Organic geochemical applications to the exploration for source-rock reservoirs – A review

Journal of Unconventional Oil and Gas Resources 13 (2016) 1–31

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Journal of Unconventional Oil and Gas Resources journal homepage: www.elsevier.com/locate/juogr

Review

Organic geochemical applications to the exploration for source-rock reservoirs – A review Joseph A. Curiale a,⇑, John B. Curtis b a b

Chevron Energy Technology Company, United States Colorado School of Mines & GeoMark Research, Ltd., United States

a r t i c l e

i n f o

Article history: Received 13 February 2015 Revised 11 October 2015 Accepted 27 October 2015 Available online 7 November 2015 Keywords: Source rock Petroleum geochemistry Source-rock reservoirs Organic matter Geochemical methods

a b s t r a c t Source-rock reservoirs are fine-grained petroleum source rocks from which liquid and gaseous hydrocarbons may be produced following fracture stimulation. A major factor that allows such a source rock to function well as a reservoir is its organic matter – specifically the quantity, quality and thermal maturity of that organic matter as it occurs within the source-rock reservoir. Here we review the published literature to assess the current status of geochemical measurement and data interpretation of organic matter in these reservoirs, and how workers have applied this information in the exploration for this reservoir type. Our focus is on the chemical and geochemical characteristics of source-rock reservoirs, with emphasis on the isotopic and molecular characteristics of their hydrocarbon fluids and solid organic matter. Special consideration is given to geochemical analytical methods particularly appropriate to the organic matter in this reservoir type. Our discussions of published studies focus on three areas: (a) source rock characteristics – organic matter quantity, quality and maturity; (b) thermally-induced cracking of kerogen, oil, condensate and gas; and (c) natural gas stable carbon isotopic anomalies often observed in shale plays. Conceptual approaches and practical applications are addressed in equal measure, and our assessment of future directions and unsolved problems is provided. Ó 2015 Elsevier Ltd. All rights reserved.

Contents Introduction and concepts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Previous reviews . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Analytical approaches to source-rock reservoir understanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Condensates and oils. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Rock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Analytical methods – organic matter quantity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Analytical methods – organic matter quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Analytical methods – organic matter maturity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Hydrocarbon generation and expulsion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Organic matter quantity, quality and maturity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Diagenesis, catagenesis and metagenesis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Cracking (to oil and gas and solid bitumen) of kerogen and subsequent migration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Crude oil thermal stability – cracking (to gas) of kerogen, bitumen, oil and gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Expulsion – compositional changes upon migration and efficiency/retention considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

⇑ Corresponding author at: Chevron Energy Technology Company, 1500 Louisiana Street, Houston, TX 77002, United States. E-mail address: [email protected] (J.A. Curiale). http://dx.doi.org/10.1016/j.juogr.2015.10.001 2213-3976/Ó 2015 Elsevier Ltd. All rights reserved.

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Source-rock reservoir organic matter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Source rock depositional settings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Age considerations – are there age limits to unconventional plays?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Source rock assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quantity of organic matter in source-rock reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quality of organic matter in source-rock reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Maturity of organic matter in source-rock reservoir plays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Migration of fluids into and out of source-rock reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fluid isotopic evolution of gases with increasing maturity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Isotope reversals and rollovers – occurrence and origins. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future directions and unsolved problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geochemical data stores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Moving from ‘what’ to ‘why’ in the unconventional world . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The ongoing nomenclature change – when does unconventional becomes conventional? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Introduction and concepts Overview The presence and character of the source rock for oil and gas is the most critical risk element in petroleum exploration, whether the target is a conventional play or an unconventional sourcerock reservoir play. It is the only element which, if absent, excludes the occurrence of oil or gas. The conceptual shift from dealing with four distinct risk elements – source, reservoir, trap, seal – to considering source and reservoir as a unified component in so-called shale plays has revolutionized 21st century petroleum exploration, and with it the question of organic matter character and distribution in fine-grained rocks. Source-rock reservoirs contain sufficient organic matter to generate petroleum and sufficient porosity and adsorption sites to retain that petroleum. Terminologies used to describe this type of reservoir and the plays involved have varied considerably over the past decade (Passey et al., 2010, and references cited therein; Cander, 2012). For our purposes, we will use the term ‘‘sourcerock reservoir” as recently proposed by Hart et al. (2013): ‘‘source-rock reservoirs are fine-grained petroleum source rocks. . . having geomechanical properties that allow those rocks to produce hydrocarbons at economic rates after stimulation by hydraulic fracturing”. We intend for this usage to encompass the range from ‘pure’ unconventional systems (e.g., Barnett gas play) to ‘hybrid’ systems (e.g., Bakken liquids play) (Williams, 2013). Several lithologies and sub-lithologies satisfy this definition, although the current literature (and industry) focus remains on mudrocks, sensu stricto (Passey et al., 2010). While we will use the term ‘‘sourcerock reservoir” throughout this review, other terms used here will conform to current usage, including common phrases such as ‘‘gas shales”, ‘‘shale plays” and ‘‘liquids plays”. This review deals with (a) the application of organic geochemistry to the exploration for source-rock reservoirs and (b) the composition of organic matter contained in these reservoirs.

Definitions We consider petroleum to be an organic molecular continuum encompassing gas, liquid and solid phases. Thus, although we will refer to the chemical composition of individual phases, we generally attempt to treat the organic matter of source-rock reservoirs as part of a continuum, rather than rigorously separating our discussion into play types according to phase.

13 13 13 14 14 14 16 17 17 21 21 24 24 25 25 25 25

Furthermore, we consider the origin of petroleum, broadly considered, to be a settled issue: it is a product of thermal generation over geologic time from disseminated organic matter syndepositionally accumulated in sedimentary rocks (Tissot and Welte, 1984; Hunt, 1979). Therefore, while the reader is welcome to investigate proposed origins of gas and oil by catalysis at temperatures below those of thermal scission (Sheiko et al., 2006; Mango et al., 2009; Mango and Jarvie, 2009, 2010) or from abiotic sources, either from the crust or mantle (Etiope and Sherwood Lollar, 2013, and references cited therein), our focus is solely on the thermal origin. Lastly, we note that terms such as ‘asphaltene’, ‘bitumen’ and ‘kerogen’ are traditionally defined operationally, and in our view they have less relevance inside the rock than after they have been removed from the rock. We will define each term as it arises, and discuss compositions accordingly. We refer to solid organic matter at standard temperatures and pressures (STP: 25 °C and 1 atm) within source-rock reservoirs as either kerogen or solid bitumen. Solid bitumen rendered insoluble in organic solvents (due to elevated temperatures) is termed pyrobitumen, after Abraham (1920). Scope The emphasis of this review is narrow: organic chemical and geochemical approaches and their application to exploration for source-rock reservoirs. We will examine the elemental, isotopic and molecular composition of the organic matter in source-rock reservoirs, with a focus on the ultimate impact of its composition on petroleum characteristics. This approach will involve both the solvent-soluble (petroleum, bitumen) and solvent-insoluble (kerogen, pyrobitumen) organic matter in the source-rock reservoir, and the chemical changes that this organic matter undergoes from initial deposition through generation of petroleum. The confined focus of this review inevitably leaves several subjects out of scope, many of which have been reviewed elsewhere. Although we will mention current plays in the context of discussing specifics of their hydrocarbon charge component, for detailed descriptions of the geology and general petroleum systems of these plays the reader is referred to a wide range of peer-reviewed and gray literature, as well as the summaries in Hart Energy’s Unconventional Playbook Series (www.ugcenter. com). Additionally, many play-types designated elsewhere as ‘unconventional’ are out of scope here. These include tight sands, heavy oil, coal bed methane, tar sands, so-called oil shales, and marine and arctic hydrates. Likewise, and similarly out of scope,

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are shallow, widely distributed accumulations of microbial gas, often labeled ‘unconventional’ in the trade literature because of their depth and geographic extent (Shurr and Ridgley, 2002; Fishman et al., 2012a; Nicolas and Bamburak, 2012). In contrast, geochemical aspects of microbial gas in deep, confined sourcerock reservoirs are in scope (e.g., Martini et al., 2003). Production studies such as the characteristics and implications of hydraulic fracturing and associated flowback fluids, including unintended (so-called ‘‘stray”) fluid release external to the source-rock reservoir as a consequence of hydraulic fracturing, and with releases into the hydrodynamic, vadose and atmospheric environments, including accompanying chemical changes in production fluids through time, have all been discussed elsewhere (e.g., Kirk et al., 2012; Warner et al., 2012; Haluszczak et al., 2013; Jackson et al., 2013; Strauss et al., 2014; Rostron and Arkadakskiy, 2014; Grant et al., 2015). And finally, although organic geochemical applications are noted in publications on reservoir, basin and economic modeling, these topics are more directly addressed in other publications (Gray et al., 2007; Lopatin et al., 2007; Leonard et al., 2008; Lorant et al., 2010; Cipolla et al., 2010; Kaiser, 2012; Wygrala et al., 2012; Romero-Sarmiento et al., 2013). Previous reviews To the best of our knowledge, despite the presence of organic matter in shales of up to 40% by volume (Passey et al., 2010), ours is the first review encompassing all aspects of – and only of – organic geochemical applications to source-rock reservoir exploration. Nevertheless, several reviews over the past decade have focused on one or more distinct aspects of our topic and related subject matter, and others touch on geochemical applications, data and interpretations as part of a more comprehensive look at these unconventional plays (e.g., Nash, 2014; Abrams et al., 2014). Geochemical information pertaining to several current shale gas and liquids plays was compiled by Jarvie (2012a, 2012b) and Nash (2014), while selected organic and inorganic aspects of sourcerock reservoir characterization were addressed by Curtis (2002), Passey et al. (2010), Martinez-Kulikowski et al. (2013), Bohacs et al. (2013) and Nandy et al. (2014). Several authors have produced comprehensive reviews of the petroleum geochemistry of specific source-rock reservoirs (e.g., see Jin and Sonnenberg, 2014, for a summary of the Bakken Formation as a source rock, and Zumberge et al. (in press) for a discussion of the Eagle Ford Formation). An excellent summary of published work on thermal maturity of source-rock reservoirs was recently published by Bernard and Horsfield (2014), and Chatellier et al. (2013) have reviewed and presented an extensive dataset on the synergy between engineering and geochemical data in source-rock reservoir plays. The Energy Mineral Division of the American Association of Petroleum Geologists (AAPG) has compiled bibliographies of shale liquids and gas shale publications (http://emd.aapg.org/members_ only/shalegas_liquids/ShaleOil.pdf and http://emd.aapg.org/ members_only/shalegas_liquids/GasShales.pdf, respectively, both updated to 2013), many of which focus on, or provide data from, the geochemical aspects of these plays. Optical studies of sourcerock reservoir organic matter were discussed by Jaeger (2013), and Paul Hackley and colleagues at the United States Geological Survey have compiled a very useful online organic petrographic atlas with discussion of the maceral distributions commonly observed in source-rock reservoirs (see http://energy.usgs.gov/ coal/organicpetrology/photomicrographatlas.aspx and Valentine et al., 2012). The organic petrology of shales is also addressed in a recent special issue of International Journal of Coal Geology (‘‘Shale gas and shale oil petrology and petrophysics”; Bustin, 2012) and in reviews by Suarez-Ruiz et al. (2012a,b). Studies of the microfabric of these shales were reviewed by Sondergeld et al. (2010) and

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Milliken et al. (2013). Klein and Myers (2012) and Michael et al. (2013, 2014) examined approaches for determining their hydrocarbon content. The continuing controversy on the origin of so-called isotopic anomalies in the gas content of shale plays – discussed in detail later in this review – has been reviewed by Hao and Zou (2013) and Xia et al. (2013). Analytical approaches to source-rock reservoir understanding Since its inception, progress in petroleum geochemistry, including conceptual developments, has closely followed the invention and development of new techniques for chemical analysis (cf. Eglinton and Murphy, 1970; Engel and Macko, 1993; Peters et al., 2005). Analytical methods developed and applied to conventional resource exploration over the past half-century have been instrumental in enhancing our understanding of organic matter associated with source-rock reservoirs. Thus, we consider the broad availability of analytical methods in this area to be a key aspect of this review, and address it accordingly. In the following subsections we will review analytical methods which already have specific application to source-rock reservoirs, and those whose applications have been recognized only recently. Gases Because of the molecular simplicity of natural gas, the types of gas analysis are limited relative to those available for oils and source rock organic matter. This limitation, however, is overcome by the fact that gas analysis can be accomplished, via elemental analysis, gas chromatography and mass spectrometry (including isotope ratio determination), with a precision far greater than that for the analysis of liquid and solid organic matter, thus providing extensive capabilities for delineating and distinguishing gas families. This ability to distinguish one gas from another via high-precision analysis is particularly crucial when studying gases generated and reservoired in source-rock reservoirs, because it is useful, in gas shale exploration, to be able to deconvolve mixtures of gas sources from very similar (yet distinct) organic matter facies. In addition, the elevated level of thermal maturity commonly seen in shale gases, and the desire to order these gases according to the thermal maturity level at which they were generated, has required geochemists to push the limits of their chromatographic and spectrometric analytical methods. Compositional (i.e., concentrations of hydrocarbons and nonhydrocarbons) and isotopic analyses of gases present in the subsurface are now routine in the evaluation of shale gases. Such evaluations involve, at a minimum, the quantification of the methane-through-pentane hydrocarbons, the non-hydrocarbon components such as carbon dioxide, hydrogen sulfide and nitrogen gas, and the stable carbon, hydrogen and sulfur isotope ratios of each of these components. The importance of accurate isotope measurements in shale gas became apparent early, when Zumberge et al. (2009, 2012, and references therein) recognized natural gas isotopic ratio trends which were clearly anomalous relative to those observed from conventional, mid-maturity gas generation. Since their initial work on North American shale gases, these anomalous trends have been observed worldwide (e.g., Li et al., 2012; these so-called rollover and reversal trends are reviewed in detail below). Chromatographic and spectrometric compositional and isotopic methods have been applied extensively in establishing and quantifying gas generation and intra- and intersource gas mixing (Rodriguez and Philp, 2010; Xia et al., 2013; Hao and Zou, 2013), and the developing technology of clumped isotope measurements will have much to offer in these areas (Stolper et al., 2014; Wang, 2015). In addition, statistical evaluations of large gas

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isotopic datasets provide promise for eventually quantifying gas mixing during the entire timespan of generation and filling (Xia, 2013). As with the hydrocarbon components, the analytical evaluation of the non-hydrocarbon composition and isotopic variability of natural gases is well-established in the conventional world, and has both exploration as well as economic significance, often because of high concentrations of components such as N2, CO2 and H2S. Although routine analysis of these components in source-rock reservoir gases is now commonplace, nonhydrocarbon analysis of trace petroleum components such as noble gases (He, Ne, Ar, Kr, Xe) is still in its infancy: Laughrey and Burruss (2010) demonstrated the utility of noble gas ratios as a maturity tool, and Jackson et al. (2013) has recently used noble gas geochemistry to address the stray gas problem in shale gas production settings. Because of their conservative (non-reactive) nature, vertical and lateral mapping of concentrations and isotope ratios of these components have significant potential as a gas migration tool. Darrah et al. (2012) recently used noble gases to distinguish in situ gases and transient aquifer gases of the Appalachian Basin. Using noble gas isotope ratios as well as elemental concentrations, these authors demonstrated the potential for noble gas geochemistry as a tool to understand aspects of the generation and migration of shale gases. 4He/40Ar and 21Ne/40Ar ratios in Marcellus and related gases of the Appalachian Basin were used by Hunt et al. (2012) to reinforce existing gas family groupings (Fig. 1), and demonstrated the potential for using noble gas isotopic analysis as a tool to map the generation and post-generative alteration and mixing of shale gases (cf. Laughrey and Burruss, 2010).

