Longmaxi Formation Research Articles

Investigation of the Mechanism and Effect of Citric Acid-Based Deep Eutectic Solvents Inhibiting Hydration and Expansion of Gas Shale Clay Minerals

This study developed a shale hydration inhibitor using a citric acid-based deep eutectic solvent (Cit-DES) and hexadecylammonium bromide (cetyltrimethylammonium bromide) to aid wellbore instability and collapse caused by drilling of shale gas wells with water-based drilling fluids. Soaking and linear expansion experiments were conducted with Na-bent and Longmaxi formation shale, respectively. The changes in illite interlayer spacing, wettability, and water absorption capacity of shale samples before and after soaking in an inhibitor solution were evaluated, which indicated that the inhibitor reduced shale hydration. The results showed that the inhibitor effectively inhibits the osmotic and surface hydration of the shale. Due to the Cit-DES hydrogen bond, the inhibitor is firmly adsorbed on the shale pore wall and inserted between clay minerals, reducing the shale surface energy, hydrophilicity, and surface potential. The swelling expansion rate of shale inhibitors is only 38.9% compared to a 3% KCl solution. The amount of shale imbibition per unit mass in distilled water is 0.011 g/g. In the inhibitor, the imbibition mass per unit of shale is 0.002 g/g, which is only 23.68% of that in distilled water. The inhibitor is environment-friendly and has a broad application prospect for maintaining shale wellbore stability and preventing wellbore collapse during horizontal shale drilling operations.

“Rigid-elastic chimera” pore skeleton model and overpressure porosity measurement method for shale: A case study of the deep overpressure siliceous shale of Silurian Longmaxi Formation in southern Sichuan Basin, SW China

Based on analysis of pore features and pore skeleton composition of shale, a “rigid elastic chimeric” pore skeleton model of shale gas reservoir was built. Pore deformation mechanisms leading to increase of shale porosity due to the pore skeleton deformation under overpressure were sorted out through analysis of stress on the shale pore and skeleton. After reviewing the difficulties and defects of existent porosity measurement methods, a dynamic deformed porosity measurement method was worked out and used to measure the porosity of overpressure Silurian Longmaxi Formation shale under real formation conditions in southern Sichuan Basin. The results show: (1) The shale reservoir is a mixture of inorganic rock particles and organic matter, which contains inorganic pores supported by rigid skeleton particles and organic pores supported by elastic-plastic particles, and thus has a special “rigid elastic chimeric” pore structure. (2) Under the action of formation overpressure, the inorganic pores have tiny changes that can be assumed that they don't change in porosity, while the organic pores may have large deformation due to skeleton compression, leading to the increase of radius, connectivity and ultimately porosity of these pores. (3) The “dynamic” deformation porosity measurement method combining high injection pressure helium porosity measurement and kerosene porosity measurement method under ultra-high variable pressure can accurately measure porosity of unconnected micro-pores under normal pressure conditions, and also the porosity increment caused by plastic skeleton compression deformation. (4) The pore deformation mechanism of shale may result in the “abnormal” phenomenon that the shale under formation conditions has higher porosity than that under normal pressure, so the overpressure shale reservoir is not necessarily “ultra-low in porosity”, and can have porosity over 10%. Application of this method in Well L210 in southern Sichuan has confirmed its practicality and reliability.

Deep shale gas exploration and development in the southern Sichuan Basin: New progress and challenges

