Oil and Gas Shales

  • Brian HorsfieldEmail author
  • Hans-Martin Schulz
  • Sylvain Bernard
  • Nicolaj Mahlstedt
  • Yuanjia Han
  • Sascha Kuske
Living reference work entry
Part of the Handbook of Hydrocarbon and Lipid Microbiology book series (HHLM)


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.

1 Introduction

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?

Natural gas features prominently in all national energy portfolios. Because of its relatively low-carbon footprint and flexible utilization, natural gas is widely regarded as the most important bridge to a low-carbon energy future. In stark contrast to conventional accumulations, where the gas now occurring in coarse-grained reservoir rocks within structural or stratigraphic traps is generated in and expelled from distant source “kitchens,” unconventional shale gas is disseminated within myriads of tiny (nm sized) pores within the source rock or adsorbed on its mineral and organic particle surfaces (Fig. 1). Individual resource plays extend across tens and hundreds of kilometers laterally and tens to hundreds of meters vertically at depths ranging from 2 to 4 km. They are characterized by widespread gas saturation, subtle trapping mechanisms, and relatively short intraformational hydrocarbon migration distances (e.g., Curtis 2002; Jarvie et al. 2007; Boyer et al. 2011; Bernard and Horsfield 2014). The gas can only be released effectively using controlled hydraulic fracturing (“fracking”). The name shale gas refers to natural gas of biogenic, thermogenic, or mixed origins contained in what is loosely termed shale but which in reality are mudstones, marls, and limestones (Fishman et al. 2011). Almost all currently producing shale gas reservoirs have been buried to great depth and hence high temperature (>150 °C) and then geologically uplifted to depths where commercial extraction is possible, typically 2–4 km. They are brittle rather than elastic and therefore suitable for effective hydraulic fracturing to be employed to micro-crack the rock and release the in situ gas (e.g., Curtis 2002; Jenkins and Boyer 2008; Boyer et al. 2011). The relative content of dry gas (methane), wet gas (ethane, propane, and butanes), and non-hydrocarbon gases (CO2, N2, H2S), and hence calorific value, varies within and between basins (Bullin and Krouskop 2008), as is also the case for conventional natural gas.
Fig. 1

FIB-SEM image of a core sample from immature Lower Toarcian Posidonia Shale (Wickensen well, 0.5% Ro; courtesy U. Hammes, Austin). Unconventional shale gas can be stored in pores (black) or adsorbed on its mineral (white for pyrite, grey for minerals) and organic particle surfaces (dark grey)

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

Fracking technology is highly advanced thanks to lessons learned from the drilling of 2.5 million wells in conventional petroleum systems (Montgomery and Smith 2010) and especially in the last 15 years from the more than 40,000 wells drilled specifically into shale targets using “slickwater” and “hybrid” drilling fluids and deploying proppants. According to Jarvie et al. (2007), Slatt and O’Brien (2011), Jarvie (2012a), and Bernard and Horsfield (2014), high prospectivity and gas production rates is usually obtained from shale resource plays that:
  1. 1.

    Are fine-grained sedimentary rocks deposited under a variety of marine settings

  2. 2.

    Were originally rich in hydrogen-rich organic matter (>2% TOC)

  3. 3.

    Reached the liquid window (<1.2% Ro) for shale oil plays and the gas window (>1.2% Ro) for shale gas plays

  4. 4.

    Have low oil saturation (<5% So) for shale gas plays

  5. 5.

    Have a significant silica content (>30%) with some carbonate and non-swelling clays

  6. 6.

    Display less than 1,000 ηd permeability

  7. 7.

    Exhibit typically about 4–7% porosity, with pore sizes down to the nanoscale

  8. 8.

    Have a thickness exceeding 45 m and are now at a depth generally <4,000 m

  9. 9.

    Are slightly to highly overpressured

  10. 10.

    Exhibit very high first-year decline rates (>60%)

  11. 11.

    Allow fracking to be performed with due consideration of known principal stress fields

  12. 12.

