Minerals In Shale Research Articles

A Study on the Surface Wettability of Clastic Rocks with Potential Application for CO2 Storage Sites

There have been many studies carried out in the past decades attempting to develop strategies for a safe injection of CO2 into storage sites without leakage and contamination of valuable resources. Leakage from these storage sites through capillary seals is one of the long-standing issues, which require a comprehensive assessment prior to CO2 injection. However, surface wettability, which is one of the major parameters controlling the capillary pressure of seals, is a poorly understood parameter, changing as a function of temperature, pressure, surface roughness, etc. The aim of this paper is to provide a deeper insight into the surface wettability of minerals in rocks, especially sandstone and shales, under subsurface conditions for a better assessment of the structural integrity in CO2 storage sites. The results obtained from a series of contact angle measurements under different pressure and temperature conditions indicated that quartz- and feldspar-dominated sandstones are strongly water wet, while kaolinite-dominated shales have a weakly water to intermediate wet system. It is also apparent that the interfacial tension is a function of the pressure and temperature conditions. It appears that the size of pore throats in rocks is the major contributor to capillary threshold pressure and it must be determined very accurately. It is recommended that surface wettability and interfacial tension under reservoir conditions are determined a priori to ensure that the seal integrity analysis is as concise as possible.

Methane adsorption capacity of marine-continental transitional facies shales: The case study of the Upper Permian Longtan Formation, northern Guizhou Province, Southwest China

Factors influencing the methane adsorption capacity (MAC) of marine-continental transitional facies shales have been identified applying a variety of techniques (e.g., total organic carbon (TOC) content, X-ray diffraction mineralogy, low-pressure CO2 and N2 adsorption, and methane adsorption analyses) on samples from the Upper Permian Longtan Formation, northern Guizhou Province, Southwest China. The TOC contents of the Longtan shale samples ranged between 1.2 and 9.9 wt% (average = 3.5 wt%). The results of the bulk XRD analysis suggested that the mineralogical composition of the studied samples was different from that of typical marine shales: the samples primarily consisted of clay minerals, followed by quartz and feldspar. The Langmuir volumes (VL) of the 14 shale samples ranged from 1.02 ml/g to 5.25 ml/g (average = 2.52 ml/g); moreover, their MAC was positively correlated with the pore volume, surface area, and TOC content, suggesting that organic matter and pore structure were the most critical factors influencing the adsorption capacity of these transitional shales. Our results showed that the MAC was not positively with the clay content; additionally, the MAC tended to increase with increasing pressure, but to decrease with increasing temperature. The presence of moisture greatly reduced the MAC. Overall, the MAC of the transitional Longtan Formation shales resulted to be quite different from that of typical marine shales (e.g., the Lower Silurian Longmaxi Formation in the Sichuan Basin) in terms of mineralogical component and abundance of organic pores. The particularly high abundance of (hydrophilic) clay minerals in the Longtan Formation transitional shales resulted in a higher number of adsorption sites occupied by water molecules than in the Longmaxi Formation and a lower MAC. Finally, the abundance of organic pores in marine shales resulted in a higher MAC than that of transitional shales.

Factors influencing shale gas accumulation in the lower Silurian Longmaxi formation between the north and South Jiaoshiba area, Southeast Sichuan Basin, China

Abstract Owing to successful shale gas exploration and development, wells were drilled into the Longmaxi shale formation in the Jiaoshiba area, Southeast Sichuan Basin, China. However, shale gas production in Longmaxi varies greatly between the North and South Jiaoshiba areas. To determine the factors controlling the shale gas accumulation mechanism, the total organic carbon (TOC) content, mineralogy, porosity, permeability, total gas content, gas preservation conditions, and tectonic activities of Longmaxi Shale in both the North and South Jiaoshiba areas were studied in detail. The results show that the concentration of organic matter and minerals in the Longmaxi shale differed slightly between the South and North Jiaoshiba areas, and the lower Longmaxi Shale (Long 1 Member), which is used in commercial shale gas production, is characterized by a high quartz content and low clay content. In addition, the Longmaxi shale in the North Jiaoshiba area is characterized by high porosity and low permeability, while that in the South Jiaoshiba area has low porosity and high permeability. Two different reservoir types were identified in the Jiaoshiba area. The major storage spaces are pores in the Longmaxi shale reservoirs located in the North Jiaoshiba area, while the storage capacity of shale reservoirs in the South Jiaoshiba area is predominantly provided by fractures. Shale gas mainly exists as free gas in the Northern Jiaoshiba area due to the good gas preservation conditions. However, owing to the development of abundant faults in the South Jiaoshiba area, a large amount of free gas was lost, causing absorbed gas to dominate the shale reservoir in this area.

