Mixed Shale Research Articles

Organic matter enrichment model of fine-grained rocks in volcanic rift lacustrine basin: A case study of lower submember of second member of Lower Cretaceous Shahezi Formation in Lishu rift depression of Songliao Basin, NE China

Based on sedimentary characteristics of the fine-grained rocks of the lower submember of second member of the Lower Cretaceous Shahezi Formation (K1sh2L) in the Lishu rift depression, combined with methods of organic petrology, analysis of major and trace elements as well as biological marker compound, the enrichment conditions and enrichment model of organic matter in the fine-grained sedimentary rocks in volcanic rift lacustrine basin are investigated. The change of sedimentary paleoenvironment controls the vertical distribution of different lithofacies types in the K1sh2L and divides it into the upper and lower parts. The lower part contains massive siliceous mudstone with bioclast-bearing siliceous mudstone, whereas the upper part is mostly composed of laminated siliceous shale and laminated fine-grained mixed shale. The kerogen types of organic matter in the lower and upper parts are types II2–III and types I–II1, respectively. The organic carbon content in the upper part is higher than that in the lower part generally. The enrichment of organic matter in volcanic rift lacustrine basin is subjected to three favorable conditions. First, continuous enhancement of rifting is the direct factor increasing the paleo-water depth, and the rise of base level leads to the expansion of deep-water mudstone/shale deposition range. Second, relatively strong underwater volcanic eruption and rifting are simultaneous, and such event can provide a lot of nutrients for the lake basin, which is conducive to the bloom of algae, resulting in higher productivity of types I–II1 kerogen. Third, the relatively dry paleoclimate leads to a decrease in input of fresh water and terrestrial materials, including Type III kerogen from terrestrial higher plants, resulting in a water body with higher salinity and anoxic stratification, which is more favorable for preservation of organic matter. The organic matter enrichment model of fine-grained sedimentary rocks of volcanic rift lacustrine basin is established, which is of reference significance to the understanding of the organic matter enrichment mechanism of fine-grained sedimentary rocks of Shahezi Formation in Songliao Basin and even in the northeast China.

Total organic carbon content estimation for mixed shale using Xgboost method and implication for shale oil exploration

In this study, the Xgboost method is employed for TOC estimation in mixed carbonate and siliciclastic shale from the Hashan area, Junggar Basin. The results show that this approach is effective for TOC estimation in this area although the model performance is not very excellent with a correlation coefficient of 0.54 between measured TOC and predicted TOC values, likely due to a small samples dataset. Therefore, the PCA method is applied to debase dimension of well log data from five dimensional to two-dimensional data, which enhances the correlation coefficient between the predicted and measured TOC from 0.54 to 0.68. Based on the model, the isopleth maps of TOC distributions in Fengcheng Formation were redrawn showing two shale oil exploration targets, which likely correspond to two depositional centers of this strata. All the same, the model in this work provides reliable data for shale oil evaluation in the study area and a good example under similar geological setting.

Pore structure of the mixed sedimentary reservoir of Permian Fengcheng Formation in the Hashan area, Junggar Basin

The Permian Fengcheng Formation (P1f.) in the Hashan area, situated on the southwestern margin of the Junggar Basin, has witnessed a remarkable breakthrough in shale oil exploration in recent years with nearly 789 million tons of shale oil resources. As a unique set of mixed sedimentary shales, the Fengcheng Formation in the Hashan area is characterized by mixed sedimentation of terrigenous siliciclastic sediments, authigenic minerals, and tuffaceous materials. However, the understanding of pore characteristics in the mixed sedimentary reservoir still remains limited, prohibiting accurate estimation of the oil content and insights into oil mobility. Scanning electron microscopy (SEM), X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), X-Ray Computer Tomography (X-CT), and geochemical analysis were performed to investigate the pore size distribution and main controlling factors of the mixed sedimentary reservoir. Results showed that the main pore types in the mixed sedimentary reservoir are intergranular pores and dissolution pores. The pores of the P1f. mixed shales in the Hashan area were classified into II-micropores (< 25 nm), I-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (> 1000 nm). In general, the mixed sedimentary rocks of P1f. formation feature few macropores but a large number of micropores and mesopores. The CS exhibits the most favourable physical properties among all lithofacies. It is concluded that the abundance and maturity of organic matter, mineral composition, sedimentary structure, and diagenesis of reservoir together impact the pore structure in the mixed sedimentary reservoirs. The maturity of organic matter and the content of tuffaceous minerals are the most significant in influencing the pore structure of P1f. shales. Overall, the pore structure of complex lithologic reservoir formed by mixed deposition and its influence on physical properties are studied, and the characteristics of the microscopic pore-throat system of the dominant lithofacies in the Hashan area are clarified, which is of great significance as a guide for the exploration and development of mixed sedimentary reservoirs in continental shale oil in China.

