Development Of Shale Gas Reservoirs Research Articles

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

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

Gas mass transfer characteristics in shales: Insights from multiple flow mechanisms, effective viscosity, and poromechanics

Accurate characterization of gas transport behavior is indispensable for successful shale gas reservoir development. In this study, a fractal-theory-based apparent permeability (AP) model is developed to better characterize real gas mass transfer in shales. The proposed model involves multi-scale organic matter (OM) and inorganic matter (IOM) flow channels and incorporates poromechanics-related dynamic pore size, multiple gas transport mechanisms, and dynamic viscosity. The discrete integration method (DIM) is employed to address viscosity changes during fractal scaling up. Experimental data, molecular dynamics simulations, and published theoretical models were used to verify the proposed model and reasonable agreements have been achieved. Results indicate that as the pore pressure and size increase, dominant mechanisms for gas transport change from surface diffusion at low pressure (lower than switch pressure) to viscous flow at higher pressure and larger pore sizes. Furthermore, higher organic matter content makes the permeability curve more similar to OM type. Ignoring effective viscosity results in underestimation of permeability, which is more noticeable when pressure rises and pore shrinks. Poromechanical properties primarily affect pore size, larger elastic modulus and smaller Poisson's ratio leads to significantly lower permeability. The real gas effect on AP reduction cannot be ignored, especially at high pressure. This work provides insights into the gas transport characteristics in shales, which have practical implications for shale gas reservoir simulation and development.

Study on Key Technologies of Geosteering for Shale Gas Horizontal Wells in the Complex Structural Area of Block H in Western Hubei-Eastern Chongqing.

Block H, located in western Hubei-eastern Chongqing, remains at a low exploration degree. Characterized by its complex structural attributes, the area presents adverse conditions such as a thin thickness of high-quality shale reservoir, rapid lateral formation occurrence, and poor stratigraphic correlation, challenging conventional geosteering methods. The primary shale gas reservoir in Block H corresponds to the Upper Permian Wujiaping Formation. To ensure that the shale gas horizontal wells in this block effectively penetrate high-quality gas reservoirs, this study delves into the geological characteristics of this stratigraphic unit, identifies principal challenges faced by current geosteering techniques, and introduces a tailored technical solution. This solution encompasses the application of real-time 3D geological modeling to track while drilling, identification of steering marker layers, optimization of steerable tools, and optimization of the steering trajectory while drilling. In the technology of optimization of the steering trajectory while drilling, a trajectory control calculation model based on the average angle technique was established for the first time. Additionally, a sectional control chart for marker layers and well inclination under different deflecting constraints was established. These methods have solved the problems of large error in target prediction and poor trajectory control effects by using the equal thickness method alone. The findings from this study can significantly enhance target prediction and trajectory control accuracy in complex structural areas, offering pivotal insights for the proficient development of analogous shale gas reservoirs in the future.

Numerical Simulation of the Simultaneous Development of Multiple Fractures in Horizontal Wells Based on the Extended Finite Element Method

Simultaneous multiple-fracture treatments in horizontal wellbores have become an essential technology for the economic development of shale gas reservoirs. During hydraulic fracturing, fracture initiation and propagation always induce additional stresses on the surrounding rock. When multiple fractures develop simultaneously, the development of some fractures is limited due to the stress-shadow effect. An in-depth understanding of the multiple-fracture propagation mechanism as reflected by fracture morphology and flow rate distribution can help to set reasonable operation parameters for improving the uniformity of multiple fractures and forming a complex fracture network according to the different in situ stress conditions in a reservoir to increase the shale gas recovery and reduce the cost. In this study, a two-dimensional (2D) fracture propagation model was developed based on the extended finite element method (XFEM). Then, the influences of various factors, including geological and operational factors, on the development of multiple fractures were studied. The results of numerical simulations showed that increasing the cluster spacing or injecting fracturing fluid with lower viscosity can help reduce the stress-shadow effect. In the case of smaller in situ stress differences, the deflection of the fractures was larger due to the stress-shadow effect. As the stress difference increased, the direction of the propagation of the fracture was gradually biased towards the direction of maximum horizontal stress. In addition, the injection rate had some effects on the fracture morphology and flow rate distribution. However, as the injection rate increased, the dominant fracture developed rapidly, and the fracture length significantly increased.

