Search

The sealing capacities of shale, roof, and floor strata are essential for the preservation of shale gas. Sealing capacity development and its influence on shale gas composition and organic matter pore development are important but have not been addressed by existing studies. In this paper, the Upper Ordovician Wufeng-the first member of the Lower Silurian Longmaxi Fm. in the Yangtze region is selected as the study object. We dissected the J1 well in the Jiaoshiba block inside the Sichuan Basin and the Y6 well in the Youyang block outside the Sichuan Basin to analyze the gas components and carbon isotopes in recovered shale gas. In this study, two microscope techniques (i.e., FIB-SEM and FIB-HIM), porosity measurement, TOC content analysis, permeability tests, isothermal adsorption measurements, are utilized. The analytical results show that both the roof and floor strata have vertical sealing effects on the organic-rich shale due to their different physical properties compared to the shale. The shale overburden pressure increases with burial depth, and the adsorbed gas increases with increasing TOC content and thickness: all of these can lead to a decrease in permeability and an increase in self-sealing capacity. This paper determined the formation mechanism of the sealing capacity for shale, roof and floor strata. Furthermore, the control patterns of "sealing capacity strength" on the shale gas source and organic matter pore development are clarified. The main findings are as follows: when the shale, roof, and floor strata have a strong sealing capacity, only a small amount of liquid hydrocarbons can be discharged from the shale, but the natural gas formed due to liquid hydrocarbon cracking is abundant. Under such circumstances, shale gas has a mixed origin of liquid hydrocarbon cracked gas and kerogen cracked gas; the carbon isotopes are inverted; abundant pyrobitumen pores with high porosity and good connectivity are developed. When the sealing capacities are weak, the amount of liquid hydrocarbons discharged from the shale are high, and the amount of natural gas is low. The shale gas is mainly derived from kerogen cracking with weak or no carbon isotope inversion, and kerogen pores are small with poor connectivity. These findings will advance the study of shale gas formation mechanisms and provide a scientific basis for selecting shale gas exploration area. • Due to different physical properties, the roof and floor strata provide a seal for the organic-rich shale. • As the burial depth, TOC content, and the shale thickness increase, the shale has a stronger sealing capacity. • Sealing capacity plays an important role in the characteristics of shale gas and organic matter pore development. [ABSTRACT FROM AUTHOR]

• CH 4 and (sub and supercritical) CO 2 adsorption experiments on shales were performed. • The adsorption ratio of CO 2 over CH 4 for tested shale samples ranges from 1.66–8.32. • Langmuir, D-A, D-R and Ono-Kondo models were fitted to the adsorption data. • The favorable models used to fit CH 4 and CO 2 adsorption on shales are recommended. A thorough study of the adsorption behavior of shales to methane (CH 4) and carbon dioxide (CO 2) is critical for carbon dioxide sequestration in shale gas reservoirs and enhanced shale gas recovery. This paper discusses the results of an adsorption study of CH 4 and CO 2 , in single gas environment, on a set of shale samples taken from the Sichuan and Ordos Basins. The results indicated that shale exhibit higher affinity to CO 2 as compared to CH 4 under similar pressure and temperature conditions, and the preferential adsorption ratio of CO 2 over CH 4 varies between 1.66 and 8.32. Furthermore, the experimental data were modeled using Langmuir, Dubibin-Astakhov (D-A), Dubinin-Redushckevich (D-R) and Ono-Kondo models. The accuracy of the models in quantifying CH 4 and CO 2 adsorption on shale was compared using an error analysis technique. For CH 4 , both of Langmuir and D-A models performed satisfactorily with comparable accuracy. For subcritical CO 2 , the performance of the D-A model is the best. However, for supercritical CO 2 , Ono-Kondo model fitted the experimental data the best, which is the proposed model to use. The results of this study can provide the basis for the estimation of the CO 2 sequestration capacity in shale formations. [ABSTRACT FROM AUTHOR]

• Resource-Richness Analogy Approach used in less explored reservoirs is proposed. • Genesis-Statistics Assessment Approach for heterogeneous tight oil is proposed. • The parameter criteria of lacustrine tight oil resource assessment are established. • In-place tight oil resources in China's major basins are estimated of 12.6 × 109 t. • 15 most favorable plays are outlined with in-place resources of 5.3 × 109 t. Large-scale commercial development of shale gas and tight oil resources in North American and continuous discoveries of tight oil in China lead to the recognition of the importance of assessment on tight oil resources. Based on the characteristics of China's tight oil reservoirs and exploration status, this paper discusses a workflow focusing on in-place resource evaluation. In the workflow, a Resource-Richness Analogy Approach (RR-AA) is proposed for assessment of tight oil resources in less explored areas, a Genesis-Statistics Assessment Approach (GS-AA) for lacustrine tight oil resources with strong heterogeneity and regions where more delicate assessment is required, and an EUR Analogy Approach (EUR-AA) for assessment on recoverable tight oil by fully using available EUR data of production wells. After analyzing the geological characteristics of the formation of tight oil in the Ordos, Bohai Bay, Songliao, Junggar, Sichuan and other major Basins, the distributions of essential parameters such as reservoir thickness, area and porosity have been defined, and the parameter evaluation criteria have been established. Finally, the tight oil resource potentials in the major basins in China have been evaluated using one of the three methods and the prospective areas of high resource abundance are outlined in each of basins. The results from this study show that China's tight oil resources have a large potential and good exploration future. The estimated in-place tight oil resources are 12.580 × 109 tons, mainly distributed in the Ordos, Songliao, Bohai Bay and Junggar Basins. 15 most favorable zones are proposed having in-place resources of 5.296 × 109 tons. [ABSTRACT FROM AUTHOR]

