Deep Shale Reservoirs Research Articles

Gas-Bearing Property in Deep Marine Shale and Its Micro Controlling Factors: Evidence from the Lower Silurian Longmaxi Formation in Southern Sichuan, China

Abstract The gas content in shale reservoirs is often determined by the micro storage and sealing capacities of the reservoir. Deep shale reservoirs are in the high- or over-thermale maturity stage and have complex pore structure and connectivity, which are highly heterogeneous in vertical distribution. Research on the gas-bearing property of deep shale reservoirs is limited by these complex microscopic conditions. To analyze the gas-bearing characteristics of deep shale reservoirs, this work collected and summarized data on total organic carbon content, mineral composition, porosity, water saturation, and gas content measured on-site for the Longmaxi Formation in the Sichuan Basin in southern Sichuan, China. Then, experimental methods, such as X-ray photoelectron spectroscopy, transmission electron microscope, low-pressure N2 adsorption, spontaneous imbibition, and high-pressure methane adsorption, were used to analyze the micro storage and sealing capacities of the deep shale reservoirs. The results show that, different from shallow shale reservoirs (<3500 m), deep shale reservoirs have a higher graphitization degree and water saturation. An abundance of graphite structures often leads to weak resistance of organic matter to compression, deformation, or even collapse of pores in organic matter and severe damage to the gas storage space. However, a higher degree of graphitization can enhance the ability of the shale reservoirs to adsorb gas and self-sealing. The high water saturation in the reservoirs can interact with clay minerals and negatively affect the gas accumulation, storage, and transmission capacities of the shale reservoirs. However, the upper shale reservoirs with higher water saturation can seal the lower shale reservoirs, helping it preserve shale gas. Based on the vertical distribution of graphite structure, clay minerals contents, lithofacies, and water content in deep shale reservoirs, the essential microscopic conditions for deep shale reservoirs to have high gas content were proposed. This paper provides a detailed explanation and evaluation of deep shale’s storage and sealing capacities at the microscopic scale and can serve as a reference for further identifying the patterns for high-yield and rich shale gas reservoirs and improving deep shale gas exploration technologies.

Mechanical behavior and constitutive model of shale under real-time high temperature and high stress conditions

The high temperature and high in-situ stress geological environment can significantly affect the mechanical properties, failure modes, and deformation characteristics of deep shale reservoirs. In this study, real-time high temperature triaxial compressive tests simulating the deep shale formation environment (temperature: 25–150 °C, confining pressure: 0–100 MPa) are carried out. The GSI-strength degradation and constitutive models are derived based on the Hoek–Brown criterion. The results show that in low confining pressure conditions, the mechanical behavior of shale is greatly influenced by temperature. Compared with shale at 25 °C, the compressive strength of shale at 150 °C decreases by up to 13.7%, and the elastic modulus decreases by up to 36.9%. The peak strain was increased by a factor of up to 1.4, and the yield stress level was advanced by as much as 7.4%. However, in high confining pressure conditions, the shale plasticity characteristics are significantly enhanced and the failure mode is relatively single. The GSI-strength degradation model can well characterize the variation law of shale strength with confining pressure under high temperature conditions. The statistical damage constitutive model matches the actual stress–strain curve very well, and it can fully reflect the deformation and failure characteristics of deep shale. The findings of this study can help us better understand the variation of mechanical properties of deep shale.

Simulation and regulation of fractures asynchronous initiation-propagation for deep shale gas horizontal well fracturing

The intensive cluster fracturing technology is widely applied in deep shale reservoirs. However, field data show that the fracture initiation time and propagation length of each cluster are different, which causes significant non-uniformity and affects the fracturing results. In this paper, a hydraulic fracture asynchronous initiation and propagation model for deep shale gas is established based on mechanics theory, which can consider the influence of in-situ stress variation and stress interference effect on the fracture asynchronous initiation and propagation behavior. According to the model design parameters, deep shale hydraulic fractures are regulated and optimized in combination with the non-uniform flow-limiting perforation technology to achieve uniform fracture propagation. The results show that, the non-uniformity of each fracture is obvious using conventional uniform perforation. However, with non-uniform perforation, each cluster perforation number is adjusted, the difference of initiation time and each fracture propagation velocity is significantly reduced, and the length of all fractures tend to be basically the same. And the field monitoring data are in good agreement with the calculation results, which verifies the reliability of the model. This study can reduce design blindness of non-uniform flow-limiting perforation technique, and has an important theoretical guidance for the optimal design of fracturing.

