Shale Microfractures Research Articles

Research Progress on the Microfracture of Shale: Experimental Methods, Microfracture Propagation, Simulations, and Perspectives

The fracture network generated by hydraulic fracturing in unconventional shale reservoirs contains numerous microfractures that are connected to macroscopic fractures. These microfractures serve as crucial pathways for shale gas to flow out from micro- and nano-scale pores, playing a critical role in enhancing shale gas recovery. Currently, more attention is being given by academia and industry to the evolution of macroscopic fracture networks, while the understanding of the microfracture mechanisms and evolution is relatively limited. A significant number of microfractures are generated during the hydraulic fracturing process of shale. These microfractures subsequently propagate, merge, and interconnect to form macroscopic fractures. Therefore, studying the fracture process of rock masses from a microscale perspective holds important theoretical significance and engineering value. Based on the authors’ research experience and literature review, this paper provides a brief overview of current progress in shale microfracture research from five aspects: in situ observation experiments of microfractures in shale, formation and evolution processes of discontinuous microfractures, the impact of inhomogeneity on microfracture propagation, measurement methods for microscale mechanical parameters and deformation quantities in shale, and numerical simulation of shale microfractures. This paper also summarizes the main challenges and future research prospects in shale microfracture studies, including: (1) quantitative characterization of in situ observation experimental data on shale microfractures; (2) formation and evolution laws of macroscopic, mesoscopic, and microscopic multi-scale discontinuous fractures; (3) more in-depth and microscale characterization of shale heterogeneity and its deformation and fracture mechanisms; (4) acquisition of shale micro-mechanical parameters; (5) refinement and accuracy improvement of the numerical simulation of microfractures in shale. Addressing these research questions will not only contribute to the further development of microfracture theory in rocks but also provide insights for hydraulic fracturing in shale gas extraction.

Effect of fracture fluid flowback on shale microfractures using CT scanning

The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs, where the flowback rate of shale fracturing fluid is lower than that of conventional reservoirs. At the early stage of flowback, there is no single-phase flow of the liquid phase in shale, but rather a gas-water two-phase flow, such that the single-phase flow model for tight oil and gas reservoirs is not applicable. In this study, pores and microfractures are extracted based on the experimental results of computed tomography (CT) scanning, and a spatial model of microfractures is established. Then, the influence of rough microfracture surfaces on the flow is corrected using the modified cubic law, which was modified by introducing the average deviation of the microfracture height as a roughness factor to consider the influence of microfracture surface roughness. The flow in the fracture network is simulated using the modified cubic law and the lattice Boltzmann method (LBM). The results obtained demonstrate that most of the fracturing fluid is retained in the shale microfractures, which explains the low fracturing fluid flowback rate in shale hydraulic fracturing.

A New Method for Comprehensive and Quantitative Characterization of Shale Microfractures: A Case Study of the Lacustrine Shale in the Yuanba Area, Northern Sichuan Basin

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

Quantitative Characteristics of Micro Bedding Fractures in the Wufeng–Longmaxi Formation Based on High-Resolution Map Imaging Technology

The study of microfractures in shale is mainly based on qualitative description. Conversely, quantitative description of the parameters of shale microfractures can provide a quantitative basis for shale fracture characterization and shale physical properties. Nine shale reservoir samples of the Wufeng–Longmaxi Formation in the Jiaoshiba area were studied, using the backscattered two-dimensional multiscale resolution imaging technology, combined with high-resolution map imaging technology (MAPS), and thousands of images were obtained using scanning electron microscopy. Gray image analysis was used to extract microfracture information from images (2 × 2 cm multiresolution). The “maximum circle method” was used to calculate the length and aperture characteristics of the fractures. Parameters such as the area of the bedding fractures, the surface rate of the fractures, and the linear density of the fractures were obtained by the integration of apertures. The fracture length was between 2~7 mm, the aperture was between 1~6 μm, the linear density was between 1~6/m and the surface rate was 1%. The bedding fractures do not contribute much to the porosity of the shale reservoir; however, shale reservoirs with high porosity have a high development of bedding fractures and good permeability. The development of a bedding fracture is controlled by the lithology within shale reservoirs. Different types of lithology contain different bedding fractures, but they have a certain regularity. Moreover, the content of organic matter and TOC (total organic content) in the shale reservoir control the development of a bedding fracture, where a high organic and TOC content are accompanied by a high number of fractures.