Condensates and oils As with natural gases, geochemical analytical methods of assessing condensates and oils comprise elemental, molecular or

isotopic approaches. Analytical precision in liquid organic matter analysis, as noted above, is less than that for natural gases, although to some extent this is compensated for by the much wider range of analytes available for examination. Full geochemical examination of oils and condensates in liquids plays involves elemental analysis (covering much of the periodical table, with an emphasis on the transition elements and, increasingly, the rare earths), molecular analysis (gas chromatography, with effluent detection via flame ionization and single/multiple-stage mass spectrometry) and stable isotope analysis (carbon and hydrogen, and increasingly sulfur and nitrogen). On this basis, geochemical analytical approaches for petroleum liquids in the conventional and unconventional worlds are quite similar to one another. However, despite the use of common data types, the search for ‘sweetspots’ – areas with an unusually high production rate – can require distinctive methods of interpretation. This occurs because liquids plays, at least to a first approximation, represent that aliquot of petroleum remaining in the source rock (or cracked therefrom: see Hill et al., 2007) following conventional generation and expulsion. Examples are (a) the use of molecular maturity ratios of shale liquids to map source rock maturity at a sensitivity and resolution unavailable with rock-based maturity techniques (Hackley et al., 2012; Dahl et al., 2013), (b) the application of unusual stable isotope ratios as correlation, migration or maturity assessment tools (Rooney et al., 2012; Williams and Hervig, 2013; Stein et al., 2013), and (c) whole oil techniques and/or ultra-high selectivity techniques, including FT-ICR-MS and GCxGC-TOFMS (Marshall and Rodgers, 2008; Eiserbeck et al., 2012). We describe results of early applications of these approaches later in this review, and anticipate that application of these methods will be utilized increasingly in exploration for liquids plays. Rock Analytical evaluation of the organic matter disseminated in source-rock reservoirs complements analyses of gases and oils recovered from these rocks. Standard source rock analytical methods have joined with modified and newly developed approaches to address geochemical characteristics novel to source-rock reservoirs. This section will review these methods in order to demonstrate the breadth of analytical types currently in use and to illustrate techniques currently in development. Our initial analytical focus will be on the three basic measures of source rock evaluation – organic matter quantity, quality (or type), and thermal maturity. We return to this three-part evaluation approach later in this paper, when we discuss applications of these methods in greater detail.

Fig. 1. Noble gas isotopes – 21Ne and 40Ar – supplement Dd values (ethane– methane) as tools for distinguishing families of Appalachian Basin gases (modified after Hunt et al., 2012, used by permission from AAPG; some data from Jenden et al., 1993). Although such family grouping approaches are useful, the greatest promise of noble gas isotope geochemistry for natural gases is in deconvolving source, maturity and migration processes.

Analytical methods – organic matter quantity The most fundamental geochemical assessment in source-rock reservoir analysis is the amount of organic matter, expressed as either total organic carbon (TOC) or total organic matter (TOM). Most TOC measurements are made using quantitative combustion or pyrolytic methods (for comparison of instrument results, see Behar et al., 2001; Jarvie et al., 2012, and Thul and Sonnenberg, 2013, and references cited therein). However, the advent of source-rock reservoir exploration has led to the development of additional direct and indirect methods. For example, lab-based spectrometric methods utilizing laser excitation are now available for measurement of organic matter content in core material (Dessort et al., 2012; Washburn, 2015), and their accuracy has even been demonstrated in cuttings obtained from wells drilled with an oil-based mud system (Charsky and Herron, 2012). Interest in proxy or correlative measures of TOC, first established decades ago (e.g., Odermatt and Curiale, 1991, and references cited therein),

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has also been renewed. For example, Nawratil et al. (2012) has recently used a handheld X-ray Fluorescence (XRF) device on samples of the Vaca Muerta Formation of the Neuquen Basin (Argentina) to establish a rough correlation between TOC and elements such as molybdenum, showing Mo concentrations of greater than 30 ppm where TOC values exceed 3%. Later work by Harris (2014), Harris et al. (2013), Baumgardner and Hamlin (2014), Bryndzia and Braunsdorf (2014) and others has also examined source-rock reservoir correlations between TOC and Mo, Ni, and other transition metals, and similar correlations with U are wellknown. Substantial work remains to be done in this area, particularly because such relationship are often play-dependent. As is the case with conventional exploration, petrophysical techniques have much to offer in rapid, high-resolution assessment of organic matter in source-rock reservoirs. Indeed, the need for frequent measurement of parameters as basic as TOC content and the volume of TOM in source-rock reservoirs has led to a reawakening and enhanced use of petrophysical methods long utilized for organic matter assessment (Schmoker, 1979; Passey et al., 1990). These established approaches are indirect, in that TOC or TOM is calculated from various permutations of petrophysical parameters (e.g., resistivity, porosity, etc.). Nevertheless, when properly calibrated, and in particular when the samples of measurement interest are closely related to the learning set used to establish the calibration, such indirect methods provide a rapid estimation of organic content in source-rock reservoirs (Cluff, 2011; Beitz et al., 2013; Alqahtani and Tutuncu, 2014). Recent downhole spectroscopic logging advances make it possible to determine TOC by difference from directly-measured total carbon and total inorganic carbon, providing both rapid and accurate estimation of organic content in source-rock reservoirs (Herron et al., 2011; Charsky and Herron, 2013). An extension of these logging approaches also makes additional measurements possible, including the direct assessment of hydrocarbon saturation (Craddock et al., 2013). Recently developed geochemical logging methods have also been used successfully in conjunction with traditional electric logging techniques, often to illuminate molecular ranges which previously remained uninvestigated (Schrynemeeckers, 2014). Analytical methods – organic matter quality In proper source rock evaluation schema, accurate assessment of organic matter quantity is followed by determination of organic matter quality or type. The primary determination of kerogen type is done through optical examination at high magnification, in order to establish the distribution of macerals present in the kerogen, each of which has its own hydrocarbon-generation capability (Mastalerz et al., 2012). Quantitative pyrolysis of source rocks can provide a proxy determination of kerogen type in cases where the unit is thermally immature. However, standard (open) pyrolysis techniques are inappropriate for quality determination in most gas shales because of their elevated maturity level, and even in liquids plays are useful only in a supplemental way. We also note that intensified use of open (generally rapid, high-temperature programmed) pyrolysis has amplified concerns about accuracy and consistency of various methods (Thul and Sonnenberg, 2013). Likewise, elemental analysis of kerogen, including C, H, N, O, S, is well established in a research setting. Atomic H/C and O/C ratios, in particular, provide information on kerogen type and kerogen evolution in conjunction with other robust thermal maturity data. Standard visual kerogen analysis (VKA, a term also applied to maceral examination in whole-rock preparations) approaches in source-rock reservoirs are similar in principle to those for conventional source rocks, although considerably more skill is necessary when working with the high maturities commonly encountered in gas shales, and with the condensate-to-wet-gas maturity levels

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increasingly encountered in unconventional liquids plays. The importance of VKA in source-rock reservoirs has led to a welcome resurgence in its use. Organic petrographic evaluation of this reservoir type requires optical recognition of numerous macerals (Valentine et al., 2012; http://energy.usgs.gov/coal/organicpetrology/photomicrographatlas.aspx), and applications to source-rock reservoirs are documented (Mastalerz et al., 2012; Rippen et al., 2013; Jaeger, 2013). In addition, detailed VKA measurements also provide information on largely inorganic components which cooccur with kerogen and are often critical in providing depositional and maturity information. Identification and reflectance measurement of graptolites and chitinozoa, for example, are helpful in early Paleozoic source-rock reservoir plays where vitrinite-based maturity tools and depositional information are unavailable (Poprawa, 2009; Zdanaviciute and Lazauskiene, 2009; Suarez-Ruiz et al., 2012a; Bowman and Mukhopadhyay, 2014). The growing use of organic matter evaluation in source-rock reservoirs has led to continued development of instrumental techniques for maceral analysis, all of which supplement and extend the utility of VKA. An excellent example of this approach is presented by Bernard et al. (2010). These authors have characterized individual macerals by laser-ablation pyrolysis gas chromatography–mass spectrometry and Raman microspectroscopy, acquiring component information far beyond what can be obtained by optical microscopy. Wang and Chang (2014) have extended this further, specifically for coals, by utilizing thermogravimetric techniques to examine individual macerals isolated via density centrifugation. Importantly, Camp et al. (2013) have noted the value of identifying and imaging macerals in source-rock reservoirs via electron microscopy, thus bridging the optical and electronic scales of microscopy. Although the most useful maceral-based studies are those which utilize whole rock preparations, direct kerogen analysis is also useful, and targeted exploration for source-rock reservoirs has elevated the importance of proper kerogen preparation and chemical analysis. Kerogen preparation schema developed in the 1970s (Durand and Alpern, 1980) have now been supplemented by methods which provide precise amounts of acid addition in a experimental arrangement which is closed to the atmosphere and unaccompanied by potential losses due to decanting (Ibrahimov and Bissada, 2010; Pernia, 2012; Pernia et al., 2012). This approach yields much higher kerogen recoveries in sourcerock reservoir systems. Chemical analyses that require substantial amounts of individual macerals (Mastalerz et al., 2012) – e.g., bulk spectroscopic methods; maceral-based molecular and isotopic pyrolytic analyses – benefit from such closed-system kerogen preparation methods because of their quantitative accuracy. Analytical methods – organic matter maturity Geochemical evaluation of source-rock reservoirs benefits greatly from assessment of organic matter quantity and quality, but is incomplete without accurate evaluation of thermal maturity. Indeed, for most shale gas plays and many liquids plays, a key parameter establishing economic viability is the thermal maturity level and its lateral variability. Thus, an understanding of thermal (and non-thermal: see Sheiko et al., 2006) bond scission is critical in exploration for source-rock reservoirs, and laboratory and fieldbased approaches to measure the extent of this bond-breaking have been studied intensively. The importance of knowledge of maturity levels in gas shale evaluation, for example, has led to the use of petrophysical log data to develop gas–oil ratios and maturity proxies (Zhao et al., 2007), and general maturity patterns have been replicated by using these proxies (an example involving density and resistivity logs is presented in Fig. 2). Because gas–oil ratios in resource plays often correlate to maturity level, Zhao et al. (2007) were also able to map GOR values via log calculations. In a

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Fig. 2. Maturity pattern obtained by Zhao et al. (2007, used by permission of AAPG), using bulk density and deep resistivity logs for wells through the Barnett Shale of the Fort Worth Basin, northeast Texas. The calculated maturity proxy (with ‘hotter’ colors corresponding to higher relative maturity) roughly correlates with gas–oil ratio of the Barnett fluids, leading to a GOR distribution pattern roughly mimicking the maturity pattern shown here. (See also Jarvie et al., 2015.) (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

similar fashion, Ward (2010) successfully used permutations of neutron and density log data in Marcellus Formation wells to estimate kerogen densities which, in turn, can be used as a proxy for thermal maturity. While these indirect methods for assessing maturity patterns in source-rock reservoirs are utilized by several operators, the gold standard for maturity measurement remains the reflectance of vitrinite (and, where vitrinite is absent, such as in early Paleozoic rocks, graptolites and chitinozoa may be used – e.g., work on Lithuanian shales by Zdanaviciute and Lazauskiene, 2009). Early recognition of the utility of vitrinite reflectance (VR) mapping in the Barnett Shale (Montgomery et al., 2005, and references therein; Pollastro et al., 2007; Jarvie et al., 2007) has led to intensive accumulation of VR data in all plays of Devonian or younger age. Efforts to obtain accurate VR (and graptolite reflectance) measurements have redoubled with the recognition that kerogen and solid bitumen porosity development in source-rock reservoirs, and in organic matter in general, is related to maturity level (King and

Wilkins, 1944; Curtis et al., 2011; Bernard et al., 2012a; Fishman et al., 2012b, 2014; Valenza et al., 2013; Mastalerz et al., 2013; Sanei et al., 2015), and evidence exists for nanometer-scale porosity in immature organic-rich sediments (Milliken et al., 2014). The interconnectedness of maturity and porosity is also evident from recent work on bitumen reflectance level which, as a measure of thermal maturity, can vary with nanoporosity of the bitumen (Sanei et al., 2015). The importance of understanding maturity trends has also been highlighted by recognition that the maturity-induced reflectance of vitrinite can be modified significantly by events other than those induced by gradual subsidence of a sedimentary basin (Wilkins et al., 1992; Carr, 2000). Most recently Newman et al. (2013), for example, has recognized corrosion-related effects of igneous and hydrothermal fluid activity on reflectance values in several parts of the stratigraphic section in the Williston Basin. The absence of vitrinite in Silurian and older intervals that predate the development of land plants, as well as the diminished

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quantities of vitrinite in distal lacustrine depositional settings, has led to a resurgence in the use and development of generalized organic matter-based maturity measurement tools for sourcerock reservoirs. Early development of spectroscopy-based maturity methods (e.g., Robin and Rouxhet, 1978) has seen renewed interest, and the use of Raman spectroscopy as a maturity tool in coals and sedimentary organic matter is undergoing a renaissance (Bernard et al., 2010; Guedes et al., 2010; Ulyanova et al., 2014; Wilkins et al., 2014; Buseck and Beysac, 2014). Workers are also revisiting other spectroscopic techniques as proxies for thermal maturity, and recent work on nuclear magnetic resonance (NMR) shows particular promise. Smernik et al. (2006) and Burdelnaya et al. (2014) have investigated possible calibrations of kerogen thermal maturity levels by using hydrous pyrolysis experiments to hold lithofacies and other non-maturity factors constant, thus monitoring – using aromaticity changes only – the differences attributable to maturity. In addition, standard molecular maturity ratio techniques are increasingly being applied to source-rock reservoir exploration (Hackley et al., 2012; Dahl et al., 2013; Zumberge et al., 2013, 2015), with special attention being paid to unusual molecular distributions characteristic of high-maturity sources (Xie and Ni, 2013). For similar purposes, isotopic methods for thermal maturity assessment of source-rock reservoir organic matter have also been pursued, using both conventional carbon and hydrogen isotope techniques (Mastalerz et al., 2012; Xia et al., 2013; Zumberge et al., 2013) and newly applied lithium and boron isotope ratio approaches (Williams and Hervig, 2013). Exploration for unconventional reservoirs has also benefited from laboratory-based pyrolysis as a tool for studying the effect of increasing maturity while holding organic facies constant. Such techniques, including closed and open pyrolysis approaches, provide a way to understand the effects of thermal maturity on organic matter through a wide range of maturity levels. Open, flow-through pyrolysis methods such as Rock–Eval have been used extensively for these purposes (see review by Jarvie (2012a) and Jarvie (2012b), as well as several studies references herein). In particular, the need to understand porosity development at increasing maturity levels has led to expanded use of hydrous pyrolysis, a relatively low-temperature closed-vessel form of pyrolysis (Lewan, 1993). Open, flow-through (e.g., Rock–Eval) and closed, confined (e.g., gold tube heating, hydrous pyrolysis) pyrolysis methods can be used in both conventional and unconventional play contexts. However, in our opinion hydrous pyrolysis is particularly wellsuited for laboratory generation of petroleum-like fluids (e.g., Lewan, 1993; Tsai et al., 2010; Little, 2012), and as a tool for artificial manipulation of maturity while constraining organic matter quantity and quality. In source-rock reservoir studies the technique has been used to generate fluids for gas-source and oilsource correlation purposes from Type I (Tang et al., 2013) and Type II (e.g., Little, 2012) kerogens, as a method for quantifying efficiencies of oil expulsion (from kerogen) in the presence of high smectite concentrations (Lewan et al., 2014), and as a laboratory tool for the understanding of natural fracturing and reactivation of existing fractures during maturity increase (Lewan and Birdwell, 2013; Birdwell et al., 2013).

