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Abstract The SRV fracturing is the core of commercial exploitation of shale gas, and the design philosophy of the SRV fracturing is gradually introduced into the stimulation of conventional low permeability reservoir and unconventional reservoir. However, in reservoirs with poorly developed natural fractures or high horizontal principal stress difference, it is difficult to achieve the multi-fracture or fracture network by conventional hydraulic fracturing, and effectively stimulating reservoir needs other assisting methods. This paper aims to present a method of guiding the multi-directional hydraulic fractures by multiple radial slim holes drilled in spatial positions, and creating multi-fractures and even complex fracture network. In this paper, a 3D hydraulic fracturing extended finite element numerical model in the vertical well assisted by planar multi-radial slim holes was established, and the effect of radial slim hole number, diameter, length, vertical density, azimuth and phase angle, Poisson's ratio, horizontal principal stress difference and rock Young's modulus, fracturing fluid viscosity and injection rate, reservoir permeability, etc. on guidance of radial slim holes were investigated. Then, we conducted the true tri-axial hydraulic fracturing test with the artificial core, and the feasibility of the technology was verified. The results show that decreasing azimuth and phase angle and increasing hole diameter, length and vertical density strengthen the guiding effect of planar multi-radial slim holes, and increasing Poisson's ratio, reservoir permeability, and fracturing fluid injection rate and viscosity enhance the guidance effect of radial slim holes. Increasing horizontal principal stress difference and reservoir Young's modulus weaken the radial slim holes guiding effect. The physical modeling experiment proves that controlling generation of complex multi-fractures is feasible by rationally arranging the spatial positions of radial slim holes. The spatial arrangement of four planar radial slim holes with phase angle of 90°, azimuth of 45° and vertical density not less than 2 holes/m in the vertical well is a scientific scheme. With the reasonable treatment scheme, creating 6 main fractures is possible. The research results provide theoretical support for multi-fractured stimulation assisted by planar multi-radial slim holes, and help the design of well completion parameters and fracturing treatment parameters of the technology. Highlights • The new multi-fractured stimulation technique for hydraulic fracturing was put forward. • Stimulation experiments of radial slim holes-assisted hydraulic fracturing were carried out. • The effects of multiple factors on the guiding strength of radial slim holes were studied. • The best technical solution for radial slim holes-assisted hydraulic fracturing was proposed. [ABSTRACT FROM AUTHOR]

Abstract The fracture calibration injection falloff test, also known as mini-frac and diagnostic fracture injection test (DFIT), is widely used to quantify essential input parameters for the following main fracture treatment design. Over time, data presentations used to facilitate the analysis have revealed trends in the before-closure falloff transient data that have been labeled as abnormal closure. This paper provides new models for all known before-closure leakoff behaviors and a comprehensive model that enables a match with the entire before-closure transient response. The before-closure leakoff behaviors in the comprehensive model include wellbore storage (WBS), friction dissipation, tip extension, pressure dependent leakoff area (PDLA), multiple apparent closures, transferred storage (also known as transverse storage), height recession and variable fracture compliance. Besides the parameters such as closure pressure, leakoff coefficient, and the hydraulic fracture geometry that can be quantified by commonly known analysis techniques, the new model enables quantification of several new parameters. Two diagnostic plots are used to facilitate identification and quantification of the standard and newly modeled parameters: the Bourdet log-log plot of pressure change and derivative and the composite G-function plot. Tip extension is more easily identified on the G-function plot, and the model match with this behavior quantifies the tip extension distance after shut-in and the fracture minimum propagation pressure. So-called pressure dependent leakoff and transferred storage may be related to opening of secondary fractures, and may be seen as multiple closure events easily identified on either diagnostic plot. Such effects enable quantification of closure stress and surface areas for the secondary fracture sets. Alternatively, when the behavior that looks like transferred storage is explained as fracture height recession, the closure stress of overlying or underlying layers can be estimated along with the recessed fracture area. Variable fracture compliance has similar appearance with transferred storage as well in the diagnostic plots. When it occurs, the way to determine fracture closure stress and other parameters are provided. Matches with field data reflect highly enhanced understanding of the nature of hydraulic fracturing and natural fracture flow mechanisms that have not been possible with other models and that greatly refine well design strategies. Highlights • The paper provides a series of analytical models that enable quantification of all known before-closure abnormal leakoff behaviors, including wellbore storage and friction dissipation, tip extension after shut-in, natural fracture related pressure dependent leakoff and transverse storage, height recession, variable fracture compliance. • Besides the derivation of these models, we also provide the methodology to use these models to interpret the field data. • Four field DFIT cases from shale gas formations are used as examples to illustrate the models. [ABSTRACT FROM AUTHOR]

Abstract This paper presents a method to quantitatively characterize natural Fractures Intensity (FI) and proposes a Comprehensive Permeability Model (CPM) coupling gas transfer mechanisms in natural fractures and matrix for shale gas reservoirs. Firstly, the Scanning Electron Microscope (SEM) images of natural shale cores are used to quantitatively characterize FI, such as the aperture, length, spacing, general fracture distribution described by Fisher orientation dispersion value (K), and the Angle between the mean pole of Fractures and the Scan-line (AFS). Secondly, the corresponding relationship between the AFS and K, which can be used to evaluate the length of fracture traces per unit area of trace plane and the area of fractures per unit volume of rock, is built based on the numerical simulation results. Then, we can obtain the natural fracture distribution state and quantitatively distinguish the natural fracture volume from the matrix. Finally, the CPM is proposed by combining the FI and matrix pore parameters based on the series-parallel circuit theory. The CPM is not only verified by the numerical simulation in which the Boundary Element Method (BEM) is adopted to simulate the fractures' influence, but also in good agreement with the lab measurements of shale samples from the Cambrian Niutitang formation in South Sichuan Basin, China. The FI evaluation method and the CPM proposed in this paper provide a new approach to quantitatively understand the natural fracture distribution and the contribution to the shale reservoir percolation capability. In turn, this will enable engineers better understand the shale gas transport mechanisms and develop the simulation in a more practical way. Highlights • Novel gas permeability model for natural fractures and matrix pores. • The model is derived according to the series-parallel circuit theory. • The model is verified by numerical simulation results and experiments results. [ABSTRACT FROM AUTHOR]

Natural gas produced from shale formations in the United States over the past decade have altered the oil and gas industry remarkably. The Barnett shale was at the forefront of the shale gas revolution in the United States and was considered to be the highest producing natural gas field in the United States until 2012, yielding the top producer spot to the Marcellus shale. Due to the uncertainty regarding the accurate determination of Estimated Ultimate Recoverable (EUR) in shale gas reservoirs, this paper aims to assess EUR values for the Barnett shale using empirical decline curve methods like the Arp's hyperbolic, Modified Arp's hyperbolic and Doung's method. In addition, we investigated the economic viability of wells over time in the Barnett under various probabilities of success. Throughout this paper, reference is made to two key publications where a similar work was carried out for various shale plays in the United States, including the Barnett shale – though only the Arp's hyperbolic decline was employed. The dataset in this paper consisted of more horizontal wells from covering more counties within the Barnett shale compared to other similar studies. We conclude that either the Arp's hyperbolic or Doung's method can be used to forecast EUR in the Barnett shale as only marginal differences were observed. This is on the basis that production history exceeds 10 months (a maximum of 80 months production history was used). We also obtained reliable and conservative estimates of EUR compared to previous studies. [ABSTRACT FROM AUTHOR]

Shale formations often consist of multiple weak interfaces between layers, which is easily opened during hydraulic fracturing treatment and affect growth of fracture height. Fracture propagation in such formations usually induced complex fracture geometry with primary vertical fractures and horizontal fracture segments between layers. Although numerous numerical models have been developed to simulate fracture propagation in unconventional reservoirs, relatively few physical three-dimensional models exist to quantitatively simulate opening of fractures affected by weak interfaces. In this paper, we analyze width profile of fractures and interaction of vertical and horizontal fracture segments with predetermined fracture path under the assumption of neglecting the flow effect. A fully three-dimensional displacement discontinuity method (3D DDM) is introduced to model multiple fractures in a stage in three dimensions. The fracture geometry is prescribed, which combined with vertical and horizontal fractures. In each case, the horizontal fracture is regarded as opening of the bedding interface and vertical fracture would either be arrested or directly cross the interface. Interfacial sliding distance, defined as width jump of the vertical fracture at the interface, is regarded as a primary impact of fracture height containment. Analysis of fracture opening, shear displacements and interfacial sliding distance is given for both vertical and horizontal fracture segments. When multiple vertical fractures intersect with a horizontal interface, shear displacements are induced on the interface and vertical fractures have smaller width compared with the case without the horizontal interface, as a result of the interaction with the interface. We observed that both widths of fracture segments and interfacial sliding distance are positively correlated with the distance between the center of the vertical fracture and the horizontal interface, half-length of horizontal fracture segment, the net pressure within fracture segments. Conversely, Young's Modulus has a negative relationship with both width of fracture segments and interfacial sliding distance. This paper analyzes the effects of opening of weak interfaces and provides critical insights of fracture width distribution and its impacts on proppant transport. [ABSTRACT FROM AUTHOR]