Study on the Impact of Flow Dynamic Allocation Mechanism on the Balanced Propagation of Multicluster Fractures in Horizontal Wells

Abstract The implementation of the multicluster fracturing technique in horizontal wells is crucial to the economic development of shale gas reservoirs. The stress shadow area generated by them suppresses the effective expansion of fractures, leading to lower construction quality. Numerous well logging and production data indicate that dynamic flow allocation is also an important mechanism restricting oil and gas production. To reveal the mechanism of multifracture synchronous competitive expansion, a multifracture expansion finite element model considering fluid-solid coupling in porous media was established. A wellbore model was built to characterize the fluid pressure drop, incorporating pipe flow and fluid connection elements to emulate fluid flow within the wellbore, and the influence of various factors on the balanced expansion of fractures was investigated. The results show that high porosity, uniform perforation, and high elastic modulus of sweet spots are favorable for the balanced expansion of multiple fractures when using high-volume and low-viscosity fracturing fluids. When the spacing is small and the porosity is low with nonuniform perforation, the threshold generated by perforation friction will dominate the balanced fluid injection and expansion of each fracture. The horizontal well fracturing plan in a certain area of southwest China was optimized using this model. After optimization, when the spacing is less than 15 m, the total number of perforations is 32, and the average injection rate per cluster will be increased by 0.125 m3/min, with a coefficient of variation of 3.9% among clusters. When the perforations are nonuniformly distributed, the average injection rate per cluster will be increased by 0.101 m3/min, the fluid inflow difference coefficient of each cluster is 4.1%, and multiclusters will have a uniformly developed fracture network. This study has certain guiding significance and reference value for the balanced expansion of multifractures in horizontal wells.

Life cycle integrated flow simulation for hydraulic fracturing horizontal wells in shale gas reservoirs

The distribution of matrix pressure and water saturation during the fracturing and shut-in period significantly impacts shale gas production. However, traditional numerical simulations primarily focus on the production period, often overlooking the impact of fracturing and shut-in on the seepage field and production rates. This study uses the dual-porosity/dual-permeability-embedded discrete fracture model (DPDK-EDFM) to characterize matrix mixed wettability and the natural/hydraulic fracture geometry. A multiscale numerical simulation model is constructed to encompass the whole life cycle of shale fracturing, shut-in, and production. The model provides a comprehensive understanding for considering the changes in rock properties and the diverse migration mechanisms. Subsequently, the life cycle model is used for sensitivity analysis on capillary pressure, shut-in time, and fracturing fluid volume. The findings demonstrate that (1) capillary pressure strongly impacts flowback rate. As surface tension increases from 0 to 72 mN/m, the flowback rate decreases from 113.00% to 68.25%. (2) The shut-in time strongly affects the uniformity of pressure distribution. (3) The fracturing fluid volume is directly proportional to the rise in formation pressure. This innovative model provides a robust framework for simulating and analyzing the seepage field behavior of shale gas reservoirs throughout the life cycle. Furthermore, through a comprehensive investigation of the main controlling factors, this study provides valuable insights into the efficient development of shale gas reservoirs, carrying both theoretical and practical significance.

Estimating hardness and Young's modulus of shale using drill cuttings: Implications for hydraulic fracturing in shale gas reservoir development

