Fracturing Fluid Retention Research Articles

Numerical Simulation of Fracturing Fluid Storage in Shale Reservoirs Based on Experimental Measurements of Stress Sensitivity of Hydraulic Fracture Network Conductivity

Hydraulic fracturing is used in shale reservoir production, with low flowback rates and a large amount of fracturing fluid retained inside the reservoir. In this study, a stress sensitivity analysis experiment on the fracture inflow capacity was implemented to investigate the relationship between the hydraulic fracture (HF) and natural fracture (NF) inflow capacities and effective stress. A three-dimensional shale reservoir model was also constructed to couple the experimentally obtained laws with the numerical model to investigate the effects of the connection and closure of the fracture network on the retention of the fracturing fluid. The results show that the stress sensitivity of natural fractures is two orders of magnitude higher than that of hydraulic fractures. The seepage-absorption effect of capillary forces is not the whole reason for the large amount of fracturing fluid retention. The closure of the fracture network formed by natural and hydraulic fractures during the production process led to the storage of a large amount of fracturing fluid, and this process maintained the stability of the water production rate during the steady water production period.

Research on water blocking and residue damage mechanism of fracturing fluid in Yongjin tight reservoirs

The existing reservoir in the Yongjin block exhibits an extremely low matrix permeability, posing challenges in precisely evaluating the damage caused by fracturing fluid using traditional core flow experimental methods. Currently, there is no established quantitative method for characterizing the degree of damage. In this study, we integrated online nuclear magnetic resonance, microscopic computed tomography, and core displacement experimental techniques, pioneering a novel approach to evaluate damage in deep tight oil reservoirs subjected to hydraulic fracturing. We analyzed the influence patterns of key factors such as backflow pressure differential, shut-in time, invasion volume, and residual retention on rock matrix damage in the operational area. The study unveiled the mechanisms behind water sensitivity, water block, and fracturing fluid retention damage among oil, water, and rock. The results indicate that water sensitivity damage is less than 20%, primarily occurring within large pores. Water block damage can significantly reduce the residual oil permeability. Experimental findings suggest that optimizing liquid backflow with a pressure differential and well shut-in time set at 5 MPa and 9 days can markedly reduce the intrusion volume of gel-breaking fluid, restoring the residual oil permeability. Under high-pressure differential conditions, residual fracturing fluid can infiltrate the rock matrix, resulting in pore damage. Additionally, it can accumulate on the fracture surfaces, thereby reducing the permeability of microfractures.

Experimental Study on Damage and Control Methods of Fracturing Fluid Retention to Tight Shale Matrix

Experimental Study on Damage and Control Methods of Fracturing Fluid Retention to Tight Shale Matrix

Impact of fracturing fluid retention and flowback on development effect after large scale fracturing in shale oil wells: A case study from the shale oil of Chang 7 Member, Yanchang Formation, Ordos Basin

In order to reveal the impact of fracturing fluid retention and flowback on the development effect after large-scale fracturing in shale oil wells, and to formulate a reasonable flowback policy, this paper employs a combination of core physical simulation experiments and theoretical analysis. We have designed a specially designed device that can evaluate the development effect of quasi-natural energy in oil reservoirs. The impact of fracturing fluid retention on development is simulated by changing the amount of fracturing fluid injected into the formation in a fractured horizontal well model (referred as injection volume), and the impact on development effect is analyzed by changing the properties of fracturing fluid to adjust the difference in the degree of flowback. Based on the experimental results, the mechanism of fracturing fluid retention and flowback after large-scale fracturing in shale reservoirs is further explored. The results of the experiments show that the flowback rate of fracturing fluid exhibits a monotonic decreasing trend with increasing the volume of injected fluid, as increasing the volume of injected fluid helps to enhance its retention in the formation and reduce the flowback rate. The degree of fracturing fluid flowback is critical to the mobility of crude oil in the tight reservoir. The entering of fracturing fluid into the reservoir slows down the rate of discharge in the fracture network, effectively extending the reach of the fracturing fluid in the tight reservoir and allowing more crude oil to be used, which in turn results in higher crude oil production. However, too much injection fluid may affect the fluid production. Simulation experiments reveal that the use of fracturing fluid retention or controlling the rate of flowback by changing the viscosity of fracturing fluid can be a way to enhance the development effect of horizontal shale oil wells. The results of this paper provide a basis for understanding the mechanism of shale oil development, exploring technical ideas to improve the development effect, and making decisions on the flowback parameters.

