Deep Shale Research Articles

Natural fractures and their attributes in organic-rich shales: Insights from the Paleozoic Wufeng-Longmaxi formation, southeastern Sichuan Basin

Fractures in organic-rich shale affect the evolution of permeability and control shale gas preservation. We characterize fracture attributes in the Qiyue-Huaying Fold-Thrust belt in the southeastern Sichuan Basin, revealing the distribution, origin and factors controlling fracture localization through investigation of cores, image logs, and thin section petrography. We found that the deformation intensity, organic matter content and lithology are the major factors for controlling fracture occurrence and location in the Wufeng-Longmaxi deep shale. The major fracture pattern in the Fuling Block is characterized by abundant inclined shear fractures, bed-parallel shear fractures, and bed-normal extension fractures, while bed-parallel veins prevail in the Luzhou Block. In general, fracture density and size in the Fuling Block are larger than those in the Luzhou Block. The competent layers (siliceous shale with high TOC) have the highest fracture density, and noticeably, organic matter content controls bed-parallel vein localization. Based on the distribution of fractures in two blocks, we suggest that the dominant origin of fractures in organic-rich shale gradually changes from tectonic events to fluid pressure changes due to organic maturation (organic events), from the Fuling Block to the Luzhou Block.

Model for fracture conductivity considering particle size redistribution caused by proppant crushing

Clarifying the dynamic evolution and control mechanisms of fracture conductivity is crucial for optimizing hydraulic fracturing design. Previous studies on fracture conductivity mechanisms in deep shale reservoirs have been insufficient, particularly when considering proppant crushing, rendering existing models inapplicable. Therefore, in this study, the coupled effects of particle size redistribution caused by proppant crushing were considered. A particle crushing model based on fractal theory was introduced. It was combined with the Kozeny–Carman equation, and equations were derived for the evolution of the equivalent diameter of the proppant pile gradation curve and permeability, establishing a new model for predicting the fracture conductivity considering the particle size redistribution caused by proppant crushing. Furthermore, it provides an optimized chart of conductivity that matches the supply conductivity of the reservoir. The results of the study reveal that the fracture conductivity decreases owing to proppant rearrangement, compaction, and crushing, with a more significant decline in the initial compression stage, where the rate of conductivity reduction is 2.5 times that of the compaction stage. Proppant crushing shifts the gradation curve leftward, reducing the equivalent particle diameter and, consequently, the fracture conductivity. By adjusting the crushing ratio, apparent Young's modulus, looseness factor, and proportion of large-particle components of the proppant, the fracture conductivity can be controlled. This provides a theoretical basis for the development of proppant properties and fracturing optimization in deep shale reservoirs.

Experimental study of hydraulic fracturing for deep shale reservoir

Compared with shallow reservoirs of shale gas, the high stress and plasticity of shale reservoirs under deep conditions significantly impact the propagation of hydraulic fractures. The study investigates the characteristics of hydraulic fracture propagation in deep shale reservoirs by conducting true triaxial fracturing tests at different stress levels and combinations under circumstances close to the original in-situ stress of the target reservoir. Specifically, it includes comparative experiments under high and low-stress levels, variable stress combinations with equal stress differences, and experiments on the influence of maximum and minimum horizontal in-situ stress, respectively. Through a series of experimental studies, it has been shown that the fracture roughness is relatively low at high stress levels. Fractures can still generate complex and multiple fractures when subject to high-stress conditions. Amongst, natural fissures or weak surfaces still dominate the complex fracture morphology. In the case of a higher in-situ stress level with the same stress difference value brings about a more complex hydraulic fracture morphology as a result of a smaller stress-difference coefficient. The Intersection of hydraulic fractures with multiple parallel weak surfaces creates hydraulic fractures in stepped shape, which can cause drastic fluctuations in injection pressure. The research results provide a reference for on-site deep shale reservoir stimulation and optimization of a fracturing design.

