Updating the U.S. Life Cycle GHG Petroleum Baseline to 2014 with Projections to 2040 Using Open-Source Engineering-Based Models.

The National Energy Technology Laboratory produced a well-to-wheels (WTW) life cycle greenhouse gas analysis of petroleum-based fuels consumed in the U.S. in 2005, known as the NETL 2005 Petroleum Baseline. This study uses a set of engineering-based, open-source models combined with publicly available data to calculate baseline results for 2014. An increase between the 2005 baseline and the 2014 results presented here (e.g., 92.4 vs 96.2 g CO2e/MJ gasoline, + 4.1%) are due to changes both in modeling platform and in the U.S. petroleum sector. An updated result for 2005 was calculated to minimize the effect of the change in modeling platform, and emissions for gasoline in 2014 were about 2% lower than in 2005 (98.1 vs 96.2 g CO2e/MJ gasoline). The same methods were utilized to forecast emissions from fuels out to 2040, indicating maximum changes from the 2014 gasoline result between +2.1% and -1.4%. The changing baseline values lead to potential compliance challenges with frameworks such as the Energy Independence and Security Act (EISA) Section 526, which states that Federal agencies should not purchase alternative fuels unless their life cycle GHG emissions are less than those of conventionally produced, petroleum-derived fuels.

Identifying/Quantifying Environmental Trade-offs Inherent in GHG Reduction Strategies for Coal-Fired Power.

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.

Evaluating the climate benefits of CO2-enhanced oil recovery using life cycle analysis.

This study uses life cycle analysis (LCA) to evaluate the greenhouse gas (GHG) performance of carbon dioxide (CO2) enhanced oil recovery (EOR) systems. A detailed gate-to-gate LCA model of EOR was developed and incorporated into a cradle-to-grave boundary with a functional unit of 1 MJ of combusted gasoline. The cradle-to-grave model includes two sources of CO2: natural domes and anthropogenic (fossil power equipped with carbon capture). A critical parameter is the crude recovery ratio, which describes how much crude is recovered for a fixed amount of purchased CO2. When CO2 is sourced from a natural dome, increasing the crude recovery ratio decreases emissions, the opposite is true for anthropogenic CO2. When the CO2 is sourced from a power plant, the electricity coproduct is assumed to displace existing power. With anthropogenic CO2, increasing the crude recovery ratio reduces the amount of CO2 required, thereby reducing the amount of power displaced and the corresponding credit. Only the anthropogenic EOR cases result in emissions lower than conventionally produced crude. This is not specific to EOR, rather the fact that carbon-intensive electricity is being displaced with captured electricity, and the fuel produced from that system receives a credit for this displacement.

Life cycle assessment and grid electricity: what do we know and what can we know?

The generation and distribution of electricity comprises nearly 40% of U.S. CO(2), emissions, as well as large shares of SO(2), NO(x), small particulates, and other toxins. Thus, correctly accounting for these electricity-related environmental releases is of great importance in life cycle assessment of products and processes. Unfortunately, there is no agreed-upon protocol for accounting for the environmental emissions associated with electricity, as well as significant uncertainty in the estimates. Here, we explore the limits of current knowledge about grid electricity in LCA and carbon footprinting for the U.S. electrical grid, and show that differences in standards, protocols, and reporting organizations can lead to important differences in estimates of CO(2) SO(2), and NO(x) emissions factors. We find a considerable divergence in published values for grid emissions factor in the U.S. We discuss the implications of this divergence and list recommendations for a standardized approach to accounting for air pollution emissions in life cycle assessment and policy analyses in a world with incomplete and uncertain information.

Environmental effects of interstate power trading on electricity consumption mixes.

Although many studies of electricity generation use national or state average generation mix assumptions, in reality a great deal of electricity is transferred between states with very different mixes of fossil and renewable fuels, and using the average numbers could result in incorrect conclusions in these studies. We create electricity consumption profiles for each state and for key industry sectors in the U.S. based on existing state generation profiles, net state power imports, industry presence by state, and an optimization model to estimate interstate electricity trading. Using these "consumption mixes" can provide a more accurate assessment of electricity use in life-cycle analyses. We conclude that the published generation mixes for states that import power are misleading, since the power consumed in-state has a different makeup than the power that was generated. And, while most industry sectors have consumption mixes similar to the U.S. average, some of the most critical sectors of the economy--such as resource extraction and material processing sectors--are very different. This result does validate the average mix assumption made in many environmental assessments, but it is important to accurately quantify the generation methods for electricity used when doing life-cycle analyses.