Shale formations are widely prevalent in the oil and gas industry as potential hydrocarbon reservoirs. The hardness and Young's modulus of shale significantly impact the success of hydraulic fracturing operations in shale gas reservoir development. The unavailability of standard-sized core samples (length to diameter ratio ∼2.5) makes it challenging to determine the mechanical properties of shale in the laboratory. This study investigates techniques for estimating hardness and Young's modulus using drill cuttings. The microhardness was measured on shale cuttings of ∼1 mm in size using a micro indenter. Young's modulus was measured at the macro-scale using a uniaxial compression test on a 25 mm diameter core sample. The relationship between microhardness and Young's modulus established for Longmaxi (China) and Ice-Box (Western Canada) shales was applied to another shale (e.g., Sembar Shale of Pakistan), for which no core samples were available. The measured mineralogy of the studied shales provides a common base for the comparison of microhardness and Young's modulus using isotropic and anisotropic theoretical models. A positive correlation was observed between Young's modulus and microhardness for the three shales tested in this study. Although the scale of measurement/assessment is different, the theoretical models show an insignificant impact of the scale range (micro (mm) to macro (cm)) on Young's modulus, microhardness, and brittleness.

Molecular dynamic simulation of the influence of layer charge characteristics on the anisotropic elastic properties of hydrated montmorillonites

Montmorillonites are commonly existing in shales and understanding the anisotropic elastic properties of montmorillonite is very crucial because they provide important geomechanical information for the discovery and development of shale gas. Layer charges with varying densities and locations are naturally associated with montmorillonites and it has been demonstrated that these layer charge characteristics can dramatically influence the anisotropic elastic properties of dry montmorillonites. However, montmorillonites are generally hydrated by water under reservoir conditions and whether the existence of water will impact the effect of the layer charge characteristics on the anisotropic elastic properties is still poorly understood. To gain such knowledge, this paper investigated the anisotropic elastic parameters of hydrated montmorillonites with various layer charge characteristics via molecular dynamic (MD) simulations. The results demonstrated that the existence of water reduces all the elastic factors of montmorillonites, and weakens the variation of the elastic factors with different layer charge locations (LCLs), in comparison with dry montmorillonites. It was also found that when hydrated, the influence of layer charge density (LCD) on the in-plane compressional factors tends to be diminished, and the out-of-plane compressional and shear factors tend to increase consistently with increasing LCD, whereas their dependence on the LCD can be disordered in different dry montmorillonite models. The variations in the basal spacing and the interactions between the atoms caused by different layer charge characteristics when water is present were found to plausibly explain and interpret the simulation results. The results not only illustrate the link between the anisotropic elastic properties and layer charge characteristics in hydrated montmorillonites but also provide crucial geomechanical information to help the successful discovery and development of shale gas reservoirs containing hydrated montmorillonite.

Frac-Hit Prevention Countermeasures in Shale Gas Reservoirs with Natural Fractures

The development of natural fractures (NFs) in shale gas reservoirs is conducive to improving the productivity of shale gas wells. However, NF development leads to high-frequency frac hits between the infill and parent wells, which critically restricts its efficiency. To elucidate the large contribution of hydraulic fractures (HFs) and NFs in frac hits during the production and the development of NF-developed shale gas reservoirs, such reservoirs in the WY area of western China are taken as an example. A total of 197 frac hits well events in this area are systematically classified via the frac-hit discrimination method, and the effects of different factors on HF- and NF- dominated frac hits are classified and studied. Combined with the correlation analysis method and the chart method, the main controlling factors affecting the two types of frac hits are determined, and the corresponding frac-hit prevention countermeasures are proposed. The research demonstrates that (1) the distribution and development of NFs are crucial to production after frac hits. NFs and HFs in the WY area cause 51% and 49%, respectively, of the frac hits. (2) The main controlling factors in NF-dominated frac hits are the approximation angle, fracture linear density, and horizontal stress difference, whereas they are net pressure in fractures, horizontal stress difference, and liquid strength in HF-dominated frac hits. Sensitivity analysis shows that the NF activation difficulty coefficient fluctuates between −35.1% and 47.6%, and the maximum hydraulic fracture length fluctuates between −43.5% and 25.29%. (3) The corresponding frac-hit prevention countermeasures are proposed for the two types of formation mechanisms from different approaches, including frac-hit risk assessment and path planning, production well pressurization and stress diversion, and infill-well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of frac hits in fractured shale gas reservoirs but also a theoretical basis for the corresponding frac-hit prevention countermeasures.

