Oil and Gas Shales
Organic matter dispersed in shales and mudstones is 10,000 times more abundant than that occurring in concentrated forms such as oil, gas, coal, and gas hydrates. So-called shale plays, distributed across all continents, are fairways where shale gas and shale oil might be extracted economically from targeted volumes of what is an extremely large potential resource. Almost all shale gas and oil reservoirs currently being exploited were formerly buried to great depth during which time gas generation took place, and then geologically uplifted to depths where extraction is feasible commercially. Productive shale reservoirs are brittle rather than elastic and therefore suitable for hydraulic fracturing to be employed effectively for releasing the dispersed gas. In this chapter we provide an overview of the chemical, physical, and biological processes involved in the formation of shale gas and shale oil and outline how organic geochemistry can be applied to the exploration and production of these resources.
In the short space of 10 years following the turn of the millennium, shale gas completely transformed the global energy market. This new natural gas resource, extracted in more than 30 sedimentary basins across the continental USA and others worldwide, accounted for about 1% of gas production in the USA in 2000, 10% in 2011, and may account for nearly two-thirds of total US production by 2025 (Energy Information Administration 2017). It all began in the Fort Worth Basin (Texas) where the integration of directional drilling and hydraulic fracturing (fracking) enabled natural gas to be extracted economically from the Barnett Shale (Jarvie 2012a). The technology was rapidly deployed to target other shale-bearing formations elsewhere, including the Fayetteville Shale (Arkansas), the Woodford Shale (Oklahoma), the Haynesville Shale (Louisiana and Texas), and the Marcellus Shale (Pennsylvania). A similar story rapidly unfolded for shale oil as the technology used for shale gas exploitation was modified to produce liquid petroleum from inter alia the Bakken Shale of North Dakota, the Eagle Ford and Wolfcamp Formations of Texas, and the Niobrara Formation of Colorado (Jarvie 2012b). The opening up of these new shale resource plays transformed the global oil market because the monopoly of the Organization of the Petroleum Exporting Countries (OPEC) was challenged, and the USA saw itself as becoming the world’s biggest oil producer by 2020 and being energy self-sufficient by 2025 (Energy Information Administration 2017). However, the ability to rapidly (over)supply produced fluids to the world market actually played a major role in the ultimate collapse of both gas and oil prices worldwide, making the future of shale gas and shale oil uncertain.
To put shale gas and shale oil resources in perspective, there are 1016 tonnes of organic matter dispersed in sedimentary rocks; this is 10,000 times greater than the organic matter occurring in concentrated forms such as oil and gas (collectively termed petroleum), coal, and gas hydrates (Killops and Killops 2005). The vast bulk of this dispersed sedimentary organic matter is contained within very fine-grained rocks such as shales and mudstones whose mineral matrices vary in their relative proportions of silica and feldspars, clays, and carbonates (Aplin and Macquaker 2011; Gamero Diaz et al. 2013; Macquaker and Adams 2003; Macquaker et al. 2014; Passey et al. 2010). Thus, the in-situ shale gas resource potential seen globally is extremely large and distributed across all continents. A first estimation of global shale gas resources was published by Rogner (1997; 16,112*1012 standard cubic feet) with North America and China as the regions with the largest potential (both around 3,000–4,000*1012 standard cubic feet). According to the World Energy Outlook 2013 published by the US Energy Information Administration, China has the largest “wet” shale gas resources of unproved technically recoverable 1,115 trillion cubic feet (Tcf), followed by Argentina (802 Tcf) and Algeria (707 Tcf). By far the largest unproven technically recoverable shale oil (tight oil) resource occurs in the USA with 78 billion barrels (BBL) and in Russia (75 BBL). Lower but still highly significant resource potentials have been calculated for China (32 BBL) and the United Arab Emirates (23 BBL). In this context, Europe has only minor shale gas and shale oil resources. While Western Canada, Argentina, and China continue to explore for and successfully produce shale gas and shale oil, the rest of the world is still at a relatively early phase of development. This is largely because of low oil and gas prices. In the case of Europe, the continuing controversy surrounding the real versus perceived impact of shale gas extraction on the environment sensu lato continues to block a logical and balanced evaluation of many promising stratigraphic target formations (International Energy Agency 2012; Hübner et al. 2013; Vetter and Horsfield 2014).
