Important geological properties of unconventional resource shales

Cent. Eur. J. Geosci. • 3(4) • 2011 • 435-448DOI: 10.2478/s13533-011-0042-2

Central European Journal of Geosciences

Important Geological Properties of UnconventionalResource Shales

Review Article

Roger M. Slatt∗

Institute of Reservoir Characterization and Conoco-Phillips School of Geology and Geophysics,University of Oklahoma, Norman, USA

Received 30 September 2011; accepted 18 November 2011

Abstract: The revelation of vast global quantities of potentially productive gas and oil-prone shales has led to advancementsin understanding important geological properties which impact reservoir performance. Based upon research on avariety of shales, several geological properties have been recognized as being common and important to hydro-carbon production. (1) transport/depositional processes include hemipelagic ’rain’, hyperpycnal flows, turbiditycurrent flows, tempestites , wave-reworking, and contour currents in both shallow and deep water settings. (2)Common shale minerals include clays, quartz, calcite, dolomite, apatite, and pyrite; organic constituents includespores (Tasmanites), plant remains, biogenic quartz and calcite, and arenaceous foraminifera. (3) Porosity andpermeability are characteristically low with pore sizes ranging down to the nanoscale. Main pore types includeintergranular (including pores within clay floccules), porous organic matter, porous fecal pellets, and microfrac-tures. (4) Important geochemical characteristics include organic richness (>3%), maturity (>1.1%Ro for shalegas and 0.6-0.9% for shale oil) and type (I-IV), in addition to certain biomarkers which are indicators of bottomwater oxicity during deposition. Remaining hydrocarbon potential [RHP = (S1 + S2)/TOC] also reflects temporalenvironmental changes. ’Isotopic reversals’ can be used to detect best producing areas in shale-gas plays. (5)Lithofacies stacking patterns and sequence stratigraphy are the result of eustatic depositional history. A generalsequence stratigraphic model is presented here that highlights this commonality. (6) Geomechanical propertiesare key to drilling, fracturing and production of hydrocarbons. Brittle-ductile couplets at several scales occur inshale sequences. (7) Geophysical properties, when calibrated to rock properties, provide a means of regionally tolocally mapping the aforementioned properties. (8) Economic and societal considerations in the exploration anddevelopment of resource shales are garnering attention. Many potentially economic shale-gas and shale-oil playsare being identified globally. Risks and uncertainties associated with gas- and oil-rich shales include the lack oflong-term production histories, environmental concerns related to hydraulic fracturing, uncertainty in calculatinghydrocarbons-in- place, and fluctuations in supply, demand, and price.

Keywords: shale • oil- and gas-productive • depositonal processes • shale geochemistry • shale sequence stratigraphy •shale porosity and permeability • shale composition • shale geomechanics • resource shale economics • shaleseismic properties© Versita Sp. z o.o.

∗E-mail: [email protected]

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Important Geological Properties of Unconventional Resource Shales

1. Introduction

Gas- and oil-bearing shales are organically-rich, fine-grained sedimentary rocks capable of producing commer-cially important quantities of hydrocarbons upon artificialfracturing. These shales typically serve as the source,reservoir and seal of the hydrocarbons produced fromthem [1]. The recent revelation of vast global quantities ofthese potentially gas- and oil-productive shales has pavedthe way for rapid advancements in understanding their ge-ological properties, some of which impact – and may evengovern – reservoir performance. Because of shale’s differ-ent, and sometimes unique physio-chemical, stratigraphic,and production properties compared with ‘conventional’sandstones and carbonates, the adjective ‘unconventional’has been amply applied to their characterization. Al-though some characteristics – such as pore networks andgeomechanical properties – are indeed different, and newtechnologies are being developed to measure these dif-ferences, other characteristics – such as depositional pro-cesses/fabric and stratigraphic characteristics – are sim-ilar, and conventional methodologies can be applied tobetter understand shales in order to meet exploration andproduction goals. The current global shale play has beendriven largely by technological advances, most notably 3Dseismic, horizontal drilling, and artificial fracturing.This paper is a summary of important shale propertiesand both the advancing and traditional knowledge thathas been gained as a direct result of shale’s economicimportance. It is based mainly upon research conductedin the University of Oklahoma’s Institute of ReservoirCharacterization on a variety of shales, including Bar-nett (Texas, USA, Caney (Oklahoma, USA), Eagle Ford(Texas, USA), Fayetteville (Arkansas, USA), Haynesville(Texas/Louisiana, USA), Horn River (British Colombia,Canada), LaLuna (Colombia), Longmaxei (China), Marcel-lus (Appalachian Basin, eastern USA), Monterey (Califor-nia, USA), and Woodford (Oklahoma, USA) shales.