There are abundant marine shale gas resources in the Sichuan Basin. After almost one decade of exploration and development, three national shale gas demonstration areas have been built in the Sichuan Basin and its periphery, and large-scale commercial development of middle and deep (above 3500 m in depth) shale gas has been successfully achieved. The volume of deep shale gas resources (3500–4500 m deep) of the upper Ordovician Wufeng Formation-lower Silurian Longmaxi Formation in the southern Sichuan Basin is 6.6 × 1012 m3, with huge exploration and exploitation potential, so it is an important area for large-scale shale gas production increase in China during the 14th Five-year Plan. Deep shale gas in the southern Sichuan Basin is influenced by complex geological engineering conditions, such as great burial depth, high temperature and pressure, and large stress and stress difference, and its high-quality development faces many challenges. After systematically summarizing the new progresses and achievements in deep shale gas exploration and development in the southern Sichuan Basin, this paper analyzes the difficulties and challenges in deep shale gas exploration and development and puts forward the next research directions. And the following research results are obtained. First, based on early practical exploration and independent innovation, key shale gas exploration and development technologies with good area selection, good well deployment, good well drilling, good well fracturing and good well management as the core are formed, and the cultivation mode of high production well is established, which supports the large-scale benefit development of deep shale gas in the southern Sichuan Basin. Second, systematical analysis indicates that the exploration and development of deep shale gas still faces a series of challenges in such three major fields as basic theory, key technology and management mode. Third, in the face of challenges, it is necessary to deepen basic theory research related to exploration and development, continuously improve key main technologies and constantly innovate mechanisms, systems and management modes. In conclusion, after years of continuous researches and pilot tests, a series of main exploration and development technologies suitable for the working conditions of deep shale gas in the southern Sichuan Basin have been basically formed, the first deep shale gas reserves of trillion cubic meters has been submitted, and the first deep shale gas production increase block of ten billion cubic meters has been selected. Thus, great progresses have been made in the exploration and development of deep shale gas, which confirms the confidence and determination in exploring and developing deep shale gas and is of great guiding significance to the rapid development of shale gas industry in China.

Porosity, permeability and rock mechanics of Lower Silurian Longmaxi Formation deep shale under temperature-pressure coupling in the Sichuan Basin, SW China

To investigate the porosity, permeability and rock mechanics of deep shale under temperature-pressure coupling, we selected the core samples of deep shale from the Lower Silurian Longmaxi Formation in the Weirong and Yongchuan areas of the Sichuan Basin for porosity and permeability experiments and a triaxial compression and sound wave integration experiment at the maximum temperature and pressure of 120 °C and 70 MPa. The results show that the microscopic porosity and permeability change and the macroscopic rock deformation are mutually constrained, both showing the trend of steep and then gentle variation. At the maximum temperature and pressure, the porosity reduces by 34%–71%, and the permeability decreases by 85%–97%. With the rising temperature and pressure, deep shale undergoes plastic deformation in which organic pores and clay mineral pores are compressed and microfractures are closed, and elastic deformation in which brittle mineral pores and rock skeleton particles are compacted. Compared with previous experiments under high confining pressure and normal temperature, the experiment under high temperature and high pressure coupling reveals the effect of high temperature on stress sensitivity of porosity and permeability. High temperature can increase the plasticity of the rock, intensify the compression of pores due to high confining pressure, and induce thermal stress between the rock skeleton particles, allowing the reopening of shale bedding or the creation of new fractures along weak planes such as bedding, which inhibits the decrease of permeability with the increase of temperature and confining pressure. Compared with the triaxial mechanical experiment at normal temperature, the triaxial compression experiment at high temperature and high pressure demonstrates that the compressive strength and peak strain of deep shale increase significantly due to the coupling of temperature and pressure. The compressive strength is up to 435 MPa and the peak strain exceeds 2%, indicating that high temperature is not conducive to fracture initiation and expansion by increasing rock plasticity. Lithofacies and mineral composition have great impacts on the porosity, permeability and rock mechanics of deep shale. Shales with different lithologies are different in the difficulty and extent of brittle failure. The stress-strain characteristics of rocks under actual geological conditions are key support to the optimization of reservoir stimulation program.