Experimental investigation of the tensile behavior and acoustic emission characteristics of anisotropic shale under geothermal environment

Shale gas is becoming a top priority for future global energy consumption and climate change mitigation, and deep and ultradeep shale gas extraction cannot overlook the influence of the geothermal environment. This paper experimentally investigated the tensile behavior and acoustic emission (AE) characteristics of anisotropic shale under geothermal environment of 25–200 °C. The results indicate that the tensile strength and absorbed energy of all specimens decreased with increasing temperature, and minimum values occurred in specimens with a layer inclination of 90° at each temperature. The evolution of tensile strength and absorbed energy versus the layer inclination did not vary with increasing temperature, exhibiting an inverted-V shape. Anisotropic failure mode of specimens with layer inclinations of 30°, 45° and 60° was influenced by the increasing temperature, but central tensile fracturing in specimens with layer inclinations of 0° and 90° was temperature-independent. With increasing temperature, the cumulative AE hits of specimens showed a highly obvious step-up trend, and anisotropic crack initiation stress levels obtained via the AE definition significantly varied. Finally, microstructure response, fracture length and fracture location and proportion of fracture types were discussed, and potential applications and challenges of geothermal environment in hydraulic fracturing of deep shale reservoirs were proposed.

Quantitative evaluation and influencing factors analysis of the brittleness of deep shale reservoir based on multiply rock mechanics experiments

Due to a great increase in the plasticity of deep marine shale reservoirs in southern Sichuan under high-temperature and high-pressure conditions, the single brittleness evaluation method is difficult to effectively characterize its fracability, which significantly limits the selection of sweet spots and fracturing reconstruction in the area. In the case of the deep marine shale reservoir of the Wufeng-Longmaxi formations in the southern Sichuan Basin, through triaxial high-temperature and high-pressure experiments, fracture toughness and X-ray diffraction experiments, the mechanical properties and its influencing factors in the shale reservoir are studied, and the rock fracture morphology under various loading conditions is quantified. According to the morphological characteristics of shale, the analysis of influencing factors and comprehensive quantitative evaluation of the brittleness has been carried out. The deep marine shale resource in the southern Sichuan Basin is likely to be characterized by its high elastic modulus and low I fracture toughness. The mineral composition, temperature, pressure, and degree of bedding development are the primary factors for determining the brittleness; with high quartz mineral content (>50%), low confining pressure (<20 MPa), medium and low temperature (<60 °C) and high density of the shale bedding, the fractal dimension of the sample after the experiment is higher; whereas the geometry of cracks are mainly complex shear cracks, and brittleness is higher. The analytic hierarchy approach establishes a comprehensive evaluation index by analyzing the relationship between the normalized rock mechanical parameters, the stress–strain curve's brittleness index, and the fractal dimension. The brittleness of deep marine shale can be more accurately described by this evaluation index. The primary target layer for future shale gas exploitation, the 31 sublayer of the first member of the Longmaxi Formation, is shown to have a high brittleness index.

Fracture network types revealed by well test curves for shale reservoirs in the Sichuan Basin, China

Pressure buildup testing can be used to analyze fracture network characteristics and conduct quantitative interpretation of relevant parameters for shale gas wells, thus providing bases for assessing the well productivity and formulating proper development strategies. This study establishes a new well test interpretation model for fractured horizontal wells based on seepage mechanisms of shale reservoirs and proposes a method for identifying fracturing patterns based on the characteristic slopes of pressure buildup curves and curve combination patterns. The pressure buildup curve patterns are identified to represent three types of shale reservoirs in the Sichuan Basin, namely the moderately deep shale reservoirs with high pressure, deep shale reservoirs with ultra-high pressure, and moderately deep shale reservoirs with normal pressure. Based on this, the relationship between the typical pressure buildup curve patterns and the fracture network types are put forward. Fracturing effects of three types of shale gas reservoir are compared and analyzed. The results show that typical flow patterns of shale reservoirs include bilinear flow in primary and secondary fractures, linear flow in secondary fractures, bilinear flow in secondary fractures and matrix, and linear flow in matrix. The fracture network characteristics can be determined using the characteristic slopes of pressure buildup curves and curve combinations. The linear flow in early secondary fractures is increasingly distinct with an increase in primary fracture conductivity. Moreover, the bilinear flow in secondary fractures and matrix and the subsequent linear flow in the matrix occur as the propping and density of secondary fractures increase. The increase in the burial depth, in-situ stress, and stress difference corresponds to a decrease in the propping of primary fractures that expand along different directions in the shale gas wells in the Sichuan Basin. Four pressure buildup curve patterns exist in the Sichuan Basin and its periphery. The pattern of pressure buildup curves of shale reservoirs in the Yongchuan area can be described as 1/2 → 1/4, indicating limited stimulated reservoir volume, poorly propped secondary fractures, and the forming of primary fractures that extend only to certain directions. The pressure buildup curves of shale reservoirs in the main block of the Fuling area show a pattern of 1/4 → 1/2 or 1/2, indicating greater stimulated reservoir volume, well propped secondary fractures, and the forming of complex fracture networks. The pattern of pressure buildup curves of shale reservoirs in the Pingqiao area is 1/2 → 1/4 → 1/2, indicating a fracturing effect somewhere between that of the Fuling and Yongchuan areas. For reservoirs with normal pressure, it is difficult to determine fracture network characteristics from pressure buildup curves due to insufficient formation energy and limited liquid drainage.

