Whether and to what extent natural gas is better than coal or oil with respect to climate impact depends on how much of it escapes into the atmosphere during extraction and transport. Unfortunately, little is known about “fugitive” methane emission rates. With this gap in mind, the Environmental Defense Fund (EDF), partnering with about 90 industry and academic partners, has launched 16 studies that aim to increase our understanding of methane emission rates from key elements of the natural gas system. This grant provides supplemental support for this series of studies, enabling EDF to compare and contrast the relative accuracy of a wide range of methodologies used to quantify methane emissions, and to assess existing and emerging methane monitoring technologies. Their findings, to be published in a final report, will aim to provide an impartial, evidence-based evaluation of the most promising technologies and methodologies for measuring fugitive methane emissions, identify additional research that is needed, and chart a path towards the commercialization and large-scale deployment of well pad methane monitoring systems.

The Bakken Shale in North Dakota and the Eagle Ford Shale in Texas are currently producing well over a million barrels of shale oil per day and have been largely responsible for the recent increase in U.S. domestic oil production and the reduction in U.S. oil imports. Understanding the productive capacity of these plays is essential to understanding how shale oil is likely to shape the future of U.S. energy production. Funds from this grant support a project by the University of Texas at Austin’s Bureau of Economic Geology (BEG) to model the current and future productive capacity of the Bakken and Eagle Ford shale oil plays. Using government and industrial data—some public, some proprietary—the BEG team will conduct a well-by-well analysis to determine the total oil and gas resources in each play, perform decline analyses; calculate current technically recoverable resources; assess acreage drained by existing wells and locations remaining to be drilled; and build a production outlook model that projects the development of acreage and economic reserves over the next 20 years in each basin, given a variety of assumptions about the pace of technology improvement, logistical constraints, and well economics.