Fractured Shale Gas Reservoirs Research Articles

Effects of mechanical layering on hydraulic fracturing in shale gas reservoirs based on numerical models

Generally, induced hydraulic fractures are generated by fluid overpressure and are used to increase reservoir permeability through forming interconnected fracture systems. However, in heterogeneous and anisotropic rocks, many hydraulic fractures may become arrested or offset at layer contacts under certain conditions and do not form vertically connected fracture networks. Mechanical layering is an important factor causing anisotropy in sedimentary layers. Hence, in this study, with a shale gas reservoir case study in the Longmaxi Formation in the southeastern Chongqing region, Sichuan Basin, we present results from several numerical models to gain quantitative insights into the effects of mechanical layering on hydraulic fracturing. Results showed that the fractured area caused by hydraulic fracturing indicated a linear relationship with the neighboring layer’s Young’s modulus. An increase of the neighboring layer’s Young’s modulus resulted in better hydraulic fracturing effects. In addition, the contact between two neighboring layers is regarded as a zone with thickness and mechanical properties, which also influences the effects of hydraulic fracturing in reservoirs. The initial hydraulic fracture was unable to propagate into neighboring layers under a relatively low contact’s Young’s modulus. When associated local tensile stresses exceeded the rock strength, hydraulic fractures propagated into neighboring layers. Moreover, with the contact’s Young’s modulus becoming higher, the fractured area increased rapidly first, then slowly and finally became stable.

Numerical Simulation for Shale Gas Flow in Complex Fracture System of Fractured Horizontal Well

Abstract Complex fracture systems including natural fractures and hydraulic fractures exist in shale gas reservoir with fractured horizontal well development. The flow of shale gas is a multi-scale flow process from microscopic nanometer pores to macroscopic large fractures. Due to the complexity of seepage mechanism and fracture parameters, it is difficult to realize fine numerical simulation for fractured horizontal wells in shale gas reservoirs. Mechanisms of adsorption–desorption on the surface of shale pores, slippage and Knudsen diffusion in the nanometer pores, Darcy and non-Darcy seepage in the matrix block and fractures are considered comprehensively in this paper. Through fine description of the complex fracture systems after horizontal well fracturing in shale gas reservoir, the problems of conventional corner point grids which are inflexible, directional, difficult to geometrically discretize arbitrarily oriented fractures are overcome. Discrete fracture network model based on unstructured perpendicular bisection grids is built in the numerical simulation. The results indicate that the discrete fracture network model can accurately describe fracture parameters including length, azimuth and density, and that the influences of fracture parameters on development effect of fractured horizontal well can be finely simulated. Cumulative production rate of shale gas is positively related to fracture half-length, fracture segments and fracture conductivity. When total fracture length is constant, fracturing effect is better if single fracture half-length or penetration ratio is relatively large and fracturing segments are moderate. Research results provide theoretical support for optimal design of fractured horizontal well in shale gas reservoir.

An analysis of stochastic discrete fracture networks on shale gas recovery

Complex fracture networks are created by hydraulic fracturing in shale gas reservoirs. The well performance is largely affected by the geometrical properties of fracture networks. It is difficult to estimate well performance because a large number of parameters are used for characterization of a fracture network. In this study, only two parameters are screened to estimate the shale gas recovery by the method of design of experiments. Synthetic fracture networks are generated based on the stochastic theory to represent the secondary fractures in the hydraulic fracture network. Two numerical experiments are designed to correlate the fracture network properties to gas recovery estimated by a commercial software. Various fracture network parameters derived from the analyses of fracture intersection, fractal and percolation are screened to correlate the gas recovery. In terms of the internal structure of a fracture network, a dimensionless parameter called the effective fracture density is proposed to estimate shale gas recovery. It is a combination of the number of fractures, fracture length and orientation. In terms of the boundary of a fracture network, the shale gas recovery is determined by the number of intersection points between the primary fractures and secondary fractures (NIPS). The shale gas recovery predicted by the two parameters (the NIPS and the dimensionless fracture density) is accurate compared with that calculated by the commercial software, which provides us a practical method to estimate the gas recovery by eliminating the number of parameters used for fracture network properties.