    Can be drilled away from structures and faulting

In practice, all shale systems are unique in their chemical composition, physical properties, and rheology (e.g., Table 3 in Jenkins and Boyer 2008), with the result that production optimization has been based on learning-by-doing and involved the drilling of hundreds of wells, factory style (Binnion 2012). To streamline and rationalize the learning process, a simple exploration equation can be employed to address the important geochemical variables (Fig. 2). The in-place gas and/or oil potential of shale resource plays, embodied in that equation, is governed by the level of conversion of the original organic matter into hydrocarbons, the proportion of those hydrocarbons that is retained within the shale, and the fraction of the retained fraction that is gas or liquid. The boxes show the rock attributes that must be analyzed in order to address the different elements. The technically recoverable proportion of the in-place potential, hereafter termed producibility, is ultimately determined by the mechanical and petrophysical properties of the rock and the degree to which that potential can be realized using tailor-made engineering protocols. Each of the these elements is considered separately in the ensuing discussion.
Fig. 2

Technical framework defining in-place potential (exploration equation) and technically recoverable resource potential (producibility)

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

At a magnification of 600, and under blue light excitation, the organic constituents of immature marine shales mainly comprise brightly fluorescing alginite, usually derived from dinoflagellate/acritarch and prasinophyte cysts, along with lesser amounts of liptodetrinite, vitrinite, and inertinite (Littke and Rullkötter 1987; Littke et al. 1988). Mature shale oil candidates display a weaker fluorescence, and this is then entirely absent by the onset of gas generation. Finely disseminated micrinite, most likely a residue of liptinite degradation, also occurs in mature shales (Hackley and Cardott 2016). Important changes in fabric and the heterogeneity of organic chemical composition cannot be determined by this low-resolution microscopy approach. While confocal laser scanning microscopy and conventional scanning electron microscopy (SEM) cannot characterize submicrometer grains and pores if broken or mechanically polished shale samples are analyzed, argon-ion beam milling can be used to overcome this difficulty because sufficiently flat samples are produced (Loucks et al. 2009; Desbois et al. 2010; Mathia et al. 2016). Indeed, recent advances of SEM coupled with a focused ion beam (FIB-SEM) systems have offered a new alternative for investigating the three-dimensional submicrometric fabric of shales (Curtis et al. 2010, 2011a, b, 2012; Desbois et al. 2010; Sondergeld et al. 2010; Bera et al. 2011; Heath et al. 2011; Walls and Sinclair 2011; Bernard et al. 2013), so that, inter alia, chemical and mineralogical heterogeneities related to depositional environment have been documented (e.g., Arthur and Sageman 1994; Katsube and Williamson 1994; Ross and Bustin 2009; Loucks et al. 2009). Highly porous fossiliferous facies at low maturity have been documented alongside interparticle organic matter using FIB-SEM (Bernard et al. 2013). The FIB-SEM technique can also be used to extract ultra-thin (<100-nm-thick) sections across areas of interest, thus providing suitable samples for transmission electron microscopy, which offers a unique combination of chemical and structural information with unsurpassed spatial resolution (Chalmers et al. 2012; Bernard et al. 2012a, b), and for synchrotron-based techniques, such as scanning transmission X-ray microscopy (STXM) allowing X-ray absorption near-edge structure (XANES) spectroscopy to be performed at high spatial resolution (20 nm scale; e.g., Bernard and Horsfield 2014). For instance, recent STXM and TEM observations have elucidated the strong heterogeneous nature of gas shales down to the nanometer scale, with kerogen, bitumen, and pyrobitumen delineated within the same sample (Bernard et al. 2012a, b) (Fig. 3).
Fig. 3

