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Organic-rich hot Qusaiba shale is the primary source rock of most of the Paleozoic hydrocarbon reservoirs of eastern and central Arabia. Representative near-surface Qusaiba shale samples were collected and characterized from one of its outcrop sections at the Tayma quadrangle in northwest Saudi Arabia. The petrophysical and geochemical characterization indicated porosity and permeability of 8.2% and 2.05 nD, respectively, with good total organic carbon (TOC) of 2.2 mg/g and mature kerogen of gas-prone type III. The tight characteristics of the formation can lead to high capillary pressure and extensive post-fracking water retention, leading to flow blockage and a reduction in gas productivity. Three different surfactants and one ionic liquid, namely, Triton X-100, Triton X-405 and Zonyle FSO surfactants and Ammoeng 102 ionic liquid, were tested as additives to fracking fluid to investigate their effectiveness in optimizing its performance. The chemical solutions exhibited no sign of instability when exposed to solution salinity and temperatures up to 70 °C. The investigated chemicals’ performance was examined by measuring methane/chemical solutions’ surface tension and their ability to alter shale’s wettability. The results indicate that Zonyl FSO is the most effective chemical, as it is able to significantly reduce surface tension and, hence, capillary pressure by 66% when added at critical micelle concentration (CMC). Using Zonyl FSO surfactant at a maximum tested concentration of 0.2% induced a relatively smaller capillary pressure drop (54%) due to the drastic drop in the contact angle rendering shale very strongly water-wet. Such a drop in capillary pressure can lower the fracking fluid invasion depth and therefore ease the liquid blockage removal during the flowback stage, enhancing gas recovery during the extended production stage. Triton X-100 at CMC was the second most effective surfactant and was able to induce a quite significant 47% drop in capillary pressure when added at the maximum tested concentration of 0.05%. This was sufficient to remove any liquid blockage but was less likely to alter the wettability of the shale. Based on the findings obtained, it is suggested to reduce the blockage tendency during the fracking process and elevate any existing blockage during the flowback stage by using Zonyl FSO at CMC where IFT is at its minimum with a higher contact angle.

Shale gas, mainly consisting of adsorbed gas and free gas, has served a critical role of supplying the growing global natural gas demand in the past decades. Considering that the adsorbed methane has contributed up to 80% of the total gas in place (GIP), understanding the methane adsorption behaviors is imperative to an accurate estimation of total GIP. Historically, the single-site Langmuir model, with the assumption of a homogeneous surface, is commonly applied to estimate the adsorbed gas amount. However, this assumption cannot depict the methane adsorption characteristics due to various compositions and pore sizes of shales. In this work, a multi-site model integrating the energetic heterogeneity in adsorption is derived to predict methane adsorption on shale. Our results show that the multi-site model is capable of addressing the heterogeneity of shales by a wide range of adsorption energy distributions (owing to the complex compositions and different pore sizes), which is different from the single-site model only characterized by single adsorption energy. Consequently, the multi-site model results have better accuracy against the experimental data. Therefore, applying the multi-site Langmuir model for estimating GIP in shales can achieve more accurate results compared with using the traditionally single-site model.

This work aims to explore the Lower Silurian shale gas and tight sandstone gas accumulation conditions in the Gongtan Syncline, southeastern Sichuan Basin. The sedimentary environment, organic geochemical characteristics, reservoir characteristics, gas content, and preservation conditions of the reservoir were comprehensively analyzed. The results show that the Wufeng–Longmaxi Formation shale formed in a deep-water shelf characterized by a large thickness (50–70 m), appropriate total organic carbon content (0.5–5.47%), high maturity (2.38%), high brittle mineral content (67.10%), and large gas content (0.71–1.64 m3/t), and the formations show the good resource potential of the shale gas. The Xintan Formation formed in a lower shore phase, and the tight sandstone is locally developed with a small thickness. The Xiaoheba Formation formed in an upper-middle shore phase, and the tight sandstone is stably distributed with large thicknesses. The porosity and permeability of the two sets of sandstone are small and some natural fractures are developed in the sandstone, but the fracture filling degree is higher. The results of well logging show that there are abnormally high values of total hydrocarbon in both the Xintan Formation and Xiaoheba Formation; this indicates that tight sandstone gas is developed in the Lower Silurian strata. A comprehensive study indicates that the Lower Silurian of the Gongtan Syncline has the geological conditions for the formation of shale gas and tight sandstone gas, which are the “Two gases” with good co-exploration prospects.

This investigation ventures into the nuanced porosity traits of shallow shale gas reservoirs, pinpointing the critical determinants of their gas content with a nuanced touch. By harnessing sophisticated microscopy and analytical methods, we embarked on an exploration into the porosity architecture of shale, identifying the distinct pore spaces that harbor shale gas and applying gas adsorption techniques to evaluate its storage potential. Noteworthy is our utilization of diverse adsorption mechanisms and models to accurately fit methane adsorption data while carefully considering the influence of marine shallow shale’s pore structure peculiarities, total organic carbon (TOC) content, and clay mineral content on its adsorption prowess. We introduce a refined model for appraising gas adsorption volumes, an innovative stride toward bolstering the precise estimation of reserves in marine dam shallow shale gas and shedding light on accurate gas adsorption volume calculations in analogous shallow shale gas scenarios. This manuscript offers profound insights into the sophisticated interplay between shale porosity and gas storage, enriching our understanding and enabling more accurate future resource estimations.

In this paper, based on the background of a deep shale reservoir, a solid–liquid two-phase flow model suitable for proppant and fracturing fluid flow was established based on the Euler method, and a large-scale fracture model was established. Based on field parameters, a proppant transport experiment was conducted. Then, on the basis of the experimental fracture model, proppant transport simulation under different influencing factors was carried out. The results show that the laboratory experiment was in good agreement with the simulated results. The process of proppant accumulation in fractures can be divided into three stages according to the characteristics of sand banks. The displacement mainly affects the sedimentation distance of the proppant in the first stage, and the viscosity of the fracturing fluid represents the strength of the fluid sand carrying performance. Compared with 40/70 mesh proppant, 70/140 mesh proppant is more easily fluidizable, the fracture width has less influence on proppant migration and placement, and the perforation location only affects the accumulation pattern at the fracture entrance, but has less influence on proppant placement in the remote well zone.

The Lower Cambrian Niutitang Formation in the Northern Guizhou harbors abundant organic-rich mud shale, constituting the most significant marine shale gas reservoir in Guizhou. In this article, the reservoir characteristics of Lower Cambrian Niutitang Formation in Northern Guizhou are analyzed in terms of lithology, mineralogy, organic geochemistry, pore structure, gas content and continuous thickness of shale, and the exploration potential of shale gas in this area is evaluated. The results indicate that the content of brittle minerals in the shale of well QX1 is 65.29% to 95.22% (average of 82.10%). The total organic carbon (TOC) content ranges from 2.06% to 12.10% (average of 5.64%). The organic matter maturity (Ro) within the range of 2.29–2.67%, and the kerogen type is identified as type I. The shale samples from the Niutitang Formation have high TOC content, suitable thermal maturity, and a favorable kerogen type, suggesting good gas generation potential. The results of scanning electron microscopy (SEM) show that intergranular pores, intragranular pores and microfractures are developed in the shale of well QX1, which can provide sufficient storage space for shale gas. The shale exhibits a continuous thickness of 105.66 m in the QX1 well, comprising a gas-bearing interval of 32.89 m at the top (with an effective continuous thickness of 18 m) and a hydrocarbon source rock layer of 75.78 m at the bottom. In comparison with other shale gas regions, Niutitang Formation shale in Northern Guizhou exhibits characteristics such as favorable gas generation conditions, greater storage conditions, excellent gas-bearing, strong frackability, and substantial continuous thickness, it has greater potential for shale gas exploration.

