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The article presents an analysis of the use of Facebook on the over 400-day-long anti-fracking protest by farmers in the village of Żurawlów in Poland against the global corporation Chevron. Analysis of this case study was used to discuss the deliberative potential of social media and their power in countering hegemonic discourse and providing visibility in the public sphere to actors and arguments marginalized or excluded by the traditional media. The results discuss Facebook's potential for mobilizing and providing identity while emphasizing the problem of visibility in the public sphere, which was key to the inclusion of discourse in public debate. Harnessing emotions and legitimizing minority interests helped create counter-power, while polarization and “homophile acts” against deliberation geared toward arriving at an agreement.

Recent observations of shale gas breakthroughs in the Weiyuan marine shale gas play in the Sichuan Basin have attracted great interest. To better understand these breakthroughs, we have used core description, cyro-focused ion beam scanning electron microscopy data, X-ray diffraction data, organic geochemistry, and well-logging data to better understand the reservoir characteristics carbonaceous shale, calcareous shale, and siliceous shale lithology, with a focus on organic-rich shale units. We find that conventional well-log methods are effective in mapping the spatial distribution of organic-rich shale in the Weiyuan area where the total organic carbon (TOC) content in the Longmaxi Formation ranges from 1.35% to 6.95%, averaging 4.42%. The kerogen is type I-II, and the vitrinite reflectance (Ro) is greater than 2.57%, which indicates that the formation is susceptible to shale gas accumulation. The clay mineral content ranges from 48 to 63 wt% (avg. 51 wt%) with illite and chlorite averaging 73.8% and 25.7%, respectively. The brittle mineral quartz and plagioclase content ranges from 32 to 61 wt% (avg. 47 wt%). Compared to the surrounding lithologic units, the marine shale exhibits relatively high gamma ray, neutron, sonic, resistivity, potassium, and uranium (U) values and relatively low density, photoelectric effect, and thorium/U values, allowing us to construct crossplots to define the units of interest. Using the same process, we quantify the TOC content providing a spatial distribution of organic-rich shale using conventional well logging.

Understanding the pore system and the geological factors controlling the adsorption of gas in mudstones and shales is a key element in predicting the gas accumulation potential of an unconventional reservoir. A series of integrated methods, including basic geochemistry, X-ray diffraction, scanning electron microscopy, low-pressure gas (CO2 and Ar) physisorption, and high-pressure methane adsorption were performed on a set of mudstones from the Triassic Yanchang Formation in Ordos Basin, to characterize the pore system and gas adsorption capacity and their geological controlling factors. The results show that the studied Yanchang Mudstones are mainly siliceous rocks with high total organic carbon concentration (average of 7.63%) and low to moderate thermal maturity (vitrinite reflectance of 0.55–0.92 %). The microscopic visible pores are mainly intergranular pores between organic matter and rigid mineral grains, while organic matter pores are less well-developed. The pore volume is mainly contained in micropores (diameter

The estimate ultimate recovery (EUR) of shale gas in individual well is affected by many factors so that it is difficult to predict accurately. Data-driven methods based on geological and engineering parameters are currently one of the mainstream methods for predicting EUR. However, the importance of early data from gas wells is often overlooked. Therefore, this research set out to use early data, including production and flowback rate data, to develop machine learning models. With the ability to analyze the data by machine learning, the controlling factors on EUR have been analyzed quantitatively. Four schemes have been designed to develop the model, and various machine learning techniques (K-Nearest Neighbor (KNN), Support Vector Machine (SVM), Random Forest (RF), Gradient Boosting Decision Tree (GBDT)) were applied to process the complex patterns in the data. The results show that, except 30-day flowback rate, the most important factor for EUR is the early production data. The relationship between the early flowback rate and EUR is poor. It is not enough to predict EUR accurately provided that only using the flowback rate data. Good prediction results have been obtained by choosing the most important factors. Among the four algorithms, SVM is considered to be the most reliable model because it is suitable for small data sets and performs well in dealing with nonlinear relationships between variables. The mean absolute percentage error is 13.41% in the test set 49 wells, which can be used as the optimal algorithm for EUR prediction only based on early data.

In contrast to the widely used sequence stratigraphic models for passive continental margins, the stacking patterns of strata within epeiric seas, which are influenced by regional tectonic activity, may display opposing characteristics during the same geological period. These variations serve as a record of basin evolution and also affect the accumulation of hydrocarbons within the strata. Our study investigated the development potential of the deep Longmaxi Shale in the southern Sichuan Basin by examining the sequence stratigraphy and sedimentary fill patterns. Using a combination of core observation, well-logging data analysis, and 3D seismic profile interpretation, we aimed to gain an understanding of the sedimentary fill history of the Longmaxi Shale during the Early Silurian. Our analysis revealed that deglaciation and regional tectonic events affected the sequence stratigraphy, resulting in unconformities that were identifiable using seismic data and wireline logs. Through an analysis of thirty wireline logs and two seismic profiles, we identified two third-order sequences suggested in the Lower Longmaxi Formation. Within the two third-order sequences were five systems tracts, with the first exhibiting a complete cycle of sea-level change and the second cycle being incomplete due to regional tectonic events. The graptolite succession on the upper Yangtze Platform provided a temporal view of the sequence stratigraphy and sedimentation rates of the Longmaxi Shale. The thickness trends of the systems tracts reflected the interplay of short-term eustasy fluctuations, subsidence, and uplift. Our analysis suggests that regional subsidence played a significant role in the deposition of the second transgressive systems tract (TST) in the Weiyuan and Luzhou areas, which represents a promising target for shale gas exploration, in addition to the first TST. However, the Changning area experienced a relative sea-level decrease due to the intense uplift of the Qianzhogn Paleo-uplift and the increased supply of sediment and is interpreted as a highstand systems tract (HST); it is not considered to have shale gas exploration potential.

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.