Abstract Multiphase (adsorbed and free) liquid water that is accumulated in shale matrix pores (i.e., pore water) substantially affects the storage and transport of gas in shale. Traditionally used macroscopic parameters (e.g., initial, irreducible, mobile and clay bound water saturations) are not sufficient to describe the microdistribution characteristics and mobility of pore water in the complex porous shale matrix. In this paper, a new classification was proposed in which the pore water is composed of adsorbed and free parts, of which the latter is subdivided into capillary bound and mobile water. The components of pore water have the following features: during the centrifugation process, (a) adsorbed water is essentially immobile, while free water is potentially mobile; (b) capillary bound water is gradually transformed into mobile water with increased centrifugal pressure difference; and (c) the maximum mobile water amount is numerically equal to the free water amount. Based on the classification, an effective technique, which integrates centrifugation, water imbibition and low temperature nitrogen adsorption methods with the modified Li's adsorption ratio equation (2018), was established to quantitatively evaluate the microdistribution characteristics (adsorbed and free amounts and their ratios) and the mobility (mobile amount, potential and capacity) of pore water in marine shales from the southern Sichuan basin in China. Furthermore, the mechanism of controlling the microdistribution and mobility of pore water is analyzed with respect to the microscopic pore structure characteristics and material compositions of shales. The primary results demonstrate that (1) adsorbed and free water amounts obtained by centrifugation tests range from 5.145 to 31.282 mg/g (adsorbed) and from 7.880 to 49.751 mg/g (free); the weight ratio of adsorbed water is 0.268–0.629. (2) The mobile potential and mobile capacity of pore water are represented by the free water amount and mid-value pressure difference, respectively. A positive relationship between these two parameters occurs in the studied shales. (3) Pore microstructure characteristics of shale mainly impact the microdistribution and mobility of pore water in the shale matrix. The adsorbed water amount is closely associated with the specific surface area of pores, while the free and mobile water amounts are controlled by the pore volume. The ratios of adsorbed and free water depend on the size and morphology of pores for certain state parameters. The mobile ratio is impacted by pore complexity, which indicates that as the complexity increases, the mobile ratio decreases. The study provides significant insight into the microdistribution and mobility of pore water in gas shale matrix. Highlights • A new classification was proposed for the components of pore water. • A technique was established to evaluate the microdistribution characteristics and the mobility of pore water in shales. • Mechanism of controlling the microdistribution and mobility of pore water was analyzed. [ABSTRACT FROM AUTHOR]

In shale plays, the in-situ effective stress is continuously being perturbed because of the production which impacts field operations. Therefore, mechanical properties of the formation and its response to stress field changes, with respect to mineral variations, is of great significance for the proper design of horizontal drilling and hydraulic fracturing. In this paper, clay-rich, calcareous and siliceous black shales are classified based on their XRD analysis, from the Wufeng and Longmaxi Formations in the Sichuan Basin of the Upper Yangtze Plate. Uniaxial quasi-static and cyclic loading tests, acoustic emissions, and CT scanning are combined to study mechanical behavior and fracturing mechanisms of the shale layer samples that own different mineral components. The results show that the strength and deformation response of the samples is a function of their mineral composition. The damage from cyclic loading is gradually accumulated in the samples which ultimately leads to fatigue and sample failure. The compressive strength of the samples under cyclic loading is lower than in the uniaxial quasi-static conditions. Furthermore, the fracturing of rock under uniaxial quasi-static loading mainly occurs after the peak strength is achieved while in cyclic loading, when a certain stress level is reached, fracturing begins, the damage accumulates up to the peak stress and the rock suddenly fails. Based on CT images from the samples after rupture, failure modes of the clay-rich, calcareous and siliceous black shales mainly constitute extensional and shear fractures, with some conjugate shearing. In comparison with uniaxial quasi-static loading, the fracture volume of the clay-rich, calcareous and siliceous black shales after cyclic loading increases by 12.2%, 25.9% and 32.9%, respectively. Overall, this study explains how cyclic loading that can be applied in the field via changing the injection pressure and other stimulation parameters, can effectively improve the complexity of the shale fracture network and lead to higher productivity of the formation. • Quasi static loading and cyclic loading are employed in the mechanical test. • The compressive strength of the cyclic loading is lower than that of uniaxial quasi-static loading. • The fracture volume of the cyclic loading is higher than that of uniaxial quasi-static loading. [ABSTRACT FROM AUTHOR]

In the process of hydraulic fracturing of shale gas horizontal wells in the Weiyuan area of Sichuan, China, casing deformation (CD) is a frequent problem that has seriously affected the benefits of shale gas development and remains to be solved for many years. In this paper, based on the analyses of Multi-finger Imaging Tool-24 (MIT-24) data, microseismic data, and the relationship between CD and engineering parameters, we confirm that the wellbore morphology in all CD sections in the Weiyuan area is consistent with shear deformation characteristics and clarify the cause of all CD: hydraulic fracturing leads to increased fluid pressure in well-intersecting faults and large fractures (F-Fs), inducing their shear slip, and eventually leads to asymmetric compression on the casing by strata on both sides of F-Fs, i.e., CD. On this basis, we propose a set of methods to control (or moderate) the shear slip of F-Fs by reducing the additional fluid pressure in target F-Fs during hydraulic fracturing to prevent CD, including multi-cluster perforations, temporary plugging F-Fs and fracturing fluid flowback. We also analyze the theoretical basis, feasibility and workflow of these methods. These methods have been tested in 44 horizontal wells in the Weiyuan area, of which the result is a radical decrease in the CD rate of the single well (from 54% to 9.1%), indicating that the slip of F-Fs and the resulting CD during hydraulic fracturing can be controlled and providing a reference for the prevention of hydraulic fracturing-induced earthquakes. • All CD during hydraulic fracturing of shale gas in the Weiyuan area is caused by induced shear slip of F-Fs. • Temporary plugging can reduce the additional fluid pressure in target F-Fs so as to prevent CD. • The integrated technical methods have been proved to be effective in preventing CD in field application. [ABSTRACT FROM AUTHOR]