Focused ion beam-scanning electron microscopy (FIB-SEM) images in backscattered electron (BSE) mode of three Posidonia Shale samples (left) and scanning transmission electron microscopy (STEM) images in high-angle annular dark-field (HAADF) mode of three Barnett Shale samples (right), showing organic matter (dark regions). These two sets of samples constitute two natural maturation series. Organic masses evolve from immature kerogen in immature samples (0.5% Ro) to bitumen and oil-mature kerogen in oil-mature samples (0.8% Ro) and to gas-mature kerogen and pyrobitumen in gas-mature samples (1.5% Ro). The scanning transmission X-ray microscopy (STXM)-based X-ray absorption near-edge structure (XANES) spectra of these different organic compounds is shown in the center. Absorption features at 285 and 285.3 eV are attributed to electronic transitions of aromatic moieties, 286.4 and 286.7 eV to ketone or phenol functionalities, 287.7 and 288 eV to aliphatic moieties, 288.5 eV to carboxyl functionalities, 289.5 eV to hydroxyl functionalities, 290.3 eV to carbonate cations, and 290.6 eV to alkyl moieties. (Modified from Bernard and Horsfield (2014))

2.3 Building Blocks in Organic Macromolecules

The potential yields of gas and oil generated per unit organic matter in shales depend upon its organic hydrogen content and thence aliphaticity versus aromaticity, after diagenesis has concluded, at the onset of catagenesis (Larter 1985; Vu et al. 2013; Sykes and Snowdon 2002). Hydrogen-rich kerogen (atomic H/C > 1.4) is usually found where anoxic lacustrine and marine shales are deposited, whereas hydrogen-poor kerogens (atomic H/C < 1.0) are found in more oxidizing, often terrestrial, settings (Tissot et al. 1974). Hydrogen-rich kerogens largely consist of algal-derived aliphatic cell membranes and lipid components (Cane and Albion 1973; Philp and Calvin 1976; Largeau et al. 1984; Tegelaar et al. 1989), whereas hydrogen-poor kerogens at low maturity often contain high proportions of altered lignocellulosic (phenolic) materials whose aliphatic constituents consist of alicyclic moieties and short alkyl chains (Mycke and Michaelis 1986). Being deposited largely under reducing conditions in marine environments, the major gas shales contain Type II kerogen and at the start of catagenesis have Hydrogen Indices in the range 300–600 mgHC/g TOC (Jarvie 2012a, b). Like the prolific source rocks in conventional petroleum systems, shale oil targets may be either marine or lacustrine and contain either Type I or II organic matter. This is illustrated in Fig. 4a for selected shales and source rocks of low maturity. The product of the TOC (%) and Hydrogen Index (mgHC/g TOC) determines the generative potential (S2) expressed as kg/tonne rock, or equivalent oilfield units (e.g., barrels per acre-foot).
Fig. 4

(a) Kerogen typing using the Rock-Eval “pseudo-Van Krevelen” diagram for a wide variety of immature and early mature shales: the method is excellent for predicting yield, but not for predicting petroleum compositions, e.g., gas-oil ratio (GOR). (b) Petroleum-type organofacies based on analytical pyrolysis reflect the chain length distributions within labile carbon moieties that are the precursors for petroleum

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.

3 Conversion

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).

Fourier transform-ion cyclotron resonance mass spectrometry (FT-ICR MS) is a powerful tool for rapidly characterizing NSO compounds in complex mixtures. Run in the ESI-negative ion mode, it has been used to rapidly assign maturity levels to produced oils and in-situ shale bitumen extracts based on the relative distribution of pyrrolic nitrogen-containing compounds (Oldenburg et al. 2014; Poetz et al. 2014; Mahlstedt et al. 2016). Specifically, as far as the alkylcarbazoles, alkylbenzocarbozoles, and alkyldibenzocarbazoles are concerned, there is an increase in the degree of benzannulation with increasing maturity (Fig. 5), and that is mainly due to fractionation processes, i.e., preferential expulsion (or production) of smaller compounds and enhanced cyclization and aromatization at the expense of aliphatic structures within retained fluids; the crude oils and extracts plot on different trend lines (Fig. 5).
Fig. 5

Ternary plot featuring alkylcarbazoles (9 DBE (double bond equivalents)), alkylbenzocarbozoles (12 DBE), and alkyldibenzocarbazoles (15 DBE). The Posidonia Shale-sourced crude oils fall roughly in a position indicating oil maturities equivalent to Ro = 0.68–0.74% according to maturity assignments for North Sea crudes (Oldenburg et al. 2014), whereas Bakken Shale and Vaca Muerta oils are positioned near Ro = 0.68% and 0.9%, respectively. Related Bakken Shale and Vaca Muerta extracts from the producing wells plot close to the Posidonia Shale extracts from source rocks with Ro values of 0.68% and 0.88%, confirming that the maturity assignments are robust

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.

