W. Michael Griffin

Life cycle greenhouse gas emissions of Marcellus shale gas

This study estimates the life cycle greenhouse gas (GHG) emissions from the production of Marcellus shale natural gas and compares its emissions with national average US natural gas emissions produced in the year 2008, prior to any significant Marcellus shale development. We estimate that the development and completion of a typical Marcellus shale well results in roughly 5500 t of carbon dioxide equivalent emissions or about 1.8 g CO2e/MJ of gas produced, assuming conservative estimates of the production lifetime of a typical well. This represents an 11% increase in GHG emissions relative to average domestic gas (excluding combustion) and a 3% increase relative to the life cycle emissions when combustion is included. The life cycle GHG emissions of Marcellus shale natural gas are estimated to be 63‐75 g CO2e/MJ of gas produced with an average of 68 g CO2e/MJ of gas produced. Marcellus shale natural gas GHG emissions are comparable to those of imported liquefied natural gas. Natural gas from the Marcellus shale has generally lower life cycle GHG emissions than coal for production of electricity in the absence of any effective carbon capture and storage processes, by 20‐50% depending upon plant efficiencies and natural gas emissions variability. There is significant uncertainty in our Marcellus shale GHG emission estimates due to eventual production volumes and variability in flaring, construction and transportation.

Uncertainty in Life Cycle Greenhouse Gas Emissions from United States Natural Gas End-Uses and its Effects on Policy

Increasing concerns about greenhouse gas (GHG) emissions in the United States have spurred interest in alternate low carbon fuel sources, such as natural gas. Life cycle assessment (LCA) methods can be used to estimate potential emissions reductions through the use of such fuels. Some recent policies have used the results of LCAs to encourage the use of low carbon fuels to meet future energy demands in the U.S., without, however, acknowledging and addressing the uncertainty and variability prevalent in LCA. Natural gas is a particularly interesting fuel since it can be used to meet various energy demands, for example, as a transportation fuel or in power generation. Estimating the magnitudes and likelihoods of achieving emissions reductions from competing end-uses of natural gas using LCA offers one way to examine optimal strategies of natural gas resource allocation, given that its availability is likely to be limited in the future. In this study, the uncertainty in life cycle GHG emissions of natural gas (domestic and imported) consumed in the U.S. was estimated using probabilistic modeling methods. Monte Carlo simulations are performed to obtain sample distributions representing life cycle GHG emissions from the use of 1 MJ of domestic natural gas and imported LNG. Life cycle GHG emissions per energy unit of average natural gas consumed in the U.S were found to range between -8 and 9% of the mean value of 66 g CO(2)e/MJ. The probabilities of achieving emissions reductions by using natural gas for transportation and power generation, as a substitute for incumbent fuels such as gasoline, diesel, and coal were estimated. The use of natural gas for power generation instead of coal was found to have the highest and most likely emissions reductions (almost a 100% probability of achieving reductions of 60 g CO(2)e/MJ of natural gas used), while there is a 10-35% probability of the emissions from natural gas being higher than the incumbent if it were used as a transportation fuel. This likelihood of an increase in GHG emissions is indicative of the potential failure of a climate policy targeting reductions in GHG emissions.

Impact of biofuel crop production on the formation of hypoxia in the Gulf of Mexico.

Many studies have compared corn-based ethanol to cellulosic ethanol on a per unit basis and have generally concluded that cellulosic ethanol will result in fewer environmental consequences, including nitrate (NO3(-)) output. This study takes a system-wide approach in considering the NO3(-) output and the relative areal extent of hypoxia in the Northern Gulf of Mexico (NGOM) due to the introduction of additional crops for biofuel production. We stochastically estimate NO3(-) loading to the NGOM and use these results to approximate the areal extent of hypoxia for scenarios that meet the Energy Independence and Security Act of 2007s biofuel goals for 2015 and 2022. Crops for ethanol include corn, corn stover, and switchgrass; all biodiesel is assumed to be from soybeans. Our results indicate that moving from corn to cellulosics for ethanol production may result in a 20-percent decrease (based on mean values) in NO3(-) output from the Mississippi and Atchafalaya River Basin (MARB). This decrease will not meet the EPA target for hypoxic zone reduction. An aggressive nutrient management strategy will be needed to reach the 5000 km2 areal extent of hypoxia in the NGOM goal set forth by the Mississippi River/Gulf of Mexico Watershed Nutrient Task Force even in the absence of biofuels, given current production to meet food, feed, and other industrial needs.

