an overview of canadian shale gas production and environmental

International Journal of Coal Geology xxx (2013) xxx–xxx

COGEL-02241; No of Pages 13

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International Journal of Coal Geology

j ourna l homepage: www.e lsev ie r .com/ locate / i j coa lgeo

An overview of Canadian shale gas production andenvironmental concerns

Christine Rivard a,⁎, Denis Lavoie a, René Lefebvre b, Stephan Séjourné c,Charles Lamontagne d, Mathieu Duchesne a

a Geological Survey of Canada, Natural Resources Canada, 490 rue de la Couronne, Québec, QC G1K 9A9, Canadab Institut national de la recherche scientifique, Centre Eau Terre Environnement (INRS-ETE), 490 rue de la Couronne, Québec, QC G1K 9A9, Canadac Consulting geologist, 5725 rue Jeanne-Mance, Montréal, QC H2V 4K7, Canadad Ministère du Développement durable, de l'Environnement, de la Faune et des Parc du Québec (MDDEFP), 675 boul René Lévesque Est, 8e étage, boîte 03, Québec, QC G1R 5V7, Canada

⁎ Corresponding author. Tel.:+1 418 654 3173.E-mail address: [email protected] (C. Rivard).

0166-5162/$ – see front matter © 2013 Published by Elsehttp://dx.doi.org/10.1016/j.coal.2013.12.004

Please cite this article as: Rivard, C., et al., Anhttp://dx.doi.org/10.1016/j.coal.2013.12.004

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Article history:Received 14 June 2013Received in revised form 20 November 2013Accepted 1 December 2013Available online xxxx

Keywords:Canadian unconventional resourcesShale gasOverviewUtica Shale

Production of hydrocarbons from Canadian shales started slowly in 2005 and has significantly increased since.Natural gas is mainly being produced from Devonian shales in the Horn River Basin and from the TriassicMontney shales and siltstones, both located in northeastern British Columbia and, to a lesser extent, in theDevonian Duvernay Formation in Alberta (western Canada). Other shaleswith natural gas potential are currentlybeing evaluated, including the Upper Ordovician Utica Shale in southern Quebec and theMississippian FrederickBrook Shale in New Brunswick (eastern Canada).This paper describes the status of shale gas exploration and production in Canada, including discussions ongeological contexts of the main shale formations containing natural gas, water use for hydraulic fracturing, thetypes of hydraulic fracturing, public concerns and on-going research efforts. As the environmental debateconcerning the shale gas industry is rather intense in Quebec, the Utica Shale context is presented inmore detail.

© 2013 Published by Elsevier B.V.

1. Introduction

Natural gas is often considered a transition fuel for a low-carboneconomy because it is abundant, efficient, and cleaner burning thanother fossil fuels. Over the past decade, shale has been heralded as thenew abundant source of natural gas in North America. The combinationof technological advancements in horizontal drilling and in multi-stagehydraulic fracturing (“fracking” in industry jargon) techniques, as wellas the progressive decline in conventional oil and gas reserves inNorth America, made shale gas the “energy game changer” over thelast years. In addition, the fact that recoverable reserves of natural gasand oil in shales have been estimated to be large enough to potentiallyfree the United States from a decade-long dependence on oil imports,and replace nearly all coal-generated electricity (Soeder, 2013), hasprobably largely contributed to making shale gas exploration andproduction increasingly appealing in this country. The United Stateswas the first to economically produce shale gas from the Barnett Shalemore than a decade ago; in 2013, there are over 40 000 producingshale gas wells spread across 20 states. However, natural gas priceshave significantly decreased over the past several years, so that manyshale dry gas plays (without liquid hydrocarbon production) arecurrently at the lower limit of economic profitability.

vier B.V.

overview of Canadian shale

Shale gas formations targeted by industry are generally locatedmorethan 1 km deep and under pressures sufficient to allow natural flow.Vertical wells must progressively be deviated to the horizontal toreach the target zone because the latter is typically relatively thin(50–100 m). Therefore, the horizontal part (termed a “lateral”) opti-mizes natural gas recovery by allowing the borehole to be in contactwith the producing shale interval over significantly longer distances(and thus over a much larger surface area) compared to a vertical bore-hole. Almost all shale reservoirs must be fractured to extract economicamounts of gas because their permeability is extremely low, whichimpedes gas flow towards the productionwell. To increase their perme-ability, shales are typically fractured with fluids injected under highpressure, usually through a cemented liner or production casing thatwas selectively perforated. The fracking fluid used is specific to eachoperator and differs from one shale formation to another, depending,among other things, on the pressure gradient, brittleness (Poissonratio and Young's modulus), clay content and overall mineralogy, hori-zontal stresses, and gas to oil ratio (GOR). Historically, the most com-mon fracking fluid used by the shale gas industry has been slickwater(a simple mixture of water, proppants (usually sand), friction reducersand other chemical additives) due to its low cost and effectiveness.More recently, shale reservoirs appear to be increasingly stimulatedwith a hybrid treatment consisting of slickwater used in alternationwith a cross-linked gel purposely designed for a specific viscosity,with hybrid slickwater energized with N2 or CO2, or with hydrocarbonssuch as gelled propane.

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2 C. Rivard et al. / International Journal of Coal Geology xxx (2013) xxx–xxx

Micro-seismic events induced by fracking operations are now beingroutinely recorded on a fraction of the wells drilled in a new exploita-tion area usingultra-sensitive seismographsplaced either in anadjacentgaswell, as a** buried array or as a surface array. These techniques allowthe estimation of fracture height and half-lengths from which a stimu-lated reservoir volume can be calculated, which helps assess the effec-tiveness of the stimulation. Generally, induced fractures are reportedto extend less than 300 m vertically (Davies et al., 2012; Fisher andWarpinski, 2012).

Hydraulic fracturing has been used to stimulate production wells inconventional oil and gas reservoirs (mostly in vertical wells) in NorthAmerica for more than 60 years. However, in the case of horizontalshale gas wells, the stimulation process requires greater amounts ofwater, sand and chemicals for a given well, and this mixture must beinjected at higher rates and pressures, and a much larger volume ofrock is involved compared to conventional reservoirs. Hence, morepowerful equipment is required on site (pumper trucks) and muchmore truck traffic for the transportation of water and sand is involved(if a local source is not available). Due to the horizontal drilling technol-ogy and multi-stage fracturing, these activities are taking place severaltimes onmulti-well pad sites, instead of taking place inmultiple verticalwells on the surface. Environmental concerns are mainly related toseven issues that are themselves related to six main activities, as sum-marized in Table 1.

This paper presents the historical context and current state of shalegas development in Canada (Section 2), geological contexts of mainCanadian shale plays containing dry gas (Section 3), facts on hydraulicfracturing (Section 4), water usage by this industry (Section 5), as wellas various research initiatives implemented to investigate differentenvironmental issues mentioned above and to characterize the shaleformations themselves (Section 6). Then, public concerns (Section 7)and regulation related to drilling and fracturing (Section 8) are brieflydiscussed. Finally, the historical background and social context of theUtica Shale (southern Quebec) are described in more detail. Althoughonly limited Utica Shale exploration has taken place, it has raised envi-ronmental concerns amongst the general public that have led to a tem-porary de facto moratorium on hydraulic fracturing in Quebec.

2. General context

Over 500 000 oil and natural gas wells have been drilled to date inCanada, of which more than 375 000 are located in Alberta (CAPP,2012). Petroleum development began in eastern Canada in 1858,where a 15.5 m (51 ft) oil well was dug (not drilled) in Oil Springs,Ontario. This well became the first commercial oil well in NorthAmerica. Natural gaswas discovered in Ontario in 1859, but commercialgaswas not produced in the province until 1889. In the late 1800s, someproduction of natural gas from unconsolidated Quaternary sands forlocal industrial purposes took place for a short period in the Trois-Rivières area (betweenMontreal and Quebec City, in southern Quebec).This very small reservoir was, however, rapidly depleted. At that time,

Table 1Issues and activities of concern relative to the shale and tight gas industry (http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale-Matrices.aspx).