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]

Natural and hydraulic fractures existence and state differs on a reservoir-by-reservoir or even on a well-by-well basis leading to the necessity of exploring the flow regimes variations with respect to the diverse fracture-network shapes forged. Conventional Dual-Porosity Dual-Permeability (DPDP) schemes are not adequate to model such complex fracture-network systems. To overcome this difficulty, in this paper, an iterative Hybrid Embedded multiscale (two-scale) Fracture model (HEF) is applied on a derived fit-for-purpose shale gas model. The HEF model involves splitting the fracture computations into two scales: (1) fine-scale solves for the flux exchange parameter within each grid cell; (2) coarse-scale solves for the pressure applied to the domain grid cells using the flux exchange parameter computed at each grid cell from the fine-scale. After that, the D dimensions matrix pressure and the (D-1) lower dimensional fracture pressure are solved as a system to apply the matrix-fracture coupling. HEF model combines the DPDP overlapping continua concept, the DFN lower dimensional fractures concept, the HFN hierarchical fracture concept, and the CCFD model simplicity. As for the fit-for-purpose shale gas model, various fit-for-purpose shale gas models can be derived using any set of selected properties plugged in one of the most popularly used proposed literature models as shown in the appendix . Also, this paper shows that shale extreme low permeability cause flow behavior to be dominated by the structure and magnitude of high permeability fractures. [ABSTRACT FROM AUTHOR]

Recent studies suggest the possibility of CO 2 sequestration in depleted shale gas reservoirs, motivated by large storage capacity estimates in these formations. Although various approaches have been proposed to evaluate and estimate CO 2 storage capacity and even almost all of researches mainly focus on the calculation of storage capacity at the present time, questions remain regarding the quantitative determination of abandonment pressure for a depleted shale gas reservoir, which is a key joint between shale gas recovery and CO 2 storage operation. Also the determination of abandonment pressure is the inversion problems of estimation of CO 2 capacity. Therefore, in this paper, to quantitatively determine the abandonment pressure and mathematically analyze related impacts of dynamic parameters on it, two semi-analytical models of pressure and rate transient analysis are simultaneously proposed for the closed outer boundary condition, without the assumption of sequential flow between the three contiguous media. Adsorption, desorption, diffusion flow, stress sensitivity and non-Darcy flow effects are simultaneously considered. Besides, a new modified Langmuir isotherm equation of CO 2 is initially established to consider the impacts of residual adsorption shale gas. Laplace transformation, source function, perturbation transformation method, superposition principle and numerical discretion method are employed to effectively solve these new models. Laplace solutions are inverted into real time space with stehfest numerical inversion algorithm. Numerical simulation and existing models are also simultaneously conducted to validate this proposed mathematical models. Based on this new solution, some crucial dynamic engineering parameters, including abandonment pressure and non-Darcy flow, are creatively analyzed combining pressure transient analysis (PTA) and rate transient analysis (RTA) For two kinds of CO 2 injection control: constant injection pressure and constant injection rate, it is the essence of this paper that typical chart referring quantitative determination of abandonment pressure is originally established via pressure transient analysis (PTA) and rate transient analysis (RTA). Via regression method using synthetic and real data, results mathematically show that for PTA method, the abandonment pressure has exponent relationship with the injection pressure, however, for RTA method, the abandonment pressure has logarithm relationship with CO 2 injection volume. Finally, well testing of gas production data, micro seismic date and core analysis allow for formation parameter estimation, two real shale gas wells from Sichuan Basin in China are selected to show the promising application prosperity of the new performance analysis and quantitatively determination of abandonment pressure for CO 2 storage in depleted shale gas reservoirs. [ABSTRACT FROM AUTHOR]

Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures. • Multiple migration mechanisms and different flow states were considered in the interlaced fracture networks model. • Novel curves of derivative are introduced to analyze the effects of secondary in induced fractures. • The angle and length of induced fractures are discussed to find the significant difference from ordinary MFHW models. • Flux distribution of interlaced fracture networks is discussed to obtain some advice for fracturing operation. [ABSTRACT FROM AUTHOR]

The study on shale gas transport mechanisms plays an important role in shale gas production simulation. The majority of previous works neglected the body gas diffusion mechanism, and the multiple effects of stress sensitivity and multi-component of gas mixture system. In this paper, first, a model is built considering the multiple transport mechanisms of continuum flow, slippage flow, body gas diffusion and Knudsen diffusion. Then, the multiple effects of stress sensitivity and multi-component of gas mixture system are coupled into the model. Results show that: (a). For the body gas flow, both of the two weighted coefficients for items of body gas diffusion and slippage flow should be equal to one. And the ratio of one to Knudsen number is belong to the equation of body gas diffusion. (b). For a nanoscale pore of shale, the contribution of body gas diffusion on total mass flux cannot be neglected. The conductivities of continuum flow, slippage flow, modified slippage flow, Knudsen diffusion and weighted average flow decrease with decreasing of pressure due to shrinkage of nanopore radii and decrease in molecular concentration. (c). The decreasing of effective radii leads to the increase of the value of Knudsen number. The dominant transport mechanism is converting from modified slippage flow to Knudsen diffusion when the increase of stress sensitivity. (d). For methane confined in nanopores with extremely small effective transport radii, the injection of CO 2 can increase the mobility of methane. After a period of CO 2 injection, the methane molecules stored in nanopores can be flooded to fractures and then produced to the ground. • Multiple transport mechanisms, including body gas diffusion, are considered. • Multiple effect of stress sensitivity and multi-component are considered. • The injection of CO 2 can increase the mobility of methane confined in nanopores. [ABSTRACT FROM AUTHOR]

Abstract The modeling of shale gas transport through nanopores is the basis for shale gas production simulation. The real shale gas always consists of a series of gases, including ethane, propane and hydrogen sulfide etc. Previous models neglected the multi-component effect on the shale gas transport mechanisms. In this paper, a novel model is presented for simulating the real gas mixture transport through nanopores of shale formation. Firstly, a model is presented for ideal shale gas transport through nanopores considering the multi-component effect, then, the real gas effect is coupled into the model. Simulation results show that: (a) When it is under low pressure level condition, the conductivities of slippage flow and Knudsen diffusion increase with decreasing methane fraction. (b) When it is under medium pressure level condition, the conductivities of slippage flow and Knudsen diffusion increase with decreasing methane fraction. (c) Under high pressure condition, the conductivities of different flow patterns increase with decreasing methane fraction. Highlights • A novel model is proposed for real gas mixture transport through nanopores. • Both of the multi-component and real gas effects are considered. • The conductivity of real gas mixture increase with decreasing of methane content. [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]

Abstract Two-phase flow of oil and gas is quite common in the reservoir during the depletion of liquid-rich shale gas and tight light-oil. Many analytical models proposed for multistage fractured horizontal wells completed in unconventional reservoirs are restricted to single phase flow problem. In this paper, an approximate semianalytical method is proposed to handle the complexities of phase change, pressure dependent PVT properties, two-phase flow behavior and complex fracture networks. The black oil model is used to model phase change and two-phase flow of oil and gas. The secondary fractures in the stimulated reservoir volume and the reservoir beyond the main fractures are considered in the physical model to make long-term production forecasts. The forecasted producing GOR is used to decrease the equations of the two-phase flow model, so only the flow equations of primary phase are used to develop the mathematic model. Then an approximate method is used to linearize the model and the analytical solution is obtained in Laplace space for constant pressure inner boundary problem. The Duhamel's principle is applied to correct the production rate under variable flowing pressure inner boundary, and a procedure is proposed for history matching of field production data and making forecasts. Finally, the semianalytical model is validated with two simulation examples, the average relative error is shown to be less than 10%. After that, two field examples are used to show its utility. Highlights • A semianalytical model is proposed for liquid-rich shale gas and tight oil wells. • Secondary fractures are considered in the semianalytical model. • Both phase change and pressure dependent PVT properties are incorporated. • A work flow for two-phase production data analysis is presented. [ABSTRACT FROM AUTHOR]

