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Casing shear deformation has become a serious problem in the development of shale gas fields, which is believed to relate to fault slipping caused by multistage fracturing. This paper presents a new investigation aiming at understanding the reduction of casing inner diameter after fault slipping under different conditions, according to microseism data and calliper surveys. A mathematical model, which was verified by measurement results, was established to build a relationship between microseism moment magnitude and slip distance. A 3D numerical model, which was verified by physical model experiments, was developed to quantify the relationships between slip distance and the reduction of casing inner diameter. And then the relationships among microseism moment magnitude, slip distance and the reduction of casing inner diameter were established. The influence of casing internal pressure, slip distance, mechanical parameters of cement sheath, and casing thickness on the reduction of casing inner diameter was analyzed. The mathematical calculation results showed that with the increase of the degree of moment magnitude, the radius and slip distance increase, and with the increase of stress drop, the radius decreases and the slip distance increases. The numerical analysis results showed maintaining high pressure, increasing the elasticity modulus and decreasing the Passion ratio of cement sheath and increasing the casing thickness were beneficial to decrease the reduction of casing inner diameter. Keeping the designed horizontal segment of well trajectory away from the fracture-developed area, or be parallel to natural fracture can decrease the slip distance of fault, which can decrease the reduction of casing inner diameter. Finally, some effective measures to reduce or prevent casing shear deformation were recommended. • The relationship between moment magnitude and slip distance was established. • The reduction of casing inner diameter after fault slipping was quantified. • Decreasing slip distance and increasing the casing thickness benefited protecting the casing. [ABSTRACT FROM AUTHOR]

Abstract The sustained casing pressure (SCP) problems in shale gas wells have not been effectively controlled by now. In field, the expandable cement sheath used in wells has decreased the SCP problems and in this paper, an analytical model is established to study how the expandable cement increases the sealing ability of cement sheath and give suggestions on optimized choosing of expandable cement. Meanwhile, the stress equilibrium state in well before cementing work which has not been considered in previous and it is considered in the analytical model here. During the curing process, the radial stress on the outer interface of cement sheath changes with time and increases much faster than it on the inner interface. In wells with single layer of casing, the radial stress on interfaces does not increase linearly with the cement elastic modulus (E t) and it will be affected by the elastic modulus of formation rock. In wells with double layers of casing, the expandable cement can significantly increase radial stress on interfaces during the production process and alters circumferential tensile stress into compressive stress which is useful for increasing the sealing ability of cement sheath. How the expandable cement increase the sealing ability of cement sheath in field has been analyzed and an optimized expand ratio of cement is proposed to control the SCP problems in shale gas wells. Highlights • An innovative stress analysis model considering the equilibrium state before the cementing work in wells is established. • Change of expand ratio and elastic modulus of cement during the solidification process is considered in mechanical model. • Integration method is used for calculating the effect of expandable cement on stress of cement sheath. • The variations of stress on the interfaces of cement sheath with time are calculated. • The stresses on interfaces of cement sheath in shale gas wells caused by cement expansion are achieved. [ABSTRACT FROM AUTHOR]

In the design of infill well trajectory in fractured area of shale gas reservoir, it is necessary to consider the problem how to bypass the fractured influence area of the old shale gas wells, as well as the problem of mutual interference between the different fractured sections during production. In this paper, the geometric model of the obstacles in fractured area of shale gas reservoir, which considers the trajectory error and fracturing effect, is established by vector algebra method. The trajectory type is classified according to positional relations among the obstacle, the directional line of initial point and target point. The trajectory optimization model for bypassing obstacles takes the minimum total well length as objective function, the safety distance to obstacle as one of the constraints. In addition, the geometric check method for judging whether there is interference between the different fractured sections is proposed based on the geometric obstacle model. Case studies have been carried out according to the field data from Fuling, and the results indicate that the trajectory optimization model in this paper can obtain the optimum trajectory to meet the needs for bypassing obstacle, minimum trajectory length and avoiding trial calculation. Besides, if the fracturing effect is ignored, the size of the obstacle will be significantly underestimated in fractured area of shale gas reservoir, which will result in drilling accidents. In sum, the obstacle model in this paper is more consistent with the situation of field fractured area drilling practice than that of the published model. This study will provide a more safer and briefer design method for optimizing the infill well trajectory in fractured area of shale gas reservoir, which is of great significance to the shale gas drilling design and drilling safety. • The coupling obstacles model considering both trajectory error and fracturing effect was proposed. • The optimization design model of well trajectory for bypassing obstacles has been established. • The geometric check method for judging whether there is interference between different fractured sections was proposed. • The obstacle size is underestimated when the fracturing effect and the unevenness of the fracturing effect are ignored. [ABSTRACT FROM AUTHOR]