Hydrocarbon generation and expulsion Because economic accumulations of petroleum have an organic origin, it is instructive to examine briefly the nature of biomass contributing to sediments through time, and the conversion of living organic matter to kerogen, bitumen and petroleum. Whereas previous sections have addressed the measurement of the changes in this organic matter, here we will examine the processes and

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concepts which result in the formation of oil and gas. In general, our comments here apply to both conventional (expelled) oil and gas as well as to oil and gas generated and retained within source-rock reservoirs. In practice, petroleum source rocks can be described according to the quantity, quality and thermal maturity of their organic matter, and according to the diagenetic, catagenetic and metagenetic changes that occur to the organic matter post-deposition. In the following, we address each of these in concept. Later in this review we discuss applications of these concepts in source-rock reservoir exploration. Organic matter quantity, quality and maturity The concentration of organic matter in recent sediments is controlled by original biotic productivity in the water column or on land, and by preservation of this material once it reaches the sediment column. Productivity and preservation are, in turn, controlled by the oceanographic conditions under which the organic matter was created, deposited and preserved. Productivity is a function of (a) sufficient light intensity for photosynthetic processes to occur, (b) favorable climate, (c) water chemistry (e.g., pH, Eh, sulfate concentration), and (d) availability and distribution of nutrients from decaying organisms, continental runoff, or upwelling (especially phosphorus and nitrogen). The importance of nutrient availability is often underestimated. For example, wind-blown iron has been shown to be of particular importance in initiating phytoplankton blooms (Boyd, 2007). This gives additional value to paleogeographic modeling of plate position and paleoclimate with a view to identifying areas of greatest productivity. The depositional environment of the host sediments also affects productivity. For example, the productivity of organic matter in the photic zone of a shallow sea is relatively constant compared to deeper water environments where intermittent upwelling of nutrient-rich waters (e.g., eastern side of ocean basins) may affect productivity (Demaison and Moore, 1980; Pedersen and Calvert, 1990; Hunt, 1996). Preservation of organic matter in the recent sediment column depends on a different set of factors: (a) resistance of organic matter to degradation, particularly microbial degradation; (b) protection from oxidizing agents such as molecular oxygen as well as sulfate and nitrate anions; and (c) sedimentation rate, because rapid sedimentation limits the exposure of organic matter to chemical degradation. Early work by Demaison and Moore (1980), Waples (1985) and many others proposed preservation as the principal control on the concentration of organic matter in sediments. However, work in the Cretaceous Niobrara and Mowry formation source-rock reservoir plays of multiple US Rocky Mountain basins indicates that while the Mowry is a good, oil-prone source rock as a result of enhanced preservation, the younger Niobrara Formation is an equally good source rock because of enhanced productivity (pers. comm, J. Zumberge). From an empirical standpoint, most liquid-generating sourcerocks appear to have been deposited into dysoxic or anoxic bottom water conditions (Demaison and Moore, 1980; Hunt, 1996), or at least within anoxic microzones such as fecal matter encapsulation or surface adsorption onto mineral matter (Fowler and Kaneuer, 1986). The limited availability of oxygen in such environments enhances the preservation and subsequent accumulation of organic matter in sediments because it effectively restricts diagenetic changes to anaerobic processes. Such processes are less efficient in destroying organic matter, particularly refractory organic matter (Emerson and Hedges, 1988), compared to aerobic processes, and are limited by the availability of sulfate and nitrate ions in the water column and in sediments. The role of green sulfur

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Fig. 3. Conceptual biochemical and geochemical changes undergone by living organic matter (top) as it is preserved and condensed as kerogen and, under the influence of catagenesis and metagenesis, converts to oil, gas, and carbon residue. Diagram is heavily modified from Tissot and Welte (1984, used by permission of Springer).

bacteria and attendant aryl isoprenoids in identifying photic zone euxinia (PZE) (Summons and Powell, 1987; Grice et al., 2007) is important to such productive plays as the Bakken and Mowry in the United States. Once organic matter has been produced, delivered to the bottom of the water column, and preserved by burial, the chemical characteristics – or quality – of that organic matter and its thermal maturity control the nature of the petroleum it might generate. In essence, these chemical characteristics are a function of the combination of lipids, proteins, carbohydrates and lignins which comprise the organic matter (Fig. 3). The resulting sedimentary organic matter is comprised dominantly of the organic solventinsoluble material (i.e., kerogen) and will vary compositionally as a function of the distribution of these four biochemical components. Kerogens are commonly classified into three types, each of which is distinguished by its mixture of microscopically recognizable fragments of structured and amorphous organic matter (i.e., macerals). When thermally immature, the three kerogen types also have reasonably distinct ranges of H/C and O/C values. Fig. 4 shows

a typical distribution of these three organic matter types on a diagram generally referred to as a modified van Krevelen plot; a selection of macerals is superimposed on the plot. The chemical composition of the kerogen, and in particular its concentration of hydrogen-rich components relative to carbon-rich components, is the primary determinant of what hydrocarbon phase is generated from the source rock – i.e., oil vs gas (Tissot and Welte, 1984). Increasing time and temperature subsequently modify the kerogen and its associated organic components (in the direction depicted by the arrows in Fig. 4), in the process generally referred to as thermal maturation. Of these, temperature is the most important factor. The mass of generated bitumen (the organic solventsoluble counterpart of the source rock organic matter generated from the kerogen) is linearly dependent on time, and exponentially dependent on temperature (Barker, 1979). This combined effect of time and temperature results in the generation of petroleum – oil and gas, either as single or multiple phases – and ultimately in expulsion of petroleum from the source rock upon sufficient thermal maturity. Expulsion, discussed in greater detail later, can result in further compositional changes in the expelled fluids.

Diagenesis, catagenesis and metagenesis

Fig. 4. Modified van Krevelen diagram showing the positioning of selected individual macerals and the maturity-induced decline (arrows) in three types of organic matter (curved black lines).

Progressive burial of the sedimentary section proceeds in the direction of gradual (and incomplete) equilibration of source rock organic matter with its local and external environment. This equilibration is generally divided into three stages of organic matter modification – diagenesis, catagenesis and metagenesis (depicted schematically in Fig. 3) – each resulting in distinctive chemical and physical changes through time. The diagenetic process extends from the sediment/water interface to a depth corresponding with a temperature of approximately 70 °C (Hunt, 1979). Within this interval, diagenetic processes, including microbial activity, polymerize and condense biochemical compounds into kerogen precursors such as fulvic and humic acids (Fig. 3). Because substantial amounts of CO2, H2O and NH3 are lost from the organic matter at this stage (Tissot and Welte, 1984), kerogen evolution can be monitored by measuring the decrease in atomic H/C and O/C ratios on a van Krevelen diagram or the

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decrease in pyrolysis-derived hydrogen and oxygen indices (as proxies for H/C and O/C ratios, respectively) on a modified van Krevelen diagram. This decrease is shown in the direction of the arrows in Fig. 4. In addition to loss of these inorganic components at this stage, diagenetic processes also generate methane and trace amounts of ethane (Oremland, 1981) via microbial processes, and these often accompany the initially expelled depositional pore fluids during sediment compaction. The catagenetic stage of kerogen evolution results in the most significant generation of bitumen which, in turn, leads to the generation of petroleum in the source rock, and ultimately to expulsion from conventional source rocks (Fig. 3). The observed temperature range for catagenesis is approximately 50°–200 °C (Hunt, 1979, 1996), although it is noteworthy that not all kerogen types generate hydrocarbons at the same temperature range or catagenetic level. For example, resinite and sulfur-rich kerogens (Type II-S) may generate liquid hydrocarbons at lower temperatures due to structural and bond-strength considerations, respectively (Tannenbaum and Aizenshtat, 1985; Waples, 1985). Resinites consist of polymerized species which were initially thought to readily decompose during a de facto reversal of the polymerization process. However, later work by Lewan and Williams (1987) showed that liquid hydrocarbons generated in laboratory-based hydrous pyrolysis experiments on representative resinites are dominated by aromatic peaks, which show no resemblance to most conventionally sourced crude oils. These authors also showed that resinites did not generate their hydrocarbons at abnormally low levels of thermal maturity during laboratory pyrolysis. In contrast, sulfur-rich kerogens are now known to decompose readily at unusually low thermal stress levels, due to weaker bond associations and to the release of sulfur radicals – which enhances carbon–carbon bond cleavage in sulfur-rich kerogens compared to sulfur-poor kerogens (Lewan, 1998; Amrani, 2014, and references therein). The presence of acidic clays is also relevant to reactions occurring during the catagenetic stage. These clays, which are known to catalyze certain refinery reactions, initially were thought to catalyze bitumen formation from kerogen, and thus reduce the temperature at which bitumen molecules are cleaved from the parent kerogen. However, as discussed by Seewald (2003), subsurface water conditions can suppress clay catalytic activity, potentially minimizing the importance of clays as sites of enhanced catagenetic activity. Catagenesis is followed by the process of metagenesis (Fig. 3), which encompasses the chemical reactions occurring in the

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organic matter at temperatures of about 200 °C and higher (Hunt, 1979). In general, metagenesis is not commonly evaluated by petroleum geochemists, because most conventional economic accumulations have already formed by this temperature. The advent of exploration for source-rock reservoir plays, however, has resulted in a renewed interest in metagenesis, particularly with respect to generation and recovery of shale gas. The metagenetic formation of methane and pyrobitumen is now known to be important from a source-rock reservoir perspective (as discussed elsewhere in this review), both from the standpoint of direct resource appraisal as well as adsorption and retention of light hydrocarbons onto/into pyrobitumen (and high-maturity kerogen) surfaces. Metagenetic temperatures result in the intense alteration of kerogen, bitumen, and petroleum in the system, ultimately leaving no residual potential to generate hydrocarbons. Nevertheless, these same alterations result in the creation and preservation of pores within the organic matter, as noted previously. Although the question of intra-source-rock hydrocarbon storage is beyond the scope of this review, it is worth noting that enhanced understanding of metagenetic reactions will undoubtedly lead to enhanced understanding of the volume retention of hydrocarbons in these reservoir types. Cracking (to oil and gas and solid bitumen) of kerogen and subsequent migration As described earlier, the cracking of kerogen to bitumen and the subsequent expulsion and migration of hydrocarbons into more porous and permeable carrier beds and reservoir-quality rocks result in the formation of conventional petroleum deposits (Lewan, 1985; Hunt, 1996). Despite the importance of distinguishing bitumen generation from expelled oil generation (Fig. 5), the requirement for a bitumen intermediary is not always invoked (e.g., Miknis et al., 1987). Therefore, kerogen and bitumen products in the laboratory setting must be defined carefully (Burnham and Braun, 1990). Although it is straightforward to envision some amount of natural gas being formed directly from kerogen as a result of cleavage of methyl and higher moieties, the creation and particularly the expulsion of longer chain, saturate products is clearly more complicated because of the involvement of bitumen. As temperatures increase with subsidence, the transformation of (insoluble) kerogen to (soluble) bitumen – i.e., from metastable macromolecular kerogen to thermodynamically favored lower molecular weight compounds – occurs as kinetic barriers are

Fig. 5. Schematic representation of the dominant origins of oil and gas from source rocks (from Jarvie et al., 2007, used by permission of AAPG).

