Explore the vast range of titles available.

Unconventional shale resource systems have provided North America with abundant energy supplies and reserves for present and future decades. This energy resource was largely overlooked until the new millennium. Prior 2000 only a few small oil and gas companies were pursuing such plays led by independent, Mitchell Energy and Development Corporation of The Woodlands, TX. Mitchell's successful commercial development of the Mississippian Barnett Shale of the Ft. Worth Basin, Texas spawned an energy renaissance in North America. In the last decade the development of unconventional shale resource systems has been phenomenal in the United States with abundant new supplies of natural gas and oil. These resource systems are all associated with petroleum source rocks, either within the source rock itself or in juxtaposed, non-source rock intervals. Three key characteristics of these rocks, apart from being associated with organic-rich intervals, are their low porosity (less than 15%), ultra-low permeability (<0.1mD), and brittle or non-ductile nature. These characteristics play a role in the storage, retention, and the requirement of high-energy stimulation to obtain petroleum fl ow. Organic richness and hydrogen content certainly play a role in petroleum generation, but they also play a role in retention and expulsion fractionation of generated petroleum. Often a substantial portion of the porosity evolves from the decomposition of organic carbon that creates organoporosity in addition to any matrix porosity. Open fracture-related porosity is seldom important. Hybrid systems, i.e., organic-lean intervals overlying, interbedded, or underlying the petroleum source rock, are the best producing shale resource systems, particularly for oil due to their limited adsorptive affi nities and the retention of polar constituents of petroleum in the source rock. Paradoxically, the best shale gas systems are those where the bulk of the retained oil in the source rock has been converted to gas by cracking. Such conversion cracks the retained polar constituents of petroleum as well as saturated and aromatic hydrocarbons to condensate-wet gas or dry gas at high thermal maturity. Such high level conversion also creates the maximum organoporosity, while enhancing pore pressure. Bitumen (petroleum)-free total organic carbon (TOC) is comprised of two components, a generative and a non-generative portion. The generative organic carbon (GOC) represents the portion of organic carbon that can be converted to petroleum, whereas the non-generative portion does not yield any commercial amounts of petroleum due to its low hydrogen content. Organoporosity is created by the decomposition of the generative organic carbon as recorded in volume percent. In the oil window, this organoporosity is fi lled with petroleum (bitumen, oil and gas) and is diffi cult to identify, whereas in the gas window any retained petroleum has been converted to gas and pyrobitumen making such organoporosity visible under high magnifi cation microscopy. Production decline analysis shows the variable production potential of many North American shale gas and oil systems and their high decline rates. The most productive North American shale gas systems are shown to be the Marcellus and Haynesville shales, whereas the best shale oil systems are the hybrid Bakken and Eagle Ford systems.

Porosity and permeability are the key factors in assessing the hydrocarbon productivity of unconventional (shale) reservoirs, which are complex in nature due to their heterogeneous mineralogy and poorly connected nano- and micro-pore systems. Experimental efforts to measure these petrophysical properties posse many limitations, because they often take weeks to complete and are difficult to reproduce. Alternatively, numerical simulations can be conducted in digital rock 3D models reconstructed from image datasets acquired via e.g., nanoscale-resolution focused ion beam–scanning electron microscopy (FIB-SEM) nano-tomography. In this study, impact of reservoir confinement (stress) on porosity and permeability of shales was investigated using two digital rock 3D models, which represented nanoporous organic/mineral microstructure of the Marcellus Shale. Five stress scenarios were simulated for different depths (2,000–6,000 feet) within the production interval of a typical oil/gas reservoir within the Marcellus Shale play. Porosity and permeability of the pre- and post-compression digital rock 3D models were calculated and compared. A minimal effect of stress on porosity and permeability was observed in both 3D models. These results have direct implications in determining the oil-/gas-in-place and assessing the production potential of a shale reservoir under various stress conditions.