Stimulated Reservoir Volume Estimation and Analysis of Hydraulic Fracturing in Shale Gas Reservoir

Hydraulic fracturing in horizontal well is the key technology for the commercial exploitation of shale gas reservoir. Stimulated reservoir volume (SRV) is an important indicator to evaluate the fracturing performance. However, estimating the SRV has been a long-standing challenge due to its complex forming mechanism. Most current SRV estimation methods are either expensive or time-consuming. This paper developed a 3D mathematical model to estimate the SRV by simulating the four main processes during shale fracturing—multiple hydraulic fractures propagation, formation stress variation, reservoir pressure lifting and natural fractures failure. In this model, hydraulic fractures propagation is calculated by pseudo-three-dimensional model, coupling with formation stress model; formation stress and reservoir pressure are obtained by displacement discontinuity method and Green’s function approach, respectively; natural fracture failure criterion is derived from Warpinski’s theory. This model not only considers the stress interference effect of multiple fractures, but also subdivides the SRV into shear-SRV and tensile-SRV according to the failure type of natural fractures network. This model was first implemented to a pilot well in the FL gas field in southwest China to estimate a SRV that matches well with the on-site monitoring microseismic signals. Then, this model was applied to FL gas field on a large scale to evaluate the overall fracturing effects. Finally, a sensitivity study was conducted to analyze the impact of engineering parameters on the SRV. This research explores an efficient method to estimate the SRV without high cost or complicated process and provides the theoretical basis and guidelines for pre-fracturing design and post-fracturing evaluation in shale gas reservoir.

Examining the Capability of Statistical Models to Mitigate Induced Seismicity during Hydraulic Fracturing of Shale Gas Reservoirs

Examining the Capability of Statistical Models to Mitigate Induced Seismicity during Hydraulic Fracturing of Shale Gas Reservoirs

A simulation method based on energy criterion for network fracturing in shale gas reservoirs

The fracture network in shale gas reservoirs has a plurality of extending frontiers and the propagation paths of fractures are difficult to predict in advance. When the network fracturing is simulated by the extended finite element method (XFEM) based on stress intensity factors, the computation is arduous and time-consuming, which limits the application of XFEM in field fracturing design. Therefore, a simulating method of crack propagation based on energy criterion is proposed. Based on the principle of energy balance, the energy criterion for controlling crack frontiers extending is established by the fluid injection energy, the rock strain energy, the surface energy, the seismic energy and the friction loss energy. The criterion only needs to calculate the energy distribution in the crack frontiers to judge whether the fracture could expand, avoiding the fussy calculation of the stress intensity factor. Based on the proposed energy criterion, the fluid solid coupling effect and the fractures interaction, an energy method is established for network fracturing simulation in shale gas horizontal well. The results show that the fracture network morphology obtained by simulation is basically consistent with micro-seismic monitoring result, and the computational efficiency of this simulation method is 10000 times higher than that of XFEM. The energy method provides an idea and basis for the simulation and design of shale reservoir fracturing.

The three-zone composite productivity model for a multi-fractured horizontal shale gas well

