15.2.1 US EPA Study

Detailed national statistics (US EPA 2015e) about spills at hydraulic fracturing sites are not available, but using the following state information, estimates can be made: on‐site spills at the HVHF well pads range from an estimate of one spill for every 100 wells in Colorado to between 0.4 and 12.2 spills per 100 wells in Pennsylvania (US EPA 2015e). If the Pennsylvania and Colorado estimates are representative, the number of spills in the United States could range from about 100–3 700 spills yearly, assuming 25 000–30 000 new unconventional oil and gas wells are fractured each year. The US EPA characterized volumes and causes of hydraulic fracturing‐related spills identified from selected state and industry data sources. US EPA (2015f) compiled incidents of spills over the period of January 2006 to April 2012 in 11 states and included 151 cases in which fracturing fluids or chemicals were spilled on or near a HVHF well pad. These cases from only 11 states underestimate the total fracturing fluid and chemical spills in the United States during this period. The reported volume of fracturing fluids or HVHF chemicals spilled ranged from 5 gal to more than 19 000 gal (19–72 000 l), with an average volume of 420 gal (1 600 L) per spill. Spill causes are due to (i) equipment failure, (ii) human error, (iii) failure of container integrity, and (iv) unknown or other causes not specified or causes such as weather and vandalism. The most common cause was equipment failure and more specifically blowout preventer failure, equipment corrosion, and failed valves. Greater than 30% of the 151 total spills of chemicals or fracturing fluid were from fluid storage units such as aboveground storage tanks, totes, and trailers (US EPA 2015g). As there is no data, unreported spill volumes were not estimated.

15.2.2 Patterson and Others (2017)

In a 10‐year study related to unconventional oil and gas spills, Patterson et al. (2017) reviewed similar publicly available data from Colorado, New Mexico, North Dakota, and Pennsylvania between 2005 and 2014; some of the data were likely included in the US EPA (2015a, b, c, d, e) study. During 2005–2014, data from 31 481 HVHF wells were evaluated for documented spills. The analysis of the public records in the 4 states identified a total of 6647 during the 10‐year period. The study noted 2–16% of wells were reported to have a spill each year. The liquids spilled included petroleum hydrocarbons, chemical‐laden water, hydraulic fracturing fluids, and other substances. The average spill volume ranged from 0.5 m³ in Pennsylvania to a high of 1294 gal (4.9 m³) in New Mexico. The largest spills exceeded 26 417 gal (100 m³). A significant number of the spills, 75–94%, occurred within the first 36 months of well life when the unconventional oil and gas wells were drilled and completed and had their largest production volumes. Across all four states in the study, 50% of spills were related to storage and moving fluids through flowlines. The study also found that a significant portion of spills, 53% in North Dakota and 26% in Colorado, occur at well sites that have already reported at least one spill incident. More rigorous equipment inspections, improved emergency response training, better communication on safe chemical handling practices, additional spill prevention measures, and a higher level of regulatory oversight could help to reduce spillage at well sites with multiple spills.

It should be noted that the data reviewed were not uniformly described in the state data files and reporting rates varied by state, affecting the overall spill rates and consistency, illustrating the high value of having standardized public data (Patterson et al. 2017). The state reporting the highest level of spills was North Dakota with recorded 4453 incidents. North Dakota had a high level of drilling activity during that period because any spill bigger than 42 US gallons (0.16 m³) or the volume of a standard US oil barrel has to be reported, which likely increases the number of spills compared with the other states with higher minimum reportable spill volumes (Patterson et al. 2017). The data is summarized in Tables 15.3, 15.4, 15.5, and 15.6.

Even with a possible spill pathway, there were only two documented spills through well communication between 2005 and 2014.

The study also looked at setbacks. In total, 7% of all spills were within 100 ft (30.5 m) setback of a stream or creek, 13.3% were within 200 ft (61.0 m) setback, 20.4% were within 300 ft (91.4 m), and 47.1% were within 750 ft (228.6 m) setback. The state with the smallest setback regulation is Pennsylvania at 100 ft (30.5 m), and 5.3% of the spills in the state were within this distance to a creek or stream (Patterson et al. 2017).

15.3.1 Rail Case Studies

There has been a major increase in unconventional crude oil production in North Dakota and nearby states and there has been a general lack of available pipeline capacity from oil fields to refineries on the East and Gulf Coast of the United States and rail transportation of crude oil across North America. The increase in unconventional crude oil production and associated rail transportation is reflected in the modest 9 500 unit cars used in 2008 compared to 435 560 unit cars used in 2013 (Congressional Research Service 2014). Even though several high‐profile accidents (see Table 15.7, Appendix I) have resulted in significant damage to public welfare and the environment, the overall trend of accidents is decreasing due to improved railcar design, increased infrastructure, improved procedures, better worker training, more regulatory oversight, and other factors. The potential for a catastrophic release along rail lines still remains high, and the safety and environmental risks of transporting Bakken crude oil by rail have increased due to larger volumes of product shipped and the larger distances traveled. On average Bakken crude oil shipments are transported over 1000 mi from point of origin in the Williston Basin to the major refineries on the US coasts (DOT 2013).

The Bakken crude oil characteristics were evaluated by the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Federal Railroad Administration (FRA) by testing 135 samples from August 2013 to May 2014, and the findings showed that the unconventional oil character is consistent with those of a class III flammable liquid, PG I or II, with a predominance of PG I, the most dangerous class of class III flammable liquids (PHMSA 2014). Although this lightweight sweet crude oil does not exhibit the characteristics of a flammable gas, corrosive liquid, or toxic material, it is more volatile than most other types of crude oil, which correlates to increased ignitability and flammability.

The volatility tests by the PHMSA tests indicate that the Bakken contains flammable dissolved gases that raise the vapor pressure and lower the flash point and reduce the initial boiling point of the oil. These characteristics reflect higher concentrations of light‐end hydrocarbons, which tend to vaporize. DOT requested the American Fuel & Petrochemical Manufacturers (AFPM) to conduct a survey of members to address questions raised by DOT. AFPM also collected data from chemical analysis of ~1400 samples of Bakken crude oil. The two chemical studies (PHMSA and AFPM) show some of the natural variations typical of the Bakken crude oil (AFPM 2014; PHMSA 2014).

15.3.2 Bakken Crude Oil Characteristics: Two Studies

A summary of Bakken crude oil characteristics is shown in Table 15.8.

Because of the volatility of the Bakken crude oil, there is an increased safety risk of a major accident due to the significant volume being transported, the routes and the extremely long distances the oil is transported by rail. Trains transporting Bakken crude oil are called unit trains, and they commonly contain more than 100 tank cars, carrying at least 2.5 million gallons (9464 m³) within a single train. Unit trains only carry a single type of product, in this case flammable Bakken crude oil. The crude shipments are transported over a thousand miles (1609 km) from the Williston Basin in North Dakota to coastal US refineries.

Dissolved flammable gases within the Bakken crude oil are released into the vapor space of rail tank cars as the ambient temperature increases. In the event of a spill or catastrophic release, the gases trapped in the rail tank car vapor space increase flammability and inhalation hazard risks. The main hazard associated with Bakken crude oil in a rail accident is flammability, resulting in explosions, fireballs, and pool fires. A major aboveground tank rupture or pipeline leak may result in an explosion and fireball after the spilled Bakken crude oil vaporizes and contacts an ignition source. A photo of the Casselton, North Dakota, fireball shows the explosion in process (Figure 15.2). The pileup of Bakken crude oil tanker cars south of Aliceville, Alabama, (US EPA 2013b) shows the extent of the derailment into the wetland environment (Figure 15.3).

15.3.3 Summary of Bakken Crude Oil Spill Incidents

Bakken crude oil rail accidents are summarized in Table 15.9 (MassDEP 2015).

15.3.4 Fate and Transport of Spilled Crude

The major migration pathways from a surface Bakken crude oil spill from a rail accident or tank failure (Table 15.10) might include a variety of media to sample depending on the active processes ().

modified after MassDEP (2015)

15.3.5 Combustion

Intentional (or uncontrolled) burning of Bakken crude oil released during train accidents emits the following hazardous compounds into the air (Lemieux et al. 2004). Those compounds which are not shown in the table are sulfur dioxide, carbon monoxide, and particulates; these are common in Bakken crude oil emissions from burns (Table 15.11).

15.3.6 DOT‐117 Tank Car Design

The 2013 train disaster in Lac‐Mégantic, Quebec, proved the need for improved safety in tank car design, while transporting Bakken crude and other flammable substances. Unlike in DOT‐111 tank cars, new regulations were developed effective 1 October 2015 for DOT‐117 tank cars, which feature improvements for unpressurized tank car design to transport flammable liquids such as crude oil and ethanol (DOT 2016; NTSB 2015; PHMSA 2017). The DOT‐117 (Figure 15.4) standard includes the following:

• Normalized steel heads and shields.
• ½‐in full head shields (full height).
• Tank material: head and shell thickness (9/16 in).
• Top fittings protection.
• ½‐in ceramic insulation.
• Steel jackets (complete).
• High flow pressure relief valve.
• Improved bottom outlet valve handle.

15.5.1 Gas Chromatograms

It has been estimated that an average crude oil has about 100 000 different compounds and the use of ultrahigh‐resolution mass analysis can separate and identify tens of thousands of these compounds (Marshall and Rodgers 2008). A gas chromatograph (GC), a primary tool in chemical laboratory business, can identify about 1000 compounds in crude oil. Chemists even use the term “fingerprint” evaluation for the forensic task of examining laboratory data to determine and differentiate sample sources, weathering, or other processes that may have modified sample characteristics. GCs have long been used to “fingerprint” crude oils for geochemical differentiation (McCaffrey et al. 2011, 2017). The number of possible analytes for coproduced water is exceedingly large (Figure 15.5). The relative abundance or ratios of specific elements or compounds and their isotopes to other analytes, the amount of weathering in a sample, or even the low concentrations of tentatively identified compounds (TICs) are all used in the multiple lines of evidence to identify the sources of hydrocarbons and other contaminants.

15.5.2 Tentatively Identified Compounds (TICs)

Laboratory‐reported TICs from VOC and SVOC analyses can sometimes provide clues to the presence of chemicals, which may help to identify potential sources of contamination. TICs are compounds that can be detected by the laboratory analytical methods, but, without the analysis of standards, these chemicals cannot be confirmed or reliably quantified. To be identified as a TIC, a chromatogram peak has to have an area of at least 10% as large as the area of the nearest internal standard as well as a match quality >80% (US EPA 2015e). The TIC match quality is based on the number and ratio of the major fragmentation ions. A TIC value of 99 is a perfect match. Although the TIC report is essentially a qualitative report, an estimated concentration can be calculated based on a response factor of 1.00 and the area of the nearest internal standard. Frequently, TICs are representative of a class of compounds rather than indicating a specific compound (US EPA 2015e), and in some cases, TICs can be useful in providing diagnostic forensic information. An example might be a TIC of 2‐butoxyethanol (C₆H₁₄O₂), a glycol ether that could be used as a hydraulic surfactant or foaming agent. Although the TIC indicates minute quantities below standard reporting levels, the presence of 2‐butoxyethanol can be important nonetheless. In the absence of other potential chemical sources, 2‐butoxyethanol could, with other lines of supporting evidence, provide a chemical source from HVHF operations. An example VOC analysis chromatogram shows four TICs identified: acetic acid, toluene, heptane, and D‐limonene (Figure 15.6). The joint presence or specific industrial uses of the TICs may help to provide evidence of the source of the contaminants.