Theoretical analysis and field application of cooling bottom hole by mud density reduction during drilling in deep shale gas well

During deep shale gas well drilling process, high bottom hole temperature (≥150 °C) often causes the conventional rotary steerable tool and logging while drilling (LWD) to malfunction. Therefore, it is essential to reduce the bottom hole temperature for safe and efficient drilling. In this paper, a simplified wellbore temperature model for deep shale gas horizontal well was established based on thermodynamic theory, comprehensively accounting for both mechanical and hydraulic heat source. A quantitative analysis was performed to assess the impact of rheological parameters, engineering parameters, thermal parameters and two cooling methods on bottom hole temperature. In addition, a density reduction and cooling scheme for drilling in the horizontal section was developed and implemented on H-29-1 and H-29-6 Well. The results indicated that the temperature model is in good agreement with the Kirbir & Hasan model and real-time measurement data with an error less than ±6 %. Mud density, behavior index, pump rate, weight on bit (WOB) and geothermal gradient had great influence on the bottom hole temperature (up to over 30 °C). If the horizontal section is shorter than 1000 m, reducing the inlet temperature can effectively reduce the bottom hole temperature. But once the horizontal section exceeds 1500 m, reducing mud density is much more effective. With field application on H-29-1 and H-29-6 Well, mud density was reduced from 2.25 g/cm3 to 1.80 g/cm3, resulting in a maximum bottom hole temperature of 143 °C in the horizontal section, and rotary steerable tools and screw worked stably in downhole. Compared to adjacent wells on the same platform that bottom hole temperatures are all above 152 °C, the maximum bottom hole temperature decreased by 9–13 °C. Furthermore, in the horizontal section, the Rate of Penetration (ROP) is increased by more than 48 %, the pump pressure is reduced by 2–5 MPa, and the average hole enlargement rate is only 1.92 %. All findings show that lower mud density can not only effectively reduce the bottom hole temperature, but also improve the drilling efficiency, which has positive significance for the development of deep shale gas.

Characterization of brittleness index of gas shale and its influence on favorable block exploitation in southwest China

The microstructure, mineral composition, total organic carbon content, etc., of gas shale are crucial parameters for shale reservoirs, which can directly/indirectly affect shale brittleness, fracturing effect, adsorption ability and production efficiency. The study proposed a workflow to characterize the physical and mechanical parameters of Lower Silurian Longmaxi shale outcrop samples extracted from the favorable block in Changning, Sichuan, southwest China. This study elaborated on the influence of these physical and mechanical characteristics and proposed a corresponding brittleness index on shale extraction. In addition, it put forward corresponding suggestions for development and risk control. For a better understanding the mechanisms of shale gas storage and production, XRD, XRF, SEM, low temperature Nitrogen adsorption method, nuclear magnetic resonance and other measurements were employed to analyze and study the mineral composition, microstructure, and adsorption performance of shale. The results demonstrated that the pores of shale are mainly slit pores; there are diverse pore types in shale, mainly including intergranular pores, mineral particle dissolution pores, and internal pores of organic matter; The samples with relatively low porosity also noticeably exhibit ultra-low permeability, and the nanopore structure is remarkably significant, with distribution primarily in range of 5–237 nm. Finally, a brittleness index considering the influence of water content and the mechanical properties was proposed, and the coupling interaction of various minerals components and mechanical properties on the brittleness index can more objectively reflect the brittleness characteristics of deep shale formation.

Integrated Analysis of Two-Phase Production Data in Hydraulic Fractured Deep Shale Reservoirs: Coupling Multiple Fluid Transport Mechanisms

Integrated Analysis of Two-Phase Production Data in Hydraulic Fractured Deep Shale Reservoirs: Coupling Multiple Fluid Transport Mechanisms

Characterization and fractal characteristics of nano-scale pore structure in shale gas reservoirs: a case study of the deep Longmaxi Formation, Zigong region, Southern Sichuan Basin, China

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.

Measures and results of prevention and control on casing deformation and frac-hit in deep shale gas wells in southern Sichuan Basin

