Shale Reservoirs Research Articles

A Real-Time Inversion Approach for Fluid-Flow Fractures in Unconventional Stimulated Reservoirs

Summary Fluid-flow fractures, through which fluids can move under pressure, make a more significant contribution to increasing production than do microseismic and propagation fractures. An accurate description of the distribution of fluid-flow fractures is the basis for evaluating hydraulic fracturing and oil/gas recovery. In this study, a real-time inversion approach for fluid-flow fractures was proposed, and the complex fluid-flow fracture morphology was obtained in real time by updating the data of the fracturing construction curve. First, a dynamic permeability model was proposed to describe the filtration rate of the fracturing fluid during hydraulic fracturing. Combined with the point source function, the flowing bottomhole pressure (pwf) can be quickly calculated based on the fracture morphology and displacement of the fracturing fluid. The variance of pwf and bottomhole pressure (pwb) obtained by pump pressure were used as an objective function, and the length of fluid-flow fractures and fracture morphology were used as fitting parameters. The length of the fluid-flow fractures was updated with the simultaneous perturbation stochastic approximation (SPSA) to achieve a rough fitting of the bottomhole pressure. On this basis, a probability function was used to constrain the randomness of the fractures, and the fracture morphology with a fixed fracture length was continuously simulated and finely matched. Finally, a complex fluid-flow fracture morphology was obtained. The method was used to analyze the fluid-flow fracture morphology of multifractured horizontal wells in shale reservoirs, and the fitting rate of the fracturing construction curve was more than 95%. The results show that the total length of the fluid-flow fractures in one stage in naturally fractured reservoirs was approximately 629 m, and those in homogeneous reservoirs and high-stress difference reservoirs were 564 m and 532 m, respectively. The length of fluid-flow fractures with “grooves” in the fracturing construction curve was longer than the length of fluid-flow fractures with “bulges.” The effectively stimulated reservoir area with fluid-flow fractures was only approximately 28–51% of the stimulated reservoir area with microseismic fractures.

Petrophysical properties identification and estimation of the Wufeng-Longmaxi shale gas reservoirs: a case study from South-West China

Abstract Petrophysical properties are critical for shale gas reservoir characterization and simulation. The Wufeng-Longmaxi shale, in the south-eastern margin of the Sichuan Basin, is identified as a complex reservoir due to its variability in lithification and geological mechanisms. Thus, determining its characteristics is challenging. Based on wireline logs and pressure data analysis, a shale reservoir was identified, and petrophysical properties were described to obtain parameters to build a reservoir simulation model. The properties include shale volume, sand porosity, net reservoir thickness, total and effective porosities, and water saturation. Total and effective porosities were calculated using density method. Shale volume was estimated by applying the Clavier equation to gamma-ray responses. Sand porosity and net reservoir thickness were evaluated using the Thomas–Stieber model, and the Simandoux equation was used to compute water saturation. The results indicate that the reservoir is characterized by a relatively low porosity and high shale content, with shale unequally distributed in its laminated form (approximately 75%), dispersed (about 20%), and structural form (5%). This research workflow can efficiently evaluate shale reservoir parameters and provide a reliable approach for future reservoir development and fracture identification.

Combined Effect of In Situ Stress Level and Bedding Anisotropy on Hydraulic Fracture Vertical Growth in Deep Marine Shale Revealed via CT Scans and Acoustic Emission

