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The main factor contributing to the decline in effective fracture width and conductivity is proppant embedding into the fracture surface. In the deep shale's high-temperature, high-pressure, and high-stress environment, the rheological properties of rock cause proppant embedding to be deeper. Additionally, the effect of hydraulic fracture is difficult to maintain after fracturing, which causes a sharp decline in cumulative production. In this paper, the Hertz contact theory is used to establish a long-term fracture conductivity model that incorporates the two embedding behaviors of proppant elastic deformation and reservoir creep deformation. Through time integration, the variation of long-term fracture conductivity is obtained. The experimental data and the theoretical model agree well. The results show that long-term fracture conductivity gradually decreases as the proppant progresses from the elastic embedding stage to the creep embedding stage. The elastic modulus, viscoelastic coefficient, and particle size significantly impact on the fracture width. The rock's elastic modulus and viscoelastic coefficient have a negligible impact on the long-term fracture conductivity, which is positively correlated with sand concentration, proppant particle size, and elastic modulus. In this research, an accurate and effective analysis model is proposed to quantify the long-term fracture conductivity, reveal the hydraulic fracture closure mechanism of deep shale under high temperature and high stress, and provide technological solutions for long-term maintenance of high conductivity fracture channels, which is useful to increase deep shale production efficiency, lower the production decline rate, and extend the stable production cycle.

Hydraulic fractures are difficult to initiate simultaneously during multi-cluster fracturing owing to the strong heterogeneity of shale reservoir and the stress interference effect between adjacent hydraulic fractures. Some hydraulic fractures can initiate early and propagate rapidly, whereas others exhibit late initiation (or even fail to initiate) and propagate slowly, resulting in non-uniform propagation behavior of multiple fractures. This non-uniform propagation behavior can significantly limit hydraulic fracturing performance in shale gas reservoirs. Therefore, the minimization of non-uniform propagation of multi-cluster fractures is important in improving the shale gas development. Currently, diverting fracturing technology is implemented to restrain overextended fractures while promoting restricted fractures to facilitate uniform propagation. Pumping diversion balls to block the perforations of overlong fractures has become an important method to improve non-uniform fracture propagation. This method is, however, limited by lagging behind of theoretical simulation, and significant blindness in the current implementation of diverting fracturing. A dynamic propagation model for multiple-cluster hydraulic fractures was established in the current study by considering the stress interference effect between adjacent fractures and the effect of flowrate dynamic adjustment by diversion balls. This model is effective for the dynamic simulation of fractures propagation after pumping diversion balls. A fractured well in the Changning block was used as an example for the simulation of the dynamic fracture’s extension and the distribution of SRV before and after diversion. The findings showed that the temporary plugging ball significantly promoted the uniform extension. The number of temporary plugging balls, the number of diversions, and the timing of diversion were then optimized. The simulation method developed in this study has important theoretical significance and field application value in guiding regulation of uniform expansion of fractures and improving optimization of diverting fracturing design.

Casing deformation (CD) will seriously affect the fracturing progress and stimulation effect of shale gas. Taking 105 gas wells in the Luzhou shale gas area in southern Sichuan as an example, the CD prediction model was established by introducing the fracture operation curve diagnosis method to analyze the changes in net pressure and propagation mode during fracturing. The fracturing stage induced by CD is called the excited (ET) stage, and the fracturing stage that occurs during CD is called the CD stage. It is concluded that the change of net pressure and the propagation mode are coupled with each other. By natural fracture development, formation curvature and horizontal well trajectory, natural fractures and bedding have been active by high fracturing strength, or because of the frequent crossing-layer in single stage, local stress reverse, makes the net pressure decrease and makes the formation in strike-slip stress state to reverse fault stress state, liquid leak-off and blocked fracture propagation time are increased, thus inducing CD. According to the response law induced by CD, the CD pre-control mode is formed, and the CD pre-control technology is established to quantitatively evaluate the wellbore risk and optimize the fracturing operation order and time arrangement. The CD rate is reduced from 56% in the early stage to 20%, and the integrity of the wellbore is guaranteed to be 100%. The method has strong applicability in the field and can be further popularized.

The classical Darcy’s law cannot effectively describe the microscopic flow rules of shale gas. In addition, conducting gas transport experiments in nanopores is difficult, and the correctness of th...

