Oil-bearing Shale Research Articles

Prediction of lamina structure and reservoir quality in shale using well logs: The Cretaceous Qingshankou Formation, Gulong Sag, Songliao Basin, China

Lamina structure is determined by composition, thickness, continuity, and mineral assemblage. Reservoir quality in oil shale reservoirs is determined by lamina structure, which controls hydrocarbon accumulation and migration. The prediction and evaluation of multi-scale lamina structures using geophysical well logs is challenging. Recent studies demonstrate that the lamina structure classification may be based on core observation and core analysis. However, there are no corresponding high-resolution geophysical logging methods to identify and categorize lamina structure continuously in a single well. Here, an experimental approach, involving an integrated analysis of cores, thin sections, well logs such as slabs and button conductivity curves of image logs (up to 5 mm vertical resolution), is used to characterize lamina structure. T1-T2 (T1, longitudinal relaxation time, and T2, transverse relaxation time) maps of nuclear magnetic resonance (NMR) logs are applied to clarify the relationships between the lamina structure, reservoir quality, and oil-bearing properties. Results demonstrate how lamina structure in shale can be divided into three types: laminated rocks, layered rocks, and massive rocks, according to observation of core at the lamina scale. The thickness of individual lamina is less than 0.01 m in the laminated rocks, and the layered rocks have bundles of genetically related laminae thickness ranging between 0.01 m and 0.1 m. In massive rocks there is no visible layering. The well log response patterns of the three types of lamina structure are established so that the distribution of lamina structure can be predicted in a single well via well logs. Results show that the oil-bearing shale intervals are dominated by laminated rocks and layered rocks, accounting for 90% of the studied Qingshankou Formation. In addition, the layered rocks play an important role in improving reservoir quality and the laminated rocks present moderate reservoir quality. The massive rocks show poor reservoir quality. Moreover, an increased proportion of felsic mineral content favors increased oil potential in oil shale reservoirs. The method is generally applicable and is of value in developing predictive indicators of subsurface reservoir sweet spots in shale oil and gas exploration and development.

Effect of CO2 Corrosion and Adsorption-Induced Strain on Permeability of Oil Shale: Numerical Simulation

Permeability is a crucial parameter for enhancing shale oil recovery through CO2 injection in oil-bearing shale. After CO2 is injected into the shale reservoir, CO2 corrosion and adsorption-induced strain can change the permeability of the oil shale, affecting the recovery of shale oil. This study aimed to explore the influence of CO2 corrosion and adsorption-induced strain on the permeability of oil shale. The deformation of the internal pore diameter of oil shale induced by CO2 corrosion under different pressures was measured by low-pressure nitrogen gas adsorption in the laboratory, and the corrosion model was fitted using the experimental data. Following the basic definitions of permeability and porosity, a dynamic mathematical model of porosity and permeability was obtained, and a fluid–solid coupling mathematical model of CO2-containing oil shale was established according to the basic theory of fluid–solid coupling. Then the effects of adsorption expansion strain and corrosion compression strain on permeability evolution were considered to improve the accuracy of the oil shale permeability model. The numerical simulation results showed that adsorption expansion strain, corrosion compression strain, and confining pressure are the important factors controlling the permeability evolution of oil shale. In addition, adsorption expansion strain and corrosion compression strain have different effects under different fluid pressures. In the low-pressure zone, the adsorption expansion strain decreases the permeability of oil shale with increasing pressure. In the high-pressure zone, the increase in pressure decreases the influence of expansion strain while permeability gradually recovers. The compressive strain increases slowly with increasing pressure in the low-pressure zone, slowly increasing oil shale permeability. However, in the high-pressure area, the increase in pressure gradually weakens the influence of corrosion compressive strain, and the permeability of oil shale gradually recovers.