The influence of different diagenesis on the elastic properties of different shale lithofacies: a case study of the upper Permian Wujiaping formation in East Sichuan Basin, China

Understanding the impact of diagenesis on the elastic properties of organic-rich shale reservoirs is essential for evaluating unconventional hydrocarbon reservoirs and interpreting seismic data. Recent advancements in the exploration of the Permian Wujiaping Formation in the eastern Sichuan Basin indicate its potential to become a significant succession within the Sichuan Basin. However, the effect of different lithofacies in the Wujiaping Formation on shale elastic properties under varying diagenetic conditions remains unclear, hindering detailed reservoir interpretation. This study employs X-ray diffraction, thin section analysis, scanning electron microscopy, organic geochemistry, and dynamic elastic property tests to investigate the Wujiaping Formation shale. The results reveal three primary lithofacies types: argillaceous shale, mixed shale, and siliceous shale. Argillaceous shale, subjected to intense compaction, forms a dense rock framework of oriented clay minerals, characterized by low porosity (1.66%), low elastic wave velocity (4122.30 m/s), low elastic modulus (2174.59 m/s), and high Poisson's ratio (32.24 GPa). Mixed shale, dominated by carbonates and quartz, exhibits a rock framework formed through dissolution and cementation, with high elastic wave velocity (5196.54 m/s), relatively high elastic modulus (2975.86 m/s), and moderate Poisson's ratio (58.53 GPa). Siliceous shale, comprising biogenic quartz particles, shows strong resistance to compaction. During hydrocarbon generation, it develops abundant organic matter pores, resulting in the highest porosity (2.36%), high elastic wave velocity (5177.92 m/s), high elastic modulus (2975.86 m/s), and low Poisson's ratio (62.23 GPa). The significant differences in mineral composition and diagenetic processes across the lithofacies lead to distinct elastic properties. This study provides a rock physics framework for the detailed seismic prediction of "sweet spots" in the Wujiaping Formation shale reservoirs and offers new insights into characterizing the diagenesis of unconventional shale reservoirs using geophysical properties.

Machine learning-based grayscale analyses for lithofacies identification of the Shahejie Formation, Bohai Bay Basin, China

It is of great significance to accurately and rapidly identify shale lithofacies in relation to the evaluation and prediction of sweet spots for shale oil and gas reservoirs. To address the problem of low resolution in logging curves, this study establishes a grayscale-phase model based on high-resolution grayscale curves using clustering analysis algorithms for shale lithofacies identification, working with the Shahejie Formation, Bohai Bay Basin, China. The grayscale phase is defined as the sum of absolute grayscale and relative amplitude as well as their features. The absolute grayscale is the absolute magnitude of the gray values and is utilized for evaluating the material composition (mineral composition + total organic carbon) of shale, while the relative amplitude is the difference between adjacent gray values and is used to identify the shale structure type. The research results show that the grayscale phase model can identify shale lithofacies well, and the accuracy and applicability of this model were verified by the fitting relationship between absolute grayscale and shale mineral composition, as well as corresponding relationships between relative amplitudes and laminae development in shales. Four lithofacies are identified in the target layer of the study area: massive mixed shale, laminated mixed shale, massive calcareous shale and laminated calcareous shale. This method can not only effectively characterize the material composition of shale, but also numerically characterize the development degree of shale laminae, and solve the problem that difficult to identify millimeter-scale laminae based on logging curves, which can provide technical support for shale lithofacies identification, sweet spot evaluation and prediction of complex continental lacustrine basins.