15.5.3 Piper Diagrams

Specific ion chemistry, when plotted on a piper diagram, can be used to help differentiate between multiple sources of water, using anion and cation ratios (Figure 15.7; Table 15.13). The piper diagram shows data from the US EPA Northeast Pennsylvania retrospective case study (US EPA 2015a), which is described later in this chapter. Piper diagrams can frequently be used to identify water sources related to specific aquifers, fluids used in unconventional oil and gas operations, or waters used in agricultural or industrial activities, based on dissolved anions and cations. The three points of the cation plot (left side of Figure 15.7) are calcium, magnesium, and sodium plus potassium cations. The points of the anion plot are sulfate, chloride, and bicarbonate and carbonate anions. The two triangular‐shaped ternary plots are then projected upward onto a diamond plot. The diamond plot is a graph of the anions (sulfate and chloride/total anions) and cations (sodium and potassium/total cations). In this case, water containing different ratios of dissolved salts have been identified using the piper diagram.

15.5.4 Biomarkers

Biomarkers, complex molecules derived originally from formerly living organisms, are found in petroleum and include pristane, phytane, porphyrin, steranes, and triterpanes. There is little change in their structures where they are detected in the range of several hundred mg l⁻¹ or parts per million (ppm) (Peters et al. 2007a, b). Biomarkers have been used for a variety of chemical fingerprinting studies relating to the origin of the petroleum, the types of the precursor organic matter in the petroleum source rock, the correlation of the crude oil with the organic material found in the source rocks, the environmental conditions of sediment deposition, the assessment of thermal maturity, the thermal history of the crude oil, the degree of biodegradation, the later alteration, and the information as to the age of the source rock (Fingas 2010).

Used as biomarkers for phytoplankton, isoprenoids pristane and phytane primarily originate from the phytol side chain of the chlorophyll molecule (Didyk et al. 1978; Volkman and Maxwell 1986) and their identification can be useful (Figure 15.8). Biomarker compounds are usually identified using gas chromatography‐mass spectrometry (GC‐MS) techniques. Although isoprenoids may comprise <5% of diesel fuel, these branched alkanes have a chemical structure that generally inhibits biodegradation, so they are usually preserved and can be relied upon as diagnostic compounds.

15.5.4.1 Compound‐Specific Isotope Analysis

When organic compounds, including petroleum hydrocarbons, degrade in the environment, the ratio of stable isotopes will often change over time. Different leaks or spills of the same material at different times may have different isotopic fingerprints or signatures that can be used for identification. Weathering processes include evaporation, emulsification, adsorption, dispersion, dissolution, oxidation–reduction reactions, and biodegradation. Compound‐specific isotope analysis (CSIA) is the technique used to assess biodegradation and source identification of organic contaminants in groundwater (Hunkeler et al. 2008). The CSIA uses a GC with an isotope‐ratio mass spectrometer (GC‐IRMS) to better differentiate comingled plumes of the same chemical compounds (Figure 15.9).

CSIA is based on the concept that atoms of a specific element must have the same number of protons and electrons, but they can have a different number of neutrons. When atoms differ only in the number of neutrons, they are referred to as isotopes of each other. If a particular isotope is not radioactive, it is called a stable isotope. Because they differ in the number of neutrons, a mass spectrometer is used to identify different isotopes of the same element, which differ in mass (Hunkeler et al. 2008). CSIA is also used to evaluate naturally occurring organic compounds such as aromatic compounds, diamondoids, isoprenoids, and n‐alkanes.

15.5.5 Chemical and Biological Transformations

Some parent compounds, such as tetrachloroethene (PCE), tetrachloroethane (PCA), and 1,2‐dichloroethane (1,2‐DCA), show transformations related to biological or abiotic processes (Figure 15.10). These compounds are industrial cleaners and solvents.

A variety of compounds that are likely to be encountered at the well pad such as benzene, toluene, ethylbenzene, and xylene (BTEX) compounds are naturally found in crude oil as well as refined products such as gasoline, diesel, and kerosene. Sorption, volatilization, and other abiotic processes also transform chemicals over time. BTEX compounds can degrade with both the faster aerobic or slower anaerobic biodegradation pathways (Figure 15.11).

For an aerobic biodegradation process, benzene ultimately breaks down to carbon dioxide and water through this general process:

The co‐metabolic degradation pathway occurs when microbial communities using one compound as an energy source produce an enzyme that chemically transforms and degrades another compound present at the same location. In some cases, analytical chemistry such as US EPA Method 8260B/C GC‐MS and understanding redox conditions can be used to explain degradation products and the ratio of parent compound to degradation products. However, not all compounds can be identified by current laboratory analytical methods.

A variety of molecular diagnostic tools can identify microbial communities and site‐specific organisms. Direct DNA isolation from soil or water samples, denaturing gradient gel electrophoresis (DGGE), polymerase chain reaction (PCR) methods, enzyme activity probes (EAPs), and nucleic acid hybridization (NAH) are a few of the molecular biology techniques providing information on the biological communities in areas with contaminated soil or groundwater. Using these advanced biochemical diagnostic tools can enable more cost‐effective and efficient bioremediation, as well as providing more biochemical evidence of microbial activity in the subsurface and possible parent chemicals and source locations.

15.5.6 Chemical Ratios

Chemical ratios have been used successfully to distinguish among various sources of stray gas. There are multiple salinity sources in the environment (Vengosh et al. 2011), and detailed geochemistry is needed to evaluate the potential salt sources (Table 15.14). The household compound, sodium chloride (NaCl) or common table salt, also provides a good example of the complexities of source identification in the subsurface. For example, the ratio of bromide/chloride (Br/Cl) to chloride can be used to differentiate among background groundwater, groundwater affected by septic sources, and groundwater affected by road salt, backflow, and brine waters (Kight and Siegel 2011).

15.5.7 Geochemical Tracers

Geochemical tracers are a specific substance used to trace the course of a process. It may be an element or compound that can be tracked and identified throughout chemical or biological processes by its chemical characteristics such as unusual isotopic mass, radioactivity, or inert behavior. An ideal geochemical tracer may have some of the following characteristics (Lalor and Pitt 1999):

• It can be detected at low concentrations.
• Small variations in tracer concentrations can be differentiated between two or more water sources.
• Tracers generally have stable behavior, so concentrations of the tracer do not attenuate much over time due to physical, chemical, or biological processes.
• A tracer is diagnostic of specific processes or from particular water sources.
• There is an ease of measurement with adequate detection limits.
• Tracers generally accepted standard method of analysis.
• Good sensitivity and repeatability for the tracer tests.

For hydraulic fracturing specialty chemical additives, some of the specific synthetic organic compounds can be used as tracers. However, due to the proprietary nature of many of the chemical additives as well as harsh geochemical conditions in deep shale basin environments, there may be few chemical additives that can serve as tracers.

15.5.8 Isotopes

Isotopes are natural variations of a specific element that contains equal number of protons but different number of neutrons in their nuclei, thus isotopes of the same element have varying relative atomic mass but have almost identical chemical properties.

15.5.8.2 Carbon and Methane Isotopes

Carbon isotopes are notated as δ¹³C and pronounced “delta carbon thirteen.” Schoell (1980) showed that the ratio of heavy hydrogen (deuterium) (δ²H _CH4); 0/00 (relative to Vienna Standard Mean Ocean Water (VSMOW)) compared with carbon (δ¹³C_CH4); 0/00 (relative to Vienna Pee Dee Belemnite (VPDB)) could be used to differentiate methane samples based on origin. The methane source zones based on hydrogen and carbon isotope data from dozens of researchers were compiled (Coleman et al. (1993) based on data from Schoell (1980)). Thermogenic methane derived from the Marcellus Shale has a relatively consistent carbon to hydrogen isotopic ratio (Figure 15.12). Other stable isotope data using carbon and hydrogen isotopes from north central and northeast Pennsylvania (Baldassar 2011a, b) show background stray gas from the northeastern Pennsylvania in Potter, Tioga, Bradford, and Chemung counties (and from the literature) to display much greater variability than the methane sourced from the Marcellus Shale (Saba 2013). Forensic methods have been developed to differentiate methane sources (Table 15.15).

Microbial methane acetate fermentation: marsh gas and landfill gas
Isotope	Fraction	Range
Carbon 13C	δ13C of CH4	−40 to −62 0/00
Heavy hydrogen (deuterium)	δ2H of CH4	−270 to −350 0/00
Microbial methane: CO2 reduction called drift gas
Isotope	Fraction	Range
Carbon 13C	δ13C of CH4	−62 to −90 0/00
Heavy hydrogen (deuterium)	δ2H of CH4	−180 to −240 0/00
Thermogenic methane: natural gas from the shale gas sources
Isotope	Fraction	Range
Carbon 13C	δ13C of CH4	−26 to −50 0/00
Heavy hydrogen (deuterium)	δ2H of CH4	−110 to −250 0/00

A stable carbon isotope relates to the gas sample, compared with the standard, as in the following equation (Saba 2013):

The stable carbon isotope of methane is expressed as parts per thousands (0/00). δ¹³C will vary in time related to depositional history: vegetation type, productivity, and organic carbon content and burial. The standard for δ¹³C is Vienna Pee Dee Belemnite (VPDB). Collected from the banks of the Pee Dee River in South Carolina, the original Pee Dee Belemnite (PDB) contained extinct fossilized belemnite shells. Since the original rock sample has been consumed completely through analysis, other reference standards were calibrated to the original PDB sample. Carbon isotope values are still reported relative to PDB using the term “VPDB” to show the values that have been normalized to the standard. The standard for δ²H is the oxygen ratios that are measured are compared relative to Vienna Standard Mean Ocean Water (VSMOW). Isotopic compositions of both oxygen and hydrogen are reported against the VSMOW standard.

15.5.9 Forensic Isotope Analysis

A wide variety of other available soluble isotopes, such as lithium, boron, strontium, radium, and others, can undergo forensic analysis. These available soluble isotopes are used in unconventional oil and gas source studies. Isotopic forms have been discovered for every element, and there are 275 isotopes of the 81 stable elements and over 800 radioactive isotopes (Thomas 2013). The isotope abundance measurements are obtained from Rosman and Taylor (1999). Stable isotopic analysis has been used to evaluate stable isotopes in the water cycle (Gat and Gonfiantini 1981) as well as differentiate rainwater (Dansgaard 1964), groundwater (Gat 1971), and surface water (Muir and Coplen 1981).

Isotope mass and abundance is described in Henderson and McIndoe (2005). Dissolved isotope chemical analysis is used in unconventional resource studies and source identification (Table 15.16). Using the dissolved isotopes for forensics is based on the theory that stable isotopes for water such as oxygen δ¹⁸O and hydrogen δ²H and dissolved salt isotopes such as boron ¹¹B/¹⁰B, strontium ⁸⁷Sr/⁸⁶Sr, and radium ²²⁸Ra/²²⁶Ra in shale waters differ from those in shallow groundwater, surface water, or other water sources.