The economic exploitation of unconventional gas and oil in deep shale relies closely on effective hydraulic fracturing stimulations. However, the fracturing operations of deep shale reservoirs face challenges of insufficient fracture growth and a rapid decline in productivity due to the increasing in situ stress level. In addition, the shale strata on the margin of the Sichuan Basin are frequently folded and faulted, and the change in bedding inclinations significantly complicates the process of hydraulic fracturing. The investigation of the combined effect of the in situ stress level and bedding anisotropy on the hydraulic fracture configuration is vital for fracturing engineering design. To analyze this, we conducted hydraulic fracturing tests on shale cores to simulate the hydraulic fracture initiation and growth from a horizontally positioned perforation. By using acoustic emission detection and CT scans, the influence of natural stress levels and the angle of the shale’s bedding on the process of hydraulic fracturing in shale and the resulting fracture geometry were analyzed. The results showed that the area of hydraulic fracture under a higher stress level (σ1 = 50 MPa, σ3 = 40 MPa) was about 13%~23% smaller than that created under the lower stress level (σ1 = 30 MPa, σ3 = 20 MPa) when the bedding angle was smaller than 60°. With the increase in bedding angle, the curves of the fracture area and fracture network index under two different stress levels presented similar decreasing trends. Also, the time from micro-crack generation to sample breakdown was significantly reduced when the bedding orientation changed from the horizontal to vertical position. The increasing stress level significantly increased the breakdown pressure. In particular, the fracturing of shale samples with bedding angles of 0° and 30° required a higher fluid pressure and released more energy than samples with larger bedding inclinations. Additionally, the measurement of the sample radial deformation indicated that the hydraulic fracture opening extent was reduced by about 46%~81% with the increasing stress level.

Nano-Scale Pore Structure Characterization and Its Controlling Factors in Wufeng and Longmaxi Shale in the Zigong Area, Southwest Sichuan Basin

The nano-scale pore systems in shale reservoirs control shale gas transportation and aggregation, which is of great significance for the resource evaluation of shale oil and gas and the selection of a “sweet spot”. Taking twelve marine shale samples from the Wufeng–Longmaxi Formation in the Zigong area, southwest Sichuan Basin, as the research target, we carried out a series of experiments, including total organic carbon (TOC) analysis, X-ray diffraction (XRD), gas adsorption (CO2 + N2), and mercury intrusion porosimetry (MIP), to study the full-scale pore structure characterization and controlling factors of pore volume and specific surface area. The results presented the following findings. (1) Marine shale samples from the target area are rich in organic matter, with an average TOC value of 3.86%; additionally, the mineral composition was dominated by quartz and clay minerals, with average contents of 44.1% and 31.4%, respectively. (2) The full-scale pore size distribution curves of pore volume developed multimodally, with the main peaks at 0.5 nm–2 nm, 3 nm–6 nm, and 700 nm–2.2 um; moreover, the full-scale pore size distribution curves of a specific surface area developed unimodally, with the main peak ranging from 0.5 nm to 1.2 nm. (3) Pore volume was mainly contributed by mesopores and macropores, with an average contribution of 46.66% and 42.42%, respectively, while the contribution of micropores was only 10.91%. The specific surface area was mainly contributed by micropores and mesopores, with an average contribution of 64.63% and 29.22%, respectively, whereas the contribution of micropores was only 6.15%. (4) The TOC content mainly controlled the pore volume and specific surface area of micropores and mesopores, while the clay and feldspar content generally controlled the pore volume and specific surface area of macropores. Additionally, the quartz content had an inhibitory effect on the development of all pore types. These results will help researchers understand the laws of gas accumulation and migration.

Exploration of Oil/Water/Gas Occurrence State in Shale Reservoir by Molecular Dynamics Simulation

The occurrence state of oil, gas, and water plays a crucial role in exploring shale reservoirs. In this study, molecular dynamics simulations were used to investigate the occurrence states of these fluids in shale nanopores. The results showed that when the alkane is light oil, in narrow pores with a width less than 3 nm, oil molecules exist only in an adsorbed state, whereas both adsorbed and free states exist in larger pores. Due to the stronger interaction of water with the rock surface, the adsorption of oil molecules near the rock is severely prohibited. Oil/water/gas occurrence characteristics in the water-containing pore study indicate that CO2 gas can drive free oil molecules out of the pore, break water bridges, and change the occurrence state of water. During displacement, the gas type affects the oil/gas occurrence state. CO2 has strong adsorption capacity, forming a 1.45 g/cm3 adsorption layer on the rock surface, higher than oil’s density peak of 1.29 g/cm3. Octane solubility in injected gases is CO2 (88.1%) > CH4 (76.8%) > N2 (75.4%), with N2 and CH4 having weak competitive adsorption on the rock. The investigation of different shale reservoir conditions suggests that at high temperature or low pressure, oil/gas molecules are more easily displaced, while at low temperature or high pressure, they are tightly adsorbed to the reservoir rock. These findings contribute to the understanding of fundamental mechanisms governing fluid behavior in shale reservoirs, which could help to develop proper hydrocarbon recovery methods from different oil reservoirs.

