groundwater protection and unconventional gas extraction ...€¦ · unconventional gas resource...

Issue Paper/

Groundwater Protection and Unconventional GasExtraction: The Critical Need for Field-BasedHydrogeological Researchby R.E. Jackson1, A.W. Gorody2, B. Mayer3, J.W. Roy4, M.C. Ryan3, and D.R. Van Stempvoort4

AbstractUnconventional natural gas extraction from tight sandstones, shales, and some coal-beds is typically

accomplished by horizontal drilling and hydraulic fracturing that is necessary for economic development of thesenew hydrocarbon resources. Concerns have been raised regarding the potential for contamination of shallowgroundwater by stray gases, formation waters, and fracturing chemicals associated with unconventional gasexploration. A lack of sound scientific hydrogeological field observations and a scarcity of published peer-reviewedarticles on the effects of both conventional and unconventional oil and gas activities on shallow groundwatermake it difficult to address these issues. Here, we discuss several case studies related to both conventional andunconventional oil and gas activities illustrating how under some circumstances stray or fugitive gas from deepgas-rich formations has migrated from the subsurface into shallow aquifers and how it has affected groundwaterquality. Examples include impacts of uncemented well annuli in areas of historic drilling operations, effectsrelated to poor cement bonding in both new and old hydrocarbon wells, and ineffective cementing practices. Wealso summarize studies describing how structural features influence the role of natural and induced fractures ascontaminant fluid migration pathways. On the basis of these studies, we identify two areas where field-focusedresearch is urgently needed to fill current science gaps related to unconventional gas extraction: (1) baselinegeochemical mapping (with time series sampling from a sufficient network of groundwater monitoring wells)and (2) field testing of potential mechanisms and pathways by which hydrocarbon gases, reservoir fluids, andfracturing chemicals might potentially invade and contaminate useable groundwater.

IntroductionIncreased natural gas extraction from low-

permeability rocks (rather than traditional permeablereservoirs) has transformed the outlook for electricity

1Corresponding author: Geofirma Engineering Ltd., 11Venus Crescent, Heidelberg, Waterloo Region, Ontario, Canada;[email protected]

2 Universal Geoscience Consulting, Inc., 1214 West AlabamaStreet, Houston, TX; [email protected]

3Department of Geoscience, University of Calgary, Calgary,Alberta, Canada; [email protected]; [email protected]

4National Water Research Institute, EnvironmentCanada, Burlington, Ontario, Canada; [email protected]; [email protected]

Received December 2012, accepted April 2013.© 2013, National Ground Water Association.doi: 10.1111/gwat.12074

generation, building heating, industry, and transportationin North America over a mere 10 years (MIT 2011). Theeconomic development of unconventional gas reservoirshas been spurred by recent advances in both directionaldrilling and reservoir stimulation by hydraulic fracturing.Deep and long horizontal wells (up to 3 km or 9000 ft inhorizontal length) combined with multi-stage hydraulicfracturing can now effectively exploit geographicallyextensive (Figure 1), often relatively thin (tens of meters)formations that contain unconventional hydrocarbonresources, resulting in an increased supply of naturalgas and a commensurate increase in gas use in NorthAmerica; between 1989 and 2009, 88% of the 306 GWof electrical generation capacity constructed in the UnitedStates was gas-fired. Gas-fired energy now providesabout one quarter of U.S. energy uses (MIT 2011),

488 Vol. 51, No. 4–Groundwater–July-August 2013 (pages 488–510) NGWA.org

approximately 90% of which comes from U.S. gas-fieldproduction and approximately 10% from Canadian fields(U.S. Energy Information Administration 2012).

Unconventional gas resource developments haveoccurred both in frontier areas and areas with historicconventional oil and gas development (Figure 1). Whileconventional gas extraction activities are typically focusedin well-defined, spatially restricted areas above oil andgas reservoirs, unconventional gas fields are developedon the premise that the gas-bearing formations are widelydistributed in the subsurface. Unconventional gas wellsare thus typically drilled in densely spaced and equidistantsurface patterns that cover far larger subsurface areasthan conventional plays. Although recent advances indirectional drilling technology permit over 20 horizontalwells to be drilled from a single well pad, large numbersof well pads can still create extensive regional footprints.

The rapid expansion of the unconventional gas indus-try has been accompanied by public concern regardingprotection of environmental and human health particularlyover possible pollution of shallow groundwater1 by migra-tion of natural gas, formation water, and/or fracturingfluids from deep formations induced by hydraulic frac-turing. In some jurisdictions—New York State, France,and Quebec (Canada) for example—explicit or de-factomoratoria on hydraulic fracturing exist until uncertaintiessurrounding the process have been resolved. Indeed manyarticles in newspapers, journals, and the electronic newsmedia regarding pollution of groundwater by the hydraulicfracturing industry (e.g., Zoback et al. 2010; Molofskyet al. 2011; Osborn et al. 2011; Myers 2012; Schnoor2012; Warner et al. 2012) convey widely differing viewsregarding risks of groundwater contamination by thedevelopment of unconventional gas plays. Unfortunately,little peer-reviewed scientific information is availableon the hydrogeological conditions—shallow groundwa-ter quality in particular—associated with unconventionalgas production or, for that matter, with conventional oiland gas production. There is a distinct possibility suchmoratoria will continue until more objective scientificinformation is available.

As an example of widely differing views, a recentnational review in the UK concluded that while it may bepossible to propagate a fracture to the ground surface fromdeep unconventional reservoirs (i.e., more than 2000 m ormore than 6000 ft) by hydraulic fracturing, it is generallynot practically feasible to do so because the pressuresrequired to increase the fracturing over the full depthare not tractable in hydraulic stimulation (UK RoyalSociety/Royal Academy of Engineering 2012). In contrast,

1We use the term ‘‘shallow groundwater’’ throughout thisarticle as a short-hand to indicate potable or otherwise useablewater with a total dissolved solids (TDS) content of less than1,000 mg/L that is—or may in future—be used as a groundwatersupply for homes, farms, industries or municipalities. Thus theterm ‘‘groundwater protection’’ refers to the protection of thisgroundwater, while ‘‘saline groundwater’’ and ‘‘saline aquifers’’indicate waters with higher TDS, typically more than 4,000 mg/L,which are not suitable for human or livestock consumption.

an article in this Journal (Myers 2012) suggested thatunder some conditions there could be surface discharge offracturing fluids along naturally occurring fractures in lessthan 10 years after hydraulic fracturing of unconventionalgas wells.

Widely differing views, such as those expressedabove (the UK’s Royal Society/Royal Academy of Engi-neering [2012] vs. Myers [2012]) clearly indicate theneed for a more comprehensive and conclusive knowledgebase. This is best approached with more extensive fieldand laboratory-based research, which is needed to supportthe development of groundwater models with well-definedhydrogeological settings, calibrated parameter values, andappropriate initial and final boundary conditions. ThisIssue Paper identifies issues and related hydrogeologi-cal research needs and approaches that will help protectgroundwater quality during the development of unconven-tional gas resources. As such, we outline a new challengein contaminant hydrogeology. Addressing this challengewill require an improved cooperation and communicationbetween hydrogeological researchers and industry, ideallythrough collaborative research.

To support our case, we briefly describe the natureof unconventional gas production activities as they relateto identifying contaminants of concern. We discuss thepotential contaminant migration pathways to shallowgroundwater and the behavior of these contaminantsin shallow groundwater and factors affecting aquifervulnerability. We stress that many of these problems arealso common to conventional hydrocarbon productionactivities and are not solely related to unconventionalgas production. Finally we address the field-basedhydrogeological research needs necessary to help protectgroundwater quality during the development of uncon-ventional gas resources and briefly describe how suchresearch might be conducted.

Stimulation and Extraction ofUnconventional Gas

The recovery of economic volumes of unconventionalnatural gas from low permeability and regionally exten-sive formations requires stimulation through hydraulicfracturing—that is, “fracing” or “fracking”—of the hostrock. Hydraulic fracturing has been conducted in verti-cal boreholes since the 1940s for enhanced conventionalproduction of oil and gas.

The increasingly long horizontal wells (most lateralsare more than 1 km or more than 3000 ft) with an increas-ing number of fracturing stages (Tutuncu et al. 2012) usedin unconventional gas production require substantiallyhigher hydraulic fracturing-fluid injection volumes, how-ever. For example, water-based hydraulic fracturing ofthe Horn River Basin (British Columbia, Canada) requiresapproximately 50,000 m3 of fluid (10–20 million gallons)and approximately 2000 metric tons of proppant per hor-izontal well with 20 fracs per well (Johnson and Johnson2012). Similarly, 7700 to 38,000 m3 of fluid (2–10 milliongallons) is used to fracture each horizontal deep well in the

NGWA.org R.E. Jackson et al. Groundwater 51, no. 4: 488–510 489

Figure 1. Distribution of shale gas plays in North America. Note that other unconventional formations (e.g., tight-gas,sandstones, and coal formations) are not shown. (Courtesy of Ziff Energy Group, Calgary, 2012.)

Marcellus Shale in the northeastern United States (Kargboet al. 2010). Because water used in hydraulic fracturingcan imbibe into the host rock’s matrix and reduce gas rela-tive permeability (and hence gas production), nonaqueousbased fracturing fluids (Table 1; e.g., Lestz et al. 2007)provide an alternative approach that also assists with watersupply and gas recovery issues.

Hydraulic fracturing is conducted sequentially in“stages” or perforated sections of the horizontal pro-duction casing (Figure 2), and involves the injection offluids (gases, liquids, foams), with a mix of additives(discussed below), at elevated hydraulic pressures aroundeach “stage” to produce and propagate fractures. The frac-tures increase the bulk formation permeability throughshear failure (see Zoback et al. 2012), allowing hydrocar-bon gases to flow into the production well. The hydraulicfracturing liquids are designed to conduct proppants (e.g.,sand and other noncrushable substances; Table 1) thatenter the new fractures formed in shales and tight sand-stones, preventing them from reclosing.

Hydraulic fracturing-induced fractures predominantlydevelop in the plane perpendicular to the orientation of theleast principal stress, which in deep shale gas reservoirs(more than 2 km or more than 6000 ft) is usually one of

the two horizontal stresses (Zoback 2010). In some cases“preferential opening of the natural fracture systems” ismore dominant than opening of new hydraulic fractures(King 2010). While “pre-existing fractures and faultshave some influence on fracture propagation, the overalltrajectory of fracture propagation is controlled by theorientation of the least principal stress” (Zoback 2010).

