countries offer insight to areas of opportunity that the United States could investigate and areas that can be readily transferred from existing solutions. By modeling and characterizing the current decommissioning practices and potential recycling solutions for the United States, a clearer vision will be created for pathways forward as to how to handle end of life WTBs to enable more efficient and cost-effective opportunities for material recovery from end-of-life WTBs.
Strategies for connecting whole-building LCA to the low-carbon design process
Abstract Decarbonization is essential to meeting urgent climate goals. With the building sector in the United States accounting for 35% of total U.S. carbon emissions, reducing environmental impacts within the built environment is critical. Whole-building life cycle analysis (WBLCA) quantifies the impacts of a building throughout its life cycle. Despite being a powerful tool, WBLCA is not standard practice in the integrated design process. When WBLCA is used, it is typically either speculative and based on early design information or conducted only after design completion as an accounting measure, with virtually no opportunity to impact the actual design. This work proposes a workflow for fully incorporating WBLCA into the building design process in an iterative, recursive manner, where design decisions impact the WBLCA, which in turn informs future design decisions. We use the example of a negative-operational carbon modular building seeking negative upfront embodied carbon using bio-based materials for carbon sequestration as a case study for demonstrating the utility of the framework. Key contributions of this work include a framework of computational processes for conducting iterative WBLCA, using a combination of an existing building WBLCA tool (Tally) within the building information modeling superstructure (Revit) and a custom script (in R) for materials, life cycle stages, and workflows not available in the WBLCA tool. Additionally, we provide strategies for harmonizing the environmental impacts of novel materials or processes from various life cycle inventory sources with materials or processes in existing building WBLCA tool repositories. These strategies are useful for those involved in building design with an interest in reducing their environmental impact. For example, this framework would be useful for researchers who are conducting WBLCAs on projects that include new or unusual materials and for design teams who want to integrate WBLCA more fully into their design process in order to ensure the building materials are consciously chosen to advance climate goals, while still ensuring best performance by traditional measures.
Techno-economic and life cycle analyses for a supercritical biodiesel production process from waste cooking oil for a plant located in the Midwest United States
Existing literature lacks detailed techno-economic and environmental life cycle analyses (TEA-LCA) focused on supercritical biodiesel production pathways produced via waste products. Therefore, in this work, the TEA-LCA was conducted to generate supercritical biodiesel from waste cooking oil for plants located in the Midwest region of USA having annual production capacities of 10,600 and 128,000 t using Aspen Plus and GREET softwares. Here, two plant production capacities were chosen to capture the economies of scale impact on biodiesel manufacture cost. In the supercritical process, methanol and propane were used as a cosolvent to synthesize biodiesel from waste cooking oil (WCO) at 280 °C and 128 bar at a residence time of 8.4 min and a WCO conversion rate of 97%. Economic analysis revealed that the supercritical process was an economically attractive pathway with a 2-year payback period for the 10,600 t/year capacity along with a break-even selling price of $\$$ 2.42/gal of diesel. In case of the larger plant (128,000 t/year capacity), the payback period and the breakeven selling price were considerably lower at values of 0.4 years and $1.31/gal of diesel, respectively, due to economies of scale impact. The generated biodiesel from supercritical process for the both the plant capacities met European (EN14214) and US (ASTM D6751) fuel quality standards while the obtained commercially valuable side product, i.e., glycerol, adhered to a pharmaceutical grade of 99.7%. Cradle to gate life cycle analysis using GREET revealed that supercritical process possessed 17% lower CO2 emissions than alkali-catalyzed process and 4% lower CO2 emissions than the conventional diesel production process. Other biodiesel production pathways in the literature were also compared to the results of the TEA-LCA of supercritical biodiesel production pathway.
