Development Of Shale Gas Reservoirs Research Articles

Experimental Study of Sand Distribution among Perforation Clusters in Horizontal Wellbore of Shale Gas Reservoir

Multistage horizontal fracturing is the key technique in developing shale gas reservoirs. In each stage, several perforation clusters will be placed to create complex fractures, and the parameters of perforation clusters are almost the same, so the production from each perforation cluster should be similar. However, in fact, production from each perforation cluster is different vastly. If the characteristics of the shale gas reservoir where the horizontal wellbore oriented through are similar, the cause that resulted in production difference may be uneven proppant distribution among perforation clusters. In order to investigate proppant distribution through perforation clusters, the theory about proppant settling along horizontal lateral is analyzed, which can provide a proper pumping rate for future experiments. Then, an experimental model to simulate horizontal lateral and perforated clusters is designed. Fresh water was pumped to transport proppant flowing into different clusters, the volume of water and proppant through each cluster was qualified. Some parameters, such as proppant concentration, sizes, flow rate, and perforation parameters, are changed in lab tests; the simulation results will be helpful in understanding the phenomenon of uneven proppant distribution in perforation clusters. There are some conclusions from the experimental results. First, proppant settling at different positions along horizontal lateral is different when the slurry is mixed by proppant and water is pumped at different rates. Meanwhile, proppants concentration also has an influence on proppants settling. The settling of proppants will impact proppants distribution among perforation clusters. Second, at a low pumping rate, uneven proppants distribution was observed mostly. When the pumping rate was increased, the phenomenon of uneven proppants distribution was decreasing. Thus, the pumping rate is the main influential factor. Third, uneven proppants distribution can be improved or even avoided by adjusting perforation parameters, such as perforation numbers and diameter.

Comprehensive modeling of multiple transport mechanisms in shale gas reservoir production

A boom in the production of shale gas has recently impacted the world’s energy supply. The hydraulic fracturing technology has been widely used in the development of shale gas reservoirs. Models for accurate reservoir simulation are essential for their economic production. In this paper, a model for shale gas reservoir production is proposed to account for slip flow, Knudsen diffusion, surface diffusion, gas adsorption/desorption, stress dependence of a pore structure, a non-ideal gas effect, and a flow mechanism difference between organic and inorganic content in the shale matrix. This model is implemented in our in-house simulator with a coupled MINC-EDFM approach to study and predict shale gas production behavior. Comprehensive sensitivity studies are performed to analyze the importance of different parameters in shale gas production. These parameters are divided into two categories. The first category includes reservoir data, such as shale matrix porosity, a nanopore radius, an organic/inorganic volume ratio, hydraulic fracture half-length, and fracture spacing. The second category includes parameters relevant to flow mechanisms, such as a non-ideal gas effect, stress dependence, presence of an adsorbed layer as well as a selection of a flow mechanism model. It is found that parameters related to hydraulic fractures impact calculated gas production more than reservoir matrix data. Among the fracturing parameters, hydraulic fracture half-length has a stronger effect than fracture spacing, and among matrix properties, porosity has a larger impact than a nanopore radius or the assumed organic/inorganic content ratio. These results help to optimize a shale gas reservoir production design. In addition, in a synthetic case assuming a 1 nm pore radius, the presence of an adsorbed gas layer has a more tremendous effect compared to the non-ideal gas and stress dependence phenomena. Moreover, the developed simulator with the multiple transport mechanisms can be used to accurately predict shale gas reservoir production. The findings of this study help a better understanding of shale gas flow and can be used to enhance the production of shale gas reservoirs.

