Life Cycle Analysis

Coal

Coal is a fossil fuel that is extracted by underground or surface mining techniques. The U.S. has a large resource base of coal, including surface mines in the western U.S. and underground mines in the eastern U.S. After extraction, coal is transported by rail to a power plant, where it is pulverized and combusted for power generation.


Life Cycle Analysis at the National Energy Technology Laboratory
This is a summary of the Life Cycle Analysis capabilities at NETL. It compares two technology options and evaluating the impact of a policy on an entire system. Boundaries and functions considered are coal and natural gas. It discusses how LCA is beneficial for energy analysis because it draws a more complete picture, allows direct comparison of different options, includes methods for evaluating emissions and impacts, and brings clarity to results.
Authors: Tim Skone
Date: April, 2014

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Power Plant Flexible Model
The Power Plant Flexible Model (PPFM) is an Excel-based tool that simulates coal combustion-based power plant electrical output, emissions, materials usage, and costs for a fully-configurable mix of boiler and steam plant types, feedstocks, and emissions control equipment. The technical documentation and user's guide for the model are included in the download package. PPFM is not engineered to be a consumer-level product and requires knowledge of coal combustion power plants and processes to yield reasonable results.
Authors: Tim Skone, Greg Cooney, Matthew Jamieson
Date: November, 2013

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Co-firing Biomass to Reduce the Environmental Footprint of Coal-fired Heat and Power: A Good Strategy?
The use of biomass as a feedstock for co-fired electricity generation and heat production is attractive, because it offers renewable energy derived from a domestically available feedstock, and the potential for reductions in greenhouse gases and other environmental impacts. Drivers for the adoption of biomass-based power and heat include the anticipation of forthcoming greenhouse gas (GHG) regulation, compatibility with existing industrial processes and electricity infrastructure, and other potential State or Federal policies. This analysis is the result of collaboration between the Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) and the Environmental Protection Agency’s (EPA) National Risk Management Research Laboratory. The overarching objective of this work is to gain a better understanding of the potential human health and environmental outcomes associated with the use of biomass in electricity generation and combined heat and power operations. Co-firing biomass with coal does reduce GHG emissions, but it can increase some human health and ecosystem impacts. The specific type of biomass and the location where it is produced are important, making it difficult to generalize the results in all impact categories. In scenarios where steam is cogenerated with electricity, co-product management methods (allocation and displacement) can yield different results.
Authors: Tim Skone, Greg Schivley, Greg Cooney, Matt Jamieson, James Littlefield, Joe Marriott
Date: October, 2013

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The Challenge of Co-product Management for Large-scale Energy Systems—Power, Fuel and CO2
Applying traditional co-product management methods such as physical allocation and system expansion in conventional ways can lead to large study uncertainty in life cycle analysis (LCA) of large scale energy systems. The National Energy Technology Laboratory's (NETL) LCA model of Carbon dioxide-Enhanced Oil Recovery (CO2-EOR) is a cradle-to-grave model that accounts for the greenhouse gas emissions and other environmental burdens from a system which connects the power sector to the liquid fuels sector. The model leverages existing NETL life cycle data to account for environmental burdens upstream and downstream from the CO2-EOR site, including alternative sources of CO2, petroleum refining, and gasoline or diesel combustion. The use of advanced power plants with carbon capture as a source of CO2 results in the co-production of electricity and transportation fuels (gasoline or diesel). Co-product allocation can be avoided by expanding the system to include displacement of other routes to electricity generation, but conjecture about the expanded system leads to wide uncertainty. If energy is used as a basis for co-product allocation between electricity and liquid fuel (diesel or gasoline), the differences between the useful energy in the energy products hinders comparability. Partitioning a portion of the system, in this case the power plant, to perform more accurate energy allocation is a third approach, and is possible when detailed plant schematics allow disaggregation of integrated processes.
Authors: Tim Skone
Date: October, 2013

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Life Cycle Analysis: Integrated Gasification Combined Cycle (IGCC) Power Plant
Life cycle analysis of an integrated gasification combined cycle (IGCC) plant. Develops an inventory of emissions results, and calculates life cycle costs for the plant with and without CCS.
Authors: Tim Skone, Robert James
Date: June, 2013

