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SHALE GAS – AN OVERVIEW

By Tristan Euzen IFP Technologies (Canada) Inc.

PREAMBLE

In the fast evolving landscape of unconventional resources, shale gas has been the topic of intense research and development activities in North America as well as huge investments from independent and major oil & gas companies over the past few years. As a North American company focused on franco-canadian technological cooperation, IFP Canada needs to understand the technological challenges associated with shale gas exploration and development. The aim of this report is to provide IFP Canada with a comprehensive review of geological as well as “above the ground” factors that control shale gas prospectivity and productivity. The material used to build this report consists in hundreds of technical and more general papers, as well as attendance to specialized sessions of oil and gas conferences, symposiums and short courses. A large part of this material has been compiled in a digital format (pdf) and sorted by topics and areas (basin or play). After an introduction presenting the general context of the recent development of the North American shale gas industry, the first part focuses on the geological factors that control the gas shale prospectivity and productivity. This chapter discusses the impact, variations and measurement techniques of each of these parameters. The second part focuses on external factors which relate to our ability to technically and economically extract these resources. It includes completion and stimulation methods as well as economical, regulatory and environmental aspects of the shale gas industry.


SUMMARY

PREAMBLE 2

SUMMARY 3

LIST OF FIGURES 5

INTRODUCTION 8

DEFINITION OF UNCONVENTIONAL RESOURCES 8

DEFINITION OF GAS SHALE AND SHALE GAS 9

A BRIEF HISTORY OF GAS SHALE DEVELOPMENT 10

GEOLOGICAL CONTROLS ON GAS SHALE PRODUCTIVITY 12

ORGANIC MATTER CONTENT 12

CONTROLS ON ORGANIC MATTER ACCUMULATION 12

VARIABILITY OF TOTAL ORGANIC CARBON (TOC) IN SHALE PLAYS 13

TOC MEASUREMENT AND ESTIMATION TECHNIQUES 16

IMPACT OF TOC ON GAS SHALE PROSPECTIVITY 17

THERMAL MATURITY 18

VARIABILITY OF SOURCE ROCK MATURITY IN SHALE PLAYS 18

IMPACT OF MATURITY ON GAS SHALE PROSPECTIVITY 19

QUANTIFICATION OF SHALE THERMAL MATURITY 20

MINERALOGY 20

CONTROLS ON MINERALOGY IN SHALE 20

VARIABLITY OF THE MINERALOGY OF SHALE PLAYS 21

IMPACT OF MINERALOGY ON GAS SHALE PROSPECTIVITY 22

QUANTIFICATION OF SHALE MINERALOGY 22

PORE SYSTEM 23

CONTROLS ON PORE SYSTEM IN SHALE 23

PORE SYSTEM VARIABILITY IN SHALES 24

QUANTIFICATION OF POROSITY IN SHALE 27

GAS ADSORPTION 28

CONTROLS ON GAS ADSORPTION 29

MEASUREMENT OF ADSORBED GAS 30

IMPACT OF GAS ADSORPTION ON SHALE PROSPECTIVITY 31

PERMEABILITY AND DIFFUSIVITY 32

IMPLICATION FOR FLUID FLOW MODELING AND PERMEABILITY MEASUREMENT 33


GEOMECHANICS 35

ROCK MECHANICAL PROPERTIES 35

IN SITU STRESS 38

EXTERNAL CONTROLS ON GAS SHALE PRODUCTIVITY AND DEVELOPMENT 41

WELL AND STIMULATION DESIGN 41

MULTISTAGE HYDRAULIC FRACTURING 41

GEOSTEERING AND COMPLETION DESIGN 42

FRACTURING JOB DESIGN 44

MONITORING AND ASSESMENT OF HYDRAULIC FRACTURING 48

SHALE GAS PRODUCTIVITY AND RESOURCE ASSESSMENT 51

SHALE GAS PRODUCTIVITY 51

SHALE GAS RESOURCES AND PRODUCTION FORECAST 52

SHALE GAS ECONOMICS 57

SHALE GAS BREAKEVEN PRICE 57

SHALE GAS OPERATORS STRATEGIES 58

IMPACT OF FUTURE GAS DEMAND ON SHALE GAS DEVELOPMENT 59

ENVIRONMENTAL IMPACT AND REGULATION OF SHALE GAS DEVELOPMENT 62

SURFACE AND DRINKING WATER CONTAMINATIONS. 62

WATER RESOURCES 66

SURFACE NUISANCES 68

SEISMIC RISKS 70

CONCLUSION: THE ROLE OF SHALE GAS IN THE FUTURE ENERGY MIX 73

REFERENCES 75


LIST OF FIGURES

Figure 1: Different types of unconventional plays. Figure 2: General classification of (a) oil and (b) gas resources based on reservoir and fluid properties. Figure 3: Increases in production and well count in the Barnett shale from 1990 to 2010. Figure 4: Estimation of technically recoverable shale gas resources in the world. Figure 5: Location map of North American shale gas plays. Figure 6: Controls on organic matter accumulation in sediments. Figure 7: Time chart of the main North American shale gas plays. Figure 8: Paleogeographic maps and location of the main organic rich shale basin systems in North America. Figure 9: Range of TOC of most of the productive and some of the prospective shale gas plays of North America. Figure 10: a) positive correlation between TOC and micropore volume in Devonian-Mississipian Canadian shales. b) Relationship between TOC and sorbed gas capacity in Devonian-Mississipian and Jurassic Canadian shales. Figure 11: Range of maturity (Vitrinite reflectance) of most of the productive and some of the prospective shale gas plays of North America Figure 12: Processes leading to the formation of thermogenic gas. Figure 13: Relative proportion of quartz, clay and carbonate in various shale play in North America. Figure 14: Influence of mineralogy on shale porosity. Figure 15: Size of pore throat and particles in sandstones and shale. Figure 16: Pore types and sizes observed in gas shale reservoirs. Figure 17: Main types of porosity in shales. Figure 18: Porosity range of various North American shale plays. Figure 19: Schematic illustration of gas adsorption. Figure 20: Langmuir isotherm. Figure 21: Relation between TOC and methane sorption capacity in Western Canadian shale at 5 MPa and 30⁰C. Figure 22: Adsorption isotherm of the Barnett shale (composite) at two different temperatures. Figure 23: Examples of the contribution of adsorbed gas to total gas in place in several shale gas plays. Figure 24: Comparison of gas flow in micropores where the flow is no-slip and in nanopores where the flow is slip. Figure 25: Different length scale of pore network and gas flow in shale. Figure 26: Stress and orientation dependency of pulse decay permeability to He measured on core plugs from various shale plays. Figure 27: Scale dependency of permeability measured on crushed samples with various particle sizes. Figure 28: Definition of Poisson’s ratio. Figure 29: Definition of Young Modulus


Figure 30: Brittleness percentage expressed as a function of Young modulus and Poisson’s ratio. Figure 30: Triaxial compression apparatus. Figure 31: Comparison between brittleness calculated from mineralogy and from full wavefrom sonic suite. Figure 32: Visualization of Young modulus and differential horizontal stress ratio (a measure of stress anisotropy) derived from 3D seismic of the Colorado shale in Central Alberta. Figure 33: Complete stress equation implemented into GOHFER software. Figure 34: Influence of stress regime on stress anisotropy and magnitude. Figure 34: impact of natural fractures on the propagation of hydraulic fractures in the Barnett shale. Figure 35: Natural gas chimneys in Marcellus shale. Figure 36: Illustration of how horizontal multistage fracturing help draining gas from shale matrix. Figure 37: Average EUR and EUR per frac stage in the Woodford shale. Figure 38: Horizontal well case study in the Woodford shale. Figure 39: Eagle Ford well completion example showing the optimization of stage and cluster placement based on brittleness (RQF) and stress log data. Figure 40: Relationship between fluid type, reservoir properties and hydraulic fracture geometry. Figure 41: Average stimulation data for various US shale plays. Figure 42: Fracturing fluid additives, main compounds and common uses. Figure 43: McGuire-Sikora folds-of-Increase curves for pseudo-steady flow. Figure 44: HyWay channel fracturing technology. Figure 45: Microseismic map and cross-section and pumping chart of a 8 stages hydraulic fracturing in a Barnett well. Figure 46: Simulation of the interaction between natural and hydraulic fractures. Figure 47: Annual gas production from US shale plays during the last decade. Figure 48: Shale versus non-shale U.S. Gas production over time. Figure 49: Average production curves of core areas of 5 US shale plays (Baihly et al 2010b). Dashed lines are decline curve analysis forecast. Figure 50: Fayetteville Shale averaged daily production rate per well in mcf/d as a function of date of first production. Figure 51: Different type of resources and their definition. Figure 52: Example of uncertainty in reserve estimate based on hyperbolic exponent b Figure 53: Rate transient analysis of a well from the Barnett shale Figure 54: Breakeven price based on basic economic analysis of core areas of major US shale gas plays. Figure 55: Comparison of dry gas and liquid rich well economics in Eagle Ford shale. Figure 56: Eagle Ford leasing movement into oil window Figure 57: North American shale gas production forecasts Figure 58: Key stages of hydraulic fracturing water lifecycle and potential contamination risks associated.


Figure 59: Target shale depth and base of treatable groundwater in selected shale plays. Figure 60: Produced water management by shale gas basin. Figure 61: Water treatment technologies. Figure 62: Estimated water needs for drilling and fracturing wells in selected shale gas plays. Figure 63: Water use by sector in producing area of major shale plays. Figure 64: Pounds of air pollutants produced per billion of Btu of energy. Figure 65: EPA natural gas environmental impact assessment and regulation timeline. Figure 66: Comparison of the magnitude different microseismic events and felt earthquake. Figure 67: Map showing location of earthquakes, producing Barnett shale gas wells and water disposal wells.


INTRODUCTION

As North American conventional hydrocarbon accumulations become increasingly mature, the oil and gas industry has been recently switching towards unconventional resources, for renewing reserves and securing long term production and supply. In the recent years, spikes in oil and gas prices and increasing US dependency on foreign oil and gas import have also put pressure on the industry towards the exploration and development of unconventional oil and gas resources.

DEFINITION OF UNCONVENTIONAL RESOURCES

The term “unconventional” has been used by the industry for a wide range of play types (Fig. 1) and it is worth giving a broad definition, in order to put in perspective these different types of unconventional resources. The most general definition is probably the one proposed by Dave Russum from AJM Petroleum Consultants, because it takes into account both reservoir and fluid properties (Fig. 2, Russum 2010). On one end of the spectrum lie the conventional resources, which correspond to light crude oil and sweet natural gas trapped into porous and permeable reservoirs. These resources can be produced at a relatively low cost because hydrocarbons flow out of the reservoir by natural depletion and no expensive upgrading processing is required. On the other hand, when the reservoir or the fluid properties, or both deteriorate, it becomes necessary to apply specific technologies to extract and/or to upgrade these resources. The application of these technologies comes at an increasing financial and environmental risk, which makes unconventional resources more challenging to develop.

