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Low-field nuclear magnetic resonance (LF-NMR) technology plays a growing role in studying reservoirs for oil displacement characteristics. To better explore the reservoir characteristics of Da'anzhai in the Sichuan Province of China, this paper uses LF-NMR imbibition flooding experiments to study the improvement of oil displacement efficiency for shale oil reservoirs in Southwest China by different imbibition flooding technologies. In this article, experiments in scanning electron microscopy, X-ray diffraction analysis, and rock mechanics were conducted to analyze the geological features of the reservoir in the study area. In combination with the test results of the nuclear magnetic resonance method, the field technology has been reformed to improve the oil recovery efficiency. The results show that the Da'anzhai area is mainly composed of interbedded shale and limestone, with a relatively low organic carbon content and low average porosity. The pores shouted are predominantly concentrated in the range of 1–100 nm, and there are micrometer-sized pores. The mineral composition of the area is primarily quartz, dolomite, and calcite, rich in clay minerals. The degree of the development of natural fractures is not high, and the mean coefficient of stress differential in two directions is 0.19. The content of brittle minerals is greater than 50%, meaning that the overall compressibility is good. The results of the stratified T2 test show that the imbibition efficiency of shale in this area is low. The imbibition efficiency of the three cores is the best in 0–20 mm, and the imbibition efficiency is low in the 40–60-mm section. The optimum imbibition formula 2 has an apparent promoting effect on the imbibition of shale in this area. Based on the optimal formula system of imbibition flooding experiments, the average reservoir volume of reconstruction (SRV) in the Sichuan Basin increased from 39 million cubic meters to 46 million cubic meters. The oil production test went from "seeing boiling oil" to almost 2 tons/day, making a significant breakthrough in "oil production." As a result, LF-NMR technology is used to investigate the effects of core imbibition and oil displacement. The results can be used as a guide for applying on-site oil production technology transformation, which is of constructive importance for improving production. [ABSTRACT FROM AUTHOR]

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels. [ABSTRACT FROM AUTHOR]

Complex and vertically overlapped lithologies exist for the high-quality shale oil reservoir of the Lianggaoshan formation in the Sichuan basin. Continental shale oil reservoirs grow bedding, lamina, and natural fractures, challenging fracture network morphology control and monitoring in horizontal well multistage fracturing technology. This study proposed a true triaxial monitoring method based on distributed fiber optic sensing for the outcrops with good emergence, occurrence, and clear lithology. The U-shaped plane layout style is adopted to monitor the initiation and propagation of hydraulic fracturing in the full-time domain. The study first found that the main vertical fracture perpendicular to the wellbore and lamina fracture had an asymmetric propagation pattern, and fracture initiation was instantaneous and had a characteristic of elastic recovery. The asymmetric propagation of multistage/multicluster fractures can be grouped into nine types combing with the relative angle and position variation. Simultaneously, there is a 2-s time difference when the vertical fracture reaches the boundary on two sides and an included angle between the vertical fracture and the maximum horizontal principal stress. Besides, the low-viscosity slick water will filtrate into the existing lamina plane after the initiation of vertical fracture under high-pressure pumping. It is helpful to open the lamina and form a complex fracture network of vertical fracture cross lamina fracture, usually in the form of a cross, I-shaped, and fishbone. This experimental study can effectively improve the calculation accuracy of stimulated reservoir volume (SRV) and shale oil production and guide the fracturing stimulation monitoring of adjacent wells. Highlights: This study proposed a physical monitoring method for laboratory true triaxial fracturing based on distributed fiber optic sensing. The asymmetric propagation pattern of fracture swarms in laminated continental shale oil reservoirs reflected the propagation speed and orientation. This article found a strain elastic recovery property after the vertical hydraulic initiation, which can guide the sand addition timing. This research summarized nine asymmetric propagation behaviors and three fracture network morphologies in the oilfield. [ABSTRACT FROM AUTHOR]

Taking the Longmaxi deep-marine shale gas reservoir in Zigong region as the research target, this paper aimed to characterize the nano-scale pore structure and investigate the reservoirs' heterogeneity based on fractal theory. By conducting a series of experimental studies, mainly including TOC, XRD, gas adsorption (N2 and CH4), we were able to clarify the main controlling factors for the heterogeneity of deep shale pore structure. Our results indicated that the deep marine shale possessed a significant amount of organic matter, as the average TOC value is 3.68%. The XRD analysis results show that quartz and clay were the main mineral types, and the total content of these two minerals averaged 77.5%. Positive correlations were observed between TOC and quartz, while TOC decreases as the clay mineral increases, this discovery indicating that quartz is biogenic. Based on FHH (Frenkele-Halseye-Hill) method, by using the LTNA adsorption isotherms, we took relative pressure P/P0 = 0.5 as the boundary, then two separate fractal dimension were deduced, D1 and D2 represent the fractal characteristics of small and large pores, respectively. Our study revealed that both D1 and D2 demonstrated positive correlations with N2 adsorption pore volume and adsorption specific surface area, while negatively correlated with the adsorption average pore diameter. Moreover, the two fractal dimensions showed positive associations with TOC and quartz and negative associations with clay. Additionally, D1 and D2 also demonstrated a positive correlation with Langmuir volume. The presence of micropores was found to significantly influence the formation of an irregular pore structure in shale. As the pore size decreased, the adsorption specific surface area increased, resulting in a more intricate pore structure, and the fractal dimension of the pores elevated, ultimately. This intricate structure is beneficial for the accumulation of shale gas. These research findings offer valuable insights for the comprehensive assessment of deep shale gas, and enrich our knowledge of enrichment mechanisms in deep shale gas reservoirs. [ABSTRACT FROM AUTHOR]

The marine shale within the Sichuan Basin constitutes China's significant shale gas production, featuring old formation age, high degree of thermal evolution, multiple tectonic movements, and complex structural conditions. However, there are significant differences in the shale gas preservation conditions and reservoir quality in different areas, limiting future large-scale exploration and development. Pore structure significantly influences shale reservoir quality, gas content, and exploration of shale gas occurrence, migration, and enrichment mechanisms. The influence of structural-dominated preservation conditions on shale pore structures is essential to comprehend for effective shale gas exploitation. This study employs field-emission scanning electron microscopy in conjunction with other techniques (low-temperature N2 adsorption, low-temperature CO2 adsorption, and nuclear magnetic resonance) for detailed analyses of the pore structure across varied structural zones, revealing the influence of structural attributes, fault systems, depth of burial, and formation pressure on pore architecture, and examining the relationship between pore structure and shale gas preservation conditions. The results show that stable structural condition is conducive to the development and preservation of shale pores. Structural compression causes inorganic and organic pores to become narrow and elongated due to shrinkage, with a significant increase in microfractures. The porosity of shale with stable structural conditions exhibits markedly increased porosity compared to samples under structural compressions. Under conditions of similar TOC and mineral composition, the pore size distribution (PSD), pore volume (PV), and specific surface area (SSA) of shale after structural compression are significantly lower than those of samples with stable structural conditions. As the burial depth increases, the shale porosity shows a decreasing trend, but the decrease is limited. Burial depth significantly impacts the SSA and PV of high-TOC samples (3%-6%). As the burial depth increases, both SSA and PV show a significant decreasing trend. When the burial depth reaches 4000 m, SSA and PV tend to concentrate. The formation pressure coefficient is an important factor for the development and preservation of shale pores, and porosity is positively correlated with the formation pressure coefficient. Increased formation pressure coefficient indicates superior preservation conditions and enhanced pore development. [ABSTRACT FROM AUTHOR]