While most shale gas plays in North America aredeeper than one kilometer, a few shallower plays areexploited to a limited extent (e.g., the eastern extent ofthe Colorado Group in Alberta (∼300 m depth) and theAntrim Shale in Michigan [180 to 670 m]). Many coal-bed gas formations are also present at shallower depths(less than 600 m), where vertical wells that are typicallyfracked with nitrogen (NEB 2009) and horizontal frac-turing orientation predominate. Empirical data suggestthat horizontal fracturing predominates in stimulationconducted shallower than 450 m depth, while verticalfracture orientations predominate below 600 m depth(Warpinski 2011), because of the principal stress orien-tations. This is because at these shallow depths withinthe overburden the direction of least principal stress isvertical due to erosional unloading that has occurred insedimentary basins (for discussion see Goodman, 1989

490 R.E. Jackson et al. Groundwater 51, no. 4: 488–510 NGWA.org

Table 1Composition of Fluids Potentially Present in Fracking Fluids

Component and Purpose Chemical

Carrier or “make-up” fluid Water, N2, CO2, LPG, foams, emulsionsProppants—designed to keep fractures open after fracking

fluid pressure decreasesSand, resin-coated sand, sintered bauxite, alumina, ceramics,

and silicon carbideClean up damage from initial drilling, initiate fracturing HCl, other acidsAdditives to adjust frack fluid viscosity, and form

gels—designed to keep proppants suspended in frack fluidso it will enter and “prop open” new fractures

Viscosity adjusters: Guar gum, cellulose-based derivatives.Gel formation: Cross-linking agents (borate compounds or

metal complexes)Viscosity “breakers” (reducers) designed to decrease viscosity

after frack fluid has reached its target zoneAmmonium persulfate, sodium peroxydisulfate

Stabilizers to delay the action of breakers, biocides, fluid-lossadditives, friction reducers

Latex polymers or copolymers of acrylamides, and acidcorrosion inhibitors, e.g., alcohols

Acid corrosion or scale inhibitors Isopropanol, methanol, formic acid, acetaldehydeFriction reducers for low-viscosity “slickwater” fracking

where proppants penetrate more deeply into fracturesSurfactants, polyacrylamide, ethylene glycol

Biocides to inhibit sulfate reducers Aldehydes, amidesSurfactants to improve relative gas permeability IsopropanolClay stabilizer to prevent clay flocculation KCl (for clays)Other Glycols, amines, defoamers

Sources: Lyons and Plisga 2004; Kaufman et al. 2008, MIT 2011; US EPA 2011; van Stempvoort and Roy, 2011, and Schlumberger (www.slb.com), and OpenFrac.com.

and Zoback 2010). Data from tiltmeters and micro-seismic imaging also indicate that mixed vertically andhorizontally oriented fractures are often generated whenstimulating reservoirs at depths below 450 m and above2 km.

Fracture growth monitoring by microseismic andmicrodeformation techniques suggests that induced ver-tical fracture heights do not exceed “tens to hundreds offeet” (Fisher and Warpinski 2012). The evidence availableis largely related to remotely measured or modeled frac-ture propagation. For instance, the empirical analyses ofmicroseismic data from several thousand fracturing oper-ations in four U.S. shale gas plays by Davies et al. (2012)indicated a maximum fracture height of approximately590 m and a probability estimate of approximately 1% thata stimulated hydraulic fracture would extend verticallymore than 500 m. From this, the authors (Davies et al.2012) derived a general minimum separation distanceof 600 m between target shale and overlying freshwateraquifers but they also suggested that minimum separationdistances be investigated for each new geologic area.

However, a Society of Exploration Geophysicistsresearch committee has reported that “downhole micro-seismic monitoring has limited spatial coverage creatinga bias at the event locations and an incomplete view ofthe stimulated reservoir volume” (Tutuncu et al. 2012).Reducing this bias would require one or more shallow (30to 60 m deep) boreholes drilled exclusively for seismicmonitoring (which, notably, could be used for subsequentgroundwater monitoring). A related technique, near sur-face microseismic data acquisition, has also recently beenadopted for hydraulic fracturing monitoring (Duncan and

Table 2Composition of Inorganic Ions in Flow-back

Fluids from Three U.S. Shale Plays

Formation

Analytes (mg/L) Fayetteville Marcellus Barnett

Na 5363 24,445 12,453Mg 77 263 253Ca 256 2921 2242Sr 21 347 357Ba 0.8 679 42Mn 0.5 3.9 44Fe 28 26 33SO4 149 9.1 60HCO3 1281 261 289Cl 8042 43,578 23,798TDS 15,219 72,533 39,570Sp Gravity 1.01 1.05 1.03Depth (m) 300–2000 1200–2600 2000–2600

Source: Aqua-Pure Ventures, Calgary, Alberta, http://www.fountainquail.com/news/presentations/assets/IOGCC_Shale_Gas_Water_Mngt.pdf.

Eisner 2010) to improve the estimation of the reservoirvolumes that are stimulated by hydraulic fracturing,identify subsurface faults, and monitor posthydraulicfracturing microseismic activity after the hydraulicfracturing pumps are turned off (Wessels et al. 2011).

“Flow-back fluids” are extracted from the gaswell after hydraulic fracturing to improve relative gaspermeability and enhance gas production. These fluids(Table 2) initially tend to be comprised mainly of the


ConventionalRecovery

UnconventionalRecovery

Coal Bed MethaneRecovery

Shale

Coal bed

Petrolem ‘trap’

‘Knick-point’

100 to 1000m long‘stages’ or ‘perforations’

formed by blasting beforefracking (15 to 25 m

apart) to allow fluid flowbetween the formation

and casing

‘Shallow

’(<

600 m)

‘deep’(>

2 km)

1. Before fracking 2. During fracking 3. After fracking

Well head constructionschematic

Not to scale.

DomesticWaterWell

Separation distance

Fractures heldopen by proppant

Frack fluid in, P

Wellproduction(includingflow-backfluids), P

Perforatedcasing

Newlyintroduced

fracture

Surfacecasingvent

Surfacecasin

Productioncasing

Production tubing

Horizontal well lengths of up to several kms

Figure 2. Schematic illustrating (i) the nature of conventional, coal-bed methane, and “unconventional” resource recovery,(ii) the hydraulic fracturing process; and (iii) the nature of surface and production casing (and associated borehole annuluscementing).

injected fracturing fluids, but with continued productionan increasing contribution may come from formationwaters if the formation contains “movable fluids,” thatis, they exhibit higher than irreducible water saturation.Injected fluids can react with the host formation andleach both salts and radionuclides that change flow-backwater quality.

These flow-back fluids usually require on-site storagefollowed by recycling, reinjection, or deep-well disposalinto a saline aquifer. The potential for groundwater con-tamination by flow-back fluids is therefore quite varied.For example, flow-back fluids may contaminate shallowgroundwater due to releases from lagoons during extremeprecipitation events or failure of the impoundments. Con-sequently, regulatory agencies have increasingly requiredon-site storage containers (and lagoons) to be covered toprevent such releases (e.g., ERCB 2011).

Contaminants of ConcernGroundwater can be affected during unconventional

gas production by substances associated with natural gasitself, that is, principally methane (US NIOSH 1983). Theprimary problem with methane in shallow aquifers is that

it poses both an explosion and asphyxiation (confinedspaces) hazard either during well water extraction or byescaping and accumulating in basements, well pits, etc.The American Conference of Governmental IndustrialHygienists’ (ACGIH) methane exposure limit in air is1000 ppm (time-weighted average). Many jurisdictionsrequire reporting for “trigger levels” of dissolved methanein well water (e.g., 28 mg/L is a “recommended actionlevel” from the U.S. Department of the Interior Office ofSurface Mining Reclamation and Enforcement; US DOI2001).

Within shales, we may expect roughly equalgas-phase and water-phase porosities, that is, saturations(Curtis 2002). However, methane dissolved in formationwaters will have a solubility controlled by the temper-ature, hydraulic pressure, and salinity of the formation(Duan et al. 1992) that is likely far greater than thesolubility of methane in groundwater at ground-surfacetemperatures and atmospheric pressure (∼30 mg CH4/L).By fracturing the gas reservoir, an operator removessome formation water to increase the relative gas perme-ability and recovers the gas as it desorbs, depressurizes(decreasing the bubbling pressure), enters the fracturesand is extracted (see Figure 2). If this gas is not captured,


it is available to migrate as the buoyant free gas phaseup the annulus of poorly cemented wells.

Free gas exsolving or bubbling through water inwater wells may also lead to deterioration of waterquality including well water discoloration and turbiditydue to microbubbles or particulate suspension (Harrison1983; Bair et al. 2010; Gorody 2012). Microbiologically-mediated oxidation of free and dissolved hydrocarbons(e.g., methane) can be accompanied by iron and sulfatereductions leading to Fe(II) and/or Mn(II) sulfide mineralprecipitation, and the attendant odor of reduced gases suchas H2S (Rauch 1983; Kelly et al. 1985; Gorody 2012).Free gases in groundwater around well screens can alsocause a decrease in hydraulic conductivity with an asso-ciated decrease in water well yield (Yager and Fountain2001; Gorody 2012). “Stray gas” or “fugitive gas” is oneof the main concerns around unconventional gas recovery.Chemical and isotopic analyses (see Box 1) are usedto differentiate between “thermogenic” gases producedfrom the target reservoirs, mixed gases from intermediateformations, and “biogenic” gases most frequently foundin shallower geologic formations and aquifers.