Effect of lithofacies on the pore system of over-mature Longmaxi shale in the Jiaoshiba area, Sichuan Basin, China

Abstract Ten Longmaxi shale samples were collected from the Jiaoshiba area, China, where 5 billion cm 3 /year of shale gas is produced. The samples were evaluated to characterize the pores of various shale lithofacies. Three shale lithofacies were determined in the Jiaoshiba area, Sichuan Basin, China, based on the shale mineral components, namely, siliceous lithofacies (SL), argillaceous lithofacies (AL), and mixed lithofacies (ML). Field emission scanning electron microscopy (FE-SEM), which was performed under high and low voltages, GRI porosity, and carbon dioxide and nitrogen adsorptions were used to investigate the bulk-shale porosity, pore type, pore size, pore morphology, and pore volume among the lithofacies. Lithofacies affects the shale total organic carbon (TOC), bulk-shale porosity, pore size, shape, and volume. SL and ML contain high porosity, high TOC, abundant organic-matter (OM)-hosted pores, and high OM porosity, whereas AL contains few OM pores and has low TOC and low porosity. In the same lithofacies, samples with various TOC values exhibit different pore morphologies. For SL, the low-TOC sample has a round and elliptical OM pore forms, whereas the high-TOC samples show linear and narrow pore shapes that are probably associated with gas expulsion. In ML, the higher TOC is related to spherical or near-spherical OM pores, whereas the OM pore shape collapses in the low-TOC shale. Therefore, lithofacies affect the shale reservoir, and the characteristic and evolution of OM pores should be considered as constraints in shale lithofacies. In SL, sections with a higher TOC value are prime targets despite the high expulsion efficiency, which does not affect the enrichment and high yield of the shale gas. Sections of ML and low-TOC SL should be considered as potential targets because of higher OM porosity and low expulsion efficiency, whereas sections of AL engender risk in exploration and development of shale gas.

Influencing factors and fracability of lacustrine shale oil reservoirs

Abstract Shale oil reservoirs need fracturing in order to achieve commercial productivity. A key factor influencing the fracturing process is shale fracability, which is strictly dependent on rock fabric. In this study, we focused on the lacustrine shale oil reservoirs located in Dongying Sag and in the Northern Jiangsu Basin. Through X-ray mineral diffraction, rock mechanics, and P- and S-wave velocity tests, we analyzed the mineral components and mechanics of different shale lithofacies, as well as the influence of these factors on shale fracability. Based on the results of these analyses, we proposed a new method for the evaluation of lake shale oil reservoir fracability. The experimental results showed that the macrostructure, mineral content, lithology, and the presence of microfractures in the shale are the main factors affecting its brittleness. Shales with lamellar and sheet-like structures have relatively high Young's modulous or lower Poisson's ratios; under these conditions, netted fractures are easily formed during fracturing. The fracture toughness of carbonate minerals in shales is strong. An appropriate amount of carbonate minerals seemed to increase the shale brittleness; however, an excessive amount increased its cohesiveness, hindering the initiation and propagation of fractures. Felsic minerals are characterized by high brittleness, a characteristic that favors shale fracability; on the other hand, clay minerals and organic matter are highly plastic, a characteristic that hinders fracturing transformations. Due to their macrostructure and composition, lamellar clayey limestones (dolomite), lamellar clayey siltstones, layered calcareous (dolomitic) siltstones, sheet-like clay-containing siltstones, and flaggy carbonate-containing siltstones are expected to be easily fractured. In addition, the presence of microfractures seemed to reduce the overall fracture toughness of the rock: they penetrated artificial fractures, enhancing rock fracability. Taking into account the fracture toughness of carbonate minerals and the plastic effect of organic matter, we proposed a new formula for the calculation of the brittleness index, based on the mineral component method. The brittleness indices obtained through the proposed formula were linearly correlated with those calculated through the rock mechanics parameters method. Overall, our results indicate that the silty lithological successions occurring in the study area should be the easiest to fracture, followed by the calcareous (dolomitic) and clayey or organic-rich lithological successions. This study is of guiding significance for evaluating the fracability of different lithofacies in lacustrine shale oil reservoirs. Especially, the new proposed brittleness index containing the plastic effect of organic matter can correctly evaluate the actual brittleness of organic-rich shale.