Figure 1: Different types of unconventional plays (modified after IFPEN 2010)


DEFINITION OF GAS SHALE AND SHALE GAS

In conventional plays, hydrocarbon accumulations depend upon three separate components, a source rock, a reservoir and a trap. These components have to combine within in a specific space and time framework for a hydrocarbon accumulation to form. On the other hand, a gas shale is a source rock holding a significant amount of residual gas that has not been expelled. As a consequence, gas shale is a source, a reservoir and a trap at the same time. In other words, it refers to a gas-charged, self-sourced, fine-grained

-rich (Total Organic Carbon or TOC >0.5) reservoir. The term shale gas more commonly used in the literature refers to the gas contained in the gas shale. Shale gas resources are less concentrated but more widespread than conventional gas resources. Shale is the most widespread sedimentary rock on earth and commonly formed thick accumulations in the vast majority of sedimentary basins. The primary key parameters for assessing the prospectivity of shale are the initial content of organic matter (TOC) and the thermal maturity. Biogenic shale gas also exist, in which case maturity is not an issue, but they only account for a minor contribution to North American shale gas production to date (Antrim shale).


Figure 2: General classification of (a) oil and (b) gas resources based on reservoir and fluid properties (Russum, 2010).

A BRIEF HISTORY OF GAS SHALE DEVELOPMENT

Shale gas has been produced as early as 1821, from a natural seepage in fractured Devonian shale in the Appalachian Mountains (Selley, 2011). Since then, shale gas has been produced throughout the Appalachians, although produced volumes were marginal. During the 1980’s and 1990’s, a combination of tax incentives, advances in technologies, operational efficiency, as well as improving understanding of the production mechanisms, led to the progressive and slow development of several shale plays throughout the United States, notably the Ohio, Antrim, New Albany and Barnett shales. Mitchell Energy & Development Co. started producing gas from the Barnett shale in the early 1980’s, but the production really started to ramp up by the end of the 1990’s, when they started implementing horizontal drilling combined with multi-stage hydraulic fracturing (Fig. 3).

Figure 3: Increases in production and well count in the Barnett shale from 1990 to 2010 (Newell 2010) Additionally, the use of slickwater (water plus chemical additives) as fracturing fluid from 1997, further increased productivity while decreasing the well cost. The Barnett shale production has been growing consistently in the 2000’s and this success spurred the


interest of the oil and gas industry. In the recent years, new and potentially promising shale gas plays started to emerge in US, Canada, and around the world, where estimation of the technically recoverable shale gas resources keep growing consistently (Fig. 4).

Figure 4: Estimation of technically recoverable shale gas resources in the world (Energy Information Administration 2011a). Russia and Middle East are not included. A location map of North American Shale gas and oil plays is published and regularly updated by the U.S. Energy Information Administration (Fig. 5).

Figure 5: Location map of North American shale gas plays (EIA, May 2011)..


GEOLOGICAL CONTROLS ON GAS SHALE PRODUCTIVITY

In this chapter, I will explore the numerous geological factors that control the productivity of gas shale. These intrinsic factors include organic matter content, thermal maturity, thickness, mineralogy, porosity, permeability, mechanical properties, natural fractures, pressure, temperature, stress regime, adsorbed and free gas content as well as gas composition.

ORGANIC MATTER CONTENT

A gas shale is by definition a source rock and the presence of organic matter is a prerequisite of hydrocarbon generation. Some plays are however described as hybrids because they contain organic rich shale intervals interbedded with gas charged silty layers. This is the case of the Montney formation in Western Canada, which contains a gradation of facies ranging from coastal sand to offshore shale and fine grained turbidites. In any case, the deposition and preservation of organic matter in the sediments is a key element of the formation of gas shale.

CONTROLS ON ORGANIC MATTER ACCUMULATION

Organic-rich deposits form by the accumulation and preservation of organisms in the sediments. The nature and proportions of organic precursors depends on the depositional setting, and result in different types of kerogen. Type I kerogen mainly forms in lacustrine environment from algae and cynobacterias, type II kerogen forms in marine environment dominated by planctonic organisms, and type III kerogen is derived from plant in continental environment. Each type of kerogen contains different proportions of carbon, hydrogen and oxygen, that ultimately control the transformation potential of the kerogen and the type of hydrocarbon generated through thermal maturation. Most of the currently producing and prospective gas shale plays in North America are overmature oil-prone source rocks (kerogene types I and II; Passey et al 2010). Three major interacting processes control the richness in organic matter of sediments: production, dilution and preservation (Fig. 6). The primary controls on organic production are solar energy, nutrients and water. However, most of the produced organic matter is consumed by other organisms or oxidized while settling through the water column or in the upper decimeters of the sediment column. Anoxic conditions as well as sufficiently high burial rates favor the preservation of organic matter by minimizing destruction processes. Dilution by clastic and/or biogenic material reduces the organic matter concentration in the sediments. All these processes are interdependent and vary through space and time in relation with the sequence stratigraphy. For these reasons, the total organic carbon (TOC) of shales is highly variable both laterally and vertically at local and regional scale. An understanding of tectonic and stratigraphic controls on shale deposition helps to better predict spatial variations of TOC in shale.


Figure 6: Controls on organic matter accumulation in sediments Accumulation of organic matter is more likely to occur over geological periods of high relative sea-level and in restricted basins with high burial rates (Kendall et al 2009). A large part of the prospective shale gas plays identified in North America occurs over three broad geological periods, in three basin systems (Fig. 7 & 8):

- The Appalachian foreland basin during Middle/Upper Devonian times (Marcellus, Ohio, New Albany,

Antrim).

- The Ouachita system during the Late Devonian/Mississipian time in the Southern United States (Woodford,

Barnett, Fayetteville).

- The Western Interior Seaway during the Upper Cretaceous in the Western United States and Western

Canada (Lewis, Mancos, Eagle Ford, Colorado).

Some of the North American shale gas plays however, formed over other geological periods and/or basins (Ordovician Utica, Devonian Horn River and Duvernay, Triassic Montney, Jurassic Haynesville).

VARIABILITY OF TOTAL ORGANIC CARBON (TOC) IN SHALE PLAYS

Total organic carbon of shale plays varies from less than 1% to over 20% by weight. These variations are due to the depositional controls mentioned above as well as thermal maturity (see next section on thermal maturity). Thermal maturation results in a progressive decrease of the TOC of the shale as hydrocarbon forms. For example, low maturity Barnett shale outcrop samples may have TOC as high as 13%, whereas producing mature Barnett shale in the core area, have a TOC range of 2-5% (Pollastro et al, 2007). This dual control on TOC (depositional and diagenetic) makes it difficult to compare


averages and ranges of TOC of different plays from the literature, because data may come from areas with different maturity. Keeping in mind this potential pitfall, Figure 9 illustrates the range of TOC of most of the productive and some of the prospective shale gas plays of North America.

Figure 7: Time chart of the main North American shale gas plays.


Figure 8: Paleogeographic maps (Scotese, 2000) and location of the main organic rich shale basin systems in North America.


Figure 9: Range of TOC of most of the productive and some of the prospective shale gas plays of North America. Sources: Marois 2011, Smith and Leon 2010, Bustin, 2010, Spencer et al, 2011, Ross and Bustin, 2008, Javrie et al 2005, Mukhopadhyay, 2008, NEB, 2009, Dawson 2000, Hettinger and Roberts, 2005.

TOC MEASUREMENT AND ESTIMATION TECHNIQUES

Analytical techniques such as the Rock Eval developed at IFPEN (IFP Energies nouvelles, Espitalié et al 1985) or Leco TOC are routinely used in the industry for measuring total organic carbon (TOC) from core and cuttings. It is worth noting that measurement on cuttings tends to underestimate the TOC, due to a dilution effect associated with caving (Jarvie et al, 2005). Numerous techniques for estimating TOC from well log data has been proposed in the literature (See Sondergeld et al 2010 for a review). Each method has to be calibrated on rock measurement to account for variations in lithology and maturity. A method popularized by Passey et al (1990) uses a scaled porosity-resistivity logs overlay technique. Another method using theoretical relationship between the presence of organic matter and the sonic and resistivity log responses has been developed at IFPEN (Carpentier et al 1991).


IMPACT OF TOC ON GAS SHALE PROSPECTIVITY

There are three ways by which organic matter content impacts gas shale prospectivity. At least 0.5% by weight of organic matter has to be present originally in the sediment in order to generate significant amounts of hydrocarbons (Cardott 2006, Talukdar 2009). Thermal maturation also creates porosity through structural transformation of organic matter and generation of hydrocarbons (Fig. 10a). Recent advances in high resolution imaging evidenced that organic matter contains most of the gas filled porosity in some if not most of the shale plays (Loucks et al 2009, Passey et al 2010). Finally, organic matter may also contribute extensively to the adsorption capacity of shale (Fig. 10b).

Figure 10: a) Positive correlation between TOC and micropore volume in Devonian-Mississipian Canadian shales (Ross and Bustin 2007). b) Relationship between TOC and sorbed gas capacity in Devonian-Mississipian and Jurassic Canadian shales (Ross and Bustin 2007).


THERMAL MATURITY

Thermal maturation processes and the type and initial content of organic matter ultimately control the nature, amount and composition of hydrocarbons generated from organic-rich shales. Consequently, mapping the variation of maturity within a shale gas play is paramount for defining prospective core areas. Before the recent gas glut and resulting fall in gas price in North America, companies were chasing overmature shales in the dry gas window, trying to avoid relative permeability issues due to liquids associated with gas. Since then, the sustained high oil to gas price differential has driven the industry to focus on the liquid rich part of shale plays and on shale oil plays because of better economics.

VARIABILITY OF SOURCE ROCK MATURITY IN SHALE PLAYS

Numerous North American shale plays formed in relatively narrow highly subsident basins, resulting in significant spatial variability of maximum burial depth and thermal maturity across the play. Figure 11 illustrates the range of maturity (vitrinite reflectance) of most of the productive and some of the prospective shale gas plays in North America.

Figure 11: Range of maturity (vitrinite reflectance) of most of the productive and some of the prospective shale gas plays of North America. Sources: Marois 2011, Smith and Leon 2010, Gilman and Robinson 2011, Bustin 2010, Montgomery et al 2005, Haas 2008, Beaton et al 2010, Spencer et al 2011, Ross and Bustin 2008, Javrie et al 2005,


Mukhopadhyay 2008, NEB 2009, Dawson 2000, Hettinger and Roberts 2005, Vassilellis et al 2010, Reed and Ruppel 2010, Talukdar 2008. Among the plays shown in Fig. 11, Antrim and Colorado shales are immature and mainly contain biogenic gas, whereas Haynesville and Muskwa shales are overmature and only contain thermogenic dry gas. In all the other shale plays, thermal maturity varies widely leading to variable proportion and composition of gas and liquids across the play.

