Development Of Shale Reservoirs Research Articles

Study on shale hydrocarbon generation pressurization and its influencing factors - taking Guoyuan area of Ordos Basin as an example

The increase in shale hydrocarbon production is the main driver of crude oil accumulation, but the lack of effective theoretical and technical means limits exploration and development. In this study, the quantitative calculation method of hydrocarbon generation pressurization was improved by the hydrocarbon overburden pressure simulation experiment. The relationship between the rate of hydrocarbon conversion rate and the content of organic matter is positively correlated with the process of hydrocarbon pressurization. On the other hand, the compression coefficient of clay minerals, the formation water content and compacted overpressure have inhibitory effects on hydrocarbon generation and pressurization. The combination of various factors determines the migration and enrichment of crude oil in shale lithology. This study, taking Ordos Basin, one of the most representative basins in China, as a case study, aims to elucidate the mechanisms and parameters involved in the generation and pressurization of hydrocarbons, providing valuable insights for the exploration and development of shale reservoirs in worldwide.

Complex fracture description and quasi-elastic energy development mathematical model for shale oil reservoirs

Reservoir numerical simulation is an important tool and method for the reasonable and efficient development of shale reservoirs. Accurate description of three-dimensional fractures in shale reservoir development is a necessary and sufficient condition to improve the accuracy and robustness of shale reservoir numerical simulation. This paper achieves precise characterization of complex fracture shapes and oil, gas and water flow by establishing an embedded discrete fracture model based on a non-structural network, which has advantages in the fine characterization of complex morphological fractures in the reservoir and the grid division of the reservoir. In the large matrix solution method, the Newton-Raphson method is used to linearize the nonlinear equations, the Jacobian matrix is ​​constructed, the ILU method is used for preprocessing, the conjugate gradient method is used to solve the linear equations, and the shale oil quasi-elasticity is established A fully implicit solution method for mathematical models of energy development.

Characteristics of Typical Shale Reservoir Development and Its Gas-Bearing Influencing Factors

Characteristics of Typical Shale Reservoir Development and Its Gas-Bearing Influencing Factors

Carbon Storage Potential of Shale Reservoirs Based on CO2 Fracturing Technology

The development of shale reservoirs is important in ensuring China’s national energy security by achieving energy independence. Among the key technologies for shale oil production, CO2 fracturing is an effective method that can not only enhance oil recovery but also promote large amounts of CO2 storage, thereby supporting China’s goals of achieving a carbon peak and carbon neutrality. This research paper aims to study the impacts and prospective applications of CO2 fracturing in shale reservoirs, using real exploitation parameters from the GYYP1 well in the Songliao Basin. By utilizing numerical simulation, the dynamics of CO2 production are analyzed. Adsorption and diffusion are identified as pivotal mechanisms for CO2 storage in shale reservoirs. After the analysis of the fracturing process, approximately 22.13% of CO2 is found to be adsorbed, which decreases to 11.06% after ten years due to pressure decline. Diffusion increases the volume of CO2 interacting with a greater extent of shale, thereby enhancing the adsorption mechanism. Over time, the diffusion process results in a remarkable increase of 26.02% in CO2 adsorption, ensuring the long-term and stable storage of CO2 within the shale reservoir. This investigation delves into the contribution of these two crucial mechanisms of CO2 storage in shale reservoirs, ultimately predicting that, by 2030, approximately two million tons of CO2 can be effectively stored in the Daqing Oilfield through CO2 fracturing in shale oil reservoirs. Such an achievement will undoubtedly contribute to the sustainable development of the energy sector and foster the transformation and upgrading of China’s energy structure.