Influences of controlled microwave field irradiation on occurrence space and state of shale oil: Implications for shale oil production

The exploration and production of shale oil play a vital role in optimizing energy consumption pattern and mitigating dependence on foreign energy. Given the existing shortcomings of current commercial hydraulic fracturing, research and development on alternative or assistive technology for producing shale oil are of great significance. In order to better understand the validity of shale oil production via microwave energy, the influences of microwave irradiation on pore and fracture structure of oil-bearing shale matrix and occurrence state of shale oil dominating shale oil production were investigated through multiple characterizations typically including the total organic carbon content, X-ray diffraction, scanning electron microscope, carbon dioxide adsorption, low-temperature nitrogen adsorption and desorption, mercury intrusion porosimetry, micro-computer tomography scanning, gas chromatography and low-field nuclear magnetic resonance. Results indicate that microwave irradiation alters geochemical characteristics of oil-bearing shale through decreasing its free hydrocarbon content and increasing pyrolysis rate of organic carbon. Moreover, microwave irradiation induces decomposition, formation, and transformation of inorganic minerals. Additionally, microwave irradiation increases surface area and volume of full-scale pores but decreases their average pore diameter. Meanwhile, microwave irradiation significantly increases number of full-scale pores, particularly macropores dominating free shale oil migration. As for fractures, microwave irradiation not only extends primary fractures but also creates new fractures parallel to the bedding direction due to inhomogeneous thermal stress generated among minerals with different microwave-absorbing capabilities. Accordingly, porosity and permeability of the oil-bearing shale remarkably increase. In terms of shale oil, microwave irradiation enhances its mobility by decreased viscosity and induced hydrocarbon pyrolysis. Finally, microwave irradiation could decrease content of kerogen, adsorbed shale oil, free shale oil and primary water. In conclusion, microwave energy is hopeful to achieve high-efficient and environmental-friendly production of shale oil due to its impacts on pores and fractures of reservoirs and occurrence state of shale oil.

Mineralogy, organic geochemistry, and microstructural characterization of lacustrine Shahejie Formation, Qikou Sag, Bohai Bay Basin: Contribution to understanding microcosmic storage mechanism of shale oil

Shale samples of lacustrine Shahejie Formation from the Well F39X1 drilled in Qikou sag were used to study microstructures, mineralogy, and organic geochemistry and their impacts on oil storage response. Samples are quartz and clay rich and contain a variable amount of calcite, dolomite, plagioclase, and pyrite minerals. The TOC content ranges between 0.33 and 2.59 wt %, Rock-Eval S 1 and S 2 values range from 0.05 to 1.07 mg/g and 0.12–9.57 mg/g, respectively. The maximum yield temperature (T max ) of pyrolysate ranges from 440 °C to 467 °C, and vitrinite reflectance calculated based on T max between 0.76 and 1.25%. High frequency 2D nuclear magnetic resonance (NMR) results show free oil contents are 1.176–1.909 μl/g, with an average of 1.542 μl/g. Mineral-related pores are dominant and volumetrically significant with a multimodal pore-throat size distribution, they could provide significant storage space and have good microstructural connectivity. Their roles in microscopic storage of oil molecules mainly depends on two mechanisms: (1) rigid mineral grains preserve large pore networks, within which residing a very large volume of free oil, and (2) clay particles existed within large interparticle pores alter pore throat size distribution, resulting in a slight increasing of adsorbed oil onto pore walls. The Well F39X1 is an important shale oil exploration well for Shahejie Formation. To reduce exploration risk and determine economic feasibility, knowledge of liquid hydrocarbon molecule microscopic storage mechanism is required so producible shale oil resources can be quantified. The investigation of oil-bearing shale mineralogy, organic geochemistry, and microstructures is an important step in better understanding of the pore network development and their related microscopic storage mechanism for oil in lacustrine shale. We suggested that siliceous Shahejie shales in Qikou sag with moderate TOC and suitable thermal maturity have well-developed pore networks and high residual hydrocarbons, which should be the important target for lacustrine shale oil exploration. Also, the well-developed mineral-related pore networks should be included in attempts to build realistic microscopic storage models of shales. • Four typical pore types in Shahejie Formation of Well F39X1 are identified. • Mineral-related pores are dominant and volumetrically significant in pore networks. • Oil molecule type, distribution, and content are identified by high-frequency 2D NMR. • Two microstructural models are proposed to reveal shale oil storage mechanism.