CO2 storage in organic nanopores with varying widths: Molecular simulation and simplified local density model

Accurately characterizing CO2 adsorption behavior in organic nanopores is a prerequisite for estimating CO2 storage capacity in shale reservoirs with complex pore structures. This study employs grand canonical Monte Carlo (GCMC) molecular simulations to investigate the CO2 adsorption characteristics in organic nanopores with varying widths over a wide range of temperatures and pressures. Based on GCMC simulations, the pore width in the simplified Local-Density (SLD) adsorption model is related to key adsorption parameters, enabling the SLD model to evaluate CO2 storage density rapidly and accurately in organic nanopores under complex reservoir conditions. The research findings suggest that the features of CO2 excess adsorption curves are mainly influenced by temperature and the number of adsorption layers. Higher temperatures and increased adsorption layers result in higher pressure requirements to achieve the CO2 excess adsorption peak. Under high pressures, the number of adsorption layers plays a critical role in enhancing the adsorption capacity. Due to the constraints of pore size, there are fewer adsorption layers in micropores, leading to higher CO2 excess adsorption in mesopores than in micropores under high pressures. In the SLD model, the key parameter Λb decays exponentially with the increase of pore width. The average density of CO2 in the nanopores calculated by the modified SLD model is in good agreement with the simulation results. Finally, the research reveals that smaller organic nanopore widths result in higher CO2 densities, with limited sensitivity to temperature and pressure variations. Low pressure and high temperature reservoir conditions are unfavorable for CO2 storage, but adsorption significantly enhances CO2 storage density in nanopores, particularly in micropores.

Classification of shale lithofacies with minimal data: Application to the early Permian shales in the Ordos Basin, China

Shale lithofacies classification is one of the key components of shale reservoir evaluation. Typically, a significant amount of laboratory X-ray diffraction (XRD) data acquired on many shale samples collected in a large number of boreholes is required to constrain the mineral composition that enables classifying shale lithofacies at the basin scale. This procedure is costly and time consuming. Here, we propose a supervised machine learning method to predict the mineral composition of shale samples, including the clay and silicate content. The main advantage of our approach is that it only uses conventional logging data and a small number of XRD measurements of core samples, combined with XGBoost algorithm, to predict shale lithofacies, which can reduce the cost and improve the efficiency of reservoir evaluation. We apply our method on the early Permian shales in the Ordos Basin, China, because these shale rocks have a high potential of gas production. However, these formations are also highly heterogeneous, making them challenging to explore and exploit. Therefore, it is critical to perform detailed lithofacies classification analysis at the basin scale before gas production. Our result show that the gamma ray, neutron porosity, and density measurements are the critical logging data that control the model predictions. These parameters are known to be sensitive to clay content, thereby supporting the robustness of model predictions. Applying the model to different wells to classify shale lithofacies, results that these shale formations are dominated by three types of lithofacies. We characterize the different shale lithofacies by microscopy images and gas adsorption measurements, and demonstrate that our results are consistent with previous studies, verifying the accuracy and applicability of our machine learning method to classify shale lithofacies.