Environmental concerns Activities

1. Water quantity2. Water contamination3. Management of fracking and

flowback fluid storage4. Radioactive wastes5. Nuisances (noise, trucking, light)6. Atmospheric emissions/air quality7. Induced seismicity

1. Site development and drilling preparation2. Drilling activities3. Completion and hydraulic fracturing4. Well operation and production5. Fracturing fluids, flowback, and

produced water storage and disposal6. Other activities (e.g. plugging and

abandonment)

Please cite this article as: Rivard, C., et al., An overview of Canadian shalehttp://dx.doi.org/10.1016/j.coal.2013.12.004

shallow conventional hydrocarbons were targeted, mainly in overbur-den (often at the bedrock/overburden contact). In western Canada,the first gas discovery was accidentally made while drilling for waternear Medicine Hat, Alberta, in 1883. A second well was drilled thefollowing year that produced enough gas to light and heat several build-ings. The discovery of theworld-class Leduc oil field in 1947 by ImperialOil made theWestern Canada Sedimentary Basin the center of Canada'spetroleum exploration and production. The industry started construct-ing a vast pipeline network in the 1950s, to start developing domesticand international markets. Canada is now the third largest producer ofnatural gas in the world (1720 billion m3 or 60 200 billion ft3 or Bcffor 2012; National Energy Board, 2012) and the 4th largest exporter,with the U.S. currently being its sole international market.

Canada's production of “primary” energy, i.e. energy found in naturebefore conversion or transformation, totalled 16 495 petajoules (PJ) in2010. Fossil fuels accounted for the greatest share of this production,with crude oil representing 41.4%; natural gas, 36.5%; and coal, 9.2%(NRCan, 2011). The remainder (12.9%) comes from renewable energysources. About 95% of the natural gas was produced from conventionalsources, and the remaining 5% was from unconventional sources suchas coal bed methane and shale gas. Recent exploration and exploitationof numerous shale gas plays in Canada have caused a sharp increase inboth estimated in-place resources and natural gas reserves. The portionof shale gas in the Canadian energy production could significantlyincrease in future years because of several factors, notably the largeand continuous nature of unconventional reservoirs and declining con-ventional (oil and gas) production. There are indeed a number of shalegas formations at various stages of exploration and development acrossthe country (British Columbia, Alberta, Yukon, Northwest Territories,Quebec, New Brunswick and Nova Scotia). Fig. 1 shows the distributionof the main shale formations targeted by the industry. In many cases,these formations produce variable volumes of liquids associated withnatural gas. Because of higher viscosities and size of the molecules,liquids are commonly produced from slightly coarser lithologies inter-bedded with the shales. As dry gas is currently not economical inmany cases, it is the production of liquids that is currently carrying thecost of the shale gas development or exploration.

The first shale gas production in Canada came from the MontneyPlay Trend (tight gas and shale gas) in 2005 and the Horn River (exclu-sively shale gas) in 2007, both located in northeastern BC, where drillingactivities have rapidly expanded (Figs. 2 and 3). Industry interest forother Canadian shale and tight sand plays started around the sameperiod in British Columbia, Alberta, New Brunswick and Quebec, asillustrated in Fig. 2. As of the end of 2012, over 1100 wells have beeneither drilled for shale gas exploration and production or exploited forgas (gas also being a common by-product of tight oil or tight sandwells) mostly in BC and AB. Fig. 2 provides the number of wells forshale and tight sand gas in Canada,1 as well as estimates of shale gasproduction in BC. Shale gas production for Alberta is not shown sinceit represents less than 1% of BC production; Alberta shale gas productionin 2011 corresponded to about 0.1% of total gas production in the prov-ince. The AB shale and tight sand wells shown in Fig. 2 were largelydrilled for liquids (condensates and oil); gas was a by-product. Fig. 3shows the production increase of unconventional wells in BC over thelast eight years. About 65 to 70% of total BC wells currently being drilledtarget theMontney Formation (Fig. 1), especially its liquid-rich domain.This expansion of tight reservoir wells is not, however, without contro-versy, and this topic will be discussed later in the section. Nonetheless,compared to the U.S., unconventional gas development in Canada isstill in its nascent stages.

1 British Columbia does not distinguish between shale and tight sand gas because theyare part of a continuumof very low permeability reservoirs inwhich economic productioncan only be achieved through hydraulic fracturing.


http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale-Matrices.aspx

http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale-Matrices.aspx


Fig. 1. Shale gas formations in Canada containing dry gas. Shale-hosted petroleum reservoirs are known in all Canadian provinces (except for Prince Edward Island) and in two territories(Northwest Territories and Yukon). The most promising are found in 5 provinces: British Columbia (BC), Alberta (AB), Quebec (QC), New Brunswick (NB) and Nova Scotia (NS).

3C. Rivard et al. / International Journal of Coal Geology xxx (2013) xxx–xxx

Most of the current drilling and production activities for shale gasand liquid-rich shale gas in Canada reside in northeast British Columbia(Fig. 1). Northern BC has now four active plays (Horn River Basin andMontney Play Trend and, to a lesser extent, the Cordova Embaymentand Liard Basin). Active plays in Alberta include the Duvernay andMontney shales. In New Brunswick, testing in the Frederick BrookShale has resulted in mixed results. This province, which was amongthe first jurisdictions in North America to develop oil and gas, has beenmainly active in tight sands gas since the 1990s. NB currently has oneproducing shale gas well in the Carboniferous tight gas McCully fieldin the southern part of the province. In Nova Scotia, five vertical explo-ration wells were drilled in the Horton Bluff shale without reported

Fig. 2. Total number of wells drilled yearly for unconventional hydrocarbon (liquids andgas) resources in shales and tight sands per year in Canada and annual production ofshale gas for British Columbia. Most wells were drilled in British Columbia (48.3%) andAB (48.2%), although gas represents a minor component in Alberta. Few wells are locatedin Quebec (2.3%), and the sum of wells in NB and NS equals 0.6%. Since total gas wells andgas production were provided for BC, the proportions shown in Fig. 3 were used to esti-mate these numbers for unconventional (shale and tight sand) gas only. Note: 106 m3/dcorresponds to 0.0355 Bcf/d.


success. There is no current exploration activity for shales in NovaScotia. Quebec presently has a de factomoratorium on shale gas drillingand hydraulic fracturing and the last shale exploration activity in the St.Lawrence Lowlands took place in December 2010. Because of low natu-ral gas prices, industry activity in Alberta and Saskatchewan is currentlyfocused on oil sands, conventional oil and gas, unconventional oil in theextension in Saskatchewan of the prolific oil-rich U.S. Bakken play (partof the Williston Basin), and liquid-rich gas in the Duvernay shale inAlberta.

3. Geological overview of main Canadian shale gas targets

The Canadian Phanerozoic successions comprise a significant num-ber of sedimentary basins with thin to thick organic-rich shale intervals(Hamblin, 2006). Of these, some are already at the gas production stage,and others are at various phases of exploration and definition of theirpotential to release economic volumes of natural gas. This section high-lights the main geological characteristics of some of the best-known

Fig. 3. Proportion of unconventional (shale and tight sand) gas production compared tototal gas production in BC (figures are from the BC Oil and Gas Commission).


image of Fig.�1

image of Fig.�2

image of Fig.�3



producing and undeveloped shales. The geological character of theUpper Ordovician Utica Shale in Quebec is not presented here, becauseit is discussed in detail in Lavoie et al., (2013, in this issue). Table 2presents areal extents, estimated resources and estimated recoverablereserves of gas in these selected shale gas formations or basins.

3.1. Upper Devonian Horn River Basin Shales

The transition from the broad Middle to Late Devonian shallow ma-rine carbonate shelf of the Western Canada Sedimentary Basin (WCSB)into a deeper shale-dominated domain occurs in the Horn River Basin(Mossop et al., 2004).

The Horn River Basin comprises three major Upper Devonian shaleunits, from base to top; the Evie and Otter Park members of the HornRiver Formation and the Muskwa Formation (Ferri et al., 2012). Innortheastern British Columbia, these three shale units form a roughly200 to 500 m thick succession that is either laterally equivalent (HornRiver Formation) or overlies (Muskwa Formation) the Middle–UpperDevonian carbonate platform and reefs of the Lower and Upper KegRiver and Slave Point formations. In turn, the Upper Devonian shalesare overlain by the Mississippian shales of the Fort Simpson Formation(Ferri et al., 2012). The transgressiveMuskwa Formation extends signif-icantly into southwestern Alberta where it is known as the DuvernayFormation.

Over most of the Horn River Basin, the Upper Devonian shales areburied to depths of 2500 m and well within the dry gas window(National Energy Board, 2011). The black to dark gray colored shaleunits in the Horn River Basin consist of marine Type II organic matterwith Total Organic Carbon (TOC) values up to 6% (British ColumbiaMinistry of Energy and Mines, 2005). The Evie and Muskwa shales aresiliceous and pyrite-rich whereas the Otter Park shale is more calcar-eous (National Energy Board, 2011). Porosity values can be relativelyhigh, reaching up to 5% (British ColumbiaMinistry of Energy andMines,2005), whereas average permeabilities range between 100 and 300nanodarcies (British Columbia Ministry of Energy and Mines, 2005).