IMPACT OF MATURITY ON GAS SHALE PROSPECTIVITY

Thermal maturation is a primary control on the proportion and composition of gas and liquids generated in shale during burial. As temperature increases, gas form by decomposition of kerogen, then by decomposition of bitumen and finally through secondary cracking of retained oil (Fig. 12, Jarvie et al 2007a). Highly mature systems tend to have much higher initial gas flow rates than low maturity systems because of gas charge and storage mechanisms (Jarvie et al 2007b). Thermal maturation increases the porosity associated with the structural transformation and conversion of organic matter (Milner et al, 2010). At low to medium thermal maturity, adsorption of hydrocarbons on organic matter may significantly contribute to oil retention and subsequent secondary cracking to gas (Javrie et al 2007a). Fluid pressure building up with gas generation may also results in the formation of natural hydraulic fractures and microfractures, providing flow path for production as described in the Marcellus shale play (Engelder and Lash 2008).


Figure 12: Processes leading to the formation of thermogenic gas (adapted from Jarvie et al 2007a)

QUANTIFICATION OF SHALE THERMAL MATURITY

The methods for estimating source rock maturity are based on organic matter petrology, experimental pyrolysis and geochemical analysis. The vitrinite reflectance method relates on the evolution of optical properties of organic matter with increasing maturity. Although widely used in the industry, a recent study suggests that this method might underestimate maturity in some shale plays (Marcellus shale, Laughrey 2008). Other less common petrographic methods include illite crystallinity, pollen translucency or conodonte transformation index (Laughrey 2008). In the pyrolysis method, a rock sample is heated and quantities of hydrocarbon expelled are measured (Rock Eval method developed at IFPEN, Espitalié et al 1985). The temperature of maximum hydrocarbon production (S2) during the experiment, Tmax, is a measure of the sample maturity. The biomarkers method relies on the evolution of the composition of organic constituents during thermal maturation, which can be measured by gas chromatography and mass spectrometry analysis (GC-MS). Another geochemical approach consists of measuring the stable isotope ratios of gas (Laughrey 2008).

MINERALOGY

Mineralogy is a primary control on the pore network structure of both conventional and unconventional reservoirs. Furthermore, the initial mineralogical composition of sediments has a strong impact on the nature and magnitude of diagenetic transformations occurring during their burial history. In gas shales, mineralogy is even more important because it impacts the mechanical properties of the rocks and how they react to hydraulic fracturing. Shale refers to sedimentary rocks made up of clay-size particles (< 4 Understanding these variations is necessary to build reliable petrophysical and geomechanical models and to optimize the placement of fracturing stages.

CONTROLS ON MINERALOGY IN SHALE

The mineralogical composition of shales is controlled by the source of clastics, mechanical and chemical weathering during erosion, transport and deposition, as well as biogenic production and diagenetic transformations. These controlling factors vary in time and space, inducing vertical and lateral changes in mineralogy both at local and regional scales. The analysis of the specific impact of all these controlling factors and their interactions is beyond the scope of this report.


VARIABLITY OF THE MINERALOGY OF SHALE PLAYS

Most shale lithofacies are a complex mixture of quartz, feldspars, clays, carbonates and accessory minerals (pyrite, apatite, hematite, anhydrite…). Carbonates as well as silica may be present in the form of fossil fragments like skeletal debris or fecal pellets. Figure 13 illustrates that the relative proportion of quartz (plus feldspars), clay and carbonates vary widely within and between plays.

Figure 13: Relative proportion of quartz, clay and carbonate in various shale play in North America. The Montney (Alberta) Clay content includes micas (Clay content < 5%). Sources: Anderson et al 2010, Passey et al 2010, Bustin 2010, Rickman et al 2008, Thériault 2008, STARR Unconventional Resources Project, Gas Research Institute 1994. Some shales have low quartz content and are clay-rich (Ohio), carbonate-rich (Second White Speck, Utica), or both (Eagle Ford, Haynesville). Other shales have relatively low carbonate content (Montney in Alberta, Devonian in Norhteast British Columbia, Mancos)


or low clay content (Montney). The Barnett and Marcellus shales show a wide range of mineralogical composition including siliceous mudstone, calacareous mudstones and clay-rich shales (Mitra et al 2010). The modal compositions presented in Fig. 13 are a compilation of published data, but probably did not capture the full range of mineralogical variability of some shale plays.

IMPACT OF MINERALOGY ON GAS SHALE PROSPECTIVITY

Mineralogy may affect shale gas prospectivity in several ways. Mineralogical variations are associated with changes in the pore network structure which impacts the porosity and flow capacity of shales. This point will be illustrated in the section related to porosity. As a general rule, porosity increases with clay (although gas-filled porosity may not) and detrital quartz contents and decreases with carbonate and biogenic quartz contents (Fig. 14, Bustin 2010). Mineralogy also impacts the shale brittleness. Clay-rich shales are more ductile and tend to deform instead of breaking under stress. On the other hand, siliceous mudstones have a more fragile behavior and tend to break more easily under stress. The presence of swelling clays (smectite) may be an issue, especially in shallow shale when water-based fracturing fluids are used. High carbonate content may also increase the risk of releasing fines when using acid treatments (Rickman et al 2009).

Figure 14: Influence of mineralogy on shale porosity (Bustin, 2010).

QUANTIFICATION OF SHALE MINERALOGY

Mineralogy can be measured or estimated from rock samples (core or cuttings) and well log data. Measurements from rock samples include optical petrography, X-Ray diffraction, chemostratigraphy (Wright et al 2010) and advanced methods combining backscattered electron imaging and energy dispersive X-ray spectroscopy (mineral mapping, Sliwinski et al 2010). Conventional and advanced well log data can be used to estimate the mineralogy. Most shales are a complex mixture of minerals and both major and accessory constituents may


have a strong impact on well log response. Consequently, it is necessary to calibrate the well log analysis on quantitative mineralogy data derived from core and/or cutting samples. The shale gas facies expert system developed by Baker Hughes uses conventional logs in conjunction with geochemical, acoustic and NMR logs to derive mineralogy as well as the petrophysical and geomechanical properties of the shale (Mitra et al 2010). Others derived the modal mineralogy by fitting simulated log response to actual log data (Eslinger and Everett 2006).

PORE SYSTEM

A pore system is defined by the volume, shape and size distribution of connected and non-connected space occupied by fluids in a reservoir rock. In conventional reservoirs, the pore size ranges from the micrometer to millimeter scale and fluids mainly occur as free phases (as opposed to adsorbed phase). In shale however, the pore size range dominantly in the tens to hundreds of nanometers (Fig. 15), where capillary bounded as well as adsorbed fluids become a significant portion of the total pore fluid volume. Therefore, understanding the pore system in shale is necessary to quantify storage and flow capacity.

Figure 15: Size of pore throat and particles in sandstones and shale (based on Nelson 2009, Passey et al 2010)

CONTROLS ON PORE SYSTEM IN SHALE


The architecture of the pore system depends on the rock texture (grain size distribution and fabric), which is controlled by depositional processes, mineralogy, diagenesis (including mechanical compaction), the type, concentration and maturity of organic matter, and presence of natural fractures. This results in the occurrence of different pore types in various proportions, ranging in scale over five orders of magnitude from nanometers to tens of micrometers.

PORE SYSTEM VARIABILITY IN SHALES

The pores in shale can be grouped according to their origin, as matrix intercrystalline, intraparticle, organic, mineral dissolution and intergranular (Fig 16, Milner et al 2010, Schieber 2010).

Figure 16: Pore types and sizes observed in gas shale reservoirs (based on Milner et al 2010) Matrix intercrystalline pores refer to the voids between clay flakes and other matrix particles. These pores tend to be more abundant in under-compacted, highly overpressured shale (Haynesville, Fig. 17-a) or in clay-rich shale (New Albany). Intraparticle pores are found within nanofossil fragments (fecal pellets, algae, Fig. 17-b) of calcareous mudstone or within framboidal pyrite (Fig. 17-c). Organic pores are the dominant gas-filled pore type in many shale gas plays (Loucks et al 2009, Milner 2010, Curtis et al 2010, Fig. 17-d). They form through the transformation of organic matter during thermal maturation. Their size is dominantly in the tens of nanometers range, but can reach several microns in highly mature shale. Carbonate dissolution pores are generally present in minor amounts (Milner et al 2010, Fig. 17-e) and are more likely to occur in carbonate rich mudstones (Schieber 2010).


Intergranular pores are associated with grain-supported silty laminae or beds within shale. These pores are orders of magnitude larger than organic matter or clay matrix pore types. There are more common in hybrid plays such as the Montney or Colorado shales (Fig. 17-f). The relative abundance of these different pore types varies between shale plays as well as within a single shale play, between the different lithotypes.


Figure 17: Main types of porosity in shales. a - Intercrystalline porosity (Haynesville, Curtis et al 2010). b - Intraparticule porosity (fecal pellet, Haynesville, Milner et al 2010). c - Intraparticle porosity in pyrite framboid (Barnett, Loucks et al 2009). d - Organic porosity (Barnett, Loucks et al 2009). e - Carbonate dissolution porosity (New Albany, Schieber


2010). f - Intergranular porosity in silt lamination (Colorado, Sliwinski et al 2010). The thick white bar on each photo corresponds to 1

QUANTIFICATION OF POROSITY IN SHALE

Estimation of porosity and more specifically of gas-filled porosity is necessary to quantify original gas in place (OGIP) in shale. Due to the very small pore size, the result of porosity measurement is very sensitive to the experimental method used and has been shown to vary significantly, even between different labs using the same method (Sondergeld et al 2010, Passey et al 2010). This is an important point because small variations of porosity value have a greater impact on OGIP estimates in low porosity rocks. Helium pycnometry on core plug tends underestimates porosity because of abundant non-connected micropores. For this reason, a method using crushed samples is most commonly used in shale (Luffel and Guirdy 1992). Mercury porosimetry on preserved (no fluid extraction) crushed sample has also been proposed as a good approximation for gas filled porosity (Olson and Grigg 2008). Several authors advocate the use of standardized lab protocols specific to shale reservoirs, in order to minimize inconsistencies between labs (Bustin et al 2008a, Sondergeld et al 2010, Passey et al 2010). A compilation of published total and gas filled porosity range of various North American gas shales is presented on Figure 18. Most thermogenic gas shales have gas filled porosity below 6%.


Figure 18: Porosity range of various North American shale plays. Sources: Marois 2011, Bustin 2010, Haas 2008, Spencer et al 2011, NEB 2009, Vassilellis et al 2010, Hayden and Pursell 2005. The presence of clay, organic matter as well as heavy minerals makes it challenging to derive shale porosity from conventional log analysis. To overcome this difficulty, it is necessary to calibrate conventional as well as advanced logging tool using mineralogical data derived from core or cuttings (Mitra et al 2010).

GAS ADSORPTION

Gas-filled porosity is a measure of free gas capacity, but free gas only account for one part of the total gas capacity of shale. Because of the small grain size and the presence of organic matter, a significant proportion of the total gas contained in some gas shale is hold as adsorbed gas. Adsorbed gas forms a denser layer on the surface of micropores (Fig. 19), and surface area of these micropores grows exponentially with decreasing pore size. Furthermore Kerogen has a high adsorptive capacity because of its very large internal surface area.