Study on the conductivity of proppant in shale reservoir

At present, in the process of developing shale reservoirs by hydraulic fracturing, proppants play a critical role in the overall fracturing effect. Therefore, accurately evaluating the conductivity of different proppants determines the development effect of shale reservoirs. In this paper, proppant screening is first carried out, and the conductivity of four different proppants under laying concentration and closing pressure is studied, including 10-20 mesh quartz sand proppants with non-standard particle size, and the influence of different factors on the embedding degree is analyzed. It is concluded that the bearing capacity of ceramsite proppant is usually 2-3 times stronger than that of quartz sand. The larger the particle size of quartz sand proppant is and the higher the concentration of sand is, the stronger the conductivity is. When the closed pressure of large-size quartz sand is less than 30 MPa, the laying concentration of 14 kg/m2 can obtain higher conductivity, and when it is greater than 30 MPa, 12 kg/m2 is more suitable for field application. The ceramsite proppant has been on the rise with the increase of closing pressure and sand concentration. The embedding depth gradually increases with the increase of closing pressure and the decrease of sand concentration. The embedding depth of shale is greater than that of sandstone, and the flow conductivity of proppant is usually lower than that of sandstone. According to the experimental results, large-size quartz sand has strong conductivity, but it is not easy to migrate and has poor bearing capacity. Therefore, large-size quartz sand proppant can be used in the low-pressure part near the well, supplemented by small-size quartz sand (40-70 mesh) to obtain better fracturing results. This study provides some technical guidance for shale reservoir development and shale fracturing dessert identification.

Investigation on the flow behavior and mechanisms of water flooding and CO2 immiscible / miscible flooding in shale oil reservoirs

Shale reservoirs represent a significant untapped source of recoverable oil, and even a slight increase in recovery can yield substantial benefits. In recent years, there has been a growing interest in the development of shale reservoirs due to their vast potential. Shale reservoirs are characterized by their intricate pore structures, ultra-low porosity, and extremely low permeability. Consequently, fluid flow within shale formations is highly complex, and the distribution of shale oil is diverse. There is an urgent need to conduct research into the flow behavior of shale reservoirs and the modes of crude oil occurrence within them, in order to support effective shale oil extraction in the field. In this work, we established a MCMP-MRT-LBM model considering nano-scale confinement effects such as slip and adsorption. The model is employed to simulate single pore channels and blind-end pores to investigate the distinct mechanisms involved in water flooding, CO2 immiscible flooding, and CO2 miscible flooding. Subsequently, the research explores the fluid flow characteristics associated with these three development methods within porous media, as well as the distribution of remaining oil. Then we compared the oil displacement efficiency, swept volume, actual liquid injection volume and displacement front position of the three fluids in porous media. The results reveal that water flooding exhibits superior displacement performance in single pore channels, while CO2 miscible flooding proves to be the most effective method for exploiting oil in blind-end pores. In porous media, CO2 miscible flooding successfully mitigates fingering phenomena and efficiently recovers crude oil located at blind-end and corner regions of the pores. The recovery efficiency achieved through CO2 miscible flooding is approximately 30% higher than that of water flooding and about 10% greater than CO2 immiscible flooding.

Quantitative prediction of the fracture scale based on frequency-dependent S-wave splitting

The development of natural fractures has a significant impact on underground reservoirs and leads to seismic anisotropy. Furthermore, the scale of natural fractures directly affects oil and gas preservation, hydraulic fracture construction, and the production development of shale reservoirs. The S-wave anisotropy is a frequency-dependent parameter and the change in S-wave anisotropy with frequency is a function of the fracture scale. We develop an innovative method for predicting the fracture scale quantitatively using frequency-dependent S-wave anisotropy. The quantitative relationship between different fracture scales and the frequency-dependent response of the S-wave splitting (SWS) anisotropy can be obtained using a dynamic rock-physics model. The frequency-dependent S-wave anisotropy is calculated via SWS analysis in the frequency domain, after which this quantitative relationship and the calculated frequency-dependent response are used to establish an objective function for the inversion of the fracture scale at different depths using the least-squares algorithm. We synthesize data under ideal conditions, test our method, apply our method to field data, and find that the quantitative prediction method of the fracture scale yielded reasonable prediction results. The S-wave anisotropy is calculated based on the SWS analysis from the horizontal components of the upgoing wavefields of the field vertical seismic profile. We compare the fracture scale calculated from logging data using our method, and the results obtained indicate that this method can successfully predict the fracture scale quantitatively.