Horizontal wells’ multi-section and multi-cluster hydraulic fracturing plays an important role in the efficient development of shale gas. However, the influence of the perforating hole and natural fracture dip angle on the process of hydraulic fracture initiation and propagation has been ignored in the current researches. This paper presents the results related to a tri-axial large-scale hydraulic fracturing experiment under different natural fracture parameters. We discuss the experimental results relating to the near-wellbore tortuosity propagation of hydraulic fractures. Experimental results showed that the triaxial principal stress of the experimental sample was deflected by the natural fracture, which caused significant near-wellbore tortuosity propagation of the hydraulic fractures. The fractures in most rock samples were not perpendicular to the minimum horizontal principal stress after the experiment. As well, the deflection degree of triaxial principal stress direction and the probability of hydraulic fractures near-wellbore tortuosity propagation decreased with the increase of the natural fracture dip angle. After hydraulic fractures’ tortuous propagation, the hydraulic fractures will propagate in the direction controlled by the triaxial stress in the far-wellbore area. For reservoirs with natural fractures, proppant in hydraulic fracturing should be added after the fractures are fully expanded to prevent sand plugging in tortuous fractures. When the permeability of natural fractures is low, the volume of fracturing fluid entering natural fractures is small, and hydraulic fractures are easy to pass through the natural fractures.

Shale gas has a permeability of

Multi-stage fracturing of horizontal wells is an indispensable technology to create complex fracture networks, which can unlock production potential and enable commercial productivity for shale gas with low porosity and permeability. Real-time monitoring of fracture networks is essential for adjusting key parameters, mitigating fracturing risks, and achieving optimal fracturing effects. Micro-seismic monitoring technology accurately captures and describes the development of fracture networks by detecting micro-seismic waves generated through rock ruptures, providing valuable insights into the evaluation of post-fracturing. In this study, we first introduced the basic parameters of well X that were obtained by laboratory experiments and logging interpretation, including porosity, gas-bearing properties, mineral composition, rock mechanics, and crustal stress. Then, the hydraulic fracturing scheme was designed on the basis of the geological engineering characteristics of well X. Finally, we conducted a comprehensive analysis of various factors that can affect hydraulic fracturing. This included an examination of the impact of pre-fluid temporary plugging and fracture complexity on the overall effectiveness of the operation. Based on the laboratory experiments and theoretical analysis, the following conclusions can be drawn: (1) fracture size is essentially formed when the fluid strength exceeds 35 m3/m; (2) both preflush with high viscosity and the amount of power sand exceeding 20 cubic meters are conducive to the propagation of fracture height; (3) temporary plugging balls facilitate the balanced propagation of multiple fracture clusters within a stage, whereas temporary plugging particles promote the formation of complex fractures; and (4) geological conditions are a prerequisite for creating a complex network of fractures, and only engineering techniques can facilitate the appropriate enhancement of fracture complexity. This study provides an essential method for the fracturing design of shale gas.

The entire process of shale gas generation, migration, and accumulation involves the diffusion of shale gas, and it is impossible to disregard the harm that gas diffusion does to gas reservoirs. The research object for this paper is the Longmaxi Formation shale gas reservoir in the Weiyuan area of the Sichuan Basin. Based on Fick’s diffusion law, an innovative mathematical model of shale gas diffusion is established, and it is clarified that the diffusion amount mainly depends on the free gas content and the diffusion coefficient. Based on the theory of fluid dynamics, the calculation equation of formation paleo-pressure is innovatively deduced. The equation fully considers gas migration, temperature and pressure changes, and the pressure control effect of organic matter gas generation, and restores the evolution history of free gas content in the reservoir. The evolution process of temperature, pressure and stratigraphic physical properties in the study area is the first to calculate the diffusion evolution history and cumulative diffusion amount of shale gas reservoirs in the study area, the reliability of the calculation results is verified by geochemical parameters. Studies have revealed that the existing Longmaxi Formation shale in the Weiyuan area of Sichuan Basin varies from 14.10 to 16.50 × 104 m3/m2 per unit area, with an average diffusion loss of 0.30 × 1012 m3 gas in the positive part and 0.30 × 1012 m3 in the negative part. The total lost gas accounts for around 1.72 times the present recappable reserves and is estimated to be 0.43 × 1012 m3 in volume. It is clear that the migration and accumulation of natural gas are significantly influenced by the research of diffusion loss.

This study presents a comprehensive material balance equation (MBE) to estimate the reserve of shale gas reservoirs including free and adsorbed gas volume. The presented material balance equation takes into account the effect of stress change, matrix shrinkage, water volume production and influx, and critical desorption pressure. The material balance equation is converted into a linear relationship between the reservoir production and expansion parameters used during the derivation procedures that include rock-fluid properties and production history data. The proposed straight line reserve evaluation technique yields a slope of original free and absorbed gas in organic matrix, while the y-intercept yields the volume of original free gas in the in-organic matrix. A field case study of shale gas located in Australia is presented. Results show that the proposed MBE and the corresponding straight line reserve evaluation technique are rational and competent in estimating the free gas and adsorbed gas volumes accurately with error less than 6% compared to the numerical simulation model presented in this study using an in-house simulator based on finite element technique and FORTRAN language. Hence, the presented technique in this study can be used as a quick and easy to use tool to accurately estimate the free and adsorbed gas reserves and to improve the development of the production strategies 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.