1.1 What Is Shale Gas?
1.2 What Is Shale Oil?
The term shale oil has been used for centuries to describe the oil that is generated by retorting (pyrolyzing) oil shales (Cane 1967). Oil shales are fine-grained rocks containing indigenous and mainly macromolecular organic matter (often >20% total organic carbon (TOC)) that have not been exposed to high geological temperatures and therefore still retain a great potential for generating oil when pyrolyzed. The name shale oil is used nowadays in a very different sense, namely, for the oil already generated naturally in the shale over geological time at elevated temperatures (>ca. 100 °C), still retained within the rock matrix and releasable by hydraulic fracturing.
Shale oil resource systems have been classified by their dominant organic and lithologic characteristics into (1) organic-rich mudstones with predominantly healed fractures, (2) organic-rich mudstones with open fractures, and (3) hybrid systems with a combination of juxtaposed organic-rich and organic-lean intervals (Jarvie 2012b). The in-situ oil is broadly similar in composition to that found in conventional reservoirs in that it contains all of the so-called SARA fractions (saturates, aromatics, resins, asphaltenes), but the produced fluid is strongly fractionated, being extremely enriched in light hydrocarbons, whereas the part remaining in the rock matrix is rich in heavy hydrocarbons and non-hydrocarbons (resins and asphaltenes).
1.3 The Organic Carbon Cycle
Shale gas and shale oil are formed over geological time as part of the subsurface organic carbon cycle. The starting point is the accumulation of organic residues from extant biota in fine-grained sediments. Upon burial, the organic matter undergoes progressive compositional change that is dictated initially by microbial agencies and thermodynamic instability (Arning et al. 2011, 2016) and later by mainly thermal stress. The continuum of processes is termed maturation and is divided into three consecutive stages called diagenesis sensu stricto (Ro < 0.5%), catagenesis (0.5% < Ro < 2.0%), and metagenesis (2.0% < Ro < 4.0%) by organic geochemists (Tissot and Welte 1978). The term Ro is defined in the next section of the chapter.
Kerogen, the major precursor of shale gas, shale oil, and conventional petroleum, is insoluble in common organic solvents and consists of selectively preserved resistant cellular organic materials from algae, pollen, spores, leaf cuticle, and the like, as well as the degraded residues of microbially less resistant biopolymers (e.g., cellulose, polysaccharides) and lipids in variable proportions (Rullkötter and Michaelis 1990; de Leeuw and Largeau 1993). Kerogen formation is complete by the end of organic diagenesis. The type of kerogen and its mode of formation exert a strong influence on oil- and gas-generating characteristics, e.g., gas-oil ratio (GOR) during catagenesis. The kerogen that is found in carbonate/evaporite source rocks is enriched in organic hydrogen and organic sulfur (Type II-S; Orr 1986) and generally accompanied by high contents of heavy bitumen (sedimentary organic matter that is soluble in common organic solvents), both of which can generate oil at low levels of thermal stress. Low sulfur Type II kerogen requires more thermal energy to generate oil, and Types I and III kerogens still more (Tissot et al. 1987). A proportion of the generated fluids remains as residual shale gas or shale oil, whereas the rest is expelled into adjacent strata; retention efficiency is variable. In the late stage of catagenesis, both residual oil and kerogen generate enhanced proportions of ethane, propane, and the butanes (Dieckmann et al. 1998). Throughout metagenesis, typically at depths of about 7 kilometers, the generated gas consists of methane (Lorant and Behar 2002; Mahlstedt and Horsfield 2012) and sometimes hydrogen sulfide (Le Tran et al. 1974) or nitrogen (Krooss et al. 1993). Periods of tectonic stress or postglacial rebound result in uplift, often on the order of several kilometers (e.g., Cavanagh et al. 2006), thus decreasing temperature and pressure and in some cases bringing about exposure to biological infiltration (Krüger et al. 2014; Schulz et al. 2015). Continued uplift leads to exposure at the Earth’s surface, erosion and oxidation, thus completing the cycle.
