Brittle Minerals Research Articles

Faulted karst reservoir spaces in Middle-Lower Triassic carbonates, Qingjiang Region, Yangtze block, China

The complexity and heterogeneity of ultra-deep faulted karst reservoirs pose significant challenges for hydrocarbon exploration. In this study, we integrated remote sensing image analysis, field measurements, and core sample testing to evaluate the characteristics and controlling factors of carbonate reservoir spaces within the Middle and Lower Triassic formations along a regional strike-slip fault in the Qingjiang region of China. The strike-slip fault zone is composed of multiple fault cores and damage zones. Based on differences in damage zone width and linear fault density, the fault zone was subdivided into transtensional and transpressional segmentations. The carbonate reservoirs, primarily developed within the damage zones, consist of fractures, fracture clusters, and cavities. Detailed measurements of the carbonate outcrops were conducted to obtain geometric parameters of the reservoir spaces. Quantitative results indicate that in the transtensional segmentation, the reservoir is dominated by tensile fracture-cavity systems, characterized by larger fracture apertures (0.13–1.25 m), higher linear fracture density (0.38–8.37 m⁻1), and well-developed cavities (0.03–4.84 m2), which contribute to better fluid connectivity and storage capacity. In contrast, the transpressional segmentation is dominated by compressional fracture-fracture cluster systems, with longer fractures (0.11–12.52 m), smaller fracture apertures (0.01–0.94 m), and extensive fracture clusters development (0.18–17.87 m2), but with lower fluid connectivity and limited storage capacity. Mechanical testing results show that the average compressive strength in the transtensional segmentation (133.95 MPa) is significantly higher than that in the transpressional segmentation (70.28 MPa). In terms of mineral composition, the transtensional segmentation has a higher calcite content, whereas the transpressional segmentation is richer in dolomite and quartz. Based on the observed differences in reservoir space characteristics across the strike-slip fault zone, we discussed the combined effects of structural segmentation, formation thickness, rock mechanics, and brittle mineral content on reservoir space development. The study emphasizes that stress conditions (primary factor) and material properties (secondary factor) jointly control fluid migration and storage efficiency in the reservoirs. Additionally, we suggest that the outcrop studies in the Qingjiang region provide valuable geological analogs for faulted karst reservoirs, offering critical insights for improving the precision of carbonate reservoir exploration and optimizing production efficiency.

Analysis of Controlling Factors of Pore Structure in Different Lithofacies Types of Continental Shale—Taking the Daqingzi Area in the Southern Songliao Basin as an Example

Due to the influence of terrigenous debris, the internal pore structure of continental shale is highly heterogeneous, and the controlling factors are complex. This paper studies the structure and controlling factors of shale reservoirs in the first member of the Qingshankou Formation in the Southern Songliao Basin using core data and various analytical test data. The results show that the original deposition and subsequent diagenesis comprehensively determine the shale reservoirs’ pore structure characteristics and evolution law. According to the severity of terrigenous debris, the shale reservoirs in the study area are divided into four categories and six subcategories of lithofacies. By comparing the characteristics of different shale lithofacies reservoirs, the results show that the lithofacies with a high brittle mineral content have more substantial anti-compaction effects, more primary pores to promote retention and a relatively high proportion of mesopores/macropores. Controlling the organic matter content when forming high-quality reservoirs leads to two possibilities. An excessive organic matter content will fill pores and reduce the pore pressure resistance. A moderate organic matter content will make the inorganic diagenesis and organic hydrocarbon generation processes interact, and the development of organic matter mainly affects the development of dissolution pores. The comprehensive results show that A3 (silty laminated felsic shale) reservoirs underwent the pore evolution process of “two drops and two rises” of compaction, cementation and pore reduction, dissolution and pore increase, and organic matter cracking and pore increase, and they are the most favourable lithofacies of the shale reservoirs in the study area.