This dissertation examines a major policy change in the context of energy decision-making for shale gas development in the province of New Brunswick, Canada. After a long series of public engagement exercises aimed at regulating and promoting the safe development of shale gas resources in New Brunswick, the provincial government implemented a moratorium on hydraulic fracturing in 2014 and extended it indefinitely in 2016. The dissertation is interested in how policy-oriented learning may have influenced this policy change from both an empirical and a theoretical perspective. Theoretically, in line with recent scholarship on policy learning, this study trains its sites on the nature of policy learning and how it may influence change. To this end, the dissertation is grounded in the Advocacy Coalition Framework (ACF), a theoretical approach with (i) clearly defined mechanisms of learning, and (ii) significant application to resource development and to case studies of resource development in jurisdictions across North America and globally. The study builds on the ACF by proposing a conception of learning drawing on post-positivist literature. The study argues that learning is too narrowly focused on policy elites in the ACF and should be expanded to consider the role of non-traditional actors. The analysis questions the notion that learning can be isolated to rational and technical understandings amongst policy elites, and aims to integrate interactive knowledge into the analysis as a fundamental component of learning. The research aims to contextualize learning and understand the factors that shape policy learning and policy change. The dissertation focuses on the role of three factors - public engagement, uncertainty and trust - in shaping policy actors' learning. Empirically, the study examines the case of New Brunswick between 2007 and 2017. The province undertook multiple public engagement exercises regarding shale gas development in the context of unknown risks and uncertainty associated with the practice of hydraulic fracturing, an emerging technology that enabled the production of shale gas on a large scale. Two major coalitions emerged that advocated for and against shale development in the province, with the dominant pro-development coalition asserting that shale gas could proceed safely through stringent regulation. Through documentary analysis, interviews and a media analysis, the research reveals that interactive knowledge was a key component of how people learned in the case. The anti-shale coalition in New Brunswick brought its lived experience - notably its lack of trust in public authorities to successfully regulate fracking - to bear on decision-making, and was able to undermine and question the pro-development coalition's position that the risks associated with hydraulic fracturing could be managed. The anti-shale coalition mobilized this knowledge through the government's public engagement exercises and successfully contested the dominant coalition's beliefs. Fundamentally, the study demonstrates that public engagement, uncertainty and trust are three key factors that can shape policy learning and change.

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.

In the Yan’an area of the Ordos Basin, the lithological heterogeneity of Chang 7 Member shale is extremely strong. In addition, sandy laminae is highly developed within the Chang 7 Member shale system. In order to explore the gas generation and migration processes of Chang 7 Member shale, geochemical characteristics of desorption gas are comprehensively compared and analyzed. In this study, rock crushing experiments were carried out to obtain shale samples, and desorption experiments were carried out to obtain shale samples and sandy laminated shale samples. For the crushing gas and desorption gas, the volume contents of different gas components were obtained using gas chromatography experiments. The rock crushing experiments revealed that the average volume percentage of CH4 in Chang 7 Member shale is 61.93%, the average volume percentage of C2H6 and C3H8 is 29.53%, and the average volume percentage of other gases is relatively small. The shale gas in Chang 7 Member is wet gas; the gas is kerogen pyrolysis gas. Most of the shale gas hosting in Chang 7 Member shale is adsorbed gas. Porosity, permeability and organic matter content are the main geological factors controlling gas migration and gas hosting. Shale with a higher porosity, good permeability and a low organic matter content is conducive to gas migration. The shale gas in Chang 7 Member shale contains CH4, C2H6, C3H8, iC4H10, nC4H10, iC5H12, nC5H12, CO2 and N2. N2 migrates more easily than CH4, and CH4 migrates more easily than CO2. For hydrocarbon gases, gas components with small molecular diameters are easier to migrate. The desorption characteristics of shale might provide clues for guiding hydrocarbon exploration in the study area. The sandy laminated shale with a higher gas content may be the “sweet spot” of shale gas targets. In Chang 7 Member, the locations hosting both shale oil and CH4 may be the most favorable targets for shale oil production.

With the advancement of technology and innovation in the oil and gas industry, the production of liquid and gaseous hydrocarbon from conventional and unconventional resources has seen exponential growth. Recently, the USA and other oil giants have shifted their paradigm from conventional to unconventional resources of exploration and production of hydrocarbon. However, there is still a perpetual force that exists to develop and devise new innovative approaches and methodologies for the exploration, extraction efficiencies, and production performance of hydrocarbons. To better evaluate the impact of well attributes, reservoir characteristics and production behavior of well machine learning and artificial intelligence-based models have been developed by researchers that with the help of simulation and modeling provide us the true picture of reservoir performance without exploring and investing billions of dollars. This review paper encompasses the literature published in the recent years and narrated the recent development made by researchers especially in the field of production performance estimation of shale gas by developing machine learning-based models. More specifically, this paper deals with the major shale gas reservoir of North America including Marcellus shale, Eagle Ford shale, and Bakken Shale. Additionally, equations, input parameters, and formations that are considered key parameters for the development of the smart shale gas models are also discussed in this manuscript. In addition, the methodology comparison of different machine learning algorithms including their limitations and advantages are also presented.

The Shanxi Formation (Shan 1 and Shan 2 Members) shales show good prospects in shale gas development in the Yan'an area of Ordos Basin. Based on the simulation experiment of hydrocarbon generation of low maturity shale samples, the hydrocarbon generation characteristics of shale samples was studied systematically. Then, combined with the geochemical analysis of shale and gas generation simulation, shale gas potential was evaluated. The results reveal that Shan 1 and Shan 2 shale samples are favorable for shale gas enrichment by and large, with C1–C5 maximum yields of 146.96–160.83 mg/g TOC and 148.48–148.67 mg/g TOC respectively at a heat rate of 20 °C/h and 2 °C/h. The Shan 1 and Shan 2 shales are basically the same in terms of organic carbon production potential of each unit. The carbon isotopic composition of alkane gas reveals that heteroatomic compounds (NSOs) cracking is an important mechanism for shale gas generation of Shanxi Formation shales, and conducive to gas generation at high-to over-mature stages. Given thermal history and kinetic parameters of hydrocarbon generation, the shales of Shanxi Formation reached the maximum gas production potential in the Late Cretaceous, with a maximum yield of 160.3 mg/g TOC under present geological conditions. During geological history, the Shanxi Formation shales went through high-to over-maturity evolution, mainly producing dry gas, and their gas generation capacity was controlled by the organic matter abundance and cracking capacity. The gas generation potential of Shan 2 shale is higher than that of Shan 1, due to its higher TOC.

Hydraulic fracturing is one of the common stimulation technologies which is used for shale gas or oil production. But the use of conventional hydro- fracturing has lot of drawbacks including water scarcity and environmental disaster, clay swelling, wellbore instability, etc. This paper discusses CO2 fracturing treatment in shale formation as an alternative of water base fracturing in shale reservoirs. The paper also includes history of CO2 fracturing, and a detailed study about the different parameters of the shales which control the fracturing performance. A key focus of the study is to understand about the CO2– shale interaction. As supercritical CO2 (SCO2) has benefits for the effectiveness of gas production from the shale reservoirs for reduction of environmental footprint.