Box 1

Geochemistry of Natural GasNatural gas forms in the subsurface by thetransformation of organic matter to methane(CH4 or C1) and potentially other low molecu-lar weight, volatile hydrocarbons such as ethane(C2H6 or C2) and propane (C3H8, or C3). Thiscan occur through anaerobic microbial reactionssuch as methanogenesis resulting in ‘‘biogenic’’or ‘‘bacterial’’ gas mainly composed of CH4,or by abiotic processes at elevated tempera-tures and pressures, resulting in ‘‘abiogenic’’,‘‘thermocatalytic’’, or ‘‘thermogenic’’ natural gas.The latter often contains not only methane(C1) and ethane (C2), but also higher alka-nes such as propane (C3), butane (C4), andpentane (C5).Over the course of the last 30 years the naturalformation of biogenic and thermogenic methanehas been documented to occur in a widearray of anaerobic environments (e.g., Barkerand Fritz 1981; Schoell 1988; Whiticar 1999).Biogenic methane is commonly associated withorganic-rich marine and lacustrine sediments,peat, and coal deposits and is generated inlow-temperature and -pressure environments.For some shallow aquifers in Alberta (Tayloret al. 2000) and Texas (Grossman et al. 1989)it has been suggested that not only methanebut also ethane is generated by biogenesis.In other shallow aquifers in Ontario (Aravenaet al. 1995), Illinois (Coleman et al. 1988) and

Iowa (Simpkins and Parking 1993) only biogenicmethane has been found. The absence ofpropane, butane, and pentane in biogenic naturalgas results typically in wetness parameters(the ratio of C1/C2-C5) > 1000. Thermogenicmethane is created under high temperatures(>120 ◦C) and pressures (50–80 MPa) foundat depth (>2500 m) within sedimentary basins(Hunt 1979; Barker 1990). Due to oftenappreciable amounts of ethane, propane, butane,and pentane in thermogenic gas its wetnessparameter is typically much lower than 1000.Coal-bed gas systems can contain thermogenic,migrated thermogenic, biogenic, or mixed(thermogenic and biogenic) gas. Mixed gas maybe produced through a variety of mechanismsincluding the incursion of Pleistocene meltwatersinto sedimentary basins containing organic-richshales (Martini et al. 2003).Natural gas formed through these differentprocesses and in different formations canbe distinguished by a suite of geochemicaland isotopic analyses. These include theconcentrations of methane (C1), ethane (C2),propane (C3), butane (C4), and pentane (C5),the stable carbon and hydrogen isotope ratioscontained within these normal alkanes, as well as14C, which allows discrimination between recentbiogenic and fossil thermogenic hydrocarbons.The upper figure presents a cross-plot of δ13Cand δ2H values of biogenic and thermogenicmethane for selected shallow aquifers andresource plays in North America. δ13C valuespredominantly < −55‰ in shallow groundwatersof Alberta and selected groundwater wells fromPennsylvania suggest that the methane is ofbiogenic origin (Cheung et al. 2010; Osbornand McIntosh 2010). In contrast, thermogenicand mixed gas from various resource plays istypically characterized by δ13C values >−60‰and sometimes higher δ2H values (Jendenet al. 1993; Desrocher 1997; Laughrey andBaldassare 1998; Martini et al. 2003; Hillet al. 2007; Cheung et al. 2010; Osborn andMcIntosh 2010; Rodriguez and Philip 2010;Tilley et al. 2011; Tilley and Muehlenbachs2013) compared to those found for biogenicmethane. This graph is typically known as aSchoell (1988) diagram. The lower figure showsa Bernard diagram where biogenic gas is typicallydistinguished by δ13C values < −55‰ andwetness parameters more than 1000 (Cheunget al. 2010; Osborn and McIntosh 2010) fromthermogenic gases that are often characterizedby δ13C values of methane > −60‰ and wetnessparameters less than 1000 (Jenden et al. 1993;Desrocher 1997; Laughrey and Baldassare


1998; Martini et al. 2003; Hill et al. 2007;Cheung et al. 2010; Osborn and McIntosh 2010;Rodriguez and Philip 2010; Tilley et al. 2011).

-50

-100

-150

-200

-250

-300

-350

δ13C [‰]

δ13C [‰]

δ2 H [‰

]

-20-30-40-50-60-70-80

Albertagroundwater

Appalachianwaterwells

Barne

tt

AntrimShale Alberta Basin

Appalachian

Basin

-20-30-40-50-60-70-80

10000

1000

100

10

100000

Wet

ness

(C

1/C

2+C

3)

Albertagroundwater

Appalachianwater wells

AlbertaFoothills

Bar

nett

Appalachian

BasinAnt

rim S

hale

AlbertaBasin

(a)

(b)

Figure for Box 1. Schoell (upper) and Bernard(lower) diagrams displaying the δ13C values ofmethane vs. δ2HCH4 values (Schoell) and gaswetness (Bernard) in shallow groundwater ofAlberta (Cheung et al. 2010, unpublished data)and Pennsylvania (Osborn and McIntosh 2010),and various natural gas plays in Northern America(Jenden et al. 1993; Desrocher 1997; Laughreyand Baldassare 1998; Martini et al. 2003; Hill et al.2007; Cheung et al. 2010; Osborn and McIntosh2010; Rodriguez and Philip 2010; Tilley et al.2011).

There is much public concern that specific chemicalspresent in fracturing fluids may pollute shallow groundwa-ter in the vicinity of unconventional gas sites. Fracturingfluids may be based on, or made up with, a number of flu-ids (water, hydrocarbon, emulsions, foams, or gases, e.g.,N2 or CO2), and may contain a wide range of chemicaladditives (Table 1 and Van Stempvoort and Roy 2011).Access to information about the chemical compositionof hydraulic fracturing fluids and additives is emergingas appropriate information databases are published (e.g.,http://fracfocus.org/).

Shallow groundwater might also becomecontaminated by natural liquids from the producingformation, including saline formation waters and gascondensates (Box 2). Formation waters are usually Na-Clsaline fluids or brines with elevated total dissolved solidsand can contain naturally occurring heavy metals (e.g.,barium) and radionuclides (e.g., 226Ra from decay ofnatural 238U in the shales). Because of the deleteriouseffects of saline formation waters or brines on activatedsludge processes in municipal treatment plants, thedisposal of brines is increasingly directed to injectionwells or to recycling facilities where they exist (e.g.,Pennsylvania and Texas). Condensates can also haveelevated salinity, sodium, metals, naturally occurringradionuclides, and organic compounds (Hitchon et al.1971; Orem et al. 2007; Kargbo et al. 2010).

Box 2

Defining ’Groundwater Gas’ Terms—AnInterdisciplinary ChallengeStates in which ‘‘gases’’ can exist:

• True ‘‘gas’’ state, also known as ‘‘free’’ gas orbubbles.

• Sorbed gas—coal-bed gases (i.e., mostlymethane) that don’t flow into wells unless theformation pressure is lowered by pumping.

• Dissolved gas—gas molecules that are dis-solved in water. Dissolved gas concentrationsare discussed below.

• Nonaqueous phase liquid (NAPL)—manyhydrocarbons can occur as an oily liquid. Thiscan also be called ‘‘liquid natural gas’’ or‘‘condensate’’.

• Gas condensate—hydrocarbons, usuallycoproduced with (or ‘‘condensed from’’) naturalgas, which are near-liquid at ambientconditions. Typically C2 to C20 compounds.

TerminologyGasoline or petrol is comprised mainly offractionally distilled petroleum that is liquid underambient conditions.Gasoline Range Organic’ (GRO) compoundsinclude four volatile petroleum compounds oftenknown by their acronym ‘‘BTEX’’: benzene,toluene, ethylbenzenes, and xylene. They arecommonly used as indicator parameters forgasoline or petrol spills.Natural Gas is dominantly methane, but can haveminor concentrations of CO2, H2S, and C2-C5hydrocarbons.Shale Gas (also known as Unconventional Gasand Tight Gas) is natural gas produced fromrelatively impermeable formations.


Methane in natural gas can be:

• biogenic—formed by microbial processes (e.g.,CO2 reduction in relatively shallow, lowtemperature environments)

• thermogenic—formed by ‘‘cracking’’ of organicmatter in deeper formations at higher temper-ature (more than 120 ◦C). Also called ‘‘thermo-catalytic’’ gas.

Liquefied petroleum gas—gas mixtures thatoccur in the liquid and/or nonaqueous phaseunder ambient conditions (e.g., propane andbutane).Wet or associated gas is natural gas with liquidhydrocarbon or condensate phases present.Dry or nonassociated gas is more than 95%methane (or C1).C1-Cn gases—one of two nomenclatureapproaches, where the subscript indicates thenumber of carbons in a chain (aliphatic) or ring(aromatic) structure (for example methane is C1;ethane, also known as ethylene are C2, etc.).‘‘Wetness’’ is often used to characterize naturalgas—often estimated as (C1/

∑C2+3) where

biogenic gas typically more than 1000 andthermogenic less than 1000. Thermogenic gasoften is rich in C2+3 hydrocarbons, whereasbiogenic gas is not.Gas as biogeochemical parameter:

• ‘‘biogeochemical’’ gases (formed of carbon,hydrogen, oxygen, nitrogen, and sulfur; e.g.,O2, CO2, CH4, N2, H2, H2S, etc.)—gases areproduced or consumed in major biogeochem-ical processes. Almost all of these gases areredox sensitive or redox determining.

• ‘‘permanent’’ or ‘‘fixed’’ gases have twopossible definitions:

• do not form a liquid phase under near-surfacetemperatures and pressures—also known as‘‘incondensable’’ gases;

• are those gases within the atmospherewith relatively constant (i.e., ‘‘permanent’’)concentrations (e.g., O2, N2, and Ar);

• inert gases can be defined as monoatomicgases with low chemical reactivity (e.g., He,Ne, Ar, Kr, Xe, and Rn),

Describing gas ‘‘concentration’’ in the sub-surface:

• Total dissolved gas pressure (TDGP orPTGD)—sum of the partial pressures of alldissolved gases, measured in situ or by

using advanced gas sampling and analyticaltechniques. PTGD can be measured inabsolute or gauge (absolute minus atmosphericpressure). At the groundwater table, absolutePTGD is equal to atmospheric pressure andgauge PTGD is equal to zero. Becausedissolved gas solubility increases with waterpressure (Manning et al. 2003), estimationof true dissolved gas concentrations requiresthe measurement of in situ total dissolvedgas pressure (PTDG; Manning et al. 2003)together with gas composition unless advancedsampling and laboratory techniques (Beyerleet al. 2000; Gardner and Solomon 2009)are used. True or in situ dissolved gasconcentration can be estimated as theproduct of the lab-estimated dissolved gasconcentration (really equivalent to a gascomposition since it is measured at theatmospheric pressure in the lab; PLAB)multiplied by the ratio of PTDG:PLAB (McLeishet al. 2007). Dissolved groundwater gasconcentrations are at their maximum at a depthin the subsurface (or a given hydraulic pressure)when PTDG is at its ‘‘bubbling pressure’’(equal to absolute pressure, or the sum ofatmospheric and hydraulic pressures; Manninget al. 2003; Roy and Ryan 2010). At this point,the groundwater is saturated with respect todissolved gases, and increased gas productioncan result in a phase change to free gas state,or bubble exsolution. Since stray gas migrationoften involves free gas transport, the PTDGcan be compared to the bubbling pressure todetermine the likelihood that free gas would bepresent in a formation. Although the build up,and possibly ‘‘pulsed migration’’, of free gases(Gorody 2012) can cause significant changes inthe mass of gases within a formation, the PTDGmay stay at or near the bubbling pressure.In this case, changes with time or space indissolved gas and isotopic composition may bemore diagnostic than changes in PTDG.