Numerical investigation of complex fracture network creation by cyclic pumping

Horizontal well with multistage fracturing is an effective method to improve the development of shale gas reservoirs. However, it is challenging to create fracture network in the formation with high horizontal stress difference. On the basis of damage mechanics, a 2D fracture propagation model coupled seepage-stress-damage was established to study the influence of cyclic pumping on fracture network. In this model, the continuum variables were used to describe the cracks and joints that provide another means of modeling a joint rock mass. Subsequently, the Weibull distribution function was introduced to describe the heterogeneity of rock mechanics. Then, the maximum tensile stress criterion and the Mohr-Coulomb criterion were used as the threshold of the constitutive relation of the damage. Furthermore, when the unit’s stress state attain maximum tensile stress criterion or the Mohr-Coulomb criterion, then tensile or shear failure of the unit occurred. In current study, the finite element simulation of hydraulic fracturing was carried out with the size of 200×60 m2. The results showed that the cyclic pumping was an effective means to create complex fracture network, and the horizontal stress difference, the flow rate, and the frequency of cyclic pumping govern the fracture network generation and fracture morphology. When the horizontal stress difference was below 12 MPa, the total fracture length increased by 37.5% at least. Meanwhile, the total length of the fracture network increased with the increasing of flow rate. Compared of fracture length under four different pumping rate, it found that the total fracture length increased by 12.1% at least. The fracture network complexity increased with increasing number of loading cycles, and the cycle pumping with variable frequency was more effective to create fracture network. In the simulation, when the frequency of the cyclic pumping increased from 7 cycles to 10 cycles, the total fracture length increased by 10.2%. When the variable frequency applied in the model, the total fracture length increased by 14.8%. Based on the simulation, it indicated that the cyclic pumping was an effective way to create the complex fracture network, it also provided a means to create the complex fracture network in the formation with high horizontal stress difference.

Strength Softening Characteristics of Shale Clay Mineral Expansion

In recent years, the exploration and development of shale oil and gas reservoirs has become a hot topic in various countries around the world. The mechanical properties of shale are an important basis for evaluating the mining effect. Previous studies have shown that shale swells with water, which greatly effects its mechanical properties. Based on the analysis of shale composition, a clay mineral swelling test and 3D compression test were carried out to analyze the influence of clay minerals on the mechanism of shale swelling and softening in water. The results show that hydration of clay minerals results in interlayer and intergranular swelling. Furthermore, an expansion force will be exerted on the rock skeleton. The clay minerals expansion will cause a decrease in the uniaxial compressive strength, decrease in the elastic modulus, and increase in the Poisson's ratio, both in normal and parallel directions to the shale plate bedding. The brittleness index calculated based on the elastic modulus and Poisson's ratio values also decreases. This work is significant for further engineering development of shale reservoirs.

Numerical simulation analysis of vertical propagation of hydraulic fracture in bedding plane

Hydraulic fracturing is one of the principle technologies employed for achieving the efficient development of shale oil and gas reservoirs, and the bedding plane of the reservoir is a key factor affecting the geometrical distribution of hydraulic fractures in three dimensions. The present study adopts cohesive force unit theory to construct a multi-layer hydraulic fracture propagation model with coupling stress damage filtration, and the effects of changes in the reservoir stress field, angle of the bedding planes relative to vertically propagating hydraulic fractures, and tensile strength of the bedding planes on the vertical propagation of hydraulic fractures are analyzed. The simulation results show that the hydraulic fracturing process of penetrating the bedding planes can be divided into three stages. Here, the hydraulic fracture propagates in the rock matrix and intersects with the bedding planes with continuous injection of fracturing fluid in stages I and II, while the vertical stress, bedding plane angle, and tensile strength of the bedding planes determine the direction of hydraulic fracture propagation in the third stage. Reservoirs with low vertical stress differences and nearly horizontal bedding planes with low dip angles are found to be favorable for opening the bedding planes, and reservoirs with high vertical stress differences and bedding plane dip angles are favorable for the longitudinal expansion of hydraulic fractures. Simultaneously, the degree of opening of the bedding planes also increases as the tensile strength of the bedding planes decreases. This is mainly because the energy consumption of the bedding layer opening process decreases as the tensile strength of the bedding planes decreases.