In this paper, taking the Wufeng Formation-Longmaxi Formation shales in the southeastern region of the Sichuan Basin as an example, the thin section, X-ray, geochemical testing and TIMA techniques are used to systematically study the source analysis and characterization of quartz fractions, and in turn, the mechanism of the development of highly brittle shale reservoirs is revealed. The results of the study show that the high quartz mineral content segments are well stacked with the organic matter enriched segments. Excess silica occurs in the lower part of the Wufeng -Longmaxi Formation, and some samples in the middle and upper part of the Wufeng and Longmaxi Formation have excess silica deficit; the K2O/Na2O ratio is generally >1, reflecting that the reservoir quality is affected by the biogenic silica. Land- sourced detrital quartz grains, on the other hand, are significantly larger and are generally distributed over a range of tens to more than a hundred micrometers, often with clay minerals and organic matter around the periphery. Biogenic siliceous fossils are mainly developed in the lower part of the Wufeng-Longmaxi Formation, dominated by biogenic siliceous remains such as radiolarians. TIMA test results show that quartz belongs to the mineral type with absolutely dominant content ratio in the bottom samples of the Wufeng-Longmaxi Formation and reflects the characteristics of fine-grained-muddy/ carbonaceous horizontal laminar deposition. There are three different types of quartz grain distribution patterns in shale reservoirs, including excess silica type, multi-source silica type, and land-source silica type. The layers of highly brittle shale reservoirs are all at the bottom of Wufeng-Longmaxi Formation, which is rich in biogenic silica, and at the same time, they are also in the active layers of montmorillonite and other abundant volcanic activities, and they are developed in the closed basins as well as the deep-water land scaffolds, so that the reservoirs have a good self-sealing; at the same time, the combination of microcrystalline quartz+organic matter makes the reservoirs have an excellent mechanical brittleness. [ABSTRACT FROM AUTHOR]

The Permian shale in Northeast Sichuan is an important shale oil and gas resource potential area, and the study of its organic matter characteristics and paleoenvironmental analysis is of great significance for revealing the shale oil and gas formation mechanism and resource evaluation. In this study, the organic matter of Permian shales in northeast Sichuan was carefully studied based on various analytical tools, such as petrology, laser Raman, microscopy, and principal trace elements, and the paleoenvironmental parameters of the shales were comprehensively analysed. A detailed study of the organic matter characteristics of Permian shales in northeast Sichuan reveals important features such as organic matter fractions, structural characteristics, maturity and sources. The results show that the organic matter of the shale consists mainly of solid bitumen, putrescine group, specular group and multicellular planktonic algae. Petrological observations and laser Raman analyses indicate a high maturity of the organic matter and a high content of organic carbon (TOC), showing good hydrocarbon potential. In this study, we reconstructed the palaeoenvironmental parameters and inferred the palaeoenvironmental evolution through palaeoenvironmental analyses of Permian shales in northeast Sichuan. The results of the comprehensive multi-indicator study show that the type of palaeoenvironment at the time of shale deposition was mainly an anoxic-reducing environment, and the depositional conditions were favourable to the enrichment and preservation of organic matter. In summary, the organic matter characteristics and paleoenvironmental analyses of the Permian shales in Northeast Sichuan provide important geological background information for an in-depth understanding of the formation mechanism, exploration potential and development prospect of shale hydrocarbons in this area. The results of this study can provide a scientific basis for the evaluation and development of shale oil and gas resources in this area, which is of great significance to geologists and the energy industry. [ABSTRACT FROM AUTHOR]

Permeability is a critical parameter for effective shale gas extraction. Shale reservoirs are dense, and fluid can hardly flow through shale rock under pressure, greatly limiting the permeability, which is commonly obtained by the steady-state core analysis method. At the same time, shale reservoirs contain abundant clay minerals and micro- and nanopores, resulting in favorable spontaneous imbibition ability. At present, most studies for predicting the absolute rock permeability are based on the imbibition process, while the combined influences of the dynamic capillary pressure, slip effect, and osmotic pressure have been considered in few effective permeability prediction studies. First, an imbibition experiment of an undersaturated shale core was conducted to obtain the spontaneous imbibition coefficient of shale. Furthermore, considering the influences of the slip effect, osmotic pressure, tortuosity, and dynamic capillary pressure, an effective permeability prediction method was established based on the imbibition coefficient of shale reservoirs. Combined with previous experimental data, the permeability calculated by this model is close to the experimental data, and the maximum error is less than 11.6%, verifying the effectiveness of the model. The permeability of the lower Silurian Longmaxi Formation shale in the Changning area, Sichuan, can be obtained by using this method. The results showed the following: (1) the calculated result error with the model results of the literature is 1.43 to 3.57%, which shows good contrast. The established effective permeability prediction method considers more comprehensive factors, requires fewer parameters, involves a clear calculation process, accurately meets the production demand, and agrees better with the real formation conditions. (2) The effects of the osmotic pressure, tortuosity, and slip length on the effective permeability successively decrease. Ignoring the osmotic pressure and slip length could lead to a higher effective permeability, while ignoring the tortuosity could lead to a low effective permeability. (3) The effective permeability of reservoirs can be obtained by using this method with different working fluids, and reservoir damage can be rapidly evaluated, which has guiding significance for selecting reasonable working fluids. The method provides a new way to evaluate the effective permeability of shale reservoirs effectively and quickly. [ABSTRACT FROM AUTHOR]

Shale oil is currently a key area for unconventional oil and gas exploration and represents a new field to ensure national energy security. As a major contributor to unconventional oil and gas in China, Sichuan Basin has enormous potential as an oil and gas resource.The exploration of Jurassic shale oil reservoirs is in its infancy, with diverse reservoir lithology and the ability to store oil and gas. Therefore, whether the generated hydrocarbon substances in shale are still gathering in situ or have undergone short distance migration plays a guiding role in the formulation of the next oil and gas exploration and development plan. In this study, we focused on the shale oil reservoirs of Lianggaoshan Formation in northeastern Sichuan Basin. Firstly, the lithological characteristics of shale oil reservoirs, as well as the physical and geochemical characteristics of different lithological reservoirs were determined via core observations and conventional reservoir geological characteristic experiments. Secondly, Laser confocal scanning microscopy (LCSM) was used to conduct three-dimensional modeling and quantitative testing of the shale oil occurrence characteristics of different lithological reservoirs. Finally, based on the differences in the occurrence of hydrocarbons in different lithological reservoirs and the physical characteristics of rocks, hydrocarbon migration is traced.The following three insights were obtained based on the experimental results: The crude oil produced was primarily composed of light hydrocarbons.The physical properties of sandstone profiles are superior, with a higher proportion of light hydrocarbons compared to shale reservoirs.The above experimental results indicate that hydrocarbons generated in shale migrated over short distances and were enriched in adjacent sandstone and siltstone bands with relatively desirable physical properties. This study provides experimental means and data support for subsequent flowability evaluations and development plan preparation for Jurassic shale oil extraction in northeastern Sichuan. [ABSTRACT FROM AUTHOR]

The Longmaxi Formation in the Sichuan Basin is a hotspot formation for shale gas exploration. In this paper, taking the Longmaxi Formation shale in Yuxi area as an example, a large number of TOC tests, X-diffraction whole-rock mineral fraction tests, electron microscope observations, physical properties, gas content, and CT scanning experiments were carried out, which in turn analyzed the characteristics of the shale gas reservoir and the factors influencing the gas content. The results of the study show that there are seven types of shale facies developed in Yuxi area, which are organic-rich siliceous shale facies (I), organic-rich carbonate-siliceous shale facies (II), organic-rich clayey shale facies (III), organic-poor clayey shale facies (IV), organic-poor carbonate-siliceous shale facies (V), organic-poor siliceous shale facies (VI), and organic-poor siliceous-carbonate shale facies (VII). The microstructural characteristics of the shale reflect that it was disturbed by multiple environmental factors at the time of deposition, and the sources of brittle minerals include both terrestrial clasts and biogenic siliciclastics. The bottom 30 m shale of Longmaxi Formation has good physical properties and gas content, which is a high-quality target section for shale gas exploration and development. TOC, Ro, permeability, quartz content and clay mineral content all have a significant effect on shale gas content and are important control factors for shale gas content. [ABSTRACT FROM AUTHOR]