Production casing deformation has hindered the safe and economic development of shale gas resources, especially in Weiyuan-Changning Shale Gas field, China. In terms of current literatures, this problem should be attributed to the casing failure induced by varying high loads during the multi-fracturing process. However, the characteristics of casing deformation under cycling loads have hardly been investigated in previous work. In order to realize the casing deformation mechanism during multi-fracturing, the casing deformation real-time monitoring system is improved, based on full-scale casing-cement sheath-formation system (CCFS) combination device. Further, the deformation testing experiments of P110 casing under cycling inner pressure loads, for four conditions (1#-standard condition, 2#-higher inner pressure, 3#-thinner casing, 4#-thicker cement sheath), are carried out ... Besides, the reliability of experiment approach is verified, by the consistency of effective circumference strain values in the loading process of first cycle between calculated by elastic theory and determined in this paper. Further, the casing strength under cycling loads is analyzed, to evaluate the casing failure in shale gas well. Results illustrate that the casing under cycling loads are available to generate residual strain, which are reliable to reach 0.035%, 0.104%, 0.042% and 0.027%, respectively, based on above mentioned four testing parameters under 16 cycles. The higher cycling inner pressure significantly increases the residual strain of casing, which is harmful for the casing protection. Increasing the thickness of casing and cement sheath is beneficial to reduce the residual strain of casing. The casing collapsing strength is linearly lowered with cycling number, due to the growing unrecovered strain of casing during multi-fracturing. It precisely explains the phenomenon that casing deformation frequently occurs in the last few fracturing stages of shale gas wells. The casing strength lines from experiment results demonstrate higher accuracy than API (American Petroleum Institute) standard, in evaluating the casing failure of field cases. This work will provide a new criterion for the parameters designs of casing and fracturing in shale gas wells, to reduce the risk of casing deformation during multi-fracturing. • The measurement of casing strain under cycling loads is achieved. • Casing under cycling loads are available to generate residual strain rather than perfect elastic strain. • The equations predicting residual strain of casing are raised by fitting experiment data. • Casing strength lines determined in this paper demonstrate higher accuracy than API standard in shale gas wells. [ABSTRACT FROM AUTHOR]

The flowback rate of a shale gas well is controlled by many factors, such as geological and engineering factors, which have a certain complexity. For the aforementioned reason, the knowledge-driven method often has difficulty effectively capturing the correlation rules among multiple datasets. As a data-driven algorithm, deep learning has strong advantages in data correlation analysis, nonlinear fitting and other applications. In this paper, an algorithm is set up to forecast the shale gas well flowback rate by using a deep learning algorithm based on the flowback characteristic factors and data from 286 shale gas wells in the Weiyuan field. An algorithm and prediction model of the flowback parameters of the Weiyuan shale gas wells is established to effectively capture their flowback characteristics. First, the general situation of the study area is briefly introduced, and the data used to predict the flowback rate in this area are analyzed. Second, based on the deep learning algorithm, two kinds of deep feedforward neural network structures and a neural network-based prediction method of shale gas well flowback rate are designed. Finally, according to the regional data, the prediction and analysis of the flowback rate of Weiyuan shale gas wells are carried out. The results show that the correlations between 17 factors, such as fracturing section length and shale gas well flowback rate, are not obvious, but that the deep learning method proposed in this paper can effectively and accurately capture the correlations between the data and predict the flowback rate. The results show high accuracy. • An approach of Shale gas well flowback rate prediction based on a deep learning algorithm is designed. • Two kinds of deep feedforward neural network structures for shale gas well flowback rate prediction are designed. • The flowback rate of Weiyuan shale gas wells are carried out using proposed algorithm. [ABSTRACT FROM AUTHOR]