Effect of Paleoenvironmental Conditions on the Distribution of Lower Carboniferous Shale in Yaziluo Rift Trough, South China: Insights from Major/Trace Elements and Shale Composition

Paleoenvironmental conditions significantly influence the distribution patterns and organic matter enrichment of shale. This study investigated the vertical variations of major elements, trace elements, and total organic carbon (TOC) in the Lower Carboniferous marine shale from the Yaziluo Rift Trough, South China, to understand the paleoenvironmental conditions, including redox conditions, terrigenous detrital input, paleoproductivity, and paleo-seawater depth. The Lower Carboniferous formation consists of three sedimentary facies: basin facies, lower slope facies, and upper slope facies. From the basin to the lower slope and then to the upper slope facies, TOC, quartz, and pyrite contents gradually decrease, whereas the carbonate mineral content shows an increasing trend. A continuous decline in paleo-seawater depth transformed a deep-water anoxic environment with high paleoproductivity and low detrital input in the basin facies into a semi-deep-water environment with dysoxic-oxic conditions and moderate detrital influx in the lower slope facies, evolving further into a suboxic environment with high detrital flux in the upper slope facies. The geochemistry results suggest that anoxic conditions and high paleoproductivity were the primary controls on organic matter enrichment in the siliceous shale of the basin facies. In contrast, redox conditions significantly influenced organic matter accumulation in the mixed shale of the lower slope facies, attributed to relatively low paleoproductivity in a more restricted marine setting. Additionally, the adsorption of carbon components by clay minerals facilitated the preservation of organic matter in the calcareous shale of the upper slope facies.

STUDY OF MICROSCALE PORE STRUCTURE AND FRACTURING ON THE EXAMPLE OF CHINA SHALE FIELD

Accurate characterization of pores and fractures in shale reservoirs is the theoretical basis for effective exploration and development of shale oil and gas. Currently, the scientific community has developed methods for determining the characteristics of the pore and fracture structure of shales with different resolutions, and also discussed the mechanisms of the influence of the characteristics of pores and cracks on the filtration of shale oil and gas. In this work, firstly, a three-dimensional model of a variable-scale pore-fracture structure was created. Secondly, on the basis of data obtained using computed tomography, the characteristics of the development of pores and cracks at different geometric sizes (25 and 2 mm) were statistically analyzed. Third, pore and fracture structures of mixed, felsitic and laminated felsitic shale have been relatively studied. The results show that: (a) the fractured porosity of group I felsite shale is 0.36–0.89 %; mixed shale of group I is 0.34–0.47 %; mixed shale of group III is 0.12–0.86 %; mixed shale of group III is 0.13–0.15 %. (b) Compared to mixed shale of group I, fracturing in felsite shale of the same group is more developed. In addition, the average fractured porosity of felsite shale is 0.28 % greater than that of mixed shale. After analyzing group III, it was noticed that the cracks of the mixed dolomite shale are less developed compared to the mixed shale of the same group, while the average porosity of the cracked shale is 0.33 % less than that of the cracks of the mixed shale (c). Various components of shale samples are distinguished on a gray scale. High density components are bright white (e.g. pyrite); medium density components — light gray (for example, quartz, carbonate and clay minerals); low-density components — dark gray (for example, organic matter); cracks — black (d). The volume of matrix components is relatively high and constitutes the bulk of the total volume of shale samples. The distribution of high-density minerals has a certain randomness. High-density ellipsoidal or irregular minerals (mainly pyrite) range in diameter from a few microns to hundreds of microns, and their volume is relatively small (e). Three types of microscale fractures are mainly developed in shale: microscale fractures within mineral particles (intragranular fractures), microscale fractures between mineral particles (intergranular fractures), and shrinkage fractures. Intragranular cracks are mainly microscale cracks formed by rigid particles that collapse in a certain direction under stress.

