Evaluation of Shale Source Rocks and Reservoirs

Organic-rich shales, until recently evaluated mainly as source-rocks feeding conventional oil and gas reservoirs, are now considered more broadly as both potential source rocks and as potential unconventional petroleum reservoirs. Laboratory analyses and models are now required to assess the extent of petroleum generation, and the quantities of petroleum retained within versus the extent of petroleum expelled from such formations over time. In this monograph we describe in detail the organo-petrographical properties, geochemical characteristics, and porous structures present within organic-rich shales. We highlight the analytical and interpretation protocols that need to be followed to provide meaningful assessment and characterization of these valuable formations.

Petroleum generation and storage in unconventional shale reservoirs is primarily controlled by the organic-matter present within shales. While organic richness is very important for acting as unconventional petroleum reservoirs, their hydrogen content and thermal maturity levels, critically influences the petroleum generation potential. Ideally, with increasing thermal maturity levels, petroleum compounds are liberated from organic-matter with concomitant creation of secondary organic-porosity. However, depending upon the type of kerogen present and its chemical composition, petroleum compounds may be generated even at lower thermal maturity levels. Organic petrologic techniques allows identification of organic-matter type and abundance within shales (mainly in dispersed state), as well as measure their thermal maturity levels and thereby enabling detailed petroleum generation modeling and interpretation. Herein utilizing organic petrology as a tool, we discuss the fundamentals of source-rock geochemistry comprising of organic content, type, and maturity.

The basic pyrolysis techniques used for source-rock geochemical analysis are generally simple and can be interpreted in a straightforward way. However, some of the data generated can be misleading and lead to confused interpretations if not properly assessed. This chapter discusses the different aspects of source-rock evaluation using the commonly used Rock-Eval technique on a step-by-step basis. Here, the impact for several factors on key Rock-Eval derived measurements, viz. particle crush-size, FID signal, S2 pyrogram shape, FID linearity, S4CO₂ oxidation graphics, are addressed. Careful monitoring of these key parameters enables analysts/interpreters to conduct meaningful source-rock assessment. The shape of S2 pyrograms helps to predict the type of kerogen(s) present within a sample and can be indicative of their level of thermal maturity. While type I kerogen bearing JR-1 standard and type II kerogen-mimicking IFP160000 synthetic shale standard, show tighter Gaussian shaped S2 peak shapes in their pyrograms, type III kerogen bearing shales typically show a right-side tailed effect. Further, owing to their extremely high hydrocarbon generation potential, even at lower sample weights, type I kerogens show higher FID signals than other kerogen types. Type III-IV kerogen bearing shales show least FID signals even at higher sample weights owing to their lower petroleum generation potential. For type I kerogen bearing shales FID signals can be very high; if they rise beyond the Rock-Eval equipment’s FID detection limits, the resulting pyrograms are likely to be erroneous. Migrated hydrocarbons in the samples tested are likely to have an impact on the Rock-Eval pyrograms they yield. Particle crush-sizes of the samples analyzed are potentially more significant for organic-rich shales compared to organic-lean shales. Sample weights on S4CO₂ oxidation graphics are shown to be potentially significant. For carbonate-free shales, with increasing sample weights, increasing portions of the CO₂ from the organic-matter (represented by S4CO₂ graphics) tends to be undercounted. This result in an underestimation of the residual carbon (RC) and TOC content, and erroneous estimation of carbonate mineral content. To obtain reliable Rock-Eval results it is necessary to conduct simultaneous monitoring of FID signals, S2 pyrograms shapes, and S4CO₂ oxidation graphics. For organic-lean shales, the S2 signals may be too low, below the FID detection limits of the Rock-Eval equipment, generating erroneous thermal maturity data.

During the Rock-Eval pyrolysis S2 stage, the heavier hydrocarbon molecules generated during to the thermal maturation of kerogen, are often retained by the shale-matrix. Argillaceous matrices of organic-rich shales generally results in a greater amount of petroleum retention. Under such matrix retention conditions, the best-fit line of a S2 versus total organic carbon (TOC) cross-plot does not pass through the origin but intercepts the TOC-axis. Furthermore, as the S2 yield is reduced, the hydrogen indices (HI) tend to be undercounted and thereby lead to inaccurate source rock assessment. However, such effects may also be caused due to the impact of inert organic-matter which does not contribute much to the S2 peak magnitude, but does contribute to the TOC content. Thus, correction of the effects from both inert organic-matter and shale-matrix retention are needed for accurate petroleum source rock estimation. The effects of matrix retention tend to be more pronounced for type III kerogen-bearing shales, than type I-II kerogen-bearing shales.

