Geology: Current and Future Developments

The concept of sedimentary organic matter, as well as the definitions and meanings of different organic facies have become an important tool in paleoenvironmental characterization, basin analysis and fossil fuel exploration. The application of this concept is the best way to integrate the techniques of microscopy to the study of kerogen contained in sedimentary rocks. The present chapter aims to provide a general view of sedimentary organic matter in relation to the techniques used for its application in the field of geosciences, with special emphasis on its contribution to both fundamental and applied scientific knowledge. Organic petrology is a branch of Earth Science that studies the organic matter present in sedimentary sequences, particularly in coal (concentrated organic matter) and finely disseminated in sedimentary rocks (dispersed organic matter - DOM) by using a set of petrographic methods generally in combination with various geochemical analytical techniques. The parameters obtained from petrological studies are important for defining the organic facies, geothermics and paleogeography of sedimentary basins, for investigating the geological structure, the present and past thermal regimes of the earth's crust as an aid to basin analysis, for assessing the mining and utilization of coal, and for the exploration of fossil fuel resources. All this explains the rapid development of organic petrology [1]. Thus, organic petrology studies based on the presence and concentration of sedimentary organic matter in both conventional and unconventional hydrocarbon systems have become, in recent years, a powerful tool for the characterization of the depositional paleoenvironment as well as for the evaluation of sedimentary sequences with oil and gas potential. Although the scope of organic petrology is broad, it employs just a few fundamental principles, one example of which is organic content characterization that is used to assess the type and quality, and thermal maturity of kerogen.

The dispersed organic matter (DOM) in sedimentary sequences derives from biological precursors and experiences changes during burial in sedimentary basins over millions of years. Organic petrology is an essential tool in the study of DOM due to its importance in exploration for fossil fuel resources, although organic matter represents the lowest amount fraction in sedimentary rocks. The study of the type and amount of organic matter, as well as the source and depositional environment define the organic facies and type of kerogen for establishing the hydrocarbon source potential of rocks during the exploration for both conventional and unconventional hydrocarbon resources. Furthermore, optical parameters have been established to determine the organic maturity and therefore, the paleotemperature history of sedimentary sequences, as organic matter is the most temperature-sensitive constituent present in sedimentary rocks.

The concept of oil shale, the requisites for a sedimentary rock to be considered an oil shale and the distribution and typification of the main oil shale deposits worldwide are addressed in this chapter. As the chapter forms part of a volume devoted to the contribution of organic petrology to the study of conventional and unconventional hydrocarbon resources a significant part is devoted to the petrographic characteristics of oil shales and the difficulties involved in their analysis. In particular aspects related to the quantification of organic components, and the level of maturation have been covered in detail. At present, only a few countries are commercially exploiting oil shales both as fuel to be burned and as a means to obtain shale oil. However the reserves are huge and emerging technologies such as in-situ recovery processes are being tested. The volatility of oil prices and the need to secure energy sources have been the driving force behind this re-evaluation and characterization of little known oil shale deposits in recent years, which will hopefully contribute to a revival of scientific and political interest in oil shale research.

Petroleum generating source rocks can be lacustrine, marine shale, marine carbonate or terrigenous/coaly, generally corresponding to Type I, Type II, Type II-S and Type III kerogen based on source rock screening data (Rock-Eval pyrolysis and TOC determination) plotted in modified van Krevelen diagrams. Rock-Eval and similar pyrolysis techniques are relatively cheap and allow analysis of many samples. However, the pyrolysis method can be problematic as it provides bulk geochemical data of the kerogen composition, which may lead to incorrect kerogen typing. This is particularly an issue for rocks with mixed kerogen compositions or for rocks with a deteriorated source potential due to, for example, slight oxidation of organic matter. Organic petrography in incident white light and fluorescing-inducing blue light of the macerals in source rocks adds granularity to the bulk geochemical characterization and is thus a strong supplementary tool for characterizing kerogen. Petrographic examination of source rocks can inter alia: (1) enhance kerogen characterization by providing qualitative or quantitative information on the maceral composition, including the proportions of oil-prone sapropelic and refractory kerogen, (2) identify mixtures of organic matter types or even slight oxidation of the sapropelic kerogen due to reduced fluorescence intensity and thereby prevent incorrect interpretations of kerogen, (3) document lateral and vertical organic facies variations within source rocks, and (4) provide evidence for petroleum generation by identifying oil droplets, oil films, solid bitumen, exsudatinite, micrinite or pyrolytic carbon. Despite the fact that reflected light microscopy is more expensive, time-consuming and complex than classic geochemical kerogen typing examination of representative or problematic source rock samples may provide just the missing piece that is required to better understand source rock composition and quality.