Cyclic thermal impact technology can effectively modify shale reservoirs and improve reservoir fracture networks while removing water phase traps to increase shale gas permeability. Therefore, an experiment on the cyclic thermal impacts of shale was conducted to investigate the alteration of pore structure and permeability of shale before and after cyclic thermal impacts. The results indicated that, under the thermal impact temperature of 300 °C, pores were continuously generated and expanded in the shale. With the increase in thermal impacts, the cumulative porosity of shale gradually increases, and the growth trend is a logarithmic function of the number of thermal impacts. The permeability of shale can be increased effectively through cyclic thermal impacts, and it increases logarithmically with the number of thermal impacts indicates the importance of multiple injection heat treatments in the process of improving the permeability of shale reservoirs.

Hydrogeochemical processes occurring in contaminated groundwater and aquifer systems may reduce the sensitivity of boron isotopes as an indicator of hydraulic fracturing flowback fluids (HFFF) in groundwater. In this paper, based on the Chaiye-1 well (the first continental shale gas well in the northern Qaidam Basin), the hydrogeochemical processes affecting boron isotopes were analyzed in HFFF-contaminated Neogene (NG1 and NG2) and Quaternary (QG1) groundwater around the shale gas field. Then, a model for boron isotopes in HFFF-contaminated groundwater was constructed to assess the sensitivity of boron isotopes as an HFFF indicator. The results show that, limited by the range of pH values and saturation indices (SI) in HFFF-contaminated groundwater, the dissolution of alkali feldspar and precipitation of carbonate have little effect on the boron isotopes in shallow groundwater. For the NG2 aquifer system containing clay minerals, the δ11B of simulated contaminated groundwater (40.0–55.6‰) is always higher than that of the corresponding groundwater mixed conservatively (−6.4–55.6‰) due to preferential adsorption of boron isotopes onto clay minerals, indicating preferential adsorption would reduce the sensitivity of boron isotopes as an indicator of groundwater contamination from HFFF. For the scenario of HFFF contamination, when the mixing ratio of HFFF in contaminated groundwater increases by 5%, boron isotopes in Neogene (NG1 and NG2) and Quaternary (QG1) groundwater have detectable responses to HFFF contamination, suggesting δ11B is a sensitive indicator of HFFF contamination in shallow groundwater from the Dameigou Shale in the northern Qaidam Basin.

O controle dos recursos energéticos é um elemento importante das disputas geopolíticas entre os Estados. Nesse contexto, o objetivo deste artigo é demonstrar que a política dos Estados Unidos relativa à exploração do gás de xisto se insere no contexto da questão estratégica da segurança energética daquele país, em um cenário de transição hegemônica. Para alcançar esse objetivo, é necessário i) descrever a relação entre a hegemonia dos Estados Unidos e o regime energético do petróleo; ii) compreender a matriz energética americana e o papel da exploração do gás de xisto na atual conjuntura global. El control de los recursos energéticos es un elemento importante de las disputas geopolíticas entre los Estados. En este contexto, el objetivo del artículo es demostrar que la política de Estados Unidos relativa a la exploración del gas de lutita se encuentra en el contexto de la cuestión estratégica de la seguridad energética de aquel país, en un escenario de transición hegemónica. Para lograr el objetivo es necesario: i) describir la relación entre la hegemonía de Estados Unidos y el régimen energético del petróleo; ii) comprender la matriz energética americana y el rol de la exploración del gas de lutita en la actual coyuntura global. The control of energy resources is an important aspect within the geopolitical disputes between States. In this context, the purpose of this paper is to show that the US policy on shale gas exploration lies within the context of the country's strategic issue of energy security. To achieve this aim it is necessary to: i) describe the relationship between the hegemony of the United States and the petroleum energy regime; ii) understand the American energy matrix and the role of shale gas exploration in the current global context.

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.

Shale gas extraction via hydraulic fracturing has been a controversial issue in many countries. In Canada, the provincial government of British Columbia (BC) has made relentless efforts on developing a liquefied natural gas (LNG) industry targeting potential Asian importers, which has been a heatedly debated public controversy since late 2011. Focusing on the two contending discourse coalitions formed by this policy initiative’s supporters and opponents, respectively, this article explores the intricate economic, political, and ideological struggles underlying Canadian extractivism. A qualitative discourse analysis of related stakeholder communications reveals that the pro-LNG coalition led by the BC Liberal government developed a “progressive extractivism” storyline to frame LNG exports as an unprecedented and ethical economic opportunity deserving the political support of environmentally minded British Columbians. By contrast, the anti-LNG coalition formed by progressive civil organizations, Indigenous groups, and concerned citizens engaged in fierce discursive resistance, notably via (a) adopting mainstream economic knowledge to highlight the fragile economic basis of BC LNG and (b) incorporating potent political issues such as democratic governance and reconciliation to expand public debates beyond the “jobs versus the environment” dichotomy.

This paper examines how Canadian media have discussed the role of natural gas in climate change mitigation from 2016 to 2019. It also explicates different stakeholders' varying stances on the environmental impacts of North America's ongoing “shale gas boom,” as manifested in their conflicting attitudes toward designating unconventional gas as a bridge to a low-carbon future. The data in question consist of 99 articles published by Canadian media sources, all of which included explicit references to either “bridge fuel” or “transition fuel.” Through a qualitative thematic analysis, I found that more than half of the articles adopted the conventional definition of bridge fuel. Meanwhile, there are three less common, yet noteworthy interpretations arising out of the rest of the articles, which conflict with each other in terms of their views on the relationship between unconventional gas and greenhouse gas emissions reduction. Overall, the fact that bridge fuel references only appeared in a fraction of Canadian environmental and energy news reports during the target period suggests the issue's peripheral status in the Canadian media sphere. Given this situation, the paper ends by calling for more knowledge mobilization efforts to raise public awareness of the controversial factors underlying expanding unconventional gas production and consumption.