Techno-Economic Analysis and Life Cycle Assessment for Guiding Bioenergy Pathway Development
The Center for Bioenergy Innovation (CBI) is a bioenergy research center recently launched by the U.S. Department of Energy Office of Science's Biological and Environmental Research program. CBI's objective is to enable innovations across the bioenergy supply chain through development of poplar and switchgrass phenotypes, microorganisms for consolidated bio-processing (CBP), in which biomass fermentation and conversion is accomplished in a single unit operation, and lignin valorization processes. In addition to basic science, CBI's activities involve the application of techno-economic analysis (TEA) and life cycle assessment (LCA) to the bioenergy pathways under study. TEA and LCA is used to quantify the impacts that research and development breakthroughs have on the economic viability and sustainability of a bioenergy pathway, and to identify drivers for reducing costs and improving sustainability through targeted research efforts. Combining TEA and LCA allows for understanding the economic and sustainability benefits and trade-offs of these integrated bioenergy systems. The focus of this presentation is a parameterized, integrated TEA-LCA model, which will be discussed along with an application to bioenergy pathways currently under study. The model combines data and information developed by CBI researchers into a superstructure of potential bioenergy pathways and their life cycles. Model parameters include feedstock species and phenotype, farming, harvesting, storage and transportation practices, and the microbes used for biomass conversion and lignin valorization, among others. The parameterized TEA-LCA model allows for the rapid quantification of pathway economic and sustainability metrics such as minimum fuel selling price, payback period, fossil fuel consumption and net greenhouse gas emissions. To demonstrate the model, economic and sustainability metrics for a bioenergy pathway utilizing CBP will be quantified and compared to the same metrics for a conventional bioenergy pathway. Results of the comparison will be used to identify and prioritize high-impact research areas within the CBP pathway. fermentation and conversion is accomplished in a single unit operation, and lignin valorization processes. In addition to basic science, CBI's activities involve the application of techno-economic analysis (TEA) and life cycle assessment (LCA) to the bioenergy pathways under study. TEA and LCA is used to quantify the impacts that research and development breakthroughs have on the economic viability and sustainability of a bioenergy pathway, and to identify drivers for reducing costs and improving sustainability through targeted research efforts. Combining TEA and LCA allows for understanding the economic and sustainability benefits and trade-offs of these integrated bioenergy systems. The focus of this presentation is a parameterized, integrated TEA-LCA model, which will be discussed along with an application to bioenergy pathways currently under study. The model combines data and information developed by CBI researchers into a superstructure of potential bioenergy pathways and their life cycles. Model parameters include feedstock species and phenotype, farming, harvesting, storage and transportation practices, and the microbes used for biomass conversion and lignin valorization, among others. The parameterized TEA-LCA model allows for the rapid quantification of pathway economic and sustainability metrics such as minimum fuel selling price, payback period, fossil fuel consumption and net greenhouse gas emissions. To demonstrate the model, economic and sustainability metrics for a bioenergy pathway utilizing CBP will be quantified and compared to the same metrics for a conventional bioenergy pathway. Results of the comparison will be used to identify and prioritize high-impact research areas within the CBP pathway.
Carbon Intensities of Refining Products in Petroleum Refineries with Co-Processed Biofeedstocks
Petroleum refineries increasingly seek to generate fuels with lower carbon intensities (CIs; a measure of life cycle greenhouse gas [GHG] emissions per unit of energy of fuel; well-to-wheel [WTW]) to meet growing demand. Co-processing refers to a process that adds biomass-derived feedstocks to the fossil-based feedstocks of existing petroleum refinery process units. With the use of biofeedstocks, it is expected that co-processed fuels would have lower CIs than their petroleum counterparts without requiring changes in the existing infrastructure for producing, transporting, and using fuels. To quantify the GHG emissions reduction benefits of co-processing, this study uses a linear programming model to simulate petroleum refinery conditions with and without co-processing. The co-processing cases include three biofeedstocks (soy oil, tallow, and used cooking oil or UCO) used as 10 vol.