Study on the Mechanism of Ionic Stabilizers on Shale Gas Reservoir Mechanics in Northwestern Hunan

The shale of the lower Cambrian Niutitang formation in northwestern Hunan is an ideal reservoir for shale gas. There is a close connection between borehole stability and drilling fluid in shale gas drilling. Ionic stabilizer is a new type of stratum consolidation agent that inhibits the hydration expansion of clay minerals and improves mechanical strength of the borehole. The traditional idea of pore wall protection is to use drilling fluid additives to prevent shale from interacting with water. However, ionic stabilizer can change the hydrophilic of clay minerals in shale, making the particles become hydrophobic and dense, therefore, the formation stability can be enhanced simultaneously. The material used in this paper is different from the normal ionic stabilizer, some chemical bonds that have been changed in the new material called enhanced normality ionic (ENI) stabilizer. This paper utilized the shale samples those obtained from Niutitang formation to study the connection between ENI and the mechanical properties of shale. Mechanical tests and microscopic pore tests were performed on different samples which were soaked in water and the ENI with different concentrations. It has been found through tests that ENI can inhibit the development of shale pores, and as the concentration increases, the inhibition increases. In addition, as the ENI concentration increases, the uniaxial compressive strength and Young’s modulus of the shale increase, and the ratio of stability coefficients decreases. It can be concluded that the ENI can improve the mechanical strength of carbon shale, and prevent the development of rock damage. Moreover, it can improve the ability of rock to resist damage, and enhance borehole stability initiatively.

Quantitative evaluation of free gas and adsorbed gas content of Wufeng-Longmaxi shales in the Jiaoshiba area, Sichuan Basin, China

Quantitative analysis of free gas and adsorbed gas content in shale reservoirs is great significance for efficient exploration and development of shale gas. Based on the isothermal adsorption experiment of shale samples from Wufeng Formation to Longmaxi Formation of JYA well in Jiaoshiba area and Langmuir volume model, the relationship between shale adsorption capacity and temperature, pressure, organic carbon content, quartz and clay mineral content is analyzed. Besides, the key parameters such as Langmuir volume and Langmuir pressure are dynamically calibrated by combining grey correlation method. A new model for calculating adsorbed gas and free gas is established, which takes fully into account the formation temperature, pressure, TOC and shale mineral components. The results showed that the gas content of shale calculated by the new dynamic modified model is in good agreement with the actual gas content characteristics of shale reservoirs. The new model fully takes into account the vertical and horizontal heterogeneity of mineral components and its influence on shale adsorption capacity. That is suitable not only for the tectonic stability area but also for the analysis of gas content in the area with strong tectonic movement. It is concluded that the modified calculation model can effectively predict the adsorbed gas, free gas and total gas content of shale reservoirs under formation conditions, which can be used as an indicator for the analysis and prediction of the exploration and development potential of shale gas wells. Cited as : Gou, Q., Xu, S. Quantitative evaluation of free gas and adsorbed gas content of Wufeng-Longmaxi shales in the Jiaoshiba area, Sichuan Basin, China. Advances in Geo-Energy Research, 2019, 3(3): 258-267, doi: 10.26804/ager.2019.03.04

THE LIMITS OF BURGESS SHALE-TYPE PRESERVATION: ASSESSING THE EVIDENCE FOR PRESERVATION OF THE BLOOD PROTEIN HEMOCYANIN IN THE BURGESS SHALE

Cambrian deposits bearing exceptional preservation of soft-bodied fossils offer unique insights into the diversity and paleobiology of the Cambrian biota. In recent years, a growing number of studies have provided evidence that highly labile tissues, such as nervous tissues, may be more common in fossils from Burgess Shale-type deposits than previously appreciated. These discoveries have provided novel insights into the anatomy and phylogeny of Cambrian animals and have also challenged the basic understanding of the limits on the resolution of anatomical information that may be captured by Burgess Shale-type preservation. Evidence used to infer primary blood chemistry was recently reported from the iconic Burgess Shale fossil Marrella splendens, the first such report from a Cambrian Lagerstatte. Diminutive crystals of a copper sulfide mineral found in association with Marrella were interpreted as evidence that the animal's blood contained the Cu-bearing protein hemocyanin. Copper minerals in shales in general, and in the Burgess Shale in particular, however, may have a complex geologic history. Using microscopy and SEM-EDS elemental mapping of material from the Walcott Quarry as well as from the Burgess Shale fossil quarry at Marble Canyon, we assess the timing of emplacement of Cu-sulfides in fossil-bearing mudrocks of the Burgess Shale. These data demonstrate that copper minerals are most conspicuously concentrated within veins that are oriented sub-perpendicular to bedding. These late-stage fluid flow paths allowed Cu-mineralizing fluids to infiltrate bedding plane-parallel cracks, which commonly run through Burgess Shale fossils and extend into the matrix around them. Based upon the relationships of mineral phases associated with fossils, it appears that Cu-mineralization occurred after metamorphic volatilization of a large proportion of the carbonaceous material that originally comprised the fossils. We find that copper minerals in the Burgess Shale are of demonstrably post-Cambrian origin, a secondary overprint that cannot be used to infer original blood chemistry or tissue composition of its fossils.