• Gas composition is the relative concentrationsof different gases as a percentage of allgases. Gas compositions can be expressedas equivalent volumetric ratios (i.e., ppmv) orvolume percentages in the gas phase. Whenthey are at STP (Standard Temperature &Pressure), gas compositions can be equal togas concentrations if they are expressed asvolume ratios (e.g., the atmosphere is 78.1%N2, or 780,900 ppmv).

• Dissolved gas concentration is

• the mass of a gas per unit volume ofwater (or unit mass of water for brines).


Common dissolved gas units are (1) mg/Lor mmol/L; (2) cm3

STP/L or ppmv, or (3)equivalent partial pressure of gas phase (atmor mm Hg). If units like ppmv are used, careneeds to be taken to ensure both the unitsof the gas solute and matrix (i.e., mass orvolume; gas or liquid state of matrix) areclearly stated;

• limited by formation of free gas or masstransfer with free gas at the ‘‘bubblingpressure’’;

• a function of Henry’s Law (temperature andsalinity dependent) and the in situ partialpressure of the gas of interest;

• Although dissolved gas concentrations areoften estimated by ‘‘headspace extraction’’(Kampbell and Vandegrift 1998), this tech-nique is only valid if the PTDG is closeto water equilibrated with the atmosphere(i.e., absolute PTDG equal to atmosphericpressure).

• Bubbling pressure is reached when PTDGis equal to the hydrostatic pressure. IfPTDG increases past this pressure, masstransfer into the free gas phase shouldoccur—i.e., exsolution, field effervescence,bubbling.

• gas solubility is the maximum concentration ofa gas that can exist in water at specific salinity,temperature, and (hydrostatic) pressure incombination with the other gases in the samewater.

Gas ‘‘Saturation’’ can have multiple meanings:

1. The relative proportion of gas phase to totalporosity (also know as gas porosity) withinsubsurface pore space. The presence of a freegas phase implies that there is a measureablegas saturation, Sg, in the pore volume (PV)such that the PV is ‘‘saturated’’ with gas(Sg), water (Sw) and perhaps oil (So) in whichPV = Sg + Sw + So.

2. Critical gas saturation (in coal-bed methane) isthe gas saturation (or gas porosity) upon whichcoal yields gas when pumped. Gas saturationcan be increased by decreasing the formationpressure (and hence decreasing the criticalbubbling pressure).

3. Dissolved gas saturation occurs when thePTDG is equal to the bubbling pressure.

Stray or fugitive gas: Terms usually applied tonatural gas (or perhaps carbon dioxide) that hasescaped from a well or gas-handling facility nearthe oil or gas well and has been detected in a

location where it is unwanted. In the context ofthis article, it is natural gas that has migrated intoshallow groundwater from a geological sourcemost likely through a poorly or incompletelycemented well.

The State of the ScienceOver the past few years numerous editorials, reports,

and issue papers have been written about environmentalissues related to shale gas development, all of whichaddress groundwater issues to varying extents (e.g.,Kargbo et al. 2010; Zoback et al. 2010; Schnoor2012; ALL Consulting 2012; Groat and Grimshaw 2012;Rozell and Reaven 2012; Tutuncu et al. 2012; UKRoyal Society/Royal Academy of Engineering 2012).Many of these contributions are “white papers,” focusingmainly on delineating the potential environmental issues,probable causes, and possible solutions (largely associatedwith more rigorous regulation and improved industrypractices).

Here we address the state of hydrogeologic science,that is, what is known and what is not known, withreference to a series of case histories or grouped studywork (Table 3). We argue that a better understandingof the hydrogeologic conditions, gas-migration processesand potential leakage pathways is required—that is,critical science gaps remain—to minimize the potentialenvironmental effects of groundwater contamination bydevelopment of unconventional gas plays. The widerange of probabilities used in a recent risk analysis ofpotential groundwater pollution by hydraulic fracturing(Rozell and Reaven 2012) reflects the lack of field dataused in their probability bounds analysis. Many of theseprobability ranges were based on newspaper articles orwere the authors’ “estimates,” which clearly demonstratesthe critical science gaps that confront hydrogeologists andregulatory officials as well as risk estimators.

Contaminant Pathways to Shallow Groundwater

Fugitive Gas Leakage from Active Production WellsMany of the current, well-publicized controversies

surrounding unconventional gas development in particu-lar relate likely to the accidental releases of “stray” or“fugitive” gases into shallow aquifers via the annuli ofimperfectly cemented gas wells. The source(s) of thesestray gases are rarely clear (Bair et al. 2010; Gorody2012). Although they could include the production zone,the shallower overlying formations in the “intermediatezone” between producing formations and shallow ground-water appear to be a more common source.

In an extensive study comparing the chemical andisotopic compositions of gases from surface casingvent flows (SCVF) and production zones accessed byalmost 300 conventional oil and gas wells in Alberta(Canada), the majority of the SCVF samples (∼75%)were sourced from formations above the production


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zones, while the remainder of the SCVF samples wereoften isotopically similar to gases from the productionformation (Muehlenbachs 2012; Tilley and Muehlenbachs2013). Similar measurements recently conducted at newlycompleted and hydraulically stimulated horizontal shalegas wells in the Montney and Horn River areas ofnortheastern British Columbia also revealed in some casesSCVF from intermediate zones and in other cases fromthe production formation (Muehlenbachs 2012; Tilley andMuehlenbachs 2013).

The potential for stray gas migration into shallowaquifers depends on various parameters including reser-voir pressures, well completion details, etc., but is oftenthought to be related to inadequate construction, comple-tion or maintenance of production wells (Chafin 1994).Indeed, unintended natural gas migration along produc-tion wellbores for conventional gas has been a “chronicproblem for the oil and gas industry . . . as a result ofpoor primary cement jobs, particularly in gas wells” (Steinet al. 2003). Between 7% and 19% of more than 1000wells drilled from 2005 to 2007 in western Canada hadgas migration along the casing annulus, and 9% to 28% ofthem had gas leakage through surface casing vents (Bexteet al. 2008). Similarly, a 1995 study determined that 15%of primary cement completions in the United States hadfailed (Dusterhoft et al. 2002).

Uncemented well annuli can become primary migra-tion pathways for stray or fugitive gas migration into shal-low aquifers. For example, uncemented well annuli wereidentified as the principal source of stray gases migratingalong vertical wells in the San Juan basin of New Mexicoand Colorado (Chafin 1994). Other causes of stray gasmigration include casing corrosion (particularly prevalentprior to the advent of cathodic protection) and accidentalrupture. Historically, regulators have not required casingcement across formations above the principal productiontarget zone.

The problem of leaky hydrocarbon wells is notconfined to a few areas of western Canada and thesouthwestern states of the United States. A report byLouisiana State University (Bourgoyne et al. 1998)indicated that there were 11,500 strings of casing in over8000 offshore wells in the Gulf of Mexico that exhibitgas migration in the annular space between casing androck or within inner casings. The pressure gauges onall casing strings should measure zero pressure after anyhydrocarbon well comes to steady state flowing conditionsand once the gauge has been opened and the pressurebled off through its needle valve. If continual bleedingoff is required, the effect is known as sustained casingpressure (SCP). Brufatto et al. (2003) cite U.S. MineralManagement Service data from the Gulf of Mexicoindicating that “by the time a well is 15 years old, thereis a 50% probability that it will have measurable SCP inone or more of its casing annuli. However SCP may bepresent in wells of any age.”

Groundwater monitoring-well data from the imme-diate vicinity of hydrocarbon wells are very sparse. VanStempvoort et al. (1996) selected oil and gas well sites

in the Lloydminster area (Alberta and Saskatchewan,Canada) with indications of seepage of natural gas throughdefective, permeable zones in the surface casing cementsheaths of these vertical wells into soil. These well siteswere considered to also be susceptible to seepage of thegas into shallow aquifers. Monitoring wells were installedin shallow aquifers immediately adjacent to these hydro-carbon wells, and subsequent sampling indicated evidencefor gas migration along well casings into the groundwaterat several of these sites.

It is conceivable that at other well sites, where thereis no detectable gas leakage at surface, annular gas flowcould be leaking into shallow aquifers that have porepressures less than the annular gas. This could resultfrom an inadequate surface casing cement seal betweenan aquifer and a gas source below. Therefore, those wellswith records of surface casing vent flow and/or SCPare also more likely to be those with gas seepage intoany aquifer meeting this criterion because the aquifer’scapillary entry pressure to gas will be very low. This is onereason why regulators address risk mitigation by requiringoperators to routinely monitor casing head pressures andreport pressures exceeding predefined thresholds.

Cement grouting in a typical horizontal productionwell is usually conducted between both surface andintermediate casings and the shallow formations theypenetrate to prevent hydrocarbon gases in the deeperformations from entering the casing or borehole annuliand traveling toward more shallow formations (Figure 2).Cement bonding between the well casing and rock istypically verified by a wireline acoustic logging toolknown as a “cement bond log” (CBL), which will clearlyidentify the absence of a cement sheath over long pipelengths of a few meters or more (i.e., “free pipe”).In many cases, but not always, geophysical logging issuccessful in identifying discontinuities in the cementsheaths (Boyd et al. 2006; also Claude Cooke Jr, Conroe,Texas, personal communication, November 28, 2012).Newer ultrasonic logging tools complement these acousticlogs but drilling-mud channels between the cement sheathand the rock wall are still not well imaged with logsin the opinion of logging experts consulted by theauthors. If identified, these discontinuities can be pluggedwith injected cement by a process known as “remedialcementing” or “squeezing.”