2. Shale Depositional Processes

Recent studies of sedimentary features of shales haverefuted the long-held generalization that shales are theproduct of deposition in quiet water environments as‘hemipelagic rain.’ Many shales exhibit mm/cm-scalecross- and parallel-laminations, scour surfaces, particlealignment parallel to bedding planes, and burrows [2–7] (Figure 1). Some shales reveal a systematic fining-upward or coarsening-upward, followed by fining-upwardgrain-size pattern [8] while others display a system-atic stacking pattern of lithofacies that indicate tempo-

Figure 1. Sedimentary features of Barnett Shale. A. Scannedcore showing parallel- and graded-laminations. B. Thinsection photomicrograph of a graded, spiculite mudstonefrom lamination shown in A. C. Laminations within coredinterval. Gray = massive mudstone; Orange = rhyth-mic silty claystone; Red = ripple/low angle laminatedmudstone; Blue = graded mustone; Black = claystone;Green=spiculitic mudstone [7]. D. Basal micro-scour sur-face (yellow arrows) in mudstone. E. Scanned thin sec-tion photograph showing low-angle cross lamination (yel-low arrows). Published with the permission of Society ofExploration Geophysicists, who’s permission is requiredfor further publication use.

ral changes in water depths, energy levels, and/or de-gree of bottom-water oxygenation [9, 10]. From these andother studies, a list of potential transport, deposition, andreworking processes include (in addition to hemipelagicrain): (1) hyperpycnal flows [5, 8, 11, 12], (2) turbid-ity current flows, (3) tempestites (storm deposits) andwave-reworked deposits [6]; and (4) contourites (bottom-hugging slope, oceanic currents) [2]. In order for clay-sized particles to move along the sea floor by tractiveprocesses, as evidenced by the sedimentary structures,they must behave in a hydraulically similar manner tocoarser grains. In fine-grained sediments, this hydraulicequivalence is achieved through formation of ‘floccules’or clumps of electrostatically-charged clay particles (Fig-ure 2) [4, 13]. Laboratory-produced mud ripples formedfrom floccules [14] have provided a mechanism for trans-porting large volumes of mud to the ocean floor by hy-perpycnal (originating from rivers) and/or turbidity cur-rent (originating in the marine environment) tractive flows,rather than by hemipelagic settling [6, 12]. Tempestitesand contour currents are more apt to redistribute mudspreviously deposited in the marine environment by trac-tive processes rather than transporting them directly intoa basin.Along with the concept of hemipelagic rain in quiet watersis the corollary that environments of deposition must be

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Figure 2. A. Cartoon showing flocculated clay particles in the formof ‘domains’ [4]. B. Freeze-dried, flocculated Georgia clayin salt water. C. Floccules in Pleistocene varved clay,Great Salt Lake, Utah. D. Floccules in Barnett Shale. E.Floccules in Woodford Shale. F. Floccules in Eagle FordShale. Scales are shown on each figure. Published withthe permission of Society of Exploration Geophysicists,who’s permission is required for further publication use.

‘deep;’ this is supported by the fact that many shales areenriched in organic matter, indicating an anoxic environ-ment of deposition [15]. However, anoxic waters can occurat shallow water depths, and extensive mud deposition canoccur in shallow-marine mud banks [16].

3. Shale Composition and Fabric(Anisotropy)The major mineral constituents of organic-rich shales areclay minerals, quartz (detrital), calcite, and dolomite (Fig-ure 3), although not all minerals may be present in anyone shale. For example, the Haynesville and Eagle FordShales are enriched in calcite, whereas the Barnett andWoodford Shales are rich in clays and quartz. Lesscommon sedimentary minerals include feldspar, apatite,pyrite, and hydrothermal minerals (sphalerite, barite, etc.),the latter of which occur in the Barnett and Horn RiverShales. These minerals are mainly clay-size (<4 µm).Some shales, such as the Woodford, exhibit a fissility andothers, like the Montney (British Colombia, Canada), aresilty.Organic constituents include (1) organic-walled spores(Tasmanites); (2) plant remains (in Mesozoic and youngershales); (3) biogenic quartz from sponge spicules, radio-larians, and within spores; (4) biogenic calcite from coc-cospheres, ammonites, mollusks, and fish, (5) thin-walledgastropods and brachiopods; and (6) arenaceous, as wellas calcareous, foraminifera (Figure 4).Both inorganic and organic constituents affect well-log

Figure 3. One half foot (0.3 m) spaced, core X-ray diffraction miner-alogy compared with mineralogy from the ECSTM (Elec-tron Capture Spectroscopy) log for a 35 ft (12 m) longcored interval of the Barnett Shale. Core description isfrom [9]. Static and dynamic FMITM images are on theright side columns. Note the overall similarity in mineral-ogy from the core- and log-based analyses, and the finer-scale stratification (beds and laminae) shown by the imagelog than by the core or mineralogy descriptions. Publishedwith the permission of Society of Exploration Geophysi-cists, who’s permission is required for further publicationuse.

Figure 4. A. Ruptured and compressed Tasmanites-cyst organicwall (black outline) in a clay lamination; diagenetic quartzoccurs within the cyst in the curls of the S shape. Wood-ford Shale [7]. B. – C. Elongate and cross sectional viewof quartz sponge spicules; interior of the spicule in C isfilled with clay. Barnett Shale. D. – E. Cross sectional andelongate views of hollow coccospheres and spines. EagleFord Shale. F. Globigerina Orbulina (?) with some diage-netic calcite partially filling the interior of the foraminifera.Eagle Ford Shale. G. Arenaceous Foraminifera, BarnettShale [9]. Scales are provided for each picture. Figure 4B,4C: Published with the permission of American Associa-tion of Petroleum Geologists, who’s permission is requiredfor further publication use.

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response. For example, shales enriched in organic matterand clay minerals exhibit a relatively high gamma-ray APIlog response, whereas those enriched in quartz and/or car-bonates generally exhibit a relatively low response. Someshales though, like the Haynesville, have both high gammaray and high carbonate contents.