15.5.10 Boron and Strontium Isotope Ratios

Some researchers have shown that the Marcellus Shale has a δ¹¹B value of 32–33‰ and a ⁸⁷Sr/⁸⁶Sr value of 0.7115. These values, obtained from the Catskill Formation in eastern Pennsylvania, differ from shallow groundwater isotope values of 13.1–28.1‰ for δ¹¹B and 0.712 01–0.715 53 for ⁸⁷Sr/⁸⁶Sr (Saba 2013). Based on these distinct ratios of boron, lithium, strontium, and selected other isotopes, flowback fluid of unconventional oil and gas operations can frequently be differentiated from the conventional coproduced water and water from other sources. These characteristics make these elements boron and lithium, which frequently occur naturally in shale formations useful in forensic analysis. When unconventional oil and gas operators inject hydraulic fracturing fluids under high pressure into a black organic‐rich shale formation, not only are the petroleum hydrocarbons released, but also soluble elements such as boron and lithium that are attached to clay minerals within the shale formation are also released during the HVHF operations. Boron and lithium are carried to the surface mixed in with the flowback fluids. Boron and lithium have distinctive isotopic fingerprints and are stable both in the deep shale basin and at the surface, making them suitable as forensic tracers. Boron (B), lithium (Li), and chloride (Cl⁻): [B/Cl, Li/Cl, δ¹¹B vs. δ⁷Li] are useful in characterizing the flowback fluids from other water sources. In a study based on 39 hydraulic fracturing flowback fluids and coproduced water samples from the Marcellus and Fayetteville black shale formations (Warner et al. 2014), the ratio of B/Cl (>0.001), Li/Cl (>0.002), δ¹¹B (25–31 ‰), and δ⁷Li (6–10 ‰) compositions of the flowback fluids was distinct in most cases from the coproduced waters collected from conventional oil and gas wells. Certain elements or compounds are more likely to be identified with flowback fluids. To reinforce the use of these elements in forensic work, a comparison of general isotope ratios of boron and lithium (Table 15.17) was used effectively to differentiate conventional coproduced water from seawater, unconventional HVHF flowback fluid from unconventional oil and gas operations, and global river waters (Warner et al. 2014).

15.5.11 Radioactive Isotopes

Isotopes of radioactive elements have been analyzed as part of the evaluation of naturally occurring radioactive materials (NORM) and technologically enhanced naturally occurring radioactive materials (TENORM) at unconventional and conventional oil and gas fields. NORM and TENORM are generally in sludges, wastes, or by‐products which is enriched with radioactive elements such as radium, uranium, thorium, and potassium and the associated decay products. US EPA regulates radionuclides based on concentration in liquids in micrograms/liter (μg l⁻¹) or parts per billion (ppb). A picocurie, or pCi, is a standard measure of the intensity of radioactivity or how frequently a radioactive particle is released in a sample of radioactive material. The background levels of NORM in Pennsylvania measured in groundwater ranged from <0.1 to 167 picocuries per liter (pCi l⁻¹) for gross alpha (α), 0.6–270 pCi l⁻¹ for gross beta (β), and <0.6–172 pCi l⁻¹ for combined radium (Saba 2013; USGS 2000). These ranges contain background concentrations greater than US EPA’s maximum contaminant levels (MCLs) of 15, 4, and 5 pCi l⁻¹ for gross alpha, beta, and combined radium, respectively. Generally, NORM samples should be collected, and the concentrations should be compared with MCLs and background levels. In other cases where NORM values have been established, the NORM background levels even in oil and gas production areas are well below MCLs.

Marcellus Shale flowback fluids and coproduced waters from gas production wells in central and western Pennsylvania show elevated concentrations of ²²⁶Ra and ²²⁸Ra in some of the flowback brines, with total ²²⁶Ra+²²⁸Ra concentrations ranging from 73 to 6540 pCi l⁻¹; these concentrations exceed US EPA’s MCL (5 pCi l⁻¹) by 13–1300 times (US EPA 2015b; Haluszczak et al. 2013; Rowan et al. 2011). Gross radioactivity and specific radionuclides including gross α radioactivity, gross β radioactivity, and the radium isotopes ²²⁶Ra and ²²⁸Ra were evaluated in southwest Pennsylvania by US EPA (2015b). The main α emitting radionuclides in the natural decay series are ²³⁸U, ²³⁴U, ²³⁰Th, ²²⁶Ra, ²¹⁰Po, ²³²Th, and ²²⁸Th. The major β emitting radionuclides are ²¹⁰Pb, ²²⁸Ra, and ⁴⁰K (Bonotto et al. 2009). US EPA (2015b) noted that naturally occurring radioactivity in groundwater is produced primarily by the radioactive decay of ²³⁸U and ²³²Th. Having a half‐life of 4.5 × 10⁹ years, the ²³⁸U atom and its decay series products include ²²⁶Ra and ²²²Rn. Flowback fluids or coproduced waters may contain some level of background radioactive elements, as in the case of the Marcellus Shale (US EPA 2015b). Levels of radioactivity and specific radioactive isotope ratios can be used to evaluate whether flowback fluids or coproduced waters have mixed with shallow groundwater or surface water resources.

Radium‐containing barite, called radiobarite, has been a documented constituent of some scale and sludge deposits that are generated in oil and gas field production equipment (Zielinski et al. 2001). Radium‐bearing saline formation water pumped to the surface along with crude oil can form a barite precipitate on production equipment surfaces. Age estimates can be calculated based on their decay: short‐lived ²²⁸Ra has a half‐life of 5.76 years, which is short compared to the significantly longer half‐life of 1600 years for ²²⁶Ra. Present activity ratios of ²²⁸Ra/²²⁶Ra in radiobarite‐rich scale or highly contaminated soil are compared with initial ratios at the time of radiobarite precipitation. Radium isotopes can be used to determine the age and source of radioactive barite at oil field production sites (Zielinski et al. 2001). Radioactivity levels in some oil field equipment and in soils contaminated by radium‐bearing scale and sludge can be high enough in some cases to pose a potential health threat, and evaluation of site‐specific data reduces the risks of uncertainty. Radioisotope information can be used to help identify water or fluid sources.

15.5.12 Case Studies

In a variety of case studies, included below, isotopic analysis, chemical ratios, other forensic information, and multiple lines of evidence are used to identify sources of water or contamination.

15.5.12.1 Water Isotope Case Study in Northern California

A stable isotope water study in the San Francisco Bay area of northern California was conducted by Jim Ulrick (2017) to differentiate water sources that included tap water, recycled water, rain water, and water from swimming pools. Over a period of 14 years, Ulrick collected 181 water samples for stable isotope ratio analyses. Monthly rainfall samples were also collected for volume‐weighted composite 2012 water‐year stable isotope values. An additional 28 isotope ratios of water from selected water sources from the area were compiled from data in other reports (Muir and Coplen 1981; Newhouse et al. 2004).

In the Ulrick study, a sample stable isotope ratio is measured and compared to the VSMOW, an internationally known reference. Delta (δ) notation is used to show the difference between the sample and VSMOW measurements. The δ values are expressed as parts per thousand or per mil (‰) because the differences are minute. For example, a positive δ value of +10 ‰ for oxygen (δ¹⁸O = +10 ‰) means that the sample is enriched in ¹⁸O by 10 ‰ compared to VSMOW. The δ¹⁸O and δ²D% ratios of precipitation worldwide vary as a function of temperature, elevation, and latitude, and plot along the global meteoric water line (GMWL) (Figure 15.13).

Main Findings: The five sources of water are clearly differentiated based on the ratio of heavy oxygen enrichment compared with heavy hydrogen enrichment (Ulrick 2017).

15.5.12.2 Water Isotope Case Study in Northeast Pennsylvania

Location	Main study	Target zone	Counties
Northeast Pennsylvania	Reilly (2014)	Marcellus Shale	Tioga, Bradford, Lycoming, and Sullivan

A geochemical study (Reilly 2014; Reilly et al. 2015) was performed using stable isotope analysis of groundwater samples collected in 2012–2013 from 21 groundwater wells in Tioga, Bradford, Lycoming, and Sullivan counties in northeastern Pennsylvania. The groundwater wells were identified by their owners as possibly being contaminated from nearby unconventional gas operations. Water samples from the 21 wells were compared with geochemical data from historical groundwater, Marcellus Formation flowback fluids, and other sources of contaminated waters (Reilly 2014; Reilly et al. 2015). The water analyses included sodium (Na), potassium (K), calcium (Ca), magnesium (Mg), barium (Ba), strontium (Sr), manganese (Mn), iron (Fe), aluminum (Al), chloride (Cl), bromide (Br), sulfate (SO₄), arsenic (As), nitrate–nitrite as N, total Kjeldahl nitrogen, total nitrogen, alkalinity, and TDS.

Road salt, animal waste, septic effluent, and Marcellus Formation flowback fluids (Figure 15.14) plotted on a trilinear diagram (piper plot) show that the flowback fluids are limited to areas on the chart that can be identified based on the specific pattern.

The study found that the cause of the 21 well owner complaints was related to natural geochemical conditions in the aquifer or, in the case of one well and possibly others, was impacted by either septic effluent or animal waste. Earlier water sampling studies in the area in 1980 showed 11% of groundwater samples to be impacted by septic effluent. The ion concentrations from the 21 wells did not exceed US EPA primary or secondary contaminant levels and were within the range established during the groundwater study performed in 1980 in the area. Common exceedances in water quality were related to the natural geochemistry of the Catskill and Lock Haven aquifers, which are naturally high in manganese and iron (Reilly et al. 2015).

Main Findings: The study concluded that no evidence exists that groundwater in the 21 wells tested was impacted by Marcellus Formation drilling, hydraulic fracture operations, or gas production activities. The study showed that water well owner complaints in the study area are not uncommon and aquifer qualities related to naturally occurring dissolved minerals such as iron or manganese can impact water quality, as can the conditions of the water wells and proximity to animal wastes and fecal matter. Based on the reaction of well owners to hydraulic fracturing operations in the general area, better communication and information transfer between the operators, regulatory agencies, and the public are needed (Reilly et al. 2015). Improvements to water well quality can be accomplished by understanding the well water chemistry and through regular well maintenance such as well redevelopment, chlorination practices, or water treatment.

15.6.1 US EPA Retrospective Case Study

Congress urged US EPA to study the relationship between HVHF operations and potable water resources in December 2009. US EPA planned for retrospective case studies by asking stakeholders across the nation to participate in identifying specific locations for potential case studies. From comments provided at US EPA meetings as well as electronic or written concerns or complaints from the public, over 40 possible locations were nominated for inclusion in the US EPA research. Possible case study locations were prioritized based on US EPA criteria, including proximity of the case study location to the population and drinking water supplies, the amount of reported evidence of water quality impacts, environmental and health concerns, and information gaps that could be filled at each possible case study location. The US EPA also wanted the selected case study areas to represent diversity in the following categories:

• Geographic and geologic characteristics.
• Populations at risk.
• Hydrogeologic and water resource conditions.
• Land uses.

US EPA reviewed the information and finalized five case study areas where hydraulic fracture operations have already occurred and alleged examples of water resource contamination are well documented. The five case study locations (Figure 15.16) included two sites in Pennsylvania, one site in Texas, one site in Colorado, and one site in North Dakota (Table 15.18).