1.4 Investigative Tools at Our Disposal
A wide range of geological and chemical tools, covering a scale from entire sedimentary basins (e.g., 105 m in length) all the way down to individual molecules (e.g., 10−9 m), is employed to study the carbon cycle in general and shale plays in particular. At the largest scale, petroleum formation histories are reconstructed using basin modelling (Poelchau et al. 1997; Hantschel and Kauerauf 2009). Going down in scale, well logs and the principles of sequence stratigraphy allow organic-rich and organic-poor lithofacies to be mapped laterally and vertically (Passey et al. 1990). With a resolution covering tens of microns down to tens of nanometers, organic petrology and scanning electron microscopy allow the habit and optical properties of organic particles, termed phytoclasts or macerals (e.g., alginite, derived from algae; sporinite, derived from spores; vitrinite, derived from wood), to be related to depositional environment and thermal maturity, as well as characterize pore dimensions and occurrence (Stasiuk 1997; Diessel 2007; Loucks et al. 2009). Thus, the reflectance under oil immersion of vitrinite (Ro) is the most widely used maturity parameter. Organic macromolecules, such as kerogen and asphaltenes (the latter being the bitumen component that is insoluble in light hydrocarbons), are characterized using pyrolysis and other degradative techniques in combination with gas chromatography and mass spectrometry (Horsfield 1984; Larter 1984; Rullkötter and Michaelis 1990). Maltenes (the bitumen component soluble in light hydrocarbons) are analyzed using a wide variety of chromatography and mass spectrometry approaches (Wilkes, Methods of Hydrocarbon Analysis). The techniques are deployed in three types of laboratory: the experimental laboratory is used to analyze individual or a combination of variables under simulated geological conditions; the natural laboratory is one where the effects of individual or groups of variables can be established by means of measurements on the natural system; and the virtual laboratory is a numerical simulation platform for integrating results in both geological time and space coordinates.
1.5 Factors Governing Shale Prospectivity
Are fine-grained sedimentary rocks deposited under a variety of marine settings
Were originally rich in hydrogen-rich organic matter (>2% TOC)
Reached the liquid window (<1.2% Ro) for shale oil plays and the gas window (>1.2% Ro) for shale gas plays
Have low oil saturation (<5% So) for shale gas plays
Have a significant silica content (>30%) with some carbonate and non-swelling clays
Display less than 1,000 ηd permeability
Exhibit typically about 4–7% porosity, with pore sizes down to the nanoscale
Have a thickness exceeding 45 m and are now at a depth generally <4,000 m
Are slightly to highly overpressured
Exhibit very high first-year decline rates (>60%)
Allow fracking to be performed with due consideration of known principal stress fields
Can be drilled away from structures and faulting
2 Original Organic Matter in Shales
Only shales that are rich in indigenous organic matter are targeted for gas or oil exploitation, because that organic matter is the source material from which the resource is generated. The deposition of sediments rich in organic matter is usually restricted to subaquatic sedimentary environments in which organic matter is produced faster than it can be destroyed (Tourtelot 1979). Deep-marine silled basins with haloclines, upwelling areas displaying oxygen minimum zones, marine transgressions onto continental shelves, evaporitic environments, lakes with stable thermoclines, and fluviodeltaic coal-bearing sequences are all sites of enhanced organic matter deposition (Jones 1987; Littke et al. 1997) and therefore of enhanced potential feedstock for shale gas and shale oil.