Experimental evaluation of oxidation sensitivity in organic-rich shale reservoir

Organic-rich shale reservoirs are rich in reductive minerals, such as pyrite and other organic matters. The working fluid for the development of shale gas reservoirs contains large amount of dissolved oxygen. Once the working fluid enters the organic shale reservoir, it will oxidize the reducing components, cause mineral transformation, release solid phase particles, change the pore structures, and damage the seepage capacity of organic-rich shale reservoirs. The understanding and evaluation of the oxidation sensitivity is of great significance for improving the productivity of shale reservoirs. Therefore, organic shale of the Longmaxi Formation in the Pengshui area of the southeastern Sichuan Basin (China) was taken as the research object in the current work. In order to evaluate the reservoir fluid sensitivity, experiments were conducted to evaluate the oxidation sensitivity of the organic-rich shale reservoir. The experimental results showed that oxic fluids had the highest degree of damage on the permeability of shale than the reductive and degassed fluids. The oxidation sensitivity indices, Sox, of the shale samples were found to be 65.62% and 54.88%, respectively, which are moderately strong. The mechanism for the damage of the oxidation sensitivity of shale involves the production of Fe2O3, Fe(OH)3, FeCO3 (siderite), CaSO4·2H2O (dihydrate gypsum), MgSO4, other precipitated solid particles (chemicals), and the shale debris. Therefore, the pores and fractures were blocked by solid particles, resulting in the decrease in fracture width as well as the number of solid particles, which could be expelled. An appropriate concentration of oxidants has a positive effect on the permeability of organic-rich shale. The oxidation will produce macroscopic cracks and a large number of dissolution pores that significantly improved the transport capacity of the pore fracture system, and increased the permeability of the organic-rich shale.

Influences of bedding characteristics on the acoustic wave propagation characteristics of shales

Abstract The acoustic response characteristics of shales were investigated by the acoustic transmission experiment, which is the basis of solving geological and engineering problems using the seismic or logging information during the process of the exploration and development of shale gas reservoirs. Based on the theory of acoustic wave and the background of acoustic transmission experiment, the initial condition, vibration source condition, boundary condition and stability condition were constructed, and the numerical simulation of acoustic transmission experiment of shales were completed through Matlab programming. The results show that under the same bedding angle, the acoustic time and attenuation coefficient of shales shown positive correlation with the bedding density; whereas under the same bedding density, the variation laws of the acoustic time and the attenuation coefficient of shales were more complex with the change of the bedding angle, that is, the acoustic time and attenuation coefficient of shales increased first, then decreased and then increased again with the increase of the bedding angle.

Study on Two Component Gas Transport in Nanopores for Enhanced Shale Gas Recovery by Using Carbon Dioxide Injection

Injecting carbon dioxide to enhance shale gas recovery (CO2-EGR) is a useful technique that has raised great research interests. Clear understanding of the two-component gas transport mechanisms in shale nanopores is the foundation for the efficient development of shale gas reservoir (SGR) and also the long-term geological storage of CO2. Although extensive studies on single-component gas transport and corresponding models in shale nanopores have been carried out in recent years, limited studies have been conducted on two-component or even multi-component gas transport models in shale nanopores. In this work, the shale nanopores were classified into inorganic and organic nanopores. The corresponding models for two-component gas transport were constructed. Mechanisms including Knudsen diffusion, slip flow, viscous flow, and molecular diffusion are considered in the inorganic pores. In the organic pores, due to existence of adsorption gas, surface diffusion is further considered besides the aforementioned mechanisms. Effects of pressure, temperature, fraction of organic nanopores, and gas concentration were analyzed. Results show that gas apparent permeability is negatively correlated with pressure, and positively correlated with temperature and organic nanopore fraction. As the concentration of CH4 decreases, the apparent permeability of CH4 increases continuously, while the apparent permeability of CO2 decreases. The permeability ratio of CH4 in the total permeability is negatively correlated with pressure and gas concentration ratio. Additionally, the contribution of transport mechanisms to the total gas apparent permeability has been analyzed. It is found that the surface diffusion contributes up to 5.68% to gas apparent permeability under high pressure. The contribution of molecular diffusion can reach up to 88.83% in mesopores under low pressure. Under high pressure and macropores, it contributes less than 1.41%. For all situations, the contribution of viscous flow is more than 46.36%, and its contribution can reach up to 86.07%. Results of this study not only can improve the understanding of two-component gas transport in nanochannels, but also can lay the foundation for more reliable reservoir simulation of CO2-EGR.

Application of SEM and EDS for mineral composition of shale gas reservoir

In recent years, great progress has been made in the exploration and exploitation of shale gas, making it the main driving force for the growth of world natural gas production. Mineral composition restricts the pore size, distribution, geometry and connectivity of shale reservoirs, and also affects the brittleness and fracturing ability of shale reservoirs. Therefore, mineral composition is of great significance to the evaluation and exploration and development of shale gas reservoirs. Taking the Paleogene shale reservoir in Liaozhong Sag as an example, this study explored the application of argon ion polishing technology, Field Emission Scanning Electron Microscope (FE-SEM) and X-ray Energy Dispersive Spectrometer (EDS) analysis in mineral identification.