The examples of water quality concerns used for the selection of the five case study sites were based on complaints, which were typical of the types of issues that were reported to the agency during the 2010 and 2011 stakeholder meetings. Water and air quality degradation complaints can be related to industrial activities or possibly other causes such as biological, geochemical, or structural processes. The US EPA study with five retrospective sites was planned to evaluate the complaints and to try to correlate the key factors that could be associated with the frequency and severity of alleged drinking water quality degradation from hydraulic fracture operations.

The US EPA examined five operations of the hydraulic fracturing water life cycle:

• Water acquisition – possible impacts related to large‐volume surface or groundwater extraction.
• Chemical mixing – possible environmental impacts at the well pad.
• Well injection – possible impacts related to the injection of specialized chemicals and hydraulic fracturing on water resources.
• Flowback and coproduced fluids and gases – possible impacts of surface spills or subsurface leakage and migration of fluids or gases into beneficial use aquifers and surface water sources.
• Wastewater treatment and waste disposal – possible impacts of incomplete treatment of wastes on water sources.

The US EPA retrospective case study program started with a project study plan (US EPA 2011a) based on extensive stakeholder outreach in five areas undergoing unconventional oil and gas development with horizontal drilling combined with hydraulic fracture operations. The study plan was developed with a large number of stakeholders, including other federal agencies, state and interstate regulatory agencies, nongovernmental organizations (NGO), the oil and gas industry, and others in the public and private sectors. The study plan underwent a peer review process by the EPA Science Advisory Board (SAB), which assembled an independent panel of experts for final comments and review.

15.6.2 US EPA Retrospective Study Approach and Sampling Activities

US EPA researchers compiled historic water quality databases and public information about drilling and hydraulic fracture operations, conducted detailed literature reviews, and analyzed historical background or baseline geology and hydrology data for each of the five case study locations. US EPA collected water samples from the summer of 2011 until the spring of 2013 from a variety of sources, including domestic wells, water supply wells, municipal wells, production wells, groundwater monitoring wells, and surface water sources during multiple sampling trips to the five case study locations. Field water quality parameters were monitored and documented during water sample collection (Table 15.19). Although variations exist, water analyses conducted by US EPA in the five retrospective case studies generally included most of these analyte groups (Table 15.20). Dissolved inorganic carbon (DIC) is the sum of all the carbonate species present such as carbonate and bicarbonate dissolved in water.

US EPA examined water sources where homeowner‐specific complaints indicated environmental concerns or where groundwater quality anomalies existed in the vicinity of unconventional gas wells. Example complaints of water quality included increased turbidity, effervescing, discoloration, staining, and odor. US EPA performed the retrospective case study to determine whether water quality concerns or anomalies could be attributed to the nearby hydraulic fracture operations or other activities.

15.6.2.1 Northeast Pennsylvania Case Study

Location	Main study	Target zone	Counties
Northeast Pennsylvania	US EPA (2015a)	Marcellus Shale	Bradford and Susquehanna

US EPA (2015a) studied groundwater wells, springs, ponds, and streams in Bradford and Susquehanna counties (Figure 15.17) in northeastern Pennsylvania. Northeastern Pennsylvania oil and gas exploration and production began as early as the 1860s. The Marcellus Formation is a Middle Devonian shale with an age of about 390 million years (Figure 15.18). The Marcellus Shale is a black, low density, and high organic carbon content. It occurs in the subsurface beneath much of New York, Pennsylvania, Ohio, and West Virginia, as well as in smaller areas of Virginia, Kentucky, Maryland, and Tennessee. In Bradford and Susquehanna counties in northeastern Pennsylvania, the Marcellus Shale lies about 4000–8000 ft (1219–2438 m) below the surface and ranges in thickness from about 150 to 300 ft (46–91 m). The Marcellus Shale is part of a transgressive sedimentary package formed by the deposition of terrestrial and marine material in a shallow, inland sea. The Marcellus Shale is underlain by the sandstones and siltstones of the Onondaga Formation and overlain by laminated shales, siltstones, and fine‐grained sandstones of the Mahantango Formation (US EPA 2015a). Aquifers in the area, notably the Devonian Catskill Formation rocks and the overlying Pleistocene glacial till aquifers, provide water sources (see Figure 15.18). Potable fresh groundwater occurs to depths of about 200 ft (61 m) in the valleys and about 800 ft (244 m) below ground surface in the upland areas. The average depth to groundwater in northeast Pennsylvania is about 175 ft (53 m) below ground surface but is frequently <40–50 ft (12–15 m) below the surface in the valleys (Battelle 2013). Generally, below the zone of fresh water, groundwater has elevated salinity, although shallow saline sources have been documented in the lowlands (Williams et al. 1998). The depth and thickness of the Marcellus Shale generally increases from northwest to southeast and near Bradford and Susquehanna counties; the formation is about 4000–7000 ft (1219–2134 m) below ground surface (Battelle 2013).

US EPA selected the initial sampling locations during an area reconnaissance conducted in August 2011 (Wilkin 2013) and analyzed for over 225 constituents including a large range of organic and inorganic constituents (US EPA 2015a). Sampling was conducted primarily in the southern portion of Bradford County, Pennsylvania. Sampling in the adjacent Susquehanna County was limited to three homeowner wells. Collectively, a total of ~100 drilled gas wells, most of which were hydraulically fractured, were within 5280 ft (1609 m) of the water sampling locations in the study, except for one well. Historic water quality data from before 2007 and before Marcellus Shale gas extraction in this area was obtained by US EPA from a literature search and from the US Geological Survey (USGS), National Water Information System (NWIS), and National Uranium Resource Evaluation (NURE) databases.

The number of water samples per sampling event ranged from 23 to 35. The US EPA study consisted of three rounds of water sampling and laboratory analyses conducted over a span of less than two years (Table 15.21).

Round	Date	Total number of samples	Wells	Springs	Ponds	Streams
Round 1	Oct–Nov 2011	35	33	2	0	0
Round 2	Apr–May 2012	27	22	1	2	2
Round 3	May 2013	23	22	1	0	0

The level of shale gas drilling activity in Bradford County during the US EPA study (October 2011 to May 2013) has increased greatly as shown on the cumulative drilled oil and gas well diagram (Figure 15.19). Approximately 98% of drilled wells in Bradford County are unconventional wells, and over 99% are gas wells. Approximately 94% of wells as of July 2013 were classified as active based on the Pennsylvania Department of Environmental Protection (PADEP 2015) database for year 2013 (US EPA 2015a). A closeup map around the town of Towanda, Pennsylvania, in Bradford County shows the plan view orientation of the horizontally drilled gas well laterals (Figure 15.20) and some of the US EPA sampling locations. Some of the horizontally drilled gas wells shown on the map were drilled but not yet fractured by 12 February 2012, according to data supplied by Chesapeake Energy.

Chemical Ratios: Bromide is a potential indicator of HVHF operations and was detected above the method quantitation limit (MQL) (1.0 mg l⁻¹) at only 3 of the 38 groundwater locations sampled in the US EPA study (US EPA 2015a) and at none of the surface water locations. The ratio of chloride/bromide weight ratio compared with that of chloride in mg l⁻¹ (Figure 15.21) shows differentiation of three groundwater wells compared with the more saline salt spring and Marcellus Shale flowback fluids. The National Uranium Resource Evaluation (NURE) 1977 groundwater data was used in the US EPA (2015a) Case Study. The figure shows a theoretical mixing curve with end members based on published data (Haluszczak et al. 2013; US EPA 2015a, using NURE 1977 data) of average flowback fluid chloride and bromide concentrations. Bradford County NURE chloride and bromide averages are 8.05 mg l⁻¹ (n = 164) and 0.0231 mg l⁻¹ (n = 112), respectively. NURE bromide data are for bromine analyzed by neutron activation analysis. Although there are only three groundwater samples, they can be separated from the flowback fluids based on these chemical ratios.

Methane: Dissolved methane in groundwater is ubiquitous in the area. According to the US EPA (2015a), stray gas migration is associated with the increased HVHF operations in this study area. This evidence comes from laboratory data that show changes in gas concentrations and/or the ratios of methane to ethane before and after unconventional gas drilling. Additional data from gas isotopes appear to show gas in some water wells is consistent with gas originating from deeper formations. Stray gas is encountered at almost all depths down to the Marcellus Formation, and according to US EPA, most of the stray gas originates from shallower formations. Based on isotope studies, elevated methane gas in the tested water wells was generally thermogenic in origin. The increased pace of unconventional gas activities in the study area has coincided with an elevated number of documented stray gas migration incidents (US EPA 2015a).

Stray gas is not unique to the current HVHF operations in northeast Pennsylvania. Baldassare (2011a, b) and Baldassare and Laughrey (1997) used geochemical and isotopic fingerprinting techniques to identify sources of stray gas. Stray gas commonly occurs within historic oil and gas basins. Methane gas occurs naturally in many water wells in the area at concentrations above both PADEP action level of 7 mg l⁻¹. The Office of Surface Mining Reclamation and Enforcement (OSMRE) of the Department of Interior recommended an action level of 10 mg l⁻¹, especially in groundwater rich in sodium bicarbonate (NaHCO₃) and sodium chloride (NaCl). Concentrations of methane <10 mg l⁻¹ in water or about 1–3% by volume in air are not generally a health or explosion concern but should be monitored to verify that the methane levels are not increasing (Eltschlager et al. 2001). At standard atmospheric pressure and at 68 °F (20 °C), dissolved methane in water can reach concentrations of 28 mg l⁻¹. Elevated methane concentrations occur when fluids or water are extracted from higher‐pressure conditions at depth, and the dissolved gas comes out of solution as bubbles during a reduction in pressure.

Stray gas can pose an explosion risk if the gases accumulate in confined spaces or traps. Stray gas is also known to increase TDS and discoloration in well water. The sustained presence of methane in water wells can promote reducing conditions, changing geochemical conditions to lead to reductive dissolution of certain metals such as iron, manganese, and, to a lesser degree in this study area, arsenic. Stray gas also contributes to supporting methanotrophs, ubiquitous microbes in soils, sediment, and groundwater. Methanotrophs metabolize methane as their source of carbon and energy and can co‐metabolize many aliphatic compounds, alkanes, and aromatic compounds.

15.6.3 Main Findings

• The US EPA (2015a) performed extensive laboratory analysis of inorganic and organic compounds in up to 35 sample locations of alleged groundwater impacts, which were possibly linked to HVHF operations. Based on multiple lines of evidence, the US EPA report indicated no evidence of groundwater impacts related to hydraulic fracturing and the extraction of gas from the Marcellus Shale. The laboratory detections of inorganic and organic constituents in water samples could not be attributed to HVHF operations.
• Low concentrations of trimethylbenzenes (TMB) were present near or below MQL at two homeowner locations.
• Toluene was detected below the MQL in one groundwater sample, which was attributed to anthropogenic sources.
• Locally elevated natural background levels of TDS, chloride, sodium, barium, strontium, and combined radium‐226 and radium‐228 were known to occur in a few wells in certain valley areas.
• Related to natural aquifer geochemistry, iron and/or manganese concentrations exceeded secondary maximum contaminant levels (SMCLs) at over 40% of the groundwater locations.
• An anomalously high concentration of sulfate (>1000 mg l⁻¹) was reported in 1 well, which may relate to the presence and dissolution of gypsum, a naturally occurring mineral in the area. The Marcellus Shale flowback and coproduced waters generally have sulfate concentrations <100 mg l⁻¹.
• US EPA noted that stray gas, as methane and ethane, was present in 9 of the 36 water wells tested.