4. Shale Porosity and PermeabilityThe storage and migration of hydrocarbon moleculesthrough shales is complex, slow and not fully understood,owing to the small pore size and capillary properties. It isfor this reason that almost all shales require artificial frac-turing to obtain commercial flow rates. Peak flow rates inhorizontal wells often occur within the first month or two,after which flow decreases rapidly and remains low, butconsistent, for several years [17, 18].Obtaining accurate and reproducible shale matrix-porosity and -permeability measurements by standardtechniques is difficult and debateable. Recent studies uti-lizing Field Emission Scanning Electron Microscopy (FE-SEM) coupled with incremental, argon(Ar)-ion milling ofshale surfaces has revealed significant ‘organo-porosity’within kerogen (Figure 5) [15, 19] This porosity is gen-erated during the organic-maturation process that accom-panies burial and hydrocarbon generation [1]. Organo-porosity is by no means the only porosity within shales,nor is Ar-ion milling the only way to image pores inshales. [13] have identified the following pore types usingFESEM and standard SEM techniques [4] porous floc-cules which appear similar to laboratory-induced floccules(Figures 2A – F), (2) porous fecal pellets, with as much as15% micro-porosity, (3) fossil fragments such as Tasminitesspores (Figure 4A), sponge spicules whose original, hol-low central chambers may be partially or completely pre-served after burial (Figures 1B, 4B, 4C), coccospheres andtheir spines, who’s chambers are also hollow and oftenopen (Figures 4D, 4E), and foraminifera with open cham-bers (Figure 4F) (4) mineral grains such as pyrite fram-boids (Figure 5B); (5) microchannels within shale matrixwhich probably are either micro-burrows and/or boundingsurfaces of scours or micro-sedimentary structures (Fig-ures 1D, 1E); and (6) fractures which occur at micron andlarger scales (Figure 5D) [13]. Some of these pore types– such as floccules which are common in many shales(Figure 2) [4, 13] – are probably at least as important asorgano-porosity in storing and providing migration path-ways for hydrocarbon molecules. In-place and migratingoil droplets before and after hydrous pyrolysis treatmenthave been documented for the Woodford Shale, Horn RiverShale, Eagle Ford Shale and Monterey Formation (Fig-ure 6) [20].

Figure 5. A. – B. FESEM images of Ar-ion milled surface of SilurianLongmaxei Shale, China, showing pores within interpar-ticle organic matter. C. FESEM image of Ar-ion milledsurface of Longmaxei Shale showing the internal pyritecrystals within two pyrite framboids. Organic matter withnanopores occurs between crystals. D. FESEM image ofmineral surfaces of Woodford Shale. Note the parallelismof fractures that developed when tensile stress was ap-plied to rock. Figures A.-C. from [47]. Published with thepermission of American Association of Petroleum Geolo-gists, whose permission is required for further publicationuse.

Figure 6. A-B. SEM images of oil droplets produced from the Wood-ford Shale during hydrous pyrolysis experiments wheresamples were heated to 350◦C for three to four days. Re-published with permission of the Gulf Coast Associationof Geological Societies (GCAGS), who’s permission is re-quired for further publication use A. Oil droplet emergingfrom pore in matrix after three days. B. Oil droplet in mi-crofracture after four days. C. Oil droplets squeezing outof two places in a shale and into a diatom frustule after hy-drous pyrolysis. Monterey Formation [20]. D. Coalescedoil droplets within diatom spines after hydrous pyrolysis,Monterey Formation. E. Oil within coccolith chamber af-ter hydrous pyrolysis, Eagle Ford Shale. F. Oil droplet inshale matrix (not generated by hydrous pyrolysis) by whitearrow, Horn River Shale. All surfaces were broken per-pendicular to bedding. Figure 6A: Published with the per-mission of American Association of Petroleum Geologists,whose permission is required for further publication use.

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5. Geochemistry

Conventional geochemical characterization of resourceshales includes assessment of the rock’s organic richness(i.e., total organic carbon – TOC), quality (e.g. visual kero-gen analysis, hydrogen index – HI), and maturity (e.g.,Tmax, vitrinite reflectance, etc.) to estimate quantity andtype of generated hydrocarbons. From ROCK-EVAL anal-ysis, prolific gas-shale systems are usually characterizedby high organic richness (usually > 3% TOC) and HI val-ues >350 mg HC/gm of rock. TOC values generally followthe same trend as gamma-ray log response, with higherTOC rocks exhibiting a higher API gamma-ray count. Ofthe various common visual kerogen types (Types I-IV),many of the shales contain Type II kerogen (oil prone)or Type II/III (oil/gas prone) kerogen. Organic maturity asmeasured by vitrinite reflectance (Ro) is usually 0.6-0.9%Ro for shale oil and >1.1% Ro for shale gas. Thickness oforganic-rich strata is quite variable, but generally > 200 ft(65 m); thicker rocks have reduced expulsion efficienciesso that more hydrocarbons are retained during initial gen-eration, thus preserving TOC for deeper and later burialmaturation and generation.Geochemical biomarkers are very useful indicators of oxicor anoxic bottom water conditions of mud depositional en-vironments. Steranes can be used to differentiate marinefrom terrestrial organic source material. The presenceof Gammacerene in sediments indicates elevated salin-ity [21]. Eukaryotic biomarkers within the extractable por-tion of shales are indicators of paleoenvironments. Forexample, the upper, relatively more quartz-rich part of aWoodford Shale core contains higher concentrations of eu-karyotic biomarkers such as C29 steranes than occurs inthe lower, more clay- and organic-rich part of the core,implying oxygenated waters in the former and anoxic wa-ters in the lower part (Figure 7). As another example,[22] suggested that variations in the pristane/phytane ra-tio (Pr/Ph) and C13-C20 regular isoprenoids measured inBarnett Shale core extracts are associated with changesin redox conditions as well as variations in terrigenous in-put during deposition. Molybdenum (Mo) content has alsobeen considered a proxy for an anoxic environment [23].TOC and ROCK-EVAL analyses are also used for deter-mining parameters such as: (1) amount of extractable or-ganic material in the source rock, generally derived fromkerogen breakdown (S1 peak on a gas chromatogram), and(2) residual kerogen (S2 peak). The S1+S2 peaks nor-malized to TOC content of analyzed samples provide theparameter named remaining hydrocarbon potential (RHP)by [24]. Within stratigraphic intervals that have a simi-lar burial history and are not widely separated strati-graphically, changes in S1 and S2 reflect changes in the