Pressure performance of multi-stage fractured horizontal well with stimulated reservoir volume and irregular fractures distribution in shale gas reservoirs

With the development of hydraulic fracturing technology of horizontal well, most unconventional gas reservoirs are developed by horizontal well multi-stage fracturing technology to improve gas well production. In this paper, we present a semi-analytical model of multi-stage fractured horizontal well (MFHWs) with consideration of adsorbed gas desorption and the irregular hydraulic fractures distribution in shale gas with the stimulated reservoir volume (SRV). On the bases of the point source function, Langmuir isotherm adsorption and Fick's law, wellbore pseudo-pressure solution of finite-conductivity MFHWs model is obtained by employing Laplace transform, finite cosine Fourier transform. and the discrete fracture approach in shale gas. The pressure transient responses log-log curves of MFHWs are drawn by Gauss elimination method and Stehfest numerical algorithm. In the light of the characteristics of the pressure derivative curve, the characteristics of each flow stage are identified and analyzed in detail. With the comparison of the commercial well test software numerical solution and the previous literature, the comparison results reach a good agreement under condition of same parameter. The effects of vital parameters, such as hydraulic fractures number and size of the SRV region, hydraulic fractures distribution styles and crossflow coefficient, on pressure transient curve are analyzed in detail. The presented model in this paper not only provides some insights for pressure dynamic analysis of shale gas reservoir development, but can help to engineers understand the pressure dynamics in shale gas reservoirs with SRV and irregular fracture distribution.

A generalized model for gas flow prediction in shale matrix with deduced coupling coefficients and its macroscopic form based on real shale pore size distribution experiments

As an unconventional natural gas resource, shale gas is attracting increasing attention worldwide because of its potential to strengthen global energy security and reduce carbon emissions. The shale gas flow in nanopores is one of the main concerns affecting its development process. However, due to the strong nonlinearity and complexity of gas flow at the nanoscale, there is no satisfactory consensus on a physically sound flow mechanism scheme and its corresponding coupling method. Furthermore, although the integration method using specific functions has been proposed to facilitate the consideration of various pore sizes in shale matrix, the real shale experiments are rarely involved to realize this integration method with definitely determined parameters. In this study, the concept of “wall-associated diffusion” is firstly utilized to clarify the relationship among several flow mechanisms, and thereby a comprehensive flow mechanism scheme differing from common research is proposed, which physically considers both the division of mechanical mechanisms in nanopores and partition of flow space. Besides, the deficiencies in the mathematical models of viscous flow and several diffusion processes for flow description are illustrated. Using the molecular collision frequency expressions, a new coupling coefficient-based flow model in nanopores is derived to eliminate the aforementioned deficiencies by strengthening the correspondence between the flow models and Knudsen number (Kn), which is applicable in the full flow regime scope and avoids segment processing. Furthermore, based on the pore size distribution experiments of the real shale samples from a gas field, the fitting parameters needed for the macroscopic form of the above coupled model are obtained, so as to establish an integration method-based unified model for gas flow prediction in shale matrix. Results show that the prediction accuracy of the new model for the two tested shale samples is at least 2.2 times higher than several typical models and is also 1.9 and 7.5 times more accurate than the model without coupling coefficients, respectively. And the application of the proposed model to the flow experiment on another shale sample at higher pressure levels is in accordance with these observations. Interestingly, as temperature increases, the flow rate decreases with minor amplitudes. Under the conditions studied, the pressure change can cause over 10 times variation of the flow rate, revealing measures should be taken to maintain relatively high reservoir pressures to guarantee appreciable gas production from matrix if the other factors remain unchanged. In addition, the difference between the average flow shape in the whole rock and the gas motion in the pore of mean radius is revealed. Sounder in theoretical bases and better in application effects, the proposed model is expected to be of practical significance for guiding shale gas reservoir development.