Tracing Organic-Inorganic Interactions by Light Stable Isotopes (H, Li, B, O) of an Oil-Bearing Shale and its Clay Fraction During Hydrous Pyrolysis

AbstractTracing interactions during burial-induced organic maturation and associated clay-material alteration is of prime importance for understanding both the individual and combined mineral and organic processes. In the present study the light elements B, Li, O, and H of a sample from oil-prone Eocene Kreyenhagen Shale from San Joaquin Basin (California) were examined. The natural burial-induced temperature increase was simulated by pyrolysis experiments at progressively increasing temperatures (270–365°C) and for varied durations (72–216 h) applied to the whole rock and its <2 μm fraction. The illite structure as well as the K-rich interlayers of the illite-smectite mixed layers were not affected by the pyrolysis experiments and the smectite-rich interlayers did not collapse, while the soluble minerals and the organic matter were altered. The distribution pattern of the rare-earth elements (REEs) from untreated whole rock and of its pyrolyzed equivalents are within analytical uncertainty, which confirms that the changes induced by pyrolysis experiments were minimal in the bulk sample. Conversely, the REEs from the <2 μm fractions were modified significantly, suggesting that the whole rocks and the <2 μm fractions may contain different types of organic materials. Also, only the carbonates, oxides, chlorides, and organic matter were affected together with the smectite-rich interlayers of the illite-smectite structure. Bitumen coating of the smectite interlayers probably increased the amount of B of organic origin in their sites. The δ11B and δ7Li of the successively expelled hydrocarbon phases changed with increasing pyrolysis temperatures, together with the B and Li contents of the hydrocarbon-related fluids. On the basis of the δ11B and δ7Li from pyrolyzed clay fractions, the B released successively was not isotopically homogeneous, probably depending on how the type of organic matter decomposed during the successive pyrolysis steps, and on which components were released. The δ11B of organic-B increased progressively from –2‰ at low experimental temperature up to +9‰ at the highest temperature. The calculated δ7Li that was released also increased relative to the value of the outcropping sample used as a reference, but it remained almost constant from –7‰ at 310°C for 72 h to –8‰ at 365°C for 216 h. The δ18O values of the <2 μm size fractions decreased significantly during pyrolysis above 300°C, but the δD changes were rather modest. The total organic carbon (TOC) remained statistically constant after pyrolysis to 300°C, as did the δ7Li values. The pyrolysis experiments in the present study suggest the presence of bitumen-coated smectite interlayers that could have been misidentified as dehydrated smectite in the literature. Together with abnormal illite K-Ar ages, the occurrence of such bitumen-coated illite-smectite interlayers occurring in source and reservoir rocks could indicate the timing of hydrocarbon maturation relative to illitization.

Pore Structure and Fractal Character of Lacustrine Oil-Bearing Shale from the Dongying Sag, Bohai Bay Basin, China