2.1 Depositional Environment
Prominent examples of shale plays occur in foreland basin settings (Mississippian Barnett and Bakken Shale, Middle Devonian Marcellus Shale), in intracratonic basins (Upper Devonian Antrim Shale), or rift basins (Upper Jurassic Haynesville Shale). The vast majority of shale resource plays were deposited in marine environments (Curtis 2002; Jarvie 2012a, b). The Lower Carboniferous Barnett Shale of the Fort Worth Basin was deposited under upwelling conditions, and has a TOC averaging 4% (Hill et al. 2007). The rhythmic stratification of chalk-marl beds is a characteristic of the Upper Cretaceous Niobrara Formation (Locklair and Sageman 2008) and brought about by the variation of siliciclastic input controlled by eustatic and climatic cycles (Pollastro 2010). TOC is in the range 1–8% (Landon et al. 2001). For the Upper Jurassic Eagle Ford Shale basin geometry played a key role in creating local depocenters of anoxic sediment deposition; TOC contents of up to 10% have been documented (Robison 1997). The marine Devonian Bakken Shale was deposited in a marine environment in the photic zone under anoxic conditions (Requejo et al. 1992) during sea level rise (Smith and Bustin 1998), and is organic-rich (TOC 3–25 wt.%; Price et al. 1984). The Upper Jurassic Haynesville Formation, whose TOC content reaches 8 wt.%, consists of shoreface clastics, carbonate shelves, and organic- and carbonate-rich mudrocks deposited in a deep, partly euxinic and anoxic basin (Hammes et al. 2011). High-salinity conditions and water density stratification prevailed during deposition of the Upper Devonian Woodford Shale, along with manifestations of photic zone euxinia (Romero and Philp 2012); the TOC content is up to 25 wt.% (Cardott and Lambert 1985). Looking further afield, the Jurassic-Cretaceous Vaca Muerta Formation of Argentina, currently under extensive exploration, and with TOC in the range 2–12 wt.%, was deposited in a distal marine environment from outer ramp to middle ramp settings in mostly dysaerobic conditions (Kietzmann et al. 2011), and the Lower Jurassic Posidonia Shale, a potential shale gas candidate in Western Europe, was deposited in a low-energy environment under largely anoxic to euxinic marine conditions in a sea that was rich in nutrients (Schmid-Röhl et al. 2002) with short phases of more oxygenated bottom water conditions (Wignall and Hallam 1991). Its TOC, where immature, is 9–12 wt.% (Rullkötter et al. 1988). Moreover, deglaciation has led to the formation of black shales by salinity stratification, as seen for the Lower Silurian in North Africa (TOC up to 17 wt.%; Lüning et al. 2000) or after the Carboniferous glaciation of Gondwana (Lower Ecca black shales TOC up to 8 wt.%; Geel et al. 2015).
2.2 Under the Microscope
2.3 Building Blocks in Organic Macromolecules
2.4 Generating Potentials
Gas versus oil generating potential is initially governed by the relative abundance of short versus long chains in macromolecular precursors. Utilizing n-alkyl chain length distributions from pyrolysis gas chromatography, Mesozoic shales containing Type II kerogen, such as the Eagle Ford, Niobrara, and Posidonia (Kuske et al. 2017; Han et al. 2018; Muscio et al. 1991), mainly fall in the Paraffinic-Naphthenic-Aromatic Low-Wax petroleum-type organofacies of Horsfield (1989), whereas Type II Paleozoic shales, such as the Alum, Bakken, and Barnett (Muscio et al. 1994; Horsfield et al. 1992a; Kuhn et al. 2010, 2012; Han et al. 2015), fall in the Gas-Condensate organofacies or at the border of the two facies. Such differences in chain length distributions within the Type II elemental class reflect the variability in inherent gas- versus oil-generating potential of organic-rich shales in nature, and thus molecular typing is a key element of the exploration equation (fraction). The same is true for lacustrine shales, which are often inherently richer in long-chain alkanes and belong to the paraffinic high-wax petroleum-type organofacies. The chain length distributions for a collection of low-maturity shales and source rocks are shown in Fig. 4b.
As the organic matter in shale is gradually exposed to progressively higher temperatures during burial over millions to tens of millions of years, its composition changes, driven by aromatization. Major aliphatic substituents of the kerogen structure are progressively cracked, more or less in the order of bond strength, and there is concomitant structural rearrangement of the residues (Ungerer 1990; Mao et al. 2010; Bernard et al. 2012a, b; Romero-Sarmiento et al. 2014). Assessing the thermal maturity of shales and the degree to which its in situ macromolecular organic matter has been converted into mobile products is a key element of the exploration equation. Thus, for example, in the case of the shales of the Eagle Ford Shale, gas-oil ratio (GOR) is regionally controlled by thermal maturity, with iso-maturity lines orientated NE-SW and thermal maturity levels increasing to the SE (Fan et al. 2011). Similarly, concentric iso-maturity contours occur in the Bakken Shale, linked to changing Hydrogen Index and petroleum properties (Kuhn et al. 2010).