Fracturing fluid imbibition impact on gas-water two phase flow in shale fracture-matrix system

A large amount of fracturing fluid in hydraulic fracturing is imbibed into the shale fracture/matrix, which leads to significant uncertainty in gas recovery evaluation. The mechanism of imbibition impact on the gas–water flow is not well understood. In this study, systematic comparative experiments are carried out to simulate imbibition in fractured shale samples obtained from the Wufeng-Longmaxi shale reservoirs in China, and the imbibition effect in the fracture–matrix system is qualitatively and quantitatively investigated. Nine cores are collected to measure their porosity and permeability using a helium porosimeter and nitrogen pulse–decay tests. Gas/liquid single-phase flow experiments are then carried out using methane and KCl solution, respectively. Subsequently, dynamic imbibition experiments are carried out on three samples in a visual cell. The gas–water interfacial tension, water imbibition amount, and displacement velocity are recorded. A single-phase gas/liquid flow test shows a high linear correlation between the fluid displacement velocity and pressure gradient in the fractured samples as the fracture is the main flow channel, dominantly determining the flow behavior. Moreover, the capillary force was introduced in the cross-flow term of the triple-medium model to characterize the imbibition effect, and a two-phase flow simulation model considering the fracturing fluid imbibition retention was developed, and the two-phase flow behavior by considering the imbibition effect of the fracturing fluid retention in the shale gas reservoir was analyzed. Valuable experiment data in this work are provided, which can be used to validate analytical equations for gas/water flow in the shale fracture–matrix system.

Characteristics of Fracturing Fluid Invasion Layer and Its Influence on Gas Production of Shale Gas Reservoirs

With the increase of shale gas resource exploitation in our country during recent decades, the situations of low gas production, fast production decline rate, and low flowback rate have been appearing in field production. It is an urgent problem to be solved in shale gas production and it is therefore necessary to study the interaction of the shale gas reservoir and the detained fracturing fluid. In this paper, the Longmaxi Formation shale samples of Sichuan Basin were selected for a water invasion experiment. The fracture propagation law, the water invasion front location, and the water invasion thickness of deep and shallow shale reservoirs after water invasion were compared and analyzed by CT scanning technology. Based on the analysis of the experimental mechanism, a numerical simulation model was established. The dimensionless permeability and thickness of the fracturing fluid invasion layer were introduced to analyze the positive and negative effects of fracturing fluid retention on the reservoir. The results show that during the hydraulic fracturing of shale gas wells, fracturing fluid can quickly enter the complex fracture network, and then slowly enter the shale matrix under various mechanisms to form the fracturing fluid invasion layer. Compared with shallow shale reservoirs, deep shale reservoirs have lower porosity and permeability, which propagates microfractures in the matrix induced by fracturing fluid retention, and results in a smaller fracturing fluid invasion layer thickness. Both the negative effect of fracturing fluid retention on shale damage and the positive effect of microfracture formation and propagation exist simultaneously. The higher the dimensionless fracturing fluid invasion layer permeability, the more complex the fracture network formed in the fractured reservoir will be, resulting in a longer stable production period and a better development effect. When the dimensionless fracturing fluid invasion layer permeability is greater than 1, that is, when the positive effect of fracturing fluid retention is greater, and the thicker the dimensionless fracturing fluid invasion layer is, the better the development effect will be. Combining reservoir characteristics and fracture development, the key to obtaining high productivity of a shale gas well is to optimize the soaking time and the speed of flowback in order to extend the stable production period. In this paper, the characteristics of the fracturing fluid invasion layer and the influence of fracturing fluid retention on gas well productivity are deeply studied, which provides a certain theoretical basis for the optimization of shale gas extraction technology and the improvement of the gas–water two-phase productivity prediction method for fractured horizontal wells.

Experimental Study on the Distribution of Retained Fracturing Fluids and Its Effect on the Permeability and Wettability in Tight Oil Reservoirs

It is not clear how the distribution of retained fracturing fluids and its effect on the permeability and wettability in tight oil reservoirs interact. Especially, there are more qualitative studies and less quantitative studies on this issue. Under laboratory experimental conditions, this paper clarifies the distribution of retained fracturing fluids in the core and reveals the influence rule of retained fracturing fluids on tight reservoir permeability and wettability. It is found that the main retention space of retained fracturing fluids in a tight reservoir is a microporous interval, and the residual oil after oil displacement by retained fracturing fluids mainly exists in the core in the form of dots or porphyries. The smaller permeability and porosity of the core will lead to more retained fracturing fluids. The permeability of different cores after fracturing fluid retention has decreased to varying degrees compared with that before fracturing fluid retention. The wettability of core slices before and after fracturing fluid retention was tested, and the effect of retained fracturing fluids on reservoir wettability was not significant. This study has important significance for improving the recovery of tight oil reservoirs and enhancing the understanding of postfracturing fluid retention.