15.6.3.1 Southwest Pennsylvania Case Study

Location	Main study	Target zone	Counties
Southwest Pennsylvania	US EPA (2015b)	Marcellus Shale	Washington

Washington County lies in the southeast corner of Pennsylvania within the Appalachian Basin. Oil and gas exploration and production has a long history in Washington County, extending back to the late 1800s. The organic‐rich Devonian Marcellus Shale ranges in thickness from <50 ft (15 m) to about 150 ft (46 m) and varies in depth from about 5000 ft to over 7000 ft (1524–2134 m) below land surface.

Shallow domestic water wells are completed in the Quaternary alluvium, while deeper bedrock aquifers include the Permian Dunkard Group, Pennsylvanian Monongahela Group, and Conemaugh Group formations (Figure 15.22). Freshwater aquifers in some locations of Washington County, Pennsylvania, have been contaminated by brine from deeper, non‐potable aquifers through historical oil and gas wells that were improperly abandoned or have corroded casings (Newport 1973).

Water sampling was conducted in Washington County, Pennsylvania (Figure 15.23), based on homeowner complaints or health concerns about water quality in potable wells. The domestic wells sampled in Washington County as part of the US EPA Retrospective Study (US EPA 2015b), ranged in depth from 50 to 160 ft (15–49 m) below land surface, with a median depth of 95 ft (29 m) below land surface. US EPA analyzed for over 235 constituents in water samples in Washington County (US EPA 2015b). Historic water quality data from before 2005 and before Marcellus Shale gas extraction in this area was obtained by US EPA from a literature search and from USGS, NWIS, and NURE databases.

The number of water samples per sampling event ranged from 15 to 16. The US EPA study consisted of three rounds of water sampling and laboratory analyses conducted in over a span of less than two years (Table 15.22).

Round	Date	Total number of samples	Wells	Springs	Surface water
Round 1	Jul 2011	16	12	1	3
Round 2	Mar 2012	15	10	3	2
Round 3	May 2013	15	11	2	2

The water samples were analyzed for over 235 target analytes, relating to local land use activities, as well as chemicals used in unconventional oil and gas drilling and production operations. Many of the types of exceedances in water quality goals in the retrospective case study conducted by the US EPA in Washington County, Pennsylvania, (Table 15.23) generally reflect natural sources of iron and manganese, natural sources of lead, nitrate from septic system or animal wastes, and dissolved methane from drift mine gas or coal seams (US EPA 2015a). Although specific spills or incidents related to HVHF operations may impact a nearby well or surface water source, as in the case of the drilling impoundment, widespread impacts to water resources were not reported by the US EPA (2015b).

Impacted parameters	Number of samples	Sample type	Description	Potential sources
Dissolved methane	6	Groundwater and springs	Detections from 0.002 to 15.5 mg l−1; consistent with biogenic and/or mixed biogenic and thermogenic sources	Drift gas; coal seams; long‐term migration from deep shales, sandstones, and coalbeds
Nitrate	1	Groundwater	Primary MCL exceedance	Septic systems; animal manure; fertilizers
Total lead	2	Groundwater	Primary MCL exceedance	Natural sources; pipes and/or solder corrosion
Iron and manganese	8	Groundwater, springs, surface water	Secondary MCL exceedances	Natural sources; turbidity potentially influenced by drilling; coal mine drainage
Aluminum	7	Groundwater and springs	Secondary MCL exceedances	Natural particulates; mineral content
Chloride	4	Groundwater, springs, surface water	Elevated concentrations compared to historical data; secondary MCL exceedances at one spring	Historical land use; current and/or historical drilling practices; impoundments; reserve pits; natural sources of brine; road salt

Chemical Ratios: In southwestern Pennsylvania, chemical ratios were used to distinguish coproduced water from oil and natural gas production from various coal‐mine related wastewaters and brine treatment plant discharges. The chemical ratios used sulfate/chloride (SO₄/Cl) weight ratios instead of bromide (Br) concentrations in mg l⁻¹ (Wilson et al. 2014). The plot of the sulfate/chloride weight ratio compared with the bromide concentration (Figure 15.24) for surface water and shallow groundwater can be differentiated from the Marcellus Shale flowback water (data from Haluszcak et al. 2013), oil and gas brines from Pennsylvania (data from Dresel and Rose 2010), abandoned mine drainage, coal‐fired power plant effluent, and Marcellus Shale coproduced water (Wilson 2014). The sulfate/chloride weight ratio is generally elevated in coal‐related wastewaters than in oil and gas coproduced waters. The yellow shaded zones (see Figure 15.19) have been established by Wilson and others (2014). Bromide concentrations are also much higher in co‐produced waters from oil and gas production than in coal mine discharge. Bromide levels in surface water and groundwater were generally orders of magnitude lower than the bromide concentrations in Marcellus Shale coproduced water (US EPA 2015b).

Methane: Background chemical data from the US EPA study showed that methane is naturally occurring in this area and was detected in 24% of the groundwater and spring samples at concentrations ranging from about 0.002 to 15.5 mg l⁻¹. US EPA noted that the isotopic signature of the methane present in domestic wells did not correlate well with the methane gas produced from the hydraulically fractured Marcellus Shale (US EPA 2015b). Methane occurs naturally in groundwater in Washington County, Pennsylvania, and is present in the subsurface down to the Marcellus Shale.

Main Findings:

• Elevated concentrations of chloride in groundwater was documented by the US EPA (2015b) at locations near a drilling mud pit site, which contained HVHF fluid wastes and drilling wastes. Based on multiple lines of evidence, US EPA concluded that the chloride contamination at sampling locations near one specific drilling mud pit was likely sourced from the impoundment itself.
• Washington County groundwater and surface samples contained no detections of acetate, GRO compounds, or glycol ethers, which might be associated with HVHF operations.
• Detections of VOCs and SVOCs were infrequent in the Washington County US EPA retrospective case study and were below US EPA’s drinking water MCLs.
• Although the primary MCL exceedances were noted at one location for nitrate and at two locations for total lead, the presence is not related to HVHF operations.
• US EPA noted that secondary MCL exceedances for manganese and iron were common in domestic wells, a reflection of naturally occurring conditions. Higher concentrations of manganese and iron reflect moderately, reducing groundwater conditions.
• Methane is naturally occurring and ubiquitous in groundwater in the area.

15.6.3.2 North Texas Case Study

Location	Main study	Target zone	Counties
North Texas	US EPA (2015c)	Barnett Shale	Wise and Denton

The US EPA studied Wise County for a north Texas retrospective study (Figure 15.25). The Barnett Shale (Figure 15.26), within the Bend Arch–Fort Worth Basin, is a Mississippian Shale with an age of about 320–360 million years ago. The Barnett Formation is widespread regionally within the basin, and recent unconventional gas production is relying on horizontal drilling and HVFS technologies to create fracture porosity, permeability, and gas flow. Wise County groundwater has been characterized as primarily calcium bicarbonate and sodium bicarbonate types, although occasionally other water types have been reported (US EPA 2015c).

The Trinity aquifer (see Figure 15.26) is the primary source of drinking water in Wise County and 15 of 16 water wells in the US EPA retrospective case study were screened in that aquifer except for one well that was screened in an alluvial deposit. In addition to the 16 domestic wells, 4 surface water bodies at 3 locations within Wise County (locations A, B, and C) were sampled (Table 15.24). One of the surface water bodies sampled was a pond at location A and was the site of a reported March of 2010 fish kill. The study also included three gas production wells sampled by the US EPA: two of the gas wells which were sampled were completed within the Barnett Shale, and one gas well sampled for coproduced water was completed in the overlying Boonesville Bend Conglomerate formation.

Round	Date	Total number of samples	Wells	Surface water	Coproduced water (gas wells)
Round 1	Sep 2011	16	13	3	0
Round 2	Mar 2012	18	15	3	0
Round 3	Sep 2012	4	3	0	1
Round 4	Dec 2012	10	9	1	0
Round 5	May 2013	15	8	5	2

Five sampling events have occurred, and in the Wise County study, the number of water samples per event ranged from 4 to 18. The water samples were analyzed for over 235 constituents relating to local land use activities, as well as chemicals used in unconventional oil and gas drilling and production operations.

15.6.3.2.1 Historical Databases

The US EPA data (2015c) was compared with historical water quality data documented in the literature, geochemical data in Texas Water Development Board (TWDB) database, and three national water quality databases: USGS, NWIS, and NURE. These sources provided data for water samples collected prior to 1993 (except NWIS), a time before the Barnett Shale was an HVHF gas target. The NWIS database only contains 1994 data for Wise County.

There are no DRO and GRO sample tests in the historical databases. The historical databases include SVOCs testing, but none were detected in the area. The historical databases showed that most of the trace elements, except for arsenic, iron, and manganese, were not detected or were found in very low concentrations. Arsenic, iron, and manganese concentrations in groundwater from the US EPA retrospective study were similar to the historical database concentrations, suggesting natural aquifer conditions. Naturally occurring, iron and manganese in groundwaters did exceed the US EPA SMCLs. Arsenic did not exceed the maximum contaminant level (MCL) (US EPA 2015c).

Methane

Dissolved methane was detected in 64% of the samples with methane concentrations in groundwater ranging from 0.0007 to 0.0242 mg l⁻¹ and a median concentration of 0.0016 mg l⁻¹. The low concentrations of dissolved methane were generally too low for isotopic analysis (US EPA 2015c). The Trinity aquifer outside of the specific US EPA study area contained dissolved methane levels that ranged from 0.0144 to 0.0347 mg l⁻¹ (Zhang et al. 1998). Methane levels in both studies of the Trinity aquifer indicate the likely range of background methane levels, which naturally exist in the Trinity aquifer.

Main Findings:

• Concentrations of organic compounds in the Wise County samples did not exceed any US EPA drinking water standards when they were detected. In addition, there were no repeated detections in any water samples of any organic compounds associated with HVHF activities. Low concentrations in surface water of DRO compounds, VOCs, and SVOCs were detected at some sample locations during a few of the sampling events. GRO compounds were detected in one groundwater sample, and an SVOC (bis‐(2‐ethylmethyl) phthalate) was detected in two wells (US EPA 2015c).
• In up to 6% of the water sample, VOCs were detected at concentrations below US EPA drinking water standards. The detected VOCs included benzene, which occurred in 6% of the detections, 1,2,4‐trimethylbenzene occurring in 2% of the detections, tert‐butyl alcohol, methyl tert‐butyl ether (MTBE), ethyl tert‐butyl ether, tert‐amyl methyl ether, m–p‐xylenes, and o‐xylene. Some of these compounds are linked to a proximity of vehicles and generators near the sampling activities. Other potential sources of VOCs were not identified.
• The study was broken into three study areas (A, B, and C), and in two out of the three study locations, there were no impacts to groundwater. In the third study area, two domestic wells had elevated levels of chloride, specific conductivity, calcium, potassium, magnesium, sodium, bromide, iodide, and strontium, likely from formation brines. Chloride was noted to exceed the SMCL by 2.2–7.9 times. A third well located at an industrial facility was identified as potentially impacted by brines and/or landfill leachate. Several sources for impacts from formation brines were identified, but specific potential pathways were not determined.
• Glycol ethers, compounds commonly found at well sites during HVHF operations or associated with other industrial processes, were not detected in surface or groundwater samples.
• Methane in the study area is naturally occurring based on the widespread occurrence of dissolved methane in groundwater from the Trinity aquifer.