Hydraulic fracturing, widely known as \"fracking,\" is a relatively inexpensive way to tap into what were previously inaccessible natural gas resources. Vidic et al. (p. 826 ) review the current status of shale gas development and discuss the possible threats to water resources. In one of the hotbeds of fracking activity, the Marcellus Shale in the eastern United States, there is little evidence that additives have directly entered groundwater supplies, but the risk remains. Ensuring access to monitoring data is an important first step toward addressing any public and environmental health concerns. Unconventional natural gas resources offer an opportunity to access a relatively clean fossil fuel that could potentially lead to energy independence for some countries. Horizontal drilling and hydraulic fracturing make the extraction of tightly bound natural gas from shale formations economically feasible. These technologies are not free from environmental risks, however, especially those related to regional water quality, such as gas migration, contaminant transport through induced and natural fractures, wastewater discharge, and accidental spills. We review the current understanding of environmental issues associated with unconventional gas extraction. Improved understanding of the fate and transport of contaminants of concern and increased long-term monitoring and data dissemination will help manage these water-quality risks today and in the future.

Lacustrine shale is an important target for the exploration of unconventional oil and gas in China beyond marine shale gas. However, the formation environment of lacustrine shale differs from that of marine shale, resulting in a different reservoir composition, organic matter, oil and gas content, and hydrocarbon mobility. In this study, the Chang 7 shale of the Yanchang Formation in the Ordos Basin was used to analyze the effect of volcanic activity on the paleoproductivity and preservation conditions during the formation of lacustrine shale. The results show that algae and bacteria were developed before the eruption. After the eruption, the number of bacteria declined, but the increased prosperity of algae reflects that the volcanic activity enhanced ancient productivity. The sulfate generated by volcanic activity promotes bacterial sulfate reduction, and the produced H 2 S leads to a strong reducing environment in the waterbody, which is conducive to the preservation of organic matter. Organic geochemical analysis shows that the black shale in the shale strata has a high total organic carbon (TOC) content and strong hydrocarbon generation potential, whereas the tuff has a low TOC content and can scarcely generate hydrocarbons, indicating that the tuff deposited by volcanic activity cannot be considered as effective source rock. In terms of storage space, shale is mainly laminar and dispersed, and it includes organic and inorganic pores. The development of organic pores is affected by thermal maturity, whereas inorganic pores mainly occur between detrital particles and crystals. Tuff is mainly supported by heterogeneous matrix and associated with alteration. Its pores include inter- and intragranular mineral pores. The development of tight sandstone pores is affected by compaction, cementation, and dissolution, which mainly consist of intra- and intergranular pores. The Chang 7 lacustrine shale generally contains oil, but different lithologies have different oil drainage efficiencies. Sandstone and shale exhibit the best and worst oil drainage efficiency, respectively. It is mainly affected by the pore size distribution, fluid properties, and rock wettability. Therefore, the development of shale oil should mainly focus on lacustrine shale formations with interbeds. The mutual dissolution of organic matter and hydrocarbons in the shale section leads to the poor mobility and difficult development of hydrocarbons.

Methane has been rising rapidly in the atmosphere over the past decade, contributing to global climate change. Unlike the late 20th century when the rise in atmospheric methane was accompanied by an enrichment in the heavier carbon stable isotope (13C) of methane, methane in recent years has become more depleted in 13C. This depletion has been widely interpreted as indicating a primarily biogenic source for the increased methane. Here we show that part of the change may instead be associated with emissions from shale-gas and shale-oil development. Previous studies have not explicitly considered shale gas, even though most of the increase in natural gas production globally over the past decade is from shale gas. The methane in shale gas is somewhat depleted in 13C relative to conventional natural gas. Correcting earlier analyses for this difference, we conclude that shale-gas production in North America over the past decade may have contributed more than half of all of the increased emissions from fossil fuels globally and approximately one-third of the total increased emissions from all sources globally over the past decade.