Data-Driven Classification and Logging Prediction of Mudrock Lithofacies Using Machine Learning: Shale Oil Reservoirs in the Eocene Shahejie Formation, Bonan Sag, Bohai Bay Basin, Eastern China

As the world’s energy demand continues to expand, shale oil has a substantial influence on the global energy reserves. The third submember of the Mbr 3 of the Shahejie Fm, characterized by complicated mudrock lithofacies, is one of the significant shale oil enrichment intervals of the Bohai Bay Basin. The classification and identification of lithofacies are key to shale oil exploration and development. However, the efficiency and reliability of lithofacies identification results can be compromised by qualitative classification resulting from an incomplete workflow. To address this issue, a comprehensive technical workflow for mudrock lithofacies classification and logging prediction was designed based on machine learning. Principal component analysis (PCA) and hierarchical cluster analysis (HCA) were conducted to realize the automatic classification of lithofacies, which can classify according to the internal relationship of the data without the disturbance of human factors and provide an accurate lithofacies result in a much shorter time. The PCA and HCA results showed that the third submember can be split into five lithofacies: massive argillaceous limestone lithofacies (MAL), laminated calcareous claystone lithofacies (LCC), intermittent lamellar argillaceous limestone lithofacies (ILAL), continuous lamellar argillaceous limestone lithofacies (CLAL), and laminated mixed shale lithofacies (LMS). Then, random forest (RF) was performed to establish the identification model for each of the lithofacies and the obtained model is optimized by grid search (GS) and K-fold cross validation (KCV), which could then be used to predict the lithofacies of the non-coring section, and the three validation methods showed that the accuracy of the GS–KCV–RF model were all above 93%. It is possible to further enhance the performance of the models by resampling, incorporating domain knowledge, and utilizing the mechanism of attention. Our method solves the problems of the subjective and time-consuming manual interpretation of lithofacies classification and the insufficient generalization ability of machine-learning methods in the previous works on lithofacies prediction research, and the accuracy of the model for mudrocks lithofacies prediction is also greatly improved. The lithofacies machine-learning workflow introduced in this study has the potential to be applied in the Bohai Bay Basin and comparable reservoirs to enhance exploration efficiency and reduce economic costs.

A composite water saturation model of continental mixed shale oil reservoirs based on complex lithology identification

The complex lithology, frequent interbedding and strong heterogeneity of the shale oil reservoir in Lucaogou Formation of the Middle Permian in Jimsar Sag lead to the complexity of litho‐electric parameters and the low accuracy of conventional reservoir saturation evaluation methods. Therefore, in this paper, automatic lithologic identification was firstly performed with the optimization inversion method of mineral components and K‐means clustering algorithm, and then, litho‐electric experiments were carried out to determine the litho‐electric parameters of different lithologies. Furthermore, the shale oil reservoir saturation calculation models of different lithologies were optimized and determined. Then, a composite water saturation model (Composite‐SW) based on complex lithology identification was constructed. Finally, the model was verified and analysed with the experimental results of water saturation. The coefficient of correlation between the calculation results of the Composite‐SW model and the core experiment results reached .88, indicating that the model was much better than conventional models. The model can be widely applied in logging evaluation of the continental mixed shale oil reservoir in the study area. The study provides a new idea for oil saturation evaluation of continental shale oil reservoirs and is significant for evaluating other types of shale oil reservoirs.

Sedimentary differentiation caused by glaciation and orogeny during the Ordovician–Silurian transition in the southern Sichuan Basin, China

The Wufeng–Longmaxi shales, which were deposited during the Ordovician–Silurian transition in the southern Sichuan Basin, exhibit distinct lithofacies transitions. The shift from organic-rich siliceous shale to organic-poor mixed shale and argillaceous shale is attributed to the influences of the Hirnantian glaciation and the Kwangsian Orogeny. Nevertheless, debates persist regarding the mechanisms underlying these significant lithofacies transformations. This study employs sequence stratigraphy, petrology, and geochemical analysis of key wells to unveil crucial insights. The findings indicate: 1) the Wufeng Formation to the Long-1 Member could be divided into two third-order sequences; 2) the waterbody underwent a transition from anoxic and strongly restricted conditions to oxic and moderately restricted conditions; and 3) the trend in formation thickness changed from an E–W orientation to a NE–SW orientation. The results suggest that considerable sediment condensation and anoxia resulting from glacier melting in the early Rhuddanian played a pivotal role in the formation of organic-rich siliceous shale. During the Middle Rhuddanian–Aeronian, the accelerated uplift caused by the Kwangsian Orogeny offset the transgression induced by glacier melting, leading to shallow water conditions and increased terrigenous influx. This diluted the organic matter content in the sediment, and subsequent turbidity currents altered sediment composition, driving the lithofacies transformation into organic-poor mixed shale and argillaceous shale. The study posits that the sedimentary differentiation in the southern Sichuan Basin during the Ordovician–Silurian transition is linked to the initiation and progression of the far-field effects of the Kwangsian Orogeny.