Post-frac evaluation of deep shale gas wells based on a new geology-engineering integrated workflow

The development of shale gas reservoir is now shifting focus from mid-shallow reservoirs to deep reservoirs in the southern Sichuan Basin. For such reservoirs with high temperature, pressure, and stress difference, along with multiple folds, faults, and complex fracture networks, improving the stimulation performance of shale gas wells is the ultimate challenge. This study presents a new geology-engineering integrated workflow coupling hydraulic fracture simulation and reservoir simulation together with artificial intelligence to perform post-frac evaluations. A two-step calibration workflow of fracturing and reservoir simulations generated an ensemble of representative models, and a confidence interval of estimated ultimate recovery forecast were obtained. Four deep shale gas wells with two different completion versions (version 1.0 and version 2.0) in Y101 study area were evaluated. Some of the key learnings include: (1) the ratio of stimulated rock volume and drained rock volume is quantified to 8%–25% for the four characterized deep shale gas wells; (2) the version 2.0 completion design is able to stimulate the near-well region more effectively than version 1.0; (3) this novel geology-engineering integrated workflow performed the first reliable, robust and quantifiable post-frac evaluation in the southern Sichuan Basin deep shale reservoir.

Mechanisms of the imbibition behavior in shales: A critical review

Despite the success of hydraulic fracturing in yielding large production increases from shale gas reservoirs, uncertainties associated with basic transport processes require understanding in order to improve the efficiency and minimize environmental impacts. The hydraulic fracturing process brings in large volumes of water into shale reservoir formations, most of which remains unrecoverable and interferes with shale gas production. The imbibition behavior in shales is commonly observed during the hydraulic fracturing process, and the mechanism greatly influences the hydrocarbon recovery in shale gas reservoirs. In this review, the imbibition models in shales are briefly summarized using the Lucas–Washburn model, piston repulsion model, capillary bundle model, and scalar model. Then the experimental study and numerical simulation of shale imbibition are discussed. Moreover, the influencing factors of the imbibition behavior in shales are analyzed, such as shale and fluid properties. Finally, the main conclusions and the future research direction prospects of the imbibition behavior in shale gas reservoirs are summarized. An accurate description of the imbibition behavior in shale is crucial for optimizing the hydraulic fracturing design and enhancing shale gas production in the development of shale gas reservoirs. It is proposed that the research on the individual influencing factors of shale percolation and the geological mechanism under coupling should be strengthened and that the research on the experimental aspects of shale powder percolation should be emphasized.

Study of Estimated Ultimate Recovery Prediction and Multi-Stage Supercharging Technology for Shale Gas Wells

The development of shale gas reservoirs often involves the utilization of horizontal well segmental multi-stage fracturing techniques. However, these reservoirs face challenges, such as rapid initial wellhead pressure and production decline, leading to extended periods of low-pressure production. To address these issues and enhance the production during the low-pressure stage, pressurized mining is considered as an effective measure. Determining the appropriate pressurization target and method for the shale gas wells is of great practical significance for ensuring stable production in shale gas fields. This study takes into account the current development status of shale gas fields and proposes a three-stage pressurization process. The process involves primary supercharging at the center station of the block, secondary supercharging at the gas collecting station, and the introduction of a small booster device located behind the platform separator and in front of the outbound valve group. By incorporating a compressor, the wellhead pressure can be reduced to 0.4 MPa, resulting in a daily output of 12,000 to 14,000 cubic meters from the platform. Using a critical liquid-carrying model for shale gas horizontal wells, this study demonstrates that reducing the wellhead pressure decreases the critical flow of liquid, thereby facilitating the discharge of the accumulated fluid from the gas well. Additionally, the formation pressure of shale gas wells is estimated using the mass balance method. This study calculates the cumulative production of different IPR curves based on the formation pressure. It develops a dynamic production decline model for gas outlet wells and establishes a relationship between the pressure depletion of gas reservoirs and the cumulative gas production before and after pressurization of H10 −2 and H10 −3 wells. The final estimated ultimate recovery of two wells is calculated. In conclusion, the implementation of multi-stage pressurization, as proposed in this study, effectively enhances the production of, and holds practical significance for, stable development of shale gas fields.

