Background Information

What is hydraulic fracturing or “hydrofracking”?

High-volume hydraulic fracturing (or “hydrofracking”) is a relatively new technology being used by the oil and gas industry to extract natural gas stored in low permeability natural gas source rocks (e.g. shale gas).  In contrast to conventional oil and natural gas deposits, where oil and gas easily flow from high permeability reservoir rocks, shale gas is found in its original source rock, where the gas is held tightly by low permeability shale (Arthur et al., 2008).

Shale gas basins are found throughout the United States and include the Marcellus Shale of the Appalachian Basin (Kerr, 2010).  The Marcellus Shale is the most expansive shale gas play in the U.S (Kargbo et al., 2010).  The small pore spaces in the shale are not well connected and enhanced extraction methods must be used to release natural gas.  Two advanced drilling techniques, horizontal drilling and hydraulic fracturing, are combined to facilitate the release of shale gas during extraction (Kargbo et al., 2010; Soeder, 2010; Soeder and Kappel, 2009).  Horizontal drilling, where a drill hole extends vertically to depth and then horizontally along a shale gas bed, allows a much greater volume of shale to be accessed from a single drilling platform.  Hydraulic fracturing increases the flow of gas to the horizontal well by creating a network of fractures in the low-permeability shale.  Millions of gallons of water, combined with sand and chemicals, are injected into the well to create extreme pressure and fractures, which are then held open by sand grains.

What are the benefits of increase production of natural gas?

Hydrofracking has unleashed a boom in shale gas production in the United States, with shale gas now providing 45% of the U.S. gas supply, up from around 5% just a decade ago.  There are a number of potential benefits to increased domestic extraction of “clean-burning” shale gas, including a reduced dependence on foreign energy and reduced consumption of relatively dirty coal, oil, and tar sands. Burning natural gas for energy releases less CO2 than burning coal, so it may also serve as a bridging fuel as we develop zero-emission alternative energy sources in the future. Despite its potential benefits, production of shale gas raises a number of environmental concerns for communities underlain by shale gas reserves.

Environmental concerns related to shale gas production are broad and include the industrialization of drill sites, increased heavy vehicle traffic to and from drill pads, and how to supply the vast volumes of water needed for well development (Soeder and Kappel, 2009). One of the greatest environmental concerns is the risk of groundwater and surface water contamination from hydrofracking fluids, released gases, and release of naturally occurring chemicals found deep within the subsurface (Kerr, 2010).  These concerns are amplified by the fact that many areas underlain by shale gas are rural and/or agricultural and there are a large number of private wells in these areas that depend on shallow groundwater for irrigation and domestic water use (Boyer et al., 2011; Osborn et al., 2011a).

During hydrofracking, potentially saline, toxic, and/or radioactive “flowback” water may be introduced into the environment due to migration of the injection fluids and formation waters from the injection wells to shallow aquifers and/or discharge of wastewater to the environment during transport and disposal (Entrekin et al., 2011; Osborn et al., 2011a). Hydraulic fracturing fluids typically include two important sources of contamination: the additives used to create optimal fluids for well stimulation and the metals, dissolved solids, and radionuclides introduced to the flowback water from naturally occurring deep groundwater (Entrekin et al., 2011). Treatment and disposal of flowback waters carries several potential risks for water contamination, including overflow or spills from on-site evaporation and storage ponds, accidents during transport to offsite deep injection wells or treatment facilities, and disposal of inadequately treated recovered wastewater (Entrekin et al., 2011).  In Pennsylvania, nearly half of the 1400 drilling violations between January 2008 and October 2010 were associated with surface water contamination, including direct discharge of pollutants and failure to properly contain wastes (Entrekin et al., 2011).  The U.S. EPA cannot regulate hydraulic fracturing (Kargbo et al., 2010; Kramer, 2011), so regulatory frameworks are different from state to state (Entrekin et al., 2011).

Has hydraulic fracturing in other states caused surface water and groundwater contamination?