Taking the Lower Silurian Longmaxi Formation in the Changning area of the southern Sichuan Basin as an example, the characteristics and formation stages of tectonic fractures are comprehensively st...

Shale gas is becoming an increasingly supplementary energy source because of its clean-burning and abundance. Economic gas production in shale requires the techniques of horizontal drilling and multistage hydraulic fracturing to create complex fracture network (CFN). How to accurately describe the characteristics of geometry and flow mechanisms of the CFN and select the most efficient approach for modeling are challenging. In this paper, a production forecasting model for multistage fractured horizontal well (MFHW) with CFN in shale is proposed based on the multiple interacting continua (MINC) theory (organic/inorganic matrix, natural fractures system) and lower-dimensional discrete fracture network (DFN) model (hydraulic fractures system). The model is designed to describe the unconventional flow mechanisms in shale system, such as fractal porous media and non-Darcy multiscale flow in ultra-tight matrix, ad-desorption on organic materials’ surface, rock un-consolidation within natural fractures, high-velocity turbulent flow near well range, and multiphase behaviors. We also propose a novel hybrid control volume finite element (CVFE) and finite-difference (FD) simulation method to obtain the numerical results of the model based on the unstructured 3D tri-prisms. The accuracy of the simulator is successfully validated and sensitivity analysis of some key factors (e.g.: fractal model permeability, Langmuir volume, heterogeneities of reservoir and fractures, well platform) are conducted to evaluate the impacts on production performance. Combing with the micro-seismic monitoring (MSM) data and engineering analyses, the DFN model is applied in Longmaxi shale formation to obtain the history matching with the field data and predict the production.

Optimum well spacing is an essential element for the economic development of shale gas reservoirs. We present an integrated assisted history matching (AHM) and embedded discrete fracture model (EDFM) workflow for well spacing optimization by considering multiple uncertainty realizations and economic analysis. This workflow is applied in shale gas reservoirs of the Sichuan Basin in China. First, we applied the AHM to calibrate ten matrices and fracture uncertain parameters using a real shale gas well, including matrix permeability, matrix porosity, three relative permeability parameters, fracture height, fracture half-length, fracture width, fracture conductivity, and fracture water saturation. There are 71 history matching solutions obtained to quantify their posterior distributions. Integrating these uncertainty realizations with five-well spacing scenarios, which are 517 ft, 620 ft, 775 ft, 1030 ft, and 1550 ft, we generated 355 cases to perform production simulations using the EDFM method coupled with a reservoir simulator. Then, P10, P50, and P90 values of gas estimated ultimate recovery (EUR) for different well spacing scenarios were determined. In addition, the degradation of EUR with and without well interference was analyzed. Next, we calculated the NPVs of all simulation cases and trained the K-nearest neighbors (KNN) proxy, which describes the relationship between the net pressure value (NPV) and all uncertain matrix and fracture parameters and varying well spacing. After that, the KNN proxy was used to maximize the NPV under the current operation cost and natural gas price. Finally, the maximum NPV of 3 million USD with well spacing of 766 ft was determined.

Shale gas is a potential substitute for the gradually depleted conventional oil and gas resources. Since studies on microscopic behavior of shale gas in nano−slits and the exact mechanical mechanisms behind it are still in urgent demand, this paper uses the model of graphite layers to describe microscopic details of shale gas occurrence behavior in organic−rich nano−slits from the viewpoint of molecular interactions by molecular simulation. “Dual adsorption mechanisms” and the consistency theory of gas distributions affected by wall effects under the condition of no overlapped wall force field are proposed to clarify the formation mechanisms of shale gas in the nano−slits. Results also show the critical channel width for all gases to be affected by the nano−scale effects is between 1 and 2 nm, and the regions (counted from the gas zone) for overlapped wall force field in 0.5 and 1 nm slits are about 0.32 and 0.42 nm, respectively. Furthermore, the effects of overlapped wall forces, channel size and pressure variations on gas aggregation and its movability etc., interaction mechanisms inside the nano−slits and their causalities, the development enlightenment for Knudsen layer (KL) and the whole gas have been explicitly depicted and clarified, which is expected to be a useful reference not only for shale gas evaluation and exploitation, but also for widespread research of gas occurrence phenomena in carbon−based materials in the field of industry.