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overcome (Seewald, 2003). That is: bitumen is a thermal decomposition product of kerogen (Fig. 5). Initially, this most likely involves the breaking of relatively weak, non-covalent bonds (Lewan, 1987). The kerogen responds by contracting in volume as the liquid to semi-solid bitumen expands in volume, increasing pressure in areas locally adjacent to organic matter domains (Momper, 1978) – an observation with important implications for source-rock reservoirs. The volume and pressure changes resulting from bitumen generation causes gradients which result in the internal movement of liquids (and generated gases) along partings and into microporosity, fractures and other voids (Momper, 1978; Lewan 1987, 1993). Given sufficient organic carbon per unit volume, a continuous bitumen network will be formed (Lewan, 1987). Interestingly, while bitumen and many non-aromatic hydrocarbons > n-C10 are relatively insoluble in water, up to 15% water may be dissolved into bitumen (Amani et al., 2013), creating at least a partially waterwet bitumen. This dissolved water may then become a source of hydrogen as bitumen converts to natural gas and liquid oil (Miknis et al., 1987; Lewan, 1997). This conversion clearly involves the cleavage of covalent bonds. The availability of hydrogen likely favors free-radical reactions (over carbonium-ion mechanisms), which result in the observed predominance of normal alkanes over isoalkanes (Seewald, 2003, after Kissin, 1987). The essential requirement of water (readily available in the subsurface) for oil generation and expulsion has been shown experimentally by Lewan et al. (1979) using closed-system hydrous pyrolysis. In contrast, Blanc and Connan (1992) subsequently demonstrated that closed-system anhydrous pyrolysis does not generate a significant amount of expelled oil. Follow-on work (e.g., Hoering, 1984; Stalker et al., 1994) has clarified the role of water in supplying both hydrogen and oxygen to the formation of petroleum. Although there is general consensus among petroleum geochemists on the mechanisms of petroleum formation and the importance of subsurface waters in that process, expulsion and migration of petroleum from its site of generation are still subjects of active discussion. However, as often occurs, some of the earliest ideas have stood the test of time. In 1978, James Momper published a seminal paper which has wide applicability to current source-rock reservoir discussions of both generation and expulsion (Momper, 1978). His classic discussion of these processes yielded the summary phrase ‘‘Expulsion is a Consequence of Generation”, a conclusion that has been widely validated in the last three decades. A whole-phase expulsion mechanism has largely replaced alternate migration theories (summarized by Hunt (1996)) such as molecular diffusion, water/brine solution (Price, 1976) and micellar transport. While these latter mechanisms undoubtedly have a minor role to play, it is Momper’s (1978) original concept of expulsion ‘‘caused by” generation which is currently advocated by most petroleum geochemists. Momper’s (1978) pressure cooker analogy of expulsion following microfracturing of the host source rock (due to pressures generated by conversion of bitumen to petroleum) is directly applicable to generation of (natural) micro-fractures in sourcerock reservoirs. Petrographic analyses of Woodford Shale samples before and after hydrous pyrolysis also provide support for the existence of a relatively continuous bitumen network (Lewan, 1987) – a concept relevant to present-day liquids plays such as the Eagle Ford and Duverney (Stankiewicz et al., 2015). Early workers, particularly those studying petroleum generation along the Gulf Coast of the United States, often considered low concentrations of TOC (e.g. 0.5–1.0 wt%) in a thick potential source rock to be adequate for expulsion. In contrast, work by Lewan and others has shown that the conversion of kerogen to bitumen, and the subsequent internal movement of generated bitumen within a marine source rock, requires pre-generation TOC values to be at least 2 wt

% before sufficient pressures are generated to cause rock failure, microfracturing and petroleum expulsion in most lithofabrics. This is a critical observation in source-rock reservoir plays, wherein expulsion of petroleum from the source rock often need not be invoked. This distinction may imply that lower initial contents of depositional TOC may be acceptable when assessing organic matter quantity in a source-rock reservoir. Crude oil thermal stability – cracking (to gas) of kerogen, bitumen, oil and gas Reactions associated with thermal decomposition of kerogen, bitumen and oil to natural gas (Fig. 5) have been studied extensively as part of the overall effort to model gas generation from oil-cracking. These studies have encompassed questions about the thermal stability of oil in the subsurface, the role of water, pressure effects on oil cracking, and other aspects. Because of the relevance of crude oil thermal stability limits to ongoing unconventional plays involving black oils and condensates, particularly as interest in gas plays has been overshadowed by interest in liquids plays, we consider the question of crude oil thermal stability to be critical, and discuss it here at length. This section will provide a detailed review of our knowledge of the subject. Early research suggested that in-reservoir cracking of oil to gas is a complex, relatively rare phenomenon, and that the limit of oil stability in the subsurface is 150 °C (Barker, 1990). More recent work, however, suggests that oil may be stable up to and perhaps beyond 200 °C. A study of deep petroleum pools of the UK Central North Sea showed no evidence of significant in-reservoir cracking at temperatures as high as 174 °C, and perhaps even as high as 195 °C (Pepper and Dodd, 1995). Price (1995), using both natural datasets and laboratory data, concluded that very distinctive compound assemblages are concentrated during thermal destruction of hydrocarbons, and therefore the lack of such assemblages in solvent extracts of rocks at vitrinite reflectance equivalents as high as 2.5% Ro implies that destruction of C15+ hydrocarbons is not complete even at that high maturity level. Stable carbon isotope signatures (d13C) as well as methane volume percentages for highly mature gases of the Anadarko Basin (Oklahoma, USA) indicated that methane, rather than resulting solely from in-reservoir thermal destruction, was co-generated with C15+ hydrocarbons (Price, 1995). Additional research over the past two decades and the compilation of large thermal datasets have moved the upper temperature limit of petroleum stability to higher and higher values. Current empirical values are summarized by Waples (2000), and studies providing anhydrous and hydrous pyrolysis evidence for higher values are described in the following paragraphs. Much of the research on the thermal degradation of oil has involved laboratory experiments under anhydrous conditions, and various pyrolysis experiments of this type have evaluated the upper thermal stability limit for oil. Behar and Vandenbroucke (1996) investigated anhydrous thermal cracking of n-C25 to develop kinetic parameters and determine the rate at which that compound degraded. Extrapolation of their kinetic parameters to geological conditions suggested that n-C25 starts to degrade above 180 °C when residence times exceed 10 million years. The implication here, assuming that these laboratory experiments speak to natural conditions, is that n-alkane-rich reservoired oil will be stable under unusually high temperature conditions. Horsfield et al. (1992) and Schenk et al. (1997) pyrolysed oils under non-isothermal anhydrous conditions. Results indicated that the C15+ fraction began to crack first, resulting in formation of C1–5 and C6–13 fractions. The C6–13 fraction ultimately cracked to methane and pyrobitumen. An important result of their research was to document the increased paraffinicity of the residual oil

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before n-alkane cracking commenced. After n-alkane cracking was initiated, the residual oil became increasingly aromatic. These results are currently being evaluated in light of present-day liquids plays involving source-rock reservoirs. In a thermal stability study touching on several thermal processes and applicable to lacustrine source-rock reservoirs, Pan et al. (2012) examined the relationship between pyrobitumen, oil cracking, and gas generation via a series of confined, gold tube, pyrolysis experiments. These authors pyrolyzed a solid bitumen extracted from Eocene lacustrine source rocks to generate a pyrobitumen, which was subsequently subjected to further pyrolysis at temperatures up to 600 °C. Experiments were also conducted using an oil from China, and with various combinations of the oil and the P pyrobitumen. Their results showed that the C1/ C1–C5 ratio – i.e., the gas dryness – was significantly higher in the experiment involving both oil and pyrobitumen in the gold tube. We suggest that these results imply a surface effect whereby thermal scission reactions occur while components are adsorbed onto pyrobitumen surfaces. Although the true importance of these results to source-rock reservoir geochemistry is unclear as yet, it is evident that focused work is needed to understand chemical reactions occurring on the surfaces of organic matter at elevated temperatures and pressures. While many crude oil thermal stability studies have involved anhydrous conditions (or, more accurately, laboratory setups in which water is not added by the researcher to the reaction vessel prior to heating), hydrous conditions have often been used (e.g., Curiale et al., 1992), and have yielded different results – often including higher temperature stability limits. For example, results from an isothermal, closed-system hydrous pyrolysis experiment using an oil produced from Sarukawa Field in northeastern Japan suggested secondary cracking temperatures under geologic conditions as high as 190–230 °C (Tsuzuki et al., 1999). This upper thermal limit is substantially higher than observed by most other workers. In general, early research in the 1970’s and 1980’s had already demonstrated the importance of water in understanding oil cracking mechanisms. As alluded to earlier, during decomposition of source rock bitumen Lewan (1992) showed that hydrous pyrolysis produced significantly more H2 and CO2 gas when compared to ‘dry’ experiments, and also inhibited the coking of aromatics within the oil. Furthermore, products from hydrous pyrolysis experiments are similar to those encountered in natural environments. Earlier, Bjoroy et al. (1988) had used three oils generated from Type I, II and III kerogens to conduct oil cracking experiments in the presence of water. Each oil was heated up to 8 days at temperatures up to 370 °C. As expected, with increasing time and temperature the amount of C15+ material cracking to C15 hydrocarbons also increased. More interesting, it was found that branched and cyclic compounds reacted faster than n-alkanes, with the residual oil becoming more aromatic. Furthermore, NSO and asphaltene fractions of the oil generated a hydrocarbon-rich, oil-like set of products – a finding that likely has significant relevance in understanding the high temperature generation of condensates in liquids-rich unconventional plays. More recently, experiments on the role of water in oil-cracking and gas generation were conducted by Shuai et al. (2012) using a Tarim Basin (China) oil. Gold tubes were filled with 8 mg of oil or a combination of 8 mg of oil and 120 lL of H2O, and the tubes were pyrolyzed at 350 °C and 50 MPa for 48, 96, or 192 h. Interestingly, gas yields from the experiments which used both oil and H2O in the tubes generated 1.8–3 times C1–5 gas when compared to the amount generated during anhydrous experiments, establishing once again the importance of water in these laboratory reactions (cf. Siskin and Katritzky, 2001; Katrizky et al., 2001). Hill et al. (1996) investigated the influence of pressure (as well as temperature) on gas, liquid and solid products of the C9+ fraction

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of a saturate hydrocarbon-rich Devonian oil from the Western Canada Sedimentary Basin. Sealed gold tube pyrolysis was employed at 350, 380, and 400 °C for 72 h with pressures ranging from 90 to 2000 bar. When experimental results were extrapolated to geologic conditions, pressure effects on oil cracking were observed to be of secondary importance to temperature. Nevertheless, although methane showed a nearly 2‰ change in carbon isotope ratio with increasing pressure up to 1380 bar, ethane and propane showed no detectable isotopic change with pressure. Their work showed that n-alkanes are generated, at least in part, from heavier molecules at 350 and 380 °C. In addition, at 400 °C n-alkanes were cracked more rapidly than they were formed, resulting in the net formation of hydrocarbon gases. Later work by Hill et al. (2003) determined that oil cracking results in considerable overlap of product generation and product cracking, and supported thermal stability of the oil up to 200 °C. Gold tube pyrolysis of a natural saturate hydrocarbon-rich Devonian oil in confined, anhydrous conditions demonstrated that the C15+ fraction cracked to form C6–C14 and C1–C5 hydrocarbons, as well as pyrobitumen, with increasing thermal stress. Oil cracking products accumulated when the rate of generation of any product is greater than the rate of removal by cracking, or when the product is a stable end member under their experimental conditions. Like Hill et al. (2003), Wang et al. (2006) used confined, dry gold tube pyrolysis – in their case to study the thermal stability of a Paleozoic marine oil from eastern Tarim Basin, NW China. At geological heating rates, the onset of oil generation was calculated to be 148–162 °C for initiation of cracking, and it reached completion at 245–276 °C. This oil showed far higher (experimental) thermal stability than observed from experiments of other workers, and Wang et al. (2006) note that their observations could affect exploration decisions for residual oil reservoirs in high-temperature geological settings. This conclusion, of course, presumes specific model characteristics in order to extrapolate their laboratory temperatures to geologic conditions. Also using sealed gold tubes, Tian et al. (2008) conducted experiments whose results generally agree with those of Hill et al. (2003): gas cracked from oil is wet until the wet components (C2–C5) begin to crack due to high levels of thermal stress. Tian et al. (2008) suggest that the potential of gas accumulation from oil cracking in original petroleum reservoirs has been underestimated using conventional kinetic models. They divided the oil cracking process into two stages, a primary stage with predominant C2–C5-containing wet gases, and a secondary stage where wet gases were cracked to methane and carbon-rich pyrobitumen residues, processes which led inevitably to increasingly dryer gas. Their kinetic model shows that initial oil saturation, temperature–pressure gradients and geological ‘‘openness” control the accumulation of gas cracked from oil in original petroleum reservoirs. Under their experimental conditions, most gas will be preserved to quite high thermal levels. In an effort to understand mineralic influences, Pan et al. (2010) conducted gold tube pyrolysis experiments to study the effects on oil cracking in the presence of calcite and montmorillonite. The tubes were heated at 2 °C/h and 20 °C/h to a final temperature of 600 °C. Each tube was filled either with oil, oil plus montmorillonite, or oil plus calcite. Their results demonstrated that the ratios of iC4/nC4, iC5/nC5, and the amount of i-butane and n-butanes were significantly higher in the oil-plus-montmorillonite experiments than for the oil alone. At low conversion values, the formation rates of CH4 and C2–C5 hydrocarbon gases were very similar in all three experimental protocols. At higher conversion values, the formation rates of CH4 and C2–C5 gases were relatively lower in the calcite experiment. In addition, they determined that carbon isotopic fractionation during methane formation was reduced in both the calcite and montmorillonite experiments. This observation is

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interesting in light of the work of Hill et al. (1996), who observed significant isotopic fractionation effects in methane-only experiments. The results of these laboratory studies, while not entirely consistent, tend to confirm maximum temperature limits established through empirical means (Waples, 2000, and references cited therein). At the same time, however, as is clear from the discussion above they also establish numerous inconsistencies in experimental results, and natural influences which have not been considered in these experimental protocols. For example, some researchers suggest that a catalytic influence involving reservoir minerals matters (e.g., Pan et al., 2010, as noted above), or that substantial gas generation may actually result from complex geocatalytic reactions involving the decomposition of long-chain hydrocarbons. Such reactions may result in enhancement or retardation of product generation, depending upon the oxidation state of hydrocarbon species in aqueous solutions (Seewald, 2001). Our discussion of oil thermal cracking studies, though extensive, is not comprehensive, and as noted, inconsistencies abound. Nevertheless, an understanding of natural cracking dynamics and product ranges will be crucial in understanding the origin of hydrocarbon components in liquids-containing source-rock reservoirs. The focus on extensive exploration for these reservoirs provides a strong economic incentive to obtain a more complete understanding of thermal (and catalytic) cracking to produce oils, condensates and gases, and we anticipate continued research in this area for some time to come. Expulsion – compositional changes upon migration and efficiency/ retention considerations It has been accepted for decades that systematic changes in petroleum composition occur during petroleum expulsion from the source rock (primary migration) followed by movement through carrier beds (secondary migration) (e.g., Day, 1897, as discussed by Krooss et al. (1991); see also Fig. III.3.2 of Tissot and Welte, 1984). Primary migration preferentially results in expulsion of a high percentage of saturate and (to a lesser extent) aromatic hydrocarbons out of the source rock, with consequent relative enrichment of heterocompounds (nitrogen-, sulfur-, oxygencontaining) and asphaltenes remaining in the source rock. For the purposes of this review, a key question is the importance of these migration findings to exploration for source-rock reservoirs. In their classic study, Leythaeuser et al. (1984) studied two interbedded shale-sand sequences from Spitsbergen Island, both at approximately mid-oil window thermal maturity level. They noted that thin shale beds and the edges of thicker shales interbedded with sands were more depleted in petroleum-range hydrocarbons than thick shale units. Effects related to both primary and secondary migration were noted: primary migration resulted in more effective expulsion of shorter-chain n-alkanes compared to higher homologues. Pristane and phytane were expelled to a lesser degree (50%) than their n-C19 and n-C20 straight-chain isomers. Expulsion efficiencies for C15+ saturated hydrocarbons ranged from 80% around C15 to zero at C25+. Expulsion calculations for total C15+ soluble organic matter (more comparable to whole oil) were much lower and averaged only 23%. Leythaeuser et al. (1984) explained their expulsion results by adsorption/desorption processes leading to chromatographic separation, resulting in both molecular size and steric separation. This study, a key to much future thinking on the subject, has obvious relevance to liquid-dominant source-rock reservoir plays, where migration within the source-reservoir could yield dramatically different compositional profiles. The analogy to laboratory chromatographic separation has led to the application of the term ‘‘geochromatography” as a