The objective of this study is to construct a refined microscopic transport model that elucidates the transport mechanisms of gas flow within micro-nano pores and fractures. The collective impact of various microscopic transport mechanisms was explained through the apparent permeability model, specifically related to gases such as methane and carbon dioxide, within the shale matrix. The apparent permeability models, taking into account microscopic transport mechanisms such as slippage flow, Knudsen diffusion, transition flow, and surface diffusion, were established individually. Subsequently, the influencing factors on apparent permeability were analyzed. The results demonstrate that the apparent permeability of the shale reservoir matrix is significantly influenced by pore pressure, temperature, pore size, and total organic carbon (TOC). As pressure decreases, the apparent permeability of Knudsen diffusion and surface diffusion increases, while the apparent permeability of slippage flow decreases. In addition, the apparent permeability of the reservoir matrix initially decreases and then increases. With increasing temperature, the apparent permeability of slippage flow, Knudsen diffusion, and surface diffusion all increase, as does the apparent permeability of the reservoir matrix. As pore size increases, the apparent permeability of surface diffusion and Knudsen diffusion decreases, while the apparent permeability of slippage flow and the reservoir matrix increases. Furthermore, an increase in TOC leads to no change in the apparent permeability of slippage flow and Knudsen diffusion, but an increase in the apparent permeability of surface diffusion and the reservoir matrix. The model presented in this paper enhances the multi-scale characterization of gas microflow mechanisms in shale and establishes the macroscopic application of these micro-mechanisms. Moreover, this study provides a theoretical foundation for the implementation of carbon capture, utilization, and storage (CCUS) in shale gas production.

Against the backdrop of the national strategic goals of carbon peaking and carbon neutrality, the imperative for China’s low-carbon new energy transformation is evident. Emerging as an efficient and clean new energy source, the coal-based “three gases” (coalbed methane, tight sandstone gas, and shale gas) have gained prominence. Nevertheless, the current exploration of the coal-based “three gases” is limited to individual reservoirs, posing challenges to achieving overall extraction efficiency. The primary obstacle lies in the conspicuous disparities in gas content among different reservoirs, with the causes of such disparities remaining elusive. To address this issue, this study focused on the Permian Longtan Formation (coal, shale, and tight sandstone) in the southeastern Sichuan Basin. Through a comparative analysis of the mineral composition, organic geochemical features, and pore structure characteristics, this study aimed to delineate reservoir variations and establish a foundation for the simultaneous exploration and exploitation of the coal-based “three gases”. The research findings revealed that the differences in reservoir characteristics account for the variations in gas content among coal, shale, and tight sandstone. The mineral composition of the rock formations in the study area primarily consists of quartz, feldspar, clay minerals, pyrite, calcite, and dolomite. By comparison, the coal samples from the four major coal seams in the study area exhibited relatively large pore sizes, which are favorable for gas accumulation.

Shale gas is considered a crucial global energy source. Hydraulic fracturing with multiple fractures in horizontal wells has been a crucial method for stimulating shale gas. During multi-stage fracturing, the fracture propagation is non-uniform, and fractures cannot be induced in some clusters due to the influence of stress shadow. To improve the multi-fracture propagation performance, technologies such as limited-entry fracturing are employed. However, perforation erosion limits the effect of the application of these technologies. In this paper, a two-dimensional numerical model that considers perforation erosion is established based on the finite element method. Then, the multi-fracture propagation, taking into account the impact of perforation erosion, is studied under different parameters. The results suggest that perforation erosion leads to a reduction in the perforation friction and exacerbates the uneven propagation of the fractures. The effects of erosion on multi-fracture propagation are heightened with a small perforation diameter and perforation number. However, reducing the perforation number and perforation diameter remains an effective method for promoting uniform fracture propagation. As the cluster spacing is increased, the effects of erosion on multi-fracture propagation are aggravated because of the weakened stress shadow effect. Furthermore, for a given volume of fracturing fluid, although a higher injection rate is associated with a shorter injection time, the effects of erosion on the multi-fracture propagation are more severe at a high injection rate.

Shale anisotropy has a significant impact on the data processing and interpretation of microseismic monitoring in shale gas reservoirs. A geology- and rock-physics-constrained approach to estimating shale anisotropy using down-hole microseismic data sets is proposed in this study and is applied to the case of Horn River shale. A priori knowledge of shale anisotropy is obtained by integrating geological analyses and rock physics studies. This knowledge serves as an important constraint when building the initial model, minimizing the uncertainties and evaluating the results. The application to Horn River shale shows that the optimized anisotropic velocity model reduces the time misfit by about 65% compared to the originally provided velocity model. As the relocated perforation shot indicates, the event locations are significantly improved. The results also show that a high fraction of clay mineral results in strong fabric anisotropy in the Fort Simpson formation, whereas the quartz-rich shale gas reservoirs (Muskwa and Otter Park formations) show weaker fabric anisotropy. The percentage of velocity anisotropy in Horn River shale can be up to 40%. The fabric anisotropy of shale derived from the downhole microseismic data set is comparable with that of laboratory experiments. This demonstrates that downhole microseismic monitoring, as a quasi in situ experiment, has the potential to contribute to a better understanding of subsurface anisotropy beyond the laboratory. In addition, microseismic measurements of shale anisotropy are conducted in the seismic frequency band and are thus more applicable for further seismic applications.

Recently, shale gas exploration of the Wufeng-Longmaxi formations (WF-LMX) in the Sichuan Basin has gradually stepped into deep to ultra-deep layers, but the pore types and characteristics of ultra-deep shale still remain unclear. In this study, the WF-LMX ultra-deep organic-rich shale samples in the Eastern Sichuan Basin were collected, and the types and development characteristics of shale pores were investigated by using high-resolution scanning electron microscopy (SEM). Our results showed that the pores of the WF-LMX ultra-deep shale reservoirs mainly included organic pores, mineral matrix pores (interparticle pores and intraparticle pores), and micro-fractures, which were dominated by organic pores, displaying oval, slit, and irregular shapes and a diameter of mainly 5–45 nm. Organic pores were poorly developed in primary organic matter (e.g., graptolite and radiolarian), while they were well developed in solid bitumen, being the most important nanopore type in shale. The pore development of ultra-deep shale was mainly controlled by the contents of organic matter and brittle minerals. Higher contents of organic matter and quartz are conducive to the development and preservation of organic pores, which are also favorable for ultra-deep shale gas exploration.

Quaternary shale gas resources are abundant in the world, but Quaternary shale contains a lot of pore water, which affects the enrichment of shale gas. At present, the controlling effect of pore water on gas enrichment in Quaternary shale is not clear. Taking the Quaternary shale of Qaidam Basin, China as an example, this paper systematically studies the characteristics of pore water in Quaternary shale through X-ray diffraction rock analysis, nuclear magnetic resonance, methane isothermal adsorption and other experiments, and reveals the controlling effect of pore water on shale gas enrichment. The results show that clay shale and silty shale are mainly developed in Quaternary shale. The clay shale is more hydrophilic, and water mainly exists in micropores and mesopores. Silty shale is less hydrophilic, and water mainly exists in mesopores and macropores. Pore water controls the formation of shale gas by the content of potassium and sodium ions, controls the adsorption of shale gas by occupying the adsorption point on the pore surface, controls the flow of shale gas by occupying the pore space, and controls the occurrence of shale gas by forming water film. Therefore, pore water has multiple controlling effects on shale gas enrichment. This achievement is significant in enriching shale gas geological theory and guide shale gas exploration.

After more than 10 years of exploration, development, research, and practical efforts, China has opened up new perspectives for the commercial exploitation of marine shale gas. While high shale gas production is a main driver for energy security and economic development in China, there have been few attempts to systemically scientific analysis the challenges, prospect, development strategies, and goals for shale gas. Here, we present a detailed comparison of the differences in shale gas between the Sichuan Basin and North America from multiple dimensions, explain how and to what extent recent advances have been made, discuss the current challenges, and provide strategies to deal with these challenges. We demonstrate that a total of 13 graptolite zones developed in the Wufeng–Longmaxi Formations, achieved by representative cores from 32 coring wells and 7 outcrop profiles, can establish the chronostratigraphic framework in the Sichuan Basin, which leads to the potential impact of high-quality reservoir distribution and shale gas production. Shale gas is still faced with the challenges of complex underground and surface conditions, low single-well EUR, and immature deep development engineering technology. To circumvent these issues, here, we propose several strategies, including sweet-spot optimization, low-cost drilling techniques, and efficient fracturing technologies. Our results strengthen the importance of adopting fundamental theoretical research and practical and feasible development goals to realize more commercial discoveries of shale gas of diverse types and higher growth of shale gas reserves and production.