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. In this study, microscopic experiments are conducted to simulate the fracturing fluid flowback progress in shale gas reservoirs. The mechanism and factors affecting fracturing fluid flowback/retention in the fracture zone were analyzed and clarified. Results show that the ultimate flowback efficiency of fracturing fluid is positively correlated with the fracturing fluid concentration and the gas driving pressure difference. There are four kinds of mechanisms responsible for fracturing fluid retention in the pore network: viscous resistance, the Jamin effect, the gas blockage effect and the dead end of the pore. Additionally, the ultimate flowback efficiency of the fracturing fluid increases linearly with increasing capillary number. These insights will advance the fundamental understanding of fracturing fluid flowback in shale gas reservoirs and provide useful guidance for shale gas reservoirs development.

Water Distribution in Marine Shales: Based on Two-Dimensional Nuclear Magnetic Resonance and Low-Temperature Nitrogen Adsorption

A significant amount of foreign fluid is kept in the marine shale reservoirs after hydraulic fracturing. The water distribution characteristics in the pore space are quite complex because of the shale’s significant inhomogeneity. The change in reservoir water status brings new challenges to studying the adsorption and flow capacity of shale gas, which also brings difficulties to assessing the geological reserves of shale reservoirs and capacity prediction and development. In this study, based on a two-dimensional nuclear magnetic resonance technique and low-temperature nitrogen adsorption technique, clay minerals, organic matter, and marine shale were used as the study objects to get the distribution characteristics of water in shale pores. The results show that after entering the shale reservoir, most of the water is adsorbed on the surface of inorganic pores, mostly clay pores, to create a bound water film with a thickness of around 0.96 nm. Shale pores’ diameter, volume, and surface area are all smaller in the wet state compared to the dry, falling by 10.11, 47.02, and 71.00%, respectively. Small-scale pores (D < 10 nm) are better at absorbing water, and the water in these pores fills the spaces between them to create capillary water besides being adsorbed on the pore surface. Bound water can aid in the development of gas reservoirs and the desorption of adsorbed gas, but the capillary water column obstructs the flow of gas and restricts the flow of shale gas in microscopic pores. This study will lay a theoretical foundation for evaluating the water-bearing characteristics of marine shale reservoirs, which will help analyze the modification effect of fracturing fluid retention on reservoir water-bearing characteristics and then guide gas well development.

Investigation on microscopic invasion characteristics and retention mechanism of fracturing fluid in fractured porous media

Reservoir damage caused by guar gum fracturing fluid and slick water seriously affects the subsequent oil and gas production. However, the invasion characteristics and retention mechanisms of fracturing fluids in the fracture-matrix zone are still unclear. In this work, a microscopic model reflecting the characteristics of the fracture-matrix zone was designed. Based on the microfluidic experimental method, the process of fracturing fluid invasion, flowback and retention in the fracture-matrix zone was investigated visually and characterized quantitatively. The factors and mechanisms affecting fracturing fluid retention in the fracture-matrix zone were analyzed and clarified. The results indicated that in the invasion process, the frontal swept range of slick water was larger than that of the guar gum fracturing fluid, and the oil displacement efficiency and damage rate were lower than those of the guar gum fracturing fluid under the same invasion pressure. With the increase in invasion pressure, the damage rate of slick water increased from 61.09% to 82.77%, and that of the guar gum fracturing fluid decreased from 93.45% to 83.36%. Before subsequent oil production, the invaded fracturing fluid was mainly concentrated in the medium-high permeability area of the fracture-matrix zone. The main resistance of slick water was capillary force, while that of the guar fracturing fluid was mainly viscous resistance. The fracturing fluid retention was most serious in the low permeability region and the region near the end of the fracture. The experimental and numerical simulation results showed that increasing the production pressure difference could improve the velocity field distribution of the fracture-matrix zone, increase the flowback swept range and finally reduce the retention rate of the fracture fluid. The retention mechanisms of slick water in the fracture-matrix zone include emulsion retention and flow field retention, while those of the guar gum fracturing fluid include viscous retention and flow field retention. Emulsion retention is caused by capillary force and flow interception effect. Viscous retention is caused by the viscous resistance of polymer, while flow-field retention is caused by uneven distribution of flowback velocity.