Shale gas exploration has achieved global success in marine shales. This study analysed geochemical, mineralogical, porosity, permeability and gas‐bearing parameters of organic‐rich shales in the Permian Wujiaping Formation in the Sichuan Basin. A comprehensive comparison was conducted with the Longtan Formation transitional shales and typical commercially developed marine shales. The results showed that: (1) siliceous shale within the Wujiaping Formation exhibits total organic carbon content ranging from 0.60% to 9.53% (average 4.45%) and vitrinite reflectance (Ro) ranging from 1.83% to 2.14% (average 1.98%), indicating an overmature stage of hydrocarbon generation. Porosity varies from 0.48% to 11.8% (average 4.94%), with an average content of 51.4% brittle minerals (quartz+calcite+dolomite) and calculating gas content exceeding 3 m3/t based on logging data. Effective sealing is achieved by the overlying carbonate of the Changxing Formation and the underlying carbonate of the Maokou Formation. (2) The primary storage space of the siliceous shale in the Wujiaping Formation encompasses diverse organic matter pores, clay mineral pores and microfractures. The porosity and permeability of the Wujiaping Formation marine shale ranges from 0.48% to 11.8% and 0.0053 to 0.8450 mD. Total gas content was estimated between 3 to 12 m3/t averaging 6 m3/t. (3) By comparing Permian Wujiaping Formation shales with Longtan Formation transitional shales, Wufeng Formation‐Longmaxi Formation shales and the typical North American marine gas shales (such as Barnett, Ohio, Antrim, New Albany, etc.), we conclude that marine siliceous shales within the Wujiaping Formation exhibit enrichment conditions comparable to established marine shales and superior to Permian transitional shales. The favourable upper and lower seals of the Wujiaping Formation resemble those of the Barnett shale gas reservoirs. In conclusion, the marine shale in Wujiaping Formation holds potential for substantial shale gas reservoirs and is poised for strategic exploration and development breakthroughs in the northeast and east Sichuan Basin. [ABSTRACT FROM AUTHOR]

Casing deformation is evident during the development of shale oil and gas wells in the Sichuan and Junggar Basins in China. Their casing deformation characteristics, distribution law of deformation points, and main controlling factors were analyzed. According to the analysis results, shear is the main cause of casing deformation of shale oil and gas wells in the Sichuan and Junggar Basins in China and has the characteristics of "a dense heel end and a sparse toe end". Faults account for 75% of casing deformation points, and fault slip caused by multi-stage fracturing is the primary factor responsible. The calculation model for fault slip that takes into account fracturing fluid invasion was established, and the dynamic variation law of fault slip was clarified: the fracturing fluid intruded into the fault, the relative dislocation of the damaged fault was caused by gravity, and the fault slippage was caused by the increase in fault activation length. This resulted in a linear increase in fault slippage, and the slippage reached its maximum when the fracturing fluid completely penetrated the fault and reached the fault boundary. The slip amount has a positive correlation with the fault length and the in situ stress difference; it increases first and then decreases with the increase in the fault dip angle. The slip amount reaches its maximum when the fault dip angle reaches 45°. [ABSTRACT FROM AUTHOR]

The deep shale of the Wufeng–Longmaxi Formation in the southern Sichuan Basin has high gas potential. The development characteristics of lamination could significantly impact reservoir property. Samples were investigated using microscopic observation, element analysis, organic petrology analysis, mineralogy analysis, and pore structure analysis to determine the types of laminae and laminasets, clarify the formation conditions of argillaceous lamina and silty lamina as well as their relationships with the sedimentary environment, and explore the influence of laminae on shale reservoir property. Results indicate that the Wufeng Formation shale exhibits weak development of laminae due to bioturbation, while the Longmaxi Formation shale develops continuous, parallel, and plate-like laminae. Compared with light silty lamina-rich shale, dark argillaceous lamina-rich shale usually develops in an anoxic reduction environment, with higher total organic carbon content, porosity, pore volume, specific surface area, and more developed organic matter pores, which can provide greater space for shale gas adsorption and storage. Shales in the middle section of the Longmaxi Formation are characterized by the development of silty-argillaceous interbedded type laminaset, which have good reservoir performance, making them the primary target for deep shale gas exploration and development. [ABSTRACT FROM AUTHOR]

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

Shale oil, an important component of unconventional oil and gas resources, mainly exists in the storage spaces such as shale pores, microfractures, etc. Porosity is commonly used to quantitatively describe the storage space of shale oil and is a key parameter in reservoir evaluation. However, there are significant differences in the results by existing experimental methods for porosity measurement, and moreover, it is difficult to compare the porosity obtained by the experimental measurement method with the logging calculation method. It is urgent to explore reasons for the differences in porosity measurement between various porosity experiments and logging calculations of the shale oil reservoir, and propose an effective method for shale oil reservoir to characterize porosity. In this research, core samples of shale oil reservoirs from the Lianggaoshan Formation of the Sichuan Basin were selected to measure the porosity by means of experimental methods including helium gas charging, saturation liquid method, nuclear magnetic resonance (NMR), etc. Meanwhile, porosity was calculated using the combination method of lithology scanning (LS) logging and conventional logging as well as the NMR logging method. Subsequently, porosity experimental results and logging calculation results were compared to clarify the applicability of various porosity characterization methods. The research results indicate that: 1) The porosity measurement results by the saturation liquid method and the NMR experimental method are close, both greater than that using the helium gas charging method; 2) The hydrogen signal of the dry-state sample is significant in the NMR experiment, mainly originating from organic matter and clay minerals; 3) The NMR short relaxation component in the water-saturated state primarily reflects the signal of organic matter and clay mineral matrix, while the long relaxation component reflects the pore fluid component; 4) After deducting the NMR signal of the dry-state core, the core NMR porosity measurement results under the water-saturated state agree well with that using the saturation liquid method, which is an indicative of effective reservoir porosity; 5) The NMR logging is limited by its echo spacing and cannot reflect the signal from organic matter and the crystal water in clay minerals at T2 < 0.3 ms. Taken together, the porosity measurement method of subtracting the dry-state NMR signal from the water-saturated state NMR signal is considered effective and can be used to reflect the porosity of shale oil reservoirs in the Lianggaoshan Formation of the Sichuan Basin. [ABSTRACT FROM AUTHOR]

As a typical rock, shale's reservoir depth is about 1500–4000 m, and the temperature of the shale reservoir at this depth is 150 °C. Therefore, in order to study the dynamic strength of shale at this temperature, it is necessary to consider the effects of temperature and strain rate on the dynamic strength of shale, and then establish the damage constitutive model of shale. This paper took black shale from the Sichuan Basin as the research object, combined it with the separated Hopkinson bar experiment and temperature control system, and conducted the Hopkinson bar experiment on shale at room temperature, 60 °C, 90 °C, 120 °C, and 150 °C, and at three groups of air pressures of 0.2 MPa, 0.3 MPa, and 0.4 MPa. The stress–strain curves of shale at the same strain rate and different temperature and at the same temperature and different strain rate were obtained. In the temperature difference range of this experiment, the dynamic strength of the sample presented two opposite trends (increasing and decreasing) with the increase in temperature, which was determined via the direction of the bedding. The peak strength linearly increased with the increase in strain rate. Based on the Weibull statistical distribution and the D–P failure criterion, a statistical damage constitutive model of shale dynamic strength considering the effects of temperature and strain rate was obtained. By modifying the parameters F0 and m, the dynamic strength statistical damage constitutive model of shale was in good agreement with the experimental results. [ABSTRACT FROM AUTHOR]