Tensile mechanical properties and AE characteristics of shale in triaxial Brazilian splitting tests

Under the high temperature and high stress geological environment, how the physical and mechanical properties of deep shale reservoirs will change has become a hot research issue. Based on the Confined Brazilian Test, this paper improves a test method for the tensile strength of shale under triaxial conditions with a simple specimen fixture and convenient specimen preparation and performs a high confining pressure (0–60 MPa) Brazilian splitting test on Longmaxi Formation shales. The stress-displacement curve records the deformation and failure of shale. Acoustic emission technology (AET) detects the evolution process of fractures and further identifies failure modes. 3D optical scanning system reconstructs the fracture morphology. The results show that the maximum tensile strength of the shale specimens in the triaxial condition is increased by 58.5% relative to direct tensile strength. As the confining pressure gradually increases to 60 MPa, the specimen enters the stress state of compressed in three directions, the tensile failure mode gradually transitions to shear failure mode via tensile-shear composite failure mode, and the fracture angle gradually increases. The AE signal in triaxial conditions mainly shows a leap trend. The appearance of AE signal with high peak frequency can be used as a reference for micro-fracture initiation. The presence of shear fractures increases the roughness of the shale main fracture surface, and this effect diminishes as the confining pressure increases. This study can provide a reliable theoretical basis for the optimal design of hydraulic fracturing in deep shale gas reservoirs.

Frictional stability of Longmaxi shale gouges and its implication for deep seismic potential in the southeastern Sichuan Basin

AbstractMicroearthquakes accompanying shale gas recovery highlight the importance of exploring the frictional and stability properties of shale gouges. Aiming to reveal the influencing factors on fault stability, this paper explores the impact of mineral compositions, effective stress and temperature on the frictional stability of Longmaxi shale gouges in deep reservoirs located in the Luzhou area, southeastern Sichuan Basin. Eleven shear experiments were conducted to define the frictional strength and stability of five shale gouges. The specific experimental conditions were as follows: temperatures: 90–270°C; a confining stress: 95 MPa; and pore fluid pressures: 25–55 MPa. The results show that all five shale gouges generally display high frictional strength with friction coefficients ranging from 0.60 to 0.70 at the aforementioned experiment condition of pressures, and temperatures. Frictional stability is significantly affected by temperature and mineral compositions, but is insensitive to variation in pore fluid pressures. Fault instability is enhanced at higher temperatures (especially at &gt;200°C) and with higher tectosilicate/carbonate contents. The results demonstrate that the combined effect of mineral composition and temperature is particularly important for induced seismicity during hydraulic fracturing in deep shale reservoirs.