The gas flow in shale reservoirs is controlled by gas desorption diffusion and multiple flow mechanisms in the shale matrix. The treatment of hydraulic fracturing injects a large amount of fracturing fluids into shale reservoirs, and the fracturing fluids can only be recovered by 30~70%. The remaining fracturing fluid invades the reservoir in the form of a water invasion layer. In this paper, by introducing the concept of a water invasion layer, the hydraulic fracture network is di-vided into three zones: major fracture, water invasion layer and stimulated reservoir volume (SRV). The mathematical model considering gas desorption, the water invasion layer and gas–water two-phase flow in a major fracture is established in the Laplace domain, and the semi-analytical solution method is developed. The new model is validated by a commercial simulator. A field case from WY shale gas reservoir in southwestern China is used to verify the utility of the model. Several key parameters of major fracture and SRV are interpreted. The gas–water two-phase flow model established in this paper provides theoretical guidance for fracturing effectiveness evaluation and an efficient development strategy of shale gas reservoirs.

Unconventional natural gas extraction presents numerous opportunities and risks for communities across the United States. To capture a portion of the revenue generated by the resource states tax unconventional natural gas development. While most states collect revenue via severance taxes, Pennsylvania took a novel approach and established an impact fee on the industry instead. Unlike severance taxes in other states, the fee is collected annually and distributed directly to municipalities. While reports show that municipalities use the funds to pay for critical infrastructure, no best practices on how to allocate the funds exist. Citing the literature on mineral resource extraction and infrastructure-led development in American communities, this study examined impact fee payments made to counties with unconventional natural gas wells. The study evaluated whether counties that used the funds to invest in infrastructure were better off in terms of employment and income than other shale-producing counties that did not. Panel fixed- and random-effects regressions suggested that no statistically significant employment or income effects existed. The results suggest that local infrastructural investments are not a successful way to overcome the resource curse issues identified in the literature.

Marine organic-rich shale is widely distributed in the Upper Ordovician Wufeng Formation (WF-F) and Silurian Longmaxi Formation (LMX-F), making it an important target for shale gas exploration and development. In order to clarify the paleoenvironment evolution characteristics and the effect of depositional environment on organic matter (OM) accumulation of the marine shale in the Wufeng and Longmaxi Formations, a series of geochemical and petrological experiments were carried out, including TOC, Rock-Eval pyrolysis, XRD, and major and trace element analyses. Research results show that based on the variation characteristics of TOC, mineral composition, and paleoenvironment evolution characteristics, four units can be identified from bottom to top: Wufeng Formation (WF-F), Lower Longmaxi Formation (L-LMX-F), Middle Longmaxi Formation (M-LMX-F) and Upper Longmaxi Formation (U-LMX-F). The high-quality marine shale developed in WF-F and LMX-F in the Zigong area (TOC: 0.65–4.56%, avg. 2.15%) contains type I kerogen (kerogen type index: 86.0–98.3, avg. 92.7) and OM in mature stage (average of Rb and Tmax are 2.94%, 646 °C, respectively). Clay minerals (avg. 42.5%) and quartz (avg. 37.7%) dominate the mineral compositions, with subordinated dolomite (avg. 6.3%), feldspar (avg. 6.0%), calcite (avg. 4.0%), and pyrite (avg. 3.5%). Paleoenvironment indicators suggest that during the sedimentary period of WF-F and L-LMX-F, the paleoclimate condition was humid; the weathering condition, paleosalinity, and redox conditions were the strongest; and there was a relatively high level of paleoproductivity and a relatively low level of terrigenous detritus influx. However, during the period of M-LMX-F and U-LMX-F, the climate gradually changed from warm and humid to hot and dry; the intensity of weathering conditions, paleosalinity, and redox conditions was relatively reduced; terrigenous detritus influx increased; and the paleoproductivity decreased. Relationships between TOC and paleoclimate condition, paleosalinity, redox condition, paleoproductivity, and terrigenous detritus influx suggest that redox condition is most important controlling factor for OM enrichment. A combination of anoxic bottom water conditions and high primary productivity and a relatively low terrigenous input resulted in the enrichment of OM in the WF-F and L-LMX-F, making it a potential exploration and development target. The research can provide scientific guidance for the selection of potential shale gas development targets in the Zigong area.

Reservoir characteristics and the occurrence mechanism of shale gas outside of the Sichuan Basin are the research hotspots of normally pressured shales in China. Taking shales on the Anchang syncline from the periphery of the Sichuan Basin as an example, X-ray diffraction, organic geochemistry, and rock physical experiments were carried out to analyze the reservoir characteristics and their main geological controls on the normally pressured shales. The mineralogical results show that the studied shales from the Anchang syncline are mainly siliceous shales with a high quartz content (average of 57%). The quartz content of these normally pressured shales is of biological origin, as shown by the positive correlation between the quartz and organic carbon (TOC) contents. The average porosity of the studied shales is about 2.9%, which is lower than shales inside the Sichuan Basin. Organic matter pores are likely the primary storage space of the normally pressured shale gas, as shown by the positive relationship between the TOC content and porosity. However, scanning electron microscopy observations on the studied shales show that the pores in these normally pressured shales are poorly preserved; many pores have been subjected to compression and deformation due to tectonic movements. Compared to shales inside the Sichuan Basin, the effective thickness of shales outside of the Sichuan Basin is thin and the stratum dip is large. Thus, shale gas outside of the Sichuan Basin is apt to escape laterally along the bedding of the strata. After losing a significant amount of shale gas, the gas pressure decreases to normal pressure, which makes it difficult for the pores to resist compaction from the overlying strata. This is probably why most shale gas reservoirs outside of the Sichuan Basin are normally pressured, while the shale strata inside the Sichuan Basin are commonly overpressured. This study provides insights to understand the pore development and hydrocarbon occurrence on normally pressured shales outside of the Sichuan Basin.

Gas reservoir numerical simulation is an important method to optimize the development strategy of shale gas reservoirs which has been influenced by the multi-stage fracture. The regular fracture network model was used to build a conventional numerical simulation, in which it was difficult to show the true situation of fracture propagation. However, the physical parameters not only affect the production, but also influence the stimulation effect; moreover, the quality of the fracturing effect also affects the production which causes the input and out parameters to be inaccurate. To solve this problem, the process simulation must be completed from geology to engineering to gas reservoir. The main controlling factors of production are identified with geological and engineering factors such as horizontal stage length, the volume of fracturing fluid, well spacing, production allocation, and proppant mass. Therefore, on the basis of the integrated simulation method of a hydraulic fracturing network simulation and an unstructured grid high-precision numerical simulation, this paper builds an integrated numerical simulation of a shale gas reservoir coupled with geology and engineering to optimize the development strategy with production as the target. Taking four wells of a platform as an example, the EUR (estimated ultimate recovery) has increased by 25% after the optimization of the development strategy.

The most significant geo-energy sources in the world today continue to be oil, gas, and geothermal reservoirs. To increase oil and gas reserves and production, new theories are constantly being developed in the laboratory and new technologies are being applied in the oilfield. This Special Issue compiles recent research focusing on cutting-edge ideas and technology in oil, gas, and geothermal reservoirs, covering the fields of well drilling, cementing, hydraulic fracturing, improved oil recovery, conformance control, and geothermal energy development.

Hydraulic fracturing of shale gas reservoirs is characterized by large fracturing fluid consumption, long working cycle and low flowback efficiency. Huge amounts of fracturing fluid retained in shale reservoirs for a long time would definitely cause formation damage and reduce the gas production efficiency. In this work, a pressure decay method was conducted in order to measure the amount of fracturing fluid imbibition and sample permeability under the conditions of formation temperature, pressure and adsorbed methane in real time. Experimental results show that (1) the mass of imbibed fracturing fluid per unit mass of shale sample is 0.00021–0.00439 g/g considering the in-situ pressure, temperature and adsorbed methane. (2) The imbibition and flowback behavior of fracturing fluid are affected by the imbibition or flowback pressure difference, pore structure, pore surface properties, mechanical properties of shale and mineral contents. (3) 0.01 mD and 0.001 mD are the critical initial permeability of shales, which could be used to determine the relationship between the formation damage degree and the flowback pressure difference. This work is beneficial for a real experimental evaluation of shale formation damage induced by fracturing fluid.