Horizontal wells with extended lateral lengths and large-scale hydraulic fracturing are a key technology for shale gas development. Lateral length is the key factor in determining the production and economic benefits of horizontal wells. Therefore, based on geology–engineering–economy integration, a method for optimizing the lateral length of shale-gas horizontal wells is established. Through fracture-shape prediction, productivity simulation and input–output analysis, the net present-value model of the technical–economic evaluation of the economic lateral length is established. A comprehensive evaluation of lateral lengths in Changning Block is then conducted. The results show that, under the current geological, engineering, and economic conditions in Changning Block, a horizontal well with a lateral length between 175 m and 3508 m is economically viable, and the optimal economic lateral length is 2000 m. The porosity and thickness of the reservoir matrix, the production time, the drilling investment, and the price of the natural gas wellhead in the first year have a great impact on the economic lateral length. On one hand, we can increase the drilling rate by increasing the technical research and development efforts. On the other hand, we can improve the construction management level to reduce investment and reasonably increase the price subsidy to optimize the lateral length of shale-gas horizontal wells.

Based on core description, thin section identification, X-ray diffraction analysis, scanning electron microscopy, low-temperature gas adsorption and high-pressure mercury intrusion porosimetry, the shale lithofacies of Shan23 sub-member of Permian Shanxi Formation in the east margin of Ordos Basin was systematically analyzed in this study. The Shan23 sub-member has six lithofacies, namely, low TOC clay shale (C-L), low TOC siliceous shale (S-L), medium TOC siliceous shale (S-M), medium TOC hybrid shale (M-M), high TOC siliceous shale (S-H), and high TOC clay shale (C-H). Among them, S-H is the best lithofacies, S-M and M-M are the second best. The C-L and C-H lithofacies, mainly found in the upper part of Shan23 sub-member, generally developed in tide-dominated delta facies; the S-L, S-M, S-H and M-M shales occurring in the lower part of Shan23 sub-member developed in tide-dominated estuarine bay facies. The S-H, S-M and M-M shales have good pore structure and largely organic matter pores and mineral interparticle pores, including interlayer pore in clay minerals, pyrite intercrystalline pore, and mineral dissolution pore. C-L and S-L shales have mainly mineral interparticle pores and clay mineral interlayer pores, and a small amount of organic matter pores, showing poorer pore structure. The C-H shale has organic micro-pores and a small number of interlayer fissures of clay minerals, showing good micro-pore structure, and poor meso-pore and macro-pore structure. The formation of favorable lithofacies is jointly controlled by depositional environment and diagenesis. Shallow bay-lagoon depositional environment is conducive to the formation of type II2 kerogen which can produce a large number of organic cellular pores. Besides, the rich biogenic silica is conducive to the preservation of primary pores and enhances the fracability of the shale reservoir.

Due to the shortage supply of propylene and the development of shale gas, there is increased interest in on-purpose propane dehydrogenation (PDH) technology for propylene production. Ga-based catalysts have great potential in PDH, due to the high activity, low carbon deposit and deactivation. Ga-hydrides formed during PDH reduce the rate, selectivity and yield of propylene. In this contribution, CO2 is introduced into PDH as a soft oxidant to eliminate the unfavorable intermediate species Gaδ+-Hx re-generating Ga3+-O pairs, and also minimize coke deposition thereby improving the catalytic performance. In situ diffuse reflectance infrared Fourier transform (DRIFT) spectroscopy experiments show that CO2 can effectively eliminate Gaδ+-Hx. At different temperatures, co-feeding CO2 during PDH over Ga2O3/SiO2 catalysts with different loadings significantly improves the stability of the conversion and selectivity, especially the latter, and provide a new dimension for improving the performance of PDH process.

Shale of the Middle–Upper Permian Dalong Formation and Gufeng Formation in the Lower Yangtze region is characterized by large thickness, high total organic carbon (TOC), wide distribution and moderate organic thermal evolution degree, so it may be the next important field of shale gas exploration. In order to point out the target and direction of shale gas exploration and development in this region, this paper selects the Dalong Formation and Gufeng Formation shale in the Xuanjing area of Lower Yangtze as the research object to quantitatively describe the development characteristics of shale pores of different scales by means of scanning electron microscopy (SEM), high pressure mercury injection, CO2 and N2adsorption. Then, the fractal dimension of sample pores is calculated by using the FHH (Frenkel–Halsey–Hill) model. Finally, combined with TOC and mineral compositions, the relationship between pore structure and fractal dimension is discussed. And the following research results are obtained. First, dominant lithofacies of Dalong Formation are argillaceous-rich siliceous shale and argillaceous-rich/siliceous mixed shale, which has smaller specific surface area and pore volume, larger average pore diameter. The pore development is mainly controlled by clay mineral content. Dominant lithofacies of Gufeng Formation is siliceous shale, which has a larger specific surface area and pore volume, and smaller average pore diameter. The pore development is controlled by organic matter and brittle mineral content. Second, the influencing factors of fractal dimension can be attributed to the controlling factors of micropore development. The fractal dimension D1of Dalong Formation ranges from 2.4515 to 2.5513 (average 2.5227), and D2ranges from 2.5817 to 2.6578 (averagely 2.6246). The fractal dimension D1of Gufeng Formation ranges from 2.5817 to 2.6578 (averagely 2.6246), and D2ranges from 2.7227 to 2.871 (averagely 2.813). Gufeng Formation shale presents the characteristics of more complex pore structure. Third, the fractal dimension D1is more sensitive to specific surface area, pore development and mineral composition, while D2is more effective in characterizing the average pore diameter. In conclusion, Dalong Formation shale with high D1and D2and Gufeng Formation shale with low D1and high D2can be taken as the favorable exploration targets of Permian marine shale gas in the Lower Yangtze region, and the regional overpressure zones (belts) with weaker structural deformation in hydrocarbon rich sags will be the favorable shale gas exploration targets in this area.