Influence of extractable organic components on shale wettability: Dongyuemiao member of Jurassic Ziliujing formation in the Fuxing area, Eastern Sichuan Basin

The wettability of reservoir rocks is a critical factor for the petroleum exploration and recovery, which plays an important role on relative permeability, capillary pressure, and ultimate recovery. This study aims to characterize the difference in wettability before and after soxhlet extraction, and reveal the influences of mineral composition, pore structure and extractable organic components on wettability of shales with different lithofacies. Several organic shale samples from the Dongyuemiao (DYM) section of the Jurassic Ziliujing (ZLJ) formation were collected to investigate the mineral composition, pore-size distribution, wettability characteristics and determine the main controlling factors on wettability alteration. Pore type and abundant are observed using argon ion polishing scanning electron microscopy. The pore volume (PV) and pore size distribution (PSD) characteristics before and after extraction were obtained using a combination of nitrogen physisorption and high-pressure mercury intrusion porosimetry (MIP). Spontaneous imbibition (SI) and nuclear magnetic resonance (NMR) experiments were used to investigate the wettability characteristics before and after extraction.Results show that clay, quartz and calcite are dominant minerals in the DYM shales, and three typical lithofacies are identified, including mixed shale (M), argillaceous shale (CM) and calcareous shale (C). Clay mineral interP pore is the dominant pore type in the DYM shales, followed by organic matter (OM) pore. Before the extraction, the DYM shale is more oil lipophilic, while its wettability alters slightly after the extraction. The M shales and C shales maintain lipophilic, while as the CM shales alters from oil wet to mixed wet. Samples with higher quartz have better connectivity of the hydrophilic and lipophilic pore networks, and carbonate minerals play an opposite role. During the extraction process, polar solvents could react with clay minerals to cause pore space expansion, which enhances the water wettability after extraction. Due to the low OM content and poor organic clay complex related pores in the study area, clay minerals have not significant correlation with oil wettability, but influence the water wettability. No correlation occurs between total organic carbon (TOC) content and oil/water wettability of shales before and after extraction. In comparison, macropore has a significant impact on water wettability, while micropore and mesopore play significant impact on oil wettability.

Lithofacies Characteristics and Sweet Spot Distribution of Lacustrine Shale Oil Reservoirs: A Case Study of the Second Member of the Kongdian Formation in the Cangdong Sag, Bohai Bay Basin

In contrast to marine shale oil reservoirs, lacustrine shale exhibits rapid lithofacies changes and strong mineral compositional heterogeneity, posing new challenges for the evaluation and distribution prediction of shale oil sweet spots. The oiliness, reservoir properties, oil fluidity, and fracability of different lithofacies were analyzed using emission-scanning electron microscopy (FE-SEM) observation, low-pressure nitrogen physisorption (LNP) analysis, mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), and triaxial compression testing. Based on the mineral composition obtained from X-ray diffraction (XRD) analysis, total organic carbon (TOC) content, and sedimentary structure, four lithofacies were classified, which are organic-rich laminated calcareous shale (LC), organic-rich laminated siliceous shale (LS), organic-rich laminated mixed shale (LM), and organic-poor massive calcareous shale (MC). Considering the factors of oiliness, reservoir properties, oil fluidity, and fracability, the LC and LS lithofacies were determined as being high-quality sweet spots (type I). Within the stratigraphic sequence divided by GR-INPEFA curves, multi-resolution graph-based clustering (MRGC) analysis of sensitive well logs was used to classify the lithofacies, after which the distribution of sweet spots was predicted. The results reveal that the sweet spots exhibit regular changes in their vertical distribution and a ring-like pattern in their planar distribution, influenced by variations in the sedimentary environment. This finding can offer valuable guidance for the future exploitation of shale oil in the Guandong region.