3.1 Primary Cracking of Kerogen and Bitumen
The primary cracking of kerogen and heavy bitumen forms gaseous and liquid products at 10–90% conversion levels – this is the maturity range for shale oil, especially the higher end of the range. The actual relationship between level of catagenesis, reflecting the thermal history of the shale, and degree of conversion into oil and gas at that maturity level is governed by their chemical kinetic parameters (activation energy distribution and frequency factor, as reviewed by Schenk et al. 1997b), and these differ appreciably from case to case, even within each of the classical kerogen Types I, II, and III (di Primio and Horsfield 2006). Very importantly as far as shale oil exploitation is concerned, bulk petroleum compositions in shales appear to reflect the most recently generated products, i.e., “instantaneously generated,” and not an accumulation of products formed since generation began, and this is because expulsion is an ongoing process during progressive maturation (Kuske et al. 2018). The GOR of instantaneous products is appreciably higher than those of cumulative products (England et al. 1987).
While the overall reaction order for petroleum generation is generally assumed to be first order (as reviewed by Schenk et al. 1997), second-order reactions between kerogen and polar bitumen components have been documented as strongly influencing bulk compositional characteristics, including gas-oil ratio (Vu et al. 2008; Mahlstedt et al. 2008). Thus, when assessing the maturation characteristics of a given shale, it is important to use samples which retain the solvent-extractable macromolecular components. Heavy bitumen makes an important yet variable contribution to the total organic matter of shales and is especially abundant in calcareous shales and marls (e.g., Powell 1984; di Primio and Horsfield 1997), even at low levels of maturation; to remove it by solvent extraction would be to take away a highly significant fraction of petroleum precursors.
3.2 Secondary Cracking of Oil
Disproportionation results in the formation of hydrogen-rich (dry and wet gases) and hydrogen-poor species (pyrobitumen) at elevated levels of maturation. In-source secondary oil-to-gas cracking begins at approximately 1.2% Ro, at a paleotemperature of about 150 °C (e.g., Dieckmann et al. 1998), this being considered a prerequisite for economically viable shale gas in the Barnett Shale of the Fort Worth Basin (Jarvie et al. 2007). By contrast, in-reservoir cracking in conventional siliciclastic reservoirs begins around 2% Ro at a paleotemperature (3 K/Ma heating rate) of approximately 200 °C (Horsfield et al. 1992b; Schenk et al. 1997a). Primary and secondary gas-forming reactions in shales overlap to variable degrees. The “GOR-Fit” model predicts the generation of primary and secondary gas from source rocks, in which overlapping liquid generation and destruction reactions occur, on the basis of simple stoichiometric relationships (Mahlstedt et al. 2015). The generation of so-called late gas from residual methyl groups in both kerogen and pyrobitumen begins at 2% Ro and appears to be complete by 3.5% Ro (Erdmann and Horsfield 2006; Mahlstedt and Horsfield 2012), this being an important prospectivity assessment parameter in plays where maturity levels are exceedingly high, e.g., the Sichuan Basin, China (Tan et al. 2013).
3.3 Role of Catalysis
Catalysis increases the gas-oil ratio when a given kerogen type is pyrolyzed in the presence of minerals, especially illite and smectite (Espitalié et al. 1980; Horsfield and Douglas 1980), and the question remains whether these organic-inorganic interactions might also occur in nature where temperatures are much lower and heating rates nine orders of magnitude slower than employed in laboratory experiments (300–650 °C). It has recently been found that gasification effects are strongly heating rate dependent and are likely to be minor under geological heating rates of, e.g., 3 K/Ma (Yang and Horsfield 2016). This means that raw data from the pyrolysis of especially relatively organic-lean (S2 < 10 mgHC/g rock) and argillaceous shales should be treated with caution as predicted gas contents and bulk aromaticity might be overestimated.