Visualization of hydraulic fracture interacting with pre-existing fracture

Hydraulic fracturing is considered the main stimulation method to develop shale gas reservoirs. Due to its strong heterogeneity, the shale gas formation is typically embedded with geological discontinuities such as bedding planes and natural fractures. Many researchers realized that the interaction between natural fractures and hydraulic fractures plays a crucial role in generating a complex fracture network. In this paper, true tri-axial hydraulic fracturing tests were performed on polymethyl methacrylate (PMMA), on which pre-existing fracture was pre-manufactured to simulate natural fracture. A cohesive model has been developed to verify the results of the experimental tests. The key findings demonstrate that the experimental results agreed well with the numerical simulation outcomes where three main interaction modes were observed: crossing; being arrested by opening the pre-existing fracture; being arrested without dilating the pre-existing fracture. Crossing behavior is more likely to occur with the approaching angle, horizontal stress difference, and injection rate increase. Furthermore, the higher flow rate might assist in reactivating the natural fractures where both sides of the pre-existing fractures were reactivated as the injection rate increased from 5 to 20 mL/min. Additionally, hydraulic fractures show a tendency to extend vertically rather than along the direction of maximum horizontal stress when they are first terminated at the interface. This research may contribute to the field application of hydraulic fracturing in shale gas formation.

Numerical simulation of deflagration fracturing in shale gas reservoirs considering the effect of stress wave impact and gas drive

Methane deflagration fracturing is a new reservoir stimulation method that serves the efficient development of shale gas reservoirs. However, the propagation law of deflagration fractures is still unclear. In this paper, a numerical model considering the effect of stress wave impact and gas drive of deflagration fracturing was established based on the continuum–discontinuum element method (CDEM). The correctness of the numerical model was verified by comparing it with a laboratory experiment, the steady and unsteady analytical solutions of gas flow, and the approximate solution of fracture propagation. Then, numerical simulations of methane deflagration fracturing in vertical wells and horizontal wells under different factors were carried out to analyze the fracture mechanism. The results indicate that deflagration fracturing in vertical wells can break through the stress concentration around the borehole; the initial radial fractures are formed under the action of stress wave impact and then propagate substantially under the driving action of high-pressure gas. The in-situ stress difference affects the deflagration fracture propagation and makes the half-fracture length in the direction of maximum principal stress larger than that in the direction of minimum principal stress. The more significant the stress difference is, the more noticeable this deviation will be. When the deflagration peak pressure is high, the reservoir burst degree is large, which is conducive to enlarging the stimulation range of deflagration fracturing. Staged deflagration fracturing in horizontal wells can form 5–8 obvious fractures perpendicular to the horizontal borehole in each explosion section. A large cluster spacing and explosion section length are conducive to expanding the stimulation scope. Moreover, the propagation of deflagration fractures will be induced by the natural fractures, and the natural fracture with a considerable length or a slight angle between the dip angle and the propagation direction of deflagration fractures is more likely to be activated.

Formulation optimization of materials used in temporary plugging diversion between fracture front end and cluster in shale gas: From laboratory research to field application

The staged and multi-cluster fracturing of horizontal wells is the main fracturing technology used for shale gas reservoir development. Temporary plugging diversion (TPD) is an important technical means to realize a uniform propagation of hydraulic fractures and avoid problems such as frac hits (i.e., well-to-well interference). Although this technology has been extensively used worldwide, field monitoring results have shown that temporary plugging cannot effectively improve the nonuniform propagation of multiple fractures. The fundamental reason is the lack of an organic combination of laboratory research and field application. To solve this problem, this study investigated the reservoir adaptability and plugging performance of three types of temporary plugging agent (TPAs), namely, powder, particle, and fiber, used in the fracturing of wells in the Weiyuan (WY) shale gas field, Sichuan, China, using a pressure-bearing capacity test device for three dimensional (3D)-printing-simulated TPA. A calculation method for the plugging efficiency of the TPA was established, and the ratio and concentration of the TPA were optimized under different fracture widths. The similarity criterion was used to calculate the amount of TPA required for different fracture widths. A field application chart of the TPA was formulated, and a method that connects laboratory research and field application was established. The results showed that the three TPAs have good reservoir adaptability and degradation performance. It is recommended to use 200–400 mesh powder + 6 mm fiber with different concentrations and dosages when performing temporary plugging and fracturing at the front end of 1–3 mm fractures. In the case of inter-cluster TPD for a fracture width of 4–6 mm, a combination of 20 mesh powder + 6 mm fiber + 1–3 mm particles is recommended. The field application results showed that the pressure increased significantly at the front end of the fractures and during inter-cluster temporary plugging when the plugging agent was in place, and there were no frac hits in the adjacent wells. This paper provides a practical research method for hydraulic fracturing involving temporary plugging, from laboratory research to engineering application.