Accurate production prediction plays a key role in the development and management of reservoirs. Since reservoir parameters are difficult to obtain for the hydraulically fractured wells, it seems very important to use wellhead pressure to predict production rate rather than bottom hole pressure and other parameters. In this paper, a new prediction method based on Temporal Convolutional Network (TCN) is proposed, which can predict production rate only based on wellhead pressure by learning past patterns between the two. The TCN model can adaptively learn past sequences of arbitrary length by adjusting the receptive field, in which the causal convolutions make it more reasonable to capture past dependencies and extract information, and each output of the model is only related to past inputs. With the direct multi-step prediction strategy, the model can learn relationship between past input-output. The grid search method is employed to select the appropriate receptive field and hyperparameters of the model. To validate the proposed method, three different shale gas wells from China are selected for evaluation and verification. The various results all show that TCN model outperforms the existing methods in terms of accuracy and trend, with all MAPEs less than 6%. By the ablation experiments of well 1 and well 2, we found that the learning of different patterns helps the TCN model to predict more accurately. • Temporal Convolutional Network (TCN) is proposed to predict production rate by wellhead pressure, not bottom hole pressure. • The method can adaptively learn past sequences, capture dependencies of the sequences and extract the underlying features. • The proposed TCN model can learn different production patterns and extract useful information to help in prediction. [ABSTRACT FROM AUTHOR]

An appropriate shut-in after fracturing can dramatically enhance performance of wells in shale gas reservoirs. In this study, a novel wettability index and mineral content curve based shut-in time optimization approach was proposed. First, a new experimental device for spontaneous imbibition of fracturing fluid under the conditions of formation temperature and confining pressure was designed. Then, we conduct a set of experiments on shale samples from the Longmaxi Formation (LF) in the Sichuan Basin to measure the water-wet index and determine the critical value of clay content. Finally, the low-field nuclear magnetic resonance (NMR) equipment was used to monitor the water flow in shale micro-pores, based on this, the shut-in time for different shale reservoirs was optimized. The experimental results show that LF shale hydration can induce new micro-fractures, and the fractures shape is mainly shale bedding fractures, with obvious directionality. The clay content is the key factor affecting water wettability of shale and the critical clay content value of type I and type II shale reservoirs was about 39.5%. The optimal shut-in time of type I and type II shale reservoirs are about 20 days and 15 days respectively. Field application of three wells showed that the average daily gas production was increased by 2–3 times. The research results can guide the development of shale gas reservoirs effectively. • In this paper, the water imbibition experiment of shale under the condition of formation temperature and pressure of shale reservoir was carried out, and the critical clay content affecting the imbibition capacity of shale was determined. • On this basis, the shut-in-time of different reservoirs types was further optimized. • The research results play an important guiding role in understanding the flow law of fracturing fluid in shale reservoirs. [ABSTRACT FROM AUTHOR]