Shale gas is a green, low-carbon and clean unconventional natural gas energy. China is rich in shale gas resources. Accelerating shale gas exploration and development is of great practical significance to improve China's energy structure and achieve the goal of “2030 carbon peak neutralization and 2060 carbon neutralization”. The Ordovician Wufeng Formation to Silurian Longmaxi Formation in Sichuan Basin is the key strata for shale gas exploration and development in China. Based on the experimental analysis of shale gas in Wufeng Formation to Longmaxi Formation in Weiyuan, Changning, Zhaotong, Fuling and Weirong areas of Sichuan Basin, this paper systematically analyzes the geochemical characteristics of shale gas in Wufeng Formation to Longmaxi Formation, discusses the genesis of shale gas, the causes of hydrocarbon isotope inversion and the source of shale gas, and looks forward to the exploration prospects of shale gas resources in the basin. It has important guiding significances for shale gas exploration and development in Sichuan Basin and even in China. The results show that: (1) The shale gas of Wufeng-Longmaxi formations is a typical dry gas, and the hydrocarbon isotopes are distributed in negative sequence. The carbon isotopes of alkane gas in Changning, Zhaotong and Fuling areas are heavier and have a higher degree of thermal evolution than those in Weiyuan and Weirong areas, and the rare gas is of crustal origin. (2) Shale gas of Wufeng-Longmaxi formations is a thermogenic oil type gas at high-over mature stage, which is mainly the mixture of crude oil cracking gas and kerogen cracking gas. The hydrocarbon isotope inversion of alkane gas is mainly caused by the mixing of crude oil cracking gas and kerogen cracking gas at high-over mature stage, the exchange between formation water and methane at high evolution stage and so on. (3) The carbon isotopic values of methane in shale gas of Wufeng-Longmaxi formations match the carbon isotopic values of kerogen in mudstone of Longmaxi Formation of Lower Silurian, which conforms to the law of carbon isotopic fractionation δ13Ckerogen>δ13Coil>δ13Calkane gas. (4) The total amount of marine, marine continental transitional and continental facies shale gas resources in Sichuan Basin is about 41.5 × 1012 m3, with broad exploration prospects in resource potential.

With the successful development of shale gas in the United States, shale gas has become an effective way to solve the energy crisis. Among a series of environmental problems caused by shale gas exploitation, the most hidden and the most difficult part to control and recover is groundwater pollution in the development zone, which has been paid more and more attention by the government and the public. Starting from the shale gas exploitation process, this paper discusses the research status and problems of shale gas exploitation on groundwater pollution prevention and control from both international and domestic Chinese directions, and considers the future development of groundwater prevention and control work: to strengthen the supervision and management of wastewater treatment; to explore and evaluate shale gas resources and to plan regional water resources; to update and improve relevant environmental laws to strengthen the support for shale gas development; to make public supervision and development transparent; and to optimize the whole development process. HIGHLIGHTS Overview of shale gas exploitation.; Current situation and problems of groundwater pollution prevention and control in international and domestic Chinese shale gas exploitation.; Future prospects for groundwater pollution control in international and Chinese shale gas exploitation.

Producers have always been eager to know the reasons for the difference in the production of different shale gas wells. The Southern Sichuan Basin in China is one of the main production zones of Longmaxi shale gas, whereas the shale gas production is quite different in different shale gas wells. The Longmaxi Formation was deposited in a deepwater shelf that had poor circulation with the open ocean, and it is composed of a variety of facies that are dominated by fine-grained (clay to silt size) particles with varied organic matter distribution, causing heterogeneity of the shale gas concentration. According to the different mother debris and sedimentary environment, we recognized three general sedimentary subfacies and seven lithofacies on the basis of mineralogy, sedimentary texture and structures, biota, and the logging response: (1) There are graptolite-rich shale facies, siliceous shale facies, calcareous shale facies, and a small amount of argillaceous limestone facies in the deepwater shelf of the Weiyuan area and graptolite-rich shale facies and carbonaceous shale facies in the Changning area; (2) there are argillaceous shale facies and argillaceous limestone facies in the semi-deepwater continental shelf of the Weiyuan area and silty shale facies in the Changning area; and (3) argillaceous shale facies mainly developed in the shallow muddy continental shelf of the Weiyuan area, whereas silty shale facies mainly developed in the shallow shelf of the Changning area. Judging from the biostratigraphy of graptolite, the sedimentary environment was different in different stages.

Predicting the diffusion coefficient of fluids under nanoconfinement is important for many applications including the extraction of shale gas from kerogen and product turnover in porous catalysts. ...

Shale gas is an important unconventional natural gas resource, and its reservoirs have pores with strong heterogeneity, which have an important effect on the adsorption and migration of shale gas, but the specific mechanism is still unclear. To further clarify the pore structure characteristics of shale gas reservoirs and the mechanism of their influence on CH4 adsorption capacity, marine shale samples from the Wufeng–Longmaxi formation of wells N1, N3, and N10 in Changning block, southern Sichuan Basin, China, were selected for total organic carbon (TOC), X-ray diffraction (XRD), N2 gas adsorption (N2-GA), CH4 gas adsorption (CH4-GA), and field emission scanning electron microscopy (FE-SEM). The Frenkel–Halsey–Hill (FHH) model and Slit Island Analysis (SIA) were used to calculate the fractal dimension of the pore system and different types of pores, and their relationship and influence on CH4 adsorption capacity were also discussed. The results show that the fractal dimension could reflect the complexity and heterogeneity of pores. According to the FHH model, fractal dimensions of the surface and structure of the pore system (D1 and D2, D1 < D2) were obtained, and the pore structure was more complex than the pore surface. According to SIA, the surface fractal dimensions of four types of reservoir space (DDP, DOP, DIP, and DMF) decrease progressively, and their main body is 2.60–2.80, 2.40–2.65, 2.20–2.40, and 2.05–2.30. Organic pores and intergranular pores are the most abundant, and so D1 is mainly related to DOP and DIP. In high-TOC samples, D1 is close to DOP, while in low-TOC samples, D1 is close to DIP. The complexity of the pore surface, D1, and specific surface area have a positive correlation, and with the increase of pore surface complexity, methane adsorption capacity could be significantly improved. Therefore, D1 may be used as a characterization parameter of CH4 adsorption capacity, which could provide some evidence to further clarify the adsorption mechanism of shale gas.

The breakthrough of clean and efficient shale gas stimulation technology and reduction of global carbon emissions is in a critical period. The injection of supercritical carbon dioxide (SCCO2) into...