3.4 Radiolysis Effects
The ionizing radiation emitted from uranium acts over the entire lifetime of a shale, beginning with deposition, to fundamentally change the chemical characteristics of organic matter in shales. This influence is significant in the case of uranium-rich shales that are Lower Paleozoic or older. While the radiation dosage resulting from the decay of uranium is linearly correlated with uranium content and exposure time, the kerogen structure changes exponentially since labile structures react early and become stabilized in later stages. The outcome is that shales which generated mainly oil during their early subsidence history, such as the Alum Shale of Scandinavia, have been altered so they appear more gas-prone than was really the case (Yang et al. 2018).
3.5 Maturity Parameters
Exact maturity assessment has been shown to be a key element in the regional exploration for sweet spots. Stable isotopes of hydrocarbon gases have been used to estimate maturity, for example, the rollover of ethane and propane δ13C values (δ13C2 and δ13C3) and isotopic reversals among methane, ethane, and propane being correlated with the occurrence of sweet spots in the Barnett of the Fort Worth Basin (e.g., Zumberge et al. 2012; Hao and Zou 2013). Rock-Eval Tmax or its purported “equivalent” in terms of vitrinite reflectance (Jarvie et al. 2001) is frequently deployed with the same goal. The fact that kinetic parameters of generation vary significantly within a given kerogen type (Tissot et al. 1987; di Primio and Horsfield 2006) means that there is actually no unique correlation between Tmax and Ro for shale plays. As an example, the relationship between the two parameters for the Duvernay Shale (Devonian) of the Western Canada Sedimentary Basin differs from that of the Barnett (Wüst et al. 2013) though both have similar initial genetic potential (Type II).
3.6 Mass Balance Modelling
In conventional petroleum exploration, it is important to determine the timing of petroleum generation relative to trap formation as well as its level of maturation (Hantschel and Kauerauf 2009), but with the unconventionals, it is simply the final degree of alteration that is most important, because the fluids to be exploited are still in-situ. The inverse modelling of organic matter abundance and composition between relatively closely spaced wells is better suited to effective shale gas exploitation because it allows the determination of generative yields and generated product compositions: mass balance calculations using quantitative pyrolysis gas chromatography data (Santamaria-Orozco and Horsfield 2003) allow the generation of compound classes and individual oil and gas components to be quantified over any selected narrow or broad maturity range. For example, the generation of n-alkanes and alkylbenzenes in closely spaced samples within the Barnett Shale showed variability that has been linked to organofacies (Han et al. 2015). Similarly, generation profiles for these components within marls of the Niobrara Formation have been contrasted with residual hydrocarbons in reservoir facies chalks (Han 2016) as a first step in calculating retention and depletion within shales, as further explained in the section below on retention.
The retention of hydrocarbons in shales is governed mainly by the sorption capacity of its organic components (Baker 1962; Tissot et al. 1971; Stainforth and Reinders 1990; Pepper 1991; Han et al. 2015). Interestingly, it is the pyrolytically labile fraction (S2 of Rock-Eval) and not simply the total organic matter that has the highest selective adsorptive capacity (Mahlstedt and Horsfield 2013; Han et al. 2015; Ziegs et al. 2017). The more aromatic the labile fraction is, the higher is the adsorptive capacity. Thus, for a given level of maturity, those Type II kerogens whose S2 is inherently more aromatic, for example, the Alum, Barnett, and Bakken Shales, have a better capacity than those that are less aromatic, for example, the Posidonia and Wealden Shales (Mahlstedt and Horsfield 2013). It is important to note that the gas sorption capacity of the Alum Shale was probably less well developed during its generative period (Paleozoic times); aromaticity and thus sorption capacity have increased due to relatively recent radiolysis effects (Yang et al. 2018); thus gas generation and the development of sorptive capacity are out of step in this example.
The retentive labile fraction is contained within both bitumen and kerogen fractions (Muscio et al. 1991; Horsfield et al. 1991), and these are distributed heterogeneously within shales, this being reflected in the breadth of reflectance histograms and the variety of phytoclast types present (e.g., Bernard et al. 2010, 2012a). Figure 3 displays the evolution of this compositional variability with increasing thermal maturation of Posidonia Shale and Barnett Shale (Bernard and Horsfield 2014). While minerals play a subsidiary role in adsorption, clay minerals, especially illite (Schettler and Parmely 1991), possess microporous structures that are capable of sorbing gas (Gasparik et al. 2014).