The estimated ultimate recovery (EUR) of a single shale gas well is one of the important evaluation indicators for the scale and benefit development of shale gas. Nevertheless, due to the lack of engineering and geologic data, as well as the limitations of the existing empirical methods, the current production forecasting methods cannot make reasonable predictions for EUR. Therefore, Duong method is used as the prototype in this paper, a rapid and accurate empirical model for improved production prediction is proposed based on the historical production profile analysis of mass producing wells in Sichuan Basin. The accuracy and universality of the new model are verified by production examples in the Weiyuan, Changning, Luzhou and Yuxi blocks of the Sichuan Basin. The examples illustrate that the new model can be applied well in typical wells, and has no limitation of flow regimes for the production prediction of gas wells. In order to solve the problem of production data fluctuation and decline curve deviation caused by stimulation measures in the production process, a multi-segment production prediction model analysis method is proposed based on the improved model in this study and has been well applied in the field. Most importantly, the new model has clear physical parameters and is easy to operate. Performance of the new model based on production data is as reasonable as the modern production decline methods (including analytical model), which is better than existing empirical methods. • Proposing an improved empirical model, which is rapid and accurate. • Less parameters were selected, the new model still has clear physical meaning. • Application condition of the new model is not limited by the flow regime. • Performance of the new model based on production data is as reasonable as the analytical model. • Multi-segment production prediction model is well applied to gas wells with production data fluctuation. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has been widely used to exploit unconventional oil and gas resources for decades. The fracture closure during flowback and early production may be characterized by fluid dehydration and pressure drop in oil and gas production. In this paper, a fully coupled flow and geomechanics model is proposed to capture the dynamic behavior of key fracture parameters for flowback and early-time production. In this coupled model, the controlled volume method is used to numerically simulate the fracture flow, which can consider the geometry and conductivity distribution of the propped and unpropped fractures. For the fracture geomechanics, the joint-closure relationship is introduced to describe the fracture aperture of unpropped fracture. The empirical formula of effective normal stress and proppant parameters is applied to characterize fracture conductivity. The fracture aperture can be calculated coupled with the discontinuous displacement method (DDM) and the matrix transient linear flow. The coupled geomechanically model can consider the flow of the propped and unpropped fracture system, which is easy model-setup and convenient for practical application due to its excellent computational performance. Detailed flow behavior analysis shows that the aperture of the unpropped fracture is relatively slow during the fracture closure process. Compared with the fracture section opening under higher normal stress condition, the fracture section opening under lower normal stress condition has larger initial aperture and faster attenuation of aperture. The crucial fracture parameters, including fracture permeability and fracture length, can be well interpreted by matching flowback and production data. Furthermore, the relationship between fracture conductivity and effective stress for both propped and unpropped fractures can be explored. These new findings can also be applied to interpret reservoir/fracture properties from ChangNing shale fractured wells in China during flowback and early production. • A new flow-geomechanics model is developed for fractured shale gas well. • Propped fracture closure may exhibit two distinct stages. • Unpropped fracture opening against higher normal-stress has faster decreasing of aperture. • Dynamic properties of fracture can be interpreted using flowback and production data. [ABSTRACT FROM AUTHOR]

Multi-stage fracturing technology makes shale gas production economically viable. In this paper, an innovative model incorporating space variable and stress-sensitive fractures is established for the production of MFHW in shale. Multi-transport mechanisms including Darcy flow, Knudson diffusion, Surface diffusion are considered in the mathematical model. Three space variable conductivity patterns (Linear, Exponential, and Logarithmic variations) are introduced and adopted. Based on the discretization method, a novel method is proposed which can simulate uniform and space varying fractures conveniently. Then the semi-analytical solution is obtained by Stehfest numerical inversion and an iteration method. And good agreements with previous models are observed in the validation. Afterward, the pressure transient type curve is generated and eight flow periods are identified. Subsequently, the influences of several vital parameters are discussed in detail. The results show that space varying fracture enlarges the pressure drop and decreases the productivity of early time. Such an effect is enhanced as the space variable coefficient is increased. And this influence decreases with the increase of initial conductivity. Considering stress-sensitive fractures, a 'hump' appears in the pressure derivative curve and the early time productivity decreases. A bigger stress-sensitive coefficient accelerates the appearance of the 'hump' and makes the 'hump' sharper. The 'hump' and productivity decline caused by dynamic conductivity becomes more obvious with the decrease of the minimum conductivity. Complex transport mechanisms enhance inter-porosity flow. The inter-porosity flow would appear earlier with complex transport mechanisms. The model can simulate the gas flow of MFHW more realistically. It can help for better understanding of the production dynamic of MFHW in shale. • A semi-analytical approach is established for the pressure and rate transient of MFHW in shale gas reservoir. • Space variable and stress-sensitive fractures and multi-transport mechanisms of shale gas are considered. • A new solution and an iteration method are utilized to solve the space varying fracture and nonlinear problem. • Effects of some vital parameters on production performance are analyzed. [ABSTRACT FROM AUTHOR]

