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• 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]

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]

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]

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]

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]