Study on the Provenance and Tectonic Setting of Mudstone in the Lower Silurian Longmaxi Formation of the Yanyuan Basin on the Western Margin of the Yangtze Platform

This study investigates the provenance and tectonic background of the lower Silurian Longmaxi Formation black shale of the Yanyuan Basin in the western Kangdian ancient land and provides guidance for shale gas exploration and development in the area. The mineral petrological and geochemical characteristics of the Longmaxi Formation black shale in this area have been studied in detail. The study area is mainly a passive continental margin environment, but also has the attributes of an active continental margin and island arc environment due to the collision between the western oceanic crust and the Yangtze continental crust. The source rocks are mainly felsic igneous rocks, with a small contribution of intermediate–basic rocks. It is inferred that the Kangdian ancient land in the eastern part of the area could be the main provenance area, but with the contribution of sediments derived from oceanic island arc located in the west. During the whole Longmaxi period, the tectonic movement was intense, the climate was cold, the degree of chemical weathering was low, and it was a highly volatile geological sedimentary basin. Therefore, the highly siliceous organic-rich mudstone, which was different from the Sichuan Basin, was deposited.

Comparison and Verification of Gas-Bearing Parameter Evaluation Methods for Deep Shale Based on the Pressure Coring Technique

Gas-bearing properties, such as gas-in-place (GIP) content and adsorbed gas ratio (AGR), have drawn considerable attention because they are essential for shale gas resource evaluation and sweet spot forecasting. The above-mentioned metrics have been determined using a variety of approaches, but they lack systematic comparison and accuracy verification, particularly for deep shale gas, where conventional methods frequently fall short. A total of 30 shales were taken for the investigation utilizing pressure and conventional coring methods from Wufeng and Longmaxi Formations in the Sichuan Basin, China. For pressure coring samples, we developed the experimental protocols and a GIP content classification scheme that categorizes the GIP content into four categories: lost gas (estimated using the temperature-corrected pressure-holding ratio), extracted gas from depressurization, degassed gas, and residual gas. The four pressure coring samples from well Y206 with measured GIP content range from 2.84 to 5.58 m3/tonne, with an average of 4.72 m3/tonne. In contrast to the calculated GIP content of the pressure coring samples, the validity of the current GIP content evaluation methodologies has been confirmed. The comparison results demonstrate that the GIP content assessed using the United States Bureau of Mines (USBM) method is frequently underestimated for samples from conventional coring and notably overstated for samples from pressure coring. The polynomial fitting method dramatically overestimated the GIP content. With its accurate time-dependent boundary conditions and strict theoretical foundation, the simplified carbon isotope fractionation (s-CIF) model exhibits the highest level of accuracy in determining GIP content. Additionally, the s-CIF model can find yet another crucial parameter of AGR. Shale samples from well Y206 had an average AGR of 20.4% but a range from 12.2 to 33.2%. The examination of the influencing factors demonstrates that the lost gas ratio, AGR, and diffusion coefficient are responsible for controlling the calculation error of the USBM method. The lost gas ratio prior to core retrieval increases with decreasing AGR (or increasing diffusion coefficient), which increases the computation error of the USBM method.

Experimental study on mechanical properties and fracture characteristics of shale layered samples with different mineral components under cyclic loading

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

Structural deformation characteristics and its influence on shale gas preservation of the Wufeng−Longmaxi Formation in the Wuxi area, Chongqing, China