Effects of fracturing fluid composition and other factors on improving the oil imbibition recovery of shale reservoir

Effects of fracturing fluid composition and other factors on improving the oil imbibition recovery of shale reservoir

Automatic pore structure analysis in organic-rich shale using FIB-SEM and attention U-Net

The pore structure is an important factor in determining the productivity of shale, which can help us make better operational decisions. Shale formations have an extremely complex pore structure with a wide range of pore sizes, shapes, orientations, and connectivity. Advanced imaging techniques, such as focused ion beam scanning electron microscopes (FIB-SEM), contribute significantly to the analysis and understanding of complex pore networks in shale, but they are time-consuming. Developing new methods and techniques to capture the spatial distribution and connectivity of pores at various scales is essential to understanding pore structure and its impact on fluid flow. This study aims to analyze the pore characteristics of shale reservoirs by using artificial intelligence (AI) and FIB-SEM. We applied a novel attention gate (AG) model to FIB-SEM images that automatically learns to focus on target structures of varying pores’ shape and size. AG can be fully incorporated into the U-Net model with minimal computational impact. The AG improved prediction accuracy by making the U-Net model more sensitive to essential features in the input images and achieved a precision of 97%, recall of 71%, and F1 score of 81% at a confidence threshold of 1. Experimental results show that Attention U-Net outperformed in predicting the pore structures in shale samples from Longmaxi Formation, Qingshankou Formation, Cambrian Niutitang Formation, Yanchang shale oil, and Bakken shale while obtaining optimal performance without requiring multiple convolutional neural network (CNN) models. Additionally, Attention U-Net addresses some of the limitations of the Edge-Threshold Automatic Processing (ETAP) method, including the limited ability to obtain a complete description of the pore space as well as the low segmentation accuracy and sensitivity. The proposed workflow offers a promising solution for optimizing the automatic processing of microscopic images for pores and microfractures identification. Researchers and industry professionals can improve their understanding of shale properties and applications in various fields by maximizing the benefits of our workflow.

Micropore Structure of Deep Shales from the Wufeng–Longmaxi Formations, Southern Sichuan Basin, China: Insight into the Vertical Heterogeneity and Controlling Factors

The microscopic pore throat structure of shale reservoir rocks directly affects the reservoir seepage capacity. The occurrence and flow channels of shale gas are mainly micron–nanometer pore throats. Therefore, to clarify the microstructural characteristics and influencing factors of the deep organic-rich shales, a study is conducted on the marine shale from the Upper Silurian to Lower Ordovician Wufeng–Longmaxi Formation in the southern Sichuan Basin. Petrographic lithofacies division is carried out in combination with petro-mineralogical characteristics, and a high-resolution scanning electron microscope, low-temperature nitrogen and low-temperature carbon dioxide adsorption, and micron-computed tomography are used to characterize the mineral composition and pore structure qualitatively and quantitatively, upon which the influencing factors of the microstructure are further analyzed. The results show that with the increase in burial depth, the total organic carbon content and siliceous mineral content decrease in the Wufeng formation to Long-11 subsection deep shale, while clay mineral content increases, which corresponds to the change in sedimentary environment from anoxic to oxidizing environment. Unexpectedly, the total pore volume of deep shale does not decrease with the increase in burial depth but increases first and then decreases. Using total organic carbon (TOC), siliceous mineral content showed a good correlation with total pore volume and specific surface area, with correlation coefficients greater than 0.7, confirming the predominant role of these two factors in controlling the pore structure of deep shales. This is mainly because the Longmaxi shale is already in the late diagenetic stage, and organic matter pores are generated in large quantities. Clay minerals have a negative correlation with the total pore volume of shale, and the correlation coefficient is 0.7591. It could be that clay minerals are much more flexible and are easily deformed to block the pores under compaction. In addition, the longitudinal heterogeneity of the deep shale reservoir structure in southern Sichuan is also controlled by the thermal effect of the Emei mantle plume on hydrocarbon generation of organic matter and the development of natural microfractures promoted by multistage tectonic movement. Overall, the complex microstructure in the deep shales of the Longmaxi Formation in the southern Sichuan Basin is jointly controlled by multiple effects, and the results of this research provide strong support for the benefit development of deep shale gas in southern Sichuan Basin.