Wellbore integrity problem induced by insufficient seal ability of the cement sheath has become a technical challenge of shale gas wells during hydraulic fracturing. In this paper, a new model has been established to characteristic the mechanics of the casing-cement interface (CCI) and the cement-formation interface (CFI) of the shale gas wells. In this model, the radial stress and the stress intensity factor has been analyzed to predict the prolongation of the initial cracks caused by perforation through comparison of the stress intensity factor and the interfacial fracture toughness of the CCI and CFI. In addition, the influence of the casing and cement parameters on the interfacial stress and the crack width of the CCI and CFI has been discussed in detail, and the optimal design of these parameters has been proposed according to the field data. Finally, the conclusions and some realistic suggestions have been put forward based on the discussion. • A method analyzing the mechanics of the casing-cement-formation has been established. • The radial stress and the stress intensity factor on the interfaces have been figured out. • The prolongation of initial cracks caused by perforation has been analyzed. • The influence of casing and cement parameters on the crack width has been discussed. • Optimal design of casing and cement sheath has been proposed. [ABSTRACT FROM AUTHOR]

The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. It is of significance to make the most of multiple data in fracture characterization, including the measurements of hydraulic fracturing treatment, core, microseismic, production data, etc. Besides, handling the complex fracture networks (CFNs) explicitly is demanded in large-scale field case studies. This paper presents an efficient method to characterize the complex fracture networks (CFNs) and reduce the uncertainties by integrating stochastic CFNs modeling, reservoir simulation, and assisted history matching. In CFNs modeling, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data, and a stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities. To efficiently simulate the discrete fractures in field cases, the edge-based Green Element Method (eGEM) is modified by applying a steady-state fundamental solution and the technique of local grid refinement (LGR). Assisted-history-matching based on EnKF is implemented to calibrate the CFNs models and further quantify the uncertainties. The proposed method is applied to a field case from a multi-fractured horizontal shale gas well. The results show that the computation of the modified eGEM is much cheaper than the original eGEM when the steady-state fundamental solution and the technique of LGR are applied. Besides, acceptable precision can be obtained with relative coarse grids, for example, 50 m primary grids and 25 m refined grids near the fractures can be used in the test case. These advantages make the modified eGEM quite efficient in assisted history matching of large-scale field applications. The history matching results and EUR distributions show that the uncertainties are significantly reduced after 5 steps assimilation, and good results can be obtained after 10 steps assimilation. The distribution ranges of the matrix permeability and porosity are significantly narrowed down after history matching, while the matrix compressibility is hard to be determined because the rock compressibility is so small comparing to gas compressibility that gas production is not sensitive to it. The results also show that only part of the fractures are well-propped because only the fractures in a certain range of the wellbore are with good properties, that is high initial fracture conductivities and low conductivity moduli. • An integrated method for complex fracture networks (CFNs) characterization. • Geological, seismic, fracturing and production data can be assimilated. • An efficient froward model for field-scale reservoir simulation with CFNs. • Property calibration and uncertainty quantification of CFNs. [ABSTRACT FROM AUTHOR]

Shale gas reservoirs demonstrate low matrix porosity and permeability, and show obvious heterogeneity due to the existence of natural fractures. During the production process, fracturing fluid can easily invade the reservoir and result in a low fracturing flowback rate. The existing numerical methods are troublesome and have poor convergence. Therefore, it is necessary to develop a new approach to study the gas-water two-phase flow in shale gas reservoirs. In this paper, fractal theory is used to quantitatively characterize the heterogeneous fractures. A Mathematical model considering fractal induced-fracture distribution and gas-water two-phase flow in shale reservoirs is established. The meshless weighted least squares (MWLS) method is applied, for the first time, to the numerical simulation of gas-water two-phase flow in multi-fractured horizontal wells of shale gas reservoirs. Based on the moving least squares approximation, the variation principle is derived in detail. A numerical model of gas-water two-phase flow in the shale gas reservoir fracturing horizontal well based on the meshless method is obtained. The gas and water production of fractured horizontal shale gas wells are predicted by the model. The model simulation results are found to be in good consistent with the mathematical calculation results obtained through finite difference method. but the proposed new approach shows significant higher calculation efficiency. In addition, by applying this new approach, The influences of fracture distribution, initial water saturation, and reservoir reconstruction degree on the utilization range and production were also systematically compared and analyzed. The results showed that the smaller the fracture fractal index a in the reservoir reform area, the lower the pressure, the higher the daily gas production and the daily water production, indicating that the fracture network is densely distributed and the production effect is better. The larger the initial water saturation resulted in the greater flow resistance of the gas phase and the decrease of daily gas production. When the fracture spacing decreases in reservoir reconstruction, the daily gas production increases, but the increase range is gradually reduced and it has little effect on the daily water production. • Fractal theory is used to establish a complex heterogeneous dual medium for shale gas reservoir horizontal well fracturing. • The meshless weighted least square method is applied to the simulation of gas-water flow in fractured horizontal wells. • The effects of fracture distribution, initial water saturation and reservoir transformation degree are analyzed. [ABSTRACT FROM AUTHOR]