This chapter considers the data measurement, analysis, modelling and interpretation techniques associated with kerogen’s conversion into petroleum fluids, thermal maturity and petroleum generation in organic-rich sediments. The roles of biogenic and thermogenic processes are distinguished. The significant roles in thermogenic generation of petroleum of the variables: temperature, time, burial depth and geothermal gradients are established. Thermal maturity models based on the Arrhenius equation and the merits of a cumulative time-temperature index (\( \sum {TTI_{ARR} } \)) applying representative but simple kerogen kinetics (a single activation energies, E, and pre-exponential factor, A) for calculating specific levels of thermal maturity, correlated with the vitrinite reflectance scale, are described in detail and applied to burial history modelling of shales over geological time scales. For quantifying the cumulative transformation fraction of kerogens into petroleum a range or distribution of kerogen kinetics (i.e., several E and A combinations) is typically required to reflect the mixed kerogen content and multiple first-order chemical reactions involved in the transformation of shale into petroleum. Kerogen kinetics follow a well-defined trend of E-A values and cumulative petroleum transformation fractions using that trend of kinetic values can be modelled and optimized to accurately fit observed pyrolysis S2 peaks for a wide range of shales containing single or multiple kerogen types. Thermally immature shales are more readily modelled (i.e., more accurate fits to their pyrolysis S2 peaks obtained) than thermally mature shales. This supports the view that first-order reaction kinetics following the Arrhenius equation dominates the pyrolysis of immature shales. On the other hand, non-kinetic processes, such as micro-porosity development and connectivity, can significantly influence the pyrograms produced by thermally mature shale samples.

Organic-matter present in shales is the source of gaseous hydrocarbons and its quantity and quality determines the gas generative capacity of the rock. It is represented by the total organic carbon (TOC) content. There exist two important organic fractions, the kerogen, which amounts to the bulk of organic-matter (~80–90%), and the second are the free molecules of lipids ‘the biomarkers’ (10–20%), which include the hydrocarbons and related compounds. The molecular compositions and stable isotope signatures determined using organic and isotope ratio mass spectrometry provide important attributes of the organic-matter such as organic richness, type and thermal maturity. This chapter presents an account of the minor fraction of the sedimentary organic carbon content, the biomarkers, its origin and occurrence in shale source and reservoir rocks, the transformations that occur with successive burial, its isotopes and the crucial information provided on the organic-matter provenance (source), depositional environment and thermal maturity along with the contemporary analytical approaches for its characterization.

Porosity is a primary characterization parameter for organic-rich shales, as gas/oil exists within the pore spaces within these formations. Careful analysis and quantification of the various attributes of the complete range of pore sizes dimensions, shapes and connectivity is required. The results of such analysis applied to a suite of samples from a specific province are typically quite revealing about the gas storage potential of the shales and how that evolves with advancing thermal maturity. While different techniques exist to assess porous structures in shales, low-pressure gas adsorption (LPGA) techniques using N₂ and CO₂ are generally the most informative and reliable tools for assessing the complex nano- to macropore distributions in shale reservoirs. In this chapter we discuss the different facets of using LPGA techniques for assessing these reservoirs. N₂ is widely for assessing predominantly the mesoporous and part of macroporous components of the pore-size distributions. Whereas, CO₂ is used to better access the microporous components of the pore-size distributions in shales. At low experimental temperatures, N₂ is unable to fully access the fine complex network of mesoporous and microporous components, particularly which are present within organic-matter. Comparative analysis of the pore properties of coals and shales (organic-rich and organic-lean) confirms that the porosity of organic-rich horizons tends to be underestimated by the low-pressure N₂-adsorption method compared to the CO₂ adsorption method. Pore surface fractal dimension D1, representing the fractal dimension at lower relative pressures is observed to be consistently lower than the pore structural fractal dimension, D2 for shales occurring in different basins and geological settings/ages. The impact of the particle crush-size of the samples analyzed can influence the pore-size distribution measurements and should be carefully selected to provide consistent shale-porosity interpretations.

Geochemical profiling-data of unconventional shale reservoirs is a key step in their characterization. However, it can provide misleading and ambiguous interpretation due to a lack of thorough understanding of the data and its limitations. Open-system programmed pyrolysis experiments (such as Rock-Eval) and organic petrological techniques are frequently used for geochemical screening of source rocks. The pyrolysis technique is more widely used because it is quicker, cheaper and easier to generate useful screening data with that technique. Significant insight can be gained by assessing shale reservoirs using the Rock-Eval pyrolysis technique, e.g., organic-matter richness, petroleum generation potential and thermal maturity levels