Impacts of Pore Structure on the Occurrence of Free Oil in Lacustrine Shale Pore Networks

The ultimate recovery of shale oil is mostly dependent upon the occurrence and content of free oil within the nano-scaled pore network of shale reservoirs. Due to the nanoporous nature of shale, quantitatively characterizing the occurrence and content of free oil in shale is a formidable undertaking. To tackle this challenge, 12 lacustrine shale samples with diverse organic matter content from the Chang7 Member in the southern Ordos Basin were selected, and the characteristics of free oil occurrence were indirectly characterized by comparing changes in pore structure before and after organic solvent extraction. The free oil enrichment in shale was assessed using the oil saturation index (OSI), corrected oil saturation index (OSIcorr), and percentage of saturated hydrocarbons. The results revealed that slit-like interparticle pores with diameters less than 30 nm are dominant in the Chang7 shale. Conceptual models for the pore structures containing free oil were established for shale with total organic carbon (TOC) content less than 9% and greater than 9%, respectively. Shale samples with TOC content less than 9% exhibit a well-developed pore network characterized by relatively larger pore volume, surface area, and heterogeneity. Conversely, shale samples with TOC content exceeding 9% display a less developed pore network characterized by relatively smaller pore volume, surface area, and heterogeneity. Larger pore volume and lower organic matter abundance favor the enrichment of free oil within the lacustrine shale pore network. This study may have significant implications for understanding oil transport in shales.

Role of magmatism in efficient gas accumulation in Upper Ordovician-Lower Silurian shales in the Yangtze plate, South China: Evidence from the calcite U-Pb ages and gas C-N isotopes

Shale gas exploration in the Yangtze plate has been hindered by strong heterogeneity of gas compositions resulting from magmatism. Borehole core and gas samples from Upper Ordovician-Lower Silurian in the Upper Yangtze plate and the Lower Yangtze plate were analyzed to explore the effects of magmatism on gas accumulation. The analyses included nitrogen isotope of gas, pore structure and X-ray photoelectron spectroscopy of shales, and U-Pb ages of fracture-filling calcites. Our results suggest that magmatism caused the development of micro-fractures in shale reservoirs and accelerated the thermal evolution rate of organic matter. Magmatism in the Upper Yangtze plate predates the peak of gas generation of Upper Ordovician-Lower Silurian shales. Generation and expulsion of hydrocarbon at high temperatures removes 12C from carbon reservoir. After the magmatism, the continuous subsidence of the strata led to further hydrocarbon generation of organic matter. Moreover, the self-sealing property of shale reservoirs were enhanced by the closure of micro-fractures, development of graphite structures, and enrichment of 13C in residual methane, which favor the efficient accumulation of shale gas. Conversely, magmatism in the Lower Yangtze plate occurred after the peak of gas generation of Upper Ordovician-Lower Silurian shales. Magmatism compromised shale gas reservoirs by disrupting sealing conditions, facilitating methane diffusion and atmospheric nitrogen influx. Additionally, overburden pressure led to the collapse of graphitized OM-hosted pores, further inhibiting gas accumulation. Our findings underscore the pivotal role of magmatism in various stages of shale gas accumulation and are critical for exploration strategies in sedimentary basins with prevalent magmatic activities.

A novel method for quantitative evaluation of oil content and mobility in shale oil reservoirs by NMR logging: a case study of the inter-salt shale oil in the Jianghan Basin