The effects of mineral composition, TOC content and pore structure on spontaneous imbibition in Lower Jurassic Dongyuemiao shale reservoirs

Spontaneous imbibition (SI) is a capillary-force controlled process, which has been identified as one of the most important mechanisms to affect hydrocarbon recovery from unconventional shale reservoirs. In this work, we focus on the mineral composition, total organic carbon (TOC) content, pore geometry characteristics and fluid imbibition behaviors of the terrestrial Lower Jurassic Dongyuemiao shale reservoirs. The pore morphology is directly imaged and observed via field emission-scanning electronic microscope (FE-SEM). Nitrogen (N2) physisorption and mercury intrusion porosimetry (MIP) are applied to investigate the pore geometry characteristics. The slopes of deionized (DI) water/n-decane imbibition from fluid imbibition experiments are used to evaluate the pore connectivity characteristics of hydrophilic and hydrophobic pore spaces, respectively. Finally, the relationships between shale dominant mineral composition, TOC content and pore structure parameters on fluid imbibition behavior are discussed. Experimental results show that clay and quartz are the two dominant minerals in the Dongyuemiao shales. In this study, four typical lithofacies are identified in the Dongyuemiao shales, including laminated or massive mudstone, silty mudstone, shell limestone and argillaceous siltstone. Organic matter (OM) pores and interP pores are the dominant pore types in the Dongyuemiao shales, and most of the pores with sizes smaller than 50 nm. The imbibition slopes of n-decane are generally higher than that of DI water, indicating better pore connectivity of hydrophobic pores. Due to protection by quartz grains, samples with higher abundances of quartz are beneficial for forming a connected pathway for DI water migration, resulting in a better-connected water-wet pathway. The hydrophobic and hydrophilic pore networks in samples with higher TOC content are better connected, which are speculated to be related to the high volume of connected organic matter in shale matrix. Positive correlations occur between porosity/pore volume and fluid (including DI water and n-decane) imbibition slopes, suggesting that the connectivity of pore networks become better as porosity and pore volume increase, regardless of whether the pores are hydrophobic or hydrophilic.

Mechanistic assessment of Seidlitzia Rosmarinus-derived surfactant for restraining shale hydration: A comprehensive experimental investigation

The physicochemical aspect of wellbore stability is linked to the interaction between the drilling fluid and rock (e.g., shale). By far, most of the surfactants utilized in the oil industry are identified with environmental drawbacks. This paper appraises for the first time the functionality of a novel environmentally-friendly bio-based surfactant, Seidlitzia Rosmarinus leaf and stem extract (SRLSE), in water-based drilling fluids (WBDF) for inhibiting shale hydration. The swelling inhibitive property of SRLSE was thoroughly evaluated using several experiments including clay inhibition, cuttings dispersion, filtration, particle size measurement, scanning electron microscopy (SEM) and thermal gravimetric analysis (TGA). The findings implied that as opposed to deionized water, the aqueous solution of SRLSE indicated fairly low rheological profiles which resulted in a greater degree of montmorillonite (MMT, an active mineral in shale) loading (22.5mass%). Addition of 3 mass% SRLSE and 8 mass% SRLSE to deionized water resulted in a shale cuttings recovery improvement of 20.8% and 40.5%, respectively. MMT in deionized water gave a fluid loss of 26ml. However, it exhibited a poor fluid loss control in the aqueous solution of SRLSE so that the fluid loss volume increased up to 73ml. As opposed to deionized water, the particle size of MMT in SRLSE aqueous solution rose extremely. According to TGA, the modified MMT in the aqueous solution of SRLSE imposed 2.88% less water content with respect to the modified MMT in deionized water. From SEM observations, MMT in SRLSE aqueous solution exhibited larger aggregates than deionized water. In addition to the aforementioned results, compatibility tests proved that SRLSE is well-compatible with typical WBDF additives. All the experimental results implied that SRLSE can be considered a capable shale inhibitor in WBDF. The interaction between the hydrophilic tail of saponin (a dominant constituent of SRLSE) and MMT's surfaces which forms a hydrophobic shell is perhaps the leading inhibition mechanism for SRLSE.