Shale gas reservoirs have huge amounts of reserves. Economically evaluating these reserves is challenging due to complex driving mechanisms, complex drilling and completion configurations, and the complexity of controlling the producing conditions. Decline Curve Analysis (DCA) is historically considered the easiest method for production prediction of unconventional reservoirs as it only requires production history. Besides uncertainties in selecting a suitable DCA model to match the production behavior of the shale gas wells, the production data are usually noisy because of the changing choke size used to control the bottom hole flowing pressure and the multiple shut-ins to remove the associated water. Removing this noise from the data is important for effective DCA prediction. In this study, 12 machine learning outlier detection algorithms were investigated to determine the one most suitable for improving the quality of production data. Five of them were found not suitable, as they remove complete portions of the production data rather than scattered data points. The other seven algorithms were deeply investigated, assuming that 20% of the production data are outliers. During the work, eight DCA models were studied and applied. Different recommendations were stated regarding their sensitivity to noise. The results showed that the clustered based outlier factor, k-nearest neighbor, and the angular based outlier factor algorithms are the most effective algorithms for improving the data quality for DCA, while the stochastic outlier selection and subspace outlier detection algorithms were found to be the least effective. Additionally, DCA models, such as the Arps, Duong, and Wang models, were found to be less sensitive to removing noise, even with different algorithms. Meanwhile, power law exponential, logistic growth model, and stretched exponent production decline models showed more sensitivity to removing the noise, with varying performance under different outlier-removal algorithms. This work introduces the best combination of DCA models and outlier-detection algorithms, which could be used to reduce the uncertainties related to production forecasting and reserve estimation of shale gas reservoirs.

Although almost all the shale gas in China is exploited from marine shale (Wufeng–Longmaxi Formation) in Sichuan Basin and several prolific wells, it has also been obtained in Jurassic lacustrine shale. However, the reservoir conditions of the lacustrine shale are not well understood, which has impeded a breakthrough regarding lacustrine shale gas in Sichuan Basin. To probe the reservoir conditions of the lacustrine shale in Sichuan Basin, we take the Wufeng–Longmaxi shale and Dongyuemiao shale sampled from wells and outcrops as examples. A series of experiments were conducted, including TOC, XRD, FE-SEM, N2 adsorption, Micro-CT, vitrinite reflectance and bitumen reflectance. The results show that the pores in marine shale are mainly composed of organic-matter-hosted pores (OM pores). However, in the lacustrine shale, the pores are mainly composed of dissolution pores and intergranular pores. The marine shale is characterized by small-caliber and large-volume pores in which cluster pores are levitated in the shale as kites and connected by past channels. However, in the lacustrine shale, the cluster pores and the past channels are mainly arranged according to the flow channels in the vertical direction. The arrangement of the pores in the marine shale is obviously deformed by compaction. The lacustrine shale is characterized by under-compaction. It can be deduced that the sweet spots for lacustrine shale gas are likely located at the areas characterized by under-compaction resulting from fluid pressure conducted upward, such as the hinge zone of syncline or the core of anticline overlap on the gas reservoirs.

Many sets of Paleozoic marine organic-rich shale strata have developed in South China. However, the exploration and development results of these shale formations are quite different. Based on the data of core experiment analysis, drilling, fracturing test of typical wells, the reservoir differences and controlling factors of four sets of typical marine organic-rich shale in southern China are investigated. The four sets of shale have obvious differences in reservoir characteristics. Ordovician–Silurian shale mainly develops siliceous shale, mixed shale and argillaceous shale, with large pore diameter, high porosity, moderate thermal maturity, large pore volume and specific surface area. Cambrian shale mainly develops siliceous shale and mixed shale, with small pore diameter, low porosity, high thermal maturity and smaller pore volume and specific surface area than Ordovician–Silurian shale. Devonian–Carboniferous shale has similar mineral composition to Ordovician–Silurian shale, with small pore diameter, low porosity, moderate thermal maturity and similar pore volume and specific surface area to that of Cambrian shale. Permian shale has very complex mineral composition, with large pore diameter, low to medium thermal maturity and small specific surface area. Mineral composition, thermal maturity and tectonic preservation conditions are the main factors controlling shale reservoir development. Siliceous minerals in Cambrian shale and Ordovician–Silurian shale are mainly of biological origin, which make the support capacity better than Devonian–Carboniferous shale and Permian shale (siliceous minerals are mainly of terrigenous origin and biological origin). Thermal maturity of Ordovician–Silurian shale and Devonian–Carboniferous shale is moderate, with a large number of organic pores developed. Thermal maturity of Cambrian shale and Permian shale is respectively too high and too low, the development of organic pores is significantly weaker than the two sets of shale above. There are obvious differences in tectonic preservation conditions inside and outside the Sichuan Basin. Shale reservoirs inside the Sichuan Basin are characterized by overpressure due to stable tectonic activities, while shale reservoirs outside the Sichuan Basin are generally normal–pressure. Four sets of marine shale in South China all have certain resource potentials, but the exploration and development of shale gas is still constrained by complicated geological conditions, single economic shale formation, high exploration and development costs and other aspects. It is necessary for further research on shale gas accumulation theory, exploration and development technology and related policies to promote the development of China’s shale gas industry.

To investigate the influence of flowback time and flowback difference on flowback behavior of shale fracturing fluid, we carried out the permeability test experiment of Longmaxi Formation shale under different flowback pressure gradients and analyzed the retention characteristics of water phase in shale pores and fractures after flowback by nuclear magnetic resonance (NMR) instrument. The results indicate that after flowback under the pressure gradient ranges of 0.06~0.18 MPa/cm, the content of retained water phase in shale samples ranges from 9.68% to 16.97% and the retention of fracturing fluid in shale does not decrease with the increase of flowback pressure difference. Additionally, increasing the flowback pressure difference will reduce the shale permeability damage rate, but the permeability damage rate is still above 80%. After the flowback, the water phase mainly stays in the pore space with D < 100 nm, especially in the pore space with 2~10 nm and 10~50 nm. It is extremely difficult for the water phase in the pores with D < 100 nm to flow back out. The experimental results show that the critical flowback pressure gradient for particle migration of rock powder in shale fracture surface is 0.09 MPa/cm. The research results have important guiding significance for shale gas well flowback.

The Luzhou area in the southern Sichuan Basin has experienced multiple tectonic movements, forming a complex fault system; the activity has an important impact on the enrichment of shale gas in this area. In order to reveal the influence of the fracture system on the differential enrichment of shale gas, this paper takes the southern Sichuan Basin as the research object. The structural evolution process and fracture development characteristics of the different tectonic units in Luzhou area of southern Sichuan were characterized by conducting a seismic profile analysis, structural recovery using a back-stripping method, and core hand specimen description. We clarified the control effect of the structural deformation and fracture on the differential enrichment of shale gas, and we established a differential enrichment model of shale gas in the Luzhou area. The results show that: (1) The Luzhou area has undergone the transformation of a multi-stage tectonic movement. There are many sets of detachment structures in the longitudinal direction, and the plane structural form is a thin-skin fold-thrust belt composed of wide and narrow anticlines in the north–south direction. (2) The faults in the study area are affected by the Himalayan tectonic movement. The high-angle reverse faults are developed, and the number of large faults is small. The second and third faults are mainly developed. The second faults are only developed at the high position of the structure, which has a significantly destructive effect on shale gas reservoirs, while the third and fourth faults have no significant destructive effect on shale gas reservoirs. (3) In the study area, the types of cracks are categorized into transformational shear cracks, bed-parallel shear cracks, intraformational open cracks, lamellation cracks, shrinkage cracks, and abnormal high-pressure cracks. The thickness of the shale rock mechanical layer, brittle mineral content, and organic matter content jointly control the crack development degree in the shale of the Wufeng–Longmaxi Formation. (4) The uplift erosion, structural deformation, and fracture development caused by the structural evolution have affected the preservation of shale gas, resulting in the differential enrichment of shale gas reservoirs in the region. Based on the enrichment factors of shale gas, we established a differential enrichment model of shale gas in typical structural units and optimized the favorable enrichment areas, which are important contributions for guiding shale gas exploration and development in the Sichuan Basin.

As a kind of clean energy, shale gas has attracted much attention, and the exploration and development potential of shale gas resources in the middle and deep layers is huge. However, due to the changeable geological and burial conditions, complex geophysical responses are formed. Therefore, studying the characteristics of reservoir rock minerals and their complex resistivity response characteristics is helpful to deepen the understanding of the electrical characteristics of shale gas reservoirs and provide theoretical basis and physical basis for exploration and development. The study is based on shale samples from the Longmaxi Formation to the Wufeng Formation of a shale gas well in southern Sichuan, China, and the mineral composition and complex resistivity of shale are measured. Through inversion of complex resistivity model, four IP parameters, namely zero-frequency resistivity, polarizability, time constant and frequency correlation coefficient, are extracted, and the relationship between mineral components of rock samples and IP parameters is analyzed. It is found that the polarizability gradually increases and the resistivity gradually decreases with the increase in borehole depth. With the increase in pyrite content, the polarization increases and the resistivity decreases. The corresponding relational model is established, and it is found that the polarizability is highly sensitive to the characteristic mineral pyrite, which provides more effective data support for the subsequent deep shale gas exploration.