The evaluation of oil content and mobility in shale oil reservoirs is the key to the optimization of the "sweet spot" of shale reservoirs and the evaluation of available resources. In order to address the challenge of quantitative evaluation of oil content and mobility in shale oil reservoirs, a combined multi-temperature pyrolysis and NMR experimental platform and experimental procedure are innovatively designed and implemented in this paper. The experiments reveal the NMR T2 distribution characteristics of hydrocarbon components in different reserve states. Accordingly, the NMR T2 cutoff values of different hydrocarbon components are determined, and the quantitative evaluation method based on NMR logging for total oil content and movable hydrocarbon content is established. The method has been applied to the inter-salt shale oil BYY2 well in Jianghan Oilfield, and the results show that the total porosity of the shale reservoir in the Qian 4 sub-Member is similar, but the total hydrocarbon content (0.04 g/kg∼16.0 g/kg) and the movable oil content (0.02 g/kg∼4.9 g/kg) are significantly different. Compared with the preferred scheme of reservoir based on porosity, accurate quantitative evaluation results of oil content and mobility based on logging provide a more straightforward indication of the resource potential of the reservoir that is available for exploitation. The experimental scheme of multi-temperature pyrolysis-NMR and the quantitative evaluation method for oil content and motility based on NMR logging will provide an important basis for resource evaluation, optimal formation selection and efficient development of shale oil reservoirs.

The Effect of Thermal Maturity on the Pore Structure Heterogeneity of Xiamaling Shale by Multifractal Analysis Theory: A Case from Pyrolysis Simulation Experiments

Shale oil and gas, as source-reservoir-type resources, result from organic matter hydrocarbon generation, diagenesis, and nanoscale pore during the evolution processes, which are essential aspects of shale gas enrichment and reservoir formation. To investigate the impact of diagenetic hydrocarbons on shale pore heterogeneity, a thermal simulation of hydrocarbon formation was conducted on immature shale from the Middle Proterozoic Xiamaling Formation in the Zhangjiakou area, covering stages from mature to overmature. Nuclear magnetic resonance (NMR) instruments analyzed the microstructure of the thermally simulated samples, and the multifractal model quantitatively assessed pore development and heterogeneity in the experimental samples. The results reveal that the quartz and clay mineral contents show alternating trends with increasing temperature. Organic matter dissolution intensifies while unstable mineral content decreases, promoting clay mineral content development. Pyrolysis intensity influences Total Organic Carbon (TOC), which reduces as hydrocarbons are generated and released during simulation. Porosity exhibits a decreasing–increasing–decreasing trend during thermal evolution, peaking at high maturity. At maturity, hydrocarbon generation obstructs pore space, resulting in higher levels of bound fluid porosity than those of movable fluid porosity. Conversely, high maturity leads to many organic matter micropores, elevating movable fluid porosity and facilitating seepage. Shale pore heterogeneity significantly increases before 450 °C due to the dissolution of pores and the generation of liquid and gas hydrocarbons. In the highly overmature stage, pore heterogeneity tends to increase slowly, correlated with the generation of numerous micro- and nano-organic matter pores.

The provenance of microorganisms adapted to extreme salinity, extreme temperature, and toxic metals within the Montney shale formation.