Division of shale sequences and prediction of the favorable shale gas intervals: an example of the Lower Cambrian of Yangtze Region in Xiuwu Basin

Abstract It is a common method to use sequence stratigraphic theory to identify favourable intervals in hydrocarbon exploration. The Lower Cambrian shale of Well Jiangye-1 in Yangtze Region in Xiuwu Basin was chosen as the research object. The content of excess silicon of siliceous minerals in shale was calculated quantitatively, and the concentration distribution of Al, Fe, Mn showed that the excess silicon is of hydrothermally origin and the shale deposited in an environment with hydrothermal activity. Using U/Th values in the study, combined with lithology and logging data, in order to divide sequences of the Lower Cambrian shale in Yangtze Region in Xiuwu Basin. The result shows that the shale of the Lower Cambrian shale is recognized as 1 2nd sequence (TST-RST, TST = Transgressive systems tract; RST = Regressive systems tract) and then further subdivided into 5 3rd sequences (SQ1-SQ5). During the deposition of SQ2 and SQ3, hydrothermal activity was active, and their excess silicon content was generally above 20%-30%. Rising sea level and active hydrothermal activity were beneficial for the enrichment of siliceous minerals and organic matter. Based on the comparison of the reservoir parameters, it tells that SQ2 and SQ3 have relatively higher content of TOC, higher content of brittle minerals (such as siliceous minerals, carbonate minerals and so on), larger effective porosity and higher content of gas, which make it as the most favourable intervals of the Lower Cambrian in Xiuwu Basin.

Fractal characteristics of nanopores in lacustrine shales of the Triassic Yanchang Formation, Ordos Basin, NW China

Abstract To further understand fractal characteristics of nanopores in lacustrine shales, core samples from Chang-7 and Chang-9 members of the Triassic Yanchang Formation, southern Ordos Basin were investigated. Total organic carbon content, vitrinite reflectance, X-ray diffraction, field emission-scanning electron microscopy and low pressure N2 physisorption (LPNP) experiments were performed. The Frenkel-Halsey-Hill (FHH) method was applied to characterize the fractal dimensions using LPNP isotherms. Two fractal dimensions (D1 and D2) were determined at relative pressures of 0-0.45 and 0.45-1, respectively. The Chang-7 shales have a D1 and D2 range of 2.17-2.36 and 2.46-2.63, while the Chang-9 shales have D1values of 2.23-2.40 and D2 values of 2.46-2.64. Fractal dimensions of the selected lacustrine shales are affected by shale mineral compositions and pore structure parameters. Positive correlations of D1 and D2 with clay minerals and quartz contents, and negative correlations of D1 and D2 with TOC contents were presented in the present study. Observations of few organic matter pores and abundant inorganic pores hosted in the Yanchang shales may contribute to these correlations. In addition, comparisons of matrix composition, nanopore fractal characteristics between the Chang-7 shales and the Chang-9 shales suggest that the latter may have more irregular and heterogeneous pore structure.

Upgrading low-quality oil shale using high-density gas-solid fluidized bed

Oil shale is a high-value fuel resource and its global output is gradually increasing with time. Based on the analysis of physical properties of oil shale, a sorting process for high-density dense-phase gas-solid separation using fluidized bed is proposed. During the separation process in a gas-solid separation fluidized bed, a binary mixture of oil shale’s mineral powder and ferrosilicon powder is formed. This paper systematically analyzes the separation characteristics of ferrosilicon powder. Furthermore, the influence of different factors (fluidization number N, and oil shale’s powder grade) on the degree of mixing of particles in the binary mixture and the influence of binary heavy medium ratio on the stability of bed are also studied. The results show that the weight of ferrosilicon is prone to stratification and grading in the fluidized bed due to its own particle size composition. The mixing process of oil shale mineral powder and ferrosilicon powder plays a crucial role in the adjustment of bed density. The density gradually narrows with the increase in the value of fluidization number. For the same fluidization number, the bed density decreases with the increase in the mass fraction of oil shale's mineral powder. The oil shale is separated under optimized operating conditions (particle size of 0.5–0.9 mm, mixing ratio of 10%, and fluidization number of 1.4). The yield of concentrate is 27.18%, while the oil content is 10.76%. Furthermore, the yield of tailings is 77.61%, whereas the oil content is 1.46%. Additionally, the separation precision (possible error) E has the value of 0.113.