Figure 7. Geochemical biomarker trends in the Woodford Shalefrom a behind-outcrop cored well in a quarry [47].The trends are of different biomarker ratios (AIR =(C13-C17)/(C18-C22) 2,3,6-trimethyl substituted aryl iso-prenoids). The upper Woodford is relatively quartz- richand biomarkers indicate an oxic environment of depo-sition. The middle Woodford is clay- and organic-richand biomarkers indicate an anoxic environment of depo-sition [48]. Published with the permission of American As-sociation of Petroleum Geologists, who’s permission is re-quired for further publication use.

amount of preserved organic matter. More of organic mat-ter will be preserved in the sediment and the S2 peak willbe larger under anoxic conditions than under oxic condi-tions, where less TOC is preserved and the S2 peak issmaller. Thus, the calculated RHP value [(S1 + S2/TOC)]will be greater for sediment deposited under anoxic con-ditions than for sediment deposited under oxic conditions.[24] interpreted an interval which becomes increasinglymore organic-rich (increasing RHP) from its base to itstop as representing deposition during marine transgres-sion and an interval with a decrease in RHP from thebase, upward, as representing deposition during marineregression. For the Barnett Shale, systematic sratigraphicfluctuations of intervals of low RHP (approximately 1.3-1.5) and high RHP (1.6-2.2) correspond with [9]’s relativesea-level curve, derived from independent interpretationof lithofacies stacking patterns (Figure 8). Those inter-vals with a relatively high RHP tend to be organic-rich(Figure 8). [25] has established a similar relationship forthe Woodford Shale.A relatively recent geochemical parameter – termed ‘iso-topic reversal’ – offers the potential to detect the bestproducing areas in shale-gas plays [26]. In mature shales,it has been postulated that hydrocarbons generated dur-ing the first stages of oil and gas generation are relativelydepleted in 13C isotope compared to the original isotopiccomposition of the kerogen. The early-generated hydro-carbons that are retained in the source rock after expulsionare cracked to gas at later stages of maturity, contributing12C to the gas being generated, and giving rise to the iso-topic reversal. This reversal has now been recognized in a

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Figure 8. Barnett Shale lithologic log based upon core descrip-tion [9], showing parasequences (labelled GRP1-13), in-terpreted relative sea level curve based upon lithofaciesand parasequence stacking patterns, remaining hydrocar-bon potential (RHP) curve and trends (arrows) derivedfrom organic geochemistry analysis, and zones that areenriched in TOC. GRP = gamma ray pattern; Forestb =Forestburg Limestone. Published with the permission ofAmerican Association of Petroleum Geologists, who’s per-mission is required for further publication use.

number of shales, including Barnett, Fayetteville, Wood-ford, Haynesville, Marcellus and Horn River [27]. In theBarnett Shale, for example, the isotopic data correlatepositively with gas production [28].

6. Lithofacies Stacking and Se-quence Stratigraphy

A variety of rock types and lithofacies are present in un-conventional gas shales (Figures 1, 3, 8). In many shales,they are vertically stacked in systematic patterns ratherthan randomly distributed stratigraphically [29–34]. Anupward decrease in API gamma-ray count from the baseof an interval is the most common pattern on BarnettShale gamma-ray logs; such a pattern is named a ‘parase-quence’ [35] (Figure 9). In the Barnett, a typical parase-quence consists of a basal organic-rich claystone, also richin phosphatic fecal pellets and agglutinated foraminifera(Figure 9A), followed upward by a clay-rich interval con-taining more detrital quartz (Figure 9B), which is cappedwith an interval of broken calcareous fragments of macro-fossils and well-rounded phosphatic peloids (Figure 9C).This stratigraphy is characteristic of deposition in an in-

Figure 9. Lower Barnett shale gamma-ray log showing thin sectionlithofacies of one parasequence. A. Matrix rich in phos-phatic fecal pellets, clay minerals and organic matter. B.Matrix rich in detrital quartz. C. Broken fragments of cal-careous macrofossils with well-rounded phosphatic pel-loids; D. 3D volume map of Barnett Shale stratigraphic in-tervals based upon gamma-ray log patterns in the NewarkEast Field, Texas (red = vertical uniform API response;blue = upward decrease in API response; yellow = upwardincrease in API response); E. 3D volume map of BarnettShale parasequences defined by [9] for the Newark EastField, Texas. Published with the permission of Society ofExploration Geophysicists, who’s permission is requiredfor further publication use.