15.6.3.3 West North Dakota Case Study

Location	Main study	Target zone	Counties
West North Dakota	US EPA (2015d)	Bakken Shale	Dunn

The US EPA Killdeer study area is the location of historical oil and gas production, as well as current unconventional oil production from the Bakken Shale. The US EPA case study near Killdeer, North Dakota, was designed to evaluate the potential impacts to drinking water resources related to a known oil well blowout, which occurred during HVHF operations in September 2010. The blowout released crude oil, hydraulic fracturing fluids, and flowback fluids onto the surrounding area. Cleanup efforts were started after the blowout. Various state agencies were involved, including the Division of Water Quality (NDDWA) of the North Dakota Department of Health and the Oil and Gas Division of the North Dakota Industrial Commission (NDIC). US EPA was requested by these agencies to perform a retrospective case study at the Killdeer blowout site. US EPA set out to determine whether drinking water resources, including the Quaternary Killdeer aquifer, were impacted from the blowout event with associated fluid surface spill, which occurred at the Franchuk 44‐20 SHW well (Figure 15.27).

Dunn County is situated on the Missouri Slope uplands of the Great Plains region of western North Dakota. The general geology of Dunn County consists of thick sequences of Cenozoic, underlain by Mesozoic, and older Paleozoic rocks, which have accumulated in the Williston Basin (Figure 15.28). Approximately 7500 ft (2,286 m) of Paleozoic rocks underlie Dunn County (Murphy 2001), including the Late Devonian to Early Mississippian organic‐rich deep marine Bakken Shale deposited ~400 million years ago. The Bakken Shale consists of an upper and lower organic‐rich deep marine shale deposited under anoxic conditions, separated by a middle dolomite member. The estimated top of the Precambrian crystalline rocks ranges from 11 000 to 13 400 ft (3 353–4 084 m) below sea level in Dunn County (Heck 1988; Heck et al. 2013; Murphy 2001).

Nearby Aquifers: Deeper wells in the area which may produce from rock aquifers (from bottom to top) include the Cretaceous Hell Creek and Fox Hills formations and Tertiary Ludlow, Cannonball, Tongue River, and Sentinel Butte formations (Klausing 1976, 1979). Overlying the Tertiary rocks, the Quaternary alluvium aquifers in Dunn County are found in sediments that were deposited before glaciation and within areas of glacial deposits, which consist of till and glacio‐fluvial sand and gravel deposits that are confined to glacial meltwater channels and include the Killdeer, Horse Nose Butte, Knife River, and Goodman Creek aquifers. The primary water source underlying the Franchuk 44‐20 SHW well is the unconfined to semiconfined Killdeer aquifer (Figure 15.29) consisting of fine to course gravel near the base overlain by a predominantly fine to medium sand, which generally lies below clay and silt deposits (Klausing 1976). The Killdeer aquifer has a maximum thickness of 233 ft (71 m) and an average thickness of 80 ft (24 m). The Killdeer aquifer recharges by infiltration of rainwater. The depth to water during the US EPA study ranged from 19.8 to 33.6 ft (6.0–10.2 m) below ground surface (bgs) (US EPA 2015d). Water extracted from the Killdeer aquifer is generally hard and is characterized as either sodium bicarbonate type or sodium sulfate type of water (Klausing 1976). The groundwater flow direction is to the southwest and has a relatively uniform gradient of 0.0009–0.0008, which varies seasonally depending on water usage and precipitation.

Blowout Details: The uncontrolled blowout occurred in the Franchuk 44‐20 SWH well on 1 September 2010 during the fifth stage of a 23‐stage hydraulic fracture program (Jacob 2011). The surface casing was compromised due to over‐pressurization at about 38.5 ft (11.7 m) bgs with fluids possibly migrating down and around the conductor casing at 60 ft (18 m) bgs and then discharging to the surface (Battelle 2013; Terracon 2012). Fluids from the damaged Franchuk 44‐20 SWH well began flowing from several locations around the wellhead when the 7‐in‐diameter (17.8‐cm) casing burst. A stream of water, crude oil, and gas was released for approximately five days until 6 September 2010 when the well was finally plugged. Except for a portion of the HVHF fluids flowing to the northwest of the well, HVHF fluids released at the surface were mostly captured on the well pad. To contain spills at the surface, the Franchuk 44‐20 SWH well pad was double lined and was diked. Approximately 2 000 barrels (84 000 gal) of HVHF fluid and crude oil were released into the environment, and the concern was whether the shallow Killdeer aquifer was impacted by the release of HVHF fluids from the subsurface or surface. Approximately 125 barrels (5250 gal) of the HVHF fluid and crude oil was recovered after the spill (Beak 2013). Contaminated soils from the well pad were excavated and disposed off‐site with an initial volume of 1889 tons (1714 metric tons) followed by another 122 tons (111 metric tons) from two smaller areas at the well pad (Terracon 2012).

For violation of several sections of the North Dakota Administrative Code (NDAC) due to the unauthorized release, the NDIC fined Denbury Resources LLC $237 500. The blowout violation included specific infractions (Battelle 2013):

• Not controlling subsurface pressure during completion activities (NDAC Section 43‐02‐03‐28).
• Allowing oil to flow over and pool on the surface of the land (NDAC Section 43‐02‐03‐49).
• Allowing brine to flow over and pool on the surface of the land (NDAC Section 43‐02‐03‐53).

After the release, state regulatory agencies required the installation of nine monitoring wells on and around the Franchuk 44‐20 SWH well pad. In addition, coordinated groundwater monitoring was performed of nearby domestic wells, municipal wells, and industrial water supply wells, which provide water for oil and gas activities.

An important aspect to the story is that the operator disclosed to state regulators the composition of the hydraulic fracturing fluid used during HVHF operations at the Franchuk 44‐20 SWH well (see Appendix F). Over a period of 15 months, US EPA conducted three separate sampling rounds and collected groundwater samples (Table 15.25), which were analyzed for over 230 constituents.

Round	Date	Total number of samples	Monitoring wells	Domestic wells	Supply wells (for O&G use)	Municipal wells	State wells
Round 1	Jul 2011	16	9	3	2	1	1
Round 2	Oct 2011	16	9	3	2	1	1
Round 3	Oct 2012	16	9	3	2	1	1

Historical Databases: The US EPA data (US EPA 2015d) was compared with historical water quality data documented in the literature, geochemical data in the North Dakota State Water Commission (NDWC) database, and information from Klausing (1976, 1979) for the Killdeer aquifer in Dunn County. Two national water quality databases were also reviewed: USGS and NWIS. The NDWC database, NWIS, and Klausing (1976) did not contain information on VOC analysis.

The potential sources of contamination in the area relate to nearby historic oil and gas exploration and production, leaking underground storage tanks, the use of road salt, land use practices, and the blowout of the Franchuk 44‐20 SWH well. US EPA ruled out other potential sources of contamination based on hydrology and the lack of residual signatures of impacts in nearby monitoring wells (US EPA 2015d).

Methane: Dissolved methane was detected in 24% of the groundwater samples, with a maximum concentration of 0.0253 mg l⁻¹. Methane concentrations during the three US EPA sampling rounds are consistent with background methane concentrations in the Killdeer aquifer, which range from 0.0149 to 0.3978 mg l⁻¹.

Main Findings:

• The chemicals or brine associated with the Franchuk 44‐20 SWH well blowout were not detected in drinking water wells sampled by US EPA, which were thousands of feet (or more) away from the damaged well.
• Located on the Franchuk 44‐20 SWH well pad, two groundwater monitoring wells were screened in the Killdeer aquifer and showed the presence of elevated concentrations of tert‐butyl alcohol (TBA) and brine. US EPA concluded that the blowout during HVHF operations was the only potential source of TBA and brine in these two groundwater monitoring wells. The geochemical characteristics of the brine detected in the two groundwater monitoring wells is consistent with impacts, which US EPA suggested was the result of mixing of deep brine waters, specifically from the Madison Formation water, with the more shallow Killdeer aquifer waters. However, the exact mechanism or flow pathways was not described or determined (US EPA 2015d).
• The presence of TBA in the two groundwater wells on the Franchuk 44‐20 SWH well pad is significant as it is a known breakdown product of tert‐butyl hydroperoxide (TBHP) (Chen 2005; Hiatt et al. 1964; Martynova et al. 2001; Stepovik and Potkina 2013), which was used during at the Franchuk 44‐20 SWH and included in the list of chemicals on‐site (US EPA 2015d). The list of chemicals associated with the HVHF operations is critical evidence and illustrates the linkage between the hydraulic fracturing chemicals on‐site and the eventual detection of TBA in the two nearby groundwater monitoring wells (Table 15.26).

  Except for TBA detected in two groundwater monitoring wells on the well pad, all VOC compounds, which were detected in three wells, and SVOC compounds, which were detected in five wells, could be related to a potential source other than HVHF operations.

• Glycols, a chemical associated with HVHF operations as well as other industrial applications, were not detected in the US EPA study wells during the study.
• For the US EPA study, 38% of the groundwater samples exceeded the SMCL for sulfate. Killdeer aquifer sulfate concentrations are consistent with the naturally occurring sources such as gypsum and selenite in the soils of Dunn County and are in line with historical data.
• The drinking water wells sampled did not show the presence of chemicals or brine associated with the Franchuk 44‐20 SWH blowout of September 2010.
• Site remediation was eventually completed, and no further actions were required for the site.
• Naturally occurring background methane concentrations in the Killdeer aquifer were observed.

Well	July 2011 (μg l−1)	October 2011 (μg l−1)	October 2012 (μg l−1)
NDGW07	156	795	229
NDGW08	975	972	287

15.6.3.4 Southeast Colorado Case Study

Location	Main study	Target zone	Counties
Southeast Colorado	US EPA (2015e)	Raton Basin Coalbed methane	Las Animas and Huerfano

The Colorado portion of the Raton Basin, located within Las Animas and Huerfano counties, have recently been the focus of unconventional gas production of coalbed methane (CBM) from several coal‐bearing strata in the basin (Figure 15.30). In response to complaints from domestic well owners living in the Raton Basin about water quality issues such as appearance, odors, and taste in southwest Colorado, US EPA selected the area for a retrospective case study (US EPA 2012). Over 2800 CBM wells have been drilled in the Colorado portion of the Raton Basin since the mid‐1990s (Battelle 2013). The recent increases in CBM gas production within the Raton Basin of southern Colorado and northern New Mexico have benefitted significantly from horizontal drilling and HVHF techniques, so that now, the Raton Basin is one of the most productive CBM gas basins in the United States. The geochemical composition of coproduced water using these new drilling and HVHF techniques relates to at least two possible sources: the original HVHF fluid, which can be altered through chemical and biological reactions with the coal deposits, and water associated with the coalbeds, which becomes mobilized as part of the drilling operation (Batley and Kookana 2012; Gordalla et al. 2013). HVHF in coal seams can create cracking that extends for up to 98 ft (30 m) (Batley and Kookana 2012).