Hydraulic Fracturing Fluid Interactions With Steel, Cement, and Shale Measured

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3722736, “The Impact of Hydraulic Fracturing Fluid on the Near-Wellbore Shale Region Involving Interactions With Steel, Cement, and Shale,” by Wei Xiong, Brandon McAdams, and Mengling Stuckman, National Energy Technology Laboratory, et al. The paper has not been peer reviewed. _ Numerous studies have been conducted on rock/fluid interactions of deep shale reservoirs exposed to hydraulic fracturing fluid (HFF). However, the effect of fluid/steel/cement components on the chemistry of the near-wellbore shale region has been overlooked. In the study described in the complete paper, steel, cement, and shale samples were exposed to HFF sequentially in the same batch for 3 days at 66°C. Unlike the reaction of fresh HFF to direct exposure to shale, the fluid chemistry and exposed surfaces of steel and cement were altered significantly after exposure. Methods Sequential Exposure Experiment. For the sequential exposure batch, three steel coupons were placed at the bottom of a borosilicate bottle with 300 mL of HFF. After 3 days of exposure, all three steel coupons were removed. 100 mL of the reacted fluid was collected and filtered for fluid-chemistry analysis. Then, two cement coupons were placed in the bottle to react with the remaining 200 mL of fluid at the same temperature. After 3 days of reaction, the two cement coupons were removed with 100 mL of fluid as a liquid sample. Finally, one shale sample was placed in the bottle, exposed to the remaining 100 mL of fluid for 3 days. A controlled group using individual coupons was the subject of experiments using the same setup. One steel, cement, or shale coupon was placed in each bottle with 100 mL of HFF individually. A blank group with 100 mL of HFF without any coupons also was set up at the same conditions. These control groups reacted for 3 days. Analytical Methods. A three-electrode voltametric system was composed of a mercury/gold (Hg/Au) amalgam 100-µm-disc working electrode (WE), a solid-state silver/silver-chloride (Ag/AgCl) reference electrode (RE), and a platinum wire counter, or auxiliary, electrode (CE). The species undergoes oxidation or reduction at the WE interface at a potential measured against the potential of the RE wherein any exchange of electrons at the WE interface is compensated by the CE to complete the circuit within the potentiostat. Peaks observed in complex solutions like those in this study can be compared with known responses in previous studies to arrive at a qualitative assessment of what is happening, and when, in these solutions with respect to redox chemistry. For the purposes of continuity, all potentials reported in the complete paper are in relation to the Ag/AgCl reference electrode and require a positive adjustment of approximately 0.21 V.

Impact of Supercritical CO2 on Shale Reservoirs and Its Implication for CO2 Sequestration

Hydraulic fracturing has transformed the international energy landscape by becoming the go-to method for the exploitation of natural gas from unconventional shale reservoirs. However, in the recent years, the search for an alternative method of shale-gas exploration has intensified, because of various problems (e.g., contamination of ground and surface water, overexploitation of precious water resources, air pollution, etc.) associated with the usage of water-based fracturing techniques. The use of CO2 for shale gas exploitation has emerged as a better alternative to aqueous-based gas exploration techniques. CO2 when injected into deep shale reservoirs, transitions into supercritical CO2 (SC-CO2) when temperature and pressure condition exceeds the critical point, i.e., 31.1 °C and 7.38 MPa. In this paper, we comprehensively review the impact of SC-CO2 on shale gas reservoirs during the different stages of shale-gas exploration, i.e., (i) drilling, which involves the superiority of SC-CO2 over water-based drilling fluids, in terms of achieving under-balanced well condition, higher rates of penetration, and resistance to formation damage; (ii) fracturing, which involves factors affecting the tortuosity of fractures created by SC-CO2 fracturing, breakdown pressure, and proppant-carrying capacity; and (iii) injection, which involves the twin-headed benefit of enhanced recovery due to CO2/CH4 competitive adsorption and geological sequestration, CO2 vs CH4 excess sorption as a function of pressure, etc. Several research works have indicated discrepancies on how SC-CO2 impacts different shale properties. Some studies show low-pressure N2-gas-adsorption-derived surface area and total pore volume to be increasing with SC-CO2 imbibition, while others show a decreasing trend for the same. Similarly, for some shales, the quartz content, along with the clay mineral contents, decreased as the exposure to SC-CO2 increased, while in some other studies, with similar long-term exposure to SC-CO2, the quartz content was observed to increase along with the decrease in clay content and vice versa. Essentially, the increased exposure to SC-CO2 results in the dissolution of primary porous structures and fractures, and reformation of newer porous structure and conduits in shales. Nonetheless, these changes in the mineralogy weaken the microstructure of the rock bringing significant changes in the mechanical properties of the shales with implications on the wellbore stability and fracturing efficiency. The mechanical properties such as uniaxial compressive strength (UCS), Young’s modulus, and tensile strength decrease as the SC-CO2 saturation period increases. However, some studies have shown factors like bedding angle and phase-state of CO2 having varying effect on the strength behavior of the shales. Moreover, changes in the structure of shales caused by the creation of fractures and the reduction of their strength can also pose major risks, because of potential leakage of CO2 through these created pathways. How these processes would interact at field scale would control the sealing capacity, especially at field-scale for addressing long-term seepage of CO2.