creasingly shallow, oxic marine environment.Once calibrated to core description and thin-section pet-rography, the stacking of parasequences is indicative ofdeposition under fluctuating relative sea-level conditions,giving rise to a cyclic sequence-stratigraphic frameworkwhich corresponds to the RHP curves (Figure 8) and whichcan provide the basis for regional mapping subdivisions ofshale strata (Figures 9D, 9E).Even though tectonic, climatic, and related factors affectthe ultimate character of basin fill, many of the commonresource shales have a similar stratigraphy, suggesting acommon origin. Examples from the Barnett, New Albany,and Woodford Shales are provided in Figure 10, which issimilar to the stratigraphy of the Marcellus, Eagle Ford,Fayetteville, Caney, Horn River, Montney, Haynesville,Longmaxei (China), and Lewis Shales [29]. This has ledto formulation of a general sequence-stratigraphic modelfor unconventional resource shales (Figure 11). Typi-cally, the shale sequence overlies a regional unconfor-mity (SB) (and/or transgressive surface of erosion; TSE)and consists of a basal organic- and clay-rich, high APIgamma-ray interval, followed upward by a general trendof lower-API strata. The lower-API strata comprise aseries of either higher frequency sequences or parase-quences, often with a thinner, basal high-API gamma-rayshale (Figure 9). Although the scarcity of high-frequency,

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Figure 10. A. Seismic reflection profile of Woodford Shale show-ing interpreted downlap patterns (arrows)indicative of re-gressive/highstand systems tract, downlapping onto ahorizontal reflector above the Hunton unconformity [49].B. Well log cross section of the New Albany Shale show-ing downlap patterns of four high-frequency sequences(bounded by sequence boundaries-sb) [34]. C. Well logcross section of the Barnett Shale showing downlap pat-terns of regressive/highstand systems tract onto organic-rich, basal condensed section (CS) which overlies theEllenburger/Viola Limestone. Published with the permis-sion of Society of Exploration Geophysicists, who’s per-mission is required for further publication use.

age-datable fossils in Paleozoic shales precludes estab-lishing an absolute age-datable, high-resolution chronos-tratigraphic framework, cyclicity at two scales has beendocumented for the Barnett Shale (Figure 8), composite2nd- and 3rd-order cyclicity has been documented for theJurassic Haynesville and Cretaceous Eagle Ford Shales,and composite 3rd and 4th order cyclicity has been doc-umented for the Cretaceous Lewis Shale (summarizedin [29]). The similarity in dual stratigraphic cyclicitybetween non-datable Paleozoic shales and age-datableMesozoic shales suggests that they all share a recognize-able, common, and predictable composite, eustatic, depo-sitional cyclicity.

7. Geomechanics and Brittle-Ductile CoupletsThe common geological characteristics of shales influencetheir geomechanical properties and thus well drilling andcompletions. Of particular interest and importance is theability to predict the relative brittleness or ductility ofrock within a stratified shale sequence. The two commonmeasures of rock strength and deformation are Young’s

Figure 11. Generalized sequence stratigraphic model for uncon-ventional resource shales showing transgressive sys-tems tract (TST) overlying and onlapping onto a com-bined falling stage sequence boundary (SB)/early ris-ing stage transgressive surface of erosion (TSE) (some-times named ravinement surface). The upper partof the TST is the condensed section (CS) which iscapped by the maximum flooding surface (mfs). High-stand/Regressive sytems tract (HST/RST) downlap ontothe mfs. This sequence is applicable at different scalesof eustatic sea level cyclicity. A type gamma-ray log re-sponse is shown in inset A; note that it is likely that thethickness between the mfs and SB/TSE would increasein a seaward direction. Inset B shows the various posi-tions of the components of the model in relation to theirtiming of formation during a relative sea level cycle.

Modulus and Poisson’s Ratio (Figure 12). Young’s modu-lus is a measure of the amount of strain or deformation ofa rock by an applied stress or force (Figures 12B, 12C).Poisson’s Ratio is a measure of the change in shape (de-gree of deformation) of a rock to an applied stress or force(Figures 12B, 12C). A brittle rock is one that deforms elas-tically as stress is applied, then breaks (ruptures) withoutbeing plastically deformed (Figure 12A). A ductile rock isone that undergoes plastic deformation before breakage(rupture) at a given stress (Figure 12A).Another popular measure of a rock’s breakage character-istics is the ‘brittleness index,’ which is a parameter basedupon mineralogy and TOC content (Figure 13) [1, 36]. Theassumption behind the brittleness index is that quartz-(and sometimes dolomite- and/or calcite-) rich rocks willbe more brittle than clay- and organic-rich rocks. How-ever, quartz comes in many forms (e.g., biogenic, detrital,diagenetic) which are not differentiated by standard min-eralogic techniques (i.e., XRD or FTIR), but which havedifferent effects on a rock’s ability to break.Geomechanical and mineralogical properties are related(Figure 13). Rocks with a relatively large numerical valueof Poisson’s ratio and small Young’s modulus tend to havea low brittleness index and are thus ductile. Rocks witha small Poisson’s ratio and a large Young’s modulus tendto have a higher brittleness index and are thus relativelybrittle.