The Upper Ordovician Wufeng to Lower Silurian Longmaxi Formation has a good material basis for marine shale gas development, and the structural preservation condition is the key factor to control the rich and integrated shale gas reservoirs in the Wuxi area of Chongqing City, China. Based on the seismic-structural interpretation data, combined with the regional structural background and drilling effect, the structural deformation characteristics and shale gas structural preservation conditions are comprehensively analyzed in the study area. The Wuxi area is located at the structural junction of the Sichuan Basin and southern Dabashan along with strong structural deformations. Seven rows of NW to near EW structural belts are mainly developed. The fold styles and fault development degrees of different structural belts are different, and the difference in the structural preservation conditions of shale gas is also obvious. The study results reveal that the shale gas structure preservation conditions of the Wufeng−Longmaxi Formation in the Wuxi area are overall poor and only locally better. The structure preservation conditions for shale gas enrichment and accumulation are divided into four grades, such as the good Class I area, the general Class II area, the poor Class III area, and the very poor Class IV area. Among them, the Heiloumen structural zone and Huangcaoping buried structural zone nearby the Sichuan Basin have good preservation conditions and are classified as the good Class I preservation area. The macroscopic preservation type of shale gas in the Wufeng−Longmaxi Formation of the Wuxi area belongs to the complex structural preservation of the basin margin. Three structural preservation modes of shale gas in the study area have also been confirmed, including the lost destruction type, lost residual type, and trap preservation type. The trap preservation type is more conducive to the preservation of shale gas, which is the most favorable structural mode for shale gas exploration.

Research on the differential tectonic-thermal evolution of Longmaxi shale in the southern Sichuan Basin

The southern Sichuan Basin in China holds abundant shale gas resources; however, the shale gas bearing property shows great differences due to the multiple stages of tectonic transformation. The key to revealing the shale gas differential enrichment mechanism is to explore the thermal evolution characteristics during tectonic evolution. Therefore, taking the Luzhou and Changning blocks as an example, which have obvious differences in tectonic evolution, the organic geochemical conditions of Longmaxi shale were firstly compared with the test data. Then, the thermal evolution characteristics under the background differential tectonic uplift-erosion were recovered using basin modeling techniques. The results showed that the two blocks contain similar organic geochemical conditions of the Longmaxi shale. Moreover, the hydrocarbon generation condition in Luzhou Block is greater than that in the Changning Block. Influenced by the differential tectonic evolution, the study area experienced a complex burial history and the formation of multiple unconformities. As a result, the present burial depth of Longmaxi Formation in the Luzhou Block is significantly greater than that in the Changning Block. The thermal evolution history of Longmaxi shale in the study area could be divided into three stages, including a low-temperature stage from Caledonian to Hercynian, a middle-temperature stage from Hercynian to Indosinian, and a high-temperature stage from Yanshanian to Himalayan. In addition, it was found that the Himalayan period is the main stage resulting in the differential gas bearing property of Longmaxi shale in the southern Sichuan area. Under the differential structural modification, the peak time of hydrocarbon generation in the Luzhou Block occurred earlier and the conversion rate was slightly higher than that in the Changning Block. Cited as: Zhao, L., Mao, W., Liu, Z., Cheng, S. Research on the differential tectonic-thermal evolution of Longmaxi shale in the southern Sichuan Basin. Advances in Geo-Energy Research, 2023, 7(3): 152-163. https://doi.org/10.46690/ager.2023.03.02

Pore structure and fractal characteristics of Wufeng–Longmaxi formation shale in northern Yunnan–Guizhou, China