3.2. Upper Devonian Duvernay Formation

The Duvernay Formation is an Upper Devonian shale-dominatedsuccession that covers a significant part of west-central Alberta of theWestern Canada Sedimentary Basin (Mossop et al., 2004). The south-ward transgressive shales of the Duvernay (from the platform marginlocated to the north) did not kill reef growth in the WCSB but arefound laterally equivalent and enclosing the oil-prolific Leduc reefs forwhich they acted as source rocks (Allan and Creaney, 1991).

In west-central Alberta, the Duvernay shales are found in the EastShale and West Shale basins (Switzer et al., 1994), both of which differin the geological setting and characteristics of the Duvernay Formation(see below). In the WCSB, the Duvernay Formation overlies the UpperDevonian carbonate platform of the Cooking Lake Formation and theformation is in turn overlain by the Upper Devonian Ireton Formationof clastics and carbonates (Mossop et al., 2004).

Table 2Extents and reserves of main shale gas formations and basins in Canada.

Shale gas formation or basin Approximate area (km2)

Horn River (BC) 11 500Montneyb (AB + BC) 25 549 + 26 000Duvernay (AB) 9850Utica (QC) 10 000Frederick Brook (NB) 1000

Note: Horn River data are fromBCMinistry of Energy andMines, National Energy Board (2011);Conservation Board (ERCB)/Alberta Geological Survey (AGS) (2012); Duvernay data are fromCorridor Resources Inc. (2009). Numbers in bold are related to Alberta (AB).

a Tcf corresponds to trillion cubic feet (1012 ft3). 109 m3 corresponds to 0.0355 Tcf.b Montney Formation.


Regionally, the Duvernay Formation is 30 to 120 m thick andconsists of three members, from base to top: 1) a black argillaceouslimestone, 2) a black shale unit with carbonate detrital beds, and 3) abrown to black shale with argillaceous limestone (Switzer et al.,1994). In the East Shale Basin (Switzer et al., 1994), the slightly thickerDuvernay Formation is dominated by organic-rich lime mudstone. TheDuvernay Formation in the West Shale Basin becomes less calcareousand more shale-rich from east to west. Depth from the surface to thetop of the Duvernay is about 1000 m near the eastern boundary toabout 5500 m in thewest, this correlates directly with thermal matura-tion datawhich documents awestward trend of increasing thermalma-turity (ERCB/AGS, 2012).

The Duvernay shales are dominated by marine-derived Type IIorganic matter with total organic carbon (TOC) content comprisedbetween 0.1 and 11.1%; the highest values are generally found in theEast Shale Basin (ERCB/AGS, 2012). Based on well logs and cuttings,the Duvernay Formation has an average porosity and permeability of6.5% and 394 nanodarcies, respectively (Dunn et al., 2012).

3.3. Lower Carboniferous Frederick Brook Member

The Frederick Brook member belongs to the Tournaisian (EarlyCarboniferous) Albert Formation of the Horton Group (St. Peter andJohnson, 2009). The Horton Group is the first sedimentary unit to bedeposited in the Maritimes Basin, a successor basin that formed afterthe Devonian Acadian Orogeny in eastern Canada (Hamblin and Rust,1989). Post-orogenic sedimentation of the Horton Group was domi-nated by alluvial to lacustrine environments (Martel and Gibling,1996).

The Frederick Brook Member is a lacustrine shale overlain and un-derlain by successions of sandstone, siltstone and shale (St. Peter andJohnson, 2009). The Frederick Brook lithofacies consist of laminatedkerogen-rich dolomitic mudstones, microlaminated kerogen-richshales (oil shales) and kerogen-rich siltstones with minor sandstoneinterbeds. St. Peter and Johnson (2009) estimated its maximum thick-ness to be around 350 m, although recent seismic data and drilling inthe Moncton sub-basin (Corridor Resources Inc., 2009) suggest that amuch thicker succession of 900 to 1100 m is locally developed. Fromburial depths of 3 to 4 km in the central part of the Moncton sub-basin, the unit shallows to 1 to 2 km at the sub-basin margin.

The Frederick Brook Member lacustrine shales are considered tohave sourced the conventional oil and gas fields of Stony Creek andMcCully, respectively (St. Peter and Johnson, 2009). The organic matterin the shales are Type I algal material with subordinate Type III land-derived organic matter (St. Peter and Johnson, 2009). The TOC valuesaverage 11% in the thermally immature areas (St. Peter and Johnson,2009) although, in the deeper, gas-prone part of the basin, TOC valuesare between 1 and 2.5% (Corridor Resources Inc., 2009). The shales areclay-rich (illite) with a similar volume-percent of quartz, diageneticalbite and carbonates (dolomite and calcite) (St. Peter and Johnson,2009).Well logs indicate that the gas-prone shales have porosities rang-ing from 3 to 8% (Corridor Resources Inc., 2009). It is noteworthy that

Estimated potential (Tcfa) Estimated recoverable reserve (Tcfa)

450 782133 + (80–700) N.A.443 N.A.100–300 22–47N75 N.A.

Montney data are from the BCMinistry of Energy andMines (2012) and Energy ResourcesERCB/AGS (2012); Utica data from Duchaine et al. (2012); and Frederick Brook data from




one vertical shale gaswell is currently producing gas from this shale unitwithin the tight sandstone McCully gas field (St. Peter and Johnson,2009).

3.4. The Lower to Middle Triassic Montney Formation

The Triassic succession of western Alberta and northeastern BritishColumbia was deposited on a passive margin marine shelf and slope(Podruski et al., 1988) before the development of a foreland basin inJurassic time. The Montney Formation unconformably overlies UpperPaleozoic rocks and is overlain by the phosphatic interval at the baseof the Doig Formation (Gibson and Barclay, 1989).

The Montney Formation lithofacies are dominated by shale and silt-stone with varying degrees of dolomitization and as such, the Montneyis not truly a shale gas unit. Fine-grained sandstones and coquinas arealso present in the upper part of the siltstone-dominated succession(Gibson and Barclay, 1989). The Montney Formation reflects a trans-gressive–regressive third order cycle (Gibson and Barclay, 1989) witha lower major transgressive facies and maximum flooding succession(lower shale-siltstone interval) overlain by shallower and coarseningupward facies.

The thickness of the Montney Formation increases westerly from0 m (at the erosional margin of the basin) up to 300–400 m in bothAlberta and British Columbia and similarly, the depth to the top of theMontney increases in the same direction from approximately 500 min the east to over 4000 m in the west. This variation in burial resultedin the development of oil to dry gas zones in an overall westerly trend.

The Montney Formation consists of Type II/III organic matter(Ibrahimbas and Riediger, 2005). The average TOC content of theMontney is 0.8%, with a range of 0.1 to 3.6%. The Montney siltstone(the gas producing lithology) has low porosities (lower than 10%),although the associated sandstone porosity can be as high as 35%. TheMontney lithofacies are clay-poor (maximum 20%, BC Oil and GasCommission, 2012) and show a high content of quartz, carbonates andfeldspars. In some areas of BC, the Montney is being actively developedfor liquids, with gas being a by-product.

4. Overview on fracturing

Over 175 000 wells have been stimulated by hydraulic fracturing inAlberta alone (mainly verticalwells),with few reported incidents. How-ever, as mentioned above, multi-stage fracking in horizontal wellsinvolves higher injection pressures and rates and a larger quantity ofwater. About 14 000 of these wells have been fracked so far acrossCanada, with most of them being located in relatively remote areas.However, this number includes all types of unconventional reservoirs(shale gas and liquid-rich shales, tight gas and tight oil, and coal bedmethane), not all of which require large amounts of water and highpressures to frac. For instance, coal bed methane is typically frackedwith nitrogen in Alberta.

In BC, slickwater is used in the Horn River Basin, while Montneyliquid-rich gas shales and siltstones are mainly fracked with foams(a mix of gas and water). In Alberta, slickwater, cross-linked fluids(typically guar-based fluids cross-linkedwith boron ions), and a combi-nation of the two have been used in the Duvernay Formation. In NewBrunswick, LPG (predominantly gelled propane) was successfully usedin the first vertical shale gas well; the following two horizontal wellsused slickwater and were unsuccessful. Industry has mainly usedslickwater fracturing and hybrid fracs (cross-linked fluids with guargum) in the calcareous shales of the Utica so far, with the exception ofone vertical well in a liquid-rich domain, where propane was used.