Novel brittleness index construction and pre‐stack seismic prediction for gas hydrate reservoirs

AbstractReservoir transformation is essential for developing gas hydrate reservoirs. Predicting sediment brittleness is key to optimizing drilling design and evaluating engineering sweet spots. Constructing a brittleness index reflecting the brittle mineral content of a rock based on elastic parameters and predicting it using seismic data is a feasible solution for assessing reservoir brittleness. In addition, the elastic brittleness index can characterize the effect of complex pore types, fractures and pore fillings on rock brittleness. With the shallow hydrate reservoir in the sea as the research target. First, a novel brittleness index characterized by multiplying the Lamé parameter () by Poisson's ratio () is proposed. Its superiority in indicating brittle mineral content is verified by a rock‐physics model. Second, a reflection coefficient approximation equation including the novel brittleness index is derived, enabling direct estimation of reservoir brittleness from seismic data. The new brittleness index has proven to better reflect brittle mineral content and effectively indicate the high brittleness characteristics of hydrate reservoirs. The accuracy of the proposed approximate equation is verified by a layered medium model, and the viability of predicting the new brittleness index using seismic data is also theoretically supported by the model test. Finally, the proposed method has obtained favourable results in the application of hydrate work area data collected at the South China Sea, confirming its availability and practicality.

Matrix Compression and Pore Heterogeneity in the Coal-Measure Shale Reservoirs of the Qinshui Basin: A Multifractal Analysis

The application of high-pressure fluid induces the closure of isolated pores inside the matrix and promotes the generation of new fractures, resulting in a compressive effect on the matrix. To examine the compressibility of coal-measure shale samples, the compression of the coal–shale matrix in the high-pressure stage was analyzed by a low-pressure nitrogen gas adsorption and mercury intrusion porosimetry experiment. The quantitative parameters describing the heterogeneity of the pore-size distribution of coal-measure shale are obtained using multifractal theory. The results indicate that the samples exhibit compressibility values ranging from 0.154 × 10−5 MPa−1 to 4.74 × 10−5 MPa−1 across a pressure range of 12–413 MPa. The presence of pliable clay minerals enhances the matrix compressibility, whereas inflexible brittle minerals exhibit resistance to matrix compression. There is a reduction in local fluctuations of pore volume across different pore sizes, an improvement in the autocorrelation of PSD, and a mitigation of nonuniformity after correction. Singular and dimension spectra have advantages in multifractal characterization. The left and right spectral width parameters of the singular spectrum emphasize the local differences between the high- and low-value pore volume areas, respectively, whereas the dimensional spectrum width is more suitable for reflecting the overall heterogeneity of the PSD.

Shale Reservoir Rock Physics Modeling and “Sweet Spot” Prediction Based on Digital Core

Abstract With the increasing advancement in shale exploration and development, the complex pore structure and organic-rich characteristics of shale have gradually become the focus of rock physics models. This study combined digital core technology to obtain detailed information on the shale mineral composition, content, pore and crack contents, and composition. The isotropic self-compatible approximation (SCA) model was used to couple the shale minerals and hard pores to construct a brittle mineral framework. The VRH model was used to mix kerogen and clay, and the SCA-DEM (differential equivalent medium) model was used to add organic pores to construct a clay-organic matter mineral framework. The anisotropic SCA model treated the clay-organic matter mineral framework as an inclusion added to the brittle mineral framework to construct the shale mineral framework. The Eshelby–Cheng model was used to add fracture to the mineral framework and establish a physical shale model. This model was used to optimise the selection of sensitive elastic parameters for physical properties such as brittle mineral and kerogen content, fracture density, and porosity, and the optimisation results were combined to construct an explanatory quantity template. In addition, according to actual data from a study area in southwestern China, we combined to the interpretation chart established by the model to perform isotropic inversion. Then, we analyzed and interpreted the brittleness index (BI) and total organic carbon (TOC) content of the reservoir and predicted the sweet spot area of the shale reservoir.

Prediction of Shale Gas Well Productivity Based on a Cuckoo-Optimized Neural Network