In this study, the microscopic pore characteristics of shale in marine strata are evaluated. Based on field emission scanning electron microscopy (FE-SEM), low-temperature N2 adsorption (LT-N2GA), low-pressure CO2 adsorption (LP-CO2GA) and high-pressure methane adsorption (HPMA) experiments, the pore characteristics of 12 shales from the Wufeng–Longmaxi Formations in northern Yunnan and Guizhou are characterized qualitatively and quantitatively. Fractal Frenkel–Halsey–Hill (FHH) theory is used to analyse the fractal characteristics, and the adsorption pore characteristics of shale are discussed. The correlation between the fractal dimension and pore structure and adsorption performance is determined. The results show that the total organic carbon (TOC) contents of the 12 shales are in the middle–low level, ranging from 0.43% to 5.42%, and the shales are generally in the highly mature to overmaturity stage (vitrinite reflectance (Ro) values between 1.80% and 2.51%). The mineral composition is mainly quartz and clay minerals. The average clay mineral content is 40.98% (ranging from 24.7% to 63.3%), and the average quartz content is 29.03% (ranging from 16.8% to 39.6%), which are consistent with those of marine shale in the Sichuan Basin. FE-SEM and LT-N2GA isotherms reveal a complex shale pore structure and open pore style, mainly ink bottle-shaped and parallel plate-like pores. The total pore volumes (PVs) range from 0.012–0.052 cm3/g, and the specific surface area (SSA) values range from 18.112–38.466 m2/g. All shale samples have abundant micropores and mesopores, accounting for >90% of the total SSA. The fractal dimensions, D1 and D2, were obtained from N2 adsorption data, with different adsorption characteristics at 0–0.5 and 0.5–1.0 relative pressures. The fractal dimensions increase with increasing BJH PV and BET SSA and decrease with decreasing average pore diameter (APD). The fractal dimensions are positively correlated with the TOC and clay mineral contents and negatively correlated with the quartz content. The fractal dimension can be used to evaluate the methane adsorption capacity; the larger the fractal dimension is, the larger the methane adsorption capacity is. Fractal analysis is helpful to better understand the pore structure and adsorption capacity of shale gas reservoirs.

Lithofacies Types and Reservoir Characteristics of Mountain Shale in Wufeng Formation-Member 1 of Longmaxi Formation in the Complex Structural Area of Northern Yunnan-Guizhou.

The mountain shale in Wufeng Formation-Member 1 of Longmaxi Formation in the complex structural area of northern Yunnan-Guizhou has great potential for exploration and development. In order to clarify the differences of reservoir quality and the longitudinal distribution law of different lithofacies, the lithofacies in Wufeng Formation-Member 1 of Longmaxi Formation was divided combined with core, logging, and analytical test data. Based on the data of total organic carbon, laminate structure, reservoir porosity types and physical properties, and gas content, the reservoir characteristics and advantageous lithofacies shale reservoir distribution were determined. The results show that the mountain shale lithofacies in the study area are divided into 7 major types and 20 subtypes. The high-carbon siliceous shale has the highest degree of organic pore development, specific surface area (average 28.55 cm2/g), and pore volume (average 0.0397 cm3/g). Two types of advantageous lithofacies shale reservoir in the study area were identified. The high-carbon siliceous shale reservoir could be considered as an excellent shale reservoir for shale gas and is mainly concentrated in the first section. It is mainly developed in layer-1 and the bottom of layer-2 of the Longmaxi Formation, providing favorable source-reservoir conditions for shale gas enrichment. The medium-carbon siliceous shale, medium-carbon clay siliceous shale, and medium-carbon calcareous siliceous shale, developed in the top of layer-2 and the bottom of layer-3 of the Longmaxi Formation, are assumed to be moderately promising for shale gas. Therefore, the research results deepen the understanding of the longitudinal distribution of the dominant shale reservoirs in the study area and are of great significance in promoting strategic transfer of the main shale gas exploration system in the south from the Sichuan basin to the outer basin.

Evaluation method for in-situ stress orientation using wave anisotropy and electrical imaging logging data: A case study from the Longmaxi Formation in Yongchuan area, Sichuan Basin

In-situ stress orientation is a key parameter in studying oil and gas migration and accumulation, analyzing the stability of borehole wall during drilling, carrying out horizontal well design, fracturing reconstruction and well pattern layout in water injection development. Accurately predicting the in-situ stress orientation of reservoirs is of utmost importance for oil and gas exploration and development. It is the most effective and commonly used method to evaluate the in-situ orientation by using the induced fracture and breakout fracture of imaging logging data. However, in cases where effective induced fracture or breakout fracture cannot be formed during drilling, the in-situ orientation cannot be evaluated by imaging data alone. Taking the shale reservoir of Longmaxi Formation in Yongchuan area as an example, this paper presents a novel method for evaluating in-situ orientation. Firstly, the in-situ orientation is determined relative to the core sample marker line through the wave velocity anisotropy experiment. Secondly, the core sample is rotated to obtain an unfolded image of the core surface. The orientation of the core marker line in the electrical imaging is then determined by comparing the core image with the electrical imaging logging image. By doing so, the true orientation of the core can be obtained. This method aligns well with the in-situ stress orientation determined through induced fracture evaluation, addressing the limitation of electrical imaging data in evaluating in-situ stress orientation in plastic strata.