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

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

The shale reservoirs of the Lower Cambrian Qiongzhusi Formation are widely distributed in the Sichuan Basin and have abundant gas resources. However, the shale lithofacies of the Qiongzhusi Formation are complex due to frequent sea level changes. The reservoir pore structure characteristics and gas content of different shale lithofacies vary significantly, which makes identifying the 'sweet spot' a challenging task. In this study, core observation and X-ray diffraction (XRD) were used to analyze the lithofacies types and characteristics of the study area. The pore types of different shale lithofacies were observed using field emission-scanning electron microscopy. Pore structures were studied using low-temperature gas (including N2 and CO2) physisorption, and the pore volume (PV), specific surface area (SSA) and pore structure were systematically characterized. The primary factors influencing pore formation in different types of shale lithofacies were analyzed by combining geochemical experiments and mineral contents. The results indicate that the lithofacies of the Qiongzhusi Formation shale in the study area can be classified into five categories according to mineral compositions: Siliceous argillaceous shale (CM-1), Argillaceous siliceous mixed shale (M-2), Argillaceous siliceous shale (S-3), Siliceous rock (S) and Calcareous siliceous shale (S-2). Pores are abundant in S-3 shale, M-2 shale and CM-1 shale. The S-3 shale is more enriched in organic pores and clay mineral pores compared to other lithofacies shales, and the pore morphology is mainly wedge-shaped and plate-like. M-2 shale and CM-1 shale are rich in clay minerals and mainly develop clay mineral pores and are mainly wedge-shaped and plate-like. The S shale and S-2 shale mainly develop interparticle pores and clay mineral pores, which are mainly slit-like. The results show that TOC, pyrite content, quartz and feldspar mineral content, clay mineral type and content affect the pore structure in the study area. Quartz and feldspar content have a negative effect on micropore and mesopore volumes. TOCs have a weak positive correlation with micropore volume and micropore SSA. Clay mineral content has significant positive effects on the PV and SSA of micropores and mesopores, indicating that clay mineral content is the main factor affecting the pore structure of shale. [ABSTRACT FROM AUTHOR]

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

In order to explore the reservoir characteristics of shallow shale gas reservoir in Zhaotong and its differences with other shale gas blocks in Sichuan Basin, the pore structure of Zhaotong shale gas reservoir was comprehensively studied by various means, including X -ray diffraction, gas adsorption (CO2, N2), NMR, and field emission-scanning electron microscopy. In addition, the adsorption capacity of samples in this area was measured by volume method and the main controlling factors were analyzed. The results show that the shale reservoir in the Zhaotong demonstration area is dominated by clay and quartz minerals, with an average content of 23.1% and 34.3%, respectively. Pore-size distribution is concentrated in the range of 0.5–1000 nm, with micropore and mesopore as the main body. Scanning electron microscopy shows that the reservoir space types are mainly organic pores, intergranular pores, intragranular pores, and microfractures. Among them, organic pores are the most developed and most of them appear in large area network structures with good connectivity. The results of the methane isothermal adsorption test show that the adsorption capacity of shale in the Zhaotong area is positively correlated with TOC content, specific surface area, and micropore volume ( D ≤ 10 nm), but poorly correlated with total pore volume. Due to the influence of mineral types and genesis, the adsorption capacity of shale in this area is negatively correlated with clay content and poorly correlated with quartz content. Through data comparison and analysis, the adsorption capacity of shale in the Zhaotong area is higher than that in the Fuling and Changning–Weiyuan areas. Additionally, due to the influence of mineral genesis, the changing trend of shale adsorption capacity with quartz content is also different in different regions. [ABSTRACT FROM AUTHOR]

Thermal maturity of the shales from the Ziliujing Formation of the Jurassic age in the Sichuan Basin is in the hydrocarbon generation window, which makes it a candidate for shale oil and gas development. The meso- and macropore characteristics and heterogeneity of shales are important factors affecting the occurrence and development of oil and gas. However, the meso- and macropores of the Ziliujing shales have not been systematically studied. Thus, the mineral compositions and total organic carbon (TOC) of samples from this formation, as well as its pore structure, are analyzed by low-temperature N2 adsorption technique. Moreover, the heterogeneity of the pores was determined by multifractal analysis. The results show that the Ziliujing shales can be classified into three types according to the distributions of mineral compositions of carbonate and mixed and argillaceous shales. Results revealed that the smallest meso- and macropore volume (PV), the smallest specific surface area (SSA), and the largest average pore diameter (APD) occur in the carbonate shales. However, the largest PV and SSA and the smallest APD are observed in the argillaceous shales. The porosity of carbonate shales is mainly concentrated between 5 nm and 30 nm. Compared with carbonate shales, the porosity with pore sizes less than 30 nm of mixed and argillaceous shales shows a rapid increase. Furthermore, inorganic minerals are the main factors affecting the pore distributions, while TOC shows a weak effect. Herein, clay minerals significantly increase the mesopore volume and the pore number with a size of less than 30 nm. The Dq-q curves reveal that the meso- and macropore distributions of Ziliujing shales show multifractal behavior, but the multifractal characteristics of pores of various shales are distinctly different. The information dimension D1, the Hurst exponent H, and the width of the right side D0–D10 are key indicators to distinguish the local variations within the pore structure of different types of shales. The carbonate shales have the largest multifractal spectra width and the smallest D1 and H, while the opposite trend is found for the argillaceous shales. Clay minerals reduce the heterogeneity of the meso- and macropore distributions and increase the pore connectivity. Nevertheless, the carbonate minerals exhibit a reverse trend. Finally, it was found that TOC does not impact pore complexity as much. Collectively, this study supports our understanding of the occurrence of shale oil within various reservoir facies, thereby providing a guideline for future explorations in the Ziliujing Formation of the Jurassic age in the Sichuan Basin. [ABSTRACT FROM AUTHOR]

Low-resistivity shales are widely developed in the Sichuan Basin. The production of low-resistivity shale gas reservoirs ranges from high to low to none. The existing methods for gas-content prediction cannot accurately predict the gas content of low-resistivity shale. This increases the risk of shale-gas exploration. To prove that the random forest algorithm has apparent advantages in predicting the gas content of low-resistivity shale and reducing the risks associated with shale-gas exploration and development, three prediction methods were selected in this paper to compare their effects. The first method is known as the grey-correlation multiple linear regression method. Low-resistivity shale-gas content logging series were optimized using the grey-correlation approach, and then the low-resistivity shale-gas-content prediction model was established using the multiple linear regression method. The second method we selected was the resistivity method. The improved water-saturation model was used to predict the water saturation of low-resistivity shale, and then the gas content of low-resistivity shale was predicted based on the free-gas content and the adsorbed-gas-content model. The random forest algorithm was the third method we selected. Fourteen logging series were used as input data and the measured gas content was used as supervised data to train the model and to apply the trained model to the gas-content prediction. The findings demonstrated that the grey-correlation multiple regression method had poor accuracy in predicting gas content in low-resistivity shale; The resistivity method accurately predicted water saturation, and the predicted gas content was higher than the actual gas content. Because the random forest algorithm accurately predicted low-resistivity shale-gas content, its use in the Sichuan Basin was advantageous. The selection of a low-resistivity shale-gas-content prediction model was guided by the research findings. [ABSTRACT FROM AUTHOR]