Study of the effects of hydraulic fractures on gas and water flow in shale gas reservoirs

ABSTRACT Horizontal drilling and multi-stage hydraulic fracturing are the two key technologies for the successful development of shale gas reservoirs. However, there exist large uncertainties in optimizing hydraulic fracturing which affects water retention into shale matrix and gas productivity. In this work, a basic reservoir model with six-stage hydraulic-fracturing treatment was constructed to understand water retention and gas production in shale gas reservoirs. Gas diffusion, gas desorption, Darcy flow as well as non-Darcy flow were considered in this model. Then, a sensitivity study was performed to investigate the effects of hydraulic fractures on water retention and gas conductivity. The results indicate that only 34% of the fracturing water could be recovered back to the surface, and most of them remain in shale formations to interfere with gas production. The increase of fracture half-length, fracture width, fracture permeability, and fracture conductivity will reduce water retention while water retention in shale matrix will increase with the increasing of fracture spacing and fracture number. This work can provide a better understanding of the effects of hydraulic fractures on gas and water flow so as to optimize the hydraulic-fracturing treatment in shale gas reservoirs.

Water-Gas Two-Phase Flow Behavior of Multi-Fractured Horizontal Wells in Shale Gas Reservoirs

Hydraulic fracturing is a necessary method to develop shale gas reservoirs effectively and economically. However, the flow behavior in multi-porosity fractured reservoirs is difficult to characterize by conventional methods. In this paper, combined with apparent porosity/permeability model of organic matter, inorganic matter and induced fractures, considering the water film in unstimulated reservoir volume (USRV) region water and bulk water in effectively stimulated reservoir volume (ESRV) region, a multi-media water-gas two-phase flow model was established. The finite difference is used to solve the model and the water-gas two-phase flow behavior of multi-fractured horizontal wells is obtained. Mass transfer between different-scale media, the effects of pore pressure on reservoirs and fluid properties at different production stages were considered in this model. The influence of the dynamic reservoir physical parameters on flow behavior and gas production in multi-fractured horizontal wells is studied. The results show that the properties of the total organic content (TOC) and the inherent porosity of the organic matter affect gas production after 40 days. With the gradual increase of production time, the gas production rate decreases rapidly compared with the water production rate, and the gas saturation in the inorganic matter of the ESRV region gradually decreases. The ignorance of stress sensitivity would cause the gas production increase, and the ignorance of organic matter shrinkage decrease the gas production gradually. The water film mainly affects gas production after 100 days, while the bulk water has a greater impact on gas production throughout the whole period. The research provides a new method to accurately describe the two-phase fluid flow behavior in different scale media of fractured shale gas reservoirs.

Horizontal well fracturing mode of "increasing net pressure, promoting network fracture and keeping conductivity" for the stimulation of deep shale gas reservoirs: A case study of the Dingshan area in SE Sichuan Basin

The deep shale gas reservoirs of Upper Ordovician Wufeng–Lower Silurian Longmaxi Formation in the Dingshan area of the southeastern Sichuan Basin have a great burial depth and complicated geologic features, so the fracturing technologies that are used for medium–shallow shale gas reservoirs are not suitable for their stimulation. In this paper, "double sweet spot" zones of shale gas were selected by combining engineering and geological research. The horizontal well fracturing technology suitable for deep shale gas reservoir was developed. And the fracturing mode suitable for medium–shallow shale gas reservoirs was improved. In addition, the improved fracturing mode and technology were applied in 3 deep shale gas wells in the Dingshan area. And the following research results were obtained. First, the deep shale gas reservoirs in the northwest of the Dingshan area have the characteristics of "double sweet spot" of geology and fracturing, and the development of natural fractures and bedding fractures provides a favorable condition for the formation of complex fracture networks after fracturing. Second, a combined fracturing mode of "pre acid + gel + slickwater + gel" was developed for the "double sweet spot" zones. In this mode, high-viscosity slickwater is adopted to increase the proppant-transport ability of liquid and enhance the fracture-creating effect, the fracturing technology of "controlling the near and extending the far" can increase the effective stimulated reservoir volume far from the well, and the ultra-high pressure facility can increase the fracturing displacement and the net pressure in fractures. Third, after reservoir stimulation, 3 deep shale gas wells present remarkable stimulation results, and their shale gas production rate during the testing is in the range of 10.50 × 104–20.56 × 104 m3/d. In conclusion, the improved fracturing mode and technology can provide a technical method for the stimulation of deep shale gas reservoirs in the Dingshan area, as well as a support for the breakthrough of exploration and development of deep shale gas reservoirs.