Lithofacies identification of shale reservoirs using a tree augmented Bayesian network: A case study of the lower Silurian Longmaxi formation in the changning block, South Sichuan basin, China

As important units for evaluating shale gas reservoirs, lithofacies exert obvious control on the abundance of shale organic matter and the enrichment degree of gas reservoirs. Therefore, it is of great significance to accurately identify the lithofacies of shale reservoirs relative to shale gas exploration and development. This paper takes the Longmaxi Formation shale in the Changning block, Sichuan Basin, China, as an example and uses a tree augmented Bayesian network for the quantitative classification and identification of lithofacies for the first time. First, based on thin section and scanning electron microscopy observations and X-ray diffraction, we can determine the shale lithofacies types of the Longmaxi Formation. Second, the logging response characteristics of different lithofacies were obtained by comparing conventional logging data. Finally, the tree augmented Bayesian network (TAN) was built according to the selected logging parameters and identified unknown lithofacies. The results are as follows: (1) Longmaxi Formation shale is rich in siliceous minerals. By comparing analysis of shale mineral composition and diagenetic characteristics, we divide the lithofacies into five types: siliceous rock, siliceous shale, argillaceous/siliceous mixed shale, calcareous/siliceous mixed shale and calcareous shale. (2) Based on the logging data, 6 logging curves (GR, AC, DEN, CNL, PE and RT) can sensitively indicate diagenesis and changes in mineral content. (3) The TAN model trained by logging information was used to identify 68 shale samples through the 5-fold cross validation method, with an accuracy rate of 95.58%. The results showed that the tree augmented Bayesian network not only can overcome the limitation of interdependence among well-logging properties but also represents an efficient and accurate new method for identifying shale lithofacies. This algorithm can be applied to lithofacies identification of shale reservoirs with only conventional well-logging data, which can help promote the development of lithofacies identification of unconventional oil and gas geology and provides a new method for shale gas reservoir evaluation.

Well-logging evaluation of the shale gas potential in the lower Silurian Longmaxi Formation, Weiyuan, southern Sichuan Basin, China

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

Carbon Isotope Fractionation Characteristics of Normally Pressured Shale Gas from the Southeastern Margin of the Sichuan Basin; Insights into Shale Gas Storage Mechanisms

Since the development of shale gas in the Wufeng-Longmaxi Formation in the Sichuan Basin, China's shale gas production and reserves have increased rapidly. The southeastern margin of the Sichuan Basin is located in a normally pressured transition zone, where single well gas production varies greatly under complex geological structures. In order to reveal the shale gas enrichment mechanism and favorable shale gas regions, shale gas samples from production wells were collected from different structures, with the formation pressure coefficient ranging between 0.98 and 1.35. The gas components and carbon isotope characteristics of normally pressured shale gas were investigated. The carbon isotope characteristics of the Wufeng-Longmaxi shale gas from the basin scale was mainly controlled using thermal maturity; as the thermal maturity increased, heavier carbon isotopes were found, in addition to drier shale gas. For normally pressured shale gas, the composition of δ13C1 and δ13C2 becomes heavier, and the dryness coefficient decreases with the decreasing pressure coefficient; this is not consistent with the results from thermal evolution. By comparing possible influencing factors, it is evident that the change in geological structure destroys the original shale gas reservoir, which leads to the escape of some gases, and it may be the main factor that contributes to the gas geochemical characteristics of the normally pressured shale gas. Compared with the geological parameters of the shale samples, such as mineral composition, organic abundance, organic pore distribution, and gas content, the carbon isotope characteristics of normally pressured shale gas show a higher efficiency, thus indicating favorable sweet spot evaluations for shale gas in the studied areas.