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

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Shale oil reservoirs in the Daanzhai section of central Sichuan are mainly developed in the Daer subsection, with a rich resource base and great exploration and development potential. However, the shale oil reservoir is characterized by shale and limestone interactions, poor physical properties, undeveloped fractures, and large differences in the fracture pressure of interactive reservoirs. Therefore, it is necessary to use temporary plugging and diverting fracturing technology to improve the complexity of fractures in reservoir reconstruction. To this end, an experimental device was innovatively established that takes into account the morphology of fractures and the permeability of reservoirs, and it can evaluate the temporary blocks and turns within third-level fractures in a reservoir. It can simulate third-level turning fractures under conditions involving 3–15 mm crack openings and different roughness values. Using this device and method, the combination and particle-size optimization experiments involving the temporary plugging agents used in the field were carried out, and the field tests were carried out in Well Long'an 1 and Well Ren'an 1 in the Sichuan Basin. The test results show that the pressure response after temporary plugging is obvious, which can significantly improve microseismic event points and increase the reservoir's reconstruction volume. Compared with Well Nanchong 2H, the length in kilometers of the SRV after tackling key problems increases from 3918 × 104 m3 to 4578 × 104 m3, an increase of 17%. The average crack length increased from 265 m to 321 m, an increase of 21%, achieving a significant breakthrough in the "oil production gap". [ABSTRACT FROM AUTHOR]

The Ordovician Wulalike Formation in the northwestern Ordos Basin is a new prospect for exploring marine shale gas in China, facing prominent problems such as unclear reservoir conditions and the distribution of enrichment areas. The types of reservoir space, fracture development, porosity composition, and physical properties of the lower Wulalike Formation are discussed through the multi-method identification and quantitative evaluation of reservoir space for appraisal wells. The Wulalike Formation in the study area contained fractured shale reservoirs with matrix pores (mainly inorganic pores) and permeable fractures. The fracture system of the lower Wulalike Formation is dominated by open bed-parallel fractures that are intermittent or continuous individually, with a width of 0.1–0.2 mm and spacing of 0.5–14.0 cm. The fracture-developed intervals generally exhibit bimodal or multimodal features on NMR T2 spectra and have a dual-track feature with a positive amplitude difference in deep and shallow resistivity logs. The length and fracture porosity of fracture-developed intervals varied greatly in different parts of the study area. In the Majiatan-Gufengzhuang area in the southern part of the study area, the fracture development degree generally decreased from west to east. In the Shanghaimiao area in the central part of the study area, fractures were extremely developed, the continuous thickness of the fracture-developed interval was generally more than 20 m, and the average fracture porosity was higher than 1.3%. In the Tiekesumiao area in the northern part of the study area, the fracture development degree was generally lower than that in the central and southern parts of the study area and also showed a decreasing trend from west to east. The lower Wulalike Formation had a total porosity of 2.46–7.08% (avg. 4.71%), roughly similar to the Longmaxi Formation in the Sichuan Basin, of which matrix porosity accounts for 34.0–90.0% (avg. 61.1%) and fracture porosity accounts for 10.0–66.0% (avg. 38.9%). From this, it could be inferred that the shale gas accumulation type of the lower Wulalike Formation in the northwest margin of the basin is mainly a fractured shale gas reservoir controlled by structure, and its "sweet spot area" is mainly controlled by tectonic setting and preservation conditions. This indicates that the Wulalike Formation in the northwestern Ordos Basin has good shale gas exploration prospects, and a large number of fault anticlines or fault noses formed by reverse dipping faults have the potential of favorable exploration targets. [ABSTRACT FROM AUTHOR]

Lacustrine shale has garnered significant attention due to its significant resource potential. The Jurassic shale in the Sichuan Basin is an important target for lacustrine shale exploration in China. However, previous studies have predominantly focused on the Da'anzhai member of the Ziliujing Formation, and little attention has been paid to the shale of other strata. This paper aims to address this gap by investigating the Jurassic Dongyuemiao member in the Sichuan Basin. The study systematically characterizes the geological properties of the Dongyuemiao shale system, reconstructs the paleosedimentary environment, identifies the key factors influencing organic matter (OM) enrichment and physical properties, and assesses its resource potential through comparative analysis. Our results show that the Dongyuemiao shale was deposited in an oxic and semi-humid sedimentary environment characterized by intense weathering conditions. The enrichment of OM in the shale is primarily controlled by redox conditions and salinity, with redox conditions playing the most crucial role in OM accumulation. In terms of pore system characterization, clay mineral-associated pores dominate the pore types in the Dongyuemiao shale, while two types of organic matter-associated pores are also widely observed. The development of framework grain-associated pores is limited and only present in certain siliceous and carbonate minerals. The shales of the Dongyuemiao member and the Da'anzhai member exhibit slight differences in TOC content. However, the kerogen in the Dongyuemiao member displays higher hydrocarbon generation potential, and the Dongyuemiao shale exhibits more favorable pore structure parameters. Overall, the Dongyuemiao shale does not exhibit any significant disadvantages compared to the Da'anzhai shale. Therefore, it deserves greater attention in future exploration endeavors. The research findings presented in this paper provide a solid theoretical foundation for expanding the exploration scope of lacustrine shale in the Sichuan Basin. [ABSTRACT FROM AUTHOR]

The Jurassic Da'anzhai Member of the Sichuan Basin has good prospects in shale oil exploration and development. However, the lack of research on the relationship between different lithofacies and oil-bearing property restricts the research on the geological theory and further exploration and development of shale oil in Da'anzhai Member. Based on core, fluorescence thin sections, rock pyrolysis, total organic carbon (TOC), extraction of chloroform bitumen 'A', and nuclear magnetic resonance (NMR) tests, the oil-bearing characteristics and reservoir physical properties in different lithofacies of Da'anzhai Member were analyzed. The results suggest that the oil-bearing and physical properties of shale are better than shell lime-stone and their peperite. The crude oil discharge from thick shale is limited because of the petrophysical property difference. The Da2b layer thick shale has the best shale oil exploration and development potential, which is the focus of the next step. [ABSTRACT FROM AUTHOR]

In the process of shale gas well drilling in the southern Sichuan Basin, China, lost circulation of high-density oil-based drilling fluid has become a main challenge. In this study, a novel oil-based crosslinking-curing lost circulation material (OBCC-LCM) system applicable for 100-150 °C shale formation was developed based on polyether, isocyanates and blocking agent. The performance of OBCC-LCM pills was comprehensively evaluated by testing fluidity, setting time, strength, elasticity and fracture sealing capacity. The OBCC-LCM pill setting time could be controlled in 70-120 min. The strength of the pill solid was 5.27-6.51 MPa after 360 min heating, and the volume almost restored to the original states after being compressed by 70%. The pill sealed fractures up to 5 mm wide under a differential pressure of 5.2-6.1 MPa, and a higher maximum fracture sealing capacity when being jointly used with bridging LCMs. The OBCC-LCM clearly demonstrated superior performance of good pumpability at room temperature, stability under high temperature, compatibility with oil-based drilling fluids, adaptability with various fracture widths and sustainability in induced fracture. It is suitable for curing loss of induced fracture in low permeability formation and loss of oil-based drilling fluid, especially for loss of oil-based drilling fluid in shale formations. [ABSTRACT FROM AUTHOR]

Microfractures can connect isolated pores within shale, significantly increasing the shale's storage capacity and permeability, and benefiting shale gas exploitation. Therefore, the quantitative characteristics of microfractures are important parameters for shale reservoir evaluation. In this paper, taking the Jurassic Da'anzhai Member (J1z4) lacustrine shale in the Yuanba area of the northern Sichuan Basin as an example, we propose a method for comprehensive and quantitative characterization of shale microfractures that combines rock thin section (RTS) and scanning electron microscopy (SEM) observations. The different magnifications of RTSs and SEM images lead to the identification and characterization of microfractures of different scales using these two methods. RTSs are mainly used to characterize microfractures with widths larger than 10 μm, while SEM is mainly used to characterize microfractures with widths smaller than 10 μm. These techniques can be combined to comprehensively and quantitatively characterize microfractures of different scales in shale. The microfracture characterization results show that the average total porosity of the J1z4 shale is 4.46%, and the average microfracture surface porosity is 1.20% in the Yuanba area. The calculated average percentage of microfracture porosity to total porosity is 21.09%, indicating that the J1z4 shale reservoir space is dominated by pores and has the conditions for stable shale gas production and potential for shale gas exploration. However, the percentage of microfracture porosity to total porosity of shale near faults and fold zones approaches or exceeds 50%, which may lead to the loss of shale gas. The new method proposed in this study is also useful for quantitative characterization of shale microfractures in the Sichuan Basin and other basins. [ABSTRACT FROM AUTHOR]

