Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Liquid Unloadings

Methane emissions from liquid unloadings were measured at 107 wells in natural gas production regions throughout the United States. Liquid unloadings clear wells of accumulated liquids to increase production, employing a variety of liquid lifting mechanisms. In this work, wells with and without plunger lifts were sampled. Most wells without plunger lifts unload less than 10 times per year with emissions averaging 21 000–35 000 scf methane (0.4–0.7 Mg) per event (95% confidence limits of 10 000–50 000 scf/event). For wells with plunger lifts, emissions averaged 1000–10 000 scf methane (0.02–0.2 Mg) per event (95% confidence limits of 500–12 000 scf/event). Some wells with plunger lifts are automatically triggered and unload thousands of times per year and these wells account for the majority of the emissions from all wells with liquid unloadings. If the data collected in this work are assumed to be representative of national populations, the data suggest that the central estimate of emissions from unloadings (270 Gg/yr, 95% confidence range of 190–400 Gg) are within a few percent of the emissions estimated in the EPA 2012 Greenhouse Gas National Emission Inventory (released in 2014), with emissions dominated by wells with high frequencies of unloadings

Changing the spatial location of electricity generation to increase water availability in areas with drought: a feasibility study and quantification of air quality impacts in Texas

The feasibility, cost, and air quality impacts of using electrical grids to shift water use from drought-stricken regions to areas with more water availability were examined. Power plant cooling represents a large portion of freshwater withdrawals in the United States, and shifting where electricity generation occurs can allow the grid to act as a virtual water pipeline, increasing water availability in regions with drought by reducing water consumption and withdrawals for power generation. During a 2006 drought, shifting electricity generation out of the most impacted areas of South Texas (~10% of base case generation) to other parts of the grid would have been feasible using transmission and power generation available at the time, and some areas would experience changes in air quality. Although expensive, drought-based electricity dispatch is a potential parallel strategy that can be faster to implement than other infrastructure changes, such as air cooling or water pipelines.National Science Foundation (U.S.). Office of Emerging Frontiers in Research and Innovation (Grant 0835414)United States. Dept. of Energ

Spatial and Temporal Impacts on Water Consumption in Texas from Shale Gas Development and Use

Despite the water intensity of hydraulic fracturing, recent life cycle analyses have concluded that increased shale gas development will lead to net decreases in water consumption if the increased natural gas production is used at natural gas combined cycle power plants, shifting electricity generation away from coal-fired steam cycle power plants. This work expands on these studies by estimating the spatial and temporal patterns of changes in consumptive water use in Texas river basins during a period of rapid shale gas development and use in electricity generation from August 2008 through December 2009. While water consumption decreased in Texas overall, some river basins saw increased water consumption and others saw decreased water consumption, depending on the extent of extraction activity in the basin, the mix of power plants using cooling water in that basin, and price-based changes in the power sector. Due to the temporal and spatial heterogeneity in the consumptive water impacts of natural gas development and use in the power sector, local and regional water use impacts must also be considered in addition to the overall supply chain impacts

Regional Ozone Impacts of Increased Natural Gas Use in the Texas Power Sector and Development in the Eagle Ford Shale

The combined emissions and air quality impacts of electricity generation in the Texas grid and natural gas production in the Eagle Ford shale were estimated at various natural gas price points for the power sector. The increased use of natural gas in the power sector, in place of coal-fired power generation, drove reductions in average daily maximum 8 h ozone concentration of 0.6–1.3 ppb in northeastern Texas for a high ozone episode used in air quality planning. The associated increase in Eagle Ford upstream oil and gas production nitrogen oxide (NO_<i>x</i>) emissions caused an estimated local increase, in south Texas, of 0.3–0.7 ppb in the same ozone metric. In addition, the potential ozone impacts of Eagle Ford emissions on nearby urban areas were estimated. On the basis of evidence from this work and a previous study on the Barnett shale, the combined ozone impact of increased natural gas development and use in the power sector is likely to vary regionally and must be analyzed on a case by case basis

Regional Air Quality Impacts of Increased Natural Gas Production and Use in Texas

Natural gas use in electricity generation in Texas was estimated, for gas prices ranging from $1.89 to$7.74 per MMBTU, using an optimal power flow model. Hourly estimates of electricity generation, for individual electricity generation units, from the model were used to estimate spatially resolved hourly emissions from electricity generation. Emissions from natural gas production activities in the Barnett Shale region were also estimated, with emissions scaled up or down to match demand in electricity generation as natural gas prices changed. As natural gas use increased, emissions decreased from electricity generation and increased from natural gas production. Overall, NO_<i>x</i> and SO₂ emissions decreased, while VOC emissions increased as natural gas use increased. To assess the effects of these changes in emissions on ozone and particulate matter concentrations, spatially and temporally resolved emissions were used in a month-long photochemical modeling episode. Over the month-long photochemical modeling episode, decreases in natural gas prices typical of those experienced from 2006 to 2012 led to net regional decreases in ozone (0.2–0.7 ppb) and fine particulate matter (PM) (0.1–0.7 μg/m³). Changes in PM were predominantly due to changes in regional PM sulfate formation. Changes in regional PM and ozone formation are primarily due to decreases in emissions from electricity generation. Increases in emissions from increased natural gas production were offset by decreasing emissions from electricity generation for all the scenarios considered

Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers

Emissions from 377 gas actuated (pneumatic) controllers were measured at natural gas production sites and a small number of oil production sites, throughout the United States. A small subset of the devices (19%), with whole gas emission rates in excess of 6 standard cubic feet per hour (scf/h), accounted for 95% of emissions. More than half of the controllers recorded emissions of 0.001 scf/h or less during 15 min of measurement. Pneumatic controllers in level control applications on separators and in compressor applications had higher emission rates than controllers in other types of applications. Regional differences in emissions were observed, with the lowest emissions measured in the Rocky Mountains and the highest emissions in the Gulf Coast. Average methane emissions per controller reported in this work are 17% higher than the average emissions per controller in the 2012 EPA greenhouse gas national emission inventory (2012 GHG NEI, released in 2014); the average of 2.7 controllers per well observed in this work is higher than the 1.0 controllers per well reported in the 2012 GHG NEI