Due to the nano-micro pore structures and the massive multi-stage multi-cluster hydraulic fracturing in shale gas reservoirs, the multi-scale seepage flows are much more complicated than in most other conventional reservoirs, and are crucial for the economic development of shale gas. In this study, a new multi-scale non-linear flow model was established and simplified, based on different diffusion and slip correction coefficients. Due to the fact that different flow laws existed between the fracture network and matrix zone, a three-zone composite model was proposed. Then, according to the conformal transformation combined with the law of equivalent percolation resistance, the productivity equation of a horizontal fractured well, with consideration given to diffusion, slip, desorption, and absorption, was built. Also, an analytic solution was derived, and the interference of the multi-cluster fractures was analyzed. The results indicated that the diffusion of the shale gas was mainly in the transition and Fick diffusion regions. The matrix permeability was found to be influenced by slippage and diffusion, which was determined by the pore pressure and diameter according to the Knudsen number. It was determined that, with the increased half-lengths of the fracture clusters, flow conductivity of the fractures, and permeability of the fracture network, the productivity of the fractured well also increased. Meanwhile, with the increased number of fractures, the distance between the fractures decreased, and the productivity slowly increased due to the mutual interfere of the fractures.

A Two-Phase Flowback Model for Multiscale Diffusion and Flow in Fractured Shale Gas Reservoirs

A shale gas reservoir is usually hydraulically fractured to enhance its gas production. When the injection of water-based fracturing fluid is stopped, a two-phase flowback is observed at the wellbore of the shale gas reservoir. So far, how this water production affects the long-term gas recovery of this fractured shale gas reservoir has not been clear. In this paper, a two-phase flowback model is developed with multiscale diffusion mechanisms. First, a fractured gas reservoir is divided into three zones: naturally fractured zone or matrix (zone 1), stimulated reservoir volume (SRV) or fractured zone (zone 2), and hydraulic fractures (zone 3). Second, a dual-porosity model is applied to zones 1 and 2, and the macroscale two-phase flow flowback is formulated in the fracture network in zones 2 and 3. Third, the gas exchange between fractures (fracture network) and matrix in zones 1 and 2 is described by a diffusion process. The interactions between microscale gas diffusion in matrix and macroscale flow in fracture network are incorporated in zones 1 and 2. This model is validated by two sets of field data. Finally, parametric study is conducted to explore key parameters which affect the short-term and long-term gas productions. It is found that the two-phase flowback and the flow consistency between matrix and fracture network have significant influences on cumulative gas production. The multiscale diffusion mechanisms in different zones should be carefully considered in the flowback model.

Coupled Thermo-Hydro-Mechanical-Chemical Modeling of Water Leak-Off Process during Hydraulic Fracturing in Shale Gas Reservoirs

The water leak-off during hydraulic fracturing in shale gas reservoirs is a complicated transport behavior involving thermal (T), hydrodynamic (H), mechanical (M) and chemical (C) processes. Although many leak-off models have been published, none of the models fully coupled the transient fluid flow modeling with heat transfer, chemical-potential equilibrium and natural-fracture dilation phenomena. In this paper, a coupled thermo-hydro-mechanical-chemical (THMC) model based on non-equilibrium thermodynamics, hydrodynamics, thermo-poroelastic rock mechanics, and non-isothermal chemical-potential equations is presented to simulate the water leak-off process in shale gas reservoirs. The THMC model takes into account a triple-porosity medium, which includes hydraulic fractures, natural fractures and shale matrix. The leak-off simulation with the THMC model involves all the important processes in this triple-porosity medium, including: (1) water transport driven by hydraulic, capillary, chemical and thermal osmotic convections; (2) gas transport induced by both hydraulic pressure driven convection and adsorption; (3) heat transport driven by thermal convection and conduction; and (4) natural-fracture dilation considered as a thermo-poroelastic rock deformation. The fluid and heat transport, coupled with rock deformation, are described by a set of partial differential equations resulting from the conservation of mass, momentum, and energy. The semi-implicit finite-difference algorithm is proposed to solve these equations. The evolution of pressure, temperature, saturation and salinity profiles of hydraulic fractures, natural fractures and matrix is calculated, revealing the multi-field coupled water leak-off process in shale gas reservoirs. The influences of hydraulic pressure, natural-fracture dilation, chemical osmosis and thermal osmosis on water leak-off are investigated. Results from this study are expected to provide a better understanding of the predominant leak-off mechanisms for slickwater fracturing-fluids in hydraulically fractured shale gas reservoirs.