Introduction Shale oil reservoirs are hypothesized to be sterile due to the extremely high temperature, pressure and salinity within these formations (Evans et al. 2018). High concentrations of toxic metals also pose challenges that demand specific microbial adaptions (Boyd and Barkay 2012, White and Gadd 1998, Ben Fekih et al. 2018). While some microorganisms are introduced into and are selected for within shale formations during hydraulic fracturing, the possibility that certain microorganisms are pre-existing inhabitants of these formations is less clear. Here, we followed the microbial diversity of input and output fluids injected into a Montney formation shale reservoir to assess the distribution and transport of microbial populations during hydraulic fracturing. Enrichment cultures distinguished various metabolisms in the microbial populations found in different sample types, and adaptations allowing them to colonize such niches. Material and methods Fracturing fluid, drilling muds (3302 m, 3350 m and 3400 m depths), shale cuttings (rinsed from the drillings muds), shale core plugs and produced water samples (12-month period) were sampled from a Montney shale oil reservoir. Microbial community compositions were analyzed by amplicon sequencing. Metal content was analyzed by inductively coupled plasma-mass spectrophotometry. High salinity enrichments at 90°C of the drilling muds or rinsed shale samples were set up in triplicate and amended with glucose and guar gum (a mannose/galactose-based polymer used during hydraulic fracturing). Sugars were measured through spectrophotometric assays. Metagenomic analyses were performed to assess microbial gene content. Results/Discussion Provenance of microorganisms from the Montney shale formation Provenance of microorganisms from the Montney shale formation Input fluids (fracturing fluid, drilling muds) were revealed to be the likely source of most of the microbial diversity. However, some microorganisms were only detected in the subsurface samples. ASVs affiliated with Aurantimonas, Caminicella, BRH-c8a (Family Desulfallas) and Geotoga exhibited occurrence patterns consistent with being derived from subsurface shale formations. Geotoga has only ever been reported from oil reservoirs (Semenova et al. 2020). Analysis of produced water revealed ASVs from these groups increasing in abundance during hydraulic fracturing operations, suggesting selective pressure from oil reservoir conditions (e.g., toxic metal presence, input of saline water, temperature and pressure fluctuations). Incubations set up from drilling muds showed a preference for glucose while incubations of the rinsed shale cuttings showed a microbial preference for guar gum (i.e., mannose production; Fig. 0), reinforcing the presence of different populations being derived from surface and subsurface samples. Adaptations for life in Montney shale Adaptations for life in Montney shale When considering adaptations of microorganisms for environmental conditions found in oil reservoirs, it is relevant to note the presence of toxic metals such as arsenic, cadmium and mercury. Levels of all three metals were found to vary over time within the 28-day shale microbial enrichments and 12-month produced water time course analyses (Suppl. material 1). Metagenomics revealed various genes for the internalization and metabolism of all three metals within the shale microbiome (i.e., arsenate reductases, arsenite transporters, metallothioneins, mercuric reductases). In conclusion, the results of this study suggest that shale reservoirs thus might not be sterile environments, and host microorganisms are able to contend with major perturbations.

DRAG: A Novel Method for Automatic Geological Boundary Recognition in Shale Strata Using Multi-Well Log Curves

Ascertaining the positions of geological boundaries serves as a cornerstone in the characterization of shale reservoirs. Existing methods heavily rely on labor-intensive manual well-to-well correlation, while automated techniques often suffer from limited efficiency and consistency due to their reliance on single well log data. To overcome these limitations, an innovative approach, termed DRAG, is introduced, which uses deep belief forest (DBF), principal component analysis (PCA), and an enhanced generative adversarial network (GAN) for automatic layering recognition in logging curves. The approach employed in this study involves the use of PCA for dimensionality reduction across multiple well log datasets, coupled with a sophisticated GAN to generate representative samples. The DBF algorithm is then applied for stratification, incorporating a confidence screening mechanism to improve computational efficiency. In order to improve both accuracy and stability, a coordinate system is introduced that adjusts for stratification variations among neighboring wells around the target well. Experimental comparisons demonstrate the superior performance of the proposed algorithm in reducing stratification fluctuations and improving precision.

Numerical Simulation of Multi-cluster Fracturing Using the Triaxiality Dependent Cohesive Zone Model in a Shale Reservoir with Mineral Heterogeneity

Numerical Simulation of Multi-cluster Fracturing Using the Triaxiality Dependent Cohesive Zone Model in a Shale Reservoir with Mineral Heterogeneity

A semi-analytical model for coupled flow in stress-sensitive multi-scale shale reservoirs with fractal characteristics

A large number of nanopores and complex fracture structures in shale reservoirs results in multi-scale flow of oil. With the development of shale oil reservoirs, the permeability of multi-scale media undergoes changes due to stress sensitivity, which plays a crucial role in controlling pressure propagation and oil flow. This paper proposes a multi-scale coupled flow mathematical model of matrix nanopores, induced fractures, and hydraulic fractures. In this model, the micro-scale effects of shale oil flow in fractal nanopores, fractal induced fracture network, and stress sensitivity of multi-scale media are considered. We solved the model iteratively using Pedrosa transform, semi-analytic Segmented Bessel function, Laplace transform. The results of this model exhibit good agreement with the numerical solution and field production data, confirming the high accuracy of the model. As well, the influence of stress sensitivity on permeability, pressure and production is analyzed. It is shown that the permeability and production decrease significantly when induced fractures are weakly supported. Closed induced fractures can inhibit interporosity flow in the stimulated reservoir volume (SRV). It has been shown in sensitivity analysis that hydraulic fractures are beneficial to early production, and induced fractures in SRV are beneficial to middle production. The model can characterize multi-scale flow characteristics of shale oil, providing theoretical guidance for rapid productivity evaluation.