Coalbeds interbedded with sandstones are located within the Paleocene Poison Canyon Formation, Late Cretaceous to Paleocene Raton Formation, and the underlying Late Cretaceous Vermejo and Trinidad Formations, which are the main sources of methane within the Raton Basin (Figure 15.31). The coals are the most likely source of the methane, and gas is also found in the adjacent sandstones. The CBM accumulation is under‐pressured in generally tight reservoirs, and the gas occurs at relatively shallow depths of <3500 ft (1067 m) (Johnson and Finn 2001). The depths of the CBM gas also overlaps with the deeper completion zones of some water wells in the area.

The US EPA retrospective case study focused on three areas: (i) the Little Creek Field area in south central Huerfano County and two locations in western Las Animas County – (ii) the North Fork Ranch area and (iii) the Arrowhead Ranchettes area. A primary interest was to evaluate potential methane gas migration from hydraulically fractured zones in the Raton and Vermejo Formations into shallow groundwater aquifers, such as the Poison Canyon Formation and younger alluvial fill deposits.

Historic Databases: The US EPA reviewed state and national geochemical information in the area and water quality databases from the Colorado Oil and Gas Conservation Commission (COGCC), as well as USGS, NWIS, and NURE. The US EPA performed statistical comparisons between the Raton Basin retrospective case study data and historic information to verify trends. The NWIS and NURE data reflect water quality information collected prior to 1990 and were used to establish baseline water quality conditions before significant CBM development occurred in the basin. After 1 April 2012, Colorado required oil and gas operators performing HVHF to make available to the public information about hydraulic fracturing chemicals and treatments through a chemical disclosure registry (COGCC 2011). This study was started prior to the time when the HVHF chemicals were disclosed.

Over a period of 19 months, US EPA conducted four separate sampling rounds and collected groundwater samples from 26 locations, which were evaluated for a total of 235 constituents (Table 15.27). US EPA wanted to evaluate the specialized chemical additives, which are components of HVHF fluids in Colorado such as acetic acid, glycol ethers, ethanol, isopropanol, 2‐BE, and petroleum distillates.

Round	Date	Total number of samples	Monitoring wells	Domestic wells	Production well	Surface water
Round 1	Oct 2011	20	5	12	2	1
Round 2	May 2012	21	3	12	3	3
Round 3	Nov 2012	21	3	12	3	3
Round 4	Apr–May 2013	21	3	12	3	3

Additional sample: residence (from kitchen tap) sampled Round 3, post domestic well treatment.

Compounds detected from October 2011 to April/May 2013 groundwater sampling in US EPA study area (Table 15.28) indicate a range of naturally and anthropogenic chemicals. Chemical additives in HVHF fluids used in the Raton Basin, Colorado, based on FracFocus (2018) are summarized in Table 15.29.

Compound	Chemical list: FracFocus (2017); US House of Representatives (2011)	Type of product
1,2‐Dichlorobenzene		Anthropogenic solvent
1,2,3‐Trimethylbenzene	(USHOR)	Aromatic hydrocarbon in coal tar and petroleum
1,2,4‐Trimethylbenzene	(USHOR)	Aromatic hydrocarbon in coal tar and petroleum
1, 2‐Butoxyethanol (2BE)	(FF)	Anthropogenic SVOC
2‐Butoxyethanol phosphate		Anthropogenic VOC
Acetone	(USHOR)	Undetermined sources; solvent
Benzene	(USHOR)	Aromatic hydrocarbon in coal tar and petroleum
Bis‐(2‐ethylhexyl) adipate		Anthropogenic SVOC
Bis‐(2‐ethylhexyl) phthalate		Anthropogenic SVOC
Carbon disulfide		Sulfur compound
Chloroform		Anthropogenic VOC; trihalomethanes
Diesel range organics (DRO)	(USHOR)	Petroleum hydrocarbon
Diethylene glycol	(USHOR)	Anthropogenic glycol ethers
Di‐n‐butyl phthalate		Anthropogenic SVOC
Di‐n‐octyl phthalate		Anthropogenic SVOC
Ethylbenzene	(USHOR)	Aromatic hydrocarbon in coal tar and petroleum
Gasoline range organics (GRO)		Petroleum hydrocarbon
Isophorone		Anthropogenic VOC
Methylene chloride		Anthropogenic VOC; solvent
Naphthalene	(USHOR)	Petroleum hydrocarbon
Nitrobenzene		Anthropogenic SVOC
Phenol	(USHOR)	Petroleum hydrocarbon; SVOC
Squalene		Petroleum hydrocarbon; SVOC
Tert‐butyl alcohol (TBA)	(USHOR: TBA precursor: tert‐butyl hydroperoxide	Undetermined sources; gasoline oxygenate
Toluene	(USHOR)	Aromatic hydrocarbon in coal tar and petroleum
Triethylene glycol	(USHOR)	Anthropogenic glycol ethers
Xylenes		Aromatic hydrocarbon in coal tar and petroleum

Additive class	Compound	HVHF Function
Acid	Hydrochloric acid a; acetic acid	Clean out the wellbore, dissolve minerals, and initiate cracks in reservoir
Activator	Methanol; ethoxylated nonylphenol	Enhance bonding of curable resin proppants together
Biocide	2‐Monobromo‐2‐nitrilopropionamide; 2,2 dibromo‐3‐nitrilopropionamide; 2‐bromo‐2‐nitro‐1,3‐propanediol; tetrakis (hydroxymethyl) phosphonium sulfate	Control microbes
Breakers	Ammonium persulfate; carbohydrates; ethylene glycol; hemicellulase enzyme; quartz; sodium chloride; sucrose; tryptone; walnut hulls; yeast extract	Promote delayed breakdown of gel polymers
Buffer	Acetic acid; acetic anhydride; sodium hydroxide	Maintain effectiveness of other compounds (such as crosslinker)
Chemical tracer	Proprietary aromatic hydrocarbon; tracerco 160c, 161b, 163a, 163b, 164b, 164c, 165b, 165c, 166c, 168a, 718, 731b	Establish water movement over an extended time period
Clay stabilizer	Choline chloride; oxyalkylated amine quaternary compound	Create a brine carrier fluid
Conductivity enhancer	Dipropylene glycol monomethyl ether	Protect against proppant diagenesis; improves permeability of proppant pack; enhances fracture conductivity
Crosslinker	Boric acid; ethanol; ethylene glycol; methanol; methyl borate; monoethanolamine borate; petroleum distillates, terpenes and terpenoids (sweet orange oil)	Maximize fluid viscosity at high temperatures
Foaming agent	2‐butoxyethanol; ethylene glycol; methanol	Used to transport and place proppant into fractures
Friction reducer	Petroleum distillates (COGCC 2013)	Minimize friction between the fluid and the pipe
Gelling agent	1‐butoxy‐2‐propanol; guar gum; ethoxylated isotridecanol; petroleum distillates; paraffinic petroleum distillates; quartz	Thicken water to suspend proppant
Inhibitor	Aldehyde; chloromethylnaphthalene quinoline quaternary amine; isopropanol; methanol; propargyl alcohol	Prevent corrosion of pipe by diluted acid; reduce deposition of scales on pipes
Iron control	Acetic acid; acetic anhydride; citric acid	Prevent precipitation of metal oxides
Nitrogen foam	Nitrogen	Transport proppant
Non‐emulsifier	Oxyalkylated alcohol	Trade secret
Otherc	2‐butoxy‐1‐propanol; boric oxide; formaldehyde; glycerol; lactose; polyethlylene glycol; organic sulfonic acid; sodium chloride; soy	Not provided
Oxygen scavenger	[Ammonium bisulfate (Vidic et al. 2013)]	Remove oxygen from fluid to reduce pipe corrosion
Proppant	Hexamethylenetetramine; phenol formaldehyde resin; quartz	Keep fractures open
Surfactant	2‐butoxyethanol; amphoteric surfactantb; essential oils; ethanol; secondary alcohol; terpenes and terpenoids (sweet orange oil)	Decrease surface tension to allow water recovery
Undisclosed	Alkoxylated amine; alkylene oxide block polymer; antifoam; organophilic clay; polymeric suspending agent; polyquaternary amine; surfactant	Trade secret

^a Compounds that are known or possible human carcinogens, regulated under the Safe Drinking Water Act for their risks to human health, or listed as hazardous air pollutants under the Clean Air Act (US House of Representatives 2011) are in italics.

^b All listed compounds are proprietary.

^c Compounds listed are designated “non‐MSDS” by the operator; additional information, other than CAS#, was not provided (FracFocus 2017).

FracFocus is a chemical disclosure registry managed by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission, two oil and gas industry organizations.

US EPA (2015e) concluded that there are no documented or known fuel spills or leaking aboveground or underground storage tanks or pipelines in the study area, which might have sourced the detected petroleum hydrocarbons. Likewise, there is no documented use of petroleum distillate compounds in the HVHF fluids.

Tertiary butyl‐alcohol (TBA) was detected in groundwater samples collected from three domestic wells, two monitoring wells, and one production well at levels ranging from 6.9 to 1310 μg l⁻¹. TBA provides an example of a compound that can form in a variety of ways (Table 15.30), including as a breakdown product of Methyl tert‐butylether (MTBE), Tert‐butyl hydroperoxide (TBHP) or other chemicals. One way to form TBA is through microbial interaction with isobutene (US EPA 2015e). Although there are several ways of forming TBA, specific sources near the wells that detected TBA and possible migration pathways of the TBA are uncertain. The presence of TBA in groundwater illustrates the challenges in forensic chemistry in identifying specific chemical sources for a compound with multiple formation pathways (see Table 15.30).

Product	Reaction with source compound	Example process	Example equation	References (US EPA 2015e)
TBA (C4H10O)	MTBE (C5H12O) or ETBE (C6H14O); fuel oxygenates	Microbial oxidation of methyl tert‐butyl ether (MTBE) or ethyl tert‐butyl ether (ETBE)	C5H12O ⇒ C4H10O	Parsons (1999), Wilson and Adair (2007), and Jacobs et al. (2001)
TBA	Tert‐butyl acetate (TBAc) (C6H12O2) natural gas‐derived oxygenated ester solvent used as fuel additive (Zeigler 2010); not used as HVHF chemical	Degradation Product of TBAc (abiotic hydrolysis of TBAc)	C6H12O2 + H2O ⇒ CH3COO− + (CH3)3COH + H+	Lyondell Chemical Co. (2006) and Hyman (2012)
TBA	Tert‐butyl hydroperoxide TBHP (C4H10O2) (industrial applications; also used as gel breaker in HVHF fluids)	Decomposition of TBHP	2(CH3)3COOH ⇒ 2(CH3)3COH + O2	Wang et al. (2007), Denney and Rosen (1964), and Hiatt et al. (1964)
TBA	Isobutane (C4H10)	Microbial oxidation of isobutane	C4H10 + O2 + 2e− ⇒ (CH3)3COH + O2−(H2O)	Mason (1957), Atlas (1981), and Parekh et al. (1977)
TBA and TBAc	Isobutylene (C4H8) precursor; a component of natural gas	Reaction of isobutylene and water in the presence of a catalyst	C4H8 + H2O ⇔ (CH3)3COH	Delion et al. (1986)

Methane: The USGS (Johnson and Finn 2001) documented evidence for gas flows at shallow depths in the Raton Basin in the uppermost Cretaceous and Paleocene strata in the Raton Basin (Broadhead 1982, 1991, 2012; Dolly and Meissner 1977; Rose et al. 1986; Johnson and Finn 2001; Woodward 1987). During the installation of shallow water wells and oil and gas wells in the area, gas flows in sandstones, coals, and fracture zones are commonly encountered in the Paleocene Poison Canyon Formation, Paleocene–Upper Cretaceous Raton Formation, Upper Cretaceous Vermejo Formation, and Upper Cretaceous Trinidad Formation (Dolly and Meissner 1977).