The estimated ultimate recovery (EUR) of shale gas is an important index for evaluating the production capacity of horizontal wells. The Weiyuan shale gas field has wells with considerable EUR differentiation, which hinders the prediction of the production capacity of new wells. Accordingly, 121 wells with highly differentiated production are used for analysis. First, the main control factors of well production are identified via single-factor and multi-factor analyses, with the EUR set as the production capacity index. Subsequently, the key factors are selected to perform the multiple linear regression of EUR, accompanied by the developed method for well production prediction. The thickness and drilled length of Long 111 (Substratum 1 of Long 1 submember, Lower Silurian Longmaxi Formation) are demonstrated to have the uttermost effects on the well production, while several other factors also play important roles, including the fractured horizontal wellbore length, gas saturation, brittle mineral content, fracturing stage quantity, and proppant injection intensity. The multiple linear regression method can help accurately predict EUR, with errors of no more than 10%, in wells that have smooth production curves and are free of artificial interference, such as casing deformation, frac hit, and sudden change in production schemes. The results of this study are expected to provide certain guiding significances for shale gas development.

Inorganic nanopores occurring in the shale matrix have strong hydrophilicity and irreducible water (IW) film can be formed on the inner surface of the pores making gas flow mechanisms in the pores more complex. In this paper, the existence of irreducible water (IW) in inorganic pores is considered, and, based on the Knudsen number (Kn) correction in shale pores, a shale gas apparent permeability model of inorganic nano-pores is established. The effect of the Kn correction on the apparent permeability, the ratio of flow with pore radius and the effect of IW on the apparent permeability are assessed. The main conclusions are as follows: (1) at low pressure (less than 10 MPa) and for medium pore size (pore radius range of 10 nm–60 nm), the effect of the Kn correction should be considered; (2) considering the effect of the Kn correction, bulk phase transport replaces surface diffusion more slowly; considering the existence of IW, bulk phase transport replaces surface diffusion more slowly; (3) with increase in pressure, the IW effect on gas apparent permeability decreases. Under low pressure, the IW, where pore size is small, promotes fluid flow, while the IW in the large pores hinders fluid flow. In conditions of ultra-high pressure, the IW promotes gas flow.

Large thickness of shales over 180.0 m was developed in the source rocks of the Shahezi and Yingcheng formations in the Lishu Fault Depression. Moreover, the high amount of gas content and the total hydrocarbon value of gas logging in several boreholes illustrate that there is a great potential of shale gas resources in this region. Therefore, an integrated characterization of shales from the lower Cretaceous Shahezi and Yingcheng formations was provided to evaluate shale gas resources potential. The measurement results illustrated that the organic-rich shale samples with kerogen type Ⅱ during high to over thermal maturity had a higher content of brittle minerals (>50%) and clay mineral dominated by illite. The shales had a total porosity of 3.11–4.70%, a permeability of 1.24 × 10−3–1.52 × 10−3 μm2, and possessed pore types including dissolution pores, inter-layer pores of clay minerals, micro-fractures, intra-granular pores, and organic pores, which were dominated by micropores and mesopores (0.5–1.7 nm, 2.2–34.3 nm) with a significant contribution from OM and clay minerals. According to the N2 adsorption isotherms, the pore volume was comprised primarily of mesopores with mean widths of 4.314–6.989 nm, while the surface area was comprised primarily of micropores with widths in ranges of 0.5–0.8 nm and 1.0–1.7 nm. Thus, the shales have a suitable porosity and permeability, indicating that fine storage capacity and favorable gas flow capacity occur in the Shahezi and Yingcheng formations, which exhibit a good reservoir quality and excellent exploration potential since the considerable thickness of shales could form a closed reservoir and served as cap rocks for in situ gas generation and accumulation. Especially, according to the measured CH4 excess adsorption amount and the calculated maximum absolute adsorption capacities of CH4 based on the Langmuir adsorption model, the estimated GIP values (1.388–3.307 m3/t) of the shales happened to be in a sampling depth under geological hydrostatic pressure and temperature conditions. This means that the shale storage capacity and high gas content from well site desorption completely met the standard of industrial exploitation when synthetically considering the GIP model. As a consequence, shales in the Shahezi and Yingcheng formations in the Lishu Fault Depression could be potential targets for shale gas exploration.

The N2 adsorption experiment is one of the most important methods for characterizing the pore structure of shale, as it covers the major pore size range present in such sediments. The goal of this work is to better understand both the mechanisms and application of low-pressure nitrogen adsorption experiments in pore structure characterization. To achieve this, the N2 adsorption molecular simulation method, low-pressure N2 adsorption experiments, total organic carbon (TOC) analysis, X-ray diffraction (XRD) analysis, scanning electron microscopy (SEM), and a total of 196 shale samples from the Wufeng–Longmaxi formations in the Sichuan basin have been employed in this study. Based on the analytical data and the simulations, two parameters, the connectivity index and the large pore volume index, are proposed. These parameters are defined as the connectivity of the pore system and the volume of large nanopores (>10 nm) respectively, and they are calculated based on the N2 adsorption and desorption isotherms. The experimental results showed that TOC content and clay minerals are the key factors controlling surface area and pore volume. However, in different shale wells and different substrata (divided based on graptolite zonation), the relative influences of TOC content and clay minerals on pore structure differ. In three of the six wells, TOC content is the key factor controlling surface area and pore volume. In contrast, clay minerals in samples from the W202 well are the key factors controlling pore volume, and with an increase in the clay mineral content, the pore volume increases linearly. When the carbonate content exceeds 50%, the pore volume decreases with an increase in carbonate content, and this may be because in the diagenetic process, carbonate cement fills the pores. It is also found that with increasing TOC content the connectivity index increases and SEM images also illustrate that organic pores have better connectivity. Furthermore, the connectivity index increases as quartz content increases. The large pore volume index increases with quartz content from 0 to 40% and decreases as quartz increases from 40% to 100%. By comparing the pore structure of shale in the same substrata of different shale gas wells, it was found that tectonic location significantly affects the surface area and pore volume of shale samples. The shale samples from wells that are located in broad tectonic zones, far from large-scale faults and overpressure zones, have larger pore volumes and surface areas. On the contrary, the shale samples from shale gas wells that are located in the anticline region with strong tectonic extrusion zones or near large-scale faults have relatively low pore volumes and surface areas. By employing large numbers of shale samples and analyzing N2 adsorption mechanism in shale, this study has expanded the application of N2 adsorption experiment in shale and clarifies the effects of sedimentary factors and tectonic factors on pore structure.

Natural gas generation is the result of organic matter degradation under the effects of biodegradation and thermal degradation. Early Cambrian black shales in the Upper Yangtze Region are rich in organic matter and have shown great shale gas potentiality in recent years. Nevertheless, the enrichment mechanism and distribution of organic matter in these black shales between different sedimentary settings, such as intra-platform basin, slope, and deep basin, are still poorly understood. In this paper, based mainly on elemental geochemistry, a comprehensive study of the marine redox conditions, primary productivity, sedimentation rate, terrigenous input, hydrothermal activity, and water mass restrictions was conducted on the Early Cambrian Niutitang black shale in the Upper Yangtze Region. Our data showed that an intra-platform basin received a higher terrigenous input and that it deposited under more restricted conditions than the slope and deep basin settings. The primary productivity in the slope and deep basin settings was higher than that in the intra-platform basin setting. In the intra-platform basin, the productivity increased from its inner part to its margin. For the slope and deep basin settings, the high paleoproductivity generated large amounts of organic matter and its preservation was synergistically affected by the redox conditions. In contrast to the slope and deep basin, the preservation of organic matter in the inner part of the intra-platform basin was mainly controlled by redox conditions because the paleoproductivity in it was much lower than in the slope and deep basin settings. The intra-platform basin margin was the most favorable area for accumulating organic matter.