During large-scale multistage hydraulic fracturing in shale-gas wells, the cement sheath loses its integrity easily because of repeated temperature and pressure variations in the wellbore. This is likely to form a potential leak path, subsequently leading to the loss of zonal isolation and sustained casing pressure. To prevent such barrier failures, it is crucial to investigate and understand the failure mechanism of cement sheath. In this study, an experimental apparatus and evaluation method of the sealing integrity and mechanical integrity for casing-cement sheath under temperatures and pressures cycle loading have been presented in this paper by which sixteen groups of full-scale integrity tests of general and high-strength cement sheath have been conducted under temperature ranging from 30 to 150 °C and pressure ranging from 0 to 70 MPa cycling loading. The anti-channeling/sealing performance and interface mechanical behavior of casing-cement sheath are measured and characterized respectively under different loading-unloading methods. The cycle numbers required for sealing integrity failure of cement sheath under different cyclic temperatures and pressures have been obtained. The interface mechanical properties (cementing force, friction force, shearing strength and lateral bonding strength) of cement sheath have been obtained, and effects of alternating temperatures and pressures on those mechanical properties and late integrity have been analyzed. Research results can provide a very important reference for the fracturing design of shale-gas wells. • Full-scale integrity test of cement sheath under cycle loading has been conducted. • Correlation between mechanical integrity and sealing integrity is obtained. • Effects of cycle loading (T/P) on interface mechanical property are obtained. • Effects of cycle loading (T/P) on sealing integrity are obtained. [ABSTRACT FROM AUTHOR]

Sustained Casing Pressure (SCP) has become a serious problem in the development of shale gas fields, which is believed to relate to the multistage fracturing. However, few researches were on this, especially the study of micro-annulus at the interface between the cement sheath and casing, which was one of the mechanisms of the cement sheath integrity failure, and always caused by accumulated plastic deformation. This paper presented experimental and numerical investigations of the emergence and development of plastic deformation occurred at the interface between the cement sheath and casing during multistage fracturing. Mechanical tests and physical simulation experiments were carried out so as to analyze the plastic deformation variation characteristic of the cement sheath under cyclical loading and unloading. 3-D numerical models were established to analyze the emergence and development of the accumulated plastic deformation based on the test results, considering the actual engineering and geological conditions during multistage fracturing in shale gas wells, which presented a new method to calculate the width of the micro-annulus between the cement sheath and casing. The research showed that the numerical results were in accordance with the experimental results. With the increase of cycle times, the accumulated plastic deformation increased, which was the greatest for the first time, and then increased linearly. Decreasing elastic modulus and increasing Poisson's ratio, cohesive force and internal friction angle could facilitate the protection of the cement sheath integrity. Finally, a new cement slurry system was proposed based on the results of study and applied in 5 wells with good effects acquired, none of them showed SCP after fracturing. • A new device was established in this work to evaluate the induction factors of SCP. • A new numerical model was developed for analysis of the accumulated plastic deformation under cyclic loading. • Reducing elastic modulus and increasing Poisson's ratio could reduce the accumulated plastic deformation. • Increasing cohesive force and internal friction angle was beneficial to the cement sheath integrity. [ABSTRACT FROM AUTHOR]