For the Raton Basin study, US EPA noted that methane was detected in all the domestic wells sampled. Although the methane levels ranged from about 0.003 to 12.4 mg l⁻¹, the average value was 0.46 mg l⁻¹. Six domestic wells in the US EPA study had a methane value above the Colorado Oil and Gas Conservation Commission (COGCC) cautionary level of 1.1 mg l⁻¹ that can lead to buildup of explosive quantities of gases in small confined spaces. Methane was also detected in all of the production wells and monitoring wells sampled during this study, reflecting the widespread occurrence of the naturally sourced gas.

Besides subsurface methane detection, US EPA noted that the gas was also detected in surface water bodies. The methane concentrations were low at <0.05 mg l⁻¹ at locations down gradient of surface‐discharged CBM water. Figure 15.32 shows gas exsolution (bubbles) in a Raton Basin groundwater sample.

Isotopic Methane Source Analysis: Forensic geochemistry uses the carbon (δ¹³C_CH4) and hydrogen (δ²H_CH4) isotopes of methane to identify the origin of an unknown sample of dissolved methane in water. Several stable isotope correlations and graphic patterns have been able to generally identify potential sources of methane in the Raton Basin. Four distinct methane sources have been categorized: (i) biogenic methane sourced from microbial activities, (ii) thermogenic methane present in deeper coalbeds, (iii) mixed thermogenic/biogenic sources, and (iv) thermogenic methane undergoing oxidation (US EPA 2015e). Methane carbon (δ¹³C_CH4) and hydrogen (δ²H_CH4) isotope diagram with analytical data from groundwater in the Raton Basin shows four methane source zones (see Figure 15.33). The North Fork Ranch Area and the Little Creek Area isotopic data are described below.

North Fork Ranch Area: Isotopic analysis requires high concentrations of dissolved methane in the water samples for identification. Two or more samples, at a minimum, are usually analyzed. The US EPA study analyzed domestic water wells containing dissolved methane and compared the results with known gas sources from the Raton and Vermejo coal‐bearing formations, which also produce methane. In the North Fork Ranch study area of the Raton Basin, the domestic and monitoring wells contained methane, which was identified as microbial in origin. Water samples collected from seven of 15 locations in the North Fork Ranch study site contained sufficient amounts of methane for isotopic analyses (δ¹³C_CH4, δ²H_CH4). The seven water samples included one domestic well, two monitoring wells, all three production wells, and a single surface water site.

The isotopic composition of headspace gases in the North Fork Ranch water production wells shows δ¹³C_CH4 and δ²H_CH4 ranging from −52.7 to −45.6‰ and −238.4 to −220.8‰, respectively; these values correspond to a thermogenic source (US EPA 2015e). Isotopic data collected from shallow monitoring wells in the North Fork Ranch study area show that the sampled methane is biogenic in origin (see Figure 15.33). The isotopic composition of headspace gases in the monitoring wells shows δ¹³C_CH4 and δ²H_CH4 ranging from −65.8 to −59.6‰ and −257.2 to −220.4‰, respectively.

Because unprocessed methane dissolved in water is odorless, tasteless, and colorless and occurs naturally in groundwater in Cretaceous and Tertiary coal seams and sedimentary deposits in the Raton Basin, methane can be overlooked as a safety hazard. As such, methane can outgas when present at high concentrations and produce flammable or explosive environments when trapped at elevated levels in basements or other enclosed areas like small sheds or garages. An example of methane buildup occurred in the North Fork Ranch area where a methane‐related explosion was noted in a water well pump shed (The Denver Post 2008).

Little Creek Field Area: After HVHF operations in 2005 in the Little Creek Field study area, production of both natural gas and water increased rapidly in the field into 2007. Dissolved gas concentrations also increased in water pumped from drinking water wells in the same area starting in the spring of 2007 where free‐phase methane gas was observed venting into domestic wells, which were completed in the shallow Poison Canyon Formation. The headspace analysis of the dissolved gases indicated the presence of nitrogen (54.3%), methane (44.3%), argon (0.99%), carbon dioxide (0.31%), and ethane (0.03%) (US EPA 2015e).

To address the increases in methane concentration in the water produced from the drinking water wells in the spring of 2007, US EPA conducted groundwater sampling in the area from October 2011 to April/May 2013. US EPA (2015e) evaluated the dissolved gases for total composition as well as methane isotopic composition of the dissolved methane to determine, if possible, the source of the methane in the gas migration event: biogenic, thermogenic, mixed, or wet thermogenic gas. Isotopic analysis of dissolved methane in groundwater from the Poison Canyon Formation collected from four domestic wells (see Figure 15.30) shows δ¹³C_CH4 and δ²H_CH4 ranging from −49.2 to −37.7‰ and −230.6 to −130.5‰, respectively. These levels are consistent with a thermogenic source (US EPA 2015e).

A domestic well in the nearby Arrowhead Ranchettes subdivision had a large change in isotopic signature over the course of the four US EPA sampling events. The first sampling event had a methane thermogenic signature, while a mixed thermogenic/biogenic signature occurred during the last three US EPA sampling events. Rapid changes in methane sources could relate to differences in available microbial electron acceptors, possible influx or degradation of organic matter, or introduction of different natural or anthropogenic compounds. Domestic wells in the Little Creek Field study area contained methane with a thermogenic signature, similar to deeper CBM‐producing coalbed gas. However, US EPA noted that the methane signature showed a distinct methane oxidation trend.

Geochemical analysis was performed, and the sulfate‐dependent anaerobic oxidation of methane was noted. Elevated dissolved sulfide concentrations within the shallow Poison Canyon Formation aquifer were related to secondary biogeochemical processes, which US EPA linked to the upward migration of thermogenic methane sourced from the Vermejo Formation into the shallow Poison Canyon Formation, which is also used locally as a potable water source. US EPA proposed that the methane is acted upon by microbes and is oxidized to carbon dioxide (CO₂) using sulfate (SO₄²⁻) as the electron receptor. The equation, as described by Reeburgh and Heggie (1977), is a slow biochemical process, which produces bisulfide (HS⁻) and bicarbonate (HCO₃⁻) as end products:

Anaerobic oxidation of methane is occurring based on multiple lines of evidence: (i) the consumption of dissolved methane and sulfate by microbial communities, (ii) the production of dissolved sulfide and bicarbonate, (iii) methane loss coupled to the production of higher molecular weight (C₂₊) gaseous hydrocarbons, (iv) distinct patterns of δ¹³C in DIC, and (v) a systematic shift in sulfur and oxygen isotope ratios of SO₄, which is indicative of microbial sulfate reduction. Sulfate‐reducing processes control the natural attenuation of methane, and there are no supporting data showing time frames required to reduce dissolved methane concentrations to low levels in groundwater (US EPA 2015e).

Due to the increased methane concentrations in groundwater in this area, some domestic wells have been equipped with water treatment units to remove dissolved methane and dissolved sulfide. Since late 2010 to early 2011, there has been a decrease in detected dissolved methane concentrations, which as US EPA (2015e) suggests is due to a combination of water treatment systems on the impacted domestic water wells and natural attenuation processes.

Main Findings:

• Water resources currently used as potable aquifers and classified as underground sources of drinking water (USDW) lie at depth ranges within or near CBM resources. The estimated vertical separation between water supply wells and methane production zones in CBM wells ranges from <100 ft (31 m) to >2000 ft (610 m).
• All 12 domestic wells in the US EPA study contained dissolved methane, consistent with widespread naturally occurring methane in different groundwater zones and surface water. In the Little Creek Field in Huerfano County, gas migration was documented but could not be correlated with high certainty to HVHF operations.
• Due to subsurface geochemistry conditions in the US EPA study area, water treatment units were installed on some domestic wells to remove methane and sulfide dissolved in the groundwater.
• Groundwater sampling showed consistent major ion patterns, suggesting that, significant during the period of the US EPA study, water migration from deeper methane‐producing zones to shallower aquifers used for drinking water has not occurred (US EPA 2015e).
• Water samples from domestic wells, monitoring wells, and surface water did not contain glycol. One of the water production wells contained low levels of diethylene glycol and triethylene glycol. Various glycol compounds have been documented to be chemicals used during HVHF operations (Ely 1989; US EPA 2015e; FracFocus 2017; US House of Representatives 2011; Veatch et al. 1989; Vidic et al. 2013).
• Concentrations of BTEX compounds in this study are in orders of magnitude lower than US EPA drinking water standards (US EPA 2009) established using MCLs. Hydrocarbons make up about half (46%) of the detected organic compounds, which may be associated with undocumented petroleum fuel spills. None of these specific hydrocarbons or their breakdown products were associated with chemicals used locally in HVHF operations, suggesting the low levels of detected hydrocarbons might be associated with naturally occurring or unidentified sources;
• Although TBA was detected in groundwater samples collected from six wells, the source of the TBA is unknown.
• Methane is widespread in aquifers in the study area, sourced from underlying coal seams. A gas migration event from October 2007 was studied by US EPA (2015e). Based on the methane isotopic signature, the gas found as a result of the gas migration event was thermogenic in origin and sourced deeper in the basin. By 2010 to early 2011, detected dissolved methane concentrations in domestic well water have decreased due to mitigation measures.

15.6.4 Summary of US EPA Retrospective Studies

The US EPA retrospective studies (2015a, b, c, d, e) provided important information but were limited to some degree by the lack of available long‐term monitoring information and background data. Nonetheless, US EPA retrospective studies (US EPA 2015a, b, c, d, e) showed the following:

• US EPA used multiple lines of evidence to demonstrate HVHF operations can, in certain circumstances, impact groundwater resources. In other cases, contaminants detected in some wells had unidentified sources.
• Impacts to water resources appear to be site specific and can range in frequency and severity:
  • In areas with limited source water availability, HVHF can impact water quantities.
  • Groundwater resources can be impacted by large‐volume or high‐concentration spills or leaks of drilling fluids, specialized fracturing chemicals, coproduced brines, and petroleum hydrocarbons.
  • Injection of HVHF fluids into oil and gas wells with inadequate mechanical integrity can allow gases or liquids to migrate and impact groundwater resources.
  • Abandoned or improperly closed or sealed mines, landfills, oil, gas, and water wells can create conduits for the migration of gas or liquid contaminants into water resources.
  • Although not common, injection of HVHF fluids directly into groundwater resources can occur.
  • Discharge of inadequately treated drilling and HVHF wastes to surface water can impact water resources.
  • Disposal or storage of HVHF wastes in unlined pits can result in contamination of groundwater resources.
  • Stray methane gas was noted in groundwater to some degree in all five study areas and is relatively common.

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Suggested Reading

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