Shale Gas Productivity Prediction Model Considering Time-Dependent Fracture Conductivity

Conventional shale gas productivity prediction techniques consider fracture conductivity to be a fixed value, but in actual production processes, conductivity changes with time. Therefore, this paper proposed a capacity prediction method that considers time-dependent conductivity and validates its accuracy using commercial simulators. First, relevant parameters were obtained by fitting the improved long-term conductivity test, and then the shale gas seepage model was established using the EDFM method. The laboratory test results showed that the order of significance affecting the conductivity retention rate was fracturing fluid viscosity &gt; sand concentration &gt; fracturing fluid retention time; the calculation results of the production prediction model show that the flow and the pressure curves that corresponded to constant conductivity and variable conductivity were to some extent different. In the presence of complex fractures and natural fractures, the increase in the variable conductivity production curve was smaller than that of the constant conductivity production curve. This study provides some guidance for field production.

Research on Conductivity Damage Based on Response Surface Analysis

Hydraulic fracturing is an important means of developing unconventional oil and gas layers. The fracture conductivity of tight sandstone reservoirs after fracture is affected by many factors, such as the interaction between the fracturing fluid, water, and rocks; the fracturing materials; and the construction parameters. This paper improves the experimental process of the long-term conductivity test and provides insight into conductivity prediction and optimization based on the response surface test method. The test process is conducted in the following manner: (1) inject nitrogen to evaluate the fracture conductivity before fracturing fluid damage; (2) inject fracturing fluid to simulate shut-in; and (3) inject nitrogen again to evaluate fracture conductivity after the damage ability of the fracturing fluid. The single factor test results show that the lower the sand concentration is, the higher the fracturing fluid viscosity will be, and the longer the fracturing fluid retention time is, the greater the damage to the conductivity of the fracturing fluid will be. The response surface test results show that the order of factors affecting the retention of conductivity is fracturing fluid viscosity &gt; sand concentration &gt; fracturing fluid retention time. There is a certain interaction between sand concentration and fluid viscosity, and there is also a certain interaction between fluid viscosity and fluid retention time, but these interactions are not significant; when the fracturing fluid retention time is longer, there will be an interaction between the sand concentration and the fracturing fluid retention time. In addition, based on the model used to optimize the fracturing construction parameters from the perspective of proppant conductivity damage, the optimal solution is when the viscosity of the fracturing fluid is 1 mPa.s, the paved-sand content is 8.49 kg/m2, and the retention time of the fracturing fluid is 10 h. The maximum retention rate of the flow conductivity is 63.19%.

Water Occurrence Characteristics of Gas Shale Based on 2D NMR Technology

Determination of water occurrence in gas shale reservoirs is vital for understanding the gas storage and migration behavior. Clay, kerogen, and shale samples with different water contents were analyzed based on the 2D NMR technology to decipher the characteristic of water occurrence in different shale compositions. By establishing a new classification method of water in shale, the water absorption characteristics of shale during hydraulic fracturing and the law of water mobilization in shale reservoirs during development are quantitatively analyzed. The results suggest that the water in shale can be classified as mobile water and immobile water, with the boundary T1 = 0.1 ms. The mobile water can be further divided into clay bound water, capillary bound water, and free water by the T1–T2 map. Most of the water in shale is clay bound water, which is also the most important object in the study of fracturing fluid retention. The influence of free water and clay bound water on the gas–water two-phase flow of shale is greater. Accurate analysis of different types of water in shale can clarify their different effects on methane occurrence and migration. This study overcomes the shortcomings of inaccurate quantitative analysis of water in shale by traditional methods and provides help for the analysis of fracturing fluid retention law and the development effect of gas wells.