The Wufeng-Longmaxi Formation shales with burial depths > 3 500 m in the southern Sichuan Basin are believed to have large shale gas potentials. However, the reservoir properties and gas-in-place (GIP) contents of these shales exhibit variations across different sublayers. In this study, a set of Wufeng-Longmaxi shales with burial depths of 4 000–4 200 m was derived from the Well Y101H2 in the Luzhou area, and the differences in geological and geochemical characteristics, porosity, water saturation and GIP content of various sublayer shales were investigated. The results indicate that the TOC content and effective porosity of the upper (LMX1-4) and lower (LMX1-3) sublayer shales of the first member of the Longmaxi Formation are better than those of the Wufeng Formation (WF) shales, which results in the LMX1-4 and LMX1-3 shales having higher GIP contents than the WF shales. The GIP contents of the LMX1-3 shales are higher than those of the LMX1-4 shales, and this is likely because the organic matter of the LMX1-3 shales had more aquatic organisms and was preserved in a stronger reductive environment, which leads to a stronger gas generation potential. In contrast to the middle-shallow LMX1-4 shales in the Sichuan Basin, the deep LMX1-4 shales in the Luzhou area have advantageous reservoir properties and GIP contents, and thus it is promising to synchronously exploit the deep LMX1-4 and LMX1-3 shales in some regions of the southern Sichuan Basin. [ABSTRACT FROM AUTHOR]

In recent years, new breakthroughs have been made in the field of shale oil and gas exploration in the Lower Jurassic Lianggaoshan Formation in Sichuan Basin. At present, there is a lack of systematic studies on reservoir properties and sedimentary facies of the Lianggaoshan Formation shale. Therefore, in this study, taking the Lianggaoshan Formation in Sichuan Basin as an example, the sedimentary facies types of shale reservoirs and their control over shale oil and gas are systematically studied, based on a large number of outcrops, experimental testing, logging, and seismic interpretation methods. The results show that five sedimentary microfacies are developed in the Lianggaoshan Formation in the study area, namely, semi-deep lake mud, shallow lake mud, wave-influenced shallow lake mud, delta-influenced shallow lake mud, and underwater interbranch bay microfacies. The stratum thickness of the Lianggaoshan Formation is in the range of 26–315 m, and mainly distributed in the eastern region, but rapidly thinned in the northwestern region. The sedimentary sequence framework of the Lianggaoshan Formation has been constructed. Moreover, the lithology of the Lianggaoshan Formation shale has been divided into three types, including shale, massive mudstone and silty mudstone. The brittleness index and total organic carbon (TOC) value of three types of shale show a negative correlation. Silty mudstone has the highest brittleness, while that of black shale is the lowest. For porosity and permeability, massive mudstone is better than silty mudstone, and silty mudstone is better than black shale. There are many kinds of matrix pores in the Lianggaoshan Formation shale, and the development degree of inorganic pores is higher than that of organic pores. Finally, based on the analysis of oil-bearing, pore types, physical properties and productivity, it is considered that black shale facies is the most favorable lithofacies type. The deep–semi-deep lacustrine facies belt obviously controls the shale oil enrichment of the Lianggaoshan Formation. [ABSTRACT FROM AUTHOR]

An integrated reservoir-geomechanics-fracture model is implemented in a deep shale gas reservoir in the Sichuan Basin, Western China, to optimize the parent–child well spacing under various complex natural fracture settings. The integrated multiphysics model employs an embedded discrete fracture model to characterize fluid flow through complex natural and hydraulic fractures, a finite element method geomechanics model to predict the 3D spatiotemporal stress changes, and a displacement discontinuity method hydraulic fracture model to simulate the multicluster fracture propagation under the depletion-induced heterogeneous stress field. Field case studies on two complex natural fracture patterns (i.e., orthogonal and clustered natural fractures) show that (a) the orientation change of maximum horizontal stress (SHmax) is negligible since the target shale gas reservoir is highly stressed and under large horizontal stress contrast; (b) the decrease in minimum horizontal stress (Shmin) over the stimulated reservoir volume is about 30–50% of pore pressure drop due to the rapid pressure depletion; (c) decreasing the parent–child horizontal/vertical spacing or elongating the production time aggravates the asymmetry growth of child-well fractures in either natural fracture pattern; (d) the parent and child wells are suggested to space farther under the clustered natural fracture pattern to avoid undesirable interwell fracture interference caused by the irregular localized stress sink. This work delivers a comprehensive understanding of the geomechanics consequences under different natural fracture settings and provides practical guidance on infill operations in layered formations of the Sichuan Basin. Article Highlights: An integrated reservoir-geomechanics-fracture model is employed to optimize the parent–child well spacing in a multilayer deep shale gas reservoir with complex natural fractures The complex fracture network, in situ stress change, and multicluster fracture propagation are simulated by EDFM, FEM geomechanics model, and DDM hydraulic fracture model, respectively The impacts of orthogonal and clustered natural fractures on spatiotemporal stress evolution and parent–child well layout are investigated based on actual field datasets The parent–child well spacing is optimized by incorporating geomechanics responses in addition to fluid-flow simulation to provide hands-on guidance for the Sichuan Basin [ABSTRACT FROM AUTHOR]

Shale in the Jurassic Lianggaoshan Formation in central Sichuan exhibits strong heterogeneity. The study of the pore structure characteristics of different lithologies is crucial to the selection of the target interval. Shale samples of the Lianggaoshan Formation from well YS5 in the central part of the Sichuan Basin were analyzed using scanning electron microscopy, low-temperature nitrogen adsorption, high-pressure mercury injection (HPMI), and large -field splicing method -based scanning electron microscopy (LFS-SEM) to elucidate the pore structure characteristics of shale and their influencing factors. The mineral composition of the reservoir in the study area was diverse, primarily consisting of clay minerals, followed by quartz and calcite. The reservoir space comprised intergranular, granular, and organic matter pores, and oil was observed to fill the reservoir space. Reservoir characteristics varied with the lithological properties. In clayey shale, intergranular pores located in clay mineral particles and pores between pyrite and natural fractures were mainly observed, with a bimodal distribution of pore size and peak distribution of 10–50 nm and >100 nm. The storage space of ash-bearing shale mainly consisted of intragranular pores and intergranular (crystalline) micropores, with pore sizes primarily concentrated in the 10–50 nm range. The storage space in silty shale mainly developed in clastic mineral particles such as quartz, followed by clay mineral intergranular pores with a relatively wide distribution of sizes. Pores were mainly inkbottle-shaped and slit-type/plate-type pores, with an average specific surface area of approximately 6.9046 m2·g−1 and an average pore volume of approximately 0.0150 cm3·g−1. The full-pore capillary pressure curve was established using a combination of gas adsorption–desorption tests and HPMI. The fractal dimension of the sample pore structure was calculated, and a significant linear correlation was found between clay mineral content and the fractal dimension. Thus, the pore structure characteristics were mainly controlled by the content and distribution of clay minerals. [ABSTRACT FROM AUTHOR]