Chemical additives used in hydraulic fracturing are one of the mainconcerns for Canadians, even though proppants and chemical additivesinmost slickwaters constitute less than 2–3% of the overall composition(Nash, 2010). To parallel the publically available U.S hydraulic fractur-ing chemical registry “fracfocus.org.”, which provides information


related to chemical additives, methods of fracking and regulations bystate, the province of British Colombia has recently implemented thewebsite http://fracfocus.ca. As of January 1, 2012, disclosure of usedadditives on this website is required by the BC Oil and Gas Commission(BCOGC); Alberta and New Brunswick have recently announced (April2013) that they now have the same legal obligation.

All wastewater is collected and stored in enclosed tanks withsecondary containment to avoid potential infiltration of slickwater orsaline flowback water into the soil in BC and AB. No unlined surfaceponds are currently being used in Canada. In BC, the vast majority ofwater is re-injected at depth in deep saline aquifers such as those inthe Debolt Formation. Seismic events induced by these injections arealso a concern for the population (see below). In eastern Canada,deep-well injection of flowback water has not been tested or donebecause of lack of understanding of potential deep-seated geologicalstorage capacity (QC) or is simply not authorized because of potentialleaks resulting from assumed permeability issues of cap rock units (NB).

An increasing number of cases of small but perceivable earthquakeshave been reported in seismically quiescent areas where active subsur-face high-pressure water injection, either for geothermal tests orhydraulic fracturing, took place. Dense arrays of seismographs havebeen locally installed (e.g., northeastern BC) to decipher the source ofthese tremors. In the case of the areas with shale gas development,the issue is to distinguish deep crustal events from shallow eventslinked either to fracking programs or to wastewater re-injection indeep aquifers. Preliminary results from the research in BC indicatethat hydraulic fracturing can lead to limited induced seismicity (BC Oiland Gas Commission, 2012). No damage has been documented as aresult of induced seismicity associated with shale gas developmentsites. The highest magnitude recorded during hydraulic fracturingactivities in northeastern British Columbia is 3.8 on the Richter scale.This corresponds to minor damage (event felt only by some people onthe Mercalli scale). From preliminary data, the time interval betweenthe start of the fracking programand the induced seismic event (magni-tude 2 to 3.8) was between a fewminutes to about one day (BC Oil andGas Commission, 2012). In 2012 and 2013, GSC deployed arrays of seis-mographs in the Northwest Territories and New Brunswick, in areas ofeventual shale exploration and development. The stations are currentlymonitoring the regional large and fine-scale natural seismicity.

In provinces where no large-scale oil and gas activities had yet takenplace, several initiatives have been implemented at the provincial levelin the last 3–5 years, including working groups (NB), a strategic envi-ronmental assessment (QC) and even a specific hydraulic fracturingreview committee (NS). In addition, public consultations and com-munity information sessions were carried out in Quebec in 2010(BAPE, 2011), leading to the recommendation of a Strategic Environ-mental Assessment (SEA) dedicated to issues related to shale gas devel-opment. During the SEA process, the Quebec Ministry of Environmentwould only have considered authorizing fracking if the SEA Committeedeemed it useful for gaining scientific knowledge. However, becauseno operator requested a permit to conduct such activities, the SEACommittee proceeded with its studies by other means, which ledeffectively to a 2-year moratorium on shale gas fracking in Quebec.This moratorium has recently been extended for the St. Lawrence Low-lands until a new legal framework is set to specifically address hydro-carbon activities. Additional public consultations (Bureau d'audiencespubliques sur l'environnement, BAPE) will be held on the SEA reportconclusions in 2014. The SEA committeewill end itsmandate inDecem-ber 2013 and the BAPE will provide recommendations in 2014. Publicconsultations were also held in New Brunswick in 2012 and expressedconcerns by stakeholders have certainly influenced the newly pub-lished (February 2013) guidelines to regulate the unconventionalshale-hosted petroleum industry in the province (New Brunswick,2013).

Two incidents recently occurred in Alberta in relation to hydraulicfracturing operations. In September 2011 in Grande Prairie, improper


http://fracfocus.ca)



completion work (perforated casing above the base of groundwaterprotection, at a depth of 136 m) was found to be the cause of contami-nation of a near-surface water-bearing sandstone with gelled propane(ERCB, 2012a). However, the impacted zonewas not a source of potablewater. The base of groundwater protection in Alberta and BritishColumbia is set at 600 m deep, unless the interface can be proven tobe shallower. In January 2012, a spill occurred in Innisfail due to inter-well bore communication, causing the release of about 500 barrels offracturing and formation fluid to the surface, affecting 4.5 ha. Frozenground conditions prevented much of the fluid from seeping into theground and themajority of the cleanup operationswere completewith-in 72 h (ERCB, 2012b).

5. Water use

Among available fracking techniques, slickwater hydraulic fractur-ing is the one that uses the most water. It is, however, the least expen-sive method and has proven to be very effective, mainly because itmaximizes the contact surface by generating complex fracture net-works in the shale unit, especially in brittle rocks with higher silica orcarbonate content and lower clay content (Johnson and Jonson, 2012).Estimates from Johnson and Jonson (2012) using approximately 500wells in seven formations and five different basins showed that thereis an order of magnitude difference for water usage between foam andslickwater fracs: foam fracs in siltstone or shale formations use around200 m3 of water, while siliceous shale slickwater completions require2500–5000 m3 per frac stage. For this reason, the cumulative waterusage for the Montney Play Trend was much lower than that of theHorn River Basin, even though more wells were drilled each year inthe former.

Besides water quality issues, there is public concern related to waterquantity. It is difficult to estimate how much water will be required foreachwell until test sites have been studied. Quantities of fluids requireddepend mainly on the geology, i.e. the lithology, petrophysical andgeomechanical properties of the rock and hence, the pressure necessaryto fracture the shale, the shale depth, length of laterals, the stimulationtechnique used, the number of frac stages per well and anticipatedwater returns (Johnson and Jonson, 2012). In addition, in order tomaximize efficiencies and minimize footprints, well pads are designedfor manywells, whichmay be fractured consecutively, thereby increas-ing water demand over a short period of time. Typically in BC, there arecurrently six or eightwells per drilling pad, but this number can goup to21 on a given pad (for example, in the Horn River Basin). Waterissues could, therefore, mainly be related to the intensity of shalegas development.

In BC, reported volumes of water use during awell hydraulic fractur-ing range from2000 m3 to over 100 000 m3 perwell (i.e. approximately66 to 3300 large tanker trucks, since a large water tank truck is able tocarry about 30 m3). Averages of 1900 to 7800 m3 for the MontneyPlay Trend and 34 900 m3 for the Horn River Basin were reportedby Johnson and Jonson (2012), while mean values of 10 000 to25 000 m3 for the Montney Play Trend and 25 000 to 75 000 m3 forthe Horn River Basin are provided in Precht and Dempster (2012). InAlberta, an average of 50 000 m3 is estimated for slickwater fracturing(Precht and Dempster, 2012). In Nova Scotia, volumes for the two ver-tical wells that have been fracked so far were of 5900 and 6800 m3,while in NB, volumes for the two horizontal wells were ~20000 m3. InQuebec, volumes ranged from several hundred cubic meters to15 000 m3 and the average frac stage used 1500 m3. The U.S. literaturereports that drilling and hydraulic fracturing of shale gas wells togethertypically use 7500 to 15 000 m3 (from 2 to 4 million gallons) of water(GWPC and ALL Consulting, 2009). The returnwater volume combiningproduced and flowback water in BC varies from 15 to 70%. In theMontney, between 50 and 100% of water is recovered, while muchless water is being recovered in the Horn River Basin. In the Utica ofQuebec, the average flowback recovery was 45%.


Water sourcing is a key issue for hydraulic fracturing in BC. In somelocations, it is difficult to collect sufficient water for a high-volumefracking program due to the highly variable stream flow conditions. Inthe Prairies (i.e. AB, SK andMB), water usage is also becoming problem-atic since several river basins in the southern regions have fully allocatedsurface waters. Initially, the industry preferred to use fresh water, butnow companies can use brackish or even saline water for fracking pur-poses. Saline water from the Debolt Formation (20 000–30 000 ppm ofTDS) underlying theHorn River Basin is being used for fracking by somecompanies. However, this source of water contains H2S and other gases(CO2, CH4) that must first be removed in a treatment facility, and thesaline water must often be diluted. Regular friction reducers can beused to a salinity up to about 25 000 ppm. Above this salinity, pipesand infrastructure, as well as chemical additives (mainly frictionreducers) have to be adapted to the higher salinity. The industry hasdeveloped additives that work at salinities reaching up to 60 000 ppm(Ferguson et al., 2013) and200 000 ppm is targeted, to reduceflowbackwater management and treatment as much as possible.