Breakthroughs in shale gas exploration in the Upper Ordovician-Lower Silurian strata of the Upper Yangtze Platform have attracted interest in its sedimentary-tectonic evolution, but the tectonic background of the northern margin of the Upper Yangtze Platform remains unclear. In this paper, the Wufeng-Longmaxi formations on the northern margin of the Upper Yangtze Platform were investigated. Based on geochemical and mineralogical analyses of the tuffs/K-bentonites of the Wufeng Formation and the barite in the Longmaxi Formation, as well as previous research results, it was concluded that the northern margin of the Upper Yangtze Platform was in an extensional tectonic background during the Late Ordovician-Early Silurian. Detailed analysis revealed that, (1) the U–Pb zircon age of the tuff in the Bajiaokou section in South Qinling is 443.91 ± 0.92 Ma. The Zr/TiO 2 –Nb/Y diagram of the tuffs/K-bentonites indicates that their protoliths were alkaline-subalkaline basalt and andesite series rock. Based on the Th–Hf/3-Ta, Th–Tb*3-Ta*2, and TiO 2 –Nb/3-Th diagrams, there are undiscovered intraplate tension calc-alkaline basalts in the northern Yangtze Platform or the southern Qinling region, which provided volcanic clastic materials to the Ziyang, Lan'gao, Chengkou, Yichang and other regions. (2) Scanning electron microscopy revealed that the barite crystals in the Longmaxi Formation exhibit dissolution features and have a large particle size. Energy spectrum analysis of these barite crystals revealed that they have C, O, S, and Ba contents of 8.48 wt%, 22.98 wt%, 13.09 wt% and 55.44 wt%, so they are speculated to have been formed via cold methane seep genesis in a weak extensional tectonic setting. The 87Sr/86Sr ratios of the barite revealed that different types of barite were simultaneously formed in this area under the influences of hydrothermal and cold methane seeps. (3) The analysis of the heavy minerals in the Lower Silurian strata in the Bajiaokou section revealed that the provenance in the South Qinling area changed significantly during the late Early Silurian. Based on the above analyses, the northern margin of the Upper Yangtze Platform was in an extensional tectonic setting during the Late Ordovician-Early Silurian. The distribution of the total organic carbon content indicated that the extensional tectonic background provided good conditions for the enrichment and preservation of organic matter. The results of this study provide an understanding of the regional sedimentary-tectonic pattern and evolution of the Yangtze Platform during this period, as well as a reference for future shale gas exploration in this region. • The tectonic background of the Late Ordovician-Early Silurian was studied. • The northern margin of the Upper Yangtze Platform is an extensional background. • The extensional tectonics caused the cold seepage events. • The extensional fault controlled the distribution of volcanic clastic sediments. • Organic matter accumulation was influenced by the extensional fault depression. [ABSTRACT FROM AUTHOR]

The casing deformation problems during hydraulic fracturing process in shale gas wells seriously affect multi-stage hydraulic fracturing treatment and cause significant impact on efficient exploitation of shale gas in Sichuan, China. But by now, the mechanism of these casing deformation problems has not been completely understood. The tests of the casing deformation show that the shear failure is the main type of casing deformation. Combined with the detected seismic data, the fault slip caused by hydraulic fracturing is identified as the main reason for casing deformation in shale gas wells. A deep understanding of fault reactivation and slip is significant important. Hence, a semi-analytical model for calculating induced stress along the fault caused by hydraulic fracture is established in this paper. Based on the induced stress along the fault, semi-analytical models for calculating two types of fault slip are established, including the reactivated zone located at one fault tip and the reactivated zone located away from fault tips. Additionally, the effects of fluid pressure, dip angle of fault, scale of fluid stimulated area and the friction coefficient on fault slippage are discussed. At last, the method for calculating fault slippage proposed in this paper is applied in field and the calculated result is consistent with the field data. The semi-analytical model proposed in this paper provides a reasonable way for identifying casing deformation in shale gas wells or other wells which need hydraulic fracturing treatments. [ABSTRACT FROM AUTHOR]

• The desorption mechanism of oil from the nano-micro pores was studied. • The oil is desorbed when the particle self-rotation speed is faster than the critical speed. • When the inlet flow rate increased, the particle self-rotation speed increased, which could strengthen the desorption process. To realize the harmless treatment and resource recycling of oily shale cuttings, the most important step is to desorb the oil phase from the pores of the cuttings. The desorption treatment must overcome the capillary force and viscous resistance inside the pores. This paper discusses a cyclone oil desorption technology. The particles of the oily shale cuttings in the swirl field generated by the cyclone will have high-speed self-rotation, thus providing sufficient centrifugal forces that separate the phase oil from the pores. The critical speed of such self-rotation for the desorption of oil phase in pores of particles was analyzed using mechanical formula, and the distribution of particle self-rotation speed in the cyclone was calculated and simulated. We collected shale cutting samples from the Sichuan shale gas field in China. Experiments were conducted to observe the changes in the porosity and oil content of the cuttings before and after cyclone desorption treatment. The results show that the particle self-rotation in the cyclone can effectively achieve the oil phase desorption from the particle pores. For the shale cuttings in the experiments, when the particle self-rotation speed is faster than the critical self-rotation speed of 507 rad/s, the oil phase in the particle pores can be desorbed. When the inlet flow rate is between 55 m3/h − 95 m3/h, the particle self-rotation speed is faster than the required critical self-rotation speed. As the inlet flow rate increases, the particle self-rotation speed in the cyclone also increases, which generates better desorption effects. [ABSTRACT FROM AUTHOR]