description of observed primary (in-source) and secondary (post-source rock expulsion) migration changes (e.g., Seifert and Moldowan, 1981). Krooss et al. (1991) reviewed the subject and proposed the following definition of a geochromatographic system as applied to natural systems: ‘‘Two or more immiscible phases, one or more of which are stationary phases and at least one of which is a mobile phase”. They observe that few workers have considered the theoretical aspects and quantification of geochromatography, and we note that this is still the situation, more than twenty years later. Clearly, a continuing challenge is to separate the combined effects on migration caused by kerogen type, thermal maturation history, microbial alteration, water washing and fractionation, and workers continue to try to reproduce the oil and compositional trends documented in natural systems (e.g., Seewald, 2003). Chromatographic separation will occur if solute molecules of different types (e.g., saturate hydrocarbons, aromatic hydrocarbons, resins and asphaltenes) interact with the stationary phase which, in the natural system, is either kerogen or fine-grained mineral matter present in carrier beds. Krooss et al. (1991) discuss four types of such interactions: (1) adsorptive effects (molecular adsorption onto solid phases) such as those observed in studies of steranes and sterenes – tetracyclic hydrocarbons found in most oils (Carlson and Chamberlain, 1986; Seifert and Moldowan, 1981); (2) partitioning of non-polar compounds into kerogen and sorbed hydrocarbon phases; (3) ion exchange processes such as those involving carboxylic acids interacting with mineral surfaces (Barth et al., 1988); and (4) size exclusion – for example, claystones acting as semipermeable membranes for petroleum moving through them (this effect is likely to be more active during primary rather than secondary migration; Krooss et al., 1991). Additionally, asphaltenes may precipitate along migration pathways, resulting in further fractionation, as well as molecularly-selective surface adsorption. Analogs of multiple types of chromatography employed in the laboratory have been observed in natural systems (e.g., gas–solid chromatography involving a gas phase during primary migration). However, Krooss et al. (1991) and others have considered fractionation that is conceptually analogous to liquid–solid chromatography to be dominant (though not exclusive). This analog is in general agreement with experimental and observational results discussed above, and would produce fractionation at the compound class-level (saturate, aromatic, NSO) as well as isotopic fractionation (discussed by Bonilla and Engel (1986)). Several studies have addressed the application of these adsorption–expulsion concepts to source-rock reservoirs (e.g., Cornford et al., 2015). Cheng and Huang (2004) studied the selective adsorption of C1–C6 hydrocarbon gases on adsorbents at 26 and 80 °C, under pressures of 1, 2 and 3 atm. While the selectivity for adsorption was mainly due to variations in vapor pressures of the gases, absolute adsorption levels for coal and oil shale organic matter were greater than they were for kaolinite and montmorillonite, and increased from C1 to C6. Interestingly, adsorption was also greater for n-C4 and n-C5 than for i-C4 and i-C5. It must be noted, however, that these authors observed considerable variation in their results. Several workers have modeled the migration of hydrocarbons, and modeling fluid movement within source-rock reservoirs has become a popular approach to assessing the history of organic matter development. Although modeling results are not fully in scope for this review, we cite one example here because of its

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direct applicability to liquids-dominated source-rock reservoir plays. Baur et al. (2011) examined the well-characterized Jeanne d’Arc basin, offshore Newfoundland, Canada, leveraging existing (‘‘ground truth”) geochemical knowledge of the basin, and taking advantage of the fact that this basin likely has only a single mature source rock. They applied four flow-modeling methods – Darcy, flowpath migration, hybrid, and invasion percolation – as migration analogs. Their results indicated that the hybrid approach of Hantschel et al. (2000), which combines Darcy and flowpath migration, yielded the best model results when compared to known accumulation data. All models predicted that the transformation ratio of kerogen to hydrocarbons averaged 67% basin-wide. Other results of Baur et al. (2011) were also quite interesting, particularly in light of current source-rock reservoir exploration efforts. For example, expelled hydrocarbon volumes were surprisingly high – up to 99% of generated hydrocarbons – while accumulated (trapped) volumes of expelled hydrocarbons ranged from 4.5% for the hybrid model to 40% for the Darcy model. A further contribution of this study, one of potential use in source-rock reservoir exploration and development, is the conclusion that adsorption capacity is reduced with increasing source rock maturity. This result appears inconsistent with our knowledge of recovered volumes from some liquids plays (e.g., the Eagle Ford), although it may be somewhat closer to the realities observed in so-called hybrid plays such as the Bakken Shale system.

Geologists, geochemists and engineers have evaluated organic matter characteristics in source-rock reservoirs of all established and developing plays, and an extensive literature is available containing organic matter data and their interpretation. Standard source rock assessment and maturity evaluation methods have been applied in source-rock reservoir plays of North America (Martini et al., 2003; Ridgley et al., 2006; Mancini et al., 2006; Totten and Oko, 2007; Jarvie et al., 2007; Repetski et al., 2008; Mukopadhyay, 2008; Novosel et al., 2010; Kornacki et al., 2010; Zumberge et al., 2012; Little, 2012; Thornhill, 2012; Illich et al., 2013; Newman et al., 2013; Thul and Sonnenberg, 2013; Cardott, 2013, 2014; Tilley and Muehlenbachs, 2013a; Romero-Sarmiento et al., 2013, 2014), Europe (Poprawa, 2009; Zdanaviciute and Lazauskiene, 2009; Bernard et al., 2012a; Kuchinskiy, 2013; Rippen et al., 2013) and Asia (Lopatin et al., 2007, 2008; Wang et al., 2013; Hui et al., 2013; Hao et al., 2013; Cong et al., 2013; Tang et al., 2013). More recently, our knowledge is expanding rapidly in the nascent source-rock reservoir plays of Australia (Ahlbrandt, 2010; Wilkinson, 2010; Menpes et al., 2013), Africa (Bada et al., 2011; Melo and Lakani, 2012; Dittrick, 2013), and South America (Legarreta and Villar, 2011; Nawratil et al., 2012; Williams et al., 2014). In the sections that follow, we review some of this published work at the fundamental level – depositional settings; organic matter assessment – and address open questions, including potential age limitations for source-rock reservoir plays and migration limits for these reservoir types.

Source-rock reservoir organic matter

Source rock depositional settings

Overview

Depositional conditions conducive to source rock development, as discussed above for conventional source rock development, are identical to the conditions required for development of source rocks in source-rock reservoir plays. Thus, concepts discussed earlier – nutrient influx, minimal bottom water oxidation, stagnant or low-current oceanic or lacustrine bottom waters – are keys to understanding source-rock reservoir development at the regional and play scales. In the following, we review studies that have translated these concepts into practice in source-rock reservoir plays. Few workers have examined and modeled the depositional setting of specific source-rock reservoirs at the regional scale, although past work on conventional source rocks has made it clear that TOC is a strong function of facies. Baumgardner and Hamlin (2014) have shown a strong TOC-facies relationship for sourcerock reservoirs of the Wolfberry Play in West Texas, with siliceous mudrocks containing the highest concentrations of organic matter. In general, local variations in depositional conditions, such as the distribution of bottom water anoxia, are known to result in significant lateral and stratigraphic variations in organic composition, as observed in practice in the Vaca Muerta shale of Argentina (Williams et al., 2014) and elsewhere. Wang and Carr (2013), in an extensive study of facies distributions in the Marcellus Formation of the Appalachian Basin, presented a conceptual organic matter depositional model. Their findings suggest that water depth and the distance from land to the deposition site are significant controls on fundamental parameters such as sedimentation rate, including the sedimentation rate of organic particles. Such approaches require parameterized organic matter depositional modeling, either via first principles (Tyson, 2001; Knies and Mann, 2002; Mann and Zweigel, 2008; Felix, 2014) or plate configuration/paleoclimate deductions (Parrish, 1982; Kruis and Barron, 1990; Bohacs and Fraticelli, 2008; Roscher et al., 2008; Bohacs et al., 2010), as well as validation using robust datasets. Although exploration for source-rock reservoirs occurred initially – and continues dominantly – in marine source rocks deposited under restricted circulation, source-rock reservoirs have now

Our understanding of the character and distribution of organic matter in source-rock reservoirs grows out of our existing knowledge of bitumen and kerogen in source rocks of conventional plays, and the processes involved in the generation of oil and gas. Previous sections have addressed this understanding from a conceptual basis, and it is shown schematically in Fig. 5 (Jarvie et al., 2007). Stepwise, thermally-induced cracking of kerogen to bitumen to oil, and thermal cracking of kerogen, bitumen and oil to thermogenic gas, are the fundamental sourcing processes of petroleum, and various permutations of these processes are responsible for almost all of the known commercial petroleum in conventional and unconventional deposits. In this and following sections we shift from concept to practice, and discuss how our origin-ofsource-rocks knowledge has been applied in studies focused explicitly on exploration for source-rock reservoirs. As massive unconventional gas shale development began in the Barnett Formation of the Fort Worth Basin, and spread worldwide from there, well-understood, rapid and inexpensive analyses were initially applied, and often over-applied, to describe these ‘‘new” reservoirs. The initial emphasis was on methods such as TOC, Rock–Eval and vitrinite reflectance, and extraordinary amounts of geochemical data were collected. Indeed, we estimate that the amount of these data collected for source-rock reservoirs in the past decade already approaches that collected since the 1960s from all source rocks of all conventional plays. After their utility for source-rock reservoir exploration and development was established, it soon became apparent that many unknowns remained, most of which related to our understanding of disseminated solid organic matter in source-rock reservoirs at the micro and nano scale. This recognition moved the geochemical study of sourcerock reservoirs beyond the simple accumulation and interpretation of TOC, Rock–Eval and vitrinite reflectance data. In this section, we review our knowledge of sedimentary organic matter in sourcerock reservoirs as reflected in published developments over the past two decades, with an emphasis on the remaining unknowns.

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been identified in organic-rich sedimentary rocks of all major depositional settings. As source-rock reservoir exploration spread from the basins of the central and eastern United States to elsewhere in North America and worldwide, interest in organic-rich lacustrine settings increased (Katz and Lin, 2014). Longunderstood inherent differences between hydrocarbon generation from fresh water algal-rich (and bacteria-rich) units and marine mixed algal/terrigenous units were examined. Martel (2013) emphasized the higher amount of hydrocarbon-generative organic carbon (relative to typical marine depositional settings) in the organic-rich lacustrine Frederick Brook shales of New Brunswick, Canada, inferring that TOC requirements in lacustrine sources may not be as high as those in marine sources. We note, however, that exploration for source-rock reservoirs in lacustrine units, while favorable from an organic matter type standpoint, may not be favorable from a mechanical standpoint (i.e., brittleness), particularly in extremely organic-rich intervals, although much uncertainly remains in this area. Nevertheless, several workers have examined lacustrine units as possible source-rock reservoirs. Legarreta and Villar (2011), in a wide-ranging survey of Argentinian sedimentary basins, identified multiple lacustrine units in multiple basins as possible shale plays. Mid-oil window liquids potential has also been documented in lacustrine shales of the Triassic Yanchang Formation in Ordos Basin (north-central China), where TOC values up to 7% are observed and organic matter is dominantly sapropelic-exinitic (Tang et al., 2013), and Rippen et al. (2013) has examined molecular distribution in Cretaceous Wealden black shales of northern Germany. The algal material in these lacustrine shales shows organic petrographic evidence for maturityinduced conversion into a solid bitumen network (with unknown effects on organic matter porosity development), potentially making these units, with increased maturity, viable gas shales. Given the organic-rich character of many lacustrine units, efforts such as these will undoubtedly continue. Age considerations – are there age limits to unconventional plays? Interest in source-rock reservoirs occurred initially in Late Paleozoic sections (Montgomery et al., 2005; Leonard et al., 2008; Zhao et al., 2007; Illich et al., 2013) and later spread to Mesozoic sections (Kornacki et al., 2010; Legarreta and Villar, 2011; Bernard et al., 2012a; Gentzis, 2013). As interest expanded, and particularly as the industry majors entered the fray, younger (Cenozoic) and older (pre-Late Paleozoic) sections were evaluated. Geochemically-based investigations of source-rock reservoir potential eventually encompassed the remainder of the Phanerozoic, with interest in the Neogene (Nia et al., 2013) and Paleogene of western North America (Lewan et al., 2014), the Devonian and older sections of North America (Martini et al., 2003; Curtis et al., 2011; Dong and Harris, 2013; Milliken et al., 2013; Cardott, 2013, 2014; Lash, 2013; Marcil et al., 2013; Thornhill, 2013; Bowman and Mukhopadhyay, 2014), and the Silurian shales of eastern Europe and China (Zdanaviciute and Lazauskiene, 2009; Poprawa, 2009; Chen et al., 2011; Kuchinskiy, 2013). Although interest in source-rock reservoirs began in, and remains focused on, the Late Paleozoic, it is now clear that there is no reason in principle why reservoir age should limit future exploration efforts. Given adequate thermal maturity and proper lithology, it is likely that Cenozoic sections (e.g., the Monterey and Kreyenhagen formations of California, USA), Mesozoic sections (e.g., Montney and Doig formations of the Western Canada Sedimentary Basin) and Proterozoic sections (e.g., the Neoproterozoic rocks of Oman, Pakistan, and elsewhere) will receive continued attention. Indeed, section age for source-rock reservoirs will be no more a limiting factor than it was for source rock and reservoir pairs connected by conventional migration pathways.