4 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

The volume of gas generated within gas shales by secondary cracking directly depends on oil retention in the system, i.e., on adsorption capabilities as well as on porosity and fracture networks. The algebraic mass balance models of Larter (1985) and Cooles et al. (1986) use dead carbon for normalization, Rock-Eval S1 to define free petroleum, and S2 to define labile kerogen. They predict that organic-rich shales are excellent expellers of petroleum (approximately 90%), and thus, petroleum that is retained, and which can act as a source of secondary gas in shales, is relatively minor. According to these models, shales with lower organic richness are poorer expellers, meaning that while they are unable to source conventional petroleum, they are nevertheless potentially good gas shales. Jarvie et al. (2007) assessed expulsion to be much lower (65%) than these models predict, correctly taking into account that a high proportion of polar compounds in the retained oil actually elute in the S2 peak and not S1 (Horsfield et al. 1991). This finding is extremely important for shale oil plays, where it is important to distinguish mobile from immobile petroleum fractions. Simple geochemical parameters from the Rock-Eval analysis of whole rock (WR) and solvent-extracted (EX) aliquots have here been formulated to describe petroleum yield and composition more rigorously:
  • 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

  • Assessing retention

    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

Changes in two of these parameters as a function of Tmax are illustrated for the Vaca Muerta Formation (Argentina), the Yanchang Shale (China), the Posidonia Shale (Germany), and the Eagle Ford Shale (USA) in Fig. 6. In the simplest case, oil quality increases progressively as the proportion of polar compounds decreases, this being most clearly discernable for the Eagle Ford maturity series. The Yanchang and Posidonia show enhanced quality at lower maturity ostensibly due to infiltration by mature fluids. The Vaca Muerta Shales shown here are actually from a limited maturity range (ca. 1% Ro); low Tmax values are most likely related to the retention of high molecular weight, in part polar, heavy oil components. The oil saturation index is said to exceed 100 mgHC/g TOC where producible oil occurs (Sandvik et al. 1992; Jarvie 2012b) and is often relatable to the presence of porous microfossils (Han et al. 2015, 2017). In the case of the Posidonia Shale, values increase and then decrease in accordance with the concepts of the oil window and kerogen swelling, and only in a few cases do values exceed 100 mgHC/g TOC. Decreasing values are seen for the Eagle Ford at high maturity levels. The Vaca Muerta displays exceedingly enriched and depleted intervals for a given maturity, consistent with intraformational migration.
Fig. 6

The rapid assessment of bulk petroleum composition in the Vaca Muerta Formation (Argentina), Yanchang Shales (PR China), Posidonia Shale (Germany), and Eagle Ford Formation (USA) using Rock-Eval parameters. (a) Oil quality, calculated as S1WR/(S1WR + S2WE-S2EX). (b) Oil Saturation Index, calculated as S1WR/TOCWR

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).

The Barnett Shale sequence of the Marathon 1 Mesquite well, Hamilton County, Texas, contains Type II kerogen throughout and is at oil window maturity (1.0% Ro). It displays significant compositional heterogeneity (Fig. 7).
  • 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.