Abstract Shale and its roof and floor are very important for shale gas preservation. How to clarify the mechanism of its vertical sealing and its effect on shale gas enrichment is a significant problem to be solved. In this paper, the objective layers are the Upper Ordovician Wufeng Formation, the first member of the Lower Silurian Longmaxi Formation and the Lower Cambrian Qiongzhusi Formation, which are all in the representative shale gas blocks in the Sichuan basin of the Yangtze region. Studied by statistical drilling data, the focus is on the detailed analyses of the JiaoYe-1, Ning-201 and Wei-201 well, and experiments were carried out such as the porosity test, the TOC content analysis and the experiment of overburden permeability, permeability experiments before and after adsorption of methane under different osmotic pressure, and isothermal adsorption experiments. The experiments results are applied on studying the effect of shale and its roof and floor on shale gas enrichment, combined with formula deduction. The results show that the roof and floor have a vertical sealing effect on the organic-rich shale by the difference of physical properties. In eastern Sichuan, the roof of the organic-rich shale of the Wufeng Formation and the first member of Longmaxi Formation is assemblage of argillaceous siltstone and siliceous shale, while in southern Sichuan it is assemblage of gray shale and siliceous shale. The floor is nodular limestone and limestone in both areas. The combination of roof and floor, with low porosity, can form a quality roof and floor sealing ability in the absence of fracture development. Its sealing ability is stronger than that in the upper part of the Qiongzhusi Formation, considering its roof and floor composed of argillaceous siltstone and siliceous shale. The floor of the organic-rich shale at the bottom of the Qiongzhusi Formation is a dolomite reservoir with good storage capacity, between which there is an unconformable contact causing the worst sealing ability among the three intervals. With the increase of burial depth, the overlying pressure of shale increases. With the increase of TOC content and thickness, the amount of adsorption gas of shale increases. These two aspects of factors can lead to the permeability decline and self-sealing enhancement of the organic-rich shale. In this study, focusing on the Upper Ordovician-Lower Silurian and the Lower Cambrian in the Sichuan basin, four patterns of organic-rich shale and its roof and floor were summed up, and the rapid evaluation method of sealing of shale and its roof and floor under the limited geological data was established. Highlights • Sealing of roof and floor is due to difference in physical properties. • The overburden pressure increases as burial depth raises. • The content of adsorbed gas increases as TOC and thickness raises. • The two factors reduce permeability leading to the enhancement of self-sealing. • Four patterns of marine shale and its roof and floor are summarized. [ABSTRACT FROM AUTHOR]

Abstract Elastic modulus, hardness and brittleness are important mechanical parameters for hydraulic fracturing design. Conventional procedure to obtain these parameters consumes a large amount of rock material and has a difficult sample processing flow. Recently-developed instrumented indentation test is ideal for obtaining the three parameters in one run. However, its applicability to brittle materials needs to be justified, and a specific brittleness quantification method is needed for the characterization of anisotropic and heterogeneous shale. In this work, instrumented indentation test is performed on the shale outcrop from Longmaxi formation to study the cracking characteristics of shale under indentation. The hardness and elastic modulus of shale obtained under different loads are recorded. The results show that shale has different cracking characteristics compared to ceramic and glass. Moreover, both Martens hardness and indentation hardness values of shale decrease as indentation load increases. Thus, only the hardness value obtained at appropriate load can be used to predict proppant embedment depth. In contrary, Indentation modulus is hardly influenced by the test load and comparable to Young's modulus. A brittleness quantification method is proposed based on the cracking characteristics of shale. This method has sound physical basis as it reflects the relationship between the energy used to create new fracture surfaces and the total energy exerted by the indenter. In summary, this paper proposes a comprehensive characterization method for shale in Longmaxi formation, it has the advantages of easy specimen processing, simple experiment procedure and attractive cost. Highlights • Siliceous shale has different cracking characteristics under indentation compared to isotropic and homogeneous materials. • The Martens hardness value obtained at appropriate load should be used to predict proppant embedment. • Indentation modulus obtained is comparable to Young's modulus and hardly influenced by the test load. • The mechanical parameters obtained at small and large loads reflect the micro and macro scale response of shale respectively. • The proposed brittleness quantification method quantifies the portion of fracture energy in total input energy. [ABSTRACT FROM AUTHOR]

Abstract The shale has ultra-low permeability wherein multi-scale natural fractures are well-developed. The success of providing high diversion channels makes multi-stage fractured horizontal wells (MFHWs) become the powerful technique for economically producing gas from shale. This study presents a triple-continuum and discrete fracture model to describe a fractured shale reservoir embedded with a MFHW. The model incorporates non-equilibrium desorption/adsorption mechanism (NEDAM), viscous flow, Knudsen diffusion, and surface diffusion. The discrete fracture networks (DFNs) is quantitatively constructed according to the fracture density and stimulated reservoir area (SRA). This model is used to analyze the temporal/spatial evolution of the gas pressure and the net desorption rate. NEDAM is compared with the conventional equilibrium desorption mechanism (EDM) and it's found that NEDAM uncovers the delayed phenomenon during gas desorption, and the use of EDM overestimates the production contributed from the adsorbed gas. The maximum net desorption rate of adsorbed gas gradually spread from the SRA region to the non-SRA region. The complete flow stages are clearly interpreted in a semi-logarithmic curve of well testing, and the flow stage controlled by the hydraulic fractures is clearly presented. Finally, the instructions on hydraulic fracturing treatment are given based on the production analysis. Highlights • This paper presents a hierarchical approach which integrates DFNs with multi-continuum concept to model various coupling mechanisms of gas nonlinear transport in shale. • By introducing the concepts of stimulated reservoir area (SRA) and fracture density, the HFNs are quantitatively generated with stochastic algorithms. • Non-equilibrium desorption/adsorption mechanism uncovers the delayed phenomenon during gas desorption, and the maximum net desorption rate of adsorbed gas gradually spread from the SRA region to the non-SRA region. • There are critical values of the flow conductivities of main fracture and secondary fractures as to improve the shale gas production. [ABSTRACT FROM AUTHOR]

Abstract Due to their initial low permeability, unconventional plays can be economical only through hydraulic fracturing. This process, in order to be controlled needs to rely on a solid representation of the natural fracture geometry, an accurate stimulation model which considers the interaction with natural lineaments, and a physical reservoir model which can account for the different flow regimes occurring during production. The stimulated volume drainage can be evaluated using either Decline Curves Analysis/Rate Transient Analysis (DCA/RTA) techniques or reservoir simulation. In both cases, the geometry of the final Discrete Fracture Network (DFN) issued from the natural characterization and the stimulation, is very important, and for practical purposes is either overly idealized (Warren & Root approach) or oversimplified (Bi-wing). The models have shown their limitations when confronted with measurements in the field, opening up ways to use DFN geometries within integrated reservoir studies. The present work addresses some of the issues above, developing a hierarchical Discrete Fracture Model (DFM) based on the "filtering" of a stimulated DFN, realistically obtained by the characterization step and the stimulation process. This leads to a triple-continuum representation, consisting of: (1) the matrix media, (2) a high conductive stimulated fracture network and (3) a low conductive stimulated fracture network. The method consists in homogenizing low conductive networks, keeping a user defined backbone of high conductive fractures as the main "reservoir" DFN. One of the main advantages of this DFM relies on the way we compute the well-known Multiple Interacting Continua (MINC) approach, using a "proximity function" formalism, able to simulate transient effects. Using practical examples, this paper demonstrates applicability capacities of this method, enabling the integration of more complex geometries within a "quick" simulation framework. Highlights • A DFM-MINC proximity function for unconventional reservoirs flow modelling is proposed. • This DFM is meshless where a 3D reservoir problem is reduced to a 1D flow problem. • This DFM has superior computational efficiency, offering the user a rapid response for any sensitivity test. • DFM-MINC proximity function offers the user the ability to fix the matrix refinement level. • Several examples provide DFM accuracy validation and ability to conform complex fractures. [ABSTRACT FROM AUTHOR]

Brittleness is a key mechanical characteristic of rock and critical to various engineering practices particularly to design efficient fracturing stimulation of unconventional shale gas reservoirs. Variety of brittleness definitions and evaluation criteria have been proposed to describe rock failure behavior; however, their suitability and reliability have yet to be verified. In this paper, the existing brittleness indices were reviewed in detail and their applicability to reflect rock brittle characteristics were then investigated. The analysis indicated that most of expressions cannot describe brittle failure characteristics of rock efficiently and either partially or thoroughly fail to correctly address the impact of stress state on rock brittleness. Therefore, a new brittleness evaluation method was proposed based on promising energy transformation analysis of the complete stress-strain behavior of rock under compression. The new criterion is capable of dealing with the plastic energy dissipation mechanisms in the pre-peak region and the extent and rate to which rock strength degrades during macroscopic fracturing in the post-peak stage. Besides, the proposed brittleness index describes the entire transition of rock failure behavior of class I, from completely plastic to absolutely brittle states, in a continuous scale corresponding to 0 to 1. The applicability and outperformance of the proposed brittleness index were then verified against uniaxial and triaxial compression test results of some carbonaceous lithofacies from the Garau shale gas play within the Lurestan Basin, Iran. Samples under compression revealed various deformation and failure characteristics transitioned from brittle to semi-brittle behaviors with increasing confining pressure. Application of the brittleness indices to the tested rock specimens clearly demonstrated that the developed energy-based expression is able to rigorously capture the relative brittleness sequences of lithofacies and evolution trends under application of confinement, whereas further proved lack of either sufficient physical basis or appropriate formulation strategy in the existing indices. Accordingly, the new evaluation method seems to provide reliable estimates of rock brittleness in various field practices even though further verification is necessary. Finally, the important relation between microstructural carbonaceous texture and rock brittleness was discussed. [ABSTRACT FROM AUTHOR]