Enrichment characteristics and exploration directions of deep shale gas of Ordovician–Silurian in the Sichuan Basin and its surrounding areas, China

The enrichment characteristics of deep shale gas in the Ordovician Wufeng–Silurian Longmaxi formations in the Sichuan Basin and its surrounding areas are investigated through experiments under high temperature and high pressure, including petrophysical properties analyses, triaxial stress test and isothermal adsorption of methane experiment. (1) The deep shale reservoirs drop significantly in porosity and permeability compared with shallower shale reservoirs, and contain mainly free gas. (2) With higher deviatoric stress and axial strain, the deep shale reservoirs have higher difficulty fracturing. (3) Affected by structural location and morphology, fracture characteristics, geofluid activity stages and intensity, deep shale gas reservoirs have more complicated preservation conditions. (4) To achieve the commercial development of deep shale gas reservoirs, deepening geological understanding is the basis, and exploring reservoir simulation technology befitting the geological features is the key. (5) The siliceous shale and limestone-bearing siliceous shale in the Metabolograptus persculptus–Parakidograptus acuminatus zones (LM1–LM3 graptolite zones) are the high-production intervals for deep shale gas and the most favorable landing targets for horizontal drilling. Deeps water areas such as Jiaoshiba, Wulong, Luzhou and Changning with deep shale reservoirs over 10 m thickness are the most favorable areas for deep shale gas enrichment. It is recommended to carry out exploration and development practice in deep-water shale gas areas deposited deep with burial depth no more than 5000 m where the geological structure is simple and the shale thickness in the LM1–LM3 graptolite zone is greater than 10 m. It is better to increase the lateral length of horizontal wells, and apply techniques including high intensity of perforations, large volume of proppant, far-field and near-wellbore diversions to maximize the stimulated deep reservoir volume.

Changes in thermophysical and thermomechanical properties of thermally treated anisotropic shale after water cooling

Shale gas has become the development focus of many countries recently for its strategic importance, and the deep shale gas extraction is becoming a priority worldwide. Water-based drilling and fracturing fluid can inevitably lead to an intense heat exchange on deep high-temperature shale reservoirs, thus understanding the changes in thermophysical and thermomechanical properties of deep shale reservoirs after being subjected to water cooling is essential. In this present work, the changes in thermophysical and thermomechanical properties of thermally treated shale specimens (25–200 ℃) with five kinds of bedding plane inclinations (BPI) of 0°, 30°, 45°, 60° and 90° after water cooling are researched in the lab. Results illustrate that as temperature increases, the density and P-wave velocity obviously decrease and the porosity increase for shale specimens with the five different BPI after thermal treatment and water cooling. Dynamic uniaxial compression strength of all the specimens after thermal treatment and water cooling decreases gradually with increasing temperature, while the static one increases except for specimens with the BPI of 60°. The dynamic and static strength anisotropy of specimens became more obvious with increasing temperature, but the treatment temperature does not act well in changing the anisotropic evolution trend under the two conditions. In the end, the overall response of anisotropic shale after thermal treatment and water cooling is discussed by the results of scanning electron microscope (SEM) and ABAQUS numerical simulation, and the mechanism of dynamic and static strength response is systematically revealed. The findings are hoped to provide theoretical guidance and technical support for the deep shale gas extraction.

Parameter Sensitivity Analysis of the Hydraulic Fracture Growth Geometry in a Deep Shale Oil Formation: An Experimental Study