[Display omitted] • The shale gas resource potential of the Longmaxi Formation was evaluated by using mud gas isotope logging technology. • The reservoir properties of shale were evaluated based on gas isotope fractionation effects. • The shale gas in the Changning area belongs to late kerogen cracking gas. • The lower part of the Longmaxi Formation has a better shale gas exploration potential. The Longmaxi Formation in the Sichuan Basin is one of the most important shale gas producing formations in China. Previous studies of shale gas were mostly carried out on based on laboratory analyses and did not provide effective guidelines for shale gas exploration. In this paper, we present a large amount of carbon isotopic data from mud gas isotope logging and rock-cutting headspace gas in wellsites. The δ13C 1 values showed a significant decrease at the bottom of the Longmaxi Formation. The δ13C 1 and δ13C 2 values in the Changning area were observed to be heavier than those in the Weiyuan and Jiaoshiba areas. The second half of the N216H27-3 horizontal well had obvious outgassing and carbon isotope fractionation effects. This indicates that the bottom of the Longmaxi Formation has better shale gas exploration potential. The shale gas of the Longmaxi Formation in the Changning area belongs to late kerogen cracking gas, where exploration prospects are poorer than those in the Weiyuan and Jiaoshiba areas. There were more oil cracking gas resources and better reservoir conditions at the end of the N216H27-3 horizontal well; therefore, drilling should be continued at this site. [ABSTRACT FROM AUTHOR]

Total organic carbon (TOC) content is significant for "sweet spots" prediction and resource calculation. Traditional physical methods and machine learning methods, however, only use labeled samples (core TOC samples and well logging data) to predict TOC, resulting in a performance bottleneck. Meanwhile, many oilfields have considerable unlabeled data (well logging data). Therefore, this paper proposed a pretrain-and-finetune few-shot learning framework, called Contrastive Learning-Convolutional Neural Network (CL-CNN), to predict TOC using unlabeled data. CL has been a research hotspot in unsupervised learning in recent years, with the principle of reducing the distance between similar samples and increasing the distance between different samples in the feature space. CNN is distinguished by its strong generalization ability and high prediction accuracy, as well as its local connectivity and weight sharing. The CL-CNN model first uses CL to pretrain the initial parameters of the CNN model on a large number of unlabeled datasets and then finetunes the resultant CNN model using the labeled data. The framework combines the advantages of CL and CNN to further improve the prediction accuracy and generalization ability. The proposed method was applied to predict the TOC of shale gas in the Sichuan Basin, China, using 121 core samples and 1224 well logging data from the JY 10 well (121 logging data for supervised learning and 1103 logging data for unsupervised learning). Besides, JY 10–10 well data were used to validate the CL-CNN model. Experimental results demonstrated that the CL-CNN model outperformed many machine learning methods, including the support vector machine (SVM), Gaussian process regression (GPR), random forest (RF), and CNN models, indicating the feasibility and effectiveness of the proposed method. Because of this, the CL-CNN model can also be used as a general prediction tool for reservoir parameters such as porosity and permeability. • Contrastive learning was used to learn the general attributes of the unlabeled data. • Contrastive learning-convolutional neural network (CL-CNN) was proposed to predict TOC content. • Unsupervised pretraining and supervised finetuning were used for few-shot TOC prediction. • CL-CNN obtained promising results for predicting TOC and outperformed many methods. • The plane distribution of TOC in the study area was predicted by CL-CNN accurately. [ABSTRACT FROM AUTHOR]

With the development of exploration and exploitation technologies, deep shale gas systems are gradually becoming an important target for the future petroleum industry. However, there is still a lack of systematic geological studies for deep shale gas systems, which restricts further exploration. In this paper, the deeply buried shales (more than 4000 m in depth) of the first member of Silurian Longmaxi (S 1 l1) at the southeastern margin of the Sichuan Basin are selected as the research object, and thin sections, scanning electron microscope (SEM) observations, total organic carbon (TOC) testing, nitrogen adsorption (NA), and major and trace element analyses are used to systemically identify the different lithofacies and delineate geological and geochemical features. Moreover, we reconstruct the paleoenvironment, summarize the controlling factors and mechanisms of organic matter accumulation and pore formation, and finally reveal the favorable exploration lithofacies. Our results show that there are four lithofacies that can be identified in deep S 1 l1 shale, namely, laminated organic-rich siliceous shale (S), laminated organic-rich mixed shale (RM), banded organic-lean mixed shale (LM), and banded organic-lean argillaceous shale (CM). Organic matter-hosted pores are the primary type in their pore system. The S and RM shales were mainly deposited under dysoxic to anoxic conditions with moderate watermass restriction, low terrestrial detrital influx, and high paleoproductivity, and the silica mainly originated from the diagenesis process (biogenic quartz); the LM and CM shales were sedimented under oxic conditions with high terrestrial detrital influx and low paleoproductivity, and the silica mainly originated from terrestrial detrital influx. Redox conditions, paleoproductivity, and terrestrial detrital influx together controlled the organic matter enrichment in the deep S 1 l1 shale, and the TOC content further influences the physical properties of the shale, thus determining the exploration potential of different lithofacies. Moreover, the significant impacts of lithofacies on the geological and geochemical features of the deep shale gas system are demonstrated. Compared with the middle-shallow shale gas system in the study area, due to less tectonically uplifted and tectonically active shale, the deep shale has more extraordinary preservation conditions, overpressure inheritance development, and higher gas amounts. The S and RM in S l l1 in the study area have better resource potential and should be given more attention in the future. • Geological and geochemical features of different lithofacies in deep shale gas systems are systematically characterized. • Paleoenvironment, organic matter accumulation, and pore formation mechanisms of different lithofacies are revealed. • Lithofacies has a considerable influence on the deep shale gas system, which is consistent with the system in shallow-middle depths. • Compared with shallow-middle shale gas systems, deep shale gas accumulations are generally characterized by overpressure, which leads to a high gas amount. • Overpressure may be due to variations in tectonic activity and preservation conditions. [ABSTRACT FROM AUTHOR]