The depth to the base of fresh groundwater aquifers is, unfortu-nately, poorly known across much of Canada. Water wells are typicallytoo shallow to reach the base of fresh groundwater, while oil and gaswells, targeting much deeper zones, have historically rarely includedthe systematic report of the water salinity for a given well, especiallyat relatively shallow depths. Alberta is the only province that hasdefined this base, using the depth at which water exceeds 4000 ppmof TDS. Work on the definition of the Base of Groundwater Protection(BGP) started in the 1980s by Alberta Environment, based on a seriesof reference cross-sections; this product was further updated andadapted by AGS and is available on a self-serve database (https://www3.eub.gov.ab.ca/Eub//COM/BGP/UI/BGP-Main.aspx). In thePrairies, groundwater is often brackish, or slightly salty, near the sur-face. In eastern Canada and BC, the base of fresh groundwater wouldlikely be in the order of 200 to 300 m, except in coastal areas and inareas where saline water from Quaternary sea invasions has not yetbeen leached out, where it could be shallower. For instance, there is a2200 km2 area in southern Quebec overlying, for its main part, theUtica Shale, which contains brackish water of Champlain Sea originthat has not been leached away by recharge or fresh groundwaterflow in the active zone (Beaudry et al., 2011).

6. On-going research

Although the regulation of shale gas development is primarily aprovincial jurisdiction in Canada, the Geological Survey of Canada hasinitiated in 2011 several new research projects focusing on variousaspects of shale gas exploration and development in Canada, in collabo-ration with the provinces and universities. These studies focus on twothemes: 1) evaluation of the gas resource (in place and recoverable)and geological characteristics of shale-hosted petroleum reservoirs,and 2) potential environmental issues related to hydraulic fracturing.The first theme includes three studies. The first one aims at developinga methodology for in-place and recoverable gas resource assessment,which will initially be tested on mature and frontier basins in Alberta,British Columbia and Quebec. The second one focuses on geologicalcharacteristics of specific shale reservoirs in Canada and the U.S., so asto better understand the quality and behavior of these reservoirs,using parameters that control their hydrocarbon storage capacity suchas mineralogy, nature of organic matter and its porosity evolutionthrough increasing thermal conditions. The third project studies thegeological integrity of cap rock in three provinces of eastern Canada:Quebec, New Brunswick and Nova Scotia.

The second research theme on environmental aspects includes twostudies: one on potential impacts of shale gas development on ground-water quality, so as to improve the understanding of a possible riskof natural or artificially-induced link between the shale gas target(N1000 m deep) and surficial aquifers (b300 m), while the second


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aims at increasing the understanding of potential induced seismicitycaused by injection for hydraulic fracturing purposes or for disposal byinjection of flowback wastewater (which includes the installation ofseveral seismographs as mentioned in Section 4). The groundwaterproject, which is described in Lavoie et al. (2013, this issue), focuseson a local study area in southern Quebec, while the induced seismicityproject is active in western Canada (BC, NWT), and has been expandedin eastern Canada (NB). All these projects are multi-partnered, includ-ing active collaboration with the industry, provincial departments ofnatural resources, energy and environment, and universities. In parallel,Environment Canada is carrying out a Canada-wide project on thedevelopment of impact indicators of shale gas activities on groundwaterusing laboratory work, field data as available, and modeling, whileHealth Canada, in collaboration with NB, has undertaken a study onair emissions to understand the potential impact that shale gas develop-ment may have on air quality in regions where such development mayoccur. Life-cycle greenhouse gas emissions related to shale gas develop-ment have already been the focus of a national compilation ((S&T)2Consultants Inc., 2011).

Research studies are also being carried out in many provinces,typically in an academic/governmental collaboration. For instance, inQuebec, the SEA Committee is funding many studies, two of which arespecific to 1) the theoretical numerical modeling of near-well gasmigration and upward fluid migration by Université Laval (Nowamoozet al., 2013a, 2013b) and 2) nature and concentration of natural back-ground dissolved gas in groundwater in the St. Lawrence Platform ledby the Université du Québec à Montreal (UQAM) (Pinti et al., 2013).These two studies will be completed by December 2013. In BritishColumbia and Alberta, detailed research on shale resource characteriza-tion and on various development-associated environmental issues is inprogress. The Alberta Geological Survey has undertaken in 2009 a studyon measurement and location of micro-earthquakes in the province, tomonitor natural and fracking-induced seismicity. Researchers from theUniversity of Alberta are studying isotope reversals and gas maturationin various reservoirs, including those in the Appalachians and WesternCanada Sedimentary Basin (WCSB) (Tilley and Muehlenbachs, 2012;Tilley et al., 2011). The same research team also currently has a projectaiming at understanding the origin of shallow natural gas in theWestern Canada Sedimentary Basin using isotope chemistry. AlbertaEnvironment commissioned a few years ago a study on chemical andisotopic characterization of groundwater in Alberta using existingmonitoring wells, which included dissolved and free gas, to establish abaseline against which future impacts on groundwater could be evalu-ated (Cheung and Mayer, 2007). In British Columbia, researchers fromSimon Fraser University in partnership with the BC Ministry of Forests,Lands and Natural Resource Operations are presently working on twoprojects related to shale gas development in northeast BC. One focuseson the characterization of the groundwater system and risk to ground-water quality in the Montney region. The second project will assesswater supply/demand and projected climate change impacts in relationto the overall water budget including interconnections between surfacewater and groundwater. In Ontario, Manitoba and Saskatchewan, thegeological features of shale gas and oil formations are currently beingcharacterized by the provinces. Regional scale initial appraisals of thenumerous lesser known shale units in Canada are in progress in allsouthern Canada jurisdictions, aswell as at specific sites in the CanadianArctic through provincial and territorial initiatives. New Brunswick hasrecently announced the creation of the New Brunswick Energy Institute(http://nbenergyinstitute.ca/) composed of researchers from NB uni-versities and elsewhere, to ensure that credible independent researchand monitoring are being carried out in support of energy files, includ-ing shale gas exploration and production, and that findings are beingcommunicated to the public. As well, government-academic projectsare being carried out to study in situ conditions prior to shale gas pro-duction (e.g. geochemistry of water wells near Sussex by the Universityof New Brunswick and Geological Survey of Canada, Al et al., 2013) and


theoretical processes that may affect groundwater quality (e.g. fluidmigrationmechanisms using numerical simulations byMcGill Universityand INRS, Gassiat et al., 2013).

In addition, other studies are being conducted that are indirectlyrelated to shale gas, including those carried out for water allocation oridentification of additional water sources to support gas development(e.g. AB and BC), those linked to optimal measurement of dissolvedgas in groundwater, such as the collaborative project between Environ-ment Canada and the University of Calgary (Roy and Ryan, 2013), andthose linked to potential impacts of oil development on aquifers suchas studies by the Institut national de la recherche scientifique (INRS)in Gaspésie and Anticosti, QC (Peel et al., 2013; Raynauld et al., 2013).Also, many regional scale hydrogeological studies have been carriedout in Canada to support water management and aquifer protectionover the last decade. These studies are crucial as they provide geological,hydrogeological and often geochemical information and maps, and abetter understanding of groundwater flow and aquifer vulnerability.The Groundwater Program of the Geological Survey of Canada (GSC)has been characterizing regional aquifer systems for the last 18 years.So far, the characterization of twelve regional aquifers has been com-pleted and seven others are underway across nine provinces; a total of30 key aquifer systems are targeted to be mapped and assessed by2024 (Rivera et al., 2003). All these projects are carried out in a collabo-rative manner between the federal and provincial governments.