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Contribution of Biomass to the LCI of Cofiring Power
Biomass includes agricultural residues, forest thinnings, and dedicated energy crops. Life cycle greenhouse gas (GHG) emission reductions can be accomplished with coal and biomass co-firing only if biomass is produced with high yield rates and there are miniminal changes to land use. Increasing power plant efficiency or using post-combustion carbon dioxide capture and sequestration can lead to larger GHG reductions than co-firing biomass with coal.
Authors: Tim Skone, Joe Marriott, PhD
Date: September, 2012

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Role of Alternative Energy Sources: Pulverized Coal and Biomass Co-firing Technology Assessment
Co-firing is seen as a way of reducing the greenhouse gas (GHG) emissions of existing coal-fired power plants, but the incorporation of biomass into an existing coal-fired system increases the complexity of feedstock acquisition. Further, the acquisition of biomass has unique GHG burdens that offset, in part, the GHG reductions from the displacement of coal with biomass. Due to the higher feedstock prices of biomass, the co-firing of biomass at a 10 percent share of feedstock energy can increase the cost of electricity by as much as 31 percent. Other risks include regulatory uncertainty; without policies that encourage the use of renewable feedstocks, there is no incentive for producers to invest in co-fired systems.
Authors: Tim Skone, James Littlefield, Robert Eckard, Greg Cooney, Robert Wallace, Joe Marriott, PhD
Date: August, 2012

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LCA: Integrated Gasification Combined Cycle (IGCC) Power Plant
LCA of an Integrated Gasification Combined Cycle plant. Develops an Inventory of emissions results, and calculates Life Cycle costs for the plant with and without CCS.
Authors: Tim Skone, Laura Draucker, Raj Bhander, Barbara Bennet, Tom Davis, Robert Eckard, William Ellis, John Kauffman, James Littlefield, Amanda Malone, Ron Munson, Mara Nippert, Massood Ramezan, Roxanne Bromiley
Date: March, 2012

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Life Cycle Greenhouse Gas Analysis of Advanced Jet Propulsion Fuels: Fischer Tropsch Based SPK-1 Case Study
In response to the Energy Independence and Security Act (EISA), NETL conducted a LCA (LCA) of 10 fuel production pathways using Fischer-Tropsch synthesis. These pathways use varying combinations of coal and swithgrass feedstocks and two options for carbon managment (sequestration or enhanced oil recovery). Only greenhouse gas (GHG) emissions are inventoried. Comparative analysis of the results demonstrate that higher percentages of biomass result in lower life cycle greenhouse gas (GHG) emissions when using switchgrass. The choice of carbon management strategy has an effect on the results.
Authors: Tim Skone
Date: September, 2011

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LCA: Integrated Gasification Combined Cycle (IGCC) Power Plant (Archived 2010)
This is a life cycle environmental and cost profile of Integrated Gasification Combined Cycle (IGCC) power using Illinois No. 6 coal as a feedstock. Scenarios with and without carbon capture and sequestration are evaluated. The capture and sequestration of 90 percent of power plant carbon reduces life cycle greenhouse gas emissions from 948 to 218 kg of carbon dioxide equivalents per MWh of delivered electricity (a 77 percent decrease) and increases the life cycle cost of power from $120 to $160 per MWh (a 33 percent increase).
Authors: Robert James, Laura Draucker, Raj Bhander, Barbara Bennet, Tom Davis, Robert Eckard, William Ellis, John Kauffman, James Littlefield, Amanda Malone, Ron Munson, Mara Nippert, Massood Ramezan, Roxanne Bromiley
Date: September, 2010

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LCA: Existing Pulverized Coal (EXPC) Power Plant
This is a life cycle environmental and cost profile of existing pulverized coal power using Illinois No. 6 coal as a feedstock. Scenarios with and without carbon capture and sequestration are evaluated. The capture and sequestration of 90 percent of power plant carbon reduces life cycle greenhouse gas emissions from 1,109 to 444 kg of carbon dioxide equivalents per MWh of delivered electricity (a 60 percent decrease) and increases the life cycle cost of power from $28 to $125 per MWh (a 350 percent increase).
Authors: Robert James, James Littlefield, Raj Bhander, Barbara Bennet, Tom Davis, Laura Draucker, Robert Eckard, William Ellis, John Kauffman, Amanda Malone, Ron Munson, Mara Nippert, Massood Ramezan, Roxanne Bromiley
Date: September, 2010