The Lower Paleozoic marine shale in southern China has undergone several strong tectonic transformations in an extensive region outside the Sichuan Basin. Although some shale strata underwent strong deformation, they still contain a significant amount of shale gas. The gas preservation mechanism in the strongly deformed shale has become the focus of attention. In this paper, the Lower Cambrian gas-bearing shale samples with a strong deformation taken from an exploration well in northern Chongqing, China, were investigated on their pore types and structure, with the aim to reveal the reason for the gas preservation. The pore types of the Lower Cambrian shale are dominated by microfractures and interparticle (interP) pores occurring mainly between clay minerals and between organic matter (OM) and clay minerals, while pores within OM that can be observed by FE-SEM (field emission-scanning electron microscopy) are rare. The shale has a low porosity, with an average of 1.56%, which is mainly controlled by the clay mineral content. The adsorption experiments of low pressure N2 (LPNA) and CO2 (LPCA) indicate that the shale is rich in micropores and small mesopores (

Recently, deep and ultra-deep shales (depth >3500 m) of the Lower Paleozoic Wufeng–Longmaxi formations (WF–LMX) have become attractive targets for shale gas exploration and development in China, and their gas contents may be influenced by the occurrence of water to some extent. However, the water content and its distribution in the different nanopores of the deep and ultra-deep shales have rarely been reported. In this study, a suite of the WF–LMX ultra-deep shale samples (5910–5965 m depth) from the Well PS1 was collected for water content measurements, and low-pressure CO2 and N2 adsorption experiments of both as-received and experimentally dried shale samples were carried out to investigate the distribution of water in the different nanopores. Since the studied ultra-deep shales are characterized by higher thermal maturity (equivalent vitrinite reflectance (EqVRo) > 2.5 %) and ultra-low water saturation, the pore water is generally dominated by irreducible water. The content of irreducible water of the studied shales varies from 1.57 to 13.66 mg/g, averaging 6.74 mg/g. Irreducible water may mainly occur in the clay-hosted pores, while it could also be hosted in parts of organic pores of organic-rich shales. Irreducible water is primarily distributed in non-micropores rather than in micropores of the studied shales, which mainly occurs in micopores with a diameter of 0.4–0.6 nm and mesopores with a diameter of 2–10 nm. Very low contents of irreducible water could reduce the specific surface area and volume of non-micropores of the shales to some extent, but the effect of irreducible water on the specific surface area of non-micropores was more significant than the volume of non-micropores, especially for organic-rich shale samples. The ultra-deep shale gas may be predominately composed of free gas, so low contents of irreducible water may play a limited role in its total gas contents. Overall, our findings can be helpful for a better understanding of water distribution in the highly-matured shales, and provide a scientific basis for ultra-deep shale gas exploration.

In recent years, big data and artificial intelligence technology have developed rapidly and are now widely used in fields of geophysics, well logging, and well test analysis in the exploration and development of oil and gas. The development of shale gas requires a large number of production wells, so big data and artificial intelligence technology have inherent advantages for evaluating the productivity of gas wells and analyzing the influencing factors for a whole development block. To this end, this paper combines the BP neural network algorithm with random probability analysis to establish a big data method for analyzing the influencing factors on the productivity of shale gas wells, using artificial intelligence and in-depth extraction of relevant information to reduce the unstable results from single-factor statistical analysis and the BP neural network. We have modeled and analyzed our model with a large amount of data. Under standard well conditions, the influences of geological and engineering factors on the productivity of a gas well can be converted to the same scale for comparison. This can more intuitively and quantitatively reflect the influences of different factors on gas well productivity. Taking 100 production wells in the Changning shale gas block as a case, random BP neural network analysis shows that maximum EUR can be obtained when a horizontal shale gas well has a fracture coefficient of 1.6, Type I reservoir of 18 m thick, optimal horizontal section of 1600 m long, and 20 fractured sections.

In the last decade, exploration for unconventional hydrocarbon (shale gas) reservoirs has been carried out in Poland. The drilling of wells in prospective shale gas areas supplies numerous physicochemical measurements from rock and reservoir fluid samples. The objective of this paper is to present the method that has been developed for finding similarities between individual geological structures in terms of their hydrocarbon generation properties and hydrocarbon resources. The measurements and geochemical investigations of six wells located in the Ordovician, Silurian, and Cambrian formations of the Polish part of the East European Platform are used. Cluster analysis is used to compare and classify objects described by multiple attributes. The focus is on the issue of generating clusters that group samples within the gas, condensate, and oil windows. The vitrinite reflectance value (Ro) is adopted as the criterion for classifying individual samples into the respective windows. An additional issue was determining other characteristic geochemical properties of the samples classified into the selected clusters. Two variants of cluster analysis are applied—the furthest neighbor method and Ward’s method—which resulted in 10 and 11 clusters, respectively. Particular attention was paid to the mean Ro values (within each cluster), allowing the classification of samples from a given cluster into one of the windows (gas, condensate, or oil). Using these methods, the samples were effectively classified into individual windows, and their percentage share within the Silurian, Ordovician, and Cambrian units is determined.

Due to the complex microscope pore structure of shale, large-scale hydraulic fracturing is required to achieve effective development, resulting in a very complicated fracturing fluid flowback characteristics. The flowback volume is time-dependent, whereas other relevant parameters, such as the permeability, porosity, and fracture half-length, are static. Thus, it is very difficult to build an end-to-end model to predict the time-dependent flowback curves using static parameters from a machine learning perspective. In order to simplify the time-dependent flowback curve into simple parameters and serve as the target parameter of big data analysis and flowback influencing factor analysis, this paper abstracted the flowback curve into two characteristic parameters, the daily flowback volume coefficient and the flowback decreasing coefficient, based on the analytical solution of the seepage equation of multistage fractured horizontal Wells. Taking the dynamic flowback data of 214 shale gas horizontal wells in Weiyuan shale gas block as a study case, the characteristic parameters of the flowback curves were obtained by exponential curve fittings. The analysis results showed that there is a positive correlation between the characteristic parameters which present the characteristics of right-skewed distribution. The calculation formula of the characteristic flowback coefficient representing the flowback potential was established. The correlations between characteristic flowback coefficient and geological and engineering parameters of 214 horizontal wells were studied by spearman correlation coefficient analysis method. The results showed that the characteristic flowback coefficient has a negative correlation with the thickness × drilling length of the high-quality reservoir, the fracturing stage interval, the number of fracturing stages, and the brittle minerals content. Through the method established in this paper, the shale gas flowback curve containing complex flow mechanism can be abstracted into simple characteristic parameters and characteristic coefficients, and the relationship between static data and dynamic data is established, which can help to establish a machine learning method for predicting the flowback curve of shale gas horizontal wells.

Shale reservoir heterogeneity is strong, which seriously affects shale gas reservoir evaluation and reserves estimation. The Longmaxi Formation shale of the Luzhou block in southern Sichuan was taken as an example to characterize the pore distribution of shale over the full scale using micro-computed tomography (CT), focusing on ion beam scanning electron microscopy (FIB-SEM) and small-angle neutron scattering (SANS); further, the heterogeneity of the shale pore distribution over the full scale was explored quantitatively within different scales. The results show that shale micropores are dominated by microfractures that are mainly developed along the bedding direction and associated with organic matter, contributing 1.24% of porosity. Shale nanopores are more developed, contributing 3.57–4.72% porosity and have strong heterogeneity locally at the microscale, but the pore distribution characteristics show lateral homogeneity and vertical heterogeneity at the macroscale. In the same layer, the porosity difference is only 0.1% for the sheet samples with 2 cm adjacent to each other. Therefore, in shale core experiments in which parallel samples are needed for comparison, parallel samples should be in the same bedding position. This paper explores the extent of heterogeneity over the full scale of pore distribution from macro to micro, which has important significance for accurately characterizing the pore distribution of shale and further carrying out reservoir evaluation and estimation of reserves.

Hydrofracturing, used for shale gas exploitation, may induce felt, even damaging earthquakes. On 15 June 2019, an Mw2.8 earthquake occurred, spatially correlated with the location of earlier exploratory hydrofracturing operations for shale gas in Wysin in Poland. However, this earthquake was atypical. Hydrofracturing-triggered seismicity mainly occurs during stimulation; occasionally, it continues a few months after completion of the stimulation. In Wysin, there were only two weaker events during two-month hydrofracturing and then 35 months of seismic silence until the mentioned earthquake occurred. The Wysin site is in Gdańsk Pomerania broader region, located on the very weakly seismically active Precambrian Platform. The historical documents, covering 1000 years, report no natural earthquakes in Gdańsk Pomerania. We conclude, therefore, that despite the never observed before that long lag time after stimulation, the Mw2.8 earthquake was triggered by hydrofracturing. It is possible that its unusually late occurrence in relation to the time of its triggering technological activity was caused by changes in stresses due to time-dependent deformation of reservoir shales. The Wysin earthquake determines a new time horizon for the effect of HF on the stress state, which can lead to triggering earthquakes. Time-dependent deformation and its induced stress changes should be considered in shall gas reservoir exploitation plans.