Life cycle inventory of CO2 in an enhanced oil recovery system.

Enhanced oil recovery (EOR) has been identified as a method of sequestering CO(2) recovered from power plants. In CO(2)-flood EOR, CO(2) is injected into an oil reservoir to reduce oil viscosity, reduce interfacial tension, and cause oil swelling which improves oil recovery. Previous studies suggest that substantial amounts of CO(2) from power plants could be sequestered in EOR projects, thus reducing the amount of CO(2) emitted into the atmosphere. This claim, however, ignores the fact that oil, a carbon rich fuel, is produced and 93% of the carbon in petroleum is refined into combustible products ultimately emitted into the atmosphere. In this study we analyze the net life cycle CO(2)emissions in an EOR system. This study assesses the overall life cycle emissions associated with sequestration via CO(2)-flood EOR under a number of different scenarios and explores the impact of various methods for allocating CO(2) system emissions and the benefits of sequestration.

Natural gas fugitive emissions rates constrained by global atmospheric methane and ethane

The amount of methane emissions released by the natural gas (NG) industry is a critical and uncertain value for various industry and policy decisions, such as for determining the climate implications of using NG over coal. Previous studies have estimated fugitive emissions rates (FER)--the fraction of produced NG (mainly methane and ethane) escaped to the atmosphere--between 1 and 9%. Most of these studies rely on few and outdated measurements, and some may represent only temporal/regional NG industry snapshots. This study estimates NG industry representative FER using global atmospheric methane and ethane measurements over three decades, and literature ranges of (i) tracer gas atmospheric lifetimes, (ii) non-NG source estimates, and (iii) fossil fuel fugitive gas hydrocarbon compositions. The modeling suggests an upper bound global average FER of 5% during 2006-2011, and a most likely FER of 2-4% since 2000, trending downward. These results do not account for highly uncertain natural hydrocarbon seepage, which could lower the FER. Further emissions reductions by the NG industry may be needed to ensure climate benefits over coal during the next few decades.

Implications of changing natural gas prices in the United States electricity sector for SO2, NOX and life cycle GHG emissions

Projections of increased domestic natural gas supply and low prices have encouraged increased natural gas utilization in the United States electricity sector. Natural gas can offset coal, likely decreasing overall greenhouse gas (GHG) emissions and other air emissions such as SO2 and NOX. Previous life cycle assessment (LCA) studies using limited system boundaries have attempted to quantify the benefit of offsetting coal use. However, these studies do not consider that relative regional fuel prices may contribute most to the choice of coal over natural gas. External incentives such as low natural gas prices compared to coal are required if natural gas is to displace coal. In this study, simplified economic dispatch models are used to determine how natural gas utilization will increase in the short-term in response to changes in natural gas prices in three US grid regions—ERCOT, MISO and PJM. The results indicate that the change in air emissions is lower than suggested by LCAs, since LCAs generally do not include the complexity of regional electricity grids. For instance, this study estimates that life cycle GHG emissions may, at best, decrease by 7‐15% due to low natural gas prices, compared to almost 50% reductions estimated by previous LCAs.

Implications of near-term coal power plant retirement for SO2 and NOX and life cycle GHG emissions.