A new approach for post-fracturing evaluation and productivity prediction based on a reservoir fracability index model in shale gas reservoirs

Multistage fracturing technology is the primary means of reservoir stimulation in shale gas wells. However, the productivity contribution of each stage varies greatly. It is essential to evaluate the fracturing effect in order to make an optimized treatment design. In this study, we adopted an integrated workflow to assess the main control factors of geological and engineering parameters and a novel approach was proposed for post-fracturing evaluation. For this purpose, the H block in Zhaotong shale gas demonstration zone in Sichuan, China, has been taken as an object of study. The production predicting model was built based on the reservoir fracability index (RFI) which took both fluid type and proppant size differences into consideration. The results demonstrated that (1) if the reservoir quality index (RQI) in the target zone is greater than 5.0, then the area has good reservoir quality and development potential. (2) The RFI of H Block is generally at 4.0–6.0, it can be used as the key parameter to screen out the sweet spot. This method not only serves as a set of practical fracturing evaluation methods but also as a set of productivity prediction and fracturing optimization methods, which can provide strong support for the development of shale gas reservoirs.

Critical properties and phase behavior of confined fluids in irregular nanopores of shale gas reservoir

Real pore size and shape can induce critical properties shifts and phase behavior alterations for confined fluids in nanopores and impact the gas storage and transport mechanisms in shale gas reservoirs. Therefore, accurate calculations of phase behavior parameters in irregular nanopores are of great significance for the efficient development of shale gas reservoirs. No publications so far have been found to study the critical properties shift of confined fluids in irregular nanopores. In this paper, first, a quantitative description method for calculating the adsorbed volume of a multicomponent confined fluid in irregular nanopores is proposed, coupled with scanning electron microscope (SEM) images of shale cores and a semi-empirical formula for adsorbed thickness. Second, an effective molar volume correction method is extended to non-circular pores. Meanwhile, a new parameter is introduced to modify a molar volume term. Third, a novel correlation is proposed to predict the critical properties shifts in irregular nanopores considering pore shape and mixed fluid composition. Finally, a modified PR-EOS (Peng-Robinson equation of state) model is proposed, solved, and validated. Moreover, the critical parameters of pure component fluids and phase behavior characteristics of mixed hydrocarbons under different pore sizes, pore shapes, and hydrocarbon components are investigated, which reveals that a real pore structure and mixed fluid composition in shale gas reservoirs can change phase behaviors of confined fluids in nanoscale pores.

Characteristics and Model of Heterogeneous Wettability in a Marine-Continental Transitional Shale Reservoir: Insights from Organic Matter, Minerals, and Microstructure