To better understand the pore structure and fractal character of lacustrine shales and their influence on liquid hydrocarbon occurrences, in this study, a total of 29 lacustrine oil-bearing shale samples collected from the Shahejie Formation in the Dongying Sag, Bohai Bay Basin, were investigated based on nitrogen adsorption (NGA) analysis combined with TOC, Rock-Eval pyrolysis, X-ray diffraction (XRD), and field emission-scanning electron microscopy (FE-SEM) experiments. The relationships among the compositions (TOC, minerals, and oil content), pore structures, and fractal dimensions of the lacustrine shale samples were discussed. The results showed that the adsorption and fractal characteristics of lacustrine oil-bearing shales differ at relative pressures of 0-0.1 and 0.5-1. Two corresponding fractal dimensions D 1 and D 2 were determined by the FHH model according to the nitrogen adsorption branches. Specifically, D 1 varies from 2.4292 to 2.6109 (mean 2.5245), and D 2 varies between 2.4680 and 2.8535 (mean 2.6889). The specific surface area (SSA) ranges from 1.512 m2/g to 34.002 m2/g, with an average of 13.656 m2/g, the total pore volume is between 6.0 × 10-3 cm3/g and 48.4 × 10-3 cm3/g (mean 24.5 × 10-3 cm3/g), and the average pore diameter is in the range of 4.22 nm to 19.57 nm (mean 9.35 nm). Both D 1 and D 2 increase with increasing SSA and increase with decreasing average pore diameters but have no correlation with pore volume. Moreover, D 1 and D 2 exhibit positive relationships with clay minerals and negative correlations with carbonate minerals (calcite and dolomite). The relationship between fractal dimensions ( D 1 and D 2 ) and TOC contents is expressed as a U-shaped curve, characterized by the minimum D values at approximately 3% TOC. The shale oil content is controlled by the pore structures and fractal dimensions, and lacustrine shales with lower SSAs and smaller fractal dimensions would have more free oil. Therefore, lacustrine shales in the oil window with TOC contents ranging from 2% to 4% are probably the preferred shale oil exploration target in the Shahejie Formation, Dongying Sag, Bohai Bay Basin. The results indicate that fractal analysis can provide insight into the pore structure characteristics and oil storage capacity of lacustrine shales.

Pore structure and controlling factors of dolomite-bearing high-salinity shale reservoir in Qianjiang Formation, Jianghan Basin, China

High-salinity shale is a unique and promising shale-oil reservoir in continental basins. We have collected representative samples from different lithologies from wells in the Qianjiang Depression to test the pore structure and basic character from prospective high-salinity oil-bearing shales. We conducted field emission scanning electron microscopy and X-ray diffraction analyses to study the high-salinity shale pore morphology and composition, respectively. We used mercury injection capillary pressure to understand the high-salinity shale macropore distribution, and we used low-pressure nitrogen (N2) adsorption to study the mesopore distribution. The results show that the high-salinity shale-oil reservoir mainly is composed of carbonate (dolomite and calcite), clay, and saline minerals (anhydrite, glauberite, and halite). Many intergranular pores were developed in the high-salinity shale. The mesopores and macropores both were developed well in argillaceous dolomite. The average pore volume of macropores is 0.0588 ml/g, which accounts for approximately 59% of the total pore volume. Therefore, in the high-salinity shale-oil reservoirs that we tested, macropores were more important than other pores. The symbiosis of dolomite and calcite improved the porosity of the high-salinity shale-oil reservoir, and the salt minerals increased the pore complexity.

1D and 2D Nuclear magnetic resonance (NMR) relaxation behaviors of protons in clay, kerogen and oil-bearing shale rocks

Abstract Few 1D T2 and 2D T1-T2 Nuclear magnetic resonance (NMR) studies have focused on oil-bearing shales with complex constituents and a deeper understanding of the NMR relaxation behaviors of oil confined in shale is needed. In this paper, a series of T2 and T1-T2 NMR experiments were performed on oil-bearing shale and its components (clay minerals and kerogen) to obtain the T1-T2 fluid typing chart and analyze the adsorbed and free oil in shale. The results were as follows: five types of water (bound, adsorbed, free, crystal and structural water) in clay minerals were qualitatively identified and described by the specific T2 to T1/T2 ratio values, and T1-T2 maps were used to qualitatively indicate the clay type. The T1-T2 fluid typing chart containing the signatures of 8 proton populations in oil-bearing shale was defined and included bulk liquid, macropore (>1000 nm) oil, nanopore (

Key factors influencing the low-field NMR characterisation of gas- and oil-bearing shales: a case study of the shales from the southern Sichuan Basin and Dongying sag, China

Key factors influencing the low-field NMR characterisation of gas- and oil-bearing shales: a case study of the shales from the southern Sichuan Basin and Dongying sag, China

Key factors influencing the low-field NMR characterisation of gas- and oil-bearing shales: a case study of the shales from the southern Sichuan Basin and Dongying sag, China