There are little, if any, data to evaluate the radiusof formation damage that may occur during drilling thatis not sealed by cement grouting. Similarly, there islittle information about the effect on the casing andsurrounding cement of consecutive pressuring of thevertical casing through the shallow and intermediate zonesdue to progressive fracturing in multiple stages.

Improved cementation procedures (e.g., Dusterhoftet al. 2002; Ravi et al. 2002) and modern acoustic andultrasonic tools will hopefully reduce the incidence offailure. However, as the Gulf of Mexico data (Brufattoet al. 2003) indicate, the aging of the cement sheath meansthat a CBL conducted at well completion cannot be reliedupon after years of continuing production during which


time the casings may expand and contract with fracturingfluids and hot, pressurized oil and/or gas, thus stressingthe annular cement sheath.

There are various potential reasons for inadequatecementation of well annuli (see Cooke et al. 1983;Dusseault et al. 2000; Bellabarba et al. 2008). The neteffect of these failures is to create a condition thatmay allow pressurized gas—and possibly, although lesslikely, fracturing and formation fluids—to escape fromthe producing zone if appropriate pressure gradients exist.More typically, pressurized gas in shallower gas-richformations, that is, the “intermediate zone” (Dusseault2000; Muehlenbachs 2012), can enter the uncementedor compromised cement bonding in the casing annulus,and then migrate up the annulus behind the wellcasing. In either manner a scenario develops by whichsuch gases, and possibly other fluids, could invadeshallow aquifers.

Such problems were illustrated by gas releases froma vertical production well in Bainbridge Township (Ohio,USA) that caused numerous shallow water wells withinthe Berea Sandstone aquifer to become contaminated withnatural gas. An Expert Panel reporting to the State Depart-ment of Natural Resources (Bair et al. 2010) concludedthat there were three successive factors leading to theaccident. First, there was inadequate cement grout presentto safely isolate both the top of the Clinton sandstonereservoir zone and the overlying gas-bearing New-burg Formation. Second, hydraulic fracturing pressuresbreached the available cement and allowed gas to flowthrough fractured cement and into to the open annulusabove the Newburg. Third, a decision was made to shutin the resulting gas flow through the casing head. Had thecasing head annulus valve not been closed and the wellallowed to vent, pressure would not have been allowedto build up in the subsurface and gas would not have hadsufficient pressure to migrate into water wells. Locally astructural dome within the Berea Sandstone aquifer actedas a gas trap resulting in longer-term gas release to thewater wells.

The conclusions from the above examples of fugitivegas migration illustrate that for gas to migrate intoshallow aquifers it requires a pathway (e.g., either anuncemented or incompletely cemented annulus), thepresence of gas under pressure at or near the path throughthe annulus, and pressure build up below the surfacecasing shoe. For these reasons, casing pressures should beroutinely monitored. If pressure exceeds certain criticallevels then the gas must be vented to mitigate the riskof it escaping into the subsurface. Once vented, if SCPreoccurs, then appropriate measures need to be takento mitigate the problem, for example, cementing off thenontarget gas-producing zones and determining if shallowgroundwater has become contaminated by leak-off ofcasing gases. This pathway should receive more attentionfor potential migration of fracturing fluids and formationwaters although migration periods for these fluids areexpected to be limited to times of pressurization.

Fugitive Gas Leakage from Abandoned WellsThe risk of fugitive gas emissions (as well as for-

mation water and fracturing fluid leakage) in areas withimproperly plugged and abandoned wells installed duringprevious eras of oil and gas extraction is considerablebased on the analysis of historic contamination incidentsin Ohio and Texas by the Ground Water Protection Coun-cil (Kell 2011). For example, the Railroad Commission ofTexas acknowledges that there are over 110,000 inactivewells in Texas plus another 7900 formally identifiedas orphan wells, that is, abandoned (Shields 2010). Anestimate of the number of abandoned wells that existin Alberta is 116,000 (Watson and Bachu 2007), andvan Everdingen and Freeze (1971) estimated there wereapproximately 30,000 abandoned wells in the old oiland gas fields of southwestern Ontario. “Orphan well”programs operated by U.S. states and Canadian provincesseek to properly plug these wells; between 2002 and 2009the Texan program plugged and abandoned 1500 suchwells per year (Kell 2011). Several operators drilling inareas with known historic drilling activity are activelydeveloping a variety of methods to pinpoint the locationof old abandoned wells (McKee and Beasley 2012).

Improperly plugged and abandoned wells installedduring previous eras of oil and gas extraction couldpose a risk for shallow groundwater contamination withgases and fluids if the formations that they penetratebecome re-pressurized as a result of either gas drilling,completion and well stimulation activities or deep welldisposal practices. The contamination of a shallowalluvial water-supply aquifer near Fort Knox (Kentucky,USA) provides an example of formation water influxdeteriorating groundwater quality. Here, chloride in excessof 10,000 mg/L discharged from abandoned explorationwells deep within the aquifer (Lyverse and Unthank 1988).

Similarly, Chafin (1994) describes gas wells in theSan Juan basin in New Mexico and Colorado drilled in the1930s that were abandoned and discharged methane intoshallow groundwater (maximum measured groundwaterconcentration of 39 mg/L; with 25% of soil gas con-centrations exceeding 100 mg/L(gas)). Therefore regionsof historical oil and gas exploration and productionwhere unconventional gas development occurs may wit-ness future problems of natural gas or formation fluidleakage.

Although not directly related to unconventional gasextraction, a fugitive gas release from natural gas storagein a salt cavern identified after natural gas explosions in2001 in Hutchinson, Kansas provides insight into free gastransport in the subsurface (Allison 2001; Watney et al.2003). Watney et al. (2003) concluded that a total of 3.5million ft3 at 600 psi (100,000 m3 at 4 MPa) had migratedalong the crest of an anticline at the contact betweentwo shales at depths from 420 ft (130 m) below groundsurface (bgs) at the cavern to 240 ft bgs (75 m) beneaththe city. Leakage occurred through a casing failure thatdamaged an annular seal in a well penetrating the storagecavern. After reaching Hutchinson, the gas escaped byflowing upward through abandoned salt wells and into


buildings. The Kansas Geological Survey (Allison 2001;Watney et al. 2003) had great difficulty in identifyingthe thin dolostone units that transmitted the gas as theysought to drill venting wells to mitigate the problem.This indicates that the detection of deep gas migrationpathways will probably not be straightforward and willrequire knowledge of the structural geology of the regionand the location of existing operating and abandonedwells—both groundwater and hydrocarbon wells. Reveszet al. (2010) and Bair et al. (2010) provide furtherexamples of the difficulty of identifying gas migrationpathways.

Interwellbore CommunicationCross-connection can also occur with active oil or

gas wells in the neighboring area. Such cases have beenreported in Alberta, including a recent case in whichhydraulic fracturing in one well caused a blow-out inan adjacent oil well completed years earlier in the sameformation (e.g., ERCB 2012a). The distance of suchinterwellbore communication (IWB) in Alberta is similarto that measured in the Barnett Shale play in Texas andappears to be up to 200 m (∼600 ft) from the well beingstimulated (M. Zoback, Stanford University, personalcommunication, November 30, 2012).

In addition, water wells can be pathways for migra-tion of natural gas from shallow formations that containcoal seams (Armstrong et al. 2009). This is likely dueto the fact that production from the water well itself (orany gas well) causes compressive stress redistributionaround the well that in turn leads to a loss of the radialstress seal around the well and an opening up of naturalfractures (Dusseault et al. 2000; M. Dusseault, Universityof Waterloo, personal communication, December 7,2012). A technical review commissioned by the ECRB inAlberta determined that a 200 m (∼600 ft) offset betweena hydraulically fractured coal-bed gas well and a waterwell provides a sufficient safety margin to protect waterwells from potential contamination (Taurus ReservoirSolutions Ltd. 2008).

Surface Spills and Infiltration of Produced WatersThe majority of examples of groundwater contami-

nation from oil and gas operations arise from historicallypersistent problems with fluid containment at the surface.Leakage from surface storage has been a significant causeof groundwater contamination in the past, including salinecontamination of alluvial groundwaters adjacent to oilfieldbrine-holding ponds (Pettyjohn 1982) and water wells(Novak and Eckstein; 1988). The storage of flow-backwater may also pose risks from heavy metals, naturallyoccurring radioactive materials (NORMs; e.g., 226Ra), andhydraulic fracturing chemicals.

On-site earth storage impoundments (“reserve pits”),typically constructed of compacted local clays and perhapsgeosynthetic membranes to yield an expected hydraulicconductivity of approximately 10−9 m/s, are still used.Brine-induced hydraulic conductivity (K) increases dueto clay shrinkage and fissuring in a salt-cavern brine

pond at Fort Saskatchewan (Alberta, Canada) wereimplicated in seepage into the underlying clay till, withpermeameter-measured K values that increased from10−11 to 10−9 m/s to approximately 10−8 m/s (Folkes1982). These results caused regulatory concern becauseof the presence of a buried channel aquifer 30 m (90 ft)beneath the impoundments although no contaminationwas reported. These impoundments are also susceptibleto overflow due to extreme precipitation events or tothe failure to empty the impoundment over periods ofseveral years. As a result, double-walled storage tanks areincreasingly required by regulatory agencies to replacesuch holding ponds and reduce the potential for overflowdue to extreme precipitation events or to the failure toempty the impoundment over periods of several years.

Holding ponds associated with coal-bed gas devel-opment in the Powder River Basin of Wyoming con-tinue to be an area of active research because infiltra-tion and chemical reactions between produced water, sur-face water, groundwater, and aquifer matrix can affectthe quality of drinking water, stock water, and irrigationwater locally used by ranchers. As a result, the WyomingDepartment of Environmental Quality (2008) has estab-lished regulations governing both the location of storageponds and monitoring of groundwater adjacent to ponds.