Pore-fracture network alteration during forced and spontaneous imbibition processes in shale formation

Imbibition controls mass transfer in the complex pore-fracture network in shale, which may change the pore-fracture network and lead to a low efficient flowback of fracturing fluid. Thus, it is necessary to accurately characterize the pore-fracture network alteration during the imbibition process. In this study, forced and spontaneous imbibition tests were conducted under the confining pressure on selected shale core samples with induced fractures, collected from Longmaxi Formation, Sichuan Basin, China. The low-field nuclear magnetic resonance (NMR) spectrometer was employed to monitor the variation of pores and micro-fractures in the shale core samples during the dynamic imbibition process. In addition, optimal surface relaxivities, ranging from 0.019 to 0.033 μm/ms, were determined by comparing the NMR T2 distributions with the pore size distributions (PSDs) measured via high-pressure mercury intrusion (HPMI) tests. Then, the measured dynamic T2 spectra with three distinct peaks were converted into the corresponding PSDs to quantitatively analyze the number, size, and connectivity changes of small pores, large pores, and micro-fractures in shale. Results show that the total porosities of the four shale core samples are increased by 3.5%, 10.2%, 32.9%, and 36.3% after the imbibition tests. The forced imbibition leads to more remarkable improvements in the pore volume of large pores with radius between 0.2 and 3.6 μm. In contrast, the spontaneous imbibition results in more significant increases in the number and size of small pores with radius between 0.0004 and 0.36 μm. It is also found that the total porosity increment is primarily an outcome of small pore alteration during the imbibition. Moreover, the enlarged pores and micro-fractures are mainly categorized as the capillary bounded fluid pores and movable fluid pores, which significantly affect the efficiency of oil and gas transfer in shale. The findings of our study demonstrate the comprehensive effects of capillary force, clay hydration, osmotic potential, confining and pore pressures, and creep deformation and failure on the pore-fracture network alteration in shale and advance the understanding of the mechanisms behind the forced and spontaneous imbibition processes.

Characteristics of Organic Matter Pores and the Relationship with Current Pressure System of Lower Silurian Longmaxi Shales in Dingshan Field, Southern Sichuan, China

Organic matter pores (OMP) provide significant storage space for hydrocarbons in lower Silurian Longmaxi shales in the Dingshan field of southern Sichuan, China. The distributions of organic matter and the different OMP structure parameters were characterized through Ar-ion polishing, scanning electron microscopy (SEM), and image analysis software for shale samples of different wells. The research results indicated that organic matter has been divided into two categories based on its occurrence, location, and its relationship with authigenic minerals: organic matter in situ and migrated organic matter. OMP for organic matter in situ are mainly micropores mostly arranged isolatedly, while in migrated organic matter pores show larger sizes and higher roundness. The development of OMP in samples is predominantly controlled by the formation pressure. The existence of overpressure alleviated the stress on the rock skeleton, causing the compaction of some migrated organic matters to lag or decrease. This played a positive role in protecting the development of pores in the interior and edge of the rock skeleton, and it can also induce the development of microfractures in shale. The protective effect of formation pressure on organic pores was provided for understanding the exploration and exploitation of Longmaxi shales in the study area.

Potential valorization of granitic waste material as microproppant for induced unpropped microfractures in shale