Fracturing fluid retention in shale gas reservoir from the perspective of pore size based on nuclear magnetic resonance

Shale gas development requires large-scale hydraulic fracturing, but a large amount of the slickwater fracturing fluid injected into the reservoir cannot be brought back to the surface. In this study, spontaneous imbibition and reverse displacement experiments were carried out on shale core to simulate fracturing fluid imbibition into the matrix during the fracturing stage of a shale gas reservoir and the displacement of fracturing fluid by reservoir gas during the flowback stage. With the help of low-field nuclear magnetic resonance technology to dynamically monitor the volume change in the liquid in the shale core throughout the entire process, the volume distribution of the liquid in the pores of the different scales were calculated at each time. The reason for the low flowback efficiency of shale gas reservoirs from the perspective of pore size was studied, and the influence of the fracturing fluid’s salinity on the flowback process was analyzed. The research results show that there is a certain pore size threshold in the shale gas reservoir. When the fracturing fluid enters pores smaller than this size threshold, it is difficult to displace it during flowback. The relative volume of the fracturing fluid entering the pores smaller than the size threshold determines the flowback efficiency. The higher the proportion of this part of the fracturing fluid to the total volume, the lower the flowback efficiency. Using a fracturing fluid with a higher salinity can reduce the volume of liquid entering the pores less than the pore threshold to a certain extent, thereby increasing the flowback efficiency. This research is important for gaining a better understanding the low flowback efficiency in shale gas reservoirs and for evaluating the safety of groundwater resources.

The retention and flowback of fracturing fluid of branch fractures in tight reservoirs

A small percentage of the fracturing fluid pumped can be recovered after multi-stage fracturing stimulation in tight reservoirs. One cause for this can be the numerous branch fractures formed at different scales during large volume fracturing. Understanding the retention mechanism and flowback law of fracturing fluid in branch fractures is a key to solving this problem. In this study, we used a leaser macroscope, a low-field nuclear magnetic resonance (NMR) instrument, and a permeability device to scan fracture surface morphology and conduct fracturing fluid retention and permeability regain experiments. Meanwhile, retention mechanisms and the flowback process of fracturing fluid in branch fractures during flowback is considered. The experimental results show that the fracturing fluid present in branch fractures can be divided into free movable water (FMW), restricted movable water (RMW) and retained water (RW). The average proportion of FMW, RMW, and RW in Lucaogou and Longmaxi shale reservoirs in our work are about 0.16: 0.14: 0.7 and 0.1: 0.1: 0.8, respectively. The rougher the surface and the greater the tortuosity of the fracture are, the higher the retention percentage of fracturing fluid in branch fractures is. The main mechanisms of fracturing fluid retention in branch fractures include water film, capillary retention on the fracture surface, and matrix imbibition. The critical T2 of FMW and RMW in branch fractures in the Lucaogou shale reservoir are 25.3 ms and 10.2 ms, respectively. However, they are 64 ms and 3.7 ms in the Longmaxi shale reservoir. During the flowback, FMW and partial RMW gradually flowback to the surface. After this, the permeability regains with the decrease of water retention in branch fractures. This study contributes to understanding fracturing fluid retention mechanism in tight reservoirs and provides guidance for the optimization of fracturing flowback.

Impact of water film on methane surface diffusion in gas shale organic nanopores

When a shale pore radius is less than 10 nm, the contribution of surface diffusion to methane transport in shale multiscale pore structure will significantly increase. It is critical to understand whether the adsorbed water film in shale nanoscale organic pores is beneficial to multiscale methane transport. Thus, a model considering the effect of a water film on methane surface diffusion is established. Furthermore, the influences of a water film on different diffusion mechanisms are discussed. The results show that, first, when water molecule enters shale organic pores, an adsorption interface changes from gas-solid to gas-water, i.e., the fractional surface coverage of gas in the surface increases so the surface diffusion ability increases; second, when a pore radius is less than 6 nm, the overall diffusion capacity of methane in pores increases, even though a water film can decrease the slip flow and Knudsen diffusion. However, when a pore radius is 8–10 nm, the apparent permeability (Kapp) increases with pressure. Since a pore surface contains a water film, Kapp is not always greater than that for a pore surface without water film. Our investigation shows that the impact of fracturing fluid retention in shale multiscale pore structure is not always negative for methane multiscale transport if the volume of a fracturing fluid and shut-in time are reasonable.

