Seepage pathway assessmentfor natural gas to shallowgroundwater during wellstimulation, in production, andafter abandonmentMaurice Dusseault and Richard Jackson

ABSTRACT

Hydraulic fracture stimulation (HFS) of unconventional oil andgas reservoirs is of public concern with respect to fugitive gasemissions, fracture height growth, induced seismicity, andgroundwater quality changes. We evaluate the potential pathwaysof fugitive gas seepage during stimulation, in production, andafter abandonment; we conclude that the quality of the casinginstallations is the major concern with respect to future gas migra-tion. The pathway outside the casing is of particular concern as itlikely leads to many wells leaking natural gas from thinintermediate-depth gas zones rather than from the deeper targetreservoirs. These paths must be understood, likely cases identi-fied, and the probability of leakage mitigated by methods suchas casing perforation and squeeze, expanding packers of long life,and induced leakoff into saline aquifers. HFS itself appears not tobe a significant risk, with two exceptions. These occur during thehigh-pressure stage of HFS when (1) legacy well casings are inter-sected by fracturing fluids and when (2) these fluids pressurizenearby offset wells that have not been shut in, particularly offsetwells in the same formation that are surrounded by a region ofpressure depletion in which the horizontal stresses are also dimin-ished. This paper focuses on the issue of gas migration fromdeeper than the surface casing that occurs outside the casingcaused by geomechanical processes associated with cementshrinkage, and we review the origin of the gas pulses recorded innoise logs, landowner wells, and surface-casing vents.

Copyright ©2014. The American Association of Petroleum Geologists/Division of EnvironmentalGeosciences. All rights reserved.

Manuscript received February 11, 2014; provisional acceptance April 23, 2014; revised manuscriptreceived June 09, 2014; final acceptance June 18, 2014.DOI: 10.1306/eg.04231414004

AUTHORS

Maurice Dusseault ∼ University ofWaterloo, Department of Earth &Environmental Sciences, Waterloo, Ontario,N2L 3G1, Canada; mauriced@uwaterloo.ca

Maurice Dusseault started teaching at theUniversity of Alberta in 1977, where he tookhis Ph.D. in Civil Engineering. He becameProfessor of Geological Engineering at theUniversity of Waterloo in 1982, where heteaches rock mechanics and petroleumengineering geomechanics. He haspublished over 500 full-text articles andworks as an advisor to industry andgovernment. He is currently President of thePetroleum Geomechanics Commission ofthe International Society of Rock Mechanics,a senior science advisor to the Provinces ofAlberta, New Brunswick and Nova Scotia,and a past member of the Expert Panel ofthe Council of Canadian Academies on ShaleGas impacts.

Richard Jackson ∼ Geofirma EngineeringLtd., Heidelberg, Ontario, N0B 2M1,Canada; rjackson@geofirma.com

Richard Jackson is a Principal with GeofirmaEngineering of Ottawa, Ontario and anAdjunct Professor of Earth & EnvironmentalSciences at the University of Waterloo,where he took his Ph.D. He received theGeoenvironmental Award of the CanadianGeotechnical Society in 2008 and theFarvolden Award of the Canadian NationalChapter of the International Association ofHydrogeologists in 2013.

ACKNOWLEDGEMENTS

This article was underwritten by a generousgrant from the Alberta Department ofEnergy to the University of Waterloo and bysimilar generosity of Geofirma EngineeringLtd., Ottawa, Ontario that allowed for thecontributions of the second author. Wefurther appreciate several discussions onwellbore integrity with Theresa Watson ofT.L. Watson & Associates, Calgary, Alberta.Bryce McKee of Shell Appalachia and KevinParsonage of BC Oil & Gas Commissionprovided helpful reviews of a draftmanuscript.

Environmental Geosciences, v. 21, no. 3 (September 2014), pp. 107–126 107

INTRODUCTION

Undoubtedly, for several decades the energy supplyof choice in North America will be natural gas,sourced primarily from shale-gas formations. TheUnited States Government’s Annual Energy Outlook2013 (USEIA, 2013) indicates rapid growth in naturalgas use by industry, in electrical power generation,potentially in transportation (CNG vehicles), andeven for export potential (USEIA, 2013). To indicatethe intensity that development of this source of gaswill entail, full development of the Marcellus Shale,which underlies much of the northeastern UnitedStates, would require (with today’s techniques) morethan one hundred thousand horizontal wells, each∼2 km (6500 ft) long, with 15 to 20 fracture stagesalong the horizontal section of each well, and 500 to2000 m3 (100,000 to 500,000 gallons) of water-basedhydraulic fracture fluid for each fracture stage. Eachwell costs about $7 to $9 million, with up to 12 wellsper pad. If the underlying Utica Formation proves tohave commercial shale-gas production potential, thenumber of wells could eventually double.

Similar intense development is foreseen for theWestern Canada sedimentary basin. During 2011 inthe Horn River basin play of northeastern BritishColumbia, water volumes for fracturing horizontalwells (∼20-stage completions), each at least2 km (1.2 mi) long, averaged 80;000 m3∕wellð2.825 × 106 ft3∕wellÞ (Johnson and Johnson, 2012).Additional development is occurring in neighboringAlberta and, to a much lesser extent, in easternCanada. These developments in Canada caused theCanadian Federal Government to establish an ExpertReview Panel to consider the issues involved inshale-gas development (see Council of CanadianAcademies, 2014). This critical review expands onthe contributions by the authors to the Panel.

The Energy Institute of Massachusetts Institute ofTechnology (MIT, 2011, p. 7) considered thisexpansion of the natural-gas industry in a“carbon-constrained world” and concluded that the“…environmental impacts of shale development arechallenging but manageable.” An indication of thischallenge is the recent evidence from the NationalOceanic and Atmospheric Administration and theUniversity of Colorado that “…a mix of venting

emissions (leaks) of raw natural gas and flashingemissions from condensate storage tanks can explainthe (gaseous hydrocarbons) we observe in air massesimpacted by oil and gas operations in northeasternColorado” (Pétron et al., 2012, p. D04304). Thesefindings have recently been further substantiated byNOAA and the University of Colorado using isotopicmeasurements to differentiate between industrial andagricultural sources (Tollefson, 2013).

Natural venting of gas (mainly CH4) to theatmosphere occurs worldwide in many locations asseepages unrelated to oil and gas development.Naturally occurring seafloor or river-bottom oil andgas seeps are well documented around the world(Levorsen, 1967; Hunt, 1979; Stahl et al., 1981;Lavoie et al., 2010). Many water wells inPennsylvania and elsewhere are well established tohave naturally occurring thermogenic methane thathas migrated into the aquifer through natural connec-tivity of rock-fracture networks with gas-bearing for-mations (Rauch, 1983, 1984; Rauch et al., 1984;Fountain and Jacobi, 2000; Molofsky et al., 2013;Baldassere et al., 2014; Wilson, 2014).