The depth of shale oil of Fengcheng Formation in Mahu of Junggar Basin, China, is 4500-5000 m. The horizontal principal stress difference of deep shale reservoir is high, which makes it difficult to form complex fractures during fracturing reconstruction. In order to fully understand the law of hydraulic fracture propagation in the formation during fracturing construction, the anisotropy characteristics and basic reservoir physical parameters (mineral composition and rock strength parameters) of rock were obtained through mineral composition test and indoor rock mechanics test (Brazil splitting test), and it was found that the heterogeneity was strong. The true triaxial fracturing simulation experimental system is used to carry out experimental research on full-diameter core rock samples, and the propagation patterns of hydraulic fractures under the influence of different geological factors (in situ stress difference and natural fractures) and engineering factors (pumping rate and fracturing fluid viscosity) are compared and analyzed. The results show that the in situ stress is the most important factor affecting fracture propagation, which determines the direction and shape of fracture propagation. The natural weak surface (lamina/bedding and natural fractures, etc.) in shale reservoir is an important reason for complex fractures. The nature of the weak plane, occurrence, and in situ stress jointly determine whether the fracture can extend through the weak plane. With the increase of pumping rate (18 mL/min to 30 mL/min), the ability of hydraulic fractures to penetrate layers is continuously enhanced. The horizontal principal stress difference of deep shale reservoir is high, and the low viscosity fracturing fluid (10 mPa·s) tends to activate the horizontal bedding, while the high viscosity fracturing fluid (80 mPa·s) tends to directly penetrate the bedding to form the vertical main fracture. Therefore, the fracturing technology of alternating injection of prehigh viscosity fracturing fluid and postlow viscosity fracturing fluid can be adopted to maximize the complexity of fracturing fractures in deep shale reservoirs. The research results are designed to provide theoretical guidance for prediction of hydraulic fracturing fracture propagation in shale reservoir and have certain reference significance for field construction.

Study on vertical multifracture propagations in deep shale reservoir with natural fracture network

AbstractBuilding a complex fracture network in a deep shale gas reservoir during multicluster hydraulic fracturing is challenging. On the one hand, hydraulic fractures tend to propagate along shale bedding planes, thus leading to a limited hydraulic fracture height; on the other hand, under the effect of high in situ stress and weak plane of fractures, multihydraulic fractures can hardly initiate and propagate uniformly. All of these will jeopardize the performance of hydraulic fracturing. This paper considers the influence of natural fracture network, shale beddings, fracturing‐fluid leakage, and high in situ stresses, and builds a numerical model to simulate multifracture propagations along vertical direction during hydraulic fracturing in deep shale reservoirs. The model is developed based on the theory of solid–fluid coupling and finite element method with pore pressure cohesive element technique are used to simulate multicluster fracture initiation and propagation. Moreover, the model is verified by published experiment data, and a good agreement between model and experiment results is observed. The influences of pump rate and fracturing‐fluid viscosity on fracture geometry are discussed, and the flow dynamics around each perforation cluster under different perforation parameters are also studied. Finally, suggestions to improve overall outcome of multicluster hydraulic fracturing are also provided.

Pore Structure Characteristics and Their Controlling Factors of Deep Shale: A Case Study of the Lower Silurian Longmaxi Formation in the Luzhou Area, Southern Sichuan Basin.

Recently, deep shale reservoirs are emerging as time requires and commence occupying a significant position in the further development of shale gas. However, the understanding of pore characteristics in deep shale remains poor, prohibiting accurate estimation of the hydrocarbon content and insights into fluid mobility. This study focuses on the Longmaxi Formation from the Luzhou (LZ) region, southern Sichuan. Scanning electron microscopy (SEM), low-temperature N2/CO2 adsorption, X-ray diffraction, and geochemical analysis were performed to investigate the micro–nanopore size distribution, main controlling factors, and unique pore features distinct from other regions. Results showed that the pores can be classified into four categories, organic matter (OM) pores, intergranular pores, intragranular pores, and microfractures, according to SEM images. The total pore volume is overwhelmingly dominated by mesopores and contributed by pores in the range of 0.5–0.6, 2–4, and 10–30 nm. The specific surface area is primarily contributed by micropores and mesopores in the range of 0.5–0.7 and 2–4 nm. By analyzing the influencing factors extensively, it is concluded that the buried depth, geochemical factors, and mineral composition can impact the pore structure in the overmature deep shales. Specifically, the total organic carbon content plays a more effective and positive role in the development of micropores, mesopores, total pores, and the porosity when compared with vitreous reflectance (Ro). The micropores are inferred to be OM-related. On the contrary, clay mineral is detrimental to the development of micropores and mesopores and the petrophysical properties (porosity and permeability), which may be attributed to the occurrence of chlorite and kaolinite instead of illite. The plagioclase conforms to the same law as clay due to their coexistence. Quartz, carbonate minerals, and pyrite can barely contribute to the pores. Eventually, the compared results suggest that the Longmaxi Formation of the LZ region are qualified with a superior pore size distribution, complicated structure, and diverse morphology, implying a potential to generate and store hydrocarbons. Overall, this study improves the understanding of complex pore structures in deep shale and provides significant insights into the development and exploration of unconventional resources in the future.