Production of natural gas from mud rocks (shale) is not new in the United States. Gas has been produced from Devonian-age shales in NE US since 1821 while the first industrial-scale shale gas development (Big Sandy Field in Kentucky) from the Ohio Shale took place in the 1920s. An exponential growth in shale gas exploration and production, led by the Barnett Shale in Texas, has occurred since the late 1990s. In 2014, shale gas production in the US reached 9.6 TCF (26 BCF/D), which corresponds to almost 40% of total gas production. The fast decline curve of shale gas wells necessitates the drilling of thousands of additional wells in order to keep up with the demand. Due to a decline in natural gas prices in recent years, the focus has shifted to shallower shale oil reservoirs. Thick sequences of shale containing varying volumes of gas are found in many basins across the US. Shales are extremely heterogeneous in their properties but at a scale not generally considered. Main challenges include, among others: screening exploration targets, identifying intervals to fracture stimulate and/or drill horizontal wells, and predicting production rates and EURs. Developing a Shale Gas Model is very complex because: a) not two shale rocks are alike, and b) there are many parameters that influence the oil/gas storage capacity and producibility, some of which are uncontrollable. The quantity (expressed by TOC content) and quality of the organic matter (expressed by the S2 and HI parameters from Rock-Eval Pyrolysis) and its thermal maturity (measured by vitrinite reflectance-VRo) are few very important – and easy to assess – parameters that influence oil and gas generating/storing capacity in the mostly microporous matrix system present in shale source/reservoirs, commonly referred to as ‘unconventional’ rocks. The objective of this chapter is to provide the reader with a better understanding of the variability in the above parameters in nine oil and gas reservoir shales in the United States- (referred thereunto as “The Magnificent Nine”). Particular emphasis will be given to the role that organic petrology plays in predicting the types of hydrocarbon (oil, wet gas/condensate liquids, and dry gas) that will be produced. These nine US shale formations were selected based on variations in their thermal maturity, organic richness, kerogen type(s), depositional environment, age, and mineralogical composition. They are the following: Utica, Marcellus, Woodford, Bakken, New Albany, Eagle Ford, Niobrara, and Green River. The ninth formation is the Wolfberry, which is considered to be a ‘hybrid’ play or a combination of unconventional and conventional. It is hoped that the contents of this chapter will serve as a useful guide to the reader and that learnings can be directly applied to basins around the world that contain analogous types of rocks.

Shale oil resource systems are oil reservoirs of fine grained facies with abundant organic matter (in many cases TOC> 2%), low porosity (normally between 4 to 14%), low permeability (in the micro- to nano Darcy range) containing in situ generated oil or short distance migrated oil. They produce light oil or condensate, usually generated from the mid to late oil window phase. These shale oil reservoirs cannot be exploited by means of conventional production technologies (vertical wells) and may require a different type of advanced, completion and development techniques. From the point of view of organic composition these systems are complex because they contain primary organic matter but also secondary products from the thermal degradation (cracking) of primary organic matter. It is here where organic petrology contributes to understanding shale oil reservoirs by identifying and estimating what kind of primary organic matter was deposited (marine or terrigenous, algae, spores, bacteria woody remains), and what the secondary organic products are, whether oil or solid bitumen and, in this way conveying an idea of the type and degree of organic matter richness in the rocks. Moreover, organic petrography also assesses the degree of maturity reached by the organic matter which in combination with the characteristics of the organic matter will define the type of fluid generated (oil or gas) during the thermal evolution. The Upper Formation (Turonian-Santonian age) of the organic-rich Cretaceous sequence located in the Middle Magdalena Valley (MMV) basin from Colombia is described here as one of the examples of shale oil reservoirs in which organic petrology has played a fundamental role in assessing the type of organic matter contained in the system, its provenance, paleosedimentary environment and thermal maturity. Moreover organic petrography is the only method of identifying sedimentary levels in this shale oil reservoir with high content in solid bitumen as a critical organic component in the development of organic porosity. The development of porosity contributes to the routes of migration of hydrocarbons and must be taken into account when evaluating the quality of these systems, their capacity to retain hydrocarbons (oil/gas) and their potential exploitability. This contribution also points out the capacity of organic petrology through its various methodologies, organic petrography, the visual assessment of kerogen and palynofacies analysis, to solve and clarify erroneous interpretations that can be made from data used as proxies for organic petrologic data.