Gas Migration through Natural Faults and FracturesWhile gas migration via abandoned wells and produc-

tion well annuli is well documented, we know little aboutthe potential for gas migration following stimulation ofhorizontal wells in unconventional gas plays throughnatural fracture or fault systems. Structurally inducedfracture zones, such as those believed to have directedgas migration near Hutchinson, Kansas (Allison 2001;Watney et al. 2003), and local structural closures (e.g.,the shallow anticline in the Berea Sandstone in Ohio; Bairet al. 2010) will be important in determining potentiallocal and regional pathways for fugitive gas. In theHutchinson case described above, the Kansas GeologicalSurvey (Allison 2001; Watney et al. 2003) had difficultyidentifying the gas migration pathway as they sought todrill venting wells to mitigate the problem. Ultimately,the pathway was identified as a 300 m (∼1 000 ft) widezone of fractured dolomite that was only 0.9 m (3 ft)thick with a fracture porosity of 2% that stretched 14 km(8.7 miles) along the crest of an anticline.

Numerous examples of structural pathways for gasmigration have been identified in the Appalachian region(Scott and Rauch 1978; Beebe and Rauch 1979; Harrison1983 1985; Rauch 1983, 1984; Rauch et al. 1984). Recentinvestigations of thermogenic gas migration in New Yorkand Pennsylvania (Fountain and Jacobi 2000; Revesz et al.2010; Molofsky et al. 2011; Osborn et al. 2011; Warneret al. 2012) implicate gas migration along structural fea-tures as pathways for gas discharge to shallow groundwa-ters. For example, Fountain and Jacobi (2000) documentedthe presence of natural gas seepage from depth via theClarendon-Linden fault zone in upstate New York. Molof-sky et al. (2011) reported that 78% of the more than 1700


shallow water wells sampled as part of preshale gasassessments (2008–2011) in Susquehanna County, Penn-sylvania, had detectable levels of dissolved methane (bio-genic, thermogenic, and mixed). Although they were notable to statistically relate gas concentration to the locationof existing gas wells, they demonstrated that water wellswith elevated dissolved methane tend to be clustered nearand within river valleys and their tributaries. Similar toRauch’s findings 30 years before (Rauch 1983, 1984;Rauch et al. 1984), this suggested a natural geologic originof the gas in this area (as opposed to hydraulic fracturestimulated), possibly related to the surface expression ofvalleys carved into regional fracture networks.

The concept of gas flow by such “microseepage” hasa long history in the oil and gas literature (e.g., Levorsen1967; Hunt 1979; Stahl et al. 1981). Brown (2000)quantitatively evaluated the potential mechanisms of gasmigration concluding that free-phase gas flow explainsthe observation of petroleum “microseeps.” According toBrown, these seeps are a consequence of a relatively lowcapillary entry pressure for gas to penetrate water-wetfractures and will exhibit a flux rate governed by the cubiclaw (i.e., gas discharge Q ∼ [2b]3, where 2b is the fractureaperture). Even so, gas discharge via such fractures is“low enough so that petroleum accumulations can existfor geological time” without being depleted. Leakage ofhydrocarbons through faults remains of intense interest topetroleum geologists (e.g., Ingram and Urai 1999; Aydin2000; Cartwright et al. 2007).

Gorody (2012) has provided an extensive account ofthe processes by which methane migrates in porous andfractured rocks toward groundwater discharge areas. Ofparticular interest is his observation that gas breakthroughmay occur in pulses due to changes in the pore pressureand the nonwetting phase pressure exerted by the buoyantgas. Gas migration can result in rapid temporary declinesin gas flow, until gas accumulation and associatedpressures in the fracture path recover to a sufficientlevel to again exceed the gas entry pressure of thefracture or porous medium. If gas flow is intermittent,a single sampling of a contaminated groundwater well isan inappropriate monitoring strategy.

Gas Migration Through Induced FracturesMuch of the public concern around unconventional

gas development appears focused on hydraulic fracturingcreating pathways for gas, formation water and fracturingchemicals from the usually deep target formation toshallow aquifers. There is no evidence that fracturepropagation “out-of-zone” to shallow groundwater hasoccurred from deep (>1000 m or >3000 ft) shale gasreservoirs, although no scientifically robust groundwatermonitoring to detect gas migration has been attempted toour knowledge. A weight-of-evidence is that such fracturepropagation is unlikely in deep (>1 km) operations (ALLConsulting 2012; UK Royal Society/Royal Academyof Engineering 2012). Available evidence is largelyrelated to measured or modeled fracture propagation asaforementioned.

This conclusion may not be true when shallowhydraulic fracturing occurs associated with coal-bedmethane development because of the shallow depth ofthe coal formations. Hydraulic fracturing in shallowformations, in particular using nitrogen or propanefracturing fluids for coal-bed methane operations, hasresulted in different interpretations of the occurrence ofshallow groundwater contamination in Alberta, Canada(Blyth 2008; Tilley and Muehlenbachs 2011).

The one documented case (ERCB 2012b) in whicha shallow aquifer became contaminated with hydraulicfracturing fluids was due to the accidental injection ofhydraulic fracturing fluids directly into a sandstone at136 m depth (443 ft depth) when the operators believedthey had perforated the coiled tubing at 1500 m depth(4900 ft). Here a chain of human errors caused the shallowgroundwater contamination but no vertical propagation ofhydraulic fracturing fluids from depth was involved.

The totality of these findings suggests a low proba-bility of shallow groundwater contamination by upwardpropagation of hydraulic fractures from deep shale gasplays. As noted above (see Interwellbore Communica-tion), there is evidence of induced horizontal fracturingto approximately 200 m from the stimulated well. Thepotential for elevated pore-pressure transmission (ratherthan fracture propagation) beyond this distance throughpreexisting fracture or fault zones has been consideredby geophysicists interested in remote triggering of earth-quakes (Manga et al. 2012).

Monitoring and Behavior of Contaminants in ShallowGroundwater

Hydrocarbon GasesThe presence of methane in shallow groundwater is,

by itself, not definitive evidence of contamination result-ing from unconventional gas development. In many areastargeted for unconventional gas, elevated concentrationsof methane have existed in shallow groundwater prior toany drilling activities. “Biogenic” methane can be gener-ated in situ in shallow groundwater (e.g., by CO2 reduc-tion or acetate fermentation reactions) but gas occurrencesin shallow aquifers can also result from upward migrationof thermogenic or mixed thermogenic/biogenic methane(Barker and Fritz 1981; Revesz et al. (2010); Bair et al.2010).

Although it may be difficult to ascertain gas source(s),some well-constrained case studies are instructive. Fugi-tive gas (mainly methane) migrated along the annulus ofan oil well and then migrated about 10 m laterally from theoil well into a buried sand and gravel aquifer near Lloy-dminster, Alberta, Canada (Van Stempvoort et al. 2005).In situ bacterial methane oxidation coupled with bacterialsulfate reduction occurring within a contaminated ground-water plume was identified by a depletion of the stableisotope 13C in bicarbonate and an enrichment of 34S inresidual sulfate in down-gradient groundwater monitoringwells. The authors concluded that these processes could


also be important near other oil and gas wells in westernCanada and perhaps globally.

Forensic identification of stray or fugitive gas originrequires a comprehensive approach (e.g., Van Stempvoortet al. 2005; Revesz et al. 2010; Tilley and Muehlenbachs2011). In addition to the usual geochemical approach ingroundwater quality investigations (e.g., measurement ofpH, DO, Eh, major ions, and redox sensitive minor ions,such as Mn and Fe), a field investigation would alsoideally include the following: (1) appropriate samplingtechniques to collect representative groundwater samplesof dissolved or free gas, (2) dissolved or free gascomposition analyses, (3) estimation of in situ totaldissolved gas pressure (Roy and Ryan, in press this issue),(4) determination of the stable isotope composition ofgases; and (5) possibly the identification of microbialconsortia responsible for catalyzing redox reactions.Inexpensive and reliable methods have been developedfor dissolved gas sampling to determine composition (e.g.,Gorody 2007; Hirsche and Mayer 2007). Compositionalanalyses for dissolved gas (Box 2) can follow differentapproaches and are increasingly undertaken at commerciallaboratories.

Fingerprinting the chemical and isotopic composi-tions of natural gas associated with both shales andshallow groundwater is an effective tool for evaluatingpotential environmental impacts of hydraulic fracturingof horizontal wells in unconventional gas plays. Biogenicgases produced in situ in shallow aquifers are predomi-nantly composed of CH4 with low δ13C (−50 to −110‰VPDB) and δ2H values (as low as −350‰ VSMOW).In contrast, thermogenic gases generated at elevated pres-sures and temperatures are usually composed of methane(C1) and higher alkanes such as ethane (C2), propane (C3),and possibly butane (C4) and pentane (C5), with δ13C val-ues often ranging between −55 and −25‰. Therefore,stable isotope analyses, wetness parameters and Bernarddiagrams (see Box 1) when used together can be an effec-tive tool to assess the sources of natural gas in shallowaquifers. If the chemical and isotopic compositions of nat-ural gas in all gas-bearing formations are known, it mayalso be possible to identify the formation from which straygases have been derived contaminating shallow ground-water with natural gas (e.g., Tilley and Muehlenbachs2011). While natural gas occurrences in some formations,such as coal-bed methane in Alberta, are readily finger-printed by geochemical and isotopic measurements (Che-ung et al. 2010; Tilley and Muehlenbachs 2011), otherformations display considerable variability in these param-eters (Gorody 2012). Tilley and Muehlenbachs (2013) pro-vide a comprehensive review of the isotope geochemistryof several United States and western Canadian shale-gasreservoirs.

A widely accepted methodology for sampling, anal-ysis, and data interpretation would help to resolve uncer-tainties and disputes regarding impact of fugitive gases onshallow aquifers and their potential causes. The protocolpresented in Gorody (2007) is one example that could be

advanced and adopted; additional field methods and iso-topic tools could be employed where conditions warrantfor interpretation of complex data (e.g., van Stempvoortet al. 2005; Hirsche and Mayer 2007; McLeish et al. 2007;Roy and Ryan 2010; Gorody 2012).