Heterogeneous wettability is characterized by a spotted-wet or mixed-wet state. It has a great influence on reservoir evaluation and the efficient development of shale gas reservoirs. In this study, reservoir properties of several core plugs from the Permian Shanxi–Taiyuan formations were studied. These formations are typical marine-continental transitional shale located in the Southern North China Basin. To investigate the effects of reservoir properties on heterogeneous wettability, we measured the water–air contact angle and compared it with other properties such as organic petrology, organic geochemistry, mineralogy, and microstructure features, including pore-fractures and surface roughness. The results reveal a negative correlation of vitrinite content with contact angle, in addition to the high clay content and residual polar groups within type III kerogen, indicating that the Shanxi–Taiyuan shales with a high maturity level still have a higher affinity to water. The contact angle of the core samples decreases with increasing surface roughness, partially due to the influence of pore-fracture development. The crossplots indicate that the majority of pore-fractures that exist in the shale preferentially tend to be water-wet. Therefore, the heterogeneous wettability of shale is dominated by the random mixture and arrangement of hydrophilic and hydrophobic components as well as the complexity of the microstructure, such as the rough pore wall. Furthermore, on the basis of improving and examining the Cassie model, a triangle method and a detailed workflow for evaluating the heterogeneous wettability of shale are proposed by comprehensively analyzing “three factors”, including pore structure, mineral components, and organic matter. The test results demonstrate that the Shanxi–Taiyuan shales are mainly water-wet (controlled by organic factor) and neutral-wet, which evidently differ from the marine Longmaxi shale with a wide distribution covering the zones of strongly water-wet, weakly water-wet (controlled by pore factor), and weakly water-wet (neutral-wet). The proposed approach can be applied to promptly and comprehensively evaluate and predict the heterogeneous wettability of shales during shale oil and gas exploration.

Analysis of CO2 effects on porosity and permeability of shale reservoirs under different water content conditions

CO2 technology has been the key technology to enhance oil and gas recovery for shale oil and gas reservoir development. After injection, CO2 can react with water and generate carbonic acid, which then can react with various minerals in shale, leading to changes of porosity and permeability. However the specific research conclusions remain controversial on whether the effect of CO2 is improvement or damage for porosity and permeability. In CO2 hybrid fracturing, The areas with varied water content are formed due to the difference in mobility. So in this article, we carried out systematic research to clarify the interaction between CO2 and shale in different water content conditions (sufficient water, deficient water and water-free) and draw a pertinent conclusion. And the results show that the effects of CO2 treatment on shale have significant differences among different water content. Under sufficient water conditions, CO2 fully dissolves into water to generate carbonic acid, and large dissolved pores are generated by the massive dissolution of minerals such as feldspar and carbonates in the shale matrix, leading to the increase of porosity and permeability. Under deficient water conditions, only a small amount of carbonic acid is formed after the reaction of CO2 and water, leading to a significant decrease of porosity and permeability. Under water-free conditions, no dissolution is observed on the shale matrix, while some soluble components of organic matter may be extracted by CO2 to form organic pores, leading to slight changes in porosity and permeability. In large scales, although both porosity and permeability in the near-wellbore water-sufficient area is improved, the CO2-affected region presents the overall decline of porosity and permeability, due to the negative effects on the water-deficient area. So, it is necessary to enlarge the volume of water-sufficient areas to get a better effect of enhanced oil and gas recovery.

The Effects of Pore Wettability on the Adsorption and Flow Capacity of Shale Gas: New Insights from Molecular Dynamic Modeling

Pore wettability plays a key role in controlling shale gas adsorption and flow in marine shales. To reveal the mechanism of shale gas adsorption and flow in pores with different wettability (hydrophobic or hydrophilic), molecular modelling is simulated using the molecular dynamics method. Three pore assemblages, namely, the quartz–illite (Q–I) pores, the quartz–organic matter (Q–OM) pores, and the illite–organic matter (I–OM) pores, are proposed and the adsorption and diffusion behavior in these pores are simulated under different conditions. The results show that matrix compositions in shale greatly affect pore wettability. Water molecules preferentially absorb on the junction of materials and result in more hydrophilicity at the junction than pores. Methane density simulations reveal that free methane molecules form clusters in the Q–I pores, with higher free methane density than adsorbed methane. Methane molecules in the Q–OM pores are primarily adsorbed on organic matter. Free methane molecules extensively exist in the I–OM pores, leading stronger density of free methane than adsorbed methane. The more the proportion of free methane, the larger the methane self‐diffusion coefficient. This study provides new insights to understanding of shale gas adsorption and diffusion behavior, which is important for the effective development of shale gas reservoirs.