Casing deformation and frac-hit pose significant challenges to the development of deep shale gas in southern Sichuan Basin. By analyzing the mechanism and main control factors of casing deformation and frac-hit, two kinds of risk assessment methods were defined, and the overall prevention and control concept and practice were formulated. The results show that initial stress, pore pressure, fault development and large scale fracturing in local block are the main factors leading to the deformation. The development of fracture through well group and uncontrolled fracturing fluid volume are the main factors leading to pressure channeling. Based on this, the risk classification technology of casing deformation and frac-hit is established, and the dual-optimal, dual-control concept and technology are formed. In terms of the prevention and control of casing deformation, the formation of small-diameter bridge plug fracturing, large section combined fracturing, glass beads cementing, single-well staggered and platform straddle fracturing mode, dual-dimension controlled and lift fracturing, hyperbolic diagnosis, etc. Frac-hit prevention and control formed pump sequence optimization mode, physical and chemical temporary plugging and other methods. The above technology achieved casing deformation rate decreased from 50.4% to 25.4%, frac-hit rate decreased from 58.6% to 33.9%, and the average well kilometer EUR reached 0.52–0.7 million square meters, an increase of 7.7% compared with the previous research, with remarkable results.

Differentiated Interval Structural Characteristics of Wufeng−Longmaxi Formation Deep Shale Gas Reservoirs in Western Chongqing Area, China: Experimental Investigation Based on Low-Field Nuclear Magnetic Resonance (NMR) and Fractal Modeling

Differentiated Interval Structural Characteristics of Wufeng−Longmaxi Formation Deep Shale Gas Reservoirs in Western Chongqing Area, China: Experimental Investigation Based on Low-Field Nuclear Magnetic Resonance (NMR) and Fractal Modeling

Segmentation Study of Deep Shale Gas Horizontal Wells of the South Sichuan Shale Gas

Summary The low porosity and low permeability of shale gas reservoirs make fracturing technology an indispensable part of shale gas reservoir development. The initial stage of shale gas development is characterized by shallow direct wells, but with the advancement of drilling and completion technology in the development of unconventional oil and gas reservoirs, horizontal wells and fracturing technology have gradually become the key methods for the effective development of oil and gas reservoirs. “Geology-engineering integration” has gradually become a hot spot in the research of horizontal well fracturing. The factors affecting the development of shale gas reservoirs are subdivided into “geological sweet spot” and “engineering sweet spot” influencing factors. Geological sweet spot refers to the area where the reservoir is rich in hydrocarbons or organic matter; engineering sweet spot refers to the area with good fracturability in the later fracturing and reforming of the reservoir. The shale gas sweet spot area should have the characteristics of high gas content, high fracturable, and high efficiency. Comprehensively evaluating the physical properties and brittleness characteristics can provide certain guidance for shale gas horizontal well segmentation.

A Review of Weak Gel Fracturing Fluids for Deep Shale Gas Reservoirs.

Low-viscosity slickwater fracturing fluids are a crucial technology for the commercial development of shallow shale gas. However, in deep shale gas formations with high pressure, a higher sand concentration is required to support fractures. Linear gel fracturing fluids and crosslinked gel fracturing fluids have a strong sand-carrying capacity, but the drag reduction effect is poor, and it needs to be pre-prepared to decrease the fracturing cost. Slick water fracturing fluids have a strong drag reduction effect and low cost, but their sand-carrying capacity is poor and the fracturing fluid sand ratio is low. The research and development of viscous slick water fracturing fluids solves this problem. It can be switched on-line between a low-viscosity slick water fracturing fluid and high-viscosity weak gel fracturing fluid, which significantly reduces the cost of single-well fracturing. A polyacrylamide drag reducer is the core additive of slick water fracturing fluids. By adjusting its concentration, the control of the on-line viscosity of fracturing fluid can be realized, that is, 'low viscosity for drag reduction, high viscosity for sand-carrying'. Therefore, this article introduces the research and application status of a linear gel fracturing fluid, crosslinked gel fracturing fluid, and slick water fracturing fluid for deep shale gas reservoirs, and focuses on the research status of a viscous slick water fracturing fluid and viscosity-controllable polyacrylamide drag reducer, with the aim of providing valuable insights for the research on water-based fracturing fluids in the stimulation of deep shale gas reservoirs.