Shale reservoirs have low or ultra-low permeability and porosity, and require achieving economic production rates by creating fracture network. The spacing between fractures is thought to be a major factor in the success of horizontal well completions. The opening of a propped transverse fracture in horizontal wells causes a reorientation of in-situ stresses in its neighborhood, which in turn affects the creation and distribution of stress-relief fractures. In this paper, the extent of stress reorientation has been calculated for fractured horizontal well using two-dimensional numerical model of the stress interference induced by the creation of propped fracture. Staged fracturing in horizontal well is simulated based on an alternate sequencing of transverse fractures. By mapping the angle of stress-relief fractures generated by different fracture stages, we calculate the network area that is the extent of the intersection of stress-relief fractures. Our results demonstrate that the network area has a peak value with the varying fracture spacing and therefore, the associated spacing is optimal fracture spacing. The effect of in-situ stress contrast and net pressure on the optimal fracture spacing has been investigated. It is shown that optimal fracture spacing will increase with lower stress anisotropy or larger net pressure. Finally, the effect of proppant on optimal spacing is investigated. The results presented in this paper can offer some new insights on the completion designs, such as optimizing fracture spacing and improving the conductivity of rock matrix. [ABSTRACT FROM AUTHOR]

At present, the technology of carbon dioxide flooding shale gas is a hot topic for scholars. The numerical simulation of shale gas driven by carbon dioxide is inseparable from the accurate understanding of gas percolation mechanism and the construction of two-component gas motion equation. During the flooding process, the gas apparent permeability and the Knudsen number both change with time and space. However, this has not been fully discussed in previous studies. In this paper, the percolation mechanisms of two-component gas are discussed. On this basis, the calculation formula of Knudsen number in porous media is modified, and the transport equation of two-component gas is established. According to the derivation of apparent permeability, the two-component gas apparent permeability model is deduced. Then, the correction effect of Knudsen number and the related properties of two-component apparent permeability are analyzed. The results show that: (1) the effect of Knudsen number correction is significant at low pressure. Under high pressure, that is, when the pressure is greater than 10 MPa, the effect can be ignored; (2) the effect of Knudsen number correction is mainly significant in the range of medium pores, which is generally 10 nm–60 nm. And the peak value range decreases with the increase of pressure; (3) for the relative component apparent permeability curve, it has the properties of both relative permeability and apparent permeability. Based on the data in this paper, for the pressure change, it can be concluded that the maximum change rate of methane is 47.79% and that of carbon dioxide is 51.36%. For the change of pore size, it can be concluded that the maximum change rate of methane is 223.45% and that of carbon dioxide is 106.19%. It can be shown that the relative permeability of carbon dioxide is sensitive to pressure and the relative permeability of methane is sensitive to pore size. • The Knudsen number correction is considered to build the gas transport model. • Multiple flow mechanisms have been considered to built the apparent permeability model. • The effect and applicable conditions of Knudsen number correction have been analyzed from multi-dimensions. • The relative component apparent permeability is proposed to analyze relative flow capacity. [ABSTRACT FROM AUTHOR]

Multi-stage fracturing, following horizontal well drilling, is the key technology in shale gas reservoir development to enhance the recovery from such tight formations for economic production. The stimulated reservoir volume (SRV), which correlates closely to fracturing performance, is a quantitative measure for both pre-fracturing design and post-fracturing evaluation. However, an accurate estimation of the SRV is a long-standing challenge, because it requires a great knowledge of various parameters and complex mechanisms. In this study, we developed a mathematical model to estimate the SRV through simulating the main process during shale fracturing—multiple simultaneous hydraulic fractures propagate, perturbing the formation stress and raising the reservoir pressure; meanwhile, the stress change and pressure rise may jointly make natural fractures occur failure, and the SRV is estimated based on the volume of the naturally fractured zone that experiences tensile or shear failure. Hybrid numerical methods have been employed in this study. It applies displacement discontinuity method (DDM) to simulate non-planar hydraulic fractures propagation and represent the induced stress triggered by hydraulic fractures. The reservoir pressure is calculated by finite difference method (FDM). The failure state of natural fractures is predicted by the tensor equations deduced from Warpinski's failure theory. The model considers complex but important physical mechanisms that involved in the shale fracturing, including unequal flow-rate distribution among each hydraulic fracture, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increase with SRV extending (pressure & stress-depend), different failure states of natural fractures, etc. We validated our model by comparing its simulation results with analytical solution, published papers and on-site microseismic monitoring data. A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Sensitivity analysis was conducted to investigate the influence of geological condition and fracturing parameters on SRV. [ABSTRACT FROM AUTHOR]

The great potential that southern China has for marine shale gas resources is well known, yet shale gas production is very small. Exploration and development of southern China has lagged because of the complicated structural history of this region. Thus, it is important to recognize the tectonic history of this region and to carefully describe the developmental characteristics of natural fractures associated with the tectonic evolution of southern China. In this paper, we discuss the developmental characteristics of natural fractures based on the description and statistical analysis of natural fractures in outcrops, cores and thin sections, and from several experimental tests. Fractures examined in outcrop appear to be principally fold-fault related, regional tectonic, bedding or weathering fractures. Fractures observed in core are mainly shear fractures, tension fractures, and shear-tension fractures. Most of these fractures are sealed by calcite. Micro fractures and pores are well developed. Analysis of the cross-cutting relation of micro fractures suggests that the study area has been subject to at least two tectonic movements, consistent with our investigation of core. Fracture development appears to have been strongly influenced by structural evolution. However, fracture density displays a weak negative correlation with organic matter content. Further, fracture density appears to correlate positively with quartz content. Vertical variations of mineralogy appear to have influenced fracture generation and, therefore, hydrocarbon migration within the Niutitang Shale. [ABSTRACT FROM AUTHOR]

In order to solve the problem related to effective weight on bit (WOB) transition during shale gas long departure horizontal well drilling, the hydro-oscillator has been applied more and more both in China and abroad to reduce drill string drag and enhance the rate of penetration (ROP) for the horizontal section drilling, which can greatly reduce the cost of shale gas horizontal well drilling. This paper presented a theoretical relation between axial vibration velocity and friction coefficient of drill string, analyzed the principle of reducing friction by the use of the hydro-oscillator. On the basis of principle that axial vibration can reduce drag and taking well bore trajectory, drill string combination, the hydro-oscillator structure, etc. into account, a dynamics analysis model for full-well drill string with the hydro-oscillator was established. The effects of installation location, maximum vibration force and vibration frequency of the hydro-oscillator on drag reduction were simulated, and comparison and analysis had been carried out by using field data, with the calculation results providing a theoretical basis for the field application of hydro-oscillator and the optimization of structure parameters. [ABSTRACT FROM AUTHOR]

Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced (hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar (orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of non-orthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Economic success in the Cana Woodford shale play in Western Oklahoma has been largely due to field development using vertically fractured long horizontal laterals. In progressing from the field delineation phase, where sections are held by single well, to the field development phase, where multiple new wells are added to a previously produced section, many of the pre-existing “parent” wells suffer significant reduction in productivity as a result of interference from fracturing operations in the neighboring “infill” wells. We hypothesized that the change in the parent well's productivity was due to changes in fracture conductivity and/or changes in effective fracture length. In order to investigate the validity of our hypothesis, we developed a novel high-resolution spectral gas reservoir simulator to determine whether we could mimic the observed production behavior in the field. In particular, we wanted a simulator that would be immune to spatial truncation errors associated with finite difference schemes, and which would allow us to clearly examine interaction between nanodarcy reservoir matrix and high permeability narrow fractures; in addition, we needed the ability to alter fracture permeability with time to simulate the hypothesized effects of fracture interference. This paper details development of the spectral simulator and demonstrates that changes in fracture conductivity and length due to the interference event can account for observed productivity changes. We qualitatively compare simulator data to observed field data and show that changes in well productivity due to fracture interference can be explained by alteration of fracture half length and/or fracture conductivity. [ABSTRACT FROM AUTHOR]