Deeply buried (>3500 m) marine shale has become a focus point for the future exploration and exploitation of shale hydrocarbon in China. Low-temperature nitrogen adsorption (LTNA), scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and other experiments were combined to characterize the pore structure and fluid division in deep-marine shale of the southern Sichuan Basin in this study. The results suggest that the deep-marine shale had a relatively developed nanopore network, especially with honeycomb organic pores. These organic pores were largely macropores with good connectivity in three-dimensional space and constituted the major reservoir space of the deep-marine shale gas. Microfractures were predominantly clay-mineral-related fractures, and the development degree of microfractures connected with organic pores was low, which contributed to the preservation of organic pores. Within the deep-marine shale interval, the pore volumes of Section 1 and Section 3 were higher. Pore volume was predominantly contributed by pores above 10 nm, where macropores accounted for a large proportion. Based on a combination of high-speed centrifugation and gradient temperature drying, the pore fluid of deep-marine shale reservoirs was quantitatively classified into four types: clay-bound fluid, capillary-bound fluid, free-flowing fluid, and closed-pore fluid. The clay-bound fluid existed in pores of less than 4.25 nm, which cannot be exploited. Quantitative division of the shale pore system could be realized by using the pore space differences of different types of fluids. [ABSTRACT FROM AUTHOR]

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Deep shale gas (3500-4500 m) will be the important succeeding field for the growth of shale gas production in China. Under the condition of high temperature and high pressure in deep shale gas reservoirs, its gas occurrence characteristics are markedly different from those of medium and shallow layers. To elucidate the gas occurrence characteristics and controlling factors of deep shales in the Wufeng-Longmaxi Formation, methane adsorption, low-temperature N2, and CO2 adsorption experiments were conducted. The results show that in deep shales, the mesopores provide approximately 75% of the total specific surface area (SSA) and 90% of the total pore volume (PV). Based on two hypotheses and comparing the theoretical and actual adsorption capacity, it is speculated that methane is adsorbed in deep shale in the form of micropore filling, and free gas is mainly stored in the mesopores. Correlation analysis demonstrated that TOC is the key material constraint for the adsorption capacity of deep shale, and micropore SSA is the key spatial constraint. Other minerals and mesopore parameters have limited effect on the amount of adsorbed gas. Moreover, the free gas content ranges from 2.72 m³/t to 6.20 m³/t, with an average value of 4.60 m³/t, and the free gas content ratio is approximately 58%, suggesting that the deep shale gas reservoirs are dominated by free gas. This ratio may also increase to approximately 70% when considering the formation temperature effect on adsorbed gas. Gas density, porosity, and gas saturation are the main controlling factors of free gas content, resulting in significantly larger free gas content in deep shale than in shallower formations. [ABSTRACT FROM AUTHOR]

The staged and multi-cluster fracturing of horizontal wells is the main fracturing technology used for shale gas reservoir development. Temporary plugging diversion (TPD) is an important technical means to realize a uniform propagation of hydraulic fractures and avoid problems such as frac hits (i.e., well-to-well interference). Although this technology has been extensively used worldwide, field monitoring results have shown that temporary plugging cannot effectively improve the nonuniform propagation of multiple fractures. The fundamental reason is the lack of an organic combination of laboratory research and field application. To solve this problem, this study investigated the reservoir adaptability and plugging performance of three types of temporary plugging agent (TPAs), namely, powder, particle, and fiber, used in the fracturing of wells in the Weiyuan (WY) shale gas field, Sichuan, China, using a pressure-bearing capacity test device for three dimensional (3D)-printing-simulated TPA. A calculation method for the plugging efficiency of the TPA was established, and the ratio and concentration of the TPA were optimized under different fracture widths. The similarity criterion was used to calculate the amount of TPA required for different fracture widths. A field application chart of the TPA was formulated, and a method that connects laboratory research and field application was established. The results showed that the three TPAs have good reservoir adaptability and degradation performance. It is recommended to use 200–400 mesh powder + 6 mm fiber with different concentrations and dosages when performing temporary plugging and fracturing at the front end of 1–3 mm fractures. In the case of inter-cluster TPD for a fracture width of 4–6 mm, a combination of 20 mesh powder + 6 mm fiber + 1–3 mm particles is recommended. The field application results showed that the pressure increased significantly at the front end of the fractures and during inter-cluster temporary plugging when the plugging agent was in place, and there were no frac hits in the adjacent wells. This paper provides a practical research method for hydraulic fracturing involving temporary plugging, from laboratory research to engineering application. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Shale oil reservoirs in Daanzhai section of central Sichuan are mainly developed in Daer sub-section, with rich resource base and great exploration and development potential. A series of reservoir engineering geological characteristics experiments have been carried out in order to form reservoir reconstruction countermeasures and technology suitable for Daanzhai shale oil. The results show that the average porosity of Daanzhai shale oil reservoir in central Sichuan is 5.9%, with pores mainly concentrated in the range of 1-100 nm, and slightly larger pores mainly concentrated in the range of 250-1000 nm, with micro-scale pores developed; The reservoir is mainly composed of shale and limestone interbedding. The fracture pressure of limestone is 9-10 MPa higher than that of adjacent depth shale, which is not conducive to the longitudinal expansion of the fracture. The test of temporary plugging and diversion fracturing technology has significantly increased the complexity of the fracture; Shale crude oil has the characteristics of high viscosity, low wax content and low gum content. It has good fluidity in shale supporting fractures, natural fractures and dislocation fractures, and hardly flows in the matrix, and is mainly used for oil displacement by osmosis; The innovatively established nuclear magnetic resonance (NMR) – permeability test technology can quantitatively characterize the flow ability of shale oil in porous media and the permeability and oil displacement ability. In the Daanzhai shale oil reservoir, the optimized soak time is not less than 6 days, and the pressure control and fluid drainage has achieved a more stable stage of fluid discharge. The test oil production has increased from "oil flower" to nearly 2 tons/day, making a major breakthrough in "oil production". [ABSTRACT FROM AUTHOR]

Natural fractures are of paramount importance in storing carbon in shale oil reservoirs, where ultra-low porosity and permeability necessitate their essentiality for enhanced oil recovery. Therefore, comprehensively clarifying the characteristics of natural fractures in shale oil reservoirs is imperative. This paper focuses on investigating the microscopic features of natural fractures in organic-rich continental shale oil reservoirs that are commonly found in the Lower Jurassic strata of the Sichuan Basin, employing them as a representative example. Multiple methods were utilized, including mechanical testing, Kaiser testing, multi-scale CT scanning (at 2 mm, 25 mm, and 100 mm scales), and a numerical simulation of fluid seepage in fracture models. The results revealed that the in situ stress of the target seam displays the characteristic of σH > σv > σh, with σv and σh being particularly similar. The relatively high lateral stress coefficient (ranging from 1.020 to 1.037) indicates that the horizontal stresses are higher than the average level. Although the 2 mm CT scan provides a more detailed view of fractures and connected pores, it primarily exhibited more pore information due to the high resolution, which may not fully unveil additional information about the fractures. Thus, the 25 mm shale core is a better option for studying natural fractures. The tortuosity of the different fractures indicated that the morphology of larger fractures is more likely to remain stable, while small-scale fractures tend to exhibit diverse shapes. The simulations demonstrated that the stress sensitivity of fracture permeability is approximately comparable across different fracture scales. Therefore, our research can enhance the understanding of the properties of natural fractures, facilitate predicting favorable areas for shale oil exploration, and aid in evaluating the carbon storage potential of shale oil reservoirs. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The Sichuan Basin in south-western China is rich in shale oil in the Jurassic strata. Due to its complex geological characteristics, reservoir identification using current log-constrained seismic inversion methods is difficult. Characteristics of the shale oil reservoirs were tested on the basis of the petrophysical experimentation of core samples from the said strata. Thin sections and logging data analysis showed the influencing factors on petrophysical characteristics and clarified the sensitive geophysical parameters for reservoir identification. The Da'anzhai Member reservoirs were determined to have high acoustic velocities, V p/ V s ratios and Young's moduli, and low Poisson's ratios. Several geological factors have influenced the petrophysical properties of the reservoirs. The Da'anzhai Member reservoirs are characterized by a low content of clay minerals and the development of fractures and laminae. The presence of clay minerals caused general high acoustic velocities of the reservoirs; the presence of fractures and laminae in high-quality reservoirs results in a decrease of the acoustic velocities. Therefore, the relatively low value against the background of high acoustic velocity can be used as the criteria for high-quality reservoirs. Poisson's ratio is obviously different in reservoirs and non-reservoirs. When it is <0.269, the reservoirs can be fully identified. In addition, the combination of the Lame constant and shear modulus (λ > 25.277 and μ > 20.72 GPa), P-wave and S-wave velocity (V p > 4967 and V s > 2781 m s−1), wave impedance and V p/ V s ratio (AI > 13.319 g · cm3 · km · s−1 and V p/ V s > 1.792) can also provide references for reservoir identification. [ABSTRACT FROM AUTHOR]