Billions of tons of quarried material are globally produced per annum, generating siliceous solid cutting and powder waste which are usually disposed of in landfill sites. Herein, two cheap and distinct granite quarry waste cuttings have been reduced into microproppant dimensions. They were characterized for potential application in hydraulic fracturing as an economic alternative to siliceous commercially available microproppants. The particle size distributions, morphology, particle density, the mineralogy, microscale mechanical hardness, and modulus of the produced microproppants were evaluated to confirm their potential application as microproppants. Also, the split core fracture conductivity of the produced microproppants was measured. Laser diffraction revealed particle size distribution with d50 of about 11 μm suitable for common natural fracture widths. Morphological images showed low sphericity and roundness appropriate for channel fracturing proppant placement. A particle density of 2.6 and 2.9 g/cc was obtained for the produced microproppants. However, a review of most granite particle density indicated proximity to commonly used quartz-based microproppant. Their density and smaller sizes suggest good transport properties. Results of the mineralogy study showed high amounts of silica content with dominant crystal phases of albite, anorthite, and orthoclase which exhibited theoretical hardness between (5.2–7.2 GPa) and modulus between (77.8–98.0 GPa). Nanoindentation confirmed the micromechanical hardness and modulus determined by density functional theory. The hardness and modulus lie between class C Fly ash and Ottawa sand which have demonstrated good performance as microproppants. Hence granite microproppants have the potential to resist reservoir stresses. Granite microproppant pillars were able to improve the baseline permeability of a fractured shale core by a magnitude of ten. Granitic microproppants are cheaper sources of silica capable of maintaining microfracture width and preventing rapid production decline within unconventional shale reservoirs while contributing to the conservation of overly exploited natural sand deposits.

Types and Quantitative Characterization of Microfractures in the Continental Shale of the Da’anzhai Member of the Ziliujing Formation in Northeast Sichuan, China

A number of wells in the Sichuan Basin of China have tested industrial gas flow pressure arising from the shale of the Da’anzhai section of the Ziliujing Formation, revealing good exploration potential. Microfractures in shales affect the enrichment and preservation of shale gas and are important storage spaces and seepage channels for gas. In order to increase productivity and to reduce the risks associated with shale gas exploration, the types, connectivity, and proportion of microfractures in the Da’anzhai Member have been studied in this work by core and thin section observations, micro-CT, scanning electron microscopy, nitrogen adsorption, and high-pressure mercury intrusion. The results show that four types of fractures have developed in the shale of the Da’anzhai section: microfractures caused by tectonic stress, diagenetic shrinkage fractures of clay minerals, marginal shrinkage fractures of organic matter, and microfractures inside mineral particles. Among these, structural fractures and organic matter contraction fractures are the main types and are significant for shale reservoirs and seepage. The structural microfractures are mainly opened and are well-developed in the shale, with a straight shape, mainly between bedding, with the fracture surface being curved, fully opened, and mainly tensile. Organic matter fractures often develop on the edge of the contact between organic matter and minerals, presenting a slit-like appearance. The fractures related to bedding in the shale are particularly developed, with larger openings, wider extensions, intersecting and expanding, and forming a three-dimensional interconnected pore-fracture system. Based on image recognition, generally speaking, microfractures account for about 20% of the total pore volume. However, the degree of the microfractures’ development varies greatly, depending upon the structural environment, with the proportion of microfractures in fault-wrinkle belts and high-steep zones reaching 40% to 90% of the total pore space. On the other hand, micro-fractures in areas with underdeveloped structures account for about 10% of the total pore space.

A study on the morphology of natural microfractures in marine and continental transitional shale based on scanning electron microscopy image

The development of natural microfractures not only directly affects exploitation efficiency of a shale gas reservoir, but also determines the quality and production of the shale gas reservoir. The environment, in which the shale forms, is considered to be the fundamental cause of shale pore formation and deformation. However, the traditional method of observing shale samples using field-emission scanning electron microscopy (FE-SEM) can be interfered by a large number of fractures caused by artificial damage on the shale surface during sample preparation, such as mechanical damage during polishing and shrinkage damage of shale mineral particles. To tackle this issue, we summarized the features of natural fractures by comparing fracture morphology of shale before and after artificial damage. In this study, the powder samples which suffered serious structural damage and the block samples with light structural damage were observed by FE-SEM. In addition, we used the pressure switch to cause slight damage to the surface of gold-plated block samples, and the difference between the gold film tearing edge and the mineral tearing edge was used to identify the artificial cracks generated during this process. We found (1) most of the open structural fractures on the shale surface are not natural, but artificially induced during the sample preparation process; (2) most non-structural natural fractures are mainly related to organic matter, clay and calcite; (3) stress and shrinkage are the main causes of natural microfractures; (4) natural microfractures in shale have a clear pressure support structure, which are categorized into self-supporting fractures.