Source rock assessment The nature of the organic matter in source-rock reservoirs is a fundamental component of a successful play. Quantity, quality and maturity of the organic matter in the source have been examined in all major unconventional plays, and numerous correlations have been established between these parameters and play success. In this sub-section we examine again the quantity, quality and maturity of organic matter in source rocks, this time from a less conceptual and more practical standpoint; here, we evaluate these relationships as they exist in current and developing source-rock reservoir plays. As apparent above when discussing analytical approaches and organic matter deposition into recent sediments, there is no universally accepted terminology for the classes of organic matter in source-rock reservoirs. Previous sections of this review have focused on conceptual definitions. For the remainder of this paper we must use more explicit definitions – definitions used in practice when evaluating source-rock reservoirs. Thus, we will use generally accepted procedural definitions for kerogen (sedimentary organic matter insoluble in common laboratory organic solvents, and generally microscopically separable into individual macerals), bitumen (sedimentary organic matter in source rocks that is soluble in common laboratory organic solvents), and asphaltene – colloidally dispersed molecules of molecular mass lower than kerogen and higher than maltenes (which are defined as nonasphaltenic bitumen). ‘‘Solid bitumen”, as distinct from ‘‘bitumen”, can be insoluble (in which case it is known as pyrobitumen, and the insolubility is induced thermally; Bernard et al., 2012b) or soluble (e.g., solid bitumens such as gilsonite), and is more homogenous than kerogen because it usually does not contain macerals. Asphalts, tars and other high-mass non-disseminated sedimentary organic material are normally classified as solid bitumen (Abraham, 1920) or migrabitumen (e.g., Fishman et al., 2014). Also from a practical perspective, it is important to note that despite phase implications in the definitions (e.g., ‘‘solid bitumen”), the phase of commercial source-rock reservoir products as they exist at the surface at standard temperature and pressure (STP; 25 °C, 1 atm) may or may not be the same phase that exists in the subsurface. For example, methane and ethane liberated by hydraulic fracturing and recovered in the gas phase are, in part, likely natural components of liquids or solids in the source-rock reservoir, either via solution of gas in bitumen or kerogen, or adsorption of gas via low-energy bonding with physical surfaces. Similar uncertainties apply to discussions of phase for the higher molecular mass organic matter associated with liquids plays. In the following sub-sections we utilize this more practical procedural terminology in reviewing published source-rock reservoir studies which investigate the quantity, quality and maturity of organic matter in the play. Quantity of organic matter in source-rock reservoirs The fundamental parameter in all source-rock reservoirs is the organic matter content, measured as total organic carbon (TOC; mass) and/or total organic matter (TOM; volume). As noted in the analytical section above, the literature on organic matter content in unconventional plays has focused on direct or indirect measurement, or estimation, of TOC or TOM. Recently, however, efforts have also been directed toward understanding depositional mechanisms and climate forcing as processes for enriching organic matter in sediments. Here we will discuss the use of TOC and related data as source-rock reservoir exploration tools. Minimal TOC needs and estimation of free hydrocarbons. As noted earlier, elevated initial TOC values must be accompanied by a minimal level of thermal maturity and an appropriate combination of

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kerogen maceral types in order to comprise a shale oil play, and an even higher level of thermal maturity in order to comprise a shale gas play. Initial/depositional TOC levels (i.e., when thermally immature) in successful shale gas plays range from 2% up to greater than 10%, with present-day values (maturity-dependent) in the 1–5% range (Jarvie, 2012a). Because the source-rock reservoirs in these plays contain almost entirely Type II kerogen, the same initial TOC levels are estimated for unconventional liquids plays (albeit at lower thermal maturity). Initial/depositional (or even present-day) TOC levels and present-day thermal maturity levels are dominant controls on the viability of shale gas plays. In contrast, the occurrence of flowable or moveable liquid hydrocarbons is a key factor in liquids plays. The amount of liquid hydrocarbon in fine-grained sedimentary rocks is often equated with the organic-soluble portion of the rock. However, that portion – the solvent-extractable organic matter – can be far greater than the amount of oil (not bitumen) that can flow following hydraulic fracturing. The latter value can often be estimated using pyrolysis techniques, including Rock–Eval. Jarvie (2012b), using concepts developed in the 1980s for assessing the commerciality of naturally fractured reservoirs, has used TOC measurements combined with Rock–Eval S1 yields to predict the potential for hydrocarbons to flow upon hydraulic fracturing. This empirical approach monitors the ‘crossover effect’ between TOC and S1 by computing the ‘‘oil saturation index” as the ratio of S1 to TOC (in units of mg/g and %, respectively) multiplied by 100; thus, ‘crossover’ occurs where this index is greater than 100 (see Fig. 6). The approach has met with success in several oil plays (e.g., Shuangfang et al., 2012), and is in use by a number of players seeking to understand its utility for specific plays. Assessment of depositional TOC values. Many source-rock reservoir plays are insufficiently developed to provide a useful understanding of lateral and stratigraphic variability in TOC, particularly at

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the spatial resolution necessary for derisking source-rock reservoir plays, and a few workers have addressed this issue (e.g., Harris et al., 2013; Hemmesch et al., 2014). For this purpose, determination of initial TOC – i.e., TOC established within a source rock at the time of its deposition – is of obvious importance. In these instances, modeling TOC from first principles and retrodicting TOC using past plate configurations and climates may serve as proxies for laboratory or downhole TOC or TOM measurement. Tyson (2001), Knies and Mann (2002), Mann and Zweigel (2008) and Felix (2014) have demonstrated numerical approaches for estimating likely values of primary productivity, carbon flux, and burial efficiency of organic matter, providing a basis for computing initial TOC. In contrast to such ‘local’ approaches, heavily parameterized general circulation climate models, sometimes accompanied by paleotidal modeling, can be executed against a plate, topography and bathymetry configuration set to assess the potential for organic matter deposition during specific past timeslices. This retrodictive approach has met with success in the evaluation of source rocks in conventional plays (Harris et al., 2006; Bohacs and Fraticelli, 2008; Roscher et al., 2008), and is poised for application to source-rock reservoir plays (Comer, 2008). Coupling of this paleoclimate approach with regional and megaregional influences on source rock deposition (e.g., emplacement of large igneous provinces – see Bishop et al., 2014) provides a full earth system approach potentially applicable to geochemical sweetspot identification and general understanding of source rock-reservoir plays. In addition to deduction of initial TOC from first principles, and retrodiction of depositional TOC from modeling endeavors, several workers have attempted to ‘backstrip’ the effects of thermal maturity on present day TOC. In this approach, an attempt is made to deduce starting TOC (and hydrogen index (HI), in some instances) based on existing nomograms relating TOC to maturity or on relationships between TOC and kerogen type or maceral distribution. Based on visual kerogen analysis, for example, Novosel et al.

Fig. 6. Example of the ‘crossover effect’ in which S1 (in units of mg/g) exceeds TOC (in units of %) in the Bazhenov Shale, West Siberian Basin, Russia (from Jarvie, 2012b, used by permission of AAPG). Empirical evidence suggests that oil in fine-grained sedimentary rocks will exhibit better flow characteristics at higher levels of ‘crossover’.

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(2010) estimate initial/depositional TOC values of the Haynesville Formation (northern Louisiana) to be in the 3–7% range across the play. Most such approaches have been developed for conventional source rocks, but the search for geochemical sweetspots in exploration for unconventionals have made them particularly relevant in mapping initial TOC in source-rock reservoir plays. An approach focused on source-rock reservoirs is shown in Fig. 7 (from Jarvie (2012a); see this reference for detailed use of this nomogram). Nomogram-based approaches such as this commonly depend on having a reasonably-sized database of measured values for use in back-testing (validating) the results. We emphasize that all approaches seeking to determine initial/ depositional TOC (or HI), while perhaps comforting to the explorationist, are heavily laden with assumptions, most of which are difficult or impossible to validate. Nevertheless, the importance of pre-drill identification of the most (initially) organic-rich part of a developing source-rock reservoir play means that efforts at retrodictive and computational determination of initial/depositional TOC will remain an important geochemical endeavor. Quality of organic matter in source-rock reservoirs Source-rock reservoir studies commonly examine the nature, using visual and chemical analyses, of the organic matter in the unit. Here we initially examine applications of organic petrographic and molecular approaches, and subsequently review the far more common (and far less reliable) use of Rock–Eval and related pyrolytic analyses for this purpose. Optical microscopic examination is our primary tool for assessing organic matter quality (also called type) in sedimentary rocks. The use of visual kerogen analysis (VKA) to inventory the distribution of macerals in source-rock reservoirs has revitalized organic

petrographic analysis for all play types in the petroleum industry. In addition, the known relationship between a kerogen’s maceral distribution and its density and chemical composition make VKA analyses critical in determining (respectively) total organic matter content from TOC as well as oil and gas types generated from a source-rock reservoir (Okiongbo et al., 2005; Strapoc et al., 2010; Mastalerz et al., 2012; Stankiewicz et al., 2015). Recent evidence that organic matter porosity varies with organic composition (Kuchinskiy, 2013), thermal maturity (Curtis et al., 2012, and references cited therein) and particularly maceral type (Fishman et al., 2012b) emphasizes the value of VKA, as does the ability of VKA to retrodict the depositional characteristics of thermally postmature organic matter. Zdanaviciute and Lazauskiene (2009), in an organic-rich Early Silurian section of western Lithuania, demonstrated that liptinitic components were the dominant macerals and that macerals associated with structured organic matter are rare. Because most of their samples were thermally immature or marginally mature, ‘‘typing” by Rock–Eval was also able to suggest a Type II character for this section, and allowed volumetric predictions of oil and gas to be made (via models). Tang et al. (2013), using VKA to establish organic matter type and oil-prone character, have shown that Triassic shales of the Ordos Basin may contain a viable liquids play, a conclusion supported by Rock–Eval analysis in these mid-oil window rocks. As noted in the previous discussion of analytical methods, the use of molecular analysis of pyrolyzates to assess lithofacies, organofacies and depositional setting has also been applied to source-rock reservoirs for evaluation of organic matter quality. In an elegant approach to determining the potential for shales to generate gas at high thermal maturities as a function of organofacies and depositional setting, Mahlstedt and Horsfield (2012) pyrolyzed

Fig. 7. Nomogram from Jarvie (2012a, used by permission of AAPG) providing an approach for estimating initial/depositional TOC given an estimate of initial hydrogen index (HI). Rock–Eval S2 pyrolysis yields (y-axis) are plotted against TOC (x-axis). Solid and dashed black lines are iso-HI lines. Red dashed lines show anticipated loss of TOC (downward) with increasing thermal maturity. Given an initial HI value, which can be determined either from the known maceral distribution or estimated from the distribution of measured HI values (perhaps as a function of thermal maturity), present-day TOC on the x-axis is backtracked up the appropriate red-dashed line until the estimate iso-HI (initial) line is encountered. A vertical drop to the x-axis provides initial/depositional TOC. See Jarvie (2012a) for more details. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

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various immature/low rank coals and organic-rich shales under closed conditions at up to 700 °C. The potential for late (‘‘secondary”) gas generation was observed to be a function of the aromatic/aliphatic ratio of the initial kerogen, with the greatest high-maturity gas generated from aromatic-rich Type III and Type III-hybrid kerogens, and the least from aliphatic-rich Type I and Type II kerogens. Their results appear counter-intuitive, given the known high-maturity gas yields of some Type II-rich source-rock reservoirs, although several of these play types contain a substantial Type III component in the kerogen. In any event, obvious uncertainties remain in all pyrolysis studies, including the applicability of Mahlstedt and Horsfield’s (2012) pyrolysis approach to the natural setting and the unknown effect of higher clay content (as an adsorption framework) on the whole-rock pyrolysis of the Type III and Type III-hybrid samples. Maturity of organic matter in source-rock reservoir plays Initial investigations of source-rock reservoirs focused on gas shales. This focus emphasized the importance of thermal maturity, and maturity-related studies are a key direction for many workers in the unconventional space. Despite the transition of emphasis from gas to liquid plays several years ago, studies utilizing maturity data to unravel the generation of oil and gas remain the most useful and cited in the published literature, for both gas and liquids plays. Although not strictly geochemically focused (and thus not a part of this review), much of the work relating to the development and type of porosity in the organic matter of source-rock reservoirs relies upon accurate and precise measurement of thermal maturity (Loucks et al., 2012a,b). Several workers have used both vitrinite reflectance (VR) and Rock–Eval Tmax values as maturity mapping tools in source-rock reservoirs and prospective source-rock reservoirs. The ubiquity of Rock–Eval pyrolysis measurements has provided many more Tmax values rather than VR values, and if the Rock–Eval measurements are properly filtered – e.g., to retain only Tmax values for samples having adequate S2 pyrolysis yields – then Tmax provides a useful maturity mapping tool for some kerogen types (Thul and Sonnenberg, 2013). An example for the Type II/III and III organic matter of the Mancos Shale in New Mexico, USA, is shown in Fig. 8, from Gentzis (2013). The general south/southeastward increasing maturity trend as depicted in Tmax data is consistent with other maturity parameters, and no relationship is observed between present-day burial depth and maturity level. Mapping thermal maturity trends in this fashion is a key task when evaluating all major source-rock reservoir plays. For examples involving vitrinite reflectance distributions, see Pollastro et al. (2007) as shown in Fig. 9 for the Barnett, and Cardott (2013) for the Woodford (although the reliability of some VR measurements in the Devonian is a concern – see Cardott et al., 2015, and references therein). VR and Tmax mapping remain important tools for sweetspot identification, particularly in shale gas plays, and accurate measurements are critical (Cardott, 2014; Cardott et al., 2015). Trends in parameters not commonly used as measures of thermal maturity have also seen application, particularly in postmature gas shale intervals. Jarvie et al. (2007) has summarized the spatial trend of hydrogen index for the Mississippian Barnett Fm (Fig. 10) demonstrating the strong correlation with the spatial trend of vitrinite reflectance for this interval. For example, compare the HI distribution in Fig. 10 with the VR distribution in Fig. 9. Although vertical (stratigraphic) variability in hydrogen index is commonly much greater than that for vitrinite reflectance, similar spatial patterns are commonly evident in such large-scale mapping. Although only a minor concern in conventional exploration, the productive limits set by thermal maturity are often critical in source-rock reservoir plays, and specifically in shale gas plays (Fig. 11). Over the past decade, values up to the 2% Ro range in

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the Barnett, and later the 3% Ro range in the Marcellus, have come to be accepted without hesitation. The practical upper limit for functioning gas plays will likely be set by product-related factors, such as increasing occurrence of carbon dioxide in gas developed at very high maturity levels, and mechanical and thermodiagenetic effects that destroy porosity and often relate to factors which cause high maturity. As gas shale plays develop worldwide, the commerciality of plays at maturity limits of 5% Ro and higher (e.g., the Permo-Triassic Karoo Group of South Africa – see Bada et al., 2011) will need to be evaluated. Evolution of organic matter with increasing maturity. The lateral variation in thermal maturity levels in many source-reservoir plays has resulted in a new level of awareness of thermal effects on hydrocarbon generation, often using techniques other than standard Rock–Eval Tmax or vitrinite reflectance (VR). Newman et al. (2013) and Edman et al. (2014), in a high-resolution study of the Bakken Formation in Parshall Field in northwestern North Dakota, used a variant of detailed VR analysis to show variability of oil generation, and likely oil composition, due to hydrothermal interaction. Their Vitrinite–Inertinite Reflectance and Fluorescence (VIRF) technique established that initial generation resulting from conventional (subsidence-induced) maturity was later supplemented by generation due to hydrothermal activity caused by igneous intrusions. Likewise, Bernard et al. (2012a), in a comprehensive geochemical and petrographic study of the Jurassic Posidonia Shale (northern Germany), present evidence for sustained heat from hydrothermal brines acting to supplement regional heat flow as a cause for maturity increases, and several others have observed evidence for hydrothermal activity in source-rock reservoirs (e.g., Rippen et al., 2013). Such changes can have a dramatic effect on the composition and phase of source-rock reservoir products, potentially causing the quality of well production to vary significantly over short distances. Repetski et al. (2008), in a study of the Ordovician-Devonian section in the Appalachian Basin – where VR measurements are uncertain or difficult to obtain – used conodont alteration indices (CAI) to establish maturity patterns. CAI maturity assessment, developed in the 1970s and normally used to determine thermal maturity levels at a local scale, were applied here on a megaregional scale, allowing product phase inferences (oil/condensate/gas) to be made in Ordovician sections. It is noteworthy that this was done without having to rely upon Rock–Eval Tmax values, which are commonly problematic in post-mature settings. Even in liquids plays where Tmax values generally remain within the oil window (430–465 °C), wide scatter is commonly observed in depth-Tmax plots. An example of this is shown in Marcil et al. (2013) for the Ordovician section of the Eastern Canada Anticosti Basin, where total reliance on Tmax values makes maturity zones difficult to delineate. Studies of source-rock reservoirs have also noted reductions in Rock–Eval S2 values following solvent extraction, along with consequential changes in Tmax (Collins and Lapierre, 2014; Zumberge et al., in press), and customized Rock– Eval heating programs have been proposed to discern, without prior extraction, the full extent of extractable organic matter during Rock–Eval pyrolysis (Romero-Sarmiento et al., 2015). Observations such as these stress both the utility and pitfalls of using Rock–Eval data to assess thermal maturity in whole-rock samples of source-rock reservoirs. Migration of fluids into and out of source-rock reservoirs Source-rock reservoirs are sometimes considered to be units from which petroleum no longer migrates, or migrates only minimally, and into which petroleum has not migrated. That is, it is sometimes considered that all petroleum movement within a