Application of incident light microscopy techniques for organic petrology in high temperature thermogenic shale gas systems demonstrates that solid bitumen is the dominant organic matter. Solid bitumen is retained as a residual conversion product as oil-prone kerogen cracks to hydrocarbons or occurs from the cracking of once liquid oil. Oil-prone Type I/II kerogens are not present in shale gas reservoirs, already having converted to hydrocarbons. Type III/IV kerogens (vitrinite and inertinite) are refractory and persist in shale gas reservoirs to high maturity with little morphological change apart from condensation and aromatization causing higher reflectance. Organic petrology applications are most useful for thermal maturity determination and delineation of hydrocarbon windows through measurement of vitrinite reflectance and vitrinite reflectance equivalents from other organic matter (zooclasts and/or solid bitumen). Depositional organo-facies determination generally is not possible in the gas window of thermal maturity; fluorescence microscopy is not useful as organic matter is no longer autofluorescent. Application of scanning electron microscopy (SEM) allows observation of an interconnected nano-scale organic porosity in shale gas systems but suffers from inability to identify organic matter types. SEM approaches to shale gas reservoir characterization therefore should not attempt differentiation of kerogen types or kerogen vs. solid bitumen identification unless correlative organic microscopy is performed. Herein are reviewed organic petrology results as used in the shale gas systems of North America, Europe and China, including SEM applications, citing recent examples from the literature.

The Early Triassic Montney Formation is a world-class tight gas play in the Western Canadian Sedimentary Basin, mainly composed of siltstone. The majority of the organic matter in the Montney siltstone consists of solid migrabitumen. This represents a former liquid oil phase which migrated into the larger paleo-intergranular pore space. Physicochemical changes in the oil led to precipitation of asphalt aggregates. These asphalt aggregates were then consolidated into solid migrabitumen while being subjected to thermal cracking (or pyrobitumen at higher thermal maturity). Petrophysical measurements of drill-core samples across the basin in conjunction with organic geochemistry and petrographic observations show that reservoir quality in the Montney tight gas is strongly influenced by the pervasive presence of pore-occluding solid migrabitumen. Solid migrabitumen obstructs porosity and hinders fluid flow, and thus shows a strong negative correlation with reservoir qualities such as porosity and pore throat size. Bitumen saturation is the proportion of solid migrabitumen filling the intergranular paleopore network. This is the dominant control on pore throat size and absolute permeability. In the economic portions of the Montney tight gas fairway, siltstones are found to have porosities in the range of 3 to 7%. The conventional determinants of porosity and permeability, such as grain size, sorting, clay content and cementation, have less of an influence on the reservoir quality in this economically key porosity range than the bitumen saturation.