A few provinces have undertaken regional hydrogeological charac-terization studies (QC, AB, SK, and BC). In Quebec and Alberta, programsstarted in 2008 with tens of millions of dollars of funding. The QuebecProgram (programme d'acquisition des connaissances en eau souterraineau Québec, PACES, http://www.mddep.gouv.qc.ca/eau/souterraines/programmes/acquisition-connaissance.htm) presently involves sixprojects that are near completion and five others that will be completedby 2015. These multi-partner research projects are led by researchers atQuebec universities. Some of the innovative aspects of the PACESProgram include 1) common databases, methodologies, and deliver-ables so that final results, tools, maps and cross-sections will be compa-rable and/or have similar meanings and 2) themandatory participationof regional organizations such as regional municipalities andwatershedorganizations to ensure that what is being studied is of interest andrelevance to the region, and that knowledge, maps and tools aretransferred to users (for more information, see Ouellet et al., 2011;Séjourné et al., 2013). In 2011, The PACES Program was acceleratedin order to cover all regions targeted by the shale gas industry,following recommendations from the public consultation processand needs of the SEA Committee. The Alberta Geological Survey(AGS) has also initiated a vast and comprehensive groundwater Pro-gram (Provincial Groundwater Inventory Program, http://www.ags.gov.ab.ca/groundwater/), which is divided into two components:saline and non-saline aquifer systems. Non-saline aquifer studies arecarried out in collaboration with Alberta Environment and Water andaims at mapping and understanding the province's groundwaterresources. The saline projects aim at mapping all major saline aquifersof the province, from the crystalline basement to the lowermost aquiferof the Colorado Group. However, AGS and the former Alberta ResearchCouncil had conducted hydrogeological mapping since 1968 and most(~85%) of the province has now been covered, except in the northeast-ern part (see Fig. 4). SK andBChave also characterized aquifers to differ-ent levels, mainly providing aquifer vulnerability indices and aquiferclassifications. BC has classified most aquifers in highly populatedareas, but these only cover ~15% of the province; vulnerability mappingusing the DRASTIC index was also carried out on Vancouver Island andthe Gulf Islands in collaboration with universities and the GSC. Theseaquifers are in the order of tens of km2 and thus, do not appear inFig. 4. Of note, the northeastern part of BC has recently been the focusof hydrogeological studies where aquifer classification was performed,based on limited available information. The Ontario Geological Survey(OGS) is currently carrying out a baseline groundwater geochemistry


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Fig. 4. Location of regional aquifer studies in Canada. The area name, extent, and project duration are provided. Shale gas formations are shownas a background, to point outwhich aquifersabove them have been studied so far. This map shows only study areas of 1500 km2 or larger, due to the size of the map. Saskatchewan has based its characterisation on 1:250 000mapsheets. Alberta has also mainly worked with 1:250 000 mapsheets until recently; because most of the study delineations are not available in digital format, the coverage shown isbased on Lemay and Guha (2009). The inset presents a detailed overview of studied areas in southern Quebec.


assessment of themajor rock and overburden units, including dissolvedgas (e.g. methane) analyses, in southern Ontario. OGS has also workedalong the Niagara Escarpment to characterize the Silurian carbonateaquifers. A fewother studieswere conducted by consultants and fundedby a program implemented by a Federal Department (Agriculture andAgriFood Canada). The area covered by these studies are, however,typically smaller than 600 km2.

Fig. 4 shows the on-going and completed regional aquifer studies.Only study areas larger than 1500 km2 were plotted at this scale. Intotal, more than 500 000 km2 are being or have been covered bythese hydrogeological characterization programs across Canada. Shalegas formations are presented in background. This map shows thatsome significant gas- and liquid-producing shales (e.g. Horn River andMontney, northeastern BC) have not yet been thoroughly studied in ahydrogeological context, mainly because they are located in remote,sparsely populated areas.

7. Public concerns and recommendations

Public concerns and opposition to shale gas development exist, par-ticularly in non-traditional hydrocarbon producing jurisdictions such asQuebec (see Section 9) and New Brunswick. The fact that some shalesare located under populated and/or agricultural areas (e.g. Utica Shalein Quebec) and below key Canadian aquifers (such as those shown in


Fig. 4) have exacerbated these concerns. Retrospectively, implementinga large-scale new industry such as oil and gas in eastern Canada wouldhave required much more preparation and prior public consultation. InQC and NB, economic benefits for provincial jurisdictions no longersway public opinion if there is a perception of environmental degrada-tion should the industry be allowed to proceed (Québec, 2011). Thereis thus a strong need for a transfer of scientific information to thestakeholders. Technology, scientific studies and regulations must alsobe developed coherently to ensure a sustainable development and anadequate resource development framework.

At a workshop on shale gas and the potential impacts of explorationand development on groundwater held in November 2011 which gath-ered mainly provincial hydrogeologists and governmental scientists,the following main conclusions were reached (Rivard et al., 2012):

• The use of brackish or saline water, which is not in conflict with otherwater uses, should be encouraged;

• Baseline studies should be carried out to ensure that groundwater ischaracterized prior to exploration;

• Research studies must be carried out on potential upward migrationof fluids, through improperly cemented casing, improperly aban-doned wells, and existing and induced fracture networks;

• Monitoringprograms should be developed for all stages of a shalewelllife cycle (pre-, syn- and post-fracturing and production);


image of Fig.�4



• Data from all sources need to bemade available (publically or at leastto provincial authorities).

The Council of Canadian Academies (CCA), which is a private, non-profit corporation funded by the Government of Canada to performindependent, expert assessments on important public issues, publishedin 2009 a report on the sustainable management of groundwater inCanada (Council of Canadian Academies, 2009). The CCA recommendedthat more efforts be focused on characterizing aquifers of populatedareas and on installing monitoring wells to ensure sustainable ground-water management, and that data should be publically available. TheCouncil is currently working on a report on potential environmentalimpacts of shale gas development that should be published in early2014.

8. Regulation

In Canada, provinces manage and generally own their onshorenatural resources, including oil and gas, and are the custodians ofsurface water and groundwater. However, the federal governmentresponsibilities assumed by the National Energy Board (NEB) and Natu-ral Resources Canada include inter-provincial and international energytrade, cross-jurisdiction pipelines, exports/imports as well as naturalresource regulation powers in the Canadian Arctic, offshore marineareas and Aboriginal lands. In Quebec, the mining system is based on afirst come, first served basis (mining claims) and is currently in effectfor onshore oil and gas exploration permits. Elsewhere in southernCanada, subsurface mineral rights for oil, gas and coal are obtainedthrough a bidding process for all areas open to exploration. In the Arcticfrontier area, exploration permits are typically awarded to the operatorwith the best exploration program that commits to work obligationsandmeets or exceeds all regulatory requirements, as ameans to encour-age exploration activities in remote places.

Almost everywhere in Canada, the exploration permit obtainedincludes the exclusive right to search for mineral and petroleumsubstances, but does not give ownership of surface rights (implyingthat landowner permissions are required for surface access to acquireseismic data or conduct any other kind of exploration activities). Acontract (surface lease) must be signed between the company and thelandowner to drill a well (private or Crown, to the exception of Quebec,where, strangely, no lease is required on public lands). However, insouthwestern Ontario (near Lake Erie), landowners own both surfaceand minerals. As in the U.S., Canada's energy policy is market oriented,i.e. gas price is based on supply, demand, transport and infrastructureinvestments. Therefore, both Federal and Provincial governments havejurisdictional powers that are important in energy issues. In addition,Canada requires aboriginal consultation on decisions that may impactaboriginal rights or title on their lands.

Some provinces have regulations that require permits for geophysi-cal work and licences for wells, while others require specific permits toeither drill, complete, hydraulically fracture, modify and or abandon awell. Lease agreements are required for surface land access, while with-drawal permits are required for water usage. There are also regulationsthat require drilling reports (including casing and cementing reports),borehole geophysical log data (rock evaluation), and well testing data(reservoir evaluation) in a timely fashion,which aremade public imme-diately, or after a brief period of confidentiality (3 months to 3 years)depending on the well category and province. Strong provincial andfederal regulations govern operational practices to protect the environ-ment including air quality, agricultural and forested area landuse, parks,wildlife habitats, fresh surface water and groundwater, although theseare not specific to the shale gas industry.

In eastern Canada, regulations go through the Departments of Minesand Energy for NB, of Natural Resources for QC, and of Energy for NS, forexploration and drilling activities (e.g. for geophysical work, drilling,and well completion) and through the Department of Environment for


environmental issues (e.g. for water withdrawals, water and air quality,gas flaring and authorization or permits for fracking operations). Inwestern provinces (BC, AB), authority has been delegated to singleorganisms (BC Oil and Gas Commission and Alberta Energy Regulator,formerly ERCB) that govern most aspects of the industry.