To investigate the brittleness of shale and its influencing factors, triaxial rock mechanics experiments, combined with X-ray diffraction, total organic carbon (TOC) measurement, rock pyrolysis, and scanning electron microscopy, were conducted on shales from the Jurassic Lianggaoshan Formation in the Sichuan Basin. BI1, based on the elastic modulus and hardness, BI2, based on mineral composition, BI3, based on strength parameters, and BI4, based on the post-peak energy of shale, were calculated. Additionally, the effects of mineral composition, density, hardness, and organic matter on the brittleness of shales were analyzed. The results show that the shale mineral compositions were dominated by quartz (mean of 45.21%) and clay minerals (mean of 45.04%), with low carbonate mineral contents and high TOC contents. The stress–strain curve showed strong brittleness characteristics. When comparing different evaluation methods, the brittleness evaluation method based on the stress–strain curve (damage energy) was found to be more effective than the mineral fraction and strength parameter methods. The higher the density and hardness, the more brittle the shale. The higher the organic matter and quartz content, the less brittle the shale. The brittleness of sub-member I of the Lianggaosan Formation in Well XQ1 was higher than that of sub-members II and III. This study investigated the brittleness of lacustrine shale and its influencing factors, which is beneficial for the development of shale oil in the Sichuan Basin. [ABSTRACT FROM AUTHOR]

The study of extraordinarily high organic matter content (EHOMC) is beneficial to promote the fine evaluation of shale oil and gas, but so far, there have been few studies on its mechanism. This paper carried out a comprehensive lithological and geochemical analysis of the black shales of the Wujiaping Formation in the Kaijiang-Liangping Trough. The results showed that the black shales of the Wujiaping Formation can be divided into two units (the upper and lower parts), and EHOMC occurs in its upper part. The redox-sensitive trace elements (RSTEs), MoEF-UEF covariation, and Ni/Co correlation showed that the lower part of Wujiaping Formation was a weakly restricted oxidation environment, while the upper part evolved into a sulfidation reducing environment. The productivity indicator elements (BaXS, NiXS, CuXS, P, and Mo) indicated that the upper Wujiaping Formation had higher primary productivity than the lower part. However, rare earth elements ((La/Yb)N) indicated that the deposition rate in the lower part of the Wujiaping Formation was higher than that in the upper part. In general, although the oxygenated water in the lower part of the Wujiaping Formation is not conducive to the preservation of organic matter, the high input of nutrients from land sources and the high deposition rate inhibit the decomposition of organic matter, so the lower part has a certain degree of organic matter accumulation. The sulfidation reducing environment and high paleoproductivity are the main reasons for the enrichment of organic matter in the upper part of the Wujiaping Formation. In addition, the sulfidation reducing environment and high paleoproductivity occurred during the violent upwelling at the end of Guadeloupe, a period of high sea level, these factors have jointly contributed to the enrichment of OM in the upper the Wujiaping Formation. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Highlights: 1. How to quantitative evaluation of mechanical properties of shale in Da'anzhai section combined with triaxial mechanical experiments? The compressive strength of dry rock samples and soaked rock samples were tested by triaxial mechanical experiments. According to the stress-strain curves, the changes of compressive strength, elastic modulus and Poisson's ratio before and after hydration were analyzed. 2. How to establish a mathematical model of shale fracability that comprehensively considers brittleness index, horizontal differential stress, and fracture toughness is proposed? Fracability index is proportional to brittleness index and horizontal differential stress, and inversely proportional to fracture toughness. Young 's modulus, Poisson's ratio and tensile strength in fracability index model are related to rock water saturation, so the fracturing index is also related to rock hydration. 3. What is the effect of shale hydration on fracability and fracture pressure? As the water saturation rate of the rock gradually decreases, the FI of the formation rock de-creases Combined with the variation law of water saturation rate, it shows that after the shale around the well is hydrated, the fracture pressure of the formation decreases Accurate evaluation of shale oil reservoir fracability helps avoid blind fracturing and ensures efficient fracturing. However, the current evaluation of the fracability index rarely considers the impact of hydration caused by drilling fluid invasion during drilling. The results of a rock triaxial mechanical test conducted to evaluate the mechanical properties of shale oil reservoirs are reported in this paper. Based on the results, we developed a comprehensive evaluation method of shale oil reservoir fracability that considers hydration; the effects of the brittleness index, horizontal difference stress, and fracture toughness; and the law of water phase intrusion into shale oil reservoirs. The research results show that the average compressive strength decreased by 37.99%, the average elastic modulus decreased by 53.36%, and the average Poisson's ratio increased by 68.75% after being soaked for 48.00 h at 80 °C and 30.00 MPa. The water saturation rate at the borehole wall was the highest; with the extension to the stratum, it gradually decreases to the original water saturation rate of the formation, while the fluctuation radius gradually increases with time. The Young's modulus and fracture toughness decrease, the Poisson's ratio increases, and the fracability index reaches a maximum value at the wellbore (i.e., the highest water saturation rate), indicating that the strength of the hydrated rock decreases and it can be easily fractured. The case analysis shows that the optimal fracturing position of the Da'anzhai Section of Well NC2H is around 2600 m deep. After the hydration occurs, the fracture initiation pressure of the formation is reduced from the original value of 72.31 MPa to 66.80 MPa. This indicates that when hydration decreases, the formation fracture pressure also increases. The research presented in this paper can be used to optimize fracture location and set a reasonable fracturing pressure. [ABSTRACT FROM AUTHOR]

The effective utilization of shale bedding fractures is of great significance to improve shale gas recovery efficiency. Taking the Wufeng–Longmaxi Formation shale in Sichuan Basin as the research object, the formation process and mechanism of bedding fractures in marine shale are discussed, based on field observation and description, high-resolution electron microscope scanning, fluid inclusion detection, and structural subsidence history analysis. The results show that the formation of bedding fractures is jointly controlled by sedimentary characteristics, hydrocarbon generation, and tectonic movement: the development degree of bedding (fractures) is controlled by the content of shale organic matter and brittle minerals, and bedding fractures formed in the layers with high organic matter; tectonic movement created stress environment and space for bedding fractures and promoted the opening of bedding fractures; the time for calcite vein to capture fluid is consistent with the time of oil-gas secondary pyrolysis stage. The formation of the calcite vein is accompanied by the opening of fractures. The acid and oil-gas generated in the hydrocarbon generation process occupied the opening space and maintained the bedding fractures open. The study of the formation process of bedding fractures is helpful to select a suitable method to identify bedding fractures, and then effectively use it to form complex fracture networks in the fracturing process to improve shale oil and gas recovery. [ABSTRACT FROM AUTHOR]