Industrial levels of shale gas have been produced from the Niutitang Formation in the lower Cambrian of the Cen'gong block, South China. The practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, data obtained from outcrops, cores, and thin sections from the Cen'gong block were used to determine the development characteristics of such natural fractures. Combined with the analysis of burial history and fluid inclusions, the stress fields during three periods (the Yanshanian period, Himalayan period and neotectonic period) are suspected to play a critical role in fracture sealing. The paleotectonic stress tensor is determined using fault activity analysis, acoustic emission tests, and burial history. The magnitude and direction of current in situ stresses are determined by drilling-induced fractures, deviated well information, and cross multipole array acoustic (XMAC) logging. Under the constraints of XMAC logging interpretation and mechanical experiments, the spatial distribution of mechanical parameters is obtained by seismic inversion, and 3D heterogeneous geomechanical models are established using a finite element method (FEM). Then, the fracture density, reactivity, and aperture are identified. The results show that the magnitudes of the maximum horizontal principal stress during the Yanshanian period, the Himalayan period, and the neotectonic period are 150–170 MPa, 110–130 MPa, and 35–45 MPa, respectively. Using the fracture sealing calculation model, the fracture sealing that developed in the Himalayan period is the worst, the fracture sealing that developed in the Yanshanian period is intermediate, and the fracture sealing that developed in the neotectonic period is the best. Based on three-dimensional heterogeneous geomechanical modeling and tectonic stress evolution estimates, the fracture sealing calculation model proposed in this paper can be widely used in the evaluation of the preservation conditions of shale reservoirs, tight sandstone reservoirs and low-permeability reservoirs in complex tectonic areas. [ABSTRACT FROM AUTHOR]

In this study, we present a new approach to evaluate shale permeability as a function of effective pressure using Mercury Injection Capillary Pressure (MICP) experiments. Traditional approaches to describe permeability from MICP data often use pore size distribution and porosity and ignore intrusion effects. However, recent studies suggest that significant misinterpretation of pore size distribution and porosity can be realized owing to ignorance of pore compressibility in shale samples. We evaluate permeability variation with pressure using MICP data while considering for pore compressibility and intrusion correction. A shale sample often undergoes three stages during MICP tests: conformance, compression and intrusion. By identifying different pressure regions associated with these stages, we characterize pore compressibility as a function of pressure using compression stage and re-evaluate pore size distribution and porosity based on intrusion stage. We then integrate intrusion correction and pore compressibility values to Katz-Thompson correlation to evaluate permeability as a function of pressure. Identifying true intrusion and applying pore compressibility allow us to alter key variables in Katz-Thompson correlation, thus significantly lowers the final estimation of permeability. We observe 10–30% permeability reduction in the samples analyzed after corrections. This paper improves the accuracy of permeability predictions from MICP data; the outcome can be further applied to improve predictions of reservoir performance. [ABSTRACT FROM AUTHOR]

In this paper, we explore the possibility of specifying the ideal hypothetical positions of matrices blocks and fractures in fractured porous media as a single-continuum reservoir model in a way that mimics the dual-porosity dual-permeability (DPDP) configuration. In order to get an ideal mimic, we use the typical configuration and geometrical hypotheses of the DPDP model for the SDFM. Unlike the DPDP model which consists of two equations for the two-continuum coupled by a transfer term, the proposed single-domain fracture model (SDFM) model consists of a single equation for the single-continuum. Each one of the two models includes slippage effect, adsorption, Knudsen diffusion, geomechanics, and thermodynamics deviation factor. For the thermodynamics calculations, the cubic Peng-Robinson equation of state is employed. The diffusion model is verified by calculating the total mass flux through a nanopore by combination of slip flow and Knudsen diffusion and compared with experimental data. A semi-implicit scheme is used for the time discretization while the thermodynamics equations are updated explicitly. The spatial discretization is done using the cell-centered finite difference (CCFD) method. Finally, numerical experiments are performed under variations of the physical parameters. Several results are discussed such as pressure, production rate and cumulative production. We compare the results of the two models using the same dimensions and physical and computational parameters. We found that the DPDP and the SDFM models production rate and cumulative production behave similarly with approximately the same slope but with some differences in values. Moreover, we found that the poroelasticity effect reduces the production rate and consequently the cumulative production rate but in the SDFM model the reservoir takes more time to achieve depletion than the DPDP model. The normal fracture factor which appears in the transfer term of the DPDP model is adjusted against the SDFM. [ABSTRACT FROM AUTHOR]

This is the second part of our study on the resistivity curve responses of marine shale gas reservoirs. The characteristics of the effects of low-porosity systems on electrical conductivity have been explored previously. However, the effects of the pore system and reservoir type should also be carefully considered. The features of the pore system that have the greatest impact on resistivity must be identified so that they can be considered in subsequent studies. This paper shows that the pore type has the most direct effect on the rock resistivity. The relationship between the porosity and resistivity of each pore type is very close. The pore types must be distinguished when considering the application of shale conductivity features. Among the reservoir classification methods considered, those based on reservoir quality characteristics and clustering have the best correspondence with the resistivity curve. In addition, this paper shows that the existing common saturation models are insufficient to evaluate the saturation of shale gas reservoirs. Subsequent research, including the derivation of conductivity models or the performance of shale resistivity experiments and simulations, should fully consider the characteristics of the mineral composition, organic matter and pore types of the rock. This series of analyses paves the way for research on shale gas electrical conduction mechanisms and saturation models, which are for the study of shale gas reservoir petrophysics. This study helps to address the lack of deep rock geophysical research on the large shale gas reserves that have been discovered. • The pore type is the pore system factor that has the greatest influence on the resistivity. • The pore classification method based on pore genesis have the closest relationship with the changes in rock resistivity. • Deriving a conductivity model consider 3 main aspects, the pore type, mineral composition, organic matter content. • Existing saturation models are still difficult to accurately predict the saturation of marine shale. [ABSTRACT FROM AUTHOR]

The identification of favourable shale-gas areas in marine-continental transitional shales are challenging because of the multiple thin producing layers and abrupt lateral pinch-outs. Using data obtained from drilling, logging, and 3D seismic and natural gamma spectroscopic logging, this paper investigates the control of early Permian palaeogeomorphology on the distribution of organic-rich shale in the southeastern Ordos Basin. Using the impression method and de-compaction correction of strata thickness based on seismic velocity reconstruction, we restore the karst palaeogeomorphology at the top of the Taiyuan Formation for the early Permian. Three geomorphic units including karst highland, karst slope, and karst depression are identified, and constitute a geomorphological pattern of interjacent depressions and highlands. In addition, based on the multi-lithological eigenvalue method, the spatial distribution of transitional shales in the Shan 2 lower sub-member of the lower Permian Shanxi Formation was inferred using post-stack seismic parameter inversion. Our results show that organic-rich shale is distributed mainly in the low section of Shan 2 lower sub-member, which is controlled by karst palaeogeomorphology mainly distributed in karst depressions. Organic-rich shale distributed in karst depressions are characterised by large cumulative thickness, high TOC, moderate thermal maturity, strong hydrocarbon generation intensity, and relatively high gas content, indicating that shale-gas sweet spots should be distributed mainly in karst depressions rather than in highlands or slope areas. Meanwhile, Th/U and Th/K ratios, which indicate paleo-environment during the period of shale deposition, show that the strength of reducing conditions was greatest in karst depressions, moderate in karst slopes, and lowest in karst highlands. Therefore, it is inferred that the distribution of shale-gas sweet spots may be related to the weakly reducing environment, which favoured the preservation of organic-rich sediments during sedimentation. The upper section of Shan 2 lower sub-member was dominated by a high-energy transitional sedimentary environment, and the paleo-redox conditions tended to be oxic, disfavouring the preservation of shale organic matter, and the organic-rich shale in the upper section is relatively poorly developed. This study shows that palaeogeomorphology and paleo-redox conditions affect the deposition and preservation of organic-rich sediments in lower section, the relationship between palaeogeomorphology and the distribution of organic-rich shale can provide reference for shale gas sweet spots prediction and promote the rapid exploitation of shale gas in eastern Ordos Basin. • Karst palaeogeomorphology at the top of the Taiyuan Formation was restored. • The karst geomorphology controlled the redox environment, distribution of organic-rich shale and gas-bearing. • The relationship between the palaeogeomorphology and the distribution of organic-rich shale in transitional facies was established. • We propose a model for the development of organic-rich shale in transitional facies. [ABSTRACT FROM AUTHOR]