Although public concern has been expressedregarding the potential for shale-gas development tocause environmental damage, such as flammable tapwater and earthquake tremors, we believe that the realconcerns are latent and long-term in consequence.Foremost among these are atmospheric emissionsand potable groundwater contamination arising frompoor annular cementing of natural-gas productionwells (Jackson et al., 2013). This old and stubbornproblem (Cooke et al., 1983; Harrison, 1985; Ernoand Schmitz, 1996; Dusseault et al., 2000; Watsonand Bachu, 2009) has not been resolved, a fact thatis acknowledged by many in industry.

We believe that the contamination is latent in thatit is not readily apparent or visible, perhaps during theentire operating life of the wellbore. Furthermore,because subsurface emissions remain unquantified,the documented natural gas emissions to the atmos-phere are most likely only part of the gas that ismigrating. This uncontrolled escape takes place inand adjacent to the annulus of operating and aban-doned production wells because of faulty, ruptured,or incomplete primary cement seals or leaky pipethreads. New isotopic evidence from British

108 Seepage Pathway Assessment

Columbia indicates that ∼75% of the occurrences ofsurface-casing vent-flow gases are associated withnon-target formations that discharge gas to the annu-lus of production wells (Muehlenbachs, 2012,2013). Gas migration (GM) in the annulus outsidethe surface casing is available for invasion of shal-lower formations, including freshwater aquifers.

Estimates of gas leakage from wells, such as pro-vided by King and King (2013, table 10), are uncer-tain in that variability exists in what is reported fromjurisdiction to jurisdiction. The Alberta estimate thatthey cite is that of Watson and Bachu (2009, table 2)—4.6% of all 316,439 wells in the Alberta database. It rep-resents surface-casing vent flow (SCVF) and GM,which is that occurring outside the wellbore into theadjacent soil or rock. These are monitored throughoutCanada at rig release and abandonment, with the pos-sibility of additional measurements dependent on pre-vious measurements. Nevertheless, the United Statesdata measure different parameters, such as sustainedannulus pressure, which vary from state to state. Theresults reported by King and King (2013) appearextremely low (<0.1%) compared with those ofWatson and Bachu (2009) from Alberta data, andIngraffea et al. (2013) who analyzed data from theMarcellus play using an online database maintainedby the Pennsylvania Department of EnvironmentalProtection. They concluded that gas leakage occurredin 6 to 9% of newly drilled wells (2010–2012) on thebasis of notice of violations issued and site inspec-tions. Thus, the frequency of gas leakage followingrig release is uncertain, but the studies by Watsonand Bachu (2009) and Ingraffea et al. (2013) suggestthat 4–9% of all wells drilled experience some formof gas leakage that is observable at the surface.

Furthermore, the USEPA data used by King andKing (2013, figure 15) to demonstrate the absenceof groundwater pollution by oil and gas operationsis inappropriate because the upstream industry isexempt from monitoring under the USEPA regula-tions (USEPA, 2002). It is also possible that the mostegregious cases that lead to groundwater contamina-tion are not recorded because they are settled off therecord by private operator–landowner agreements(Vidic et al., 2013).

This paper argues that the principal environmen-tal concern from increased natural gas exploitation

comes not from hydraulic fracture stimulation(HFS), but rather from the leakage of gas from non-target formations into inadequately sealed wellborecasings that allow the gas to migrate to the surfaceor to be vented from the well casings. The structureof an unconventional gas well is discussed as it iscentral to this argument that the well itself, not HFS,is of primary concern.

The depth of hydraulic fracture development dur-ing stimulation is considered and how such develop-ment might interact with shallow groundwater zonesor with pre-existing conduits; wellbore leakagebetween deep- and intermediate-depth zones and thesurface is also discussed. Our conclusion is that theintermediate-depth zones are the source of gas-wellleakage, which finding is supported by consideringGM in the exterior annulus of wellbores (i.e.,between rock and the outermost casing) in areasundergoing natural gas development.

UNCONVENTIONAL GAS WELLS

Figure 1 represents a typical well construction for anunconventional gas well. One may view its lengthas traversing three zones that are approximatelydefined as:

1. A shallow zone containing potable groundwater orslightly brackish water that may be suitable foragricultural or industrial uses.

2. A deep zone consisting of the target productionformation and its cap rock, including all strataaffected directly by HFS of the horizontal wellboreas well as several hundred meters of overlyingstrata that could possibly be in hydraulic commu-nication with the horizontal wellbore and thusmight be pressure depleted during production.

3. An intermediate zone where exists a sequence ofstrata of differing porosities and permeabilitiescontaining formation fluids (saline water, naturalgas, oil) in contact with the production casing,which may or may not be cemented to the adjacentrock (depending on regulatory requirements).

The conductor casing or pipe shown in Figure 1prevents soils from caving into the borehole duringinitiation of drilling operations. The surface casing

DUSSEAULT AND JACKSON 109

(a) guides drilling fluids to the surface without inter-action with shallow strata during the drilling phaseof well construction, (b) protects shallow strata fromall produced or injected fluids during the life of thewell, and (c) is used to affix a wellhead to providecontrol of flow and pressures of fluids going intoand coming out of the wellbore during drilling thenext hole section. Placing the bottom of the surfacecasing below the base of potable water is consideredgood practice by most regulatory agencies.

The surface casing is cemented completely to thesurface, and if any difficulty arises in getting thecement to the surface, remedial cementing may benecessary using a small tube lowered behind the cas-ing, a challenging process difficult to execute withexcellent results. Alternatively, remedial cementingis conducted by perforating the casing and injectingcement to seal off a saline aquifer or an annular space(squeeze cementing) that might conduct fluids.

Sometimes the production casing is cemented allthe way to the surface or a substantial distance intothe surface casing if deep enough. Commonly,another casing—the intermediate casing—and forextremely deep wells or in cases of high overpressure(usually offshore), as many as three intermediate

strings or liners (a short casing hung in the previouscasing and cemented in place) are used before thehole for the production casing is drilled. The standardcement slurry should be placed above a minimumdensity (∼2.05 g∕cm3 [128 lbs∕ft3]), althoughlight-weight cements are available to address lost-circulation issues during cementing operations. Theproduction tubing is hung in the production casing,attached to the wellhead, and isolated from the pro-duction casing with a pressure-sealing mechanicalpacker at the base of the tubing as shown in Figure 1.

HYDRAULIC FRACTURE STIMULATION(HFS)

The large liquid volume used in a single unconven-tional gas well during fracturing (e.g., ∼80;000 m3

or 20 million gallons in some Horn River wells inBritish Columbia during a 10-day, 20-stage fracturetreatment) means that the volumetric strains placedon the reservoir are an order of magnitude greaterthan in almost all previous conventional oil- andgas-well fracture treatments. These large HFSs havecaused concern and have been cited as responsible

Figure 1. Schematic well construction diagram for an unconventional gas well. No intermediate casing is shown, but such a casing canbe assumed to be required in deep wells and be cemented in place similar to that shown for the surface casing. Tubing is not cementedin place; casings are cemented.