The response characteristics of transverse relaxation time (T2) of key experimental parameters [waiting time (TW), number of scans (NS) and echo number (NECH)], sample size and probe fluid, are analysed systematically based on NMR experiments of oil- and gas-bearing shales from the Shahejie Formation in Dongying sag and the Wufeng and Longmaxi Formations in the southern Sichuan Basin. The results indicate that: 1) the optimised NMR parameters for TW, NS and NECH are 1,500 ms, 64 and 6,000, respectively, which will ensure higher accuracy and signal-to-noise ratio (SNR); 2) the total signal amplitude of the T2 spectrum increases with decreasing grain size. The T2 spectra of shale which grain size bigger than 10 mesh can characterize the shale PSD; 3) water porosity clearly decreases with increasing brittle minerals but decreasing clay content than n-dodecane-saturated porosity, which indicates the hydration of clay and brittle minerals together controls the reconstruction of PSD. [Received: May 30, 2018; Accepted: October 24, 2018]

Formation, distribution and resource potential of the "sweet areas (sections)" of continental shale oil in China

Abstract Shale oil refers to oil stored in organic-rich shale. It is an important part of unconventional oil and provides a large amount of resources. Based on the systematic study of the geological characteristics of shale oil in China's major continental basins, the geological connotation of the “sweet area (section)” in shale oil is proposed in this paper, and it refers to areas that can be preferentially explored and developed in oil-bearing shale formations under current economic and technical conditions. The formation conditions and distribution characteristics of continental shale oil in China are analyzed with a focus on the geological properties of the Triassic Yanchang Formation in the Ordos Basin, the Cretaceous Qingshankou Formation in the Songliao Basin and the Permian Lucaogou Formation of the Jimusar Sag in the Junggar Basin. It is found that the “sweet areas” of shale oil with medium-high maturation are mainly located in thick shales with a Ro greater than 0.9%, and the “sweet sections” are mainly located in the middle and lower parts of the shale formation. The geological resources of continental shale oil in the major continental basins in China are estimated to be approximately 3700 × 108 tons. The in situ conversion process (ICP) may be a key technology for the effective development of medium-to low-mature shale oil. The scale, maximum burial depth and present depth of the organic-rich shale are proposed as the three key parameters for the optimization of pilot sites by taking the Triassic Yanchang Formation in the Ordos Basin as an example. Using ICP, it is expected that the recoverable resources of China's continental shale oil will be approximately (400–500) × 108 tons. The terminology of man-made reservoir is proposed in this paper. In an man-made reservoir, the overall industrial output of the sweet areas (sections) is formed by artificial intervention and the construction of an underground fracture network system with man-made permeability. Continental shale oil may be another revolutionary source of unconventional oil and is expected to be first successfully produced in China.

Geologic significance and optimization technique of sweet spots in unconventional shale systems

Crude oil in unconventional shale systems, present as tight oil and shale oil, accumulates inside an oil kitchen in formations with coexistent sources and reservoirs. Organic matter present in oil shale is not yet mature and requires heating to convert it into crude oil. Oil exploration in shale systems involves the exploration of shale oil retained in source rocks and tight oil rich zones located near source rocks. Tight oil is a type of realistic unconventional oil resources in China. The marked increase in potential shale oil reserves, and exploration of these reserves, will result in a shale oil revolution similar to that experienced for shale gas. Based on a systematic comparison of geologic features of shale systems in the US and China, the geologic significance of the sweet spots in shale systems is proposed. This zone contains an abundance of unconventional oil in shale systems that can be explored and developed under current economic and technical conditions. The sweet spot zone refers to the zone in the tight oil rich zone which has industrial value within the scope of matured high-quality source rocks on the plane. The sweet spot interval refers to the high-productivity interval of tight oil which has industrial value through artificial stimulation. The main aim of oil exploration in shale formations is to identify the sweet spots. The distribution of the economic sweet spots in shale systems is evaluated by overlapping the geologic, engineering and economic sweet spots. Resource assessment techniques, the identification of logging data properties, high-resolution 3D seismic surveys, horizontal well production from well pads, and artificial reservoir development of sweet spots in oil-bearing shale formations can assist efficient development of oil. Globally, shale formations contain a significant volume of oil reserves. Currently, stimulated reservoir volume (SRV) techniques in horizontal wells in marine shale gas formations in the United States have average peak-productivity cycles of 10–15 years. To achieve commecial oil production in lacustrine shale systems in China, it is important to utilize large formation thicknesses and the high abundance of organic matter. In addition, the development of practical and economic techniques will result in an increase of productivity of tight oil and shale oil by 30–50 million tons, as well as the economic development of oil in lacustrine shale systems in China.