CT-based 3D reconstruction of the geometry and propagation of hydraulic fracturing in shale

Hydraulic fracturing is one of the primary techniques which has been widely implemented in order to allow for the stimulation of shale gas reservoirs. To accurately distinguish the extension characteristics and the spatial distribution of fractures during the hydraulic fracturing of the Longmaxi shale reservoirs in Changning, a self-developed, multifunctional, true triaxial experimental process (utilizing a fluid-solid coupling testing system) was used to simulate the horizontal well hydraulic fracturing. The CT technique was used to scan the samples prior to and following the conduction of the experiments; the CT scanning images of internal fractures were reconstructed and visualized via 3D reconstruction. The influence of in-situ stress, the displacement of the fracturing fluid upon the fracture morphology and the resultant fractural extensions caused by hydraulic fracturing were discussed. The study shows that the reconstructed 3D model based on the different CT values corresponding to the shale matrix, minerals and fractures can accurately characterize the internal structure and fracture distribution of shale. Shale hydraulic fracturing fractures can be divided into 3 categories: single transverse fractures, main arc fractures and complex fractures. The “fluctuation phenomenon” of a water pressure curve is related to the formation and extension of reservoir fractures, and is a discernible characteristic of complex fractures formed by the volume fracturing of shale. Stress differences and the stress difference coefficient are the governing factors in terms of the complexity of shale hydraulic fracturing networks. Displacement has a particular range of influence on the manifestation of fracture complexity; a low displacement may not result in a complete fracture, but too high a displacement tends to culminate a single fracture in the formation, which to a certain extent reduces fractural complexity.

Assessing shale mineral composition: From lab to seismic scale

Shales have always been a difficult target for drilling of deviated and horizontal wells. In the presence of azimuthal stress fields, inclined boreholes in smectite-rich shales exhibit geomechanical instabilities and can result in borehole failure. The complex geology of the major gas fields in the Northern Carnarvon Basin on the North West Shelf of Australia makes it necessary to drill deviated wells through the smectite-rich shale seal extending more than 1 km in thickness. Predicting the mineralogical composition of shales in the area is therefore crucial for the success of drilling operations related to hydrocarbon exploration and production. Here we introduce a novel workflow that combines seismic data, well logs, and laboratory measurements to rapidly infer smectite content in shale. The workflow is applied to the Duyfken 3D seismic survey in the central part of the Northern Carnarvon Basin. The results of our quantitative interpretation are verified against the laboratory X-ray diffraction measurements from the test well that was not used for interpretation, and they match the test data well within the determined uncertainty bounds.

Characterization of quartz in the Wufeng Formation in northwest Hunan Province, south China and its implications for reservoir quality

Quartz is one of the most important and common minerals in marine shales. This is especially true for the Wufeng-Longmaxi and Niutitang Formations in south China. However, the type, origin and formation mechanism of the quartz in these marine shales are as yet unclear. Thirteen samples of Ordovician shale from the Wufeng Formation in northwest Hunan Province were collected for this study. The quartz within the Wufeng shale was characterized through a series of experiments employing scanning electron microscopy with cathodoluminescence, nitrogen physisorption, X-ray diffraction, and geochemical analysis. The results were then used to assess the implications of the quartz component for reservoir quality. Three quartz types were identified based on scanning electron microscopy and cathodoluminescence imaging. Type I quartz has a relatively large grain size and exhibits bright luminescence, indicative of a terrigenous origin, whereas Type II and Type III quartz is authigenic and has dull or no luminescence. Type II quartz has small grain sizes and may be mainly biogenic in origin. This type of quartz may have formed during early diagenesis, with the silica being sourced from the dissolution of siliceous organisms. Type III quartz generally appears as dark rims on Type I quartz grains; the silica may have been derived from clay mineral alteration, with quartz-formation occurring during middle or late diagenesis. The authigenic quartz (Types II and III quartz) likely formed as a cement and would be expected to generate brittle behavior. The shale with a high content of authigenic quartz has a high Young's modulus and low Poisson's ratio. The biogenic authigenic quartz (Type II quartz) was pore-filling and formed during shallow burial. It would thus have been able to resist further compaction and provide a rigid framework within which the primary pores in the shale could be preserved, controlling the distribution of organic matter and the development of organic pores. The biogenic authigenic quartz has positive relationships with porosity and pore volume and specific surface area. Shale that was high in biogenic quartz had high porosity and adsorption capacity. The characterization of quartz in marine shales has significance for shale gas exploration and development and provides a new angle for evaluating the fracability and storage capacity of shale gas reservoirs.

Provenance, shallow to deep diagenesis, and chemical mass balance in supermature arenites and pelites, Ordovician Simpson Group, Oklahoma and Kansas, U.S.A.