A particularly important component needed for theisotopic fingerprinting of gas-bearing formations is thecharacterization of δ13C values of gases in drilling mudsrecovered from the vertical portion of energy wells (Roweand Muehlenbachs 1999; Tilley and Muehlenbachs 2006,2011). This would greatly facilitate the identification ofsources of potential stray gas in shallow aquifers and mayfacilitate the remediation of gas leakage into aquifers, ifnecessary.

Formation WatersSaline formation waters typically contain solutes that,

when brought to the surface, can potentially contaminatesoil and groundwater. These solutes are primarily sodiumand chloride but may also include arsenic, barium andradium-226, the latter generated by the radioactive decayof uranium in shales. Because of the deleterious effects ofsaline formation waters or brines on activated sludge pro-cesses in municipal treatment plants, the disposal of brinesis increasingly directed to injection wells or to recyclingfacilities where they exist (e.g., Pennsylvania and Texas).

Saline formation waters have recently become partof the shale-gas controversy due to the claims thatMarcellus formation brines are migrating to shallowaquifers through pathways “unrelated to recent drillingactivities” (Warner et al. 2012). Given that the Siluriansandstones and Devonian shales of the Appalachianbasin have water-phase porosities approaching irreduciblesaturations (Soeder 1988; Ryder and Zagorski 2003),there is some question as to the availability of suchbrine for migration. Engelder (2012) suggests a higherbrine saturation but also argues for “capillary binding”of the brine within the Marcellus shale. Nevertheless,geochemical characterization of formation waters shouldbe part and parcel of the hydrogeological baselinereporting that will increasingly become standard if furtherdisputes are to be rapidly and fairly resolved.

Fracturing Chemicals and Other Compounds of InterestThe US EPA (2011) is currently conducting research

on hydraulic fracturing, specifically related to its potentialimpacts on drinking water. In part, it is anticipatedthat this study will determine whether some of thechemicals used in fracturing fluids can be detected ingroundwater, and if so, obtain information about theirfate and transport and toxicity. This study is using acombination of (1) analysis of existing data, (2) newcase studies, both retrospective (studies at locationswhere hydraulic fracturing has already occurred) andprospective (collection of data at new sites prior to, during,and after hydraulic fracturing activities), (3) scenarioevaluations, (4) laboratory studies, and (5) toxicityassessments.


The hydrogeological community has suitableexpertise to evaluate the transport and fate of relevantchemicals in groundwater, including their attenuation bydispersion, sorption, and biodegradation. The behavior ofsome of the relevant chemicals (e.g., brine salts, aromatichydrocarbons) in groundwater has already been well stud-ied in other applications in contaminant hydrogeology. Bycontrast there is little or no peer-reviewed and publishedfield data regarding the groundwater occurrence and fateof various anthropogenic chemicals that are widely usedin unconventional natural gas production. These includevarious glycols, amines, and metal complexes used ascorrosion inhibitors, some of which have been deemed“proprietary,” or metabolites and degradates that mayform from these chemicals, for example, acrylamide. Inmany cases, assumptions about the biodegradability ofthe various chemical additives, if available, have beenbased on laboratory studies in oxygenated environmentsusing samples of soil, surficial sediments and/or surfacewaters, which are not necessarily applicable to the deepsubsurface (Van Stempvoort and Roy 2011). Also thereis apparently very little information about groundwatercontamination by and the fate of some of the lessabundant chemicals that occur in produced gas and/orcondensates (e.g., hydrocarbons that contain sulfur) orproduced water (e.g., 226Ra, Ba, among others).

The peer-reviewed literature about groundwatermonitoring programs at both conventional and unconven-tional natural gas production sites is sparse, suggestingthat such monitoring is rarely conducted unless spillshave been reported. Furthermore, many of the abovechemicals are typically not included in groundwatermonitoring programs. To address these science gaps, itwould make sense to study the fate and transport of thosechemicals considered to be threats to the environmentand public health, as well as some chemicals that wouldbe good tracers or indicators of the fluids produced orused in unconventional gas development.

Recommendations as to Research ProgramsTo support both sustainable development of uncon-

ventional gas and protection of groundwater resources, weidentify two areas of hydrogeological research that willaddress key science gaps: (1) the characterization of thebackground or baseline conditions (including groundwaterflow, geochemical and isotopic characterization, and gaspressure (PTDG; Box 2) in shallow groundwater); and (2)field experiments and studies to understand better the pro-cesses by which natural gas, saline formation waters andfracturing chemicals may invade and contaminate shallowgroundwaters and then be remediated where necessary.Laboratory experiments and computational studies willbe needed to support this research into the transport andfate of natural gas, saline formation waters and fracturingchemicals into and within shallow groundwaters.

Baseline Groundwater Quality MappingBaseline or background testing of groundwater for

methane concentrations and its carbon (and sometimeshydrogen) isotope ratios in some jurisdictions (e.g.,ERCB 2006) is becoming standard practice in areaswhere unconventional gas development occurs. The aimis to determine a baseline of water quality screeningparameters from which any perceived changes followingthe drilling and stimulation of wells in unconventionalgas plays can be compared. Regulatory requirementsto collect such data are principally used to addresscomplaints. These baseline surveys tend to includeexisting water wells only, without use of groundwaterprofiling systems to detect spatial variability in free- anddissolved-gas phases, and usually fail to assess naturalvariations in concentrations and isotopic compositionsof methane, and how these are affected by geographicregion and/or geology, and with differences in aquiferproperties, well construction, and pumping scenarios.

Generalized monitoring analytes useful for screeningwater quality are presented in Box 3 (Forensic anal-ysis of hydrocarbons in shallow groundwater and sur-face gas seeps). This information could assist in rapidresolution in any disputes that arise. While domesticwater well surveys provide useful analytical chemicaldata for public health authorities, the data are suscep-tible to gas exchange and microbially-catalyzed redoxreactions within the well itself (Bair et al. 2010). Thesewells can also be poorly protected from surface con-tamination, poorly maintained and the source of thewater is often uncertain. More comprehensive geochemi-cal mapping could involve a time series of an expandedsuite of parameters, ideally in a network of dedicatedgroundwater monitoring wells. The continued use ofdomestic or landowner wells requires careful consider-ation as they provide an initial screening of groundwa-ter quality but one which is likely to reflect biases asidentified above.

Box 3

Forensic Analysis of Hydrocarbons in ShallowGroundwater and Surface Gas SeepsForensic analyses of free and dissolvedhydrocarbons in groundwater are designedto:

• Unambiguously identify the source(s) ofstray hydrocarbons impacting surface andgroundwater resources;

• Provide defensible data to demonstratewhether groundwater and surface waterimpacts are due to oil and gas operations, andif so, to determine when such impacts havebeen satisfactorily mitigated so that there is no


longer a threat to public health, safety, and theenvironment.

The approach is to sample potential gas sourceswithin a certain radius of influence and to comparethem with baseline and postimpact sample dataof free and dissolved gases from affected waterwells. If there is good pressure communicationbetween a point source of natural gas and agas seep, then the stable isotopic compositionof the free gas phase at the seep tends tocorrespond precisely to that of the source. Moreoften than not in such cases, the gas compositionof both source and seep is also nearly identical.When gas contaminants occur in the dissolvedphase, then source hydrocarbons are more likelyto influenced by dilution, alteration, and mixing.Because of the hydrologic complexity of shallowgroundwater environments, the objectives ofa comprehensive sampling and analysis planshould strive to unravel three principal factorsaffecting the interpretation of results. Theseare dilution (Hirsche and Mayer 2007; Gorody2012), mixing (Jenden et al. 1993; Tilley andMuehlenbachs 2006, 2011; Revesz et al. 2010),and hydrocarbon oxidation (Barker and Fritz1981; Coleman et al. 1988; Whiticar 1999).Dilution of hydrocarbon contaminants in agroundwater plume depends on the size ofa plume, plume velocity, adsorption effectswithin the aquifer matrix, dispersion and fluidsincorporated and mixed along the migration path.Mixing occurs as a result of the interactionbetween dissolved gas plumes of multipleorigins. For example, it is common to observemixing between naturally occurring biogenicgas and contaminant thermogenic gas sources.Baseline samples provide the needed end-member dissolved hydrocarbon compositionsrequired for mixing model calculations.Hydrocarbon oxidation is principally mediated bybacteria. Ordinarily, hydrocarbon oxidation trendsin gas composition and stable isotope data do nottend to appear until well after a contaminant pointsource has been mitigated, for example, a leakygas well. However, hydrocarbon oxidation ratesalso vary depending on the size of a plume, plumevelocity, the extent of the oxidation gradient nearthe leading edge of the plume, and the redoxenvironment in the host aquifer. Furthermore, ifthe rate of fresh dissolved hydrocarbon influx intoa water well is significantly greater than oxidationrates in the surrounding wellbore environment,then the chemical and isotopic composition ofhydrocarbons is not significantly altered.Demonstrating the effects of bacterially mediatedhydrocarbon oxidation is one requirement needed

to demonstrate that a contaminant source hasbeen mitigated. High oxidation rates will lowerthe concentration of dissolved hydrocarbons.However, when a contaminant plume mixes withaquifer fluids devoid of dissolved hydrocarbonsin a water well, dilution could be mistaken forthe effects of remediation. For this reason it isimportant to determine the composition of fluidshosting a contaminant plume and to differentiatethose fluids, if possible, from fluids that may bederived from other aquifers supplying water to awater well.Addressing the effects of dilution, mixing, andoxidation is best achieved by collecting multiplesamples of both potential hydrocarbon pointsources (produced hydrocarbons, hydrocarbonsin annular spaces, and shallow gas obtainedby sampling while drilling), and of shallowgroundwater receptor sites (water and monitorwells, and hydrocarbon seeps). Using a varietyof such sample types is vital to satisfactorilyinterpret the source of hydrocarbons in shallowgroundwater environments.Sampling available water wells within a radiusof influence from potential contaminant pointsources (e.g., commercial oil or gas wells)multiple times is most easily accomplishedby collecting pre and postdrilling sample sets.Although providing detailed sampling protocols isbeyond the scope of this paper, all samplingevents should follow written, and preferablystandardized, sampling and analysis plans toensure that data quality is defensible. Thisincludes routine collection and analysis ofselected blind duplicate sample sets.Minimum screening parameters needed toaddress the occurrence and source of free anddissolved hydrocarbons in groundwater samplesshould ideally include the following:

• dissolved methane, ethane, and BTEX concen-trations;

• stable isotope analysis of carbon and hydrogenin both free and dissolved methane;

• stable isotope analysis of carbon in both freeand dissolved ethane;

• fixed gases (including argon) and hydrocarbongas chromatography of samples containingdissolved methane and ethane concentrationsabove a predetermined threshold or in free gassamples;

• charge-balanced major ion analyses;• parameters useful for identifying the redox state

of shallow groundwater samples; and• routine monitoring, sampling, and analysis of

gases derived from the headspace of a waterwell.