Current shale gas well production capacity predictions primarily rely on analytical and numerical simulation methods, which necessitate extensive calculations and manual parameter tuning and produce lowly accurate predictions. Although employing neural networks yields highly accurate predictions, they can easily fall into local optima. This paper suggests a new way to use Cuckoo Search (CS)-optimized neural networks to make shale gas well production capacity predictions more accurate and to solve the problem of local optima. It aims to assist engineers in devising more effective development plans and production strategies, optimizing resource allocation, and reducing risk. The method first analyzes the factors influencing the production capacity of shale gas wells in a block located in western China through correlation coefficients. It identifies the main factors affecting the gas test absolute open flow as organic carbon content, small-layer passage rate, fracture pressure, acid volume, pump-in fluid volume, brittle mineral content in the rock, and rock density. Subsequently, we used the CS algorithm to conduct the global training of the neural network, avoiding the problem of local optima, and established a neural network model for predicting shale gas well production capacity optimized by the CS algorithm. A comparative analysis with other relevant methods demonstrates that the CS-optimized neural network model can accurately predict production capacity, enabling a more rational and effective exploitation of shale gas resources, which lower development costs and increase the economic returns of oil and gas fields. Compared to numerical simulation, SVM, and BP neural network algorithms, the CS-optimized BP neural network (CS-BP) exhibits significantly lower prediction error. Its correlation coefficient between predicted and actual values reaches as high as 0.9924. Verification experiments conducted on another shale gas well also demonstrate that, in comparison to the BP neural network algorithm, CS-BP offers superior prediction performance, with model validation showing a prediction error of only 0.05. This study can facilitate more rational and efficient exploitation of shale gas resources, reduce development costs, and enhance the economic benefits of oil and gas fields.

Adsorption Behavior of Different Components of a Polymer/Surfactant Composite Control System along an Injection-Production Channel in Sand Conglomerate Reservoirs.

Sandy conglomerate reservoirs have become an important replacement area for unconventional energy to increase reserves and production. The polymer/surfactant composite control flooding system can effectively alleviate the water flooding front breakthrough caused by the interlayer or plane heterogeneity of the sand conglomerate reservoir and is an effective production method to reduce the water cutoff of the well and increase the oil recovery. In the process of controlling the oil displacement process of the system, the chromatographic separation effect was found due to the different viscosities of each component and the adsorption difference between the components and the rock, which weakened the development effect of the reservoir. It is necessary to study the adsorption law of each component of the complex controlled displacement system along the injection-production channel in the sand conglomerate reservoir. In this study, the microstructure and mineral composition of sandy conglomerates were determined by scanning electron microscopy and X-ray diffraction tests. The main particle size distribution was counted through a rock particle sieving experiment. A new characterization method called the large-size core physical model was used. The composite control system of sulfonate and betaine was used as the surfactant component, and the adsorption degree of each component in the displacement process was analyzed. The experimental results showed that the mass fraction of the sandy conglomerate increased with the decrease in particle size. The particles with a size of less than 0.08 mm account for a relatively high proportion, with a mass fraction of 60%. The content of brittle minerals, such as quartz and feldspar, in the glutenite was relatively high, and micrometer-sized pores and fractures were developed. The main factors affecting the viscosity of the composite system were the concentration and molecular weight of the polymer. The increase of injection volume of the flooding system is conducive to the maintenance of ultralow interfacial tension migration to the deep core. In the displacement process, when the polymer molecular chain was cut to a certain extent, the effect of throat shear was also slowed due to the short molecular chain. However, the shortened polymer molecules were more easily adsorbed on the surface of rock particles and the adsorption rate increased. The adsorption capacity of each component gradually decreased with the increase of the injection volume and injection concentration. The relative content of the composite control system and crude oil affects the type of emulsion, which undergoes a corresponding transformation during the driving process from a water-in-oil emulsion to an oil-in-water one. The research results of this paper enrich the mechanism of enhancing oil recovery of sand conglomerate reservoirs by polymer-surfactant composite regulation technology.

Fracability evaluation model for unconventional reservoirs: From the perspective of hydraulic fracturing performance

Fracability evaluation for unconventional reservoir is critical to the selection of candidate zones for post-frac productivity and plays a key role in fracturing design. Historically, the prevailing models for assessing fracability have been largely relied on brittleness indices. Brittleness indices focus mainly on rock fracture characteristics and offers limited assessment of fracture surface area and the complexity of fracture network, which are more relevant to the practical production. We explored a new fracability evaluation model for unconventional reservoirs from the perspective of fracturing performance, which comprehensively characterizes the rock's ability to generate larger fracture surface areas, more shear fractures and complex fracture networks. The new fracability index considers both the physical processes of rock failure and fracture propagation, and is directly associated with the dynamic production capacities of reservoir. According to the analysis of energy conservation during hydraulic fracturing, we quantify the rock fracture surface area using the KGD and the PKN models. The ability of rock formation to generate shear fractures is mainly influenced by Poisson's ratio and mode II fracture toughness. Brittle mineral content and mineral heterogeneity are two vital criteria that significantly affect the complexity of fracture networks. Based on the logging and production data, this fracability model was applied to two types of unconventional reservoirs. Preliminary results show that this fracability model has an improved correlation with the pay zones and actual production, which is beneficial for optimizing fracturing strategies and identifying production sweet spots.