Petrophysical characterization of oil-bearing shales by low-field nuclear magnetic resonance (NMR)

Shales are important components of petroleum systems, and it is necessary to reveal their petrophysical properties as reservoirs. Low-field nuclear magnetic resonance (NMR) has proven to be a non-invasive and effective technique for petrophysical characterization of sandstone, carbonate and coal. However, little study has been done using this technique to systematically investigate the petrophysical properties of oil-bearing shales, which is essential for characterizing shale oil reservoirs. In this study, two sets of NMR measurements were performed to reveal the porosity, permeability, movable fluid volume and pore size distribution (PSD) of oil-bearing shales. The results show the following: (1) The NMR T2 spectrum strongly relates to the content of quartz and the amount of dissolution pores within shale. Three T2 spectrum peaks were identified by the relaxation times at 0.03–1 ms, 1–20 ms and >20 ms, corresponding to micropores (<100 nm), mesopores (100–1000 nm) and macropores (>1000 nm), respectively. (2) By combining NMR with centrifugation, both NMR porosity and movable porosity (MP) were calculated. NMR porosity is well consistent with helium porosity, and the MP values strongly relate to the development of mesopores in shales. (3) Based on the T2 spectrum, an effective permeability model was proposed, which can conveniently estimate the permeability of shales. Moreover, two classical permeability models (Coates and SDR) were also used to estimate shale permeability, and the permeability values determined by these models agrees well with helium permeability. (4) In combination with SEM images analyses, an NMR-based PSD was constructed that agrees well with the PSD determined by SEM. The results demonstrate the applicability of NMR relaxation in a systematic investigation of the petrophysical properties of shales, which has potential applications for geophysical logging in shale oil exploration.

Adsorption Properties of Hydrocarbons (n-Decane, Methyl Cyclohexane and Toluene) on Clay Minerals: An Experimental Study

Adsorption of hydrocarbons may significantly affect hydrocarbon migration in unconventional reservoirs. Clay minerals form the primary adsorbent surfaces for hydrocarbons adsorbed in mudstone/shale. To study the adsorption properties of hydrocarbons (n-decane (C10H22), methyl cyclohexane (C7H14) and toluene (C7H8)) on clay minerals (i.e., cookeite, ripidolite, kaolinite, illite, illite/smectite mixed-layer, Na-montmorillonite and Ca-montmorillonite), hydrocarbon vapor adsorption (HVA) tests were conducted at 298.15 K. The results showed that (i) the adsorption amounts of C10H22, C7H14 and C7H8 ranged from 0.45–1.03 mg/m2, 0.28–0.90 mg/m2 and 0.16–0.53 mg/m2, respectively; (ii) for cookeite, ripidolite and kaolinite, the adsorption capacity of C10H22 was less than C7H14, which was less than C7H8; (iii) for illite, Na-montmorillonite and Ca-montmorillonite, the adsorption capacity of C10H22 was greater than that of C7H8, and the adsorption capacity of C7H14 was the lowest; (iv) for an illite/smectite mixed-layer, C7H14 had the highest adsorption capacity, followed by C10H22, and C7H8 had the lowest capacity. Adsorption properties were correlated with the microscopic parameters of pores in clay minerals and with experimental pressure. Finally, the weighted average method was applied to evaluate the adsorption properties of C10H22, C7H14 and C7H8 on clay minerals in oil-bearing shale from the Shahejie Formation of Dongying Sag in the Bohai Bay Basin, China. For these samples, the adsorbed amounts of C7H14 ranged from 18.03–28.02 mg/g (mean 23.33 mg/g), which is larger than that of C10H22, which ranges from 15.40–21.72 mg/g (mean 18.82 mg/g). The adsorption capacity of C7H8 was slightly low, ranging from 10.51–14.60 mg/g (mean 12.78 mg/g).