Shale gas has enormous potential and has become a hotspot in recent decades. To exploit shale gas, a variety of working fluids (drilling fluid, fracturing fluid, etc.) have to be applied in drillin...

We present a novel workflow for forecasting production in unconventional reservoirs using reduced-order models and machine-learning. Our physics-informed machine-learning workflow addresses the challenges to real-time reservoir management in unconventionals, namely the lack of data (i.e., the time-frame for which the wells have been producing), and the significant computational expense of high-fidelity modeling. We do this by applying the machine-learning paradigm of transfer learning, where we combine fast, but less accurate reduced-order models with slow, but accurate high-fidelity models. We use the Patzek model (Proc Natl Acad Sci 11:19731–19736, https://doi.org/10.1073/pnas.1313380110, 2013) as the reduced-order model to generate synthetic production data and supplement this data with synthetic production data obtained from high-fidelity discrete fracture network simulations of the site of interest. Our results demonstrate that training with low-fidelity models is not sufficient for accurate forecasting, but transfer learning is able to augment the knowledge and perform well once trained with the small set of results from the high-fidelity model. Such a physics-informed machine-learning (PIML) workflow, grounded in physics, is a viable candidate for real-time history matching and production forecasting in a fractured shale gas reservoir.

The Upper Paleozoic coal-measure strata in the Western Henan has good unconventional oil and gas exploration prospects. However, there is a lack of systematic evaluation of potential source rocks. Aiming at the fully exposed the coring boreholes in the Upper Paleozoic in the Western Henan (Luoyang Basin), this paper systematically collects and analyzes samples. Considering the sedimentary environmental conditions, this paper evaluates the Upper Paleozoic source rocks in the Western Henan. The results show that the source rocks include mudstone, carbonate rocks, and coal rocks; Vertically, the source rocks are continuously distributed in the lower layer below the Dazhan sandstone of Shanxi Formation, and only locally developed above Dazhan sandstone; The organic matter type of coal and mudstone is type III, and the kerogen type of carbonate rocks is also type III, which is different from the organic matter type of general carbonate rocks (type I), which is related to the sedimentary environment. The average value of vitrinite reflectance is more than 4.27% and the average value of maximum pyrolysis temperature is more than 430 °C. The thermal evolution degree of source rocks reached the mature to over-mature stage, which tends to gradually increase with the increase of depth, which may be related to Meso–Cenozoic tectonothermal events.

In recent years, short-term creep parameters determined in the laboratory from cylindrical gas shale samples subjected to triaxial (in-situ) stress conditions have been used successfully to infer long-term deformation and stress relaxation at the reservoir scale across geologic time scales. Due to the viscoelastic formalism, both the laboratory creep response and field-scale stress relaxation can be modeled with power law functions of time involving the elastic compliance of the shale B, the time-dependence exponent n, and the amount of total strain ∊. Gas shales often exhibit a high specific surface area associated with their high content in clay minerals and/or total organic carbon (TOC). The low-pressure nitrogen adsorption technique can be used advantageously to estimate specific surface area (SN2); i.e., it is a relatively fast and cost-effective measurement conducted on powdered samples of shale material. A robust global empirical correlation between gas shale creep parameters and SN2 emerges from the analysis of laboratory data collected from multiple gas shale formations in Australia (the prospective Goldwyer Formation) and the United States (Barnett, Haynesville, and Eagle Ford formations), and spanning a broad range of clay content, organic matter, maturity, and porosity values. This data set also shows that the summed fractions of clay minerals, TOC, and porosity, the so-called weak phase fraction, correlates nearly as well with primary creep parameters. The weak phase fraction can also be estimated from faster and more cost-effective measurements or from well logs. To evaluate its predictive capacity, the key correlation between SN2 and creep parameters is used in a case study to predict the magnitude of present-day least principal stress Shmin across six depth intervals/lithologic layers in a prolific unconventional shale formation in the northeastern United States. Several Shmin measurements are available for verification, and our approach successfully captures the observed layered variation of stress with depth.

Gas transport in ultra-tight rock is non-Darcian. In addition to continuum flow, there are multiple other flow mechanisms such as slip flow and pore and surface diffusion. Various multi-physics models have been put forth in the literature to forecast the apparent permeability of gas in shales and ultra-tight formations. However, a means of accurately describing the relative contributions of physics in multiscale pore systems remains a challenge. Moreover, it is important to explain pore size, pressure dependency, and the relationships among adsorption, diffusion, and permeability in porous media. For these reasons, a semi-analytical model is proposed to predict gas permeability according to the viscous flux, pore diffusion and surface diffusion and establish control of the adsorbed gas layer. The reliability of the equations developed was checked by validation using experimental and molecular simulation data obtained from macropore- and micropore-sized nanotubes systems respectively. Furthermore, the equations’ performance for micropores was compared to existing theoretical shale permeability models. The subsequent sensitivity analysis showed that permeability is sensitive to the nanoscale geometry factor and adsorption mechanisms. Moreover, the relevance of the surface diffusion was found to increase as the pore size decreased. For instance, surface diffusion constituted over 50% of the apparent permeability below the 10 MPa and 5.0 MPa conditions in micro- and mesopore systems, respectively, while the Darcy scale phenomenon controlled the transport of gas in macropores. Across all diffusion regimes, the microstructure geometry and sorption dynamics significantly influenced the total diffusion of methane, particularly at low pressures and decreased pore sizes. The decline in reservoir pressure during production shifted the relative importance of the adsorption and diffusion mechanisms, consequently altering the apparent gas permeability. Therefore, reservoir management teams should take into account the dynamics of gas permeability at different pressures and representative pore sizes throughout the life cycle of the asset.