In addition to a cemented surface casing to protect groundwater, adual-barrier regulation is generally in effect and mandatory in the caseof a new basin, formation or region, or if there is significant changein the fracking technique/design. However, a single barrier may beapproved under certain conditions, depending on the jurisdiction. At aminimum, cement integrity must be confirmed visually by observingcement returns at surface, and a cement bond-log must be performedif no returns are observed at surface in AB, BC and NB. A leak-off testafter drilling the cement shoe does not appear to be mandatory in allthese provinces, but can be performed as a standard best practice, andit is presently mandatory in SK, QC and NB. Casing and cement integritymust be verified before any hydraulic fracturing operation in NB andAlberta, while it is not mandatory in BC and SK (but these operationscan again be part of standard best practices). Quebec currently doesnot have a specific regulation for hydraulic fracturing. However, evenwhen legislation is in place to test the casing integrity, potential envi-ronmental issues related to wellbore leakage remains, as these testscan fail to detect cement defects (Jackson et al., 2013). Therefore, thedevelopment of better engineering/technical methods is needed,including research and monitoring on cement curing, emplacementtechniques and bonding; in parallel, detection and monitoring of thepresence of fugitive gas, brine and flowback chemicals in shallowgroundwater that could be indicative of leakage should also be carriedout on a routine basis (Jackson et al., 2013).

For these reasons andmany others, environmental regulation needsto be regularly updated following technological and scientific develop-ments and strengthened to best protect health and environment(Rivard et al., 2012). For instance, groundwater monitoring wells arenot required at this time, except for coal bedmethane operations. Com-panies carry out baseline geochemical studies around their sites on avoluntary basis. Members of the Canadian Association of PetroleumProducers (CAPP), which account for 90% of the petroleum productionin Canada, pledged to uphold operating practices beyond current legalregulations, such as assessing potential health and environmental risksof each additive, and baseline groundwater testing (http://www.capp.ca/aboutUs/mediaCentre/NewsReleases/Pages/GuidingPrinciplesforHydraulicFracturing.aspx). The BC governmentinstalled 6 groundwater monitoring wells in the Montney Basin in2011, and discussion are on-going to put provincial monitoring wellsin the Horn River Basin. In Quebec, one of the SEA projects on samplingdissolved gas across the St. Lawrence Lowlands (Pinti et al., 2013)represents another provincial initiative.

9. The Quebec Utica Shale case

The case of the Utica Shale is discussed here because it is located inQuebec, where a shale gas hydraulic fracking moratorium is currentlyin place and large-scale development has not occurred. This sectionpresents informationmeant to provide insight into themuch publicizedsocietal context that led to strong public concerns, the de factomorato-rium, and the end in 2010 of all shale gas exploration activities in the St.Lawrence Lowlands. The Utica Shale is found along the St. LawrenceRiver, mostly on the south shore, as are about 90% of the people (asMontreal is part of the shale gas exploration area) and 90% of thefarmlands of Quebec. At the apex of the exploration rush in 2008, oper-ators acquired permits over (and beyond) the entire sedimentary suc-cession of the St. Lawrence Platform (BAPE, 2011); the area coveredby exploration permits for the Utica Shale (shown in red in Fig. 5)extends over ~20 000 km2, although it contains a zone northwest ofthe St. Lawrence River that has limited potential for gas since the UticaShale actually outcrops on the north shore of the St. Lawrence and is


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Fig. 5. Spatial distribution of the Utica Shale thermal maturity (adapted from Séjourné et al., 2013).


usually too close to the surface to maintain adequate pressure. The areaunder permits for exploration includes the geological province of the St.Lawrence Platform and thewestern reach of the outermost Appalachiandomain (External Humber Zone; Lavoie, 2008), extending from QuebecCity south-westward to Montreal and southward towards the UnitedStates. The geological setting of the St. Lawrence Platform, as well ascharacteristics of the Utica Shale, are presented in detail in Lavoieet al. (2013, this issue).

Gas seeps were identified in the 1950s–1960s on the northern sideof the St. Lawrence River (close to the very small reservoir exploitedin the late 1800s, see Section 2) and a small gas field in Quaternarysands was put into production from 1965 to 1976 (91 million m3 or3.2 Bcf, Pointe-du-Lac, near Trois-Rivières; Lavoie et al., 2009). Artisanalgaswellswere often drilled during this period and some of these are stillbeing used for heating farmbuildings. One conventional gas reservoir inOrdovician dolostones was found by Shell in the early 1970s and pro-duction ceased in the early 1990s (163 million m3 or 5.7 Bcf; St. Flaviengas field, 50 km south-west of Quebec City; Bertrand et al., 2003). Ther-mogenic gas from theUtica Shalewas demonstrated to be present in theSt. Flavien fieldwhereas amixture of thermogenic and biogenic gaswasrecognized in the Pointe-du-Lac reservoir (Lavoie et al., 2009; Saint-Antoine and Héroux, 1993). These two fields have since been converted


into storage reservoirs. Presently, there is no natural gas production inQuebec.

Current exploration permits for oil and gas exploration in the entireProvince of Quebec cover 31 160 km2 (7.7 million acres); most of thepermits appear to belong to joint ventures. In total, more than 450wells have been drilled in Quebec since the 1860s, of which 280 (62%)are located in the St. Lawrence Platform. The Utica Shale subsurfacethermal domain is mostly dominated by dry gas conditions, althougha liquid-rich (condensate and oil) zone is known in the NW area ofthe St. Lawrence Platform (Fig. 5). Analyses available in the oil andgas database reveal that gas from the Utica Shale and overlying units(e.g., the conformably Utica-overlying Lorraine Group) is generallycomposed of at least 90% methane, the remainder being essentiallycomposed of ethane, propane and carbon dioxide; little to no hydrogensulfide has been reported (Séjourné et al., 2013).

Industry still has to confirm the potential of the Utica Shale and itseconomical viability. Nevertheless, encouraging gas flow rates werereported in both vertical and horizontal wells. In 2006, two explorationwells were drilled for a conventional gas target. This explorationprogram also had, as a secondary objective, to collect data to evaluatethe shale for its geological character and shale gas potential. The twofirst wells specifically targeting Utica shale gas were drilled in 2007.


image of Fig.�5



Twenty-five others were drilled between 2007 and 2010. In total, 18 ofthese wells were hydraulically fractured. In February 2010, an an-nouncement was made that the St-Édouard-de-Lotbinière horizontalwell averaged 0.17 million m3/d (0.006 Bcf/d) of natural gas duringthe first 21 days of the production test. However, due to several factors,namely, the lack of hydrocarbon-oriented legislative and regulatoryframeworks together with the emplacement of very strict rules forfracking, including the need to receive social acceptability to conductany activity related to shale gas, resulted in the end of all explorationactivities in the Utica Shale. One of the major permit holders subse-quentlywrote-off its investment in theUtica Shale in 2012. In themean-time, the low price of natural gas has led to a reorientation of industry,which is generally now focusing its efforts on producing liquids (oil orliquid-rich gas) and, in Quebec, interest has moved to Anticosti Islandwhere the Utica-coeval Upper Ordovician shale (the Macasty Shale)occurs in the oil and condensate thermal domains. The presence of adense gas distribution network in the heart of the Utica play as well asa large local market represents, nonetheless, an economic advantagesince only short lateral connections from the well head to the pipelineswould be needed.

Few studies on the geological framework of the Utica Shale andoverlying units have been conducted; the most comprehensive studiesare from Thériault (2012a and b). Konstantinovskaya et al. (2012)focused on studying the actual stress regime in the St. Lawrence Plat-formanddefined the conditions thatwould trigger reactivation of struc-tural discontinuities, including faults. Séjourné et al. (2013), followingthe initial deep seismic reinterpretation of Castonguay et al. (2006),developed conceptual tectono-stratigraphic cross-sections of the UticaShale and overlying units that include the main geological constraints(structural discontinuities, stratigraphy and depth/thickness variations)of the region targeted by the industry for shale gas development.

Séjourné et al. (2013) have also synthesized available information tohighlight regions or types of data with little or no information to guidefuture research work devoted, among other things, to evaluate the caprock integrity above the Utica Shale. These authors have compileddata from water wells and oil and gas wells. They present tables pro-viding areal extent, number of oil and gas wells, and the number ofseveral types of analyses (e.g. gas and water shows, XRD, drill stemtests, production tests, and cores) available in each hydrogeologicalstudy area being investigated within the PACES Program. This reportmentions that some fluid analyses are available, but they have notbeen synthesized or statistically analyzed yet. Authors point out thatthese analyses should significantly contribute to a regional hydro-geological assessment (such as the saline/fresh water interface depthand location of dissolved gas in groundwater) and help constrainpetrophysical models. They also underline the fact that the impact ofthe presence of many dykes on the regional fracturing conditions ispoorly known and that there are no known under-pressurized reser-voirs in this area. Reports from the Utica Shale operators indicate thatan overpressure regime is the norm, confirming that these deep shalesare hydraulically isolated from the surface. Therefore, these authorsconclude that, given the actual regional knowledge, surficial aquifersshould not be connected to the deep Utica Shale unit (in spite of numer-ous cases of gas in water wells reported since the 1950s), although thepresence of (undetected) structural discontinuities at the local scalecould alter these conditions.