The Sichuan Basin is rich in shale oil and gas resources, with favorable geological conditions that the other shale reservoirs in China cannot match. Thus, the basin is an ideal option for fully “exploring petroleum inside source kitchen” with respect to onshore shale oil and gas in China. This paper analyzes the characteristics of shale oil and gas resources in the United States and China, and points out that maturity plays an important role in controlling shale oil and gas composition. US shale oil and gas exhibit high proportions of light hydrocarbon and wet gas, whereas Chinese marine and transitional shale gas is mainly dry gas and continental shale oil is generally heavy. A comprehensive geological study of shale oil and gas in the Sichuan Basin reveals findings with respect to the following three aspects. First, there are multiple sets of organic-rich shale reservoirs of three types in the basin, such as the Cambrian Qiongzhusi Formation and Ordovician Wufeng Formation-Silurian Longmaxi Formation marine shale, Permian Longtan Formation transitional shale, Triassic Xujiahe Formation lake-swamp shale, and Jurassic lacustrine shale. Marine shale gas enrichment is mainly controlled by four elements: Deep-water shelf facies, moderate thermal evolution, calcium-rich and silicon-rich rock association, and closed roof/floor. Second, the “sweet section” is generally characterized by high total organic carbon, high gas content, large porosity, high brittle minerals content, high formation pressure, and the presence of lamellation/bedding and natural microfractures. Moreover, the “sweet area” is generally characterized by very thick organic-rich shale, moderate thermal evolution, good preservation conditions, and shallow burial depth, which are exemplified by the shale oil and gas in the Wufeng-Longmaxi Formation, Longtan Formation, and Daanzhai Member of the Ziliujing Formation. Third, the marine, transitional, and continental shale oil and gas resources in the Sichuan Basin account for 50%, 25%, and 30% of the respective types of shale oil and gas geological resources in China, with great potential to become the cradle of the shale oil and gas industrial revolution in China. Following the “Conventional Daqing-Oil” (i.e., the Daqing oilfield in the Songliao Basin) and the “Western Daqing-Oil & Gas” (i.e., the Changqing oilfield in the Ordos Basin), the Southwest oil and gas field in the Sichuan Basin is expected to be built into a “Sichuan-Chongqing Daqing-Gas” in China.

Evaluation of the gas shale mechanical properties is very important screening criteria for determining the potential intervals for hydraulic fracturing and as a result in gas shale sweet spot mapping. Young’s modulus and Poisson’s ratio are two controlling mechanical properties that dictate the brittleness of the gas shale layers. These parameters can be determined in the laboratory by testing the rock sample under different conditions (static method) or can be calculated using the well-logging data including sonic and density log data (dynamic method). This study investigates the importance of the shale composition and geochemical parameters on the Young’s modulus and Poisson’s ratio using log data. The data set of this study is coming from five different wells targeting the Kockatea Shale and Carynginia formation, two potential gas shale formations in the Perth Basin, Western Australia. The results show that converse to the common idea the effect of organic matter quantity and maturity on the rock mechanical properties of the gas shale reservoirs is not so much prominent, while the composition of the rock has an important effect on these properties. Considering the weight percentage of shale composition and organic matter quantity it could be concluded that effect of these parameters on rock mechanical properties is dependent on their weight contribution on the shale matrix. As well as effect of thermal maturity on the shale matrix and consequently on the rock mechanical properties of the shales is dependent on the organic matter content itself; therefore, obviously with a low organic matter content thermal maturity has no prominent effect on the brittleness as well.