For shale gas resevoirs development, many researches focus on how to improve the estimated ultimate recovery (EUR), and ignore the relation of economic benefits and EUR. Therefore, based on the research of EUR evaluation procedure as the basis of economic estimation, the relation of economic benefits and EUR is revealed in detail, and the economy-geology-engineering (EGE) model is creatively built. The results show that six researched wells all have economic benefits: the average EUR is 1.60 × 108 m3, and the after-tax averages of net present value, financial internal rate of return and investment payback period (Pt) are 434.32 × 104 USD, 10.39% and 4.45 years respectively. Combining with the seepage theory and on-site experience, the negative relation of Pt and development degree of free gas is determined. The economic benefits for the unit volume of shale gas are close about 0.03 USD/m3 under the current development technologies. The influence degrees of economic parameters from large to small are gas price, drilling cost, fracturing cost, business cost and subsidy respectively. The proposed EGE model can effectively predict the economic benefits with the complex geology-engineering factors in the Changning block, and the corresponding method can be generalized to more fields.

In recent years, the greenhouse gas control has been a hot issue. A solution of injecting supercritical CO2 (scCO2) in Longmaxi shale gas formation (in Southwest China) is proposed in this study. To evaluate the feasibility of this method that storing CO2 and enhanced gas recovery (EGR) simultaneously, we first carried out isothermal adsorption experiments on samples from Longmaxi formation to describe the adsorption behavior of CH4 and CO2, and a generalized Ono-Kondo Lattice (OK) model was applied to predict adsorption amount of pure CH4/CO2 and their binary mixtures under supercritical, high-pressure conditions. In addition, discrete fracture network (DFN) model was adopted to characterize the complex hydraulic fracture networks constructed from micro-seismic monitoring (MSM) data and engineering analysis. The porous flow in shale matrix was modeled with the multiple interacting continua (MINC) and fractal theories. A multiscale compositional numerical model based on unstructured tri-prism grids was finally developed and solved by control volume finite element (CVFE) method. The simulation results of base and CO2 injection cases presented that scCO2 huff ‘n’ puff in Longmaxi formation might be an effective method for CO2 storage and EGR, and the orthogonal experiments were designed to optimize scenarios in the field application and obtain a maximum balanced result of EUR and CO2 storage capacity (CSC) for multistage fractured horizontal well (MFHW) with complex fracture networks in shale.

We investigated the difference in production performances of three shale gas wells with different completions and fracturing designs. We used assisted history matching technique to perform production match automatically and obtain multiple history matching solutions. The history matching algorithm used in this study is neural networks Markov chain Monte Carlo. In addition, we utilized embedded discrete fracture model technique to model hydraulic fractures instead of local grid refinement method to speed up the simulation runs. The history matching parameters consist of fracture half-length, fracture height, fracture conductivity, fracture width and fracture water saturation for hydraulic fractures properties and include matrix porosity, matrix permeability and relative permeability curves for matrix properties. We found that fracture width, fracture half-length, fracture conductivity and matrix permeability were significantly different in three shale gas wells while fracture height, fracture water saturation, porosity and relative permeability curves were less different. The information from this study will be used further to improve completion and fracturing design.

We performed assisted history matching (AHM) in a real shale gas well using uncertain parameters such as fracture geometry, fracture conductivity, matrix permeability, matrix and fracture water saturation, and relative permeability curves. We also investigated the performance of two proxy models including K-nearest neighbors (KNN) and neural networks (NN) to be used in multiple-proxy-based Markov chain Monte Carlo (MCMC) algorithm. We emphasized the performance of both proxy models by comparing the number of history matching solution found and elapsed time. While, KNN required less elapsed time by half than NN, we found that NN performed better in terms of accuracy and predictability than KNN. In other words, NN required a smaller number of simulations by half than KNN in order to obtain the same number of history matching solutions. Therefore, it depends on what is more important to each problem either number of simulations or elapsed time. For history matching result, both proxy models in the multiple-proxy-based MCMC algorithm have similar results of posterior distribution of uncertain parameters. This confirms the robustness of the proposed history matching algorithm. The benefits of this study are that we can characterize fracture geometry and reservoir properties in a probabilistic manner. These multiple realizations can be further used for a probabilistic production forecast, future fracturing design, and well spacing optimization and planning. This AHM workflow can be applied to any hydraulic-fractured wells with historical production data.