Influences of shale microstructure on mechanical properties and bedding fractures distribution

The difference in microstructure leads to the diversity of shale mechanical properties and bedding fractures distribution patterns. In this paper, the microstructure and mechanical properties of Longmaxi marine shale and Qingshankou continental shale were studied by X-ray diffractometer (XRD), field emission scanning electron microscope (FE-SEM) with mineral analysis system, and nanoindentation. Additionally, the typical bedding layers area was properly stratified using Focused Ion Beam (FIB), and the effects of microstructure and mechanical properties on the distribution patterns of bedding fractures were analyzed. The results show that the Longmaxi marine shale sample contains more clay mineral grains, while the Qingshankou continental shale sample contains more hard brittle mineral grains such as feldspar. For Longmaxi marine shale sample, hard brittle minerals with grain sizes larger than 20 μm is 18.24% and those with grain sizes smaller than 20 μm is 16.22%. For Qingshankou continental shale sample, hard brittle minerals with grain sizes larger than 20 μm is 40.7% and those with grain sizes smaller than 20 μm is 11.82%. In comparison to the Qingshankou continental shale sample, the Longmaxi marine shale sample has a lower modulus, hardness, and heterogeneity. Laminated shales are formed by alternating coarse-grained and fine-grained layers during deposition. The average single-layer thickness of Longmaxi marine shale sample is greater than Qingshankou continental shale sample. The two types of shale have similar bedding fractures distribution patterns and fractures tend to occur in the transition zone from coarse-grained to fine-grained deposition. The orientation of the fracture is usually parallel to the bedding plane and detour occurs in the presence of hard brittle grains. The fracture distribution density of the Longmaxi marine shale sample is lower than that of the Qingshankou continental shale sample due to the strong heterogeneity of the Qingshankou continental shale. The current research provides guidelines for the effective development of shale reservoirs in various sedimentary environments.

Hydrocarbon Potential and Reservoir Characteristics of Lacustrine Shale: A Case of Lower Jurassic in the Western Qaidam Basin, NW China

The Lower Jurassic lacustrine shale is well developed in the western Qaidam Basin and characterized by significant thickness and continuous distribution. Previous investigations have indicated its substantial potential as a shale gas resource. Based on experiments of organic carbon content, vitrinite reflectance, rock-eval pyrolysis, X-ray diffraction, and low-temperature nitrogen adsorption, the hydrocarbon potential and reservoir characteristics of Lower Jurassic lacustrine shale in the western Qaidam Basin were systematically analyzed. The results show that the total organic carbon (TOC) content ranges from 1.71% to 4.49%, with an average of 2.98%. The kerogen belongs to type II–III. The vitrinite reflectance (Ro) ranges from 1.05% to 1.95%, with an average of 1.62%, indicating that the kerogen has reached the high thermal maturity stage (gas window). The maximum pyrolysis peak temperature (Tmax) ranges from 408 °C to 580 °C, with an average of 498.38 °C, further supporting the high thermal maturity of the kerogen. The content of brittle minerals, including quartz, feldspar, pyrite, and carbonate, ranges from 21% to 44% (averaging 32.54%), which is comparable to shale minerals found in American Ohio shale. The pore structure of the shale is predominantly characterized by open parallel plate slit pores and inclined slit pores. The pore diameter distribution curve can be divided into two types, including unimodal distribution and bimodal distribution. Micropores and mesopores contribute significantly to the specific surface area, and mesopores account for the highest proportion of pore volume. The thermal evolution degree has a direct impact on pore development of shale reservoirs. The micropore, mesopore, macropore, and total pore volumes of lacustrine shale in the study area show a negative correlation with TOC content, indicating that the organic matter within the shale is probably still in the first pyrolysis stage. However, no significant correlation is observed between pore volume and clay mineral content or between pore volume and brittle mineral content due to the complex interplay of several geological factors. These findings contribute to a better understanding of the lacustrine shale gas resource potential and can guide future exploration and exploitation efforts. In addition, the systematic analysis of reservoir characteristics serves as a foundation for the introduction and exploration of new shale fracturing technologies, which is of great significance for reducing the consumption of water resources and mitigating potential geo-disasters.

Study on the Difference in CO2 and Air Injection in the Fracture/Matrix Dual Medium of Continental Shale Reservoirs.