Figure 19: Schematic illustration of gas adsorption (Lewis 2011) The variation of sorption capacity of a specific rock with pressure at a given temperature is described by the Langmuir isotherm (Fig. 20). At a given pressure, there is only so much gas that can be adsorbed and when pressure decreases, adsorbed gas is progressively released as free gas into the pore system.

Figure 20: Langmuir isotherm

CONTROLS ON GAS ADSORPTION

In addition to the pore size (surface area) and pressure, the main controlling factors on shale gas sorption capacity include content and maturity of organic matter as well as temperature. Figure 21 illustrates the correlation between organic content and methane sorption capacity of shale in several formations from Western Canada (Ramos 2004). The size of the symbols increases with sample maturity. The steeper slope in higher maturity samples, as shown by the arrows, indicates a higher sorption capacity of the more mature samples.


Figure 21: Relation between TOC and methane sorption capacity in Western Canadian shale at 5 MPa and 30⁰C (modified from Ramos 2004). Gas sorption capacity decrease with increasing temperature, as illustrated for the Barnett shale on Figure 22 (Bustin 2010).

Figure 22: Adsorption isotherm of the Barnett shale (composite) at two different temperatures (modified from Bustin 2010)

MEASUREMENT OF ADSORBED GAS

The sorption capacity of shale can be measured either by desorption isotherm or by equilibrium adsorption isotherm and is expressed in standard cubic feet per ton of rock (SCF/ton). The desorption isotherm method, commonly used for CBM, consists in placing a core sample inside a sealed canister at the well site and measuring the volumes of gas evolved with decreasing pressure at reservoir temperature (Waechter et al 2004). Bustin et al (2008) suggest that the gas released from canister desorption of shale gas contains not only desorbed gas, but also free gas retained in the core due to the very low


permeability of shale. Equilibrium adsorption isotherm method overcomes this difficulty, by measuring the gas sorption capacity to methane with increasing pressure of a previously desorbed sample (Bustin et al 2008a). This method requires an accurate estimate of the moisture content, temperature and pressure of the reservoir, in order to accurately measure in situ sorption capacity.

IMPACT OF GAS ADSORPTION ON SHALE PROSPECTIVITY

The knowledge of gas sorption capacity is essential for estimating the gas in place as well as for predicting the flow characteristics of shale gas. The total gas in place is a combination of free gas, adsorbed gas and gas dissolved in oil or water (Ambrose et al 2010). Although a recent publication suggests that solubility of gas may be significantly enhanced in nanopores (Diaz-Campos et al 2010), solution gas is generally not significant in published volumetric calculation of gas in place. Adsorbed gas, on the other hand, contributes significantly to the total gas volume of most shale gas plays. The gas in place is calculated by summing the free gas derived from the measurement of the gas filled porosity (generally by helium pycnometry), to the adsorbed gas derived from the equilibrium adsorption isotherm. Ambrose et al (2010) stressed that failing to correct gas-filled porosity from the pore volume occupied by adsorbed gas lead to overestimating the total gas in place. Figure 23 illustrates the contribution of adsorbed gas to the total gas in place, calculated in examples from different shale plays. The sample from the Montney play shows relatively minor contribution of adsorbed gas, probably due to the moderate TOC (2.9%) and fairly high reservoir temperature (79⁰C). The Colorado example shows a low gas yield associated with low pressure, but has a high proportion of adsorbed gas related to high TOC (5-6%) and low reservoir temperature (21⁰C). In the example of the Besa River Upper Black Shale (Horn River Basin), there is virtually no adsorbed gas, due to high reservoir temperature (100⁰C). In the sample considered in the Barnett example, almost 40% of the gas in place is adsorbed gas. This is related to the high TOC value (6.85%) and to the fact that most of the porosity is contained in the organic matter (Loucks et al 2009). Gas desorption also have a strong impact the long term production decline of gas shale with high sorption capacity. As pressure drop with reservoir depletion, the contribution of desorbed gas is likely to increase progressively and mitigate the production decline (Cao et al 2010). Numerical simulations also suggest that desorption of gas maintains reservoir pressure for a longer period of time (Sharbo et al, 2011). This implies that plays with high gas adsorption capacity like the Barnett shale might have a flatter production decline than plays with little adsorption capacity like the Haynesville shale (high temperature and relatively low TOC). Gas desorption is also likely to influence the evolution of gas composition over the life of a well, because of the different sorption affinity of gases. For instance, CO2 has a much higher sorption affinity to kerogen than methane. The consequence is that the proportion of CO2 in desorbed gas (and thus in production) might increase over time (Bustin 2010).


Figure 23: Examples of the contribution of adsorbed gas to total gas in place in several shale gas plays (note the different unit used for GIP between top and bottom diagrams). Source: Bustin 2010, Ross and Bustin 2008 and Jarvie et al 2005.

PERMEABILITY AND DIFFUSIVITY

Gas flow in shale occurs at various scales, from nanopores in kerogen, through larger pore and natural fractures where present, to propped hydraulic fractures. This results in a complex interaction of different flow processes that cannot be fully described using a simple Darcy flow model. Permeability is inherently associated in Darcy’s law as the proportionality constant that relates flow rate and fluid viscosity to the pressure gradient applied to a porous media. Darcy’s law relates to laminar flow and is only valid in a domain where interactions between fluid molecules and pore walls are negligible, as in macropores of conventional reservoirs (Figure 24a, Javadpour et al 2007). In shale however, fluid flow occurring in nanopores is governed by slip flow and diffusion, where gas molecules slip on the surface of pores and collide with the wall and other gas molecules (Figure 24b, Javadpour 2009).


Figure 24: Comparison of gas flow (a) in micropores where the flow is no-slip and (b) in nanopores where the flow is slip (Javadpour 2007).

IMPLICATION FOR FLUID FLOW MODELING AND PERMEABILITY MEASUREMENT

Non-Darcy flow processes as well as desorption have to be taken into account in lab analytical models and in fluid flow simulations of shale gas. Notions of apparent diffusion coefficient (Cui et al 2009) or apparent permeability (Javadpour 2009) have been introduced in fluid flow equations, in order to take into account non-Darcy flow processes. Unlike Darcy permeability, these coefficients are not only a property of the porous media, but also depend on properties of flowing gas at specified pressure and temperature (known as the Klinkenberg effect). Cui et al (2009) suggest that a triple porosity model may be necessary in fluid flow simulation of shale gas, in order to take into account micropore, macropore and natural fractures. Shabro et al 2011 combined diffusion, darcy flow and desorption in a single model to simulate gas flow in shale. Finally, flow simulators have also to take into account turbulent flow within hydraulic fractures. Figure 25 summarizes the different length scales involved in shale gas flow.

Figure 25: Different length scale of pore network and gas flow in shale (based on Javadpour et al 2007).


Considering the variety of processes and scales involved in the flow of gas in shale, it is important to understand (1) the scale dependency of permeability measurement and (2) the significance of a measured permeability value in relation to non-darcy flow processes. Standard methods used for measuring permeability of shale are Pulsed-decay techniques applied to core plug or to cuttings (Luffel 1993, Egermann et al 2005). The advantage of using core plug is that measurement can be performed at in situ confining stress, accounting for stress dependency of permeability (Fig. 26a). However, pulse-decay permeability from core plugs may be strongly influenced by sample anisotropy, like microfractures or bedding (Fig. 26b). In such cases, several measurements on orientated core plugs may be required. Luffel (1993) suggested that permeability measurement on core may be dominated by bedding-parallel fractures induced by coring but not present in the reservoir.

Figure 26: Stress (a) and orientation (b) dependency of pulse decay permeability to He measured on core plugs from various shale plays (Bustin et al 2008a). Permeability measurements on crushed samples are more representative of true matrix permeability because microfractures and bedding planes are eliminated. However, even crushed samples show a scale dependency as measured permeability decreases with particle size. This is consistent with a dual pore system, with macropores and micropores (Fig. 27, Cui et al 2009).

Figure 27: Scale dependency of permeability measured on crushed samples with various particle sizes (Cui et al 2010).


Permeability measurement on crushed sample cannot be performed at reservoir confining stress. However, Cui et al (2009) argue that this permeability is contributed by micorpores likely insensitive to stress. Even if this is true, the effect of pressure and temperature on flowing gas properties has still to be considered. Finally, as transport properties in nanopores are specific to individual gases, permeability measured with helium or nitrogen may not be applicable to methane. Cui et al (2009) suggest that permeability or diffusivity should be measured using reservoir fluids (i.e. methane) and corrected from adsorption effects.

GEOMECHANICS

Due to very low permeability, shale gas cannot be produced economically without horizontal drilling and multi-stage hydraulic fracturing. Geomechanics is paramount for optimizing drilling, completion and stimulation of gas shale. The main controls on gas shale fraccability are (1) the rock mechanical properties, (2) in situ stress and (3) density and orientation of natural fractures.

ROCK MECHANICAL PROPERTIES

The two elastic moduli commonly used by the industry to quantify shale brittleness are Poisson’s ratio and Young Modulus. Poisson’s ratio is the ratio of transverse strain over axial strain (Figure 28). The lower the Poisson’s ratio, the more brittle is the rock. As illustrated on Figure 28, sandstone has lower Poisson’s ratio and thus is more brittle than shale.

Figure 28: Definition of Poisson’s ratio.


Young modulus is the ratio of stress over strain (Fig. 29). The higher the Young modulus the more stress required for a given amount of strain. Sandstone has higher Young modulus and thus is stiffer than shale.

Figure 29: Definition of Young Modulus Rickman et al (2008) quantified brittleness from the arithmetic mean of normalized values of Young modulus (maximum value equal 100%) and Poisson’s ratio (minimum value equal 100%, Fig. 30).

Figure 30: Brittleness percentage expressed as a function of Young modulus and Poisson’s ratio (Rickmane et al 2008). The reason why shale brittleness is so important is because it has a direct impact on the geometry of the fracture network generated by hydraulic fracturing. the objective of hydraulic fracturing is to maximize the surface area of the fracture network in contact with the low permeability matrix of shale.


Elastic properties can be quantified from direct measurement in the lab, from well log data, from mineralogy and from seismic data. Static Poisson’s ratio and Young modulus can be measured in the lab by triaxial compression test on core sample (Fig.30).

Figure 30: Triaxial compression apparatus (Bustin 2010). This method measures static properties, as opposed to dynamic properties. Dynamic elastic properties are derived from compression velocity, shear velocity and density logs (Mullen et al 2007). Due to the strong impact of mineralogy on rock mechanical properties, a brittleness index has also been defined as the ratio Quartz over Quartz + Carbonates + Clays (Sondergeld et al 2010). Figure 31 shows a good agreement between method based on mineralogy and method based on elastic moduli derived from full waveform sonic suit.

Figure 31: Comparison (Track 6) between brittleness calculated from mineralogy (Track 4) and from full wavefrom sonic suite (Track 10, Sondergeld et al 2010, Rickman et al 2008).