Investigation of induced change in pore structure by the reaction of shale with fracturing fluid

To study the change in the shale pore structure during the reaction between shale and fracturing fluid, a soaking experiment was conducted on shale from the Longmaxi Formation in the Sichuan Basin, China. The changes in the pore structure before and after the experiment were analyzed. The results show that the number of mesopores, macropores, and microfractures increased after the shale reacted with fracturing fluid. The analysis reveals that the dissolution of salts is the main reason for the change in the shale's pore structure. In addition, the dissolution of salt promotes the hydration of clay minerals and changes the pH of the fracturing fluid to produce 500–1000 nm corrosion pores.

Investigation of Stress Sensitivity of Shale Nanopores via a Nuclear Magnetic Resonance Method

Nuclear magnetic resonance (NMR) is widely used to characterize the pore structure of rock. The nanoscale pores and fractures are well developed in a shale gas reservoir. The closure of nanopores caused by the increase in effective stress during the gas production process could induce stress sensitivity in shale nanopores, which has a great impact on the single-well productivity in the middle–late development stage. In this paper, shale samples from the Longmaxi Formation were taken to investigate the nanopore stress sensitivity via an NMR method. Samples with different degrees of pore and fracture development were selected and NMR experiments under different effective stress conditions were carried out. The results show that: (1) As the effective stress increases, the pore space in shale is continuously compressed, and the cumulative pore volume of shale decreases; (2) There is a more pronounced decrease in the cumulative pore volume of samples containing larger pores with the increase in effective stress. However, there are obvious differences in the pore volume changes in different pore sizes; (3) The transformation of nanopores of different sizes occurs in the process of effective stress loading. When the effective stress is small, the pores with diameters larger than 50 nm are mainly transformed to those with diameters of 10–50 nm. When the effective stress increases to a certain extent, the pores with diameters of 10–50 nm are mainly transformed to those with diameters of 0–10 nm; (4) There are significant differences in the compressibility of nanopores of different sizes. Larger nanopores generally have a higher compression coefficient and a stronger stress sensitivity. In the process of effective stress loading, the compression coefficient of pores with diameters between 10 and 50 nm changes relatively slowly, which can well-maintain the pore shape and quantity. Based on the variation in porosity ratio with effective stress, a new method of dividing shale nanopores is proposed; those with diameters smaller than 10 nm, those with diameters of 10–50 nm, and those with diameters larger than 50 nm.

Geochemical Characteristics and Organic Matter Accumulation of Wufeng-Longmaxi Shales in the Southeast of the Sichuan Basin of South China

The Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation black shales are the critical targets for shale gas exploration in the Sichuan Basin of South China. The enrichment of organic matter (OM) in shale is the basis for the generation of large-scale shale gas; however, its controlling factors in Wufeng-Longmaxi shales are still under debate, and few studies have focused on the edge of the Sichuan Basin. Based on the mineral composition, total organic carbon (TOC), and systematic inorganic geochemistry analysis of 72 core samples from Wufeng and Longmaxi formations in Well Xike 1, southeastern Sichuan Basin, the sedimentary conditions (palaeoclimate, palaeoredox, and palaeoproductivity) were reconstructed, and the controlling factors of OM enrichment were identified. The mineral compositions are dominated by quartz, clay minerals, calcite, and feldspar, associated with minor dolomite, pyrite, and anhydrite. The TOC contents (0.31%-6.84%, avg. 2.22%) show an upward decreasing trend from the Wufeng Formation to Longmaxi Formation. The chemical index of alteration (CIA) ranges from 65 to 71 (avg. 69), indicating warm and humid climate with moderate weathering. The diagrams of Al2O3-TiO2, TiO2-Zr, Zr/Sc-Th/Sc, La/Th-Hf, and La-Th-Sc jointly indicate the contribution from felsic and intermediate rock weathering. The P/Al, Cu/Al, and Ni/Al ratios suggest that marine paleoproductivity was relatively high in the Wufeng Formation and relatively low to moderate in the Longmaxi Formation. The V/Cr, V/Sc, U/Th, MoEF/UEF, and Corg/P ratios indicate that the bottom water was anoxic during the Wufeng Formation deposition and then fluctuating dysoxic and/or oxic in the overlying Longmaxi Formation. The TOC content was positively correlated with productivity proxies (P/Al, Cu/Al, and Ni/Al) as well as redox proxies (U/Th, V/Cr, MoEF/UEF, and Corg/P), indicating that the OM accumulation in Wufeng-Longmaxi shales is mainly controlled by high productivity and anoxic bottom water conditions.