To clarify the impact of different displacement media on the enhanced oil recovery of continental shale and realize the efficient and reasonable development of shale reservoirs, this paper takes the continental shale of the Lucaogou Formation in the Jimusar Sag in the Junggar Basin (China, Xinjiang) as the research object and uses real cores to build the fracture/matrix dual-medium model. Computerized tomography (CT) scanning is used to visually compare and analyze the influence of fracture/matrix dual-medium and single-matrix medium seepage systems on oil production characteristics and clarify the difference between air and CO2 in enhancing the oil recovery of continental shale reservoirs. Through a comprehensive analysis of the production parameters, the whole oil displacement process can be divided into three stages: the oil-rich and gas-poor stage, oil and gas coproduction stage, and gas-rich and oil-poor stage. Shale oil production follows the rule of fractures first and matrix second. However, for CO2 injection, after the crude oil in the fractures is recovered, the oil in the matrix migrates to the fractures under the action of CO2 dissolution and extraction. Overall, the oil displacement effect of CO2 is better than that of air, resulting in a 5.42% higher final recovery factor. Additionally, fractures can increase the permeability of the reservoir, which can greatly enhance oil recovery in the early oil displacement process. However, as the amount of injected gas increases, its impact gradually decreases, and ultimately, it is consistent with the recovery of nonfractured shale, which can achieve nearly the same development effect.

Development and Drag Reduction Behaviors of a Water-in-Water Emulsion Polymer Drag Reducer

As a key component of slickwater fracturing fluids, drag reducers play a critical role. Water-in-water (W/W) emulsion polymer drag reducers with the characteristics of rapid dissolution and the ability to increase viscosity are attracting substantial attention. In this work, a W/W emulsion polymer drag reducer P(AM-DMC) was synthesized via dispersion polymerization. The material P(AM-DMC) was characterized using Fourier transform infrared spectrometry, hydrogen nuclear magnetic resonance spectrometry, and environmental scanning electron microscopy. The results showed that the aqueous P(AM-DMC) solution was a pseudoplastic fluid with appreciable viscosity enhancement and shear resistance. The dissolution time of 0.1 wt % P(AM-DMC) was only 29 s. The drag-reduction rate of P(AM-DMC) reached 71.75%. The drag reducer also exhibited good temperature and salt resistance. Finally, a drag-reduction mechanism was proposed. We hope that this study can broaden the application of W/W drag reducers in shale reservoir development.

A three-dimensional numerical pressure transient analysis model for fractured horizontal wells in shale gas reservoirs

Shale gas development has greatly contributed to the world's energy supply. Pressure transient analysis (PTA) has extremely helped the development of shale gas. In this paper, a three-dimensional numerical model for transient pressure analysis of multi-stage fractured horizontal wells (MFHWs) in shale gas reservoirs was proposed, which was based on the embedded discrete fracture model (EDFM). The adsorption effect of shale gas, stress sensitivity of shale reservoir, and high-velocity non-Darcy flow in fractures were considered in this model, and the model was solved by Matlab Reservoir Simulation Tool (MRST). The discrete process of governing equations is described in detail, the typical MFHW pressure transient response curve of a shale gas reservoir was obtained, different flow regimes were divided, and three-dimensional pressure distribution profile of different flow stages were drawn to clearly understand the flow states of shale gas in the reservoir. The effects of different flow mechanisms and fracture properties on the log–log curves of the MFHW pressure transient response were analyzed in detail. The numerical PTA model proposed in this paper not only considers a variety of complex flow mechanisms of shale gas, but also accurately describes the characteristics of complex fracture network of shale reservoirs in three-dimensional conditions through EDFM. In addition, the problems of the incomplete description of shale gas flow stages by conventional analytical methods and semi-analytical methods were avoided through the numerical solution. The pressure response behavior of fluid in shale gas reservoir can be better explained by using this model, which helps to reduce the uncertainty of shale reservoir development.

Coupled pressure-driven flow and spontaneous imbibition in shale oil reservoirs

Coupled pressure-driven (viscous) flow and spontaneous imbibition are the main regimes during shale oil production. Revealing the unclear mechanisms of this coupled flow is a major concern for scholars and field engineers. In this work, the oil–water flow mechanisms within shale pore structures are investigated by pore-scale modeling methods in focused ion beam scanning electron microscopy digital rocks enhanced by applying super-resolution reconstruction (SRR). More small pores are identified with SRR, and the connectivity is improved. The enhanced pore size distribution is consistent with the nitrogen adsorption measurement; hence, more representative capillary pressure and relative permeability curves are obtained with essential experimental measurements. Then, an analytical solution of coupled pressure-driven (viscous) flow and spontaneous imbibition is derived, and a corresponding algorithm is proposed. Based on the pore-scale calculated relative permeability and capillary pressure curves, the analytical solution is applied to investigate the variations in water saturation profiles and conductance of the oil phase during the shale reservoir development. The results demonstrate that most of the shale oil is recovered by pressure dropdown-induced viscous flow and that imbibition is a minor factor. The overall oil-relative permeability decreases due to imbibition invasion. When the fracture spacing increases, the impairment of the overall oil-relative permeability decreases.