In the process of hydraulic fracturing of shale gas horizontal wells in the Weiyuan area of Sichuan, China, casing deformation (CD) is a frequent problem that has seriously affected the benefits of shale gas development and remains to be solved for many years. In this paper, based on the analyses of Multi-finger Imaging Tool-24 (MIT-24) data, microseismic data, and the relationship between CD and engineering parameters, we confirm that the wellbore morphology in all CD sections in the Weiyuan area is consistent with shear deformation characteristics and clarify the cause of all CD: hydraulic fracturing leads to increased fluid pressure in well-intersecting faults and large fractures (F-Fs), inducing their shear slip, and eventually leads to asymmetric compression on the casing by strata on both sides of F-Fs, i.e., CD. On this basis, we propose a set of methods to control (or moderate) the shear slip of F-Fs by reducing the additional fluid pressure in target F-Fs during hydraulic fracturing to prevent CD, including multi-cluster perforations, temporary plugging F-Fs and fracturing fluid flowback. We also analyze the theoretical basis, feasibility and workflow of these methods. These methods have been tested in 44 horizontal wells in the Weiyuan area, of which the result is a radical decrease in the CD rate of the single well (from 54% to 9.1%), indicating that the slip of F-Fs and the resulting CD during hydraulic fracturing can be controlled and providing a reference for the prevention of hydraulic fracturing-induced earthquakes. • All CD during hydraulic fracturing of shale gas in the Weiyuan area is caused by induced shear slip of F-Fs. • Temporary plugging can reduce the additional fluid pressure in target F-Fs so as to prevent CD. • The integrated technical methods have been proved to be effective in preventing CD in field application. [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]

The large-scale hydraulic fracturing technology used in shale gas development will cause major environmental pollution problems. Therefore, determining the concentration of contaminants in the fracturing flowback fluid to reduce surface water pollution caused by shale gas development is one of the main tasks facing shale gas development. This paper mainly studies the convection, reaction and diffusion process of contaminants in fracturing flowback fluid in non-equidistant fractures with arbitrary inclination. Firstly, based on the convection-reaction-diffusion model of fluid and combined with the fracture morphology, the convection-reaction-diffusion model of contaminants in fracturing flowback fluid in non-equidistant fractures with arbitrary inclination is established. Secondly, in order to solve the established model, an improved fracture equivalent method is proposed, which fully considers all the distributions of the left and right wings of the fractures. Thirdly, the convection-reaction-diffusion model is solved by using coordinate transformation, the Laplace transform method, the characteristic root method, and the Gaver-Stehfest numerical inversion method. Then the concentration of contaminants at the port of the left and right wings of each fracture near the horizontal wellbore in real space is obtained. Finally, taking the chloride ion in the fracturing flowback fluid as an example, the influence of the main controlling factors on its concentration is studied. The results show that the chloride ion concentration increases nonlinearly with the linear increase of backflow velocity and molecular diffusion coefficients, and decreases nonlinearly with the linear increase of rate coefficients and the length of the fracture. This research provides a theoretical basis for the research on the flowback pollution of fracturing flowback fluid. • Convection-reaction-diffusion model of contaminants in flowback fluid in non-isometric fractures is established. • This paper proposes the improved fracture equivalent method. • The model is solved by using coordinate transformation, characteristic root method, Laplace transform and its inversion-. • The methods to solve the model are simple and effective for solving convection-reaction-diffusion model. • By the sensitivity analysis, we know that varies nonlinearly with the linear increase of ς f i l , v f i l , D and L f i l . [ABSTRACT FROM AUTHOR]

Gas flow in nanoporous rocks is closely relevant to several globally important energy and environmental issues, such as shale-gas production and CO 2 subsurface sequestration. The Klinkenberg effect is critical to an understanding of gas flow, yet many specifics are unclear for nanoporous rocks. Here we investigated gas flow and the Klinkenberg effect in nanoporous rocks on the basis of a systematic study of gas permeability and diffusivity under a range of pore pressures and varying water saturations. We invalidated the use of the Klinkenberg equation for determination of intrinsic permeability and the Klinkenberg slippage factor on the basis of measurements in current laboratory conditions and propose a modified Klinkenberg equation for a more reliable determination of the slippage factor. We show that gas relative permeability is higher at higher pore pressures and that the Klinkenberg effect is more important in lower water saturations than in higher ones. The underlying mechanism of increased pore size after saturation was elucidated through neutron imaging on water distribution. In addition, we demonstrate that gas diffusivity better characterizes the diffusive gas flow than gas permeability and can be higher at higher pressures in either dry or partly saturated conditions. Finally, a characteristic pore-diameter index was derived on the basis of a new form of porosity–permeability relationship and was found to have a good correlation, which was previously lacking, with the Klinkenberg slippage factor for nanoporous rocks. Collectively, these new insights can advance the understanding of gas flow in nanoporous rocks and will have important implications on industrial applications. • The paper addressed the pore pressure influence on gas relative permeability in shale/tight formation rocks and revealed that gas relative permeability is higher at higher pore pressure. • This paper quantified the gas relative diffusivity and gas diffusivity under different pressures. • A modified Klinkenberg equation is proposed to obtain the slippage factor in a more reliable way. • A newly defined pore diameter index, which is derived from a new form of porosity-permeability relationship, is proposed and can be used to predict the Klinkenberg slippage factor for nanoporous rocks. [ABSTRACT FROM AUTHOR]

In view of the limitations of the traditional shale gas reservoir model when used in describing the process of shale gas flow, this paper establishes the seepage model of a triple media shale gas reservoir, and takes the adsorption and desorption process into account. By combining the use of Laplace transforms with similar structure theory, pseudo pressure solutions under three different outer boundary conditions having similar structures are obtained in Laplace space. The pseudo pressures are then inverted into real space with the Stehfest numerical inversion logarithm. In addition, the characteristic curves are drawn, and impact of the variation of the main parameters on them are analyzed. The results show that three different outer boundary conditions of the pseudo pressures are only different at the kernel functions. Furthermore, under the similar structure theory, portraying the characteristic curves of three different outer boundary conditions only requires a change to the kernel functions. Therefore, the similar structure theory replaces the complex calculation process of seepage equations in the simple algebraic calculation. At the same time, the similar structure theory tremendously simplifies the drawing process of the characteristic curves. This will have a profound influence on the development of well testing analysis software in the future as well. [ABSTRACT FROM AUTHOR]

The goal of this paper is to investigate the geological controls on the methane adsorption capacity of Lower Permian transitional black shales. To this end, a variety of methods, including quantifying organic matter richness, vitrinite reflectance, kerogen stable isotope analysis, X-ray diffraction (XRD), low-pressure nitrogen adsorption, and high-pressure methane adsorption were performed on black shale samples collected from the Mouye-1 well in the Southern North China Basin. Among them, high-pressure methane adsorption experiments were performed over a pressure range of 0–20 MPa at temperatures of 30 °C, 40 °C, and 50 °C. Then, the effects of organic matter, mineral compositions, pore properties, temperature, and pressure on methane adsorption capacity were analyzed, and a new formula for predicting the gas adsorption capacity and methane adsorption capacity of transitional shales as a function of burial depth in the Southern North China Basin was established. Experimental results indicate that the total organic carbon content (TOC) of shales in the present study ranges from 0.49% to 2.37% with an average value of 1.14%. The thermal maturity of these samples, as reflected by their vitrinite reflectance (R o ) values, demonstrates that all involved shale samples have extremely high thermal maturities with an average value of 3.23%. The levels of kerogen stable carbon isotopes (δ 13 C PDB ) range from −25.00‰ to −24.10‰, thereby indicating the presence of primarily type III organic matter within these shale samples. Mineral compositions mainly comprise clay minerals and quartz with average values of 57.8% and 37.6%, respectively. Within clay mineral populations, illite, kaolinite, I-S mixed layer clays, and chlorite are the dominant clay minerals. BET (Brunauer-Emmett-Teller) surface area and total pore volumes of the studied shale samples range from 4.7085 m 2 /g to 9.1883 m 2 /g and 0.01069 cm 3 /g to 0.01802 cm 3 /g, respectively. Under the measured pressure range, methane adsorption capacity correlates positively with TOC content, likely due to the increase in surface area and total pore volume with increasing TOC content. Nanometer-scale pores ranging from 2 to 10 nm, as revealed by low-pressure nitrogen adsorption, are the main contributors to surface area and total pore volume within these shales. Although the TOC-normalized surface area increases with thermal maturity, a negative correlation between thermal maturity and methane adsorption capacity was observed in the present study, most likely due to the decrease in TOC during thermal maturation. A weak positive quadratic correlation was also observed between clay mineral contents and methane adsorption capacity, with the Langmuir volume initially decreasing before subsequently increasing with increasing total clay content, thereby indicating that clay minerals have a weaker effect than TOC on methane adsorption capacity. Geologically applying the methane adsorption capacity of shales as a function of burial depth, which was established based on the Langmuir model, indicates that the methane adsorption capacity of transitional shales initially increases before ultimately decreasing as the depth increases due to the joint effects of temperature and pressure. [ABSTRACT FROM AUTHOR]