Study on the evaluation of shale reservoir brittleness based on mineral disorder

Brittleness serves as a critical indicator for assessing whether reservoirs can form complex fracture networks. While methods based on brittle mineral content or rock mechanical parameters are widely used, their lack of integration between mineralogy and mechanics introduces limitations. A single evaluation parameter cannot accurately assess shale brittleness. There is a need for a universally applicable method that comprehensively considers mineral composition, mechanical properties, and brittleness variations in shale evaluation. This study uses Longmaxi shale in the Sichuan Basin as an example, establishing a mineral disorder index based on shale mineral composition and mechanical characteristics, incorporating the influence of confining pressure to establish a shale brittleness index. Results indicate varying weights of brittleness contributions from different minerals, ranked in descending order: pyrite, quartz, calcite, dolomite, feldspar, and clay. Greater complexity in mineral combinations correlates with lower shale brittleness indices. Typically, single mineral disorder indices show a positive correlation with internal mineral disorder indices. Confining pressure exhibits an inversely proportional relationship with shale brittleness indices, with brittleness at 30, 50, and 70 MPa confining pressures being 0.737, 0.586, and 0.451 times those without confining pressure, respectively. This method guides current brittleness research and reservoir production enhancement.

Control and prediction of bedding-parallel fractures in fine-grained sedimentary rocks: A case from the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin, Western China

The fine-grained sedimentary rocks have numerous bedding-parallel fractures that are essential for the migration, enrichment, and efficient development of oil and gas. However, because of their variety and the complexity of the factors that affect them, their spatial prediction by the industrial community becomes challenging. Based on sample cores, thin sections, and well-logging and seismic data, this study employed a multi-scale data matching approach to quantitatively predict the development of bedding-parallel fractures and investigate their spatial distribution. Bedding-parallel fractures in the Lucaogou Formation in Jimusar Sag frequently occur along preexisting bedding planes and lithological interfaces. Unfilled bedding-parallel fractures inside or near source-rocks exhibit enhanced oil-bearing capacity. They were identified on micro-resistivity scanning images by the presence of regularly continuous black or nearly black sinusoidal curves. Overall, the developmental degree of bedding-parallel fractures was positively related to the brittle mineral and total organic carbon contents and negatively related to single reservoir interval thickness. The maintained porosity of the reservoir matrix contributed to a thorough response to factors affecting the development of bedding-parallel fractures. Here, an effective and objective method was proposed for predicting the development and distribution of bedding-parallel fractures in the fine-grained sedimentary rocks. The method was based on the matched reservoir interval density, reservoir interval density, and matched sweet spot density of bedding-parallel fractures. The prediction method integrated the significant advantages of high vertical resolution from logging curves and strong lateral continuity from seismic data. The average relative prediction error was 8% in the upper sweet spot in the Lucaogou Formation, indicating that the evaluation parameters for bedding-parallel fractures in fine-grained sedimentary rocks were reasonable and reliable and that the proposed prediction method has a stronger adaptability than the previously reported methods. The workflow based on multi-scale matching and stepwise progression can be applied in similar fine-grained sedimentary rocks, providing reliable technological support for the exploration and development of hydrocarbons.

Geological Conditions of Shale Gas Accumulation in Coal Measures

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II2, with TOC content greater than 1%. The maturity of shale samples is relatively higher (Ro,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m2/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm3/g, with an average of 2.1 cm3/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential.

A regularized variational mechanics theory for modeling the evolution of brittle crack networks in composite materials with sharp interfaces

In the design of structural materials, there is traditionally a tradeoff between achieving high strength and achieving high toughness. Nature offers creative solutions to this problem in the form of structural biomaterials (SBs), intelligent arrangements of mineral and organic phases which possess greater strength and toughness than the constituents. The micro-architecture of SBs like nacre and sea sponge spicules are characterized by weak organic interfaces between brittle mineral phases. To better understand the toughening mechanisms in SBs requires simulation techniques which can resolve arbitrary interface and bulk fracture patterns.In this work, we present a modified regularization of Variational Fracture Theory (VFT) that allows for simulation of fracture in materials and structures with weak interfaces. The core of our approach is to widen the weak interfaces on a length scale proportional to that of the diffuse damage field, and assign a reduced fracture toughness therein. We show that in 2D the modified regularized functionals Γ-converge to that for sharp cracks. The resulting thin weak interfaces have fracture toughness which depends on the bulk material fracture toughness, the widened interface fracture toughness, and the ratio of the widened interface length scale to the crack regularization length scale. We next apply our modified regularization within a computer implementation of regularized VFT, which we term RVFTI. We assess the performance of RVFTI in 2D by reproducing the effective interface fracture toughness predicted by the Γ-convergence theory and simulating crack trapping at a bi-material interface. We then use RVFTI to study toughening in SB-inspired microarchitectures, namely layered materials and materials with wavy interfaces.