In the absence of dipole sonic logs (providing shear velocity), Mullen et al (2007) proposed a composite rock property model (CRPM) in which they derived rock mechanical properties from conventional logs using multiple petrophysical relationships and neural network methods. Rock elastic properties as well as in situ stresses can also be quantified using seismic inversion methods (Paddock 2009, Gray et al 2010). Gray et al (2010) present an application on 3D seismic of Colorado shale in Central Alberta, where they use seismic anisotropy to visualize Young modulus together with differential horizontal stress ratio (Fig. 32). This visualization aims at identifying areas where stimulation will produce fracture networks, aligned fractures and their direction and where it is likely to fail.

Figure 32: Visualization of Young modulus and differential horizontal stress ratio (a measure of stress anisotropy) derived from 3D seismic of the Colorado shale in Central Alberta (Gray et al 2010).

IN SITU STRESS

In stimulation treatment, fracture growth is controlled by stress profile which depends on rock elastic properties, lithostatic pressure (vertical stress), tectonic stress and pore pressure. Closure pressure is the minimum pressure theoretically necessary for opening fractures in the reservoir (equivalent to minimum horizontal stress). It is an important parameter for designing hydraulic fracturing. In practice, breakdown pressure is higher than closure pressure because of the friction losses during the fracturing fluid injection


(Crain 2010). In Figure 33, closure pressure (Pc) is expressed in the complete stress equation implemented in the fracture simulator GOHFER (Barree 2009a).

Figure 33: Complete stress equation implemented into GOHFER software (Barree 2009a) Stress distribution controls fracture orientation and height (vertical containment) and determines the fluid pressure required to open a fracture during the fracturing job (Barree 2009a). In an isotropic media, fracture will always open in the direction of the minimum principal stress and propagate in the direction of maximum or intermediate principal stresses. The magnitude of the minimum horizontal stress (equivalent to the closure pressure) will control the fluid pressure required to open fractures. Closure pressure increases with increasing pore pressure and fractures tend to grow into areas of depletion (all else being equal). The magnitude and orientation of the tectonic stress depends on the present stress regime. Figure 34 shows the influence of the stress regime on stress anisotropy in three different shale plays (Moos and Dell’Angello 2011). In the Barnett shale, pure normal faulting regime induces limited stress anisotropy and breakdown pressure varies only slightly with azimuth. In the Marcellus shale, strike slip stress regime induces higher stress anisotropy. In the Montney shale, strike slip / reverse stress regime results in the highest stress anisotropy and well orientation will have a strong impact on wellbore stability and hydraulic fracturing.


Figure 34: Influence of stress regime on stress anisotropy and magnitude (Moos and Dell’Angello 2011). Stereo plot is lower hemisphere and color scale is proportional to fracture breakdown pressure. Shales are heterogeneous rocks that contain plans of weakness like bedding planes and natural fractures, which have a strong impact on hydraulic fracture growth. Figure 34 illustrates how induced hydraulic fractures grow parallel to the maximum horizontal stress and are diverted by the reactivation of natural fractures (Gale et al 2007). In this specific example of the Barnett shale, Gale et al (2007) propose that the fracture reactivation is due to the weak contact between whole rock and calcite cement along the natural fracture faces (as confirmed by broken fracture surfaces on cores, Fig. 34b).


Figure 34: impact of natural facture on the propagation of hydraulic fractures in the Barnett shale (modified from Gale et al 2007) At the time of the gas generation in the Marcellus shale, the stress field controlled the formation of natural hydraulic fractures due to overpressure (Engelder and Lash 2008). Today these fracture are still perpendicular to minimum horizontal stress are thus prone to be reactivated by hydraulic fraccing (Fig. 35).

Figure 35: Natural gas chimneys in Marcellus shale (Engelder and Lash 2008)

EXTERNAL CONTROLS ON GAS SHALE PRODUCTIVITY AND DEVELOPMENT

External controls on shale gas productivity relate to technological as well as economical, environmental and regulatory requirements that make shale gas a viable and sustainable resource. Although the presence of gas in shale has been known for many years, it didn’t make sense to even estimate these resources until the combination of horizontal drilling and multistage hydraulic fracturing made it technically recoverable. It is only after two decades of experimentation and development in the Barnett shale that the shale gas wave started growing with the emersion of several promising shale play in North America, and now around the world.

WELL AND STIMULATION DESIGN

MULTISTAGE HYDRAULIC FRACTURING

Due to the extremely low permeability of shale (micro to nanodarcy), gas molecules move very slowly in shale matrix and a conventional vertical well can only access very limited gas reserve at low production rate. The objective of horizontal multistage hydraulic fracturing is to increase as much as possible the contact surface between the well bore and the shale matrix (Fig. 36).


Figure 36: Illustration of how horizontal multistage fracturing helps draining gas from shale matrix (images from Bustin et al 2008b and Regal Energy website). Hydraulic fracturing consists in pumping water, proppant and chemicals at high pressure down the wellbore. The objective of hydraulic fracturing is to create the most widespread and complex fracture network as possible, while staying in the targeted zone. In a perfectly homogeneous shale gas play (which we know is far from reality), drilling a longer horizontal leg and increasing the number of fracturing stages should increase the well productivity and the estimated ultimate recovery (EUR). Gilman and Robinson (2010) showed that it is exactly what is happening in the Woodford shale on an average EUR per frac stage basis (Fig 37a). However, there is a very large variability of well productivity for any given number of frac stage, clearly indicating that numerous other factors impact stimulation performance (Fig. 37b).

Figure 37: Average EUR and EUR per frac stage in the Woodford shale (Gilman and Robinson 2010).

GEOSTEERING AND COMPLETION DESIGN


Not only production from neighboring wells may differ significantly, but even in a single well individual frac stages may perform differently, as demonstrated by production log or microseismic data (Baihly et al 2010a). This is primarily due to local heterogeneity which, as we have seen in the first part of this report, is controlled by many factors and occurs at different scales. That’s the reason why geosteering is very important for optimizing the design of horizontal wells. Logging while drilling (LWD) provides valuable information that can be used to steer the well bore while drilling as well as for placing the fracturing stages and designing the stimulation treatment. Baihly et al (2010a) illustrates how a better placement of 10 perforation clusters located out of the sweet spot zone might improve the gross gas revenue by $3 million on a 3 Bcf well, based on $5/Mcf gas price (Fig. 38).

Figure 38: Horizontal well case study in the Woodford shale (Baihly et al 2010a). The well was steered with conventional gamma ray only. The vertical red bars represent production log values. Clusters located outside the sweet spot zone in purple provided only minor contribution to the total production. Beside well placement, the location of fracturing stages and perforation clusters may be optimized to improve well productivity. Figure 39 illustrates the use of brittleness (in the form of Rock Failure Quotient, a function of Poisson’s ratio and Young modulus) and stress log data to optimize the placement of the fracturing stages and clusters, targeting low stress, high brittleness intervals. In this example from Eagle Ford shale, a benchmark between two wells based on production normalized by number of stages and lateral footage, indicates a 20% increase of production resulting from this optimization step (Baihly et al 2010a).


Figure 39: Eagle Ford well completion example showing the optimization of stage and cluster placement based on brittleness (RQF) and stress log data (Modified from Baihly et al 2010a). The completion methods commonly used in shale gas development are “plug and perf” method with cased and cemented hole and open-hole method with external packers and sliding sleeves . The advantage of the first method, widely used in most shale plays, is that it is possible to precisely place selective fracturing initiation point and efficiently isolate the fracturing jobs. The open-hole method on the other hand saves money and time by avoiding costly cementing process and limiting trips downhole. There is still plenty of debate in the industry regarding the advantages and drawbacks of different methods (Budd 2011, King 2010, Mason 2011, Roche 2011a).

FRACTURING JOB DESIGN

The first step of a fracturing job consists in pumping down fluid at high pressure (the “pad”) in order to create a fracture network in the reservoir rock. This first step is followed by the injecting of a proppant laden fluid (the “slurry”) to maintain the fractures opened after the end of the pumping. Designing a hydraulic fracturing job is a tradeoff between expected incremental production improvement and additional costs. It involves deciding on the number and location of fracturing stages, selecting of the fracturing fluids, proppant and additives and determining the volumes and injection rates. Figure 40 summarizes general relationship between reservoir properties (brittleness, permeability), hydraulic fracturing design (fluid type and volume, proppant concentration) and resulting fracture geometry. In clay-rich ductile shale, simple “bi-wing” fractures are more likely to occur. Unpropped fractures will most likely not be conductive and proppant embedment can also be expected. For these reasons, hydraulic fracturing design in ductile shale involves low injection rate of viscous fluid (gels) with high proppant concentration


(lower left on Fig. 40). On the other hand, complex fracture network is more likely to occur in brittle siliceous mudstone. In this case, large amount of low viscosity fracturing fluid (slick water) pumped at high rates is used to maximize fluid travel distance and stimulated reservoir volume (SRV). However, water-based fluids can carry lower proppant concentration (upper right on Fig. 40).

Figure 40: Relationship between fluid type, reservoir properties and hydraulic fracture geometry (Chong et al 2010). Between these two end-members any intermediate situation may be envisioned, as for instance using slick water (water plus friction reducer) for creating extensive fracture network and higher viscosity gel-based fluid for transporting the proppant (hybrid fluid system). Figure 41 summarizes average stimulation design for various US shale plays. King (2010) proposed a comprehensive review of fluid combinations that have been used for over thirty years in hydraulic fracturing of shale.


Figure 41: Average stimulation data for various US shale plays (Chong et al 2010). Numerous chemical additives are commonly used to optimize hydraulic fraccing treatment. These chemicals aim at minimizing friction, eliminating bacteria, reducing (breaker) or enhancing viscosity (gel, crosslinker) and preventing corrosion, oxidation or scaling. The US Department of Energy published a list of the representative major compounds used in hydraulic fracturing of gas shales (Fig. 42). slickwater fracturing fluids contain 0.5% to 2% of chemical additives with water making up 98% to 99.5% (US Departement of Energy 2009). Proppants commonly used in hydraulic fracturing include sand, resin-coated sand, low density ceramic and sintered bauxite (Lafollette 2010).


Figure 42: Fracturing fluid additives, main compounds and common uses (US Departement of Energy 2009). Critical input parameters needed for hydraulic fracturing design and reservoir models are commonly obtained by performing pre-frac injection tests, also referred to as minifrac tests. They consist in injecting water, oil or nitrogen to breakdown the formation and monitoring injection and falloff pressure variation with time. Analysis of pre-frac test can provide key parameters such as closure pressure, pipe and near-well bore friction losses, fracture geometry, fluid leakoff coefficient and formation permeability (Barree 2009b, Santo 2011). The total size of a frac job depends on the desired fracture length which is related to the maximum conductivity that can be established in the fracture compared to the flow capacity of the reservoir (Barree 2009c). This is illustrated by McGuire-Siroka curves that relate the production’s folds of increase to the relative conductivity of fracture (Fig. 43). This graph shows that fracture length has to be increased in conjunction with its relative conductivity to optimize production improvement.