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for contamination of shallow groundwater above theMarcellus and Utica formations in Pennsylvania(Osborn et al., 2011), a process of vertical migrationof fluids and contaminants to the surface that hasbeen simulated by Myers (2012), Flewelling andSharma (2014), and Gassiat et al. (2013). We nowconsider this possibility.

HFS proceeds from the toe to the heel of the hori-zontal well in individual fracture stages (Figure 1).The fractured length is about 1.5 to 2.5 km (1 to2 mi) and, because of the well geometry, the last frac-ture stage—that closest to the heel—is far enoughfrom the vertical part of the well so that the fracturefluid should not intersect the vertical section of thewell that passes through the intermediate-depth zone.

Figure 2 is a schematic cross section, not to scale,of the disposition of the fractured horizontal well sec-tion in a shale-gas reservoir with overlying strata. Thehydraulic fractures at each stage are represented as aseries of thin lines to indicate that the fracturing proc-ess, which is implemented at fluid injection rates ofup to 10 m3∕min ð∼350 ft3∕minÞ, opens many natu-ral fractures hydraulically, and allows these fracturesto be propped open with a granular agent (proppant).The induced fractures predominantly develop in theplane perpendicular to the orientation of the leastprincipal stress, which in deep gas reservoirs

(>2 km or >6500 ft) is usually one of the two hori-zontal stresses (Zoback, 2010; Zoback et al., 2012).

However, the rock mass volume that has anenhanced transmissivity (the product of permeability× rock-volume thickness) is now understood to befar larger than the volume of rock that has beenreached by the proppant itself. This effect arisesbecause significant volumetric strains in the regionclose to the fracturing point cause distortions in therock mass and the high injection pressure reducesthe frictional strength along natural joints. Theseprocesses lead to wedging open of more distant frac-tures, and most importantly, to shear displacementacross pre-existing natural fractures (see Figure 3).Because a natural fracture is a rough surface, a smallshear displacement (millimeters in scale) will preventit from fitting closely back together when the activefracturing pressure is dissipated following stimula-tion. Called shear dilation, it leads to transmissivityenhancement of the naturally fractured shale-gas res-ervoir by opening up minute flow paths far from theproppant zone, but still within the shale-gas reservoir(Warpinski and Teufel, 1987; Hossain et al., 2002;Nassir et al., 2014, and references therein).

Nothing is to be gained commercially in forcingshear dilation to occur any significant distanceoutside of the shale- or tight-gas reservoir, and

Figure 2. Fracturing the horizontal well section in a shale-gas well.

DUSSEAULT AND JACKSON 111

monitoring and modeling are used to design eachfracture stage so that the fractures remain within thetarget zone (see Davies et al., 2012; Fisher andWarpinski, 2012). The propped zone, combined withthe zone of shear dilation, is called the stimulatedrock volume or SRV. Generally considered to be anellipsoidal volume as shown in Figure 4, the SRVhas grown upward more than downward with itsshape being a complicated function of the naturalstress field, the natural fabric of the rock mass, andthe strategy used during the HFS (viscosity, fluiddensity, injection rate, leak-off control agents, etc.).

HFS, when conducted in structurally deformedregions or areas where the deviatoric stresses areclose to a critical slip condition (see Zoback, 2010,chapter 11), may conceivably cause lateral pore-pressure transmission to nearby stressed faults ordeep fracture systems and may temporarily enhancegas seepage before production begins. Such even-tualities involve complex processes requiring furtherresearch (see subsequent discussion on inter-wellborecommunication).

Several factors inhibit uncontrolled upwardmigration of induced fractures:

a. Production well construction—Hydraulic fractur-ing is done through the production tubing that issealed from the production casing (see Figure 1),not through the production casing itself, and theannular pressure on the production casing is moni-tored. If a breach occurs in the production casing,it is detected immediately, so the risk that the

production casing becomes pressurized and thenloses fluid confinement (seal) somewhere alongits length becomes manageable. The bottom partof the production casing is usually well cementedbecause the cement, as it was placed and as it set,was under a high hydrostatic head, densifying thecement, and producing an optimum seal for thequality of cement used. (Note that an exception tothis case occurs if the deviated production casingis not properly centralized within the borehole.)Therefore, a hydraulic fracture in the horizontalwell section has little chance of moving laterally,intersecting the vertical section of the wellbore aconsiderable distance away, and propagating upalong the wellbore during injection. This is espe-cially so because the horizontal section is drilledapproximately parallel to the minimum principalstress in situ, so induced fractures should be domi-nantly propagating at 90° to the horizontal section.

b. Orientation of induced fractures—Hydraulic frac-turing in zones where the minimum principalstress is horizontal will lead to induced fracturesthat will rise preferentially, rather than be verti-cally symmetrical around the fracture point(Figure 5). This is because the rock-mass fracturegradient (the minimum stress gradient) is on theorder of 18 to 23 kPa/m (0.80 to 1.0 psi/ft)depending on rock density. However, the densityof the fracturing fluid is perhaps 1000 to1300 kg∕m3 (i.e., a specific gravity of 1.0 to 1.3,depending on the amount of suspended proppant),producing a vertical pressure gradient in thefracture of about 10 to 13 kPa/m (∼0.44 to0.58 psi/ft). As shown in Figure 5, this leads to a

Figure 3. Shear dilation enhances the flow capacity of therock mass.

Figure 4. The stimulated volume is the total volume of therock mass surrounding the fracture point at which enhancedtransmissivity has been generated.

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greater driving pressure at the top of the fracturethan at the bottom, leading to preferred fracturerise. The maximum fracture growth height appearsto be on the order of 600 m (1969 ft) in variousUnited States shales including the Marcellusand Barnett shales, and around 1100 m (3609 ft)offshore (Davies et al., 2012; Fisher andWarpinski, 2012). Beyond such vertical heights,natural fractures in the form of joints, faults, andbedding-plane partings arrest vertical growth byallowing leakoff (i.e., fluid diversion) into multi-ple fractures or saline aquifers (Warpinski andTeufel, 1987).

c. Imbibition of injected fluids and associatedstrain—Some of the fluid volume injected eitherflows back at the end of each hydraulic fracturestage, is accommodated within open or partiallyopen fractures in the shale-gas reservoir, or isabsorbed by the shale itself. For example, theMarcellus Shale has a water-phase porosityapproaching irreducible saturation (Soeder, 1988;Ryder and Zagorski, 2003; Engelder, 2012),meaning that the water is held by strong capillaryforces. Therefore, irrespective of any potential

gradient, the availability of brine for migrationfrom the Marcellus to shallower horizons, asclaimed by Warner et al. (2012), is limited becausethe brine is trapped by capillary forces and lowpermeability. Some permanent volumetric strainis associated with hydraulic fracturing, but it islikely to be on the order of 30 to 50% of the vol-umes injected during the fracturing (dependingon leakoff and flowback volumes). Furthermore,it is feasible to measure this strain indirectlythrough the use of sensitive inclinometers(tiltmeters); therefore, this is amenable to explicitquantification (Dusseault and Rothenburg, 2002)and, if required, reporting to the regulatory author-ities, undoubtedly not on all wells in a field, butperhaps for every 20th hydraulic fracturing treat-ment, or for the first ones in a region.