4.1 Shale Porosity and Kerogen Swelling
Low-pressure adsorption isotherms (e.g., Bustin et al. 2008), high-pressure mercury intrusion porosimetry (e.g., Nelson 2009), solid-state nuclear magnetic resonance (e.g., Sondergeld et al. 2010), and small-angle and ultrasmall-angle neutron scattering (e.g., Ruppert et al. 2013) have shown that pore sizes within gas shales are on the order of a few nanometers to tens of nanometers. Besides sorption on particle surfaces, petroleum storage in the pores of either organic (Loucks et al. 2009) or inorganic (Bernard et al. 2013; Han et al. 2015) matrices has been documented, as have natural fractures (Lopatin et al. 2003; Pollastro 2010; Bernard et al. 2013). The occurrence of organic particles exhibiting irregular ellipsoid-shaped nanopores of approximately 1–500 nm first observed by Loucks et al. (2009) has now been reported in most gas shale systems worldwide, as reviewed by Bernard and Horsfield (2014). In high-maturity gas shales, these organic pores govern gas occurrence. Porosity in shales evolves from mostly submicrometric interparticle pores in immature samples to mostly intramineral and intraorganic pores in gas mature samples (Curtis et al. 2010, 2012; Loucks et al. 2010, 2012; Bernard et al. 2013; Mathia et al. 2016), but primary organic pores have been observed within immature and oil mature samples as reported in a recent comprehensive literature review (Han et al. 2017). For the vast bulk of the shale volume, hydrocarbon retention and porosity evolution appear to be strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation (Kelemen et al. 2006; Han et al. 2017). Secondary organic pores form only after the maximum kerogen retention (swelling) ability is exceeded, namely, where Tmax = 445 °C, or 0.8% Ro. The shrinkage of kerogen has therefore been proposed as a mechanism for forming organic nanopores, and is ostensibly a major cause of associated porosity increase, in the gas window.
4.2 Quantification of Precursors and Retained Products
Assessing in-place oil characteristics
Volatile oil represents all FID-detectable-free hydrocarbons in the sample.
Volatile oil = S1WR mg/g rock
Total oil refers to the sum of volatile oil (S1WR) and the macromolecular components (part of S2) that are soluble in the extraction solvent.
Total oil = S1WR + (S2WR−S2EX) mg/g rock
Oil quality refers to the ratio of volatile oil (S1) to total oil.
Oil quality = S1WR/(S1WR + (S2WR−S2EX))
Assessing kerogen and bitumen contributions
The relative contributions of kerogen to the S2 signal
S2K = S2EX/S2WR
is also reflected in the Tmax shift
ΔTmax = (TmaxEX – TmaxWR) °C
Hydrogen Indices of the macromolecular kerogen and bitumen components:
Hydrogen Index kerogen = S2EX/TOCEX mg/g
Hydrogen Index bitumen = (S2WR−S2EX)/(TOCWR – TOCEX) mg/g
The so-called Oil Saturation Index provides a measure of the oil in place that is more readily producible (Jarvie 2012b).
Oil saturation index = S1WR/TOCWR mg/g
The total oil saturation index provides a measure of the total oil in place.
Total oil saturation index = S1WR + (S2WR−S2EX)/TOCWR mg/g
5 Production Characteristics
Prospectivity largely depends on the degree to which lithologies and compositional heterogeneities (fluids and matrix) can be recognized so that artificially stimulated fractures can be induced within selected packages (Binnion 2012). It is also noteworthy that compositional fractionations due to selective retention, and sometimes induced by phase separation, can change the ratio of gas to oil and the chemistry of the oil. Three examples are presented here to illustrate these important points.
5.1 Recognition of Sweet Spots Within Heterogeneous Sequences
This illustrative example is taken from Han et al. (2015).
Beginning at the top, the first interval is carbonate-rich and organic-lean.
The deeper second interval consists mainly of organic-rich noncalcareous mudstones, including porous biogenic silica from sponge spicules. It behaves like a reservoir unit within the succession, exhibiting the highest Oil Saturation Index and suppressed Tmax values.
The third interval is argillaceous and consists mainly of organic-rich siliceous noncalcareous mudstones and phosphatic shales. It represents the best source interval.