Figure 43: McGuire-Sikora folds-of-Increase curves for pseudo-steady flow (Barree 2099c). Kf: fracture permeability, wf: fracture width, k: formation permeability, A: well spacing, J0: productivity index before fracture, J: productivity index after fracture, re: drainage radius, rw, well bore radius, L: fracture length. In very low permeability reservoirs (in the order of 100 nanoDary), generating a large and complex fracture network using low viscosity fluid is likely to be beneficial to the production. For higher permeability reservoirs however (0.01-1 mD), fracture conductivity in a complex network might be too low to drain efficiently the matrix (Cipolla et al 2010). Hydraulic fracturing design and technology development is a very dynamic and innovative field as shale gas producers consistently seek to lower the well costs. Simultaneous or sequential fracturing of multiple parallel wells are examples of innovative techniques taking advantage of the modification of the stress field to divert fracturing fluids and


increase the stimulated reservoir volume (King 2010). Another example of innovative technology is flow-channel fracturing developed by Schlumberger, which increase hydraulic fracture conductivity by creating “channels” in the proppant pack (Figure 44).

Figure 44: HyWay channel fracturing technology (Denney 2010)

MONITORING AND ASSESMENT OF HYDRAULIC FRACTURING

Various types of data can be used to monitor and assess hydraulic fracturing performance. These data include pumping records (pressure, rate and loading), microseismic events, tracer–marking of proppant, fluid tracer analysis of backflow fluid, recovered brine salinity, volume and ion analysis and production logging (King and Leonard 2011). During each fracturing stage, pumping pressure rate ramps-up and tends to stabilized after reaching the breakdown pressure. Variations from this idealized model like pumping pressure break or steep increase may be indicative of changes in fracture growth patterns, opening of a secondary natural fracture system, propagation of hydraulic fractures out of the target zone or screenout. Microseimic data record the position of shear fracturing event and gives indirect evidences of the shape and dimensions of the stimulated reservoir volume (SRV). However, the presence of a microseismic event does not necessarily means that a conductive fracture formed at this location and contributes to the actual flow system. Figure 45 illustrate the use of microseismic data and pumping charts for hydraulic fracturing monitoring in the Barnett shale (King 2009). In this case, the hydraulic fracturing design resulted in low complexity fracture networks (complexity index of 0.3, equal to the width divided by half-length of the microseismic event cloud), net declining pressure during the fracturing in each stage (blue curve on the charts), 20 % of the microseismic events below the zone and 500 barrels of water per day. Fluid tracers and salinity changes indicated large influx of water coming from the Ellenberger formation, below the target zone (King and Leonard 2011). Hydraulic fracturing jobs where improved in subsequent wells by reducing pumping rates and dropping sand slugs, in order to


increase fracture network complexity and keep fractures from propagating out of the zone.

Figure 45: Microseismic map and cross-section and pumping chart of a 8 stages hydraulic fracturing in a Barnett well (King 2009). An increasing number of fluid flow simulators integrate hydraulic fracturing in their workflow. Hydraulic fracture network may be generated using deterministic or stochastic approach and the model can be calibrated using microseismic and production data (Mayerhofer et al 2006, Rogers et al 2010). Other models integrate geomechanics to constraint the generation of fracture network (Barree 2009a). Figure 46 shows an example of a discret fracture network model (DFN) simulating the influence of natural fractures on the development of the hydraulic fracture network (Rogers et al 2010). The small inset represents microseismic event, also simulated from the model. Comparison of simulated microseismic events with real data allows calibrating the input parameters of the model.


Figure 46: Simulation of the interaction between natural and hydraulic fractures (Rogers et al 2010). Stimulated reservoir volume (SRV) derived from microseismic data and initial production rates (IP) are good indicators of hydraulic fracturing efficiency, but only long term production data will ultimately give the final reality check.


SHALE GAS PRODUCTIVITY AND RESOURCE ASSESSMENT

SHALE GAS PRODUCTIVITY

The production from major U.S. shale gas plays as been increasing exponentially, from virtually nothing in 2000 to more than 20% of the total US gas production in 2010 (Fig. 47, Newell 2011).

Figure 47: Annual gas production from US shale plays during the last decade (Newell 2011). While U.S. conventional gas production has been steadily decreasing since 2009, shale gas production has been more than offsetting this decline, resulting in a net increase in total gas production (Fig. 48).

Figure 48: Shale versus non-shale U.S. Gas production over time (Tertzakian 2011). Baihly et el (2010b) conducted an extensive analysis of 1957 producing horizontal wells from the core areas of 5 of the most productive US shale gas plays (Barnett, Fayetteville, Woodford, Haynesville and Eagle Ford). Average initial production rates of analyzed core areas vary between 2 and 10 millions of cubic feet per day (57.103 to 283.103 cubic meters


per day). Typical production curve shows a steep initial decline, followed by a flattening after about six months of production (Fig. 49).

Figure 49: Average production curves of core areas of 5 US shale plays (Baihly et al 2010b). Dashed lines are decline curve analysis forecast. Higher IPs of Haynesville and Eagle Ford average curves may be due to higher reservoir pressures and also possibly to the well and completion design (Baihly et al 2010b). Haynesville and Eagle Ford average production curves also show steepest decline rates in the first year, as the gas from fractures is produced more quickly and higher stress may also have a stronger impact the evolution of fracture conductivity with depletion. The Barnett shale production curve, on the other hand, shows a more gradual decline than the other shale plays. This may be due to lower stress allowing for a better preservation of the conductivity of poorly/un-propped fractures (Baihly et al 2010b) as well as to a higher contribution of gas desorption. Initial production rates and EUR also keep increasing with time due to the evolution of drilling, completion and stimulation practices. This is illustrated on Figure 50, where average production curves from the Fayetteville shale are grouped by date of first production from 2005 to 2009 (Baihly et al 2010b).

Figure 50: Fayetteville Shale averaged daily production rate per well as a function of date of first production (Baihly et al 2010).

SHALE GAS RESOURCES AND PRODUCTION FORECAST


Although there is a relative consensus on the enormous shale gas resources in place, there is more controversy about the part of these resources that are technically and economically recoverable (Fig. 51).

Figure 51: Different type of resources and their definition (Medlock and Hartley 2010). Economics of shale gas projects and the reserves of companies with large shale gas asset base strongly depend on long-term gas production forecasts and estimated ultimate recovery (EUR). The short development history of shale gas and the complex processes involved in their production make it challenging to use conventional methods for long term production forecast. The main techniques used for determining EUR in conventional reservoirs are volumetric analysis, analogy, decline curve analysis, material balance analysis, numerical simulation and rate transient analysis (Strickland et al 2011). Volumetric analysis has been extensively used to estimate the technically recoverable resources of shale gas of sedimentary basins around the world (Energy Information Administration 2011a). EIA used areal extent, thickness, other key reservoir properties and above the ground factors to estimate risked gas in place. A recovery factor was then applied to estimate technically recoverable resources (see Fig. 4). Although this approach is very useful for an initial assessment of the potential of shale gas basins, large uncertainty on recovery factor and drainage area make it difficult to apply to individual wells or group of wells at field scale. Recent estimation of undeveloped technically recoverable gas in the lower 48 states shale plays amounts to 750 Tcf (Energy Information Administration 2011b). More than 50 % of these resources (410 Tcf) come from the Marcellus shale play. EIA estimates of US shale gas technically recoverable resources are based on the area, well spacing, and average EUR in different shale plays or play areas. However, USGS recently estimated technically recoverable gas in the Marcellus shale to 84 tcf (Coleman et al 2011), down 80% from EIA estimates. This strong discrepancy relates to differing methods and dataset used for the estimates and further stressed the high uncertainty associated with volumetric analysis and EUR. Production forecast using analogues has been proven to be extremely difficult because of the large variability of well performance within and between shale plays, the large


number of variables controlling the productivity and the lack of analogues with long term production (Lee and Sidle 2010). Due to the extremely low permeability of shale, material balance calculations are difficult to apply because of prohibitive shut-in time necessary to obtain accurate reservoir pressure measurement. The increasing integration of complex processes involved in shale gas production keeps improving predictive capability of reservoir simulators (diffusion, desorption, geomechanics, etc.). However, these developments also come with an increasing need for calibration of the numerous input parameters, in order to reduce the cumulative uncertainty associated with these complex models. Furthermore, history matching and production forecast using a reservoir simulator is data and manpower intensive and often considered as impractical in the industry (Strickland et al 2011). For all the reasons mentioned above, decline curve analysis remains probably the most commonly used method for shale gas production forecasting (Baihly et al 2010b, Lee and Sidle 2010). The typical shape of shale gas production curves can be matched empirically using the hyperbolic form of Arps equation (Arps 1945). On a theoretical basis however, applying the Arps equation requires among other conditions, boundary-dominated flow to be valid. Shale gas well typically shows transient flow conditions over most of their life. Furthermore, matching shale gas production curves using hyperbolic Arps equation often requires a value of the hyperbolic exponent b greater than unity. Lee and Sidle (2010) demonstrated that the use of b>1 results in unrealistic physical conditions whereby cumulated gas production increase indefinitely with time (infinite time results in infinite production). Strickland et al (2010) suggest that high values of the hyperbolic exponent may result in overestimating reserves by a factor 2 to 3 or even more when production history is short (Fig. 52). Alternative decline curve models specific to tight gas sandstone and shale gas (Ilk et al 2008, Vadkó 2009) have recently been proposed to overcome the limitations of Arps equation (Lee and Sidle 2010).


Figure 52: Example of uncertainty in reserve estimate based on hyperbolic exponent b (Barnett Shale well, Strickland et al 2010). qg(t) is the gas production rate at time t, qgi is the initial production rate, Di is the initial decline rate and b is the hyperbolic exponent. Finally, rate transient analysis (RTA) provides an intermediate analytical approach for shale gas production forecast. This method is less data intensive than numerical simulation, but more process-based than decline curve analysis methods. RTA uses flow rate and flowing pressure data to derive reservoir parameters (permeability, fractures half-length and conductivity, skin) and gas in place within the drainage area (Fig. 53, Strickland et al 2011).


Figure 53: Rate transient analysis of a well from the Barnett shale (Strickland et al 2011). According to the rules of the Securities and Exchange Commission, reserves estimation procedures must be based on reliable technology and meet the criteria of repeatability and consistency (Lee 2009). Several authors suggested that these criteria are not met by most current methods when applied to shale gas and that shale gas reserves are generally overestimated (Lee and Sidle 2010, Bermann and Pittinger 2011).


SHALE GAS ECONOMICS

Beyond technically recoverable resource, economically recoverable gas is even more uncertain because many other “above the ground” factors are entering the equation. As opposed to resources, reserves must be economic and thus have a net present value (NPV), with an appropriate discount factor applied, greater than zero. Two recent papers in the New York Times (Urbina 2011a, 2011b) indicate that shale gas economics is currently at the center of a public debate in the United States. The main concerns regarding shale gas economics are related to persistent low gas price in North America, high full-cycle costs (including land acquisition), low production rates away from core areas of limited extension, and potentially higher than expected production decline rates.