This study, considering original detrital compositions and diagenetic alterations, relates sandstone and shale mineral and chemical composition to provenance and mass balance between the sedimentary assemblage and its provenance. Mature quartz-rich sandstones and siltstones with clay-rich shales in cores at depths of 60 m–5.2 km and burial temperatures of <50 to >150 °C from over 50 wells were utilized in this work. These provide the material for analysis of compositions and alterations in coastal and shallow marine clastic sedimentary rocks of the Middle Ordovician Simpson Group in Oklahoma and Kansas, U.S.A. Mineral and geochemical data were obtained by optical petrography, X-ray diffraction, scanning electron microscopy, electron microprobe, and whole rock X-ray fluorescence and ICP/MS analyses. Results of the study show significant progressive diagenetic changes with increased burial depth and temperature. Mineralogically and chemically, less altered rocks are comparable to modern quartz-rich sands and kaolinitic muds in siliciclastic sediments developed during humid tropical weathering in crystalline basement shield provenance in Africa and South America. By analogy to modern tropical cases, muds composed of major kaolinite with minor smectite and illite at deposition, were diagenetically transformed to illite-rich rocks by possible microbial action, at surface to shallow (<200 m, <40 °C) burial with influx of K, Rb and Mg from seawater. In sandstones, early open system diagenesis with calcite cementation and quartz overgrowths occurred at <1 km depth and < 40 °C. Further closed system silica diagenesis and K-metasomatism, occurred with deeper burial (to 3+ km and 100 °C) in the Pennsylvanian and Permian and later, during and following uplift of the Arbuckle and Wichita Mountains, with establishment of a new fold and thrust belt structural and hydrologic regime. Pressure solution of quartz and the illite to muscovite transformation in shales in the depth range 3–8 km, yielded silica for later generation quartz cement (10- >20%) in sandstone buried >3 km. During deep burial, high temperature (>110 °C) calcite cement from deep basin sources was precipitated in sandstones. Geochemical mass balance estimates, physical, and chemical evidence suggest quartz cement was sourced from within clastic rocks of the Simpson Group with minor external contribution of SiO2. Na is in low abundance due to loss in solution during weathering in the provenance. Rare earth elements (REE) have typical abundances and distributions in shales with enrichment in light REE; littoral environment siltstones and matrix-rich sandstones display enrichment of heavy REE in phosphatic brachiopod shell fragments.

Molecular simulation of methane adsorption within illite minerals in the Longmaxi Formation shale based on a grand canonical Monte Carlo method and the pore size distribution in southeastern Chongqing, China

In order to investigate the pore structure and the adsorption capacity of illite with respect to the methane in the Longmaxi Formation, isothermal adsorption experiments utilizing mercury intrusion, liquid nitrogen, and low-temperature carbon dioxide techniques were applied to the shale samples from southeastern Chongqing. The adsorption characteristics of illite slit pores varying in diameters were simulated using a Monte Carlo method. The results reveal that the pore volume and the specific surface area of the shale are primarily supplied by pore diameters measuring less than 2 nm. Illite is one of the primary components of the clay mineralogy within the shale that forms parallel or nearly-parallel plate pores. For pore sizes ranging from 0.5 nm to 0.9 nm (at conditions of 303.15 K and 8 MPa), the methane molecules are affected by van der Waals and electrostatic forces that leads to a large excess in the adsorption capacity of methane. Once the pore size becomes less than 0.9 nm, the methane adsorption becomes primarily affected by van der Waals forces. At the said size, the excess adsorption capacity of methane initially decreases, after which it remains constant with an increase in the pore size. The free gas content surges with the growing pore diameters. The average equivalent adsorption heat reflects that the adsorption of methane onto illite is characterized by physical adsorption. During the adsorption process, when the pore size is between 0.5 nm and 1.2 nm, the average equivalent adsorption heat decreases rapidly with an increase in the pore diameter. In pore size that exceeds 1.2 nm, the adsorption intensity between the methane molecules and the illite slit becomes stable. In this case, the average adsorption heat is measured to be 6.72 kJ/mol. Meanwhile, the monolayer of methane is adsorbed onto the pore wall and the local density of methane exhibits the characteristics evident of that of a single peak when the pore size is between 0.5 nm and 0.8 nm. The adsorption mode changes from single-layer adsorption to double-layer adsorption when the pore size is between 0.8 nm and 1.2 nm. In addition, the local density curve changes from unimodal to bimodal. In pores sized larger than 1.2 nm, the free volume of methane adsorption can be larger, wherein the local density curve is bimodal.

Nanoscale Surface Properties of Organic Matter and Clay Minerals in Shale.