Assessment of extended Derjaguin–Landau–Verwey–Overbeek‐based water film on multiphase transport behavior in shale microfractures

AbstractThis study presents a novel model to predict gas–water two‐phase transport behaviors in shale microfractures by incorporating a mobile water film with varying thickness according to the extended Derjaguin–Landau–Verwey–Overbeek theory as well as multiple fluid transport mechanisms (i.e., real gas transport controlled by the Knudsen number and water slippage). This model is implemented in real shale microfractures via digital‐core imaging. A gas–water displacement process is modeled by the invasion percolation theory, while a local multiphase distribution is determined by combining disjoining pressure with capillary force. Key findings reveal that gas relative permeability decreases by 17% and water RP enhances by 33.5%, when the mean aperture decreases from 1.67 to 0.0418 μm. Neglecting water film brings a decrease in water RP and an overestimation of gas transport ability. Moreover, two critical microfracture apertures are determined, which enhances an understanding of the water film impact on gas–water transport properties in application.

Experimental investigation of the effects of ultrasonic stimulation on adsorption, desorption and seepage characteristics of shale gas

To verify the feasibility of applying ultrasonics to enhancing gas production from shale gas reservoirs, experimental study on the effects of ultrasonics on adsorption, desorption and seepage characteristics of shale gas using four samples from Sichuan Basin has been carried out. Adsorption and desorption of methane, were tested by volume method under different conditions, while the permeabilities of shale samples were tested by steady state method under different conditions. Results show that ultrasonics has a negative effect on the adsorption of shale gas, while a positive effect on desorption, resulting from the fact that ultrasonics treatment can enhance the vibration of gas molecules to break down the adsorption equilibrium. Further, the permeability dropped significantly with the effective confining pressure and pore pressure increasing, resulting from that high confining pressure decreases the area of seepage channels. The results also illustrate that permeability increases with the ultrasonics power increasing, presumbly by forming microfractures in shale which results in significant increase in the area of seepage channels.

The crucial geometric distinctions of microfractures as the indispensable transportation channels in hydrocarbon-rich shale reservoir

This study aimed to investigate the crucial geometric distinctions of microfractures as the indispensable transportation channels in hydrocarbon-rich shale so as to find the new evidence for hydrocarbon exploration and exploitation.This study mainly shows that (1) microfracture length and width would show a good positive linear correlation, but when the length of microfracture reaches a key point, the width of microfracture would gradually deviate from the linear relationship and gradually diverges. (2) compaction or other tectonic stress can promote the formation of shale microfractures and promote the occurrence of pressure solution. (3) Similarly, before a certain key point, the poor orientation degree of microfractures often coexists with the higher convexity of microfractures, which is positively correlated. When this key point is crossed, the two begin to show a negative correlation. This may be due to the fact that the microfractures will open, close, extend or even interlace more frequently when the rock is under complex stress conditions.It proved that when describing the heterogeneity characteristics of microfractures, we should clearly describe them from two aspects of size and geometry so as to ensure the integrity of the conclusion.

A dynamic apparent permeability model for shale microfractures: Coupling poromechanics, fluid dynamics, and sorption-induced strain

The widely distributed microfractures play an important role in shale gas production. However, limited studies focus on gas flow behavior in microfractures, and ignore the complex transport mechanisms, leading to a large error for gas permeability evaluation. In this work, a newly dynamic apparent permeability (AP) model, coupling poromechanics, sorption-induced strain, and gas slippage, has been proposed to effectively reveal the gas flow mechanisms through microfractures of shale. Specifically, a dynamic aperture is innovatively incorporated into the Navier-Stokes (N–S) equation using the second-order slip boundary condition to calculate the gas velocity and volume flux in single microfracture. Based on that, the gas transport model for microfracture networks considering the distributions of aperture and tortuosity is derived using the fractal theory. The newly developed model is verified well with experimental data and network simulation. Results indicate that the gas conductance highly depends on the structure of microfracture networks (i.e., the maximum aperture and fractal dimensions). There are three different AP evolutions under various boundary conditions (i.e., constant confining pressure (Pc), constant pore pressure (Pp), and constant effective stress (σeff)) resulting from the coupling transport mechanisms. The AP presents a similar shape of “V” at reservoir conditions (i.e., constant Pc ), indicating the “negative contribution” of poromechanics at an early stage, and the “positive contribution” for both gas slippage and sorption-induced strain at the late stage should be underlined during gas production. Moreover, the “negative factor” of poromechanics is positively correlated with fracture compressibility coefficient but negatively associated with Biot's coefficient at high pressures (>15 [MPa]). Increasing gas desorption capacity, fracture spacing, and internal swelling coefficient can enhance the “positive factor” of sorption-induced strain at low pressures (<15 [MPa]). This work provides a theoretical guidance to develop shale gas effectively.