An appropriate shut-in after fracturing can dramatically enhance performance of wells in shale gas reservoirs. In this study, a novel wettability index and mineral content curve based shut-in time optimization approach was proposed. First, a new experimental device for spontaneous imbibition of fracturing fluid under the conditions of formation temperature and confining pressure was designed. Then, we conduct a set of experiments on shale samples from the Longmaxi Formation (LF) in the Sichuan Basin to measure the water-wet index and determine the critical value of clay content. Finally, the low-field nuclear magnetic resonance (NMR) equipment was used to monitor the water flow in shale micro-pores, based on this, the shut-in time for different shale reservoirs was optimized. The experimental results show that LF shale hydration can induce new micro-fractures, and the fractures shape is mainly shale bedding fractures, with obvious directionality. The clay content is the key factor affecting water wettability of shale and the critical clay content value of type I and type II shale reservoirs was about 39.5%. The optimal shut-in time of type I and type II shale reservoirs are about 20 days and 15 days respectively. Field application of three wells showed that the average daily gas production was increased by 2–3 times. The research results can guide the development of shale gas reservoirs effectively. • In this paper, the water imbibition experiment of shale under the condition of formation temperature and pressure of shale reservoir was carried out, and the critical clay content affecting the imbibition capacity of shale was determined. • On this basis, the shut-in-time of different reservoirs types was further optimized. • The research results play an important guiding role in understanding the flow law of fracturing fluid in shale reservoirs. [ABSTRACT FROM AUTHOR]

The Longmaxi Formation has abundant shale gas resources. High-yield wells have been obtained in medium-shallow and deep areas in the Sichuan Basin. Quantitative research on the brittle-ductile change in rocks is a basic geological component for caprock evaluation, and it can also be applied to shale gas exploration. This paper fully considers the difference between the lower shale (N1) and upper shale (N2) of the Longmaxi gas-bearing shale. Through total organic carbon (TOC), mineral components, field emission scanning electron microscopy (FE-SEM), and triaxial mechanics experiments, the two groups of shale samples, N1 and N2, were compared and analyzed, and the brittle-ductile transition was quantitatively studied. Based on previous work, a method for the fast calculation of the key over consolidation ratio (OCR) was proposed. The results show that N1 is mainly organic-rich siliceous shale, N2 is primarily organic-poor clay shale and mixed shale, and N1 is generally more brittle than N2. The key OCRs of N1 and N2 are 2.16 and 2.60, respectively. The key confining pressures at which N1 and N2 become fully ductile are 87.87 MPa and 70.28 MPa, respectively. Therefore, the key depths of the brittle zones of N1 and N2 (H b1 and H b2) and the key depths of the ductile zones of N1 and N2 (H d1 and H d2) are obtained. On this basis, a comprehensive model for the Longmaxi shale gas' brittle-ductile transition exploration zone in the Sichuan Basin and H b1 and H b2 maps of the Longmaxi gas-bearing shale have been established. Through comprehensive vertical and horizontal analysis, Longmaxi shale gas exploration risks in different blocks of the Sichuan Basin have been clarified. Therefore, this study of the variation in the brittle-ductile transition has an important guiding role in refining the exploration of Longmaxi shale gas in the Sichuan Basin. • There are obvious differences between the lower shale and the upper shale. • Difference of brittle-ductile transition makes shale gas exploration more complicated. • The new method can quickly calculate the threshold value of over consolidation ratio. • The new model provides more comprehensive guidance for shale gas exploration. [ABSTRACT FROM AUTHOR]

The estimated ultimate recovery (EUR) of a single shale gas well is one of the important evaluation indicators for the scale and benefit development of shale gas. Nevertheless, due to the lack of engineering and geologic data, as well as the limitations of the existing empirical methods, the current production forecasting methods cannot make reasonable predictions for EUR. Therefore, Duong method is used as the prototype in this paper, a rapid and accurate empirical model for improved production prediction is proposed based on the historical production profile analysis of mass producing wells in Sichuan Basin. The accuracy and universality of the new model are verified by production examples in the Weiyuan, Changning, Luzhou and Yuxi blocks of the Sichuan Basin. The examples illustrate that the new model can be applied well in typical wells, and has no limitation of flow regimes for the production prediction of gas wells. In order to solve the problem of production data fluctuation and decline curve deviation caused by stimulation measures in the production process, a multi-segment production prediction model analysis method is proposed based on the improved model in this study and has been well applied in the field. Most importantly, the new model has clear physical parameters and is easy to operate. Performance of the new model based on production data is as reasonable as the modern production decline methods (including analytical model), which is better than existing empirical methods. • Proposing an improved empirical model, which is rapid and accurate. • Less parameters were selected, the new model still has clear physical meaning. • Application condition of the new model is not limited by the flow regime. • Performance of the new model based on production data is as reasonable as the analytical model. • Multi-segment production prediction model is well applied to gas wells with production data fluctuation. [ABSTRACT FROM AUTHOR]