d. Effect of uplift and surface erosion—In most partsof the world where sedimentary basins have beenuplifted and subsequently eroded (all shale-gasbasins identified to date are in uplifted, erodedbasins), the stresses in the earth become redistrib-uted. Commonly, a zone will be created from100 m (300 ft) below ground surface to perhapsas much as 1000 m (3000 ft) thick in which frac-tures will not tend to rise vertically, but will turnand propagate horizontally, parallel to bedding(Han et al., 2009), because the vertical stress hasbecome the smallest of the principal stresses. Forexample, Figure 6 shows a carefully measuredcase in southeastern Alberta northeast ofMedicine Hat, showing that above a depth of∼350 m (∼1100 ft), the natural stress regime leadsto horizontal fracture propagation and, below∼400 m (∼1300 ft), induced fractures will propa-gate vertically. If a fracture is initiated in a hori-zontal well at a depth of 425 m (1400 ft), it willlikely rise and when it encounters the depth regionwhere the stress turnover exists, it will start topropagate horizontally, and be more influencedby bedding. This stress condition provides a fur-ther barrier to the upward migration of fracturingfluids in most geological environments.

e. The nature of the overlying strata—Significantthicknesses of low-permeability strata generallyoverlie shale-gas reservoirs. These may rangefrom stiff, naturally fractured rocks as above theUtica Shale, or they may, as in the case of theWestern Canada sedimentary basin, be ductilefine-grained strata of the Colorado Group that

Figure 5. Hydraulic fractures tend to rise because of differen-tial gradients.

DUSSEAULT AND JACKSON 113

have essentially no natural fractures. Ductileshales at shallower depths are effective seals toupward migration of fluids, and, of course, in mostcases the actual hydraulic fracture openings are fardeeper, so the imposed mechanical strains are min-imal. The presence of ductile overlying shales inAlberta and Saskatchewan appears to be the sealfor the shallow tight gas sands found in theCretaceous strata (300–1000 m [984–3281 ft]deep). A ductile shale is far less stiff than a sili-ceous shale of low porosity and therefore canexperience more strain before the opening of anyfractures within the shale. Slatt and Abousleiman(2011) discuss the relationship of sequence stratig-raphy and geomechanics in unconventional gasshales. In the case of stiff, naturally fractured over-burden, the overlying strata may have acted as par-tial seals against upward migration of gas becausethe shale-gas reservoirs are still intact, several hun-dred million years after the gas formed, althoughthe gas in shale-gas reservoirs is pore bound,rather than free gas in large pores. Even wheregas seeps from depth (e.g., Stahl et al., 1981;Fountain and Jacobi, 2000), Brown (2000) hasshown that such gas seepage can be low enough

to not deplete the reservoir through geologic time.Nevertheless, the volumetric changes from deepfracturing could cause rotational distortion (bend-ing) of the overlying strata, perhaps enough toopen new pathways far above the zone in whichthe fracturing took place. In ductile shales, this isquite improbable. Suffice to say that naturallyoccurring thermogenic gas in shallow bedrock iswell documented (e.g., Rauch et al., 1984;Fountain and Jacobi, 2000; Molofsky et al., 2013;Baldassere et al., 2014) even if the gas-migrationpathways are poorly understood. This thermogenicgas is usually mixed with shallower biogenic gas,or the shallow bedrock gas may be entirely bio-genic in nature. Bending of the overburden strata,generating new open pathways for GM, is consid-ered an extremely improbable case, given thesmall strains involved, but it may be worthy of fur-ther investigation through measurements and mon-itoring (instrumented wells in the intermediatezones).

f. Hydraulics of upward fracturing fluids migrationto shallow groundwater—Myers (2012) postulatedthat hydraulic fracturing might cause a conditionwhereby a shale-gas reservoir, similar to that

Figure 6. Fracture orientation and stresses, north of Medicine Hat, Alberta, Western Canada sedimentary basin.

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shown in Figure 2, is connected with pre-existingvertical fractures to the shallow-zone aquifersshown at the top of this Figure. The critique byCohen et al. (2013) is sufficient to dispense withthe extraordinary simulation of this hypothesis byMyers (2012), but omits addressing the improb-ability of it occurring because of hydraulic fractur-ing. Estimating the required hydraulic head in ashale-gas reservoir needed to lift the fracking fluid1500 meters (∼4900 ft) through sandstone andshale “to near-surface aquifers through naturalpathways” (Myers, 2012, p. 873) is a straightfor-ward task. For such an event, the hydraulic head(i.e., elevation head + pore-pressure head; Freezeand Cherry, 1979) in the fractured reservoir mustat least equal the head in the shallow aquifer. Wemay estimate this as a hydraulic head of 1500 mor ∼4900 ft (pore pressure = 0, or atmospheric, atthe water table) above the shale-gas reservoir, ourreference datum (elevation = 0 m). Thus, to realizeMyers’ scenario, the hydraulic fracturing fluid hasto be lifted for a prolonged period to a height of1500 m (4900 ft) above the shale-gas reservoir ifwe wish to cause the fracturing fluid to penetratethe shallow aquifer. Within the fractured reservoir,let us assume that the head was hydrostatic prior tohydraulic fracturing and that the overlying sand-stones and siltstones have a pore-fluid density of1100 kg∕m3 ð68.7 lbs∕ft3Þ (specific gravity =1.10) and that the fracturing fluid has a density of1050 kg∕m3 ð65.5 lbs∕ft3Þ (specific gravity =1.05). The hydrostatic head within the fracturedreservoir is therefore ∼16 MPa (2321 psi), and thatis increased by 50 MPa (7252 psi) by the injectionof the hydraulic fracturing fluid, but only at the topof the injection tubing. In theory, this fluid pres-sure could support an instantaneous column offracking fluid to a height of ∼6400 m (∼20997 ft;66 MPa ÷ 1050 kg∕m3 ÷ g) for the short periodof time the pressure increment remains at 50 MPa(7252 psi) above the hydrostatic pressure at thisdepth. However, hydraulic head is a measure ofthe fluid’s mechanical energy per unit weight(J/kg), and the vast majority of this energy avail-able at the top of the injection tubing is dissipatedduring fracturing by pipe friction, proppant trans-port, friction in the narrow induced fractures, lat-eral migration (leakoff), pressure loss throughradial flow, and shale fracturing. Furthermore,should any fluid migrate out of zone, that is,

beyond the target formation, it is more likely toleak off into pre-existing fracture systems or deepsaline aquifers (de Pater and Dong, 2009).Therefore, the additional pressure incrementapplied at the ground surface by a fleet of frackingtrucks is unavailable to lift fracking fluid to thesurface in the time provided and explains themeasured fracture-height growths of <600 m(<1969 ft) reported by Davies et al. (2012) andFisher and Warpinski (2012). Consequently, sig-nificant out-of-zone vertical migration of fractur-ing fluid will occur only in the case of the targetformation being penetrated by a nearby abandonedor producing well with poor cement completion ora corroded casing, either of which may allow thefluid injected at 50 MPa (7252 psi) above hydro-static to escape from the target formation. Suchan event occurred in Alberta in 2012 (see follow-ing discussion) when a horizontal well camewithin 129 m (423 ft) of an offset well producingfrom the same formation; the result was a surfacerelease of fracturing fluid, brine, and oil aroundthe offset well.