Surface properties of shale play an essential role in adsorption, transport, and production of hydrocarbons from shale reservoirs. Nanoscale surface properties of kerogen and minerals of shale were examined by a series of techniques including X-ray diffraction (XRD), scanning electron microscopy (SEM), X-ray photoelectron spectroscopy (XPS), Fourier transform infrared spectroscopy (FTIRS), and atomic force microscopy (AFM). The results show that aluminosilicate is the main component of inorganic matter, while kerogen chiefly consists of carbon. FTIRS and XPS analysis indicate that the chemical bonds of the kerogen surface are O-H, C-C, C-O, pyrrolic, and so on. In contrast to kerogen, illite's bonds are mainly Si-O and Al-O. AFM results indicate that the adhesion force of kerogen is higher than that of illite in shale. In addition, at a preloading force of 2500 nN, the adhesion force of kerogen increases from 40.8 to 118.2 nN when retraction velocity increases from 500 to 2500 nm/s. The adhesion forces of montmorillonite, calcite, and muscovite are 33.7 ± 6.28, 23.8 ± 11.8, and 105.1 ± 9.1 nN, respectively. The chemical composition and bonds have a profound effect on the adhesion force of shale, which further reveals the transport and adsorption mechanism of methane in kerogen.

Isotope Systematics and the Age of Authigenic Minerals in Shales of the Inzer Formation, the Southern Urals

The 2–5, 0.6–2, 0.3–0.6, 0.2–0.3 and 0.1–0.2 µm clay subfractions (SFs) separated from two shale samples of the Upper Riphean Inzer Formation, the southern Urals, were studied by the TEM, XRD, and U–Pb, Sm–Nd, Rb–Sr and K–Ar isotopic methods. All the SFs consist of the low-temperature 1Md illite; admixtures of quartz, chlorite and 2M1 illite occur only in the coarsest SFs. The clay particles are isometric, regardless of their size. The CIS (Crystallinity Index Standard) illite values for the all SFs are typical for the dia(kata)genetic zone. As the size of particles in the SF decreases from 2–5 to 0.1–0.2 µm, the CIS rises, the I002/I001 ratio on the XRD diagrams decreases, and the K content and the K/Rb ratio increase.&#x0D; Leaching with 1N HCl and 1N ammonium acetate (NH4OAc) and subsequent U–Pb, Sm–Nd and Rb–Sr analyses of the untreated SF, acid (acetate) leachate and residue made possible to study the mixing systematics in mobile and silicate materials of the shales. The 238U/204Pb and 87Rb/86Sr ratios in the acid and acetate leachates are below, and the 147Sm/144Nd ratio is above those in the residues. Less radiogenic Pb and Sr and more radiogenic Nd are also common for the leachates compared to the residues. As the size of particles in the SFs decreases, the U, Pb, Sm, Nd and Sr contents in the residues are smoothly reduced, whereas the Rb content shows an increase. The 87Rb/86Sr and 87Sr/86Sr values in the residues for fine-grained SFs are well above, and the 238U/204Pb value is well below those for coarse-grained SFs. What is more, in the 87Rb/86Sr–87Sr/86Sr and 1/86Sr–87Sr/86Sr diagrams, data points for the residues of variable size are arranged on the mixing lines. The data points of respective acid and acetate leachates also form linear trends in the 238U/204Pb–206Pb/204Pb, 206Pb/204Pb–207Pb/204Pb, 147Sm/144Nd–143Nd/144Nd, and 87Rb/86Sr–87Sr/86Sr coordinates. The apparent Rb–Sr age values, calculated from the slopes of “inner isochrons” (“leachochrons”), along with the K–Ar ages are smoothly lowered from 835–836 and 721–773 m.y. for the 2–5 µm SF to 572–580 and 555–580 m.y. for the 0.1–0.2 µm SF. Hence the XRD and isotopic data testify that the clay as well as the mobile material of the shale represent the mixtures of at least two components, the silicate phase containing authigenic illites of different ages. The first illite generation enriched in coarse-grained 2–5 and 0.6–2 µm SFs was formed shortly after deposition of the Inzer sediments, and its age of 803–836 m.y. is in agreement with the stratigraphic age of the formation. Simple lithostatic burial or intensive lateral fluid flow induced by tectonic inversion in the eastern regions of the Urals paleobasin may be considered as the geological processes responsible for the forming of this illite. The second illite generation was formed 572–580 m.y. ago. As the starting points for its formation, alternatively, may be concerned either vertical tectonics or renewal of pore fluid compositions during deformations and metamorphism on the southern Urals area related to evolution of the Beloretsk metamorphic complex.