Water-Based Drilling Fluid Using Nanoparticles Proves Effective in Unconventional Shales

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19342, “Design and Evaluation of a Water-Based Drilling-Fluid Formulation Using SIO2 and Graphene Oxide Nanoparticles for Unconventional Shales,” by Jose Aramendiz, SPE, Abdulmohsin H. Imqam, SPE, and Sherif M. Fakher, SPE, Missouri University of Science and Technology, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. Traditionally, oil-based drilling fluids are preferable in drilling shale plays because of their negligible chemical interactions, but strict environmental regulations have motived the industry to design water-based muds (WBMs) capable of controlling shale/water interactions. Still, conventional additives in general are too large to plug shale microfractures and nanopores. Thus, nanoparticles, because of their size, shape, and other properties, can provide a solution for WBMs. This study focus on the design and evaluation of a customized water-based mud (NP-WBM) using silica oxide nanoparticles (SiO2-NPs) and graphene oxide nanoplatelets (GNPs). Experimental Description Experimental Materials. Conventional Drilling-Fluid Additives. The micro-size additives used in this work included bentonite to provide primary viscosity and xanthan gum to adjust the final rheological properties of the base fluid. Polyanionic cellulose low- viscosity and pregelled starch were included as conventional filtrate-loss additives. Graphite was used as conventional lost- circulation-material (LCM) additive. Potassium hydroxide was included as an alkalinity-control agent. Nanomaterials. SiO2-NPs were supplied in a white powder form. The SiO2-NPs are near-spherical with an approximate diameter ranging between 15 and 20 nm. The NPs were unmodified (bare surface) and nonporous with a density of 0.1 g/cm3, a specific surface area of 170–200 m2/g, and purity greater than 99.5 wt%. GNPs used in this study had a density of 0.13 g/cm3. The GNPs have a 2D structure with an average particle size ranging from 1.3 to 2.3 µm and a thickness of less than 3 nm. Shale Rock Properties. Woodford shale was used to test the effect of using NPs to enhance the inhibition capabilities of WBM. This rock is described as a late Devonian-Early Mississippian marine shale. In this study, shale samples of 1 in. in diameter and lengths between 0.5 to 2 in. were cored and stored in high-purity mineral oil to avoid property alterations. The rock contains 31.5% clay minerals (22.8% illite, 5.4% chlorite, and 3.3% kaolinite), 67% quartz, and 1.5% pyrite, indicating a high degree of brittleness as well as low water sensitivity. Fig.• 1 shows a sequence of scanning electron microscope (SEM) images in which Image A is equivalent to 7,000x magnification and Image B shows a 30,000x magnification with respect to the original sample size. The SEM images suggested a pore-size distribution between mesopores (2–50•nm) and macropores (greater than 50 nm) with an estimated median pore size of 112.84 nm. Therefore, the nanomaterials in this study have a scale matching that of the Woodford shale and can be used as theoretical bridging agents.