g. Design of HFS—The companies that undertakehydraulic fracturing use mathematical models andmonitoring data to design their injection operationin such a way that the actual fracturing zone,including the region of beneficial perturbation ofthe natural fractures (the SRV) does not extendsignificantly beyond the top of the shale-gas targetzone. To go beyond the zone in which the shalegas is found is merely a waste of money.However, mathematical models of high-pressure,high-rate hydraulic fracturing are understood tobe semi-quantitative because of simplificationsmade regarding the stress field and the presenceof natural fractures the orientations of which areunknown (Tutuncu et al., 2012). Understandingof the hydraulic fracturing process is undergoingrapid improvement (e.g., Dusseault et al., 2011;Gu et al., 2012; Zoback et al., 2012) and will pre-sumably be added to future mathematical models.

h. Volumetric strains and fracture rise—In a simplefirst-order approximation, the total volume changefrom propping, wedging, and shear dilation can beconsidered as an ellipsoid (Figure 4), in which thevolume is proportional to W×L×H (aperture ×length × height). Suppose that a designed fracturetreatment is expected to have a height of 75 m(∼250 ft) from the injection of a volume of fluid

DUSSEAULT AND JACKSON 115

(no leakoff); to achieve a height of 150 m (492 ft),twice the designed height, would require a volumeabout eight times larger (2W×2L×2H). Thus, theconcept of hydraulic fractures rising in an uncon-trolled manner toward potable water layers is notrealistic. To cause a fracture to propagate duringthe fracturing period to the potable water level,perhaps 1–2 km (3281–6562 ft) above, wouldrequire fluid volumes orders of magnitude largerthan are used, pumping for many days or weeksor months, and an absence of appreciable leakoffto permeable zones. The height of fracturing hasbeen associated with the height at which micro-seismic events have been recorded (Fisher andWarpinsky, 2012), giving an estimate of fracturerise no more than 600 m (1969 ft) above the injec-tion point for more than 800 monitored operations.Realistically, this probably bounds fracture risebecause microseismicity (shear dilation) can betriggered far in advance of the presence of actualfracture fluids through wedging (reduction in nor-mal effective stress) and pore-pressure reduction.

i. Production from shale-gas reservoirs—Depletionduring production of the shale-gas reservoir is thegoal of drilling and HFS. From 40% to 60% ofthe total gas in place is expected to be producedfrom the shale-gas zone throughout a 10 to 25 yearwell life (Clarkson 2013), although King (2010)indicates the present recovery is the range15–35%. The volumetric strains associated withthe depletion of the pressures are extremely smallbecause the framework of the rock is exceptionallystiff. Calculations suggest that these volumetricstrains will generate only small strains in the over-lying rock, not sufficient to affect the natural frac-tures in those rocks. Following production, thedepleted shale-gas formation becomes a zone oflow regional pressure (and reduced horizontal totalstress) and is more likely to induce brine flow intoit than to allow gas flow to escape. Gassiat et al.(2013, p. 8325) conclude from their simulationsthat hydraulic connectivity between the hydrauli-cally fractured overpressured shale and a high-permeability fault is a necessary condition forleakage of fracturing fluids to a shallow aquifer.However, their model is based on the furtherassumption that extraction of shale gas and associ-ated fluids, which of course is the purpose of thefracture stimulation, would not “lower the pressurein the hydrofractured zone and decrease the initial

upward stability of solutes, as well as the durationof overpressured conditions that drive the upwardfluid flow.” Thus, this model requires conditionsof sustained overpressuring that are most unlikelybecause hydraulic fracture well stimulation is fol-lowed by extraction to recover costs, or at the veryleast to test the commerciality of the prospect interms of its productivity over some time period.Therefore, the pressure in the hydraulically frac-tured zone is lowered from its original state, andif the well is maintained on production, large-scaledepletion takes place, raising the effective stress atthe scale of the drainage radius, and increasing thefrictional resistance of the rock mass. We considerthe conditions for the simulations by Gassiat et al.(2013) extremely unlikely in practice.

Therefore, it is reasonable to conclude that therisk of hydraulic fracture fluids or gas from the zonerising up into the intermediate zone during or afterfracturing is remote. Because operators have an eco-nomic incentive to reduce the loss of injected fluidsinto overlying zones that are non-productive, thechances of dramatic fracture rise toward shallowerdepth and intersection with potable water aquifers,remote as they are, will become even lower as thecompanies perfect their techniques. This, of course,ignores the possibility that an inexperienced operatormay cause hydraulic fracturing fluids to penetrate ashallow aquifer because of mistakes that lead them tobelieve they are fracturing at the target depth (1.5 kmor 4900 ft below ground surface [bgs]), not at 136 m(446 ft bgs) and into a shallow sandstone aquifer(ERCB, 2012b).

However, if decommissioned wells intersect thehydraulic fracturing volume, then such wells consti-tute the seepage pathway of greatest risk for hydraulicfracture fluids. The most serious fluid communicationrisk during hydraulic fracturing is the possible inter-section of the fractured zone with offset wellboresthat pass through the SRV created by the hydraulicfractures. If the quality of the cement and completionof the offset well is poor, fracturing fluids could fea-sibly move laterally to the offset vertical cased wellsthen upward along the annulus between the casingand the rock.

If the offset well is an old producing well exploit-ing the same formation as a new shale-gas horizontal

116 Seepage Pathway Assessment

well, the effect of stress depletion associated with itspressure depletion because of production from thatformation will influence the extent of the SRV. Thisporoelastic effect reduces the horizontal stress in thedepleted region (e.g., Hillis, 2001) so that hydrauli-cally induced fractures will tend to propagate prefer-entially toward the depleted zone around the legacyproducing well. In such a case it is essential thatthe old producing well be shut in and monitoredduring hydraulic fracturing of the new well, and thepathway along the outside of the old producing wellmay still represent a risk to hydraulic fracture fluidmigration.