Deep/ultra-deep shale strength criterion: A case study of southern Sichuan Basin shale

Deep/ultra-deep shale gas reservoirs are a vital area for future shale gas development, which mainly relies on the stimulation of network fracturing. In such a reservoir, engineering technologies such as wellbore stability evaluation and network fracturing design are all closely related to the shale mechanical characteristics. Currently, most studies focus on the elastic-plastic, brittle-ductile properties of shale, which are characterized based on shale strength. However, there is still a lack of in-depth research on their failure strength and strength criteria specifically for deep/ultra-deep shale. To accurately characterize shale failure strength, numerous scholars have researched shale strength criteria. Nevertheless, due to the high geo-stress of deep/ultra-deep reservoirs, shale properties tend to transition from brittle to ductile, resulting in poor fitting of classical rock strength criteria to test data under high confining stresses. This study focused on the outcrops of the Longmaxi Formation shale, and high-confining-stress triaxial compression tests were conducted to investigate the strength variation characteristics of shale. Based on the Mohr-Coulomb criterion, a power-form MC criterion was proposed by introducing a power function of confining stress as a correction term, and its reliability, sensitivity, and applicability were evaluated. The results indicate that the non-linear characteristics of the power-form MC criterion curve better match the actual situation, allowing for a more accurate prediction of shale strength under high confining stress. Furthermore, the power-form MC criterion has low sensitivity to changes in confining stresses, indicating that the required amount of test data for fitting can be appropriately reduced during application. Additionally, the power-form MC criterion is applicable to some extent to other types of high-strength rocks buried at greater depths. The results of this study contribute to understanding the strength characteristics of deep/ultra-deep shale under high confining stress, providing important references and theoretical basis for drilling, completion, and stimulation practices in deep shale gas reservoirs.

Multiple hydraulic fracture propagation simulation in deep shale gas reservoir considering thermal effects

Deep and ultra-deep shale gas will gradually become the focus of unconventional oil and gas resources in the petroleum industry. In the development of shallow shale reservoirs, the multi-cluster hydraulic fracturing of horizontal wells is the commonly applied technique to create a network of fractures and achieve reservoir stimulation. However, for deep shale reservoirs, the behavior of multiple hydraulic fracture propagation is affected by stress interference between fractures. On the other hand, it is also influenced by the temperature disturbances caused by the injection of low-temperature fracturing fluids into high-temperature formations and the resulting thermal effects. Currently, most research on multiple hydraulic fracture propagation in shale only considers the interaction between fluids and solids while neglecting thermal effects. Therefore, based on the displacement discontinuity method, finite volume method, and finite difference method, this study established a numerical model for the non-planar propagation of multi-cluster hydraulic fractures in deep shale, considering the thermal effects. And the model was validated through numerical solutions of the temperature field and double-fracture propagation. Moreover, the number of fracture clusters, pumping rate, and formation temperature were selected as influencing factors, and the differences in multiple hydraulic fracture propagation with and without considering thermal effects were analyzed. The results show that as the formation temperature increases, the thermal effects become more significant, leading to greater differences in the morphology of multi-cluster fractures. Moreover, the thermal effects are more significant when the formation temperature exceeds 90 °C. Additionally, appropriately reducing the number of fracture clusters or increasing the pumping rate can to some extent mitigate stress interference between fractures and promote uniform fracture propagation. The findings of this study contribute to understanding the influence of thermal effects on multiple hydraulic fracture propagation and provide theoretical basis for the efficient development of deep shale gas.

Optimization design of plugging agent dosage and application of deep shale gas inner-diversion fracturing

China boasts abundant deep shale gas resources with considerable development potential. However, the weak brittleness and large horizontal stress contrast of deep shale rock may restrain the complex fractures network extension during hydraulic fracturing. To address this challenge, the inner-diversion fracturing technique is widely employed, facilitating the formation of a complex fractures network. Numerous theoretical studies emphasize the pivotal role of plugging pressure exerted by temporary plugging agents within fractures in enhancing deep shale stimulation performance. However, various types of temporary plugging agents with different plugging performances make it difficult to determine the optimal dosage of temporary plugging agents before fracturing operation. This study considered the dynamic propagation of fractures affected by the coupling of the induced stress from clustered fractures and the fluid pressure within the fractures into the mathematical model, based on rock mechanics theory. Subsequently, the inner-diversion capability testing instrument was utilized to evaluate the critical plugging pressure of several common temporary plugging materials. By integrating on-site data from temporary plugging and inner-diversion fracturing operations in the Southern Sichuan deep shale gas reservoir with this approach, the optimal dosage of temporary plugging agents in the operational scheme was refined. The fracturing operation curves demonstrate that the temporary plugging and inner-diversion pressure significantly increased after pumping the temporary plugging agent, indicating the hydraulic fractures successful plugging and a large-scale complex fractures network extension. This underscores the potential effectiveness of the temporary plugging dosage optimization method for inner-diversion fracturing. Furthermore, this study not only provides important guidance for optimal design but also mitigates the operational risks of inner-diversion fracturing in deep shale gas horizontal wells.