% of the feedstock to a hydrotreater or hydrocracker since these lipid-based feedstocks have favorable properties to be treated in a hydrotreater or hydrocracker. In addition, we considered pyrolysis oil used as 10 vol.% of the feedstock to a fluid catalytic cracking (FCC) unit in the modeled refinery due to its higher oxygen content compared to other lipid-based feedstocks. Life cycle analysis (LCA) using two distinct approaches—process-level energy allocation and a refinery-level marginal approach—has been conducted for each case. The LCA results using process-level allocation show that there are no noticeable changes in emissions or energy use impacts at the facility level. The life cycle GHG emission reductions of co-processing cases are mainly related to the fraction of biogenic carbon embedded in each fuel product. For example, co-processed jet fuels (a mixture of fossil and biogenic fuels) made via hydrotreating or hydrocracking have higher biogenic carbon, which results in jet fuel CI reductions of 3.9%–8.6% compared to the CI of baseline petroleum jet fuels on a WTW basis. However, analysis of co-processed pyrolysis oil in an FCC shows that a higher fraction of biofeedstocks (29%) becomes process emissions (i.e., CO and CO 2 ), mainly due to the oxygenates in pyrolysis oil, and so it generates less renewable fuel than biofeedstocks co-processed via hydrotreating or hydrocracking. Using the refinery-level marginal approach, the changes in energy use and emissions of co-processing cases compared to the petroleum-only baseline case are allocated to the changes in fuel production (assuming renewable fuels). This approach generates the life cycle GHG emission values of co-processed renewable fuels, which are comparable to the CIs of standalone biofuel production pathways. However, as this approach relies on a rough assumption that product yields and emissions from co-processing units on fossil feedstocks remain the same with and without biofeedstock inputs, co-processing cases like FCC pyrolysis oil may generate quite skewed results.
Intensified Co-electrolysis Process for Syngas Production from Captured CO 2
CO 2 reduction to syngas provides a way of ameliorating carbon footprint and storing energy in high-energy-density and versatile feedstock. This current work explores the isothermal integration of CO2 capture with an intensified unit operation for the reduction of CO2 and capture media regeneration. Intensified captured CO2 co-electrolysis (ICC) to syngas (H2:CO ratio of 2) with low CO2 content (<10%) was demonstrated with over 70% CO2 conversion at a current density up to 0.20 A/cm2 for 14 hours of operation. Integration of the co-electrolysis unit with CO2 capture was performed feeding pure and diluted CO2, for which CO2 conversions >65% were observed. Performance of the capture unit becomes critical to maintain syngas ratios (SR). Technology feasibility was assessed through comparative techno-economic and life cycle analysis showing that process intensification enables competitive performance, even at the higher energy consumption featured at the current state of the technology. This because several unit operations can be avoided. LCA also showed that based on the current US electricity mix the reduction of life cycle CO2 emissions is possible at scenarios observed with 0.15 A/cm2 to accomplish a carbon-negative technology.
GREET® Analysis for TERRA/ROOTS Success Scenarios
The Renewable Fuel Standard (RFS2), significantly amended under the U.S. Energy Independence and Security Act (EISA) of 2007, calls for production of 36 billion gallons of renewable fuels by 2022. To qualify as a renewable fuel under RFS2, fuels must achieve a reduction in greenhouse gas (GHG) emissions as compared to a 2005 petroleum baseline. The U.S. Environmental Protection Agency (USEPA) is responsible for evaluating if a certain biofuel pathway meets EISA reduction targets, based on lifecycle analysis (LCA). Typically, the tools/models for biofuel LCA describe the full bioenergy pathway including farm input manufacturing (e.g. fertilizers), feedstock production, conversion processing at the bio-refinery, and land use change (LUC) prompted by increased feedstock production and calculate the amount of GHGs emitted per unit of biofuel produced. This type of information has been a critical driver of public opinion and national policy. LCA technique has also been utilized by California Air Resources Board (CARB)’s Low-Carbon Fuel Standard (LCFS) to evaluate the lifecycle carbon intensity (CI) of biofuels. Through this program, California seeks to reduce the GHG emissions from transportation fuel and has committed to reduce the state’s transportation GHG emissions by 20% by 2030. This program operates through a system of tradable permits that are valued based on the difference in CI of alternative fuels and the fuel they displace (e.g. ethanol and gasoline). Lower CI fuels generate LCFS credits that increase in value as this difference gets larger. In 2018, CO 2 in the LCFS market was priced at $\$$160/metric ton.