Coupled thermo-hydro-chemical modeling of fracturing-fluid leakoff in hydraulically fractured shale gas reservoirs

Once the low-temperature, high-pressure and low-salinity water contacts the shale matrix through the hydraulic fractures during the treatment of hydraulic fracturing, both mass and energy transfer occur due to the significant temperature, pressure, saturation and salinity gradients. Although, many leakoff models have been published, none of the models coupled the transient fluid flow modeling with heat transfer and chemical-potential equilibrium phenomena. In this paper, a coupled thermo-hydro-chemical (THC) model based on the derivation of non-isothermal chemical-potential equations from Gibbs’ free energy is presented to simulate fluid/heat flow behaviors during the leakoff process of hydraulic fracturing. The THC model takes into account a two-phase flow and a triple-porosity medium, which includes hydraulic fractures, organic and inorganic shale matrix. The simulation of fluid flow and leakoff with the THC model accounts for all the important mass and heat transfer processes occurring in fractured shale system, including fluid transport driven by convection, adsorption and diffusion, and heat transport driven by thermal convection and conductivity. The dynamic temperature, pressure, saturation and salt concentration profiles within fractures and shale matrix are calculated, revealing a multi-field coupled invasion region of fracturing-fluids during the treatment of hydraulic fracturing. In sensitivity analyses, cases with different initial reservoir temperature, pressure, saturation and brine salinity are considered. The impacts of the temperature, pressure, saturation and salinity gradients between the shale formation and the pumped fluids on the well injection and leakoff volumes during the treatment of hydraulic fracturing are investigated. Results show that although hydraulic pressure is the most factor which affects the fracturing-fluid leakoff behavior, the combination of chemical-osmosis, thermal-osmosis and capillarity still has a non-negligible influence on the fracturing-fluid leakoff. This study provides a better understanding of the mass and heat transport mechanism of water-based fracturing-fluids in shale gas reservoirs.

Coupled fluid flow and geomechanics modeling of stress-sensitive production behavior in fractured shale gas reservoirs

Compared with conventional reservoirs, gas flow in shale formation is affected by additional nonlinear coupled processes such as matrix/fracture deformations. We present a fully-coupled fluid flow and geomechanics model to accurately characterize the complex production behaviors of fractured shale gas reservoirs. The flow equations are discretized using a mimetic finite difference method, and poro-elasticity equations by a Galerkin finite-element approximation. A unified apparent-permeability model is implemented to quantify the combined impacts of the non-Darcy flow, adsorbed layer and pore-structure alterations on matrix permeability.The discrete fracture-matrix (DFM) model based on a conformal unstructured grid is employed to explicitly represent fractures. The nonlinear contact problem between the two fracture surfaces is introduced to describe the fracture mechanics behavior. A splitting-node technique is used to deal with the discontinuities in the displacement field across the fracture interface. Under the effects of pressure decline and high confining stresses on the fracture faces, proppant compaction and embedment may occur, causing fracture closure and thus substantial production loss. Hence we also develop a comprehensive proppant-fracture model which is based on the theories of elasto-plastic contact mechanics, to capture the complex interactions between proppant and fracture.The multiphysics numerical model enables us to investigate which factors have the most influential effect on the gas recovery of shale formations. High fidelity numerical solutions are provided to characterize the rate-transient signatures in the presence of the different flow and geomechanical mechanisms.