Machine-learning-based object detection in images for reservoir characterization: A case study of fracture detection in shales

Imaging tools are widely used in the petroleum industry to investigate structural features of reservoir rocks directly at multiple scales. Quantitative image analysis is often used to determine various rock properties, but it requires significant time and effort, particularly to analyze a large number of samples. Automated object detection represents a potential solution to this efficiency problem. This method uses computers to efficiently provide quantitative information for thousands of images. Automated fracture detection in scanning electron microscope (SEM) images is presented as an example to show the workflow of using advanced deep-learning tools for quantitative rock characterization. First, an automatic object-detection method is presented for fast identification and characterization of microfractures in shales. Using this approach, we analyzed 100 SEM images obtained from deformed and intact samples of a carbonate-rich shale and a siliceous shale with the goal of analyzing the abundance and characteristics of microfractures generated during hydraulic fracturing. Most of the fractures are detected with about 90% success rate relative to manual picking. Second, we obtained statistics of length and areal porosities of these fractures. The experimentally deformed samples had slightly more detectable microfractures (1.8 fractures/image on average compared to 1.6 fractures/image), and the microfractures induced by shear deformation tend to be short (&lt;50 μm) in the Eagle Ford and long in the siliceous samples, presumably because of differences in rock fabric. In future work, this approach will be applied to characterize the shape and size of mineral grains and to analyze relationships between fractures and minerals.

Reasons for the low flowback rates of fracturing fluids in marine shale

In this paper, marine shale cores taken from Zhaotong, Changning and Weiyuan Blocks in South China were used as samples to investigate the interaction between fracturing fluids and shale and the retention mechanisms. Firstly, adsorption, swelling, dissolution pore, dissolution fluid mineralization degree and ionic composition were experimentally studied to reveal the occurrence of water in shale and the reason for a high mineralization degree. Then, the mechanisms of water retention and mineralization degree increase were simulated and calculated. The scanning electron microscopy (SEM) analysis shows that there are a large number of micro fractures originated from clay minerals in the shale. Mineral dissolution rates of shale immersed in ultrasonic is around 0.5–0.7%. The ionic composition is in accordance with that of formation water. The clay minerals in core samples are mainly composed of chlorites and illites with a small amount of illites/smectites, but no montmorillonites (SS), and its content is between 18% and 20%. It is verified by XRD and infrared spectroscopy that the fracturing fluid doesn't flow into the space between clay mineral layers, so it can't lead to shale swelling. Thus, the retention of fracturing fluids is mainly caused by the adsorption at the surface of the newly fractured micro fractures in shale in a mode of successive permeation, and its adsorptive saturation rates is proportional to the pore diameters. It is concluded that the step-by-step extraction of fracturing fluids to shale and the repulsion of nano-cracks to ion are the main reasons for the abrupt increase of mineralization degree in the late stage of flowing back. In addition, the liquid carrying effect of methane during the formation of a gas reservoir is also a possible reason. Based on the experimental and field data, fracturing fluid flowback rates and gas production rates of 9 wells were analyzed. It is indicated that the same block follows an overall trend, namely, the lower the flowback rates, the more developed the micro fractures, the better the volume simulation effect and the higher the gas production rates.

Effect of fluid–solid coupling on shale mechanics and seepage laws

In this paper, the cores of outcropped black shale of Lower Silurian Longmaxi Fm in the Yibin area, Sichuan Basin, were taken as samples to investigate the effects of extraneous water on shale mechanics and seepage laws during the production of shale gas reservoirs. Firstly, the development of fractures in water saturated cores was observed by using a VHX-5000 optical superdepth microscope. Secondly, water, formation water and slick water, as well as the damage form and compression strength of water saturated/unsaturated cores were investigated by means of a uniaxial compression testing machine and a strain testing & analysis system. Finally, the effects of fluid–solid coupling on shale gas flowing performance in different water saturations were analyzed by using a DYQ-1 multi-function displacement device. Analysis on core components shows that the Longmaxi shale is a highly crushable reservoir with a high content of fragile minerals, so fracturing stimulation is suitable for it. Shale compression strength test reveals that the effects of deionized water, formation water and slick water on shale are different, so the compression strength of shale before being saturated is quite different from that after being saturated. Due to the existence of water, the compression strength of shale drops, so the shale can be fractured easily, more fractures are generated and thus its seepage capacity is improved. Experiments on shale gas seepage under different water saturations show that under the condition of fluid–solid coupling, the higher the water saturation is, the better the propagation and seepage capacity of micro-fractures in shale under the effect of pressure. To sum up, the existence of water is beneficial to fracturing stimulation of shale gas reservoirs and helps to achieve the goal of production improvement.