Mapping the composite nature of clay matrix in mudstones: integrated micromechanics profiling by high-throughput nanoindentation and data analysis

AbstractMudstones and shales serve as natural barrier rocks in various geoenergy applications. Although many studies have investigated their mechanical properties, characterizing these parameters at the microscale remains challenging due to their fine-grained nature and susceptibility to microstructural damage introduced during sample preparation. This study aims to investigate the micromechanical properties of clay matrix composite in mudstones by combining high-speed nanoindentation mapping and machine learning data analysis. The nanoindentation approach effectively captured the heterogeneity in high-resolution mechanical property maps. Utilizing machine learning-based k-means clustering, the mechanical characteristics of matrix clay, brittle minerals, as well as measurements on grain boundaries and structural discontinuities (e.g., cracks) were successfully distinguished. The classification results were validated through correlation with broad ion beam-scanning electron microscopy images. The resulting average reduced elastic modulus (Er) and hardness (H) values for the clay matrix were determined to be 16.2 ± 6.2 and 0.5 ± 0.5 GPa, respectively, showing consistency across different test settings and indenter tips. Furthermore, the sensitivity of indentation measurements to various factors was investigated, revealing limited sensitivity to indentation depth and tip geometry (when comparing Cube corner and Berkovich tip in a small range of indentation depth variations), but decreased stability at lower loading rates. Box counting and bootstrapping methods were applied to assess the representativeness of parameters determined for the clay matrix. A relatively small dataset (indentation number = 60) is needed to achieve representativeness, while the main challenges is to cover a representative mapping area for clay matrix characterization. Overall, this study demonstrates the feasibility of high-speed nanoindentation mapping combined with data analysis for micromechanical characterization of the clay matrix in mudstones, paving the way for efficient analysis of similar fine-grained sedimentary rocks.

Study on the Fracture Extension Pattern of Shale Reservoir Fracturing under the Influence of Mineral Content.

This study aimed to investigate the effect of the microstructure of shale on fracture initiation and extension during hydraulic fracturing. The Longmaxi Formation shale reservoir in the Sichuan Basin was considered as the research object; its structure was modeled from a microscopic perspective, and a zero-thickness cohesive unit was embedded within the solid unit. Numerical simulations were performed to study the effect of mineral content on the microextension of the hydraulic fracture, extension behavior, and evolution law of shale. The results showed that changes in the mineral content resulted in changes in the forces between molecules within the minerals, which, in turn, affected the shale's brittleness. The percentages of brittle mineral content in the Long I, II, and III reservoir sections are 60.37, 47.60, and 53.56%, respectively. The fracture initiation pressures of the three reservoirs were 29.22, 31.42, and 30.22 MPa, respectively, and a linear correlation was found between the fracture initiation pressures and the brittle mineral contents of the reservoir sections. An increase in the reservoirs' percentage of brittle mineral content facilitated the fracture initiation, with a corresponding gradual decrease in the resistance to fracture initiation. The pore pressures of the fractures in the three reservoirs after fracture initiation were 0.90, 1.18, and 1.00 MPa, respectively. The larger the percentage of brittle minerals was, the lower was the fracture pore pressure. The greater the length, number, area, and width of the cracks were, the more likely they were to form longer and wider cracks. Hence, reservoirs with a high percentage of brittle minerals should be prioritized as the target formations for hydraulic fracturing operations. The results of this study reveal how the mineral content affects the extension of microscopic hydraulic fractures in shale reservoirs. As such, this work can provide a theoretical basis for rationally selecting a hydraulic fracturing operation layer in shale gas reservoirs.