The upper Permian Longtan Formation (LTF) shale is a new shale gas exploration and development focus in China, which was formed in a transitional depositional environment. Because of the difference in the sedimentary environment between marine-continental transitional shale and marine shale, the enrichment characteristics and mechanism of organic matter (OM) are very different. Because of a weak research foundation, the enrichment mechanism of OM in the LTF shale in the Sichuan Basin is still unclear. In this paper, shale samples of the upper Permian LTF from the Well F5 were collected, and the abundance, source and sedimentary environment of organic matter were studied by using paleoclimate, detrital input, redox, paleoproductivity and sedimentation rate parameters. The results show that the TOC content of the LTF shale is high (average = 3.04%) and reaches the high to overmature stage (average = 2.46%), indicating a favorable source rock. The LTF shale was deposited in a humid and hot climate, which was conducive to the growth and prosperity of a large number of plants. The source of organic matter was mainly terrestrial plant fragments. The sedimentary environment of the LTF shale was oxic, it had a high sedimentation rate, which reduced the oxidation rate of OM, promoted the rapid deposition of OM, and ensured the preservation of organic matter. In summary, the enrichment of OM of LTF shale in the Sichuan Basin was affected by the sedimentary environment, which was complicated. The main controlling factors were detrital input, redox conditions and sedimentation rate. • The geochemical characteristics of Permian Longtan Formation (PLTF) shale in eastern Sichuan are analyzed. • The sedimentary paleoenvironment of PLTF shale in eastern Sichuan is reconstructed. • The main controlling factors of organic matter enrichment of PLTF in eastern Sichuan are studied for the first time. [ABSTRACT FROM AUTHOR]

The lamellation fractures in marine shales are important to the accumulation and preservation of shale gas, whose characteristics and controlling factors are still unclear. This paper focus on the characteristics descriptions and controlling factor analyses based on core observations, thin sections, and scanning electron microscope (SEM) experiments. The marine shales of Paleozoic Wufeng Formation and Longmaxi Formation in the Fuling Area of Eastern Sichuan Basin are taken as an instance. The lamellation fractures are occurring along the direction of the lamellations, partially of them curved, bifurcated, and converged. The apertures of fractures typically range from 1 to 500 μm. Only a few (<1%) lamellation fractures are filled with quartz, calcite, pyrite, and bitumen. After a series of analyses, developments of lamellation fractures are controlled by total organic carbon (TOC), brittle minerals, laminae, and pyrite. (1) The organic matters control the formation and evolution of lamellation fractures by generating gas and resulting in overpressure. An increase in the TOC content of 1% can increase the lamellation fracture density by 0.26 cm-1. (2) Brittle minerals, especially authigenic quartz, is also an important controlling factor to the development of lamellation fractures. When BI increases by 10%, the lamellation fracture density increases by 19%. (3) Besides, siliceous and carbonate laminae in the shale are more suitable for lamellation fractures to develop. When the laminae density is smaller than 4 cm−1, it is easier to develop lamellation fractures with higher laminae density. However, too densely-distributed laminae will suppress the formation of lamellation fractures. (4) Higher pyrite content is good for the development of lamellation fractures. Lamellation fracture density will increase by 9%, with pyrite content increased by 1%. For the shale at the bottom of the Wufeng Formation - Longmaxi Formation, lamellation fractures develop extensively due to the high TOC and pyrite content, great brittleness, and moderate laminae density. The density of lamellation fractures decreases from the bottom to the top. • Quantitative characterize about development characteristics of the lamellation fractures. • The lamellation fractures is controlled by brittle mineral, TOC, laminae and pyrite. • TOC is the main one that affects the development of lamellation fractures. • Clarify vertical distribution characteristic of lamellation fractures in the Wufeng-longmaxi Fm. [ABSTRACT FROM AUTHOR]

• CO 2 and SRB were the main factors of shale gas pipeline corrosion and perforation. • Pre-cultured with culture medium increased the corrosion rate of the steel, and SRB catalytic corrosion process. • CO 2 promotes bacterial film formation and accelerates corrosion. • Bacterial enrichment is the main cause of pitting corrosion. In the shale gas field in southern Sichuan Basin, the corrosion-induced failure has been observed. In this paper, first, the corrosion phenomenon was analyzed. Second, the causes of corrosion were analyzed thoroughly from the aspects of corrosive environment, materials, and corrosion products. Finally, the field water environment was simulated, and the result showed the following: SRB is one of the main causes of corrosion and perforation of shale gas pipelines, bacterial enrichment is the primary reason for local corrosion, and CO 2 promotes the formation of bacterial film and accelerates corrosion. [ABSTRACT FROM AUTHOR]