Prospect of shale gas recovery enhancement by oxidation-induced rock burst

By horizontal well multi-staged fracturing technology, shale rocks can be broken to form fracture networks via hydraulic force and increase the production rate of shale gas wells. Nonetheless, the fracturing stimulation effect may be offset by the water phase trapping damage caused by water retention. In this paper, a technique in transferring the negative factor of fracturing fluid retention into a positive factor of changing the gas existence state and facilitating shale cracking was discussed using the easy oxidation characteristics of organic matter, pyrite and other minerals in shale rocks. Furthermore, the prospect of this technique in tackling the challenges of large retention volume of hydraulic fracturing fluid in shale gas reservoirs, high reservoir damage risks, sharp production decline rate of gas wells and low gas recovery, was analyzed. The organic matter and pyrite in shale rocks can produce a large number of dissolved pores and seams to improve the gas deliverability of the matrix pore throats to the fracture systems. Meanwhile, in the oxidation process, released heat and increased pore pressure will make shale rock burst, inducing expansion and extension of shale micro-fractures, increasing the drainage area and shortening the gas flowing path in matrix, and ultimately, removing reservoir damage and improving gas recovery. To sum up, the technique discussed in the paper can be used to “break” shale rocks via hydraulic force and to “burst” shale rocks via chemical oxidation by adding oxidizing fluid to the hydraulic fracturing fluid. It can thus be concluded that this method can be a favorable supplementation for the conventional hydraulic fracturing of shale gas reservoirs. It has a broad application future in terms of reducing costs and increasing profits, maintaining plateau shale gas production and improving shale gas recovery.

Study of shale micro-fracture propagation based on tomographic technique

Basing on the CT tomography technique, the micro structure changes of Longmaxi Shale were studied in four different drilling fluids. They are deionized water, KCl-polymer drilling fluid, SM-Shaledrill drilling fluid and oil based mud. Experiments showed that micro fracture propagation which caused by fluid invasion along the micro-fracture is the main reason of shale wellbore instability. And micro fractures propagate directively and instantaneously, fractures are mainly developed in the previous two hours when immersed in fluids. And micro fractures are mostly parallel to the bedding plane of shale. The micro structure changes obvious differently when immersed in different drilling fluids. Micro fractures propagated most and fastest in deionized water, KCl-polymer drilling fluid is the next; and shale in SM-Shaledrill drilling fluid and oil based mud has no obvious change. As for the newly developed micro fractures, width of fractures maintain constant once developed. But the width of the existing micro fractures in shale have an obviously increasing process when contact with fluid.

Control of medium- to small-scale tectonic deformations on fracture development in Longmaxi Formation shale

This study conducted a detailed geological survey and experimental analysis on the area of Golden Buddha Mountain syncline of Nanchuan, Chongqing, to examine the development characteristics and mechanism of fractures in Longmaxi Formation shale. Results showed the following: The width of the microfracture of the Longmaxi Formation shale in the research area ranges from hundreds of nanometers to hundreds of micrometers. The percentage of the shale fracture is high if width is small. The dominant strikes of joints and microfractures are consistent overall, which are the WNW, NW–NWN, NE, and NE–ENE directions. The shale shows that the density and width of the fracture and the permeability in the core of the syncline are larger than those in the wing are. The following conclusions were drawn. (1) Regardless of size, the mechanical origin of fracture is controlled by tectonic deformation. (2) During the Early Yanshanian (J3–K1) Period in the research area, a series of WNW shear fractures, NWN shear fractures, and NW tensile fractures were formed by strong squeezing effect with the NW–SE trending. During the Late Yanshanian–Himalayan Period, the tectonic stress was mainly presented as extrusion with the NE–SW trending and the NW–SE trending stretch, and a series of NE–ENE shear fractures and NE tensile fractures were formed. (3) Medium- to small-scale tectonic deformations exert dominant control effects on the fracture development of Longmaxi Formation shale in the research area. (4) A fracture network consists of joints and microfractures in shale in different scales. The finer the microfractures, the denser they grow.