Fig. 7

Geochemical depth profile of the Marathon 1 Mesquite well. Interval subdivisions are based on (1) gamma ray (GR) log, (2) core description, (3) Rock-Eval parameters. TOC = total organic carbon (%); S1 = thermally extractable petroleum (mgHC/g rock); oil quality = S1/(S1WR + S2WR–S2EX); saturates refers to C15+ fraction from medium pressure liquid chromatography separation; Tmax = temperature at which S2 generation rate is at a maximum

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

Elias and Gelin (2015) used the relative proportions of heavy versus medium cuts (h/m) from GPC/UV analysis of produced oils and rock extracts to document differences in the in-situ API gravity of fluids within the Vaca Muerta Formation (Fig. 8b). Adopting and adapting this approach, Mahlstedt et al. (2017) used the chain lengths of alkyl substituents in N1 carbazoles (DBE 9) from FT-ICR MS (ESI-negative mode) for the same purpose. The low and intermediate aliphatic carbon numbers (C1−14) were used as the medium cut and high aliphatic carbon numbers (C15+) as the heavy cut (Fig. 8a). Plotting API gravity versus aliphatic carbon number-based h/m ratios and comparing with the GPC/UV-API° trend line resulted in a good correlation, showing that meaningful API values could already be assessed for potential resource plays, e.g., the Posidonia Shale and the Vaca Muerta Formation. The API gravity prediction for produced oil from one well in the Neuquén Basin is 40°, which is clearly within the reported range of 39–41°API for this well. API gravity predictions for source rock extracts from the producing well are 41° for the Upper Vaca Muerta and 44° for the Lower Vaca Muerta indicating that the initial oil was produced from the UVM.
Fig. 8

FT-ICR MS N1 aliphaticity for API prediction. (a) The aliphatic carbon number distribution of Posidonia Shale-sourced crude oils and extracts, as well as Vaca Muerta-sourced crude oils and two extracts (Upper and Lower VM), is compared in a ternary diagram displaying N1 compounds of the 9 DBE class. Carbazoles with alkyl substituents of 1–5 carbon atoms, 6–14 carbon atoms, and ≥15 carbon atoms form the apices. The ratio of heavy (h) versus medium (m) molecular weight is determined from >C15+/(C1-C5 + C6-C14). (b) API gravity prediction using the heavy/medium cut as determined by gel permeation chromatography, as well as FT-ICR MS of N1 compounds of the 9 DBE class, of the total extracts/oils

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.

Using microscale sealed vessel (MSSV) pyrolysis, Horsfield et al. (2015) and Kuske et al. (2017) performed artificial maturation experiments on mature Eagle Ford samples and used the results to model how the PVT properties of generated fluids would be at a slightly higher level of conversion (Fig. 9a). Phase behavior predictions from the so-called PhaseSnapShot model were compared with a regional PVT database for DeWitt County compiled from the public domain. The model that best matched the targeted PVT data was comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability matrix and (2) bitumen that was the precursor of gas in zones of enhanced porosity within the matrix. Importantly, the enhanced generation of gas from the admixture of kerogen and bitumen and the significant retention of C7+ fluids in the matrix were required to enable a match between the phase behavior and geochemical compositions of fluids from the majority of wells in the study area. Cumulative compositions based on experiments using an immature sample produced gas-poor products and hence phase envelopes with consistently low Psat (Fig. 9b). The overall implications were that instantaneous (most recently generated) rather than cumulatively generated fluids occur in shale reservoirs and that in situ petroleum compositions differ significantly from those at the surface, there being a major increase in gas-oil ratio because of selective retention of petroleum liquids.
Fig. 9

(a) Phase envelopes of petroleums produced from the Eagle Ford Formation of DeWitt County compared with those of instantaneous petroleums generated using MSSV SnapShot experiments, (b) phase envelopes resulting from PhaseKinetics cumulative compositional predictions based on an immature outcrop sample

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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Copyright information

© Springer Nature Switzerland AG 2018

Authors and Affiliations

  • Brian Horsfield
    • 1
    Email author
  • Hans-Martin Schulz
    • 1
  • Sylvain Bernard
    • 2
  • Nicolaj Mahlstedt
    • 1
  • Yuanjia Han
    • 1
  • Sascha Kuske
    • 1
  1. 1.GFZ German Research Centre for GeosciencesSec. 3.2 Organic GeochemistryPotsdamGermany
  2. 2.Muséum National d’Histoire Naturelle, Sorbonne Université, CNRS UMR 7590, IRDInstitut de Minéralogie, de Physique des Matériaux et de Cosmochimie, IMPMCParisFrance

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