As an emerging unconventional energy resource, shale gas has great resource potential and developmental prospects. The effective evaluation of geological sweet spots (GSS), engineering sweet spots (ESS) and comprehensive sweet spots (CSS) is one of the main factors for a high-yield scale and economic production of shale gas. Sweet spot evaluation involves a comprehensive analysis based on multiple parameters. Conventional evaluation methods consider relatively simple or single factors. Although the main influencing factors are understood, the influence of different factors is as of yet unknown, and a comprehensive consideration may strongly affect the evaluation results. In this paper, the fuzzy mathematics method is introduced for shale gas sweet spot evaluation. With the help of fuzzy mathematics tools, such as membership function, the objective of comprehensive sweet spots evaluation based on multiple parameters is realized. Additionally, the reliability of the evaluation of sweet spots is improved. Firstly, previous research results are used for reference, and the evaluation factor system of geological and engineering sweet spots of shale gas is systematically analyzed and established. Then, the basic principle of the fuzzy comprehensive evaluation method is briefly introduced, and a geological engineering integrated shale gas sweet spots evaluation method, based on the fuzzy comprehensive evaluation method, is designed and implemented. Finally, the data from HB blocks in the Z shale gas field in China are adopted. According to the evaluation results, the modified method is tested. The results show that the method proposed in this paper can synthesize a number of evaluation indices, quickly and effectively evaluate the GSS, ESS and CSS in the target area, and the results have high rationality and accuracy, which can effectively assist in well-pattern deployment and fracture design.

In the Benxi Formation of the Carboniferous system of the Upper Paleozoic in the Ordos Basin, there are many sets of coal measures dark organic-rich shale, being marine continental transitional facies, with significant unconventional natural gas potential. Previous studies are only limited to the evaluation of tight sandstone reservoir in this set of strata, with no sufficient study on gas bearing and geological characteristics of organic-rich shale, restricting the exploration and evaluation of shale gas resources. In this study, analysis has been conducted on the organic carbon content, the major elements, the trace elements, and the mineral composition of core samples from the Benxi Formation in key drilling sections. In addition, qualitative and quantitative pore observation and characterization of core samples have been conducted. The sedimentary environments and reservoir characteristics of the shale of the Benxi Formation have been analyzed. Combined with the gas content analyzing the results of the field coring samples, the shale gas resource potentials of the Benxi Formation have been studied, and the geological characteristics of the Benxi Formation shale gas in the eastern Ordos Basin have been made clear, to provide a theoretical basis for shale gas resource evaluation of the Benxi Formation in the Ordos Basin. The results show that (1) in the Hutian Member, Pangou Member, and Jinci Member of the Benxi Formation, organic-rich shale is well developed, with the characteristics of seawater input as a whole. There is a slight difference in sedimentary redox index, which shows that the reducibility increases gradually from bottom to top. (2) There is an evident difference in the mineral characteristics of shale in these three members. The Hutian Member is rich in clay minerals, while the Jinci Member is high in quartz minerals. (3) The pores are mainly inorganic mineral intergranular pores, clay interlayer fractures, and micro fractures, and organic matter pores are developed on the surface of local organic matter. (4) The mud shale in the Jinci Member has a large cumulative thickness, has relatively high gas-bearing property, and is rich in brittle minerals. The Jinci Member is a favorable section for shale gas exploration of the Benxi Formation.

With the rapid development of computer science and technology, the Chinese petroleum industry has ushered in the era of big data. In this study, by collecting fracturing data from 303 horizontal wells in the Fuling Shale Gas Demonstration Area in China, a series of big data analysis studies was conducted using Pearson’s correlation coefficient, the unweighted pair group with arithmetic means method, and the graphical plate method to determine which is best. The fracturing parameters were determined through a series of big data analysis studies. The big data analysis process is divided into three main steps. The first is data preprocessing to screen out eligible, high-yielding wells. The second is a fracturing parameter correlation clustering analysis to determine the reasonableness of the parameters. The third is a big data panel method analysis of specific fracturing construction parameters to determine the optimal parameter range. The analyses revealed that the current amount of 100 mesh sand in the Fuling area is unreasonable; further, there are different preferred areas for different fracturing construction parameters. We have combined different fracturing parameter schemes by preferring areas. This analysis process is expected to provide new ideas regarding fracturing scheme design for engineers working on the frontline.

We propose three idealized hydraulic fracture geometries (“fracture scenarios”) likely to occur in shale oil reservoirs characterized by high pore pressure and low differential in situ stresses. We integrate these geometries into a commercial reservoir simulator (CMG-IMEX) and examine their effect on reservoir fluids production. Our first, reference fracture scenario includes only vertical, planar hydraulic fractures. The second scenario has stimulated vertical natural fractures oriented perpendicularly to the vertical hydraulic fractures. The third fracture scenario has stimulated horizontal bedding planes intersecting the vertical hydraulic fractures. This last scenario may occur in mudrock plays characterized by high pore pressure and transitional strike-slip to reverse faulting stress regimes. We demonstrate that the vertical and planar fractures are an oversimplification of the hydraulic fracture geometry in anisotropic shale plays. They fail to represent the stimulated volume geometric complexity in the reservoir simulations and may confuse hydrocarbon production forecast. We also show that stimulating mechanically weak bedding planes harms hydrocarbon production, while stimulated natural fractures may enhance initial production. Our findings reveal that stimulated horizontal bedding planes might decrease the cumulative hydrocarbon production by as much as 20%, and the initial hydrocarbon production by about 50% compared with the reference scenario. We present unique reservoir simulations that enable practical assessment of the impact of varied hydraulic fracture configurations on hydrocarbon production and highlight the importance of constraining present-day in situ stress state and pore pressure conditions to obtain a realistic hydrocarbon production forecast.

This study is predominantly about the differences in shale pore structure and the controlling factors of shale gas content between Lower Silurian and Lower Cambrian from the upper Yangtze plate, which are of great significance to the occurrence mechanism of shale gas. The field emission scanning electron microscopy combined with Particles (Pores) and Cracks Analysis System software, CO2/N2 adsorption and the high-pressure mercury injection porosimetry, and methane adsorption were used to investigate characteristics of overall shale pore structure and organic matter pore, heterogeneity and gas content of the Lower Paleozoic in southern Sichuan Basin and northern Guizhou province from the upper Yangtze plate. Results show that porosity and the development of organic matter pores of the Lower Silurian are better than that of the Lower Cambrian, and there are four main types of pore, including interparticle pore, intraparticle pore, organic matter pore and micro-fracture. The micropores of the Lower Cambrian shale provide major pore volume and specific surface areas. In the Lower Silurian shale, there are mesopores besides micropores. Fractal dimensions representing pore structure complexity and heterogeneity gradually increase with the increase in pore volume and specific surface areas. There is a significant positive linear relationship between total organic carbon content and micropores volume and specific surface areas of the Lower Paleozoic shale, and the correlation of the Lower Silurian is more obvious than that of the Lower Cambrian. The plane porosity of organic matter increases with the increase in total organic carbon when it is less than 5%. The plane porosity of organic matter pores is positively correlated with clay minerals content and negatively correlated with brittle minerals content. The adsorption gas content of Lower Silurian and Lower Cambrian shale are 1.51–3.86 m3/t (average, 2.31 m3/t) and 0.35–2.38 m3/t (average, 1.36 m3/t). Total organic carbon, clay minerals and porosity are the main controlling factors for the differences in shale gas content between Lower Cambrian and Lower Silurian from the upper Yangtze plate. Probability entropy and organic matter plane porosity of the Lower Silurian are higher than those of Lower Cambrian shale, but form factor and roundness is smaller.