A model for the interpretation of nuclear magnetic resonance spin-lattice dispersion measurements on mortar, plaster paste, synthetic clay and oil-bearing shale

A model linking the molecular-scale dynamics of fluids confined to nano-pores to nuclear magnetic resonance (NMR) relaxation rates is proposed. The model is used to re-analyse fast field-cycling spin-lattice relaxation rate measurements for the separate water and oil dispersions from an oil-bearing shale [Korb et al., J. Phys. Chem. C, 118, 199 (2014)]. The model assumes that pore fluid can be characterized by three time constants: the surface and bulk diffusion correlation times and a surface desorption time constant. Results are shown to yield meaningful and consistent intra-pore dynamical time constants, insight into diffusion mechanisms and pore morphology. The shale is found to be oil-wetting and the water dispersion is found to be due to the interaction of aqueous Mn2+ ions with bulk water spins. Clay, mortar and plaster paste dispersions measurements have also been successfully re-analysed and a summary of the results is presented. The results demonstrate the wide applicability of the model which advances NMR dispersion experimentation as a powerful tool for measuring nano-porous fluid properties.

Explicit calculation of nuclear-magnetic-resonance relaxation rates in small pores to elucidate molecular-scale fluid dynamics.

Nuclear-magnetic-resonance (NMR) spin-lattice (T_{1}^{-1}) and spin-spin (T_{2}^{-1}) relaxation rate measurements can act as effective nondestructive probes of the nanoscale dynamics of ^{1}H spins in porous media. In particular, fast-field-cycling T_{1}^{-1} dispersion measurements contain information on the dynamics of diffusing spins over time scales spanning many orders of magnitude. Previously published experimental T_{1}^{-1} dispersions from a plaster paste, synthetic saponite, mortar, and oil-bearing shale are reanalyzed using a model and associated theory which describe the relaxation rate contributions due to the interaction between spin ensembles in quasi-two-dimensional pores. Application of the model yields physically meaningful diffusion correlation times for all systems. In particular, the surface diffusion correlation time and the surface desorption time take similar values for each system, suggesting that surface mobility and desorption are linked processes. The bulk fluid diffusion correlation time is found to be two to five times the value for the pure liquid at room temperature for each system. Reanalysis of the oil-bearing shale yields diffusion time constants for both the oil and water constituents. The shale is found to be oil wetting and the water T_{1}^{-1} dispersion is found to be associated with aqueous Mn^{2+} paramagnetic impurities in the bulk water. These results escalate the NMR T_{1}^{-1} dispersion measurement technique as the primary probe of molecular-scale dynamics in porous media yielding diffusion parameters and a wealth of information on pore morphology.

Microstructural and geomechanical analysis of Bakken shale at nanoscale

With the development in production from shale oil and shale gas in North America during the last decade, more studies are being conducted in order to improve our knowledge of the shale characteristics. In this paper, samples from Upper and Middle Bakken Formation, which is an oil-bearing shale formation, were collected and analyzed. Permeability, porosity and saturation of the samples were studied in the lab. 2D XRD and EDX were used to study the mineral compositions, and FESEM was used to characterize the pore structure at micro and nanoscale. Implementing the image analysis method, the pore structure and pore size distributions (PSD) of the samples at nanoscale were quantified. In addition, nanoindentation method, which is a novel technique to investigate the geomechanical behavior of rocks, was applied to quantify the mechanical properties of the shale samples including Young's modulus, hardness, and fracture toughness at nanoscale.