Mechanical response to dynamic compressive load applied to shale after thermal treatment

In deep shale gas extraction, high temperature environment and dynamic loads are two important factors in affecting reservoir reconstruction and shale breaking. By employing the test techniques of Split Hopkinson pressure bar, dynamic compressive mechanical response of shale specimens with five different bedding dips after thermal treatment of 25–200 °C was investigated under the same impact energy. Results reveal that the increasing thermal treatment temperature weakens the post-peak behavior in stress-strain curves of specimens with bedding dips of 0°, 30° and 90°, and strengthens that of specimens with bedding dips of 45° and 60°. The dynamic compression strength variation of specimens versus increasing thermal treatment temperature shows two opposite trends bounded by the bedding dip of 30°. With increasing thermal treatment temperature, failure mode of specimens with bedding dips of 45° and 60° is affected evidently, but that of specimens with bedding dips of 0°, 30° and 90° has no fundamental change. The increasing thermal treatment temperature impacts the amount of absorbed energy in one of two ways depending on the bedding dip, and increases the dynamic fragmentation degree of all specimens, but that of specimens with bedding dips of 45° and 60° is much larger. Furthermore, the dynamic anisotropy of specimens after thermal treatment and its possible application in deep shale gas extraction are discussed. Results can be beneficial to the perforation design in hydraulic fracturing and the dynamic fracturing technology development in deep shale reservoirs.

A Laboratory Approach Considering Salinity to Investigate Archie’s Parameters in Deep Shale: A Case Study in Longmaxi Formation, Southern Sichuan

Archie’s parameters are substantial to be investigated in the evaluation of water saturation. Many researchers adhered to the opinion that Archie’s equation can still be applied to water saturation calculation in shale if the accuracy of relative parameters could be improved. External conditions, such as temperature, confining pressure, water salinity, wettability, and displacement, may influence the determination of Archie’s parameters. The aim of the study is to investigate the effect of salinity on Archie’s parameters and their correlation with mineral composition and pore structure. The mineral contents and petrophysical properties were firstly acquired through X-ray diffraction (XRD) and basic measurements. Rock-electric experiments under different salinity were conducted on deep shale samples taken from Longmaxi (LMX) Formation in Luzhou (LZ). The results indicate that Archie’s parameters of “ a ,” “ b ,” “ m ,” and “ n ” under actual brine salinity are assigned to 1.47, 1, 1.26, and 1.6, respectively. Our cementation factor is lower than that in other studies including (shaly) sandstones, carbonates, and shales, probably due to the extremely low porosity in study area. Salinity has a positive effect on cementation factor ( m ) and saturation exponent ( n ), suggesting the traditional assignment to Archie’s parameters is inappropriate. It was concluded that the complicated pore structure and high porosity mainly associated with clay mineral may trigger the increased cementation factor. Further mathematical derivations confirmed that the rock resistivity is inextricable from pore system and establish a physical model. The paper provides a solid evidence base for further understanding and evaluation of water saturation in unconventional shale reservoirs, more significantly, innovatively unveils the research into Archie formula in deep shale reservoirs of southern Sichuan basin.

Geomechanical Modeling and Inversion Analysis of the in-situ Stress Field in Deep Marine Shale Formations: A Case Study of the Longmaxi Formation, Dingshan Area, China

Based on the comprehensive analysis of wellbore characteristics in a deep shale gas field, the in-situ stress state of the shale reservoir was assessed in this study for the Longmaxi formation in the Dingshan area, Southwestern China. The data obtained from hydraulic fracturing, drilling-induced fractures, and in-situ core testing were used to determine the magnitude and direction of the maximum principal horizontal stress in five wells. Besides, hydraulic fracturing and cross-multipole array acoustic logging (XMAC) were employed to determine the vertical variation of the in-situ stress. Based on the logging interpretation and mechanical test results, the spatial distribution of rock mechanical parameters in the Dingshan area was assessed by the amplitude variation versus offset (AVO) seismic inversion. A 3D heterogeneous mechanical inversion model was realized via the ANSYS and CATIA3D finite element software packages, providing the area in-situ stress field simulation. The depth, fault strike, and position change effects on the main stress, horizontal stress difference, and horizontal stress difference coefficient were numerically simulated. The results show that the maximum principal stress azimuth was mainly concentrated in the NE20°-NE80° sector. Moreover, the development zone of natural fractures was related to the area with the highest principal stress differences. The maximum principal stress variation in the study area was mainly in the compressive range from −135 to −45 MPa, gradually increasing from east to west and south to north. The stress type mainly depended on the depth, fault strike, and rock mechanical parameters, while the stress difference and stress difference coefficient near the fault structure were relatively small. This study’s findings are considered instrumental in improving the borehole stability, determining the casing setting point, and optimizing the well location in deep shale reservoirs with similar geological conditions.