Shale gas‐bearing capacity and its controlling factors of Wufeng–Longmaxi formations in northern Guizhou, China

Great progress has been made in marine shale gas of Wufeng–Longmaxi formations in the Sichuan Basin. However, shale gas exploration in the complex structural belt around the Sichuan Basin still faces great challenges. In this study, shales of Wufeng–Longmaxi formations collected from the northern Guizhou were taken as the studied target, organic matter (OM) characteristics, mineral composition, pore structure, methane adsorption capacity and in situ desorption gas content were measured, and the controlling factors of shale gas content were further discussed. The results indicated that the sedimentary facies of Wufeng–Longmaxi formations in north Guizhou varies from shallow‐water shelf facies to deep‐water shelf facies from south to north, and organic‐rich shales are primarily distributed in Daozhen‐Xishui areas, with a maximum thickness of about 80–100 m. Organic‐rich shales are characterized by high total organic carbon (TOC) content, high thermal maturation and type I–II1 kerogens, which can be comparable with those in commercially produced shale gas field in Sichuan Basin. High‐quality shale gas reservoirs generally have a high content of brittle minerals, making them easier to be fractured. OM pores are the dominanted pore type in the studied shales, followed by intergranular pores associated with brittle minerals, dissolution pores within carbonate grains and microcracks, while clay mineral‐related pores are poorly developed. The Wufeng–Longmaxi Formation shales generally have strong methane adsorption capacities, but these vary greatly across different areas. Shale gas adsorption capacity is primarily controlled by TOC content and thermal maturation level. Similarly, total gas content, including desorption gas and lost gas, varies greatly in different areas, and it is obviously lower than that in Fuling and Luzhou shale gas field, due to the loss of shale gas and low‐pressure coefficient in the complex structural zone. It is worth explaining that shale gas is not always low in northern Guizhou, which is determined by burial depth and the distance of great fractures. Shale gas content is relatively high in LY1 well and DY1 well in Xishui‐Daozhen area, and it is extremely low in TY1 well and AY1 well in Tongzi‐Zheng'an area. Shale gas content in the same structural unit is primarily influenced by TOC content, OM pore development degree and water saturation. However, different structural units have different shale gas contents, due to the differences in preservation conditions. Shale reservoirs with good preservation conditions, that is, wide and gentle structure, far from a large fault and great burial depth, generally have high shale gas contents.

Characteristics and controlling factors of Lucaogou formation shale reservoir in the northern edge of Bogda Mountain, the Junggar Basin, China

The practice of oil and gas exploration has confirmed the existence of recoverable shale oil resources in the Permian Lucaogou Formation on the northern edge of the Bogda Mountains. However, previous research on the development characteristics and main controlling factors of shale oil resources in this area is relatively limited. In order to elucidate the development characteristics and principal controlling factors of the shale deposit in the Lucaogou Formation, the characteristics, physical properties, diagenesis, and influencing factors of the shale ore were investigated utilising data derived from outcrop, drilling, seismic, and geochemical analysis. The findings indicate that the shale of the Lucaogou Formation is prevalent and extensive. The deposit’s lithology is predominantly composed of dark grey and grey-black mud shale, interspersed with thin layers of dark grey and grey-black sandy mud shale and dolomite mud shale. The most prevalent minerals are carbonate minerals, followed by feldspar and quartz, with a notable proportion of brittle minerals. The deposit is primarily composed of dissolution pores, bedding fractures, and structural fractures, with a porosity of 1.23–3.26% and permeability of 0.012–0.076 mD, which are characteristic of ultra-low porosity and ultra-low permeability deposits. Among the three deposit types, the sandstone type exhibits the most favourable physical properties, followed by the dolomite type and the shale type, which displays the least favourable properties. The shale of the Lucaogou Formation is currently in the middle diagenetic phase, which is characterised by compaction, cementation (carbonate cementation, mudstone cementation, pebble cementation), and dissolution. The destructive effect of compaction and cementation on the physical properties is counterbalanced by the constructive effect of dissolution. The diagenetic environment has gradually changed from an alkaline environment to a slightly alkaline, slightly acidic stage.