Numerical analysis of hydraulic fracture propagation in deep shale reservoir with different injection strategies

Deep shale reservoirs are characterized by elevated breakdown pressures, diminished fracture complexity, and reduced modified volumes compared to medium and shallow reservoirs. Therefore, it is urgent to investigate particular injection strategies that can optimize breakdown pressure and fracturing efficiency to address the increasing demands for deep shale reservoir stimulation. In this study, the efficiency of various stimulation strategies, including multi-cluster simultaneous fracturing, modified alternating fracturing, alternating shut-in fracturing, and cyclic alternating fracturing, was evaluated. Subsequently, the sensitivity of factors such as the cycle index, shut-in time, cluster spacing, and horizontal permeability was investigated. Additionally, the flow distribution effect within the wellbore was discussed. The results indicate that relative to multi-cluster simultaneous fracturing, modified alternating fracturing exhibits reduced susceptibility to the stress shadow effect, which results in earlier breakdown, extended hydraulic fracture lengths, and more consistent propagation despite an increase in breakdown pressure. The alternating shut-in fracturing benefits the increase of fracture length, which is closely related to the shut-in time. Furthermore, cyclic alternating fracturing markedly lowers breakdown pressure and contributes to uniform fracture propagation, in which the cycle count plays an important role. Modified alternating fracturing demonstrates insensitivity to variations in cluster spacing, whereas horizontal permeability is a critical factor affecting fracture length. The wellbore effect restrains the accumulation of pressure and flow near the perforation, delaying the initiation of hydraulic fractures. The simulation results can provide valuable numerical insights for optimizing injection strategies for deep shale hydraulic fracturing.

Analysis of Fracture Network Formation Mechanisms and Main Controlling Factors of Methane Explosion Fracturing in Deep Shale Reservoir

Analysis of Fracture Network Formation Mechanisms and Main Controlling Factors of Methane Explosion Fracturing in Deep Shale Reservoir

Formation and evolution of shale overpressure in deep Wufeng-Longmaxi Formation in southern Sichuan basin and its influence on reservoir pore characteristics

In the deep Longmaxi Formation shale gas reservoirs of the southern Sichuan Basin, strong overpressure is universally developed to varying degrees. However, there is currently a lack of in-depth research on the formation mechanisms, evolutionary patterns, and the controlling effects on reservoir pore characteristics of strong overpressure. This limitation significantly restricts the evaluation of deep shale gas reservoirs. This study selected typical overpressured shale gas wells in Yongchuan, Luzhou, and Dazu areas as research subjects. Through comprehensive methods such as log analysis, fluid inclusion analysis, and numerical simulation, the dominant mechanisms of strong overpressure formation were determined, and the pressure evolution from early burial to late strong uplift was characterized. Additionally, the impact of varying degrees of overpressure on reservoir pore characteristics was studied using techniques such as scanning electron microscopy, gas adsorption-mercury intrusion, and helium porosity testing. The research findings indicate that hydrocarbon generation expansion is the primary mechanism for strong overpressure formation. The pressure evolution in the early burial phase is controlled by the processes of kerogen oil generation and residual oil cracking into gas. The reservoir experienced three stages: normal pressure (Ordovician to Early Triassic), overpressure (Early Triassic to Early Jurassic), and strong overpressure (Early Jurassic to Late Cretaceous), with pressure coefficients of approximately 1.08, 1.56, and 2.09, respectively. During the late strong uplift phase, the adjustment of early overpressure occurred due to temperature decrease and gas escape, leading to a decrease in formation pressure from 140.55 MPa to 81.63 MPa, while still maintaining a state of strong overpressure. Different degrees of strong overpressure exert a significant control on the physical properties of shale reservoirs and the composition of organic matter pores. Variations exist in the organic matter pore morphology, structure, and connectivity within the deep Wufeng-Longmaxi shale. Higher overpressure favors the preservation of organic large pores and reservoir porosity. Under conditions of strong overpressure development, deep siliceous shales and organically rich clay shales exhibit favorable reservoir properties. By determining the dominant mechanisms of strong overpressure in the Wufeng-Longmaxi Formation and studying pore characteristics, this research not only deepens the understanding of the geological features of deep shale gas reservoirs but also provides a new perspective for understanding the overpressure mechanisms and reservoir properties of deep shale gas reservoirs. Moreover, it is of significant importance for guiding the exploration and development of deep Longmaxi shale and provides valuable references for further research in related fields.