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Figure 12. A. Stress-stain diagram showing the behavior of brit-tle and ductile rocks due to application of compressivestress. B. Initial dimensions of a block of rock andchanges in these dimensions upon application of stress.C. Equations for Young’s modulus (E) and Poisson’s ra-tio (Pr). Symbols are given in the figures.

Figure 13. Plot of Young’s modulus and Poisson’s ratio comparedwith Brittleness Index (BI). Equation for brittleness indexis shown. Rocks with relatively small Young’s modulusand large Poisson’s Ratio have a low brittleness index(are ductile) and those with large Young’s modulus andsmall Poisson’s ratio have a high Brittleness index (arebrittle) [36]. Published with the permission of HoustonGeological Society, who’s permission is required for fur-ther publication use.

Recent stratigraphic-geomechanical studies indicate fab-ric (degree of lamination or anisotropy) also plays a signif-icant role in rock strength and its ability to break [37, 38].Shales are often finely bedded or laminated at a scalethat is only easily observeable with a borehole-image log(Figure 3). Laboratory tensile strength measurements in-dicate that core-plug-sized samples of laminated shale

Figure 14. A. Scanned core showing laminated facies. Tensilestrength is 7.1 MPa when applied parallel to lamina-tions and 12.6 MPa when applied perpendicular to lam-inations [37]; B. Thin section photomicrograph of spi-culite mudstone lamination overlain by clay-rich lamina-tion. C. Microseismic events between an injector andmonitor well, spaced 1500 ft (500 m) apart in the Bar-nett Shale. Interval GRP-1 contains 154 beds with anaverage thickness of 0.4 ft (0.13 m). Interval GRP-2contains 175 beds with an average thickness of 0.2 ft(0.7 m). There are many more microseismic events as-sociated with the more thinly laminated GRP-2 than withthe more thickly laminated GRP-1; D. Interbedded brittlechert and ductile shale within a Woodford Shale outcrop.This scale of ductile-brittle stratification is referred to inthe text as bedset scale. Tensile fractures are commonin the brittle chert beds and a few shear fractures arepresent in the ductile beds [50]. Published with the per-mission of Society of Exploration Geophysicists, who’spermission is required for further publication use.

break more easily when stress is applied parallel to theorientation of the laminae and with more difficulty whenstress is applied perpendicular to that orientation (Fig-ures 14A, 14B). The same principle is applicable at thelarger scale; for example, a greater number of microseis-mic events occur within a stratigraphic interval comprisedof thin beds than occur within an interval comprised ofthicker beds (Figure 14C). The implication of this find-ing is that rocks will break differently depending uponwhether a well is drilled perpendicular or parallel to theorientation of laminae or beds (i.e., horizontal vs. struc-turally dipping beds).Irrespective of the degree of lamination, brittle rocks tendto break cleanly under an applied stress while ductilerocks significantly deform prior to breaking under ap-plied stress (Figure 12). A common feature of interbed-ded strata seen in many outcrops (not just shales) is thattectonically-produced vertical fractures extend throughbrittle rocks, but not through interbedded ductile shales(Figure 14D). Applying these observations to a subsurfacewell allows speculation that the initial energy associated

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Figure 15. Barnett Shale cored well showing core description, coregamma-scan, 14 gamma-ray parasequences (GRP 1-14), and three scales of brittle-ductile couplets(modifiedfrom [38]. Porosity values of different lithofacies areshown in the inset. Published with the permission of So-ciety of Exploration Geophysicists, who’s permission isrequired for further publication use.

Figure 16. Seismic characteristics of Barnett Shale from a 3D seis-mic survey in North Texas [40]. Gamma-ray parase-quences from a cored well and their stratigraphic posi-tion on a vertical seismic line are shown along with themapped surfaces of the different stratigraphic units in the3D seismic area. Labelled seismic horizons have notbeen flattened to any datum. Published with the permis-sion of American Association of Petroleum Geologists,who’s permission is required for further publication use.

with artificial fracturing may send fractures through an en-tire interbedded rock sequence so that proppant flows intoall the interbeds, but when the fracture energy dissipates,the ductile rocks may deform and close around the prop-pant, resulting in vertically discontinuous fractures [39].Combining sequence stratigraphy with geomechanicalproperties allows interpretation of ductile-brittle couplets

at at least three stratigraphic scales (Figure 15) [38]. The“Sequence Scale” comprises the entire stratigraphic in-terval, with the ductile component being the basal, trans-gressive, organic-rich shale (i.e. ‘condensed section’)and the relatively brittle component being the overly-ing highstand/regressive systems tract (Figures 11, 15).The ‘Parasequence Scale” comprises either higher-ordersequences or parasequences within the Sequence Scalesystems tracts. The “Bedset Scale” comprises interbedsof ductile and brittle rocks within the parasequences. Afourth scale of minerals such as clays, calcite or quartzcomprising a lamination (Figure 5D) is also possible.