A recent case in Alberta (ERCB, 2012a) deter-mined that a horizontal well had been drilled towithin 129 m (423 ft) of an offset well that sub-sequently discharged ∼500 barrels (21,000 gallonsor 80 m3) of hydraulic fracturing and formation fluidsat the surface when the new well was fractured. Thevast majority of cases of such inter-wellbore (IWB)communication involve pore-pressure pulses, notfluid breakthroughs. Experience in the Barnett Shaleof Texas indicates that a distance of ∼200 m(∼656 ft) is sufficient to allow such IWB communica-tion (M.D. Zoback, Stanford University, personalcommunication, 30 November 2012). Kim (2012)indicates that the distances measured in Alberta arelarger with a median value of ∼250 m (∼800 ft). Amaximum IWB communication value of 2400 m(7700 ft) has been reported in Alberta (Kim, 2012),whereas in British Columbia evidence of IWB com-munication to 4100 m (13451 ft) has been noted bythe Provincial regulatory agency (BC OGC, personalcommunication, 24 January 2014). New regulatoryguidelines have been published in Alberta to reducethe probability and impact of this type of transmission(AER, 2013). We emphasize that lateral migration ofa pressure pulse is not the same as vertical fracturepropagation through various stress and lithologicalbarriers (e.g., high leakoff zones) nor does it involvefluid breakthroughs.

Therefore, the migration of hydraulic fracturingor formation fluids including natural gas to the sur-face because of deep hydraulic fracturing of typicalshale-gas reservoirs appears most unlikely.Controversial issues in the Appalachian basin associ-ated by public media with HFS may actually have

been associated with the drilling phase of unconven-tional gas development when high-pressure-drillingair leaks into shallow bedrock (Soeder, 2012; Genget al., 2013). Rather, the actual subsurface threat toshallow groundwater contamination is likely to comefrom a combination of factors involving the charac-teristics of annular cement seals of production wellsand the presence of natural gas in intermediate zonesbetween shallow aquifers containing potable ground-water and the deep shale-gas formations to be devel-oped. This possibility is considered next.

WELLBORE LEAKAGE

We conclude that the critical pathway for upwardmigration of fluids is along the wellbore of energywells, and the fluid of concern is generally methaneðCH4Þ and other buoyant gases. Any direct liquidmigration within or around the wellbore is improb-able because the density of the formation liquids isthe same as the pressure gradient increase with depthin many normally pressured cases, and because thetarget shale-gas reservoir is depleted with time. Atypical initial stress and pressure condition for ashale-gas reservoir is shown in Figure 7.

Shale-gas reservoirs may or may not be overpres-sured. Some reservoirs, particularly those less than2.5 km (∼8200 ft) deep, are under a hydrostaticpressure gradient, ranging from 10 to perhaps

Figure 7. Initial stresses and pressures with depth.

DUSSEAULT AND JACKSON 117

11.5 MPa/km (0.43 to 0.49 psi/ft; the hydrostaticpressure of pure water is ∼9.8 MPa/km or 0.433 psi/ft; of saturated NaCl brine it is ∼1.2 MPa/km or0.52 psi/ft). Others, particularly at depths greater thanabout 2.5 km (∼8000 ft), have mild to moderateoverpressures (11.5 to 14 MPa/km [0.49 to 0.60 psi/ft];Chatellier et al., 2011), but overpressures >15 MPa/km(>0.64 psi/ft) are uncommon in shale gas plays.If shale-gas exploration and development areextended to greater depths, for example, beyond4 km (∼13000 ft) depth, the odds of encountering sig-nificant overpressures will be higher. (Note that drill-ing risks associated with significant overpressures inshale-gas strata are far less than with overpressuresin highly permeable conventional reservoirs becausethe volume and influx rate of gas that wouldenter the wellbore during an inflow incident wouldbe limited).

The vertical stress is generally taken to be thethickness of the overburden times the average unitweight of the rock column. In sedimentary basins,rock density can be as high as 2.55–2.60 g∕cm3

ð1.47–1.50 oz∕in3Þ for low-porosity (2–10%) shalesand sandstones (such as the Marcellus andUtica Shales in eastern North America). However,they can be as low as 2.15–2.25 g∕cm3 ð1.24–1.30 oz∕in3Þ for high-porosity (22–30%), shallow over-burden strata that are much younger and havenever been deeply buried, such as in the shallow offshoreGulf of Mexico or the Cretaceous and Tertiary strata ofthe Western Canada sedimentary basin.

In Figure 7, the minimum horizontal stressðσhminÞ is assumed somewhat larger than the verticalstress to a depth of perhaps a kilometer (3280 ft) ora bit more because of tectonic loading combined witherosion effects. With increasing depth, σhmin isassumed somewhat less than σv. As discussed previ-ously, this lateral stress distribution is common ineroded sedimentary basins around the world, and isthe case in the Western Canada sedimentary basin(Horn River, Montney, and Duvernay formations)and in the Appalachian (Marcellus Shale) and BendArch–Fort Worth Basins (Barnett Shale) in the USA.

Between the deep shale-gas horizon and the sur-face casing, that is, in the intermediate depth zone,thin low-permeability sands or finer grained strataoccur that contain natural gas that exists at the same

pressure as the liquid phase in the rock mass, the blueline in Figure 7. These thin gas zones are not eco-nomically exploitable, therefore their presence isbarely acknowledged in oil-field literature, and thesestrata are rarely subjected to detailed geological andgeochemical characterization. During exploitation ofthe deep shale formations, they would not be depletedwhatsoever; thus, they would remain at their virginpressures.

After the horizontal wells are fracture stimulated,the shale-gas reservoir is placed on production andthe pressure depleted during a period of many yearsto a pressure value that will be on the order of 20 to30% of the original pressure, perhaps somewhat lessif the well is totally dry of liquids. This does not meanthat all of the gas in the shale reservoir has been pro-duced. It is widely known (e.g., Ross and Bustin,2008) that about 20 to 40% of the gas in the rock issimply too well trapped by the extremely low-permeability structure to ever be accessed. In addi-tion, some of the more easily accessible gas in thehorizon will never be fully depleted in the lifetimeof the wells because it lies too far from the stimulatedregion (the region of open fractures from the HFS).Estimates of ultimately producible gas vary widely;King (2010) puts it in the range 15–35%.

Depletion leads to a drop in pressure within thedrained zone, as shown in Figure 8. At the same time,because a drop in pressure must also generate a small

Figure 8. Changes in pressure and horizontal stress afterreservoir depletion.

118 Seepage Pathway Assessment

amount of rock shrinkage because of the rock com-pressibility effect, the horizontal total stresses in theshale reservoir will drop, usually by an amount thatis roughly ⅔ of the pressure drop (Hillis, 2001). Thevertical total stress is controlled by the weight of theoverburden, so it will remain roughly the same afterwidespread depletion. Because depletion is takingplace, the vertical effective stress is increasing byabout the same magnitude as the pressure depletion,whereas the horizontal effective stress is increasingby about ⅓ of the pressure depletion. These increasesin effective stress are known to affect the permeabil-ity of the stimulated zone, reducing it substantiallyas depletion continues (Miller et al., 2010). As men-tioned previously, the low-pressure depleted regioncomprises a regional pressure sink, so once theexploitation of the shale-gas zone is completed, fluids(gas, saline water) will migrate slowly to the depletedreservoir, eventually repressurizing it, but only after along time, perhaps many centuries.

