Characterization of Organic-Rich Shales for Petroleum Exploration & Exploitation: A Review-Part 2: Geochemistry, Thermal Maturity, Isotopes and Biomarkers

As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ra- tio （C1/~＇（C2＋C3））, and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production ＂sweet- spots＂, discriminate oil-, gas-liquid- and gas-prone shales from kerogen compositions and thermal ma- turities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indica- tive of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance （Ro） measurements of thermal maturity highlight dis- crepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measure- ment, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, sta- ble and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identi- fication, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions as- sociated with them.

Characterization of Organic-Rich Shales for Petroleum Exploration & Exploitation: A Review-Part 1: Bulk Properties, Multi-Scale Geometry and Gas Adsorption

Shales, the most abundant of sedimentary rocks, are valued as the source-rocks and seals to porous petroleum reservoirs. Over the past-twenty years, organic-rich shales have also emerged as valuable petroleum systems （reservoir, seal, and source rocks contained in the same for- mation）. As such they have become primary targets for petroleum exploration and exploitation. This Part 1 of a three-part review addresses the bulk properties, multi-scale geometry and gas adsorption characteristics of these diverse and complex rocks. Shales display extremely low permeability, and their porosity is also low, but multi-scale. Characterizing the geometry and interconnectivity of the pore-structure frameworks with the natural-fracture networks within shales is essential for establish- ing their petroleum exploitation potential. Organic-rich shales typically contain two distinct types of porosity： matrix porosity and fracture porosity. In addition to inter-granular porosity, the matrix po- rosity includes two types of mineral-hosted porosity： inorganic-mineral-hosted porosity （1P）; and, organic-matter-hosted （within the kerogen） porosity （OP）. Whereas, the fracture porosity and per- meability is crucial for petroleum production from shales, it is within the OP where, typically, much of the in-situ oil and gas resources resides, and from where it needs to be mobilized. OP increases signifi- cantly as shales become more thermally mature （i.e., within the gas generation zones）, and plays a key role in the ultimate recovery from shale-gas systems. Shales＇ methane sorption capacities （MSC） tends to be positively correlated with their total organic carbon content （TOC）, thermal maturation, and mi- cropore volume. Clay minerals also significantly influence key physical properties of shale related to fluid flow （permeability） and response to stress （fracability） that determine their prospectivity for pe- troleum exploitation. Clay minerals can also adsorb gas, some much better than others. The surface area of the pore structure of shales can be positively or negatively correlated with TOC content, de- pending upon mineralogy and thermal maturity, and can influence its gas adsorption capacity. Part 2 of this three-part review considers, in a separate article, the geochemistry and thermal maturity cha- racteristics of shale; whereas Part 3, addresses the geomechanical attributes of shales, including their complex wettability, adsorption, water imbibition and ＂fracability＂ characteristics. The objectives of this Part 1 of the review is to identify important distinguishing characteristics related to the bulk properties of the most-prospective, petroleum-rich shales.

Characterization of Organic-Rich Shales for Petroleum Exploration & Exploitation: A Review-Part 3: Applied Geomechanics, Petrophysics and Reservoir Modeling

Modeling geomechanical properties of shales to make sense of their complex properties is at the forefront of petroleum exploration and exploitation application and has received much re- search attention in recent years. A shale＇s key geomechanical properties help to identify its ＂fracibility＂ its fluid flow patterns and rates, and its in-place petroleum resources and potential commercial re- serves. The models and the information they provide, in turn, enable engineers to design drilling pat- terns, fracture-stimulation programs and materials selection that will avoid formation damage and op- timize recovery of petroleum. A wide-range of tools, technologies, experiments and mathematical techniques are deployed to achieve this. Characterizing the interconnected fracture, permeability and porosity network is an essential step in understanding a shales highly-anisotropic features on multiple scales （nano to macro）. Weli-log data, and its petrophysical interpretation to calibrate many geome- chanical metrics to those measured in rock samples by laboratory techniques plays a key role in pro- viding affordable tools that can be deployed cost-effectively in multiple well bores. Likewise, micro- seismic data helps to match fracture density and propagation observed on a reservoir scale with pre- dictions from simulations and laboratory tests conducted on idealised/simplified discrete fracture net- work models. Shales complex wettability, adsorption and water imbibition characteristics have a sig- nificant influence on potential formation damage during stimulation and the short-term and long-term flow of petroleum achievable. Many gas flow mechanisms and models are proposed taking into ac- count the multiple flow mechanisms involved （e.g., desorption, diffusion, slippage and viscous flow op- erating at multiple porosity levels from nano- to macro-scales）. Fitting historical production data and well decline curves to model predictions helps to verify whether model＇s geomechanical assumptions are realistic or not. This review discusses the techniques applied and the models developed that are relevant to applied geomechanics, highlighting examples of their application and the numerous out- standin~ questions associated with them.

Impact of Particle Crush-Size and Weight on Rock-Eval S2,S4,and Kinetics of Shales

The Rock-Eval technique in the last few decades has found extensive application for source rock analysis.The impact of shale particle crush-size and sample weight on key Rock-Eval measurements,viz.the S;curve(heavier hydrocarbons released during the non-isothermal pyrolysis-stage)and the S;curve(CO_(2)released from oxidation of organic matter during the oxidation-stage)are investigated in this study.For high and low total organic carbon(TOC)samples of different thermal maturity levels,it is apparent that particle crush-size has a strong influence on the results obtained from RockEval analysis,with the effect being stronger in high-TOC samples.In comparison to the coarser-splits,S;and pyrolyzable carbon(PC)were found to be higher for the finer crush sizes in all the shales studied.The S_(2)CO_(2)oxidation curve shapes of Permian shales show contrasting signatures in comparison to the Paleocene-aged lignitic shale,both from Indian basins.A reduced TOC was observed with rising sample weight for a mature Permian shale from the Jharia basin,while the other shales sampled showed no significant reduction.The results indicate that the S_(2)CO_(2)curve and the S_(2)T_(2),are strongly dependent on the type of organic-matter present and its level of thermal maturity.Sample weight and particle size both influence the S;-curve shapes at different heating rates.With increasing sample weights,an increase in S;-curve magnitude was observed for the shales of diverse maturities.These differences in the S;curve shape lead to substantially different kinetic distributions being fitted to these curves.These findings are considered to have significant implications for the accuracy of reaction kinetics obtained from pyrolysis experiments using different sample characteristics.