Brittle minerals, mechanical properties and fracability evaluation of shales

Brittle minerals, mechanical properties and fracability evaluation of shales

Geomechanical properties of laminated shale and bedding shale after water absorption: A case study of the Chang 7 shale in Ordos basin, China

There are abundant oil and gas resources in China's continental shale formations, and these formations often contain sandy lamina, tuffaceous lamina and carbonate lamina parallel to the bedding planes, resulting in complex geomechanical properties. During the drilling process, the mechanical weak surface structure inside the shale and the hydration effect of drilling fluid may easily cause wellbore instability, which reduces the safety and benefit of drilling. To explore the geomechanical properties of laminated shale and bedding shale after water absorption, a series of tests were conducted on the Chang 7 laminated shale and bedding shale in the Ordos Basin. The result indicates that the compressive strength and elastic modulus of laminated shale and bedding shale show a trend of decreasing first and then starting to drop as β (the angle between bedding/lamina and the direction of stress) keeps increasing, and laminated shale has stronger anisotropy, lower compressive strength and elastic modulus. The moisture content of laminated shale and bedding shale increases as the soaking time increases, which leads to a decrease in the compressive strength. Compared to bedding shale, laminated shale reaches water saturation faster and has a higher moisture content. Based on the macroscopic and microscopic images before and after shale hydration, it can be concluded that natural microfractures are easily formed at the interface between the lamina and shale matrix, and brittle minerals at the edges of natural microfractures are prone to detachment, thereby increase the hydration area and intensify the hydration process. Compared to bedding shale formations, laminated shale formations have a higher hole-size elongation ratio and are more prone to collapse according to on-site data. This study reveals the geomechanical properties of laminated shale under the dual influence of anisotropy and hydration, provides support for drilling design in such formations.

Fracability Modeling in Shale Hydrocarbon Development Based on Geomechanical Analysis of Well Log and Mineralogy Analysis of Drill Cuttings: A Case Study of the Lower Baong Fm and the Belumai Fm of the NSB-001 Well in the North Sumatra Basin, Indonesia

Abstract The North Sumatra Basin, Indonesia has a very large shale hydrocarbon potential, especially from the Lower Baong Formation and the Belumai Formation. The Belumai and Lower Baong Formations were deposited in the Early Miocene - Middle Miocene, in transgression conditions, when the North Sumatra Basin was in the regional sagging phase. These conditions greatly affect the facies and diagenetic changes of quartz, smectite and kaolinite minerals in rock fracability. The main problem in producing shale hydrocarbons is the very low permeability of unconventional-shale-reservoirs, so that at the production stage of shale hydrocarbon, a fracability model is needed as a basis for planning hydraulic fracking, thus the fractures are connected to each other and can flow the hydrocarbon fluid optimally. From the results of previous studies, it was shown that the shale hydrocarbon fracability value was controlled by lithofacies, and correlated with rock brittleness, brittle mineral content, clay content, and compressive strength. The fracability model is used to determine fracable zone intervals as a candidate for hydraulic fracking, by using geomechanical analysis of well log data and mineralogy analysis of drill cuttings data from the NSB-001 well as a case study. Based on the correlation results of lithology (Mud Log), mineralogy analysis, MBT, and TOC (Drill Cuttings), the sweetpot fracable window (fracable zone interval) can be determined, which is correlated with the presence of fracture barrier.

A novel rock-physics model of organic-rich shale considering maturation influence

Geochemical parameters, e.g., maturity and total organic carbon (TOC) content, play a crucial role in the prediction of sweet spots and the exploration of oil and gas in organic-rich shales. Thermal maturity significantly affects the conversion of solid organic matter into hydrocarbons and the evolution of microstructures, thereby altering the overall elastic properties of shales. To clarify how maturity affects shale properties, we develop a novel rock-physics model (RPM) of organic-rich shale, in which we consider the continuous process of thermal maturity. First, we present how to estimate the maturity level, TOC content, and organic porosity using logging data. Second, different from only considering the discrete-stage maturity, we establish a novel RPM in which a continuous kerogen maturation process serves as a key control condition. Furthermore, we calibrate the volumetric proportion of each porosity type as a function of maturation. Finally, we apply the RPM to investigate how sweet spot parameters (thermal maturity, TOC content, and brittle mineral content), overpressure, and diagenesis affect the overall elastic properties and anisotropy of shale during thermal maturation. Results demonstrate that using our RPM, we may predict the acoustic velocity of shale formations reliably and that kerogen evolution has a noticeable impact on the elastic properties of shale rocks, particularly during the wet gas window stage of mid-to-high maturation. We conclude that thermal maturity emerges as a crucial sweet spot parameter in the case of the exploration of oil and gas in organic-rich shales.