Following depletion, it is almost inconceivable toaccept that any fluids from the shale-gas reservoircould migrate to the shallow- or intermediate-depthzones because of the new pressure gradients. Beforeshutting down the shale-gas field entirely, eachshale-gas well would typically be abandoned by plac-ing a series of cement plugs into the production cas-ing. However, migration of gas from depth does notoccur inside the casing if it is properly abandoned;gas migration almost certainly occurs along the out-side of the casing, sourced from intermediate-depth,thin, non-target gas-bearing units (Rowe andMuehlenbachs, 1999; Muehlenbachs, 2012, 2013).

Even if primary cementing is carried out withappropriate quality control, achieving the right levelsof density and rates, the pure cement paste mayshrink a very small amount after the primary set. Ifthis happens, the radial stress around the casing isreduced, and this sets up conditions for a narrow gascolumn to develop in a thin annular region betweenthe cement and the rock wall. Because the rock massis very stiff, even a volumetric strain of 0.001 (0.1%shrinkage) will reduce the radial stress to the level ofthe fluid pressure.

Other well-documented problems remain thatcause GM in the wellbore annulus (see review byWatson and Bachu [2009]). These include cement

shrinkage (e.g., Reddy et al., 2009) or involving gasinvasion of the setting cement caused by fluid pres-sure differences between cement slurry and adjacentrock that lead to channels forming in the cement(Sabins et al., 1982; Bannister et al., 1984).Goodwin and Crook (1992) discussed fracturing ofthe cement sheath by pressure and temperaturecycling from the wellbore and its impact on cementand formation compaction. Bois et al. (2011) discussmechanisms favoring the formation of a microannu-lus, in particular, cement hydration followed byshrinkage and pressure or temperature cycling.

If a column of free gas is allowed to form, it has astrong tendency to rise because the pressure differ-ence at the top of the gas column between the gasand the fluid is greater than the pressure differenceat the bottom of the gas column. This arises directlybecause of the difference in density of the gas and ofthe pore water, or the difference in density of the gasand the lateral stress gradient in the rock mass; thatis, it is buoyant. This column begins to rise with a dis-placement pressure (Pd) given by (Tiab andDonaldson, 2004):

Pd = zgðρw − ρgÞ

in which z is the height of the gas column, g is thegravitational constant, and ρw and ρg are the densitiesof water (brine) and gas respectively, as discussedpreviously. The longer the gas column that develops,the greater the pressure difference and the strongerthe upward driving force at the top of the gas column(see following discussion). The phenomenon arisesfor the same reason that a hydraulic fracture usingwater or gas will preferentially rise, rather than propa-gate upward and downward equal amounts (shown inFigure 5).

To give an idea of the magnitude of this force,some simple calculations can be performed.If a very thin (submillimeter) but continuous gascolumn 10 m (33 ft) high develops adjacent to anintermediate-depth-zone gas-bearing stratum, theadditional driving force displacing the water at thetop is approximately 100 kPa (roughly one atmos-phere or 14.7 psi). This force will push the water inthe zone behind the casing back into adjacent forma-tions, and the free gas column will continue to rise

DUSSEAULT AND JACKSON 119

ever more rapidly because the excess force is a directfunction of the height of the gas column. The effect isshown in Figure 9.

GAS MIGRATION WITHIN THE WELLBOREANNULUS

We have identified the wellbore as the most likelypathway of fluid leakage from depth to the surfaceor shallow subsurface where freshwater aquifersmay exist. The principal fluid we expect to be mobilealong the wellbore axis is hydrocarbon gas. The driv-ing force is the pore pressure and buoyancy for gasesshown in Figure 9. The principal pathway that wehave identified is a microannulus between the outer-most casing and the cement sheath or, more likely,between the cement sheath and borehole rock wall.This microannulus should not be confused with thewell-documented cases of channeling within thecement sheath itself that may not be continuousthroughout the length of the cement sheath.

Because of autogenous shrinkage of cement (e.g.,Reddy et al., 2009, and references therein) and thesubsequent reduction in radial contact stress betweenthe borehole wall and the cement sheath, a microan-nulus may develop that creates a pathway by whichnatural gas may rise outside the casing. That is, thecement sheath becomes debonded from the borehole

wall (Mueller and Eid, 2006). Gas seepage maybecome evident as surface-casing vent flow (SCVF)or as gas migration (GM) that is defined as occurringoutside the casing strings. GM may emit atground surface, where it contributes directly to green-house gas effects, or it may penetrate shallow aqui-fers, leading to gassy water wells or groundwatercontamination.

According to the records of the Alberta EnergyRegulator (AER, formerly the ERCB) 14% of energywells in Alberta completed since 1971 had reportedSCVF measurements that were considered serious.This typically means gas flows >300 m3∕dayð>7.36 ft3∕minÞ or a surface-casing vent stabilizedshut-in pressure >11 kPa/m (>0.49 psi/ft) times thesurface-casing depth as initially or subsequently mea-sured prior to abandonment, thus requiring remedialmeasures such as casing perforation and cementsqueezing. In Canada, surface-casing vents are leftopen to the atmosphere so that gas may vent freely.

In the USA, however, the practice of shutting-insurface and other casing-head valves is widespread.Once a certain shut-in pressure is achieved at thedepth of the surface casing shoe, it is more likely thatGM will occur and gas seepage will develop outsidethe surface casing, most probably through a thinannular space induced between the cement sheathand the borehole–rock wall. Now the potential forgroundwater contamination is much increased (seethe cases described by Bair et al., 2010; Penoyer,2012). Because an aquifer is permeable by definition,it will exhibit a low capillary entry pressure to gaswhich, if the differential pressure is sufficient, willenter the aquifer, and, if the aquifer is confined, willspread laterally.

Within the cemented or partially cemented annu-lus, we expect GM to occur through an annular pathgenerated in part by cement shrinkage with time.Gas that is measured as SCVF or as GM (Watsonand Bachu, 2009) or causes groundwater contamina-tion in a shallow aquifer likely migrates within theannulus and appears in monitoring or landownerwells as pulsed flow (Gorody, 2012), rather than thecontinuous gas flow discussed by Brown (2000).

Moreover, the occurrence of mixed gas, that is,gases from different formations having unique iso-topic fingerprints, has been observed to be seldom

Figure 9. The pressure or stress profile in water, gas, and therock mass.

120 Seepage Pathway Assessment

measured as SCVF. Rather, the gas fingerprint indi-cates a relatively uniform isotopic fingerprint indicat-ing a source beneath the surface-casing shoe butabove the production zone (Muehlenbachs, K.,University of Alberta, personal communication,November 6, 2013); this depth is called theIntermediate Zone by Canadian hydrogeologists(Council of Canadian Academies, 2014).