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Fig. 8. The distribution of Tmax values (°C) in the Mancos Shale of New Mexico (from Gentzis, 2013, used by permission of Elsevier). In this case, Tmax distributions are geologically reasonable, and generally consistent with other maturity parameters such as vitrinite reflectance. Note that the trends suggest a relative structural simplicity. (Black outline shows the primary study area. Note that the monotonic changes in this figure may result from the limited number of data points. Approximate scale is 1:160,000.)

source-rock reservoir consists of primary migration. However, on reflection it is clear that all liquids (and some gas) plays exist because past migration within and out of the source rock has not been 100% efficient – i.e., that the petroleum we recover via fracturing methods is a prior-generated fraction left behind following previous migration episodes. This retained portion – which, as noted earlier, can vary widely in quantity (Hunt, 1979; Tissot and Welte, 1984; Sandvik et al., 1992; Pepper and Dodd, 1995) – may even be supplemented by exogenous hydrocarbons, making correlative approaches important in understanding the genesis of both gas and liquids plays. Recent work on source-rock reservoirs also

emphasizes the importance of net loss of hydrocarbons from the system pursuant to pressure release accompanying uplift of the reservoir (Hao et al., 2013), an observation of volumetric importance when evaluating shale gas plays. Geochemical analysis of source-rock reservoir organic matter – using well-established correlation methods – provides an excellent approach to evaluating the supposed self-enclosed nature of these plays. Whereas some plays are considered self-enclosed (e.g., Barnett), others exhibit more of a hybrid character (e.g., Bakken), and environmental/aquifer studies have established the propensity of petroleum, particularly of gas, to migrate extensively – often

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Fig. 9. Barnett Shale, Fort Worth Basin, Texas, thermal maturity map, showing iso-vitrinite reflectance contours. A general west to east trend of increasing thermal maturity is evident, with anomalous zones thought to be caused by hydrothermal heating. Note limitations in maturity trend assessment arising from limited well control. From Pollastro et al. (2007, used by permission of AAPG).

vertically from the source-rock reservoir to the surface (Baldassare et al., 2014). This fugitive nature of petroleum, long recognized in conventional accumulations, has been addressed by many workers, and is established in recent studies investigating the use of remote

(surface) geochemical techniques as tools for source-rock reservoir exploration. Here we address these applications, and broadly discuss the self-enclosed nature of source-rock reservoirs with respect to migration of petroleum fluids.

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Fig. 10. Barnett Shale, Fort Worth Basin, Texas, hydrogen index (HI) map (from Jarvie et al., 2007). Note the similarity with the spatial distribution of vitrinite reflectance as shown from Pollastro et al. (2007) in Fig. 9. (County outlines in each map demonstrate the difference in map scales; used by permission of AAPG.)

Although migration out of a Type II source rock is accepted (and is the origin of most conventional oil plays worldwide), early development of shale gas plays largely proceeded under the assumption that all gas in the unit was self-sourced. Nevertheless, less than a decade ago the self-sourcing capacity of East Texas Bossier Formation gas was considered uncertain (Ridgley et al., 2006). Recognition of the highly fugitive nature of natural gas, as well as recent studies of the molecular and isotopic character of shale gases, now leads most workers to begin with the presumption that not all gas in

source-rock reservoirs is self-sourced. The less fugitive nature of crude oil, and its substantially lower expulsion factor, have led to the belief that the hydrocarbons in most liquids plays derive entirely from the source-rock reservoir, and we know of no claims to the contrary. However, hydraulic stimulation may inadvertently cause mixing of fluids: Ordovician-sourced oils have been produced from Devonian Woodford Formation laterals (J. Zumberge, pers. comm.). The use of various high-magnification imaging techniques on source-rock reservoir samples (e.g., electron microscopy) has

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Fig. 11. The evolution of product as a function of increasing thermal maturity of source-rock reservoirs. Note that initially solid organic matter – immature kerogen accompanied by soluble bitumen – ultimately yields large quantities of gas and smaller amounts of largely insoluble solids (e.g., pyrobitumen). (Modified after Bohacs et al., 2013, used by permission.)

opened new vistas in the study of organic matter migration in shales, at scales heretofore unimagined. Bernard et al. (2010), using scanning transmission X-ray microscopy, have demonstrated two distinct types of bitumen in a German mudstone sample – preoil solid bitumen and post-oil solid bitumen (cf. Curiale, 1986; Cardott et al., 2015) – each with its own migration characteristics. At the nanometer scale, the early-generative, pre-oil solid bitumen has migrated minimally, if at all, whereas the second bitumen type is most likely representative of the solid residue left behind postgeneration and post-migration. Although the scales of migration in both instances are miniscule relative to conventional sources and reservoirs, continued examination of petroleum movement at this scale ‘‘can be very valuable in understanding the role of solid bitumen in oil and gas generation” (Bernard et al., 2010, p. 130; Cardott et al., 2015), particularly as methods are developed to scale up porosity imaging to the centimeter scale and beyond (Curtis et al., 2014). Fluid isotopic evolution of gases with increasing maturity Shale gas plays represent a special instance of the interaction of maximal levels of thermal maturity with minimal levels of present-day hydrocarbon migration. This has been pursued in detail in several gas plays, primarily using stable carbon isotope data and observing their systematic variation with excessive maturity. In this section we will review the practical applications of this work, with emphasis on the general utility of compound-specific carbon isotope ratio analysis in assessing the history of the gases in source-rock reservoirs. Stable carbon isotopic compositions of natural gases have long been employed to determine the origin and thermal maturity of their source rocks (Chung and Sackett, 1979; Clayton, 1991; James, 1990; Schoell, 1980, 1983; Schoell, 1988; Stahl, 1977; Tang et al., 2000; and many others). The d13C value of natural gas and its components in individual reservoirs depends primarily on the initial isotopic composition of the organic matter (biota) from which the kerogen was derived (Stahl and Carey, 1975; Tissot and Welte, 1984) along with subsequent diagenetic modifications of the kerogen (Fig. 3), and secondarily on burial history, migration, mixing of gases from different sources with different maturities and other post-source and in-reservoir alteration processes. The mixing of microbial gases and thermogenic gases is a significant secondary effect, particularly in the Gulf of Mexico. Microbial gas formed during early stages of burial by methanogens is enriched in 12C and typically has light d13C1 (stable carbon isotope ratio of methane) values in the range of 110 to 60‰. (Schoell, 1980). With increasing subsurface temperatures, microbial activity decreases (with the exception of thermophiles) and eventually ceases (Wilhelms et al., 2001). In contrast, carbon isotope ratios

of methane in thermogenic gases range from 60 to 30‰ for wet gases and 40 to 15‰ for dry gases (Hunt, 1996). The importance of microbial gas as an admixture in shale gas plays is commonly and legitimately disregarded, although exceptions are known to exist (Martini et al., 2003) and others are likely yet to be encountered. As some readers may not be familiar with isotope dynamics, a brief summary is appropriate. Trends of alkane d13C values in thermogenic gases are primarily determined by the kinetics of natural gas generation from kerogen, bitumen, oil and condensate (Xia et al., 2013). Systematic changes in isotopic composition are determined primarily by the kinetic isotope effect (KIE), which results from differences in energy required for cleavage of 12C–12C and 12 C–13C bonds in the precursor organic matter and products (Tang et al., 2000). With increasing maturity, the KIE results in a more positive hydrocarbon carbon isotopic composition as the isotopically lightest material is cleaved off. The KIE is more pronounced for smaller molecules due to the larger relative molecular weight differences between their isotopologues. Two trends in compound-specific carbon isotopes in natural gases are considered ‘normal’, and derive from the KIE (Xia et al., 2013). First, d13C values of each gaseous HC component will become more positive with increasing maturity (Stahl and Carey, 1975; Stahl, 1977; Schoell, 1983; Whiticar, 1996). This trend is sufficiently consistent that it can be used to monitor increasing maturity of thermogenic gas (Xia et al., 2013; Hao and Zou, 2013), as validated by comparison with the increase of vitrinite reflectance of the source rock. More directly, we can also monitor maturity increase by the decrease in gas wetness, which we define here as % C2–5 = 100 * R (C2–C5)/R(C1–C5). Given similar organic matter types and reservoir conditions, gas wetness decreases monotonically with maturity at levels of Ro > 0.8% (Hill et al., 2003). The second ‘normal’ observed trend (Xia et al., 2013) in natural gas carbon isotope ratios is that d13C values are increasingly more positive with increasing carbon number, from methane (d13C1) to ethane (d13C2) to propane (d13C3). This trend is consistent at isomaturity levels (i.e., d13C1 < d13C2 < d13C3), and is observed in most natural gases worldwide (thus the designation ‘normal’). As we will see, both of these normal trends can become abnormal in the world of gas-filled source-rock reservoirs. Isotope reversals and rollovers – occurrence and origins Exceptions to the normal trends – i.e., so-called ‘isotope reversals’ as described below – were first observed in gases within source-rock reservoirs by Ferworn et al. (2008) and Zumberge et al. (2009). These occur most particularly in gases observed in very high-maturity source-rock reservoirs (Fig. 12), and several explanations have been advanced. For example, migration

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Fig. 12. Trend of d13C1 vs d13C2 variation for a set of gases. With respect to normal vs reversed carbon isotope ratios, the A–B line segment separates the gases with the expected isotope trend (above) from those showing a reversed trend (below). Note that although most of the Barnett gases are ‘normal’ in this respect, they fall on the rollover part of the wetness curve (see Fig. 14). Data are from multiple published sources discussed in this paper. Figure from Dai et al. (2014, used by permission of Elsevier).

accompanied by adsorption/desorption and diffusion is known to fractionate isotopes, and is a particularly intriguing potential explanation for reversals because organic-rich shale is known to be an effective hydrocarbon adsorbent, and diffusion is thought to play a role in gas flow through the shale micropore system (Passey et al., 2010). Nevertheless, not all isotopic reversal situations involve high-organic matter shales – for example, reversals have also been observed in organic-poor sandstone and carbonate reservoirs in the Ordos Basin (Xia et al., 2013). These observations suggest that fractionation caused by gas migration through shale cannot be the cause of all observed isotopic reversals (Xia and Tang, 2012), and more generally that a single explanation is likely insufficient for all observed cases. Indeed, Xia et al. (2013) concluded that unusual trends result from multiple indigenous

(secondary) mechanisms within the source rock itself – i.e., mechanisms other than primary cracking of kerogen. As will be developed below, these secondary processes are thought to result in conversion of oil, condensates and heavy gases to light gases, with resulting fractionation yielding products more enriched in 12C. In addition to these isotope reversals as recorded by Xia et al. (2013) and others, numerous authors have also observed anomalous relationships between the isotope ratios of individual gas components and the wetness of the gas – namely the anomalous decrease in component isotope ratios with decreasing wetness. Such phenomena are referred to as isotope rollovers, a term coined by Zumberge et al. (2012) in describing a reversal of the normal maturity trend of carbon gas isotopes in the source-rock reservoirs of the Barnett and Fayetteville formations. Definitions of both reversals and rollovers were proposed by Tilley and Muehlenbachs (2013b), although not all workers apply these definitions universally. Here we will use their terminology: full isotope reversal occurs when d13C3 < d13C2 < d13C1. We will refer to isotope rollover when the maturity trend of a single family of gases – as indicated by gas wetness – occurs such that the normal increase in the relative amount of 13C (becoming isotopically heavier with increasing maturity due to the KIE) ‘‘rolls over” as wetness decreases (and maturity increases) – i.e., selected gas components eventually become isotopically lighter with increasing maturity. The rollover phenomenon is most easily explained visually – see Fig. 13, where both ‘rollover’ and ‘reversal’ terminologies are used. Because many authors convolve these terms, it is important to emphasize, as do Tilley and Muehlenbachs (2013b), that from an isotopic perspective a gas may be in the rollover region of the isotope-wetness curve, but not reversed. Furthermore, a gas may be reversed, but not in the rollover zone. These distinctions are pursued and exemplified further by Zumberge et al. (2012). Before leaving this question of terminology, an additional distinction is noted. Isotope reversals are, by their nature, observed in isotopic analyses of gas components within a single natural gas sample. In contrast, isotope rollovers, to be observed in their entirety, involve isotopic analyses of numerous gases, ideally all of a single (source) family. Therefore, large datasets are necessary to observe the rollover effect (e.g., Fig. 13), whereas the reversal effect may be observed in the individual gas components of a

Fig. 13. Classic depiction of the carbon isotope rollover curve for source-rock reservoir gases. The ‘normal’ trend of increasing carbon isotope ratio with decreasing wetness (a direct measure of increasing maturity) is shown in the points plotted to the right. The rollover is evident for most Barnett and all Fayetteville gases. Data and figure from Zumberge et al. (2012, used by permission of Elsevier).