Regulations monitoring SO(2), NO(X), mercury, and other metal emissions in the U.S. will likely result in coal plant retirement in the near-term. Life cycle assessment studies have previously estimated the environmental benefits of displacing coal with natural gas for electricity generation, by comparing systems that consist of individual natural gas and coal power plants. However, such system comparisons may not be appropriate to analyze impacts of coal plant retirement in existing power fleets. To meet this limitation, simplified economic dispatch models for PJM, MISO, and ERCOT regions are developed in this study to examine changes in regional power plant dispatch that occur when coal power plants are retired. These models estimate the order in which existing power plants are dispatched to meet electricity demand based on short-run marginal costs, with cheaper plants being dispatched first. Five scenarios of coal plant retirement are considered: retiring top CO(2) emitters, top NO(X) emitters, top SO(2) emitters, small and inefficient plants, and old and inefficient plants. Changes in fuel use, life cycle greenhouse gas emissions (including uncertainty), and SO(2) and NO(X) emissions are estimated. Life cycle GHG emissions were found to decrease by less than 4% in almost all scenarios modeled. In addition, changes in marginal damage costs due to SO(2), and NO(X) emissions are estimated using the county level marginal damage costs reported in the Air Pollution Emissions Experiments and Policy (APEEP) model, which are a proxy for measuring regional impacts of SO(2) and NO(X) emissions. Results suggest that location specific parameters should be considered within environmental policy frameworks targeting coal plant retirement, to account for regional variability in the benefits of reducing the impact of SO(2) and NO(X) emissions.

Alternative transport fuels for the future

Petroleum fuels, which are not sustainable and which contribute substantially to greenhouse gas emissions, power nearly all light-duty vehicles. We review the North American literature on alternative fuels such as natural gas, ethanol from corn and biomass, and hydrogen and electricity from renewable resources, as well as propulsion systems including internal combustion engines, electric motors, and fuel cells. Vehicle characteristics including emissions, safety and consumer attributes such as range and power are examined. Results for greenhouse gas emissions and energy use for the well-to-wheel (fuel production and vehicle operation) aspects of the life cycles of the fuel/vehicle combinations are evaluated. While fuel cells and batteries might some day be attractive, in the near term they cannot replace the internal combustion engine. We focus on ethanol and explore its potential to replace nearly all gasoline used in the United States and Canada. We conclude that ethanol produced from biomass is an attractive near/midterm fuel among those that are sustainable.

Life cycle greenhouse gas emissions from U.S. liquefied natural gas exports: implications for end uses.

This study analyzes how incremental U.S. liquefied natural gas (LNG) exports affect global greenhouse gas (GHG) emissions. We find that exported U.S. LNG has mean precombustion emissions of 37 g CO2-equiv/MJ when regasified in Europe and Asia. Shipping emissions of LNG exported from U.S. ports to Asian and European markets account for only 3.5-5.5% of precombustion life cycle emissions, hence shipping distance is not a major driver of GHGs. A scenario-based analysis addressing how potential end uses (electricity and industrial heating) and displacement of existing fuels (coal and Russian natural gas) affect GHG emissions shows the mean emissions for electricity generation using U.S. exported LNG were 655 g CO2-equiv/kWh (with a 90% confidence interval of 562-770), an 11% increase over U.S. natural gas electricity generation. Mean emissions from industrial heating were 104 g CO2-equiv/MJ (90% CI: 87-123). By displacing coal, LNG saves 550 g CO2-equiv per kWh of electricity and 20 g per MJ of heat. LNG saves GHGs under upstream fugitive emissions rates up to 9% and 5% for electricity and heating, respectively. GHG reductions were found if Russian pipeline natural gas was displaced for electricity and heating use regardless of GWP, as long as U.S. fugitive emission rates remain below the estimated 5-7% rate of Russian gas. However, from a country specific carbon accounting perspective, there is an imbalance in accrued social costs and benefits. Assuming a mean social cost of carbon of

Inventory Development and Input-Output Model of U.S. Land Use: Relating Land in Production to Consumption

49/metric ton, mean global savings from U.S. LNG displacement of coal for electricity generation are