Permian endemic bivalves of the “Irati anoxic event”, Paraná Basin, Brazil: Taphonomical, paleogeographical and evolutionary implications

Anoxic to dysoxic conditions must have existed in the Paraná Basin during the deposition of the Permian oil-bearing shales of the Irati Formation, reflecting the marine isolation of the basin from the Panthalassic Ocean. In this environment, benthic invertebrates are extremely rare, in contrast to the overlying Serra Alta and Teresina formations, which were deposited in dysoxic/oxic waters, respectively. Hence, the abundant shallow-burrowing, endemic bivalves recorded in the shales of the basal portion of the Irati Formation are one of the most distinctive features of this stratigraphic interval. Their preservation in offshore deposits is, however, a product of storm flows in shallow waters that swept the shells to distal settings. Subsequently, these were sorted by long-lasting shelf currents that produced dense (2–5shells/20cm2) pavements in which shells in a hydrodynamically stable posture (convex-up) predominate, forming thin, complex shell concentrations despite their simple internal stratigraphy. The new data presented here have important paleoecologic, paleogeographic and evolutionary implications and indicate that (a) during the deposition of the oil-rich shales of the Irati Formation, numerous benthic bivalves thrived in the contemporary shallow-water bottoms of the Paraná Basin; (b) the mono- to paucispecific nature of the studied shell-rich pavements is, in part, due to hydrologic shell transport; and (c) restricted connections to open ocean waters (Panthalassa) existed during Irati times. Therefore, the origin of the endemic Passa Dois molluscan fauna occurred somewhere between the interval represented by the underlying Palermo Formation and the basal portion of the Irati Formation. Finally, these endemic bivalves appeared at least ~10millionyears earlier than previously thought.

Characteristics and resource prospects of tight oil in Ordos Basin, China

AbstractEfficient large-scale development of ultra-low-permeability reservoirs (0.3–1mD) has been achieved in the Changqing Oilfield, Ordos Basin of China. According to unique features of petroleum exploration and development in this basin, tight oil herein refers to petroleum that occurs in oil-bearing shales and interbedded tight sandstone reservoirs adjacent to source rocks with ambient air permeability <0.3mD. Tight oil in tight sandstone and shale have generally not yet experienced large-scale long-distance migration. In the Yanchang Formation, tight oil has mainly accumulated in the semi-deep to deep lacustrine facies, typically in oil-bearing shales and tight sandstones of the 7th member oil-bearing formation and tight sandstones of the 6th member oil-bearing formation in the center of the basin. Tight oil resource in the Ordos Basin is characterized by wide spatial distribution, excellent source rocks, extremely tight sandstone reservoirs, complex pore throat structures, poor physical properties, high oil saturation, good crude-oil properties, and low reservoir pressure. A fundamental feature of the continuous oil and gas accumulation in tight oil reservoirs is the widespread development of nano-scale pore-throat systems. In the Yanchang Formation, most of connected pore throats in tight sandstone reservoirs have diameters greater than critical pore throat diameter, allowing oil and gas migration in the tight reservoirs. According to contact relationship between tight reservoirs and source rocks, three types of tight oil reservoirs are identified in the Yanchang Formation, i.e., tight massive sandstone reservoir, sand - shale interbed reservoir, and oil-bearing shale reservoir. In the Ordos Basin, tight oil is widely distributed in the 6th and 7th members of the Yanchang Formation, with total resources estimated to be 3×109 t. These include > 1×109 t of oil resources in shale in the 7th member of the Yanchang Formation and approximately 0.9×109 t and 1.1×109 t of tight sandstone oil resource in the 6th and 7th members of the Yanchang Formation, respectively. These tight oil resources are the realistic resources addition for the oilfield, which can ensure an annual production of 50×106 t of oil and gas equivalent and maintain long-term stable oil production in the Changqing Oilfield, Ordos Basin, China.

Carlsonite, , and huizingite-(Al), (NH4)9Al3(SO4)8(OH)2·4H2O, two new minerals from a natural fire in an oil-bearing shale near Milan, Ohio

Carlsonite, , and huizingite-(Al), (NH₄)₉Al₃(SO₄)₈(OH)₂·4H₂O, two new minerals from a natural fire in an oil-bearing shale near Milan, Ohio