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single gas sample. An additional complication with respect to this terminology is that the very high maturity portion of the rollover curve is often referred to as the ‘reversed portion’, because of the decrease in carbon isotope ratio (usually of ethane) with increasing maturity (as measured by decreasing wetness). And as noted below, this is confounded yet further in some gas families where the reversal is reversed (!) to yield a normal isotope-wetness profile at extremely high maturities, as described at the end of this section. d13C reversals and rollovers are not commonly encountered in conventional petroleum exploration, where source rocks and reservoired fluids are separated by significant distances and migration and maturities are generally lower than in economically successful gas shale reservoirs. When observed in these conventional circumstances, these anomalies are often attributed to highly unusual occurrences, such as the abiogenic generation of natural gas (Sherwood Lollar et al., 2002, and references cited therein). When observed in gases within source-rock reservoirs (usually commercial gas shales), different unusual preconditions are invoked, and most of these involve – indeed, require – an elevated range of source rock maturities. Generally this range is from 1.5% to 3 + % Ro. Where a full range of oil and gas window maturities is present in a single family of gases, the full rollover phenomenon is often observed (Fig. 13). In contrast, if the lower maturity range is absent, often only the ‘‘reversal” portion of the range is evident (a situation observed, for example, in conventional Carboniferous reservoirs in eastern Sichuan Basin, China; Dai et al., 2014). Stable tectonics and long-lived traps, accompanied by short migration distances, generally favor the preservation of just the highmaturity (‘reversed’) portion of the rollover. As noted, both of these anomalous isotope trends are strongly associated with elevated thermal maturity levels; in general, source rock organic matter type and other considerations are not critical factors (Dai et al., 2014). Nor are such anomalies confined to gases in source-rock reservoirs. Indeed, isotope reversals have been reported in natural gas samples from both conventional and unconventional production, provided they are in close association with highly mature hydrocarbon source rocks. Examples have been noted by Seewald and Whelan (2005) in the Potato Hills gas field of southeastern Oklahoma, by Burruss and Laughrey (2010) in Silurian and Ordovician reservoirs of the Appalachian Basin, and by Tilley et al. (2011) in Permian and Triassic reservoirs of the Western Canada Sedimentary Basin. Numerous workers have proposed processes to explain isotopic reversals and rollovers in gases of source-rock reservoirs, and Hao and Zou (2013) have summarized these mechanisms. The earliest suggestions were proposed by Ferworn et al. (2008) and Zumberge et al. (2009) and later expanded by Zumberge et al. (2012). These authors identified rollover of iC4/nC4 (a ‘compositional’ rather than the now-classic isotopic rollover discussed above) and d13C2 and d13C3 in natural gases from the Barnett, Fayetteville and Marcellus formations (e.g., Fig. 13 for an example of the ethane carbon isotope trend), and attributed it to in situ cracking of C2+ gas components in most instances. Zumberge et al. (2012) also presented a preliminary interpretation of d13C2 reversal with respect to wetness involving mechanisms related to both generation and mass transport. They analyzed produced gases from the Mississippian Barnett Shale of the Ft. Worth Basin, Texas and the Fayetteville Shale of the Arkoma basin of Arkansas in which C2, C3 and CO2 showed both reversed and rolled over carbon isotopic maturity trends at thermal maturity levels greater than 1.5% VRE (vitrinite reflectance equivalent; Fig. 13), using gas wetness as a direct maturity indicator. The iC4/nC4 ratio is also rolled over, suggesting that wet gas cracking has occurred. Such cracking has resulted in the generation of more gas molecules in the same volume, leading to a practical observation: the cracking leads to

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overpressure, which has been shown to correlate with increased stabilized production rates in Barnett wells. Reaction between hydrocarbons and water at very high maturity may be another cause for isotopic rollover. Lewan (1997) and Price (2001) have shown that water-kerogen redox reactions are important in hydrocarbon generation, indicating that hydrous wet-gas cracking could account for isotopic rollover: H2 and isotopically light CO2 were generated by a water reforming reaction which occurred prior to H2 and CO2 reacting to form isotopically light ethane and propane. The proximity of the Ouachita Thrust with its associated hydrothermal fluids to the south (Bowker, 2007) may have enhanced the thermal maturity of the Barnett and Fayetteville by providing water necessary to generate isotopically light CO2 and H2 followed by formation of isotopically light C2 and C3. Hao and Zou (2013) believe that the proposed water– hydrocarbon reaction explanation of Zumberge et al. (2012) cannot account for co-variation of other parameters subject to the rollover phenomenon, including d13C3, iC4/nC4 and iC5/nC5 ratios. However, recent experimental work reproduced the rollover effect for the first time and showed the probable significance of water (Gao et al., 2014). Gold tube pyrolysis of isolated Type II kerogens with maturities between 0.7 and 1.4% Ro was carried out in the presence and absence of added water. Water had a pronounced influence on the composition, yields, and d13C1, d13C2, d13CCO2 and d2H of generated thermogenic gases. Methane, ethane and CO2 generated from the experiments with added water exhibited carbon isotope rollover, while the experiments without added water did not show this phenomenon. The rollover effect occurred at a calculated Ro of 1.49% for the least mature kerogen sample and at 1.65% for more mature kerogens. While there was insufficient generation of C3+ to address the conclusions of Hao and Zou (2013) noted earlier, more experimental work is needed to complement conceptual thinking. Numerous other explanations have been advanced to explain these isotopic data for specific plays. For example, Tilley et al. (2011) observed isotopic reversals in conventional Permian and Triassic reservoirs in the Western Canada Sedimentary Basin, suggested that these gases originated in shales and invoked simultaneous cracking of kerogens, oils and gases within a closed system. In contrast, Burruss and Laughrey (2010) observed complete isotopic reversals in gases from unconventional fractured carbonate and tight sandstone Ordovician and Silurian reservoirs in the Northern Appalachian basin, and attributed this to Rayleigh fractionation occurring during redox reactions at elevated temperatures and maturities (5% Ro). Xia et al. (2013) reviews the general concept of gas mixing as a mechanism for creating the observed reversals and rollovers (at least in high-maturity source-rock reservoirs), and ultimately proposes that isotope reversals are caused primarily by the mixing of gas generated from primary cracking (of kerogen) and secondary cracking (of bitumen and oil); this idea is presented in Fig. 14. Greater isotopic fractionation is expected during secondary generation than during primary generation. The activation energy for secondary generation is higher, causing its KIE to be stronger (Tang et al., 2000) and yielding a much more negative d13C value from secondary generation gas derived from cracking of oil and condensates. Furthermore, oil and gas condensate conversion, because of the cleavage of carbon chains, produces much larger amounts of C2 and C3 than (primary) demethylation of high maturity kerogen. Therefore the secondary gas is wetter and has more negative d13C values than primary gas generated at high maturity levels. As a result, in a mixture of primary and secondary gas at high maturity, methane is dominantly contributed from the former and ethane is dominantly contributed from the latter, yielding an isotopic reversal with respect to carbon number. Meanwhile, C2 (and C3) from secondary generation increases with maturity,

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Fig. 14. Conceptual schema for producing reversed and ‘‘rolled over” carbon isotope trends for gases in mature and postmature source-rock reservoirs. From Xia et al. (2013, used by permission of Elsevier).

Finally, it is noted that Dai et al. (2014) also examined hydrocarbon gases of extremely high maturity, and accordingly heavy carbon isotope ratios. Their samples include the Longmaxi shale gas of the southern Sichuan Basin, China, which has the heaviest reported d13C1 value and a reversed isotope trend (d13C3 < d13C2 < d13C1). A normal relationship was observed between the d13C1 and d13C2 values at extremely low wetness values, indicating a ‘‘post-reversal” stage occurring at extremely high maturity. They summarize observations from multiple studies in a single figure, reproduced here as Fig. 15. The first inversion point (wetness = 4.8%) may be the beginning of secondary cracking (Hao and Zou, 2013; Xia et al., 2013). The second inversion point (wetness = 1.2%) reflects the onset of extremely high maturity, and is interpreted to occur after the peak contribution of secondary cracking. Fig. 15 presents a summary of our present-day level of understanding with respect to reversed and rolled over carbon isotopic trends, absent further work on the role of water as shown by Gao et al. (2014). Future directions and unsolved problems

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bringing about a trend of d C2 reversal with respect to maturity (Fig. 13). Condensates dominate the hydrocarbon fluids in much of the Eagle Ford Shale, and occur in the Barnett Shale as well. Therefore it is reasonable to expect these condensates to serve as the precursor of secondary gas in these shales (Hill et al., 2007; Xia et al., 2013). In view of the potential for mixing of primary- and secondarygenerated gases, Hao and Zou (2013) examined the Rayleigh fractionation model of Burruss and Laughrey (2010) and suggested that it does not apply to the Barnett Shale. Instead, Hao and Zou (2013) invoke a relatively closed kerogen cracking (primary generation) system for the Barnett Shale. Their model predicts that carbon isotope distribution patterns of the shale gases will change with increasing thermal maturity in the order: d13C1 < d13C2 < d13C3 (normal), d13C2 < d13C1 < d13C3, d13C2 < d13C3 < d13C1 (partial reversal) and d13C3 < d13C2 < d13C1 (complete reversal). This implies that complete carbon isotope reversals in organic-rich shales probably occur only at high thermal maturity, perhaps when most C4–5 hydrocarbon gases have been cracked into C1–3 gases. Indeed, this is commonly what is observed. Using data predominantly from Zumberge et al. (2012), Hao and Zou (2013) determined that the Barnett Shale at Ro < 2.0 and the Fayetteville Shale at 2–3% Ro show partial reversal (d13C2 < d13C1 < d13C3) in 6 of the 101 samples, a different type of partial reversal (d13C2 < d13C3 < d13C1) in 77 of the 101 samples, and complete reversal (d13C3 < d13C2 < d13C1) in 18 of the 101 samples. Their model supports the suggestions of Tilley et al. (2011) who proposed that simultaneous heating of kerogen, oil and gas in a closed shale system yields isotopically reversed gas with light d13C2 and heavy d13C1. Their model also explains how the distribution patterns change from normal at lower thermal maturity through partial reversal to complete reversal at high thermal maturity. In the view of Hao and Zou (2013), isotopic reversals are restricted to closed-system maturation of kerogen and retained oil within organic-rich shales. This agrees with observations and conclusions of Tilley et al. (2011), Tilley and Muehlenbachs (2013b) and Xia et al. (2013): in-situ mixing and accumulation of gases generated from different precursors (kerogen, retained oil, wet gas) at different thermal maturities accounts for observed reversals and rollovers. We anticipate that future work will clarify the maturity levels beyond which primary kerogen cracking ceases and secondary oil and wet gas cracking becomes dominant. Lewan and Kotarba (2014) have recently made a start on this, by establishing a maximum maturity level beyond which primary (thermal) generation of gas from coal diminishes to near-zero.

Geochemical data stores Geochemists have long understood the importance of construction of, and access to, large datasets; several concepts not apparent in small data collections are recognizable when data density is high (Cornford et al., 1998). Early efforts to understand petroleum source rock potential in source-rock reservoirs benefited significantly from the prior existence in public and industry files of large amounts of geochemical data, including datasets and databases of TOC and Rock–Eval data collected during the initial stages of conventional plays in a basin. The last several years have seen a formalization of this effort, as major players in unconventionals have often compiled proprietary datasets in each of their active play areas. In addition, databases are now available commercially, and some of these – e.g., Neftex (Petroleum Systems Database; Sutcliffe, 2012), CGG-Robertson (FRogi), IGI Ltd. (pIGI), and GeoMark (RFDbase) – contain a wealth of geochemical data useful for source-rock reservoir explorers. As shale gas and liquids plays

Fig. 15. Trend (yellow curve) of d13C2 variation with decreasing wetness for a set of gases. The ‘normal’ increase in isotope ratio with decreasing wetness (a direct measure of increasing thermal maturity) is shown at far right, followed by a rollover depicted by decreasing ethane carbon isotope ratios with decreasing wetness. Extremely high maturities, proxied by extremely low wetness values, show a return to the ‘normal’ trend (at left). Data are from multiple published sources discussed in this paper. Figure from Dai et al. (2014, used by permission of Elsevier). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

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progress over the next decade, data collection will increase, and we anticipate (and encourage) continued progress in this direction.

The ongoing nomenclature change – when does unconventional becomes conventional?

Moving from ‘what’ to ‘why’ in the unconventional world

Many geochemists and other earth scientists familiar with the development of the field over the past several decades consider that the description of source-rock reservoir plays as ‘unconventional’ fits their engineering aspects far more than their scientific aspects. These plays were made possible, commercially, by advances in drilling and fracturing technologies. In contrast, the earth science concepts which lead to the generation of petroleum in source-rock reservoirs are indistinguishable from those applied in the conventional world of exploration. With the large BOE volumes currently being produced from source-rock reservoirs, and given the enormous capital outlays for many of these plays, we expect the ‘unconventional’ label to gradually disappear. Among petroleum geochemists who study source rocks, the deposition of organic matter and generation of petroleum are conventional processes, even when they occur in reservoirs.

The engineering challenges of horizontal drilling and hydraulic fracturing require an economic focus on drilling operations and flow rates, and much of the early effort in exploring for sourcerock reservoirs was justifiably focused on ‘what worked’. Thus, the recognized importance of organic matter amount and maturity in unconventional plays led to the collection of vast amounts of TOC and VR (or Tmax) data. Continued development of individual plays, accompanied by some costly failures, made it apparent that source rock characteristics vary widely, even on a small scale, and that individual source units are laterally and stratigraphically heterogenous. This awareness made it clear that understanding fundamental aspects of source rock deposition, variations in preserved organic matter, and the molecular and isotopic characteristics of generated petroleum could have a significant effect on economics. Attempts to understand the variations in sedimentary organic matter – from the nuclear (isotopic) level to the molecular level to the microscopic level – began decades ago in the conventional world, and no fundamental and novel concepts, perhaps other than isotopic rollover and reversal phenomena, have evolved to supplement these understandings in the unconventional world. Yet the importance of organic geochemistry to success in exploration for source-rock reservoirs has, as with many other aspects of unconventionals, led to a renaissance in the collection and interpretation of molecular and isotope data for organic-rich sedimentary sections. Much of this new knowledge is only now being released in the peer-reviewed literature, and we anticipate the pace to increase as existing plays become operationally mature. With increased publication of ongoing source-reservoir geochemical studies we expect to see a step change in our understanding of the geochemical characteristics of organic matter in source-rock reservoirs, particularly with respect to several remaining uncertainties, some of which have been described earlier. For example, in the absence of significant migration distances in source-rock reservoir plays, the inability to predict with confidence organic matter characteristics away from control – i.e., between wells or below total well depth – is a critical missing element, an issue which organic depositional modeling is only now beginning to address. In addition, remote measurement of organic matter characteristics in source rocks, either through seismic or by evaluation of near-surface (‘‘stray”) petroleum components, is critical in minimizing the number of penetrations and containing costs. Other anticipated advances include further determination of the role of water and quantitative use of isotope rollovers and reversals to compute accurate gas contributions from kerogen, bitumen and oil cracking, continued development of rapid organofacies assessment methods using X-ray techniques (Evenick and McClain, 2013), and the use of petroleum geochemical data to inform volumetric estimates (Michael et al., 2013, 2014). In addition, we anticipate that continued development of organic petrographic methods for assessing maceral distribution at time of deposition will become increasingly useful in postmature source rocks. Indeed, recent evidence of this has been presented by Gorbanenko and Ligouis (2014), who showed that several kerogen typedetermining macerals were still morphologically recognizable in postmature Posidonia Shale. These types of observations allow depositional environment assessment in source-rock reservoirs that have reached the gas-mature thermal maturity stage and beyond.

Acknowledgements In any review of the public literature, the first and most important acknowledgement goes to those individuals who have taken the time and made the effort to publish their ideas and data. We thank our many colleagues who have guided our thinking about the application of geochemistry in exploration for source-rock reservoirs, and especially appreciate those who made their work available to us pre-publication. In particular, we appreciate comments and suggestions from Jon Porch, Fang Lin and Barry Katz on an early version of this paper. J.B.C. thanks Donna C. Willette, Michael D. Lewan and Paul G. Lillis for guidance and insightful discussions concerning oil cracking reactions and hydrocarbon generation/expulsion mechanisms. We particularly wish to thank journal reviewers John Zumberge, Nick Harris and two anonymous individuals – the paper has been improved substantially as a result of their efforts. We also acknowledge various publishers for permission to include here their prior-published figures, and J.A.C. acknowledges Chevron for permission to publish.

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