We believe that these observations may beexplained by the formation of gas slugs at depthcaused by the coalescence of numerous bubblesbehind the casing (Jackson and Dusseault, 2014; seeFigure 10). McKinley et al. (1973) demonstrated thatnoise logging by a wireline tool would allow the iden-tification of various forms of gas migration in thewellbore annulus. Their diagnostic methods are stillin use (e.g., Wang et al., 1999; Molenaar et al., 2010;Arthur, 2012). For two-phase flow of gas and forma-tion water, they identified various classes of behaviorproducing a noise spectrum peak at different frequen-cies by simulating the processes involved in a 4.3 m(14 ft) long, 27 cm (10.75 in.) casing. They identified

discrete bubbling noise occurring in the 300- to 600-Hz range caused by bubble trains, mild slugging atnoise frequencies above 200 Hz, and severe sluggingat a noise frequency of ∼200 Hz. Single- or two-phaseflow was identified as noise above 1000 Hz, indicat-ing free-stream turbulence. However, Wang et al.(1999) point out that slug flow is noisier (i.e., in termsof sensor voltage response), so both amplitude andfrequency are indicators of flow type.

In the chemical engineering literature, thesebullet-shaped gas slugs shown in Figure 10 are com-monly referred to as Taylor bubbles based on thework of Davies and Taylor (1950). At a gas volumefraction of ∼0.25 in brine at the depth of thegas-intrusion zone, a transition occurs from bubblesto a gas slug with the displacement pressure: Pd =zgðρw − ρgÞ, as discussed previously. By rising, theslug decompresses, expands, and increases its verticalextent, and therefore velocity. The physics of thisprocess is described in the chemical engineeringliterature (e.g., White and Beardmore, 1962; Wallis,1969; Kostakis and Harrison, 1999; Vianaet al., 2003; and Taha and Cui, 2006). It is likely sim-ilar to the upward migration of gas-rich magma(Gonnerman and Manga, 2013; James et al., 2013),the upward migration of natural gas in basins(Mandl and Harkness, 1987), or that observed inwater wells by Gorody (2012).

The rate of pulsing seen in landowner wells or inSCVF records (see Figure 11) is thus controlled bythe rate of coalescence at the depth of the gas source.These gas slugs have a thickness slightly less than theannulus so that liquid countercurrent flow may occuralong the walls of the annulus as the buoyant gasrises. At the depth of the surface-casing shoe, the ris-ing slug will either migrate into the surface-casingannulus formed with an interior casing or migrateoutside the shoe. The outside gas will then migrateup the annulus between the surface casing and therock wall. The slug will exhibit an overpressure whenencountering a shallow aquifer and will thus morereadily invade a fractured bedrock or granular aquiferand perhaps form a gas cap if sufficient gas enters aconfined aquifer.

It appears that when a wellbore’s casing-headvalves are shut in, including its surface-casing ventvalve, as is usually the practice in the USA (but not

Figure 10. Gas flow regimes in bubble-column experimentswith the gas phase in white and the liquid (e.g., brine) in black(modified from Gonnerman and Manga, 2013, courtesyCambridge University Press).

DUSSEAULT AND JACKSON 121

in Canada), the potential for GM and subsequentgroundwater contamination is exacerbated, illustratedby examples from Ohio and Pennsylvania.

In the first case in Bainbridge Township, Ohio(Bair et al., 2010), a casing-head valve was keptclosed following the upward migration of gas throughthe wellbore annulus following stimulation. This ledto the pressurized gas invading the shallow Bereasandstone aquifer, which was used locally for drink-ing water. Had the casing-head annulus valve notbeen closed and the gases allowed to vent to theatmosphere, it is unlikely that sufficient pressurewould have built up in the subsurface to have allowedgas to migrate into the Berea sandstone and sub-sequently into the domestic wells.

The second case is that described by Penoyer(2012), who illustrates the development of a gas capbeneath the shut-in casing head of a well in theMarcellus shale-gas play. Upward GMn occurs fromthin non-target gas sediments at approximately5000 ft (∼1,500 m) depth, which are exposed to anopen borehole (see Figures 2, 7, 8, 9), and risesthrough 1400 m (4500 ft) of uncemented boreholeannular space. The overpressured gas cap displaces

230 ft (70 m) of water beneath the casing head andsits above the surface-casing shoe at 500 ft (150 m)depth. As Penoyer points out, this condition causesGM around the surface-casing shoe into the adjacentfractured bedrock, thus allowing gas to move throughfracture networks and faults to freshwater aquifersand valley streams.

Thus, shutting in the casing-head valves mayinduce GM outside the casing toward shallowgroundwaters. Canadian regulatory practice has neverfollowed this policy and thus may perhaps have unin-tentionally limited the number of cases of GM caus-ing groundwater contamination but exacerbatingatmospheric releases. We believe also that the prac-tice of leaving long-uncemented zones behind theproduction casing in older conventional wells canexacerbate the possibility of GM because of thegreater ease of formation of a high gas column.

CONCLUSIONS

The quality of the cement completions of surface anddeeper casing installations is a concern with respect

Figure 11. Taylor bubble (image) rising within water in a pipe of 76.2 mm (3 in.) diameter (from Viana et al., 2003; courtesyCambridge University Press). Pulsed flow (graph) measured as surface-casing vent flow by a VentMeter™ (courtesy John Hull, HifiEngineering Ltd., Calgary, Alberta). Casing perforations and cement squeeze injections are shown as dotted vertical red lines; the thirdremediation was successful in stopping gas flow.

122 Seepage Pathway Assessment

to future gas migration (GM) within the cementedannulus of modern unconventional oil and gas wells.The pathway outside the casing is of greatest concern,and likely leads to many wells slowly leaking naturalgas upward from intermediate, non-depleted thin gaszones. These paths must be understood and the prob-ability of leakage addressed by mitigation methods,such as better initial cementation quality control, ini-tially installed expanding packers of long life, meth-ods to force induced leakoff into deep salineaquifers to avoid interaction with shallow aquifers,and better casing perforation and squeeze correctiveactions if leakage does develop.

The deep hydraulic fracturing process itselfappears not to present a significant environmentalrisk, except when abandoned or suspended (i.e., idle)well casings are intersected within the zone contactedby fracturing fluids during the high-pressure stage offracture injection. Similarly, producing wells in thesame target formation as new horizontal wells under-going HFS may be affected by fracture fluids whenthe inter-wellbore distance is within perhaps 250 m(800 ft), depending on the size of the HFS. This dis-tance may increase if faults are intersected.

GM outside the casing is typically a result ofincomplete cementing (in the case of older conven-tional wells) or the formation of microannuli withinor on the periphery of the cement sheath because ofcement shrinkage. Gas-pressure gradients will allowthe vertical ascent of gas slugs that will appear at thesurface as pulsed gas flow. Hydrogeologistsmust consider this phenomenon when samplinggroundwater-monitoring wells.

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