The fourth and fifth intervals are calcite-rich and consist mainly of siliceous calcareous mudstones.
Oil quality increases with increasing depth in the well-reflecting increasing contributions of light hydrocarbons. A preferential migration of C15+ aliphatic hydrocarbons from the third into the second interval, accompanied by selective retention of aromatic hydrocarbons and polar compounds in the third interval, has occurred. The migration pathway from the third to the second is via natural fractures. Carbonate-cemented fractures perpendicular to the bedding have been documented, as well as the coexistence of oil inclusion clusters within these fractures.
Whereas the retention of hydrocarbons within most intervals is primarily controlled by organic matter richness, additional storage occurs within siliceous microfossils of the second interval. Based on this enrichment and its siliceous nature, the interval represents a much more attractive target for hydrocarbon production than the clay-rich third interval.
Furthermore, at higher maturities, the horizon is expected to yield higher additional amounts of secondary gas by oil cracking. This might explain why the primary producing facies of the Barnett Shale is largely quartz dominated.
5.2 Rapid Insight into In-Situ Physical Properties of Fluids
5.3 Fractionation During Production: Insights from PVT Modelling
The phase behavior of in situ petroleum is governed by the pressure-temperature (P-T) conditions of the reservoir and the bulk composition of the petroleum fluid (England et al. 1987; Düppenbecker and Horsfield 1990; di Primio 2002). The petroleum phase or physical state of fluids at any given P-T condition can be described by phase envelopes whose shapes are ultimately controlled by the organofacies and thermal maturity of the source organic matter (di Primio et al. 1998). A one-phase system exists in P-T conditions that are outside of the phase envelope (undersaturated), whereas a two-phase system exists at or within the envelope (saturated), and the two meet at the saturation pressure (Psat).
To date, only a few investigators have addressed prediction of petroleum quality and phase behavior within unconventional resources. Using petroleum engineering models, Whitson and Sunjerga (2012) were the first to publish that petroleum fluid produced from surface wellhead facilities did not represent downhole fluid properties. They noted that the ultralow permeability usually found in unconventional shale plays leads to substantial amounts of oil drawdown (retention) and that the degree of oil recovery depends on whether the reservoir is initially saturated by oil or gas and whether conditions are near-saturated (greatest oil recovery loss) and to what degree.
6 Research Needs for Unconventional Resource Assessments
The boom in shale gas and shale oil exploration and development appears to be essentially over. However, these unconventional resources will continue to be exploited in years to come, but at a more sustainable and conservative pace than seen in the past. Looking back, we can readily see that the huge number of shale core and cutting samples principally made available for applied scientific and commercial investigation actually led to a fundamental re-think as to the workings of the deep organic carbon cycle. Shales make up the greatest global repository for sedimentary organic matter. Classically they have been viewed as containing molecular archives of paleoclimate and paleoecosystems, and as far as resources are concerned, they have been recognized as sources and/or seals for petroleum (e.g., Killops and Killops 2005). What is now clear is that transport within and throughout low permeability shale packages is extensive. It is also clear that macromolecular organic matter in a form other than kerogen, namely, heavy bitumen, is not only abundant but plays a fundamental role in the generation and storage of hydrocarbons. Either of these fractions can develop porosity during progressive maturation, and both contain thermally labile moieties that actively adsorb hydrocarbons. Working to reveal the true chemical nature of heavy bitumen is an important research avenue that is open for development, and that means in the broadest sense unraveling the cycling of nitrogen, sulfur, and oxygen in the geosphere. Very little is actually known about the fate of these elements in the stages that fall between early diagenesis (amino acids, fatty acids, humic acids, sulfurized lipids) and metagenesis (H2S, CO2, N2). Both analytical and simulation pyrolysis methods, selective chemical degradation, and advanced analytical characterization (e.g., FT-ICR MS, STXM) provide the means to undertake the work. The role played by microbes especially in uplifted shales must also be considered. The conceptual and technological advances regarding process understanding (chemical, physical, and biological) can readily be transferred from the area of resources to that of repositories, thereby allowing the potential consequences of nuclear waste storage in shales to be better assessed.
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