Experimental characterization and molecular modeling of kerogen in Silurian deep gas shale from southern Sichuan Basin, China

A representative molecular model of kerogen is the prerequisite to the study on molecular interaction of fluid molecules with organic nanopores of shale. The molecular kerogen model in Silurian deep gas shale from southern China remains to be developed. In this work, the chemical structure of the targeted deep shale kerogen is characterized by organic geochemical measurements. The derived structural parameters are utilized to build the molecular structure of the kerogen unit. The kerogen unit shows a good representation of realistic kerogen structure in shale reservoir in terms of carbon skeleton, heteroatomic compositions and groups. The kerogen matrix and a extended kerogen slit model are constructed based on the kerogen unit, which match well with the experimental results in matrix density and kerogen porosity, respectively. The kerogen matrix is overall disordered with gentle stacking of polyaromatic fragments, due to the bendable aliphatic linkages and large-size aromatic units. The kerogen nanopores are not saturated with methane at deep shale reservoir conditions. At high pressure, the absolute adsorption tends to reach a maximum, while the excess adsorption shows a decreasing trend. The effect of pressure on the dissolved gas density is not pronounced. The generated kerogen model can serve as a starting point for further theoretical investigations on fluid storage and transport in organic nanopores of deep shale reservoir at microscopic scale.

A Comparison of Shale Gas Fracturing Based on Deep and Shallow Shale Reservoirs in the United States and China

China began to build its national shale gas demonstration area in 2012. The central exploration, drilling, and development technologies for medium and shallow marine shale reservoirs with less than 3,500 m of buried depth in Changning-Weiyuan, Zhaotong, and other regions had matured. In this study, we macroscopically investigated the development history of shale gas in the United States and China and compared the physical and mechanical conditions of deep and shallow reservoirs. The comparative results revealed that the main reasons for the order-ofmagnitude difference between China’s annual shale gas output and the United States could be attributed to three aspects: reservoir buried depth, reservoir physical and mechanical properties, and engineering technology level. The current engineering technology level of China could not meet the requirements of increasing production and reducing costs for deep shale gas reservoirs; they had reached the beneficial threshold development stage and lacked the capacity for large-scale commercial production. We identified several physical and mechanical reasons for this threshold development stage. Deep shale reservoirs were affected by the bedding fracture, low brittleness index, low clay mineral content, and significant areal differences, as well as by the transformation from elasticity to plasticity, difficulty in sanding, and high mechanical and strength parameters. Simultaneously, they were accompanied by six high values of formation temperature, horizontal principal stress difference, pore pressure, fracture pressure, extension pressure, and closure pressure. The key to deep shale gas horizontal well fracturing was to improve the complexity of the hydraulic fracture network, form adequate proppant support of fracture surface, and increase the practical stimulated reservoir volume (SRV), which accompanied visual hydraulic discrete network monitoring. On this basis, we proposed several ideas to improve China’s deep shale gas development involving advanced technology systems, developing tools, and supporting technologies in shale gas exploration and development in the United States. These ideas primarily involved stimulation technologies, such as vertically integrated dessert identification and optimization, horizontal well multistage/multicluster fracturing, staged tools development for horizontal wells, fractures network morphology monitoring by microseismic and distributed optical fiber, shale hydration expansion, soak well, and fracturing fluid flow back. China initially developed the critical technology of horizontal well large-scale and high-strength volume fracturing with a core of “staged fracturing with dense cutting + shorter cluster spacing + fracture reorientation by pitching + forced-sand addition + increasing diameter perforating + proppant combination by high strength and small particle size particles”. We concluded that China should continue to conduct critical research on theories and technical methods of horizontal well fracturing, suitable for domestic deep and ultra-deep marine and marine-continental sedimentary shale, to support and promote the efficient development of shale gas in China in the future. It is essential to balance the relationship between the overall utilization degree of the gas reservoir and associated economic benefits and to localize some essential tools and supporting technologies. These findings can contribute to the flourishing developments of China’s deep shale gas.