Wettability plays a significant role in exploration and exploitation of shale gas. However, the characterization and evaluation of the wettability of gas shale is a challenge due to the complexity and heterogeneity of components and pore structure. The objective of this paper is to characterize the wettability of gas shale and analyze its relationships with mineral composition, total organic carbon (TOC), and nuclear magnetic resonance (NMR) T 2 spectrum by a series of parallel experiments of oil (water) contact angles, NMR, and rock composition analysis on core samples of Longmaxi Formation drilled from shale gas wells in Jiaoshiba gas field, Sichuan Basin, China. The study shows that: ① the gas shale is both water-wet and oil-wet and prone to be oil-wet with water contact angle (θ w ) ranging from 32° to 41.5°; ② the mineral composition together with TOC jointly affects θ w ; the quartz mineral and TOC have a negative effect on θ w , whereas clay minerals have a positive influence on θ w of gas shale; ③ the θ w shows distinctive correlations to the characteristic of T 2 spectrums; Recognized as a crucial parameter describing the characteristic of the T 2 spectrum, the geometric mean of T 2 spectrum (T 2 g ) is considered as a preferable model parameter to relate the θ w and the T 2 spectrum. Thus, novel equations for predicting contact angle by NMR are proposed. [ABSTRACT FROM AUTHOR]

Widmerpool Gulf is one of the basins in the carboniferous Bowland Hodder shale in Central Britain. The area of interest in the Widmerpool Gulf is the Bowland Shale Formation within the Upper Bowland. This paper focuses on evaluating the total organic carbon (TOC) from Rempstone 1 and Old Dalby 1 both penetrating the Bowland Shale Formation using Passey's delta Log R method. TOC is an essential property needed to have a productive shale gas play – accurate characterisation of TOC is critical in evaluating the potential of shale gas reservoirs because it closely relates to the amount of kerogen and therefore total gas content. Passey's method involves the use of well logs to obtain the organic richness i.e. TOC. It relies on the response of well logs to organic matter using an overlay of porosity logs and resistivity logs. Which causes a separation i.e. a delta Log R separation. The reasons for the delta Log R separation in an organic rich reservoir/non reservoir rocks is due to the presence of low density, high transit time kerogen and the presence of formation fluid i.e. oil, gas or water. Immature source rocks also observe a separation but only from the porosity log whilst non source rocks observe no separation. Rempstone 1 and Old Dalby 1 well logs were exported on Interactive Petrophysics to analyze the lithology of the intervals before been exported to Microsoft Excel to evaluate the parameters of Passey's equation to enable TOC determination. TOC estimates for the Upper Bowland Shale section in the Widmerpool Gulf and was found comparable to estimates obtained from British Geological Survey (BGS) RockEval core analysis report. This method proved to be a suitable way of estimating the total organic carbon using simple well logs. [ABSTRACT FROM AUTHOR]

Breakthroughs in shale gas exploration in the Upper Ordovician-Lower Silurian strata of the Upper Yangtze Platform have attracted interest in its sedimentary-tectonic evolution, but the tectonic background of the northern margin of the Upper Yangtze Platform remains unclear. In this paper, the Wufeng-Longmaxi formations on the northern margin of the Upper Yangtze Platform were investigated. Based on geochemical and mineralogical analyses of the tuffs/K-bentonites of the Wufeng Formation and the barite in the Longmaxi Formation, as well as previous research results, it was concluded that the northern margin of the Upper Yangtze Platform was in an extensional tectonic background during the Late Ordovician-Early Silurian. Detailed analysis revealed that, (1) the U–Pb zircon age of the tuff in the Bajiaokou section in South Qinling is 443.91 ± 0.92 Ma. The Zr/TiO 2 –Nb/Y diagram of the tuffs/K-bentonites indicates that their protoliths were alkaline-subalkaline basalt and andesite series rock. Based on the Th–Hf/3-Ta, Th–Tb*3-Ta*2, and TiO 2 –Nb/3-Th diagrams, there are undiscovered intraplate tension calc-alkaline basalts in the northern Yangtze Platform or the southern Qinling region, which provided volcanic clastic materials to the Ziyang, Lan'gao, Chengkou, Yichang and other regions. (2) Scanning electron microscopy revealed that the barite crystals in the Longmaxi Formation exhibit dissolution features and have a large particle size. Energy spectrum analysis of these barite crystals revealed that they have C, O, S, and Ba contents of 8.48 wt%, 22.98 wt%, 13.09 wt% and 55.44 wt%, so they are speculated to have been formed via cold methane seep genesis in a weak extensional tectonic setting. The 87Sr/86Sr ratios of the barite revealed that different types of barite were simultaneously formed in this area under the influences of hydrothermal and cold methane seeps. (3) The analysis of the heavy minerals in the Lower Silurian strata in the Bajiaokou section revealed that the provenance in the South Qinling area changed significantly during the late Early Silurian. Based on the above analyses, the northern margin of the Upper Yangtze Platform was in an extensional tectonic setting during the Late Ordovician-Early Silurian. The distribution of the total organic carbon content indicated that the extensional tectonic background provided good conditions for the enrichment and preservation of organic matter. The results of this study provide an understanding of the regional sedimentary-tectonic pattern and evolution of the Yangtze Platform during this period, as well as a reference for future shale gas exploration in this region. • The tectonic background of the Late Ordovician-Early Silurian was studied. • The northern margin of the Upper Yangtze Platform is an extensional background. • The extensional tectonics caused the cold seepage events. • The extensional fault controlled the distribution of volcanic clastic sediments. • Organic matter accumulation was influenced by the extensional fault depression. [ABSTRACT FROM AUTHOR]

Pore sizes are typically on the order of nanometers for many shale and tight rock oil reservoirs. Such small pores can affect the phase behavior of in situ oil and gas owing to large capillary pressure. Current black-oil simulation practice is to alter the unconfined black-oil data for a fixed mean pore size to generate confined black-oil data with a suppressed bubble-point pressure. This approach ignores compositional effects on interfacial tension and the impact of pore-size distribution (PSD) with variable phase saturations on capillary pressure and phase behavior. In this paper, we develop a compositionally-extended black-oil model where we solve the compositional equations (gas, oil, and water components) directly so that black-oil data are a function of gas content in the oleic phase and gas-oil capillary pressure. The principle unknowns in the variable bubble-point fully-implicit formulation are oil pressure, overall gas composition, and water saturation. Flash calculations in the model are non-iterative and are based on K- values calculated explicitly from the black-oil data. The advantage of solving the black-oil model using the compositional equations is to increase robustness of the simulations owing to a variable bubble-point pressure that is a function of two parameters; gas content and capillary pressure. Leverett J-functions measured for the Bakken reservoir are used to establish the effective pore size- P c -saturation relationship, where the effective pore size depends on gas saturation, which is the non-wetting phase saturation. The input fluid data to the simulator, e.g. interfacial tension (IFT), phase densities and viscosities, are pre-calculated as functions of pressure from the Peng-Robinson equation of state (PREOS) for three fixed pore sizes. During the simulation, at any pressure and saturation, fluid properties are calculated at the effective pore radius by using linear interpolation between these three data sets. We compare the results of the compositionally-extended black oil model with those of a fully-implicit eight-component compositional model that we have also developed. The results for the Bakken reservoir show that including PSD in the model can increase estimated recoveries by nearly 10% for initially undersaturated reservoirs while the increase can be over 100% for initially saturated reservoirs. Capillary pressure significantly increases the original oil-in-place (OOIP) for reservoirs that would otherwise be initially saturated leading to larger oil production. [ABSTRACT FROM AUTHOR]

In unconventional petroleum and geothermal reservoirs, a complex fracture network is mostly desired in order to enhance the reservoir permeability. In this paper, the mechanism of hydraulic fracture branching and generation of a cluster of fractures is investigated via numerical simulation. Firstly, the reservoir rock is modeled using lattice cell version of the discretized virtual internal bond method. An algorithm is developed to identify the hydraulic fracture trajectory. A sensitivity study is conducted with different pressurization rates, fluid pressures, in-situ stresses and orientations of perforations. It is found that a high fluid pressure and a high pumping rate are the necessary and sufficient conditions, respectively for creating fracture branching and clusters. The pressurization rate plays a critical role in branching fracture, but the role it plays is subjected to its duration as fracture propagates. The fluid pressure, as a controlling factor that integratively accounts for the effects of pressurization rate and duration, determines the degree of fracture branching. The location of fracture network is controllable by adjusting the magnitude of fluid pressure. The direction of propagation and distribution of fractures are determined by the in-situ stress contrast. As the contrast in the in-situ stresses increases, the branched fractures increasingly tend to propagate along the maximum in-situ stress direction. As expected, the effect of perforation direction on fracture growth is local; with hydraulic fracture advancing forward, it gradually turns to and propagates along the maximum in-situ direction. The degree of contrast between the in-situ stresses determines how fast the hydraulic fracture turns to the maximum in-situ stress direction. The simulation study helps to understand the mechanism and dynamics of complex hydraulic fracture generation in unconventional reservoirs. [ABSTRACT FROM AUTHOR]