The Lower Cambrian Qiongzhusi Formation source rock is one of the main sources of oil and gas in the Sichuan Basin. Owing to the controversial thermal history and the complex structural pattern in the Sichuan Basin, it is difficult to characterize the differences in maturity evolution and the timing of hydrocarbon generation periods of Qiongzhusi hydrocarbon source rocks in different tectonic zones. Based on the comprehensive analysis of the previous thermal history and denudation studies from the tectonic units of the basin, the thermal histories and denudation amount in main period of tectonic movement of a five-part tectonic development are obtained in this paper. Although the thermal history of different tectonic units varies, generally, the heat flow increased slowly in the early Paleozoic, and it experienced a peak heat flow at the end of the Middle Permian and decreased subsequently. Based on new thermal history and denudation data, the maturation of the Lower Cambrian Qiongzhusi Formation source rocks in the Sichuan Basin were modeled and their evolution can be classified into three patterns, which are: (1) continuous heating pattern in southern Sichuan, (2) Silurian-Permian heating cessation pattern in western Sichuan and northwest central Sichuan, and (3) Silurian-Permian and Triassic heating cessation pattern in the central uplift, northern structural zone and western part of the eastern structural zone. In addition, the key hydrocarbon generation periods of different tectonic units were determined in this study. Tectonic and sedimentary burial, together with high heat flow values during the Late Permian, were the main factors controlling levels of thermal maturity and thermal evolution models of the Qiongzhusi Formation. The present-day thermal maturity of the Qiongzhusi Formation depends on the thermal history and maximum burial depth before uplift in Late Cretaceous. However, the maturity evolution pattern affecting the key hydrocarbon generation stage was mainly related to the burial histories of source rocks in the Paleozoic. The thermal modelling of this study provides new evidence for the source rock evolution and new insight into Lower Paleozoic shale gas. • Thermal history, denudation amount and process of different tectonic units are summarized. • Maturity evolution and key HC generation periods of the Qiongzhusi Formation are obtained. • Three thermal evolution patterns of source rocks are classified. [ABSTRACT FROM AUTHOR]

Shale gas development in the Sichuan-Chongqing region in China has experienced a high level of casing deformation or failure during hydraulic fracturing treatment, which has resulted in significant productivity decline and economic losses. This problem has motivated many studies in the literature but focusing on the shearing deformation using the finite element method. This paper categorizes the casing failure modes and mechanisms in the region and presents casing collapse laboratory results. The designed laboratory tests rendered us critical data points in casing deformation under different loading scenarios. For multiple stage hydraulic wells in the region, we propose to use a strain-based protocol for casing design instead of the current design based on maximum stress. • Present laboratory experiments on casing deformation due to shearing stress. • Propose a model to predict the maximum allowable stress for a casing tubular. • Update statistics on casing deformations and failures in the Changning-Weiyuan region. • Introduce one of a kind laboratory experiment setup for full size tubular testing. [ABSTRACT FROM AUTHOR]

Fractures gradually open under the action of fluid pressure in drilling shale gas reservoirs because of the existence of shale natural fractures, which leads to the leakage of expansible fractures. Induced fracture leakage is difficult to find and control in the early stage of drilling, resulting in great economic losses. The current model of induced fracture leakage pressure model is based on takes rock fracture criterion, which can only be used to judge whether the fracture is fractures created or not but cannot analyze the influence of fracture width change on leakage pressure after natural fracture of shale cracking. In addition, the model cannot control the occurrence of leakage. In this paper, the calculation method of fracture's width change under induced pressure is established. According to the field leakage rate data, a dynamic model of leakage pressure is established based on the parameters of time, leakage rate, fracture's width, fluid viscosity, and wellbore radius. The model is applied to calculate the dynamic change of leakage pressure on the Sichuan Shale Gas Field site and control the induced fracture's change to control leakage. Results show the following observations. (i) The fracture's width and leakage velocity of induced fracture increase with the increase of leakage pressure. Blocking the leakage when any leakage is found on the site is not advisable because it can increase the fracture's width artificially and increase leakage. (ii) The critical value of the fracture's width may cause severe leakage. When the leakage's differential pressure remains unchanged, the relationship between the fracture's width and leakage velocity refers to the power exponent change. The method of controlling the leakage pressure and reducing the fracture's width that is less than the critical leakage fracture degree is adopted for the leakage of the shale gas drilling in the Longmaxi Formation field Jiaoshiba, which effectively reduces the leakage amount. Taking a particular project, for example, controlling leakage pressure of induced fracture is given to verify the feasibility of the method. • The calculation method of fracture's width change under induced pressure is established. • A modal of leakage pressure is established based on time,leakage rate,fracture's width,and fluid viscosity. • The method of controlling the pressure to reduce the fracture's width to control the leakage is established. [ABSTRACT FROM AUTHOR]

Based on low-temperature thermochronological data (i.e., apatite fission-track (AFT) and (U–Th)/He (AHe)), structural evolution, burial and thermal history, this paper examines the relationship of multi-stage evolution between the upper Ordovician Wufeng and lower Silurian Longmaxi formations (i.e., the WL formation) and rapid exhumation at the Changning shale gas field in the southern Sichuan basin. AFT ages are generally young from southeast to northwest, decreasing from ca. 40 to 15 Ma while AHe single-grain ages range from ~35 to ~5 Ma. Inverse thermal histories show that a multi-stage cooling history with initial cooling began in the Late Cretaceous to early Cenozoic (middle Eocene), followed by accelerated rapid cooling in the late Cenozoic, with cooling rates of 2–4 °C/Myr across the Changning shale gas field. In particular, thermal models of samples in the western Changning area show a substantial increase in the cooling rates, i.e., from less than 1 °C/Myr to 3–5 °C/Myr in the Miocene. Integrated with inverse T-t models of low-temperature thermochronological data, the burial history indicates a four-stage thermal evolution of the WL Formation in the Changning shale-gas field: Early Mature from the middle Silurian to middle Permian, Middle Mature from the late Permian to Late Triassic, Late Mature from the Early Jurassic to Early Cretaceous, and Over mature since the middle Cretaceous, reaching a maximum burial depth of ~6000 m and maximum temperature of 190–200 °C at ca. 70–80 Ma. This evolution further suggests that a normal hydrostatic pressure index dominated the WL Formations in the Paleozoic. The gas generation and pressure index, however, have substantially increased since the Late Jurassic, particularly from the Early to middle Cretaceous, with a maximum pressure index of 2.1, which is indicative of the main shale gas accumulation and enrichment period in the WL Formation. Post-gas-generation structural deformation, uplift, and exhumation had a significant impact on shale gas enrichment, mainly through their influence on shale gas preservation. This suggests some relationships among the higher pressure coefficient of the WL Formation, the higher productivity and total gas content of the WL Formation, a weaker post-gas-generation structural deformation, and a weaker uplift, as indicated by the erosion and burial depth across the Changning shale gas field. Due to a significantly stronger cooling and uplift that occurred the in Late Cenozoic across the western Changning area, the pressure index decreased rapidly from ~2.0 to 1.0 with a normal pressure condition, indicating the destruction of the reservation condition in the WL Formation. • New low-temperature thermochronological data was from the SE Sichuan basin. • An accelerated cooling in the late Cenozoic was found. • Post-gas-generation deformation and exhumation controlled the shale gas enrichment. [ABSTRACT FROM AUTHOR]