The accurate determination of the gas in place in shale reservoirs is a basic but challenging issue for shale gas evaluation. Conventional canister gas desorption tests on retrieved core samples and subsequent data analyses (via linear or polynomial regression)—originally developed for coalbed methane, where gases are mainly stored in the adsorbed phase—is unadvisable for shale gas, which is stored as an appreciable amount of free gas in shale reservoirs. In the present study, a mathematical model that simultaneously takes into account gas expansion, adsorption/desorption, and the gas flow in shale is proposed to simulate gas release from a core sample retrieved from the Lower Silurian Longmaxi Formation of the Fuling shale gas field, Sichuan Basin. The results indicate that, compared with the value of 2.11 m3/t rock estimated with the traditional United States Bureau of Mines (USBM) method, the total gas in place within the studied Longmaxi Shale estimated with our mathematical model under reservoir pressure conditions is up to 5.88 m3/t rock, which is more consistent with the result from the new volumetric approach based on Ambrose et al. According to our mathematical model, the content of free gas is 4.11 m3/t rock at true “time zero”, which accounts for 69.9% of the total gas. On the other hand, the lost gas portion is determined to be up to 4.88 m3/t rock (~85% of the total gas). These results suggest that the majority of the free shale gas is actually trapped within the pore space of the shale formation.

Shale gas accumulates in reservoirs that have favorable characteristics and associated organic geochemistry. The Wufeng-Longmaxi formation of Well Yucan-6 in Southeast Chongqing, SW China was used as a representative example to analyze the organic geochemical and reservoir characteristics of various shale intervals. Total organic carbon (TOC), vitrinite reflectance (Ro), rock pyrolysis, scanning electron microscopy (SEM), and nitrogen adsorption analyses were conducted, and a vertical coupling variation law was established. Results showed the following: the Wufeng-Longmaxi formation shale contains kerogen types I and II2; the average TOC value at the bottom of the formation is 3.04% (and the average value overall is 0.78%); the average Ro value is 1.94%; the organic matter is in a post mature thermal evolutionary stage; the shale minerals are mainly quartz and clay; and the pores are mainly intergranular, intragranular dissolved pores, organic matter pores and micro fractures. In addition, the average specific surface area (BET) of the shale is 5.171 m2/g; micropores account for 4.46% of the total volume; the specific surface area reaches 14.6%; and mesopores and macropores are the main pore spaces. There is a positive correlation between TOC and the quartz content of Wufeng-Longmaxi shale, and porosity is positively correlated with the clay mineral content. It is known that organic pores and the specific area develop more favorably when the clay mineral content is higher because the adsorption capacity is enhanced. In addition, as shale with a high clay mineral content and high TOC content promotes the formation of a large number of nanopores, it has a strong adsorption capacity. Therefore, the most favorable interval for shale gas exploration and development in this well is the shale that has a high TOC content, high clay mineral content, and a suitable quartz content. The findings of this study can help to better identify shale reservoirs and predict the sweet point in shale gas exploration and development.

The effect of clay minerals on the methane adsorption capacity of shales is a basic issue that needs to be clarified and is of great significance for understanding the adsorption characteristics and mechanisms of shale gas. In this study, a variety of experimental methods, including XRD, LTNA, HPMA experiments, were conducted on 82 marine shale samples from the Wufeng–Longmaxi Formation of 10 evaluation wells in the southern Sichuan Basin of China. The controlling factors of adsorption capacities were determined through a correlation analysis with pore characteristics and mineral composition. In terms of mineral composition, organic matter (OM) is the most key methane adsorbent in marine shale, and clay minerals have little effect on methane adsorption. The ultra-low adsorption capacity of illite and chlorite and the hydrophilicity and water absorption ability of clay minerals are the main reasons for their limited effect on gas adsorption in marine shales. From the perspective of the pore structure, the micropore and mesopore specific surface areas (SSAs) control the methane adsorption capacity of marine shales, which are mainly provided by OM. Clay minerals have no relationship with SSAs, regardless of mesopores or micropores. In the competitive adsorption process of OM and clay minerals, OM has an absolute advantage. Clay minerals become carriers for water absorption, due to their interlayer polarity and water wettability. Based on the analysis of a large number of experimental datasets, this study clarified the key problem of whether clay minerals in marine shales control methane adsorption.

Estimation and correct determination of vitrinite equivalent reflectance in rock is crucial for the assessment of the source rock in both conventional and unconventional hydrocarbon deposits. These parameters can be determined in laboratories on rock samples. Laboratory measurements provide only point information. However, the use of well logs could overcome discontinuities in the data and provide parameters throughout a study interval. Attention has been paid to the estimation of TOC based on well logs. Vitrinite equivalent reflectance estimation is less well discussed and most papers reported cases with high TOC content in analyzed deposits. In this paper, the estimation of improved Ro is presented using a calculated maturity indicator with well logs. As the organic matter content is not high, additional steps were required for the calculation. To improve the quality of the fit and to find similar intervals, the data were grouped using cluster and neural network analysis. The next step was to use the resistivity log to improve the obtained maturity indicator. Due to the changing properties of kerogen with the type and degree of thermal maturity, this approach turned out to be reliable. The use of resistivity significantly increased the correlation coefficient and reduced errors. The method was tested on two wells with different type and maturity of kerogen. The obtained results are satisfactory, which makes it possible to use the method even in formations with a low organic matter content.

Several approaches have been applied for the evaluation of formation organic content. For further developments in the interpretation of organic richness, this research proposes a multivariate statistical method for exploring the interdependencies between the well logs and model parameters. A factor analysis-based approach is presented for the quantitative determination of total organic content of shale formations. Uncorrelated factors are extracted from well logging data using Jöreskog’s algorithm, and then the factor logs are correlated with estimated petrophysical properties. Whereas the first factor holds information on the amount of shaliness, the second is identified as an organic factor. The estimation method is applied both to synthetic and real datasets from different reservoir types and geologic basins, i.e., Derecske Trough in East Hungary (tight gas); Kingak formation in North Slope Alaska, United States of America (shale gas); and shale source rock formations in the Norwegian continental shelf. The estimated total organic content logs are verified by core data and/or results from other indirect estimation methods such as interval inversion, artificial neural networks and cluster analysis. The presented statistical method used for the interpretation of wireline logs offers an effective tool for the evaluation of organic matter content in unconventional reservoirs.

Complex geology and fracturing operations have led to frequent sand production problem in the shale gas well. Sand production brings huge engineering risks and seriously affects the normal production of the shale gas well. In order to study the property and source of the yielded sand, sand samples in three production periods of flowback, production test and gas production are collected from Sichuan Basin of China. Combining the methods of particle size analysis, microscope observation, scanning electron microscope, CT scanning, infrared spectroscopy and energy dispersive spectrum analysis, the multi-scale structure and composition characteristics of the yielded sand from different production periods were investigated. Results show that the sand size is the largest in the production test period and the smallest in the gas production period. The large-size sand is blocky in the flowback period, while it is flaky in the period of production test and gas production. The roundness of sand becomes worse as the sand size decreasing. Sand composition has the characteristics of fracturing proppant and shale mineral. Cementing material between large-size sands has the network structure and the higher content of aluminum and iron. Organic chemicals are found to be adhered to the sand surface in all three periods. Both shale fracture and proppant failure can generate particles that provide the material source for sand production. This research provides the source of the yielded sand and a theoretical guidance for the sand production mechanism.

Pores of shale exhibit multiscale characteristics, and pore characterization is challenging due to the complexity of pore systems. Currently, research is focused on nano-submicron pores, but the structure of micrometer-scaled pores is not well understood. In this research, an investigation of the three-dimensional pore network of the Chang 7 shale in the Ordos Basin of China was conducted, in order to provide an insight into the full characteristics of pore systems. Nano-CT and micro-CT scanning technology was used to comprehensively delineate the pore structure at different scales, for further understanding the gas storage mechanism in shale rocks. Results show that the radius of micro-scale pores ranges from 1 to 15 μm, with an average of 2.8 μm, and pores with radii of 1–5 μm occupy approximately 90% of all the pores. For the nano-scale pores, the size ranges from 86 to 2679 nm, with an average of 152 nm, yet it has a rather concentrated distribution within 300 nm. The nano-scale pores constitute most of the pore amount in the shale, whereas the micro-scale pores constitute most of the pore volumes. Moreover, the results show that more than 70% of nano-scale pores in the Chang 7 shale are isolated pores, indicating that pore bodies formed in the shale reservoir have poor connectivity. Positive linear relationships between pore sizes and the number of pore throats at the micro-scale and nano-scale were both obtained, suggesting that larger pores tend to have better connectivity than smaller pores.