The occurrence characteristics of oil in shales matrix from organic geochemical screening data and pore structure properties: An experimental study

The occurrence characteristics of shale oil are of great significance to the movability of shale oil. In this study, the occurrence characteristics of oil in the shale matrix at Funing Formation shale in Subei Basin were quantitatively evaluated by organic geochemistry and microscopic pore structure characterization experiments. The Multiple Isothermal Stages Pyrolysis (MIS) experiment results show that the content of total oil, adsorbed oil, and free oil in the shales are 3.15–11.25 mg/g, 1.41–4.95 mg/g, and 1.74–6.51 mg/g, respectively. among which the silicon-rich shale has the best oil-bearing. The relative content of free oil shows an increasing trend in pores with pore diameters greater than 3 nm. When the relative content of free oil reaches 100%, the pore size of silicon-rich shale is about 200 nm, while that of calcium-rich shale, clay-rich shale, and siliceous mixed shale is about 10 nm. The occurrence law of adsorbed oil is opposite to that of free oil, which indicates that shale oil will occur in the pores and fractures in a free state in a more extensive pore size range (>200 nm). This study also enables us to further understand the occurrence characteristics of shale oil under the interaction of occurrence state and occurrence space.

Petrography and mineralogy control the nm-μm-scale pore structure of saline lacustrine carbonate-rich shales from the Jianghan Basin, China

Carbonate-rich shale in salt lakes has become a potential target for petroleum exploration. A full understanding of storage space development characteristics is the basis for the efficient development of this kind of shale. In this study, the complex mineral composition and multiple pore structure of a typical carbonate-rich shale from the Paleogene Xin'gouzui Formation in the Jianghan Basin were systematically analyzed. The mixed shale and dolomitic shale were the main lithofacies types in the study area. Both of them were dominated by interparticle (interP) pores. However, their pore sizes are noticeably different. Pores with a size of <100 nm are the main compositions of the mixed shale, with an average volume proportion of 78.24%. Conversely, the dolomitic shale develops mainly micro-sized pores and micro-fractures, with a ratio of 70.46%. The difference in pore structure for different types of shales is closely associated with mineral composition. When particles of different sizes are mixed, most of the interP pores are prone to be filled by fine minerals (e.g., clay), resulting in relatively small pore sizes for the mixed shale. Homogeneous carbonate minerals are favorable for the residual of larger size interP pores. However, recrystallization and secondary enlargement of carbonate minerals can also lead to a significant decrease in pore diameter of interP pores. With these results, a storage space development model for different lithofacies shales was established. This work is crucial to further reveal the reservoir mechanisms and hydrocarbon scales of an argillaceous dolomite reservoir.

Effect of litho-facies on nano-pore structure of continental shale in shuinan formation of Jiaolai Basin

Continental shale lithofacies has an important influence on nano-pore structure? However, nano-pore distribution heterogeneity (NDH) in continental shale lithofacies is not well documented. Continental shale was collected from the Shuinan Formation in the Jiaolai Basin, and the shale lithofacies of all samples are identified based on the mineralogical composition and TOC content. Nano-pore size distributions are characterized by LPN2 and CO2GA tests. Then, micro-pore (0.3∼2 nm) and meso-pore (2∼100 nm) distribution heterogeneity of different facies are discussed by single and multi-fractal model. Finally, the pore structure mechanism in shale lithofacies is clarified, and the results are as follows. The lithofacies of all shale samples are classified into three types, (A) calcareous shale lithofacies is characterized by the higher siliceous minerals and highest TOC content; (B) Calcareous/siliceous mixed shale lithofacies is characterized by middle TOC content; (C) Siliceous shale lithofacies is characterized by higher clay minerals and lowest TOC content. Micro- and meso-pore volume and A shale lithofacies NDH is much lower than that of B and C, which indicates that the lithofacies type has a great influence on the nano-pore structure. Felsic mineral and TOC content has a weak negative correlation with nano-pore structure, and there is a linear relationship between clay mineral content and nano-pore volume, indicating that clay mineral content is the main factor that can affect nano-pore structure. Moreover, fractal characteristics of the nitrogen desorption curve have been proved, and there are obvious differences in the fractal values of adsorption and desorption curves among those different lithofacies. Single fractal dimension D1 derived from LPN2 and CO2GA tests has a linear correlation with the multifractal parameter D-10-D0, which shows that a lower pore volume of pore diameter determines NDH variation. In conclusion, siliceous rich shale can provide a larger pore volume and specific surface area, and it acts as the dominant lithofacies for shale gas drainage in the study area.