Public protest against shale gas development has led to the creationof nearly 100 local anti-shale gas protest groups. This opposition can berelated to several factors: 1) shale gas is found in relatively populatedareas; 2) Quebec does not have a history of large-scale oil and gasindustry and has for years promoted its hydroelectricity as “green ener-gy”; and 3) groundwater is an importantwater supply in this area, char-acterized by numerous small municipalities. There were indeed in 2012over 30 local (municipal or to regional levels) opposition groups, 3provincial protest groups and 63 municipalities that have announcedmotions pertaining to no drill zones around water wells, limits on


transporting chemicals used for fracking, or restrictions on injectingchemicals. Public concerns are mainly related to water contamination,health impacts, nuisances (traffic and noise) and local economic im-pacts. Water quantity on the other hand, is usually not a problem.Quebec receives over 1000 mm of annual precipitation and has manyrivers and lakes; groundwater is, if not abundant everywhere, alwayssufficient to supply residential needs. In addition, there is a large salinebrackish groundwater zone in the northwestern part of the St. LawrencePlatform (i.e. east and north of Montreal), as mentioned in Section 2.2,which could be used for this purpose since this groundwater has noother use.

A brief historical background of gas exploration leading to the UticaShale discovery and de facto moratorium can be summarized with thefollowing timeline:

• 19th century: first industry reports of natural gas in Quaternarydeposits overlying the Utica Shale.

• 1950s: First geological reports indicating gas in groundwater duringwater well and oil & gas drilling. First suggestion to try hydraulic frac-turing on the Utica Shale in Quebec by Clark (1953).

• 1971–1992: Vertical and horizontal drilling in Villeroy (~45 km south-west of Quebec City) for natural gas in fractured shales (Utica Shaleand Lorraine Group), no commercial production due to inadequatetechnology at the time.

• 1973–2004: Drilling in Saint-Flavien (~30 km south-west of QuebecCity); 163 million m3 (5.7 Bcf) production from a conventional car-bonate reservoir sourced by the Utica Shale; reservoir connectedthrough horizontal well drilling, now converted for gas storage.

• 2006: Two companies (Talisman and Junex) drill wells through theUtica Shale, targeting underlying conventional reservoirs; first wellsto be analyzed for shale gas potential in Quebec after the Villeroyattempts.

• 2007: First two wells (Gastem) fully dedicated to test the potential ofthe Utica Shale; first two hydraulic fracs on vertical wells (Forest Oil,partner).

• 2008: First three horizontal wells drilled and frac-stimulated and firstpublic release of results and resource estimates (Forest Oil).

• 2009: First public protest: a letter is sent to the government by a grouppreoccupied mainly by air quality. Release of the movie Gasland.

• 2010: Public hearings/consultations (BAPE) on shale gas development.• 2011: BAPE report. Announcement of new rules, permitting frackingunder very strict conditions that contributed to the pause in industryactivities and the de facto temporary moratorium. Creation of a strate-gic environmental assessment committee (SEA). Start of hearings onMining Lawmodifications.

• 2013: The Quebec Ministry of Environment (MDDEFP, ministère duDéveloppement durable, de l'Environnement, de la Faune et des Parcs duQuébec) released a draft regulation in May that should be adopted atthe end of 2013.

• 2014: Forthcoming new hydrocarbon law and environmental regula-tions announced by the Quebec Ministry of Natural Resources.

Mainly due to low gas prices and strong public concerns, shale gasproduction seems unlikely in the near future in Quebec; moreover, themoratorium on fracking may last until 2018. On the other hand, shaleoil exploration has commenced and hydraulic fracturing activitieshave been announced for the coming years on the largely unpopulatedAnticosti Island.

10. Conclusion

There are abundant supplies of natural gas in Canada. Unconven-tional resources have doubled Canada's natural gas resource base and,as exploration continues, this number could still increase. Presently,large-scale production is occurring only in northeastern British Colum-bia, where the population is sparse. Four plays are in production, ofwhich the Horn River Basin and the Montney Play Trend are the most




productive. Modest exploitation of dry gas occurs in the DuvernayFormation (Alberta), where liquids are also being produced at increas-ing rates. In British Columbia, the unconventional gas production repre-sents nearly 60% of the total natural gas production in the province andabout 90% of the drilling activity, while shale gas production in Albertarepresents only about 0.1% of the total provincial gas production andusually represents a by-product of the liquid production. Very fewshale wells have been drilled in eastern Canada so far. Nonetheless,one well is currently producing in the McCully Field (southern NewBrunswick) from the Frederick Brook Member shale (since 2008). Con-tinued exploration and development of natural gas from the FrederickBrook Shale is planned in the future with renewed drilling and frackingin the McCully gas field area in order to determine feasibility of com-mercial development. The Quebec Utica Shale economic productionpotential is still to be determined, but promising results were obtainedfrom 2006 to 2010. Amoratorium on shale gas exploration and hydrau-lic fracturing is, however, currently in place in southern Quebec.

Hydrocarbon exploration and production operations involve var-ious surface and subsurface risks of degrading groundwater qualityand these hazards need to be assessed and minimized. Driven by im-proved operational techniques and strategies, competition for wateraccess and public concerns, the industry is evolving toward increasinglyenvironmentally-conscious practices (e.g. use of saline water and“green” additives, groundwater monitoring, flowback and producedwater recycling, disclosure of fracking fluid additives), although theserequirements, in many cases, are not regulated yet. Many researchprojects at different scales and on various topics related to environmen-tal issues of shale gas have been initiated in the last few years at theCanadian federal and provincial levels, as well as in universities. Theseshould provide an impartial scientific base to support the sustainableuse of groundwater related to shale gas development.

Acknowledgments

The authors would like to thank the following individuals for theirhelp and willingness to provide information and access to data andstatistics for this publication: Annie Daigle from the NB Department ofEnvironment; John Drage and Adam MacDonald from the NS Depart-ments of Natural Resources and Energy, respectively; Dr. Kevin Parks,Tony Lemay, Andrew Beaton, Marie-Anne Kirsh, and Dean Rockoshfrom the Alberta Energy Regulator (AER, formerly ERCB); ChristopherAdams and Fillippo Ferri from BCMinistry of Energy (Mines andNaturalGas); Kei Lo from the SK Water security Agency; Dan Cowan from theEnergy Sector of Natural Resources Canada; Sylvain Gagné of UQAM,Dan Palombi from the Alberta Geological Survey, and Mike Wei of theBC Water Protection and Sustainability Branch. Special thanks go toFrançois Létourneau for his work on the figures, to Dr. Alfonso Riverafrom the GSC-QC for his review of the text on on-going research at theGSC, and to Marianne Molgat from Talisman Energy for her valuablecomments and information. The authors also wish to thank Dr. SteveGrasby (GSC-Calgary) for his careful internal review, as well as theGuest Editor, Daniel J. Soeder, and an anonymous reviewer for theirvaluable comments.

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http://www2.gnb.ca/content/dam/gnb/Corporate/pdf/ShaleGas/en/RulesforIndustry.pdf











http://www.nrcan.gc.ca/statistics-facts/energy/895














http://www.gov.ns.ca/nse/pollutionprevention/docs/Consultation.Hydraulic.Fracturing-Jurisdictional.Review.pdf



http://www.vgq.qc.ca/fr/fr_publications/fr_rapport-annuel/fr_2010-2011-CDD/fr_Rapport2010-2011-CDD-Chap03.pdf

http://www.vgq.qc.ca/fr/fr_publications/fr_rapport-annuel/fr_2010-2011-CDD/fr_Rapport2010-2011-CDD-Chap03.pdf





http://dx.doi.org/10.4095/290257

ftp://ftp2.cits.rncan.gc.ca/pub/geott/ess_pubs/214/214620/gid_214620.pdf

ftp://ftp2.cits.rncan.gc.ca/pub/geott/ess_pubs/214/214620/gid_214620.pdf
