The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration. • Comprehensive analysis the sedimentary environment based on three scales: outcrop, core and energy spectrum logging. • Later and small-scale tectonic uplift, moderate fracture development, good roof preservation are conducive to gas enrichment. • A structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration. [ABSTRACT FROM AUTHOR]

The Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation marine shale are the major shale gas exploration and development target in the Middle-Upper Yangtze region. Although three national shale gas demonstration areas have been built and several high-yield shale gas wells have been discovered in the Wufeng Formation and Longmaxi Formation, shale gas in these areas has not been fully commercialized because the enrichment degree of shale gas varies greatly in different tectonic settings. By analyzing the formation processes and distribution characteristics of the organic-rich shale, reconstructing the burial history and hydrocarbon generation history, and comparing the shale gas enrichment and preservation conditions in different tectonic settings in South China, this paper points out that (1) The craton depression and foreland basin on the cratonic margin are favorable zones for the development of organic-rich shale. Because the Yangtze plate is small, the foreland basin is greatly affected by the input of terrigenous clastic and the thickness and area of organic-rich shale in the craton basin is larger than that in the foreland basin. The organic-rich shale is mainly distributed in south Sichuan deep-water shelf and west Hubei-east Chongqing deep-water shelf, and the enrichment interval is the Dillcellograptus complexus-Cystograptus Vesicolus graptolite zone from the Wufeng Formation to the bottom of Longmaxi Formation are favorable intervals for shale gas enrichment. (2) Since the Late Jurassic, significant differential intracontinental tectonic deformation, uplift and denudation occurred in the Middle-Upper Yangtze region. Moderate compression and uplift were beneficial to the development of micro-fractures and bedding fractures in shale, resulting in good preservation conditions of shale gas reservoirs with a high-pressure coefficient. In contrast, strongly deformed areas, where faults and high-angle large fractures were developed, are not conducive to the preservation of shale gas reservoirs. (3) The craton depression of the Middle-Upper Yangtze region, where organic-rich shale was deposited, is favorable to shale gas enrichment because it provides a good material basis, and also a relatively stable and compression-resistant tectonic environment for later tectonic deformation and uplift-derived destruction. Based on the analysis and evaluation of tectonic construction–transformation conditions under the macro-control of plate tectonics, it can well explain the existing commercial shale gas discoveries and failure cases and can guide the optimization of future exploration targets. • ►Deep water in the craton depression controlled the distribution of organic-rich shale. • Stable tectonic settings are favorable for shale gas enrichments. • Two depressions in Yangtze Craton are the most favorable areas for shale gas accumulation. [ABSTRACT FROM AUTHOR]

Numerous studies have been conducted on the isotopic geochemical characteristics of shale gas. However, a systematic study of the relationship between the isotopic geochemical characteristics and gas content has not been addressed to date. In this study, we investigated the geochemical and isotopic compositions of shale gas samples, and the gas content of the Lower Silurian Longmaxi marine shale in the Huangjinba area, southern Sichuan Basin, China. In addition, we analyzed the quantitative relationship between the geochemical parameters and the gas content. The Longmaxi shale gas is a dry gas with a low wetness (0.12%–0.67%), dominated by methane (89.49%–99.00%) with a small amount of ethane (0.11%–0.61%). The average values of δ13C methane , δ13C ethane and δ13C propane are −29.8‰, −35.0‰, and −33.2‰, characterized by a partial isotopic reversal (δ13C methane > δ13C propane > δ13C ethane) with a maturity level (Ro ≈ 2.30%–2.51%). The total gas content of the Longmaxi shale varies widely from 0.42 m3/t to 3.88 m3/t. Correlation analyses revealed that the ethane isotope (δ13C ethane) and the magnitude of isotopic reversal (δ13C methane - δ13C ethane) exhibit strong correlations with the total gas content and the free gas content. This study demonstrates that carbon isotopic reversal of shale gas largely depends on the secondary cracking, and thermal maturity and residual liquid hydrocarbons content are important factors affecting the magnitude of carbon isotopic reversal. Based on the quantitative study conducted in this paper, we provide a new proxy for predicting the gas content of high maturity shale using an isotopic method. • Carbon isotopic reversal of shale gas largely depends on the secondary cracking. • Sufficient residual liquid hydrocarbon is necessary for the carbon isotopic reversal. • Wetness of 1.4% in high maturity shale gas indicates the peak of secondary cracking. • δ13C methane –δ13C ethane can be used to predict the gas content of high maturity shale. [ABSTRACT FROM AUTHOR]