The gas industry maintains that there have been no documented cases of groundwater contamination due to hydrofracking (Kramer, 2011) and evidence for contamination of water due to hydraulic fracturing is sparse, controversial and hotly debated (e.g. Davies, 2011; Jackson et al., 2011; Osborn et al., 2011a; Osborn et al., 2011b; Saba and Orzechowski, 2011; Schon, 2011).  Elevated methane in shallow groundwater wells located near shale gas extraction sites has been attributed to gas migration underground due to leaky gas well casings (Osborn et al., 2011a). These findings have been hotly contested, with criticism of the small, nonrandom dataset size (Davies, 2011; Saba and Orzechowski, 2011) and the lack of pre-hydraulic fracturing baseline data (Davies, 2011; Schon, 2011).

There is little documented evidence to date that shallow groundwater wells over the Marcellus Shale have been contaminated by introduction of fracturing fluids, flowback water, or formation water.  In contrast, recent well sampling in Wyoming has indicated the presence of drilling-related chemicals in several wells near extraction sites (Kargbo et al., 2010). One recent study by Boyer et al. (2011) found no significant change in post-hydraulic fracturing water quality over much of Pennsylvania. Two possible conclusions can be drawn from the Boyer et al. study: there is no detectable contamination, or the parameters measured in their water chemistry analysis may not be effective to unequivocally detect low-levels of brine and fracking fluid contamination.

How can we detect contamination of surface water and ground water from fracturing fluids?

There are several challenges to definitively identifying contamination of surface or ground water due to hydrofracking, not the least of which is the real possibility of other sources of water contamination in the human-impacted watersheds in which drilling is taking place (Entrekin et al., 2011).  For example, as many as 40% of private water wells in Pennsylvania failed to meet drinking water standards even before hydraulic fracturing began (Boyer et al., 2011).  Other potential sources of contamination in regions with hydraulic fracturing include mine drainage, brines from abandoned, shallow oil and gas wells, road salt, wastewater effluent, and industrial discharge (Chapman et al., 2012).  Natural conditions can also complicate interpretations of potential contamination of shallow groundwater; in regions of Pennsylvania, water wells located in low elevation valley areas have significantly higher dissolved methane levels than water wells in upland areas, regardless of the proximity to gas extraction wells (Molofsky et al., 2011).  In the context of these complicating factors, hydraulic fracturing has been blamed for a variety of types of water contamination, ranging from the presence of pharmaceuticals to contamination by gasoline (Soeder, 2010).

Flowback water, which includes the fracturing fluids and deep groundwater, may have a distinct elemental and isotopic composition that allows for the development of geochemical fingerprinting tools that distinguish contamination due to hydraulic fracturing fluids from other sources of contamination (Entrekin et al., 2011), although there are only a few geochemical parameters that can definitively distinguish among all possible sources of contamination (Chapman et al., 2012).  Shale gas flowback water from the Marcellus Shale has a chemical composition similar to deep groundwater found in other Appalachain Basin formations (Osborn and McIntosh, 2010), is dominated by calcium, sodium, and chloride, and has metal concentrations consistent with deep Appalachian Basin brines (Chapman et al., 2012; Siegel et al., 1991; Soeder, 2010). Total dissolved solids (TDS), bromide, and ratios of halogens and major solutes (e.g. chloride, bromide, calcium) have been proposed as potentially distinct tracers of groundwater contamination by hydraulic fracturing fluids and flowback waters (Boyer et al., 2011; Kight and Siegel, 2011; Soeder, 2010).  Additionally, the isotopic composition of flowback waters is distinct from the isotopic composition of shallow groundwaters with respect to strontium isotopes (87Sr/86Sr) and iodine-129 (129I) (Brinck and Frost, 2007; Chapman et al., 2012; Osborn et al., 2012). The unique isotopic composition may be used to differentiate Marcellus Formation water from other potential sources of high TDS to surface and ground waters (Chapman et al., 2012).

Several researchers have argued that baseline measurements before and after hydraulic fracturing are needed to effectively test whether hydraulic fracturing has caused groundwater contamination (Davies, 2011; Schon, 2011).  There is also a need for a publicly-available database of surface water, groundwater, fracturing fluid and flowback water chemistry (Jackson et al., 2011), particularly given that gas companies typically withhold environmental quality data from public view (Entrekin et al., 2011; Kargbo et al., 2010).  This dataset needs to have a large sample size, random distribution of samples, and cover a broad area.  Research is also needed to identify an appropriate, standardized list of minimum required testing parameters for pre-drilling water quality testing, which is commonly done by the gas industry to avoid the presumption of responsibility in the case of post-drilling water pollution (Boyer et al., 2011).

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