Changes in retained fracturing fluid properties and their effect on shale mechanical properties

To understand the fluid-shale interactions and the mechanisms that produce cracks during the retention of the fracturing fluid. This paper details experiments performed in shale particle immersion and core plug imbibition, and it investigates changes in fluid properties during a shale well shut-in period at the Longmaxi formation in Southeast Chongqing, China. The results indicate that soluble salts in a shale formation are dissolved during fracturing fluid retention in a shale reservoir, causing the salinity and pH of the fracturing fluid to increase significantly and eventually resulting in the formation of a weakly alkaline solution. Furthermore, fracturing fluid retention significantly reduces the mechanical strength of shale. In the experiments, the elasticity modulus and Poisson's ratio of the shale decreased by 85% and 54%, respectively, which was immersed in the fracturing fluid for seven days. Two types of forces, repulsive hydration and electric double-layer repulsion, are shown to be the main factors that lead to the formation of a large number of microcracks. The repulsive hydration pressure force is in a short range, operating over only a few nanometers, while the electric double-layer repulsion force operates over a long distance and can act between clay mineral slices. As the concentration of the solution increases, the double-layer repulsive force increases, though the range over which it acts becomes shorter. The increase in the OH− concentration of the solution also accelerates crack propagation. These conclusions are conducive to developing reasonable rules for fracturing fluid flowback in shale gas wells.

Fracturing fluid retention in shale gas reservoirs:mechanisms and functions

Shale gas reservoirs are characterized by nano-Darcy permeability, rich organic matter, ultralow water saturation, developed bedding, and micro-fractures, leading to multi-scale transportation of shale gas. Multistage fracturing of horizontal wells is the main development technology to stimulate shale gas reservoirs, and tens of thousands of cubic meters of fluids are injected into the reservoir. Retention and flowback of fracturing fluids on gas transfer plays an important role on the effect of hydraulic fracturing. Through the analysis of geological and engineering factors controlling water imbibition and diffusion in shale gas reservoirs, the mechanisms of low recovery of fracturing fluids and the reasons that some shale gas wells with low recovery of fracturing fluids have high gas production rate were revealed. This paper carried out a series of experiments of the fluid imbibition and fracture initiation in the shale selected from the Longmaxi Formation in Sichuan basin. In detail, this paper investigated imbibition and dispersion the fluid in shale and analyzed the mechanisms of the shale-water interactions causing the reduction of shale strength and fracture initiation and propagation. Based on the field case studies of well shut-in after fracturing, its influence on the well production was assessed. Formation damage caused by fracturing fluid is multi-scale, and the evaluation of formation damage caused by fracturing fluids should take the influence on the gas transmission capacity into consideration, and residual fracturing fluids may have a positive effect on gas transfer. It should take the long-term stable production of shale gas well and the effect of fracturing fluids transmission on gas multi-scale transport into consideration when determining the timing and pressure difference of fracturing fluids flowback from shale gas reservoirs.

The effect of anionic surfactant (SDS) on pore-fracture evolution of acidified coal and its significance for coalbed methane extraction

Adding the compound solution included hydrochloric acid and hydrofluoric acid into coal seam, the pore structure of coal can be destroyed by acidizing treatment, and the permeability of coal seam can be improved. In order to increase the acidification damage effect, in this paper, the effects of anion surfactant named Sodium Dodecyl Sulfate (SDS) on the pressure relief and enlarge permeability effect of compound solution acidified coal were studied from four aspects: mechanical characteristics, porosity and pore distribution of coal samples, retention effect of fracturing fluid and microscopic morphology of coal sample surface. The results show that the SDS promotes the pressure relief effect of acidified coal body and reduces the strength of the treated coal sample. At the same time, the SDS increases the reaction area of acid fracturing fluid and impurity minerals in the fractures of coal sample, enhancing the acidification effect of HCL and HF on coal sample and increasing the porosity of coal. In the aspect of pore distribution, through the acidification synergism of SDS, the macropores and fractures of coal samples increase obviously. With the addition of SDS, the reversible work required for HCL and HF compound solution to break away from coal molecules is reduced by 18.45 J, which can significantly reduce the water blocking effect caused by the fracturing fluid retention, and improve the efficiency of coalbed methane extraction. After the compound solution erodes the coal sample, the microscopic morphology of coal sample surface has changed greatly, and the destruction degree of acidizing erosion is the highest after SDS synergism. The results of this paper are great significance for studying the mechanism of pressure relief and enlarge permeability effect of acidified coal.

The effects of fracturing fluid retention on permeability of shale reservoirs

In this study, an induced fracture model and Lower Silurian Longmaxi Formation shale were used to study the effects of retained fracturing fluid on production. The results reveal that permeability will decrease first after contacted with fracturing fluid, then it will recover with increasing immersion time. The major reason for permeability recovery is that induced fractures is formation because of internal pressure of pores higher than initiation pressure. A lot of natural fracture and induced fractures interconnected each other and form network cracks to provide channels for gas. Therefore, prolonging the shut-in time of shale reservoir after fracturing can improve the gas production.