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LCA: Supercritical Pulverized Coal (SCPC) Power Plant
This is a life cycle environmental and cost profile of Supercritical Pulverized Coal (SCPC) power using Illinois No. 6 coal as a feedstock. Scenarios with and without  carbon capture and sequestration are evaluated.  The capture and sequestration of 90 percent of power plant carbon reduces life cycle greenhouse gas emissions from 944 to 247 kg of carbon dioxide equivalents per MWh of delivered electricity (a 74 percent decrease) and increases the life cycle cost of power from $94.3 to $16.3 per MWh (a 73 percent increase).
Authors: Robert James, Laura Draucker, Raj Bhander, Barbara Bennet, Tom Davis, Robert Eckard, William Ellis, John Kauffman, James Littlefield, Amanda Malone, Ron Munson, Mara Nippert, Massood Ramezan, Roxanne Bromiley
Date: September, 2010

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Progress Update: Interagency Workgroup on Life Cycle GHG Emissions of Alternative Aviation Fuels
This presentation covers efforts to examine life cycle greenhouse gas (GHG) emissions of alternative aviation fuels, as led by the U.S. Air Force Research Laboratory with the support of a multi-disciplinary group of federal, industrial, academic institutions. The primary objective of the workgroup is to develop a set of standard guidance on how to evaluate the life cycle GHG footprint of various alternative jet fuel production pathways using a wide-range of feedstock sources. Application of the guidelines can be used by fuel suppliers, military, and commercial airlines to assess the environmental preferability of a specific fuel production pathway when compared to conventional jet fuel. Workgroup activity status and plans for testing on specific case studies are also discussed.
Authors: Tim Skone
Date: February, 2010

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Framework and Guidance for Estimating Greenhouse Gas Footprints of Aviation Fuels
Federal policies, such as those outlined in Section 526 of EISA 2007, cause federal agencies to institute enforceable guidelines for procuring low carbon alternative fuels. This report provides guidance on how to estimate greenhouse gas (GHG) emissions in aviation applications. This guidance is based on collaboration among the U.S. Air Force, government agencies, universities, and companies that are actively engaged in assessing GHG emissions from transportation fuels.
Authors: Phil DiPietro, David T. Allen, Charles Allport, Kristopher Atkins, Joyce S. Cooper, Robert M. Dilmore, Laura C. Drauker, Kenneth E. Eickmann, Jeffrey C. Gillen, Warren Gillette, W. M. Griffin, William E. Harrison III, James I. Hileman, John R. Ingham, Fred A. Kimler III, Aaron Levy, Cynthia F. Murphy, Michael J. O'Donnell, David Pamplin, Greg Schively, Tim Skone, Shannon M. Strank, Russell W. Stratton, Philip H. Taylor, Valerie M. Thomas, Michael Q. Wang, Thomas Zidow
Date: April, 2009

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Balancing Climate Change, Energy Security, and Economic Sustainability: A Life Cycle Comparison of Diesel Fuel from Crude Oil and Domestic Coal and Biomass Resources
Brief 4-page summary of the near-term benefits of co-gasifying U.S. coal and biomass resources to produce FT diesel; a domestic transportation fuel. The paper summarizes the climate change, energy security, and economic benefits when compared to conventional diesel fuel production from domestic and imported crude oil.
Authors: Phil DiPietro, Tim Skone, Kristin Gerdes, Tom Tarka, John Wimer
Date: April, 2009

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LCA of Greenhouse Gas Emissions for Hydrogen Fuel Production in the USA from LNG and Coal
This is a LCA (LCA) that accounts for the greenhouse gas (GHG) emissions from the production of hydrogen from liquefied natural gas (LNG) via steam methane reforming (SMR) or from coal gasification. Carbon capture and sequestration (CCS) is one option for managing carbon dioxide emissions from hydrogen production.  By employing a CCS system with a 92 percent capture rate at an SMR plant, the life cycle GHG emissions from hydrogen production from LNG are reduced by 64 percent. Gasification of coal is another pathway to hydrogen production, but the GHG emissions are highly variable due to coal mine methane (CMM) emissions. Mitigation of CMM is a key opportunity for improving GHG emissions from the the coal-to-hydrogen pathway.
Authors: Eric Grol, Massood Ramezan, John Ruether
Date: November, 2005

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