SHALE GAS BREAKEVEN PRICE

Theoretically, economically recoverable resource depends on the cost of getting the gas from underground to the market, relative to the price of gas. Taking into account different costs involved in the production of each unit of gas, one can define a breakeven price below which production is uneconomic. Baihly et al (2010) performed a basic economic analysis on the core area of several major US shale plays based on average EUR, well cost, royalty rate and operation cost with a 10% discount factor. Figure 54 shows that given the cost assumptions used in this model, average Woodford, Haynesville and Eagle Ford shale gas wells are uneconomic at current gas price in the 4 $/mcf range. Despite their higher EUR, Haynesville and Eagle Ford average wells are not associated with the lowest breakeven prices. This is due to high well and operating costs. Barnett and Fayetteville average wells, on the other hand, have the lowest breakeven prices associated the lowest well and operating costs. These examples illustrate that minimizing costs is key in shale gas profitability. Improving drilling and completion technologies as well as optimizing development strategy and using multi-well pads contribute to reducing costs.


Figure 54: Breakeven price based on basic economic analysis of core areas of major US shale gas plays. EUR is from wells with date of first production in 2009 and discount rate is 10% (Baihly et al 2010).

SHALE GAS OPERATORS STRATEGIES

Baihly et al (2010) stressed that their economic analysis is based on average estimates of costs and that these costs can vary greatly between operators, resulting in a large impact on overall economics. Furthermore, most gas producers have also been minimizing their exposure to low gas spot price by implementing hedging strategies. However, in a context of moderate gas price forecast, new hedges are likely to be put at lower prices and producers need to find other ways to improve their returns on investment. Persistent low gas price in recent years has forced companies to focus on the liquid-rich part of shale plays. Figure 55 compares the economics of a well producing in the dry gas window to a well producing in the oil window of the Eagle Ford play (EOG corporate presentation 2010). Despite an equivalent EUR in barrels of oil equivalent, the liquid rich well has a net present value more than three times higher than the well in the dry gas window. As an example, leasing activity in Eagle Ford shale has dramatically shifted from the gas and wet gas windows in 2006 and 2007 to the oil window in 2009 and 2010 (Fig. 56, Hovey 2011).

Figure 55: Comparison of dry gas and liquid rich well economics in Eagle Ford shale (data from EOG corporate presentation 2010).


Figure 56: Eagle Ford leasing movement into oil window (Hovey 2011). Despite the low gas price environment in North America, strong drilling activity keeps feeding the gas glut, partly because companies are still fulfilling drilling requirements to maintain leases. The resulting supply/demand imbalance, amplified by economic recession, lead to a low to moderate short to medium-term gas price outlook in North America. In response to this low gas price environment, companies focus on reducing finding and development costs and by employing new business models (Prakash and Carr 2010). Shale gas producers seek additional capital by divesting non-core assets and building strategic relationships. Talisman recently generated $1.9 billion through conventional gas assets divestiture and $1.03 billion through its partnership with Sasol. Building strategic relationships and advanced contracting strategies with service companies is also a way of reducing costs in a context of high demand. Finally, gas producers and lobbyists are seeking ways to increase domestic demand and to access new markets.

IMPACT OF FUTURE GAS DEMAND ON SHALE GAS DEVELOPMENT

Increasing gas domestic demand may be achieved by raising the share of gas in electricity generation and in the transportation sector. Gas needs for power generation mainly depends on price differential with coal and on the real or expected costs of complying with restrictions of greenhouse gas emissions and other pollutants (Black and Veatch Management Consulting 2010). According to Powers (2011), natural gas prices would need to rise to approximately $6.30 per mcf before coal and natural gas trade at parity for electricity generation. Furthermore, tightening CO2 emissions rules as well as higher energy efficiency and lower cost of gas-fired plant over


coal-fired plant, are additional incentives to increase the share of gas in power generation (Roche 2011b). Compressed (CNG) and liquefied (LNG) natural gas can be used as clean alternative to gasoline or diesel. The NAT GAS Act (National Alternative Transportation to Give Americans Solutions) is a US bill proposal supported by 104 democrats and 77 republicans co-sponsors (as of April 2011), aiming at providing incentives for using natural gas in vehicles, buying natural gas vehicles (NGVs) and installing natural gas fuel pumps. In Canada, Shell is pursuing engineering and regulatory permits that would enable its Jumping Pound gas processing facility to produce LNG for heavy-duty fleet customers by 2013. Encana Natural Gas Inc. opened recently its first natural gas fleet fuelling station in the Denver-Julesburg basin of Colorado to serve the CNG fuelling needs of the company’s local fleet of field vehicles. Converting gas to diesel or jet fuel (gas to liquid or GTL technology) is another solution for using natural gas in the transportation sector. Although conversion of gas to liquid fuel is an expensive process, it can make a lot of sense if oil to gas price differential remains consistently high. Sasol, a world expert in GTL technology, acquired 50% of the Farrel Creek and Cypress A assets of Talisman Energy Inc. in the Montney play. The joint venture will conduct a feasibility project around the economic viability of a commercial GTL facility in Western Canada. Access to the market is a major challenge for Canadian Horn River and Montney shale plays. Due to higher production and transportation costs, shale gas from Western Canada cannot compete with other major shale gas plays in the US gas market (Weixel 2010). Both Canadian and US gas producers are eying towards the Asian market because gas demand is rapidly growing (even more after the Fukushima nuclear disaster) and gas price is expected to be persistently higher than in North America. Asian companies like Petronas (Malaysia), Kogas (South Korea), and Mitsubishi (Japan) are actively investing in Canadian shale gas assets. The Kitimat LNG project in British Columbia, initially designed as an LNG import terminal, has been reversed to an export facility with an expected capacity of 700 mmcf per day by 2015. A project has also been approved by the US Department of Energy for exporting up to 2200 mmcf per day of gas from the Sabine Pass terminal in Louisiana. The pace of North America shale gas development will largely depend on future finding and development costs, gas prices and access to domestic and foreign markets (Fig. 57).


Figure 57: North American shale gas production forecasts (source: Black and Veatch Management Consulting 2010)


ENVIRONMENTAL IMPACT AND REGULATION OF SHALE GAS DEVELOPMENT

Beyond economical considerations, sustainable development of the huge shale gas resources in North America and potentially in many other places around the world depends on managing environmental impact in a responsible and cost-effective way. Growing concerns have been expressed by the public, environmental organizations and government agencies about the environmental risks associated with hydraulic fracturing. Potential environmental issues related to hydraulic fracturing concern the contamination of surface and drinking water, excessive use of water resources, surface nuisances (traffic, noise, emissions) and micro-earthquakes.

SURFACE AND DRINKING WATER CONTAMINATIONS.

Contamination by fracturing fluids may potentially occurs at different stages of a well treatment, during chemicals transport and mixing, by spills or leaks of surface storage, during injection or flowback production and associated with the treatment and disposal of wastewater (Fig. 58).

Figure 58: Key stages of hydraulic fracturing water lifecycle and potential contamination risks associated (Environmental Protection Agency 2011).


A frequently expressed concern about shale gas development is the risk of migration of gas, formation water or fracturing fluid through hydraulic fractures into the shallow drinking water aquifers. A peer reviewed paper recently published by the US National Academy of Science indicates that the methane content in water wells increases to dangerous level in the vicinity of some Marcellus shale drilling sites (Osborn et al 2011). Isotopic analyses of the gas are compatible with a thermogenic origin. The study performed on 68 water wells didn’t find any evidence of contamination by fracturing or formation fluids. Most of the producing gas shale formations, with the exception of shallow New Albany and Antrim plays, are separated from aquifer water by 1000 to 3000 m of rocks (Fig. 59). It is therefore very unlikely that any hydraulic fracture could propagate or fluid could migrate through such thick packages of rock, unless specific geological hazard occurs, like conductive faults in a tectonically active area. Research and policy recommendations published by a group of researchers from the Duke University (North Carolina), advocate undertaking field and modeling studies to verify in which case such fluid migrations could occur (Jackson et al 2011). Zoback et al (2010) suggest that a more systematic use of microseismic monitoring and public dissemination of the results would increase public confidence in hydraulic fracturing.

Figure 59: Target shale depth (feet) and base of treatable groundwater in selected shale plays (Zoback et al 2010). Leaks into aquifers are more likely to occur through the wellbore near the surface, due to poorly constructed casing. In the case of hydraulic fracturing, the risk of leaks may be


enhanced relative to conventional gas wells, by the fact that fracturing fluid and proppant are injected at high pressure. The quality of cement jobs is a critical factor, because proper sealing of annular spaces with cement creates a hydraulic barrier to both vertical and horizontal fluid migrations. Specific standard and guidelines for well integrity in hydraulic fracturing operations are published by the American Petroleum Institute (API 2009), but regulatory requirements vary between states. Zoback et al (2010) suggest that cement bond log, which measure the quality of cement-casing and cement-formation bonds, should always be mandatory. For public safety as well as for industry credibility, producers, regulators and the scientific community should collaborate to undertake additional research at larger scale, including pre and post-drilling water testing. The main risk of surface contamination by fracturing and formation fluids are associated with temporary storage, transport and treatment of flowback water. Storage of flowback water in lined or even unlined evaporation pits may cause direct infiltration or contaminated runoff associated with heavy rains. Storing wastewater in steel tanks reduces these risks of contamination. In most US shale plays wastewater is primarily injected in disposal wells (Fig. 60).


Figure 60: Produced water management by shale gas basin (U.S. Department of Energy 2009). However, the very small number of licensed class II injection wells in Pennsylvania results in disposal of flowback in municipal waste water facilities. These facilities are neither sufficient nor designed to handle large volumes of highly saline water if Marcellus shale development were to increase significantly (Zoback et al 2010). Finally, the most sustainable way of managing flowback water is to recycle and reuse it for subsequent fracturing jobs. This approach minimizes both the total amount of water used and the risk of contamination by reducing disposal volumes. ALL Consulting in partnership with the Ground Water Protection Council created a project website for water treatment catalog and decision tool, where various technologies available and vendors are listed (Fig. 61).


Figure 61: Water treatment technologies (ALL Consulting website). Public disclosure of chemicals used in fracturing fluid is also an important step for a better management of potential hazard by regulatory agencies, health professionals and the public. The Ground Water Protection Council and the Interstate Oil and Gas Compact Commission designed a hydraulic fracturing chemical registry website, where detailed information on fluid composition can be found on a well by well basis (FracFocus website).

WATER RESOURCES

As of 2008, drilling and fracturing a horizontal shale gas well required on average 50,000 to 100,000 bbl (8,000 to 16,000 m3) of water (Fig. 62, U.S. Department of Energy 2009). The tendency since then has been an increase of the number of stages and a decrease of the volume of water per stage, with a net increase of the fracturing fluid volumes to 80,000 to 150,000 bbl per well (based on Fig. 41, Chong et al 2010). Although these represent large volumes of water, it is important to put these numbers in perspective, with respect to other water usages. According to the U.S. Department of Energy (2009), shale gas water use represents less than 1% of the total volume of water used in shale gas basins. Figure 63 shows water use by sector in selected producing shale gas areas (Satterfield et al 2008).