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

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

Numerical studies of interactions between hydraulic and natural fractures by Smooth Joint Model

The hydraulic fracturing technology is a key for enhancing the permeability of reservoirs during the production of natural gas. Significant progress has been made in hydraulic fracturing theory and practices, however, precise prediction of the fracture patterns in naturally fracture reservoirs still requires further study. The mechanisms influencing the interaction between hydraulic fracture (HF) and natural fracture (NF) should be well understood to achieve a wider application of hydraulic fracturing. In this paper, it is the first time to simulate the details of the interactions between hydraulic fractures (HFs) and natural fractures (NFs) using two-dimensional particle flow code (PFC2D) with embedded Smooth Joint Model (SJM). Firstly, the ability of SJM to emulate the natural rock joint was validated, and the fluid-mechanically coupled mechanism was introduced. Secondly, the interactions between a driven HF and a pre-existing NF were simulated considering fracturing fluid injection in a borehole. Lastly, the influence of approach angles and in-situ differential stress were studied. It is found that the model is capable of simulating the variety of interactions between HFs and NFs such as direct crossing, crossing with an offset and HFs arrested by NFs. Under high approach angles and high differential stresses, the HF tend to cross pre-existing NFs; on the contrary, a HF is more favorable to propagate along the NF and re-initiate at the weak point or the tip of NF. Moreover, our numerical results agree well with the analytical results based on the modified Renshaw and Pollards' criterion. Therefore, this numerical method may become a useful and powerful tool for optimizing fracture design in naturally fractured shale gas reservoirs.

An optimal design of cluster spacing intervals for staged fracturing in horizontal shale gas wells based on the optimal SRVs

When horizontal well staged cluster fracturing is applied in shale gas reservoirs, the cluster spacing is essential to fracturing performance. If the cluster spacing is too small, the stimulated area between major fractures will be overlapped, and the efficiency of fracturing stimulation will be decreased. If the cluster spacing is too large, the area between major fractures cannot be stimulated completely and reservoir recovery extent will be adversely impacted. At present, cluster spacing design is mainly based on the static model with the potential reservoir stimulation area as the target, and there is no cluster spacing design method in accordance with the actual fracturing process and targets dynamic stimulated reservoir volume (SRV). In this paper, a dynamic SRV calculation model for cluster fracture propagation was established by analyzing the coupling mechanisms among fracture propagation, fracturing fluid loss and stress. Then, the cluster spacing was optimized to reach the target of the optimal SRVs. This model was applied for validation on site in the Jiaoshiba shale gasfield in the Fuling area of the Sichuan Basin. The key geological engineering parameters influencing the optimal cluster spacing intervals were analyzed. The reference charts for the optimal cluster spacing design were prepared based on the geological characteristics of south and north blocks in the Jiaoshiba shale gasfield. It is concluded that the cluster spacing optimal design method proposed in this paper is of great significance in overcoming the blindness in current cluster perforation design and guiding the optimal design of volume fracturing in shale gas reservoirs.

Estimating spatial distribution of natural fractures by changing NMR [formula omitted] relaxation with magnetic nanoparticles