Study on microscale pore structure and bedding fracture characteristics of shale oil reservoir

Accurately characterizing the cross-scale structure of pores and fractures in shale reservoirs is the theoretical basis for efficient exploration and development of shale oil and gas. In this paper, (a) Based on the research background of different shale maturity and sedimentary characteristics, a three-dimensional model of cross-scale pore-fracture structure is established; (b) Based on a large number of CT characterization data of core pore-fracture structure, the characteristics of pore-fracture development under different geometric dimensions (25 mm and 2 mm) are statistically analyzed; (c) Pore and fracture structures of mixed shale, felsic shale and laminated felsic shale is comparatively studied, and the pore structure and bedding fracture characteristics of shale oil reservoir is revealed. Results show that: (a) for the bedding fracture porosity, felsic shale in Group I is 0.36 %–0.89%; mixed shale in Group I is 0.34 %–0.47%; mixed shale in Group III is 0.12 %–0.86%; mixed shale gravelly dolomite in Group III is 0.13 %–0.15%. (b) Compared with block 1, the laminated felsic shale bedding in block 2 is more developed. (c) CT imaging is based on density difference. Different components of shale samples are distinguished by gray scale.

Favorable lithofacies and pore characteristics of the Permian Longtan Formation shale in the southern Sichuan Basin

The marine–continental transitional shale (MCTS) reservoirs of the Longtan Formation (LTF) are widely distributed in the Sichuan Basin. However, the LTF shale exhibits considerable variations in mineral composition and pore characteristics, which makes identifying the 'sweet spot'a challenging task. To address this issue, 10 samples from four typical shale gas wells in the LTF in the southern Sichuan Basin were selected and analyzed for total organic carbon (TOC) content, whole-rock composition using X-ray diffraction (XRD), low-pressure gas adsorption, and high-pressure mercury intrusion. The lithofacies distribution and pore structure of the MCTS were studied to determine the pore structural characteristics and the primary factors influencing pore formation in different types of shale lithofacies in the LTF. The lithofacies of the LTF shale in the study area can be classified into three categories: siliceous clay shale, clay shale and mixed shale. Mineral content has a significant impact on the pore characteristics, while TOC content has a minor effect on the pore volume and specific surface area of micropores and mesopores. It can be inferred that the mesopores in the MCTS are mainly related to clay mineral pores, and mineral dissolution and TOC content are not the primary factors contributing to pore formation.

Oil occurrence state and quantity in alkaline lacustrine shale using a high-frequency NMR technique

Complex fluid occurrence states and structures of shale reservoirs greatly affect shale oil productivity. For lacustrine shales with strong heterogeneity, it is important to identify oil movability, occurrence states and pore structures in different lithofacies in order to efficiently develop shale oil. This study combines conventional core analysis, X-ray diffraction (XRD), argon ion milled-scanning electron microscopy (AIM-SEM), multiple isothermal stages (MIS) pyrolysis and high-frequency nuclear magnetic resonance (HF-NMR) to create maps for samples in native, saturated, centrifuged, and dried states. A new T1-T2 map interpretation scheme is proposed, and fluid occurrence models for different shale lithofacies are established. Four oil species can be identified on the T1-T2 map. Free oil and adsorbed oil in macropores are located in the centers and edges of intergranular/intercrystalline pores, respectively. Oil in mesopores is located in intragranular/intracrystalline dissolution pores. Adsorbed oil exists in the pores of dispersed organic matter and in the marginal fractures of organic matter laminae. NMR and pyrolysis correlate well in the oil contents that they define. The occurrence state of shale oil in the Fengcheng Fm is closely related to minerals and organic matter. Siliceous minerals are beneficial to the occurrence of free oil that is usually a highly movable. The fluid-holding capacity of calcareous shale is limited, especially for adsorbed oil and restricted oil. Clay minerals (>10%) are not conducive to shale oil enrichment and flow, and mixed shale almost exclusively contains bound water. Organic matter is conducive to increasing oil content and to the movable oil saturation of siliceous shale and mixed shale.