The effect of lamina and lithofacies assemblage on molecular maturity of oil in a shale source-rock reservoir

This paper discusses the effect of the source rock–reservoir assemblage and the assemblage–induced variability in hydrocarbon expulsion and the subsequent molecular composition as well as molecular thermal maturity within a hybrid shale system. The characterization work was conducted on lithofacies and microlamina scales using core samples from the Chang 73 sub-member of the Triassic Yanchang Formation in the Ordos Basin, China. Samples were collected from a narrow interval with a depth range of less than 15 m, and the main characterization work was performed by Rock-Eval pyrolysis and GC–MS analysis. The results show that chemical fractionation of preferential expulsion and migration of the saturated fraction exists in the source rock–reservoir assemblages at both the lithofacies and lamina scales. However, the molecular composition behaves differently at the lithofacies and lamina scale's source rock–reservoir assemblages, in which ∑C21−/∑C22+ is higher in lamina scale reservoir but lower in lithofacies scale reservoir. It is assumed that the low-molecular weight n-alkanes also follow molecular fractionation. The lithofacies reservoir has a lower ∑C21−/∑C22+ because of the strong storage capacity of the laminated micro-reservoir within shale, which prevents the newly generated lighter oil from being charged into the lithofacies reservoir. The variation trends of thermal maturity indices Ts/hopane, the relative pregnane content, and TA(I)/TA(I + II) ratios, which have the same chemical basis with ∑C21−/∑C22+, carry the same maturity signature as ∑C21−/∑C22+. The above profile of the molecular composition and molecular-derived thermal maturity parameters indicate that within the short interval of a shale system where no differences in thermal maturity are expected, chain scission reactions and their derived thermal maturity indicators are very sensitive to source rock and reservoir. In addition, within a shale system, oil is more easily to expel out from the organic-rich lithofacies that are interbedded with organic-lean lithofacies. Oil expulsion may promote both chain cracking of oil and subsequently kerogen decomposition. This may provide geological evidence to explain why the frequent-stacking assemblage of source rock and reservoir lithofacies in a hybrid shale system is an ideal target for shale oil exploration.

An XFEM-based CZM Numerical Strategy for Modeling Hydraulic Fracture Propagation under Different Fracturing Schemes

Segmented and cluster fracturing can improve the efficiency of volume stimulation in shale reservoirs and reduce construction costs. It is important to clarify the propagation characteristics of hydraulic fractures and stress interference under different fracturing techniques to optimize the process of clustered and staged fracturing. For this purpose, we have developed a 2D XFEM-based CZM hydraulic fracturing model. The capability of this model was validated by analytical solutions and then used to study the propagation paths of hydraulic fractures and the characteristics of stress interference under simultaneous fracturing, sequential fracturing, zipper fracturing and multi-cluster fracturing. The results show that in simultaneous fracturing, the middle cluster is compressed by the external position clusters, and the opening width of hydraulic fractures is reduced. In sequential fracturing, the fracture that first initiates create an additional stress field that inhibits the propagation distance of subsequent fractures and the propagation path of hydraulic fractures is also affected in the stress shadow region. Zipper fracturing can effectively alleviate stress interference between multiple fractures, and internal fractures can also propagate a certain distance. In multi-cluster fracturing, the fluid rate into the internal fractures may be limited, and fracture propagation is also limited by stress interference. Therefore, it is necessary to optimize the parameters of clusters to ensure that all clusters can initiate fractures normally. The research results are important for the parameter optimization of clustered and staged fracturing, especially for well factory fracturing mode.