Natural fractures have been widely found and thought to be an important factor in creating a complex hydraulic fractures network and improving hydrocarbon production in shale reservoirs. Nuclear magnetic resonance (NMR) is extensively applied to measure in-situ petrophysical properties, and magnetic nanoparticles provide good contrast agents to distinguish hydrogen relaxation time for NMR. The objective of this paper was to estimate spatial distribution of natural fractures in shale gas reservoirs by applying magnetic nanoparticles to change the NMR relaxation times. Firstly, a three-dimensional (3D) reservoir model including multiple natural fractures was built to investigate the flow of nanoparticles and the distribution of volume magnetic susceptibility (VMS) when injecting magnetic nanoparticles. The sensitivity analyses about nanoparticle concentration and nanoparticles size were investigated. Secondly, a forward model was introduced about how to obtain Carr-Purcell-Meiboom-Gill (CPMG) echo decay trains from given relaxation times. Thirdly, an inversion method was presented to convert the typical CPMG echo decay curve into the distribution of T2 relaxation amplitudes and times. The inversion method was used to show the change of T2 amplitude and time for the two synthetic cases with and without magnetic nanoparticles.The dynamic distribution of nanoparticles concentration and VMS are graphically displayed along each time step in 3D mesh. The results show that magnetic nanoparticles bring much larger VMS while most nanoparticles only flow into these natural fractures (NF) directly connected with wellbore. The others’ NF have somewhat higher VMS than matrix. Additionally, based on various sensitivity cases, a higher concentration of nanoparticles yields a stronger magnetic field, and larger nanoparticle size could lead to higher VMS, although the nanoparticles face stronger flow resistance and less diffusion movement. The CPMG decay curve is a multi-dimensional exponential function related to relaxation amplitudes and times, and the least squares minimization technique can be applied to obtain the T2 amplitudes from CPMG curve. The comparison between two synthetic cases shows the amplitude for small T2 time increases and the amplitude for large T2 time reduces, which provides a clear indicator to detect the locations of natural fractures because their T2 largely reduce. The nanoparticle model provides valuable guidance about choosing parameters for optimizing magnetic nanoparticle injection design to enhance VMS and NMR signals. The inversion model introduces an efficient path for estimating T2 distribution and petrophysical properties from the acquired NMR CPMG signals. Additionally, magnetic Nanoparticles provide excellent relaxation contrasts to distinguish the magnetization signals of formation for estimating the spatial natural fractures distribution. Consequently, in-situ fracture characterization and the development of hydraulic fracture treatments could be beneficially improved.

Recovery Efficiency in Hydraulically Fractured Shale Gas Reservoirs

At the end of 2015 the U.S. held 5.6% or approximately 369 Tcf of worldwide conventional natural gas proved reserves (British Petroleum Company, 2016, “BP Statistical Review of World Energy June 2016,” British Petroleum Co., London). If unconventional gas sources are considered, natural gas reserves rise steeply to 2276 Tcf. Shale gas alone accounts for approximately 750 Tcf of the technically recoverable gas reserves in the U.S. (U.S. Energy Information Administration, 2011, “Review of Emerging Resources: U.S. Shale Gas and Shale Oil plays,” U.S. Department of Energy, Washington, DC). However, this represents only a very small fraction of the gas associated with shale formations and is indicative of current technological limits. This manuscript addresses the question of recovery efficiency/recovery factor (RF) in fractured gas shales. Predictions of gas RF in fractured shale gas reservoirs are presented as a function of operating conditions, non-Darcy flow, gas slippage, proppant crushing, and proppant diagenesis. Recovery factors are simulated using a fully implicit, three-dimensional, two-phase, dual-porosity finite difference model that was developed specifically for this purpose. The results presented in this article provide clear insight into the range of recovery factors one can expect from a fractured shale gas formation, the impact that operation procedures and other phenomena have on these recovery factors, and the efficiency or inefficiency of contemporary shale gas production technology.

Real-time microseismic monitoring technology for hydraulic fracturing in shale gas reservoirs: A case study from the Southern Sichuan Basin

Zipper hydraulic fracturing in multiple wells with long horizontal sections is a primary solution means to increase the shale gas production rate and efficiency and to reduce the cost in Southern Sichuan Basin. Microseismic based fracturing monitoring can be used for real-time imaging of hydraulic fractures, so it has been widely used to evaluate the fracturing effect of shale gas reservoirs and to direct the optimization and adjustment of fracturing parameters. In China, however, the microseismic fracturing monitoring on fracturing of shale gas reservoirs cannot be used to evaluate the fracturing results until the fracturing operation in the pad wells is completed according to the parameters which are designed prior to the fracturing monitoring. Its evaluation results can merely provide a guidance for the fracturing parameters of the next pad wells instead of the wells in operation. As a result, the real-time effect of microseismic fracturing monitoring is out of work. In view of this, the fractures induced by zipper hydraulic fracturing in multiple shale gas wells with long horizontal sections in the southern Sichuan Basin, was real-time imaged by using the combined technology of radially arranged microseismic surface monitoring and microseismic well monitoring on the basis of real-time positioning method. The fracturing results were assessed and used in real time for the optimization of prepad fluid parameter, perforation and temporary plugging additive releasing time, so as to effectively avoid repeated fracturing and uneven fracturing effects and improve fracturing stimulation effects. This method is applied in two well groups. It is shown that the average shale gas production rate is increased by 2–5 times. Furthermore, microseismic fracturing real-time monitoring plays a vital role in real-time evaluation of fracturing effect and real-time optimization of fracturing parameters, so it can be used as the reference and should be popularized further.