Exploration and development potential of the low-maturity continental shale gas in the Fuxin Basin

In order to promote the exploration and development of continental shale gas reservoirs in China further, we systematically summarized the geological features of typical continental shale, such as the Ordos Basin. Then, the shale gas reservoir characteristics, geochemical characteristics and fracturing performance of the Lower Cretaceous Shahai Fm in the Fuxin Basin were analyzed by using the data of TOC contents, rock specific surface, pore size distribution and X-ray diffraction analysis of the whole rock. Based on this, it was compared with the marine/continental shale gas reservoirs from the aspect of geological feature. Finally, the shale gas reservoir and resource potential of the Shahai Fm were evaluated. And the following research results were obtained. First, the formation age of China's continental shale is later, its TOC contents vary in a large range, and its organic matters are mainly of a mixed-humic type. And it is characterized by low thermal evolution degree, low quartz content, high feldspar content, high carbonate content, and comparability of total brittle mineral content to marine shale. Second, shale in the Shahai Fm has shallow burial depth and its mineral composition is dominated by quartz, feldspar and carbonate minerals. Its pores are mainly mesopores with an average porosity of 3.47%. There are diverse reservoir spaces, which is favorable for the accumulation of shale gas. Third, the TOC content of the Shahai Fm shale is mainly above 2%, with a moderate thermal evolution degree of organic matter and high gas content. Fourth, the total brittle mineral content of Shahai Fm shale is up to 60%, indicating a good fracturing performance. Fifth, shale reservoirs in the Shahai Fm can be classified into three categories. Type I is target reservoirs of exploration and development, and Type II is favorable reservoirs. It is estimated that the amount of shale gas resources are in the range of 232.2–286.2 billion m3. It is concluded that the Shahai Fm shale in the Fuxin Basin has both resource potential in geology and fracturing performance in engineering, and its exploration and development prospect is broad. What's more, the potential of commercial shale gas development is great in the sweet-point areas.

Study on mechanical characteristics and damage mechanism of the Longmaxi Formation shale in southern Sichuan Basin, China

During the development of shale gas reservoirs, the mechanical parameters of shale rocks are greatly significant to guide reservoir drilling design, reservoir stimulation, scheme design, and wellbore stability evaluation. Compared with conventional gas reservoirs, the mechanical properties of shale gas reservoir are more complex and lack of the comprehensive understanding. In this study, the uniaxial and triaxial compression experiments of the Longmaxi shale in South China were conducted to understand the mechanical characteristics and damage mechanism of shale rocks. Combined with the characteristics of shale microstructure, the effects of the mechanical properties such as mineral composition, deformation, stress–strain, and fracture damage characteristics were analyzed and discussed. The results show that the stress–strain curves of shale are two main types of elastic deformation and elastic–plastic deformation. There is a significant difference in effective pressure of yield platform in different shale post-peak deformation. The effective pressure of rigid shale is 60 MPa while that of other shales is 30 MPa. With the increase of effective pressure, the increase of peak compressive strength decreases gradually, and the effect of effective pressure on compressive strength decreases gradually with the transition from the brittleness to the ductility. The higher the effective pressure of the brittleness to the ductility is, the greater the change of compressive strength with effective pressure is, and the smaller the compressive strength under low effective pressure is, the smaller the variation with pressure is. Shale rocks with relatively high brittleness under different effective pressures are mainly characterized by brittle split fracture dominated by tensile fracture, while other shales with low brittleness are dominated by single shear fracture plane.

Optimal design of cumulative shale gas hydraulic fracturing process based on rock fatigue damage theory

Staged fracturing technology for horizontal wells is one of the key technologies and is represented by the effective shale gas development technology of the unconventional energy economy. Rock fatigue cumulative damage theory is applied to study the design of hydraulic fracturing. This paper puts forward a design concept for hydraulic fracturing aimed at maximizing the volume of shale gas reservoir transformation. Based on Corten Dolan’s study on cyclic loading fatigue cumulative damage research, a rock fatigue damage accumulation equation is developed to quantitatively study the relationship between the residual strength of rock and related influencing factors. The results provide an important guiding role to optimize the hydraulic fracture parameters for the shale gas reservoir development programs and also for pump design programs.