Study on failure characteristics and evaluation index of aquifer shale based on energy evolution

AbstractThe presence of abundant clay components and microporous structure in shale results in its high hydrophilicity, making a water-rich environment inevitable in petroleum exploration projects. Therefore, it is crucial to consider the influence of bedding structure, moisture content, confining pressure, and their combined effects on the geomechanical properties of shale. This article aims to investigate the mechanical properties of deep shale under varying water content conditions, elucidate the failure mode and failure mechanism of shale in actual engineering scenarios, and explores the interplay between stress, structure, moisture content, and other factors on its mechanical properties. The evaluation of wellbore stability and fracture propagation effects is proposed based on laboratory experiments using triaxial stress and strain data, along with the application of energy evolution theory. The experimental procedures encompass an analysis of shale's microscopic components and structure, as well as anisotropic shale triaxial compression tests conducted under different moisture contents and confining pressures. The results demonstrate that shale exhibits dense pores in its microstructure and displays pronounced anisotropic characteristics in its macrostructure. The presence of water within these pores, combined with the in situ stress within the formation, significantly influences the mechanical properties of shale. This anisotropy decreases with increasing moisture content, but the mechanical performance still decreases. Under triaxial compression conditions, the increase in confining pressure to some extent enhances the anisotropy of shale's deformation characteristics, which is related to the failure modes of shale. However, the detrimental effect of moisture content on shale's mechanical properties still persists. In order to quantify the impact of these factors, this study utilizes the elastic modulus as an indicator of the coupling effect. It combines the triaxial strain curve obtained from laboratory tests and proposes an evaluation index for shale mechanical properties based on the energy evolution theory. This index is suitable for assessing wellbore stability (the stability index called SIr) and crack expansion (the brittleness index called BIr). The calculation results reveal that, during the wellbore drilling process, excavating parallel to the direction of shale bedding while maintaining low moisture content and high confining pressure yields a higher SIr value, indicating better wellbore stability. On the other hand, during reservoir fracturing, fracturing perpendicular to the shale bedding direction and maintaining low confining pressure and moisture content result in a smaller BIr value. This approach is more beneficial for the expansion of shale fracture network in engineering.

Study on the influence of thermo-pressure coupling environment on the fracture properties of shale in deep reservoirs

Deep reservoir in-situ environments enhance rock plasticity. Most current experiments that combine temperature and pressure are difficult to observe the crack tip directly, impeding the understanding of deep rock fracture properties. This paper used a digital image correlation method and the principle of fracture mechanics to establish an innovative visual experimental rock fracture system with in-situ environment. Crack tip initiation and propagation were captured dynamically in real-time temperature and pressure coupling conditions, and the influence on shale fracture properties was analyzed, providing a feasible method for examining the fracture behavior of deep reservoir rocks. The results showed that the fracture characteristics of deep shale should be reflected and characterized by jointly considering temperature and confining pressure. Shale plasticity produced crack tip passivation in combined in-situ temperature and pressure conditions, and reduced the local stress concentration effect. The post-peak softening relationship showed a nonlinear “convex” trend, indicating nonlinear fracture characteristics with increased toughness. The exponential coefficient representing the degree of nonlinearity rose as the buried depth increased. The exponential coefficient related to the buried depth was introduced to modify the constitutive model, which was used to effectively characterize the nonlinear fracture behavior of deep reservoirs and provide a basis for deep reservoir fracturing reform research.

Study on the induced effect of bedding weakness in deep shale gas reservoir on hydraulic fractures propagation

Study on the induced effect of bedding weakness in deep shale gas reservoir on hydraulic fractures propagation