Understanding pore structure evolution in lacustrine shale systems provides critical insights for marine shale reservoir characterization. This study presents an integrated petrological and petrophysical analysis of a representative lacustrine shale succession, employing low temperature nitrogen adsorption (LTNA), whole rock X-ray diffraction (XRD), and scanning electron microscopy (SEM). The study shows that (1) Clay-dominated pore systems evolve through distinct pathways compared to marine shales, with illite/smectite mixed-layer minerals generating abundant mesopores through diagenetic transformation. (2) Organic matter- dominated pores display limited connectivity due to Type III kerogen characteristics and hydrocarbon generation-induced pore occlusion, contrasting with marine shale systems dominated by Type II kerogen. (3) Comparative analysis demonstrates that lacustrine shales preserve 30–40% higher micro-mesopore volumes than their marine counterparts under similar thermal maturity conditions, attributed to enhanced clay mineral diagenesis in freshwater environments. These findings provide a new framework for understanding pore structure development in non-marine depositional systems and provide valuable analogs for marine shale reservoir evaluation, particularly in transitional marine-lacustrine basins.

Multistage fracturing of the horizontal well is recognized as the main stimulation technology for shale gas development. The hydraulic fracture geometry and stimulated reservoir volume (SRV) is interpreted by using the microseismic mapping technology. In this paper, we used a computerized tomography (CT) scanning technique to reveal the fracture geometry created in natural bedding-developed shale (cubic block of 30 cm × 30 cm × 30 cm) by laboratory fracturing. Experimental results show that partially opened bedding planes are helpful in increasing fracture complexity in shale. However, they tend to dominate fracture patterns for vertical stress difference Δ σ v  ≤ 6 MPa, which decreases the vertical fracture number, resulting in the minimum SRV. A uniformly distributed complex fracture network requires the induced hydraulic fractures that can connect the pre-existing fractures as well as pulverize the continuum rock mass. In typical shale with a narrow (<0.05 mm) and closed natural fracture system, it is likely to create complex fracture for horizontal stress difference Δ σ h  ≤ 6 MPa and simple transverse fracture for Δ σ h  ≥ 9 MPa. However, high naturally fractured shale with a wide open natural fracture system (>0.1 mm) does not agree with the rule that low Δ σ h is favorable for uniformly creating a complex fracture network in zone. In such case, a moderate Δ σ h from 3 to 6 MPa is favorable for both the growth of new hydraulic fractures and the activation of a natural fracture system. Shale bedding, natural fracture, and geostress are objective formation conditions that we cannot change; we can only maximize the fracture complexity by controlling the engineering design for fluid viscosity, flow rate, and well completion type. Variable flow rate fracturing with low-viscosity slickwater fluid of 2.5 mPa s was proved to be an effective treatment to improve the connectivity of induced hydraulic fracture with pre-existing fractures. Moreover, the simultaneous fracturing can effectively reduce the stress difference and increase the fracture number, making it possible to generate a large-scale complex fracture network, even for high Δ σ h from 6 MPa to 12 MPa.

Multiple stressors threaten stream physical and biological quality, including elevated nutrients and other contaminants, riparian and in-stream habitat degradation and altered natural flow regime. Unconventional oil and gas (UOG) development is one emerging stressor that spans the U.S. UOG development could alter stream sedimentation, riparian extent and composition, in-stream flow, and water quality. We developed indices to describe the watershed sensitivity and exposure to natural and anthropogenic disturbances and computed a vulnerability index from these two scores across stream catchments in six productive shale plays. We predicted that catchment vulnerability scores would vary across plays due to climatic, geologic and anthropogenic differences. Across-shale averages supported this prediction revealing differences in catchment sensitivity, exposure, and vulnerability scores that resulted from different natural and anthropogenic environmental conditions. For example, semi-arid Western shale play catchments (Mowry, Hilliard, and Bakken) tended to be more sensitive to stressors due to low annual average precipitation and extensive grassland. Catchments in the Barnett and Marcellus-Utica were naturally sensitive from more erosive soils and steeper catchment slopes, but these catchments also experienced areas with greater UOG densities and urbanization. Our analysis suggested Fayetteville and Barnett catchments were vulnerable due to existing anthropogenic exposure. However, all shale plays had catchments that spanned a wide vulnerability gradient. Our results identify vulnerable catchments that can help prioritize stream protection and monitoring efforts. Resource managers can also use these findings to guide local development activities to help reduce possible environmental effects.