Sedimentary environment controls on the lacustrine shale lithofacies: A case study from the Nanpu depression, Bohai Bay Basin

Organic-rich shale of the Paleogene Shahejie Formation in the Nanpu Sag Bohai Bay Basin was analyzed using petrographic and elements analysis. These analyses were used to identify the lithofacies, reconstruct the sedimentary paleoenvironment and their relation. This paper adopted the division scheme and naming method of “Total organic carbon (TOC) + sedimentary structure + mineral composition” to carry out lithofacies identification and division. The petrographical characteristics indicated that there are 15 types of lithofacies. According to the lithologic changes, we divided the study interval from the fourth sub-member of the third member of the Shahejie formation into three parts from the bottom up. The lower part has an evident fluctuation in paleoclimate, salinity, productivity, and redox condition. The middle part has cold and arid climate conditions, the weakest weathering, the highest paleo-productivity, and anoxic conditions. The upper part was deposited under humid and warm climate conditions, strongest weathering, brackish-fresh water, lowest paleo-productivity, and dominant oxic condition. Paleo-productivity and redox conditions are the basic conditions for the enrichment and preservation of organic matter, the paleo-climate and paleo-salinity were the critical factors controlling the mineral composition and laminae development. Under warm and humid climate conditions, the shallow lake mainly develops organic-poor massive felsic shale and siltstone; the semi-deep lake is mainly developed with organic-medium laminated/layered felsic shale; the deep lake mainly develops organic-rich laminated/layered clayey shale and mixed shale. Under dry and cold climate conditions, the shallow lake area mainly develops organic-poor felsic shale, and the semi-deep lake mainly develops organic-rich layered carbonate shale and organic-rich massive mixed shale; the deep lake mainly develops organic-rich laminated/layered clayey shale.

Reservoir characteristics of different shale lithofacies and their effects on the gas content of Wufeng-Longmaxi Formation, southern Sichuan Basin, China

Various shale lithofacies differ significantly in terms of gas content and pore structure characteristics. In this study, FE-SEM, low-pressure gas adsorption (LPGA), in-situ reservoir water saturation restoring, and high-pressure (0–51Mpa) methane adsorption were conducted to systematically characterize pore structure and evaluate the gas content of different shale lithofacies in the Wufeng-Longmaxi Formation, southern Sichuan Basin. The mineral compositions identified four shale lithofacies, and pores are abundant in siliceous shale and mixed shale. Siliceous shale has the largest pore volume (PV) and specific surface area (SSA), averaging 0.0310 cm3/g and 25.827 m2/g, respectively. However, the PV and SSA are lowest in argillaceous shale, averaging 0.0217 cm3/g and 18.734 m2/g, respectively. Water saturation is positively correlated with clay minerals, and argillaceous shale possess the highest water saturation of 60% due to the highest clay content. The supercritical Dubinin-Astakhov (S-DA) excess adsorption model predictions deviated less from the measured data and fitted well. The shale adsorption capacity are dominated by TOC content and total SSA. However, water and temperature have an inhibitory activity on adsorption capacity, with the adsorption capacity of water-bearing shales decreasing by 28%∼81% at a water saturation of 30%∼65% compared to dry shales. As the temperature increased from 40 °C to 80 °C, the methane adsorption capacity decreased from 3.95 to 2.79 m3/t, a 29% decrease. The shale gas content prediction models were established and extrapolated into the functions of reservoir depth. Deep shale gas reservoirs are dominated by free gas, accounting for over 90% at 5000 m. Siliceous shale has the highest gas content, followed by mixed shale, argillaceous-siliceous shale, and argillaceous shale. It is estimated that siliceous shale has a three-fold higher gas content than argillaceous shale. Siliceous and mixed shale are favorable reservoirs for shale gas exploration and development due to their high gas contents and low water saturation.