Bringing change to shale reservoir development

Bringing change to shale reservoir development

Long-Term Microbial DNA-Based Monitoring of the Mature Sarukawa Oil Field in Japan

Summary Microbial DNA-based monitoring is a promising tool for reservoir monitoring that has been used mainly for shale reservoir development. In this study, long-term microbial DNA-based monitoring was applied to the Sarukawa oil field, which has a complex reservoir structure with no practical simulation model available. Fluid samples were collected periodically from nine production wells and two injection wells from October 2019 to July 2021. DNA was extracted from the samples, and the microbial composition was analyzed by 16S ribosomal ribonucleic acid (rRNA) gene amplicon sequencing and real-time polymerase chain reaction (PCR). Based on similarities between the microbial profiles, the samples were classified into seven clusters that corresponded closely to the original fluid type (i.e., injection or production fluid) and specific environment (e.g., geological strata or compartments). A comparative analysis of the microbial profiles suggested possible well connectivity and water breakthrough. These results demonstrate that microbial DNA-based monitoring can provide useful information for optimizing production processes (e.g., waterflooding) in mature oil fields.

Experimental evaluation of energy supplement methods in the Yanchang Oilfield shale reservoir

Shale oil development in the Yanchang Oilfield is characterized by rapid production decline and low productivity, and supplementing the energy requirements and enhancing the recovery of oil are major challenges for shale reservoir development. In this study, physical simulations of cyclic water flooding, CO2 immiscible huff and puff, CO2 miscible huff and puff, and gas–water alternate drive processes were conducted on Chang 7 shale reservoir samples from the Yanchang Oilfield. The mechanism behind micro-displacement was analyzed by online NMR detection technologies, which showed that the displacement should be kept above the minimum miscible pressure during CO2 huff and puff. Furthermore, our analyses showed the highest recovery rate was that of water–gas alternate flooding is due to its higher utilization of small pores. Overall, CO2–water alternating flooding or CO2 miscible huff and puff is recommended to obtain higher recovery rates, based on our results. Considering the economic benefits and construction conditions, cyclic water flooding can be used first and then converted to other modes. This study can provide theoretical support for different ways of supplementing energy and provides scientific guidance for gas injection pilot test in similar reservoirs.

Gas content prediction model of water-sensitive shale based on gas–water miscible competitive adsorption

The evaluation of gas content plays a key role in determining the efficient development of shale reservoirs. To better understand the gas–water miscible competitive adsorption mechanism in the pore-fracture system of water-bearing shale, the water vapor adsorption experiment of dry shale and the methane gas adsorption experiment of water-bearing shale were carried out to compare and analyze the competitive adsorption laws of formation water and methane gas on the shale surface under different temperatures, pressures, and water saturation conditions. Moreover, based on the molecular layer adsorption theory, the gas–liquid–solid interface competitive adsorption model considering the coupling of temperature, pressure, and water saturation was established to predict the actual gas content of water-bearing shale reservoirs. The results show that the main controlling factors affecting the adsorbed gas content of water-bearing shale are specific surface area, temperature, and water content in turn according to weight coefficients; Compared with the gas–solid adsorption model, the gas–liquid–solid competitive adsorption model has higher accuracy in calculation results, which are much closer to the desorption data of shale cores in Jiaoshiba area, Fuling, China. Hence, the competitive adsorption model provides a theoretical foundation for reasonably evaluating the exploitation potential of shale gas reservoirs.