8. Seismic ReflectionConventional seismic-reflection methodologies are ca-pable of detecting Sequence-Scale and sometimesParasequence-Scale ductile-brittle couplets when theyare of sufficient thickness and of sufficient variability inacoustic properties to be resolved (Figure 16) [40]. How-ever, it is generally not possible with conventional seismicreflection to detect lithologic variability within a particularparasequence nor of thin interbeds of strata at the bedsetscale. However, more sophisticated seismic-reflection pro-cessing and manipulation, such as seismic inversion andseismic-attribute analysis [41] are routinely being usedto improve imaging and interpretation of various shale-strata properties. Nevertheless, the geological knowledgethat strata at the Parasequence Scale are composed of aspecific ductile-brittle stacking pattern provides an indi-rect indicator for detecting these couplets from seismic-reflection records. This seismic indicator can be used toguide horizontal wells into strata optimal for artificial frac-turing and production.

9. Economic and societal consider-ations of gas- and oil-bearing shales

9.1. History of shale reservoir development

Consideration of shale as a reservoir for direct productionhas led to a new paradigm in global energy resource de-velopment. This paradigm shift blossomed with the onsetof unconventional gas production from the Barnett Shaleof North Texas, U.S.A. Although the Barnett has producedgas from vertical wells for more than 30 years, it wasMitchell Energy that first attempted horizontal drillingin the Barnett, and though not initially very successful,the technology evolved rapidly and led to dramatic in-creases in production. The acquisition of Mitchell Energy

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by Devon Energy led to expansion of technologies such ashorizontal drilling, so that by 2010, 95% of Barnett wellswere horizontal. Over its history, more than 14,000 wellshave been drilled in the Barnett. It is often consideredthe ‘standard’ for gas shale development and for under-standing the geologic and technical aspects of gas (andliquids-rich) shales. However, as has been noted above,not all shales have the same properties nor productionbehavior as the Barnett Shale, so Barnett should not beconsidered a ‘global analog’.Success of the Barnett Shale play led to a rush of explo-ration and development over the last few years in the U.S.and globally, and gas shale is now considered the ‘game-changer’ for North America’s energy future. The discov-ered and potentially recoverable natural gas in NorthAmerica is now considered to represent 100 years of con-sumption at current rates according to many authorities.According to one such authority, Daniel Yergin, “This issimply the most significant energy innovation so far thiscentury. As recently as 2007 it was widely thought thatnatural gas was in tight supply in the U.S., and the U.S.was going to become a growing importer of gas. But thisoutlook has been turned on its head by the shale gale.”

9.2. 2011 shale plays and economics

At present, about 60 potentially economic gas shale playshave been identified in North America. Although statisticson reserve potential vary among energy economists, un-conventional shale gas reservoirs in the U.S. are estimatedto exceed 500 Tcf with another 200 Tcf in Canada [42].For example, the Marcellus Shale natural gas potentialis 250 Tcf and the Haynesville shale is 240 Tcf com-pared with the Barnett’s 40 Tcf. In 2010, U.S. naturalgas production from shale plays was 2.75 Tcf/year and isexpected to reach 6 Tcf by 2035. Gas shale exploration isnow global, including China, Poland, Romania, Germany,Austria, Australia, Colombia and Argentina. For example,according to [43], Europe’s total unconventional gas-in-place could be 173 Tcm (6,115 Tcf).The greater attention being paid by oil and gas companiesand government agencies to gas and liquid-rich shale hasfostered an expansion of mergers, joint ventures, and ac-quisitions. For example oil and gas transactions reached$39 billion during the second quarter of 2011 [44]. Theaverage deal value increased to $765 million for deals val-ued at more than $50 million during the 2nd quarter com-pared with an average of $672 million for the 2nd quarter2010. During the 2nd quarter of 2011 upstream transac-tions led merger and acquisition activity with 7 of the top10 deals by value being associated with shale plays; fourof those seven involved upstream assets. These 10 deals

totaled $7.5 billion, including 2 deals involving the Mar-cellus shale, totaling $2.3 billion. Even with reduced gasprices, there is strong competition amongst the larger com-panies for long-term assets of gas and liquid-rich shales.Smaller companies are becoming more aggressive as well,joint-venturing with larger international companies

9.3. A success story

There are many recently announced success stories, oneof which is described here for an oil and gas play in theWoodford Shale, which is an important gas and oil shale inOklahoma, U.S.A. A 2005 study estimated oil- in- place at130 BB and gas in place at 600 BCF. A leading companyin the play, which has been actively exploring and devel-oping the play for a number of years, recently reported anextension from their active horizontal play by offsettinga well that has been flowing 4.2 MMcfd (1,350 Btu gasand 110 bopd) since May, 2011 from an initial flow rateof 5.4 MMcfd and 160 bopd. The well’s rich gas broughta realized price of $6.25 MMcf compared with Nymexposted price of $3.95 [44]. The well was completed in10 stages over 4,200 ft.(1,400 m) lateral distance at aTVD of 15,000 ft (5,000 m). The completion extends theplay a further 15,000 net acres over a 25 mile distanceaway from the active drilling area. The company has av-eraged 4,032 beopd in the 2nd quarter 2011, 50% higherthan in the 1st quarter!. Drilling times have been reducedto 40 days, which is 43% faster than the 2010 average.