Impact of cyclic liquid nitrogen treatment on the pore and fracture structures of shale at different scales and its effect on permeability enhancement

The ultra-low permeability of shale reservoirs limits shale gas production. Liquid nitrogen (LN2) fracturing is a promising reservoir stimulation technology that has attracted considerable attention in the unconventional natural gas industry. However, the evolution of pore and fracture structures in shale subjected to cyclic LN2 treatment and its effect on permeability enhancement have not been fully elucidated, especially with the presence of pore or fracture water. In this study, the physical response of Longmaxi Formation shale to cyclic LN2 treatment was carefully investigated. Scanning electron microscopy (SEM) and computed tomography (CT) were used to investigate the alteration of the pore and fracture structures in water-saturated and dry shale samples at different scales before and after cyclic LN2 treatment. Based on digital image processing and the fractal theory of pore structure, the variation in pore and fracture structures in shale matrices at the microscale was quantitatively analyzed. The experimental results indicate that cyclic LN2 treatment can effectively enhance pore volume and induce microfracture initiation and propagation. These phenomena were more significant in the water-saturated shale samples. Different correlations between the areal porosity of matrices and overall porosity/permeability in dry and water-saturated samples indicate that thermal stress and frost-heave force have different effects on shale pore and fracture structures. Owing to the different generation mechanisms, thermal stress was mostly applied to shale matrices, whereas frost-heavy force only existed near water-rich minerals, which were mainly clay in shale natural fractures. These two driving forces also had different responses to cyclic LN2 treatment. Because the new generated pores and microfractures have increased the distance among mineral particles, thermal stress gradually decreased with increasing LN2 treatment cycles. However, frost-heavy force could still induce macro-fractures along the bedding face of shale samples after several LN2 treatment cycles, owing to water migration during water-ice phase change.

Dynamic evolution of shale permeability under coupled temperature and effective stress conditions

The permeability of shale in unconventional subsurface reservoirs under high-temperature and high effective stress conditions is of great significance for evaluating the extraction efficiency of shale gas and determining reservoir development programs. In this study, a series of permeability experiments using nitrogen gas were conducted on a sample from the lower Longmaxi Formation over a range of temperature (25–100 °C), effective stress (22.5–52.5 MPa), and pore pressure (0.5–8 MPa) conditions. The dynamic relationships between permeability and temperature, effective stress, and pore pressure are analyzed in detail. The results show that the apparent permeability decreases approximately linearly with increasing pore pressure, temperature, and effective stress. The absolute permeability also decreases with increasing temperature or effective stress. Upon increasing the reservoir depth by 1000 m, the permeability decreases by an average of approximately 25%. Approximately two-thirds of this decline is caused by changes in the effective stress and approximately one-third by changes in temperature. The Klinkenberg parameter is also found to be positively correlated with temperature and effective stress. The results herein provide important guidance for evaluating permeability changes and the extraction efficiency for deep shale gas development.