Figure 62: Estimated water needs for drilling and fracturing wells in selected shale gas plays (U.S. Department of Energy 2009).

Figure 63: Water use by sector in producing area of major shale plays (Satterfield et al 2008, CHK: Chesapeake, second-largest gas producer and most active driller of new wells in the U.S) Figure 63 shows that total amount of water as well as volumes of water used per sector are highly variable from one area to another. Based on total water used in the Barnett shale area of 11.15 billion barrels per year (Fig. 63) and on the number of horizontal wells


drilled (2500) and average water use per well in 2008 (Newell 2011, Chong et al 2010), water used for hydraulic fracturing in Barnett horizontal wells represent about 1.9% of the total water use in the area. Assuming 2500 wells per year during peak Marcellus shale activity and based on 125000 bbl of water per well (See Fig. 41), water used for hydraulic fracturing in Marcellus shale would represent less than 0.4% of the total water use in the area. The sources of water used for shale gas development include surface water bodies (rivers, lakes), ground water, private water sources, municipal water and re-used produced water. Although volumes of water used for shale gas development are small compared to the overall water consumption, it can have a negative impact, depending on local water availability and competition with other users. Consequently water resource management plans for shale gas development have to take into account local water needs, seasonal variation of surface water availability as well as opportunities for using alternative water sources (ex: Debolt water in Horn River basin, Smith 2011) and for recycling and reuse water.

SURFACE NUISANCES

Surface development (although minimized by drilling multiple wells per pad) and intense activity associated with drilling and completion of shale gas wells generate significant surface nuisances. It may include road construction, gathering infrastructure installation, traffic (truck used to transport equipment, fracturing fluid ingredient and water to the wellpad), noise and air pollutant emissions. Potential air pollutants include carbon dioxide, nitrogen and sulfur oxides, particulate matter and methane. Volatile organic compounds can also evaporate from pits (Zoback et al 2010). Monitoring and minimizing these impacts is part of a sustainable development of shale gas resources. It is well recognized that gas emits less pollutants than coal when burned (Fig. 64). However, recent publications raised concerns about methane emissions associated with shale gas development (Environmental Protection Agency 2010, Howarth et al 2011). Methane has a global warming potential (GWP) estimated at 25 times higher than Co2 on a 100-year basis (Fulton et al 2011). For assessing the relative effect of gas and coal on global warming, life cycle greenhouse gas emissions per unit of energy produced has to be quantified (including production, transportation and burning of the fossil fuel).


Figure 64: Pounds of air pollutants produced per billion of Btu of energy (Energy Information Administration 1998). Howarth et al (2011) suggest that 3.6% to 7.9% of the methane from shale gas production escapes to the atmosphere in venting and leaks. They conclude that greenhouse gas footprint of shale gas is at least 20% greater than that for coal, when expressed per quantity of energy available during combustion. However, Howarth et al (2011) conclusions are based on a very limited dataset and on basic assumptions that appears to be in contradiction with common industry practices (Barcella et al 2011). An assumption of Howarth et al (2011) is that all flowback methane is vented when, according to Barcella et al (2011), common industry practice is to flare gas contained in the flowback and to capture the gas as soon as it flows in sufficient quantity and adequate quality. Flaring gas emits CO2 but very little methane, only due to combustion efficiency under 100%. Tracking methane emissions data has recently become compulsory for oil and gas under U.S. Environment Protection Agency (EPA) mandatory reporting rules (MRR). Collecting and reporting these data will provide critical information for comparing life cycle greenhouse gas emissions from natural gas and coal. Figure 65 provides an overview of assessment and regulation by EPA of the impact of natural gas on environment (Fulton 2011).


Figure 65: EPA natural gas environmental impact assessment and regulation timeline (Fulton 2011).

SEISMIC RISKS

Concerns have also been expressed about risk of low to moderate magnitude earthquakes associated with hydraulic fracturing and wastewater disposal. It is well known that hydraulic fracturing generates underground microseismic activity and these events are commonly recorded for monitoring purpose. However, the magnitude of these microseismic events associated with minute shear displacements is typically too small to be felt in surface (Fig. 66)


Figure 66: Comparison of the magnitude different microseismic events and felt earthquake (Halliburton 2011). Note that each step in the magnitude scale corresponds to about 30 time increase of energy. There are 7 orders of magnitude between the biggest microseismic event in the Barnett shale and an earthquake that can be felt in surface (Fig. 66). Furthermore, the relatively small volumes of fluid (compared to other fluid injection activities like geothermal projects) and the short durations associated with hydraulic fracturing result in a very low risk of unwanted seismicity large enough to be detected on the surface (US Department of Energy 2011). However, injecting large volumes of fluid in the vicinity of an active fault may locally increase the pore pressure, decreasing effective stress and causing shear failure and slippage along the fault plane (US Department of Energy 2011). The risk and magnitude of earthquake increase with depth as in situ stress increases. Induced seismicity is known to be associated with activities involving deep injection of very large volumes of fluid like in geothermal projects (Majer et al 2008). In the case of shale gas development, any risk of induced seismicity is more likely to be associated with the injection of large quantities of wastewater in deep formations (Perry et al 2011). Frohlich et al (2010a) have demonstrated a direct link between a salt water disposal well and several earthquakes of magnitude between 2.5 and 3.3 in the Dallas-Fort Worth area. The disposal well and earthquakes are within 1 km from a mapped subsurface fault and earthquake epicenters are aligned along the fault direction (Fig. 67). Earthquakes appear not to be induced by hydraulic fracturing (Frohlich et al 2010b). The main risk of induced seismicity consequently relates to wastewater disposal, not to hydraulic fracturing. The risk increases with depth, tectonic stress and the proximity of faults. Frohlich et al (2010b) advocate operating dense seismograph network for monitoring small magnitude earthquakes in areas of fluid injection projects, among which wastewater injection associated with shale gas development. Beyond the benefit of monitoring and mitigating possible risks of earthquake swarms or larger earthquakes, these data may also help communicating that small earthquakes are common and harmless to the public (Frohlich et al 2010b).


Figure 67: Map showing location of earthquakes, producing Barnett shale gas wells and water disposal wells (Frohlich et al 2010a).


CONCLUSION: THE ROLE OF SHALE GAS IN THE FUTURE ENERGY MIX

There is a general consensus on the fact that organic shale hold enormous amount of gas in North America and potentially in many countries around the world. Whether these huge resources can and will be produced is however highly uncertain and depends on many factors. The development of the Barnett shale and other emerging shale plays in North America has demonstrated that horizontal drilling and multistage hydraulic fracturing make it technically possible to extract large amounts of gas from shale. Today, shale gas production accounts for more than 20% of the total US gas production. Growing amount of data and the past successes and failures of the industry have demonstrated that shale characteristics are highly variable, both between and within plays. Moreover, the prospectivity of shale depends on numerous controlling factors that vary spatially from nanometer to basin scale. In the first part of this report, we have seen that several parameters that are not involved in the assessment of most conventional plays have to be analyzed and integrated in shale gas evaluation. Among those parameters are the organic matter content and maturity, adsorption capacity, rock elastic properties and in situ stress. Recent advances in high resolution imaging techniques have demonstrated that vast amounts of gas are trapped in micropores of organic matter in shale. As a result, reservoir simulators and lab analytical models have to account for adsorption effect and non-darcy flow processes. Adsorption capacity evaluation is needed to quantify gas in place and better predict long term productivity. Quantifying shale mineralogy is also paramount because it impacts pore network structure, elastic properties, fluid sensitivity and log response of shale. Knowledge of rock elastic properties, in situ stress and natural fractures orientation and density is required to properly design the well and hydraulic fracturing job. In the recent years, thanks to the contribution of hundreds of technical papers from producers, service companies and academia, the industry acknowledged the complexity of shale plays and developed a variety specific evaluation tools and approaches. As a result, shale gas producers have become more efficient in defining porspective areas and designing well and completion strategies. Horizontal well drilling and stimulation technologies and practices have been evolving at a fast pace, contributing to an overall increase of initial production rates (IP) and estimated ultimate recovery (EUR) of gas shale. In particular, geosteering using LWD, advanced log suits (shale expert systems) and microseismic monitoring contribute to optimizing the placement of the well and fracturing stages. Various combinations of fluids, additives and proppant are designed for specific areas and plays, depending on shale composition, mechanical properties, pore pressure and in situ stress. Recent technology innovations also aim at improving fracture and near wellbore conductivity and flowback recovery. Different combinations of multiple wells stimulation design including sequential and simultaneous fracturing are implemented to increase the stimulated reservoir volume. Overall, improving understanding of shale gas plays and technological innovations have proven the technical ability of the industry to tap in the very large shale gas resources. However, the shale gas industry is facing a greater challenge when it comes to economics


and environmental issues. Starting in 2008, the combination of economic recession and exponential increase of shale gas production in United States resulted in oversupplied market and low gas price. Surprisingly, shale gas production has been increasing consistently since then, despite sustained low gas price below 5 $/mcf. At current spot gas price (Henry Hub below 4 $/mcf as of September 2011), the most part of shale gas plays are marginally to not economic. Shale gas producers have been mitigating the effect of low gas price by optimizing well and operating costs, implementing hedging strategies and by focusing on liquid rich parts of the plays. Companies are also divesting non-core assets to provide additional capital and improve their balance sheet. Despite the current debate on shale gas economics, huge investments made by major companies in land positions, joint-ventures and acquisitions, demonstrate that shale gas is part of their long-term strategy. On the longer term, gas demand increase will be necessary to allows for the full development of North American shale gas plays and the gas industry is seeking for new markets. Domestic demand will largely depend on public policies and incentives regarding the use of gas in power generation and transportation sectors. Due to growing demand and higher price, the Asian gas market can be an important part of the future of North American shale gas. Asian companies are actively investing in North American shale gas assets while producers are seeking for government approval for LNG export projects. A major impediment of future shale gas development in North America and even more adversely in other part of the world is related to the public perception and environmental issues associated with hydraulic fracturing. Sustainable development of shale gas resources depends on responsible and cost-effective management of environmental risks. Proactive collaboration of the industry with regulatory agencies and academia to understand and mitigate risks associated with surface and drinking water contaminations, flowback disposal and water resource management will be paramount. Disseminating the results of this research and educating the public can contribute to alleviate negative perception of shale gas by the public. Current estimations of global shale gas resources represent about 30% of the world technically recoverable gas and are widely dispersed geographically. The development of shale gas has the potential to improve energy security in many areas around the world. According to the International Energy Agency, the share of gas in the global energy mix might increase by 50% from 2010 to 2035, to represent more than 25% of the world energy demand (International Energy Agency 2011). In this “high gas” scenario, natural gas-fired generation is expected to push the share of coal into decline and to back up increasing intermittent renewable sources of electricity. A lower growth of nuclear power after the Fukushima accident would also favor an increasing share of gas to reduce green house gas emissions. Increasing gas demand in the transportation sector may also be part of a low carbon future. If shale gas development is proven to be environmentally and economically sustainable and gains large public acceptance, it will play a major role in the future global energy mix.


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