9.4. Risks and uncertainties in shale explo-ration and development

Like any other investment venture, there are also risksand uncertainties associated with gas- and oil-rich shales.Richard Nehring, a well-known energy economist, hasraised some caution concerning economic evaluations ofshale plays [45]. Of particular note is the lack of long termproduction rates for shales other than the Barnett and per-haps the Woodford. [17] provides a good example of thisfor the Woodford Shale; below $6/MCF gas (Henry HubSpot price), most Woodford wells are non-economic. Notall shales are the same, so production rates for the Barnettthat are used for comparison with other shale plays, pro-vide a high degree of uncertainty. Most of the other shaleplays have only 2-4 years of production history, and allthat can be ascertained is that the peak flow rate comesquickly after production begins. Nehring also notes thatthere are wide ranges in estimated EUR, which sometimesare ignored by companies using mean values and conven-tional parameters for calculating gas- and oil-in –place.Environmental concerns have been growing proportional

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to shale gas production, particularly in heavily populatedareas of the U.S.. Hydraulic fracturing requires a largevolume of surface or well water, the use of chemicals ofpoorly advertised composition, produces flowback water,and according to some, may effect ground water supplies.Also, because hydraulic fracturing requires a large surfacearea to hold all of the equipment, a negative ‘footprint’ lefton the ground surface which in addition to being unsitely,can affect indigenous fauna and flora populations. Thisimpediment has taken the forefront particularly with theshale activity in the heavily populated northeast US andhas led two states and one Canadian province to place amoratorium on hydraulic fracturing, with many more statesand the federal government crafting and debating new reg-ulations. To diminish the regulatory environment, some ofthe measures being tested by companies include usingsubsurface aquifers as a water source and other poroussubsurface formations for storage of flowback water, treat-ing and recycling flowback water that reaches the groundsurface, and reducing the chemicals required in the fracingprocess. Most knowledgeable individuals in the oil andgas industry would acknowledge the fact that gas wellsare generally drilled and produced well beneath the shal-low subsurface where potable water supplies occur, butthis fact has not prevented considerable debate on thepossible toxicity to drinking water supplies in areas offracing. In this regard, better and continual education ofgovernment and the general public by the oil and gas in-dustry is a necessity, which is just now being realized bythe industry.

Another impdediment to gas shales is that because of theartificial fracturing technique, peak gas production occurswithin the first half year of production. However, this istypically offset by a long term low, but consistent flowrate. Also, companies now routinely “re-frac” a well afterthe first fracture job.

A significant technical and economic risk is calculationof gas- (or oil-) in place. Standard techniques used inconventional reservoirs are not appropriate for the fine-grained, ductile shales. Pore spaces are very small (of-ten in the nanometer size range) and not connected ex-cept perhaps at the nano-scale. Laboratory measurementsof porosity and permeability by commercial entities havecome under fire recently for providing mixed results, andhas led to the “we must agree to disagree” philosophy andto some companies building their own internal analyticalfacilities. The complexity of pore networks in shales hasonly recently been divulged as being complex and dif-ficult to accurately measure [13, 19]. Also, there is notcurrent agreement on where free and adsorbed gas andoil molecules reside within a shale’s pore network. With-out an understanding of these factors and without reliable

data, it is not possible to accurately and reproducibly de-termine an in-place hydrocarbon estimate for managementand development planning.Perhaps the largest impediment to continued, stablegrowth of gas shale development is the commercial priceof natural gas. When prices were high in the early 2000’s,there was considerable exploration and development, re-sulting in part to an oversupply of gas, which led to areduction in price, and then associated reduction in ex-ploration and development. The current low gas prices,coupled with a rise in oil prices, in turn led to companiesheavily invested in shale gas exploration to divert to ex-ploration for liquids-rich shale, with some early successes.There are several oil-rich shales that are amenable to pro-duction, such as the Monterey Shale in California, whichhas been producing oil for more than 100 years. The Mon-terey is considered to be the source for 37BBO in Cal-ifornia’s conventional hydrocarbon accumulations of thestate’s estimated total resource of 500BBO [45].

10. Concluding RemarksNew results of shale studies are being released throughpublication and presentation at a very fast pace as a re-sult of the recognition and popularization of their vastpotential as a source of clean energy. Although thereare real and perceived environmental, political, technicaland social risks associated with exploration and develop-ment of shale resources, it is likely that they will becomean important, long-term part of the global energy mix.The generalities outlined in this paper will undoubtedlybe refined as research and applications continue into thefuture. Of particular importance is the need to integratevarious technical disciplines and expertise in order to max-imize the knowledge base to enhance resource develop-ment. The sooner this is accomplished, the smaller will bethe cycle time from exploration to discovery to long-termexploitation of globally plentiful resource shales.

AcknowledgementsSponsorship for part of this research from a consortiumof companies (Anadarko, QEP, Black Diamond, Exxon-Mobil, Chesepeake, Newfield, Nexen, and SouthwesternEnergy) is greatly appreciated, as is the dedicated the-sis research of a number of graduate students at Univer-sity of Oklahoma’s School of Geology and Geophysics.Other collaborators, who are greatfully acknowledged in-clude Drs. Neal O’Brien (State University of New York atPotsdam, Younane Abousleiman (University of Oklahoma’s

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Poromechanics Institute), Omar Abou-Elresh (Suez Uni-versity, Egypt), Eric Eslinger (The College of Saint Rose,New York), Paul Philp (University of Oklahoma School ofGeology and Geophysics) and Dennis Eberly (U.S. Geo-logical Survey, Colorado).

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Documents

Important geological properties of unconventional resource shales