Coals hold a unique position in conventional and unconventional hydrocarbon systems in that organic matter forms the bulk of the rock. Gases within coals have a dominant storage mechanism of adsorption within the fundamental structure of the organic matter rather than the conventional state as a compressed gas in intergranular spaces or dissolved within liquid hydrocarbons. Gases form an integral part of the coal substance. Multiple phases of gas generation are the norm and result in complex relationships between gas content and organic petrology. Thermogenic gases are produced during normal burial metamorphic processes. Biogenic gases are produced during earliest coalification as well as post-coalification, after uplift. Understanding the variability of the organic matter is key to understanding the variability in gas content and gas composition. Coal type is determined at the peat stage and strongly influences mechanical properties of the coal, amount and type of gas generated, timing of gas generation and storage capacity. Coal type needs to be studied at the macroscopic level through lithotype analysis; at the microscopic level via maceral analysis and; geochemically. Rank studies by vitrinite reflectance are preferred over bulk geochemical techniques and provide insights into the timing and generation of thermogenic gases. Petrographic studies can also be used to detect the presence of igneous intrusion, which affects both gas composition and storage capacity. The importance of individual, detailed basin studies cannot be overstated. Attempts to make global generalizations usually fail due to the complexity of the starting material coupled with unique geological histories.

In this work, the important role of organic petrology in the reconstruction of the evolution of a paleo-petroleum system, whose source rocks have exhausted their ability to generate hydrocarbons due to their overmature state, is demonstrated. Whereas geochemical screening is generally used to characterize immature-to-mature source rocks, in the case of overmature spent source rocks, organic petrology is used to determine the type and amount of organic matter initially contained in the rocks. In this paper, a case study of the Cameros Basin (North-Central Spain) is presented. By means of vitrinite reflectance measurements, a marked difference in maturity has been determined throughout the basin. Immature to oil-window thermal conditions were reached in the southern part of the basin, whereas overmature to dry-gas thermal conditions were observed in the central and northern areas. In the northern sector the organic matter shows several thermal alteration textures as a consequence of the circulation of hydrothermal fluids during the evolution of the basin. In some of the overmature units, the presence of micrinite residues, framboidal pyrite in the mineral matrix and a large amount of solid bitumens suggest that these rocks originally contained abundant organic matter and that hydrocarbons were generated during the thermal evolution of the basin. These deposits can therefore be considered as the original source rocks of the Cameros Basin petroleum system. Evidence of the migration of hydrocarbons is frequently found in the form of fractures that vertically propagate through the organic matter rich-layers. The hydrocarbon accumulations formed by these rocks could have given rise to tar sandstone deposits that are located in the south of the basin.

Both conventional and unconventional petroleum systems assessments involve detailed analysis of the components and processes involved in the generation and storage of petroleum. A key of this assessment is the characterization of organic matter and its thermal maturity. Assessment of kerogen type and thermal maturity requires the use of multiple techniques to fully assess the petrological and geochemical risks associated with exploration and production (E&P) prospects and plays. A combination of visual and chemical techniques provides essential data to elucidate the various risks associated with finding and producing commercial amounts of petroleum. Visual techniques for kerogen characterization provide information that cannot be derived strictly from chemical data. Similarly, chemical data enhances the findings of the organic petrologist. Kerogen type assessment is best provided by visual kerogen analysis and various chemical analyses such as pyrolysis gas chromatography. Detailed analysis such as pyrolysis gas chromatography and laboratory maturation techniques such as microscale sealed vessel analysis provides detailed chemical composition and product type at various levels of thermal maturity. Imaging techniques have advanced the understanding of petroleum storage in source rocks as well as the mineralogical variability. Further input is needed from organic petrologists to understand the full complexity of the organic and inorganic matrix. Thermal maturity is also best addressed by a combination of visual and chemical techniques. The most common technique and industry standard is vitrinite reflectance. However, on marine shale source rocks, vitrinite is typically only present in minor amounts and is morphologically similar to bitumen or at higher thermal maturity, pyrobitumen. A solution to this conundrum is to perform vitrinite reflectance measurements on shales or coaly organic matter up-hole from the shale reservoir of interest. Identification of reasonably organic-rich and more mixed to gas prone organic matter provides indications of up-hole samples more suitable for vitrinite reflectivity analysis. These data can then be projected through the shale of interest if the burial history is understood. Clarification of thermal maturity can be addressed by utilization of chemical techniques especially quantitative aromatic hydrocarbons. It is essential to provide E&P teams interpreted kerogen and thermal maturity data. Otherwise, the complexity of the data can easily confuse experts and management that are not familiar with the idiosyncrasies of such analysis. Not all data can be considered equal due to various limitations such as sample choice for specific analysis.