Reservoir Characteristics and Resource Potential of Marine Shale in South China: A Review

Many sets of Paleozoic marine organic-rich shale strata have developed in South China. However, the exploration and development results of these shale formations are quite different. Based on the data of core experiment analysis, drilling, fracturing test of typical wells, the reservoir differences and controlling factors of four sets of typical marine organic-rich shale in southern China are investigated. The four sets of shale have obvious differences in reservoir characteristics. Ordovician–Silurian shale mainly develops siliceous shale, mixed shale and argillaceous shale, with large pore diameter, high porosity, moderate thermal maturity, large pore volume and specific surface area. Cambrian shale mainly develops siliceous shale and mixed shale, with small pore diameter, low porosity, high thermal maturity and smaller pore volume and specific surface area than Ordovician–Silurian shale. Devonian–Carboniferous shale has similar mineral composition to Ordovician–Silurian shale, with small pore diameter, low porosity, moderate thermal maturity and similar pore volume and specific surface area to that of Cambrian shale. Permian shale has very complex mineral composition, with large pore diameter, low to medium thermal maturity and small specific surface area. Mineral composition, thermal maturity and tectonic preservation conditions are the main factors controlling shale reservoir development. Siliceous minerals in Cambrian shale and Ordovician–Silurian shale are mainly of biological origin, which make the support capacity better than Devonian–Carboniferous shale and Permian shale (siliceous minerals are mainly of terrigenous origin and biological origin). Thermal maturity of Ordovician–Silurian shale and Devonian–Carboniferous shale is moderate, with a large number of organic pores developed. Thermal maturity of Cambrian shale and Permian shale is respectively too high and too low, the development of organic pores is significantly weaker than the two sets of shale above. There are obvious differences in tectonic preservation conditions inside and outside the Sichuan Basin. Shale reservoirs inside the Sichuan Basin are characterized by overpressure due to stable tectonic activities, while shale reservoirs outside the Sichuan Basin are generally normal–pressure. Four sets of marine shale in South China all have certain resource potentials, but the exploration and development of shale gas is still constrained by complicated geological conditions, single economic shale formation, high exploration and development costs and other aspects. It is necessary for further research on shale gas accumulation theory, exploration and development technology and related policies to promote the development of China’s shale gas industry.

Controls on East Shale Basin reservoir distribution within the Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin

The Duvernay Formation accumulated as an organic-rich basinal mudrock concurrent with shallow marine platform carbonates of the Leduc and Grosmont formations. Historically classified as a major source rock to conventional hydrocarbon production, the Duvernay evolved into an unconventional shale reservoir across Alberta, Canada much like other source rock intervals worldwide. Distributions of the Duvernay Formation are partitioned into the West and East Shale basins by a narrow, linear Leduc Formation reef complex known as the Rimbey-Meadowbrook trend. Since 2011, development has focused on the West Shale Basin, but thermal maturity trends suggest the potential for expanded shale reservoir development within the southern portion of the East Shale Basin. This study characterizes sedimentologic and stratigraphic controls on Duvernay reservoir potential to identify development “sweet spots” within the East Shale Basin. Duvernay geologic attributes mapped within this study include: oil thermal maturity, thick restricted basin facies association occurrence (at least 5-10m thick), high average TOC values (greater than 2.0 wt.%), and high net carbonate thickness (greater than 40m). The geologic attributes are predictive of production potential within horizontal wells, and the distribution of their co-occurrence suggests the potential for expanded development within the southern portion of the East Shale Basin.

Multiscale Pore Structure Evolution of Longmaxi Shale Induced by Acid Treatment

SummaryHydraulic fracturing to generate complex fracture networks is essential for shale reservoir development. However, the recovery of shale oil and gas is still low due to various engineering and geological factors. Acid treatment has been approved as a potential approach to enhance stimulated reservoir volume (SRV) by changing petrophysical and mechanical properties. Understanding the multiscale pore structure evolution behind the macro-performance change is critical in the application of acid treatment in shale reservoirs. In this study, cylindrical and powder shale samples from the Longmaxi formation are treated with 15 wt% hydrochloric acid (HCl) for 10 days. Before and after acid treatment, X-ray computed tomography (CT) and N2 adsorption techniques are used to characterize shale pore structure at microscale and nanoscale, respectively. Combined with the determination of variations in chemical compositions of shale samples and acid solutions, the mechanism of multiscale pore structure evolution induced by acid treatment is discussed. The N2 adsorption results uncover a considerable increase in volume and size of nanopores. All the nanopores increase in carbonate-rich shale, whereas the micropores and mesopores undergo a decrease in clay-rich shale. Reconstructed 3D CT images reveal the generation of large volumes of microscale pores and fractures, which leads to an increase in porosity of about 9%. The pore structure evolution in shale due to acid treatment is controlled by both mineralogy and microstructure. These findings demonstrate the promise of acid treatment for enhanced SRV and long-term productivity of shale oil and gas reservoirs in China.