Deep shale gas reservoir (3,500 ∼ 4,500 m) of Wufeng–Longmaxi Formation in southern Sichuan Basin in China has great potential for exploration and development, with resource of 16.31 × 1012 m3, counting 84% of the total resources in this area. And the deep shale gas wells in Luzhou and west Chongqing have achieved good development results in the past two years. We systematically summarized the geological characteristics of deep shale gas reservoir of Wufeng–Longmaxi Formation, and discussed the facing challenges and proposed some corresponding strategies. The deep shale gas reservoir in southern Sichuan Basin has six major characteristics. The reservoir is concentrated in depositional center and deep-water shelf environment. The reservoir is rich in silica and organic carbon while low in calcium and clay. Organic pores, inorganic pores, and microfractures are developed and well interconnected to form networks. Surface porosity is generally > 5% and increasing with depth. The gas content is 4.7 ∼ 7.5 m3/t, higher than that in Changning, Weiyuan, and Zhaotong area. The deep shale gas pressure coefficient is greater than 2.0 and is the highest in the southern Sichuan Basin, indicating its best preservation condition. Up to now, deep shale gas exploration is still encountered with many problems and challenges, including great difficulty in accurately obtaining reservoir parameters, unclear of high production mechanism, urgent need for optimal and quick drilling technology, great difficulty in reservoir fracturing, and unclear of hydro-fracture expansion rules. We proposed two strategies corresponding to the challenges, including deepen the delicate reservoir evaluation and clarify the rules of high production and enrichment of shale gas wells, and strengthen field experiments and explore effective and applicable technologies for drilling and fracturing of deep shale gas in China.

This paper presents a shale gas field geomechanics case study in the Peri-Baltic Syneclise (northern Poland). Polish Oil and Gas Company drilled a vertical well, W-1, and stimulated the Silurian target. Next, a horizontal well, W-2H, drilled the Ordovician target and partially collapsed. The remaining interval was stimulated, and microseismic monitoring was performed. A second horizontal well, W-3H, was drilled at the same azimuth as W-2H, but the well collapsed in the upper horizontal section (Silurian). A geomechanical earth model was constructed that matches the drilling experiences and well failure observations found in wells W-1, W-2H, and W-3H. The field was found to be in a strike-slip faulting stress regime, heavily fractured, with weak bedding contributing to the observed drilling problems. An analysis of safe mud weights, optimal casing setting depths, and optimal drilling directions was carried out for a planned well, W-4H. Specific recommendations are made to further enhance the model in any future studies. These recommendations include data acquisition and best practices for the planned well.

Hydraulic fracturing (HF) and horizontal drilling are essential to the development of shale gas and oil. Production depends on the stimulation success. During fracture initiation, propagation, and closure, cracks emit acoustic waves; these can be monitored in real time as microseismics in the field and as acoustic emissions (AEs) in the laboratory. AEs are the laboratory equivalent of field-scale microseismics and contain detailed information about HF fracture mechanics. The number of acoustic events correlates with the number of induced fractures and hence the stimulation volume. Three HF protocols under dry conditions were carried out on Tennessee sandstone: (1) a constant injection rate, (2) a precyclic injection, and (3) a variable-rate injection test. All three tests were performed under the same principal stress conditions: vertical stress of 10.3 MPa (1500 psi), minimum horizontal stress of 3.5 MPa (500 psi), and maximum horizontal stress of 20.7 MPa (3000 psi). In total, 16 piezoelectric transducers were mounted around a cylindrical sample to record the AEs. We have performed postsignal processing to extract AE event attributes, including the amplitudes, signal-to-noise ratio, arrival time, event location (with the velocity-anisotropy input), and frequency analyses. The AE events associated with the constant-rate injection test possessed the lowest frequencies (150–270 kHz). The variable-rate test AE events possessed higher frequencies (160–310 kHz), whereas the precyclic injection had events with the highest frequencies, peaking at 330 kHz. Acoustic events before failure had lower amplitudes, but higher frequency compared to those recorded postbreakdown, suggesting different failure modes. Precyclic injection induced the greatest number of locatable events before and after failure.

Deep shale gas reservoirs are a significant alternative type of shale gas reservoir in China. The productivity of deep shale gas wells is lower than that of shallow shale, and the imbibition characteristics of deep shale have a significant effect on the retention and backflow of fracturing fluid and the productivity of shale gas wells. In this study, the pore structure characteristics of organic-rich deep shale in the Lower Silurian Longmaxi Formation of Weiyuan-Luzhou play were analyzed by low-temperature nitrogen adsorption experiments, and then the imbibition characteristics and factors influencing deep shale were extensively investigated by spontaneous imbibition and nuclear magnetic resonance experiments. The results show that mainly micropores and mesopores are growing in the deep organic-rich shale of the Longmaxi Formation. The spontaneous imbibition curve of deep shale can be divided into an initial spontaneous imbibition stage, an intermediate transition stage, and a later diffusion stage, and the imbibition capacity coefficient of deep shale is lower than that of shallow shale. The transverse relaxation time (T2) spectrum distributions suggest that clay hydration and swelling produce new pores and microcracks, but then some pores and microfractures close. Deep shale reservoirs have an optimal hydration time when their physical properties are optimal. The increasing pore volume and the decreasing TOC content can enhance the imbibition capacity of shale. An inorganic salt solution, especially a KCl solution, has an inhibitory effect on the imbibition of shale. Higher salinity will result in a stronger inhibitory effect. It is crucial to determine the optimal amount of fracturing fluid and soaking time, and fracturing fluid with a high K+ content can be injected into the Longmaxi Formation deep shale to suppress hydration. These results provide theoretical guiding significance for comprehending the spontaneous imbibition and pore structure evolution characteristics of deep shale and enhancing methane production in deep shale gas reservoirs.

Along with horizontal drilling techniques, multi-stage hydraulic fracturing has improved shale gas production significantly in past decades. In order to understand the mechanism of hydraulic fracturing and improve treatment designs, it is critical to conduct modelling to predict stimulated fractures. In this paper, related physical processes in hydraulic fracturing are firstly discussed and their effects on hydraulic fracturing processes are analysed. Then historical and state of the art numerical models for hydraulic fracturing are reviewed, to highlight the pros and cons of different numerical methods. Next, commercially available software for hydraulic fracturing design are discussed and key features are summarised. Finally, we draw conclusions from the previous discussions in relation to physics, method and applications and provide recommendations for further research.

Energy security is sensitive to the behavioural characteristics of resource trade, especially for the US as the world’s largest energy-consuming economy. This paper applies the Markov switching mod...