基于应力敏感的天然裂缝性页岩气藏双孔模型解的结构

For naturally fractured shale gas reservoirs, the problem about fixed output was addressed in 3 outer boundary conditions (infinite boundary, constant pressure and closed boundary) and inner boundary conditions, to build a well test analysis model for unsteady seepage flow in view of stress sensitivity and desorption & adsorption. Firstly, the model was linearized. Secondly, the perturbation method and the Laplace transform were used to get the exact solution of dimensionless reservoir pressure in the Laplace space with the linearized model. Finally, according to the similar structure theory, the steps leading to the similar structure of the solution to this model were presented. In addition, the kernel functions in the 3 outer boundary conditions were defined and it was found that a similar structure existed among the exact solutions of this model in the 3 outer boundary conditions. The work not only facilitates the development of well test analysis software with higher calculation efficiency, but also helps a lot in the investigation of shale gas seepage mechanisms, making a new method for the solution of the shale gas seepage model.

Numerical simulation of chemical potential dominated fracturing fluid flowback in hydraulically fractured shale gas reservoirs

To find out the impact of chemical potential difference between the low salinity fracturing fluid and the high salinity formation water on fracturing fluid flowback, a chemical potential difference expression of fracturing fluid and formation water was deduced, on this basis, a mathematical model which considers viscous force, capillary force and osmosis pressure driven gas-water flow in matrix-fracture system was built, the flow back performance of fracturing fluid driven by chemical potential difference was simulated, and the formation water saturation and salt concentration profile with flow back time were analyzed. The results show that in the process of flow back, the water molecules in the matrix driven by the chemical potential difference continually migrated to the deeper reservoirs, while salt ions in the matrix constantly spread to the fractures. After 168 h of fracturing-fluid flow back, the migration distance of water was up to 40 cm, and the salt concentration near the fracture surface increased by 0.841%, and the cumulative flowback ratio of the gas well was only 22.1%. The cumulative flowback ratio would be 23.5%, 32.4% and 41.1% respectively, without taking into account the effect of gas absorption, chemical osmosis or capillary imbibition. The capillary imbibition and chemical osmosis seriously hindered the fracturing-fluid flow back, therefore, the two factors should be fully considered in the post-fracturing evaluation of shale gas wells.

Numerical simulation study of shale gas reservoir with stress-dependent fracture conductivity using multiscale discrete fracture network model

ABSTRACTThe exploitation of shale gas has increasingly become the focus of worldwide energy industry. Due to the existence of natural/hydraulic fractures, most of the shale gas reservoirs exhibit high degree of heterogeneity and complexity which leads to the stress-dependent fracture conductivity of shale gas reservoir. Discrete fracture network (DFN) model is adopted in this research since the conventional continuum model cannot meet the numerical simulation requirements of fractured shale gas reservoir. A series of experiments about the fracture properties stress-dependent have been conducted on some shale core samples, the stress-dependent fracture conductivity correlation is selected and incorporated into the mathematical model to characterize the reduction of fracture conductivity potential with the reservoir pressure drop. The DFN model is applied to a shale gas reservoir with fracture network to study the effect of the stress-dependent fracture conductivity on the shale gas well performance. The results show that the effect of fracture conductivity reduction with pressure drop on the shale gas well performance depends on both the initial fracture conductivity and matrix permeability. The complex interactions between the fracture and matrix permeability should be considered when select the appropriate size of proppants for fracturing.