A relatively large number of pH-sensitive minerals (e.g., calcite, dolomite, siderite) and redox-sensitive compositions (e.g., organic matter, siderite, pyrite, and chlorite) are present in gas-bearing shale formations. During hydraulic fracturing, some of these compositions can be dissolved under acidic or oxic condition and may generate critical transport pathways to bypass water blockage within the fracture-matrix interface. This paper reports the effects of 5% HCl or 15% H 2 O 2 reactive fluids on transport pathway and methane diffusion capacity of Longmaxi shale samples. Experiments show that these sensitive minerals are distributed evenly throughout the shale matrix as dispersed or isolated grains. Reactivity differences between sensitive compositions and non-sensitive minerals cause heterogeneous dissolution at micrometer scale and generate substantial new pore space in the reaction zones, giving an overall pore volume increase by 4.6–6.6 vol % calculated using μCT data. Apart from dissolution pores, many oxidation-related microfractures with a spacing less than 10 μm are also observed in H 2 O 2 -treated shale. Due to resolution limitations of SEM and μCT imaging, these new transport pathways appearing as separated void spaces are actually connected by much smaller pores at nanoscale, leading to a greater than 3.7-fold increase in macropore diffusivity. Despite more water imbibition into the H 2 O 2 -treated shales, the largest increase in diffusivity is also observed post oxidizing treatment. Our study clearly demonstrates that the newly formed transport pathways can reduce the diffusion pathway length and tortuosity of nanopore systems, thereby significantly improving wet shales' diffusivity. These observed changes in transport pathway and diffusivity indicate that acidizing or oxidizing treatment may be a possible method for mitigating water blockage within fracture-matrix interface of hydraulically fractured Longmaxi shale gas formation. • Heterogeneous dissolution in Longmaxi shale occurs after 5% HCl acidizing or 15% H 2 O 2 oxidizing treatment. • The newly formed pores and dense microfractures can generate well-interconnected transport pathways, leading to a greater than 3.7-fold increase in macropore diffusivity. • The newly formed transport pathways have a great potential for mitigating water blockage within fracture-matrix interface. [ABSTRACT FROM AUTHOR]

Under the high temperature and high stress geological environment, how the physical and mechanical properties of deep shale reservoirs will change has become a hot research issue. Based on the Confined Brazilian Test, this paper improves a test method for the tensile strength of shale under triaxial conditions with a simple specimen fixture and convenient specimen preparation and performs a high confining pressure (0–60 MPa) Brazilian splitting test on Longmaxi Formation shales. The stress-displacement curve records the deformation and failure of shale. Acoustic emission technology (AET) detects the evolution process of fractures and further identifies failure modes. 3D optical scanning system reconstructs the fracture morphology. The results show that the maximum tensile strength of the shale specimens in the triaxial condition is increased by 58.5% relative to direct tensile strength. As the confining pressure gradually increases to 60 MPa, the specimen enters the stress state of compressed in three directions, the tensile failure mode gradually transitions to shear failure mode via tensile-shear composite failure mode, and the fracture angle gradually increases. The AE signal in triaxial conditions mainly shows a leap trend. The appearance of AE signal with high peak frequency can be used as a reference for micro-fracture initiation. The presence of shear fractures increases the roughness of the shale main fracture surface, and this effect diminishes as the confining pressure increases. This study can provide a reliable theoretical basis for the optimal design of hydraulic fracturing in deep shale gas reservoirs. • A test method for the tensile strength of shale under triaxial conditions is improved. • The maximum value of tensile strength of shale under triaxial conditions is determined. • The failure mode of the specimen and the process of fracture initiation-propagation are discussed. • AE characteristics can reasonably reflect the fracture characteristics of the specimen. [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]

Casing deformation is a severe problem in shale gas well development. The field data show that multiple deformations usually occur in the same casing well, and the distance is close, and the degree of deformation is different. In this paper, firstly, based on the distribution of micro-seismic event points in the Ning M well, the fracture group is inverted, and to establish the finite element numerical model to simulate the multi-stage fracturing, Then, the stress at each point of the casing is analyzed with the fracturing time, the circumferential stress at each point after fracturing and the axial stress of casing, and the displacement variation of casing in the directions of maximum, minimum and vertical principal stress are discussed. Finally, the effect of the intensive fracturing technology on controlling casing deformation is discussed. The results show that: a) Casing stress increases in different amplitude at a local point, circumferential direction, an axial direction, and regional stress difference is formed; b) Some local areas around the wellbore are subjected to twice or more re-fractures, and the corresponding rock properties (such as elastic modulus and Poisson's ratio) will change differently; c) Casing deformations with different directions and displacements appear in some reconstructed areas, showing "S" shape deformation, consistent with the actual deformation situation on site; d) The intensive fracturing technology can alleviate the non-uniformity of fracturing and reduce the non-uniform load of the casing, and effectively reduce the casing deformation rate after field application. • Inversion of fracture group distribution after fracturing based on micro-seismic signals. • The mechanism of casing deformation during multistage fracturing is clarified. • The intensive fracturing technique has a significant effect on alleviating casing deformation. [ABSTRACT FROM AUTHOR]

With the gradual depletion of traditional energy sources such as oil and natural gas. As an unconventional energy that can replace traditional resources, shale gas has attracted the attention of the world energy department. The storage environment of shale gas (oil) is usually accompanied by in-situ stress, and the exploitation of shale gas is actually a dynamic process. Therefore, it is of great significance to study the dynamic mechanical characteristics of shale under in-situ stress. In this paper, the dynamic mechanical parameter and constitutive relationship of shales with different bedding (0°, 30°, 45°, 60°, 90°) was studied by the triaxial SHPB tests with the confining pressure from 0 to 15 MPa. The effects of confining pressure on the mechanical properties of shale with different bedding were discussed from the aspects of the dynamic compressive strength, elastic modulus, failure strain, energy characteristics as well as the dynamic failure mode. The experimental results showed that, the dynamic mechanical properties of shale mainly depended on the interaction of the bedding dip angle and various confining pressures. The failure modes of shale under confining pressure mainly present compression shear failure or only damage crack. In additional, a modified dynamic constitutive model of shales was based on the ZWT viscoelastic constitutive relationship, which simplified the low frequency term and took into account shale material damage characteristics. The modified constitutive model is simple in structure and can predict the strength characteristics of shale under confining pressure in a certain range when the basic mechanical parameters and empirical parameters are known. • The dynamic mechanical properties of shale with different bedding under the triaxial compression impact tests were comprehensively studied. • The failure modes of shale with different bedding under confining pressure were revealed. • The relationship between energy absorption and failure mode of rock was analyzed systematically. • A improved ZWT damage constitutive model was used to describe the dynamic mechanical characteristics of shale under confining pressure. [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]

Infinite acting linear flow is a dominant flow regime in many multi-fractured horizontal wells completed in shale/tight gas reservoirs. A well-accepted methodology for analysis of this flow regime in systems without aquifer influence is the square-root of time plot. For reservoirs producing single phase oil, fracture half-length can be estimated from the slope of this plot, provided reservoir permeability is known. However, for gas reservoirs, pseudovariables are required to account for the pressure-dependence of gas properties. For example, the pseudotime function must be used to account for the strong dependence of gas viscosity and compressibility on pressure. As has been previously noted, for tight reservoirs, the pseudotime function must be evaluated at average pressure in the region of influence, which in turn is calculated from the material balance equation. Therefore, the linear flow equation should be coupled with the material balance equation so that fracture half-length can be estimated. This solution methodology is implicit and may require iterative procedures. This paper introduces an explicit solution methodology for estimating fracture half-length. As in the case of implicit solution methodology, the assumptions of no aquifer influence and infinite acting flow are considered. Because of no aquifer support, we can use material balance equation of volumetric reservoirs. We propose an appropriate correlation between viscosity–compressibility product and the material balance equation. This correlation helps to simplify pseudotime calculations and remove the implicit and iterative nature of the previous solution methodology. Accordingly, we have developed simple semi-analytic solutions that provide a methodology for direct estimation of fracture half-length. The solutions were developed for constant rate, constant pressure, and variable pressure/rate production from wells. We used numerical simulation to generate many synthetic production examples with wide ranges in reservoir properties to validate the introduced equations. We further used our approach for analysis of field cases (multi-fractured horizontal wells completed in shale reservoirs) to demonstrate its practical applicability to real data. [ABSTRACT FROM AUTHOR]