Forensic investigations designed to addressimpacts from potential point sources on shallowgroundwater should include all the aboveparameters, and additional parameters to furthercharacterize both fluid and hydrocarbon sourcesas needed. Parameter selection should be basedon site and potential point source-specific criteriaand may include one or more of the following:

• Volatile organic compounds (including ben-zene, toluene, ethylbenzene, o-xylenes,m-xylenes, p-xylenes, 1,2,4, and 1,3,5-trimethylbenzenes) and semi-volatile organiccompound analysis using standard GC/MSmethods;

• Stable isotope analyses of hydrogen andoxygen in water;

• Stable isotope analysis of carbon in dissolvedinorganic carbon.

Minimum parameters useful for characterizinghydrocarbons in produced and bradenhead orcasing-head gas samples ideally include thefollowing:

• Fixed (including argon) and hydrocarbon gaschromatography;

• Stable isotope analysis of carbon in methane,ethane, propane, butane, and CO2;

• Stable isotope analysis of hydrogen in methane;• BTEX compounds (i.e., benzene, toluene,

ethylbenzene, o-xylenes, m-xylenes,p-xylenes, 1,2,4, and 1,3,5trimethylbenzenes)using standard GC/MS methods.

Given the potential role of fractures and structuralfeatures in gas migration to shallow aquifers, carefullydesigned and located groundwater monitoring instrumen-tation will likely be needed, particularly for research stud-ies and dispute resolution. Depth discrete monitoring haslong been used by those industries regulated under U.S.environmental laws (e.g., the Safe Drinking Water Actor SDWA, the Comprehensive Environmental Response,Compensation and Liability Act or CERCLA and theResource Conservation and Recovery Act or RCRA) usingmultilevel well systems (e.g., Einarson 2006; Cherry et al.2007; Mayer et al. 2008). Monitoring to detect upwardmigration of contaminants is unusual in contaminanthydrogeology. Lesage et al. (1991) presented an approachthat was used to assess the potential for upward migrationof refinery wastewaters following their deep-well injec-tion; they employed the complementary use of deep, mul-tilevel wells and shallow, conventional monitoring wells.

Experimental Field StudiesFurther scientific investigation into the potential

for groundwater contamination following unconven-tional gas development activities is warranted. At leastthree approaches to field programs are possible: (1) aforensic or “retrospective” analysis of existing cases ofunconventional gas development, (2) an investigationthat includes gathering of field data prior to the instal-lation and stimulation of unconventional gas wells, andperiodically during the subsequent production period,and (3) controlled experiments to understand processesthat are believed to be responsible for or may result ingroundwater contamination.

The U.S. Environmental Protection Agency study(US EPA 2011), which deals specifically with hydraulicfracturing, involves hydrogeologic field research compo-nents, including retrospective case studies at five devel-oped sites with reported instances of water contamination,and two prospective case studies at sites where hydraulicfracturing will occur following baseline monitoring. Siteidentification, initial assessment and the first round ofsampling have occurred for the five retrospective sites(includes oil, shale gas, and coal gas).

Rather than simply undertaking forensic or “retro-spective” analyses of unconventional natural gas sites,an appropriate approach to understanding the potentialpropagation of natural gases into aquifers would be todesign and conduct field-scale experiments in a controlledsetting. A handful of prominent field sites with collabora-tive, long-term research programs have spawned dozensof research papers on the fate and transport of other con-taminants, in particular chlorinated solvents and gasolinecomponents, and many of the major advances in hydro-geology have occurred as a result of these integratedfield-research programs (Anderson and McCray 2011).

A similar field-focused approach for unconventionalgas development with hydraulic fracturing would allowengineers and geoscientists from industry to work withresearch hydrogeologists and environmental chemiststo develop a greater understanding of how effectivemonitoring systems might be developed to detect poten-tial migration and fate of gases and chemicals usedin the hydraulic stimulation process. Controlled fieldexperiments were critical to understanding the practiceof hydraulic fracturing in the 1980s at U.S. Departmentof Energy’s Multiwell Experiment program in westernColorado (e.g., Lorenz et al. 1989; Warpinski 1990).Sites selected for this approach could include variablehydrogeologic settings in major play areas such as thosein Rocky Mountain foothills in the Western Canadiansedimentary basin, the Front Range of Colorado, theAppalachian region of New York and Quebec, andemerging CBM plays in Wyoming and Alberta.

Recent advances in carbon capture and geologicalstorage and in unconventional oil and gas production havedeveloped separately. Given the overlap in research needsfor these activities, for instance with respect to potentialgas leakage, there appear to be significant opportunitiesfor technology transfers and other mutually beneficial and


synergetic interactions (Nicot and Duncan 2012). It will beessential that collaboration between government, industry,academia and other third party groups ensures experi-mental studies are conducted in a manner that inspireswidespread credibility without politically motivatedconflicts of interest. Furthermore, it will be necessary thatthe design, implementation and analysis of such studiesare independently reviewed and verified by experts.

Industry has an opportunity to play a cooperative rolein ensuring that unconventional natural gas productionis environmentally safe and sustainable. We proposethat working groups of environmental geoscientists andengineers from industry and academia cooperate to testand develop new methods to detect and monitor thepresence of fugitive gas, saline water, and flowbackchemicals in shallow groundwater at unconventional gassites. Industry participation would also help to defer costsrequired for more comprehensive monitoring of shallowgroundwater and soil coring of impoundments to addressthe fate of potentially hazardous chemicals in storedflow back and produced fluids. Other research objectivesmight also include the following: identification of gas andother fluids that may have escaped the production stringof casings; improved understanding of cement curing andcement emplacement techniques; improved downholemonitoring of cement bonding; and testing the confine-ment of wastewaters injected into saline aquifers, depletedoil reservoirs, and other formations as proposed by VanEverdingen and Freeze (1971). Finally, it will be impor-tant to greatly expand the techniques available to hydro-geologists to undertake aquifer remediation in the event ofcontamination (e.g., Van Stempvoort et al. 2007a, 2007b).

Laboratory and Computational ExperimentsThere will be numerous reasons to conduct laboratory

and numerical simulation experiments and investigations.For example, in order to design field experiments with aminimal risk of failure, it will be necessary to carefullystudy transport and attenuation processes of compoundsof concern in the laboratory and by numerical simulationbefore undertaking field experiments under controlledconditions. Soil column studies and aquifer tank exper-iments of the fate and transport of fracturing chemicalscan be used to identify the more mobile and recalcitrantcompounds for field testing. Numerical simulations canalso be used to evaluate risks of fluid migration throughdeep fault zones with known surface expressions basedon parameters derived from the hydraulic testing of faultzones (e.g., Rafini and Larocque 2012).

Summary and ConclusionsThis article has referred to issues that are not con-

fined to unconventional gas extraction. It also mentionedissues that have arisen with conventional hydrocarbonextraction and which can be expected to occur withunconventional gas extraction. Articles on groundwatercontamination arising from conventional oil and gasextraction sites have appeared infrequently in the two

journals of the NGWA (Ground Water and GroundWater Monitoring & Remediation). Notably, oil andgas exploration and production were exempted fromU.S. Federal regulations (RCRA and CERCLA) in the1970s and 1980s; perhaps in part as a result of thatpolicy, “upstream” groundwater issues that arose duringexploration and production—gas leakage from wells andcontamination from impoundments—received relativelylittle research attention.

Consequently, less than 10 articles in total can becounted in both NGWA journals since the early 1980s onupstream oil and gas issues. By contrast, both journalshave carried numerous articles on the characterizationand remediation of sites contaminated by chlorinatedsolvents, gasoline, and other contaminants. This lack of“anticipatory research” was observed 30 years ago to haveharmed groundwater protection (Brooks 1982) throughlimited research. Kell (2011) has emphasized in his reviewof groundwater investigations conducted by state oil andgas agencies in the USA that competent site investigationis the driving force for regulatory reform.

We identify several case histories (Table 3) involvingthe migration of natural gas to shallow aquifers, waterwells, or buildings. Several of the examples indicate thelong-standing problems arising from poorly completed oilor gas wells, while one identifies the importance of aban-doned wells in gas migration. It is likely that the naturalgas migrated as a buoyant free phase in all cases. Whilethese case studies are the exception and not the rule, themigration of the gas through bedrock indicates the impor-tance of fracture flow systems and the ability of hydro-geologists to identify those pathways in order to monitorthem to the depth of surface casings, that is, the full depthof potentially potable groundwater. Table 3 represents a“canon” of peer-reviewed publications on this subject.

We have identified two areas where science gapsare evident and field-focused research is required: (1)baseline geochemical mapping and the development ofproblem-specific groundwater monitoring systems andnetworks; and (2) field testing of potential mechanismsby which hydrocarbon gases, saline fluids, and fracturingchemicals might invade and contaminate shallow ground-water and of methods of aquifer remediation. To supportthese research initiatives it will be necessary to undertakelaboratory and computational studies to (1) design andanalyze field experiments, (2) screen potential groundwa-ter contaminants and (3) evaluate potentially vulnerableaquifers near fault zones with near-surface expression.

Thus we have illustrated the potential role ofthe hydrogeologists in identifying, characterizing, andmonitoring aquifers deemed vulnerable to contaminationby natural gas and perhaps other gas-field fluids andchemicals. All of these topics will require collabora-tion of engineers and geoscientists from industry withhydrogeologists and geochemists from the researchcommunity. These gaps in knowledge are harmful tothe safe development of natural gas resources and theprotection of groundwaters as well as to the socialperception of their safe development.


AcknowledgmentsThe authors appreciate the comments of J.A. Cherry,

B. Parker, T.M. Missimer, two anonymous reviewers, andthose of Frank Schwartz, Editor-in-Chief of Groundwater .

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