A novel numerical model of gas transport in multiscale shale gas reservoirs with considering surface diffusion and Langmuir slip conditions

AbstractMultiflow mechanisms coexist in shale gas reservoirs (SGRs) due to the abundant nanopores and the organic matter as a medium of gas souring and storage. The gas transport mechanisms in nanopores including bulk gas transfer and adsorption‐gas surface diffusion were already investigated in pore‐scale models, but their effects on actual gas production of multistage fractured horizontal wells in SGRs are not clearly understood, which are crucial for the economic development of unconventional resources. Therefore, a comprehensive apparent permeability (AP) model which couples the surface diffusion of adsorbed gas, slippage flow considering the additional flux generated by surface diffusion based on Langmuir's theory, and Knudsen diffusion is established. The presented model is validated with the experimental data and lattice Boltzmann method (LBM) simulation results. Then, we propose a numerical model which combines multiflow mechanisms in microscale pores and a multistage fractured horizontal well (MSFHW) in macroscale shale gas reservoirs together. The effects of different transport mechanisms on both AP of nanopores and gas production are analyzed thoroughly. The results show that the effect of surface diffusion on the apparent permeability of nanopores is much greater than that on the actual gas production of MSFHW, and the influence of high‐pressure condition must be considered when calculating the surface diffusion coefficient. The presented numerical model has important implications for accurate numerical simulation and efficient development of shale gas reservoirs.

Characterization of fracture formation in organic-rich shales - An experimental and real time study of the Permian Lucaogou Formation, Junggar Basin, northwestern China

Abstract Volume fracturing in horizontal wells represents a principal technology in the effective economic development of unconventional shale oil and gas reservoirs. However, the number of intervals that were effectively fractured by this technology only account for 20%–50% of the total designed sections. Fracture development characteristics and the factors controlling artificial fracture growth in organic-rich shale require detailed evaluation; this cannot be accomplished using microseismic monitoring technology or well-log interpretation. In this paper, formation processes of micro- and nano-scale fractures in the organic-rich shales of the Lucaogou Formation, Jimusaer Sag, Junggar Basin, northwestern China, were presented. The study focused on the application of in situ, nano-scale CT imaging technology, in combination with rock mechanics analysis. Results allowed the visualization of fracture growth in the shale reservoirs, and revealed the influence of organic matter, mineral composition, and pore structure on the formation and distribution of artificial fractures. A three-dimensional dynamic growth model of micro- and nano-scale fractures in organic-rich shale was established. Data revealed that the Lucaogou Formation shale contained dolomite and illite intragranular pores, with a low abundance of organic pores; pore size ranged between 200 nm and 2 μm. Micro- and nano-size fractures were observed. The development of artificial fractures was positively correlated with the loading stress. The initiation stress of new generated fractures was 475 mN, which could break up dolomite, albite, K-feldspar, and the original pore system as well. The original pore system was generally conducive to fracture extension and expansion. As loading stress increased from 50 mN to 515 mN, the sample extension increased from 2 μm to 14 μm, and artificial fracture width increased from 0.3 μm to 10 μm. The total porosity increased from 5.45% to 8.35%, and volume growth rate reached 53.2%. These findings provide valuable insights into the study of fracture growth in organic-rich shales, and have implications for the design of hydro-fracturing in organic-rich shales.

Production Performance Evaluation of Multifractured Horizontal Wells in Shale Oil Reservoirs: An Analytical Method

Hydraulic fracturing stimulation has become a routine for the development of shale oil and gas reservoirs, which creates large volumes of fracturing networks by helping the hydrocarbon to transport quickly into the wellbore. However, the optimal fracture spacing distance and fracture conductivity are still unclear for the field practice, even though the technique has improved significantly over the last several years. In this work, an analytical method is proposed to address it. First, the analytical production rate for a single fracture is proposed, and then, we apply Duhamel principle to obtain the production rate of a horizontal well with multifractures. Based on this model, the flow regimes and essential affecting factors including fracture spacing, fracture conductivity, and skin factor are analyzed in this work. The optimal values and suggestion are provided based on the simulation results.